REG - BP PLC - 3Q25 SEA Part 1 of 1
Tue 07:00
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RNS Number : 0057G BP PLC 04 November 2025
Top of page 1
FOR IMMEDIATE RELEASE
London 4 November 2025
BP p.l.c. Group results
Third quarter and nine months 2025
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Strong operations and strategic progress
Financial summary Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Profit (loss) for the period attributable to bp shareholders 1,161 1,629 206 3,477 2,340
Inventory holding (gains) losses*, net of tax 62 407 906 351 362
Replacement cost (RC) profit (loss)* 1,223 2,036 1,112 3,828 2,702
Net (favourable) adverse impact of adjusting items*, net of tax 987 317 1,155 2,116 5,044
Underlying RC profit* 2,210 2,353 2,267 5,944 7,746
Operating cash flow* 7,786 6,271 6,761 16,891 19,870
Capital expenditure* (3,381) (3,361) (4,542) (10,365) (12,511)
Divestment and other proceeds((a)) 28 1,356 290 1,712 1,463
Net issue (repurchase) of shares (750) (1,063) (2,001) (3,660) (5,502)
Net debt*((b)) 26,054 26,043 24,268 26,054 24,268
Adjusted EBITDA* 9,981 9,972 9,654 28,654 29,599
Underlying operating expenditure* 5,487 5,457 5,590 16,248 16,542
Announced dividend per ordinary share (cents per share) 8.320 8.320 8.000 24.640 23.270
Underlying RC profit per ordinary share* (cents) 14.24 15.03 13.89 37.98 46.79
Underlying RC profit per ADS* (dollars) 0.85 0.90 0.83 2.28 2.81
Highlights
• Good earnings and cash generation: 3Q25 operating cash flow
$7.8bn; stronger underlying earnings across the operating segments supporting
3Q25 underlying RC profit $2.2bn.
• Significant progress in upstream*: 3Q25 upstream plant
reliability* 96.8% supporting underlying production* +3% quarter-on-quarter;
six major projects* started up in 2025, FID taken on Tiber-Guadalupe in the
Gulf of America; 12 exploration discoveries year-to-date.
• Improved reliability and profitability in downstream*: 3Q25
refining availability* increased to 96.6%; around half of Customers &
products' share of the group's 2027 structural cost reduction* target now
delivered.
• Continued progress on divestments; disciplined capital allocation:
Now expect divestment and other proceeds received in 2025 to be above $4
billion. Full year capital expenditure guidance continues to be around $14.5bn
with organic capital expenditure* remaining on track to be below $14bn; net
debt broadly flat versus prior quarter despite redemption of $1.2bn hybrid
bonds.
"We've delivered another quarter of good performance across the business with
operations continuing to run well. All six of the major oil and gas projects
planned for 2025 are online, including four ahead of schedule. We've
sanctioned our seventh operated production hub in the Gulf of America and have
had further exploration success. We delivered record 3Q underlying earnings in
customers and refining captured a better margin environment. Meanwhile, we
expect full year divestment proceeds to be higher - underpinned by around $5
billion of completed or announced disposal agreements.
We continue to make good progress to cut costs, strengthen our balance sheet
and increase cash flow and returns. We are looking to accelerate delivery of
our plans, including undertaking a thorough review of our portfolio to drive
simplification and targeting further improvements in cost performance and
efficiency. There is much more to do but we are moving at pace, and
demonstrating that bp can and will do better for our investors."
Murray Auchincloss
Chief executive officer
(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, net debt, adjusted EBITDA, underlying
operating expenditure, 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.
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Highlights
3Q25 underlying replacement cost (RC) profit* $2.2 billion
• Underlying RC profit for the quarter of $2.2 billion, compared with $2.4
billion for the previous quarter, reflects higher profitability in the
operating segments offset by a higher underlying effective tax rate (ETR)* in
the quarter of 39% which includes changes in the geographical mix of profits.
Higher quarter-on-quarter underlying RC profit before interest and tax was
driven by significantly lower level of refinery turnaround activity, stronger
realized refining margins, and higher production, partly offset by a weak oil
trading result, seasonal effects of environmental compliance costs, lower
realizations and higher other businesses & corporate underlying charge.
• Reported profit for the quarter was $1.2 billion, compared with $1.6 billion
for the second quarter 2025. The reported result for the third quarter is
adjusted for inventory holding losses* of $0.1 billion (net of tax) and a net
adverse impact of adjusting items* of $1.0 billion (net of tax) to derive the
underlying RC profit. Adjusting items include net impairments and losses on
sale of businesses and fixed assets of $0.8 billion (see page 25 for more
information on adjusting items).
Segment results
• Gas & low carbon energy: The RC profit before interest and tax for the
third quarter 2025 was $1.1 billion, compared with $1.0 billion for the
previous quarter. After adjusting RC profit before interest and tax for a net
adverse impact of adjusting items of $0.4 billion, the underlying RC profit
before interest and tax* for the third quarter was $1.5 billion, compared
with $1.5 billion in the second quarter 2025. The third quarter underlying
result before interest and tax reflects a lower depreciation, depletion and
amortization charge and higher production, partly offset by lower
realizations. The gas marketing and trading result was average.
• Oil production & operations: The RC profit before interest and tax for the
third quarter 2025 was $2.1 billion, compared with $1.9 billion for the
previous quarter. After adjusting RC profit before interest and tax for a net
adverse impact of adjusting items of $0.2 billion, the underlying RC profit
before interest and tax for the third quarter was $2.3 billion, compared with
$2.3 billion in the second quarter 2025. The third quarter underlying result
before interest and tax reflects higher production, primarily in bpx energy,
partly offset by higher exploration write-offs.
