TIDMBP.
RNS Number : 2598D
BP PLC
27 October 2020
FOR IMMEDIATE RELEASE
London 27 October 2020
BP p.l.c. Group results
Third quarter and nine months 2020
==================================
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Highlights Performance improving despite difficult environment
Financial results and progress
- Underlying replacement cost profit for the quarter was $0.1
billion, compared with a loss of $6.7 billion for the second
quarter of 2020 and $2.3 billion profit for the third quarter of
2019. Compared to the previous quarter, the result benefitted from
the absence of significant exploration write-offs and recovering
oil and gas prices and demand. This was partly offset by a
significantly lower oil trading result.
- Reported loss for the quarter was $0.5 billion, compared with
losses of $16.8 billion for the previous quarter of 2020,
reflecting absence of significant exploration write-offs and
impairment charges, and $0.7 billion for the third quarter of
2019.
- Operating cash flow for the quarter, excluding Gulf of Mexico
oil spill payments, was resilient at $5.3 billion, including $0.9
billion working capital release (after adjusting for net inventory
holding gains). Gulf of Mexico oil spill payments in the quarter
were $0.1 billion post-tax.
- Organic capital expenditure in the first three quarters of
2020 was $9.1 billion, in line with the full-year target of around
$12 billion.
- BP continues to make progress towards its target of $2.5
billion in annual cash cost savings by end-2021 compared with 2019,
with its new organization on schedule to be in place by start of
2021.
- Proceeds from divestments and other disposals in the quarter
were $0.6 billion. BP has already completed or agreed transactions
for approaching half its target of $25 billion in proceeds by 2025,
including the agreed $5 billion sale of BP's petrochemicals
business, expected to complete by year end.
- Net debt at quarter-end was $40.4 billion, down $0.5 billion.
This includes the impact of the $1.1 billion payment for the
completion of the joint venture with Reliance. Net debt is expected
to fall in the fourth quarter as proceeds from divestments are
received.
- A dividend of 5.25 cents per share was announced for the
quarter.
Performing while transforming
- BP has brought two new Upstream major projects into production
since mid-year: Atlantis Phase 3 in the US Gulf of Mexico and,
ahead of schedule, Khazzan Phase 2 (Ghazeer) in Oman.
- Operations continued to be good with refining availability of
96.2% and Upstream plant reliability of 93.0%. Upstream unit
production costs for the nine months of 2020 were 10% lower than
2019, reflecting progress on cost efficiency and strategic
divestments.
- While refining margins remained at historical lows, driven by
the extremely weak environment, BP's marketing businesses recovered
strongly in the quarter, with fuels marketing earnings growing 3%
year on year and lubricants result broadly in line with a year
earlier.
- BP agreed to enter the offshore wind sector through a
strategic partnership with Equinor to pursue offshore wind
opportunities in the US, including taking a 50% stake in two leases
off the US east coast.
- BP announced plans for a network of ultra-fast chargers in
Germany and BP Chargemaster won a contract to deliver over 1,000
charging points for Police Scotland.
- BP also announced a partnership with Microsoft under which the
two companies will co-operate to progress their sustainability
aims. As part of this, BP has agreed to supply Microsoft with
renewable energy and to extend its use of Microsoft's cloud-based
services.
See chart on pdf
Bernard Looney - chief executive officer :
Having set out our new strategy in detail, our priority is execution
and, despite a challenging environment, we are doing just that - performing
while transforming. Major projects are coming online, our consumer-facing
businesses are really delivering and we remain firmly focused on cost
and capital discipline. Importantly , net debt continues to fall. We
are firmly committed to our updated financial frame, including the dividend
- the first call on our funds.
Financial summary Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
================================================= ======= ======== ======= ======== ========
Profit (loss) for the period attributable
to BP shareholders (450) (16,848) (749) (21,663) 4,007
Inventory holding (gains) losses, net
of tax (194) (809) 398 2,734 (488)
================================================== ======= ======== ======= ======== ======
RC profit (loss) (644) (17,657) (351) (18,929) 3,519
Net (favourable) adverse impact of non-operating
items and fair value accounting effects,
net of tax 730 10,975 2,605 13,124 3,904
================================================== ======= ======== ======= ======== ======
Underlying RC profit (loss) 86 (6,682) 2,254 (5,805) 7,423
================================================== ======= ======== ======= ======== ======
RC profit (loss) per ordinary share (cents) (3.18) (87.32) (1.72) (93.63) 17.33
RC profit (loss) per ADS (dollars) (0.19) (5.24) (0.10) (5.62) 1.04
Underlying RC profit (loss) per ordinary
share (cents) 0.42 (33.05) 11.06 (28.72) 36.57
Underlying RC profit (loss) per ADS (dollars) 0.03 (1.98) 0.66 (1.72) 2.19
================================================== ======= ======== ======= ======== ======
RC profit (loss), underlying RC profit, operating cash flow
excluding Gulf of Mexico oil spill payments, working capital,
organic capital expenditure, net debt and gearing are non-GAAP
measures. These measures and inventory holding gains and losses,
non-operating items, fair value accounting effects, major project,
Upstream plant reliability. refining availability and cash balance
point are defined in the Glossary on page 32.
Top of page 2
BP p.l.c. Group results
Third quarter and nine months 2020
Murray Auchincloss - chief financial officer :
The underlying business performance in the quarter remained resilient
a nd we made substantial progress in strengthening our balance sheet.
In the quarter, net debt reduced to around $40 billion and our cash balance
point was around $42 Brent, despite weak refining margins, low gas prices
reduced product demand and the payment to Reliance. Funding the dividend
remains our first priority and we are confident in moving towards our
$35 billion net debt target, supported by value accretive divestments.
COVID-19 Update
Strengthening finances:
- BP has continued to take deliberate steps to strengthen its
finances and drive down its cash balance point.
- Organic capital expenditure is on track for the revised
full-year target of around $12 billion, announced in April. Total
for the first nine months was $9.1 billion.
- BP has continued to progress its divestment programme towards
delivery of $25 billion of proceeds by 2025. The $5 billion sale of
its petrochemicals business is expected to complete by year end. In
the quarter, BP also sold an interest in a portfolio of UK retail
properties for $0.5 billion.
- BP's headcount has reduced by a total of around 2,800 so far
during 2020, including around 300 who have already left the
organization as part of the reinvent bp programme. A further 2,100
have elected to leave under the programme, which is expected to
result in a total reduction of around 10,000 positions, the
majority by the end of this year. BP expects to incur
people-related costs associated with the reinvent programme,
including redundancy payments, of around $1.4 billion over the next
1-2 years, primarily in 2020.
- Net debt was $40.4 billion at quarter-end and is expected to
fall further in the fourth quarter as divestment proceeds are
received. BP also continues to actively manage the profile of its
debt portfolio, buying back/retiring $4.0 billion of shorter-term
debt in the quarter. At quarter end BP had around $44 billion of
liquidity, including cash and undrawn revolving credit
facilities.
- BP will continue to review these actions, and any further
actions that may be appropriate, in response to changes in
prevailing market conditions.
- BP's future financial performance, including cash flows, net
debt and gearing, will be impacted by the extent and duration of
the current market conditions and the effectiveness of the actions
that it and others take, including its financial interventions. It
is difficult to predict when current supply and demand imbalances
will be resolved and what the ultimate impact of COVID-19 will
be.
- Costs that are directly attributable to COVID-19 were around
$0.1 billion for the quarter (second quarter 2020 $0.2
billion).
Protecting our people and operations:
- BP continues to monitor the impact of COVID-19 on global
operations and to date there has been no direct significant
operational impact, although this could change through the rest of
the fourth quarter.
- Refinery utilization in the quarter was around 10% below 2019
levels, driven by COVID-19 impacts. Year-on-year, demand for retail
fuels was lower by 7% and for aviation by around 60%. However fuels
marketing earnings grew, benefitting from continued growth in
convenience sales.
- Despite the significant challenges of the environment, BP's
operations performed safely and reliably in the quarter.
BP-operated Upstream plant reliability was 93.0% and BP-operated
refining availability 96.2%.
- BP continues to take steps to protect and support its staff
through the pandemic. The great majority of BP staff who are able
to work from home are still doing so. Precautions in operations and
offices include: reduced manning levels, changing working patterns,
deploying appropriate personal protective equipment (PPE), enhanced
cleaning and social distancing measures at plants and retail sites.
Decisions on repopulating offices are being taken with caution and
in compliance with local and national guidelines and
regulations.
- BP is providing enhanced support and guidance to staff on
safety, health and hygiene, homeworking and mental health.
Outlook:
- The ongoing impacts of the COVID-19 pandemic continue to
create a volatile and challenging trading environment. There have
been some early signs of global economic recovery as countries move
to more regional or localised restrictions on movement and
governments continue to offer monetary and fiscal policy stimulus.
However, the shape and pace of the recovery is uncertain, as it
depends on the further spread of the pandemic.
- The gradual recovery in oil demand seen since the spring looks
set to continue, led by strengthening demand in Asia. The IEA
estimates an increase of around six million barrels a day in 2021,
as economies continue to open up. OPEC+ production cuts have played
a major role in stabilising the market and there is already a
reduction in crude and product inventories. Inventories are likely
to reduce through 2021, although the pace at which they normalise
will depend on the strength of economic recovery and the degree of
continued OPEC+ compliance.
- US gas supply is expected to continue on a declining trend in
2021, largely due to a drop in associated gas production.
Tightening gas balances have caused the prompt price to rise, and
the futures curve for Henry Hub now averages above $3 for 2021.
This would be expected to provide some support to pricing in Europe
and Asia until more gas comes to market.
- The refining margin outlook remains challenging, given record
high inventory levels and a levelling off in demand recovery for
gasoline and jet fuel due to COVID-19.
The commentary above and following should be read in conjunction with
the cautionary statement on page 36.
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Top of page 3
Group headlines
Results
For the nine months, underlying replacement Share buybacks
cost (RC) loss* was $5,805 million, BP repurchased 120 million ordinary
compared with a profit of $7,423 million shares at a cost of $776 million (including
in 2019. Underlying RC loss is after fees and stamp duty) in the nine months
adjusting RC loss* for a net charge of 2020, all of which was completed
for non-operating items* of $13,357 in the first quarter. In January 2020,
million and net favourable fair value the share dilution buyback programme
accounting effects* of $233 million had fully offset the impact of scrip
(both on a post-tax basis). dilution since the third quarter 2017.
RC loss was $18,929 million for the Operating cash flow*
nine months, compared with a profit Operating cash flow excluding Gulf
of $3,519 million in 2019. of Mexico oil spill payments* was
For the third quarter, underlying $5.3 billion for the third quarter
RC profit was $86 million, compared and $11.4 billion for the nine months.
with $2,254 million in 2019. Underlying These amounts include a working capital*
RC profit is after adjusting RC loss release of $0.9 billion in the third
for a net charge for non-operating quarter and a working capital build
items of $1,109 million and net favourable of $1.3 billion in the nine months,
fair value accounting effects of $379 after adjusting for net inventory
million (both on a post-tax basis). holding gains or losses* and working
RC loss was $644 million for the third capital effects of the Gulf of Mexico
quarter, compared with $351 million oil spill. The comparable amount for
in 2019. the same periods in 2019 was $6.5
Loss for the third quarter and nine billion and $20.6 billion.
months attributable to BP shareholders Operating cash flow as reported in
was $450 million and $21,663 million the group cash flow statement was
respectively, compared with a loss $5.2 billion for the third quarter
of $749 million and a profit of $4,007 and $9.9 billion for the nine months,
million for the same periods in 2019. including a working capital release
See further information on pages 4, of $0.6 billion and $0.6 billion respectively,
27 and 28. compared with $6.1 billion and $18.2
Depreciation, depletion and amortization billion for the same periods in 2019.
The charge for depreciation, depletion See page 30 and Glossary for further
and amortization was $3.5 billion information on Gulf of Mexico oil
in the quarter and $11.5 billion in spill cash flows and on working capital.
the nine months, compared with $4.3 Capital expenditure*
billion and $13.3 billion for the Organic capital expenditure* for the
same periods in 2019. BP now expects third quarter and nine months was
the 2020 full-year charge to be around $2.5 billion and $9.1 billion respectively,
15% lower than 2019. compared with $3.9 billion and $11.3
Effective tax rate billion for the same periods in 2019.
The effective tax rate (ETR) on RC Inorganic capital expenditure* for
profit or loss* for the third quarter the third quarter and nine months
and nine months was -504% and 13% was $1.1 billion and $1.5 billion
respectively, compared with 168% and respectively, compared with $0.1 billion
49% for the same periods in 2019. and $4.0 billion for the same periods
Adjusting for non-operating items in 2019.
and fair value accounting effects, BP expects total capital expenditure
the underlying ETR* for the third for 2021 to be at the lower end of
quarter and nine months was 64% and a $13-15 billion range.
-10% respectively, compared with 40% Organic capital expenditure and inorganic
and 38% for the same periods a year capital expenditure are non-GAAP measures.
ago. The higher underlying ETR for See page 26 for further information.
the third quarter reflects changes Divestment and other proceeds
in the mix of profits and losses. Divestment proceeds* were $0.1 billion
The lower underlying ETR for the nine for the third quarter and $1.5 billion
months mainly reflects the exploration for the nine months, compared with
write-offs with a limited deferred $0.7 billion and $1.4 billion for
tax benefit and the reassessment of the same periods in 2019. In addition,
deferred tax asset recognition in $0.5 billion was received in the third
the second quarter. ETR on RC profit quarter of 2020 in relation to the
or loss and underlying ETR are non-GAAP sale of an interest in BP's UK retail
measures. property portfolio.
Dividend Net debt* and gearing*
BP today announced a quarterly dividend Net debt at 30 September 2020 was
of 5.25 cents per ordinary share ($0.315 $40.4 billion, compared with $46.5
per ADS), which is expected to be billion a year ago. Gearing at 30
paid on 18 December 2020. The corresponding September 2020 was 33.0%, compared
amount in sterling will be announced with 31.7% a year ago, reflecting
on 7 December 2020. See page 24 for the reduction in equity in the period.
more information. Gearing including leases* at 30 September
2020 was 37.7%, compared with 35.9%
a year ago. Net debt, gearing and
gearing including leases are non-GAAP
measures. See pages 25 and 29 for
more information.
* For items marked with an asterisk throughout this document,
definitions are provided in the Glossary on page 32.
The commentary above contains forward-looking statements and should be
read in conjunction with the cautionary statement on page 36.
