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Growing the business
and advancing the
energy transition
BP Annual Report and Form 20-F 2018
Advancing energy to
improve people’s lives
Contents
Strategic report
Overview
2
4
6
8
9
BP at a glance
How we run our business
Chairman’s letter
Group chief executive’s letter
The changing energy mix
Strategy
10 Our strategy
12 BP investor proposition
14 Major project start-ups
Performance
16 Measuring our progress
18 Global energy markets
19 Group performance
22 Upstream
28 Downstream
34 Rosneft
37 Other businesses and corporate
38 Alternative energy
Innovation in BP
40
43 Sustainability
43 Safety and security
45 Climate change
48 Managing our impacts
49 Value to society
49 Human rights
50 Ethical conduct
51 Our people
53 How we manage risk
55 Risk factors
Helge Lund succeeded
Carl-Henric Svanberg
as chairman. Helge
joined the board in July
and took the chair on
1 January 2019.
See page 6.
Financial statements
113 Consolidated financial statements
of the BP group
134 Notes on financial statements
210 Supplementary information on
oil and natural gas (unaudited)
238 Parent company financial
statements of BP p.l.c.
Corporate governance
Additional disclosures
Introduction from the chairman
58 Board of directors
63 Executive team
68
70 Board activity in 2018
74 Shareholder engagement
74
75 Audit committee
81
International advisory board
Safety, ethics and environment
assurance committee
Remuneration committee
83
84
Geopolitical committee
85 Chairman’s committee
86
87 Directors’ remuneration report
110 Directors’ statements
Nomination and governance committee
273 Contents
Including information on liquidity
and capital resources, oil and gas
disclosures, upstream regional
analysis and legal proceedings.
Shareholder information
305 Contents
Including information on dividends,
our annual general meeting
and share prices.
315 Glossary
320 Non-GAAP measures reconciliations
323 Signatures
324 Cross-reference to Form 20-F
325 Information about this report
Glossary
Words and terms with this symbol
are defined in the glossary on page 315.
Cautionary statement
This document should be read in conjunction with the cautionary statement on page 303.
What we do
We provide customers with fuel for
transport, energy for heat and light,
power for industry, lubricants to keep
engines moving and the petrochemicals
products used to make everyday items
such as paints, clothes and packaging.
Find out more about our activities
on page 4.
Our people
and our values
The BP values express who we are
and what we stand for. They capture the
individual and collective behaviours we
expect from everyone who works for us.
Our people help build enduring
relationships based on mutual trust
with governments, customers, partners,
suppliers and communities.
Read more about our people on page 51
or visit bp.com/values.
Safety
Respect
Excellence
Courage
One team
Our performance
in 2018
See how our businesses have performed
and how we are reducing our emissions,
improving our products and creating low
carbon businesses.
Find out more on pages 16 to 56.
Our strategy
Our four strategic priorities are designed
to allow us to be competitive at a time
when prices, policy, technology and
customer preferences are evolving
rapidly.
Find out more on page 10.
Informing our thinking
Global prosperity is shaping economic
and energy trends.
By 2040:
GDP doubling
>2.5 billion people
lifted from low incomes
See how we consider a range of
scenarios on page 9.
BP Annual Report and Form 20-F 2018
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.
Data as at or for the year ended 31 December 2018
unless otherwise stated.
Scale 73,000 78
employees
countries
18,700
retail sites
63,000
square kilometres of
new exploration
access
19,945
million barrels of oil
equivalent – proved
hydrocarbon reservesa
a On a combined basis of
subsidiaries and equity-
accounted entities.
BP in action
Highlights of some of
our activities in 2018.
Completed a significant
turnaround at our largest
refinery, Whiting in
the US.
Acquired Chargemaster,
operator of the UK’s
largest electric vehicle
charging network.
Purchased a 16.5% interest
in the UK’s Clair field from
ConocoPhillips – increasing
our share to 45.1%.
Opened more than
220 REWE to Go®
convenience retail
sites in Germany.
Acquired a portfolio of
unconventional assets from BHP
in some of the best basins across
Texas and Louisiana.
Signed a production-sharing
agreement with SOCAR to
explore and develop in the
North Absheron basin in
Azerbaijan’s Caspian Sea.
Opened our 440th
BP-branded retail site
in Mexico.
Formed a strategic alliance
with Petrobras to explore
joint projects in upstream,
downstream, trading and low
carbon. And accessed new
acreage in the Santos basin,
offshore Brazil, making us the
second-largest exploration
holder in the basin.
2
2
See Glossary
See Glossary
BP Annual Report and Form 20-F 2018
BP Annual Report and Form 20-F 2018
Signed an agreement
with the governments of
Mauritania and Senegal
to enable development of
the BP-operated Greater
Tortue Ahmeyim gas
project.
Gained approval for the
Ghazeer project to develop
the second phase of the
Khazzan field in Oman.
Performance
$9.4bn 3.7
16
profit attributable
to BP shareholders
million barrels of oil
equivalent per day –
hydrocarbon productiona
tier 1 process
safety events
(2017 $3.4 billion)
KPI
(2017 3.6mmboe/d)
KPI
(2017 18)
KPI
$12.7bn 100%
underlying replacement
cost profit
group proved reserves
replacement ratio a
KPI See key performance
indicators on page 16.
(2017 $6.2 billion)
KPI
(2017 143%)
KPI
a On a combined basis of
subsidiaries and equity-
accounted entities.
Completed a deal to
develop resources in
the Kharampurskoe and
Festivalnoye licence
areas in Russia, jointly
with Rosneft.
Invested in PowerShare – a Chinese
company that’s connecting EV
drivers, charge point operators
and power suppliers. And signed
a memorandum of understanding
with NIO Capital to explore
opportunities in advanced mobility.
Six major projects
started up in 2018
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See pages 14 and 15.
More on our
renewables activity
Investments in electric vehicle
technology on page 42.
Low carbon ambitions on
pages 46-48.
Took delivery of British
Partner – the first of six
state-of-the-art liquefied
natural gas ships being
constructed in
South Korea.
Fuelled the first non-stop
flight from Perth to
London with Air BP jet
fuel produced at our
nearby Kwinana refinery.
Lightsource BP delivered its
first Indian solar project. And BP
sanctioned the second phase of
the KG D6 development in the
‘Satellite cluster’ deepwater gas
fields in India with Reliance.
BP Annual Report and Form 20-F 2018
BP Annual Report and Form 20-F 2018
BP Annual Report and Form 20-F 2018
BP Annual Report and Form 20-F 2018
See Glossary
3
3
How we run our business
Business model foundations
Safe and reliable operations
Talented people
From the deep sea to the desert,
from rigs to retail, we deliver
energy products and services
to people around the world.
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 depend on it.
We provide customers with fuel for
transport, energy for heat and light,
power for industry, 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,
downstream and renewables 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 are helping to
meet the dual challenge of society’s
need for more energy while reducing
emissions through our ‘reduce, improve,
create’ framework (see page 46).
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 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 great employer.
We believe the societies and
communities we work in should benefit
from our presence. We aim to create
positive, meaningful and sustainable
impacts in those communities through
our social investments.
We contribute to economies around
the world by employing local people,
helping to develop national and local
suppliers, and through the funds we
pay to governments from taxes and
other agreements.
See bp.com/society for more information
on how we generate value to society.
See Safety and security on page 43.
See Our people on page 51.
1 Finding oil and gas
2 Developing and extracting oil and gas
Creating value
1 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.
2 Developing and extracting
oil and gas
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.
We also seek to grow or extend the life of
existing fields – such as our Clair Ridge project,
which is helping unlock additional resources
from the Clair field in the UK North Sea.
See Upstream on page 22.
3 Transporting and trading
We move oil and gas through pipelines and by
ship, truck and rail. We also trade a variety of
products including oil, natural gas, liquefied
natural gas, power and carbon products, as
well as derivatives and currencies. BP’s traders
serve more than 12,000 customers across
some 140 countries in a year. Our customers
range from independent power producers to
utilities and municipalities. We are the largest
trader of natural gas in North America.
We use our market intelligence to analyse
supply and demand for commodities across
our global network.
4
BP Annual Report and Form 20-F 2018
Technology and innovation
Partnerships and collaboration
Governance and oversight
New technologies help us produce energy
safely and more efficiently. We selectively
invest in areas with the potential to add greatest
value to our business, now and in the future,
including building lower carbon businesses.
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 40.
See Rosneft on page 34 and Upstream analysis
by region on page 279.
See How we manage risk on page 53
and Corporate governance on page 57.
3 Transporting and trading
4 Manufacturing and marketing
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6 Venturing
5 Generating renewable energy
4 Manufacturing and marketing fuels
and products
We produce refined petroleum products
at our refineries and supply distinctive
fuels 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,
including lower carbon products.
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
lubricant markets across the world.
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.
See Downstream on page 28.
5 Generating renewable energy
We have been investing in renewables for
many years. Our focus 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 renewable
ethanol and power. We also provide renewable
power through our significant interests in
onshore wind energy in the US, and develop
and deploy technology to drive efficiency.
And in solar energy we target the growing
demand for large-scale solar projects
worldwide through Lightsource BP.
See Alternative energy on page 38 and
Climate change on page 45.
6 Venturing
We invest in high-tech companies to help
accelerate and commercialize new
technologies, products and business
models. Our focus is on five areas that
are core to our strategy for advancing the
energy transition: advanced mobility,
bio and low carbon products, carbon
management, digital transformation and
power and storage.
See bp.com/venturing.
BP Annual Report and Form 20-F 2018
5
Strategic report – overview
Chairman’s letter
$8.1bn
total dividends distributed
to BP shareholders
6.3%
ordinary shareholders
annual dividend yield
6.4%
ADS shareholders
annual dividend yield
6
See Glossary
BP Annual Report and Form 20-F 2018
I am of the view that more energy with
fewer emissions – the dual challenge
– can be met if a progressive and
pragmatic approach is taken to the
energy transition.
Dear fellow shareholder,
2018 has been a year of very good operating performance, important
strategic progress and continued change. Our teams have delivered
strong results across the business and we are well positioned to
continue to deliver value as we play our part in the dual challenge
of delivering more energy with fewer emissions.
It was an honour to be appointed chairman of BP. I have huge
respect for the responsibilities that come with the role and I will do
my utmost to provide thoughtful leadership to the board of directors
and support for Bob Dudley and his team as we advance BP in a
changing energy landscape.
BP’s strong position is a great tribute to my predecessor as chairman,
Carl-Henric Svanberg. During his nine-year tenure Carl-Henric did an
outstanding job of guiding our company through difficult times.
On behalf of the board, I want to thank him for his contribution.
It has been a pleasure to get to know my new colleagues on the board,
and I believe we have a wide ranging combination of diversity, skills,
experience and knowledge that we need to steer the company through
a landscape that is both uncertain and presents possibilities. Last year
we welcomed Dame Alison Carnwath and Pamela Daley to the board,
each with extensive experience gained in a range of executive and
non-executive roles in large companies. And this year we say farewell to
Alan Boeckmann and Admiral Frank ‘Skip’ Bowman. Alan and Skip have
both made valuable contributions during their tenures, particularly
through their leadership and membership of our safety, ethics and
environment assurance committee.
Strengthening organizational culture and capability
The work of the board will continue to evolve over time to make sure
that BP is best positioned to advance the energy transition, embrace
digital disruption and meet society’s changing expectations of major
companies. In my short time so far at BP I have already seen for myself
many examples of the commitment of our people. Their drive and
determination have brought BP to where it is today, and I want to thank
them for their hard work. It is critically important we continue to
strengthen our organizational capabilities – both by developing our
people and by continuing to attract the world’s top talent. We look
forward to doing this by continuing to foster a diverse and inclusive
culture, where everyone feels valued.
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Our progressive, pragmatic approach to the
energy transition
There are two defining priorities for our industry. One is to produce
more energy to meet growing global demand as emerging economies
develop and provide people with a better quality of life. The other is
to play our part in reducing greenhouse gas emissions. I am of the
view that more energy with fewer emissions – the dual challenge –
can be met if a progressive and pragmatic approach is taken to the
energy transition.
In BP we recognize that energy in many forms will be required, produced
in ways that are cleaner and better. That is why we see ourselves not
just as an oil and gas business but as a global energy business. We also
recognize that we must be constantly improving and seeking out new
ideas and possibilities. We must be able to learn fast and harness all the
potential of the rapid advances in digital and other new technologies.
Earning trust through strong values
Pursuing this approach, BP is guided by its values of safety, respect,
excellence, courage and one team. These are values I personally
share. I believe they help to build trust with our people, partners,
the communities in which we work, and with you, the owners of
the company.
Above all, our primary focus has to always be on operating safely
and reliably, minute by minute, day after day. Protecting people, the
environment and our assets is always our top priority and the bedrock
on which success is built. I think of it as having the tightest defence in
the league, like a good football team. If you have a strong defence, you
can be more forward looking, compete harder and be better positioned
to win.
We value the dialogue we have with you and others, sharing our
achievements, our challenges and our plans and seeking your views.
This report is one of many ways we update you on our activities
and progress.
This year, the board is pleased to support a resolution that has been
proposed by a group of investors at our annual general meeting in May.
The resolution, if passed, will pave the way for additional reporting to
help investors better understand how BP’s strategy is consistent with
the Paris climate goals. We see this as an important opportunity for
investors to appraise our progress in responding to the dual challenge.
Further details can be found in the Notice of Meeting, to be published
in April.
Our clear purpose
Finally, I think it is important for BP’s success that we have a clear
purpose – one that is strongly linked to society’s needs. That is why
one of the first things I have done with the board is review our purpose
in line with our strategy and values. Our purpose is to advance energy
to improve people’s lives. Today the world needs more energy than
ever but with fewer emissions. To help meet this dual challenge we
have to be financially strong and make sure we continue to be an
attractive investment through the energy transition.
I look forward to working with Bob and the team as we advance the
energy transition, delivering through our strategy, guided by our values
and inspired by our purpose. I also look forward to hearing from you, and
meeting many of you, in the coming months and years as we look to
reward your trust and confidence in BP.
Helge Lund
Chairman
29 March 2019
More information
Corporate governance
Page 57
BP Annual Report and Form 20-F 2018
7
Group chief executive’s letter
Dear fellow shareholder,
I am pleased to report that 2018 was another remarkable year for BP.
Our safety performance continued to improve overall, helping to create
record operational reliability, which led to strong production, and record
refining throughput.
Strength in numbers
This ultimately contributed to us maintaining a healthy balance sheet
as we more than doubled our underlying profit, nearly doubled our
return on average capital employed, and significantly increased
operating cash flow.
It was a year in which we secured our biggest deal in 20 years, acquiring
BHP’s world-class unconventional oil and gas onshore US assets. We
also made progressive moves in mobility, such as the acquisition
of the UK’s leading electric vehicle charging network to create
BP Chargemaster.
BP is in good shape. Our strategy is delivering value for you,
our shareholders, while being flexible and agile for the energy
transition underway.
• We continued to focus on advantaged oil and gas in the Upstream,
delivering new supplies of gas from four of our six new major projects
brought online in 2018. We are also expanding our LNG portfolio and
developing new markets in transport and power.
• In the Downstream, we expanded our retail offer, as seen by more
than 25% growth in our convenience partnerships, to around 1,400
sites worldwide.
• As we pursue venturing and low carbon across multiple fronts,
Lightsource BP doubled its global solar presence to 10 countries.
• And we underpinned all this by continuing to modernize our plants,
processes, and portfolio by harnessing the potential of digital and new
technologies to provide greater efficiencies, reliability and safety.
8
Our strategy is delivering value for you,
our shareholders, while being flexible
and agile for the energy transition
underway.
Advancing the energy transition
The deals we made and the strategy we have in place are evidence that
BP is a forward-looking energy business. One that is already playing an
active role in advancing the energy transition.
That’s why we are making bold changes across our entire business to
reduce emissions in our operations, improve products to help customers
reduce their own emissions, and to create new low carbon businesses.
This is our ‘reduce, improve, create’ (RIC) framework which we are
backing up with clear targets. I am pleased to report we are making
good progress against these targets.
BP is also working with peers on a range of fronts, in particular to tackle
methane emissions and create opportunities for carbon capture,
utilization and storage. You’ll see this in our work with the Oil and Gas
Climate Initiative, which I chair, and whose members now represent
30% of global oil and gas production.
As well as action across the industry, at BP we understand that meeting
our own low carbon ambitions is a shared responsibility across our
entire business. That’s why we are now incentivizing around 36,000
employees who are eligible for an annual cash bonus to play a role by
linking their reward to one of our emissions reduction targets.
Possibilities everywhere
We will continue to be open and transparent about our ambitions, plans
and progress, recognizing that the trust of our shareholders and other
stakeholders is essential to BP remaining a reliable and attractive
long-term investment. And only by ensuring we remain a world-class
investment, can we most effectively play our part in advancing a low
carbon future.
As a global energy business with scale, expertise and strong
relationships around the world, we don’t just believe we have an
important part to play in the dual challenge, we see value-generating
opportunities for BP throughout the energy transition.
We’re making good progress delivering our strategy while flexing and
adapting to an environment that is changing fast. We have a great team
at BP and I would like to thank them all for their continued dedication and
relentless commitment to advancing the energy transition.
Bob Dudley
Group chief executive
29 March 2019
GAAP equivalents
Profit attributable to shareholders: $9.4bn (2017: $3.4bn)
Average capital employed: $165.5bn (2017: $159.4bn)
BP Annual Report and Form 20-F 2018 The changing energy mix
The BP Energy Outlook explores the forces shaping the
global energy transition out to 2040 and the key uncertainties
surrounding that transition. We use the scenarios in the
Outlook together with a range of other analysis and
information when forming our long-term strategy.
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The demand for energy is set to increase significantly – growing
economies need energy to support their industry and infrastructure.
In all the scenarios considered, world GDP more than doubles by 2040
driven by increasing prosperity in fast-growing developing economies.
That said, oil and gas could meet at least 50% of the world’s energy
needs in 2040 – even in a scenario consistent with the Paris goals, with
the share of gas growing aided by increasing use of carbon capture, use
and storage.
In the evolving transition scenario, this improvement in living standards
causes energy demand to increase by a third by 2040, driven mainly by
India, China and other developing Asian economies. The rate of growth
however is slower than in the previous 20 years, as the world increasingly
learns to produce more with less energy. Despite this, a substantial
proportion of the world’s population in 2040 could live in countries where
the average energy consumption per person is relatively low.
At the same time, the energy mix is changing as technology advances,
consumer preferences shift and policy measures evolve. Renewables
are now the fastest-growing energy source in the world today and in our
evolving transition scenario we estimate that they could account for
15% of all energy consumption in 2040 – and in other scenarios more.
Gas offers a cleaner alternative to coal for power generation and can
lower emissions at scale. It also provides a valuable partner for
renewables intermittency, delivers heating at the high temperatures
required by industry and is increasingly used in transportation. Across
our scenarios, gas grows robustly, overtaking coal as the second-largest
source of energy by 2030.
Oil demand grows for the next 10 years in our evolving transition scenario,
before gradually levelling out due to factors such as accelerating gains in
vehicle efficiency and greater use of biofuels, natural gas and electricity.
The largest source of oil demand growth is the non-combusted use of oil,
for example as a feedstock for petrochemicals.
Energy consumption – 2040 projections
%
4
3
%
3
2
%
8
2
%
4
%
7
%
4
Actual energy mix
2017
Evolving transition
2040
%
7
2
%
6
2
%
0
2
%
4
%
7
%
5
1
Rapid transition
2040
%
3
2
%
6
2
%
7
%
6
%
9
%
9
2
0
5
10
15
20
Billion tonnes of oil equivalent. The sum of the fuel shares may not equal 100% due to rounding.
Oil
Gas
Coal
Nuclear
Hydro
Renewables
1 Evolving transition
This scenario assumes that
government policies, technology
and social preferences continue to
evolve in a manner and speed seen
over the recent past.
2 Rapid transition
This scenario is consistent with the
Paris goals, and is broadly similar to
the reduction in carbon emissions in
the IEA’s Sustainable Development
Scenario.
1 Evolving transition
• World energy demand increases by one third
2 Rapid transition
• Oil demand in 2040 decreases by 14Mb/d.
from 2017 to 2040.
Biofuels grow by 4Mb/d.
• CO2 emissions from energy use increase
• CO2 emissions from energy use decline
by 7% by 2040.
by around 45% by 2040.
• Oil and gas account for more than half of
• Global energy consumption grows by
global energy in 2040.
around one fifth.
More information
BP Energy Outlook
See bp.com/energyoutlook for more information on
our projections of future energy trends and factors
that could affect them out to 2040.
BP Technology Outlook
See bp.com/technologyoutlook for information on
how technology could influence the way we meet
the energy challenge into the future.
9
BP Annual Report and Form 20-F 2018
Our strategy
Society is demanding solutions
for more energy, delivered in new
and better ways for a low carbon
future. Our strategy is designed
to meet this dual challenge.
Through new technologies, energy will be
produced more efficiently and in new ways,
helping to meet the expected rise in demand.
Our strategy allows us to be competitive at a
time when prices, policy, technology and
customer preferences are evolving rapidly.
We believe having a balanced portfolio with
advantaged oil and gas, a competitive
downstream and a range of low carbon
activities, with the flexibility of our strategy,
gives us optionality whatever path the
transition takes.
With the experience we have and the portfolio
we’ve created, we can embrace the energy
transition in a way that enhances our investor
proposition, while continuing to meet the need
for energy.
More information
Financial framework
How this underpins our commitment
to disciplined investment and growing
shareholder value. See page 13.
10
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BP Annual Report and Form 20-F 2018
Growing advantaged oil
and gas in the upstream
Invest in more oil and gas,
producing both with increasing
efficiency.
Key highlights
Transforming US onshore
Purchased unconventional assets from BHP,
giving us access to some of the best basins
in the onshore US.
See Upstream on page 24.
Collaborative partnerships
Signed a new production-sharing agreement
with SOCAR, Azerbaijan’s state oil and gas
company, to jointly explore and develop block
D230 in the Caspian Sea. And formed a
strategic alliance with Petrobras to explore joint
projects in upstream, downstream, trading and
low carbon in Brazil.
See Upstream analysis by region on page 279.
Project approvals
Sanctioned Ghazeer in Oman – the second
phase of development in the Khazzan gas
field; Alligin and Vorlich in the UK North Sea;
the Cassia Compression and Matapal gas
projects in Trinidad; KG D6 Satellites in India;
Zinia 2 in Angola; Manuel and Atlantis Phase 3
in the Gulf of Mexico; and Tortue in Mauritania
and Senegal.
See Upstream on page 22.
Major project start-ups
Started up six major projects, making a
significant contribution to the 900,000 barrels
per day of expected new production from major
project start-ups between 2016 and 2021.
See Upstream on page 22.
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 partnerships.
Pursue new opportunities
to meet evolving technology,
consumer and policy trends.
Simplify our processes and enhance
our productivity through digital
solutions.
Key highlights
Convenience partnerships
Harnessing battery power
Using wearable technologies
Opened more than 220 additional REWE to
Go® retail sites in Germany, taking the total
number of convenience partnership sites to
around 1,400 across our global retail network.
Made a series of investments in electric
vehicle technology and infrastructure to help
us respond to rising demand for battery
charging facilities, including the acquisition
of Chargemaster, operator of the UK’s largest
electric vehicle charging network.
Trialled new technologies, such as smart
glasses in the US and digital vests in Oman,
to help increase safety and efficiency at our
operations.
See Downstream on page 28.
See Innovation in BP on page 42.
See page 52.
Growing retail in new markets
Expanded our network to 440 BP-branded
retail sites in Mexico and opened our first
sites in Indonesia.
Advancing solar
Lightsource BP has doubled the number
of countries where it has a presence since
December 2017.
See Downstream on page 28.
See Climate change on page 45.
Sustainable aviation fuel
Entered into an innovative collaboration
between Air BP and Neste, a leading
renewable products producer, to secure and
promote the supply of sustainable aviation fuel.
Turning waste to fuel
Licensed technology, developed by BP and
Johnson Matthey, to Fulcrum BioEnergy® for
use at their planned US commercial-scale
waste-to-fuels plant.
Strong brands and partnerships
Strengthened our lubricants and fuels
partnership with Renault Sport Racing –
extending our BP Castrol sponsorship and
broadening the relationship to include joint
development of advanced mobility solutions
and new technologies.
See Downstream page 28.
See Climate change on page 45.
Cleaner power
Working with the Oil and Gas Climate Initiative
to progress the Clean Gas Project, which plans
to use natural gas to generate power, and then
capture and transport the CO2 by pipeline for
storage in a formation under the southern
North Sea.
See bp.com/sustainability for more information.
Cloud-based technologies
Deployed Plant Operations Advisor on our
four platforms in the US Gulf of Mexico. The
cloud-based tool helps reduce the time it
could take engineers to diagnose a problem
from hours to minutes.
See Innovation in BP on page 40.
Intelligent operations
Installed APEX technology across all our
upstream BP-operated assets to gather data
about every well and help identify efficiency
improvements.
See Innovation in BP on page 40.
Process automation
Reduced the time it takes to complete manual
tasks, such as contract management and
customer data processing, by using robotic
process automation. This is helping to optimize
our business processes, drive productivity and
improve customer satisfaction.
BP Annual Report and Form 20-F 2018
11
BP investor proposition
BP investor proposition
Safer
Fit for the
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
Our investor proposition is to grow sustainable free cash flow and
distributions to shareholders over the long term. We believe our strategy
enables this, through a focus on safe, reliable and efficient execution,
leveraging our distinctive portfolio, and disciplined investment to support
growing returns.
Safer
Safety is one of our core values and our number one priority. We are
focused on being systematic, disciplined and process driven.
A safe business doesn’t just protect people, it also helps improve
operating performance, leading to improved business and financial
performance. In recent years overall safety events have declined, and
we’ve increased upstream plant reliability and downstream refining
availability .
See Measuring our progress on page 16 and Safety on page 43.
Fit for the future
As an integrated business, we benefit from having upstream,
downstream, renewable energy businesses and an established trading
function. Our balanced portfolio spans resource types and geographies
with a strong and distinctive set of assets, brands and relationships.
In the Upstream we are growing ‘advantaged’ oil and gas – that
means low cost or high margin. This improves the likelihood that
the hydrocarbons we produce are resilient and competitive in terms
of demand in a low carbon world. We have strong incumbent positions
in many of the world’s top hydrocarbon basins and a robust pipeline
of growth opportunities – see page 27. We started up six major projects
in 2018.
The Downstream business has a strong and focused presence. We
have advantaged manufacturing facilities, considerable potential for
growth in our marketing businesses, and are expanding our retail
network in rapidly growing markets such as Mexico, Indonesia and
China. We also provide products – such as fuels with ACTIVE technology
– and offers that help consumers lower their emissions – see page 28.
Through our well-established supply and trading function we generate
value by providing the link between our businesses and third-party
customers. In November BP and partners in banking and trading
launched VAKT, the world’s first blockchain platform for managing
post-trade oil and commodities commercially.
And we’re increasing our activity in renewables, building on our existing
solar, wind and biofuels businesses, and creating new business models.
For example Lightsource BP has doubled the number of countries
where it has a presence since December 2017 – see page 47.
Embedded within our strategy is our commitment to advance a low
carbon future. We plan to deliver this across our entire business by
reducing emissions in our operations, improving our products and
services, and creating low carbon businesses.
See Our low carbon ambitions on page 46.
We are actively managing the portfolio to remain resilient in a
changing world and believe we have enough flexibility in our portfolio
to reshape our business and balance sheet in around 10 years should
we need to. This enables us to monitor changing trends and legislation,
and provides us with optionality to adjust our portfolio and adapt to
the future.
Focused on returns
We have a disciplined financial framework that is central to our strategy,
and clear growth plans out to 2021 and beyond.
Recent portfolio additions and new long-term agreements – for example
our purchase of BHP’s unconventional onshore assets in the US and
we signed with SOCAR in
the new production-sharing agreement
Azerbaijan – have strengthened our position.
We have held our capital frame of $15-17 billion a year for organic
expenditure for the past three years and expect to do so at least out to
2021. We believe we can continue to generate robust organic growth
within this framework and that the strength of our balance sheet will
allow us to deal with any near-term volatility.
We remain confident in our guidance on returns of greater than 10%
by 2021 at an oil price of $55/bbl (based on real 2017 Brent
oil prices).
See Group performance on page 19.
Distributions to shareholders
Our commitment to growing distributions to shareholders is underpinned
by our progressive dividend policy and share buyback programme.
In July 2018 we announced a 2.5% increase to our dividend, and over the year
distributed total dividends to shareholders of $8.1 billion. We have remained
active in our share buyback programme, buying back 50 million ordinary shares
in 2018 at a cost of $355 million including fees and stamp duty.
12
See Glossary
BP Annual Report and Form 20-F 2018
2.5%
dividend increase
in July
$8.1bn
total dividends distributed
to BP shareholders in 2018
Our financial framework
We maintain a disciplined financial framework, which underpins our investment choices and supports growth in sustainable free cash flow,
returns and distributions to shareholders. Our balance sheet and cash cover metrics are strong, and during 2018 this enabled us to acquire the
BHP Lower 48 assets, funded using available cash. Alongside the real momentum across our businesses, and in line with growing free cash
flow and the receipt of divestment proceeds, we continue to expect to deliver the 2021 targets laid out two years ago.
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Capital expenditure
Divestments
2018 outcome
Guidance 2019-2021
Organic capital expenditure was $15.1
billion*, at the bottom end of our guidance.
We expect organic capital expenditure to be
in the range of $15-17 billion per year.
Total divestment and other proceeds of
$3.5 billiona achieved. This was in line with
guidance of more than $3 billion for the year.
Gulf of Mexico oil spill
payments
2018 payments totalled $3.2 billion, in line
with our guidance of just over $3 billion.
Gearing
Gearing at the end of 2018 was 30.3%**.
Group return on average
capital employed (ROACE)
ROACE was 11.2%***, almost double that
in 2017.
Distributions
We increased the quarterly dividend by 2.5%
in July and repurchased 50 million ordinary
shares at a cost of $355 million in 2018.
We expect more than $10 billion of
divestments over the next two years. This
includes divestments announced as part of
the BHP transaction.
We expect payments of around $2 billion in
2019, stepping down to around $1 billion per
year for the next 14 years.
We expect gearing to be in the range of
20-30%.
We expect ROACE to be more than 10% by
2021 at $55/bbl (based on real 2017 Brent
oil prices).
Progressive dividend and a continued share
buyback programme, which is expected to
fully offset the impact of scrip dilution since
the third quarter of 2017 by the end of 2019.
Our published guidance will be updated for any impacts associated with the new lease accounting standard, IFRS 16 ‘Leases’, during 2019.
a This includes a $0.6 billion loan repayment to BP relating to the refinancing of Trans Adriatic Pipeline AG. Divestment proceeds for 2018 were $2.9 billion.
Balancing our sources and uses of cashb
Following the rebalancing of organic sources and uses of cash in 2017,
operating cash flow excluding the Gulf of Mexico oil spill payments
exceeded organic capital expenditure and dividends in 2018. After
adjusting for a working capital
build in the year, BP’s free cash flow
surplus was $6.5 billion equivalent to an organic cash break even oil
price of $50 per barrel on a full dividend basis. We continue to
expect the cash break even to reduce over time in line with growing
operating cash flow across the businesses and organic capital
expenditure in the range of $15-17 billion per year.
Organic sources and uses of cash b ($ billion)
For the year ended 31 December
2018
30
25
20
15
10
5
30
25
20
15
10
5
2017
Sources
Uses
Sources
Uses
Nearest equivalent GAAP measures
* Capital expenditure: $25.1 billion.
** Gross debt ratio: 39.3%.
*** Numerator: Profit attributable to BP shareholders $9.4 billion;
Denominator: Average capital employed $165.5 billion.
b This does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
c 2018 includes a $0.6 billion loan repayment to BP relating to the refinancing of Trans Adriatic
Pipeline AG. 2017 includes proceeds of $0.8 billion received relating to the initial public offering
of BP Midstream Partners LP’s common units, which are shown within financing activities in
the group cash flow statement.
Other sources and uses of cashb ($ billion)
For the year ended 31 December
2018
15
10
5
2017
15
10
5
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 proceedsc
Other uses
Operating cash flow – Gulf of Mexico
oil spill
Inorganic capital expenditure
BP Annual Report and Form 20-F 2018
BP Annual Report and Form 20-F 2018
See Glossary
13
Major project start-ups
Atoll Phase 1, Egypt
We developed and delivered first gas from
Atoll Phase 1 less than three years after its
discovery. It supports our commitment to
help realize Egypt’s oil and gas potential
and meet the increasing demand from its
growing population.
Operator
Pharaonic Petroleum
Company
Partners
BP (100%)
Project type
Conventional gas
110km
subsea tieback
6,400
metres
well depth,
more than Mount
Kilimanjaro
Cairo
Suez
<3 years
to deliver
Clair Ridge, UK North Sea
Clair Ridge is the second phase
development of the Clair field –
the largest in the UK continental shelf.
Operator
BP
Partners
BP (45.1%), Shell (28%),
Chevron (19.4%), Conoco
Phillips (7.5%),
Project type
Conventional oil
Thunder Horse Northwest
Expansion, US
16 months
from sanction to
first oil
We started up the Thunder Horse
Northwest Expansion project 16 months
after it was sanctioned. The project is on
our largest platform in the deepwater
Gulf of Mexico.
Operator
BP
Partners
BP (75%), ExxonMobil
(25%)
Project type
Deepwater oil
14
BP Annual Report and Form 20-F 2018 Western Flank B, Australia
Taas-Yuryakh expansion, Russia
Led by our partner Rosneft, the Taas-Yuryakh expansion project
in Eastern Siberia is an example of successful collaboration in
the remote Russian region of Sakha (Yakutia).
Operator
Taas
Partners
Rosneft (50.1%), Oil India, Indian Oil, Bharat
PetroResources (29.9%), BP (20%)
Project type
Conventional oil and gas
Located off the north-west coast of
Australia, the Western Flank B project
develops five fields via an eight subsea
well tieback to the Goodwyn A platform.
Operator
Partners
Woodside
BP, BHP, Chevron,
Shell, Woodside and
Japan Australia LNG
(16.67% each)
Project type
LNG
Photo credit: Woodside Energy Ltd.
Shah Deniz Stage 2, Azerbaijan
26
subsea wells
500km
of subsea flow lines
Shah Deniz Stage 2 was our biggest major project start-up in
2018. It includes complex offshore and onshore projects with
pipeline developments across the Southern Gas Corridor.
Operator
BP
Partners
BP (28.8%), SOCAR (16.7%), PETRONAS (15.5%),
Lukoil (10%), NICO (10%), TPAO (19%)
Project type
Conventional gas
Azerbaijan
2 new bridge-
linked platforms
constructed by 5,000+
workers and installed in
the Caspian Sea
Georgia
2 new
compressor
stations
each approximately the
size of 20 football pitches
Turkey
2,760 metres
the highest point of the
1,850km TANAP pipeline,
in eastern Turkey
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15
BP Annual Report and Form 20-F 2018
Measuring our progress
We assess our performance
across a wide range of
measures and indicators that
are consistent with our strategy
and investor proposition.
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.
Safer
Tier 1 process safety eventsa
REM
Reported recordable injury frequencya
REM
REM
REM
2018
2017
2016
2015
2014
16
18
16
20
10
20
28
30
40
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.
2018 performance We have seen a slight decrease in tier 1
process safety events. However there is always more we can
do and we remain focused on achieving better results today
and in the future.
2018
2017
2016
2015
2014
0.20
0.22
0.21
0.24
0.31
0.1
0.4
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.
0.2
0.3
2018 performance We have seen a decrease in our RIF
compared with 2017. Our goals stay the same – to have
no accidents, no harm to people and no damage to the
environment.
More information
Focused on returns
Strategy
Pages 10-13
Changes to KPIs
In 2018 we introduced a target to achieve
3.5 million tonnes of sustainable GHG
emissions reductions in our operations
worldwide by 2025. Progress towards this
target has now been incorporated into the
assessment of the group’s performance that
is a factor in determining annual bonuses for
eligible BP employees worldwide. This will
apply to our performance assessment in
2019 and beyond. We are also changing
downstream refining availability to BP-
operated downstream refining availability
to more closely align with our BP-operated
upstream plant reliability measure.
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.
REM Measures used for the remuneration policy
approved by shareholders at the 2017 AGM.
Underlying replacement cost profit
($ billion) REM
2018
2017
2016
2015
2014
(6.5)
9.4
3.4
6.2
0.1
2.6
5.9
3.8
0
REM
12.7
12.1
Operating cash flow ($ billion)
REM
REM
2018
2017
2016
2015
2014
26.1
22.9
24.1
10.7
18.9
17.6
20.3
19.1
32.8
32.8
Profit (loss) for the year
Underlying RC profit for the year (non-GAAP)
Underlying RC profit is a useful measure for investors
because it is one of the profitability measures BP management
uses to assess performance. It assists management
in understanding the underlying trends in operational
performance on a comparable year-on-year basis.
It reflects the replacement cost of inventories sold in the
period and is arrived at by excluding inventory holding gains
and losses from profit or loss. Adjustments are also made
for non-operating items and fair value accounting effects .
2018 performance The significant increase in both profit for
the year and underlying RC profit was largely due to higher
profits in Upstream, reflecting major project start-ups and
higher prices, partly offset by higher taxes.
Operating cash flow excluding Gulf of Mexico oil
spill payments (non-GAAP)b
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.
2018 performance Operating cash flow was higher due to
improved business results, including the benefit of higher
oil prices and lower Gulf of Mexico oil spill payments, which
amounted to $3.2 billion in 2018, partly offset by higher
working capital.
Return on average capital employed (%)
REM
Total shareholder return (%)
REM
REM
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.
2018
2017
2016
2015
2014
2.8
5.8
5.5
11.2
9.6
Return on average capital employed (non-GAAP) 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
321 for more information including the nearest equivalent
GAAP data.
2018 performance The increase reflects improved business
results, including the impact of higher prices and the benefit of
further upstream major project start-ups in the year.
REM These measures were used for executive
remuneration under the terms of our
discontinued 2014-16 policy.
More information
Directors’ remuneration
Page 87
Footnotes key
a This represents reported incidents occurring within BP’s
operational HSSE reporting boundary. That boundary
includes BP’s own operated facilities and certain other
locations or situations.
b These bars on the chart do not form part of BP’s
Annual Report on Form 20-F as filed with the SEC.
c Relates to BP employees.
16
See Glossary
2018
2017
2016
2015
2014
(4.6)
0.5
20.0
9.5
29.0
55.5
(12.8)
(8.3)
(16.5)
(11.6)
-20
0
0
20
40
60
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.
2018 performance Reduced TSR reflects a reduction in the
share price in 2018 compared with share price growth in 2017,
largely offset by higher dividend in 2018.
BP Annual Report and Form 20-F 2018 Fit for the future
Reserves replacement ratio (%)
Production (mboe/d)
Upstream unit production costs ($/boe)
REM
2018
2017
2016
2015
2014
REM
100
143
109
61
63
2018
2017
2016
2015
2014
3,268
3,239
3,141
3,683
3,595
2018
2017
2016
2015
2014
7.15
7.11
8.46
10.46
12.75
60
80
100
120
140
160
3,000
3,200
3,400
3,600
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.
2018 performance The ratio of 100.4% was in line with our
five-year average reserves replacement ratio, due to new
project investments and revisions in our existing projects.
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.
2018 performance BP’s total reported production, including
Upstream and Rosneft segments, was 2.4% higher than in
2017. This was due to major project ramp-ups and improved
plant reliability.
The upstream unit production cost indicator shows how
supply chain, headcount and scope optimization impact cost
efficiency.
2018 performance Higher unit production costs, compared
with 2017, were due to increased well-work activity and the
impact of higher prices on production entitlements.
Refining availability (%)
REM
Major project delivery
Upstream plant reliability (%)
REM
REM
2018
2017
2016
2015
2014
90
94.9
95.3
95.3
94.7
94.9
2018
2017
2016
2015
2014
6
6
6
7
7
2018
2017
2016
2015
2014
8
90
4
4
2
95.7
94.7
95.3
95.0
93.4
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.
2018 performance Refining availability remained strong,
underpinned by our global reliability improvement programmes.
The result was, however, lower than 2017 reflecting increased
maintenance, particularly at our Gelsenkirchen refinery.
We monitor the progress of our major projects to gauge
whether we are delivering our core pipeline of projects under
construction on time.
BP-operated upstream plant reliability is calculated as
100% less the ratio of total unplanned plant deferrals divided
by installed production capacity.
Projects take many years to complete, requiring differing
amounts of resource, so a smooth or increasing trend should
not be anticipated.
2018 performance The result was a record, reflecting our
focus on efficiency of execution, and use of advanced new
technologies and digital applications.
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.
2018 performance We started up six major projects in
Australia, Azerbaijan, Egypt, Russia, the UK and US.
Greenhouse gas emissions
(million tonnes of CO2 equivalent)
Diversity and inclusionc (%)
Employee engagement (%)
2018
2017
2016
2015
2014
46.5
49.4
50.1
49.0
48.7
20
40
60
We provide data on greenhouse gas (GHG) emissions material
to our business on a carbon dioxide-equivalent basis. This
comprises direct emissions of CO2 and methane. Our GHG
KPI comprises 100% emissions from subsidiaries and the
percentage of emissions equivalent to our share of joint
arrangements and associates , other than BP’s share
of Rosneft.
2018 performance The primary reasons for the overall
decrease include actions taken by our businesses to reduce
emissions in areas such as flaring, methane and energy
efficiency, and operational changes such as increased gas
being captured and exported to the liquefied natural gas facility
in Angola.
2018
2017
2016
2015
2014
24
24
24
21
22
23
19
18
21
21
5
10
15
20
25
30
Women
Non UK/US
Each year we report the percentage of women and individuals
from countries other than the UK and the US among BP’s
group leaders.
2018 performance While the percentage of our group leaders
who are non-UK/US remained the same, the percentage
of female group leaders rose. As a global business we are
committed to increasing the diversity of our workforce and
leadership.
2018
2017
2016
2015
2014
66
66
73
71
73
We conduct an annual employee survey to understand and
monitor levels of employee engagement and identify areas for
improvement.
2018 performance We changed our survey questions in 2017
to reflect the new priorities set out in our refreshed strategy.
The scores prior to 2017 are based on questions on priorities
set out in 2012, so the numbers are not directly comparable.
See Glossary
17
Strategic report – performanceBP Annual Report and Form 20-F 2018 Global energy markets
Average oil prices increased again in 2018, but remained
well below the prices seen in 2011-13. Co-ordinated OPEC
and non-OPEC production restraint early in the year and
robust global demand growth were countered by record
growth in US production.
The world economy grew at 3% in 2018, reflecting slower growth in
both advanced and emerging economies. This was slightly lower than
the 3.1% seen in 2017, but around the average of nearly 3% over the
past 20 years. Growth in advanced economies slightly decelerated to
2.2% from 2.4% in 2017, reflecting temporary factors, such as natural
disasters in Japan, slowing net exports in Europe and the ongoing trade
disputes. Emerging markets showed a similar broad-based deceleration,
growing by 4.2% in 2018, compared with 4.3% in 2017. The slowdown
in emerging markets activity reflects softening global trade and
tightening monetary conditions.
Oil
Crude oil prices ($/bbl – quarterly average)
Brent dated
150
120
90
60
09
10
11
12
13
14
15
16
17
2018
Prices
Dated Brent crude oil prices averaged $71.31 per barrel in 2018 – a
second consecutive annual increase but still well below the average
of over $110 seen in 2011-13. Prices drifted higher over the first half of
the year as production restraint remained in place among OPEC and
co-operating non-OPEC countries, then rose more rapidly to reach their
annual peak near $85 in October. In the face of rising prices, producers
relaxed their restraint at mid-year and prices fell sharply late in the year,
ending 2018 at their annual low point of about $50.
Consumptiona
Global consumption increased by 1.3 million barrels per day (mmb/d) to
99.2mmb/d for the year (1.3%) – a fourth consecutive increase greater
than the 10-year average – due to continued lower than average oil
prices and stronger world economic growth. Demand once again grew
most rapidly in Asia’s emerging economies (+0.8mmb/d), but OECD
demand also increased for a fourth consecutive year.
Productiona
Global oil production grew by a robust 2.6mmb/d (2.7%) to average
100.0mmb/d, with non-OPEC countries (+2.7mmb/d) accounting for all
of the increase. The US saw record production growth of 2.2mmb/d. In
contrast OPEC production declined by 0.1mmb/d – the second consecutive
annual decline – although it began to recover later in the year.
Inventoriesa
These changes resulted in global supply significantly exceeding
demand in 2018, especially later in the year. In the face of production
restraint from OPEC and co-operating non-OPEC countries early in the
year, commercial oil inventories in the OECD were below the five-
18
See Glossary
year average for much of the year. But with the reversal of production
restraint inventories began to rise, and by the end of December were
slightly above the five-year average, standing at 2,858 million barrels.
Natural gas
Natural gas prices ($/mmBtu – quarterly average)
Henry Hub
12
10
8
6
4
2
09
10
11
12
13
14
15
16
17
2018
Prices
Gas prices rebounded in all key markets in 2018. Asian and European
gas prices have increased to $9.76/mmBtu and 60.38 pence per therm
respectively, up from $7.13/mmBtu and 44.95 pence per therm in 2017.
This was driven by higher oil, coal, and CO2 prices (in Europe) as well
as a relatively tight liquefied natural gas (LNG) market. Asian prices
were strong at above $10/mmBtu during summer due to high Asian
LNG demand and a tight LNG market, but dropped below $9/mmBtu
in late 2018 due to warm weather in Asia and growing LNG supplies.
While LNG supply increased strongly, all of these incremental LNG
supplies were absorbed by Asia – with China accounting for around half
of that growth. US spot prices averaged $3.11/mmBtu – after being flat
at $3/mmBtu for most of the year, they rebounded during the last
quarter due to low storage levels.
Consumption
Global consumption is estimated to have increased more rapidly in
2018 than in 2017, driven by strong growth in the US and China. US
demand growth was largely driven by increasing gas use in the power
sector as power generation recovered and an estimated 14GW of coal
capacity was retired in 2018. Chinese gas demand continued to grow at
a double-digit rate on the back of coal-to-gas switching in the industrial
and buildings sectors.
Production
Total gas production increased substantially in 2018. Significant
production increases were achieved in the US and Australia – supported
by the start of new LNG trains – and Russia. Global LNG supply
capacity expanded slightly faster than in 2017, with around 28mtpa
of LNG capacity starting commercial operations. Several trains came
online in Australia, Russia, the US and Cameroon.
a From IEA Oil Market Report, 13
February 2019 ©, OECD/IEA 2019
More information
Prices and margins
Pages 25 and 30
BP Annual Report and Form 20-F 2018 S
t
r
a
t
e
g
c
i
r
e
p
o
r
t
–
p
e
r
f
o
r
m
a
n
c
e
Group performance
We saw significant growth in earnings, cash and returns. The
continued strong cash flow growth underpins the balance
sheet as we absorb the BHP acquisition and deliver more
than $10 billion of divestments over the next two years.
Dr Brian Gilvary
Group chief financial officer
$12.7bn
underlying replacement cost (RC)
profit
$26.1bn
operating cash flow
excluding Gulf of Mexico
oil spill payments a
(2017 $6.2 billion)
(2017 $24.1 billion)
$9.4bn
profit attributable to
BP shareholders
$22.9bn
operating cash flow
(2017 $3.4 billion)
(2017 $18.9 billion)
Financial and operating performance
Segment RC profit (loss) before interest and tax
($ billion)
2018
2017
2016
(15)
(10)
(5)
0
5
10
15
20
25
Downstream
Upstream
Rosneft
Other businesses and corporate (includes
costs related to the 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
RC profit (loss)
Net (favourable) adverse impact of non-operating items and fair value
$ million
except per share amounts
2016
(430)
2017
9,474
(2,294)
(3,712)
(79)
3,389
(853)
225
2,761
(1,865)
2,467
(57)
115
(1,597)
483
(999)
2018
19,378
(2,655)
(7,145)
(195)
9,383
801
(198)
9,986
accounting effects , before tax
3,380
3,730
6,746
Taxation charge (credit) on non-operating items and fair value
accounting effects
Underlying RC 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.
(643)
12,723
40.5
30.568
(325)
6,166
40.0
30.979
(3,162)
2,585
40.0
29.418
More information
Upstream
Page 22
Downstream
Page 28
Rosneft
Page 34
Other businesses
and corporate
Page 37
Oil and gas disclosures
for the group
Page 285
See Glossary
19
BP Annual Report and Form 20-F 2018
Results
Profit for the year ended 31 December 2018 was $9.4 billion, compared
with $3.4 billion in 2017. Including inventory holding losses, replacement
cost (RC) profit was $10.0 billion, compared with $2.8 billion in 2017.
After adjusting for a net charge for non-operating items of $2.8 billion
and net favourable fair value accounting effects of $68 million (both on
a post-tax basis), underlying RC profit for the year ended 31 December
2018 was $12.7 billion, an increase of $6.6 billion compared with 2017.
The increase was predominantly due to higher results in Upstream,
as well as Downstream and Rosneft segments, partly offset by
higher taxes. The upstream result reflected higher oil prices, record
plant reliability and the benefit of new major projects start-ups. The
downstream result reflected stronger refining margins and strong fuels
marketing growth. The Rosneft segment result primarily reflected
higher oil prices.
Profit for the year ended 31 December 2017 was $3.4 billion, compared
with $115 million in 2016. Excluding inventory holding gains, RC profit
was $2.8 billion, compared with a loss of $1.0 billion in 2016. After
adjusting for a net charge 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.
Non-operating items
The net charge for non-operating items was $2.8 billion post-tax in
2018, mainly related to additional charges for the Gulf of Mexico oil spill,
environmental and other provisions, and further restructuring costs.
The group restructuring programme originally announced in 2014 has
now been completed.
The net charge for non-operating items was $3.3 billion post-tax in
2017. This 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 reflected an impairment charge in
relation to upstream assets.
More information on non-operating items and fair value accounting
effects can be found on pages 276 and 320. 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 was $7,145 million in 2018
compared with $3,712 million in 2017. The increase mainly reflects the
higher level of profit in 2018. In 2017 the charge for corporate income
taxes included 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. A further credit of
$121 million following a clarification of the legislation has been included
in 2018. The effective tax rate (ETR) on the profit or loss for the year was
43% in 2018, 52% in 2017 and 107% in 2016. 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 reduction
in the UK North Sea supplementary charge in 2016, the adjusted ETR
on RC profit was 38% in 2018 (2017 38%, 2016 23%). The adjusted
ETR for 2017 was 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. In the current
environment the adjusted ETR in 2019 is expected to be around 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)
financing activities
Cash and cash equivalents at end
2018
2017
$ million
2016
26,091
22,873
24,098
18,931
17,583
10,691
(21,571)
(14,077)
(14,753)
(4,079)
(3,296)
1,977
of year
22,468
25,586
23,484
Capital expenditure
Organic capital expenditure
Inorganic capital expenditure
Gross debt
Net debt
Gross debt ratio (%)
Net debt ratio (%)
(15,140)
(9,948)
(25,088)
65,799
44,144
39.3%
30.3%
(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%
a This does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
Operating cash flow
Net cash provided by operating activities for the year ended
31 December 2018 was $22.9 billion, $4.0 billion higher than the
$18.9 billion reported in 2017. Operating cash flow in 2018 reflects
$3.5 billion of pre-tax cash outflows related to the Gulf of Mexico
oil spill (2017 $5.3 billion). Compared with 2017, operating cash flows in
2018 reflected improved business results, including a more favourable
price environment and higher production, partly offset by working capital
effects, and a $1.7 billion increase in income taxes paid.
adversely impacted cash flow in the
Movements in working capital
year by $4.8 billion. There was an adverse impact on working capital
from the Gulf of Mexico oil spill of $3.1 billion. Other working capital
effects, principally an increase in other current and non-current assets
partially offset by a decrease in inventory, had an adverse effect of
$1.7 billion. BP actively manages its working capital balances to
optimize and reduce volatility in cash flow.
There was an increase in net cash provided by operating activities of
$8.2 billion in 2017 compared with 2016, of which $1.7 billion related
to lower pre-tax cash outflows related to the Gulf of Mexico oil spill.
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.
20
See Glossary
BP Annual Report and Form 20-F 2018
Movements in working capital adversely impacted cash flow in 2017
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.
Net cash used in investing activities
Net cash used in investing activities for the year ended 31 December
2018 increased by $7.5 billion compared with 2017.
The increase mainly reflected higher inorganic capital expenditure
of $6.7 billion in relation to the BHP acquisition and a reduction of
$0.6 billion in net disposal proceeds.
The decrease of $0.7 billion in 2017 compared with 2016 mainly
reflected an increase of $0.8 billion in disposal proceeds.
Debt
Gross debt at the end of 2018 increased by $2.6 billion from the end of
2017. The gross debt ratio at the end of 2018 increased by 0.7%. Net
debt at the end of 2018 increased by $6.3 billion from the 2017 year-end
position. The net debt ratio at the end of 2018 increased by 2.9%. At
current oil prices, and in line with growing free cash flow supported by
divestment proceeds, we expect gearing to move towards the middle
of our targeted range of 20-30% in 2020. Net debt and the net debt ratio
are non-GAAP measures. See Financial statements – Note 27 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
2018 were $3.1 billion lower than 2017. For information on financing the
group’s activities, see Financial statements – Note 29 and Liquidity and
capital resources on page 277.
Group reserves and production (including Rosneft segment)a
2018
2017
2016
There were no significant cash flows in respect of acquisitions in 2017
and 2016.
Estimated net proved reserves
(net of royalties)
Total capital expenditure for 2018 was $25.1 billion (2017 $17.8 billion),
of which organic capital expenditure was $15.1 billion (2017 $16.5
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 $15-17 billion in 2019.
Divestment proceeds for 2018 were $2.9 billion (2017 $3.4 billion,
2016 $2.6 billion). In addition, we received a $0.6-billion loan repayment
relating to the refinancing of Trans Adriatic Pipeline AG, and total
divestment and other proceeds for 2018 amounted to $3.5 billion. In
2017 divestment proceeds included amounts received for the disposal
of our interest in the Shanghai SECCO Petrochemical Company Limited
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 group cash flow statement, and
total divestment and other proceeds for 2017 amounted to $4.3 billion.
BP intends to complete more than $10 billion of divestments over the
next two years, which includes plans announced following the BHP
transaction.
Net cash used in financing activities
Net cash used in financing activities for the year ended 31 December
2018 was $4.1 billion, compared with $3.3 billion used in financing
activities in 2017. This was mainly the result of an increase of $0.9 billion
in net proceeds from financing offset by a reduction of $1.1 billion
in cash received in relation to non-controlling interests and an increase
in dividend payments of $0.5 billion.
In 2017 the net cash used in financing activities reflected 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.
Total dividends distributed to shareholders in 2018 were 40.50 cents per
share, 0.50 cents higher than 2017. This amounted to a total distribution
to shareholders of $8.1 billion (2017 $7.9 billion, 2016 $7.5 billion), of
which shareholders elected to receive $1.4 billion (2017 $1.7 billion,
2016 $2.9 billion) in shares under the scrip dividend programme. The
total amount distributed in cash during the year amounted to $6.7 billion
(2017 $6.2 billion, 2016 $4.6 billion).
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
11,456
49,239
19,945
10,672
45,060
18,441
10,333
43,368
17,810
9,757
8,949
8,679
2,191
8,659
3,683
2,328
1,355
2,260
7,744
3,595
2,164
1,431
2,048
7,075
3,268
1,939
1,329
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 34 and Supplementary information
on oil and natural gas on page 210 for further information.
c Includes BP’s share of Rosneft. See Rosneft on page 34 and Oil and gas disclosures for the
group on page 285 for further information.
Total hydrocarbon proved reserves at 31 December 2018, on an
oil-equivalent basis including equity-accounted entities, increased
by 8% compared with 31 December 2017. The change includes a net
increase from acquisitions and disposals of 1,498mmboe (increase
of 993mmboe within our subsidiaries, increase of 505mmboe within
our equity-accounted entities). Acquisition activity in our subsidiaries
occurred in the US and the UK, and divestment activity in our
subsidiaries was in the US and the UK. In our equity-accounted
entities, acquisitions occurred in Russia.
Total hydrocarbon production for the group was 2% higher compared
with 2017. The increase comprised an 8% increase (1% decrease
for liquids and 17% increase for gas) for subsidiaries and a 5%
decrease (5% decrease for liquids and 5% decrease for gas) for
equity-accounted entities.
See Glossary
21
Strategic report – performanceBP Annual Report and Form 20-F 2018 Upstream
2018 has been a good year for Upstream, where we
increased confidence in 2021 delivery and underpinned
our ability to continue growth well into the next decade.
Bernard Looney
Chief executive, Upstream
63,000km 2 95.7% 7
new exploration access
BP-operated upstream
plant reliability
successful completion
of turnarounds
(2017 28,000km2)
(2017 94.7%)
9
6
final investment decisions
major project start-ups
(2017 6)
2.5
million barrels of oil equivalent
per day – hydrocarbon production
Upstream profitability ($ billion)
2018
2017
2016
2015
2014
-0.5
-0.9
0.6
1.2
14.3
14.6
5.2
5.9
8.9
15.2
(2017 3)
(2017 7)
(2017 2.5mmboe/d)
Replacement cost (RC) profit (loss) before interest and tax
Underlying RC profit (loss) before interest and tax
Business model
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
Wells and projects
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 competitive in
every basin, and as a business, get more
from a unit of capital than our peers.
22
See Glossary
Growing advantaged oil and gas
We will manage our portfolio through
disciplined investment in many of the world’s
great 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. Our gas portfolio will
be complemented by advantaged oil assets –
oil we can produce at a lower cost or higher
margin, creating a portfolio that is flexible for
different price environments.
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.
BP Annual Report and Form 20-F 2018 Underpinning our business model and strategy is our transformation
agenda. We have around 1,000 projects across the Upstream aimed
at sustainably improving both performance and how it feels to work
in the Upstream. We believe in the potential of this agenda to transform
the efficiency of our business, and we are delivering real value today
to the bottom line.
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 2018 our activities took place in 33 countries.
The US Lower 48 business continues to operate as a separate,
asset-focused, onshore business, and changed its name to BPX
Energy in October.
With the exception of BPX Energy, we deliver our exploration,
development and production activities through five global technical
and operating functions.
We optimize and integrate the delivery of our activities across
12 regions, with support provided by global functions in specialist
areas of expertise: technology, finance, procurement and supply
chain, human resources, information technology and legal.
In 2016 we identified a future growth target of 900,000 barrels of oil
equivalent per day of production from new major 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.
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 believe we are balanced and flexible – 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.
Financial performance
Sales and other operating
revenuesa
RC profit 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 d
Average oil marker pricese
Brent
West Texas Intermediate
Average natural gas
marker prices
Average Henry Hub gas pricef
Average UK National Balancing
2018
2017
56,399
14,328
45,440
5,221
$ million
2016
33,188
574
222
644
(1,116)
14,550
12,027
5,865
13,763
(542)
14,344
67.81
29.42
64.98
3.92
2.43
43.47
71.31
65.20
51.71
26.00
49.92
$ per barrel
39.99
17.31
38.27
$ per thousand cubic feet
2.84
1.90
$ per barrel of oil equivalent
28.24
3.19
2.36
35.38
54.19
50.79
$ per barrel
43.73
43.34
3.09
$ per million British thermal units
2.46
pence per therm
3.11
Point gas price e
60.38
44.95
34.63
a Includes sales to other segments.
b A reconciliation to GAAP information at the group level is provided on page 275.
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.
See Glossary
23
Strategic report – performanceBP Annual Report and Form 20-F 2018 Growing
advantaged oil
and gas in the
upstream
470,000
acres of access
Transforming
US onshore
BP is transforming its US
onshore oil and gas business
with our purchase of world-class
unconventional assets from BHP.
This acquisition gives us access
to some of the best basins in the
onshore US and positions BP as
a top producer in the region.
The transaction includes 470,000 acres
of licences across a new position in the
liquids-rich Permian-Delaware basin, and
two premium positions in the Eagle Ford and
Haynesville basins. Together these assets will
significantly increase the liquid hydrocarbon
proportion of our production and resources –
helping to upgrade and reposition BPX Energy,
which was previously known as the US Lower
48 business.
BPX Energy has operated as a separate
business since 2015. Its innovative approach
to using new technology such as big-data
analytics, augmented reality, drones and
advanced drilling techniques, have helped
the business achieve significant improvements
in operational and financial performance.
We plan to apply this approach to operations
at our newly acquired basins.
24
BP Annual Report and Form 20-F 2018
United States
Oklahoma
New Mexico
Texas
Permian
Haynesville
Houston
Eagle Ford
83,000
~3,400
~29,000
194,000
~720
~85,000
Louisiana
194,000
~1,400
~83,000
Size
(acres)
Number of
drilling sites
Current production
(boe/d)
Permian
• Delaware sub-basin of the Permian in
West Texas.
• 83,000 acres with around 3,400 drilling sites.
• Current production – around 29,000boe/d
(~70% liquids).
Eagle Ford
• Karnes Trough and Eagle Ford in South Texas.
• 194,000 acres with 1,400 gross
drilling locations.
• Current production – around 83,000boe/d
(~70% liquids).
Haynesville
• East Texas and Louisiana.
• 194,000 acres with 720 gross drilling locations.
• Current production – around 85,000boe/d,
all gas.
As at 31 December 2018.
Market prices
Brent remains an integral marker to the production portfolio, from
which a significant proportion of production is priced directly or
indirectly.
Brent ($/bbl)
150
120
90
60
30
2018
2017
2016
Five-year range
Jan
Feb Mar
Apr May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Dated Brent crude oil prices averaged $71.31 per barrel in 2018 – a
second consecutive annual increase but still well below the average
of more than $110 seen in 2011-13. Prices drifted higher over the first
half of the year, then rose more rapidly to reach an annual peak near
$85 in October, before falling sharply and ending the year at an annual
low point of about $50. Oil demand recorded a fourth consecutive
above-average increase, growing by 1.3mmb/d. Global production
increased by an even more robust 2.6mmb/d, with all of the increase
coming from non-OPEC countries (2.7mmb/d); the US recorded record
production growth of 2.2mmb/d. OPEC production fell slightly
(-0.1mmb/d) for a second consecutive year as the group engaged with
co-operating non-OPEC countries in production restraint early in the
year, although OPEC production began to recover in the second half
of the year as production restraint was eased.
Henry Hub ($/mmBtu)
9
6
3
2018
2017
2016
Five-year range
Jan
Feb Mar
Apr May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Henry Hub prices decreased to $3.09/mmBtu in 2018 from $3.11/
mmBtu in 2017. The UK National Balancing Point hub price was 60.38
pence per therm in 2018, 34% higher than in 2017 (44.95), on the back
of increasing coal, oil and CO2 prices. Asian spot prices rose to $9.76/
mmBtu in 2018, up from $7.13/mmBtu supported by higher coal, and oil
prices as well as a relatively tight LNG market – except in the later part of
2018, where ample LNG supplies combined with warm weather caused
Asian spot prices to drop to below $9/mmBtu.
For more information on global energy markets in 2018 see page 18.
Financial results
Sales and other operating revenues for 2018 increased compared with
2017, primarily reflecting higher liquids realizations, higher production
and higher gas marketing and trading revenues. The increase in 2017
compared with 2016 primarily reflected higher liquids realizations,
higher production and higher gas marketing and trading revenues.
Replacement cost profit before interest and tax for the segment
included a net non-operating charge of $183 million. This primarily
relates to impairment charges associated with a number of assets,
following changes in reserves estimates, the decision to dispose of
certain assets and the decision to relinquish a number of leases expiring
in the near future, partially offset by reversals of prior year impairment
charges. See Financial statements – Note 5 for further information.
Fair value accounting effects had an adverse impact of $39 million
relative to management’s view of performance.
The 2017 result included a net non-operating charge of $671 million,
primarily related to impairment charges associated with a number of
assets, following changes in reserves estimates, and the decision to
dispose of certain assets. Fair value accounting effects had a favourable
impact of $27 million relative to management’s view of performance.
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.
After adjusting for non-operating items and fair value accounting
effects, the underlying replacement cost result before interest and
tax was significantly higher in 2018 compared with 2017. This primarily
reflected higher liquids and gas realizations, higher production and
lower exploration write-offs.
Compared with 2016 the 2017 result 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.
Organic capital expenditure was $12.0 billion.
In total, disposal transactions generated $2.1 billion in proceeds in 2018,
with a corresponding reduction in net proved reserves of 229mmboe
within our subsidiaries. The major disposal transactions during 2018
were the disposal of our interests in the Bruce, Keith and Rhum fields in
the UK North Sea and our interest in the Greater Kuparuk Area in the US,
the consideration for which was a 16.5% interest in the Clair field in
North Sea. More information on disposals is provided in Upstream
analysis by region on page 279 and Financial statements – Note 4.
Outlook for 2019
• Five new major projects expected to start up in 2019.
• We expect underlying production to be higher than 2018 due to
major projects. 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 .
• Upstream capital investment is expected to increase, largely as a
result of our increased presence in the onshore US.
• We expect oil prices will continue to be volatile in the near term.
Exploration
The group explores for oil and natural gas under a wide range
of licensing, joint arrangement and other contractual agreements.
We may do this alone or, more frequently, with partners.
Our exploration and new access teams work to optimize our resource
base and provide us with a greater number of options.
In the current environment, we are spending less on exploration and
we will spend a material part of our exploration budget on lower-risk,
shorter-cycle-time opportunities around our incumbent positions.
See Glossary
25
Strategic report – performanceBP Annual Report and Form 20-F 2018
New access in 2018
We gained access to new acreage covering around 63,000km2 in
10 countries – Australia, Azerbaijan, Brazil, Canada, Egypt, Madagascar,
Mexico, São Tomé and Príncipe, the UK North Sea and the US Gulf
of Mexico.
Exploration success
We participated in three potentially commercial discoveries in 2018 –
Manuel and Nearly Headless Nick in the US Gulf of Mexico and Bongos
in Trinidad.
Exploration and appraisal costs
Excluding lease acquisitions, the costs for exploration and appraisal
were $1,298 million (2017 $1,655 million, 2016 $1,402 million).
These costs included exploration and appraisal activities, which were
capitalized within intangible fixed assets, and geological and geophysical
exploration costs, which were charged to income as incurred.
Approximately 5% of exploration and appraisal costs were directed
towards appraisal activity. We participated in 29 gross (19 net)
exploration and appraisal wells in eight countries.
Exploration expense
Total exploration expense of $1,445 million (2017 $2,080 million,
2016 $1,721 million) included the write-off of expenses related to
unsuccessful drilling activities, lease expiration or uncertainties around
development in the Gulf of Mexico ($450 million), Egypt ($236 million),
and others ($759 million), as well as geological and geophysical
exploration costs (see Financial statements – Note 8).
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 the segment’s equity-accounted entities at 31
December 2018, increased by 11% (an increase of 7% for subsidiaries
and an increase of 47% for equity-accounted entities) compared with
proved reserves at 31 December 2017.
Proved reserves replacement ratio
The proved reserves replacement ratio for the segment in 2018 was
69% for subsidiaries and equity-accounted entities (2017 127%), 66%
for subsidiaries alone (2017 133%) and 106% for equity-accounted
entities alone (2017 78%). For more information on proved reserves
replacement for the group see page 285.
Upstream proved reserves (mmboe)
Estimated net proved reservesa (net of royalties)
Liquids
Crude oilb
Subsidiaries
Equity-accounted entitiesc
Natural gas liquids
Subsidiaries
Equity-accounted entitiesc
Total liquids
Subsidiariesd
Equity-accounted entitiesc
Natural gas
Subsidiariese
Equity-accounted entitiesc
Total hydrocarbons
Subsidiaries
Equity-accounted entitiesc
2018
2017
2016
million barrels
4,378
794
5,172
576
15
590
4,954
808
5,762
30,355
4,559
34,914
10,188
1,594
11,782
4,129
674
4,803
318
18
336
4,447
692
5,139
3,778
771
4,549
373
16
389
4,151
787
4,938
billion cubic feet
28,888
2,580
31,468
29,263
2,274
31,537
million barrels of oil equivalent
9,131
1,232
9,492
1,085
10,577
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 2018
upstream operations in Argentina, Bolivia, Mexico, Russia and Norway as well as some of
our operations in Angola were conducted through equity-accounted entities.
d Includes 12 million barrels (14 million barrels at 31 December 2017 and 16 million barrels
at 31 December 2016) in respect of the 30% non-controlling interest in BP Trinidad &
Tobago LLC.
e Includes 1,573 billion cubic feet of natural gas (1,860 billion cubic feet at 31 December 2017
and 2,026 billion cubic feet at 31 December 2016) in respect of the 30% non-controlling
interest in BP Trinidad & Tobago LLC.
Developments
We achieved six major project start-ups in 2018 – in Azerbaijan,
Australia, the Gulf of Mexico, Egypt, Russia and the UK North Sea.
In addition to these, we made good progress on projects in Trinidad,
Egypt and the UK North Sea.
• Trinidad – Work on the Angelin project progressed well after we
started the drilling programme in late 2018, and we announced first
gas production in February 2019.
Liquids
1. Subsidiaries
2. Equity-accounted entities
Total
Gas
3. Subsidiaries
4. Equity-accounted entities
Total
4,954
808
5,762
5,234
786
6,020
4
• Egypt – Raven, the third phase of the West Nile Delta development
project is on target to achieve first gas in second half of 2019 with well
commissioning activities underway.
1
• UK North Sea – At Culzean, perforation of wells on the Total-operated
project is about to get underway after completion of trees installation.
Production is expected in the first half of 2019.
Subsidiaries’ development expenditure incurred, excluding midstream
activities, was $9.9 billion (2017 $10.7 billion, 2016 $11.1 billion).
3
2
26
See Glossary
BP Annual Report and Form 20-F 2018
Our project pipeline
*BP operated
Project
Gas
Oil
Type
Location
2018 start-ups
Shah Deniz Stage 2*
Western Flank B
Atoll Phase 1*
Clair Ridge*
Taas Expansion
Thunder Horse North West Expansion* US Gulf of Mexico
Azerbaijan
Australia
Egypt
UK North Sea
Russia
Expected start-ups 2019-2021
Projects currently under construction
Angelin*a
Cassia Compression*
Culzean
KG D6 R-Series
KG D6 Satellites
Khazzan Phase 2*
Tangguh Expansion*
West Nile Delta Giza and Fayoum*a
West Nile Delta Raven*
Alligin*
Atlantis Phase 3
Constellationa
Mad Dog Phase 2*
Manuel*
Vorlich*
Zinia 2
a Production commenced in early 2019.
Trinidad
Trinidad
UK North Sea
India
India
Oman
Indonesia
Egypt
Egypt
UK North Sea
US Gulf of Mexico
US Gulf of Mexico
US Gulf of Mexico
US Gulf of Mexico
UK North Sea
Angola
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.
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 assets. Our principal areas of production are Angola,
Argentina, Australia, Azerbaijan, Egypt, Oman, Trinidad, the UAE, the
UK and the US. With BP-operated plant reliability increasing from around
86% in 2011 to 96% in 2018, 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
2018
2017
2016
thousand barrels per day
1,051
121
1,172
88
8
96
1,139
129
1,268
6,900
474
7,374
1,064
199
1,263
85
8
93
1,149
207
1,356
943
179
1,122
82
4
86
1,025
184
1,208
million cubic feet per day
5,302
5,889
547
494
5,796
6,436
thousand barrels of oil equivalent per day
1,939
2,164
302
269
2,208
2,466
2,328
211
2,539
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 2018 was 3.0%
higher compared with 2017. The increase comprised a 7.6% increase
(0.9% decrease for liquids and 17.2% increase for gas) for subsidiaries
and a 30.0% decrease (37.6% for liquids and 13.4% for gas) for
equity-accounted entities compared with 2017. For more information
on production see Oil and gas disclosures for the group on page 285.
In aggregate, underlying production increased versus 2017.
The group and its equity-accounted entities have numerous long-term
sales commitments in their various business activities, all of which are
expected to be sourced from supplies available to the group that are not
subject to priorities, curtailments or other restrictions. No single contract
or group of related contracts is material to the group.
Gas and power 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.
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 29 and the range of contracts used is described in
Glossary – commodity trading contracts on page 315.
See Glossary
27
Strategic report – performanceBP Annual Report and Form 20-F 2018 Downstream
In 2018 we have continued to demonstrate, through the
execution of our strategy, that we have a competitively
advantaged business. Our strategy is fit for now and
fit for the future.
Tufan Erginbilgic
Chief executive, Downstream
10%
fuels marketing earnings
growth (17% on an
underlying RC profit basis)
1,400
convenience
partnership sites
46%
of lubricant sales
were premium grade
(2017 >10%)
(2017 1,100)
(2017 44%)
94.9% 1.7
11.9
refining availability
million barrels of oil
refined per day
million tonnes of
petrochemicals produced
(2017 95.3%)
(2017 1.7mmb/d)
(2017 15.3mmte)
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
Downstream profitability ($ billion)
2018
2017
2016
2015
2014
6.9
7.6
7.2
7.0
7.1
7.5
5.2
5.6
3.7
4.4
Replacement cost (RC) profit before interest and tax
Underlying RC profit before interest and tax
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 and a growing
presence in the advanced mobility and
low carbon sectors.
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 earnings growth and build competitively advantaged
businesses. It is fit for now and fit for the future. The execution of our strategy in 2018 has continued to deliver, with underlying replacement cost
profit growing to $7.6 billion in the year.
Safe and reliable operations
This remains our core value and first priority
and we continue to drive improvements 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.
28
See Glossary
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 delivering and developing new
products, offers and business models that
support the transition to a lower carbon and
digitally enabled future.
BP Annual Report and Form 20-F 2018
Market-led
growth in the
downstream
S
t
r
a
t
e
g
c
i
r
e
p
o
r
t
–
p
e
r
f
o
r
m
a
n
c
e
Convenience
partnerships
Throughout 2018 BP continued
to transform its global retail
business. We’ve refreshed our
forecourts, rolled out more BP
fuels with ACTIVE technology and
further enhanced our customer
offers. And that’s not all, we’re
also rapidly expanding our
convenience partnerships.
>25%
increase in convenience
partnership sites
We increased the number of convenience
partnership sites by over 25% in 2018 – taking
the total to around 1,400 sites across our
network. Much of this growth was in Germany,
where our strategic partnership with REWE
to Go® is expanding rapidly. Since opening
our first site in 2014, we now have over 460
in the country, and around half of those
opened in 2018. Our REWE to Go® sites
deliver substantially higher returns than
an industry average site, driven by our
differentiated customer offer including fresh,
quality food and drink.
We also continue to grow our convenience
partnership model in established markets
such as the UK with M&S Simply Food® and
in October we opened our first partnership
site in Luxembourg with MyAuchan®.
We have rolled out our
Ultimate fuel to forecourts
in China.
Global markets
Our footprint in Mexico is growing and we
now have 440 BP-operated sites, more than
300 of which were opened in 2018. We are
also continuing to progress our plans for
growth in China, and in Indonesia we opened
our first sites at the end of the year.
BP Annual Report and Form 20-F 2018
29
Financial performance
2018
2017
$ million
2016
Sale of crude oil through spot
and term contracts
62,484
47,702
31,569
Marketing, spot and term sales
of refined products
195,020
159,475
126,419
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
13,185
12,676
9,695
270,689
219,853
167,683
5,261
1,065
614
6,940
381
227
13
621
5,642
1,292
627
7,561
2,781
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
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 275.
Financial results
Sales and other operating revenues in 2018 were higher due to higher
crude and product prices. Sales and other operating revenues in 2017
were higher than 2016 due to higher crude and product prices as well
as higher sales volumes.
Replacement cost (RC) profit before interest and tax for 2018 included
a net non-operating charge of $716 million, primarily reflecting
restructuring costs. The 2017 result included a net non-operating gain
of $389 million, primarily reflecting the gain on disposal of our share in
the Shanghai SECCO Petrochemical Company Limited (SECCO) joint
venture in petrochemicals, while 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. In addition fair value accounting effects had a favourable
impact of $95 million, compared with an adverse impact of $135 million
in 2017 and $448 million in 2016.
After adjusting for non-operating items and fair value accounting effects,
underlying RC profit before interest and tax in 2018 was $7,561 million.
Outlook for 2019
We anticipate lower industry refining margins, narrower North American
heavy crude oil discounts and a lower level of turnaround activity than
in 2018.
30
See Glossary
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 strong
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 2017, reflecting continued growth in fuels
marketing and refining despite 2018 having one of the highest levels
of turnaround activity in our history. This was partially offset by a weaker
contribution from supply and trading. Compared with 2016, the 2017
result was higher, reflecting stronger refining performance and growth
in fuels marketing, partially offset by a weaker contribution from supply
and trading.
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
Crude marker
Alaska North
Slope
West Texas
Intermediate
US Midwest
Northwest Europe Brent
Mediterranean
Australia
BP RMM
Azeri Light
Brent
2018
2017
$ per barrel
2016
16.2
16.0
11.1
9.8
11.5
13.1
18.8
16.9
11.7
10.4
12.9
14.1
16.9
13.2
10.0
9.0
10.9
11.8
The global RMM averaged $13.1/bbl in 2018, $1/bbl lower than in 2017.
The RMM was lower mainly due to weaker gasoline margins as a result
of lower demand growth and higher inventory levels in the US.
BP refining marker margin ($/bbl)
32
24
16
8
2018
2017
2016
Five-year range
Jan
Feb Mar
Apr May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
BP Annual Report and Form 20-F 2018
Refining
At 31 December 2018 we owned or had a share in 11 refineriesa
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 284.
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 2018
operations remained strong, with refining availability of 94.9% (2017
95.3%) and refinery utilization rates at 91% (2017 90%). As a result
we achieved record levels of refining throughput on a current portfolio
basis despite high turnaround activity.
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. 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.
In 2018 we delivered continued improvement in our net cash margin
per barrel
and extended lower carbon bio-processing into more of our refineries.
, a measure of the competitiveness of our refinery portfolio,
The refining result was higher in 2018 compared with 2017, reflecting
increased commercial optimization and strong operations, which in
North America allowed us to capture the benefits from higher North
American heavy crude oil discounts, partially offset by lower industry
refining margins and a higher level of turnaround activity. Compared with
2016, refining performance continued to improve in 2017, capturing
higher industry refining margins and 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.
2018
2017
2016
Refinery throughputsab
US
Europe
Rest of world
Total
Refining availability
703
781
241
1,725
94.9
713
773
216
1,702
thousand barrels per day
646
803
236
1,685
%
95.3
95.3
a This does not include BP’s interest in Pan American Energy Group, which is reported through
the Upstream segment.
b Refinery throughputs reflect crude oil and other feedstock volumes.
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 advanced fuels and use of digital technology, as well as our
customer relationships. This differentiation enables our growth in
existing markets and supports our growth plans in new material markets
such as Mexico, India, Indonesia and China. During 2018 we continued
our expansion in Mexico with 440 BP-branded sites operational at the
end of the year. In the fourth quarter of 2018 we also opened our first
retail sites in Indonesia.
See Glossary
31
Strategic report – performanceBP Annual Report and Form 20-F 2018 We have a clear strategy and focused activity set for the transition to a
lower carbon and digitally enabled future. We are actively implementing
and developing new offers and business models centred around digital
and advanced mobility trends. In 2018 we acquired Chargemaster, the
operator of the UK’s largest electric vehicle charging network and
invested in StoreDot, a leading developer of ultra-fast charging battery
technology and FreeWire, a manufacturer of mobile rapid charging
systems for electric vehicles. Our ambition is to roll out more than 2,000
additional charging points in the UK, bringing the total to around 9,000
by 2021, including more than 400 new ultra-fast chargers at our retail
forecourts – see page 42. These investments and our differentiated
fuels and convenience offers support BP’s aim to become the leading
fuel provider for both conventional and electric vehicles.
Fuels marketing performance in 2018 was significantly higher compared
with 2017, reflecting the benefits from our strategic improvement
programmes, enabling improved margin capture and supply chain
optimization. Our convenience partnership model is now in around
1,400 sites across our network, with more than 460 sites in Germany
with our REWE to Go® offer. Compared with 2016, fuels marketing
performance in 2017 was higher, reflecting continued earnings growth
supported by higher premium fuel volumes, and the continued roll out of
our convenience partnership model..
thousand barrels per day
Aviation
Our Air BP business is one of the world’s largest suppliers of aviation
fuels and services, selling fuel to commercial airlines, the military
and general aviation customers at around 800 locations across more
than 50 countries. We have marketing sales of more than 430,000
barrels per day. Air BP’s services include the design, build and operation
of fuelling facilities, technical consultancy and training, supporting
customers to meet their lower carbon goals and digital fuelling solutions
to increase efficiency and reduce risk. Our Air BP business is
differentiated through its strong market positions, brand strength,
partnerships, technology and customer relationships. Our strategy is
to maintain a strong presence in our core geographies of Australia,
New Zealand, Europe, the Middle East and the US, while expanding
into major growth markets that offer long-term competitive advantages,
such as Asia, Africa and Latin America.
In 2018 we continued to develop new offers and solutions in response
to the needs of our customers. This included a collaboration with Neste,
a leading producer of renewable products, to advance the supply
of sustainable aviation fuels. We also launched the world’s first
commercially deployed airfield automation system that actively
helps prevent misfuelling. This digital platform for operators and airports
provides an integrated, real-time, global solution to strengthen safety
barriers and mitigate risks during the fuelling process.
Sales volumes
Marketing salesa
Trading/supply salesb
Total refined product sales
Crude oilc
Total
2018
2,736
3,194
5,930
2,624
8,554
2017
2,799
3,149
5,948
2,616
8,564
2016
2,825
2,775
5,600
2,169
7,769
Oil 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:
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. 2018 includes
102 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
2018
7,200
8,200
3,300
18,700
2017
7,200
8,100
3,000
18,300
2016
7,100
8,100
2,800
18,000
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.
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, it seeks 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 29 and the range of contracts used is described in
Glossary – commodity trading contracts on page 315.
32
BP Annual Report and Form 20-F 2018 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.
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 65% of profit generated from growth markets and 46% of our
sales from premium grade lubricants, we have a strong base for further
expansion and sustained profit growth.
In 2018 we significantly strengthened our relationship with Renault
through the continuation of our Renault Formula 1 sponsorship with
Renault Sport Racing, and are exploring new opportunities to work
globally with the Renault-Nissan-Mitsubishi Alliance. This includes
collaborating in a number of areas including fuel and lubricants supply
and the joint development of advanced mobility solutions and new
technologies.
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 2018 we extended the roll out of Castrol EDGE
BIO-SYNTHETIC into China, 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 lower than 2017. The 2018 results reflected continued
premium brand growth, more than offset by the adverse lag impact of
increasing base oil prices, as well as adverse foreign exchange rate
movements. The 2017 results reflected growth in premium brands
and growth markets, offset by the adverse lag impact of increasing
base oil prices.
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 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.
We continue to work on reducing our carbon footprint through the
application of our proprietary technologies, and are assessing further
opportunities to advance the circular economy in the chemicals and
plastics sector.
In 2018 the petrochemicals business delivered an underlying RC
profit before interest and tax that was higher compared with 2017 –
which in turn was higher than 2016. The 2018 result reflected an
improved margin environment, increased margin optimization and
continued cost management focus, partially offset by a higher level of
turnaround activity and the divestment of our 50% shareholding in the
SECCO joint venture, which completed in the fourth quarter of 2017.
Compared with 2016, the higher result in 2017 reflected an improved
margin environment, higher 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.
Our petrochemicals production of 11.9 million tonnes in 2018 was
lower than 2017 and 2016 (2017 15.3mmte, 2016 14.2mmte) due to
higher levels of turnaround activity and the divestment of our interest
in the SECCO joint venture in 2017.
Our technology remains a significant source of competitive advantage.
In 2018 we secured six new licensing agreements out of the 10 PTA
and PX licences announced globally.
In 2018 we also signed a heads of agreement with SOCAR to evaluate
the creation of a joint venture to build and operate a world-scale
petrochemicals complex in Turkey. This facility would be the largest
and most competitive integrated PTA, PX and aromatics complex
in the western hemisphere.
See Glossary
33
Strategic report – performanceBP Annual Report and Form 20-F 2018 Rosneft
Rosneft is the largest oil company in Russia, with
a strong portfolio of current and future opportunities.
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.
19.75%
BP’s shareholding in Rosneft
8,163
1.1
million barrels of oil equivalent
– BP share of Rosneft proved
reserves
million barrels of oil equivalent
per day – BP share of Rosneft
hydrocarbon production
(2017 7,864mmboe)
(2017 1.1mmboe/d)
18
refineries – owned
or hold a stake in
2.33
million barrels of oil
refined per day
>2,960
retail service stations,
in Russia and abroad
(2017 18)
(2017 2.29mmb/d)
(2017 >2,960)
BP share of Rosneft dividend
($ million)*
2018
2017
2016
2015
2014
420
200
124
190
332
271
693
Interim
Annual for previous year, less interim
*Net of withholding taxes.
New fuels
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 is the leading Russian refining company based on throughput.
It owns and operates 13 refineries in Russia, and also holds stakes in
three refineries in Germany, one in India and one in Belarus.
Downstream operations include jet fuel, bunkering, bitumen and
lubricants. Rosneft also owns and operates Rosneft-branded retail
service stations, as well as BP-branded sites operating under a licensing
agreement.
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.
2018 summary
• BP received $620 million, net of withholding taxes, (2017 $314 million,
2016 $332 million), representing its share of Rosneft’s dividends.
• Rosneft implemented a new dividend policy in 2017, 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.
• Rosneft and BP launched a new range of fuels featuring ACTIVE
technology at all BP retail service stations in Russia.
• BP remains committed to our strategic investment in Rosneft,
while complying with all relevant sanctions.
34
BP Annual Report and Form 20-F 2018 BP’s strategy in Russia
Our strategy is to work in co-operation with Rosneft to increase total
shareholder return. This comprises support for our shareholding and
partnering with Rosneft in building a material business in addition to
the shareholding. This strategy is implemented through our activities
in the following areas.
Rosneft Board of Directors
Collaboration
BP has a 19.75% shareholding and two directors on the 11-person
board. Bob Dudley and Guillermo Quintero are currently elected to
those roles.
BP collaborates on the provision of technical, HSE and
non-technical services on a contractual basis to improve
functional asset performance.
See Innovation in BP on page 41.
Joint ventures
BP partners with Rosneft to generate incremental value from
joint ventures and associates that are separate from BP’s core
19.75% shareholding.
• In December 2017 Rosneft and BP announced an
agreement to develop resources within the Kharampurskoe
and Festivalnoye licence areas in Yamalo-Nenets in
northern Russia. In the second quarter of 2018 BP acquired
a 49% stake in LLC Kharampurneftegaz and in December
2018 the licence transfer was completed. BP’s interest
is reported through the Upstream segment.
• BP holds a 20% interest in Taas-Yuryakh Neftegazodobycha
(Taas), together with Rosneft (50.1%) and a consortium
comprising Oil India Limited, Indian Oil Corporation Limited
and Bharat PetroResources Limited (29.9%). Taas
completed commissioning of the main project facilities for
the Srednebotuobinskoye oil and gas condensate field.
This was the second of six BP major projects started up
in 2018. The project was delivered under budget and on
schedule. In 2018 BP received the first dividends from
Taas of $48 million, net of withholding taxes. 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 has also carried out further appraisal
work on the Baikalovskoye field, an existing Rosneft
discovery in the Yenisei-Khatanga area of mutual interest.
In September Rosneft and BP also agreed to jointly explore
two additional oil and gas licence areas located in
Sakha (Yakutia) republic of the Russian Federation via
Yermak. Completion of the deal, subject to external
approvals, is expected in 2019. BP’s interest in Yermak
is reported through the Upstream segment.
