REG - BP PLC - 3Q23 SEA Part 1 of 1
31/10/2023 07:00
For best results when printing this announcement, please click on link below:
http://newsfile.refinitiv.com/getnewsfile/v1/story?guid=urn:newsml:reuters.com:20231031:nRSe7730Ra&default-theme=true
RNS Number : 7730R BP PLC 31 October 2023
Top of page 1
FOR IMMEDIATE RELEASE
London 31 October 2023
BP p.l.c. Group results
Third quarter and nine months 2023
"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/7730R_1-2023-10-30.pdf
(http://www.rns-pdf.londonstockexchange.com/rns/7730R_1-2023-10-30.pdf)
Performing while transforming
Financial summary Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Profit (loss) for the period attributable to bp shareholders 4,858 1,792 (2,163) 14,868 (13,290)
Inventory holding (gains) losses*, net of tax (1,212) 549 2,186 (211) (2,085)
Replacement cost (RC) profit (loss)* 3,646 2,341 23 14,657 (15,375)
Net (favourable) adverse impact of adjusting items*, net of tax (353) 248 8,127 (3,812) 38,221
Underlying RC profit* 3,293 2,589 8,150 10,845 22,846
Operating cash flow* 8,747 6,293 8,288 22,662 27,361
Capital expenditure* (3,603) (4,314) (3,194) (11,542) (8,961)
Divestment and other proceeds((a)) 655 88 606 1,543 2,509
Surplus cash flow* 3,107 (269) 3,496 5,121 14,080
Net issue (repurchase) of shares (2,047) (2,073) (2,876) (6,568) (6,756)
Net debt*((b)) 22,324 23,660 22,002 22,324 22,002
Adjusted EBITDA* 10,306 9,770 17,407 33,142 47,647
Announced dividend per ordinary share (cents per share) 7.270 7.270 6.006 21.150 17.472
Underlying RC profit per ordinary share* (cents) 19.14 14.77 43.15 61.83 118.61
Underlying RC profit per ADS* (dollars) 1.15 0.89 2.59 3.71 7.12
• Underlying RC profit $3.3bn; Operating cash flow $8.7bn; Net debt reduced • Further $1.5bn share buyback announced • Delivering resilient hydrocarbons - start up of major project* - Tangguh • Continued progress to an IEC - first Archaea modular biogas plant;
to $22.3bn Expansion; North Sea Murlach project gets regulatory approval; bpx energy Woodfibre and OMV LNG agreements
brings online 'Bingo' facility
This has been a solid quarter supported by strong underlying operational
performance demonstrating our continued focus on delivery. Momentum continues
to build across our businesses, with recent start-ups including Tangguh
Expansion, bpx energy's 'Bingo' central processing facility and Archaea
Energy's first modular biogas plant in Indiana. As we laid out at our investor
update in Denver, we remain committed to executing our strategy, expect to
grow earnings through this decade, and on track to deliver strong returns for
our shareholders.
Murray Auchincloss
Chief executive officer (Interim)
(a) Divestment proceeds are disposal proceeds as per the condensed
group cash flow statement. See page 3 for more information on other proceeds.
(b) See Note 9 for more information.
RC profit (loss), underlying RC profit (loss), surplus cash flow, net debt,
adjusted EBITDA, underlying RC profit per ordinary share and underlying RC
profit per ADS are non-IFRS measures. Inventory holding (gains) losses and
adjusting items are non-IFRS adjustments.
* For items marked with an asterisk throughout this document, definitions are
provided in the Glossary on page 31.
Top of page 2
Highlights
Underlying replacement cost profit* $3.3 billion
• Underlying replacement cost profit for the quarter was $3.3
billion, compared with $2.6 billion for the previous quarter. Compared to the
second quarter 2023, the result reflects: higher realized refining margins,
lower level of refining turnaround activity, a very strong oil trading result,
higher oil and gas production, partly offset by a weak gas marketing and
trading result.
• Reported profit for the quarter was $4.9 billion, compared with
$1.8 billion for the second quarter 2023. The reported result for the third
quarter is adjusted for inventory holding gains* of $1.2 billion (net of tax)
and a net favourable impact of adjusting items* of $0.4 billion (net of tax)
to derive the underlying replacement cost profit. Adjusting items include
impairments of $1.2 billion and favourable fair value accounting effects* of
$1.5 billion.
Operating cash flow* $8.7 billion and net debt* reduced to $22.3 billion
• Operating cash flow in the quarter of $8.7 billion includes a
working capital* release (after adjusting for inventory holding gains, fair
value accounting effects and other adjusting items) of $2.0 billion (see page
27).
• Capital expenditure* in the third quarter was $3.6 billion. bp now
expects capital expenditure, including inorganic capital expenditure* to be
around $16 billion in 2023.
• During the third quarter, bp completed $2.0 billion of share
buybacks. This included $225 million as part of the $675 million programme
announced on 7 February 2023 to offset the expected full-year dilution from
the vesting of awards under employee share schemes in 2023. bp completed the
$675 million buyback programme on 1 September 2023.
• The $1.5 billion share buyback programme announced with the second
quarter results was completed on 27 October 2023.
• Net debt was reduced by $1.3 billion to $22.3 billion at the end
of the third quarter.
Further $ 1.5 billion share buyback within a disciplined financial frame
• A resilient dividend is bp's first priority within its disciplined
financial frame, underpinned by a cash balance point* of around $40 per barrel
Brent, $11 per barrel RMM and $3 per mmBtu Henry Hub (all 2021 real).
• For the third quarter, bp has announced a dividend per ordinary
share of 7.270 cents.
• bp remains committed to using 60% of 2023 surplus cash flow* for
share buybacks, subject to maintaining a strong investment grade credit
rating.
• bp intends to execute a further $1.5 billion share buyback prior
to reporting fourth quarter results.
• In setting the dividend per ordinary share and buyback each
quarter, the board will continue to 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.
• bp's guidance for distributions remains unchanged. Based on bp's
current forecasts, at around $60 per barrel Brent and subject to the board's
discretion each quarter, bp expects to be able to deliver share buybacks of
around $4.0 billion per annum, at the lower end of its $14-18 billion capital
expenditure range, and have capacity for an annual increase in the dividend
per ordinary share of around 4%.
Continued progress in transformation to an integrated energy company
• In resilient hydrocarbons, bp has announced the start-up of
Tangguh Expansion - the third major project* in 2023 - adding around 3.8mtpa
of producing capacity to the existing 7.6mtpa facility. It has safely produced
the first commercial cargo. In August, bpx energy successfully brought online
'Bingo', its second central processing facility in the Permian Basin. In
September, a regulatory approval was received for the Murlach oil and gas
development in the North Sea, a two well redevelopment of the Marnock-Skua
field back to the ETAP (Eastern Trough Area Project) hub. bp has accelerated
its biogas strategy - part of its bioenergy transition growth* engine - bp's
Archaea Energy announced the start-up of its original Archaea Modular Design
(AMD) renewable natural gas plant in Medora, Indiana.
• In convenience and mobility, bp continued to advance its growth
strategy in EV charging and convenience: announcing an agreement in October
with Tesla for the future purchase of $100 million of ultra-fast chargers in
the US - this is part of the approved $500 million of investment in the US;
and expanding its successful strategic convenience partnership with Auchan in
Poland, with plans to add more than 100 EasyAuchan stores to its retail
network by the end of 2025.
• In low carbon energy, bp has strengthened its renewables pipeline
to 43.9GW net to bp from the rights awarded to develop two offshore wind
projects, with total potential generating capacity of 4GW, in the German
tender round.
bp delivered robust operating cash flow in the quarter as we continue to
execute against our unchanged financial frame. Net debt reduced by $1.3
billion to $22.3 billion; we are investing with discipline; and we are
delivering on our commitment to shareholder distributions, announcing a
further $1.5 billion share buyback programme.
Kate Thomson
Chief financial officer (Interim)
The commentary above contains forward-looking statements and should be read in
conjunction with the cautionary statement on page 37.
Top of page 3
Financial results
In addition to the highlights on page 2:
• Profit attributable to bp shareholders in the third quarter and nine
months was $4.9 billion and $14.9 billion respectively, compared with a loss
of $2.2 billion and $13.3 billion in the same periods of 2022.
- After adjusting profit attributable to bp shareholders for inventory holding
gains* and net impact of adjusting items*, underlying replacement cost profit*
for the third quarter and nine months was $3.3 billion and $10.8 billion
respectively, compared with $8.2 billion and $22.8 billion for the same
periods of 2022. This reduction in underlying replacement cost profit for the
third quarter mainly reflects lower oil and gas realizations and a weak gas
marketing and trading result. For the nine months, the reduction reflects
lower oil and gas realizations; the impact of portfolio changes in oil
production & operations; a lower refining and oil trading performance; and
a weak gas marketing and trading result in the third quarter.
- Adjusting items in the third quarter and nine months had a net favourable
pre-tax impact of $0.5 billion and $3.8 billion respectively, compared with
an adverse pre-tax impact of $8.3 billion and $39.4 billion in the same
periods of 2022.
- Adjusting items for the third quarter and nine months of 2023 include a
favourable impact of pre-tax fair value accounting effects*, relative to
management's internal measure of performance, of $1.5 billion and $6.8 billion
respectively, compared with an adverse pre-tax impact of $10.1 billion and
$16.7 billion in the same periods of 2022. This is primarily due to a decline
in the forward price of LNG during the 2023 periods, but an increase in the
2022 comparative periods. 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. The underlying result includes the
mark-to-market value of the hedges but also recognizes changes in value of the
LNG contracts being risk managed.
- Adjusting items for the nine months 2022 include a pre-tax charge of
$24.0 billion relating to bp's decision to exit its 19.75% shareholding in
Rosneft. A further $1.5 billion pre-tax charge relating to bp's decision to
exit its other businesses with Rosneft in Russia is also included.
• The effective tax rate (ETR) on RC profit or loss* for the third quarter
and nine months was 33% and 32% respectively, compared with 96% and -242% for
the same periods in 2022. Excluding adjusting items, the underlying ETR* for
the third quarter and nine months was 33% and 39% respectively, compared with
37% and 33% for the same periods a year ago. The lower underlying ETR for the
third quarter reflects adjustments in respect of prior periods. The higher
underlying ETR for the nine months reflects changes in the geographical mix of
profits and the increased impact of the UK Energy Profits Levy. ETR on RC
profit or loss and underlying ETR are non-IFRS measures.
• Operating cash flow* for the third quarter and nine months was
$8.7 billion and $22.7 billion respectively, compared with $8.3 billion and
$27.4 billion for the same periods in 2022 driven by the movements in
underlying replacement cost profit and working capital in the periods.
• Capital expenditure* in the third quarter and nine months was
$3.6 billion and $11.5 billion respectively, compared with $3.2 billion and
$9.0 billion in the same periods of 2022. The nine months 2023 reflected the
inorganic $1.1 billion spend on the acquisition of TravelCenters of America in
the second quarter 2023.
• Total divestment and other proceeds for the third quarter and nine months
were $0.7 billion and $1.5 billion respectively, compared with $0.6 billion
and $2.5 billion for the same periods in 2022. Other proceeds for the third
quarter and nine months of 2023 were $0.5 billion of proceeds from the sale of
a 49% interest in a controlled affiliate holding certain midstream assets
onshore US. Other proceeds for the nine months of 2022 were $0.6 billion of
proceeds from the disposal of a loan note related to the Alaska divestment.