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Top of page 4
Analysis of underlying RC profit (loss)* before interest and
tax
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
================================================ ======= ======= ======= ======= =========
Underlying RC profit (loss) before interest
and tax
Upstream 878 (8,487) 2,139 (5,738) 8,480
Downstream 636 1,405 1,883 2,962 4,981
Rosneft (177) (61) 802 (255) 2,007
Other businesses and corporate (130) (260) (322) (951) (1,030)
Consolidation adjustment - UPII* 34 (46) 30 166 51
================================================= ======= ======= ======= ======= =======
Underlying RC profit (loss) before interest
and tax 1,241 (7,449) 4,532 (3,816) 14,489
Finance costs and net finance expense
relating to pensions and other post-retirement
benefits (610) (677) (754) (1,955) (2,260)
Taxation on an underlying RC basis (402) 770 (1,506) (585) (4,641)
Non-controlling interests (143) 674 (18) 551 (165)
================================================= ======= ======= ======= ======= =======
Underlying RC profit (loss) attributable
to BP shareholders 86 (6,682) 2,254 (5,805) 7,423
================================================= ======= ======= ======= ======= =======
Reconciliations of underlying RC profit or loss attributable to
BP shareholders to the nearest equivalent IFRS measure are provided
on page 1 for the group and on pages 6-11 for the segments.
Analysis of RC profit (loss)* before interest and tax and
reconciliation to profit (loss) for the period
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
================================================= ======= ======== ======= ======== =========
RC profit (loss) before interest and
tax
Upstream 30 (22,008) (1,050) (20,955) 4,303
Downstream 915 594 2,016 2,173 5,069
Rosneft (278) (124) 802 (419) 1,813
Other businesses and corporate 24 (317) (412) (991) (1,339)
Consolidation adjustment - UPII 34 (46) 30 166 51
================================================== ======= ======== ======= ======== =======
RC profit (loss) before interest and
tax 725 (21,901) 1,386 (20,026) 9,897
Finance costs and net finance expense
relating to pensions and other post-retirement
benefits (808) (791) (899) (2,389) (2,649)
Taxation on a RC basis (418) 4,361 (820) 2,935 (3,564)
Non-controlling interests (143) 674 (18) 551 (165)
================================================== ======= ======== ======= ======== =======
RC profit (loss) attributable to BP shareholders (644) (17,657) (351) (18,929) 3,519
Inventory holding gains (losses)* 233 1,088 (512) (3,563) 657
Taxation (charge) credit on inventory
holding gains and losses (39) (279) 114 829 (169)
================================================== ======= ======== ======= ======== =======
Profit (loss) for the period attributable
to BP shareholders (450) (16,848) (749) (21,663) 4,007
================================================== ======= ======== ======= ======== =======
Top of page 5
Operational updates Strategic progress
Upstream In September, BP agreed to enter into
Upstream production, which excludes a strategic partnership with Equinor
Rosneft, for the nine months of the to develop offshore wind projects
year averaged 2,448mboe/d, 6.4% lower in the US. This includes the purchase
than a year earlier. Underlying production*, of a 50% interest in two existing
for the nine months was slightly lower wind leases and associated projects
than 2019 reflecting adverse weather, off the east coast of the US. Subject
primarily in the US Gulf of Mexico. to customary regulatory and other
For the first nine months of 2020, approvals, the transaction is expected
BP-operated Upstream plant reliability* to close in early 2021.
was 93.8% and Upstream unit production BP continued to progress electrification
costs of $6.30/boe were more than in the quarter with plans announced
10% lower than in 2019 reflecting in July to build a network of ultra-fast
ongoing progress on cost efficiency charging points across Germany, including
in operations, and strategic divestments. more than 100 charging points at Aral
Since mid-year, BP has started production retail sites over the next 12 months.
on the Atlantis Phase 3 project in BP Chargemaster was recently awarded
the Gulf of Mexico, followed by the a contract by Police Scotland, to
Ghazeer gas project, the second phase deliver more than 1,000 charging points
of development on Block 61 in Oman, over the next four years.
that began production three months BP announced a strategic partnership
ahead of schedule. These are the first with Microsoft under which the two
of five Upstream major projects* expected companies will co-operate to progress
to begin production in 2020. BP also their sustainability aims. As part
brought the Galeota expansion project of this, BP has agreed to supply Microsoft
in Trinidad into operation during with renewable energy and to extend
the quarter. its use of Microsoft's cloud-based
In September, BP confirmed a gas discovery services.
with the Nidoco NW-1 exploratory well BP announced an agreement to partner
in the Abu Madi West development lease, with Aberdeen City Council to help
offshore Egypt. it achieve the goals of its Net Zero
The Trans Adriatic Gas pipeline (TAP) Vision to reduce emissions and become
has completed construction and is a climate positive city. This follows
expected to soon commence gas exports the partnership with the City of Houston
from Azerbaijan to customers in Europe. that BP announced in July.
Downstream
Fuels marketing earnings for the third Financial framework
quarter were 3% higher than in 2019, Operating cash flow excluding Gulf
benefiting from continued growth in of Mexico oil spill payments* was
store gross margin, despite COVID-driven $11.4 billion for the nine months
fuel demand impacts. of 2020, compared with $20.6 billion
BP-operated refining availability for the same period in 2019.
continued to be strong, at 96.2% in Organic capital expenditure * for
the quarter. However, refining margins the nine months of 2020 was $9.1 billion.
were extremely weak and refinery utilization BP expects 2020 organic capital expenditure
was around 10% below 2019 levels. to be around $12 billion.
Lubricants saw strong demand recovery Divestment and other proceeds were
in the third quarter, including year-on-year $2.4 billion for the nine months of
growth in key markets such as India 2020.
and China. Gulf of Mexico oil spill payments
The sale of BP's petrochemicals business on a post-tax basis were $1.5 billion
to INEOS, agreed in June, remains in the nine months of 2020. Payments
on track to complete by the end of for the full year are expected to
2020. be around $1.5 billion on a post-tax
basis.
Gearing * at 30 September 2020 was
33.0%, in part reflecting the recent
hybrid bond issue. See page 25 for
more information.
Operating metrics Nine months 2020 Financial metrics Nine months 2020
========================= ===========================
(vs. Nine months (vs. Nine months
2019) 2019)
========================= ================ =========================== ================
Tier 1 and tier 2 Underlying RC profit
process safety events 66 (loss)* $(5.8)bn
========================= ===========================
(-7) (-$13.2bn)
========================= ================ =========================== ================
Reported recordable Operating cash flow
injury frequency* excluding Gulf of
Mexico oil spill payments
0.127 (post-tax) $11.4bn
========================= ===========================
(-29.2%) (-$9.2bn)
========================= ================ =========================== ================
Group production 3,542mboe/d Organic capital expenditure $9.1bn
========================= ===========================
(-5.7%) (-$2.2bn)
========================= ================ =========================== ================
Upstream production Gulf of Mexico oil
(excludes Rosneft spill payments (post-tax)
segment) 2,448mboe/d $1.5bn
========================= ===========================
(-6.4%) (-$1.0bn)
========================= ================ =========================== ================
Upstream unit production Divestment proceeds*
costs (a) $6.30/boe $1.5bn
========================= ===========================
(-10.3%) (+$0.1bn)
========================= ================ =========================== ================
BP-operated Upstream
plant reliability 93.8% Gearing 33.0%
========================== ===========================
(-0.6) (+1.3)
================ =========================== ================
BP-operated refining Dividend per ordinary
availability* 96.0% share (b) 5.25 cents
========================= ===========================
(+1.4) (-48.8%)
================ =========================== ================
(a) Reflecting lower costs and divestment impacts.
(b) Represents dividend announced in the quarter (vs. prior year quarter).
The commentary above contains forward-looking statements and should be
read in conjunction with the cautionary statement on page 36.
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Upstream
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
================================================= ======= ======== ======= ======== ========
Profit (loss) before interest and tax 38 (21,951) (1,050) (20,958) 4,295
Inventory holding (gains) losses* (8) (57) - 3 8
================================================== ======= ======== ======= ======== ======
RC profit (loss) before interest and
tax 30 (22,008) (1,050) (20,955) 4,303
Net (favourable) adverse impact of non-operating
items* and fair value accounting effects* 848 13,521 3,189 15,217 4,177
================================================== ======= ======== ======= ======== ======
Underlying RC profit (loss) before interest
and tax*(a) 878 (8,487) 2,139 (5,738) 8,480
================================================== ======= ======== ======= ======== ======
(a) See page 7 for a reconciliation to segment RC profit before interest and tax by region.
Financial results
The replacement cost result before interest and tax for the
third quarter and nine months was a profit of $30 million and a
loss of $20,955 million respectively, compared with a loss of
$1,050 million and a profit of $4,303 million for the same periods
in 2019. The third quarter and nine months included a net
non-operating charge of $631 million and $15,156 million
respectively, compared with a net charge of $3,454 million and
$4,224 million for the same periods in 2019. The net non-operating
charge for the nine months is principally related to impairments
associated with revisions to long-term price assumptions. Fair
value accounting effects in the third quarter and nine months had
an adverse impact of $217 million and $61 million respectively,
compared with a favourable impact of $265 million and $47 million
in the same periods of 2019.
After adjusting for non-operating items and fair value
accounting effects, the underlying replacement cost result before
interest and tax for the third quarter and nine months was a profit
of $878 million and a loss of $5,738 million respectively, compared
with a profit of $2,139 million and $8,480 million for the same
periods in 2019. The result for the third quarter mainly reflects
lower liquids and gas realizations, partly offset by lower
depreciation, depletion and amortization. The result for the nine
months mainly reflects lower liquids and gas realizations and the
impact of writing down certain exploration intangible carrying
values.
Production
Production for the quarter was 2,243mboe/d, 12.7% lower than the
third quarter of 2019 mainly due to divestments in BPX Energy,
Alaska and Gulf of Suez oil concessions in Egypt. Underlying
production* for the quarter decreased by 3.0% mainly due to decline
associated with reduced capital investment levels and significant
weather impacts from hurricanes in the US Gulf of Mexico.
For the nine months, production was 2,448mboe/d, 6.4% lower than
the nine months of 2019. Underlying production for the nine months
was slightly lower than 2019 reflecting adverse weather, primarily
in the US Gulf of Mexico.
Key events
During the third quarter, BP was awarded eight operated and
three non-operated blocks in the North Sea as part of the UK Oil
& Gas Authority 32nd offshore licensing round.
On 25 August, BP confirmed it started production on Atlantis
Phase 3 in the US Gulf of Mexico (BP operator 56%, BHP Billiton
44%).
On 16 September, BP confirmed a gas discovery with the Nidoco
NW-1 exploratory well in the Abu Madi West development lease,
offshore Egypt (Eni operator 75%, BP 25%).
On 28 September, BP Trinidad and Tobago LLC started up the
Galeota expansion project in Trinidad.
On 1 October, BP confirmed force majeure was lifted on the
Greater Tortue Ahmeyim (GTA) project offshore Mauritania and
Senegal (BP operator 56%, Kosmos 27%, Petrosen 10%, SMHPM 7%).
On 6 October, BP confirmed the planned divestment to Premier Oil
of its interests in the Andrew area and Shearwater assets, both
located in the UK North Sea, will not proceed following the
announcement of a proposed merger between Chrysaor and Premier
Oil.
On 12 October, BP announced the start-up of production from
Block 61 Phase 2 Ghazeer gas field in Oman (BP operator 60%,
Makarim Gas Development Limited 30%, PC Oman Ventures Limited
10%).
Outlook
Looking ahead, we expect fourth-quarter 2020 reported production
to be slightly lower than the third quarter due to maintenance
activity.
The commentary above contains forward-looking statements and should be
read in conjunction with the cautionary statement on page 36.
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Top of page 7
Upstream (continued)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
============================================ ======= ======== ======= ======== =========
Underlying RC profit (loss) before interest
and tax
US 125 (2,960) 552 (2,296) 2,025
Non-US 753 (5,527) 1,587 (3,442) 6,455
============================================= ======= ======== ======= ======== =======
878 (8,487) 2,139 (5,738) 8,480
======= ======== ======= ======== =======
Non-operating items (a)(b)
US (114) (2,122) (3,338) (2,868) (3,814)
Non-US (517) (11,332) (116) (12,288) (410)
============================================= ======= ======== ======= ======== =======
(631) (13,454) (3,454) (15,156) (4,224)
======= ======== ======= ======== =======
Fair value accounting effects
US 57 39 19 94 (299)
Non-US (274) (106) 246 (155) 346
============================================= ======= ======== ======= ======== =======
(217) (67) 265 (61) 47
======= ======== ======= ======== =======
RC profit (loss) before interest and
tax
US 68 (5,043) (2,767) (5,070) (2,088)
Non-US (38) (16,965) 1,717 (15,885) 6,391
============================================= ======= ======== ======= ======== =======
30 (22,008) (1,050) (20,955) 4,303
======= ======== ======= ======== =======
Exploration expense
US 40 2,560 53 2,620 147
Non-US 150 7,114 132 7,446 551
============================================= ======= ======== ======= ======== =======
190 9,674 185 10,066 698
======= ======== ======= ======== =======
Of which: Exploration expenditure written
off(b) 50 9,618 115 9,766 476
============================================= ======= ======== ======= ======== =======
Production (net of royalties)(c)(d)
Liquids* (mb/d)
US 363 472 449 446 470
Europe 143 166 118 152 138
Rest of World 623 728 657 668 667
============================================= ======= ======== ======= ======== =======
1,129 1,366 1,224 1,266 1,274
======= ======== ======= ======== =======
Natural gas (mmcf/d)
US 1,419 1,549 2,396 1,671 2,372
Europe 265 298 188 269 155
Rest of World 4,774 4,878 5,211 4,915 5,254
============================================= ======= ======== ======= ======== =======
6,457 6,725 7,795 6,855 7,782
======= ======== ======= ======== =======
Total hydrocarbons* (mboe/d)
US 608 739 862 735 879
Europe 188 217 151 198 165
Rest of World 1,446 1,569 1,555 1,516 1,573
============================================= ======= ======== ======= ======== =======
2,243 2,525 2,568 2,448 2,616
======= ======== ======= ======== =======
Average realizations* (e)
Total liquids(f) ($/bbl) 38.17 22.75 55.68 35.51 58.38
Natural gas ($/mcf) 2.56 2.53 3.11 2.65 3.49
Total hydrocarbons ($/boe) 26.42 19.06 35.48 25.68 38.55
============================================= ======= ======== ======= ======== =======
(a) Second quarter and nine months 2020 principally relate to
impairments in a number of our businesses resulting from the
revisions to BP's long-term price assumptions. Nine months 2020
also includes impairment charges and loss principally related to
the disposal of our Alaska business, BPX Energy assets and oil
price impacts in the UK North Sea. Third quarter and nine months
2019 include impairment charges related to the disposal of heritage
BPX Energy assets, Alaska and GUPCO divestment. See Note 3 for
further information.
