TIDMBP.
RNS Number : 9904Q
BP PLC
02 November 2021
Top of page 1
FOR IMMEDIATE RELEASE
London 2 November 2021
BP p.l.c. Group results
Third quarter and nine months 2021
----------------------------------
"For a printer friendly version of this announcement please
click on the link below to open a PDF version of the
announcement"
http://www.rns-pdf.londonstockexchange.com/rns/9904Q_1-2021-11-1.pdf
Reducing net debt, growing distributions, executing strategy
Financial summary Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
--------------------------------------------- -------- ------- ------- ------- ----------
Profit (loss) for the period attributable
to bp shareholders (2,544) 3,116 (450) 5,239 (21,663)
Inventory holding (gains) losses*, net
of tax (390) (736) (194) (2,468) 2,734
---------------------------------------------- -------- ------- ------- ------- --------
Replacement cost (RC) profit (loss)* (2,934) 2,380 (644) 2,771 (18,929)
Net (favourable) adverse impact of adjusting
items*(a) , net of tax 6,256 418 730 5,979 13,124
---------------------------------------------- -------- ------- ------- ------- --------
Underlying RC profit (loss)* 3,322 2,798 86 8,750 (5,805)
---------------------------------------------- -------- ------- ------- ------- --------
Operating cash flow* 5,976 5,411 5,204 17,496 9,893
----------------------------------------------
Capital expenditure* (2,903) (2,514) (3,636) (9,215) (10,564)
---------------------------------------------- -------- ------- ------- ------- --------
Divestment and other proceeds(b) 313 215 597 5,367 2,413
----------------------------------------------
Net issue (repurchase) of shares (926) (500) - (1,426) (776)
---------------------------------------------- -------- ------- ------- ------- --------
Net debt*(c) 31,971 32,706 40,379 31,971 40,379
----------------------------------------------
Announced dividend per ordinary share
(cents per share) 5.46 5.46 5.25 16.17 21.00
---------------------------------------------- -------- ------- ------- ------- --------
Underlying RC profit (loss) per ordinary
share* (cents) 16.48 13.80 0.42 43.22 (28.72)
---------------------------------------------- -------- ------- ------- ------- --------
Underlying RC profit (loss) per ADS*
(dollars) 0.99 0.83 0.03 2.59 (1.72)
---------------------------------------------- -------- ------- ------- ------- --------
* Strong underlying results and cash flow underpinning * Further $1.25 billion buyback planned - delivering on * Six-year target for major project delivery completed * Continued momentum across strategic focus areas
continued net debt reduction commitment to distributions on schedule and around 15% under-budget
This has been another good quarter for bp - our businesses are generating
strong underlying earnings and cash flow while maintaining their focus
on safe and reliable operations. Rising commodity prices certainly helped,
but I am most pleased that quarter by quarter, we're doing what we said
we would - delivering significant cash to strengthen our finances, grow
distributions to shareholders and invest in our strategic transformation.
This is what we mean by performing while transforming.
Bernard Looney
Chief executive officer
(a) Prior to 2021 adjusting items were reported under two
different headings - non-operating items and fair value accounting
effects*. See page 30 for more information.
(b) Divestment proceeds are disposal proceeds as per the
condensed group cash flow statement. Other proceeds were $675
million from the sale of a 49% interest in a controlled affiliate
holding certain refined product and crude logistics assets onshore
US in the nine months 2021, $481 million in relation to the sale of
an interest in bp's UK retail property portfolio in the third
quarter and nine months 2020 and also $455 million in relation to
TANAP pipeline refinancing in the nine months 2020. There are no
other proceeds in the third quarter 2021.
(c) See Note 9 for more information.
RC profit (loss), underlying RC profit (loss) and net debt are
non-GAAP measures. Inventory holding (gains) losses and adjusting
items are non-GAAP adjustments.
* For items marked with an asterisk throughout this document,
definitions are provided in the Glossary on page 35 .
Top of page 2
Highlights
Strong underlying results and cash flow underpins continued net debt
reduction
* Underlying replacement cost profit* was $3.3 billion,
compared with $2.8 billion for the previous quarter.
This result was driven by higher oil and gas
realizations, higher refining availability and
throughput enabling the capture of a stronger
environment and a stronger gas marketing and trading
result, partly offset by a higher underlying tax
charge.
* Reported loss for the quarter was $2.5 billion,
compared with a $3.1 billion profit for the second
quarter 2021. This was driven by significant adverse
fair value accounting effects* of $6.1 billion
pre-tax, primarily due to the exceptional increase in
forward gas prices towards the end of the quarter.
Under IFRS, reported earnings include the
mark-to-market value of the hedges used to
risk-manage LNG contracts, but not of the LNG
contracts themselves. This mismatch at the end of the
third quarter is expected to unwind if prices decline
and as the cargoes are delivered. The underlying
result is adjusted to remove this mismatch.
* Operating cash flow* of $6.0 billion includes a
working capital* build of $1.8 billion (after
adjusting for inventory holding gains and fair value
accounting effects).
* bp received $5.4 billion of divestment and other
proceeds in the first nine months including $0.3
billion during the third quarter. bp now expects
proceeds of $6-7 billion by the end of 2021.
* Net debt* fell to $32.0 billion at the end of the
third quarter.
Further $1.25 billion share buyback planned - delivering on commitment
to distributions
* bp is committed to the disciplined execution of its
financial frame with a resilient dividend the first
priority. For the third quarter bp has announced a
dividend of 5.46 cents per ordinary share payable in
the fourth quarter - unchanged following the 4%
increase announced with second quarter results.
* With second quarter results, bp announced an
intention to execute a buyback of $1.4 billion from
first half 2021 surplus cash flow* of $2.4 billion.
This programme was completed on 1 November 2021 with
$0.9 billion executed during the third quarter.
* Taking into account the cumulative level of and
outlook for surplus cash flow and subject to
maintaining a strong investment grade credit rating,
the board remains committed to using 60% of 2021
surplus cash flow for share buybacks and plans to
allocate the remaining 40% to continue strengthening
the balance sheet.
* Recognizing third quarter surplus cash flow of $0.9
billion and reflecting confidence in the outlook bp
intends to execute a further buyback of $1.25 billion
prior to announcing its fourth quarter 2021 results.
bp expects to outline plans for the final tranche of
buybacks from 2021 surplus cash flow at the time of
such results.
* On average, based on bp's current forecasts, at
around $60 per barrel Brent and subject to the
board's discretion each quarter, bp continues to
expect to be able to deliver buybacks of around $1.0
billion per quarter and have capacity for an annual
increase in the dividend per ordinary share of around
4% through 2025.
* The board will take into account factors including
the cumulative level of and outlook for surplus cash
flow, the cash balance point* and the maintenance of
a strong investment grade credit rating in setting
the dividend per ordinary share and the buyback each
quarter.
Continued momentum across our strategic focus areas
* In resilient and focused hydrocarbons, bp delivered
its six-year programme of major project* execution,
on average around 15% under-budget, hitting its
target of bringing online 900 thousand barrels oil
equivalent per day of new production by 2021. Six
major projects have now come online in 2021,
including two in the third quarter - Matapal,
offshore Trinidad, under budget and ahead of its 2022
schedule, and Thunder Horse South Expansion Phase 2
in the Gulf of Mexico.
* Operational performance in resilient and focused
hydrocarbons was robust. Relative to the second
quarter, upstream* reported production rose by 4%,
hydrocarbon plant reliability* increased to 95.4% and
refining availability* increased to 95.6%.
* In convenience and mobility, bp delivered record
year-to-date convenience gross margin*; strong growth
in next-gen mobility, with 45% growth in electrons
sold into EV charging compared to last quarter; and
record year-to-date underlying earnings in China, a
key growth market.
* In low carbon, confidence in bp's 2025 target of 20GW
developed renewables to FID* has been strengthened
with a further 2GW added to the renewables pipeline*
and Lightsource bp's announcement of their increased
25GW development target for 2025.
Underpinned by the disciplined execution of our financial frame, we have
delivered another quarter of strong underlying earnings and cash flow.
We are maintaining a resilient dividend, have reduced net debt for the
sixth consecutive quarter, are demonstrating capital discipline and are
delivering on our distribution commitment with a further $1.25 billion
of share buybacks planned.
Murray Auchincloss
Chief financial officer
The commentary above contains forward-looking statements and should be
read in conjunction with the cautionary statement on page 41.
----------------------------------------------------------------------
Top of page 3
Financial results
At 31 December 2020, the group's reportable segments were
Upstream, Downstream and Rosneft. From the first quarter of 2021,
the group's reportable segments are gas & low carbon energy,
oil production & operations, customers & products, and
Rosneft. Comparative information for 2020 has been restated to
reflect the changes in reportable segments. For more information
see note 1 Basis of preparation - Change in segmentation.
In addition to the highlights on page 2:
-- Loss attributable to bp shareholders in the third quarter was
$2,544 million with a profit of $5,239 million for the nine months
compared with losses of $450 million and $21,663 million in the
third quarter and nine months of 2020 respectively. Underlying
replacement cost profits have improved as result of higher oil and
gas prices and refining margins and strong trading results, with
adjusting items* being the other significant driver of the
movements in the loss/profit attributable to bp shareholders.
-- Adjusting items in the third quarter and nine months were an
adverse pre-tax impact of $6,416 million and $5,712 million
respectively compared with an adverse pre-tax impact of $714
million and $16,644 million in the same periods of 2020. The third
quarter and nine months 2021 charges were driven by adverse fair
value accounting effects* of $6,101 million in the third quarter
primarily arising from the exceptional increase in forward gas
prices towards the end of the quarter. The 2020 nine months charge
was primarily driven by net impairment charges of $12,912 million
which were mainly recorded in the second quarter. Pre-tax net
impairment reversals of $2,483 million are included in the nine
months 2021 adjusting items total.
-- Capital expenditure* in the third quarter and nine months was
$2.9 billion and $9.2 billion respectively, compared with $3.6
billion and $10.6 billion in the same periods of 2020.
-- At the end of the third quarter, net debt* was $32.0 billion,
compared to $32.7 billion at the end of the second quarter 2021 and
$40.4 billion at the end of the third quarter 2020.
-- Operating cash flow* was $6.0 billion for the third quarter,
and $17.5 billion for the nine months, compared with $5.2 billion
and $9.9 billion for the same periods of 2020. Third quarter and
nine months 2021 includes $0.1 billion and $0.8 billion
respectively of cash flow relating to severance costs associated
with the reinvent programme.
-- The effective tax rate (ETR) on RC profit or loss* for the
third quarter and nine months was -175% and 57% respectively,
compared with -504% and 13% for the same periods in 2020. Excluding
adjusting items*, the underlying ETR* for the third quarter and
nine months was 35% and 31% respectively, compared with 64% and
-10% for the same periods a year ago. The lower underlying ETR for
the third quarter reflects changes in the geographical mix of
profits. The underlying ETR for the nine months is higher than the
same period a year ago due to the absence of the exploration
write-offs with a limited deferred tax benefit and the reassessment
of deferred tax asset recognition. ETR on RC profit or loss and
underlying ETR are non-GAAP measures.
Analysis of RC profit (loss) before interest and tax and
reconciliation to profit (loss) for the period
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
-------------------------------------------------- ------- ------- ------- ------- ----------
RC profit (loss) before interest and
tax
gas & low carbon energy (4,135) 927 252 222 (6,430)
oil production & operations 2,692 3,118 (156) 7,289 (14,649)
customers & products 1,060 640 915 2,634 2,173
Rosneft 868 643 (278) 1,874 (419)
other businesses & corporate (750) (425) (42) (1,853) (867)
Consolidation adjustment - UPII* (42) (31) 34 (60) 166
--------------------------------------------------- ------- ------- ------- ------- --------
RC profit (loss) before interest and
tax (307) 4,872 725 10,106 (20,026)
Finance costs and net finance expense
relating to pensions and other post-retirement
benefits (688) (687) (808) (2,104) (2,389)
Taxation on a RC basis (1,740) (1,567) (418) (4,561) 2,935
Non-controlling interests (199) (238) (143) (670) 551
--------------------------------------------------- ------- ------- ------- ------- --------
RC profit (loss) attributable to bp shareholders* (2,934) 2,380 (644) 2,771 (18,929)
Inventory holding gains (losses)* 500 953 233 3,183 (3,563)
Taxation (charge) credit on inventory
holding gains and losses (110) (217) (39) (715) 829
--------------------------------------------------- ------- ------- ------- ------- --------
Profit (loss) for the period attributable
to bp shareholders (2,544) 3,116 (450) 5,239 (21,663)
--------------------------------------------------- ------- ------- ------- ------- --------
Top of page 4
Analysis of underlying RC profit (loss) before interest and
tax
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
------------------------------------------------ ------- ------- ------- ------- ---------
Underlying RC profit (loss) before interest
and tax
gas & low carbon energy 1,807 1,240 502 5,317 535
oil production & operations 2,461 2,242 367 6,268 (6,451)
customers & products 1,158 827 636 2,641 2,962
Rosneft 923 689 (177) 1,975 (255)
other businesses & corporate (373) (305) (121) (848) (773)
Consolidation adjustment - UPII (42) (31) 34 (60) 166
------------------------------------------------- ------- ------- ------- ------- -------
Underlying RC profit (loss) before interest
and tax 5,934 4,662 1,241 15,293 (3,816)
Finance costs and net finance expense
relating to pensions and other post-retirement
benefits (513) (485) (610) (1,579) (1,955)
Taxation on an underlying RC basis (1,900) (1,141) (402) (4,294) (585)
Non-controlling interests (199) (238) (143) (670) 551
------------------------------------------------- ------- ------- ------- ------- -------
Underlying RC profit (loss) attributable
to bp shareholders* 3,322 2,798 86 8,750 (5,805)
------------------------------------------------- ------- ------- ------- ------- -------
Reconciliations of underlying RC profit attributable to bp
shareholders to the nearest equivalent IFRS measure are provided on
page 1 for the group and on pages 6-14 for the segments.
Operating Metrics
Operating metrics Nine months vs Nine
2021 months 2020
------------------------------------------------ ----------- ------------
Tier 1 and tier 2 process safety events* 49 -16
Reported recordable injury frequency* 0.145 +15.4%
Group production (mboe/d)(a) 3,269 -7.7%
upstream* production (mboe/d) (excludes Rosneft
segment) 2,180 -10.9%
upstream unit production costs*(b) ($/boe) 6.96 +10.4%
bp-operated hydrocarbon plant reliability* 94.3% +0.5
bp-operated refining availability*(a) 94.6% -1.4
------------------------------------------------- ----------- ------------
(a) See Operational updates on pages 6, 8 and 10.
