BP Annual Report and Form 20-F 2019
Our purpose
is reimagining
energy for people
and our planet.
We want to help the world
reach net zero and improve
people’s lives.
We will aim to dramatically reduce carbon in
our operations and production and grow new
low carbon businesses, products and services.
We will advocate for fundamental and rapid
progress towards Paris and strive to be
a leader in transparency.
We know we don’t have all the answers
and will listen to and work with others.
We want to be an energy company with
purpose; one that is trusted by society,
valued by shareholders and motivating
for everyone who works at BP.
We believe we have the experience and
expertise, the relationships and the reach,
the skill and the will, to do this.
Financial statements
Consolidated financial statements
of the BP group
Notes on the financial statements
Supplementary information on
oil and natural gas (unaudited)
Parent company financial statements
of BP p.l.c.
Additional disclosures
Shareholder information
Glossary
Non-GAAP measures
reconciliations
Signatures
Cross-reference to Form 20-F
Information about this report
Exhibits
131
157
232
260
297
327
337
344
347
348
349
349
Strategic report
Chairman’s letter
Chief executive officer’s letter
Our ambition for the energy transition
At a glance
Global context
Our business model
Our strategy
Our investment process
Our strategy in action
Measuring our progress
Group performance
Sustainability
Upstream
Downstream
Rosneft
Other businesses and corporate
Alternative Energy
Section 172 statement
How we manage risk
Risk factors
Corporate governance
Board of directors
Executive team
The leadership team
Introduction from the chair
Board activities in 2019
2
4
6
8
10
14
16
19
24
32
36
39
50
56
61
63
63
66
68
70
74
78
80
82
84
How the board has engaged with shareholders, 88
the workforce and other stakeholders
Nomination and governance committee
Audit committee
Safety, environment and security
assurance committee
Geopolitical committee
Chairman’s committee
Directors’ remuneration report
Remuneration committee
Directors’ statements
90
91
96
98
99
100
101
128
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sustainability information.
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Glossary
Like any industry, ours has its own unique language.
For that reason, words and terms marked with
are defined in the glossary on page 337.
bp.com/annualreport.
bp.com/reportingcentre.
BP Annual Report and Form 20-F 2019
1
Chairman’s
letter
“
We enter a new
decade with a new
company purpose:
to reimagine energy
for people and
our planet.”
Our investor proposition
Growing sustainable free cash flow
and distributions to shareholders over
the long term.
$8.3bn
total dividends distributed
to BP shareholders
(2018 $8.1bn)
6.9%
annual dividend yield
ordinary share
(2018 6.3%)
2
BP Annual Report and Form 20-F 2019
Strategic report
Dear fellow shareholders,
As I write, the world is facing an
unprecedented set of challenges. The
coronavirus pandemic (COVID-19) is
spreading rapidly, with tragic consequences
for many people across many geographies.
Global efforts to stop the virus are also
having significant economic consequences.
And in an oil market where demand has
fallen, supply has sharply increased.
Though unprecedented, a global energy
company like BP should be prepared for
such challenges.
BP is indeed prepared. Our global
operating structure and long time-
horizons are intended to mitigate the
effect of near-term shocks. That is how
BP has approached shocks and volatility
in its 110-year history, and that is how
we will approach this storm too. In
particular, the past decade has given
BP unique experience in successfully
handling crises – and we enter this one
even better prepared.
But in this world of change, BP itself is also
changing. We enter a new decade with a
new company purpose: to reimagine
energy for people and our planet. We have
also set a new ambition: to become a net
zero company by 2050 or sooner, and to
help the world get to net zero. And to lead
and deliver on both we have a new chief
executive officer, Bernard Looney, who
took on the role on 5 February 2020.
Evolving for an uncertain world
This is a new direction for BP, and it is only
possible because of the foundation laid by
Bob Dudley. Bob served as BP’s group
chief executive with distinction for almost
a decade, and he and his team deserve
our considerable thanks for guiding BP to
a position of operational and financial
strength and deepened resilience.
At these times, BP’s 110-year history of
navigating uncertainty is also reassuring.
Your company has anticipated and
responded to change many times over.
Indeed, throughout 2019 your board has
focused on evolving BP’s strategy and
portfolio to address the challenges of
tomorrow. This focus has included
ensuring the smooth transition in
leadership from Bob to Bernard, followed
by regular engagement by the board with
Bernard and his new leadership team to
develop BP’s purpose and net zero
ambition. This is a process which has
been supported by our dialogue with
investors, governments, employees
and other key stakeholders.
Our enduring commitments
BP is now set for a future that is different
to its past, but some things won’t change.
BP’s values-based culture will be maintained
and further developed. BP’s purpose and
ambition reflect its culture, and together
they position BP well to develop as an
increasingly sustainable company.
Our commitment to safe and reliable
operations will remain paramount. BP’s
safety performance has seen near
continuous improvement since 2010, and
we must continue to learn and improve.
We believe that the new organizational
structure BP set out last month will help
to reinforce this commitment.
As well as our enduring commitment
to safety, BP’s commitment to its
relationships and partnerships will not
change, including with governments
around the world. BP intends to use its
energy market experience, skills and
technology to help countries, cities and
corporations decarbonize, while at the
same time building a thriving, lower
carbon energy business.
BP’s new ambition also gives us extra
reason to maintain the capital discipline
and focus that has served the company so
well. We can only reimagine energy if we
generate the cash needed to manage the
balance sheet, invest in new low carbon
businesses, and continue to pay the
dividend on which you, our owners, depend.
That is how we will meet our ambition. It is
something that I, together with the BP
board, look forward to working on with
Bernard and his executive team.
Our focus throughout 2020
One of the focal points for the board in
2020 will be BP’s capital markets day
in September, when Bernard and his
leadership team will lay out more detail
about the strategy, near-term targets and
ways to measure progress. It will be the
moment the vision and ambition set out in
February becomes much more concrete.
We will do this while ensuring that we
maintain a strong focus on high quality and
efficient operations and on delivering the
promises we have made to our investors
My thanks to you all
In addition to thanking Bob, two other
departing senior leaders deserve a special
mention – chief financial officer Brian
Gilvary, who has decided to step down from
the board in June after eight years in the job,
and Downstream chief executive Tufan
Erginbilgic, who leaves BP at the end of
March. On behalf of the board, I extend my
thanks and my deep appreciation for the
profound contributions they each made
during an important period for the company.
Of course, each of our employees has a
very important role to play in BP’s progress,
and they should be recognized. On behalf
of the board I extend my sincere thanks to
all our people for a job well done in 2019.
Today, BP’s engagement with its
customers, suppliers, shareholders,
employees and others is wider and deeper
than ever, but it has to further develop as
we progress on our journey. I therefore want
to use this opportunity to thank you, BP
shareholders, for your continued support
and engagement during 2019, including
through your votes at our AGM in May. Your
challenge and input have been important in
our effort to set a new strategic direction.
I look forward to continuing our dialogue.
Helge Lund
Chairman
18 March 2020
BP Annual Report and Form 20-F 2019
3
Reimagining and reinventing energy
In February, we announced a new
purpose for BP, and a major reorganization
to deliver our new ambition to be a net
zero company by 2050 or sooner and help
the world get to net zero.
Our investor proposition will remain
unchanged as we lay out new near-term
plans later this year. This includes our
commitment to growing sustainable free
cash flow and returns to shareholders
over the long term.
The current market shocks only reaffirm
the need for this reimagining of energy and
reinvention of BP. Our current upstream-
downstream structure has served us well
for over a century, but I believe we now
need a different model for the rapidly
changing demands of the future. We need
an agile, highly integrated structure that is
more focused than ever on our core
capabilities in operations, customers, low
carbon and innovation. The leadership team
is working with the board to develop this
structure, along with a new strategy and
near-term targets, which we intend to
share with you in September 2020.
I see huge opportunity for BP given our
distinctive combination of reach,
resources and relationships. The world will
need to invest trillions of dollars in new
energies over the next several decades.
We have the skill and the will to help the
world deliver a rapid energy transition.
Performing while transforming
This may be our most wide-ranging
reorganization for more than a century, but
I want to assure you of our commitment
to perform as we transform. Among many
significant changes, however, there will be
no change to the fundamental principles
that have served us well over the last
decade and which apply equally in low
price environments as well as high.
Above all, our commitment to safe and
reliable operations remains unchanged.
Safety will always be a BP core value and
we believe that the new structure we are
introducing will further strengthen our
safety performance.
We will continue to maintain a strong
financial frame, including a focus on
deleveraging our balance sheet and
staying within a disciplined frame for our
capital expenditure.
And now, more than ever, we will focus
on managing costs, pursuing efficiencies
and driving waste out of the system.
A force for good and competitive returns
This new decade is a pivotal time for BP.
We will continue to be an energy business,
but a very different kind of energy business
in years to come. We may not get
everything right along the way and will
need to listen and learn from others, not
least you, our owners.
But with your continued support we
expect to become leaner, faster-moving,
lower carbon – and more valuable.
Our destination is a thriving, sustainable
energy business in a net zero world. One
that is a motivating and inspiring place to
work for our employees. That is wanted
as well as needed by society. And one
that is valued by you, our shareholders, as
a force for good as well as a provider of
competitive returns.
Bernard Looney
Chief executive officer
18 March 2020
Chief executive
officer’s letter
Dear fellow shareholders,
As we publish this report, the world is
working through extraordinarily difficult
times. Countries around the globe are
battling the coronavirus pandemic
(COVID-19). People’s lives are being
hugely disrupted, with tragic
consequences for many. The financial
markets are reflecting the disruption and
our sector is particularly hard hit, not just
by a virus-related shock to demand but by
a supply-side shock as well.
At BP, we are taking calm and deliberate
actions for the well-being of our people
and the health of your company. We do
so with a robust balance sheet, strong
liquidity and the flexibility in our portfolio
and financial framework that provide us
with options.
A resilient company
This resilience is a tribute to Bob Dudley’s
leadership over the past decade.
Following the Deepwater Horizon
accident, Bob’s steady hand has guided
BP through recovery and back to growth
as a safer, stronger and more disciplined
company – one that has delivered
consistently for 12 consecutive quarters
on the plan we put forward in 2017.
• We made an underlying profit of
$10 billion in 2019.
• Operating cash flow was strong at
$26 billion for the year.
• That gave us the confidence to increase
our dividend, which currently stands at
10.5c per ordinary share.
During 2019, two colleagues sadly lost
their lives while working at BP. My heart
goes out to their families and friends. We
must learn from these tragedies and
continue to make BP safer. I believe that
we can build on progress that last year
saw our lowest-ever figure for BP people
getting hurt at work (our recordable injury
frequency measure).
Profit attributable to
BP shareholders
$4.0bn
Nearest GAAP equivalent
to underlying profit.
4
BP Annual Report and Form 20-F 2019
“
Our destination is a
thriving, sustainable
energy business in a
net zero world. One
that is a motivating
and inspiring place
to work for our
employees.”
Strategic report
Our purpose is reimagining energy
for people and our planet. This will
frame our thinking, our activities
and our interactions.
Introducing a new structure, new
leadership team and new ways
of working.
Our commitment to safe and
reliable operations remains
unchanged. And our investor
proposition remains unchanged.
BP Annual Report and Form 20-F 2019
5
Our ambition is to be a net
zero company by 2050
or sooner and to help the
world get to net zero.
Our ambition for the energy transition
Pursuing a strategy that is
consistent with the Paris goals
The world needs a rapid transition to net
zero and to reimagine the global energy
system. This presents an opportunity for
BP to provide the cleaner energy the
world wants and needs.
We see opportunities in helping the
world decarbonize through new
business models and creating cleaner
cities. We plan to provide more
information on our future strategy and
near-term plans at our capital markets
day in September 2020.
Responding to increased shareholder interest
In 2019 the board recommended that
shareholders support a special resolution
requisitioned by Climate Action 100+
(CA100+) on climate change disclosures.
The CA100+ resolution, which requires BP
to respond to a number of different elements,
passed with more than 99% of the vote.
These responses are contained throughout
this annual report.
The CA100+ resolution, which includes safeguards such as for commercially confidential and
competitively sensitive information, is on page 337. Key terms related to this resolution response
are indicated with and defined in the glossary on page 337. These should be reviewed with
the following information.
Element of the CA100+ resolution
Strategy that the board considers in good faith
to be consistent with the Paris goals.
Related content
Our strategy
For more information about how we
believe our current strategy is consistent
with the Paris goals, see page 17.
How BP evaluates each new material capex investment
for consistency with the Paris goals and other outcomes
relevant to BP’s strategy.
Our investment process
Disclosure of BP’s principal metrics and relevant
targets or goals over the short, medium and long
term, consistent with the Paris goals.
Anticipated levels of investment in:
(i) Oil and gas resources and reserves
(ii) Other energy sources and technologies.
Measuring our progress
Financial framework
BP’s targets to promote operational GHG reductions.
Sustainability
Estimated carbon intensity of BP’s energy products
and progress over time.
Sustainability
Any linkage between above targets and executive pay
remuneration.
Directors’ remuneration report
2019 annual bonus outcome
2020 remuneration: Policy on a page
6
BP Annual Report and Form 20-F 2019
Where
16
19
17
18
40
40
100
105
110
Strategic report
This is supported by 10 aims, which when taken
collectively, set out a path that we believe is
consistent with the Paris goals.
Five aims to get BP to net zero
Aim 1 is to be net zero
across our entire operations
on an absolute basis by
2050 or sooner. This aim
relates to Scope 1 and 2 GHG
emissions.
For more on our
operational emissions,
see Sustainability,
page 40.
Aim 2 is to be net zero on
an absolute basis across
the carbon in our upstream
oil and gas production by
2050 or sooner. This aim
relates to Scope 3 emissions,
and is on a BP equity share
basis excluding Rosneft.
See Sustainability,
page 40.
Aim 3 is to cut the carbon
intensity of the products
we sell by 50% by 2050 or
sooner. This is a lifecycle
carbon intensity approach,
per unit of energy. It covers
marketing sales of energy
products and potentially, in
future, certain other products
e.g. associated with land
carbon projects.
Aim 4 is to install methane
measurement at all our
existing major oil and gas
processing sites by 2023,
publish the data, and then
drive a 50% reduction in
methane intensity of our
operations. And we will work
to influence our joint ventures
to set their own methane
intensity targets of 0.2%.
See Sustainability,
page 40.
See Modernizing the
whole group, page 31.
Aim 5 is to increase the
proportion of investment
we make into our non-oil
and gas businesses. Over
time, as investment goes up
in low and no carbon, we see
it going down in oil and gas.
Five aims to help the world get to net zero
Aim 6 is to more actively
advocate for policies that
support net zero, including
carbon pricing. We will
stop corporate reputation
advertising campaigns and
re-direct resources to promote
well-designed climate policies.
In future, any corporate
advertising will be to push
for progressive climate policy;
communicate our net zero
ambition; invite ideas; or build
collaboration. We will continue
to run recruitment campaigns
and advertise our products,
services and partnerships –
although we aim for these to
increasingly be low carbon.
See bp.com/sustainability.
Aim 7 is to incentivize our
global workforce to deliver
on our aims and mobilize
them to become advocates
for net zero. This will include
increasing the percentage
of remuneration linked to
emissions reductions for
leadership and around
37,000 employees.
See Directors’
remuneration report,
page 100.
Aim 8 is to set new
expectations for our
relationships with trade
associations around the
globe. We will make the
case for our views on
climate change within the
associations we belong to and
we will be transparent where
we differ. And where we can’t
reach alignment, we will be
prepared to leave.
See Sustainability,
page 49 and bp.com/
tradeassociations.
Aim 9 is to be recognized
as an industry leader for
the transparency of our
reporting. On 12 February
2020, we declared our support
for the recommendations of
the Task Force on Climate-
related Financial Disclosures
(TCFD). We intend to work
constructively with the TCFD
and others – such as the
Sustainability Accounting
Standards Board – to develop
good practices and standards
for transparency.
See Sustainability,
page 44.
Aim 10 is to launch a new
team to create integrated
clean energy and mobility
solutions. The team will
help countries, cities and
corporations around the
world decarbonize.
BP Annual Report and Form 20-F 2019
7
2019 at a glance
Our scale, our reach and range of activities,
from exploration to refining and biofuels to solar,
make us a truly global energy provider.
This section gives an overview of BP’s structure, scale and performance
in 2019. For details of our future structure, see pages 15 and 80.
Upstream
Responsible for oil and natural gas exploration, field development
and production, gas and power marketing and trading activities.
Replacement cost (RC) profit
before interest and tax
$4.9bn
(2018 $14.3bn)
Underlying RC profit
before interest and tax
$11.2bn
(2018 $14.6bn)
Rosneft
We have a 19.75% shareholding in Rosneft, one of
Russia’s largest oil and gas companies, which has
both upstream and downstream operations.
RC profit before
interest and tax
$2.3bn
(2018 $2.2bn)
Underlying RC profit
before interest and tax
$2.4bn
(2018 $2.3bn)
Other businesses
and corporate
Downstream
Comprises our Alternative Energy business as
well as a number of corporate activities.
Comprises the manufacturing and marketing of fuels, lubricants, and
petrochemicals, as well as our oil integrated supply and trading function.
RC loss before
interest and tax
$(2.8)bn
(2018 $(3.5)bn)
Underlying RC loss
before interest and tax
$(1.3)bn
(2018 $(1.6)bn)
RC profit before
interest and tax
$6.5bn
(2018 $6.9bn)
Underlying RC profit
before interest and tax
$6.4bn
(2018 $7.6bn)
8
BP Annual Report and Form 20-F 2019
Strategic report
Scale
Performance
We are an integrated energy business. We
have operations in Europe, North and South
America, Australasia, Asia and Africa.
Our 2019 performance has helped us
deliver for our shareholders and other
stakeholders, including energy
consumers worldwide.
Advancing low carbon
We are committed to advancing a low carbon
future. We will aim to dramatically reduce
carbon in our operations and in our production,
and grow new lower carbon businesses,
products and services.
70,100
employees
(2018 73,000)
79
countries
(2018 78)
19,341
million barrels of oil equivalent –
group proved hydrocarbon reservesa
(2018 19,945mmboe)
18,900
retail sites
(2018 18,700)
98
tier 1 and 2 process safety events
(2018 72) KPI
$4.0bn
profit attributable to BP shareholders
(2018 $9.4bn)
$10.0bn
underlying RC profit
(2018 $12.7bn) KPI
>20
years in renewable businesses
>$500m
invested in low carbon activities in 2019
>7,500
BP Chargemaster charging points in the UK
94.9%
downstream refining availability
(2018 95.0%) KPI
13
countries where Lightsource BP
is active
3.8
million barrels of oil equivalent per day
– group hydrocarbon productiona
(2018 3.7mmboe/d)
a On a combined basis of subsidiaries and equity-accounted entities.
KPI See key performance indicators on page 32.
BP Annual Report and Form 20-F 2019
9
Global context
Many forces and trends are fundamentally changing
the business environment, creating uncertainties and
influencing the way we operate. We monitor these
trends closely and explore the forces shaping the
global energy transition.
Megatrends
BP Energy Outlook 2019
The exact pace and nature of the
energy transition is unclear, but it
is clear that the market for our
products is changing. Megatrends
affecting our industry include:
Growing global concern over
climate change
Rapidly advancing digital
technology, affecting all
aspects of economic activity
Increasing prosperity in the
emerging world driving
economic growth
Changing societal expectations
of corporations
Shifting geopolitical trends as
trade, economies and
relationships change over time
Growing global concern over
climate change is a key driving
force among these trends. The
way the world responds to this,
and the resulting impact on
the energy sector, is the most
significant uncertainty we face.
10
BP Annual Report and Form 20-F 2019
Our Outlook explores the forces shaping the
global energy transition out to 2040 and the
key uncertainties surrounding it. The 2019
Outlook considers a range of scenarios. They
have some common features, such as ongoing
economic growth and a shift towards a lower
carbon fuel mix, but differ in terms of policy,
technology and behavioural assumptions.
Scenarios
• Evolving transition: assumes that government
policies, technology and social preferences
continue to evolve in a manner and speed seen
over the recent past.
• Rapid transition: envisages a more rapid
transition to a lower carbon energy system,
through a reduction in emissions stemming from
greater energy efficiency, fuel switching and use
of carbon capture, use and storage (CCUS).
For more information see bp.com/energyoutlook.
The BP Energy Outlook 2020 will be published
later in the year.
Global carbon emissions
(GtCO2)
50
45
40
35
30
25
20
15
10
5
0
1970
1980
1990
2000
2010
2020
2030
2040
Evolving transition
Rapid transition
Source: BP Energy Outlook 2019
Strategic report
The transition envisaged in the 2019 Outlook
The world economy continues to grow,
driven by increasing prosperity
• The global population grows by 1.7 billion,
reaching close to 9.2 billion people in 2040.
• The global economy more than doubles over
the next 25 years, with twice as much
economic activity in 2040 than we see today.
• The emergence of a large and growing
Demand for energy is set to
grow significantly
• Global energy demand increases by about
20-35% by 2040 in the different scenarios.
• The vast majority of demand growth comes
from developing economies to support their
industry and infrastructure and allow living
standards to keep improving.
But carbon emissions need to fall sharply
• There is a growing commitment around
the world to move to a pathway consistent
with meeting the climate goals of the
Paris Agreementa.
• To help achieve this, the world needs to
transition to a lower carbon energy system.
middle class, particularly in emerging Asia,
is an increasingly important force shaping
growth and energy trends.
The key dimensions of the energy transition
To meet the Paris goals, we believe the world must take strong action on a range of fronts.
Improving energy efficiency, to
decouple energy demand growth
from growing prosperity.
Switching to lower or zero carbon liquid
and gaseous fuels, particularly in areas
such as heavy transport.
Rapid growth in renewable energy and
other low or zero carbon energy sources.
Deploying carbon-removal technologies,
such as CCUS, at scale.
Increasing the share of electricity in
final energy use and decarbonizing
power generation.
Promoting natural climate solutions,
including the management and restoration
of habitats, and the role of carbon credits.
The pace at which the transition can be
achieved and the precise mix of elements
is uncertain.
There are many possible pathways to meeting
the Paris goals and we use different scenarios
to explore this uncertainty. When we evaluate
the consistency of our new material capex
investments with the Paris goals, we
consider a range of different possible
pathways and scenarios, see page 21.
a Paris Agreement: (1) Article 2.1(a) of the Paris Agreement states the goal of ‘Holding the increase in the global average temperature to well below 2°C above pre-industrial levels and pursuing
efforts to limit the temperature increase to 1.5°C above pre-industrial levels, recognizing that this would significantly reduce the risks and impacts of climate change.’ (2) Article 4.1 of the
Paris Agreement: In order to achieve the long-term temperature goal set out in Article 2, parties aim to reach global peaking of greenhouse gas emissions as soon as possible, recognizing
that peaking will take longer for developing country parties, and to undertake rapid reductions thereafter in accordance with best available science, so as to achieve a balance between
anthropogenic emissions by sources and removals by sinks of greenhouse gases in the second half of this century, on the basis of equity, and in the context of sustainable development and
efforts to eradicate poverty.
BP Annual Report and Form 20-F 2019
11
85%
of primary energy growth
is from renewables and
natural gas in our ‘evolving
transition’ scenario
Primary energy consumption by fuel
Exajoules (EJ)
2040
800
700
600
500
400
300
200
100
0
2017
Evolving
transition
Rapid
transition
Renew*
Hydro
Nuclear
Coal
Gas
Oil
* Renewables includes wind, solar, geothermal,
biomass and biofuels
Source: BP Energy Outlook 2019
Demand and supply of oil
(Mb/d)
140
120
100
80
60
40
20
0
1970
1980
1990
2000
2010
2020
2030
2040
Evolving transition
Rapid transition
Source: BP Energy Outlook 2019
(cid:31)Supply with no investments in new fields
The changing energy mix
Increased demand for energy is likely to be
met over the coming decades through a
diverse range of supplies including renewable
energy, oil and natural gas.
The energy mix is shifting as the transition to a
lower carbon energy system continues, with
renewable energy and natural gas gaining in
importance relative to oil and coal.
Scenarios
• Evolving transition: renewables and natural
gas account for almost 85% of the growth in
primary energy by 2040, with their
importance increasing relative to all other
sources of energy.
• Rapid transition: renewable energy grows
rapidly, accounting for more than the entire
increase in primary energy by 2040 – and a
sharp contraction in the use of coal. The
level of oil consumption falls, but gas
continues to grow aided by increasing use
of carbon capture, use and storage (CCUS).
What this means for oil and gas
The BP Energy Outlook 2019 considers a range
of scenarios for oil demand, with the timing of
the peak in demand varying from the next few
years to beyond 2040.
Despite these differences, the scenarios
share two common features. First, they
each suggest that oil will continue to play a
significant role in the global energy system
in 2040, with the level of oil demand in 2040
ranging from around 80Mb/d to 100Mb/d.
Second, significant levels of investment are
required for there to be sufficient supplies of
oil to meet demand in 2040.
Similarly there is a wide range of uncertainty
in relation to the role of gas in the energy mix
even in scenarios that achieve the Paris goals,
with different organizations using significantly
different assumptions. Those with a higher
proportion of CCUS see a higher demand for
gas, and in the outlook’s ‘rapid transition’
scenario, close to a third of natural gas in
2040 is being used in conjunction with CCUS.
12
BP Annual Report and Form 20-F 2019
Achieving the Paris goals – a multitude of pathways
Strategic report
There are many different pathways to
achieve the Paris goals, with substantial
variation in the implied energy mix.
The Intergovernmental Panel on Climate
Change (IPCC) is the United Nations’ body
for assessing the science related to climate
change. It is the leading source of data that
summarises the potential pathways to
achieve the Paris goals. The IPCC compiles
a database of the published results on
mitigation pathways from modelling teams
around the world.
The chart shows a range of modelled
pathways for carbon emissions from energy
and industrial use, collected by the IPCC,
that meet the long-term temperature goals
in the Paris Agreement, together with the
paths associated with two of BP’s own
scenarios. The ‘rapid transition’ scenario
clearly sits well within the range. Also
highlighted is the ‘Sustainable Development
Scenario’ from the International Energy
Agency (IEA SDS), which is often cited
as a reference case for a scenario that is
consistent with meeting the Paris goals.
Global energy markets in 2019
The world economy grew at 2.4% in 2019,
reflecting slower growth in both advanced and
emerging economies, amid weakening trade
and investment. This was below the average
of around 3% seen over the past 10 years.
Growth in advanced economies was 1.6% in
2019 while in emerging markets was 3.5%a.
2020 volatility
There has been considerable market
volatility in the first quarter, compounded
by the coronavirus (COVID-19). We
expect the outlook for the year to remain
challenging, see pages 52 and 57.
Global carbon emissions from energy use
(GtCO2)
40
30
20
10
0
-10
-20
1980
1990
2000
2010
2020
2030
2040
2050
2060
2070
2080
2090
2100
Range of scenarios collected by the IPCC which
meet the long-term temperature goals of the
Paris Agreement
Energy Outlook ‘evolving transition’
IEA SDS
Energy Outlook ‘rapid transition’
Source: Integrated Assessment Modeling Consortium (IAMC) 1.5°C Scenario Explorer and Data hosted
by International Institute for Applied Systems Analysis (IIASA), release 2.0. Scenario data has
been rebased to common starting point that matches the BP Energy Outlook history for 2015.
Oil
• Dated Brent crude oil prices averaged
$64 per barrel in 2019 – a 9% decrease
from 2018 levels but almost 30% above
the 2015-17 average.
• Global consumptionb increased by
0.9 million barrels per day (mmb/d) to
100.1mmb/d for the year (0.9%) – a
slowdown from growth rates seen in the
prior two years as trade tensions slowed
global macroeconomic growth.
• Global oil production remained flat at
100.5mmb/d, with growth from non-OPEC
countries offsetting supply restraint and
disruptions in OPEC countries.
Natural gas
• Gas spot prices dropped in all three
key regional markets in 2019.
• Global consumptionc growth slowed
down in 2019 compared with the
exceptional growth in 2018, driven by
slower growth in both the US and China.
• Total gas production growth slowed
down in 2019, with the exception of the
US. Meanwhile, LNG trade increased
significantly during 2019.
For more information on prices and margins
see pages 52 and 58.
a World Bank Global Economic Prospects, January 2020.
b
c JODI-Gas World Database, and IHS Markit: China Natural Gas Data Tables: February 2020 for China.
IEA Oil Market Report, February 2020©.
BP Annual Report and Form 20-F 2019
13
Our business model
We deliver a diverse range of energy products
and services to people around the world.
What
we do
New business models
Investing in innovative companies across
our value chain to help accelerate and
commercialize new technologies, products
and business models that we believe can
benefit BP and global energy systems.
Venturing and low carbon
across the business
Finding and
generating energy
Refining, manufacturing
and marketing
Delivering products
and services
Repowering some
of our facilities
Using technology and
partnership to recycle
and reuse our products
Transport and trading
• Producing refined petroleum products and
scaling up co-processing of lower carbon
fuels at our refineries.
• Manufacturing and marketing lubricants
and petrochemicals products.
• Developing technologies to help advance
the circular economy, such as BP Infinia,
which can recycle previously
unrecyclable plastics.
• Delivering fuels, fast electric-vehicle
charging and convenience retail services,
as well as premium and lower carbon
lubricants.
• Supplying petrochemical products that
are used to make a range of products
including clothes and building materials.
• Providing renewable power to industries
and local electricity grids.
• Finding additional resources and
replenishing our development options
with exploration and technology.
• Developing and extracting oil and gas, and
seeking to extend the life of existing fields.
• Generating renewable energy using
biofuels, biopower, wind and solar.
More information
Upstream on page 50.
Downstream on page 56.
Other businesses and corporate on page 63.
14
BP Annual Report and Form 20-F 2019
Strategic report
Reinventing BP
On 12 February 2020 we introduced our ambition and aims with a new structure, a new leadership team, and new ways of working.
To deliver our ambition we are reinventing BP, retiring our existing model and replacing it with one that is more focused, more integrated and
faces the energy transition head on. One that can deliver for the changing demands of consumers, investors and governments.
Our new leadership structure is due to come into place on 1 July 2020 and is expected to be fully operational by 1 January 2021. The new
leadership will focus on four core capabilities: operations, customers, low carbon and innovation. These four highly focused business groups
will work with three integrators (sustainability and strategy; regions, cities and solutions; and trading and shipping) to facilitate collaboration
and unlock value. And four teams will serve as enablers of business delivery.
For more information see bp.com/reimagine.
Business model
foundations
These are the things that every
energy business needs and are
critical foundations for what we
do and how we do it.
Partnerships and collaboration
We aim to build enduring relationships with our
key stakeholders, and partner with others to find
innovations that can improve efficiency and deliver
low carbon solutions.
Governance and oversight
Our board has a diversity of knowledge, expertise,
and ways of thinking that help us transition our
business, manage risks and continue to deliver
value over the long term.
• 20 years of collaboration with the world’s
• ~42% of the company’s board are women.
top universities.
See page 74.
Safe and reliable
We value the safety of our workforce and focus on
maintaining a safe operating culture every day. This
culture of safety also improves the integrity and
reliability of our assets.
Talented people
We work to attract, motivate 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.
Technology and innovation
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.
• 94.4% BP-operated upstream plant reliability.
• 8th most desirable employer in the UK
• >3,900 patents granted or pending across
See page 45.
What makes
us different
These are the things we believe set us
apart from our peers and demonstrate
our distinctive ways of working.
on LinkedIn.
See page 47.
the BP group in 2019.
Global energy trading
We combine expertise in physical supply and trading
and advanced analytics to deliver long-term value,
from wellhead to end customer. We trade a variety of
products such as crude oil, refined products, natural
gas, LNG, carbon products and power.
Distinctive customer offers
Our convenience partnerships provide customers
with a differentiated offer that includes fresh,
high-quality food and drink, such as M&S Simply
Food® in the UK and REWE to Go® in Germany.
4bn
~1,600
barrels of crude a year traded, equivalent
to 20% global traded oil.
differentiated convenience partnership sites
across our network of around 18,900 retail sites.
‘Reduce, improve,
create’ framework
Our framework helps focus everyone in BP on our low
carbon ambitions. It encompasses activities across
the group to reduce emissions from our operations,
improve the products we offer to help customers
reduce their emissions, and create low or zero carbon
businesses to deliver more energy with fewer emissions.
Rosneft
partnership
Our share in Rosneft, one of Russia’s largest oil and gas
producers, gives us a stake in one of the largest and
lowest-cost hydrocarbon resource bases in the world,
with access to huge markets, both east and west.
0.14%
methane intensity in 2019.
See page 40.
19.75%
BP’s stake in Rosneft.
See page 61.
BP Annual Report and Form 20-F 2019
15
Our strategy
We have established a track record
of operational and financial delivery.
This has helped create a strong
foundation for us to advance our
low carbon agenda as we work to
achieve our ambition to become
a net zero company by 2050 or
sooner and to help the world get
to net zero.
Our strategy, which we set out in
2017, allows us to be competitive,
flexible and resilient while also
responding to a rapidly changing
energy landscape, with growing
expectations for us to adapt to
changing demands from
stakeholders.
We remain committed to managing
our portfolio for value, and investing
with discipline in flexible and
resilient options, which together
support our pursuit of a strategy
which we believe is consistent with
the goals of the Paris Agreement.
Following BP’s new ambition and
aims, set out in February 2020, we
plan to announce more information on
how we intend to reimagine energy
and reinvent BP, while performing as
we transform, at our capital markets
day in September 2020.
Strategic
priorities
Growing
advantaged
oil and gas in
the Upstream
Invest in oil and gas,
producing both with
increasing efficiency
(lower cost, higher
margin and close to
markets), with a focus
on carbon.
Market-led
growth in the
Downstream
Innovate with
advanced products and
strategic partnerships,
building competitively
advantaged businesses
that deliver profitable
marketing growth
Venturing and
low carbon
across multiple
fronts
Pursue new
opportunities to meet
evolving technology,
consumer and
policy trends.
Modernizing
the whole group
Simplify our processes
and enhance our
productivity through
digital solutions.
See page 25.
See page 27.
See page 28.
See page 31.
Supported
by our
low carbon
ambitions
Embedded within
our strategy is our
commitment to advance
a low carbon future.
We plan to deliver this
across our entire
business through what
we call our ‘reduce,
improve, create’
(RIC) framework.
Reducing
emissions in
our operations
Improving
our products
• Achieve zero net
growth in operational
emissions out to 2025.
• Make 3.5Mte of
sustainable GHG
reductions by 2025.
• Target industry leading
methane intensity of
0.2%.
• Provide lower
emissions gas.
• Develop more
efficient and lower
carbon fuels,
lubricants and
petrochemicals.
• Grow lower carbon
offers for customers.
Creating
low carbon
businesses
• Expand low carbon
and renewable
businesses.
• Invest $500 million in
low carbon activities
each year.
• Collaborate and invest
in the OGCI’s $1bn+
fund for research
and technology.
For more information on our RIC framework,
see page 41.
16
BP Annual Report and Form 20-F 2019
Strategic report
Pursuing a strategy that is
consistent with the Paris goals
In February 2020 we set out our ambition to be
a net zero company by 2050 or sooner and to
help the world get to net zero. This is supported
by 10 aims which, when taken collectively, set
out a path that we believe is consistent with the
Paris goals, see page 7. One specific aim relates
to increasing the proportion of investment in
our non-oil and gas business. Over time, as
investment in low or no carbon activity increases,
we see investment in oil and gas going down.
Since 2017, when BP reset its five-year strategy,
we have pursued a way forward that is flexible
and adaptable to a range of energy and market
scenarios. These different scenarios are based on
a range of assumptions about policy, technology
and consumer behaviour, and supply and demand
changes. We do not know what path the energy
transition will take, so BP’s strategy is intended to
be effective under a range of scenarios, and not a
single, deterministic view of the future – in short,
responsive to uncertainty.
We believe that our current strategy is consistent
with the Paris goals. This consistency has, at its
core, two key parts. And these remain relevant as
we work towards our net zero ambition and aims.
1. We are striving to play our part in meeting the
world’s energy needs in reliable, affordable and
lower carbon; and we intend to achieve this
through collaboration, technology, innovation
and advocating for progressive climate policies
to advance a low carbon future in support of the
Paris goals.
In 2019 examples included:
• Launching a review of our climate-related trade
association memberships – read more on page 49.
Our aim going forward is to set new expectations
for trade associations around the globe.
• Establishing a collaboration with DiDi to begin
building an electric-vehicle charging network in China.
• Beginning the roll out of ultra-fast chargers across
BP forecourts in the UK and piloting ultra-fast
charging at Aral forecourts in Germany, bringing
charging time closer to the time taken to fill a tank.
• Increasing our stake in Lightsource BP to create a
50:50 joint venture.
• Expanding our biofuels business in Brazil by more
than 50% through a joint venture with Bunge to
create BP Bunge Bioenergia.
• Installing continuous methane measurement at our
Khazzan central processing facility in Oman to help
quickly identify new leaks and reduce time taken
to respond.
• Supporting well-designed carbon pricing, such as
the Washington State cap-and-invest bill. We aim
to advocate more actively for policies that support
net zero, including carbon pricing.
For more information on our strategy in action,
see pages 24-31.
2. We believe that our strategy positions BP to
remain an attractive investment for current
and prospective shareholders throughout the
energy transition, including in a world that is
meeting the Paris goals. Our strong and
disciplined financial framework supports the
delivery of our strategy. This provides us with
a strong platform to deliver our purpose to
reimagine energy, and work towards our new
net zero ambition and aims.
For more information on our investor
proposition and financial framework, see
page 18.
The role of the board
The board is responsible for setting the strategy
and has oversight of the overall conduct of the
group’s business. During 2019, the board
considered BP’s strategy at every board meeting.
This took into account the wider operating
environment and discussed strategic themes
relating to BP’s purpose, including in relation to
the segments and key functions. The impact of
the lower carbon energy transition on the group’s
business model was also reviewed and discussed
throughout 2019. As a result, the board considers
that the strategy allows us to be flexible to adapt
to market changes and scenarios to remain
consistent with the Paris goals.
For more information on the role of the board
in relation to climate governance, see page 42.
For the board’s activity in relation to strategy,
see Corporate governance on page 84.
Measuring our progress
Our group-wide principal metrics and relevant targets/goals
The CA100+ resolution requires us to disclose
the company’s principal metrics and relevant
targets or goals consistent with the Paris goals.
We consider this to cover the principal metrics
used at group level to help monitor progress
on delivery of our strategic consistency with
the Paris goals – including our near-term
RIC framework.
A number of these metrics and targets are
relevant to the recommendations of the
Task Force on Climate-related Financial
Disclosures (TCFD).
Going forward, we are considering metrics to
support our ambition to be a net zero company
by 2050 or sooner, and to help the world get to
net zero. We plan to provide more information
on our future strategy and near-term plans at
our capital markets day in September 2020.
RIC framework
Sustainability, page 40.
Reduce
• Zero net growth in operational emissions out to 2025.
• 3.5Mte sustainable emissions reductions by 2025.
• 0.2% methane intensity.
Create
• $500 million invested in low carbon activities annually.
(>$500 million in 2019).
• Collaborate and invest in OGCI’s $1bn+ fund for
research and technology.
Investment process (RCM)
Our investment process, page 22.
• Profitability index.
• Average operational carbon intensity.
Greenhouse gas emissions
Sustainability, page 40.
Carbon intensity
• Scope 1 and 2 emissions.
• Emissions from the carbon in our upstream oil and
gas production.
• For further GHG metrics see bp.com/ESGdata.
• Average emissions intensity of marketed energy products.
• Ratio of Scope 1 and 2 emissions: gross production.
Remuneration
• 2020 annual bonus scorecard target related to sustainable
Directors’ remuneration report, page 100.
emissions reductions.
BP Annual Report and Form 20-F 2019
17
For more information on the TCFD, see page 42.
Sustainability, page 40.
Our investor
proposition
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.
Our financial
framework
We maintain a disciplined financial
framework, which underpins our strategy
and investment choices, and supports
growth in sustainable free cash flow,
returns and distributions to shareholders.
This discipline helps us maintain a
focused portfolio, which we believe is
resilient in the long run to many potential
outcomes and seeks to grow long-term
returns to shareholders.
Our capital frame is reviewed on an ongoing
basis. We believe that the continuing flexibility
it provides gives us the flexibility to pursue
our net zero ambition and aims, allocating an
increasing proportion of investment toward
lower carbon businesses over time. This will
help drive both the long-term resilience of
the portfolio and the creation of new value.
This is balanced against the pace of
development of these new lower carbon
business developments and levels of cash
flow generation.
In addition, our capital expenditure programme
has flexibility, which enables us to respond
to a low-price environment by reducing or
rephasing investment.
18
BP Annual Report and Form 20-F 2019
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
We continue to expect to deliver the 2021
targets laid out three years ago.
We plan to increasingly focus our investment
on the highest-quality barrels and drive returns
and cash flow, not volumes. As a result, the
anticipated proportion of our investment that
goes to oil and gas is expected to change.
The CA100+ resolution requires us to disclose
(a) our anticipated investment in oil and gas
resources and reserves – this is anticipated
to be less in 2020 than it was in 2019, and
(b) our anticipated investment in other energy
sources and technologies – which is
anticipated to be significantly greater
than 2019 levels.
We also plan to provide more information
on this as part of our capital markets day
in September 2020.
Upstream production excluding Rosneft
2.6mmboe/d
2019 actual
Organic capital expenditure
Depreciation, depletion and amortization
Gulf of Mexico oil spill payments
Other businesses and corporate average
underlying quarterly charge
Underlying effective tax rate
$15.2bni
$17.8bn
$2.4bn
$320m
36%ii
Nearest equivalent GAAP measures: i Capital expenditure: $19.4bn.
ii Effective tax rate: 49%.
2020 guidance
Lower than
2019
Lower end of
$15-17bn
range
Slightly below
2019
<$1bn
~$350m
Below
40%
Our investment process
Strategic report
BP’s investments fall within
a governance framework.
This seeks to ensure investments align with
our strategy, fall within our prevailing financial
framework, and add shareholder value. The
governance framework also provides for
investments to be assessed consistently
and against a range of other outcomes
relevant to our strategy, including a range
of environmental and sustainability factors.
Investments follow an integrated stage gate
process designed to enable us to choose
and develop the most attractive investment
cases. A balanced set of investment criteria
are used, see page 20. This allows for the
comparison and prioritization of investments
across an increasingly diverse range of
business models.
The governance framework also specifies
that investments are tested against a range
of carbon prices for projected operational
emissions and subject to assurance by
functions independent of the business before
a final investment decision (FID) is taken.
For more information on BP’s governance
framework, see page 83.
Price assumptions
Resource commitment meeting
Investments are evaluated against a range
of alternative prices (central, upper and lower)
for oil, natural gas, refining margins and carbon
prices. These price ranges do not link to
specific scenarios or outcomes, but instead
try to capture the range of different
possibilities surrounding the future path of
the global energy system. The price ranges
refer to the long-run level of prices over the
next 20 years. The nature of the uncertainty
means that these price ranges inevitably
reflect considerable judgement. The ranges
are reviewed and updated on an annual basis
as our understanding and judgement about
the energy transition evolves.
Range of prices
Brenta
($/bbl)
Henry
Huba
($/mmBtu)
RMMb
($/bbl)
90
70
50
5.0
4.0
2.0
17
14
11
For capital investments above defined financial
thresholds for organic or inorganic spend, the
investment approval is conducted by the
executive-level resource commitment meeting
(RCM), which is chaired by the chief executive
officer. The RCM reviews the merits of each
such investment case against a balanced set
of criteria and considers any key issues raised
in the assurance process.
The CA100+ resolution requires BP to disclose
how we evaluate the consistency of new
material capex investments with (i) the Paris
goals and (ii) a range of other outcomes
relevant to BP’s strategy. BP’s evaluation of
consistency of such investments with the Paris
goals was undertaken by the RCM in 2019.
The role of the board
The board assesses the impact of portfolio
changes, such as strategic acquisitions and
the allocation of capital. They also consider
specific investment cases deemed sufficiently
material to warrant their attention, which have
been approved by the RCM.
Upper case
Central case
Lower case
Carbon prices
Upper case
Central case
Lower case
a 2015 $ real.
b Nominal.
($/tonnea)
For more information on climate governance,
see page 42.
80
40
0
BP Annual Report and Form 20-F 2019
19
Balanced investment criteria
For the purposes of evaluating consistency
with a range of other outcomes relevant to
BP’s strategy, all group-wide investment
cases are required to set out the investment
merits in a standard format against a set of
balanced criteria.
Investments are considered against a range
of prices (upper, central and lower). All three
price assumptions place some weight on
scenarios in which the transition to a low
carbon energy system is sufficiently rapid
to meet the goals of the Paris Agreement,
as well as scenarios in which the transition
is not, or may not be, sufficiently rapid.
They also place some weight on a range
of other factors, which can drive prices,
and are not related to the goals of the
Paris Agreement.
In addition, investment cases are asked
to present scenarios covering a range of
variables, related to the economics of the
investment, such as cost, resource, policy
changes and schedule, to highlight the
robustness of investment cases to a range
of other factors.
This standardized approach creates a level
playing field for decision making and allows
portfolio wide comparisons of investment
cases. Further, the decision to endorse an
investment based on the information
provided represents BP’s evaluation that
the investment is considered consistent
with a range of other outcomes, relevant
to BP’s strategy.
20
BP Annual Report and Form 20-F 2019
Investment
economics
Safety
and risks
Cash flow
certainty
Investment
criteria
Capability
and scale
Optionality
Environment
and
sustainability
Environment and sustainability
All investment cases are considered
against appropriate environmental impacts
and sustainability measures, including but
not limited to carbon. Investment cases
above defined thresholds for anticipated
annual greenhouse gas (GHG) emissions
from operations must estimate those
anticipated GHG emissions and include
an associated carbon price of $40/te
2015 $ real (and sensitivities of $0 and
$80) in the investment economics.
Capability and scale
For all investment cases, we consider whether
they involve distinctive capability that BP has,
or intends to develop, and whether it adds to
an existing ‘scale’ business within the portfolio
or could help us create one.
Investment economics
We consider investment economics against
a range of measures including profitability
index, internal rate of return, net present
value, discounted payback, investment
efficiency, using a set of scenarios for
commodity prices, margins and carbon prices.
Investments are generally considered against
internal rate of return hurdles typically set in
the mid to high teens. Close attention is paid
to discounted payback as a measure of
commercial risk in the context of the energy
transition and profitability index as a measure
of capital efficiency.
Cash flow certainty
Economic metrics are also considered in
the context of the cash flow certainty of the
investment assumptions. For example, a high
return deepwater tieback will have less certain
and more volatile (oil price linked) cash flows
than a lower return but more certain renewable
power project with a long-term power purchase
agreement (and a fixed power price).
Safety and risks
Investment cases are required to describe
risks unique to the project which have a
significantly higher probability than usual or
have a significantly greater impact (relative to
the size of the project) were they to occur.
Optionality
All investment cases are requested to
quantify the strategic optionality that might
be accessed through follow-on activity.
For example, a greenfield offshore platform
may provide additional optionality to develop
nearby satellite fields in the future.
Strategic report
Evaluating new material capex investments for consistency
with the Paris goals
When evaluating the consistency of our 2019
new material capex investments with the
Paris goals, a focus of the evaluation criteria
was on their competitiveness and financial
robustness as the prices of different forms of
energy and products adjust in response to the
changing market environment.
The 2019 evaluation was done in the context
of a ‘sustained low-price environment’, which
assumes the lower price case for oil ($50/bbla),
natural gas ($2/mmBtua) and refining margins
($11/bbl (nominal)) together with the higher
carbon price ($80/teCO2
a).
These price assumptions do not
correspond to a single specific ‘Paris-
consistent’ scenario, but instead place
weight on a range of possibilities for how
the demand for different forms of energy
may change in Paris-consistent pathways
and how this may affect future energy pricesb.
Sustained low-price environment
Oil price (Brent):
$50/bbla
In many ‘Paris-consistent’ scenarios, global oil demand peaks within the next five years or so and falls
between 15-35% by 2040. Such a fall in demand, combined with the abundance of oil resources, would be
expected to lead to an increasingly competitive market for oil. But the extent to which these competitive
forces feed through into a sustained reduction in global oil prices is expected to be tempered by the
dependence of many oil-producing economies on oil revenues to support their wider economies.
For example, the IMF estimate that the fiscal break-even prices of the major Middle East and North African
oil exporters is close to $80c. We consider that the pace at which the major oil producing economies are
able to diversify their economies and so reduce the fiscally sustainable price at which they can produce oil
is likely to limit the extent to which oil prices can fall on a sustained basis over the next 20 yearsd.
US natural gas price (Henry Hub):
$2/mmBtua
The price of US gas (Henry Hub) is used as the main price for evaluating gas-based investments, either
directly for US-based projects or indirectly (via netback pricing relationships) for gas-based projects in other
parts of the world.
Refining marker margin (RMM):
$11/bbl
(nominal)
Carbon prices:
$80/teCO2
a
The outlook for natural gas in ‘Paris-consistent’ scenarios is more varied across different scenarios: some
point to global gas consumption increasing or remaining broadly flat over the next 20 years; others point to
gas demand peaking within the next five years and declining by 20-30% by 2040. These differences stem
in part from the extent to which natural gas is assumed to be used in conjunction with carbon capture, use
and storage (CCUS) projects, either in the power and industrial sectors directly, or to produce decarbonized
gas (in the form of ‘blue’ hydrogen). US natural gas prices will also depend on a number of supply-side factors,
such as: the extent to which productivity gains within shale gas continue to improve, and how quickly US
tight oil production – and hence the associated gas produced as part of that production – peaks.
The outlook for refining margins is most relevant when considering investments in refineries or closely
related activities.
Many ‘Paris-consistent’ scenarios provide less detailed information on the outlook for refined products and
refining activity. However, the significant falls in global oil demand envisaged in many of these scenarios
are likely to also be reflected in the demand for refined products. Indeed, some scenarios highlight the
expected growth in natural gas liquids (NGLs) and biofuels which suggest that refining activity might
decline by even more than the overall demand for liquid fuels. To the extent that falling demand for refined
products leads to over-capacity in the refining sector, this would be expected to lead to the least-efficient
refineries closing over time, raising the average efficiency of the remaining refineries and so reducing the
sustainable level of refining margins. However, the need for some refineries to continue to operate can
be expected to limit the extent to which refining margins can fall on a sustained basis.
The outlook for carbon prices has both a direct and indirect effect on the evaluation of new material
investments. The direct effect relates to the operational emissions associated with different investment
projects: the greater the operational emissions, the greater the exposure to increases in carbon prices.
The indirect impact relates to the impact of carbon prices on the differential between retail and wholesale
prices for oil and natural gas. An increase in carbon prices can be expected to increase the differential
between retail and wholesale prices: potentially both dampening demand growth (due to higher retail
prices) and reducing the prices received by oil and gas producers (due to lower wholesale prices). The
direct effects associated with carbon prices are explicitly assessed within BP’s investment evaluation
criteria, whereas the indirect effects are captured within the overall prospects for oil and gas demand
and the associated prices.
In many ‘Paris-consistent’ scenarios, carbon prices are used as a key policy instrument for accelerating
the transition to a low carbon energy system, with carbon prices (on a global basis) increasing to between
$100-200/teCO2 by 2040. But in these scenarios, carbon prices are typically increased only gradually,
in part since this mitigates the costs to the economy of prematurely scrapping and replacing productive
assets. Hence, the average level of carbon prices in these scenarios over the next 20 years tends to be
significantly lower than the level they are projected to reach in 2040 or so. For example, in BP’s rapid
transition scenario, carbon prices in developed economies are assumed to reach $200/teCO2 by 2040,
but the average level of carbon prices between 2017 and 2040 in that scenario is around $75/teCO2.
a 2015 $ real.
b To aid this analysis, we consider a range of scenarios which claim to be consistent with meeting the Paris goals including: IEA’s ‘Sustainable Development Scenario’, BEIS’ ‘Low Prices’
case, Aurora Energy Research’s ‘Two degrees’ scenario and MIT’s ‘Paris to 2°C’ scenario.
c Regional Economic Outlook – Middle East and Central Asia, International Monetary Fund, October 2019.
d The Oil and Gas Industry in Energy Transitions | IEA 2020.
BP Annual Report and Form 20-F 2019
21
Evaluating new material capex investments for consistency
with the Paris goals – continued
Evaluation process
Our new material capital investments
are intended to support the delivery of
BP’s strategy. In 2019, we evaluated
their consistency with the Paris goals
by considering them against a balanced
set of investment criteria (see page 20).
For each of the investment criteria, a
qualitative explanation of each business
case was considered and presented to
the resource commitment meeting (RCM).
They then discussed and addressed key
issues raised, as per the description on
page 19.
Two quantitative evaluations were
considered for Paris consistency. As our
approach matures with experience, we
may adjust or supplement these.
Evaluation outcome
As shown in the figure, each of the new
material capex investments approved in
2019 met the evaluation guides, with the
exception of one investment not meeting
the guide level for carbon intensity. This
investment was evaluated to be consistent
with the Paris goals, based on the strength
of the investment economics with a short
payback period, delivering short-cycle cash
returns and reducing the timeframe during
which the investment would be exposed
to uncertainties associated with Paris
consistent pathways.
In 2019, the overall averages for the new
material capex investments met the guide
levels for each of the two quantitative
evaluation tests:
• Profitability index on an average capital
weighted basis was approximately 1.5x,
versus a guide level of greater than 1.0x.
• An average operational carbon intensity
of approximately 45% relative to the
current portfolio(s), versus a guide level of
less than 100%.
Quantitative evaluations
Investment economics
The calculation of profitability index (PI)
using the ‘low-price’ case for commodity
prices and margins and the ‘high’ carbon
price of $80 per tonne (2015 $ real). As a
guide, we would normally target a minimum
threshold of greater than 1.0x on this basis.
Environment and sustainability
Where appropriate, the operational carbon
intensity of the investment relative to that
of the portfolio average for the segment or
the related business activity (upstream,
refining, petrochemicals). As a guide, we
would normally target a ratio of less than
100%, meaning that the investment is
expected to reduce the average operational
carbon intensity of that portfolio.
The potential impact of new material capex
investments on BP’s greenhouse gas
emission targets is a further consideration.
There may be instances when new material capex investments are evaluated as consistent
with the Paris goals despite either or both of these guide levels not being met, due to other
considerations being taken into account.
The figure shows the respective rankings of investment performance against each of the tests
Investment economics:
Profitability index
Environment and sustainability:
Carbon intensity (%)
Guide
Guide
Capital weighted average ~1.5x
Average operational carbon intensity is ~45%
1. The respective 2019 new material capex investments have been ranked against the two tests. As a result they are ordered
differently in each graph above.
2. For two of the 2019 new material capex investments the operational carbon intensity was not calculated due to the nature of
these investments:
• We do not calculate operational carbon intensity for replacement of end of life assets.
• The projected operational carbon intensity of fuels marketing businesses is not considered necessary to quantify for
these purposes as the relevant operational emissions would not be expected to be significant.
22
BP Annual Report and Form 20-F 2019
Strategic report
Decisions taken in 2019
Eight new material capex investment decisions were taken in 2019, six in the Upstream and two in the Downstream.
Upstream
Azeri Central East (ACE)
A new offshore platform and facilities in the Azeri-Chirag-Deepwater
Gunashli field in Azerbaijan.
Angola Block 18 – Platina
Four subsea well tiebacks to an existing FPSO vessel, which also support
continued production from the main field under the licence extension
granted by the Angolan government.
India KGD6 – MJ
The third phase of Block KG D6 gas development, seven subsea wells
will tie-back to a new FPSO vessel to process and separate liquids.
Angola Block 15
Further investment, which will extend the production-sharing agreement
for the block through 2032.
Thunder Horse South Expansion Phase 2
Two new subsea production units with eight wells tied back to existing
infrastructure in the US Gulf of Mexico.
Block 61 2020 development wells
Further development and drilling of 18 wells at Ghazeer and seven wells at
Khazzan, both in Oman.
Downstream
Gelsenkirchen steam and water project
Construction of four boilers and a steam turbine to further the safe and
reliable management of fuel gas excess.
Reliance partnership
Strategic agreement with Reliance Industries Limited to form a retail and
aviation joint venture in India.
BP Annual Report and Form 20-F 2019
23
24
BP Annual Report and Form 20-F 2019
Strategic report
Growing advantaged oil
and gas in the Upstream
What this strategic priority means
We aim to invest in oil and gas, producing
both with increasing efficiency. This means
lower cost, higher margin and close to
markets, with a focus on carbon.
Almost half of BP’s upstream portfolio is
natural gas, and several more gas projects
are planned to come onstream in the next
few years.
As the world moves towards net zero
emissions, we think natural gas can play
an important role in getting us there. When
burned for power, natural gas has, on average
on a lifecycle basis, about half the GHG
emissions of coal, with fewer air pollutants,
so expanding its use globally to displace coal
will help to reduce carbon emissions. In fact,
switching from coal to gas has avoided more
than 500 million tonnes of CO2 from the power
sector globally since 2010.
Progress in 2019
We’ve started up 24 of the 35 planned
major projects since 2016 and are on track
to deliver 900,000 barrels of oil equivalent
per day of new major project production by
the end of 2021.
• Sanctioned $6 billion Azeri Central East
development with partners.
• Agreed to sell our Alaska assets to Hilcorp.
• Sanctioned the third project in block
KG D6, offshore India with our
partner Reliance.
5
major project
start ups.
$100m
fund for projects that will
help reduce greenhouse
gas emissions.
For more information see Upstream on page 50.
BP Annual Report and Form 20-F 2019
25
Energy with purpose
Gas in Oman
BP successfully brought the Khazzan
major project into production in 2017,
and since then we’ve continued to build
successful partnerships and reinforce
our commitment to the country.
Exploration opportunity
Together with Eni, we signed an
exploration and production-sharing
agreement for Block 77 in central Oman
with the Ministry of Oil and Gas of the
Sultanate of Oman.
• The block covers a total area of
•
more than 2,700 square kilometres.
It is located 30 kilometres east of
Block 61, where the Khazzan gas
field is already producing around
1 billion cubic feet of gas a day.
• BP and Eni will each hold a 50%
interest, subject to royal decree,
with Eni acting as operator during
exploration.
Khazzan phase two
Ghazeer, the second development
phase of the gas field, is expected to
come online in 2021.
Advantaged gas
We used expertise and technology from
our US onshore business to help access
tight gas locked in the Khazzan field
and bring it commercially to market.
Detecting methane
We installed and tested continuous
measurement of methane emissions
at our Khazzan central processing facility.
The technology uses instruments such
as a gas cloud imaging camera to
continuously monitor our facilities,
quickly identify new leaks and reduce
time taken to respond. We now aim to
install methane measurement at all our
existing major oil and gas processing
sites by 2023.
26
BP Annual Report and Form 20-F 2019
Strategic report
Market-led growth in
the Downstream
What this strategic priority means
We aim to innovate with advanced products
and strategic partnerships, building
competitively advantaged businesses that
deliver profitable marketing growth.
We aim to invest in higher-returning fuels
marketing and lubricants businesses with
growth potential and reliable cash flows.
And we are continuing to expand into
fast-growing emerging markets.
We are also delivering and developing
new products, offers and business models
that support the transition to a lower
carbon and digitally enabled future over
the longer term.
Progress in 2019
We have continued to make strategic
progress in fuels marketing, with our
convenience partnership model now in
around 1,600 sites across the network.
• Agreed to expand our partnership with
Reliance Industries Ltd to include a retail
service station network and aviation fuels
business across India.
• Continued to expand in other material
markets – most notably in Mexico where we
now have more than 520 BP-branded retail
sites. We also continued to grow our
network in Indonesia and expanded our
China network into Shandong and Hebei
provinces through our joint venture with
Dongming.
• Announced the development of BP Infinia,
an enhanced recycling technology, capable
of processing currently unrecyclable PET
plastic waste.
>1,200
retail sites in new
markets of China,
Mexico and Indonesia.
~1,600
convenience
partnership sites.
For more information see Downstream on
page 56.
BP Annual Report and Form 20-F 2019
27
Energy with purpose
Electrifying China
BP has joined forces with DiDi, the
world’s leading mobile transportation
platform, to build an electric vehicle
(EV) charging network in China.
Why it matters
China is the largest and fastest-
developing EV market.
• 50% of the world’s battery EVs
are in China.
• DiDi offers a full range of app-based
services across Asia, Latin America
and Australia, including ride-hailing,
automobile solutions and other offers.
• The platform has 550 million users,
tens of millions of drivers and serves
around 1 million EVs.
What’s involved
The joint venture plans to develop
high-quality EV charging hubs for
DiDi users and other drivers.
• The partners intend to add loyalty,
convenience and fleet services
in the future.
Why we’re doing it
As the world’s largest EV market, China
offers extraordinary opportunities to
develop innovative new businesses at
scale and we see this as the perfect
partnership for such a fast-evolving
environment. The lessons we learn here
will help further expand BP’s advanced
mobility business worldwide, helping
drive the energy transition and develop
solutions for a low carbon world.
And elsewhere
BP Chargemaster is powering around
1.5 million electric miles a week, making
this the most-used public charging
infrastructure operator in the UK. We
have also begun rolling out 150kW
ultra-fast chargers on BP forecourts
across the UK with plans to build a
national network of high-power charging
– one which will closely replicate the
current fuelling experience.
This is helping to accelerate the
adoption of EVs, by making EV
charging fast, convenient and
hassle-free.
Venturing and low carbon
across multiple fronts
What this strategic priority means
We aim to pursue new opportunities to
meet evolving technology, consumer and
policy trends.
We are building up our renewable energy
portfolio – with activities spanning renewable
fuels and products, wind and solar energy
and biopower. We work across multiple
fronts through our investments in low carbon
activities with joint ventures, collaborations
and new business models. Through BP
Ventures we have invested more than
$650 million in around 40 companies since it
was set up in 2007. Our investments support
technologies and innovations that we believe
could benefit BP and global energy systems.
Progress in 2019
We increased our stake in Lightsource BP
to create a 50:50 joint venture and expanded
our biofuels business in Brazil by more than
50%, through a joint venture with Bunge to
create BP Bunge Bioenergia. We also made a
number of other investments spanning a range
of strategic focus areas.
• Started BP Launchpad, our scale-up factory,
designed to help quickly grow disruptive
technologies and business models which
could become future BP business units.
• Expanded our digital energy portfolio by
investing in Grid Edge, which has developed
an artificial intelligence-based energy
management platform that helps customers
predict, control and optimize their buildings’
energy profile.
• Invested $5 million in Belmont Technology
to further strengthen BP’s artificial
intelligence and digital capabilities.
>50%
increase in biofuels
business in Brazil,
through BP Bunge
Bioenergia.
7
new investments
through BP Ventures
in 2019.
For more information see page 63.
28
BP Annual Report and Form 20-F 2019
“
Pairing Calysta’s exciting
technology and
entrepreneurial drive with
BP’s global scale and gas
market expertise offers the
opportunity to improve food
security and sustainability.”
Dominic Emery
Group chief of staff
Energy with purpose
Using gas to create
sustainable fish food
BP Ventures has invested $30 million
o help create new markets for our
natural gas in the fish-farming industry.
What we’re doing
We’re extending the idea of gas
as a source of energy beyond its
conventional applications, through
our investment in California start-up,
Calysta, to create Feedkind® – protein
food for fish, livestock and pets.
Why it matters
Finding sustainable ways to feed
a growing global population within
planetary boundaries is a pressing
issue and Calysta can be part of
the solution:
• Feedkind® is produced with fewer
resources, such as water and land,
than current alternatives.
• Existing protein sources, including
fishmeal and soya bean protein, are
either at full capacity or connected to
other issues such as deforestation.
• The global aquaculture market is
expected to grow by around 25% by
2025 and Feedkind® offers a way to
support this increase sustainably.
How it works
Naturally occurring bacteria is fermented
using methane from gas as its energy
source. The protein created is harvested,
dried and sold in pellet form.
Why we’re doing it
The investment supports BP’s strategy
of creating new markets in which gas
can deliver a more sustainable future.
Strategic report
BP Annual Report and Form 20-F 2019
29
“
This programme reflects our
commitment to be a leader
in advancing the energy
transition by maximizing
the benefits of natural gas.”
Gordon Birrell
Chief operating officer – production,
transformation and carbon
30
BP Annual Report and Form 20-F 2019
Strategic report
Modernizing the
whole group
What this strategic priority means
We aim to simplify our processes and
enhance our productivity through digital
solutions.
We achieve this through three pillars:
• Agility – improving and simplifying the way
we operate.
• Mindset change – accepting the reality and
adopting the right attitude for a business
that is increasingly competitive and
margin-dependent.
• Digital transformation – digitizing and
automating our work.
Progress in 2019
We’ve introduced a range of technologies
and improved ways of working across BP
to support our modernization priority. Our
mentors and coaches deliver a programme of
training for employees to share agile practices
and support changing mindsets, which are key
to generating ideas to improve how we work
across the whole business.
• Launched ‘Connected BP’ in partnership
with data technology pioneer Palantir.
The programme connects different
systems and business areas into one
platform where users can connect,
transform and share data.
• Developed a holistic process for leak
detection and intervention using infrared
cameras, lasers and drone technology at
our US onshore BPX Energy operations.
• Performed a concept trial of Spot, a robot
from Boston Dynamics, at our US Whiting
refinery. Spot can gather data, detect
abnormalities and perform tasks, such
as detecting gas emissions and helping
remove people from hazardous spaces.
>1,000
transformation projects
running in the Upstream.
~$1.5bn
invested every year
in maintaining BP’s
infrastructure.
BP Annual Report and Form 20-F 2019
31
Energy with purpose
Managing methane
BP is introducing a programme of new
and complementary technologies to
continuously detect, measure and
help reduce methane emissions at
our BP-operated upstream assets.
Why it matters
Methane is the primary component
of natural gas. If it escapes into the
atmosphere unburnt, it can be a
potent greenhouse gas.
What we’re doing
We aim to install methane
measurement, such as gas cloud
imaging, at all BP’s major oil and gas
processing sites by 2023 and then
reduce methane intensity of our
operations by 50%.
What else?
We’re also planning to deploy a new
generation of drones, hand-held devices
and multi-spectral flare combustion
cameras – drawing upon scientific
breakthroughs made in diverse fields,
spanning healthcare, space exploration
and defence.
Collaboration with stakeholders
We have agreed to work in collaboration
with the Environmental Defense
Fund, a New York-based non-profit
environmental advocacy group.
The three-year commitment aims
to advance technologies and practices
to reduce methane emissions from the
global oil and gas supply chain.
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. BP
management uses these measures to evaluate
operating performance and make financial,
strategic and operating decisions.
Changes to KPIs
• Added sustainable GHG emission
reductions and methane intensity, in line
with our ‘reduce, improve, create’
framework.
• Removed production as a volume measure
as it doesn’t reflect our value over volume
approach, and is not used to assess
executive remuneration. The metric is
reported on At a glance, page 9.
• Combined tier 1 and tier 2 process safety
events, giving investors a wider view of
process safety events.
• As reported in 2018, we have now
revised our refining availability metric
to BP-operated refining availability, to
more closely match our 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.
Key
New/amended
New or amended in 2019
REM
Used for the remuneration policy
For more information see Directors’
remuneration report on page 100.
2019
26
72
98
2018
16
56
72
2017
18
61
79
2016
16
2015
20
Tier 1
Tier 2
84
100
83
103
2019 performance
The total number of tier 1 and tier 2 process
safety events increased in 2019, mainly
reflecting performance in assets acquired over
the past 18 months. Underlying performance
across the group improved slightly from 2018.
We are implementing BP procedures and
processes to help bring newly acquired assets
in line with BP assets.
2019
2018
2017
2016
2015
0.166
0.198
0.218
0.211
0.243
2019 performance
We have seen a decrease in RIF compared with
2018; and maintain our focus to drive toward zero
incidents.
Safety
Tier 1 and 2 process safety eventsa
We track tier 1 and tier 2 events and report the
aggregated outcome. Tier 1 events are losses of
primary containment from a process of greatest
consequence – causing harm to a member of the
workforce, damage to equipment from a fire or
explosion, a community impact or exceeding
defined quantities. Tier 2 events are those of
lesser consequence.
Reported recordable injury frequencya
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.
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.
32
BP Annual Report and Form 20-F 2019
Sustainable operations
Proved reserves replacement ratio (%)
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.
Upstream unit production costs
($/boe)
The upstream unit production cost indicator
shows how supply chain, headcount and scope
optimization impact cost efficiency.
Upstream plant reliability
(%)
BP-operated upstream plant reliability is
calculated as 100% less the ratio of total
unplanned plant deferrals divided by installed
production capacity.
Downstream refining availability
(%)
Refining availability represents Solomon
Associates’ operational availability for BP-
operated refineries. 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.
Major project delivery
We monitor the progress of our major projects to
gauge whether we are delivering our core pipeline
of projects under construction on time.
Projects take many years to complete, requiring
differing amounts of resource, so a smooth or
increasing trend should not be anticipated.
Major projects are defined as those with a BP net
investment of at least $250 million, or considered
to be of strategic importance to BP, or of a high
degree of complexity.
2019
2018
2017
2016
2015
2019
2018
2017
2016
2015
2019
2018
2017
2016
2015
90.0
2019
2018
2017
2016
2015
90.0
2019
2018
2017
2016
2015
Strategic report
67
61
100
109
143
2019 performance
The lower ratio reflects a net decrease of reserves
due to lower gas and oil prices mainly within the
US Lower 48, partly offset by new developments
and existing field optimization in Angola,
Argentina, Azerbaijan, India, Oman, Russia
and the US.
6.84
7.15
7.11
8.46
10.46
94.4
95.7
94.7
95.3
95.0
94.9
95.0
95.2
95.2
94.6
5
6
6
7
4
2019 performance
Lower production costs compared with 2018
were mainly due to the impacts of IFRS 16.
2019 performance
Plant reliability was 1.3% lower than 2018 mainly
due to design and integrity issues addressed
through maintenance activities.
2019 performance
Refining availability was similar to 2018, reflecting
continued strong operational performance in our
portfolio. This performance is underpinned by our
global reliability programmes.
2019 performance
We started up five major projects in Egypt,
Trinidad, the UK and US.
BP Annual Report and Form 20-F 2019
33
Sustainable operations
Greenhouse gas emissions (MtCO2e)
We provide data on greenhouse gas (GHG)
emissions material to our business on a
carbon dioxide-equivalent basis. This particular
KPI comprises Scope 1 (direct) emissions of
CO2 and methane, for 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.
2019
2018
2017
2016
2015
Sustainable GHG emissions reduction
(MtCO2e)
This measure includes actions taken by our
businesses to improve energy efficiency and
reduce methane emissions and flaring – all leading
to ongoing, quantifiable GHG reductions. These
refer to the GHG emissions that would have
occurred had we not made the change i.e. they
could be absolute in nature or underlying. Since
2019, progress against this target is used as a
factor in determining bonuses for around 37,000
employees, including executives.
Methane intensity
(%)
We define methane intensity as the amount of
methane emissions from our upstream oil and gas
operations as a percentage of the gas that goes to
market from those operations. This applies to
methane emissions within our operational control
boundary, where we have the highest degree of
control. Methane emissions from non-producing
activities, such as exploration drilling, are
excluded. We have an existing methane target of
0.2% and a new ambition that seeks to reduce
that – once validated – by 50%.
Diversity and inclusionb (%)
Each year we report the percentage of women and
individuals from countries other than the UK and
the US among BP’s group leaders.
2019
2018
2017
2016
2015
2019
2018
2019
2018
2017
2016
2015
Women in group leadership
People from beyond the UK
and US in group leadership
2019
2018
2017
2016
2015
Employee engagement (%)
We conduct an annual employee survey to
understand and monitor levels of employee
engagement and identify areas for improvement.
34
BP Annual Report and Form 20-F 2019
46.0
46.5
49.4
50.1
49.0
1.4
1.3
2019 performance
Our Scope 1 (direct) equity share emissions
decreased by 0.5MtCO2e to 46.0MtCO2e in 2019
(46.5MtCO2e in 2018). Emissions resulting from
the BHP acquisitions were balanced out by
sustainable emissions reductions and the impact
of divestments.
2019 performance
We delivered 1.4Mte of sustainable emissions
reductions (SERs), and this meant we exceeded
our target of 3.5Mte of SERs for the period 2016
to 2025, six years ahead of schedule.
0.5
0.7
0.2
0.14
0.16
2019 performance
Our methane intensity was 0.14%, a reduction
from 0.16% in 2018 and below our stated target
of 0.2%.
25
25
24
24
24
21
22
23
19
21
65
66
66
73
71
2019 performance
Both measures increased slightly. As a global
business we are committed to increasing the
diversity of our workforce and leadership.
b Relates to BP employees.
2019 performance
The overall employee engagement score saw
a marginal decline since last year. We are working
to identify areas for improvement. Scores prior
to 2017 are based on questions on priorities
set out in 2012, so the numbers are not
directly comparable.
Strategic report
2019 performance
2019 underlying RC profit was lower, largely
reflecting the impact of the weaker price
environment. Profit for the year was significantly
lower, due to the above factor, divestment-related
impairment charges and reclassification of past
foreign exchange losses on the formation of the
BP Bunge Bioenergia joint venture.
2019 performance
Operating cash flow was higher than 2018,
reflecting lower Gulf of Mexico oil spill payments
and the favourable impact of lease payments
that are now classified as financing cash flows
under IFRS 16.
Financial performance
Underlying replacement cost profit
($ billion)
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.
2019
2018
2017
2016
(6.5)
2015
4.0
10.0
9.4
12.7
3.4
6.2
0.1
2.6
5.9
Operating cash flow
($ billion)
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.
Profit (loss) for the year attributable
to BP shareholders
Underlying RC profit for the year (non-GAAP)
2019
2018
2017
2016
2015
28.2
25.8
26.1
22.9
24.1
10.7
18.9
17.6
20.3
19.1
Operating cash flow excluding Gulf of
Mexico oil spill payments (non-GAAP)c
Operating cash flow
c The green bars on the chart do not form part of BP’s
Annual Report on Form 20-F as filed with the SEC.
Return on average capital employed
(%)
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
345 for more information including the nearest
equivalent GAAP data.
Total shareholder return
(%)
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.
2019
2018
2017
2016
2015
2019
2018
2017
2016
8.9
11.2
2019 performance
The decrease reflects lower profit due to the
impact of lower oil and gas prices and weaker
refining environment.
2019 performance
Improvement in TSR reflects increased dividends
in 2019.
2.8
5.8
5.5
5.8
1.1
0.5
(4.6)
20.0
9.5
29.0
55.5
2015
(12.8)
(8.3)
ADS basis
Ordinary share basis
BP Annual Report and Form 20-F 2019
35
Group performance
“
Despite the challenging environment in 2019, we continued
to deliver operating cash flow growth, which together with
continued capital discipline has underpinned growth in free
cash flow. Furthermore, we have made significant progress
towards our $10 billion divestment target. Together this
supported our decision to increase the dividend with the
fourth-quarter results.”
Dr Brian Gilvary
Group chief financial officer
$10.0bn
Underlying replacement cost (RC) profit
(2018 $12.7bn)
$28.2bn
Operating cash flow excluding
Gulf of Mexico oil spill paymentsa
(2018 $26.1bn)
$4.0bn
Profit attributable to BP shareholders
(2018 $9.4bn)
$25.8bn
Operating cash flow
(2018 $22.9bn)
Financial and operating performance
Segment RC profit (loss) before
interest and tax
($ billion)
Profit before interest and taxation
Finance costs and net finance expense relating to pensions and
other post-retirement benefits
$ million
except per
share amounts
2018
19,378
(2,655)
(7,145)
(195)
9,383
801
(198)
9,986
3,380
2017
9,474
(2,294)
(3,712)
(79)
3,389
(853)
225
2,761
3,730
2019
11,706
(3,552)
(3,964)
(164)
4,026
(667)
156
3,515
8,263
Taxation
Non-controlling interests
Profit for the yearb
Inventory holding (gains) losses, before tax
Taxation charge (credit) on inventory holding gains and losses
RC profit
Net (favourable) adverse impact of non-operating items
and fair value accounting effects before tax
Taxation charge (credit) on non-operating items
(1,788)
(643)
(325)
and fair value accounting effects
Underlying RC profit
Dividends paid per share – cents
– pence
9,990
41.0
31.977
12,723
40.5
30.568
6,166
40.0
30.979
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.
More information
Upstream, see page 50.
Downstream, see page 56.
Rosneft, see page 61.
Other businesses and corporate, see page 63.
Oil and gas disclosures for the group, see page 308.
For a discussion of BP’s financial and operating performance for the year ending 31 December
2017, see BP Annual Report and Form 20-F 2018, pages 19-39 and BP Annual Report and Form
20-F 2017, pages 21-43.
2019
2018
2017
(5)
0
5
10
15
20
25
● Upstream ● Downstream ● Rosneft
● Other businesses and corporate (includes
costs related to the Gulf of Mexico oil spill)
● Consolidation adjustment – UPll★
❙ Group RC profit before interest and tax
36
BP Annual Report and Form 20-F 2019
Strategic report
Results
Cash flow and net debt information
Profit for the year ended 31 December 2019 attributable to BP
shareholders was $4.0 billion, compared with $9.4 billion in 2018.
Excluding inventory holding gains, replacement cost (RC) profit was
$3.5 billion, compared with $10.0 billion in 2018.
After adjusting RC profit for a net charge for non-operating items
of $7.2 billion and net favourable fair value accounting effects of
$0.7 billion (both on a post-tax basis), underlying RC profit for the year
ended 31 December 2019 was $10.0 billion, a decrease of $2.7 billion
compared with 2018. The decrease was predominantly due to lower
oil and gas prices in the Upstream segment and a significantly weaker
environment in the Downstream segment.
Profit for the year ended 31 December 2018 attributable to BP
shareholders was $9.4 billion, including inventory holding losses,
RC profit was $10.0 billion. After adjusting RC profit 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. This
reflected higher oil prices, record plant reliability and the benefit of new
major projects start-ups in Upstream; stronger refining margins and
strong fuels marketing growth in Downstream; and higher oil prices in
Rosneft segment.
Non-operating items
The net charge for non-operating items was $7.2 billion after tax in
2019, mainly related to impairment charges, principally resulting from
the announcements to dispose of certain assets in the US and
reclassification of accumulated foreign exchange losses from reserves
to the income statement on the formation of the BP Bunge Bioenergia
joint venture.
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.
More information on non-operating items and fair value accounting
effects can be found on pages 300 and 344.
Taxation
The charge for corporate income taxes was $3,964 million in 2019
compared with $7,145 million in 2018. The decrease mainly reflects the
lower level of profit in 2019. The effective tax rate (ETR) on the profit or
loss for the year was 49% in 2019 and 43% in 2018. The ETR for both
years was impacted by various one-off items.
Adjusting for inventory holding impacts, non-operating items and fair
value accounting effects, the underlying ETR was 36% in 2019 (2018
38%). The lower underlying ETR in 2019 compared with 2018 reflects
the reassessment of the recognition of deferred tax assets. In the
current environment, the underlying ETR in 2020 is expected to be
lower than 40%.
Operating cash flow excluding
28,199
26,091
2019
2018
Gulf of Mexico oil spill paymentsa
Operating cash flow
Net cash used in investing activities
Net cash used in financing activities
Cash and cash equivalents at end of year
Capital expenditure
Organic capital expenditure
Inorganic capital expenditure
Finance debt
Net debt
Finance debt ratio (%)
Gearing (%)
25,770
(16,974)
(8,817)
22,472
22,873
(21,571)
(4,079)
22,468
(15,238)
(4,183)
(15,140)
(9,948)
(19,421)
(25,088)
67,724
45,442
40.2%
31.1%
65,132
43,477
39.3%
30.0%
$ million
2017
24,098
18,931
(14,077)
(3,296)
25,586
(16,501)
(1,339)
(17,840)
62,574
37,819
38.6%
27.0%
a This does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
Operating cash flow
Operating cash flow for the year ended 31 December 2019 was
$25.8 billion, $2.9 billion higher than 2018. Operating cash flow in
2019 reflects $2.7 billion of pre-tax cash outflows related to the Gulf
of Mexico oil spill. Compared with 2018, operating cash flows in 2019
also reflected the favourable effect of an estimated $2.0 billion of lease
payments being classified as financing cash flows from 1 January 2019
following the implementation of IFRS 16.
Movements in working capital adversely impacted cash flow in the
year by $2.9 billion, including an adverse impact on working capital from
the Gulf of Mexico oil spill of $2.6 billion. BP actively manages its
working capital balances to optimize and reduce volatility in cash flow.
Operating cash flow for the year ended 31 December 2018 was
$22.9 billion, reflecting $3.5 billion of pre-tax cash outflows related to
the Gulf of Mexico oil spill.
Movements in working capital adversely impacted cash flow in the 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 Annual Report and Form 20-F 2019
37
Group reserves and production (including
Rosneft segment)a
Estimated net proved reserves
(net of royalties)
Liquids (mmb)
Natural gas (bcf)
Total hydrocarbons (mmboe)
Of which:
2019
2018
$ million
2017
11,478
45,601
19,341
11,456
49,239
19,945
10,672
45,060
18,441
Equity-accounted entitiesb
9,965
9,757
8,949
Production (net of royalties)
Liquids (mb/d)
Natural gas (mmcf/d)
Total hydrocarbons (mboe/d)
Of which:
Subsidiaries
Equity-accounted entitiesc
2,211
9,102
3,781
2,420
1,360
2,191
8,659
3,683
2,328
1,355
2,260
7,744
3,595
2,164
1,431
a Because of rounding, some totals may not agree exactly with the sum of their component
b
c
parts.
Includes BP’s share of Rosneft. See Rosneft on page 61 and Supplementary information on
oil and natural gas on page 232 for further information.
Includes BP’s share of Rosneft. See Rosneft on page 61 and Oil and gas disclosures for the
group on page 308 for further information.
Total hydrocarbon proved reserves at 31 December 2019, on an oil
equivalent basis including equity-accounted entities, decreased by 3%
(decrease of 8% for subsidiaries and increase of 2% for equity-
accounted entities) compared with 31 December 2018. Natural gas
represented about 41% (48% for subsidiaries and 34% for equity-
accounted entities) of these reserves. The change includes a net
decrease from acquisitions and disposals of 133mmboe (decrease of
134mmboe within our subsidiaries and increase of 1mmboe within our
equity-accounted entities). Acquisition activity in our subsidiaries
occurred in India, and divestment activity in our subsidiaries in the US
and Egypt. There were no material acquisitions or divestments in our
equity-accounted entities.
Total hydrocarbon production for the group was 3% higher compared
with 2018. The increase comprised a 4% increase (1% increase for
liquids and 7% increase for gas) for subsidiaries and was broadly flat
with 2018 for equity-accounted entities.
Net cash used in investing activities
Net cash used in investing activities for the year ended 31 December
2019 decreased by $4.6 billion compared with 2018.
The decrease mainly reflected the phasing of the payments to BHP for
the Petrohawk acquisition.
Total capital expenditure for 2019 was $19.4 billion (2018 $25.1 billion),
of which organic capital expenditure was $15.2 billion (2018 $15.1
billion). Sources of funding are fungible, but the majority of the group’s
funding requirements for new investment comes from cash generated
by existing operations. We expect 2020 organic capital expenditure to
remain towards the lower end of our $15-17 billion range.
Total divestment and other proceeds for 2019 amounted to $2.8 billion
including $0.6 billion received in relation to the sale of a 49% interest
in BP’s retail property portfolio in Australia, shown within financing
activities in the group cash flow statement. Total divestment and other
proceeds for 2018 amounted to $3.5 billion including a $0.6 billion loan
repayment, relating to the refinancing of Trans Adriatic Pipeline AG.
BP expects to meet its target of $10 billion proceeds by end-2020 and
expects to announce a further $5 billion of agreed disposals by
mid-2021.
Net cash used in financing activities
Net cash used in financing activities for the year ended 31 December
2019 was $8.8 billion, compared with $4.1 billion in 2018. This was
mainly as a result of $2.3 billion in lease liability repayments which were
presented as operating cash flows and capital expenditure prior to the
implementation of IFRS 16, an increase of $1.5 billion in debt financing,
an increase of $1.2 billion in net repurchase of shares and an increase in
dividend payments of $0.3 billion offset by $0.6 billion in cash received
in relation to the sale of the 49% interest in BP’s retail property portfolio
in Australia as described above.
Total dividends distributed to shareholders in 2019 were 41.0 cents per
share, 0.5 cents higher than 2018. This amounted to a total distribution
to shareholders of $8.3 billion (2018 $8.1 billion), of which shareholders
elected to receive $1.4 billion (2018 $1.4 billion) in shares under the
scrip dividend programme. The total distributed in cash during the year
amounted to $6.9 billion (2018 $6.7 billion).
Debt
Finance debt at the end of 2019 increased by $2.6 billion from the end
of 2018. The finance debt ratio at the end of 2019 increased by 0.9%.
Net debt at the end of 2019 increased by $2.0 billion from the 2018
year-end position. Gearing at the end of 2019 increased by 1.1%. Net
debt and gearing are non-GAAP measures. See Financial statements –
Note 26 for finance debt, which is the nearest equivalent measure on an
IFRS basis, and Note 27 for further information on net debt, including
the amendment of comparative information for finance debt, net debt
and gearing following the implementation of IFRS 16.
For information on financing the group’s activities, see Financial
statements – Note 29 and Liquidity and capital resources on page 301.
38
BP Annual Report and Form 20-F 2019
Strategic report
Sustainability
Operating sustainably, safely and responsibly is core to
our ability to create long-term value for our stakeholders,
deliver our net zero ambition and aims, and realize our
purpose to reimagine energy for people and our planet.
Our sustainability focus areas
We refreshed and expanded our
sustainability materiality assessment
process in 2019. We asked a range of
external and internal stakeholders,
including shareholders and employees,
to share their feedback on the issues that
matter most to them. We also asked them
to consider the relative impact of these
issues on our business and how they think
BP can influence them positively. We
validated and prioritized the findings with
experts in BP to help prioritize our
sustainability reporting. We’ve covered
the main issues they consider in this
section, along with additional key
non-financial information.
Our reporting
For more information on our sustainability
performance, see the BP Sustainability
Report 2019.
For key environmental, social and
governance data, see our ESG datasheet
at bp.com/ESGdata.
For our mapping to some key sustainability
frameworks and standards, including GRI
and IPIECA, see bp.com/reportingcentre.
Environment
• Climate change and
the energy transition.
• Net zero aims.
• Carbon intensity of our products.
• GHG emissions
from our operations.
• Our ‘reduce, improve,
create’ framework.
Safety and
security
• Keeping people safe.
• Managing safety.
• Our operating
management system.
• Preventing incidents.
• Emergency preparedness.
• Accrediting our low
carbon activities.
• Calling for more
progressive climate policies
• Climate-related financial
disclosures.
• Working with others.
• Managing our impacts.
• Cyber threats.
• Security.
• Working with contractors
• Our partners in joint
arrangements.
Our people
• Attraction and retention.
• Diversity.
• Inclusion.
• Employee engagement.
• Share ownership.
Communities • Value to society.
• Human rights.
Governance
and business
ethics
• Our values.
• The BP code of conduct.
• Anti-bribery and corruption.
• Lobbying and political
donations.
• Trade associations.
• Tax and transparency.
Non-financial reporting
information statement
This sustainability section, and other pages
referenced below, provide information as
required by section 414CB of the Companies
Act 2006 in relation to:
Page
Other related information
Page
Environmental matters
Our employees
Social matters
Human rights
Anti-bribery and corruption
40-45
47, 88-89, 221
48
48
49
Business model
Strategy
Non-financial KPIs
Principal risks
Policies
14-15
16-18
32-34
69-71
39-49, 68-69
BP Annual Report and Form 20-F 2019
39
Greenhouse gas emissions from our operations
We report Scope 1 (direct) and Scope 2 (indirect) GHG emissions on
a carbon dioxide equivalent (CO2e) basis. Direct emissions include CO2
and methane from the combustion of fuel and the operation of facilities,
and indirect emissions include those resulting from the purchase of
electricity and steam we import into our operations.
Our overall emissions, on an operational control basis, increased in
2019, mainly due to major acquisitions. But the SERs we achieved
came close to countering this increase. We achieved zero net growth
in our operational emissions with no offsets required against our
adjusted 2015 baseline.
Greenhouse gas emissions (MteCO2e)a
Operational controlb
Scope 1 (direct) emissions
Scope 2 (indirect) emissions
Total
BP equity sharec
Scope 1 (direct) emissions
Scope 2 (Indirect) emissions
Total
2019
49.2
5.2
54.4
2019
46.0
5.7
51.7
2018
48.8
5.4
54.2
2018
46.5
5.7
52.2
2017
50.5
6.1
56.6
2017
49.4
6.8
56.2
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.
Ratio of Scope 1 (direct) and Scope 2 (indirect) GHG emissions to gross
production (teCO2e/te)d
2019
0.22
2018
0.22
2017
0.24
2016
0.24
d Gross production comprises upstream production, refining throughput and
petrochemicals produced.
Environment
Climate change and the energy transition
The world needs more energy to fuel prosperity and improve standards
of living for a growing global population. This energy must be delivered
in affordable and reliable ways, but it must also be lower carbon. BP’s
purpose is to reimagine energy for people and our planet. To deliver
this, we have set out a new ambition to become a net zero company
by 2050 or sooner, and to help the world reach net zero.
Net zero aims
Aim 1: Net zero operations
We aim to be net zero across our entire operations on an absolute basis
by 2050 or sooner. This aim relates to Scope 1 (direct) and Scope 2
(indirect) greenhouse gas (GHG) emissions.
Aim 2: Net zero oil and gas
We aim to be net zero on an absolute basis across the carbon in our
upstream oil and gas production by 2050 or sooner. This is our Scope 3
aim, and is on a BP equity share basis excluding Rosneft. This carbon
was equivalent to 360MteCO2ea of emissions in 2019.
Scope 3
There are 15 categories of Scope 3 emissions. For our industry
the most important of these categories is the ‘use of sold
products’ (category 11). For this category of Scope 3, we are
reporting for the first time the estimated CO2 emissions from
the carbon in our upstream oil and gas productiona. This metric
replaces the ‘customer emissions’ metric, which we previously
reported in our Sustainability Report. For more information see
bp.com/sustainabilityreport.
a This figure assumes that 100% of the oil and gas produced is combusted with no carbon
capture, use and storage, although a proportion of global oil and gas goes into non-
combusted uses, such as petrochemicals and lubricants.
Aim 3: Halving intensity
Our aim is to cut the carbon intensity of the products we sell by 50%,
by 2050 or sooner. This is a lifecycle GHG emissions intensity approach,
per unit of energy. It covers marketing sales of energy products and,
potentially, in the future, certain other products, such as those
associated with land carbon projects.
This metric also responds to the CA100+ resolution, which requires
us to report the estimated carbon intensity of our energy products.
Estimated emissions intensity (gCO2e/MJ)
Average emissions intensity of marketed energy products
Refined energy products
Gas products
Bio-products
Power products
2019
79.7
93.7
71.6
28.8
43.8
40
BP Annual Report and Form 20-F 2019
Strategic report
Our ‘reduce, improve, create’ framework
In 2018 we set out our low carbon ambition and targets in
our ‘reduce, improve, create’ (RIC) framework:
• Reducing GHG emissions in our own operations.
• Improving products to help our customers and consumers
lower their emissions.
• Creating low carbon businesses.
In 2019 we announced plans to link our annual cash bonus to our
sustainable emissions reduction (SER) target. This means around
37,000 employees, including executives, are now incentivized and
rewarded for their contribution to reducing carbon emissions in BP.
We’ve met our SER target six years ahead of schedule and this has
motivated us to start work to set new targets. We plan to provide
more detail in September 2020.
Reducing
emissions in our operations
Improving
our products
Creating
low carbon businesses
2019 progress
• Achieved zero net growth in
2019 progress
• Continued to scale up our
co-processing business, growing
the volume of lower carbon bio-
feedstock processed at our refineries.
• Established more than 30 carbon
neutral BP retail sites, offering a
range of carbon neutral products
and services.
• Increased the supply of BP biojet, our
sustainable aviation fuel, to 11 locations
worldwide – including in Sweden,
France and the US.
operational emissions. Our total
GHG emissions (operated) increased
slightly in 2019, largely due to the
major acquisitions at the end of 2018.
This was countered by other
emissions reductions. Total emissions
were still below the adjusted 2015
baseline so no offsets were required.
• 1.4Mte of SERs delivered in 2019
and 3.9Mte since 2016. And we linked
this target to the annual cash bonus
of around 37,000 eligible employees
in 2019.
• Methane intensity of 0.14%, below
our target of 0.2%.
More information
Our strategy on page 16.
Directors’ remuneration report on page 100.
bp.com/sustainability.
2019 progress
• Began rolling out BP Chargemaster
ultra-fast charging across BP forecourts
in the UK and piloted ultra-fast charging
at Aral forecourts in Germany.
• Increased our stake in Lightsource BP,
to create a 50:50 joint venture, see
page 73.
• Took a leading role in the OGCI’s Net
Zero Teesside project in the UK. Using
integrated carbon capture, use and
storage, the project aims to store the
carbon dioxide emissions of the
carbon-intensive industries situated
within the Teesside industrial cluster.
Accrediting our lower carbon activities
Calling for more progressive climate policies
Our advancing low carbon (ALC) accreditation programme aims to
inspire every part of BP to identify lower carbon opportunities. Since its
launch, the programme has motivated people across BP to do more to
advance low carbon, with 76 activities being accredited in 2019. Each
activity supports one of our low carbon ambitions. Deloitte conducts
independent assurance on ALC activities. We estimate that 64MteCO2e
have been saved or offset through activities delivered by BP, and
5.4Mte through activities delivered by BP partners since the
programme began in 2017a.
See bp.com/advancinglowcarbon for details on the programme and
Deloitte’s assurance statement.
a The total emissions saved or offset from the accredited activities are estimated using a
variety of methodologies and baselines. The figures aim only to illustrate the impact of the
activities within the programme, and delivered by BP or a BP partner only refers to the
organization leading on delivering the activity. Savings or offsets may be claimed by or
attributed to other parties. The scope of accredited activities is wider than, and does not
seek to align with, our GHG reporting boundaries. Therefore, the figures are not directly
comparable to BP’s reported emissions.
We plan to allocate more resources to advocate for well-designed
policies, including carbon pricing. We believe carbon pricing is the
most efficient way to reduce GHG emissions and incentivize everyone,
including energy producers and consumers, to play their part. In our
view, pricing can be as effective as a tax or a cap-and-trade system.
While we support well-designed carbon pricing, we’re prepared to
oppose poorly designed proposals. For example, we opposed the
ballot initiative to introduce a carbon fee in Washington State, US in
November 2018. We believed that the policy was badly designed and
would have harmed Washington’s economy without significantly
reducing carbon emissions. The ballot was not passed.
We continued to work with legislative leaders in the state and in 2019
supported a cap-and-invest bill, which we believe will be more effective.
We intend to continue working with the Washington legislature during its
2020 session to see if a new carbon bill can be advanced.