• At the end of the third quarter, net debt* was $22.3 billion, compared
with $23.7 billion at the end of the second quarter 2023 and $22.0 billion
at the end of the third quarter 2022.
Top of page 4
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 2023 2023 2022 2023 2022
RC profit (loss) before interest and tax
gas & low carbon energy 2,275 2,289 (2,956) 11,911 (1,743)
oil production & operations 3,427 2,568 6,965 9,312 18,033
customers & products 1,549 555 2,586 4,784 8,098
other businesses & corporate (500) (297) (1,093) (887) (26,840)
Of which:
other businesses & corporate excluding Rosneft (500) (297) (1,093) (887) (2,807)
Rosneft - - - - (24,033)
Consolidation adjustment - UPII* (57) (30) (21) (109) (8)
RC profit (loss) before interest and tax 6,694 5,085 5,481 25,011 (2,460)
Finance costs and net finance expense relating to pensions and other (978) (859) (633) (2,622) (1,816)
post-retirement benefits
Taxation on a RC basis (1,859) (1,724) (4,646) (7,156) (10,327)
Non-controlling interests (211) (161) (179) (576) (772)
RC profit (loss) attributable to bp shareholders* 3,646 2,341 23 14,657 (15,375)
Inventory holding gains (losses)* 1,593 (732) (2,868) 261 2,779
Taxation (charge) credit on inventory holding gains and losses (381) 183 682 (50) (694)
Profit (loss) for the period attributable to bp shareholders 4,858 1,792 (2,163) 14,868 (13,290)
Analysis of underlying RC profit (loss) before interest and tax
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Underlying RC profit (loss) before interest and tax
gas & low carbon energy 1,256 2,233 6,240 6,945 12,915
oil production & operations 3,136 2,777 5,211 9,232 15,796
customers & products 2,055 796 2,725 5,610 8,887
other businesses & corporate (303) (170) (405) (769) (865)
Of which:
other businesses & corporate excluding Rosneft (303) (170) (405) (769) (865)
Rosneft - - - - -
Consolidation adjustment - UPII (57) (30) (21) (109) (8)
Underlying RC profit before interest and tax 6,087 5,606 13,750 20,909 36,725
Finance costs and net finance expense relating to pensions and other (882) (740) (565) (2,303) (1,560)
post-retirement benefits
Taxation on an underlying RC basis (1,701) (2,116) (4,856) (7,185) (11,547)
Non-controlling interests (211) (161) (179) (576) (772)
Underlying RC profit attributable to bp shareholders* 3,293 2,589 8,150 10,845 22,846
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 2023 vs Nine months 2022
Tier 1 and tier 2 process safety events* 29 -7
Reported recordable injury frequency* 0.255 +31.8%
upstream* production((a)) (mboe/d) 2,310 +2.7%
upstream unit production costs*((b)) ($/boe) 5.88 -5.9%
bp-operated upstream plant reliability* 95.7% -0.1
bp-operated refining availability*((a)) 96.0% 1.6
(a) See Operational updates on pages 6, 9 and 11. Because of
rounding, upstream production may not agree exactly with the sum of gas &
low carbon energy and oil production & operations.
(b) Mainly reflecting impact of portfolio changes.
Top of page 5
Outlook & Guidance
Macro outlook
In the fourth quarter:
• bp expects oil prices to be supported by OPEC+ production restrictions and
the continued demand rebound;
• European gas and Asian LNG prices will be driven by weather, demand
recovery in Europe and China and ongoing geopolitical tension. In the US,
weather is also a risk factor, but higher than normal storage levels and
higher production should help to dampen volatility; and
• bp expects industry refining margins to be significantly lower than the
third quarter.
4Q23 guidance
• Looking ahead, we expect fourth-quarter 2023 reported upstream* production
to be broadly flat compared to third-quarter 2023.
• In its customers business, bp expects seasonally lower volumes with
marketing margins to remain sensitive to movements in the cost of supply. In
refining, we expect significantly lower realized refining margins and a higher
level of turnaround activity in the fourth quarter.
2023 guidance
In addition to the guidance on page 2:
• bp expects both reported and underlying upstream production to be higher
compared with 2022. Within this, bp expects underlying production from oil
production & operations to be higher and production from gas & low
carbon energy to be slightly lower. bp continues to expect four major project
start-ups during 2023.
• bp expects the other businesses & corporate underlying annual charge
to be at the lower end of the range $1.1-1.3 billion for 2023. The charge may
vary from quarter to quarter.
• bp continues to expect the depreciation, depletion and amortization to be
slightly above 2022.
• bp continues to expect the underlying ETR* for 2023 to be around 40% but
it 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.
• Having realized $17.5 billion of divestment and other proceeds since the
second quarter of 2020, bp continues to expect divestment and other proceeds
of $2-3 billion in 2023 and continues to expect to reach $25 billion of
divestment and other proceeds between the second half of 2020 and 2025.
• bp continues to expect Gulf of Mexico oil spill payments for the year to
be around $1.3 billion pre-tax including the $1.2 billion pre-tax payment made
during the second quarter.
• bp now expects capital expenditure* of around $16 billion in 2023
including inorganic capital expenditure*.
• bp is committed to maintaining a strong investment grade credit rating,
targeting further progress within an 'A' grade credit rating. For 2023 bp
continues to intend to allocate 40% of surplus cash flow* to further
strengthen the balance sheet.
• For 2023 and subject to maintaining a strong investment grade credit
rating, bp remains committed to using 60% of surplus cash flow for share
buybacks.
• In setting the dividend per ordinary share and buyback each quarter, the
board will continue to 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.
• 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 share buybacks of around $4.0 billion per annum, at the lower
end of its $14-18 billion capital expenditure range, and have capacity for an
annual increase in the dividend per ordinary share of around 4%.
Adjusted EBITDA* aims(a)
• bp has increased its 2030 Adjusted EBITDA aims for resilient hydrocarbons
and group by $2 billion to a range of $41-44 billion and $53-58 billion
respectively.
(a) Brent $70/bbl 2021 real, at bp planning assumptions, and at the
upper end of the respective expected capital expenditure* ranges.
The commentary above contains forward-looking statements and should be read in
conjunction with the cautionary statement on page 37.
Top of page 6
gas & low carbon energy*
Financial results
• The replacement cost (RC) profit before interest and tax for the
third quarter and nine months was $2,275 million and $11,911 million
respectively, compared with a loss of $2,956 million and $1,743 million for
the same periods in 2022. The third quarter and nine months are adjusted by a
favourable impact of net adjusting items* of $1,019 million and $4,966 million
respectively, compared with an adverse impact of net adjusting items of $9,196
million and $14,658 million for the same periods in 2022. Adjusting items
include impacts of fair value accounting effects*, relative to management's
internal measure of performance, which are a favourable impact of $1,816
million and $6,972 million for the third quarter and nine months in 2023 and
an adverse impact of $9,224 million and $14,313 million for the same periods
in 2022. 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. The underlying result includes the mark-to-market value of the
hedges but also recognizes changes in value of the LNG contracts being risk
managed, which decreased as forward prices fell during the nine months.
Adjusting items also include a net impairment charge of $224 million and
$1,284 million respectively, compared with net charges of $6 million and
$523 million for the same periods in 2022.
• After adjusting RC profit before interest and tax for adjusting
items, the underlying RC profit before interest and tax* for the third quarter
and nine months was $1,256 million and $6,945 million respectively, compared
with $6,240 million and $12,915 million for the same periods in 2022.
• The underlying RC profit for the third quarter and nine months,
compared with the same periods in 2022, both reflect lower realizations, a
higher depreciation, depletion and amortization charge, and a weak gas
marketing and trading result in the third quarter.
Operational update
• Reported production for the quarter was 946mboe/d, 3.6% lower
than the same period in 2022. Underlying production* was 2.6% lower, mainly
due to base decline and increased planned maintenance offset by major project*
delivery.
• Reported production for the nine months was 940mboe/d, 1.8%
lower than the same period in 2022. Underlying production was 2.2% lower,
mainly due to base decline partly offset by major project delivery.
• Renewables pipeline* at the end of the quarter was 43.9GW (bp
net), including 17.7GW bp net share of Lightsource bp's (LSbp's) pipeline. The
renewables pipeline increased by 6.7GW during the nine months due to bp being
awarded the rights to develop two North Sea offshore wind projects in Germany
(4GW) and increases to LSbp's pipeline. In addition, there is over 13GW (bp
net) of early stage opportunities in LSbp's hopper.
Strategic progress
gas
• On 19 October bp, on behalf of the Tangguh
production-sharing contract* partners (bp 40.22% operator), announced that the
first cargo of liquefied natural gas (LNG) produced by the new third
liquefaction train at the Tangguh LNG facility, in Papua Barat, Indonesia, has
safely been loaded and sailed. The start-up of Tangguh Train 3 will add 3.8
million tonnes per annum (mtpa) of gross LNG production capacity to the
existing facility, bringing total plant capacity to 11.4mtpa gross.
• On 26 September bp announced that a bp and Shell joint
venture (bp 50%, Shell 50%) had been awarded three deepwater exploration
blocks off Trinidad's east coast.
• bp continues to work towards its aim of building an LNG
portfolio of 30 million tonnes per year (mpta) by 2030:
◦ On July 28, bp and OMV announced the signing of a long-term
agreement to supply of up to 1mtpa of LNG for 10 years from 2026. This builds
on bp in May 2023 agreeing 2bcm per year of regasification capacity for 20
years at the Gate terminal in Rotterdam.
◦ On 5 September, bp announced its third long-term LNG offtake
contract from Woodfibre's British Columbia LNG facility with firm offtake
totalling 1.95mtpa and any additional production on a flexible offtake basis.
low carbon energy
• Hydrogen and CCS
◦ On 13 October the Midwest Alliance for Clean Hydrogen (MachH2), of
which bp is a member, announced it has been selected by the U.S. Department of
Energy's Office of Clean Energy Demonstrations to develop a Regional Clean
Hydrogen Hub. Under the proposals, it would include blue hydrogen* production
at or near bp's Whiting refinery and a potential hydrogen mobility corridor
across Indiana and neighbouring states.
◦ Hydrogen pipeline* at the end of the third quarter was 2.9mtpa, an
increase of 1.1mtpa compared with the start of the year.
• Offshore wind
◦ bp and its partner Equinor continue to work on options for their
US offshore wind projects to mitigate the effect of inflationary pressures and
permitting delays. A filing on 7 June with the New York Public Services
Commission (PSC) requesting to renegotiate the power purchase agreements
associated with three wind farms off the coast of New York (Empire Wind 1 and
2, Beacon Wind 1) was rejected on 12 October. Equinor and bp are assessing the
impact of the decision on these projects and future development plans. We have
recognized a pre-tax impairment charge of $540 million in the third quarter
related to these assets. The pre-tax charge is recorded through
equity-accounted earnings and is classified as an 'other' adjusting item.