Taas – one of BP’s
6 major project
start-ups in 2018
See Glossary
35
Strategic report – performanceBP Annual Report and Form 20-F 2018 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 17 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)
2018
2,288
(67)
2,221
95
2,316
$ million
2016
643
(53)
590
(23)
567
2017
923
(87)
836
–
836
$ per barrel
69.89 52.84 41.68
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)
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 $(5) million (2017 $(2) million, 2016 $3 million) of foreign exchange (gain)/losses
arising on the dividend received.
Crude oild
Natural gas liquids
Total liquidsf
2018
2017
$ million
2016
10,074 10,059
8,243
2018
2017
2016
919
4
923
1,285
1,144
900
4
904
1,308
1,129
836
4
840
1,279
1,060
5,539
154
5,693
5,330
5,402
65
131
5,533
5,395
14,325 13,522 11,900
7,447
7,864
8,163
Natural gas (billion cubic feet)g
Total hydrocarbons (mmboe)
c See Financial statements – Note 17 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 356 million barrels of liquids (338 million barrels at 31 December 2017 and 347
million barrels at 31 December 2016) in respect of the 6.32% non-controlling interest
(6.31% at 31 December 2017 and 6.58% at 31 December 2016) in Rosneft held assets
in Russia including 24 million barrels (6 million barrels at 31 December 2017 and 6 million
barrels at 31 December 2016) held through BP’s interests in Russia other than Rosneft.
g Includes 1,211 billion cubic feet of natural gas (306 billion cubic feet at 31 December 2017
and 300 billion cubic feet at 31 December 2016) in respect of the 8.60% non-controlling
interest (2.30% at 31 December 2017 and 2.53% at 31 December 2016) in Rosneft held
assets in Russia including 480 billion cubic feet (2 billion cubic feet at 31 December 2017
and 1 billion cubic feet at 31 December 2016) held through BP’s interests in Russia other
than Rosneft.
Market price
The price of Urals delivered in North West Europe (Rotterdam) averaged
$69.89/bbl in 2018. The discount to dated Brent was $1.42/bbl, similar
to 2017 ($1.35/bbl).
Financial results
Replacement cost (RC) profit before interest and tax for the segment
included a non-operating charge of $95 million for 2018 and a non-
operating gain of $23 million for 2016, whereas the 2017 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 2017 primarily reflected
higher oil prices and favourable foreign exchange, partially offset by
adverse duty lag effects.
Compared with 2016, the 2017 result was affected by higher oil prices
partially offset by adverse foreign exchange effects. The 2017 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. See also Financial statements – Notes
17 and 32 for other foreign exchange effects.
36
See Glossary
BP Annual Report and Form 20-F 2018
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.
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
a Includes sales to other segments.
b A reconciliation to GAAP information at the group level is provided on page 275.
The replacement cost (RC) loss before interest and tax for the year
ended 31 December 2018 was $3,521 million (2017 $4,445 million,
2016 $8,157 million). The 2018 result included a net charge for
non-operating items of $1,963 million, including Gulf of Mexico
oil spill related costs of $714 million (non-operating items in 2017
$2,847 million, 2016 $6,919 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 2018
was $1,558 million, similar to prior year (2017 $1,598 million, 2016
$1,238 million).
Outlook
Other businesses and corporate annual charges, excluding non-
operating items, are expected to be around $1.4 billion in 2019.
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 2018 BP had three time-chartered vessels to support
operations in Alaska and 34 BP-operated and 22 time-chartered
vessels for our international oil and gas shipping operations. In 2018
three new technically advanced LNG tankers were delivered into the
BP-operated fleet, with a further three to be delivered in 2019. All
vessels conducting BP shipping activities are required to meet BP
approved health, safety, security and environmental standards.
S
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p
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–
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2018
1,678
(714)
(2,807)
(3,521)
714
1,249
1,963
(1,558)
332
2017
1,469
(2,687)
(1,758)
(4,445)
2,687
160
2,847
(1,598)
339
$ million
2016
1,667
(6,640)
(1,517)
(8,157)
6,640
279
6,919
(1,238)
229
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 29.
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.
BP Annual Report and Form 20-F 2018
See Glossary
37
BP Annual Report and Form 20-F 2018
Alternative energy
2.8 million tonnes
of CO2 equivalent avoided in 2018.
BP has been in the renewable energy business for more than 20 years.
We remain one of the largest operators among our peers and we’re
expanding in areas where we see opportunities for growth.
Biofuels
We believe that biofuels offer one of the best large-scale solutions
to reduce emissions in the transportation system.
Renewables are the fastest-growing energy source in the world today
and we estimate that they could provide at least 15% of the global
energy mix by 2040.
As part of our approach to building our alternative energy business,
we aim to grow our existing businesses and to develop new businesses
and partnerships to deliver competitive value in the fastest-growing
energy sector.
Solar energy
Solar could generate 12% of total global power by 2040, in a scenario
based on recent trends. That could grow to 21% in a scenario consistent
with the Paris climate goals.
We have a 43% share in Lightsource BP and plan to invest $200 million
over a three-year period. Lightsource BP aims to play a vital role in
shaping the future of global energy delivery by developing substantial
solar capacity around the world, and we are working with Lightsource
BP to expand its global presence.
Lightsource BP has doubled the number of countries where it has
a presence since December 2017 – see Climate change on page 45.
We produce ethanol from sugar cane in Brazil, which has life-cycle
greenhouse gas emissions around 70% lower than conventional
transport fuels. In 2018 our three sites produced 765 million litres
of ethanol equivalent.
Brazil is one of the world’s largest markets for ethanol fuel. In order
to better connect our ethanol production with the country’s main fuels
markets, we established a joint venture in 2018 with Copersucar – one
of the world’s leading ethanol and sugar traders. This includes operating
a major ethanol storage terminal in Brazil’s main fuels distribution hub.
Our Tropical and Ituiutaba biofuels sites are certified to Bonsucro, an
independent standard for sustainable sugar cane production. We are
working towards certification for Itumbiara in 2019.
Our strategy is enabled by:
• Safe and reliable operations – continuing to drive improvements
in safety performance.
• Driving quality and improved efficiency in our feedstock –
concentrating our efforts in Brazil, which has one of the most
cost-competitive biofuel sources in the world.
• Domestic and international markets – selling ethanol and sugar
domestically in Brazil and to international markets such as the US.
Renewable products
Butamax®, our 50/50 joint venture with DuPont, has developed
technology that converts sugars from corn into bio-isobutanol,
an energy-rich bio product. Bio-isobutanol has a wide variety of
applications. For example, it can be used in the production of paints,
coatings and lubricant components. It can also be blended with gasoline
at higher concentrations than ethanol, which can be transported through
existing fuel pipelines and infrastructure. Butamax® has upgraded its
ethanol facility in Kansas to produce bio-isobutanol.
38
See Glossary
BP Annual Report and Form 20-F 2018 Biopower
We create biopower from bagasse, the fibre that remains after
crushing sugar cane stalks. In 2018 our three biofuels manufacturing
facilities produced around 892GWh of electricity – enough renewable
energy to power all of these sites, with the remaining 70% exported
to the local electricity grid.
This is a low carbon power source, with part of the CO2 emitted from
burning bagasse offset by the CO2 absorbed by sugar cane during
its growth.
Wind energy
BP has significant interests in onshore wind energy in the US. We
operate 10 sites in seven states and hold an interest in another facility
in Hawaii. Together they have a net generating capacity of just
over 1,000MW.
At our Titan 1 wind energy site in South Dakota, we’ve partnered
with Tesla to test how effectively wind energy can be stored – see
Harnessing battery power on page 42.
In 2018 we divested three wind energy operations in Texas, as part
of a broader restructuring programme designed to optimize our US
wind portfolio for long-term growth.
More information
Low carbon ambitions
We have set targets and aims to reduce emissions in our operations, improve
our products to help customers reduce their emissions and create low carbon
businesses – see pages 46-48.
45,000km
travelled a day
Using technology in biofuels
Our SmartLog programme is helping improve
performance across our three biofuels sites
in Brazil. SmartLog is designed to increase
efficiency across sugar cane cutting, loading
and transportation operations – and
consequently reduces the costs involved.
Every day across our sites we make around
800 trips covering 45,000 kilometres.
This takes place in remote locations with
poor network and communications coverage.
Using a combination of mobile satellite
technology, sensors and radios we can
connect our people and their vehicles to a
central control room. Here we receive 24-hour
real-time information about what’s happening
in the field to help manage activities remotely,
as well as monitoring and analysing
behaviours and giving advice or intervening
about safety or efficiency.
Automation guides workers on improvements
such as how to prioritize harvest activities and
indicates the optimum speed for harvesters
to run at based on prevailing conditions.
Since introducing SmartLog in 2018, we’ve
reduced equipment needed by 20% and our
remote monitoring is helping to reinforce our
safety culture in the field. It has also helped
to lower emissions as the reduction in
equipment means we use less diesel.
See Glossary
39
Strategic report – performanceBP Annual Report and Form 20-F 2018 Innovation in BP
Across the business we face the dual
challenge of meeting society’s need for
more energy, while at the same time working
to reduce carbon emissions. Our industry is
changing rapidly, and the energy mix is
shifting towards lower carbon sources,
driven by technological advances and
growing environmental concerns.
Technology is ever-present in all that we
do – from safely discovering and recovering
oil and gas, to renewable energy and lower
carbon fuels and products. And digital, big
data and advanced technologies, as well
as an innovative mindset, are driving rapid
development of new ways to tackle emissions
and improve efficiency at BP.
We also invest in high-tech companies
to help accelerate and commercialize new
technologies, products and business models.
8 major
technology
centres
in the US, UK,
Asia and Germany
BPme available in
>6,000 retail sites
A new way to pay
Customers in six countries now have the
option to pay for fuel from their vehicle using
BPme. And since its launch our smartphone
app has been downloaded more than one
million times.
Using a phone’s GPS signal BPme locates the
nearest BP site and provides details of opening
times and facilities. Customers can use the app
to activate their fuel pump and pay from inside
their car.
BPme is designed to appeal to people who
don’t want to leave children, pets or valuables
alone while they go to pay for fuel, and it saves
time queuing at the checkout. Over the coming
months we plan to roll it out to new markets
and introduce the option to order coffee and
receive offers and discounts from the app.
Group highlights
$429 million
invested in research and development
~$200 million
used to develop options for new lower
carbon businesses
Collaborations
with innovative academic programmes
>4,000
24 hours to 20 minutes
with APEX
granted and pending patent applications
held by BP and its subsidiaries throughout
the world
150 million+
data points a day with POA
bp.com/technology
40
BP Annual Report and Form 20-F 2018
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A clearer view below
the earth
Below land and sea, in challenging terrains
and conditions, BP’s developments in seismic
technology are allowing us to see deeper
into the earth with better accuracy than ever
before. And the better we can see, the easier
and safer it is to find oil and gas and unlock
more of it from our existing assets.
One of the big challenges for conventional
seismic sources when surveying offshore in
the Gulf of Mexico is the ability to look deep
into the earth without the thick horizontal salt
layers above distorting the images captured.
To help tackle this we designed and built
Wolfspar. The ultra-low-frequency system
works with our other advanced recording
technologies to help overcome the subsalt
imaging challenge. We believe the clearer
view will help reduce uncertainty about where
the resources are, resulting in more drillable
targets in the region. Having completed a
series of successful proof-of-concept tests,
BP plans to move to industrialize the
technology with our strategic seismic partners,
so that it can be used across our global
subsurface portfolio.
We also reached a major milestone in the
development of an innovative land seismic
recording system, in partnership with Rosneft
01010101
10
Wolfspar
~1,000km
of data acquired in 143 hours
and Schlumberger. The project aims to move
beyond the existing limitations of bulky, heavy
and expensive onshore seismic equipment,
and at the same time provide better images of
the reservoir. Following successful initial field
trials in Norway and Abu Dhabi in 2017, the
‘nimble node‘ system was used to safely
acquire 3D seismic data in the challenging
climate of West Siberia in 2018. Early images
show better data quality compared to
conventional equipment, with fewer people
and vehicles needed as well as a simplified
derigging process – which is otherwise very
time consuming and challenging.
The new node is the lightest, smallest and
lowest-cost system in the world, and the
project is on course to help change how
future seismic is acquired. Its development
will be completed with a large-scale field trial
in early 2019. Soon after this we plan to begin
the first commercial survey.
Intelligent operations
New technologies are helping us build
intelligent operations throughout our business.
Across all our upstream-operated assets, we
are creating ‘virtual copies’ of our production
systems using APEX – our highly sophisticated
simulation, surveillance and optimization
toolkit. The technology recreates every
element of a well network in digital ‘twin’
form, and works in near real time to gather
data about every well across our business.
It can pinpoint where efficiency can be
improved and helps our production engineers
run simulations in seconds. With APEX, a
full-field optimization that used to take hours
now takes a few minutes. Engineers from
around the world are proactively sharing their
know-how and expertise across our global
operations, as they embed the use of APEX
and start benefiting from it.
And following our successful pilot in the
Atlantis field, we are now using Plant
Operations Advisor (POA), which was
developed in partnership with BHGE, on
all four BP-operated platforms in the US
Gulf of Mexico.
The cloud-based tool gives performance
information on around 1,200 important
pieces of process equipment – with more
than 150 million data points analysed every
day. If the system identifies an issue with
any of the equipment, it sends an alert to
our engineers so they can respond quickly.
By pinpointing anomalies in operations
and identifying the causes, problems that
might once have taken hours for engineers
to work through manually can be diagnosed
in minutes. Following its success in the Gulf
of Mexico, we now plan to use the tool at
more than 30 upstream locations worldwide
by the end of 2019.
Robot inspections
Inspection robots are helping us deliver against
our strategic priority of modernizing and
transforming BP. At our Cherry Point refinery
in the US we’ve adapted a robotic solution
that allows us to inspect equipment such
as the hydrocracker reactor. The robot uses
ultrasound technology to spot microscopic
cracks in its walls by crawling along the reactor.
This process would have previously taken
more than 23 work hours, with engineers
working inside the hydrocracker unit during a
planned shutdown. Now they can gather the
same information in just one hour with robots.
23 hours to
1 hour
BP Annual Report and Form 20-F 2018
41
01010101010101010101 10101010101 01010101010101010101 01010101010101010101 01010101010101101 01010101010101010101 0101010101 0101010101
Venturing and
low carbon across
multiple fronts
Harnessing
battery
power
>6,500
UK charging points
with BP Chargemaster in 2018
12 million
electric vehicles
projected on UK roads by 2040
in the BP Energy Outlook .
As we support the transition to
a lower carbon future and to help
meet our customers’ changing
needs, we’re making investments
in electric vehicle technology and
infrastructure. Our work aims to
support electric vehicle adoption
by tackling issues such as poor
battery life and slow charging
times.
To allow us to respond rapidly to demand
for charging facilities at our forecourts, we
invested $5 million in FreeWire. The US-based
company manufactures mobile rapid charging
systems, which we successfully piloted at a
BP retail site in the UK, and are now exploring
options to offer FreeWire’s innovative charging
services across the retail networks.
We also invested $20 million in StoreDot,
a company that develops ultra-fast charging
battery technology for mobile and industrial
markets. We anticipate the technology will
be used in mobile devices by 2020 and BP
will be working with them to help transfer this
technology to electric vehicles. StoreDot aims
to bring recharging times down to five minutes,
making the time it takes to charge an electric
vehicle similar to that of filling a tank.
BP now has more than 6,500 charging points
in the UK, through BP Chargemaster. The
business combines the complementary
expertise, experience and assets of BP and
Chargemaster and is an important step
towards offering widened access to fast and
ultra-fast charging at BP sites across the UK.
The chargers will start to become available
across our UK forecourts throughout 2019.
Storing wind energy
We’ve partnered with Tesla to test
how effectively wind energy can be
stored at our Titan 1 wind energy site
in South Dakota. The electricity captured
is then available for the site to use
whenever we need it – even when
the wind isn’t blowing.
The pilot will help develop valuable
insights for energy storage applications
across our diverse portfolio.
StoreDot – aim to reduce
electric vehicle
recharging time
to five minutes.
42
BP Annual Report and Form 20-F 2018
BP Annual Report and Form 20-F 2018
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.
BP Sustainability
Report 2018
publishes April
S
t
r
a
t
e
g
c
i
r
e
p
o
r
t
–
p
e
r
f
o
r
m
a
n
c
e
Our 2018 sustainability focus areas
These sustainability issues are the ones that could impact
our business the most and that are of greatest interest to
our stakeholders.
> Safety and security
> Climate change
> Managing our impacts
> Value to society
> Ethical conduct
> Our people
Process safety events
(number of incidents)
150
100
50
2014
2015
2016
2017
2018
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
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
2018
0.20
0.15
0.23
American Petroleum Institute US benchmarka
International Association of Oil & Gas Producers benchmarka
a API and IOGP 2018 data reports are not available until May 2019.
Safety and security
Safety is our number one priority and a core value. Our aim is to have
no accidents, no harm to people and no damage to the environment.
We are working to continuously embed and improve personal and
process safety and operational risk management across BP and to
strengthen our safety management.
Our approach builds on our experience, including learning from
incidents, operations audits, annual risk reviews and sharing lessons
learned with our industry peers.
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. 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.
Our operating management system
Our operating management system (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.
Our OMS also helps us improve the quality of our activities by setting
a common framework that our operations must work to. We review
and amend these requirements from time to time to reflect our
priorities. Any variations in the application of OMS, in order to meet
local regulations or circumstances, are subject to a governance process.
Recently acquired operations need to transition to our OMS. See page
44 for information about contractors and joint arrangements .
Preventing incidents
We carefully plan our operations, with the aim of identifying potential
hazards and having rigorous operating and maintenance practices
applied by capable people to manage risks at every stage. We design
our new facilities in line with process safety – the application of good
design and engineering principles.
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.
BP Annual Report and Form 20-F 2018
See Glossary
43
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)
2018
16
56
124
63
57
538
131
2017
18
61
139
81
58
886
265
2016
16
84
149
91
58
677
311
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 2018 we saw a reduction in the number of tier 1 and tier 2 process
safety events. We investigate incidents including near misses. And we
use leading indicators, such as inspections and equipment tests, to
monitor the strength of controls to prevent incidents. We also use
techniques that help teams to analyse and redesign tasks to reduce
the chance of mistakes occurring.
Keeping people safe
All our employees and contractors have the responsibility and the
authority to stop unsafe work. Our safety rules guide our workers on
staying safe while performing tasks with the potential to cause most
harm. The rules are aligned with our OMS and focus on areas such as
working at heights, lifting operations and driving safety.
We monitor and report on key workforce personal safety metrics in line
with industry standards. We include both employees and contractors in
our data.
Tragically we suffered one fatality in 2018. In our lubricants business a
heavy goods driver working for one of our contractors in the US was
struck by a passing vehicle while checking a tyre. We are deeply
saddened by this loss and are working closely with our contractors to
continue to improve safety and to seek to prevent injuries in our work
together.
Recordable injury frequencyd
Day away from work case
frequencye
Severe vehicle accident rate
2018
0.20
0.048
0.04
2017
0.22
0.055
0.03
2016
0.21
0.051
0.05
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.
We saw an overall decrease in our recordable injury frequency and day
away from work case frequency. Our goals stay the same – to have no
accidents, no harm to people and no damage to the environment. There
is always more we can do and we remain focused on achieving better
results today and in the future.
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 Brazilian biofuels business is spread
across geographically remote locations, so we introduced a digital
platform to connect our people and vehicles to a central control room.
This provides 24-hour, real-time information about what’s happening,
helps us monitor and analyse behaviour and aids improvements around
learning and safety. We also use in-vehicle monitoring systems and
cameras to improve transportation safety.
Emergency preparedness
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.
44
See Glossary
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
impact on our business in 2018.
We have 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.
To encourage vigilance among our employees, our cyber security
training programme covers topics such as email phishing and the correct
classification and handling of our information. We collaborate closely
with governments, law enforcement and industry peers to understand
and respond to new and emerging threats.
Security and response
We monitor for hostile actions that could harm our people or disrupt
our operations, focusing on areas affected by political and social unrest,
terrorism, armed conflict or criminal activity. We take steps to help
people stay safe when they are travelling on business. Our 24-hour
response information centre monitors global events and related
developments which means we can assess the safety of our people
and provide timely advice if there is an emergency.
We run exercises and drills to test our procedures to help ensure our
people are prepared in the event of an emergency. We conducted a
two-day oil spill response drill in the UK North Sea involving more than
200 people, including regulators. This was designed to test plans as part
of our annual crisis and continuity management programme. We also
held a number of large-scale exercises in the US.
Working with contractors and partners
More than half of the hours worked by BP are carried out by contractors.
Through bridging and other documents, we define the way our safety
management system co-exists with those of our contractors to manage
risk on a site. 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. Our standard model contracts include health, safety and
security requirements. We expect and encourage our contractors and
their employees to act in a way that is consistent with our code of
conduct and 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. We monitor performance and how
risk is managed in our joint arrangements, whether we are the operator
or not.
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. Where
appropriate, we may seek to influence how risk is managed in
arrangements where we are not the operator.
BP Annual Report and Form 20-F 2018
Climate change
The world needs more energy but with fewer carbon
emissions. BP is playing an active role in meeting
this dual challenge.
The Taskforce for Climate-related Financial Disclosures (TCFD) was
established by the Financial Stability Board with the aim of improving the
reporting of climate-related risks and opportunities. We support this aim.
Our reporting provides information supporting the principles of the
TCFD recommended disclosures.
See bp.com/tcfd.
Strategy
Our strategy is designed to grow shareholder value while also helping
to meet the dual challenge. We believe it is consistent with the climate
goals of the Paris Agreement, which calls for the world to rapidly reduce
greenhouse gas emissions in the context of sustainable development
and eradicating poverty.
A key element of our strategy is our ‘reduce, improve, create’
framework, where we have set measurable, near-term targets for
reducing greenhouse gas emissions in our own operations and
ambitions for improving products to help our customers and
consumers lower their emissions, and creating low carbon
businesses. See page 46.
In 2019 we are supporting a resolution from a group of institutional
investors to describe in our corporate reporting how our strategy is
Climate governance
BP’s governance framework applies equally to the management
of the various aspects of climate change and the transition to a
lower carbon economy. In addition to the oversight provided by the
executive team, the board and relevant committees, various groups
consistent with the Paris goals. Subject to shareholder approval at our
annual general meeting, we will provide more information on this in
future reports.
Risk management
We recognize the significance of the energy transition and the risks and
opportunities it presents. As part of their review of BP’s strategy, the
board and executive team considered risks and opportunities associated
with climate change and the energy transition, in the context of different
paths expressed in the BP Energy Outlook – which looks at long-term
trends and develops projections for world energy markets over the next
two decades.
Under BP’s risk management policy and the associated risk
management procedures, our operating businesses are responsible for
identifying and managing their risks. Risks which may be identified
include potential effects on operations at the asset level, performance at
the business level and developments at the regional level from extreme
weather or the transition to a lower carbon economy.
As part of our annual planning process we review the group’s principal
risks and uncertainties. Climate change and the transition to a lower
carbon economy has been identified as a principal risk (see page 55).
This covers various aspects of how risks associated with the energy
transition could manifest such as in the policy, legal and regulatory
environment, technological developments and market changes.
Similarly, physical climate-related risks such as extreme weather
are covered in our principal risks related to safety and operations.
See page 53 for more information on how we manage risk.
and committees in BP bring together cross-segment and
cross-functional expertise of relevance to this area, including
those set out below.
BP governance framework
See page 69
Renewal committee
Reviews strategic, commercial and investment decisions outside of core activity and related to new lines of business.
Chaired by our deputy chief executive.
New energy frontiers steering committee
Oversees strategy and development of growth opportunities in low carbon business models that can be scaled up to create
new businesses for BP. Chaired by our deputy chief executive.
Carbon steering group
Focuses on strategy, policy, performance oversight and collaboration relating to carbon management
activities across the group. Chaired by our vice president of carbon management.
Upstream carbon
steering committee
Focuses on the delivery of lower carbon plans in the Upstream.
Chaired by our chief operating officer of production, transformation
and carbon, Upstream.
Downstream advancing the
energy transition committee
Develops and drives the implementation of advancing the energy
transition in the Downstream. Chaired by our head of technology,
Downstream and BP chief scientist.
Key:
Executive-level committee
Cross-functional committee
Business and segment committee
45
Strategic report – performanceBP Annual Report and Form 20-F 2018
Our low carbon ambitions
We aim to advance a low carbon future through what
we call our ‘reduce, improve, create’ framework.
We have set targets and aims to reduce emissions in our operations,
improve our products to help customers reduce their emissions and
create low carbon businesses. We are already in action and have made
good progress in 2018 against these ambitions.
See bp.com/sustainability for more information on the actions we are
taking and bp.com/targets for specifics on our goals.
Reducing
emissions in our operations
Improving
our products
We are targeting zero net growth in our operational emissions out
to 2025. We aim to deliver this through sustainable greenhouse gas
(GHG) emissions reductions totalling 3.5Mte by 2025, by targeting
a methane intensity of 0.2% and, as necessary, with offsets to keep
net emissions growth to zero.
We are continuing to innovate with fuels, lubricants and chemicals that
can help our customers and consumers lower their emissions.
2018 progress
2018 progress
• Zero net growth in operational emissions.
• 2.5Mte of sustainable GHG emissions reductions
since the beginning of 2016. This includes actions
to improve energy efficiency and reduce methane
emissions and flaring.
• Methane intensity of 0.2%.
• Collaborated with Neste to explore opportunities
to increase supply of sustainable aviation fuel.
• Launched Castrol GTX ECO, made using a base oil
blend of at least 50% re-refined base oil, in the US.
• Gave UK drivers the option to offset the CO2
emissions from the fuel they buy from us, through
our BPme fuel payment app.
From waste to fuel
We’ve invested in Fulcrum BioEnergy®, which is constructing the
first commercial scale waste-to-fuels plant in the US. The facility
aims to use technology, developed by BP and Johnson Matthey,
to help convert household rubbish that would otherwise be sent
to landfill, into fuel for transport. Fulcrum, in which BP owns an 8%
interest, estimates that when it begins commercial operations,
the plant will be able to convert around 175,000 tons of waste into
about 11 million gallons of fuel each year.
175,000
tons of waste to
11 million
gallons of fuel
Detecting methane
As a colourless and odourless gas – detecting leaks of methane
can be challenging. For several years we’ve used hand-held infrared
cameras to detect small leaks before they become larger ones.
Improvements in technology now make it possible to quantify the
emissions that these cameras detect, helping us to better target
and prioritize our responses. We piloted this technology in
Azerbaijan and the US in 2018 and plan to deploy the cameras
more widely in 2019.
46
BP Annual Report and Form 20-F 2018 Creating
low carbon businesses
We are building up our renewable energy portfolio – focusing on
biofuels, biopower, wind and solar. And together with our dynamic
venturing arm we are working on multiple fronts – through joint
ventures, creative collaborations and new business models.
2018 progress
• Invested $500 million in low carbon activities, such
as FreeWire – which supports development of rapid
mobile electric vehicle charging.
• Worked with OGCI to help progress the Clean Gas
Project, see page 48.
Advancing solar
Lightsource BP has doubled the number of countries
where it has a presence since December 2017.
Lightsource BP sites
As at 31 December 2018
Belfast
Wales
Bath
London
UK
Completed the UK’s biggest-
ever unsubsidized solar power
deal to supply AB InBev, the
Budweiser brewer, with
100MW of solar power at its
UK operations in South Wales
and Lancashire.
Australia
Awarded the project to provide
105MW of solar power to
Snowy Hydro, the country’s
fourth-largest national energy
retailer, through a 15-year
power purchase agreement.
US
Agreed to bring 25MW
of locally generated solar
power to western US,
through new collaborations
in California and New Mexico
over 20+ year terms.
Brazil
Announced plans to develop
solar and smart energy storage
solutions for Brazil’s domestic,
commercial and industrial sectors.
San Francisco
Philadelphia
Dublin and
Limerick
Amsterdam
Milan
Madrid
Cairo
Mumbai
Chennai
São Paulo
Melbourne
Sydney
5 new
countries
in 2018
Europe
Extended operations into
the Italian and Iberian
renewable energy sectors.
Egypt
Formed a joint venture
with Hassan Allam
Utilities to develop and
operate utility scale
solar projects in Egypt.
India
Established EverSource Capital
with Everstone to manage the
Green Growth Equity Fund
aiming to raise up to $700 million of
investment in low carbon energy
infrastructure projects across India.
47
Strategic report – performanceBP Annual Report and Form 20-F 2018 Metrics
We report direct and indirect greenhouse gas (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 we import into our operations.
There was a decrease in our direct GHG emissions in 2018. The primary
reasons for this include actions taken by our businesses to reduce
emissions in areas such as flaring, methane and energy efficiency as
well as operational changes, such as increased gas being captured and
exported to the liquefied natural gas facility in Angola.
Greenhouse gas emissions (MteCO2e)a
Operational controlb
Direct emissions
Indirect emissions
BP equity sharec
Direct emissions
Indirect emissions
2018
2017
2016
48.8
5.4
46.5
5.7
50.5
6.1
49.4
6.8
51.4
6.2
50.1
6.2
a 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 report CO2 and methane. We do
not include nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulphur hexafluoride as
they are not material to our operations and it is not practical to collect this data.
b 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.
c BP equity share data comprises 100% of emissions from subsidiaries and the percentage
of emissions equivalent to our share of joint arrangements and associates , other than BP’s
share of Rosneft.
The ratio of our total GHG emissions reported on an operational control
basis to gross production was 0.22teCO2e/te production in 2018 (2017
0.24teCO2e/te, 2016 0.24teCO2e/te). Gross production comprises
upstream production, refining throughput and petrochemicals produced.
part of the project. This is currently $40 per tonne of CO2 equivalent,
with a stress test at a carbon price of $80 per tonne. Until late January
2019 we used these specific prices in industrialized countries, but have
now expanded this to apply globally.
Working with others
We work with peers, non-governmental organizations and academic
institutions to address the climate challenge.
The Oil and Gas Climate Initiative (OGCI) – currently chaired by our
group chief executive Bob Dudley – brings together 13 oil and gas
companies to increase the ambition, speed and scale of the initiatives
undertaken by its individual companies to help reduce manmade GHG
emissions. OGCI announced a collective methane intensity target
for member companies in 2018. The target aims to reduce the collective
average methane intensity of the group’s aggregated upstream oil and
gas operations to below 0.25% by 2025, compared with the baseline of
0.32% in 2017. See page 46 for information on BP’s methane intensity.
BP is working with OGCI Climate Investments to help progress the
UK’s first commercial full-chain carbon capture, use and storage project.
The Clean Gas Project plans to capture CO2 from new efficient gas-fired
power generation and transport it by pipeline to be stored in a formation
under the southern North Sea. The infrastructure would also allow other
industries in Teesside to store CO2 captured from their processes. The
project, which is currently undergoing a feasibility study, could be in
operation by the mid-2020s.
Managing our impacts
We work hard to avoid, mitigate and manage our
environmental and social impacts over the life of
our operations.
Accrediting our lower carbon activities
To reinforce our ambitions, we implemented our Advancing Low Carbon
accreditation programme, which aims to inspire every part of BP to
identify lower carbon opportunities.
The way our businesses around the world understand and manage
their environmental and social impacts is set out in our operating
management system. This includes requirements on engaging with
stakeholders who may be affected by our activities.
To gain accreditation by BP, each activity must meet certain criteria,
including delivering what we call a better carbon outcome. This means
either reducing GHG emissions, producing less carbon than competitor
or industry benchmarks, providing renewable energy, offsetting carbon
produced, furthering research and technology to advance low carbon or
enabling BP or others to meet their low carbon objectives.
Deloitte conducts independent assurance on the Advancing Low
Carbon activities, including assessing the application of BP’s process
and criteria for accrediting activities, and GHG emissions offset and
saved within the programme.
A total of 52 activities met the criteria for accreditation or reaccreditation
in 2019, up from 33 in 2018. These include emission reductions in our
operations, carbon neutral products, more efficient ships, investments
in electrification and support for low carbon technologies.
See bp.com/advancinglowcarbon for details on the programme
and Deloitte’s assurance statement.
Calling for a price on carbon
BP believes that well-designed 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 carbon capture, use and storage, more cost
competitive.
We use a carbon price when evaluating our plans for certain large new
projects and also those for which emissions costs would be a material
48
See Glossary
In planning our projects, we identify potential impacts from our activities
in areas such as land rights, water use and protected areas. We use the
results of this analysis to identify actions and mitigation measures and
implement these in project design, construction and operations. For
example, as part of our exploration activities in São Tomé and Príncipe,
we are using underwater sound recorders and an autonomous vehicle
to help understand the distribution and movement of marine mammals.
The outcomes of this will inform our approach to planning for potential
future activities.
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.
See page 44 for information on our oil spill performance.
Water
We review risks related to management of water in our portfolio
each year, considering the local availability, quantity, quality and
regulatory requirements. In our gas operations in Oman – an area
where the availability of fresh water is extremely scarce – we withdraw
brackish water under permit from a local underground aquifer that is only
used for industrial purposes. We desalinate the water and use it for
drilling and hydraulic fracturing. We completed a modelling study in 2018
to assess the sustainability of this water supply. The results of the study
have been incorporated into a long-term water management plan to
reduce water demand.
Air quality
We put measures in place to manage our air emissions, in line with
regulations and industry guidelines designed to protect the health
BP Annual Report and Form 20-F 2018
of local communities and the environment. In our shipping business, we
introduced three new liquefied natural gas carriers to our fleet in 2018.
The carriers are designed to use approximately 25% less fuel and emit
less nitrogen oxides than our older ships.
Hydraulic fracturing
We aim to apply responsible practices to the design of our wells to
mitigate potential risks associated with hydraulic fracturing. For example,
we install multiple layers of steel into each well and cement above and
below any freshwater aquifers. We then test the integrity of each well
before we begin the fracturing process and again at completion.
Hydraulic fracturing creates very small earth tremors that are rarely felt
at the surface. Before we start work we assess the likelihood of our
operations causing such activity. For example, we work to identify
natural faults in the rock. This analysis informs our development plans
for drilling and hydraulic fracturing activity, and we seek to mitigate this
risk through the design of our operations.
See bp.com/environment for more information.
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.
We support transparency in the flow of revenue from oil and gas
activities to governments. This 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 2018 we continued to support EITI
implementation in a number of countries where we operate, including
Iraq and Trinidad & Tobago.
See bp.com/tax for our approach to tax and our payments
to governments report.
Value to society
We aim to have a positive and enduring impact
on the communities in which we operate.
In supplying energy, we contribute to economies around the world
by employing local staff, helping to develop national and local suppliers,
and through the funds we pay to governments from taxes and other
agreements.
Additionally, our social investments support community efforts to
increase incomes and improve standards of living. We contributed
$114.2 million in social investment in 2018 (2017 $89.5 million, 2016
$61.1 million). In India we developed a training programme to help
motorcycle mechanics working in small enterprises develop additional
skills in business management and customer service. Since it began in
2009, the programme has trained more than 200,000 mechanics.
We aim to recruit our workforce from the community or country in
which we operate. We also run programmes to build the skills of
businesses and develop the local supply chain in a number of
locations. For example, in 2018 we launched an initiative with oil
and gas peers in Senegal to support local company efforts to achieve
international standards and improve their ability to bid for work with
companies like BP.
Human rights
We are committed to respecting the rights and
dignity of all people when conducting our 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 potentially 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 incorporating the UN Guiding Principles on Business and
Human Rights, which set out how companies should prevent, address
and remedy human rights impacts, into our business processes. Our
focus areas include the ethical recruitment and working conditions of
contracted workforces at our sites, responsible security, community
health and livelihoods, and mechanisms for workers and communities
to raise their concerns.
Nationals employed
In 2018 our actions included:
Trinidad
& Tobago 96%
Egypt 78%
Azerbaijan 91%
Oman 77%
Indonesia 96%
Angola 87%
See bp.com/society for more information on how we generate
value to society.
Tax and transparency
We are committed to complying with tax laws in a responsible manner
and having open and constructive relationships with tax authorities.
We paid $7.5 billion in income and production taxes to governments
in 2018 (2017 $5.8 billion, 2016 $2.2 billion).
• Reviewing the risk of modern slavery in prioritized locations, including
on-site assessments in some cases and addressing findings.
• Working with a number of our peers to create an oil and gas industry
framework for human rights supplier assessments with a particular
focus on labour rights.
• Developing clear expectations on labour rights and a systematic
approach to modern slavery risk management to build into business
systems and processes.
• Continuing to develop capability on modern slavery and labour rights
for our employees and selected contractors, as well as taking steps
to raise worker awareness of their rights.
• Assessing the practices of private security contractors and the way
we work with public security forces in our operations in Georgia, in line
with our continued implementation of the Voluntary Principles on
Security and Human Rights.
See bp.com/humanrights for more information about our approach to
human rights.
49
Strategic report – performanceBP Annual Report and Form 20-F 2018
Ethical conduct
We are committed to conducting our business in an
ethical, transparent way, using our values and code
of conduct to guide us.
Our values
Our values represent the qualities and actions we wish to see in BP.
They inform the way we do business and the decisions we make. We
use these values as part of our recruitment, promotion and individual
performance management 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 unethical or
unsafe 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 1,712 concerns or enquiries were recorded in 2018 (2017
1,612, 2016 1,701) through these channels. The most commonly raised
concerns were about fair treatment of people, workplace harassment
and protecting BP’s assets.
We take steps to identify and correct areas of non-conformance and
take disciplinary action where appropriate. In 2018 our businesses
dismissed 50 employees for non-conformance with our code of conduct
or unethical behaviour (2017 70, 2016 109). This excludes dismissals of
staff employed at our retail service stations.
See bp.com/codeofconduct for more information.
Gulf of Mexico oil spill
The term of appointment of the ethics monitor, who was appointed
under the administrative agreement with the US Environmental
Protection Agency, came to an end in March 2019. In his final report
the ethics monitor confirmed that BP had successfully completed
the recommendations he had made.
Anti-bribery and corruption
BP operates in parts of the world where bribery and corruption present
a high risk. 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 10,957 employees completed anti-bribery and
corruption training in 2018 (2017 12,500, 2016 13,000).
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 conformance with our anti-bribery and corruption
contractual requirements. Potential areas for improvement are shared
with our suppliers and where necessary, this enables us to work with
them to find ways to strengthen their procedures. We issued a total of
27 audit reports in 2018 (2017 36, 2016 25). 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.
We are members of multiple industry associations that offer
opportunities to share good practices and collaborate on issues of
importance to our sector. We aim for alignment between our policies
and those of trade associations, but understand that associations’
positions reflect a compromise of the assorted views of the
membership.
50
BP Annual Report and Form 20-F 2018
Our people
BP’s success depends on the wholehearted
contribution of 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
2018
16,900
42,700
13,400
73,000
17,400
2017
17,700
42,100
14,200
74,000
16,800
2016
18,700
41,800
14,000
74,500
16,200
3,400
4,300
4,600
52,200
52,900
53,700
a Reported to the nearest 100. For more information see Financial statements – Note 35.
Our industry relies on creative and scientific thinking to solve some of
the world’s biggest energy problems. We focus on attracting and
developing innovative and capable individuals, while also maintaining
safe and reliable operations.
The group people committee helps facilitate the group chief executive’s
oversight of policies relating to employees. In 2018 the committee
discussed remuneration policy, progress in our diversity and inclusion
programme, modernizing and strengthening our attractiveness as an
employer, our talent and learning programmes and long-term people
priorities.
Attraction and retention
A total of 296 graduates joined BP in 2018 (2017 314, 2016 231). We
were named the UK’s highest-ranking recruiter in the oil and gas sector
in The Times newspaper’s Top 100 Graduate Employer rankings in 2018.
We invest in employee development – with an average spend of around
$3,200 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 35% of BP’s total population (2017 34%, 2016
33%). We are working to improve these numbers further by, for
example, developing mentoring, sponsorship and coaching programmes
to help more women advance. But we still have work to do at the
executive and senior levels.
See bp.com/ukgenderpaygap for data and more information on our gender
pay gap in the UK.
At the end of 2018 we had five female directors (2017 3, 2016 3) on our
board. Our nomination committee remains mindful of diversity when
considering potential candidates.
For more information on the composition of our board, see page 58.
Workforce by gender
Members as at 31 December
Board directors
Executive team
Group leaders
Subsidiary directors
All employees
Male
9
11
286
1,161
47,171
Female
5
2
89
233
25,824
Female %
36
15
24
17
35
A total of 24% of our group leaders came from countries other than the
UK and the US in 2018 (2017 24%, 2016 23%).
Inclusion
BP is committed to creating a positive and empowering workplace in
which all employees feel valued for the work they do and the impact
they make. 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,
ethnicity, sexual orientation and disability. As well as bringing employees
together, these groups support our recruitment programmes and
provide feedback on the potential impact of policy changes. Each
group is sponsored by a senior executive.
We made progress in a number of important areas in 2018. For example,
we worked with MyPlus, a disability consultancy, to increase our
understanding of the needs of disabled candidates in our application and
hiring processes. And we launched our gender transition guidelines to
support employees who are transitioning, or helping someone who is.
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.
To better understand how employees feel about BP, we conduct an
annual survey. The overall employee engagement score in 2018 was
66%. Pride in working for BP was at the highest level in a decade at
76% in 2018.
The area where our employees scored us as needing attention was in
the efficiency of our processes and ways of working. We know we still
have work to do to streamline our processes and drive the benefits of
digitization throughout BP.
Share ownership
We encourage employee share ownership and have a number of
employee share plans in place. For example, we operate a ShareMatch
plan in more than 50 countries, matching 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.
See Glossary
51
Strategic report – performanceBP Annual Report and Form 20-F 2018 Modernizing
the whole
group
Using
wearable
technologies
New technologies are helping
to modernize our operations
and improve safety, performance
and efficiency right across our
business. And we are testing a
range of wearable technologies to
understand how they can support
our people in a variety of roles.
Smart glasses
used across BPX Energy
We are using augmented reality (AR)
devices such as ‘smart glasses’ across
BPX Energy. Technicians can use the
glasses to transmit real-time video to experts
anywhere in the business and they can then
return AR-enabled instruction back to the
technician – all while keeping their hands
free. We are now using the mobile platform
to troubleshoot equipment, conduct safety
verifications and deliver remote training.
This is helping increase productivity and
contributing to improvements in the safety
and efficiency of our operations.
Digital vests
In Oman, where temperatures can reach
55°C, we are testing technologies such
as biometric vests to protect our people
working in high temperatures. Working
in extreme heat can trigger fatigue,
dehydration and stress – and this can
affect safety and effective performance.
The lightweight vest is designed to prevent
this by monitoring location and core body
temperature and transmitting data about
heart and respiratory rates. It sends an
alert if there is a potential concern or a real
emergency. As technologies like these
evolve, we will continue to trial them in our
operations, so that we can roll out those
that are the best fit.
Temperatures in
Oman can reach
55°C
52
BP Annual Report and Form 20-F 2018
How we manage risk
BP manages, monitors and reports on the principal risks and uncertainties
that can impact our ability to deliver our strategy. These risks are described
in the Risk factors on page 55.
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 management and to the board. The system seeks to avoid
incidents and maximize business outcomes by allowing us to:
• Understand the risk environment, identify the specific risks and assess
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.
• Monitor and seek assurance of the effectiveness of the management
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:
Executive committees
• Executive team meeting – for strategic and commercial risks.
• Group operations risk committee – for health, safety, security,
environment and operations integrity risks.
• Group financial risk committee – for finance, treasury, trading
and cyber risks.
• Group disclosure committee – for financial reporting risks.
• Group people committee – for employee risks.
of these risks and intervene for improvement where necessary.
• Group ethics and compliance committee – for legal and regulatory
• 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
compliance and ethics risks.
• Resource commitment meeting – for investment decision risks.
• Renewal committee – for strategic, commercial and investment
decision risks related to new lines of business.
Board and its committees
• BP board.
• Audit committee.
• Safety, ethics and environment assurance committee.
• Geopolitical committee.
Facilities,
assets and
operations
Business
segments and
functions
Executive and
corporate
functions
Board
See BP governance framework on page 69, Board activity in 2018 on
page 70, committee reports on pages 75-86 and Risk management and
internal control on page 110.
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 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 in connection with planning new
activities.
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.
Risk management processes
We aim for a consistent basis of measuring risk to:
• Establish a common understanding of risks on a like-for-like basis,
taking into account potential impact and likelihood.
• Report risks and their management to the appropriate levels
of the organization.
• Inform prioritization of specific risk management activities and
resource allocation.
Businesses and functions review significant risks and associated risk
management activities in alignment with key business processes to help
enable key decisions to be risk informed.
As part of BP’s annual planning process, the executive team and
board review the group’s principal risks and uncertainties. These may
be updated during the year in response to changes in internal and
external circumstances.
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.
53
Strategic report – performanceBP Annual Report and Form 20-F 2018
We identify high priority risks for particular oversight by the board and
its various committees in the coming year. Those identified for 2019
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.
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 55.
Risks for particular oversight by the board and its
committees in 2019
The risks for particular oversight by the board and its committees in
2019 have been reviewed. These risks remain the same as for 2018.
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, maintaining a significant
cash buffer, 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.
The impact of the UK’s exit from the EU
Following the referendum in 2016, we have been assessing the
potential impact of Brexit on BP. We have been preparing for
different scenarios for the UK’s exit from the EU but do not believe
any of these scenarios will pose a significant risk to our business.
The board’s geopolitical committee discussed this, most recently
in January 2019.
We continue to monitor developments in this area in line with our
risk management processes and procedures.
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.
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.
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 activities 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.
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
employee conduct.
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.
54
See Glossary
BP Annual Report and Form 20-F 2018 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 – 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,
unsuccessful exploration activity 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. Poor investment
choice, efficiency or delivery, or operational challenges 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 277 and Financial statements – Note 29.
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
See Glossary
55
Strategic report – performanceBP Annual Report and Form 20-F 2018
the demand for our products, investor sentiment, our financial
performance and our competitiveness. See Climate change on page 45.
Security – hostile acts against our staff and activities could cause harm
to people and disrupt our operations.
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.
Our industry faces increasing challenge to recruit and retain diverse,
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 cause harm to people, the environment and our assets and
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 43.
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 or stop
production 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.
56
See Glossary
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.
Compliance and control risks
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, 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 29.
Reporting – failure to accurately report our data could lead to regulatory
action, legal liability and reputational damage.
External reporting of financial and non-financial data, including reserves
estimates, relies on the integrity of systems and people. Failure to report
data accurately and in compliance with applicable standards could result
in regulatory action, legal liability and damage to our reputation.
The Strategic report was approved by the board and signed on its behalf
by Jens Bertelsen, company secretary on 29 March 2019.
BP Annual Report and Form 20-F 2018 Corporate
governance
58 Board of directors
63 Executive team
66 Executive management teams
68
Introduction from the chairman
69 Governance framework
69 Board and committee attendance
70 Board activity in 2018
70 Role of the board
71 Skills and expertise
71 Diversity
71
71 Appointment and time commitment
72 Training and induction
72 Board evaluation
73 Site visits
Independence
74 Shareholder engagement
Institutional investors
74
74 Retail investors
74 AGM
74 UK Corporate Governance Code compliance
74
International advisory board
75 Committee reports
75 Audit committee
81
83 Remuneration committee
84 Geopolitical committee
85 Chairman’s committee
86 Nomination and governance committee
Safety, ethics and environment assurance committee
87 Directors’ remuneration report
90 2018 performance and pay outcomes
91 2018 annual bonus outcome
92 2016-18 performance share plan outcome
94 Alignment with strategy
95 Executive directors’ pay for 2018
97 Wider workforce in 2018
100 Stewardship and executive director interests
102 Non-executive director outcomes and interests
104 Other disclosures
105 Executive director remuneration policy and implementation for 2019
109 Non-executive director remuneration policy for 2019
110 Directors’ statements
110 Statement of directors’ responsibilities
110 Risk management and internal control
111 Longer-term viability
111 Going concern
111 Fair, balanced and understandable
BP Annual Report and Form 20-F 2018
57
Corporate governance
Board of directors
As at 29 March 2019
See BP’s board governance principles relating
to director independence on page 300.
Helge Lund
Bob Dudley
Brian Gilvary
Nils Andersen
Alan Boeckmann
Admiral Frank
Bowman
Dame Alison
Carnwath
Pamela Daley
Ian Davis
Professor Dame
Ann Dowling
Melody Meyer
Brendan Nelson
Paula Rosput
Reynolds
Sir John Sawers
Jens Bertelsen
He has a degree in business economics from
the Norwegian School of Economics and
Business Administration in Bergen and a
Master of Business Administration from
INSEAD business school in France.
Relevant skills and experience
Helge Lund was appointed chair of the BP
board following a detailed process involving
all members of the board. Helge has an
impressive track record of leadership in the
oil and gas industry. His open-minded and
forward-looking approach will be vital as the
industry focuses on the transition to a lower
carbon world. He has deep industry
knowledge and global business experience –
not only in the oil and gas industry but also in
pharmaceuticals, healthcare and construction.
Prior to Statoil, he was president and chief
executive officer of Aker Kvaerner, an industrial
conglomerate with operations in oil and gas,
engineering and construction, pulp and paper
and shipbuilding. He has also held executive
positions in Aker RGI, a Norwegian industrial
holding company, and Hafslund Nycomed, an
industrial group with business activities in
pharmaceuticals and energy.
He has worked as a consultant with McKinsey
& Company and has served as a political
adviser for the parliamentary group of the
Conservative party in Norway.
Helge is chairman of the board of Novo Nordisk
AS, a global healthcare company. Prior to
joining BP, he was a non-executive director of
the oil service group Schlumberger from 2016
to 2018, and Nokia from 2011 to 2014.
He is an operating adviser to Clayton Dubilier &
Rice, a US investment firm. He is a member of
the Board of Trustees of the International Crisis
Group and served as a member on the United
Nations Secretary-General’s Advisory Group
on Sustainable Energy from 2011 to 2014.
Helge Lund
Chairman
Tenure
Appointed 26 July 2018
Board and committee activities
Chair of the chairman’s committee and
nomination and governance committee,
regularly attends the safety, ethics and
environment assurance, audit, remuneration
and geopolitical committees
Outside interests
• Chairman of Novo Nordisk AS
• Operating Advisor to Clayton Dubilier & Rice
• Member of the Board of Trustees of the
International Crisis Group
Age 56 Nationality Norwegian
Career
Helge Lund became a board director on
26 July 2018 and chairman of the BP board
on 1 January 2019.
Helge served as chief executive of BG Group
from 2015 to 2016, when the company
merged with Shell. He joined BG Group from
Statoil where he served as president and chief
executive officer for 10 years from 2004.
58
BP Annual Report and Form 20-F 2018 Bob Dudley
Group chief executive
Tenure
Appointed to the board 6 April 2009
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 Oil and Gas Climate Initiative
(OGCI)
Age 63 Nationality American and British
Career
Bob Dudley became group chief executive on
1 October 2010.
Bob joined Amoco Corporation in 1979,
working in a variety of engineering and
commercial posts. Between 1994 and 1997 he
worked on corporate development in Russia.
In 1997 he became general manager for
strategy for Amoco and in 1999, following the
merger between BP and Amoco, was
appointed to a similar role in BP.
Between 1999 and 2000 he was executive
assistant to the group chief executive,
subsequently becoming group vice president
for BP’s renewables and alternative energy
activities. In 2002 he became group vice
president responsible for BP’s upstream
businesses in Russia, the Caspian region,
Angola, Algeria and Egypt.
From 2003 to 2008 he was president and chief
executive officer of TNK-BP. On his return to
BP in 2009, he was appointed to the BP board
and oversaw the group’s activities in the
Americas and Asia. During 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. Since 2016, he has chaired
the Oil and Gas Community of the World
Economic Forum and is chair of the Oil and
Gas Climate Initiative (OGCI).
Relevant skills and experience
Bob Dudley has spent his whole career in the
oil and gas industry. As group chief executive,
the board believes Bob has demonstrated
outstanding leadership and vision and has
transformed BP into a safer, stronger and
simpler business. Over the past eight years,
Bob has based this transformation on a
consistent set of values and behaviours. BP
is now more resilient and is able to continue
delivering results in an uncertain economic
environment. Bob continues to lead the
development of the group’s strategy, as BP
adapts to the challenges of the advancing
transition to a lower carbon economy. Under
his leadership, BP successfully acquired the
lower 48 assets of BHP in 2018 and delivered
six major projects as planned.
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 of Air Liquide
• Non-executive director of (Royal) Navy Board
• Non-executive director of The Francis Crick
Institute
• Chairman of The 100 Group
• Member of Trilateral Commission
• Honorary professor at Manchester University
• Great Britain Age Group Triathlete
Age 57 Nationality 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.
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, with broad experience of working across all
facets of the group. This has provided him with
deep insight into BP’s assets and businesses.
Brian has been a key player as BP has
implemented its strategy to transform into a
‘value over volume’ based business where
trading is a key creator of value throughout the
integrated business.
In addition to underpinning his role as chief
financial officer, his deep 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.
He played a major role in overseeing the
financial consequences of the 2010 oil spill in
the Gulf of Mexico, and leading the 2015
settlement negotiations with the US
government and states to resolve the
outstanding federal and state claims. Brian also
played a lead role in the negotiations around
the exit of TNK-BP and investment into
Rosneft and led the recent acquisition of the
BHP onshore Lower 48 assets. Brian has also
been at the centre of the group’s work on
addressing cyber security 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 safety, ethics and environment
assurance, geopolitical and chairman’s
committees
Outside interests
• Non-executive director of Unilever Plc and
Unilever NV
• Chairman of Salling Group A/S
• Chairman of Færch Plast A/S
• Chairman of Akzo Nobel N.V.
• Chairman of WWF Denmark
Age 60 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 was elected as a member and chairman
of the supervisory board of Akzo Nobel N.V.
in April 2018 and was recently appointed as
chairman of WWF Denmark.
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 has
recently moved from the audit committee to
the safety, ethics and environment assurance
59
Corporate governanceBP Annual Report and Form 20-F 2018 committee where he will shortly take the chair.
His broad business experience and his
knowledge of safe operations in our industry
makes him very well qualified for that role.
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 governance
and chairman’s committees
Outside interests
• Non-executive director of Sempra Energy
• Non-executive director of Archer Daniels
Midland
Age 70 Nationality American
Career
Alan Boeckmann retired as non-executive
chairman of Fluor Corporation in February
2012, ending a 35-year career with the
company. Between 2002 and 2011 he held
the post of chairman and chief executive
officer, having previously been president
and chief operating officer from 2001 to
2002. His tenure with the company included
responsibility for global operations. As
chairman and chief executive officer, he
refocused the company on engineering,
procurement, construction and maintenance
services.
After graduating from the University of
Arizona with a degree in electrical engineering,
he joined Fluor in 1974 as an engineer
and worked in a variety of domestic and
international locations, including South Africa
and Venezuela.
Alan was previously a non-executive director
of BHP Billiton and the Burlington Santa Fe
Corporation, and has served on the boards
of the American Petroleum Institute, the
National Petroleum Council, the Eisenhower
Medical Center and the advisory board of
Southern Methodist University’s Cox School
of Business.
He led the formation of the World Economic
Forum’s ‘Partnering Against Corruption’
initiative in 2004.
Relevant skills and experience
Alan Boeckmann has worked in a wide range
of industries including engineering,
construction, chemicals and 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.
60
Admiral Frank Bowman
Independent non-executive director
Dame Alison Carnwath
Independent non-executive director
Tenure
Appointed 8 November 2010
Tenure
Appointed 21 May 2018
Board and committee activities
Member of the audit and chairman’s
committees
Outside interests
• Member of Supervisory Board and Audit
Committee chair of BASF SE
• Director and Audit Committee chair of Zurich
Insurance Group
• Independent director of PACCAR Inc
• Member of UK Panel on Takeovers and
Mergers
• Trustee of The Economist Group
Age 66 Nationality British
Career
Dame Alison Carnwath qualified as a chartered
accountant before going on to hold a number
of senior financial advisory roles in London and
New York.
For more than 15 years, Dame Alison’s career,
in her capacities as senior adviser, director and
chairman, has enabled her to demonstrate her
expertise on financial, strategic and good
governance matters both in and outside of
the board room. Her current roles include
independent director of PACCAR Inc, director
and audit committee chair of Zurich Insurance
Group and supervisory board member
and audit committee chair BASF SE.
Previous roles of note include chairmanship
of Land Securities Group plc as well as
non-executive directorships of Barclays plc
and Man Group plc.
Dame Alison is a chartered accountant, holds
an undergraduate degree, has two honorary
degrees and in 2014 was appointed to the order
of Dame Commander of the Most Excellent
Order of the British Empire for her services
to business and diversity.
Relevant skills and experience
Dame Alison has extensive financial
experience both as an executive and non-
executive director. Dame Alison has chaired
significant boards and has deep experience
of the workings of investors and the finance
industry in the City of London. She has
worked with global organizations and brings
this broad range of skills to the BP board
and to the audit committee.
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 74 Nationality American
Career
Frank 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.
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 safety,
ethics and environment assurance committee.
He has led the oversight of BP’s compliance
with the agreements with the US government
stemming from the Deepwater Horizon
oil spill.
BP Annual Report and Form 20-F 2018
Pamela Daley
Independent non-executive director
Tenure
Appointed 26 July 2018
Board and committee activities
Member of the audit, remuneration and
chairman’s committees
Outside interests
• Director of BlackRock, Inc
• Director of SecureWorks, Inc
Age 66 Nationality American
Career
Pamela Daley spent most of her career with
the General Electric Company. She joined GE
in 1989 as tax counsel and held a number of
senior executive roles in the company, serving
most recently as senior vice president and
senior advisor to the chairman from April to
December 2013, when she retired from GE.
Between 2004 and 2013 she was senior vice
president of corporate business development
at GE, where she was responsible for GE’s
mergers, acquisitions and divestiture activities
worldwide, and prior to that, from 1991 to 2004,
served as vice president and senior counsel
for transactions.
Pamela Daley has served as a director of
BlackRock since 2014 and of SecureWorks
since 2016. She was a director of BG Group plc
from 2014 to 2016 until its acquisition by Shell,
a director of Patheon N.V. from 2016 to 2017
until its acquisition by Thermo Fisher, and
was previously a partner at Morgan, Lewis &
Bockius, a major US law firm, where she
specialized in domestic and cross-border
tax-oriented financings and commercial
transactions.
Pamela Daley is a qualified lawyer, she worked
in highly regulated industries, holding senior
roles on other boards including chair of the
governance and nominating committee at
SecureWorks and chair of the audit committee
at BlackRock.
Relevant skills and experience
Pamela Daley has deep experience of global
business through her executive role at GE. She
has also served on a UK board in the oil and
gas industry which gave her further insight into
that sector. Pamela has joined the audit
committee to which she brings deep financial
experience and expertise. She has also joined
the remuneration committee, where her
understanding of employee and investor points
of view will provide important input.
Ian Davis
Senior independent director
Tenure
Appointed 2 April 2010
Board and committee activities
Member of the remuneration, geopolitical,
nomination and governance 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 68 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 of Mexico 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 led the search
for a successor to Carl-Henric Svanberg as
chairman, resulting in the appointment of
Helge Lund.
Professor Dame Ann Dowling
Independent non-executive director
Tenure
Appointed 3 February 2012
Board and committee activities
Member of the safety, ethics and environment
assurance 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 Smiths Group plc
Age 66 Nationality British
Career
Dame Ann Dowling is a deputy vice-chancellor
at the University of Cambridge where she was
appointed a professor of mechanical engineering
in the department of engineering in 1993. She
was head of the department of engineering at
the university from 2009 to 2014. Her research
is in fluid mechanics, acoustics and combustion,
and she has held visiting posts at MIT and at
Caltech. She chairs BP’s technical advisory
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 18
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 safety, ethics and environment assurance
committee, particularly as developments in
technology accelerate. Her work in this area is
supplemented by her chairing the company’s
technology advisory council.
Dame Ann was chair of the remuneration
committee from 2015 and stood down from
that committee after the 2018 AGM.
Melody Meyer
Independent non-executive director
Tenure
Appointed 17 May 2017
Board and committee activities
Member of the safety, ethics and environment
assurance, geopolitical and chairman’s
committees.
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
• Director of National Oilwell Varco, Inc.
Age 61 Nationality American
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 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
61
Corporate governanceBP Annual Report and Form 20-F 2018 insight into the challenges faced by global
businesses by regulatory frameworks. He
recently joined the remuneration committee.
Paula Rosput Reynolds
Independent non-executive director
Tenure
Appointed 14 May 2015
Board and committee activities
Chair of the remuneration committee; member
of the audit, nomination and governance and
chairman’s committees
Outside interests
• Non-executive director of BAE Systems plc
• Non-executive director of TransCanada
Corporation (until May 2019)
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 governance 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
• Trustee of the Bilderberg Association, UK
• Non-executive director of CBRE Group (until
Age 63 Nationality British
May 2019)
• Non-executive director of General Electric
Company
Age 62 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 currently serves as the chair of the
remuneration committee of BAE Systems plc.
Her experience there and her wider business
experience and understanding of the views of
investors are well suited to her being the chair
of the BP remuneration committee.
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 from 2007 to 2009, political
director and main board member of the Foreign
Office from 2003 to 2007, special representative
in Iraq during 2003, ambassador to Egypt from
2001 to 2003 and foreign policy adviser to the
Prime Minister from 1999 to 2001. 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’s 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 gained in government, diplomacy and
policy analysis and advice are invaluable to
both the board and the safety, ethics and
environment assurance committee.
Jens Bertelsen
Company secretary
Tenure
Appointed 1 January 2019
Jens Bertelsen is a solicitor and formerly
deputy secretary.
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, nomination and governance 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 69 Nationality British
Career
Brendan Nelson is a chartered accountant.
He was made a partner of KPMG in 1984. He
served as a member of the UK board of KPMG
from 2000 to 2006, subsequently being
appointed vice chairman until his retirement in
2010. At KPMG International he held a number
of senior positions including global chairman,
banking and global chairman, financial services.
He served for six years as a member of the
Financial Services Practitioner Panel and in 2013
was the president of the Institute of Chartered
Accountants of Scotland.
Relevant skills and experience
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 specialism in the financial
services industry allows him to contribute
62
BP Annual Report and Form 20-F 2018 Executive team
As at 29 March 2019
The executive team represents the principal executive leadership of the BP group.
Its members include BP’s executive directors (Bob Dudley and Brian Gilvary whose
biographies appear on pages 58-62) and the senior management listed on these
pages.
Susan Dio
Tufan Erginbilgic
David Eyton
Bob Fryar
Andy Hopwood
Bernard Looney
Lamar McKay
Eric Nitcher
Dev Sanyal
Helmut Schuster
Dame Angela Strank
David Eyton
Group head of technology
Executive team tenure
Appointed 1 September 2018
Outside interests
• Fellow of the UK Royal Academy of
Engineering
• Fellow of the Institute of Materials, Minerals
and Mining
• Fellow of the Institute of Directors
• Trustee of the John Lyons Foundation
Age 58 Nationality British
Career
As group head of technology, David Eyton is
accountable for technology strategy and its
implementation across BP. This includes
corporate venture capital investments and
conducting research and development in areas
of corporate renewal. In this role, David sits
on the Oil & Gas Climate Initiative Climate
Investments Board.
David joined BP in 1982 from Cambridge
University with an engineering degree.
Susan Dio
Chairman and president of BP America
Executive team tenure
Appointed 1 September 2018
Outside interests
• Member of the American Petroleum Institute
Board and Executive Committee
• Member of the Greater Houston Partnership
Executive Committee
• Member of the Ford’s Theatre Board of
Trustees Executive Committee
Age 58 Nationality American
Career
Susan Dio is chairman and president of BP
America, providing leadership and oversight
to BP’s US businesses, which employ around
14,000 people. These businesses include oil
and gas exploration and production, refining,
petrochemicals, supply and trading, pipeline
operations, shipping, retail, and alternative
energy.
Since joining the company in 1984, she has
held key operational and executive positions
in the US, UK, and Australia. Before assuming
her current role, Susan served as chief
executive officer of BP shipping, where
she managed the fleet of BP-operated and
chartered vessels that move more than 200
million tonnes of products across the globe
each year.
She also previously served as head of audit for
BP’s downstream segment, as business unit
leader of the Bulwer Island refinery, and as
plant manager of Texas City chemicals.
Outside BP, Susan is a member of the
American Petroleum Institute Board and
Executive Committee, the Greater Houston
Partnership Executive Committee, and the
Ford’s Theatre Board of Trustees Executive
Committee.
Tufan Erginbilgic
Chief executive, Downstream
Executive team tenure
Appointed 1 October 2014
Outside interests
• Member of the Turkish-British Chamber of
Commerce & Industry Board of Directors
• Member of the Strategic Advisory Board of
the University of Surrey
Age 59 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.
He became head of the European fuels
business in 2004 and 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.
63
Corporate governanceBP Annual Report and Form 20-F 2018
Bob Fryar
Executive vice president, safety
and operational risk
Executive team tenure
Appointed 1 October 2010
Outside interests
No external appointments
Age 55 Nationality American
Career
Bob Fryar is responsible for strengthening
safety, operational risk management and the
systematic management of operations across
the BP group. He is group head of safety and
operational risk, with accountability for
group-level disciplines including engineering,
health, safety, security, remediation
management and the environment. In this
capacity, he looks after the group-wide
operating management system
implementation and capability programmes.
Bob has over 30 years’ experience in the
oil and gas industry, having joined Amoco
Production Company in 1985. Between 2010
and 2013 Bob was executive vice president of
the production division, accountable for safe
and compliant exploration and production
operations and stewardship of resources
across all regions.
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.
Andy Hopwood
Executive vice-president, chief operating
officer, upstream strategy
Executive team tenure
Appointed 1 November 2010
Outside interests
No external appointments
Age 61 Nationality British
Career
Andy Hopwood is responsible for BP’s upstream
strategy.
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.
64
Most recently, Andy was appointed chief
operating officer, upstream strategy in April
2018.
Bernard Looney
Chief executive, Upstream
Executive team tenure
Appointed 1 November 2010
Outside interests
• Fellow of the Royal Academy of Engineering
• Fellow of the Energy Institute
Age 48 Nationality Irish
Career
Bernard Looney is responsible for the
Upstream segment which consists of
exploration, development and production.
Bernard joined BP in 1991 as a drilling
engineer, working in the North Sea, Vietnam
and the Gulf of Mexico. In 2005 he became
senior vice president for BP Alaska before
becoming head of the group chief executive’s
office in 2007.
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.
Lamar McKay
Deputy group chief executive
Executive team tenure
Appointed 16 June 2008
Outside interests
No external appointments
Age 60 Nationality American
Career
Lamar McKay is accountable for group
strategy and long-term planning, group
economics, safety and operational risk, group
technology and the legal function. In addition
to supporting the group chief executive, he
also focuses on various corporate governance
activities including ethics and compliance.
Lamar started his career in 1980 with Amoco
and held a range of technical and leadership
roles.
During 1998 to 2000, he worked on the
BP-Amoco merger and served as head of
strategy and planning for the exploration and
production business. In 2000 he became
business unit leader for the central North Sea.
In 2001 he became chief of staff for
exploration and production, and subsequently
for BP’s deputy group chief executive. Lamar
became group vice president, Russia and
Kazakhstan in 2003. He served as a member
of the board of directors of TNK-BP between
February 2004 and May 2007.
In 2007 he was appointed executive vice
president, BP America. In 2008 he became
executive vice president, special projects
where he led BP’s efforts to restructure the
governance framework for TNK-BP. In 2009
Lamar was appointed chairman and president
of BP America, serving as BP’s chief
representative in the US. In January 2013, he
became chief executive, upstream,
responsible for exploration, development and
production, serving in the role until April 2016.
Eric Nitcher
Group general counsel
Executive team tenure
Appointed 1 January 2017
Outside interests
No external appointments
Age 56 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 US
government claims and resolution of many of
the remaining private claims.
Dev Sanyal
Chief executive, alternative energy and
executive vice president, regions
Executive team tenure
Appointed 1 January 2012
Outside interests
• Independent non-executive director
of Man Group plc
• Member of the Accenture Global
Energy Board
• Member of the Board of Advisors of
The Fletcher School of Law and Diplomacy,
Tufts University
• Member, International Advisory Board of the
Ministry of Petroleum and Natural Gas,
Government of India
• Member of the Advisory Board of the Centre
for European Reform
Age 53 Nationality British and Indian
Career
Dev Sanyal is responsible for alternative
energy globally and for the group’s interests in
the Europe and Asia regions.
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
BP Annual Report and Form 20-F 2018
Mediterranean in 1999. In November 2003
he was appointed chief executive, Air BP
International and in June 2006 was appointed
head of the group chief executive’s office.
In 2007, he assumed the role of group vice
president and group treasurer. During this
period he was also chairman of BP investment
management and was accountable for the
group’s aluminium interests. Until April 2016,
Dev was executive vice president, strategy
and regions.
Helmut Schuster
Executive vice president, group human
resources director
Executive team tenure
Appointed 1 March 2011
Outside interests
• Non-executive director of Ivoclar
Vivadent AG, Germany
Age 58 Nationality Austrian and British
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, which is an
NGO that promotes intercultural learning.
Dame Angela Strank
BP chief scientist and head of
technology, downstream
Executive team tenure
Appointed 1 September 2018
Outside interests
• Non-executive director of Severn Trent plc
• Fellow of the Royal Society
• Fellow of the Royal Academy of Engineering
• Honorary Fellow of the Energy Institute
• Honorary Professor of Earth Sciences,
University of Manchester
Age 66 Nationality British
Career
Dame Angela Strank is responsible for
technology across BP’s petrochemicals,
refining, fuels and lubricants businesses.
As BP’s chief scientist she is accountable
for developing strategic insights from
advances in science and managing
technology capability in BP.
Dame Angela joined BP in 1982 as a geologist
in exploration and has held various technical
and commercial leadership roles across
upstream and downstream including: chief
financial officer lubricants (Americas), BP/
Statoil alliance manager Nigeria, business
development manager Angola, technology
vice president, and head of the BP group chief
executive’s office.
In 2010 Dame Angela won the UK First
Women’s Award in Science and Technology,
and in 2018 was the first woman to receive the
UK Energy Institute’s Cadman Award.
In 2017 Dame Angela was awarded a Dame
Commander of the Order of the British Empire
in Her Majesty the Queen’s Birthday Honours
List for services to the oil industry and women
in science, technology, engineering and
mathematics (STEM).
Dame Angela holds honorary degrees from
Royal Holloway University, London (DSc) and
the University of Bradford.
65
Corporate governanceBP Annual Report and Form 20-F 2018 Executive management teams
Upstream
1. David Campbell
President, BP Russia
2. William Lin
Chief operating officer,
upstream regions
3. Murray Auchincloss
Chief financial officer
4. Gordon Birrell
Chief operating officer, production,
transformation and carbon
5. Kerry Dryburgh
Head of human resources
6. Nigel Jones
Associate general counsel
7. Andy Hopwood
Chief operating officer,
upstream strategy
8. Bernard Looney
Chief executive
9. Tony Brock
Head of safety and
operational risk
10. James Dupree
Chief operating officer,
developments and technology
1
3
6
5
8
10
4
2
7
9
Other business and functions leaders
1. Steve Fortune
Chief information officer, information
technology and services
4. Geoff Morrell
Group head of communications
and external affairs
2. Craig Marshall
Group head of investor relations
3. Camille Drummond
Vice president of global
business services
5. David Anderson
Chief financial officer,
alternative energy
6. Trudi Charles
Associate general counsel,
integrated supply and trading
and BP shipping
7. Nick Wayth
Chief development officer,
alternative energy
8. David Jardine
Group head of audit
10. Joan Wales
Head of safety and operational
risk, other businesses and corporate
11. Jan Lyons
Group head of tax
9. David Bucknall
Group controller and chief financial
officer, other businesses and corporate
3
2
4
1
7
6
9
8
11
66
5
10
BP Annual Report and Form 20-F 2018 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 2019.
3. Tufan Erginbilgic
Chief executive
4. Evelyn Gardiner
Head of human resources
5. Doug Sparkman
Chief operating officer,
fuels, North America
6. Rita Griffin
Chief operating officer,
petrochemicals
7. Michael Sosso
Associate general counsel,
downstream and BP shipping
8. Mike O’Sullivan
Chief financial officer
9. Andy Holmes
Chief operating officer,
fuels ASPAC and Air BP
10. Angela Strank
Head of technology and
BP chief scientist
2
3
7
5
8
10
Downstream
1. Mandhir Singh
Chief operating officer,
lubricants
2. Guy Moeyens
Chief operating officer, fuels,
Europe and Southern Africa
1
4
6
9
Other business and functions leaders
12. David Windle
Head of solar and renewable products,
alternative energy
15. Dominic Emery
Vice president, group
strategic planning
18. Alan Haywood
Chief executive officer, integrated
supply and trading
13. Carol Howle
Chief executive officer, BP shipping and
chief operating officer, global oil,
integrated supply and trading
14. Ashok Pillai
Vice president, group reward
16. Mario Lindenhayn
Chief executive officer, biofuels,
alternative energy
17. Lucy Knight
Human resources vice president,
corporate business activities
and functions
19. Robert Lawson
Global head of mergers
and acquisitions
20. Laura Folse
Chief executive officer,
wind, alternative energy
21. Spencer Dale
Group chief economist
22. Rahul Saxena
Group ethics and compliance officer
23. Kate Thomson
Group treasurer
12
14
15
16
19
17
20
21
23
13
18
22
67
Corporate governanceBP Annual Report and Form 20-F 2018 Introduction from the chairman
BP’s culture is well grounded with the right
values and behaviours embedded by the
board and the senior leadership.
It is now nine months since I joined BP, initially as a non-executive
director. In that time, my experience has confirmed the very positive
impression of BP’s culture and values I arrived with. Based on my time
spent in the business, the values of safety, respect, excellence, courage
and one team are clearly embedded and genuinely lived. I see a culture
that is grounded, responsible and humble – by which I mean one where
people have confidence in their capabilities and the strategy, but not
complacency or arrogance, and with a strong desire to learn and develop.
I firmly believe that is the right combination for maintaining safe
operations, earning the trust of stakeholders and embracing the
challenges and opportunities the energy transition presents. A priority for
my chairmanship is to see that the board continues to help sustain and
evolve this positive culture by having the right capability around the table
and the right engagement with stakeholders outside the boardroom.
Board capability
BP’s board has evolved considerably during Carl-Henric Svanberg’s
tenure. Together we will look to continue its development and find
the right balance of continuity and renewal. In my letter on page 6,
I mentioned Dame Alison Carnwath and Pamela Daley joining the board
in 2018, and that this year we are losing the distinguished services of
Admiral Frank Bowman and Alan Boeckmann.
Ian Davis is now in his 10th year as a director and continues as our senior
independent director, having held this role since 2017. I have huge
respect and regard for Ian’s skills and experience and, to provide the
continuity that I believe is critical I have asked him to extend his service
to at least the AGM in 2020. Ian continues to demonstrate constructive
challenge and engagement both in the board and with executive
management. The board therefore retains complete confidence in Ian’s
independence and supports his re-election in this capacity.
Governance and remuneration processes
We have spent considerable time evaluating the work of the board and
its committees, for which we also brought in external expertise to
facilitate our discussions. This was a very valuable exercise and resulted
in a number of recommendations that I am considering with the board,
and certain changes to our ways of working have already been made.
Details of these changes will be included in a revised set of board
governance principles to be published later this year.
engagement it has with both our people and with our wider community
of stakeholders. As a board, we fully support this – it builds on the work
we already do, and we will continue to evolve and enhance this
engagement and provide more detail next year.
Our oversight of the significant risks (such as operational, compliance
and cyber security) facing BP continues. Both the audit committee and
the safety, ethics and environmental assurance committee (SEEAC)
continue to review these in depth and receive assurance from manage-
ment as to how they are understood and mitigated to the level of risk
acceptable to the board. In this regard, I want to once again pay tribute to
the exceptional service over many years of Alan Boeckmann and Admiral
Frank Bowman on the SEEAC and welcome Nils Andersen to the role of
SEEAC chair. Brendan Nelson continues to chair the audit committee
and brings enormous financial and regulatory experience and expertise
to the role. I also want to thank Sir John Sawers for all his work chairing
the geopolitical committee. John brings unique insight and experience to
his role and the committee does important work overseeing significant
political and related risks in key geographies where BP operates.
The nomination and governance committee continues to review the
skills that we need while always considering diversity and the need for
independent thinking and challenge. The committee will also continue to
review the size of the board to confirm that it is appropriate with a good
mix of skills, experience and knowledge and the ability to maintain
appropriate oversight of the executive team and provide constructive
challenge and support.
Executive remuneration remains a significant issue and we appreciated
the strong support that was given to our remuneration report at last
year’s AGM. This was the second year in which our three-year policy,
developed following extensive engagement with shareholders, was in
effect. Paula Reynolds is working with the remuneration committee in
implementing that policy this year and to develop the new three-year
policy for which shareholder approval will be sought in 2020. Paula is
currently in the process of reducing her directorship commitments
with other companies during 2019 to ensure that she can retain her
strong focus on chairing the remuneration committee.
You will see from Paula’s report on page 83 that the committee
continues to exercise appropriate discretion in relation to executive
remuneration. From 2019 we are linking BP’s progress towards one
of our emissions reduction targets to the remuneration of a significant
number of our employees, including executive directors.
Engaging with stakeholders
Remuneration is just one issue where I believe dialogue is invaluable,
and I will continue to encourage the board to meet with a range of
stakeholders, including investors, partners, and our people, and gain
first-hand experience of BP’s businesses and operations around the
world. Over the past year, board members visited BP operations in the
US, UK and Oman and individual members also took opportunities to
visit BP sites when travelling and pursuing their other interests and
business activities. Personally, I have already visited our operations in
several countries including in the UK, the US, China, Oman and the
Netherlands. I look forward to making many more visits this year and
sharing my observations and reflections in due course.
Finally, I am grateful to Bob, the executive team, our employees and my
colleagues on the board for all of their hard work, their commitment to
BP and for the way that they have so warmly welcomed me into the
company. I am excited for our future.
Looking outwards, there were changes to UK legislation and
governance requirements during 2018 that have now come into effect.
In particular, the board is required to understand more deeply the
Helge Lund
Chairman
68
BP Annual Report and Form 20-F 2018 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.
More information
See bp.com/governance for the board
governance principles.
D
e
l
e
g
a
t
i
o
n
Owners/shareholders
BP board
Nomination
and governance
committee
See page 86
Remuneration
committee
See page 87
Chairman’s
committee
See page 85
Geopolitical
committee
See page 84
Audit
committee
See page 75
Safety,
ethics and
environment
assurance
committee
See page 81
Strategy/group risks/annual plan
Group chief executive
Group chief executive’s delegations
Executive management
Group
operations
risk committee
(GORC)
Group financial
risk committee
(GFRC)
Group
disclosure
committee
(GDC)
Group people
committee
(GPC)
Group ethics
and compliance
committee
(GECC)
Resource
commitments
meeting (RCM)
Group renewal
committee
Board and committee attendance
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
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 (if
relevant)
• Independent
advice (if
requested)
• Independent
assurance (as
needed)
y
t
i
l
i
b
a
t
n
u
o
c
c
A
Board
Audit
committee
SEEAC
Joint audit/
SEEAC
Remuneration
committee
Geopolitical
committee
Nomination
and governance
committee
Chairman’s
committee
Non-executive directors
Carl-Heneric Svanberg
Nils Andersen
Paul Anderson
Alan Boeckmann+
Frank Bowman
Alison Carnwath
Pamela Daley
Ian Davis
Ann Dowling
Helge Lund+
Melody Meyer
Brendan Nelson+
Paula Reynolds+
John Sawers+
Executive directors
Bob Dudley
Brian Gilvary
A
9
9
4
9
9
5
4
9
9
4
9
9
9
9
A
9
9
A
7
5
2
9
9
B
9
8
4
7
9
5
3
9
9
4
8
9
8
8
B
9
9
B
A
B
A
B
A
B
A
6
4
2
9
8
1
2
6
6
6
6
6
1
2
4
6
6
6
6
4
1
4
4
3
1
4
4
4
4
4
4
1
2
3
2
1
4
4
4
3
4
7
7
3
7
7
2
1
4
4
4
4
5
7
3
7
7
B
2
1
4
4
4
4
A
3
3
3
3
2
3
3
B
3
3
3
3
2
1
3
A
6
6
4
6
6
2
1
6
6
1
6
6
6
6
A = Total number of meetings the director was eligible to attend.
B = Total number of meetings the director did attend.
+ Committee chair.
Nils Andersen missed a board meeting due to a pre-existing external commitment.
Alan Boeckmann missed meetings of the board due to unforeseen personal circumstances.
Pamela Daley missed a board meeting due to a pre-existing external commitment.
Melody Meyer missed a board meeting due to other commitments.
Paula Reynolds missed a board meeting due to a pre-existing external commitment.
John Sawers missed a board meeting due to other commitments.
B
6
4
4
4
6
2
1
6
6
1
6
6
6
6
69
Corporate governanceBP Annual Report and Form 20-F 2018 Board activity in 2018
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 in 2018 included:
1Active consideration and direction
Active consideration and direction
1
of long-term strategy and approval
of long-term strategy and approval
of the annual plan
of the annual plan
Monitoring of BP’s
Monitoring of BP’s
performance against the
performance against the
strategy and plan
strategy and plan
Ensuring that the principal risks and
Ensuring that the principal risks and
uncertainties to BP are identified and that
uncertainties to BP are identified and that
systems of risk management and control
systems of risk management and control
are in place
are in place
Board and executive
Board and executive
management
management
succession
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.
The board also held several
long-term strategy sessions
covering upstream, downstream
and the future plans for the
integrated supply and trading
function that supports them.
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 subsequent
allocation of risks to the board
and monitoring committees
(the audit, SEEA and
geopolitical committees) for
2018, 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 board meeting.
The board monitored the
company’s performance against
the annual plan for 2018 and
approved the forward framework
for the annual plan for 2019.
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 2019. The group
risks allocated to the committees
for review over the year are
outlined in the reports of the
committees on pages 75-86.
Further information on BP’s
system of risk management is
outlined in How we manage risk
on page 53. Information about
BP’s system of internal control is
on page 110.
Performance and monitoring
The board reviews financial
and operational performance
at each meeting. It receives
regular updates on the group’s
performance for the year across
a range of metrics as well as the
latest view on expected full-year
delivery against external
scorecard measures. Updates
are also given on various
components of value delivery for
BP’s business. Regular reports
presented to the board include:
• Chief executive’s report.
• Group performance report.
• Group financial outlook.
• Effectiveness of investment
review.
Succession
The board, in conjunction with
the nomination and governance
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
2018 Egon Zehnder assisted
in the search for non-executive
directors. Egon Zehnder has
no other connection with the
company or individual directors.
• Quarterly and full-year results.
• Shareholder distributions.
The board reviews the quarterly
and full-year results, including
the shareholder distribution
policy. The 2018 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.
• Paul Anderson stood down
from the board at the 2018
AGM.
• Alison Carnwath was elected
as a director at the 2018 AGM.
• Helge Lund and Pamela
Daley joined the board in
July 2018 as non-executive
director and chairman
designate, and non-executive
director, respectively.
• Carl-Henric Svanberg stepped
down as non-executive
director and chairman of the
board effective 31 December
2018, succeeded by Helge
Lund with effect from
1 January 2019.
• Alan Boeckmann and
Frank Bowman will stand
down from the board at
the 2019 AGM.
70
BP Annual Report and Form 20-F 2018 Skills and expertise
In order to carry out its duties on behalf of shareholders, the board needs to manage its overall membership and continuously maintain its knowledge
and expertise to benefit the business. It does this through four activity sets:
Succession planning to
ensure future diversity
and balance
Diversity including skills,
experience, gender, ethnicity
and tenure
Training including
site visits and induction
of new directors
Evaluation
Background and diversity
Non-executive director Background
Oil and gas/
extractives/
energy
Engineering/
technology
Financial
expertise
Safety
Brand/
marketing/
reputation
Regulatory/
government
affairs
Diversity
Female
Non
UK/US
Tenure
(years)
Nils Andersen
Alan Boeckmann
Frank Bowman
Alison Carnwath
Pamela Daley
Ian Davis
Ann Dowling
Helge Lund
Melody Meyer
Brendan Nelson
Paula Reynolds
John Sawers
3
5
8
1
1
9
6
1
2
8
4
4
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 social and ethnic background.
The board operates a policy that aims to promote diversity in its
composition. Under this policy, director appointments are evaluated
against the existing balance of skills, knowledge and experience on the
board, with directors asked to be mindful of diversity, inclusiveness and
meritocracy considerations when examining nominations to the board.
Implementation of this policy is monitored through agreed metrics.
During its annual evaluation, the board considered diversity as part of
the review of its performance and effectiveness.
At the end of 2018, there were five female directors (2017 3, 2016 3)
on our board of 14. Our nomination and governance 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.
BP continues to take action to address the broader issue of diversity
within the group.
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 are independent.
The board is satisfied that there is no compromise to the independence
of, and nothing to give rise to conflicts of interest for, those directors
who serve together as directors on the boards of other entities or who
hold other external appointments. The nomination and governance
committee keeps the other interests of the NEDs under review to
ensure that the effectiveness of the board is not compromised.
Ian Davis is proposed for re-election notwithstanding he will be in his
tenth year as a non-executive director. Following careful consideration,
the board believes that Ian continues to provide constructive challenge
and robust scrutiny of matters that come before the board. Accordingly,
the board is satisfied that Ian continues to demonstrate the qualities of
independence in carrying out his role as senior independent director.
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.
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. The
board believes that, notwithstanding the NEDs’ other appointments,
they have sufficient time to fulfil their BP duties.
Executive directors are permitted to take up one board appointment
at an external listed company, subject to the agreement of the chairman.
71
Corporate governanceBP Annual Report and Form 20-F 2018 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 2017 evaluation and how these were
addressed included:
• Ongoing focus on capital allocation: the board continued to develop
and deepen its understanding of the capital allocation process and
the way in which investment decisions were taken.
• Longer term vision and strategy: the board held three ‘deep dive’
discussions to explore the group’s longer-term vision and strategy,
including challenges in BP’s core businesses as well as the transition
to a lower carbon economy.
• Employee views on safety and culture: the board developed a greater
understanding of employee views within the group, particularly
through review of more detailed data from the annual Pulse Survey,
by using the Technology Advisory Council (TAC) reports and through
site visits, town halls and employee engagement forums.
• International advisory board: the board reviewed the relationship
between the board, the geopolitical committee and the international
advisory board (IAB). Directors were invited to IAB dinners to hear the
debate on broader issues.
2018 evaluation
The evaluation was undertaken through a questionnaire facilitated by
an external consultant (Independent Audit) and individual interviews
between the consultant and the chairman and each director and other
executives. The results of the evaluation and feedback from the
interviews were collectively discussed by the board and will be
incorporated into a revised version of the board governance principles
that will be published later this year.
Fees received for an external appointment may be retained by the
executive director and are reported in the directors’ remuneration report
(see page 87). 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 2018, the
board continued to receive training on ethics and compliance.
NEDs are expected to visit at least one business a year as part of their
learning programme. In 2018, the board as a whole visited operations
at the Khazzan gas field in Oman. Members of the SEEAC and other
directors also visited the Cooper River petrochemicals plant in the US
and the Thunder Horse platform in the Gulf of Mexico.
Newly appointed NEDs follow a structured induction process. In 2018,
Helge Lund, Alison Carnwath and Pamela Daley all participated in the
induction programme, which includes one-to-one meetings with
management and the external auditors and other management who
support the board and committees. Pamela Daley’s induction is set out
below as an example.