BP Annual Report and Form 20-F 2019
41
and the preparation and consideration of corporate reporting documents
and AGM materials. The board has reviewed the consistency of our
current strategy with the Paris goals, see page 17.
The executive
The assessment and management of climate-related matters is
embedded across BP at various levels and delegated authority flows
down from the board, see page 83.
Climate-related matters were discussed at each of the 11 executive
team meetings in 2019 including the development of BP’s net zero
ambition and aims ahead of discussion with the board.
The executive team is supported by BP’s senior-level leadership and
their respective teams, with dedicated business and functional
expertise focused on climate-related matters. This includes our carbon
management, safety and operational risk, group policy and our
economics teams.
Alignment between group, business and functional leaders is fostered
through cross-functional bodies, including the group, upstream and
downstream carbon steering committees.
Climate-related financial disclosures
We support the recommendations of the Task Force on Climate-related
Financial Disclosures (TCFD), which was established by the Financial
Stability Board with the aim of improving the reporting of climate-
related risks and opportunities. We intend to work constructively with
the TCFD, and others, to develop good practices and standards for
transparency. This will be a multi-year journey, but we have already
started, and our latest reporting provides information supporting the
TCFD’s recommended disclosures.
Governance
Recommendation: Disclose the organization’s governance around
climate-related issues and opportunities.
The board
The board is responsible for the overall conduct of the group’s business,
which extends to setting our strategy and approach to the energy
transition. The board and its associated committees, where appropriate,
have oversight of climate-related matters (which include issues and
opportunities) and are updated on these matters as frequently as
necessary. In 2019 climate matters were included on the agenda for
each of the six board meetings. This informed the board’s consideration
of strategy.
The process by which the board is updated on climate-related matters
is managed by our company secretary’s office and depends on the topic
being discussed. In 2019 these processes included formal analysis of
our RIC targets, briefings with subject matter experts from the business
Climate governance: investments in 2019
BP board
Considers investment cases deemed sufficiently material to warrant
the board’s attention.
New business models
Existing and new business models
Renewal committee
Resource commitment meeting
Reviews strategic, commercial and investment decisions outside of core
activity and related to new lines of business (up to $250 million organic
and $25 million inorganic capital investment). Chaired by our chief
transition officer.
Reviews strategic, commercial and investment decisions related to
existing and new lines of business (above $250 million organic and
$25 million inorganic capital investment). Chaired by our chief executive.
New energy frontiers
steering committee
Ventures investment
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 chief transition officer.
Oversees strategic, commercial
and investment decisions in
venturing business. Chaired by
our group head of technology.
BP Launchpad
Launchpad is BP’s business-builder and scale-up factory. Its mission
is to build five $1 billion business unicorns. Chaired by our group head
of technology.
42
BP Annual Report and Form 20-F 2019
Executive-level committee.
Cross-functional committee.
Strategic report
Strategy
Recommendation: Disclose the actual and potential impacts of
climate-related risks and opportunities on the organization’s
business, strategy and financial planning where such information
is material.
We recognize the significance of the energy transition and the risks
and opportunities it presents. As part of their consideration of BP’s
strategy, the board and executive team consider risks and opportunities
associated with climate change and the energy transition informed by
a range of external inputs, including the International Panel on Climate
Change (IPCC), academic research and emerging regulatory
requirements, and BP materials such as the different scenarios
described in the BP Energy Outlook 2019.
We believe that the transition to a lower carbon economy presents
significant business opportunities for BP. One of our strategic priorities
is to pursue new opportunities to meet evolving technology, consumer
and policy trends through venturing and low carbon, see page 28.
Some of the opportunities we see are set out in our RIC framework –
to improve our products, to help customers lower their emissions and to
create new, lower carbon businesses, see page 41.
We have set out 10 aims to support our ambition to be a net zero
company by 2050 or sooner and to help the world reach net zero. We
believe that collectively, these 10 aims set out a path that is consistent
with the Paris goals. One of our specific aims relates to halving the
carbon intensity of our marketed products by 2050 or sooner.
See page 6 for more information on our net zero ambition and aims.
For the first time we have published the estimated lifecycle carbon
intensity of our marketed energy products, see page 40.
We recognize that climate-related risks include both:
• Physical risks – risks related to the physical impacts of climate
change including event driven risks such as changes in the severity
and/or frequency of extreme weather events.
• Transition risks – risks related to the transition to a lower carbon
economy including policy and legal, technology, markets and
reputational risks.
The potential impacts of such climate-related risks are described in Risk
factors, see pages 70-71. We place importance on pursuing a flexible
strategy which gives us optionality where there is uncertainty about the
pathways to achieve the Paris goals. This positions us to deliver our
strategic priorities, and net zero ambition and aims.
When developing our strategy, we draw on expertise from across the
organization. This includes our group economics team and their work
on the scenarios described in the BP Energy Outlook 2019. The Energy
Outlook, together with other scenarios, informs our price assumptions
which are part of our investment governance processes. The evaluation
of new material capex investment in 2019 for consistency with the Paris
goals is discussed on page 21.
Climate governance: management of climate-related matters in 2019
Chief executive and the executive team
Senior leadership
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.
n
o
i
t
a
g
e
e
D
l
A
c
c
o
u
n
t
a
b
i
l
i
t
y
Upstream carbon steering committee
Downstream advancing the energy transition committee
Focuses on the delivery of lower carbon plans in the Upstream.
Chaired by our chief operating officer of production,
transformation and carbon, Upstream.
Develops and drives the implementation of advancing the
energy transition in the Downstream. Chaired by our head
of technology, Downstream and chief scientist.
Underpinned by systems, processes and risk management.
Executive-level committee.
Senior-leadership level.
Cross-functional committee.
Business and segment committee.
BP Annual Report and Form 20-F 2019
43
Our group strategic planning team is responsible for using data from
the BP Energy Outlook and implementing the insights in our strategic
frameworks, including our net zero ambition and mid-term RIC targets.
We recognize that climate-related risks are an important consideration
in developing our strategy. Climate-related risks are incorporated into
BP’s governance process, see How we manage risk on page 69.
Risk management
Recommendation: Disclose how the organization identifies,
assesses and manages climate-related risks.
Our processes for identifying and managing climate-related risks are
integrated into BP’s risk management policy and the associated risk
management procedures. BP’s risk management system is designed
to address all types of risks and as part of this system our operating
businesses are responsible for identifying and managing their risks.
Risks which may be identified include potential effects on operations
at asset level, performance at business level and developments at
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 69.
This covers various aspects of how risks associated with the energy
transition could manifest. Similarly, physical climate-related risks such
as extreme weather are covered in our principal risks related to safety
and operations.
Metrics and targets
Recommendation: Disclose the metrics and targets used to assess
and manage relevant climate-related risks and opportunities where
such information is material.
We present the principal group-wide metrics and targets used to assess
and manage climate-related risks and opportunities on page 17. This
includes the targets we set out in 2018 in our RIC framework.
In addition, in 2019 BP announced that sustainable GHG emissions
reductions would be included as a factor in the reward of around
37,000 eligible employees across the group and around the world,
including executive directors. This target was 10% of the group’s annual
cash bonus scorecard and we exceeded the target set of 1.0Mte
(1.4Mte). In 2020 we plan to increase the percentage of remuneration
which is linked to emissions reductions for our leadership and eligible
employees. Our aim is to mobilize our workforce to become advocates
for our net zero ambition.
For information on our 2020 remuneration policy, see page 110.
TCFD index table
TCFD recommended disclosure
Governance
Disclose the organization’s
governance around climate-
related issues and opportunities.
Strategy
Disclose the actual and potential
impacts of climate-related risks
and opportunities on the
organization’s business, strategy
and financial planning where
such information is material.
Risk management
Disclose how the organization
identifies, assesses and
manages climate-related risks.
Metrics and targets
Disclose the metrics and targets
used to assess and manage
relevant climate-related risks
and opportunities where such
information is material.
a. Describe the board’s oversight of climate-related
risks and opportunities.
b. Describe the management’s role in assessing and
managing climate related risks and opportunities.
a. Describe the climate-related risks and opportunities
the organization has identified over the short,
medium, and long term.
b. Describe the impact of climate-related risks and
opportunities on the organization’s businesses,
strategy, and financial planning.
c. Describe the resilience of the organization’s strategy,
taking into consideration different climate-related
scenarios, including a 2°C or lower scenario.
a. Describe the organization’s processes for identifying
and assessing climate-related risks.
Where reported
Page 42.
Page 42.
Achieving the Paris goals, page 13 – for a discussion of the
different pathways and time horizons considered
RIC framework, page 41 – for an outline of opportunities.
Risk factors, pages 70-71 – description of principal risks.
Risk factors, pages 70-71 – description of principal risks.
Achieving the Paris goals, page 13.
Our strategy, page 16.
Risk management, page 44.
Upstream, page 50.
Downstream, page 56.
Other businesses and corporate, page 63.
b. Describe the organization’s processes for managing
Risk management, page 44.
climate-related risks.
c. Describe how processes for identifying, assessing,
and managing climate-related risks are integrated
into the organization’s overall risk management.
Risk management, page 44.
How we manage risk, pages 68-69.
Risk factors, pages 70-71.
a. Disclose the metrics used by the organization to
Relevant group-wide metrics and targets, page 17.
assess climate-related risks and opportunities in line
with its strategy and risk management process.
b. Disclose Scope 1, Scope 2, and, if appropriate,
Scope 3 GHG emissions, and the related risks.
c. Describe the targets used by the organization to
manage climate-related risks and opportunities and
performance against targets.
GHG emissions data, page 40.
RIC framework, page 41.
(Also note: Net zero ambition and aims, page 6).
44
BP Annual Report and Form 20-F 2019
Working with others
We work with peers, non-governmental organizations and
academic institutions to support the energy transition.
The Oil and Gas Climate Initiative (OGCI) 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.
For more information on BP’s methane intensity, see page 34.
BP is working with OGCI Climate Investments and certain other OGCI
member companies to help progress the UK’s first commercial
full-chain carbon capture, use and storage project. Net Zero Teesside
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.
The way our businesses around the world are expected to understand
and manage their environmental and social impacts is set out in our
operating management system (OMS). This includes requirements on
engaging with stakeholders who may be affected by our activities.
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
look to implement these in project design, construction and operations.
For example, in Mauritania and Senegal we are working with national
and international scientists on the biodiversity action plan for the
Greater Tortue Ahmeyim development.
Our OMS requires each of BP’s operating businesses and functions to
create and maintain its own OMS handbook, describing how it will carry
out its local operating activities. Through self-verification, local business
processes are reviewed and areas for improvement are prioritized,
allowing focus on delivering safe, reliable and compliant operations.
For information on our oil spill performance see page 46.
Water
We review water risks every year, taking into account availability,
quantity, quality and regulatory requirements. We also use a range of
tools, including the Global Environmental Management Initiative Local
Water Tool and the World Resources Institute Aqueduct Global Water
Risk Atlas.
In 2019 we saw a 4% rise in freshwater withdrawals and a 3% rise in
freshwater consumption. This was largely due to increased production,
with freshwater withdrawal and consumption intensities remaining flat,
compared with 2018.
Air emissions
We put measures in place to manage our air emissions, in line with
regulations and industry guidelines designed to protect the health of
local communities and the environment. In 2019 we took delivery of
the last three vessels in our new fleet of six liquefied natural gas (LNG)
carriers. These use around 25% less fuel and emit less nitrogen oxides
than the older LNG carriers in the BP operated fleet.
See bp.com/environment for more information.
Strategic report
Safety and security
Safety remains our number one priority and one of our core values.
Our aim is to have no accidents, no harm to people and no damage
to the environment.
We are working to continue to 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.
Process safety events
(number of incidents)
Recordable injury frequency
(workforce incidents per 200,000 hours worked)
100
75
50
25
0
83
84
61
56
20
16
18
16
72
26
0.4
0.3
0.2
0.1
0
2015
2016
2017 2018
2019
2015
2016
2017
2018 2019
Tier 1
Tier 2
Workforce 0.243 0.211 0.218 0.198 0.166
Employee 0.203 0.194 0.202 0.152 0.128
Contractor 0.279 0.222 0.229 0.233 0.193
American Petroleum Institute US benchmark*
International Association of Oil & Gas
Producers benchmark*
* API and IOGP 2019 data reports are not available
until May 2020.
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 two fatalities in 2019. In July a fire-fighting
assistant in our biofuels business in Brazil was fatally injured following a
fire truck accident while attending to an agricultural fire. In October a
contractor at our Whiting refinery in the US was fatally injured when he
fell from a scaffold ladder.
Recordable injury frequencya
Day away from work case frequencyb
Severe vehicle accident rate
2019
0.166
0.047
0.05
2018
0.198
0.048
0.04
2017
0.218
0.055
0.03
a
b
Incidents that result in a fatality or injury per 200,000 hours worked.
Incidents that result in an injury where a person is unable to work for a day (shift) or more
per 200,000 hours worked.
Our recordable injury frequency, which includes BHP assets acquired in
2018, reduced by 16% in 2019. There is always more we can do and we
remain focused on achieving better results today and in the future.
BP Annual Report and Form 20-F 2019
45
Managing safety
Cyber threats
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 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 our OMS, in order to meet local
regulations or circumstances, are subject to a governance process.
Recently acquired operations need to transition to our OMS.
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, 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.
Tier 1 and tier 2 process safety eventsa
Oil spills – numberb
Oil spills contained
Oil spills reaching land and water
Oil spilled – volume (thousand litres)
Oil unrecovered (thousand litres)
2019
98
152
90
58
710
300
2018
72
124
63
57
538
131
2017
79
139
81
58
886
265
a Tier 1 process safety events are losses of primary containment of greatest consequence
– such as causing harm to a member of the workforce, costly damage to equipment or
exceeding defined quantities. Tier 2 events are those of lesser consequence.
b Number of spills greater than or equal to one barrel (159 litres, 42 US gallons).
The total number of tier 1 and tier 2 process safety events increased
in 2019, mainly reflecting performance in assets recently acquired.
Underlying performance across the group improved slightly from 2018.
We are implementing BP procedures and processes to help bring newly
acquired assets in line with BP assets.
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.
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.
46
BP Annual Report and Form 20-F 2019
The severity, sophistication and scale of cyber attacks continues to
evolve. The increasing digitalization and reliance on IT systems makes
managing cyber risk an even greater priority for many industries,
including our own.
The risk comes from a variety of cyber-threat actors, including nation
states, criminals, terrorists, hacktivists and insiders. As with previous
years, we’ve experienced threats to the security of our digital
infrastructure, but none of these had a significant impact on our
business in 2019. We have a range of measures to manage this risk,
including the use of cyber-security policies and procedures, security
protection tools, continuous threat monitoring and event detection
capabilities, and incident response plans. We also conduct exercises
to test our response to and recovery from cyber attacks. To encourage
vigilance among our staff, our cyber-security training and awareness
programme covers topics such as 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
We monitor for hostile actions that could harm our people or disrupt
our operations. These actions might be connected to political or social
unrest, terrorism, armed conflict or criminal activity. We take these
potential threats seriously and assess them continuously.
Our 24-hour response information centre in the UK uses state-of-the-art
technology to monitor evolving high-risk situations in real-time. It helps
us to assess the safety of our people and provide them with practical
advice if there is an emergency.
This year, we faced a number of protests. We worked with local police,
including marine authorities, to minimize any disruption from these to
our operations.
Working with contractors
Through documents that help bridge between our policies and those
of our contractors, 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.
Strategic report
Our people
BP’s success depends on having a talented and diverse workforce that
represents the communities we serve.
Number of employees at 31 Decembera
2019
2018
2017
Upstream
Downstream
Other businesses and corporate
Total
16,600
44,300
9,200
70,100
16,900
42,700
13,400
73,000
17,700
42,100
14,200
74,000
At the end of 2019 we had five female directors (2018 5) 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 74.
In the UK we report the gender pay gap for five BP entities. Our 2019
report shows small improvements since 2018, including improvements
in our highest pay gap entities – BP p.l.c. and BP Exploration Operating
Company Limited. Six of the 10 gaps have narrowed. Our challenge is
to maintain and, if possible, accelerate this trend. We are working to
address the differences but recognize that this is a long-term challenge.
a Reported to the nearest 100. For more information see Financial statements – Note 35.
See bp.com/ukgenderpaygap for data and more information on our gender
Our people are the most important element of our success. We need
a motivated, engaged, and diverse workforce to deliver our purpose
and strategy. We aim to build a culture that generates the diversity
of thought, approach and ideas needed to play a leading role in the
energy transition, a culture in which people’s wellbeing is valued and
differences are respected.
The group people committee helps facilitate the group chief executive’s
oversight of policies relating to employees. In 2019 the committee
discussed people policies, including our 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
We aim to recruit talented people from diverse backgrounds, and
invest in training, development and competitive rewards for all our
people. We invest in employee development – with a focus on driving
safe, reliable and compliant operations, and on building technical,
functional and leadership capability. This includes a range of
development opportunities for our people through a mix of on-the-job
learning, developmental relationships with mentors, managers and
peers, and training delivered face-to-face, virtually and through
simulation or e-learning.
Diversity
We set out our current diversity and inclusion ambition in 2012. It is
based on our core values of safety, respect, excellence, courage and
one team.
We aim to attract, develop and retain the best talent and to create a
diverse and inclusive working environment, where everyone is
accepted, valued and treated equally without discrimination.
A total of 25% of our group leaders came from countries other than the
UK and the US in 2019 (2018 24%).
Workforce by gender
As at 31 December 2019
Male
Female
Female %
Board directors
Executive team
Group leaders
Subsidiary directors
All employees
7
11
285
1,202
5
2
93
247
43,762
26,280
42
15
25
17
38
The gender balance across BP as a whole is improving, with women
representing 38% of BP’s total population (2018 35%). 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.
pay gap in the UK.
Inclusion
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.
In 2019 we built closer ties between our central diversity and
inclusion team and local business resource groups (BRGs). We also
held a number of events for employees from our BRGs, including an
‘economics of diversity’ webcast, a roadshow and a diversity and
inclusion week.
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 engage
and use occupational assistance where needed, and to use reasonable
accommodations or adjustments to enable continued employment.
We have been recognized by a number of external awards in 2019,
including The Times newspaper’s Top 50 Employers for Women,
Stonewall Global Leader and the FT’s Inclusive Companies recognition.
Employee engagement
Our managers hold regular team and one-to-one meetings with their
team members, 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 understand what our employees think and feel about BP, we run an
annual ‘Pulse’ survey and in 2019 we introduced ‘Pulse Live’, which
enables us to monitor changes in employee sentiment on a weekly
basis. The overall employee engagement score in our 2019 survey was
65% (2018 66%). Pride in working for BP was 75% (2018 76%). In the
2019 survey, participating employees told us we should focus more
attention in several areas, including: sharing our strategy, reinforcing the
need for an open speak-up culture, explaining how BP is taking action to
help create a low carbon future and providing updates on safety
improvements and other priorities.
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.
BP Annual Report and Form 20-F 2019
47
Communities
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 committed
$84 million in social investment in 2019 (2018 $114.2 million).
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 the West Nile Delta, we provided training on vocational
skills and health and safety standards for local people. We reached
more than 2,000 people by the end of 2019.
Nationals employed
Angola
Azerbaijan
Egypt
Indonesia
Oman
Trinidad & Tobago
2019
88%
92%
81%
97%
80%
96%
2018
87%
91%
78%
96%
77%
96%
See bp.com/society for more information on how we generate value
to society.
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 business and human rights policy
and our code of conduct. Our OMS 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 ethical recruitment and working conditions, responsible
security and community health and livelihoods.
See bp.com/humanrights for more information about our approach to
human rights.
BP Target Neutral
By buying carbon offsets, Target Neutral is
supporting finance in projects that not only reduce
carbon but make a critical difference to the health
of low-income families.
The ONIL cookstove project has equipped 25,000
rural homes in Mexico with cookstoves that burn
more efficiently, using up to 58% less firewood
than a traditional open fire, and are equipped with
chimneys to take harmful cooking fumes outside
the household.
48
BP Annual Report and Form 20-F 2019
Strategic report
Governance and business ethics
Lobbying and political donations
Our values
Our values of safety, respect, excellence, courage and one team
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, including
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 this with their managers, supporting teams,
works councils (where relevant) or through OpenTalk, a confidential
and anonymous helpline operated by an independent company.
We received more than 1,800 concerns or enquiries through these
channels in 2019 (2018 1,712). The most commonly raised concerns
were related to the ‘Our people’ section of our code. The section
addresses issues such as harassment, equal opportunity, and diversity
and inclusion.
We take steps to identify and correct areas of non-conformance and
take disciplinary action where appropriate. In 2019 our businesses
dismissed 74 employees for non-conformance with our code of conduct
or unethical behaviour (2018 50). This excludes dismissals of staff
employed at our retail service stations.
See bp.com/codeofconduct for more information.
Anti-bribery and corruption
We operate in 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. Around 11,000 employees completed anti-bribery and
corruption training in 2019 (2018 10,957).
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. We take corrective action
with suppliers and business partners that fail to meet our expectations,
which may include terminating contracts. In 2019 we issued 25 audit
reports (2018 27).
Our aim is to more actively advocate for policies that support net zero,
including carbon pricing, see page 41.
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 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.
Trade associations
We aim to set new expectations for our relationships with trade
associations around the world. BP is a member of many industry
associations that offer opportunities to share good practices and
collaborate on issues of importance to our sector. In 2019 we began
an in-depth review assessing the alignment of the climate-related
policies and activities of 30 key trade associations to which we
belong with BP’s position. As a result of this process we will be
leaving three associations due to misalignment on climate policy.
For more information on the review process and outcomes see
bp.com/tradeassociations.
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 $6.9 billion in income and production taxes to governments
in 2019 (2018 $7.5 billion).
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 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.
Through EITI we work with governments, NGOs and international
agencies to improve transparency. For example, in 2019 we enacted
our global commitment through membership of the international board,
including supporting decision making on the new global EITI standard,
which represents a further evolution in transparency. The focus is on
making disclosure and open data a routine part of government and
corporate reporting, providing information to stakeholders in a way
that supports its widespread use in analysis and decision making. It
now requires contract transparency for new contracts from 2021, as
well as new requirements on environmental reporting and gender.
See bp.com/tax for our approach to tax and our payments to
governments report.
BP Annual Report and Form 20-F 2019
49
Upstream
The Upstream segment is
responsible for our activities in oil
and natural gas exploration, field
development and production.
Business model
Exploration
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.
Performance in 2019
Wells and
projects
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.
Global operations
organization
The global operations
organization is responsible for
safe, reliable and compliant
operations, including upstream
production assets and midstream
transportation and processing
activities.
Upstream profitability
($ billion)
58,000km2
94.4%
9
4.9
11.2
new exploration access
(2018 63,000km2)
BP-operated upstream plant
reliability
(2018 95.7%)
successful completion
of turnarounds
(2018 7)
5.2
5.9
14.3
14.6
5
5
final investment decisions
(2018 9)
major project start ups
(2018 6)
2.6
million barrels of oil equivalent
per day – hydrocarbon production
(2018 2.5mmboe/d)
2019
2018
2017
2016
–0.5
–0.9
2015
0.6
1.2
RC profit (loss) before interest and tax
Underlying RC profit (loss) before
interest and tax★
50
BP Annual Report and Form 20-F 2019
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.
Growing advantaged oil and gas
We manage our portfolio through disciplined investment in the world’s
great oil and gas basins.
We intend to make longer-term investments in natural gas as a lower
carbon fuel which can complement renewables and provide stable cash
flows while contributing to the energy transition to a lower carbon
future. We see our gas portfolio being complemented by oil assets
that we consider to be advantaged in the energy transition; this is oil
we can produce at a lower cost and higher margin, with faster payback
times and ready access to markets, and maintaining a rigorous focus
on carbon.
We aim to maintain a strong financial frame, allocating capital to
build resilience to withstand uncertainty and change in the external
environment. Ensuring sustainability of our business model and
products will be key to maintaining competitiveness.
Returns-led growth
We want to grow returns and value, and believe this will come from
many sources – expanding and managing our margins, operational
efficiency, unit cost reduction, and capital efficiency with disciplined
levels of capital reinvestment.
Our major projects are selected and evaluated on a balanced set of
investment criteria, which allow for comparison and prioritization, and to
evaluate for consistency with Paris goals within an appropriate portfolio
context. In the Upstream this evaluation includes confirming whether
we expect them to generate positive returns within a price and demand
environment we consider to be consistent with those goals, with a bias
towards shorter payback times and a comparison with the operational
emissions profile of our wider Upstream portfolio.
Underpinning our business model and strategy is our transformation
agenda. In 2019 we had more than 1,000 projects across the Upstream
aimed at sustainably improving both performance and ways of working
in the Upstream. Since the inception of our transformation programme
in 2016, projects are estimated to have delivered an additional
$1.5 billion of cash flow to the business.
In addition to our core upstream exploration, development and
production activities, the segment is responsible for the midstream
transportation, storage and processing that support its operations. We
also market and trade natural gas, including liquefied natural gas (LNG),
power and natural gas liquids. In 2019 our activities took place in 34
countries.
BPX Energy, our onshore oil and gas business in the US Lower 48
states, continues to operate as a separate, asset-focused, onshore
business. Integration of the BHP assets acquired in 2018 has gone
well, with realized savings from synergies more than double our
original target for 2019.
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.
Strategic report
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, having started up 24 of the 35 major
projects needed to reach this target by the end of 2019.
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.
This describes our strategy and organizational model in 2019.
Following BP’s new ambition and aims set out in February 2020,
we are transforming our business. We plan to provide more
information on our future strategy and near-term plans at our
capital markets day in September 2020.
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 expenditureb
BP average realizationsc
Crude oild
Natural gas liquids
Liquids
Natural gas
US natural gas
2019
54,501
4,917
2018
56,399
14,328
$ million
2017
45,440
5,221
6,241
222
644
11,158
11,904
14,550
12,027
5,865
13,763
$ per barrel
51.71
26.00
49.92
67.81
29.42
64.98
$ per thousand cubic feet
3.92
2.43
3.19
2.36
$ per barrel of oil equivalent
61.56
18.23
57.73
3.39
1.93
Total hydrocarbons
38.00
43.47
35.38
Average oil marker pricese
Brent
West Texas Intermediate
$ per barrel of oil equivalent
64.21
57.03
71.31
65.20
$ per barrel
54.19
50.79
Average natural gas marker prices
$ per million British thermal units
Average Henry Hub gas pricef
2.63
3.09
3.11
Average UK National Balancing
Point gas pricee
34.70
60.38
44.95
pence per therm
Includes sales to other segments.
a
b A reconciliation to GAAP information at the group level is provided on page 299.
c Realizations are based on sales by consolidated subsidiaries only, which excludes
equity-accounted entities.
d
Includes condensate.
e All traded days average.
f Henry Hub First of Month Index.
BP Annual Report and Form 20-F 2019
51
Market prices
Financial results
Brent remains an integral marker to the production portfolio, from which
a significant proportion of production is priced directly or indirectly.
Brent
120
120
120
90
60
30
0
0
0
Jan
($/bbl)
Feb Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2019
2018
2017
Five-year range
Dated Brent prices averaged $64.21 per barrel in 2019 – a 9% decrease
from 2018 levels but almost 30% above the 2015-17 average. Prices
fluctuated during the year reaching a peak of $71 in April on OPEC+
supply restraints and the decline in Venezuelan and Iranian output. In
the second half of the year, prices fluctuated between $59 in August
to $67 in December as OPEC+ restrained supply amid trade tensions.
Global consumption increased by 0.9 million barrels per day (mmb/d) to
100.1mmb/d for the year (0.9%) – a slowdown from growth rates seen
in the prior two years as trade tensions slowed global macroeconomic
growth. Global oil production remained flat at 100.5mmb/d, with growth
from non-OPEC countries offsetting supply restraint and disruptions
in OPEC countries. The fall in output in Venezuela and Iran due to
sanctions significantly contributed to the 1.9mmb/d decline in
OPEC output in 2019.
Henry Hub
($/mmBtu)
9
9
6
3
0 0
Jan
Feb Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2019
2018
2017
Five-year range
Henry Hub prices decreased to $2.63/mmBtu in 2019 from
$3.09/mmBtu in 2018 as US associated gas production continued
to grow strongly while US gas consumption growth slowed down.
The UK National Balancing Point hub price was almost halved from
60.38 pence per therm in 2018, down to 34.70 in 2019, due to a
significant increase in European LNG imports and record high storage
levels. Asian spot prices declined from $9.76/mmBtu in 2018, down to
$5.49/mmBtu on the back of global LNG oversupply, declining LNG
demand in Japan and Korea and a slow-down of Chinese LNG imports.
Sales and other operating revenues for 2019 decreased compared
with 2018, primarily reflecting lower liquids and gas realizations
partially offset by higher production and strong gas marketing
and trading revenues.
Replacement cost profit before interest and tax for the segment
included a net non-operating charge of $6,947 million. This
primarily relates to impairments arising from disposal transactions.
See Financial statements – Note 5 for further information. Fair value
accounting effects had a favourable impact of $706 million relative to
management’s view of performance.
The 2018 result included a net non-operating charge of $183 million,
primarily related 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. Fair value accounting effects had an adverse
impact of $39 million relative to management’s view of performance.
After adjusting for non-operating items and fair value accounting
effects, the underlying replacement cost result before interest and tax
was lower in 2019 compared with 2018. This primarily reflected lower
liquids and gas realizations and higher depreciation, depletion and
amortization partly offset by strong gas marketing and trading results
and higher production.
Organic capital expenditure was $11.9 billion (2018 $12.0 billion).
In total, disposal transactions generated $2 billion in proceeds in 2019,
with a corresponding reduction in net proved reserves of 134mmboe
within our subsidiaries. The major disposal transaction during 2019 was
the disposal of our interests in Gulf of Suez oil concessions in Egypt.
At year end, a number of balances associated with assets awaiting
the completion of announced disposals were held within the Assets
held for sale category in the balance sheet. These related to assets in
Alaska and US Lower 48. Impairment charges totalling $6.0 billion were
recognized in connection with these planned disposals. See Financial
statements – Notes 2 and 4 for further information.
More information on disposals is provided in Upstream analysis by
region on page 303.
Outlook for 2020
At the current time the global spread of the coronavirus (COVID-19)
is causing considerable uncertainty in the market, lowering demand
forecasts. This, and the changing dynamic among OPEC+ members,
has put downward pressure on prices. Aside from these factors,
we had expected price volatility in the near term. Taking these
factors into account, we expect the outlook for the year as a whole
to remain challenging.
52
BP Annual Report and Form 20-F 2019
Strategic report
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 find advantaged barrels
to build our hopper of options for potential future development. That
hopper of options gives us the flexibility to grow the cash and value
in the Upstream business while increasing the average quality of
the portfolio.
In line with our strategy, we are spending less on exploration and we
plan to spend a significant part of our exploration budget on lower-risk,
shorter-cycle-time opportunities around our incumbent positions.
New access in 2019
We gained access to new acreage covering around 58,000km2 in nine
countries – Argentina, Australia, Brazil, the Gambia, India, Oman, Peru,
the UK North Sea and the US Gulf of Mexico.
Exploration success
Proved reserves replacement ratio
The proved reserves replacement ratio for the segment in 2019 was
41% for subsidiaries and equity-accounted entities (2018 69%), 25%
for subsidiaries alone (2018 66%) and 210% for equity-accounted
entities alone (2018 106%). For more information on proved reserves
replacement for the group see page 308.
Upstream proved reserves
(mmboe)
Liquids
4,902 Subsidiaries
831
Equity-accounted entities
Gas
4,473 Subsidiaries
854
Equity-accounted entities
Estimated net proved reservesa (net of royalties)
We participated in 10 potentially commercial discoveries in 2019 – King
Embayment in the US Gulf of Mexico, Bele-1, Tuk-1, Hi-Hat-1, Boom-1
and Ginger in Trinidad, Nour North Sinai in Egypt, GTA-1 and Yakaar-2 in
Senegal and Orca-1 in Mauritania.
Liquids
Crude oilb
Subsidiaries
Exploration and appraisal costs
Total exploration and appraisal costs were $1,587 million (2018 $1,478
million), of which $302 million (2018 $180 million) related to lease
acquisition.
Natural gas liquids
Subsidiaries
Equity-accounted entitiesc
Equity-accounted entitiesc
Total liquids
Subsidiariesd
Equity-accounted entitiesc
Natural gas
Subsidiariese
Equity-accounted entitiesc
Total hydrocarbons
Subsidiariese
Equity-accounted entitiesc
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 6% of exploration and appraisal costs were directed
towards appraisal activity. We participated in 47 gross (21.15 net)
exploration and appraisal wells in 11 countries. Of these, 11 were lower
risk wells around incumbent positions.
Exploration expense
Total exploration expense of $964 million (2018 $1,445 million,
2017 $2,080 million) comprised the write-off of expenses related to
unsuccessful drilling activities, lease expiration or uncertainties around
development, 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 2019, decreased by 6% (a decrease of 8% for
subsidiaries and an increase of 6% for equity-accounted entities)
compared with proved reserves at 31 December 2018.
2019
2018
2017
million barrels
4,367
810
5,177
535
21
556
4,902
831
5,733
25,946
4,951
30,897
9,375
1,685
11,060
4,378
794
5,172
576
15
590
4,954
808
5,762
4,129
674
4,803
318
18
336
4,447
692
5,139
billion cubic feet
30,355
4,559
34,914
29,263
2,274
31,537
million barrels of oil equivalent
10,188
1,594
11,782
9,492
1,085
10,577
a Because of rounding, some totals may not agree exactly with the sum of their component
parts.
Includes condensate and bitumen.
d
b
c BP’s share of reserves of equity-accounted entities in the Upstream segment. During 2019
upstream operations in Argentina, Bolivia, Mexico, Russia and Norway as well as some of
our operations in Angola were conducted through equity-accounted entities.
Includes 11 million barrels (12 million barrels at 31 December 2018 and 14 million barrels
at 31 December 2017) in respect of the 30% non-controlling interest in BP Trinidad &
Tobago LLC.
Includes 1,330 billion cubic feet of natural gas (1,573 billion cubic feet at 31 December 2018
and 1,860 billion cubic feet at 31 December 2017) in respect of the 30% non-controlling
interest in BP Trinidad & Tobago LLC.
e
BP Annual Report and Form 20-F 2019
53
Developments
We achieved five major project start-ups in 2019 – in the US Gulf
of Mexico, Egypt, Trinidad and the UK North Sea. The Raven project
in Egypt is now expected to come onstream at the end of 2020.
In addition to these, we continued to progress all 11 of the remaining
projects that we expect will deliver our future production growth
target announced in 2016. Highlights from a selection of these are:
• India – Work on the KG D6 series of projects continued and the
first of the three projects is expected to begin production in 2020.
• Mauritania and Senegal – In Phase 1 of the Greater Tortue
Ahmeyim project, the first deepwater cross-border LNG project
is underway following sanction in early 2019 with a ramp up in
engineering, procurement and fabrication activity.
• UK North Sea – At Vorlich, two wells were drilled during the year
and production is expected to start in 2020.
Subsidiaries’ development expenditure incurred, excluding midstream
activities, was $10.8 billion (2018 $9.9 billion, 2017 $10.7 billion).
Major project start-ups in 2019
Giza and Fayoum, Egypt
Includes a deepwater, long-distance
tieback to an existing onshore plant
and eight wells.
Operator: BP
Partners: BP (82.75%), DEA Deutsche
Erdoel AG (17.25%)
Project type: Conventional gas
Angelin, Trinidad & Tobago
Includes a new platform and four
wells, with gas flowing to the
Serrette platform hub via a new
13-mile pipeline.
Operator: BP
Partners: BP (70%) and Repsol (30%)
Project type: LNG
Constellation, US Gulf of Mexico
Discovered in 2016, the field has
been developed as a subsea tieback
to Anadarko’s Constitution spar.
Operator: Anadarko
Partners: Anadarko (33.33%),
BP (66.67%)
Project type: Deepwater oil
Culzean, UK North Sea
Includes a standalone three-bridge-
linked platform development with
six production wells.
Operator: Total
Partners: Total (50%), BP (32%),
JX Nippon (18%)
Project type: High-pressure gas
Alligin, UK North Sea
Includes two wells, tied-back into
the existing Schiehallion and Loyal
subsea infrastructure.
Operator: BP
Partners: BP (50%) and Shell (50%)
Project type: Conventional Oil
54
BP Annual Report and Form 20-F 2019
Strategic report
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 as well as asset optimization and trading.
This means we have a single interface with gas trading markets and
a single set of trading compliance and risk management processes,
systems and controls. We are continuing to expand our LNG portfolio,
which includes global partnerships with utility companies, gas
distributors and national oil and gas companies.
This 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 337.
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 94%
in 2019, efficient delivery of turnarounds and strong infill drilling
performance, we have maintained base decline to 3-5% on average
over the last five years. Our long-term expectation for managed base
decline remains at 3-5% per guidance we have previously given.
Productiona (net of royalties)
Liquids
Crude oilb
Subsidiaries
Equity-accounted entitiesc
Natural gas liquids
Subsidiaries
Equity-accounted entitiesc
Total liquids
Subsidiaries
Equity-accounted entitiesc
Natural gas
Subsidiaries
Equity-accounted entitiesc
Total hydrocarbons
Subsidiaries
Equity-accounted entitiesc
2019
2018
2017
thousand barrels per day
1,046
127
1,173
104
10
114
1,150
138
1,288
7,366
457
7,823
1,051
121
1,172
88
8
96
1,139
129
1,268
1,064
199
1,263
85
8
93
1,149
207
1,356
million cubic feet per day
6,900
474
7,374
5,889
547
6,436
thousand barrels of oil equivalent per day
2,420
216
2,637
2,328
211
2,539
2,164
302
2,466
a Because of rounding, some totals may not agree exactly with the sum of their component
parts.
Includes condensate and bitumen.
Includes BP’s share of the production of equity-accounted entities in the Upstream segment.
b
c
Our total hydrocarbon production for the segment in 2019 was 3.8%
higher compared with 2018. The increase comprised a 3.9% increase
(1.0% for liquids and 6.8% for gas) for subsidiaries and a 2.5% increase
(6.4% increase for liquids and 3.6% decrease for gas) for equity-
accounted entities compared with 2018. For more information on
production, see Oil and gas disclosures for the group on page 308.
Underlying production was broadly flat compared to 2018.
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.
BP Annual Report and Form 20-F 2019
55
Downstream
The Downstream segment has global
marketing and manufacturing operations.
It is the product and service-led arm of
BP and is made up of three businesses.
Business model
Fuels
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. We also have a growing
presence in electric vehicle
charging with a focused strategy to
build the fastest, most convenient
networks for our customers.
Performance in 2019
$2.7bn
fuels marketing earnings
+2.5% vs 2018
(2018 $2.6bn)
94.9%
refining availability
(2018 95.0%)
Strategy
Lubricants
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.
Petrochemicals
Manufactures and markets
products that are produced
using industry-leading proprietary
BP technology, and are then used
by others to make consumer
products such as food packaging,
textiles and building materials.
Through our new BP Infinia
technology, we are working to
reduce plastic waste, helping
to enable a stronger circular
economy.
~1,600
convenience
partnership sites
(2018 ~1,400)
1.7
million barrels of oil
refined per day
(2018 1.7mmb/d)
49%
of lubricant sales
were premium grade
(2018 46%)
12.1
million tonnes of
petrochemicals produced
(2018 11.9mmte)
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 resilient, competitively
advantaged businesses, and we
are working at pace to create low
carbon businesses that can
advance the energy transition.
The execution of our strategy in
2019 has continued to deliver,
with underlying replacement cost
profit of $6.4 billion in the year.
Safe and reliable operations
This remains our core value and
first priority and we continue to
drive improvements in personal
and process safety performance.
Profitable marketing growth
We invest in higher-returning
fuels marketing and lubricants
businesses with growth potential
and reliable cash flows.
Advantaged manufacturing
We aim to have a competitively
advantaged refining and
petrochemicals portfolio
underpinned by operational
excellence and to grow earnings
potential, making the businesses
more resilient to margin volatility.
Simplification and efficiency
This remains central to what
we do to support performance
improvement and make our
businesses even more
competitive.
Transition to a lower carbon
and digitally enabled future
We are delivering and developing
new products, offers and business
models that support the transition
to a lower carbon and digitally
enabled future.
Downstream profitability
($ billion)
2019
2018
2017
2016
2015
6.5
6.4
6.9
7.6
7.2
7.0
7.1
7.5
5.2
5.6
RC profit before interest and tax
Underlying RC profit before interest
and tax★
This describes our strategy and
organizational model in 2019.
Following BP’s new ambition
and aims set out in February
2020, we are transforming our
business. We plan to provide
more information on our future
strategy and near-term plans
at our capital markets day in
September 2020.
56
BP Annual Report and Form 20-F 2019
Energy with purpose
Making more plastics recyclable
Companies joining the consortium:
• Packaging and recycling specialist
ALPLA.
• Food, drink and consumer goods
producers Britvic, Danone and
Unilever.
• Waste management and recycling
specialist REMONDIS.
Thinking beyond business as usual,
we’re using our know-how to explore
a breakthrough technology for
recycling opaque and difficult-to-
recycle PET plastic waste – familiar
to consumers as coloured bottles and
food trays. Our enhanced recycling
technology, BP Infinia, enables
PET to be diverted from landfill or
incineration and transformed into
virgin-quality feedstocks.
We plan to build a $25 million
pilot plant in the US to prove the
technology, which is expected to
be operational in late 2020. And
we’ve now joined forces with
leading businesses across the
PET packaging value chain to help
accelerate commercialization of
the technology.
We believe BP Infinia has the potential
to be a game-changer and important
stepping stone in enabling a stronger
circular economy and helping to reduce
unmanaged plastic waste.
Strategic report
Financial performance
Sale of crude oil through spot
59,738
62,484
and term contracts
2019
2018
$ million
2017
47,702
Marketing, spot and term sales
180,236
195,020
159,475
of refined products
Other sales and operating revenues
10,923
13,185
12,676
Sales and 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 expenditurec
250,897
270,689
219,853
4,791
1,315
396
6,502
(32)
(57)
6
(83)
4,759
1,258
402
6,419
2,997
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
a
b
Includes sales to other segments.
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 299.
Financial results
Sales and other operating revenues in 2019 were lower than in 2018,
mainly due to lower crude and product prices.
Replacement cost (RC) profit before interest and tax for 2019 included
a net non-operating charge of $77 million, which includes environmental
provisions. The 2018 result included a net non-operating charge of
$716 million, primarily reflecting restructuring costs. In addition, fair
value accounting effects had a favourable impact of $160 million,
compared with a favourable impact of $95 million in 2018.
After adjusting for non-operating items and fair value accounting effects,
underlying RC profit before interest and tax in 2019 was $6,419 million.
Outlook for 2020
The coronavirus (COVID-19) has already had significant impact on
margins and activity at the start of the year. We expect this uncertainty
to continue and anticipate lower industry refining margins during 2020.
We also anticipate wider North American heavy crude oil discounts and
a lower level of turnaround activity than in 2019.
BP Annual Report and Form 20-F 2019
57
BP refining marker margin
($/bbl)
32
24
16
8
0
Jan
Feb Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2019
2018
2017
Five-year range
Refining
At 31 December 2019 we owned or had a share in 10 refineriesab
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 307.
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 2019
operations remained strong, with refining availability at BP-operated
refineries of 94.9% (2018 95%) and refinery utilization rates across
our refining portfolio at 91% (2018 91%). As a result, we achieved
record levels of refining throughput for a second consecutive year,
despite high levels of 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.
During 2019 we also continued to scale up co-processing at our
refineries, growing the volume of lower carbon bio-feedstock
processed.
The refining result was lower in 2019 compared with 2018, with strong
operational performance and higher commercial optimization, which
was more than offset by a significantly weaker refining environment,
primarily driven by narrower heavy crude oil discounts.
thousand barrels per day
2019
2018
2017
Refinery throughputsac
US
Europe
Rest of the world
Total
737
787
225
703
781
241
1,749
1,725
Refining availability
94.9
95.0
713
773
216
1,702
%
95.2
a This does not include BP’s interest in Pan American Energy Group.
b On 31 December we completed the sale of our interest in the German Bayernoil refinery.
c Refinery throughputs reflect crude oil and other feedstock volumes.
Our fuels business
Our fuels strategy focuses primarily on fuels value chains (FVCs). This
includes 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.
We have also grown our presence in electric vehicle charging in recent
years, with a focus on the key markets of China, UK and Germany,
where we aim to build the fastest, most convenient networks for
electric vehicle customers.
Underlying RC profit before interest and tax for our fuels business
was lower compared with 2018, with strong refining operational
performance, which led to a second consecutive year of record refining
throughput and higher commercial optimization, despite high levels
of turnaround activity. This was more than offset, however, by lower
refining margins, including significantly narrower heavy crude oil
discounts, which together represented one of the weakest refining
environments across our portfolio in the last 10 years. In fuels marketing
we saw volumes and margins grow year on year, offset by adverse
foreign exchange effects. The full year result also reflects a higher
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
US Mid West
Northwest
Europe
Crude marker
Alaska
North Slope
West Texas
Intermediate
Brent
Mediterranean
Azeri Light
Australia
BP RMM
Brent
2019
17.6
16.0
11.1
9.1
11.1
13.2
2018
16.2
16.0
11.1
9.8
11.5
13.1
$ per barrel
2017
18.8
16.9
11.7
10.4
12.9
14.1
The global RMM averaged $13.2/bbl in 2019, similar to the level in 2018
($13.1/bbl), with weaker demand balanced by reduced supply due to an
increased level of refinery maintenance over the year. In addition
refining margins across our portfolio were significantly impacted by
other crude and product differentials outside of the global RMM,
primarily due to narrower heavy crude oil discounts.
58
BP Annual Report and Form 20-F 2019
Strategic report
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 2019 we continued to expand our convenience partnership
model, which is now in around 1,600 sites across our network,
including our differentiated REWE to Go® offer, now in around 550 sites
across Germany.
We also made significant progress towards our growth ambition in new
markets, most notably in Mexico where we now have more than 520
BP-branded retail sites, with volumes more than doubling in 2019, and
in December we signed an agreement with Reliance Industries Limited
to form a fuels retail and aviation joint venture across India, providing
access to one of the world’s largest and fastest growing fuels markets.
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 2019 we signed an agreement with DiDi, the world’s leading mobile
transportation platform, to build an electric vehicle charging network in
China, the world’s largest market for electric vehicles. In addition, in the
UK, BP Chargemaster began installing 150kW ultra-fast electric vehicle
chargers at our BP retail sites, with plans to build a national network of
high-power charging – one which will closely replicate the current
fuelling experience. These advances support BP’s strategy to create the
fastest and most convenient electrification networks in these markets.
BPme is our global customer engagement platform, which is also fast
becoming the portal to a suite of offers and services that will transform
our retail offer and deliver an enhanced and personalized customer
experience. The platform provides an easy, fast and convenient way for
customers to pay for fuel from their car, and for customers in the UK,
Australia and the US, it also incorporates our new loyalty programme
BPme Rewards.
Fuels marketing earnings in 2019 were similar to 2018, with volume
and margin growth offset by adverse foreign exchange effects.
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. Air BP supplies around 6.6 billion gallons of aviation
fuel a year at over 800 locations in more than 55 countries. 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 2019 we continued to develop new offers and solutions to advance
the energy transition and to meet the changing needs of our customers.
Through our collaboration with Neste, a leading producer of renewable
products, we began supplying aviation fuel made from sustainable materials
to a number of airports in Sweden. We also expanded our partnership with
China National Aviation Fuel Group, signing a joint venture agreement to
operate a general aviation fuel and services business in southwest China.
The joint venture intends to support the growth and development of China’s
general aviation sector.
Oil supply and trading
Our integrated supply and trading function is responsible for delivering
value across our crude and oil products supply chain. This enables our
downstream businesses to maintain a single interface with oil trading
markets and operate with a single set of trading compliance and risk
management processes, systems and controls. It principally achieves
this objective in two ways:
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 generate incremental margin.
Second, it aims to create and capture trading opportunities by entering
into a full range of exchange-traded commodity derivatives and
over-the-counter spot and term contracts. In combination with its rights to
access storage and transportation capacity, it also seeks to access
advantageous price differences between locations, time periods, and
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 the 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 337.
Sales volume
Marketing salesa
Trading/supply salesb
Total refined product sales
Crude oilc
Total
2019
2,727
3,268
5,995
2,713
8,708
thousand barrels per day
2018
2,736
3,194
5,930
2,624
8,554
2017
2,799
3,149
5,948
2,616
8,564
a Marketing sales include branded and unbranded sales of refined fuel products and lubricants
to business-to-business and business-to-consumer customers, including service station
dealers, jobbers, airlines, small and large resellers such as hypermarkets, and 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. 2019 includes
118 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
2019
7,200
8,200
3,500
2018
7,200
8,200
3,300
2017
7,200
8,100
3,000
18,900
18,700
18,300
d Reported to the nearest 100. Includes sites not operated by BP but instead operated by dealers,
jobbers, franchisees or brand licensees under a BP brand. These may move to or from the BP
brand as their fuel supply or brand licence agreements expire and are renegotiated in the normal
course of business. Retail sites are primarily branded BP, ARCO, Amoco and Aral.
BP Annual Report and Form 20-F 2019
59
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
49% of our sales from premium grade lubricants, we have a strong
base for further expansion and sustained profit growth.
In 2019 we strengthened our strategic relationship with Groupe
Renault, extending the Renault Sport Racing Formula 1 sponsorship
through to the end of 2024 and taking over as global service fill engine
oil lubricants partner. We also announced a partnership with Bosch to
run jointly branded workshops in China and the US.
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.
With the onset of electrification, demand for EV-fluids is expected to
grow. These include transmission fluids, battery coolants and greases.
Castrol is investing in and partnering with original equipment
manufacturers (OEMs) to develop advantaged EV-fluid technologies,
and in 2019 we announced a new partnership with the Panasonic
Jaguar Racing Formula E Team for season 2019/20. Using Castrol’s
EV-fluids allows Jaguar and Castrol to collaborate and further develop
advanced technology and EV-fluids for both race and road cars
of the future.
The lubricants business delivered an underlying RC profit before interest
and tax that was similar to 2018, reflecting year-on-year unit margin
improvement, offset by adverse foreign exchange rate movements.
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 have also grown our third-party
technology licensing income to create additional value.
We aim to create material, industry leading business models in
sustainable chemicals and plastics circularity and in 2019 we announced
the development of BP Infinia, an enhanced recycling technology,
capable of processing currently unrecyclable PET plastic waste. We also
formed a consortium with a number of leading companies operating
across the polyester packaging value chain which aims to accelerate the
commercialization of BP Infinia technology and to develop a new circular
approach to dealing with PET plastic waste. In 2020 BP plans to build a
pilot plant in the US to prove the technology, before progressing to
full-scale commercialization. We believe these are important steps in
enabling a stronger circular economy in the PET plastics industry,
underpinned by our advantaged technology and strategic partnerships.
In addition, we signed an agreement with Virent and Johnson Matthey
to further advance the development of bio-paraxylene, a key raw
material for the production of renewable polyester.
As part of our growth agenda we expanded capacity at our joint venture
acetyls site in South Korea and signed an agreement with Zhejiang
Petroleum and Chemical Corporation (ZPCC) to explore the creation of a
new, world-scale joint venture to build and operate a 1 million tonne per
annum acetic acid plant in Zhejiang Province, China.
In December 2018 we 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 advantaged facility would
be the largest integrated aromatics and PTA complex in the western
hemisphere. Significant progress has been made in defining the project
with a final investment decision expected towards the end of 2020.
In 2019 the petrochemicals business delivered an underlying RC profit
before interest and tax that was lower compared with 2018, reflecting
a significantly weaker margin environment across both aromatics
and acetyls.
Our petrochemicals production of 12.1 million tonnes in 2019 was
higher than in 2018 (2018 11.9mmte).
60
BP Annual Report and Form 20-F 2019
Strategic report
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.
Rosneft shareholding
ROSNEFTEGAZ JSC 50.00%a
BP
QH Oil
Investments LLC
Others
19.75%
18.93%
11.32%
a 50% plus one share.
BP share of Rosneft dividend
($ millions)b
2019
451
2018
420
334
785
200
620
2017
124
190
314
2016
2015
Interim
332
271
Annual for previous year, less interim
b Net of withholding taxes.
About Rosneft
Rosneft is the largest oil company
in Russia and one of the largest
publicly traded oil companies in
the world based on hydrocarbon
production volume. Rosneft
has a major resource base of
hydrocarbons onshore and
offshore, with assets in all of
Russia’s key hydrocarbon
regions and abroad.
2019 summary
Rosneft is the leading Russian
refining company based on
throughput. It owns and operates
13 refineries in Russia, and 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
with 50% plus one share
is Rosneftegaz JSC
(Rosneftegaz), which is
wholly owned by the
Russian government.
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 received $785 million, net of withholding taxes, (2018 $620 million), representing its share of
Rosneft’s dividends. This dividend represents 50% of IFRS net profit, and is paid twice a year in line
with the dividend policy adopted in 2017.
• BP remains committed to our strategic investment in Rosneft, while complying with all relevant sanctions.
8,281
million barrels of oil equivalent
– BP share of Rosneft
proved reserves
(2018 8,163mmboe)
1.1
million barrels of oil equivalent
per day – BP share of Rosneft
hydrocarbon production
(2018 1.1mmboe/d)
18
refineries – owned
or hold a stake in
(2018 18)
2.24
million barrels of oil
refined per day
(2018 2.33mmb/d)
19.75%
BP’s shareholding in Rosneft
>3,000
retail service stations
in Russia and abroad
(2018 >2,960)
BP Annual Report and Form 20-F 2019
61
Co-operation with Rosneft
Our strategy is to work in co-operation with Rosneft to increase total
shareholder return. We also partner with Rosneft in building a material
business in addition to our shareholding.
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.
• BP holds a 49% interest in Kharampurneftegaz LLC (Kharampur),
together with Rosneft (51%), which develops resources within the
Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets
in northern Russia. 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%). In 2019 BP received dividends from Taas of
$157 million, net of withholding taxes (2018 $48 million). BP’s
interest in Taas is reported through the Upstream segment.
• Rosneft (51%) and BP (49%) jointly own Yermak Neftegaz LLC
(Yermak). The joint venture conducts onshore exploration in the
West Siberian and Yenisei-Khatanga basins. In April the right to
explore two additional oil and gas licence areas located in Sakha
(Yakutia) was transferred to a wholly owned subsidiary of Yermak.
BP’s interest in Yermak is reported through the Upstream segment.
• Rosneft and BP are in the process of creating a joint venture
investment fund (VIF). This supports BP and Rosneft’s agenda to
accelerate new innovations in the oil and gas industry.
Collaboration
BP collaborates on the provision of technical, HSE and non-technical
services on a contractual basis to improve functional asset performance.
BP and Rosneft have developed an innovative cable-less onshore
seismic acquisition system and are in discussions about further
collaboration.
Social projects
BP together with Rosneft sponsor the Petroleum Engineering Masters
degree programme led by the Kazan Federal University (Russia) and
Imperial College London (UK), providing financial support, mentoring
and lecturing for the students.
Also, with Rosneft, BP sponsors the Britten-Shostakovich Festival
Orchestra which brings together the finest young talents from British
and Russian music schools, with an average age of 22. Performances
in 2019 took place in both the UK and Russia.
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
2019
2,306
10
2,316
103
2,419
2018
2,288
(67)
2,221
95
2,316
$ million
2017
923
(87)
836
–
836
Average oil marker prices
$ per barrel
Urals (Northwest Europe – CIF)
62.96
69.89
52.84
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.
Includes $(11) million (2018 $(5) million, 2017 $(2) million) of foreign exchange (gain)/losses
arising on the dividend received.
b
Market price
The price of Urals delivered in North West Europe (Rotterdam) averaged
$62.96/bbl in 2019. The discount to dated Brent was $1.25/bbl in line
with 2018 ($1.42/bbl).
Financial results
Replacement cost (RC) profit before interest and tax for the segment
included a non-operating charge of $103 million for 2019 and $95 million
for 2018.
After adjusting for non-operating items, the increase in the underlying
RC profit before interest and tax compared with 2018 primarily reflected
favourable foreign exchange and certain one-off items offset by lower
oil prices. See also Financial statements – Notes 17 and 32 for other
foreign exchange effects.
Balance sheet
As at 31 December
2019
2018
$ million
2017
Investments in associatesc
12,927
10,074
10,059
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 reserves
(net of royalties) (BP share)
Liquids (million barrels)
Crude oild
Natural gas liquids
Total liquidse
Natural gas (billion cubic feet)f
Total hydrocarbons (mmboe)
2019
2018
2017
920
3
923
1,279
1,144
919
4
923
1,285
1,144
900
4
904
1,308
1,129
5,604
141
5,745
14,705
8,281
5,539
154
5,693
5,402
131
5,533
14,325
13,522
8,163
7,864
c See Financial statements – Note 17 for further information.
d
e
Includes condensate.
Includes 357mmb (356mmb at 31 December 2018; 338mmb at 31 December 2017) for the
6.21% non-controlling interest (6.32% at 31 December 2018; 6.31% at 31 December 2017)
in Rosneft held assets in Russia including 26 million barrels (24mmb at 31 December 2018;
6mmb at 31 December 2017) held through BP’s interests in Russia other than Rosneft.
Includes 1,430bcf (1,211bcf at 31 December 2018; 306bcf at 31 December 2017) for the
9.72% non-controlling interest (8.60% at 31 December 2018; 2.30% at 31 December 2017)
in Rosneft held assets in Russia including 569bcf (480bcf at 31 December 2018; 2bcf at
31 December 2017) held through BP’s interests in Russia other than Rosneft.
f
62
BP Annual Report and Form 20-F 2019
Strategic report
Other businesses and corporate
Currently comprises our Alternative Energy
business, shipping, treasury, BP Ventures
and corporate activities, including centralized
functions and any residual costs of the Gulf
of Mexico oil spill.
Alternative Energy
Financial performance
BP Ventures
Shipping
Treasury
Insurance
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 expenditureb
2019
1,788
(319)
(2,452)
(2,771)
319
1,172
1,491
(1,280)
337
2018
1,678
(714)
(2,807)
(3,521)
714
1,249
1,963
(1,558)
332
$ million
2017
1,469
(2,687)
(1,758)
(4,445)
2,687
160
2,847
(1,598)
339
Includes sales to other segments.
a
b A reconciliation to GAAP information at the group level is provided on page 299.
The replacement cost (RC) loss before interest
and tax for the year ended 31 December 2019
was $2,771 million (2018 $3,521 million). The
2019 result included a net charge for non-
operating items of $1,491 million, primarily
relating to the reclassification of $877 million
of accumulated foreign exchange losses from
reserves to the income statement, which
arose as a result of the contribution of our
Brazilian biofuels business to BP Bunge
Bioenergia, as well as Gulf of Mexico oil spill
related costs of $319 million (non-operating
items in 2018 $1,963 million).
After adjusting for these non-operating items,
the underlying RC loss before interest and tax
for the year ended 31 December 2019 was
$1,280 million (2018 $1,558 million). This
result mainly reflected improved shipping
performance.
Outlook
Other businesses and corporate annual
charges, excluding non-operating items, are
expected to be around $1.4 billion in 2020.
Alternative Energy
Renewables are the fastest-growing energy
source, potentially contributing half of the
growth in global energy, with its share in
primary energy increasing from 4% in 2019
to around 15% by 2040a.
In BP, we have an established and growing
alternative energy business, with a significant
portfolio across renewable fuels, power
and products. And we are developing new
business models in areas such as low carbon
power and digital energy.
a BP Energy Outlook 2019: ‘evolving transition’ scenario.
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 – see page 41.
BP Annual Report and Form 20-F 2019
63
Our Alternative Energy portfolio
Biofuels
Biopower
Wind
energy
We formed BP Bunge Bioenergia, a joint venture that
combines BP and Bunge’s Brazilian bioenergy and
sugarcane ethanol businesses. The venture operates
11 biofuels sites and has a production capacity of
32 million metric tonnes of sugarcane a year (see
Going big in biofuels).
Solar
energy
We increased our stake in Lightsource BP to
become a 50:50 joint venture. Lightsource BP aims
to develop 10GW of solar projects by 2023, see
page 73 for more information.
BP Bunge Bioenergia produces renewable energy
from its biofuels manufacturing sites. The joint
venture is capable of exporting 1,200GW hours of
biopower to the national grid.
Renewable
products
Butamax® our 50:50 joint venture with DuPont
produces bio-isobutanol from corn. The energy-rich
bioproduct has a variety of uses, such as in paints
and lubricants.
We operate nine sites in six US states and hold an
interest in another facility in Hawaii. Together they
have a net generating capacity of 926MW.
Low carbon
power and
digital energy
We are developing a number of digital platforms to
connect consumers with local, low carbon electricity
to power their homes and transport, and are
exploring opportunities to create value at the
interplay between gas and renewable energy.
Energy with purpose
Investing in energy
management
To help grow our digital energy
portfolio, we have invested in Grid
Edge, an energy management
company. Its technology helps
customers predict, control and
optimize a building’s energy profile.
• Grid Edge can help customers lower
carbon emissions by 10-15%
on average.
The cloud-based software can
anticipate a building’s energy demand
using data such as weather forecasts
and expected occupancy.
• This allows building managers to
adapt energy use and take
advantage of periods of high
renewable power generation.
• Customers can also use the
building’s flexibility in energy
demand and generation like a
giant battery.
“
This investment is
in support of our
strategy to create
an ecosystem of
distinctive, digitally
enabled, low carbon
businesses for
commercial and
industrial customers.”
Nick Wayth
Chief development officer,
Alternative Energy
Going big in biofuels
BP has formed a 50:50 joint
venture in Brazil with leading
agri-commodities company Bunge
Limited. The deal expands our
existing biofuels business by more
than 50%.
• BP Bunge Bioenergia is now
the second-largest operator by
effective crushing capacity in the
country’s bioethanol market.
Brazil is the world’s second-largest
market for ethanol as a transportation
fuel, with around 75% of the country’s
vehicles able to run on it.
• Demand for ethanol is growing
rapidly in the country. In 2019
demand increased 10% versus
2018 and is set to increase up to
55% by 2030.
“
With a shared
commitment to safety
and sustainability,
bringing together our
assets and expertise
allows us to improve
performance, develop
options for growth and
generate real value.”
Dev Sanyal
Chief executive,
Alternative Energy
64
BP Annual Report and Form 20-F 2019
BP Ventures
The energy transition is driving the need for rapid change in technology
and ways of working, and the imperative for innovation has never been
more urgent.
Venturing plays a key role in BP, helping meet the world’s need for
more energy, while at the same time reducing carbon emissions.
We aim to do this by leveraging our investments across a portfolio of
relevant technology businesses that can help BP transition to a lower
carbon economy.
BP Ventures is set up to grow new energy businesses in the Upstream,
Downstream, Alternative Energy and in five areas: advanced mobility,
power and storage, carbon management, bio and low carbon products,
and digital transformation. We have invested over $650 million dollars
since 2007 in more than 40 companies with technologies and
innovations that we believe will materially impact BP and global
energy systems.
We invested $30 million into Calysta in 2019. This alternative protein
producer uses natural gas to produce protein for fish, livestock and pet
feeds, see page 28. We also invested a further $30 million into Fulcrum
Bioenergy®, a pioneer in making low carbon, low-cost, transportation
fuels from one of the most abundant resources – household garbage.
And we made two investments in energy management companies –
Grid Edge and R&B – totalling $5.4 million.
BP Launchpad
BP’s scale-up factory, BP Launchpad, became fully operational in 2019.
The initiative aims to quickly create multiple businesses valued over
$1 billion that can help tackle the dual energy challenge. Launchpad is
focused on building world-scale businesses that specialize in digital and
low carbon technologies and the circular economy, with potential for
these businesses to become future BP business units.
Examples of growth businesses in the Launchpad portfolio:
• Lytt: a subsurface analytics business, providing fibre optic
development, deployment and operational services, including
acoustic and temperature sensing.
• STRYDE: a land seismic receiver technology business. STRYDE’s
technology breaks the cost/time trade-off to generate high-quality
seismic images of the subsurface.
• Fotech: a technology company focused on developing and deploying
advanced fibre optic sensing hardware. Launchpad acquired Fotech in
late 2019; BP Ventures has been a minority investor since 2013.
Shipping
BP’s shipping and chartering activities help to ensure the safe and efficient
transportation of our hydrocarbons using a combination of BP-operated,
time-chartered and spot-chartered vessels. At 31 December 2019, BP had
35 BP-operated and 40 time-chartered vessels for our international oil and
LNG shipping operations. All vessels conducting BP shipping activities are
required to meet BP approved standards.
Strategic report
Energy with purpose
“
The conservation and
restoration of forests
is vital to combatting
climate change. We look
forward to supporting
the team’s expansion
into the voluntary
carbon market.”
Nacho Gimenez
Managing director,
BP Ventures
BP invests in forest
carbon offsets leader
BP Ventures’ investment in Finite
Resources is helping to grow its
business, supporting sustainable
forest management practices.
The funding will help Finite Carbon,
a subsidiary of Finite Resources,
scale up its voluntary carbon offsets
programme for businesses.
The programme aims to connect
landowners to businesses that want
to purchase forest carbon offsets, with
corporations paying a fee per tonne of
carbon stored in the forest.
This investment is part of our aim
to support the technologies and
innovations we believe will benefit BP
and global energy systems during the
transition to a low carbon economy.
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 seeking to ensure that
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 more 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 2019
65
Section 172 statement
How the board complied with its Section 172 duty.
3. Monitoring decisions and actions of the CEO and the
The board welcomes the new reporting requirement as an opportunity
to explain how dialogue with stakeholders has informed and helped to
shape its decisions. For example the board’s engagement with Climate
Action 100+ in the lead up to the 2019 AGM.
Following the announcement of Bernard Looney’s appointment as chief
executive officer (CEO) in October 2019, the board engaged with Bernard
and the leadership team to develop the company’s new purpose, net
zero ambition and aims. This was supported by extensive dialogue with
investors, governments, employees and other stakeholders.
Through working collaboratively with management and listening to
feedback from the company’s many stakeholders, the board believes
that BP is well positioned to respond to increasing uncertainty. We are
embarking on a period of change to deliver on our purpose to reimagine
energy for people and our planet, while reinventing BP so that we can
succeed over the long term. This means continuing to deliver our
investor proposition, while responding to society’s expectations.
Delegation of authority
The board believes governance of BP is best achieved by delegation
of its authority for the executive management of BP to the CEO, subject
to defined limits and monitoring by the board. The board routinely
monitors the delegation of authority, ensuring that it is regularly
updated, while retaining ultimate responsibility.
The board has adopted a long-standing corporate governance
framework, which includes principles outlining:
• The board’s relationship with shareholders and executive management.
• The conduct of board affairs and the tasks and requirements for
board committees.
• The board’s focus on activities that enable it to promote shareholders’
interests, including development of strategy, monitoring of executive
action and ongoing board and executive management succession.
The framework is being reviewed to ensure it is best suited to support
the evolving strategy and BP’s new purpose, ambition and aims.
The current framework covers the following principal areas:
1. Company purpose: pursuing BP’s purpose and accountability to
shareholders for the company’s actions. This means focusing
primarily on strategic issues, while having regard to economic,
political and social issues and other relevant external matters which
may influence or affect the development of BP’s business and
exemplify through the board principles (including the executive
limitations), its expectations for the conduct of the BP business
and its employees.
2. Strategy: responsibility for establishing and reviewing the long-term
strategy and the annual plan (the plan) for BP, based on proposals
made by the CEO for achieving BP’s purpose.
performance of BP: including implementation of, and performance
against, the strategy and the plan; and the exercise of authority
delegated to the CEO. The board satisfies itself that emerging and
principal risks to BP are identified and understood, systems of risk
management, compliance and controls are in place to mitigate such
risks and expected conduct of BP’s business and its employees is
reflected in a set of values established by the CEO.
4. Succession: ensuring systems and processes are in place for
succession, evaluation and compensation of the CEO, executive and
non-executive directors and key members of senior management.
Those delegated to by the directors to take decisions have access to
functional assurance support to identify matters which may have an
impact on a proposed decision.
The Companies Act 2006 (CA2006) sets out a number of general
duties which directors owe to the company. New legislation has
been introduced to help shareholders better understand how
directors have discharged their duty to promote the success of
the company, while having regard to the matters set out in section
172(1)(a) to (f) of the CA2006 (s172 factors). In 2019 the directors
continued to exercise all their duties, while having regard to these
and other factors as they reviewed and considered proposals from
senior management and governed the company on behalf of its
shareholders through the BP board.
Further information as to how the board has had regard to the s172 factors:
Section 172 factor
Key examples
Consequence of any
decision in the long term
Interests of employees
Fostering business
relationships with suppliers,
customers and others
Impact of operations
on the community
and the environment
New ambition and purpose
Investment process
Strategy
Engagement, below and page
Sustainability ‘Our people’
Parental leave
Alignment of ACB and option
to carbon offset
Engagement, below and page
New ambition and purpose
See our support for CA100+
resolution and response
Engagement, below and pages
Maintaining high standard
of business conduct
Governance, pages
Sustainability
Acting fairly between
members
Stakeholder engagement,
below and page
Balanced long-term decision making
Investor proposition
Page
6
19
16
88
47
89
34, 41, 44
88
6
6
40-45, 48
81-99, 101
40-49
88
67
18
How we engage and foster strong relationships with some of our key stakeholders
Customers
Employees
• Pulse survey.
• Town halls.
• Helios awards.
• Original equipment
manufacturer
collaborations.
• Global customer
brand tracking.
• Customer events.
See bp.com/
sustainabilityreport.
66
BP Annual Report and Form 20-F 2019
Government
and regulators
• Country economic
impact reports.
• Multi-stakeholder
Investors and
shareholders
• Annual engagement
programme.
• Quarterly and
Partners and
suppliers
• Industry events and
memberships.
Society
• Social media.
• Community workshops
• Supplier workshops and
and training.
groups.
year-end results.
training.
• Government lobbying.
• Annual general meeting.
• University collaborations.
• Social investment
programmes.
See Sustainability
on page 47 and
Corporate governance
on page 88.
See bp.com/
tradeassociations and
bp.com/tax.
See Corporate
governance on
page 88.
See bp.com/technology.
See Sustainability
on page 39
and bp.com/
sustainabilityreport.
Strategic report
How our board considers stakeholders in decision making
Strategy
Performance
People
Governance
At every board meeting the directors
review, with the management team, the
progress against strategic priorities and the
changing shape of the business portfolio.
This collaborative approach by the board,
together with the board’s approval of the
company strategy, helps it to promote the
long-term success of BP. The board
assesses different areas of the business
so that BP is well positioned to deliver on
its ambition to become a net zero company
by 2050 or sooner, and to help the world
get to net zero. Ultimately board decisions
are taken against the backdrop of what
it considers to be in the best interest of
the long-term financial success of the
company and BP’s stakeholders,
including shareholders, employees,
the community and environment,
our suppliers and customers.
We made strong progress with our
divestment plans and built exciting new
opportunities in fast-growing markets in
2019. BP’s flexible strategy allows it to
grow in ways that can make a significant
contribution to the energy transition,
helping deliver the lower carbon energy
the world wants and needs, while
fostering strong relationships with our
stakeholders. This further strengthens the
company’s balance sheet, enabling us to
pursue new advantaged opportunities for
BP’s portfolio within our disciplined
financial framework.
In order to become a net zero company by
2050 or sooner, BP must perform as we
transform.
The board regularly reviews and monitors
BP’s safety, reliability and environmental
performance, with the aim of continually
making BP safer for our entire workforce
and minimizing our environmental impact.
It also focuses on maintaining financial
discipline and delivering strong earnings,
cash flow and returns to shareholders.
In 2019, BP increased its stake in
Lightsource BP, see page 73; formed
a new joint venture with BP Bunge
Bioenergia, see page 64; partnered with
the world-leading mobility platform,
DiDi, to create a new electric vehicle
charging network in China, see page 27;
and is exiting BP’s Alaska business as
part of a two-year $10 billion divestment
programme.
In 2019 a recordable injury frequency rate
of 0.166 was the lowest since reporting
began, while the number of injuries
recorded fell by 17%. Safety will always
be one of our core values. This is
important to our workforce, local
communities and the environment, while
securing strong operational availability
and reliability is crucial to our partners,
suppliers and customers.
BP’s workforce is key to its success.
Our people help us maintain our strong
reputation for high standards of business
conduct are fundamental in delivering our
purpose to reimagine energy.
The past year was significant for BP,
with the announcement of Bernard
Looney as new CEO. As part of the
succession planning for this role, the
board considered a number of factors,
including the values and leadership
behaviours that this role requires. Bernard
has been with BP since 1991 and has a
strong sense of BP’s culture and values.
As chief executive of Upstream, he
oversaw improvements in personal
safety and initiated developments in the
workplace in areas such as mental health,
diversity and inclusion.
Together the board and new CEO
reviewed the new organizational structure,
including the appointment of the
leadership team and restructuring plans.
The board is reviewing the manner in
which it engages with the workforce
to enable it to better understand the
interests and concerns of BP’s people,
see page 88.
The board, led by the chairman, believes
that strong governance is essential to
the success of the company. At the end
of 2018, it participated in an external
evaluation of its performance. The board
discussed the findings of this review
and the chairman introduced changes to
the board’s ways of working. It agreed
to implement changes to board meetings,
so that agendas will be structured around
four distinct pillars in 2020 – strategy,
performance, people and governance.
In light of BP’s new corporate purpose,
ambition and aims and the changing
corporate governance landscape, the
board is reviewing its governance
framework in order to modernize its
principles and processes. The new
framework will continue to drive the
highest levels of business standards
and best practice, aligning these with
BP’s business purpose, values, strategy
and culture.
The board will continue to assess and
monitor culture and will look to obtain
useful insight through effective dialogue
with our key stakeholders and taking
feedback into account in the board’s
decision-making process.
Relevant section 172 factors
The board
(including delegation of authority)
Customers
Employees
Government
and regulators
Investors and
shareholders
Partners and
suppliers
Society
Our broad customer
base spans industries,
businesses and end
consumers of our products
and services. We work
closely with our customers
to understand their evolving
needs so we can improve
and adapt to meet them.
We work to attract, develop
and retain the world’s best
talent, equipped with the
right skills for the future.
Our people have a crucial
role in delivering against our
strategy and creating value.
We aim to help countries
around the world grow their
domestic energy supplies
and boost energy security.
This in turn helps create
jobs and generates
revenues for governments.
We aim to maintain dialogue
with governments and
engage in policy debates
that are of concern to us
and the communities in
which we operate.
Our investment proposition
is to grow sustainable
free cash flow and
distributions to shareholders
over the long term. We rely
on the support of our
investors, analysts and
proxy voting agencies and
engage with global
investment centres, sharing
updates on our strategic
progress and our financial
and non-financial plans.
We depend on the
capability and performance
of our suppliers, contractors
and other partners, such as
small businesses, industry
peers and academia, to help
deliver the products and
services we need for our
operations and our
customers.
We consult with local
people and NGOs to gain
valuable perspectives on
the ways in which our
activities could impact
the local community or
environment. We typically
engage well before any
physical work begins on a
project and continue the
conversation throughout a
project’s lifespan.
>10m
retail customers served
every day
70,100
employees
worldwide
$6.9bn
paid in income and
production taxes to
governments in 2019
$8.3bn
total dividends
distributed to BP
shareholders in 2019
$364m
invested in research
and development
$84m
committed to social
investment in 2019
BP Annual Report and Form 20-F 2019
67
Oversight and
governance
Risk management processes
We aim for a consistent basis of measuring risk to:
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 70.
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
of these risks and intervene for improvement where necessary.
• Report up the management chain and to the board on a periodic basis
on how significant risks are being managed, monitored, assured and
the improvements that are being made.
Our risk management activities
Day-to-day risk
management
Identify,
manage and
report risks
Business and
strategic risk
management
Plan, manage
performance
and assure
Set policy
and monitor
principal risks
Facilities,
assets and
operations
Business
segments and
functions
Executive
and corporate
functions
The
board
Day-to-day risk management – management and staff at our
facilities, assets and functions seek to identify and manage risk,
promoting safe, compliant and reliable operations. BP requirements,
which take into account applicable laws and regulations, underpin the
practical plans developed to help reduce risk and deliver 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. Such oversight may include
reviews of the outcomes of business processes including strategy,
planning and resource and capital allocation.
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.
68
BP Annual Report and Form 20-F 2019
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.
• Group ethics and compliance committee – for legal and
regulatory 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, environment and security assurance committee.
• Geopolitical committee.
See BP governance framework on page 83, Board activity in 2019
on page 84, committee reports on pages 90-99 and 101 and Risk
management and internal control on page 128.
• 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 and determine risks
for particular oversight by the board and its committees. 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. These may include emerging
risks which are considered through existing processes, including BP’s
risk management system, BP’s Energy Outlook, BP’s Technology
Outlook and group strategic reviews.
We identify longer-term strategic risks and high priority risks for particular
oversight by the board and its various committees in the coming year.
Those identified for particular oversight in 2020 are listed in this section.
These may be updated throughout the year in response to changes in
internal and external circumstances. The oversight and management of
other risks is undertaken in the normal course of business.
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 70.
Strategic report
Risks for particular oversight by the board and its
committees in 2020
The risks for particular oversight by the board and its committees in
2020 have been reviewed. In addition to the risks reviewed in 2019,
climate-related risks have been added as a longer-term strategic risk.
Climate-related risks
Risks associated with climate change and the transition to a lower carbon
economy impact many elements of our strategy and, as such, these risks are
considered through key business processes including the strategy, annual
plan, capital allocation and investment decisions. The outputs of these key
business processes are reviewed in line with the cadence of these activities.
Further details are described in Environment on page 40 and Climate
change and the transition to a lower carbon economy on page 70.
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,
consumer preferences for low carbon energy, 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.
See Prices and markets and Liquidity, financial capacity and financial,
including credit, exposure on page 70.
The impact of coronavirus (COVID-19)
The spread of coronavirus coupled with actions from OPEC+ has
caused a significant drop in the oil price. Our financial frame is
designed to be robust to periods of low price, with flexibility to
reduce cost and capital expenditure if required. We continue to
assess the potential impact of coronavirus on our staff and
operations and have instigated appropriate mitigation plans.
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
We have been assessing the potential impact on BP of Brexit
and the UK’s future global relationships and have considered
different outcomes but do not believe any of these outcomes
pose a significant risk to our business. The board’s geopolitical
committee continues to monitor these developments.
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 advisors 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
Cyber security
The targeted and indiscriminate threats to the security of our digital
infrastructure and those of third parties continue to evolve rapidly and
are increasingly prevalent across industries worldwide.
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.
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.
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.
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.
BP Annual Report and Form 20-F 2019
69
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 or alternative low carbon energy sources, technological change, global
economic conditions, public health situations 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.
Renewing our reserve base depends on our ability to continually replenish 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 reserve replacement. 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, acts of war and public health situations (including an outbreak of an
epidemic or pandemic) 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.
70
BP Annual Report and Form 20-F 2019
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, divestments may not be successfully
completed 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
financial liquidity and our credit ratings. Credit ratings downgrades 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 301 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 or failure of our or
third parties’ digital infrastructure or cyber security, 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 or third parties’ 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 fines, cost of remediation or reputational consequences.
Climate change and the transition to a lower carbon economy
– policy, legal, regulatory, technology and market developments related
to the issue of climate change could increase costs, reduce demand for
our products, reduce revenue and limit certain growth opportunities.
Laws, regulations, policies, obligations, social attitudes and customer preferences
relating to climate change and the transition to a lower carbon economy could
have an adverse impact on our business (including increased costs from
compliance, litigation, and regulatory or litigation outcomes), and could lead to
constraints on production and supply and access to new reserves and a decline in
demand for certain products.
Technological improvements or innovations that support the transition to a lower
carbon economy, and customer preferences or regulatory incentives that alter
fuel or power choices, could impact demand for oil and gas. Depending on the
nature and speed of any such changes and our response, this could adversely
affect the demand for our products, investor sentiment, our access to capital
markets, our competitiveness and financial performance. Policy, legal regulatory,
technological and market developments related to climate change could also
affect future price assumptions used in the assessment of recoverability of
asset carrying values including goodwill, the judgement as to whether there is
continued intent to develop exploration and appraisal intangible assets, the timing
of decommissioning of assets and the useful economic lives of assets used for
the calculation of depreciation and amortization. See Financial statements –
Note 1 and Environment on page 40.
Strategic report
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, new
technologies or customer offer that 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.
Security – hostile acts against our staff and activities could cause harm
to people and disrupt our operations.
Acts of terrorism, piracy, sabotage and similar activities directed against our
operations and facilities, pipelines, transportation or digital infrastructure could
cause harm to people and severely disrupt operations. Our activities could also be
severely affected by conflict, civil strife or political unrest.
Product quality – supplying customers with off-specification products
could damage our reputation, lead to regulatory action and legal liability,
and impact our financial performance.
Failure to meet product quality specifications could cause harm to people and the
environment, damage our reputation, result in regulatory action and legal liability,
and impact financial performance.
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, including
breach of digital security, could lead to loss of containment of hydrocarbons or other
hazardous materials. This could also lead to 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, including acquired businesses will be conducted in
conformance with these systems. See Safety and security on page 45.
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.
Compliance and control risks
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, and result in
litigation, regulatory action and penalties.
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.
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 Ben J. S. Mathews, company secretary on 18 March 2020.
BP Annual Report and Form 20-F 2019
71
Energy with purpose means
helping the world reach
net zero.
72
BP Annual Report and Form 20-F 2019
Corporate governance
Corporate governance
Board of directors
Executive team
The leadership team
Introduction from the chairman
Board activities in 2019
74
78
80
82
84
How the board has engaged with shareholders, 88
the workforce and other stakeholders
Nomination and governance committee
Audit committee
Safety, environment and security
assurance committee
Geopolitical committee
Chairman’s committee
Directors’ remuneration report
Remuneration committee
Directors’ statements
90
91
96
98
99
100
101
128
Energy with purpose
Expanding solar
Lightsource BP is helping shape the
future of global energy delivery by
developing solar capacity around
the world.
• We increased our stake in Lightsource
BP to create a 50:50 joint venture
in 2019.
Lightsource BP highlights in 2019
• Entered the Spanish solar market with
the purchase of a 300MW portfolio of
solar development projects across
six sites.
• Signed a long-term agreement to
build a 240MW facility, supplying
EVRAZ, a US steel company.
• Established a presence in Brazil with
the purchase of 1.9GW of solar
projects in various stages of
development.
BP Annual Report and Form 20-F 2019
73
Board of directors
as at 18 March 2020
Committee membership key
Chairman
Audit
Safety, environment
and security assurance
Remuneration
Geopolitical
Chairman’s
Nomination and governance
Non-executive directors’ tenure
Helge Lund
Chairman
Appointed to the board 26 July 2018 (appointed
chairman 1 January 2019)
Outside interests:
Chairman of Novo Nordisk AS, Operating Advisor to
Clayton Dubilier & Rice, Member of the Board of
Trustees of the International Crisis Group, Member
of the European Round Table of Industrialists
Age: 57
Nationality: Norwegian
Career summary:
Helge served as chief executive of BG Group from
2015 to 2016, when the company merged with Shell.
He joined BG Group from Equinor (formerly Statoil)
where he served as its president and chief executive
officer for 10 years from 2004. Prior to Equinor,
Helge was president and chief executive officer of
the industrial conglomerate, Aker Kvaerner, and has
also held executive positions in the Norwegian
industrial holding company, Aker RGI and the former
Norwegian power and industry company, Hafslund
Nycomed. He worked as a consultant with McKinsey
& Company and served as a political adviser for the
parliamentary group of the Conservative party in
Norway. 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
served as a member on the United Nations
Secretary-General’s Advisory Group on Sustainable
Energy from 2011 to 2014.
Relevant skills and experience:
Helge has an impressive track record of leadership
in the oil and gas industry. His open-minded and
forward-looking approach is 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.
1 – 3 years
4 – 6 years
7+ years
Board gender diversity
Female
Male
Board nationality
UK
US
Non UK/US
5
2
4
5
6
6
3
2
View the directors’ biographies
in full at bp.com/board.
74
BP Annual Report and Form 20-F 2019
Bernard Looney
Chief executive officer
Appointed 5 February 2020
Outside interests:
Fellow of the Royal Academy of Engineering, Fellow
of the Energy Institute, Mentor for FTSE 100
Cross-Company Mentoring Executive Programme
Age: 49
Nationality: Irish
Career summary:
Bernard Looney joined BP in 1991 as a drilling
engineer working in roles in the North Sea, Vietnam
and the Gulf of Mexico. Prior to becoming the chief
executive of BP Upstream in April 2016, Bernard held
a range of senior roles, including chief operating
officer of production, managing director BP North
Sea and vice president in Norway and North Sea
infrastructure and BP Alaska. He has led access into
new countries, including Mauritania and Senegal,
high-graded the portfolio with the acquisition of
onshore US assets from BHP Billiton and the sale of
the Alaska business, and created innovative new
business models, such as Aker BP in Norway.
As chief executive of BP Upstream, Bernard
oversaw improvements in both process and personal
safety performances and production grew by 20%.
There were also significant improvements in both
gender and global diversity. Bernard initiated a
group-wide dialogue on mental health in hope of
‘ending the stigma’ associated with the issue.
Relevant skills and experience:
Bernard has spent his career at BP and has
demonstrated dynamic leadership and vision as he
has progressed through various roles within the
Company. As part of the appointment process to
becoming the new chief executive officer, Bernard
exceeded at range of aptitude and psychometric
testing. During his 10 years as a leader of Upstream,
Bernard saw the segment through one of the most
difficult periods in the BP’s history, helping transform
the company into a safer, stronger and more resilient
business. He was instrumental in a number of
workforce based initiatives to promote a diverse and
inclusive environment.
Corporate governance
Dame Alison Carnwath
Pamela Daley
Independent non-executive director
Appointed 21 May 2018
Independent non-executive director
Appointed 26 July 2018
Outside interests:
Member of Supervisory Board of BASF SE, Director
of Zurich Insurance Group, Independent director of
PACCAR Inc, Member of UK Panel on Takeovers and
Mergers, Trustee of The Economist Group
Outside interests:
Director of BlackRock, Inc, Director of SecureWorks, Inc
Age: 67
Nationality: American
Age: 67
Nationality: British
Career summary:
Dame Alison is a qualified chartered accountant with
a wealth of financial industry experience obtained
during an expansive career in London and New York.
In addition to her current appointments, she was
previously Chairman of Land Securities Group plc
from September 2004 until July 2018 and served as
a non-executive director of Barclays PLC from 2010
to 2012 and Man Group plc from November 2012 to
May 2013. In 2014, Dame Alison 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.
Career summary:
Pam joined General Electric Company in 1989 as tax
counsel and held a number of senior executive roles
in the company, overseeing a wide range of
corporate transactions and serving as senior vice
president and senior advisor to the chairman in 2013,
before retiring from GE. Pam 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.
Relevant skills and experience:
Pam is a qualified lawyer with significant
management insight obtained from previous senior
positions held at companies that operate in highly
regulated industries. Pam has a wealth of experience
in global business and strategy gained from over 20
years in an executive role at GE. She also has
experience in the UK oil and gas industry from her
time served on the BG Group plc board. Pam
contributes important insight to the audit committee
from her previous executive experience. In 2019, she
joined the remuneration committee, where her
understanding of employee and investor
perspectives brings value.
Brian Gilvary
Chief financial officer
Appointed 1 January 2012
Brian will retire on 30 June 2020.
Outside interests:
Non-executive director of Air Liquide SA, Non-
executive director of Barclays PLC, Non-executive
director of Royal Navy Board, Senior independent
director of The Francis Crick Institute, Chairman of
The Hundred Group of Financial Directors (The 100
Group), Fellow of the Energy Institute; Great Britain
Age Group Triathlete
Age: 58
Nationality: British
Career summary:
Brian joined BP in 1986 after obtaining a PhD in
mathematics from the University of Manchester.
Following a broad range of roles across the group in
upstream, downstream and trading in Europe and the
US, he became downstream’s commercial director in
2002. From 2005 until 2009 he was chief executive
of BP’s commodity trading arm and, in 2010, he was
appointed deputy group chief financial officer. Brian
was a director of TNK-BP over two separate 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’s broad experience of working across the
group has provided him with deep insight into BP’s
assets and businesses. He has been key during
BP’s strategy implementation to transform into a
‘value over volume’ business where trading is a key
creator of value. 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. Brian played a major role in overseeing
financial aspects of the Gulf of Mexico oil spill,
and leading settlement negotiations to resolve
outstanding federal and state claims. He also
played a lead role in the negotiations around the
exit of TNK-BP and investment into Rosneft and led
the 2018 acquisition of the BHP onshore Lower
48 assets.
BP Annual Report and Form 20-F 2019
75
Sir Ian Davis
Senior independent director
Appointed 2 April 2010
Professor Dame Ann Dowling
Melody Meyer
Independent non-executive director
Appointed 3 February 2012
Independent non-executive director
Appointed 17 May 2017
Outside interests:
Chairman of Rolls-Royce Holdings plc, Non-executive
director of Majid Al Futtaim Holding LLC,
Non-executive director of Johnson & Johnson, Inc.
Age: 68
Nationality: British
Career summary:
Sir Ian began his career at The Bowater Corporation
Limited, a paper manufacturing company, before
joining McKinsey & Company in 1979. He was a
partner at McKinsey & Company for 31 years until his
retirement in 2010 and also served as chairman and
managing director between 2003 and 2009. Sir Ian
has remained as a senior partner emeritus of
McKinsey & Company since his retirement. He also
served as a lead non-executive board member for the
Cabinet Office from 2015 to 2016. Sir Ian was given
the honour of knighthood in the 2019 Birthday
Honours for services to business.
Relevant skills and experience:
Sir Ian 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.
Sir Ian’s previous experience as a non-executive
director for the Cabinet Office gives him an important
perspective on government affairs which is an asset
to both the board and the geopolitical committee.
Outside interests:
Deputy vice-chancellor and emeritus professor
of Mechanical Engineering at the University of
Cambridge, Non-executive director of Smiths
Group plc
Age: 67
Nationality: British
Career summary:
Professor Dame Ann is a deputy vice-chancellor and
emeritus professor of Mechanical Engineering at the
University of Cambridge where her research includes
fluid mechanics, acoustics and combustion. She has
held visiting posts at MIT and at Caltech. 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 was an advisor at
Rolls-Royce until 2015. Dame Ann was President of
the Royal Academy of Engineering from September
2014 to 2019. In December 2015 she 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,
research and academic leadership in these fields are
admired internationally. Her academic background
provides balance to the board and brings a different
perspective to the safety, environment and security
assurance committee, particularly as developments
in technology accelerate. Her work in this area is
supplemented by her chairing the company’s
technology advisory council.
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., Non-executive director of National
Oilwell Varco, Inc.
Age: 62
Nationality: American
Career summary:
Melody started her career in 1979 with Gulf Oil
which later merged with Chevron Corporation, where
she remained until her retirement in 2016. During her
career with Chevron, Melody held several key
leadership roles in global exploration and production,
working on a number of international projects and
operational assignments. 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. Melody has
received several awards and accolades throughout
her career including being recognized as a 2009
Trinity Distinguished Alumni, with the BioHouston
Women in Science Award and she was most recently
recognized by Hart Energy as an Influential Woman
in Energy in 2018.
Relevant skills and experience:
Melody 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.
76
BP Annual Report and Form 20-F 2019
Corporate governance
Brendan Nelson
Paula Rosput Reynolds
Sir John Sawers
Independent non-executive director
Appointed 8 November 2010
Independent non-executive director
Appointed 14 May 2015
Independent non-executive director
Appointed 14 May 2015
Outside interests:
Non-executive director of NatWest Markets plc,
Member of the Financial Reporting Review Panel
Outside interests:
Non-executive director of BAE Systems plc,
Non-executive director of General Electric Company
Age: 70
Nationality: British
Age: 63
Nationality: American
Career summary:
Brendan is a qualified chartered accountant and
former partner at KPMG having held a number of
senior positions at KPMG International. He served
on the KPMG UK board from 2000 until his
retirement in 2010. Brendan previously served as a
member of the Financial Services Practitioner Panel
for six years and was president of the Institute of
Chartered Accountants of Scotland in 2013/14. He
has extensive financial and banking experience
having been a non-executive director of The Royal
Bank of Scotland Group p.l.c. and National
Westminster Bank p.l.c. from 2010 until April 2019
and December 2018 respectively.
Relevant skills and experience:
Brendan 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 insight into the challenges faced by
global businesses by regulatory frameworks.
Career summary:
Paula commenced her energy career at Pacific Gas &
Electric Corp in 1979 and spent over 25 years in the
energy industry. She has held a number of executive
positions during her career, including CEO of Duke
Energy Power Services, Chairman, President and
CEO of AGL Resources as well as Chairman and CEO
of Safeco Corporation and Vice Chairman and Chief
Restructuring Officer of AIG. Paula was a non-
executive director of TransCanada Corporation and
CBRE Group, Inc until May 2019, having been
appointed in 2011 and 2016 respectively. Paula was
awarded the National Association of Corporate
Directors (US) Lifetime Achievement Award in 2014.
Relevant skills and experience:
Paula 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.
Outside interests:
Visiting professor at King’s College London, Governor
of the Ditchley Foundation, Trustee of the Bilderberg
Association, UK, Executive Chairman of Newbridge
Advisory Limited
Age: 64
Nationality: British
Career summary:
Sir John spent 36 years in public service in the UK,
working on foreign policy, international security and
intelligence. He was chief of the Secret Intelligence
Service, MI6, from 2009 to 2014 and prior to that
spent the bulk of his career in the Diplomatic Service,
representing the British government around the
world and leading negotiations at the UN, in the
European Union and in the G8. After he left public
service, Sir John was chairman and general partner
of Macro Advisory Partners, a firm that advises
clients on the intersection of policy, politics and
markets, from February 2015 to May 2019. He then
set up his own firm, Newbridge Advisory, to carry
out similar work. Sir John was appointed Knight
Grand Cross of the Order of St Michael and St
George in the 2015 New Year Honours for services
to national security.
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, environment and security assurance
committee.
Ben J S Mathews
Company secretary
Appointed 7 May 2019
Ben joined BP as a company secretary in May 2019. He is chairman of the
The Association of General Counsel and Company Secretaries of the FTSE
100 (GC100) and the co-chair of the Corporate Governance Council of the
Conference Board. Ben is also a Fellow of the Institute of Chartered
Secretaries and Administrators. Former appointments include Group
Company Secretary of HSBC Holdings plc and Rio Tinto plc.
BP Annual Report and Form 20-F 2019
77
Executive team
as at 18 March 2020
Gordon Birrell
Interim head of upstream
Appointed 12 February 2020
Gordon will continue as part of the new
leadership team.
Outside interests:
No external appointments
Age: 57 Nationality: British
Career summary:
Before being appointed to his new role, Gordon
was chief operating officer for production,
transformation and carbon. In a long BP career,
Gordon has spent time in various technical,
safety and operational risk (S&OR) and leadership
roles including four years as BP president
Azerbaijan, Georgia and Turkey.