Top of page 7
gas & low carbon energy (continued)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Profit (loss) before interest and tax 2,275 2,289 (2,970) 11,912 (1,741)
Inventory holding (gains) losses* - - 14 (1) (2)
RC profit (loss) before interest and tax 2,275 2,289 (2,956) 11,911 (1,743)
Net (favourable) adverse impact of adjusting items (1,019) (56) 9,196 (4,966) 14,658
Underlying RC profit before interest and tax 1,256 2,233 6,240 6,945 12,915
Taxation on an underlying RC basis (448) (575) (1,478) (1,984) (3,204)
Underlying RC profit before interest 808 1,658 4,762 4,961 9,711
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Depreciation, depletion and amortization
Total depreciation, depletion and amortization 1,543 1,407 1,177 4,390 3,635
Exploration write-offs
Exploration write-offs 15 (1) 10 13 8
Adjusted EBITDA*
Total adjusted EBITDA 2,814 3,639 7,427 11,348 16,558
Capital expenditure*
gas 833 697 872 2,177 2,195
low carbon energy 222 190 86 778 447
Total capital expenditure 1,055 887 958 2,955 2,642
Third Second Third Nine Nine
quarter quarter quarter months months
2023 2023 2022 2023 2022
Production (net of royalties)((a))
Liquids* (mb/d) 106 103 117 107 117
Natural gas (mmcf/d) 4,875 4,641 5,011 4,826 4,873
Total hydrocarbons* (mboe/d) 946 903 981 940 957
Average realizations*((b))
Liquids ($/bbl) 76.69 73.57 88.03 76.51 92.93
Natural gas ($/mcf) 5.38 5.53 9.85 6.11 8.74
Total hydrocarbons* ($/boe) 36.82 36.96 60.80 40.23 55.91
(a) Includes bp's share of production of equity-accounted entities
in the gas & low carbon energy segment.
(b) Realizations are based on sales by consolidated subsidiaries only
- this excludes equity-accounted entities.
Top of page 8
gas & low carbon energy (continued)
30 September 30 June 30 September
low carbon energy((c)) 2023 2023 2022
Renewables (bp net, GW)
Installed renewables capacity* 2.5 2.4 2.0
Developed renewables to FID* 6.1 6.1 4.6
Renewables pipeline 43.9 39.6 26.9
of which by geographical area:
Renewables pipeline - Americas 18.4 17.8 17.5
Renewables pipeline - Asia Pacific((d)) 12.1 12.2 1.7
Renewables pipeline - Europe 13.4 9.5 7.6
Renewables pipeline - Other - 0.1 0.1
of which by technology:
Renewables pipeline - offshore wind 9.3 5.3 5.2
Renewables pipeline - onshore wind 6.1 6.3 -
Renewables pipeline - solar 28.5 28.1 21.7
Total Developed renewables to FID and Renewables pipeline 50.0 45.7 31.5
(c) Because of rounding, some totals may not agree exactly with the
sum of their component parts.
(d) 30 September 2023 and 30 June 2023 include 10.3GW of onshore wind
and solar pipeline in support of hydrogen.
Top of page 9
oil production & operations
Financial results
• The replacement cost (RC) profit before interest and tax for the
third quarter and nine months was $3,427 million and $9,312 million
respectively, compared with $6,965 million and $18,033 million for the same
periods in 2022. The third quarter and nine months are adjusted by a
favourable impact of net adjusting items* of $291 million and $80 million
respectively, compared with a favourable impact of net adjusting items of
$1,754 million and $2,237 million for the same periods in 2022.
• After adjusting items, the underlying RC profit before interest
and tax* for the third quarter and nine months was $3,136 million and $9,232
million respectively, compared with $5,211 million and $15,796 million for the
same periods in 2022.
• The underlying RC profit for the third quarter and nine months
compared to the same periods in 2022, reflects lower realizations, and the
impact of portfolio changes, partly offset by higher volumes.
Operational update
• Reported production for the quarter was 1,382mboe/d, 5.0% higher
than the third quarter of 2022. Underlying production* for the quarter was
5.1% higher compared with the third quarter of 2022 reflecting reduced
seasonal maintenance, major projects* and bpx energy performance.
• Reported production for the nine months was 1,371mboe/d, 6.1%
higher than the same period of 2022. Underlying production for the nine months
was 5.6% higher compared with the same period of 2022 reflecting bpx energy
performance, reduced seasonal maintenance and major projects.
Strategic Progress
• In August bpx energy successfully brought online 'Bingo', its
second central processing facility in the Permian Basin. It is a low-emission,
electrified facility that will enable further production growth for bpx energy
in the basin (bp 100% operator).
• During the third quarter the Azeri Central East (ACE) platform
topsides were safely installed in the field. This is the 9th and most
automated platform installed in the giant Azeri Chirag Gunashli (ACG) field
with approximately 90,000 barrels a day installed capacity (bp 30.37%
operator).
• Regulatory approval was received on 8 September 2023 for the
Murlach oil and gas development in the North Sea, a two well redevelopment of
the Marnock-Skua field back to the ETAP (Eastern Trough Area Project) hub (bp
80% operator).
• In September, bp and its coventurers in the Clair joint venture,
made the final investment decision to proceed with the construction and
operation of the Shetland Crossover Pipeline, reinforcing the gas export
network and supporting UK security of supply (bp 45% operator).
• Moving forward with concept selection for a bp-operated Tiber
development project in the Gulf of Mexico.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Profit before interest and tax 3,426 2,568 6,966 9,312 18,028
Inventory holding (gains) losses* 1 - (1) - 5
RC profit before interest and tax 3,427 2,568 6,965 9,312 18,033
Net (favourable) adverse impact of adjusting items (291) 209 (1,754) (80) (2,237)
Underlying RC profit before interest and tax 3,136 2,777 5,211 9,232 15,796
Taxation on an underlying RC basis (1,386) (1,413) (2,921) (4,565) (7,128)
Underlying RC profit before interest 1,750 1,364 2,290 4,667 8,668
Top of page 10
oil production & operations (continued)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Depreciation, depletion and amortization
Total depreciation, depletion and amortization 1,432 1,370 1,381 4,129 4,181
Exploration write-offs
Exploration write-offs 59 242 180 352 310
Adjusted EBITDA*
Total adjusted EBITDA 4,627 4,389 6,772 13,713 20,287
Capital expenditure*
Total capital expenditure 1,644 1,478 1,386 4,642 3,848
Third Second Third Nine Nine
quarter quarter quarter months months
2023 2023 2022 2023 2022
Production (net of royalties)((a))
Liquids* (mb/d) 1,011 1,000 959 1,005 947
Natural gas (mmcf/d) 2,155 2,140 2,075 2,118 2,001
Total hydrocarbons* (mboe/d) 1,382 1,369 1,317 1,371 1,292
Average realizations*((b))
Liquids ($/bbl) 71.10 69.19 93.14 70.65 92.35
Natural gas((c)) ($/mcf) 3.44 3.23 12.12 4.37 10.54
Total hydrocarbons*((c)) ($/boe) 56.76 54.57 86.83 57.86 84.57
(a) Includes bp's share of production of equity-accounted entities
in the oil production & operations segment.
(b) Realizations are based on sales by consolidated subsidiaries only
- this excludes equity-accounted entities.
(c) Realizations calculation methodology has been changed to reflect
gas price fluctuations within the North Sea region. Third quarter 2022 and
nine months 2022 were restated. There is no impact on financial results.
Top of page 11
customers & products
Financial results
• The replacement cost (RC) profit before interest and tax for the
third quarter and nine months was $1,549 million and $4,784 million
respectively, compared with $2,586 million and $8,098 million for the same
periods in 2022. The third quarter and nine months are adjusted by an adverse
impact of net adjusting items* of $506 million and $826 million respectively,
compared with an adverse impact of net adjusting items of $139 million and
$789 million for the same periods in 2022. Adjusting items include impacts of
fair value accounting effects*, relative to management's internal measure of
performance, which are an adverse impact of $198 million for the quarter and
$230 million for the nine months in 2023, compared with an adverse impact of
$59 million and $498 million for the same periods in 2022.
• After adjusting items, the underlying RC profit before interest
and tax* for the third quarter and nine months was $2,055 million and $5,610
million respectively, compared with $2,725 million and $8,887 million for the
same periods in 2022.
• The customers & products result for the third quarter was
lower than the same period in 2022, with lower results in both customers and
refining. The result for the nine months was significantly lower than the same
period in 2022, primarily reflecting a lower refining and oil trading
performance.
• customers - the convenience and mobility results, excluding
Castrol, for the third quarter and nine months were lower than the same
periods in 2022. In the third quarter, the benefits of a strong convenience
performance and higher volumes were more than offset by a weaker retail
performance, compared with the same period last year, which had benefited from
higher margins as a result of falling cost of supply. In addition, the result
included higher costs, including increased expenditure in our transition
growth* engines, inflationary impacts and increased depreciation.
Castrol result for the third quarter was higher than the same period in 2022,
primarily due to higher margins. The result for the nine months was lower,
with higher margins more than offset by higher costs and adverse foreign
exchange impacts.
• products - the products results for the third quarter and nine
months were lower compared with the same periods in 2022, primarily due to
lower industry refining margins. In refining, the result for the third quarter
reflected lower realized refining margins, including the impact of narrower
North American heavy crude differentials, and lower commercial optimization
opportunities compared to the strong performance in the same period last year.
This was partially offset by lower maintenance activity. In addition, the
result for the nine months was impacted by higher turnaround activity. The oil
trading contribution for the third quarter was very strong compared to the
average result in the same period last year. The result for the nine months
however was lower, as the first half of 2022 benefited from an exceptionally
strong oil trading performance.
Operational update
• bp-operated refining availability* for the third quarter and
nine months was 96.3% and 96.0% respectively, higher compared with 94.3% and
94.4% for the same periods in 2022.
Strategic progress
• In support of bp's convenience transition growth engine
delivery, bp signed an agreement in August with Auchan to extend its
successful strategic convenience partnership in Poland, with plans to add more
than 100 EasyAuchan stores to its retail network by the end of 2025. In
addition, in September, bp strengthened its BPme Rewards loyalty scheme with
the launch of loyalty pricing, giving customers exclusive discounts on retail
store products at around 300 bp company-owned retail sites across the UK.
• In August, bp announced it had approved $500 million of
investment in the US to begin building its EV network over the next two to
three years. As part of this investment, in October, bp announced it had
entered into an agreement with Tesla for the future purchase of $100 million
of ultra-fast chargers.
• In September, bp pulse, The EV Network and NEC Group, launched
the UK's largest public EV charging hub at the NEC campus in Birmingham, UK.
The new Gigahub™ at the NEC boasts 30 ultra-fast 150KW and 150 fast 7kW
charge points enabling 180 EVs to charge simultaneously.
• In September, Castrol opened the Castrol Americas Technology
Center, in Wayne, New Jersey. This is a 12,000 square foot, state-of-the-art
laboratory to develop and test fluids for electric vehicles, engine and
driveline oils and industrial lubricants.
• In October, bp's Archaea Energy announced the official start-up
of its original Archaea Modular Design (AMD) renewable natural gas plant in
Medora, Indiana, located next to a landfill site owned by Rumpke Waste and
Recycling.