• Customers & products: The RC profit before interest and tax for the third
quarter 2025 was $1.6 billion, compared with $1.0 billion for the previous
quarter. After adjusting RC profit before interest and tax for a net adverse
impact of adjusting items of $0.1 billion, the underlying RC profit before
interest and tax (underlying result) for the third quarter was $1.7 billion,
compared with $1.5 billion in the second quarter 2025. The customers third
quarter underlying result was higher by $0.1 billion, reflecting seasonally
higher volumes, stronger integrated performance across fuels and midstream,
and lower underlying operating expenditure*. The products third quarter
underlying result was higher by $0.1 billion, reflecting stronger realized
refining margins and a significantly lower level of turnaround activity,
partly offset by seasonal effects of environmental compliance costs and the
impact of unplanned Whiting outage due to exceptional weather conditions. The
oil trading contribution was weak.
Operating cash flow* $7.8 billion and net debt* $26.1 billion
• Operating cash flow of $7.8 billion was around $1.5 billion higher than the
previous quarter, reflecting a $0.9 billion working capital* release (after
adjusting inventory holding losses, fair value accounting effects and other
adjusting items) this quarter compared to a $1.4 billion build in the previous
quarter, partly offset by $0.9 billion higher income taxes paid. Net debt was
broadly flat at $26.1 billion in the third quarter as higher operating cash
flow was partly offset by the redemption of $1.2 billion perpetual hybrid
bonds.
Financial frame
• bp is committed to maintaining a strong balance sheet and maintaining 'A'
grade credit range through the cycle. We have a target of $14-18 billion of
net debt by the end of 2027((a)).
• Our policy is to maintain a resilient dividend. Subject to board approval, we
expect an increase in the dividend per ordinary share of at least 4% per
year((b)). For the third quarter, bp has announced a dividend per ordinary
share of 8.320 cents.
• Share buybacks are a mechanism to return excess cash. When added to the
resilient dividend, we expect total shareholder distributions of 30-40% of
operating cash flow, over time. Related to the third quarter results, bp
intends to execute a $0.75 billion share buyback prior to reporting the fourth
quarter results. The $0.75 billion share buyback programme announced with the
second quarter results was completed on 31 October 2025.
• bp will continue to invest with discipline, driven by value and focused on
delivering returns. We continue to expect capital expenditure to be around
$14.5 billion in 2025. The capital frame of around $13-15 billion for 2026 and
2027 remains unchanged.
(a) Potential proceeds from any transactions related to the Castrol
strategic review and announcement to bring a strategic partner into
Lightsource bp will be allocated to reduce net debt.
(b) Subject to board discretion each quarter taking into account factors
including current forecasts, the cumulative level of and outlook for cash
flow, share count reduction from buybacks and maintaining 'A' range credit
metrics.
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 $1.2 billion and $3.5 billion respectively, compared with a
profit of $0.2 billion and $2.3 billion in the same periods of 2024.
- After adjusting profit attributable to bp shareholders for inventory holding
losses* and net impact of adjusting items*, underlying replacement cost (RC)
profit* for the third quarter and nine months was $2.2 billion and
$5.9 billion respectively, compared with $2.3 billion and $7.7 billion for
the same periods of 2024. The underlying RC profit for the third quarter
compared with the same period in 2024 mainly reflects higher realized refining
margins and lower realizations. The underlying RC profit for the nine months
compared with the same period in 2024 mainly reflects lower realizations and a
lower gas marketing and trading result, partly offset by stronger performance
in customers & products.
- Adjusting items in the third quarter and nine months had a net adverse
pre-tax impact of $0.9 billion and $2.0 billion respectively, compared with
a net adverse pre-tax impact of $1.6 billion and $5.9 billion in the same
periods of 2024.
- Adjusting items for the third quarter and nine months include a favourable
pre-tax impact of fair value accounting effects*, relative to management's
internal measure of performance, of $0.2 billion and $1.7 billion
respectively, compared with a favourable pre-tax impact of $0.4 billion and
an adverse pre-tax impact of $0.9 billion in the same periods of 2024. This
is primarily due to a decline in the LNG forward price over the 2025 periods
compared with an increase in the comparative periods of 2024. In addition
there is no significant impact of the fair value accounting effects relating
to the hybrid bonds in the third quarter 2025 compared with a favourable
impact in the third quarter 2024 and a significantly higher favourable impact
of these in the nine months 2025 compared with 2024.
- Adjusting items for the third quarter and nine months of 2025 include an
adverse pre-tax impact of asset impairments of $0.4 billion and $1.9 billion
respectively, compared with an adverse pre-tax impact of $1.7 billion and $3.7
billion in the same periods of 2024.
• The effective tax rate (ETR) on RC profit or loss* for the third quarter
and nine months was 53% and 51% respectively, compared with 51% and 59% for
the same periods in 2024. Excluding adjusting items, the underlying ETR* for
the third quarter and nine months was 39% and 41%, compared with 42% and 40%
for the same periods in 2024. The lower underlying ETR for the third quarter
reflects changes in the geographical mix of profits. ETR on RC profit or loss
and underlying ETR are non-IFRS measures.
• Operating cash flow* for the third quarter and nine months was
$7.8 billion and $16.9 billion respectively, compared with $6.8 billion and
$19.9 billion for the same periods in 2024. The change in the operating cash
flows reflects the lower tax paid and the lower underlying replacement cost
profit before tax for both periods compared with 2024, and differing impact of
working capital* movements in the nine months 2025 compared with 2024.