Susan Dio
Tufan Erginbilgic
Chairman and president of BP America
Appointed 1 September 2018
Chief executive, Downstream
Appointed 1 October 2014
Susan will step down from her role on 30 June 2020
and retire from the company in the second half
of 2020.
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: 59 Nationality: American
Career summary:
Susan is chairman and president of BP America,
providing leadership and oversight to BP’s US
businesses.
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.
Tufan will retire from the company on 31 March 2020.
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: 60 Nationality: British and Turkish
Career summary:
Tufan 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.
David Eyton
Group head of technology
Appointed 1 September 2018
David will continue as part of the new leadership team.
Outside interests:
Fellow of the UK Royal Academy of Engineering,
Fellow of the Institute of Materials, Minerals &
Mining, Fellow of the Institute of Directors, Trustee
of the John Lyons Foundation, Member of Oil & Gas
Climate Initiative Climate Investments Board.
Age: 58 Nationality: British
Career summary:
As group head of technology, David 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 was recognized for his services to engineering
and energy in 2018 and awarded a CBE.
78
BP Annual Report and Form 20-F 2019
Bob Fryar
Andy Hopwood
Executive vice president, safety and
operational risk
Appointed 1 October 2010
Executive vice president, chief operating officer,
upstream strategy
Appointed 1 November 2010
Bob will retire from the company in the second half
of 2020.
Andy will retire from the company in the second half
of 2020.
Outside interests:
No external appointments
Outside interests:
No external appointments
Age: 56 Nationality: American
Age: 62 Nationality: British
Career summary:
Bob is responsible for safety, operational risk
management and the systematic management of
operations across the BP group. He is accountable
for a variety of group-level disciplines. In this capacity,
he looks after the group-wide operating management
system implementation and capability programmes.
Career summary:
Andy was appointed chief operating officer, upstream
strategy in April 2018. 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.
Bob has over 30 years’ experience in the oil and gas
industry, having joined Amoco Production Company
in 1985.
Following the BP-Amoco merger, Andy spent time
leading BP’s businesses across the world. He was
appointed executive vice president, exploration and
production in 2010.
Corporate governance
Lamar McKay
Chief transition officer
Appointed 16 June 2008
Eric Nitcher
Group general counsel
Appointed 1 January 2017
Lamar’s current portfolio will be redistributed on
1 July and he will continue in his capacity as chief
transition officer.
Outside interests:
No external appointments
Age: 61 Nationality: American
Career summary:
Lamar took on a new role as chief transition officer in
2019. He is responsible for supporting the chairman
and new group chief executive in achieving a full and
orderly transfer of leadership. In addition, he
continues to hold responsibility for leading BP’s
strategy work for the energy transition.
Lamar started his career in 1980 with Amoco and
has since held a number of senior roles including
most recently group deputy CEO.
Eric will continue as part of the new leadership team.
Outside interests:
No external appointments
Age: 57 Nationality: American
Career summary:
Eric is responsible for legal matters across the BP
group. He joined Amoco in 1990 and over the years
has held a wide variety of roles.
Eric moved to London in 2000, to join the mergers
and acquisitions legal team. He returned to Houston
in 2007 to serve 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
Appointed 1 January 2012
Dev will continue as part of the new leadership team.
Outside interests:
Independent non-executive director of Man Group plc;
Member of the International Advisory Board on Energy,
Government of India; Advisory Board of the Centre for
European Reform; Board of Advisors of The Fletcher
School of Law and Diplomacy, Tufts University; Fellow
of the Energy Institute.
Age: 54 Nationality: British and Indian
Career summary:
Dev is responsible for BP’s global alternative energy
business and for the group’s interests in the Europe
and Asia regions. He was appointed to the BP Group
executive committee in 2011.
Dev joined BP in 1989 and has held a variety of
international roles in London, Athens, Istanbul,
Vienna and Dubai. Dev was previously appointed
group treasurer in 2007 and was also chairman of BP
Investment Management. Until April 2016, Dev was
executive vice president, strategy and regions.
Dame Angela Strank
Helmut Schuster
BP chief scientist and head of technology,
downstream
Appointed 1 September 2018
Executive vice president, group human
resources director
Appointed 1 March 2011
Angela will retire from the company at the end of 2020.
Outside interests:
Non-executive director of Severn Trent plc, Fellow of
the Royal Society, Fellow of the Royal Academy of
Engineering.
Age: 67 Nationality: British
Career summary:
Dame Angela is responsible for technology across a
number of BP’s businesses. As BP’s chief scientist
she is accountable for developing strategic insights
from advances in science and managing technology
capability in BP.
She joined BP in 1982 as a geologist in exploration and
has held various leadership roles across the business.
She was recognized for her services to the oil industry
and women in science, technology, engineering and
mathematics in 2017 and awarded a DBE.
Helmut will step down from his current role on 1 July
and continue working with BP as an advisor.
Outside interests:
Non-executive director of Ivoclar Vivadent AG, Germany
Age: 59 Nationality: Austrian and British
Career summary:
Helmut became group human resources (HR)
director in March 2011. Since joining BP in 1989,
Helmut has held a number of leadership roles. He
has worked for 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
leading the people agenda for roughly 60,000 people
across the globe.
BP Annual Report and Form 20-F 2019
79
The leadership team
from 1 July 2020
Murray Auchincloss
Giulia Chierchia
Emma Delaney
Kerry Dryburgh
Executive vice president,
finance
Executive vice president,
strategy and sustainability
Executive vice president,
customers and products
Executive vice president,
people and culture
From 2015 until being announced to
his new position, Murray was chief
financial officer for BP Upstream. He
has held other senior roles in the
segment and spent three years as
head of the group chief executive’s
office. He spent his early career in
North America and qualified as a
Chartered Financial Analyst.
Giulia joins BP from McKinsey, where
she was a senior partner. She led the
global downstream oil and gas practice
and was a key member of the
chemicals and electricity, power and
natural gas practices. She begins this
role with more than 10 years’
experience in the energy sector,
including helping companies shape
their strategies for the energy
transition.
Emma has spent 25 years working in
BP, both in the Upstream and the
Downstream, most recently as regional
president, West Africa. Prior to this
role she held a variety of senior roles:
CFO (chief financial officer) for Asia
Pacific, head of business development
for Upstream gas value chains and
commercial director for Iraq. She
was the vice president for integrated
social and economic programmes in
Indonesia. In Downstream she held a
number of roles in marketing and
planning.
Kerry was previously head of HR for
the Upstream and has held a series of
senior HR positions. She was a key
driver behind the Upstream people
transformation during 2015-2017. Kerry
previously ran HR in BP’s shipping,
integrated supply and trading (IST)
and corporate functions teams. She
brings experience from other sectors
in Europe and Asia, having worked at
both BT and Honeywell before joining
BP. She currently sits as a non-
executive director for the United
Kingdom Strategic Command.
Carol Howle
William Lin
Geoff Morell
Executive vice president,
trading and shipping
Executive vice president,
regions, cities and solutions
Executive vice president,
communications and advocacy
Before taking on her current role, Carol
ran BP shipping and was the chief
operating officer for IST oil. She has
more than 20 years’ experience in the
energy industry, many in IST. Previous
roles, include chief operating officer
for natural gas liquids, regional leader
of global oil Europe and finance. Carol
also served as the head of the group
chief executive’s office.
William served as chief operating
officer, upstream regions before joining
the leadership team. Previous senior
roles include vice president – gas
development and operations for Egypt,
regional president for Asia Pacific and
head of the group chief executive’s
office. William managed the
successful start-up of the Tangguh
LNG facility during his time in
Indonesia. He is a non-executive
director for Pan American
Energy Group that operates in
Argentina.
Geoff has run group communications
and external affairs (C&EA) since 2017,
after six years leading BP America’s
communications and government
relations teams. He was instrumental
in rebuilding BP’s reputation in the
years following Deepwater Horizon.
Prior to BP, Geoff spent four years at
the Pentagon, serving as the chief
spokesperson for the military under
presidents Bush and Obama. He
previously worked in television,
including as White House
correspondent for ABC News.
Biographies for the
other members of the
leadership team
Bernard Looney, chief executive
officer, page 74.
Gordon Birrell, executive
vice-president, production and
operations, page 78.
David Eyton, executive vice
president, innovation and
engineering, page 78.
Eric Nitcher, executive vice
president, legal, page 79.
Dev Sanyal, executive vice
president, gas and low carbon
energy, page 79.
80
BP Annual Report and Form 20-F 2019
Introduction from the chairman
Corporate governance
“
Our new purpose is the result of
a period of careful development
and wide debate with the
management team and also
reflects the valuable feedback
we have received from a
number of our stakeholders,
both inside and outside of BP.”
Helge Lund
Chairman
It has been a privilege to lead BP’s board for the past year,
especially given the important decisions we have taken
together. BP now begins the new decade with a new direction.
Our new purpose, to reimagine energy for people and our
planet, is supported by a new ambition - for BP to get to net
zero by 2050 or sooner, and to help the world get to net zero
too. And we have appointed a new chief executive officer,
Bernard Looney, who under the board’s oversight, will lead
BP in achieving both its purpose and its ambition.
BP’s board has been deeply involved in each of these
changes. It is the board’s responsibility to define and set
the company’s purpose, its values and its strategy, and to
be assured that these are aligned with BP’s culture. Our
strategy and evolving portfolio have been discussed with
the management team at every board meeting in 2019. Our
new purpose is the result of a period of careful development
and wide debate with the management team and also reflects
the valuable feedback we have received from a number of
our stakeholders, both inside and outside of BP.
BP’s new leadership
During the year, the board, through its nomination and
governance committee, took equal care in its executive
succession planning, including in our appointment of a
successor to Bob Dudley. When we began that planning in
earnest in autumn 2018, we knew that Bob’s many
achievements in the role set a high bar for his eventual
successor. That was reflected in the time we took to define
the qualities we were looking for in the new leadership of BP
at a time of considerable change. A year on, we were delighted
to welcome Bernard Looney to the role. He is both capable,
performance oriented and deeply aware of the importance that
we attach to working in close dialogue with BPs stakeholders.
New ways of working
The board itself is an important component of BP’s leadership.
The most effective boards – and the most effective board
meetings – are inclusive, collaborative, open and transparent.
During 2019, I was pleased with the support I received from
my colleagues on the board as we fostered an atmosphere
with the management team in which those standards are
clearly exhibited.
These improvements have gone in-hand with improvements
to the board’s efficiency and productivity. We have strengthened
how we manage the board’s meeting agenda, the materials
developed for the board and the division of labour between the
committees and the board. I believe that these changes have
enabled us to effectively manage both the leadership succession
and develop our new purpose and ambition.
Evolving board composition
The make-up of the board has also evolved, and I expect that
to continue in future as we seek to ensure we have the right
balance of skills, experience and diversity. In November last
year, Nils Andersen was appointed Chairman of Unilever, and
therefore stepped down from BP’s board on 18 March after a
period of transition. On behalf of the board, I thank Nils for his
service to BP. In Nils’ place, Melody Meyer agreed to chair the
safety, environment and security assurance committee (SESAC),
recognizing her strong operational and safety experience.
Separately, the board has assumed direct oversight of ethics
and compliance matters, previously the responsibility of SESAC.
One of the chairman’s responsibilities is to ensure cohesion
of the board over time, especially during times of transition.
To provide continuity, Sir Ian Davis and Brendan Nelson have
kindly agreed to stand for re-election at the 2020 AGM for up to
a further year. Because they have now each exceeded nine years
BP Annual Report and Form 20-F 2019
81
in the role, in putting them forward for re-election this year the board
carefully considered whether, they still demonstrate the necessary
qualities of independence. I am pleased to confirm that the board is
satisfied that they do, and I am grateful for the support and wisdom that
Sir Ian and Brendan bring to the board. Our nomination and governance
committee has, as you would expect, begun a process to identify
successors to these important roles.
While continuity is important, BP’s new direction gives reason
to examine whether the board’s composition is optimally aligned to
BP’s new direction. We’ll always need a core cadre of members with
global executive experience from similar industries, but different
specialist skills may also be valuable. These include skills relevant to
BP’s ambition, individuals with strong digital and transformational skills
and those with broader energy and sustainability experience.
In light of the changes ahead of us, but also as a consequence of natural
succession, I anticipate that we will add new competences and
experiences to the board during 2020.
Evolving remuneration structure
The year 2019 also marked a transition for executive remuneration. In
order to develop a new remuneration policy, which will be proposed at
the 2020 AGM, the remuneration committee sought candid feedback
from some of our largest shareholders. Consequently, while we will
retain our current structure, which is simple and well understood, we
will strengthen the elements relating to our energy transition ambition.
More details of our new policy are set out in the Directors’ remuneration
report on page 100.
Our stakeholders
This year also marks the first year in which the board is required to
report on how it has fulfilled its duties under section 172 of the
Companies Act, which requires directors to promote the success of the
company for the benefit of its members, and in doing so to have regard
to our stakeholders, including employees, suppliers and customers, the
impact of our operations on communities and the environment, and the
likely consequences of any decision in the long term.
Regard for a wider group of stakeholders is not new. Indeed, it has been
incorporated into the board’s working for some time. But new reporting
requirements are an opportunity to explain the processes we have
followed, and how dialogue with stakeholders has shaped decisions.
Details can be found on page 66, and information about how the board
has engaged with BP’s workforce is on page 88.
Closing thanks
Finally, I want to express my gratitude to Bob Dudley, Bernard Looney,
the executive team, our employees and my board colleagues for their
hard work, their commitment, and their contribution to BP’s new direction.
I look forward to working with our teams to compete effectively in a
changing energy market.
Helge Lund
Chairman
82
BP Annual Report and Form 20-F 2019
Corporate governance
Governance framework
Shareholders
BP board
Audit committee
HPGR* monitored
• Financial liquidity.
• Cyber security.
• Compliance
with business
regulations.
• Trading
compliance
and control.
Responsibilities
• Reviewing
financial
disclosures.
• Monitoring
compliance.
• Reviewing audit
effectiveness,
including internal
controls and risk
management.
• Advice on external
auditor.
See page 91.
Safety,
environment and
security assurance
committee
HPGR monitored
• Monitor marine,
well and pipeline
incidents.
• Oversee effective
controls around
releases at
facilities and/or
explosion.
• Review and advise
on major security
incident.
• Cyber security.
Responsibilities
• Review safety and
operational risk.
• Monitor security
developments.
• Review
environmental
matters.
See page 96.
n
o
i
t
a
g
e
e
D
l
Geopolitical
committee
HPGR monitored
• Geopolitical.
Responsibilities
• Monitor social,
economic and
political events
around the world.
• Identify major and
correlated
geopolitical risks.
• Consider broader
political policy
developments.
Remuneration
committee
Responsibilities
• Recommend
remuneration
principles and
policy.
• Maintain dialogue
with shareholders
and workforce
on remuneration
issues.
• Monitor alignment
of remuneration
and incentives
for all employees.
See page 98.
• Report on
Nomination and
governance
committee
Responsibilities
• Review
composition
of board.
• Review outside
commitments
of the NEDs.
• Maintain strong
pipeline.
• Review
developments in
corporate
governance,
law and ESG.
Chairman’s
committee
Responsibilities
• Evaluate
performance and
effectiveness
of chief executive
officer.
• Review the
structure and
effectiveness
of the business
organization.
• Review system
of executive
development
and succession.
implementation
of remuneration
policy.
See page 101.
See page 90.
See page 99.
A
c
c
o
u
n
t
a
b
i
l
i
t
y
Chief executive officer
Executive committee
Group
operations risk
committee
Group
financial risk
committee
Group
disclosure
committee
Group people
committee
Group
ethics and
compliance
committee
Resource
commitment
meeting
Technical
advisory
council
Framework changes in 2020
As part of the governance framework review, the board
committees and their responsibilities will be reviewed.
* HPGR – highest priority group risks.
BP Annual Report and Form 20-F 2019
83
Board activities in 2019
Role of the board
Strategy
The board is responsible for the overall
conduct of the group’s business. Directors
have duties under the both UK company law
and BP’s Articles of Association. The primary
tasks of the board in 2019 included:
• Active consideration and establishment of
long-term strategy and approval of the
annual plan.
• Monitoring of BP’s performance against
the strategy and plan including ethics and
compliance.
• Ensuring that the principal and emerging
risks and uncertainties to BP are identified
and that systems of risk management and
control are in place.
• Board and executive management
succession.
“
The board is responsible
for establishing the
company’s purpose, its
values and strategy, and
satisfying itself that these
and its culture are aligned.”
Helge Lund
Chairman
During 2019 the board considered the BP strategy at
every board meeting and held a two-day strategy
discussion in September. The board also received a
number of technical briefings to expand the directors’
knowledge in particular areas, such as Scope 3
emissions, the BP Energy Outlook and
environmental, social and corporate governance
(ESG) matters, to best equip the board to consider
and debate strategic themes relating to BP’s
segments, key functions and the impact of the lower
carbon transition on the group’s business model.
This included looking at long-term energy trends and
projections for world energy markets.
The board monitored the company’s performance
against the annual plan for 2019 and approved the
annual plan for 2020 after taking into account
management’s revised assumptions and outlook for
the year. They received regular reports on the
progress and implementation of the strategy from
the group chief executive (GCE) and chief financial
officer (CFO) by means of a strategic performance
scorecard, which is discussed at each board
meeting.
The board undertook portfolio reviews of various
parts of the BP group, including upstream,
downstream and renewables. It assessed the
potential impact changes to the portfolio might have
on the financial framework and discussed allocation
of capital. The board looked at circular and
sustainable solutions and business development
opportunities in a low carbon future, through the lens
of what was in the best interest of long-term success
of the company.
In a year that saw BP face significant transition, both
internally with the announcement of Bob Dudley’s
retirement and more widely as the company looks
to play an important role in the world’s energy
transition, the board discussed BP’s purpose and
ambitions and their alignment with strategy and the
BP culture.
Performance and monitoring
The board reviews financial, operational and safety
performance throughout the year, as well as the
latest view on expected full-year delivery against
external scorecard measures. During the year there
were a number of business and regional reviews,
including North Sea, Russia, the lubricants business
and BPX Energy.
Updates are also given on various components of
value delivery for BP’s business. Regular reports
presented to the board include:
• Chief executive’s report.
• Group performance report.
• Group financial outlook.
• Effectiveness of investment review.
• Quarterly and full-year results.
• Shareholder distributions.
In 2019 the board re-assumed primary responsibility
for ethics and compliance (E&C), having previously
managed oversight jointly through the SESAC and
the audit committee. The group head of E&C
attended the board meeting four times in 2019,
providing an update on E&C matters, and how the
importance of such was embedded within the BP
culture throughout the business. The board was also
provided ethics and compliance training. The NEDs
held private sessions with the head of E&C.
The board reviews the quarterly and full-year results,
including shareholder and capital distributions. The
2019 annual report was assessed in terms of the
directors’ obligations and reflects the briefings on
updated corporate governance requirements and
best practice.
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.
Feedback from other stakeholders is also considered
by the board as part of its monitoring of performance,
as outlined in the BP Section 172 statement and on
pages 88-89.
84
BP Annual Report and Form 20-F 2019
Risk
Succession
The board, either directly or through its committees,
regularly reviews the processes whereby principal and
emerging risks are identified, evaluated and managed.
Each of the highest priority group risks were
reviewed in 2019. The board has a focus on emerging
risks and how these are being managed and
mitigated. The board undertook its annual review of
cyber security risk in particular in December 2019.
Each year the board assesses the effectiveness of
the group’s system of internal control and risk
management as part of the review and sign off of the
BP Annual Report and Form 20-F, to satisfy itself that
the report, taken as a whole, is fair, balanced and
understandable, and provides the information
necessary for shareholders to assess the company’s
position, performance, business model and strategy.
Further information on BP’s system of risk
management is outlined in How we manage risk on
page 68. Information about BP’s system of internal
control is on page 128.
The board, in conjunction with the nomination and
governance and chairman’s committees, reviews
succession plans for executive and non-executive
directors and senior executives on a regular basis.
The board ensures that potential candidates are
identified and evaluated against objective criteria and
on merit, with due regards to the benefits of diversity
of thought, gender, social and ethnic backgrounds
and cognitive and personal strengths, through a
formal and rigorous procedure. BP operated board
and senior executive succession planning across
three horizons.
1. Contingency planning is constantly at the forefront
as mitigation against key person risk in cases of
sudden and unforeseen departures.
2. Medium-term planning relates to the orderly
replacement of board and committee members and
senior executives as they retire or change roles.
3. Finally, long-term planning seeks to equip BP with
the skills required now and in the future as we
implement the long-term strategy.
The board employs executive search firms when it
concludes that this is an effective way of finding
suitable candidates. Bernard Looney’s appointment
as chief executive officer (CEO) resulted from a
review of both internal and external candidates. The
nomination and governance committee engaged with
external headhunters to source external candidates
for this purpose of the CEO succession and in
support of the overall process.
• Pamela Daley was appointed to the remuneration
committee on 30 January 2019.
• Nils Andersen was appointed to the nomination
and governance and remuneration committees
upon becoming the chair of the safety,
environment and security assurance committee on
8 April 2019. Subsequently Nils stepped down as
chair of the safety, environment and security
assurance committee on 13 November 2019
following the announcement of his appointment as
chairman of Unilever. He was succeeded by
Melody Meyer as chair of the SESAC on the same
day. He resigned from the board and all other
committees on 18 March 2020.
• Alan Boeckmann and Admiral Frank Bowman
stood down as directors and from all committees
following the AGM on 21 May 2019.
• Bob Dudley retired as group chief executive and a
director on 4 February 2020. Bernard Looney
succeeded him as chief executive officer on 5
February 2020.
• Brian Gilvary announced his retirement in January
2020. He will be succeeded by Murray
Auchincloss on 1 July 2020.
Corporate governance
Looking forward, the board is implementing
changes to its ways of working and redefining
its primary responsibilities. As outlined on
page 66, from 2020, board agendas will be
structured along the following four distinct
pillars – strategy, performance, people and
governance. Within those areas the key areas
of focus will be:
Strategy: the board will consider and help
establish the strategy of BP alongside the
new CEO and leadership team to achieve
the purpose, ambition and aims set out on
12 February 2020, see page 6. In doing so,
the board will ensure that every member of
the board has a deep understanding of the
board’s role in determining BP’s capital
allocation process and enabling effective
decision making.
Performance: the board will continue to
perform an important monitoring role, making
sure the CEO and the leadership team are held
to account against the 2020 Annual Plan to
satisfy itself that BP is performing while
transforming.
People: the board will focus on reviewing
the composition, skills, experience and
diversity of the board and executive
management, as well as the process for
executive succession planning talent
management and development. It will ensure
that workforce policies and practices are
consistent with the company’s values and the
manner in which BP invests and rewards its
workforce is designed and implemented in a
way that supports the company’s long-term
sustainable success.
Governance: as outlined on page 83,the
board is developing a new corporate
governance framework. This framework will
reinforce the effectiveness of the internal
control framework and be more closely aligned
with BP’s new purpose and ambition.
BP Annual Report and Form 20-F 2019
85
Board and committee attendance
Non-executive director
Helge Lund
Nils Andersen*
Alan Boeckmann
Admiral Frank Bowman
Dame Alison Carnwath
Pamela Daley
Sir Ian Davis
Professor Dame Ann Dowling
Melody Meyer
Brendan Nelson
Paula Rosput Reynolds
Sir John Sawers
Executive directors
Bob Dudley*
Brian Gilvary
Board
9 (9)
8 (9)
3 (3)
3 (3)
9 (9)
9 (9)
9 (9)
9 (9)
9 (9)
9 (9)
9 (9)
9 (9)
9 (9)
9 (9)
Audit
committee
8 (8)
7 (8)
8 (8)
8 (8)
SESAC
6 (6)
2 (2)
2 (2)
6 (6)
6 (6)
6 (6)
Remuneration
committee
Geopolitical
committee
Nomination and
governance
committee
4 (6)
3 (3)
8 (8)
8 (9)
9 (9)
9 (9)
3 (4)
2 (2)
4 (4)
4 (4)
4 (4)
6 (6)
2 (2)
6 (6)
6 (6)
6 (6)
6 (6)
Chairman’s
committee
7 (7)
6 (7)
2 (2)
2 (2)
7 (7)
6 (7)
7 (7)
6 (7)
7 (7)
7 (7)
7 (7)
7 (7)
Chairman of board/committee
* Bob Dudley stepped down from the board 4 February; Nils Andersen stepped down from the board 18 March 2020
Background
Non-executive director
Background and experience
Energy markets
Operational
excellence and risk
management
Global business
leadership and
governance
People leadership
and organizational
transformation
Technology, digital
and innovation
Society, politics
and geopolitics
Finance, risk,
trading, etc
Dame Alison Carnwath
Pamela Daley
Sir Ian Davis
Professor Dame Ann Dowling
Helge Lund
Melody Meyer
Brendan Nelson
Paula Rosput Reynolds
Sir John Sawers
Diversity
BP believes diversity and inclusion is vital to our values, the group strategy and
the success of the company. We understand that better decisions and outcomes
are achieved when we have different people, with differences of opinions from
different backgrounds.
We recognize the importance of diversity, whether that be gender, social or
ethnic backgrounds, personal identities, age, religion, physical abilities and more.
These all promote diversity of thought and reduce the risk of groupthink. This
approach is followed by the board, senior executives and their direct reports and
throughout the BP group.
We are committed to attracting the best talent to BP and feel an inclusive and
respectful work environment, where people are valued as individuals, is key.
When reviewing the composition of the board, the nomination and governance
committee reviews not only the skills and experience of existing board members,
but also their background and diversity. Equally, when seeking to identify
candidates to join the board, the committee gives consideration to merits of
diversity, including gender, in helping to bring greater balance to the board’s
discussion and debates on strategy and associated matters.
Diversity is considered as an integral part of succession planning. Executive gender
and ethnicity were taken into consideration as part of the board’s wider executive
succession review in 2019, while diversity of thought, deriving from a robust
combination of gender, social or ethnic backgrounds, was a prominent factor in the
selection process, ensuring that BP has a diverse executive pipeline.
86
BP Annual Report and Form 20-F 2019
At the end of 2019 the board comprised five female directors (2018 5, 2017 3)
representing 42% of a 12-person board (46% of an 11 person board at the time
of publication). Our senior management, as defined by the Corporate Governance
Code 2018, and their direct reports comprise 38% female and 18% black, Asian
and minority ethnic (BAME) individuals. For details of BP workforce diversity and
inclusion, see Our people on page 47. The board looked at 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 BP 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 other company’s boards or who hold other external appointments.
Directors are required to provide the board with sufficient information to evaluate
their independence and the board keeps the other interests of the NEDs under
review and regularly reviews the conflicts of interest register.
Sir Ian Davis and Brendan Nelson are proposed for re-election notwithstanding
that they have both served beyond nine years as non-executive directors.
Following careful consideration, the board believes that both Sir Ian and Brendan
continue to provide constructive challenge and robust scrutiny of matters that
come before the board and the committees on which they serve. Neither director
has served simultaneously with an executive director for over nine years and the
overall average tenure of the board is similar to that of the average FTSE 100
directors’ tenure. In 2018 the board undertook significant refreshment of its
composition with a number of new non-executives and a new chairman. Since
assuming the chairmanship of the board at the beginning of the year, Helge Lund
has led the process to identify and, in October 2019, to announce the
appointment of a new group CEO. This was supplemented by a process to
identify and, in January 2020, announce the appointment of a new group CFO.
Sir Ian and Brendan will play crucial roles in the transition period as these new
appointments come into effect, so that BP’s culture and values are not adversely
impacted and that the integrity of its financial reporting is maintained. After
careful consideration, the board is satisfied that Sir Ian and Brendan continue
to demonstrate the qualities of independence in carrying out their duties.
Appointment and time commitment
The chairman and NEDs each 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 in line with best governance practice.
The chairman’s letter of appointment sets out the time commitment expected of
him. The NEDs’ letters of appointment do not set out a fixed time commitment.
The time required of directors fluctuates depending on the demands of BP
business and other events. They are expected to allocate appropriate 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 normally permitted to take up one board appointment at
an external listed company, subject to the agreement of the chairman and after
consultation with the company secretary. In February 2020, Brian Gilvary was
appointed as a non-executive director of Barclays PLC. An announcement in
respect of Brian’s plans to retire as CFO of BP was made in January 2020. He will
stay in the role until June 2020 to work with his successor, Murray Auchincloss,
in order to ensure an orderly transition. Given these circumstances and after
consideration by the chairman and company secretary, it was concluded that
Brian’s role at Barclays PLC was unlikely to be detrimental to his duties as
outgoing CFO. Fees received for an external appointment may be retained by the
executive director and are reported in the Directors’ remuneration report (see
page 100). Neither the chairman nor the senior independent director are
employed as an executive of the group.
The board also considers all NED external appointments and considers the impact
those requiring significant commitment might have on the director’s ability to
dedicate sufficient capacity in times of increased demand. In November 2019,
the board acknowledged the appointment of Nils Andersen as Chairman of
Unilever NV/PLC and accepted his resignation from the BP board. Nils remained
as a non-executive director until March 2020 to support Melody Meyer who took
over as chair of the SESAC in November 2019.
Corporate governance
Learning, development and inductions
The board held a number of developmental briefing sessions during the year, in which
field experts with a range of academic and practical knowledge were invited to provide
bespoke training sessions, updating them on latest intelligence in their particular area.
This develops and optimizes the skill set within the board on evolving technical topics
and aids conversation around strategic planning.
The board continued to build its knowledge of the BP business through briefings
and site visits as part of its learning programme, see examples on page 89.
No new directors were appointed during 2019. In October 2019, BP announced that
Bob Dudley would be retiring in 2020, succeeded by Bernard Looney. Bernard’s
functional and operational knowledge of BP meant that an in-depth induction
programme was not necessary. Nonetheless, Bernard attended a number of town
halls with Helge Lund in 2019 to engage with BP people.
Board evaluation
Each year, BP completes a review of the board, its committees and of the
individual directors. It is generally recommended that such reviews are externally
led once every three years. Having undertaken an externally facilitated review in
2018, the 2019 evaluation was facilitated by the incoming company secretary.
The process involved interviews with each member of the board based around a
number of themes, including strategy formulation and portfolio development, the
role of the new chairman and boardroom dynamics, the evolution of BP’s purpose
and wider stakeholder engagement and the processes in place for managing
succession across the organization. Positive feedback was received on the new
chairman’s style and the benefits his inclusive leadership approach had brought to
the board during the year. The outputs of this review highlighted three areas of
future focus and attention:
• Reviewing the composition, skills, experience and diversity of the board and
the process for executive succession planning talent management and
development.
• Ensuring every member of the board has a deep understanding of the board’s
role in determining BP’s capital allocation process and enabling effective
decision making.
• Re-shaping the BP corporate governance framework and how this it should
reinforce the effectiveness of the internal control framework and be more
closely aligned with BP’s new purpose and ambition.
A new corporate governance framework is in development, supported by the
outputs from this year’s board review process, with the aim of ensuring that this
new framework is in place by the time that the new organizational structure and
reporting arrangements take effect.
UK Corporate Governance Code compliance
BP complied throughout 2019 with the principles and provisions of the 2018 UK
Corporate Governance Code except in the following aspects:
Provision 33
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.
Provision 38
The pension arrangements for Bob Dudley and Brian Gilvary reflect the historical
retirement benefits available to employees that joined BP at similar times. We
recognize that the contribution rates under these arrangements are higher than
the majority of the current workforce and as such the pension contributions for
the new executive directors, Bernard Looney and Murray Auchincloss, have been
aligned with those available to the majority of the workforce.
A copy of the 2018 UK Corporate Governance Code is available at frc.org.uk.
BP Annual Report and Form 20-F 2019
87
How the board has engaged with shareholders,
the workforce and other stakeholders
Shareholders
Institutional investors
The company engages with its institutional shareholders through its
active investor relations programme. The board receives feedback on
shareholder views in many ways, particularly through the chairman and
senior management who meet regularly with shareholders throughout
the year, as well as through the results of an independent investor study
and report.
In September 2019 the chair of the remuneration committee hosted an
event for large investors on considerations for the new remuneration
policy which is to be tabled at the 2020 AGM in May (see Remuneration
committee report on page 101). The chairman also held one-to-one
meetings with major institutional investors during the year, collecting
their views and sharing these with the other board members and the
remuneration committee.
During the course of the year, senior management met regularly with
institutional investors through road shows, group and one-to-one
meetings, events for socially responsible investors (SRIs), meetings
with various investors to discuss environment, social and governance
matters, and oil and gas sector conferences.
In May 2019, the chairman and board committee chairs held their
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 non-executive directors.
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 2019
Q1 • Fourth quarter and full year 2018 results and strategy update
• Investor roadshows with executive management – fourth
quarter and full year 2018 results
• BP Energy Outlook presentation
• BP Annual Report 2018 launch
• BP Sustainability Report 2018 launch
Q2 • Chairman and board committee chairs meeting with investors
• UKSA (retail shareholders’) meeting with the chairman
• First quarter 2019 results presentation
• Annual general meeting
• BP Statistical Review of World Energy launch
Q3 • Second quarter 2019 results presentation
• Investor roadshows with executive management following
2Q results
Q4 • Third quarter 2019 results presentation
• Investor roadshows with executive management following
3Q results
Retail investors
BP held an event for retail investors in conjunction with the UK
Shareholders’ Association (UKSA) in 2019. The chairman and a
representative from 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 were relatively consistent at 67.1% (of issued share capital,
including votes cast as withheld) in 2019, compared to 67.3% in 2018.
The lower voting level of 50.8% in 2017 was due to the negative impact
of stock lending.
In 2019 the AGM was held in Aberdeen for the first time, which enabled
the board to engage with shareholders who might not have had the
opportunity to attend a meeting before. There were two shareholder
requisitioned resolutions put to the meeting in 2019.
All resolutions supported by the board, including the shareholder
resolution from the Climate Action 100+ group, passed at the meeting,
see page 6. The shareholder resolution from Follow This, which was not
supported by the board, did not pass.
Each year the board receives a report after the AGM giving a breakdown
of the votes and investor feedback on its voting decisions to inform it on
any issues arising.
Workforce
At BP we believe a diverse and engaged workforce is critical to us
successfully delivering our group strategy. BP strives to create an open
culture where dialogue between the board, senior management and
the workforce, which includes a wide range of employees, contractors,
agency and remote workers across all of its geographical locations, is
encouraged and expected. ‘Respect’ and ‘courage’ are two of our
corporate values that underpin this and are embedded in our
performance management system. Employees are informed of
information on matters of concern to them as employees through BP’s
intranet and local sites, social media channels, town halls, site visits
and webinars including topics such as quarterly results, strategy, the
low carbon transition and diversity. We have a number of employee-led
forums and business resource groups and aim to build constructive
relationships with labour unions formally representing some employees.
Employees are consulted on a regular basis through regular team and
one-to-one meetings and through our annual ‘Pulse’ survey. These
initiatives are applied where practicable.
Our annual employee ‘Pulse’ survey results for overall engagement,
long-term cultural metrics and listening and involvement have shown
a steady and sustained improvement over this period, see page 47.
With such a diverse and globally distributed workforce, we believe
ongoing dialogue through multiple channels is the best way for the
board and management to engage with our people and listen to what
they have to say. The board is firmly of the opinion that face-to-face
interaction with our people is the best way to get direct feedback and
an understanding of the important issues of the workforce, as well as
deepen the board’s operational understanding. Only by visiting and
meeting with employees from all aspects of the business can the board
fully assess the culture and tone of BP. The board held a number of site
visits in 2019 to a number of different locations, including Busan, Kuala
Lumpur, Singapore, Aberdeen and Denver. A number of non-executive
directors also took opportunities to engage directly with local workforce
at various BP offices around the globe. As part of Helge Lund’s first
year as chairman, he conducted town hall meetings with the workforce
in Washington DC, Baku, Rotterdam, Beijing, Houston and London.
The board and its committees are committed to meeting with a
wide range of employees across the entire workforce and at times
exclude senior management from meetings to get the unfettered
opinions of their teams. An example of this was the SESAC’s visit
to a new LNG vessel off the coast of South Korea immediately prior
to its maiden voyage. This was the first shipping visit of its kind,
during which members of the SESAC held private informal meetings
with the ship’s crew, away from senior officers. The crew highlighted
a couple of potential improvements, the SESAC members agreed
and, as a consequence, certain improvements were undertaken by
shipping leadership.
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BP Annual Report and Form 20-F 2019
Corporate governance
As an example of how engagement has directly contributed to shaping
policy, in 2019 we launched a new global commitment to minimum
parental leave for new parents. This policy was established through
engagement with our employee-led business resource groups and
employee forums, including the working parents’ forum.
BP invests in its workforce through a number of employee share
ownership schemes and plans. For example, we operate ‘ShareMatch’
in more than 50 countries. The plan matches BP shares purchased by
our employees. We also operate a group-wide discretionary share plan,
which rewards employees with participation in BP’s equity at different
levels globally and is linked to BP performance.
As we look to achieve our purpose, ambition and aims – engagement
with our global talent pool is as critical as ever. BP wants to recruit,
retain and reward people from wide-ranging and diverse backgrounds
who can support us in the global transition to a low carbon energy
system. We will continue to expand our existing networks of
communication to foster a listening culture that enables the board and
management to gain meaningful insight directly from our colleagues
around the world, and respond accordingly. For instance, following
feedback from BP’s working parents’ forum, agile working and parental
leave policies have been improved, and in response to growing demand
from our workforce, BP introduced a way for some employees to offset
their personal carbon emissions and is working towards expanding this
scheme to more employees across the group. The board will dedicate
time to specifically review the outputs from the various channels of
workforce engagement at board sessions.
The board believes the existing approaches and mechanisms described
above enable comprehensive two-way engagement opportunities
with BP’s workforce, and as such, is satisfied that these are effective
alternatives to the proposed workforce engagement methods set out
in Provision 5 of the Code. Given the current period of transition within
BP, the board will continue to review its engagement mechanisms to
seek new ways to strengthen existing workforce forums to ensure a
continuing robust relationship and collaboration.
Other stakeholders
For details of how the board complied with Section 172 of the
Companies Act 2006 and how it further engaged with other
stakeholders, see page 66.
300
employees attended
the town hall presented
by Helge Lund and
Bob Dudley.
Site visits
Denver
The board visited BP’s Denver office in
September 2019 where they hosted
several employee events. A town hall
took place, led by Helge Lund, with the
rest of the board present to talk with
the workforce and answer questions
over a community lunch with over 150
employees in attendance. The board was
also introduced to emerging talent in the
region and met with senior leadership.
As part of the suite of events the board
also met with external stakeholders
at a business reception in the city.
150
employees attended a community
lunch with the board.
Aberdeen
Following the AGM in Aberdeen, the
board held a number of engagement
activities. Helge Lund and Bob
Dudley led a town hall which was
attended by over 300 employees at
BP’s Dyce office and streamed live to
the offshore teams in the North Sea.
The board hosted a business
reception, inviting members of the
local community, local political and
government officials, employees and
local businesses.
Members of the board had further
engagement with the workforce at the
Dyce office, observing new agile ways
of working and gaining technological
insight into new initiatives. Members
of the board also visited the Clair
Ridge platform, where they learnt
more about operations offshore.
They discussed the safety agenda
onsite, visited the drilling floor and
spoke with employees directly to
better understand the culture when
working offshore.
Kuala Lumpur and Singapore
Members of the audit committee
visited the global business services
in Kuala Lumpur. Touring BP’s
offices gave valuable insight into
the workforce which has been
responsible for centralizing and
standardizing key business processes
across the organization and
transforming processes end-to-end.
The directors then visited the IST
team in Singapore where they met
with senior leadership and the wider
workforce at BP’s offices.
“
The committee members
noted strong morale.”
South Korea
The SESAC visited BP’s shipping
function and spent a day at sea in
South Korea on board a new LNG
vessel. They experienced the vessel
in a period of ‘shakedown’ ahead of
going into service. The committee
observed safety processes in action
and were able to discuss physical
and cyber security planning.
Members of the SESAC met with
sea farers without management
present to discuss life working on
board the vessels.
BP Annual Report and Form 20-F 2019
89
Nomination and governance committee
Role of the committee
The committee seeks to ensure an orderly succession
of candidates for directors, the company secretary and
senior executives 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 Non-Executive Directors (NEDs).
• Review the mix of knowledge, skills, experience and
diversity of the board for the orderly succession of
directors.
• Identify, evaluate and recommend candidates for
appointment as company secretary.
• Review developments in law, regulation and best
practice relating to corporate governance and make
recommendations to the board on appropriate
action, including on Environmental, Social and
Governance matters.
Membership
Helge Lund
Member since July 2018 and
chairman since September 2018
Alan Boeckmann Member
Sir Ian Davis
Nils Andersen
(resigned April 2019)
Member
Member
(resigned March 2020)
Brendan Nelson Member
Paula Reynolds
Member
Sir John Sawers Member
Meetings and attendance
The committee met six times in 2019. All members
attended each meeting with the exception of Nils
Andersen who missed two meetings owing to prior
commitments.
Activities during the year
2019 saw the workload and required time commitment
of committee members increase significantly as the
committee continued to monitor the composition and
skills of the board, with foresight across the three
succession planning horizons, as part of the process
of developing a reinvented BP.
During the year, it supported the board in the
selection of the new CEO, which was announced
in October 2019, and the new CFO, which was
announced in January 2020. Regular updates were
provided to the chairman’s committee to ensure that
all NEDs were kept informed of the pending changes
to BP’s executive leadership. The committee also
reviewed the wider executive team’s succession
planning, considered the implications of the new UK
Corporate Governance Code 2018 and made
recommendations to the board following the
results of the external board evaluation in 2018.
We will continue to focus on ensuring that the
board’s composition is strong and diverse and to
promote best practice governance in the boardroom
and throughout the company.
“
The committee dedicated a significant
amount of time to its role in 2019 and this
will continue as BP implements its new
purpose, ambition and aims.”
Helge Lund
Committee chair
Chairman’s introduction
The committee dedicated a significant amount of time to its role in 2019, a
year which was vitally important for BP and the future direction of the
company. This will continue as BP implements its new purpose, ambition
and aims.
During the year the committee led the search for a new CEO to succeed
Bob Dudley. This involved agreeing the leadership credentials and desired
experiences for the executive role. External headhunters were engaged to
support the process and to identify candidates with the required skills,
experience and diversity credentials. After a thorough and transparent
process, Bernard Looney was identified as the best suited candidate and
his appointment was announced in October 2019.
The committee’s focus on executive succession planning continued, and
BP announced Murray Auchincloss as Brian Gilvary’s successor as CFO in
January 2020.
Finally, a review was undertaken by the committee of the new leadership
team which was announced in February 2020.
As part of the selection and appointment process for each of these roles,
candidates completed extensive leadership assessment testing and were
asked to give insight to their aims for BP’s future.
During the year the committee also undertook a review of the executive
succession pipeline, considering the process, emerging talent and
leadership role key-person-risks. As part of this review, the committee
took into account the importance of diverse talent pipelines and the current
and future skill sets required to help the company achieve its strategy
The committee discussed the implications of the UK Corporate Governance
Code 2018 and how to maintain the highest standards of governance.
Lastly, the committee considered the findings of the 2018 board evaluation
and made proposals to the board on new ways of working. Together with the
results from the 2019 board review, these changes are being incorporated
into a new corporate governance framework.
Helge Lund
Committee chair
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BP Annual Report and Form 20-F 2019
Audit committee
“
The committee robustly challenges
reports...enabling it to determine
whether BP’s financial reporting is
fair, balanced and understandable.”
Brendan Nelson
Committee chair
Chairman’s introduction
During 2019, in keeping with the new UK Corporate Governance Code
2018, the committee continued its focus on monitoring the integrity of
the group’s financial reporting and risk management systems. Each
quarter the committee robustly challenges the reports from management
and the external auditor highlighting significant accounting issues and
judgements, enabling it to determine whether BP’s financial reporting is
‘fair, balanced and understandable’. Throughout the year, the committee
reviewed the group’s principal and emerging risks, including scenarios
which could impact the company’s long-term viability which also helped
to inform the committee’s debates on what would constitute significant
failings and weaknesses in our system of internal control.
In 2019 the committee focused on the effectiveness of a number of
group functions including integrated supply and trading, treasury, tax,
information technology and security. We also received presentations
regarding, and reviewed performance of, both the Upstream and
Downstream segments and regularly considered climate change risk
affecting the whole business. These reviews helped inform the
committee of the work and future plans of those functions and
businesses and enabled the committee to understand the key risks and
challenges (and associated mitigations and lessons learned) 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.
There were no changes to the committee membership during the year
and the skills and experience of our committee members remain strong,
enabling the committee to continue to perform effectively.
Brendan Nelson
Committee chair
Corporate governance
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 process
to identify, manage and mitigate principal and
emerging financial risks are appropriately addressed
by the chief executive officer 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.
Membership
Brendan Nelson Member since November 2010
Dame Alison
Carnwath
Pamela Daley
Paula Reynolds
and chair since April 2011
Member
Member
Member
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 NatWest Markets 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 eight committee meetings in 2019. All
members attended each meeting with the exception of
Pamela Daley who was absent from the September
meeting owing to prior 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.
BP Annual Report and Form 20-F 2019
91
Activities during the year
How the committee reviewed 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, systems of risk management and 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 considered whether the
period covered by the company’s viability statement was appropriate.
The committee considered the BP Annual Report and Form 20-F 2018 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, which in turn reviewed the report as
a whole, confirmed the assessment and approved the report’s publication.
Other disclosures reviewed included:
• Oil and gas reserves.
• Pensions and post-retirement benefits assumptions.
• Risk factors.
• Legal liabilities.
• Tax strategy.
• Going concern.
• IFRS 16 (lease accounting).
How risks were reviewed
The principal risks allocated to the audit committee for monitoring in
2019 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 to a rapidly
changing environment, including modernizing its control environment
policies to strengthen its compliance and control culture. The committee
further considered updates in the integrated supply and trading
function’s risk management programme, including compliance with
regulatory developments, activities in response to cyber threats, and
efficiencies derived from more collaborative ways of working across
group functions and businesses and the use of digital technologies.
Compliance with business 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.
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BP Annual Report and Form 20-F 2019
The committee reviewed the group’s programme of controls and
contingencies for managing this risk, including enhanced approaches to
monitor the risk in light of business evolution (such as an increase in
venturing), as well as other internal and external trends. 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 a strengthened approach in order to
manage the ever increasing threat of cyber risk and maintain cyber
security, as the focus on a digital transformation across BP continues.
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 assumptions, and underlying
judgements, used to manage the group’s liquidity, and capital
investments (including appraisal, effectiveness and efficiency).
How other reviews were undertaken
Other reviews undertaken in 2019 by the committee included the
following, and in each case where the committee received segment and
function reviews, each reported on strategy, performance, capability and
risk management as well as on their first, second and third lines of
defence policies as appropriate:
• Non-operated joint venture: including management of exposure to
financial, reputational and regulatory risks.
• Upstream: including strategy, business model, financial performance
and risk management.
• Downstream: including strategy, performance, capability and risk
management.
• Tax: including strategy, performance, key drivers of the group’s
effective tax rate, the global indirect tax environment, the tax
modernization programme and the evolving approach to management
of key risks.
• Other businesses and corporate: including overview of the
businesses and functional activities, financial performance and
financial control framework.
• Treasury: including performance, capability, and risk management.
• Integrated supply and trading: including strategy, performance,
capability and risk management.
• Capability and succession in BP’s finance function, including the
group’s finance summary of change programme.
• Effectiveness of investment: annual review of performance of
projects with sanctioned capital over a certain threshold.
• Assessment of financial metrics for executive remuneration:
consideration of financial performance for the group’s 2019 annual
cash bonus scorecard and performance share plan, including
adjustments to plan conditions and non-operating items.
• Internal controls: assessments of management’s plans to remediate
the external auditor’s findings.
• Information technology and security: including an update on the
transformation of the function to enable the digitization and
modernization of the firm at pace.
How internal control and risk management
was assessed
Group audit
The committee received quarterly reports on the findings of group audit in
2019, including their assessment of issues raised in previous years,
especially those relating to IT access controls. The committee met
Corporate governance
privately with the group head of audit and key members of his leadership
team. The committee monitored and reviewed the effectiveness of
internal audit and considered whether it had the appropriate level of
independence and its importance in assessing the company culture.
Training
The committee considered market updates and developments throughout
the year including the CMA statutory audit market study, the Brydon
Review and the Kingman Review. It received technical updates from the
chief accounting officer on developments in financial reporting and
accounting policy, in particular an update on IFRS 16 ‘Leases’ and the
stakeholder engagement disclosures required under The Companies
(Miscellaneous Reporting) Regulations 2018 for the 2019 accounting year,
and amendments to IFRS 9 ‘Financial Instruments’ for interest rate
benchmark reform from the start of 2020.
GBS and integrated supply and trading visit
In March the committee visited BP’s global business services (GBS)
centre in Kuala Lumpur. During the visit they met with the head of country
and his leadership team who presented GBS strategy to 2025 enabling
modernization of BP through accelerated standardization, digital solutions
and process transformation – underpinned by a global functional operating
model. They also met with the Procurement and HR services teams
including an interactive session with local business resource colleagues.
In March the committee also visited BP’s integrated supply and trading
(IST) function in Singapore, meeting with senior leaders to discuss the
role of this function in BP, review of the risks and controls processes
and a floor walk through key functions and the trading desks. See page
89 for more information on these visits by the committee.
In October, the committee held its meeting at BP’s IST function in London
and conducted its annual tour, which covered global oil strategy, integrated
gas and power, associated key risks and risk and compliance management
and how the function was responding to a fast evolving market by using
digital tools to drive efficiencies. The following trading desks were visited
by the committee: treasury trading, global environmental products and
integrated gas and power.
External audit
How the committee assessed audit risk
The external auditor set out its audit strategy for 2019, identifying significant
audit risks to be addressed during the course of the audit. These included:
• Focus on the consistency of management’s judgements and
estimates within BP’s strategy in the context of climate change.
• Responding to the risk of material misstatements in the group, by
way of substantive testing and the use of detailed data analytics.
• The risk of impairment of upstream oil and gas property, plant and
equipment, and exploration and appraisal assets.
• Accounting for structured commodity transactions in the integrated
supply and trading function.
• Valuation of level 3 financial instruments held by the integrated supply
and trading function.
• 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.
How the committee assessed 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 $49 million (2018 $42
million), of which 2% 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 $1 million (2018 $2 million). Non-audit or
non-audit related services consisted of other assurance services.
How the committee assessed audit effectiveness
Management undertook a survey which 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 results of the survey indicated that the external auditor’s performance
was broadly comparable with the previous year. Areas with high scores and
favourable comments included quality of accounting and auditing judgement
and robust stance on issues. Areas for improvement were identified but
none impacted on the effectiveness of the audit, mostly in recognition of it
having been Deloitte’s first year in role. The results of the survey were
discussed with Deloitte for consideration in their 2019 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 auditor’s approach to providing
audit services. 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.
The committee specifically considered the findings of the FRC’s Audit
Quality Review team’s review of Deloitte’s 2018 audit. The committee
noted the single observation raised and Deloitte’s proposed response
thereto. Overall the committee noted the review did not raise any
concerns in respect of audit quality.
How the auditor reappointment and independence was assessed
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 five to seven years. No partners or
senior staff associated with the BP audit may transfer to the group.
How the committee had oversight of 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), International Auditing and Assurance
Standards Board (IAASB) 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 BP 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 322.
BP Annual Report and Form 20-F 2019
93
How accounting judgements and estimates were considered and addressed
Key judgements and estimates
in financial reporting
Audit committee activity
Conclusions/outcomes
Exploration and appraisal intangible assets
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.
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
• Exploration write-offs totalling $0.6 billion were
group’s quarterly due diligence process.
recognized during the year.
• 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.
• Received briefings on the status of upstream
intangible assets, including the status of items on
the intangible assets ‘watch-list’.
• Exploration intangibles totalled $14.1 billion at
31 December 2019.
• BP believes it is appropriate to continue to
capitalize the costs relating to intangible assets, on
the ‘watch-list’.
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 prices, discount rates,
production profiles, reserves and the impact of
inflation on operating expenses.
• 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.
• Reviewed the group’s oil and gas price
assumptions.
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.
• 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.
Investment in Rosneft
Judgement is required in assessing the level of
control or influence over another entity in which the
group holds an interest.
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.
• Reviewed the judgement on whether the group
continues to have significant influence over
Rosneft, including following Bob Dudley stepping
down from his role as BP group chief executive.
• Considered IFRS guidance on evidence of
participation in policy-making processes.
• Received reports from management which
assessed the extent of significant influence,
including BP’s participation in decision-making.
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.
• The group’s long-term price assumption for Brent
oil, was reduced by $5 from 2018 assumptions
and was unchanged for Henry Hub gas.
• The period over which the group’s price
assumptions transition from recent market prices
to the long-term assumption was unchanged at
five years for Brent oil and increased from 5 to 12
years for Henry Hub gas from 2018.
• A sensitivity analysis estimating the effect of
reductions in the price assumptions has been
disclosed in Note 1.
• The methodology for determining the group’s
discount rates used for impairment testing was
enhanced, resulting in country-specific rates being
applied.
• Impairments of $6.6 billion were recorded in the
year, net of impairment reversals, primarily relating
to decisions to dispose of certain assets.
• BP has retained significant influence over Rosneft
throughout 2019 as defined by IFRS.
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BP Annual Report and Form 20-F 2019
Corporate governance
Key judgements and estimates
in financial reporting
Audit committee activity
Conclusions/outcomes
Derivative financial instruments
For its level 3 derivative financial instruments, BP
estimates their fair values using internal models due
to the absence of quoted market pricing or other
observable, market-corroborated data. Judgement
may be required to determine whether contracts to
buy or sell commodities meet the definition of a
derivative, in particular longer-term LNG contracts.
• Received a briefing on the group’s trading risks
and reviewed the system of risk management and
controls in place.
• The committee annually reviews the control
process and risks relating to the trading business.
• BP considers that longer-term contracts to buy or
sell LNG do not meet the definition of a derivative
under IFRS. BP has assets and liabilities of $5.5
and $4.4 billion respectively, recognized on the
balance sheet for level 3 derivative financial
instruments at 31 December 2019, 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.
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.
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.
• Received briefings on decommissioning,
environmental, asbestos and litigation provisions,
including those related to the Gulf of Mexico oil
spill. These included the requirements,
governance and controls for the development
and approval of cost estimates and provisions
in the financial statements.
• Reviewed the group’s discount rates for
calculating provisions.
• Decommissioning provisions of $15.1 billion
were recognized on the balance sheet at
31 December 2019.
• The discount rate used by BP to determine the
balance sheet obligation at the end of 2019 was
a nominal rate of 2.5% – based on long-dated
US government bonds – a reduction of 0.5%
from 2018.
• The impact of applying the revised rate has
been disclosed.
• Reviewed the group’s assumptions used to
• The method for determining the group’s
determine the projected benefit obligation at
the year end, including the discount rate, rate
of inflation, salary growth and mortality levels.
assumptions remained largely unchanged from
2018. 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 2019, surpluses of $7.1 billion
and deficits of $8.6 billion were recognized on
the balance sheet in relation to pensions and
other post-retirement benefits.
BP Annual Report and Form 20-F 2019
95
Safety, environment and security
assurance committee (SESAC)
Committee overview
Role of the committee
The role of the SESAC 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 risk, security and environment risks
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 and functions, which include,
but are not limited to, the safety and operational risk
function, shipping, group audit and group security.
The SESAC can access any other independent advice
and counsel it requires on an unrestricted basis.
The SESAC 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.
Meetings and attendance
There were six committee meetings in 2019. All
directors attended every meeting for which they
were eligible.
In addition to the committee members, all SESAC
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 has access
to the chair and secretary to the committee as
required. The group general counsel 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 is invited to a private
meeting with the committee.
Membership
Melody Meyer
Nils Andersen
Member since May 2017 and
chair since November 2019
Member
(resigned March 2020)
Alan Boeckmann Member
(retired April 2019)
Member
(retired May 2019)
Member
Admiral Frank
Bowman
Professor Dame
Ann Dowling
Sir John Sawers Member
“
The committee has continued to
focus on working with executive
management to drive safe and
reliable operations.”
Melody Meyer
Committee chair
Chairman’s introduction
At the end of 2019 I took the role of chair for the committee. Alan
Boeckmann retired from the board in April 2019 and Nils Andersen
replaced him as the committee chair. In November last year, Nils
announced his intention to step down from the board in March 2020
and I replaced Nils as SESAC chair with immediate effect.
During 2019 the committee has continued to focus on working with
executive management to drive safe and reliable operations. As part of
the committee’s review of the executives’ management of the highest
priority non-financial group risks assigned to SESAC we provide
constructive challenge and oversight. The risks under our remit remained
the same as for 2018: 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.
In 2019 the committee reviewed the BP Sustainability Report 2018. It
also reviewed work practices in BP in relation to and following publication
of the company’s Modern Slavery Act (MSA) statement in 2019. The
committee will continue to review progress in developing and embedding
practices to mitigate the risk of modern slavery and related human rights.
In March, members of the committee visited the shipping function as one
of the new LNG vessels went into service from the building yard in
Busan, South Korea. This afforded the committee time with the crew on
board the vessel, employees in the office and with contractors in the
shipyard. See page 89 for more details. The level of access into the
operations on such visits gives the directors first-hand, 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.
Melody Meyer
Committee chair
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BP Annual Report and Form 20-F 2019
Corporate governance
Activities during the year
System of internal control and risk management
The board also undertook a site visit. This was not a SESAC site visit
but, nevertheless, safety and non-financial risk matters were covered
during the visit to Clair Ridge in May 2019.
Corporate reporting
The committee oversaw the BP Sustainability Report 2018. The
committee reviewed the content and worked with the external auditor
with respect to its assurance of the report.
The review of operational risk and performance forms a large part of the
committee’s agenda. Group audit provided quarterly reports on its
assurance work and its 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, security 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 auditor regularly 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. The
committee reviewed the 2019 forward programme for the group audit
function.
Site visits
In March members of the committee made a physical visit to the
shipping function for the first time. While the committee has regular
access to senior leaders in the function, attempting to visit the vessels
needed careful planning. With the launch of six new LNG vessels
between October 2018 and April 2019, the committee took the
opportunity to visit, and arrived as the fifth LNG vessel was in its period
of ‘shakedown’ – a period post-launch and pre-service, when checks
are made onboard the ship. The visit, hosted by the chief operating
officer of shipping, was made to The British Mentor while it was at sea,
just off the coast of South Korea. Committee members went on board
and were met by the ship’s crew, undertook a thorough tour, and later
met with various seafarers, without the captain present, to get a sense
of the culture on board. The committee also spent time at the office and
held an informal town hall and lunch to hear from employees. The
following day the committee was also able to visit the shipyard which
had built the LNG vessels, and meet with management. The committee
members were able to take a tour of a LNG vessel in the building phase
and see the technology used in the construction of the vessel at various
stages of completion. The committee spent time with the shipyard
owners, important stakeholders in the programme of delivery. In
respect of the visit, 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 the visit to the committee and subsequently to the board.
See page 89 for further details.
BP Annual Report and Form 20-F 2019
97
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.
• 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.
• 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.
Membership
Sir John Sawers Member since September 2015
Nils Andersen
Admiral Frank
Bowman
Sir Ian Davis
Melody Meyer
and chair since April 2016
Member
(resigned March 2020)
Member
(resigned May 2019)
Member
Member
Meetings and attendance
The chairman and group chief executive regularly
attend committee meetings. The chief executive of
Alternative Energy and executive vice president,
regions and the head of 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, with
the exception of Nils Andersen who missed one
meeting due to a prior commitment.
Geopolitical committee
“
The committee continued to address
key geopolitical matters and their
potential impact on BP.”
Sir John Sawers
Committee chair
Chairman’s introduction
The work of the geopolitical committee in 2019 continued to address key
geopolitical matters and their potential impact on BP and how these
evolved during the year. As chair of this committee I also attended all of
the international advisory board (IAB) meetings in 2019. Now that the IAB
has been disbanded, this committee will look to take some of the IAB’s
remit and we will report next year on how that evolves. In May 2019,
Admiral Frank Bowman stood down from the committee. Nils Andersen
left the committee upon his resignation from the board in March 2020.
I would like to thank Frank and Nils, both of whose contributions were
much valued. Other board members joined our meetings from time
to time.
Sir John Sawers
Committee chair
Activities during the year
The committee discussed BP’s involvement in the key countries
where it has existing investments or is considering investment.
These included the EU, Mexico, Brazil, Algeria, Libya, Egypt, Iraq,
Oman and The Gambia.
The committee also discussed the potential impact of Brexit on BP, and
the negotiations between the UK and the EU on their future relationship.
It reviewed the geopolitical background to BP’s global investments, the
global politics of climate change, the geopolitics of gas, Russian energy
exports, OPEC, the USA-China trade war, and developments in the
Persian Gulf.
98
BP Annual Report and Form 20-F 2019
Chairman’s committee
“
The committee spent significant time
discussing the development and
progression of BP’s purpose,
expanding upon what the purpose
actually means for the company and
how it impacts BP’s stakeholders.”
Helge Lund
Committee chair
Chairman’s introduction
The chairman’s committee worked closely with the nomination and
governance committee on the selection process of the new group CEO
and CFO, receiving regular updates and providing feedback on the
succession planning. The committee also spent significant time
discussing the development and progression of BP’s purpose, expanding
upon what the purpose actually means for the company and how it
impacts BP’s stakeholders. We discussed the updated UK Corporate
Governance Code 2018 and the implications for the business. In May
2019, Alan Boeckmann and Frank Bowman stood down from the board
and the chairman’s committee. I would like to pay tribute to their
exceptional service and thank them for their dedication to the committee
and BP as a whole.
Helge Lund
Committee chair
Activities during the year
• Evaluated the performance of the group chief executive.
• Reviewed the composition of and the succession plans for the
executive team.
• Discussed the company’s purpose and what it meant for the business.
• Considered updates to the UK Corporate Governance Code 2018.
Corporate governance
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 chief executive officer.
• Review the structure and effectiveness of the
business organization.
• Review the systems for senior executive
development and determine succession plans for
the chief executive officer, 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.
Membership
The committee is made up solely of non-executive
directors, each of whom is appointed to the committee
upon their appointment to the board.
Meetings and attendance
The committee met seven times in 2019. Nils
Andersen, Pamela Daley and Professor Dame Ann
Dowling each missed one meeting during the year, all
other directors attended every meeting for which they
were eligible.
BP Annual Report and Form 20-F 2019
99
Directors’ remuneration report
“
Through a vibrant exchange
of views, we believe the
committee will be wiser.”
Paula Rosput Reynolds
Committee chair
Contents
2019 performance and pay outcomes
2019 annual bonus outcome
2017-19 performance share plan outcome
Executive directors’ pay for 2019
2020 remuneration: Policy on a page
Alignment with strategy
Wider workforce in 2019
Stewardship and executive director interests
Non-executive director outcomes and interests
Other disclosures
Directors’ remuneration report – the 2020 policy
104
105
106
108
110
111
112
114
116
118
119
Dear shareholder,
Results, progress and incentive outcomes
This is my second letter to you as chair of the remuneration
committee. It comes at the end of a period during which we have
engaged with many of you on our new remuneration policy. I have
been fortunate to get to know a number of you individually, and as
a committee we have deeply appreciated the spirit of collaboration
evident throughout our dialogue on remuneration matters.
It also comes at a time when, as a global community, we are
navigating uncharted territory because of the global onset of
coronavirus (COVID-19). None of us yet know quite how broad its
impact will be, nor how deeply it will be felt. What we do know is that
our industry is seeing a significant demand and supply-side shock,
with consequent share price volatility. The board and I will remain
close as the situation develops, and we will respond with consideration
of the facts. Clearly, the remuneration targets we have set for the year
will need to be adjusted to the circumstances as they unfold. I can
also confirm that the remuneration committee will monitor business
conditions and exercise judgement in applying discretion relating to
2020 remuneration. We will proceed with great care in determining
the timing and magnitude of equity awards. At year-end, when we
assess performance, we will be thoughtful in the interpretation of
results, balanced with the shareholder experience. I do believe that
the 2020 policy as drafted provides us with maximum flexibility in
applying discretion – which the times call upon us to exercise.
Turning to our 2019 report, we cover three areas. First the
remuneration outcomes over 2019 and the 2017-19 performance
shares cycle are presented, along with a discussion about the
relationship between company performance, earned rewards and
the shareholder experience. Second, the largely regulatory driven
reporting of stewardship and related matters is shown. Third, the
2020 directors’ remuneration policy, which will be the subject of a
binding vote at our annual general meeting in May.
With the number of statutory requirements increasing, this report
continues to grow. For those of you needing a quick overview,
I recommend our summary pages on 104 and 110 which reflect
outcomes for 2019 and the 2020 policy respectively.
2019 has been another year of challenges and accomplishments in
our operating and financial performance, and concludes a three-year
cycle which has seen significant strategic progress. From a shareholder
perspective, robust operating cash flow gave headroom for
distributions of $8.3 billion through dividends, together with $1.5 billion
of share buybacks. Although recent share price performance has been
disappointing for BP and global share markets generally, the year
nonetheless concludes a three-year cycle that has delivered a 29%
total return.
From our analysis of annual performance outcomes, the committee
determined that the 2019 bonus should be 67.5% of maximum,
rather than the purely formulaic 71.5% derived from the performance
scorecard. This was to reflect our judgment that strong cash receipts
at year-end would potentially impact receipts in 2020, hence the
reduction in the formulaic result.
The committee also determined that the performance share
outcome should be 71.2% of maximum. We took the financial
measures as reported but used our discretion in determining the
quality of the strategic progress. We determined that, over the
three-year performance cycle that ended in 2019, significant
strategic progress was made towards a lower carbon future. But our
message, too, with scoring of strategic progress, is that there is the
need for greater pace and accomplishment in the years ahead.
To this point, as we look forward, the committee is faced with measuring
strategic progress through a different lens. As our recently appointed
BP leadership realigns strategy to reduce the carbon footprint of our
business with greater urgency, the committee must strike the balance
between rewarding progress in energy transition matters and rewarding
delivery of our commitment to strong financial performance and safe
operations. As we progress the energy transition, we will be faced with
establishing new goals for which benchmark measures may not be
readily and immediately available. You will read herein, even the question
of the peer group to be used to measure relative total shareholder returns
(rTSR) is greatly complicated by the question of whose performance
should be tracked in the energy transition.
100
BP Annual Report and Form-20F 2019
Corporate governance
Remuneration committee
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.
• 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.
• Receive and consider regular updates on
workforce views and engagement initiatives
related to remuneration, insight from data sources
on pay ratio, gender pay gap and other workforce
remuneration outcomes as appropriate.
• Maintain appropriate dialogue with shareholders
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.
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 and the
executive team.
• 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.
• Prepare the annual remuneration report to
shareholders to show how the policy has
been implemented.
on remuneration matters.
Membership
Member since September 2017
Paula Rosput
and chair since May 2018
Reynolds
Nils Andersen
Member (resigned March 2020)
Member
Pamela Daley
Member
Sir Ian Davis
Melody Meyer
Member
Brendan Nelson Member
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 as necessary.
The committee met nine times during the year.
All directors attended each meeting that they were
eligible to attend, except Nils Andersen who was
not able to attend two meetings. Pamela Daley and
Sir Ian Davis each missed one committee meeting.
We understand that these are matters of great importance to our
shareholders. Therefore we will work closely with the incoming
leadership team to assure that goal-setting, in particular for progress
against the carbon agenda, remains ambitious while also delivering pay
outcomes that align with your own experience. We intend to confer
with shareholders later in 2020 to establish goals once the details of our
energy transition efforts have been provided.
Single figure results for executive directors
2019 single figures of total remuneration for Bob Dudley and Brian Gilvary
are $13.23 million and £6.56 million respectively, as reported on page 108.
These outcomes represent a 13% decrease for Bob, and a 20% decrease
for Brian, reflecting reductions in the performance shares outcome, and in
particular lower share price growth over the three-year cycle. As noted
above, the committee applied the well-established formulas where
relevant and, in conjunction with strategic progress, carefully reviewed
the contributions of the executives. The impact of weaker share price
performance on realized value is consistent with the experience of
shareholders and thus we deem these outcomes reasonable.
For an overview of our executive remuneration structure, please refer to
the “at a glance” table on page 103.
Succession arrangements
2019 also marked a point of succession, as our group chief executive
Bob Dudley announced his intention to retire from BP, to be succeeded
by Bernard Looney.
Bob has now stepped down from the BP board, and ceases employment
from 31 March. As we announced in October 2019, he has waived his
entitlement to notice pay for the unserved part of his notice period, and
to any bonus for any part of 2020. By any measure, Bob has been an
exemplar of corporate service; he leaves BP as a ‘good leaver’ under
the terms of our executive director incentive plan, and therefore his
interests under various deferred share awards are preserved and will
vest in line with scheduled vesting dates and decisions, subject only
to the committee retaining its discretion in the administration of the
underpin on safety.
For our new chief executive officer, Bernard Looney, pay will be governed
by the 2020 remuneration policy. The committee disclosed in October
2019 that it had set Bernard’s salary at £1.3 million (approximately 9%
below Bob Dudley’s salary) as of 5 February 2020, with a reduced cash
allowance retirement benefit of 15% of salary, which puts his allowance in
line with the majority of our wider workforce. Bernard retains a deferred
pension benefit from service prior to April 2011, and certain deferred share
awards from service prior to 2020.
Earlier this year we made similar announcements regarding the
retirement of Brian Gilvary and the appointment of his successor,
Murray Auchincloss, with effect from 1 July 2020. Further detail is
provided on page 103 for the new executives.
Our 2020 policy renewal
During 2019 we have been grateful for the time and attention our major
shareholders gave us as we consulted on requirements for the new
2020 policy. In particular, 30 of our largest shareholders joined us in
September for a novel session focused on expressing unconstrained
views on remuneration arrangements. Together with subsequent
discussions and correspondence, the key issues emerging for
consideration have been:
• Clear end-to-end alignment from strategy, through measurable
performance indicators and reward outcomes, to shareholder
experience.
• Balance our contribution to the energy transition with delivering
shareholder returns. The committee was encouraged to use
appropriate discretion, given the complexity of the environment in the
energy transition.
• Assure that strategic moves align to long-term sustainability, relative
to a wider peer group.
• Use meaningful and transparent measures to reflect our progress in
the energy transition and reductions to our carbon impact.
BP Annual Report and Form-20F 2019
101
Directors’ remuneration report
With all of this in mind, we have established a policy proposal which
we believe reflects our strategic imperatives and allows for competitive
remuneration outcomes aligned to the shareholder experience. The
proposal makes modest but appropriate adjustments to our 2017
framework which, to our mind, is well understood and has delivered
appropriate results for both shareholders and executive directors. We
studied many far-reaching alternatives in concluding our final proposal
but typically found other approaches carried too much complexity, an
amplified concern given the transition our industry faces.
The key changes we are making include a reduced emphasis on relative
total shareholder return, but measuring our returns against a more
diverse group of companies; a sharpened focus on energy transition
measures throughout the structure; tighter limits on pension benefits;
and a reduction in the number of measures that will be considered for
the annual bonus plan.
Other matters
Our committee activity in 2019 was extensive. It included a review of
the principles of remuneration to support our updated policy (page 119)
and engagement with shareholders and shareholder representatives.
We also spent considerable time on remuneration matters related to the
succession of the group chief executive and the various leadership
changes that followed, in line with our increasing accountability for
setting senior executive pay.
As UK remuneration committees now have the regulatory obligation to
review remuneration of the wider workforce, our committee has sought
to understand how pay practices vary across the globe and to examine
issues of fundamental fairness. We examined pay outcomes by gender
and other criteria. We have also considered how the committee can
effectively add value to our stewardship of the wider workforce and
our 2020 plans will include some additional engagement in this area.
The committee reviewed the breadth of historical pension
arrangements across the spectrum of our employees in 2019. As an
outcome, BP made changes that have brought pensions for executive
directors and the wider workforce into alignment.
Our committee appreciated the time and thoughtful input shareholders
and their representatives have given to the refreshment of the
remuneration policy. Through a vibrant exchange of views, we believe
the committee will be wiser as it considers executive pay against the
backdrop of a challenging environment. We respectfully ask for your
endorsement of the committee’s 2019 remuneration decisions and your
approval of the proposed 2020 policy framework.
Paula Rosput Reynolds
Chair of the remuneration committee
18 March 2020
In this Directors’ remuneration report RC profit (loss), underlying RC profit,
return on average capital employed and 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 335.
102
BP Annual Report and Form-20F 2019
Corporate governance
Remuneration at a glance
Salary and
benefits
Retirement
benefits
Annual
bonus
Performance
shares
Key features
Purpose and
link to strategy
Outcomes for 2019
(2017 policy)
Implementation in 2020 (2020 policy
proposal unless stated otherwise)
• Salary is reviewed annually
• Fixed remuneration
• Bob Dudley’s salary
• Bob Dudley’s salary to remain at
and, if appropriate, increased
following the AGM.
• Benchmarked to market at
inception with increases
reflective of those of our
wider workforce.
reflecting the scale and
complexity of our
business, enabling us to
attract and keep the
highest calibre global
talent.
unchanged at $1,854,000.
• Brian Gilvary’s salary
increased by 2% to
£790,500.
• Benefits remain
unchanged.
$1,854,000 until he ceases employment
on 31 March.
• Bernard Looney’s salary is set at
£1,300,000.
• Brian Gilvary’s salary to remain at
£790,500 until he ceases employment.
• Murray Auchincloss’s salary to be set at
£695,000.
• Bernard’s benefits remain unchanged.
Murray will be eligible for standard UK
benefits from his appointment on 1 July.
• 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
• Arrangements for Bob will continue
pension did not increase in
2019. His actual and
notional company
contributions, together
with investment returns
within his retirement
savings plans, amounted
to $543,661.
• Brian’s accrued defined
benefit pension increase
was below inflation. He
received a cash allowance
at 35% of salary to 31
May, and at 30% of salary
from 1 June 2019, which is
included in the single
figure table.
unchanged until he ceases employment on
31 March.
• Bernard’s cash allowance reduces to 15%
of salary from the date of his appointment.
Accrued service for his deferred pension is
already capped, and the pension
calculation will be based on his pre-
appointment salary.
• Brian’s cash allowance is subject to a
previously agreed schedule of reductions
and will terminate when he ceases
employment on 30 June.
• Murray’s cash allowance will be set at 15%
of salary from his appointment on 1 July.
He retains a deferred pension arrangement
from his US service, which will be based
on his pre-appointment salary.
• 112.5% of salary at target,
and 225% at maximum.
• 50% of the bonus is paid in
cash and 50% is mandatorily
deferred and held in BP
shares for three years.
• To continue under 2020
policy.
• To incentivize delivery
• Against our scorecard of
• Bob has waived any entitlement to an
of our annual and
strategic goals.
• The 50% deferral
reinforces the long-term
nature of our business
and the importance of
sustainability.
safety (20%), environment
(10%), reliable operations
(20%) and financial
performance (50%), our
performance score is
135% of target (67.5% of
maximum).
annual bonus for 2020.
• Brian will qualify for a pro-rated bonus for
his service in 2020.
• Proposed scorecard with four measures
across safety (20%), environment (20%),
operational (10%) and financial (50%)
performance.
• Annual grant of performance
shares, representing the
maximum outcome. 500%
of salary for group chief
executive and 450% of salary
for chief financial officer.
• Shares only vest to the
extent performance
conditions are met.
• To continue under 2020
policy.
• To link the largest part of
remuneration opportunity
with the long-term
performance of the
business. The outcome
varies with performance
against measures linked
directly to financial
returns and strategic
priorities.
• Against our balanced
scorecard of financial
measures (80%), and
strategic progress (20%),
our 2017-19 performance
score is 71.2% of
maximum.
• Awards granted in 2018, under our 2017
policy, at 500% (Bob Dudley) and 450%
(Brian Gilvary) of salary will vest in
proportion to success against the
measures of our 2018-20 scorecard, on a
pro-rata basis for time in service.
• For our 2020-23 cycle, grant levels will
remain unchanged for our incoming chief
executive and chief financial officer at
500% and 450% of salary respectively,
with weightings of 40% for relative total
shareholder return (rTSR), 30% for return
on average capital employed (ROACE) and
30% for energy transition measures.
Shareholding
requirement
• Executive directors are
required to maintain a
shareholding equivalent to at
least five times their salary.
• Additionally, they have been
• To ensure sustained
alignment between the
interests of executive
directors and our
shareholders.
expected to maintain
shareholdings of at least two
and a half times salary for two
years post employment.
• Both Bob Dudley and Brian
Gilvary materially exceed
the share ownership
requirements.
• From 2020, executive directors are
required to maintain their full minimum
shareholding requirement for two years
post employment.
• The minimum shareholding requirement
remains five times salary for the group
chief executive and is four and a half times
salary for other executive directors.
BP Annual Report and Form-20F 2019
103
Directors’ remuneration report
2019 performance and pay outcomes
Business
performance
A strong year of operational performance, set against challenging external conditions. Improvement across safety
metrics, and significant growth in our retail business. Strong underlying profits for 2019, with a 29% return to
shareholders over the three-year cycle.
Key strategic highlights
• $10 billion underlying replacement cost profit
• Dividend increased to 10.5 cents per share
• Expansion of our convenience partnership sites
to around 1,600 globally
• Created BP Bunge Bioenergia, a world-class
bioenergy company
2nd (29%)
Among peers for
total shareholder
return 2017-19
$28.2bn
Operating
cash flow
(excluding Gulf of
Mexico oil spill
payments)
$8.3bn
Dividends paid,
including scrip
Performance
outcomes
Strong results for the year, beating targets on five out of six measurement categories in our scorecards.
2019 Annual bonus
2017-19 Performance shares
71.5%
Formulaic
outcome
(% of maximum)
-4.0%
Committee
judgement,
discretionary
reduction
67.5%
Final outcome
(% of maximum)
71.2%
Formulaic
outcome
(% of maximum)
0%
Committee
judgement,
no adjustment
71.2%
Final outcome
(% of maximum)
Performance dimensions (% weighting)
Performance dimensions (% weighting)
Safety (20%)
Environment (10%)
Reliability (20%)
Financial (50%)
KPI
KPI
KPI
KPI
15.5/20
Financial (80%)
KPI
7/10
Strategic progress (20%)
KPI
57/80
14/20
8.5/20
40/50a
Annual bonus outcome (67.5% of maximum)
Bob Dudley
Brian Gilvary
$2,815,763
£1,200,572
Performance shares outcome (71.2% of maximum)
Bob Dudley
Brian Gilvary
$7,936,660
£2,752,815
KPI This legend denotes remuneration measures that directly relate to BP’s key performance indicators. See page 32.
Total
remuneration
2019
Bob Dudley
Group chief executive
18.7% fixed
81.3% variable
Brian Gilvary
Chief financial officer
16.7% fixed
83.3% variable
Salary and benefits, (14.6)%
Retirement benefits, (4.1)%
Annual bonus, (21.3)%
Performance shares, (60.0)%
$13.23m
2018: $15.25m
Salary and benefits, (12.9)%
Retirement benefits, (3.8)%
Annual bonus, (18.3)%
Performance shares, (42.0)%
Discontinued plans, (23.0)%
£6.56m
2018: £8.22m
Share
ownership
Shareholding is a key means by which the interests of executive directors are aligned with those of shareholders.
As at 3 March 2020 both directors had holdings in BP which significantly exceeded our shareholding policy
requirement of five times salary.
Bob Dudley, Group chief executive
Brian Gilvary, Chief financial officer
15.18 times salary, 5,290,446 sharesb.
16.20 times salary, 3,086,437 shares.
a Due to rounding, these figures do not precisely equal the overall outcome, 71.5%
b Held as American depository shares (ADSs)
Policy requirements (5x)
Actual
104
BP Annual Report and Form-20F 2019
Corporate governance
2019 annual bonus outcome
For 2019 the committee established a bonus scorecard of eight
measures across four areas of focus: safety and operational risk, the
environment, reliable operations and financial performance. These
measures align with our strategy and investor proposition and, in
particular, reflect the annual plan. Seven of the eight measures align
with our 2018 scorecard. The eighth measure, sustainable emissions
reduction, was new and marked an acceleration of our intent to gear
elements of financial reward to our progress in navigating the low
carbon transition.
In order to build on the strong results of 2018, the committee again set
notably stretching targets for each measure. For instance, our 2019
threshold outcome for recordable injury frequency was set at the level of
our 2018 outcome, meaning we had to exceed that 2018 result to achieve
even a minimum contribution to the 2019 bonus. Overall, our focus on
safety delivered a year with both the fewest process safety incidents on
record (excluding the impact of recent Mexico retail and BHP onshore
aquisitions), and the lowest recordable injury frequency on record.
As noteworthy as this result is, we still regard any accident as one too
many, and it is a matter of great regret that two of our colleagues suffered
fatal injuries in 2019. To underscore our determination to eliminate these
tragic incidents, we reflect any fatality in the performance assessment of
the relevant business, thereby causing a material reduction in bonus for
every individual in that business. In reaching our final conclusion, we rely
on the judgement of the safety, environment and security assurance
committee (SESAC) on the evaluation of safety outcomes.
Similarly, we sought the input of the audit committee to ensure our
conclusions are robust and properly reflect underlying financial
performance relative to markets. This included a review of the
adjustments we make in our financial targets to reflect any pricing
impacts, and thereby avoid windfall outcomes in our financial measures.
For 2019, this led to a proportional reduction in our profit and cash flow
targets, reflecting the weaker oil price environment. Over the eight years
to 2019, we have increased targets four times, and reduced them four
times, consistently stripping out the impact of the price environment.
2019 annual bonus scorecard
These measures were set under the terms of our 2017 policy
KPI See key performance indicators on page 32.
Safety
0.31
+
Environment
0.14
+
Reliable
operations
0.17
+
Financial
performance
0.80
=
Formulaic
score 1.43a
out of 2.0
Measures
Safety
(20% weight)
Environment
(10% weight)
Reliable
operations
(20% weight)
Financial
performance
(50% weight)
Formulaic score
Formulaic
scorecard
outcome
1.43 out of 2
Weighting
Threshold (0)
Target (1)
Maximum (2)
Outcome
Process safety tier 1
and tier 2 eventsb
Recordable injury
frequency
Sustainable emissions
reductions
BP-operated refining
availabilityc
BP-operated upstream
plant reliability
Operating cash flow
(excluding Gulf of Mexico
oil spill payments)
Underlying replacement
cost profit
Upstream unit
production costs
KPI 10%
KPI 10%
KPI 10%
KPI 10%
KPI 10%
KPI 20%
KPI 20%
KPI 10%
80 events
0
72 events
0.1
56 events
0.2
70 events
0.11
0.198/200k hrs
0
0.188/200k hrs
0.1
0.168/200k hrs
0.2
0.159/200k hrs
0.20
Outcome
0.31
0.49 mte
0
94.5%
0
92.6%
0
$24.0 bn
0
$8.1 bn
0
$7.12/bbl
0
1.0 mte
0.1
95.0%
0.1
94.6%
0.1
$26.5 bn
0.2
$8.9 bn
0.2
$6.72/bbl
0.1
2.0 mte
0.2
95.5%
0.2
96.6%
0.2
$29.0 bn
0.4
$9.7 bn
0.4
$6.32/bbl
0.2
1.4 mte
0.14
94.9%
0.08
94.4%
0.09
Outcome
0.17
$28.2 bn
0.33
$10.0 bn
0.40
$6.84/bbl
0.07
Input audit
committee
and SESAC
No adjustment
Remuneration
committee
judgement
Minus 0.08
Final
scorecard
outcome
1.35 out of 2
Outcome
0.80
1.43a out of 2.0
67.5%
of
maximum
a Due to rounding, the total does not equal the sum of the parts.
b Measure excludes data from Mexico retail and BHP onshore operations for two years from the date of their acquisition by BP.
c Solomon Associates’ operational availability.
BP Annual Report and Form-20F 2019
105
Directors’ remuneration report
While we continue to believe these adjustments are appropriate,
they potentially create some tension between the relative basis of our
financial measurement, and shareholders’ experience of cash flow and
profit. With this context, we decided to reduce the formulaic bonus
scorecard outcome to reflect our judgement that strong cash receipts
at year end would potentially impact receipts in 2020.
Our bonus outcome for 2019 is therefore 135% of target and 67.5% of
maximum. This compares with 81% of target and 40.5% of maximum
in 2018. With the rigour of our process and discussions, and the support
we have received from the SESAC and audit committee, we believe the
2019 annual bonuses fairly reflect and reward 2019 performance for the
executive directors and senior leadership of BP.
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 2019 bonus, including the
deferred shares, is included in the 2019 single figure table. This differs
from reporting in respect of the 2014 policy, under which deferred
shares related to the 2016 bonus are included in the 2019 single figure,
i.e. the year in which they vest.
Bob Dudley
Brian Gilvary
Adjusted
outcome
Paid
in cash
Deferred into
BP shares
$2,815,763a
$1,407,881
$1,407,881
£1,200,572
£600,286
£600,286
a Due to rounding the total does not match the sum of the parts.
The annual bonus outcome is unrelated to the BP share price, and
therefore no part of the bonus is attributable to share price appreciation.
2017-19 performance share plan outcome
Vesting levels for the 2017-19 performance share awards are
determined under the terms of the 2017 policy, in line with the
performance measures and outcomes shown on the scorecard on
page 107, and the committee’s broader deliberations in line with the
‘underpin’ established in that policy. The scorecard for this period
included relative total shareholder return (50%), return on average
capital employed (30%) and four strategic progress measures (20%)
that are assessed both quantitatively and qualitatively.
Assessed against the two financial scorecard measures, the group’s
performance for the three years from 2017 to 2019 is strong. We placed
second on relative total shareholder return (with a 29% total return)
which measures us against our super-major peers, Chevron,
ExxonMobil, Shell and Total. Return on average capital employed
(ROACE) was 8.9%, comfortably ahead of the 8.1% target.
We introduced the four strategic progress measures in our 2017 policy.
Hence this is the first cycle for which we have made an assessment on
strategic progress. We find that a rating of 13.8% out of 20% maximum
opportunity is appropriate. Below are the four strategic pillars and a short
description of some of the factors that influenced our scoring decision:
Shift to gas and advantaged oil in the upstream. Gas production
has grown 35% (comparing 2019 with 2016), and 75% of all pre-2022
start-ups planned during the 2017-19 cycle are in gas. Pre-2022 start-ups
in oil are lower-cost or adjacent to existing basins, creating additional
value and lowering carbon intensity relative to BP’s legacy portfolio.
Market-led growth in the downstream. BP has materially entered
the retail markets in Mexico and Indonesia and expanded our overall
retail network with 850 sites opened since 2016. Marketing of premium
fuels has seen compound growth of 7% per annum in these higher
value sales.
Venturing and low carbon across multiple fronts. BP has made
signature investments in BP Chargemaster, our DiDi fast-charging joint
venture in China and Lightsource BP, all of which underpin growth in
electric vehicle charging and solar. We merged our biofuels business
with another operator to create BP Bunge Bioenergia thereby creating
synergies and scale for growth in biofuels. We have created a ‘scale-up’
factory known as BP Launchpad, to enhance our access to investment
in new ventures, and have increased the portfolio over the last three
years. The committee will be monitoring and measuring the progress
of these ventures over time.
Gas, power and renewables trading and marketing growth. We
noted robust early progress with BP’s new integrated gas and power
organization, mainly through a growing presence as a merchant in the
global LNG trade, although financial results remain volatile. We also
noted the development of infrastructure to undertake renewables
trading, which has included building diverse counter-party relationships,
such as with renewable energy source producers and owners of forests
for the purposes of creating a market for natural climate solutions (NCS).
Along with the combination of financial and strategic measures that
shareholders approved in the 2017 policy, the provision for ‘underpin’
decision by the committee was instituted. Namely, before deciding on
the final result, the committee takes a broader view of performance to
ensure that reward outcomes align with absolute shareholder returns,
safety and environmental factors, and progress in low carbon and
climate change matters. Our conclusion is that returns from the 2017-19
performance shares cycle are proportional and appropriate. Therefore,
we have made no further adjustment to the scorecard outcome. Vesting
therefore has been set at 71.2% of maximum, delivering the outcomes
detailed below.
Bob Dudleya
Brian Gilvary
Shares awarded
Shares vesting
including
dividends
Value of
vested shares
1,571,628
1,319,478
$7,936,660
722,093
606,347
£2,752,815
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.
The value of vested shares reflects the share price changes all
shareholders experienced over the three-year period. For this 2017-19
award cycle, the original grant was calculated based on ordinary share
and ADS prices of £4.73 and $35.39 respectively, while the equivalent
prices on 18 February 2020, the vesting date, were £4.54 and $36.09.
Consequently, share price appreciation in this cycle accounts for
$130,549 (1.6%) of the value of Bob’s vested shares, and none of the
value of Brian’s vested shares.
106
BP Annual Report and Form-20F 2019
Corporate governance
2017-19 performance shares scorecard
These measures were set under the terms of our 2017 policy
KPI See key performance indicators on page 32.
Financial
57.4%
Measures
Financial
Strategic
progress
Total formulaic
score
Formulaic
vesting
71.2%
Strategic progress
13.8%
+
=
Formulaic
vesting
71.2%
Relative total
shareholder return
Return on average
capital employed
Weighting
at maximum
Threshold
performance
Maximum
performance
KPI 50%
KPI 30%
Third
7.25%
First
11.0%
Outcome
Second
40.0%
8.9%
17.4%
Outcome
57.4%
Shift to 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
5%
5%
5%
5%
Qualitative and quantitative assessment
by the committee. No numeric scale for
vesting outcome – see page 106.
3.75%
3.0%
4.25%
2.75%
Outcome
13.8%
71.2%
Underpin: Committee review of absolute shareholder returns, long-term safety
and environmental performance, low carbon and climate change considerations.
No adjustment
71.2%
final vesting
after committee
judgement
BP Annual Report and Form-20F 2019
107
Directors’ remuneration report
Executive directors’ pay for 2019
Single figure table – executive directors (audited)
Remuneration is reported in the currency
in which the individual is paid
Bob Dudley
(thousand)
Brian Gilvary
(thousand)
Salary
Benefits
Pension and retirement saving – value increasea
Cash in lieu of future accrual
Cash bonus
Shares – deferred for three years
Performance shares
2019
$1,854
$84
$544
–
$1,408
$1,408
2018
$1,854
$79
$0
–
$845
$845
2019
£785
£59
£0
£252
£600
£600
2018
£769
£67
£0
£269
£353
£353
$7,937b
$11,630c
£2,753b
£4,295c
Deferred share awards from prior-year bonuses
–d
– d
£1,510e
£2,113e
Salary and
benefits
Retirement
benefits
Annual
bonus
Performance
shares
Discontinued
plans
Total remunerationf
Value attributed to share price appreciationg
$13,234
$131
$15,253
$2,033
£6,558
–
£8,219
£1,753
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. Full details are set out on page 109. For Brian
Gilvary this represents the annual increase in accrued pension, net of inflation, multiplied by 20. In 2019 Brian’s salary increased by less than
inflation, hence there is no net increase in accrued pension, and zero is reported as per regulations. Full details are set out on page 109.
b Represents the vesting of shares on 18 February 2020 following the end of the 2017-19 performance period, based on the assessment of
performance achieved under the rules of the plan and includes accrued dividends on shares vested. The value of shares at vesting was
$36.09 for ADSs and £4.54 for ordinary shares.
c
d
In accordance with UK regulations, in the 2018 single figure table, the performance outcome values were based on fourth quarter average
prices of $41.48 for ADSs and £5.33 for ordinary shares. In May 2019, 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 80%. On 3 May 2019, 269,974 ADSs for
Bob Dudley and 776,611 ordinary shares for Brian Gilvary vested at prices of $43.08 and £5.53. The 2018 values for the total vesting have
increased by $587,301 for Bob Dudley and £211,889 for Brian Gilvary because of the higher share prices and additional accrued dividends.
In line with previous practice Bob Dudley has voluntarily agreed to defer performance assessment and vesting of the awards related to his
2016 annual bonus until at least one year after retirement, therefore the performance period will exceed the minimum term of three years. As
stated in the 2017 and 2018 directors’ remuneration reports, Bob voluntarily deferred performance assessment and vesting of the 2014 and
2015 deferred and matching awards until at least one year after retirement. See the Deferred shares table on page 115 for further details on
these awards.
e The amounts reported for 2019 relate to the matching element of the 2014 annual bonus deferral, which Brian had voluntarily deferred for an
additional two years, and the deferred element of the 2016 annual bonus. These awards vested on 18 February 2020 at the market price of
£4.54 for ordinary shares and include accrued dividends on shares vested. The amounts reported for 2018 relate to the 2015 annual bonus,
comprising the underlying award that vested on 19 February 2019 at a market price of £5.38 (as disclosed in our 2018 report), and the
additional vesting of accrued dividends on 3 May 2019 at the market price of £5.53. See the Deferred shares table on page 115 for further
details on these awards.
f Due to rounding, the totals do not agree exactly with the sum of their component parts.
g The values shown for performance shares and deferred share awards include the share price appreciation, if any, experienced over the
applicable 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 multiplied by the increase in share price from grant date to vesting date. The 2018 values
have been restated from the 2018 reported values to exclude share price growth relating to accrued dividends.
108
BP Annual Report and Form-20F 2019
Corporate governance
Overview of single figure outcomes (audited)
The single figures of total remuneration for Bob Dudley and Brian
Gilvary are $13.234 million and £6.558 million respectively. This is a
13% decrease for Bob, and a 20% decrease for Brian.
Salary and benefits
Bob Dudley’s salary remained at $1,854,000 throughout 2019. Brian
Gilvary’s salary was increased by 2% to £790,500 with effect from
21 May 2019. Both executive directors received car-related benefits,
assistance with tax return preparation, security assistance, insurance
and medical benefits.
2019 annual bonus and 2017-19 performance shares
Please refer to pages 105-107 for details of the performance measures,
targets, results and the related reward outcomes for annual bonus and
performance shares.
Discontinued plans: deferral of 2014 and 2016 bonus
In accordance with 2014 policy, Bob Dudley and Brian Gilvary
compulsorily deferred one third of their 2016 annual bonus and
each received an equivalent value matching award of BP shares.
Both the deferred and matching awards were subject to a three-year
performance period which ended on 31 December 2019.
Bob has requested that the committee delay the performance
assessment and hence the vesting of his 2016 deferred and matching
awards. This is a continuing practice from previous years and reflects
his ongoing commitment to the long-term success of BP, even post
employment. These awards will vest, subject to an assessment against
the original safety and environmental sustainability conditions, after
his retirement.
Brian had previously voluntarily requested that the committee delay
the performance assessment and vesting of his 2014 matching award
for two years. In 2018 he requested that the committee delay the
performance assessment and vesting of his 2016 matching award
until at least one year post employment.
For Brian’s 2014 matching award and 2016 deferred awards, the
committee considered operational and financial performance and
reviewed safety and environmental sustainability performance over the
2015-19 and 2017-19 periods, seeking input from the SESAC 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 these two
awards should vest in full.