Top of page 12
customers & products (continued)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Profit (loss) before interest and tax 3,143 (177) (269) 5,044 10,880
Inventory holding (gains) losses* (1,594) 732 2,855 (260) (2,782)
RC profit before interest and tax 1,549 555 2,586 4,784 8,098
Net (favourable) adverse impact of adjusting items 506 241 139 826 789
Underlying RC profit before interest and tax 2,055 796 2,725 5,610 8,887
Of which:((a))
customers - convenience & mobility 670 701 1,137 1,762 2,338
Castrol - included in customers 185 171 151 517 630
products - refining & trading 1,385 95 1,588 3,848 6,549
Taxation on an underlying RC basis (167) (271) (725) (1,215) (1,908)
Underlying RC profit before interest 1,888 525 2,000 4,395 6,979
(a) A reconciliation to RC profit before interest and tax by
business is provided on page 29.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Adjusted EBITDA*((b))
customers - convenience & mobility 1,151 1,149 1,448 3,032 3,290
Castrol - included in customers 228 213 187 641 743
products - refining & trading 1,819 541 1,974 5,184 7,726
2,970 1,690 3,422 8,216 11,016
Depreciation, depletion and amortization
Total depreciation, depletion and amortization 915 894 697 2,606 2,129
Capital expenditure*
customers - convenience & mobility 435 1,452 404 2,345 1,085
Castrol - included in customers 60 44 42 172 137
products - refining & trading 367 406 309 1,305 1,018
Total capital expenditure 802 1,858 713 3,650 2,103
(b) A reconciliation to RC profit before interest and tax by business
is provided on page 29.
Retail((c)) Third Second Third Nine Nine
quarter quarter quarter months months
2023 2023 2022 2023 2022
bp retail sites* - total (#) 21,150 21,100 20,550 21,150 20,550
Strategic convenience sites* 2,750 2,750 2,250 2,750 2,250
(c) Reported to the nearest 50.
Marketing sales of refined products (mb/d) Third Second Third Nine Nine
quarter quarter quarter months months
2023 2023 2022 2023 2022
US 1,280 1,275 1,143 1,212 1,140
Europe 1,093 1,056 1,098 1,041 1,005
Rest of World 474 472 451 469 454
2,847 2,803 2,692 2,722 2,599
Trading/supply sales of refined products 392 353 355 359 359
Total sales volume of refined products 3,239 3,156 3,047 3,081 2,958
Top of page 13
customers & products (continued)
Refining marker margin* Third Second Third Nine Nine
quarter quarter quarter months months
2023 2023 2022 2023 2022
bp average refining marker margin (RMM)((d)) ($/bbl) 31.8 24.7 35.5 28.2 33.4
(d) The RMM in the quarter is calculated based on bp's current
refinery portfolio. On a comparative basis, the third quarter and nine months
2022 RMM would be $35.4/bbl and $33.4/bbl respectively.
Refinery throughputs (mb/d) Third Second Third Nine Nine
quarter quarter quarter months months
2023 2023 2022 2023 2022
US 690 638 703 671 700
Europe 760 726 809 773 818
Rest of World - - - - 29
Total refinery throughputs 1,450 1,364 1,512 1,444 1,547
bp-operated refining availability* (%) 96.3 95.7 94.3 96.0 94.4
Top of page 14
other businesses & corporate
Other businesses & corporate comprises innovation & engineering, bp
ventures, Launchpad, regions, corporates & solutions, our corporate
activities & functions and any residual costs of the Gulf of Mexico oil
spill. It also includes Rosneft results up to 27 February 2022.
Financial results
• The replacement cost (RC) loss before interest and tax for the
third quarter and nine months was $500 million and $887 million respectively,
compared with a loss of $1,093 million and $26,840 million for the same
periods in 2022. The third quarter and nine months are adjusted by an adverse
impact of net adjusting items* of $197 million and $118 million respectively,
compared with an adverse impact of net adjusting items of $688 million and
$25,975 million for the same periods in 2022. Adjusting items include impacts
of fair value accounting effects* which are an adverse impact of $146 million
for the quarter and a favourable impact of $51 million for the nine months in
2023, an adverse impact of $785 million and $1,896 million for the same
periods in 2022. The adjusting items for the nine months in 2022 mainly relate
to Rosneft.
• After adjusting RC loss for net adjusting items, the underlying
RC loss before interest and tax* for the third quarter and nine months was
$303 million and $769 million respectively, compared with a loss of $405
million and $865 million for the same periods in 2022.
Strategic progress
• In August bp ventures invested $5 million in Advanced Ionics, a
company developing a new category of hydrogen electrolyzers, supporting the
expansion of green hydrogen* production.
• In August bp ventures announced that it had invested $5 million
in Dynamon, which provides advanced data analytics and AI tools helping the
road transport industry maximize sustainability.
• In July bp ventures invested $30 million in Electric Hydrogen, a
company which is developing high efficiency and lower cost electrolyzers with
the aim of delivering its first 100MW product in 2024.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Profit (loss) before interest and tax (500) (297) (1,093) (887) (26,840)
Inventory holding (gains) losses* - - - - -
RC profit (loss) before interest and tax (500) (297) (1,093) (887) (26,840)
Net (favourable) adverse impact of adjusting items((a)) 197 127 688 118 25,975
Underlying RC profit (loss) before interest and tax (303) (170) (405) (769) (865)
Taxation on an underlying RC basis 162 10 206 201 396
Underlying RC profit (loss) before interest (141) (160) (199) (568) (469)
(a) Includes fair value accounting effects relating to the hybrid
bonds that were issued on 17 June 2020. See page 32 for more information.
other businesses & corporate (excluding Rosneft)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Profit (loss) before interest and tax (500) (297) (1,093) (887) (2,807)
Inventory holding (gains) losses* - - - - -
RC profit (loss) before interest and tax (500) (297) (1,093) (887) (2,807)
Net (favourable) adverse impact of adjusting items 197 127 688 118 1,942
Underlying RC profit (loss) before interest and tax (303) (170) (405) (769) (865)
Taxation on an underlying RC basis 162 10 206 201 396
Underlying RC profit (loss) before interest (141) (160) (199) (568) (469)
other businesses & corporate (Rosneft)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Profit (loss) before interest and tax - - - - (24,033)
Inventory holding (gains) losses* - - - - -
RC profit (loss) before interest and tax - - - - (24,033)
Net (favourable) adverse impact of adjusting items - - - - 24,033
Underlying RC profit (loss) before interest and tax - - - - -
Taxation on an underlying RC basis - - - - -
Underlying RC profit (loss) before interest - - - - -
Top of page 15
Financial statements
Group income statement
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Sales and other operating revenues (Note 5) 53,269 48,538 55,011 157,989 172,135
Earnings from joint ventures - after interest and tax (198) 360 498 357 939
Earnings from associates - after interest and tax 271 231 275 675 1,273
Interest and other income 410 378 159 1,036 495
Gains on sale of businesses and fixed assets 264 (28) 1,866 389 3,693
Total revenues and other income 54,016 49,479 57,809 160,446 178,535
Purchases 29,951 29,172 39,993 88,245 106,942
Production and manufacturing expenses 6,080 6,231 7,193 19,293 21,769
Production and similar taxes 456 404 639 1,334 1,768
Depreciation, depletion and amortization (Note 6) 4,145 3,923 3,467 11,868 10,604
Net impairment and losses on sale of businesses and fixed assets (Note 3) 542 1,269 417 1,899 26,893
Exploration expense 97 293 225 496 445
Distribution and administration expenses 4,458 3,834 3,262 12,039 9,795
Profit (loss) before interest and taxation 8,287 4,353 2,613 25,272 319
Finance costs 1,039 920 649 2,802 1,869
Net finance (income) expense relating to pensions and other post-retirement (61) (61) (16) (180) (53)
benefits
Profit (loss) before taxation 7,309 3,494 1,980 22,650 (1,497)
Taxation 2,240 1,541 3,964 7,206 11,021
Profit (loss) for the period 5,069 1,953 (1,984) 15,444 (12,518)
Attributable to
bp shareholders 4,858 1,792 (2,163) 14,868 (13,290)
Non-controlling interests 211 161 179 576 772
5,069 1,953 (1,984) 15,444 (12,518)
Earnings per share (Note 7)
Profit (loss) for the period attributable to bp shareholders
Per ordinary share (cents)
Basic 28.24 10.22 (11.45) 84.77 (69.01)
Diluted 27.59 10.01 (11.45) 82.99 (69.01)
Per ADS (dollars)
Basic 1.69 0.61 (0.69) 5.09 (4.14)
Diluted 1.66 0.60 (0.69) 4.98 (4.14)
Top of page 16
Condensed group statement of comprehensive income
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Profit (loss) for the period 5,069 1,953 (1,984) 15,444 (12,518)
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences((a)) (590) 11 (1,725) (126) (5,928)
Exchange (gains) losses on translation of foreign operations reclassified to (2) - - (2) 10,791
gain or loss on sale of businesses and fixed assets((b))
Cash flow hedges and costs of hedging (56) (56) (142) 434 179
Share of items relating to equity-accounted entities, net of tax 25 (27) (134) (205) 10
Income tax relating to items that may be reclassified (69) 71 (54) (74) (226)
(692) (1) (2,055) 27 4,826
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability (111) (855) 112 (1,053) 1,848
or asset
Cash flow hedges that will subsequently be transferred to the balance sheet (1) - (1) (1) (5)
Income tax relating to items that will not be reclassified 57 308 19 388 (470)
(55) (547) 130 (666) 1,373
Other comprehensive income (747) (548) (1,925) (639) 6,199
Total comprehensive income 4,322 1,405 (3,909) 14,805 (6,319)
Attributable to
bp shareholders 4,140 1,240 (4,042) 14,241 (6,978)
Non-controlling interests 182 165 133 564 659
4,322 1,405 (3,909) 14,805 (6,319)
(a) Third quarter 2022 is principally affected by movements in the
Pound Sterling against the US dollar. Nine months 2022 is principally affected
by movements in the Russian rouble and Pound Sterling against the US dollar.
(b) Nine months 2022 predominantly relates to the loss of significant
influence over Rosneft.
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 2023 67,553 13,390 2,047 82,990
Total comprehensive income 14,241 438 126 14,805
Dividends (3,598) - (326) (3,924)
Repurchase of ordinary share capital (6,666) - - (6,666)
Share-based payments, net of tax 531 - - 531
Issue of perpetual hybrid bonds (1) 163 - 162
Payments on perpetual hybrid bonds (5) (494) - (499)
Transactions involving non-controlling interests, net of tax 363 - (86) 277
At 30 September 2023 72,418 13,497 1,761 87,676
bp shareholders' Non-controlling interests Total
$ million equity((a)) Hybrid bonds Other interest equity
At 1 January 2022 75,463 13,041 1,935 90,439
Total comprehensive income (6,978) 383 276 (6,319)
Dividends (3,267) - (194) (3,461)
Issue of ordinary share capital((b)) 820 - - 820
Repurchase of ordinary share capital (7,988) - - (7,988)
Share-based payments, net of tax 631 - - 631
Issue of perpetual hybrid bonds (3) 325 - 322
Payments on perpetual hybrid bonds 15 (462) - (447)
Transactions involving non-controlling interests, net of tax (512) - (152) (664)
At 30 September 2022 58,181 13,287 1,865 73,333
(a) In 2022 $9.2 billion of the opening foreign currency translation
reserve has been moved to the profit and loss account reserve as a result of
bp's decision to exit its shareholding in Rosneft and its other businesses
with Rosneft in Russia.