• Capital expenditure* in the third quarter and nine months was
$3.4 billion and $10.4 billion respectively, compared with $4.5 billion and
$12.5 billion in the same periods of 2024 reflecting the lower capital frame
in place for 2025.
• Total divestment and other proceeds for the third quarter and nine
months were $28.0 million and $1.7 billion respectively, compared with
$0.3 billion and $1.5 billion for the same periods in 2024. Other proceeds
for the nine months 2025 were $1.0 billion from the sale of a non-controlling
interest in the subsidiary that holds our 12% share in the Trans-Anatolian
natural gas pipeline (TANAP). Other proceeds for the nine months 2024 were
$0.5 billion from the sale of a 49% interest in a controlled affiliate holding
certain midstream assets offshore US.
• At the end of the third quarter, net debt* was $26.1 billion, compared
with $26.0 billion at the end of the second quarter 2025 and $24.3 billion
at the end of the third quarter 2024. The year on year increase largely
reflects lower operating cash flow over the period and acquired net debt,
partially offset by the issuance of perpetual hybrid bonds.
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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 2025 2025 2024 2025 2024
RC profit (loss) before interest and tax
gas & low carbon energy 1,097 1,047 1,007 3,502 1,728
oil production & operations 2,119 1,916 1,891 6,823 8,218
customers & products 1,610 972 23 2,685 878
other businesses & corporate (277) 645 653 346 173
Consolidation adjustment - UPII* (19) 30 65 24 24
RC profit before interest and tax 4,530 4,610 3,639 13,380 11,021
Finance costs and net finance expense relating to pensions and other (1,212) (1,173) (1,059) (3,654) (3,269)
post-employment benefits
Taxation on a RC basis (1,747) (1,101) (1,304) (4,955) (4,541)
Non-controlling interests (348) (300) (164) (943) (509)
RC profit attributable to bp shareholders* 1,223 2,036 1,112 3,828 2,702
Inventory holding gains (losses)* (82) (554) (1,182) (477) (467)
Taxation (charge) credit on inventory holding gains and losses 20 147 276 126 105
Profit for the period attributable to bp shareholders 1,161 1,629 206 3,477 2,340
Analysis of underlying RC profit (loss) before interest and tax
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Underlying RC profit (loss) before interest and tax
gas & low carbon energy 1,519 1,462 1,756 3,978 4,816
oil production & operations 2,299 2,262 2,794 7,456 9,013
customers & products 1,716 1,533 381 3,926 2,819
other businesses & corporate (189) (38) 231 (344) (81)
Consolidation adjustment - UPII (19) 30 65 24 24
Underlying RC profit before interest and tax 5,326 5,249 5,227 15,040 16,591
Finance costs on an underlying RC basis((a)) and net finance expense relating (1,129) (1,095) (1,001) (3,306) (2,914)
to pensions and other post-employment benefits
Taxation on an underlying RC basis (1,639) (1,501) (1,795) (4,847) (5,422)
Non-controlling interests (348) (300) (164) (943) (509)
Underlying RC profit attributable to bp shareholders* 2,210 2,353 2,267 5,944 7,746
(a) A non-IFRS measure. Finance costs on an underlying RC basis is defined
as finance costs as stated in the group income statement excluding finance
costs classified as adjusting items* (see footnote (e) on page 25).
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 6-12 for the segments.
Operating Metrics
Third Second Third Nine Nine
quarter quarter quarter months months
2025 2025 2024 2025 2024
Tier 1 and tier 2 process safety events* 7 5 11 22 32
upstream* production((a)) (mboe/d) 2,362 2,300 2,378 2,301 2,378
upstream unit production costs*((b)) ($/boe) 6.19 6.81 6.40 6.44 6.25
bp-operated upstream plant reliability* 96.8% 96.8% 95.0% 96.3% 95.3%
bp-operated refining availability*((a)) 96.6% 96.4% 95.6% 96.4% 94.1%
(a) See Operational updates on pages 6, 8 and 10. Because of rounding,
upstream production may not agree exactly with the sum of gas & low carbon
energy and oil production & operations.
(b) The increase in the nine months 2025, compared with the nine months
2024 mainly reflects portfolio mix.
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Outlook & Guidance
4Q 2025 guidance
• Looking ahead, bp expects fourth quarter 2025 reported upstream*
production to be broadly flat compared with the third quarter 2025. Within
this, bp expects reported production from oil production & operations to
be slightly higher and production from gas & low carbon energy to be
lower.
• In its customers business, bp expects seasonally lower volumes compared
to the third quarter and fuels margins to remain sensitive to movements in the
cost of supply.
• In products, bp expects, compared to the third quarter, similar level of
refinery turnaround activity.
2025 guidance
In addition to the guidance on page 2:
• bp now expects reported upstream* production to be slightly lower and
underlying upstream production* to be broadly flat compared with 2024. Within
this, bp expects underlying production from oil production & operations to
be higher and production from gas & low carbon energy to be lower.
• In its customers business, bp continues to expect growth in its
customers businesses including a full year contribution from bp bioenergy.
Earnings growth is expected to be supported by structural cost reduction*. bp
continues to expect fuels margins to remain sensitive to the cost of supply.
• In products, bp continues to expect stronger underlying performance
underpinned by the absence of the plant-wide power outage at Whiting refinery,
and improvement plans across the portfolio. bp continues to expect similar
levels of refinery turnaround activity, with phasing of turnaround activity in
2025 heavily weighted towards the first half, with the highest impact in the
second quarter.
• bp now expects other businesses & corporate underlying annual charge
to be around $0.5-0.75 billion for 2025, subject to foreign exchange impacts.
The charge may vary from quarter to quarter.