(b) Second quarter and nine months 2020 include the write-off of
$1,969 million relating to value ascribed to certain licences as
part of the accounting for the acquisition of upstream assets in
Brazil, India and the Gulf of Mexico. This has been classified
within the 'other' category of non-operating items. See Note 4 for
further information.
(c) Includes BP's share of production of equity-accounted entities in the Upstream segment.
(d) Because of rounding, some totals may not agree exactly with the sum of their component parts.
(e) Realizations are based on sales by consolidated subsidiaries
only - this excludes equity-accounted entities.
(f) Includes condensate, natural gas liquids and bitumen.
Top of page 8
Downstream
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
================================================= ======= ======= ======= ======= ========
Profit (loss) before interest and tax 1,106 1,572 1,583 (1,273) 5,775
Inventory holding (gains) losses* (191) (978) 433 3,446 (706)
================================================== ======= ======= ======= ======= ======
RC profit before interest and tax 915 594 2,016 2,173 5,069
Net (favourable) adverse impact of non-operating
items* and fair value accounting effects* (279) 811 (133) 789 (88)
================================================== ======= ======= ======= ======= ======
Underlying RC profit before interest
and tax*(a) 636 1,405 1,883 2,962 4,981
================================================== ======= ======= ======= ======= ======
(a) See page 9 for a reconciliation to segment RC profit before
interest and tax by region and by business.
Financial results
The replacement cost profit before interest and tax for the
third quarter and nine months was $915 million and $2,173 million
respectively, compared with $2,016 million and $5,069 million for
the same periods in 2019.
The third quarter and nine months include a net non-operating
charge of $146 million and $924 million respectively, compared with
a charge of $14 million and $49 million for the same periods in
2019. The charge for the quarter mainly relates to restructuring,
while the charge for the nine months primarily reflects
impairments. Fair value accounting effects in the third quarter and
nine months had a favourable impact of $425 million and $135
million respectively, compared with a favourable impact of $147
million and $137 million in the same periods in 2019.
After adjusting for non-operating items and fair value
accounting effects, the underlying replacement cost profit before
interest and tax for the third quarter and nine months was $636
million and $2,962 million respectively, compared with $1,883
million and $4,981 million for the same periods in 2019.
Replacement cost profit before interest and tax for the fuels,
lubricants and petrochemicals businesses is set out on page 9.
Fuels
The fuels business reported an underlying replacement cost
profit before interest and tax of $222 million for the third
quarter and $2,206 million for the nine months, compared with
$1,438 million and $3,691 million for the same periods in 2019.
Across fuels marketing we saw earnings growth of 3% year on year
primarily driven by increased store gross margin. This growth is
despite continued COVID-19 demand impacts with retail volumes in
the quarter 7% lower than last year. The result for the nine
months, however, remained impacted by COVID-19, with year to date
retail volumes 15% lower than 2019, and aviation volumes down by
50%.
The refining result for the quarter and nine months continued to
be impacted by an extremely weak environment with refining margins
remaining at historical lows. Utilization of 83% for the quarter
improved compared with the second quarter, albeit still around 10%
lower than 2019, driven by continued COVID-19 demand impacts. These
factors were partially offset by a lower level of turnaround
activity and strong refining availability.
The quarterly result also reflects a weaker contribution from
supply and trading, although the contribution for the nine months
remains higher year on year.
We continued to progress our advanced mobility agenda in the
quarter with plans announced in July to build a network of
ultra-fast charging across Germany, beginning with the roll out of
more than 100 charging points at Aral retail sites over the next 12
months. In addition, BP Chargemaster was recently awarded the UK's
largest ever EV infrastructure contract by Police Scotland, to
deliver more than 1,000 charging points over the next four
years.
Lubricants
The lubricants business saw significant recovery in the third
quarter as volumes improved to levels similar to 2019, supported by
growth of more than 5% in China and India. The result for the nine
months, however, continued to reflect significant COVID-19 demand
destruction seen in the first half of 2020.
Underlying replacement cost profit before interest and tax was
$326 million for the third quarter and $556 million for the nine
months, compared with $332 million and $925 million for the same
periods in 2019.
Petrochemicals
The petrochemicals business reported an underlying replacement
cost profit before interest and tax of $88 million for the third
quarter and $200 million for the nine months, compared with $113
million and $365 million for the same periods in 2019. The result
for the quarter and nine months reflects a significantly weaker
margin environment and the demand impact of COVID-19.
As previously reported, in the second quarter we announced the
sale of BP's petrochemicals business to INEOS for a total
consideration of $5 billion, subject to customary adjustments. The
transaction remains on track and, subject to approvals, is expected
to complete by the end of the year.
Outlook
Looking to the fourth quarter of 2020, we expect continued
pressure on industry refining margins and for marketing volumes to
remain impacted by COVID-19 restrictions.
The commentary above contains forward-looking statements and should be
read in conjunction with the cautionary statement on page 36.
----------------------------------------------------------------------
Top of page 9
Downstream (continued)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
============================================== ======= ======= ======= ====== ========
Underlying RC profit before interest
and tax - by region
US 96 719 537 1,372 1,634
Non-US 540 686 1,346 1,590 3,347
=============================================== ======= ======= ======= ====== ======
636 1,405 1,883 2,962 4,981
======= ======= ======= ====== ======
Non-operating items
US (27) (69) (5) (90) (2)
Non-US (119) (711) (9) (834) (47)
=============================================== ======= ======= ======= ====== ======
(146) (780) (14) (924) (49)
======= ======= ======= ====== ======
Fair value accounting effects(a)
US 78 (71) 116 152 185
Non-US 347 40 31 (17) (48)
=============================================== ======= ======= ======= ====== ======
425 (31) 147 135 137
======= ======= ======= ====== ======
RC profit before interest and tax
US 147 579 648 1,434 1,817
Non-US 768 15 1,368 739 3,252
=============================================== ======= ======= ======= ====== ======
915 594 2,016 2,173 5,069
======= ======= ======= ====== ======
Underlying RC profit before interest
and tax - by business (b)(c)
Fuels 222 1,295 1,438 2,206 3,691
Lubricants 326 63 332 556 925
Petrochemicals 88 47 113 200 365
=============================================== ======= ======= ======= ====== ======
636 1,405 1,883 2,962 4,981
======= ======= ======= ====== ======
Non-operating items and fair value accounting
effects (a)
Fuels 288 (748) 135 (717) 73
Lubricants (7) (51) - (58) 18
Petrochemicals (2) (12) (2) (14) (3)
=============================================== ======= ======= ======= ====== ======
279 (811) 133 (789) 88
======= ======= ======= ====== ======
RC profit before interest and tax (b)(c)
Fuels 510 547 1,573 1,489 3,764
Lubricants 319 12 332 498 943
Petrochemicals 86 35 111 186 362
=============================================== ======= ======= ======= ====== ======
915 594 2,016 2,173 5,069
======= ======= ======= ====== ======
BP average refining marker margin (RMM)*
($/bbl) 6.2 5.9 14.7 7.0 13.4
=============================================== ======= ======= ======= ====== ======
Refinery throughputs (mb/d)
US 701 614 781 687 730
Europe 699 716 815 750 766
Rest of World 187 157 217 189 221
=============================================== ======= ======= ======= ====== ======
1,587 1,487 1,813 1,626 1,717
======= ======= ======= ====== ======
BP-operated refining availability* (%) 96.2 95.6 96.1 96.0 94.6
=============================================== ======= ======= ======= ====== ======
Marketing sales of refined products
(mb/d)
US 1,083 872 1,172 997 1,141
Europe 849 685 1,157 830 1,081
Rest of World 422 364 459 435 500
=============================================== ======= ======= ======= ====== ======
2,354 1,921 2,788 2,262 2,722
Trading/supply sales of refined products 2,618 3,172 3,157 3,054 3,183
=============================================== ======= ======= ======= ====== ======
Total sales volumes of refined products 4,972 5,093 5,945 5,316 5,905
=============================================== ======= ======= ======= ====== ======
Petrochemicals production (kte)
US 541 410 564 1,562 1,749
Europe 1,325 1,246 1,187 3,942 3,573
Rest of World 1,211 1,271 1,325 3,635 3,780
=============================================== ======= ======= ======= ====== ======
3,077 2,927 3,076 9,139 9,102
======= ======= ======= ====== ======
(a) For Downstream, fair value accounting effects arise solely
in the fuels business. See page 28 for further information.
(b) Segment-level overhead expenses are included in the fuels business result.
(c) Results from petrochemicals at our Gelsenkirchen and Mülheim
sites in Germany are reported in the fuels business.
Top of page 10
Rosneft
Third Second Third Nine Nine
quarter quarter quarter months months
2020 2020
$ million (a) 2020 2019 (a) 2019
============================================= ======= ======= ======= ====== ========
Profit (loss) before interest and tax(b)(c) (244) (71) 723 (533) 1,772
Inventory holding (gains) losses* (34) (53) 79 114 41
============================================= ======= ======= ======= ====== ======
RC profit (loss) before interest and
tax (278) (124) 802 (419) 1,813
Net charge (credit) for non-operating
items* 101 63 - 164 194
============================================= ======= ======= ======= ====== ======
Underlying RC profit (loss) before interest
and tax* (177) (61) 802 (255) 2,007
============================================= ======= ======= ======= ====== ======
Financial results
Replacement cost (RC) loss before interest and tax for the third
quarter and nine months was $278 million and $419 million
respectively, compared with a profit of $802 million and $1,813
million for the same periods in 2019.
After adjusting for non-operating items, the underlying RC loss
before interest and tax for the third quarter and nine months was
$177 million and $255 million respectively, compared with a profit
of $802 million and $2,007 million for the same periods in
2019.
Compared with the same periods in 2019, the results for the
third quarter and nine months primarily reflects lower oil prices
and adverse foreign exchange effects and lower production as a
result of OPEC+ agreement.
Third Second Third Nine Nine
quarter quarter quarter months months
2020 2020
(a) 2020 2019 (a) 2019
======= ======= ======= ====== ========
Production (net of royalties) (BP share)
Liquids* (mb/d) 858 856 920 877 923
Natural gas (mmcf/d) 1,260 1,248 1,236 1,261 1,271
Total hydrocarbons* (mboe/d) 1,075 1,071 1,133 1,094 1,142
========================================== ======= ======= ======= ====== ======
(a) The operational and financial information of the Rosneft
segment for the third quarter and nine months is based on
preliminary operational and financial results of Rosneft for the
three months and nine months ended 30 September 2020. Actual
results may differ from these amounts. Amounts reported for the
third quarter are based on BP's 21.96% average economic interest
for the quarter (second quarter 2020 21.20%, first quarter 2020 and
2019 19.75%).
(b) The Rosneft segment result includes equity-accounted
earnings arising from BP's economic interest in Rosneft as adjusted
for accounting required under IFRS relating to BP's purchase of its
interest in Rosneft, and the amortization of the deferred gain
relating to the divestment of BP's interest in TNK-BP.
(c) BP's adjusted share of Rosneft's earnings after Rosneft's
own finance costs, taxation and non-controlling interests is
included in the BP group income statement within profit before
interest and taxation. For each year-to-date period it is
calculated by translating the amounts reported in Russian roubles
into US dollars using the average exchange rate for the year to
date.
Top of page 11
Other businesses and corporate
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
Profit (loss) before interest and tax 24 (317) (412) (991) (1,339)
Inventory holding (gains) losses* - - - - -
================================================= ======= ======= ======= ====== =======
RC profit (loss) before interest and
tax 24 (317) (412) (991) (1,339)
Net (favourable) adverse impact of non-operating
items* and fair value accounting effects* (154) 57 90 40 309
================================================== ======= ======= ======= ====== =======
Underlying RC profit (loss) before interest
and tax* (130) (260) (322) (951) (1,030)
================================================== ======= ======= ======= ====== =======
Underlying RC profit (loss) before interest
and tax
US (65) (129) (249) (318) (628)
Non-US (65) (131) (73) (633) (402)
================================================== ======= ======= ======= ====== =======
(130) (260) (322) (951) (1,030)
======= ======= ======= ====== =======
Non-operating items
US (62) (62) (85) (172) (291)
Non-US (50) 46 (5) (93) (18)
================================================== ======= ======= ======= ====== =======
(112) (16) (90) (265) (309)
======= ======= ======= ====== =======
Fair value accounting effects
US - - - - -
Non-US 266 (41) - 225 -
================================================== ======= ======= ======= ====== =======
266 (41) - 225 -
======= ======= ======= ====== =======
RC profit (loss) before interest and
tax
US (127) (191) (334) (490) (919)
Non-US 151 (126) (78) (501) (420)
================================================== ======= ======= ======= ====== =======
24 (317) (412) (991) (1,339)
======= ======= ======= ====== =======
Other businesses and corporate 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.
Financial results
The replacement cost result before interest and tax for the
third quarter and nine months was a profit of $24 million and a
loss of $991 million respectively, compared with a loss of $412
million and $1,339 million for the same periods in 2019.
The results included a net non-operating charge of $112 million
for the third quarter and $265 million for the nine months,
compared with a charge of $90 million and $309 million for the same
periods in 2019. Fair value accounting effects in the third quarter
and nine months had a favourable impact of $266 million and $225
million. See page 28 for further information.
After adjusting for non-operating items and fair value
accounting effects, the underlying replacement cost loss before
interest and tax for the third quarter and nine months was $130
million and $951 million respectively, compared with $322 million
and $1,030 million for the same periods in 2019.
Alternative Energy
BP's net ethanol-equivalent production* for the third quarter
and nine months of the year averaged 36.5kb/d and 22.1kb/d
respectively, compared with 24.4kb/d and 14.4kb/d for the 100%
BP-owned business for the same periods in 2019.
Net wind generation capacity* was 1,072MW at 30 September 2020,
compared with 926MW at 30 September 2019. BP's net share of wind
generation for the third quarter and nine months was 454GWh and
1,904GWh respectively, compared with 506GWh and 1,967GWh for the
same periods in 2019. In September BP acquired the remaining 50%
interest in the BP-operated Fowler Ridge 1 wind asset. The asset
increased net wind capacity by 150MW to 1,072MW.