(b) Relates to ordinary shares issued as non-cash consideration for
the acquisition of the public units of BP Midstream Partners LP.
Top of page 18
Group balance sheet
30 September 31 December
$ million 2023 2022
Non-current assets
Property, plant and equipment 107,163 106,044
Goodwill 12,283 11,960
Intangible assets 9,997 10,200
Investments in joint ventures 12,635 12,400
Investments in associates 7,954 8,201
Other investments 2,337 2,670
Fixed assets 152,369 151,475
Loans 1,656 1,271
Trade and other receivables 1,066 1,092
Derivative financial instruments 9,495 12,841
Prepayments 600 576
Deferred tax assets 3,470 3,908
Defined benefit pension plan surpluses 8,173 9,269
176,829 180,432
Current assets
Loans 363 315
Inventories 25,671 28,081
Trade and other receivables 31,558 34,010
Derivative financial instruments 12,950 11,554
Prepayments 1,333 2,092
Current tax receivable 674 621
Other investments 932 578
Cash and cash equivalents 29,926 29,195
103,407 106,446
Assets classified as held for sale (Note 2) - 1,242
103,407 107,688
Total assets 280,236 288,120
Current liabilities
Trade and other payables 60,440 63,984
Derivative financial instruments 6,542 12,618
Accruals 5,958 6,398
Lease liabilities 2,536 2,102
Finance debt 2,872 3,198
Current tax payable 3,054 4,065
Provisions 4,193 6,332
85,595 98,697
Liabilities directly associated with assets classified as held for sale (Note - 321
2)
85,595 99,018
Non-current liabilities
Other payables 9,465 10,387
Derivative financial instruments 11,409 13,537
Accruals 1,273 1,233
Lease liabilities 8,343 6,447
Finance debt 45,938 43,746
Deferred tax liabilities 10,293 10,526
Provisions 15,497 14,992
Defined benefit pension plan and other post-retirement benefit plan deficits 4,747 5,244
106,965 106,112
Total liabilities 192,560 205,130
Net assets 87,676 82,990
Equity
bp shareholders' equity 72,418 67,553
Non-controlling interests 15,258 15,437
Total equity 87,676 82,990
Top of page 19
Condensed group cash flow statement
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Operating activities
Profit (loss) before taxation 7,309 3,494 1,980 22,650 (1,497)
Adjustments to reconcile profit (loss) before taxation to net cash provided by
operating activities
Depreciation, depletion and amortization and exploration expenditure written 4,219 4,164 3,657 12,233 10,922
off
Net impairment and (gain) loss on sale of businesses and fixed assets 278 1,297 (1,449) 1,510 23,200
Earnings from equity-accounted entities, less dividends received 421 (31) (391) 391 (1,412)
Net charge for interest and other finance expense, less net interest paid 136 102 72 301 210
Share-based payments 298 243 251 519 629
Net operating charge for pensions and other post-retirement benefits, less (40) (47) (15) (130) (197)
contributions and benefit payments for unfunded plans
Net charge for provisions, less payments (342) (221) 173 (1,662) 1,453
Movements in inventories and other current and non-current assets and (783) (742) 6,764 (5,280) 577
liabilities
Income taxes paid (2,749) (1,966) (2,754) (7,870) (6,524)
Net cash provided by operating activities 8,747 6,293 8,288 22,662 27,361
Investing activities
Expenditure on property, plant and equipment, intangible and other assets (3,456) (3,453) (3,105) (10,038) (8,373)
Acquisitions, net of cash acquired (9) (804) (3) (761) (8)
Investment in joint ventures (102) (50) (40) (692) (493)
Investment in associates (36) (7) (46) (51) (87)
Total cash capital expenditure (3,603) (4,314) (3,194) (11,542) (8,961)
Proceeds from disposal of fixed assets 59 28 12 102 682
Proceeds from disposal of businesses, net of cash disposed 79 60 594 924 1,254
Proceeds from loan repayments 12 21 15 39 60
Cash provided from investing activities 150 109 621 1,065 1,996
Net cash used in investing activities (3,453) (4,205) (2,573) (10,477) (6,965)
Financing activities
Net issue (repurchase) of shares (Note 7) (2,047) (2,073) (2,876) (6,568) (6,756)
Lease liability payments (663) (620) (478) (1,838) (1,448)
Proceeds from long-term financing 8 3,643 1 6,046 2,003
Repayments of long-term financing (264) (2,828) (4,035) (3,891) (9,500)
Net increase (decrease) in short-term debt (71) (348) (618) (948) (1,582)
Issue of perpetual hybrid bonds 30 87 194 162 322
Payments relating to perpetual hybrid bonds (258) (250) (180) (744) (489)
Payments relating to transactions involving non-controlling interests (Other - - (2) (180) (8)
interest)
Receipts relating to transactions involving non-controlling interests (Other 527 2 3 536 10
interest)
Dividends paid - bp shareholders (1,249) (1,153) (1,140) (3,585) (3,270)
- non-controlling interests (191) (67) (66) (326) (194)
Net cash provided by (used in) financing activities (4,178) (3,607) (9,197) (11,336) (20,912)
Currency translation differences relating to cash and cash equivalents (104) - (322) (118) (861)
Increase (decrease) in cash and cash equivalents 1,012 (1,519) (3,804) 731 (1,377)
Cash and cash equivalents at beginning of period 28,914 30,433 33,108 29,195 30,681
Cash and cash equivalents at end of period 29,926 28,914 29,304 29,926 29,304
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 2022
included in BP Annual Report and Form 20-F 2022.
The directors consider it appropriate to adopt the going concern basis of
accounting in preparing these interim financial statements. 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 UK, and European Union (EU), and in accordance with the provisions of
the UK Companies Act 2006 as applicable to companies reporting under
international accounting standards. IFRS as adopted by the UK does not differ
from IFRS as adopted by the EU except for the Pillar Two amendments noted
below. IFRS as adopted by the UK and EU 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 2023 which are the same as those used in preparing BP Annual Report and
Form 20-F 2022.
In May 2023 the IASB issued International Tax Reform - Pillar Two Model Rules
- Amendments to IAS 12 Income Taxes to clarify the application of IAS 12 to
tax legislation enacted or substantively enacted to implement Pillar Two of
the Organisation for Economic Co-operation and Development's Base Erosion and
Profit Shifting project, which aims to address the tax challenges arising from
the digitalisation of the economy. The amendments include a mandatory
temporary exception from accounting for deferred tax on such tax law. The
amendments were adopted by the UK in July and are yet to be adopted by the EU,
however no impact is expected on the financial statements for 2023.
In July 2023 the UK government enacted legislation to implement the Pillar Two
rules. The legislation is effective for bp from 1 January 2024 and includes an
income inclusion rule and a domestic minimum tax, which together are designed
to ensure a minimum effective tax rate of 15% in each country in which the
group operates. Similar legislation is being enacted by other governments
around the world. As a result of the amendments to IAS 12, no impact is
expected on the financial statements in 2023, and work is ongoing to assess
the potential impact in the 2024 financial statements.
There are no other new or amended standards or interpretations adopted from 1
January 2023 onwards, including IFRS 17 'Insurance Contracts,' that have a
significant impact on the financial information.
Significant accounting judgements and estimates
bp's significant accounting judgements and estimates were disclosed in BP
Annual Report and Form 20-F 2022. These have been subsequently considered at
the end of each quarter to determine if any changes were required to those
judgements and estimates. No significant changes were identified.
Investment in Rosneft
Since the first quarter 2022, bp accounts for its interest in Rosneft and its
other businesses with Rosneft within Russia, as financial assets measured at
fair value within 'Other investments'. It is considered by management that any
measure of fair value, other than nil, would be subject to such high
measurement uncertainty that no estimate would provide useful information even
if it were accompanied by a description of the estimate made in producing it
and an explanation of the uncertainties that affect the estimate. Accordingly,
it is not currently possible to estimate any carrying value other than zero
when determining the measurement of the interest in Rosneft and the other
businesses with Rosneft within Russia as at 30 September 2023.
Top of page 21
Note 2. Non-current assets held for sale
There were no assets or liabilities classified as held for sale at 30
September 2023.
Note 3. Impairment and losses on sale of businesses and fixed assets
Net impairment charges and losses on sale of businesses and fixed assets for
the third quarter and nine months were $542 million and $1,899 million
respectively, compared with net charges of $417 million and $26,893 million
for the same periods in 2022 and include net impairment charges for the third
quarter and nine months of $612 million and $1,779 million respectively,
compared with net impairment reversals of $11 million and charges of
$14,777 million for the same periods in 2022.
Third quarter and nine months of 2023 impairments includes a net impairment
charge of $224 million and $1,284 million respectively, compared with net
charges of $6 million and $523 million for the same periods in 2022 in the
gas & low carbon energy segment. A further $540 million pre-tax impairment
charge relating to our offshore US wind assets has been recognised in the
third quarter 2023 through equity-accounted earnings.
The impairment charge and the loss on sale of businesses and fixed assets for
2022 mainly relates to bp's investment in Rosneft, which has been reported in
other businesses and corporate.
Note 4. Analysis of replacement cost profit (loss) before interest and tax and
reconciliation to profit (loss) before taxation
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
gas & low carbon energy 2,275 2,289 (2,956) 11,911 (1,743)
oil production & operations 3,427 2,568 6,965 9,312 18,033
customers & products 1,549 555 2,586 4,784 8,098
other businesses & corporate (500) (297) (1,093) (887) (26,840)
6,751 5,115 5,502 25,120 (2,452)
Consolidation adjustment - UPII* (57) (30) (21) (109) (8)
RC profit (loss) before interest and tax 6,694 5,085 5,481 25,011 (2,460)
Inventory holding gains (losses)*
gas & low carbon energy - - (14) 1 2
oil production & operations (1) - 1 - (5)
customers & products 1,594 (732) (2,855) 260 2,782
Profit (loss) before interest and tax 8,287 4,353 2,613 25,272 319
Finance costs 1,039 920 649 2,802 1,869
Net finance expense/(income) relating to pensions and other post-retirement (61) (61) (16) (180) (53)
benefits
Profit (loss) before taxation 7,309 3,494 1,980 22,650 (1,497)
RC profit (loss) before interest and tax*
US 1,467 2,244 3,954 6,786 9,553
Non-US 5,227 2,841 1,527 18,225 (12,013)
6,694 5,085 5,481 25,011 (2,460)
Top of page 22
Note 5. Sales and other operating revenues
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
By segment
gas & low carbon energy 10,313 10,428 8,053 38,627 29,462
oil production & operations 6,225 5,777 8,599 18,155 26,261
customers & products 42,908 38,051 47,831 119,841 145,551
other businesses & corporate 672 590 552 2,000 1,520
60,118 54,846 65,035 178,623 202,794
Less: sales and other operating revenues between segments
gas & low carbon energy 367 840 2,785 1,743 6,354
oil production & operations 5,747 5,236 7,589 17,244 23,378
customers & products 508 (180) (276) 472 808
other businesses & corporate 227 412 (74) 1,175 119
6,849 6,308 10,024 20,634 30,659
External sales and other operating revenues
gas & low carbon energy 9,946 9,588 5,268 36,884 23,108
oil production & operations 478 541 1,010 911 2,883
customers & products 42,400 38,231 48,107 119,369 144,743
other businesses & corporate 445 178 626 825 1,401
Total sales and other operating revenues 53,269 48,538 55,011 157,989 172,135
By geographical area
US 22,032 20,065 22,451 61,257 68,934
Non-US 43,382 38,492 45,111 128,224 142,239
65,414 58,557 67,562 189,481 211,173
Less: sales and other operating revenues between areas 12,145 10,019 12,551 31,492 39,038
53,269 48,538 55,011 157,989 172,135
Revenues from contracts with customers
Sales and other operating revenues include the following in relation to
revenues from contracts with customers:
Crude oil 496 520 1,322 1,653 5,500
Oil products 35,486 31,218 40,036 96,845 115,054
Natural gas, LNG and NGLs 6,396 5,841 11,106 21,881 30,730
Non-oil products and other revenues from contracts with customers 2,765 2,750 2,267 7,387 6,437
Revenue from contracts with customers 45,143 40,329 54,731 127,766 157,721
Other operating revenues((a)) 8,126 8,209 280 30,223 14,414
Total sales and other operating revenues 53,269 48,538 55,011 157,989 172,135
(a) Principally relates to commodity derivative transactions
including sales of bp own production in trading books.