• bp continues to expect the depreciation, depletion and amortization to
be slightly higher compared with 2024.
• bp continues to expect the underlying ETR* for 2025 to be around 40% but
it is sensitive to a range of factors, including the volatility of the price
environment and its impact on the geographical mix of the group's profits and
losses.
• bp now expects divestment and other proceeds to be above $4 billion in
2025.
• bp continues to expect Gulf of America settlement payments for the year
to be around $1.2 billion pre-tax including $1.1 billion pre-tax paid during
the second quarter.
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 $1,097 million and $3,502 million
respectively, compared with $1,007 million and $1,728 million for the same
periods in 2024. The third quarter and nine months are adjusted by an adverse
impact of net adjusting items* of $422 million and $476 million respectively,
compared with an adverse impact of net adjusting items of $749 million and
$3,088 million for the same periods in 2024. Adjusting items include impacts
of fair value accounting effects*, relative to management's internal measure
of performance, which are a favourable impact of $131 million and $817 million
for the third quarter and nine months in 2025 and an adverse impact of $275
million and $1,173 million for the same periods in 2024. See page 25 for more
information on adjusting items.
• 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 $1,519 million and $3,978 million
respectively, compared with $1,756 million and $4,816 million for the same
periods in 2024.
• The underlying RC profit before interest and tax for the third
quarter, compared with the same period in 2024, reflects lower production and
lower realizations. The gas marketing and trading result was average.
• The underlying RC profit for the nine months, compared with
the same period in 2024, reflects lower production, a lower gas marketing and
trading result, and a higher depreciation, depletion and amortization charge,
partly offset by lower exploration write-offs and the absence of the foreign
exchange loss in Egypt in the first quarter of 2024.
Operational update
• Reported production for the quarter was 806mboe/d, 9.5% lower
than the same period in 2024, reflecting the divestments in Egypt and Trinidad
in the fourth quarter of 2024. Underlying production* was 0.2% lower due to
base decline offset by major project* start-ups in the year.
• Reported production for the nine months was 784mboe/d, 13.0%
lower than the same period in 2024, reflecting the divestments in Egypt and
Trinidad in the fourth quarter of 2024. Underlying production was 2.8% lower,
mainly due to base decline partly offset by major project start-ups in the
year.
Strategic progress
gas
• In August, a consortium of bp (16.09%), its Tangguh partners
(23.91%), operator EnQuest (40%), and Agra (20%) secured the right to explore
the Gaea and Gaea II cover onshore and offshore gas blocks near our Tangguh
LNG facility with the signing of government-backed contracts.
• In September bp announced the signing of a memorandum of
understanding (MoU) to evaluate opportunities for a five-well programme at
water depths ranging from 300 to 1,500 metres in the Mediterranean Sea,
offshore Egypt. Drilling operations are expected to start in 2026, with
possible tie-back options following evaluation of the drilling campaign and
resource potential.
• In September BOTAS and bp signed a three year liquefied
natural gas (LNG) purchase agreement to supply 1.6 billion cubic meters (bcm)
of LNG annually into Türkiye, totalling 4.8bcm over the contract period.
low carbon energy
• In August JERA Nex bp and EnBW were granted development
consent for the 1.5GW Morgan offshore wind project in the Irish Sea from the
UK Secretary of State for Energy Security and Net Zero. Morgan is one of three
proposed offshore wind projects in the UK, alongside Mona and Morven. Morgan's
sister project in the Irish Sea, Mona, received development consent in July.
Following deal completion, bp's interests in the projects moved to JERA Nex bp
- bp's 50:50 offshore wind joint venture with JERA.
Top of page 7
gas & low carbon energy (continued)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Profit before interest and tax 1,097 1,047 1,007 3,502 1,728
Inventory holding (gains) losses* - - - - -
RC profit before interest and tax 1,097 1,047 1,007 3,502 1,728
Net (favourable) adverse impact of adjusting items 422 415 749 476 3,088
Underlying RC profit before interest and tax 1,519 1,462 1,756 3,978 4,816
Taxation on an underlying RC basis (529) (509) (545) (1,509) (1,432)
Underlying RC profit before interest 990 953 1,211 2,469 3,384
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Depreciation, depletion and amortization
Total depreciation, depletion and amortization 1,223 1,407 1,180 3,796 3,682
Exploration write-offs
Exploration write-offs 29 1 1 30 232
Adjusted EBITDA*
Total adjusted EBITDA 2,771 2,870 2,937 7,804 8,730
Capital expenditure*
gas((a)) 727 688 1,248 2,189 3,018
low carbon energy 101 102 908 332 1,703
Total capital expenditure((a)) 828 790 2,156 2,521 4,721
(a) Comparative periods in 2024 have been restated to reflect the move of
our Archaea business from the customers & products segment to the gas
& low carbon energy segment.
Third Second Third Nine Nine
quarter quarter quarter months months
2025 2025 2024 2025 2024
Production (net of royalties)((b))
Liquids* (mb/d) 87 85 92 85 97
Natural gas (mmcf/d) 4,167 4,043 4,627 4,054 4,661
Total hydrocarbons* (mboe/d) 806 782 890 784 901
Average realizations*((c))
Liquids ($/bbl) 64.57 64.15 74.80 66.31 77.23
Natural gas ($/mcf) 6.41 6.50 5.80 6.71 5.57
Total hydrocarbons ($/boe) 40.30 40.84 37.91 42.06 37.13
(b) Includes bp's share of production of equity-accounted entities in the
gas & low carbon energy segment.
(c) Realizations are based on sales by consolidated subsidiaries only -
this excludes equity-accounted entities.