(b) Reflecting lower volumes and higher costs including phasing impacts.
Top of page 5
Outlook & Guidance
Macro outlook
-- Oil prices have continued to increase, and inventories have
reduced back towards pre-pandemic levels. We expect oil prices to
be supported by continued inventory draw-down, with the potential
for additional demand from gas to oil switching.
-- OPEC+ decision making on production levels continues to be a
key factor in oil prices and market rebalancing.
-- Gas markets were very strong in the quarter and we expect
they will remain tight during the period of peak winter demand.
-- In the fourth quarter industry refining margins are expected
to be lower compared to the third quarter driven by seasonal
demand.
4Q21 guidance
-- Looking ahead, we expect fourth quarter reported upstream*
production to be higher than the third quarter reflecting major
project* ramp-up, mainly in gas regions, recovery from seasonal
maintenance activity and continuing impacts from Hurricane Ida on
our non-operated production in the US Gulf of Mexico. Within this,
we expect production from both oil production & operations and
gas & low carbon to be higher.
-- In our customer businesses, we expect lower product demand
due to seasonal impacts and continued base oil tightness and
additive supply shortages in Castrol. In products, refining margins
are expected to be lower in the fourth quarter driven by seasonal
demand and we expect energy prices to remain under pressure and
maintenance activity to remain high.
2021 Guidance
In addition to the guidance on page 2:
-- We now expect divestment and other proceeds for the year of
$6-7 billion. Our target of $25 billion of divestment and other
proceeds between the second half of 2020 and 2025 is now
underpinned by agreed or completed transactions of around $15.2
billion with over $10 billion of proceeds received.
-- The underlying ETR* for 2021 is now expected to be below 35%
but is sensitive to the impact that volatility in the current price
environment may have on the geographical mix of the group's profits
and losses.
-- For full year 2021 we continue to expect reported upstream
production to be lower than 2020 due to the impact of the ongoing
divestment programme. However, we expect upstream underlying
production* to be slightly higher than 2020 with the ramp-up of
major projects, primarily in gas regions, partly offset by the
impacts of reduced capital investment and decline in lower-margin
gas assets.
-- bp continues to expect capital expenditure*, including
inorganic capital expenditure*, of around $13 billion in 2021.
-- Depreciation, depletion and amortization is still expected to
be at a similar level to 2020.
-- Gulf of Mexico oil spill payments for the year are still
expected to be around $1.5 billion pre-tax.
-- The other businesses & corporate underlying annual charge
is still expected to be in the range of $1.2-1.4 billion for 2021.
The quarterly charges may vary from quarter to quarter.
COVID-19 Update
-- bp's future financial performance, including cash flows and
net debt, will be impacted by the extent and duration of the
current market conditions and the effectiveness of the actions that
it and others take, including its financial interventions. It is
difficult to predict when all current supply and demand imbalances
will be resolved and what the ultimate impact of COVID-19 will
be.
-- bp continues to take steps to protect and support its staff
through the pandemic. Precautions in operations and offices
together with enhanced support and guidance to staff continue with
a focus on safety, health and hygiene, homeworking and mental
health. Decisions on working practices and return to office based
working are being taken with caution and in compliance with local
and national guidelines and regulations.
The commentary above contains forward-looking statements and should be
read in conjunction with the cautionary statement on page 41.
----------------------------------------------------------------------
Top of page 6
gas & low carbon energy
Financial results
-- The replacement cost loss before interest and tax for the
third quarter and profit for the nine months was $4,135 million and
$222 million respectively, compared with a profit of $252 million
and a loss of $6,430 million for the same periods in 2020. The
third quarter and nine months included an adverse impact of net
adjusting items* of $5,942 million and $5,095 million respectively,
compared with an adverse impact of net adjusting items of $250
million and $6,965 million for the same periods in 2020.
-- After excluding adjusting items, the underlying replacement
cost profit before interest and tax* for the third quarter and nine
months was $1,807 million and $5,317 million respectively, compared
with a profit of $502 million and $535 million for the same periods
in 2020. Adjusting items* include adverse fair value accounting
effects* of $5,808 million, primarily arising from the exceptional
increase in forward gas prices towards the end of the quarter.
Under IFRS, reported earnings include the mark-to-market value of
the hedges used to risk-manage forward LNG contracts, but not of
the LNG contracts themselves. This mismatch at the end of the third
quarter is expected to unwind if prices decline and as the cargoes
are delivered. The underlying result is adjusted to remove this
mismatch.
-- The underlying replacement cost profit for the third quarter,
compared with the same period in 2020, reflects higher
realizations, the higher depreciation, depletion and amortization
charge, and the very strong trading result. For the nine months,
compared with the same period in 2020, the underlying replacement
cost profit mainly reflects higher realizations, the higher
depreciation, depletion and amortization charge, lower exploration
write-offs and the exceptional trading result.
Operational update
-- Reported production for the quarter and nine months were
889mboe/d and 891mboe/d respectively, higher than the same periods
in 2020 due to growth in underlying production*, partly offset by
the partial divestment in Oman. Underlying production was higher,
mainly due to major project* start-ups, partially offset by base
decline.
-- Renewables pipeline* at the end of the quarter was 23GW (bp
net). The renewables pipeline grew by 2GW (bp net) in the quarter
due to increases in Lightsource bp's (LSbp's) pipeline and 12.1GW
(bp net) in the nine months, as a result of growth in LSbp and the
acquisition of a 9GW development pipeline from 7X Energy.
Strategic progress
gas
-- On 20 September, bp Trinidad and Tobago announced that its
Matapal subsea gas development safely achieved first gas seven
months ahead of schedule and under budget.
-- On 16 September, Gas Natural Açu (GNA), a joint venture
between bp, Prumo, Siemens and SPIC Brasil, announced the start of
commercial operations at GNA I, a LNG to power thermoelectric plant
located in Porto do Açu, Rio de Janeiro, Brazil. The project has a
1.3GW capacity.
-- On 6 September, bp Singapore announced its first carbon
offset LNG cargo had been delivered to CPC Corporation, Taiwan,
sourced from bp's LNG portfolio.
-- On 7 October, bp China signed a 10-year pipeline gas supply
agreement with Shenzhen Gas. Starting in 2023, bp has agreed to
provide up to 300,000 tonnes per year of pipeline gas. The supply
will be re-gasified through Guangdong Dapeng LNG's receiving
terminal, in which bp has a 30% stake.
low carbon energy
-- On 20 September, Lightsource bp announced its new global
growth strategy of developing 25GW of solar projects by 2025.
-- On 16 September, bp announced a strategic partnership with
ADNOC and Masdar. Through this partnership we aim to jointly
develop a range of low carbon energy projects, including the
development of green and blue hydrogen hubs.
-- On 19 October, the East Coast Cluster was selected as one of
the UK's first two carbon capture and storage projects by the UK
government. The East Coast Cluster is enabled by the Northern
Endurance Partnership - a collaboration between bp, Eni, Equinor,
National Grid, Shell and Total, with bp as operator.
-- On 7 July, bp closed its transaction with US solar developer
7X Energy to acquire 9GW of solar development projects. Projects
with a combined generating capacity of 2.2GW are expected to reach
final investment decision (FID) by 2025, with further projects
expected to progress by 2030.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
--------------------------------------------- ------- ------- ------- ------- ---------
Profit (loss) before interest and tax (4,120) 931 259 263 (6,421)
Inventory holding (gains) losses* (15) (4) (7) (41) (9)
---------------------------------------------- ------- ------- ------- ------- -------
RC profit (loss) before interest and tax (4,135) 927 252 222 (6,430)
Net (favourable) adverse impact of adjusting
items 5,942 313 250 5,095 6,965
---------------------------------------------- ------- ------- ------- ------- -------
Underlying RC profit (loss) before interest
and tax 1,807 1,240 502 5,317 535
Taxation on an underlying RC basis (389) (244) (249) (1,168) (621)
---------------------------------------------- ------- ------- ------- ------- -------
Underlying RC profit (loss) before interest 1,418 996 253 4,149 (86)
---------------------------------------------- ------- ------- ------- ------- -------
Top of page 7
gas & low carbon energy (continued)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
----------------------------------------------- ------- ------- ------- ------ --------
Depreciation, depletion and amortization
Total depreciation, depletion and amortization 1,230 1,115 746 3,199 2,736
------------------------------------------------ ------- ------- ------- ------ ------
Exploration write-offs
----------------------------------------------- ------- ------- ------- ------ --------
Exploration write-offs(a) 14 21 65 41 1,699
------------------------------------------------ ------- ------- ------- ------ ------
Adjusted EBITDA*
----------------------------------------------- ------- ------- ------- ------ --------
Total adjusted EBITDA 3,051 2,376 1,311 8,557 4,300
------------------------------------------------ ------- ------- ------- ------ ------
Capital expenditure*
gas 736 705 892 2,252 3,083
low carbon energy(b) 336 42 43 1,452 55
------------------------------------------------ ------- ------- ------- ------ ------
Total capital expenditure 1,072 747 935 3,704 3,138
------------------------------------------------ ------- ------- ------- ------ ------
(a) Third quarter and nine months 2020 include a write-off of $2
million and $670 million respectively, which have been classified
within the 'other' category of adjusting items.
(b) Nine months 2021 includes $712 million in respect of the
remaining payment to Equinor for our investment in our strategic US
offshore wind partnership and $326 million as a lease option fee
deposit paid to The Crown Estate in connection with our
participation in the UK Round 4 Offshore Wind Leasing together with
our partner EnBW.
Third Second Third Nine Nine
quarter quarter quarter months months
2021 2021 2020 2021 2020
--------------------------------- ------- ------- ------- ------ --------
Production (net of royalties)(c)
Liquids* (mb/d) 109 109 92 110 96
Natural gas (mmcf/d) 4,520 4,440 4,343 4,527 4,490
Total hydrocarbons* (mboe/d) 889 875 841 891 870
---------------------------------- ------- ------- ------- ------ ------
Average realizations* (d)
Liquids ($/bbl) 66.39 61.69 37.77 61.11 35.41
Natural gas ($/mcf) 5.26 4.14 2.99 4.44 3.21
Total hydrocarbons* ($/boe) 34.91 28.97 19.64 30.21 20.55
---------------------------------- ------- ------- ------- ------ ------
(c) Includes bp's share of production of equity-accounted
entities in the gas & low carbon energy segment.
(d) Realizations are based on sales by consolidated subsidiaries
only - this excludes equity-accounted entities.
Third Second Third Nine Nine
quarter quarter quarter months months
low carbon energy 2021 2021 2020 2021 2020
Renewables (bp net, GW)
Installed renewables capacity* 1.7 1.6 1.2 1.7 1.2
--------------------------------------- ------- ------- ------- ------ ------
Developed renewables to FID*(e) 3.6 3.5 3.1 3.6 3.1
Renewables pipeline 23.3 21.2 23.3
of which by geographical area:
-------------------------------------- ------- ------- ------- ------ --------
Renewables pipeline - Americas 16.8 15.3 16.8
Renewables pipeline - Asia Pacific 1.1 0.8 1.1
Renewables pipeline - Europe 5.2 5.1 5.2
Renewables pipeline - Other 0.2 - 0.2
--------------------------------------- ------- ------- ------- ------ --------
of which by technology:
-------------------------------------- ------- ------- ------- ------ --------
Renewables pipeline - offshore wind 3.7 3.7 3.7
Renewables pipeline - solar 19.6 17.5 19.6
--------------------------------------- ------- ------- ------- ------ --------
Total Developed renewables to FID and
Renewables pipeline(e) 26.9 24.7 26.9
--------------------------------------- ------- ------- ------- ------ --------
(e) An amendment of 0.2GW has been made to the amount presented
for the second quarter 2021 (previously Developed renewables to FID
3.7GW.)
Top of page 8
oil production & operations
Financial results
-- The replacement cost profit before interest and tax for the
third quarter and nine months was $2,692 million and $7,289 million
respectively, compared with a loss of $156 million and $14,649
million for the same periods in 2020. The third quarter and nine
months includes a favourable impact of net adjusting items* of $231
million and $1,021 million respectively, compared with an adverse
impact of net adjusting items of $523 million and $8,198 million
for the same periods in 2020.
-- After excluding adjusting items, the underlying replacement
cost profit before interest and tax* for the third quarter and nine
months was $2,461 million and $6,268 million respectively, compared
with a profit of $367 million and a loss of $6,451 million for the
same periods in 2020.
-- The underlying replacement cost profit for the third quarter,
compared with the same period in 2020, primarily reflects higher
liquids and gas realizations. For the nine months, compared with
the same period in 2020, the underlying replacement cost profit
mainly reflects higher liquids and gas realizations, significantly
lower exploration write-offs, and lower volumes.
Operational update
-- Reported production for the quarter was 1,313mboe/d, 6.3%
lower than the third quarter of 2020. This includes price impacts
on PSA* and TSC* entitlement volumes and the impact of BPX Energy
divestments. Underlying production* for the quarter was flat
reflecting major project* ramp-up offset by impacts from reduced
capital investment, decline and weather impacts in the US Gulf of
Mexico.
-- Reported production for the nine months was 1,289mboe/d,
18.3% lower than the same period in 2020. This includes price
impacts on PSA and TSC entitlement volumes and the impact of
divestments in Alaska and BPX Energy. Underlying production for the
nine months decreased by 6.1% mainly due to impacts from reduced
capital investment and decline.
Strategic progress
-- On 28 September, bp announced the start-up of its Thunder
Horse South Expansion Phase 2 project in the deepwater Gulf of
Mexico (bp 75% operator, ExxonMobil 25%).
-- On 29 September, bp announced it has agreed to sell a 25%
participating interest in the Shallow Water Absheron Peninsula
(SWAP) exploration project in the Azerbaijan sector of the Caspian
Sea to LUKOIL. Subject to approval, the transaction, with an
effective date of 1 July 2021, is expected to complete in the
fourth quarter of 2021, following which the participating interests
will be: SOCAR Oil Affiliate 50%, bp operator 25% and LUKOIL
25%.