( )
Top of page 23
Note 6. Depreciation, depletion and amortization
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Total depreciation, depletion and amortization by segment
gas & low carbon energy 1,543 1,407 1,177 4,390 3,635
oil production & operations 1,432 1,370 1,381 4,129 4,181
customers & products 915 894 697 2,606 2,129
other businesses & corporate 255 252 212 743 659
4,145 3,923 3,467 11,868 10,604
Total depreciation, depletion and amortization by geographical area
US 1,479 1,338 1,180 4,071 3,422
Non-US 2,666 2,585 2,287 7,797 7,182
4,145 3,923 3,467 11,868 10,604
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.
Against the authority granted at bp's 2022 annual general meeting,
331 million ordinary shares repurchased for cancellation were settled during
the third quarter 2023 for a total cost of $2,047 million. A further
92 million ordinary shares were repurchased between the end of the reporting
period and the date when the financial statements are authorised for issue for
a total cost of $595 million. This amount has been accrued at 30 September
2023. The number of shares in issue is reduced when shares are repurchased,
but is not reduced in respect of the period-end commitment to repurchase
shares subsequent to the end of the period.
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 2023 2023 2022 2023 2022
Results for the period
Profit (loss) for the period attributable to bp shareholders 4,858 1,792 (2,163) 14,868 (13,290)
Less: preference dividend - 1 - 1 1
Profit (loss) attributable to bp ordinary shareholders 4,858 1,791 (2,163) 14,867 (13,291)
Number of shares (thousand)((a)(b))
Basic weighted average number of shares outstanding 17,204,488 17,523,778 18,885,725 17,537,170 19,260,486
ADS equivalent((c)) 2,867,414 2,920,629 3,147,620 2,922,861 3,210,081
Weighted average number of shares outstanding used to calculate diluted 17,609,601 17,900,984 18,885,725 17,914,383 19,260,486
earnings per share
ADS equivalent((c)) 2,934,933 2,983,497 3,147,620 2,985,730 3,210,081
Shares in issue at period-end 17,061,004 17,379,366 18,566,848 17,061,004 18,566,848
ADS equivalent((c)) 2,843,500 2,896,561 3,094,474 2,843,500 3,094,474
(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 2022 and nine months 2022 are 274,005
thousand (ADS equivalent 45,668 thousand) and 217,311 thousand (ADS equivalent
36,218 thousand).
(c) One ADS is equivalent to six ordinary shares.
Top of page 24
Note 8. Dividends
Dividends payable
BP today announced an interim dividend of 7.270 cents per ordinary share which
is expected to be paid on 19 December 2023 to ordinary shareholders and
American Depositary Share (ADS) holders on the register on 10 November 2023.
The ex-dividend date will be 9 November 2023. The corresponding amount in
sterling is due to be announced on 6 December 2023, calculated based on the
average of the market exchange rates over three dealing days between 30
November 2023 and 4 December 2023. Holders of ADSs are expected to receive
$0.43620 per ADS (less applicable fees). The board has decided not to offer a
scrip dividend alternative in respect of the third quarter 2023 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
2023 2023 2022 2023 2022
Dividends paid per ordinary share
cents 7.270 6.610 6.006 20.490 16.926
pence 5.732 5.309 5.168 16.592 13.683
Dividends paid per ADS (cents) 43.62 39.66 36.04 122.94 101.56
Note 9. Net debt
Net debt* 30 September 30 June 30 September
$ million 2023 2023 2022
Finance debt((a)) 48,810 49,738 46,560
Fair value (asset) liability of hedges related to finance debt((b)) 3,440 2,836 4,746
52,250 52,574 51,306
Less: cash and cash equivalents 29,926 28,914 29,304
Net debt((c)) 22,324 23,660 22,002
Total equity 87,676 85,603 73,333
Gearing* 20.3% 21.7% 23.1%
(a) The fair value of finance debt at 30 September 2023 was
$43,387 million (30 June 2023 $45,580 million, 30 September 2022 $41,414
million).
(b) 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 $102 million at 30 September
2023 (second quarter 2023 liability of $98 million and third quarter 2022
liability of $116 million) are not included in the calculation of net debt
shown above as hedge accounting is not applied for these instruments.
(c) 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.
In the third quarter the group bought back $nil equivalent of finance debt
(second quarter 2023 $1.7 billion, third quarter 2022 $2.9 billion). As part
of actively managing its debt portfolio, year to date the group has bought
back a total of $1.7 billion equivalent of finance debt ($7.4 billion for the
comparative period in 2022). Derivatives associated with non-US dollar debt
bought back were also terminated. These transactions have no significant
impact on net debt or gearing.
Note 10. Statutory accounts
The financial information shown in this publication, which was approved by the
Board of Directors on 30 October 2023, is unaudited and does not constitute
statutory financial statements. Audited financial information will be
published in BP Annual Report and Form 20-F 2023. BP Annual Report and Form
20-F 2022 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 25
Additional information
Capital expenditure*
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Capital expenditure
Organic capital expenditure* 3,597 3,233 3,191 10,325 8,609
Inorganic capital expenditure*((a)) 6 1,081 3 1,217 352
3,603 4,314 3,194 11,542 8,961
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Capital expenditure by segment
gas & low carbon energy 1,055 887 958 2,955 2,642
oil production & operations 1,644 1,478 1,386 4,642 3,848
customers & products((a)) 802 1,858 713 3,650 2,103
other businesses & corporate 102 91 137 295 368
3,603 4,314 3,194 11,542 8,961
Capital expenditure by geographical area
US 1,583 2,661 1,377 5,941 3,727
Non-US 2,020 1,653 1,817 5,601 5,234
3,603 4,314 3,194 11,542 8,961
(a) Second quarter and nine months 2023 include $1.1 billion, net of
adjustments, in respect of the TravelCenters of America acquisition.
Top of page 26
Adjusting items*
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
gas & low carbon energy
Gains on sale of businesses and fixed assets - 1 3 16 12
Net impairment and losses on sale of businesses and fixed assets((a)) (224) (1,058) (6) (1,284) (523)
Environmental and other provisions - - - - -
Restructuring, integration and rationalization costs (1) 1 - - 5
Fair value accounting effects((b)(c)) 1,816 1,222 (9,224) 6,972 (14,313)
Other((d)) (572) (110) 31 (738) 161
1,019 56 (9,196) 4,966 (14,658)
oil production & operations
Gains on sale of businesses and fixed assets((e)) 246 (31) 1,851 352 3,378
Net impairment and losses on sale of businesses and fixed assets (52) (140) (326) (184) (1,262)
Environmental and other provisions 99 (44) 244 6 98
Restructuring, integration and rationalization costs - (1) 3 (1) (14)
Fair value accounting effects - - - - -
Other (2) 7 (18) (93) 37
291 (209) 1,754 80 2,237
customers & products
Gains on sale of businesses and fixed assets 18 2 10 21 302
Net impairment and losses on sale of businesses and fixed assets (242) (36) (85) (361) (532)
Environmental and other provisions - (1) (1) (11) (36)
Restructuring, integration and rationalization costs 1 1 (4) - 6
Fair value accounting effects((c)) (198) (109) (59) (230) (498)
Other (85) (98) - (245) (31)
(506) (241) (139) (826) (789)
other businesses & corporate
Gains on sale of businesses and fixed assets - - 1 - -
Net impairment and losses on sale of businesses and fixed assets (23) (31) - (60) (16)
Environmental and other provisions (8) (17) 67 (39) (25)
Restructuring, integration and rationalization costs (3) - 6 (13) 16
Fair value accounting effects((c)) (146) (48) (785) 51 (1,896)
Rosneft - - - - (24,033)
Gulf of Mexico oil spill (19) (18) (21) (46) (61)
Other 2 (13) 44 (11) 40
(197) (127) (688) (118) (25,975)
Total before interest and taxation 607 (521) (8,269) 4,102 (39,185)
Finance costs((f)) (96) (119) (68) (319) (256)
Total before taxation 511 (640) (8,337) 3,783 (39,441)
Taxation on adjusting items((g)) (158) 160 988 (203) 1,998
Taxation - tax rate change effect of UK energy profits levy((h)) - 232 (778) 232 (778)
Total after taxation for period((i)) 353 (248) (8,127) 3,812 (38,221)
(a) See Note 3 for further information.
(b) Under IFRS bp marks-to-market the value of the hedges used to
risk-manage LNG contracts, but not the contracts themselves, resulting in a
mismatch in accounting treatment. The fair value accounting effect includes
the change in value of LNG contracts that are being risk managed, and the
underlying result reflects how bp risk-manages its LNG contracts.
(c) For further information, including the nature of fair value
accounting effects reported in each segment, see pages 3, 6 and 32.
(d) Third quarter and nine months 2023 include a $540 million
impairment charge recognized through equity-accounted earnings relating to US
offshore wind projects.
(e) Third quarter and nine months 2022 include a non-taxable gain of
$1,951 million arising from the contribution of bp's Angolan business to
Azule Energy. Nine months 2022 also includes gains of $904 million related to
the deemed disposal of 12% of the group's interest in Aker BP, an associate of
bp, following completion of Aker BP's acquisition of Lundin Energy, and $361
million in relation to the disposal of the group's interest in the Rumaila
field in Iraq to Basra Energy Company, an associate of bp.
(f) Includes the unwinding of discounting effects relating to Gulf
of Mexico oil spill payables, the income statement impact associated with
the buyback of finance debt (see Note 9 for further information) and temporary
valuation differences associated with the group's interest rate and foreign
currency exchange risk management of finance debt.
(g) Includes 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.
(h) Second quarter and nine months 2023 include a revision to the
deferred tax impact of the introduction of the UK Energy Profits Levy (EPL) on
temporary differences existing at 31 December 2022 that are expected to unwind
over the period 1 January 2023 to 31 March 2028. The EPL increases the
headline rate of tax to 75% and applies to taxable profits from bp's North Sea
business made from 1 January 2023 until 31 March 2028.