Top of page 8
oil production & operations
Financial results
• The replacement cost (RC) profit before interest and tax for
the third quarter and nine months was $2,119 million and $6,823 million
respectively, compared with $1,891 million and $8,218 million for the same
periods in 2024. The third quarter and nine months are adjusted by an adverse
impact of net adjusting items* of $180 million and $633 million respectively,
compared with an adverse impact of net adjusting items of $903 million and
$795 million for the same periods in 2024. See page 25 for more information on
adjusting items.
• 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 $2,299 million and $7,456 million
respectively, compared with $2,794 million and $9,013 million for the same
periods in 2024.
• The underlying RC profit before interest and tax for the third
quarter and nine months, compared with the same periods in 2024, primarily
reflects lower realizations and a higher depreciation, depletion and
amortization charge, partly offset by higher production and lower exploration
write-offs.
Operational update
• Reported production for the quarter was 1,556mboe/d, 4.6%
higher than the same period in 2024. Underlying production* for the quarter
was 3.5% higher, mainly reflecting higher production in bpx energy.
• Reported production for the nine months was 1,517mboe/d, 2.7%
higher than the same period in 2024. Underlying production was 1.9% higher,
mainly reflecting higher production in bpx energy.
Strategic progress
• Following the announcement in August regarding an exploration
discovery in the Bumerangue block, offshore Brazil, initial laboratory and
pressure gradient analysis has confirmed the presence of a ~1,000 metre gross
hydrocarbon column including a ~100 metre gross oil column and a ~900 metre
gross liquid rich gas-condensate column. Given the presence of liquids across
the entire hydrocarbon column, the high-quality rock properties observed and
our extensive technology and deepwater developments experience, bp believes
that the carbon dioxide in the reservoir can be managed. bp is continuing
laboratory testing and other analysis in addition to planning appraisal
activities.
• In August Aker BP announced successful completion of the Omega
Alfa exploration campaign in the Norwegian North Sea, resulting in a
significant oil discovery that adds substantial new resources to the Yggdrasil
area. The recoverable volume is estimated at 96-134 million barrels of oil
equivalent. The drilling campaign included the three longest well branches
ever drilled on the Norwegian continental shelf. First oil from Yggdrasil is
expected in 2027.
• In September bp announced it has reached a final investment
decision (FID) on the Tiber-Guadalupe project in the Gulf of America. The 100%
bp-owned Tiber-Guadalupe will be bp's seventh operated oil and gas production
hub in the Gulf of America, featuring a new floating production platform with
the capacity to produce 80,000 barrels of crude oil per day. The project
includes six wells in the Tiber field and a two-well tieback from the
Guadalupe field. Production is expected to start in 2030.
• In October Rhino Resources, operator of the Petroleum
Exploration Licence 85 in the Orange Basin offshore Namibia, partnering with
Azule Energy (bp's 50% joint venture), announced a discovery at the Volans 1-X
well. The well found 26 metres of net pay in rich-gas condensate bearing
reservoirs with excellent quality petrophysical properties and a high
condensate to gas ratio. This discovery builds on the announcement in April of
a discovery in the Capricornus 1-X exploration well in the same licence block.
• In October bp's contract with Iraq's North Oil Company and
North Gas Company became effective, after agreeing an initial baseline
production rate of 328,000 barrels per day. Under the contract bp will
rehabilitate and expand production at the Baba and Avana domes of the Kirkuk
field, as well as the Jambour, Bai Hassan, and Khabbaz fields.
• In October bp announced it had safely started up production
from the Murlach field in the UK North Sea. The two-well subsea tieback is
expected to add a peak net production of around 15,000 barrels of oil
equivalent per day. Murlach is bp's sixth major project* start-up in 2025, in
line with its strategy to grow the upstream business.
• In October bp agreed to sell its 32% non-operated working
interest in the Culzean development in the central North Sea to Serica Energy.
The sale is subject to a pre-emption period which runs for 30 days, with each
of the Culzean field partners (TotalEnergies, 49.99%, and NEO NEXT, 18.01%)
having the option to acquire bp's stake on the same terms as those agreed by
Serica.
• In November bp announced that it had reached agreement to
divest non-controlling interests in Permian and Eagle Ford midstream assets to
investor Sixth Street for $1.5 billion. The transaction is structured in two
phases: approximately $1 billion paid upon signing with the balance expected
by the end of the year, subject to regulatory approvals.
Top of page 9
oil production & operations (continued)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Profit before interest and tax 2,116 1,914 1,889 6,825 8,216
Inventory holding (gains) losses* 3 2 2 (2) 2
RC profit before interest and tax 2,119 1,916 1,891 6,823 8,218
Net (favourable) adverse impact of adjusting items 180 346 903 633 795
Underlying RC profit before interest and tax 2,299 2,262 2,794 7,456 9,013
Taxation on an underlying RC basis (1,054) (1,062) (1,259) (3,491) (3,939)
Underlying RC profit before interest 1,245 1,200 1,535 3,965 5,074
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Depreciation, depletion and amortization
Total depreciation, depletion and amortization 1,961 1,933 1,708 5,681 5,063
Exploration write-offs
Exploration write-offs 154 81 309 288 411
Adjusted EBITDA*
Total adjusted EBITDA 4,414 4,276 4,811 13,425 14,487
Capital expenditure*
Total capital expenditure 1,722 1,706 1,410 5,124 4,720
Third Second Third Nine Nine
quarter quarter quarter months months
2025 2025 2024 2025 2024
Production (net of royalties)((a))
Liquids* (mb/d) 1,121 1,115 1,084 1,107 1,075
Natural gas (mmcf/d) 2,525 2,338 2,348 2,374 2,335
Total hydrocarbons* (mboe/d) 1,556 1,518 1,488 1,517 1,477
Average realizations*((b))
Liquids ($/bbl) 59.58 59.74 70.22 62.17 71.26
Natural gas ($/mcf) 3.32 3.66 2.25 3.87 2.32
Total hydrocarbons ($/boe) 47.89 49.03 53.65 50.99 54.51
(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.