In September BP and Equinor announced the formation of a new
strategic partnership to develop four assets in two existing
offshore wind leases located offshore New York and Massachusetts.
Subject to customary regulatory and other approvals, the
transaction is expected to close in early 2021 and will mark BP's
first entry into the offshore wind sector, one of the fastest
growing energy sectors.
Lightsource BP has developed 637MW for the nine months of the
year to 30 September 2020. In September Lightsource BP reached
financial close and mobilized construction for the 300MW Bighorn
Solar project in the US, which will deliver energy to the EVRAZ
North America steel mill in Pueblo, Colorado. In October they
completed construction on three solar sites in Franklin County,
Pennsylvania in the US. The sites will deliver electricity to Penn
State University under the 70MW Power Purchase Agreement (PPA) to
provide over 100 million kilowatt-hours of electricity in year
one.
BP has developed a total of 3GW net renewable energy generating
capacity by 30 September 2020 across our businesses. We intend to
continue building our renewable energy businesses and to have
developed 20GW by 2025.
Outlook
Other businesses and corporate average quarterly charges,
excluding non-operating items, fair value accounting effects and
foreign exchange volatility impact, are expected to be around $350
million although this will fluctuate quarter to quarter.
The commentary above contains forward-looking statements and should be
read in conjunction with the cautionary statement on page 36.
----------------------------------------------------------------------
Top of page 12
Financial statements
Group income statement
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
============================================ ======= ======== ======= ======== =========
Sales and other operating revenues (Note
6) 44,251 31,676 68,291 135,577 207,288
Earnings from joint ventures - after
interest and tax 73 (567) 90 (516) 413
Earnings from associates - after interest
and tax (332) (100) 784 (676) 2,041
Interest and other income 183 107 126 430 559
Gains on sale of businesses and fixed
assets 27 74 1 117 145
============================================= ======= ======== ======= ======== =======
Total revenues and other income 44,202 31,190 69,292 134,932 210,446
Purchases 31,645 18,778 52,273 99,301 156,228
Production and manufacturing expenses 5,073 5,211 5,259 16,383 16,006
Production and similar taxes (Note 8) 140 124 340 467 1,135
Depreciation, depletion and amortization
(Note 7) 3,467 3,937 4,297 11,463 13,346
Impairment and losses on sale of businesses
and fixed assets (Note 3) 294 11,770 3,416 13,213 4,418
Exploration expense (Note 4) 190 9,674 185 10,066 698
Distribution and administration expenses 2,435 2,509 2,648 7,628 8,061
============================================= ======= ======== ======= ======== =======
Profit (loss) before interest and taxation 958 (20,813) 874 (23,589) 10,554
Finance costs 800 783 883 2,366 2,603
Net finance expense relating to pensions
and other post-retirement benefits 8 8 16 23 46
============================================= ======= ======== ======= ======== =======
Profit (loss) before taxation 150 (21,604) (25) (25,978) 7,905
Taxation 457 (4,082) 706 (3,764) 3,733
============================================= ======= ======== ======= ======== =======
Profit (loss) for the period (307) (17,522) (731) (22,214) 4,172
============================================= ======= ======== ======= ======== =======
Attributable to
BP shareholders (450) (16,848) (749) (21,663) 4,007
Non-controlling interests 143 (674) 18 (551) 165
============================================= ======= ======== ======= ======== =======
(307) (17,522) (731) (22,214) 4,172
======= ======== ======= ======== =======
Earnings per share (Note 9)
Profit (loss) for the period attributable
to BP shareholders
Per ordinary share (cents)
Basic (2.22) (83.32) (3.68) (107.15) 19.74
Diluted (2.22) (83.32) (3.68) (107.15) 19.63
Per ADS (dollars)
Basic (0.13) (5.00) (0.22) (6.43) 1.18
Diluted (0.13) (5.00) (0.22) (6.43) 1.18
============================================= ======= ======== ======= ======== =======
Top of page 13
Condensed group statement of comprehensive income
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
============================================== ======= ======== ======= ======== =========
Profit (loss) for the period (307) (17,522) (731) (22,214) 4,172
=============================================== ======= ======== ======= ======== =======
Other comprehensive income
Items that may be reclassified subsequently
to profit or loss
Currency translation differences(a) (166) 1,371 (986) (3,437) 134
Exchange (gains) losses on translation
of foreign operations reclassified to
gain or loss on sale of businesses and
fixed assets - 3 - 4 -
Cash flow hedges and costs of hedging (90) 68 (17) 63 135
Share of items relating to equity-accounted
entities, net of tax 308 (333) 119 417 39
Income tax relating to items that may
be reclassified (16) (37) 12 64 (31)
=============================================== ======= ======== ======= ======== =======
36 1,072 (872) (2,889) 277
======= ======== ======= ======== =======
Items that will not be reclassified to
profit or loss
Remeasurements of the net pension and
other post-retirement benefit liability
or asset(b) 78 (1,960) (260) (163) (1,152)
Cash flow hedges that will subsequently
be transferred to the balance sheet 8 (2) (10) (2) (9)
Income tax relating to items that will
not be reclassified (16) 623 27 (16) 302
=============================================== ======= ======== ======= ======== =======
70 (1,339) (243) (181) (859)
======= ======== ======= ======== =======
Other comprehensive income 106 (267) (1,115) (3,070) (582)
=============================================== ======= ======== ======= ======== =======
Total comprehensive income (201) (17,789) (1,846) (25,284) 3,590
=============================================== ======= ======== ======= ======== =======
Attributable to
BP shareholders (364) (17,142) (1,848) (24,723) 3,434
Non-controlling interests 163 (647) 2 (561) 156
=============================================== ======= ======== ======= ======== =======
(201) (17,789) (1,846) (25,284) 3,590
======= ======== ======= ======== =======
(a) Second quarter and nine months 2020 was principally affected
by movements in the Russian rouble against the US dollar.
(b) See Note 1 for further information.
Top of page 14
Condensed group statement of changes in equity
BP shareholders' Non-controlling interests Total
$ million equity Hybrid bonds Other interest equity
At 1 January 2020 98,412 - 2,296 100,708
======================================== ================ ================== ============== ========
Total comprehensive income (24,723) 133 (694) (25,284)
Dividends (5,305) - (163) (5,468)
Cash flow hedges transferred
to the balance sheet, net of
tax 7 - - 7
Repurchase of ordinary share
capital (776) - - (776)
Share-based payments, net of
tax 547 - - 547
Share of equity-accounted entities'
changes in equity, net of tax - - - -
Issue of perpetual hybrid bonds (48) 11,909 - 11,861
Payments on perpetual hybrid
bonds - (27) - (27)
Tax on issue of perpetual hybrid
bonds 1 - - 1
Transactions involving non-controlling
interests, net of tax (160) - 746 586
======================================== ================ ================== ============== ========
At 30 September 2020 67,955 12,015 2,185 82,155
======================================== ================ ================== ============== ========
BP shareholders' Non-controlling interests Total
$ million equity Hybrid bonds Other interest equity
======================================= ================ ================== ============== ==========
At 31 December 2018 99,444 - 2,104 101,548
Adjustment on adoption of IFRS
16, net of tax(a) (329) - (1) (330)
======================================== ================ ================== ============== ========
At 1 January 2019 99,115 - 2,103 101,218
======================================== ================ ================== ============== ========
Total comprehensive income 3,434 - 156 3,590
Dividends (4,857) - (166) (5,023)
Cash flow hedges transferred
to the balance sheet, net of
tax 18 - - 18
Repurchase of ordinary share
capital (340) - - (340)
Share-based payments, net of
tax 544 - - 544
Share of equity-accounted entities'
changes in equity, net of tax 8 - - 8
At 30 September 2019 97,922 - 2,093 100,015
======================================== ================ ================== ============== ========
(a) See Note 1 in BP Annual Report and Form 20-F 2019 for further information.
Top of page 15
Group balance sheet
30 September 31 December
$ million 2020 2019
======================================================= ============ =============
Non-current assets
Property, plant and equipment 116,580 132,642
Goodwill 12,457 11,868
Intangible assets 6,293 15,539
Investments in joint ventures 7,953 9,991
Investments in associates 16,929 20,334
Other investments 2,439 1,276
======================================================== ============ ===========
Fixed assets 162,651 191,650
Loans 711 630
Trade and other receivables 4,239 2,147
Derivative financial instruments 7,705 6,314
Prepayments 497 781
Deferred tax assets 6,816 4,560
Defined benefit pension plan surpluses 6,806 7,053
======================================================== ============ ===========
189,425 213,135
============ ===========
Current assets
Loans 555 339
Inventories 13,840 20,880
Trade and other receivables 15,954 24,442
Derivative financial instruments 3,562 4,153
Prepayments 645 857
Current tax receivable 681 1,282
Other investments 298 169
Cash and cash equivalents 30,749 22,472
======================================================== ============ ===========
66,284 74,594
Assets classified as held for sale (Note 2) 4,541 7,465
======================================================== ============ ===========
70,825 82,059
============ ===========
Total assets 260,250 295,194
======================================================== ============ ===========
Current liabilities
Trade and other payables 33,823 46,829
Derivative financial instruments 3,088 3,261
Accruals 3,822 5,066
Lease liabilities 1,907 2,067
Finance debt 11,013 10,487
Current tax payable 804 2,039
Provisions 2,563 2,453
======================================================== ============ ===========
57,020 72,202
Liabilities directly associated with assets classified
as held for sale (Note 2) 1,057 1,393
======================================================== ============ ===========
58,077 73,595
============ ===========
Non-current liabilities
Other payables 11,908 12,626
Derivative financial instruments 4,761 5,537
Accruals 908 996
Lease liabilities 7,375 7,655
Finance debt 61,796 57,237
Deferred tax liabilities 6,634 9,750
Provisions 17,892 18,498
Defined benefit pension plan and other post-retirement
benefit plan deficits 8,744 8,592
======================================================== ============ ===========
120,018 120,891
============ ===========
Total liabilities 178,095 194,486
======================================================== ============ ===========
Net assets 82,155 100,708
======================================================== ============ ===========
Equity
BP shareholders' equity 67,955 98,412
Non-controlling interests 14,200 2,296
======================================================== ============ ===========
Total equity 82,155 100,708
======================================================== ============ ===========
Top of page 16
Condensed group cash flow statement
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
==================================================== ======= ======== ======= ======== ==========
Operating activities
Profit (loss) before taxation 150 (21,604) (25) (25,978) 7,905
Adjustments to reconcile profit (loss) before
taxation to net cash provided by operating
activities
Depreciation, depletion and amortization
and exploration expenditure written off 3,517 13,555 4,412 21,229 13,822
Impairment and (gain) loss on sale of businesses
and fixed assets 267 11,696 3,415 13,096 4,273
Earnings from equity-accounted entities,
less dividends received 1,018 860 (236) 2,383 (1,220)
Net charge for interest and other finance
expense, less net interest paid 60 17 257 214 407
Share-based payments 199 351 149 544 563
Net operating charge for pensions and other
post-retirement benefits, less contributions
and benefit payments for unfunded plans (46) (34) (50) (100) (195)
Net charge for provisions, less payments 293 (365) (132) (131) (446)
Movements in inventories and other current
and non-current assets and liabilities 556 (609) 141 630 (2,612)
Income taxes paid (810) (130) (1,875) (1,994) (4,330)
===================================================== ======= ======== ======= ======== ========
Net cash provided by operating activities 5,204 3,737 6,056 9,893 18,167
===================================================== ======= ======== ======= ======== ========
Investing activities
Expenditure on property, plant and equipment,
intangible and other assets (2,577) (3,018) (3,954) (9,384) (11,482)
Acquisitions, net of cash acquired (10) - 13 (27) (3,529)
Investment in joint ventures (12) (8) (60) (38) (80)
Investment in associates (1,037) (41) (22) (1,115) (221)
===================================================== ======= ======== ======= ======== ========
Total cash capital expenditure (3,636) (3,067) (4,023) (10,564) (15,312)
Proceeds from disposal of fixed assets 32 10 171 52 476
Proceeds from disposal of businesses, net
of cash disposed 84 670 536 1,425 909
Proceeds from loan repayments 50 543 63 656 182
===================================================== ======= ======== ======= ======== ========
Net cash used in investing activities (3,470) (1,844) (3,253) (8,431) (13,745)
===================================================== ======= ======== ======= ======== ========
Financing activities
Net issue (repurchase) of shares (Note 9) - - (215) (776) (340)
Lease liability payments (578) (664) (594) (1,811) (1,806)
Proceeds from long-term financing 2,587 6,846 213 12,117 6,718
Repayments of long-term financing (4,307) (964) (516) (8,988) (6,758)
Net increase (decrease) in short-term debt (2,630) (215) (852) (328) 118
Issue of perpetual hybrid bonds - 11,861 - 11,861 -
Payments on perpetual hybrid bonds (27) - - (27) -
Payments relating to transactions involving
non-controlling interests (other) - (8) - (8) -
Receipts relating to transactions involving
non-controlling interests (other) 483 - - 492 -
Dividends paid - BP shareholders (1,060) (2,119) (1,656) (5,281) (4,870)
- non-controlling interests (58) (74) (47) (163) (166)
===================================================== ======= ======== ======= ======== ========
Net cash provided by (used in) financing
activities (5,590) 14,663 (3,667) 7,088 (7,104)
===================================================== ======= ======== ======= ======== ========
Currency translation differences relating
to cash and cash equivalents 268 (42) (118) 43 (94)
===================================================== ======= ======== ======= ======== ========
Increase (decrease) in cash and cash equivalents (3,588) 16,514 (982) 8,593 (2,776)
===================================================== ======= ======== ======= ======== ========
Cash and cash equivalents at beginning of
period 34,653 18,139 20,674 22,472 22,468
Cash and cash equivalents at end of period(a) 31,065 34,653 19,692 31,065 19,692
===================================================== ======= ======== ======= ======== ========
(a) Third quarter and nine months 2020 include $316 million
(second quarter 2020 $436 million) of cash and cash equivalents
classified as assets held for sale in the group balance sheet.
Top of page 17
Notes
Note 1. Basis of preparation
The interim financial information included in this report has
been prepared in accordance with IAS 34 'Interim Financial
Reporting'.
