Top of
page 5
Operational updates
Upstream
Upstream
production, which excludes Rosneft, for the nine months of the year
averaged 2,448mboe/d, 6.4% lower than a year earlier. Underlying
production*, for the nine months was slightly lower than 2019
reflecting adverse weather, primarily in the US Gulf of
Mexico.
For the
first nine months of 2020, BP-operated Upstream plant reliability*
was 93.8% and Upstream unit production costs of $6.30/boe were more
than 10% lower than in 2019 reflecting ongoing progress on cost
efficiency in operations, and strategic divestments.
Since
mid-year, BP has started production on the Atlantis Phase 3 project
in the Gulf of Mexico, followed by the Ghazeer gas project, the
second phase of development on Block 61 in Oman, that began
production three months ahead of schedule. These are the first of
five Upstream major projects* expected to begin production in 2020.
BP also brought the Galeota expansion project in Trinidad into
operation during the quarter.
In
September, BP confirmed a gas discovery with the Nidoco NW-1
exploratory well in the Abu Madi West development lease, offshore
Egypt.
The
Trans Adriatic Gas pipeline (TAP) has completed construction and is
expected to soon commence gas exports from Azerbaijan to customers
in Europe.
Downstream
Fuels
marketing earnings for the third quarter were 3% higher than in
2019, benefiting from continued growth in store gross margin,
despite COVID-driven fuel demand impacts.
BP-operated
refining availability continued to be strong, at 96.2% in the
quarter. However, refining margins were extremely weak and refinery
utilization was around 10% below 2019 levels.
Lubricants
saw strong demand recovery in the third quarter, including
year-on-year growth in key markets such as India and
China.
The
sale of BP’s petrochemicals business to INEOS, agreed in
June, remains on track to complete by the end of 2020.
|
Strategic progress
In
September, BP agreed to enter into a strategic partnership with
Equinor to develop offshore wind projects in the US. This includes
the purchase of a 50% interest in two existing wind leases and
associated projects off the east coast of the US. Subject to
customary regulatory and other approvals, the transaction is
expected to close in early 2021.
BP
continued to progress electrification in the quarter with plans
announced in July to build a network of ultra-fast charging points
across Germany, including more than 100 charging points at Aral
retail sites over the next 12 months. BP Chargemaster was recently
awarded a contract by Police Scotland, to deliver more than 1,000
charging points over the next four years.
BP
announced a strategic 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.
BP
announced an agreement to partner with Aberdeen City Council to
help it achieve the goals of its Net Zero Vision to reduce
emissions and become a climate positive city. This follows the
partnership with the City of Houston that BP announced in
July.
Financial framework
Operating cash flow excluding Gulf of Mexico oil spill
payments* was $11.4 billion for the nine months of 2020, compared
with $20.6 billion for the same period in 2019.
Organic capital expenditure* for the nine months of 2020 was
$9.1 billion. BP expects 2020 organic capital expenditure to be
around $12 billion.
Divestment and other proceeds were $2.4 billion for the nine
months of 2020.
Gulf of Mexico oil spill payments on a post-tax basis were
$1.5 billion in the nine months of 2020. Payments for the full year
are expected to 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 2019)
|
|
|
(vs. Nine months 2019)
|
Tier 1 and tier 2 process safety events
|
|
66
|
|
Underlying RC profit (loss)*
|
|
$(5.8)bn
|
|
(-7)
|
|
|
(-$13.2bn)
|
Reported recordable injury frequency*
|
|
0.127
|
|
Operating cash flow excluding Gulf of Mexico oil spill payments
(post-tax)
|
|
$11.4bn
|
|
(-29.2%)
|
|
|
(-$9.2bn)
|
Group production
|
|
3,542mboe/d
|
|
Organic capital expenditure
|
|
$9.1bn
|
|
(-5.7%)
|
|
|
(-$2.2bn)
|
Upstream production (excludes Rosneft segment)
|
|
2,448mboe/d
|
|
Gulf of Mexico oil spill payments (post-tax)
|
|
$1.5bn
|
|
(-6.4%)
|
|
|
(-$1.0bn)
|
Upstream unit production costs(a)
|
|
$6.30/boe
|
|
Divestment proceeds*
|
|
$1.5bn
|
|
(-10.3%)
|
|
|
(+$0.1bn)
|
BP-operated Upstream plant reliability
|
|
93.8%
|
|
Gearing
|
|
33.0%
|
|
(-0.6)
|
|
|
(+1.3)
|
BP-operated refining availability*
|
|
96.0%
|
|
Dividend per ordinary 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.
|
Top of
page 6
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.
|
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
|
$ million
|
|
2020(a)
|
2020
|
2019
|
|
2020(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(a)
|
2020
|
2019
|
|
2020(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
|
$/£ average rate for the period
|
|
1.29
|
|
1.24
|
|
1.23
|
|
|
1.27
|
|
1.27
|
|
$/£ period-end rate
|
|
1.28
|
|
1.23
|
|
1.23
|
|
|
1.28
|
|
1.23
|
|
|
|
|
|
|
|
|
|
$/€ average rate for the period
|
|
1.17
|
|
1.10
|
|
1.11
|
|
|
1.12
|
|
1.12
|
|
$/€ period-end rate
|
|
1.17
|
|
1.12
|
|
1.09
|
|
|
1.17
|
|
1.09
|
|
|
|
|
|
|
|
|
|
Rouble/$ 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
SIGNATURES
Pursuant
to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
|
BP
p.l.c.
|
|
(Registrant)
|
|
|
Dated: 27
October 2020
|
|
|
/s/ Ben
J. S. Mathews
|
|
------------------------
|
|
Ben J.
S. Mathews
|
|
Company
Secretary
|
BP (NYSE:BP)
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