Director induction programme
I deeply appreciate the
quality of the BP induction
programme and the BP
team’s dedication to
educating me.
Pamela Daley
Non-executive director
Pamela Daley, appointed in 2018, followed a
tailored induction process. The programme
of topics included:
Board and governance
• BP’s board governance
model, directors’ duties,
interests and potential
conflicts.
Business introduction
• Alternative energy
• BP’s business
• BP’s performance relative
to competitors
• Downstream (refining,
marketing and lubricants)
• Integrated supply and
trading (IST)
• Lower carbon transition
• Strategy
• Financial planning
• Upstream (exploration,
development, production,
overview of our operations)
Functional input
• Communications and
corporate reporting
• Ethics and compliance
• External audit
• Finance
• Human resources, including
capability and reward
• Legal, including litigation
• Safety
• Treasury
• Tax
Audit committee specific
• Reporting and disclosure
• Business ‘deep dives’
including IST risks and
compliance and procurement
• Cyber security and trading
regulations.
72
BP Annual Report and Form 20-F 2018 Site visits
NEDs visit at least one business every year to help deepen their operational understanding.
In 2018, the board visited the Khazzan gas field in Oman and the International Centre for
Advanced Materials (ICAM), of which BP is a significant sponsor, at the University of
Manchester. Members of the SEEAC and other directors visited upstream and downstream
operations in the Gulf of Mexico and South Carolina respectively. The board met local
management and were briefed at each visit and subsequently provided their feedback to the
appropriate committee and to the board.
A number of non-executives took the opportunity to engage directly with the local workforce
as described below.
Khazzan, Oman
The board visited the Khazzan gas field in
Oman, touring the facility and meeting with
local staff. They experienced the scale of the
field first hand following start-up of the project.
They also visited the new residential camp
offices and accommodation, and spent time
in the central processing facility control room.
They met site staff over lunch and concluded
their visit by meeting a local tribal leader who
had been instrumental in securing community
support for the Khazzan development.
Manchester, UK
In May the board attended the ICAM, where
they met with leading academics to better
understand how investment in research is
helping advance fundamental understanding
and use of materials across a variety of energy
and industrial applications.
Thunder Horse, US
SEEAC and the audit committee chair visited
Thunder Horse in July. Their trip included a
half-day session with the Gulf of Mexico
upstream leadership team followed by a day
offshore. The regional president led the site
visit and facilitated thorough discussion of
working practices, the risks and challenges
faced on site and management of those risks.
The visit demonstrated the safety culture on
board the rig.
Cooper River, US
In September members of the SEEAC and
other directors visited Cooper River, BP’s
petrochemicals plant in South Carolina.
Board members met with site leaders and
discussed business emergency continuity
planning, safety, risk and operating culture
at the plant. They also heard about new
sustainability-related technologies.
Workforce engagement
Melody Meyer visited the Muscat office in
March to meet with women from BP Oman,
as part of an empowering women in business
event. She advocated helping and supporting
women saying, “we all have a part to play
in this, we can help ensure our female
colleagues’ voices are heard.” Melody
highlighted the need to focus on driving value,
creating advantage from change, showing
respect and valuing contribution.
Melody also conducted a town hall at our
Houston office in July and Paula Reynolds led
a BP woman’s international network event at
BP’s London head office in December.
Houston, US
Alongside the SEEAC visit in July, members
of the board also spent time in the Houston
office, following the damage caused by
Hurricane Harvey in 2017. They spent time
with BP’s US-based integrated supply and
trading team and learned about the execution
of business continuity planning following
Harvey. They visited key group monitoring,
communication and response centres across
multiple businesses.
73
Corporate governanceBP Annual Report and Form 20-F 2018 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 2018 the chair of
the remuneration committee undertook extensive engagement on
the application of the remuneration policy prior to the AGM in May
(see the remuneration committee report on page 83). Helge Lund also
held one-to-one meetings with 14 major institutional investors during
the last quarter of the year prior to him becoming the chairman.
Senior management regularly meets with institutional investors
through road shows, 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 investors
to share their views directly with NEDs.
More information
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 2018
• Fourth quarter and full year 2017 results and
strategy update
• Investor roadshows with executive management
– fourth quarter and full year 2017 results
• BP Energy Outlook presentation
• US SRI meetings on remuneration
• Investor meetings on remuneration, continuing
into Q2
• BP Annual Report 2017 launch
• BP Sustainability Report 2017 launch
• BP Technology Outlook launch
• Chairman and board committee chairs meetings
• UKSA (retail shareholders’) meeting with
the chairman
• First quarter 2018 results presentation
• Annual general meeting
• Advancing the Energy Transition launch
• BP Statistical Review of World Energy launch
• Second quarter 2018 results presentation
• Investor roadshows with executive management
following 2Q results
• Third quarter 2018 results presentation
• Upstream investor day in Oman
Q1
Q2
Q3
Q4
74
Retail investors
BP held a further event for retail investors in conjunction with the UK
Shareholders’ Association (UKSA) in 2018. 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 increased in 2018 to 67.3% (of issued share capital,
including votes cast as withheld), compared to 50.8% in 2017 and
64.3% in 2016.
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 2018 with the provisions of the 2016 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
and governance 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.
BP remains cognizant of the new UK Corporate Governance Code and
will report accordingly in our 2019 Annual Report and Form 20-F. A copy
of the UK Corporate Governance Code is available at frc.org.uk.
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.
Membership of the IAB in 2018 comprised Lord Patten of Barnes, Josh
Bolten, President Romano Prodi, Dr Ernesto Zedillo, John Key and Dr
Javier Solana. The chairman, chief executive and Sir John Sawers
attend meetings of the IAB. Issues discussed in 2018 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 2018.
BP Annual Report and Form 20-F 2018 Committee reports
Audit committee
The committee continued to monitor the
group’s system of internal control, risk
management and work of key functions
as well as reviewing and challenging as
appropriate the disclosures and key
judgements made by management.
Chairman’s introduction
As in previous years, 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 2018 the committee focused on the effectiveness of a number of
group functions including integrated supply and trading, procurement,
tax, information technology and security, and shipping. We also received
presentations regarding, and reviewed performance of, the Upstream
segment and the lubricants business. These reviews were valuable in
not only informing the committee of the work and future plans of those
functions and businesses but also examining the key risks (and
associated mitigations) faced by each of them. In addition, the
committee carried out reviews into the group risks of financial liquidity,
cyber security and compliance with business regulations.
The transition to Deloitte from EY was completed in 2018. We met with
both EY and Deloitte during 2018 as the transition occurred and oversaw
and monitored Deloitte’s work as they settled into their role. We meet
regularly with the lead audit partner.
Nils Andersen retired from the committee in September 2018 as he
joined the SEEAC. I would like to thank Nils for his service to the
committee, and for the challenge and perspective he provided as a
member. We were very pleased to welcome Dame Alison Carnwath
to the committee in May 2018 with Pamela Daley also joining in October
2018. Each of them bring excellent financial and other relevant skills to
the committee.
Brendan Nelson
Committee chair
Role of the committee
The committee monitors the effectiveness of the group’s financial
reporting, systems of internal control and risk management and the
integrity of the group’s external and internal audit processes.
Key responsibilities
• Monitoring and obtaining assurance that the management or
mitigation of financial risks is appropriately addressed by the group
chief executive and that the system of internal control is designed
and implemented effectively in support of the limits imposed by
the board (‘executive limitations’), as set out in the BP board
governance principles.
• Reviewing financial statements and other financial disclosures and
monitoring compliance with relevant legal and listing requirements.
• Reviewing the effectiveness of the group audit function, BP’s
internal financial controls and systems of internal control and risk
management.
• Overseeing the appointment, remuneration, independence and
performance of the external auditor and the integrity of the audit
process as a whole, including the engagement of the external auditor
to supply non-audit services to BP.
• Reviewing the systems in place to enable those who work for BP to
raise concerns about possible improprieties in financial reporting or
other issues and for those matters to be investigated.
Members
Brendan Nelson
Nils Andersen
Member since November 2010 and chair
since April 2011
Member since October 2016; resigned
September 2018
Alison Carnwath
Member since May 2018
Pamela Daley
Member since October 2018
Paula Reynolds
Member since May 2015
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 nine committee meetings in 2018, of which three were by
teleconference. All directors attended every meeting during the period
in which they were committee members, except for Nils Andersen,
Alison Carnwath and Paula Reynolds who all missed a meeting each
due to pre-existing external commitments. Regular attendees at the
meetings include the chief financial officer, group controller, chief
accounting officer, group head of audit, group general counsel and
external auditor.
75
Corporate governanceBP Annual Report and Form 20-F 2018 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 results
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
operational events, and
Risk reviews
The principal risks allocated to the
audit committee for monitoring in
2018 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, such as emissions
trading and impacts on the
control environment.
The committee further
considered updates in the
76
See Glossary
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 control over financial
reporting. 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:
and compliance functions,
development of the anti-bribery
and corruption elements of
the programme, enhanced
policies, tools and training and
strengthening of counter-party risk
measures, including due diligence.
The committee also reviewed key
areas of BP’s legal function that
advise on compliance matters.
Cyber security risk: including
inappropriate access to or misuse
of information and systems and
disruption of business activity.
The committee reviewed ongoing
developments 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.
Financial liquidity: 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 .
These assumptions also impacted
financial reporting (see page 79).
BP’s principal risks are listed on
page 55.
For 2019, the board has agreed
that the committee will continue
to monitor the same four group
risks as for 2018.
Other reviews
• Oil and gas reserves.
• Pensions and post-retirement
Other reviews undertaken in 2018
by the committee included:
benefits assumptions.
• Risk factors.
• Legal liabilities.
• Tax strategy.
• Going concern.
• IFRS 16 (lease accounting).
integrated supply and 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 the
group’s ethics and compliance
programme, including the work of
the business integrity and ethics
• Lubricants: 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 tangible and 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).
• Tax: including strategy and
strategic progress, key
drivers of the group’s effective
tax rate, the global indirect tax
environment and the tax
modernization programme.
• Procurement: including strategy
and strategic progress, financial
performance, risk management
and controls, audit findings, key
litigation and ethics and
compliance findings.
• 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
2018 annual cash bonus
scorecard and performance
share plan, including
adjustments to plan conditions
and NOIs.
• Auditor transition: regular
reports from the external
auditor regarding its transition
into the role including detailed
updates on issues identified by
the external auditor.
• Internal controls: assessments
of management’s plans to
remediate the external auditors
findings in relation to IT access
risks.
BP Annual Report and Form 20-F 2018 Inte rnal control and risk management
The committee received
quarterly reports on the findings
of group audit in 2018. The
committee met privately with
the group head of audit and key
members of his leadership team.
The committee reviewed the
effectiveness of internal audit.
The audit committee also held
private meetings with the group
ethics and compliance officer
during the year.
Training
The committee held a review on reserves and pensions. It received
technical updates from the chief accounting officer on developments
in financial reporting and accounting policy, in particular regarding the
introduction of IFRS 16 ‘Leases’ accounting from the start of 2019.
Integrated supply and trading visit
In October, the committee held its meeting at BP’s integrated supply
and trading (IST) business in London and conducted its annual tour
of the business which 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 2018 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.
The group income statement includes a
pre-tax charge of $1.2 billion in relation to the
Gulf of Mexico oil spill.
Disclosure includes information on
remaining uncertainties.
The audit committee noted that following
the significant number of BEL claim
settlements in the year, the degree of
judgement necessary to determine the
year-end provision had reduced significantly.
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.
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.
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’, including certain Gulf of Mexico
licences which expired in 2013 and 2014.
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.
Exploration write-offs totalling $1.1 billion
were recognized during the year.
BP remains committed to developing the
Gulf of Mexico licences and believes it is
appropriate to continue to capitalize the
costs.
Exploration intangibles totalled $16.0 billion
at 31 December 2018.
77
Corporate governanceBP Annual Report and Form 20-F 2018 Key judgements and estimates
in financial reporting
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.
Investment in Rosneft
Audit committee activity
Conclusions/outcomes
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.
The group’s long-term price assumptions for
Brent
oil, and Henry Hub gas were
unchanged from 2017.
The group’s discount rates used for
impairment testing were also unchanged.
Impairments of $0.1 billion were recorded in
the year, net of impairment reversals.
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 2018 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.
Derivative financial instruments
For its level 3 derivative financial instruments,
BP estimates their fair value 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.
Considered IFRS guidance on evidence
participation in policy-making processes.
Received reports from management which
assessed the extent of significant influence,
including BP’s participation in decision
making.
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
level 3 derivative financial instruments,
using models where observable market
pricing is not available.
The committee annually reviews the control
process and risks relating to the trading
business.
BP has assets and liabilities of $3.6 billion and
$3.1 billion respectively recognized on the
balance sheet for level 3 derivative financial
instruments at 31 December 2018, mainly
relating to the activities of the integrated
supply and trading function (IST).
BP’s use of internal models to value certain
of these contracts has been disclosed in
Note 30 in the financial statements.
78
See Glossary
BP Annual Report and Form 20-F 2018 Audit committee activity
Conclusions/outcomes
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, including the change
to use the nominal discount rate (i.e. taking
account of expected inflation) from the
second quarter of 2018.
Decommissioning provisions of $13.6 billion
were recognized on the balance sheet at
31 December 2018.
The discount rate used by BP to determine
the balance sheet obligation at the end of
2018 was a nominal rate of 3% – based on
long-dated US government bonds.
The impact of this revised rate has been
disclosed.
Key judgements and estimates
in financial reporting
Provisions
BP’s most significant provisions relate to
decommissioning, environmental remediation
and 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.
Following a regular review of decommissioning
cost estimates, from 30 June 2018 the present
value of the decommissioning provision was
determined by discounting the estimated cash
flows expressed in expected future prices, i.e.
taking account of expected inflation. Prior to
30 June 2018, the group estimated future cash
flows in real terms.
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.
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
2017. 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 24.
At 31 December 2018, surpluses of $6.0 billion
and deficits of $8.4 billion were recognized on
the balance sheet in relation to pensions and
other post-retirement benefits.
External audit
Audit risk
The external auditor set out its audit strategy for 2018, identifying
significant audit risks to be addressed during the course of the audit.
These included:
• The risk of impairment in certain cash-generating units which are
particularly sensitive to changes in the key assumptions, in particular
the long-term oil and gas price assumptions.
• The carrying value of certain exploration and appraisal assets where
there could be potential indicators of impairment through licence
expiry and/or partner withdrawal.
• Accounting for structured commodity transactions in the integrated
supply and trading function.
• Level 3 of derivative financial instruments valuations within the
integrated supply and trading function which involve using bespoke
valuation models and/or unobservable inputs.
• Management override of controls.
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 $42 million (2017 $47
million), of which 5% was for non-audit assurance work (see Financial
statements – Note 36). The audit committee is satisfied that this level of
fee is appropriate in respect of the audit services provided and that an
effective audit can be conducted for this fee. Non-audit or non-audit
related assurance fees were $2 million (2017 $3 million). Non-audit or
non-audit related services consisted of other assurance services.
79
Corporate governanceBP Annual Report and Form 20-F 2018 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.
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
auditor 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 considered for permitted non-audit services only when its
expertise and experience of the company is important.
Approvals for individual engagements of pre-approved permitted
services below certain thresholds are delegated to the group controller
or the chief financial officer. 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 accountant’s fees and
services on page 301. The committee’s policies were updated in 2018
to clarify the engagement of the incoming auditor, Deloitte, and the
outgoing auditor (and auditor of Rosneft) EY.
Committee evaluation
The audit committee undertakes an annual evaluation of its performance
and effectiveness.
2018 evaluation
For 2018, an external assessment was used to evaluate the work of the
committee as part of a wider review of the operation of the board as a
whole. The review concluded that it had performed effectively.
Areas of focus for 2019 include succession planning for membership of
the committee, a site visit to global business services Kuala Lumpur and
integrated supply and trading Singapore and a further review of capital
spending.
Audit effectiveness
The effectiveness, performance and integrity of the external audit
process was evaluated through separate surveys completed by
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 auditor’s performance:
• Robustness of the audit process.
• Independence and objectivity.
• Quality of delivery.
• Quality of people and service.
• Value added advice.
The 2018 evaluation was the last of EY as the outgoing auditor. It also
included certain questions about the effectiveness of the transition to
the incoming auditor, Deloitte. The results of the survey indicated that
the external auditor’s performance had remained largely consistent in
key areas compared with the previous year. Areas with high scores and
favourable comments included quality of accounting and auditing
judgement and the working relationship with management. Areas for
improvement were identified but none impacted on the effectiveness
of the audit. The results of the questions regarding auditor transition
indicated that management were confident that Deloitte would be
effective in their role. The results of the survey were discussed with
Deloitte for consideration in their 2018 audit approach.
The committee held private meetings with the external auditor during
the year and the committee chair met separately with the external
auditor and group head of audit at least quarterly.
The effectiveness of the external auditor is evaluated by the audit
committee. The committee assessed the new auditor’s approach to
providing audit services as the team undertook its first audit. On the
basis of such assessment, the committee concluded that the audit team
was providing the required quality in relation to the provision of the
services. The audit team had shown the necessary commitment and
ability to provide the services together with a demonstrable depth of
knowledge, robustness, independence and objectivity as well as an
appreciation of complex issues. The team had posed constructive
challenge to management where appropriate.
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. 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 became 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.
Deloitte confirmed its independence to the committee in October 2017.
EY resigned on 29 March 2018 following completion of the 2017 audit.
The committee also received reports from the external auditor’s
transition team in April, May and July 2018 and an update to their plan
in December 2018.
80
BP Annual Report and Form 20-F 2018 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
their 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.
Safety, ethics and environment
assurance committee (SEEAC)
At every site visit, we engage with the local
leadership who help to embed a culture
focused on operational risk mitigation.
Members
Alan Boeckmann
Member since September 2014 and chair
since May 2016
Nils Andersen
Member since December 2018
Paul Anderson
Member since February 2010; resigned May
2018
Frank Bowman
Member since November 2010
Ann Dowling
Member since February 2012
Melody Meyer
Member since May 2017
John Sawers
Member since July 2015
Meetings and attendance
There were six committee meetings in 2018. All directors attended
every meeting for which they were eligible, apart from Alan
Boeckmann who missed two meetings due to unforeseen personal
circumstances.
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 has
access to the chair and secretary to the committee as required. 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
receives invitations to join the private meetings on an ad hoc basis and
at least once a year the head of group audit and at least twice a year the
group ethics and compliance officer are invited to a private meeting
with the committee.
Chairman’s introduction
The committee’s focus continued to be on working with executive
management to drive safe, ethical and reliable operations. It
continued to provide constructive challenge as part of its review of
the executives’ management of the highest priority non-financial
group risks assigned to SEEAC. The risks under our remit remained
the same as for 2017: marine, wells, pipelines, explosion or release at
facilities, major security incidents and cyber security in the process
control network. The committee receives reports on each of these
risks and monitors their management and mitigation.
Following publication of the company’s second Modern Slavery
Act (MSA) statement in 2018, the committee again reviewed
related work practices in BP and will continue to review progress in
developing and embedding those practices. In 2018 it also reviewed
the BP Sustainability Report 2017.
The committee made two site visits in the year (see page 73). In July
members of the committee visited the Thunder Horse platform in the
Gulf of Mexico, and in September members visited Cooper River
petrochemicals plant in South Carolina. The level of access into the
operations on such visits gives the directors first hand and direct
insight. This framework provides an opportunity for meaningful and
open dialogue with the local site teams, allowing the committee to
better fulfil its obligations.
In May 2018, Paul Anderson retired from the board and the
committee. In preparation for my stepping down from the BP board
at the annual general meeting in May 2019, Nils Andersen, who was
appointed to the committee in December 2018, will assume the role
of the chair of SEEAC from April 2019.
Alan Boeckmann
Committee chair
81
Corporate governanceBP Annual Report and Form 20-F 2018 Activities during the year
System of internal control and risk management
The review of operational risk and
performance forms a large part of
the committee’s agenda.
Group audit provided quarterly
reports on their assurance work
and their annual review of the
system of internal control and risk
management.
The committee also received
regular reports from the group
chief executive and vice president
for S&OR on operational risk,
including regular reports prepared
on the group’s health, safety and
environmental performance and
operational integrity. These
included meeting-by-meeting
measures of personal and process
safety, environmental and
regulatory compliance, security
and cyber risk analysis, as well as
quarterly reports from group audit.
In addition, the group ethics and
Site visits
In July members of the
committee, and other directors,
visited the Houston office and
went offshore to Thunder Horse
in the Gulf of Mexico. The
Houston visit included time with
various teams understanding the
effects of Hurricane Harvey, how
central office-based functions
support the offshore community
and other group monitoring
teams. In preparation for the
offshore visit to Thunder Horse
the directors met with the Gulf of
Mexico leadership. Offshore,
there was a full tour of the asset
including control room, topsides
and drilling rig and plenty of
opportunity was provided to
converse with employees on the
rig. In September, committee
members, and other directors,
Corporate reporting
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.
visited the petrochemicals plant,
Cooper River, in South Carolina.
During the visit, directors were
able to discuss business
continuity planning and
emergency response which had
been in effect just prior to the
visit as a result of Hurricane
Florence. For all 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 reported
back in detail about each visit to
the committee and subsequently
to the board. See page 73 for
further details.
The committee was responsible
for the overview of the BP
Sustainability Report 2017. The
committee reviewed content and
worked with the external auditor
with respect to their assurance
of the report.
82
Committee evaluation
In 2018, the committee examined its performance and effectiveness
through an externally facilitated evaluation which included individual
interviews. Discussion focused on the responsibilities of the committee,
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 to both
inform and drive discussion.
The evaluation results continued to be 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. The committee agreed to
review its remit in 2019.
Site visits remained an important element of the committee’s work,
acknowledged through the responses in the evaluation process. These
gave members the opportunity to examine and witness risk
management processes embedded in businesses and facilities,
including the right 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).
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 2018, 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 2019 forward
programmes for the group audit and ethics and compliance
functions.
BP Annual Report and Form 20-F 2018 Remuneration committee
Chair’s introduction
As the new committee chair, I took the opportunity in the autumn to
engage with some of our institutional shareholders. In a changing
governance landscape, it has been important to ensure our stakeholders
continue to be heard.
We have reviewed the responsibilities of the committee and have
extended the scope to include oversight of remuneration below board
level.
We have continued to operate under the policy approved by
shareholders in 2017. Our focus for 2019 will of course be the
preparation of a new policy for approval by shareholders at the 2020
AGM. Pamela Daley has joined the remuneration committee from
1 January 2019. We welcome Pamela to the committee and look
forward to her valuable contribution.
PricewaterhouseCoopers LLP has continued as our independent
adviser following their appointment in 2017. PwC has other
engagements with the company to provide certain services none of
which are deemed material in this context.
Paula Rosput Reynolds
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.
The committee recognizes the remuneration principles applicable to all
employees below board level.
Key responsibilities
• Recommend to the board the remuneration principles and policy for
the chairman and the executive directors while considering policies
for employees below the board.
• Determine the terms of engagement, remuneration, benefits and
termination of employment for the chairman and the executive
directors, executive team and the company secretary in accordance
with the policy.
• Review the relevant remuneration principles and policies for
employees below the executive team.
• 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.
• Ensure termination terms and payments to executive directors and
the executive team are fair.
• Approve changes to the design of remuneration for BP group leaders,
as proposed by the group chief executive.
• Receive, and take into account as appropriate, regular updates on
workforce views and engagement initiatives related to remuneration.
• Ensure insight from data sources on pay ratio, gender pay gap and
other workforce remuneration outcomes are considered as
appropriate.
• Maintain appropriate dialogue with shareholders on remuneration
matters.
• Monitor the alignment of incentives and remuneration for all
employees below the executive team with the expected values and
behaviours.
• Engage independent consultants or other advisers as the committee
may from time to time deem necessary, at the expense of the
company.
Members
Paula Reynolds
Member since September 2017 and chair
since May 2018
Alan Boeckmann
Member since May 2015
Pamela Daley
Member since January 2019
Ian Davis
Member since July 2010
Ann Dowling
Member since July 2012 and chair since May
2015; resigned May 2018
Brendan Nelson
Member since May 2017
83
Corporate governanceBP Annual Report and Form 20-F 2018 Meetings and attendance
The chairman and the group chief executive attend meetings of the
committee except for matters relating to their own remuneration.
The group chief executive is consulted on the remuneration of the chief
financial officer, 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.
The committee met seven times during the year. All directors attended
each meeting that they were eligible to attend, either in person or by
telephone, except Alan Boeckmann who was not able to attend two
meetings due to unforeseen personal circumstances.
Activities during the year
In the period before the 2018 AGM, the committee focused on the
outcomes for 2017. This involved reviewing directors’ salaries and the
group’s performance outcome which in turn determined the annual
bonus and the performance share plan.
PwC has continued as independent adviser during 2018. The committee
continued to monitor developments in potential regulation and legislation
and resulting implications. 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 engagement with shareholders and proxy voting agencies
ahead of the 2018 AGM, carried out by the chair of the committee, the
chairman and company secretary as required. The new committee chair
continued engagement throughout the year, primarily with larger
shareholders and representative bodies, in light of evolving regulation
and related remuneration issues.
Committee evaluation
An externally facilitated evaluation was undertaken to examine the
committee’s performance in 2018. The evaluation concluded that the
committee had worked well and had responded to the previous
evaluation by increasing its remit to take on oversight of remuneration
below board level.
Focus areas for 2019 include responding to regulation and
governance reform and planning for the new remuneration policy
to be brought to shareholders for approval in 2020. The commitment
to stay focused on external developments and emerging ‘best
practice’ and improving remuneration reporting remained. See
page 87 for the Directors’ remuneration report.
84
Geopolitical committee
Chairman’s introduction
I am pleased to report on the work of the geopolitical committee in
2018, which continued to develop and evolve during the year. During
2018 I also joined discussions of the international advisory board.
Paul Anderson stood down in May 2018. I want to thank Paul for
his valuable contribution. We welcomed Nils Andersen to the
committee in August 2018 and his experience is invaluable given
he was CEO of major companies, such as Carlsberg and Mærsk,
which had operations in many jurisdictions with significant political
risk considerations. 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.
BP Annual Report and Form 20-F 2018 Members
John Sawers
Member since September 2015 and chair
since April 2016
Nils Andersen
Member since August 2018
Paul Anderson
Member since September 2015; resigned
May 2018
Frank Bowman
Member since September 2015
Ian Davis
Member since September 2016
Melody Meyer
Member since May 2017
Meetings and attendance
The chairman and group chief executive regularly attend committee
meetings. The executive vice president, regions and the vice president,
government and political affairs attend meetings as required.
The committee met four times during the year. All directors attended
each meeting that they were eligible to attend.
Chairman’s and nomination
and governance committees
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 existing
investments or is considering investment in detail. These included the
US, Russia, Mexico, Brazil, India and China.
It considered broader policy issues such as the US domestic and foreign
policy and the political and economic impact of a low oil price on
producing countries.
We reviewed the geopolitical background to BP’s global investments
and the politics around climate change.
Chairman’s introduction
The chairman’s and the nomination and governance committees were
actively involved in the evolution of the board in 2018. In October,
Carl-Henric Svanberg stood down as chairman of both committees
and I pay tribute to his exceptional service since 2010. The board
expanded the nomination committee’s remit in September 2018 to
help fulfil requirements provided in the new UK Corporate Governance
Code and it was re-named the nomination and governance committee.
It also continues to focus on board renewal and diversity as well as the
talent in the senior levels of executive management and development
of future leaders.
Committee evaluation
The committee reviewed its performance through feedback from the
external evaluation of its work and of the work of the board as a whole.
The evaluation concluded that the committee was working well and
considering the right issues. The committee currently meets four 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. This is being further considered during 2019.
Helge Lund
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.
85
Corporate governanceBP Annual Report and Form 20-F 2018 Meetings and attendance
The committee met six times in 2018. All directors attended all the
meetings for which they were eligible, except that Nils Andersen was
excused from two meetings due to a potential conflict of interest and
Alan Boeckmann missed two meetings due to unforeseen personal
circumstances.
Bob Dudley and Brian Gilvary joined meetings where the chairman’s
succession was discussed. Matters relating to the business of the
nomination and governance committee were also discussed at some
meetings.
Activities during the year
• Evaluated the performance of the chairman and the group chief
executive.
Nomination and governance committee
Role of the committee
The committee ensures an orderly succession of candidates for
directors and the company secretary and oversees corporate
governance matters for the group.
Key responsibilities
• Identify, evaluate and recommend candidates for appointment or
reappointment as directors.
• Review the outside directorships/commitments of the NEDs.
• Review the mix of knowledge, skills experience and diversity of the
board to ensure the orderly succession of directors.
• Identify, evaluate and recommend candidates for appointment as
• Considered the composition of and the succession plans for the
company secretary.
executive team.
• Discussed the strategy options for the company, including the
transition to a lower carbon future.
• Review developments in law, regulation and best practice relating to
corporate governance and make recommendations to the board on
appropriate actions to allow compliance.
Committee evaluation
The committee continues to work well. The balance of skills and
experience amongst its non-executive director membership ensures
it is best able to support and challenge the company as it implements
its strategy.
Members
Helge Lund
Carl-Henric
Svanberg
Member since July 2018 and chair since
September 2018
Member since September 2009 and chair
since January 2010; resigned as chair
September 2018 and from committee
December 2018
Alan Boeckmann
Member since April 2016
Ian Davis
Member since August 2010
Ann Dowling
Member since May 2015 and resigned May
2018
Brendan Nelson
Member since September 2018
Paula Reynolds
Member since May 2018
John Sawers
Member since April 2016
Meetings and attendance
The committee met three times in 2018. 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, except Paula Reynolds
due to pre-existing external commitments.
Activities during the year
The committee continued to monitor the composition and skills of the
board. The committee will continue to focus on ensuring that the board’s
composition is strong and diverse. During the year, it was agreed that
the committee would assume oversight of governance.
Committee evaluation
Following the board evaluation, it was agreed that the committee would
also focus on governance requirements arising from the new UK
Corporate Governance Code.
86
BP Annual Report and Form 20-F 2018 Directors’ remuneration report
Contents
90
2018 performance and
pay outcomes
91 2018 annual bonus outcome
92
2016-18 performance share
plan outcome
94 Alignment with strategy
95
Executive directors’ pay
for 2018
97 Wider workforce in 2018
100 Stewardship and executive
director interests
102 Non-executive director
outcomes and interests
104 Other disclosures
105 Executive director
remuneration policy and
implementation for 2019
109 Non-executive director
remuneration policy for 2019
Targets are strongly aligned with
the company’s strategic priorities,
they are ambitious and require
material effort to achieve outcomes.
Paula Rosput Reynolds
Chair of the remuneration committee
Dear shareholder,
Following extensive shareholder consultation
led by my board colleague Professor Dame
Ann Dowling, BP introduced our current
remuneration policy in 2017. Thus 2018
was our second year using this policy. The
remuneration committee believes the
structure remains fit for purpose, the targets
are strongly aligned with the company’s
strategic priorities, they are ambitious and
require material effort to achieve outcomes,
and the rewards conferred to date align with
our financial results and strategic progress.
Please refer to the ‘Remuneration at a glance’
table for an overview.
The policy delivers remuneration in three parts:
a market-aligned foundation of base salary,
benefits and retirement provision; annual
incentives based on measures that reflect our
strategy, assessed against targets that require
progressive improvement year-on-year; and a
material opportunity to earn shares at the end
of a three-year performance period, which is
accompanied by a shareholding requirement
to ensure our executive directors’ interests
align with your own. Of course it is not enough
to rely on a purely formulaic application of
policy. Therefore the committee engages in
a dialogue with Bob Dudley, Brian Gilvary and
our board colleagues, particularly those on
the safety, ethics and environment assurance
committee (SEEAC) and the main board audit
committee (MBAC) to test the reasonableness
of the outcomes. This dialogue ensures we are
well equipped to apply and explain discretion
and judgement as needed.
Results and progress in 2018
BP delivered another year of disciplined
execution in 2018, alongside further progress
against our five-year strategy to 2021.
Strong operating performance across all
our businesses has more than doubled
our underlying replacement cost profit to
$12.7 billion, with operating cash flow
excluding Gulf of Mexico oil spill payments
of $26.1 billion. BP distributed $8.1 billion in
dividends in 2018, and continued the share
buyback programme started in 2017 to offset
the dilutive effects of the scrip shares.
BP continues to play an active role in relation
to the energy transition. We are carefully
considering our mix of natural gas and oil, while
investing in new technology and businesses
that have the potential to contribute to a lower
carbon world through our ‘reduce, improve,
create’ framework.
Our acquisition of Chargemaster, the UK’s
largest electric vehicle charging company (see
page 42), and further expansion of the solar
company Lightsource BP (see page 47),
are among the most promising investments
consistent with our commitment to advancing
a lower carbon future.
At the same time we continue to sustain our
traditional business. Our organic reserves
replacement ratio for the year was 100%, and
our acquisition of BHP assets provides us with
significant new reserves and opportunities
for growth. We delivered a further six major
projects in 2018, bringing the total to 19 over
the 2016-18 cycle.
87
Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018 Remuneration at a glance
Key features
Purpose and link to strategy
Outcomes for 2018
Implementation in 2019
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• Salary is reviewed annually and, if
appropriate, increased following
the AGM.
• Relates to market and our wider
workforce.
• Fixed remuneration reflecting
• Bob Dudley’s salary unchanged
• Bob Dudley’s salary
the scale and complexity of our
business, enabling us to attract
and keep the highest calibre
global talent.
at $1,854,000.
to remain at $1,854,000.
• Brian Gilvary’s salary increased
• Brian Gilvary’s salary increased
by 2% to £775,000.
by 2% to £790,500.
• Benefits remain unchanged.
• Benefits remain unchanged.
• To recognize competitive
practice in home country.
• Bob is a member of both US
pension (defined benefit) and
retirement savings (defined
contribution) plans.
• Brian is a member of a UK final
salary defined benefit pension
plan, and receives a cash
allowance in lieu of further
service accrual.
• Bob’s defined benefit pension
did not increase in 2018. His
actual and notional company
contributions were more than
offset by investment losses
within his retirement savings
plans, hence he received no
net benefit in 2018.
• Brian’s accrued defined benefit
pension increase was below
inflation. He received a cash
allowance at 35% of salary,
which is included in the single
figure table.
• Arrangements for Bob will
continue unchanged.
• Brian has offered to accelerate
the scheduled reductions in
his cash allowance. These will
now reduce by 5% of salary at
each of 1 June 2019, 2020 and
2021, and a further 5% of
salary at 1 June 2023, taking
his cash allowance to 15%
of salary.
• These proposed changes
reduce Brian’s cash
supplement sooner than the
transition for other members
of the BP UK defined benefits
plan. He will not receive any
form of compensation related
to the reductions.
• 112.5% of salary at target, and
225% at maximum.
• To incentivize delivery of our
annual and strategic goals.
• 50% of the bonus is paid in cash
and 50% is mandatorily deferred
and held in BP shares for three
years.
• The 50% deferral reinforces
the long-term nature of our
business and the importance
of sustainability.
• Against our scorecard of safety
• We will include an
and operational risk (20%),
reliable operations (30%) and
financial performance (50%),
our performance score is 81%
of target (40.5% of maximum).
environmental target, weighted
at 10%, in our performance
scorecard for 2019.
• Annual grant of performance
• To link the largest part of
shares, representing the
maximum outcome.
– 500% of salary for group chief
executive.
– 450% of salary for chief
financial officer.
• Shares only vest to the extent
performance conditions are met.
remuneration opportunity with
the long-term performance of
the business. The outcome
varies with performance against
measures linked directly to
financial returns and strategic
priorities.
• Against our balanced scorecard
of financial measures (67%),
and strategic imperatives (33%),
our 2016-18 performance score
is 90.5% of maximum.
• The committee has exercised
discretion to reduce the actual
vesting outcome to 80%.
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• Awards granted in 2017 at
500% (group chief executive)
and 450% (chief financial
officer) of salary will vest in
proportion to success against
the measures of our 2017-19
scorecard.
• Awards granted in 2019 will be
granted at 500% (group chief
executive) and 450% (chief
financial officer) of salary.
• For awards granted in 2019,
strategic priorities will be
weighted at 30% (previously
20%) with return on average
capital employed reducing
to 20%.
• In 2019 we will engage with
stakeholders to review and
revise, as appropriate, our post
employment shareholding
policy for 2020 onwards.
• Executive directors are required
• To provide alignment between
• Both executive directors
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to maintain a shareholding
equivalent to at least five times
their salary.
• Additionally, they are expected to
maintain shareholdings of at least
two and a half times salary for two
years post employment.
the interests of executive
directors and our shareholders.
materially exceed the share
ownership requirements.
• The executive directors maintain
their commitment to retain
shareholdings of at least two
and a half times salary for two
years post employment.
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88
Directors’ remuneration report BP Annual Report and Form 20-F 2018
Performance and remuneration outcomes in 2018
As we seek to incentivize year-on-year improvement, the committee
set stretching targets for the 2018 annual bonus scorecard. Therefore,
despite the strong business results for the year, we assessed 2018
performance as below plan, at 81% of target (40.5% of maximum).
Following our discussions with SEEAC and MBAC, we found no reason
to adjust this formulaic scorecard outcome. Half of the bonus for the
executive directors will be delivered as shares and held for three years.
2018 was the final year of the 2016-18 performance share award, the
last grant under our 2014 policy, with financial and strategic measures
as shown in the table on page 93. BP again ranked first place on relative
TSR, delivered robust operating cash flow, and exceeded maximum
expectations for major project delivery. These strong results across the
range of measures led to a formulaic vesting outcome of 90.5% of
maximum.
The foregoing results, including TSR, cash flow, and project execution,
were delivered alongside an almost 50% return to shareholders over the
same three-year period. Thus, there is directional alignment between
executives and shareholders. However, the formula from which the
outcome was calculated originated in the 2014 plan which we
substantially revised in 2017. The committee recognized that merely
applying a dated formula might not best serve the interests of the
stakeholders. Therefore, despite the clear value delivered to
shareholders and the relatively muted annual bonus outcome, we
concluded we should apply downward discretion on the executive
directors’ long term award outcomes. We will vest the 2016-18
performance shares at 80% rather than at the 90.5% formulaic
scorecard outcome.
In exercising our judgement we have opted to apply the more
challenging scales of our 2017 policy in measuring performance
outcomes relating to operating cash flow, major project delivery and
safety and operational risk. This adjustment brings the 2016 vintage
EDIP outcome into harmony with the policy that was approved by
shareholders in 2017. This adjustment reduced 2018 incentive pay by
$1.45 million for Bob and £0.54 million for Brian.
In addition, the committee has again acted on Bob’s request to re-base
his 2016-18 award from its original 550% grant level to the 500% of
salary grant level established in the 2017 policy. This adjustment
reduces Bob’s vesting outcome by a further $1.10 million, thus reducing
his incentive pay by $2.70 million overall.
The single figures of total remuneration for Bob and Brian are $14.67
million and £7.98 million respectively, as reported on page 95. This
represents a 3% decrease for Bob, reflecting significant reductions
in both his annual bonus and the investment return on his retirement
savings, partly offset by an increase attributable to share price growth.
For Brian, this represents a 12% increase, largely due to vesting of
deferred awards from his 2015 bonus, and the increase attributable to
share price growth. In our committee deliberations, we considered
these outcomes and believe they are appropriate given the operational
and financial performance of BP this year and the tremendous recovery
that BP has made over the past three years.
Looking ahead to 2019
We recently announced our support for a shareholder resolution at
the 2019 annual general meeting that would broaden our corporate
reporting to describe how our strategy is consistent with the goals of
the Paris Agreement. We welcome this resolution as an opportunity
to provide further detail on our strategy and on our attractiveness as
an investment proposition in the energy transition, and for continued
investor engagement. We believe that all constituencies will be well
served by our increasing the target financial rewards relating to how
we navigate the low-carbon transition. To this end, we have introduced
a greenhouse gas emissions reduction measure for our 2019 bonus
scorecard. This means that 10% of the outcome will now reflect our
progress in emissions reduction (consequently reducing slightly the
relative weighting of other customary measures in our bonus plan).
The 2019-21 performance share plan scorecard will continue to focus
on relative total shareholder return, absolute returns on average capital
employed over the three years, and a focused suite of strategic progress
measures. To better reflect the importance of strategic progress,
which includes BP’s role in the energy transition, we are increasing
the weighting of this measure from 20% to 30%, while reducing the
returns measure from 30% to 20%.
Following our review of their total remuneration, we have decided to
keep Bob’s salary unchanged, and propose to increase Brian’s salary
by 2% from the date of the AGM. We have also agreed to accelerate
the reductions to the cash supplement Brian receives in lieu of further
defined benefit pension service accrual, which will now start from
1 June 2019.
More broadly, our committee activity in 2019 has included a review of
the committee charter, approving remuneration decisions in respect of
the executive team, deepening our understanding of wider workforce
remuneration and adopting other measures as appropriate under the
revised UK Corporate Governance Code, including an examination of
the implications of pay and benefits differences across the workforce.
We will be reviewing BP’s strategic progress in the context of share
programmes approved under the 2017 policy, in particular progress
related to the challenges of a lower carbon world. These evaluations
will take time and thoughtful discussion and will lead in to the important
business of engaging with our major shareholders and representative
bodies ahead of our new policy approval in 2020. In that regard, we will
be consulting widely on the ways in which we reflect the strategic
imperatives of the company within a competitive global remuneration
structure.
Paula Rosput Reynolds
Chair of the remuneration committee
29 March 2019
In this Directors’ remuneration report RC profit (loss), underlying
RC profit, return on average capital employed, operating cash
flow excluding Gulf of Mexico oil spill payments are non-GAAP
measures. These measures and upstream plant reliability, refining
availability, major projects and underlying production and reserves
replacement ratio are defined in the Glossary on page 315.
89
Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018 Business
performance
A year of exceptional operational performance, with record plant reliability in the Upstream and refining throughput in
the Downstream. Improvement across virtually all safety measures, growth in our retail business and delivery of six
major projects. Profits have more than doubled, with an 11.2% return on capital, and strong foundations for continuing
returns over the near and long term.
Key strategic highlights
• $12.7 billion underlying replacement cost profit.
• Transformation of our US onshore business.
• Six new major projects delivered.
1st
Among peers for total
shareholder return for
2016-18.
$26.1bn
Operating cash flow
excluding Gulf of Mexico
oil spill payments.
$8.1bn
Dividends paid,
including scrip.
Performance outcomes
Robust results for the year fell short of our stretching targets, particularly on cash flow. On a three-year basis,
2018 concluded a remarkable period of delivery and preparation for the future.
Annual bonus
40.5%
Formulaic outcome
(% of maximum)
Performance shares
0%
Committee judgement,
no adjustment
40.5%
Final outcome
(% of maximum)
90.5%
Formulaic outcome
(% of maximum)
-10.5%
Committee judgement
to reduce vesting
80%
Expected outcome after
committee discretiona
(% of maximum)
Performance measures
(% weighting)
Nil
Maximum
Performance measures
(% weighting)
Nil
Maximum
Safety
Tier 1 process safety events (10%)
Recordable injury frequency (10%)
Reliability
Downstream refining availability (15%)
BP-operated upstream plant
reliability (15%)
Financial
Operating cash flow (excluding Gulf
of Mexico oil spill payments) (20%)
Underlying replacement cost profit (20%)
Upstream unit production costs (10%)
KPI
KPI
KPI
KPI
KPI
KPI
KPI
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%)
KPI
KPI
KPI
KPI
KPI
KPI
a The final outcome for part of this award is based on BP’s relative RRR ranking. This is forecast
at second place but cannot be confirmed until after publication of our peers’ reports. This final
outcome will be reported in our 2019 report.
KPI This symbol denotes remuneration measures that directly relate to the key performance indicators of our investor proposition – see page 16.
Remuneration outcomes
Reduced annual bonus and pension, partly offset by increases in performance share vesting, lead to a reduction
for Bob. The increase for Brian reflects increases in the values of performance and deferred share vesting.
Bob Dudley, group chief executive
Total remuneration
Brian Gilvary, chief financial officer
Total remuneration
2018
2017
2016
2015
2014
$14.7m
$15.1m
$11.9m
$19.4m
$16.4m
2018
2017
2016
2015
2014
£8.0m
£7.1m
£4.2m
£5.1m
£3.6m
Salary and benefits
Retirement benefits
Annual bonus
Performance shares
Discontinued plans (see page 96 for descriptions)
Share ownership
This is a key means by which the interests of executive directors are aligned with those of shareholders. Both directors
have holdings in BP which significantly exceeded our shareholding policy requirement of five times salary.
Bob Dudley, group chief executive
Brian Gilvary, chief financial officer
Policy requirements (5x)
Actual
90
14.66 times salary, 3,718,074 sharesa, as at 15 March 2019
15.80 times salary, 2,248,905 shares, as at 15 March 2019
aHeld as ADSs
Directors’ remuneration report 2018 performance and pay outcomes2018BP Annual Report and Form 20-F 2018
For 2018 the committee established a bonus scorecard of seven
measures across three areas of focus: safety and operational risk,
reliable operations and financial performance. These measures align
with our strategy and, in particular, reflect the annual plan. Six of the
seven measures are identical to our 2017 scorecard. The seventh
measure, ‘BP-operated upstream plant reliability’, replaces ‘Upstream
operating efficiency’ from 2017, bringing unplanned downtime into
account which provides a closer comparison with the equivalent
measure for the Downstream.
To avoid windfall outcomes in our financial measures, and drive genuine
year-on-year improvement, we adjust our financial targets to reflect any
pricing impacts, i.e. the stronger oil price environment of 2018 led to a
proportional increase in our profit and cash flow targets. This is the
fourth occasion in the last seven years in which we have adjusted our
performance measurement to strip out positive price environments and
better reflect financial improvement in underlying terms. Unadjusted,
the scores would all have been significantly higher, leading to
remuneration outcomes greater than we would have intended.
In order to build on the strong results of 2017, the committee set notably
stretching targets for each of these measures. For instance, our 2018
threshold outcomes for safety performance were set at the level of our
2017 outcomes, meaning we had to exceed 2017 results to achieve
even a minimum contribution to the 2018 bonus.
Consequently, and despite another strong year of results and delivery
for shareholders, our bonus outcome for 2018 is 81% of target, or
40.5% of maximum, compared with 143% of target, or 71.5% of
maximum, in 2017.
Annual bonus
Scorecard
2018 annual bonus
REM
Measures used for the 2017 remuneration policy.
Safety
0.21
Reliable
operations
0.21
Financial
performance
0.40
KPI See key performance
indicators on page 16.
Formulaic score
0.81a out of 2.0
Measures
Weighting
Threshold (0)
Target (1)
Maximum (2)
Outcome
Safety (20% weight)
Tier 1 process safety events
(defined by API) KPI
Recordable injury
frequency KPI
Safety outcome
Reliable operations (30% weight)
Downstream refining availability
(Solomon Associates’
operational availability) KPI
BP-operated upstream
plant reliability KPI
Reliable operations outcome
15%
15%
Financial performance (50% weight)
Operating cash flow
(excluding Gulf of Mexico
oil spill payments) KPI
Underlying replacement
cost profit KPI
Upstream unit production
costs KPI
Financial performance outcome
Formulaic score
20%
20%
10%
10%
10%
19 events
0
16 events
0.1
12 events
0.2
16 events
0.10
0.219/200k hrs
0
0.200/200k hrs
0.1
0.164/200k hrs
0.2
0.198/200k hrs
0.11
94.8%
0
93.3%
0
$26.4bn
0
$11.4bn
0
$7.41/bbl
0
95.3%
0.15
95.3%
0.15
95.8%
0.3
97.3%
0.3
$28.9bn
0.2
$31.4bn
0.4
$12.2bn
0.2
$7.01/bbl
0.1
$13.0bn
0.4
$6.61/bbl
0.2
0.21
94.9%
0.03
95.7%
0.18
0.21
$26.1bn
0
0.00
$12.7bn
0.33
$7.15/bbl
0.07
0.40
Formulaic
scorecard
outcome
0.81a out of 2.0
SEEAC
discretion
MBAC
discretion
No adjustment
No adjustment
Final
scorecard
outcome
0.81a out of 2.0
a Due to rounding, the total does not agree exactly with the sum of its component parts.
0.81a out of 2.0
Outcome 40.5% of
maximum bonus
91
Corporate governanceDirectors’ remuneration report 2018 annual bonus outcomeBP Annual Report and Form 20-F 2018
Shareholders will note that the most significant divergence from our
2018 targets is in operating cash flow. Even though the 2018 outcome
of $26.1 billion is 8% higher than 2017, it fell marginally short of the
threshold level of $26.4 billion on an adjusted basis. This meant a score
of zero on an element that contributes 20% of the overall bonus target.
We feel this is a reflection of the rigor in our policy and target-setting
process, delivering a nil outcome even in a year which saw underlying
profit more than double, and returns almost double.
As in previous years, in order to confirm the final bonus score we have
discussed the formulaic score with the chairs of the safety, ethics and
environment assurance committee (SEEAC) and the main board audit
committee (MBAC). This year, neither of these committees raised
issues for which we felt any need to adjust. On this basis, and in view
of the demanding target levels we had set for 2018 performance, we
believe that the formulaic score, and the annual bonuses that result,
fairly reflect and reward 2018 performance for the executive directors
and senior leadership of BP. Accordingly we have made no discretionary
adjustments to the formulaic scorecard outcome, which applies to the
executive directors and BP’s senior leadership (approximately 4,400
employees).
Notwithstanding this outcome, we discussed and agreed Bob’s decision
to adjust the group performance element of annual bonus for the wider
workforce (employees below senior leadership level) and consequently
these 32,600 employees received 2018 annual bonus based on an
adjusted group performance score of 100%, rather than 81%, of target.
The annual bonus outcome is unrelated to the BP share price, and
therefore no part of the bonus is attributable to share price appreciation.
As shown below, half of the bonus is paid in cash after year end, and
half is deferred into shares that will vest in three years, according to 2017
policy terms. The full value of the 2018 bonus, including the deferred
shares, is included in the 2018 single figure table. This differs from
reporting in respect of the 2014 policy, under which deferred shares
are included in the single figure for the year in which they vest.
Name
Bob Dudley
Brian Gilvary
Adjusted
outcome
$1,689,458
£706,219a
Paid
in cash
$844,729
£353,109
Deferred
into BP
shares
$844,729
£353,109
a Due to rounding, the total does not agree exactly with the sum of its component parts.
Vesting levels for the 2016-18 performance share awards we granted
in 2016 are determined under the terms of the 2014 policy, in line with
the performance measures and outcomes shown on the scorecard on
page 93.
Assessed against these scorecard measures, the group’s performance for
the three years from 2016 to 2018 is strong. Notably, we placed first on
relative total shareholder return (with 49.3%) which measures us against
our super-major peers, Chevron, ExxonMobil, Shell and Total. We also
placed first in the 2015-17 performance cycle. Total shareholder return
represents the change in value of a shareholding over a three-year period,
assuming that dividends are re-invested to purchase additional shares.
ratio over the period, which yields vesting at 80% of maximum for this
element. We will confirm our final outcome for this measure once
competitor data is published in full later in the year.
As before, we have assessed performance against the safety and
operational risk measure by looking back at tier 1 process safety
incidents and recordable injury frequency over the three-year period.
This is a detailed assessment looking at year-on-year performance
for which we sought input from the SEEAC. Based on continuing
reductions in tier 1 events and in recordable injury frequency, and the
SEEAC overview, we assessed a score of 88% of maximum for this
element of the performance shares scorecard.
BP’s standard practice is to calculate this change in value based on
the average US market prices over the fourth quarter immediately
before, and at the end of, the three-year performance cycle. Using
a three-month period average helps to counter the impact of share
price volatility.
The choice of basis period for calculating share price growth can be
a material factor in the ranking result. This generally explains why our
peers who use relative TSR in their remuneration plans can arrive at
a different result. For example, in the three year scorecard period just
ended, BP and Shell showed different relative TSR rankings because
unlike BP’s average of the calendar quarter approach, Shell’s standard
basis is to use a 90-day averaging period around the start and end of the
performance period.
We have again made strong progress in major project delivery,
exceeding the top of the measurement scale (13) with 19 major
projects delivered over the three-year period, allowing maximum
vesting for this element.
Our $68 billion cumulative operating cash flow excluding the Gulf
of Mexico oil spill payments for the period exceeds the threshold
performance level of $61.2 billion, following adjustments for oil price
in line with the 2014 policy. For the purposes of this report, we have
forecast a second place outcome for our relative reserves replacement
While the scorecard provides a balanced view of longer-term results,
as a committee we wish to take a broader view of performance in order
to ensure reward outcomes are proportional and appropriate. Our first
concern is to ensure outcomes align with shareholders’ own experience
of both returns, and of the company’s positioning to generate value into
the future. In this regard we believe the scorecard has worked well.
Clearly there are also broader societal views to consider, together with
the general experience of the wider workforce as a key stakeholder
group. These broader considerations create a compelling case for
restraint on quantum, even as they emphasize the need to align to
performance.
Therefore while we believe that 2016-18 performance has been
exemplary, and that the business is both operationally and strategically
well positioned for the future, the committee has nonetheless decided
to reduce vesting of the performance share award from the formulaic
90.5% to a discretionary 80% of maximum. In applying this judgement
and making this reduction the committee decided to apply the more
challenging measurement scales of our 2017 policy. The committee
studied the impact of share price appreciation on pay outcomes and is
satisfied that the gains arising are an appropriate and necessary design
feature of a long-term incentive. We believe there should be no routine
adjustment, either for gains that in part reflect low grant prices, or for
shortfalls that reflect the opposite.
92
Directors’ remuneration report 2016-18 performance share plan outcomeBP Annual Report and Form 20-F 2018 In addition, and in line with treatment last year, the committee has
agreed to Bob’s request to re-base his original grant from 550% of
salary to 500% of salary, recognizing the change from the 2014 policy
to the 2017 policy. The impact these decisions have on pay outcomes
for Bob and Brian are detailed below.
Shares
awarded
Shares
vesting
including
dividends
1,809,582b 1,597,374
765,998
786,559
Value of
vested
shares
$11,043,179
£4,082,769
Reduction in value
due to discretion
and re-basing
$2,698,677
£535,863
Name
Bob Dudleya
Brian Gilvary
The value of vested shares reflects the share price appreciation all
shareholders experienced over the three-year period. For this 2016-18
award cycle, the original grant was calculated based on ordinary share
and American depositary share (ADS) prices of £3.72 and $33.81
respectively, while the 2018 fourth-quarter average prices are £5.33 and
$41.48. Consequently, share price appreciation accounts for $2.04
million (18.5%) of the value of Bob’s vested shares, and for £1.23 million
(30.2%) of the value of Brian’s vested shares. The committee did not
regard this as a direct reason to exercise discretion, although overall pay
outcomes have been a part of our consideration of downward discretion.
a Bob Dudley’s award is granted in respect of American depositary shares (ADSs). The
numbers in this table reflect calculated equivalents in ordinary shares. One ADS equates to
six ordinary shares.
b This original award was based on 550% of salary, according to the terms of the 2014 policy.
Performance shares
Scorecard
2016-18 performance shares
REM
Measures used for the 2014 remuneration policy.
KPI See key performance
indicators on page 16.
Financial
60.7%
Measures
Financial
Strategic imperatives
29.8%
Formulaic vesting
90.5%
Weightinga
Threshold
performance
Maximum
performance
Outcome
Relative total shareholder return KPI
33.3%
Third
First
Cumulative operating cash flow KPI
33.3%
$61.2bn
$73.2bn
Strategic imperatives
Relative reserves replacement ratio KPI
11.1%
Major project delivery KPI
11.1%
Third
9
First
13
11.1%
Assessment of improvement over the three years
First
33.3%
$67.8bn
27.3%
60.7%b
Secondc
8.9%
19
11.1%
5.0%
4.8%
29.8%
90.5%
Committee review of stakeholder context and
experience over three-year period of plan
80%
final vesting
after committee
discretion
Safety and operational risk:
– Process safety tier 1 events KPI
– Recordable injury frequency KPI
Total formulaic vesting
Formulaic
vesting
90.5%
a Due to rounding, the sum of the weightings does not agree with the actual total, which is 100%.
b Due to rounding, the total does not agree exactly with the sum of its component parts.
c Forecast position, to be confirmed after external data becomes available later in 2019.
93
Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018
Alignment with strategy
The strategy we set in 2017 commits us to a balance of short-term
goals and long-term ambitions, encompassing both conventional
and emerging sources of energy. To help the board and executive
management assess delivery against this strategy, we track progress
against a number of key performance indicators (KPIs) – see page 16.
This strategy and these KPIs represent the foundation of our investor
proposition. Importantly the majority of our KPIs translate directly into
the measures we use to assess our annual bonus and performance
share awards. This helps us align the focus of our board and executive
management with the interests of our shareholders. To maintain this
alignment over time, we will adjust our bonus and performance share
measures as and when BP’s strategy evolves or finds new areas
of focus.
The annual bonus rewards activities that assure our success in the near
term, with measures focused on safety, reliable operations, financial
performance and, from 2019, a new emissions reduction target.
Ensuring our near-term health is a critical building block for the longer
term, providing the funds for us to invest, innovate, pursue new
opportunities and enhance our productivity. For instance, the reliable
operations measure in our annual plan has a strong and direct bearing
on the financial measures for our three-year performance share
outcomes. Our new sustainable emissions reduction measure, with a
10% weighting for 2019, connects bonus outcomes directly with the
progress we make under the reduce element of our ‘reduce, improve,
create’ (RIC) framework for a low carbon transition.
Our longer-term view is explicitly covered in the strategic progress
element for our performance shares, alongside measures that focus
on shareholder returns and return on average capital employed (ROACE)
over each three-year cycle. These are the measures we established two
years ago with our 2017 policy, and we will see the first cycle of results
under that policy when we report the 2017-19 performance shares
outcome in next year’s report. Looking ahead, the committee has
decided to increase the weighting of the strategic progress measure
from 20% to 30% to better reflect its importance. This will apply for the
performance shares we grant in 2019 as part of the 2019-21 cycle. As a
result, we will reduce the weighting on ROACE from 30% to 20%.
To ensure we take a rounded view in our performance assessment, the
performance share plan also features an underpin to bring absolute TSR,
safety and environmental factors into account. This underpin allows the
committee to embrace the energy transition in a way that enhances our
investor proposition and allows us to be competitive at a time when
prices, policy, technology and customer preferences are volatile and
evolving, while managing the alignment between remuneration
outcomes and our strategic progress.
Reducing our
emissions in
our operations
Improving
our
products
Creating
low carbon
businesses
See our low carbon ambitions on page 46.
BP set out an update of its strategy in 2017, which was reinforced in the results announcements in February 2018 and 2019. The foundations for
strong performance are safe and reliable operations, a balanced portfolio, and a focus on returns.
Safer
Fit for
future
Safe, reliable
and efficient
execution
A distinctive
portfolio fit for a
changing world
Focused on
returns
Value based,
disciplined
investment and
cost focus
Growing
sustainable free
cash flow and
distributions to
shareholders over
the long term
How we align
our strategy and
remuneration
measures
Annual bonus
Safety
Environment
Reliable operations
Financial performance
Performance shares
Total shareholder return
Return on average capital employed
Strategic priorities
Underpin: absolute TSR and safety/
environmental factors
94
Directors’ remuneration report BP Annual Report and Form 20-F 2018 Executive directors’ pay for 2018
Single figure table – executive directors (audited)
Remuneration is reported in the currency
in which the individual is paid
Salary and benefits
Salary
Benefits
Retirement benefits
Pension and retirement
savings – value increasea
Cash in lieu of future accrual
Annual bonus
Cash bonus
Shares – deferred for three years
Bob Dudley
(thousand)
2018
2017
$1,854
$1,854
$79
$70
$0
–
$845
$845
$746
–
$1,491
$1,491
Brian Gilvary
(thousand)
2018
£769
£67
£0
£269
£353
£353
2017
£752
£38
£186
£263
£611
£611
Performance shares
Performance shares
$11,043b
$9,455c
£4,083b
£3,595c
Discontinued plans
Deferred share awards from
prior-year bonuses
–d
–d
£2,083e
£1,060e
Total remunerationf
Value attributable to share price appreciationg
$14,666
$2,042
$15,108
$1,349
£7,977
£1,876
£7,115
£936
a For Bob Dudley this represents the aggregate value of the company match and investment gains on the accumulating unfunded BP Excess
Compensation (Savings) Plan (ECSP) account under Bob’s US retirement savings arrangements. In 2018 Bob incurred investment losses
of $193,910 in this account, hence this aggregate value is negative and reported as zero per regulations. Full details are set out on page 96.
For Brian Gilvary this represents the annual increase in accrued pension, net of inflation, multiplied by 20. In 2018 Brian’s salary increased
by less than inflation, hence the net increase is reported as zero per regulations. Full details are set out on page 96.
b Represents the assumed vesting of shares in 2019 following the end of the relevant performance period, based on a preliminary assessment of
performance achieved under the rules of the plan and includes accrued 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 2018 which was £5.33 for ordinary shares and $41.48 for ADSs.
The final vesting will be confirmed by the committee in the second quarter of 2019 and provided in the 2019 directors’ remuneration report.
c In accordance with UK regulations, in the 2017 single figure table, the performance outcome values were based on fourth-quarter average prices
of £5.01 for ordinary shares and $39.85 for ADSs. In May 2018, after the external data became available, the committee reviewed the relative
reserves replacement ratio position, and this resulted in no adjustment to the final vesting of 70%. On 22 May 2018, 198,306 ADSs for Bob Dudley
and 603,831 ordinary shares for Brian Gilvary vested at prices of $47.09 and £5.88 respectively. On 31 July 2019 an additional 2,599 ADS and 7,795
ordinary shares vested, representing accrued dividends at prices of $45.09 and £5.73 for Bob and Brian respectively. The 2017 reported values for
the total vesting have therefore increased by $1,168 thousand for Bob and by £614 thousand for Brian.
d Bob Dudley has voluntarily agreed to defer performance assessment and vesting of the awards related to his 2015 annual bonus until at least
one year after retirement, therefore the performance period is expected to exceed the minimum term of three years. As stated in the 2017
directors’ remuneration report, Bob voluntarily deferred performance assessment and vesting of the 2014 deferred and matching awards until
at least one year after retirement – see the Deferred shares table on page 101 for further details on these awards.
e The amounts reported for 2018 relate to the 2015 annual bonus deferred over three years, which vested on 19 February 2019 at the market price
of £5.38 for ordinary shares and include accrued dividends on shares vested. Brian Gilvary has voluntarily agreed to defer performance assessment
and vesting of the matching awards related to his 2015 annual bonus for a further two years – see the Deferred shares table on page 101 for further
details on these awards. The amounts reported for 2017 relate to the 2014 annual bonus and have been adjusted from the number provided in the
2017 directors’ remuneration report to include the accrual and vesting of accrued dividends.
f Due to rounding, the total does not agree exactly with the sum of its component parts.
g The values shown for performance shares and deferred share awards include the share price appreciation experienced over the three-year vesting
periods. This additional line shows the value of those awards that is directly attributable to share price appreciation, being the number of shares
vesting, including accrued dividends, multiplied by the increase in share price from grant date to vesting date.
95
Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018 Overview of single figure outcomes
The single figures of total remuneration for Bob Dudley and Brian Gilvary
are $14.67 million and £7.98 million respectively. This is a 3% decrease
for Bob, and a 12% increase for Brian. In both cases 2018 remuneration
includes material value from share price appreciation over the 2016 to
2018 period. Both individuals pay a majority of their taxes in the UK. After
these tax and social security liabilities on this BP income, the net values
of 2018 total remuneration are approximately $7.77 million for Bob, and
approximately £4.23 million for Brian.
Salary and benefits
Bob Dudley’s salary remained at $1,854,000 throughout 2018. Brian
Gilvary’s salary was increased by 2% to £775,000 with effect from
21 May 2018. Both executive directors received car-related benefits,
assistance with tax return preparation, security assistance, insurance
and medical benefits. In 2018 BP reimbursed Brian for holiday
curtailment costs incurred due to BP commitments. Part of this
reimbursement is considered non-business related, hence is subject
to tax and included as a benefit in the single figure table.
2018 annual bonus and 2016-18 performance shares
Please refer to pages 91-93 for details of the performance measures,
targets, and outcomes, and the related reward outcomes
for annual bonus and performance shares.
Discontinued plans: deferral of 2015 bonus – deferred and
matching awards of shares
In accordance with 2014 policy, Bob Dudley and Brian Gilvary deferred
two thirds of their 2015 annual bonus. As a result, they each received
an equivalent value deferred award of BP shares, together with a
matching award of BP shares. Both the deferred and matching awards
were subject to a three-year performance period which ended on
31 December 2018.
Conclusions of the safety and sustainability assessment
Bob has requested that the committee delay the performance
assessment and hence the vesting of his 2015 deferred and matching
awards. This reflects his commitment to the long-term success of BP
and adds to his alignment with shareholders’ interests. These awards
will now vest, subject to an assessment against the original safety and
environmental sustainability conditions, after his retirement. Similarly,
Brian has requested a two-year extension to the performance
assessment and vesting date of his 2015 matching award.
For the 2015 deferred award for Brian, the committee considered
operational and financial performance and reviewed safety and
environmental sustainability performance over the 2016-18 period,
seeking input from the SEEAC on safety and sustainability measures.
The committee concluded that safety performance continues to show
improvement, with safety embedded in the culture of the organization
and supporting strong operational and financial performance. The
committee concluded that the deferred award should vest in full.
2015 bonus – deferred and matching awards
Name
Bob Dudleya
Deferred award
Matching award
Brian Gilvaryb
Deferred award
Matching award
Shares
granted
Vesting
agreed
Total shares
vesting,
including
dividends
Total value at
vesting
551,784
551,784
–a
–a
–
–
–
–
318,042
318,042
100%
–b
387,160 £2,082,921c
–
–
a Vesting of deferred and matching awards deferred until at least one year after retirement,
subject to conditions.
b Vesting of matching award deferred for two years, subject to conditions.
c Based on a vesting share price of £5.38.
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
Bob Dudley is a member of the US pension and retirement savings plans
described on page 108. His normal retirement age is 60. In 2018 Bob’s
accrued defined benefit pension did not increase. In accordance with the
requirements of the UK regulations, the amount included in the single
figure table on page 95 is therefore zero. In 2018 Bob made contributions
to the BP Employee Savings Plan (ESP) totalling $27,000 and BP made
matching contributions to the ESP, and notional contributions to the BP
Excess Compensation (Savings) Plan (ECSP), totalling $129,780.
However, investment losses of $193,910 in his unfunded ECSP account
(aggregating the unfunded arrangements relating to his overall service
with BP and TNK-BP), exceeded the sum of these contributions, hence
the amount included in the single figure table is zero.
Brian Gilvary is a member of the UK pension arrangement described on
page 108 in common with more than 3,800 UK employees employed
prior to 2010 (or before 2014 in the North Sea). His normal retirement
age is 60, although benefits accrued before 1 December 2006 may be
paid from age 55 with BP’s consent. Brian’s 2018 salary increase was
below inflation, and his accrued defined benefit pension increase was
therefore likewise below inflation. In accordance with the requirements
of the UK regulations, the amount included in the single figure table is
therefore zero.
Brian has exceeded the lifetime allowance under UK pension legislation
and now receives a cash allowance of 35% of base salary in lieu of
further service accrual. This amount has been separately identified
in the single figure table on page 95.
This cash allowance is a feature of the UK pension arrangement, and
will transition down to 15% of salary by 1 June 2023 – see page 105
for more detail. The committee continues to review the value of pension
benefits for individual directors and its alignment to the broader workforce.
History of group chief executive remuneration
Group chief
executive
Tony Hayward
Tony Hayward
Bob Dudley
Bob Dudley
Bob Dudley
Bob Dudley
Bob Dudley
Bob Dudley
Bob Dudley
Bob Dudley
Bob Dudley
Total
remuneration
thousanda
£6,753
£3,890
$8,057
$8,439
$9,609
$15,086
$16,390
$19,376
$11,904
$15,108
$14,666
Annual bonus
% of
maximum
88.9b
0
0
66.7
64.9
88.0
73.3
100.0
61.0
71.5
40.5
Performance
shares vesting
% of maximum
17.5
0
0
16.7
0
45.5
63.8
74.3
40.0
70.0
80.0
Year
2009
2010c
2011
2012
2013
2014
2015
2016
2017
2018
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 2018 the preliminary assessment has been reflected.
b 2009 annual bonus did not have an absolute maximum and so is shown as a percentage of
the maximum established in 2010.
c 2010 figures show full-year total remuneration for both Tony Hayward and Bob Dudley,
although Bob Dudley did not become GCE until October 2010.
96
Directors’ remuneration report BP Annual Report and Form 20-F 2018 Wider workforce in 2018
Workforce experience
Delivery of our strategy, both near and long term, depends upon BP’s
success in attracting and engaging a highly talented workforce, and on
equipping our people with the skills for the future. While the board is
currently considering ways to engage more deeply with the workforce,
and about the workplace in its broadest sense, the remuneration
committee continues to receive and review information on pay
outcomes and processes for our wider workforce.
We are building insight into the remuneration models used in different
BP entities and stay informed on the pay structures and typical salary
budgets for the core areas of the group’s business. For example, we
have looked at data from the organization’s gender pay reporting, at
progression of reward across the hierarchy of job levels, and reviewed
the reward structures and processes in BP’s trading business.
Overall we observe a well-balanced and structured approach to reward
(summarized in the table below), and to the ‘non-financial’ reward
elements that contribute to an engaged and productive environment.
This context has informed our decision making on executive director
pay and our views on incentive outcomes across the group. In our
consideration of the annual bonus scorecard for 2018, for instance, while
we felt the formulaic result delivered appropriate outcomes for BP’s
senior leadership, we agreed with Bob’s decision to apply a more
generous outcome to the wider workforce on the basis that, individually,
they have limited influence over financial outcomes such as cash flow.
Looking beyond pay, much of the workforce experience at BP is centred
on a disciplined approach to performance management, for which
employees set annual priorities related to both safety and value creation,
balanced with behavioural objectives that give focus to the importance
of good conduct. This deeply embedded programme has served to
develop the management skills of team leaders and drives quality
dialogue between employees and their managers. We agree with the
executive team’s view that the time invested in managing performance
both aligns individual effort to corporate goals and allows employees to
understand the value of their own contribution. The benefit of this
approach is largely qualitative, through direction and feedback, but the
individual contribution is also measured and then rewarded as part of
the annual bonus. For a more immediate impact, BP is also encouraging
more ‘in the moment’ feedback through our new global recognition
programme ‘energize!’, introduced in 2018. Energize! has been well
received in all business areas and locations, with 77% of employees
recognized at least once, at a frequency of around 1,500 recognition
moments every day by year end.
With strong emphasis on diversity and inclusion to create teams that
reflect their communities, and with the enduring foundation of BP’s
values and behaviours to build respect, we believe BP employees work
in a supportive, meritocratic and progressive environment. This positive
environment is reflected in being the highest-ranked UK recruiter in the
oil and gas sector in the Times newspaper’s Top 100 Graduate Employer
rankings 2018.
Summary of remuneration structure for employees below the board
Element
Policy features for the wider workforce
Comparison with executive director remuneration
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Our salary is the basis for a competitive total reward package for all employees,
and we conduct an annual salary review for all non-unionized employees.
As we determine salaries in this review, we take account of comparable pay rates
at other relevant employers, the skills, knowledge and experience of each individual,
relativity to peers within BP, individual performance, and the overall budget we set
for each country.
In setting the budget each year, we assess how employee pay is currently positioned
relative to market rates, forecasts of any further market increases, and business
context related to such things as growth plans, workforce turnover and affordability.
The salaries of our executive directors and executive
team form the basis of their total remuneration, and
we review these salaries annually.
The primary purpose of the review is to stay aligned
with relevant market comparators, although we ensure
any increases are kept within the budgets
set for our wider workforce salary review.
We offer market-aligned benefits packages reflecting normal practice in each country
in which we operate. Where appropriate, and subject to scale, we offer significant
elements of personal benefit choice to our employees.
Other than the addition of security-related benefits,
our executive director benefit packages are broadly
aligned with other employees who joined BP in the
same country at the same time.
Approximately half of our global workforce participate in an annual cash bonus plan
that multiplies a target bonus amount by a performance factor in the range 0 to 2. The
performance factor is an average of performance outcomes measured at a group,
business area and individual level. This structure places equal emphasis on the
importance of an employee’s personal contribution, the success of their broad team,
and the results achieved by BP.
We operate different bonus plans for those distinct parts of our business where
remuneration models in the market are markedly different, such as our trading and
marketing businesses.
Annual bonus for executive directors is directly
related to the same group performance measures
and outcomes as the wider workforce, but without
the business area and individual performance element.
We operate a performance share plan with three-year vesting for employees from our
professional entry level and above. Operation varies based on seniority in three broad
tiers: group leaders (approximately 400); senior leaders (approximately 4,000); and all
other professional employees (approximately 35,000 potential participants, of whom
20% will participate). Vesting is subject to group performance outcomes for the group
leader population only.
Performance shares for our executive directors
are assessed using the same group performance
scorecard used for the group leader performance
shares, with some adjustment to the weightings.
97
Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018
Group chief executive-to-employee pay ratio
In 2016 and 2017 we disclosed the ratio between our group chief
executive’s (GCE) total remuneration and the median (P50)
remuneration of a comparator group of our UK and US professional
workforce (representing 38% of our global professional workforce).
We believe this representation offers a valuable data point, highlighting
relevant pay differentials within BP. On this basis, our 2018 GCE
to median pay ratio is 106:1.
GCE pay ratios
Year
2017
2018
Method
BP voluntary
BP voluntary
P50 pay
ratio on total
remuneration
105:1a
106:1
P50 salary
$112,100
$114,800
P50 total
remuneration
$136,865
$138,101
a Re-based from original 92:1 to reflect final value at vesting of 2015-17 performance shares.
With effect from year ending 31 December 2019, the UK government
will require that we calculate the total remuneration of the three BP UK
employees whose remuneration represents the 25th, 50th and 75th
percentile of our entire UK workforce. We are then required to disclose
the ratio of our group chief executive’s total remuneration against each
of those three representative employees.
Percentage change comparisons: GCE remuneration
versus professional workforce
Comparing
2018 to 2017
% change in GCE
remuneration
Salary
Benefits
Bonus
0%
8.0%
-43.4%
% change in comparator group
remuneration
4.4%
0%
-7.8%
The comparator group used here is the same as used in our voluntary
pay ratio disclosures since 2017, i.e. our professional and managerial
grade staff in the UK and US. This group is employed on readily
comparable terms to the group chief executive, and represents
approximately one third of our total employee base.
Relative importance of spend on pay ($ million)
Distributions to
shareholders
Remuneration paid to
all employees
Capital investment
16,501
15,140
8,435a
8,210a
10,494
10,204
2018
2017
2018
2017
2018
2017
a Distributions to shareholders comprise dividend payments of $8,080 million ($7,867 million
in 2017) and share buybacks at a cost of $355 million ($343 million in 2017). See page 275
for details.
98
Directors’ remuneration report BP Annual Report and Form 20-F 2018 The illustration below, from our 2018 UK gender pay gap reporting,
highlights the representation issue and how it relates to the gender pay
gap for each entity. For instance, our larger gender pay gaps relate to BP
Exploration and BP p.l.c. where we have the largest differential between
female representation in the top and bottom pay quartiles. By contrast,
we reported a negative pay gap in BP Chemicals, where male to female
representation is more consistent.
Equal pay and UK gender pay gap reporting
As well as looking at pay structures, the committee has spent time
understanding how effectively current pay policies and processes
manage fairness and avoid bias in pay outcomes. We noted the
February 2018 UK gender pay gap reporting for the five legal entities
covered by the regulations, and the explanations provided in the
narrative that accompanied BP’s reporting.
Overall the committee feels assured that the anti-discrimination
controls written into pay policies, and the quality of processes behind
individual pay decision making, are effective in delivering an equal pay
environment (like pay for like work) for the wider workforce. While the
UK gender pay gap reporting showed pay gaps in favour of men for four
out of the five entities, we understand that these gaps result largely
from the relative under-representation of women in senior roles, and
that the group’s primary focus should therefore be on improving female
representation, rather than adjusting pay practices. Therefore we have
reviewed the various initiatives taken by management to address these
representation concerns and will continue to monitor progress in
addressing the underlying issues.
Proportion of females and males in each quartile band
These charts show how men and women are represented in each pay band.
An even distribution across the quartiles would tend to minimize the gender pay gap.
BP Chemicals Limited
BP Exploration Operating Company Limited
Upper
85%
82%
93%
Lower
76%
BP Chemicals is our petrochemicals business
in the UK, principally our operations in Hull.
BP Oil UK Limited
Upper
69%
68%
63%
Lower
44%
BP Oil represents our downstream
fuels and lubricants businesses.
BP p.l.c.
Upper
71%
70%
60%
Lower
36%
15%
18%
7%
24%
31%
32%
37%
56%
29%
30%
40%
64%
Upper
92%
88%
83%
Lower
63%
BP Exploration covers upstream activities
in the UK, principally North Sea operations.
BP Express Shopping Limited
Upper
63%
62%
48%
Lower
42%
BP Express Shopping is our largest UK employing
business, concerned with retail operations
supporting our UK-wide network of forecourts.
8%
12%
17%
37%
37%
38%
52%
58%
BP p.l.c. predominantly covers employees in corporate
business and functions, including our integrated
supply and trading and Air BP businesses.
Men
Women
99
Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018 Stewardship and executive director interests
We believe that our executive directors should have a material interest
in the company, both during their tenure and after they leave BP. Our
shareholding policy therefore requires executive directors to build a
personal shareholding of five times their salary within five years of their
appointment. They are expected to maintain personal shareholdings of
at least two and a half times salary for two years post employment.
Directors’ shareholdings (audited)
The tables below detail the personal shareholdings of each executive
director, and demonstrate that both significantly exceed the policy
requirement as at 15 March 2019. These figures include all beneficial and
non-beneficial ownership of shares of BP (or calculated equivalents) that
have been disclosed to the company and exclude the anticipated vesting
of the 2016-18 performance shares.
Ordinary
shares or
Ordinary shares
equivalents at
or equivalents
31 Dec 2018
at 1 Jan 2018
3,065,520
3,718,284
1,709,243 2,043,899
Changes from
31 Dec 2018 to
15 Mar 2019
Ordinary shares
or equivalents
total at
15 Mar 2019
-210b 3,718,074
205,006 2,248,905
Director
Bob Dudleya
Brian Gilvary
a Held as ADSs.
b This reflects change in the equivalent value of BP ADRs under the BP Employee Savings Plan
(‘ESP’), due to the BP ADR price movement. See page 108 for explanation of the ESP.
Performance shares (audited)
Director
Bob Dudley
Brian Gilvary
Appointment date
October 2010
January 2012
Value of
current shareholding
Multiple of
salary achieved
(policy requires 5x)
$27,185,318 14.66 x salary
£12,256,532 15.80 x salary
The executive directors have interests in both performance shares and
deferred bonus shares under the executive directors’ incentive plan
(EDIP). The share interests are shown in aggregate and by plan in the
tables below. These figures show the maximum possible vesting levels.
The actual number of shares/ADSs that vest will depend on the extent
to which performance conditions are satisfied.
Unvested
ordinary shares
or equivalents
at 1 Jan 2018
Unvested
ordinary shares
or equivalents as
31 Dec 2018
Changes from
31 Dec 2018 to
15 Mar 2019
Unvested
ordinary shares
or equivalents at
15 Mar 2019
Director
Bob Dudleya
Brian Gilvary
6,569,010b
3,329,274
6,825,606b
3,291,614
1,459,350
400,709
8,284,956
3,692,323
a Held as ADSs.
b This shareholding has been re-based to reflect the 500% of salary grant level of the 2017
policy, in place of the original 550% per the 2014 policy.
Bob Dudleyb
Brian Gilvary
Date of award
of performance
shares
Performance period
2015-17
11 Feb 2015
4 Mar 2016
2016-18
2017-19g 19 May 2017
2018-20i 22 May 2018
11 Feb 2015
2015-17
4 Mar 2016
2016-18
2017-19g 19 May 2017
2018-20i 22 May 2018
Share element interests
Potential maximum performance sharesa
At 1 Jan
2018
1,365,240
1,645,074
1,571,628h
–
685,246
786,559
722,093
–
Awarded
2018
–
–
–
1,395,600
–
–
–
696,705
At 31 Dec
2018
–
1,645,074e
1,571,628
1,395,600
–
786,559
722,093
696,705
Interests vested in 2018 and 2019
Number of
ordinary shares
vested
Vesting date
1,205,430c 22 May 2018d
2019f
1,597,374f
–
–
–
–
611,626c 22 May 2018d
2019f
765,998f
–
–
–
–
Face value of
the award, £
–
–
7,418,084
8,206,128
–
–
3,408,279
4,096,625
a For awards under the 2015-17 and 2016-18 plans, performance conditions are measured one third on TSR relative to Chevron, ExxonMobil, Shell and Total (‘comparator companies’); 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 2017-19 plan, performance conditions are measured 50% on TSR relative to Chevron, ExxonMobil, Shell and Total over three years; 30% on ROACE based on performance in 2019
and 20% on strategic progress assessed over the performance period. For awards under the 2018-20 plan, performance conditions are measured on the same basis as the 2017-19 plan,
except ROACE which will be based on performance in the last two years of the performance period (i.e. 2019 and 2020). 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 22 May 2018 was £5.88 and for ADSs was $47.09. These totals include the additional accrual of dividends which vested on
31 July 2018.
d The 2015-17 award vested on 22 May 2018. Details can be found in the single figure table on page 95.
e Bob Dudley has requested that the EDIP performance shares vesting in respect of the performance period 2016-18 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. The number reported here has been
re-based to 500%.
f For the assumed vestings in the second quarter of 2019 a price of £5.33 per ordinary share and $41.48 per ADS has been used. These are the average prices from the fourth quarter of 2018.
g The face value has been calculated using the market price of ordinary shares on 19 May 2017 of £4.72.
h In our 2017 report, the 31 December 2017 value for this award was incorrectly stated as 1,428,750.
i The face value has been calculated using the market price of ordinary shares on 22 May 2018 of £5.88.
100
Directors’ remuneration report BP Annual Report and Form 20-F 2018
Deferred shares (audited)a
Bob Dudleyb
Brian Gilvary
Bonus
year
Type
2014c Comp
Vol
Mat
2015e Comp
Vol
Mat
2016f Comp
Mat
2017g Comp
2014 Comp
Vol
Mat
2015 Comp
Vol
Mat
2016f Comp
Mat
2017g Comp
Performance
period
2015-17d
2015-17d
2015-17d
2016-18d
2016-18d
2016-18d
2017-19
2017-19d
2018-20
2015-17
2015-17
2015-17i
2016-18
2016-18
2016-18i
2017-19
2017-19k
2018-20
Date of award of
deferred shares
11 Feb 2015
11 Feb 2015
11 Feb 2015
4 Mar 2016
4 Mar 2016
4 Mar 2016
19 May 2017
19 May 2017
22 May 2018
11 Feb 2015
11 Feb 2015
11 Feb 2015
4 Mar 2016
4 Mar 2016
4 Mar 2016i
19 May 2017
19 May 2017
22 May 2018
Share element interests
Potential maximum deferred shares
At 1 Jan
2018
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
–
Awarded
2018
–
–
–
–
–
–
–
–
226,236
–
–
–
–
–
–
–
–
127,457
At 31 Dec
2018
147,054
147,054
294,108
275,892
275,892
551,784
147,642
147,642
226,236
–
–
176,576
159,021
159,021
318,042
73,070
73,070
127,457
Interests vested in 2018 and 2019
Number of
ordinary shares
vested
–
–
–
–
–
–
–
–
–
Vesting date
–
–
–
–
–
–
–
–
–
111,161h 20 Feb 2018
111,161h 20 Feb 2018
–
193,580j 19 Feb 2019
193,580j 19 Feb 2019
–
–
–
–
–
–
–
–
–
Face value of
the award, £
655,861
655,861
1,311,722
1,015,283
1,015,283
2,030,565
696,870
696,870
1,330,268
–
–
787,529
–
–
1,170,395
344,890
344,890
749,447
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 The face value has been calculated using the market price of ordinary shares on 11 February 2015 of £4.46.
d Bob Dudley has voluntarily agreed to defer the performance assessment and vesting of these awards until at least one year after retirement, therefore the performance period is expected to
exceed the minimum term of three years.
e The face value has been calculated using the market price of ordinary shares on 4 March 2016 of £3.68.
f 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.
g The market price at closing of ordinary shares on 22 May 2018 was £5.88 and for ADSs was $47.09. The sterling value has been used to calculate the face value.
h 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 date of 20 February 2018 was £4.75. These totals include the additional accrual of dividends
which vested on 22 May 2018 and 31 July 2018.
i Brian Gilvary has voluntarily agreed to defer the performance assessment and vesting of these matching awards for a total of five years with a further one-year retention period. The face values
have been calculated using the market prices of £4.46 per ordinary share on 11 February 2015 and £3.68 per ordinary share on 4 March 2016.
j Represents vesting of shares at the end of the relevant performance period based on performance achieved under rules of the plan. Includes reinvested dividends on the shares vested.
The market price of each share used to determine the total value on the vesting date of 19 February 2019 was £5.38.
k Brian Gilvary has voluntarily agreed to defer the performance assessment and vesting of these awards until the later of three years post award or one year post employment, therefore the
performance period is expected to exceed the minimum term of three years.
In common with many of our UK employees, Brian Gilvary holds options under the BP group save as you earn (SAYE) schemes as shown below.
These options are not subject to performance conditions.
Share interests in share options plans (audited)
Brian Gilvary
Option type At 1 Jan 2018
BP 2011b
500,000
3,103
SAYE
Granted
–
–
Exercised
100,000
–
At 31 Dec
2018a
400,000
3,103
Option price
£3.72
£2.90
Market price at
date of exercise
Date from which
first exercisable
Expiry date
£5.27 07 Sep 2014 07 Sep 2021
– 01 Sep 2019 28 Feb 2020
a The closing market price of an ordinary share on 31 December 2018 was £4.96. During 2018 the highest market price was £5.98 and the lowest market price was £4.60.
b ‘BP 2011’ means the BP 2011 plan. These options were granted to Brian Gilvary prior to his appointment as a director and are not subject to performance conditions.
Neither Bob Dudley or Brian Gilvary have any interest in BP preference
shares, debentures or option plans (other than as listed above), and
neither have interests in shares or loan stock of any subsidiary company.
No directors or other executive team members (see page 63) own more
than 1% of the ordinary shares in issue.
At 15 March 2019, our directors and other executive team members
collectively held interests of 17,436,602 ordinary shares or their
calculated equivalents, 5,978,567 restricted share units (with or without
conditions) or their calculated equivalents, 11,977,279 performance
shares or their calculated equivalents and 4,417,149 options over
ordinary shares or their calculated equivalents, under BP group share
option schemes.
Post employment share ownership interests
As we reported last year, to maintain their alignment with shareholders
and in keeping with the long-term nature of our business, our executive
directors will retain significant interests in BP post employment. These
ongoing interests are centred on a) the personal commitment by each
executive director to maintain actual holdings equivalent to two and a
half times salary for two years post employment, and b) their anticipated
interests in share awards under group plans which remain subject to
vesting and/or holding periods at the time they leave BP.
101
Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018
Non-executive director outcomes and interests
The board’s remuneration policy for the chairman and non-executive
directors (NEDs) was approved at the 2017 AGM and implemented
during 2017. There has been no variance of the fees or allowances for
the chairman and the NEDs since approval in 2017.