-- Furthermore, Yermak IJV (Rosneft 51%, bp 49%) secured access to two new license blocks, Khoshgortyeganskiy and Kharayeganskiy, in the established West Siberia basin.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
--------------------------------------------- ------- ------- ------- ------- ----------
Profit (loss) before interest and tax 2,691 3,112 (155) 7,297 (14,661)
Inventory holding (gains) losses* 1 6 (1) (8) 12
---------------------------------------------- ------- ------- ------- ------- --------
RC profit (loss) before interest and
tax 2,692 3,118 (156) 7,289 (14,649)
Net (favourable) adverse impact of adjusting
items (231) (876) 523 (1,021) 8,198
---------------------------------------------- ------- ------- ------- ------- --------
Underlying RC profit (loss) before interest
and tax 2,461 2,242 367 6,268 (6,451)
Taxation on an underlying RC basis (1,220) (939) (247) (2,888) 345
---------------------------------------------- ------- ------- ------- ------- --------
Underlying RC profit (loss) before interest 1,241 1,303 120 3,380 (6,106)
---------------------------------------------- ------- ------- ------- ------- --------
Top of page 9
oil production & operations (continued)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
----------------------------------------------- ------- ------- ------- ------ --------
Depreciation, depletion and amortization
----------------------------------------------- ------- ------- ------- ------ --------
Total depreciation, depletion and amortization 1,767 1,559 1,814 4,900 6,001
------------------------------------------------ ------- ------- ------- ------ ------
Exploration write-offs
----------------------------------------------- ------- ------- ------- ------ --------
Exploration write-offs(a) 16 8 (15) 80 8,067
------------------------------------------------ ------- ------- ------- ------ ------
Adjusted EBITDA*
----------------------------------------------- ------- ------- ------- ------ --------
Total adjusted EBITDA 4,244 3,809 2,166 11,248 6,316
------------------------------------------------ ------- ------- ------- ------ ------
Capital expenditure*
----------------------------------------------- ------- ------- ------- ------ --------
Total capital expenditure 1,099 1,148 1,117 3,566 4,696
------------------------------------------------ ------- ------- ------- ------ ------
(a) Nine months 2020 includes a write-off of $1,301 million
which has been classified within the 'other' category of adjusting
items.
Third Second Third Nine Nine
quarter quarter quarter months months
2021 2021 2020 2021 2020
--------------------------------- ------- ------- ------- ------ --------
Production (net of royalties)(b)
Liquids* (mb/d) 975 938 1,037 970 1,171
Natural gas (mmcf/d) 1,961 1,786 2,115 1,853 2,365
Total hydrocarbons* (mboe/d) 1,313 1,245 1,402 1,289 1,578
---------------------------------- ------- ------- ------- ------ ------
Average realizations* (c)
Liquids ($/bbl) 65.53 60.55 38.21 59.60 35.52
Natural gas ($/mcf) 5.61 3.90 1.42 4.59 1.31
Total hydrocarbons* ($/boe) 57.72 52.47 31.21 52.35 28.94
---------------------------------- ------- ------- ------- ------ ------
(b) Includes bp's share of production of equity-accounted
entities in the oil production & operations segment.
(c) Realizations are based on sales by consolidated subsidiaries
only - this excludes equity-accounted entities.
Top of page 10
customers & products
Financial results
-- The replacement cost profit before interest and tax for the
third quarter and nine months was $1,060 million and $2,634 million
respectively, compared with $915 million and $2,173 million for the
same periods in 2020. The third quarter and nine months included an
adverse impact of net adjusting items* of $98 million and $7
million respectively, compared with a favourable impact of net
adjusting items of $279 million and an adverse impact of net
adjusting items of $789 million for the same periods in 2020.
-- After excluding adjusting items, the underlying replacement
cost profit before interest and tax* for the third quarter and nine
months was $1,158 million and $2,641 million respectively, compared
with $636 million and $2,962 million for the same periods in
2020.
-- The customers & products result for the third quarter
reflects a materially stronger performance, nearly double that of
last year, primarily driven by a stronger refining environment. The
result for the nine months, reflects a stronger customers
performance, more than offset by a lower trading result in products
and absence of earnings from our divested petrochemicals
business.
-- customers - convenience and mobility results, excluding
Castrol, for the quarter and nine months demonstrated resilient
performance, albeit with lower earnings than the same periods last
year. These results were supported by higher volumes and resilient
fuel margins despite rising crude prices, as well as strong
convenience performance, with record year-to-date gross margin*.
Costs for both periods were higher in support of the re-opening of
some markets following COVID and increased digital and marketing
expenditure underpinning our growth agenda.
Castrol results in the quarter were lower than last year, with
industry base oil prices more than doubling and severe lockdown
restrictions in place across key Asian markets. For the nine months
performance was strong, with volumes and earnings materially higher
than the same period in 2020, and with China delivering record
underlying earnings.
-- products - the products result for the quarter was materially
stronger than last year, with higher results in both refining and
trading. The result for the nine months was lower than last year
due to an exceptionally strong trading performance in the second
quarter of last year. In refining the result for the quarter and
the nine months was stronger due to higher utilization, which
enabled the capture of improved realized refining margins. This was
partially offset by a higher level of turnaround and maintenance
activity and increased energy prices.
Operational update
-- Utilization for the quarter was around 9 percentage points
higher than the same period last year due to lower COVID related
demand impacts. bp-operated refining availability* for the third
quarter and nine months was 95.6% and 94.6% respectively, lower
compared with 96.2% and 96.0% for the same periods last year, due
to a higher level of maintenance activity.
Strategic progress
-- In support of our strategic agenda to redefine convenience,
we have grown our strategic convenience sites* to 2,050 at the end
of the third quarter. Additionally, we have:
expanded our convenience partnership model with Albert Heijn,
the leading supermarket chain in the Netherlands, with plans to
roll out a new exclusive food-to-go offer to more than 100 retail
sites by the end of next year;
completed the transaction to take full ownership of the
Thorntons business, positioning bp to be a leading convenience
operator in the Midwest US.
-- In next-gen mobility, nearly half of our network is now
either rapid or ultra-fast charging and in the quarter we delivered
45% growth in electrons sold compared to the prior quarter. In
addition, in October, our investment with Daimler and BMW in
Digital Charging Solutions completed.
-- In growth markets, our fuels and mobility joint venture in
India with Reliance, Jio-bp, opened their first mobility station in
October. The site has a fully-integrated customer offer, including
high-quality additivised fuels, EV charging points, tailored
convenience offers, as well as our Castrol products and services.
Jio-bp also announced an agreement with EV demand partner, Swiggy,
a leading food delivery company, to roll out a network of battery
swap stations.
-- In Castrol, our market leading position in advanced e-fluids,
Castrol ON, was further strengthened with more than two-thirds of
the world's major vehicle manufacturers(a) having now approved
Castrol ON products as part of their factory fill.
-- In refining:
we announced plans to invest $270 million at the Cherry Point
refinery in the US, to improve efficiency, reduce CO emissions and
increase its renewable diesel production capability;
bp Castellón in Spain, was the first refinery in the world to
receive accreditation from the Carbon Offsetting and Reduction
Scheme for International Aviation (CORSIA) for the production of
sustainable fuel for aviation.
(a) Based on LMCA data for top 20 selling OEMs (total new car sales) in 2019.
Top of page 11
customers & products (continued)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
--------------------------------------------- ------- ------- ------- ------- ---------
Profit (loss) before interest and tax 1,511 1,527 1,106 5,577 (1,273)
Inventory holding (gains) losses* (451) (887) (191) (2,943) 3,446
---------------------------------------------- ------- ------- ------- ------- -------
RC profit before interest and tax 1,060 640 915 2,634 2,173
Net (favourable) adverse impact of adjusting
items 98 187 (279) 7 789
---------------------------------------------- ------- ------- ------- ------- -------
Underlying RC profit before interest
and tax 1,158 827 636 2,641 2,962
Of which:(a)
customers - convenience & mobility 806 951 1,081 2,415 2,201
Castrol - included in customers 231 265 326 830 556
products - refining & trading 352 (124) (533) 226 561
petrochemicals - - 88 - 200
---------------------------------------------- ------- ------- ------- ------- -------
Taxation on an underlying RC basis (314) (123) (51) (570) (637)
---------------------------------------------- ------- ------- ------- ------- -------
Underlying RC profit before interest 844 704 585 2,071 2,325
---------------------------------------------- ------- ------- ------- ------- -------
(a) A reconciliation to RC profit before interest and tax by business is provided on page 33.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
----------------------------------------------- ------- ------- ------- ------ --------
Adjusted EBITDA*(b)
customers - convenience & mobility 1,130 1,280 1,387 3,392 3,077
Castrol - included in customers 267 304 364 944 675
products - refining & trading 775 301 (98) 1,495 1,825
petrochemicals - - 90 - 302
------------------------------------------------ ------- ------- ------- ------ ------
1,905 1,581 1,379 4,887 5,204
------- ------- ------- ------ ------
Depreciation, depletion and amortization
----------------------------------------------- ------- ------- ------- ------ --------
Total depreciation, depletion and amortization 747 754 743 2,246 2,242
------------------------------------------------ ------- ------- ------- ------ ------
Capital expenditure*
customers - convenience & mobility 301 255 1,266 872 1,756
Castrol - included in customers 37 42 33 120 104
products - refining & trading 296 264 244 776 702
petrochemicals - - 9 - 87
------------------------------------------------ ------- ------- ------- ------ ------
Total capital expenditure 597 519 1,519 1,648 2,545
------------------------------------------------ ------- ------- ------- ------ ------
(b) A reconciliation to RC profit before interest and tax by business is provided on page 33.
Retail(c) Third Second Third Nine Nine
quarter quarter quarter months months
2021 2021 2020 2021 2020
------------------------------------- ------- ------- ------- ------ --------
bp retail sites* - total (#) 20,350 20,300 20,550 20,350 20,550
bp retail sites in growth markets* 2,650 2,700 2,700 2,650 2,700
Strategic convenience sites* 2,050 2,000 1,900 2,050 1,900
-------------------------------------- ------- ------- ------- ------ ------
(c) Reported to the nearest 50.
Marketing sales of refined products (mb/d) Third Second Third Nine Nine
quarter quarter quarter months months
2021 2021 2020 2021 2020
-------------------------------------------- ------- ------- ------- ------ --------
US 1,161 1,131 1,083 1,103 997
Europe 968 838 849 838 830
Rest of World 439 469 422 450 435
--------------------------------------------- ------- ------- ------- ------ ------
2,568 2,438 2,354 2,391 2,262
Trading/supply sales of refined products(d) 425 415 435 392 432
--------------------------------------------- ------- ------- ------- ------ ------
Total sales volume of refined products 2,993 2,853 2,789 2,783 2,694
--------------------------------------------- ------- ------- ------- ------ ------
(d) Comparative information for 2020 has been restated for the
changes to net presentation of revenues and purchases relating to
physically settled derivative contracts effective 1 January 2021.
For more information see Note 1 basis of preparation - Voluntary
change in accounting policy.
Top of page 12
customers & products (continued)
Refining marker margin*(a) Third Second Third Nine Nine
quarter quarter quarter months months
2021 2021 2020 2021 2020
---------------------------------------- ------- ------- ------- ------ --------
bp average refining marker margin (RMM)
($/bbl) 15.2 13.7 6.2 12.6 7.0
----------------------------------------- ------- ------- ------- ------ ------
(a) In 2021 the RMM has been updated to reflect changes in bp's
portfolio, and the update of crude reference for Mediterranean
region. On this basis the third quarter and nine months 2020 RMM
would be $6.4/bbl and $7.1/bbl respectively.
Refinery throughputs - operated refineries
(mb/d) Third Second Third Nine Nine
quarter quarter quarter months months
2021 2021 2020 2021 2020
------------------------------------------- ------- ------- ------- ------ --------
US 737 692 701 719 687
Europe 804 763 699 771 750
Rest of World 81 52 187 87 189
-------------------------------------------- ------- ------- ------- ------ ------
Total refinery throughputs 1,622 1,507 1,587 1,577 1,626
-------------------------------------------- ------- ------- ------- ------ ------
bp-operated refining availability* (%) 95.6 93.5 96.2 94.6 96.0
-------------------------------------------- ------- ------- ------- ------ ------
Top of page 13
Rosneft
Financial results
-- The replacement cost (RC) profit before interest and tax for
the third quarter and nine months was $868 million and $1,874
million respectively, compared with a loss of $278 million and $419
million for the same periods in 2020. The third quarter and nine
months included an adverse impact of net adjusting items* of $55
million and $101 million respectively, compared with an adverse
impact of net adjusting items of $101 million and $164 million for
the same periods in 2020.
-- After excluding adjusting items, the underlying RC profit
before interest and tax* for the third quarter and nine months was
$923 million and $1,975 million respectively, compared with a loss
of $177 million and $255 million for the same periods in 2020.
-- Compared with the same periods in 2020, the results for the
third quarter and nine months primarily reflect higher oil prices
and favourable foreign exchange effects.
-- The extraordinary general meeting held on 30 September
adopted a resolution to pay interim dividends of 18.03 roubles per
ordinary share which constitute 50% of Rosneft's IFRS net profit
for the first half of 2021. bp expects to receive dividends of 34
billion roubles (net of withholding tax) in the fourth quarter.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021(a) 2021 2020 2021(a) 2020
--------------------------------------------- ------- ------- ------- ------- --------
Profit (loss) before interest and tax(b)(c) 903 711 (244) 2,065 (533)
Inventory holding (gains) losses* (35) (68) (34) (191) 114
---------------------------------------------- ------- ------- ------- ------- ------
RC profit (loss) before interest and
tax 868 643 (278) 1,874 (419)
Net (favourable) adverse impact of adjusting
items 55 46 101 101 164
---------------------------------------------- ------- ------- ------- ------- ------
Underlying RC profit (loss) before interest
and tax 923 689 (177) 1,975 (255)
Taxation on an underlying RC basis (93) (68) 17 (196) 28
---------------------------------------------- ------- ------- ------- ------- ------
Underlying RC profit (loss) before interest 830 621 (160) 1,779 (227)
---------------------------------------------- ------- ------- ------- ------- ------
Third Second Third Nine Nine
quarter quarter quarter months months
2021(a) 2021 2020 2021(a) 2020
-------------------------------------------- ------- ------- ------- ------- --------
Production: Hydrocarbons (net of royalties,
bp share)
Liquids* (mb/d) 876 858 858 854 877
Natural gas (mmcf/d) 1,418 1,374 1,260 1,363 1,261
Total hydrocarbons* (mboe/d) 1,120 1,095 1,075 1,089 1,094
--------------------------------------------- ------- ------- ------- ------- ------
(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 2021. Actual
results may differ from these amounts. Amounts reported for the
third quarter are based on bp's 22.03% average economic interest
for the quarter (second quarter 2021 22.03% and third quarter 2020
21.96%).
(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 14
other businesses & corporate
Other businesses & corporate comprises our innovation &
engineering business including bp ventures and Launchpad, regions,
cities & solutions, our corporate activities & functions
and any residual costs of the Gulf of Mexico oil spill.