Retirement benefits
Bob Dudley 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 proportion
of earnings for each year of service. In 2019 his accrued defined benefit
pension did not increase and in accordance with the requirements of UK
regulations, the amount included in the single figure table on page 108
is zero.
The BP Employee Savings Plan (ESP) is a US tax-qualified defined
contribution plan to which both Bob and BP contribute. 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 2019 Bob made contributions to the
ESP totalling $28,000 and BP made matching contributions to the ESP,
and notional contributions to the ECSP, totalling $129,780. In addition to
these contributions, Bob realised investment gains of $413,881 in his
unfunded ECSP account (aggregating the unfunded arrangements
relating to his overall service with BP and TNK-BP), hence the amount
included in the single figure table is $543,661.
Brian Gilvary is provided with pension benefits through a combination of
tax-qualified and non-qualified plans for service to 31 March 2011, but
linked to his final salary, and a cash allowance for service thereafter. In
common with more than 3,800 UK employees employed prior to 2010
(or before 2014 in the North Sea) Brian is a member of the BP Pension
Scheme (BPPS), a UK final salary defined benefit pension plan. Pension
benefits accrued in excess of the individual lifetime tax allowance set by
legislation are provided to Brian via a non-qualified, unfunded pension
arrangement designed to mirror the design of the approved BPPS. His
normal retirement age is 60, although due to his long service, benefits
accrued before 1 December 2006 may be paid unreduced from age 55
with BP’s consent.
In 2019 Brian’s salary increase was below inflation. In accordance with
the requirements of UK regulations, the amount included in the single
figure table on page 108 is zero.
Brian receives a cash allowance of 30% of salary (this will reduce to 25%
on 1 June 2020 for his last month of service). This amount has been
separately identified in the single figure table.
History of group chief executive remuneration
Shares
granted
Vesting
agreed
Total shares
vesting,
including
dividends
Total value
at vesting
Name
Bob Dudleya
2016 Deferred award
2016 Matching award
147,642
147,642
–a
–a
–
–
–
–
Brian Gilvaryb
2014 Matching award
176,576
2016 Deferred award
2016 Matching award
73,070
73,070
100%
100%
–a
246,359
£1,118,470
86,176
£391,239
–a
–a
a Vesting of these awards deferred until at least one year post employment, subject
to conditions.
b Based on a vesting share price of £4.54.
Year
2010b
2011
2012
2013
2014
2015
2016
2017
2018
2019
Group chief
executive
Tony Hayward
Bob Dudley
Bob Dudley
Bob Dudley
Bob Dudley
Bob Dudley
Bob Dudley
Bob Dudley
Bob Dudley
Bob Dudley
Bob Dudley
Total
remuneration
thousanda
Annual bonus %
of maximum
Performance
shares % of
maximum
£3,890
$8,057
$8,439
$9,609
$15,086
$16,390
$19,376
$11,904
$15,108
$15,253
$13,234
0
0
66.7
64.9
88.0
73.3
100.0
61.0
71.5
40.5
67.5
0
0
16.7
0
45.5
63.8
74.3
40.0
70.0
80.0
71.2
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, the
adjusted outcome for the years 2012 to 2018 where preliminary assessments of
performance for EDIP had initially been made, and the actual outcome for 2019.
b 2010 figures show full year remuneration for both Tony Hayward and Bob Dudley, although
Bob Dudley did not become group chief executive until October 2010.
BP Annual Report and Form-20F 2019
109
Directors’ remuneration report
2020 remuneration: Policy on a page
Approach: We will retain the structure that has served well since 2017, reserving increased flexibility to adapt as BP pursues its ambition to
become a net zero company by 2050 or sooner, and help the world get to net zero.
Salary and
benefits
Retirement
benefits
Annual bonus
Salary will be reviewed annually. Increases are measured against
external pay relativity, and will not exceed the increase for our
wider workforce.
Benefits are unchanged and include car-related provisions (or cash
in lieu), security assistance, insurance and medical cover.
New appointees from within the BP group retain previously accrued
benefits. For their service as a director, retirement benefits will be
no more than the median provision offered to the wider workforce
in the UK.
This is a material reduction from our 2017 policy.
Bonus is measured against an annual scorecard. Measures will
include financial (50%), operational (10%), safety (20%) and
environmental (20%) goals.
The committee will set appropriately stretching targets for each
measure.
Target bonus is 112.5%, and maximum bonus is 225% of salary.
The committee holds discretion to choose the specific measures to
be adopted within each of these categories and the relative
weightings to assign to them to reflect the annual plan as agreed
with the board.
Numeric scales are set for each measure, to score outcomes
relative to targets.
Half of the bonus for each year is paid in cash, and half is delivered
as a deferred share award vesting in three years.
Performance
shares
Performance shares are granted with a three-year performance
period. Awards to be granted under this policy will vest in 2023,
2024 and 2025, and shares held until 2026, 2027 and 2028.
Measures will include rTSR (40%), assessed against a broader peer
group, ROACE (30%) and an assessment related to the low carbon
transition (30%).
For 2020, the rTSR peer group will include additional energy
companies in our sector, but ones who also have low carbon
businesses or material commitments, such as Equinor, ENI and
Repsol. Beyond 2020, the committee will consider additional
companies whose programmes provide meaningful challenge to
BP regarding its own lower carbon ambitions.
At the outset of each award the committee will review the
measures that are to govern the award, along with weightings and
targets, to ensure they remain focused on delivering the strategy
and are in the interests of shareholders.
Annual grants will be at 500% of salary for the chief executive
officer, and 450% of salary for any other executive director.
These awards will vest in three years and in proportion to the
outcomes measured through the performance scorecard, with a
holding period that requires the shares to be retained for a further
three years.
The committee will assess safety outcomes over the perfomance
cycle as an underpin in determining the final vesting percentage.
Shareholding
requirement
Malus and
clawback
Chief executive officer to build a shareholding of at least five times
salary, and other executive directors four and a half times salary,
within five years of appointment.
Executive directors are required to maintain that level for at least
two years post employment.
Malus provisions may apply where there is: a material safety or
environmental failure; an incorrect award outcome due to
miscalculation or incorrect information; a restatement due to
financial reporting failure or misstatement of audited results;
material misconduct; or other exceptional circumstances that the
committee considers similar in nature.
Clawback provisions may apply where there is: an incorrect
outcome due to miscalculation or incorrect information; a
restatement due to financial reporting failure or misstatement of
audited results; or material misconduct.
Committee
flexibility
Under this policy, the committee will hold flexibility to choose the
measures and weightings to be adopted for each annual bonus and
performance shares scorecard, and to adjust the peer group for the
rTSR measure, at the start of each performance cycle.
The committee reserves discretion in determining the outcomes
for annual bonus and performance shares, allowing it to take broad
views on alignment with shareholder experience, environmental,
societal and other inputs.
This will allow appropriate re-alignment, over the policy term, to the
anticipated evolution of the low carbon competitor market.
The table above shows an at-a-glance summary of our proposed 2020 executive director remuneration policy. For the full remuneration policy,
which will be proposed for shareholder approval at our 2020 AGM, please see pages 119 to 127.
110
BP Annual Report and Form-20F 2019
Corporate governance
The strategic shift that BP signalled in February, and which will be
further detailed during our capital markets presentation in September,
sharply increases the need for the remuneration policy to reflect low
carbon ambitions and the energy transition. For this reason, the
environmental measure in annual bonus will increase from 10% to 20%
weighting, and the strategic measures for performance share vesting
are now explicitly tied to low carbon/energy transition, and carry a 30%
weighting. As BP’s leadership continues to develop specific strategic
goals in this space, we are reserving committee discretion to define and
communicate the precise measures and weighting that will apply for the
performance share awards, and to adjust from cycle to cycle.
Alignment with strategy
Bernard Looney recently announced a bold new purpose and ambition
for BP, reaching out to 2050. This reframes a crucial part of our investor
proposition with an explicit commitment to the energy transition that
investors and wider society rightly expect. It also recommits us to
delivering competitive financial returns, through our ‘performing while
transforming’ programme.
While the specifics of our strategic milestones are yet to be defined,
our direction is clear. For alignment of remuneration policy to corporate
strategy, we will broadly retain our policy structure, while reserving
specific flexibility to allow an evolution of performance measures and
their weightings over the three-year policy term. Our 2017 policy
structure, driven by an annual bonus and three-year performance
shares, has allowed us to harness the energy and commitment of our
executive directors and senior leadership through a set of clearly
articulated and ambitious goals. By retaining flexibility to adjust
performance measures and weightings, we have been able to maintain
alignment between shareholders and executives even as BP’s strategy
has developed over time. We therefore believe that this combination of
structure and flexibility, that has served us well through the last policy
cycle, is equally well suited to the transition years ahead.
The annual bonus is determined in line with performance relative to
annual targets for safety, environmental, operational and financial
measures. Performance shares vest in line with performance relative to
three-year targets for rTSR, ROACE and a set of low carbon/energy
transition measures. This suite of measures allows for an end-to-end
alignment between our strategic direction, our executive focus and our
remuneration outcomes, always with the underpin of committee
discretion to adjust outcomes as appropriate to match shareholders’
own experience.
Safety is and will remain a core value, hence continues to drive a
material part of the bonus outcome, as well as forming part of the
committee’s ‘underpin’ consideration in the finalvesting of performance
shares. Likewise, BP has made clear strategic commitment to maintain
focus on financial returns to shareholders, which therefore remain
well-represented in the performance measures for annual bonus (50%
weighting) and performance shares (40% weighting on rTSR and 30%
weighting on ROACE). Reflecting the views of our shareholders, we
have reduced the rTSR weighting (from 50%) and also started to
widen the comparator group. For the first performance share cycle
under the new 2020 policy, the comparator group is expanded from the
four super majors to include ENI, Equinor and Repsol, all of whom have
some lower carbon elements in their strategies. We have studied
opportunities to expand the peer group further. But we conclude that
other low carbon operators and indices have yet to reach sufficient
maturity for inclusion at this time. Nevertheless it is possible that this
will change during the policy cycle and hence we retain the discretion to
introduce other companies or an index of low carbon companies in the
coming equity cycles within the life of this policy.
BP Annual Report and Form-20F 2019
111
Directors’ remuneration report
Wider workforce in 2019
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
considers ways to deepen engagement with the workforce, and to
understand the workplace in its broadest sense, the remuneration
committee continues to receive and review information on pay
outcomes and processes for our wider workforce.
During 2019, we have taken a measured path towards deepening our
understanding of this complex field by studying these five areas:
• The overall demographics of the workforce, to understand where we
employ our people, at what levels within the organization, and in what
business areas.
• The distinct reward frameworks used by our major business areas, to
understand different approaches to fixed pay, incentives and benefits.
This review included a detailed consideration, by way of case study
examples, of the progression of total reward across the job hierarchy
in seven representative business areas.
• A deeper look at annual bonus, to build a greater appreciation of the
business and geographic profile of our total bonus spend, and how
target levels of bonus vary across the employee hierarchy in our top
eight countries.
• An analysis of the use of equity-based reward, to understand the
extent to which equity forms a core element of reward in different
locations and business areas.
• The structure of workforce pensions in the US and UK, to deepen our
understanding of the variety of entitlements that exist across
different levels of the organization, given obligations to honour
legacy arrangements from prior policies.
This wider workforce context is helpful to our thinking about future
reward policies. Aside from our specific oversight of remuneration in
the IST business, the committee does not intend to supplant the
appropriate role of management in setting rewards for the wider
workforce. But the committee believes our engagement and our own
experiences in other companies and other industries can be additive to
the thought process of management.
In addition to the board’s workforce engagement initiatives, as a
committee we have started a programme of engagement directly
related to remuneration. This includes focus group sessions related to
our remuneration practices and the connectivity we see between
executive and wider workforce remuneration.
Summary of remuneration structure for employees below the board
Element
Policy features for the wider workforce
Comparison with executive director remuneration
Salary
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 market rates
of pay at relevant comparators, 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.
Pensions and
benefits
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. Given the variety of markets in which we operate, and with
the aspect of choice available to many employees, there is no identifiable
pension rate for our wider workforce. For context, however, a majority of
our UK employees are entitled to a 15% (of salary) benefits budget.
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.
For new executive directors, pension benefits have been sharply
reduced. Bernard Looney’s cash-in-lieu of pension allowance is set at
15% of salary. His defined benefit calculation is based on his pre-
appointment salary and his accrued service is capped.
Annual bonus 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 and individual level. This
structure places equal emphasis on the importance of an employee’s
personal contribution 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.
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
112
BP Annual Report and Form-20F 2019
Annual bonus for executive directors is directly related to the same group
performance measures and outcomes as the wider workforce, but
without the individual performance element.
Performance shares for our executive directors are assessed using the
same group performance scorecard used for the group leader
performance shares.
Corporate governance
Group chief executive-to-employee pay ratio
Equal pay and UK gender pay gap reporting
Since 2016 we have disclosed the ratio between our group chief
executive’s total remuneration and the median remuneration of a
comparator group of our UK and US professional and managerial
workforce (representing 38% of our global professional workforce).
This calculation highlights pay differentials across the concentrated
portion of our workforce and thus we have retained this voluntary
measure for the purpose of comparison over time.
For 2019, however, we also report the pay ratio based on the new
requirements set out in the 2018 regulations. Given the markedly
different comparator groups, the voluntary and required pay ratios
are not directly comparable. The different ratios arise because of two
key differences: the required method includes BP hourly paid retail
workforce in its fuels and convenience stations who are employed in
roles which attract relatively lower market rates of pay; and the required
method excludes the majority of our professional workforce, namely
those outside the UK, such as our Houston, Texas campus.
Method
BP voluntary
BP voluntary
25th
percentile
pay ratio
50th
percentile
pay ratio
50th
percentile
total pay
75th
percentile
pay ratio
–
–
106:1
$136,865
$147,612/
£115,683a
89:1a
–
–
Option Ab
543:1c
188:1df
£55,071
82:1e
Year
2018
2019
2019
a Remuneration converted from $ to £ at an exchange rate of 1.276.
b Option A has been selected as it is the most accurate approach. Pay and benefits have been
calculated using values for the year ended 31 December 2019 and no broadly applicable
components of pay or benefits have been omitted. Full-time equivalent remuneration has
been calculated by mathematical engrossment.
c The relevant 25th percentile values are £19,108 total pay and benefits, and £18,845 salary.
d The relevant 50th percentile values are £55,071 total pay and benefits, and £38,800 salary.
e The relevant 75th percentile values are £126,085 total pay and benefits, and £74,200 salary.
f The company believes that the 50th percentile pay ratio reflects total pay and benefits values
fully in line with reward policies for the group chief executive and the median UK employee
respectively, and consequently that the ratio is consistent with policy.
Percentage change comparisons:
GCE remuneration versus UK workforce
Comparing 2019 to 2018
% change in GCE remuneration
% change in comparator group remuneration
Salary
Benefits
0%
3.8%
6.3%
1.0%
Bonus
66.7%
16.8%
The comparator group used here is our UK workforce, in line with the
required basis for chief executive to employee pay ratio reporting and
therefore provides a measure of consistency in reporting.
Relative importance of spend on pay
($ million)
Distributions to
shareholders
Remuneration paid to
all employees
9,844a
8,435a
9,872
10,497b
2019
2018
2019
2018
2019
2018
a Distributions to shareholders comprise dividend payments of $8,333 million.
($8,080 million in 2018) and share buybacks at a cost of $1,511 million ($355 million in 2018).
See page 299 for details.
b This amount was misstated as $10,494 in our 2018 report.
As well as looking at pay structures, the committee has spent time
understanding how effectively current pay policies and processes
maintain fairness and avoid bias in pay outcomes. We noted BP’s 2019
UK gender pay gap reporting, published in March 2020, 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
representation of women, rather than adjusting pay practices. We are
encouraged by the various initiatives taken by management to address
these representation concerns and will continue to monitor progress.
The illustration below, from our 2019 UK gender pay gap reporting (the
most recent available), highlights the representation issue and how it
relates to the gender pay gap for each entity. For instance, our larger
median gender pay gaps relate to BP Exploration and BP p.l.c. where
we have the largest differential between representation of women in
the top and bottom pay quartiles. By contrast, we reported a negative
median pay gap in BP Chemicals (-12.4%), where male to female
representation is more balanced.
BP Chemicals Limited
median pay gap -12.4%
BP Exploration Operating
Company Limited
median pay gap 24.9%
Upper
74%
73%
88%
Lower
75%
26%
Upper
90%
84%
80%
Lower
58%
27%
12%
25%
BP Chemicals is our petrochemicals business
in the UK, principally our operation in Hull.
BP Exploration covers Upstream activities
in the UK, principally North Sea operations.
BP Oil UK Limited
median pay gap 9.5%
Upper
69%
61%
69%
Men
Women
BP Express Shopping Limited
median pay gap 4.0%
31%
39%
31%
Upper
61%
60%
49%
10%
16%
20%
42%
39%
40%
51%
62%
BP p.l.c.
median pay gap 18.9%
Upper
71%
66%
56%
Lower
37%
29%
34%
44%
63%
BP p.l.c. predominantly covers employees in
corporate business and functions, including
our integrated Supply and Trading and Air
BP businesses.
Bar charts represent the balance between
male (
total pay quartile of the relevant business.
) employees in each
) and female (
BP Annual Report and Form-20F 2019
113
Capital investment
Lower
42%
58%
Lower
38%
15,238
15,140
BP Oil represents our Downstream
fuels and lubricants businesses.
BP Express Shopping is our largest UK
employing business, concerned with retail
operations supporting our UK-wide network
of forecourts.
Directors’ remuneration report
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
recent shareholding policy therefore required executive directors to
build a personal shareholding of five times their salary within five years
of their appointment. They were expected to maintain personal
shareholdings of at least two and a half times salary for two years post
employment. Updates to this policy are proposed as an integral part of
our 2020 remuneration policy, as detailed on page 121.
Directors’ shareholdings (audited)
The tables below detail the personal shareholdings of each current
and recent executive director. Both Bob Dudley and Brian Gilvary
significantly exceed the policy requirement at 3 March 2020, with
Bernard Looney building towards the policy requirement that applies
five years from his appointment on 5 February 2020. These figures
include all beneficial and non-beneficial ownership of shares of BP
(or calculated equivalents) that have been disclosed to the company.
Director
Ordinary shares
or equivalents at
1 Jan 2019
Ordinary shares
or equivalents at
31 Dec 2019
Changes from
31 Dec 2019 to
3 Mar 2020
Ordinary shares
or equivalents at
3 Mar 2020
Bob Dudleya
3,718,284
4,592,208
Brian Gilvary
2,043,899
2,593,708
698,238
492,729
5,290,446
3,086,437
a Held as ADSs.
Director
Bob Dudley
Brian Gilvary
Appointment date
Value of current
shareholding
Multiple of
salary achieved
October 2010
$28,145,173
15.18 x salary
January 2012
£12,808,714 16.20 x salary
Bob and Brian 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 2019
Unvested
ordinary shares
or equivalents as
31 Dec 2019
Changes from
31 Dec 2019 to
3 Mar 2020
Unvested
ordinary shares
or equivalents at
3 Mar 2020
6,825,606b
6,639,882
-1,343,142
5,296,740
3,291,614
2,905,764
-845,629
2,060,135
Director
Bob Dudleya
Brian Gilvary
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.
Performance shares (audited)
Performance
period
Date of award of
performance shares
At 1 Jan 2019
Awarded 2019
At 31 Dec 2019
Potential maximum performance sharesa
Number of
ordinary shares
vested
Vesting date
Face value of
award, £
Share element interests
Interests vested in 2019 and 2020
Bob Dudleyb
Brian Gilvary
2016-18
2017-19
2018-20
2019-21
2016-18
2017-19
2018-20
2019-21
19 May 2017
22 May 2018
19 Feb 2019
4 Mar 2016
19 May 2017
22 May 2018
19 Feb 2019
4 Mar 2016
1,645,074c
1,571,628
1,395,600
–
–
–
–
1,340,766
786,559
722,093
696,705
–
–
–
–
654,315
–
1,619,844d
3 May 2019d
1,319,478e
18 Feb 2020e
1,571,628
1,395,600
1,340,766
722,093
696,705
654,315
–
–
–
–
8,206,128f
7,199,913g
–
776,611d
3 May 2019d
606,347e
18 Feb 2020e
–
–
–
–
4,096,625f
3,513,672g
–
–
–
–
a For awards under the 2016-18 plan, 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 the comparator companies 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 2018-2020 plan, performance conditions are measured on the same basis as the 2017-2019 plan, except ROACE which will be based on performance in the last two
years of the performance period (i.e. 2019 and 2020).
For awards under the 2019-2021 plan, performance conditions are measured 50% on TSR relative to the comparator companies over three years, 30% on strategic progress assessed over
the performance period and 20% ROACE averaged over the full performance period. In the event that no threshhold performance targets are met, no shares would vest unless the
committee found reason to exercise discretion.
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 Bob Dudley has requested that the EDIP performance shares vesting in respect of the performance period 2016-2018 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 applied under the 2014 directors’ remuneration policy.
d 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. This 2016-2018 award vested on 3 May 2019. The market price of each share at the vesting date was £5.48 and for ADSs was $43.08. Details can be found in the single figure table
on page 108.
e 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. This 2017-2019 award vested on 18 February 2020. The market price of each share at the vesting date was £4.54 and for ADSs was $36.09. Details can be found in the single figure
table on page 108.
f The face value has been calculated using the market price at closing of ordinary shares on 22 May 2018 of £5.88.
g The face value has been calculated using the market price at closing of ordinary shares on 19 February 2019 of £5.37.
114
BP Annual Report and Form-20F 2019
Deferred shares (audited)a
Bob Dudleybc
Bonus
year
2014
Performance
period
Date of award
of deferred
shares
2015-17
11 Feb 2015
2015-17
11 Feb 2015
2015-17
11 Feb 2015
Type
Comp
Vol
Mat
2015
Comp
2016-18
04 Mar 2016
Brian Gilvary
Vol
Mat
Comp
Mat
Comp
Comp
Mat
Comp
Vol
Mat
Comp
Mat
Comp
Comp
2016
2017
2018
2014
2015
2016
2017
2018
2016-18
04 Mar 2016
2016-18
04 Mar 2016
2017-19 19 May 2017
2017-19 19 May 2017
2018-20 22 May 2018
226,236
2019-21
19 Feb 2019
2015-17
11 Feb 2015
2016-18
04 Mar 2016
2016-18
04 Mar 2016
2016-18k 04 Mar 2016
2017-19 19 May 2017
2017-19l 19 May 2017
176,576
159,021
159,021
318,042
73,070
73,070
2018-20 22 May 2018
127,457
2019-21
19 Feb 2019
64,436
Corporate governance
Deferred share element interests
Potential maximum deferred shares
Interests vested in 2019 and 2020
Awarded
At 31 Dec
2019
–
–
–
–
–
–
–
–
–
118,584
–
–
–
–
–
–
–
2019
147,054
147,054
294,108
275,892
275,892
551,784
147,642
147,642
226,236
118,584
176,576
159,021
159,021
318,042
73,070
73,070
127,457
64,436
Number of
ordinary
shares
vested
Vesting
date
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
246,359i
18 Feb 20
196,262j
196,262j
–
19 Feb 19
19 Feb 19
Face
value of
the award,
£
655,861d
655,861d
1,311,722d
1,015,283e
1,015,283e
2,030,565e
696,870f
696,870f
1,330,268g
636,796h
–
–
–
–
1,170,395e
86,176i
18 Feb 20
–
–
–
–
–
–
–
344,890f
749,447g
346,021h
At 1 Jan
2019
147,054
147,054
294,108
275,892
275,892
551,784
147,642
147,642
a Since 2010, vesting of the deferred shares has been subject to a safety and environmental sustainability hurdle. 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 SESAC. 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 Bob Dudley has voluntarily agreed to defer vesting of these awards until the later of one year post employment or the end of the relevant performance period, therefore the performance
period will exceed the minimum term of three years.
d The face value has been calculated using the market price of ordinary shares on 11 February 2015 of £4.46.
e The face value has been calculated using the market price of ordinary shares on 4 March 2016 of £3.68.
f The face value has been calculated using the market price of ordinary shares on 19 May 2017 of £4.72.
g The face value has been calculated using the market price of ordinary shares on 22 May 2018 of £5.88.
h The face value has been calculated using the market price of ordinary shares on 19 February 2019 of £5.37
i 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 18 February 2020 was £4.54.
j 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 19 February 2019 was £5.38. These totals include the accrual of dividends which
vested on 3 May 2019.
k Brian Gilvary has voluntarily agreed to defer vesting of these matching awards for a total of five years with a further one-year retention period.
l Brian Gilvary has voluntarily agreed to defer vesting of this matching award to at least one year post employment.
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 option plans (audited)
Option type
At 1 Jan
2019
Granted
Exercised
Brian Gilvary
BP 2011b
400,000
SAYE
SAYE
3,103
–
–
–
2,064
–
3,103
–
a The closing market prices of an ordinary share on 31 December 2019 was £4.72.
During 2019 the highest market price was £5.83 and the lowest market price was £4.62.
At 31 Dec
2019a
400,000
–
2,064
Option
price
£3.72
£2.90
£4.36
Market price
at date of
exercise
Date from
which first
exercisable
Expiry
date
–
07 Sep 14
07 Sep 2021
£5.07
01 Sep 19
28 Feb 2020
01 Sep 22
28 Feb 2023
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.
Bob Dudley and Brian Gilvary have no interests in BP preference shares, debentures or option plans (other than as listed above), and no interests in
shares or loan stock of any subsidiary company.
No directors or other senior managers own more than 1% of the ordinary shares in issue. At 3 March 2020, our directors and senior managers
collectively held interests of 19,004,688 ordinary shares or their calculated equivalents, 7,699,795 restricted share units (with or without
conditions) or their calculated equivalents, 8,542,463 performance shares or their calculated equivalents and 4,299,972 options over ordinary
shares or their calculated equivalents, under BP group share option schemes.
BP Annual Report and Form-20F 2019
115
Directors’ remuneration report
Post employment share ownership interests
As we reported last year, Bob Dudley and Brian Gilvary will retain significant interests in BP post employment. They have given their personal
commitment as executive directors to maintain actual holdings equivalent to two and a half times salary for two years post employment. The
commitment is guaranteed by the fact that their anticipated interests in share awards under group plans which remain subject to vesting and/or holding
periods at the time they leave BP exceed the two and a half times salary threshold. Although we are instituting a formal post employment share
ownership requirement as part of our 2020 policy, given the foregoing, we see no need to modify the commitments of these outgoing executives.
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 2019, Helge Lund had the use of a fully
maintained office for company business, a car and driver, and security advice in London. The table below shows the fees paid for the year ended
31 December 2019.
2019 remuneration (audited)
£ thousand
Helge Lundc
Carl-Henric Svanberge
2019
785
–
Fees
2018
46
785
2019
95d
–
Benefitsa
2018
122d
24
2019
880
–
Totalb
2018
169
809
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.
b Due to rounding, the totals may not agree exactly with the sum of the component parts.
c Appointed as a director on 26 July 2018 and as chairman on 1 January 2019.
d Benefits include relocation expenses.
e Resigned on 31 December 2018.
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 2019, as a percentage of the shareholding policy, were 361%.
Helge Lund
Ordinary shares
or equivalents at
Ordinary shares
or equivalents as
Changes from
31 Dec 2019 to
1 Jan 2019
31 Dec 2019
3 Mar 2020
Ordinary
shares or
equivalents at
3 Mar 2020
600,000
600,000
–
600,000
Non-executive directors’ fee structure
The table below shows the fee structure for non-executive directors, per our 2017 policy.
Senior independent directora
Board member
Audit, geopolitical, remuneration and SESA committees chairmanship feesb
Committee membership feec
Intercontinental travel allowance
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, SESA and remuneration committees.
Fees
£ thousand
120
90
30
20
5
116
BP Annual Report and Form-20F 2019
Corporate governance
2019 remuneration (audited)
£ thousand
Nils Andersen
Alan Boeckmannc
Admiral Frank Bowmanc
Dame Alison Carnwathd
Pamela Daleye
Sir Ian Davis
Professor Dame Ann Dowlingf
Melody Meyer
Brendan Nelson
Paula Rosput Reynolds
Sir John Sawers
2019
161
68
74
115
164
165
140
152
150
170
145
Fees
2018
132
155
160
74
55
170
158
160
150
166
150
2019
Benefitsa
2018
11
6
6
33
37
5
3
16
11
36
1
11
10
14
47
42
2
2
26
12
33
1
2019
172
74
80
148
201
170
143
168
161
206
146
Totalb
2018
144
165
174
121
97
172
159
186
162
200
151
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 the component parts.
c Resigned on 21 May 2019.
d Appointed 21 May 2018.
e Appointed 26 July 2018.
f Fee includes £25,000 for chairing and being a member of the BP technology advisory council.
Non-executive director fees are reviewed on a regular basis and were last changed in 2012. This year, following a review of the increasing time
commitment associated with the role and taking into account non-executive director fees against those of comparable UK listed companies, the
fee structure below will be adopted from 1 June 2020.
Senior independent directora
Board member
Audit, geopolitical, remuneration and SESA committees chairmanship feesb
Committee membership feec
Fees
£ thousand
155
115
35
20
a The senior independent director is eligible for committee chairmanship fees plus any committee membership fees, excluding the nomination and governance committee.
b Committee chairmen do not receive an additional membership fee for the committee they chair.
c A membership fee is not payable for the chairman’s committee.
The board has decided to remove the intercontinental travel allowance to simplify the structure of non-executive director fees, although under
the proposed policy it retains the flexibility to reintroduce such an allowance. In addition, following a review of the time commitment required, a fee
of membership of the nomination and governance committee will be introduced in line with other committee membership fees to compensate for
the increased time commitment. The senior independent director will not be eligible for this fee and no fee is payable for chairing the nomination
and governance committee.
Non-executive directors’ interests
The figures below indicate and include all the beneficial and non-beneficial interests of each non-executive director of the company in shares of BP
(or calculated equivalents) that have been disclosed to the company under the DTRs as at the applicable dates.
Nils Andersen
Alan Boeckmannb
Admiral Frank Bowmanb
Dame Alison Carnwath
Pamela Daley
Sir Ian Davis
Professor Dame Ann Dowling
Melody Meyer
Brendan Nelson
Paula Rosput Reynolds
Sir John Sawers
Ordinary shares
or equivalents at
Ordinary shares
or equivalents at
Changes from
31 Dec 2019 to
Ordinary shares
or equivalents at
1 Jan 2019
31 Dec 2019
3 Mar 2020
3 Mar 2020
Value of current
shareholdinga
125,000
125,000
44,812cd
24,864c
17,700
17,592c
50,296
22,320
20,646c
11,040
73,200c
15,030
17,700
17,592c
52,671
22,320
20,646c
11,040
73,200c
15,506
–
–
–
–
–
–
–
–
6,494
125,000
£518,750
17,700
17,592c
52,671
22,320
20,646c
11,040
73,200c
22,000
£73,455
$93,589
£218,585
£92,628
$109,837
£45,816
$389,424
£91,300
% of policy
achieved
576%
82%
82%
243%
103%
96%
51%
339%
101%
a Based on share and ADS prices at 3 March 2020 of £4.15 and $31.92.
b Resigned on 21 May 2019.
c Held as ADSs.
d Amended from 44,772 as originally disclosed in the 2018 report.
BP Annual Report and Form-20F 2019
117
Directors’ remuneration report
Other disclosures
Payments for loss of office and payments to past
directors (audited)
We made no payments for loss of office during or in respect of 2019
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 2019, he received £100,000 for this role. Other than this,
we made no payment to any past director of BP during 2019 (we have
no de minimis threshold for such disclosures).
Historical TSR performance
250
200
150
100
50
0
2010
BP
FTSE 100
2013
2016
2019
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 2009 to
31 December 2019.
Freshfields Bruckhaus Deringer LLP (‘Freshfields’) 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; global mobility; internal audit
subject matter expertise; cyber security risk reviews; tax modernization;
low carbon strategy consulting; digital, data analytics and IT
implementation services.
Shareholder engagement
Throughout 2019 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 2020, as we
consider updates to our remuneration policies for 2020 and beyond.
The table below shows the votes on the report for the last three years.
AGM directors’ remuneration report vote results
Year
2019
2018
2017
% vote
‘for’
95.93%
96.42%
97.05%
% vote
‘against’
4.07%
3.58%
2.95%
Votes
withheld
337,586,814
42,741,541
63,453,383
The remuneration policy was approved by shareholders at the 2017 AGM
on 17 May 2017. The votes on the policy are shown below.
2017 AGM directors’ remuneration policy vote results
Year
2017
% vote
‘for’
97.28%
% vote
‘against’
Votes
withheld
2.72%
36,563,886
Independence and advice
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 2019 are shown below.
Director
Bob Dudley
Appointee
company
Rosnefta
Additional position held at
appointee company
Director
Total fees
0
Brian Gilvary
Air Liquide SA
Non-executive director
Euros 77,500
a Bob Dudley holds this appointment as a result of the company’s shareholding in Rosneft.
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 101.
During 2019 Hannah Ashdown and, from his appointment as company
secretary on 7 May 2019, Ben Mathews, 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 2019, following its appointment
as independent adviser to the committee in September 2017, following
a competitive tender process. None of PwC’s consultants advising the
BP remuneration committee have any connection with the company’s
directors. Advice included, for example, support with the remuneration
policy review and remuneration benchmarking. 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. Total fees or other charges (based on an hourly rate) for
the provision of remuneration advice to the committee in 2019 (save in
respect of legal advice) were £144,175 to PwC.
118
BP Annual Report and Form-20F 2019
Directors’ remuneration report – the 2020 policy
Corporate governance
In this part of our report we set out our directors’ remuneration policy for 2020 and subsequent years (the ‘2020 policy’). We will present this 2020
policy to shareholders at the 2020 annual general meeting and, subject to shareholder approval, it will take effect for the 2020 financial year.
Remuneration principles
In preparation for the review of our directors’ remuneration policy, the committee gave deep consideration to the changing reward frameworks for
the wider workforce, alongside our more specific debates on executive remuneration. All of this is in the context of a changing business model as
we evolve to meet and contribute to the low carbon energy transition. From this, we have drawn a unifying set of remuneration principles that
apply equally to executives, and to employees at all levels of our workforce hierarchy.
Alignment
Our remuneration programmes will align with BP’s strategic priorities, long-term success and shareholders’ experience.
In delivering our remuneration programmes across the globe we will reflect the policies and practices of the respective markets in
which we operate.
Competitiveness
Total remuneration will be competitive for the role taking into account scale, sector, complexity of responsibility and geography.
When setting senior executive pay, we will consider both external pay relativity and wider workforce remuneration and conditions.
Pay for performance
We promote a culture where all employees are accountable for delivering performance .
Depending on the level of the individual in the organization, we use variable pay to incentivize delivery against performance.
Pay will be delivered with an emphasis on long-term equity in line with seniority.
Performance measures and targets will seek to balance collective BP success with clear line of sight for participants.
Remuneration outcomes aim to reflect sustained long-term underlying performance of BP. Factors beyond the control of management
will be adjusted in determining final outcomes.
Judgement
Sustainability
We will use discretion and judgement to review formulaic performance outcomes to arrive at fair and balanced remuneration outcomes for
both BP and employees.
Remuneration programmes will support the development of a long-term sustainable business informed by environmental, societal and
other inputs.
Performance targets and measures will typically be chosen with due regard to incentives for prudent risk taking.
Individual contribution and values and behaviours will be reflected in remuneration outcomes.
Consideration of shareholder views
We have reflected on the valuable shareholder engagement exercise that led to the significant changes from our 2014 to 2017 policy. In our view,
those changes have stood up well over the last three years, have delivered remuneration outcomes that align to shareholders’ own experience, and
have encouraged strategic decisions appropriate for the long term. Notably, the current 2017 policy also corresponds well to our recently concluded
remuneration principles, shown above.
Throughout 2019 we consulted widely with shareholder representatives individually and collectively. In particular through a constructive listening
session with our largest shareholders in September 2019, we identified four broad themes for our future policy direction:
• Clear end-to-end alignment from strategy, through measurable performance indicators and reward outcomes, to shareholder experience
• Balance our contribution to the energy transition with delivering shareholder returns. The committee was encouraged to use appropriate
discretion, given the complexity of the environment in the energy transition
• Assure that strategic moves align to long-term sustainability, relative to a wide peer group
• Use meaningful and transparent measures to reflect our progress in the energy transition and reductions to our carbon impact.
We have concluded that the strongly performance-oriented reward model that has served us well in recovery from the aftermath of the 2010
Deepwater Horizon oil spill, and particularly the structure of our 2017 policy, broadly remains the right frame as we look ahead to the equally great
challenge of reducing our carbon footprint. The 2020 policy set out below therefore retains and builds upon the 2017 policy structure, and thus
commands the advantage of being well-understood and accepted by our executives and wider workforce alike.
BP Annual Report and Form-20F 2019
119
Directors’ remuneration report – 2020 policy
Policy table – executive directors
Salary and benefits
Purpose
Operation and
opportunity
To provide fixed remuneration to reflect the scale and complexity of both the business and the role, and to be competitive with the
external market.
Salary
Salary levels will relate to the nature of the role, performance
of the business and the individual, market positioning and pay
conditions in the wider BP group. There is no maximum salary
under the policy.
Benefits
Executive directors are entitled to receive those benefits available
to all BP employees generally, such as participation in all-employee
share plans, sickness pay, relocation assistance and parental leave.
Benefits are not pensionable.
When setting salaries, the committee considers practice in other
oil and gas majors as well as European and US companies of a
similar size, geographic spread and business dynamic to BP. The
committee will consider salary increases for the most senior
management and the wider workforce. In particular, percentage
increases for executive directors will not exceed increases for the
broader employee population, other than in specific circumstances
identified by the committee (e.g. in response to a substantial
change in responsibilities).
Salaries are normally set in the home currency of the executive
director and are reviewed annually. They may be reviewed at other
times where appropriate, for example following a major role change.
Executive directors may receive other benefits that are judged to
be cost effective and appropriate in terms of the individual’s role,
time and/or security. These include car-related benefits or cash
in lieu, security, assistance with tax return preparation, insurance
and medical benefits. The company may meet any tax charges
arising on business-related benefits provided to directors, for
example security.
The taxable value of benefits provided may fluctuate during the
period of this policy, depending on the cost of provision and a
director’s personal circumstances.
In general, the committee expects to maintain benefits at the
current level.
Performance
framework
Not applicable
Retirement benefits
Purpose
To recognize competitive practice in home country.
Operation and
opportunity
Executive directors normally participate in the company retirement
plans that operate in their home country.
For future appointments, the committee will carefully review any
retirement benefits to be granted to a new director, taking account
of retirement policies across the wider group and any arrangements
currently in place. Specifically, the committee will be sensitive to
investor concerns over pensions for directors, and limit pension
contribution rates to no more than the median allowance offered to
the wider workforce in the UK (as a percentage of salary).
Retirement benefits are not directly linked to performance.
Performance
framework
Annual bonus
Purpose
Current executives (including designates) in BP have been
employees of the group for a number of years and remain as
participants in long-standing arrangements in which other similarly
situated employees continue to participate.
UK participants will become deferred pensioners of the company’s
defined benefit plan. They will receive a cash supplement in lieu of
further service accrual under the plan.
To provide variable remuneration dependent on performance against annual financial, operational, safety and environmental measures.
50% of the bonus is paid in cash and 50% is mandatorily deferred and held in BP shares for three years to reinforce the long-term nature
of the business and the importance of sustainability.
Operation and
opportunity
The bonus is based on performance against annual measures and
targets set at the start of the year, evaluated over the financial year
and assessed following the year end.
The target annual bonus is half of the maximum available, and relates
to delivery of performance in line with targets in the annual plan.
Executive directors may earn a maximum annual bonus of 225%
of salary. This maximum level would relate to performance at or
above the highest end of the performance scale for every measure.
The committee intends to set demanding requirements for
maximum payment.
The final bonus outcome, following the formulaic assessment of
performance relative to targets, is specifically reserved as a matter
for the committee’s judgement. Accordingly, the committee may
exercise its discretion to adjust the formulaic outcome either
upwards or downwards.
Half the bonus is paid in cash, and half is deferred into BP shares
for three years. Dividends (or equivalents, including the value of any
reinvestment) may accrue in respect of any deferred shares.
Awards are subject to malus and clawback provisions as described
on page 123.
120
BP Annual Report and Form-20F 2019
Corporate governance
Performance
framework
The committee determines a scorecard of specific measures,
weightings and targets each year to reflect the priorities
in the annual plan. The scorecard is designed to deliver the
group’s strategy.
The scorecard will typically include a balance of financial,
operational, environmental and safety measures. Details of the
measures and weighting will be reported in advance each year in
the annual report on remuneration, while targets will be disclosed
retrospectively.
The committee holds discretion to choose the specific measures
and weightings to be adopted within each of these categories to
better reflect the annual plan as agreed with the board.
Performance shares
Purpose
To link the largest part of remuneration opportunity with the long-term performance of the business. The outcome varies with
performance against measures of relative total shareholder return (rTSR), return on average capital employed (ROACE) and an assessment
related to the low carbon transition.
Operation and
opportunity
The maximum annual award level for the chief executive officer will
be 500% of salary and 450% of salary for the chief financial officer.
Annual awards of shares will vest based on performance relative to
measures and targets that reflect the delivery of BP’s strategy over
a performance period of typically three years.
For each measure, the threshold level at which vesting is
first triggered is not expected to yield vesting above 25% of
the maximum.
The final performance shares outcome, following the formulaic
assessment of performance relative to targets, is specifically
reserved as a matter for the committee’s judgement. Accordingly,
the committee may exercise its discretion to adjust the formulaic
outcome either upwards or downwards.
The shares that vest are subject to a holding period. The combined
length of the performance and holding periods will normally be
six years.
Dividends (or equivalents, including the value of reinvestment) may
accrue in respect of share awards to the extent that they vest.
Awards are subject to malus and clawback provisions as described
on page 123.
Performance
framework
Performance shares vest relative to performance achieved against
a combination of financial and strategic measures.
For 2020 awards, the measures (weightings) will be:
• Relative total shareholder return (40%) assessed relative to
Chevron, Eni, Equinor Exxon, Repsol, Shell and Total
• Return on average capital employed (30%). This will be assessed
on a three-year average basis, with no adjustment for market
conditions
• Low carbon/energy transition (30%).
At the outset of each cycle the committee will review the
measures that are to govern the award, along with weightings and
targets, to ensure they remain focused on delivering the strategy
and are in the interests of shareholders.
For the relative assessment of total shareholder returns, the
committee will in time consider broadening the comparator set as
our own transition towards low carbon evolves.
We expect to outline specific measures for the low carbon / energy
transition element later this year. This will follow, and align with, the
strategy update planned for our capital markets day later this year.
The committee would consult appropriately with major
shareholders regarding any material changes to the measures.
The committee will assess safety outcomes over the perfomance
cycle as an underpin in determining the final vesting percentage.
Shareholding requirements
Purpose
To provide alignment between the interests of executive directors and our other shareholders.
Operation and
opportunity
The chief executive officer is required to build and maintain a
minimum shareholding of five times base salary within five years
of appointment, and to maintain that minimum shareholding for at
least two years post-retirement.
Other executive directors are required to build and maintain
a minimum shareholding of four and a half times base salary
within five years of appointment, and to maintain that minimum
shareholding for at least two years post-retirement.
Performance
framework
Not applicable.
BP Annual Report and Form-20F 2019
121
Directors’ remuneration report – 2020 policy
Notes to the policy table
1. New components and key changes from the 2017 policy
While the structure of the 2017 policy has been retained, the committee highlights the following key changes from 2017:
• A new requirement to limit the value of retirement benefits for service as an executive director. In practice, we do not expect to offer pension
contribution rates worth more than 15% of salary.
• The minimum shareholding requirement is clearly stated and continues to apply, in full, for two years post employment. This minimum
shareholding requirement is now formally adopted as part of the remuneration policy.
2. How is variable pay linked to performance?
Annual bonus
Bonus aligned with annual objectives
50% paid in cash; 50% in BP
shares deferred for 3 years
Performance
bonus
Share award for meeting three-year targets
6 years; 3 year performance period
+ 3 year holding period
Share ownership
Long-term shareholding
Built up over 5 years
and maintained
The three elements described above provide a balance between focus on short-term, medium-term and long-term performance, while encouraging
behaviours which are in the long-term interests of shareholders. The operation of variable pay is supported by a focus on stewardship. There is a
requirement that the chief executive officer will build up a holding of five times salary, and other executive directors a holding of four and a half times
salary, over a period of five years following appointment and maintain that level during employment and for a further two years post employment.
3. How are performance measures linked to strategy?
Variable pay is linked to performance measures designed to deliver the BP strategy. At the start of each year, the remuneration committee reviews
the measures, targets and weightings to ensure they remain consistent with the priorities in the annual plan and the group strategy. For the annual
bonus and performance shares, the approach to performance measurement is intended to provide a balance of measures to assess performance
reflecting the global scale of the business, the unique characteristics of the oil and gas sector, and the role our enterprise will play in advancing the
transition to lower carbon energy. The key changes from our 2017 policy, and a summary of measures for 2020 awards, are shown below:
• Weighting of the environment target in our annual bonus scorecard is doubled to 20%.
• Fewer measures in our annual bonus scorecard (from two to one on safety, from two to one on reliable operations, from three to two on financial
performance). Our 2020 financial performance on cash flow changes from operating cash flow to free cash flow.
• Weighting of the rTSR measure in our performance shares scorecard reduced to 40%. The comparator group has been expanded to include
Repsol, ENI and Equinor. The low carbon / energy transition category replaces strategic progress and weighting increases to 30%.
New remuneration policy measures for the period commencing in 2020
Annual bonus
Safety
20%
Environment
20%
Operational performance
10%
Financial performance
50%
Performance shares
Relative total shareholder return
40%
Return on average capital employment
30%
Low carbon / energy transition
30%
Underpin: Take into account safety outcomes prior to determining final vesting percentage.
Discretion to reflect shareholder experience, environmental, societal and other inputs.
Robust malus and clawback.
122
BP Annual Report and Form-20F 2019
Corporate governance
4. How will we use flexibility, judgement and discretion?
The committee reviews BP’s performance against specific measures and targets, and in doing so may make both quantitative and qualitative
assessments of performance in reaching its decisions. This involves the application of judgement and discretion, in which the committee also
seeks relevant input from the board’s audit and safety, environment and security assurance committees. Accordingly, the committee may decide
to adjust the formulaic outcome derived from the relevant scorecards, either upwards or downwards, to reflect broader considerations. The
committee continues to consider that the powers of flexibility, judgement and discretion are critical to the successful execution of the policy.
In framing the policy, the committee has taken care to ensure that these important powers continue to be available:
• Sufficient flexibility to take account of future changes in the industry environment and in remuneration practice generally. This allows the
committee to respond to changes in circumstances, for example in applying particular performance measures and/or weightings within the
plans, or in broadening the comparator group for the relative returns measure, in order to evolve with the company’s strategy, without the need
for specific shareholder approval.
• Power to exercise judgement in making a qualitative assessment in certain circumstances. A number of measures are used for annual or
long-term incentive awards, many of which are numerical in nature and require a quantitative assessment of performance. Others may require
a qualitative assessment, such as the low carbon / energy transition measures in the performance shares plan.
• Scope for the committee to exercise discretion, mainly where it is desirable to vary a formulaic outcome that would otherwise arise from
the policy’s implementation. The committee considers that the ability to exercise discretion, upwards or downwards, is important to ensure
that a particular outcome is fair in light of the director’s own performance, the company’s overall performance and positioning under particular
performance measures and outcomes for shareholders.
The committee intends to provide appropriate disclosure on the use of discretion so that shareholders can understand the basis for its decisions.
5. How will we safeguard against payments for failure?
Performance
based pay
A significant portion of remuneration varies with performance –
where performance targets are not achieved, lower or no payments
will be made under the plans.
Discretion
The committee may vary formulaic outcomes where these do not
suitably reflect performance over the relevant performance period.
Malus and clawback
The malus provisions enable the committee to reduce the size of
award, cancel an unvested award, or impose further conditions on
an award made under this policy.
The clawback provisions enable the committee to require
participants to return some or all of an award after payment or
vesting. They may be applied under the following circumstances:
The malus provisions may apply if, prior to the vesting or payment
of an award, there is a negative event such as:
• material failure impacting safety or environmental sustainability
• incorrect award outcomes due to miscalculation or based on
incorrect information
• restatement due to financial reporting failure or misstatement of
audited results
• material misconduct by the participant
• such other exceptional circumstances that the committee
consider to be similar in nature.
• incorrect outcomes due to miscalculation or based on incorrect
information
• restatement due to financial reporting failure or misstatement of
audited results
• material misconduct by the participant.
BP Annual Report and Form-20F 2019
123
Directors’ remuneration report – 2020 policy
6. Differences from remuneration policy in the wider group
This executive director remuneration policy is structurally similar to remuneration for the majority of the wider workforce, but naturally differs
in quantum reflecting market norms for the differing size and complexity of roles. Although performance assessment is a common feature
for executive and wider workforce remuneration, the relative importance of different performance measures changes in line with seniority.
For instance, executive directors are subject to longer-term measures and no individual performance element, whereas the majority of the
wider workforce receive variable pay that is based on annual performance measures, including their own individual performance.
Illustrations of application of remuneration policy
The total remuneration opportunity for executive directors is strongly performance based and weighted to the long term. The charts below provide
scenarios for the total remuneration of executive directors at different levels of performance and are calculated as prescribed in UK regulations.
Bernard Looney
Brian Gilvary
Min
100%
£1.5m
Min
100%
£1.1m
Mid
25%
23%
52%
£6.3m
Mid
29%
24%
48%
£3.8m
Max
14%
27%
59%
£11.0m
Max
17%
28%
55%
£6.4m
Fixed pay
Annual bonus
Performance shares
Fixed pay
Annual bonus
Performance shares
Murray Auchincloss
Min
100%
£0.85m
Mid
27%
24%
49%
£3.2m
Max
15%
28%
56%a
£5.5m
Fixed pay
Annual bonus
Performance shares
a Due to rounding, the sum of the parts does not equal 100%.
The remuneration outcomes reported above reflect the face value of performance shares and therefore exclude the impact of potential share price
growth, as well as dividends. If share prices were to appreciate by 50% from face value, then the maximum remuneration receivable by Bernard
Looney, Brian Gilvary and Murray Auchincloss would increase to £14.2m, £8.2m and £7.1m respectively.
Fixed components
For these illustrations salary, benefits and pension are the same in all three scenarios (annual values shown).
Salary
CEO (Looney)
CFO (Gilvary)
£1,300,000
Bernard Looney’s salary from appointment on 5 February 2020.
£790,500
Brian’s salary, effective until his retirement from BP on 30 June 2020.
CFO (Auchincloss)
£695,000
Murray’s salary, effective from his appointment on 1 July 2020.
Benefits and
pension benefits
CEO (Looney)
CFO (Gilvary)
£245,000
Based on pension benefits at 15% of salary, with an estimated £50,000 total for other benefits.
£296,150
Based on Brian’s 30% cash in lieu of pension, plus the total of other benefits shown in the 2019
single figure table.
CFO (Auchincloss)
£154,250
Based on pension benefits at 15% of salary, with an estimated £50,000 total for other benefits.
Variable components
Variable pay under the policy comprises annual bonus and performance shares.
Scenario
Minimum
Mid
Maximum
Annual bonus
(including cash and
deferred elements)
Performance
shares
Threshold not met
Nil
50% of maximum
112.5% of salary
100% of maximum
225% of salary
Threshold not met
CEO – Nil
CFO – Nil
50% vesting
CEO – 250% of salary
CFO – 225% of salary
100% vesting
CEO – 500% of salary
CFO – 450% of salary
124
BP Annual Report and Form-20F 2019
7. Clarity, simplicity, and other considerations related to the
Corporate Governance Code
The committee consider the scorecard-based approach to setting
targets and measuring outcomes provides great clarity in our ability to
engage transparently with shareholders and the wider workforce on
remuneration arrangements, and that this is complemented by retaining
the simple structure of our 2017 policy; market aligned fixed pay with
annual cash and three-year performance share incentives. Risks are
managed through a combination of careful setting of performance
measures and targets, the many options to apply committee discretion
in assessing outcomes, and the robust malus and clawback measures
reserved in this policy. The committee also considers that remuneration
outcomes are predictable, as shown clearly in the scenario charts at note
6 above, and proportional by virtue of the challenging performance levels
required to achieve target pay outcomes. By retaining material weighting
in measures related to both safety and the environment, this policy
aligns closely with central themes of BP’s culture, purpose and ambition.
Recruitment policy
The committee expects any new executive director to be engaged on
terms that are consistent with the policy. However it recognizes that it
cannot anticipate circumstances in which any new executive director may
be recruited. The committee may determine that it is in the interests of
the company and shareholders to secure the services of a particular
individual which may require it to take account of the terms of that
individual’s existing employment and/or their personal circumstances.
Accordingly, the committee will ensure that:
• The salary level of any new director is appropriate to their role and
the competitive environment at the time of appointment. Where
appropriate it may appoint an individual on a lower salary (relative to
any previous incumbent), then gradually increase salary levels as the
individual gains experience in the role.
• Variable remuneration will be awarded within the parameters of
the policy for current executive directors.
• The committee may tailor the vesting criteria for initial incentive
awards depending on the specific circumstances.
• Where an existing employee is promoted to the board, the company
may honour all existing contractual commitments including any
outstanding share awards or pension entitlements.
• The committee would expect any new director to participate
in the company pension and benefit schemes that are open to
other employees (where appropriate referencing the candidate’s
home country).
• Where an individual is relocating in order to take up the role, the
company may provide certain one-off benefits such as reasonable
relocation expenses, accommodation for a period following
appointment, assistance with visa applications or other immigration
issues and ongoing arrangements such as tax filing assistance,
annual flights home and a housing/utilities allowance.
• Where an individual would be forfeiting remuneration or employment
terms in order to join the company, the committee may award
appropriate compensation. The committee would require reasonable
evidence of the nature and value of any forfeited arrangements and
would, to the extent practicable, ensure any compensation was of
comparable commercial value and capped as appropriate, considering
the terms of the previous arrangement being forfeited (for example
the form and structure of award, timeframe, performance criteria and
likelihood of vesting). Where appropriate, the committee prefers to
deliver buy-outs in the form of restricted shares in the company.
In making any decision on the remuneration of a new director, the
committee would balance shareholder expectations, current best
practice and the circumstances of any new director. It would strive not
to pay more than is necessary to recruit the right candidate and would
give full details in the next remuneration report.
Corporate governance
Service contract
Bob Dudley’s service contract is with BP Corporation North America
Inc., Bernard Looney’s and Brian Gilvary’s service contracts are with
BP p.l.c., and Murray Auchincloss’ service contract will be with BP p.l.c.
Each executive director is entitled to retirement benefits as outlined on
page 120.
Each executive director is also entitled to the following contractual
benefits:
• If appropriate for security reasons, a company car and driver is
provided for business and private use, with the company bearing
all normal employment, servicing, insurance and running costs.
Alternatively, where not required for security reasons, a cash
allowance may be paid instead.
• Medical and dental benefits, sick pay during periods of absence and
assistance with the preparation of tax returns.
• Indemnification in accordance with applicable law.
• Participation in bonus or incentive arrangements at the committee’s
sole discretion.
Each executive director may terminate their employment by giving
12 months’ written notice. In this event, for business reasons, the
employer may not necessarily hold the executive director to their full
notice period.
The employer may lawfully terminate the executive director’s
employment in the following ways:
• By giving the director 12 months’ written notice.
• Without compensation, in circumstances where the employer is
entitled to terminate for cause, as defined for the purposes of their
service contract.
The company may lawfully terminate employment by making a lump
sum payment in lieu of notice equal to 12 months’ salary or by monthly
instalments rather than as a lump sum.
The lawful termination mechanisms described above are without
prejudice to the employer’s ability in appropriate circumstances to
terminate in breach of the notice period referred to above, and thereby
to be liable for damages to the executive director.
In the event of termination by the company, each executive director
may have an entitlement to compensation in respect of their statutory
rights under employment protection legislation in the UK and potentially
elsewhere. Where appropriate the company may also meet a director’s
reasonable legal expenses in connection with either their appointment
or termination of their appointment.
Copies of the executive directors’ service contracts, along with the
non-executive director appointment letters, are available for inspection
at the registered office of BP p.l.c.
BP Annual Report and Form-20F 2019
125
Directors’ remuneration report – 2020 policy
Termination payments
In determining overall termination arrangements, the committee will distinguish between types of leaver and the circumstances of their leaving.
The committee would also consider all relevant circumstances, including whether a contractual provision in the director’s arrangements complied
with best practice at the time of termination and the date the provision was agreed, as well as the performance of the director in certain respects.
Where appropriate, the committee may consider providing certain benefits relating to termination including the provision of outplacement support
or reasonable costs associated with relocation back to an individual’s home country. Should it become necessary to terminate an executive
director’s employment, and therefore to determine a termination payment, the committee’s policy is as follows:
Termination
payments
Annual bonus
Share awards
The director’s primary entitlement would be a termination payment
in respect of their service agreement, as set out above. However
the committee will consider mitigation to reduce the termination
payment where appropriate to do so, taking into account the
circumstances for leaving and the terms of the agreement.
Mitigation would not be applicable where a contractual payment
in lieu of notice is made.
If the departing director is eligible for an early retirement pension,
the committee would consider, if relevant under the terms of the
appropriate plan, the extent of any actuarial reduction that should be
applied. UK directors who leave in circumstances approved by the
committee may have a favourable actuarial reduction applied to their
pensions (which to date has been 3%). Departing directors who
leave in other circumstances may be subject to a greater reduction.
The committee would consider whether the director should be
entitled to an annual bonus in respect of the financial year in which
the termination occurs.
Normally, any such bonus would be restricted to the director’s
actual period of service in that financial year.
Share awards will be treated in accordance with the relevant plan
rules. For awards granted under the executive directors’ incentive
plan (EDIP), the treatment can only be made in accordance with the
framework approved by shareholders.
The committee would consider whether conditional share awards
held by the director should lapse on leaving or should, at the
committee’s discretion, be preserved. If awards are preserved,
the award would normally continue until the vesting date. Awards
may be pro-rated based on service over the performance period.
In deciding whether to exercise discretion to preserve EDIP
awards, the committee would also consider the proximity of the
award to its maturity date.
To the extent that any such share award vests, the release of those
shares to the former director will be made approximately one year
after their date of termination (even if they would have been subject
to a longer holding period had the executive remained in
employment with BP).
Legacy arrangements and other detailed provisions
Previously the deferred element of the annual bonus in respect of years up to and including 2016 attracted a corresponding award of matching
shares. Although the committee no longer grants matching awards in respect of future bonus awards, executives retain interests in legacy awards
previously granted under this arrangement under the terms set out in the 2014 policy.
For completeness, the table below summarizes the key terms of the previous matching share element.
Purpose
Operation
To reinforce the long-term nature of the business and the importance of sustainability.
Previously one third of the annual bonus was subject to compulsory
deferral and a further third was subject to voluntary deferral.
Where shares vest, additional shares representing the value of
reinvested dividends are added.
These deferred shares were matched on a one-for-one basis.
Performance
framework
Both deferred and matching shares must pass an additional hurdle
related to safety and environmental sustainability performance in
order to vest.
All deferred shares are subject to clawback provisions if they are
found to have been granted on the basis of a material misstatement
of financial or other data.
If there has been a material deterioration in safety and
environmental metrics, or major incidents revealing underlying
weaknesses in safety and environmental management then the
committee, with advice from the board’s safety, environment and
security assurance committee, may conclude that shares vest in
part, or not at all.
In addition to the award described above, the committee may continue to satisfy existing remuneration commitments and/or payments for loss of
office, including the exercise of any discretion in connection with such payments provided that such terms were agreed:
• before 10 April 2014 when the first approved remuneration policy came into effect
• before the 2020 policy came into effect, provided that the terms of the payment were consistent with the shareholder-approved directors’
remuneration policy in force at the time they were agreed
• at a time when the relevant individual was not a director of the company and, in the opinion of the committee, the payment was not in
consideration for the individual becoming a director.
Share awards are subject to the terms of the relevant plan rules under which the award has been granted. The committee may adjust or amend
awards, but only in accordance with the provisions of the plan rules. This includes making adjustments to awards to reflect one-off corporate
events, such as a change in the company’s capital structure or treatment of awards in the event of a change of control. In accordance with the plan
rules, awards may be settled in cash rather than shares, where the committee considers this appropriate.
The committee may make minor amendments to the policy to aid its operation or implementation without seeking shareholder approval, for
example for regulatory, exchange control, tax or administrative purposes or to take account of a change in legislation provided that any such change
is not to the material advantage of the directors.
126
BP Annual Report and Form-20F 2019
Corporate governance
Remuneration in the wider group
The committee considers employment conditions in the BP group when establishing and implementing policy for executive directors to ensure
the alignment of and context for principles and approach. In particular, the committee reviews the policy and makes decisions for the most senior leaders
(the BP leadership team that reports to the CEO). Decisions regarding remuneration for employees outside the most senior leaders are the responsibility of
the chief executive officer. The committee does not consult directly with employees when formulating the policy. However, feedback from employee focus
groups and employee surveys, that are regularly reported to the board, provide views on a wide range of employee matters including pay.
The wider employee group participates in performance-based incentives. Throughout the group, salary and benefit levels are set in accordance
with the prevailing relevant market conditions and practice in the countries in which employees are based. Differences between executive director
pay policy and that of other employees reflect the senior position of the individuals, prevailing market conditions and corporate governance
practices in respect of executive director remuneration. The key difference in policy for executive directors is that a greater proportion of total
remuneration is delivered as performance-based incentives.
Policy table – non-executive directors
The following table sets out the framework that will be used to determine the fees for non-executive directors during the term of this policy.
Non-executive chairman
Fees
Approach
Remuneration is in the form of cash fees, payable monthly. The level and structure of the chairman’s remuneration will primarily be
compared against UK best practice.
Operation and
opportunity
The quantum and structure of the non-executive chairman’s remuneration is reviewed annually by the remuneration committee, which
makes a recommendation to the board.
Benefits and expenses
Approach
Operation and
opportunity
Non-executive directors
Fees
Approach
The chairman is provided with support and reasonable travelling expenses.
The chairman is provided with an office and full-time secretarial and administrative support in London and a contribution to an office
and secretarial support in his home country as appropriate. A car and the use of a driver is provided in London, together with security
assistance. All reasonable travelling and other expenses (including any relevant tax) incurred in carrying out his duties is reimbursed.
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 CEO and the company secretary who
make a recommendation to the board. Non-executive directors do not vote on their own remuneration.
Intercontinental allowance
Remuneration for non-executive directors is reviewed annually.
Approach
Operation and
opportunity
Benefits and expenses
Approach
Non-executive directors may receive an allowance to reflect the global nature of the company’s business. This allowance would be
payable for the purpose of attending board or committee meetings or site visits.
This allowance would be 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.
Operation and
opportunity
Non-executive directors are reimbursed for all reasonable travelling and subsistence expenses (including any relevant tax) incurred in
carrying out their duties. Professional fees incurred by non-executive directors based outside the UK in connection with advice and
assistance on UK tax compliance matters are reimbursed.
Shareholding guidelines
Approach
Non-executive directors are encouraged to establish a holding in BP shares of the equivalent value of one year’s base fee.
Letters of appointment for chairman and non-executive directors
Approach
The chairman and non-executive directors each 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 in line with best governance practice. There are no obligations arising from the
non-executive directors’ letters of appointment for remuneration or payments for loss of office, except for the chairman whose
appointment may be terminated in the following ways:
• by either party giving three months’ written notice, or
• by the company for cause (as set out in the letter of appointment) and without compensation.
The company may lawfully terminate the appointment by making a lump sum payment in lieu of notice equal to three months’ fees.
Copies of the executive directors’ service contracts and non-executive directors’ letters of appointment are available for inspection at the
registered office of the company.
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 Ben J.S. Mathews, company secretary on 18 March 2020.
BP Annual Report and Form-20F 2019
127
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.
This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
128
BP Annual Report and Form 20-F 2019
• 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
18 March 2020
Risk management and internal control
Under the UK Corporate Governance Code 2018 (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 chief executive officer to operate
the company with a comprehensive system of controls and internal
audit to identify and manage the risks including emerging 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
O of the Code.
The board has processes in place to:
• Assess the principal and emerging risks facing the company.
• Monitor the company’s system of internal control (which includes
the ongoing process for identifying, evaluating and managing the
principal and emerging 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 and emerging 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 70.
During the year, the board undertook a robust assessment of the
principal and emerging 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 68.
In assessing the risks faced by the company and monitoring the system
of internal control, the board and the audit, safety, environment and
security 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 90-99, 101.
During the year, the committees as relevant 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 2020 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.
Corporate governance
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 2020, 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 322.
Longer-term viability
In accordance with provision 31 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 70, 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 significant process safety incident when operating facilities, drilling
wells or transportation of hydrocarbons;
• a sustained significant oil price decline;
• a significant cyber-security incident; and
• a loss of a significant market or asset.
The risks associated with the transition to a lower carbon economy and
a global pandemic are embedded in these scenarios.
In assessing the prospects of the company, the directors noted that
such assessment is subject to a degree of uncertainty that can be
expected to increase looking out over time and, accordingly, that future
outcomes cannot be guaranteed or predicted with certainty.
Going concern
In accordance with provision 30 of the Code, the directors consider it
appropriate to adopt the going concern basis of accounting in preparing
the financial statements.
Fair, balanced and understandable
The board considers the annual report and financial statements, taken
as a whole, is fair, balanced and understandable and provides the
information necessary for shareholders to assess the company’s
position and performance, business model and strategy.
This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
BP Annual Report and Form 20-F 2019
129
Energy with purpose means
transforming while performing.
Energy with purpose
BPX Energy:
Delivering synergies
We have been transforming BPX Energy,
our US onshore oil and gas business,
with the purchase of world-class
unconventional assets from BHP.
• The acquisition gave us access to
some of the best basins in the
onshore US, with 487,000 acres of
leasehold across a new position in the
liquids-rich Permian-Delaware basin,
and two positions in the Eagle Ford
and Haynesville basins.
• It positions BP as a top producer in
the region.
Good progress
Since we began operating the assets,
we have delivered synergies of
$240 million in 2019, above our
planned target of $90 million.
130
BP Annual Report and Form 20-F 2019
Financial statements
Consolidated financial statements of the BP group
Independent auditor’s reports
Group income statement
Group statement of comprehensive income
Notes on financial statements
1. Significant accounting policies
2. Non-current assets held for sale
3. Business combinations and other
significant transactions
4. Disposals and impairment
5. Segmental analysis
6. Revenue from contracts with customers
7.
Income statement analysis
8. Exploration expenditure
9. Taxation
10. Dividends
11. Earnings per share
12. Property, plant and equipment
13. Capital commitments
14. Goodwill
15. Intangible assets
16. Investments in joint ventures
17. Investments in associates
18. Other investments
19. Inventories
20. Trade and other receivables
21. Valuation and qualifying accounts
132
152
153
157
173
174
175
177
180
180
181
181
184
184
186
187
187
188
189
189
191
191
192
192
Group statement of changes in equity
Group balance sheet
Group cash flow statement
22. Trade and other payables
23. Provisions
154
155
156
193
193
24. Pensions and other post-retirement benefits 194
25. Cash and cash equivalents
26. Finance debt
27. Capital disclosures and net debt
28. Leases
29. Financial instruments and financial
risk factors
30. Derivative financial instruments
31. Called-up share capital
32. Capital and reserves
33. Contingent liabilities
200
200
201
202
202
207
215
216
219
34. Remuneration of senior management
220
and non-executive directors
35. Employee costs and numbers
36. Auditor’s remuneration
37. Subsidiaries, joint arrangements
and associates
221
221
222
38. Condensed consolidating information
223
on certain US subsidiaries
Supplementary information on oil and natural gas (unaudited)
Oil and natural gas exploration
and production activities
233
Movements in estimated net proved reserves
239
Standardized measure of discounted future
net cash flows and changes therein relating
to proved oil and gas reserves
254
Operational and statistical information
257
Parent company financial statements of BP p.l.c.
Company balance sheet
Company statement of changes in equity
Notes on financial statements
1. Significant accounting policies
2.
Investments
3. Receivables
4. Pensions
5. Payables
6. Taxation
7. Called-up share capital
8. Capital and reserves
9. Financial guarantees
10. Share-based payments
11. Auditor’s remuneration
12. Directors’ remuneration
13. Employee costs and numbers
14. Related undertakings
260
261
262
262
265
265
265
269
269
270
270
271
271
271
271
272
273
BP Annual Report and Form 20-F 2019
131
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 2019 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 Financial Reporting Standard (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 the:
• 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 accounting 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 reporting framework that has been applied in the preparation of the
parent company financial statements is applicable law and United Kingdom Accounting Standards, including FRS 101 “Reduced Disclosure
Framework” (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. The non-audit services provided to the
group and parent company for the year are disclosed in note 36 to the financial statements. 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 are as follows:
• Potential impact of climate change and the energy transition (impacting PP&E, goodwill, intangible assets and
provisions);
• Impairment of upstream oil and gas property, plant and equipment (PP&E) assets;
• Impairment of exploration and appraisal assets (included within 'intangible assets' in the Group balance sheet);
• Accounting for structured commodity transactions (SCTs) within the integrated supply and trading (IST) function,
and the valuation of other level 3 financial instruments (potentially impacting all financial statement accounts, in
particular finance debt);
• IT controls relating to financial systems (potentially impacting all financial statement accounts); and
• Management override of controls (potentially impacting all financial statement accounts).
These key audit matters are consistent with those we identified in the prior year except that:
• This year we identified the potential impact of climate change and the energy transition as a key audit matter, given
the significant increase in focus on this issue by management and by external stakeholders, and the potential impact
on the financial statements as a consequence.
• In our report for the year ended 31 December 2018 we identified the accounting for acquisitions and disposals
within the upstream segment as a key audit matter, in large part as a consequence of the accounting complexities
surrounding the $10.3 billion acquisition of BHP Billiton assets in the US. During the current year, there were no
material acquisitions and there were fewer significant accounting complexities and judgements in the disposal
transactions undertaken by BP. Accordingly, we did not identify this as a key audit matter for 2019.
We have set materiality for the current year at $850 million (2018 $750 million) based on profit before tax, profit before
impairment charges and tax, and underlying replacement cost profit before interest and tax.
Our scope covered 263 components. Of these, 179 were full-scope audits and the remaining 84 were subject to
specific procedures on certain account balances by component audit teams or the group audit team. These covered
81% of group revenue and 75% of PP&E.
Changes in our key
audit matters since
the prior year
Materiality
Scoping
This page does not form part of BP's Annual Report on Form 20-F as filed with the SEC.
132
BP Annual Report and Form 20-F 2019
Conclusions relating to going concern, principal risks and viability statement
Going concern
We have reviewed the directors’ statement on page 157 to the financial statements 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 12 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.
Going concern is the basis of
preparation of the financial
statements that assumes an
entity will remain in operation
for a period of at least 12
months from the date of
approval of the financial
statements.
We confirm that we have nothing
material to report, add or draw
attention to in respect of these
matters.
Principal risks and viability statement
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 68-71 that describe the principal risks, procedures to identify emerging risks,
and an explanation of how these are being managed or mitigated;
• the directors' confirmation on page 128 that they have carried out a robust assessment of the principal
and emerging risks facing the group, including those that would threaten its business model, future
performance, solvency or liquidity; or
• the directors’ explanation on page 129 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.
Viability means the ability of
the company to continue over
the time horizon considered
appropriate by the directors,
which for BP is three years.
We confirm that we have nothing
material to report, add or draw
attention to in respect of these
matters.
Key audit matters
Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the financial statements of
the current period and include the most significant assessed risks of material misstatement (whether or not due to fraud) that we identified.
These matters included those which had the greatest effect on: the overall audit strategy; the allocation of resources in the audit; and directing
the efforts of the engagement team. All of these matters were considered and discussed with the audit committee as described on page 93.
Throughout the course of our audit we identify risks of material misstatement ('risks'). We consider both the likelihood of a risk 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.
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133
Potential impact of climate change and the energy transition (impacting PP&E, goodwill, intangible assets and provisions)
Key audit matter description
How the scope of our audit responded to the key audit matter
Climate change impacts BP’s business in a number of ways as set
out in the strategic report on pages 2-71 of the Annual Report and
Accounts.
It represents a strategic challenge with its implications becoming
increasingly significant towards 2050 and beyond. Whilst many of
BP’s oil and gas properties and refining assets are long-term in
nature, none are being amortised over a period that extends beyond
this date. At current rates of depreciation, depletion and amortisation
(DD&A), the average life of the upstream PP&E is seven years and the
downstream PP&E is 13 years. Accordingly, the related principal risks
that we have identified for our audit are as follows:
• Forecast assumptions used in assessing the value of assets
within BP’s balance sheet for impairment testing, particularly oil
and gas price assumptions relevant to upstream oil and gas
PP&E assets, may not appropriately reflect changes in supply
and demand due to climate change and the energy transition
(see 'impairment of upstream PP&E' below);
• Recoverability of exploration and appraisal (E&A) assets included
within BP’s balance sheet where the investment required in
order to develop particular projects into producing oil and gas
PP&E assets might not be sanctioned by the board in future due
to climate change considerations or a potential development
may not be considered to be economic due to the impact of
climate change and the energy transition on oil and gas prices
(see 'impairment of exploration and appraisal assets' below)
Management also assessed the following potential risks that could
arise from climate change considerations.
• The carrying value of goodwill may no longer be recoverable and
therefore may need to be impaired;
• The useful economic lives of the group’s PP&E may be
shortened as society moves towards 'net zero' emissions
targets, such that the DD&A charge is materially understated;
• Decommissioning and asset retirement obligations may need to
be brought forward with a resulting increase in the present value
of the associated liabilities; and
Overall response
We held discussions with management, with Deloitte specialists and
within the Group engagement team to identify the areas where we
felt climate change could have a potential impact on the financial
statements.
We also established a climate change steering committee comprising
a group of senior partners with specific sustainability and technical
audit and accounting expertise within Deloitte to provide an
independent challenge to our key decisions and conclusions with
respect to this area.
Audit procedures in respect of impairment of upstream oil and gas
PP&E assets and exploration and appraisal assets
The audit response related to the two principal risks identified is set
out under the key audit matters for impairment of upstream oil and
gas PP&E assets on pages 135-136 and the impairment of exploration
and appraisal assets on page 137.
Other audit procedures performed
We challenged management’s assertion that the impact of potential
changes in DD&A charges, or to decommissioning dates, would not
have a material impact on the amounts reported in the current period,
by making inquiries of relevant BP personnel outside the finance
function, reviewing internal and external documents and conducting
sensitivity analysis as part of our audit risk assessment procedures.
We obtained third party forecasts of future refined petroleum product
demand for those countries which are included in our group full audit
scope for downstream, under a range of scenarios including
scenarios noted as being consistent with achieving the 2015 COP 21
Paris agreement goal to limit temperature rises to well below 2°C
('Paris 2°C Goal'). These indicated that global demand for such
products was expected to remain significant until at least 2040.
We performed procedures to satisfy ourselves that, other than future
oil and gas price assumptions, there were no other assumptions in
management's goodwill calculations to which reasonably possible
changes could cause goodwill to be materially misstated.
• Climate change-related litigation brought against BP, as disclosed
in Note 33 to the financial statements and described on page 320
under legal proceedings, may lead to an outflow of funds
requiring provision in the current year.
We obtained an understanding of the controls identified by management
as being relevant to ensuring the completeness and accuracy of litigation
and climate change related disclosure within the Annual Report; we
performed procedures to test these controls.
The material upstream goodwill balance is recorded and tested at the
segment level. The most significant assumption in the goodwill
impairment test affected by climate change relates to future oil and
gas prices (see 'impairment of upstream PP&E' below). Given the
significant headroom in the goodwill impairment test, management
identified no other assumption that could lead to a material
misstatement of goodwill due to the energy transition and other
climate change factors. Disclosures in relation to sensitivities for
goodwill are included within Note 14 on pages 187-188.
The downstream segment has a goodwill balance at 31 December
2019 of $3.9 billion, of which the most significant element is $2.8
billion relating to the Lubricants business. Notwithstanding the
expected global transition to electric vehicles, management noted
that demand for lubricants is forecast to continue to grow until at
least 2040, underpinning the substantial headroom in the most recent
impairment test as described in Note 14.
As described on pages 70-71 and in Note 1, the impact of potential
changes in DD&A charges, or to decommissioning dates would not
have a material impact on the amounts reported in the current period.
With regard to climate change litigation, we designed procedures
specifically to respond to the risks that provisions could be
understated or that contingent liability disclosures may be omitted or
be inaccurate including:
• Holding discussions with the group general counsel and other
senior BP lawyers regarding climate change matters;
• Conducting a search for climate change litigation and claims
brought against the group; and
• Making written inquiries of, and holding discussions with,
external legal counsel advising BP in relation to climate change
litigation.
We read the other information included in the Annual Report and
considered (a) whether there was any material inconsistency
between the other information and the financial statements; or (b)
whether there was any material inconsistency between the other
information and our understanding of the business based on audit
evidence obtained and conclusions reached in the audit.
The above considerations were a significant focus of management
during the period which led to this being a matter that we
communicated to the audit committee, and which had a significant
effect on the overall audit strategy. We therefore identified this as a
key audit matter.
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BP Annual Report and Form 20-F 2019
Key observations
Key observations in relation to oil and gas price assumptions used in upstream oil and gas PP&E assets
impairment tests, and the recoverability of exploration and appraisal assets including the impacts of climate
change, are set out in the relevant key audit matter below.
Based on the audit evidence obtained both from internal and external legal counsel, we were satisfied with
management’s assertion that no provision should currently be made in respect of climate change litigation.
We reviewed management’s disclosure of the contingent liabilities in respect of these matters and concluded
that the disclosures are appropriate.
We were satisfied with the results of our procedures relating to DD&A charges, goodwill and
decommissioning.
We are satisfied that management’s other disclosures in the Annual Report relating to climate change are
consistent with the financial statements and our understanding of the business.
Impairment of upstream oil and gas property, plant and equipment (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 $133 billion (2018 $135 billion), of which $90 billion (2018 $99 billion)
is oil and gas properties within the upstream segment.
Management announced an approximately $10 billion disposal
programme for 2019 and 2020. As a consequence of this, certain
assets identified for disposal have been assessed for impairment in
the context of their fair value based on the expected disposal
proceeds from third parties, as opposed to their value in use.
The transition to a lower carbon global economy may potentially lead
to a lower oil and gas price scenario in the future due to declining
demand. Management took into account considerations of
uncertainty over the pace of the transition to lower-carbon supply and
demand and the social, political and environmental actions that will
be taken to meet the goals of the Paris climate change agreement
when determining their future oil and gas price assumptions and
revised the future price assumptions downwards when compared
with the prior year assumptions as set out in Note 1 on page 162. As
a consequence, they identified a risk of impairment across all
upstream CGUs.
Accordingly, as required by International Accounting Standard (IAS)
36 'Impairment of Assets', management performed a review of all
the upstream cash generating units (CGUs) for indicators of
impairment and impairment reversal as at 31 December 2019.
Further information has been provided in Note 1.
In large part due to the disposal programme, for the year ended 31
December 2019, BP recorded $5,871 million (2018 $400 million) of
upstream impairment charges and $129 million (2018 $580 million) of
impairment reversals. Through our risk assessment procedures, we
have determined that there are three key estimates in management’s
determination of the level of impairment charge/reversal to record.
These are:
• Oil and gas prices - BP’s oil and gas price assumptions have a
significant impact on CGU impairment assessments and
valuations performed across the portfolio, and are inherently
uncertain. Furthermore, as noted above the estimation of future
oil and gas prices is subject to increased uncertainty, given
climate change and the global energy transition. There is a risk
that management’s oil and gas price assumptions are not
reasonable, leading to a material misstatement. The assumptions
are highly judgemental.
We tested management’s internal controls over the setting of oil and
gas prices, discount rates and reserve estimates, as well as the
controls over the performance of the impairment valuation tests. In
addition, we conducted the following substantive procedures.
Oil and gas prices
• We independently developed a reasonable range of forecasts
based on external data obtained, against which we compared the
company’s future oil and gas price assumptions in order to
challenge whether they are reasonable.
• In developing this range we obtained a variety of reputable third
party forecasts, peer information and market data.
• In challenging management's price assumptions, we considered
the extent to which they and each of the forecast pricing
scenarios obtained from third parties reflect the impact of lower
oil and gas demand due to climate change. We specifically
reviewed third party forecasts stated as being, or interpreted by
us as being, consistent with achieving the Paris 2°C Goal and
considered whether they presented contradictory evidence.
• We reviewed and challenged management’s disclosures
including in relation to the sensitivity of oil and gas price
assumptions to reduced demand scenarios whether due to
climate change or other reasons.
Discount rates
• We independently evaluated BP’s discount rates used in
impairment tests with input from Deloitte valuation specialists.
• We assessed whether country risks and tax adjustments were
appropriately reflected in BP’s discount rates.
Reserves estimates
• We reviewed BP’s reserves estimation methods and policies,
assisted by Deloitte reserves experts.
• We assessed, with the assistance of Deloitte reserves experts,
how these policies had been applied to a sample of internal
reserves estimates.
• We reviewed reports provided by external experts and assessed
their scope of work and findings.
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BP Annual Report and Form 20-F 2019
135
Impairment of upstream oil and gas property, plant and equipment (PP&E) assets (continued)
Key audit matter description
How the scope of our audit responded to the key audit matter
• Discount rates - Given the long timeframes involved, certain
recoverable amounts of assets 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.
We identified and focused on certain individual CGUs with a total
carrying value of $12.3 billion (2018 $21.8 billion) which we
determined would be most at risk of a material impairment as a result
of a reasonably possible change in the key assumptions, particularly
the oil and gas price assumptions. Accordingly, we identified these as
a significant audit risk. We also focused on assets with a further $33.4
billion (2018 $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 to the consolidated financial
statements.
• We assessed the competence, capability and objectivity of BP’s
internal and external reserve experts, through obtaining their
relevant professional qualifications and experience.
• We compared hydrocarbon production forecasts used in
impairment tests to estimates and reports and our
understanding of the life of fields.
• We performed a retrospective review to check for indications of
estimation bias over time.
Other procedures
• We challenged management’s cash generating unit
determination and considered whether there was any
contradictory evidence present.
• We validated that BP’s asset impairment methodology was
appropriate and tested the integrity of impairment models.
• Where relevant, we also assessed management’s historical
forecasting accuracy and whether the estimates had been
determined and applied on a consistent basis across the group.
Since 31 December 2019, the oil price has fallen sharply in large part
due to the impact of the international spread of COVID-19
(Coronavirus) and geopolitical factors. As part of our post balance
sheet audit procedures we considered whether these events provide
evidence of conditions that existed at the balance sheet date.
Key observations
Oil and gas prices
The long-term oil and gas price assumptions used to determine recoverable amount through value-in-use
impairment tests are derived from the central case long term price assumption used for investment
appraisal purposes (as set out on page 19) and represent management’s best estimate of future prices as
set out in Note 1. We determined that BP’s oil and gas price assumptions are reasonable when compared
against the range of third party forecasts we identified as being appropriate for the purpose. In forming
this view, we included each forecaster’s 'best case', 'central case' or 'most likely' estimate.
For the purpose of PP&E impairment tests, management is required under IAS 36 to apply its current
'best estimate' of future oil and gas prices.
We observed that, as well as publishing a 'best case', 'central case' or 'most likely' estimate, the majority
of third party price forecasters publish a number of other future scenarios under different plausible
economic assumption sets, and that the price forecasts stated as being or interpreted by us as being
'Paris 2°C Goal' scenarios were the lowest of all scenarios from those forecasters. We observed that for
oil, all the prices in third party 'Paris 2°C Goal' scenarios in our sample were lower than BP’s oil price
assumption from 2023 onwards, and for gas, BP's price assumptions for impairment purposes were
close to the highest 'Paris 2°C Goal' scenario.
While these 'Paris 2°C Goal' scenarios indicate that BP’s price assumptions for impairment purposes are
not consistent with the world being on a path to achieving the Paris 2°C Goal we observed that none of
those third party forecasters described their 'Paris 2°C Goal' scenarios as their 'best case', 'central case'
or “most likely” estimate.
We reviewed the disclosures included in Note 1 to the accounts in respect of price assumptions,
including the sensitivity analysis presented therein. We observed that the second downside sensitivity, in
which prices start 15% lower than the best estimate and gradually reduce to 25% lower than the best
estimate by 2040, is within the range of third party Paris 2°C Goal forecasts both for oil and for gas albeit
towards the upper end for oil.
We are satisfied that the COVID-19 outbreak and the geopolitical factors are both non-adjusting events
and accordingly the recent sharp fall in the oil price is a result of conditions that arose after the balance
sheet date. As such we concluded that management’s future oil and gas price assumptions used in
impairment tests to assess the recoverable amount of assets at the balance sheet date should not be
adjusted.
Discount rates
BP’s post-tax nominal 6% weighted average cost of capital, used as the starting point for setting discount
rates used for impairment testing, was within the independent range calculated by our Deloitte valuation
specialists.
We were also satisfied with the calculation of country risk premia. When the rates were grossed up for
tax as required for impairment testing the rates for a small number of countries fell outside of our
reasonable range but there was an insignificant impact in respect of a small number of CGUs.
Accordingly, we are satisfied with the discount rates used in the impairment testing.
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BP Annual Report and Form 20-F 2019
Key observations
We reviewed the disclosures included in Note 1 to the accounts in respect of discount rate assumptions
used and confirmed that they are consistent with the IFRS disclosure requirements.
Reserves estimates
We concluded that the assumptions used to derive the estimates were reasonable.
Impairment of exploration and appraisal assets (included within intangible assets within the Group balance sheet)
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 2019, $14 billion
(2018 $16 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 significant judgement relating to the 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.
Furthermore, similar to upstream PP&E assets discussed above, E&A
assets are also potentially exposed to climate change and the global
energy transition. A greater number of projects may be expected not
to proceed as a consequence of lower forecast future demand, lower
appetite by management and the board to allocate capital to certain
projects, or increased objections from stakeholders to the
development of certain projects. In response, management has
updated its internal controls over its IFRS 6 assessment to reflect the
potential impact that climate change and the energy transition may
have on E&A assets.
In the prior year audit, we had identified this key audit matter as a
significant risk primarily on account of uncertainty arising from the
potential inability of the Company to secure key license extensions
in respect of assets in the Gulf of Mexico and on three licenses in
other regions.
During the current year, and subsequent to the year end,
management have obtained licence extensions in the Gulf of Mexico
and other regions such that we have concluded this no longer
represents a significant audit risk. Nevertheless, given the inherent
uncertainty associated with the development and deployment of
these assets, we still consider this area to be a higher risk.
We obtained an understanding of the group’s E&A impairment
assessment processes and tested management’s internal controls,
including the new control procedures implemented to address
potential climate change considerations.
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 current period risk of impairment (e.g. new
information from exploration activities, or imminent licence expiry).
We performed a retrospective review of impairment charges
recorded in the period, and assessed whether impairment charges
were timely.
We reviewed and challenged management’s significant IFRS 6
impairment judgements, having regard to the impairment criteria of
IFRS 6 and BP’s accounting policy. We verified key facts relevant to
significant carrying amounts (by obtaining for example evidence of
future E&A plans and budgets, and evidence of active dialogue with
partners and regulators including negotiations to renew licences or
modify key terms).
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
agreeing 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 the development of any projects
would be inconsistent with the elements of BP’s current strategy
which are designed to ensure it is resilient to the energy transition
and climate change considerations 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 E&A costs were carried in respect of projects where licences had previously expired, we obtained
evidence that these licences have been renewed.
We also confirmed management's view that they did not consider that the development of any of their
E&A assets is inconsistent with BP’s current strategy. In that context we particularly considered the
Canadian oil sands assets (see Note 1) and concluded that, given low-carbon extraction technologies
required to optimise the development of these assets are being researched, continuing to carry the
assets was consistent with IFRS6.
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BP Annual Report and Form 20-F 2019
137
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 (potentially impacting all financial
statement accounts, in particular finance debt)
Key audit matter description
How the scope of our audit responded to the key audit matter
In the normal course of business, 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.
Accounting for SCTs is often complex and involves significant
judgement, as these transactions often feature multiple elements
that will have a material impact on the presentation and disclosure of
these transactions in the financial statements and on key
performance measures, including in particular classification of
liabilities as finance debt. 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 complex 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.
As at 31 December 2019, the group’s total financial assets and
liabilities measured at fair value were $12.5 billion (2018 $12.8 billion)
and $8.8 billion (2018 $8.9 billion), of which level 3 derivative financial
assets were $5.3 billion (2018 $3.6 billion) and level 3 derivative
financial liabilities were $4.4 billion (2018 $3.1 billion).
Accounting for structured commodity transactions:
For structured commodity transactions, we performed audit
procedures to:
• Test controls related to the transactions.
• Develop an understanding of the commercial rationale of the
transactions through review of transaction support documents
and executed agreements, and discussions with management.
• Perform a detailed accounting analysis for a sample of structured
commodity transactions involving significant day 1 profits,
deferred working capital arrangements, offtake arrangements
and/or commitments.
To assess the appropriateness of the accounting treatment of SCTs,
we embedded technical accounting specialists within the audit team.
During the year we identified two new SCTs which were subjected to
our audit procedures listed above. We also reconsidered the SCTs
which were identified during 2018 and which have been subject to
ongoing assessment in 2019.
Other level 3 financial instruments:
To address the complexities associated with auditing the value of
level 3 financial instruments, the engagement 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 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:
• Engaging a Deloitte valuations specialist to develop fair value
estimates, using independently sourced inputs where these
were available, and challenge 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. In
situations where we utilised management’s inputs, these were
compared to external data sources to ensure they were
reasonable;
• Evaluating management’s valuation methodologies against
standard valuation practice and analysing whether a consistent
framework is applied across the business period over period; and
• Comparing management’s input assumptions against the
expected assumptions of other market participants and
observable market data.
Key observations
We reviewed the features of the 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 indications of fraudulent misrepresentation of revenue recognition in the
transactions, valuation estimates or accounting entries that we tested.
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IT controls relating to financial systems (potentially impacting all financial statement accounts)
Key audit matter description
How the scope of our audit responded to the key audit matter
We obtained an understanding of management’s processes and
relevant financial systems, and tested the associated general IT
controls and automated business controls. We also tested the
integrity of key reports. This testing led us to identify a number of
deficiencies, notably in relation to user access and change
management.
User Access Management:
In responding to the identified deficiencies in user access, our IT
audit specialists performed procedures to:
• Test the controls that management has implemented or re-
designed in order to remediate the deficiencies;
• Assess and test the mitigating controls that management
identified, including directly testing those controls operated by IT
service organizations; 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 test controls implemented by
management to identify instances of the use of inappropriate
access.
Change Management:
In responding to the identified deficiencies our IT audit specialists
performed independent testing over:
• The mitigating controls performed by management; and
• Key automated business controls and the logic and accuracy of key
reports to ensure no changes had impacted their effectiveness.
These procedures were designed to address the likelihood and
impact of inappropriate or untested changes being implemented.
The group’s financial systems environment is complex, with 121
separate systems scoped as being relevant for the group audit.
Due to the reliance on financial systems within the group, IT controls
which support these systems are critical to maintaining an effective
control environment.
We identified IT control deficiencies in two key areas.
User Access Management:
In the prior year, we identified a number of deficiencies relating to
user access management, both within the group and at the
group’s IT service organizations (together ‘access deficiencies’).
Management commenced the implementation of a remediation
programme in the prior year, although this programme extends
into 2020.
During our 2019 audit we identified a number of additional
deficiencies relating to user access management in the IT
environment as a result of new systems in scope, the control of
highly privileged finance access and the management of
segregation of duties.
The access deficiencies identified increase the risk that individuals
across BP had inappropriate access during the period. This results in
an increased risk that data and reports from the affected systems
are not reliable. The access deficiencies impact all components
within the scope of our group audit.
Management remediated some of the deficiencies during 2019. For
the remaining deficiencies, management implemented mitigating
controls to confirm that no inappropriate access had been exploited.
Change Management:
A new change management process and change control ticketing
system, ServiceNow, was implemented for 2019. Following the change
in process and tool a number of deficiencies were identified by Deloitte
and by management around the consistent implementation of the
minimum change management controls.
The change management deficiencies identified increase the risk of
inappropriate or untested changes being made which could negatively
impact the way a system operates and accordingly, the ongoing integrity
of the controls, reports and data within key financial systems.
In responding to the identified deficiencies management have
implemented retrospective approvals for all exceptions identified.
Management also performed a full review of all changes made to all
systems in the scope of our group audit to ensure all changes were
appropriate and that change management controls were documented.
In addition management established a programme to remediate all the
identified deficiencies.
The change management issues identified impact all components
within the scope of our group audit.
Both the user access management controls and the controls over the
management of system change 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 the
risks addressed by the control.
Key observations
Our testing confirmed that the remediated controls were operating effectively.
Our testing of the mitigating controls management performed, alongside our independent testing to
demonstrate whether the access and change management deficiencies were exploited during the year, did
not identify instances of inappropriate access usage or change implementation.
Accordingly, we were satisfied with the results of the remediation to date and the mitigation such that we
continued to adopt an audit approach which places reliance on the operating effectiveness of financial
controls. Under our methodology, this enables us to apply lower sample sizes in our substantive testing.
Management continues to work to remediate fully the access and change management deficiencies
identified.
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139
Management override of controls (potentially impacting all financial statement accounts)
Key audit matter description
How the scope of our audit responded to the key audit matter
We conducted an assessment of the fraud risks arising from
management override of controls by considering potential areas
where the group’s financial statements could be manipulated,
including:
• Inappropriate accounting estimates and judgements; and
• Accounting for significant unusual transactions arising from
changes to the business.
In performing this assessment we considered 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.
During our 2018 audit we identified control deficiencies relating to the
posting of accounting journal entries at the components where
testing was performed. These control deficiencies remain as of the
end of 2019 and extended to other components where testing was
performed. There were also other changes to BP’s processes for the
posting of certain journals which created further deficiencies. As in
the previous year, management directed us to other compensating
controls which they considered to mitigate the risks, which we
subsequently tested. Management has initiated a remediation
programme which will extend into 2020.
This had a significant bearing again this year on the allocation of
resources in the audit, and the direction of effort of the audit team
globally and was a matter we discussed with the audit committee.
Accordingly, we identified this as a key audit matter.
We tested the relevant primary and, where necessary, compensating
controls that management identified as responding to the risk of
fraudulent journal entries.
In addition, we:
• 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 on page 138.
Key observations
The nature of the identified deficiencies over journal entry controls varies from business to business, so
there is no single root cause. Management identified compensating controls to mitigate the risk
associated with the design deficiencies identified. These included low-level analytical reviews, controls
over closing balances, period-end analytical review controls and certain automated business controls. Our
testing of these compensating controls concluded they were, in combination, appropriately designed and
implemented and that they were operating effectively for the year.
Our substantive testing of journal entries and other adjustments, selected through the use of our data
analytics tools, did not identify any inappropriate items.