Chairman
The fee structure for the chairman, which has been in place since May
2013, is £785,000 per year. The chairman is not eligible for committee
chairmanship and membership fees or intercontinental travel allowance.
As chairman throughout 2018, Carl-Henric Svanberg had the use of a
fully maintained office for company business, a car and driver, and
security advice in London. He received a contribution to an office and
secretarial support as appropriate to his needs in Sweden. The table
below shows the fees paid for the year ended 31 December 2018.
2018 remuneration (audited)
£ thousand
Carl-Henric Svanberg
Fees
Benefitsa
Total
2018
785
2017
785
2018
24
2017
35
2018
809
2017
820
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.
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 according to the disclosure guidance and transparency
rules in the Financial Conduct Authority handbook (‘the DTRs’) as at the
applicable dates. The chairman’s holdings as at 31 December 2018, as a
percentage of the shareholding policy, were 1,312%.
Ordinary
shares or
equivalents at
1 Jan 2018
Ordinary
shares or
equivalents at
31 Dec 2018
Change from
31 Dec 2018
to
15 Mar 2019
Ordinary
shares or
equivalents
total at
15 Mar 2019
2,076,695
2,076,695
–
–
Chairman
Carl-Henric
Svanberga
a Resigned on 31 December 2018.
Helge Lund assumed the role of chairman with effect from 1 January
2019. His share interests are disclosed on page 103.
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.
2018 remuneration (audited)
£ thousand
Fees
Benefitsa
Totalb
Nils Andersen
Paul Andersonc
Alan Boeckmann
Admiral Frank Bowman
Dame Alison Carnwathd
Pamela Daleye
Ian Davis
Professor Dame Ann
Dowlingf
Helge Lunde
Melody Meyerh
Brendan Nelson
Paula Rosput Reynolds
Sir John Sawers
2018
132
69
155
160
74
55
170
158
46
160
150
166
150
2017
115
155
165
155
–
–
154
145
–
86
138
146i
145
2018
11
6
10
14
47
42
2
2
122g
26
12
33
1
2017
17
27
11
15
–
–
2
5
–
23
14
8
5
2018
144
76
165
174
121
97
172
159
169
186
162
200
151
2017
132
182
176
170
–
–
156
150
–
109
152
154i
150
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 Due to rounding, the totals may not agree exactly with the sum of its component parts.
c Resigned on 21 May 2018.
d Appointed on 21 May 2018.
e Appointed on 26 July 2018.
f Fee includes £25 thousand for chairing and being a member of the BP technology
advisory council.
g Benefits include relocation expenses.
h Appointed on 17 May 2017.
i Amended from £140 thousand (fees) and £148 thousand (total) as originally disclosed in our
2017 report.
102
Directors’ remuneration report BP Annual Report and Form 20-F 2018
Non-executive directors’ interests (audited)
The figures below indicate and include all the beneficial and
non-beneficial interests of each non-executive director of the
company in shares of BP (or calculated equivalents) that have been
disclosed to the company under the DTRs as at the applicable dates.
Nils Andersen
Paul Andersonb
Alan Boeckmann
Admiral Frank Bowman
Dame Alison Carnwathd
Pamela Daleye
Ian Davis
Professor Dame Ann Dowling
Helge Lundf
Melody Meyer
Brendan Nelson
Paula Rosput Reynolds
Sir John Sawers
Ordinary shares
or equivalents at
1 Jan 2018
125,000
30,000c
44,772c
24,864c
–
–
47,500
22,320
–
20,646c
11,040
58,200c
14,198
Ordinary shares
or equivalents at
31 Dec 2018
125,000
–
44,772c
24,864c
17,700
17,592c
50,296
22,320
600,000
20,646c
11,040
73,200c
15,030
Changes from
31 Dec 2018 to
15 Mar 2019
–
–
–
–
–
–
–
–
–
–
–
–
–
Ordinary shares or
equivalents at
15 Mar 2019
125,000
–
44,772c
24,864c
17,700
17,592c
50,296
22,320
600,000
20,646c
11,040
73,200c
15,030
Value of current
shareholdinga
£681,250
–
$327,358
$181,797
£96,465
$128,627
£274,113
£121,644
£3,270,000
$150,957
£60,168
$535,214
£81,914
% of policy
achieved
757%
–
273%
151%
107%
107%
305%
135%
417%
126%
67%
446%
91%
a Based on share and ADS prices at 15 March 2019 of £5.45 and $43.87.
b Resigned on 21 May 2018.
c Held as ADSs.
d Appointed on 21 May 2018.
e Appointed on 26 July 2018.
f Appointed 26 July 2018. Became chairman with effect from 1 January 2019. Percentage of
policy achieved based on annual equivalent fee for role of chairman.
Payments for loss of office and payments to past
directors (audited)
We made no payments for loss of office during or in respect of 2018 to
current or former 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 2018, he received
£100,000 for this role. Other than this, we made no payment to any past
director of BP during 2018 (we have no de minimis threshold for such
disclosures).
103
Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018
Other disclosures
Historical TSR performance
FTSE 100
BP
£250
£200
£150
£100
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
l
£50V
Shareholder engagement
Throughout 2018 we continued to discuss remuneration policy and
approach with many of our largest shareholders, as well as investor
representative bodies. We plan to continue this dialogue in 2019, as we
consider updates to our remuneration and minimum shareholdings
policies for 2020.
The table below shows the votes on the report for the last three years.
AGM directors’ remuneration report vote results
Year
2018
2017
2016
% vote ‘for’
96.42%
97.05%
40.70%
% vote ‘against’
3.58%
2.95%
59.30%
Votes withheld
42,741,541
63,453,383
464,259,340
The remuneration policy was approved by shareholders at the 2017
AGM on 17 May 2017. The votes on the policy are shown below.
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2017 AGM directors’ remuneration policy vote results
Year
2017
% vote ‘for’
97.28%
% vote ‘against’
2.72%
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 retain any fee from their external
appointments. Such 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 of publicly listed companies
during 2018 are shown below.
Director
Bob Dudley
Brian Gilvary
Appointee
company
Rosnefta
Additional position
held at appointee company
Director
Total fees
0
Air Liquide Non-executive director Euros 70,500
a Bob Dudley holds this appointment as a result of the company’s shareholding in Rosneft.
Committee membership
Please refer to the committee report on page 83 for details of
membership of the remuneration committee during 2018.
This graph shows the growth in value of hypothetical £100 investments
in BP p.l.c. ordinary shares, and in the FTSE 100 Index (of which
BP is a constituent), over 10 years from 31 December 2008 to
31 December 2018.
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,
advice received and shareholder engagement is set out in the
remuneration committee report on page 83.
During 2018 David Jackson, the then company secretary, and
subsequently Hannah Ashdown, both of whom were employed by the
company and reported to the chairman of the board, acted as secretary
to the remuneration committee.
The committee also received advice on various matters relating to the
remuneration of executive directors’ and senior management from
Helmut Schuster, executive vice president, group human resources,
and Ashok Pillai, vice president, group reward.
PricewaterhouseCoopers LLP (‘PwC’) continued to provide
independent advice to the committee in 2018, following its appointment
as independent adviser to the committee in September 2017, following
a competitive tender process. 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.
PwC and Freshfields provide other advice in their respective areas to
the group. During the year, 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 2018 (save in respect of legal
advice) were £179,200 to PwC.
104
Directors’ remuneration report BP Annual Report and Form 20-F 2018
Executive director remuneration policy
and implementation for 2019
2019
The table below shows how the remuneration policy approved by shareholders at the 2017 AGM
will be implemented in 2019. For the full remuneration policy, please go to bp.com/remuneration.
Salary and benefits
Reflects role and home
country market
Salary and benefits reflect the scale and complexity of the role, and competitive practice in the market.
• Bob Dudley’s salary will remain at $1,854,000 for 2019.
• Benefits will remain unchanged for 2019. These include
• With effect from the AGM, Brian Gilvary’s salary will increase
by 2% to £790,500.
• This compares to an average increase of over 3.5% to our UK
salaried staff, effective on our annual salary review date 1 April.
car-related benefits, assistance with tax return preparation,
security assistance, insurance and medical benefits.
Retirement benefits
Reflects home
country market
• Since September 2016, Bob has had no further service
accrual under his defined benefit pension arrangements.
The 401(k) benefits have been partially capped for
future years. His normal retirement age is 60.
• Starting from 1 June 2019, we agreed to reduce Brian’s cash
supplement by 5% of salary each year to reach 20% of salary
with effect from 1 June 2021, with a further 5% reduction,
to 15% of salary, with effect from 1 September 2023.
Annual bonus
Up to 225% of salary
Aligned with annual
objectives
• Brian is a member of the BP UK defined benefits pension
plan and he receives a cash supplement in lieu of further
service accrual on the same terms as other participants in
the plan, currently 35% of salary.
• These changes reduce Brian’s cash supplement sooner
than the transition for other members of the BP UK defined
benefits plan, and Brian will not receive any form of
compensation related to the reductions. His normal
retirement age is 60, although benefits accrued before
1 December 2006 may be paid from age 55 with BP’s
consent.
The bonus links variable pay to safety, environmental goals, reliable operations and financial performance
for the year.
• Maximum bonus requires performance at the top of the
measurement scale on every measure – a scorecard
outcome of 2.0.
• A scorecard outcome of 1.0, reflecting target on each
measurement scale, delivers half of maximum bonus.
• 50% of bonus earned is paid in cash, 50% is deferred into
shares for three years.
• The scorecard measures for the bonus are set annually to
reflect priorities. The committee sets measurement scales
(disclosed retrospectively) that require year-on-year
improvement.
• For 2019, performance will be assessed against:
– Safety – 20%
– Environment – 10%
– Reliable operations – 20%
– Financial performance – 50%.
• The committee holds discretion to adjust outcomes to reflect
broader performance considerations.
Bonus is subject to malus and clawback provisions
following events such as misconduct, restatement or
misstatement of results, and miscalculation. Malus
may also be applied following a material failure
impacting safety or environmental sustainability,
or other exceptional circumstances as decided
by the committee.
Performance shares
GCE – 500%
CFO – 450%
of salary
Vesting reflects
three-year performance
Directly linked to long-term performance and represents the largest part of total remuneration.
• Three-year performance period, followed by further
three-year holding period.
• Measures aligned to BP strategy and shareholders’ interests.
• For the 2019-21 cycle, vesting level will first be assessed on
performance over the three years in these areas:
– TSR relative to oil and gas majors – 50% weighting.
– ROACE – averaged over the full period – 20% weighting.
– Progress against our strategic objectives – 30%
weighting.
• Underpin – the committee will then review broader
performance, including absolute TSR, safety and
environmental factors in order to determine the
final vesting outcome.
Performance shares are subject to malus and clawback
provisions following events such as misconduct,
restatement or misstatement of results, and
miscalculation. Malus may also be applied following
a material failure impacting safety or environmental
sustainability, or other exceptional circumstances as
decided by the committee.
Share ownership
Long-term shareholding
obligation
Reinforces alignment with shareholder interests, and stewardship of the enterprise.
• Continuing requirement for executive directors to maintain a
holding of five times salary.
• Bob and Brian are expected to maintain a holding of at least
two and a half times salary for two years post employment.
• In addition, the executive directors have voluntarily elected to
defer the vesting date of certain other share awards, with
associated performance conditions, which would otherwise
have been unrestricted.
105
Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018 Salary and benefits
Bob’s annual salary will remain at $1,854,000 for 2019. Brian’s salary
will increase by 2% to £790,500 from the date of the 2019 AGM. For
reference, the April 2019 annual pay review of our salaried employees
in the UK was subject to a budget in excess of 3.5%.
We expect to maintain benefits at the current level.
Salary increases over the last five years
Bob Dudley
Brian Gilvary
2019
Nil
2018
Nil
2017
Nil
2016
Nil
2015
Nil
Bob Dudley
Brian Gilvary
2.0%
2.0%
3.75%
2019
2018
2017
2016
Nil
2015
Nil
Salary with
effect from AGM
$1,854,000
£790,500
Increase
Nil
2.0%
Annual bonus
For 2019 we have amended our bonus measures to include an
environmental measure (10%) alongside safety (20%), reliable
operations (20%) and financial performance (50%). This approach
will provide a balanced assessment of how the business has performed
over the course of the year and of our progress in addressing emissions
reduction. We are also changing downstream refining availability to
BP-operated downstream refining availability to more closely align to our
BP-operated upstream plant reliability measure.
The committee has set the 2019 targets after consultation on the safety
targets with the SEEAC and on the financial targets with the MBAC.
Although the detail of these targets is currently commercially sensitive,
the committee will provide retrospective disclosure following the year
end, as with previous cycles. As before, the committee will consider
changes in plan conditions (including oil and gas prices and refining
margins) when reviewing financial outcomes at year end, and 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 remains 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 score of 1.0 out of a maximum of 2.0) is half of maximum,
112.5% of salary.
For any bonus earned, 50% will be delivered in cash and 50% will be
deferred into shares that will vest after three years.
Measures for 2019 annual bonus
Element
Safety
20%
Measures
include
Environment
10%
Financial performance
Reliable operations
50%
20%
Weighting
for 2019
Measures
include
Weighting
for 2019
Measures
include
Weighting
for 2019
Measures
include
Weighting
for 2019
Recordable injury
frequency KPI
10%
Sustainable emissions 10%
reduction KPI
Tier 1 and tier 2 process 10%
safety events KPI
Operating cash
flow excluding Gulf of
Mexico oil spill payments KPI
20%
Underlying
replacement
cost profit KPI
20%
Upstream unit
production costs KPI
10%
BP-operated upstream 10%
plant reliability KPI
10%
BP-operated
downstream refining
availability (Solomon
Associates’ operational
availability) KPI
106
Directors’ remuneration report BP Annual Report and Form 20-F 2018
Performance shares
In line with our 2017 policy, the performance share awards for our
2019-21 cycle will be granted in 2019 at the level of 500% of salary for
Bob and 450% of salary for Brian. Performance will then be measured
over three years, with any vested shares being subject to a mandatory
holding period of a further three years. These awards are subject to
malus and clawback provisions as set out in the policy.
The measures for the 2019-21 cycle of performance shares focus on
shareholder value, capital discipline and future growth.
Shareholder value
The TSR element is measured on a relative basis against the oil majors:
Chevron, ExxonMobil, Shell and Total. We maintain our belief that the
current comparator group remains appropriate as it is used for
benchmarking across a range of activities in other parts of the group.
This measure carries a 50% weighting in the vesting calculation, with
targets shown below.
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 (see Glossary on page 315 for full definition). 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 2019-21 performance shares award, this assessment will be
averaged over the full three-year period.
This ROACE measure carries a 20% weighting in the vesting calculation,
and targets are shown in the table below.
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 progress targets – which carry a 30% weighting
in the vesting calculation – 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 will be able to review the basis of our
assessment. 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.
Broader performance assessment – the underpin
Prior to approving vesting outcomes, the committee will also consider
the broader performance of the business including absolute TSR
performance, together with safety and environmental factors (including
consideration of issues around greenhouse gases) over the three-year
period. We refer to this as the 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 – see page 46.
Measures for 2019-21 performance shares
Element
Relative TSR versus oil majorsa
Return on average capital employedb
Strategic progress
50%
Threshold
vesting
Maximum
vesting
KPI
20%
KPI
30%
25% of element
Third out of five
100% of element
First place
0% of element
8.5% return on average capital employed
100% of element
12.5% return on average capital employed
• Growing gas and advantaged oil in the
upstream
• 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, 2020 and 2021. 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).
107
Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018 provided directly by the company rather than through the BPPS. The
rules of this non-qualified arrangement are designed to mirror the design
of the approved BPPS.
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.
On 1 April 2011, Brian elected to stop future service accrual and instead
receive a cash allowance. His accrued benefits in the approved and
unapproved plans remain linked to his final base pay.
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 has a normal retirement age of 60.
Subject to the consent of the committee, Brian may retire between age
55 and 60 and 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 from his leaving date.
BPPS members can elect to stop accrual and instead receive a cash
allowance of 35% of salary until March 2021, then progressively
reducing to 15% of salary by March 2024 (or such earlier date that they
would have accrued a maximum two-thirds pension under the BPPS
had they not opted out). As noted above, on 1 April 2011 Brian elected
to stop future service accrual and receive this cash allowance. Currently
over 650 employees have elected to stop future service accrual under
the final salary plan and instead receive the 35% cash allowance. Brian
has offered to accelerate the schedule of this progressive reduction.
Accordingly reductions to 30%, 25% and 20% will be made with effect
from 1 June 2019, 2020 and 2021 respectively, and a final reduction to
15% with effect from 1 September 2023 being the date on which Brian
would have reached a maximum two-thirds pension under the BPPS
had he not opted out.
Retirement benefits
Bob Dudley
Bob is provided with pension benefits and retirement savings through a
combination of tax-qualified and non-qualified benefit plans. His normal
retirement age is 60.
The BP Supplemental Executive Retirement Benefit Plan (SERB) is a
non-qualified defined benefit pension plan which provides a pension of
1.3% of final average earnings for each year of service, less benefits
paid under all other BP (US) tax-qualified and non-qualified pension
plans. In 2016 Bob reached the SERB service limit of 37 years of service
and therefore no longer builds up further service accrual under these
pension plans. However the accrued benefit remains linked to highest
average earnings within the final 10 years. The benefit payable under the
SERB is unreduced at age 60 or older.
The BP Employee Savings Plan (ESP) is a US tax-qualified defined
contribution plan to which both Bob and BP contribute. BP matches
Bob’s salary contributions to a maximum of 7% of base salary, up
to the IRS limit. The BP Excess Compensation (Savings) Plan (ECSP)
is a non-qualified, unfunded, retirement savings plan to which BP
notionally contributes 7% of base salary above the annual IRS limit.
In common with around 2,000 other participants, Bob does not
contribute to the ECSP.
Under both savings plans, Bob is entitled to make investment elections,
involving the actual investment holdings in the case of the ESP,
and the notional investment holdings in the case of the ECSP. Benefits
payable under the ECSP are unfunded and will therefore be paid from
corporate assets. Accordingly annual investment returns on the ECSP
are recognized as income for the single figure table, in addition to the
notional contributions themselves. Conversely, annual investment
losses are offset against the value of contributions and notional
contributions by BP and therefore reduce the amount recognized as
income for the single figure table.
Brian Gilvary
Brian is provided with pension benefits and retirement savings through
a combination of tax-qualified and non-qualified benefit plans and a
cash allowance. His normal retirement age is 60, although benefits
accrued before 1 December 2006 may be paid from age 55 with BP’s
consent.
Brian is a member of a UK final salary defined benefit pension plan,
the BP Pension Scheme (BPPS), along with over 3,800 other UK
employees. Pension benefits that have been accrued in the BPPS in
excess of the individual lifetime tax allowance set by legislation are
provided to Brian via a non-qualified, unfunded pension arrangement
Shareholding requirements
Both executive directors remain subject to the share ownership
requirement of five-times salary, which they currently exceed. Based on
the commitments each director has made to the committee, we expect
that Bob and Brian will each maintain shareholdings of at least 250% of
salary for two years post employment.
108
Directors’ remuneration report BP Annual Report and Form 20-F 2018 Non-executive director remuneration policy for 2019
The table below shows the remuneration policy approved by shareholders at
the 2017 AGM. For the full remuneration policy, please go to bp.com/remuneration.
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
The chairman is provided with support and reasonable travelling expenses.
Operation and
opportunity
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
Approach
Operation and
opportunity
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.
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.
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 Jens Bertelsen, company secretary on 29 March 2019.
109
Corporate governanceDirectors’ remuneration report BP Annual Report and Form 20-F 2018 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), including FRS 101 ‘Reduced Disclosure
Framework’. 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 adequate 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.
Helge Lund
Chairman
29 March 2019
Risk management and internal control
Under the UK Corporate Governance Code (Code), the board is
responsible for the company’s risk management and internal control
systems. In discharging this responsibility the board, through its
governance principles, requires the group chief executive to operate the
company with a comprehensive system of controls and internal audit to
identify and manage the risks that are material to BP. In turn, the board,
through its monitoring processes, satisfies itself that these material risks
are identified and understood by management and that systems of risk
management and internal control are in place to mitigate them. These
systems are reviewed periodically by the board, have been in place for
the year under review and up to the date of this report and are consistent
with the requirements of principle C.2 of the Code.
The board has processes in place to:
• Assess the principal risks facing the company.
• Monitor the company’s system of internal control (which includes the
ongoing process for identifying, evaluating and managing the principal
risks).
• Review the effectiveness of that system annually.
Non-operated joint ventures and associates have not been dealt with as
part of this board process.
A description of the principal risks facing the company, including those
that could potentially threaten its business model, future performance,
solvency or liquidity, is set out in Risk factors on page 55. 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 53.
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 75-86.
This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
110
BP Annual Report and Form 20-F 2018 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.
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.
An audit committee meeting in January 2019 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, in addition to considering 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 2019, 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 300.
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 a viability 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, including
committed capital investment.
Taking into account the company’s current position and its principal risks
on page 55, 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. These scenarios included a process safety
incident and a sustained oil price decline.
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.
This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
111
Corporate governanceBP Annual Report and Form 20-F 2018 112
BP Annual Report and Form 20-F 2018 Financial
statements
114 Consolidated financial statements of the BP group
Independent auditor’s reports
Group income statement
Group statement of
comprehensive income
114
129
130
Group statement of
changes in equity
Group balance sheet
Group cash flow statement
131
132
133
1.
2.
3.
151
134
4.
5.
6.
153
154
156
134 Notes on financial statements
Significant accounting
policies
Significant event – Gulf of
Mexico oil spill
Business combinations and
other significant transactions
Disposals and impairment
Segmental analysis
Revenue from contracts
with customers
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
13.
14.
15.
16.
17.
18.
19.
20.
165
165
166
167
168
168
170
170
159
159
160
160
163
163
7.
8.
9.
10.
11.
12.
171
171
21.
22.
23.
24.
25.
26.
27.
28.
29.
30.
31.
32.
33.
34.
35.
36.
37.
38.
Trade and other payables
Provisions
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
210 Supplementary information on oil and natural gas
(unaudited)
Oil and natural gas exploration
and production activities
Movements in estimated
net proved reserves
211
217
Standardized measure of
discounted future net cash
flows and changes therein
relating to proved oil and
gas reserves
Operational and statistical
information
238 Parent company financial statements of BP p.l.c.
Company balance sheet
Company statement of
changes in equity
Notes on financial statements
1.
2.
3.
4.
5.
Significant accounting
policies
Investments
Receivables
Pensions
Payables
238
239
240
240
243
243
243
247
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
172
172
172
179
179
180
180
181
185
192
194
197
198
199
199
200
201
232
235
247
248
248
249
249
249
249
250
251
BP Annual Report and Form 20-F 2017
BP Annual Report and Form 20-F 2018
115
113
i
F
n
a
n
c
a
i
l
s
t
a
t
e
m
e
n
t
s
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.
Report on the audit of the financial statements
Opinion
In our opinion:
• The financial statements of BP p.l.c. (the ‘parent company’) and its subsidiaries (the ‘group’) give a true and fair view of the state of the
group’s and of the parent company’s affairs as at 31 December 2018 and of the group’s profit for the year then ended.
• The group financial statements have been properly prepared in accordance with International Financial Reporting Standards (IFRSs) as
adopted by the European Union (EU) and IFRSs as issued by the International Accounting Standards Board (IASB).
• The parent company financial statements have been properly prepared in accordance with United Kingdom generally accepted accounting
practice including FRS 101 ‘Reduced Disclosure Framework'.
• 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.
We have audited the financial statements of BP p.l.c. which comprise:
• Group income statement;
• Group statement of comprehensive income;
• Group and parent company statements of changes in equity;
• Group and parent company balance sheets;
• Group cash flow statement;
• Group related Notes 1 to 38 to the financial statements, including a summary of significant policies; and
• Parent company related Notes 1 to 14 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 IFRSs as
adopted by the European Union and as issued by the IASB. The financial 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.
We are independent of the group and the parent company in accordance with the ethical requirements that are relevant to our audit of the
financial statements in the UK, including the Financial Reporting Council’s (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 confirm that the non-audit services
prohibited by the FRC’s Ethical Standard were not provided to the group or the parent company.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.
Summary of our audit approach
Key audit matters
The key audit matters that we identified in the current year were:
• Impairment of Upstream oil and gas property, plant and equipment (PP&E) assets;
• Accounting for acquisitions and disposals within the Upstream segment;
• Impairment of exploration and appraisal assets;
• Accounting for structured commodity transactions within the integrated supply and trading function, and the
valuation of other level 3 financial instruments, where fraud risks may arise in revenue recognition;
• User access management controls relating to financial systems; and
• Management override of controls.
Two key audit matters were identified by the previous auditor and described in their report for the year ended 31
December 2017 and are not included in our report for the year ended 31 December 2018. These were:
• The determination of the liabilities, contingent liabilities and disclosures arising from the Gulf of Mexico oil spill - the
provisions have substantially decreased from a quantitative perspective and the level of judgement in determining
BP’s liabilities has reduced significantly as legal settlements have been reached; and
• US Tax reform - the reform was signed into law in 2017 and gave rise to a one-off taxation charge. Whilst the impact
of the reform has continued to be assessed in 2018, the judgement required and quantitative impact in the current
year is considerably lower.
The previous auditor also included a key audit matter in respect of unauthorized trading activity in the integrated supply
and trading function. This is covered by the key audit matter set out above covering the accounting for structured
commodity transactions and valuation of certain level 3 financial instruments. They also identified a key audit matter in
respect of the estimation of oil and gas reserves and resources, which we have considered in the context of
impairment of Upstream oil and gas PP&E assets.
Materiality
We have set materiality for the current year at $750 million based on profit before tax and underlying replacement cost
profit before interest and tax.
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114
BP Annual Report and Form 20-F 2018
Scoping
Our scope covered 136 components. Of these, 108 were full-scope audits, covering 71% of group revenue, and the
remaining 28 were subject to specific procedures on certain account balances by component audit teams or the group
audit team.
First year audit
transition
The year ended 31 December 2018 is our first as auditor of the group. We commenced transition activities after our
selection as auditor being announced in November 2016.
These activities included:
• Establishing independence from BP by exiting non-audit services which would be independence-impairing, as BP
transitioned these to new service providers;
• Establishing an appropriately resourced and skilled global audit team, including specialists, in all relevant locations;
• Developing and delivering a bespoke “BP Academy” training course for Deloitte personnel joining the BP audit
engagement; and
• Holding introductory meetings with BP management.
We commenced our audit planning procedures subsequent to us becoming independent on 16 October 2017. After
establishing independence, our work included:
• Shadowing the previous auditor through the 31 December 2017 audit, including attendance at key meetings,
including audit committee meetings;
• Reviewing the previous auditor’s 2016 and 2017 audit files;
• Reviewing historical accounting policies and accounting judgements through discussion with management and
review and challenge of management’s papers and supporting documentation; and
• Conducting group audit team visits to components.
These procedures built our understanding of the group which, together with our existing knowledge of the oil and gas
industry, informed our audit risk assessment, through which we identified the risks of material misstatement to the
group’s financial statements.
We presented our transition observations to the group’s audit committee in a transition report in April 2018, with an
update in May 2018. We presented further observations, together with our audit plan, in July 2018, and provided an
update to our plan in December 2018.
Conclusions relating to going concern, principal risks and viability statement
Going concern
We have reviewed the directors’ statement on page 111 about whether they considered it appropriate to
adopt the going concern basis of accounting in preparing them and their identification of any material
uncertainties to the group’s and company’s ability to continue to do so over a period of at least twelve
months from the date of approval of the financial statements.
We considered as part of our risk assessment the nature of the group, its business model and related
risks including where relevant the impact of Brexit, the requirements of the applicable financial reporting
framework and the system of internal control. We evaluated the directors’ assessment of the group’s
ability to continue as a going concern, including challenging the underlying data and key assumptions
used to make the assessment, and evaluated the directors’ plans for future actions in relation to their
going concern assessment.
We are required to state whether we have anything material to add or draw attention to in relation to that
statement required by Listing Rule 9.8.6R(3) and report if the statement is materially inconsistent with
our knowledge obtained in the audit.
Principal risks and viability statement
We confirm that we have
nothing material to report, add
or draw attention to in respect
of these matters.
Based solely on reading the directors’ statements and considering whether they were consistent with
the knowledge we obtained in the course of the audit, including the knowledge obtained in the evaluation
of the directors’ assessment of the group’s and the company’s ability to continue as a going concern, we
are required to state whether we have anything material to add or draw attention to in relation to:
• the disclosures on pages 55-56 that describe the principal risks and explain how they are being
We confirm that we have
nothing material to report, add
or draw attention to in respect
of these matters.
managed or mitigated;
• the directors' confirmation on page 110 that they have carried out a robust assessment of the principal
risks facing the group, including those that would threaten its business model, future performance,
solvency or liquidity; or
• the directors’ explanation on page 111 as to how they have assessed the prospects of the group, 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 group 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.
We are also required to report whether the directors’ statement relating to the prospects of the group
required by Listing Rule 9.8.6R(3) is materially inconsistent with our knowledge obtained in the audit.
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.
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BP Annual Report and Form 20-F 2018
115
These matters included those which had the greatest effect on: the overall audit strategy, the allocation of resources in the audit; and directing
the efforts of the engagement team.
Throughout the course of our audit we identify risks of material misstatement (‘risks’) and classify those risks according to their severity. In
assigning a category we consider both the likelihood of a risk of a material misstatement and the potential magnitude of a misstatement in
making the assessment. Certain risks are classified as ‘significant’ or ‘higher’ depending on their severity. The category of the risk determines
the level of evidence we seek in providing assurance that the associated financial statement item is not materially misstated.
These matters were addressed in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we
do not provide a separate opinion on these matters.
Impairment of upstream oil and gas PP&E assets
Key audit matter description
How the scope of our audit responded to the key audit matter
The group balance sheet includes property, plant and equipment
(PP&E) of $135 billion, of which $99 billion is oil and gas properties
within the Upstream segment. As required by IAS 36 'Impairment of
Assets', management performed a review of the upstream cash
generating units (CGUs) for indicators of impairment and impairment
reversal as at 31 December 2018.
Where such indicators were identified, management estimated the
recoverable amount of the CGU to determine if any impairment
charges or reversals were required. For the year ended 31 December
2018, BP recorded $400 million of Upstream impairment charges and
$580 million of impairment reversals.
Through our risk assessment procedures, we have determined that
there are three key estimates in management’s review for indicators
of impairment/reversal and the level of impairment charge/reversal to
record where indicators are identified. These are:
• Long-term oil and gas prices - BP’s long-term oil and gas price
assumptions have a significant impact on CGU impairment
assessments and valuations performed across the portfolio, and
are inherently uncertain. There is a risk that management’s oil
and gas price assumptions are not reasonable, leading to a
material misstatement.
• Discount rates - Given the long timeframes involved, certain
impairment assessments and valuations are sensitive to the
discount rate applied. There is a risk that discount rates do not
reflect the return required by the market and the risks inherent in
the cash flows being discounted, leading to a material
misstatement. Determination of the appropriate discount rate
can be judgemental.
• Reserves estimates - A key input to impairment assessments
and valuations is the production forecast, in turn closely related
to the group’s reserves estimates and field development
assumptions. CGU-specific estimates are not generally material.
However, material misstatements could arise either from
systematic flaws in reserves estimation policies, or due to flawed
estimates in a particularly material individual impairment test.
Whilst all CGUs must be assessed for indicators of impairment and
impairment reversal annually, we focused on certain individual CGUs
with a total carrying value of $21.8 billion which we determined would
be most at risk of a material impairment ($750 million) as a result of a
reasonably possible change in the key assumptions, particularly the
long-term oil and gas price assumptions. Accordingly, we identified
these as a significant audit risk. We also focused on assets with a
further $31.5 billion of combined CGU carrying value which were less
sensitive. We identified these as a higher audit risk as they would be
potentially at risk in aggregate to a material impairment by a change
in such assumptions. Further information regarding these sensitivities
is given in Note 1.
We tested management’s internal controls over the setting of oil and
gas prices, discount rates and reserve estimates. In addition, we
conducted the following substantive procedures.
Long-term oil and gas prices
• We compared BP’s oil and gas price assumptions against third-
party forecasts, peer information and relevant market data to
determine whether BP’s forecasts were within the range of such
forecasts.
• In challenging management's forecasts, we considered the
extent to which they reflected the energy transition due to
climate change.
Discount rates
• We independently evaluated BP’s discount rates used in
impairment tests with input from Deloitte valuation specialists.
• We assessed whether country risks were appropriately reflected
in BP’s discount rates.
Reserves estimates
• We performed a look-back analysis to check for indications of
bias over time.
• We reviewed BP’s reserves estimation methods and policies,
assisted by Deloitte reserves experts.
• We assessed how these policies had been applied to seven
internal reserves estimates.
• We reviewed reports provided by external experts and assessed
their scope of work and findings.
• We assessed the competence, capability and objectivity of BP’s
internal and external reserve experts, through obtaining their
relevant professional qualifications and experience.
Other procedures
• We challenged management’s cash generating unit
determination, scrutinized the impairment and impairment
reversal indicator analysis and considered whether there was any
contradictory evidence present.
• Where such indicators were identified, we validated that BP’s
asset impairment methodology was appropriate and tested the
integrity of impairment models.
• We compared hydrocarbon production forecasts and proved and
probable reserves to reserve reports and our understanding of
the life of fields.
• We verified estimated future capital and operational costs by
comparison to approved budgets and assessed them with
reference to field production forecasts.
• We also assessed these estimates against management’s
historical forecasting accuracy and whether the estimates had
been determined and applied on a consistent basis across the
group where relevant.
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BP Annual Report and Form 20-F 2018
Key observations
Long-term oil and gas prices
We determined that BP’s Brent oil price forecasts are reasonable when compared against the range of
other third-party forecasts.
We challenged BP’s Henry Hub, NBP and Asian LNG price curves for periods when they were somewhat
higher than the range of other third-party forecasts. However, management ran additional tests using a
Henry Hub, NBP and Asian LNG price curve consistent with the range of third-party forecasts, which
demonstrated that the carrying values recorded in the balance sheet are not impacted.
Discount rates
Our Deloitte valuation specialists calculated a different range for weighted average cost of capital than
was determined by management. We also found that some simplifications are taken when making group-
wide assumptions for country and asset-specific risk premium adjustments, and for calculating pre-tax
discount rates, given the group's CGUs which operate in multiple tax jurisdictions.
Management reperformed impairment tests using higher discount rates and only one impairment test
was impacted, with a difference which was not significant. Accordingly we were satisfied with the results
of the testing.
We reviewed the disclosures included in Note 1 to the accounts in respect of price and discount rate
assumptions used and confirmed that they were the same as those used in the impairment tests.
Reserves estimates
Having involved Deloitte oil and gas reserves experts in our testing, we concluded that the assumptions
used to derive the estimates were reasonable.
Accounting for acquisitions and disposals within the Upstream segment
Key audit matter description
How the scope of our audit responded to the key audit matter
There were certain acquisition and disposal transactions within the
Upstream segment that required fair valuation of assets and liabilities
acquired and disposed of, and consideration of complex accounting
judgements, to which we devoted significant engagement team time
and resource. Accordingly, this had a significant effect on our audit
strategy. These transactions were:
• The $10.3 billion acquisition of onshore US assets from BHP,
including the fair valuation of assets and liabilities acquired;
• The disposal of BP’s interest in the Greater Kuparuk Area in
Alaska and simultaneous purchase of an incremental interest in
the BP-operated Clair field in the UK North Sea; and
• The disposal of BP’s interest in the Magnus field in the North
Sea, where the consideration included a level 3 financial asset,
the valuation of which depends on the future performance of
Magnus.
We tested management’s internal key controls over the valuation
assumptions and accounting approaches for each of these significant
transactions. In addition, we conducted the following substantive
procedures:
• We reviewed the enacted sale and purchase agreements and
management’s accounting analysis to corroborate that the
accounting treatment applied was consistent with the underlying
commercial terms.
• With input from our valuations and reserves specialist teams, we
reviewed and challenged management’s fair value estimates,
focusing on the key assumptions (including pricing, discount
rates and reserves risking estimates).
• We tested the mechanical accuracy of the valuation models.
• We assessed the independence, objectivity, competence and
scope of work performed by BP’s third-party valuation specialist
used in the acquisition from BHP.
Key observations
We noted that the assumptions underlying the fair value calculation for the onshore US assets acquired
from BHP were at the conservative end of the range but concurred that the purchase price represented
the fair value of the assets and liabilities acquired, in accordance with IFRS 3.
We observed that in some cases, the fair values of oil and gas assets from certain market transactions,
including the BHP acquisition, implied valuation assumptions that were more conservative than those
used in value-in-use impairment calculations. The latter, as defined in IAS 36, represents management’s
best estimate of the future cash flows of an asset, discounted at a market rate of return, whereas the
former, as defined in IFRS 13 'Fair Value Measurement', is determined by the prices at which oil and gas
assets are actually changing hands in orderly transactions under prevailing market conditions. We
concluded that in their respective IFRS contexts, and in the presence of valid evidence, the use of
different assumptions to estimate fair values and value in use was appropriate.
We reviewed the disclosures included by management in Note 3 to the accounts and concluded that
these are compliant with IFRS 3 requirements.
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BP Annual Report and Form 20-F 2018
117
Impairment of exploration and appraisal assets
Key audit matter description
How the scope of our audit responded to the key audit matter
The group capitalizes exploration and appraisal (E&A) expenditure on
a project-by-project basis in line with IFRS 6 'Exploration for and
Evaluation of Mineral Resources'. At the end of 2018, $16.0 billion of
E&A expenditure was carried in the group balance sheet. E&A
activity is inherently risky and a significant proportion of projects fail,
requiring the write-off of the related capitalized costs when the
relevant criteria in IFRS 6 and BP’s accounting policy are met.
There is a risk that certain capitalized E&A costs are not written off
promptly at the appropriate time, in line with information from, and
decisions about E&A activities, and the impairment requirements of
IFRS 6.
Through our detailed risk assessment, which is based on our analysis
of the portfolio of E&A assets held by BP, making reference to BP’s
own analysis of the same assets, we identified a significant risk in
respect of certain specific assets in the Gulf of Mexico with a total
carrying value of $2.3 billion, as certain licences in question have
expired and a partner has recently withdrawn from other licences,
and three licences elsewhere ($1.6 billion) which are scheduled to
expire or require next phase decisions in 2019. BP is in negotiations
to extend all these licences. Further details regarding the significant
accounting judgement are given in Note 1 to the accounts.
We obtained an understanding of the group’s E&A impairment
assessment processes and tested management’s controls. In
addition, we conducted the following substantive procedures:
We reviewed and challenged management’s significant IFRS 6
impairment judgements, guided by our risk assessment, having
regard to the impairment criteria of IFRS 6 and BP’s accounting policy.
We verified key facts relevant to significant carrying amounts (e.g.
obtaining evidence of future E&A plans and budgets, evidence of
active dialogue with partners and regulators including negotiations to
renew licences or modify key terms).
We performed a licence-by-licence risk assessment of the group’s
E&A balance through to year end, to identify significant carrying
amounts with a significant current period risk of impairment (e.g. new
information from exploration activities, or imminent licence expiry).
We performed a look-back analysis of impairment charges recorded in
the period, and assessed whether impairment charges were timely.
We tested the completeness and accuracy of information used in
management’s E&A impairment assessment, by reviewing and
testing key controls over management’s register of E&A licences and
vouching key aspects of this to underlying support (e.g. licence
documentation); holding meetings and discussions with operational
and finance management; considering adverse changes in
management’s reserves and resource estimates associated with E&A
assets; reviewing correspondence with regulators and joint
arrangement partners; and considering the implications of capital
allocation decisions. When considering capital allocation decision
making, we considered whether any projects are unlikely to proceed
on the grounds that they are not currently consistent with BP’s
strategy or which would otherwise have a prohibitively high
environmental or social impact for the directors to sanction the
necessary investment.
Key observations
We concluded that the key assumptions had been appropriately determined, the judgements
management had made were appropriately supported, and no additional impairments were identified
from the work we performed.
Where BP had concluded that E&A costs should continue to be carried in respect of projects where
licences had expired, we obtained appropriate evidence that there was ongoing correspondence with the
relevant regulatory bodies, as referred to in Note 1 to the financial statements, to support management’s
judgement. We also confirmed management's view that they did not consider that the development of
any of their assets is inconsistent with BP’s strategy and stated climate change ambitions.
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118
BP Annual Report and Form 20-F 2018
Accounting for structured commodity transactions (SCTs) within the integrated supply and trading function (IST), and the valuation
of other level 3 financial instruments, where fraud risks may arise in revenue recognition
Key audit matter description
How the scope of our audit responded to the key audit matter
In the normal course of business, the integrated supply and trading
function (IST) enters into a variety of transactions for delivering value
across the group’s supply chain. The nature of these transactions
requires significant audit effort be directed towards challenging
management’s valuation estimates or the adopted accounting
treatment.
Accounting for structured commodity transactions: IST may also
enter into a variety of transactions which we refer to as SCTs. We
generally consider a SCT to be an arrangement having one of the
following features:
a) two or more counterparties with non-standard contractual
terms;
b) multiple commodity-based transactions; and/or
c) contractual arrangements entered into in contemplation of each
other.
SCTs are often long-dated, can have a significant multi-year financial
impact, and may require the use of complex valuation models or
unobservable market inputs when determining their fair value, in
which case they will be classified as level 3 financial instruments
under IFRS 13, Fair Value Measurement.
There are inherent risks in the accounting for SCTs as these
contracts are often complex and the associated accounting
considerations often feature multiple elements, which are subject to
management judgement, that will have a material impact on the
presentation and disclosure of these transactions on the primary
financial statements and key performance measures, including in
particular whether finance debt should be recognized. We have
identified the accounting for SCTs as a significant audit risk.
Level 3 financial instruments: Unlike other financial instruments
whose values or inputs are readily observable and therefore more
easily independently corroborated, there are certain transactions for
which the valuation is inherently more subjective due to the use of
either bespoke valuation models and/or unobservable inputs. These
instruments are classified as level 3 financial assets or liabilities
under IFRS 13. This degree of subjectivity also gives rise to potential
fraud through management incorporating bias in determining fair
values. Accordingly, we have identified these as a significant audit
risk, and the area in which a fraud risk is most likely to arise in
relation to revenue recognition.
As at 31 December 2018, the group’s total financial assets and
liabilities measured at fair value were $12.8 billion and $8.9 billion, of
which level 3 derivative financial instruments were $3.6 billion and
$3.1 billion, respectively.
Accounting for structured commodity transactions:
For structured commodity transactions, we performed audit
procedures to:
• Evaluate the design, implementation and operating effectiveness
of controls related to the review of such non-standard
transactions, including the:
• New activity integration control, which is designed to
evaluate and approve the appropriateness of the new
activity; and
• Accounting policy review, which is designed to evaluate the
appropriateness of accounting treatment in line with
published IFRS accounting literature.
• Develop an understanding of the commercial rationale of the
transactions through review of executed transaction documents
and discussions with management.
• Perform a detailed accounting analysis for a sample of structured
commodity transactions involving significant day 1 profits,
working capital arrangements, offtake arrangements and/or
commitments.
To assess the appropriateness of the accounting treatment of SCTs,
we embedded technical accounting specialists on the audit team to
assist in performing an assessment of the treatment applied by
management.
Other level 3 financial instruments:
To address the complexities associated with auditing the value of
level 3 financial instruments, our team included valuation specialists
having significant quantitative and modelling expertise to assist in
performing our audit procedures. Our valuation audit procedures
included the following control and substantive procedures:
We tested the design and operating effectiveness of the group’s
valuation controls including the:
• Model certification control, which is designed to review a
model’s theoretical soundness and the appropriateness of its
valuation methodology; and
• Independent price verification control, which is designed to
review the appropriateness of valuation inputs that are not
observable and are significant to the financial instrument’s
valuation.
We performed substantive valuation testing procedures at interim
and year-end balance sheet dates, including:
• Developing independent estimates, using externally sourced
inputs and challenger models to evaluate against management’s
fair value estimates by evaluating whether the differences
between our independent estimates and management’s
estimates were within a reasonable range;
• Evaluating management’s valuation methodologies against
standard valuation practice and analysing whether a consistent
framework is applied across the business period over period; and
• Benchmarking management’s input assumptions against the
expected assumptions of other market participants and
observable market data.
Key observations
We reviewed the features of 10 SCTs and determined that the accounting adopted for each of these was
appropriate and in accordance with IFRS.
We concluded that management’s valuations relating to level 3 instruments were appropriate.
We did not identify any transactions, valuation estimates or accounting entries which were the result of
fraudulent misrepresentation of revenue recognition.
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119
User access management controls relating to financial systems
Key audit matter description
How the scope of our audit responded to the key audit matter
The group’s financial systems environment is complex, with 107
separate systems scoped as being relevant for the group audit. In
addition, during the year, BP changed one of its key IT service
providers.
We obtained an understanding of management’s processes and
relevant financial systems and tested the associated general IT
controls. This testing led us to identify a number of deficiencies,
notably in relation to user access.
Due to the reliance on financial systems within the group, controls
over system user access are critical to maintaining an effective
control environment.
As a result of our procedures, we identified a number of deficiencies
relating to user access management, both within the group and the
group’s IT service organizations (together ‘access deficiencies’). The
access deficiencies identified increase the risk that individuals within
the group and at service organizations had inappropriate access
during the period. The existence of deficiencies during the year and at
the year end, and the transition of the main IT service organization
from one supplier to another during the year, result in an increased
risk that data and reports from the affected systems are not reliable.
The issues identified impact all components within the scope of our
group audit.
The group put in place a programme of activities to remediate the
deficiencies, which extends into 2019. Accordingly, management also
identified mitigating and compensating controls, and in particular
established controls to analyse, through exploitation analyses,
whether inappropriate access had been exploited during the year,
working with both the legacy and new IT service organizations.
The user access management controls are pervasive to the group’s
operations and accordingly the level of risk ascribed to our work in
this area is dependent on the nature and complexity of the control
itself and balances within the financial statements the control
addresses.
In responding to the identified deficiencies in user access we have
used our teams of IT and internal control specialists to:
• Test the controls that management has implemented or re-
designed in order to remediate the deficiencies;
• Assess and test the alternative or compensating controls that
management has identified as mitigating access deficiencies,
including the direct assessment of those controls operated by
the legacy and new IT service organizations and identified
business controls that do not rely on information that is
potentially affected by the access deficiencies; and
• Determine the impact that utilizing inappropriate levels of access
could feasibly have had on the affected systems including
assessing the likelihood of inappropriate user access impacting
the financial statements, and testing controls implemented by
management to identify instances of the use of inappropriate
access, working with both the legacy and new IT service
organizations.
Key observations
Our review of the analysis management performed to identify whether the access deficiencies were
exploited during the year did not identify instances where such access had been used inappropriately.
As a result, we were satisfied with the results of the remediation to date and mitigation activities such
that we continued to adopt an audit approach which places reliance on the effectiveness of financial
controls and which, under our methodology, enables us to apply lower sample sizes in our substantive
testing.
Management continues to work, with the support of the new IT service provider, to remediate fully the
access deficiencies identified.
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BP Annual Report and Form 20-F 2018
Management override of controls
Key audit matter description
How the scope of our audit responded to the key audit matter
We conducted a risk assessment for management override fraud
risks by considering:
• Potential areas where the group’s financial statements could be
We tested the relevant primary and, where necessary, compensating
controls that management identified as responding to the risk of
fraudulent journal entries.
manipulated;
• Pressures or incentives to achieve certain IFRS or non-GAAP
measures due to the remuneration arrangements of people in
Financial Reporting Oversight Roles (FRORs), including
management and senior executives;
• Potential for inappropriate accounting estimates and
judgements; and
• Accounting for significant unusual transactions and estimates
arising from changes to the business.
Our response to the risk of management override of controls
included testing the appropriateness of journal entries recorded in the
general ledger. We identified control deficiencies at components
where testing was performed and as a result, our audit approach
required adjustment. Management remediated the control
deficiencies identified where it was possible to do so. Some
remediation activity will continue into 2019 and accordingly,
management also directed us to other compensating controls which
they considered to mitigate the risks, which we subsequently tested.
This had a bearing on the allocation of resources in the audit, and the
direction of effort of the audit team. Accordingly, we identified this as
a key audit matter.
In addition, we have:
• Made inquiries of individuals involved in the financial reporting
process about inappropriate or unusual activity relating to the
processing of journal entries and other adjustments.
• Identified and tested relevant entity-level controls, in particular
those related to the BP Code of Conduct, whistleblowing (BP
OpenTalk) and controls monitoring financial reporting processes
and financial results.
• Used our data analytics tools to select journal entries and other
adjustments made at the end of a reporting period or otherwise
having characteristics which are associated with common fraud
schemes for testing.
• Tested journal entries and other adjustments recorded in the
general ledger throughout the period, with a particular focus on
adjustments that occur late in the financial close process.
We have reviewed accounting estimates for bias and evaluated
whether the circumstances producing the bias, if any, represent a risk
of material misstatement due to fraud. A number of the most
significant estimates are covered by the other Key Audit Matters set
out above. This assessment included:
• Evaluating whether the judgements and decisions made by
management in making the accounting estimates included in the
financial statements, even if they are individually reasonable,
indicate a possible bias on the part of BP's management that
may represent a risk of material misstatement due to fraud; and
• Performing a retrospective review of management judgements
and assumptions related to significant accounting estimates
reflected in the financial statements of the prior year.
We considered whether there were any significant transactions that
are outside the normal course of business, or that otherwise appear
to be unusual due to their nature, timing or size.
The risks and responses to the revenue recognition risks within the
integrated supply and trading function are set out above.
Key observations
The nature of the identified deficiencies over journal-entry controls varies from business to business, so
there is no single root cause. At the year end:
• In some businesses these operating effectiveness deficiencies were able to be remediated by
management and our testing of the remediation concluded it was effective.
• In other businesses the deficiencies could not be quickly remediated and management identified
direct and precise compensating controls to mitigate the design deficiencies identified. These
compensating controls included low-level analytical reviews (e.g. individual asset reviews), controls
over closing balances, period-end analytical review controls, and certain automated business
controls. Our testing of these compensating controls concluded that they were, in combination,
appropriately designed and implemented and that they were operating effectively for the period.
Our substantive testing of the journal entries and other adjustments, selected through the use of data
analytics tools, did not identify any inappropriate items, and accordingly we concluded that there was no
evidence of management override.
We did not identify any evidence of overall bias or any significant unusual transactions for which the
business rationale (or the lack thereof) of the transaction suggested that it may have been entered into to
engage in fraudulent financial reporting or to conceal misappropriation of assets.
Our application of materiality
We define materiality as the magnitude of misstatement in the financial statements that could reasonably be expected to influence the
economic decisions of a reasonably knowledgeable user. We use materiality both in planning the scope of our audit work and in evaluating the
results of our work.
Based on our professional judgement, we determined materiality for the financial statements as a whole as follows:
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121
Materiality
Basis for determining
materiality
Rationale for the
benchmark applied
Group financial statements
Parent company financial statements
Materiality has been set at $750 million for the current
year. In 2017, the previous auditor used a materiality of
$500 million. This reflects BP’s financial performance in
2018 and 2017.
We used a number of metrics to determine group
materiality, most notably profit before taxation and
underlying replacement cost profit before interest and
taxation. Our selected materiality figure represents
4.5% of profit before taxation, and 3.2% of underlying
replacement cost profit before interest and taxation. In
2017, the previous auditor used 5% of underlying
replacement cost profit before interest and taxation to
determine materiality.
Materiality has been set at $1,200 million for the
current year. In 2017, the previous auditor used a
materiality of $1,300 million.
We determined materiality for our audit of the
standalone parent using 1% of net assets.
We conducted an assessment of which line items we
understand to be the most important to investors and
analysts by reviewing analyst reports and BP’s
communications to shareholders and lenders, as well
as the communications of peer companies. This
assessment resulted in us selecting the financial
statement line items above.
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. As the company is non-
trading and operates primarily as a holding company,
we believe the net asset position is the most
appropriate benchmark to use.
Profit before tax is the benchmark ordinarily considered
by us when auditing listed entities. It provides
comparability against other companies across all
sectors, but has limitations when auditing companies
whose earnings are strongly correlated to commodity
prices, which can be volatile from one period to the
next, and therefore may not be representative of the
volume of transactions and the overall size of the
business in the year.
Where there were balances and transactions within the
parent company accounts that were within the scope
of the audit of the group financial statements, our
procedures were undertaken using the lower
materiality level applying to the group audit
components. It was only for the purposes of testing
balances not relevant to the group audit, such as
intercompany investment balances, that the higher
level of materiality applied in practice.
Whilst not a GAAP measure, underlying replacement
cost profit before interest and tax is one of the key
metrics communicated by management in BP's results
announcements. It excludes some of the volatility
arising from changes in crude oil, gas and product
prices as well as “non-operating items” and this was
also the key measure applied by the previous auditor
when determining materiality in 2017.
Profit before tax
$16,723 million
Profit before tax
Group materiality
Group materiality
$750 million
Component
materiality range
$413 million to
$150 million
Audit committee
reporting threshold
$25 million
Performance materiality, which is the value that determines the extent of our audit sampling, has been set at $375 million which is 50% of
group materiality (2017 75%). Given overall group materiality is higher in 2018 reflecting the improved results of the business, performance
materiality could also be set at a higher level but we judged it to be appropriate to constrain this for 2018 given it is our first year as auditor,
which gives a potentially heightened risk of not identifying misstatements due to us having a lower level of knowledge of the business than a
recurring auditor would have.
We agreed with the Main Board Audit Committee that we would report to the committee all audit differences in excess of $25 million (2017
$25 million), as well as differences below that threshold that, in our view, warranted reporting on qualitative grounds. We also report to the
audit committee on disclosure matters that we identified when assessing the overall presentation of the financial statements.
An overview of the scope of our audit
As a result of the highly disaggregated nature of the group, with operations in over 70 countries through approximately 1,000 components, a
significant portion of our audit planning effort was ensuring that the scope of our work is appropriate in addressing the identified risks of
material misstatement.
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BP Annual Report and Form 20-F 2018
The factors that we considered when assessing the scope of the BP audit, and the level of work to be performed at the components that are
in scope for group reporting purposes, included the following:
• The financial significance of an operating unit to BP’s revenue and profit before tax, or PP&E, including consideration of the financial
significance of specific account balances or transactions.
• The significance of specific risks relating to an operating unit, history of unusual or complex transactions, identification of significant audit
issues or the potential for, or a history of, material misstatements.
• The effectiveness of the control environment and monitoring activities, including entity-level controls.
• The findings, observations and audit differences that we noted as a result of the previous auditor’s 2016 and 2017 audit engagements.
To ensure we were able to obtain sufficient, appropriate audit evidence for the purposes of our audit of the financial statements, we performed
full scope audit procedures for 108 reporting consolidation units ('cons units' or components) which were selected based on their size or risk
characteristics. Our full-scope audits are in the UK, US, Angola, Azerbaijan, Germany and Singapore. One of the full-scope cons units includes
the investment in Rosneft, a material associate not controlled by BP.
In addition, we performed audit procedures on specified account balances by local teams for 16 cons units also covering operations in Trinidad
& Tobago and Australia. We performed audit procedures on specified account balances by segment teams to component materiality, with
certain additional specific procedures performed by local teams, covering an additional 12 cons units.
In our assessment of the residual balances, we have considered in particular the risk that there could be a material misstatement within the
large number of geographically dispersed businesses, in particular within the Downstream segment. This assessment included use of our
analytic tools to interrogate data, preparation of trend analysis and comparison of business performance to market benchmark prices. We
concluded that through this additional risk assessment, we have reduced the audit risk of such a misstatement arising to a sufficiently low
level.
The remaining components are not significant individually and include many small, low risk components and balances. On average, they each
represent 0.06% of group revenue and 0.08% of property, plant and equipment. For these components, we performed other procedures,
including conducting analytical review procedures, making inquiries, and evaluating and testing management’s group-wide controls across a
range of locations and segments in order to address the risk of residual misstatement on a segment-wide and component basis.
Oversight of component auditors
The group audit team provides direct oversight, review, and coordination of our local audit teams. The group audit team interacted regularly
with the local Deloitte teams during each stage of the audit, were responsible for the scope and direction of the audit process and reviewed
key working papers. We maintained continuous and open dialogue with our local teams in addition to holding formal meetings quarterly to
ensure that we were fully aware of their progress and results of their procedures.
The senior statutory auditor and other group audit partners and staff visited local component teams in all of the locations named above. These
visits included attending planning meetings, discussing the audit approach and any issues arising from the component team's work, meetings
with local management, and reviewing key audit working papers on higher and significant-risk areas to drive a consistent and high-quality audit.
We were provided with direct access to Rosneft’s auditor in order to evaluate their audit work on the financial statements of Rosneft, used as
the basis for BP’s equity accounting. We held meetings with Rosneft’s auditor throughout the year, issued audit instructions to them, reviewed
their written clearance reports responding to these instructions and, through our direct access, were able to exercise appropriate supervision
and oversight of their audit work. We also tested directly BP’s procedures and controls over its accounting for the investment in Rosneft.
19%
20%
9%
Property, plant
and equipment
8%
64%
3% Sales and other
6%
operating
revenues
71%
Full audit scope
Specified account balances
Specific audit procedures
Review at group level
Full audit scope
Specified account balances
Specific audit procedures
Review at group level
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BP Annual Report and Form 20-F 2018
123
Other information
The directors are responsible for the other information. The other information comprises the information included
in the annual report other than the financial statements and our auditor’s report thereon.
Our opinion on the financial statements does not cover the other information and, except to the extent otherwise
explicitly stated in our report, we do not express any form of assurance conclusion thereon.
We have nothing to
report in respect of
these matters.
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 this
other information, we are required to report that fact.
In this context, matters that we are specifically required to report to you as uncorrected material misstatements
of the other information include where we conclude that:
• Fair, balanced and understandable - 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 position and performance, business model and strategy, is
materially inconsistent with our knowledge obtained in the audit; or
• Audit committee reporting - 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 - 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.
Responsibilities of directors
As explained more fully in the directors’ responsibilities statement, 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’s and the 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 a reasonably knowledgeable user, taken on the basis of these financial statements.
Details of the extent to which the audit was considered capable of detecting irregularities, including fraud are set out below.
A further description of our responsibilities for the audit of the financial statements is located on the FRC’s website at: frc.org.uk/
auditorsresponsibilities. This description forms part of our auditor’s report.
Extent to which the audit was considered capable of detecting irregularities, including fraud
We identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and then design and
perform audit procedures responsive to those risks, including obtaining audit evidence that is sufficient and appropriate to provide a basis for
our opinion.
Identifying and assessing potential risks related to irregularities
In identifying and assessing risks of material misstatement in respect of irregularities, including fraud and non-compliance with laws and
regulations, our procedures included the following:
• Meeting throughout the year with the group head of ethics and compliance and reviewing BP’s internal ethics and compliance reporting
summaries, including concerning investigations;
• Enquiring of management, internal audit, and the audit committee, including obtaining and reviewing supporting documentation, concerning
the group’s policies and procedures relating to:
– identifying, evaluating and complying with laws and regulations and whether they were aware of any instances of non-compliance
– detecting and responding to the risks of fraud and whether they have knowledge of any actual, suspected or alleged fraud
– the internal controls established to mitigate risks related to fraud or non-compliance with laws and regulations;
• Discussing among the engagement team regarding how and where fraud might occur in the financial statements and any potential
indicators of fraud. The engagement team includes audit partners and staff who have extensive experience of working with companies in the
same sectors as BP operates, and this experience was relevant to the discussion about where fraud risks may arise. The discussions also
involved fraud experts from Deloitte’s forensic accounting function in the Corporate Finance service line, who advised the engagement team
of fraud schemes that had arisen in similar sectors and industries and participated in the initial fraud risk assessment brainstorming
discussions; and
• Obtaining an understanding of the legal and regulatory frameworks that the group operates in, focusing on those laws and regulations that
we determined had a direct effect on the financial statements or that had a fundamental effect on the operations of the group. These include
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124
BP Annual Report and Form 20-F 2018
the UK Companies Act, UK Corporate Governance Code, IFRS as issued by the IASB and adopted by the EU, FRS 101, US Securities
Exchange Act 1934 and relevant SEC regulations, as well as laws and regulations prevailing in each country in which we identified a full-
scope component. In addition, we considered compliance with terms of the group’s operating licence / regulatory solvency requirements /
environmental regulations when assessing the group’s ability to continue as a going concern.
Audit response to risks identified
As a result of performing the above, we did not identify any key audit matters related to the potential risk of non-compliance with laws and
regulations. We did identify two key audit matters relating to fraud risks, as described above.
Our procedures to respond to risks identified included the following:
• Reviewing the financial statement disclosures and testing supporting documentation to assess compliance with relevant laws and
regulations discussed above;
• Enquiring of management, the audit committee and legal counsel concerning actual and potential litigation and claims;
• Performing analytical procedures to identify any unusual or unexpected relationships that may indicate risks of material misstatement due to
fraud;
• Reading minutes of meetings of those charged with governance, reviewing internal audit reports and reviewing correspondence with
HMRC; and
• In addressing the risk of fraud through management override of controls, testing the appropriateness of journal entries and other
adjustments; assessing whether the judgements made in making accounting estimates are indicative of a potential bias; and evaluating the
business rationale of any significant transactions that are unusual or outside the normal course of business.
We also communicated relevant identified laws and regulations and potential fraud risks to all engagement team members, including internal
specialists and significant component audit teams, and remained alert to any indications of fraud or non-compliance with laws and regulations
throughout the audit.
Report on other legal and regulatory requirements
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.
In the light of the knowledge and understanding of the group and the parent company and their environment obtained in the course of the
audit, we have not identified any material misstatements in the strategic report or the directors’ report.
Matters on which we are required to report by exception
Adequacy of explanations received and accounting records
Under the Companies Act 2006 we are required to report to you if, in our opinion:
• We have not received all the information and explanations we require for our audit; or
• Adequate accounting records have not been kept by the parent company, or returns adequate for our audit
We have nothing to
report in respect of
these matters.
have not been received from branches not visited by us; or
• The parent company financial statements are not in agreement with the accounting records and returns.
Directors’ remuneration
Under the Companies Act 2006 we are also required to report if in our opinion certain disclosures of directors’
remuneration have not been made or the part of the directors’ remuneration report to be audited is not in
agreement with the accounting records and returns.
We have nothing to
report in respect of
these matters.
Other matters
Auditor tenure
The board appointed Deloitte as the company’s auditor with effect from 29 March 2018 to fill the vacancy arising from the resignation of the
previous auditor. On 21 May 2018, shareholders resolved at the annual general meeting to appoint Deloitte as auditor from the conclusion of
the meeting until the conclusion of the annual general meeting to be held in 2019 and authorized the directors to set the audit fees.
The first accounting period we audited was the 12 months ended 31 December 2018. In 2017, we commenced our audit planning procedures.
The period of total uninterrupted engagement including previous renewals and reappointments of the firm is accordingly one year.
Consistency of the audit report with the additional report to the audit committee
Our audit opinion is consistent with the additional report to the audit committee we are required to provide in accordance with ISAs (UK).
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.
Douglas King FCA (Senior statutory auditor)
For and on behalf of Deloitte LLP
Statutory Auditor
London, United Kingdom
29 March 2019
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BP Annual Report and Form 20-F 2018
125
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 sheet of BP p.l.c. and subsidiaries (the Company) as at 31 December 2018, the related
group income statement, statements of comprehensive income and changes in equity, and group cash flow statement, for the year ended
31 December 2018, and the related notes (collectively referred to as the 'financial statements'). In our opinion, the financial statements present
fairly, in all material respects, the financial position of the Company as of 31 December 2018, and the results of its operations and its cash
flows for the year ended 31 December 2018, 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 have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the
Company's internal control over financial reporting as of 31 December 2018, based on criteria established in the UK Financial Reporting
Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting relating to internal control over
financial reporting and our report dated 29 March 2019 expressed an unqualified opinion on the Company's internal control over financial
reporting.
Basis for opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's
financial statements 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 the financial statements are free of material misstatement, whether due to error or fraud. Our audit
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 audit 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 audit provides a reasonable basis
for our opinion.
/s/ Deloitte LLP
London
United Kingdom
29 March 2019
The first accounting period we audited was the 12 months ended 31 December 2018. In 2017, we commenced our audit planning procedures.
126
BP Annual Report and Form 20-F 2018
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 the internal control over financial reporting of BP p.l.c. and subsidiaries (the Company) as at 31 December 2018, based on the
criteria established in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business
Reporting relating to internal control over financial reporting (UK FRC Guidance). In our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of 31 December 2018, based on the criteria established in the UK FRC Guidance.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the
consolidated financial statements as at and for the year ended 31 December 2018, of the Company and our report dated 29 March 2019,
expressed an unqualified opinion on those financial statements.
As described in Management’s report on internal control over financial reporting on page 301, management excluded from its assessment the
internal control over financial reporting at Petrohawk Energy Corporation, which was acquired on 31 October 2018 and whose financial
statements constitute 10.3% and 4.0% of net and total assets, respectively, 0.2% of total revenues and other income, and 0.05% of profit for
the year of the consolidated financial statement amounts as at and for the year ended 31 December 2018. Accordingly, our audit did not include
the internal control over financial reporting at Petrohawk Energy Corporation.
Basis for opinion
The Company'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. 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/ Deloitte LLP
London, United Kingdom
29 March 2019
Consent of independent registered public accounting firm
We consent to the incorporation by reference of our reports dated 29 March 2019, relating to the consolidated financial statements of BP p.l.c.
(the 'company'), and the effectiveness of the company's internal control over financial reporting, appearing in the Annual Report on Form 20-F
of the company for the year ended 31 December 2018, in the following Registration Statements:
Registration Statements on Form F-3 (File Nos. 333-226485, 333-226485-01 and 333-226485-02) of BP p.l.c., BP Capital Markets
p.l.c. and BP Capital Markets America Inc.; 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, 333-210318) of BP p.l.c.
/s/ Deloitte LLP
London, United Kingdom
29 March 2019
BP Annual Report and Form 20-F 2018
127
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 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
two 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 the
results of its operations and its cash flows for each of the two 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.
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 served as the Company's auditor from 1909 to 2018.
London, United Kingdom
29 March 2018
Note that the report set out above is included for the purposes of BP p.l.c.’s Annual Report on Form 20-F for 2018 only and does not form part
of BP p.l.c.’s Annual Report and Accounts for 2017.
1.
2.
128
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 2018
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
2018
2017
5
16
17
7
4
19
5
5
4
8
7
24
9
11
11
11
11
298,756
897
2,856
773
456
303,738
229,878
23,005
1,536
15,457
860
1,445
12,179
19,378
2,528
127
16,723
7,145
9,578
9,383
195
9,578
46.98
46.67
2.82
2.80
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
$ million
2016
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
BP Annual Report and Form 20-F 2018
129
$ million
2016
172
254
30
1
(639)
196
81
—
—
833
13
769
(2,496)
—
739
(1,757)
(988)
(816)
(846)
30
(816)
Note
2018
9,578
2017
3,468
(3,771)
1,986
—
—
(126)
120
—
(244)
58
417
4
(3,542)
2,317
(37)
(718)
1,562
(1,980)
7,598
7,444
154
7,598
(120)
14
197
116
112
—
—
564
(196)
2,673
3,646
—
(1,303)
2,343
5,016
8,484
8,353
131
8,484
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
Costs of hedging marked to market
Costs of hedging reclassified to the income statement
Share of items relating to equity-accounted entities, net of tax
Income tax relating to items that may be reclassified
30
30
30
30
30
16, 17
9
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Cash flow hedges that will subsequently be transferred to the balance sheet
Income tax relating to items that will not be reclassified
24
30
9
Other comprehensive income
Total comprehensive income
Attributable to
BP shareholders
Non-controlling interests
a See Note 32 for further information.
130
BP Annual Report and Form 20-F 2018
Group statement of changes in equitya
At 31 December 2017
Adjustment on adoption of IFRS 9, net of tax
At 1 January 2018
Profit (loss) for the year
Other comprehensive income
Total comprehensive income
Dividendsb
Cash flow hedges transferred to the balance
sheet, net of tax
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 2018
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
a See Note 32 for further information.
b See Note 10 for further information.
Share
capital and
capital
reserves
46,122
—
46,122
—
—
—
—
—
—
230
—
—
Treasury
shares
(16,958)
—
(16,958)
—
—
—
—
—
—
1,191
—
—
Foreign
currency
translation
reserve
(5,156)
—
(5,156)
—
(3,746)
(3,746)
—
—
—
—
—
—
Fair value
reserves
Profit and
loss
account
BP
shareholders'
equity
Non-
controlling
interests Total equity
$ million
(743)
(54)
(797)
—
(216)
(216)
—
26
—
—
—
—
75,226
(126)
75,100
9,383
2,023
11,406
(6,699)
—
(355)
(718)
14
—
98,491
(180)
98,311
9,383
(1,939)
7,444
(6,699)
26
(355)
703
14
—
1,913
—
1,913
195
(41)
154
(170)
100,404
(180)
100,224
9,578
(1,980)
7,598
(6,869)
—
—
—
—
207
26
(355)
703
14
207
46,352
(15,767)
(8,902)
(987)
78,748
99,444
2,104
101,548
46,122
—
—
—
—
—
—
—
—
(18,443)
—
—
—
—
—
1,485
—
—
(6,878)
—
1,722
1,722
—
—
—
—
—
(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
BP Annual Report and Form 20-F 2018
131
Note
2018
12
14
15
16
17
18
20
30
9
24
19
20
30
18
25
22
30
26
23
22
30
26
9
23
24
32
32
32
135,261
12,204
17,284
8,647
17,673
1,341
192,410
637
1,834
5,145
1,179
3,706
5,955
210,866
326
17,988
24,478
3,846
963
1,019
222
22,468
71,310
282,176
46,265
3,308
4,626
9,373
2,101
2,564
68,237
13,830
5,625
575
56,426
9,812
17,732
8,391
112,391
180,628
101,548
99,444
2,104
101,548
$ million
2017
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
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
Helge Lund Chairman
R W Dudley Group chief executive
29 March 2019
132
BP Annual Report and Form 20-F 2018
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
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 yeara
Cash and cash equivalents at end of year
a See Note 1 for further information.
Note
2018
2017
$ million
2016
16,723
7,180
(2,295)
8
5
4
7
24
24
3
4
4
10
1,085
15,457
404
(3,753)
1,535
(468)
348
2,528
(1,928)
127
690
(386)
986
672
(2,858)
(2,577)
(5,712)
22,873
(16,707)
(6,986)
(382)
(1,013)
(25,088)
940
1,911
666
(21,571)
(355)
9,038
(7,210)
1,317
—
(6,699)
(170)
(4,079)
(330)
(3,107)
25,575
22,468
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
BP Annual Report and Form 20-F 2018
133
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 BP p.l.c and its subsidiaries (collectively referred to as BP or the group) for the year ended
31 December 2018 were approved and signed by the group chief executive and chairman on 29 March 2019 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 as
applicable to companies reporting under IFRS. 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 2018. The accounting policies that follow have been
consistently applied to all years presented, except where otherwise indicated.
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 consolidated 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 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 the investment in Rosneft;
oil and natural gas accounting, including the estimation of reserves; the recoverability of asset carrying values; derivative financial instruments;
provisions and contingencies; and pensions and other post-retirement benefits. 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. The group no longer considers the recoverability of trade receivables to represent one of its significant accounting judgements following
the adoption of IFRS 9 ‘Financial Instruments´ and resulting recognition of expected credit losses, see Impact of new International Financial
Reporting Standards for more information. The group does not consider income taxes to represent a significant estimate or judgement for
2018, see Income taxes for more information.
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 14 for further information.
Goodwill may 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.
Goodwill may also arise upon acquisition of interests in joint operations that meet the definition of a business. The amount of goodwill
separately recognized is the excess of the consideration transferred over the group's share of the net fair value of the identifiable assets and
liabilities.
Interests in joint arrangements
The results, assets and liabilities of joint ventures are incorporated in these consolidated 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 consolidated financial statements using the equity method of
accounting as described below.
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BP Annual Report and Form 20-F 2018
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 investment in an equity instrument measured at fair value 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 2018. 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 there is objective evidence that the investment is
impaired. If any such objective evidence of impairment exists, the carrying amount of the investment is compared with its recoverable amount,
being the higher of its fair value less costs of disposal and value in use. If the carrying amount exceeds the recoverable amount, the
investment is written down to its recoverable amount.
Segmental reporting
The group’s operating segments are established on the basis of those components of the group that are evaluated regularly by the group chief
executive, BP’s chief operating decision maker, in deciding how to allocate resources and in assessing performance.
The accounting policies of the operating segments are the same as the group’s accounting policies described in this note, except that IFRS
requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating
decision maker. For BP, this measure of profit or loss is replacement cost profit before interest and tax which reflects the replacement cost of
inventories sold in the period and is arrived at by excluding inventory holding gains and losses from profit. Replacement cost profit for the
group is not a recognized measure under IFRS. For further information see Note 5.
Foreign currency translation
In individual subsidiaries, joint ventures and associates, transactions in foreign currencies are initially recorded in the functional currency of
those entities at the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are
retranslated into the functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange differences are included
in the income statement, unless hedge accounting is applied. Non-monetary assets and liabilities, other than those measured at fair value, are
not retranslated subsequent to initial recognition.
In the consolidated financial statements, the assets and liabilities of non-US dollar functional currency subsidiaries, joint ventures, associates,
and related goodwill, are translated into US dollars at the spot exchange rate on the balance sheet date. The results and cash flows of non-US
dollar functional currency subsidiaries, joint ventures and associates are translated into US dollars using average rates of exchange. In the
consolidated financial statements, exchange adjustments arising when the opening net assets and the profits for the year retained by non-US
dollar functional currency subsidiaries, joint ventures and associates are translated into US dollars are recognized in a separate component of
equity and reported in other comprehensive income. Exchange gains and losses arising on long-term intra-group foreign currency borrowings
used to finance the group’s non-US dollar investments are also reported in other comprehensive income if the borrowings form part of the net
investment in the subsidiary, joint venture or associate. On disposal or for certain partial disposals 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.
Significant 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 2018
135
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 are carried initially at cost unless acquired as part of a business combination. Any such asset is measured at fair value at the
date of the business combination 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 and the amortization method are reviewed on an annual basis and, if necessary, changes in useful lives or
the amortization method 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. This includes costs relating to exploration licences or leasehold property acquisitions. 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. The carrying amount of capitalized costs is included in Note 8.
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BP Annual Report and Form 20-F 2018
1. Significant accounting policies, judgements, estimates and assumptions – continued
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 general or specific finance
costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the
asset. The capitalized value of a finance lease is also included within property, plant and equipment.
Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul
costs. Where an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits
associated with the item will flow to the group, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized.
Inspection costs associated with major maintenance programmes are capitalized and amortized over the period to the next inspection.
Overhaul costs for major maintenance programmes, and all other maintenance costs are expensed as incurred.
Oil and natural gas properties, including related pipelines, are depreciated using a unit-of-production method. The cost of producing wells is
amortized over proved developed reserves. Licence acquisition, common facilities and future decommissioning costs are amortized over total
proved reserves. The unit-of-production rate for the depreciation of common facilities takes into account expenditures incurred to date,
together with estimated future capital expenditure expected to be incurred relating to as yet undeveloped reserves expected to be processed
through these common facilities. 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 12 and Note 5 respectively.
Estimates of oil and natural gas reserves determined by applying US Securities and Exchange Commission regulations including the
determination of prices using 12-month historical data 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.
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 210, which is unaudited. Details on BP’s proved reserves and production compliance and governance processes are
provided on page 286. The 2018 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 210.
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 and depreciation method of property, plant and equipment are reviewed on an annual basis and, if necessary,
changes in useful lives or the depreciation method 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.
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.
BP Annual Report and Form 20-F 2018
137
1. Significant accounting policies, judgements, estimates and assumptions – continued
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 that are not reflected in the discount rate and are discounted to their present value typically
using a pre-tax discount rate that reflects current market assessments of the time value of money.
Fair value less costs of disposal is the price that would be received to sell the asset in an orderly transaction between market participants and
does not reflect the effects of factors that may be specific to the group and not applicable to entities in general.
An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no
longer exist or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss
is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss
was recognized. If that is the case, the carrying amount of the asset is increased to the lower of its recoverable amount and the carrying
amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years.
Impairment reversals are recognized in profit or loss. After a reversal, the depreciation charge is adjusted in future periods to allocate the
asset’s revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.
Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate the recoverable amount of the
group of CGUs to which the goodwill relates should be assessed. In assessing whether goodwill has been impaired, the carrying amount of
the group of CGUs to which goodwill has been allocated is compared with its recoverable amount. Where the recoverable amount of the group
of 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. For example, certain oil and gas properties with shared
infrastructure may be grouped together to form a single CGU. Alternative groupings of assets or CGUs may result in a different outcome
from impairment testing. See Note 14 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 expected sales proceeds or similar recent market transaction data or, where recent market
transactions 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, estimates 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.
Details of impairment charges and reversals recognized in the income statement are provided in Note 4 and details on the carrying amounts
of assets are shown in Note 12, Note 14 and Note 15.
The estimates for assumptions made in impairment tests in 2018 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 discounted cash flow calculations, future cash flows are adjusted for risks specific to the cash-generating unit. Value-in-use calculations
are typically discounted using a pre-tax discount rate 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 2018 the post-tax discount rate was 6% (2017 6%) and the pre-
tax discount rate was 9% (2017 9%). 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 (2017 2%). The judgement of classifying a country as higher risk takes into account various
economic and geopolitical factors.
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.
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 value-in-use impairment tests from 2024 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 (2017 $75
per barrel and $4/mmBtu, both in 2015 prices, from 2023 onwards).
The price assumptions used for the five-year period to 2023 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.
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BP Annual Report and Form 20-F 2018
1. Significant accounting policies, judgements, estimates and assumptions – continued
Oil prices rebounded in 2018 in the face of cooperative production restraint from OPEC and some non-OPEC producers, but weakened late in
the year as production restraint eased and US supply recorded record growth. 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, especially given the financial requirements of key low-cost oil producing economies.
US gas prices remained relatively low for much of 2018, before increasing temporarily in the final quarter due to a combination of low storage
and cold weather. Strong growth of low-cost supply helped to moderate prices through much of the year. BP's long-term price assumption
for US gas is higher than recent market prices as US gas demand is expected to grow strongly, both domestic demand as well as exports of
liquefied natural gas, absorbing the lowest cost resources from the sweet spots, and forcing producers to go to more expensive/drier gas, as
well as requiring increased investment in infrastructure.
Oil and natural gas reserves
In addition to oil and gas prices, significant technical and commercial assessments 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 and drilling of new wells 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.
Reserves assumptions for value-in-use and fair value tests reflect the reserves and resources that management currently intend to develop.
The recoverable amount of oil and gas properties is determined using a combination of inputs including reserves, resources and production
volumes. Risk factors may be applied to reserves and resources which do not meet the criteria to be treated as proved.
The interdependency of these inputs, risk factors and the wide diversity of our oil and gas properties limits the practicability of estimating the
probability or extent to which the overall recoverable amount is impacted by changes to one or more of the underlying assumptions. The
recoverable amount of oil and gas properties is primarily sensitive to changes in the long-term oil and gas price assumptions. Management do
not expect a change in these long-term price assumptions within the next financial year that would result in a material impairment charge.
However, sensitivity analysis may be performed if a specific oil and gas property is identified to have low headroom above its carrying amount.
In 2018, the group identified oil and gas properties with carrying amounts totalling $22,000 million where the headroom, as at the dates of the
last impairment test performed on those assets, was less than or equal to 20% of the carrying value, including $1,345 million in relation to
equity-accounted entities. A change in the discount rate, reserves, resources or the oil and gas price assumptions in the next financial year may
result in the recoverable amount of one or more of these assets falling below the current carrying amount.
Goodwill
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 $12.2 billion on its balance sheet (2017 $11.6 billion), principally relating to the
Atlantic Richfield, Burmah Castrol, Devon Energy and Reliance transactions. If there are low oil or natural gas prices for an extended period or
the long-term price outlook weakens, 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 14.
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
except where capitalized as exploration or appraisal expenditure. See significant accounting policy: Exploration and appraisal expenditure.
Financial assets
Financial assets are recognized initially at fair value, normally being the transaction price. In the case of financial assets not at fair value through
profit or loss, directly attributable transaction costs are also included. 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. This includes the derecognition of receivables for which discounting arrangements are entered into.
From 1 January 2018, the group classifies its financial asset debt instruments as measured at amortized cost, fair value through other
comprehensive income or fair value through profit or loss. The classification depends on the business model for managing the financial assets
and the contractual cash flow characteristics of the financial asset.
Financial assets measured at amortized cost
Financial assets are classified as measured at amortized cost when they are held in a business model the objective of which is to collect
contractual cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortized
cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the
assets are derecognized or impaired and when interest is recognized using the effective interest method. This category of financial assets
includes trade and other receivables.
BP Annual Report and Form 20-F 2018
139
1. Significant accounting policies, judgements, estimates and assumptions – continued
Financial assets measured at fair value through other comprehensive income
Financial assets are classified as measured at fair value through other comprehensive income when they are held in a business model the
objective of which is both to collect contractual cash flows and sell the financial assets, and the contractual cash flows represent solely
payments of principal and interest. The group does not have any financial assets classified in this category.
Financial assets measured at fair value through profit or loss
Financial assets are classified as measured at fair value through profit or loss when the asset does not meet the criteria to be measured at
amortized cost or fair value through other comprehensive income. Such assets 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 included in this
category.
Investments in equity instruments
Investments in equity instruments are subsequently measured at fair value through profit or loss unless an election is made on an instrument-
by-instrument basis to recognise fair value gains and losses in other comprehensive income.
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.
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
financial assets measured at amortized cost or fair value through profit or loss.
Impairment of financial assets measured at amortized cost
The group assesses on a forward looking basis the expected credit losses associated with financial assets classified as measured at amortized
cost at each balance sheet date. Expected credit losses are measured based on the maximum contractual period over which the group is
exposed to credit risk. Since this is typically less than 12 months there is no significant difference between the measurement of 12-month and
lifetime expected credit losses for the group's in-scope financial assets. The measurement of expected credit losses is a function of the
probability of default, loss given default and exposure at default. The expected credit loss is estimated as the difference between the asset’s
carrying amount and the present value of the future cash flows the group expects to receive discounted at the financial asset’s original
effective interest rate. The carrying amount of the asset is adjusted, with the amount of the impairment gain or loss recognized in the income
statement.
A financial asset or group of financial assets classified as measured at amortized cost is considered to be credit-impaired if there is reasonable
and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset (or
group of financial assets) have occurred. Financial assets are written off where the group has no reasonable expectation of recovering amounts
due.
Financial liabilities
The measurement of financial liabilities depends on their classification, as follows:
Financial liabilities measured at fair value through profit or loss
Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities 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 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 directly attributable transaction costs. For interest-bearing loans and
borrowings this is typically equivalent to 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.
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 at inception of a contract are recognized immediately in the income statement.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
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, the existence at inception of an economic relationship and subsequent measurement of the hedging instrument's
effectiveness in offsetting the exposure to changes in the hedged item’s fair value or cash flows attributable to the hedged risk, the hedge
ratio and sources of hedge ineffectiveness. 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, where it offsets. The
group applies fair value hedge accounting when hedging interest rate risk and certain currency risks on fixed rate finance debt.
Fair value hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This
includes when the risk management objective changes or when the hedging instrument is sold, terminated or exercised. The accumulated
adjustment to the carrying amount of a hedged item at such time is then amortized prospectively to profit or loss as finance interest expense
over the hedged item's 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 highly probably forecast transaction that results in the recognition of 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 transferred 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.
Cash flow hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This
includes when the designated hedged forecast transaction or part thereof is no longer considered to be highly probable to occur, or when the
hedging instrument is sold, terminated or exercised without replacement or rollover. When cash flow hedge accounting is discontinued
amounts previously recognized within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified
to profit or loss or transferred 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 profit or loss.
Costs of hedging
Time value of options and the foreign currency basis spread of cross-currency interest rate swaps are excluded from hedge designations and
accounted for as costs of hedging. Changes in fair value of the time-value component of option contracts and the foreign currency basis spread
of cross-currency interest rate swaps are recognized in other comprehensive income to the extent that they relate to the hedged item. For
transaction-related hedged items, the amount recognized in other comprehensive income is reclassified to profit or loss when the hedged
transaction affects profit or loss. For time-period related hedged items, the amount recognized in other comprehensive income is amortized to
profit or loss on a straight line over the term of the hedging relationship.
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 financial instruments
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 historical and long-term pricing relationships. Price volatility is also an input for options models. Changes in the key
assumptions, in particular price curves, could have a material impact on the carrying amounts of derivative assets and liabilities in the next
financial year. The impact on net assets and the Group income statement would be limited as a result of offsetting movements on derivative
assets and liabilities. For more information see Note 30.
In some cases, judgement is required to determine whether contracts to buy or sell commodities meet the definition of a derivative. In
particular longer -term contracts to buy and sell LNG are not considered to meet the definition as they are not considered capable of being
net settled due to a lack of liquidity in the LNG market 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.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
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. Provisions are discounted using a nominal discount rate of 3.0% (2017 2.5%).
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 consolidated 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
future prices, depending on the expected timing of the activity, and discounted using the nominal discount rate. The weighted average period
over which these costs are generally expected to be incurred is estimated to be approximately 18 years.
An amount equivalent to the decommissioning provision is recognized as part of the corresponding intangible asset (in the case of an
exploration or appraisal well) or property, plant and equipment. The decommissioning portion of the property, plant and equipment is
subsequently depreciated at the same rate as the rest of the asset. Other than the unwinding of discount on the provision, any change in the
present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding asset where that asset is
generating or is expected to generate future economic benefits.
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 future prices and discounted using a nominal discount rate. The weighted-average period over
which these costs are generally expected to be incurred is estimated to be approximately six years.
Significant judgements and estimates: provisions
The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their
economic lives. The largest decommissioning obligations facing BP relate to the plugging and abandonment of wells and the removal and
disposal of oil and natural gas platforms and pipelines around the world. Most of these decommissioning events are many years in the future
and the precise requirements that will have to be met when the removal event occurs are uncertain. Decommissioning technologies and
costs are constantly changing, as 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 2018 was
a nominal rate of 3.0% (2017 a real rate of 0.5% and a nominal rate of 2.5%), which was based on long-dated US government bonds.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
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. A 0.5% change in the nominal discount rate could have an
impact of approximately $1.3 billion on the value of the group’s provisions, excluding those relating to the Gulf of Mexico oil spill. The impact
on the group income statement would not be significant as the majority of the group’s provisions relate to decommissioning costs.
As described in Note 33, the group is subject to 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.
Change in significant estimate - decommissioning provision
Decommissioning provision cost estimates are reviewed regularly and such a review was undertaken in the second quarter of 2018. The
timing and amount of estimated future expenditures were re-assessed and discounted to determine the present value. From 30 June 2018
the present value of the decommissioning provision is determined by discounting the estimated cash flows expressed in expected future
prices, i.e. taking account of expected inflation, at a nominal discount rate of 2.5% as at 30 June 2018. Prior to 30 June 2018, the group
estimated future cash flows in real terms i.e. at current prices and discounted them using a real discount rate of 0.5% as at 31 December
2017.
The impact of the review was a reduction in the provision of $1.5 billion as at 30 June 2018, with a similar reduction in the carrying amount of
property, plant and equipment. There was no significant impact on the income statement for the first half of 2018. The impact on the income
statement for the second half of 2018 was a decrease in depreciation, depletion and amortization of approximately $80 million and an
increase in finance costs of approximately $80 million.
The nominal discount rate applied to provisions was revised at 31 December 2018 to 3.0%. The impact of this increase was a further $1.3-
billion reduction in the decommissioning provision, with a similar reduction in the carrying amount of property, plant and equipment.