Financial results
-- The replacement cost loss before interest and tax for the
third quarter and nine months was $750 million and $1,853 million
respectively, compared with $42 million and $867 million for the
same periods in 2020. The third quarter and nine months included an
adverse impact of net adjusting items* of $377 million and $1,005
million respectively, including $263 million and $637 million of
adverse fair value accounting effects* respectively, compared with
a favourable impact of net adjusting items of $79 million and an
adverse impact of net adjusting items of $94 million, including
$266 million and $225 million of favourable fair value accounting
effects respectively, for the same periods in 2020.
-- After excluding adjusting items*, the underlying replacement
cost loss before interest and tax* for the third quarter and nine
months was $373 million and $848 million respectively, compared
with $121 million and $773 million for the same periods in 2020,
reflecting foreign exchange and employee cost impacts.
Strategic progress
-- bp and NYK Line signed a memorandum of understanding on 24
August to collaborate on future fuels and transportation solutions
to help industrial sectors, including shipping, decarbonize.
-- On 2 September, bp Launchpad acquired Blueprint Power
(Blueprint), a US-based company whose technology is focused on
optimizing the power networks of buildings by connecting them to
energy markets through cloud-based software. Blueprint's technology
presents an opportunity to help decarbonize commercial real estate,
help real estate owners meet their environmental goals and give
them access to new revenue streams.
-- On 24 September, bp ventures led a $25 million investment
round in all-electric ride hailing & EV charging start-up
BluSmart. BluSmart is India's first and largest integrated EV
ride-hailing and charging service. BluSmart intends to use the
capital to expand its fleet of electric vehicles and charging
stations in its home city of Delhi and into five additional Indian
cities in the next two years.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
--------------------------------------------- ------- ------- ------- ------- --------
Profit (loss) before interest and tax (750) (425) (42) (1,853) (867)
Inventory holding (gains) losses* - - - - -
--------------------------------------------- ------- ------- ------- ------- ------
RC profit (loss) before interest and
tax (750) (425) (42) (1,853) (867)
Net (favourable) adverse impact of adjusting
items(a) 377 120 (79) 1,005 94
---------------------------------------------- ------- ------- ------- ------- ------
Underlying RC profit (loss) before interest
and tax (373) (305) (121) (848) (773)
Taxation on an underlying RC basis 11 101 13 166 (18)
---------------------------------------------- ------- ------- ------- ------- ------
Underlying RC profit (loss) before interest (362) (204) (108) (682) (791)
---------------------------------------------- ------- ------- ------- ------- ------
(a) Includes fair value accounting effects relating to the
hybrid bonds that were issued on 17 June 2020. See page 36 for more
information.
Top of page 15
Financial statements
Group income statement
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
-------------------------------------------------- ------- ------- ------- ------- ----------
Sales and other operating revenues (Note 5)(a) 36,174 36,467 26,312 107,185 78,547
Earnings from joint ventures - after interest
and tax 197 (57) 73 300 (516)
Earnings from associates - after interest
and tax 1,103 856 (332) 2,560 (676)
Interest and other income 158 82 183 322 430
Gains on sale of businesses and fixed assets 235 250 27 1,590 117
--------------------------------------------------- ------- ------- ------- ------- --------
Total revenues and other income 37,867 37,598 26,263 111,957 77,902
Purchases(a) 23,937 21,241 13,706 60,834 42,271
Production and manufacturing expenses 6,026 6,562 5,073 19,446 16,383
Production and similar taxes 354 295 140 902 467
Depreciation, depletion and amortization (Note
6) 3,944 3,631 3,467 10,942 11,463
Impairment and losses on sale of businesses
and fixed assets (Note 3) 220 (2,937) 294 (2,344) 13,213
Exploration expense 116 107 190 322 10,066
Distribution and administration expenses 3,077 2,874 2,435 8,566 7,628
--------------------------------------------------- ------- ------- ------- ------- --------
Profit (loss) before interest and taxation 193 5,825 958 13,289 (23,589)
Finance costs 693 682 800 2,098 2,366
Net finance (income) expense relating to pensions
and other post-retirement benefits (5) 5 8 6 23
--------------------------------------------------- ------- ------- ------- ------- --------
Profit (loss) before taxation (495) 5,138 150 11,185 (25,978)
Taxation 1,850 1,784 457 5,276 (3,764)
--------------------------------------------------- ------- ------- ------- ------- --------
Profit (loss) for the period (2,345) 3,354 (307) 5,909 (22,214)
--------------------------------------------------- ------- ------- ------- ------- --------
Attributable to
BP shareholders (2,544) 3,116 (450) 5,239 (21,663)
Non-controlling interests 199 238 143 670 (551)
--------------------------------------------------- ------- ------- ------- ------- --------
(2,345) 3,354 (307) 5,909 (22,214)
------- ------- ------- ------- --------
Earnings per share (Note 7)
Profit (loss) for the period attributable
to BP shareholders
Per ordinary share (cents)
Basic (12.63) 15.37 (2.22) 25.88 (107.15)
Diluted (12.63) 15.30 (2.22) 25.72 (107.15)
Per ADS (dollars)
Basic (0.76) 0.92 (0.13) 1.55 (6.43)
Diluted (0.76) 0.92 (0.13) 1.54 (6.43)
--------------------------------------------------- ------- ------- ------- ------- --------
(a) 2020 numbers have been restated as a result of changes to
the net presentation of revenues and purchases relating to
physically settled derivative contracts effective 1 January 2021.
For more information see Note 1 Basis of preparation - Voluntary
change in accounting policy.
Top of page 16
Condensed group statement of comprehensive income
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
---------------------------------------------- ------- ------- ------- ------ ----------
Profit (loss) for the period (2,345) 3,354 (307) 5,909 (22,214)
----------------------------------------------- ------- ------- ------- ------ --------
Other comprehensive income
Items that may be reclassified subsequently
to profit or loss
Currency translation differences(a) (599) 902 (166) (302) (3,437)
Exchange (gains) losses on translation
of foreign operations reclassified to
gain or loss on sale of businesses and
fixed assets - - - - 4
Cash flow hedges and costs of hedging (398) (207) (90) (667) 63
Share of items relating to equity-accounted
entities, net of tax (3) (68) 308 (60) 417
Income tax relating to items that may
be reclassified 80 8 (16) 89 64
----------------------------------------------- ------- ------- ------- ------ --------
(920) 635 36 (940) (2,889)
------- ------- ------- ------ --------
Items that will not be reclassified to
profit or loss
Remeasurements of the net pension and
other post-retirement benefit liability
or asset(b) 494 590 78 3,110 (163)
Cash flow hedges that will subsequently
be transferred to the balance sheet (2) 1 8 1 (2)
Income tax relating to items that will
not be reclassified (130) (165) (16) (883) (16)
----------------------------------------------- ------- ------- ------- ------ --------
362 426 70 2,228 (181)
------- ------- ------- ------ --------
Other comprehensive income (558) 1,061 106 1,288 (3,070)
----------------------------------------------- ------- ------- ------- ------ --------
Total comprehensive income (2,903) 4,415 (201) 7,197 (25,284)
----------------------------------------------- ------- ------- ------- ------ --------
Attributable to
BP shareholders (3,084) 4,183 (364) 6,559 (24,723)
Non-controlling interests 181 232 163 638 (561)
----------------------------------------------- ------- ------- ------- ------ --------
(2,903) 4,415 (201) 7,197 (25,284)
------- ------- ------- ------ --------
(a) Second quarter 2021 and nine months 2020 principally
affected by movements in the Russian rouble against the US
dollar.
(b) See Note 1 - Basis of preparation - Pensions and other
post-retirement benefits for further information.
Top of page 17
Condensed group statement of changes in equity
bp shareholders' Non-controlling interests Total
$ million equity Hybrid bonds Other interest equity
---------------------------------------
At 1 January 2021 71,250 12,076 2,242 85,568
---------------------------------------- ---------------- ------------------ -------------- --------
Total comprehensive income 6,559 377 261 7,197
Dividends (3,236) - (245) (3,481)
Cash flow hedges transferred
to the balance sheet, net of
tax (8) - - (8)
Repurchase of ordinary share
capital (1,897) - - (1,897)
Share-based payments, net of
tax 407 - - 407
Share of equity-accounted entities'
changes in equity, net of tax 558 - - 558
Issue of perpetual hybrid bonds
(a) (24) 883 - 859
Payments on perpetual hybrid
bonds (7) (431) - (438)
Transactions involving non-controlling
interests, net of tax 873 - (372) 501
---------------------------------------- ---------------- ------------------ -------------- --------
At 30 September 2021 74,475 12,905 1,886 89,266
---------------------------------------- ---------------- ------------------ -------------- --------
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
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
---------------------------------------- ---------------- ------------------ -------------- --------
(a) See note 1 - Issuance of hybrid securities for further information.
Top of page 18
Group balance sheet
30 September 31 December
$ million 2021 2020
------------------------------------------------------- ------------ -------------
Non-current assets
Property, plant and equipment 114,458 114,836
Goodwill 12,428 12,480
Intangible assets 6,261 6,093
Investments in joint ventures 9,777 8,362
Investments in associates 21,359 18,975
Other investments 2,396 2,746
-------------------------------------------------------- ------------ -----------
Fixed assets 166,679 163,492
Loans 972 840
Trade and other receivables 3,815 4,351
Derivative financial instruments 7,203 9,755
Prepayments 473 533
Deferred tax assets 6,259 7,744
Defined benefit pension plan surpluses 10,659 7,957
-------------------------------------------------------- ------------ -----------
196,060 194,672
------------ -----------
Current assets
Loans 478 458
Inventories 25,232 16,873
Trade and other receivables 25,327 17,948
Derivative financial instruments 6,542 2,992
Prepayments 1,479 1,269
Current tax receivable 494 672
Other investments 191 333
Cash and cash equivalents 30,694 31,111
-------------------------------------------------------- ------------ -----------
90,437 71,656
Assets classified as held for sale (Note 2) 39 1,326
-------------------------------------------------------- ------------ -----------
90,476 72,982
------------ -----------
Total assets 286,536 267,654
-------------------------------------------------------- ------------ -----------
Current liabilities
Trade and other payables 49,406 36,014
Derivative financial instruments 10,666 2,998
Accruals 5,623 4,650
Lease liabilities 1,762 1,933
Finance debt 3,693 9,359
Current tax payable 1,346 1,038
Provisions 5,585 3,761
-------------------------------------------------------- ------------ -----------
78,081 59,753
Liabilities directly associated with assets classified
as held for sale (Note 2) 31 46
-------------------------------------------------------- ------------ -----------
78,112 59,799
------------ -----------
Non-current liabilities
Other payables 10,603 12,112
Derivative financial instruments 6,095 5,404
Accruals 978 852
Lease liabilities 6,866 7,329
Finance debt 59,521 63,305
Deferred tax liabilities 8,044 6,831
Provisions 18,820 17,200
Defined benefit pension plan and other post-retirement
benefit plan deficits 8,231 9,254
-------------------------------------------------------- ------------ -----------
119,158 122,287
------------ -----------
Total liabilities 197,270 182,086
-------------------------------------------------------- ------------ -----------
Net assets 89,266 85,568
-------------------------------------------------------- ------------ -----------
Equity
BP shareholders' equity 74,475 71,250
Non-controlling interests 14,791 14,318
-------------------------------------------------------- ------------ -----------
Total equity 89,266 85,568
-------------------------------------------------------- ------------ -----------
Top of page 19
Condensed group cash flow statement
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
---------------------------------------------------- ------- ------- ------- -------- ----------
Operating activities
Profit (loss) before taxation (495) 5,138 150 11,185 (25,978)
Adjustments to reconcile profit (loss) before
taxation to net cash provided by operating
activities
Depreciation, depletion and amortization
and exploration expenditure written off 3,976 3,659 3,517 11,063 21,229
Impairment and (gain) loss on sale of businesses
and fixed assets (15) (3,187) 267 (3,934) 13,096
Earnings from equity-accounted entities,
less dividends received (784) (539) 1,018 (1,956) 2,383
Net charge for interest and other finance
expense, less net interest paid 63 300 60 392 214
Share-based payments 219 228 199 401 544
Net operating charge for pensions and other
post-retirement benefits, less contributions
and benefit payments for unfunded plans (80) (371) (46) (471) (100)
Net charge for provisions, less payments 666 1,172 293 2,740 (131)
Movements in inventories and other current
and non-current assets and liabilities 3,850 26 556 1,083 630
Income taxes paid (1,424) (1,015) (810) (3,007) (1,994)
----------------------------------------------------- ------- ------- ------- -------- --------
Net cash provided by operating activities 5,976 5,411 5,204 17,496 9,893
----------------------------------------------------- ------- ------- ------- -------- --------
Investing activities
Expenditure on property, plant and equipment,
intangible and other assets (2,647) (2,435) (2,577) (8,115) (9,384)
Acquisitions, net of cash acquired (53) - (10) (54) (27)
Investment in joint ventures (70) (47) (12) (859) (38)
Investment in associates (133) (32) (1,037) (187) (1,115)
----------------------------------------------------- ------- ------- ------- -------- --------
Total cash capital expenditure (2,903) (2,514) (3,636) (9,215) (10,564)
Proceeds from disposal of fixed assets (19) 93 32 625 52
Proceeds from disposal of businesses, net
of cash disposed 332 122 84 4,067 1,425
Proceeds from loan repayments 33 67 50 161 656
===================================================== ======= ======= ======= ======== ========
Cash provided from investing activities 346 282 166 4,853 2,133
----------------------------------------------------- ------- ------- ------- -------- --------
Net cash used in investing activities (2,557) (2,232) (3,470) (4,362) (8,431)
----------------------------------------------------- ------- ------- ------- -------- --------
Financing activities
Net issue (repurchase) of shares (Note 7) (926) (500) - (1,426) (776)
Lease liability payments (506) (514) (578) (1,580) (1,811)
Proceeds from long-term financing 2,398 1,985 2,587 6,339 12,117
Repayments of long-term financing (6,745) (67) (4,307) (13,841) (8,988)
Net increase (decrease) in short-term debt (81) (33) (2,630) 108 (328)
Issue of perpetual hybrid bonds (a) 859 - - 859 11,861
Payments on perpetual hybrid bonds (55) (328) (27) (438) (27)
Payments relating to transactions involving
non-controlling interests (Other interest) (560) - - (560) (8)
Receipts relating to transactions involving
non-controlling interests (Other interest) - 3 483 671 492
Dividends paid - BP shareholders (1,101) (1,062) (1,060) (3,227) (5,281)
- non-controlling interests (87) (107) (58) (245) (163)
----------------------------------------------------- ------- ------- ------- -------- --------
Net cash provided by (used in) financing
activities (6,804) (623) (5,590) (13,340) 7,088
----------------------------------------------------- ------- ------- ------- -------- --------
Currency translation differences relating
to cash and cash equivalents (177) 24 268 (211) 43
----------------------------------------------------- ------- ------- ------- -------- --------
Increase (decrease) in cash and cash equivalents (3,562) 2,580 (3,588) (417) 8,593
----------------------------------------------------- ------- ------- ------- -------- --------
Cash and cash equivalents at beginning of
period 34,256 31,676 34,653 31,111 22,472
Cash and cash equivalents at end of period(b) 30,694 34,256 31,065 30,694 31,065
----------------------------------------------------- ------- ------- ------- -------- --------
(a) See note 1 - Issuance of hybrid securities for further information.