The results for the interim periods are unaudited and, in the
opinion of management, include all adjustments necessary for a fair
presentation of the results for each period. All such adjustments
are of a normal recurring nature. This report should be read in
conjunction with the consolidated financial statements and related
notes for the year ended 31 December 2019 included in BP Annual
Report and Form 20-F 2019.
The directors consider it appropriate to adopt the going concern
basis of accounting in preparing the interim financial information.
The impact of COVID-19 and the current economic environment has
been considered as part of the going concern assessment. Forecast
liquidity has been assessed under a number of stressed scenarios
and a reverse stress test performed to support this assertion.
BP prepares its consolidated financial statements included
within BP Annual Report and Form 20-F on the basis of 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 periods presented.
The financial information presented herein has been prepared in
accordance with the accounting policies expected to be used in
preparing BP Annual Report and Form 20-F 2020 which are the same as
those used in preparing BP Annual Report and Form 20-F 2019 with
the exception of the changes described in the 'Updates to
significant accounting policies' section below. There are no other
new or amended standards or interpretations adopted from 1 January
2020 onwards that have a significant impact on the interim
financial information.
Considerations in respect of COVID-19 (coronavirus) and the
current economic environment
BP's significant accounting judgements and estimates were
disclosed in BP Annual Report and Form 20-F 2019. These have been
subsequently reviewed at the end of each quarter to determine if
any changes were required to those judgements and estimates as a
result of current market conditions. The valuation of certain
assets and liabilities is subject to a greater level of uncertainty
than when reported in BP Annual Report and Form 20-F 2019,
including those set out below.
Impairment testing assumptions
BP now sees the prospect of an enduring impact on the global
economy as a result of the COVID-19 pandemic, with the potential
for weaker demand for energy for a sustained period. BP's
management also has a growing expectation that the aftermath of the
pandemic will accelerate the pace of transition to a lower carbon
economy and energy system as countries seek to 'build back better'
so that their economies will be more resilient in the future. As a
result of all the above, during the second quarter, BP revised its
price assumptions for value-in-use impairment testing, lowering
them and extending the period covered to 2050. The price assumption
for the remainder of 2020 for Henry Hub gas was subsequently
increased during the third quarter to reflect improving observed
market prices. A summary of the group's revised price assumptions,
in real 2020 terms, is provided below:
4Q20 2021 2025 2030 2040 2050
======================== ==== ==== ==== ==== ==== ====
Brent oil ($/bbl) 40 50 50 60 60 50
Henry Hub gas ($/mmBtu) 2.75 3.00 3.00 3.00 3.00 2.75
========================= ==== ==== ==== ==== ==== ====
As disclosed in BP Annual Report and Form 20-F 2019 - Note 1,
the majority of BP's reserves and resources that support the
carrying amount of the group's oil and gas properties are expected
to be produced over the next ten years. The revised assumptions for
Brent oil and Henry Hub gas for the next 10 years are lower by
approximately 30% and 15% respectively than the average prices used
to estimate cash flows over this period as disclosed in BP Annual
Report and Form 20-F 2019 - Note 1. The revised impairment testing
price assumptions are lower, on average, by approximately 27% and
31% respectively for the period from 2020 to 2050, than the prices
referenced in BP Annual Report and Form 20-F 2019 - Note 1.
The group has identified oil and gas properties with carrying
amounts totalling $40 billion where the headroom, based on the most
recent impairment tests performed, was less than or equal to 20% of
the carrying value. The significant majority of these assets have
nil headroom. A change in price or other assumptions within the
next financial year may result in a recoverable amount of one or
more of these assets above or below the current carrying amount and
therefore there is a significant risk of impairment reversals or
charges in that period.
The discount rates used in value-in-use impairment testing were
also reviewed. As these are set using a number of parameters that
are applicable to longer-term assets, a revision of the discount
rate assumption was determined not to be appropriate and therefore
the rates, as disclosed in BP Annual Report and Form 20-F 2019,
remain unchanged.
Provisions
The nominal risk-free discount rate applied to provisions is
reviewed on a quarterly basis. Recent changes in long-dated US
government bond yields have not affected the group's overall
assessment of the discount rate applied to the group's provisions
and therefore the rate, as disclosed in BP Annual Report and Form
20-F 2019, remains unchanged. The timing and amount of cash flows
relating to the group's existing provisions are not currently
expected to change significantly as a result of the current
environment. The detailed annual review will take place later in
2020.
In addition, the group has recognized provisions for
restructuring costs for plans that were formalized during the third
quarter.
Top of page 18
Note 1. Basis of preparation (continued)
Pensions and other post-retirement benefits
The group's defined benefit pension plans are reviewed quarterly
to determine any changes to the fair value of the plan assets or
present value of the defined benefit obligations. As a result of
the review during the third quarter of 2020, the group's total net
defined benefit pension plan deficit as at 30 September 2020 is
$1.9 billion, a reduction in the deficit of $0.2 billion and an
increase by $0.4 billion from 30 June 2020 and 31 December 2019
respectively. The movement for the nine months principally reflects
actuarial losses reported in other comprehensive income arising
from decreasing discount rates and higher inflation assumptions
increasing the plan obligations partially offset by increases in
the valuation of plan assets. The current environment is likely to
continue to affect the values of the plan assets and obligations
resulting in potential volatility in the amount of the net defined
benefit pension plan surplus/deficit recognized.
Impairment of financial assets measured at amortized cost
The estimate of the loss allowance recognized on financial
assets measured at amortized cost using an expected credit loss
approach was determined not to be a significant accounting estimate
in preparing BP Annual Report and Form 20-F 2019. Expected credit
loss allowances are, however, reviewed and updated quarterly.
Allowances are recognized on assets where there is evidence that
the asset is credit-impaired and on a forward-looking expected
credit loss basis for assets that are not credit-impaired. The
current economic environment and future credit risk outlook have
been considered in updating the estimate of loss allowances
although the full economic impact of COVID-19 on the
forward-looking expected credit loss is subject to significant
uncertainty due to the limited forward-looking information
currently available.
Whilst credit risk has increased since 31 December 2019, there
has also been a significant reduction in the group's trade and
other receivables balance. Therefore, the total expected credit
loss allowances recognized as at 30 September 2020 have not
significantly increased from the amounts disclosed in BP Annual
Report and Form 20-F 2019 - Financial statements - Note 21
Valuation and qualifying accounts.
The group continues to believe that the calculation of expected
credit loss allowances is not a significant accounting estimate.
The group continues to apply its credit policy as disclosed in BP
Annual Report and Form 20-F 2019 - Financial statements - Note 29
Financial instruments and financial risk factors - credit risk.
Income taxes
None of the group's deferred tax assets in BP Annual Report and
Form 20-F 2019 were determined to be a significant accounting
estimate. The carrying amounts are, however, reviewed and updated
quarterly to the extent that there are changes in the probability
of sufficient taxable profits being available to utilize the
reported deferred tax assets. The group has recognized deferred tax
assets as at 30 September 2020 of $6.8 billion, an increase of $2.3
billion from 31 December 2019. The group continues to believe that
the measurement of its deferred tax assets is not a significant
accounting estimate.
Other accounting judgements and estimates
All other significant accounting judgements and estimates
disclosed in BP Annual Report and Form 20-F 2019 remain applicable
and no new significant accounting judgements or estimates have been
identified.
Updates to significant accounting policies
Hybrid bond issuance
On 17 June 2020, a group subsidiary issued perpetual
subordinated hybrid bonds in EUR, GBP and USD for a US dollar
equivalent amount of $11.9 billion. As the group has the
unconditional right to avoid transferring cash or another financial
asset in relation to these hybrid bonds, they are classified as
equity instruments and reported within non-controlling interests in
the condensed consolidated financial statements. The contractual
terms of these instruments allow the group to defer coupon payments
and the repayment of principal indefinitely, however their terms
and conditions stipulate that any deferred payments must be made in
the event of an announcement of an ordinary share or parity equity
dividend distribution or certain share repurchases or
redemptions.
Change in accounting policy - Interest Rate Benchmark Reform:
Amendments to IFRS 9 'Financial instruments'
Financial authorities in the US, UK, EU and other territories
are currently undertaking reviews of key interest rate benchmarks
such as the London Inter-bank Offered Rate (LIBOR) with a view to
replacing them with alternative benchmarks. Uncertainty around the
method and timing of transition from Inter-bank Offered Rates
(IBORs) to alternative risk-free rates (RfRs) may impact the
assessment of whether hedge accounting can be applied to certain
hedging relationships.
BP is significantly exposed to benchmark interest rate
components e.g. USD LIBOR, GBP LIBOR, EURIBOR and CHF LIBOR. All of
the group's existing fair value hedge relationships are directly
affected by interest rate benchmark reform as they all manage
interest rate risk. Further information about the group's fair
value hedges is included in BP Annual Report and Form 20-F 2019 -
Financial statements - Note 30 Derivative financial instruments -
Fair value hedges.
BP adopted the amendments to IFRS 9 and IFRS 7 'Financial
Instruments: Disclosures' relating to interest rate benchmark
reform with effect from 1 January 2020. This first phase of
amendments provides temporary relief from applying specific hedge
accounting requirements to hedging relationships directly affected
by interest rate benchmark reforms.
The reliefs provided by the amendments allow BP, in the event
that significant uncertainty around the reforms arise, to assume
that:
- the interest rate benchmark component of fair value hedges
only needs to be assessed as separately identifiable at initial
designation; 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.
In accordance with the transition provisions, the amendments
have been adopted retrospectively to hedging relationships that
existed at the start of the current reporting period and will be
applied to new hedging relationships designated after that
date.
Top of page 19
Note 1. Basis of preparation (continued)
The reliefs have meant that the uncertainty over the interest
rate benchmark reforms has not resulted in discontinuation of hedge
accounting for any of BP's fair value hedges.
The second phase of IFRS amendments were issued by the IASB in
August 2020 to address the financial reporting impacts of
transitioning from IBORs to RfRs. These amendments will be
effective for BP from 1 January 2021.The amendments are not yet
endorsed by the EU or the UK. BP has set up an internal working
group to monitor and manage the transition to alternative benchmark
rates and are currently assessing the impact on contracts and
arrangements that are linked to existing interest rate benchmarks,
for example, borrowings, leases and derivative contracts. BP is
also participating on external committees and task forces dedicated
to interest rate benchmark reform.
Change in accounting policy - physically settled derivative
contracts
In March 2019, the IFRS Interpretations Committee ("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. 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 in BP Annual
Report and Form 20-F 2019, revenue recognized at the time such
contracts were physically settled was measured at the contractual
transaction price and was presented together with revenue from
contracts with customers in those financial statements.
BP changed its accounting policy for these contracts, in
accordance with the conclusions included in the agenda decision,
with effect from 1 April 2020, as follows:
- Revenues and purchases from such contracts are measured at the
contractual transaction price plus the carrying amount of the
related derivative at the date of settlement. Realized derivative
gains and losses on physically settled derivative contracts are
included in other revenues.
- There is no significant effect on current period or
comparative information for 'Sales and other operating revenues'
and 'Purchases' as presented in the group income statement,
therefore no comparative information has been re-stated.
- There is no significant effect on net assets or on comparative
information for 'Profit before taxation' or 'Profit after taxation'
as presented in the group income statement.
In addition, BP chose to change its presentation of revenues
from physically settled derivative sales contracts from first
quarter 2020. Revenues from physically settled derivative sales
contracts are no longer presented together with revenue from
contracts with customers. They are now presented as other revenues.
Comparative information in Note 6 for revenue from contracts with
customers and other revenues have been re-presented to align with
the current period.
Note 2. Non-current assets held for sale
The carrying amount of assets classified as held for sale at 30
September 2020 is $4,541 million, with associated liabilities of
$1,057 million. These principally relate to two transactions.
Downstream segment
On 29 June 2020 BP announced that it had agreed to sell its
global petrochemicals business to INEOS for a total consideration
of $5 billion, subject to customary closing adjustments. Under the
terms of the agreement, INEOS paid BP a deposit of $400 million and
will pay a further $3.6 billion on completion. An additional $1
billion will be deferred and paid in three separate instalments of
$100 million in March, April and May 2021 with the remaining $700
million payable by the end of June 2021. The business has interests
in manufacturing plants in Asia, Europe and the US, including
interests held in equity-accounted entities. Subject to regulatory
and other approvals, the transaction is expected to complete by the
end of 2020. Assets of $3,963 million and associated liabilities of
$745 million have been classified as held for sale in the group
balance sheet at 30 September 2020. Accumulated foreign exchange
differences will be reclassified from the foreign currency
translation reserve to the income statement when the sale
transaction completes. At 30 September 2020 these foreign exchange
differences amounted to a gain of approximately $375 million.
Upstream segment
On 27 August 2019, BP announced that it had agreed to sell all
of its Alaska operations and interests to Hilcorp Energy
('Hilcorp'), including its ownership interests in BP Exploration
(Alaska) Inc, which owned all of BP's upstream oil and gas
interests in Alaska, and the assets of BP Pipelines (Alaska) Inc.,
including a 49% interest in the Trans Alaska Pipeline System
(TAPS), for up to $5.6 billion, subject to customary closing
adjustments. Assets of $6,518 million and associated liabilities of
$969 million relating to this transaction were classified as held
for sale at 31 December 2019. Deposit payments totalling $500
million in cash were received in 2019.
On 30 June 2020, BP completed the sale of BP Exploration
(Alaska) Inc. On completion, BP received $209 million in cash and
recognized a loan note with a principal amount of $2,100 million
receivable from Hilcorp. The group also recognized other assets
totalling $1,689 million, including amounts in relation to the
'earn-out' provisions of the agreement.
The sale of BP Pipelines (Alaska) Inc.'s 49% interest in the
Trans Alaska Pipeline System (TAPS) and other midstream assets,
which is subject to regulatory approvals, is expected to complete
during the fourth quarter of 2020. On completion of the sale, BP
will retain its decommissioning liability relating to TAPS, which
will be partially offset by a 30% cost reimbursement from Harvest
Alaska LLC, an affiliate of Hilcorp. Assets of $499 million and
associated liabilities of $279 million relating to this transaction
continue to be classified as held for sale at 30 September
2020.
Top of page 20
Note 3. Impairment and losses on sale of businesses and fixed
assets
Impairment and losses on sale of businesses and fixed assets for
the third quarter and nine months were $294 million and $13,213
million and include net impairment charges of $277 million and
$12,923 million respectively. Impairment charges also arose in
certain equity-accounted entities in the nine months. The BP shares
of these charges, amounting to $978 million for the nine months,
are reported in the line items 'Earnings from joint ventures' and
'Earnings from associates' in the group income statement.