We did not identify evidence of overall bias or any significant and 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.
Management is continuing to design and implement appropriate process level controls over journal
entries in 2020.
Our application of materiality
We define materiality as the magnitude of misstatement in the financial statements that makes it probable that the economic decisions of a
reasonably knowledgeable person would be changed or influenced. 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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Group financial statements
Parent company financial statements
Materiality has been set at $1,200 million for the
current year. (2018 $1,200 million)
We determined materiality for our audit of the
standalone parent using 1% (2018 1%) of net assets.
Materiality
Basis for determining
materiality
Materiality has been set at $850 million for the current
year. In 2018, we used a materiality of $750 million. The
increase is partly due to BP’s financial performance in
2019 and also the fact that our 2018 materiality level
reflected some conservatism in our first year as auditor.
We considered a number of metrics when determining
group materiality, including profit before taxation, profit
before impairment charges and taxation and underlying
replacement cost profit before interest and taxation.
Our selected materiality figure represents 10.3% of
profit before taxation, 5.7% of profit before impairment
charges and taxation, and 5.0% of underlying
replacement cost profit before interest and taxation. In
2018, we determined materiality to be $750m which
represented 4.5% of profit before taxation and 3.2% of
underlying replacement cost profit before interest and
taxation. The significant impairment charges of
$6,847m recognized in 2019 caused us to place more
emphasis on profit before impairment charges and
taxation in our determination of materiality this year.
Rationale for the
benchmark applied
We conducted an assessment of which line items are
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 parent company operations. As the
company is nontrading and operates primarily as a
holding company, we believe the net asset position is
the most appropriate benchmark to use.
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.
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, or where the impact of price
volatility may result in material impairment charges or
reversals in a particular year. The significant impairment
charges recognized in 2019 caused us to place more
emphasis on profit before impairment charges and
taxation this year.
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.
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BP Annual Report and Form 20-F 2019
141
Performance materiality
We set performance materiality at a level lower than materiality to reduce the probability that, in aggregate, uncorrected and undetected
misstatements exceed the materiality for the financial statements as a whole. Group performance materiality was set at 60% of group
materiality for the 2019 audit (2018 50%). The increase was due to performance materiality being set at a conservative level for 2018, given it
was our first year as auditor, and to reflect our increased knowledge of the business.
Error reporting threshold
We agreed with the audit committee that we would report to the committee all audit differences in excess of $35 million (2018 $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
Identification and scoping of components
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.
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 our 2018 audit engagement.
Our audit approach was generally to place reliance on management’s controls over financial reporting.
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 179 reporting consolidation units ('cons units' or components) (2018 108) which were selected based on their
size or risk characteristics. The primary reason for the change in scope is a change in our approach to the global audit of the IST function. We
also added to our full scope audit components for 2019 the new businesses acquired in onshore US in 2018 from BHP. Our full-scope audits are
in the UK, US, 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, component teams performed audit procedures on specified account balances for 55 cons units (2018 16) also covering operations
in Angola, Alaska, Trinidad & Tobago and Australia. The group engagement team performed audit procedures on specified account balances by
segment teams to component materiality, with certain additional specific procedures performed by component teams, covering an additional
29 cons units (2018 12).
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 0.03% of group revenue (2018 0.06%) and 0.03% of property, plant and equipment (2018 0.08%). 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.
Working with other auditors
The group audit team provides direct oversight, review, and coordination of our component audit teams. The group audit team interacted
regularly with the compnent 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 component 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 conducted visits to meet with the component teams responsible for all of
the full scope locations during the year as well as Egypt, Trinidad & Tobago, and key Global Business Services (GBS) accounting locations. 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.
In addition, a global audit planning meeting was held in London for two days in July led by the senior statutory auditor and involving the group
audit team, partners and staff from all full scope component teams, audit teams responsible for testing at key GBS locations, senior
management from BP, and the audit committee chairman.
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.
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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 users taken on the basis of these financial statements.
Details of the extent to which the audit was considered capable of detecting irregularities, including fraud and non-compliance with laws and
regulations are set out below.
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143
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, we considered the following:
• Our meetings throughout the year with the Group Head of Ethics and Compliance and reviews of BP’s internal ethics and compliance
reporting summaries, including those concerning investigations;
• Enquiries 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; and
– the internal controls established to mitigate risks related to fraud or non-compliance with laws and regulations;
• The group’s remuneration policies, key drivers for remuneration and bonus levels; and
• Discussions 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 Financial Advisory 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 discussions.
In common with all audits under ISAs (UK), we are also required to perform specific procedures to respond to the risk of management
override.
We also obtained an understanding of the legal and regulatory framework that the group operates in, focusing on provisions of those laws and
regulations that had a direct effect on the determination of material amounts and disclosures in the financial statements. The key laws and
regulations we considered in this context included 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 provisions of other laws and regulations that do not have a direct effect on the financial statements but compliance
with which may be fundamental to the group’s ability to operate or to avoid a material penalty. These included the group’s operating licences,
environmental regulations etc.
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 fraud or non-compliance with laws
and regulations. We did identify two key audit matters relating to fraud risks, as described above, being the accounting for SCTs and Level 3
instruments within IST, and management override of controls. The key audit matters section of our report explains the matters in more detail
and also describes the specific procedures we performed in response to those key audit matters.
In addition to the above, our procedures to respond to risks identified included the following:
• Reviewing the financial statement disclosures and testing to supporting documentation to assess compliance with provisions of relevant
laws and regulations described as having a direct effect on the financial statements;
• Enquiring of management, the audit committee, and both internal and external 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
relevant tax authorities including HMRC and IRS; 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.
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BP Annual Report and Form 20-F 2019
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 2019, shareholders resolved at the annual general meeting to reappoint Deloitte as auditor from the conclusion of
the meeting until the conclusion of the annual general meeting to be held in 2020 and authorized the directors to set the audit fees.
The first accounting period we audited was the 12 month period 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 two years.
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
18 March 2020
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BP Annual Report and Form 20-F 2019
145
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 consolidated group balance sheets of BP p.l.c. (the company) and subsidiaries (together the group) as at
31 December 2019 and 2018, and the related consolidated group income statements, group statements of comprehensive income, group
statements of changes in equity, and group cash flow statements, for each of the two years in the period ended 31 December 2019, and the
related notes as well as the legal proceedings described on pages 319-320 (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 the group as at 31 December 2019 and
2018, and the results of its operations and its cash flows for each of the two years in the period ended 31 December 2019, 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
group's internal control over financial reporting as of 31 December 2019, 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 18 March 2020 expressed an unqualified opinion on the group's internal control over financial reporting.
Basis for opinion
These financial statements are the responsibility of the group's management. Our responsibility is to express an opinion on the group's
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 the group 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 audit provides a reasonable
basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the group financial statements that were
communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the
group financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit
matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical
audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Throughout the course of our audit we identify risks of material misstatement ('risks'). We consider both the likelihood of a risk 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.
Impairment of upstream oil and gas property, plant and equipment (PP&E) assets - Notes 1 and 12 to the financial statements
Critical Audit Matter Description
The group balance sheet includes property, plant and equipment (PP&E) of $133 billion, of which $90 billion is oil and gas properties within the
upstream segment.
Management announced an approximately $10 billion disposal programme for 2019 and 2020. As a consequence of this, certain assets
identified for disposal have been assessed for impairment in the context of their fair value based on the expected disposal proceeds from third
parties, as opposed to their value in use.
The transition to a lower carbon global economy may potentially lead to a lower oil and gas price scenario in the future due to declining
demand. Management took into account considerations of uncertainty over the pace of the transition to lower-carbon supply and demand and
the social, political and environmental actions that will be taken to meet the goals of the Paris climate change agreement when determining
their future oil and gas price assumptions and revised the future price assumptions downwards when compared with the prior year
assumptions as set out in Note 1 on page 162. As a consequence, they identified a risk of impairment across all upstream CGUs.
Accordingly, as required by International Accounting Standard (IAS) 36 'Impairment of Assets', management performed a review of all the
upstream cash generating units (CGUs) for indicators of impairment and impairment reversal as at 31 December 2019. Further information has
been provided in Note 1.
In large part due to the disposal programme, for the year ended 31 December 2019 BP recorded $5,871 million of upstream impairment
charges and $129 million of impairment reversals. Through our risk assessment procedures, we have determined that there are three key
estimates in management’s determination of the level of impairment charge/reversal to record. These are:
a. Oil and gas prices - BP’s oil and gas price assumptions have a significant impact on CGU impairment assessments and valuations
performed across the portfolio, and are inherently uncertain. Furthermore, as noted above the estimation of future oil and gas prices is
subject to increased uncertainty, given climate change and the global energy transition. There is a risk that management’s oil and gas
price assumptions are not reasonable, leading to a material misstatement. The assumptions are highly judgemental.
b. Discount rates - Given the long timeframes involved, certain recoverable amounts of assets 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.
c. 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
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BP Annual Report and Form 20-F 2019
misstatements could arise either from systematic flaws in reserves estimation policies, or due to flawed estimates in a particularly
material individual impairment test.
We identified and focused on certain individual CGUs with a total carrying value of $12.3 billion which we determined would be most at risk of
a material impairment as a result of a reasonably possible change in the key assumptions, particularly the oil and gas price assumptions.
Accordingly, we identified these as a significant audit risk. We also focused on assets with a further $33.4 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 to the consolidated financial
statements.
How the Critical Audit Matter was addressed in the Audit
We tested management’s internal controls over the setting of oil and gas prices, discount rates and reserve estimates, as well as the
controls over the performance of the impairment valuation tests. In addition, we conducted the following substantive procedures.
Oil and gas prices
• We independently developed a reasonable range of forecasts based on external data obtained, against which we compared the company’s
future oil and gas price assumptions in order to challenge whether they are reasonable.
• In developing this range we obtained a variety of reputable third party forecasts, peer information and market data.
• In challenging management's price assumptions, we considered the extent to which they and each of the forecast pricing scenarios
obtained from third parties reflect the impact of lower oil and gas demand due to climate change. We specifically reviewed third party
forecasts stated as being, or interpreted by us as being, consistent with achieving the 2015 COP 21 Paris agreement goal to limit
temperature rises to well below 2°C (Paris 2°C Goal).
• We reviewed and challenged management’s disclosures including in relation to the sensitivity of oil and gas price assumptions to reduced
demand scenarios whether due to climate change or other reasons.
Discount rates
• We independently evaluated BP’s discount rates used in impairment tests with input from Deloitte valuation specialists.
• We assessed whether country risks and tax adjustments were appropriately reflected in BP’s discount rates.
Reserves estimates
• We reviewed BP’s reserves estimation methods and policies, assisted by Deloitte reserves experts.
• We assessed, with the assistance of Deloitte reserves experts, how these policies had been applied to a sample of 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.
• We compared hydrocarbon production forecasts used in impairment tests to estimates and reports and our understanding of the life of
fields.
• We performed a retrospective review to check for indications of estimation bias over time.
Other procedures
• We challenged management’s CGU determination, and considered whether there was any contradictory evidence present.
• We validated that BP’s asset impairment methodology was appropriate and tested the integrity of impairment models.
• Where relevant, we also assessed management’s historical forecasting accuracy and whether the estimates had been determined and
applied on a consistent basis across the group.
Since 31 December 2019, the oil price has fallen sharply in large part due to the impact of the international spread of COVID-19 (Coronavirus)
and geopolitical factors. As part of our post balance sheet audit procedures we considered whether these events provide evidence of
conditions that existed at the balance sheet date.
Impairment of exploration and appraisal assets (included within 'intangible assets' within the group balance sheet) - Notes 1 and 15
to the financial statements
Critical Audit Matter Description
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 2019, $14 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 significant judgement relating to the 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.
Furthermore, similar to upstream PP&E assets discussed above, E&A assets are also potentially exposed to climate change and the global
energy transition. A greater number of projects may be expected not to proceed as a consequence of lower forecast future demand, lower
appetite by management and the board to allocate capital to certain projects, or increased objections from stakeholders to the
development of certain projects.
During the current year, and subsequent to the year end, management have obtained license extensions in the Gulf of Mexico and other
regions where licenses had previously expired such that we have concluded this does not represent a significant audit risk. Nevertheless,
given the inherent uncertainty associated with the development and deployment of these assets, we still consider this area to be a higher
risk.
How the Critical Audit Matter was addressed in the Audit
We obtained an understanding of the group’s E&A impairment assessment processes and tested management’s internal controls,
BP Annual Report and Form 20-F 2019
147
including the controls addressing potential climate change considerations.
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 current period risk of impairment (e.g. new information from exploration activities, or imminent licence expiry).
We performed a retrospective review of impairment charges recorded in the period, and assessed whether impairment charges were
timely.
We reviewed and challenged management’s significant IFRS 6 impairment judgements, having regard to the impairment criteria of IFRS 6
and BP’s accounting policy. We verified key facts relevant to significant carrying amounts (by obtaining for example evidence of future E&A
plans and budgets, and evidence of active dialogue with partners and regulators including negotiations to renew licences or modify key
terms).
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 agreeing 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 the development of any projects would be inconsistent with the elements of BP’s current strategy which are
designed to ensure it is resilient to the energy transition and climate change considerations or which would otherwise have a prohibitively
high environmental or social impact for the directors to sanction the necessary investment.
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 (potentially impacting all
financial statement accounts, in particular finance debt) - Notes 1, 20, 22, 29 and 30 to the financial statements
Critical Audit Matter Description
In the normal course of business, 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:
• Two or more counterparties with non-standard contractual terms;
• Multiple commodity-based transactions; and/or
• 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 inputs when determining their fair value, in which case they will be classified as level 3 financial instruments under IFRS 13,
‘Fair Value Measurement’.
Accounting for SCTs is often complex and involves significant judgement, as these transactions often feature multiple elements that will
have a material impact on the presentation and disclosure of these transactions in the financial statements and on key performance
measures, including in particular classification of liabilities as finance debt. 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 complex 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.
As at 31 December 2019, the group’s total financial assets and liabilities measured at fair value were $12.5 billion and $8.8 billion, of which
level 3 derivative financial assets were $5.3 billion and level 3 derivative financial liabilities were $4.4 billion.
How the Critical Audit Matter was addressed in the Audit
Accounting for SCTs
For structured commodity transactions, we performed audit procedures to:
• Test controls related to the accounting for complex transactions.
• Develop an understanding of the commercial rationale of the transactions through review of transaction support documents and executed
agreements, and discussions with management.
• Perform a detailed accounting analysis for a sample of structured commodity transactions involving significant day one profits, deferred
working capital arrangements, offtake arrangements and/or commitments.
To assess the appropriateness of the accounting treatment of SCTs, we embedded technical accounting specialists within the audit team.
During the year we identified two new SCTs which were subjected to our audit procedures listed above. We also reconsidered the SCTs which
were identified during 2018 and which have been subject to ongoing assessment in 2019.
Other level 3 financial instruments:
To address the complexities associated with auditing the value of level 3 financial instruments, the engagement 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 group’s valuation controls including the:
148
BP Annual Report and Form 20-F 2019
– 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 date, including:
– Engaging a Deloitte valuations specialist to develop fair value estimates, using independently sourced inputs where these were
available, and challenge 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. In situations where we utilised
management’s inputs, these were compared to external data sources to ensure they were reasonable;
– Evaluating management’s valuation methodologies against standard valuation practice and analysing whether a consistent framework
is applied across the business period over period; and
– Comparing management’s input assumptions against the expected assumptions of other market participants and observable market
data.
/s/ Deloitte LLP
London
United Kingdom
18 March 2020
The first accounting period we audited was the 12 months ended 31 December 2018. In 2017, we commenced our audit planning procedures.
BP Annual Report and Form 20-F 2019
149
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 2019, 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 2019, 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 2019, of the Company and our report dated 18 March 2020,
expressed an unqualified opinion on those financial statements.
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
18 March 2020
150
BP Annual Report and Form 20-F 2019
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. (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 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 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 audit. 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 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/ 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 2019 only and does not form part
of BP p.l.c.’s Annual Report and Accounts for 2017.
1.
2.
The maintenance and integrity of the BP p.l.c. web site is the responsibility of BP p.l.c.; the work carried out by the auditors does not
involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to
the financial statements since they were initially presented on the web site.
Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other
jurisdictions.
BP Annual Report and Form 20-F 2019
151
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 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 before interest and taxation
Finance costs
Net finance expense relating to pensions and other post-retirement benefits
Profit before taxation
Taxation
Profit for the year
Attributable to
BP shareholders
Non-controlling interests
Earnings per share
Profit for the year attributable to BP shareholders
Per ordinary share (cents)
Basic
Diluted
Per ADS (dollars)
Basic
Diluted
Note
2019
2018
5
16
17
7
4
19
5
5
4
8
7
24
9
11
11
11
11
278,397
576
2,681
769
193
282,616
209,672
21,815
1,547
17,780
8,075
964
11,057
11,706
3,489
63
8,154
3,964
4,190
4,026
164
4,190
19.84
19.73
1.19
1.18
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
$ million
2017
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
152
BP Annual Report and Form 20-F 2019
Group statement of comprehensive incomea
For the year ended 31 December
Profit for the year
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
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.
Note
2019
4,190
2018
9,578
$ million
2017
3,468
1,538
(3,771)
1,986
880
—
(100)
106
—
(4)
57
82
(70)
2,489
328
(3)
(157)
168
2,657
6,847
6,674
173
6,847
—
—
(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
BP Annual Report and Form 20-F 2019
153
Group statement of changes in equitya
At 31 December 2018
Adjustment on adoption of IFRS 16, net of tax
At 1 January 2019
Profit 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 2019
At 31 December 2017
Adjustment on adoption of IFRS 9, net of tax
At 1 January 2018
Profit 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 for the year
Other comprehensive income
Total comprehensive income
Dividendsb
Repurchases of ordinary share capital
Share-based payments, net of tax
Share of equity-accounted entities’ changes in
equity, net of tax
Transactions involving non-controlling interests,
net of tax
At 31 December 2017
a See Note 32 for further information.
b See Note 10 for further information.
Share
capital and
capital
reserves
46,352
—
46,352
—
—
—
—
—
—
173
—
—
Treasury
shares
(15,767)
—
(15,767)
—
—
—
—
—
—
1,355
—
—
Foreign
currency
translation
reserve
(8,902)
—
(8,902)
—
2,407
2,407
—
—
—
—
—
—
Fair value
reserves
Profit and
loss
account
BP
shareholders'
equity
Non-
controlling
interests Total equity
$ million
(987)
—
(987)
—
52
52
—
23
—
—
—
—
78,748
(329)
78,419
4,026
189
4,215
(6,929)
—
(1,511)
(809)
5
316
99,444
(329)
99,115
4,026
2,648
6,674
(6,929)
23
(1,511)
719
5
2,104
(1)
2,103
164
9
173
(213)
101,548
(330)
101,218
4,190
2,657
6,847
(7,142)
—
—
—
—
23
(1,511)
719
5
316
233
549
46,525
(14,412)
(6,495)
(912)
73,706
98,412
2,296
100,708
46,122
—
46,122
—
—
—
—
—
—
230
—
—
(16,958)
—
(16,958)
—
—
—
—
—
—
1,191
—
—
(5,156)
—
(5,156)
—
(3,746)
(3,746)
—
—
—
—
—
—
(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
154
BP Annual Report and Form 20-F 2019
Group balance sheet
At 31 December
Non-current assets
Property, plant and equipment
Goodwill
Intangible assets
Investments in joint ventures
Investments in associates
Other investments
Fixed assets
Loans
Trade and other receivables
Derivative financial instruments
Prepayments
Deferred tax assets
Defined benefit pension plan surpluses
Current assets
Loans
Inventories
Trade and other receivables
Derivative financial instruments
Prepayments
Current tax receivable
Other investments
Cash and cash equivalents
Assets classified as held for sale
Total assets
Current liabilities
Trade and other payables
Derivative financial instruments
Accruals
Lease liabilities
Finance debta
Current tax payable
Provisions
Liabilities directly associated with assets classified as held for sale
Non-current liabilities
Other payables
Derivative financial instruments
Accruals
Lease liabilities
Finance debta
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
a Finance debt on the comparative balance sheet has been re-presented to align with the current period. See Note 1 for further information.
Helge Lund Chairman
B Looney Chief executive officer
18 March 2020
Note
2019
12
14
15
16
17
18
20
30
9
24
19
20
30
18
25
2
22
30
28
26
23
2
22
30
28
26
9
23
24
32
32
32
132,642
11,868
15,539
9,991
20,334
1,276
191,650
630
2,147
6,314
781
4,560
7,053
213,135
339
20,880
24,442
4,153
857
1,282
169
22,472
74,594
7,465
82,059
295,194
46,829
3,261
5,066
2,067
10,487
2,039
2,453
72,202
1,393
73,595
12,626
5,537
996
7,655
57,237
9,750
18,498
8,592
120,891
194,486
100,708
98,412
2,296
100,708
$ million
2018a
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
—
71,310
282,176
46,265
3,308
4,626
44
9,329
2,101
2,564
68,237
—
68,237
13,830
5,625
575
623
55,803
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 2019
155
Group cash flow statement
For the year ended 31 December
Operating activities
Profit before taxation
Adjustments to reconcile profit before taxation to net cash provided by operating
activities
Exploration expenditure written off
Depreciation, depletion and amortization
Impairment and (gain) loss on sale of businesses and fixed assets
Earnings from joint ventures and associates
Dividends received from joint ventures and associates
Interest receivable
Interest received
Finance costs
Interest paid
Net finance expense relating to pensions and other post-retirement benefits
Share-based payments
Net operating charge for pensions and other post-retirement benefits, less
contributions and benefit payments for unfunded plans
Net charge for provisions, less payments
(Increase) decrease in inventories
(Increase) decrease in other current and non-current assets
Increase (decrease) in other current and non-current liabilities
Income taxes paid
Net cash provided by operating activities
Investing activities
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 activitiesa
Repurchase of shares
Lease liability payments
Proceeds from long-term financing
Repayments of long-term financing
Net increase (decrease) in short-term debt
Net increase (decrease) in non-controlling interests
Dividends paid
BP shareholders
Non-controlling interests
Net cash provided by (used in) financing activities
Currency translation differences relating to cash and cash equivalents
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Note
2019
2018
$ million
2017
8,154
16,723
7,180
8
5
4
7
24
24
3
4
4
10
631
17,780
7,882
(3,257)
1,962
(441)
416
3,489
(2,870)
63
730
(238)
(176)
(3,406)
(2,335)
2,823
(5,437)
25,770
(15,418)
(3,562)
(137)
(304)
(19,421)
500
1,701
246
(16,974)
(1,511)
(2,372)
8,597
(7,118)
180
566
(6,946)
(213)
(8,817)
25
4
22,468
22,472
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)
(35)
9,038
(7,175)
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)
(45)
8,712
(6,231)
(158)
1,063
(6,153)
(141)
(3,296)
544
2,102
23,484
25,586
a The presentation of financing cash flows for the comparative periods have been amended to align with the current period. See Note 1 for further information.
156
BP Annual Report and Form 20-F 2019
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 2019 were approved and signed by the chief executive officer and chairman on 18 March 2020 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 2019. 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;
exploration and appraisal intangible assets; the recoverability of asset carrying values, including the estimation of reserves; 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 does not consider income taxes to represent a significant estimate or judgement for 2019, 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. The amount recognized for any non-controlling interest is measured at the present ownership's
proportionate share in the recognized amounts of the acquiree’s identifiable net assets. 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.
BP Annual Report and Form 20-F 2019
157
1. Significant accounting policies, judgements, estimates and assumptions – continued
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.
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 2019. 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, as at 31 December 2019, Bob Dudley, has been a member of the board of directors of Rosneft since
2013 and remains one of BP's nominated directors following his resignation as BP's group chief executive. He is also 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 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.
158
BP Annual Report and Form 20-F 2019
1. Significant accounting policies, judgements, estimates and assumptions – continued
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.
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 internal approval for development and
recognition of proved reserves of oil and natural gas, 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. Upon internal approval for development and recognition of proved reserves, 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.
BP Annual Report and Form 20-F 2019
159
1. Significant accounting policies, judgements, estimates and assumptions – continued
Significant judgement: exploration and appraisal intangible assets
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.The costs are
carried based on the current regulatory and political environment or any known changes to that environment. 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.
In scenarios where the expected time horizon for establishing the development plan is lengthy or uncertain, greater judgement is required. BP
is in the exploration and appraisal phase in certain Canadian oil sands assets that require further advancement of low-carbon extraction technology
in order to achieve optimum development. Sufficient technological progress is expected to be achieved and therefore BP continues to carry the
capitalized costs on its balance sheet.
The judgement disclosed in prior years in relation to expiring leases in the Gulf of Mexico is no longer considered to be significant following
recent agreement of lease extensions with the US Bureau of Safety and Environmental Enforcement.
The carrying amount of capitalized costs is included in Note 8.
Property, plant and equipment
Property, plant and equipment owned by the group 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.
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 certain 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. Therefore, the charges are not dependent on management forecasts of future oil and gas prices. 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. Management does not believe that a reasonably possible change in the economic environment would result in a material change to
the depreciation and amortization charge for other classes of assets.
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 232, which is unaudited. Details on BP’s proved reserves and production compliance and governance processes are
provided on page 286. The 2019 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 232.
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.
160
BP Annual Report and Form 20-F 2019
1. Significant accounting policies, judgements, estimates and assumptions – continued
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. If it is probable that the value of the CGU will be primarily recovered through a disposal transaction, the expected disposal
proceeds are considered in determining the recoverable amount. Where the carrying amount of a CGU exceeds its recoverable amount, the
CGU is considered impaired and is written down to its recoverable amount.
The business segment plans, which are approved on an annual basis by senior management, are the primary source of information for the
determination of value in use. They contain forecasts for oil and natural gas production, refinery throughputs, sales volumes for various types of
refined products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. As an initial step in the preparation of these plans,
various assumptions regarding market conditions, such as oil prices, natural gas prices, refining margins, refined product margins and cost
inflation rates are set by senior management. These assumptions take account of existing prices, global supply-demand equilibrium for oil and
natural gas, other macroeconomic factors and historical trends and variability. In assessing value in use, the estimated future cash flows are
adjusted for the risks specific to the asset group 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. In limited circumstances
where recent market transactions are not available for reference, discounted cash flow techniques are applied. 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.
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.
BP Annual Report and Form 20-F 2019
161
1. Significant accounting policies, judgements, estimates and assumptions – continued
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, individual oil and gas properties may form separate
CGUs whilst 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.
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 2019 relating to discount rates and oil and gas properties 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 CGU. 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 and incorporating a market participant capital structure. 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 2019 the post-tax discount rate was 6% (2018 6%) and the pre-
tax discount rate typically ranged from 7% to 13% (2018 9%) depending on the applicable tax rate in the geographic location of the CGU.
Where the CGU is located in a country that is judged to be higher risk an additional premium of 1% to 4% was added to the discount rates
(2018 2%). The judgement of classifying a country as higher risk and the applicable premium 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 recoverable amount of oil and gas properties is primarily sensitive to changes in the oil and gas price assumptions. Further sensitivity analysis
may be performed if a specific oil and gas property is identified to have low headroom above its carrying amount. In 2019, the group identified
oil and gas properties with carrying amounts totalling $25,092 million (2018 $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 $1,256 million (2018 $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.
The recoverability of intangible exploration and appraisal expenditure is covered under Oil and natural gas exploration, appraisal and
development expenditure above.
Oil and natural gas prices
The long-term price assumptions used for investment appraisal are recommended by the group chief economist after considering a range of
external price, and supply and demand forecasts under various energy transition scenarios. They are reviewed and approved by
management. As a result of the current uncertainty over the pace of transition to lower-carbon supply and demand and the social, political
and environmental actions that will be taken to meet the goals of the Paris climate change agreement, the forecasts and scenarios
considered include those where those goals are met as well as those where they are not met. The assumptions below represent
management’s best estimate of future prices; they do not reflect a specific scenario and sit within the range of the external forecasts
considered.
The long-term price assumptions used to determine recoverable amount based on value-in-use impairments tests are derived from the
central case investment appraisal assumptions (see page 19) of $70 per barrel for Brent and $4 per mmBtu for Henry Hub gas, both in 2015
prices (2018 $75 per barrel and $4 per mmBtu respectively, in 2015 prices). These long-term prices are applied from 2025 and 2032
respectively (2018 both from 2024) and continue to be inflated for the remaining life of the asset.
The price assumptions used over the periods to 2025 and 2032 have been set such that there is a linear progression from our best estimate
of 2020 prices, which were set by reference to 2019 average prices, to the long-term assumptions.
The majority of BP’s reserves and resources that support the carrying value of the group’s oil and gas properties are expected to be produced
over the next 10 years. Average prices (in real 2015 terms) used to estimate cash flows over this period are $67 per barrel for Brent and $3.1
per mmBtu for Henry Hub gas.
Oil prices fell 10% in 2019 from 2018 due to trade tensions, a macroeconomic downturn, and a slight slowdown in oil demand. OPEC+
production restraint, unplanned outages, and sanctions on Venezuela and Iran kept prices from falling further. BP's long-term assumption for
oil prices is higher than the 2019 price average, based on the judgement that current price levels would not encourage sufficient investment
to meet global oil demand sustainably in the longer term, especially given the financial requirements of key low-cost oil producing
economies.
US gas prices dropped by around 15% in 2019 compared to 2018. After an initial spike in January, they remained relatively low for much of
the year due to a combination of strong associated gas production growth, and storage levels coming back to normal. US gas demand
growth was much lower than the exceptional increase in 2018, while LNG exports continued to expand. BP's long-term price assumption for
US gas is higher than recent market prices due to forecast rising domestic demand, rapidly increasing pipeline and LNG exports, and lowest
cost resources being absorbed leading to production of more expensive gas, as well as requiring increased investment in infrastructure.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
Management tested the impact of a reduction in prices of 15% against the best estimate for Brent oil and Henry Hub gas in all future years.
These price reductions in isolation could indicatively lead to a reduction in the carrying amount of BP’s oil and gas properties in the range of
$2-3 billion, which is approximately 1-2% of the net book value of property, plant and equipment as at 31 December 2019.
Management also tested the impact of a scenario where Brent oil and Henry Hub gas prices start 15% lower than the best estimate and
gradually reduce to 25% lower than the best estimate by 2040. Although this is not considered to be a reasonably possible change in the
long-term assumptions within the next financial year, it reflects the inherent uncertainty in forecasting long-term prices. These price
reductions in isolation could indicatively lead to a reduction in the carrying amount of BP’s oil and gas properties in the range of $4-5 billion
which is approximately 3-4% of the net book value of property, plant and equipment as at 31 December 2019. Additionally, such a price
reduction does not indicate a reduction in the carrying amount of the Upstream goodwill balance.
These sensitivity analyses do not, however, represent management’s best estimate of any impairments that might be recognized as they do
not fully incorporate consequential changes that may arise, such as reductions in costs and changes to business plans, phasing of
development, levels of reserves and resources, and production volumes. As the extent of a price reduction increases, the more likely it is that
costs would decrease across the industry. The above sensitivity analyses therefore do not reflect a linear relationship between price and
value that can be extrapolated. Past experience of performing impairment tests suggests that any impairment arising from such price
reductions is likely to be lower once all these factors are taken into consideration. The interdependency of these inputs and risk factors plus
the diverse characteristics 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 the price assumptions.
The decline in oil and natural gas prices in the first quarter of 2020 is not expected to materially impact the recoverable amount of the group’s
oil and natural gas properties.
Oil and natural gas reserves
In addition to oil and natural 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 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.
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 $11.9 billion on its balance sheet (2018 $12.2 billion), principally relating to the
Atlantic Richfield, Burmah Castrol, Devon Energy and Reliance transactions. Sensitivities and additional information 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 that convey the right to control the use of an identified asset for a period of time in exchange for consideration are accounted for
as leases. The right to control is conveyed if BP has both the right to obtain substantially all of the economic benefits from, and the right to
direct the use of, the identified asset throughout the period of use. An asset is identified if it is explicitly or implicitly specified by the
agreement and any substitution rights held by the lessor over the asset are not considered substantive.
Agreements that convey the right to control the use of an intangible asset including rights to explore for or use hydrocarbons are not accounted
for as leases. See significant accounting policy: intangible assets.
A lease liability is recognized on the balance sheet on the lease commencement date at the present value of future lease payments over the
lease term. The discount rate applied is the rate implicit in the lease if readily determinable, otherwise an incremental borrowing rate is used.
The incremental borrowing rate is determined based on factors such as the group’s cost of borrowing, lessee legal entity credit risk, currency
and lease term. The lease term is the non-cancellable period of a lease together with any periods covered by an extension option that BP is
reasonably certain to exercise, or periods covered by a termination option that BP is reasonably certain not to exercise. The future lease
payments included in the present value calculation are any fixed payments, payments that vary depending on an index or rate, payments due
for the reasonably certain exercise of options and expected residual value guarantee payments.
Payments that vary based on factors other than an index or a rate such as usage, sales volumes or revenues are not included in the present
value calculation and are recognized in the income statement. The lease liability is recognized on an amortized cost basis with interest expense
recognized in the income statement over the lease term, except for where capitalized as exploration, appraisal or development expenditure.
The right-of-use asset is recognized on the balance sheet as property, plant and equipment at a value equivalent to the initial measurement of
the lease liability adjusted for lease prepayments, lease incentives, initial direct costs and any restoration obligations. The right-of-use asset is
depreciated typically on a straight-line basis over the lease term. The depreciation charge is recognized in the income statement except for
where capitalized as exploration, appraisal or development expenditure. Right-of-use assets are assessed for impairment in line with the
accounting policy for impairment of property, plant and equipment, intangible assets, and goodwill.
Agreements may include both lease and non-lease components. Payments for lease and non-lease components are allocated on a relative
stand-alone selling price basis except for leases of retail service stations where the group has elected not to separate non-lease payments
from the calculation of the lease liability and right-of-use asset.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
If the lease term at commencement of the agreement is less than 12 months, a lease liability and right-of-use asset are not recognized, and a
lease expense is recognized in the income statement on a straight-line basis.
If a significant event or change in circumstances, within the control of BP, arises that affects the reasonably certain lease term or there are
changes to the lease payments, the present value of the lease liability is remeasured using the revised term and payments, with the right-of-
use asset adjusted by an equivalent amount.
Modifications to a lease agreement beyond the original terms and conditions are accounted for as a re-measurement of the lease liability with
a corresponding adjustment to the right-of-use asset. Any gain or loss on modification is recognized in the income statement. Modifications
that increase the scope of the lease at a price commensurate with the stand-alone selling price are accounted for as a separate new lease.
The group recognizes the full lease liability, rather than its working interest share, for leases entered into on behalf of a joint operation if the
group has the primary responsibility for making the lease payments. In such cases, BP’s working interest share of the right-of-use asset is
recognized if it is jointly controlled by the group and the other joint operators, and a receivable is recognized for the share of the asset
transferred to the other joint operators. If BP is a non-operator, a payable to the operator is recognized if they have the primary responsibility for
making the lease payments and BP has joint control over the right-of-use asset, otherwise no balances are recognized.
As noted in ‘Impact of new International Financial Reporting Standards - IFRS 16 ‘Leases’, BP elected to apply the ‘modified retrospective’
transition approach on adoption of IFRS 16. Under this approach, comparative periods’ financial information is not restated. The accounting
policy applicable for leases in the comparative periods only is disclosed in the following paragraphs.
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 rights to
receive cash flows have been transferred to a third party along with either substantially all of the risks and rewards or control of the asset. This
includes the derecognition of receivables for which discounting arrangements are entered into.
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.
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. The group does not have any investments for
which this election has been made.
Derivatives designated as hedging instruments in an effective hedge
Derivatives designated as hedging instruments in an effective hedge 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, in the case of certain money market funds, fair value through profit or loss.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
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. As lifetime expected credit losses are recognized for trade receivables and the tenor of substantially all of other in-scope
financial assets is less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit
losses for the group. 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
Derivatives designated as hedging instruments in an effective hedge 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.
The group’s trade payables include some supplier arrangements that utilize letter of credit facilities (see Note 29 - Liquidity risk for further
information). The group assesses the payables subject to these arrangements to determine whether they should continue to be classified as
trade payables and give rise to operating cash flows or finance debt and financing cash flows. The criteria used in making this assessment
include the payment terms for the amount due relative to terms commonly seen in the markets in which BP operates. Liabilities subject to
these arrangements with payment terms of up to approximately 60 days are generally considered to be trade payables and give rise to
operating cash flows.
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.
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:
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1. Significant accounting policies, judgements, estimates and assumptions – continued
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 or sales and other operating revenues as appropriate.
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
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 foreign currency basis spread are recognized in other comprehensive income to the extent that they
relate to the hedged item. For time-period related hedged items, the amount recognized in other comprehensive income is amortized to profit
or loss on a straight line basis 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 estimate and judgement: 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 primarily 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
(including volatility and correlation) and modelled using the maximum available external information. Additionally, where limited data exists for
certain products, prices are determined using historical and long-term pricing relationships. The use of alternative assumptions or valuation
methodologies may result in significantly different values for these derivatives. A reasonably possible change in the price assumptions used
in the models relating to index price would not have a material impact on net assets and the Group income statement primarily as a result of
offsetting movements between derivative assets and liabilities. For more information, including the carrying amounts of level 3 derivatives,
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, rather than as a derivative.
Offsetting of financial assets and liabilities
Financial assets and liabilities are presented gross in the balance sheet unless both of the following criteria are met: the group currently has a
legally enforceable right to set off the recognized amounts; and the group intends to either settle on a net basis or realize the asset and settle
the liability simultaneously. A right of set off is the group’s legal right to settle an amount payable to a creditor by applying against it an amount
receivable from the same counterparty. The relevant legal jurisdiction and laws applicable to the relationships between the parties are
considered when assessing whether a current legally enforceable right to set off exists.
Provisions and contingencies
Provisions are recognized when the group has a present legal or constructive obligation as a result of a past event, it is probable that an
outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount
of the obligation. Where appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability.
If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax risk-
free rate that reflects current market assessments of the time value of money. Where discounting is used, the increase in the provision due to
the passage of time is recognized within finance costs. Provisions are discounted using a nominal discount rate of 2.5% (2018 3.0%).
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).
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1. Significant accounting policies, judgements, estimates and assumptions – continued
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.
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 or utilisation of 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.
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. The group has assessed that no material decommissioning provisions should be recognized as at 31 December 2019 (2018
no material provisions) for assets sold to third parties where the sale transferred the decommissioning obligation to the new owner.
Decommissioning provisions associated with downstream refineries 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 refineries 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 2019 was
a nominal rate of 2.5% (2018 a nominal rate of 3.0%), which was based on long-dated US government bonds. The weighted average period
over which decommissioning and environmental costs are generally expected to be incurred is estimated to be approximately 18 years (2018
18 years) and 6 years (2018 6 years) respectively.
Further information about the group’s provisions is provided in Note 23. 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 $1.4 billion (2018 $1.3 billion) on the value of the group’s provisions.
A two-year change in the timing of expected future decommissioning expenditures does not have a material impact on the value of the
group’s decommissioning provision. Management do not consider a change of greater than two years to be reasonably possible either in the
next financial year or as a result of changes in the longer-term economic environment.
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.
BP Annual Report and Form 20-F 2019
167
1. Significant accounting policies, judgements, estimates and assumptions – continued
Employee benefits
Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated
services are rendered by employees of the group. Deferred bonus arrangements that have a vesting date more than 12 months after the
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.
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.
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BP Annual Report and Form 20-F 2019
1. Significant accounting policies, judgements, estimates and assumptions – continued
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 within
the carrying amount of the applicable tax asset or liability 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.
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 2019 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. 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. The cost of treasury shares subsequently sold or reissued
is calculated on a weighted-average basis. 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.
BP Annual Report and Form 20-F 2019
169
1. Significant accounting policies, judgements, estimates and assumptions – continued
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. 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.
Certain contracts entered into by the group that result in physical delivery of products such as crude oil, natural gas and refined products are
required by IFRS 9 to be accounted for as derivative financial instruments. The group's counterparties in these transactions may, however,
meet the IFRS 15 definition of a customer. Revenue recognized relating to such contracts when physical delivery occurs is, therefore,
measured at the contractual transaction price and presented together with revenue from contracts with customers. Changes in the fair value
of derivative assets and liabilities prior to physical delivery are excluded from revenue from contracts with customers and are classified as other
operating revenues. See also Impact of new International Financial Reporting Standards - Not yet adopted - IFRIC agenda decision on IFRS 9
'Financial instruments' below.
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.
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.
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.
Contract asset and contract liability balances are included within amounts presented for trade receivables and other payables respectively.
Finance costs
Finance costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a
substantial period of time to get ready for their intended use, are added to the cost of those assets until such time as the assets are
substantially ready for their intended use. All other finance costs are recognized in the income statement in the period in which they are
incurred.
Impact of new International Financial Reporting Standards
BP adopted IFRS 16 ‘Leases’, which replaced IAS 17 ‘Leases’ and IFRIC 4 ‘Determining whether an arrangement contains a lease’, with effect
from 1 January 2019. 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 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 is recognized in profit or loss over the lease term.
BP 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. Comparative information in
the group balance sheet and group cash flow statement has, however, been re-presented to align with current year presentation, showing
lease liabilities and lease liability payments as separate line items. These were previously included within finance debt and repayments of long-
term financing line items respectively. Amounts presented in these line items for the comparative periods relate to leases accounted for as
finance leases under IAS 17. We do not consider any of the judgements or estimates made on transition to IFRS 16 to be significant.
IFRS 16 introduces a revised definition of a lease. As permitted by the standard, BP elected not to reassess the existing population of leases
under the new definition and only applies the new definition for the assessment of contracts entered into after the transition date. On
transition the standard permitted, 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 a historical basis as if the standard had always applied. BP elected to use the
historical asset measurement for its more material leases and used the asset equals liability approach for the remainder of the population. In
measuring the right-of-use asset BP applied the transition practical expedient to exclude initial direct costs. BP also elected 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 performing impairment tests on transition.
The effect on the group’s balance sheet is set out further below. The presentation and timing of recognition of charges in the income
statement has changed following the adoption of IFRS 16. The operating lease expense previously reported under IAS 17, typically on a straight-
line basis, has been replaced by depreciation of the right-of-use asset and interest on the lease liability. In the cash flow statement payments
are now presented as financing cash flows, representing repayments of principal, 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. In prior years, operating lease payments were principally presented within cash flows from operating activities.
170
BP Annual Report and Form 20-F 2019
1. Significant accounting policies, judgements, estimates and assumptions – continued
The following table provides a reconciliation of the operating lease commitments as at 31 December 2018 to the total lease liability 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 recognized on adoption of IFRS 16
Finance lease obligations at 31 December 2018
Adjustment for finance leases in joint operations
Total 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 as at 31 December 2018 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. Commitments for leases
not yet commenced as at 31 December 2019 are disclosed in note 28.
Short-term leases and leases below materiality threshold: As part of the transition to IFRS 16, BP elected not to recognize assets and liabilities
relating to short-term leases i.e. leases with a term of less than 12 months and 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 include amounts related to such leases.
Effect of discounting: The amount of the lease liability recognized in accordance with IFRS 16 is on a discounted basis whereas the operating
lease commitments information as at 31 December 2018 is presented on an undiscounted basis. The discount rates used on transition were
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 used on transition was around 3.5%, with a weighted average remaining lease term of around nine 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.
Impact on leases in joint operations: The operating lease commitments for leases within joint operations as at 31 December 2018 were
included on the basis of BP’s net working interest, 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 were 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 as at 31 December 2018 was based on the variable factor as at inception of the lease and was not updated to reflect
subsequent changes in the variable factor. Such subsequent changes in the lease payments were treated as contingent rentals and charged to
profit or loss as and when paid. Under IFRS 16 the lease liability is adjusted whenever the lease payments are changed in response to changes
in the variable factor, and for transition the liability was 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 were redetermined with the
benefit of hindsight, on the basis that BP was reasonably certain to exercise its option to terminate those leases before the full term.
Under IAS 17 finance leases were recognized on the group balance sheet and 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 previous finance
leases within joint operations are on a net or gross basis as appropriate as described above.
BP Annual Report and Form 20-F 2019
171
1. Significant accounting policies, judgements, estimates and assumptions – continued
In addition to the lease liability, other line items on the group balance sheet adjusted on transition to IFRS 16 include property, plant and
equipment for the right-of-use assets, lease related prepayments, receivables from joint operation partners, accruals, payables to operators of
joint operations, onerous lease 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
Lease liabilities
Finance debt
Provisions
Non-current liabilities
Other payables
Accruals
Lease liabilities
Finance debt
Deferred tax liabilities
Provisions
Net assetsa
Equity
BP shareholders' equity
Non-controlling interests
a Net assets also includes the line items not affected by the transition to IFRS 16 that are not presented separately in the table
The total adjustments to the group's lease liabilities at 1 January 2019 are reconciled as follows:
Total additional lease liabilities recognized on adoption of IFRS 16
Less: adjustment for finance leases in joint operations
Total adjustment to lease liabilities
Of which – current
– non-current
135,261
1,834
1,179
3,706
24,478
963
46,265
4,626
44
9,329
2,564
13,830
575
623
55,803
9,812
17,732
143,950
2,159
849
3,736
24,673
872
46,209
4,578
2,196
9,329
2,547
14,013
548
7,704
55,803
9,767
17,657
101,548
101,218
99,444
2,104
101,548
99,115
2,103
101,218
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
Not yet adopted
The following pronouncements from the IASB have not been adopted by the group in these financial statements as they will only become
effective for future financial reporting periods. In addition, the group is voluntarily changing certain accounting policies from 1 January 2020
following an IFRIC agenda decision on IFRS 9 'Financial instruments'. There are no other standards, amendments or 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 17 ' Insurance Contracts'
IFRS 17 'Insurance Contracts' provides a new general model for accounting for contracts where the issuer accepts significant insurance risk
from another party and agrees to compensate that party if a future uncertain event adversely affects them. IFRS 17 replaces IFRS 4 'Insurance
Contracts' and will be effective for BP for the financial reporting period commencing 1 January 2022 subject to endorsement by the UK and the
EU. BP has commenced an assessment of the impact of IFRS 17 but it is not expected to have a significant effect on future financial reporting.
Interest Rate Benchmark Reform: Amendments to IFRS 9 'Financial instruments'
Amendments to IFRS 9 were issued in September 2019 to provide temporary relief from applying specific hedge accounting requirements to
hedging relationships directly affected by interest rate benchmark reforms. The reliefs have the effect that the uncertainty over the interest rate
benchmark reforms should not generally result in discontinuation of hedge accounting. The amendments have been endorsed by the EU. BP
will adopt the IFRS 9 amendments in the financial reporting period commencing 1 January 2020.
The reliefs provided by the amendments would allow BP to assume that:
• the interest rate benchmark component at initial designation of fair value hedges is separately identifiable; and
• the interest rate benchmark is not altered for the purposes of assessing the economic relationship between the hedged item and the
hedging instrument for fair value hedges.
The amendments are applicable to all of the group's fair value hedges disclosed in note 30.
172
BP Annual Report and Form 20-F 2019
1. Significant accounting policies, judgements, estimates and assumptions – continued
IFRIC agenda decision on IFRS 9
In March 2019, the IFRIC issued an agenda decision on the application of IFRS 9 to the physical settlement of contracts to buy or sell a non-
financial item such as commodities that are not accounted for as 'own-use' contracts. The IFRIC concluded that such contracts are settled by
the delivery or receipt of a non-financial item in exchange for both cash and the settlement of the derivative asset or liability. BP regularly
enters into forward sale and purchase contracts. As described in the group's accounting policy for revenue, revenue recognized at the time
such contracts are physically settled is measured at the contractual transaction price and is presented together with revenue from contracts
with customers in these financial statements. From 1 January 2020, however, the group has changed its accounting policy for these contracts
in accordance with the conclusions included in the agenda decision. Purchases and revenues from such contracts will be measured at the
contractual transaction price plus the carrying amount of the related derivative at the date of settlement. Furthermore, revenues on such sales
contracts will no longer be presented together with the group's revenue from contracts with customers but will be included in other revenues.
This change will have a significant effect on the group's disclosures in relation to revenue from contracts with customers. For 2019, it is
currently estimated that the amount of revenue measured at the contractual transaction price presented together with revenue from contracts
with customers in these financial statements that would be presented as other revenues following application of this change in accounting
policy is approximately $130 billion. Comparative information for revenue from contracts with customers (see Note 6) will be restated in BP's
2020 financial statements.
Gains and losses on these realized physically settled derivative contracts will also be included in other revenues. The group expects there to be
no material effect on reported profit as presented in the group income statement or on net assets as a result of these changes.
2. Non-current assets held for sale
The carrying amount of assets classified as held for sale at 31 December 2019 is $7,465 million, with associated liabilities of $1,393 million.
These principally relate to two material disposal transactions which have been classified as held for sale in the group balance sheet.
On 27 August 2019, BP announced that it had agreed to sell all its Alaska operations and interests to Hilcorp Energy for up to $5.6 billion,
subject to customary closing adjustments, of which $1.6 billion is contingent on future cash flows. The sale will include BP’s entire upstream
and midstream business in the state, including BP Exploration (Alaska) Inc., which owns all of BP’s upstream oil and gas interests in Alaska,
and BP Pipelines (Alaska) Inc.’s 49% interest in the Trans Alaska Pipeline System (TAPS). BP will retain decommissioning liability relating to
TAPS, which will be partially offset by a 30% cost reimbursement from Hilcorp. The deal, which is subject to governmental authorizations, is
expected to complete during 2020. Assets of $6,518 million and associated liabilities of $969 million relating to this transaction are classified as
held for sale at 31 December 2019.
In November 2019, BP agreed to sell its interests in the San Juan basin in Colorado and New Mexico to IKAV. The deal is expected to complete
during the first half of 2020. Assets and associated liabilities relating to this transaction are classified as held for sale at 31 December 2019.
The total assets and liabilities held for sale, which are all in the Upstream segment, are set out in the table below.
Property, plant and equipment
Intangible assets
Investments in associates
Inventories
Trade and other receivables
Assets classified as held for sale
Trade and other payables
Lease liabilities
Provisions
Defined benefit pension plan and other post-retirement benefit plan deficits
Liabilities directly associated with assets classified as held for sale
$ million
2019
6,359
610
43
318
135
7,465
(33)
(280)
(1,012)
(68)
(1,393)
BP Annual Report and Form 20-F 2019
173
3. Business combinations and other significant transactions
Business combinations
As agreed as part of the original transaction, $3,480 million was paid in 2019 in respect of the 2018 acquisition of Petrohawk Energy
Corporation from BHP Billiton that is described below. Payments on this transaction are now complete. A number of other individually
insignificant business combinations were also undertaken by BP in 2019.
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, was $10,302
million, which was all paid in cash.
The transaction was accounted for as a business combination using the acquisition method. The fair values of the identifiable assets and
liabilities acquired, as at the date of acquisition, are shown in the table below. No goodwill was recognized on the acquisition and no significant
adjustments were made to the provisional fair values of the identifiable assets and liabilities acquired when those values were finalized.
Assets
Property, plant and equipment
Intangible assets
Inventories
Trade and other receivables
Cash
Liabilities
Trade and other payables
Provisions
Non-controlling interest
Total consideration
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
10,845
21
27
493
104
(659)
(323)
(206)
10,302
$ 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 for 2018. Goodwill of $804 million, resulting from the recognition of a deferred tax liability as part of the transaction accounting, was
recognized on the purchase of the interest in the Clair field.
174
BP Annual Report and Form 20-F 2019
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
2019
2018
143
50
—
193
437
15
4
456
2019
2018
415
57
887
1,359
6,752
65
30
6,847
(131)
—
—
(131)
8,075
2019
500
1,701
2,201
2,048
152
1
2,201
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
$ million
2017
526
674
10
1,210
$ million
2017
127
88
—
215
1,138
69
32
1,239
(176)
(62)
—
(238)
1,216
$ million
2017
2,936
478
3,414
1,183
2,078
153
3,414
At 31 December 2019, deferred consideration relating to disposals amounted to $159 million receivable within one year (2018 $35 million and
2017 $259 million) and $125 million receivable after one year (2018 $304 million and 2017 $268 million). In addition, contingent consideration
receivable relating to disposals amounted to $598 million at 31 December 2019 (2018 $893 million and 2017 $237 million). These amounts of
contingent consideration are reported within Other investments on the group balance sheet - see Note 18 for further information.
Upstream
In 2019, losses included $191 million fair value movements in relation to contingent consideration arising from the prior period disposal of the
Bruce, Keith and Devenick assets and $171 million in relation to severance costs associated with the divestment of our Alaskan business.
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.
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.
BP Annual Report and Form 20-F 2019
175
4. Disposals and impairment – continued
Other businesses and corporate
In 2019 losses on disposal of businesses and fixed assets were principally in respect of the reclassification of accumulated foreign exchange
losses from reserves to the income statement upon the contribution of our Brazilian biofuels business to a new 50:50 joint venture BP Bunge
Bioenergia.
In 2018 proceeds from disposals were principally in respect of life insurance policies in the US and wind farms within our US wind business.
Summarized financial information relating to the sale of businesses is shown in the table below.
The principal transaction categorized as a business disposal in 2019 was the sale of our interests in the Gulf of Suez oil concessions in Egypt.
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.
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 disposal
Gains (losses) on sale of businesses
Total consideration
Non-cash consideration
Consideration received (receivable)a
Proceeds from the sale of businesses, net of cash disposedb
a $633 million relates to deposits received in advance of the disposal of our Alaska business and certain assets in our BPX business
b Proceeds are stated net of cash and cash equivalents disposed of $30 million (2018 $15 million and 2017 $25 million).
2019
1,653
507
(257)
(108)
1,795
880
190
2,865
(1,190)
1,675
(938)
964
1,701
2018
3,274
173
(250)
(97)
3,100
—
3
3,103
(221)
2,882
(282)
(689)
1,911
$ million
2017
735
57
(173)
(86)
533
—
3
536
44
580
(216)
114
478
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,
and Note 15 for further information on impairments by asset category.
Upstream
Impairment losses and reversals in all years relate primarily to producing and midstream assets.
The 2019 impairment losses of $6,752 million related to various assets, with the most significant charges arising in the US. Impairment losses
arose primarily as a result of the decision to dispose of certain assets, including $4,703 million in relation to completed and expected disposals
in BPX Energy and $1,264 million relating to the expected disposal of our Alaskan business; of these amounts $355 million primarily relates to
impairment of associated goodwill.
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.
Downstream
Impairment losses totalling $65 million, $12 million, and $69 million were recognized in 2019, 2018 and 2017 respectively.
Other businesses and corporate
Impairment losses totalling $30 million, $254 million, and $32 million were recognized in 2019, 2018 and 2017 respectively. The amount for
2018 is in respect of assets within our US wind business in advance of their disposal in December 2018.
176
BP Annual Report and Form 20-F 2019
5. Segmental analysis
The group’s organizational structure reflects the various activities in which BP is engaged. At 31 December 2019, 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.
In February 2020, BP announced plans for a future reorganization of the group’s operating segments. The group’s current segmental reporting
structure is expected to remain in place throughout 2020 with any changes coming into effect from 1 January 2021.
a Inventory holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-
out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS
reporting, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this
can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after
adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement
cost of inventory is calculated using data from each operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows
this approach. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a
trading position and certain other temporary inventory positions.
BP Annual Report and Form 20-F 2019
177
28,789
—
—
75
—
75
—
—
—
—
—
—
278,397
3,257
11,039
667
11,706
(3,489)
(63)
8,154
6,062
11,718
1,185
30,325
22,613
$ million
2018
Total
group
5. Segmental analysis – continued
By business
Upstream
Downstream
Rosneft
Other
businesses
and
corporate
Consolidation
adjustment
and
eliminations
$ million
2019
Total
group
1,788
(28,789)
278,397
Segment revenues
Sales and other operating revenues
Less: sales and other operating revenues between
segments
Third party sales and other operating revenues
Earnings from joint ventures and associates – after
interest and tax
Segment results
Replacement cost profit (loss) before interest and
taxation
Inventory holding gains (losses)a
Profit (loss) before interest and taxation
Finance costs
Net finance expense relating to pensions and other
post-retirement benefits
Profit before taxation
Other income statement items
Depreciation, depletion and amortization
US
Non-US
Charges for provisions, net of write-back of unused
provisions, including change in discount rate
Segment assets
Investments in joint ventures and associates
Additions to non-current assetsb
54,501
250,897
(27,034)
(973)
27,467
249,924
—
—
—
603
374
2,295
4,917
(8)
4,909
6,502
685
7,187
2,316
(10)
2,306
(782)
1,006
(15)
(2,771)
—
(2,771)
4,672
9,560
118
12,196
16,254
1,335
1,586
507
3,609
4,014
—
—
—
12,927
—
55
572
560
1,593
2,345
a See explanation of inventory holding gains and losses on page 177.
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 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 c
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
4,211
8,907
355
12,785
24,266
900
1,177
834
2,772
3,609
—
—
—
10,074
—
1,678
(30,010)
298,756
(871)
807
(70)
(3,521)
—
(3,521)
59
203
1,557
689
477
30,010
—
—
211
—
211
—
—
—
—
—
—
298,756
3,753
20,179
(801)
19,378
(2,528)
(127)
16,723
5,170
10,287
2,746
26,320
28,352
a See explanation of inventory holding gains and losses on page 177.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
c Amounts have been restated to include acquisitions
178
BP Annual Report and Form 20-F 2019
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 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 177.
By geographical area
Revenues
Third party sales and other operating revenuesa
Other income statement items
Production and similar taxes
Non-current assets
Non-current assetsb c
Other
businesses and
corporate
Consolidation
adjustment and
eliminations
$ million
2017
Total
group
1,469
(26,554)
240,208
(575)
894
(19)
(4,445)
—
(4,445)
26,554
—
—
—
240,208
2,507
(212)
—
(212)
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
875
1,141
304
—
—
—
65
235
2,902
—
—
—
US
Non-US
89,334
189,063
278,397
315
1,232
1,547
57,757
133,398
191,155
8,621
853
9,474
(2,074)
(220)
7,180
5,571
10,013
3,426
$ million
2019
Total
a Non-US region includes UK $63,194 million
b Non-US region includes UK $22,881 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
Non-current assets
Non-current assetsb c
US
Non-US
$ million
2018
Total
98,066
200,690
298,756
369
1,167
1,536
68,188
124,060
192,248
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.
BP Annual Report and Form 20-F 2019
179
5. Segmental analysis – continued
By geographical area
Revenues
Third party sales and other operating revenuesa
Other income statement items
Production and similar taxes
a Non-US region includes UK $48,837 million.
US
Non-US
$ million
2017
Total
83,269
156,939
240,208
52
1,723
1,775
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
2019
62,130
180,528
20,167
13,254
276,079
2018
65,276
195,466
21,745
13,768
296,255
$ million
2017
49,670
159,821
16,196
12,538
238,225
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.
See Note 1 - impact of new International Financial Reporting Standards - Not yet adopted - IFRIC agenda decision on IFRS 9 'Financial
instruments' for further information on changes to the presentation of revenue from contracts with customers that will apply from 1 January
2020.
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
Costs relating to the Gulf of Mexico oil spill (pre-interest and tax)b
Finance costs
Interest payable on lease liabilitiesc
Interest payable on other liabilities measured at amortized cost
Capitalized at 3.50% (2018 3.56% and 2017 2.25%)d
Unwinding of discount on provisionse
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 Included within production and manufacturing expenses.
c Interest payable on lease liabilities in comparative periods relate to leases previously classified as finance leases under IAS 17.
d Tax relief on capitalized interest is approximately $51 million (2018 $55 million and 2017 $64 million).
e From 1 July 2018, the group changed its method of discounting and unwinding provisions from using real rates to using nominal rates.
2019
2018
$ million
2017
371
49
349
769
37
364
319
379
2,410
(374)
505
569
3,489
421
39
313
773
368
429
714
51
2,147
(419)
210
539
2,528
288
—
369
657
83
391
2,687
56
1,662
(297)
150
503
2,074
180
BP Annual Report and Form 20-F 2019
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
2019
2018
631
333
964
2
14,091
73
14,018
333
1,215
1,085
360
1,445
137
15,989
60
15,929
360
1,119
$ million
2017
1,603
477
2,080
—
17,026
82
16,944
477
1,901
a 2018 includes $447 million in the deepwater Gulf of Mexico principally relating to licence expiries. 2017 included write-offs 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. For further information see Upstream – Exploration on
page 53.
b 2019 includes approximately $2.5 billion relating to Canadian oil sands. See Note 1 for further information.
The carrying amount, by location, of exploration and appraisal expenditure capitalized as intangible assets at 31 December 2019 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 on profit
Angola; Egypt; Middle East
US - Gulf of Mexico; Canada; Brazil
Location
2019
2018
5,316
(68)
5,248
(1,190)
(94)
(1,284)
3,964
6,217
(221)
5,996
907
242
1,149
7,145
$ million
2017
4,208
58
4,266
(503)
(51)
(554)
3,712
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 2019, the total tax charge recognized within other comprehensive income was $227 million (2018 $714 million charge and 2017 $1,499
million charge), primarily comprising the deferred tax impact of the remeasurements of the net pension and other post-retirement benefit
liability or asset. See Note 32 for further information.
The total tax charge recognized directly in equity was $37 million (2018 $17 million charge and 2017 $263 million charge).
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 before taxation.
BP Annual Report and Form 20-F 2019
181
2019
8,154
3,964
49%
2018
16,723
7,145
43%
$ million
2017
7,180
3,712
52%
52
(7)
(2)
(3)
1
4
—
4
49
43
(5)
1
(2)
3
1
(1)
3
43
44
(7)
6
(6)
(4)
5
12
2
52
$ million
2018
3,513
(36)
—
3,477
(68)
1,149
734
17
797
6,106
9. Taxation – continued
Profit before taxation
Tax charge on profit
Effective tax rate
Tax rate computed at the weighted average statutory ratea
Increase (decrease) resulting from
Tax reported in equity-accounted entities
Deferred tax not recognizedb
Tax incentives for investment
Foreign exchange
Items not deductible for tax purposes
Impact of US tax reformc
Otherb
Effective tax rate
a Calculated based on the statutory corporate income tax rate applicable in the countries in which the group operates, weighted by the profits and losses before tax in the respective
countries.
b A minor amendment has been made to 2017 and 2018 to align with current period presentation.
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.
Deferred tax
Analysis of movements during the year in the net deferred tax liability
At 31 December
Adjustment on adoption of IFRS 9a
Adjustment on adoption of IFRS 16b
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, disposals and other additionsc
At 31 December
2019
6,106
—
(75)
6,031
72
(1,284)
233
37
101
5,190
a 2018 reflects the deferred tax impact of adjustments recorded by the group on adoption of IFRS 9. See BP Annual Report and Form 20-F 2018 - Financial statements - Note 1 for further
information.
b 2019 reflects the deferred tax impact of adjustments recorded by the group on adoption of IFRS 16. See Note 1 for further information.
c 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.
182
BP Annual Report and Form 20-F 2019
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
Lease liabilities
Pension plan and other post-retirement benefit plan deficits
Decommissioning, environmental and other provisions
Derivative financial instruments
Tax credits
Loss carry forward
Other deductible temporary differences
Net deferred tax charge (credit) and net deferred tax liabilityc
Of which – deferred tax liabilities
– deferred tax assets
Income statementab
$ million
Balance sheetab
2019
2018
2017
2019
2018
(1,436)
(31)
29
159
(1,279)
264
62
(472)
63
(336)
12
402
(5)
(1,284)
(1,297)
65
(36)
(57)
(1,325)
8
(6)
1,505
(31)
123
559
316
2,474
1,149
(3,971)
(12)
(27)
(64)
(4,074)
(16)
340
3,503
(47)
1,476
(964)
(772)
3,520
(554)
22,627
2,290
29
1,496
26,442
(1,380)
(1,367)
(7,579)
(24)
(3,964)
(5,834)
(1,104)
(21,252)
5,190
9,750
4,560
22,565
1,956
—
1,224
25,745
(90)
(1,319)
(7,126)
(95)
(3,626)
(5,900)
(1,483)
(19,639)
6,106
9,812
3,706
a The 2017 and 2018 income statement and 2018 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 2019 balance sheet is impacted by the adoption of IFRS 16 and minor amendments have been made to the balance sheet and income statement comparatives to align with current
period presentation.
c Included within the net deferred tax liability is a deferred tax asset balance of $5,526 million (2018 $5,562 million) related to the Gulf of Mexico oil spill.
Of the $4,560 million of deferred tax assets recognised on the group balance sheet at 31 December 2019 (2018 $3,706 million), $2,421 million
(2018 $2,758 million) relates to entities that have suffered a loss in either the current or preceding period. This amount is supported by
forecasts that indicate sufficient future taxable profits will be available to utilize such assets. For 2019, $2,421 million relates to the US (2018
$1,563 million relates to the US and $1,108 million relates to India).
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
2019
2.3
3.5
25.4
21.5
3.9
40.4
1.5
$ billion
2018
6.6
4.3
22.5
18.7
3.8
37.3
1.5
a For 2019 these losses expire in the period 2020-2039 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 2019 the US unused tax credits expire in the period 2020-2029.
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
2019
272
96
364
73
2018
83
—
112
169
$ million
2017
22
—
436
78
BP Annual Report and Form 20-F 2019
183
10. Dividends
The quarterly dividend which is expected to be paid on 27 March 2020 in respect of the fourth quarter 2019 is 10.50 cents per ordinary share
($0.630 per American Depositary Share (ADS)). The corresponding amount in sterling was announced on 16 March 2020.
Pence per share
Cents per share
2019
2018
2017
2019
2018
2017
2019
2018
$ million
2017
Dividends announced and paid in cash
Preference shares
Ordinary shares
March
June
September
December
Dividend announced, paid in March
2020
7.7380
8.0660
8.3480
7.8250
31.9770
7.1691
7.4435
7.9296
8.0251
30.5673
8.1587
7.7563
7.6213
7.4435
30.9798
10.00
10.00
10.25
10.25
40.50
10.00
10.00
10.00
10.00
40.00
10.25
10.25
10.25
10.25
41.00
10.50
1
1
1
1,828
1,727
1,409
1,734
6,699
1,303
1,546
1,676
1,627
6,153
1,435
1,779
1,656
2,075
6,946
2,120
The details of the scrip dividends issued are shown in the table below. The board decided not to offer a scrip dividend alternative in respect of
the third quarter 2019 dividend paid in December 2019 and fourth quarter 2019 dividend expected to be paid on 27 March 2020.
Number of shares issued (thousand)
Value of shares issued ($ million)
2019
2018
2017
208,927
1,387
195,305
1,381
289,789
1,714
The financial statements for the year ended 31 December 2019 do not reflect the dividend announced on 4 February 2020 and paid in March
2020; this will be treated as an appropriation of profit in the year ending 31 December 2020.
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
2019
19.84
19.73
2019
1.19
1.18
2018
46.98
46.67
2018
2.82
2.80
Cents per share
2017
17.20
17.10
Dollars per share
2017
1.03
1.03
Basic earnings per ordinary share amounts are calculated by dividing the profit for the year attributable to BP ordinary shareholders by the
weighted average number of ordinary shares outstanding during the year.
The weighted 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 attributable to BP shareholders
Less: dividend requirements on preference shares
Profit for the year attributable to BP ordinary shareholders
Basic weighted average number of ordinary shares
Potential dilutive effect of ordinary shares issuable under employee share-based payment
plans
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
2019
4,026
1
4,025
2018
9,383
1
9,382
$ million
2017
3,389
1
3,388
2019
2018
2017
20,284,859
19,970,215
19,692,613
Shares thousand
114,811
132,278
123,829
20,399,670
20,102,493
19,816,442
2019
2018
2017
3,380,809
3,328,369
3,282,102
Shares thousand
19,136
22,046
20,638
3,399,945
3,350,415
3,302,740
184
BP Annual Report and Form 20-F 2019
11. Earnings per share – continued
The number of ordinary shares outstanding at 31 December 2019, excluding treasury shares, and including certain shares that will be issuable
in the future under employee share-based payment plans was 20,241,170,965. Between 31 December 2019 and 27 February 2020, the latest
practicable date before the completion of these financial statements, there was a net decrease of 46,527,851 in the number of ordinary shares
outstanding primarily as a result of share issues in relation to employee share-based payment plans. A further 120 million of shares have also
been repurchased in January 2020 as part of the share buyback programme at a total cost of $776 million.
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 100-127.
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
2019
Number of optionsab
thousand
17,112
1,067
3,990
Weighted average
exercise price $
4.91
3.97
n/a
Number of optionsab
thousand
19,437
481
6,123
2018
Weighted average
exercise price $
4.28
4.69
n/a
a Numbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
b At 31 December 2019 the quoted market price of one BP ordinary share was £4.72 (2018 £4.96).
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
2019
2018
Number of sharesa
Number of sharesa
thousand
91,105
89,939
80,844
725
576
263,189
92,343
thousand
108,934
106,337
71,407
588
799
288,065
127,165
a Numbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
There has been a net decrease of 37,497,364 in the number of potential ordinary shares relating to employee share-based payment plans
between 31 December 2019 and 27 February 2020.
BP Annual Report and Form 20-F 2019
185
12. Property, plant and equipment
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
$ million
Total
Cost - owned property, plant and
equipment (PP&E)
At 1 January 2019
Exchange adjustments
Additions
Acquisitions
Transfers from intangible assets
Reclassified as assets held for sale
Deletions
At 31 December 2019
Depreciation - owned PP&E
At 1 January 2019
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Reclassified as assets held for sale
Deletions
At 31 December 2019
Owned PP&E - net book amount at
31 December 2019
Right-of-use assets - net book
amount at 31 December 2019c
Total PP&E - net book amount at 31
December 2019
Cost
At 1 January 2018
Exchange adjustments
Additions
Acquisitions
Remeasurementsb
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
Assets held under finance leases at net book
amount included aboved
At 31 December 2018
Assets under construction included above
At 31 December 2019
At 31 December 2018
Depreciation charge for the year on right-of-use
assets
2019
3,562
(22)
88
51
—
(26)
(44)
3,609
626
(4)
44
1
—
—
(86)
581
1,502
5
93
—
—
—
(178)
1,422
697
5
59
1
—
—
(65)
697
232,684
—
13,237
—
1,885
(22,602)
(10,852)
214,352
133,687
—
13,012
5,871
(129)
(17,764)
(9,911)
124,766
45,721
(158)
2,433
—
—
—
(1,272)
46,724
20,512
(63)
1,705
64
—
—
(691)
21,527
3,028
725
89,586
25,197
—
1,196
128
1,241
3,028
1,921
89,714
26,438
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
2,936
807
99,010
25,417
2,747
15
172
—
—
(76)
(326)
2,532
2,041
12
168
1
—
(69)
(147)
2,006
526
16
542
2,853
(73)
204
1
—
—
(238)
2,747
2,136
(52)
189
—
—
(232)
2,041
706
10,183
(3)
274
—
—
(6,708)
(272)
3,474
7,819
(3)
173
404
(2)
(5,478)
(169)
2,744
305,265
8,866
(232)
(69)
16,941
644
59
8
—
1,885
— (29,412)
(13,699)
280,807
(755)
8,694
170,528
5,146
(98)
(45)
15,581
420
6,346
4
—
(131)
— (23,311)
(11,729)
157,186
(660)
4,865
730
3,829
123,621
3,385
3,055
9,021
4,115
6,884
132,642
10,774
(43)
(112)
2
—
—
(128)
10,493
7,523
(27)
252
178
(17)
(75)
7,834
2,659
8,748
(501)
736
36
—
—
(146)
8,873
5,185
(279)
384
2
—
(145)
5,147
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
3,726
135,261
—
2
12
207
—
295
6
522
23,897
22,522
220
31
671
9
784
526
2,241
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.
c $653 million of drilling rig right-of-use assets and $2,929 million of shipping vessel right-of-use assets are included in Plant, machinery and equipment and Transportation respectively.
d Leases previously classified as finance leases are included within right-of-use assets following the implementation of IFRS 16 ‘Leases’; see Note 1 for further information. The reconciliation
of owned property, plant and equipment for 2019 does not include right-of-use assets and, therefore, the cost and depreciation at 1 January 2019 is not equal to the cost and depreciation of
total property, plant and equipment at 31 December 2018. The relevant amounts excluded are cost of $1,083 million and depreciation of $559 million relating to leases previously classified as
finance leases.
186
BP Annual Report and Form 20-F 2019
13. Capital commitments
Authorized future capital expenditure for property, plant and equipment (excluding right-of-use assets) by group companies for which contracts
had been signed at 31 December 2019 amounted to $11,382 million (2018 $8,319 million, 2017 $11,340 million). BP has contracted capital
commitments amounting to $787 million (2018 $1,227 million, 2017 $1,451 million) in relation to associates. BP’s share of contracted capital
commitments of joint ventures amounted to $1,024 million (2018 $619 million, 2017 $483 million).
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
Impairment losses for the year
Deletions
At 31 December
Net book amount at 31 December
Net book amount at 1 January
2019
12,815
79
26
(55)
12,865
611
—
386
—
997
11,868
12,204
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
2019
7,958
3,904
6
11,868
$ million
2018
12,163
(210)
1,046
(184)
12,815
612
—
—
(1)
611
12,204
11,551
2018
8,346
3,802
56
12,204
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
2019
7,958
93,250
2018
8,346
53,391
The table above shows the carrying amount of goodwill for the segment and the excess of the recoverable amount, based on a pre-tax value-
in-use calculation, over the carrying amount (headroom) at the date of the test. The increase in headroom principally arises from acquisitions
(including the acquisition from BHP), new activity and discount rate changes, net of highly probable and completed divestments and price
assumption changes.
Goodwill impairments of $386 million, related to goodwill allocated to expected divestments, were recognized during 2019 (2018 nil).
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.
BP Annual Report and Form 20-F 2019
187
14. Goodwill and impairment review of goodwill – continued
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 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. Due to economic developments, regulatory
change and emissions reduction activity arising from climate concern and other factors, future commodity prices and other assumptions 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 fully reflect the specific impacts for each contractual arrangement and will not capture all favourable impacts that may arise from cost
deflation. A detailed calculation at any given price or production profile may, therefore, produce a different result.
It is estimated that no reasonable sustained fall in the oil or gas price assumption over the next 20 years would individually 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 829
mmboe per year (2018 829 mmboe per year). It is estimated that no reasonably possible change in production volumes 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 reasonably possible change in the pre-tax discount rate would cause the recoverable amount to be equal to the carrying
amount of goodwill and related net non-current assets of the segment. The weighted average discount rate used in the test is 12%.
Downstream
Goodwill
Lubricants
2,779
Other
1,125
2019
Total
3,904
Lubricants
2,692
Other
1,110
$ million
2018
Total
3,802
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 2018
was used as the basis for the tests in 2019 as the criteria of IAS 36 were considered satisfied: the headroom was substantial in 2018; there
have been no significant changes in the assets and liabilities; and the likelihood that the recoverable amount would be less than the carrying
amount is remote.
The key assumptions to which the calculation of value in use for the Lubricants unit is most sensitive are operating unit margins, sales
volumes, and discount rate. 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.
15. Intangible assets
Cost
At 1 January
Exchange adjustments
Acquisitions
Additions
Transfers to property, plant and equipment
Reclassified as assets held for sale
Deletions
At 31 December
Amortization
At 1 January
Exchange adjustments
Charge for the year
Impairment losses
Reclassified as assets held for sale
Deletions
At 31 December
Net book amount at 31 December
Net book amount at 1 January
a For further information see Intangible assets within Note 1 and Note 8.
Exploration
and appraisal
expenditurea
Other
intangibles
17,053
—
—
1,268
(1,885)
(671)
(459)
15,306
1,064
—
631
2
(61)
(421)
1,215
14,091
15,989
4,504
2
35
457
—
—
(98)
4,900
3,209
4
331
2
—
(94)
3,452
1,448
1,295
2019
Total
21,557
2
35
1,725
(1,885)
(671)
(557)
20,206
4,273
4
962
4
(61)
(515)
4,667
15,539
17,284
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
$ million
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
188
BP Annual Report and Form 20-F 2019
16. Investments in joint ventures
The following table provides aggregated summarized financial information relating to the group’s share of joint ventures. In December 2019, BP
and Bunge both contributed their Brazilian biofuels and biopower businesses into a new joint venture, BP Bunge Bioenergia. BP owns 50% of
the new entity.
$ million
2017
11,380
1,394
100
1,294
117
1,177
8
1,185
$ million
2017
Amount
receivable at
31 December
352
$ million
2017
Amount
payable at
31 December
Sales and other operating revenues
Profit before interest and taxation
Finance costs
Profit before taxation
Taxation
Profit for the year
Other comprehensive income
Total comprehensive income
Non-current assets
Current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Net assets
Group investment in joint ventures
Group share of net assets (as above)
Loans made by group companies to joint ventures
Transactions between the group and its joint ventures are summarized below.
2019
14,139
975
111
864
288
576
(6)
570
13,408
3,738
17,146
2,514
4,676
7,190
9,956
9,956
35
9,991
Sales to joint ventures
Product
LNG, crude oil and oil products, natural gas
Purchases from joint ventures
Sales
4,884
2019
Amount
receivable at
31 December
431
2019
Sales
4,603
2018
Amount
receivable at
31 December
251
2018
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
Sales
3,578
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
1,812
225
1,336
300
1,257
176
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
2019
2,295
386
2,681
2018
2,283
573
2,856
2017
922
408
1,330
2019
12,927
7,407
20,334
$ million
Balance sheet
Investments in
associates
2018
10,074
7,599
17,673
The associate that is material to the group at both 31 December 2019 and 2018 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 2019.
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 2019 compared
with 31 December 2018 principally relates to earnings from Rosneft and foreign exchange effects, which have been recognized in other
comprehensive income, offset by dividends.
BP Annual Report and Form 20-F 2019
189
17. Investments in associates – continued
The value of BP’s 19.75% shareholding in Rosneft based on the quoted market share price of $7.21 per share (2018 $6.18 per share) was
$15,090 million at 31 December 2019 (2018 $12,934 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 2019, 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
2017
103,028
9,949
2,228
7,721
1,742
1,311
4,668
2,810
7,478
2019
134,046
17,473
1,281
16,192
3,058
1,514
11,620
572
12,192
161,327
38,657
199,984
44,459
79,327
123,786
76,198
10,744
65,454
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
The group received dividends, net of withholding tax, of $785 million from Rosneft in 2019 (2018 $620 million and 2017 $314 million).
Summarized financial information for the group’s share of associates is shown below.
$ million
BP share
2017
Total
27,948
2,591
494
2,097
508
259
1,330
556
1,886
Rosnefta
20,348
1,965
440
1,525
344
259
922
555
1,477
Other
7,600
626
54
572
164
—
408
1
409
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
26,474
3,451
253
3,198
604
299
2,295
113
2,408
31,862
7,635
39,497
8,781
15,667
24,448
15,049
2,122
12,927
Other
7,934
788
87
701
315
—
386
(25)
361
11,504
1,924
13,428
1,908
4,577
6,485
6,943
—
6,943
2019
Total
34,408
4,239
340
3,899
919
299
2,681
88
2,769
43,366
9,559
52,925
10,689
20,244
30,933
21,992
2,122
19,870
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
12,927
6,943
19,870
10,074
7,136
17,210
—
464
464
—
463
463
12,927
7,407
20,334
10,074
7,599
17,673
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.
190
BP Annual Report and Form 20-F 2019
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
1,544
2019
Amount
receivable at
31 December
243
2019
Sales
2,064
2018
Amount
receivable at
31 December
393
2018
Sales
1,612
Amount
payable at
31 December
Purchases
Amount
payable at
31 December
Purchases
Purchases
$ million
2017
Amount
receivable at
31 December
216
$ million
2017
Amount
payable at
31 December
Crude oil and oil products, natural gas, transportation
tariff
9,503
1,641
14,112
2,069
11,613
1,681
In addition to the transactions shown in the table above, in 2018 BP acquired a 49% stake in LLC Kharampurneftegaz, a Rosneft subsidiary,
which develops resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets 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 purchases from associates relate to crude oil and oil products transactions with Rosneft. Sales to associates are related to
various entities.
BP has commitments amounting to $11,198 million (2018 $11,303 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.
2019
$ million
2018
Current
Non-current
Current
Non-current
—
169
169
571
705
1,276
1
221
222
482
859
1,341
Other investments includes $598 million relating to contingent consideration amounts arising on disposals (2018 $893 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
2019
5,610
222
12,907
18,739
182
18,921
1,959
20,880
209,672
$ million
2018
4,878
322
10,419
15,619
282
15,901
2,087
17,988
229,878
The inventory valuation at 31 December 2019 is stated net of a provision of $650 million (2018 $1,009 million) to write down inventories to their
net realizable value, of which $290 million (2018 $604 million) relates to hydrocarbon inventories. The net credit to the income statement in the
year in respect of inventory net realizable value provisions was $348 million (2018 $552 million charge), of which $309 million credit (2018 $553
million charge) 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.
BP Annual Report and Form 20-F 2019
191
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
2019
$ million
2018
Current
Non-current
Current
Non-current
19,424
672
3,325
23,421
201
640
180
1,021
24,442
22
2
826
850
—
538
759
1,297
2,147
19,414
642
3,275
23,331
214
790
143
1,147
24,478
7
2
740
749
—
482
603
1,085
1,834
In both 2019 and 2018 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
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.
2019
2018
$ million
2017
Trade and
other
receivables
Fixed asset
investments
Trade and
other
receivables
Fixed asset
investments
Trade and
other
receivables
Fixed asset
investments
416
—
416
206
(2)
(111)
509
235
—
235
28
—
(14)
249
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
Valuation and qualifying accounts relating to trade and other receivables comprise expected credit loss allowances in 2019 and 2018 and
impairment provisions recognized on an incurred loss basis in 2017. The adjustment on adoption of IFRS 9 relates to the additional loss
allowance required by IFRS 9's expected credit loss model. The expected credit loss allowance comprises $414 million (2018 $327 million)
relating to receivables that were credit-impaired at the end of the year and $95 million (2018 $89 million) relating to receivables that were not
credit-impaired at the end of the year. 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 2019.
Valuation and qualifying accounts relating to fixed asset investments comprise impairment provisions for investments in equity-accounted
entities in 2019 and 2018. This includes expected credit loss allowances of $2 million (2018 $44 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 (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.
192
BP Annual Report and Form 20-F 2019
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 spill
Other payables
Non-financial liabilities
Sales taxes, customs duties, production taxes and social security
Other payables
2019
$ million
2018
Current
Non-current
Current
Non-current
30,538
1,866
3,868
1,617
5,810
43,699
2,381
749
3,130
46,829
—
—
1,196
10,863
133
12,192
33
401
434
12,626
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
a 2018 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.
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.
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.
Payables related to the Gulf of Mexico oil spill 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 $5,166 million payable over 13 years,
$2,742 million payable over 14 years and $3,782 million payable over 13 years respectively at 31 December 2019. Reported within net cash
provided by operating activities in the group cash flow statement is a net cash outflow of $2,694 million (2018 outflow of $3,531 million, 2017
outflow of $5,336 million) related to the Gulf of Mexico oil spill, which includes payments made in relation to these agreements. For 2018 and
2017 payments under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident are also
included. For full details of these agreements, see BP Annual Report and Form 20-F 2015.
Payables related to the Gulf of Mexico oil spill at 31 December 2019 also include amounts payable for settled economic loss and property
damage claims which are payable over a period of up to eight years.
23. Provisions
At 1 January 2019a
Exchange adjustments
Acquisitions
Increase (decrease) in existing provisions
Write-back of unused provisions
Unwinding of discount
Change in discount rate
Utilization
Reclassified to other payables
Reclassified as liabilities directly associated with assets held
for sale
Deletions
At 31 December 2019
Of which – current
– non-current
Of which – Gulf of Mexico oil spill
Decommissioning
Environmental
Litigation and
claims
13,613
74
13
1,045
(22)
415
1,360
(9)
(187)
(1,004)
(188)
15,110
317
14,793
—
1,567
(1)
—
272
(43)
45
40
(252)
—
(8)
—
1,620
280
1,340
—
1,718
—
47
290
(15)
28
31
(674)
(139)
—
(5)
1,281
558
723
189
a Includes adjustment of $92 million for the implementation of IFRS 16. See Note 1 for further information.
$ million
Total
20,204
54
82
2,567
(441)
505
1,442
(1,600)
(654)
(1,012)
(196)
20,951
2,453
18,498
189
Other
3,306
(19)
22
960
(361)
17
11
(665)
(328)
—
(3)
2,940
1,298
1,642
—
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 2019 are provisions for deferred employee compensation of $311 million (2018 $338 million).
For information on significant estimates and judgements made in relation to provisions, see Provisions and contingencies within Note 1.
BP Annual Report and Form 20-F 2019
193
23. Provisions – continued
Gulf of Mexico oil spill
The group has recognized certain assets, payables and provisions and incurs certain residual costs relating to the Gulf of Mexico oil spill that
occurred in 2010. In addition to the Litigation and claims narrative provided in this note, for further information see Notes 7, 9, 20, 22, 29, 33
and Legal proceedings on pages 319-320.
Litigation and claims - PSC settlements
The Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) with the Plaintiff's 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 319.
The litigation and claims provision reflects the latest estimate for the remaining costs associated with the PSC settlements. These costs relate
predominantly to business economic loss (BEL) claims and associated administration costs. Only a very small number of claims remained to be
determined by the end of 2019 however certain BEL claims determined by the DHCSSP have been and continue to be appealed by BP and/or
the claimants. 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 settlements are expected to be made over the next couple 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.
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.
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. During 2019 the committee was composed of six BP employees appointed
by the president of BP Corporation North America Inc. (the appointing officer). A seventh BP employee was added to the committee on 1
January 2020. 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 2019 the aggregate level of contributions was $349 million (2018 $610 million and 2017 $637 million). The aggregate level of
contributions in 2020 is expected to be approximately $550 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 $1,276 million
at 31 December 2019, 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 302.
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 2019 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 2019.
194
BP Annual Report and Form 20-F 2019
24. Pensions and other post-retirement benefits – continued
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 2019. 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
2019
2.1
3.4
2.7
2.7
2.7
2019
3.0
2.9
3.1
2018
2.9
3.8
3.0
3.0
3.1
2018
2.6
2.5
3.1
UK
2017
2.5
4.1
2.9
2.9
3.1
UK
2017
2.7
2.7
3.2
2019
3.1
3.9
—
—
1.5
2019
4.2
4.1
1.5
2018
4.1
3.9
—
—
1.5
2018
3.6
3.5
1.7
US
2017
3.5
4.1
—
—
1.7
US
2017
4.1
3.9
1.8
2019
1.3
3.1
1.5
0.5
1.7
2019
2.5
2.0
1.7
%
Eurozone
2017
1.9
3.0
1.4
0.6
1.6
%
Eurozone
2017
2.1
1.7
1.6
2018
2.0
3.1
1.5
0.5
1.7
2018
2.4
1.9
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.
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
2019
2018
UK
2017
2019
2018
US
2017
Years
Eurozone
2019
2018
2017
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
27.3
27.4
27.4
24.9
25.1
25.1
25.7
25.6
25.1
28.9
28.9
29.0
26.7
26.9
26.8
28.3
28.1
27.6
28.7
28.8
28.8
28.0
28.5
28.4
29.1
29.0
29.0
30.5
30.6
30.5
29.7
30.1
30.0
31.2
31.2
31.4
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 2019, the UK and the US plans switched 2% and nil of plan assets respectively
from equities to bonds (2018 12.5% and 10% respectively).
BP Annual Report and Form 20-F 2019
195
24. Pensions and other post-retirement benefits – continued
The current asset allocation policy for the major plans at 31 December 2019 was as follows:
Asset category
Total equity (including private equity)
Bonds/cash (including LDI)
Property/real estate
UK
%
28
65
7
US
%
40
60
—
The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2019 were $4,804 million (2018 $4,197
million) of government-issued nominal bonds and $19,462 million (2018 $17,491 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 197.
Fair value of pension plan assets
At 31 December 2019
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 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
UKa
USb
Eurozone
Other
6,285
1,096
2,675
4,884
19,462
6,132
2,507
426
98
(7,436)
36,129
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
1,290
124
1,474
2,100
—
2,304
—
289
74
—
7,655
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
495
61
—
959
100
569
96
33
30
—
2,343
413
65
—
895
102
506
57
42
32
—
2,112
537
83
—
941
2
546
71
21
23
—
2,224
371
64
3
572
—
256
27
93
26
—
1,412
306
56
4
533
—
243
25
83
40
—
1,290
376
53
—
545
—
272
30
98
45
—
1,419
$ million
Total
8,441
1,345
4,152
8,515
19,562
9,261
2,630
841
228
(7,436)
47,539
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
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 transaction price or third-party net asset, revenue or earnings based valuations that generally result in the use of significant
unobservable inputs.
d Bonds held by pension plans are valued using quoted prices in active markets.
e Properties are valued based on an analysis of recent market transactions supported by market knowledge derived from third-party professional valuers that generally result in the use of
significant unobservable inputs.
196
BP Annual Report and Form 20-F 2019
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
Reclassified as assets held for sale
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
Reclassified as assets held for sale
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
227
2
—
229
42
271
(909)
757
(152)
2,945
(2,294)
136
(57)
730
26,830
942
229
757
20
(1,207)
(6)
—
—
2,215
29,780
32,085
1,141
909
20
236
(1,207)
—
2,945
36,129
6,349
6,588
(239)
6,349
6,588
(239)
6,349
263
—
(13)
250
188
438
(285)
387
102
1,079
(1,036)
91
(22)
112
9,696
—
250
387
—
(830)
(205)
(146)
—
967
10,119
7,195
—
285
—
4
(830)
(78)
1,079
7,655
(2,464)
81
5
8
94
7
101
(43)
133
90
220
(748)
3
6
(519)
6,906
(142)
94
133
2
(76)
(273)
—
(30)
739
7,353
2,112
(43)
43
2
85
(76)
—
220
2,343
(5,010)
387
(2,851)
(2,464)
27
(5,037)
(5,010)
387
(2,851)
(2,464)
(136)
(4,874)
(5,010)
38
(1)
—
37
38
75
(46)
69
23
97
(92)
(4)
4
5
1,686
26
37
69
6
(75)
(15)
—
—
92
1,826
1,290
24
46
6
24
(75)
—
97
1,412
(414)
51
(465)
(414)
(87)
(327)
(414)
$ million
2019
Total
609
6
(5)
610
275
885
(1,283)
1,346
63
4,341
(4,170)
226
(69)
328
45,118
826
610
1,346
28
(2,188)
(499)
(146)
(30)
4,013
49,078
42,682
1,122
1,283
28
349
(2,188)
(78)
4,341
47,539
(1,539)
7,053
(8,592)
(1,539)
6,752
(8,291)
(1,539)
(29,541)
(239)
(29,780)
(7,268)
(2,851)
(10,119)
(2,479)
(4,874)
(7,353)
(1,499)
(327)
(1,826)
(40,787)
(8,291)
(49,078)
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 in the Eurozone have arisen from restructuring programmes and represent charges for special termination benefits reflecting the increased liability arising
as a result of early retirements. Settlements in the US are the result of a buy-out transaction for the pensions of a group of low value annuitants.
c Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice.
d The benefit payments amount shown above comprises $2,304 million benefits and $346 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 $7,789 million for pension liabilities and $2,330 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree
medical liabilities). The benefit obligation for the Eurozone includes $4,567 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 196.
BP Annual Report and Form 20-F 2019
197
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)
418
(2,919)
(2,501)
396
(2,897)
(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)
29
(4,823)
(4,794)
(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 196.
198
BP Annual Report and Form 20-F 2019
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
357
12
—
369
31
400
(845)
831
(14)
2,396
(236)
734
91
2,985
292
—
—
292
191
483
(266)
393
127
826
(514)
72
(40)
344
85
5
13
103
7
110
(37)
121
84
30
336
—
(36)
330
46
(1)
—
45
38
83
(48)
71
23
43
(47)
(23)
14
(13)
$ million
2017
Total
780
16
13
809
267
1,076
(1,196)
1,416
220
3,295
(461)
783
29
3,646
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.
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 2019 for the group’s pensions and other post-retirement
benefit expense would have had the effects shown in the tables below. The effects shown for the expense in 2020 comprise the total of
current service cost and net finance income or expense.
Discount ratea
Effect on expense in 2020
Effect on obligation at 31 December 2019
Inflation rateb
Effect on expense in 2020
Effect on obligation at 31 December 2019
Salary growth
Effect on expense in 2020
Effect on obligation at 31 December 2019
UK
US
Eurozone
Increase
Decrease
Increase
Decrease
Increase
Decrease
$ million
One percentage point
(274)
(4,729)
227
6,364
(66)
(1,191)
58
1,478
(1)
(1,060)
(11)
1,347
171
4,711
(134)
(3,890)
42
604
(36)
(525)
11
67
13
80
(9)
(54)
(11)
(67)
35
978
7
93
(27)
(824)
(7)
(89)
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.
Longevity
Effect on expense in 2020
Effect on obligation at 31 December 2019
$ million
One year increase
UK
US
Eurozone
31
1,140
6
147
9
306
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 2029 and the
weighted average duration of the defined benefit obligations at 31 December 2019 are as follows:
Estimated future benefit payments
2020
2021
2022
2023
2024
2025-2029
UK
1,065
1,078
1,098
1,138
1,151
5,895
US
Eurozone
Other
743
789
711
718
699
3,277
333
323
319
314
300
1,438
104
98
101
98
99
489
$ million
Total
2,245
2,288
2,229
2,268
2,249
11,099
Years
Weighted average duration
18.3
13.2
16.4
13.0
BP Annual Report and Form 20-F 2019
199
25. Cash and cash equivalents
Cash
Term bank deposits
Cash equivalents (excluding term bank deposits)
2019
6,462
10,296
5,714
22,472
$ million
2018
6,148
13,105
3,215
22,468
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 2019 includes $1,676 million (2018 $1,350 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 $4,678 million (2018 $4,693 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
Current
Non-current
2019
Total
10,487
57,237
67,724
Current
9,329
Non-current
55,803
$ million
2018
Total
65,132
As a result of the adoption of IFRS 16 ‘Leases’, leases that were previously classified as finance leases under IAS 17 are now presented as
‘Lease liabilities’ on the group balance sheet and therefore do not form part of finance debt. Comparative information for finance debt has been
amended to be on a consistent basis with amounts presented for 2019. See Note 1 and Note 27 for further information.
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
$8,166 million (2018 $7,175 million) and issued commercial paper of $2,279 million (2018 $2,040 million). Finance debt does not include accrued
interest, which is reported within other payables.
The following table shows the weighted-average interest rates achieved through a combination of borrowings and derivative financial
instruments entered into to manage interest rate and currency exposures.