(b) Third quarter and nine months 2020 includes $316 million of
cash and cash equivalents classified as assets held for sale in the
group balance sheet.
Top of page 20
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 2020 included in BP Annual
Report and Form 20-F 2020.
The directors consider it appropriate to adopt the going concern
basis of accounting in preparing the interim financial statements.
The ongoing 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 to support this assertion. Reverse stress tests indicated
that the group will continue to operate as a going concern for at
least 12 months from the date of approval of the interim financial
statements even if the Brent price fell to zero.
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
international accounting standards. As a result of the UK's
withdrawal from the EU, with effect from 1 January 2021, the
consolidated financial statements are also prepared in accordance
with IFRS as adopted by the UK. IFRS as adopted by the UK does not
differ from IFRS as adopted by the EU. IFRS as adopted by the EU
and UK differ 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 2021 which are the same as
those used in preparing BP Annual Report and Form 20-F 2020 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
2021 onwards that have a significant impact on the financial
information.
Considerations in respect of COVID-19 and the current economic
environment
bp's significant accounting judgements and estimates were
disclosed in BP Annual Report and Form 20-F 2020. These have been
subsequently considered 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 conditions also result in
the valuation of certain assets and liabilities remaining subject
to more uncertainty, including those set out below.
Impairment testing assumptions
The group's price assumption for Brent oil was revised during
the second quarter. The assumption up to 2030 was increased to
reflect near-term supply constraints whereas the long-term
assumption was decreased reaching $55 per barrel by 2040 and $45
per barrel by 2050 (in real 2020 terms) as bp's management expects
an acceleration of the pace of transition to a lower carbon
economy. The price assumption for Henry Hub gas were unchanged from
those disclosed in BP Annual Report and Form 20-F 2020. A summary
of the group's price assumptions, in real 2020 terms, is provided
below:
4Q21 2025 2030 2040 2050
------------------------ ---- ---- ---- ---- ----
Brent oil ($/bbl) 60 60 60 55 45
Henry Hub gas ($/mmBtu) 3.00 3.00 3.00 3.00 2.75
-------------------------- ---- ---- ---- ---- ----
The group has identified upstream oil and gas properties with
carrying amounts totalling approximately $30 billion where the
headroom, based on the most recent impairment tests performed, was
less than or equal to 20% of the carrying value. 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 as
disclosed in BP Annual Report and Form 20-F 2020, are
unchanged.
Provisions
The nominal risk-free discount rate applied to provisions is
reviewed on a quarterly basis. The discount rate applied to the
group's provisions remains at 2.0% (31 December 2020 2.5%).
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 2021, the group's total net
defined benefit pension plan surplus as at 30 September 2021 is
$2.4 billion, compared to a surplus of $2.0 billion and a deficit
of $1.3 billion at 30 June 2021 and 31 December 2020
respectively.
The movement for the nine months principally reflects net
actuarial gains reported in other comprehensive income arising from
increases in the UK, US and Eurozone discount rates and positive
asset performance, partly offset by increases in inflation rates.
Also reflected in the nine months is a reduction in the liability
of the UK funded final salary pension plan which was closed to
future accrual on 30 June 2021. A curtailment gain of $0.3 billion
was recognized in the income statement in the second quarter. For
active members of the scheme at 30 June 2021, benefits payable are
now linked to salary as at that date rather than to salary on
retirement. 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.
Top of page 21
Note 1. Basis of preparation (continued)
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 2020. 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 with no
significant impact in the quarter.
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 2020 - Financial statements - Note 29
Financial instruments and financial risk factors - credit risk.
Other accounting judgements and estimates
All other significant accounting judgements and estimates
disclosed in BP Annual Report and Form 20-F 2020 remain applicable
and no new significant accounting judgements or estimates have been
identified specifically arising from the impact of COVID-19.
Issuance of hybrid securities
During the quarter, a group subsidiary issued perpetual
subordinated hybrid capital securities of $0.9 billion. The
proceeds from this issuance were specifically earmarked to fund a
forward purchase and leaseback of an under-construction floating,
production, storage, and offloading vessel (FPSO) to be used on one
of the group's major projects.
As the group has the unconditional right to defer interest and
principal indefinitely, they are classified as equity instruments
and reported within non-controlling interests in the condensed
consolidated financial statements.
Updates to significant accounting policies
Change in accounting policy - Interest Rate Benchmark Reform -
Phase II
Financial authorities have announced the timing of interest rate
benchmark transitions with market discussions continuing around
benchmark application. The replacement of key interest rate
benchmarks such as the London Inter-bank Offered Rate (LIBOR) with
alternative benchmarks in the US, UK, EU and other territories is
expected at the end of 2021 for most benchmarks, with remaining USD
tenors expected to cease in 2023. bp is primarily exposed to USD
LIBORs that will be available until June 2023.
Amendments to IFRS 9 'Financial instruments', IFRS 16 'Leases'
and other IFRSs were issued by the IASB in August 2020 to provide
practical expedients and reliefs when changes are made to
contractual cash flows or hedging relationships because of the
transition from Inter-bank Offered Rates to alternative risk-free
rates. bp adopted these amendments from 1 January 2021 and they
will be applied prospectively.
bp has set up an internal working group on interest rate
benchmark reform to monitor market developments and manage the
transition to alternative benchmark rates. The impacts on contracts
and arrangements that are linked to existing interest rate
benchmarks, for example, borrowings, leases and derivative
contracts have been assessed and transition plans are being
developed. bp is also participating on external committees and task
forces dedicated to interest rate benchmark reform.
Change in segmentation
During the first quarter of 2021, the group's reportable
segments were changed consistent with a change in the way that
resources are allocated and performance is assessed by the chief
operating decision maker, who for bp is the group chief executive,
from that date. From the first quarter of 2021, the group's
reportable segments are gas & low carbon energy, oil production
& operations, customers & products, and Rosneft. At 31
December 2020, the group's reportable segments were Upstream,
Downstream and Rosneft.
Gas & low carbon energy comprises regions with upstream
businesses that predominantly produce natural gas, gas marketing
and trading activities and the group's renewables businesses,
including biofuels, solar and wind. Gas producing regions were
previously in the Upstream segment. The group's renewables
businesses were previously part of 'Other businesses and
corporate'.
Oil production & operations comprises regions with upstream
activities that predominantly produce crude oil. These activities
were previously in the Upstream segment.
Customers & products comprises the group's customer-focused
businesses, spanning convenience and mobility, which includes fuels
retail and next-gen offers such as electrification, as well as
aviation, midstream, and Castrol lubricants. It also includes our
oil products businesses, refining & trading. The petrochemicals
business will also be reported in restated comparative information
as part of the customers and products segment up to its sale in
December 2020. The customers & products segment is, therefore,
substantially unchanged from the former Downstream segment with the
exception of the Petrochemicals disposal.
The Rosneft segment is unchanged and continues to include
equity-accounted earnings from the group's investment in
Rosneft.
The segment measure of profit or loss continues to be
replacement cost profit or loss before interest and tax, which
reflects the replacement cost of supplies by excluding from profit
or loss before interest and tax inventory holding gains and losses.
See Note 4 for further information.
Comparative information for 2020 has been restated in Notes 4, 5
and 6 to reflect the changes in reportable segments.
Top of page 22
Note 1. Basis of preparation (continued)
Voluntary change in accounting policy - Net presentation of
revenues and purchases relating to physically settled derivative
contracts
bp routinely enters into transactions for the sale and purchase
of commodities that are physically settled and meet the definition
of a derivative financial instrument. These contracts are within
the scope of IFRS 9 and as such, prior to settlement, changes in
the fair value of these derivative contracts are presented as gains
and losses within other operating revenues. The group previously
presented revenues and purchases for such contracts on a gross
basis in the income statement upon physical settlement.
These transactions have historically represented a substantial
portion of the revenues and purchases reported in the group's
consolidated financial statements.
The change in strategic direction of the group supported by
organisational changes to implement the strategy from 1 January
2021, resulted in the group determining that the revenue and
corresponding purchases relating to such transactions should be
presented net, as gains or losses within other operating revenues,
from that date.
Additionally the group's trading activity has continued to
evolve over time from one of capturing third-party physical trades
to provide flow assurance to one with increasing levels of
optimisation, taking advantage of price volatility and fluctuations
in demand and supply, which will continue under the new strategy,
further supporting the change in presentation. The new presentation
provides reliable and more relevant information for users of the
accounts as the group's revenue recognition is more closely aligned
with its assessment of 'Scope 3' emissions from its products, its
'Net Zero' ambition and how management monitors and manages
performance of such contracts. Comparative information for sales
and other operating revenues and purchases for 2020 has been
restated as shown in the table below. There is no significant
impact on comparative information for profit before income and tax
or earnings per share.
In addition, as disclosed in the group's 2020 financial
statements, in 2020 revenues from physically settled derivative
contracts were reclassified as other operating revenues and were no
longer presented together with revenues from contracts with
customers. In these financial statements certain other similar
contracts have been reclassified as other operating revenues and
then been subject to net presentation as described above.
Comparative information for natural gas, LNG and NGLs, and non-oil
products and other revenue from contracts with customers in Note 5
has been amended to align with current period presentation as shown
in the table below.
Top of page 23
Note 1. Basis of preparation (continued)
Third Third Nine Nine
quarter quarter months months
2020 2020 Impact 2020 2020 Impact
of net of net
$ million Restated presentation(a) Restated presentation(a)
------------------------------- ------- -------- --------------- ------- -------- -----------------
Sales and other operating revenues (Note
5)
gas & low carbon energy 4,141 3,518 (623) 14,376 12,270 (2,106)
oil production & operations 3,998 3,998 - 13,133 13,133 -
customers & products 40,256 22,940 (17,316) 121,461 66,537 (54,924)
other businesses & corporate 383 383 - 1,262 1,262 -
-------------------------------- ------- -------- --------------- ------- -------- ---------------
48,778 30,839 (17,939) 150,232 93,202 (57,030)
------- -------- --------------- ------- -------- ---------------
Less: sales and other revenues
between segments
gas & low carbon energy 254 254 - 2,092 2,092 -
oil production & operations 3,726 3,726 - 12,097 12,097 -
customers & products 124 124 - (328) (328) -
other businesses & corporate 423 423 - 794 794 -
-------------------------------- ------- -------- --------------- ------- -------- ---------------
4,527 4,527 - 14,655 14,655 -
------- -------- --------------- ------- -------- ---------------
External sales and other
operating revenues
gas & low carbon energy 3,887 3,264 (623) 12,284 10,178 (2,106)
oil production & operations 272 272 - 1,037 1,037 -
customers & products 40,132 22,816 (17,316) 121,789 66,865 (54,924)
other businesses & corporate (40) (40) - 467 467 -
-------------------------------- ------- -------- --------------- ------- -------- ---------------
Total sales and other operating
revenues 44,251 26,312 (17,939) 135,577 78,547 (57,030)
Sales and other operating
revenues include the following
in relation to revenues from
contracts with customers:
Crude oil 1,366 1,366 - 3,863 3,863 -
Oil products 16,642 16,642 - 47,348 47,348 -
Natural gas, LNG and NGLs 2,844 1,443 (1,401) 9,474 6,693 (2,781)
Non-oil products and other
revenues from contracts
with
customers 2,624 2,580 (44) 7,232 7,149 (83)
-------------------------------- ------- -------- --------------- ------- -------- ---------------
Revenues from contracts with
customers 23,476 22,031 (1,445) 67,917 65,053 (2,864)
-------------------------------- ------- -------- --------------- ------- -------- ---------------
Other operating revenues 20,775 4,281 (16,494) 67,660 13,494 (54,166)
-------------------------------- ------- -------- --------------- ------- -------- ---------------
Total sales and other operating
revenues 44,251 26,312 (17,939) 135,577 78,547 (57,030)
-------------------------------- ------- -------- --------------- ------- -------- ---------------
(a) Total purchases for the third quarter and nine months 2020
have been re-stated by the equal and opposite amount as total sales
and other operating revenues.
Note 2. Non-current assets held for sale
The carrying amount of assets classified as held for sale at 30
September 2021 is $39 million, with associated liabilities of $31
million.
At 31 December 2020 the balance consists primarily of a 20%
participating interest from BP's 60% participating interest in
Block 61 in Oman, which is reported in the gas & low carbon
energy segment. As announced on 1 February 2021, BP agreed to sell
this interest to PTT Exploration and Production Public Company
Limited (PTTEP) of Thailand for a total consideration of up to $2.6
billion, subject to final adjustments. On 28 March, a royal decree
was published approving the sale and $2.4 billion was received in
March 2021.
Top of page 24
Note 3. Impairment and losses on sale of businesses and fixed
assets(a)
Impairment charges net of losses on sale of businesses and fixed
assets for the third quarter were $220 million and impairment
reversals net of losses on sale of businesses and fixed assets for
the nine months 2021 were $2,344 million respectively (charges of
$294 million and $13,213 million for the comparative periods in
2020) and include net impairment charges for the third quarter of
2021 of $256 million and net impairment reversals for the nine
months 2021 of $2,488 million (charges of $278 million and $12,924
million for the comparative periods in 2020).
gas & low carbon energy segment
In the gas & low carbon energy segment there was a net
impairment charge of $197 million for the third quarter and a net
impairment reversal of $951 million for the nine months 2021
(charges of $76 million and $6,188 million for the comparative
periods in 2020).
Impairment reversals for the nine months 2021 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, India and Trinidad. The recoverable amounts of the cash
generating units within these businesses were based on value-in-use
calculations.
oil production & operations segment
In the oil production & operations segment there was a net
impairment charge of $5 million for the third quarter and a net
impairment reversal of $1,652 million for the nine months 2021
(charges of $197 million and $5,989 million for the comparative
periods in 2020).
Impairment reversals for the nine months 2021 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
BPX Energy and the North Sea. The recoverable amounts of the cash
generating units within these businesses were based on value-in-use
calculations.
(a) All disclosures are pre-tax.