Upstream segment
Net impairment charges in the Upstream segment were $272 million
and $12,157 million for the third quarter and nine months
respectively.
Impairment charges for the nine months mainly relate to
producing assets and principally arose as a result of changes to
the group's oil and gas price assumptions. They include amounts in
Azerbaijan, BPX Energy, Canada, Egypt, India, Mauritania &
Senegal, the North Sea, and Trinidad. The recoverable amounts of
the cash generating units within these businesses were based on
value-in-use calculations.
Impairment charges for the nine months also include amounts
relating to the disposal of the group's interests in its Alaska
business. See Note 2 for further information.
The BP share of impairment charges arising in equity-accounted
entities reported in the Upstream segment in the nine months was
$742 million.
Downstream segment
Impairment charges in the Downstream segment were $736 million
for the nine months, principally relating to anticipated portfolio
changes in the fuels business. Materially all of the impairment
charges arose in the second quarter.
Note 4. Exploration expense
Exploration expense in the third quarter and nine months was
$190 million and $10,066 million and includes exploration
expenditure write-offs of $50 million and $9,766 million
respectively. All exploration expenditure is recorded within the
Upstream segment.
The exploration write-offs principally arose following
management's re-assessment of expectations to extract value from
certain exploration prospects as a result of a review of the
group's long-term strategic plan and changes in the group's price
assumptions. The exploration write-offs for the nine months
principally arose in Angola, Brazil, Canada, Egypt, India and the
Gulf of Mexico.
Top of page 21
Note 5. Analysis of replacement cost profit (loss) before
interest and tax and reconciliation to profit (loss) before
taxation
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
========================================= ======= ======== ======= ======== =========
Upstream 30 (22,008) (1,050) (20,955) 4,303
Downstream 915 594 2,016 2,173 5,069
Rosneft (278) (124) 802 (419) 1,813
Other businesses and corporate 24 (317) (412) (991) (1,339)
========================================== ======= ======== ======= ======== =======
691 (21,855) 1,356 (20,192) 9,846
Consolidation adjustment - UPII* 34 (46) 30 166 51
========================================== ======= ======== ======= ======== =======
RC profit (loss) before interest and
tax* 725 (21,901) 1,386 (20,026) 9,897
Inventory holding gains (losses)*
Upstream 8 57 - (3) (8)
Downstream 191 978 (433) (3,446) 706
Rosneft (net of tax) 34 53 (79) (114) (41)
========================================== ======= ======== ======= ======== =======
Profit (loss) before interest and tax 958 (20,813) 874 (23,589) 10,554
Finance costs 800 783 883 2,366 2,603
Net finance expense relating to pensions
and other post-retirement benefits 8 8 16 23 46
========================================== ======= ======== ======= ======== =======
Profit (loss) before taxation 150 (21,604) (25) (25,978) 7,905
========================================== ======= ======== ======= ======== =======
RC profit (loss) before interest and
tax*
US 105 (4,695) (2,425) (3,995) (1,156)
Non-US 620 (17,206) 3,811 (16,031) 11,053
========================================== ======= ======== ======= ======== =======
725 (21,901) 1,386 (20,026) 9,897
======= ======== ======= ======== =======
Top of page 22
Note 6. Sales and other operating revenues
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
=========================================== ======= ======= ======= ======= =========
By segment
Upstream 7,797 7,194 12,396 26,455 40,546
Downstream 40,256 27,241 61,834 121,461 186,646
Other businesses and corporate 391 450 461 1,294 1,250
============================================ ======= ======= ======= ======= =======
48,444 34,885 74,691 149,210 228,442
======= ======= ======= ======= =======
Less: sales and other operating revenues
between segments
Upstream 3,647 2,613 6,406 13,167 20,211
Downstream 124 330 (59) (328) 589
Other businesses and corporate 422 266 53 794 354
============================================ ======= ======= ======= ======= =======
4,193 3,209 6,400 13,633 21,154
======= ======= ======= ======= =======
Third party sales and other operating
revenues
Upstream 4,150 4,581 5,990 13,288 20,335
Downstream 40,132 26,911 61,893 121,789 186,057
Other businesses and corporate (31) 184 408 500 896
============================================ ======= ======= ======= ======= =======
Total sales and other operating revenues 44,251 31,676 68,291 135,577 207,288
============================================ ======= ======= ======= ======= =======
By geographical area
US 16,513 10,117 23,413 47,849 71,347
Non-US 32,328 24,776 51,030 101,059 153,581
============================================ ======= ======= ======= ======= =======
48,841 34,893 74,443 148,908 224,928
Less: sales and other operating revenues
between areas 4,590 3,217 6,152 13,331 17,640
============================================ ======= ======= ======= ======= =======
44,251 31,676 68,291 135,577 207,288
======= ======= ======= ======= =======
Revenues from contracts with customers(a)
Sales and other operating revenues include
the following in relation to revenues
from contracts with customers:
Crude oil 1,366 1,062 2,194 3,863 7,261
Oil products 16,301 10,452 26,547 47,007 76,462
Natural gas, LNG and NGLs 2,844 2,992 4,387 9,474 14,038
Non-oil products and other revenues from
contracts with customers 2,965 2,118 2,970 7,573 9,291
============================================ ======= ======= ======= ======= =======
Revenue from contracts with customers 23,476 16,624 36,098 67,917 107,052
============================================ ======= ======= ======= ======= =======
Other operating revenues(b) 20,775 15,052 32,193 67,660 100,236
============================================ ======= ======= ======= ======= =======
Total sales and other operating revenues 44,251 31,676 68,291 135,577 207,288
============================================ ======= ======= ======= ======= =======
(a) Amounts shown for revenue from contracts with customers and
other operating revenues for third quarter and nine months 2019
have been represented to align with the current period. See Note 1
for further information.
(b) Principally relates to physically settled derivative sales contracts.
Top of page 23
Note 7. Depreciation, depletion and amortization
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
=============================== ======= ======= ======= ====== ========
Upstream
US 842 1,044 1,121 2,954 3,522
Non-US 1,713 1,973 2,295 5,768 7,189
================================ ======= ======= ======= ====== ======
2,555 3,017 3,416 8,722 10,711
======= ======= ======= ====== ======
Downstream
US 336 344 336 1,022 992
Non-US 407 408 394 1,220 1,169
================================ ======= ======= ======= ====== ======
743 752 730 2,242 2,161
======= ======= ======= ====== ======
Other businesses and corporate
US 13 16 14 44 41
Non-US 156 152 137 455 433
================================ ======= ======= ======= ====== ======
169 168 151 499 474
======= ======= ======= ====== ======
Total group 3,467 3,937 4,297 11,463 13,346
================================ ======= ======= ======= ====== ======
Note 8. Production and similar taxes
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
========== ======= ======= ======= ====== ========
US 14 13 66 40 226
Non-US 126 111 274 427 909
=========== ======= ======= ======= ====== ======
140 124 340 467 1,135
======= ======= ======= ====== ======
Note 9. Earnings per share and shares in issue
Basic earnings per ordinary share (EpS) amounts are calculated
by dividing the profit (loss) for the period attributable to
ordinary shareholders by the weighted average number of ordinary
shares outstanding during the period. No share buybacks were
carried out during the quarter. A total of 120 million ordinary
shares were repurchased for cancellation in the nine months, as
part of the share buyback programme announced on 31 October 2017.
The shares had a total cost of $776 million, including transaction
costs of $4 million. The number of shares in issue is reduced when
shares are repurchased.
The calculation of EpS is performed separately for each discrete
quarterly period, and for the year-to-date period. As a result, the
sum of the discrete quarterly EpS amounts in any particular
year-to-date period may not be equal to the EpS amount for the
year-to-date period.
For the diluted EpS calculation the weighted average number of
shares outstanding during the period is adjusted for the number of
shares that are potentially issuable in connection with employee
share-based payment plans using the treasury stock method.
Top of page 24
Note 9. Earnings per share and shares in issue (continued)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
========================================== ========== ========== ========== ========== ============
Results for the period
Profit (loss) for the period attributable
to BP shareholders (450) (16,848) (749) (21,663) 4,007
Less: preference dividend - 1 - 1 1
=========================================== ========== ========== ========== ========== ==========
Profit (loss) attributable to
BP ordinary shareholders (450) (16,849) (749) (21,664) 4,006
=========================================== ========== ========== ========== ========== ==========
Number of shares (thousand) (a)(b)
Basic weighted average number
of shares outstanding 20,251,199 20,222,575 20,371,728 20,217,559 20,295,078
ADS equivalent 3,375,199 3,370,429 3,395,288 3,369,593 3,382,513
=========================================== ========== ========== ========== ========== ==========
Weighted average number of shares
outstanding used to calculate
diluted earnings per share 20,251,199 20,222,575 20,371,728 20,217,559 20,411,739
ADS equivalent 3,375,199 3,370,429 3,395,288 3,369,593 3,401,957
=========================================== ========== ========== ========== ========== ==========
Shares in issue at period-end 20,254,417 20,249,046 20,417,220 20,254,417 20,417,220
ADS equivalent 3,375,736 3,374,841 3,402,870 3,375,736 3,402,870
=========================================== ========== ========== ========== ========== ==========
(a) Excludes treasury shares and includes certain shares that
will be issued in the future under employee share-based payment
plans.
(b) 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. The numbers of
potentially issuable shares that have been excluded from the
calculation for the second quarter 2020, third quarter 2020 and
nine months 2020 are 63,119 thousand (ADS equivalent 10,520
thousand), 81,097 thousand (ADS equivalent 13,516 thousand) and
94,302 thousand (ADS equivalent 15,717 thousand) respectively.
Note 10. Dividends
Dividends payable
BP today announced an interim dividend of 5.25 cents per
ordinary share which is expected to be paid on 18 December 2020 to
ordinary shareholders and American Depositary Share (ADS) holders
on the register on 6 November 2020. The corresponding amount in
sterling is due to be announced on 7 December 2020, calculated
based on the average of the market exchange rates for the four
dealing days commencing on 1 December 2020. Holders of ADSs are
expected to receive $0.315 per ADS (less applicable fees). The
board has decided not to offer a scrip dividend alternative in
respect of the third quarter 2020 dividend. Ordinary shareholders
and ADS holders (subject to certain exceptions) will be able to
participate in a dividend reinvestment programme. Details of the
third quarter dividend and timetable are available at
bp.com/dividends and further details of the dividend reinvestment
programmes are available at bp.com/drip.
Third Second Third Nine Nine
quarter quarter quarter months months
2020 2020 2019 2020 2019
=================================== ======= ======= ======= ====== ========
Dividends paid per ordinary share
cents 5.250 10.500 10.250 26.250 30.750
pence 4.043 8.342 8.348 20.541 24.152
Dividends paid per ADS (cents) 31.50 63.00 61.50 157.50 184.50
==================================== ======= ======= ======= ====== ======
Scrip dividends
Number of shares issued (millions) - - 72.5 - 208.9
Value of shares issued ($ million) - - 440 - 1,387
==================================== ======= ======= ======= ====== ======
Top of page 25
Note 11. Net debt
Net debt* Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
======================================= ======== ======== ======== ======== ==========
Finance debt(a)(b) 72,828 76,003 65,867 72,828 65,867
Fair value (asset) liability of hedges
related to finance debt(c) (1,384) (430) 319 (1,384) 319
======================================== ======== ======== ======== ======== ========
71,444 75,573 66,186 71,444 66,186
Less: cash and cash equivalents(b) 31,065 34,653 19,692 31,065 19,692
======================================== ======== ======== ======== ======== ========
Net debt 40,379 40,920 46,494 40,379 46,494
======================================== ======== ======== ======== ======== ========
Total equity 82,155 82,811 100,015 82,155 100,015
Gearing* 33.0% 33.1% 31.7% 33.0% 31.7%
======================================== ======== ======== ======== ======== ==========
(a) The fair value of finance debt at 30 September 2020 was
$75,338 million (30 September 2019 $66,879 million).
(b) Third quarter and nine months 2020 include $316 million of
cash and $19 million of finance debt included in assets and
liabilities held for sale in the group balance sheet.
(c) 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 $372 million (second quarter 2020 liability of $554 million and
third quarter 2019 liability of $682 million) are not included in
the calculation of net debt shown above as hedge accounting is not
applied for these instruments.
In the third quarter, the group bought back $4.0 billion
equivalent of euro and sterling bonds as part of actively managing
its debt portfolio. Derivatives associated with the debt bought
back were also terminated. There was no significant impact on net
debt as a result of these transactions.
On 17 June 2020 the group issued perpetual hybrid bonds with a
US dollar equivalent value of $11.9 billion. See Note 1 for further
information.
Note 12. Inventory valuation
A provision of $544 million was held against hydrocarbon
inventories at 30 September 2020 ($289 million at 30 June 2020 and
$290 million at 31 December 2019) to write them down to their net
realizable value.
Note 13. Statutory accounts
The financial information shown in this publication, which was
approved by the Board of Directors on 26 October 2020, is unaudited
and does not constitute statutory financial statements. Audited
financial information will be published in BP Annual Report and
Form 20-F 2020. BP Annual Report and Form 20-F 2019 has been filed
with the Registrar of Companies in England and Wales. The report of
the auditor on those accounts was unqualified, did not include a
reference to any matters to which the auditor drew attention by way
of emphasis without qualifying the report and did not contain a
statement under section 498(2) or section 498(3) of the UK
Companies Act 2006.
Top of page 26
Additional information
Capital expenditure*
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
===================================== ======= ======= ======= ====== ========
Capital expenditure on a cash basis
Organic capital expenditure* 2,512 3,034 3,946 9,085 11,280
Inorganic capital expenditure*(a)(b) 1,124 33 77 1,479 4,032
====================================== ======= ======= ======= ====== ======
3,636 3,067 4,023 10,564 15,312
======= ======= ======= ====== ======
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
============================================ ======= ======= ======= ====== ========
Organic capital expenditure by segment
Upstream
US 589 1,018 1,036 2,775 2,990
Non-US 1,367 1,517 2,110 4,546 5,856
============================================= ======= ======= ======= ====== ======
1,956 2,535 3,146 7,321 8,846
======= ======= ======= ====== ======
Downstream
US 139 135 197 395 655
Non-US 345 295 558 1,171 1,562
============================================= ======= ======= ======= ====== ======
484 430 755 1,566 2,217
======= ======= ======= ====== ======
Other businesses and corporate
US 13 21 8 66 32
Non-US 59 48 37 132 185
============================================= ======= ======= ======= ====== ======
72 69 45 198 217
======= ======= ======= ====== ======
2,512 3,034 3,946 9,085 11,280
======= ======= ======= ====== ======
Organic capital expenditure by geographical
area
US 741 1,174 1,241 3,236 3,677
Non-US 1,771 1,860 2,705 5,849 7,603
============================================= ======= ======= ======= ====== ======
2,512 3,034 3,946 9,085 11,280
======= ======= ======= ====== ======
(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 the nine months 2019 relating to this
transaction.