Employee benefits
Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated
services are rendered by employees of the group. Deferred bonus arrangements that have a vesting date more than 12 months after the
balance sheet date are valued on an actuarial basis using the projected unit credit method and amortized on a straight-line basis over the
service period until the award vests. The accounting policies for share-based payments and for pensions and other post-retirement benefits are
described below.
Share-based payments
Equity-settled transactions
The cost of equity-settled transactions with employees is measured by reference to the fair value of the equity instruments on the date on
which they are granted and is recognized as an expense over the vesting period, which ends on the date on which the employees become fully
entitled to the award. A corresponding credit is recognized within equity. Fair value is determined by using an appropriate, widely used,
valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other than conditions linked to the price of
the shares of the company (market conditions). Non-vesting conditions, such as the condition that employees contribute to a savings-related
plan, are taken into account in the grant-date fair value, and failure to meet a non-vesting condition, where this is within the control of the
employee is treated as a cancellation and any remaining unrecognized cost is expensed.
For other equity-settled share-based payment transactions, the goods or services received and the corresponding increase in equity are
measured at the fair value of the goods or services received unless their fair value cannot be reliably estimated. If the fair value of the goods
and services received cannot be reliably estimated, the transaction is measured by reference to the fair value of the equity instruments
granted.
Cash-settled transactions
The cost of cash-settled transactions is recognized as an expense over the vesting period, measured by reference to the fair value of the
corresponding liability which is recognized on the balance sheet. The liability is remeasured at fair value at each balance sheet date until
settlement, with changes in fair value recognized in the income statement.
Pensions and other post-retirement benefits
The cost of providing benefits under the group’s defined benefit plans is determined separately for each plan using the projected unit credit
method, which attributes entitlement to benefits to the current period to determine current service cost and to the current and prior periods to
determine the present value of the defined benefit obligation. Past service costs, resulting from either a plan amendment or a curtailment (a
reduction in future obligations as a result of a material reduction in the plan membership), are recognized immediately when the company
becomes committed to a change.
Net interest expense relating to pensions and other post-retirement benefits, which is recognized in the income statement, represents the net
change in present value of plan obligations and the value of plan assets resulting from the passage of time, and is determined by applying the
discount rate to the present value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year,
taking into account expected changes in the obligation or plan assets during the year.
Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding
amounts included in net interest described above) are recognized within other comprehensive income in the period in which they occur and
are not subsequently reclassified to profit and loss.
The defined benefit pension plan surplus or deficit recognized on the balance sheet for each plan comprises the difference between the
present value of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets
out of which the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is
the published bid price. Defined benefit pension plan surpluses are only recognized to the extent they are recoverable, either by way of a
refund from the plan or reductions in future contributions to the plan.
Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
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, in particular for the UK, US and Eurozone plans. 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 24.
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 or
increased to the extent that it is 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.
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.
Management do not assess there to be a significant risk of a material change to the group’s tax provisioning or recognition of deferred tax
assets within the next financial year, however the tax position remains inherently uncertain and therefore subject to change. 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 9 and Note 33.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
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 in accordance with the applicable accounting policy such as Provisions and contingencies. No new
significant judgements were made in 2018 in this regard.
Customs duties and sales taxes
Customs duties and sales taxes that are passed on or charged 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 consolidated financial statements as treasury shares. Consideration, if any, received for the sale of such shares
is also recognized in equity. 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 and other income
Revenue from contracts with customers is recognized when or as the group satisfies a performance obligation by transferring control of a
promised good or service to a customer. The transfer of control of oil, natural gas, natural gas liquids, LNG, petroleum and chemical products,
and other items 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; the amounts of revenue recognized relating to performance obligations satisfied over
time are not significant.
When, or as, a performance obligation is satisfied, the group recognizes as revenue the amount of the transaction price that is allocated to that
performance obligation. The transaction price is the amount of consideration to which the group expects to be entitled. The transaction price is
allocated to the performance obligations in the contract based on standalone selling prices of the goods or services promised.
Contracts for the sale of commodities are typically priced by reference to quoted prices. Revenue from term commodity contracts is
recognized based on the contractual pricing provisions for each delivery. Certain of these contracts have pricing terms based on prices at a
point in time after delivery has been made. Revenue from such contracts is initially recognized based on relevant prices at the time of delivery
and subsequently adjusted as appropriate.
Physical exchanges with counterparties in the same line of business in order to facilitate sales to customers are reported net, as are sales and
purchases made with a common counterparty, as part of an arrangement similar to a physical exchange.
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.
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.
Interest income is recognized as the interest accrues (using the effective interest rate, that is, the rate that exactly discounts estimated future
cash receipts through the expected life of the financial instrument to the net carrying amount of the financial asset).
Dividend income from investments is recognized when the shareholders’ right to receive the payment is established.
Finance costs
Finance costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a
substantial period of time to get ready for their intended use, are added to the cost of those assets until such time as the assets are
substantially ready for their intended use. All other finance costs are recognized in the income statement in the period in which they are
incurred.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
Impact of new International Financial Reporting Standards
BP adopted two new accounting standards issued by the IASB with effect from 1 January 2018, IFRS 9 ‘Financial instruments’ and IFRS 15
‘Revenue from contracts with customers’. There are no other new or amended standards or interpretations adopted during the year that have a
significant impact on the consolidated financial statements.
IFRS 9 ‘Financial Instruments’
IFRS 9 ‘Financial Instruments’ was issued in July 2014 and replaced IAS 39 ‘Financial Instruments: Recognition and Measurement.’ BP adopted
IFRS 9 and the related consequential amendments to other IFRSs in the financial reporting period commencing 1 January 2018. The group has
applied the new standard in accordance with the transition provisions of IFRS 9. Comparatives have not been restated and adjustments on
transition have been reported in opening retained earnings at 1 January 2018.
The group’s revised accounting policies in relation to financial instruments are provided above.
The overall impact on transition to IFRS 9, including the impact upon the group's share of equity-accounted entities, was a reduction of $180
million in net assets, net of tax. This adjustment mainly related to an increase in the loss allowance for financial assets in the scope of IFRS 9's
impairment requirements. As comparatives have not been restated the closing balance at 31 December 2017 for certain line items in the
balance sheet differ from the opening balance at 1 January 2018 (as summarized below). Cash and cash equivalents at the beginning of 2018 in
the Group cash flow statement are the 1 January 2018 amounts included in the table below.
Non-current
Investments in equity-accounted entities
Loans, trade and other receivables
Deferred tax liabilities
Current
Loans, trade and other receivables
Cash and cash equivalents
Net assets
Reserves
Available-for-sale investments
Costs of hedging
Profit and loss account
31 December 2017
1 January 2018
$ million
Adjustment on
adoption of IFRS 9
24,985
2,080
(7,982)
25,039
25,586
24,903
2,069
(7,946)
24,927
25,575
100,404
100,224
17
—
75,226
75,243
—
(37)
75,100
75,063
(82)
(11)
36
(112)
(11)
(180)
(17)
(37)
(126)
(180)
Classification and measurement
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. For financial liabilities the existing classification and measurement requirements of IAS 39 are
largely retained.
The table below illustrates the classification and carrying amounts of financial assets under IFRS 9 and IAS 39 at the date of initial application, 1
January 2018. There were no differences in classification or carrying amounts for financial liabilities and no differences in the measurement of
liabilities for financial guarantee contracts.
At 1 January 2018
Financial assets
Other investments – equity shares
– other
– other
Loans
Loans
Trade and other receivables
Derivative financial instruments
Derivative financial instruments
Cash and cash equivalents
Cash and cash equivalents
Cash and cash equivalents
Cash and cash equivalents
Classification under IAS 39
Classification under IFRS 9
Available-for-sale
financial assets
Available-for-sale
financial assets
At fair value through
profit or loss
Loans and receivables Amortized cost
Loans and receivables Fair value through
Fair value through
profit or loss
Fair value through
profit or loss
Fair value through
profit or loss
profit or loss
Fair value through
profit or loss
Derivative hedging
instruments
Loans and receivables Amortized cost
At fair value through
profit or loss
Derivative hedging
instruments
Loans and receivables Amortized cost
Available-for-sale
financial assets
Available-for-sale
financial assets
Held-to-maturity
investments
Fair value through
profit or loss
Amortized cost
Amortized cost
146
BP Annual Report and Form 20-F 2018
Carrying
amount
under IAS 39
Measurement
category
adjustment
on transition
Measurement
attribute
adjustment
on transition
$ million
Carrying
amount
under IFRS 9
433
275
662
836
—
24,361
6,454
688
21,916
—
—
—
(100)
100
—
—
—
—
2,270
(2,058)
—
2,058
1,400
59,295
—
—
—
—
—
—
(8)
433
275
662
736
92
(115)
24,246
—
—
6,454
688
(11)
21,905
—
—
—
212
2,058
1,400
(134)
59,161
1. Significant accounting policies, judgements, estimates and assumptions – continued
Other investments existing on transition that were classified as available-for-sale financial assets under IAS 39 are classified as mandatorily
measured at fair value through profit or loss (FVTPL) under IFRS 9. The contractual terms of these assets do not give rise to cash flows that are
solely payments of principal and interest. Fair value gains and losses will be recognized in profit or loss rather than in other comprehensive
income as was the case under IAS 39. An adjustment to the 2018 opening balance sheet was 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.
Certain loans that were classified as loans and receivables under IAS 39 have been classified as mandatorily measured at FVTPL under IFRS 9
as a result of the business model in which they are held. The adjustment of $8m to the carrying amount of these assets on transition reflects
the difference between amortized cost measurement under IAS 39 and fair value measurement under IFRS 9.
Cash and cash equivalents that were classified as available-for-sale and held-to-maturity financial assets under IAS 39 have been classified as
either measured at amortized cost or measured at FVTPL under IFRS 9. Cash and cash equivalents measured at FVTPL comprise money
market funds that do not give rise to cash flows that are solely payments of principal and interest. For cash and cash equivalents that have
been reclassified to measured at amortized cost, the carrying amount of those assets at the end of the reporting period approximate their fair
value. The fair value gain or loss that would have been recognized in other comprehensive income in the reporting period if those financial
assets had not been reclassified to amortized cost is immaterial.
Adjustments to the carrying amount of financial assets classified as measured at amortized cost under IFRS 9 relate entirely to the additional
loss allowance required by the new standard's expected credit loss model.
There were no financial assets or financial liabilities which the group had previously designated as at FVTPL under IAS 39 that were required to
be reclassified, or which the group has elected to reclassify upon the application of IFRS 9. The group did not elect to designate at FVTPL any
financial assets or financial liabilities at the date of initial application of IFRS 9.
Under IFRS 9 the group has elected to apply hedge accounting prospectively to certain of its commodity price risk management activities for
which hedge accounting was not possible under IAS 39. Certain derivatives that were previously classified as at FVTPL have therefore been
reclassified to derivative hedging instruments at 1 January 2018. As the hedging instruments are exchange traded derivatives, the value
transferred on transition was nil.
Impairment
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. The adjustment to the 2018 opening balance sheet relating to expected credit loss
reduced both the carrying amounts of financial assets and the profit and loss account reserve.
The table below reconciles the ending impairment allowances in accordance with IAS 39 and the provisions in accordance with IAS 37 to the
opening loss allowances determined in accordance with IFRS 9.
Classification under IAS 39
Classification under IFRS 9
Available-for-sale
financial assets
Loans and receivables Amortized cost
Loans and receivables Amortized cost
Fair value through
profit or loss
At 1 January 2018
Financial assets
Other investments – equity shares
Trade and other receivables
Cash and cash equivalents
Total loss allowance on financial assets
Loans that form part of the net
investment in equity-accounted
entities
Total loss allowance
Measurement
category
effect on
transition
Measurement
attribute
adjustment
on transition
IAS 39 loss
allowance
$ million
IFRS 9 loss
allowance
91
335
—
426
37
463
(91)
—
—
(91)
—
(91)
—
115
11
126
6
132
—
450
11
461
43
504
Impairment allowances on available-for-sale assets represent amounts provided against investments in equity instruments that were held at
cost under IAS 39. Under IFRS 9 these assets are classified as measured at fair value through profit or loss and therefore no loss allowance
exists on these assets under IFRS 9.
The increase in the loss allowances for financial assets classified as measured at amortized cost under IFRS 9 and loans that form part of the
net investment in equity-accounted entities represent the additional loss allowance required by the new standard's expected credit loss model.
Hedge accounting
Under IFRS 9 all existing hedging relationships qualified as continuing hedging relationships and the group has applied hedge accounting
prospectively to certain of its commodity price risk management activities for which hedge accounting was not possible under IAS 39.
BP Annual Report and Form 20-F 2018
147
1. Significant accounting policies, judgements, estimates and assumptions – continued
IFRS 9 also introduces a new way of treating fair value movements on the time value and foreign 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 has elected 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
was 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.
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 is 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 replaced IAS 18 ‘Revenue’ and certain other standards and
interpretations. IFRS 15 provides a single model for accounting for revenue arising from contracts with customers, focusing on the
identification and satisfaction of performance obligations. BP adopted IFRS 15 from 1 January 2018 and applied the ‘modified retrospective’
transition approach to implementation.
The group’s revised accounting policy in relation to revenue is provided above. A disaggregation of revenue from contracts with customers is
provided in note 5.
The group identified certain minor changes in accounting relating to its revenue from contracts with customers but the new standard had no
material effect on the group’s net assets as at 1 January 2018 and so no transition adjustment is 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 using the entitlement method of accounting under which revenue was
recognized 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. In its 2018 consolidated financial statements the group has recognized revenue
when sales are made to customers; production costs have been accrued or deferred to reflect differences between volumes taken and sold to
customers and the group's ownership interest in total production volumes. Compared to the group’s previous accounting policy this may result
in timing differences in respect of 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. The impact on the consolidated financial statements for the year ended 31 December 2018 was not
material.
In addition, BP has made determinations about presentation and disclosure relating to its revenue from contracts with customers as follows:
Derivative contracts resulting in physical delivery to a customer
Certain contracts entered into by the group that result in physical delivery to a counterparty of products such as crude oil, natural gas and
refined products are required by IFRS to be accounted for as financial instruments. These contracts are within the scope of IFRS 9 rather than
IFRS 15. The group’s counterparties in these transactions, however, may meet the IFRS 15 definition of a customer. Revenue recognized
relating to such contracts when physical delivery occurs is, therefore, presented together with revenue from contracts with customers in the
group’s consolidated financial statements. Changes in the fair value of derivative assets and liabilities prior to physical delivery are excluded
from revenue from contracts with customers and are presented as other operating revenues. Additionally, where forward sales and purchase
contracts for oil, natural gas or power have been determined to be for short-term trading purposes, the associated sales and purchases
continue to be reported net within other operating revenues consistent with the group’s practice prior to implementation of IFRS 15.
Contracts with post-delivery pricing terms
Contracts entered into by the group for the sale of oil, natural gas (including LNG), NGLs and refined products are typically priced by reference
to quoted prices. In line with market practice, certain of these contracts are based on average prices over a period that is partially or entirely
after delivery. Revenue relating to such contracts is recognized initially based on relevant prices at the time of delivery and subsequently
adjusted as prices are finalized, consistent with the group’s practice prior to implementation of IFRS 15. Whilst these post-delivery adjustments
are changes in the value of receivables within the scope of IFRS 9, not IFRS 15, the distinction between revenue recognized at the time of
delivery and revenue recognized as a result of post-delivery changes in quoted commodity prices relating to the same transaction is not
considered to be significant. All revenue from these contracts, both that recognized at the time of delivery and that from post-delivery price
adjustments, is disclosed as revenue from contracts with customers.
Disclosure of the amount of the transaction price allocated to unsatisfied performance obligations
The disclosures required by IFRS 15 include the amount of the contract transaction price allocated to performance obligations that are
unsatisfied at the balance sheet date. Many of BP’s commodity sales are made under term contracts in which sales are made based on quoted
prices at or near the time of delivery, meaning the consideration for future deliveries is entirely variable. In these arrangements, each delivery is
considered to be a separate performance obligation and the transaction price is the amount of revenue expected to be earned from all sales
that are contracted to be made in future periods, which can be up to 20 years from the balance sheet date.
BP does not consider the disclosure of the amount of the transaction price allocated to contracted future deliveries of commodities within the
scope of IFRS 15 to be relevant information. This disclosure has not, therefore, been provided in these consolidated financial statements. The
consideration in many such contracts is entirely variable so would be subject to the requirement of IFRS 15 relating to constraining estimates
of variable consideration. Applying the constraint for the purposes of this disclosure requirement would provide an indication only of contracted
revenues based on estimated future minimum market prices. Such commodities are regularly sold in liquid markets on a spot basis, using
similar pricing bases to sales made under term contracts, meaning that disclosure of contracted sales would have little predictive value.
Furthermore, as described above, a significant proportion of the group’s commodity sales contracts are within the scope of IFRS 9, not IFRS
15. Derivative assets or liabilities representing the difference between contracted price and forward price are recognized on the group balance
sheet for these contracts.
Contract assets and liabilities
The group does not have material contract asset or contract liability balances and so these amounts are included within amounts presented for
trade receivables and other payables.
148
BP Annual Report and Form 20-F 2018
1. Significant accounting policies, judgements, estimates and assumptions – continued
Not yet adopted
The IASB has issued IFRS 16 'Leases' which will become effective from financial reporting periods beginning on or after 1 January 2019 and
has been adopted by the EU. The group has not adopted IFRS 16 in these consolidated financial statements and will adopt it from 1 January
2019. 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 16 ‘Leases’
IFRS 16 ‘Leases’ provides a new model for lessee accounting in which the majority of leases will be accounted for by the recognition on the
balance sheet of a right-of-use asset and a lease liability. The subsequent amortization of the right-of-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 in the financial reporting period commencing 1 January 2019 and has elected to apply the modified retrospective
transition approach in which the cumulative effect of initial application 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 has elected not 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. On
transition the standard permits, on a lease-by-lease basis, the right-of-use asset to be measured either at an amount equal to the lease liability
(as adjusted for prepaid or accrued lease payments), or on an historical basis as if the standard had always applied. BP has elected to use the
historical asset measurement for its more material leases and to use the asset equals liability approach for the remainder of the population. In
addition, BP has also elected the option to adjust the carrying amounts of the right-of-use assets as at 1 January 2019 for onerous lease
provisions that had been recognized on the group balance sheet as at 31 December 2018, rather than the alternative of performing impairment
tests on transition.
The group’s evaluation of the effect of adoption of the standard is substantially complete and a material effect on the group’s balance sheet is
expected, as set out further below. 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-of-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 classified as operating leases under IAS 17, which are not recognized on the balance sheet as at 31
December 2018, is presented in Note 28. The following table provides a reconciliation of the operating lease commitments disclosed in Note
28 to the total lease liability expected to be recognized on the group balance sheet in accordance with IFRS 16 as at 1 January 2019, with
explanations below.
Operating lease commitments at 31 December 2018
Leases not yet commenced
Leases below materiality threshold
Short-term leases
Effect of discounting
Impact on leases in joint operations
Variable lease payments
Redetermination of lease term
Other
Total additional lease liabilities expected to be recognized on adoption of IFRS 16
Finance lease obligations at 31 December 2018
Adjustment for finance leases in joint operations
Total expected lease liabilities at 1 January 2019
$ million
11,979
(1,372)
(86)
(91)
(1,512)
836
(58)
(252)
(22)
9,422
667
(189)
9,900
Leases not yet commenced: The operating lease commitments disclosed in Note 28 include amounts relating to leases entered into by the
group that had not yet commenced as at 31 December 2018. In accordance with IFRS 16 assets and liabilities will not be recognized on the
group balance sheet in relation to these leases until the dates of commencement of the leases. Such commitments will continue to be
disclosed in future under IFRS 16.
Short-term leases and leases below materiality threshold: As part of the transition to IFRS 16, BP has elected not to recognize assets and
liabilities relating to short-term leases i.e. leases with a term of less than 12 months and has also applied a materiality threshold for the
recognition of assets and liabilities related to leases. The disclosed operating lease commitments as at 31 December 2018 in Note 28 includes
amounts related to such leases.
Effect of discounting: The amount of the lease liability recognized in accordance with IFRS 16 will be on a discounted basis whereas the
operating lease commitments information in Note 28 is presented on an undiscounted basis. The discount rates used on transition are
incremental borrowing rates as appropriate for each lease based on factors such as the lessee legal entity, lease term and currency. The
weighted average discount rate to be used on transition is expected to be around 3.5%, with a weighted average remaining lease term of
around 9 years. For new leases commencing after 1 January 2019 the discount rate used will be the interest rate implicit in the lease, if this is
readily determinable, or the incremental borrowing rate if the implicit rate cannot be readily determined.
BP Annual Report and Form 20-F 2018
149
1. Significant accounting policies, judgements, estimates and assumptions – continued
Impact on leases in joint operations: 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 28, irrespective of whether BP is the operator and whether the lease has been co-signed
by the joint operators or not. However, for transition to IFRS 16, the facts and circumstances of each lease in a joint operation have been
assessed to determine the group’s rights and obligations and to recognize assets and liabilities on the group balance sheet accordingly. This
relates mainly to leases of drilling rigs within joint operations in the Upstream segment. Where all parties to a joint operation jointly have the
right to control the use of the identified asset and all parties have a legal obligation to make lease payments to the lessor, the group’s share of
the right-of-use asset and its share of the lease liability will be recognized on the group balance sheet. This may arise in cases where the lease
is signed by all parties to the joint operation. However, in cases where BP is the only party with the legal obligation to make lease payments to
the lessor, the full lease liability will be recognized on the group balance sheet. This may be the case if for example BP, as operator of the joint
operation, is the sole signatory to the lease. If, however, the underlying asset is jointly controlled by all parties to the joint operation BP will
recognize its net share of the right-of-use asset on the group balance sheet along with a receivable representing the amounts to be recovered
from the other parties. If BP is not legally obliged to make lease payments to the lessor but jointly controls the asset, the net share of the right-
of-use asset will be recognized on the group balance sheet along with a payable representing amounts to be paid to the other parties.
Variable lease payments: Where there are lease payments that vary depending on an index or rate, the measurement of the operating lease
commitments in Note 28 is based on the variable factor as at inception of the lease and is not updated to reflect subsequent changes in the
variable factor. Such subsequent changes in the lease payments are currently treated as contingent rentals and charged to profit or loss as and
when paid. Under IFRS 16 the lease liability will be adjusted whenever the lease payments are changed in response to changes in the variable
factor, and for transition the liability is measured on the basis of the prevailing variable factor on 1 January 2019.
Redetermination of lease term: Under the transition provisions of IFRS 16, the remaining terms of certain leases have been redetermined with
the benefit of hindsight, on the basis that BP is now reasonably certain to exercise its option to terminate those leases before the full term.
Under IAS 17 finance leases are recognized on the group balance sheet and will continue to be recognized in accordance with IFRS 16. The
amounts recognized on the group balance sheet as at 1 January 2019 in relation to the right-of-use assets and liabilities for existing finance
leases within joint operations will be on a net or gross basis as appropriate as described above.
In addition to the lease liability, which will be presented within finance debt, other line items on the group balance sheet expected to be
adjusted on transition to IFRS 16 include property, plant and equipment, prepayments, receivables, accruals, payables, provisions and deferred
tax balances, as set out below.
31 December 2018
1 January 2019
$ million
Adjustment on
adoption of IFRS 16
Non-current assets
Property, plant and equipment
Trade and other receivables
Prepayments
Deferred tax assets
Current assets
Trade and other receivables
Prepayments
Current liabilities
Trade and other payables
Accruals
Finance debt and leases
Provisions
Non-current liabilities
Other payables
Accruals
Finance debt and leases
Deferred tax liabilities
Provisions
Net assets
Equity
BP shareholders' equity
Non-controlling interests
135,261
1,834
1,179
3,706
24,478
963
46,265
4,626
9,373
2,564
13,830
575
56,426
9,812
17,732
143,950
2,159
849
3,736
24,673
872
46,209
4,578
11,525
2,547
14,013
548
63,507
9,767
17,657
101,548
101,218
99,444
2,104
101,548
99,115
2,103
101,218
The total expected adjustments to the group's lease liabilities at 1 January 2019 may be reconciled as follows:
Total additional lease liabilities expected to be recognized on adoption of IFRS 16
Less: adjustment for finance leases in joint operations
Total expected adjustment to lease liabilities
Of which – current
– non-current
150
BP Annual Report and Form 20-F 2018
8,689
325
(330)
30
195
(91)
(56)
(48)
2,152
(17)
183
(27)
7,081
(45)
(75)
(330)
(329)
(1)
(330)
$ million
9,422
(189)
9,233
2,152
7,081
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
2018
2017
714
(714)
479
(1,193)
174
(1,019)
2,687
(2,687)
493
(3,180)
(2,222)
(5,402)
214
252
(2,279)
(333)
(2,398)
(2,089)
(1,439)
(3,276)
1,563
2,067
(11,922)
(12)
3,999
(6,372)
(8,770)
(1,193)
479
240
(485)
(2,572)
(3,531)
(12,253)
(1,141)
3,634
(7,693)
(10,969)
(3,180)
493
2,542
(1,738)
(3,453)
(5,336)
$ million
2016
6,640
(6,640)
494
(7,134)
3,105
(4,029)
(7,134)
494
4,353
(3,210)
(1,608)
(7,105)
Income statement
The group income statement for 2018 includes a pre-tax charge of $1,193 million (2017 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 2018 of $714 million (2017
$2,687 million, 2016 $6,640 million) relates mainly to business economic loss (BEL) and other claims associated with the Deepwater Horizon
Court Supervised Settlement Program (DHCSSP). Finance costs of $479 million (2017 $493 million, 2016 $494 million) reflect the unwinding of
the discount on payables and, for 2016, provisions.
The cumulative amount charged to the income statement to date comprises spill response costs arising in the aftermath of the incident,
amounts charged for the 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 $67.0 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
2018
—
—
629
—
85
—
714
479
1,193
2017
—
—
2,647
—
40
—
2,687
493
3,180
$ million
Cumulative since
the incident
8,526
14,304
42,410
4,061
1,394
(5,681)
65,014
1,944
66,958
2016
—
—
6,596
—
44
—
6,640
494
7,134
BP Annual Report and Form 20-F 2018
151
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
2018
Litigation and
claims
2,580
629
(2,045)
(819)
345
333
12
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 296.
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 DHCSSP’s determination of BEL claims was substantially completed by the end of 2017 and remaining claims continued to be processed
throughout 2018 with only a very small number of claims remaining to be determined by the end of 2018. However certain BEL claims
determined by the DHCSSP have been and continue to be appealed by BP and/or the claimants.
During 2018 settlement agreements were reached with claimants for a significant proportion of the provision existing at the beginning of the
year. Amounts payable under these settlement agreements have been reclassified from provisions to other payables. The remaining 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, the amounts payable may differ from those currently provided.
Payments to resolve outstanding claims under the PSC settlement are 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 296-298. 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 $5,485 million payable over 14 years, $2,897 million payable over
15 years and $4,010 million payable over 14 years respectively at 31 December 2018. For full details of these agreements, see BP Annual
Report and Form 20-F 2015.
In addition, other payables at 31 December 2018 also includes amounts payable for settled economic loss and property damage claims which
are payable over a period of up to nine years.
Cash flow statement
The impact on net cash provided by operating activities on a pre-tax basis amounted to an outflow of $3,531 million (2017 outflow of $5,336
million, 2016 outflow of $7,105 million). On a post-tax basis, the amounts were an outflow of $3,218 million (2017 outflow of $5,167 million and
2016 outflow of $6,892 million).
Cash outflows in 2018, 2017 and 2016 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.
152
BP Annual Report and Form 20-F 2018
3. Business combinations and other significant transactions
Business combinations
BP undertook a number of business combinations in 2018. For the full year, total consideration paid in cash amounted to $7,100 million, offset
by cash acquired of $114 million.
On 31 October 2018, BP acquired from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy
Corporation, a wholly owned subsidiary of BHP that holds a portfolio of unconventional onshore US oil and gas assets.
The acquisition brings BP extensive oil and gas production and resources in the liquids-rich regions of the Permian and Eagle Ford basins in
Texas and in the Haynesville gas basin in Texas and Louisiana.
The total consideration for the transaction, after customary closing adjustments and the effect of discounting deferred payments, is $10,302
million, which will all be paid in cash. As at 31 December 2018, $6,788 million of the consideration had been paid. The remaining discounted
amount of $3,514 million is included within other payables on the group balance sheet and will be paid in four instalments, with the final
instalment being paid in April 2019.
The transaction has been accounted for as a business combination using the acquisition method. The provisional fair values of the identifiable
assets and liabilities acquired, as at the date of acquisition, are shown in the table below. No goodwill has been recognized on the acquisition.
Assets
Property, plant and equipment
Intangible assets
Inventories
Trade and other receivables
Cash
Liabilities
Trade and other payables
Provisions
Non-controlling interest
Total consideration
$ million
2018
10,845
21
27
493
104
(659)
(323)
(206)
10,302
The acquisition-date fair values of the assets and liabilities acquired are provisional. As we gain further understanding of the acquired properties
and development options, these fair values may be adjusted.
An analysis of the cash flows relating to the acquisition included within the cash flow statement for 2018 is provided below.
Transaction costs of the acquisition (included in cash flows from operating activities)
Interest on deferred payments (included in cash flows from operating activities)
Cash consideration paid, net of cash acquired (included in cash flows from investing activities)
Total net cash outflow for the acquisition
$ million
2018
62
21
6,684
6,767
From the date of acquisition to 31 December 2018, the acquired activities generated revenues of $472 million and profit before tax of $49
million. If the business combination had taken place on 1 January 2018, it is estimated that the acquired activities would have generated
revenues of $2,798 million and profit before tax of $431 million.
In addition to the BHP transaction described above, BP undertook a number of other individually insignificant business combinations in 2018.
Other significant transactions
On 18 December 2018, BP purchased an additional 16.5% interest in the Clair field in the North Sea, as part of the agreements with
ConocoPhillips in which ConocoPhillips simultaneously purchased BP's entire 39.2% interest in the Greater Kuparuk Area on the North Slope
of Alaska. The purchase gives BP a 45.1% interest in Clair in total. Gross payments made and received of $1,739 million and $1,490 million are
included in Capital expenditure and Proceeds from disposals of businesses, net of cash acquired, respectively, in the group cash flow
statement. Goodwill of $804 million, resulting from the recognition of a deferred tax liability as part of the transaction accounting, has been
recognized on the purchase of the interest in the Clair field.
BP Annual Report and Form 20-F 2018
153
4. Disposals and impairment
The following amounts were recognized in the income statement in respect of disposals and impairments.
Gains on sale of businesses and fixed assets
Upstream
Downstream
Other businesses and corporate
Losses on sale of businesses and fixed assets
Upstream
Downstream
Other businesses and corporate
Impairment losses
Upstream
Downstream
Other businesses and corporate
Impairment reversals
Upstream
Downstream
Other businesses and corporate
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
2018
437
15
4
456
2017
526
674
10
1,210
2018
2017
707
59
11
777
400
12
254
666
(580)
(2)
(1)
(583)
860
2018
940
1,911
2,851
2,145
120
586
2,851
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
$ million
2016
557
561
14
1,132
$ million
2016
169
89
3
261
1,022
84
11
1,117
(3,025)
(17)
—
(3,042)
(1,664)
$ million
2016
1,372
1,259
2,631
839
1,646
146
2,631
At 31 December 2018, deferred consideration relating to disposals amounted to $35 million receivable within one year (2017 $259 million and
2016 $255 million) and $304 million receivable after one year (2017 $268 million and 2016 $271 million). In addition, contingent consideration
receivable relating to disposals amounted to $893 million at 31 December 2018 (2017 $237 million and 2016 $131 million). These amounts of
contingent consideration are reported within Other investments on the group balance sheet - see Note 18 for further information.
Upstream
In 2018, gains principally resulted from the disposal of interests in the Bruce, Keith and Rhum fields in the UK North Sea, from the disposal of
certain properties in the US, and from adjustments to disposals in prior periods. Losses included $335 million resulting from the disposal of our
interest in the Magnus field and associated assets in the UK North Sea, $221 million from the disposal of our interest in the Greater Kuparuk
Area in the US (see Note 3 for further information), and adjustments to disposals in prior periods.
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.
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.
Other businesses and corporate
In 2018 proceeds from disposals were principally in respect of life insurance policies in the US and wind farms within our US wind business.
154
BP Annual Report and Form 20-F 2018
4. 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 2018 was the disposal of our interest in the Greater Kuparuk Area in the US - see Note 3 for further information. 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.
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 (losses) on sale of businessesb
Total consideration
Non-cash considerationc
Consideration received (receivable)
Proceeds from the sale of businesses, net of cash disposedd
2018
3,274
173
(250)
(97)
3,100
—
3
3,103
(221)
2,882
(282)
(689)
1,911
2017
735
57
(173)
(86)
533
—
3
536
44
580
(216)
114
478
$ million
2016
4,794
1,202
(2,558)
(532)
2,906
25
229
3,160
593
3,753
(2,698)
204
1,259
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 Proceeds are stated net of cash and cash equivalents disposed of $15 million (2017 $25 million and 2016 $676 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 12,
Note 15 and Note 21 for further information on impairments by asset category.
Upstream
Impairment losses and reversals related primarily to producing and midstream assets.
The 2018 impairment losses of $400 million related to a number of different assets, with the most significant charges arising in Australia and
the US. Impairment losses arose primarily as a result of changes to project activity, asset obsolescence and the decision to dispose of certain
assets. The 2018 impairment reversals of $580 million related to a number of different assets, with the most significant reversals arising in the
North Sea and Angola following a change to decommissioning cost estimates.
The 2017 impairment losses of $1,138 million related to a number of different assets, with the most significant charges arising in BPX Energy
(previously known as the US Lower 48 business) 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 8). 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.
Downstream
Impairment losses totalling $12 million, $69 million, and $84 million were recognized in 2018, 2017 and 2016 respectively.
Other businesses and corporate
Impairment losses totalling $254 million, $32 million, and $11 million were recognized in 2018, 2017 and 2016 respectively. The amount for 2018
is in respect of assets within our US wind business in advance of their disposal in December 2018.
BP Annual Report and Form 20-F 2018
155
5. Segmental analysis
The group’s organizational structure reflects the various activities in which BP is engaged. At 31 December 2018, 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.
156
BP Annual Report and Form 20-F 2018
—
298,756
3,753
20,179
(801)
19,378
(2,528)
(127)
16,723
5,170
10,287
2,746
26,320
14,640
$ million
2017
Total
group
5. Segmental analysis – continued
By business
Upstream
Downstream
Rosneft
Other
businesses
and
corporate
Consolidation
adjustment
and
eliminations
$ million
2018
Total
group
1,678
(30,010)
298,756
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
56,399
270,689
(28,565)
(574)
27,834
270,115
—
—
—
951
589
2,283
14,328
(6)
14,322
6,940
(862)
6,078
2,221
67
2,288
(871)
807
(70)
(3,521)
—
(3,521)
30,010
—
—
211
—
211
4,211
8,907
355
12,785
11,533
900
1,177
834
2,772
2,862
—
—
—
10,074
—
59
203
1,557
689
245
—
—
—
—
—
a See explanation of inventory holding gains and losses on page 156.
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
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
4,631
8,637
220
12,093
14,500
875
1,141
304
2,349
2,677
—
—
—
10,059
—
1,469
(26,554)
240,208
(575)
894
(19)
(4,445)
—
(4,445)
65
235
2,902
484
275
26,554
—
—
—
240,208
2,507
(212)
—
(212)
—
—
—
—
—
8,621
853
9,474
(2,074)
(220)
7,180
5,571
10,013
3,426
24,985
17,452
a See explanation of inventory holding gains and losses on page 156.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
BP Annual Report and Form 20-F 2018
157
5. Segmental analysis – continued
By business
Upstream
Downstream
Rosneft
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
a See explanation of inventory holding gains and losses on page 156.
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
Other
businesses and
corporate
Consolidation
adjustment and
eliminations
$ million
2016
Total
group
1,667
(19,530)
183,008
(658)
1,009
(18)
(8,157)
—
(8,157)
19,530
—
—
—
183,008
1,960
(196)
—
(196)
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
856
1,094
758
—
—
—
71
253
6,719
—
—
—
US
Non-US
98,066
200,690
298,756
369
1,167
1,536
3,041
17,138
20,179
68,188
124,060
192,248
(2,027)
1,597
(430)
(1,675)
(190)
(2,295)
5,323
9,182
7,829
$ million
2018
Total
a Non-US region includes UK $65,630 million
b Non-US region includes UK $19,426 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
2017
Total
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.
158
BP Annual Report and Form 20-F 2018
5. 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
a Non-US region includes UK $37,119 million.
US
Non-US
$ million
2016
Total
65,132
117,876
183,008
155
528
683
(8,311)
6,284
(2,027)
6. Revenue from contracts with customers
The amounts shown in the table below are included in Sales and other operating revenues in the group income statement. An analysis of total
sales and other operating revenues by segment and region is provided in Note 5.
Revenue from contracts with customers, by product
Crude oil
Oil products
Natural gas, LNG and NGLs
Non-oil products and other revenues from contracts with customers
Revenues from contracts with customers
2018
65,276
195,466
21,745
13,768
296,255
2017
49,670
159,821
16,196
12,538
238,225
$ million
2016
32,284
126,465
11,337
11,487
181,573
The group’s sales to customers of crude oil and oil products were substantially all made by the Downstream segment. The group’s sales to
customers of natural gas, LNG and NGLs were made by the Upstream segment. A significant majority of the group’s sales of non-oil products
and other revenues from contracts with customers were made by the Downstream segment.
7. Income statement analysis
Interest and other income
Interest income from
Financial assets measured at amortized cost
Financial assets measured at fair value through profit or loss
Other income
Currency exchange losses charged to the income statementa
Expenditure on research and development
Finance costs
Interest payable on liabilities measured at amortized cost
Capitalized at 3.56% (2017 2.25% and 2016 1.81%)b
Unwinding of discount on provisions
Unwinding of discount on other payables measured at amortized cost
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 $55 million (2017 $64 million and 2016 $56 million).
2018
2017
$ million
2016
421
39
313
773
368
429
2,198
(419)
210
539
2,528
288
—
369
657
83
391
1,718
(297)
150
503
2,074
183
—
323
506
698
400
1,221
(244)
310
388
1,675
BP Annual Report and Form 20-F 2018
159
8. 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 in 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 expenditureb
Liabilities
Net assets
Cash used in operating activities
Cash used in investing activities
2018
2017
1,085
360
1,445
137
15,989
60
15,929
360
1,119
1,603
477
2,080
—
17,026
82
16,944
477
1,901
$ million
2016
1,274
447
1,721
62
16,960
102
16,858
447
2,920
a 2018 includes $447 million in the deepwater Gulf of Mexico principally relating to licence expiries. 2017 included 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 included 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. For further
information see Upstream – Exploration on page 25.
b 2018 includes $2.3 billion relating to licences in the Gulf of Mexico that have expired and approximately $1.6 billion relating to certain licences elsewhere that are due to expire in the next
financial year. BP remains committed to developing these prospects. See Note 1 for further information.
The carrying amount, by location, of exploration and appraisal expenditure capitalized as intangible assets at 31 December 2018 is shown in the
table below.
Carrying amount
$1 - 2 billion
$2 - 3 billion
9. 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 years
Tax charge (credit) on profit or loss
Angola; India; Egypt; Middle East
US - Gulf of Mexico; Canada; Brazil
Location
2018
2017
6,217
(221)
5,996
907
242
1,149
7,145
4,208
58
4,266
(503)
(51)
(554)
3,712
$ million
2016
1,762
(123)
1,639
(3,709)
(397)
(4,106)
(2,467)
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. 2018 includes a credit of $121 million (2017 $859 million
charge) in respect of the reduction in the US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018. The adjustments in respect of prior years reflect the
reassessment of deferred tax balances for prior periods in light of all other changes in facts and circumstances during the year.
In 2018, the total tax charge recognized within other comprehensive income was $714 million (2017 $1,499 million charge and 2016 $752
million credit), primarily comprising the deferred tax impact of the remeasurements of the net pension and other post-retirement benefit
liability or asset. See Note 32 for further information.
The total tax charge recognized directly in equity was $17 million (2017 $263 million charge and 2016 $5 million credit).
For information on significant estimates and judgements made in relation to taxation see Income taxes in 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, 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.
160
BP Annual Report and Form 20-F 2018
9. Taxation – continued
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 investment
Gulf of Mexico oil spill non-deductible costs
Disposal impactsb
Foreign exchange
Items not deductible for tax purposes
Impact of US tax reformc
Decrease in rate of UK supplementary charged
Other
Effective tax rate
2016 excluding
impacts of Gulf
of Mexico oil
spill and
impairments
2016 impacts of
Gulf of Mexico
oil spill and
impairments
2,914
(117)
(4)%
(5,209)
(2,350)
45%
2017
7,180
3,712
52%
2018
16,723
7,145
43%
$ million
2016
(2,295)
(2,467)
107%
% of profit or loss before taxation
43
(5)
—
2
(2)
—
—
3
1
(1)
—
2
43
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
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.
b In 2016 this related primarily to the tax impact on the contribution of BP’s Norwegian upstream business into Aker BP ASA.
c 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.
d Relates to the deferred tax impact of the reduction in the UK supplementary charge rate applicable to profits arising in the North Sea from 20% to 10% in 2016.
Deferred tax
Analysis of movements during the year in the net deferred tax liability
At 31 December
Adjustment on adoption of IFRS 9a
At 1 January
Exchange adjustments
Charge (credit) for the year in the income statement
Charge for the year in other comprehensive income
Charge for the year in equity
Acquisitions and other additionsb
At 31 December
a 2018 reflects the deferred tax impact of adjustments recorded by the group on adoption of IFRS 9. See Note 1 for further information.
b 2018 relates primarily to the purchase of an additional 16.5% interest in the Clair field. See Note 3 - Other significant transactions for further information.
2018
3,513
(36)
3,477
(68)
1,149
734
17
797
6,106
$ million
2017
2,497
—
2,497
12
(554)
1,503
1
54
3,513
BP Annual Report and Form 20-F 2018
161
9. Taxation – continued
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
2018
2017
2016
2018
2017
(1,297)
65
(36)
(57)
(1,325)
(6)
1,505
(25)
123
559
318
2,474
1,149
(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)
22,565
1,956
—
1,224
25,745
(1,319)
(7,126)
(144)
(3,626)
(5,900)
(1,524)
(19,639)
6,106
9,812
3,706
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
a The 2017 and 2018 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 $2,758 million (2017 $3,503 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 2018,
$1,563 million relates to the US (2017 $2,067 million) and $1,108 million relates to India (2017 $1,336 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
2018
6.6
4.3
22.5
18.7
3.8
37.3
1.5
$ billion
2017
6.8
4.5
20.1
16.3
3.8
31.4
1.6
a For 2018 these losses expire in the period 2019-2038 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 For 2018 the US unused tax credits expire in the period 2019-2028.
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 assets
Deferred tax expense arising from the write-down of a previously recognized deferred tax asset
2018
83
—
112
169
2017
22
—
436
78
$ million
2016
40
269
394
55
162
BP Annual Report and Form 20-F 2018
10. Dividends
The quarterly dividend paid on 29 March 2019 in respect of the fourth quarter 2018 was 10.25 cents per ordinary share ($0.615 per American
Depositary Share (ADS)). The corresponding amount in sterling was announced on 18 March 2019. 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
2018
2017
2016
2018
2017
2016
2018
2017
$ million
2016
Dividends announced and paid in cash
Preference shares
Ordinary shares
March
June
September
December
Dividend announced, paid in March
2019
1
1
1
7.1691
7.4435
7.9296
8.0251
30.5673
8.1587
7.7563
7.6213
7.4435
30.9798
7.0125
6.9167
7.5578
7.9313
29.4183
10.00
10.00
10.00
10.00
40.00
10.00
10.00
10.00
10.00
40.00
10.00
10.00
10.25
10.25
40.50
10.25
1,828
1,727
1,409
1,734
6,699
1,435
1,303
1,546
1,676
1,627
6,153
1,099
1,168
1,161
1,182
4,611
The details of the scrip dividends issued are shown in the table below.
Number of shares issued (thousand)
Value of shares issued ($ million)
2018
2017
2016
195,305
1,381
289,789
1,714
548,005
2,858
The financial statements for the year ended 31 December 2018 do not reflect the dividend announced on 5 February 2019 and paid in March
2019; this will be treated as an appropriation of profit in the year ending 31 December 2019.
11. 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
2018
46.98
46.67
2018
2.82
2.80
2017
17.20
17.10
2017
1.03
1.03
Cents per share
2016
0.61
0.60
Dollars per share
2016
0.04
0.04
Basic earnings per ordinary share amounts are calculated by dividing the profit (loss) for the year attributable to BP 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.
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
2018
9,383
1
9,382
2017
3,389
1
3,388
$ million
2016
115
1
114
2018
2017
2016
19,970,215
19,692,613
18,744,800
Shares thousand
132,278
123,829
110,519
20,102,493
19,816,442
18,855,319
2018
2017
2016
3,328,369
3,282,102
3,124,133
Shares thousand
22,046
20,638
18,420
3,350,415
3,302,740
3,142,553
BP Annual Report and Form 20-F 2018
163
11. Earnings per share – continued
The number of ordinary shares outstanding at 31 December 2018, excluding treasury shares, and including certain shares that will be issuable
in the future under employee share-based payment plans was 20,101,658,664. Between 31 December 2018 and 11 March 2019, the latest
practicable date before the completion of these financial statements, there was a net increase of 143,038,241 in the number of ordinary shares
outstanding primarily 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 87-109.
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
2018
Number of optionsab
thousand
19,437
481
6,123
Weighted average
exercise price $
4.28
4.69
n/a
Number of optionsab
thousand
22,399
1,112
5,145
2017
Weighted average
exercise price $
4.34
4.46
n/a
a Numbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
b At 31 December 2018 the quoted market price of one BP ordinary share was £4.96 (2017 £5.23).
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
2018
2017
Number of sharesa
Number of sharesa
thousand
108,934
106,337
71,407
588
799
288,065
127,165
thousand
101,550
108,373
85,878
413
166
296,380
126,122
a Numbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
There has been a net decrease of 56,796,490 in the number of potential ordinary shares relating to employee share-based payment plans
between 31 December 2018 and 11 March 2019.
164
BP Annual Report and Form 20-F 2018
12. Property, plant and equipment
Cost
At 1 January 2018
Exchange adjustments
Additions
Acquisitions
Remeasurements
Transfers from intangible assets
Deletions
At 31 December 2018
Depreciation
At 1 January 2018
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Deletions
At 31 December 2018
Net book amount at 31
December 2018
Cost
At 1 January 2017
Exchange adjustments
Additions
Acquisitions
Transfers from intangible assets
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
Assets held under finance leases at net book
amount included above
At 31 December 2018
At 31 December 2017
Assets under construction included above
At 31 December 2018
At 31 December 2017
Land and land
improvements
Buildings
Oil and gas
propertiesa
Plant,
machinery
and
equipment
Fittings,
fixtures and
office
equipment Transportationb
Oil depots,
storage tanks
and service
stations
3,474
(168)
233
163
—
—
(140)
3,562
683
(25)
92
2
—
(126)
626
1,573
(58)
40
4
—
—
(45)
1,514
818
(24)
52
—
—
(139)
707
226,054
—
9,712
10,882
17
901
(14,699)
232,867
133,326
—
12,342
86
(564)
(11,333)
133,857
46,662
(892)
2,323
9
—
—
(1,810)
46,292
20,996
(460)
1,820
253
(1)
(1,733)
20,875
2,853
(73)
204
1
—
—
(238)
2,747
2,136
(52)
189
—
—
(232)
2,041
10,774
(43)
(112)
2
—
—
(128)
10,493
7,523
(27)
252
178
(17)
(75)
7,834
8,748
(501)
736
36
—
—
(146)
8,873
5,185
(279)
384
2
—
(145)
5,147
$ million
Total
300,138
(1,735)
13,136
11,097
17
901
(17,206)
306,348
170,667
(867)
15,131
521
(582)
(13,783)
171,087
2,936
807
99,010
25,417
706
2,659
3,726
135,261
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
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
—
—
2
2
12
16
207
238
—
—
295
233
6
7
522
496
22,522
23,789
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 Includes adjustments to decommissioning provisions see Note 1 for further information.
13. Capital commitments
Authorized future capital expenditure for property, plant and equipment by group companies for which contracts had been signed at
31 December 2018 amounted to $8,319 million (2017 $11,340 million). BP has capital commitments amounting to $1,227 million (2017 $1,451
million) in relation to associates. BP’s share of capital commitments of joint ventures amounted to $619 million (2017 $483 million).
BP Annual Report and Form 20-F 2018
165
14. Goodwill and impairment review of goodwill
Cost
At 1 January
Exchange adjustments
Acquisitions and other additionsa
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
2018
12,163
(210)
1,046
(184)
12,815
612
—
(1)
611
12,204
11,551
a 2018 principally relates to the purchase of an additional 16.5% share in the Clair field in the North Sea. See Note 3 - Other significant transactions for further information.
Impairment review of goodwill
Goodwill at 31 December
Upstream
Downstream
Other businesses and corporate
2018
8,346
3,802
56
12,204
$ million
2017
11,805
336
83
(61)
12,163
611
1
—
612
11,551
11,194
$ million
2017
7,728
3,758
65
11,551
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 in Note 1.
Upstream
Goodwill
Excess of recoverable amount over carrying amount
2018
8,346
53,391
$ million
2017
7,728
27,705
The table above shows the carrying amount of goodwill for the segment and the excess of the recoverable amount, based upon a post-tax
value-in-use calculation, over the carrying amount (headroom) at the date of the test. The increase in headroom principally arises from
acquisitions, new activity and changes in US tax. In the prior year, the recoverable amount was estimated using a fair value less costs of
disposal calculation and was based on cash flows estimated for the impairment test performed in 2016 as permitted by IAS 36.
The value in use is based on the cash flows expected to be generated by the projected oil or natural gas production profiles up to the expected
dates of cessation of production of each producing field, based on current estimates of reserves and resources, appropriately risked.
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. As the
production profile and related cash flows can be estimated from BP’s past experience, management believes that the cash flows generated
over the estimated life of field is the appropriate basis upon which to assess goodwill and individual assets for impairment. The estimated date
of cessation of production depends on the interaction of a number of variables, such as the recoverable quantities of hydrocarbons, the
production profile of the hydrocarbons, the cost of the development of the infrastructure necessary to recover the hydrocarbons, production
costs, the contractual duration of the production concession and the selling price of the hydrocarbons produced. As each producing field has
specific reservoir characteristics and economic circumstances, the cash flows of the fields are computed using appropriate individual economic
models and key assumptions agreed by BP management. Capital expenditure, operating costs and expected hydrocarbon production profiles
are derived from the business segment plan adjusted for assumptions reflecting the price environment at the time that the test was
performed. Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis are 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.
The most recent review for impairment was carried out in the fourth quarter. The key assumptions used in the value-in-use calculation are oil
and natural gas prices, production volumes and the discount rate. Oil and gas price assumptions for the first five years are based on
management’s best estimate of prices over those five years, with the long-term price applied from year 6 onwards. Price assumptions and
discount rate assumptions used were as disclosed in Note 1. The value-in-use calculation has been prepared solely for the purposes of
determining whether the goodwill balance was impaired. Estimated future cash flows were prepared on the basis of certain assumptions
prevailing at the time of the test. The actual outcomes may differ from the assumptions made. For example, reserves and resources estimates
and production forecasts are subject to revision as further technical information becomes available and economic conditions change, and
future commodity prices may differ from the forecasts used in the calculations.
Sensitivities to different variables have been estimated using certain simplifying assumptions. For example, lower oil and gas price sensitivities
do not reflect the specific impacts for each contractual arrangement and will not capture fully any favourable impacts that may arise from cost
deflation. Therefore a detailed calculation at any given price or production profile may produce a different result.
166
BP Annual Report and Form 20-F 2018
14. Goodwill and impairment review of goodwill – continued
It is estimated that if the oil price assumption for all future years was approximately $14 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 no
reasonable fall in the gas price assumption would cause the recoverable amount to be equal to the carrying amount of goodwill and related net
non-current assets of the segment.
Estimated production volumes are based on detailed data for each field and take into account development plans agreed by management as
part of the long-term planning process. The average production for the purposes of goodwill impairment testing over the next 15 years is
829mmboe per year (2017 889mmboe per year). It is estimated that if production volumes were to be reduced by approximately 13% for this
period, this would cause the recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets of the
segment.
It is estimated that if the post-tax discount rate was approximately 11% for the entire portfolio, an increase of 5% for all countries not
considered ‘higher risk’ and 3% 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
2,692
Other
1,110
2018
Total
3,802
Lubricants
2,849
Other
909
$ million
2017
Total
3,758
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 as the basis for the tests in 2014-2017 as the criteria of IAS 36 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. IAS 36 does not specify for how many years such an approach is appropriate and management determined that a
re-performance of the test was appropriate in 2018 given the passage of time since 2013. There was no significant change in the outcome of
this test compared to that in 2013.
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. Operating margin and sales volumes assumptions used in the detailed impairment review of goodwill calculation
are consistent with the assumptions used in the Lubricants unit’s business plan and values assigned to these key assumptions reflect past
experience. No reasonably possible change in any of these key assumptions would cause the unit’s carrying amount to exceed its recoverable
amount. Cash flows beyond the plan period are extrapolated using a nominal 2.8% growth rate (2013 3%).
15. Intangible assets
Cost
At 1 January
Exchange adjustments
Acquisitions
Additions
Transfers to property, plant and equipment
Deletions
At 31 December
Amortization
At 1 January
Exchange adjustments
Charge for the year
Impairment losses
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 8.
Exploration
and appraisal
expenditurea
Other
intangibles
17,886
—
—
1,095
(901)
(1,027)
17,053
860
—
1,085
137
(1,018)
1,064
15,989
17,026
4,488
(128)
25
318
—
(199)
4,504
3,159
(77)
326
—
(199)
3,209
1,295
1,329
2018
Total
22,374
(128)
25
1,413
(901)
(1,226)
21,557
4,019
(77)
1,411
137
(1,217)
4,273
17,284
18,355
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
$ million
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
BP Annual Report and Form 20-F 2018
167
16. Investments in joint ventures
The following table provides aggregated summarized financial information relating to the group’s share of joint ventures.
Sales and other operating revenues
Profit before interest and taxation
Finance costs
Profit before taxation
Taxation
Profit for the year
Other comprehensive income
Total comprehensive income
Non-current assets
Current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Net assets
Group investment in joint ventures
Group share of net assets (as above)
Loans made by group companies to joint ventures
2018
13,258
1,396
85
1,311
414
897
6
903
10,399
2,935
13,334
1,715
3,017
4,732
8,602
8,602
45
8,647
Transactions between the group and its joint ventures are summarized below.
Sales to joint ventures
Product
LNG, crude oil and oil products, natural gas
Purchases from joint ventures
Sales
4,603
2018
Amount
receivable at
31 December
251
2018
Sales
3,578
2017
Amount
receivable at
31 December
352
2017
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
Sales
3,327
$ million
2016
10,081
1,612
156
1,456
490
966
5
971
$ million
2016
Amount
receivable at
31 December
291
$ million
2016
Amount
payable at
31 December
Product
LNG, crude oil and oil products, natural gas, refinery
operating costs, plant processing fees
Amount
payable at
31 December
Purchases
Amount
payable at
31 December
Purchases
Purchases
1,336
300
1,257
176
943
120
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.
17. 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
2018
2,283
573
2,856
2017
922
408
1,330
2016
647
347
994
2018
10,074
7,599
17,673
$ million
Balance sheet
Investments in
associates
2017
10,059
6,932
16,991
The associate that is material to the group at both 31 December 2018 and 2017 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 2018.
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 2018 compared
with 31 December 2017 principally relates to earnings from Rosneft offset by dividends distribution and foreign exchange effects which have
been recognized in other comprehensive income.
168
BP Annual Report and Form 20-F 2018
17. Investments in associates – continued
The value of BP’s 19.75% shareholding in Rosneft based on the quoted market share price of $6.18 per share (2017 $4.99 per share) was
$12,934 million at 31 December 2018 (2017 $10,444 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 2018, as shown in the table below, compared with the amounts
reported in Rosneft's IFRS financial statements. In particular, in 2018 these adjustments resulted in BP reporting a lower amount relating to
impairment charges of downstream goodwill than the equivalent amounts reported by Rosneft.
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
2016
74,380
7,094
1,747
5,347
1,797
273
3,277
4,203
7,480
2018
131,322
18,886
2,785
16,101
2,957
1,585
11,559
2,086
13,645
137,038
43,438
180,476
41,311
78,754
120,065
60,411
9,403
51,008
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
The group received dividends, net of withholding tax, of $620 million from Rosneft in 2018 (2017 $314 million and 2016 $332 million).
Summarized financial information for the group’s share of associates is shown below.
$ million
BP share
2016
Total
20,067
1,926
367
1,559
511
54
994
828
1,822
Rosnefta
14,690
1,401
345
1,056
355
54
647
830
1,477
Other
5,377
525
22
503
156
—
347
(2)
345
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
25,936
3,730
550
3,180
584
313
2,283
412
2,695
27,065
8,579
35,644
8,159
15,554
23,713
11,931
1,857
10,074
Other
9,134
1,150
78
1,072
499
—
573
(1)
572
10,787
2,398
13,185
2,232
3,817
6,049
7,136
—
7,136
2018
Total
35,070
4,880
628
4,252
1,083
313
2,856
411
3,267
37,852
10,977
48,829
10,391
19,371
29,762
19,067
1,857
17,210
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
10,074
7,136
17,210
10,059
6,097
16,156
—
463
463
—
835
835
10,074
7,599
17,673
10,059
6,932
16,991
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 2018
169
17. 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
2,064
2018
Amount
receivable at
31 December
393
2018
Sales
1,612
2017
Amount
receivable at
31 December
216
2017
Sales
3,643
Amount
payable at
31 December
Purchases
Amount
payable at
31 December
Purchases
Purchases
$ million
2016
Amount
receivable at
31 December
765
$ million
2016
Amount
payable at
31 December
Crude oil and oil products, natural gas, transportation
tariff
14,112
2,069
11,613
1,681
8,873
2,000
In addition to the transactions shown in the table above, in 2018 BP acquired a 49% stake in LLC Kharampurneftegaz, a Rosneft subsidiary,
which will develop subsoil resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets Autonomous Okrug in
northern Russia. BP’s interest in LLC Kharampurneftegaz is accounted for as an associate.
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 $11,303 million (2017 $13,932 million), primarily in relation to contracts with its associates for the purchase
of transportation capacity. For information on capital commitments in relation to associates see Note 13.
18. Other investments
Equity investmentsa
Other
a The majority of equity investments are unlisted.
2018
$ million
2017
Current
Non-current
Current
Non-current
1
221
222
482
859
1,341
15
110
125
418
827
1,245
Other investments includes $893 million relating to contingent consideration amounts arising on disposals (2017 $237 million) which are
financial assets classified as measured at fair value through profit or loss. The fair value is determined using an estimate of discounted future
cash flows that are expected to be received and is considered a level 3 valuation under the fair value hierarchy. Future cash flows are estimated
based on inputs including oil and natural gas prices, production volumes and operating costs related to the disposed operations. The discount
rate used is based on a risk-free rate adjusted for asset-specific risks.
19. Inventories
Crude oil
Natural gas
Refined petroleum and petrochemical products
Trading inventories
Supplies
Cost of inventories expensed in the income statement
2018
4,878
322
10,419
15,619
282
15,901
2,087
17,988
229,878
$ million
2017
5,692
119
10,694
16,505
295
16,800
2,211
19,011
179,716
The inventory valuation at 31 December 2018 is stated net of a provision of $1,009 million (2017 $474 million) to write down inventories to their
net realizable value, of which $604 million (2017 $62 million) relates to hydrocarbon inventories. The net charge to the income statement in the
year in respect of inventory net realizable value provisions was $552 million (2017 $27 million credit), of which $553 million (2017 $31 million
credit) related to hydrocarbon inventories.
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.
170
BP Annual Report and Form 20-F 2018
20. 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
Sales taxes and production taxes
Other receivables
2018
$ million
2017
Current
Non-current
Current
Non-current
19,414
642
3,275
23,331
214
790
143
1,147
24,478
7
2
740
749
—
482
603
1,085
1,834
18,912
566
4,206
23,684
252
746
167
1,165
24,849
4
2
671
677
—
276
481
757
1,434
In both 2018 and 2017 the group entered into non-recourse arrangements to discount certain receivables in support of supply and trading
activities and the management of credit risk.
Trade and other receivables are predominantly non-interest bearing. See Note 29 for further information.
21. Valuation and qualifying accounts
2018
2017
$ million
2016
Not credit-
impaired
Credit
impaired
Trade and
other
receivables
Fixed asset
investments
Trade and
other
receivables
Fixed asset
investments
Trade and
other
receivables
Fixed asset
investments
—
115
115
(26)
—
—
89
335
—
335
56
(12)
(52)
327
335
115
450
30
(12)
(52)
416
314
(85)
229
10
(1)
(3)
235
392
—
392
68
13
(138)
335
335
—
335
47
3
(71)
314
447
—
447
120
(7)
(168)
392
435
—
435
55
(2)
(153)
335
At 1 January – IAS 39
Adjustment on adoption of IFRS 9
At 1 January – IFRS 9
Charged to costs and expenses
Charged to other accountsa
Deductions
At 31 December
a Principally exchange adjustments.
Valuation and qualifying accounts relating to trade and other receivables comprise expected credit loss allowances in 2018 and impairment
provisions recognized on an incurred loss basis in comparative periods. The adjustment on adoption of IFRS 9 relates to the additional loss
allowance required by the new standard's expected credit loss model. There were no significant changes to the gross carrying amounts of
trade and other receivables during the year that affected the estimation of the loss allowance at 31 December 2018.
Valuation and qualifying accounts relating to fixed asset investments comprise impairment provisions for investments in equity-accounted
entities in 2018. This includes expected credit loss allowances of $44 million (1 January 2018 $43 million) relating to loans that form part of the
net investment in equity-accounted entities. The adjustment on adoption of IFRS 9 primarily relates to amounts provided against investments in
equity instruments that were held at cost less impairment losses under IAS 39 but that are classified as measured at fair value through profit
or loss under IFRS 9.
In addition to the amounts presented above, expected loss allowances on cash and cash equivalents classified as measured at amortized cost
totalled $11 million (1 January 2018 $11 million). For further information on the group's credit risk management policies and how the group
recognizes and measures expected losses see Note 29.
Valuation and qualifying accounts are deducted in the balance sheet from the assets to which they apply.
For further information on the adjustments on adoption of IFRS 9 see Note 1.
BP Annual Report and Form 20-F 2018
171
22. Trade and other payables
Financial liabilities
Trade payables
Amounts payable to joint ventures and associates
Payables for capital expenditure and acquisitionsa
Payables related to the Gulf of Mexico oil spillb
Other payables
Non-financial liabilities
Sales taxes, customs duties, production taxes and social security
Other payables
2018
$ million
2017
Current
Non-current
Current
Non-current
26,252
2,369
7,325
2,279
4,980
43,205
2,272
788
3,060
46,265
—
—
1,345
11,922
318
13,585
35
210
245
13,830
26,983
1,857
3,810
2,089
5,733
40,472
2,586
1,151
3,737
44,209
—
—
1,269
12,253
60
13,582
50
257
307
13,889
a Includes $3,514 million deferred consideration relating to the acquisition of Petrohawk Energy Corporation from BHP Billiton Petroleum (North America) Inc. See Note 3 for further
information.
b See Note 2 for further information.
Materially all of BP's trade payables have payment terms in the range of 30 to 60 days and give rise to operating cash flows. The active
management of supplier payment terms within this range enables BP to optimize and reduce volatility in cash flow.
Trade and other payables, other than those relating to the Gulf of Mexico oil spill, are predominantly interest free. See Note 29 (c) for further
information.
23. Provisions
At 1 January 2018
Exchange adjustments
Acquisitions
Increase (decrease) in existing provisions
Write-back of unused provisions
Unwinding of discount
Change in discount ratea
Utilization
Reclassified to other payables
Deletions
At 31 December 2018
Of which – current
– non-current
Of which – Gulf of Mexico oil spillb
Decommissioning
Environmental
Litigation and
claims
16,100
(135)
295
137
(2)
162
(2,377)
(9)
(270)
(288)
13,613
257
13,356
—
1,516
(9)
12
428
(115)
22
(38)
(245)
(4)
—
1,567
300
1,267
—
3,334
(3)
24
1,492
(21)
9
(31)
(1,034)
(2,051)
(1)
1,718
798
920
345
$ million
Total
23,944
(231)
336
3,360
(393)
210
(2,463)
(1,816)
(2,362)
(289)
20,296
2,564
17,732
345
Other
2,994
(84)
5
1,303
(255)
17
(17)
(528)
(37)
—
3,398
1,209
2,189
—
a Includes the impact of changing from a real to nominal discount rate. See Note 1 for further information.
b Further information on the financial impacts of the Gulf of Mexico oil spill is provided in Note 2.
The decommissioning provision comprises the future cost of decommissioning oil and natural gas wells, facilities and related pipelines. The
environmental provision includes provisions for costs related to the control, abatement, clean-up or elimination of environmental pollution
relating to soil, groundwater, surface water and sediment contamination. The litigation and claims category includes provisions for matters
related to, for example, commercial disputes, product liability, and allegations of exposures of third parties to toxic substances. Included within
the other category at 31 December 2018 are provisions for deferred employee compensation of $338 million (2017 $391 million).
For information on significant estimates and judgements made in relation to provisions, see Provisions and contingencies within Note 1.
24. 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 in 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.
172
BP Annual Report and Form 20-F 2018
24. Pensions and other post-retirement benefits – continued
In the US, all pension benefits now accrue 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 2018 the aggregate level of contributions was $610 million (2017 $637 million and 2016 $651 million). The aggregate level of
contributions in 2019 is expected to be approximately $700 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 covering the next five years. Contractually committed funding amounted to $1,275 million
at 31 December 2018, all of which relates to future 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 278.
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. No contributions were
made into the primary US pension plan in 2018 and no statutory funding requirement is expected in the next 12 months.
The surplus relating to the primary US fund is recognized on the balance sheet on the basis that economic benefit can be gained from the
surplus through a reduction in future contributions.
There was no minimum funding requirement for the US plan, and no significant minimum funding requirements in other countries at
31 December 2018.
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 2018. 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 2017. A valuation of the US plan and largest Eurozone plans are 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
2018
2.9
3.8
3.0
3.0
3.1
2018
2.6
2.5
3.1
2017
2.5
4.1
2.9
2.9
3.1
2017
2.7
2.7
3.2
UK
2016
2.7
4.6
3.0
3.0
3.2
UK
2016
4.0
3.9
3.1
2018
4.1
3.9
—
—
1.5
2018
3.6
3.5
1.7
2017
3.5
4.1
—
—
1.7
2017
4.1
3.9
1.8
US
2016
3.9
4.2
—
—
1.8
US
2016
4.2
4.0
1.5
2018
2.0
3.1
1.5
0.5
1.7
2018
2.4
1.9
1.6
%
Eurozone
2016
1.7
3.0
1.5
0.5
1.6
%
Eurozone
2016
2.7
2.4
1.8
2017
1.9
3.0
1.4
0.6
1.6
2017
2.1
1.7
1.6
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.
BP Annual Report and Form 20-F 2018
173
24. Pensions and other post-retirement benefits – continued
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
2018
2017
UK
2016
2018
2017
US
2016
Years
Eurozone
2018
2017
2016
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
27.4
28.0
25.1
25.1
25.7
25.6
25.1
25.0
28.9
29.0
30.0
26.9
26.8
27.5
28.1
27.6
27.6
28.8
28.8
29.5
28.5
28.4
29.3
29.0
29.0
28.9
30.6
30.5
31.9
30.1
30.0
31.0
31.2
31.4
31.3
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 primarily 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.
For the primary UK pension plan there is an agreement with the trustee to increase the proportion of assets with liability matching
characteristics over time primarily 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 2018, the UK and the US plans switched 12.5% and 10% of plan assets
respectively from equities to bonds.
The current asset allocation policy for the major plans at 31 December 2018 was as follows:
Asset category
Total equity (including private equity)
Bonds/cash (including LDI)
Property/real estate
UK
%
30
63
7
US
%
40
60
—
The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2018 were $4,197 million (2017 $2,588
million) of government-issued nominal bonds and $17,491 million (2017 $16,177 million) of index-linked bonds.
Some of the group’s pension plans in the Eurozone and other countries use derivative financial instruments as part of their asset mix to
manage the level of risk. The fair value of these instruments are included in other assets in the table below. The UK and US plans do not use
derivative financial instruments.
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 176.
174
BP Annual Report and Form 20-F 2018
24. Pensions and other post-retirement benefits – continued
UKa
USb
Eurozone
Other
Fair value of pension plan assets
At 31 December 2018
Listed equities – developed markets
– emerging markets
Private equityc
Government issued nominal bondsd
Government issued index-linked bondsd
Corporate bondsd
Propertye
Cash
Other
Debt (repurchase agreements) used to fund liability driven investments
At 31 December 2017
Listed equities – developed markets
– emerging markets
Private equityc
Government issued nominal bondsd
Government issued index-linked bondsd
Corporate bondsd
Propertye
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 bondsd
Government issued index-linked bondsd
Corporate bondsd
Propertye
Cash
Other
Debt (repurchase agreements) used to fund liability driven investments
5,191
950
2,792
4,263
17,491
4,606
2,311
376
116
(6,011)
32,085
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
1,238
63
1,495
2,072
—
2,184
6
73
64
—
7,195
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
413
65
—
895
102
506
57
42
32
—
2,112
537
83
—
941
2
546
71
21
23
—
2,224
436
54
1
821
4
427
45
17
74
—
1,879
306
56
4
533
—
243
25
83
40
—
1,290
376
53
—
545
—
272
30
98
45
—
1,419
363
46
—
448
—
259
28
83
83
—
1,310
$ million
Total
7,148
1,134
4,291
7,763
17,593
7,539
2,399
574
252
(6,011)
42,682
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
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 Bonds held by pension plans are valued using quoted prices in active markets. Where quoted prices are not available, quoted prices for similar instruments in active markets are used.
e Properties are valued based on an analysis of recent market transactions supported by market knowledge derived from third-party valuers.
BP Annual Report and Form 20-F 2018
175
24. Pensions and other post-retirement benefits – continued
Analysis of the amount charged to profit or loss
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
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
295
15
—
310
38
348
(868)
774
(94)
(722)
1,770
123
520
1,691
31,513
(1,589)
310
774
21
(1,780)
(6)
—
(2,413)
26,830
35,091
(1,883)
868
21
490
(1,780)
—
(722)
32,085
5,255
5,473
(218)
5,255
5,473
(218)
5,255
299
—
—
299
178
477
(262)
369
107
(256)
945
(9)
41
721
10,820
—
299
369
—
(597)
(218)
—
(977)
9,696
7,779
—
262
—
7
(597)
—
(256)
7,195
(2,501)
84
9
17
110
5
115
(44)
136
92
(69)
14
(42)
(43)
(140)
7,275
(303)
110
136
2
(84)
(301)
—
71
6,906
2,224
(93)
44
2
88
(84)
—
(69)
2,112
(4,794)
418
(2,919)
(2,501)
29
(4,823)
(4,794)
396
(2,897)
(2,501)
(152)
(4,642)
(4,794)
43
4
—
47
40
87
(45)
67
22
(36)
65
7
9
45
1,873
(113)
47
67
7
(83)
(17)
(14)
(81)
1,686
1,419
(73)
45
7
25
(83)
(14)
(36)
1,290
(396)
35
(431)
(396)
(97)
(299)
(396)
$ million
2018
Total
721
28
17
766
261
1,027
(1,219)
1,346
127
(1,083)
2,794
79
527
2,317
51,481
(2,005)
766
1,346
30
(2,544)
(542)
(14)
(3,400)
45,118
46,513
(2,049)
1,219
30
610
(2,544)
(14)
(1,083)
42,682
(2,436)
5,955
(8,391)
(2,436)
5,620
(8,056)
(2,436)
(26,612)
(218)
(26,830)
(6,799)
(2,897)
(9,696)
(2,264)
(4,642)
(6,906)
(1,387)
(299)
(1,686)
(37,062)
(8,056)
(45,118)
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 $3,046 million benefits and $2 million settlements, plus $38 million of plan expenses incurred in the administration of the benefit.
e The benefit obligation for the US is made up of $7,290 million for pension liabilities and $2,406 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree
medical liabilities). The benefit obligation for the Eurozone includes $4,328 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 174.
176
BP Annual Report and Form 20-F 2018
24. Pensions and other post-retirement benefits – continued
Analysis of the amount charged to profit or loss
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)
260
(3,301)
(3,041)
238
(3,279)
(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)
43
(5,094)
(5,051)
(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 174.
BP Annual Report and Form 20-F 2018
177
24. Pensions and other post-retirement benefits – continued
Analysis of the amount charged to profit or loss
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
UK
US
Eurozone
Other
333
17
—
350
30
380
(1,086)
1,005
(81)
4,422
(6,932)
430
55
(2,025)
310
(24)
—
286
194
480
(287)
417
130
330
(239)
9
(62)
38
76
7
9
92
7
99
(47)
159
112
53
(622)
12
26
(531)
71
1
(1)
71
33
104
(51)
80
29
8
4
(5)
15
22
$ million
2016
Total
790
1
8
799
264
1,063
(1,471)
1,661
190
4,813
(7,789)
446
34
(2,496)
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.
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 2018 for the group’s plans would have had the effects shown
in the table below. The effects shown for the expense in 2019 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 2019
Effect on pension and other post-retirement benefit obligation at 31 December 2018
Inflation rateb
Effect on pension and other post-retirement benefit expense in 2019
Effect on pension and other post-retirement benefit obligation at 31 December 2018
Salary growth
Effect on pension and other post-retirement benefit expense in 2019
Effect on pension and other post-retirement benefit obligation at 31 December 2018
$ million
One percentage point
Increase
Decrease
(337)
(6,179)
227
4,919
64
653
295
8,153
(187)
(4,225)
(55)
(595)
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 2019 pension and other post-retirement benefit expense by
$52 million and the pension and other post-retirement benefit obligation at 31 December 2018 by $1,432 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 2028 and the
weighted average duration of the defined benefit obligations at 31 December 2018 are as follows:
Estimated future benefit payments
2019
2020
2021
2022
2023
2024-2028
Weighted average duration
UK
1,030
1,036
1,056
1,088
1,120
5,777
17.8
US
Eurozone
Other
787
755
806
749
741
3,476
350
339
331
326
317
1,501
101
97
97
100
98
498
9.5
14.2
13.0
$ million
Total
2,268
2,227
2,290
2,263
2,276
11,252
Years
178
BP Annual Report and Form 20-F 2018
25. Cash and cash equivalents
Cash
Term bank deposits
Cash equivalents (excluding term bank deposits)
2018
6,148
13,105
3,215
22,468
$ million
2017
4,592
17,324
3,670
25,586
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 2018 includes $1,350 million (2017 $1,488 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 $4,693 million (2017 $3,638 million) of cash and cash equivalents outside the UK and it is not expected that any significant tax
will arise on repatriation.
26. Finance debt
Borrowings
Net obligations under finance leases
Current
Non-current
9,329
44
9,373
55,803
623
56,426
2018
Total
65,132
667
65,799
Current
7,701
38
7,739
Non-current
54,873
618
55,491
$ million
2017
Total
62,574
656
63,230
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
$7,175 million (2017 $6,849 million) and issued commercial paper of $2,040 million (2017 $744 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
7
4
6
4
18
4
16
Weighted
average
interest
rate
%
4
8
3
3
Amount
$ million
17,593
657
18,250
18,090
895
18,985
Amount
$ million
47,465
84
47,549
44,212
33
44,245
Amount
$ million
2018
65,058
741
65,799
2017
62,302
928
63,230
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 2018, whereas in the
group 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
2018
Carrying
amount
2,153
62,979
667
65,799
Fair value
852
63,182
1,131
65,165
Fair value
2,153
63,106
1,087
66,346
$ million
2017
Carrying
amount
852
61,722
656
63,230
BP Annual Report and Form 20-F 2018
179
27. 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 2018, the net debt ratio
was 30.3% (2017 27.4%).
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
2018
65,799
(813)
66,612
22,468
44,144
101,548
30.3%
$ million
2017
63,230
(175)
63,405
25,586
37,819
100,404
27.4 %
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 $827
million (2017 liability of $634 million, 2016 liability of $1,962 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 flow of $nil (2017 net cash outflow $242 million) and fair value losses of $193 million (2017 fair value gains of $1,086 million).
An analysis of changes in net debt is provided below.
Movement in net debt
At 1 January
Adjustment on adoption of
IFRS 9
Exchange adjustments
Net financing cash flow
Fair value gains (losses)
Other movements
At 31 December
Finance
debt
Hedge-
accounted
derivatives
Cash and
cash
equivalents
Net debt
Finance
debt
Hedge-
accounted
derivatives
Cash and
cash
equivalents
(63,230)
(175)
25,586
(37,819)
(58,300)
(697)
23,484
2018
—
259
(3,505)
856
(179)
(65,799)
—
—
360
(998)
—
(813)
(11)
(330)
(2,777)
—
—
22,468
(11)
(71)
(5,922)
(142)
(179)
(44,144)
—
(1,324)
(2,236)
(1,314)
(56)
(63,230)
—
—
(284)
1,282
(476)
(175)
—
544
1,558
—
—
25,586
$ million
2017
Net debt
(35,513)
—
(780)
(962)
(32)
(532)
(37,819)
a The adjustment on adoption of IFRS 9 reflects the creation of a credit loss allowance for cash and cash equivalents as a result of the new standard`s expected credit loss impairment model.
28. Operating leases
The cost recognized in relation to minimum lease payments for the year was $3,514 million (2017 $4,423 million and 2016 $5,113 million).
The future minimum lease payments at 31 December 2018, before deducting related rental income from operating sub-leases of $120 million
(2017 $188 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
2018
2,511
5,359
4,109
11,979
$ million
2017
2,969
6,387
4,614
13,970
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 2018, the future minimum lease payments relating to these amounted to $1,378 million (2017 $2,088 million).
180
BP Annual Report and Form 20-F 2018
28. Operating leases – continued
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 $3,032 million (2017 $3,172 million). Commercial vehicles hired under operating leases are
primarily railcars.
Retail service station sites and office accommodation are the main items in the land and buildings category. At 31 December 2018, the future
minimum lease payments relating to land and buildings amounted to $1,914 million (2017 $2,167 million).
The terms and conditions of these operating leases do not impose any significant financial restrictions on the group. Some of the leases of
rigs, 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' in the financial reporting period commencing 1 January 2019. See Note 1 for further details.
29. Financial instruments and financial risk factors
The accounting classification of each category of financial instruments and their carrying amounts are set out below. Current year amounts are
presented based on the classification, measurement and impairment requirements of IFRS 9. Comparatives are presented based on the
classification, measurement and impairment requirements of IAS 39.
At 31 December 2018
Financial assets
Other investments
Loans
Trade and other receivables
Derivative financial instruments
Cash and cash equivalents
Financial liabilities
Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Measured at
amortized
cost
Note
Mandatorily
measured at
fair value
through
profit or loss
Derivative
hedging
instruments
Total carrying
amount
$ million
18
20
30
25
22
30
26
—
839
24,080
—
20,366
(56,790)
—
(5,201)
(65,799)
(82,505)
1,563
124
—
8,564
2,102
—
(7,685)
—
—
4,668
—
—
—
427
—
—
(1,248)
—
—
(821)
1,563
963
24,080
8,991
22,468
(56,790)
(8,933)
(5,201)
(65,799)
(78,658)
$ million
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
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
Total carrying
amount
18
18
20
30
25
22
30
26
—
—
836
24,361
—
21,916
—
—
—
—
47,113
433
275
—
—
—
2,270
—
—
—
—
2,978
—
—
—
—
—
1,400
—
—
—
1,400
—
662
—
—
6,454
—
—
(5,705)
—
—
1,411
—
—
—
—
688
—
—
(864)
—
—
(176)
—
—
—
—
—
—
(54,054)
—
(5,465)
(63,230)
(122,749)
433
937
836
24,361
7,142
25,586
(54,054)
(6,569)
(5,465)
(63,230)
(70,023)
The fair value of finance debt is shown in Note 26. For all other financial instruments, the carrying amount is either the fair value, or
approximates the fair value.
Information on gains and losses on derivative financial assets and financial liabilities classified as measured at fair value through profit or loss is
provided in the derivative gains and losses section of Note 30. Fair value gains and losses related to other assets and liabilities classified as
measured at fair value through profit or loss totalled a net loss of $78 million. Dividend income of $8 million from investments in equity
instruments classified as measured at fair value through profit or loss is presented within other income - see Note 7.
Interest income and expenses arising on financial instruments are disclosed in Note 7.
BP Annual Report and Form 20-F 2018
181
29. Financial instruments and financial risk factors – continued
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 supply and
trading function. All derivative activity is carried out by specialist teams that have the appropriate skills, experience and supervision. These
teams are subject to close financial and management control.
The integrated supply and trading function maintains formal governance processes that provide oversight of market risk, credit risk and
operational risk associated with trading activity. A policy and risk committee approves value-at-risk delegations, reviews incidents and validates
risk-related policies, methodologies and procedures. A commitments committee approves 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.
(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 2018, the total foreign currency
borrowings not swapped into US dollars amounted to $741 million (2017 $928 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. A continuous assessment is made in respect to the group’s foreign currency exposures to capture
hedging requirements.
During the year, hedge accounting was applied to foreign currency exposure to highly probable forecast capital expenditure commitments. The
group fixes the US dollar cost of non-US dollar supplies by using currency forwards for the highly probable forecast capital expenditure; the
exposures are in sterling, euro, Australian dollar, Norwegian krone and Korean won. At 31 December 2018 the most significant open contracts
in place were for $434 million sterling (2017 $437 million sterling).
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.
182
BP Annual Report and Form 20-F 2018
29. Financial instruments and financial risk factors – continued
(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. While the group issues debt in a variety of currencies based on market opportunities, it uses
derivatives to swap the debt to a floating rate exposure, mainly to US dollar floating, but in certain defined circumstances maintains a US dollar
fixed rate exposure for a proportion of debt. The proportion of floating rate debt net of interest rate swaps at 31 December 2018 was 72% of
total finance debt outstanding (2017 70%). The weighted average interest rate on finance debt at 31 December 2018 was 4% (2017 3%) and
the weighted average maturity of fixed rate debt was five years (2017 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 changed by one percentage point on 1 January 2019, it is estimated that the group’s
finance costs for 2019 would change by approximately $475 million (2017 $442 million).
(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 2018 was
$696 million (2017 $656 million) in respect of liabilities of joint ventures and associates and $432 million (2017 $382 million) in respect of
liabilities of other third parties.
The group has a credit policy, approved by the CFO that is designed to ensure that consistent processes are in place throughout the group to
measure and control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business
contract the extent to which the arrangement exposes the group to credit risk is considered. Key requirements of the policy include
segregation of credit approval authorities from any sales, marketing or trading teams authorized to incur credit risk; the establishment of credit
systems and processes to ensure that all counterparty exposure is rated and that all counterparty exposure and limits can be monitored and
reported; and the timely identification and reporting of any non-approved credit exposures and credit losses. While each segment is
responsible for its own credit risk management and reporting consistent with group policy, the treasury function holds group-wide credit risk
authority and oversight responsibility for exposure to banks and financial institutions.
For the purposes of financial reporting the group calculates expected loss allowances based on the maximum contractual period over which
the group is exposed to credit risk. Since this is typically less than 12 months for the group's in-scope financial assets there is no significant
difference between the measurement of 12-month and lifetime expected credit losses. The group has no significant financial guarantee
liabilities measured on an expected loss basis. Financial assets are considered to be credit-impaired when there is reasonable and supportable
evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset have occurred. This
includes observable data concerning significant financial difficulty of the counterparty; a breach of contract; concession being granted to the
counterparty for economic or contractual reasons relating to the counterparty’s financial difficulty, that would not otherwise be considered; it
becoming probable that the counterparty will enter bankruptcy or other financial re-organization or an active market for the financial asset
disappearing because of financial difficulties. The group also applies a rebuttable presumption that an asset is credit-impaired when contractual
payments are more than 30 days past due. Where the group has no reasonable expectation of recovering a financial asset in its entirety or a
portion thereof for example where all legal avenues for collection of amounts due have been exhausted, the financial asset (or relevant portion)
is written off.
The measurement of expected credit losses is a function of the probability of default, loss given default (i.e. the magnitude of the loss after
recovery if there is a default) and the exposure at default (i.e. the asset's carrying amount). The group allocates a credit risk rating to exposures
based on data that is determined to be predictive of the risk of loss, including but not limited to external ratings. Probabilities of default derived
from historical, current and future-looking market data are assigned by credit risk rating with a loss given default based on historical experience
and relevant market and academic research applied by exposure type. Experienced credit judgement is applied to ensure probabilities of
default are reflective of the credit risk associated with the group's exposures. Credit enhancements that would reduce the group's credit
losses in the event of default are reflected in the calculation when they are considered integral to the related asset.
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 2018, the group had in place credit enhancements
designed to mitigate approximately $7.3 billion of credit risk, of which $6.7 billion relates to assets in the scope of IFRS 9's impairment
requirements. Credit enhancements include standby and documentary letters of credit, bank guarantees, insurance and liens which are
typically taken out with financial institutions who have investment grade credit ratings, or are liens over assets held by the counterparty of the
related receivables. 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, which reflects the impact of credit enhancements, indicates that the risk profile of
financial assets which are subject to review for impairment under IFRS 9 is as set out below.
As at 31 December
AAA to AA-
A+ to A-
BBB+ to BBB-
BB+ to BB-
B+ to B-
CCC+ and below
For the comparative period an analysis of the ageing of trade and other receivables reported under IAS 39 is provided.
%
2018
22%
41%
16%
8%
11%
2%
BP Annual Report and Form 20-F 2018
183
29. Financial instruments and financial risk factors – continued
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
$ million
2017
22,858
53
637
130
114
569
24,361
Movements in the impairment provision for trade and other receivables are shown in Note 21.
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 2018
Derivative assets
Derivative liabilities
Trade and other receivables
Trade and other payables
At 31 December 2017
Derivative assets
Derivative liabilities
Trade and other receivables
Trade and other payables
Gross
amounts of
recognized
financial
assets
(liabilities)
11,502
(11,337)
11,296
(10,797)
8,522
(7,818)
11,648
(12,543)
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
8,991
(8,826)
5,906
(5,407)
7,142
(6,438)
6,337
(7,232)
(2,079)
2,079
(1,020)
1,020
(1,554)
1,554
(2,156)
2,156
(299)
—
(169)
—
(321)
—
(114)
—
6,613
(6,747)
4,717
(4,387)
5,267
(4,884)
4,067
(5,076)
Amounts
set off
(2,511)
2,511
(5,390)
5,390
(1,380)
1,380
(5,311)
5,311
(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.
BP utilizes various arrangements in order to manage its working capital including discounting of receivables and, in the supply and trading
business, the active management of supplier payment terms, inventory and collateral. In line with normal industry practice some supplier
arrangements utilize letter of credit (LC) facilities. In certain of those arrangements BP’s payments are made to the provider of the LC rather
than the supplier.
Standard & Poor’s Ratings long-term credit rating for BP is A- (stable outlook) and Moody’s Investors Service rating is A1 (stable outlook).
During 2018, $9 billion of long-term taxable bonds were issued with terms ranging from four to ten years. Commercial paper is issued at
competitive rates to meet short-term borrowing requirements as and when needed.