Note 4. Analysis of replacement cost profit (loss) before
interest and tax and reconciliation to profit (loss) before
taxation(a)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
--------------------------------------- ------- ------- ------- ------- ----------
gas & low carbon energy (4,135) 927 252 222 (6,430)
oil production & operations 2,692 3,118 (156) 7,289 (14,649)
customers & products 1,060 640 915 2,634 2,173
Rosneft 868 643 (278) 1,874 (419)
other businesses & corporate (750) (425) (42) (1,853) (867)
---------------------------------------- ------- ------- ------- ------- --------
(265) 4,903 691 10,166 (20,192)
Consolidation adjustment - UPII* (42) (31) 34 (60) 166
---------------------------------------- ------- ------- ------- ------- --------
RC profit (loss) before interest and
tax* (307) 4,872 725 10,106 (20,026)
Inventory holding gains (losses)*
gas & low carbon energy 15 4 7 41 9
oil production & operations (1) (6) 1 8 (12)
customers & products 451 887 191 2,943 (3,446)
Rosneft (net of tax) 35 68 34 191 (114)
---------------------------------------- ------- ------- ------- ------- --------
Profit (loss) before interest and tax 193 5,825 958 13,289 (23,589)
Finance costs 693 682 800 2,098 2,366
Net finance expense/(income) relating
to pensions and other post-retirement
benefits (5) 5 8 6 23
---------------------------------------- ------- ------- ------- ------- --------
Profit (loss) before taxation (495) 5,138 150 11,185 (25,978)
---------------------------------------- ------- ------- ------- ------- --------
RC profit (loss) before interest and
tax*
US 1,964 955 105 4,826 (3,995)
Non-US (2,271) 3,917 620 5,280 (16,031)
---------------------------------------- ------- ------- ------- ------- --------
(307) 4,872 725 10,106 (20,026)
------- ------- ------- ------- --------
(a) Comparative information for 2020 has been restated to
reflect the changes in reportable segments. For more information
see Note 1 basis of preparation - Change in segmentation.
Top of page 25
Note 5. Sales and other operating revenues(a)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
--------------------------------------------------- ------- ------- ------- ------- --------
By segment
gas & low carbon energy 2,554 5,739 3,518 16,295 12,270
oil production & operations 6,285 5,597 3,998 17,037 13,133
customers & products 34,382 31,160 22,940 92,649 66,537
other businesses & corporate 423 381 383 1,240 1,262
---------------------------------------------------- ------- ------- ------- ------- ------
43,644 42,877 30,839 127,221 93,202
------- ------- ------- ------- ------
Less: sales and other operating revenues between
segments
gas & low carbon energy 1,269 1,063 254 3,364 2,092
oil production & operations 5,423 4,928 3,726 15,206 12,097
customers & products 354 112 124 576 (328)
other businesses & corporate 424 307 423 890 794
---------------------------------------------------- ------- ------- ------- ------- ------
7,470 6,410 4,527 20,036 14,655
------- ------- ------- ------- ------
External sales and other operating revenues
gas & low carbon energy 1,285 4,676 3,264 12,931 10,178
oil production & operations 862 669 272 1,831 1,037
customers & products 34,028 31,048 22,816 92,073 66,865
other businesses & corporate (1) 74 (40) 350 467
---------------------------------------------------- ------- ------- ------- ------- ------
Total sales and other operating revenues 36,174 36,467 26,312 107,185 78,547
---------------------------------------------------- ------- ------- ------- ------- ------
By geographical area
US 15,372 15,305 8,319 45,168 25,516
Non-US 28,578 29,700 22,583 85,161 66,361
---------------------------------------------------- ------- ------- ------- ------- ------
43,950 45,005 30,902 130,329 91,877
Less: sales and other operating revenues between
areas 7,776 8,538 4,590 23,144 13,330
---------------------------------------------------- ------- ------- ------- ------- ------
36,174 36,467 26,312 107,185 78,547
------- ------- ------- ------- ------
Revenues from contracts with customers
Sales and other operating revenues include
the following in relation to revenues from
contracts with customers:
Crude oil 2,292 1,291 1,366 4,917 3,863
Oil products 27,699 24,651 16,642 71,628 47,348
Natural gas, LNG and NGLs(b) 4,458 4,273 1,443 12,912 6,693
Non-oil products and other revenues from contracts
with customers(b) 2,275 1,603 2,580 5,276 7,149
---------------------------------------------------- ------- ------- ------- ------- ------
Revenue from contracts with customers 36,724 31,818 22,031 94,733 65,053
---------------------------------------------------- ------- ------- ------- ------- ------
Other operating revenues(c) (550) 4,649 4,281 12,452 13,494
---------------------------------------------------- ------- ------- ------- ------- ------
Total sales and other operating revenues 36,174 36,467 26,312 107,185 78,547
---------------------------------------------------- ------- ------- ------- ------- ------
(a) Comparative information for 2020 has been restated for the
changes in reportable segments and also for the changes to net
presentation of revenues and purchases relating to physically
settled derivative contracts effective 1 January 2021. For more
information see Note 1 Basis of preparation - Voluntary change in
accounting policy and Change in segmentation.
(b) Comparative information has been amended for certain
contracts that have been reclassified to other operating revenues
and restated to reflect the net presentation described in Note 1
Basis of preparation - Voluntary change in accounting policy.
(c) Principally relates to commodity derivative transactions.
Top of page 26
Note 6. Depreciation, depletion and amortization(a)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
----------------------------------------------- ------- ------- ------- ------ --------
Total depreciation, depletion and amortization
by segment
gas & low carbon energy 1,230 1,115 746 3,199 2,736
oil production & operations 1,767 1,559 1,814 4,900 6,001
customers & products 747 754 743 2,246 2,242
other businesses & corporate 200 203 164 597 484
------------------------------------------------ ------- ------- ------- ------ ------
3,944 3,631 3,467 10,942 11,463
------- ------- ------- ------ ------
Total depreciation, depletion and amortization
by geographical area
US 1,206 1,161 1,191 3,488 4,020
Non-US 2,738 2,470 2,276 7,454 7,443
------------------------------------------------ ------- ------- ------- ------ ------
3,944 3,631 3,467 10,942 11,463
------- ------- ------- ------ ------
(a) Comparative information for 2020 has been restated to
reflect the changes in reportable segments. For more information
see Note 1 basis of preparation - Change in segmentation.
Note 7. 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. During the third quarter 2021
221 million of ordinary shares were repurchased for cancellation
for a total cost of $926 million, including transaction costs of $5
million, as part of the share buyback programme announced on 27
April 2021. This brings the total number of shares repurchased in
the nine months to 336 million for a total cost of $1,426 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.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
------------------------------------------ ---------- ---------- ---------- ---------- ------------
Results for the period
Profit (loss) for the period attributable
to bp shareholders (2,544) 3,116 (450) 5,239 (21,663)
Less: preference dividend 1 - - 2 1
------------------------------------------- ---------- ---------- ---------- ---------- ----------
Profit (loss) attributable to
bp ordinary shareholders (2,545) 3,116 (450) 5,237 (21,664)
------------------------------------------- ---------- ---------- ---------- ---------- ----------
Number of shares (thousand) (a)(b)
Basic weighted average number
of shares outstanding 20,150,186 20,272,111 20,251,199 20,239,365 20,217,559
ADS equivalent(c) 3,358,364 3,378,685 3,375,199 3,373,228 3,369,593
------------------------------------------- ---------- ---------- ---------- ---------- ----------
Weighted average number of shares
outstanding used to calculate
diluted earnings per share 20,150,186 20,366,731 20,251,199 20,359,280 20,217,559
ADS equivalent(c) 3,358,364 3,394,455 3,375,199 3,393,213 3,369,593
------------------------------------------- ---------- ---------- ---------- ---------- ----------
Shares in issue at period-end 20,008,900 20,224,314 20,254,417 20,008,900 20,254,417
ADS equivalent(c) 3,334,816 3,370,719 3,375,736 3,334,816 3,375,736
------------------------------------------- ---------- ---------- ---------- ---------- ----------
(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 third quarter 2021, third quarter 2020 and nine
months 2020 are 123,543 thousand (ADS equivalent 20,591 thousand),
81,097 thousand (ADS equivalent 13,516 thousand) and 94,302
thousand (ADS equivalent 15,717 thousand) respectively.
(c) One ADS is equivalent to six ordinary shares.
Top of page 27
Note 8. Dividends
Dividends payable
BP today announced an interim dividend of 5.46 cents per
ordinary share which is expected to be paid on 17 December 2021 to
ordinary shareholders and American Depositary Share (ADS) holders
on the register on 12 November 2021. The ex-dividend date will be
10 November 2021 for ADS holders and 11 November 2021 for ordinary
shareholders. The corresponding amount in sterling is due to be
announced on 7 December 2021, calculated based on the average of
the market exchange rates over three dealing days between 1
December 2021 and 3 December 2021. Holders of ADSs are expected to
receive $0.3276 per ADS (less applicable fees). The board has
decided not to offer a scrip dividend alternative in respect of the
third quarter 2021 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
2021 2021 2020 2021 2020
---------------------------------- ------- ------- ------- ------ --------
Dividends paid per ordinary share
cents 5.460 5.250 5.250 15.960 26.250
pence 3.953 3.712 4.043 11.433 20.541
Dividends paid per ADS (cents) 32.76 31.50 31.50 95.76 157.50
----------------------------------- ------- ------- ------- ------ ------
Note 9. Net debt
Net debt* Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
--------------------------------------- -------- -------- -------- -------- ----------
Finance debt(a)(b) 63,214 68,247 72,828 63,214 72,828
Fair value (asset) liability of hedges
related to finance debt(c) (549) (1,285) (1,384) (549) (1,384)
---------------------------------------- -------- -------- -------- -------- --------
62,665 66,962 71,444 62,665 71,444
Less: cash and cash equivalents(b) 30,694 34,256 31,065 30,694 31,065
---------------------------------------- -------- -------- -------- -------- --------
Net debt(d) 31,971 32,706 40,379 31,971 40,379
---------------------------------------- -------- -------- -------- -------- --------
Total equity 89,266 93,232 82,155 89,266 82,155
Gearing* 26.4% 26.0% 33.0% 26.4% 33.0%
---------------------------------------- -------- -------- -------- -------- ----------
(a) The fair value of finance debt at 30 September 2021 was
$65,316 million (30 June 2021 $70,589 million, 30 September 2020
$75,338 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 $151 million at 30 September 2021 (second quarter 2021 liability
of $308 million and third quarter 2020 liability of $372 million)
are not included in the calculation of net debt shown above as
hedge accounting is not applied for these instruments.
(d) Net debt does not include accrued interest, which is
reported within other receivables and other payables on the balance
sheet and for which the associated cash flows are presented as
operating cash flows in the group cash flow statement.
As part of actively managing its debt portfolio, in the third
quarter the group bought back $4.2 billion equivalent of finance
debt (second quarter 2021 $nil; third quarter 2020 $4.0 billion)
consisting of $2.4 billion of USD bonds in July 2021, and a further
$1.8 billion equivalent in September 2021 comprising $1.4 billion
euro and sterling bonds and $0.4 billion other USD debt. Year to
date the group has bought back a total of $8.1 billion equivalent
of finance debt ($4.0 billion for the comparative period in 2020).
Derivatives associated with debt bought back in each of these
periods were also terminated. There was no significant impact on
net debt or gearing as a result of these transactions.
Note 10. Inventory valuation
A provision of $129 million was held against hydrocarbon
inventories at 30 September 2021 ($17 million at 30 June 2021 and
$544 million at 30 September 2020) to write them down to their net
realizable value. As a result of the changes in strategic direction
of the group and the evolution of the trading strategy set out in
Note 1, from 1 January, certain inventory, totalling $12.8 billion
as at 30 September 2021 ($11.0 billion as at 30 June 2021), is now
treated as trading inventory and is valued at fair value whereas
the equivalent inventory was previously valued at the lower of cost
or net realisable value in prior periods.
Top of page 28
Note 11. Statutory accounts
The financial information shown in this publication, which was
approved by the Board of Directors on 1 November 2021, is unaudited
and does not constitute statutory financial statements. Audited
financial information will be published in BP Annual Report and
Form 20-F 2021. BP Annual Report and Form 20-F 2020 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 29
Additional information
Capital expenditure*(a)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
------------------------------------- ------- ------- ------- ------ --------
Capital expenditure
Organic capital expenditure* 2,850 2,511 2,512 8,267 9,085
Inorganic capital expenditure*(b)(c) 53 3 1,124 948 1,479
-------------------------------------- ------- ------- ------- ------ ------
2,903 2,514 3,636 9,215 10,564
------- ------- ------- ------ ------
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
----------------------------------------- ------- ------- ------- ------ --------
Capital expenditure by segment
gas & low carbon energy(b) 1,072 747 935 3,704 3,138
oil production & operations 1,099 1,148 1,117 3,566 4,696
customers & products 597 519 1,519 1,648 2,545
other businesses & corporate 135 100 65 297 185
------------------------------------------ ------- ------- ------- ------ ------
2,903 2,514 3,636 9,215 10,564
------- ------- ------- ------ ------
Capital expenditure by geographical area
US 1,176 890 741 3,553 3,177
Non-US 1,727 1,624 2,895 5,662 7,387
------------------------------------------ ------- ------- ------- ------ ------
2,903 2,514 3,636 9,215 10,564
------- ------- ------- ------ ------
(a) Comparative information for 2020 has been restated to
reflect the changes in reportable segments. For more information
see Note 1 Basis of preparation - Change in segmentation.
(b) Nine months 2021 includes the final payment of $712 million
in respect of the strategic partnership with Equinor.
(c) 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 also includes amounts relating to the 25-year extension to our
ACG production-sharing agreement* in Azerbaijan.