Fixed rate debt
Floating rate debt
Total
US dollar
Other currencies
US dollar
Other currencies
Weighted
average
interest
rate
%
Weighted
average
time for
which rate
is fixed
Years
4
6
4
5
5
10
4
5
Weighted
average
interest
rate
%
3
7
4
8
Amount
$ million
25,634
183
25,817
17,264
323
17,587
Amount
$ million
41,871
36
41,907
47,461
84
47,545
Amount
$ million
2019
67,505
219
67,724
2018
64,725
407
65,132
Comparative information in the table above has been amended to exclude previously classified finance lease liabilities of $667 million from US
dollar and other currencies, primarily from fixed-rate debt. The calculation of the comparative weighted-average interest rate and time for which
rate is fixed is unchanged for US dollar fixed-rate debt and was previously 7% and 18 years respectively for other currencies fixed-rate debt.
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 2019, 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 significant 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.
Short-term borrowings
Long-term borrowings
Total finance debt
2019
Carrying
amount
2,321
65,403
67,724
Fair value
2,153
63,213
65,366
Fair value
2,321
67,055
69,376
$ million
2018
Carrying
amount
2,153
62,979
65,132
200
BP Annual Report and Form 20-F 2019
27. Capital disclosures and 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 basis of gearing (previously termed 'net debt ratio'), that is, the ratio of net debt to net debt plus equity. Net debt
is calculated as 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 gearing are non-GAAP measures. BP believes these measures provide useful information to investors. Net debt enables
investors to see the economic effect of finance debt, related hedges and cash and cash equivalents in total. Gearing 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 gearing within a 20-30% band and maintain a significant liquidity buffer. At 31 December 2019, gearing was 31.1%
(2018 30.0%).
As a result of the adoption of IFRS 16 ‘Leases’ from 1 January 2019, leases that were previously classified as finance leases under IAS 17 are
now presented as ‘Lease liabilities’ on the group balance sheet and therefore do not form part of finance debt. Comparative information for
finance debt (previously also termed ‘gross debt’), net debt and gearing have been amended to be on a consistent basis with amounts
presented for 2019. The relevant amount for finance lease liabilities that has been excluded from comparative information for 2018 is $667
million. The previously disclosed amounts for finance debt and net debt for 2018 were $65,799 million and $44,144 million respectively. The
previously disclosed gearing for 2018 was 30.3%.
At 31 December
Finance debt
Less: fair value asset (liability) of hedges related to finance debta
Less: cash and cash equivalents
Net debt
Equity
Gearing
2019
67,724
(190)
67,914
22,472
45,442
100,708
31.1%
$ million
2018
65,132
(813)
65,945
22,468
43,477
101,548
30.0%
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 $601
million (2018 liability of $827 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 out flow of $286 million (2018 net cash flow $nil) and fair value loss of $60 million (2018 fair value losses of $193 million).
Net debt including leases is shown in the table below.
At 31 December
Net debt
Lease liabilities
Net partner (receivable) payable for leases entered into on behalf of joint operations
Net debt including leases
An analysis of changes in liabilities arising from financing activities is provided below.
2019
45,442
9,722
(158)
55,006
$ million
2018
43,477
667
—
44,144
$ million
At 1 January 2019
Adjustment on adoption of IFRS 16a
Exchange adjustments
Net financing cash flow
Fair value (gains) losses
New and remeasured leases/joint operation payables
Other movements
At 31 December 2019
At 1 January 2018
Exchange adjustments
Net financing cash flow
Fair value (gains) losses
New leases
Other movements
At 31 December 2018
a See Note 1 for information on adoption of IFRS 16 'Leases'.
Hedge-
accounted
derivatives Lease liabilities
Net partner
payable for
leases entered
into on behalf
of joint
operations
Total liabilities
arising from
financing
activities
813
—
—
2
(1,104)
—
479
190
175
—
(360)
998
—
—
813
667
9,233
(4)
(2,372)
—
2,614
(416)
9,722
656
(22)
(35)
—
74
(6)
667
—
217
8
(14)
—
82
(3)
290
—
—
—
—
—
—
—
66,612
9,450
(58)
(713)
(180)
2,696
119
77,926
63,405
(259)
3,145
142
74
105
66,612
Finance
debt
65,132
—
(62)
1,671
924
—
59
67,724
62,574
(237)
3,540
(856)
—
111
65,132
BP Annual Report and Form 20-F 2019
201
28. Leases
The group leases a number of assets as part of its activities. This primarily includes drilling rigs in the Upstream segment and retail service
stations, oil depots and storage tanks in the Downstream segment as well as office accommodation and vessel charters across the group. The
weighted-average remaining lease term for the total lease portfolio is around 9 years. Some leases will have payments that vary with market
interest or inflation rates. Certain leases contain residual value guarantees, which may be triggered in certain circumstances such as if market
values have significantly declined at the conclusion of the lease.
The table below shows the timing of the undiscounted cash outflows for the lease liabilities included on the balance sheet.
Undiscounted lease liability cash flows due:
Within 1 year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
5 to 10 years
Over 10 years
Impact of discounting
Lease liabilities at 31 December
Of which – current
– non-current
2019
$ million
2018a
2,514
1,839
1,364
1,105
876
2,427
1,174
11,299
(1,577)
9,722
2,067
7,655
98
97
95
94
86
309
571
1,350
(683)
667
44
623
a Comparative information represents finance leases accounted for under IAS 17
The group may enter into lease arrangements a number of years before taking control of the underlying asset due to construction lead times or
to secure future operational requirements. The total undiscounted amount for future commitments for leases not yet commenced as at 31
December 2019 is $5,688 million. The majority of this future commitment relates to the floating LNG vessel to service the Greater Tortue
Ahmeyim project from 2022.
Total cash outflow for amounts included in lease liabilitiesa
Expense for variable payments not included in the lease liability
Short-term lease expense
Additions to right-of-use assets in the period
a The cash outflows for amounts not included in lease liabilities approximate the income statement expense disclosed above
An analysis of right-of-use assets and depreciation is provided in Note 12. An analysis of lease interest expense is provided in Note 7.
29. Financial instruments and financial risk factors
The accounting classification of each category of financial instruments and their carrying amounts are set out below.
$ million
2019
2,709
67
331
2,542
$ million
At 31 December 2019
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
Lease liabilities
Finance debta
Measured at
amortized
cost
Note
Mandatorily
measured at
fair value
through
profit or loss
Derivative
hedging
instruments
Total carrying
amount
18
20
30
25
22
30
28
26
—
906
24,271
—
18,183
(55,891)
—
(6,062)
(9,722)
(67,724)
(96,039)
1,445
63
—
9,984
4,289
—
(8,122)
—
—
—
7,659
—
—
—
483
—
—
(676)
—
—
—
(193)
1,445
969
24,271
10,467
22,472
(55,891)
(8,798)
(6,062)
(9,722)
(67,724)
(88,573)
202
BP Annual Report and Form 20-F 2019
29. Financial instruments and financial risk factors – continued
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
Lease liabilities
Finance debta
$ million
Mandatorily
measured at
fair value
through profit
or loss
Measured at
amortized
cost
Derivative
hedging
instruments
Total carrying
amount
—
839
24,080
—
20,366
(56,790)
—
(5,201)
(667)
(65,132)
(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)
(667)
(65,132)
(78,658)
Note
18
20
30
25
22
30
28
26
a As a result of the adoption of IFRS 16 ‘Leases’, leases that were previously classified as finance leases under IAS 17 are now presented as ‘Lease liabilities’ on the group balance sheet and
therefore do not form part of finance debt. Comparative information for finance debt and lease liabilities have been amended to be on a consistent basis with amounts presented for 2019.
The previously disclosed amounts for finance debt for 2018 was $65,799 million.
The fair value of finance debt is shown in Note 26. For all other financial instruments within the scope of IFRS 9, 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 $129 million. Dividend income of $20 million (2018 $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.
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.
BP Annual Report and Form 20-F 2019
203
29. Financial instruments and financial risk factors – continued
(i) Commodity price risk
The group’s integrated, supply and trading function is responsible for delivering value across the overall crude, oil products, gas and power
supply chains. As such, it routinely enters into spot and term physical commodity contracts in addition to optimising physical storage, pipeline
and transportation capacity. These activities expose the group to commodity price risk which is managed by entering into oil and natural gas
swaps, options and futures.
The group measures market risk exposure arising from its trading positions in liquid periods using value-at-risk techniques based on Variance/
Covariance or Monte Carlo simulation models. These techniques make a statistical assessment of the market risk arising from possible future
changes in market prices over a one-day holding period within a 95% confidence level. The value-at-risk measure is supplemented by stress
testing and scenario analysis through simulating the financial impact of certain physical, economic and geo-political scenarios. Trading activity
occurring in liquid periods is subject to value-at-risk and other limits for each trading activity and the aggregate of all trading activity. The board
has delegated a limit of $100 million (2018 $100 million) value at risk in support of this trading activity. Alternative measures are used to monitor
exposures which are outside liquid periods and for which value-at-risk techniques are not appropriate.
(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 2019, the total foreign currency
borrowings not swapped into US dollars amounted to $219 million (2018 $407 million excludes leases).
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 and Korean won. At 31 December 2019 the most significant open contracts in place were for
$106 million sterling (2018 $434 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.
(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 2019 was 62% of
total finance debt outstanding (2018 73% excludes leases). The weighted average interest rate on finance debt at 31 December 2019 was 3%
(2018 4%) and the weighted average maturity of fixed rate debt was five years (2018 four years excludes leases).
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 2020, it is estimated that the group’s
finance costs for 2020 would change by approximately $419 million (2018 $475 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 2019 was
$692 million (2018 $696 million) in respect of liabilities of joint ventures and associates and $523 million (2018 $432 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.
204
BP Annual Report and Form 20-F 2019
29. Financial instruments and financial risk factors – continued
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. Lifetime expected credit losses are recognized for trade receivables and the credit risk associated with the
significant majority of financial assets measured at amortized cost is considered to be low. Since the tenor of substantially all of the group's in-
scope financial assets is less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected
credit losses. Expected loss allowances for financial guarantee contracts are typically lower than their fair value less, where appropriate,
amortization. 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 2019, the group had in place credit enhancements
designed to mitigate approximately $7.0 billion (2018 $7.3 billion) of credit risk, of which substantially all 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
2019
16%
51%
13%
7%
11%
2%
%
2018
22%
41%
16%
8%
11 %
2%
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 2019
Derivative assets
Derivative liabilities
Trade and other receivables
Trade and other payables
At 31 December 2018
Derivative assets
Derivative liabilities
Trade and other receivables
Trade and other payables
Gross
amounts of
recognized
financial
assets
(liabilities)
13,191
(11,445)
10,661
(10,266)
11,502
(11,337)
11,296
(10,797)
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
10,467
(8,721)
5,450
(5,055)
8,991
(8,826)
5,906
(5,407)
(1,971)
1,971
(961)
961
(2,079)
2,079
(1,020)
1,020
(206)
—
(190)
—
(299)
—
(169)
—
8,290
(6,750)
4,299
(4,094)
6,613
(6,747)
4,717
(4,387)
Amounts
set off
(2,724)
2,724
(5,211)
5,211
(2,511)
2,511
(5,390)
5,390
BP Annual Report and Form 20-F 2019
205
29. Financial instruments and financial risk factors – continued
(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.
The group benefits from open credit provided by suppliers who generally sell on five to 60-day payment terms in accordance with industry
norms. BP utilizes various arrangements in order to manage its working capital and reduce volatility in cash flow. This includes discounting of
receivables and, in the supply and trading business, managing inventory, collateral and supplier payment terms within a maximum of 60 days.
It is normal practice in the oil and gas supply and trading business for customers and suppliers to utilise letter of credit (LC) facilities to mitigate
credit and non-performance risk. Consequently, LCs facilitate active trading in a global market where credit and performance risk can be
significant. In common with the industry, BP routinely provides LCs to some of its suppliers.
The group has committed LC facilities totalling $12,175 million (2018 $12,175 million), allowing LCs to be issued for a maximum 24-month
duration. There were also uncommitted secured LC facilities in place at 31 December 2019 for $4,440 million (2018 $4,190 million), which are
secured against inventories or receivables when utilized. The facilities are held with over 20 international banks. The uncommitted secured LC
facilities can only be terminated by either party giving a stipulated termination notice to the other.
In certain circumstances, the supplier has the option to request accelerated payment from the LC provider in order to further reduce their
exposure. BP’s payments are made to the provider of the LC rather than the supplier according to the original contractual payment terms. At
31 December 2019, $4,755 million (2018 $3,705 million) of the group’s trade payables subject to these arrangements were payable to LC
providers, with no material exposure to any individual provider.
Standard & Poor’s Ratings long-term credit rating for BP is A- (positive outlook) and Moody’s Investors Service rating is A1 (stable outlook).
During 2019, $8 billion (2018 $9 billion) of long-term taxable bonds were issued with terms ranging from one to thirty 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 2019 (2018 $22.5 billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate
and short notice. At 31 December 2019, the group had substantial amounts of undrawn borrowing facilities available, consisting of $7,625
million (2018 $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. On 13th March the group entered into a committed $10,000
million credit facility which is available for two years at pre-agreed margins.
The table below shows the timing of cash outflows relating to finance debt, trade and other payables and accruals.
Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
5 to 10 years
Over 10 years
Trade and
other
payablesa
43,699
1,937
1,465
1,409
1,332
5,863
3,957
59,662
Accruals
5,066
261
146
181
108
231
69
6,062
2019
Interest on
finance debt
2,037
1,641
1,409
1,172
942
1,970
249
9,420
Finance
debt
10,065
6,726
7,949
7,022
7,554
23,540
2,497
65,353
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
$ million
2018
Interest on
finance debtb
2,350
1,904
1,653
1,379
1,101
2,250
9
10,646
Finance
debtb
9,257
6,743
6,758
8,005
7,009
25,187
983
63,942
a 2019 includes $16,129 million (2018 $18,360 million) in relation to the Gulf of Mexico oil spill, of which $14,501 million (2018 $16,058 million) matures in greater than one year.
b As a result of the adoption of IFRS 16 ‘Leases’, leases that were previously classified as finance leases under IAS 17 are now presented as ‘Lease liabilities’ on the group balance sheet and
therefore do not form part of finance debt. Comparative information for finance debt and interest on finance debt has been amended to be on a consistent basis with amounts presented for
2019. $667 million and $683 million relating to finance lease liabilities have been excluded from the comparative information for finance debt and interest on finance debt respectively for
2018. The previously disclosed amounts for finance debt and interest on finance debt for 2018 was $64,608 million and $11,329 million respectively. The timing of cash outflows relating to
lease liabilities reported on the balance sheet are now shown in Note 28.
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.
206
BP Annual Report and Form 20-F 2019
29. Financial instruments and financial risk factors – continued
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 $24,787 million at 31 December 2019 (2018 $22,453
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
2019
1,678
2,384
2,838
2,906
3,321
10,633
2,224
25,984
$ million
2018
1,700
1,678
2,384
2,838
2,906
11,475
724
23,705
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.
BP Annual Report and Form 20-F 2019
207
30. Derivative financial instruments – continued
Financial OTC and physical commodity options are valued using industry standard models that consider various assumptions, including quoted
forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant
economic factors. The degree to which these inputs are observable in the forward markets determines whether the option is categorized
within level 2 or level 3 of the fair value hierarchy.
Derivatives held for trading
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Other derivatives
Embedded derivatives
Other embedded derivatives
Cash flow hedges
Currency forwards
Gas price futures
Fair value hedges
Currency swaps
Interest rate swaps
Of which – current
– non-current
Fair value
asset
2019
Fair value
liability
81
1,918
6,569
1,306
110
9,984
—
—
1
—
1
344
138
482
10,467
4,153
6,314
(744)
(1,478)
(4,871)
(952)
—
(8,045)
(77)
(77)
(4)
—
(4)
(637)
(35)
(672)
(8,798)
(3,261)
(5,537)
Fair value
asset
69
2,361
4,787
1,240
107
8,564
—
—
5
2
7
158
262
420
8,991
3,846
5,145
$ million
2018
Fair value
liability
(898)
(1,849)
(3,888)
(943)
—
(7,578)
(107)
(107)
(14)
—
(14)
(789)
(445)
(1,234)
(8,933)
(3,308)
(5,625)
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
1,619
1,889
556
33
4,145
Less than
1 year
48
1,916
1,333
540
—
3,837
1-2 years
2-3 years
3-4 years
4-5 years
23
114
824
269
—
1,230
9
76
615
146
—
846
1
53
489
94
77
714
—
45
433
67
—
545
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
$ million
2019
Total
81
1,918
6,569
1,306
110
9,984
$ million
2018
Total
69
2,361
4,787
1,240
107
8,564
Over
5 years
—
11
2,319
174
—
2,504
Over
5 years
—
—
1,400
132
—
1,532
208
BP Annual Report and Form 20-F 2019
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
(166)
(1,405)
(1,070)
(395)
(3,036)
Less than
1 year
(299)
(1,560)
(1,030)
(401)
(3,290)
1-2 years
2-3 years
3-4 years
4-5 years
(283)
(56)
(522)
(165)
(1,026)
(201)
(14)
(446)
(104)
(765)
(1)
(2)
(399)
(76)
(478)
(23)
(1)
(363)
(51)
(438)
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)
$ million
2019
Total
(744)
(1,478)
(4,871)
(952)
(8,045)
$ million
2018
Total
(898)
(1,849)
(3,888)
(943)
(7,578)
Over
5 years
(70)
—
(2,071)
(161)
(2,302)
Over
5 years
(98)
—
(1,287)
(133)
(1,518)
The following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by
methodology of fair value estimation. This information is presented on a gross basis, that is, before netting by counterparty.
Fair value of derivative assets
Level 1
Level 2
Level 3
Less: netting by counterparty
Fair value of derivative liabilities
Level 1
Level 2
Level 3
Less: netting by counterparty
Net fair value
Fair value of derivative assets
Level 1
Level 2
Level 3
Less: netting by counterparty
Fair value of derivative liabilities
Level 1
Level 2
Level 3
Less: netting by counterparty
Net fair value
Less than
1 year
63
5,344
779
6,186
(2,041)
4,145
(49)
(4,522)
(506)
(5,077)
2,041
(3,036)
1,109
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
1-2 years
2-3 years
3-4 years
4-5 years
6
1,014
501
1,521
(291)
1,230
(8)
(932)
(377)
(1,317)
291
(1,026)
204
2
439
485
926
(80)
846
(4)
(458)
(383)
(845)
80
(765)
81
—
210
540
750
(36)
714
(1)
(146)
(367)
(514)
36
(478)
236
2
120
452
574
(29)
545
(2)
(113)
(352)
(467)
29
(438)
107
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
$ million
2019
Total
74
7,169
5,465
12,708
(2,724)
9,984
(65)
(6,272)
(4,432)
(10,769)
2,724
(8,045)
1,939
$ 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
Over
5 years
1
42
2,708
2,751
(247)
2,504
(1)
(101)
(2,447)
(2,549)
247
(2,302)
202
Over
5 years
—
72
1,640
1,712
(180)
1,532
—
(163)
(1,535)
(1,698)
180
(1,518)
14
BP Annual Report and Form 20-F 2019
209
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 2019
Gains (losses) recognized in the income statement
Gains (losses) recognized in other comprehensive income
Settlements
Transfers out of level 3
Net fair value of contracts at 31 December 2019
Deferred day-one gains (losses)
Derivative asset (liability)
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)
Oil
price
23
128
—
(79)
(1)
71
Oil
price
67
58
(107)
5
23
Natural gas
price
(13)
82
—
(21)
(20)
28
Natural gas
price
65
(26)
(32)
(20)
(13)
Power
price
(148)
244
(18)
(179)
(24)
(125)
Power
price
(226)
209
(97)
(34)
(148)
Other
107
2
—
—
1
110
Other
115
(8)
—
—
107
$ million
Total
(31)
456
(18)
(279)
(44)
84
949
1,033
$ million
Total
21
233
(236)
(49)
(31)
577
546
The amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at 31 December 2019 was a
$250-million gain (2018 $123-million gain related to derivatives still held at 31 December 2018).
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 was a net gain of $2,153 million (2018 $2,504 million net gain and 2017 $1,983 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 relating to foreign currency risk management activities. Gains and losses on these contracts are
included within production and manufacturing expenses in the income statement. The change in the unrealized value of these contracts was a
net gain of $160 million (2018 $351 million net loss and 2017 $1,420 million net gain), 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 2019, 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 and foreign currency basis spreads 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, 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.
210
BP Annual Report and Form 20-F 2019
30. Derivative financial instruments – continued
(ii) Commodity price risk of highly probable forecast sales
During the period the group held Henry Hub NYMEX futures designated as hedging instruments in cash flow hedge relationships of certain
highly probable forecast future sales. At 31 December 2019, these hedging instruments and highly probably forecast sales had been realised
and the corresponding amounts recognised in the cash flow hedge reserve were released to the income statement during the period.
The group is exposed to the variability in the gas price, but only applied 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).
The group applied hedge accounting in relation to these highly probable future sales where there was an economic relationship between the
hedged item and hedging instrument. The existence of an economic relationship was determined at inception and prospectively by comparing
the critical terms of the hedging instrument and those of the hedged item. The group entered into hedging derivatives that matched the
notional amounts of the hedged items on a 1:1 hedge ratio basis. The hedge ratio was determined by comparing the notional amount of the
derivative with the notional amount designated on the forecast transaction.
The hedge was highly effective due to the price index of the hedging instruments matching the price index of the hedged item. The group did
not designate any net positions as hedged items in cash flow hedges of commodity price risk.
The tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the
period.
At 31 December 2019
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure
Commodity price risk
Highly probable forecast sales
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)
(1)
(100)
(5)
(126)
1
100
5
126
—
—
—
—
The tables below summarize the carrying amount and nominal amount of the derivatives designated as hedging instruments in cash flow
hedge relationships.
At 31 December 2019
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure
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
1
5
2
(4)
150
386
(14)
—
145
All hedging instruments are presented within derivative financial instruments on the group balance sheet.
Of the nominal amount of hedging instruments at 31 December relating to highly probably forecast capital expenditure $150 million (2018 $304
million) matures within 12 months and $nil (2018 $82 million) within one to two years. All of the hedging instruments relating to highly probable
forecast sales at 31 December 2018 matured in 2019.
BP Annual Report and Form 20-F 2019
211
30. Derivative financial instruments – continued
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.
At 31 December
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
2019
Forecast
capital
expenditure
1.35
1.11
—
—
1,115.66
2018
Forecast capital
expenditure
Forecast sales
1.34
1.14
0.72
8.67
1,107.90
2.86
Fair value hedges
At 31 December 2019, 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, 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 tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the
period. The signage convention for changes in fair value presented in this table is consistent with that presented in Note 27.
At 31 December 2019
Fair value hedges
Interest rate risk on finance debt
Interest rate and foreign currency risk on finance debt
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)
(764)
(336)
737
286
(70)
812
69
(809)
27
50
(1)
3
212
BP Annual Report and Form 20-F 2019
30. Derivative financial instruments – continued
The tables below summarize the carrying amount of the derivatives designated as hedging instruments in fair value hedge relationships at 31
December.
At 31 December 2019
Fair value hedges
Interest rate risk on finance debt
Interest rate and foreign currency risk on finance debt
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
138
344
262
158
(35)
(637)
13,442
21,296
(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 tables below summarize the profile by tenor of the nominal amount of the derivatives designated as hedging instruments in fair value
hedge relationships at 31 December. The weighted average floating interest rate of these interest rate swaps and cross-currency interest rate
swaps was 2.36% (2018 3.04%) and 3.27% (2018 4.07%) respectively.
At 31 December 2019
Fair value hedges
Interest rate risk on finance debt
Interest rate and foreign currency
risk on finance debt
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
3,000
2,576
882
672
4,039
1,400
1,200
2,777
206
2,421
—
13,442
3,109
10,216
2,240
21,296
2,694
—
2,324
1,245
2,597
1,167
4,923
707
1,700
2,921
10,275
10,254
—
286
24,513
16,580
The tables below summarize 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.
At 31 December 2019
Fair value hedges
Interest rate risk on finance debt
Interest rate and foreign currency risk on finance debt
At 31 December 2018
Fair value hedges
Interest rate risk on finance debt
Interest rate and foreign currency risk on finance debt
Carrying amount of hedged item
Accumulated fair value adjustment included in the
carrying amount of hedged items
$ million
Assets
Liabilities
Assets
Liabilities
Discontinued
hedges
—
—
—
—
(13,441)
(21,240)
(24,747)
(16,883)
—
—
175
—
(100)
(525)
(714)
—
—
(62)
(360)
—
The hedged item for all fair value hedges is presented within finance debt on the group balance sheet.
BP Annual Report and Form 20-F 2019
213
30. Derivative financial instruments – continued
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.
At 1 January 2019
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 2019
Cash flow hedge reserve
Highly
probable
forecast capital
expenditure
Highly
probable
forecast sales
Purchase of
equitya
Costs of
hedging
reserve
Interest rate
and foreign
currency risk
on finance
debt
(21)
(6)
(651)
(223)
(3)
—
—
—
(3)
23
(1)
(100)
106
—
—
6
—
—
—
—
—
—
—
—
(651)
—
—
(4)
57
53
—
(170)
Cash flow hedge reserve
Costs of
hedging reserve
Highly probable
forecast capital
expenditure
Highly probable
forecast sales
Purchase of
equitya
Interest rate
and foreign
currency risk on
finance debt
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)
—
(37)
(37)
—
—
(244)
58
(186)
—
(223)
$ million
Total
(901)
(103)
106
(4)
57
56
23
(822)
$ 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.
214
BP Annual Report and Form 20-F 2019
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 – other
Repurchase of ordinary share capital
At 31 December
Shares
thousand
7,233
5,473
2019
$ million
12
9
21
Shares
thousand
7,233
5,473
2018
$ million
12
9
21
Shares
thousand
7,233
5,473
21,525,464
208,927
5,381
52
21,288,193
195,305
5,322
49
21,049,696
289,789
37,400
—
(235,951)
21,535,840
9
92,168
—
(50,202)
21,525,464
—
(59)
5,383
5,404
—
—
(51,292)
21,288,193
23
—
(13)
5,381
5,402
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 2019 the company repurchased 236 million ordinary shares for a total consideration of $1,511 million, including transaction costs of $8
million, as part of the share repurchase programme announced on 31 October 2017. All shares purchased were for cancellation. The
repurchased shares represented 1.1% of ordinary share capital. A further 120 million of shares have been repurchased in January 2020 at a
total cost of $776 million. The number of shares in issue is reduced when shares are repurchased.
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
2019
Shares
thousand
1,426,265
1,118
Nominal value
$ million
356
—
Shares
thousand
1,482,072
757
2018
Nominal value
$ million
370
—
Shares
thousand
1,614,657
4,423
2017
Nominal value
$ million
403
1
37,400
9
92,168
23
—
(167,927)
(42)
(148,732)
(37)
(137,008)
1,296,856
1,163,077
133,707
72
323
290
33
—
1,426,265
1,264,732
161,518
15
356
316
40
—
1,482,072
1,472,343
9,705
24
—
(34)
370
368
2
—
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 5.9% (2018 6.9% and 2017 7.5%) of the called-up ordinary share capital of the company.
During 2019, the movement in shares held in treasury by BP represented less than 0.5% (2018 less than 1.0% and 2017 less than 0.5%) of the
ordinary share capital of the company.
BP Annual Report and Form 20-F 2019
215
32. Capital and reserves
At 31 December 2018
Adjustment on adoption of IFRS 16, net of tax
At 1 January 2019
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 taxc
At 31 December 2019
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 taxd
At 31 December 2017
a Principally foreign exchange effects relating to the Russian rouble.
b Movements in treasury shares relate to employee share-based payment plans.
216
BP Annual Report and Form 20-F 2019
Share
capital
Share
premium
account
Capital
redemption
reserve
Merger
reserve
—
5,402 12,305
—
5,402 12,305
—
—
—
1,439 27,206
—
1,439 27,206
—
—
—
—
—
—
—
—
—
—
—
—
—
52
—
(59)
9
—
—
—
—
—
(52)
—
—
164
—
—
5,404 12,417
—
—
—
—
—
—
—
—
—
—
—
—
—
59
—
—
—
—
—
—
—
—
—
—
—
—
1,498 27,206
—
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
5,284 12,219
—
—
1,413 27,206
—
—
—
—
—
—
—
—
—
—
—
—
—
—
72
(13)
—
—
—
—
—
(72)
—
—
—
—
5,343 12,147
—
—
—
—
—
—
—
—
—
—
—
—
—
13
—
—
—
—
—
—
—
—
—
—
1,426 27,206
Total
share capital
and capital
reserves
46,352
—
46,352
—
—
—
—
—
—
—
—
—
—
—
173
—
—
46,525
46,122
—
46,122
—
—
—
—
—
—
—
—
—
—
—
230
—
—
46,352
46,122
—
—
—
—
—
—
—
—
—
—
—
—
—
46,122
32. Capital and reserves – continued
Treasury
shares
(15,767)
—
(15,767)
—
Foreign
currency
translation
reserve
(8,902)
—
(8,902)
—
—
—
—
—
—
—
—
—
—
—
1,355
—
—
(14,412)
(16,958)
—
(16,958)
—
—
—
—
—
—
—
—
—
—
—
1,191
—
—
(15,767)
(18,443)
—
—
—
—
—
—
—
—
—
—
1,485
—
—
(16,958)
2,407
—
—
—
—
—
2,407
—
—
—
—
—
—
(6,495)
(5,156)
—
(5,156)
—
(3,746)
—
—
—
—
—
(3,746)
—
—
—
—
—
—
(8,902)
(6,878)
—
1,722
—
—
—
—
—
1,722
—
—
—
—
—
(5,156)
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)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
3
—
—
14
—
—
—
—
14
—
—
—
—
—
17
(777)
—
(777)
—
—
5
—
—
—
(3)
2
—
23
—
—
—
—
(752)
(760)
—
(760)
—
—
(6)
—
—
—
(37)
(43)
—
26
—
—
—
—
(777)
(1,156)
—
—
—
396
—
—
—
396
—
—
—
—
—
(760)
(210)
—
(210)
—
—
50
—
—
—
—
50
—
—
—
—
—
—
(160)
—
(37)
(37)
—
—
(173)
—
—
—
—
(173)
—
—
—
—
—
—
(210)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(987)
—
(987)
—
—
55
—
—
—
(3)
52
—
23
—
—
—
—
(912)
(743)
(54)
(797)
—
—
(179)
—
—
—
(37)
(216)
—
26
—
—
—
—
(987)
(1,153)
—
—
14
396
—
—
—
410
—
—
—
—
—
(743)
78,748
(329)
78,419
4,026
—
—
82
(64)
171
—
4,215
(6,929)
—
(1,511)
(809)
5
316
73,706
75,226
(126)
75,100
9,383
—
—
417
7
1,599
—
11,406
(6,699)
—
(355)
(718)
14
—
78,748
75,638
3,389
(3)
—
—
564
(72)
2,343
6,221
(6,153)
(343)
(798)
215
446
75,226
99,444
(329)
99,115
4,026
2,407
55
82
(64)
171
(3)
6,674
(6,929)
23
(1,511)
719
5
316
98,412
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
95,286
3,389
1,719
14
396
564
(72)
2,343
8,353
(6,153)
(343)
687
215
446
98,491
2,104
(1)
2,103
164
9
—
—
—
—
—
173
(213)
—
—
—
—
233
2,296
1,913
—
1,913
195
(41)
—
—
—
—
—
154
(170)
—
—
—
—
207
2,104
1,557
79
52
—
—
—
—
—
131
(141)
—
—
—
366
1,913
c Principally relates to the sale of a 49% interest in BP's retail property portfolio in Australia.
d Principally relates to the initial public offering of common units in BP Midstream Partners LP for which net proceeds of $811 million were received.
$ million
Total equity
101,548
(330)
101,218
4,190
2,416
55
82
(64)
171
(3)
6,847
(7,142)
23
(1,511)
719
5
549
100,708
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
96,843
3,468
1,771
14
396
564
(72)
2,343
8,484
(6,294)
(343)
687
215
812
100,404
BP Annual Report and Form 20-F 2019
217
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.
218
BP Annual Report and Form 20-F 2019
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)
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
Pre-tax
Tax
Net of tax
$ million
2019
2,418
6
53
82
—
328
(3)
2,884
(2)
(1)
(3)
—
(64)
(157)
—
(227)
2,416
5
50
82
(64)
171
(3)
2,657
$ million
2018
Pre-tax
Tax
Net of tax
(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
33. Contingent liabilities
There were contingent liabilities at 31 December 2019 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, BP group entities are subject to legal and regulatory proceedings 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, climate change and environmental claims and allegations of exposures of third parties to toxic
substances, such as lead pigment in paint, asbestos and other chemicals. The amounts claimed 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, BP expects
that the impact of current 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, in aggregate, 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, BP does not expect there to be any
material impact upon the group‘s results of operations, financial position or liquidity.
BP Annual Report and Form 20-F 2019
219
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 costs are
inherently difficult to estimate. However, the estimated cost of environmental obligations has been provided in these accounts in accordance
with the group‘s accounting policies. While the amounts of future possible costs that are not provided for could be significant and 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 319-320.
Contingent liabilities related to the Gulf of Mexico oil spill
For information on legal proceedings relating to the Deepwater Horizon oil spill, see Legal proceedings on pages 319-320. Any further
outstanding Deepwater Horizon related claims are not expected to have a material impact on the group's financial performance.
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.
2019
2018
9
20
29
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.
Pension contributions
During 2019 one executive director participated in a UK final salary pension plan in respect of service prior to 1 April 2011. During 2019, 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 100. See also Related-party
transactions on page 321.
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
2019
2018
30
2
32
64
25
2
32
59
$ million
2017
29
2
29
60
Senior management comprises members of the executive team, see pages 78-79 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 2019 (2018 $nil and 2017 $nil).
Pensions and other post-retirement benefits
The amounts represent the estimated cost to the group of providing pensions and other post-retirement benefits to senior management in
respect of the current year of service measured in accordance with IAS 19 ‘Employee Benefits’.
Share-based payments
This is the cost to the group of senior management’s participation in share-based payment plans, as measured by the fair value of options and
shares granted, accounted for in accordance with IFRS 2 ‘Share-based Payments’.
220
BP Annual Report and Form 20-F 2019
35. Employee costs and numbers
Employee costs
Wages and salariesa
Social security costs
Share-based paymentsb
Pension and other post-retirement benefit costs
2019
7,497
733
694
948
9,872
2018
7,931
743
669
1,154
10,497
Average number of employeesc
US
Non-US
Upstream
Downstreamd
Other businesses and corporatee
5,800
5,700
2,100
13,600
11,000
37,300
10,600
58,900
2019
Total
16,800
43,000
12,700
72,500
US
Non-US
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
$ million
2017
7,572
711
624
1,296
10,203
2017
Total
18,400
42,000
14,300
74,700
a Includes termination costs of $182 million (2018 $493 million and 2017 $189 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 18,100 (2018 17,100 and 2017 16,500) service station staff.
e Includes 2,500 (2018 4,000 and 2017 4,700) 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
Non-audit and other assurance services
Total non-audit or non-audit-related assurance services
Services relating to BP pension plans
2019
2018
$ million
2017
32
11
43
4
47
1
1
1
49
25
10
35
4
39
2
2
1
42
26
11
37
7
44
3
3
—
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 years ended 31 December 2019 and 31
December 2018 thus relates to Deloitte and for the year ended 31 December 2017 EY.
2019 includes $3.6 million of additional fees for 2018. 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. Auditor's remuneration is included in the income statement within distribution and
administration expenses.
Tax services (in relation to income tax, indirect tax compliance, employee tax services and tax advisory services) were $nil in all periods
presented.
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 $49 million (2018 $42 million and 2017 $47 million) is required to be presented as
follows: audit $43 million (2018 $35 million and 2017 $37 million); other audit-related $4 million (2018 $4 million and 2017 $7 million); tax $nil
(2018 $nil and 2017 $nil); and all other fees $3 million (2018 $3 million and 2017 $3 million).
BP Annual Report and Form 20-F 2019
221
37. Subsidiaries, joint arrangements and associates
The more important subsidiaries and associates of the group at 31 December 2019 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
222
BP Annual Report and Form 20-F 2019
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. As described in Note 2, in 2020 BP expects, subject to governmental authorizations, to complete the sale of all of
its Alaska operations, including its interest in BP Exploration (Alaska) Inc., to Hilcorp Energy. Following completion of the sale, BP will continue
to fully and unconditionally guarantee the payment obligations of BP Exploration (Alaska) Inc. to 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.
BP p.l.c.
Other
subsidiaries
Eliminations
and
reclassifications
4,413
—
—
—
42
4
4,459
2,361
907
163
169
747
—
75
37
17
—
20
(40)
60
60
—
60
—
—
—
5,916
385
—
6,301
—
—
—
—
—
—
803
5,498
1,569
(153)
4,082
56
4,026
4,026
—
4,026
278,111
576
2,681
—
2,284
189
283,841
211,438
20,908
1,384
17,611
7,328
964
10,333
13,875
3,691
216
9,968
3,948
6,020
5,856
164
6,020
(4,127)
—
—
(5,916)
(1,942)
—
(11,985)
(4,127)
—
—
—
—
—
(154)
(7,704)
(1,788)
—
(5,916)
—
(5,916)
(5,916)
—
(5,916)
$ million
2019
BP group
278,397
576
2,681
—
769
193
282,616
209,672
21,815
1,547
17,780
8,075
964
11,057
11,706
3,489
63
8,154
3,964
4,190
4,026
164
4,190
BP Annual Report and Form 20-F 2019
223
38. Condensed consolidating information on certain US subsidiaries – continued
Income statement continued
Sales and other operating revenues
Earnings from joint ventures - after interest and tax
Earnings from associates - after interest and tax
Equity-accounted income of subsidiaries - after interest and tax
Interest and other income
Gains on sale of businesses and fixed assets
Total revenues and other income
Purchases
Production and manufacturing expenses
Production and similar taxes
Depreciation, depletion and amortization
Impairment and losses on sale of businesses and fixed assets
Exploration expense
Distribution and administration expenses
Profit (loss) before interest and taxation
Finance costs
Net finance (income) expense relating to pensions and other post-
retirement benefits
Profit (loss) before taxation
Taxation
Profit (loss) for the year
Attributable to
BP shareholders
Non-controlling interests
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.
4,315
—
—
—
42
—
4,357
1,507
1,015
282
377
66
—
22
1,088
8
—
1,080
164
916
916
—
916
BP p.l.c.
—
—
—
10,942
373
—
11,315
—
—
—
—
—
—
642
10,673
1,326
(95)
9,442
59
9,383
9,383
—
9,383
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)
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
3,264
—
—
—
11
71
3,346
1,010
1,156
(18)
735
—
—
19
444
6
—
438
(392)
830
830
—
830
BP p.l.c.
—
—
—
4,436
369
9
4,814
—
—
—
—
—
—
616
4,198
826
(15)
3,387
(11)
3,398
3,398
—
3,398
Other
subsidiaries
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
Eliminations and
reclassifications
(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
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
$ 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.
224
BP Annual Report and Form 20-F 2019
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
Exchange (gains) or losses on translation of foreign operations
transferred to gain or loss on sale of businesses and fixed assets
Cash flow hedges marked to market
Cash flow hedges - recycled to the income statement
Costs of hedging market 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
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
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
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
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
60
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
60
60
—
60
Other
subsidiaries
Eliminations
and
reclassifications
6,020
(5,916)
BP p.l.c.
4,026
200
—
—
—
—
—
—
—
200
732
—
(331)
401
601
2,047
6,674
6,674
—
6,674
1,338
880
(100)
106
(4)
57
82
(70)
2,289
(404)
(3)
174
(233)
2,056
—
8,076
7,903
173
8,076
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(2,047)
(7,963)
(7,963)
—
(7,963)
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
916
BP p.l.c.
9,383
Other
subsidiaries
Eliminations and
reclassifications
10,221
(10,942)
—
—
—
—
—
—
—
—
—
—
—
—
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)
BP Annual Report and Form 20-F 2019
$ million
2019
BP group
4,190
1,538
880
(100)
106
(4)
57
82
(70)
2,489
328
(3)
(157)
168
2,657
—
6,847
6,674
173
6,847
$ 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
225
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.
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)
$ 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
226
BP Annual Report and Form 20-F 2019
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
Assets classified as held for sale
Total assets
Current liabilities
Trade and other payables
Derivative financial instruments
Accruals
Lease liabilities
Finance debt
Current tax payable
Provisions
Liabilities directly associated with assets classified as held for sale
Non-current liabilities
Other payables
Derivative financial instruments
Accruals
Lease liabilities
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
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
44
690
—
—
45
—
—
779
5,023
5,802
5,802
436
—
347
—
—
—
—
783
706
1,489
—
—
—
—
—
456
114
—
570
2,059
3,743
3,743
—
3,743
—
—
—
—
2
—
167,895
167,897
—
2,771
—
—
—
6,588
177,256
—
—
135
—
—
—
—
—
135
—
135
177,391
17,986
—
21
—
—
—
—
18,007
—
18,007
31,927
—
—
—
—
2,293
—
202
34,422
52,429
124,962
124,962
—
124,962
132,642
11,868
15,539
9,991
20,332
1,276
—
191,648
32,524
2,147
6,314
781
4,560
465
238,439
339
20,836
42,157
4,153
857
1,237
169
22,472
92,220
2,442
94,662
333,101
46,947
3,261
4,698
2,067
10,487
2,039
2,453
71,952
687
72,639
15,364
5,537
996
7,655
57,237
7,001
18,384
8,390
120,564
193,203
139,898
137,602
2,296
139,898
—
—
—
—
—
—
(167,895)
(167,895)
(31,894)
(2,771)
—
—
—
—
(202,560)
—
—
(18,540)
—
—
—
—
—
(18,540)
—
(18,540)
(221,100)
(18,540)
—
—
—
—
—
—
(18,540)
—
(18,540)
(34,665)
—
—
—
—
—
—
—
(34,665)
(53,205)
(167,895)
(167,895)
—
(167,895)
BP Annual Report and Form 20-F 2019
$ million
2019
BP group
132,642
11,868
15,539
9,991
20,334
1,276
—
191,650
630
2,147
6,314
781
4,560
7,053
213,135
339
20,880
24,442
4,153
857
1,282
169
22,472
74,594
7,465
82,059
295,194
46,829
3,261
5,066
2,067
10,487
2,039
2,453
72,202
1,393
73,595
12,626
5,537
996
7,655
57,237
9,750
18,498
8,592
120,891
194,486
100,708
98,412
2,296
100,708
227
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 payables
Derivative financial instruments
Accruals
Lease liabilities
Finance debt
Current tax payable
Provisions
Non-current liabilities
Other payables
Derivative financial instruments
Accruals
Lease liabilities
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
2018
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
44
9,329
1,791
2,563
69,899
16,395
5,625
575
623
55,803
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)
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
44
9,329
2,101
2,564
68,237
13,830
5,625
575
623
55,803
9,812
17,732
8,391
112,391
180,628
101,548
99,444
2,104
101,548
228
BP Annual Report and Form 20-F 2019
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
Lease liability payments
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
$ million
2019
BP group
20
4,082
9,968
(5,916)
8,154
—
169
743
—
—
—
—
(1)
1
17
(6)
—
—
—
21
(31)
(132)
1,954
(444)
2,311
(173)
—
—
—
(173)
19
—
21
(133)
—
(46)
—
—
—
—
(2,132)
—
(2,178)
—
—
—
—
—
—
—
—
—
(5,916)
6,360
—
12
—
—
(153)
739
(10)
—
—
(155)
3,469
(1)
8,427
—
—
—
—
—
—
—
—
—
(1,511)
—
—
—
—
—
(6,929)
—
(8,440)
—
(13)
13
—
631
17,611
7,139
(3,257)
1,962
—
—
(2,228)
2,191
5,260
(4,652)
216
(9)
(228)
(197)
(3,375)
(2,048)
(2,600)
(4,992)
21,392
(15,245)
(3,562)
(137)
(304)
(19,248)
481
1,701
225
(16,841)
—
(2,326)
8,597
(7,118)
180
566
(4,245)
(213)
(4,559)
25
17
22,455
22,472
—
—
—
—
—
5,916
(6,360)
1,788
(1,788)
(1,788)
1,788
—
—
—
—
—
—
—
—
(6,360)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
6,360
—
6,360
—
—
—
—
631
17,780
7,882
(3,257)
1,962
—
—
(441)
416
3,489
(2,870)
63
730
(238)
(176)
(3,406)
(2,335)
2,823
(5,437)
25,770
(15,418)
(3,562)
(137)
(304)
(19,421)
500
1,701
246
(16,974)
(1,511)
(2,372)
8,597
(7,118)
180
566
(6,946)
(213)
(8,817)
25
4
22,468
22,472
BP Annual Report and Form 20-F 2019
229
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
Repurchase of shares
Lease liability payments
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
$ million
2018
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
BP p.l.c.
Other
subsidiaries
Eliminations and
reclassifications
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)
—
(35)
9,038
(7,175)
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)
(35)
9,038
(7,175)
1,317
(6,699)
(170)
(4,079)
(330)
(3,107)
25,575
22,468
230
BP Annual Report and Form 20-F 2019
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
Net issue (repurchase) of shares
Lease liability payments
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)
—
(45)
8,712
(6,231)
(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)
(45)
8,712
(6,231)
(158)
1,063
(6,153)
(141)
(3,296)
544
2,102
23,484
25,586
BP Annual Report and Form 20-F 2019
231
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 308-313.
232
BP Annual Report and Form 20-F 2019
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
2019
31,655
425
32,080
18,481
13,599
— 67,319
— 3,106
— 70,425
— 35,379
— 35,046
3,421
2,547
5,968
409
5,559
15,194
3,262
18,456
9,922
8,534
48,150
3,495
51,645
35,572
16,073
— 42,629
— 1,865
— 44,494
— 22,481
— 22,013
606
6,300 214,668
15,306
6,906 229,974
3,924 126,168
2,982 103,806
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
2
13
15
128
717
860
Results of operations for the year ended 31 Decembera
Sales and other operating revenuesd
229
2,345
2,574
157
607
(75)
(308)
1,383
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 taxes
Results of operations
5
—
50
—
55
—
—
271
— 4,047
— 4,373
— 1,780
— 10,785
— 12,565
—
233
— 2,742
—
315
— 2,527
— 4,456
—
1
1
15
33
49
274
1
275
13
118
—
67
118
(1)
315
(40)
(76)
36
—
220
220
220
737
1,177
1,620
142
1,762
124
437
293
92
1,056
—
18
18
417
2,530
2,965
2,736
2,815
5,551
222
1,045
—
33
3,806
483
(10)
5,726
2,247
327
(141)
468
(10) 15,999
(3,434)
10
—
(776)
(2,658)
10
160
151
2,162
(400)
(234)
(166)
5,257
294
593
(299)
—
46
(44)
(8)
(36)
1
4,360
4,824
3,078
1,746
188
—
—
—
188
—
2
171
— 2,614
2,973
2
—
—
—
61
137
198
195
302
497
1,285
10,815
12,597
1,588
2
— 7,596
9,184
2
187
2
961
—
951
—
(124)
42
2,384
2
1,142
554
1,696
26
131
63
153
297
9,371
24,238
33,609
964
6,041
1,547
2,482
13,502
—
6,510
670
1,026
392
634
31,046
2,563
2,828
(265)
Upstream and Rosneft segments replacement cost profit (loss) before interest and tax
Exploration and production activities –
subsidiaries (as above)
Midstream and other activities –
subsidiariesg
Equity-accounted entitiesh
Total replacement cost profit (loss)
before interest and tax
327
10
(3,434)
(40)
(400)
294
(44)
4,824
1,026
2,563
749
(6)
1,070
(26)
(363)
70
54
23
(3,774)
442
—
402
194
65
(19)
11
82
2,460
766
213
9
—
1,763
2,907
(141)
357
2,427
5,803
1,035
7,233
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 and other government take. The UK region includes a $361-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 $439 million which is included in finance costs in the group income statement.
g Midstream and other activities excludes inventory holding gains and losses.
h The profits of equity-accounted entities are included after interest and tax.
BP Annual Report and Form 20-F 2019
233
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
2019
Equity-accounted entities (BP share)
Capitalized costs at 31 Decemberb c
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
— 4,078
—
768
— 4,846
— 1,046
— 3,800
Costs incurred for the year ended 31 Decemberb d e
Acquisition of propertiesc
Proved
Unproved
Exploration and appraisal costsd
Development
Total costs
—
—
—
—
—
—
—
—
—
120
640
760
Results of operations for the year ended 31 Decemberb
Sales and other operating revenuesf
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)
Depreciation, depletion and amortization
Net impairments and losses on sale of
businesses and fixed assets
Profit (loss) before taxation
Allocable taxes
Results of operations
— 1,002
—
—
— 1,002
92
—
216
—
—
—
59
—
323
—
—
—
—
—
—
—
690
312
229
83
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— 10,376
—
93
— 10,469
— 5,078
— 5,391
— 29,883
— 1,120
— 31,003
— 9,248
— 21,755
—
—
—
—
—
—
—
—
—
19
675
694
— 1,621
—
—
— 1,621
43
—
465
—
343
—
16
—
414
—
—
—
58
—
58
—
—
198
— 3,076
— 3,332
—
—
— 15,979
— 15,979
—
73
— 1,535
— 7,861
—
358
— 1,773
—
(42)
—
49
— 1,239
382
—
245
—
137
—
— 11,649
— 4,330
—
848
— 3,482
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— 44,337
— 1,981
— 46,318
— 15,372
— 30,946
—
—
58
—
58
—
—
337
— 4,391
— 4,786
— 2,623
— 15,979
— 18,602
—
208
— 2,216
— 8,204
—
433
— 2,510
—
7
— 13,578
— 5,024
— 1,322
— 3,702
Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities
Exploration and production activities –
equity-accounted entities after tax (as
above)
Midstream and other activities after taxg
Total replacement cost profit (loss) after
interest and tax
—
(6)
(6)
83
(13)
70
—
23
23
—
—
—
137
(72)
— 3,482
82
(1,022)
65
82
2,460
—
213
213
— 3,702
—
(795)
— 2,907
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 sales tax.
g Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.
234
BP Annual Report and Form 20-F 2019
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
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
—
—
—
139
46
185
105
1
106
146
120
—
43
101
—
100
100
245
591
936
(1)
50
49
283
2,340
2,672
36
—
(5)
—
31
—
148
5
— 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
— 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
(226)
—
203
1,124
1,750
446
1,304
(2) 10,110
2,852
2
454
—
2,398
2
10
420
(314)
(95)
(219)
—
(141)
2,227
42
314
(272)
5,098
2,058
1,184
874
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 taxes.
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 2019
235
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
425
—
148
—
573
—
—
207
— 3,255
— 4,035
— 1,792
—
—
— 1,792
7
—
438
—
361
—
55
—
416
—
—
—
— 15,901
— 15,901
—
112
— 1,487
— 7,634
—
638
— 1,627
—
—
—
47
— 1,277
515
—
321
—
194
—
— 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
—
714
— 2,545
—
54
— 13,781
— 5,379
— 1,520
— 3,859
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
—
—
—
194
15
209
— 3,507
207
(1,161)
207
2,346
7
238
245
— 3,859
—
(696)
— 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 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.
236
BP Annual Report and Form 20-F 2019
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 2019
237
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 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.
238
BP Annual Report and Form 20-F 2019
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
Production
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
UK
Rest of
Europe
USc d
Rest of
North
America
223
243
466
(23)
—
—
—
(36)
—
(59)
206
200
406
—
—
—
—
—
—
—
—
—
—
—
—
—
223
243
466
962
—
—
802
— 1,764
—
—
—
—
—
—
—
72
189
—
34
(143)
(12)
141
— 1,063
842
—
— 1,905
57
100
157
2
4
—
—
(13)
—
(7)
115
35
150
57
100
157
—
—
—
—
—
—
—
—
—
—
—
—
—
962
802
1,764
1,063
842
1,905
43
190
234
(8)
1
—
—
(9)
—
(16)
40
179
218
—
19
19
1
—
—
—
—
—
1
—
20
20
43
209
253
40
198
238
8
5
14
1
—
—
—
(3)
—
(2)
7
5
12
293
259
552
(13)
—
—
33
(24)
—
(4)
291
257
548
302
264
566
298
262
560
Africa
Asia
Australasia
Total
million barrels
2019
Russia
Rest of
Asia
— 1,126
—
482
— 1,608
—
—
—
—
—
—
—
104
—
1
11
(125)
—
(9)
— 1,074
525
—
— 1,599
223
36
259
39
—
—
—
(57)
(45)
(63)
156
40
196
3,190
1
— 2,414
5,604
1
1
—
—
—
—
—
1
158
—
7
277
(345)
(6)
91
2
3,159
— 2,535
5,695
2
—
—
—
—
—
—
—
—
—
—
—
—
—
224
36
260
158
40
198
3,190
2,414
5,604
3,159
2,535
5,695
1,126
482
1,608
1,074
525
1,599
30
5
34
2
—
—
—
(6)
—
(4)
26
4
30
2,615
1,763
4,378
187
191
1
45
(378)
(57)
(12)
2,572
1,794
4,367
— 3,541
— 2,792
— 6,333
—
—
—
—
—
—
—
147
4
7
310
(382)
(6)
81
— 3,567
— 2,847
— 6,415
30
5
34
26
4
30
6,156
4,555
10,711
6,140
4,642
10,781
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
At 31 December
Developed
Undeveloped
206
200
406
115
35
150
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 4.5 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 362 million barrels of crude oil associated with Assets Held for Sale in the USA.
e Includes 4 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 346 million barrels of crude oil in respect of the 6.17% non-controlling interest in Rosneft, including 26 mmbbl held through BP's interests in Russia other than Rosneft.
h Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,604 million barrels, comprising less than 1 million barrels in Egypt, Vietnam, Iraq and Canada, 35 million
barrels in Venezuela and 5,568 million barrels in Russia.
BP Annual Report and Form 20-F 2019
239
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
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
Total
million barrels
2019
UK
8
6
14
—
1
—
—
(1)
—
(1)
8
5
13
—
—
—
—
—
—
—
—
—
—
—
—
—
Rest of
Europe
—
—
—
—
—
—
—
—
—
—
—
—
—
4
3
7
—
1
—
—
(1)
—
—
5
3
7
4
3
7
5
3
7
Rest of
North
America
Russia
Rest of
Asia
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2
25
27
(1)
—
—
—
(3)
—
(4)
2
21
23
—
—
—
3
—
—
—
—
—
2
2
—
2
2
25
27
4
21
25
14
4
18
—
—
—
—
(3)
—
(3)
12
4
16
7
—
7
5
—
—
—
(2)
—
4
11
—
11
22
4
26
23
4
27
—
—
—
—
—
—
—
—
—
—
—
—
—
103
51
154
(11)
—
—
—
(2)
—
(13)
89
52
141
103
51
154
89
52
141
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
USc
266
246
511
(46)
62
—
1
(33)
(17)
(32)
229
250
479
—
—
—
—
—
—
—
—
—
—
—
—
—
266
246
511
229
250
479
5
—
5
—
—
—
—
(1)
—
(1)
4
—
4
—
—
—
—
—
—
—
—
—
—
—
—
—
5
—
5
4
—
4
295
280
576
(47)
63
—
1
(41)
(17)
(41)
255
280
535
114
54
169
(3)
1
—
—
(4)
—
(7)
107
55
162
409
335
744
363
334
697
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
8
6
14
At 31 December
Developed
Undeveloped
8
5
13
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 94 million barrels of NGL associated with Assets Held for Sale in the USA.
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 Includes 7 million barrels of NGL 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 11 million barrels of NGLs in respect of the 7.90% non-controlling interest in Rosneft.
h Total proved NGL reserves held as part of our equity interest in Rosneft is 141 million barrels, comprising less than 1 million barrels in Egypt, Venezuela, Vietnam and Canada, and 141 million
barrels in Russia.
240
BP Annual Report and Form 20-F 2019
Movements in estimated net proved reserves - continued
Total liquidsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione
Sales of reserves-in-place
At 31 Decemberf
Developed
Undeveloped
Equity-accounted entities (BP share)g
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberh i
Developed
Undeveloped
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
USc d
Rest of
North
America
Russia
Rest of
Asia
million barrels
2019
231
249
480
(24)
1
—
—
(38)
—
(60)
214
205
420
—
—
—
—
—
—
—
—
—
—
—
—
—
231
249
480
— 1,228
— 1,048
— 2,276
—
—
—
—
—
—
—
26
252
—
35
(176)
(28)
109
— 1,292
— 1,092
— 2,384
60
104
164
2
5
—
—
(14)
—
(7)
120
37
157
60
104
164
—
—
—
—
—
—
—
—
—
—
—
—
—
1,228
1,048
2,276
1,292
1,092
2,384
43
190
234
(8)
1
—
—
(9)
—
(16)
40
179
218
—
19
19
1
—
—
—
—
—
1
—
20
20
44
209
253
40
198
238
10
30
41
—
—
—
—
(6)
—
(6)
9
26
35
293
259
552
(11)
—
—
33
(24)
—
(1)
293
257
550
303
289
593
302
283
585
237
40
277
40
—
—
—
(60)
(45)
(65)
168
43
212
— 1,126
—
482
— 1,608
—
—
—
—
—
—
—
104
—
1
11
(125)
—
(9)
— 1,074
525
—
— 1,599
3,293
8
— 2,465
5,758
8
7
—
—
—
(2)
—
5
146
—
7
277
(346)
(6)
78
13
3,248
— 2,588
5,836
13
—
—
—
—
—
—
—
—
—
—
—
—
—
245
40
285
181
43
224
3,293
2,465
5,758
3,248
2,588
5,836
1,126
482
1,608
1,074
525
1,599
35
5
39
2
—
—
—
(7)
—
(5)
30
4
34
2,910
2,044
4,954
140
254
1
46
(420)
(74)
(52)
2,828
2,074
4,902
— 3,655
— 2,846
— 6,502
—
—
—
—
—
—
—
145
5
7
310
(386)
(6)
75
— 3,675
— 2,902
— 6,576
35
5
39
30
4
34
6,565
4,890
11,456
6,502
4,976
11,478
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
At 31 December
Developed
Undeveloped
214
205
420
120
37
157
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 4.5 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 Includes 456 million barrels associated with Assets Held for Sale in the USA.
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 11 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 357 million barrels in respect of the non-controlling interest in Rosneft, including 26 mmboe held through BP’s interests in Russia other than Rosneft.
i Total proved liquid reserves held as part of our equity interest in Rosneft is 5,745 million barrels, comprising 35 million barrels in Venezuela, less than 1 million barrels in Iraq, Canada, Egypt
and Vietnam and 5,709 million barrels in Russia.
BP Annual Report and Form 20-F 2019
241
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
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
Productiond
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
Africa
Asia
Australasia
Total
billion cubic feet
2019
Russia
Rest of
Asia
439
343
782
(34)
9
—
—
(57)
—
(82)
493
207
700
—
—
—
—
—
—
—
—
—
—
—
—
—
439
343
782
— 6,270
— 5,056
— 11,326
— (1,877)
307
—
—
—
11
—
(923)
—
—
(386)
— (2,869)
— 6,330
— 2,127
— 8,458
— 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
1
—
—
—
(1)
—
—
(263)
—
—
178
(729)
—
(814)
(4)
—
—
—
(450)
(21)
(475)
—
—
—
—
—
—
—
285
—
50
299
(383)
—
251
(129)
—
—
—
(291)
—
(420)
(2,022)
315
50
488
(2,834)
(406)
(4,410)
— 2,192
— 2,235
— 4,427
1,163
742
1,905
— 3,667
— 3,401
— 7,068
2,256
1,132
3,389
16,101
9,844
25,946
107
55
161
9
15
—
—
(22)
—
2
108
56
164
107
55
161
—
—
—
—
—
—
—
—
—
—
—
—
—
6,270
5,056
11,326
6,330
2,127
8,458
— 1,207
4
446
1,653
4
391
143
534
7,798
8,719
16,517
12
4
15
—
—
—
—
(5)
—
(5)
10
—
10
— 9,515
— 9,369
— 18,884
—
—
—
—
—
—
—
718
15
—
714
(676)
—
772
— 11,079
— 8,576
— 19,656
38
—
—
—
(65)
—
(27)
789
—
—
534
(448)
—
874
507
9,324
— 8,067
17,391
507
1,704
1,210
2,914
1,670
742
2,412
7,798
8,719
16,517
9,324
8,067
17,391
3,610
3,221
6,832
3,677
3,401
7,078
2,630
1,179
3,809
2,256
1,132
3,389
25,934
23,305
49,239
27,181
18,421
45,601
3
—
—
—
—
—
3
(120)
—
—
180
(135)
—
(75)
— 1,130
6
447
1,577
6
— 3,375
3,519
4
6,894
4
— 3,323
2,682
6
6,004
6
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
At 31 December
Developed
Undeveloped
493
207
700
108
56
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 Includes 3,054 billion cubic feet of natural gas associated with Assets Held for Sale in the USA.
d Includes 188 billion cubic feet of natural gas consumed in operations, 146 billion cubic feet in subsidiaries, 42 billion cubic feet in equity-accounted entities.
e Includes 1,330 billion cubic feet of natural gas 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 1,433 billion cubic feet of natural gas in respect of the 9.72% non-controlling interest in Rosneft including 569 billion cubic feet held through BP’s interests in Russia other than
Rosneft.
h Total proved gas reserves held as part of our equity interest in Rosneft is 14,705 billion cubic feet, comprising 28 billion cubic feet in Venezuela, 10 billion cubic feet in Vietnam, 171 billion
cubic feet in Egypt and 14,495 billion cubic feet in Russia.
242
BP Annual Report and Form 20-F 2019
Movements in estimated net proved reserves – continued
Total hydrocarbonsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionf g
Sales of reserves-in-place
At 31 Decemberh
Developed
Undeveloped
Equity-accounted entities (BP share)i
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionf
Sales of reserves-in-place
At 31 Decemberj k
Developed
Undeveloped
Europe
North
America
South
America
UK
Rest of
Europe
USd e
Rest of
North
America
million barrels of oil equivalentc
2019
Africa
Asia
Australasia
Total
Russia
Rest of
Asia
— 1,746
— 1,037
— 2,783
488
208
696
5,741
4,447
10,188
307
308
615
(29)
3
—
—
(48)
—
(74)
300
241
540
—
—
—
—
—
—
—
—
—
—
—
—
—
307
308
615
— 2,309
— 1,919
— 4,228
—
—
—
—
—
—
—
(297)
305
—
36
(335)
(95)
(386)
— 2,384
— 1,459
— 3,842
79
113
192
4
7
—
—
(17)
—
(6)
139
47
186
79
113
192
—
—
—
—
—
—
—
—
—
—
—
—
—
2,309
1,919
4,228
2,384
1,459
3,842
43
190
234
(8)
1
—
—
(9)
—
(16)
40
179
218
—
20
20
1
—
—
—
—
—
1
—
21
21
44
210
253
40
199
239
384
560
944
(45)
—
—
31
(131)
—
(146)
387
411
798
501
336
837
(31)
—
—
64
(47)
—
(14)
488
334
822
464
224
687
39
—
—
—
(137)
(49)
(147)
369
171
540
76
25
101
13
—
—
—
(13)
—
—
—
—
—
—
—
—
—
153
—
10
63
(191)
—
35
— 1,707
— 1,111
— 2,818
4,638
3,968
8,605
282
—
7
369
(424)
(6)
229
100
4,856
— 3,978
8,834
100
2
1
3
—
—
—
—
(1)
—
(1)
2
—
2
885
896
1,781
875
746
1,621
539
249
788
469
171
640
4,638
3,968
8,605
4,856
3,978
8,834
1,749
1,037
2,786
1,708
1,112
2,820
(21)
—
—
—
(57)
—
(78)
419
199
618
(208)
309
10
130
(908)
(144)
(813)
5,604
3,771
9,375
— 5,296
— 4,462
— 9,757
—
—
—
—
—
—
—
269
7
7
434
(503)
(6)
208
— 5,585
— 4,381
— 9,965
488
208
696
419
199
618
11,037
8,908
19,945
11,189
8,152
19,341
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
At 31 December
Developed
Undeveloped
300
241
540
139
47
186
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 4.5 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 Includes 982 million barrels of oil equivalent associated with Assets Held for Sale in the USA.
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 32 million barrels of oil equivalent of natural gas consumed in operations, 25 million barrels of oil equivalent in subsidiaries, 7 million barrels of oil equivalent in equity-accounted
entities.
h Includes 240 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 603 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 124 mmboe held through BP’s interests in Russia other than Rosneft.
k Total proved reserves held as part of our equity interest in Rosneft is 8,281 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Iraq and Canada, 40 million
barrels of oil equivalent in Venezuela, 2 million barrels of oil equivalent in Vietnam, 30 million barrels of oil equivalent in Egypt and 8,208 million barrels of oil equivalent in Russia.
BP Annual Report and Form 20-F 2019
243
Movements in estimated net proved reserves – continued
Crude oila b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberd e
Developed
Undeveloped
Equity-accounted entities (BP share)f
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberg
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
2018
Total
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
281
28
309
11
1
—
13
(75)
—
(50)
223
36
259
— 1,040
—
642
— 1,682
—
—
—
—
—
—
—
40
—
—
—
(114)
—
(74)
— 1,126
482
—
— 1,608
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.
244
BP Annual Report and Form 20-F 2019
Movements in estimated net proved reserves – continued
Europe
North
America
South
America
Africa
Asia
Australasia
million barrels
2018
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
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.
g 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.
BP Annual Report and Form 20-F 2019
245
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
Total
UK
Rest of
Europe
USc
Rest of
North
America
Russia
Rest of
Asia
million barrels
2018
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
301
28
329
8
3
—
16
(79)
—
(52)
237
40
277
— 1,040
—
642
— 1,682
—
—
—
—
—
—
—
40
—
—
—
(114)
—
(74)
— 1,126
482
—
— 1,608
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.
246
BP Annual Report and Form 20-F 2019
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
2018
Total
billion cubic feet
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
446
4
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.
BP Annual Report and Form 20-F 2019
247
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
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.
248
BP Annual Report and Form 20-F 2019
Movements in estimated net proved reserves – continued
Crude oila b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberd e
Developed
Undeveloped
Equity-accounted entities (BP share)f
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberg
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.
BP Annual Report and Form 20-F 2019
249
Movements in estimated net proved reserves – continued
Europe
North
America
South
America
Africa
Asia
Australasia
million barrels
2017
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
13
3
16
2
—
—
—
(3)
(1)
(2)
11
3
14
—
—
—
—
—
—
—
—
—
—
—
—
—
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
13
3
16
At 31 December
Developed
Undeveloped
11
3
14
—
—
—
—
—
—
—
—
—
—
—
—
—
3
2
5
—
1
2
—
(1)
—
3
4
4
8
3
2
5
4
4
8
226
73
299
(44)
15
—
1
(24)
—
(52)
177
69
246
—
—
—
—
—
—
—
—
—
—
—
—
—
226
73
299
177
69
246
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
5
28
33
—
—
—
—
(3)
—
(3)
2
28
30
—
—
—
—
—
—
—
—
—
—
—
—
—
5
28
33
2
28
30
13
1
14
11
—
—
—
(4)
—
7
21
—
21
11
—
11
1
—
—
—
(1)
—
(1)
10
—
10
24
1
25
31
—
31
—
—
—
—
—
—
—
—
—
—
—
—
—
50
15
65
68
—
—
—
(2)
—
66
82
49
131
50
15
65
82
49
131
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
9
2
11
(4)
—
—
—
(1)
—
(5)
5
1
6
—
—
—
—
—
—
—
—
—
—
—
—
—
9
2
11
5
1
6
266
107
373
(36)
15
—
1
(35)
(1)
(55)
216
102
318
65
17
81
69
1
2
—
(4)
—
68
97
53
149
331
123
454
313
154
467
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to
make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 2 thousand barrels per day for equity-accounted entities.
d Includes 9 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
f Total proved NGL reserves held as part of our equity interest in Rosneft is 131 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 131 million barrels
in Russia.
250
BP Annual Report and Form 20-F 2019
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.
h Total proved liquid reserves held as part of our equity interest in Rosneft is 5,533 million barrels, comprising less than 1 million barrels in Canada, 59 million barrels in Venezuela, less than
1 million barrels in Vietnam and 5,473 million barrels in Russia.
BP Annual Report and Form 20-F 2019
251
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.
252
BP Annual Report and Form 20-F 2019
Movements in estimated net proved reserves – continued
Total hydrocarbonsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione f
Sales of reserves-in-place
At 31 Decemberg
Developed
Undeveloped
Equity-accounted entities (BP share)h
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione
Sales of reserves-in-place
At 31 Decemberi j
Developed
Undeveloped
Europe
North
America
South
America
UK
Rest of
Europe
USd
Rest of
North
America
million barrels of oil equivalentc
2017
Africa
Asia
Australasia
Total
254
338
592
25
—
8
—
(45)
(11)
(23)
347
222
569
—
—
—
—
—
—
—
—
—
—
—
—
—
254
338
592
— 1,990
— 1,012
— 3,002
42
209
251
321
896
1,217
—
—
—
—
—
—
—
157
200
1
14
(270)
—
102
5
—
—
—
(8)
—
(2)
(116)
—
—
143
(131)
—
(104)
— 2,011
— 1,093
— 3,104
54
195
248
505
608
1,114
462
420
882
(32)
2
92
3
(157)
—
(93)
501
288
790
Russia
Rest of
Asia
— 1,433
—
895
— 2,327
—
—
—
—
—
—
—
451
1
—
254
(145)
—
562
— 1,515
— 1,374
— 2,889
63
75
138
5
19
42
1
(15)
(7)
46
80
105
184
63
75
138
—
—
—
—
—
—
—
—
—
—
—
—
—
1,990
1,012
3,002
2,011
1,093
3,104
588
—
—
417
— 1,005
4,168
83
— 3,235
7,404
83
—
—
—
—
—
—
—
—
—
—
42
209
251
54
195
249
9
14
—
34
(58)
(158)
(159)
505
341
846
909
1,313
2,222
1,010
949
1,959
2
—
41
—
(7)
—
35
93
25
119
545
420
966
595
314
908
439
—
38
320
(411)
—
386
4,254
3,536
7,790
4,168
3,235
7,404
4,254
3,536
7,790
47
1
49
(1)
—
—
—
(38)
—
(39)
9
1
10
1,480
896
2,376
1,524
1,374
2,899
561
299
860
(24)
—
—
—
(57)
—
(81)
507
272
779
5,063
4,068
9,131
467
203
100
413
(812)
(11)
361
5,440
4,052
9,492
— 4,951
— 3,729
— 8,679
—
—
—
—
—
—
—
454
33
122
355
(530)
(165)
269
— 4,941
— 4,008
— 8,949
561
299
860
507
272
779
10,014
7,797
17,810
10,381
8,060
18,441
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
At 31 December
Developed
Undeveloped
347
222
569
80
105
184
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to
make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 9 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the
terms of the BP Prudhoe Bay Royalty Trust.
e Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 2 thousand barrels per day for equity-accounted entities.
f Includes 31 million barrels of oil equivalent of natural gas consumed in operations, 23 million barrels of oil equivalent in subsidiaries, 8 million barrels of oil equivalent in equity-accounted
entities.
g Includes 335 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
h Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
i
Includes 391 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 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.
BP Annual Report and Form 20-F 2019
253
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
2019
Total
28,600
13,700
1,700
5,200
8,000
2,700
— 135,900
— 59,200
— 16,400
—
8,700
— 51,600
— 23,100
7,400
3,400
1,200
200
2,600
1,400
11,500
5,700
2,000
1,300
2,500
600
21,200
6,700
1,300
3,300
9,900
2,300
— 135,800
— 53,200
— 16,700
— 46,000
— 19,900
7,200
—
24,000 364,400
6,100 148,000
42,000
2,700
5,300
70,000
9,900 104,400
41,700
4,400
5,300
— 28,500
1,200
1,900
7,600
— 12,700
5,500
62,700
— 10,300
— 3,500
—
700
— 4,700
— 1,400
400
—
— 1,000
—
—
—
—
—
—
—
— 36,800
— 14,900
— 3,900
— 4,100
— 13,900
— 8,200
— 322,000
— 222,600
— 21,800
— 13,300
— 64,300
— 37,100
— 5,700
— 27,200
—
—
—
—
—
—
—
— 369,100
— 241,000
— 26,400
— 22,100
— 79,600
— 45,700
— 33,900
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
Total subsidiaries and equity-accounted entities
Standardized measure of discounted
future net cash flowsj
5,300
1,000
28,500
1,200
7,600
7,600
27,200
12,700
5,500
96,600
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 yeark
Subsidiaries
Equity-accounted
entities (BP share)
(27,400)
9,200
3,800
(28,100)
300
16,600
(1,500)
(1,400)
8,300
(20,200)
(8,400)
4,100
2,600
(8,200)
1,100
2,400
(4,300)
—
4,100
(6,600)
$ million
Total subsidiaries and
equity-accounted
entities
(35,800)
13,300
6,400
(36,300)
1,400
19,000
(5,800)
(1,400)
12,400
(26,800)
a The marker prices used were Brent $62.74/bbl, Henry Hub $2.58/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 $600 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 $2,100 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
Includes future net cash flows for assets held for sale at 31 December 2019.
k 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’.
254
BP Annual Report and Form 20-F 2019
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
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
— 238,400
— 19,300
— 17,700
— 81,400
— 48,100
— 5,900
— 33,300
—
—
—
—
—
—
—
— 408,100
— 258,700
— 23,700
— 28,000
— 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
3,300
13,100
2,000
(4,600)
(3,500)
400
3,100
10,100
$ million
Total subsidiaries and
equity-accounted
entities
(26,800)
12,800
9,100
54,100
(100)
(21,600)
(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. 2018 comparative for Russia equity-accounted entity future production cost has been restated from $232,100 million to maintain consistency
with 2019 presentation.
c Taxation is computed with reference to appropriate year-end statutory corporate income tax rates. 2018 comparative for Russia equity-accounted entity future taxation has been restated
from $24,000 million to maintain consistency with 2019 presentation.
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’.
BP Annual Report and Form 20-F 2019
255
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 yearj
Subsidiaries
Equity-accounted
entities (BP share)
(12,800)
9,800
2,300
33,100
2,800
(12,500)
3,000
800
2,300
28,800
(5,500)
4,200
1,300
7,300
1,000
(1,500)
(4,600)
(600)
2,600
4,200
$ million
Total subsidiaries and
equity-accounted
entities
(18,300)
14,000
3,600
40,400
3,800
(14,000)
(1,600)
200
4,900
33,000
a The marker prices used were Brent $54.36/bbl, Henry Hub $2.96/mmBtu.
b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions.
Future decommissioning costs are included.
c Taxation is computed with reference to appropriate year-end statutory corporate income tax rates.
d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.
e Non-controlling interests in BP Trinidad and Tobago LLC amounted to $1,100 million.
f The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted
investments of those entities.
g Non-controlling interests in Rosneft amounted to $1,963 million in Russia.
h No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
i Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft to US
dollars are included within ‘Net changes in prices and production cost’.
256
BP Annual Report and Form 20-F 2019
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 2019, 2018 and 2017.
Production for the yeara b
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
Subsidiariesd
Crude oile
2019
2018
2017
Natural gas liquids
2019
2018
2017
Natural gasf
2019
2018
2017
Equity-accounted entities (BP share)
Crude oile
2019
2018
2017
Natural gas liquids
2019
2018
2017
Natural gasf
2019
2018
2017
100
101
80
3
5
6
129
152
182
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
35
34
31
2
2
2
56
59
53
US
400
385
370
81
60
56
2,358
1,900
1,659
—
—
—
—
—
—
—
—
—
Rest of
North
America
Russiac
Rest of
Asia
24
24
20
—
—
—
2
7
9
—
—
—
—
—
—
—
—
—
7
7
12
9
9
10
156
204
241
8
11
10
1,977
2,136
1,936
1,138
1,061
949
56
55
63
1
—
—
314
335
418
1
1
1
8
6
6
87
80
77
—
—
—
—
—
—
—
—
—
955
933
905
3
4
4
1,279
1,286
1,308
thousand barrels per day
17
17
17
1,046
1,051
1,064
thousand barrels per day
2
2
2
104
88
85
million cubic feet per day
786
819
783
7,366
6,900
5,889
thousand barrels per day
—
—
—
1,047
1,040
1,099
thousand barrels per day
—
—
—
14
12
12
million cubic feet per day
—
—
—
1,736
1,760
1,855
343
313
325
—
—
—
976
826
371
—
16
99
—
—
—
—
—
—
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 All of the oil and liquid production from Canada is bitumen.
e Crude oil includes condensate.
f Natural gas production excludes gas consumed in operations.
BP Annual Report and Form 20-F 2019
257
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 2019. 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 2019
Oil wellsc
Gas wellsd
Undevelopede
– gross
– net
– gross
– net
– gross
– net
– gross
– net
Oil and natural gas acreage at 31 December 2019
Developed
Europe
UK
Rest of
Europe
South
America
North
America
US
Rest of
North
America
117
70
36
7
75
44
2,851
1,594
80
24
1
—
81
24
150
45
2,775
1,152
18,552
8,811
6,232
3,658
5,311
3,749
177
48
238
118
143
62
14,953
7,890
5,526
2,528
1,119
401
1,354
361
23,892
8,456
Africa
Asia
Australasia
Totalb
Russiaa
66,696
13,278
447
92
290
65
220
91
823
287
51,105
33,683
7,709
1,377
439,848
84,689
Rest of
Asia
2,067
477
129
60
1,322
292
9,793
2,430
77,740
12
17,644
2
20,820
78
9,596
16
thousands of acres
173
41
4,022
1,889
17,912
6,146
551,925
144,425
a Based on information received from Rosneft as at 31 December 2019.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes approximately 6,916 gross (1,314 net) multiple completion wells (more than one formation producing into the same well bore).
d Includes approximately 2,618 gross (1,265 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
2019
Exploratory
Productive
Dry
Development
Productive
Dry
2018
Exploratory
Productive
Dry
Development
Productive
Dry
2017
Exploratory
Productive
Dry
Development
Productive
Dry
UK
Rest of
Europe
—
1.0
1.7
—
0.3
—
1.4
—
2.8
2.4
2.5
—
0.2
0.3
2.4
0.3
—
—
0.6
—
0.1
—
0.5
—
US
0.8
1.6
193.0
10.0
1.7
—
142.7
6.8
1.5
—
124.0
0.5
Rest of
North
America
Russia
Rest of
Asia
0.8
0.5
0.2
—
—
0.5
5.0
—
1.2
—
8.0
—
3.5
1.1
110.7
0.6
2.0
2.0
103.9
3.6
3.2
—
103.7
1.6
2.3
0.3
6.0
—
—
2.4
14.4
—
2.6
2.9
16.5
2.1
11.6
0.5
230.8
—
15.0
—
137.3
—
9.4
—
282.7
—
5.2
0.4
49.6
1.0
5.0
—
53.5
2.6
1.4
1.0
43.6
0.8
—
0.2
0.4
—
—
—
1.3
—
—
—
1.1
—
24.4
5.9
594.8
11.9
24.0
4.9
460.1
13.0
22.2
6.3
582.6
5.0
a Because of rounding, some totals may not exactly agree with the sum of their component parts.
258
BP Annual Report and Form 20-F 2019
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 2019. 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 2019
Exploratory
Gross
Net
Development
Gross
Net
UK
—
—
6.0
2.0
Rest of
Europe
—
—
3.6
1.1
US
8.0
4.9
213.0
140.0
Rest of
North
America
—
—
6.0
3.0
a Because of rounding, some totals may not exactly agree with the sum of their component parts.
Russia
Rest of
Asia
2.0
0.5
13.0
4.1
4.0
1.6
26.0
14.5
—
—
—
—
5.0
0.5
216.0
29.1
—
—
2.0
0.8
19.0
7.5
485.6
194.6
BP Annual Report and Form 20-F 2019
259
Parent company financial statements of BP p.l.c.
Company balance sheet
At 31 December
Non-current assets
Investments
Receivables
Defined benefit pension plan surpluses
Current assets
Receivables
Cash and cash equivalents
Total assets
Current liabilities
Payables
Non-current liabilities
Payables
Deferred tax liabilities
Defined benefit pension plan deficits
Total liabilities
Net assets
Capital and reservesa
Profit and loss account
Brought forward
Profit for the year
Other movements
Called-up share capital
Share premium account
Other capital and reserves
Note
2019
2
3
4
3
5
5
6
4
7
$ million
2018
166,271
2,600
5,473
174,344
151
13
164
174,508
166,256
2,771
6,588
175,615
135
—
135
175,750
18,007
14,665
31,927
2,293
202
34,422
52,429
123,321
96,430
4,470
(8,829)
92,071
5,404
12,417
13,429
123,321
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
a See Statement of changes in equity on page 261 for further information.
The financial statements on pages 260-296 were approved and signed by the group chief executive on 18 March 2020 having been duly
authorized to do so by the board of directors:
B Looney Chief executive officer
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
Company statement of changes in equitya
Share capital
Share
premium
account
Capital
redemption
reserve
5,402
—
—
—
52
(59)
9
5,404
5,343
—
—
—
49
(13)
23
5,402
12,305
—
—
—
(52)
—
164
12,417
12,147
—
—
—
(49)
—
207
12,305
1,439
—
—
—
—
59
—
1,498
1,426
—
—
—
—
13
—
1,439
Merger
reserve
26,509
—
—
—
—
—
—
26,509
26,509
—
—
—
—
—
—
26,509
$ million
Foreign
currency
translation
reserve
Profit and
loss account
Total equity
(366)
—
200
200
—
—
—
(166)
(70)
—
(296)
(296)
—
—
—
(366)
96,430
4,470
401
4,871
(6,929)
(1,511)
(790)
92,071
101,078
1,931
1,178
3,109
(6,699)
(355)
(703)
96,430
125,952
4,470
601
5,071
(6,929)
(1,511)
738
123,321
129,475
1,931
882
2,813
(6,699)
(355)
718
125,952
Treasury
shares
(15,767)
—
—
—
—
—
1,355
(14,412)
(16,958)
—
—
—
—
—
1,191
(15,767)
At 1 January 2019
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 2019
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
a See Note 8 for further information.
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
261
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 2019 were approved and signed by the chief executive officer on
18 March 2020 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)
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 in paragraph 38 of IAS 1 'Presentation of Financial Statements' to present comparative information in respect of
paragraph 79(a)(iv) of IAS 1.
(d)
the requirements of IAS 7 ‘Statement of Cash Flows’;
(e)
(f)
(g)
(h)
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’;
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; and
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 260-296 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 2019
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 260-296 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 2019
263
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
rights to receive cash flows have been transferred to a third party along with substantially all of the risks and rewards or control of the 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.
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 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.
Impact of new International Financial Reporting Standards
The company adopted IFRS 16 ‘Leases’, which replaced IAS 17 ‘Leases’ and IFRIC 4 ‘Determining whether an arrangement contains a lease’,
with effect from 1 January 2019. The adoption of IFRS 16 has had no material impact on the company's financial statements. There are no other
new or amended standards or interpretations adopted during the year that have a significant impact on the financial statements.
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
2. Investments
Cost
At 1 January 2019
Additions
Disposals
At 31 December 2019
Amounts provided
At 1 January 2019
At 31 December 2019
Cost
At 1 January 2018
Additions
Disposals
At 31 December 2018
Amounts provided
At 1 January 2018
At 31 December 2018
At 31 December 2019
At 31 December 2018
Subsidiaries
Associates
Shares
Shares
Total
$ million
166,302
—
(15)
166,287
33
33
166,307
270
(275)
166,302
33
33
166,254
166,269
2
—
—
2
—
—
2
—
—
2
—
—
2
2
166,304
—
(15)
166,289
33
33
166,309
270
(275)
166,304
33
33
166,256
166,271
The more important subsidiaries of the company at 31 December 2019 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 2019 was $76,152 million (2018 $76,152 million).
3. Receivables
Amounts receivable from subsidiariesa
Amounts receivable from associates
Other receivables
2019
$ million
2018
Current
Non-current
Current
Non-current
134
1
—
135
2,771
—
—
2,771
148
4
(1)
151
2,600
—
—
2,600
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 2019 the aggregate level of contributions was $236 million (2018 $490 million). The aggregate level of contributions in 2020 is
expected to be approximately $255 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 260-296 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 2019
265
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 $1,276 million
at 31 December 2019, 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 2019. 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
2019
2.1
3.4
2.7
2.7
2.7
2019
3.0
2.9
3.1
%
2018
2.9
3.8
3.0
3.0
3.1
%
2018
2.6
2.5
3.1
The discount rate assumption is based on third-party AA corporate bond indices and we use yields that reflect the maturity profile of the
expected benefit payments. The inflation rate assumption is based on the difference between the yields on index-linked and fixed-interest long-
term government bonds. The inflation assumption is used to determine the rate of increase for pensions in payment and the rate of increase in
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
2019
27.3
28.9
28.7
30.5
Years
2018
27.4
28.9
28.8
30.6
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 2019, the plan switched 2% from equities to bonds (2018 12.5%).
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
%
28
65
7
The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2019 were $4,804 million (2018 $4,197
million) of government-issued nominal bonds and $19,462 million (2018 $17,491 million) of index-linked bonds.
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
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 268.
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
2019
6,285
1,096
2,675
4,884
19,462
6,132
2,507
426
98
(7,436)
36,129
$ million
2018
5,191
950
2,792
4,263
17,491
4,606
2,311
376
116
(6,011)
32,085
a Private equity is valued at fair value based on the most recent third-party net asset, revenue or earnings based valuations that generally result in the use of significant unobservable inputs.
b Bonds held are denominated in sterling and valued using quoted prices in active markets.
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
2019
227
2
229
42
271
(909)
756
(153)
2,945
(2,292)
136
(57)
732
$ million
2018
295
15
310
38
348
(868)
773
(95)
(722)
1,768
123
520
1,689
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 260-296 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 2019
267
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
2019
26,796
941
229
756
20
(1,207)
(5)
2,213
29,743
32,085
1,141
909
20
236
(1,207)
2,945
36,129
6,386
6,588
(202)
6,386
6,588
(202)
6,386
$ million
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
(29,541)
(202)
(29,743)
(26,612)
(184)
(26,796)
a Most of the contributions made by plan participants were made under salary sacrifice.
b The benefit payments amount shown above comprises $1,194 million benefits (2018 $1,764 million) plus $18 million (2018 $20 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 $35,811 million of assets held in the BP Pension Fund (2018 $31,818 million) and $251 million held in the BP Global Pension Trust (2018 $203 million), as well as $53 million
representing the company’s share of Merchant Navy Officers Pension Fund (2018 $51 million) and $14 million of Merchant Navy Ratings Pension Fund (2018 $13 million).
e The fair value of plan assets includes borrowings related to the LDI programme as described on page 266.
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 2019 for the company’s plans would have had the effects
shown in the table below. The effects shown for the expense in 2020 comprise the total of current service cost and net finance income or
expense.
Discount ratea
Effect on pension expense in 2020
Effect on pension obligation at 31 December 2019
Inflation rateb
Effect on pension expense in 2020
Effect on pension obligation at 31 December 2019
Salary growth
Effect on pension expense in 2020
Effect on pension obligation at 31 December 2019
$ million
One percentage point
Increase
Decrease
(274)
(4,725)
171
4,711
42
604
227
6,359
(134)
(3,890)
(36)
(525)
a The amounts presented reflect that the discount rate is used to determine the asset interest income as well as the interest cost on the obligation.
b The amounts presented reflect the total impact of an inflation rate change on the assumptions for rate of increase in salaries, pensions in payment and deferred pensions.
One additional year of longevity in the mortality assumptions would increase the 2020 pension expense by $31 million and the pension
obligation at 31 December 2019 by $1,130 million.
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
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 2019 are as follows:
Estimated future benefit payments
2020
2021
2022
2023
2024
2025-2029
Weighted average duration
5. Payables
Amounts payable to subsidiaries
Accruals and deferred income
Other payables
$ million
1,063
1,076
1,096
1,136
1,150
5,886
Years
18.3
$ million
2018
2019
Current
Non-current
Current
Non-current
17,916
21
70
18,007
31,894
—
33
31,927
14,559
31
75
14,665
31,765
—
35
31,800
Included in non-current amounts payable to subsidiaries is an interest-bearing payable of $4,236 million (2018 $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 (2018 $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 $5,031 million (2018 $5,000 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
2019
48
31,499
380
31,927
2019
389
389
2,293
2,293
1,907
55
331
2,293
$ million
2018
40
31,520
240
31,800
$ million
2018
570
570
1,907
1,907
1,337
59
511
1,907
At 31 December 2019, deferred tax assets of $467 million on other temporary differences, $9 million relating to pensions, $67 million relating
to income losses and $391 million relating to other deductible temporary differences (2018 $258 million relating to other temporary differences,
$7 million relating to pensions, $67 million relating to income losses and $184 million relating to other deductible temporary differences) 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 unrecognized temporary differences.
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
269
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
21,525,464
208,927
37,400
(235,951)
21,535,840
2019
$ million
12
9
21
5,381
52
9
(59)
5,383
5,404
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
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 2019 the company repurchased 236 million ordinary shares at a cost of $1,511 million, including transaction costs of $8 million, as part
of the share repurchase programme announced on 31 October 2017. All shares purchased were for cancellation. The repurchased shares
represented 1.1% 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
1,426,265
1,118
37,400
(167,927)
1,296,856
1,163,077
133,707
72
2019
Nominal value
$ million
356
—
9
(42)
323
290
33
—
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
—
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 5.9% (2018 6.9%) of the called-up ordinary share capital of the company.
During 2019, the movement in shares held in treasury by BP represented less than 0.5% (2018 less than 1.0%) 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 260-296 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 2019
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 (2018 $24,107 million), the distribution of which is limited by statutory or other
restrictions.
The financial statements for the year ended 31 December 2019 do not reflect the dividend announced on 4 February 2020 and paid in March
2020; this will be treated as an appropriation of profit in the year ended 31 December 2020.
9. Financial guarantees
The company has issued guarantees under which the maximum aggregate liabilities at 31 December 2019 were $78,586 million (2018 $77,965
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
2019
433
(1)
432
17
16
$ million
2018
429
(9)
420
27
23
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.
2019
9
20
29
$ million
2018
8
16
24
Emoluments
These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and
benefits earned during the relevant financial year, plus cash bonuses awarded for the year. Further information is provided in the Directors’
remuneration report on page 100.
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
271
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
2019
468
84
63
615
2019
279
1,142
2,300
3,721
$ million
2018
491
74
80
645
2018
269
1,151
2,344
3,764
The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
272
BP Annual Report and Form 20-F 2019
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 2019 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.
563916 Alberta Ltd. (99.90%)a
ACP (Malaysia), Inc.
Actomat B.V.
Advance Petroleum Holdings Pty Ltd
Advance Petroleum Pty Ltd
AE Cedar Creek Holdings LLCb
AE Goshen II Holdings LLCb
AE Goshen II Wind Farm LLCb
AE Power Services LLCb
AE Wind PartsCo LLCb
Air BP Albania SHA
Air BP Brasil Ltda.
Air BP Canada LLCb
Air BP Croatia d.o.o.
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 Ltdc
Allgreen Pty Ltd
AM/PM International Inc.
American Oil Company
Amoco (Fiddich) Limited
Amoco (U.K.) Exploration Company, LLCb
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 Cypress Pipeline Company
Amoco Destin Pipeline Company
Amoco Environmental Services Companyd
Amoco Exploration Holdings B.V.
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 Limitede
Amoco Nigeria Oil Company Limitede
Amoco Nigeria Petroleum Company
Amoco Nigeria Petroleum Company Limited
Amoco Norway Oil Company
Amoco Oil Holding Company
Amoco Olefins Corporation
Amoco Overseas Exploration Company
Amoco Pipeline Asset Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
240 - 4th 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
Air BP Albania Sh.A., 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
Savska cesta 32, Zagreb, Croatia
Öljytie 4, 01530 Vantaa, Finland
Armula 24, 108, Reykjavik, Iceland
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Drammensveien 167, Oslo, 0277, Norway
59 Aurel Vlaicu Street, Otopeni, Ilfov County, Romania
Box 8107, 10420, Stockholm, Sweden
17 Level, 717 Bourke Street, Docklands, Melbourne VIC 3008, 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
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
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 ID 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
188, Awolowo Road, S. W. Ikoyi, Lagos, Nigeria
188, Awolowo Road, S. W. Ikoyi, Lagos, Nigeria
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
188, Awolowo Road, S. W. Ikoyi, Lagos, Nigeria
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
273
14. Related undertakings of the group – continued
Amoco Pipeline Holding Company
Amoco Properties Incorporated
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 Partnershipf
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
ARCO British International, Inc.
ARCO British Limited, LLCb
ARCO Coal Australia Inc.
ARCO El-Djazair Holdings Inc.
ARCO Environmental Remediation, L.L.C.b
ARCO Exploration, Inc.
ARCO Gaviota Company
ARCO International Investments Inc.
ARCO International Services Inc.
Arco Mediterraneo Inversiones, S.L
ARCO Midcon LLCb
ARCO Oil Company Nigeria Unlimitedb
ARCO Oman Inc.
ARCO Resources Limited
ARCO Trinidad Exploration and Production Company
Limited
ARCO Unimar Holdings LLCb
Areas Noriega S.L.
Areas Singulares Reyes S.L.
Aspac Lubricants (Malaysia) Sdn. Bhd. (63.03%)
Atlantic 2/3 UK Holdings Limited
Atlantic Richfield Companyd
Autino Holdings Limited (88.85%)g
Autino Limited (88.85%)
Auwahi Wind Energy Holdings LLCb
B2Mobility GmbH
Bahia de Bizkaia Electridad, S.L. (75.00%)
Baltimore Ennis Land Company, Inc.
BASS Management Pty Ltd (51.00%)
Black Lake Pipe Line Company
BP - Castrol (Thailand) Limited (57.59%)h
BP (Abu Dhabi) Limited
BP (Barbados) Holding SRL
BP (Barbican) Limitedi
BP (China) Holdings Limitedb
BP (China) Industrial Lubricants Limitedb
BP (Gibraltar) Limitedj
BP (GTA Mauritania) Finance Limited
BP (GTA Senegal) Finance Limited
BP (Guangzhou) Advanced Mobility Limitedb
BP (Hunan) Petroleum Company Limitedb
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
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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, 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 Berchem Ouest, Luxembourg
Bâtiment B, 36route de Longwy, L-8080 Bertrange, Luxembourg
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
Federico García Lorca, 43, entreplanta, 04004, Almería, Spain
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
8/10, Broad Street, Lagos, Nigeria
Trident Corporate Services (Bahamas) Limited, Providence House, East Hill Street, P.O.Box N-3944,
Nassau, Bahamas, Bahamas
Level 17, 717 Bourke Street, Docklands VIC, Australia
2 Bayside Executive Park, West Bay, Nassau, Bahamas
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Ronda de Poniente 3, 1ªPlanta, 28760 Tres Cantos, Madrid, Spain
Cl Velázquez 18 4ªPlanta 28001 , Madrid, Spain
Level 9, 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
Abbey Gardens, 7th Floor, 4 Abbey Street, Reading, RG1 3BA, United Kingdom
Abbey Gardens, 7th Floor, 4 Abbey Street, Reading, RG1 3BA, 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
4400 Easton Commons Way , Suite 125, Columbus OH 43219, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
23rd Fl. Rajanakarn Bldg, 3 South Sathon Road, Yannawa South 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 Pilot Free Trade Zone,
PRC
No.9 Bin Jiang South Road, Petrochemical Industrial Park, Taicang Gangkou Development Zone, Jiangsu
Province, 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
Room 1218, Building 3, No. 6 Hanxing San jie, Zhongcun Street, Panyu District, Guangzhou, Guangdong
Province , China
Room 1001, 10th Floor, Building A2, Xiangjiang Times Business Square, No.179 Xiandao Road, Yuelu
District, Changsha, Hunan, China
BP (Indian Agencies) Limitedi
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
274
BP Annual Report and Form 20-F 2019
14. Related undertakings of the group – continued
BP (Shandong) Petroleum Co., Ltdb
BP (Shanghai) Trading Limitedb
BP Absheron Limited
BP Advanced Mobility Limited
BP Africa Limitedi
BP Africa Oil Limited
BP Akaryakit Ortakligi (70.00%)f
BP Alaska LNG LLCb
BP Alternative Energy Holdings Limited
BP Alternative Energy Investments Limited
BP Alternative Energy North America Inc.