As a further liquidity measure, the group continues to maintain suitable levels of cash and cash equivalents, amounting to $22.5 billion at
31 December 2018 (2017 $25.6 billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate
and short notice. At 31 December 2018, 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 has committed LC facilities totalling $12,175 million with a number of banks, allowing LCs to be issued for a maximum 24-month
duration. There were also uncommitted secured LC facilities in place at 31 December 2018 for $4,190 million, which are secured against
inventories or receivables when utilized. The facilities only terminate by either party giving a stipulated termination notice to the other.
The amounts shown for finance debt in the table below include future minimum lease payments with respect to finance leases. The table also
shows the timing of cash outflows relating to trade and other payables and accruals.
184
BP Annual Report and Form 20-F 2018
29. Financial instruments and financial risk factors – continued
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
43,230
2,232
1,662
1,484
1,406
6,058
5,001
61,073
Accruals
4,626
146
95
64
89
113
68
5,201
2018
Interest on
finance debt
2,404
1,955
1,700
1,422
1,138
2,390
320
11,329
Finance
debt
9,301
6,788
6,805
8,057
7,058
25,356
1,243
64,608
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
Finance
debt
7,626
7,331
7,068
6,766
7,986
24,162
2,089
63,028
$ million
2017
Interest on
finance debt
1,757
1,537
1,321
1,114
894
1,951
390
8,964
a 2018 includes $18,360 million (2017 $18,918 million) in relation to the Gulf of Mexico oil spill.
The group manages liquidity risk associated with derivative contracts, other than derivative hedging instruments, based on the expected
maturities of both derivative assets and liabilities as indicated in Note 30. 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 finance 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 $22,453 million at 31 December 2018 (2017 $21,484
million) to be received on the same day as the related cash outflows. For further information on our derivative financial instruments, see Note
30.
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
2018
1,700
1,678
2,384
2,838
2,906
11,475
724
23,705
$ million
2017
1,505
1,700
1,678
2,384
2,838
11,238
724
22,067
30. 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 29. 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. Exchange traded derivatives are typically considered settled through the (normally daily)
payment or receipt of variation margin.
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 2018
185
30. 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
Gas price futures
Fair value hedges
Currency forwards, futures and swaps
Interest rate swaps
Of which – current
– non-current
Fair value
asset
2018
Fair value
liability
69
2,361
4,787
1,240
107
8,564
—
—
—
5
2
7
158
262
420
8,991
3,846
5,145
(898)
(1,849)
(3,888)
(943)
—
(7,578)
—
(107)
(107)
(14)
—
(14)
(789)
(445)
(1,234)
(8,933)
(3,308)
(5,625)
Fair value
asset
237
1,637
3,580
885
115
6,454
—
—
—
35
—
35
460
193
653
7,142
3,032
4,110
$ million
2017
Fair value
liability
(756)
(1,281)
(2,844)
(693)
—
(5,574)
(16)
(115)
(131)
(35)
—
(35)
(523)
(306)
(829)
(6,569)
(2,808)
(3,761)
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 29.
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
48
1,916
1,333
540
—
3,837
Less than
1 year
186
1,280
1,122
420
—
3,008
1-2 years
2-3 years
3-4 years
4-5 years
12
363
708
276
—
1,359
9
53
542
158
—
762
—
25
452
79
—
556
—
4
352
55
107
518
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
$ million
2018
Total
69
2,361
4,787
1,240
107
8,564
$ million
2017
Total
237
1,637
3,580
885
115
6,454
Over
5 years
—
—
1,400
132
—
1,532
Over
5 years
4
1
805
98
115
1,023
186
BP Annual Report and Form 20-F 2018
30. 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
(299)
(1,560)
(1,030)
(401)
(3,290)
Less than
1 year
(92)
(1,120)
(973)
(337)
(2,522)
1-2 years
2-3 years
3-4 years
4-5 years
(71)
(232)
(557)
(213)
(1,073)
(256)
(43)
(391)
(95)
(785)
(171)
(12)
(338)
(54)
(575)
(3)
(2)
(285)
(47)
(337)
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)
$ million
2018
Total
(898)
(1,849)
(3,888)
(943)
(7,578)
$ million
2017
Total
(756)
(1,281)
(2,844)
(693)
(5,574)
Over
5 years
(98)
—
(1,287)
(133)
(1,518)
Over
5 years
(79)
—
(709)
(91)
(879)
The following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by
methodology of fair value estimation. This information is presented on a gross basis, that is, before netting by counterparty.
Fair value of derivative assets
Level 1
Level 2
Level 3
Less: netting by counterparty
Fair value of derivative liabilities
Level 1
Level 2
Level 3
Less: netting by counterparty
Net fair value
Fair value of derivative assets
Level 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
111
5,000
491
5,602
(1,765)
3,837
(156)
(4,562)
(337)
(5,055)
1,765
(3,290)
547
Less than
1 year
3,663
386
4,049
(1,041)
3,008
(3,338)
(225)
(3,563)
1,041
(2,522)
486
1-2 years
2-3 years
3-4 years
4-5 years
14
1,362
385
1,761
(402)
1,359
(11)
(1,161)
(303)
(1,475)
402
(1,073)
286
3
504
353
860
(98)
762
(2)
(576)
(305)
(883)
98
(785)
(23)
—
262
331
593
(37)
556
(2)
(308)
(302)
(612)
37
(575)
(19)
—
120
427
547
(29)
518
—
(67)
(299)
(366)
29
(337)
181
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
$ million
2018
Total
128
7,320
3,627
11,075
(2,511)
8,564
(171)
(6,837)
(3,081)
(10,089)
2,511
(7,578)
986
$ million
2017
Total
5,623
2,211
7,834
(1,380)
6,454
(5,267)
(1,687)
(6,954)
1,380
(5,574)
880
Over
5 years
—
72
1,640
1,712
(180)
1,532
—
(163)
(1,535)
(1,698)
180
(1,518)
14
Over
5 years
135
899
1,034
(11)
1,023
(166)
(724)
(890)
11
(879)
144
BP Annual Report and Form 20-F 2018
187
30. 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 2018
Gains (losses) recognized in the income statement
Settlements
Transfers out of level 3
Net fair value of contracts at 31 December 2018
Deferred day-one gains (losses)
Derivative asset (liability)
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)
Oil
price
67
58
(107)
5
23
Natural gas
price
65
(26)
(32)
(20)
(13)
Oil
price
68
76
(68)
(9)
67
Natural gas
price
145
161
(35)
(206)
65
Power
price
(226)
209
(97)
(34)
(148)
Power
price
(147)
61
(113)
(27)
(226)
Other
115
(8)
—
—
107
Other
231
15
(131)
—
115
$ million
Total
21
233
(236)
(49)
(31)
577
546
$ million
Total
297
313
(347)
(242)
21
503
524
The amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at 31 December 2018 was a
$123-million gain (2017 $234-million gain related to derivatives still held at 31 December 2017).
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 $2,504 million (2017 $1,983 million net gain and 2016 $1,435 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 loss of $351 million (2017
$1,420 million net gain and 2016 $154 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
(i) Foreign currency risk of highly probable forecast capital expenditure
At 31 December 2018, the group held currency forwards designated as hedging instruments in cash flow hedge relationships of highly
probable forecast non-US dollar capital expenditure. Note 29 outlines the group’s approach to foreign currency exchange risk management.
When the highly probable forecast capital expenditure designated as a hedged item occurs, a non-financial asset is recognized and is
presented within the fixed asset section of the balance sheet.
The group claims hedge accounting only for the spot value of the currency exposure in line with the strategy to fix the volatility in the spot
exchange rate element. The fair value on the instrument attributable to forward points is taken immediately to the income statement.
The group applies hedge accounting where there is an economic relationship between the hedged item and hedging instrument. The existence
of an economic relationship is determined at inception and prospectively by comparing the critical terms of the hedging instrument and those
of the hedged item. The group enters into hedging derivatives that match the currency and notional of the hedged items on a 1:1 hedge ratio
basis. The hedge ratio is determined by comparing the notional amount of the derivative with the notional designated on the forecast
transaction. The group determines the extent to which it hedges highly probable forecast capital expenditures on a project by project basis.
The group has identified the following sources of ineffectiveness, which are not expected to be material:
• counterparty's credit risk, the group mitigates counterparty credit risk by entering into derivative transactions with high credit quality
counterparties; and
• differences in settlement timing between the derivative and hedged items. The latter impacts the discount factor used in the calculation of
the hedge ineffectiveness. The group mitigates differences in timing between the derivatives and hedged items by applying a rolling strategy
and by hedging currency pairs from stable economies (i.e. sterling/US dollar, Euro/US dollar, Norwegian krone/US dollar, Korean won/US
dollar). The group's cash flow hedge designations are highly effective as the sources of ineffectiveness identified are expected to result in
minimal hedge ineffectiveness.
The group has not designated any net positions as hedged items in cash flow hedges of foreign currency risk.
188
BP Annual Report and Form 20-F 2018
30. Derivative financial instruments – continued
(ii) Commodity price risk of highly probable forecast sales
At 31 December 2018, the group held Henry Hub NYMEX futures designated as hedging instruments in cash flow hedge relationships of
certain highly probable forecast future sales.
The group is exposed to the variability in the gas price, but only applies hedge accounting to the risk of Henry Hub price movements for a
percentage of future gas sales from its BPX Energy business (previously known as US Lower 48 business). Hedge accounting may be applied
to such sales for up to the following two calendar years.
The group applies hedge accounting in relation to these highly probable future sales where there is an economic relationship between the
hedged item and hedging instrument. The existence of an economic relationship is determined at inception and prospectively by comparing the
critical terms of the hedging instrument and those of the hedged item. The group enters into hedging derivatives that match the notional
amounts of the hedged items on a 1:1 hedge ratio basis. The hedge ratio is determined by comparing the notional amount of the derivative
with the notional amount designated on the forecast transaction.
The hedge is expected to be highly effective due to the price index of the hedging instruments matching the price index of the hedged item
and the derivative assets or liabilities recognized in respect of exchange-traded instruments reflect the impact of daily margin payments and
receipts.
The group has not designated any net positions as hedged items in cash flow hedges of commodity price risk.
The table below summarizes the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the
period.
At 31 December 2018
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure
Commodity price risk
Highly probable forecast sales
Change in fair
value of
hedging
instrument
used to
calculate
ineffectiveness
Change in fair
value of
hedged item
used to
calculate
ineffectiveness
$ million
Hedge
ineffectiveness
recognized in
profit or (loss)
(5)
(126)
5
126
—
—
The table below summarizes the carrying amount and nominal amount of the derivatives designated as hedging instruments in cash flow
hedge relationships at 31 December 2018.
At 31 December 2018
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure
Commodity price risk
Highly probable forecast sales
Carrying amount of hedging
instrument
Assets
Liabilities
Nominal amounts of hedging
instruments
$ million
$ million
$ million
mmBtu
5
2
(14)
—
386
145
All hedging instruments are presented within derivative financial instruments on the group balance sheet.
Of the nominal amount of hedging instruments relating to highly probable forecast capital expenditure $304 million matures in 2019 and $82
million matures in 2020. All of the hedging instruments relating to highly probable forecast sales mature in 2019.
The table below summarizes the weighted average exchange rates and the weighted average sales price in relation to the derivatives
designated as hedging instruments in cash flow hedge relationships at 31 December 2018.
At 31 December 2018
Sterling/US dollar
Euro/US dollar
Australian dollar/US dollar
Norwegian krone/US dollar
Korean won/US dollar
Henry Hub $/mmBtu
Weighted average price/rate
Forecast
capital
expenditure
1.34
1.14
0.72
8.67
1,107.90
Forecast sales
2.86
BP Annual Report and Form 20-F 2018
189
30. Derivative financial instruments – continued
Fair value hedges
At 31 December 2018, 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 arising from group fixed rate debt issuances. The interest rate swaps are used to convert US dollar denominated fixed
rate borrowings into floating rate debt. The cross-currency interest rate swaps are used to convert sterling, euro, Swiss franc, Australian dollar,
Canadian dollar and Norwegian krone denominated fixed rate borrowings into US dollar floating rate debt. The group manages all risks derived
from debt issuance, such as credit risk, however, the group applies hedge accounting only to certain components of interest rate and foreign
currency risk in order to minimize hedge ineffectiveness. Note 29 outlines the group’s approach to interest rate and foreign currency exchange
risk management.
The interest rate and foreign currency exposures are identified and hedged on an instrument-by-instrument basis. For interest rate exposures,
the group designates as a fair value hedge the benchmark interest rate component only. This is an observable and reliably measurable
component of interest rate risk. For foreign currency exposures, the group excludes from the designation the foreign currency basis spread
component implicit in the cross-currency interest rate swaps. This is separately calculated at hedge designation, is recognized in other
comprehensive income over the life of the hedge and amortized to the income statement on a straight-line basis, in accordance with the
group’s policy on costs of hedging.
The group applies hedge accounting where there is an economic relationship between the hedged item and the hedging instrument. The
existence of an economic relationship is determined initially by comparing the critical terms of the hedging instrument and those of the hedged
item and it is prospectively assessed using linear regression analysis. The group issues fixed rate debt and enters into interest rate and cross-
currency interest rate swaps with critical terms that match those of the debt and on a 1:1 hedge ratio basis. The hedge ratio is determined by
comparing the notional amount of the derivative with the notional amount of the debt. The hedge relationship is designated for the full term
and notional value of the debt. Both the hedging instrument and the hedged item are expected to be held to maturity.
The group has identified the following sources of ineffectiveness, which are not expected to be material:
• derivative counterparty’s credit risk which is not offset by the hedged item. This risk is mitigated by entering into derivative transactions only
with high credit quality counterparties; and
• sensitivity to interest rate between the hedged item and the derivatives. This is driven by differences in payment frequencies between the
instrument and the bond.
The table below summarizes the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the
period.
At 31 December 2018
Fair value hedges
Interest rate risk on finance debt
Interest rate and foreign currency risk on finance debt
Change in fair
value of
hedging
instrument
used to
calculate
ineffectiveness
Change in fair
value of
hedged item
used to
calculate
ineffectiveness
$ million
Hedge
ineffectiveness
recognized in
profit or (loss)
(70)
812
69
(809)
(1)
3
The table below summarizes the carrying amount of the derivatives designated as hedging instruments in fair value hedge relationships at
31 December 2018.
At 31 December 2018
Fair value hedges
Interest rate risk on finance debt
Interest rate and foreign currency risk on finance debt
$ million
Carrying amount of hedging
instrument
Assets
Liabilities
Nominal
amounts of
hedging
instruments
262
158
(445)
(789)
24,513
16,580
All hedging instruments are presented within derivative financial instruments on the group balance sheet. Ineffectiveness arising on fair value
hedges is included within the production and manufacturing expenses section of the income statement.
The table below summarizes the profile by tenor of the nominal amount of the derivatives designated as hedging instruments in fair value
hedge relationships at 31 December 2018. The weighted average floating interest rate of these interest rate swaps and cross-currency interest
rate swaps was 3.04% and 4.07% respectively.
At 31 December 2018
Fair value hedges
Interest rate risk on finance debt
Interest rate and foreign currency
risk on finance debt
Less than 1
year
1-2 years
2-3 years
3-4 years
4-5 years
5-10 years Over 10 years
Total
$ million
2,694
—
2,324
1,245
2,597
1,167
4,923
1,700
10,275
707
2,921
10,254
—
286
24,513
16,580
190
BP Annual Report and Form 20-F 2018
30. Derivative financial instruments – continued
The table below summarizes the carrying amount, and the accumulated fair value adjustments included within the carrying amount, of the
hedged items designated in fair value hedge relationships at 31 December 2018.
At 31 December 2018
Fair value hedges
Carrying amount of hedged item
Accumulated fair value adjustment included in the
carrying amount of hedged items
$ million
Assets
Liabilities
Assets
Liabilities
Discontinued
hedges
Interest rate risk on finance debt
Interest rate and foreign currency risk on finance debt
—
—
(24,747)
(16,883)
175
—
—
(62)
(360)
—
The hedged item for all fair value hedges is presented within finance debt on the group balance sheet.
Movement in reserves related to hedge accounting
The table below provides a reconciliation of the cash flow hedge and costs of hedging reserves on a pre-tax basis by risk category. The signage
convention of this table is consistent with that presented in Note 32.
Cash flow hedge reserve
Highly
probable
forecast capital
expenditure
Highly
probable
forecast sales
Purchase of
equitya
At 31 December 2017
Adjustment on adoption of IFRS 9
At 1 January 2018
Recognized in other comprehensive income
Cash flow hedges marked to market
Cash flow hedges reclassified to the income statement - hedged
item affected profit or loss
Costs of hedging marked to market
Costs of hedging reclassified to the income statement
Cash flow hedges transferred to the balance sheet
At 31 December 2018
a See Note 32 for further information on the cash flow hedge reserve relating to the purchase of equity
(10)
—
(10)
(37)
—
—
—
(37)
26
(21)
—
—
—
(126)
120
—
—
(6)
—
(6)
(651)
—
(651)
—
—
—
—
—
—
(651)
Costs of
hedging
reserve
Interest rate
and foreign
currency risk
on finance
debt
—
(37)
(37)
—
—
(244)
58
(186)
—
(223)
$ million
Total
(661)
(37)
(698)
(163)
120
(244)
58
(229)
26
(901)
Substantially all of the cash flow hedge reserve balances and all of the amounts reclassified into profit or loss during the year relate to
continuing hedge relationships. Amounts deferred in the cash flow hedge reserve that have been reclassified to profit or loss are presented in
sales and other operating revenues in the income statement.
Costs of hedging relates to the foreign currency basis spreads of hedging instruments used to hedge the group's interest rate and foreign
currency risk on debt which is a time-period related item.
BP Annual Report and Form 20-F 2018
191
31. Called-up share capital
The allotted, called up and fully paid share capital at 31 December was as follows:
Issued
8% cumulative first preference shares of £1 eacha
9% cumulative second preference shares of £1 eacha
Ordinary shares of 25 cents each
At 1 January
Issue of new shares for the scrip dividend programme
Issue of new shares for employee share-based
payment plans
Issue of new shares – otherb
Repurchase of ordinary share capital
At 31 December
Shares
thousand
7,233
5,473
2018
$ million
12
9
21
Shares
thousand
7,233
5,473
2017
$ million
12
9
21
Shares
thousand
7,233
5,473
21,288,193
195,305
5,322
49
21,049,696
289,789
5,263
72
20,108,771
548,005
92,168
—
(50,202)
21,525,464
—
—
(51,292)
21,288,193
23
—
(13)
5,381
5,402
—
392,920
—
21,049,696
—
—
(13)
5,322
5,343
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 2016 relates to the issue of new ordinary shares in consideration for a 10% interest in the Abu Dhabi onshore oil concession. See Note 32 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 2018 the company repurchased 50 million ordinary shares for a total consideration of $355 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
Issue of new shares for employee share-based
payment plans
Shares re-issued for employee share-based payment
plans
At 31 December
Of which – shares held in treasury by BP
– shares held in ESOP trusts
– shares held by BP’s US share plan
administratorb
2018
Shares
thousand
1,482,072
757
Nominal value
$ million
370
—
Shares
thousand
1,614,657
4,423
2017
Nominal value
$ million
403
1
Shares
thousand
1,756,327
9,631
2016
Nominal value
$ million
439
2
92,168
23
—
—
—
(148,732)
(37)
(137,008)
(34)
(151,301)
1,426,265
1,264,732
161,518
15
356
316
40
—
1,482,072
1,472,343
9,705
24
370
368
2
—
1,614,657
1,576,411
21,432
16,814
—
(38)
403
394
5
4
a See Note 32 for definition of treasury shares.
b Held in the form of ADSs to meet the requirements of employee share-based payment plans in the US.
For each year presented, the balance at 1 January represents the maximum number of shares held in treasury by BP during the year,
representing 6.9% (2017 7.5% and 2016 8.6%) of the called-up ordinary share capital of the company.
During 2018, the movement in shares held in treasury by BP represented less than 1.0% (2017 less than 0.5% and 2016 less than 0.8%) of the
ordinary share capital of the company.
192
BP Annual Report and Form 20-F 2018
THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY
BP Annual Report and Form 20-F 2018
193
32. Capital and reserves
At 31 December 2017
Adjustment on adoption of IFRS 9, net of tax
At 1 January 2018
Profit (loss) for the year
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including reclassifications)
Cash flow hedges and costs of hedging (including reclassifications)
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
Cash flow hedges that will subsequently be transferred to the balance sheet
Total comprehensive income
Dividends
Cash flow hedges transferred to the balance sheet, net of tax
Repurchases of ordinary share capital
Share-based payments, net of taxb
Share of equity-accounted entities’ changes in equity, net of tax
Transactions involving non-controlling interests, net of tax
At 31 December 2018
At 1 January 2017
Profit (loss) for the year
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including reclassifications)
Available-for-sale investments (including reclassifications)
Cash flow hedges (including reclassifications)
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 interests, net of taxc
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 reclassifications)a
Available-for-sale investments (including reclassifications)
Cash flow hedges (including reclassifications)
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, net of tax
At 31 December 2016
a Principally foreign exchange effects relating to the Russian rouble.
b Movements in treasury shares relate to employee share-based payment plans.
194
BP Annual Report and Form 20-F 2018
Share
capital
Share
premium
account
Capital
redemption
reserve
Merger
reserve
—
5,343 12,147
—
5,343 12,147
—
—
—
1,426 27,206
—
1,426 27,206
—
—
—
—
—
—
—
—
—
—
—
—
—
49
—
(13)
23
—
—
—
—
—
(49)
—
—
207
—
—
5,402 12,305
—
—
—
—
—
—
—
—
—
—
—
—
—
13
—
—
—
—
—
—
—
—
—
—
—
—
1,439 27,206
Total
share capital
and capital
reserves
46,122
—
46,122
—
—
—
—
—
—
—
—
—
—
—
230
—
—
46,352
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
32. Capital and reserves – continued
Treasury
shares
(16,958)
—
(16,958)
—
—
—
—
—
—
—
—
—
—
—
1,191
—
—
(15,767)
Treasury
shares
(18,443)
—
—
—
—
—
—
—
—
—
—
1,485
—
—
(16,958)
Treasury
shares
(19,964)
—
—
—
—
—
—
—
—
—
1,521
—
—
(18,443)
Foreign
currency
translation
reserve
(5,156)
—
(5,156)
—
(3,746)
—
—
—
—
—
(3,746)
—
—
—
—
—
—
(8,902)
Foreign
currency
translation
reserve
(6,878)
—
1,722
—
—
—
—
—
1,722
—
—
—
—
—
(5,156)
Foreign
currency
translation
reserve
(7,267)
—
389
—
—
—
—
—
389
—
—
—
—
(6,878)
Available-
for-sale
investments
Cash flow
hedges
Costs of
hedging
Total
fair value
reserves
Profit and
loss
account
BP
shareholders’
equity
Non-
controlling
interests
17
(17)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Available-
for-sale
investments
3
—
—
14
—
—
—
—
14
—
—
—
—
—
17
(760)
—
(760)
—
—
(6)
—
—
—
(37)
(43)
—
26
—
—
—
—
(777)
Cash flow
hedges
(1,156)
—
—
—
396
—
—
—
396
—
—
—
—
—
(760)
—
(37)
(37)
—
—
(173)
—
—
—
—
(173)
—
—
—
—
—
—
(210)
Costs of
hedging
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Available-
for-sale
investments
Cash flow
hedges
Costs of
hedging
2
—
—
1
—
—
—
—
1
—
—
—
—
3
(825)
—
—
—
(331)
—
—
—
(331)
—
—
—
—
(1,156)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(743)
(54)
(797)
—
—
(179)
—
—
—
(37)
(216)
—
26
—
—
—
—
(987)
Total
fair value
reserves
(1,153)
—
—
14
396
—
—
—
410
—
—
—
—
—
(743)
Total
fair value
reserves
(823)
—
—
1
(331)
—
—
—
(330)
—
—
—
—
(1,153)
75,226
(126)
75,100
9,383
—
—
417
7
1,599
—
11,406
(6,699)
—
(355)
(718)
14
—
78,748
Profit and
loss
account
75,638
3,389
(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
98,491
(180)
98,311
9,383
(3,746)
(179)
417
7
1,599
(37)
7,444
(6,699)
26
(355)
703
14
—
99,444
1,913
—
1,913
195
(41)
—
—
—
—
—
154
(170)
—
—
—
—
207
2,104
BP
shareholders’
equity
95,286
3,389
Non-
controlling
interests
1,557
79
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
$ million
Total equity
100,404
(180)
100,224
9,578
(3,787)
(179)
417
7
1,599
(37)
7,598
(6,869)
26
(355)
703
14
207
101,548
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
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.
BP Annual Report and Form 20-F 2018
195
32. Capital and reserves – continued
Share capital
The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including
treasury shares.
Share premium account
The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference
shares.
Capital redemption reserve
The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled.
Merger reserve
The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares
issued in an acquisition made by the issue of shares.
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 reclassified to the income statement.
Available-for-sale investments
This reserve recorded the changes in fair value of investments classified as available-for-sale under IAS 39 except for impairment losses,
foreign exchange gains or losses, or changes arising from revised estimates of future cash flows. On adoption of IFRS 9 the balance in this
reserve was transferred to the profit and loss account reserve. Under the new standard the group recognizes fair value gains and losses on
these investments in profit or loss.
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.
Costs of hedging
This reserve records the change in fair value of the foreign currency basis spread of financial instruments to which cost of hedge accounting
has been applied. The accumulated amount relates to time-period related hedged items and is amortized to profit or loss over the term of the
hedging relationship.
Prior to the group’s adoption of IFRS 9 changes in the fair value of such foreign currency basis spreads were recognized in profit or loss. On
adoption of the new standard a transfer from the profit and loss account reserve to the costs of hedging reserve was made in order to reflect
the opening reserves position for relevant hedging instruments existing on transition. For further information on the accounting for costs of
hedging 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.
196
BP Annual Report and Form 20-F 2018
32. Capital and reserves – continued
The pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below.
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including reclassifications)
Cash flow hedges (including reclassifications)
Costs of hedging (including reclassifications)
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
Cash flow hedges that will subsequently be transferred to the balance sheet
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including reclassifications)
Available-for-sale investments (including reclassifications)
Cash flow hedges (including reclassifications)
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 reclassifications)
Available-for-sale investments (including reclassifications)
Cash flow hedges (including reclassifications)
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
33. Contingent liabilities
Pre-tax
Tax
Net of tax
$ million
2018
(3,771)
(6)
(186)
417
—
2,317
(37)
(1,266)
(16)
—
13
—
7
(718)
—
(714)
(3,787)
(6)
(173)
417
7
1,599
(37)
(1,980)
$ million
2017
Pre-tax
Tax
Net of tax
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)
Contingent liabilities related to the Gulf of Mexico oil spill
See Note 2 for information on contingent liabilities related to the Gulf of Mexico oil spill.
Contingent liabilities not related to the Gulf of Mexico oil spill
There were contingent liabilities at 31 December 2018 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 29.
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 and regulatory
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 2018
197
33. 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 impact on the group’s results of operations, 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.
While the amounts associated with decommissioning provisions reverting to the group could be significant and could be material, 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.
See also Legal proceedings on pages 296-298.
34. 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.
2018
2017
8
16
24
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.
Pension contributions
During 2018 one executive director participated in a UK final salary pension plan in respect of service prior to 1 April 2011. During 2018, one
executive director participated in retirement savings plans established for US employees and in a US defined benefit 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 87. See also Related-party transactions
on page 300.
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
2018
2017
25
2
32
59
29
2
29
60
$ million
2016
28
3
39
70
Senior management comprises members of the executive team, see pages 63-65 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 2018 (2017 $nil and 2016 $2.2 million).
Pensions and other post-retirement benefits
The amounts represent the estimated cost to the group of providing pensions and other post-retirement benefits to senior management in
respect of the current year of service measured in accordance with IAS 19 ‘Employee Benefits’.
Share-based payments
This is the cost to the group of senior management’s participation in share-based payment plans, as measured by the fair value of options and
shares granted, accounted for in accordance with IFRS 2 ‘Share-based Payments’.
198
BP Annual Report and Form 20-F 2018
35. Employee costs and numbers
Employee costs
Wages and salariesa
Social security costs
Share-based paymentsb
Pension and other post-retirement benefit costs
2018
7,931
743
669
1,154
10,497
2017
7,572
711
624
1,296
10,203
Average number of employeesc
US
Non-US
Upstream
Downstreamd e
Other businesses and corporatee f
5,900
6,000
1,900
13,800
11,500
36,300
12,100
59,900
2018
Total
17,400
42,300
14,000
73,700
US
Non-US
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
$ million
2016
8,456
760
764
1,253
11,233
2016
Total
20,200
43,200
14,000
77,400
a Includes termination costs of $493 million (2017 $189 million and 2016 $545 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 17,100 (2017 16,500 and 2016 15,800) service station staff.
e Around 800 centralized function employees were reallocated from Upstream and Downstream to Other businesses and corporate during 2016.
f Includes 4,000 (2017 4,700 and 2016 4,900) agricultural, operational and seasonal workers in Brazil.
36. Auditor’s remuneration
Fees
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
Non-audit and other assurance services
Total non-audit or non-audit-related assurance services
Services relating to BP pension plans
2018
2017
$ million
2016
25
10
35
4
39
—
2
2
1
42
26
11
37
7
44
—
3
3
—
47
25
12
37
7
44
1
1
2
1
47
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.
With effect from 2018, following a competitive tender process, Deloitte LLP (Deloitte) was appointed as auditor of the Company, replacing
Ernst & Young LLP (EY). In the table above, auditor’s remuneration for services provided during the year ended 31 December 2018 thus relates
to Deloitte and for the years ended 31 December 2017 and 31 December 2016 to EY.
In addition to the amounts shown in the table above, in 2018 $0.75 million of additional fees were paid to EY in respect of their audit for 2017.
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 Deloitte to render audit and certain
assurance and other services. The audit fees payable to Deloitte were considered as part of the audit tender process in 2016 and challenged by
the audit committee through comparison with the audit pricing proposals of the other bidding firms, before being approved. Deloitte performed
further assurance services that were not prohibited by regulatory or other professional requirements and were pre-approved by the
Committee. Deloitte is engaged for these services when its expertise and experience of BP are important. Most of this work is of an audit-
related or assurance nature.
Under SEC regulations, the remuneration of the auditor of $42 million (2017 $47 million and 2016 $47 million) is required to be presented as
follows: audit $35 million (2017 $37 million and 2016 $37 million); other audit-related $4 million (2017 $7 million and 2016 $7 million); tax $nil
(2017 $nil and 2016 $1 million); and all other fees $3 million (2017 $3 million and 2016 $2 million).
BP Annual Report and Form 20-F 2018
199
37. Subsidiaries, joint arrangements and associates
The more important subsidiaries and associates of the group at 31 December 2018 and the group percentage of ordinary share capital (to
nearest whole number) are set out below. There are no individually significant incorporated joint arrangements. The group's share of the assets
and liabilities of the more important unincorporated joint arrangements are held by subsidiaries listed in the table below. Those subsidiaries
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
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
Rosneft Oil Company
19.75 Russia
Integrated oil operations
200
BP Annual Report and Form 20-F 2018
38. 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
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
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
4,315
—
—
—
42
—
4,357
1,507
1,015
282
377
66
—
22
1,088
8
—
1,080
164
916
916
—
916
Other
subsidiaries
Eliminations
and
reclassifications
298,620
897
2,856
—
2,081
456
304,910
232,550
21,990
1,254
15,080
794
1,445
11,673
20,124
2,759
222
17,143
6,922
10,221
10,026
195
10,221
(4,179)
—
—
(10,942)
(1,723)
—
(16,844)
(4,179)
—
—
—
—
—
(158)
(12,507)
(1,565)
—
(10,942)
—
(10,942)
(10,942)
—
(10,942)
BP p.l.c.
—
—
—
10,942
373
—
11,315
—
—
—
—
—
—
642
10,673
1,326
(95)
9,442
59
9,383
9,383
—
9,383
$ million
2018
BP group
298,756
897
2,856
—
773
456
303,738
229,878
23,005
1,536
15,457
860
1,445
12,179
19,378
2,528
127
16,723
7,145
9,578
9,383
195
9,578
BP Annual Report and Form 20-F 2018
201
38. Condensed consolidating information on certain US subsidiaries – continued
Statement of comprehensive income
Profit (loss) for the year
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences
Cash flow hedges (including reclassifications)
Costs of hedging (including reclassifications)
Share of items relating to equity-accounted entities, net of tax
Income tax relating to items that may be reclassified
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement
benefit liability or asset
Cash flow hedges that will subsequently be transferred to the
balance sheet
Income tax relating to items that will not be reclassified
Other comprehensive income
Equity-accounted other comprehensive income of subsidiaries
Total comprehensive income
Attributable to
BP shareholders
Non-controlling interests
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 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.
916
Other
subsidiaries
Eliminations
and
reclassifications
10,221
(10,942)
BP p.l.c.
9,383
—
—
—
—
—
—
—
—
—
—
—
—
916
916
—
916
(296)
—
—
—
—
(296)
1,689
—
(511)
1,178
882
(2,821)
7,444
7,444
—
7,444
(3,475)
(6)
(186)
417
4
(3,246)
628
(37)
(207)
384
(2,862)
—
7,359
7,205
154
7,359
—
—
—
—
—
—
—
—
—
—
—
2,821
(8,121)
(8,121)
—
(8,121)
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)
$ million
2018
BP group
9,578
(3,771)
(6)
(186)
417
4
(3,542)
2,317
(37)
(718)
1,562
(1,980)
—
7,598
7,444
154
7,598
$ 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
a Includes revised non-cash provision adjustments; actual cash payments for Production and similar taxes remain in line with prior year.
202
BP Annual Report and Form 20-F 2018
38. Condensed consolidating information on certain US subsidiaries – continued
Statement of comprehensive income continued
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
transferred to gain or loss on sale of businesses and fixed assets
Available-for-sale investments marked to market
Cash flow hedges marked to market
Cash flow hedges reclassified to the income statement
Cash flow hedges reclassified to the balance sheet
Share of items relating to equity-accounted entities, net of tax
Income tax relating to items that may be reclassified
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement
benefit liability or asset
Income tax relating to items that will not be reclassified
Other comprehensive income
Equity-accounted other comprehensive income of subsidiaries
Total comprehensive income
Attributable to
BP shareholders
Non-controlling interests
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
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
830
BP p.l.c.
3,398
Other
subsidiaries
Eliminations and
reclassifications
3,685
(4,445)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
830
830
—
830
166
—
—
—
—
—
—
—
166
2,984
(1,169)
1,815
1,981
2,983
8,362
8,362
—
8,362
1,820
(120)
14
197
116
112
564
(196)
2,507
662
(134)
528
3,035
—
6,720
6,589
131
6,720
—
—
—
—
—
—
—
—
—
—
—
—
—
(2,983)
(7,428)
(7,428)
—
(7,428)
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
2,740
—
—
—
94
—
2,834
888
1,171
102
673
(147)
—
—
147
103
—
44
(41)
85
85
—
85
BP p.l.c.
—
—
—
862
343
—
1,205
—
—
—
—
—
—
808
397
311
(82)
168
53
115
115
—
115
Other
subsidiaries
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
Eliminations and
reclassifications
(2,731)
—
—
(862)
(830)
—
(4,423)
(2,731)
—
—
—
—
—
(110)
(1,582)
(720)
272
(1,645)
(2,479)
834
777
57
834
—
(862)
—
(862)
(862)
—
(862)
BP Annual Report and Form 20-F 2018
$ million
2017
BP group
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
$ 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
203
38. Condensed consolidating information on certain US subsidiaries – continued
Statement of comprehensive income continued
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
transferred to gain or loss on sale of businesses and fixed assets
Available-for-sale investments marked to market
Cash flow hedges marked to market
Cash flow hedges reclassified to the income statement
Cash flow hedges reclassified to the balance sheet
Share of items relating to equity-accounted entities, net of tax
Income tax relating to items that may be reclassified
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement
benefit liability or asset
Income tax relating to items that will not be reclassified
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
Other
subsidiaries
Eliminations and
reclassifications
834
(862)
(236)
—
—
—
—
—
—
—
(236)
(2,019)
750
(1,269)
(1,505)
544
(846)
(846)
—
(846)
490
30
1
(639)
196
81
833
13
1,005
(477)
(11)
(488)
517
—
1,351
1,321
30
1,351
—
—
—
—
—
—
—
—
—
—
—
—
—
(544)
(1,406)
(1,406)
—
(1,406)
$ million
2016
BP group
172
254
30
1
(639)
196
81
833
13
769
(2,496)
739
(1,757)
(988)
—
(816)
(846)
30
(816)
204
BP Annual Report and Form 20-F 2018
38. Condensed consolidating information on certain US subsidiaries – continued
Balance sheet
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
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
BP p.l.c.
Other
subsidiaries
Eliminations and
reclassifications
4,445
—
598
—
—
—
—
5,043
—
—
—
—
—
—
5,043
—
302
2,536
—
7
—
—
—
2,845
7,888
413
—
89
—
310
1
813
—
—
—
—
586
670
—
1,256
2,069
5,819
5,819
—
5,819
—
—
—
—
2
—
166,311
166,313
—
2,600
—
—
—
5,473
174,386
—
—
151
—
—
—
—
13
164
174,550
14,634
—
31
—
—
—
14,665
31,800
—
—
—
1,907
—
184
33,891
48,556
125,994
125,994
—
125,994
130,816
12,204
16,686
8,647
17,671
1,341
—
187,365
32,402
1,834
5,145
1,179
3,706
482
232,113
326
17,686
38,931
3,846
956
1,019
222
22,455
85,441
317,554
48,358
3,308
4,506
9,373
1,791
2,563
69,899
16,395
5,625
575
56,426
7,319
17,062
8,207
111,609
181,508
136,046
133,942
2,104
136,046
—
—
—
—
—
—
(166,311)
(166,311)
(31,765)
(2,600)
—
—
—
—
(200,676)
—
—
(17,140)
—
—
—
—
—
(17,140)
(217,816)
(17,140)
—
—
—
—
—
(17,140)
(34,365)
—
—
—
—
—
—
(34,365)
(51,505)
(166,311)
(166,311)
—
(166,311)
$ million
2018
BP group
135,261
12,204
17,284
8,647
17,673
1,341
—
192,410
637
1,834
5,145
1,179
3,706
5,955
210,866
326
17,988
24,478
3,846
963
1,019
222
22,468
71,310
282,176
46,265
3,308
4,626
9,373
2,101
2,564
68,237
13,830
5,625
575
56,426
9,812
17,732
8,391
112,391
180,628
101,548
99,444
2,104
101,548
BP Annual Report and Form 20-F 2018
205
38. 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 receivables
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 payable
Provisions
Non-current liabilities
Other payablesa
Derivative financial instruments
Accruals
Finance debt
Deferred tax liabilities
Provisions
Defined benefit pension plan and other post-retirement benefit
plan deficits
Total liabilities
Net assets
Equity
BP shareholders’ equity
Non-controlling interests
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
BP p.l.c.
Other
subsidiaries
Eliminations and
reclassifications
BP group
$ million
2017
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
—
—
—
—
2
—
161,840
161,842
—
2,623
—
—
—
3,838
168,303
—
—
293
—
—
—
—
10
303
168,606
10,143
—
60
—
—
—
10,203
31,804
—
—
—
1,337
—
221
33,362
43,565
125,041
125,041
—
125,041
122,498
11,551
17,770
7,994
16,989
1,245
—
178,047
32,401
1,434
4,110
1,112
4,469
331
221,904
190
18,737
34,991
3,032
1,412
761
125
25,576
84,824
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)
(31,756)
(2,623)
—
—
—
—
(196,219)
—
—
(12,641)
—
—
—
—
—
(12,641)
(208,860)
(12,641)
—
—
—
—
—
(12,641)
(34,379)
—
—
—
—
—
—
(34,379)
(47,020)
(161,840)
(161,840)
—
(161,840)
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
a For BP plc, an amount of $2,300 million has been reclassified from non-current other payables to current trade and other payables, with consequential amendments to the eliminations and
reclassifications column.
206
BP Annual Report and Form 20-F 2018
38. Condensed consolidating information on certain US subsidiaries – continued
Cash flow statement
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
Equity accounted income of subsidiaries - after interest and tax
Dividends received from subsidiaries
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 (used in) 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 provided by (used in) investing activities
Financing activities
Repurchase of shares
Proceeds from long-term financing
Repayments of long-term financing
Net increase (decrease) in short-term debt
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
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
BP p.l.c.
Other
subsidiaries
Eliminations
and
reclassifications
$ million
2018
BP group
1,080
9,442
17,143
(10,942)
16,723
—
377
66
—
—
—
—
(42)
42
8
(8)
—
—
—
33
(62)
(72)
(491)
(133)
798
(273)
—
—
—
(273)
—
1,475
—
1,202
—
—
—
—
(2,000)
—
(2,000)
—
—
—
—
—
—
—
—
—
(10,942)
3,490
(215)
215
1,326
(1,326)
(95)
671
(183)
—
—
165
4,509
—
7,057
—
—
—
—
—
—
—
—
—
(355)
—
—
—
(6,699)
—
(7,054)
—
3
10
13
1,085
15,080
338
(3,753)
1,535
—
—
(1,776)
1,656
2,759
(2,159)
222
19
(203)
953
734
(951)
(6,595)
(5,579)
20,508
(16,434)
(6,986)
(382)
(1,013)
(24,815)
940
436
666
(22,773)
—
9,038
(7,210)
1,317
(3,490)
(170)
(515)
(330)
(3,110)
25,565
22,455
—
—
—
—
—
10,942
(3,490)
1,565
(1,565)
(1,565)
1,565
—
—
—
—
—
(2,000)
—
—
(5,490)
—
—
—
—
—
—
—
—
—
—
—
—
—
5,490
—
5,490
—
—
—
—
1,085
15,457
404
(3,753)
1,535
—
—
(468)
348
2,528
(1,928)
127
690
(386)
986
672
(2,858)
(2,577)
(5,712)
22,873
(16,707)
(6,986)
(382)
(1,013)
(25,088)
940
1,911
666
(21,571)
(355)
9,038
(7,210)
1,317
(6,699)
(170)
(4,079)
(330)
(3,107)
25,575
22,468
BP Annual Report and Form 20-F 2018
207
38. Condensed consolidating information on certain US subsidiaries – continued
Cash flow statement continued
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
Equity accounted income of subsidiaries - after interest and tax
Dividends received from subsidiaries
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 provided by (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
$ million
2017
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
BP p.l.c.
Other
subsidiaries
Eliminations and
reclassifications
BP group
438
3,387
7,800
(4,445)
7,180
—
735
(71)
—
—
—
—
(11)
11
6
(6)
—
—
—
(128)
(25)
108
(830)
—
227
(321)
—
—
—
(321)
94
—
—
(227)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(9)
—
—
(4,436)
3,183
(220)
220
826
(826)
(15)
595
(145)
—
—
522
3,374
—
6,456
—
—
—
—
—
—
—
—
—
(343)
—
—
—
—
(6,153)
—
(6,496)
—
(40)
50
10
1,603
14,849
77
(2,507)
1,253
—
—
(1,117)
1,188
2,286
(1,784)
235
66
(249)
2,234
(823)
(5,478)
(200)
(4,002)
15,431
(16,241)
(327)
(50)
(901)
(17,519)
2,842
478
349
(13,850)
—
8,712
(6,276)
(158)
1,063
(3,183)
(141)
17
544
2,142
23,434
25,576
—
—
9
—
—
4,436
(3,183)
1,044
(1,044)
(1,044)
1,044
—
—
—
—
—
—
—
—
(3,183)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
3,183
—
3,183
—
—
—
—
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
208
BP Annual Report and Form 20-F 2018
38. Condensed consolidating information on certain US subsidiaries – continued
Cash flow statement continued
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
Equity accounted income of subsidiaries - after interest and tax
Dividends received from (paid to) subsidiaries
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 provided by (used in) investing activities
Financing activities
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
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
BP p.l.c.
Other
subsidiaries
Eliminations and
reclassifications
BP group
$ million
2016
44
168
(1,645)
(862)
(2,295)
—
673
(148)
—
—
—
(7,000)
(94)
94
103
(103)
—
—
—
77
(3)
6,985
(33)
104
699
(699)
—
—
—
(699)
—
—
—
(699)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(862)
372
(233)
233
311
(311)
(82)
780
(192)
—
—
(156)
4,634
(1)
4,661
—
—
—
—
—
—
—
—
—
—
—
—
—
(4,611)
—
(4,611)
—
50
—
50
1,274
13,832
(2,648)
(1,960)
1,105
—
—
(593)
660
1,981
(1,443)
272
(1)
(275)
4,410
(3,678)
(1,001)
(2,946)
(1,641)
5,703
(16,002)
(1)
(50)
(700)
(16,753)
1,372
1,259
68
(14,054)
12,442
(6,685)
51
887
(372)
(107)
6,216
(820)
(2,955)
26,389
23,434
—
—
—
—
—
862
6,628
720
(720)
(720)
720
—
—
—
—
—
(7,000)
—
—
(372)
—
—
—
—
—
—
—
—
—
—
—
—
—
372
—
372
—
—
—
—
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
BP Annual Report and Form 20-F 2018
209
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 285-290.
210
BP Annual Report and Form 20-F 2018
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
2018
29,730
451
30,181
16,809
13,372
— 89,069
— 3,602
— 92,671
— 47,051
— 45,620
3,385
2,667
6,052
420
5,632
14,269
2,742
17,011
8,517
8,494
51,980
3,870
55,850
38,324
17,526
— 38,315
— 3,153
— 41,468
— 20,173
— 21,295
568
6,119 232,867
17,053
6,687 249,920
3,626 134,920
3,061 115,000
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
1,933
—
1,933
238
817
2,988
Results of operations for the year ended 31 Decembera
Sales and other operating revenuesd
619
2,255
2,874
105
646
(269)
(331)
1,199
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
— 10,650
—
35
— 10,685
—
216
— 3,429
— 14,330
— 1,306
— 11,656
— 12,962
—
509
— 2,729
—
369
(2)
2,379
— 3,921
(226)
—
203
1,124
1,750
446
1,304
(2) 10,110
2,852
2
—
454
2,398
2
420
(314)
(95)
(219)
—
—
—
139
46
185
105
1
106
146
120
—
43
101
10
—
100
100
245
591
936
(1)
50
49
283
2,340
2,672
36
—
(5)
—
31
—
5
148
— 2,458
2,637
5
— 12,618
—
180
— 12,798
1,298
24
9,917
236
24,013
260
2,074
195
2,269
252
430
357
165
1,023
3,228
3,928
7,156
405
1,066
—
133
3,635
—
(141)
2,227
42
314
(272)
5,098
2,058
1,184
874
— 1,430
— 7,793
— 9,223
20
5
951
—
— 1,010
42
94
— 2,165
—
47
(47)
13
(60)
21
4,261
4,962
3,509
1,453
1,410
665
2,075
3
138
69
223
298
136
867
1,208
508
700
10,172
26,493
36,665
1,445
6,080
1,536
2,746
12,342
3
24,152
12,513
6,333
6,180
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
1,750
2
2,852
(314)
42
2,058
(47)
4,962
1,208
12,513
(20)
(2)
265
130
188
28
(111)
—
135
209
(58)
5
207
2,346
463
245
6
—
873
3,163
1,728
397
3,068
(425)
386
2,207
2,304
5,670
1,214
16,549
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 and the Baku-Tbilisi-Ceyhan pipeline. Major
LNG activities are located in Trinidad, Indonesia, Australia and Angola.
b Costs of decommissioning 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 $17 million. The UK region includes a $384-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 $208 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.
BP Annual Report and Form 20-F 2018
211
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
2018
Equity-accounted entities (BP share)
Capitalized costs at 31 Decemberb c
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
— 3,439
—
657
— 4,096
670
—
— 3,426
Costs incurred for the year ended 31 Decemberb d e
Acquisition of propertiesc
Proved
Unproved
Exploration and appraisal costsd
Development
Total costs
—
—
—
—
—
—
—
137
137
67
251
455
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
— 1,114
—
—
— 1,114
89
—
207
—
—
—
21
—
290
—
—
—
—
—
—
6
613
501
350
151
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— 9,643
—
86
— 9,729
— 4,665
— 5,064
— 24,052
—
828
— 24,880
— 6,749
— 18,131
3,646
26
3,672
3,672
—
—
—
—
—
—
—
—
—
—
25
575
600
— 1,792
—
—
— 1,792
7
—
438
—
361
—
127
—
416
—
425
—
148
—
573
—
—
207
— 3,255
— 4,035
—
—
— 15,901
— 15,901
—
112
— 1,487
— 7,634
—
638
— 1,627
—
—
—
47
— 1,349
443
—
279
—
164
—
— 11,545
— 4,356
—
849
— 3,507
—
—
—
—
212
212
353
—
353
—
39
94
—
212
1
346
7
—
7
— 40,780
— 1,597
— 42,377
— 15,756
— 26,621
425
—
285
—
710
—
—
299
— 4,293
— 5,302
— 3,259
— 15,901
— 19,160
—
208
— 2,171
— 8,089
—
786
— 2,545
—
54
— 13,853
— 5,307
— 1,478
— 3,829
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
—
(2)
(2)
151
(21)
130
—
28
28
—
—
—
164
45
209
— 3,507
207
(1,161)
207
2,346
7
238
245
— 3,829
—
(666)
— 3,163
a Amounts reported for Russia in this table include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. The amounts reported include the
corresponding amounts for their equity-accounted entities.
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.
c Costs of decommissioning 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.
h Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.
212
BP Annual Report and Form 20-F 2018
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
Russia
Rest of
Asia
$ million
2017
Total
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
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
204
1,745
1,949
331
629
(37)
(272)
1,190
133
1,974
(25)
(104)
79
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
(12)
87
8,590
(10)
10
1,251
— (1,811)
3,062
10
(1)
284
(111)
(28)
(83)
—
330
330
264
911
1,505
1,134
327
1,461
83
573
86
71
742
(31)
1,524
(63)
155
(218)
564
374
938
682
2,972
4,592
2,211
4,022
6,233
1,346
979
—
280
3,586
—
6,191
42
788
(746)
— 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
— 1,276
— 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 Costs of decommissioning 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.
BP Annual Report and Form 20-F 2018
213
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
Russiaa
Rest of
Asia
$ million
2017
Total
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
653
—
—
416
— 1,069
—
194
— 3,361
— 4,624
— 1,750
—
—
— 1,750
—
—
592
—
336
—
11
—
458
—
—
—
— 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. The amounts reported include the
corresponding amounts for their equity-accounted entities.
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.
c Costs of decommissioning 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.
214
BP Annual Report and Form 20-F 2018
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 Costs of decommissioning 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.
BP Annual Report and Form 20-F 2018
215
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. The amounts reported include the
corresponding amounts for their equity-accounted entities. 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.
c Costs of decommissioning 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.
216
BP Annual Report and Form 20-F 2018
Movements in estimated net proved reserves
Crude oila b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place
At 31 Decembere
Developed
Undeveloped
Equity-accounted entities (BP share)f
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberg
Developed
Undeveloped
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
USc
245
164
409
22
—
93
15
(37)
(37)
57
223
243
466
—
—
—
—
—
—
—
—
—
—
—
—
—
245
164
409
932
—
—
492
— 1,423
—
—
—
—
—
—
—
116
51
412
17
(137)
(118)
341
—
962
802
—
— 1,764
56
89
145
11
13
—
—
(13)
—
12
57
100
157
56
89
145
—
—
—
—
—
—
—
—
—
—
—
—
—
932
492
1,423
962
802
1,764
54
195
248
(6)
—
—
—
(9)
—
(15)
43
190
234
—
—
—
—
—
—
19
—
—
19
—
19
19
54
195
249
43
209
253
10
6
16
1
—
—
—
(3)
—
(2)
8
5
14
285
263
548
7
—
—
21
(25)
—
4
293
259
552
295
269
564
302
264
566
Africa
Asia
Australasia
Total
million barrels
2018
Russia
Rest of
Asia
— 1,040
—
642
— 1,682
—
—
—
—
—
—
—
40
—
—
—
(114)
—
(74)
— 1,126
482
—
— 1,608
281
28
309
11
1
—
13
(75)
—
(50)
223
36
259
3,124
1
— 2,251
5,374
1
—
—
—
—
—
—
(1)
150
—
89
326
(335)
—
229
1
3,190
— 2,414
5,604
1
6
—
6
—
—
—
—
(6)
—
(6)
—
—
—
282
28
310
224
36
260
3,124
2,251
5,374
3,190
2,414
5,604
1,047
642
1,688
1,126
482
1,608
31
11
42
(2)
—
—
—
(6)
—
(8)
30
5
34
2,592
1,537
4,129
183
52
504
46
(381)
(155)
249
2,615
1,763
4,378
— 3,473
— 2,603
— 6,076
—
—
—
—
—
—
—
168
13
89
366
(379)
—
257
— 3,541
— 2,792
— 6,333
31
11
42
30
5
34
6,064
4,140
10,205
6,156
4,555
10,711
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
At 31 December
Developed
Undeveloped
223
243
466
57
100
157
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 16 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 4 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 344 million barrels of crude oil in respect of the 6.28% non-controlling interest in Rosneft, including 24 mmbbl held through BP's interests in Russia other than Rosneft.
g Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,539 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 58 million barrels in
Venezuela and 5,481 million barrels in Russia.
BP Annual Report and Form 20-F 2018
217
Movements in estimated net proved reserves - continued
Europe
North
America
South
America
Africa
Asia
Australasia
Total
million barrels
2018
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
11
3
14
1
—
—
3
(2)
(3)
—
8
6
14
—
—
—
—
—
—
—
—
—
—
—
—
—
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
11
3
14
At 31 December
Developed
Undeveloped
8
6
14
—
—
—
—
—
—
—
—
—
—
—
—
—
4
4
8
—
—
—
—
(1)
—
(1)
4
3
7
4
4
8
4
3
7
177
69
246
20
16
253
1
(25)
—
265
266
246
511
—
—
—
—
—
—
—
—
—
—
—
—
—
177
69
246
266
246
511
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2
28
30
—
—
—
—
(3)
—
(3)
2
25
27
—
—
—
—
—
—
—
—
—
—
—
—
—
2
28
30
2
25
27
21
—
21
(3)
2
—
3
(3)
—
(2)
14
4
18
10
—
10
(1)
—
—
—
(1)
—
(3)
7
—
7
31
—
31
22
4
26
—
—
—
—
—
—
—
—
—
—
—
—
—
82
49
131
25
—
—
—
(2)
—
23
103
51
154
82
49
131
103
51
154
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
5
1
6
—
—
—
—
(1)
—
(1)
5
—
5
—
—
—
—
—
—
—
—
—
—
—
—
—
5
1
6
5
—
5
216
102
318
17
18
253
7
(34)
(3)
258
295
280
576
97
53
149
23
—
—
—
(4)
—
19
114
54
169
313
154
467
409
335
744
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 8 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 Includes 12 million barrels of NGLs in respect of the 7.82% non-controlling interest in Rosneft.
f Total proved NGL reserves held as part of our equity interest in Rosneft is 154 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 154 million barrels
in Russia.
218
BP Annual Report and Form 20-F 2018
Movements in estimated net proved reserves - continued
Total liquidsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place
At 31 Decembere
Developed
Undeveloped
Equity-accounted entities (BP share)f
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberg h
Developed
Undeveloped
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
USc
256
167
424
23
—
93
18
(39)
(40)
56
231
249
480
—
—
—
—
—
—
—
—
—
—
—
—
—
256
167
424
— 1,108
—
561
— 1,669
—
—
—
—
—
—
—
136
67
665
18
(162)
(118)
606
— 1,228
— 1,048
— 2,276
60
93
153
11
13
—
—
(13)
—
11
60
104
164
60
93
153
—
—
—
—
—
—
—
—
—
—
—
—
—
1,108
561
1,669
1,228
1,048
2,276
54
195
248
(6)
—
—
—
(9)
—
(15)
43
190
234
—
—
—
—
—
—
19
—
—
19
—
19
19
54
195
249
44
209
253
12
34
46
1
—
—
—
(6)
—
(5)
10
30
41
285
263
548
7
—
—
21
(25)
—
4
293
259
552
297
297
594
303
289
593
million barrels
2018
Africa
Asia
Australasia
Total
Russia
Rest of
Asia
— 1,040
—
642
— 1,682
—
—
—
—
—
—
—
40
—
—
—
(114)
—
(74)
— 1,126
482
—
— 1,608
301
28
329
8
3
—
16
(79)
—
(52)
237
40
277
3,206
11
— 2,300
5,505
12
(2)
—
—
—
(2)
—
(3)
175
—
89
326
(337)
—
253
8
3,293
— 2,465
5,758
8
6
—
6
—
—
—
—
(6)
—
(6)
—
—
—
313
28
341
245
40
285
3,206
2,300
5,505
3,293
2,465
5,758
1,047
642
1,688
1,126
482
1,608
36
12
48
(2)
—
—
—
(7)
—
(9)
35
5
39
2,808
1,639
4,447
200
70
758
52
(415)
(158)
507
2,910
2,044
4,954
— 3,569
— 2,656
— 6,225
—
—
—
—
—
—
—
191
13
89
366
(383)
—
277
— 3,655
— 2,846
— 6,502
36
12
48
35
5
39
6,377
4,295
10,672
6,565
4,890
11,456
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
At 31 December
Developed
Undeveloped
231
249
480
60
104
164
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 16 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 3 thousand barrels per day for equity-accounted entities.
e Also includes 12 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 356 million barrels in respect of the non-controlling interest in Rosneft, including 24 mmboe held through BP’s interests in Russia other than Rosneft.
h Total proved liquid reserves held as part of our equity interest in Rosneft is 5,693 million barrels, comprising less than 1 million barrels in Canada, 58 million barrels in Venezuela, less than
1 million barrels in Vietnam and 5,635 million barrels in Russia.
BP Annual Report and Form 20-F 2018
219
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
2018
Russia
Rest of
Asia
523
320
843
84
—
40
60
(66)
(178)
(61)
439
343
782
—
—
—
—
—
—
—
—
—
—
—
—
—
523
320
843
— 5,238
— 3,086
— 8,323
10
—
— 1,315
— 2,655
11
—
(751)
—
—
(237)
— 3,003
— 6,270
— 5,056
— 11,326
(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
3
—
—
—
(3)
—
1
(195)
—
—
31
(788)
—
(951)
(444)
—
—
578
(423)
—
(290)
—
—
—
—
—
—
—
140
—
—
—
(324)
—
(184)
(123)
(524)
— 1,315
— 2,695
680
—
(2,658)
(303)
(416)
—
1,092
(426)
— 2,168
— 3,073
— 5,241
1,313
1,067
2,380
— 3,599
— 3,218
— 6,817
2,630
1,179
3,809
16,420
13,936
30,355
112
69
180
2
—
—
—
(22)
—
(19)
107
55
161
112
69
180
—
—
—
—
—
—
—
—
—
—
—
—
—
5,238
3,086
8,323
— 1,274
—
450
— 1,724
476
146
622
6,077
7,173
13,250
—
—
—
4
—
—
3
(50)
1
—
122
(145)
—
(71)
(39)
805
—
—
— 2,413
512
—
(464)
(48)
—
—
3,267
(87)
— 1,207
4
446
1,653
4
391
143
534
7,798
8,719
16,517
17
3
20
2
—
—
—
(6)
—
(5)
12
4
15
— 7,955
— 7,841
— 15,796
—
719
1
—
— 2,413
638
—
(685)
—
—
—
— 3,087
— 9,515
— 9,369
— 18,884
— 4,136
— 3,781
— 7,917
— 3,375
3,519
4
6,894
4
1,635
1,656
3,291
1,704
1,210
2,914
6,077
7,173
13,250
7,798
8,719
16,517
2,771
4,249
7,020
3,610
3,221
6,832
2,730
1,505
4,235
2,630
1,179
3,809
23,221
21,838
45,060
25,934
23,305
49,239
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
At 31 December
Developed
Undeveloped
439
343
782
107
55
161
6,270
5,056
11,326
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to
make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 181 billion cubic feet of natural gas consumed in operations, 139 billion cubic feet in subsidiaries, 42 billion cubic feet in equity-accounted entities.
d Includes 1,573 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 1,211 billion cubic feet of natural gas in respect of the 8.60% non-controlling interest in Rosneft including 480 billion cubic feet held through BP’s interests in Russia other than
Rosneft.
g Total proved gas reserves held as part of our equity interest in Rosneft is 14,325 billion cubic feet, comprising 0 billion cubic feet in Canada, 26 billion cubic feet in Venezuela, 15 billion cubic
feet in Vietnam, 200 billion cubic feet in Egypt and 14,084 billion cubic feet in Russia.
220
BP Annual Report and Form 20-F 2018
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
2018
Africa
Asia
Australasia
Total
Russia
Rest of
Asia
347
222
569
38
—
100
29
(50)
(70)
46
307
308
615
—
—
—
—
—
—
—
—
—
—
—
—
—
347
222
569
— 2,011
— 1,093
— 3,104
138
—
—
294
— 1,123
—
20
(292)
—
—
(159)
— 1,124
— 2,309
— 1,919
— 4,228
80
105
184
11
13
—
—
(17)
—
8
79
113
192
80
105
184
—
—
—
—
—
—
—
—
—
—
—
—
—
2,011
1,093
3,104
2,309
1,919
4,228
54
195
248
(5)
—
—
—
(9)
—
(15)
43
190
234
—
—
—
—
—
—
20
—
—
19
—
20
20
54
195
249
44
210
253
505
608
1,114
(33)
—
—
5
(142)
—
(169)
384
560
944
505
341
846
(1)
—
—
42
(50)
—
(9)
501
336
837
1,010
949
1,959
885
896
1,781
501
288
790
(69)
3
—
116
(152)
—
(102)
464
224
687
93
25
119
(8)
—
—
—
(10)
—
(18)
76
25
101
595
314
908
539
249
788
— 1,515
— 1,374
— 2,889
507
272
779
5,440
4,052
9,492
—
—
—
—
—
—
—
64
—
—
—
(170)
—
(106)
110
(23)
—
297
— 1,222
169
—
(874)
(59)
(229)
—
696
(82)
— 1,746
— 1,037
— 2,783
488
208
696
5,741
4,447
10,188
4,254
3,536
7,790
313
—
505
414
(417)
—
816
4,638
3,968
8,605
4,254
3,536
7,790
4,638
3,968
8,605
9
1
10
—
—
—
—
(7)
—
(7)
2
1
3
1,524
1,374
2,899
1,749
1,037
2,786
— 4,941
— 4,008
— 8,949
—
—
—
—
—
—
—
315
14
505
476
(501)
—
809
— 5,296
— 4,462
— 9,757
507
272
779
488
208
696
10,381
8,060
18,441
11,037
8,908
19,945
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
At 31 December
Developed
Undeveloped
307
308
615
79
113
192
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 16 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 3 thousand barrels per day for equity-accounted entities.
f Includes 31 million barrels of oil equivalent of natural gas consumed in operations, 24 million barrels of oil equivalent in subsidiaries, 7 million barrels of oil equivalent in equity-accounted
entities.
g Includes 283 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 565 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 107 mmboe held through BP’s interests in Russia other than Rosneft.
j Total proved reserves held as part of our equity interest in Rosneft is 8,163 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Canada, 62 million barrels
of oil equivalent in Venezuela, 3 million barrels of oil equivalent in Vietnam, 35 million barrels of oil equivalent in Egypt and 8,063 million barrels of oil equivalent in Russia.
BP Annual Report and Form 20-F 2018
221
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
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
Europe
North
America
South
America
Africa
Asia
Australasia
UK
Rest of
Europe
USc
Rest of
North
America
Russia
Rest of
Asia
million barrels
2017
Total
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
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
317
42
358
35
2
1
—
(88)
—
(50)
281
28
309
— 1,107
—
245
— 1,352
—
—
—
—
—
—
—
407
—
—
42
(119)
—
330
— 1,040
642
—
— 1,682
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
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 6 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.
222
BP Annual Report and Form 20-F 2018
Movements in estimated net proved reserves – continued
Natural gas liquidsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionc
Sales of reserves-in-place
At 31 Decemberd
Developed
Undeveloped
Equity-accounted entities (BP share)e
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberf
Developed
Undeveloped
Europe
North
America
South
America
Africa
Asia
Australasia
million barrels
2017
Total
UK
13
3
16
2
—
—
—
(3)
(1)
(2)
11
3
14
—
—
—
—
—
—
—
—
—
—
—
—
—
Rest of
Europe
—
—
—
—
—
—
—
—
—
—
—
—
—
3
2
5
—
1
2
—
(1)
—
3
4
4
8
3
2
5
4
4
8
Rest of
North
America
Russia
Rest of
Asia
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
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
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
US
226
73
299
(44)
15
—
1
(24)
—
(52)
177
69
246
—
—
—
—
—
—
—
—
—
—
—
—
—
226
73
299
177
69
246
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
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
13
3
16
At 31 December
Developed
Undeveloped
11
3
14
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 2018
223
Movements in estimated net proved reserves – continued
Total liquidsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place
At 31 Decembere
Developed
Undeveloped
Equity-accounted entities (BP share)f
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberg h
Developed
Undeveloped
Europe
North
America
South
America
Africa
Asia
Australasia
UK
Rest of
Europe
USc
Rest of
North
America
Russia
Rest of
Asia
million barrels
2017
Total
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
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
330
43
372
45
2
1
—
(92)
—
(43)
301
28
329
— 1,107
—
245
— 1,352
—
—
—
—
—
—
—
407
—
—
42
(119)
—
330
— 1,040
642
—
— 1,682
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
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 6 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 5,533 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.
224
BP Annual Report and Form 20-F 2018
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
2017
Total
billion cubic feet
Russia
Rest of
Asia
499
350
848
50
—
25
—
(77)
(4)
(5)
523
320
843
—
—
—
—
—
—
—
—
—
—
—
—
—
499
350
848
— 5,447
— 2,567
— 8,014
(38)
—
— 1,002
—
—
—
10
(664)
—
—
—
309
—
— 5,238
— 3,086
— 8,323
— 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
89
21
110
19
37
39
1
(19)
(6)
70
112
69
180
89
21
110
—
—
—
—
—
—
—
—
—
—
—
—
—
5,447
2,567
8,014
5,238
3,086
8,323
— 1,546
534
—
2,080
1
—
—
—
—
—
—
—
47
55
—
67
(178)
(347)
(356)
— 1,274
—
450
— 1,724
— 3,330
— 5,505
— 8,835
— 4,136
— 3,781
— 7,917
412
5,544
— 6,304
11,847
412
5
—
237
—
(32)
—
210
476
146
622
1,179
2,191
3,370
1,635
1,656
3,291
1,556
—
10
324
(488)
—
1,403
6,077
7,173
13,250
5,544
6,304
11,847
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
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
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
At 31 December
Developed
Undeveloped
523
320
843
112
69
180
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 2 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 2018
225
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 equivalent c
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 7 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.
226
BP Annual Report and Form 20-F 2018
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 6 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 2018
227
Movements in estimated net proved reserves – continued
Europe
North
America
South
America
Africa
Asia
Australasia
million barrels
2016
Total
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
5
4
10
7
—
1
—
(2)
—
7
13
3
16
—
—
—
—
—
—
—
—
—
—
—
—
—
5
4
10
11
1
12
—
—
—
—
(1)
(10)
(12)
—
—
—
—
—
—
—
—
5
—
—
—
5
3
2
5
11
1
12
269
70
339
(24)
3
4
—
(24)
—
(40)
226
73
299
—
—
—
—
—
—
—
—
—
—
—
—
—
269
70
339
226
73
299
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
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
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
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
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.
228
BP Annual Report and Form 20-F 2018
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
UK
Rest of
Europe
USc
Rest of
North
America
Russia
Rest of
Asia
million barrels
2016
Total
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 6 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 2018
229
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 1 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.
230
BP Annual Report and Form 20-F 2018
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 6 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 2018
231
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
2018
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 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
39,700
15,000
2,100
8,900
13,700
5,000
— 160,000
— 57,600
— 17,800
— 16,600
— 68,000
— 29,900
4,100
3,400
1,100
17,500
7,200
2,800
— 3,200
4,300
700
(400)
(200)
30,400
8,500
2,600
5,300
14,000
3,300
— 147,500
— 55,800
— 16,400
— 51,100
— 24,200
9,400
—
30,000 429,200
7,600 155,100
45,300
2,500
92,000
6,900
13,000 136,800
53,900
5,800
8,700
— 38,100
(200)
3,600
10,700
— 14,800
7,200
82,900
— 12,800
— 4,200
—
800
— 5,900
— 1,900
600
—
— 1,300
—
—
—
—
—
—
—
— 38,500
— 16,100
— 3,600
— 4,400
— 14,400
— 8,500
— 356,800
— 232,100
— 19,300
— 24,000
— 81,400
— 48,100
— 5,900
— 33,300
—
—
—
—
—
—
—
— 408,100
— 252,400
— 23,700
— 34,300
— 97,700
— 57,200
— 40,500
Total subsidiaries and equity-accounted entities
Standardized measure of discounted
future net cash flows
8,700
1,300
38,100
(200)
9,500
10,700
33,300
14,800
7,200 123,400
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
Sales and transfers of oil and gas produced, net of production costs
Development costs for the current year as estimated in previous year
Extensions, discoveries and improved recovery, less related costs
Net changes in prices and production cost
Revisions of previous reserves estimates
Net change in taxation
Future development costs
Net change in purchase and sales of reserves-in-place
Addition of 10% annual discount
Total change in the standardized measure during the yearj
Subsidiaries
Equity-accounted
entities (BP share)
(18,800)
8,500
5,800
41,000
(2,100)
(17,000)
1,000
7,600
5,200
31,200
(8,000)
4,300
3,500
15,800
2,100
(7,600)
(3,500)
400
3,100
10,100
$ million
Total subsidiaries and
equity-accounted
entities
(26,800)
12,800
9,300
56,800
—
(24,600)
(2,500)
8,000
8,300
41,300
a The marker prices used were Brent $71.43/bbl, Henry Hub $3.10/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.
f Non-controlling interests in BP Trinidad and Tobago LLC amounted to $1,100 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 $2,500 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.
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’.
232
BP Annual Report and Form 20-F 2018
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
2017
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
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 yeari
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 2018
233
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’.
234
BP Annual Report and Form 20-F 2018
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 2018, 2017 and 2016.
Production for the yeara b
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
Subsidiariese
Crude oilf
2018
2017
2016
Natural gas liquids
2018
2017
2016
Natural gasg
2018
2017
2016
Equity-accounted entities (BP share)
Crude oilf
2018
2017
2016
Natural gas liquids
2018
2017
2016
Natural gasg
2018
2017
2016
101
80
79
5
6
6
152
182
170
—
—
—
—
—
—
—
—
—
—
—
24
—
—
4
—
—
82
34
31
7
2
2
—
59
53
12
US
385
370
335
60
56
56
1,900
1,659
1,656
—
—
—
—
—
—
—
—
—
Rest of
North
America
Russiac
Rest of
Asiad
24
20
13
—
—
—
7
9
10
—
—
—
—
—
—
—
—
—
7
12
10
9
10
8
204
241
263
11
10
5
2,136
1,936
1,689
1,061
949
513
55
63
65
—
—
1
335
418
449
1
1
—
6
6
4
80
77
18
—
—
—
—
—
—
—
—
—
933
905
840
4
4
4
1,286
1,308
1,279
thousand barrels per day
17
17
16
1,051
1,064
943
thousand barrels per day
2
2
3
88
85
82
million cubic feet per day
819
783
820
6,900
5,889
5,302
thousand barrels per day
—
—
—
1,040
1,099
1,015
thousand barrels per day
—
—
—
12
12
8
million cubic feet per day
—
—
—
1,760
1,855
1,773
313
325
204
—
—
—
826
371
363
16
99
102
—
—
—
—
—
15
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.
BP Annual Report and Form 20-F 2018
235
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 2018. 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 2018
Oil wellsc
Gas wellsd
Undevelopede
– gross
– net
– gross
– net
– gross
– net
– gross
– net
Oil and natural gas acreage at 31 December 2018
Developed
Europe
UK
Rest of
Europe
South
America
North
America
US
Rest of
North
America
116
69
34
5
81
46
3,067
1,861
2,677
74
1,097
22
1
20,565
— 10,602
169
45
244
121
57
17
180
54
6,263
3,683
5,012
3,700
147
64
17,110
8,750
5,356
2,437
1,069
379
1,336
355
19,890
6,469
Africa
Asia
Australasia
Totalb
Russiaa
66,147
13,151
512
114
695
466
209
89
868
345
52,698
36,504
6,751
1,297
431,130
86,045
Rest of
Asia
1,979
445
102
45
1,290
272
8,586
2,357
77,225
12
17,734
2
22,814
78
11,371
16
thousands of acres
173
41
4,022
1,889
16,966
6,120
541,695
147,629
a Based on information received from Rosneft as at 31 December 2018.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes approximately 7,381 gross (1,447 net) multiple completion wells (more than one formation producing into the same well bore).
d Includes approximately 2,768 gross (1,407 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
2018
Exploratory
Productive
Dry
Development
Productive
Dry
2017
Exploratory
Productive
Dry
Development
Productive
Dry
2016
Exploratory
Productive
Dry
Development
Productive
Dry
UK
Rest of
Europe
0.3
—
1.4
—
2.8
2.4
2.5
—
0.3
1.0
3.4
0.8
—
—
0.6
—
0.1
—
0.5
—
0.4
0.3
1.4
—
US
1.7
—
142.7
6.8
1.5
—
124.0
0.5
0.5
4.7
145.6
—
Rest of
North
America
Russia
Rest of
Asia
—
0.5
5.0
—
1.2
—
8.0
—
—
—
—
—
2.0
2.0
103.9
3.6
3.2
—
103.7
1.6
0.6
—
99.8
0.6
—
2.4
14.4
—
2.6
2.9
16.5
2.1
2.1
1.5
20.2
2.0
15.0
—
137.3
—
9.4
—
282.7
—
3.4
—
88.5
—
5.0
—
53.5
2.6
1.4
1.0
43.6
0.8
1.6
0.3
55.2
1.0
—
—
1.3
—
—
—
1.1
—
—
—
0.5
—
24.0
4.9
460.1
13.0
22.2
6.3
582.6
5.0
8.9
7.8
414.6
4.4
a Because of rounding, some totals may not exactly agree with the sum of their component parts.
236
BP Annual Report and Form 20-F 2018
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 2018. 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 2018
Exploratory
Gross
Net
Development
Gross
Net
UK
—
—
9.0
2.9
Rest of
Europe
0.9
0.3
4.6
1.4
US
5.0
2.9
147.0
80.5
Rest of
North
America
—
—
5.0
2.5
a Because of rounding, some totals may not exactly agree with the sum of their component parts.
Russia
Rest of
Asia
3.0
0.8
11.0
5.0
3.0
1.3
18.0
9.2
—
—
—
—
3.0
3.0
108.0
19.0
—
—
—
—
14.9
8.3
302.6
120.5
BP Annual Report and Form 20-F 2018
237
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
Payablesa
Non-current liabilities
Payablesa
Deferred tax liabilities
Defined benefit pension plan deficits
Total liabilities
Net assets
Capital and reservesb
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
2018
2
3
4
3
5
5
6
4
7
$ million
2017
166,276
2,623
3,838
172,737
293
10
303
173,040
166,271
2,600
5,473
174,344
151
13
164
174,508
14,665
10,203
31,800
1,907
184
33,891
48,556
125,952
101,078
1,931
(6,579)
96,430
5,402
12,305
11,815
125,952
31,804
1,337
221
33,362
43,565
129,475
104,498
2,145
(5,565)
101,078
5,343
12,147
10,907
129,475
a A re-presentation from non-current payables to current payables has been made in 2017. See Note 5 for details.
b See Statement of changes in equity on page 239 for further information.
The financial statements on pages 238-271 were approved and signed by the group chief executive on 29 March 2019 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 238-271 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 2018
Company statement of changes in equitya
Share capital
Share
premium
account
Capital
redemption
reserve
5,343
—
—
—
49
(13)
23
5,402
5,284
—
—
—
72
(13)
—
5,343
12,147
—
—
—
(49)
—
207
12,305
12,219
—
—
—
(72)
—
—
12,147
1,426
—
—
—
—
13
—
1,439
1,413
—
—
—
—
13
—
1,426
Merger
reserve
26,509
—
—
—
—
—
—
26,509
26,509
—
—
—
—
—
—
26,509
$ million
Foreign
currency
translation
reserve
Profit and
loss account
Total equity
(70)
—
(296)
(296)
—
—
—
(366)
(236)
—
166
166
—
—
—
(70)
101,078
1,931
1,178
3,109
(6,699)
(355)
(703)
96,430
104,498
2,145
1,815
3,960
(6,153)
(343)
(884)
101,078
129,475
1,931
882
2,813
(6,699)
(355)
718
125,952
131,244
2,145
1,981
4,126
(6,153)
(343)
601
129,475
Treasury
shares
(16,958)
—
—
—
—
—
1,191
(15,767)
(18,443)
—
—
—
—
—
1,485
(16,958)
At 1 January 2018
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 2018
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
a See Note 8 for further information.
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
239
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 2018 were approved and signed by the group chief executive on
29 March 2019 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)
(g)
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.
the requirement of the second sentence of paragraph 110 and paragraphs 113(a), 114,115, 118, 119(a) to (c), 120 to 127 and 129 of IFRS 15
Revenue from Contracts with Customers
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 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.
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 238-271 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 2018
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 defined benefit pension plans are plans that share risks between entities under common control. In each instance BP p.l.c. is the principal
employer and carries the whole plan surplus or deficit on its balance sheet. 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 for the UK
plan. 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 238-271 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 2018
241
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. See note 6 for further details.
Financial assets
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 subsequent measurement of financial assets depends on
their classification, as set out below. The company derecognizes financial assets when the contractual rights to the cash flows expire or the
financial asset is transferred to a third party.
Financial assets measured at amortized cost
Financial assets are classified as measured at amortized cost when they are held in a business model the objective of which is to collect contractual
cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortized cost using
the effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the assets 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
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
financial assets measured at amortized cost.
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 directly attributable transaction costs. For interest-bearing loans and borrowings
this is typically equivalent to 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.
Impact of new International Financial Reporting Standards
The company adopted two new accounting standards issued by the IASB with effect from 1 January 2018, IFRS 9 ‘Financial instruments’ and
IFRS 15 ‘Revenue from contracts with customers’. There are no other new or amended standards or interpretations adopted during the year
that have a significant impact on the financial statements.
IFRS 9 ‘Financial Instruments’
IFRS 9 ‘Financial Instruments’ was issued in July 2014 and replaced IAS 39 ‘Financial Instruments: Recognition and Measurement.’ The
company adopted IFRS 9 and the related consequential amendments to other IFRSs in the financial reporting period commencing 1 January
2018. The company has applied the new standard in accordance with the transition provisions of IFRS 9. Comparatives have not been restated
and there were no material adjustments on transition reported in opening retained earnings at 1 January 2018.
The company’s revised accounting policies in relation to financial instruments are provided above.
IFRS 15 ‘Revenue from Contracts with Customers’
IFRS 15 ‘Revenue from Contracts with Customers’ was issued in May 2014 and replaced IAS 18 ‘Revenue’ and certain other standards and
interpretations. IFRS 15 provides a single model for accounting for revenue arising from contracts with customers, focusing on the
identification and satisfaction of performance obligations. The company adopted IFRS 15 from 1 January 2018 and applied the ‘modified
retrospective’ transition approach to implementation. The company identified no changes in accounting as a result of implementing IFRS 15.
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
2. Investments
Cost
At 1 January 2018
Additions
Disposals
At 31 December 2018
Amounts provided
At 1 January 2018
At 31 December 2018
Cost
At 1 January 2017
Disposals
Other movements
At 31 December 2017
Amounts provided
At 1 January 2017
Disposals
At 31 December 2017
At 31 December 2018
At 31 December 2017
Subsidiaries
Associates
Shares
Shares
Total
$ million
166,307
270
(275)
166,302
33
33
166,355
(41)
(7)
166,307
74
(41)
33
166,269
166,274
2
—
—
2
—
—
2
—
—
2
—
—
—
2
2
166,309
270
(275)
166,304
33
33
166,357
(41)
(7)
166,309
74
(41)
33
166,271
166,276
The more important subsidiaries of the company at 31 December 2018 and the percentage holding of ordinary share capital (to the nearest
whole number) are set out below. For a full list of related undertakings see Note 14.
Subsidiaries
International
BP Global Investments
BP International
Burmah Castrol
Canada
BP Holdings Canada
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 2018 was $76,152 million (2017 $76,152 million).
3. Receivables
Amounts receivable from subsidiariesa
Amounts receivable from associates
Other receivables
2018
$ million
2017
Current
Non-current
Current
Non-current
148
4
(1)
151
2,600
—
—
2,600
289
4
—
293
2,623
—
—
2,623
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.
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 2018 the aggregate level of contributions was $490 million (2017 $509 million). The aggregate level of contributions in 2019 is
expected to be approximately $262 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.
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
243
4. Pensions – continued
For the primary UK plan there is a funding agreement between the company and the trustee. On an annual basis the latest funding position is
reviewed and a schedule of contributions is agreed covering the next five years. Contractually committed funding amounted to $1,275 million
at 31 December 2018, all of which relates to future service. 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.
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 2018. The principal plans are subject to a formal actuarial valuation every three years in the UK. The
most recent formal actuarial valuation of the main pension plan was as at 31 December 2017.
The material financial assumptions used for estimating the benefit obligations of the plans are set out below. The assumptions are reviewed by
management at the end of each year and are used to evaluate accrued pension benefits at 31 December and pension expense for the following
year.
Financial assumptions used to determine benefit obligation
Discount rate for pension plan liabilities
Rate of increase in salaries
Rate of increase for pensions in payment
Rate of increase in deferred pensions
Inflation for pension plan liabilities
Financial assumptions used to determine benefit expense
Discount rate for pension plan service costs
Discount rate for pension plan other finance expense
Inflation for pension plan service costs
2018
2.9
3.8
3.0
3.0
3.1
2018
2.6
2.5
3.1
%
2017
2.5
4.1
2.9
2.9
3.1
%
2017
2.7
2.7
3.2
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 comprises of 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 the latest available published tables adjusted to reflect the experience of the
plans and an extrapolation of past longevity improvements into the future. For the main 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
2018
27.4
28.9
28.8
30.6
Years
2017
27.4
29.0
28.8
30.5
The assets of the primary plan are held in a trust, the primary objective of which is to accumulate pools of assets sufficient to meet the
obligations of the plan. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current
practices in portfolio management.
A significant proportion of the assets are held in equities, owing to a higher expected level of return over the long term of such assets with an
acceptable level of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the
total portfolio, the investment portfolios are highly diversified.
The 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 primarily 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.
For the primary UK pension plan there is an agreement with the trustee to increase the proportion of assets with liability matching
characteristics over time primarily by reducing the proportion of plan assets held as equities and increasing the proportion held as bonds.
During 2018, the plan switched 12.5% 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
%
30
63
7
The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2018 were $4,197 million (2017 $2,588
million) of government-issued nominal bonds and $17,491 million (2017 $16,177 million) of index-linked bonds.
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
4. Pensions – continued
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 246.
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
2018
5,191
950
2,792
4,263
17,491
4,606
2,311
376
116
(6,011)
32,085
$ million
2017
9,548
2,220
2,679
2,663
16,177
4,682
2,211
390
104
(5,583)
35,091
a Private equity is valued as fair value based on the most recent third-party net asset valuation.
b Bonds held are denominated in sterling and valued using quoted prices in active markets. Where quoted prices are not available, quoted prices for similar instruments in active markets are
used.
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.
Analysis of the amount charged to profit or loss
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)
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
2018
295
15
310
38
348
(868)
773
(95)
(722)
1,768
123
520
1,689
$ million
2017
357
12
369
31
400
(845)
830
(15)
2,396
(237)
734
91
2,984
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.
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
245
4. Pensions – continued
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
2018
31,474
(1,587)
310
773
21
(1,780)
(4)
(2,411)
26,796
35,091
(1,883)
868
21
490
(1,780)
(722)
32,085
5,289
5,473
(184)
5,289
5,473
(184)
5,289
$ million
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
(26,612)
(184)
(26,796)
(31,253)
(221)
(31,474)
a Most of the contributions made by plan participants were made under salary sacrifice.
b The benefit payments amount shown above comprises $1,764 million benefits (2017 $1,888 million) plus $20 million (2017 $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 $31,818 million of assets held in the BP Pension Fund (2017 $34,841 million) and $203 million held in the BP Global Pension Trust (2017 $183 million), as well as $51 million
representing the company’s share of Merchant Navy Officers Pension Fund (2017 $53 million) and $13 million of Merchant Navy Ratings Pension Fund (2017 $14 million).
e The fair value of plan assets includes borrowings related to the LDI programme as described on page 244.
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 2018 for the company’s plans would have had the effects
shown in the table below. The effects shown for the expense in 2019 comprise the total of current service cost and net finance income or
expense.
Discount ratea
Effect on pension expense in 2019
Effect on pension obligation at 31 December 2018
Inflation rateb
Effect on pension expense in 2019
Effect on pension obligation at 31 December 2018
Salary growth
Effect on pension expense in 2019
Effect on pension obligation at 31 December 2018
$ million
One percentage point
Increase
Decrease
(270)
(4,137)
176
3,939
37
449
239
5,527
(145)
(3,396)
(33)
(411)
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 2019 pension expense by $34 million and the pension
obligation at 31 December 2018 by $965 million.
The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
246
BP Annual Report and Form 20-F 2018
4. Pensions – continued
Estimated future benefit payments and the weighted average duration of defined benefit obligations
The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2028 and the
weighted average duration of the defined benefit obligations at 31 December 2018 are as follows:
Estimated future benefit payments
2019
2020
2021
2022
2023
2024-2028
Weighted average duration
5. Payables
Amounts payable to subsidiariesa
Accruals and deferred income
Other payables
$ million
1,027
1,034
1,054
1,086
1,118
5,766
Years
17.8
$ million
2017
2018
Current
Non-current
Current
Non-current
14,559
31
75
14,665
31,765
—
35
31,800
10,070
60
73
10,203
31,755
—
49
31,804
a In 2017, an amount of $2,300 million has been reclassified from non-current payables to current payables.
Included in non-current amounts payable to subsidiaries is an interest-bearing payable of $4,236 million (2017 $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 (2017 $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. Current amounts payable to
subsidiaries also includes an interest-bearing payable of $5,000 million (2017 $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, callable upon demand.
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
6. Taxation
Tax charge included in total comprehensive income
Deferred tax
Origination and reversal of temporary 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 in the income statement
Charge (credit) for the year in other comprehensive income
At 31 December
2018
40
31,520
240
31,800
2018
570
570
1,907
1,907
1,337
59
511
1,907
$ million
2017
73
4,530
27,201
31,804
$ million
2017
1,158
1,158
1,337
1,337
179
(11)
1,169
1,337
At 31 December 2018, deferred tax assets of $258 million on other temporary differences, $7 million relating to pensions, $67 million relating
to income losses and $184 million relating to other deductible temporary differences (2017 $92 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. There is no fixed expiry date for the
unrecognised temporary differences.
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
247
7. Called-up share capital
The allotted, called-up and fully paid share capital at 31 December was as follows:
Issued
8% cumulative first preference shares of £1 eacha
9% cumulative second preference shares of £1 eacha
Ordinary shares of 25 cents each
At 1 January
Issue of new shares for the scrip dividend programme
Issue of new shares for employee share-based payment plans
Repurchase of ordinary share capital
At 31 December
Shares
thousand
7,233
5,473
21,288,193
195,305
92,168
(50,202)
21,525,464
2018
$ million
12
9
21
5,322
49
23
(13)
5,381
5,402
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
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.