Top of page 27
Third quarter and nine months 2022 included the deferred tax impact of the
introduction of the original UK EPL on existing temporary differences
unwinding over the period 1 October 2022 to 31 December 2025. The original
levy increased the headline rate of tax from 40% to 65% on profits from bp's
North Sea business made from 26 May 2022 until 31 December 2025.
(i) Third quarter and nine months 2023 include a $43 million
charge and a $121 million charge respectively for the EU Solidarity
Contribution.
Net debt including leases
Net debt including leases* 30 September 30 June 30 September
$ million 2023 2023 2022
Net debt 22,324 23,660 22,002
Lease liabilities 10,879 10,961 7,895
Net partner (receivable) payable for leases entered into on behalf of joint (124) (136) 22
operations
Net debt including leases 33,079 34,485 29,919
Total equity 87,676 85,603 73,333
Gearing including leases* 27.4% 28.7% 29.0%
Gulf of Mexico oil spill
30 September 31 December
$ million 2023 2022
Gulf of Mexico oil spill payables and provisions (8,639) (9,566)
Of which - current (1,122) (1,216)
Deferred tax asset 1,306 1,444
During the second quarter pre-tax payments of $1,204 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 2022 - Financial statements -
Notes 7, 22, 23, 29, and 33.
Working capital* reconciliation
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Movements in inventories and other current and non-current assets and (783) (742) 6,764 (5,280) 577
liabilities as per condensed group cash flow statement((a))
Adjusted for inventory holding gains (losses)* (Note 4) 1,593 (732) (2,868) 261 2,779
Adjusted for fair value accounting effects relating to subsidiaries 1,443 1,053 (10,068) 6,738 (16,561)
Other adjusting items((b)) (300) 558 645 (1,040) 2,094
Working capital release (build) after adjusting for net inventory gains 1,953 137 (5,527) 679 (11,111)
(losses), fair value accounting effects and other adjusting items
(a) The movement in working capital includes outflows relating to
the Gulf of Mexico oil spill on a pre-tax basis of $6 million and
$1,222 million in the third quarter and nine months of 2023 respectively. For
the same periods in 2022 the amount was an outflow of $29 million and
$1,285 million respectively.
(b) Other adjusting items relate to the non-cash movement of US
emissions obligations carried as a provision that will be settled by
allowances held as inventory.
Top of page 28
Surplus cash flow* reconciliation
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Sources:
Net cash provided by operating activities 8,747 6,293 8,288 22,662 27,361
Cash provided from investing activities 150 109 621 1,065 1,996
Other((a)) 503 (42) (31) 402 454
Cash inflow 9,400 6,360 8,878 24,129 29,811
Uses:
Lease liability payments (663) (620) (478) (1,838) (1,448)
Payments on perpetual hybrid bonds (258) (250) (180) (744) (489)
Dividends paid - BP shareholders (1,249) (1,153) (1,140) (3,585) (3,270)
- non-controlling interests (191) (67) (66) (326) (194)
Total capital expenditure* (3,603) (4,314) (3,194) (11,542) (8,961)
Net repurchase of shares relating to employee share schemes (225) (225) - (675) (500)
Payments relating to transactions involving non-controlling interests - - (2) (180) (8)
Currency translation differences relating to cash and cash equivalents (104) - (322) (118) (861)
Cash outflow (6,293) (6,629) (5,382) (19,008) (15,731)
Surplus cash flow 3,107 (269) 3,496 5,121 14,080
(a) Other includes adjustments for net operating cash received or
paid which is held on behalf of third parties for medium-term deferred payment
and prior periods have been adjusted accordingly. Third quarter and nine
months 2023 include $517 million of proceeds from the sale of a 49% interest
in a controlled affiliate holding certain midstream assets onshore US. Nine
months 2022 includes $573 million of proceeds from the disposal of a loan note
related to the Alaska divestment. The cash was received in the fourth quarter
2021, was reported as a financing cash flow and was not included in other
proceeds at the time due to potential recourse from the counterparty. The
proceeds were recognized as the potential recourse reduces and by end second
quarter 2022 all were recognized.
Top of page 29
Adjusted earnings before interest, taxation, depreciation and amortization
(adjusted EBITDA)*
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2023 2023 2022 2023 2022
Profit (loss) for the period 5,069 1,953 (1,984) 15,444 (12,518)
Finance costs 1,039 920 649 2,802 1,869
Net finance (income) expense relating to pensions and other post-retirement (61) (61) (16) (180) (53)
benefits
Taxation 2,240 1,541 3,964 7,206 11,021
Profit before interest and tax 8,287 4,353 2,613 25,272 319
Inventory holding (gains) losses*, before tax (1,593) 732 2,868 (261) (2,779)
RC profit (loss) before interest and tax 6,694 5,085 5,481 25,011 (2,460)
Net (favourable) adverse impact of adjusting items*, before interest and tax (607) 521 8,269 (4,102) 39,185
Underlying RC profit before interest and tax 6,087 5,606 13,750 20,909 36,725
Add back:
Depreciation, depletion and amortization 4,145 3,923 3,467 11,868 10,604
Exploration expenditure written off 74 241 190 365 318
Adjusted EBITDA 10,306 9,770 17,407 33,142 47,647
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 2023 2023 2022 2023 2022
RC profit before interest and tax for customers & products 1,549 555 2,586 4,784 8,098
Less: Adjusting items* gains (charges) (506) (241) (139) (826) (789)
Underlying RC profit before interest and tax for customers & products 2,055 796 2,725 5,610 8,887
By business:
customers - convenience & mobility 670 701 1,137 1,762 2,338
Castrol - included in customers 185 171 151 517 630
products - refining & trading 1,385 95 1,588 3,848 6,549
Add back: Depreciation, depletion and amortization 915 894 697 2,606 2,129
By business:
customers - convenience & mobility 481 448 311 1,270 952
Castrol - included in customers 43 42 36 124 113
products - refining & trading 434 446 386 1,336 1,177
Adjusted EBITDA for customers & products 2,970 1,690 3,422 8,216 11,016
By business:
customers - convenience & mobility 1,151 1,149 1,448 3,032 3,290
Castrol - included in customers 228 213 187 641 743
products - refining & trading 1,819 541 1,974 5,184 7,726
Top of page 30
Realizations* and marker prices
Third Second Third Nine Nine
quarter quarter quarter months months
2023 2023 2022 2023 2022
Average realizations((a))
Liquids* ($/bbl)
US 63.95 60.53 82.23 62.44 81.05
Europe 90.76 75.14 94.21 80.59 104.12
Rest of World 78.34 79.35 101.82 80.05 98.93
BP Average 71.85 69.76 92.44 71.40 92.42
Natural gas ($/mcf)
US 2.24 1.58 7.25 2.09 5.88
Europe((b)) 11.22 12.46 36.72 17.20 32.73
Rest of World 5.38 5.53 9.85 6.11 8.74
BP Average((b)) 4.88 4.91 10.41 5.66 9.18
Total hydrocarbons* ($/boe)
US 45.39 40.84 66.82 43.77 63.19
Europe((b)) 80.61 74.20 137.66 87.43 134.42
Rest of World 45.61 45.97 71.19 48.73 68.34
BP Average((b)) 47.28 46.27 74.08 49.47 71.17
Average oil marker prices ($/bbl)
Brent 86.75 78.05 100.84 82.07 105.51
West Texas Intermediate 82.54 73.56 91.63 77.36 98.46
Western Canadian Select 65.42 60.07 69.02 60.72 79.72
Alaska North Slope 87.95 78.26 98.84 81.74 102.34
Mars 82.99 73.17 89.54 76.80 96.01
Urals (NWE - cif) 73.62 54.56 71.24 58.20 78.58
Average natural gas marker prices
Henry Hub gas price((c)) ($/mmBtu) 2.54 2.09 8.20 2.69 6.78
UK Gas - National Balancing Point (p/therm) 82.04 83.18 281.01 99.01 216.37
(a) Based on sales of consolidated subsidiaries only - this excludes
equity-accounted entities.
(b) Realizations calculation methodology has been changed to reflect
gas price fluctuations within the North Sea region. Third quarter 2022 and
nine months 2022 were restated. There is no impact on financial results.
(c) Henry Hub First of Month Index.
Exchange rates
Third Second Third Nine Nine
quarter quarter quarter months months
2023 2023 2022 2023 2022
$/£ average rate for the period 1.27 1.25 1.18 1.24 1.25
$/£ period-end rate 1.22 1.26 1.12 1.22 1.12
$/€ average rate for the period 1.09 1.09 1.01 1.08 1.06
$/€ period-end rate 1.06 1.09 0.98 1.06 0.98
$/AUD average rate for the period 0.65 0.67 0.68 0.67 0.71
$/AUD period-end rate 0.64 0.66 0.65 0.64 0.65
Top of page 31
Legal proceedings
For a full discussion of the group's material legal proceedings, see pages
258-259 of bp Annual Report and Form 20-F 2022 and page 35 of BP p.l.c. Group
results second quarter and half-year 2023 results announcement. The following
discussion sets out the material developments in the group's material legal
proceedings in the period following the second quarter and half-year 2023
results announcement.
Louisiana Coastal restoration
Six coastal parishes and the State of Louisiana have filed over 40 separate
lawsuits in state courts in Louisiana against various oil and gas companies
seeking damages for coastal erosion. bp entities are defendants in 17 of these
cases. The lawsuits allege that the defendants' historical operations in oil
and gas fields within the Louisiana onshore coastal zone failed to comply with
state permits and/or were conducted without the required coastal use permits.
The scope and scale of plaintiffs' damages demands are significant and
unprecedented, including substantial remediation costs and the claimed costs
for restoring coastal wetlands allegedly impacted by oil and gas field
operations.
Defendants removed all of these lawsuits to federal court and the removals
were contested by plaintiffs, eventually resulting in a decision from the US
Fifth Circuit Court of Appeals rejecting defendants' "federal officer"
jurisdiction removal in the lead test case. Defendants' petition for writ of
certiorari to the US Supreme Court seeking review of the US Fifth Circuit's
decision was denied in early 2023. On remand from the US District Court, the
state court in the case of Cameron Parish v. Auster et al. has established a
November 2023 trial date. bp is the lead defendant in Auster. A subset of the
removed cases remain in federal court pending further Fifth Circuit rulings on
a related "federal officer" removal jurisdiction theory.
In addition, four private landowners have filed separate claims in the state
courts in Jefferson and Plaquemines Parishes of Louisiana for restoration
damages related to alleged impacts to their marshlands associated with
historic oil field operations. bp entities are defendants in two of these
private landowner cases.
With the exception of the Auster case, which is nearing completion of the
expert discovery stage and final pre-trial activity, all of the other remanded
cases remain at early stages in the litigation. While it is not possible to
predict the outcomes of these novel legal actions, bp believes that it has
valid defences, and it intends to defend such actions vigorously.
Glossary
Non-IFRS 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-IFRS measures are sometimes referred to
as alternative performance measures.
Adjusted EBITDA is a non-IFRS measure presented for bp's operating segments
and is defined as replacement cost (RC) profit before interest and tax,
excluding net adjusting items* before interest and tax, and 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. A
reconciliation to IFRS information is provided on page 29 for the customers
& products businesses.