BP Alternative Energy Trinidad and Tobago Limited
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 Exploration (Faroes) Limited
BP Amoco Exploration (In Amenas) Limited
BP Andaman II Ltd
BP Angola (Block 18) B.V.
BP Argentina Exploration Company
BP Argentina Holdings LLCb
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 Ltdi
BP Australia Capital Markets Limited
BP Australia Employee Share Plan Proprietary Limited
BP Australia Group Pty Ltde
BP Australia Investments Pty Ltd
BP Australia Nominees Proprietary Limited
BP Australia Pty Ltd
BP Australia Shipping Pty Ltdk
BP Australia Swaps Management Limited
BP Aviation A/S
BP Benevolent Fund Trustees Limitedi
BP Berau Ltd.
BP Biocombustíveis S.A. (96.53%)
BP Bioenergia Campina Verde Ltda. (96.53%)
BP Bioenergia Ituiutaba Ltda. (96.53%)
BP Bioenergia Itumbiara S.A. (96.53%)
BP Bioenergia Tropical S.A. (97.46%)
BP Biofuels Advanced Technology Inc.
BP Biofuels Brazil Investments Limited
BP Biofuels Louisiana LLCb
BP Biofuels North America LLCb
BP Biofuels Trading Comércio, Importação e
Exportação Ltda. (96.53%)
BP Bomberai Ltd.
BP Brasil Ltda.
BP Brazil Tracking L.L.C.b
BP Bulwer Island Pty Ltdl
BP Business Service Centre Asia Sdn Bhd
Room 1-2201, Sijian Meilin Mansion, No. 48-15 Wuyingshan Middle Road, Tianqiao District, Ji'nan,
Shandong, China
Room 2105, No. 28 Maji Road, Donghua Financial Building, China (Shanghai) Pilot Free Trade, Shanghai,
200131, 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
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
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
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
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
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, Hong Kong
Level 9, 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, I/SKøbenhavns Lufthavn 1, 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, Zona Rural, 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, Gleba B, 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
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
Level 9, Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur,
Malaysia
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
275
14. Related undertakings of the group – continued
BP Business Service Centre KFTb
BP Canada Energy Development Company
BP Canada Energy Group ULC
BP Canada Energy Marketing Corp.
BP Canada International Holdings B.V.
BP Canada Investments Inc.
BP Capellen Sarl
BP Capital Markets America Inc.
BP Capital Markets p.l.c.
BP Car Fleet Limitedi
BP Caribbean Company
BP Castrol KK (64.84%)
BP Castrol Lubricants (Malaysia) Sdn. Bhd. (63.03%)
BP Central Pipelines LLCb
BP Chembel
BP Chemicals (Korea) Limited
BP Chemicals East China Investments Limited
BP Chemicals Investments Limited
BP Chemicals Limited
BP China Exploration and Production Company
BP CIV Pty Ltd
BP Comercializadora de Energia Ltda.
BP Commodities Trading Limited
BP Commodity Supply B.V.
BP Company North America Inc.m
BP Containment Response Limited
BP Containment Response System Holdings LLCb
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 LLC (54.37%)f
BP Developments Australia Pty. Ltd.
BP Dogal Gaz Ticaret Anonim Sirketi
BP East Kalimantan CBM Limited
BP Eastern Mediterranean Limited
BP Egypt Company
BP Egypt East Delta Marine Corporation
BP Egypt East Tanka B.V.
BP Egypt Production B.V.
BP Egypt Ras El Barr B.V.
BP Egypt West Mediterranean (Block B) B.V.
BP Energía México, S. de R.L. de C.V.
BP Energy Asia Pte. Limited
BP Energy Colombia Limited
BP Energy Company
BP Energy do Brasil Ltda.
BP Energy Europe Limited
BP Energy Solutions B.V.
BP Espana, S.A. Unipersonaln
BP Estaciones y Servicios Energéticos, Sociedad
Anónima de Capital Variablec
BP Europa SEo
BP Exploracion de Venezuela S.A.
BP Business Service Centre KFT, 32-34 Soroksári út, H-1095 Budapest, Hungary
Stewart McKelvey, Attention: Lawrence J. Stordy, 900, 1959 Upper Water Street, Halifax NS B3J 3N2,
Canada
Stewart McKelvey, Attention: Lawrence J. Stordy, 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
Level 9, Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur,
Malaysia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Avenida das Nações Unidas, 12399, rooms 62,63 and 64 size B, 6th floor, Landmark Building, São Paulo,
04578-000, 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 15, 240 St Georges Terrace, Perth WA 6000, Australia
Degirmen yolu cad. No:28 , Asia OfisPark K:3 İcerenkoy-Atasehir, Istanbul, 34752, Turkey
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, Mexico
7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Avenida de Barajas 30, Madrid, 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, con primera avenida de Los Palos , Grandes, Edif Cavendes, piso 9, ofi 903,
Los Palos Grandes, Chacao / Caracas, Caracas / Miranda, 1060, Venezuela, Bolivarian Republic of
BP Exploration & Production Inc.d
BP Exploration (Absheron) Limited
BP Exploration (Alaska) Inc.
BP Exploration (Algeria) Limited
BP Exploration (Alpha) Limited
BP Exploration (Angola) Limited
BP Exploration (Azerbaijan) Limited
BP Exploration (Canada) Limited
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
276
BP Annual Report and Form 20-F 2019
14. Related undertakings of the group – continued
BP Exploration (Caspian Sea) Limited
BP Exploration (D230) Limited
BP Exploration (Delta) Limited
BP Exploration (El Djazair) Limited
BP Exploration (Epsilon) Limited
BP Exploration (Gambia) Limited
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 (Psi) Limited
BP Exploration (Shafag-Asiman) Limited
BP Exploration (Shah Deniz) Limited
BP Exploration (South Atlantic) Limited
BP Exploration (STP) Limited
BP Exploration (Xazar) Pte. Ltd.
BP Exploration Angola (Kwanza Benguela) Limited
BP Exploration Argentina Limited
BP Exploration Australia Pty Ltd
BP Exploration Beta Limited
BP Exploration China Limited
BP Exploration Company (Middle East) Limited
BP Exploration Company Limited
BP Exploration Indonesia Limited
BP Exploration Libya Limited
BP Exploration Mexico Limited
BP Exploration Mexico, S.A. De C.V.c
BP Exploration North Africa Limited
BP Exploration Operating Company Limited
BP Exploration Orinoco Limited
BP Exploration Personnel Company Limited
BP Exploration Peru Limited
BP Express Shopping Limited
BP Finance Australia Pty Ltd
BP Finance p.l.c.
BP Foundation Incorporatedb
BP France
BP Fuels & Lubricants AS
BP Fuels Deutschland GmbH
BP Gas & Power Investments Limited
BP Gas Europe, S.A.U.
BP Gas Marketing Limited
BP Gas Supply (Angola) LLCb
BP Ghana Limited
BP Global Investments Limitedi
BP Global Investments Salalah & Co LLC
BP Global West Africa Limited
BP GOM Logistics LLCb
BP Greece Limited
BP Guangdong Limited (90.00%)b
BP High Density Polyethylene - France
BP Holdings (Thailand) Limited (81.18%)p
BP Holdings B.V.
BP Holdings Canada Limitedi
BP Holdings International B.V.
BP Holdings North America Limitedi
BP Hong Kong Limited
BP India Private Limited (88.65%)
BP Indonesia Investment Limited
BP International Limitedi
BP International Services Company
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
PricewaterhouseCoopers (Bahamas) Limited, Providence House, East Hill Street, P.O. Box N-3910,
Nassau, Bahamas
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
3 Kairaba Avenue, 3rd Floor Centenary, Serekunda West, Kanifing Municipality, Gambia
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
1, Oyinka Abayomi Drive, Ikoyi, 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
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Level 15, 240 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
Av. Santa Fe No. 505 Piso 10, Col. Cruz Manca Santa Fe, Deleg. CuajimalpaC.P., 05349 México D.F.,
Mexico
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
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
Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe,
Cergy Pontoise, France
Drammensveien 167, Oslo, 0277, Norway
Wittener Straße 45, 44789 Bochum, Germany
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Avenida de la Transición Española 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, Hong Kong
Technopolis Knowledge Park, Mahakali Caves Road, Andheri (East), Mumbai 400093, 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
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
277
14. Related undertakings of the group – continued
BP Investment Management Limited
BP Investments Asia Limited
BP Iran Limited
BP Iraq N.V.
BP Italia SpA
BP Japan K.K.
BP Korea Limited
BP Kuwait Limited
BP Latin America LLCb
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 LLCb
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 Limitedi
BP Middle East LLC
BP Midstream Partners GP LLCb
BP Midstream Partners Holdings LLCb
BP Midstream Partners LP (54.37%)q
BP Midwest Product Pipelines Holdings LLCb
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 LLCb
BP Offshore Response Company LLCb
BP Oil (Thailand) Limited (90.40%)r
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 Senegal S.A.
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 One Pipeline Company LLCb
BP Pacific Investments Ltd
BP Pakistan (Badin) Inc.
BP Pakistan Exploration and Production, Inc.
BP Pension Escrow Limited
BP Pension Trustees Limitedi
BP Pensions (Overseas) Limitedj
BP Pensions Limitedi
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
15th Fl. Roppongi Hills Mori Tower, 10-1 Roppongi 6-chome, Minato-ku, Tokyo106-6115, Japan
2nd Floor, 306, Banpo-daero, Seocho-gu, Seoul 06509, 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
Washington House, 4th Floor, 16 Church Street, Hamilton HM 11 , 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
Level 9, 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
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
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
26A Apostolopoulou, Halandri, Athens, Attica, 152 31, 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
Route de Ouakam x Corniche Ouest, Immeuble Alphadio Barry, Dakar, Senegal
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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
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
The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
278
BP Annual Report and Form 20-F 2019
14. Related undertakings of the group – continued
BP Petrochemicals India Investments Limited
BP Petroleo y Gas, S.A.
BP Petrolleri Anonim Sirketi
BP Pipelines (Alaska) Inc.
BP Pipelines (BTC) Limited
BP Pipelines (North America) Inc.
BP Pipelines (SCP) Limited
BP Pipelines (TANAP) Limited
BP Pipelines TAP Limited
BP Polska Services Sp. z o.o.
BP Portugal -Comercio de Combustiveis e Lubrificantes
SA
BP Poseidon Limited
BP Products North America Inc.
BP Properties Limitedi
BP Raffinaderij Rotterdam B.V.
BP Refinery (Kwinana) Proprietary Limited
BP Regional Australasia Holdings Pty Ltd
BP River Rouge Pipeline Company LLC (54.37%)f
BP Russian Investments Limited
BP Russian Ventures Limited
BP SC Holdings LLCb
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 LLCb
BP Solar Espana, S.A. Unipersonalc
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Av. Francisco de Miranda, con primera avenida de Los Palos , Grandes, Edif Cavendes, piso 9, ofi 903,
Los Palos Grandes, Chacao / Caracas, Caracas / Miranda, 1060, Venezuela, Bolivarian Republic of
Degirmen yolu cad. No:28 , Asia OfisPark K:3 İcerenkoy-Atasehir, Istanbul, 34752, Turkey
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
45 Memorial Circle, Augusta ME 04330, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Ul. Jasnogórska 1, 31-358 Kraków, Malopolskie, Poland
Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
The Corporation Trust Incorporated, 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 la Transición Española 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid,
Spain
BP Solar International Inc.
BP Solar Pty Ltd
BP South America Holdings Ltd
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 Technology Ventures Inc.
BP Technology Ventures Limited
BP Train 2/3 Holding SRL
BP Transportation (Alaska) Inc.
BP Trinidad and Tobago LLC (70.00%)b
BP Trinidad Processing Limited
BP Turkey Refining Limitedi
BP Two Pipeline Company LLC (54.37%)f
BP UK Retained Holdings Limited
BP Venezuela Investments B.V.
BP West Aru I Limited
BP West Aru II Limited
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%)b
BP+Amoco International Limitedi
BPA Investment Holding Company
BP-AIOC Exploration (TISA) LLC (65.88%)b
BPNE International B.V.
BPRY Caribbean Ventures LLC (70.00%)b
BPX (Eagle Ford) Gathering LLC (75.00%)b
BPX (Karnes) Gathering LLCb
BPX (KCS Resources) LLCb
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
199 Oxford Road, Oxford Parks, Dunkeld, Johannesburg, Gauteng, 2196, 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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Erin Court, Bishop's Court Hill, St. Michael , Barbados
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
5-5A Queen's Park West, Port-of-Spain, Trinidad and Tobago
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
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
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
279
14. Related undertakings of the group – continued
BPX (Permian) Gathering LLCb
BPX (WSF Operating) Inc.
BPX Energy Inc.
BPX Midstream LLCb
BPX Operating Company
BPX Production Company
BPX Properties (GP) LLCb
BPX Properties (LP) LLCb
BPX Properties (NA) LPf
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%)s
Britoil Limited
BTC Pipeline Holding Company Limited
Burmah Castrol Australia Pty Ltdt
Burmah Castrol Holdings Inc.
Burmah Castrol PLCi
Burmah Castrol South Africa (Pty) Limitedu
Burmah Chile SpA
BXL Plastics Limitedv
Cadman DBP Limited
Casitas Pipeline Company
Castrol (China) Limited
Castrol (Ireland) Limited
Castrol (Shanghai) Management Co., Ltdb
Castrol (Shenzhen) Company Limitedb
Castrol (Tianjin) Lubricants Co., Ltdb
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
5615 Corporate Blvd., Suite 400B, Baton Rouge LA 70808, 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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
CT Corporation System, 1021 Main Street, Suite 1150, Houston, Texas 77002, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
1999 Bryan St., STE 900, Dallas TX 75201, 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, Herts., HP2 5BS, United Kingdom
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Level 17, 717 Bourke Street, Docklands VIC, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
199 Oxford Road, Oxford Parks, Dunkeld, Johannesburg, Gauteng, 2196, 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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Unit 807, Tower B, Manulife Financial Centre, 223 Wai Yip Street, Kwun Tong, Hong Kong
One Spencer Dock, North Wall Quay, Dublin 1, Ireland
Floor 3, Building 5, 255 Guiqiao Road, Shanghai Pilot Free Trade Zone, China
No.1120 Mawan Road, Nanshan District, Shenzhen, China
South of NanGang Industrial Area, and East of Hai Gang Road, Tianjin Economic Development Area,
Tianjin, China, China
Castrol (U.K.) Limited
Castrol Australia Pty. Limited
CASTROL Austria GmbHb
Castrol B.V.
Castrol BP Petco Limited Liability Company (65.00%)b
Castrol Brasil Ltda.
Castrol Caribbean & Central America Inc.
Castrol Colombia Ltda.
Castrol Del Peru S.A. (99.49%)
Castrol Egypt Lubricants S.A.E. (51.00%)
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.c
Castrol Namibia (Pty) Limited
Castrol Offshore Limited
Castrol Pakistan (Private) Limited
Castrol Philippines, Inc.
Castrol Servicos Ltda.
Castrol Ukraine LLCb
Castrol Zimbabwe (Private) Limited
Centrel Pty Ltd
Charge Your Car Limitedc
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.
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
9th Floor, 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
Calle 81, No 11 - 42, Oficina 901, Torre Sur, Bogota, Colombia
Av. Camino Real, 111 Torre B Oficina, 603 San Isidro, Lima, Peru
First floor of building located at Plot 28- the first Sector, City Center, New Cairo, Cairo, Egypt
Technopolis Knowledge Park, Mahakali Caves Road, Andheri (East), Mumbai 400093, 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
Av. Santa Fe No. 505 Piso 10, Col. Cruz Manca Santa Fe, Deleg. CuajimalpaC.P., 05349 México D.F.,
Mexico
24 Orban Street, Klein Windhoek, Windhoek, Namibia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
D-67/1, Block # 4, Scheme # 5, Clifton, Karachi, Pakistan
32/F LKG Tower, Ayala Avenue, Makati City, 6801, Philippines
Avenida Tamboré, 448, Barueri, Sao Paulo, Brazil
2A Kostiantynivska 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
Avenida Eugenio Mendoza / San Felipe Edificio Centro Letonia, Torre Ing-Bank, Piso 12, Oficina 124-B, La
Castellana, Caracas, 1060, Venezuela, Bolivarian Republic of
Conti Cross Keys Inn, Inc.
Coro Trading NZ Limited
Easton and Swamp Roads, Buckinham Township, Bucks County, Pennsylvania, United States
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
280
BP Annual Report and Form 20-F 2019
14. Related undertakings of the group – continued
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 Wallis (1980) Limited Partnership (92.50%)f
Dradnats, Inc.
Dualez 16, S.L.
ECM Markets SA (Pty) Ltd (75.00%)
Elektromotive Limited
Elite Customer Solutions Pty Ltd
Elm Holdings Inc.
Energy Global Investments (USA) Inc.
Enstar LLCb
Estacion de Servicio Alto Campoo, S.L.
Estacion de Servicio Ganzo 10, S.L.
Estacion de Servicio Reocin 9, S.L.
Estacion de Servicio Santillana II, S.L.
Estacion de Servicio Sardinero, S.L.
Estonian Aviation Fuelling Services (50.00%)
Europa Oil NZ Limited
Exomet, Inc.
Expandite Contract Services Limited
Exploration (Luderitz Basin) Limited
Exploration Service Company Limited
Flat Ridge 2 Holdings LLCb
Flat Ridge Wind Energy, LLCb
Foseco Holding International B.V.
Foseco Holding, Inc.
Foseco, Inc.
Fosroc Expandite Limited
Fowler Ridge Holdings LLCb
Fowler Ridge I Land Investments LLCb
Fowler Ridge II Holdings LLCb
Fowler Ridge III Wind Farm LLCb
FreeBees B.V.
Fuel & Retail Aviation Sweden AB
Fuelplane- Sociedade Abastecedora De Aeronaves,
Unipessoal, Lda
FWK (2017) Limitedw
FWK Holdings (2017) LTDw
Gardena Holdings Inc.
Gelsenkirchen Raffinerie Netz GmbH
GOAM 1 C.I S. A .S
Grampian Aviation Fuelling Services Limited
Guangdong Investments Limited
Highlands Ethanol, LLCb
Hosteleria Noriega S.L.
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
Iraq Petroleum Company Limited
Jupiter Insurance Limited
Ken-Chas Reserve Company
Kenilworth Oil Company Limitedi
Kingbook Inversiones Socimi, S.A.
Latin Energy Argentina S.A.
Lebanese Aviation Technical Services S.A.L.
Limited Liability Company BP Toplivnaya Kompaniab
Limited liability company Setra Lubricantsb
Lubricants UK Limited
Lytt Limited
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 - 4th Avenue SW, Calgary AB T2P 4H4, Canada
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Avenida de la Transición Espanola 30, Alcobendas, 28108, Madrid, Spain
199 Oxford Road, Oxford Parks, Dunkeld, Johannesburg, Gauteng, 2196, South Africa
500, Capability Green, Luton, LU1 3LS, United Kingdom
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
Avenida de la Transición Espanola 30, Alcobendas, 28108, Madrid, Spain
Avenida de la Transición Espanola 30, Alcobendas, 28108, Madrid, Spain
Avenida de la Transición Espanola 30, Alcobendas, 28108, Madrid, Spain
Avenida de la Transición Espanola 30, Alcobendas, 28108, Madrid, Spain
Avenida de la Transición Espanola 30, Alcobendas, 28108, Madrid, Spain
Harju maakond, Lasnamäe linnaosa, Väike-Sõjamäe tn 12a, Tallinn, 11415, Estonia
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
4400 Easton Commons Way , Suite 125, Columbus OH 43219, 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
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, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
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
921 S. Orchard St. Ste G, Boise ID 83705, 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
Albert House, South Esplanade, St. Peter Port, GY1 1AW, 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, premises 11, 121099, Moscow, Russian Federation
2 Paveletskaya sq, Building1, 115054 Moscow, Russia
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 260-296 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 2019
281
14. Related undertakings of the group – continued
Manormaker (Nominee No. 1) Limited (99.90%)
Manormaker (Nominee No. 2) Limited (99.90%)
Manormaker GP Limited (99.90%)
Mardi Gras Transportation System Company LLC
(70.34%)b
Markoil, S.A. Unipersonal
Masana Petroleum Solutions (Pty) Ltd (37.88%)
Mayaro Initiative for Private Enterprise Development
(70.00%)
Mehoopany Holdings LLCb
Mes Tecnologia En Servicios Y Energia, S.A. De C.V.c
11 Black Horse Lane, Ipswich, Suffolk, IP1 2EF, United Kingdom
11 Black Horse Lane, Ipswich, Suffolk, IP1 2EF, United Kingdom
11 Black Horse Lane, Ipswich, Suffolk, IP1 2EF, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Avenida de la Transición Española 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid,
Spain
199 Oxford Road, Oxford Parks, Dunkeld, Johannesburg, Gauteng, 2196, South Africa
5-5A Queen's Park West, Port-of-Spain, Trinidad and Tobago
Minza Pty. Ltd.
Mountain City Remediation, LLCb
No. 1 Riverside Quay Proprietary Limited
Nordic Lubricants A/S
Nordic Lubricants AB
North America Funding Company
OMD87, Inc.
Omega Oil Company
OnSight Analytics Solutions India Private Ltd. (74.50%) Office No. 306, Regus Business Center , 3rd Floor, Abbusali St, Saligramam, Chennai, Tamil Nadu,
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Av. Santa Fe No. 505 Piso 10, Col. Cruz Manca Santa Fe, Deleg. CuajimalpaC.P., 05349 México D.F.,
Mexico
Level 17, 717 Bourke Street, Docklands VIC, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Arne Jacobsens Allé 7, 5th Floor, 2300, Copenhagen, Denmark
Hemvärnsgatan , 171 54, Solna, Sweden
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
111 Eighth Avenue, New York, New York, 10011
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
OOO BP STLb
Orion Delaware Mountain Wind Farm LPb
Orion Energy Holdings, LLCb
Orion Energy L.L.C.b
Orion Post Land Investments, LLCb
Oyambre 1, S.L.
Pacroy (Thailand) Co., Ltd. (39.50%)
Peaks America Inc.
Pearl River Delta Investments Limited
Petrocorner Retail S.L.U.
Phoenix Petroleum Services, Limited Liability Company Royal Tulip Al Rasheed Hotel, Baghdad Tower, PO Box 8070, Baghdad, Iraq
Pozuelo 4, S.L.
PRODUITS METALLURGIE DOITTAU
600093, India
Novinskiy blvd.8, 18th floor, office 14, 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
Avenida de la Transición Espanola 30, Alcobendas, 28108, Madrid, Spain
23rd Fl. Rajanakarn Bldg, 3 South Sathon Road, Yannawa South 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
Avenida de la Transición Espanola 30, Alcobendas, 28108, Madrid, Spain
Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe,
Cergy Pontoise, France
Prospect International, C.A. (In liquidation)
PT BP Petrochemicals Indonesia
PT Castrol Indonesia (68.30%)
PT Castrol Manufacturing Indonesia (68.30%)
PT Jasatama Petroindoc
Avenida Eugenio Mendoza / San Felipe Edificio Centro Letonia, Torre Ing-Bank, Piso 12, Oficina 124-B, La
Castellana, Caracas, 1060, Venezuela, Bolivarian Republic of
20th Floor Summitmas II Jl., Jend. Sudirman Kav. 61 - 62, Jakarta, Selatan, Indonesia
Perkantoran Hijau Arkadia, Tower B 9th Floor, Jl. Let. Jenderal TB. Simatupang Kav. 88, Jakarta12520,
Indonesia
JL. Raya, Merak KM 117, DS Gerem, Gerem Grogol, Cilegon, Banten, Indonesia
Puente Arce 4, S.L.
Remediation Management Services Company
Richfield Oil Corporation
Rio Corvo 2, S.L.
Rolling Thunder I Power Partners, LLCb
Romax Insight Korea Ltd. (74.50%)
Ropemaker Deansgate Limited
Ropemaker Properties Limited
Ruhr Oel GmbH (ROG)
Rusdene GSS Limitedw
Saturn Insurance Inc.
Sherbino I Holdings LLCb
Sherbino Mesa I Land Investments LLCb
Sociedade de Promocao Imobiliaria Quinta do Loureiro,
SA
Société de Gestion de Dépots d'Hydrocarbures - GDHb Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe,
Perkantoran Hijau Arkadia, Tower B 8th Floor, Jl. Let. Jenderal TB. Simatupang Kav. 88, Jakarta12520,
Indonesia
Avenida de la Transición Espanola 30, Alcobendas, 28108, Madrid, Spain
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Avenida de la Transición Espanola 30, Alcobendas, 28108, Madrid, Spain
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
504 Smart Building, 213-3 Cheomdan-ro, Jeju-si, Jeju-do, Korea, Republic of
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Alexander-von-Humboldt-Straße 1, Gelsenkirchen, 45896, Germany
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
400 Cornerstone Drive, Suite 240, Williston VT 05495, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal
Cergy Pontoise, France
SOFAST Limited (63.09%)x
South Texas Shale LLCb
Southeast Texas Biofuels LLCb
Southern Ridge Pipeline Holding Company
Southern Ridge Pipeline LP LLCb
Sp/f Decision3 (GreenSteam) Company (61.68%)y
23rd Fl. Rajanakarn Bldg, 3 South Sathon Road, Yannawa South 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
The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
282
BP Annual Report and Form 20-F 2019
14. Related undertakings of the group – continued
SRHP (99.99%)b
Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe,
Cergy Pontoise, France
Standard Oil Company, Inc.
Stryde Limited
Sunrise Oil Sands Partnership (50.00%)f
Taradadis Pty. Ltd.
Telcom General Corporation (99.96%)d
Terre de Grace Partnership (75.00%)f
The Anaconda Company
The BP Share Plans Trustees Limitedi
The Burmah Oil Company (Pakistan Trading) Limited
The Standard Oil Company
TISA Education Complex LLC (65.88%)b
TJKK
Toledo Refinery Holding Company LLCb
Torrelavega 7, S.L.
Union Texas International Corporation
Vastar Pipeline, LLCb
Viceroy Investments Limited
Villacarriedo 8, S.L.
Warrenville Development Limited Partnershipb
Water Way Trading and Petroleum Services LLC
(90.00%)
Welchem, Inc.
West Kimberley Fuels Pty Ltd
Westlake Houston Development, LLCb
Whiting Clean Energy, Inc.
Windpark Energy Nederland B.V.
Winwell Resources, L.L.C.b
Wiriagar Overseas Ltd
251 East Ohio Street, Suite 500, Indianapolis IN 46204, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
c/o Husky Oil Operations Limited, 707 - 8th Avenue SW, Calgary AB T2P 1H5, Canada
Level 17, 717 Bourke Street, Docklands VIC, Australia
818 West Seventh Street, 2nd Floor, Los Angeles, CA, 90017
1100, 635 - 8th Avenue SW, Calgary AB T2P 3M3, Canada
814 Thayer Avenue, Bismarck, ND, 58501-4018
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
15th Fl. 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
Avenida de la Transición Espanola 30, Alcobendas, 28108, Madrid, Spain
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
Avenida de la Transición Espanola 30, Alcobendas, 28108, Madrid, Spain
33 North LaSalle Street, Chicago, Illinois 60602, United States
Khur Al-Zubair, pear No 1, Basra, Iraq
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
5615 Corporate Blvd., Suite 400B, Baton Rouge LA 70808, United States
Estera Corporate Services (BVI) Limited, Jayla Place, Wickhams Cay 1, PO Box 3190, Road Town, Tortola,
VG1110, Virgin Islands, British
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
283
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, United States
Berghausener Straße 96, 40764 Langenfeld, Germany
A Flygbranslehantering AB (AFAB) (25.00%)
Aashman Power Limited (49.97%)
ABG Autobahn-Betriebe GmbH (32.58%)b
Abu Dhabi Marine Areas Limited (33.33%)h
Advanced Biocatalytics Corporation (24.20%)a
AEP I HoldCo LLC (24.30%)b
AGES International GmbH & Co. KG, Langenfeld
(24.70%)f
AGES Maut System GmbH & Co. KG, Langenfeld
(24.70%)f
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%)b
Aker BP ASA (30.00%)
Alaska LNG Project LLC (33.33%)b
Alaska Tanker Company, LLC (25.00%)b
Alyeska Pipeline Service Company (48.44%)
Alyssum Group Ltd (26.20%)e
Ambarli Depolama Hizmetleri Limited Sirketi (50.00%) Yakuplu Mahallesi Genc, Osman Caddesi, No.7 Beylikdüzü, Istanbul, Turkey
Ammenn GmbH (75.00%)
Apollo Geração de Energia Ltda (49.97%)b
Aragonesa de Gestión de Energías Alternativas, SL
(49.97%)
ATAS Anadolu Tasfiyehanesi Anonim Sirketi (68.00%)z Degirmen yolu cad. No:28 , Asia OfisPark K:3 İcerenkoy-Atasehir, Istanbul, 34752, Turkey
Atlantic 1 Holdings LLC (34.00%)b
Atlantic 2/3 Holdings LLC (42.50%)b
Atlantic 4 Holdings LLC (37.78%)b
Atlantic LNG 2/3 Company of Trinidad and Tobago
Unlimited (42.50%)
Atlantic LNG 4 Company of Trinidad and Tobago
Unlimited (37.78%)
Patricio Raby Benavente, Moneda N° 920 Of 205, Santiago, Chile
Via Sardegna 38, 00187, Roma, Italy
Avenida Ricardo Rivera Navarrete n.501 / room 1602, Lima, Peru, 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
Oksenoyveien 10, , 1366 Lysaker, Norway
Corporation Service Company, 2711 Centerville Road,, Suite 400, Wilmington DE 19808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
9360 Glacier Highway, Suite 202, Juneau AK 99801, United States
522 Fulham Road, London, SW6 5NR, United Kingdom
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
Luisenstraße 5 a, 26382 Wilhelmshaven, Germany
Sitio Canto, número S/N, bairro / distrito Zona Rural, município Russas - CE, CEP 62900-000
Calle Alcala numero 63, 28014, Madrid, Spain
Princes Court, Cor. Pembroke & Keate Street, Port-of-Spain, Trinidad and Tobago
Atlantic LNG Company of Trinidad and Tobago
(34.00%)
Atlas Methanol Company Unlimited (36.90%)
Australasian Lubricants Manufacturing Company Pty
Ltd (50.00%)h
Australian Terminal Operations Management Pty Ltd
(50.00%)
Auwahi Holdings, LLC (50.00%)b
Auwahi Wind Energy LLC (50.00%)b
Aviation Fuel Services Limited (25.00%)
Aviation Service (Iraq) Limited (40.00%)α
Axion Comercializacion De Combustibles Y
Lubricantes S.A. (50.00%)
Axion Energy Argentina S.A. (50.00%)
Axion Energy Holding S.L. (50.00%)b
Axion Energy Paraguay S.R.L. (50.00%)b
Axuy Energy Holdings S.R.L. (50.00%)b
Axuy Energy Investments S.R.L. (50.00%)b
Azerbaijan Gas Supply Company Limited (23.06%)h
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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Calshot Way Central Area, Heathrow Airport, Hounslow, Middlesex, TW6 1PY, United Kingdom
2 World Business Centre Heathrow, Newall Road, London Heathrow Airport, Hounslow, TW6 2SF, United
Kingdom
Avenida Luis Alberto de Herrera 1248, Oficina 1901, Montevideo, Uruguay
Carlos María Della Paolera 265, Piso 22, Ciudad Autónoma de Buenos Aires, Argentina
Arbea Campus Empresarial, Edifico 1. Ctra de Fuencarral a Alcobendas, M603, KM 3,8 28108
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
Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman,
Cayman Islands
Azerbaijan International Operating Company (30.37%)β 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%)f
BGFH Betankungs-Gesellschaft Frankfurt-Hahn GbR
(50.00%)f
Bighorn Solar 1, LLC (49.97%)b
Billund Refuelling I/S (50.00%)
Blackbear Alabama Solar 1, LLC (49.97%)b
Blackbear Alabama Solar Land Holdings, LLC
(49.97%)b
Blendcor (Pty) Limited (37.50%)α
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
GA Centervej 1, DK-7190, Billund, Denmark
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
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
135 Honshu Road, Islandview, Durban, 4052, South Africa
The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
284
BP Annual Report and Form 20-F 2019
14. Related undertakings of the group – continued
Blue Marble Holdings Limited (23.58%)γ
Blue Ocean Seismic Services Limited (52.50%)a
Bodmin Solar Limited (49.97%)
BP AOC Pumpstation Maatschap (50.00%)f
BP Bunge Bioenergia S.A. (48.27%)
BP Dhofar LLC (49.00%)
BP Esso AOC Maatschap (22.80%)f
BP Esso Pipeline Maatschap (50.00%)f
BP Guangzhou Development Oil Product Co., Ltd
(40.00%)b
BP Petro China Jiangmen Fuels Co., Ltd. (49.00%)b
BP PetroChina Petroleum Co., Ltd (49.00%)b
BP PETRONAS Acetyls Sdn. Bhd. (70.00%)
BP Sinopec (ZheJiang) Petroleum Co., Ltd (40.00%)b
BP Sinopec Marine Fuels Pte. Ltd. (50.00%)
BP West Africa Supply Limited (50.00%)
BP YPC Acetyls Company (Nanjing) Limited (50.00%)b
BP-Husky Refining LLC (50.00%)b
BP-Japan Oil Development Company Limited
(50.00%)h
Braendstoflageret Kobenhavns Lufthavn I/S (20.83%)f
BTC International Investment Co. (30.10%)δ
Burnthouse Solar Limited (49.97%)
Butamax™ Advanced Biofuels LLC (50.00%)b
Caesar Oil Pipeline Company, LLC (39.39%)b
Cairns Airport Refuelling Service Pty Ltd (33.33%)
Cantera K-3 Limited Partnership (39.00%)f
Canton Renewables, LLC (50.00%)b
Castrol Cuba S.A. (50.00%)
Castrol DongFeng Lubricant Co., Ltd (50.00%)b
Northgate House, 2nd Floor, Upper Borough Walls, Bath, BA1 1RG, United Kingdom
12-14 Carlton Place, Southampton, SO15 2EA, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
Avenida das Nações Unidas, nº 12.399, 4º andar, Brooklin Paulista, São Paulo, CEP 04578-000, Brazil
P.O.Box 20302/211, 20302, Oman
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
Room X2072, 2/F, 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 B1, 11th Floor, No.22 Gang Kou Yi Road, Peng Jiang District, Jiangmen, Guangdong Province,
China
Level 8, Symphony House, Pusat Dagangan Dana 1, Jalan PJU 1A/46 47301 Petaling Jaya, Selangor
Darul Ehsan, Malaysia
F12, Hua Zhe Square Tower 1, 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
Københavns, Lufthavn, 2770 Kastrup, Denmark
Maples & Calder, 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
Company Matters Pty Ltd, Level 12, 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
C1/C2-1, C1/C2-2, 1-6F, No. C1/C2 building, No.107 Huazhong Electronics Industry Park, Fangcao 2
Road, Wuhan Economic and Technological Development Zone, Wuhan, Hubei Province, China
Block 1Tendeseka Office Park, Samora Machel Av/Renfrew Road, Harare, Zimbabwe
800 S. Gay Street, Suite 2021, Knoxville TN 37929, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
6th Floor, No. 413 Section 2 Ti-Ding Blvd., Neihu, Taipei, 11493, Taiwan
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
1560 Broadway, Suite 2090, Denver, Colorado, 80202
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Cedar Creek II Holdings LLC (50.00%)b
Cedar Creek II, LLC (50.00%)b
Cefari RNG OKC, LLC (50.00%)b
Cekisan Depolama Hizmetleri Limited Sirketi (35.00%) Liman Mah. 60 Sk., Çekisan-İdari Bina sit. No:25 A/1, Konyaaltı, Antalya, Turkey
Central African Petroleum Refineries (Pvt) Ltd
(20.75%)
CERF Shelby, LLC (50.00%)b
Chicap Pipe Line Company (56.17%)
China American Petrochemical Company, Ltd.
(CAPCO) (61.36%)
China Aviation Oil (Singapore) Corporation Ltd
(20.03%)
Chittering Solar Limited (49.97%)
Clean Eagle RNG, LLC (50.00%)b
Clean Vision Solar LLC (49.97%)b
Cleopatra Gas Gathering Company, LLC (37.28%)b
CNAF Air BP General Aviation Fuel Company Limited
(49.00%)
Coastal Oil Logistics Limited (25.00%)
Compatible Opportunity Lda (49.97%)
Compatibleglobe Lda (49.97%)
Concessionaria Stalvedro SA (50.00%)
Continental Divide Solar I, LLC (49.97%)b
Continental Divide Solar II, LLC (49.97%)b
Continental Divide Solar Land Holdings, LLC (49.97%)
b
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
400 Montgomery Street, Floor 8, San Francisco, CA 94104
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
11/F, Building No.2, No. 32 Lingang Road Section One, Xihang Port Street, Shuangliu District, Chengdu,
Sichuan Province, China
10th Floor, The Bayleys Building, Cnr Brandon St and Lambton Quay, Wellington, 6011, New Zealand
Rua Sousa Martins, no 10, 1050 218, Lisboa, Portugal
Rua Sousa Martins, no 10, 1050 218, Lisboa, Portugal
San Gottardo Sud, 6780, Airolo, Switzerland
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
8 Temasek Boulevard #31-02, Suntec City Tower 3, Singapore 038988, Singapore
CSG Convenience Service GmbH (24.80%)
Danish Refuelling Services I/S (50.00%)f
Danish Tankage Services I/S (50.00%)f
Dapsun - Investimentos e Consultoria, LDA. (24.99%)
Wittener Straße 45, 44789 Bochum, Germany
Kastrup Lufthavn, 2770 Kastrup, Denmark
Kastrup Lufthavn 1, 2770 Kastrup, Denmark
Rua Júlio Dinis, n.º 247, 6.º, E-1, Edifício Mota Galiza, Parish of Lordelo do Ouro and Massarelos,
4050-027, Porto, Portugal
Dinarel S.A. (20.00%)
Donoma Power Limited (49.97%)
DOPARK GmbH (25.00%)
Dusseldorf Fuelling Services GbR (33.00%)f
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
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
285
14. Related undertakings of the group – continued
Dusseldorf Tank Services GbR (33.00%)f
El Temsah Petroleum Company
"PETROTEMSAH" (25.00%)
Elk Hill Solar 1, LLC (49.97%)b
Elk Hill Solar 2, LLC (49.97%)b
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 (45.72%)b
Energías Renovables de Ixion, SL (49.97%)
Energy Emerging Investments, LLC (50.00%)b
Entrepot petrolier de Chambery (32.00%)
Entrepôt Pétrolier de Puget sur Argens - EPPA
(58.25%)
Erdol-Lagergesellschaft m.b.H. (23.00%)b
Etzel-Kavernenbetriebsgesellschaft mbH & Co. KG
(33.33%)f
Etzel-Kavernenbetriebs-Verwaltungsgesellschaft mbH
(33.33%)
EverSource Advisors Private Ltd (24.99%)
Sportallee 6, 22335 Hamburg, Germany
5 El Mokhayam El Daiem St, 6th Sector, Nasr City, Egypt
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
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
Calle Alcala numero 63, 28014, Madrid, Spain
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
562 Avenue du Parc de l'Ile, 92000, NANTERRE, France
Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe,
Cergy Pontoise, France
Radlpaßstraße 6, 8502 Lannach, Austria
Bertrand-Russell-Straße 3, 22761 Hamburg, Germany
Bertrand-Russell-Straße 3, 22761 Hamburg, Germany
One Indiabulls Center, 16th Floor, Tower 2A, Senapati Bapat Marg, Mumbai City, Maharashtra, Mumbai,
400013, India
3rd Floor, Standard Chartered Tower, Bank Street, 19 Cybercity, Ebene, 72201, Mauritius
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Sportallee 6, 22335 Hamburg, Germany
Av. Leandro N. Alem 1180, piso 11°, Buenos Aires, Argentina
435 Devon Park Drive, Suite 700, Wayne, Pennsylvania, 19087, United States
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, Hamburg, Germany
Überseeallee 1, 20457, Hamburg, Hamburg, Germany
60 Sloane Avenue, London, SW3 3XB, United Kingdom
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
Corporation Service Company, 421 West Main Street, Frankfort KY 40601, United States
3 Rue des Vignes, Aéroport Roissy Charles de Gaulle, 93290, TREMBLAY EN FRANCE, France
EverSource Management Holdings (24.99%)
Ffos Las Solar Developments Limited (49.97%)
FFS Frankfurt Fuelling Services (GmbH & Co.) OHG
(33.00%)f
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%)b
Flat Ridge 2 Wind Holdings LLC (50.00%)b
Flughafen Hannover Pipeline Verwaltungsgesellschaft
mbH (50.00%)
Flughafen Hannover Pipelinegesellschaft mbH & Co.
KG (50.00%)f
Fly Victor Ltd (26.20%)
Flytanking AS (50.00%)
Foreseer Ltd (25.00%)
Formosa BP Chemicals Corporation (50.00%)
Fotech Group Limited (22.40%)a
Fowler I Holdings LLC (50.00%)b
Fowler II Holdings LLC (50.00%)b
Fowler Ridge II Wind Farm LLC (50.00%)b
Fowler Ridge Wind Farm LLC (50.00%)b
Free Power for Schools 13 Limited (49.97%)
Free Power for Schools 14 Limited (49.97%)
Free Power for Schools 15 Limited (49.97%)
Free Power for Schools 17 Limited (49.97%)
Free Power for Schools 19 Limited (49.97%)
Free Power for Schools 4 Limited (49.97%)
Free Power for Schools 5 Limited (49.97%)
Free Power for Schools 6 Limited (49.97%)
Free Power for Schools 7 Limited (49.97%)
Freetricity Central June Limited (49.97%)
Freetricity Commercial June Limited (49.97%)
Fresh-Serve Bakeries LLC (37.04%)b
Fuelling Aviation Service - FAS (50.00%)b
Fuerzas Energéticas del Sur de Europa IV, SL (49.97%) Calle Alcala numero 63, 28014, Madrid, Spain
Calle Alcala numero 63, 28014, Madrid, Spain
Fuerzas Energéticas del Sur de Europa XIX, SL
(49.97%)
Fundación para la Eficiencia Energética de la
Comunidad Valenciana (33.33%)b
Gardermeon Fuelling Services AS (33.33%)
Gas Natural Acu Comercializadora de Energia Ltda.
(50.00%)
Gas Natural Acu S.A. (30.00%)
Gas Natural Infraestrutura S.A. (28.51%)
Gemalsur S.A. (50.00%)
Georgian Pipeline Company (30.37%)β
Calle Lituania nº 10, Castellón de la Plana, Spain
Postboks 133, Gardermoen, NO-2061, Norway
Rua do Russel 804, 5th floor, Gloria, Rio de Janeiro, Brazil
Praia do Flamengo 66, 13th and 14th floors, Block A, Flamengo, Rio de Janeiro, Brazil
Rua do Russel 804, 5th floor, Gloria, Rio de Janeiro, Brazil
Colonia 810, Oficina 403, Montevideo, Uruguay
190 Elgin Avenue, George Town, Grand Cayman , KY1-9005, Cayman Islands
The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
286
BP Annual Report and Form 20-F 2019
14. Related undertakings of the group – continued
Gezamenlijke Tankdienst Schiphol B.V. (50.00%)
GISSCO S.A. (50.00%)
Glade CD Solar Holdings, LLC (49.97%)b
Glade Solar Class B, LLC (49.97%)b
Glade Solar Construction Holdings, LLC (49.97%)b
Glade Solar Construction, LLC (49.97%)b
Glade Solar Holdings 1, LLC (49.97%)b
Glade Solar Holdings 2, LLC (49.97%)b
Glade Solar Holdings, LLC (49.97%)b
Glade Solar Land Holdings, LLC (49.97%)b
Gnowee Power Limited (49.97%)
Goshen Phase II LLC (50.00%)b
Gothenburgh Fuelling Company AB (GFC) (33.33%)
Gravcap, Inc. (25.00%)
Great Ropemaker Partnership (G.P.) Limited (50.00%)α
Great Ropemaker Property (Nominee 1) Limited
(50.00%)
Great Ropemaker Property (Nominee 2) Limited
(50.00%)
Great Ropemaker Property Ltd (50.00%)
Green Growth Feeder Fund Pte. Ltd (24.99%)
Grid Edge Limited (60.00%)a
Anchoragelaan 6, 1118LD Luchthaven Schiphol, Netherlands
2,Vouliagmenis Ave & Papaflessa, 16777 Elliniko, Athens, Attika, Greece
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
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
33 Cavendish Square, London, W1G 0PW, United Kingdom
33 Cavendish Square, London, W1G 0PW, United Kingdom
33 Cavendish Square, London, W1G 0PW, United Kingdom
33 Cavendish Square, London, W1G 0PW, United Kingdom
163 Penang Road, #08-01, Winsland House II, Singapore, 238463, Singapore
Mclaren Building Suite, 14a Mclaren Building, 46 Priory Queensway, Birmingham, B4 7LR, United
Kingdom
Groupement Pétrolier de Saint Pierre des Corps -
GPSPC (20.00%)b
Guangdong Dapeng LNG Company Limited (30.00%)b 10-11/FTime Finance Center, No.4001 Shennan Dadao, Futian Street, Futian District, Shenzhen,
150 Avenue Yves Farge, 37700, SAINT PIERRE DES CORPS, France
GVÖ Gebinde-Verwertungsgesellschaft der
Mineralölwirtschaft mbH (21.00%)
H7 Energy Limited (49.97%)
Hamburg Tank Service (HTS) GbR (33.00%)f
Hebei Dongming Yinglun Petroleum Co., Ltd.
(49.00%)b
Heinrich Fip GmbH & Co. KG (50.00%)f
Heliex Power Limited (32.40%)a
Henan Dongming Yinglun Petroleum Co., Ltd.
(49.00%)b
HFS Hamburg Fuelling Services GbR (25.00%)f
Hiergeist Heizolhandel GmbH & Co. KG (50.00%)f
Hokchi Energy S.A. de C.V. (50.00%)
Hokchi Iberica S.L. (50.00%)
Howbery Solar Park Limited (49.97%)
Impact Solar 1, LLC (49.97%)b
Impact Solar Class B, LLC (49.97%)b
Impact Solar Construction, LLC (49.97%)b
Impact Solar Holdings 1, LLC (49.97%)b
Impact Solar Holdings 2, LLC (49.97%)b
Impact Solar Holdings, LLC (49.97%)b
Implantación de Fuentes Energéticas de Origen
Renovable, SL (49.97%)
In Salah Gas Limited (25.50%)α
In Salah Gas Services Limited (25.50%)α
India Gas Solutions Private Limited (50.00%)
Guangdong Province, China
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 District, Shijiazhuang
City, 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
Torre A, piso 4, oficina 402, Calzada Legaria 549, Colonia 10 de Abril, Delegación Miguel Hidalgo, Ciudad
de Mexico, C. P. 11250, Mexico
Campus Empresarial Arbea - Edificio Nº 1, Carretera Fuencarral a Alcobendas (M-603), Km 3,8.,
Alcobendas, Madrid, Spain
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Calle Alcala numero 63, 28014, Madrid, Spain
IFC 5, St Helier, Jersey, JE1 1ST, Jersey
IFC 5, St Helier, Jersey, JE1 1ST, Jersey
Unit Nos.71 & 737th Floor, Maker Maxity, 2nd North Avenue, Bandra - Kurla Complex, Bandra (East),
Mumbai 400 051, Maharashtra, India
Jamaica Aircraft Refuelling Services Limited (51.00%)h PCJ Building36 Trafalgar Road, Kingston 10, Jamaica
Johnson Corner Solar I, LLC (49.97%)b
Kala Power Limited (49.97%)
Kingston Research Limited (50.00%)
Klaus Köhn GmbH (50.00%)
Köhn & Plambeck GmbH & Co. KG (50.00%)f
Kurt Ammenn GmbH & Co. KG (50.00%)f
LCA Aviation Fuelling Systems Limited (35.00%)
LFS Langenhagen Fuelling Services GbR (50.00%)f
Lightning Hybrids, LLC (31.60%)d
Lightsource Asset Holdings (Australia) Limited
(49.97%)
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
C/O Banks Cooper Associates, 21 Marina Court, Hull, HU1 1TJ , United Kingdom
An der Braker Bahn 22, 26122 Oldenburg, Germany
An der Braker Bahn 22, 26122 Oldenburg, Germany
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 2HT, United Kingdom
Lightsource Asset Holdings (Europe) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
287
14. Related undertakings of the group – continued
Lightsource Asset Holdings (Spain) Limited (49.97%)
Lightsource Asset Holdings (UK) Limited (49.97%)
Lightsource Asset Holdings (USA) Limited (49.97%)
Lightsource Asset Holdings (Vendimia I) Limited
(49.97%)
Lightsource Asset Holdings (Vendimia II) Limited
(49.97%)
Lightsource Asset Holdings 1 Limited (49.97%)
Lightsource Asset Holdings 2 Limited (49.97%)
Lightsource Asset Holdings 3 Limited (49.97%)
Lightsource Asset Management Australia Pty Ltd
(49.97%)
Lightsource Asset Management Limited (49.97%)
Lightsource Australia FinCo Holdings Limited
(49.97%)
Lightsource Australia SPV 1 Pty Limited (49.97%)
Lightsource Australia SPV 2 Pty Limited (49.97%)
Lightsource Australia SPV 3 Pty Limited (49.97%)
Lightsource Australia SPV 4 Pty Ltd (49.97%)
Lightsource Beacon Holdings, LLC (49.97%)b
Lightsource Beacon, LLC (49.97%)b
Lightsource Bodegas Limited (49.97%)
Lightsource Bom Lugar IV Geração de Energia Ltda
(49.97%)
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 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Fazenda Terra Nova, located at Rod. Padre Cícero (CE 153), S/N, KM 58, Lima Campos, City of Icó, State
of Ceará, Zip Code 63.435-000
Lightsource Bom Lugar IX Geração de Energia Ltda
(49.97%)
Fazenda Terra Nova, located at Rod. Padre Cícero (CE 153), S/N, KM 58, Lima Campos, City of Icó, State
of Ceará, Zip Code 63.435-000
Lightsource Bom Lugar V Geração de Energia Ltda
(49.97%)
Fazenda Terra Nova, located at Rod. Padre Cícero (CE 153), S/N, KM 58, Lima Campos, City of Icó, State
of Ceará, Zip Code 63.435-000
Lightsource Bom Lugar VI Geração de Energia Ltda
(49.97%)
Fazenda Terra Nova, located at Rod. Padre Cícero (CE 153), S/N, KM 58, Lima Campos, City of Icó, State
of Ceará, Zip Code 63.435-000
Lightsource Bom Lugar VII Geração de Energia Ltda
(49.97%)
Fazenda Terra Nova, located at Rod. Padre Cícero (CE 153), S/N, KM 58, Lima Campos, City of Icó, State
of Ceará, Zip Code 63.435-000
Lightsource Bom Lugar VIII Geração de Energia Ltda
(49.97%)
Fazenda Terra Nova, located at Rod. Padre Cícero (CE 153), S/N, KM 58, Lima Campos, City of Icó, State
of Ceará, Zip Code 63.435-000
Lightsource BP Hassan Allam Developments for
Renewable Energy S.A.E (24.99%)
Lightsource BP Hassan Allam Holdings B.V. (24.99%)
Lightsource BP Renewable Energy Investments
Limited (49.97%)ε
Lightsource Brasil Energia Renovavel Participacoes
S.A. (49.97%)
Lightsource Brazil Holdings 1 Limited (49.97%)
Lightsource Brazil Holdings 2 Limited (49.97%)
14 Kamal El Tawil ST, Zamalek, Cairo, Egypt
Jan van Goyenkade 8, 1075HP, Amsterdam, Netherlands
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Av. Bernardino de Campos, n. 98., Conj. A, 12 Andar, Sala 37, Paraiso, São Paulo, 04.004-040, Brazil
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
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
Lightsource Commercial Rooftops (Buyback) Limited
(49.97%)
Lightsource Commercial Rooftops Limited (49.97%)
Lightsource Construction Management Limited
(49.97%)
Lightsource Development Services Australia Pty Ltd
(49.97%)
Lightsource Development Services Limited (49.97%)
Lightsource Egypt Holdings Limited (49.97%)
Lightsource Europe Asset Management, SL (49.97%) Calle Suero de Quinones, Numero 34-36, 28002, Madrid, Spain
Lightsource Finance 55 Limited (49.97%)
Lightsource Finca Limited (49.97%)
Lightsource Grace 1 Limited (49.97%)
Lightsource Grace 2 Limited (49.97%)
Lightsource Grace 3 Limited (49.97%)
Lightsource Holdings 1 Limited (49.97%)
Lightsource Holdings 2 Limited (49.97%)
Lightsource Holdings 3 Limited (49.97%)
Lightsource Impact 1 Limited (49.97%)
Lightsource Impact 2 Limited (49.97%)
Lightsource India Holdings (Mauritius) Limited
(49.97%)
Lightsource India Holdings Limited (49.97%)
Lightsource India Investments (UK) Limited (49.97%)
Lightsource India Limited (25.48%)h
Lightsource India Maharashtra 1 Holdings Limited
(49.97%)
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 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 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
288
BP Annual Report and Form 20-F 2019
14. Related undertakings of the group – continued
Lightsource India Maharashtra 1 Limited (49.97%)
Lightsource Kingfisher Holdings Limited (49.97%)
Lightsource Kingpin 1 Limited (49.97%)
Lightsource Kingpin 2 Limited (49.97%)
Lightsource Kingpin 3 Limited (49.97%)
Lightsource Labs 1 Limited (49.97%)
Lightsource Labs Holdings Limited (49.97%)
Lightsource Labs Limited (47.47%)
Lightsource Largescale Limited (49.97%)
Lightsource LS Labs Australia Operations Pty Ltd
(49.97%)
Lightsource LS Labs Australia Pty LTD (49.97%)
Lightsource Midscale Limited (49.97%)
Lightsource Milagres I Geracao de Energia Ltda.
(49.97%)
Lightsource Milagres II Geracao de Energia Ltda.
(49.97%)
Lightsource Milagres III Geracao de Energia Ltda.
(49.97%)
Lightsource Milagres IV Geracao de Energia Ltda.
(49.97%)
Lightsource Milagres V Geracao de Energia Ltda.
(49.97%)
Lightsource Nala Limited (49.97%)
Lightsource Operations 1 Limited (49.97%)
Lightsource Operations 2 Limited (49.97%)
Lightsource Operations 3 Limited (49.97%)
Lightsource Operations Services Limited (49.97%)
Lightsource Property 1 Limited (49.97%)
Lightsource Property 2 Limited (49.97%)
Lightsource Property Investment Holdings Ltd
(49.97%)
Lightsource Property Investment Management (LPIM)
LLP (49.97%)f
Lightsource Property Investments 1 Ltd (49.97%)
Lightsource Pumbaa Limited (49.97%)
Lightsource Radiate 1 Limited (49.97%)
Lightsource Radiate 2 Limited (49.97%)
Lightsource Raindrop Limited (49.97%)
Lightsource Renewable Energy (Australia) Pty Ltd
(49.97%)
Lightsource Renewable Energy (India) Limited
(49.97%)
Lightsource Renewable Energy (NI) Limited (49.97%)
Lightsource Renewable Energy Asset Management
Holdings, LLC (49.97%)b
Lightsource Renewable Energy Asset Management,
LLC (49.97%)b
Lightsource Renewable Energy Assets Holdings, LLC
(49.97%)b
Lightsource Renewable Energy Australia Holdings
Limited (49.97%)
Lightsource Renewable Energy Development, LLC
(49.97%)b
Lightsource Renewable Energy Garnacha, S.L.
(49.97%)
Lightsource Renewable Energy Holdings Limited
(49.97%)
Lightsource Renewable Energy Iberia Holdings
Limited (49.97%)
Lightsource Renewable Energy India Assets Limited
(49.97%)
Lightsource Renewable Energy India Holdings Limited
(49.97%)
Lightsource Renewable Energy India Opco Private
Limited (49.97%)
Lightsource Renewable Energy India Projects Limited
(49.97%)
Lightsource Renewable Energy Ireland Limited
(49.97%)
Lightsource Renewable Energy Italy Development,
S.r.l. (49.97%)
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
Trinity House, Charleston Road, Ranelagh, Dublin 6, D06C8X4, Ireland
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
C/- Baker McKenzie, Level 19, 181 William Street, Melbourne VIC 3000, Australia
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Sítio Cajueiro - Abaiara - left of BR 116, KM491, Caatinga Grande, Zona Rural, Abaiara, 63.240-000, Brazil
Sítio Cajueiro - Abaiara - left of BR 116, KM491, Caatinga Grande, Zona Rural, Abaiara, 63.240-000, Brazil
Sítio Cajueiro - Abaiara - left of BR 116, KM491, Caatinga Grande, Zona Rural, Abaiara, 63.240-000, Brazil
Sítio Cajueiro - Abaiara - left of BR 116, KM491, Caatinga Grande, Zona Rural, Abaiara, 63.240-000, Brazil
Sítio Cajueiro - Abaiara - left of BR 116, KM491, Caatinga Grande, Zona Rural, Abaiara, 63.240-000, Brazil
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 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808, United States
Calle Alcala numero 63, 28014, Madrid, Spain
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
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
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
289
14. Related undertakings of the group – continued
Lightsource Renewable Energy Italy Holdings Limited
(49.97%)
Lightsource Renewable Energy Italy Holdings S.r.l.
(49.97%)
Lightsource Renewable Energy Italy SPV 1 s.r.l.
(49.97%)
Lightsource Renewable Energy Italy SPV 10 s.r.l.
(49.97%)
Lightsource Renewable Energy Italy SPV 2 s.r.l.
(49.97%)
Lightsource Renewable Energy Italy SPV 3 s.r.l.
(49.97%)
Lightsource Renewable Energy Italy SPV 4 s.r.l.
(49.97%)
Lightsource Renewable Energy Italy SPV 5 s.r.l.
(49.97%)
Lightsource Renewable Energy Italy SPV 6 s.r.l.
(49.97%)
Lightsource Renewable Energy Italy SPV 7 s.r.l.
(49.97%)
Lightsource Renewable Energy Italy SPV 8 s.r.l.
(49.97%)
Lightsource Renewable Energy Italy SPV 9 s.r.l.
(49.97%)
Lightsource Renewable Energy Limited (49.97%)
Lightsource Renewable Energy Management LLC
(49.97%)b
Lightsource Renewable Energy Netherlands
Development B.V. (49.97%)
Lightsource Renewable Energy Netherlands Holdings
B.V. (49.97%)
Lightsource Renewable Energy Netherlands Holdings
Limited (49.97%)
Lightsource Renewable Energy Operations LLC
(49.97%)b
Lightsource Renewable Energy Portugal Holdings
Limited (49.97%)
Lightsource Renewable Energy Services Holdings,
LLC (49.97%)b
Lightsource Renewable Energy Services, Inc.
(49.97%)
Lightsource Renewable Energy Spain Development,
SL (49.97%)
Lightsource Renewable Energy Spain Holdings, SL
(49.97%)
Lightsource Renewable Energy Spain SPV 1, SL
(49.97%)
Lightsource Renewable Energy Trading, SL (49.97%)
Lightsource Renewable Energy US, LLC (49.97%)b
Lightsource Renewable Global Development Limited
(49.97%)
Lightsource Renewable Services Limited (49.97%)
Lightsource Renewable UK Development Limited
(49.97%)
Lightsource Residential NI Limited (49.97%)
Lightsource Residential Rooftops (Buyback) Limited
(49.97%)
Lightsource Residential Rooftops (PPA) Limited
(49.97%)
Lightsource Residential Rooftops Limited (49.97%)
Lightsource Simba Limited (49.97%)
Lightsource Singapore Renewables Holdings Private
Limited (49.97%)
Lightsource Singapore Renewables Private Limited
(49.97%)
Lightsource Spain O&M, SL (49.97%)
Lightsource SPV 10 Limited (49.97%)
Lightsource SPV 100 Limited (49.97%)
Lightsource SPV 101 Limited (49.97%)
Lightsource SPV 105 Limited (49.97%)
Lightsource SPV 106 Limited (49.97%)
Lightsource SPV 108 Limited (49.97%)
Lightsource SPV 109 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware 19902, United States
Prins Bernhardplein 200, 1097JB, Amsterdam, Netherlands
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 19902, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Calle Alcala numero 63, 28014, Madrid, Spain
Calle Alcala numero 63, 28014, Madrid, Spain
Calle Alcala numero 63, 28014, Madrid, Spain
C/Pradillo 5, Bajo Exterior Derecha, 28002, Madrid, Spain
Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware 19902, United States
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
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
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
Calle Suero de Quinones, Numero 34-36, 28002, Madrid, Spain
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
The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
290
BP Annual Report and Form 20-F 2019
14. Related undertakings of the group – continued
Lightsource SPV 112 Limited (49.97%)
Lightsource SPV 114 Limited (49.97%)
Lightsource SPV 115 Limited (49.97%)
Lightsource SPV 116 Limited (49.97%)
Lightsource SPV 118 Limited (49.97%)
Lightsource SPV 123 Limited (49.97%)
Lightsource SPV 126 Limited (49.97%)
Lightsource SPV 127 Limited (49.97%)
Lightsource SPV 128 Limited (49.97%)
Lightsource SPV 130 Limited (49.97%)
Lightsource SPV 133 Limited (49.97%)
Lightsource SPV 135 Limited (49.97%)
Lightsource SPV 138 Limited (49.97%)
Lightsource SPV 140 Limited (49.97%)
Lightsource SPV 142 Limited (49.97%)
Lightsource SPV 143 Limited (49.97%)
Lightsource SPV 145 Limited (49.97%)
Lightsource SPV 149 Limited (49.97%)
Lightsource SPV 151 Limited (49.97%)
Lightsource SPV 152 Limited (49.97%)
Lightsource SPV 154 Limited (49.97%)
Lightsource SPV 155 Limited (49.97%)
Lightsource SPV 156 Limited (49.97%)
Lightsource SPV 160 Limited (49.97%)
Lightsource SPV 162 Limited (49.97%)
Lightsource SPV 166 Limited (49.97%)
Lightsource SPV 167 Limited (49.97%)
Lightsource SPV 169 Limited (49.97%)
Lightsource SPV 170 Limited (49.97%)
Lightsource SPV 171 Limited (49.97%)
Lightsource SPV 174 Limited (49.97%)
Lightsource SPV 175 Limited (49.97%)
Lightsource SPV 176 Limited (49.97%)
Lightsource SPV 179 Limited (49.97%)
Lightsource SPV 18 Limited (49.97%)
Lightsource SPV 180 Limited (49.97%)
Lightsource SPV 182 Limited (49.97%)
Lightsource SPV 183 Limited (49.97%)
Lightsource SPV 184 Limited (49.97%)
Lightsource SPV 185 Limited (49.97%)
Lightsource SPV 187 Limited (49.97%)
Lightsource SPV 189 Limited (49.97%)
Lightsource SPV 19 Limited (49.97%)
Lightsource SPV 191 Limited (49.97%)
Lightsource SPV 192 Limited (49.97%)
Lightsource SPV 196 Limited (49.97%)
Lightsource SPV 199 Limited (49.97%)
Lightsource SPV 20 Limited (49.97%)
Lightsource SPV 200 Limited (49.97%)
Lightsource SPV 201 Limited (49.97%)
Lightsource SPV 202 Limited (49.97%)
Lightsource SPV 203 Limited (49.97%)
Lightsource SPV 204 Limited (49.97%)
Lightsource SPV 205 Limited (49.97%)
Lightsource SPV 206 Limited (49.97%)
Lightsource SPV 212 Limited (49.97%)
Lightsource SPV 213 Limited (49.97%)
Lightsource SPV 214 Limited (49.97%)
Lightsource SPV 215 Limited (49.97%)
Lightsource SPV 216 Limited (49.97%)
Lightsource SPV 217 Limited (49.97%)
Lightsource SPV 218 Limited (49.97%)
Lightsource SPV 219 Limited (49.97%)
Lightsource SPV 221 Limited (49.97%)
Lightsource SPV 222 Limited (49.97%)
Lightsource SPV 223 Limited (49.97%)
Lightsource SPV 224 Limited (49.97%)
Lightsource SPV 225 Limited (49.97%)
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 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 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
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
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
291
14. Related undertakings of the group – continued
Lightsource SPV 226 Limited (49.97%)
Lightsource SPV 227 Limited (49.97%)
Lightsource SPV 230 Limited (49.97%)
Lightsource SPV 232 Limited (49.97%)
Lightsource SPV 233 Limited (49.97%)
Lightsource SPV 234 Limited (49.97%)
Lightsource SPV 235 Limited (49.97%)
Lightsource SPV 236 Limited (49.97%)
Lightsource SPV 237 Limited (49.97%)
Lightsource SPV 238 Limited (49.97%)
Lightsource SPV 239 Limited (49.97%)
Lightsource SPV 241 Limited (49.97%)
Lightsource SPV 242 Limited (49.97%)
Lightsource SPV 243 Limited (49.97%)
Lightsource SPV 244 Limited (49.97%)
Lightsource SPV 245 Limited (49.97%)
Lightsource SPV 246 Limited (49.97%)
Lightsource SPV 247 Limited (49.97%)
Lightsource SPV 248 Limited (49.97%)
Lightsource SPV 249 Limited (49.97%)
Lightsource SPV 25 Limited (49.97%)
Lightsource SPV 250 Limited (49.97%)
Lightsource SPV 251 Limited (49.97%)
Lightsource SPV 252 Limited (49.97%)
Lightsource SPV 253 Limited (49.97%)
Lightsource SPV 254 Limited (49.97%)
Lightsource SPV 255 Limited (49.97%)
Lightsource SPV 258 Limited (49.97%)
Lightsource SPV 259 Limited (49.97%)
Lightsource SPV 26 Limited (49.97%)
Lightsource SPV 261 Limited (49.97%)
Lightsource SPV 262 Limited (49.97%)
Lightsource SPV 263 Limited (49.97%)
Lightsource SPV 264 Limited (49.97%)
Lightsource SPV 265 Limited (49.97%)
Lightsource SPV 266 (NI) Limited (49.97%)
Lightsource SPV 267 (NI) Limited (49.97%)
Lightsource SPV 268 (NI) Limited (49.97%)
Lightsource SPV 269 (NI) Limited (49.97%)
Lightsource SPV 270 (NI) Limited (49.97%)
Lightsource SPV 271 (NI) Limited (49.97%)
Lightsource SPV 272 (NI) Limited (49.97%)
Lightsource SPV 273 (NI) Limited (49.97%)
Lightsource SPV 274 (NI) Limited (49.97%)
Lightsource SPV 275 (NI) Limited (49.97%)
Lightsource SPV 276 (NI) Limited (49.97%)
Lightsource SPV 277 (NI) Limited (49.97%)
Lightsource SPV 278 (NI) Limited (49.97%)
Lightsource SPV 279 (NI) Limited (49.97%)
Lightsource SPV 280 (NI) Limited (49.97%)
Lightsource SPV 281 (NI) Limited (49.97%)
Lightsource SPV 282 (NI) Limited (49.97%)
Lightsource SPV 283 (NI) Limited (49.97%)
Lightsource SPV 284 (NI) Limited (49.97%)
Lightsource SPV 285 (NI) Limited (49.97%)
Lightsource SPV 286 Limited (49.97%)
Lightsource SPV 29 Limited (49.97%)
Lightsource SPV 32 Limited (49.97%)
Lightsource SPV 35 Limited (49.97%)
Lightsource SPV 39 Limited (49.97%)
Lightsource SPV 40 Limited (49.97%)
Lightsource SPV 41 Limited (49.97%)
Lightsource SPV 42 Limited (49.97%)
Lightsource SPV 44 Limited (49.97%)
Lightsource SPV 47 Limited (49.97%)
Lightsource SPV 49 Limited (49.97%)
Lightsource SPV 5 Limited (49.97%)
Lightsource SPV 50 Limited (49.97%)
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
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
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA
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
The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
292
BP Annual Report and Form 20-F 2019
14. Related undertakings of the group – continued
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
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
629830 Yamalo-Nenetskiy Anatomy Region, city of Gubkinskiy, Russian Federation
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Grunwaldzka 472B, 80-309, Gdansk, Poland
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 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Pervomayskaya street, 32A, 678144, Lensk, Sakha (Yakutiya) Republic, Russian Federation
Lightsource SPV 54 Limited (49.97%)
Lightsource SPV 56 Limited (49.97%)
Lightsource SPV 60 Limited (49.97%)
Lightsource SPV 69 Limited (49.97%)
Lightsource SPV 73 Limited (49.97%)
Lightsource SPV 74 Limited (49.97%)
Lightsource SPV 75 Limited (49.97%)
Lightsource SPV 76 Limited (49.97%)
Lightsource SPV 78 Limited (49.97%)
Lightsource SPV 79 Limited (49.97%)
Lightsource SPV 8 Limited (49.97%)
Lightsource SPV 88 Limited (49.97%)
Lightsource SPV 91 Limited (49.97%)
Lightsource SPV 92 Limited (49.97%)
Lightsource SPV 98 Limited (49.97%)
Lightsource Timon Limited (49.97%)
Lightsource Trading Limited (49.97%)
Lightsource Viking 1 Limited (49.97%)
Lightsource Viking 2 Limited (49.97%)
Limited Liability Company TYNGD (20.00%)b
Limited Liability Company Yermak Neftegaz (49.00%)b Kosmodamianskaya nab, 52/3, 115035, Moscow, Russian Federation
LL Property Services 2 Limited (49.97%)
LL Property Services Limited (49.97%)
LLC "Kharampurneftegaz" (49.00%)b
Lora Solar Limited (49.97%)
Lotos - Air BP Polska Spółka z ograniczoną
odpowiedzialnością (50.00%)
LOTTE BP Chemical Co., Ltd (50.94%)
LREHL Renewables India SPV 1 Private Limited
(37.93%)
LS Australia FinCo 1 Pty Limited (49.97%)
LS Australia HoldCo1 Pty Ltd (49.97%)
LSBP NE Development LLC (49.97%)b
Maasvlakte Europoort Pipeline Maatschap (50.00%)f
Maatschap Europoort Terminal (50.00%)f
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 (49.97%)
Manpetrol S.A. (50.00%)
Maputo International Airport Fuelling Services (MIAFS)
Limitada (50.00%)b
Masana Employee Share Trust No. 1 (37.88%)b
Mavrix, LLC (50.00%)b
McFall Fuel Limited (49.00%)
Mediteranean Gas Co. "MEDGAS" (25.00%)
Mehoopany Wind Energy LLC (50.00%)b
Mehoopany Wind Holdings LLC (50.00%)b
Meri Power Limited (49.97%)
Middle East Lubricants Company LLC (29.33%)
Milne Point Pipeline, LLC (50.00%)b
Mobene Beteiligungs GmbH & Co. KG (50.00%)f
Mobene Beteiligungs Verwaltungs GmbH (50.00%)
Mobene GmbH & Co. KG (50.00%)f
Mobene Verwaltungs-GmbH (50.00%)
MTS Francis Court Solar Limited (49.97%)
MTS Trefinnick Solar Limited (49.97%)
N.V. Rotterdam-Rijn-Pijpleiding Maatschappij (RRP)
(44.40%)
Natural Gas Vehicles Company "NGVC" (40.00%)
New Zealand Oil Services Limited (50.00%)
Nextpower Trevemper Limited (49.97%)
NFX Combustíveis Marítimos Ltda. (50.00%)
Nima Power Limited (49.97%)
Nord-West Oelleitung GmbH (59.33%)
Ocwen Energy Pty Ltd (49.50%)
Olympic Pipe Line Company LLC (70.00%)b
199 Oxford Road, Oxford Parks, Dunkeld, Johannesburg, Gauteng, 2196, South Africa
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
KPMG, 247 Cameron Road, Tauranga, 3110, 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
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
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
GTH Accounting Group Pty Ltd '2', 1A Kitchener Street, Toowoomba QLD 4350, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
C/- Baker McKenzie, Level 19, 181 William Street, Melbourne VIC 3000, Australia
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
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
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
293
14. Related undertakings of the group – continued
Oslo Lufthaven Tankanlegg AS (33.33%)
PAE E & P Bolivia Limited (50.00%)
PAE Oil & Gas Bolivia Ltda. (50.00%)
Palk Power Limited (49.97%)
Pan American Energy Chile Limitada (50.00%)
Pan American Energy do Brasil Ltda. (50.00%)b
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%)b
Pan American Energy, S.L. (50.00%)b
Pan American Fueguina S.A. (50.00%)
Pan American Sur S.A. (50.00%)
Parque Eolico Del Sur S.A. (27.50%)
Peninsular Aviation Services Company Limited
(25.00%)i
Pentland Aviation Fuelling Services Limited (50.00%)c
Petrostock SA (50.00%)
Pharaonic Petroleum Company "PhPC" (25.00%)
Pont Andrew Limited (49.97%)
Porteiras Geração de Energia Ltda (49.97%)
Prince William Sound Oil Spill Response Corporation
(25.00%)
Proteus Oil Pipeline Company, LLC (45.72%)b
PT Petro Storindo Energi (30.00%)
PT. Dirgantara Petroindo Raya (49.90%)
PTE Pipeline LLC (32.00%)b
R&B Technology Holding CO., LTD (59.02%)a
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%)f
Rhein-Main-Rohrleitungstransportgesellschaft mbH
(35.00%)
RMF Holdings Limited (49.00%)
Romanian Fuelling Services S.R.L. (50.00%)
Rosneft Oil Company (19.75%)
Routex B.V. (25.00%)
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%)b
SAMCOL - Sociedade de Armazenamento e
Manuseamento de Combustiveis Liquidos, Limitada
(50.00%)b
Saraco SA (20.00%)
SeaPort Midstream Partners, LLC (49.00%)b
Sel PV 09 Limited (49.97%)
Servicios Logísticos de Combustibles de Aviación, S.L
(50.00%)
Shakti Power Limited (49.97%)
Shandong Dongming Yinglun Petroleum Co., Ltd.
(49.00%)b
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%)h
Shell Mex and B.P. Limited (40.00%)α
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, Edificio Torre , e/ Jaime Román y Victor Pinto, 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
Arbea Campus Empresarial, Edifico 1. Ctra de Fuencarral a Alcobendas, M603, KM 3,8 28108
Alcobendas, MADRID, SPAIN
Colonia 810, Oficina 403, Montevideo, Uruguay
Campus Empresarial Arbea - Edificio Nº 1, Carretera Fuencarral a Alcobendas (M-603), Km 3,8.,
Alcobendas, Madrid, Spain
Trinity Place Annex, Corner of Frederick & Shirley Streets, P.O. Box N-4805, Nassau, Bahamas
Colonia 810, Oficina 403, Montevideo, Uruguay
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Arbea Campus Empresarial, Edifico 1. Ctra de Fuencarral a Alcobendas, M603, KM 3,8 28108
Alcobendas, MADRID, SPAIN
O´Higgins N° 194, Rio Grande, Argentina
O´Higgins N° 194, Rio Grande, Argentina
0
P O Box 6369, Jeddah21442, Saudi Arabia
6th Floor (c/o Q8 Aviation), Dukes Court, Duke Street, Woking, GU21 5BH, Surrey
route de Pré-Bois 2, 1214, Vernier, Switzerland
70/72 Road 200, Maadi, Cairo, Egypt
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Estrada BR 135, número S/N, KM 250, bairro / distrito Angico de Minas, município Japonvar - MG, CEP
39335-000
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
Wisma AKR, 25th floor, Jalan Panjang No.5, Kebon Jeruk, , Jakarta Barat, 11530, Indonesia
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
PO Box 472, 2nd Floor, Harbour Place, 103 South Church Street, George Town, Grand Cayman,
KY1-1106, Cayman Islands
70/72 Road 200, Maadi, Cairo, Egypt
26 Kifissias Ave. and 2 Paradissou st., 15125 Maroussi, Athens, Greece
Nideracher 1, 8867, Niederurnen, Switzerland
399 Moray Place, Dunedin, 9016, New Zealand
1675 Broadway, Denver CO 80202, United States
Godorfer Hauptstraße 186, 50997 Köln, Germany
KPMG, 247 Cameron Road, Tauranga, 3110, New Zealand
59 Aurel Vlaicu Street, Otopeni, Ilfov County, Romania
26/1 Sofiyskaya Embankment, 115035, Moscow, Russian Federation, Russian Federation
Strawinskylaan 1725, 1077XX Amsterdam, Netherlands
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
Parcela 729, via onze mil cento e trinta, numero cento e qua, Matola Lingamo, Mozambique
route de Pré-Bois 17, 1216, Cointrin, Switzerland
Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware, 19904, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Paseo de la Castellana 278, Madrid, Spain, Spain
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Room B-703, B-704, B-705, B-706, B-707, Floor 7, 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
The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
294
BP Annual Report and Form 20-F 2019
14. Related undertakings of the group – continued
Shenzhen Cheng Yuan Aviation Oil Company Limited
(25.00%)b
Shenzhen Dapeng LNG Marketing Company Limited
(30.00%)b
Sherbino I Wind Farm LLC (50.00%)b
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%)b
Société de Gestion de Produits Pétroliers - SOGEPP
(37.00%)
Fu Yong Town, Bao An county, ShenZhen Airport, Guangdong Province, China
Guangdong Dapeng Liquefied Natural Gas Filling Station, Cheng Tou Corner, Xia Sha Village, Dapeng
Street, Dapeng New 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 Centre, London, SE1 7NA, England
1 Place Gustave Eiffel, 94150, RUNGIS, France
27 Route du Bassin Numéro 6, 92230, GENNEVILLIERS, France
Solar Photovoltaic (SPV2) Limited (49.97%)
Solar Photovoltaic (SPV3) Limited (49.97%)
Solar Strategic Energy LLC (49.97%)b
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
400 Montgomery Street, Floor 8, San Francisco, CA 94104
South Caucasus Pipeline Company Limited (28.83%)α Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman,
Cayman Islands
South Caucasus Pipeline Holding Company Limited
(28.83%)
Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman,
Cayman Islands
South Caucasus Pipeline Option Gas Company
Limited (28.83%)
Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman,
Cayman Islands
2-5F, No. 571, Yuncheng Dong Road, Baiyun District, Guangzhou City, Guangdong Province, China
Causeway House, 1 Dane Street, Bishop's Stortford, Hertfordshire, CM23 3BT, United Kingdom
Holstenhofweg 47, 22043 Hamburg, Germany
South China Bluesky Aviation Oil Company Limited
(24.50%)b
Stansted Intoplane Company Limited (20.00%)
STDG Strassentransport Dispositions Gesellschaft
mbH (50.00%)
Box 7, 190 45 Arlanda, Sweden
Stockholm Fuelling Services Aktiebolag (25.00%)
Palm Grove House, P.O. Box 438, Road Town, Tortola, Virgin Islands, British
Stonewall Resources Ltd. (50.00%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Sula Power Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Sun and Soil Renewable 12 Limited (49.97%)
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%)f Wesermünder Straße 1, 27729 Hambergen, Germany
Terminal CP S.A.U. (50.00%)
Terminales Canarios, S.L. (50.00%)
TFSS Turbo Fuel Services Sachsen GbR (20.00%)f
TGC Solar 106 Limited (49.97%)
TGC Solar 91 Limited (49.97%)
TGFH Tanklager-Gesellschaft Frankfurt-Hahn GbR
(50.00%)f
TGH Tankdienst-Gesellschaft Hamburg GbR (33.33%)f Sportallee 6, 22335 Hamburg, Germany
Sportallee 6, 22335 Hamburg, Germany
TGHL Tanklager-Gesellschaft Hannover-Langenhagen
GbR (50.00%)f
TGK Tanklagergesellschaft Koln-Bonn (25.00%)f
Thames Electricity Limited (49.97%)
The Baku-Tbilisi-Ceyhan Pipeline Company (30.10%)δ Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman,
Av. Leandro N. Alem 1180, piso 11°, Buenos Aires, Argentina
Carretera de San Andréss/n, La Jurada-María Jiménez, Santa Cruz de Tenerife, Spain
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
Sportallee 6, 22335 Hamburg, Germany
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
The Consolidated Petroleum Company Limited
(50.00%)α
The Consolidated Petroleum Supply Company Limited
(50.00%)ζ
The Great Ropemaker Partnership (50.00%)f
Thornton Transportation LLC (37.04%)b
Thorntons LLC (37.04%)b
TLK Holding Company LLC (37.04%)b
TLK Intermediate Holding Company LLC (37.04%)b
TLK Operating Company LLC (37.04%)b
TLM Tanklager Management GmbH (49.00%)b
TLS Tanklager Stuttgart GmbH (45.00%)
Tonatiuh Trading 1 Limited (49.97%)
TRaBP GbR (75.00%)f
Trafineo GmbH & Co. KG (75.00%)f
Trafineo Service GmbH (75.00%)
Trafineo Verwaltungs-GmbH (75.00%)
TransTank GmbH (50.00%)
Tricoya Ventures UK Limited (36.73%)
Tuwale Power Limited (49.97%)
Cayman Islands
Shell Centre, London, SE1 7NA, United Kingdom
Shell Centre, London, SE1 7NA, United Kingdom
33 Cavendish Square, London, W1G 0PW, United Kingdom
Corporation Service Company, 421 West Main Street, Frankfort KY 40601, United States
CSC, 251 Little Falls Drive, Wilmington, County of New Castle 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
Am Tankhafen 4, 4020 Linz, Austria
Zum Ölhafen 49, 70327 Stuttgart, Germany
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Huestraße 25, 44787, Bochum, Germany
Wittener Straße 56, Bochum, Germany
Wittener Straße 45, 44789 Bochum, Germany
Wittener Straße 56, Bochum, Germany
Am Stadthafen 60, 45881 Gelsenkirchen, Germany
Brettenham House, 19 Lancaster Place, London, WC2E 7EN, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
The parent company financial statements of BP p.l.c. on pages 260-296 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 2019
295
14. Related undertakings of the group – continued
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Trinity House, Charleston Road, Ranelagh, Dublin 6, D06C8X4, Ireland
Building No. 349 & 351, Third Sector of City Centre, Fifth Settlement, Cairo, Egypt
5-7 Alexandra Road, Hemel Hempstead, Hertfordshire, HP2 5BS, United Kingdom
Estrada BR 030, número S/N, CXPST 08, bairro / distrito Zona Rural, município Montalvania - MG, CEP
39495-000
Calle Alcala numero 63, 28014, Madrid, Spain
Fazenda Contendas, localizada na Rodovia Joaquim de Freitas, sentido Mato Verde a Catuti, Km 2 à
direita, Zona Rural, município de Mato Verde-MG, CEP 39527-000
Eni House, 10 Ebury Bridge Road, London, SW1W 8PZ, United Kingdom
Av. Leandro N. Alem 1180, piso 11°, Buenos Aires, Argentina
Lavalle 190, piso 6 Depto L, Buenos Aires
Lavalle 190, piso 6 Depto L, Buenos Aires
Eni House, 10 Ebury Bridge Road, London, SW1W 8PZ, United Kingdom
5-7 Alexandra Road, Hemel Hempstead, Herts., HP2 5BS, United Kingdom
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
5-7 Alexandra Road, Hemel Hempstead, Herts., HP2 5BS, United Kingdom
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Woodwater House, Pynes Hill, Exeter, EX2 5WR, United Kingdom
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
Ross Pauling & Partners Limited, 106b Bush Road, Albany, Auckland, 0632, New Zealand
97 Weijiang Road (in the Petrochemical Park), Changshou District, Chongqing, China
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
Prins Bernhardplein 200, 1097JB, Amsterdam, Netherlands
160 Greentree Drive, Suite 101, Dover, County of Kent DE 19904, United States
TWQE2 Limited (49.97%)
Ubiworx Systems Designated Activity Company
(47.47%)
United Gas Derivatives Company "UGDC" (33.33%)
United Kingdom Oil Pipelines Limited (22.15%)
Vale do Cochá Geração de Energia Ltda (49.97%)
Vendimia Grid, AIE (49.97%)
Verde Grande Geração de Energia Ltda (49.97%)
VIC CBM Limited (50.00%)
Vientos Ombu III S.A. (25.00%)
Vientos Patagonicos Chubut Norte III S.A. (24.50%)
Vientos Sudamericanos Chubut Norte IV S.A.
(24.50%)
Virginia Indonesia Co. CBM Limited (50.00%)
Walton-Gatwick Pipeline Company Limited (42.33%)
Wellington LandCo Pty Ltd (49.97%)
West London Pipeline and Storage Limited (30.50%)
Whitetail Solar 1, LLC (49.97%)b
Whitetail Solar 2, LLC (49.97%)b
Whitetail Solar 3, LLC (49.97%)b
Whitetail Solar 6, LLC (49.97%)b
Whitetail Solar Land Holdings, LLC (49.97%)b
Wick Farm Grid Limited (24.99%)
Wildflower Solar I, LLC (49.97%)b
Wildflower Solar Land Holdings, LLC (49.97%)b
Wiri Oil Services Limited (27.78%)
Yangtze River Acetyls Co., Ltd (51.00%)b
Your Power No. 1 Limited (49.97%)
Your Power No. 10 Limited (49.97%)
Your Power No. 19 Limited (49.97%)
Your Power No. 2 Limited (49.97%)
Your Power No. 3 Limited (49.97%)
Your Power No. 8 Limited (49.97%)
Your Power No12 Limited (49.97%)
Zonneweide Westdorperveen B.V. (49.97%)
Zubie, Inc. (20.30%)
a Preference shares
b Member interest
c A and B shares
d Common stock and preference shares
e Ordinary shares and preference shares
f Partnership interest
g A, B and D shares
h A shares
i
Interest held directly by BP p.l.c.
j 99% held directly by BP p.l.c.
k 1% held directly by BP p.l.c.
l Ordinary, A and B shares
m Common stock and redeemable preference shares
n Ordinary A, B and C shares
o 0.008% held directly by BP p.l.c.
p 80.01% ordinary shares and 99.07% preference shares
q Members interest, (49.99%) subordinated units and (4.37%) common units traded on the New York stock exchange
r 93.64% ordinary shares and 81.18% preference shares
s Subsidiary in which the group does not hold a majority of the voting rights but exercises control over it
t Ordinary shares and redeemable preference shares
u Ordinary and A shares
v Ordinary and deferred shares
w Subsidiary undertaking pursuant to sections 1162(2), 1162(3)(b) and Paragraph 6 of Schedule 7 of the Companies Act 2006
x 100% ordinary shares and 58.65% preference shares
y 92.31% B shares and 78.43% D shares
z 15% held directly by BP p.l.c
α B shares
β Unlimited redeemable shares
γ 96.52% C shares
δ 1.89% A shares and 40.80% B shares
ε 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
ζ 5% held directly by BP p.l.c
The parent company financial statements of BP p.l.c. on pages 260-296 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
296
BP Annual Report and Form 20-F 2019
Additional
disclosures
298 Selected financial information
301
Liquidity and capital resources
303 Upstream analysis by region
307 Downstream plant capacity
308 Oil and gas disclosures for the group
314 Environmental expenditure
314 Regulation of the group’s business
319 Legal proceedings
320 International trade sanctions
321 Material contracts
321 Property, plant and equipment
321 Related-party transactions
321 Corporate governance practices
321 Code of ethics
322 Controls and procedures
322 Principal accountant’s fees and services
323 Directors’ report information
323 Disclosures required under Listing Rule 9.8.4R
324 Cautionary statement
BP Annual Report and Form 20-F 2019
297
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
2019 and 2018 and for the three years ended 31 December 2019 are presented on page 132.
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
Gearing«
Ordinary share datae
Basic weighted average number of shares
Diluted weighted average number of shares
2019
2018
2017
2016
2015
$ million except per share amounts
278,397
11,706
298,756
19,378
240,208
9,474
183,008
(430)
222,894
(7,918)
(3,552)
(3,964)
(164)
4,026
(667)
156
3,515
(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)
8,263
3,380
3,730
6,746
15,067
(1,788)
9,990
(643)
12,723
(325)
6,166
(3,162)
2,585
(4,000)
5,905
19.84
19.73
17.32
49.24
41.00
31.977
15,238
4,183
19,421
295,194
100,708
5,404
98,412
57,237
31.1%
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
55,803
30.0%
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
54,873
27.0%
0.61
0.60
(5.33)
13.79
40.00
29.418
16,675
777
17,452
(35.39)
(35.39)
(28.18)
32.22
40.00
26.383
N/A
N/A
20,202
263,316
96,843
5,284
95,286
51,073
26.5%
261,832
98,387
5,049
97,216
45,567
21.2%
Share million
20,285
20,400
19,970
20,102
19,693
19,816
18,745
18,855
18,324
18,324
a Profit attributable to BP shareholders.
b See pages 300 and 344 for further analysis of these items.
c A reconciliation to GAAP information is provided on page 344.
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 is not available.
e The number of ordinary shares shown has been used to calculate the per share amounts.
298
«See Glossary
BP Annual Report and Form 20-F 2019
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
2019
2018
15,238
4,183
19,421
15,140
9,948
25,088
2019
2018
4,019
7,885
11,904
913
2,084
2,997
47
290
337
15,238
4,979
10,259
15,238
3,482
8,545
12,027
877
1,904
2,781
54
278
332
15,140
4,413
10,727
15,140
$ million
2017
16,501
1,339
17,840
$ million
2017
2,999
10,764
13,763
809
1,590
2,399
64
275
339
16,501
3,872
12,629
16,501
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. The entire consideration payable of $10,268 million, after customary closing adjustments, was paid in instalments
between July 2018 and April 2019. The amounts presented as inorganic capital expenditure include $3,480 million for 2019 and $6,788 million for 2018 relating to this transaction. 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 Conoco-Phillips in which
Conoco-Philips simultaneously purchased BP's entire 39.2% interest in the Greater Kuparuk Area on the North Slope of Alaska. 2019 and 2018 also include 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 2019
«See Glossary
299
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.
2019
2018
$ million
2017
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
Otherd
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 f
Environmental and other provisionsg
Restructuring, integration and rationalization costsc
Fair value gain (loss) on embedded derivatives
Gulf of Mexico oil spill response
Other
Total before interest and taxation
Finance costsh
Total before taxation
Taxation credit (charge) on non-operating itemsi
Taxation - impact of US tax reformj
Total after taxation
(6,893)
(32)
(89)
—
67
(6,947)
(72)
(78)
85
—
(12)
(77)
(103)
—
—
—
—
(103)
(917)
(231)
6
—
(319)
(30)
(1,491)
(8,618)
(511)
(9,129)
1,943
—
(7,186)
(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)
a See Financial statements – Note 4 for further information.
b 2019 includes impairments charges principally resulting from the announcements to dispose of certain assets in the US and Egypt. 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.
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, was completed in 2018.
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.
e 2017 primarily reflects the disposal of our shareholding in the SECCO joint venture.
f 2019 includes $877 million relating to the reclassification of accumulated foreign exchange losses from reserves to the income statement upon the contribution of our Brazilian biofuels
bussiness to BP Bunge Bioenergia.
g 2019 and 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.
h Relates to the unwinding of discounting effects relating to Gulf of Mexico oil spill payables.
i 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.
j
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.
300
«See Glossary
BP Annual Report and Form 20-F 2019
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 that reflects 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.
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. In a
period of low prices, the group has the flexibility to reduce cash costs
and to reduce or defer capital investment, as appropriate.
Gulf of Mexico oil spill payments were $2.4 billion on a post-tax basis
in 2019 and are expected to step down to around $1 billion per annum
thereafter. In 2020, we expect to meet our target of $10 billion
divestment and other proceeds and plan a further $5 billion of agreed
disposals by mid-2021. In 2020, divestment proceeds« will be
primarily focussed on reducing gearing«.
We continue to target a gearing band of 20-30%. In 2019, gearing
moved to 31.1%, above the top end of the band, reflecting the impact
of completing the acquisition of BHP’s onshore US assets using
available cash. Gearing may increase in the short-term with the
impact of lower prices, but is expected to reduce again in line with
the receipt of divestment proceeds.
In 2019, the return on average capital employed« was 8.9%a at an
average of $64 per barrel. At $55 per barrel 2017 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
$4.0 billion; Denominator – Average capital employed $167.6 billion.
Dividends and other distributions to shareholders
The dividend is determined in US dollars, the economic currency of
BP, and the dividend level is reviewed by the board each quarter. The
quarterly dividend was increased to 10.50 cents per share for the
fourth quarter of 2019, having been increased to 10.25 cents from
10.00 cents per share in the third quarter of 2018.
The total dividend distributed to BP shareholders in 2019 was
$8.3 billion (2018 $8.1 billion). Prior to its suspension in the fourth
quarter of 2019, shareholders had the option to receive a scrip
dividend in place of receiving cash and in 2019 the total dividend paid
in cash was $6.9 billion (2018 $6.7 billion). The impact of the scrip
dilution since the third quarter of 2017 was fully offset in January
2020.
Details of share repurchases to satisfy the requirements of certain
employee share-based payment plans are set out on page 334. The
share buyback programme, to offset the dilutive impact of the scrip
dividend, purchased 235 million ordinary shares in 2019 at a cost of
$1.5 billion (2018 $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 70 for further information
on risks associated with prices and markets and Financial
statements – Note 29.
The group’s finance debt at 31 December 2019 amounted to $67.7
billion (2018 $65.1 billionb). Of the total finance debt, $10.5 billion is
classified as short term at the end of 2019 (2018 $9.3 billion). See
Financial statements – Note 26 for more information on the short-
term balance. Net debt« was $45.4 billion at the end of 2019, an
increase of $1.9 billion from the 2018 year-end position of $43.5
billionb.
The ratio of finance debt to finance debt plus total equity at
31 December 2019 was 40.2% (2018 39.1%b). The ratio of net debt to
net debt plus total equity« was 31.1% at the end of 2019 (2018
30.0%b). See Financial statements – Note 27 for finance 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 2019 (2018
$22.5 billion) are included in net debt. We manage our cash position
so that the group has adequate cover to respond to potential short-
term market illiquidity, short term price environment volatility and
expect to maintain a robust cash position.