Top of page 30
Adjusting items*(a)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
----------------------------------------------- ------- ------- ------- ------- ----------
gas & low carbon energy
Gains on sale of businesses and fixed
assets(b) - - - 1,034 -
Impairment and losses on sale of businesses
and fixed assets(c) (197) 1,270 (83) 950 (6,197)
Environmental and other provisions - - - - -
Restructuring, integration and rationalization
costs(d) - (21) (36) (29) (40)
Fair value accounting effects(e)(f) (5,808) (1,311) (217) (6,872) (61)
Other(g) 63 (251) 86 (178) (667)
------------------------------------------------ ------- ------- ------- ------- --------
(5,942) (313) (250) (5,095) (6,965)
------- ------- ------- ------- --------
oil production & operations
Gains on sale of businesses and fixed
assets 261 216 9 645 103
Impairment and losses on sale of businesses
and fixed assets(c) 33 1,751 (191) 1,575 (6,182)
Environmental and other provisions(h) (68) (776) (9) (909) (22)
Restructuring, integration and rationalization
costs(d) 4 (90) (129) (90) (153)
Fair value accounting effects - - - - -
Other(g)(i) 1 (225) (203) (200) (1,944)
------------------------------------------------ ------- ------- ------- ------- --------
231 876 (523) 1,021 (8,198)
------- ------- ------- ------- --------
customers & products
Gains on sale of businesses and fixed
assets (25) 8 16 (114) 10
Impairment and losses on sale of businesses
and fixed assets (58) (35) (20) (136) (823)
Environmental and other provisions (1) (8) - (9) -
Restructuring, integration and rationalization
costs(d) 16 (10) (142) (35) (111)
Fair value accounting effects(f) (30) (139) 425 290 135
Other - (3) - (3) -
------------------------------------------------ ------- ------- ------- ------- --------
(98) (187) 279 (7) (789)
------- ------- ------- ------- --------
Rosneft
Other (55) (46) (101) (101) (164)
------------------------------------------------ ------- ------- ------- ------- --------
(55) (46) (101) (101) (164)
------- ------- ------- ------- --------
other businesses & corporate
Gains on sale of businesses and fixed
assets - - 2 - 4
Impairment and losses on sale of businesses
and fixed assets 1 (50) - (50) -
Environmental and other provisions (65) (72) (32) (137) (55)
Restructuring, integration and rationalization
costs(d) (12) (74) (155) (111) (201)
Gulf of Mexico oil spill (17) (18) (63) (46) (115)
Fair value accounting effects(f) (263) 73 266 (637) 225
Other (21) 21 61 (24) 48
------------------------------------------------ ------- ------- ------- ------- --------
(377) (120) 79 (1,005) (94)
Total before interest and taxation (6,241) 210 (516) (5,187) (16,210)
Finance costs(j)(k) (175) (202) (198) (525) (434)
------------------------------------------------ ------- ------- ------- ------- --------
Total before taxation (6,416) 8 (714) (5,712) (16,644)
Taxation credit (charge) on adjusting
items 193 (396) (101) (191) 3,686
Taxation - impact of foreign exchange(l) (33) (30) 85 (76) (166)
------------------------------------------------ ------- ------- ------- ------- --------
Total taxation on adjusting items 160 (426) (16) (267) 3,520
------------------------------------------------ ------- ------- ------- ------- --------
Total after taxation for period (6,256) (418) (730) (5,979) (13,124)
------------------------------------------------ ------- ------- ------- ------- --------
(a) Prior to 2021 adjusting items were reported under two
different headings - non-operating items and fair value accounting
effects. Comparative information for 2020 has been restated to
reflect the changes in reportable segments. For more information
see Note 1 Basis of preparation - Change in segmentation.
(b) Nine months 2021 relates to a gain from the divestment of a 20% stake in Oman Block 61.
(c) See Note 3 for further information.
(d) All periods in 2021 include recognized provisions for
restructuring costs associated with the reinvent programme that was
formalized in 2020.
(e) Under IFRS bp marks-to-market the derivative financial
instruments used to risk-manage LNG contracts, but does not
mark-to-market the physical LNG contracts themselves, resulting in
a mismatch in accounting treatment. The fair value accounting
effect removes this mismatch, and the underlying result reflects
how bp risk-manages its LNG contracts.
(f) For further information, including the nature of fair value
accounting effects reported in each segment, see page 36.
(g) Nine months 2020 includes the exploration write-off of $670
million in gas and low carbon energy relating to fair value
ascribed to certain licences as part of the accounting at the time
of acquisition of gas & low carbon assets in India and the
impairment of certain intangible assets in Mauritania and Senegal
and $1,301 million in oil production & operations relating to
fair value ascribed to certain licences as part of the accounting
at the time of acquisition of oil production & operations
assets in Brazil and the Gulf of Mexico.
Top of page 31
(h) Second quarter and nine months 2021 include adjustments
relating to the change in discount rate on retained decommissioning
provisions and the recognition of a decommissioning provision in
relation to certain assets previously sold to a third party where
the decommissioning obligation transferred may revert to bp due to
the financial condition of the current owner.
(i) Nine months 2021 includes a $415 million charge relating to
a remeasurement of deferred tax balances in our equity-accounted
entity in Argentina following income tax rate changes partially
offset by impairment reversals in equity-accounted entities.
(j) All periods presented include the unwinding of discounting
effects relating to Gulf of Mexico oil spill payables and the
income statement impact associated with the buyback of finance
debt. See Note 9 for further information.
(k) From first quarter 2021 bp is presenting temporary valuation
differences associated with the group's interest rate and foreign
currency exchange risk management of finance debt as an adjusting
item within finance costs. In 2020 these amounts were presented
within production and manufacturing expenses and as an 'other'
adjusting item in the other business & corporate segment.
Relevant amounts in the comparative periods presented were not
material.
(l) bp is presenting certain foreign exchange effects on tax as
adjusting 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.
Net debt including leases
Net debt including leases* Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
---------------------------------------- -------- -------- -------- -------- ----------
Net debt 31,971 32,706 40,379 31,971 40,379
Lease liabilities 8,628 8,863 9,282 8,628 9,282
Net partner (receivable) payable for
leases entered into on behalf of joint
operations 111 109 (41) 111 (41)
Net debt including leases 40,710 41,678 49,620 40,710 49,620
----------------------------------------- -------- -------- -------- -------- --------
Total equity 89,266 93,232 82,155 89,266 82,155
Gearing including leases* 31.3% 30.9% 37.7% 31.3% 37.7%
----------------------------------------- -------- -------- -------- -------- ----------
Gulf of Mexico oil spill
30 September 31 December
$ million 2021 2020
Gulf of Mexico oil spill payables and provisions (10,329) (11,436)
-------------------------------------------------- ------------ -----------
Of which - current (1,272) (1,444)
Deferred tax asset 4,016 5,471
-------------------------------------------------- ------------ -----------
During the second quarter pre-tax payments of $1,199 million
were made relating to the 2016 consent decree and settlement
agreement with the United States and the five Gulf coast states.
Payables and provisions presented in the table above reflect the
latest estimate for the remaining costs associated with the Gulf of
Mexico oil spill. Where amounts have been provided on an estimated
basis, the amounts ultimately payable may differ from the amounts
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 2020 - Financial statements - Notes 7, 9, 20, 22, 23,
29, and 33.
Top of page 32
Working capital* reconciliation(a)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
----------------------------------------------- ------- ------- ------- ------- ---------
Movements in inventories and other current
and non-current assets and liabilities
as per condensed group cash flow statement(b) 3,850 26 556 1,083 630
Adjusted for inventory holding gains
(losses)* (Note 4 excluding Rosneft) 465 885 199 2,992 (3,449)
Adjusted for fair value accounting effects (6,101) (1,377) 474 (7,219) 299
------------------------------------------------ ------- ------- ------- ------- -------
Working capital release (build) after
adjusting for net inventory gains (losses)
and fair value accounting effects (1,786) (466) 1,229 (3,144) (2,520)
------------------------------------------------ ------- ------- ------- ------- -------
(a) Commencing with second quarter 2021 results fair value
accounting effects have been included in the working capital
reconciliation. For further information see Glossary page 40.
(b) The movement in working capital includes outflows relating
to the Gulf of Mexico oil spill on a pre-tax basis of $37 million
and $1,375 million in the third quarter and nine months of 2021
respectively. For the same periods in 2020 the amount was an
outflow of $180 million and $1,670 million respectively. Net cash
outflows relating to the Gulf of Mexico oil spill in 2021 and 2020
include payments made under the 2016 consent decree and settlement
agreement with the United States and the five Gulf coast
states.
Surplus cash flow* reconciliation
Third Nine
quarter months
$ million 2021 2021
------------------------------------------------------------ ------- ----------
Sources:
Net cash provided by operating activities 5,976 17,496
Cash provided from investing activities 346 4,853
Receipts relating to transactions involving non-controlling
interests - 671
------------------------------------------------------------- ------- --------
Cash inflow 6,322 23,020
------------------------------------------------------------- ------- --------
Uses:
Lease liability payments (506) (1,580)
Payments on perpetual hybrid bonds (55) (438)
Dividends paid - BP shareholders (1,101) (3,227)
- non-controlling interests (87) (245)
Total capital expenditure* (2,903) (9,215)
Net repurchase of shares relating to employee
share schemes - (500)
Payments relating to transactions involving non-controlling
interests (560) (560)
Currency translation differences relating to
cash and cash equivalents (177) (211)
------------------------------------------------------------- ------- --------
Cash outflow (5,389) (15,976)
------------------------------------------------------------- ------- --------
Cash used to meet net debt target - (3,729)
Surplus cash flow 933 3,315
------------------------------------------------------------- ------- --------
Top of page 33
Reconciliation of customers & products RC profit before
interest and tax* to underlying RC profit before interest and tax
to adjusted EBITDA* by business
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2021 2021 2020 2021 2020
----------------------------------------- ------- ------- ------- ------ --------
RC profit before interest and tax for
customers & products 1,060 640 915 2,634 2,173
Less: Adjusting items gains (charges) (98) (187) 279 (7) (789)
Underlying RC profit before interest
and tax for customers & products 1,158 827 636 2,641 2,962
By business:
customers - convenience & mobility 806 951 1,081 2,415 2,201
Castrol - included in customers 231 265 326 830 556
products - refining & trading 352 (124) (533) 226 561
petrochemicals - - 88 - 200
Add back: Depreciation, depletion and
amortization 747 754 743 2,246 2,242
By business:
customers - convenience & mobility 324 329 306 977 876
Castrol - included in customers 36 39 38 114 119
products - refining & trading 423 425 435 1,269 1,264
petrochemicals - - 2 - 102
Adjusted EBITDA for customers & products 1,905 1,581 1,379 4,887 5,204
By business:
customers - convenience & mobility 1,130 1,280 1,387 3,392 3,077
Castrol - included in customers 267 304 364 944 675
products - refining & trading 775 301 (98) 1,495 1,825
petrochemicals - - 90 - 302
------------------------------------------ ------- ------- ------- ------ ------
Top of page 34
Realizations* and marker prices
Third Second Third Nine Nine
quarter quarter quarter months months
2021 2021 2020 2021 2020
-------------------------------------------- ------- ------- ------- ------ --------
Average realizations (a)
Liquids* ($/bbl)
US 59.87 53.64 31.74 52.92 33.24
Europe 74.02 69.19 43.52 67.79 41.35
Rest of World 68.67 64.44 41.46 63.51 36.13
BP Average 65.63 60.69 38.17 59.78 35.51
--------------------------------------------- ------- ------- ------- ------ ------
Natural gas ($/mcf)
US 3.51 3.03 1.29 3.33 1.19
Europe 17.07 8.94 2.34 10.96 2.22
Rest of World 5.26 4.13 2.99 4.44 3.21
BP Average 5.35 4.08 2.56 4.48 2.65
--------------------------------------------- ------- ------- ------- ------ ------
Total hydrocarbons* ($/boe)
US 45.39 41.14 22.04 41.24 23.01
Europe 81.99 63.85 36.14 66.51 34.34
Rest of World 45.13 40.27 27.40 40.45 26.19
BP Average 47.57 41.84 26.42 42.37 25.68
--------------------------------------------- ------- ------- ------- ------ ------
Average oil marker prices ($/bbl)
Brent 73.51 68.97 42.94 67.92 41.06
West Texas Intermediate 70.54 66.19 40.91 65.06 38.12
Western Canadian Select 56.95 53.10 31.62 52.06 27.54
Alaska North Slope 72.66 68.58 42.75 67.53 41.32
Mars 69.09 66.01 42.01 64.67 39.18
Urals (NWE - cif) 70.63 66.69 42.83 65.60 40.83
--------------------------------------------- ------- ------- ------- ------ ------
Average natural gas marker prices
Henry Hub gas price(b) ($/mmBtu) 4.02 2.83 1.98 3.19 1.88
UK Gas - National Balancing Point (p/therm) 118.81 64.79 21.06 78.38 19.69
--------------------------------------------- ------- ------- ------- ------ ------
(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
2021 2021 2020 2021 2020
------------------------------------- ------- ------- ------- ------ --------
$/GBP average rate for the period 1.38 1.40 1.29 1.39 1.27
$/GBP period-end rate 1.34 1.38 1.28 1.34 1.28
$/EUR average rate for the period 1.18 1.21 1.17 1.20 1.12
$/EUR period-end rate 1.16 1.19 1.17 1.16 1.17
$/AUD average rate for the period 0.73 0.77 0.71 0.76 0.67
$/AUD period-end rate 0.72 0.75 0.71 0.72 0.71
Rouble/$ average rate for the period 73.52 74.20 73.74 74.04 71.00
Rouble/$ period-end rate 72.78 72.70 77.57 72.78 77.57
-------------------------------------- ------- ------- ------- ------ ------
Top of page 35
Legal proceedings
For a full discussion of the group's material legal proceedings,
see pages 226-227 of bp Annual Report and Form 20-F 2020.
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.
New metrics have been introduced in 2021 to provide transparency
against key strategic value drivers.
Adjusted EBITDA is a non-GAAP measure presented for bp's
operating segments and is defined as replacement cost (RC) profit
before interest and tax, excluding net adjusting items*, adding
back depreciation, depletion and amortization and exploration
write-offs (net of adjusting items). Adjusted EBITDA by business is
a further analysis of adjusted EBITDA for the customers &
products businesses. bp believes it is helpful to disclose adjusted
EBITDA by operating segment and by business because it reflects how
the segments measure underlying business delivery. The nearest
equivalent measure on an IFRS basis for the segment is RC profit or
loss before interest and tax, which is bp's measure of profit or
loss that is required to be disclosed for each operating segment
under IFRS.
Adjusting items are items that bp discloses separately because
it considers such disclosures to be meaningful and relevant to
investors. They are items that management considers to be important
to period-on-period analysis of the group's results and are
disclosed in order to enable investors to better understand and
evaluate the group's reported financial performance. Adjusting
items include gains and losses on the sale of businesses and fixed
assets, impairments, environmental and other provisions,
restructuring, integration and rationalization costs, fair value
accounting effects, costs relating to the Gulf of Mexico oil spill
and other items. Adjusting items within equity-accounted earnings
are reported net of incremental income tax reported by the
equity-accounted entity. Adjusting items are used as a reconciling
adjustment to derive underlying RC profit or loss and related
underlying measures which are non-GAAP measures. An analysis of
adjusting items by segment and type is shown on page 30. Prior to
2021 adjusting items were reported under two different headings -
non-operating items and fair value accounting effects.