(b) Third quarter and nine months 2020 include $1 billion
relating to an investment in a 49% interest in the group's Indian
fuels and mobility venture with Reliance industries. Nine months
2020 and 2019 also include amounts relating to the 25-year
extension to our ACG production-sharing agreement* in
Azerbaijan.
Top of page 27
Non-operating items*
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
=============================================== ======= ======== ======= ======== =========
Upstream
Gains on sale of businesses and fixed
assets 10 87 - 104 105
Impairment and losses on sale of businesses
and fixed assets(a) (274) (10,953) (3,406) (12,358) (4,318)
Environmental and other provisions (9) - - (22) -
Restructuring, integration and rationalization
costs(b) (164) (24) (24) (192) (76)
Other(c)(d) (194) (2,564) (24) (2,688) 65
================================================ ======= ======== ======= ======== =======
(631) (13,454) (3,454) (15,156) (4,224)
======= ======== ======= ======== =======
Downstream
Gains on sale of businesses and fixed
assets 16 (13) 2 10 44
Impairment and losses on sale of businesses
and fixed assets(a) (20) (798) (11) (823) (100)
Environmental and other provisions - - (1) - (1)
Restructuring, integration and rationalization
costs(b) (142) 31 (4) (111) 14
Other - - - - (6)
================================================ ======= ======== ======= ======== =======
(146) (780) (14) (924) (49)
======= ======== ======= ======== =======
Rosneft
Other (101) (63) - (164) (194)
(101) (63) - (164) (194)
======= ======== ======= ======== =======
Other businesses and corporate
Gains on sale of businesses and fixed
assets 1 - - 3 (4)
Impairment and losses on sale of businesses
and fixed assets - (19) - (21) -
Environmental and other provisions (32) - - (55) (28)
Restructuring, integration and rationalization
costs(b) (156) (33) - (202) 7
Gulf of Mexico oil spill (63) (31) (84) (115) (256)
Other(e) 138 67 (6) 125 (28)
================================================ ======= ======== ======= ======== =======
(112) (16) (90) (265) (309)
======= ======== ======= ======== =======
Total before interest and taxation (990) (14,313) (3,558) (16,509) (4,776)
Finance costs(f) (198) (114) (145) (434) (389)
================================================ ======= ======== ======= ======== =======
Total before taxation (1,188) (14,427) (3,703) (16,943) (5,165)
Taxation credit (charge) on non-operating
items (6) 3,456 772 3,752 1,121
Taxation - impact of foreign exchange(g) 85 114 - (166) -
================================================ ======= ======== ======= ======== =======
Total after taxation for period (1,109) (10,857) (2,931) (13,357) (4,044)
================================================ ======= ======== ======= ======== =======
(a) See Note 3 for further information.
(b) Third quarter 2020 includes recognized provisions for
restructuring costs for plans that were formalized during the
quarter.
(c) Second quarter and nine months 2020 include exploration
write-offs of $1,969 million relating to fair value ascribed to
certain licences as part of the accounting at the time of
acquisition of upstream assets in Brazil, India and the Gulf of
Mexico and the impairment of certain intangible assets in
Mauritania and Senegal.
(d) Second quarter and nine months 2020 include $585 million and
$742 million of impairments reported by equity-accounted
entities.
(e) From first quarter 2020, BP is presenting temporary
valuation differences associated with the group's interest rate and
foreign currency exchange risk management of finance debt as
non-operating items. These amounts represent: (i) the impact of
ineffectiveness and the amortisation of cross currency basis
resulting from the application of fair value hedge accounting; and
(ii) the net impact of foreign currency exchange movements on
finance debt and associated derivatives where hedge accounting is
not applied. Relevant amounts in the comparative periods presented
were not material.
(f) All periods presented include the unwinding of discounting
effects relating to Gulf of Mexico oil spill payables. Third
quarter and nine months 2020 also include the income statement
impact associated with the buyback of finance debt. See Note 11 for
further information.
(g) From first quarter 2020, BP is presenting certain foreign
exchange effects on tax as non-operating items. These amounts
represent the impact of: (i) foreign exchange on deferred tax
balances arising from the conversion of local currency tax base
amounts into functional currency, and (ii) taxable gains and losses
from the retranslation of US dollar-denominated intra-group loans
to local currency. Relevant amounts in the comparative periods
presented were not material.
Top of page 28
Non-GAAP information on fair value accounting effects
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
======================================== ======= ======= ======= ====== ========
Favourable (adverse) impact relative to
management's measure of performance
Upstream (217) (67) 265 (61) 47
Downstream 425 (31) 147 135 137
Other businesses and corporate 266 (41) - 225 -
========================================= ======= ======= ======= ====== ======
474 (139) 412 299 184
Taxation credit (charge) (95) 21 (86) (66) (44)
========================================= ======= ======= ======= ====== ======
379 (118) 326 233 140
======= ======= ======= ====== ======
Fair value accounting effects reflect differences in the way
that BP manages the economic exposure and measures performance
relating to certain activities and the way these activities are
measured under IFRS. They relate to certain of the group's
commodity, interest rate and currency risk exposures as detailed
below.
BP uses 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, other than net realizable value provisions, 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, liquefied natural gas
(LNG) and certain gas and power contracts 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, power 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.
Fair value accounting effects also include changes in the fair
value of the near-term portions of LNG contracts that fall within
BP's risk management framework. LNG contracts are not considered
derivatives, because there is insufficient market liquidity, and
they are therefore accrual accounted under IFRS. However, oil and
natural gas derivative financial instruments (used to risk manage
the near-term portions of the LNG contracts) are fair valued under
IFRS. The fair value accounting effect reduces timing differences
between recognition of the derivative financial instruments used to
risk manage the LNG contracts and the recognition of the LNG
contracts themselves, which therefore gives a better representation
of performance in each period.
In addition, from the second quarter 2020 fair value accounting
effects include changes in the fair value of derivatives entered
into by the group to manage currency exposure and interest rate
risks relating to hybrid bonds to their respective first call
periods. The hybrid bonds which were issued on 17 June 2020 are
classified as equity instruments and were recorded in the balance
sheet at that date at their USD equivalent issued value. Under IFRS
these equity instruments are not remeasured from period to period,
and do not qualify for application of hedge accounting. The
derivative instruments relating to the hybrid bonds, however, are
required to be recorded at fair value with mark to market gains and
losses recognized in the income statement. Therefore, measurement
differences in relation to the recognition of gains and losses
occur. The fair value accounting effect, which is reported in the
Other businesses and corporate segment in the table above,
eliminates the fair value gains and losses of these derivative
financial instruments that are recognized in the income statement.
We believe that this gives a better representation of performance,
by more appropriately reflecting the economic effect of these risk
management activities, in each period.
Top of page 29
Net debt including leases
Net debt including leases* Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
======================================== ======== ======== ======== ======== ==========
Net debt 40,379 40,920 46,494 40,379 46,494
Lease liabilities 9,282 9,331 9,639 9,282 9,639
Net partner (receivable) payable for
leases entered into on behalf of joint
operations (41) (90) (197) (41) (197)
Net debt including leases 49,620 50,161 55,936 49,620 55,936
========================================= ======== ======== ======== ======== ========
Total equity 82,155 82,811 100,015 82,155 100,015
Gearing including leases* 37.7% 37.7% 35.9% 37.7% 35.9%
========================================= ======== ======== ======== ======== ==========
Readily marketable inventory* (RMI)
30 September 31 December
$ million 2020 2019
=================== ============ =============
RMI at fair value* 4,506 6,837
Paid-up RMI* 1,474 3,217
==================== ============ ===========
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. Paid-up RMI is RMI that BP has paid for.
We believe 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.
See the Glossary on page 32 for a more detailed definition of
RMI. RMI at fair value, paid-up RMI and unpaid RMI are non-GAAP
measures. A reconciliation of total inventory as reported on the
group balance sheet to paid-up RMI is provided below.
30 September 31 December
$ million 2020 2019
=================================================== ============ =============
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet
under IFRS 13,840 20,880
Less: (a) inventories that are not oil and oil
products and (b) oil and oil product inventories
that are not risk-managed by IST (9,474) (14,280)
==================================================== ============ ===========
4,366 6,600
Plus: difference between RMI at fair value and
RMI on an IFRS basis 140 237
==================================================== ============ ===========
RMI at fair value 4,506 6,837
Less: unpaid RMI* at fair value (3,032) (3,620)
==================================================== ============ ===========
Paid-up RMI 1,474 3,217
==================================================== ============ ===========
Top of page 30
Gulf of Mexico oil spill
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
============================================== ======= ======= ======= ====== ========
Net cash provided by operating activities
as per condensed group cash flow statement 5,204 3,737 6,056 9,893 18,167
Exclude net cash from operating activities
relating to the Gulf of Mexico oil spill
on a post-tax basis 142 1,097 409 1,520 2,471
=============================================== ======= ======= ======= ====== ======
Operating cash flow, excluding Gulf of Mexico
oil spill payments* 5,346 4,834 6,465 11,413 20,638
=============================================== ======= ======= ======= ====== ======
Net cash from operating activities relating to the Gulf of
Mexico oil spill on a pre-tax basis amounted to an outflow of $180
million and $1,670 million in the third quarter and nine months of
2020 respectively. For the same periods in 2019, the amount was an
outflow of $443 million and $2,569 million respectively. Net cash
outflows relating to the Gulf of Mexico oil spill in 2020 and 2019
include payments made under the 2016 consent decree and settlement
agreement with the United States and the five Gulf coast
states.
30 September 31 December
$ million 2020 2019
================================================= ============ =============
Trade and other payables (11,298) (12,480)
Provisions (23) (189)
================================================== ============ ===========
Gulf of Mexico oil spill payables and provisions (11,321) (12,669)
================================================== ============ ===========
Of which - current (1,427) (1,800)
Deferred tax asset 5,449 5,526
================================================== ============ ===========
The provision reflects the latest estimate for the remaining
costs associated with the Gulf of Mexico oil spill. The amounts
ultimately payable may differ from the amount provided and the
timing of payments is uncertain. Further information relating to
the Gulf of Mexico oil spill, including information on the nature
and expected timing of payments relating to provisions and other
payables, is provided in BP Annual Report and Form 20-F 2019 -
Financial statements - Notes 7, 9, 20, 22, 23, 29, 33 and pages 319
to 320 of Legal proceedings.
Working capital* reconciliation
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2020 2020 2019 2020 2019
================================================ ======= ======= ======= ======= =========
Movements in inventories and other current
and non-current assets and liabilities
as per condensed group cash flow statement 556 (609) 141 630 (2,612)
Adjustments to exclude movements in inventories
and other current and non-current assets
and liabilities for the Gulf of Mexico
oil spill 165 1,120 413 1,539 2,495
Adjusted for Inventory holding gains
(losses)* (Note 5)
Upstream 8 57 - (3) (8)
Downstream 191 978 (433) (3,446) 706
================================================= ======= ======= ======= ======= =======
Working capital release (build) 920 1,546 121 (1,280) 581
================================================= ======= ======= ======= ======= =======
Top of page 31
Realizations* and marker prices
Third Second Third Nine Nine
quarter quarter quarter months months
2020 2020 2019 2020 2019
============================================ ======= ======= ======= ====== ========
Average realizations (a)
Liquids* ($/bbl)
US 31.74 21.63 50.46 33.24 52.80
Europe 43.52 28.91 61.90 41.35 64.21
Rest of World 41.46 22.58 59.14 36.13 61.91
BP Average 38.17 22.75 55.68 35.51 58.38
============================================= ======= ======= ======= ====== ======
Natural gas ($/mcf)
US 1.29 0.97 1.72 1.19 2.02
Europe 2.34 1.38 3.03 2.22 3.98
Rest of World 2.99 3.12 3.82 3.21 4.21
BP Average 2.56 2.53 3.11 2.65 3.49
============================================= ======= ======= ======= ====== ======
Total hydrocarbons* ($/boe)
US 22.04 16.05 31.23 23.01 33.81
Europe 36.14 23.00 52.47 34.34 58.55
Rest of World 27.40 20.21 36.82 26.19 39.69
BP Average 26.42 19.06 35.48 25.68 38.55
============================================= ======= ======= ======= ====== ======
Average oil marker prices ($/bbl)
Brent 42.94 29.56 62.00 41.06 64.59
West Texas Intermediate 40.91 27.96 56.40 38.12 57.08
Western Canadian Select 31.62 22.19 43.61 27.54 45.30
Alaska North Slope 42.75 30.28 62.98 41.32 65.23
Mars 42.01 30.02 59.19 39.18 61.85
Urals (NWE - cif) 42.83 31.36 60.82 40.83 63.71
============================================= ======= ======= ======= ====== ======
Average natural gas marker prices
Henry Hub gas price(b) ($/mmBtu) 1.98 1.71 2.23 1.88 2.67
UK Gas - National Balancing Point (p/therm) 21.06 12.88 27.46 19.69 35.70
============================================= ======= ======= ======= ====== ======
(a) Based on sales of consolidated subsidiaries only - this excludes equity-accounted entities.
(b) Henry Hub First of Month Index.
Exchange rates
Third Second Third Nine Nine
quarter quarter quarter months months
2020 2020 2019 2020 2019
===================================== ======= ======= ======= ====== ========
$/GBP average rate for the period 1.29 1.24 1.23 1.27 1.27
$/GBP period-end rate 1.28 1.23 1.23 1.28 1.23
$/EUR average rate for the period 1.17 1.10 1.11 1.12 1.12
$/EUR period-end rate 1.17 1.12 1.09 1.17 1.09
Rouble/$ average rate for the period 73.74 72.40 64.64 71.00 65.06
Rouble/$ period-end rate 77.57 71.25 64.32 77.57 64.32
====================================== ======= ======= ======= ====== ======
Top of page 32
Legal proceedings
For a full discussion of the group's material legal proceedings,
see pages 319-320 of BP Annual Report and Form 20-F 2019.