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 2018 the company repurchased 50 million ordinary shares at a cost of $355 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
Issue of new shares for employee share-based payment plans
Shares re-issued for employee share-based payment plans
At 31 December
Of which - shares held in treasury by BP
- shares held in ESOP trusts
- shares held by BP’s US plan administratorb
Shares
thousand
1,482,072
757
92,168
(148,732)
1,426,265
1,264,732
161,518
15
2018
Nominal value
$ million
370
—
23
(37)
356
316
40
—
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
—
a See Note 8 for definition of treasury shares.
b Held by the company in the form of ADSs to meet the requirements of employee share-based payment plans in the US.
For each year presented, the balance at 1 January represents the maximum number of shares held in treasury by BP during the year,
representing 6.9% (2017 7.5%) of the called-up ordinary share capital of the company.
During 2018, the movement in shares held in treasury by BP represented less than 1.0% (2017 less than 0.5%) 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.
The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
248
BP Annual Report and Form 20-F 2018
8. Capital and reserves – continued
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 (2017 $24,107 million), the distribution of which is limited by statutory or other
restrictions.
The financial statements for the year ended 31 December 2018 do not reflect the dividend announced on 5 February 2019 and paid in March
2019; this will be treated as an appropriation of profit in the year ended 31 December 2019.
9. Financial guarantees
The company has issued guarantees under which the maximum aggregate liabilities at 31 December 2018 were $77,965 million (2017 $75,824
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.
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
2018
429
(9)
420
27
23
$ million
2017
397
9
406
54
58
Additional information on the company’s share-based payment plans is provided in Note 11 to the consolidated financial statements.
11. Auditor’s remuneration
Note 36 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.
2018
8
16
24
$ million
2017
9
9
18
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 87.
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
249
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
2018
491
74
80
645
2018
269
1,151
2,344
3,764
$ million
2017
496
74
92
662
2017
262
1,125
2,384
3,771
The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
250
BP Annual Report and Form 20-F 2018
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 2018 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 Oy
Air BP Iceland
Air BP Limited
Air BP Norway AS
Air BP Sales Romania S.R.L.
Air BP Sweden AB
Air Refuel Pty Ltdb
Allgreen Pty Ltd
AM/PM International Inc.
American Oil Company
Amoco (Fiddich) Limited
Amoco (U.K.) Exploration Company, LLCa
Amoco Bolivia Petroleum Company
Amoco Bolivia Services Company Inc.
Amoco Canada International Holdings B.V.
Amoco Capline Pipeline Company
Amoco Chemical (Europe) S.A.
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 and Fibers Ltd.c
Amoco Guatemala Petroleum Company
Amoco International Finance Corporation
Amoco International Petroleum Company
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 Limitedd
Amoco Nigeria Oil Company Limitedd
Amoco Nigeria Petroleum Company
Amoco Nigeria Petroleum Company Limited
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
Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands
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
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
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
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
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
251
14. Related undertakings of the group – continued
Amoco Norway Oil Company
Amoco Oil Holding Company
Amoco Olefins Corporation
Amoco Overseas Exploration Company
Amoco Pipeline Asset Company
Amoco Pipeline Holding Company
Amoco Properties Incorporated
Amoco Realty Company
Amoco Remediation Management Services
Corporation
Amoco Research Operating Company
Amoco Rio Grande Pipeline Company
Amoco Somalia Petroleum Company
Amoco Sulfur Recovery Company
Amoco Trinidad Gas B.V.
Amoco Tri-States NGL Pipeline Company
Amoco U.K. Petroleum Limited
AmProp Finance Company
Amprop Illinois I Limited Partnershipe
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 Mediterraneo Inversiones, S.L
ARCO Midcon LLCa
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
Areas Noriega S.L.
Areas Singulares Reyes S.L.
Aspac Lubricants (Malaysia) Sdn. Bhd. (63.03%)
Atlantic 2/3 UK Holdings Limited
Atlantic Richfield Company
Autino Holdings Limited (88.85%)f
Autino Limited (88.85%)
Auwahi Wind Energy Holdings LLCa
B2Mobility GmbH
Bahia de Bizkaia Electridad, S.L. (75.00%)
Baltimore Ennis Land Company, Inc.
BHP Billiton Petroleum (Eagle Ford Gathering) LLC
(75.00%)a
BHP Billiton Petroleum (KCS Resources), LLCa
BHP Billiton Petroleum (Tx Gathering), LLCa
BHP Billiton Petroleum (TxLa Operating) Company
BHP Billiton Petroleum (WSF Operating), Inc.
BHP Billiton Petroleum Properties (GP), LLCa
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
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
Federico García Lorca, 43, entreplanta, 04004, Almería, Spain
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
Ronda de Poniente 3, 1ªPlanta, 28760 Tres Cantos, Madrid, Spain
Calle Velázquez 18, 28001 Madrid, Spain
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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
The Corporation Company, 1833 South Morgan Road,, Oklahoma City OK 73128, United States
350 North St. Paul Street, Suite 2900, Dallas, Texas 75201, United States
5615 Corporate Blvd., Suite 400B, Baton Rouge LA 70808, United States
CT Corporation System, 1021 Main Street, Suite 1150, Houston, Texas 77002, United States
The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
252
BP Annual Report and Form 20-F 2018
14. Related undertakings of the group – continued
BHP Billiton Petroleum Properties (LP) LLCa
BHP Billiton Petroleum Properties (N.A.), LPe
Black Lake Pipe Line Company
BP - Castrol (Thailand) Limited (57.57%)g
BP (Abu Dhabi) Limited
BP (Barbados) Holding SRL
BP (Barbican) Limitedh
BP (China) Holdings Limiteda
BP (China) Industrial Lubricants Limiteda
BP (Gibraltar) Limitedi
BP (Indian Agencies) Limitedh
BP (Malta) Limited (in liquidation)h
BP (Shandong) Petroleum Co., Ltda
BP (Shanghai) Trading Limiteda
BP Absheron Limited
BP Advanced Mobility Limited
BP Africa Limitedh
BP Akaryakit Ortakligi (70.00%)e
BP Alaska LNG LLCa
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 Angola (Block 18) B.V.
BP Argentina Exploration Company
BP Argentina Holdings LLCa
BP Aromatics Holdings Limited
BP Aromatics Limited
BP Asia Limited
BP Asia Pacific (Malaysia) Sdn. Bhd.
BP Asia Pacific Holdings Limited
BP Asia Pacific Pte Ltdh
BP Australia Capital Markets Limited
BP Australia Employee Share Plan Proprietary Limited
BP Australia Group Pty Ltdd
BP Australia Investments Pty Ltd
BP Australia Nominees Proprietary Limited
BP Australia Pty Ltd
BP Australia Shipping Pty Ltdj
BP Australia Swaps Management Limited
BP Aviation A/S
BP Benevolent Fund Trustees Limitedh
BP Berau Ltd.
BP Biocombustíveis S.A. (91.10%)
BP Bioenergia Campina Verde Ltda. (91.10%)
BP Bioenergia Ituiutaba Ltda. (81.26%)
BP Bioenergia Itumbiara S.A. (73.95%)
BP Bioenergia Tropical S.A. (94.04%)
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. (81.18%)
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
1999 Bryan St., STE 900, Dallas TX 75201, 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
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
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
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
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, 12399, 4fl, Sao Paulo, Brazil
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
253
14. Related undertakings of the group – continued
BP Bomberai Ltd.
BP Brasil Ltda.
BP Brazil Tracking L.L.C.a
BP Bulwer Island Pty Ltdk
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 Limitedh
BP Caribbean Company
BP Castrol KK (64.84%)
BP Castrol Lubricants (Malaysia) Sdn. Bhd. (63.03%)
BP Chembel N.V.
BP Chemicals (Korea) Limited
BP Chemicals East China Investments Limited
BP Chemicals Investments Limited
BP Chemicals Limited
BP Chemicals Trading Limited (In Liquidation)
BP China Exploration and Production Company
BP China Limited (In Liquidation)h
BP Comercializadora de Energia Ltda.
BP Commodities Trading Limited
BP Commodity Supply B.V.
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 D230 Limited
BP Danmark A/S
BP D-B Pipeline Company LLCe
BP Developments Australia Pty. Ltd.
BP Diagnostic Acoustic Sensing Limited
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 Energy Solutions B.V.
BP Espana, S.A. Unipersonalk
BP Estaciones y Servicios Energéticos, Sociedad
Anónima de Capital Variableb
BP Europa SEl
BP Exploracion de Venezuela S.A.
BP Exploration & Production Inc.c
BP Exploration (Absheron) Limited
BP Exploration (Alaska) Inc.
BP Exploration (Algeria) Limited
BP Exploration (Alpha) Limited
BP Exploration (Angola) Limited
BP Exploration (Azerbaijan) Limited
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
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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
55 Baker Street, London, W1U 7EU, United Kingdom
Avenida das Nações Unidas, 12399, 4fl, Sao Paulo, Brazil
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
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
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
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
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
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
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
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
The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
254
BP Annual Report and Form 20-F 2018
14. Related undertakings of the group – continued
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 (STP) Limited
BP Exploration (Vietnam) Limited (In Liquidation)
BP Exploration (Xazar) Pte. Ltd.
BP Exploration Angola (Kwanza Benguela) Limited
BP Exploration Australia Pty Ltd
BP Exploration Beta Limited
BP Exploration China Limited
BP Exploration Company (Middle East) Limited
BP Exploration Company Limitedm
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 Limitedk
BP Exploration Orinoco Limited
BP Exploration Personnel Company Limited
BP Express Shopping Limited
BP Finance Australia Pty Ltd
BP Finance p.l.c.
BP Foundation Incorporateda
BP France
BP Fuels & Lubricants AS
BP Fuels Deutschland GmbH
BP Gas Europe, S.A.U.
BP Gas Marketing Limited
BP Gas Supply (Angola) LLCa
BP Ghana Limited
BP Global Investments Limitedh
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 Holdings (Thailand) Limited (81.01%)n
BP Holdings B.V.
BP Holdings Canada Limitedh
BP Holdings International B.V.
BP Holdings North America Limitedh
BP Hong Kong Limited
BP India Limited
BP India Services Private Limited
BP Indonesia Investment Limited
BP International Limitedh
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.
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
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
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
Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe,
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
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
255
14. Related undertakings of the group – continued
BP Kapuas II Limited (in liquidation)
BP Korea Limited
BP Kuwait Limited
BP Latin America LLCa
BP Latin America Upstream Services Inc.
BP LNG Shipping Limited
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 (In Liquidation)
BP Middle East Enterprises Corporation
BP Middle East Limitedh
BP Middle East LLC
BP Midstream Partners GP LLCa
BP Midstream Partners Holdings LLCa
BP Midstream Partners LP (54.37%)o
BP Mocambique Limitada
BP Mocambique Limited
BP Muturi Holdings B.V.
BP Nederland Holdings BV
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 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 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 Limitedh
BP Pensions (Overseas) Limitedi
BP Pensions Limitedh
BP Petrochemicals India Investments Limited
BP Petroleo y Gas, S.A.
BP Petrolleri Anonim Sirketi
BP Pipelines (Alaska) Inc.
BP Pipelines (BTC) Limited
BP Pipelines (North America) Inc.
BP Pipelines (SCP) Limited
BP Pipelines (TANAP) Limited
BP Pipelines TAP Limited
55 Baker Street, London, W1U 7EU, 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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Clarendon House, 2 Church Street, P.O. Box HM 1022, Hamilton, HM DX, Bermuda
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
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
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
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
The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
256
BP Annual Report and Form 20-F 2018
14. Related undertakings of the group – continued
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 Limitedh
BP Raffinaderij Rotterdam B.V.
BP Refinery (Kwinana) Proprietary Limited
BP Regional Australasia Holdings Pty Ltd
BP River Rouge Pipeline Company LLCe
BP Russian Investments Limited
BP Russian Ventures Limited
BP SC Holdings LLCa
BP Scale Up Factory Limited
BP Senegal Investments Limited
BP Services International Limited
BP Servicios de Combustibles S.A. de C.V.
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. Unipersonalb
BP Solar International Inc.
BP Solar Pty Ltd
BP South America Holdings Ltd
BP South East Asia Limited (In Liquidation)h
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 (In Liquidation)
BP Technology Ventures Inc.
BP Technology Ventures Limited
BP Trading Limited (In Liquidation)
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 Limitedh
BP Two Pipeline Company LLCe
BP Venezuela Investments B.V.
BP West Aru I Limited
BP West Aru II Limited
BP West Coast Products LLCa
BP West Papua I Limited
BP West Papua III Limited
BP Wind Energy North America Inc.
BP Wiriagar Ltd.
BP World-Wide Technical Services Limited
BP Zhuhai Chemical Company Limited (91.90%)a
BP+Amoco International Limitedh
BPA Investment Holding Company
BP-AIOC Exploration (TISA) LLC (65.88%)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%)g q
Britoil Limited
BTC Pipeline Holding Company Limited
Burmah Castrol Australia Pty Ltdr
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
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
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
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
55 Baker Street, London, W1U 7EU, 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
55 Baker Street, London, W1U 7EU, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
55 Baker Street, London, W1U 7EU, 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
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
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
257
14. Related undertakings of the group – continued
Burmah Castrol Holdings Inc.
Burmah Castrol PLCh
Burmah Castrol South Africa (Pty) Limiteds
Burmah Chile SpA
BXL Plastics Limitedt
Cadman DBP Limited
Cape Vincent Wind Power, LLCa
Casitas Pipeline Company
Castrol (China) Limited
Castrol (Ireland) Limited
Castrol (Shanghai) Management Co., Ltda
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 Digital Holdings Limited
Castrol Egypt Lubricants S.A.E. (51.00%)
Castrol Hungária Trading Co. LLC "u.d." (Castrol
Hungária Kereskedelmi Kft. "v.a.")a
Castrol India Limited (51.00%)
Castrol Industrie und Service GmbH
Castrol KK (64.84%)
Castrol Limited
Castrol Lubricants RO S.R.L
Castrol Mexico, S.A. de C.V.b
Castrol Namibia (Pty) Limited
Castrol Offshore Limited
Castrol Pakistan (Private) Limited
Castrol Philippines, Inc.
Castrol Servicos Ltda.
Castrol Slovensko, s.r.o. (v likvidácii) (in liquidation)a
Castrol Ukraine LLCa
Castrol Zimbabwe (Private) Limited
Centrel Pty Ltd
Charge Your Car Limitedb
Chargemaster (Europe) GmbH
Chargemaster Limited
Charging Solutions Limited
CH-Twenty, Inc.
Clarisse Holdings Pty Ltd
Coastwise Trading Company, Inc.
Consolidada de Energia y Lubricantes, (CENERLUB)
C.A.
Conti Cross Keys Inn, Inc.
Corner Card, S.L.
Coro Trading NZ Limited
Cuyama Pipeline Company
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 Partnershipe
Dome Beaufort Petroleum Limited 1979 Partnership
No. 1e
Dome Wallis (1980) Limited Partnership (92.50%)e
Dradnats, Inc.
ECM Markets SA (Pty) Ltd (75.00%)
Elektromotive Limited
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
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
Floor 20, Shanghai Youyou International Plaza, No.76 Pujian Road, Pudong, Shanghai, China
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
Technology Centre, Whitchurch Hill, Pangbourne, Reading, RG8 7QR, United Kingdom
Plot 28, North 90 Road, Housing & Construction Bank Building, New Cairo, Cairo, 11835, Egypt
32-34 Soroksári út, Budapest, 1095, Hungary
Technopolis Knowledge Park, Mahakali Caves Road, Andheri (East), Mumbai 400 093, India
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
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
2a Konstiantynivskay Street, Kyiv, 04071, Ukraine
Barking Road, Willowvale, Harare, Zimbabwe
Level 17, 717 Bourke Street, Docklands VIC, Australia
500 Capability Green, Luton, LU1 3LS, United Kingdom
Bischof-von-Henle-Straße 2a, Regensburg, 93051, Germany
500 Capability Green, Luton, LU1 3LS, United Kingdom
500 Capability Green, Luton, LU1 3LS, United Kingdom
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
Ronda de Poniente 3, 1ªPlanta, 28760 Tres Cantos, Madrid, Spain
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Level 17, 717 Bourke Street, Docklands VIC, Australia
Level 17, 717 Bourke Street, Docklands VIC, Australia
Level 17, 717 Bourke Street, Docklands VIC, Australia
Timmerhellstsr. 28, 45478, Mülheim/Ruhr, Germany
240 - 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
500 Capability Green, Luton, LU1 3LS, United Kingdom
The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
258
BP Annual Report and Form 20-F 2018
14. Related undertakings of the group – continued
Elite Customer Solutions Pty Ltd
Elm Holdings Inc.
Energy Global Investments (USA) Inc.
Enstar LLCa
Estacion De Servicio Molinar S.L.
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 Holding International B.V.
Foseco Holding, Inc.
Foseco, Inc.
Fosroc Expandite Limited
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) Limitedu
FWK Holdings (2017) LTDu
Gardena Holdings Inc.
Gasolin GmbH
GB Electrical and Building Services Limited
Gelsenkirchen Raffinerie Netz GmbH
GOAM 1 C.I S. A .S
Grampian Aviation Fuelling Services Limited
Guangdong Investments Limited
Highlands Ethanol, LLCa
Hosteleria Noriega S.L.
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
Ken-Chas Reserve Company
Kenilworth Oil Company Limitedh
Kingbook Inversiones Socimi, S.A.
Latin Energy Argentina S.A.
Lebanese Aviation Technical Services S.A.L.
Limited Liability Company BP Toplivnaya Kompaniaa
Limited liability company Setra Lubricantsa
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.b
Minza Pty. Ltd.
Mountain City Remediation, LLCa
No. 1 Riverside Quay Proprietary Limited
Nordic Lubricants A/S
Nordic Lubricants AB
Nordic Lubricants Oy, (in liquidation)
North America Funding Company
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
Ronda de Poniente 3, 1ªPlanta, 28760 Tres Cantos, Madrid, Spain
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
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
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
500 Capability Green, Luton, LU1 3LS, United Kingdom
Alexander-von-Humboldt-Straße 1, Gelsenkirchen, 45896, 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
Ronda de Poniente 3, 1ªPlanta, 28760 Tres Cantos, Madrid, Spain
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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Calle Velázquez 18, 28001 Madrid, Spain
Av. Cordoba 315 Piso 8, Buenos Aires, 1054, Argentina
P O Box - 11 -5814c/o Coral Oil Building, 583Avenue de Gaulle, Raoucheh, Beirut, Lebanon
Novinskiy blvd.8, 17th floor, office 11, 121099, Moscow, Russian Federation
2 Paveletskaya sq, Building1, 115054 Moscow, Russian Federation
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
Teknobulevardi 3-5, 01530 Vantaa, Finland
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
259
14. Related undertakings of the group – continued
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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Ronda de Poniente 3, 1ªPlanta, 28760 Tres Cantos, Madrid, Spain
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
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%)
Peaks America Inc.
Pearl River Delta Investments Limited
Petrocorner Retail S.L.U.
Petrohawk Energy Corporation
Phoenix Petroleum Services, Limited Liability Company Baghdad International Airport, Al-Burhan Commercial Complex , First floor, Baghdad, Iraq
Produits Métallurgie Doittau
Prospect International, C.A. (In liquidation)
PT BP Petrochemicals Indonesia
PT Castrol Indonesia (68.30%)
PT Castrol Manufacturing Indonesia
PT Jasatama Petroindob
Remediation Management Services Company
Richfield Oil Corporation
Rolling Thunder I Power Partners, LLCa
Romax Insight Korea Limited (74.50%)
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
JL. Raya Merak KM 117, DS Gerem, Gerem Grogol, Cilegon, Banten, Indonesia
Perkantoran Hijau Arkadia, Tower B, Jl. Let. Jenderal TB. Simatupang Kav. 88, Jakarta12520, Indonesia
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
Ropemaker Deansgate Limited
Ropemaker Properties Limited
Ruhr Oel GmbH (ROG)
Rusdene GSS Limitedu
Saturn Insurance Inc.
Setra Lubricants Kazakhstan LLP (in liquidation)e
Sherbino I Holdings LLCa
Sherbino Mesa I Land Investments LLCa
Shine Top International Investment Limited
Sociedade de Promocao Imobiliaria Quinta do Loureiro,
SA
Société de Gestion de Dépots d'Hydrocarbures - GDHa
SOFAST Limited (62.77%)v
South Texas Shale LLCa
Southeast Texas Biofuels LLCa
Southern Ridge Pipeline Holding Company
Southern Ridge Pipeline LP LLCa
Sp/f Decision3 (GreenSteam) Company (61.68%)w
SRHP (99.99%)a
Standard Oil Company, Inc.
Taradadis Pty. Ltd.
Telcom General Corporation (99.96%)c
Terre de Grace Partnership (75.00%)e
The Anaconda Company
The BP Share Plans Trustees Limitedh
The Burmah Oil Company (Pakistan Trading) Limited
The Standard Oil Company
TISA Education Complex LLC (65.88%)a
TJKK
Toledo Refinery Holding Company LLCa
Union Texas International Corporation
Vastar Pipeline, LLCa
Viceroy Investments Limited
Warrenville Development Limited Partnershipa
Water Way Trading and Petroleum Services LLC
(90.00%)
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Johannastraße 2-8, 45899 Gelsenkirchen-Horst, Germany
4 High Street, Alton, Hampshire, GU34 1BU, United Kingdom
400 Cornerstone Drive, Suite 240, Williston VT 05495, United States
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
Unit 807, Tower B, Manulife Financial Centre, 223 Wai Yip Street, Kwun Tong, Kowloon, Hong Kong
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
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
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
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
33 North LaSalle Street, Chicago, Illinois 60602, United States
Hay Al Wihda, Q904, Alley 68, H32, Korodha, Baghdad, Iraq
Welchem, Inc.
West Kimberley Fuels Pty Ltd
Westlake Houston Development, LLCa
Whiting Clean Energy, Inc.
Windpark Energy Nederland B.V.
Winwell Resources, L.L.C.a
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
5615 Corporate Blvd., Suite 400B, Baton Rouge LA 70808, United States
Wiriagar Overseas Ltd
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 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
260
BP Annual Report and Form 20-F 2018
14. Related undertakings of the group – continued
Related undertakings other than subsidiaries
Berghausener Straße 96, 40764 Langenfeld, Germany
Box 135, 190 46 Arlanda, Sweden
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Brucknerstraße 4, 1041 Wien, Austria
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
18010 Skypark Circle , #130 , Irvine CA 92614, United States
Harvard Business Services, Inc., 16192 Coastal Hwy, Lewes, Delaware, 19958, USA
Berghausener Straße 96, 40764 Langenfeld, Germany
A Flygbranslehantering AB (AFAB) (25.00%)
Aashman Power Limited (43.20%)
ABG Autobahn-Betriebe GmbH (32.58%)a
Abu Dhabi Marine Areas Limited (33.33%)g
Advanced Biocatalytics Corporation (24.20%)x
AEP I HoldCo LLC (24.30%)
AGES International GmbH & Co. KG, Langenfeld
(24.70%)e
AGES Maut System GmbH & Co. KG, Langenfeld
(24.70%)e
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 (51.00%)
Ammenn GmbH (75.00%)
ATAS Anadolu Tasfiyehanesi Anonim Sirketi (68.00%)y Degirmen yolu cad. No:28, Asia OfisPark K:3 İcerenkoy-Atasehir, Istanbul, 34752, Turkey
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%)
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
Yakuplu Mahallesi Genc, Osman Caddesi, No.7 Beylikdüzü, Istanbul, Turkey
Luisenstraße 5 a, 26382 Wilhelmshaven, Germany
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
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%)g
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
Princes Court, Cor. Pembroke & Keate Street, Port-of-Spain, Trinidad and Tobago
Princes Court, Cor. Pembroke & Keate Street, Port-of-Spain, Trinidad and Tobago
Maracaibo Drive, Point Lisas Industrial Estate, Point Lisas, Trinidad and Tobago
Building 1, 747 Lytton Road, Murarrie QLD 4172, Australia
Level 3, Unit 3, 22 Albert Road, South Melbourne VIC 3205, Australia
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
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
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%)g
Azerbaijan International Operating Company (30.37%)z 190 Elgin Avenue, George Town, Grand Cayman , KY1-9005, Cayman Islands
Baplor S.A. (50.00%)
Barranca Sur Minera S.A. (50.00%)
Beer GmbH (50.00%)
Beer GmbH & Co. Mineralol-Vertriebs-KG (50.00%)e
BGFH Betankungs-Gesellschaft Frankfurt-Hahn GbR
(50.00%)e
Billund Refuelling I/S (50.00%)
Blendcor (Pty) Limited (37.50%)α
Blue Marble Holdings Limited (23.58%)β
Bodmin Solar Limited (43.20%)
BP AOC Pumpstation Maatschap (50.00%)e
BP Dhofar LLC (49.00%)
BP Esso AOC Maatschap (22.80%)e
BP Esso Pipeline Maatschap (50.00%)e
BP Guangzhou Development Oil Product Co., Ltd
(40.00%)a
BP Petro China Jiangmen Fuels Co., Ltd. (49.00%)a
BP PetroChina Petroleum Co., Ltd (49.00%)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
7th Floor, 33 Holborn, London, EC1N 2HU, 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 A, building B , 5th floor, no. 22 Gangang Road, Jiangmen, China
Room A17th Floor, No.22 Gangkou Road, Jiangmen, Guangdong Province, China
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
261
14. Related undertakings of the group – continued
BP PETRONAS Acetyls Sdn. Bhd. (70.00%)
BP Sinopec (ZheJiang) Petroleum Co., Ltd (40.00%)a
BP Sinopec Marine Fuels Pte. Ltd. (50.00%)
BP West Africa Supply Limited (50.00%)
Symphony House, Pusat Dagangan Dana 1, Jalan PJU 1A/46, 47301 Petaling Jaya, Selangor, Malaysia
12 Hua Zhe Plaza, 1 Hua Zhe Square, Hang Zhou City, Zhe Jiang Province, China
112 Robinson Road, #05-01, Robinson 112, 068902, Singapore
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
BP YPC Acetyls Company (Nanjing) Limited (50.00%)a
BP-Husky Refining LLC (50.00%)a
BP-Japan Oil Development Company Limited
(50.00%)g
Braendstoflageret Kobenhavns Lufthavn I/S (20.83%)e Københavns, Lufthavn, 2770 Kastrup, Denmark
BTC International Investment Co. (30.10%)γ
Burnthouse Solar Limited (43.20%)
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%)e
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 (35.70%) Yakuplu Ambarli Mevkii, 9 Ada2-3-6-7 Parsel, Büyükçekmece, Istanbul, Turkey
Central African Petroleum Refineries (Pvt) Ltd
(20.75%)
CERF Shelby, LLC (50.00%)a
Chicap Pipe Line Company (56.17%)a
China American Petrochemical Company, Ltd.
(CAPCO) (61.36%)
P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
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
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
Block 1Tendeseka Office Park, Samora Machel Av/Renfrew Road, Harare, Zimbabwe
China Aviation Oil (Singapore) Corporation Ltd
(20.03%)
Chittering Solar Limited (43.20%)
Clean Eagle RNG, LLC (50.00%)a
Cleopatra Gas Gathering Company, LLC (53.00%)a
Coastal Oil Logistics Limited (25.00%)
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%)e
Danish Tankage Services I/S (50.00%)e
Dinarel S.A. (20.00%)
Donoma Power Limited (43.20%)
DOPARK GmbH (25.00%)
Dusseldorf Fuelling Services GbR (33.00%)e
Dusseldorf Tank Services GbR (33.00%)e
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%)
EMSEP S.A. de C.V. (50.00%)
Endymion Oil Pipeline Company, LLC (65.00%)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
Esma Petroleum Company "ESMA" (50.00%)
Estonian Aviation Fuelling Services
Etzel-Kavernenbetriebsgesellschaft mbH & Co. KG
(33.00%)e
Etzel-Kavernenbetriebs-Verwaltungsgesellschaft mbH
(33.33%)
Ffos Las Solar Developments Limited (43.20%)
FFS Frankfurt Fuelling Services (GmbH & Co.) OHG
(33.00%)e
8 Temasek Boulevard #31-02, Suntec City Tower 3, Singapore 038988, Singapore
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
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
Av. Andrés Bello 2711, Piso 24, Las Condes, Santiago, Chile
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
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
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
P.O.Box 261781, Dubai, United Arab Emirates
Plot No. B003R04, Box No. 9400, Dubai, United Arab Emirates, Dubai, United Arab Emirates
Av. Paseo de la Reforma 505 piso 32, Colonia Cuauhtémoc, Delegación Cuauhtémoc (06500), CDMX,
Mexico
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
562 Avenue du Parc de l'Ile, 92000, Nanterre, France
Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise, France
Radlpaßstraße 6, 8502 Lannach, Austria
4 Palestine Road, 4th District, New Maadi, Cairo, Egypt
Lennujaama tee 2, Tallinn EE0011, Estonia
Bertrand-Russell-Straße 3, 22761 Hamburg, Germany
Bertrand-Russell-Straße 3, 22761 Hamburg, Germany
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Sportallee 6, 22335 Hamburg, Germany
The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
262
BP Annual Report and Form 20-F 2018
14. Related undertakings of the group – continued
Field Services Enterprise S.A. (50.00%)
Finite Carbon Corporation (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%)e
Flytanking AS (50.00%)
Foreseer Ltd (25.00%)
Formosa BP Chemicals Corporation (50.00%)
Fotech Group Limited (22.40%)x
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
Free Power for Schools 13 Limited (43.20%)
Free Power for Schools 14 Limited (43.20%)
Free Power for Schools 15 Limited (43.20%)
Free Power for Schools 17 Limited (43.20%)
Free Power for Schools 19 Limited (43.20%)
Free Power for Schools 4 Limited (43.20%)
Free Power for Schools 5 Limited (43.20%)
Free Power for Schools 6 Limited (43.20%)
Free Power for Schools 7 Limited (43.20%)
Freetricity Central June Limited (43.20%)
Freetricity Commercial June Limited (43.20%)
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%)
Georgian Pipeline Company (30.37%)z
Gezamenlijke Tankdienst Schiphol B.V. (50.00%)
GISSCO S.A. (50.00%)
Gnowee Power Limited (43.20%)
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
Guangdong Dapeng LNG Company Limited (30.00%)a
Gulf Of Suez Petroleum Company "GUPCO" (50.00%)
GVÖ Gebinde-Verwertungsgesellschaft der
Mineralölwirtschaft mbH (21.00%)
H7 Energy Limited (43.20%)
Hamburg Tank Service (HTS) GbR (33.00%)e
Hebei Dongming Yinglun Petroleum Co., Ltd.
(49.00%)a
Heinrich Fip GmbH & Co. KG (50.00%)e
Heliex Power Limited (32.40%)x
Henan Dongming Yinglun Petroleum Co., Ltd.
(49.00%)a
HFS Hamburg Fuelling Services GbR (25.00%)e
Hiergeist Heizolhandel GmbH & Co. KG (50.00%)e
Hiergeist Verwaltung GmbH (50.00%)
Hokchi Energy S.A. de C.V. (50.00%)
Hokchi Iberica S.L. (50.00%)
Av. Leandro N. Alem 1180, piso 11, Buenos Aires, Argentina
435 Devon Park Drive, Suite 700, Wayne, Pennsylvania, 19087
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Rheinstraße 36, 49090 Osnabrück, Germany
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Überseeallee 1, 20457, Hamburg, Germany
Überseeallee 1, 20457, Hamburg, Hamburg, Germany
Postboks 36, Stjordal, NO-7501, Norway
121A Thoday Street, Cambridge , Cambridgeshire, CB1 3AT , United Kingdom
No. 1-1Formosa Industrial Comples, Mailiao, Yunlin Hsien, Taiwan
5th Floor, Condor House, 10 St Paul's Churchyard, London, EC4M 8AL , 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
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
3 Rue des Vignes, Aéroport Charles de Gaulle, 93290, Tremblay en France, France
Calle Lituania nº 10, Castellón de la Plana, Spain
Postboks 133, Gardermoen, NO-2061, Norway
Colonia 810, Oficina 403, Montevideo, Uruguay
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
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
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
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
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Sportallee 6, 22335 Hamburg, Germany
South Side, Floor 10, Insurance Industrial Park, No. 672, Chengjiao Street, Qiaoxi, Shijiazhuang, Hebei
Province, China
Rheinstraße 36, 49090 Osnabrück, Germany
Kelvin Building , Bramah Avenue , East Kilbride, Glasgow , Scotland, G75 0RD, United Kingdom
Room 124, Longhu Enterprise Service Center, Floor 1, Building No. 10, Courtyard No.1, Long Xing Jia
Yuan, No. 66, Longhu Outer Ring Road, Zhengdong New District, Zhenzhou City
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
Howbery Solar Park Limited (43.20%)
In Salah Gas Ltd (25.50%)α
In Salah Gas Services Ltd (25.50%)α
India Gas Solutions Private Limited (50.00%)
Jamaica Aircraft Refuelling Services Limited (51.00%)g PCJ Building36 Trafalgar Road, Kingston 10, Jamaica
Johnson Corner Solar I, LLC (43.20%)a
Kala Power Limited (43.20%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
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
Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware, 19904, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
263
14. Related undertakings of the group – continued
Kingston Research Limited (50.00%)
Klaus Köhn GmbH (50.00%)
KM Phoenix Holdings LLC (25.00%)a
Köhn & Plambeck GmbH & Co. KG (50.00%)e
Kosmos Energy Investments Senegal Limited
(49.99%)g
Kurt Ammenn GmbH & Co. KG (50.00%)e
LCA Aviation Fuelling Systems Limited (35.00%)
LFS Langenhagen Fuelling Services GbR (50.00%)e
Lightning Hybrids, LLC (31.60%)c
Lightsource Asset Holdings Limited (43.20%)
Lightsource Asset Management Limited (43.20%)
Lightsource Australia SPV 1 Pty Limited (43.20%)
Lightsource BP Renewable Energy Investments
Limited (43.20%)δ
Lightsource Commercial Rooftops (Buyback) Limited
(43.20%)
Lightsource Commercial Rooftops Limited (43.20%)
Lightsource Construction Management Limited
(43.20%)
Lightsource Development Services Australia Pty Ltd
(43.20%)
Lightsource Development Services Limited (43.20%)
Lightsource Egypt Holdings Limited (43.20%)
Lightsource Finance 55 Limited (43.20%)
Lightsource Grace 1 Limited (43.20%)
Lightsource Grace 2 Limited (43.20%)
Lightsource Grace 3 Limited (43.20%)
Lightsource Holdings 1 Limited (43.20%)
Lightsource Holdings 2 Limited (43.20%)
Lightsource India Holdings (Mauritius) Limited
(43.20%)
Lightsource India Holdings Limited (43.20%)
Lightsource India Investments (UK) Limited (43.20%)
Lightsource India Limited (22.03%)g
Lightsource India Maharashtra 1 Holdings Limited
(43.20%)
Lightsource India Maharashtra 1 Limited (43.20%)
Lightsource Kingfisher Holdings Limited (43.20%)
Lightsource Kingpin 1 Limited (43.20%)
Lightsource Kingpin 2 Limited (43.20%)
Lightsource Kingpin 3 Limited (43.20%)
Lightsource Labs Holdings Limited (43.20%)
Lightsource Labs Limited (41.04%)
Lightsource Largescale Limited (43.20%)
Lightsource Midscale Limited (43.20%)
Lightsource Nala Limited (43.20%)
Lightsource Operations 1 Limited (43.20%)
Lightsource Operations 2 Limited (43.20%)
Lightsource Operations 3 Limited (43.20%)
Lightsource Operations Services Limited (43.20%)
Lightsource Pumbaa Limited (43.20%)
Lightsource Radiate 1 Limited (43.20%)
Lightsource Radiate 2 Limited (43.20%)
Lightsource Raindrop Limited (43.20%)
Lightsource Renewable Development Limited
(43.20%)
Lightsource Renewable Energy (Australia) Pty Ltd
(43.20%)
Lightsource Renewable Energy (India) Limited
(43.20%)
Lightsource Renewable Energy (NI) Limited (43.20%)
Lightsource Renewable Energy Australia Holdings
Limited (43.20%)
Lightsource Renewable Energy Development LLC
(43.20%)a
Lightsource Renewable Energy Holdings Limited
(43.20%)
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
90 Archiepiskopou str, Dromolaxia – Meneou, 7020 Larnaca , Cyprus
Sportallee 6, 22335 Hamburg, Germany
160 Greentree Drive, Suite 101, Dover, County of Kent DE 19904, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
CBW' Level 19, 181 William Street, Melbourne, VIC 3000, Australia
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
CBW' Level 19, 181 William Street, Melbourne, VIC 3000, Australia
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, Jie Tai Plaza, 218 - 222 Zhong Shan Liu Road, Guangzhou, China
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Trinity House, Charleston Road, Ranelagh, Dublin 6, D06C8X4, Ireland
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
CBW' Level 19, 181 William Street, Melbourne, VIC 3000, Australia
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware, 19904, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
264
BP Annual Report and Form 20-F 2018
14. Related undertakings of the group – continued
Lightsource Renewable Energy India Assets Limited
(43.20%)
Lightsource Renewable Energy India Holdings Limited
(43.20%)
Lightsource Renewable Energy India Opco Private
Limited (43.20%)
Lightsource Renewable Energy India Projects Limited
(43.20%)
Lightsource Renewable Energy Ireland Limited
(43.20%)
Lightsource Renewable Energy Limited (43.20%)
Lightsource Renewable Energy Nederland Holdings
B.V. (43.20%)
Lightsource Renewable Energy Netherlands Holdings
Limited (43.20%)
Lightsource Renewable Energy North America LLC
(43.20%)a
Lightsource Renewable Energy North America
Management LLC (43.20%)a
Lightsource Renewable Energy North America
Operations LLC (43.20%)a
Lightsource Renewable Services Limited (43.20%)
Lightsource Residential NI Limited (43.20%)
Lightsource Residential Rooftops (Buyback) Limited
(43.20%)
Lightsource Residential Rooftops (PPA) Limited
(43.20%)
Lightsource Residential Rooftops Limited (43.20%)
Lightsource Simba Limited (43.20%)
Lightsource Singapore Renewables Holdings Private
Limited (43.20%)
Lightsource Singapore Renewables Private Limited
(43.20%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
No.44/38, 1st Floor, Veerabhadran Street, Valluvarkottam, Nungambakkam, Chennai, 600034, India
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Trinity House, Charleston Road, Ranelagh, Dublin 6, D06C8X4, Ireland
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Prins Bernhardplein 200, 1097JB, Amsterdam, Netherlands
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware, 19904, United States
Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware, 19904, United States
Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware, 19904, United States
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
8 Marina Boulevard, #05-02 Marina Bay Financial Centre, Singapore
8 Marina Boulevard, #05-02 Marina Bay Financial Centre, Singapore
Lightsource SPV 10 Limited (43.20%)
Lightsource SPV 100 Limited (43.20%)
Lightsource SPV 101 Limited (43.20%)
Lightsource SPV 104 Limited (43.20%)
Lightsource SPV 105 Limited (43.20%)
Lightsource SPV 106 Limited (43.20%)
Lightsource SPV 108 Limited (43.20%)
Lightsource SPV 109 Limited (43.20%)
Lightsource SPV 112 Limited (43.20%)
Lightsource SPV 114 Limited (43.20%)
Lightsource SPV 115 Limited (43.20%)
Lightsource SPV 116 Limited (43.20%)
Lightsource SPV 118 Limited (43.20%)
Lightsource SPV 123 Limited (43.20%)
Lightsource SPV 126 Limited (43.20%)
Lightsource SPV 127 Limited (43.20%)
Lightsource SPV 128 Limited (43.20%)
Lightsource SPV 130 Limited (43.20%)
Lightsource SPV 133 Limited (43.20%)
Lightsource SPV 135 Limited (43.20%)
Lightsource SPV 137 Limited (43.20%)
Lightsource SPV 138 Limited (43.20%)
Lightsource SPV 140 Limited (43.20%)
Lightsource SPV 142 Limited (43.20%)
Lightsource SPV 143 Limited (43.20%)
Lightsource SPV 145 Limited (43.20%)
Lightsource SPV 147 Limited (43.20%)
Lightsource SPV 149 Limited (43.20%)
Lightsource SPV 151 Limited (43.20%)
Lightsource SPV 152 Limited (43.20%)
Lightsource SPV 154 Limited (43.20%)
Lightsource SPV 155 Limited (43.20%)
Lightsource SPV 156 Limited (43.20%)
Lightsource SPV 160 Limited (43.20%)
Lightsource SPV 162 Limited (43.20%)
Lightsource SPV 166 Limited (43.20%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
265
14. Related undertakings of the group – continued
Lightsource SPV 167 Limited (43.20%)
Lightsource SPV 169 Limited (43.20%)
Lightsource SPV 170 Limited (43.20%)
Lightsource SPV 171 Limited (43.20%)
Lightsource SPV 174 Limited (43.20%)
Lightsource SPV 175 Limited (43.20%)
Lightsource SPV 176 Limited (43.20%)
Lightsource SPV 179 Limited (43.20%)
Lightsource SPV 18 Limited (43.20%)
Lightsource SPV 180 Limited (43.20%)
Lightsource SPV 182 Limited (43.20%)
Lightsource SPV 183 Limited (43.20%)
Lightsource SPV 184 Limited (43.20%)
Lightsource SPV 185 Limited (43.20%)
Lightsource SPV 187 Limited (43.20%)
Lightsource SPV 189 Limited (43.20%)
Lightsource SPV 19 Limited (43.20%)
Lightsource SPV 191 Limited (43.20%)
Lightsource SPV 192 Limited (43.20%)
Lightsource SPV 196 Limited (43.20%)
Lightsource SPV 199 Limited (43.20%)
Lightsource SPV 20 Limited (43.20%)
Lightsource SPV 200 Limited (43.20%)
Lightsource SPV 201 Limited (43.20%)
Lightsource SPV 202 Limited (43.20%)
Lightsource SPV 203 Limited (43.20%)
Lightsource SPV 204 Limited (43.20%)
Lightsource SPV 205 Limited (43.20%)
Lightsource SPV 206 Limited (43.20%)
Lightsource SPV 212 Limited (43.20%)
Lightsource SPV 213 Limited (43.20%)
Lightsource SPV 214 Limited (43.20%)
Lightsource SPV 215 Limited (43.20%)
Lightsource SPV 216 Limited (43.20%)
Lightsource SPV 217 Limited (43.20%)
Lightsource SPV 218 Limited (43.20%)
Lightsource SPV 219 Limited (43.20%)
Lightsource SPV 220 Limited (43.20%)
Lightsource SPV 221 Limited (43.20%)
Lightsource SPV 222 Limited (43.20%)
Lightsource SPV 223 Limited (43.20%)
Lightsource SPV 224 Limited (43.20%)
Lightsource SPV 225 Limited (43.20%)
Lightsource SPV 226 Limited (43.20%)
Lightsource SPV 227 Limited (43.20%)
Lightsource SPV 228 Limited (43.20%)
Lightsource SPV 229 Limited (43.20%)
Lightsource SPV 230 Limited (43.20%)
Lightsource SPV 232 Limited (43.20%)
Lightsource SPV 233 Limited (43.20%)
Lightsource SPV 234 Limited (43.20%)
Lightsource SPV 235 Limited (43.20%)
Lightsource SPV 236 Limited (43.20%)
Lightsource SPV 237 Limited (43.20%)
Lightsource SPV 238 Limited (43.20%)
Lightsource SPV 239 Limited (43.20%)
Lightsource SPV 240 Limited (43.20%)
Lightsource SPV 241 Limited (43.20%)
Lightsource SPV 242 Limited (43.20%)
Lightsource SPV 243 Limited (43.20%)
Lightsource SPV 244 Limited (43.20%)
Lightsource SPV 245 Limited (43.20%)
Lightsource SPV 246 Limited (43.20%)
Lightsource SPV 247 Limited (43.20%)
Lightsource SPV 248 Limited (43.20%)
Lightsource SPV 249 Limited (43.20%)
Lightsource SPV 25 Limited (43.20%)
Lightsource SPV 250 Limited (43.20%)
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
266
BP Annual Report and Form 20-F 2018
14. Related undertakings of the group – continued
Lightsource SPV 251 Limited (43.20%)
Lightsource SPV 252 Limited (43.20%)
Lightsource SPV 253 Limited (43.20%)
Lightsource SPV 254 Limited (43.20%)
Lightsource SPV 255 Limited (43.20%)
Lightsource SPV 256 Limited (43.20%)
Lightsource SPV 257 Limited (43.20%)
Lightsource SPV 258 Limited (43.20%)
Lightsource SPV 259 Limited (43.20%)
Lightsource SPV 26 Limited (43.20%)
Lightsource SPV 260 Limited (43.20%)
Lightsource SPV 261 Limited (43.20%)
Lightsource SPV 262 Limited (43.20%)
Lightsource SPV 263 Limited (43.20%)
Lightsource SPV 264 Limited (43.20%)
Lightsource SPV 265 Limited (43.20%)
Lightsource SPV 266 (NI) Limited (43.20%)
Lightsource SPV 267 (NI) Limited (43.20%)
Lightsource SPV 268 (NI) Limited (43.20%)
Lightsource SPV 269 (NI) Limited (43.20%)
Lightsource SPV 270 (NI) Limited (43.20%)
Lightsource SPV 271 (NI) Limited (43.20%)
Lightsource SPV 272 (NI) Limited (43.20%)
Lightsource SPV 273 (NI) Limited (43.20%)
Lightsource SPV 274 (NI) Limited (43.20%)
Lightsource SPV 275 (NI) Limited (43.20%)
Lightsource SPV 276 (NI) Limited (43.20%)
Lightsource SPV 277 (NI) Limited (43.20%)
Lightsource SPV 278 (NI) Limited (43.20%)
Lightsource SPV 279 (NI) Limited (43.20%)
Lightsource SPV 280 (NI) Limited (43.20%)
Lightsource SPV 281 (NI) Limited (43.20%)
Lightsource SPV 282 (NI) Limited (43.20%)
Lightsource SPV 283 (NI) Limited (43.20%)
Lightsource SPV 284 (NI) Limited (43.20%)
Lightsource SPV 285 (NI) Limited (43.20%)
Lightsource SPV 286 Limited (43.20%)
Lightsource SPV 29 Limited (43.20%)
Lightsource SPV 32 Limited (43.20%)
Lightsource SPV 35 Limited (43.20%)
Lightsource SPV 39 Limited (43.20%)
Lightsource SPV 40 Limited (43.20%)
Lightsource SPV 41 Limited (43.20%)
Lightsource SPV 42 Limited (43.20%)
Lightsource SPV 44 Limited (43.20%)
Lightsource SPV 47 Limited (43.20%)
Lightsource SPV 49 Limited (43.20%)
Lightsource SPV 5 Limited (43.20%)
Lightsource SPV 50 Limited (43.20%)
Lightsource SPV 54 Limited (43.20%)
Lightsource SPV 56 Limited (43.20%)
Lightsource SPV 60 Limited (43.20%)
Lightsource SPV 69 Limited (43.20%)
Lightsource SPV 73 Limited (43.20%)
Lightsource SPV 74 Limited (43.20%)
Lightsource SPV 75 Limited (43.20%)
Lightsource SPV 76 Limited (43.20%)
Lightsource SPV 78 Limited (43.20%)
Lightsource SPV 79 Limited (43.20%)
Lightsource SPV 8 Limited (43.20%)
Lightsource SPV 88 Limited (43.20%)
Lightsource SPV 91 Limited (43.20%)
Lightsource SPV 92 Limited (43.20%)
Lightsource SPV 98 Limited (43.20%)
Lightsource Timon Limited (43.20%)
Lightsource Trading Limited (43.20%)
Lightsource Trojan 1 Limited (43.20%)
Lightsource Trojan 2 Limited (43.20%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
Scottish Provident Building, 7 Donegall Square West, Belfast, BT1 6JH, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
267
14. Related undertakings of the group – continued
Lightsource Viking 1 Limited (43.20%)
Lightsource Viking 2 Limited (43.20%)
Limited Liability Company TYNGD (20.00%)a
LL Property Services 2 Limited (43.20%)
LL Property Services Limited (43.20%)
LLC "Kharampurneftegaz" (49.00%)a
Lora Solar Limited (43.20%)
Lotos - Air BP Polska Spółka z ograniczoną
odpowiedzialnością (50.00%)
LOTTE BP Chemical Co., Ltd (50.94%)
LREHL Renewables India SPV 1 Private Limited
(32.79%)
Maasvlakte Europoort Pipeline Maatschap (50.00%)e
Maatschap Europoort Terminal (50.00%)e
Mach Monument Aviation Fuelling Co. Ltd. (70.00%)
Malmo Fuelling Services AB (33.33%)
Manchester Airport Storage and Hydrant Company
Limited (25.00%)
Manor Farm (Solar Power) Limited (43.20%)
Manpetrol S.A. (50.00%)
Maputo International Airport Fuelling Services (MIAFS)
Limitada (50.00%)a
Mars Oil Pipeline Company LLC (28.50%)e
Masana Employee Share Trust No. 1 (37.88%)a
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
Meri Power Limited (43.20%)
Middle East Lubricants Company LLC (40.00%)
Milne Point Pipeline, LLC (50.00%)a
Mobene Beteiligungs GmbH & Co. KG (50.00%)a
Mobene GmbH & Co. KG (50.00%)e
Mobene Verwaltungs-GmbH (50.00%)
MTS Francis Court Solar Limited (43.20%)
MTS Trefinnick Solar Limited (43.20%)
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%)
Nextpower Trevemper Limited (43.20%)
NFX Combustíveis Marítimos Ltda. (50.00%)
Nima Power Limited (43.20%)
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%)
Olympic Pipe Line Company LLC (70.00%)a
Oslo Lufthaven Tankanlegg AS (33.33%)
PAE E & P Bolivia Limited (50.00%)
PAE Oil & Gas Bolivia Ltda. (50.00%)
Palk Power Limited (43.20%)
Pan American Energy Chile Limitada (50.00%)
Pan American Energy do Brasil Ltda. (50.00%)a
Pan American Energy Group, S.L. (50.00%)α
Pan American Energy Holdings S.A. (50.00%)
Pan American Energy Iberica S.L. (50.00%)
Pan American Energy Investments Ltd. (50.00%)
Pan American Energy Uruguay S.A. (50.00%)
Pan American Energy US LLC (51.00%)a
Pan American Energy, S.L. (50.00%)a
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Pervomayskaya street, 32A, 678144, Lensk, Sakha (Yakutiya) Republic, Russian Federation
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
629830, Gubkinskiy town, Yamalo-Nenets Autonomous Okrug, Russian Federation
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Grunwaldzka 472B, 80-309, Gdansk, Poland
2-2 Sangnam-ri, Chungryang-myun, Ulju-gun, Ulsan 689-863, Republic of Korea
815-816 International Trade Tower, Nehru Place, New Delhi, New Delhi, 110019, India
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
Moezelweg 101, 3198LS Europoort, Rotterdam, Netherlands
Naz City, Building J, Suite 10 Erbil, Iraq
Box 22, SE 230 32 Malmö-Sturup, Sweden
Bircham Dyson Bell, 50 Broadway, London, SW1H 0BL , United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Francisco Behr 20, Barrio Pueyrredon, Comodoro Rivadavia, Provincia del Chubut, Argentina
Praca Dos Trabalhadores, Nr 09, Distrito Urbano 1, Maputo, Mozambique
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
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
6th Flr City Tower, 2 - Sheikh Zayed Road, PO Box 1699, Dubai, United Arab Emirates
900 E. Benson Boulevard, Anchorage, Alaska, 99508, United States
Spaldingstraße 64, 20097 Hamburg, Germany
Spaldingstraße 64, 20097 Hamburg, Germany
Spaldingstraße 64, 20097 Hamburg, Germany
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
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
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Avenida Atlântica, no. 1.130, 2nd floor (part), Copacabana, Rio de Janeiro, RJ, 22021-000, Brazil
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Zum Ölhafen 207, 26384 Wilhelmshaven, Germany
4 Palestine Road, 4th District, New Maadi, Cairo, Egypt
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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Postboks 134, Gardermoen, NO-2061, Norway
Trinity Place Annex, Corner of Frederick & Shirley Streets, P.O. Box N-4805, Nassau, Bahamas
Cuarto anillo, Avda. Ovidio Barbery N° 4200,Equipetrol Norte, Santa Cruz de la Sierra, Bolivia
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
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
Colonia 810, Oficina 403, Montevideo, Uruguay
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
Colonia 810, Oficina 403, Montevideo, Uruguay
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Campus Empresarial Arbea - Edificio No 1, Carretera Fuencarral a Alcobendas, Alcobendas, Madrid,
Spain
The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
268
BP Annual Report and Form 20-F 2018
14. Related undertakings of the group – continued
Pan American Fueguina S.A. (50.00%)
Pan American Sur S.A. (50.00%)
Peninsular Aviation Services Company Limited
(25.00%)h
Pentland Aviation Fuelling Services Limited (50.00%)b
Petrostock SA (50.00%)
Pharaonic Petroleum Company "PhPC" (25.00%)
Pont Andrew Limited (43.20%)
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 (in liquidation) (33.33%)
Rahamat Petroleum Company (PETRORAHAMAT)
(50.00%)
RAPI SA (62.51%)
Raststaette Glarnerland AG, Niederurnen (20.00%)
RD Petroleum Limited (49.00%)
Resolution Partners LLP (68.00%)e
Rhein-Main-Rohrleitungstransportgesellschaft mbH
(35.00%)
Rio Grande Pipeline Company (30.00%)e
RMF Holdings Limited (49.00%)
Romanian Fuelling Services S.R.L. (50.00%)
Rosneft Oil Company (19.75%)
Routex B.V. (25.00%)
Rudeis Oil Company "RUDOCO" (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%)
Shakti Power Limited (43.20%)
Shandong Dongming Yinglun Petroleum Co., Ltd.
(49.00%)a
Sharjah Aviation Services Co. LLC (49.00%)α
Sharjah Pipeline Company LLC (49.00%)
Shell and BP South African Petroleum Refineries (Pty)
Ltd (37.50%)g
Shell Mex and B.P. Limited (40.00%)α
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%)
Solar Photovoltaic (SPV2) Limited (43.20%)
Solar Photovoltaic (SPV3) Limited (43.20%)
South Caucasus Pipeline Company Limited (28.83%)α
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%)
O´Higgins N° 194, Rio Grande, Argentina
O´Higgins N° 194, Rio Grande, Argentina
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
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
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
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
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
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, United States
Vía de los Poblados1, Madrid, Spain
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Room 01, 08, 09, 10, Floor 11, Block B, , No. 8, Luoyuan Avenue, Lixia District, Jinan City, China
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
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
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
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
269
14. Related undertakings of the group – continued
STDG Strassentransport Dispositions Gesellschaft
mbH (50.00%)
Holstenhofweg 47, 22043 Hamburg, Germany
Sportallee 6, 22335 Hamburg, Germany
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands
Shell Centre, London, SE1 7NA, United Kingdom
Carretera de San Andréss/n, La Jurada-María Jiménez, Santa Cruz de Tenerife, Spain
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
Sportallee 6, 22335 Hamburg, Germany
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Sportallee 6, 22335 Hamburg, Germany
Box 7, 190 45 Arlanda, Sweden
Stockholm Fuelling Services Aktiebolag (25.00%)
Palm Grove House, P.O. Box 438, Road Town, Tortola, British Virgin Islands
Stonewall Resources Ltd. (50.00%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Sula Power Limited (43.20%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Sun and Soil Renewable 12 Limited (43.20%)
Sunrise Oil Sands Partnership (50.00%)e
c/o Husky Oil Operations Limited, 707 - 8th Avenue SW, Calgary AB T2P 1H5, Canada
Birmenstorferstrasse 2, 5507, Mellingen, Switzerland
Tankanlage AG Mellingen (33.33%)
Zwüscheteich, 8153, Rümlang, Switzerland
TAR - Tankanlage Ruemlang AG (27.32%)
Auhafenstrasse 10a, 4132, Muttenz, Switzerland
TAU Tanklager Auhafen AG (50.00%)
Avenida Paulista, 287, 1st floor, room 10, São Paulo, São Paulo, 01311000, Brazil
TCE Participações S.A. (50.00%)
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
Team Terminal B.V. (22.80%)
Tecklenburg GmbH (50.00%)
Wesermünder Straße 1, 27729 Hambergen, Germany
Tecklenburg GmbH & Co. Energiebedarf KG (50.00%)e Wesermünder Straße 1, 27729 Hambergen, Germany
Terminales Canarios, S.L. (50.00%)
Texaco Esso AOC Maatschap (TEAM) (22.80%)e
TFSS Turbo Fuel Services Sachsen GbR (20.00%)e
TGC Solar 106 Limited (43.20%)
TGC Solar 91 Limited (43.20%)
TGFH Tanklager-Gesellschaft Frankfurt-Hahn GbR
(50.00%)e
TGH Tankdienst-Gesellschaft Hamburg GbR (33.33%)e Sportallee 6, 22335 Hamburg, Germany
Sportallee 6, 22335 Hamburg, Germany
TGHL Tanklager-Gesellschaft Hannover-Langenhagen
GbR (50.00%)e
TGK Tanklagergesellschaft Koln-Bonn (25.00%)e
Thames Electricity Limited (43.20%)
The Baku-Tbilisi-Ceyhan Pipeline Company (30.10%)γ
The Consolidated Petroleum Company Limited
(50.00%)α
The Consolidated Petroleum Supply Company Limited
(50.00%)ε
The Sullom Voe Association Limited (33.33%)α
TLK Holding Company LLC (37.04%)a
TLK Intermediate Holding Company LLC (37.04%)a
TLK Operating Company LLC (37.04%)a
TLM Tanklager Management GmbH (49.00%)a
TLS Tanklager Stuttgart GmbH (45.00%)
Tonatiuh Trading 1 Limited (43.20%)
Torsina Oil Company "TORSINA" (37.50%)
TRaBP GbR (75.00%)e
Trafineo GmbH & Co. KG (75.00%)e
Trafineo Service GmbH (75.00%)
Trafineo Verwaltungs-GmbH (75.00%)
Trans Adriatic Pipeline AG (24.57%)
TransTank GmbH (50.00%)
Tricoya Ventures UK Limited (35.56%)
TRTM Inc. (37.04%)
Tuwale Power Limited (43.20%)
TWQE2 Limited (43.20%)
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 (42.33%)
West London Pipeline and Storage Limited (30.50%)
West Morgan Petroleum Company (PETROMORGAN)
(50.00%)
Town Hall, Lerwick, Shetland, ZE1 0HB, 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
Am Tankhafen 4, 4020 Linz, Austria
Zum Ölhafen 49, 70327 Stuttgart, Germany
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
4 Palestine Road, 4th District, New Maadi, Cairo, Egypt
Huestraße 25, 44787, Bochum, Germany
Wittener Straße 56, Bochum, Germany
Wittener Straße 45, 44789 Bochum, Germany
Wittener Straße 56, Bochum, Germany
Lindenstrasse 2, 6340 Baar, Switzerland
Am Stadthafen 60, 45881 Gelsenkirchen, Germany
Brettenham House, 19 Lancaster Place, London, WC2E 7EN, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, 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
Shell Centre, London, SE1 7NA, United Kingdom
Wick Farm Grid Limited (21.60%)
Wiri Oil Services Limited (27.78%)
Yangtze River Acetyls Co., Ltd (51.00%)a
Yermak Neftegaz LLC (49.00%)a
Your Power No. 1 Limited (43.20%)
Your Power No. 10 Limited (43.20%)
Your Power No. 19 Limited (43.20%)
Your Power No. 2 Limited (43.20%)
Your Power No. 3 Limited (43.20%)
Your Power No. 8 Limited (43.20%)
Woodwater House, Pynes Hill, Exeter, England, EX2 5WR
303 Parnell Rd, Parnell, Auckland, New Zealand
97 Weijiang Road (in the Petrochemical Park), Changshou District, Chongqing, China
Kosmodamianskaya nab, 52/3, 115035, Moscow, Russian Federation
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
The parent company financial statements of BP p.l.c. on pages 238-271 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
270
BP Annual Report and Form 20-F 2018
14. Related undertakings of the group – continued
Your Power No12 Limited (43.20%)
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Zubie, Inc. (20.30%)
160 Greentree Drive, Suite 101, Dover, County of Kent DE 19904, United States
a Member interest
b A and B shares
c Common stock and preference shares
d Ordinary shares and preference shares
e Partnership interest
f A, B and D shares
g A shares
h Interest held directly by BP p.l.c.
i 99% held directly by BP p.l.c.
j 1% held directly by BP p.l.c.
k Ordinary, A and B shares
l 0.008% held directly by BP p.l.c.
m Ordinary shares and cumulative redeemable preference shares
n 79.93% ordinary shares and 99.06% preference shares
o Members interest, (49.99%) subordinated units and (4.37%) common units traded on the New York stock exchange
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 Ordinary and A shares
t Ordinary and deferred shares
u Subsidiary undertaking pursuant to sections 1162(2), 1162(3)(b) and Paragraph 6 of Schedule 7 of the Companies Act 2006
v 100% ordinary shares and 58.63% preference shares
w 92.31% B shares and 78.43% D shares
x Preference shares
y 15% held directly by BP p.l.c
z Unlimited redeemable shares
α B shares
β 96.52% C shares
γ 1.89% A shares and 40.80% B shares
δ 43.2% A shares, 43.2% C shares, 43.2% D shares, 43.2% E shares, 43.2% F shares and 43.2% G shares
ε 5% held directly by BP p.l.c
The parent company financial statements of BP p.l.c. on pages 238-271 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 2018
271
THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY
272
BP Annual Report and Form 20-F 2018
Additional
disclosures
274 Selected financial information
277 Liquidity and capital resources
279 Upstream analysis by region
284 Downstream plant capacity
285 Oil and gas disclosures for the group
291 Environmental expenditure
291 Regulation of the group’s business
296 Legal proceedings
298
International trade sanctions
300 Material contracts
300 Property, plant and equipment
300 Related-party transactions
300 Corporate governance practices
300 Code of ethics
300 Controls and procedures
301 Principal accountant’s fees and services
301 Directors’ report information
302 Disclosures required under Listing Rule 9.8.4R
303 Cautionary statement
BP Annual Report and Form 20-F 2017
BP Annual Report and Form 20-F 2018
247
273
A
d
d
i
t
i
o
n
a
l
l
i
d
s
c
o
s
u
r
e
s
Selected financial information
This information has been extracted or derived from the audited consolidated financial statements of the BP group. 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. The audited consolidated financial statements and related notes as of 31 December
2018 and 2017 and for the three years ended 31 December 2018 are presented on page 114.
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
2018
2017
2016
2015
2014
$ million except per share amounts
298,756
19,378
240,208
9,474
183,008
(430)
222,894
(7,918)
353,568
6,412
(2,655)
(7,145)
(195)
9,383
801
(198)
9,986
(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
3,380
3,730
6,746
15,067
8,234
(643)
12,723
(325)
6,166
(3,162)
2,585
(4,000)
5,905
(4,171)
12,136
46.98
46.67
50.00
63.70
40.50
30.568
15,140
9,948
25,088
282,176
101,548
5,402
99,444
56,426
30.3%
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
20.55
20.42
43.90
66.00
39.00
23.850
N/A
N/A
23,192
261,832
98,387
5,049
97,216
46,224
21.6%
284,305
112,642
5,023
111,441
45,977
16.7%
Share million
19,970
20,102
19,693
19,816
18,745
18,855
18,324
18,324
18,385
18,497
a Profit attributable to BP shareholders.
b See pages 276 and 320 for further analysis of these items.
c A reconciliation to GAAP information is provided on page 320.
d From 2017 onwards BP reports 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 consistent with other financial metrics used when comparing sources and uses of cash. An analysis of capital expenditure on a cash basis for 2015 and 2014 is not available.
e The number of ordinary shares shown has been used to calculate the per share amounts.
274
«See Glossary
BP Annual Report and Form 20-F 2018
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
2018
2017
15,140
9,948
25,088
16,501
1,339
17,840
2018
2017
3,482
8,545
12,027
877
1,904
2,781
54
278
332
15,140
4,413
10,727
15,140
2,999
10,764
13,763
809
1,590
2,399
64
275
339
16,501
3,872
12,629
16,501
$ million
2016
16,675
777
17,452
$ million
2016
3,415
10,929
14,344
774
1,328
2,102
32
197
229
16,675
4,221
12,454
16,675
a On 31 October 2018, BP acquired from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy Corporation, a wholly owned subsidiary of BHP
that holds a portfolio of unconventional onshore US oil and gas assets. As at 31 December 2018, $6,788 million of the consideration had been paid. 2018 includes $1,739 million relating to
the purchase of an additional 16.5% interest in the Clair field west of Shetland in the North Sea, as part of the agreements with ConocoPhillips in which ConocoPhillips simultaneously
purchased BP's entire 39.2% interest in the Greater Kuparuk Area on the North Slope of Alaska. 2018 also includes amounts relating to the 25-year extension to our ACG production-sharing
agreement« in Azerbaijan. 2017 includes amounts paid to acquire interests in Mauritania and Senegal and in the Zohr gas field in Egypt.
BP Annual Report and Form 20-F 2018
«See Glossary
275
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 assets
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Other
Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assetsa
Environmental and other provisionsf
Restructuring, integration and rationalization costsc
Fair value gain (loss) on embedded derivatives
Gulf of Mexico oil spill responseg
Other
Total before interest and taxation
Finance costsg
Total before taxation
Taxation credit (charge) on non-operating itemsh
Taxation - impact of US tax reformi
Total after taxation
2018
2017
(90)
(35)
(131)
17
56
(183)
(54)
(83)
(405)
—
(174)
(716)
(95)
—
—
—
—
(95)
(260)
(640)
(190)
—
(714)
(159)
(1,963)
(2,957)
(479)
(3,436)
510
121
(2,805)
(563)
1
(24)
33
(118)
(671)
579
(19)
(171)
—
—
389
—
—
—
—
—
—
(22)
(156)
(72)
—
(2,687)
90
(2,847)
(3,129)
(493)
(3,622)
1,172
(859)
(3,309)
$ million
2016
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)
(5,661)
2,833
—
(2,828)
a See Financial statements – Note 4 for further information.
b 2018 includes an impairment reversal for assets in the North Sea and Angola. 2017 includes an impairment charge relating to BPX Energy (previously known as the US Lower 48 business),
partially offset by gains associated with asset divestments. In addition, 2017 includes an impairment charge arising following the announcement of the agreement to sell the Forties Pipeline
System business to INEOS. 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 group's restructuring programme, originally announced in 2014, has now been completed.
d 2018 and 2017 include exploration write-offs of $124 million and $145 million respectively 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. 2017 also includes BP’s share of an impairment reversal recognized by the Angola LNG equity-accounted entity,
partially offset by other items. 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.
e 2017 primarily reflects the disposal of our shareholding in the SECCO joint venture.
f 2018 primarily reflects charges due to the annual update of environmental provisions, including asbestos-related provisions for past operations, together with updates of non-Gulf of Mexico
oil spill related legal provisions.
g See Financial statements – Note 2 for further details regarding costs relating to the Gulf of Mexico oil spill.
h 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.
i
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. 2018 reflects a further impact following a clarification of the tax reform. 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.
276
«See Glossary
BP Annual Report and Form 20-F 2018
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.
We maintain our progressive dividend policy and the commitment to
the share buyback programme and expect the impact of the scrip
dilution since the third quarter of 2017 to be fully offset by the end of
2019. The shape of the buyback programme will reflect ongoing
consideration 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 continue to cover organic capital expenditure« of
$15-17 billion and the full dividend« (including scrip) 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 per 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 were just over $3 billion in 2018, are
expected to step down to around $2 billion in 2019 and around
$1 billion per annum thereafter. Over the next two years we plan to
complete more than $10 billion of divestments and we expect
divestment proceeds« subsequently to revert to the historical norm
of around $2-3 billion per annum.
We continue to target a gearing« band on a pre-IFRS 16 basis of
20-30%, while maintaining strong liquidity and debt market access.
Payments for the acquisition of BHP’s onshore US assets using
available cash moved gearing to 30.3% at the end of 2018. Gearing is
expected to move towards the middle of the band in 2020 in line with
the generation of free cash flow and receipt of disposal proceeds.
In 2018, the return on average capital employed« was 11.2%a at an
average of $71 per barrel. At $55 per barrel real, return on average
capital employed is targeted to improve to over 10% by 2021, as we
continue to grow our underlying business.
a Nearest equivalent GAAP measures: Numerator – Profit attributable to BP shareholders
$9.4 billion; Denominator – Average capital employed $165.5 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 increased to 10.25 cents per share from the
third quarter of 2018 (2017 10 cents per share).
The total dividend distributed to BP shareholders in 2018 was
$8.1 billion (2017 $7.9 billion). Shareholders have the option to receive
a scrip dividend in place of receiving cash. In 2018 the total dividend
paid in cash was $6.7 billion (2017 $6.2 billion).
Details of share repurchases to satisfy the requirements of certain
employee share-based payment plans are set out on page 312. The
share buyback programme to offset the dilutive impact of the scrip
dividend purchased 50 million ordinary shares in 2018 at a cost of
$355 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. 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 55 for further information
on risks associated with prices and markets and Financial
statements – Note 29.
The group’s gross debt at 31 December 2018 amounted to
$65.8 billion (2017 $63.2 billion). Of the total gross debt, $9.4 billion is
classified as short term at the end of 2018 (2017 $7.7 billion). See
Financial statements – Note 26 for more information on the short-
term balance. Net debt« was $44.1 billion at the end of 2018, an
increase of $6.3 billion from the 2017 year-end position of $37.8 billion.
The ratio of gross debt to gross debt plus equity at
31 December 2018 was 39.3% (2017 38.6%). The ratio of net debt to
net debt plus equity« was 30.3% at the end of 2018 (2017 27.4%).
See Financial statements – Note 27 for gross debt, which is the
nearest equivalent measure on an IFRS basis, and for further
information on net debt.
Cash and cash equivalents of $22.5 billion at 31 December 2018 (2017
$25.6 billion) are included in net debt. We manage our cash position
to ensure the group has adequate cover to respond to potential short-
term market illiquidity, and expect to maintain a robust cash position.
The group also has undrawn committed bank facilities of $7.6 billion
(see Financial statements – Note 29 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.
BP utilizes various arrangements in order to manage its working
capital including discounting of receivables and, in the supply and
trading business, the active management of supplier payment terms,
inventory and collateral.
Standard & Poor’s Ratings’ long-term credit rating for BP is A- (stable
outlook) and the Moody’s Investors Service rating is A1 (stable
outlook).
The group’s sources of funding, its access to capital markets and
maintaining a strong cash position are described in Financial
statements – Note 25 and Note 29. On 14 December 2018, BP
completed the exchange of $10.5 billion of notes previously issued by
BP Capital Markets p.l.c for new notes issued by BP Capital Markets
America Inc. in order to optimize the BP group’s capital structure and
align revenue generation to indebtedness. 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 26 and Note 29.
Off-balance sheet arrangements
At 31 December 2018, the group’s share of third-party finance debt of
equity-accounted entities was $16.1 billion (2017 $18.0 billion). These
amounts are not reflected in the group’s debt on the balance sheet.
The group has issued third-party guarantees under which amounts
outstanding, incremental to amounts recognized on the balance
sheet, at 31 December 2018 were $696 million (2017 $656 million) in
respect of liabilities of joint ventures«and associates«and $432
million (2017 $382 million) in respect of liabilities of other third parties.
Of these amounts, $684 million (2017 $645 million) of the joint
ventures and associates guarantees relate to borrowings and for
other third-party guarantees, $423 million (2017 $350 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 28.
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 303 and Risk factors on page 55, 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 2018
«See Glossary
277
Contractual obligations
The following table summarizes the group’s capital expenditure commitments for property, plant and equipment at 31 December 2018 and the
proportion of that expenditure for which contracts have been placed.
Capital expenditure
Committed
of which is contracted
Total
26,378
8,319
2019
12,749
5,646
2020
5,689
1,742
2021
3,456
528
2022
1,653
157
2023
1,001
53
2024 and
thereafter
1,830
193
$ 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 2018, the group had committed to capital expenditure relating to investments in equity-accounted entities
amounting to $1,411 million. Contracts were in place for $1,170 million of this total.
The following table summarizes the group’s principal contractual obligations at 31 December 2018, 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 26 and more information on operating leases is given in Financial statements – Note 28.
$ million
Payments due by period
Expected payments by period under contractual obligations
Total
2019
2020
2021
2022
2023
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
74,587
1,350
23,807
1,663
18,360
19,114
138,881
11,979
144,660
156,639
295,520
11,607
98
290
300
2,302
1,237
15,834
2,511
69,676
72,187
88,021
8,646
97
169
303
1,569
1,211
11,995
1,875
16,422
18,297
30,292
8,410
95
107
219
1,343
1,149
11,323
1,446
11,479
12,925
24,248
9,385
94
339
173
1,267
1,084
12,342
1,124
8,326
9,450
21,792
2024 and
thereafter
28,429
880
22,806
532
10,660
13,366
76,673
8,110
86
96
136
1,219
1,067
10,714
914
4,109
6,715
7,629
18,343
32,042
36,151
112,824
a Expected payments include interest totalling $10,646 million ($2,350 million in 2019, $1,904 million in 2020, $1,653 million in 2021, $1,379 million in 2022, $1,101 million in 2023 and $2,259
million thereafter).
b Expected payments include interest totalling $683 million ($54 million in 2019, $51 million in 2020, $47 million in 2021, $43 million in 2022, $37 million in 2023 and $451 million thereafter).
c The amounts presented 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 2019 include purchase commitments existing at 31 December 2018
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 29.
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
62,801
27,642
6,715
5,573
1,037
21,682
19,210
144,660
2019
43,265
14,916
4,857
3,296
163
1,740
1,439
69,676
2020
6,395
4,922
923
1,087
138
1,480
1,477
16,422
2021
4,679
2,880
298
494
80
1,580
1,468
11,479
2022
2,769
2,325
291
158
64
1,412
1,307
8,326
$ million
Payments due by period
2023
2,356
1,555
118
113
64
1,412
1,097
6,715
2024 and
thereafter
3,337
1,044
228
425
528
14,058
12,422
32,042
278
«See Glossary
BP Annual Report and Form 20-F 2018
Upstream analysis by region
Our upstream operations are set out below by geographical area, with
associated significant events for 2018. 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 liquefied natural gas
(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 3.5 million tonnes per
annum of our LNG production to IST, which uses contractual rights to
access import terminal capacity in the liquid markets of Italy (Rovigo),
the Netherlands (Gate), Spain (Bilbao), the UK (the Isle of Grain) and
the US (Cove Point), with the remainder marketed directly to
customers. LNG is supplied to customers in markets including
Argentina, China, the Dominican Republic, India, Japan, Kuwait, South
Korea, Taiwan and Thailand.
Europe
BP is active in the North Sea and the Norwegian Sea. In 2018 BP’s
production came from three key areas: the Shetland area comprising
the Clair, Foinaven, Magnus and Schiehallion fields; the central area
comprising the Andrew area, Bruce, ETAP, Keith, Kinnoull and Rhum
fields; and Norway, through our equity accounted 30% interest in
Aker BP.
• In July we announced that we had entered into an agreement with
ConocoPhillips to increase our holding in the Clair field (prior to the
increase BP 29% and operator) by 16.5%, while selling our non-
operated interest in the Greater Kuparuk Area on the North Slope
of Alaska as well as our holding in the Kuparuk Transportation
Company. Clair is the largest oilfield on the UK Continental Shelf.
The transaction completed in December.
• In September we received approval from the Oil and Gas Authority
(OGA) to proceed with the Vorlich development (BP 66% and
operator). Located 240 kilometres east of Aberdeen, in the central
North Sea, Vorlich will consist of two wells tied back to the existing
Ithaca Energy-operated FPF-1 floating production facility. The
development is part of a programme of North Sea subsea tie-back
developments that seek to access new production from fields
located near to established producing infrastructure. The field is
expected to come onstream in 2020.
• In October EnQuest notified BP that it would exercise its option to
acquire the remaining 75% of BP’s stake in the Magnus field and
associated infrastructure. The disposal completed at the end of
November. EnQuest acquired the initial 25% of BP’s interest in the
Magnus field and associated infrastructure in December 2017.
• Also in October we received approval from OGA to proceed with
the Alligin development (BP 50% and operator). Located 140
kilometres west of Shetland, Alligin is part of the Greater
Schiehallion area. We announced our intention to develop it in April.
The development will consist of two wells tied back to the existing
Schiehallion and Loyal subsea infrastructure, and is expected to
come onstream in 2020.
• Development progressed at the Total-operated Culzean field (BP
32%) during the year. The field will be developed with three fixed
platforms and a floating storage unit. At the end of 2018,
construction activities were complete and the hook-up and
commissioning activities were underway, with first production
expected in 2019.
• In November 2017 we announced that we had agreed to sell a
package of our interests in the North Sea comprising the Bruce (BP
37%), Keith (BP 35%) and Rhum (BP 50%) fields, three bridge-
linked platforms and associated subsea infrastructure to Serica
Energy plc. We operated the assets through the year until the sale
and transfer of ownership completed at the end of November 2018.
• In November as part of the sale of Rhum to Serica Energy plc the
US Office of Foreign Assets Control issued a joint licence to BP
and Serica permitting certain US persons and US owned and
controlled companies to support Rhum activities in compliance
with US primary sanctions and a letter of comfort permitting all
non-US persons to support Rhum activities in compliance with US
secondary sanctions. The Rhum field is now owned by Serica
(50%) and the Iranian Oil Company (U.K.) Limited (IOC, 50%) under
a joint operating agreement. The shares in IOC are now held in
trust. See International Trade Sanctions on page 298.
• In November we announced the start-up of production at Clair
Ridge – the second phase of development at the Clair field. Two
new, bridge-linked platforms and oil and gas export pipelines have
been constructed as part of the project. The new facilities, which
required capital investment in excess of $6 billion, are designed for
around 40 years of production.
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 240 lease blocks in the deepwater Gulf of Mexico and
operates four production hubs.
• In October we announced the start-up of the Northwest Expansion
project at our Thunder Horse platform, under budget and ahead of
schedule. The project, which achieved first oil just 16 months after
being sanctioned, adds a new subsea manifold and two wells tied
into existing flowlines two miles to the north of the platform. The
new project is expected to boost production at Thunder Horse and
is the third major field expansion there in recent years.
• We participated in lease sales 250 and 251 during the year, and
were awarded 44 leases in total.
• In December BP received approval from the Bureau of Safety
Environmental Enforcement of the assignment of Chevron’s
interest in the Tiber and Guadalupe leases. BP now has a 100%
working interest in these leases.
• Exploration write-offs totalling $447 million were recognized in
2018, driven primarily by lease relinquishment ($131 million of this
was recognized as a non-operating item).
• In February 2019 we announced the start-up of the Constellation
project (BP 66.67%), operated by Anadarko.
• See also Financial statements – Note 1 for further information on
exploration leases.
The US Lower 48 onshore new combined business, following
acquisition of BHP's unconventional assets (see below), has
significant operated and non-operated activities across Colorado,
Louisiana, New Mexico, Oklahoma, Texas and Wyoming producing
natural gas, oil, NGLs and condensate. It had a 2.4 billion boe proved
reserve base as at 31 December 2018, predominantly in
unconventional reservoirs (tight gas«, shale gas and coalbed
methane, and newly acquired shale oil). This resource spans 3.5
million net developed acres and has approximately 12,000 operated
gross wells, with daily net production around 500mboe/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. With its own governance, systems and
processes, it was established to increase competitive performance
through swift decision making and innovation, while maintaining BP’s
commitment to safe, reliable and compliant operations. In October
2018 we announced that we had changed the name of our Lower 48
business to BPX Energy.
• In October we completed the acquisition of BHP’s US
unconventional assets in a landmark deal that will significantly
upgrade our US onshore oil and gas portfolio and help drive long-
term growth. The acquisition, which was announced in July, adds
oil and gas production of 190mboe/d in the liquids-rich regions of
BP Annual Report and Form 20-F 2018
«See Glossary
279
the Permian and Eagle Ford basins in Texas and in the Haynesville
natural gas basin in East Texas and Louisiana.
offshore exploration licences in Nova Scotia, Newfoundland and
Labrador and the Canadian Beaufort Sea.
• As part of the BHP acquisition announcement, BPX Energy expects
to divest some existing assets to shift the organization’s core focus
towards the newly-acquired BHP assets. The divestment includes
core positions in San Juan, Wamsutter, Anadarko, Arkoma, legacy
East Texas and Southwest Oklahoma basins, as well as diversified
non-operated royalty and working interests across the US Lower
48.
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.
For the past four years BP has slowed decline at Prudhoe Bay through
wellwork and improved operating field efficiencies, with production
being largely maintained. Infrastructure renewal activities in 2018
included compressor replacements, fire and gas system upgrades,
safety system upgrades, pipeline renewal, and facility piping upgrade
projects. BP owns significant interests in three producing fields
operated by others, as well as a non-operating interest in the Liberty
development project and owned significant interests in an additional
five producing fields operated by others prior to the sale of our
interest in the Greater Kuparuk Area (see below).
• In July we announced the sale of our non-operated 39.2% interest
in the Greater Kuparuk Area on the North Slope comprising five
fields, as well as our holding in the Kuparuk Transportation
Company to ConocoPhillips. The transaction received all regulatory
approvals and closed in December, with a retroactive effective date
of 1 July 2018.
• In May 2018 BP signed a Gas Sales Precedent Agreement with the
Alaska Gas Development Corporation detailing key terms for
potential future gas sales to the State. In addition, in September an
amendment to the Point Thomson development plan was agreed
with the State to better align field milestones to those of the
Alaska LNG project.
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
southcentral 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
pending legal challenges involving TAPS interstate rates at FERC
for the years 2009-15 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 resolved all challenges involving TAPS intrastate
rates from 2008 to 2019 and established intrastate rate ceilings for
the future through to 30 June 2019. RCA approval was granted in
January and FERC approval in February and all associated
settlement amounts and tariff refunds were paid.
• In September BP Alaska removed one of its four Alaska grade
crude oil tankers from service (the vessel Frontier). Historically, BP
Alaska has utilized four tankers to carry crude oil shipments from
Alaska. With the reduction in volume over time, as well as new
efficiencies identified in the shipping programme, Frontier has
been removed from service and its carrying value impaired
accordingly.
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
• The government of Canada continued with its plans to introduce
legislation to allow it to suspend any oil and gas activities in the
Beaufort Sea.
In Mexico, we have interests in two exploration joint operations« in
the Salina Basin with Equinor and Total, Block 1 (BP 33% and
operator) and Block 3 (BP 33%), and in one exploration joint operation
in the Sureste Basin with Total and Hokchi, a subsidiary of Pan
American Energy Group (PAEG), Block 34 (BP 42.5% and operator).
Both Salina Basin operations received exploration plan approval in
March from Comisión Nacional de Hidrocarburos (CNH), the Mexican
regulator. Seismic interpretation and well pre-spud activities are
taking place in 2018 and 2019 with the tentative plan to commence
drilling in the first half of 2020. The Sureste Basin operation submitted
an exploration plan for approval to CNH at the end of December.
South America
BP has upstream activities in Brazil and Trinidad & Tobago and through
PAEG, in Argentina and Bolivia.
In Brazil BP has interests in 25 exploration concessions across five
basins.
• In the North Campos basin, BP was nominated as operator
following Anadarko's withdrawal from both the BM-C-30 and BM-
C-32 blocks. Regulatory consent is being sought for both
Anadarko's exit and the operatorship transfer. The consortium
decided not to perform the previously planned extended well test
during the year. Instead it elected to finalize the appraisal plans and
request a postponement of up to five years to decide whether the
projects are commercially feasible. During this period, the
consortium will assess alternative development concepts. Approval
of this request by the Brazilian National Petroleum Agency (ANP) is
still pending.
• BP continues to progress the preparatory activities for drilling
exploration wells in the Foz do Amazonas Basin, with a BP-
operated well scheduled to start drilling in 2021. An extension
request to August 2020 was approved by the ANP regarding the
BP-operated Block FZA-M-59. BP is monitoring developments on
its other non-operated interests in the Foz de Amazonas basin (BP
30%) to establish an expected drilling activity schedule.
• In the South Campos basin, BP's request for a contract suspension
in Block BM-C-35 is under review by the ANP.
• BP won Blocks C-M-755 and C-M-793 at the 15th bid round in
March in a consortium with Equinor (BP 60%).
• In June BP won the licence for the Dois Irmãos block located in the
Campos basin, offshore Brazil, as a result of the fourth Pre-Salt
Production Sharing Contract Bid Round (Petrobras operator 45%,
BP 30%, and Equinor 25%).
• BP accessed new acreage in the Santos basin, offshore Brazil in
September by winning the licence for the Pau Brasil block (BP 50%
and operator). This represents BP’s first operated production
sharing acreage in the Santos basin.
• In October drilling commenced at the Peroba block (BP 40%). Well
results are expected in the first quarter of 2019.
In Argentina and Bolivia BP conducts activity through PAEG, a joint
venture that is owned by BP (50%) and Bridas Corporation (50%).
PAEG also has activities in Mexico.
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
train 1, 2 and 3 and process gas in train 4. All LNG from train 1 and
most of the LNG from trains 2 and 3 is sold to third parties under
280
«See Glossary
BP Annual Report and Form 20-F 2018
long-term contracts. BP’s LNG entitlement from trains 2, 3 and 4 is
marketed to the US, Europe, Asia and South America.
• The Atoll field in the North Damietta concession came fully
onstream at the start of 2018.
• In December, the Cassia compression project was sanctioned. This
project involves the installation of a new compression platform
(Cassia C), bridge-linked to the Cassia B processing platform and
providing lowered wellhead pressures to fields served by the Cassia
hub. The expected project start-up date is 2021.
• Negotiations of three historical upstream commercial issues were
completed with the government of the Republic of Trinidad &
Tobago at the end of 2018. This resulted in a payment of $144
million representing final settlement.
• The Atlantic LNG Train 1 gas supply contract is currently being
negotiated for the period April 2019 to September 2024.
• Discussions are ongoing with partners in the Manakin project on the
Unit Operating Agreement (UOA), Field Development Plan and
subsurface arrangements following declaration of commerciality in
January 2018. The UOA is expected to be agreed in 2019. Manakin,
discovered in 1998, is a cross-border field with Venezuela.
• In October the Bongos exploration well in the deepwater Block 14
(BP 30%) was announced as a discovery. Assessment of the well
results is currently in progress.
• The Angelin project, sanctioned in June 2017, involves the
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 includes four
wells, with gas from Angelin flowing to the Cassia B hub for
processing via a new pipeline to the Serrette platform. During 2018
the jacket and topsides were installed and subsea skid and pipeline
installation was also completed. The first well was completed in
January 2019 and the project commenced production in February
2019.
Africa
BP’s upstream activities in Africa are located in Algeria, Angola, Côte
d'Ivoire, Egypt, Libya, Madagascar, Mauritania, São Tomé & Príncipe
and Senegal.
In Algeria BP, Sonatrach and Equinor 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.
• In December 2017 BP and Equinor signed an extension agreement
for the In Amenas production sharing contract with Sonatrach, the
Algerian state-owned energy company. The agreement was
formally ratified in April 2018.
In Angola, BP owns an interest in five 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%).
• During the year a final investment decision (FID) on Block 17 was
made by the operator, Total, to proceed with the Zinia 2 deep
offshore development project (BP 16.67%).
• In December, BP announced it had taken the FID to progress the
Platina project in Block 18. The agreement also extends the
production licence for the Greater Plutonio operation in Block 18 to
2032, and provides for Sonangol to take an 8% equity interest in
the block, all subject to government approval.