Top of page 10
customers & products
Financial results
• The replacement cost (RC) profit before interest and tax for
the third quarter and nine months was $1,610 million and $2,685 million
respectively, compared with $23 million and $878 million for the same periods
in 2024. The third quarter and nine months are adjusted by an adverse impact
of net adjusting items* of $106 million and $1,241 million respectively,
compared with an adverse impact of net adjusting items of $358 million and
$1,941 million for the same periods in 2024. See page 25 for more information
on adjusting items.
• After adjusting RC profit before interest and tax for
adjusting items, the underlying RC profit before interest and tax* (underlying
result) for the third quarter and nine months was $1,716 million and $3,926
million respectively, compared with $381 million and $2,819 million for the
same periods in 2024.
• The customers & products underlying result for the third
quarter was significantly higher than the same period in 2024, primarily
reflecting higher realized refining margins. The result for the nine months
was significantly higher than the same period in 2024, reflecting stronger
performance both in customers and products.
• customers - the customers underlying result for the third
quarter and nine months was higher compared with the same periods in 2024. The
underlying result benefited from stronger integrated performance across fuels
and midstream, lower underlying operating expenditure* supported by structural
cost reductions*, and reflects a more than 20% increase in Castrol's earnings.
• products - the products underlying result for the third
quarter was significantly higher compared with the same period in 2024. In
refining, the third quarter benefited from significantly higher realized
margins and lower turnaround activity, as well as lower underlying operating
expenditure. The refining result for the nine months was higher compared with
the same period in 2024, primarily driven by the absence of the first quarter
2024 plant-wide power outage at the Whiting refinery and lower underlying
operating expenditure, partly offset by lower realized margins and higher
turnaround activity. The oil trading contribution for the third quarter and
nine months was higher compared with the same periods in 2024.
Operational update
• bp-operated refining availability* for the third quarter and
nine months was 96.6% and 96.4%, compared with 95.6% and 94.1% for the same
periods in 2024. The nine months was higher reflecting strong performance and
notably the absence of the Whiting refinery power outage.
Strategic progress
• Consistent with our strategy to focus downstream and
prioritize high-return investments, bp took the decision to stop further work
on development of a standalone biofuels production (HEFA) facility at our
Rotterdam refinery in the Netherlands.
• Castrol has announced a strategic investment in Electronic
Cooling Solutions to expand into full-service thermal management for
next-generation AI and high-performance computing systems.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Profit (loss) before interest and tax 1,531 420 (1,157) 2,206 413
Inventory holding (gains) losses* 79 552 1,180 479 465
RC profit (loss) before interest and tax 1,610 972 23 2,685 878
Net (favourable) adverse impact of adjusting items 106 561 358 1,241 1,941
Underlying RC profit before interest and tax 1,716 1,533 381 3,926 2,819
Of which:((a))
customers - convenience & mobility 1,167 1,056 897 2,887 2,057
Castrol - included in customers 261 245 216 744 611
products - refining & trading 549 477 (516) 1,039 762
Taxation on an underlying RC basis (360) (251) (67) (687) (525)
Underlying RC profit before interest 1,356 1,282 314 3,239 2,294
(a) A reconciliation to RC profit before interest and tax by business is
provided on page 29.
Top of page 11
customers & products (continued)
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Adjusted EBITDA*((b))
customers - convenience & mobility 1,786 1,698 1,410 4,715 3,545
Castrol - included in customers 309 295 261 888 740
products - refining & trading 975 895 (66) 2,301 2,120
2,761 2,593 1,344 7,016 5,665
Depreciation, depletion and amortization
Total depreciation, depletion and amortization 1,045 1,060 963 3,090 2,846
Capital expenditure*
customers - convenience & mobility 386 387 455 1,358 1,518
Castrol - included in customers 37 36 50 110 167
products - refining & trading((c)) 384 410 416 1,152 1,256
Total capital expenditure((c)) 770 797 871 2,510 2,774
(b) A reconciliation to RC profit before interest and tax by business is
provided on page 29.
(c) Comparative periods in 2024 have been restated to reflect the move of
our Archaea business from the customers & products segment to the gas
& low carbon energy segment.
Third Second Third Nine Nine
quarter quarter quarter months months
Marketing sales of refined products (mb/d) 2025 2025 2024 2025 2024
US 1,273 1,248 1,240 1,240 1,197
Europe 1,046 1,006 1,130 1,000 1,049
Rest of World 456 466 457 463 463
2,775 2,720 2,827 2,703 2,709
Trading/supply sales of refined products 557 478 354 492 364
Total sales volume of refined products 3,332 3,198 3,181 3,195 3,073
bp average refining indicator margin* (RIM) ($/bbl) 15.8 11.9 8.7 12.0 11.9
Refinery throughputs (mb/d)
US 683 573 671 643 622
Europe 833 715 769 790 774
Total refinery throughputs 1,516 1,288 1,440 1,433 1,396
bp-operated refining availability* (%) 96.6 96.4 95.6 96.4 94.1
Top of page 12
other businesses & corporate
Other businesses & corporate comprises technology, bp ventures, our
corporate activities & functions and any residual costs of the Gulf of
America oil spill.