Adjusted EBITDA for the group is defined as profit or loss for the period,
adjusting for finance costs and net finance (income) or expense relating to
pensions and other post-retirement benefits and taxation, inventory holding
gains or losses before tax, net adjusting items before interest and tax, and
adding back depreciation, depletion and amortization (pre-tax) and exploration
expenditure written-off (net of adjusting items, pre-tax). The nearest
equivalent measure on an IFRS basis for the group is profit or loss for the
period. A reconciliation to IFRS information is provided on page 29 for the
group.
We are unable to present reconciliations of forward-looking information for
adjusted EBITDA for the group or resilient hydrocarbons, because without
unreasonable efforts, we are unable to forecast accurately certain adjusting
items required to calculate a meaningful comparable IFRS forward-looking
financial measure. These items include inventory holding gains or losses,
adjusting items and exploration expenditure written off that are difficult to
predict in advance in order to include in an IFRS estimate.
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, financial impacts
relating to Rosneft for the 2022 financial reporting period and 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-IFRS measures. An analysis of adjusting items by
segment and type is shown on page 26.
Blue hydrogen - Hydrogen made from natural gas in combination with carbon
capture and storage (CCS).
Capital expenditure is total cash capital expenditure as stated in the
condensed group cash flow statement. Capital expenditure for the operating
segments, gas & low carbon energy businesses and customers & products
businesses is presented on the same basis.
Cash balance point is defined as the implied Brent oil price 2021 real to
balance bp's sources and uses of cash assuming an average bp refining marker
margin around $11/bbl and Henry Hub at $3/mmBtu in 2021 real terms.
Consolidation adjustment - UPII is unrealized profit in inventory arising on
inter-segment transactions.
Top of page 32
Glossary (continued)
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-IFRS
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-IFRS measures. The nearest equivalent measure on an IFRS basis is the
ETR on profit or loss for the period.
Electric vehicle charge points / EV charge points are defined as the number of
connectors on a charging device, operated by either bp or a bp joint venture.
Fair value accounting effects are non-IFRS 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.
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.
These include:
• 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.
• 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, represents the change in
value of LNG contacts that are being risk managed and which is reflected in
the underlying result, but not in reported earnings. Management believes that
this gives a better representation of performance in each period.
Furthermore, the fair values of derivative instruments used to risk manage
certain other oil, gas, power and other contracts, are deferred to match with
the underlying exposure. The commodity contracts for business requirements are
accounted for on an accruals basis.
In addition, 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
Top of page 33
Glossary (continued)
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.
Gas & low carbon energy segment comprises our gas and low carbon
businesses. Our gas business includes regions with upstream activities that
predominantly produce natural gas, integrated gas and power, and gas trading.
Our low carbon business includes solar, offshore and onshore wind, hydrogen
and CCS and power trading. Power trading includes trading of both renewable
and non-renewable power.
Gearing and net debt are non-IFRS 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 measures on an IFRS basis are finance debt and finance
debt ratio. A reconciliation of finance debt to net debt is provided on page
24.
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 IFRS 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 an IFRS estimate.
Gearing including leases and net debt including leases are non-IFRS 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
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 27.
Green hydrogen - Hydrogen produced by electrolysis of water using renewable
power.
Hydrocarbons - Liquids and natural gas. Natural gas is converted to oil
equivalent at 5.8 billion cubic feet = 1 million barrels.
Hydrogen pipeline - Hydrogen projects which have not been developed to final
investment decision (FID) but which have advanced to the concept development
stage.
Inorganic capital expenditure is a subset of capital expenditure on a cash
basis and a non-IFRS 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 IFRS information is provided on page 25.
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-IFRS 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.
Top of page 34
Glossary (continued)
Liquids - Liquids comprises crude oil, condensate and natural gas liquids. For
the oil production & operations segment, it also includes bitumen.
Low carbon activity - An activity relating to low carbon including: renewable
electricity; bioenergy; electric vehicles and other future mobility solutions;
trading and marketing low carbon products; blue or green hydrogen and carbon
capture, use and storage (CCUS).
Note that, while there is some overlap of activities, these terms do not mean
the same as bp's strategic focus area of low carbon energy or our low carbon
energy sub-segment, reported within the gas & low carbon energy segment.
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.
Organic capital expenditure is a non-IFRS 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 IFRS
information is provided on page 25.
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 IFRS 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. For the
gas & low carbon energy and oil production & operations segments,
realizations include transfers between businesses.
Refining availability represents Solomon Associates' operational availability
for bp-operated refineries, which is defined as the percentage of the year
that a unit is available for processing after subtracting the annualized time
lost due to turnaround activity and all planned mechanical, process and
regulatory downtime.
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 the following criteria
until the point they can be considered developed to final investment decision
(FID): Site based projects that have obtained land exclusivity rights, or for
power purchase agreement 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 IFRS 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 IFRS 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.
Solomon availability - See Refining availability definition.
Top of page 35
Glossary (continued)
Strategic convenience sites are retail sites, within the bp portfolio, which
sell bp-branded vehicle energy (e.g. bp, Aral, Arco, Amoco, Thorntons,
TravelCenters of America and bp pulse) and either carry one of the strategic
convenience brands (e.g. M&S, Rewe to Go) or a differentiated convenience
offer. To be considered a strategic convenience site, the convenience offer
should have a demonstrable level of differentiation in the market in which it
operates. Strategic convenience site count includes sites under a pilot phase.
Surplus cash flow does not represent the residual cash flow available for
discretionary expenditures. It is a non-IFRS financial measure that should be
considered in addition to, not as a substitute for or superior to, net cash
provided by operating activities, reported in accordance with IFRS. bp
believes it is helpful to disclose the surplus cash flow because this measure
forms part of bp's financial frame.
Surplus cash flow 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.
For the nine months of 2022, the sources of cash includes other proceeds
related to the proceeds from the disposal of a loan note related to the Alaska
divestment. The cash was received in the fourth quarter 2021, was reported as
a financing cash flow and was not included in other proceeds at the time due
to potential recourse from the counterparty. The proceeds are being recognized
as the potential recourse reduces. See page 28 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.
Transition growth - Activities, represented by a set of transition growth
engines, that transition bp toward its objective to be an Integrated Energy
Company, and that comprise our low carbon activity* alongside other businesses
that support transition, such as our power trading & marketing business
and convenience.
Underlying effective tax rate (ETR) is a non-IFRS 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-IFRS 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 IFRS 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 an IFRS estimate.
Underlying production - 2023 underlying production, when compared with 2022,
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-IFRS measure and is RC profit or loss* (as defined on
page 34) after excluding net adjusting items and related taxation. See page 26
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.
Top of page 36
Glossary (continued)
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 IFRS
information is provided on page 1 for the group and pages 6-14 for the
segments.
Underlying RC profit or loss per share / underlying RC profit or loss per ADS
is a non-IFRS 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.
upstream/hydrocarbon plant reliability (bp-operated) is calculated taking 100%
less the ratio of total unplanned plant deferrals divided by installed
production capacity, excluding non-operated assets and bpx energy. 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, fair
value accounting effects relating to subsidiaries and other adjusting items is
a non-IFRS measure. It is calculated by adjusting for inventory holding
gains/losses reported in the period; fair value accounting effects relating to
subsidiaries reported within adjusting items for the period; and other
adjusting items relating to the non-cash movement of US emissions obligations
carried as a provision that will be settled by allowances held as inventory.
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, bp pulse, Castrol and Thorntons
Top of page 37
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: plans, expectations and assumptions regarding oil and gas demand,
supply, prices or volatility; expectations regarding reserves; expectations
regarding production; expectations regarding bp's customers & products
business; expectations regarding refining margins; expectations regarding
turnaround and maintenance activity; expectations regarding financial
performance, results of operations and cash flows, and Adjusted EBITDA;
expectations regarding future project start-ups; expectations with regards to
bp's transformation to an IEC; price assumptions used in accounting estimates;
bp's plans and expectations regarding the amount and timing of share buybacks
and dividends; 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 with respect to
the total depreciation, depletion and amortization and the other businesses
& corporate underlying annual charge for 2023; plans and expectations
regarding bp's development of its LNG portfolio; plans and expectations
regarding investments, collaborations and partnerships in electric vehicle
(EV) charging infrastructure; plans and expectations related to bp's
transition growth engines of bioenergy, convenience, EV charging, renewables
and power, and hydrogen; expectations relating to bp's development of its wind
pipeline; plans and expectations regarding the amount or timing of payments
related to divestment and other proceeds, and the timing, quantum and nature
of certain acquisitions and divestments; expectations regarding the underlying
effective tax rate for 2023; expectations regarding the timing and amount of
future payments relating to the Gulf of Mexico oil spill; plans and
expectations regarding capital expenditure; expectations regarding greenhouse
gas emissions; expectations regarding legal proceedings, including those
related to the Louisiana coastal restoration and climate change; plans and
expectations regarding bp-operated projects and ventures, and its projects,
joint ventures, partnerships and agreements with commercial entities and other
third party partners, including those related to Advanced Ionics, Dynamon,
Electric Hydrogen, Midwest Alliance for Clean Hydrogen and Auchan.
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 or outcomes, 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 effects of bp's plan to exit its shareholding in Rosneft
and other investments in Russia, the impact of COVID-19, overall global
economic and business conditions impacting bp's business and demand for bp's
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 and policies, including related
to climate change; changes in social attitudes and customer preferences;
regulatory or legal actions including the types of enforcement action pursued
and the nature of remedies sought or imposed; the actions of prosecutors,
regulatory authorities and courts; delays in the processes for resolving
claims; amounts ultimately 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; bp's
access to future credit resources; business disruption and crisis management;
the impact on bp's reputation of ethical misconduct and non-compliance with
regulatory obligations; trading losses; major uninsured losses; the
possibility that international sanctions or other steps taken by any competent
authorities or any other relevant persons may impact or limit bp's ability to
sell its interests in Rosneft, or the price for which it could sell such
interests; 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 those
factors discussed under "Principal risks and uncertainties" in bp's Report on
Form 6-K regarding results for the six-month period ended 30 June 2023 as
filed with the US Securities and Exchange Commission (the "SEC") as well as
those factors discussed under "Risk factors" in bp's Annual Report and Form
20-F 2022 as filed with the SEC.
This announcement contains inside information. The person responsible for
arranging the release of this announcement on behalf of BP p.l.c. is Ben
Mathews, Company Secretary.
Top of page 38
Contacts
London Houston
Press Office David Nicholas Megan Baldino
+44 (0) 7831 095541 +1 907 529 9029
Investor Relations Craig Marshall Graham Collins
bp.com/investors +44 (0) 203 401 5592 +1 832 753 5116
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 (mailto:rns@lseg.com)
or visit
www.rns.com (http://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 (https://www.lseg.com/privacy-and-cookie-policy)
. END QRTBCBDGBBXDGXGRecent news on BP
See all newsREG - BP PLC - Transaction in Own Shares
AnnouncementREG - BP PLC - Transaction in Own Shares
AnnouncementREG - BP PLC - Transaction in Own Shares
AnnouncementREG - BP PLC - Result of AGM
AnnouncementREG - BP PLC - Transaction in Own Shares
Announcement