The group also has an undrawn committed $10 billion credit facility
and 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-
(positive 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. 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.
b As a result of the adoption of IFRS 16 ‘Leases’, leases that were previously classified as
finance leases under IAS 17 are now presented as ‘Lease liabilities’ on the group balance
sheet and therefore do not form part of finance debt. Comparative information for finance
debt (previously termed ‘gross debt’), net debt and gearing (previously termed 'net debt
ratio') have been amended to be on a consistent basis with amounts presented for 2019.
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 324 and Risk factors on page 70, 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 2019
«See Glossary
301
Off-balance sheet arrangements
At 31 December 2019, the group’s share of third-party finance debt of equity-accounted entities was $17.3 billion (2018 $16.1 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 2019 were $692 million (2018 $696 million) in respect
of liabilities of joint ventures«and associates«and $523 million (2018 $432 million) in respect of liabilities of other third parties. Of these
amounts, $681 million (2018 $684 million) of the joint ventures and associates guarantees relate to borrowings and for other third-party
guarantees, $494 million (2018 $423 million) relate to guarantees of borrowings.
Contractual obligations
The following table summarizes the group’s capital expenditure commitments for property, plant and equipment at 31 December 2019 and the
proportion of that expenditure for which contracts have been placed.
Capital expenditure
Committed
of which is contracted
Total
24,853
11,382
2020
12,745
7,497
2021
7,070
3,388
2022
2,599
347
2023
1,398
52
$ million
Payments due by period
2024
396
27
2025 and
thereafter
645
71
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 2019, the group had committed to capital expenditure relating to investments in equity-accounted entities
amounting to $1,156 million. Contracts were in place for $864 million of this total.
The following table summarizes the group’s principal contractual obligations at 31 December 2019, 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 leases is given in Financial statements – Note 28.
$ million
Payments due by period
Expected payments by period under contractual obligations
Total
2020
2021
2022
2023
2024
Balance sheet obligations
Borrowingsa
Lease liabilitiesb
Decommissioning liabilitiesc
Environmental liabilitiesc
Gulf of Mexico oil spill liabilitiesd
Pensions and other post-retirement benefitse
Off-balance sheet obligations
Unconditional purchase obligationsf
Crude oil and oil products
Natural gas and LNG
Chemicals and other refinery feedstocks
Power
Utilities
Transportation
Use of facilities and services
Total
75,567
11,299
25,964
1,867
16,129
18,016
148,842
64,486
39,097
5,009
5,001
964
20,526
20,855
155,938
304,780
14,166
2,514
395
278
1,628
1,127
20,108
48,954
12,182
2,918
2,673
144
1,650
2,565
71,086
91,194
8,119
1,839
218
276
1,355
1,155
12,962
6,720
4,478
927
1,164
123
1,637
2,132
17,181
30,143
9,156
1,364
80
224
1,267
1,076
13,167
3,919
3,247
922
394
103
1,428
1,767
11,780
24,947
8,030
1,105
196
206
1,219
1,072
11,828
2,016
2,692
118
204
67
1,361
1,460
7,918
19,746
8,363
876
146
170
1,141
1,048
11,744
1,288
2,183
53
121
64
1,332
1,252
6,293
18,037
2025 and
thereafter
27,733
3,601
24,929
713
9,519
12,538
79,033
1,589
14,315
71
445
463
13,118
11,679
41,680
120,713
a Expected payments include interest totalling $7,843 million ($1,730 million in 2020, $1,393 million in 2021, $1,207 million in 2022, $1,008 million in 2023, $809 million in 2024 and $1,696
million thereafter).
b Expected payments include interest totalling $1,577 million ($307 million in 2020, $248 million in 2021, $202 million in 2022, $164 million in 2023, $133 million in 2024 and $523 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 22 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 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 2020 include purchase commitments existing at 31 December 2019
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.
Commitments for the delivery of oil and gas
We sell crude oil, natural gas and liquefied natural gas under a variety of contractual obligations. Some of these contracts specify the delivery
of fixed and determinable quantities. For the period from 2020 to 2022 worldwide, we are contractually committed to deliver approximately
292 million barrels of oil, 8,600 billion cubic feet of natural gas, and 36 million tonnes of liquefied natural gas. The commitments principally
relate to group subsidiaries based in Canada, Egypt, Singapore, United Kingdom and United States. We expect to fulfil these delivery
commitments with production from our proved developed reserves and supplies from existing contracts, supplemented by market purchases
as necessary.
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BP Annual Report and Form 20-F 2019
Upstream analysis by region
Our upstream operations are set out below by geographical area, with
associated significant events for 2019. 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. In 2019 we marketed around 4.6 million
tonnes 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 or trading entities. LNG is supplied to customers into
markets including Argentina, China, the Dominican Republic,
European Union, India, Japan, Kuwait, Singapore, South Korea,
Taiwan, Thailand and Turkey.
Europe
BP is active in the North Sea and the Norwegian Sea. In 2019 BP’s
production came from three key areas: the Shetland area comprising
the Clair, Foinaven, and Schiehallion fields; the central area
comprising the Andrew area, Culzean, ETAP, Kinnoull and Shearwater
fields; and Norway, through our equity accounted 30% interest in
Aker BP.
• In March 2019 a final investment decision was made on Seagull
(BP 50%), a development tieback to ETAP in the central UK North
Sea.
• In June BP confirmed the start-up of gas production from the Total
operated Culzean field (BP 32%) in the central UK North Sea.
• Also in June, BP was awarded a new exploration licence in the
31st Offshore Licensing Round in the West of Shetland Area in the
UK North Sea for one licence covering 10 blocks (BP 50% and
operator).
• In October production started at the Equinor operated Johan
Sverdrup field (Aker BP 11.57%).
• The Alligin field commenced production through the Glen Lyon
facility in December 2019.
• Development of the Vorlich field continued with two wells
successfully drilled during the year. Production is expected to
commence in 2020.
• In January 2020 BP announced that it had agreed terms to sell its
interests in the Andrew Area and non-operated interest in
Shearwater to Premier Oil. The deal covers the Andrew, Arundel,
Cyrus, Farragon and Kinnoull fields plus our interest in Shearwater.
BP currently owns 62.75% of Andrew, 100% of Arundel, 100% of
Cyrus, 50% of Farragon and 77.06% of Kinnoull. We have a 27.50%
share in Shearwater. Under the terms of the agreement, Premier
Oil will pay BP $625m. The transaction is expected to complete in
2020.
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 290 lease blocks in the Gulf of Mexico and operates
four production hubs.
• In February 2019 we announced the start-up of the Constellation
project (BP 66.67%), operated by Anadarko.
• On 6 May BP announced the final investment decision for the
Thunder Horse South Expansion Phase 2 in the US Gulf of Mexico
(BP operator 75%, ExxonMobil 25%). This project will add two new
subsea production units approximately two miles to the south of
the existing Thunder Horse platform with two new production wells
in the near term. Eventually eight wells will be drilled as part of the
overall development, with first oil expected in 2021.
• In June BP confirmed the discovery of King Embayment in the
Mars corridor, in the US Gulf of Mexico (BP 28.5%).
• BP participated in two lease sales in 2019. In March we were
awarded 23 leases in lease sale 252, and in August we were
awarded 21 leases in lease sale 253.
• We have interests in three Paleogene fields: Tiber, Guadalupe, and
Kaskida. Over the next few years we will be running subsurface
work to better understand and define the concept development for
these fields. BP has history with the development of technology
required to develop such high pressure, deepwater fields and will
continue to connect with the market to understand the options we
will have available for the development of these fields.
See also Financial Statements Note 1 for further information on
exploration leases.
BPX Energy, BP's onshore oil and gas business in the Lower 48
states, has significant operated and non-operated activities across
Colorado, Louisiana, New Mexico, Oklahoma, Texas and Wyoming
producing natural gas, oil, NGLs and condensate, with primary focus
on developing unconventional resources in Texas. It had a 1.5 billion
boe proved reserve base at 31 December 2019, predominantly in
unconventional reservoirs (tight gas, shale gas and coalbed methane,
and newly acquired shale oil). This resource spans 3.4 million net
developed acres and has approximately 10,000 operated gross wells,
with daily net production around 500mboe/d.
BPX Energy operates as a separate business while remaining part of
our Upstream segment. With its own governance, systems and
processes, it is structured to increase competitive performance
through swift decision making and innovation, while maintaining BP’s
commitment to safe, reliable and compliant operations.
• On 1 March BPX Energy assumed physical control of all Petrohawk
Energy Corporation operations from BHP following acquisition of
these assets in 2018. BPX is making progress towards its goal of
achieving $400 million of annual synergies by 2021, when
integration is completed. BPX surpassed the 2019 savings estimate
of $90m, delivering $240m in the first year after the acquisition.
• In November 2019 BPX Energy confirmed agreements to sell its oil
and gas interests in the San Juan basin in Colorado and New
Mexico and the Arkoma basin in Oklahoma. These disposals
completed in March 2020. Additionally, in December 2019 BPX
Energy completed divestments in certain fields within the
Anadarko basin in Oklahoma and Texas and the Haynesville basin in
Texas. Primarily as a result of the divestment program of heritage
assets, BPX Energy incurred $4.7 billion in impairment charges.
Proceeds of $642 million were received in 2019, including
performance deposits for the disposals that closed in 2020.
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.
BP owns significant interests in three producing fields operated by
others, as well as a non-operating interest in the Liberty development
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 reached agreement in
mid-2019 to settle ongoing litigation and transfer Unocal’s interest in
TAPS to the other owners. The Parties are seeking regulatory
approval at the state and federal level.
• On 27 August BP announced an agreement to sell the entirety of
interests in its Alaska operations to Hilcorp Energy, including
upstream and midstream businesses, for a headline price of $5.6
BP Annual Report and Form 20-F 2019
«See Glossary
303
billion. BP will retain decommissioning liabilities associated with
TAPS as part of the transaction. Subject to regulatory approval, the
transaction is expected to complete in 2020. As part of this
transaction BP recognized impairments of circa $1 billion in 2019.
• In October, in the 16th bid round, BP was awarded exploration and
production rights to block C-M-477 offshore Brazil in the Campos
Basin (BP 30%) and to block S-M-1500 (BP 100%) in the Santos
Basin.
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 offshore
exploration licences in Nova Scotia, Newfoundland and Labrador and
the Canadian Beaufort Sea.
• In July the government of Canada issued an order prohibiting any
work or activity authorized under the Canada Oil and Gas
Operations Act on frontier lands that are situated in Canadian
Arctic offshore waters. This includes the Beaufort Sea. The order
will remain in effect until 31 December 2021. BP currently holds an
intangible balance of $64 million related to two blocks operated by
others in this area.
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).
• Following approval from Comisión Nacional de Hidrocarburos
(CNH), the Mexican regulator, of the exploration plans for both
Salina Basin operations in March 2018, seismic interpretation and
well planning activities continued in 2019. These activities are
expected to ramp up in 2020 with tentative plans to commence
drilling in the first half of 2021.
• The Sureste Basin operation received exploration plan approval in
July 2019 from CNH. Seismic licensing and reprocessing activities
were initiated in 2019 and are expected to continue in 2020 with
plans for drilling to commence in 2022.
PAEG, a joint venture that is owned by BP (50%) and Bridas
Corporation (50%), has activities mainly in Argentina and Mexico, but
is also present in Uruguay and Bolivia.
During the second quarter, BP achieved new access in Argentina’s
first offshore licensing round blocks, obtaining the CAN-111 and
CAN-113 blocks (BP 50%).
In Trinidad & Tobago BP holds interests in exploration and production
licences and production-sharing contracts«(PSCs) covering 1.6 million
acres offshore of the east and north-east coast. Facilities include 15
offshore platforms and two onshore processing facilities. Production
comprises gas and associated liquids.
BP also holds interests in the Atlantic LNG facility. BP’s shareholding
averages 39% across four LNG trains« with a combined capacity of
approximately 15 million tonnes per annum. We sell gas to trains 1, 2
and 3 and process gas in train 4. Most of the LNG produced from BP
gas supplied to trains 2, 3 and 4 is sold to third parties under long-
term contracts. BP sells approximately one third of its gas production
to the National Gas Company who supply the volumes into the
petrochemical, power and other industrial markets. The remainder BP
sells to third parties under long-term contracts.
• Production started at the Angelin project (BP 100% and operator) in
February 2019.
• BP confirmed the following hydrocarbon discoveries during the
year: Bélé-1 in April, Tuk-1 in May, Hi-Hat-1 in June, Boom-1 in
September, and Ginger in November, all located offshore Trinidad
and Tobago (BP 30%).
• The initial gas sales and LNG offtake arrangements for Atlantic
LNG Train 1 ended in September 2018 and gas is currently sold into
Train 1 on a short-term basis with BP lifting the majority of the LNG
produced. The Train 1 gas supply arrangements are under
discussion for the period April 2020 onwards.
• In November we signed a swap agreement with Equinor covering
our interests in Blocks 1 and 3 in the Salina Basin. Subject to
receipt of Government approvals expected in the second half of
2020, BP’s interests are expected to be 56.67% in Block 1 and
10% in Block 3.
• BP is operator of the Manakin Block which was discovered in 1998
and is a cross border reservoir field with the Venezuelan reservoir,
Cocuina. Manakin declared commerciality in January 2018 however
cross border commercial agreements have not progressed due to
the impact of US sanctions.
South America
BP has upstream activities in Brazil and Trinidad & Tobago and through
PAEG, in Argentina and Bolivia and Uruguay.
In Brazil BP has interests in 26 exploration concessions across five
basins.
• In the North Campos basin BP is now formally the operator of BM-
C-30 and BM-C-32 blocks following Anadarko's withdrawal from
both blocks and the transfer of their interest. The Brazilian National
Petroleum Agency (ANP) approved the joint venture’s request for a
postponement of declaration of commerciality.
• In the Foz de Amazonas basin Total as operator of blocks FZA-M-57,
86, 88, 125 and 127 is analysing the next steps following IBAMA’s
license denial. The Foz do Amazonas blocks are eligible for a 2-year
license extension according to Resolution 708, the deadline to
request such extension is May 2020 for the Total-operated blocks.
In the BP-operated block FZA-M-59, the extension deadline is
March 2020, environmental licensing process is ongoing and the
extension has been requested. All blocks may also be subject to
further extensions should ANP agree.
• In the South Campos basin ANP approved a revised plan of
appraisal for the BM-C-35 block. The agreement includes a
commitment to drill an exploratory well in 2021 with a deadline to
declare commerciality or end the appraisal period by 1 March 2022.
• In the Pau Brasil block the consortium group is undertaking seismic
reprocessing to aid in subsurface description.
• In the Potiguar basin blocks ANP approved the consortium's
request to modify the appraisal plan timelines.
Africa
BP’s upstream activities in Africa are located in Algeria, Angola, Côte
d'Ivoire, Egypt, The Gambia, 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%) non-operated joint ventures
that supply gas to the domestic and European markets.
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%).
• On 6 June BP announced an agreement to extend the production-
sharing agreement«(PSA) for Block 15 to 2032 and to provide for
Sonangol to take a 10% equity interest in the Block. The
transaction completed on 27 January 2020.
• Development progressed at the Total-operated Zinia 2 deep
offshore development project in Block 17 (BP 16.67%). At the end
of 2019 construction activities were underway, with first production
expected in 2021.
• Development progressed at the Platina project in Block 18, with
construction activities expected to commence in 2020 and first
production expected in 2021.
• In November BP agreed to join the New Gas Consortium (NGC),
subject to completion of certain conditions precedent. This will be
the first upstream natural gas partnership in Angola and will be
operated by ENI (BP 11.8%).
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• In December the Total-operated Block 17 contractor group signed
an agreement with the national agency ANPG (Agência Nacional de
Petróleo, Gás e Biocombustíveis) and Sonangol, to extend all Block
17 production licenses up to 2045, subject to Government
approval. As part of the extension agreement, Sonangol will
become a 5% holder in Block 17 from 2020 with an additional 5%
interest from 2036.
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%). Seismic
reprocessing and interpretation are ongoing and are expected to be
completed by the end of 2020.
In Egypt, BP and its partners currently produce 60% of Egypt’s gas
production.
• In February 2019 production started at the Giza and Fayoum fields
in the West Nile Delta development (BP 82.75%).
• In March 2019 BP confirmed a gas discovery, in the ENI operated
Nour North Sinai offshore prospect (BP 25%) in the Egyptian
Eastern Mediterranean. Technical studies are currently being
progressed by the operator.
• In June BP announced an agreement to sell its interests in Gulf of
Suez oil concessions in Egypt, including BP’s interest in the Gulf of
Suez Production Company (GUPCO), to Dragon Oil. The
agreement, completed in October 2019.
• In September BP confirmed the start-up of the offshore Baltim
South West gas field in Egypt (BP 50%).
• Work continues at the West Nile Delta Raven project, which is
mechanically complete and currently addressing issues identified
during commissioning. Start up is now expected in the second half
of 2020.
In the Gambia, BP has a 90% interest in offshore block A1 with the
state oil company, Gambia National Petroleum Corporation. An
exploration well is expected to be drilled during the first two years of
the licence.
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.
• BP, LIA and Eni continue to work with the NOC towards Eni
acquiring a 42.5% interest in the BP-operated EPSA in Libya. On
completion, Eni would become operator of the EPSA. The
companies are continuing to work together to finalize and
complete all agreements.
In Mauritania and Senegal, BP has a 62% participating interest in the
C6, C8, C12 and C13 exploration blocks in Mauritania and a 60%
participating interest in the Cayar Profond Offshore and St Louis
Profond Ofshore exploration blocks in Senegal. Together these blocks
cover approximately 24,300 square kilometres. BP also had a 15%
interest in the Total operated C18 exploration block until exit in May
2019. For the Greater Tortue Ahmeyin (GTA) Unit across the border of
Mauritania and Senegal, BP has 56% participating interest. The Phase
1 Execute activity has continued to ramp up following the exploitation
license grant on 20th February 2019.
• In July BP confirmed that the GTA-1 (BP 56% and operator)
appraisal well, located offshore Senegal, encountered
approximately 30 metres of net gas pay in high-quality Albian
reservoir confirming gas resource expectations.
• In September BP confirmed the Yakaar-2 appraisal well in the Cayar
Profond block (BP 60% and Operator), located offshore Senegal,
encountered approximately 22 metres of net gas pay in the
reservoir confirming gas resource.
• In December BP confirmed the successful result of the Orca-1
appraisal well located in block C8 (BP 62% and operator) in the Bir
Allah appraisal area offshore Mauritania. The well successfully
encountered all five of the gas sands originally targeted. The well
was then further deepened to reach an additional target, which
also encountered gas.
In Madagascar, BP has interest in four PSCs 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%). A
baseline monitoring survey is underway as part of Phase 1 of the
exploration period.
In São Tomé & Príncipe, BP is operator in two offshore blocks under
PSAs with KE and the state oil company Agencia Nacional do Petroleo
(BP 50%). Following the acquisition and analysis of baseline
environmental data, seismic acquisition is ongoing and expected to
be completed by mid-2020.
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%).
• In the first quarter of 2019 BP relinquished its interest in its two
PSCs for shale gas exploration, development and production in the
Neijiang-Dazu block and Rong Chang Bei block in the Sichuan
basin, resulting in a $141m exploration write-off. Exit was fully
completed in the fourth quarter of 2019 when a termination
agreement was formally executed with CNPC.
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.
• Naftiran Intertrade Co Ltd (NICO), a subsidiary of the National
Iranian Oil Company, holds a 10% interest in the Shah Deniz joint
venture. For information on the exclusion of this project from EU
and US trade sanctions, or exemptions from such trade sanctions
in relation to this project, see International trade sanctions on page
320.
• In April a final investment decision was made on the Azeri Central
East (ACE) project, the next stage of the Azeri-Chirag-Deepwater
Gunashli (ACG) field. The $6 billion development includes a new
offshore platform and facilities designed to process up to 100,000
barrels of oil per day. The project is expected to achieve first
production in 2023.
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 2019 of 643mboe/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 2019.
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 440mboe/d (including expansion), with average
throughput in 2019 of 177mboe/d.
BP also holds a 12% interest in the Trans Anatolian Natural Gas
Pipeline. In the first phase, which commenced in 2018, gas from
Shah Deniz is transported from Georgia to Eskishehir in Turkey. The
capacity of the pipeline during the first phase is 100mboe/d and the
average throughput in 2019 was 47mboe/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 Oman BP operates the Khazzan field in Block 61 (BP 60%).
• Progress on the Ghazeer project, phase two of the Khazzan
development, is on track for first gas in 2021.
BP Annual Report and Form 20-F 2019
«See Glossary
305
• In July BP and Eni signed an EPSA for Block 77 (BP 50%) in central
Oman with the Ministry of Oil and Gas of the Sultanate of Oman.
Approval by Royal Decree is still pending.
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 6 million tonnes of LNG (0.786bcfed
regasified) in 2019. 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 took effect from 1
April 2019, and replaced an existing agreement which expired on
31 March 2019.
• Also in March 2019 ADNOC LNG and NGSCO agreed to extend the
transportation agreements and the shipping services agreement to
2022. The new agreements took effect from 1 April 2019, and
replaced an existing agreement which expired on 31 March 2019.
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 2018-19
plan was delivered and implementation of the 2019-20 plan is
underway.
In India we have a participating interest in two oil and gas PSAs (KG
D6 33.33% and NEC25 33.33%), one oil and gas block under a
Revenue Sharing Contract (KG-UDWHP-2018/1), all 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 June BP and RIL announced the sanction of the MJ gas
development project (also known as D55) in Block KG D6, offshore
the east coast of India. MJ is the third of three new projects in the
Block KG D6 integrated development plan.
• All three KG D6 Projects (R-Series, Satellites Cluster and MJ) are
under development with first gas production phased over
2020-2022. R-Series, the first of the three projects, is expected to
begin production in 2020.
• BP and its partner RIL have been awarded the ultra deep-water
Block KG-UDWHP-2018/1 (RIL operator 60%, BP 40%) adjacent to
Block KG D6 in India’s Open Acreage Licensing Policy round 2 and
both RIL and BP have entered into a Revenue Sharing Contract
with the Government of India (GoI).
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 joint venture participants are progressing the
development of Browse by connecting it via a 900km pipeline to
the NWS Venture's Karratha Gas Plant. A final investment decision
is expected in late 2021.
• During the second quarter BP achieved new access with a farm-in
to an exploration permit WA-359-P offshore Western Australia (BP
42.5% and operator).
• In September BP confirmed the award of the WA-541 acreage
permit in Western Australia’s offshore Northern Carnarvon basin
(BP 50%).
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 comprises a third LNG processing
train, two offshore platforms, 13 new production wells, an expanded
LNG loading facility, and supporting infrastructure. 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. The
installation of offshore platforms and pipelines has completed while
the multi-year drilling campaign continues after the completion of the
first production well. The construction of the LNG processing train is
in progress with expected start-up in 2021.
• Pursuant to government approval, Niko (NECO) Limited’s 10%
participating interest in Block KG D6 has been assigned to BP and
RIL proportionately in the ratio of their existing interests (RIL
6.67%, BP 3.33%), in compliance with the PSC and JOA
requirements.
.
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. BP's
activities have not been materially impacted by the continued political
instability and public protests which have occurred in 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. Also with Rosneft, we hold a
49% interest in Kharampurneftegaz LLC (Kharampur) to develop
subsoil resources within the Kharampurskoe and Festivalnoye licence
areas in Yamalo-Nenets. Rosneft (51%) and BP (49%) jointly own
Yermak Neftegaz LLC (Yermak), which conducts onshore exploration
in the West Siberian and Yenisei-Khatanga basins and currently holds
five exploration and production licences. See Rosneft on page 61 for
further details.
• In April the right to explore two additional oil and gas licence areas
located in Sakha (Yakutia) was transferred to a Yermak wholly owned
subsidiary.
306
«See Glossary
BP Annual Report and Form 20-F 2019
Downstream plant capacity
The following tablea summarizes BP group’s interests in refineries and average daily crude distillation capacities as at 31 December 2019.
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
Gelsenkirchen
Lingen
Rotterdam
Castellón
Australia
New Zealand
South Africa
Kwinana
Whangareief
Durbane
Crude distillation capacitiesbc
Group interestd
(%)
BP share
thousand barrels
per day
100
100
50
100
100
100
100
100
10.1
50
251
440
80
771
265
97
387
110
859
152
34
90
276
1,906
Total BP share of capacity at 31 December 2019
a This does not include BP’s interest in Pan American Energy Group.
b Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period under normal operational conditions.
c On 31 December 2019 we completed the sale of our interest in the German Bayernoil refinery.
d BP share of equity, which is not necessarily the same as BP share of processing entitlements.
e Indicates refineries not operated by BP.
f 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 2019.
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 2019
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.
BP Annual Report and Form 20-F 2019
«See Glossary
307
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 2019 BP had material volumes of proved undeveloped
reserves held for more than five years in Russia, Trinidad, Gulf of
Mexico and the North Sea. 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% (19% for 2018 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 less than 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 2019 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 2019 we progressed 1,328mmboe of proved undeveloped reserves
(561mmboe for our subsidiaries« alone) to proved developed
reserves through ongoing investment in our subsidiaries’ and equity-
accounted entities’ upstream development activities. Total
development expenditure, excluding midstream activities, was
$15,206 million in 2019 ($10,815 million for subsidiaries and $4,391
million for equity-accounted entities). The major areas with
progressed volumes in 2019 were Russia, US, Trinidad, Egypt,
Azerbaijan, Argentina, Oman and UAE. 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 negative
revisions in the US Lower 48 due to reducing price impacts and
changes in our development plan to incorporate activity associated
with the purchase of new assets partially offset by material net
positive revisions to our proved undeveloped resources in Russia as a
result of development drilling results. The following tables describe
the changes to our proved undeveloped reserves position through the
year for our subsidiaries and equity-accounted entities and for our
subsidiaries alone.
Subsidiaries and equity-accounted entities
Proved undeveloped reserves at 1 January 2019
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
2019
Subsidiaries only
Proved undeveloped reserves at 1 January 2019
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
2019
volumes in mmboea
8,908
(320)
316
563
17
(35)
541
31
(1,328)
8,152
volumes in mmboea
4,447
(545)
309
130
10
(29)
(127)
13
(561)
3,771
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
308
«See Glossary
BP Annual Report and Form 20-F 2019
certainty of commercial recovery, BP employs a general method of
reserves assessment that relies on the integration of three types of
data:
• well data used to assess the local characteristics and conditions of
reservoirs and fluids
• 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 14 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 Management.
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 2019, 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 2019. 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 2019, 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 2019. 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
91% of our total proved reserves of subsidiaries at
31 December 2019 were held through joint operations«(89% in
2018), and 28% of the proved reserves were held through such joint
operations where we were not the operator (34% in 2018).
BP Annual Report and Form 20-F 2019
«See Glossary
309
Estimated net proved reserves of crude oil at
31 December 2019a b c
UK
USd
Rest of North Americae
South Americaf
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entities
Total
Developed
Undeveloped
206
1,063
40
7
156
1,074
26
2,572
3,567
6,140
200
842
179
5
40
525
4
1,794
2,847
4,642
Estimated net proved reserves of natural gas liquids at
31 December 2019a b
UK
US
Rest of North America
South America
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entities
Total
Developed
Undeveloped
8
229
—
2
12
—
4
255
107
363
5
250
—
21
4
—
—
280
55
334
million barrels
Total
406
1,905
218
12
196
1,599
30
4,367
6,415
10,781
million barrels
Total
13
479
—
23
16
—
4
535
162
697
Estimated net proved reserves of liquids«
Subsidiariesf
Equity-accounted entitiesg
Total
Developed
Undeveloped
2,828
3,675
6,502
2,074
2,902
4,976
million barrels
Total
4,902
6,576
11,478
Estimated net proved reserves of natural gas at
31 December 2019a b
UK
US
Rest of North America
South Americah
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entitiesi
Total
billion cubic feet
Developed Undeveloped
493
6,330
—
2,192
1,163
3,667
2,256
16,101
11,079
27,181
207
2,127
—
2,235
742
3,401
1,132
9,844
8,576
18,421
Total
700
8,458
—
4,427
1,905
7,068
3,389
25,946
19,656
45,601
Estimated net proved reserves on an oil equivalent basisj
Subsidiaries
Equity-accounted entities
Total
million barrels of oil equivalent
Developed
5,604
5,585
11,189
Undeveloped
3,771
4,381
8,152
Total
9,375
9,965
19,341
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 2019 marker prices used were Brent« $62.74/bbl (2018 $71.43/bbl and 2017 $54.36/
bbl) and Henry Hub« $2.58/mmBtu (2018 $3.10/mmBtu and 2017 $2.96/mmBtu).
c Includes condensate.
d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 4.5 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 11 million barrels of liquids in respect of the 30% non-controlling interest in BP
Trinidad and Tobago LLC.
g Includes 357 million barrels of liquids in respect of the non-controlling interest in Rosneft
held assets in Russia including 26 million barrels held through BP’s interests in Russia other
than Rosneft.
h Includes 1,330 billion cubic feet of natural gas in respect of the 30% non-controlling
interest in BP Trinidad and Tobago LLC.
i
Includes 1,430 billion cubic feet of natural gas in respect of the non-controlling interest in
Rosneft held assets in Russia including 569 billion cubic feet held through BP’s interests in
Russia other than Rosneft.
j Includes 982 million barrels of oil equivalent associated with Assets held for sale in the US.
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 2019, on an oil
equivalent basis including equity-accounted entities, decreased by
3% (decrease of 8% for subsidiaries and increase of 2% for equity-
accounted entities) compared with 31 December 2018. Natural gas
represented about 41% (48% for subsidiaries and 34% for equity-
accounted entities) of these reserves. The change includes a net
decrease from acquisitions and disposals of 133mmboe (decrease of
134mmboe within our subsidiaries and increase of 1mmboe within
our equity-accounted entities). Acquisition activity in our subsidiaries
occurred in India, and divestment activity in our subsidiaries in the US
and Egypt. There were no material acquisitions or 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 2019, the proved reserves replacement ratio
excluding acquisitions and disposals was 67% (100% in 2018 and
143% in 2017) for subsidiaries and equity-accounted entities, 25% for
subsidiaries alone and 141% for equity-accounted entities alone.
There was a net decrease (221mmboe) of reserves due to lower gas
and oil prices mainly within the US Lower 48 (-206mmboe). The total
loss was partly offset by increases in reserves in our PSAs, principally
in Azerbaijan, Iraq and Angola.
In 2019 net additions to the group’s proved reserves (excluding
production and sales and purchases of reserves-in-place) amounted
to 939mmboe (230mmboe for subsidiaries and 709mmboe 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 2019
principally resulted from the application of conventional technologies
and extensions of field size by development drilling. The principal
proved reserves additions in our subsidiaries by region were in the
US, Oman, UAE, Azerbaijan and India. We had material reductions in
our proved reserves in US Lower 48 principally due to lower oil and
gas prices. The principal reserves additions in our equity-accounted
entities were in Pan American Energy Group, Rosneft and
Kharampurneftegaz LLC.
15% of our proved reserves are associated with PSAs. The countries
in which we produced under PSAs in 2019 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.
BP holds reserves classified as Assets held for sale within the US
associated with our announced divestment of our Alaska and San
Juan fields.
For further information on our reserves see page 239.
310
«See Glossary
BP Annual Report and Form 20-F 2019
BP’s net production by country – crude oila and natural gas liquids
2019
2018
Crude oil
2017
thousand barrels per day
BP net share of productionb
Natural gas
liquids
2019
2018
2017
Subsidiaries
UKc d
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
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
100
100
71
66
263
400
24
24
424
7
7
115
34
7
156
180
79
64
—
20
343
343
15
2
17
1,046
920
—
54
2
—
35
35
1
—
1,047
2,093
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
3
3
—
58
24
81
—
—
81
9
9
—
—
8
8
—
—
—
—
—
—
—
2
—
2
104
3
—
1
—
3
2
—
5
—
14
118
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
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 2019, BP completed the sale of its interest in the Gulf of Suez Petroleum Company (GUPCO) in Egypt and certain US assets in Lower 48 onshore and disposed of its interests in the Gulf
of Mexico Santiago and Santa Cruz wells. 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.
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 (2018 3mboe/d and 2017 3mboe/d).
Because of rounding, some totals may not agree exactly with the sum of their component parts.
BP Annual Report and Form 20-F 2019
«See Glossary
311
BP’s net production by country – natural gas
Subsidiaries
UKb
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
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
2019
2018
2017
129
129
2,175
179
4
2,358
2
2
2,361
1,977
1,977
952
186
1,138
367
15
594
976
976
411
375
786
7,366
1,279
250
64
56
87
—
1,736
9,102
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
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 2019, BP completed the sale of its interest in the Gulf of Suez Petroleum Company (GUPCO) in Egypt and certain US assets in Lower 48 onshore and disposed of its interests in the Gulf
of Mexico Santiago and Santa Cruz wells. 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.
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.
312
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BP Annual Report and Form 20-F 2019
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
65.44
29.58
4.01
71.28
31.63
7.71
53.67
32.77
5.09
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
64.75
—
5.01
70.24
—
7.93
55.08
—
5.78
59.19
14.67
1.93
67.11
25.81
2.43
49.98
22.42
2.36
—
—
—
—
—
—
—
—
—
40.92
—
—
33.57
—
—
36.80
—
—
—
—
—
—
—
—
—
—
—
63.30
25.86
2.78
69.17
35.74
3.08
55.44
26.79
2.25
56.85
18.14
3.98
62.35
—
4.36
49.97
—
4.49
63.75
31.89
4.59
68.81
39.14
4.82
53.61
36.48
3.82
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
57.00
N/A
1.83
62.46
N/A
1.70
45.66
N/A
1.63
64.39
—
3.99
70.80
92.47
3.85
52.88
—
3.44
—
—
—
39.49
—
—
15.61
—
—
59.65
38.11
6.86
67.54
52.14
7.97
53.26
39.39
6.14
—
—
—
—
—
—
—
—
—
Total
group
average
61.56
18.23
3.39
67.81
29.42
3.92
51.71
26.00
3.19
57.36
20.40
3.39
62.24
—
2.50
42.33
—
2.47
Subsidiaries
2019
Crude oilc
Natural gas liquids
Gas
2018
Crude oilc
Natural gas liquids
Gas
2017
Crude oilc
Natural gas liquids
Gas
Equity-accounted
entitiesd
2019
Crude oilc
Natural gas liquidse
Gas
2018
Crude oilc
Natural gas liquidse
Gas
2017
Crude oilc
Natural gas liquidse
Gas
Average production cost per unit of productionf
$ per unit of production
Europe
UK
Rest of
Europe
13.22
13.76
14.58
—
—
—
—
—
—
12.51
12.15
10.33
North
America
South
America
Africa
Asia
Australasia
Rest of
North
America
13.36
13.10
15.02
—
—
—
US
8.46
9.63
8.68
—
—
—
Russia
Rest of
Asia
3.36
3.08
4.41
11.50
10.61
11.92
7.95
7.31
6.47
10.40
—
—
—
—
—
3.07
3.09
3.19
5.15
5.72
6.37
—
5.92
3.27
2.33
2.35
2.79
—
—
—
Total
group
average
6.84
7.15
7.11
5.13
4.16
4.32
Subsidiaries
2019
2018
2017
Equity-accounted
entities
2019
2018
2017
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.
BP Annual Report and Form 20-F 2019
«See Glossary
313
Environmental expenditure
Operating expenditure
Capital expenditure
Clean-ups
Additions to environmental
remediation provision
Increase (decrease) in
decommissioning provision
2019
511
468
23
272
1,045
2018
501
449
31
428
137
$ million
2017
441
487
22
249
(228)
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 $511 million in 2019 (2018
$501 million) showed an overall increase of 2%, with increases in
Upstream costs (due in large part to increases in expenditure
associated with the acquisitions of BHP assets into BPX Energy)
largely balanced out by slight reductions in costs for Downstream and
Shipping.
Environmental capital expenditure in 2019 was slightly higher overall
than in 2018 largely due to increased costs in Upstream, due in large
part to increases in expenditure associated with the acquisitions of
BHP assets into BPX Energy.
Clean-up costs were $23 million in 2019 (2018 $31 million)
representing oil spill clean-up costs and other associated remediation
and disposal costs. The reduction compared to 2018 results largely
from the downstream business where clean-up costs in BP Pipelines
(North America) were significantly lower than in 2018.
In addition to operating and capital expenditure, we also establish
provisions for future environmental remediation work. Expenditure
against such provisions normally occurs in subsequent periods and is
not included in environmental operating expenditure reported for such
periods.
Provisions for environmental remediation are made when a clean-up
is probable and the amount of the obligation can be reliably
estimated. Generally, this coincides with the commitment to a formal
plan of action or, if earlier, on divestment or on closure of inactive
sites.
The extent and cost of future environmental restoration, remediation
and abatement programmes are inherently difficult to estimate. They
often depend on the extent of contamination, and the associated
impact and timing of the corrective actions required, technological
feasibility and BP’s share of liability. Though the costs of future
programmes could be significant and may be material to the results
of operations in the period in which they are recognized, it is not
expected that such costs will be material to the group’s overall results
of operations or financial position.
Additions to our environmental remediation provision was similar to
prior years and also reflects scope reassessments of the remediation
plans of a number of our sites in the US and Canada. The charge for
environmental remediation provisions in 2019 included $9 million in
respect of provisions for new sites (2018 $8 million and 2017 $8
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 2019, the net increase in the decommissioning provision was due
to a change in the discount rate and a detailed reviews of expected
future costs.
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.
Regulation of the group’s business
BP’s activities are subject to a broad range of EU, US, international,
national, 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.
Following the UK’s exit from the European Union on 31 January 2020,
the UK has now entered a transition period which, unless extended,
is due to run until 31 December 2020. During the transition period,
most EU law will continue to apply to the UK and therefore to BP’s
UK business during that period. The vast majority of environment-
related statutory instruments passed by the UK Government in
anticipation of Brexit have included no substantive changes to the
current EU underlying regime, but rather seek to make the
amendments required to allow their continued operation after the
transition period. The UK Government’s Environment Bill and 25 Year
Plan will be central to the UK’s environmental regime going forward
but further changes are as yet uncertain. The following section
describes EU laws and regulations relevant to our business both in
the UK and the EU.
Upstream contractual and regulatory framework
The terms and conditions of the leases, licences and contracts under
which our upstream 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.
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.
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. 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.
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
314
«See Glossary
BP Annual Report and Form 20-F 2019
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, licence or PSA are shared
among the joint arrangement or co-owning parties according to these
agreed ownership interests. Ownership of joint arrangement or co-
owned property and hydrocarbons to which the joint arrangement or
co-ownership is entitled is also shared in these proportions. To the
extent that any liabilities arise, whether to governments or third
parties, or as between the joint arrangement parties or co-owners
themselves, each joint arrangement party or co-owner will generally
be liable to meet these in proportion to its ownership interest. In
many upstream operations, a party (known as the operator) will be
appointed (pursuant to a joint operating agreement) to carry out day-
to-day operations on behalf of the joint arrangement or co-ownership.
The operator is typically one of the joint arrangement parties or a co-
owner and will carry out its duties either through its own staff, or by
contracting out various elements to third-party contractors or service
providers. BP acts as operator on behalf of joint arrangements and co-
ownerships in a number of countries.
Frequently, work (including drilling and related activities) will be
contracted out to third-party service providers. The relevant contract
will specify the work, the remuneration, and typically the risk
allocation between the parties. Depending on the service to be
provided, the 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 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. On 1 June 2017, the US announced that it will
withdraw from the Paris Agreement. The process for withdrawal can
be completed no earlier than 4 November 2020.
Recent annual United Nations climate change conferences have
established a ‘Paris Rulebook’ defining how some elements of the
Paris Agreement will be implemented. Rules for implementing Article
6, which could enable international carbon trading to assist in meeting
NDCs, have not been agreed. This has now been deferred to COP26
to take place in Glasgow, Scotland in November 2020.
More stringent national and regional measures relating to the
transition to a lower carbon economy, such as the UK's 2050 net zero
carbon emissions commitment 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, BP's operations are affected by GHG regulation in a
number of ways. The federal Clean Air Act (CAA), for example,
regulates air emissions, permitting, fuel specifications and other
aspects of our production, refining, distribution and marketing
activities.
Environmental Protection Agency (EPA) regulations 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
were introduced by the Obama administration. In August 2019,
however, the EPA issued a new proposed rule to that would both
rescind certain methane regulations and potentially remove storage
and transmission facilities from the regulatory scheme. In addition,
the Bureau of Land Management (BLM) in 2018 issued a new waste
prevention rule which rescinded the prior 2017 rule regarding
methane regulation on federal lands. The EPA rule and the new BLM
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.
In 2019, the EPA issued the final Affordable Clean Energy (ACE) Rule,
which is intended to address GHG emissions from certain existing
sources in the electricity sector, and which is intended to replace the
Obama-administration’s Clean Power Plan (CPP). A number of
lawsuits have been filed regarding the legality of the ACE Rule and
the repeal of the CPP regulations. 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.
The Energy Policy Act of 2005 and the Energy Independence and
Security Act of 2007 impose the Renewable Fuel Standard (RFS),
requiring transportation fuel sold in the United States to contain a
minimum volume of renewable fuels. Certain state initiatives impose
lower GHG emissions thresholds for transportation fuels (e.g., in
California and Oregon). In 2019, EPA promulgated regulations easing
volatility requirements for certain categories of gasoline and revising
certain elements of the RFS credit-trading programme, which is the
open market for renewables credit trading.
The GHG mandatory reporting rule (GHGMRR), requires annual GHG
emissions reports to 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 easing
environmental regulation with separate initiatives that affect our US
operations. For example, the California cap and trade programme
started in January 2012 and expanded to cover emissions from
transportation fuels in 2015. The State of Washington has adopted a
carbon cap rule although the state’s supreme court has modified the
rule to exclude coverage of sales and distribution of petroleum fuels.
Our US businesses are subject to increased GHG and other
environmental requirements and regulatory uncertainty, including
that future US administrations could revise or revoke current
administration programs, as well as increased expenditures in having
to comply with numerous diverse and non-uniform regulatory
initiatives at the state and local level.
European Union
• The EU has adopted various measures seeking to reduce GHG
emissions and encourage renewables. A set of regulatory
BP Annual Report and Form 20-F 2019
«See Glossary
315
measures were adopted which included: a collective national
reduction target for emissions not covered by the EU Emissions
Trading System (EU ETS) Directive; binding national renewable
energy targets (including targets in the transport sector) under the
Renewable Energy Directive; and a legal framework to promote
carbon capture and storage (CCS).
• In 2014 EU leaders adopted a climate and energy framework
setting 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 addressing
surplus allowances and the amount of free allocation for sectors
prone to international competition. In November 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. It also
sets a renewable energy target of 14% for the transportation
sector.
• In December 2019 the European Commission proposed an
ambitious ‘European Green Deal’. These proposals will require
formal approval by European Member States and include:
– a climate neutrality commitment for 2050 and raising the
2030 ambition to at least 50% GHG reductions by 2030 from
1990 levels, up from the 40% currently agreed;
– a proposal to enshrine the 2050 climate-neutrality target into
legislation;
– a plan to extend the Emissions Trading System to include the
maritime sector and reduce the allowances allocated for free
to airlines;
– a proposal to implement a carbon border tax adjustment to
protect European industry from carbon leakage; and
– a review of the Energy Taxation Directive, with the aim of
harmonising and directing energy taxation across the
member states.
• The Medium Combustion Plants Directive 2015 (MCPD) regulates
sulphur dioxide (SO2), nitrogen oxides (NOx) and particulates
emissions and monitoring of carbon monoxide (CO) emissions from
certain mid-size plants. It applies to new plants and by 2025 or
2030 to existing plants, depending on their size.
• The National Emission Ceilings Directive 2016 (NECD) introduces
stricter emissions limits from 2020 and 2030, with new indicative
national targets applying from 2025. NECD has been implemented
in the UK by the National Emission Ceilings Regulations 2018. Each
EU Member State was also required to produce a National Air
Pollution Control Programme 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.
• In December 2019 the Dutch Supreme Court (De Hoge Raad) ruled
that the Dutch Government must reduce gross GHG Emissions in
the Netherlands by 25% based on 1990 levels. The Dutch
Government is expected to publish its policy proposals to achieve
the 25% target in early 2020.
• The German Government has passed a national emissions trading
law that will in a first phase include limits on emissions from
transport and heating fuels. Impacted fuel suppliers in Germany will
pay a fixed price for emissions certificates of EUR 25 per tonne
CO2 in 2021 rising to EUR 55 per tonne by 2025. From 2026
emissions certificates will be auctioned but with prices limited
between EUR 55 and EUR 65 per tonne CO2 emitted.
Other
• Alberta Province has adopted large facility carbon emission
regulations requiring reductions in carbon intensity year-on-year
which can be met by improving emissions intensity, the purchase
of offsets or payments into a provincial emissions technology fund.
Emissions not covered under these regulations are subject to
escalating Federal carbon emissions backstop pricing. Additional
requirements are in place relating to electricity generation sources
and limits on overall oil sands emissions.
• The Canadian federal climate change regulations include 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 provincial implementation of the price
and associated large emitters pricing system, use of any funds
generated, and outcome reporting. Newfoundland & Labrador and
Nova Scotia have implemented 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.
China launched its national emissions trading market (initially
covering the power sector only) politically in 2017 with a three-step
roadmap (“National ETS”). The National ETS will not supersede the
above eight pilot programmes immediately but allow those pilot
schemes to be incorporated into the national scheme gradually. In
the short term, the existing pilot schemes are expected to operate
in parallel covering the non-power sectors. In March 2018, the new
Ministry of Ecology and Environment was established as part of the
overall ministerial restructuring which absorbs the climate change
responsibilities previously under the National Development and
Reform Commission and takes charge of the development of the
National ETS. As of December 2019, the National ETS is still at the
first phase (infrastructure development phase) and preparing for
the second phase (simulation trading phase).
• 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 has been accelerating
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 – Environment on page 40.
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.
Environmental laws also 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 314 and for a discussion of legal
proceedings, see page 319.
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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 include the following:
United States
• The Trump administration has issued a number of Executive Orders
affecting federal permitting and rulemaking processes that seek to
reduce regulatory burdens placed on manufacturing generally and
the energy industry specifically. 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 an
environmental analysis 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, modify or block projects. State law analogues to
NEPA could also limit or delay our projects. The Trump
administration has taken steps to significantly modify and
streamline the NEPA review process for major infrastructure
projects including energy production, pipeline and transmission
systems. The timing and effect on our operations remain uncertain
and any final rule is likely to face legal challenges.
• As discussed above under ‘Greenhouse gas regulation’, US fuel
markets are affected by EPA regulation of light, medium and heavy
duty vehicle emissions (both fuel economy and tailpipe standards)
as well as for non-road engines and vehicles and 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, as allowed by CAA
authority, have adopted standards identical to California’s
standards. 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. The Trump administration has challenged California’s
authority to impose stricter vehicle emission standards, which are
followed by numerous other states, and the outcome of this
challenge remains uncertain.
• In 2018 the Trump administration proposed rolling back the Obama
administration’s fuel economy and tailpipe carbon dioxide
emissions standards for passenger cars and light trucks covering
model years (MY) 2021 through 2026 by locking in the 2020
standards until 2026. It has also proposed eliminating the waiver
allowing California to set its own LEV and ZEV standards and for
other states to adopt standards identical to California. In
September 2019, NHTSA and EPA issued part one of One National
Program for fuel economy regulation by announcing EPA's decision
to withdraw California's waiver of pre-emption for its LEV and ZEV
standards and finalizing the Department of Transportation’s
regulatory text relating to pre-emption of state fuel economy
standards. California and twenty-five states and cities filed a
lawsuit challenging those regulations. The outcome of that litigation
is uncertain.
• In January 2020, EPA issued an Advance Notice of Proposed Rule
(ANPR) soliciting pre-proposal comments on a rulemaking known
as the Cleaner Trucks Initiative. The rule would establish new
emission standards for oxides of nitrogen (NOx) and other
pollutants for highway heavy-duty engines. It would seek to
streamline and improve certification procedures to reduce costs for
engine manufacturers. California is also working on tighter heavy-
duty engine NOx standards. EPA has not notified fuels suppliers of
any expected fuel specification changes that would be included
with these new engine standards and BP continues to monitor this
rule for implications for fuels.
• 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 and
natural resource damages under other federal and state laws which
also require notification of spills to designated government
agencies.
• The Emergency Planning and Community Right-to-Know Act
requires reporting on the storage, use and releases of certain
quantities of listed hazardous substances to designated
government agencies.
• The Toxic Substances Control Act (TSCA) regulates BP’s
manufacture, import, export, sale and use of chemical substances
and products. In addition, EPA has revised processes and
procedures for prioritization of existing chemicals for risk
evaluation, assessment and management. Agency actions and
announcements are monitored regularly to identify developments
with potential impacts on chemical substances important to BP
products and operations. Thus far, two substances have been
identified for specific ongoing monitoring of developments and
impacts.
• The Occupational Safety and Health Act imposes workplace safety
and health requirements on BP operations along with significant
process safety management obligations (PSM), requiring
continuous evaluation and improvement of operational practices to
enhance safety and reduce workplace emissions at gas
processing, refining and other regulated facilities. The US
Occupational Safety and Health Administration (OSHA) conducts
inspections under the National Emphasis Program to ensure
compliance with PSM requirements in both refineries and chemical
plants.
• The Oil Pollution Act 1990 (OPA) imposes operational
requirements, liability standards and other obligations governing
the transportation of petroleum products in US waters. States may
impose additional obligations. 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’ habitats from adverse human impacts by
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. These include the BAT Conclusions for the refining
sector, for large combustion plants as well as common wastewater
and waste gas treatment and management systems in the
chemical sector these may require 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 Annual Report and Form 20-F 2019
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317
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 2019, the European Parliament and the Council adopted
Regulation (EU) 2019/631 setting CO2 emission performance
standards for new passenger cars and for new light commercial
vehicles (vans) in the EU for the period after 2020. From a 2021
baseline, it requires EU fleet-wide reductions of 15% by 2025 and
37.5% by 2030 for passenger cars, and 15% by 2025 and 31% by
2030 for new light commercial 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. 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
continue to undergo 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.
• 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 implementation in the EU member
states is still ongoing, planned to be finalised by 2027. At the
moment a Fitness Check (comprehensive policy evaluation) of the
EU Water Legislation is ongoing, also covering the WFD and its
daughter directives (Groundwater Directive and Environmental
Quality Standards Directive). The outcome of the policy evaluation,
expected to be published in 2020, may require additional
compliance efforts and increased costs for managing freshwater
withdrawals and discharges from BP’s EU operations.
Other countries and regions
Turkey has published REACH-like regulations, known as KKDIK, as
well as related implementation schedules and substance
registrations.
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.
The Abidjan Convention, along with the Additional Protocol published
in 2012, sets environmental quality standards for the discharge of
chemicals to the marine environment. The convention and associated
protocols has been ratified by 19 African nations including Senegal
and Mauritania. BP is currently designing produced water
management systems to meet the environmental quality standards
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 2019, the HNS
Convention had not entered into force.
• A global sulphur cap of 0.5% applies to marine fuel under
MARPOL. In order to comply, ships will either need to consume
low sulphur marine fuels, operate on alternative 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.
• In December 2019 EPA finalized measures to facilitate smooth
implementation of IMO 2020. EPA finalized technical corrections
that will allow fuel suppliers to distribute distillate diesel fuel that
complies with the 5,000 ppm international sulphur standard for
ships instead of the fuel standards that otherwise apply to distillate
diesel fuel in the United States. The EPA clarified that fuel meeting
the 5,000 ppm global sulphur cap may not be used inside of
Emission Control Area (ECA) boundaries.
• The Convention for the Protection of the Marine Environment of
the North-East Atlantic (OSPAR), aims to protect the marine
environment of the North-East Atlantic. OSPAR Recommendation
2001/1 regulates the management of produced water from
offshore installations in the North Sea including reductions in the
total quantity of oil in produced water and a performance standard
for dispersed oil in produced water discharged into the sea.
Guidelines for the implementation of a risk-based approach to the
management of produced water discharges from offshore
installations supports a key goal of achieving a reduction of oil in
produced water discharged into the sea by 2020 to a level which
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BP Annual Report and Form 20-F 2019
will adequately ensure that each of those discharges will present
no harm to the marine environment.
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, 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 into two multi-district litigation proceedings, one in
federal district court in Houston for the securities 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.
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 in 2019. 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.
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).
The deadline for submitting SPC and PMCP claims was 12
February 2015. A total of 37,226 claims have been submitted. As
of 31 December 2019, 27,604 claims (comprising 22,831 SPC
claims and 4,773 PMCP claims) have been approved for
compensation totalling approximately $67 million; 9,621 claims
have been denied; and 1 claim is 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 the date of first diagnosis of the
LMPC. As of 31 December 2019, there were 2,701 pending
lawsuits brought by class members claiming LMPCs.
Other civil complaints – economic loss
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 have
been settled or dismissed. 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. Most of these have now been either settled or
dismissed. On 5 February 2019, the district court issued a case
management order addressing the 184 remaining plaintiffs in
MDL 2179 with claims for economic loss or property damage. The
district court ordered BP and 69 of those plaintiffs to undertake
mandatory mediation and so far this has resulted in settlement of
more than 40 plaintiffs’ claims. The district court ordered that BP
file any dispositive motions as to the other 115 plaintiffs
(principally Mexican-resident plaintiffs who are fishermen or
fishing cooperatives) by 7 March 2019. BP moved to dismiss
those 115 claims on 7 March 2019, and its motion remains
pending.
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.
In 2019, the district court in MDL 2179 determined in a series of
proceedings that 923 plaintiffs had post-explosion clean-up,
medical monitoring and personal injury claims that complied with
the court’s prior order to show cause why their claims should not
be dismissed. Five plaintiffs have appealed their dismissal to the
Fifth Circuit. Briefing is ongoing and oral argument and a decision
are expected in 2020.
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
2019, 28 actions on behalf of 115 plaintiffs remained pending in MDL
2185. Pursuant to a scheduling order issued by the district court, fact
and expert discovery with respect to 16 representative plaintiffs is
scheduled to proceed through to August 2020 and dispositive
motions are scheduled to be filed by 27 October 2020.
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. On 24 June 2019, the plaintiff filed an
amended complaint adding fraud claims. On 8 November 2019, the
court granted BP’s motion to dismiss the case in its entirety. On 6
December 2019, the plaintiff appealed that decision.
Non-US government lawsuits
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 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.
BP Annual Report and Form 20-F 2019
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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 and BPAPC opposed class
certification and sought dismissal, principally on the basis that no oil
reached Mexican waters or land and there was no economic or
environmental harm in Mexico. On 25 September 2019, the court
certified the class. On 15 October 2019, BP appealed that decision.
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.
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. In March 2019, BP and the Plaintiffs agreed to a
settlement of the class action lawsuit, subject to final court approval.
On 4 June 2019 the court granted final approval of the settlement
agreement. The judgment dismissing the case was entered on 13
June 2019. No appeal was taken from the judgment on or before the
14 July 2019 deadline. On 15 July 2019, BP made its first payment
under the terms of the settlement agreement. The second and final
payment is due in July 2020.
Climate change
BP p.l.c., BP America Inc. and BP Products North America Inc. are co-
defendants with other oil and gas companies in multiple lawsuits
brought in various state courts on behalf of several US cities and
counties, one state, and a crab fishing industry association. In the
lawsuits, the plaintiffs generally plead a variety of legal theories
seeking to hold the defendant companies responsible for impacts
allegedly caused by and/or relating to climate change and claim
damages. All of the cases remain at relatively early stages.
Louisiana Coastal restoration
Six coastal parishes and the State of Louisiana have filed over 40
separate lawsuits in state courts in Louisiana against various oil and
gas companies seeking damages for coastal erosion. BP entities are
defendants in 17 of these cases. The lawsuits allege that the
defendants' historical operations in oil fields within the Louisiana
onshore coastal zone failed to comply with state permits and/or were
conducted without the required coastal use permits. The plaintiffs
seek unspecified statutory penalties and damages, including the
costs of restoring coastal wetlands allegedly impacted by oil field
operations. All of the cases are at relatively early stages.
In addition, four private landowners have filed separate claims in the
state courts in Jefferson and Plaquemines Parishes of Louisiana for
restoration damages related to alleged impacts to their marshlands
associated with historic oil field operations. BP entities are
defendants in three of these private landowner cases.
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.
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-operating
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
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 27 November 2019, OFAC issued a new
licence in relation to these arrangements.
Following the imposition in 2011 of further US and EU sanctions
against Syria, BP terminated all sales of crude oil and petroleum
products into Syria, though BP continues to supply aviation fuel to
non-governmental Syrian resellers outside of Syria.
BP has a joint arrangement in Cuba which imports, manufactures,
markets and sells 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
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sectoral sanctions list own a certain percentage interest. 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 ITRA Section 219
To our knowledge, none of BP’s activities, transactions or dealings are
required to be disclosed pursuant to ITRA Section 219.
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 2019 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 2019 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 2019 to 3 March
2020.
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
directors whom the board has determined to be independent, in the
manner described above.
The BP board governance principles prescribe the composition, main
tasks and requirements of each of the committees (see the board
committee reports on pages 90-99). BP has not, therefore, adopted
separate charters for each committee but the board will focus on
developing a new corporate governance framework as the successor
to the BP governance principles. This framework will reinforce the
effectiveness of the internal control framework and be more closely
aligned with BP’s new purpose and ambition.
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
and the UK Corporate Governance code 2018 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 91). 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.
BP Annual Report and Form 20-F 2019
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321
Code of ethics
The company has adopted a code of ethics for its group chief
executive, chief financial officer, group controller, group head of audit
and chief accounting officer as required by the provisions of
Section 406 of the Sarbanes-Oxley Act of 2002 and the rules issued
by the SEC. There have been no waivers from the code of ethics
relating to any officers.
BP also has a code of conduct, which is applicable to all employees,
officers and members of the board. This was updated (and published)
in July 2014.
Controls and procedures
Evaluation of disclosure controls and procedures
The company maintains ‘disclosure controls and procedures’, as such
term is defined in Exchange Act Rule 13a-15(e), that are designed to
ensure that information required to be disclosed in reports the
company files or submits under the Exchange Act is recorded,
processed, summarized and reported within the time periods
specified in the Securities and Exchange Commission rules and
forms, and that such information is accumulated and communicated
to management, including the company’s group chief executive and
chief financial officer, as appropriate, to allow timely decisions
regarding required disclosure.
In designing and evaluating our disclosure controls and procedures,
our management, including the group chief executive and chief
financial officer, recognize that any controls and procedures, no
matter how well designed and operated, can provide only reasonable,
not absolute, assurance that the objectives of the disclosure controls
and procedures are met. Because of the inherent limitations in all
control systems, no evaluation of controls can provide absolute
assurance that all control issues and instances of fraud 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 2019 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 2019 was effective.
The company’s internal control over financial reporting includes
policies and procedures that pertain to the maintenance of records
that, in reasonable detail, accurately and fairly reflect transactions and
dispositions of assets; provide reasonable assurances that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with IFRS and that receipts and
expenditures are being made only in accordance with authorizations
of management and the directors of BP; and provide reasonable
assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of BP’s assets that could have a
material effect on our financial statements. BP’s internal control over
financial reporting as of 31 December 2019 has been audited by
Deloitte LLP, an independent registered public accounting firm, as
stated in their report appearing on page 151 of BP Annual Report and
Form 20-F 2019.
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
committee regularly reviews the policy, including in 2019, to assesses
whether the policy remains fit for purpose against the latest ethical
standards and guidance. The committee will review the policy again in
2020 and the policy will be updated in line with the revised FRC 2019
Ethical Standards.
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
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Employees
Disclosures in respect of how the directors have engaged with
employees and had regard to their interests are included in How the
board has engaged with shareholders, the workforce and other
stakeholders on page 88 and section 172 statement on page 66.
The disclosures concerning policies in relation to the employment of
disabled persons and employee involvement are included in
Sustainability – Our people on page 47.
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.
Suppliers, customers and others
Disclosures in respect of how the directors have engaged with
suppliers, customers and others in business relationships with the
company are included in How the board has engaged with
shareholders, the workforce and other stakeholders on page 88 and
section 172 statement on page 66.
Change of control provisions
On 5 October 2015, the United States lodged with the district court in
MDL 2179 a proposed Consent Decree between the United States,
the Gulf states, BP Exploration & Production Inc., BP Corporation
North America Inc. and BP p.l.c., to fully and finally resolve any and all
natural resource damages claims of the United States, the Gulf states
and their respective natural resource trustees and all Clean Water Act
penalty claims, and certain other claims of the United States and the
Gulf states. Concurrently, BP entered into a definitive Settlement
Agreement with the five Gulf states (Settlement Agreement) with
respect to state claims for economic, property and other losses. On
4 April 2016, the district court approved the Consent Decree, at which
time the Consent Decree and Settlement Agreement became
effective. The federal government and the Gulf states may jointly
elect to accelerate the payments under the Consent Decree in the
event of a change of control or insolvency of BP p.l.c., and the Gulf
states individually have similar acceleration rights under the
Settlement Agreement. For further details of the Consent Decree and
the Settlement Agreement, see Legal proceedings in BP Annual
Report and Form 20-F 2015.
Greenhouse gas emissions
The disclosures in relation to greenhouse gas emissions are included
in Sustainability – Climate change on page 40.
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
180
Not applicable
323
Not applicable
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 93 for details of fees
for services provided by the auditor.
Directors’ report information
This section of BP Annual Report and Form 20-F 2019 forms part of,
and includes certain disclosures which are required by law to be
included in, the Directors’ report.
Indemnity provisions
In accordance with BP’s Articles of Association, on appointment each
director is granted an indemnity from the company in respect of
liabilities incurred as a result of their office, to the extent permitted by
law. These indemnities were in force throughout the financial year and
at the date of this report. In respect of those liabilities for which
directors may not be indemnified, the company maintained a
directors’ and officers’ liability insurance policy throughout 2019.
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 68, Liquidity and capital resources on page 301
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
Indications of our activities in the field of research and development
are provided throughout the Strategic report and the Directors’ report
including examples on pages 15 (technology and innovation), 16
(creating low carbon businesses), 28 and 65 (venturing), 31
(modernizing the group) and 57 (BP Infinia). See also page 180 for our
expenditure on research and development.
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.
BP Annual Report and Form 20-F 2019
«See Glossary
323
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 2-3), the Chief executive officer’s letter
(pages 4-5), the Strategic report (inside cover and pages 1-71),
Additional disclosures (pages 297-325) and Shareholder information
(pages 327-336), including but not limited to statements under the
headings ‘Our ambition for the energy transition’, ‘Our business
model’, ‘Our strategy’ and ‘Measuring our progress’ and including but
not limited to statements regarding: the coronavirus pandemic
(COVID19), its impact, consequences and challenges and how BP is
prepared for and responding to this; plans and expectations relating
to organic capital expenditure, maintaining a strong financial frame,
deleveraging our balance sheet, working capital and operating cash
flows, capital discipline, growth in sustainable free cash flow and
shareholder distributions and future dividend payments; BP's new
ambition to be a net zero company by 2050 or sooner and help the
world get to net zero, including its aims regarding emissions across
operations, the carbon content of its oil and gas production; a 50%
cut in the carbon intensity of products BP sells, methane
measurement at major oil and gas processing sites by 2023 and
subsequent reduction of methane intensity of operations, and aims to
increase the proportion of investment into non-oil and gas businesses
over time; aims to help the world get to net zero; plans for
incentivising BP's global workforce; plans for a wide-ranging
restructuring of the business; the aim to build a more agile, innovative
and efficient BP; continuing commitment to safe and reliable
operations; commitment to continuing to perform as BP transforms;
continuing commitment to the investor proposition and commitment
to transparency and advocacy for a low carbon world; plans and
expectations regarding the new leadership structure, including timing
of its implementation and areas of focus; plans to focus on
developing a new corporate governance framework; plans and
expectations regarding our relationships with trade associations;
plans to advance a low-carbon future through the reduce, improve,
create framework; plans and expectations regarding BP’s level of
investment in energy sources and technologies other than oil and gas
resources and reserves; expectations regarding world energy
demand, including the growth in relative demand for renewables, oil
and gas, and the proportional growth of renewables; expectations
regarding scenarios that are consistent with the Paris goals;
expectations with respect to the world energy mix, production,
consumption and emissions to 2040; plans and expectations
regarding BP’s portfolio, including to maintain a focused portfolio, to
manage the portfolio through disciplined investment to support
growing returns and to focus on highest-quality barrels; 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 regard to the supply and trading function, the fuels,
lubricants and the petrochemicals businesses; plans and expectations
with regard to new technologies, including their efficiency and impact
on production; plans and expectations regarding the retail business,
including BP Chargemaster, and to roll-out electric vehicle charging
networks in China, Germany and the UK; plans to develop a number
of digital platforms to connect consumers with local, low carbon
electricity and to enhance productivity through digital solutions; plans
and expectations regarding BP’s role in OGCI’s Net Zero Teesside
project; plans and expectations regarding BP’s advancing low carbon
accreditation programme; plans and expectations with respect to the
commercial optimization programme; plans and expectations
regarding BPX Energy, including for it to achieve $400 million of
annual synergies by 2021; plans and expectations with respect to the
Alternative Energy portfolio, including for Lightsource BP to have
10GW of developed assets by the end of 2023, Grid Edge’s impact on
energy use and carbon emissions of buildings and expectations for
Brazil’s ethanol demand to increase up to 55% by 2030; plans and
expectations regarding BP Launchpad, including to quickly create
multiple businesses valued over $1 billion; plans and expectations
regarding BP Ventures, including to grow advanced mobility, power
and storage, carbon management, bio and low carbon products and
its investment in Finite Resources; plans and expectations regarding
the Other business and corporate annual charge and underlying
quarterly charge in 2020; plans and expectations relating to
divestments and disposals, including expectations that BP will meet
its target of $10 billion of divestment proceeds by the end of 2020
and a further $5 billion of agreed disposals by mid-2021; expectations
with respect to completion and the timing of receipt of proceeds of
agreed divestments and disposals including the sale of BP’s Alaska
operations to Hilcorp Energy and the sale of BP’s interests in the
Andrew Area and Shearwater to Premier Oil; 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, for divestment proceeds to be
primarily focused on reducing gearing and for gearing to increase in
the short-term and subsequently reduce in line with divestment
proceeds; expectations regarding oil prices, including for prices to be
challenging in 2020; expectations for return on average capital
employed to improve to over 10% by 2021; plans with regard to BP’s
exploration budget; expectations regarding depreciation, depletion
and amortization charges; expectations regarding the effective tax
rate in 2020; plans to produce 900,000boe/d from new projects by
2021 and expectations regarding operating cash margins of this
production; plans to start up four projects in 2020; plans and
expectations for the Raven project to come onstream at the end of
2020; plans and expectations with respect to a joint venture with
ZPCC to build an acetic acid plant; plans and expectations regarding
investment, development, and production levels and the timing
thereof with respect to projects and partnerships in Angola, Australia,
Azerbaijan, Brazil, Egypt, the Gambia, India, Indonesia, Mexico,
Russia, São Tomé and Príncipe, Turkey, 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 relationships with governments, customers,
partners, suppliers, communities and key stakeholders, including
working with the Washington state legislature to advance a new
carbon bill; plans and expectations with respect to BP’s public
reporting of ambitions, plans, progress and reporting structure; plans
and expectations regarding the effectiveness of the group’s foreign
currency exchange risk management; plans and expectations
regarding plant reliability and base decline, including for base decline
to remain between 3-5%; plans and expectations regarding business
models in sustainable chemicals and plastics, including with respect
to BP Infinia technology and to build a $25-million pilot plant to prove
the technology; plans and expectations regarding the Tangguh gas
facility; expectations regarding refining margins, North American
heavy crude oil discounts and refining turnarounds; plans to
undertake joint exploration and development with Rosneft, including
to create a joint venture investment fund; expectations regarding
pensions and other post-retirement benefits, including contributions;
expectations regarding payments under contractual obligations and
sales commitments; plans and expectations regarding BP’s
workforce, including the aim to attract, develop and retain the best
talent, to create a diverse inclusive working environment and an open
culture and to ensure equal opportunity in recruitment; policies and
goals related to risk management plans; aim to help countries around
the world grow their domestic energy supplies and boost energy
security; plans and projections regarding oil and gas reserves,
including the turnover time of proved undeveloped reserves to proved
developed reserves and volume of turnover; expectations regarding
the costs of environmental restoration programmes; expectations
regarding contingent liabilities and their impact on BP; expectations
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BP Annual Report and Form 20-F 2019
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 and potential impact of
such proceedings and BP’s intentions in respect thereof; and (ii)
certain statements in Corporate governance (pages 72-99) and the
Directors’ remuneration report (pages 100-127) 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
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; public health situations (including an
outbreak of an epidemic or pandemic); wars and acts of terrorism;
cyberattacks or sabotage; and other factors discussed elsewhere in
this report including under Risk factors (pages 70-71). 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.
BP Annual Report and Form 20-F 2019
«See Glossary
325
THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY
326
«See Glossary
BP Annual Report and Form 20-F 2019
Shareholder
information
Share prices and listings
Shareholder taxation information
328
328 Dividends
328
330 Major shareholders
331 Annual general meeting
331 Memorandum and Articles of Association
334
Purchases of equity securities by the issuer and
affiliated purchasers
Fees and charges payable by ADS holders
Fees and payments made by the Depositary to the
issuer
335
335
335 Documents on display
336
336
Shareholding administration
2020 Shareholder calendar
BP Annual Report and Form 20-F 2019
327
Share prices and listings
Markets and market prices
The primary market for the company’s ordinary shares (trading symbol
'BP.'), 8% cumulative first preference shares (trading symbol 'BP.A')
and 9% cumulative second preference shares (trading symbol 'BP.B')
is the London Stock Exchange (LSE). The company’s ordinary shares
are a constituent element of the Financial Times Stock Exchange 100
Index.
In the US, the company’s securities are listed and 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 evidenced by American
depositary receipts (ADRs), which may be issued in either certificated
or book entry form.
The company's ordinary shares are also traded in the form of a global
depositary certificate representing the company's ordinary shares on
the Frankfurt, Hamburg and Dusseldorf Stock Exchanges.
On 27 February 2020, 916,049,377 ADSs (equivalent to approximately
5,496,296,262 ordinary shares or some 27.15% of the total issued
share capital, excluding shares held in treasury) were outstanding and
were held by approximately 77,424 ADS holders. Of these, about
76,535 had registered addresses in the US at that date. One of the
registered holders of ADSs represents some 1,237,693 underlying
holders.
On 27 February 2020 there were approximately 229,193 ordinary
shareholders. Of these shareholders, around 1,535 had registered
addresses in the US and held a total of some 4,094,154 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
The company’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 the
company's ordinary shares will be paid in sterling and on the
company's 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 enabled the company's ordinary shareholders and ADS
holders to elect to receive dividends by way of new fully paid 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.
The company announced on 29 October 2019 and 4 February 2020
that the board had suspended the Scrip Programme in respect of the
third quarter 2019 and fourth quarter 2019 dividends. Ordinary
shareholders and ADS holders (subject to certain exceptions) may be
able to participate in dividend reinvestment plans. Any decisions with
respect to future dividends will be made by the board of BP p.l.c.
following the end of each quarter.
Future dividends will be dependent on future earnings, the financial
condition of the group, the Risk factors set out on page 70 and other
matters that may affect the business of the group set out in Our
strategy on page 16 and in Liquidity and capital resources on page
301.
The following table shows dividends announced and paid by the
company per ADS for the past five years.
Dividends per ADSa
2017
2015
2016
UK pence
US cents
UK pence
US cents
UK pence
US cents
UK pence
US cents
2019 UK pence
US cents
2018
March
40.00
60
42.08
60
48.95
60
43.01
60
46.43
61.50
June September December
Total
39.18
60
41.50
60
46.54
60
44.66
60
48.39
61.50
39.29
60
45.35
60
45.73
60
47.58
61.50
50.09
61.50
39.81
60
47.59
60
44.66
60
48.15
61.50
46.95
61.50
158.28
240
176.52
240
185.88
240
183.40
243
191.86
246
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.
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
328
«See Glossary
BP Annual Report and Form 20-F 2019
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.
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 £37,500 (for
BP Annual Report and Form 20-F 2019
«See Glossary
329
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 2019
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
52,926
77,165
88,204
10,640
928
693
230,556
22.96
33.47
38.26
4.61
0.40
0.30
100.00
0.01
0.21
1.37
1.10
1.68
95.63
100.00
a Includes JPMorgan Chase Bank, N.A. holding 27.04% 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.
2019/20), 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 2019/20, this has
been set at £12,000. 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
Until the publication of the 2019 third quarter results, the company
had an optional Scrip Programme, wherein holders of BP ordinary
shares or ADSs could 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
330
«See Glossary
BP Annual Report and Form 20-F 2019
Register of holders of American depositary shares (ADSs) as at
31 December 2019a
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
46,802
20,337
10,654
466
7
1
78,267
59.80
25.98
13.61
0.60
0.01
0.00
100.00
0.27
1.05
3.00
0.84
0.14
94.70
100.00
a One ADS represents six 25 cent ordinary shares.
b One holder of ADSs represents 1,231,543 underlying shareholders.
As at 31 December 2019 there were also 1,236 preference
shareholders. Preference shareholders represented 0.41% and
ordinary shareholders represented 99.59% of the total issued
nominal share capital of the company (excluding shares held in
treasury) as at that date.
As at 31 December 2019, we had been notified pursuant to DTR5
that BlackRock, Inc. held 7.37% of the voting rights attached to the
issued share capital of the company.
The company did not receive any notifications pursuant to DTR5
between 1 January 2020 and 27 February 2020.
Under the US Securities Exchange Act of 1934 BP is aware of the
following interests as at 27 February 2020:
Holder
JPMorgan Chase Bank N.A.,
depositary for ADSs, through
its nominee Guaranty
Nominees Limited
BlackRock, Inc.
The Vanguard Group, Inc
Holding of
ordinary shares
Percentage of
ordinary share capital
excluding shares held
in treasury
5,496,296,263
1,531,724,983
813,197,253
27.13
7.60
4.00
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 27 February 2020:
Holder
The National Farmers Union Mutual
Insurance Society Limited
Hargreaves Lansdown Asset
Management Limited
Canaccord Genuity Group Inc.
M&G Investment Management Ltd.
Interactive Investor Share Dealing
Services
A J Bell Securities Limited
Holder
The National Farmers Union Mutual
Insurance Society Limited
M&G Investment Management Ltd.
Safra Group
Canaccord Genuity Group Inc.
Barclays PLC
Holding of 8%
cumulative first
preference shares
Percentage
of class
945,000
13.10
644,225
544,163
528,150
513,068
390,807
8.90
7.50
7.30
7.10
5.40
Holding of 9%
cumulative second
preference shares
Percentage
of class
987,000
644,450
385,000
273,135
271,080
18.00
11.80
7.00
5.00
5.00
As at 27 February 2020, 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 2020 AGM will be held on Wednesday 27 May 2020 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 2020.
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 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.
• 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.
BP Annual Report and Form 20-F 2019
«See Glossary
331
• Any proposal concerning the purchase or maintenance of any
insurance policy under which the director may benefit.
the sale may be made at such time and on such terms as the
directors may decide.
• 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 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.
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.
332
«See Glossary
BP Annual Report and Form 20-F 2019
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.
Called-up share capital
Details of the allotted, called-up and fully-paid share capital at
31 December 2019 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 2019, 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 2019. These authorities
were given for the period until the next AGM in 2020 or 21 August
2020, 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.
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
BP Annual Report and Form 20-F 2019
«See Glossary
333
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 company to make market purchases (as defined in section 693(4) of the Companies Act 2006) of ordinary
shares with a nominal value of $0.25 each in the company was renewed at the company’s 2019 AGM covering the period until the date of the
company's 2020 AGM or 21 August 2020, whichever is earlier. The maximum number of ordinary shares to be purchased under this authority
will not exceed 2,025,988,313 ordinary shares. 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.
2019
January
February 5 – February 21
March 11 – March 29
April 30
May 8 – May 31
June 3 – June 25
July
August 5 – August 29
September 2 – September 24
October 7 - October 31
November 1 – November 29
December 2 - December 19
2020
January 7 - January 28
February (to February 26)
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
2,753,983
4,260,056
120,000
5,012,700
5,763,677
Nil
18,852,607
16,867,892
103,926,413
55,589,904
23,921,618
120,057,464
Nil
7.10
7.29
7.32
6.97
6.96
6.11
6.24
6.33
6.53
6.25
6.47
120,000
Nil
120,000
Nil
Nil
Nil
878,000
Nil
Nil
Nil
2,633,983
4,260,056
Nil
5,012,700
5,763,677
18,852,607
15,989,892
103,926,413
55,589,904
23,921,618
Nil
120,057,464
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 2019, authorization was given to the company to repurchase up to 2,025,988,313 ordinary shares, for the period ending on the date of the AGM in 2020 or 21 August 2020,
whichever is the earlier. This authorization is renewed annually at the AGM. The total number of ordinary shares repurchased during 2019 under the programme was 235,950,850 at a cost of
$1,511 million (including fees and stamp duty) representing 1.16% of the company’s issued share capital excluding shares held in treasury on 31 December 2019. All ordinary shares
repurchased in 2019 under the programme were cancelled in order to reduce the company’s issued share capital.
334
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BP Annual Report and Form 20-F 2019
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, sell or
reinvest dividends into further 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. Dividend
reinvestment is 5% of the dividend amount up
to a maximum of $5.00. Purchase trading
commission is $0.12 per share.
Documents on display
BP Annual Report and Form 20-F 2019 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) 800 037 2172 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 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 321) 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 2019. The Depositary reimbursed to the
company, or paid amounts on the company’s behalf to third parties, or
waived its fees and expenses, of $15,923,592.90 for the year ended
31 December 2019.
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 2019.
Category of expense reimbursed,
waived or paid directly to third parties
Fees for delivery and surrender of BP
ADSs
Dividend feesa
Total
Amount reimbursed, waived or
paid directly to third parties for the
year ended 31 December 2019
$
169,235.12
15,754,357.78
15,923,592.90
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 2019
«See Glossary
335
Shareholding administration
If you have any queries about the administration of shareholdings,
such as change of address, change of ownership, dividend payment
options 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
ADS holders
BP Shareowner Services
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
2020 shareholder calendara
27 Mar 2020
Fourth quarter interim dividend payment for 2019
28 April 2020 First quarter results announced
11 May 2020 Record date (to be eligible for the first quarter
interim dividend)
27 May 2020 Annual general meeting
19 Jun 2020
First quarter interim dividend payment for 2020
3 Jul 2020
8% and 9% preference shares record date
28 Jul 2020
Second quarter results announced
31 Jul 2020
8% and 9% preference shares dividend payment
7 Aug 2020
18 Sep 2020
Record date (to be eligible for the second quarter
interim dividend)
Second quarter interim dividend payment for 2020
27 Oct 2020
Third quarter results announced
6 Nov 2020
Record date (to be eligible for the third quarter
interim dividend)
18 Dec 2020
Third quarter interim dividend payment for 2020
a All future dates are provisional and may be subject to change. For the full calendar see
bp.com/financialcalendar.
336
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BP Annual Report and Form 20-F 2019
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.
FPSO
Floating production, storage and offloading.
GAAP
Generally accepted accounting practice.
Gas
Natural gas.
gCO2e/MJ
Grams of carbon dioxide equivalent per megajoule of energy.
GHG
Greenhouse gas.
GRI
Global Reporting Initiative.
GtCO2
Gigatonnes of carbon dioxide.
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.
CA100+ resolution glossary
CA100+ resolution
The CA100+ resolution means the special resolution requisitioned by
Climate Action 100+ and passed at BP’s 2019 Annual General
Meeting, the text of which is set out below.
Special resolution: Climate Action 100+ shareholder resolution on
climate change disclosures.
That in order to promote the long term success of the company,
given the recognised risks and opportunities associated with climate
change, we as shareholders direct the company to include in its
strategic report and/or other corporate reports, as appropriate, for the
year ending 2019 onwards, a description of its strategy which the
board considers, in good faith, to be consistent with the goals of
Articles 2.1(a)(1) and 4.1(2) of the Paris Agreement(3) (the ‘Paris
goals’), as well as:
(1) Capital expenditure: how the company evaluates the consistency
of each new material capex investment, including in the
exploration, acquisition or development of oil and gas resources
and reserves and other energy sources and technologies, with (a)
the Paris goals and separately (b) a range of other outcomes
relevant to its strategy.
(2) Metrics and targets: the company’s principal metrics and relevant
targets or goals over the short, medium and/or long-term,
consistent with the Paris goals, together with disclosure of:
a. The anticipated levels of investment in (i) oil and gas resources
and reserves; and (ii) other energy sources and technologies.
b. The company’s targets to promote reductions in its operational
greenhouse gas emissions, to be reviewed in line with
changing protocols and other relevant factors
c. The estimated carbon intensity of the company’s energy
products and progress on carbon intensity over time.
d. Any linkage between the above targets and executive
remuneration.
(3) Progress reporting: an annual review of progress against (1) and
(2) above.
Such disclosure and reporting to include the criteria and summaries
of the methodology and core assumptions used, and to omit
commercially confidential or competitively sensitive information and
be prepared at reasonable cost; and provided that nothing in this
resolution shall limit the company’s powers to set and vary its
strategy, or associated targets or metrics, or to take any action which
BP Annual Report and Form 20-F 2019
337
it believes in good faith, would best promote the long-term success
of the company.
qualifying activities such as sinks under our methodology at the
applicable time.
The Paris goals
(1) Article 2.1(a) of the Paris Agreement states the goal of ‘Holding
the increase in the global average temperature to well below 2°C
above pre-industrial levels and pursuing efforts to limit the
temperature increase to 1.5°C above pre-industrial levels,
recognizing that this would significantly reduce the risks and
impacts of climate change’.
Emissions from the carbon in our Upstream oil and gas
production
Estimated CO2 emissions from the combustion of upstream
production of crude oil, natural gas and natural gas liquids (NGLs) on a
BP equity-share basis based on BP’s net share of production,
excluding BP’s share of Rosneft production and assuming that all
produced volumes undergo full stoichiometric combustion to CO2.
(2) Article 4.1 of the Paris Agreement: In order to achieve the long-
term temperature goal set out in Article 2, parties aim to reach
global peaking of greenhouse gas emissions as soon as possible,
recognizing that peaking will take longer for developing country
parties, and to undertake rapid reductions thereafter in
accordance with best available science, so as to achieve a
balance between anthropogenic emissions by sources and
removals by sinks of greenhouse gases in the second half of this
century, on the basis of equity, and in the context of sustainable
development and efforts to eradicate poverty.
(3) U.N. Framework Convention on Climate Change Conference of
Parties, Twenty-First Session, Adoption of the Paris Agreement,
U.N. Doc. FCCC/CP/2015/L.9/Rev.1 (Dec. 12, 2015).
New material capex investment
For the purposes of the 2019 evaluation discussed on pages 19-22,
‘new material capex investment’ means a decision taken by the
resource commitment meeting (RCM) in 2019 to incur inorganic or
organic investments greater than $250 million that relate to a new
project or asset, extending an existing project or asset, or acquiring or
increasing a share in a project, asset or entity.
There were eight investments that met the above criteria in 2019.
Material capex evaluation: Paris-consistency quantitative tests.
For the purposes of evaluating material capex investments for
consistency with the Paris goals, two quantitative tests were applied,
see page 22.
1. Operational carbon intensity (CI)
The annual average operational GHG emissions (TeCO2e/unit),
divided by the relevant unit of output:
• per thousand barrels of oil equivalent in Upstream
• per utilized equivalent distillation capacity in refining
• per thousand tonnes in petrochemicals.
2. Profitability index (PI)
Operating cash flow divided by investment required (both on a
present value basis).
‘Investment required’ means economic resources including capital
investment, decommissioning expenditure and the value of any
credit support to third parties (e.g. partner carry).
Average emissions intensity of marketed energy products
The weighted average GHG emissions per unit of energy delivered
grams CO2e/MJ, estimated in respect of marketing sales of energy
products. GHG emissions are estimated on a lifecycle basis covering
production, distribution and use of the relevant products, assuming
full stoichiometric combustion to CO2.
Net zero aims and ambition glossary
Net zero
References to global net zero in the phrase, 'to help the world get to
net zero', means achieving '...a balance between anthropogenic
emissions by sources and removals by sinks of greenhouse
gases...on the basis of equity, and in the context of sustainable
development and efforts to eradicate poverty', as set out in Article 4
(1) of the Paris Agreement.
References to net zero for BP in the context of our ambition and Aims
1 and 2 as set out on page 7 (such as 'be a net zero company by 2050
or sooner'), means achieving a balance between (a) the relevant
Scope 1 and 2 emissions (for our Aim 1), or Scope 3 emissions (for
our Aim 2), and (b) the aggregate of applicable deductions from
Adjusted 2015 baseline
In accordance with our zero net growth methodology, the starting
direct and indirect GHG emissions baseline (end of 2015) is adjusted
at the end of each reporting year for any qualifying changes (being
changes due to (a) acquisitions, divestments, outsourcing or
insourcing where the total for the year is greater than 5% the total
direct and indirect GHG emissions in the previous year or (b)
methodology or protocol changes).
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 344.
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
50 and in Downstream on page 56. 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.
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BP Annual Report and Form 20-F 2019
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 344.
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.
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
BP Annual Report and Form 20-F 2019
339
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.
Finance debt ratio
Finance debt ratio is defined as the ratio of finance debt to the total of
finance debt plus total equity.
Free cash flow
Operating cash flow less net cash used in investing activities and
lease liability payments included in financing activities, as presented
in the group cash flow statement.
Gearing and net debt
Non-GAAP measures. Net debt is calculated as 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.
Gearing is defined as the ratio of net debt to the total of net debt plus
total equity. BP believes these measures provide useful information
to investors. Net debt enables investors to see the economic effect of
finance debt, related hedges and cash and cash equivalents in total.
Gearing enables investors to see how significant net debt is relative
to total equity. The derivatives are reported on the balance sheet
within the headings ‘Derivative financial instruments’. See Financial
statements – Note 27 for information on finance 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 gearing to finance 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.
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. Further information and a reconciliation
to GAAP information is provided on page 299.
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 including leases
Non-GAAP measure. Net debt including leases is calculated as net
debt plus lease liabilities, less the net amount of partner receivables
and payables relating to leases entered into on behalf of joint
operations. BP believes this measure provides useful information to
investors as it enables investors to understand the impact of the
group’s lease portfolio on net debt. See Financial statements – Note
27 for information on finance debt, which is the nearest equivalent
measure to net debt on an IFRS basis.
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.
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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 300.
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 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
299.
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 / contract (PSA / PSC)
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 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 346.
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 for BP-
operated refineries, 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
BP Annual Report and Form 20-F 2019
341
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 298.
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.
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
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 344.
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 2015, 2016 and 2017
interest expense was net of notional tax at an assumed 35%), divided
by average capital employed (total equity plus finance debt), excluding
cash and cash equivalents and goodwill. Interest expense is finance
costs excluding lease interest and 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 345.
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 and tier 2 process safety events
Tier 1 events are losses of primary containment from a process of
greatest consequence – causing harm to a member of the workforce,
damage to equipment from a fire or explosion, a community impact
or exceeding defined quantities. Tier 2 events are those of lesser
consequence. These represent 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
Underlying effective tax rate (ETR)
Non-GAAP measure. The underlying ETR is calculated by dividing
taxation on an underlying replacement cost (RC) basis 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 underlying 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 344.
We are unable to present reconciliations of forward-looking
information for underlying 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.
Underlying production
Production after adjusting for acquisitions and divestments and
entitlement impacts in our production-sharing agreements (PSAs).
2019 underlying production, when compared with 2018, is production
after adjusting for BPX Energy, other acquisitions and divestments,
and entitlement impacts in our PSAs.
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 300 and
344 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 chief executive
officer’s letter on page 4 refers to full year underlying RC profit for the
group. A reconciliation to GAAP information is provided on page 298.
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 344.
342
BP Annual Report and Form 20-F 2019
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: Aral, ARCO, BP, BP Infinia, BPme, BPme Rewards, Castrol
Trade marks:
Butamax – a registered trade mark of Butamax Advance Biofuels LLC.
Fulcrum BioEnergy – registered trade marks of Fulcrum BioEnergy,
Inc.
M&S Simply Food – a registered trade mark of Marks & Spencer plc.
REWE to Go – a registered trade mark of REWE.
BP Annual Report and Form 20-F 2019
343
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 339.
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)
2019
2018
$ million
2017
(455)
706
2
253
(56)
160
104
(179)
885
706
148
12
160
866
(155)
711
(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)
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.
b Fair value accounting effects arise solely in the fuels business.
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.
2019
19.84
(3.29)
0.77
17.32
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)
40.73
16.93
18.94
35.99
82.23
(8.81)
49.24
(3.23)
63.70
(1.65)
31.31
(16.87)
13.79
(21.83)
32.22
344
«See Glossary
BP Annual Report and Form 20-F 2019
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
Finance debt
Capital employed (2019 average $167,556 million)
Less: Goodwill
Cash and cash equivalents
Average capital employed excluding goodwill and cash and cash
equivalents
ROACE
2019
(3,964)
(156)
(3,808)
1,788
—
—
2018
(7,145)
198
(7,343)
522
121
—
2017
(3,712)
(225)
(3,487)
1,184
(859)
—
(5,596)
(7,986)
(3,812)
2019
49
2
51
(15)
—
—
36
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
$ million
2015
3,171
569
2,602
4,000
—
915
(2,313)
%
2015
33
1
34
(15)
—
12
31
2019
4,026
(511)
6,475
9,990
1,744
164
11,898
100,708
67,724
168,432
11,868
22,472
134,092
2018
9,383
603
2,737
12,723
1,583
195
14,501
101,548
65,132
166,680
12,204
22,468
132,008
2017
2016
3,389
(628)
3,405
6,166
924
79
7,169
100,404
62,574
162,978
11,551
25,586
125,841
115
(1,114)
3,584
2,585
635
57
3,277
96,843
57,665
154,508
11,194
23,484
119,830
$ million
2015
(6,482)
1,320
11,067
5,905
576
82
6,563
98,387
52,465
150,852
11,627
26,389
112,836
133,050
128,925
123,481
117,002
118,702
8.9%
11.2 %
5.8%
2.8%
5.5%
a Calculated on a post-tax basis (for 2017 and earlier interest expense was net of notional tax at an assumed 35%).
BP Annual Report and Form 20-F 2019
«See Glossary
345
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 341.
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
2019
6,837
3,217
2019
$ million
2018
4,202
1,641
$ million
2018
20,880
17,988
(14,280)
(14,066)
6,600
237
6,837
(3,620)
3,217
3,922
280
4,202
(2,561)
1,641
The Directors’ report on pages 72-99, 101 (in respect of the remuneration committee report shown in green only), 128-130, 232-259 and
297-346 was approved by the board and signed on its behalf by Ben J. S. Mathews, company secretary on 18 March 2020.
BP p.l.c.
Registered in England and Wales No. 102498
346
«See Glossary
BP Annual Report and Form 20-F 2019
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/ Ben J. S. Mathews
Company secretary
18 March 2020
BP Annual Report and Form 20-F 2019
347
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
298, 328
n/a
n/a
70-71
23, 36-38, 50-65, 174-176, 181, 187, 189-191, 303-306, 331
8-9, 13, 36-38, 50-65, 177-180, 303-306, 314-319, 325
33, 55, 58, 186, 257-259, 301-313, 323
None
222
36-38, 50-65, 70, 180, 189-191, 200, 202-214, 314-320
156, 187, 200-207, 301-302
180, 323
36-38, 50-65
177-179, 189-191, 301
301
324-325
74-81
32-35, 101-127, 194-199, 220-221
74-77, 88-95, 100, 114
47, 221
47, 113, 194-199, 220-220
330-331
189, 321
n/a
Consolidated statements and other financial information
146-149, 152, 154-156, 157-259, 319-320, 328
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
328
n/a
328
n/a
n/a
n/a
n/a
331-333
321
328
328-330
n/a
n/a
335
n/a
202-207
n/a
n/a
n/a
335
None
None
150, 322
77, 86, 91
322
93, 221, 322
n/a
334
n/a
321
n/a
152-156
349
348
BP Annual Report and Form 20-F 2019
Information about this report
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 2019. A cross reference to
Form 20-F requirements is included on page 348.
This document contains the Strategic report on the inside front cover
and pages 1-71 and the Directors’ report on pages 72-99, 101 (in part
only), 128-130, 232-259 and 297-346. 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 100-127. The consolidated financial statements of the group are
on pages 131-231 and the corresponding reports of the auditor are on
pages 132-151. The parent company financial statements of BP p.l.c.
are on pages 260-296.
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 35, 36 and 37 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 2019 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 2019, forms any
part of this document. References in this document to other
documents on the BP website, such as BP Energy Outlook, BP
Sustainability Report, BP Statistical Review of World Energy and BP
Technology Outlook are included as an aid to their location and are
not incorporated by reference into this document.
BP p.l.c. is the parent company of the BP group of companies. The
company was incorporated in 1909 in England and Wales and
changed its name to BP p.l.c. in 2001. Where we refer to the
company, we mean BP p.l.c. The company and each of its
subsidiaries« are separate legal entities. Unless otherwise stated or
the context otherwise requires, the term “BP” and terms such as
“we”, “us” and “our” are used in this report for convenience to refer
to one or more of the members of the BP group instead of identifying
a particular entity or entities. 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.
The company’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 328 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 the company's shares, in the form of ADSs, are
listed on the NYSE, an Annual Report on Form 20-F is filed with the
SEC. Ordinary shares are ordinary fully paid shares in BP p.l.c. of 25
cents each. Preference shares are cumulative first preference shares
and cumulative second preference shares in BP p.l.c. of £1 each.
Registered office and
our worldwide headquarters:
BP p.l.c.
1 St James’s Square
London SW1Y 4PD
UK
Tel +44 (0)20 7496 4000
Our agent in the US:
BP America Inc.
501 Westlake Park Boulevard
Houston, Texas 77079
US
Tel +1 281 366 2000
Registered in England and Wales No. 102498.
London Stock Exchange symbol ‘BP.’
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 2
Exhibit 4.1
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
Exhibit 101
Memorandum and Articles of Association
of BP p.l.c.*******†
Description of rights of each class of
securities registered under Section 12 of
the Securities Exchange Act of 1934†
The BP Executive Directors’ Incentive
Plan******†
Director’s Service Agreement for B
Looney†
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†
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.
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BP Annual Report and Form 20-F 2019
«See Glossary
349
BP’s corporate reporting suite includes
information about our financial and operating
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also on global energy trends and projections.
Annual Report
and Form 20-F 2019
Details of our financial
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in print and online.
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Report 2019
Details of our sustainability
performance with additional
information online.
bp.com/annualreport
bp.com/sustainability
BP Energy Outlook
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and factors that could
affect them out to 2040.
bp.com/energyoutlook
Statistical Review
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An objective review of
key global energy trends.
bp.com/statisticalreview
Financial and Operating
Information 2015-2019
How technology could
influence the way we meet
the energy challenge into
the future.
bp.com/financialandoperating
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