Financial results
• The replacement cost (RC) loss or profit before interest and
tax for the third quarter and nine months was a loss of $277 million and a
profit of $346 million respectively, compared with a profit of $653 million
and $173 million for the same periods in 2024. The third quarter and nine
months are adjusted by an adverse impact of net adjusting items* of $88
million and a favourable impact of net adjusting items of $690 million
respectively, compared with a favourable impact of net adjusting items of $422
million and $254 million for the same periods in 2024. Adjusting items include
adverse impacts of fair value accounting effects* of $13 million for the third
quarter and favourable impacts of fair value accounting effects of $1,096
million for the nine months in 2025, and a favourable impact of $494 million
and $272 million for the same periods in 2024. See page 25 for more
information on adjusting items.
• After adjusting RC loss or profit before interest and tax for
adjusting items, the underlying RC loss before interest and tax* for the third
quarter and nine months was $189 million and $344 million respectively,
compared with a profit of $231 million and a loss of $81 million for the same
periods in 2024.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Profit (loss) before interest and tax (277) 645 653 346 173
Inventory holding (gains) losses* - - - - -
RC profit (loss) before interest and tax (277) 645 653 346 173
Net (favourable) adverse impact of adjusting items((a)) 88 (683) (422) (690) (254)
Underlying RC profit (loss) before interest and tax (189) (38) 231 (344) (81)
Taxation on an underlying RC basis 106 109 (64) 248 38
Underlying RC profit (loss) before interest (83) 71 167 (96) (43)
(a) Includes fair value accounting effects relating to hybrid bonds. See
page 32 for more information.
Top of page 13
Financial statements
Group income statement
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Sales and other operating revenues (Note 5) 48,420 46,627 47,254 141,952 143,433
Earnings from joint ventures - after interest and tax 176 241 406 744 834
Earnings from associates - after interest and tax 275 155 280 679 844
Interest and other income 397 375 438 1,157 1,233
Gains on sale of businesses and fixed assets (18) 279 (48) 275 197
Total revenues and other income 49,250 47,677 48,330 144,807 146,541
Purchases 28,031 26,875 30,139 82,626 86,677
Production and manufacturing expenses 6,620 6,153 5,004 18,887 18,543
Production and similar taxes 431 414 469 1,292 1,397
Depreciation, depletion and amortization (Note 6) 4,472 4,641 4,117 13,296 12,365
Net impairment and losses on sale of businesses and fixed assets (Note 3) 753 1,157 1,842 2,413 3,888
Exploration expense 224 139 372 466 798
Distribution and administration expenses 4,271 4,242 3,930 12,924 12,319
Profit (loss) before interest and taxation 4,448 4,056 2,457 12,903 10,554
Finance costs 1,267 1,229 1,101 3,817 3,392
Net finance (income) expense relating to pensions and other post-employment (55) (56) (42) (163) (123)
benefits
Profit (loss) before taxation 3,236 2,883 1,398 9,249 7,285
Taxation 1,727 954 1,028 4,829 4,436
Profit (loss) for the period 1,509 1,929 370 4,420 2,849
Attributable to
bp shareholders 1,161 1,629 206 3,477 2,340
Non-controlling interests 348 300 164 943 509
1,509 1,929 370 4,420 2,849
Earnings per share (Note 7)
Profit (loss) for the period attributable to bp shareholders
Per ordinary share (cents)
Basic 7.48 10.41 1.26 22.22 14.19
Diluted 7.38 10.27 1.23 21.77 13.83
Per ADS (dollars)
Basic 0.45 0.62 0.08 1.33 0.85
Diluted 0.44 0.62 0.07 1.31 0.83
Top of page 14
Condensed group statement of comprehensive income
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Profit (loss) for the period 1,509 1,929 370 4,420 2,849
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences((a)) (276) 1,323 838 1,866 248
Exchange (gains) losses on translation of foreign operations reclassified to 22 - - 22 -
gain or loss on sale of businesses and fixed assets
Cash flow hedges and costs of hedging 134 235 (111) 184 (326)
Share of items relating to equity-accounted entities, net of tax (5) 3 (41) (1) (39)
Income tax relating to items that may be reclassified (3) (57) 91 (18) 127
(128) 1,504 777 2,053 10
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-employment benefit liability (447) (214) (51) (330) (357)
or asset
Remeasurements of equity investments - 2 (8) 1 (38)
Cash flow hedges that will subsequently be transferred to the balance sheet (1) 2 10 3 7
Income tax relating to items that will not be reclassified(b) 126 52 12 83 745
(322) (158) (37) (243) 357
Other comprehensive income (450) 1,346 740 1,810 367
Total comprehensive income 1,059 3,275 1,110 6,230 3,216
Attributable to
bp shareholders 726 2,883 922 5,165 2,705
Non-controlling interests 333 392 188 1,065 511
1,059 3,275 1,110 6,230 3,216
(a) Second quarter and nine months 2025 are principally affected by
movements in the Pound Sterling against the US dollar.
(b) Nine months 2024 includes a $658-million credit in respect of the
reduction in the deferred tax liability on defined benefit pension plan
surpluses following the reduction in the rate of the authorized surplus
payments tax charge in the UK from 35% to 25%.