Glossary
Non-GAAP measures are provided for investors because they are
closely tracked by management to evaluate BP's operating
performance and to make financial, strategic and operating
decisions. Non-GAAP measures are sometimes referred to as
alternative performance measures.
Capital expenditure is total cash capital expenditure as stated
in the condensed group cash flow statement.
Cash balance point is defined as the implied Brent oil price for
the quarter that would cause the sum of operating cash flow
excluding Gulf of Mexico oil spill payments (assuming actual
refining marker margins and Henry Hub gas prices for the quarter)
and proceeds from loan repayments to equate to the sum of total
cash capital expenditure, lease liability payments, dividend paid,
and payments on perpetual hybrid bonds.
Consolidation adjustment - UPII is unrealized profit in
inventory arising on inter-segment transactions.
Divestment proceeds are disposal proceeds as per the condensed
group cash flow statement.
Effective tax rate (ETR) on replacement cost (RC) profit or loss
is a 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.
Ethanol-equivalent production (which includes ethanol and sugar)
is converted to thousands of barrels a day at 6.289 million litres
= 1 thousand barrels divided by the total number of days in the
period reported.
Fair value accounting effects are non-GAAP adjustments to our
IFRS profit (loss). They reflect the difference between the way BP
manages the economic exposure and internally measures performance
of certain activities and the way those activities are measured
under IFRS. Further information on fair value accounting effects is
provided on page 28.
Gearing and net debt are 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'. The nearest
equivalent GAAP measures on an IFRS basis are finance debt and
finance debt ratio. A reconciliation of finance debt to net debt is
provided on page 25.
We are unable to present reconciliations of forward-looking
information for gearing to finance debt and total equity, 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.
Gearing including leases and net debt including leases are
non-GAAP measures. 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. Gearing including leases is defined as the
ratio of net debt including leases to the total of net debt
including leases plus total equity. BP believes these measures
provide useful information to investors as they enable investors to
understand the impact of the group's lease portfolio on net debt
and gearing. The nearest equivalent GAAP measures on an IFRS basis
are finance debt and finance debt ratio. A reconciliation of
finance debt to net debt including leases is provided on page
29.
Hydrocarbons - Liquids and natural gas. Natural gas is converted
to oil equivalent at 5.8 billion cubic feet = 1 million
barrels.
Inorganic capital expenditure is 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 26.
Top of page 33
Glossary (continued)
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. See Replacement cost (RC) profit or
loss definition below.
Liquids - Liquids for Upstream and Rosneft comprises crude oil,
condensate and natural gas liquids. For Upstream, liquids also
includes bitumen.
Major projects have a BP net investment of at least $250
million, or are considered to be of strategic importance to BP or
of a high degree of complexity.
Net wind generation capacity is the sum of the rated capacities
of the assets/turbines that have entered into commercial operation,
including BP's share of equity-accounted entities.
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 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 region is shown on pages 7, 9 and 11, and by
segment and type is shown on page 27.
Operating cash flow is net cash provided by (used in) operating
activities as stated in the condensed group cash flow statement.
When used in the context of a segment rather than the group, the
terms refer to the segment's share thereof.
Operating cash flow excluding Gulf of Mexico oil spill payments
is a 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
condensed 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 capital expenditure is 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 26.
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.
Production-sharing agreement/contract (PSA/PSC) is 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) 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.
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. Further information is provided on page 29.
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.
Top of page 34
Glossary (continued)
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.
The Refining marker margin (RMM) is the average of regional
indicator margins weighted for BP's crude refining capacity in each
region. Each regional marker margin is based on product yields and
a marker crude oil deemed appropriate for the region. The regional
indicator margins may not be representative of the margins achieved
by BP in any period because of BP's particular refinery
configurations and crude and product slate.
Replacement cost (RC) profit or loss reflects the replacement
cost of inventories sold in the period and is arrived at by
excluding inventory holding gains and losses from profit or loss.
RC profit or loss for the group is not a recognized GAAP measure.
BP believes this measure is useful to illustrate to investors the
fact that crude oil and product prices can vary significantly from
period to period and that the impact on our reported result under
IFRS can be significant. Inventory holding gains and losses vary
from period to period due to changes in prices as well as changes
in underlying inventory levels. In order for investors to
understand the operating performance of the group excluding the
impact of price changes on the replacement of inventories, and to
make comparisons of operating performance between reporting
periods, BP's management believes it is helpful to disclose this
measure. The nearest equivalent measure on an IFRS basis is profit
or loss attributable to BP shareholders. A reconciliation to GAAP
information is provided on page 1. RC profit or loss before
interest and tax is the measure of profit or loss that is required
to be disclosed for each operating segment under IFRS.
RC profit or loss per share is a non-GAAP measure. Earnings per
share is defined in Note 9. RC profit or loss per share is
calculated using the same denominator. The numerator used is RC
profit or loss attributable to BP shareholders rather than profit
or loss attributable to BP shareholders. BP believes it is helpful
to disclose the RC profit or loss per share because this measure
excludes the impact of price changes on the replacement of
inventories and allows for more meaningful comparisons between
reporting periods. The nearest equivalent measure on an IFRS basis
is basic earnings per share based on profit or loss for the period
attributable to BP shareholders.
Reported recordable injury frequency measures the number of
reported work-related employee and contractor incidents that result
in a fatality or injury per 200,000 hours worked. 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.
Solomon availability - See Refining availability definition.
Technical service contract (TSC) - Technical service contract is
an arrangement through which an oil and gas company bears the risks
and costs of exploration, development and production. In return,
the oil and gas company receives entitlement to variable physical
volumes of hydrocarbons, representing recovery of the costs
incurred and a profit margin which reflects incremental production
added to the oilfield.
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.
Underlying effective tax rate (ETR) is a 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.
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 - 2020 underlying production, when
compared with 2019, is production after adjusting for acquisitions
and divestments, curtailments, and entitlement impacts in our
production-sharing agreements/contracts and technical service
contract.
Underlying RC profit or loss is RC profit or loss after
adjusting for non-operating items and fair value accounting
effects. Underlying RC profit or loss and adjustments for fair
value accounting effects are not recognized GAAP measures. See
pages 27 and 28 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,
period on period, 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
attributable to BP shareholders. The nearest equivalent measure on
an IFRS basis for segments is RC profit or loss before interest and
taxation. A reconciliation to GAAP information is provided on page
1.
Top of page 35
Glossary (continued)
Underlying RC profit or loss per share is a non-GAAP measure.
Earnings per share is defined in Note 9. Underlying RC profit or
loss per share is calculated using the same denominator. The
numerator used is underlying RC profit or loss attributable to BP
shareholders rather than profit or loss attributable to BP
shareholders. BP believes it is helpful to disclose the underlying
RC profit or loss per share because this measure may help investors
to understand and evaluate, in the same manner as management, the
underlying trends in BP's operational performance on a comparable
basis, period on period. The nearest equivalent measure on an IFRS
basis is basic earnings per share based on profit or loss for the
period attributable to BP shareholders.
Upstream plant reliability (BP-operated) 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 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.
Working capital - Change in working capital is movements in
inventories and other current and non-current assets and
liabilities as reported in the condensed group cash flow statement.
Change in working capital adjusted for inventory holding
gains/losses is a non-GAAP measure. It is calculated by adjusting
for inventory holding gains/losses reported in the period and this
therefore represents what would have been reported as movements in
inventories and other current and non-current assets and
liabilities, if the starting point in determining net cash provided
by operating activities had been replacement cost profit rather
than profit for the period. The nearest equivalent measure on an
IFRS basis for this is movements in inventories and other current
and non-current assets and liabilities. In the context of
describing operating cash flow excluding Gulf of Mexico oil spill
payments, change in working capital also excludes movements in
inventories and other current and non-current assets and
liabilities relating to the Gulf of Mexico oil spill. See page 30
for further details.
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.
Top of page 36
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: The discussion in
this results announcement 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, the following, among other statements,
are all forward looking in nature: the expectations regarding the
COVID-19 pandemic including its risks, impacts, consequences and
challenges and BP's response, including the impact on financial
performance (including cash flows, net debt and gearing),
operations, credit losses, trading environment, oil and gas prices,
global GDP, the shape of the COVID-19 recovery and the pace of
transition to a lower-carbon economy and energy system; plans and
expectations regarding the divestment programme, including reaching
$25 billion of proceeds by 2025 and expectations with respect to
completion of transactions and the timing and amount of proceeds of
agreed disposals (including the expected completion of the sales of
the midstream portion of BP's Alaskan business (including TAPS) to
Hilcorp and BP's petrochemicals business to INEOS); plans and
expectations with respect to the total amount of organic capital
expenditure and the DD&A charge in 2020; plans and expectations
with respect to the total capital expenditure for 2021; plans and
expectations regarding net debt, including to deliver the target of
$35 billion; plans and expectations regarding new joint ventures
and other agreements, including partnerships with Equinor, Police
Scotland, Microsoft, Aberdeen City and Aral in Germany; plans and
expectations regarding BP's priorities, including to focus on
maintaining capital discipline, driving costs down, delivering
divestments and reducing debt while bringing new major projects
onstream; plans to expand the India retail business; expectations
regarding quarterly dividends; expectations regarding demand for
BP's products in the Upstream and Downstream; expectations
regarding the Downstream refining margins and marketing volumes;
expectations regarding BP's future financial performance and cash
flows; plans and expectations with respect to the implementation
and impact of BP's strategic reinvention and redesign of its
organization, including for the organization to be in place by the
start of 2021, the announced reduction of up to 10,000 jobs, and
plans for BP to deliver $2.5 billion in cash cost savings from 2019
to end-2021, and the amount and timing of associated people-related
costs; expectations regarding the underlying effective tax rate in
the fourth quarter of 2020; plans and expectations with respect the
Lightsource BP Bighorn Solar project and BP's ambition to reach
20GW of developed assets by the end of 2025; plans and expectations
regarding Upstream projects, including for five Upstream major
projects to begin production in 2020 and the timing of the Trans
Adriatic Gas pipeline project; expectations regarding Upstream
fourth-quarter 2020 reported and underlying production and
maintenance activity; expectations regarding the timing of
implementation of new accounting policies; expectations regarding
price assumptions used in accounting estimates; expectations
regarding the Other businesses and corporate average quarterly
charges; and expectations with
respect to the timing and amount of future payments relating to
the Gulf of Mexico oil spill. 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 extent and duration of the
impact of current market conditions including the significant drop
in the oil price, the impact of COVID-19, overall global economic
and business conditions impacting our business and demand for our
products as well as the specific factors identified in the
discussions accompanying such forward-looking statements; the
receipt of relevant third party and/or regulatory approvals; the
timing and level of maintenance and/or turnaround activity; the
timing and volume of refinery additions and outages; the timing of
bringing new fields onstream; the timing, quantum and nature of
certain acquisitions and divestments; future levels of industry
product supply, demand and pricing, including supply growth in
North America; OPEC quota restrictions; PSA and TSC effects;
operational and safety problems; potential lapses in product
quality; economic and financial market conditions generally or in
various countries and regions; political stability and economic
growth in relevant areas of the world; changes in laws and
governmental regulations; regulatory or legal actions including the
types of enforcement action pursued and the nature of remedies
sought or imposed; the actions of prosecutors, regulatory
authorities and courts; delays in the processes for resolving
claims; amounts ultimately payable and timing of payments relating
to the Gulf of Mexico oil spill; exchange rate fluctuations;
development and use of new technology; recruitment and retention of
a skilled workforce; the success or otherwise of partnering; the
actions of competitors, trading partners, contractors,
subcontractors, creditors, rating agencies and others; our access
to future credit resources; business disruption and crisis
management; the impact on our reputation of ethical misconduct and
non-compliance with regulatory obligations; trading losses; major
uninsured losses; decisions by Rosneft's management and board of
directors; the actions of contractors; natural disasters and
adverse weather conditions; changes in public expectations and
other changes to business conditions; wars and acts of terrorism;
cyber-attacks or sabotage; and other factors discussed elsewhere in
this report, under "Principal risks and uncertainties" in our
results announcement for the period ended 30 June 2020 and under
"Risk factors" in BP Annual Report and Form 20-F 2019 as filed with
the US Securities and Exchange Commission. 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
extent and duration of the impact of current market conditions
including the significant drop in the oil price, the impact of
COVID-19, overall global economic and business conditions impacting
our business and demand for our products as well as the specific
factors identified in the discussions accompanying such
forward-looking statements; the receipt of relevant third party
and/or regulatory approvals; the timing and level of maintenance
and/or turnaround activity; the timing and volume of refinery
additions and outages; the timing of bringing new fields onstream;
the timing, quantum and nature of certain acquisitions and
divestments; future levels of industry product supply, demand and
pricing, including supply growth in North America; OPEC quota
restrictions; PSA and TSC effects; operational and safety problems;
potential lapses in product quality; economic and financial market
conditions generally or in various countries and regions; political
stability and economic growth in relevant areas of the world;
changes in laws and governmental regulations; regulatory or legal
actions including the types of enforcement action pursued and the
nature of remedies sought or imposed; the actions of prosecutors,
regulatory authorities and courts; delays in the processes for
resolving claims; amounts ultimately payable and timing of payments
relating to the Gulf of Mexico oil spill; exchange rate
fluctuations; development and use of new technology; recruitment
and retention of a skilled workforce; the success or otherwise of
partnering; the actions of competitors, trading partners,
contractors, subcontractors, creditors, rating agencies and others;
our access to future credit resources; business disruption and
crisis management; the impact on our reputation of ethical
misconduct and non-compliance with regulatory obligations; trading
losses; major uninsured losses; decisions by Rosneft's management
and board of directors; the actions of contractors; natural
disasters and adverse weather conditions; changes in public
expectations and other changes to business conditions; wars and
acts of terrorism; cyber-attacks or sabotage; and other factors
discussed elsewhere in this report, under "Principal risks and
uncertainties" in our results announcement for the period ended 30
June 2020 and under "Risk factors" in BP Annual Report and Form
20-F 2019 as filed with the US Securities and Exchange
Commission.
Top of page 37
Contacts
London Houston
Press Office David Nicholas Brett Clanton
+44 (0)20 7496 4708 +1 281 366 8346
Investor Relations Craig Marshall Brian Sullivan
bp.com/investors +44 (0)20 7496 4962 +1 281 892 3421
BP p.l.c.'s LEI Code 213800LH1BZH3D16G760
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