• The Block 25/11 production sharing agreement expired in January
2019. The remaining intangible asset of $42 million associated with
the licence acquisition cost was written off at the start of 2018 as
no further drilling activity was planned.
In Côte d’Ivoire, BP has interests in five offshore oil blocks with
Kosmos Energy (KE) 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% and
operator, PETROCI approximately 10%). New 3D seismic data was
acquired during the year and analysis of it is ongoing.
In Egypt, BP and its partners currently produce 10% of Egypt’s
liquids« production and over 50% of its gas production.
• In 2018 exploration write-offs of $236 million were recognized, the
most significant being $169 million in connection with withdrawal
from the Rahamat lease.
• Following concept sanction in 2017, BP continued progressing the
Baltim South West field. Two wells are planned in 2019 followed by
further development wells in 2020. A new nine-slot platform will be
installed and tied back to existing infrastructure (Abu Madi) through
a new offshore and onshore pipeline.
• In December BP announced it had acquired a 25% interest in the
Nour North Sinai offshore concession area from Eni. The
concession is in the East Nile Delta Basin. Eni, the operator, is
currently carrying out drilling of the first exploration well and will
remain the operator with a 40% stake in the concession. BP will
hold a 25% interest, Mubadala Petroleum 20% and Tharwa
Petroleum Company 15%.
• In February 2019 BP announced the start-up of gas production from
the Giza and Fayoum fields in the West Nile Delta development (BP
82.75%). 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. The
first of these three projects (Taurus and Libra) started production in
2017, Giza and Fayoum is the second, and the third project (Raven)
is expected to be onstream in 2019.
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%).
BP wrote off all balances associated with the Libya EPSA in 2015.
• In October we announced that we had signed an agreement with
the Libyan National Oil Corporation and Eni with a view to working
together to resume exploration activities in Libya. The parties have
agreed to work towards Eni acquiring a 42.5% interest in the BP-
operated EPSA in Libya. On completion, Eni would also become
operator of the EPSA. The companies are working to finalize and
complete all agreements with a target of resuming exploration
activities in 2019.
In Mauritania and Senegal, BP has a 62% participating interest in the
C-6, C-8, C-12 and C-13 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 33,000 square kilometres. BP also has a 15% interest
in the C-18 exploration block, operated by Total.
• In February KE announced that the Requin Tigre-1 well in the Saint
Louis Profond Block, offshore Senegal, was fully tested but did not
encounter hydrocarbons.
• In December BP and partners announced that the FID for Phase 1
of the cross-border Greater Tortue Ahmeyim development had
been agreed. The decision was made following agreement
between the Mauritanian and Senegalese governments and
partners BP, KE and National Oil Companies, Petrosen and
SMHPM. The project will produce gas from an ultra-deepwater
subsea system and mid-water floating production, storage and
offloading (FPSO) vessel. The gas will then be transferred to a
floating liquefied natural gas (FLNG) facility at a near-shore hub
located on the Mauritania and Senegal maritime border. The FLNG
facility is designed to provide approximately 2.5 million tonnes of
LNG per annum on average. The project, the first major gas project
to reach FID in the basin, is planned to provide LNG for global
export as well as making gas available for domestic use in both
Mauritania and Senegal. First gas for the project is expected in
2022.
In Madagascar, BP signed four production-sharing contracts (PSC) in
2018 for exploration licences situated offshore northwest
Madagascar, under agreements with the government of Madagascar
represented by Office des Mines Nationales et des Industries
Stratégiques (OMNIS) (BP 100%).
BP Annual Report and Form 20-F 2018
«See Glossary
281
In São Tomé & Príncipe, BP and KE were awarded two offshore
blocks in March 2018, under production-sharing agreements with the
government of São Tomé & Príncipe represented by Agência Nacional
do Petróleo de São Tomé e Príncipe (ANP-STP) (BP 50% (operator), KE
35% ANP-STP 15%). During the year work began on environmental
baseline surveys, with completion anticipated in the second half of
2019.
capacity of the pipeline during the first phase is 106mboe/d and the
average throughput in 2018 was 30mboe/d. The second phase will
take gas from Eskishehir to the connection with the Trans Adriatic
Pipeline (TAP) in Greece. BP has a 20% interest in TAP, that will take
gas through Greece and Albania into Italy. In December TAP entered
into project financing arrangements with multiple lenders. BP's share
of the funds received as a result of financing is $594 million.
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 640,000 cubic metres. The project is supplied under a
long-term contract with Australia’s North West Shelf venture (BP
16.67%).
• BP has two PSCs for shale gas exploration, development and
production in the Neijiang-Dazu block and Rong Chang Bei block in
the Sichuan basin. The two blocks, both in the exploration phase,
cover a total area of approximately 2,500 square kilometres. China
National Petroleum Corporation (CNPC) is the operator. In 2018,
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 were lifted or suspended as part of the Joint
Comprehensive Plan of Action. However, in November the US
secondary sanctions were reinstated. For further information see
International trade sanctions on page 298.
• In April we announced that we had signed a new PSA with the
State Oil Company of Azerbaijan Republic (SOCAR) for the joint
exploration and development of Block D230 in the North Absheron
basin. The block lies 135 kilometres north-east of Baku in the
Caspian Sea, covering an area of 3,200 square kilometres. Under
the PSA, which is for 25 years, BP will be the operator during the
exploration phase and hold a 50% interest, with SOCAR holding
the remaining 50%. The signing of the PSA follows the
memorandum of understanding for exploration of Block D230,
which was agreed in May 2016.
• In July we announced the start-up of the landmark Shah Deniz
Stage 2 gas development in Azerbaijan, including its first
commercial gas delivery to Turkey. The BP-operated $28 billion
project is the first subsea development in the Caspian Sea and the
largest subsea infrastructure operated by BP worldwide. It is also
the starting point for the Southern Gas Corridor series of pipelines
that will deliver natural gas from the Caspian Sea direct to
European markets for the first time.
BP holds a 30.1% interest in and operates the Baku-Tbilisi-Ceyhan 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 2018 of 697mboe/d.
BP is technical operator of, and currently holds a 28.83% interest in,
the 693 kilometre South Caucasus Pipeline. The pipeline takes gas
from Azerbaijan through Georgia to the Turkish border and has a
capacity of 143mboe/d, with average throughput in 2018 of
142mboe/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 76mboe/d in 2018.
BP also holds a 12% interest in the Trans Anatolian Natural Gas
Pipeline. In the first phase, which commenced in June, gas from
Shah Deniz is transported from Georgia to Eskishehir in Turkey. The
In Oman BP operates the Khazzan field in Block 61 (BP 60%).
• In April BP announced that, together with its partner the Oman Oil
Company Exploration & Production (OOCEP), it had approved the
development of Ghazeer, the second phase of the Khazzan gas
field in Oman. The Ghazeer project is expected to increase
production by 50% and will involve construction of a third gas
processing train to handle this. The project is currently on track to
deliver first gas as planned in 2021.
• In January 2019 BP announced that together with Eni, they had
signed a heads of agreement (HoA) with the Ministry of Oil and
Gas of the Sultanate of Oman to work jointly towards a significant
new exploration opportunity in Oman. Under the HoA, the two
companies will work with the government of Oman towards the
award of a new EPSA for Block 77 in central Oman. BP and Eni
have entered discussions with the Ministry to finalise details of the
EPSA. Block 77, with a total area of almost 3,100 square
kilometres, is located in central Oman, 30 kilometres east of the
BP-operated Block 61.
In Abu Dhabi, BP holds a 10% interest in the ADNOC onshore
concession. We also have a 10% equity shareholding in ADNOC LNG
and a 10% shareholding in the shipping company NGSCO. ADNOC
LNG supplied approximately 5.4 million tonnes of LNG (729bcfe
regasified) in 2018. Our interest in the ADNOC onshore concession
expires at the end of 2054.
•
In March 2019 ADNOC and ADNOC LNG agreed to extend the
gas supply agreement to 2040. The new agreement will take
effect from 1 April 2019, and replaces an existing agreement
expiring on 31 March 2019.
Our interest in the ADNOC offshore concession expired in March
2018. The concession, together with all related rights and obligations,
has reverted back to the government of the Emirate of Abu Dhabi.
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. Target performance for the 2017-18
plan was delivered and implementation of the 2018-19 plan is
underway.
In India we have a participating interest in two oil and gas PSAs (KG
D6 30% and NEC25 33.33%) both operated by Reliance Industries
Limited (RIL). We also have a stake in a 50:50 joint venture (India Gas
Solutions Private Limited) with RIL for the sourcing and marketing of
gas in India.
• In April BP and RIL sanctioned the Satellite Cluster project in Block
KG D6. This is the second of three projects in the Block KG D6
integrated development. The first of the projects, development of
the R-Series deep-water gas fields, was sanctioned in June 2017
and is currently under development. The Satellite Cluster is a dry
gas development and comprises four discoveries with a five-well
subsea development in Block KG D6, off the east coast of India. It is
expected to come on stream in 2021.
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.
• In January 2018 BP entered into a letter of intent to work on the
Kirkuk field which extends until 2019.
In Russia in addition to its 19.75% equity interest in Rosneft, BP
holds a 20% interest in Taas-Yuryakh Neftegazodobycha (Taas)
together with Rosneft (50.1%) and a consortium comprising Oil India
Limited, Indian Oil Corporation Limited and Bharat PetroResources
Limited (29.9%). Taas is developing the Srednebotuobinskoye oil and
gas condensate field in East Siberia (see Rosneft on page 34 for
further details). Also with Rosneft, we hold a 49% interest in Yermak
282
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BP Annual Report and Form 20-F 2018
Neftegaz LLC, which conducts exploration in the West Siberian and
Yenisei-Khatanga basins. Yermak Neftegaz LLC currently holds seven
exploration and production licences. The venture has carried out
further appraisal work on the Baikalovskoye field, an existing Rosneft
discovery in the Yenisei-Khatanga area of mutual interest.
• In the second quarter, the Taas-Yuryakh expansion project
completed commissioning of the main project facilities for the
Srednebotuobinskoye oil and gas condensate.
• Also in the second quarter BP acquired a 49% stake in
LLC Kharampurneftegaz to develop subsoil resources jointly with
Rosneft within the Kharampurskoe and Festivalnoye licence areas in
Yamalo-Nenets.
• In September Rosneft and BP also agreed to jointly explore two
additional oil and gas licence areas located in Sakha (Yakutia). The
licences are expected to be held by a Yermak subsidiary. Completion
of the deal, subject to external approvals, is expected in 2019.
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.
• The Browse project participants finalized evaluating a range of
development options for the project and have selected to develop
Browse by connecting it via a 900 kilometre pipeline to the NWS
venture's Karratha gas plant. A final investment decision is
expected in 2021. This decision has resulted in the write-off of $136
million in relation to previous project development costs for
Browse.
• In October we announced the start-up of production at our Western
Flank B project (BP 16.67%), ahead of schedule.
• During the year, the Ocean Great White rig contract was cancelled
and a commercial arrangement entered into with the lessor
whereby BP will utilize different rigs on projects in the future.
In Papua Barat, Eastern Indonesia, BP operates the Tangguh LNG
plant (BP 40.22%). The asset currently comprises 16 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,
Mexico, China, South Korea, and Japan through a combination of
long, medium and short-term contracts.
• The Tangguh expansion project is progressing on schedule with the
installation of two offshore platforms completed and the
construction of the onshore LNG production train and supporting
facilities currently ongoing. Drilling on the first of 13 new
production wells commenced in early 2019, and first production is
expected in 2020. The project will add 3.8 million tonnes per
annum (mtpa) of production capacity to the existing facility,
bringing total plant capacity to 11.4mtpa.
• In November approval from the government of Indonesia to
relinquish BP’s 32% interest in the Chevron-operated West Papua I
was received.
BP Annual Report and Form 20-F 2018
«See Glossary
283
Downstream plant capacity
The following tablea summarizes BP group’s interests in refineries and average daily crude distillation capacities as at 31 December 2018.
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
Bayernoild
Gelsenkirchen
Lingen
Rotterdam
Castellón
Australia
New Zealand
South Africa
Kwinana
Whangareid e
Durband
Total BP share of capacity at 31 December 2018
a This does not include BP’s interest in Pan American Energy Group, which is reported through the Upstream segment.
b Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period.
c BP share of equity, which is not necessarily the same as BP share of processing entitlements.
d Indicates refineries not operated by BP.
e 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 2018.
Crude distillation capacitiesb
Group interestc
(%)
BP share
thousand barrels
per day
100
100
50
10
100
100
100
100
100
10.1
50
236
430
80
746
22
265
95
377
110
869
152
33
90
275
1,890
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
91.9
100
34-51
70
50
61.4
Total BP share of capacity at 31 December 2018
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.
284
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BP Annual Report and Form 20-F 2018
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 2018 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, or where there are significant
commitments on delivery to the relevant authority.
Over the past five years, BP has annually progressed a weighted
average 19% (18% for 2017 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 2018 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 2018 we progressed 1,306mmboe of proved undeveloped reserves
(745mmboe for our subsidiaries« alone) to proved developed
reserves through ongoing investment in our subsidiaries’ and equity-
accounted entities’ upstream development activities. Total
development expenditure, excluding midstream activities, was
$14,210 million in 2018 ($9,917 million for subsidiaries and $4,293
million for equity-accounted entities). The major areas with
progressed volumes in 2018 were Russia, US, Azerbaijan, UAE and
Egypt. 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 net positive revisions to our proved undeveloped
resources in Russia as a result of development drilling results and
material net negative revisions in the US Lower 48 due to changes in
our development plan to incorporate activity associated with the
purchase of new assets. 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 2018
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
2018
Subsidiaries only
Proved undeveloped reserves at 1 January 2018
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
2018
volumes in mmboea
8,060
20
311
646
1,174
(12)
2,139
15
(1,306)
8,908
volumes in mmboea
4,052
(272)
297
169
945
(12)
1,128
12
(745)
4,447
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
BP Annual Report and Form 20-F 2018
«See Glossary
285
reserves assessment that relies on the integration of three types of
data:
• well data used to assess the local characteristics and conditions of
reservoirs and fluids
• 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 35 years of diversified industry
experience, with 13 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 2018, 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 2018. 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.
Netherland, Sewell & Associates (NSAI), 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 2018, of certain properties owned by BP in the US
Lower 48. The properties evaluated by NSAI account for 100% of BP’s
net proved reserves in the US Lower 48 as of 31 December 2018. The
net proved reserves estimates prepared by NSAI 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 NSAI’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
89% of our total proved reserves of subsidiaries at
31 December 2018 were held through joint operations«(88% in
2017), and 31% of the proved reserves were held through such joint
operations where we were not the operator (34% in 2017).
286
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BP Annual Report and Form 20-F 2018
Estimated net proved reserves of crude oil at
31 December 2018a 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
223
—
962
43
8
223
1,126
30
2,615
3,541
6,156
243
—
802
190
5
36
482
5
1,763
2,792
4,555
Estimated net proved reserves of natural gas liquids at
31 December 2018a b
UK
Rest of Europe
US
Rest of North America
South America
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entities
Total
Developed
Undeveloped
8
—
266
—
2
14
—
5
295
114
409
6
—
246
—
25
4
—
—
280
54
335
million barrels
Total
466
—
1,764
234
14
259
1,608
34
4,378
6,333
10,711
million barrels
Total
14
—
511
—
27
18
—
5
576
169
744
Estimated net proved reserves of liquids«
Subsidiariesf
Equity-accounted entitiesg
Total
Developed
Undeveloped
2,910
3,655
6,565
2,044
2,846
4,890
million barrels
Total
4,954
6,502
11,456
Estimated net proved reserves of natural gas at
31 December 2018a b
UK
Rest of Europe
US
Rest of North America
South Americah
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entitiesi
Total
billion cubic feet
Developed Undeveloped
439
—
6,270
—
2,168
1,313
3,599
2,630
16,420
9,515
25,934
343
—
5,056
—
3,073
1,067
3,218
1,179
13,936
9,369
23,305
Total
782
—
11,326
—
5,241
2,380
6,817
3,809
30,355
18,884
49,239
Estimated net proved reserves on an oil equivalent basis
Subsidiaries
Equity-accounted entities
Total
million barrels of oil equivalent
Developed
5,741
5,296
11,037
Undeveloped
4,447
4,462
8,908
Total
10,188
9,757
19,945
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 2018 marker prices used were Brent« $71.43/bbl (2017 $54.36/bbl and 2016 $42.82/
bbl) and Henry Hub« $3.10/mmBtu (2017 $2.96/mmBtu and 2016 $2.46/mmBtu).
c Includes condensate.
d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16 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 12 million barrels of liquids in respect of the 30% non-controlling interest in BP
Trinidad and Tobago LLC.
g Includes 356 million barrels of liquids in respect of the non-controlling interest in Rosneft
held assets in Russia including 24 million barrels held through BP’s interests in Russia other
than Rosneft.
h Includes 1,573 billion cubic feet of natural gas in respect of the 30% non-controlling
interest in BP Trinidad and Tobago LLC.
i
Includes 1,211 billion cubic feet of natural gas in respect of the non-controlling interest in
Rosneft held assets in Russia including 480 billion cubic feet held through BP’s interests in
Russia other than Rosneft.
Because of rounding, some totals may not agree exactly with the
sum of their component parts.
Proved reserves replacement
Total hydrocarbon proved reserves at 31 December 2018, on an oil
equivalent basis including equity-accounted entities, increased by 8%
(increase of 7% for subsidiaries and increase of 9% for equity-
accounted entities) compared with 31 December 2017. Natural gas
represented about 43% (51% for subsidiaries and 33% for equity-
accounted entities) of these reserves. The change includes a net
increase from acquisitions and disposals of 1,498mmboe (increase of
993mmboe within our subsidiaries and increase of 505mmboe within
our equity-accounted entities). Acquisition activity in our subsidiaries
occurred in the US and UK, and divestment activity in our subsidiaries
in the US and UK. In our equity-accounted entities acquisitions
occurred in our Russian joint ventures other than Rosneft. There
were no divestments in our equity-accounted entities.
The proved reserves replacement ratio« is the extent to which
production is replaced by proved reserves additions. This ratio is
expressed in oil equivalent terms and includes changes resulting from
revisions to previous estimates, improved recovery, and extensions
and discoveries. For 2018, the proved reserves replacement ratio
excluding acquisitions and disposals was 100% (143% in 2017 and
109% in 2016) for subsidiaries and equity-accounted entities, 66% for
subsidiaries alone and 161% for equity-accounted entities alone.
There were increases (131mmboe) 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 more than offset by decreases
(140mmboe) in PSAs, principally in Azerbaijan, Indonesia and Iraq
resulting from decreased cost recovery volumes due to higher oil and
gas prices.
In 2018 net additions to the group’s proved reserves (excluding
production and sales and purchases of reserves-in-place) amounted
to 1,381mmboe (576mmboe for subsidiaries and 805mmboe 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 were through
improved recovery from, and extensions to, existing fields and
discoveries of new fields where they represented a mixture of proved
developed and proved undeveloped reserves. Volumes added in 2018
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 by
region were in UAE, Oman 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.
14% of our proved reserves are associated with PSAs. The countries
in which we operated under PSAs in 2018 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.
The group holds no 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 217.
BP Annual Report and Form 20-F 2018
«See Glossary
287
BP’s net production by country – crude oila and natural gas liquids
2018
2017
Crude oil
2016
thousand barrels per day
BP net share of productionb
Natural gas
liquids
2018
2017
2016
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 Dhabi
Argentinac
Boliviac
Egypt
Norwayc
Russiac
Angola
Other
Total equity-accounted entities
Total subsidiaries and equity-accounted entitiesf
101
—
—
101
106
18
261
385
24
24
408
7
7
147
49
9
204
169
72
—
54
—
17
313
313
16
2
17
1,051
919
16
52
3
—
34
14
1
—
1,040
2,091
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
5
—
—
5
—
37
23
60
—
—
60
9
9
—
—
11
11
—
—
—
—
—
—
—
—
2
—
2
88
4
—
—
—
3
2
—
3
—
12
100
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
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 2018, BP acquired various interests in the Permian Basin, Eagle Ford and Haynesville Shales in Lower 48 onshore as a result of the acquisition of BHP’s US unconventional assets,
increased its interest in the Clair asset in the UK North Sea, and acquired an interest in LLC Kharampurneftegaz in Russia, and in certain US offshore assets. It also disposed of its interests
in the Greater Kuparuk Area in Alaska, the Magnus field in the UK North Sea, and in certain other assets in the UK North Sea and US onshore assets. 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.
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 Includes 3 net mboe/d of NGLs from processing plants in which BP has an interest (2017 3mboe/d and 2016 3mboe/d).
Because of rounding, some totals may not agree exactly with the sum of their component parts.
288
«See Glossary
BP Annual Report and Form 20-F 2018
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
2018
2017
2016
152
—
—
152
1,705
190
5
1,900
7
7
1,907
2,136
2,136
878
183
1,061
256
—
32
538
826
826
437
382
819
6,900
1,286
264
71
59
80
—
1,760
8,659
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
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 2018, BP acquired various interests in the Permian Basin, Eagle Ford and Haynesville Shales in Lower 48 onshore as a result of the acquisition of BHP’s US unconventional assets,
increased its interest in the Clair asset in the UK North Sea, and acquired an interest in LLC Kharampurneftegaz in Russia, and in certain US offshore assets. It also disposed of its interests
in the Greater Kuparuk Area in Alaska, the Magnus field in the UK North Sea, and in certain other assets in the UK North Sea and US onshore assets. 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.
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 2018
«See Glossary
289
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
71.28
31.63
7.71
53.67
32.77
5.09
42.80
25.70
4.50
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
40.16
20.16
4.19
70.24
—
7.93
55.08
—
5.78
50.71
—
5.16
67.11
25.81
2.43
49.98
22.42
2.36
39.65
14.71
1.90
—
—
—
—
—
—
—
—
—
33.57
—
—
36.80
—
—
26.11
—
—
—
—
—
—
—
—
—
—
—
69.17
35.74
3.08
55.44
26.79
2.25
45.64
21.40
1.72
62.35
—
4.36
49.97
—
4.49
48.88
34.51
4.21
68.81
39.14
4.82
53.61
36.48
3.82
40.83
21.30
3.89
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
62.46
N/A
1.70
45.66
N/A
1.63
36.36
N/A
1.39
70.80
92.47
3.85
52.88
—
3.44
39.29
—
3.39
39.49
—
—
15.61
—
—
12.92
—
6.11
67.54
52.14
7.97
53.26
39.39
6.14
41.52
32.70
5.71
—
—
—
—
—
—
—
—
—
Total
group
average
67.81
29.42
3.92
51.71
26.00
3.19
39.99
17.31
2.84
62.24
—
2.50
42.33
—
2.47
34.04
34.51
2.20
Subsidiaries
2018
Crude oilc
Natural gas liquids
Gas
2017
Crude oilc
Natural gas liquids
Gas
2016
Crude oilc
Natural gas liquids
Gas
Equity-accounted
entitiesd
2018
Crude oilc
Natural gas liquidse
Gas
2017
Crude oilc
Natural gas liquidse
Gas
2016
Crude oilc
Natural gas liquidse
Gas
Average production cost per unit of productionf
$ per unit of production
Europe
UK
Rest of
Europe
13.76
14.58
14.80
—
—
—
—
—
13.72
12.15
10.33
10.41
North
America
South
America
Africa
Asia
Australasia
US
9.63
8.68
10.20
—
—
—
Rest of
North
America
13.10
15.02
21.79
—
—
—
3.08
4.41
4.21
10.61
11.92
10.66
Russia
Rest of
Asia
7.31
6.47
9.34
—
—
—
—
—
—
3.09
3.19
2.46
5.72
6.37
7.08
5.92
3.27
3.67
2.35
2.79
2.62
—
—
—
Total
group
average
7.15
7.11
8.46
4.16
4.32
3.57
Subsidiaries
2018
2017
2016
Equity-accounted
entities
2018
2017
2016
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.
290
«See Glossary
BP Annual Report and Form 20-F 2018
Environmental expenditure
Operating expenditure
Capital expenditure
Clean-ups
Additions to environmental
remediation provision
Increase (decrease) in
decommissioning provision
2018
501
449
31
428
137
2017
441
487
22
249
$ million
2016
487
564
27
262
(228)
(804)
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 $501 million in 2018 (2017
$441 million) showed an overall increase of 14% the largest element
of which was due to higher expenditures associated with sustaining
and increasing production volumes in the Gulf of Mexico region.
Environmental capital expenditure in 2018 was lower overall than in
2017 largely due to lower spend resulting from the divestiture of the
North Sea Forties Pipeline System and lower expenditure on Arundel,
Clair and Schiehallion fields.
Clean-up costs were $31 million in 2018 (2017 $22 million)
representing increases in oil spill clean-up costs and other associated
remediation and disposal costs as well as costs related to the
replacement of underground storage tanks in the US.
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 increased in
2018 largely due to the scope reassessments of the remediation
plans of a number of our sites in the US and Canada. The charge for
environmental remediation provisions in 2018 included $8 million in
respect of provisions for new sites (2017 $8 million and 2016 $7
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 2018, the net decrease in the decommissioning provision, similar
to the decrease in 2017, 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 23.
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, solar and shipping activities, 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 US government entities are usually by
lease. Arrangements with private property owners are also usually in
the form of leases.
Licences (or concessions) give the holder the right to explore for,
develop and produce 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, develop and produce 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,
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
BP Annual Report and Form 20-F 2018
«See Glossary
291
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. This agreement applies to both developing and
developed countries, although in some instances allowances or
flexibilities are provided for developing countries. The Paris
Agreement aims to hold the increase in the global average
temperature to well below 2°C above pre-industrial levels and to
pursue efforts to limit the temperature increase 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 towards absolute emission
reduction targets over time. 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.
At the United Nations climate change conference in Poland (COP24)
in December 2018, the ‘Paris Rulebook’ was agreed. This rulebook
describes how the elements of the Paris Agreement will be
implemented when it comes into force in 2020. COP24 failed to
agree on rules for implementing Article 6, which could enable
international carbon trading to assist in meeting NDCs. Discussions
on Article 6 have now been deferred to COP25 which will take place
in Chile in 2019.
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 used its existing statutory authority to implement that
plan, including the Clean Air Act (CAA) and the Mineral Leasing Act
(MLA). BP's operations are affected by regulation in a number of
ways under the CAA, for example:
• 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. As discussed below, the Bureau of
Land Management (BLM) has issued a new waste prevention
rule which rescinded the prior rule regarding methane regulation
on federal lands.
• 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).
As noted below, some of these regulations may be suspended,
revised or rescinded resulting in regulatory uncertainty and
complex compliance challenges for our affected businesses
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 (CPP)
which was an important element of the Obama administration’s
Climate Action Plan, and the EPA new source methane rule.
On 21 August 2018, the EPA introduced the Affordable Clean
Energy (ACE) Rule, which is intended to address GHG emissions
from certain stationary sources, and which is intended to replace
the CPP. The CPP regulations are currently stayed pending
resolution of existing legal challenges; the EPA may decline to
defend certain of these legal challenges. When the ACE Rule is
finalized, it is likely to face legal challenges as well. The outcome
with respect to these rules may 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. 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. EO 13783 instructed the Department of Interior (DOI) to
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review and possibly suspend, revise or rescind the BLM methane
rule. In September 2018, BLM finalized a new waste prevention
rule, which removed many of the provisions of the former BLM
methane rule. The EPA rule and the new waste prevention rule are
being challenged by states and NGOs. The final outcome of the rule
revisions and legal challenges with respect to these EPA and BLM
rules is uncertain.
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 are being phased in - the emission limit
values set in the Directive applied from 20 December 2018 for new
plants and by 2025 or 2030 for existing plants, depending on their
size.
The Energy Policy Act of 2005 and the Energy Independence and
Security Act of 2007 impose a renewable fuel mandate (the federal
Renewable Fuel Standard) as well as state initiatives that impose
low GHG emissions thresholds for transportation fuels (currently
adopted in California, through the California Low Carbon Fuel
Standard, and in Oregon). In October 2018, President Trump
directed the EPA to conduct rulemaking to extend to E15 gasoline
the volatility allowance currently given to E10 gasoline under the
CAA. Current law allows E15 gasoline to be sold year-round, but
this rule will make it easier for E15 to meet the more stringent
summer volatility standards. This rulemaking will also address
“market reforms” of the RFS credit-trading programme, which is
the open market for renewables credit trading. EPA has indicated it
hopes to have the rulemaking finalized by the summer 2019 driving
season.
Under the GHG mandatory reporting rule (GHGMRR), annual
reports on GHG emissions must be filed with the EPA. 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.
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. The State of
Washington adopted a carbon cap rule that was to become
effective 2017, but the rule has been suspended pending review
before the state’s supreme court.
European Union
• EU leaders in 2007 endorsed a set of measures to reduce GHG
emissions and encourage renewables in the 2010 to 2020 period.
These include an overall GHG reduction target of 20% by 2020. To
meet this, a set of regulatory measures were adopted which
include: a collective national reduction target for emissions not
covered by the EU Emissions Trading System (EU ETS) Directive;
binding national renewable energy targets of 20% renewable
energy used in 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 legal framework to
promote carbon capture and storage (CCS); and a revised EU ETS
Phase 3.
• In October 2014 EU leaders adopted the climate and energy
framework setting key targets for the year 2030 including at least
40% cuts in GHG emissions (from 1990 levels). 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. Measures to achieve
the 2030 targets include a significant revision of the EU ETS for
Phase 4 agreed in 2017, which addresses the surplus allowances in
the system and the amount of free allocation for sectors prone to
international competition. In mid-2018 a 32% share of renewable
energy and a 32.5% increase in energy efficiency was agreed
which must be met by EU Member States by 2030. The package
also sets a renewable energy target of 14% for the transportation
sector.
• On 28 November 2018 the European Commission presented its
long-term Energy and Climate Strategy that sets a “vision” towards
a net-zero GHG emissions economy by the mid-twenty first
century.
• The Medium Combustion Plants Directive (MCPD) applies to air
emissions of sulphur dioxide (SO2), nitrogen oxides (NOx) and
• 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. EU member states had to
implement the Directive by 1 July 2018. NECD has been
implemented in the UK by the National Emission Ceiling
Regulations 2018. Each EU Member State is also required to
produce a National Air Pollution Control Programme by 31 March
2019 setting out the measures it will take to ensure compliance
with the 2020 and 2030 reduction commitments.
• 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.
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 compliance obligations
being based on facility performance relative to product specific
benchmarks. Compliance is possible by improving emissions
intensity, the purchase of offsets or the payment of C$30/tonne to
the Climate Change and Emissions Management Fund. In addition,
there is an economy-wide price of carbon policy that covers
emissions not in the scope of the existing regulations for large final
emitters (C$30/tonne in 2019; then escalating in line with Federal
backstop pricing). Additional requirements are in place relating to
electricity generation sources and limits on overall oil sands
emissions. The Canadian federal government has announced
climate change regulations, effective from January 2019, including
a national backstop carbon price starting at C$20/tonne in 2019 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. Newfoundland & Labrador and Nova Scotia are
implementing regulations that meet equivalency requirements of
the Federal regulations via economy wide carbon taxes on fuels
and large emitter programs (intensity based for Newfoundland &
Labrador and cap and trade for Nova Scotia).
• China is operating emission trading pilot programmes in five cities
and three provinces. One of BP's subsidiaries and one of BP’s joint
venture« companies in China are participating in these schemes. A
plan to establish a nationwide carbon emissions trading market
(initially covering the power sector only) was promulgated in
December 2017 by the National Development and Reform
Commission, which will not supersede the above eight pilot
programmes immediately but allow those pilot schemes to be
incorporated into the national scheme gradually. In 2018, the
Climate Change Bureau was transferred to the newly formed
Ministry for Ecology & Environment as part of the overall ministerial
restructuring. The Climate Change Bureau remains in charge of the
nationwide Emission Trading Scheme with no changes to the 2017
implementation plan.
• In July 2016, China carried out pilot programmes on 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 draft
regulation issued in 2018. The scheme is expected to undergo
further testing in 2019 before becoming mandatory. Generators will
be able to obtain certificates, which then can be sold to the two
national grid companies. No secondary trading is foreseen initially.
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• 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 45.
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 23 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 291.
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 which can result in regulatory uncertainty and
compliance challenges for our operations.
• 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. In 2018 the Trump Administration
started the rulemaking process to reform the NEPA regulations
consistent with EO 13807.
• 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’. EPA regulations impose light, medium
and heavy duty vehicle emissions standards for GHGs (both fuel
economy and tailpipe standards) as well as for nonroad engines
and vehicles and permitting requirements for certain large GHG
stationary emission sources. California also imposes Low Emission
Vehicle (LEV) and Zero Emission Vehicle (ZEV) standards on vehicle
manufacturers and a number of other states impose different
stricter GHG emission limits on vehicles. These regulations may
impact fuel demand and product mix in California and those states
adopting LEV and ZEV standards and may impact BP’s product mix
and demand for particular products.
• In August 2018 the US Department of Transportation and EPA
issued a joint proposed rulemaking to establish new or revised fuel
economy and tailpipe carbon dioxide emissions standards for
passenger cars and light trucks covering model years (MY) 2021
through 2026. The Trump administration’s proposed option would
lock in the 2020 standards until 2026. This would be a rollback from
the Obama Administration’s rules. The agencies have said they
intend to finalize this rulemaking in Spring 2019. The proposal
would also eliminate the waiver allowing California and other states
to set their own LEV and ZEV standards. California and other states
have announced their intention to litigate if such a rule is finalized.
• 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
who 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
reporting on the storage, use and releases of designated quantities
of certain listed hazardous substances to federal, 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.
• 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
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safety and reduce workplace emissions at gas processing, refining
and other regulated facilities. On 17 January 2017, the US
Occupational Safety and Health Administration (OSHA) published
an instruction guidance document for implementing and
conducting a “National Emphasis Program” for process safety
management (PSM) in covered facilities. Over the next several
years OSHA will pursue inspections through the National Emphasis
Program to ensure compliance with PSM requirements in both
refineries and chemical plants.
• The US Department of Transportation (DOT) regulates the transport
of BP’s petroleum products such as crude oil, gasoline,
petrochemicals and other hydrocarbon liquids.
• The Maritime Transportation Security Act and the DOT Hazardous
Materials (HAZMAT) regulations impose security compliance
regulations on certain BP facilities.
• OPA 90 imposes operational requirements, liability standards and
other obligations governing the transportation of petroleum
products in US waters and 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, including equipment and
testing, on offshore and onshore operations on federal lands
subject to DOI authority.
• 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
experienced increasing restrictions on our activities.
European Union
• 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 EU regulation on ozone depleting substances 2009 (ODS
Regulation) requires companies 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) came into
force on 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.
• 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 October 2018 the European Council released an updated
proposal on setting CO2 reduction targets, from a 2021 baseline, of
15% by 2025 and 35% by 2030 for passenger cars, and 15% by
2025 and 30% by 2030 for passenger vans and heavy duty
vehicles.
• 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 of which was completed 31 May 2018. 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. An amendment to
the Annex of the Regulation on classification, labelling and
packaging of substances and mixture (CLP Regulation) requires
harmonized notification of information on hazardous materials
(certain lubricant and fuel formations) to EU member state poison
centres. The uniform notification rules will apply as of January 2020
for consumer products, from 2021 for professional and 2024 for
industrial uses.
• Outside the EU, Turkey has published REACH-like regulations,
known as KKDIK, as well as related implementation schedules and
substance registrations. BP is compiling and preparing the
requisite information to meet the pre-registration requirements for
the KKDIK.
• 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.
• The “Best Available Techniques Guidance Document on upstream
hydrocarbon exploration and production” seeks to document best
practice in the upstream sector. The guidance defines Best
Available Techniques and best risk management approaches across
the upstream lifecycle, from exploration and appraisal through to
decommissioning, and largely draws on experience and good
practice from existing standards as well as existing regulatory
regimes from Member States. While the document is non-binding,
the European Commission are encouraging regulatory authorities
to utilize this guidance when issuing permits. The guidance is in the
final stages of review and is expected to be published in 2019.
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.
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The Abidjan Convention has been now been ratified by more than 15
African nations, including Angola. The Convention, along with the
Additional Protocol published in 2012, sets environmental quality
standards for the discharge of chemicals to the marine environment.
BP currently operates produced water treatment to meet these
quality standards in Angola and is designing systems to meet the
standard for our future gas operations in Mauritania and Senegal.
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. OPA 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 2018, as the required
minimum number of contracting states had not been achieved, the
HNS Convention had not entered into force.
• A global sulphur cap of 0.5% will apply to marine fuel from January
2020 under MARPOL. In order to comply, ships will either need to
consume low sulphur marine fuels, operate on other low sulphur
fuels such as LNG or implement approved abatement technology
to enable them to meet the low sulphur emissions requirements
while 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. Measures to support
consistent global implementation are expected to be finalized in
2019.
• Under the International Convention for the Control and
Management of Ships’ Ballast Water and Sediments 2004, which
entered into force in September 2017, ships in international traffic
are required to manage their ballast water and sediments to a
certain standard, according to a ship-specific ballast water
management plan.
• 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 EU. OSPAR Recommendation 2001/1
relates to the management of produced water from offshore
installations in the North Sea. The 2001 recommendation set a
target of a 15% reduction in the total quantity of oil in produced
water discharged by 2006 compared to 2000 levels and a
performance standard for dispersed oil in produced water
discharged into the sea of 30 mg/l. 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). This approach supports
a key goal of the 2001 recommendations, that by 2020 Contracting
Parties should achieve a reduction of oil in produced water
discharged into the sea to a level which will adequately ensure that
each of those discharges will present no harm to the marine
environment.
• 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 came 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 explosion and fire and
resulting oil spill (the Incident). Lawsuits and claims arising from
the Incident were brought principally 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 governmental claims
in relation to the Incident have now been settled or dismissed
and the 2014 administrative agreement with the US
Environmental Protection Agency and BP’s obligations thereunder
ended in March 2019. The remaining proceedings arising from the
Incident are discussed below.
PSC settlements
PSC settlements – Economic and Property Damages Settlement
Agreement
In 2012 the Economic and Property Damages Settlement was
entered into with the PSC to resolve 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, which is
under court supervision through the settlement claims process
established by the Economic and Property Damages Settlement,
continued during 2018. Only a very small number of business
economic loss claims remain to be determined, although certain
business economic loss claims continue to be appealed by BP
and/or the claimants.
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
In 2012 the Medical Benefits Class Action Settlement (Medical
Settlement) was entered into with the PSC. It 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).
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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 37,226. As of 25 January
2019, 27,607 claims (comprising 22,833 SPC and 4,774 PMCP
only) have been approved for compensation totalling
approximately $67 million; 9,615 claims have been denied; and 4
claims are pending determination.
In order to seek compensation from BP for an LMPC, class
members must file a notice with the Medical Claims
Administrator within 4 years after either (i) the date of first
diagnosis of the LMPC or (ii) the effective date of the MSA (12
February 2014), whichever is later. As of 22 February 2019, there
are 2,159 pending lawsuits brought by class members claiming
LMPCs.
Other civil complaints – economic loss
PSC settlement - Opt out and Excluded claims
In 2016, the vast majority of economic loss and property damage
claims from individuals and businesses that either opted out of
the 2012 PSC settlement and/or were excluded from that
settlement were either resolved or dismissed. Although several
groups of plaintiffs whose claims were dismissed by the district
court for noncompliance with the district court’s prior orders filed
appeals in the Fifth Circuit, only a small number of those
individual and business plaintiffs now have pending appeals.
BP-Branded Fuel Dealers
On 23 March 2017, two plaintiffs filed an appeal to the Fifth Circuit
from the district court’s October 2012 ruling dismissing their
claims on the grounds that alleged losses by dealers of BP-
branded fuel allegedly caused by the reputation impact of the spill
on the BP brand are not compensable under OPA 90. On 3 July
2018, the Fifth Circuit affirmed the district court’s ruling dismissing
their claims.
General Maritime Law Claims
On 19 July 2017 the district court held that maritime claims by 215
plaintiffs 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. Five
groups of plaintiffs filed appeals in the Fifth Circuit from the
dismissal of their claims, and two of those appeals remain
pending.
MDL 2179 - Other Economic Loss and Property Damage Claims
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. On 10 July 2018
the district court issued an order on those plaintiffs’ compliance
with the January 2018 order and on 29 November 2018 ruled on
several motions for reconsideration of its July 2018 compliance
order. In those two orders, the district court identified fewer than
200 plaintiffs with economic loss or property damage claims that
it deemed to have complied with its January 2018 order, and it
dismissed the remaining economic loss or property damage
claims with prejudice.
Other civil complaints – personal injury
The vast majority of post-explosion clean-up, medical monitoring
and personal injury claims from individuals that either opted out
of the 2012 PSC settlement and/or were excluded from that
settlement have been dismissed.
On 9 April 2018 the district court in MDL 2179 issued an order
requiring the 981 plaintiffs whose claims for post-explosion clean-
up, medical monitoring and personal injury claims occurring after
the Incident remain pending in MDL 2179 to file a sworn
statement providing detailed information regarding their claims.
On 20 September 2018, the district court issued an order
requiring more than 150 plaintiffs whose responses to the 9 April
2018 order BP deemed to be materially deficient to show cause
in writing by 11 October 2018 why their claims should not be
dismissed with prejudice for their failure to comply with the
court’s order. The district court has not yet ruled on the show
cause submissions.
Individual securities litigation
Following court approval of the settlement of a securities class action
brought on behalf of a class of post-explosion American depository
share (ADS) holders in 2017, there remained individual cases filed in
state and federal courts by pension funds, investment funds and
advisers. These were 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. All of the cases, with the exception of one case that
has been stayed, were transferred to MDL 2185. As at 31 December
2018, 28 actions on behalf of 113 plaintiffs remained pending in MDL
2185.
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 1 September 2017 the court
granted in part and denied in part BP’s motion for summary
judgment, limiting the case to three alleged misstatements and
narrowing the class period. On 3 April 2018, the Court of Appeal for
Ontario affirmed that decision.
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 sought a
determination that each defendant was liable under OPA 90 for
damages that included 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 and dismissed on 28 March 2018.
On 18 October 2012, before a Mexican Federal District Court located
in Mexico City, a class action complaint was filed against BP America
Production Company (BPAPC) and other BP subsidiaries. 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. On 15 May 2018, BP was formally served with the
post-class certification complaint. On 27 June 2018, BP answered the
complaint by seeking dismissal on various grounds including that no
oil reached Mexican waters or land and there was no economic or
environmental harm in Mexico.
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. 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. BPAPC was formally served with the
BP Annual Report and Form 20-F 2018
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297
action in October 2018 and filed an opposition to class certification
and requested dismissal on 28 December 2018.
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.
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. On 27 September 2018, the OSH Review Commission
issued its decision, which reduced the citations to two
remaining, and reduced the penalty to $7,000. OSHA has decided
not to appeal this decision.
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. On July 31, 2018 the Ninth Circuit
granted the parties’ motion to dismiss the appeal voluntarily
ending the litigation.
Lead paint matters
Since 1987, Atlantic Richfield Company (Atlantic Richfield), a
subsidiary of BP, has been named as a co-defendant in numerous
lawsuits brought in the US alleging injury to persons and property
caused by lead pigment in paint. The majority of the lawsuits
have been abandoned or dismissed against Atlantic Richfield.
Atlantic Richfield is named in these lawsuits as alleged
successor to International Smelting and Refining and another
company that manufactured lead pigment during the period
1920-1946. The plaintiffs include individuals and governmental
entities. Several of the lawsuits purport to be class actions. The
lawsuits seek various remedies including compensation to lead-
poisoned children, cost to find and remove lead paint from
buildings, medical monitoring and screening programmes, public
warning and education of lead hazards, reimbursement of
government healthcare costs and special education for lead-
poisoned citizens and punitive damages. No lawsuit against
Atlantic Richfield has been settled nor has Atlantic Richfield been
subject to a final adverse judgment in any proceeding. The
amounts claimed and, if such suits were successful, the costs of
implementing the remedies sought in the various cases could be
substantial. While it is not possible to predict the outcome of
these legal actions, Atlantic Richfield believes that it has valid
defences. It intends to defend such actions vigorously and
believes that the incurrence of liability is remote. Consequently,
BP believes that the impact of these lawsuits on the group’s
results, financial position or liquidity will not be material.
Scharfstein v. BP West Coast Products, LLC
A class action lawsuit was filed against BP West Coast Products, LLC
(BPWCP) 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 BPWCP 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 against BPWCP for the amount of $417.3 million.
On 31 May 2018 the Oregon Court of Appeals affirmed the trial
court’s ruling. BP filed a Petition for Review to the Oregon Supreme
Court which was denied on 8 November 2018. In March 2019, BP and
the Plaintiffs agreed to a settlement of the class action lawsuit,
subject to final court approval. BP intends to file a petition for a writ of
certiorari to the US Supreme Court in order to preserve BP’s appeal
rights pending final court approval of the settlement. BP’s provisions
for litigation and claims includes a provision for this lawsuit.
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.
In May 2018, the US government announced its planned withdrawal
from the Joint Comprehensive Plan of Action (JCPOA) under which
the US and the EU had implemented temporary, limited and
reversible relief of certain sanctions related to Iran. The US
government tasked OFAC with implementing the full re-imposition of
both primary and secondary sanctions in respect of Iran by the end of
a wind-down period. As a result of the JCPOA, BP had considered
and developed possible business opportunities in relation to Iran,
engaged in discussions with Iranian government officials and other
Iranian nationals and attended conferences. BP will continue to
monitor and assess business opportunities in Iran which are
compliant with EU and US laws applicable to BP including potentially
attending meetings in connection with this purpose.
On 30 November 2018, BP completed the sale of certain of its assets
in the North Sea, including its ownership stake, and the transfer of its
role as operator, in the North Sea Rhum field (Rhum) joint
arrangement to Serica Energy plc (Serica). Prior to that date, Rhum
was owned under a 50:50 unincorporated joint arrangement between
BP and Iranian Oil Company (U.K.) Limited (IOC).
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).
On 3 December 2018 BP entered into an agreement with, among
others, SOCAR and NICO pursuant to which SOCAR shall pay to BP
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Exploration Shah Deniz Limited (BPXSD), as the Shah Deniz Operator,
an amount in respect of compensation for NICO’s waiver of its right
to lift its share of Shah Deniz condensate. Such amounts shall be
used to cover cash calls to NICO in respect of operating costs due
from NICO to BPXSD. On 30 November 2018, OFAC issued a new
licence in relation to these arrangements.
BP holds an interest in a non-BP operated Indian joint venture« that
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 in which entities on the relevant
sectoral sanctions list own a certain percentage interest, being either
33% or 50% depending on certain criteria. In August 2017, 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 exploration and production oil projects. We
are not aware of any material adverse effect on our current income
and investment in Russia or elsewhere as a consequence of those
sanctions.
BP maintains bank accounts and has registered and paid required
fees to maintain registrations of patents and trademarks in certain
Sanctioned Countries.
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:
• Prior to 30 November 2018, Rhum, located in the UK sector of the
North Sea, was operated by BP Exploration Operating Company
Limited (BPEOC), a non-US subsidiary of BP, and Rhum was owned
under a 50:50 unincorporated joint arrangement between BPEOC
and Iranian Oil Company (U.K.) Limited (IOC) which was initially
established in 1974. During 2018, BP recorded gross revenues of
$177.3 million related to its interests in Rhum. BP had a net profit
of $87.7 million for the year ended 31 December 2018.
• BP has sought to carry out its role as operator of the Rhum joint
arrangement in compliance with US sanctions and has obtained a
series of specific OFAC licences relating to the ongoing operation
of the Rhum field.
• 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
($39.88 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.
• During 2018, BPEOC received £223,693 ($298,456 equivalent) (net
of tariffs) from BPEOC Forties Pipeline System in respect of
monies owed to IOC in relation to the purchase of IOC’s share of
Onshore Raw Gas at the Kinneil terminal of the Forties Pipeline
System. BP and IOC agreed to set off the £223,693 ($298,456
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.
• During 2018, BPEOC received £2.79 million ($3.73 million
equivalent) (net of tariffs) from a non-US third party in respect of
the sale to such non-US third party of certain NGLs redelivered
from the St Fergus terminal. These NGLs had been acquired by
BPEOC from IOC at the St. Fergus terminal. BP and IOC agreed to
set off the £2.79 million ($3.73 million equivalent) against IOC’s
share of operating costs incurred by BPEOC as operator of the
Rhum field under the Rhum joint operating agreement.
• As noted above, on 30 November 2018, BP completed the sale of
its ownership stake in the Rhum joint arrangement and transferred
its role as operator to Serica. Prior to the sale, on 5 October 2018,
Serica and BP received a conditional licence from OFAC relating to
the ongoing operation of the Rhum field. The licence was valid until
31 October 2019 and was conditional upon arrangements being put
in place before 5 November 2018 relating to the interests in Rhum
held by IOC. An updated licence from OFAC on substantially the
same terms and a letter of comfort permitting all non-US persons
to support Rhum activities in compliance with US secondary
sanctions were issued on 2 November 2018. On the same date the
conditions in such OFAC licence in respect of the interest in Rhum
held by IOC were met in full. These conditions were satisfied
through arrangements which provide that all benefits accruing from
and relating to IOC’s interest in Rhum will be held in escrow, by a
trust and management company (Rhum Management Company)
set up for this purpose, for such period as US sanctions apply. The
arrangements are designed to ensure that neither IOC nor any
direct or indirect parent company of IOC (including any member of
the Government of Iran) will derive any economic benefit from
Rhum, or exercise any decision-making powers in respect of
Rhum, during that period. From satisfaction of the OFAC licence
conditions on 2 November 2018, BP dealt with the Rhum
Management Company in respect of Rhum joint venture matters.
• In December 2018, BP made a cash transfer of £2.69 million ($3.59
million equivalent) to Rhum Management Company. This transfer
represented the net amount of IOC funds in the Rhum joint
venture account which had not, to that date, 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 similar arrangements
with IOC or any member of the Government of Iran in relation to
the Rhum field. BP will continue to purchase from Serica’s liftings
from Rhum or provide services to Serica as the operator of Rhum.
• On 17 July 2018 BP Iran Limited terminated its lease of an office in
Tehran. The office had been used for administrative activities. In
2018, taxes, including rental tax payments associated with the
Tehran office, with an aggregate US dollar equivalent value of
approximately $11,000, 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.
• During 2018, 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
$3,000. 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. BP will continue to monitor and
assess business opportunities in Iran which are compliant with EU
BP Annual Report and Form 20-F 2018
«See Glossary
299
and US laws applicable to BP including potentially attending
meetings in connection with this purpose.
directors whom the board has determined to be independent, in the
manner described above.
Material contracts
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 resolved 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 2018 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 2018 and the group
percentage of ordinary share capital see Financial statements – Note
37. For information on significant joint ventures« and associates« of
the group see Financial statements – Notes 16 and 17.
Related-party transactions
Transactions between the group and its significant joint ventures and
associates are summarized in Financial statements – Note 16 and
Note 17. 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 2018 to 15 March
2019.
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 approach to corporate
governance. As such, the way in which BP makes determinations of
directors’ independence differs from the NYSE rules.
BP’s board governance principles require that all non-executive
directors be determined by the board to be ‘independent in character
and judgement and free from any business or other relationship
which could materially interfere with the exercise of their judgement’.
The BP board has determined that, in its judgement, all of the non-
executive directors are independent. In doing so, however, the board
did not explicitly take into consideration the independence
requirements outlined in the NYSE’s listing standards.
Committees
BP has a number of board committees that are broadly comparable in
purpose and composition to those required by NYSE rules for
domestic US companies. For instance, BP has a chairman’s (rather
than executive) committee 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
The BP board governance principles prescribe the composition, main
tasks and requirements of each of the committees (see the board
committee reports on pages 75-86). 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 75). 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
300
«See Glossary
BP Annual Report and Form 20-F 2018
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 within the
company, if any, 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
costs and benefits of possible control and procedure design options.
Also, we have investments in 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 2018 fiscal year, management conducted an
assessment of the effectiveness of internal control over financial
reporting in accordance with the criteria in the UK Financial Reporting
Council’s Guidance on Risk Management, Internal Control and
Related Financial and Business Reporting relating to internal control
over financial reporting. Based on this assessment, management has
determined that BP’s internal control over financial reporting as of
31 December 2018 was effective.
Management’s assessment of the effectiveness of internal control
over financial reporting excluded Petrohawk Energy Corporation,
which was acquired on 31 October 2018. Petrohawk financial
statements constitute 10.3% and 4.0% of net and total assets
respectively, 0.2% of revenues, and 0.05% of net income of the
consolidated financial statement amounts as of and for the year
ended 31 December 2018. This exclusion is in accordance with the
general guidance issued by the SEC that an assessment of a recent
business combination may be omitted from management’s report on
internal control over financial reporting in the first year of
consolidation.
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 2018 has been audited by
Deloitte, an independent registered public accounting firm, as stated
in their report appearing on page 127 of BP Annual Report and Form
20-F 2018.
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 control over financial reporting.
Principal accountant's fees and
services
The audit committee has established policies and procedures for the
engagement of the independent registered public accounting firm,
Deloitte 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. Deloitte
is 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, Deloitte
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 and in 2018 further updated
its policies to clarify the engagement of the incoming auditor,
Deloitte, and the outgoing auditor (and auditor of Rosneft) Ernst &
Young to ensure independence. 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.
The audit committee evaluates the performance of the auditor each
year. The audit fees payable to Deloitte 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
auditor. External regulation and BP policy requires the auditor to
rotate its lead audit partner every five years. See Financial statements
– Note 36 and Audit committee report on page 79 for details of fees
for services provided by the auditor.
Directors’ report information
This section of BP Annual Report and Form 20-F 2018 forms part of,
and includes certain disclosures which are required by law to be
included in, the Directors’ report.
Indemnity provisions
BP Annual Report and Form 20-F 2018
«See Glossary
301
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 45.
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
159
Not applicable
302
Not applicable
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 2018.
During the year, a review of the terms and scope of the policy was
undertaken. The policy was renewed during 2018 and continued into
2019. 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 53, Liquidity and capital resources on page 277
and Financial statements – Notes 29 and 30.
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 29.
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 in the business of the
company 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 40.
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 51.
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
302
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BP Annual Report and Form 20-F 2018
Cautionary statement
In order to utilize the ‘safe harbor’ provisions of the United States
Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the
general doctrine of cautionary statements, 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 (page
8), the Strategic report (inside cover and pages 1-56), Additional
disclosures (pages 273-304) and Shareholder information (pages
305-314), including but not limited to statements under the headings
‘The changing energy mix’, ‘How we run our business’, ‘Our strategy’
and ‘Global energy markets’ and including but not limited to
statements regarding plans and prospects relating to near- and long-
term growth, organic capital expenditure, organic growth, the
strength of BP’s balance sheet, maintaining a robust cash position,
working capital, operating cash flow and margins, capital discipline,
growth in sustainable free cash flow and shareholder distributions
and future dividend and optional scrip dividend payments; plans and
expectations regarding share buybacks, including to offset the impact
of dilution from the scrip programme since the third quarter 2017 by
the end of 2019; expectations regarding world energy demand,
including the growth in relative demand for renewables, oil and gas,
and the proportional growth of renewables; expectations with respect
to the world energy mix, production, consumption and emissions to
2040; plans and expectations regarding BP’s portfolio, including
having a distinctive portfolio, BP’s active management of the portfolio
and the flexibility of the portfolio; plans and expectations with respect
to disciplined investment; plans and expectations with respect to the
Upstream, including growing advantaged oil and gas, being
competitive in every basin and producing resilient and competitive
barrels; plans and expectations with respect to BP’s transformation
agenda; plans and expectations to deliver 2021 financial targets;
expectations with respect to reserves bookings from new
discoveries; plans and expectations regarding BP’s quality of
execution, including to get more from a unit of capital compared to
peers; plans and expectations with respect to BP’s refining and
petrochemicals portfolio; plans and expectations with respect to
creating distinctive retail offers in the Downstream; plans and
expectations with regard to new technologies, including their
efficiency and impact on production; plans and expectations with
respect to BP’s investments in Chargemaster, StoreDot and
FreeWire, including for BP to become the leading fuel provider for
both conventional and electric vehicles and supporting electric vehicle
adoption; plans and expectations with respect to BP’s investment in
solar energy and biofuels, including to invest $200 million in
Lightsource BP over a three-year period; plans and expectations with
respect to the commercial optimization programme; plans and
expectations to run safe and reliable operations; plans and
expectations regarding BP’s acquisition of onshore-US oil and gas
assets from BHP, including expectations regarding the funding and
timing of further purchase price payments, future performance and
operations and related divestments; plans and expectations to reduce
emissions in operations and the low carbon future, including to target
zero net growth in operational emissions to 2025 and the Advancing
Low Carbon accreditation programme; plans and expectations with
respect to evaluating the creation of a joint venture with SOCAR;
plans and expectations regarding BP’s low carbon businesses,
including in Brazil and India; plans and expectations with respect to
Fulcrum BioEnergy’s commercial operations; plans to grow third-party
technology licensing income; plans and expectations regarding
charges in Other businesses and corporate in 2019 and proceeds
from divestments and disposals, including to have more than $10
billion of divestments over the next two years; 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;
expectations with respect to the cash break even point; plans and
expectations regarding the US onshore, including to increase the
liquid hydrocarbon proportion and to upgrade and reposition BPX
Energy; plans with regard to BP’s exploration budget; plans and
expectations regarding the resiliency of downstream businesses;
expectations regarding the effective tax rate in 2019; plans to produce
900,000boe/d from new major projects by 2021 and expectations
regarding operating cash margins of this production; plans to start up
five major projects in 2019; plans and expectations with respect to
expected project start-ups between 2019 and 2021; plans and
expectations regarding investment, development, and production
levels and the timing thereof with respect to projects and
partnerships in Australia, Azerbaijan, Brazil, China, Egypt, India,
Indonesia, Libya, Mexico, Mauritania, Russia, São Tomé and Príncipe,
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 the dual energy
challenge and the energy transition, including BP’s progressive and
pragmatic approach and planned investments; plans and expectations
regarding shareholder resolutions; plans and expectations with
respect to BP’s public reporting of ambitions, plans and progress;
plans and expectations regarding innovation in BP, including the
development of BPme, Wolfspar, a land seismic recording system,
APEX, Plant Operations Advisor and wind energy storage systems;
plans and expectations regarding plant reliability and base decline,
including for base decline to remain between 3-5%; plans and
expectations regarding the Tangguh gas facility; expectations
regarding discounts for North American heavy crude oil, refining
margins and refining turnarounds; plans to undertake joint exploration
and development with Rosneft, including to explore oil and gas
licence areas in Sakha (Yakutia); expectations regarding pensions and
other post-retirement benefits; expectations regarding payments
under contractual obligations; 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 and
transactions relating to Iran; 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; 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
57-86) and the Directors’ remuneration report (pages 87-109) with
regard to the anticipated future composition of the board of directors
and the effects thereof; the board’s goals and areas of focus,
including changes to KPIs and those goals stemming from the
board’s annual evaluation; plans and expectations regarding directors’
share ownership and remuneration; plans regarding the governance
and remuneration processes; 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
BP Annual Report and Form 20-F 2018
«See Glossary
303
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 projects
onstream; the timing, quantum and nature of certain acquisitions and
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;
cyberattacks or sabotage; and other factors discussed elsewhere in
this report including under Risk factors (pages 55-56). In addition to
factors set forth elsewhere in this report, those set out above are
important factors, although not exhaustive, that may cause actual
results and developments to differ materially from those expressed or
implied by these forward-looking statements.
Statements regarding competitive position
Statements referring to BP’s competitive position are based on the
company’s belief and, in some cases, rely on a range of sources,
including investment analysts’ reports, independent market studies
and BP’s internal assessments of market share based on publicly
available information about the financial results and performance of
market participants.
304
«See Glossary
BP Annual Report and Form 20-F 2018
Shareholder
information
306 Share pricings and listings
306 Dividends
306 Shareholder taxation information
308 Major shareholders
309 Annual general meeting
309 Memoradum and Articles of Association
312
Purchases of equity securities by the issuer
and affiliated purchasers
313 Fees and charges payable by ADS holders
313 Fees and payments made by the Depositary to the issuer
313 Documents on display
314 Shareholding administration
314 Exhibits
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BP Annual Report and Form 20-F 2017
BP Annual Report and Form 20-F 2018
279
305
Share prices and listings
Markets and market prices
The primary market for BP’s ordinary shares is the London Stock
Exchange (LSE) (trading symbol 'BP'). BP’s ordinary shares are a
constituent element of the Financial Times Stock Exchange 100 Index.
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 (trading symbol 'BP'), for which
JPMorgan Chase Bank, N.A. is the depositary (the Depositary) and
transfer agent. The Depositary’s principal office is 383 Madison
Avenue, Floor 11, New York, NY, 10179, 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.
BP's securities are also traded in the form of a global depositary
certificate representing BP ordinary shares on the Frankfurt, Hamburg
and Dusseldorf Stock Exchanges.
On 11 March 2019, 922,206,611 ADSs (equivalent to approximately
5,533,239,666 ordinary shares or some 27.31% of the total issued
share capital, excluding shares held in treasury) were outstanding and
were held by approximately 81,329 ADS holders. Of these, about
80,393 had registered addresses in the US at that date. One of the
registered holders of ADSs represents some 1,207,639 underlying
holders.
On 11 March 2019 there were approximately 235,594 ordinary
shareholders. Of these shareholders, around 1,540 had registered
addresses in the US and held a total of some 4,112,535 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 or 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 10.
A Scrip Dividend Programme (Scrip Programme) was approved by
shareholders in 2010 and was 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 55 and other
matters that may affect the business of the group set out in Our
strategy on page 10 and in Liquidity and capital resources on page
277.
The following table shows dividends announced and paid by the
company per ADS for the past five years.
Dividends per ADSa
2013
2015
2014
UK pence
US cents
UK pence
US cents
UK pence
US cents
UK pence
US cents
UK pence
US cents
2018 UK pence
US cents
2016
2017
March
36.01
54
34.24
57
40.00
60
42.08
60
48.95
60
43.01
60
June September December
Total
35.01
54
34.84
58.5
39.18
60
41.50
60
46.54
60
44.66
60
34.58
54
35.76
58.5
39.29
60
45.35
60
45.73
60
47.58
61.50
34.80
57
38.26
60
39.81
60
47.59
60
44.66
60
48.15
61.50
140.40
219
143.10
234
158.28
240
176.52
240
185.88
240
183.40
243
a Dividends announced and paid by the company on ordinary and preference shares are
provided in Financial statements – Note 10.
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.
306
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BP Annual Report and Form 20-F 2018
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. The dividend allowance
was £5,000 but this has been reduced to £2,000 as of 6 April 2018.
The dividend allowance of £2,000 means there is no UK tax due on
the first £2,000 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 £2,000 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 £2,000 allowance. For instance, if
an individual has an annual gross salary of £50,000 and also receives
a dividend of £12,000 they will be subject to the following scenario.
The individual's personal allowance and the basic rate tax band will be
used up by the gross salary. The remaining part of the salary and the
whole of the dividend will be subject to tax at the higher rate,
although the dividend allowance will reduce the amount of dividend
subject to tax. The dividend of £12,000 will be reduced by the
dividend allowance of £2,000 leaving taxable dividend income of
£10,000. The dividend will be taxed at 32.5% so that the total tax
payable on the dividends is £3,250.
How the shareholder pays the tax arising on the dividend income
depends on the amount of dividend income and salary they receive in
the tax year. If less than £2,000 they will not need to report anything
or pay any tax. If between £2,000 and £10,000, the shareholder can
pay what they owe by: contacting the helpline; asking HMRC to
change their tax code – the tax will be taken from their wages or
pension or through completion of the ‘Dividends’ section of their tax
return, where one is being filed. If over £10,000 they will be required
to file a self-assessment tax return and should complete the
‘Dividends’ section with details of the amounts received.
US federal income taxation
A US holder is subject to US federal income taxation on the gross
amount of any dividend paid by the company out of its current or
accumulated earnings and profits (as determined for US federal
income tax purposes). Dividends paid to a non-corporate US holder
that constitute qualified dividend income will be taxable to the holder
at a preferential rate, provided that the holder has a holding period in
the ordinary shares or ADSs of more than 60 days during the 121-day
period beginning 60 days before the ex-dividend date and meets other
holding period requirements. Dividends paid by the company with
respect to the ordinary shares or ADSs will generally be qualified
dividend income.
For US federal income tax purposes, a dividend must be included in
income when the US holder, in the case of ordinary shares, or the
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.
BP Annual Report and Form 20-F 2018
«See Glossary
307
For gains on or after 23 June 2010, the UK Capital Gains Tax rate will
be dependent on the level of an individual’s taxable income. Where
total taxable income and gains after all allowable deductions are less
than the upper limit of the basic rate income tax band of £34,500 (for
2018/19), the rate of Capital Gains Tax will be 10%. For gains (and any
parts of gains) above that limit the rate will be 20%.
From 6 April 2008, entitlement to the annual exemption is based on
an individual’s circumstances (taking into account Domicile status,
remittance basis of taxation and number of years in the UK). For
individuals who are entitled to the exemption for 2018/19, this has
been set at £11,700. Corporation tax on chargeable gains is levied at
19 per cent for companies from 1 April 2017.
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 (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
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.
Register of members holding BP ordinary shares as at
31 December 2018
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
53,495
79,856
90,654
10,801
948
689
236,443
22.63
33.77
38.34
4.57
0.40
0.29
100.00
0.01
0.22
1.41
1.11
1.77
95.48
100.00
a Includes JPMorgan Chase Bank, N.A. holding 27.32% 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.
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Register of holders of American depositary shares (ADSs) as at
31 December 2018a
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
48,763
21,504
11,266
501
7
1
82,042
59.44
26.21
13.73
0.61
0.01
0.00
100.00
0.28
1.11
3.17
0.91
0.13
94.40
100.00
a One ADS represents six 25 cent ordinary shares.
b One holder of ADSs represents 1,169,280 underlying shareholders.
As at 31 December 2018 there were also 1,286 preference
shareholders. Preference shareholders represented 0.42% and
ordinary shareholders represented 99.58% of the total issued
nominal share capital of the company (excluding shares held in
treasury) as at that date.
As at 31 December 2018, we had been notified pursuant to DTR5
that BlackRock, Inc. held 6.84% of the voting rights attached to the
issued share capital of the company.
Between 1 January 2019 and 11 March 2019, we received notification
of the following interests pursuant to DTR5. On 12 February 2019,
BlackRock, Inc. notified BP that it held 7.29% of the voting rights
attached to the issued share capital of the company. On 19 February
2019, BlackRock, Inc. notified BP that it held 7.28% of the voting
rights attached to the issued share capital of the company.
We are also aware that, as at 11 March 2019, BlackRock, Inc. held
6.61% and The Vanguard Group, Inc. held 3.45% of the ordinary
issued share capital of the company.
Under the US Securities Exchange Act of 1934 BP is aware of the
following interests as at 11 March 2019:
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
5,533,239,667
1,339,183,607
27.31
6.61
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 11 March 2019:
Holder
Holding of 8%
cumulative first
preference shares
Percentage
of class
The National Farmers Union Mutual
Insurance Society Limited
945,000
13.10
Hargreaves Lansdown Asset
Management Limited
Canaccord Genuity Group Inc.
Prudential plc
Holder
The National Farmers Union Mutual
Insurance Society Limited
Prudential plc
628,471
587,885
528,150
8.70
8.10
7.30
Holding of 9%
cumulative second
preference shares
Percentage
of class
987,000
644,450
18.00
11.80
Safra Group
Hargreaves Lansdown Asset
Management Limited
Canaccord Genuity Group Inc.
320,000
317,789
283,135
5.80
5.80
5.20
As at 11 March 2019, 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 2019 AGM will be held on Tuesday 21 May 2019 at 11.00am. A
separate notice convening the meeting is distributed to shareholders,
which includes an explanation of the items of business to be
considered at the meeting.
All resolutions for which notice has been given will be decided on a
poll. Deloitte LLP have expressed their willingness to continue in
office as auditors and a resolution for their reappointment is included
in the Notice of BP Annual General Meeting 2019.
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. The Memorandum and Articles of Association
are available online at bp.com/usefuldocs.
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 and shareholders voted to adopt new
Articles of Association at the AGM held on 16 April 2015. At the AGM
held on 21 May 2018 shareholders voted to adopt new Articles of
Association to reflect developments in market practice and to provide
clarification and additional flexibility where necessary or appropriate.
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 and secretary
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 subsidiary undertakings.
• 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 subsidiary undertakings.
BP Annual Report and Form 20-F 2018
«See Glossary
309
• 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.
The Articles of Association provide entitlement to the directors’
pensions and death and disability benefits to the directors’ relations
and dependants respectively.
The circumstances in which a director’s office will automatically
terminate include: when a director ceases to hold an executive office
of the company and the directors resolve that he should cease to be
a director; if a medical practitioner provides an opinion that a director
has become incapable of acting as a director and may remain so
incapable for a further three months and the directors resolve that he
should cease to be a director; and if all of the other directors vote in
favour of a resolution stating that the person should cease to be a
director.
The company secretary has express powers to delegate any of the
powers or discretions conferred on him or her.
Dividend rights; other rights to share in company profits;
capital calls
If recommended by the directors of BP, shareholders of BP 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 10 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
entitlement to claim dividends or other monies unclaimed in respect
of those shares will be for a period of twelve months after the sale.
The company may take such steps as the directors decide are
appropriate in the circumstances to trace the member entitled and
the sale may be made at such time and on such terms as the
directors may decide.
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 21 May 2018 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. The directors may
determine in relation to any scrip dividend plan or programme how
the costs of the programme will be met, the minimum number of
ordinary shares required in order to be able to participate in the
programme and any arrangements to deal with legal and practical
difficulties in any particular territory.
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.
Share transfers and share certificates
The directors may permit transfers to be effected other than by an
instrument in writing and that share certificates will not be required to
be issued by the company if they are not required by law.
The company may charge an administrative fee in the event that a
shareholder wishes to replace two or more certificates representing
shares with a single certificate or wishes to surrender a single
certificate and replace it with two or more certificates. All certificates
are sent at the member’s risk.
310
«See Glossary
BP Annual Report and Form 20-F 2018
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 determined by the directors. If any
shareholders’ meeting is adjourned for lack of quorum, notice of the
time and place of the adjourned meeting may be given in any lawful
manner, including electronically. Powers exist for action to be taken
either before or at the meeting by authorized officers to ensure its
orderly conduct and safety of those attending.
The directors have power to convene a general meeting which is a
hybrid meeting, that is to provide facilities for shareholders to attend
a meeting which is being held at a physical place by electronic means
as well (but not to convene a purely electronic meeting).
The provisions of the Articles of Association in relation to satellite
meetings permit facilities being provided by electronic means to allow
those persons at each place to participate in the meeting.
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.
BP Annual Report and Form 20-F 2018
«See Glossary
311
Called-up share capital
Details of the allotted, called-up and fully-paid share capital at
31 December 2018 are set out in Financial statements – Note 31. In
accordance with institutional investor guidelines, the company deems
it appropriate to grant authority to the directors to allot shares and
other securities and to disapply pre-emption rights by way of
shareholders resolutions at each AGM in place of authority granted by
virtue of the company's Articles of Association. At the AGM on 21
May 2018, authorization was given to the directors to allot shares in
the company and to grant rights to subscribe for, or to convert any
security into, shares in the company up to an aggregate nominal
amount as set out in the Notice of Meeting 2018. These authorities
were given for the period until the next AGM in 2019 or 21 August
2019, whichever is the earlier. These authorities are renewed annually
at the AGM.
Company records and service of notice
In relation to notices not covered by the Act, the reference to notice
by advertisement in a national newspaper also includes
advertisements via other means such as a public announcement.
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. Authorization for the programme was renewed at the company’s 2018 AGM covering the period until the date of the company's
2019 AGM. The maximum number of ordinary shares to be purchased will not exceed 1.99 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
2018 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.
2018
January
February 6 – February 28
March 8 – March 21
April
May 1 – May 11
June 6 – June 27
July
August 3 – August 30
September 4 – September 21
October
November 1 – November 28
December
2019
January
February 5 – February 21
March 11
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
Maximun
approximate
dollar value of
shares yet to
be purchased
under the
programme
$ million
Nil
12,574,000
5,500,000
Nil
7,765,798
3,230,500
Nil
6,788,050
12,497,354
Nil
2,603,190
Nil
Nil
2,753,983
717,995
6.69
6.62
7.50
7.66
7.24
7.22
24,000
Nil
12,550,000
5,500,000
463,650
Nil
7,302,148
3,230,500
Nil
Nil
6,788,050
12,497,354
6.84
269,000
2,334,190
7.10
7.14
120,000
Nil
2,633,983
717,995
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
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 21 May 2018, authorization was given to the company to repurchase up to 1.99 billion ordinary shares, for the period ending on the date of the AGM in 2019 or 21 August 2019,
whichever is the earlier. This authorization is renewed annually at the AGM. The total number of ordinary shares repurchased during 2018 under the programme was 50,202,242 at a cost of
$355 million (including fees and stamp duty) representing 0.25% of BP’s issued share capital excluding shares held in treasury on 31 December 2018. All ordinary shares repurchased in 2018
under the programme were cancelled in order to reduce BP’s issued share capital.
312
«See Glossary
BP Annual Report and Form 20-F 2018
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
Dividend fees
Expenses incurred on behalf of holders in connection
with:
• Stock transfer or other taxes and governmental
charges.
• Delivery by cable, telex, electronic and facsimile
transmission.
• Transfer or registration fees, if applicable, for the
registration of transfers of underlying shares.
• Expenses of the Depositary in connection with the
conversion of foreign currency into US dollars (which
are paid out of such foreign currency).
ADS holders who receive a cash dividend are charged a
fee which BP uses to offset the costs associated with
administering the ADS programme.
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.
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.
The Deposit Agreement provides that a fee of
$0.05 or less per ADS can be charged. The
current fee is $0.02 per BP ADS per calendar
year (equivalent to $0.005 per BP ADS per
quarter per cash distribution).
Cost per transaction is $2.00 for recurring, $2.00
for one-time automatic investments, and $5.00
for investment made by check, plus $0.12
commission per share.
Documents on display
BP Annual Report and Form 20-F 2018 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. The
SEC maintains an internet site at http://www.sec.gov that contains
reports and other information regarding issuers, including BP, that file
electronically with the SEC. BP's SEC filings are also available at
bp.com/sec. BP discloses in this report (see Corporate governance
practices (Form 20-F Item 16G) on page 300) significant ways (if any)
in which its corporate governance practices differ from those
mandated for US companies under NYSE listing standards.
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 2018. The Depositary reimbursed to the
company, or paid amounts on the company’s behalf to third parties, or
waived its fees and expenses, of $16,582,418.54 for the year ended
31 December 2018.
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 2018.
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 2018
$
Fees for delivery and surrender of BP
ADSs
Dividend feesa
Total
647,683.39
15,934,735.15
16,582,418.54
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.
BP Annual Report and Form 20-F 2018
«See Glossary
313
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)371 277 1014
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
2019 shareholder calendara
30 April 2019
First quarter results announced
10 May 2019 Record date (to be eligible for the first quarter
interim dividend)
21 May 2019 Annual general meeting
21 Jun 2019
First quarter interim dividend payment for 2019
5 Jul 2019
8% and 9% preference shares record date
30 Jul 2019
Second quarter results announced
31 Jul 2019
8% and 9% preference shares dividend payment
9 Aug 2019
20 Sep 2019
Record date (to be eligible for the second quarter
interim dividend)
Second quarter interim dividend payment for 2019
29 Oct 2019
Third quarter results announced
8 Nov 2019
Record date (to be eligible for the third quarter
interim dividend)
20 Dec 2019
Third quarter interim dividend payment for 2019
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 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
Exhibit 15.7
Exhibit 15.8
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*******†
Subsidiaries (included as Note 37 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†
Consent of Netherland, Sewell &
Associates†
Report of Netherland, Sewell &
Associates†
Consent Decree*******†
Gulf states Settlement
Agreement*******†
Consent of Ernst & Young LLP†
Consent of Deloitte LLP (included on page
127)
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 BP p.l.c. and its
subsidiaries under any one instrument does not exceed 10% of their
total assets on a consolidated basis.
The company agrees to furnish copies of any or all such instruments
to the SEC on request.
314
«See Glossary
BP Annual Report and Form 20-F 2018
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.
b/d
Barrels per day.
boe/d
Barrels of oil equivalent per day.
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 or Mb/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 or Mte
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 320.
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
22 and in Downstream on page 28. The range of contracts the group
enters into in its commodity trading operations is described below.
Using these contracts, in combination with rights to access storage
and transportation capacity, allows the group to access advantageous
pricing differences between locations, time periods and arbitrage
between markets.
BP Annual Report and Form 20-F 2018
315
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.
Divestment proceeds
Disposal proceeds as per the group cash flow statement.
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 320.
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 physical
contracts are treated as derivatives and are required to be fair valued
when they are managed as part of a larger portfolio of similar
transactions. Gains and losses arising are recognized in the income
statement from the time the derivative commodity contract is
entered into.
IFRS require that inventory held for trading is recorded at its fair value
using period-end spot prices, whereas any related derivative
commodity instruments are required to be recorded at values based
on forward prices consistent with the contract maturity. Depending
on market conditions, these forward prices can be either higher or
lower than spot prices, resulting in measurement differences.
BP enters into contracts for pipelines and other transportation,
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 that BP manages the economic exposures described above,
and measures performance internally, differs from the way these
activities are measured under IFRS. BP calculates this difference for
consolidated entities by comparing the IFRS result with
management’s internal measure of performance. Under
management’s internal measure of performance the inventory,
transportation 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 derivative instruments used to risk manage
certain oil, gas and other 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 320.
316
BP Annual Report and Form 20-F 2018
In addition, from 2018 fair value accounting effects include changes in
the fair value of the near-term portions of LNG contracts that fall
within BP’s risk management framework. LNG contracts are not
considered derivatives, because there is insufficient market liquidity,
and they are therefore accrual accounted under IFRS. However, oil
and natural gas derivative financial instruments (used to risk manage
the near-term portions of the LNG contracts) are fair valued under
IFRS. The fair value accounting effect reduces timing differences
between recognition of the derivative financial instruments used to
risk manage the LNG contracts and the recognition of the LNG
contracts themselves, which therefore gives a better representation
of performance in each period. Comparative information has not been
restated on the basis that the effect was not material.
Free cash flow
Operating cash flow less net cash used in investing activities, as
presented in the group cash flow statement.
Full dividend
Full dividend is cash dividend plus cash equivalent value of scrip
dividend.
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 275.
Inventory holding gains and losses
The difference between the cost of sales calculated using the
replacement cost of inventory and the cost of sales calculated on the
first-in first-out (FIFO) method after adjusting for any changes in
provisions where the net realizable value of the inventory is lower
than its cost. Under the FIFO method, which we use for IFRS
reporting, the cost of inventory charged to the income statement is
based on its historical cost of purchase or manufacture, rather than its
replacement cost. In volatile energy markets, this can have a
significant distorting effect on reported income. The amounts
disclosed represent the difference between the charge to the income
statement for inventory on a FIFO basis (after adjusting for any
related movements in net realizable value provisions) and the charge
that would have arisen based on the replacement cost of inventory.
For this purpose, the replacement cost of inventory is calculated
using data from each operation’s production and manufacturing
system, either on a monthly basis, or separately for each transaction
where the system allows this approach. The amounts disclosed are
not separately reflected in the financial statements as a gain or loss.
No adjustment is made in respect of the cost of inventories held as
part of a trading position and certain other temporary inventory
positions. See Replacement cost (RC) profit or loss definition below.
Joint arrangement
An arrangement in which two or more parties have joint control.
Joint control
Contractually agreed sharing of control over an arrangement, which
exists only when decisions about the relevant activities require the
unanimous consent of the parties sharing control.
Joint operation
A joint arrangement whereby the parties that have joint control of the
arrangement have rights to the assets, and obligations for the
liabilities, relating to the arrangement.
Joint venture
A joint arrangement whereby the parties that have joint control of the
arrangement have rights to the net assets of the arrangement.
Liquids
Comprises crude oil, condensate and natural gas liquids. For the
Upstream segment, it also includes bitumen.
LNG train
An LNG train is a processing facility used to liquefy and purify natural
gas in the formation of LNG.
Major projects
Have a BP net investment of at least $250 million, or are considered
to be of strategic importance to BP or of a high degree of complexity.
Net debt and net debt ratio (gearing)
Non-GAAP measures. Net debt 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 27 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 276.
BP Annual Report and Form 20-F 2018
317
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
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.
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
275.
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. 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 322.
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 5. A reconciliation to
GAAP information is provided on page 274.
RC profit or loss per share
Non-GAAP measure. Earnings per share is defined in Financial
statements – Note 11. 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
318
BP Annual Report and Form 20-F 2018
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 320.
Reserves replacement ratio
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.
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 tax (for the comparative periods
interest expense was 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 before tax. 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 321.
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 acquisitions and divestments and
entitlement impacts in our production-sharing agreements.
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 276 and
320 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
274.
Underlying replacement cost (RC) profit or loss per share
Non-GAAP measure. Earnings per share is defined Financial
statements – Note 11. 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 320.
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.
Wellwork
Activities undertaken on previously completed wells with the primary
objective to restore or increase production.
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.
Working capital
Movements in inventories and other current and non-current assets
and liabilities as stated in the group cash flow statement.
Trade marks
Trade marks of the BP group appear throughout this report. They
include: ACTIVE, Aral, ARCO, BP, BPme, BP Ultimate, Castrol, Castrol
EDGE BIO-SYNTHETIC, Castrol GTX ECO, Castrol Opitgear, PTAir
Trade marks:
Butamax – a registered trade mark of Butamax Advance Biofuels LLC.
Fulcrum and Fulcrum BioEnergy – registered trade marks of Fulcrum
BioEnergy, Inc.
M&S Simply Food – a registered trade mark of Marks & Spencer plc.
MyAuchan – a registered trade mark of Auchan.
REWE to Go – a registered trade mark of REWE.
BP Annual Report and Form 20-F 2018
319
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 316.
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)
2018
2017
$ million
2016
(419)
(39)
3
(455)
(151)
95
(56)
(35)
(4)
(39)
(155)
250
95
56
12
68
(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)
a 2018 brought forward fair value accounting effect balances include a $55-million adjustment between Upstream and Downstream as part of the transfer of the NGL business between
segments. 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
2018
2017
14,367
(39)
14,328
6,845
95
6,940
19,322
56
19,378
5,194
27
5,221
7,356
(135)
7,221
9,582
(108)
9,474
$ million
2016
1,211
(637)
574
5,610
(448)
5,162
655
(1,085)
(430)
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.
2018
46.98
4.01
(0.99)
50.00
2017
17.20
(4.32)
1.14
14.02
Per ordinary share – cents
2016
0.61
(8.52)
2.58
(5.33)
2015
(35.39)
10.31
(3.10)
(28.18)
2014
20.55
33.78
(10.43)
43.90
16.93
18.94
35.99
82.23
44.79
(3.23)
63.70
(1.65)
31.31
(16.87)
13.79
(21.83)
32.22
(22.69)
66.00
320
«See Glossary
BP Annual Report and Form 20-F 2018
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 (2018 average $165,491 million)
Less: Goodwill
Cash and cash equivalents
2018
(7,145)
198
(7,343)
522
121
—
2017
(3,712)
(225)
(3,487)
1,184
(859)
—
(7,986)
(3,812)
2018
2017
43
(1)
42
(5)
1
—
38
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
$ million
2014
(947)
1,917
(2,864)
4,171
—
—
(2,313)
(7,035)
2015
33
1
34
(15)
—
12
31
%
2014
19
7
26
10
—
—
36
2018
9,383
603
2,737
12,723
1,583
195
14,501
101,548
65,799
167,347
12,204
22,468
132,675
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
$ million
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
Average capital employed excluding goodwill and cash and cash
equivalents
ROACE
129,586
123,481
117,002
118,702
133,882
11.2 %
5.8%
2.8%
5.5%
9.6%
a Calculated on a post-tax basis (for 2017 interest expense was net of notional tax at an assumed 35%).
BP Annual Report and Form 20-F 2018
«See Glossary
321
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 318.
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
2018
4,202
1,641
$ million
2017
5,661
2,688
2018
$ million
2017
17,988
19,011
(14,066)
(13,929)
3,922
280
4,202
(2,561)
1,641
5,082
579
5,661
(2,973)
2,688
The Directors’ report on pages 57-86, 110-111, 210-237 and 273-322 was approved by the board and signed on its behalf by Jens Bertelsen,
company secretary on 29 March 2019.
BP p.l.c.
Registered in England and Wales No. 102498
322
«See Glossary
BP Annual Report and Form 20-F 2018
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/ Jens Bertelsen
Company secretary
29 March 2019
BP Annual Report and Form 20-F 2018
323
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
History and development of the company
Business overview
Organizational structure
Property, plants and equipment
Unresolved Staff Comments
Operating and Financial Review and Prospects
Operating results
Liquidity and capital resources
Research and development, patent and licenses
Trend information
Off-balance sheet arrangements
Tabular disclosure of contractual commitments
Safe harbor
Directors, Senior Management and Employees
Directors and senior management
Compensation
Board practices
Employees
Share ownership
Major Shareholders and Related Party Transactions
Major shareholders
Related party transactions
Interests of experts and counsel
Financial Information
Page
n/a
n/a
274, 306
n/a
n/a
55-56
2-3, 19-42, 151-160, 165, 168-170, 278-283, 291, 309
2-36, 43-54, 139, 156-159, 279-283, 291-296, 301
200, 325
21, 26-27, 36, 137, 165, 169-170, 235-237, 279-290, 300
None
16-17, 19-36, 55-56, 130, 133-150, 151-153, 156-159, 168-170, 179, 181-191, 275-277,
291-296, 298-299
16, 20, 132-133, 140, 165, 170-173, 179-185, 232-234, 277-278
9, 40, 44, 159
9-11, 18, 19-21, 25-27, 30
180-181, 277-278
278
303-304
58-67, 71
16-17, 87-109, 198
58-62, 68-86, 198
51, 199
51, 87-109, 172-178, 198-199
308-309
168-170, 300
n/a
Consolidated statements and other financial information
126-128, 129-209, 296-298, 306
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
306
n/a
306
n/a
n/a
n/a
n/a
309-312
300
306
306-308
n/a
n/a
313
n/a
181-185
n/a
n/a
n/a
313
None
None
126-127, 300-301
62, 75, 300
300
80, 199, 301
None
312
n/a
300
n/a
129-209
314
324
BP Annual Report and Form 20-F 2018
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.
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US
Tel +1 281 366 2000
This document constitutes the Annual Report and Accounts in accordance with UK requirements
and the Annual Report on Form 20-F in accordance with the US Securities Exchange Act of 1934,
for BP p.l.c. for the year ended 31 December 2018. A cross reference to Form 20-F requirements
is included on page 324.
This document contains the Strategic report on the inside front cover and pages 1-56 and the
Directors’ report on pages 57-86, 110-111, 210-237 and 273-322. 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 87-109. The consolidated financial statements of the group are
on pages 113-209 and the corresponding reports of the auditor are on pages 114-128. The parent
company financial statements of BP p.l.c. are on pages 238 -271.
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 13, 16, 19 and 20 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 2018 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
2018, 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. In the US, the company’s securities are
traded on the New York Stock Exchange (NYSE) in the form of ADSs (see page 306 for more
details) and in Germany in the form of a global depositary certificate representing BP ordinary
shares traded on the Frankfurt, Hamburg and Dusseldorf Stock Exchanges.
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
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This document has been printed using vegetable inks.
BP Annual Report and Form 20-F 2018
«See Glossary
325
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© BP p.l.c. 2019