Capital expenditure is total cash capital expenditure as stated
in the condensed group cash flow statement. Capital expenditure for
the operating segments and customers & products businesses is
presented on the same basis.
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.
Convenience gross margin is a non-GAAP measure. Convenience
gross margin is calculated as RC profit before interest and tax for
the customers & products segment, excluding RC profit before
interest and tax for the refining & trading and petrochemicals
businesses, and adjusting items* (as defined above) for the
convenience & mobility business to derive underlying RC profit
before interest and tax for the convenience & mobility
business; subtracting underlying RC profit before interest and tax
for the Castrol business; adding back depreciation, depletion and
amortization, production and manufacturing, distribution and
administration expenses for convenience & mobility (excluding
Castrol); subtracting earnings from equity-accounted entities in
the convenience & mobility business (excluding Castrol) and
gross margin for the retail fuels, next-gen, aviation, B2B and
midstream businesses.
Convenience gross margin growth at constant foreign exchange is
a non-GAAP measure. This metric requires a calculation of the
comparative convenience gross margin ($ million) at current period
foreign exchange rates (constant foreign exchange) and compares the
current period value with the restated comparative period value,
which results in the growth % at constant foreign exchange rates.
bp believes the convenience gross margin and growth at constant
foreign exchange are useful measures because these measures may
help investors to understand and evaluate, in the same way as
management, our progress against our strategic objectives of
redefining convenience. The nearest GAAP measure to convenience
gross margin is RC profit before interest and tax for the customer
& products segment.
Developed renewables to final investment decision (FID) - Total
generating capacity for assets developed to FID by all entities
where bp has an equity share (proportionate to equity share). If
asset is subsequently sold bp will continue to record capacity as
developed to FID. If bp equity share increases developed capacity
to FID will increase proportionately to share increase for any
assets where bp held equity at the point of FID.
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.
Taxation on a RC basis for the group is calculated as taxation as
stated on the group income statement adjusted for taxation on
inventory holding gains and losses. 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. Taxation on
a RC basis and ETR on RC profit or loss are non-GAAP measures. The
nearest equivalent measure on an IFRS basis is the ETR on profit or
loss for the period.
Top of page 36
Glossary (continued)
Electric vehicle charge points are defined as charge points
operated by either bp or a bp joint venture.
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. Fair value accounting effects are included within
adjusting items. They relate to certain of the group's commodity,
interest rate and currency risk exposures as detailed below. Other
than as noted below, the fair value accounting effects described
are reported in both the gas & low carbon energy and customer
& products segments.
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, which is reported in the
gas and low carbon energy segment, reduces the measurement
differences between that of the derivative financial instruments
used to risk manage the LNG contracts and the measurement 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 & corporate segment, 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 37
Glossary (continued)
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. Net debt does not include accrued
interest, which is reported within other receivables and other
payables on the balance sheet and for which the associated cash
flows are presented as operating cash flows in the group cash flow
statement. 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
27.
We are unable to present reconciliations of forward-looking
information for net debt or 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
31.
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 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. The nearest
equivalent measure on an IFRS basis is capital expenditure on a
cash basis. Further information and a reconciliation to GAAP
information is provided on page 29.
Installed renewables capacity is bp's share of capacity for
operating assets owned by entities where bp has an equity
share.
Inventory holding gains and losses are non-GAAP adjustments to
our IFRS profit (loss) and represent:
a. 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 of inventories other than for trading
inventories, 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 as inventory holding gains and losses 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; and
b. an adjustment relating to certain trading inventories that
are not price risk managed which relate to a minimum inventory
volume that is required to be held to maintain underlying business
activities. This adjustment represents the movement in fair value
of the inventories due to prices, on a grade by grade basis, during
the period. This is calculated from each operation's inventory
management system on a monthly basis using the discrete monthly
movement in market prices for these inventories.
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 that are
price risk-managed. See Replacement cost (RC) profit or loss
definition below.
Liquids - Liquids for oil production & operations, gas &
low carbon energy and Rosneft comprises crude oil, condensate and
natural gas liquids. For oil production & operations and gas
& low carbon energy, 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.
Operating cash flow is net cash provided by (used in) operating
activities as stated in the condensed group cash flow
statement.
Top of page 38
Glossary (continued)
Organic capital expenditure is a non-GAAP measure. Organic
capital expenditure comprises capital expenditure on a cash basis
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. The nearest equivalent measure on an IFRS basis is
capital expenditure on a cash basis and a reconciliation to GAAP
information is provided on page 29.
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.
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.
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.
Renewables pipeline - Renewable projects satisfying criteria to
the point they can be considered developed to final investment
decision (FID): Site based projects have obtained land exclusivity
rights, or for PPA based projects an offer has been made to the
counterparty, or for auction projects pre-qualification criteria
has been met, or for acquisition projects post a binding offer
being accepted.
Replacement cost (RC) profit or loss / RC profit or loss
attributable to bp shareholders reflects the replacement cost of
inventories sold in the period and is calculated as profit or loss
attributable to bp shareholders, adjusting for inventory holding
gains and losses (net of tax). 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
bp's measure of profit or loss that is required to be disclosed for
each operating segment under IFRS.
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. Reported incidents are
investigated throughout the year and as a result there may be
changes in previously reported incidents. Therefore comparative
movements are calculated against internal data reflecting the final
outcomes of such investigations, rather than the previously
reported comparative period, as this this represents a more up to
date reflection of the safety environment.
Retail sites include sites operated by dealers, jobbers,
franchisees or brand licensees or joint venture (JV) partners,
under the bp brand. These may move to and from the bp brand as
their fuel supply agreement or brand licence agreement expires and
are renegotiated in the normal course of business. Retail sites are
primarily branded bp, ARCO, Amoco, Aral and Thorntons, and also
includes sites in India through our Jio-bp JV.
Retail sites in growth markets are retail sites that are either
bp branded or co-branded with our partners in China, Mexico and
Indonesia and also include sites in India through our Jio-bp
JV.
Solomon availability - See Refining availability definition.
Strategic convenience sites are retail sites, within the bp
portfolio, which both sell bp branded fuel and carry one of the
strategic convenience brands (e.g. M&S, Rewe to Go). To be
considered a strategic convenience brand the convenience offer
should be a strategic differentiator in the market in which it
operates. Strategic convenience site count includes sites under a
pilot phase.
Top of page 39
Glossary (continued)
Surplus cash flow is a non-GAAP measure and refers to the net
surplus of sources of cash over uses of cash, after reaching the
$35 billion net debt target. Sources of cash include net cash
provided by operating activities, cash provided from investing
activities and cash receipts relating to transactions involving
non-controlling interests. Uses of cash include lease liability
payments, payments on perpetual hybrid bond, dividends paid, cash
capital expenditure, the cash cost of share buybacks to offset the
dilution from vesting of awards under employee share schemes, cash
payments relating to transactions involving non-controlling
interests and currency translation differences relating to cash and
cash equivalents as presented on the condensed group cash flow
statement . See page 32 for the components of our sources of cash
and uses of cash.
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.
Reported process safety events are investigated throughout the year
and as a result there may be changes in previously reported events.
Therefore comparative movements are calculated against internal
data reflecting the final outcomes of such investigations, rather
than the previously reported comparative period, as this this
represents a more up to date reflection of the safety
environment.
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 for the group is calculated
as taxation as stated on the group income statement adjusted for
taxation on inventory holding gains and losses and total taxation
on adjusting items. Information on underlying RC profit or loss is
provided below. Taxation on an underlying RC basis presented for
the operating segments is calculated through an allocation of
taxation on an underlying RC basis to each segment. 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. Taxation on an underlying
RC basis and underlying ETR are non-GAAP measures. 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
and adjusting items, that are difficult to predict in advance in
order to include in a GAAP estimate.
Underlying production - 2021 underlying production, when
compared with 2020, 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 / underlying RC profit or loss
attributable to bp shareholders is a non-GAAP measure and is RC
profit or loss* (as defined on page 38) after excluding net
adjusting items and related taxation. See page 30 for additional
information on the adjusting items that are used to arrive at
underlying RC profit or loss in order to enable a full
understanding of the items and their financial impact. Underlying
RC profit or loss before interest and tax for the operating
segments or customers & products businesses is calculated as RC
profit or loss (as defined above) including profit or loss
attributable to non-controlling interests before interest and tax
for the operating segments and excluding net adjusting items for
the respective operating segment or business.
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 adjusting items. 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 and businesses is RC profit or loss before interest and
taxation. A reconciliation to GAAP information is provided on page
1 for the group and pages 6-14 for the segments.
Top of page 40
Glossary (continued)
Underlying RC profit or loss per share is a non-GAAP measure.
Earnings per share is defined in Note 7. Underlying RC profit or
loss per ordinary share is calculated using the same denominator as
earnings per share as defined in the consolidated financial
statements. The numerator used is underlying RC profit or loss
attributable to bp shareholders rather than profit or loss
attributable to bp shareholders. Underlying RC profit or loss per
ADS is calculated as outlined above for underlying RC profit or
loss per share except the denominator is adjusted to reflect one
ADS equivalent to six ordinary shares. bp believes it is helpful to
disclose the underlying RC profit or loss per ordinary share and
per ADS because these measures 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 includes oil and natural gas field development and
production within the gas & low carbon energy and oil
production & operations segments. References to upstream
exclude Rosneft.
upstream/hydrocarbon 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 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 and fair value accounting effects is a non-GAAP
measure. It is calculated by adjusting for inventory holding
gains/losses reported in the period and from the second quarter
onwards, it is also adjusted for fair value accounting effects
reported within adjusting items for the period. This 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 underlying 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.
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.
Trade marks
Trade marks of the bp group appear throughout this announcement.
They include:
bp , Amoco, Aral, Castrol ON and Thorntons
Top of page 41
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: expectations regarding the COVID-19
pandemic, including its risks, impacts, consequences, duration,
continued restrictions, challenges, bp's response, the impact on
bp's financial performance (including cash flows and net debt),
operations and credit losses, and the impact on the trading
environment, oil and gas prices, and global GDP; expectations
regarding the shape of the COVID-19 recovery and the pace of
transition to a lower-carbon economy and energy system; plans,
expectations and assumptions regarding oil and gas demand, supply
or prices, the timing of production of reserves, or decision making
by OPEC+; expectations regarding refining margins, refinery
utilization rates and product demand; expectations regarding bp's
future financial performance and cash flows; expectations regarding
future upstream production and project ramp-up; expectations
regarding supply shortages; expectations with respect to completion
of transactions and the timing and amount of proceeds of agreed
disposals; expectations with regards to bp's transformation to an
IEC; plans and expectations regarding bp's financial framework;
expectations regarding price assumptions used in accounting
estimates; bp's plans and expectations regarding the amount and
timing of share buybacks; expectations regarding future quarterly
dividends; plans and expectations regarding net debt; plans and
expectations regarding bp's credit rating, including in respect of
maintaining a strong investment grade credit rating; plans and
expectations regarding the allocation of surplus cash flow to share
buybacks and strengthening the balance sheet; plans and
expectations regarding bp's 2025 target of 20GW renewables
developed to FID and Lightsource bp's increased development target
for 2025; plans and expectations regarding the East Coast Cluster
and the Northern Endurance Partnership; plans and expectations with
respect to the total capital expenditure, depreciation, depletion
and amortization, expected tax rate and business and corporate
underlying annual charge for 2021; plans and expectations regarding
net debt; plans and expectations regarding the divestment
programme, including the amount and timing of proceeds in 2021, and
plans and expectations in respect of reaching $25 billion of
divestment and other proceeds by 2025 and expectations that
divestment and other proceeds for 2021 will be $6-7 billion; plans
and expectations regarding bp's renewable energy and alternative
energy businesses; expectations regarding reported and underlying
production and related major project ramp-up, capital investments,
divestment and maintenance activity; expectations regarding price
assumptions used in accounting estimates; expectations regarding
the underlying effective tax rate for 2021; expectations regarding
the timing and amount of future payments relating to the Gulf of
Mexico oil spill; plans and expectations that capital expenditure,
including inorganic capital expenditure, will reach around $13
billion in 2021; expectations regarding Rosneft's operational and
financial results and expectations with respect to Rosneft
dividends; plans and expectations regarding new joint ventures and
other agreements, including partnerships and other collaborations
with Prumo, Siemens, SPIC Brazil, Reliance Industries, Shenzhen
Gas, Swiggy, ADNOC, Masdar, Eni, Equinor, National Grid, Shell,
Total, EnBW, Albert Heijn, NYK Line, ExxonMobil, Daimler, BMW,
Albert Heijn and our Jio-bp JV, as well as plans and expectations
regarding the solar development projects acquired from 7X Energy,
the Thunder Horse South Expansion Phase 2 project, the sale of bp's
participating interest in the Shallow Water Absheron Peninsula
exploration project to LUKOIL, Yermak IJV's access to new license
blocks, the Thorntons business, bp's investment in Digital Charging
Solutions, bp's planned investment in the Cherry Point refinery,
the acquisition of Blueprint Power, and bp ventures' investment in
BluSmart.
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 volatility of oil prices, 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; changes in consumer preferences and
societal expectations; the pace of development and adoption of
alternative energy solutions; developments in policy, law,
regulation, technology and markets, including societal and investor
sentiment related to the issue of climate change; 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 and continued base oil and additive supply shortages; 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, as well those factors discussed
under "Risk factors" in bp Annual Report and Form 20-F 2020 as
filed with the US Securities and Exchange Commission.
Top of page 42
Contacts
London Houston
Press Office David Nicholas Brett Clanton
+44 (0)20 7496 4708 +1 281 366 8346
Investor Relations Craig Marshall Geoff Carr
bp.com/investors +44 (0)20 7496 4962 +1 281 892 3065
BP p.l.c.'s LEI Code 213800LH1BZH3D16G760
This information is provided by RNS, the news service of the
London Stock Exchange. RNS is approved by the Financial Conduct
Authority to act as a Primary Information Provider in the United
Kingdom. Terms and conditions relating to the use and distribution
of this information may apply. For further information, please
contact rns@lseg.com or visit www.rns.com.
RNS may use your IP address to confirm compliance with the terms
and conditions, to analyse how you engage with the information
contained in this communication, and to share such analysis on an
anonymised basis with others as part of our commercial services.
For further information about how RNS and the London Stock Exchange
use the personal data you provide us, please see our Privacy
Policy.
END
QRTBCBDBISGDGBB
(END) Dow Jones Newswires
November 02, 2021 03:00 ET (07:00 GMT)
Bp (LSE:BP.)
Historical Stock Chart
From Aug 2024 to Sep 2024
Bp (LSE:BP.)
Historical Stock Chart
From Sep 2023 to Sep 2024