Top of page 15
Condensed group statement of changes in equity
bp shareholders' Non-controlling interests Total
$ million equity Hybrid bonds Other interest equity
At 1 January 2025 59,246 16,649 2,423 78,318
Total comprehensive income 5,165 607 458 6,230
Dividends (3,805) - (386) (4,191)
Cash flow hedges transferred to the balance sheet, net of tax (5) - - (5)
Repurchase of ordinary share capital (3,261) - - (3,261)
Share-based payments, net of tax 908 - - 908
Share of equity-accounted entities' changes in equity, net of tax 1 - - 1
Issue of perpetual hybrid bonds((a)) - 500 - 500
Redemption of perpetual hybrid bonds, net of tax((b)) - (1,200) - (1,200)
Payments on perpetual hybrid bonds (9) (618) - (627)
Transactions involving non-controlling interests, net of tax((c)) 4 - 968 972
At 30 September 2025 58,244 15,938 3,463 77,645
bp shareholders' Non-controlling interests Total
$ million equity Hybrid bonds Other interest equity
At 1 January 2024 70,283 13,566 1,644 85,493
Total comprehensive income 2,705 470 41 3,216
Dividends (3,739) - (282) (4,021)
Cash flow hedges transferred to the balance sheet, net of tax (8) - - (8)
Repurchase of ordinary share capital (5,554) - - (5,554)
Share-based payments, net of tax 903 - - 903
Issue of perpetual hybrid bonds (4) 1,300 - 1,296
Redemption of perpetual hybrid bonds, net of tax 9 (1,300) - (1,291)
Payments on perpetual hybrid bonds - (520) - (520)
Transactions involving non-controlling interests, net of tax 231 - 201 432
At 30 September 2024 64,826 13,516 1,604 79,946
(a) During the nine months 2025 a group subsidiary issued perpetual
subordinated hybrid securities of $0.5 billion, the proceeds of which were
specifically earmarked to fund BP Alternative Energy Investments Ltd including
the funding of Lightsource bp. This transaction resulted in a reduction of net
debt and gearing.
(b) In the third quarter 2025, BP Capital Markets p.l.c. exercised its
option to redeem $1.2 billion of hybrid bonds.
(c) In the nine months 2025, a group subsidiary that holds a 12% stake in
the Trans-Anatolian Natural Gas Pipeline (TANAP), issued $1.0 billion of
equity instruments with preferred distributions. The group retains control
over the ability to defer these distributions which are not guaranteed, and
investors cannot redeem their shares except under specific conditions that are
within the group's control.
Top of page 16
Group balance sheet
30 September 31 December
$ million 2025 2024
Non-current assets
Property, plant and equipment 100,363 100,238
Goodwill 15,114 14,888
Intangible assets 9,007 9,646
Investments in joint ventures 12,392 12,291
Investments in associates 9,910 7,741
Other investments 1,166 1,292
Fixed assets 147,952 146,096
Loans 2,172 1,961
Trade and other receivables 2,372 1,815
Derivative financial instruments 18,207 16,114
Prepayments 545 548
Deferred tax assets 5,702 5,403
Defined benefit pension plan surpluses 7,651 7,457
184,601 179,394
Current assets
Loans 444 223
Inventories 24,154 23,232
Trade and other receivables 26,169 27,127
Derivative financial instruments 4,525 5,112
Prepayments 1,714 2,594
Current tax receivable 973 1,096
Other investments 139 165
Cash and cash equivalents 34,909 39,204
93,027 98,753
Assets classified as held for sale (Note 2) 2,831 4,081
95,858 102,834
Total assets 280,459 282,228
Current liabilities
Trade and other payables 54,625 58,411
Derivative financial instruments 3,694 4,347
Accruals 5,290 6,071
Lease liabilities 2,761 2,660
Finance debt 6,091 4,474
Current tax payable 1,562 1,573
Provisions 5,003 3,600
79,026 81,136
Liabilities directly associated with assets classified as held for sale (Note 1,334 1,105
2)
80,360 82,241
Non-current liabilities
Other payables 8,086 9,409
Derivative financial instruments 17,415 18,532
Accruals 1,693 1,326
Lease liabilities 11,868 9,340
Finance debt 54,097 55,073
Deferred tax liabilities 8,432 8,428
Provisions 15,810 14,688
Defined benefit pension plan and other post-employment benefit plan deficits 5,053 4,873
122,454 121,669
Total liabilities 202,814 203,910
Net assets 77,645 78,318
Equity
bp shareholders' equity 58,244 59,246
Non-controlling interests 19,401 19,072
Total equity 77,645 78,318
Top of page 17
Condensed group cash flow statement
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Operating activities
Profit (loss) before taxation 3,236 2,883 1,398 9,249 7,285
Adjustments to reconcile profit (loss) before taxation to net cash provided by
operating activities
Depreciation, depletion and amortization and exploration expenditure written 4,655 4,723 4,427 13,614 13,008
off
Net impairment and (gain) loss on sale of businesses and fixed assets 771 878 1,890 2,138 3,691
Earnings from equity-accounted entities, less dividends received 192 40 (196) 32 (273)
Net charge for interest and other finance expense, less net interest paid 470 126 324 743 1,040
Share-based payments 264 215 278 880 946
Net operating charge for pensions and other post-employment benefits, less (96) (36) (52) (143) (118)
contributions and benefit payments for unfunded plans
Net charge for provisions, less payments (60) 666 (48) 1,710 33
Movements in inventories and other current and non-current assets and 494 (2,030) 1,798 (6,605) 1,223
liabilities
Income taxes paid (2,140) (1,194) (3,058) (4,727) (6,965)
Net cash provided by operating activities 7,786 6,271 6,761 16,891 19,870
Investing activities
Expenditure on property, plant and equipment, intangible and other assets (3,171) (3,236) (4,223) (9,758) (11,404)
Acquisitions, net of cash acquired (52) (39) (218) (293) (440)
Investment in joint ventures (128) (59) (76) (245) (524)
Investment in associates (30) (27) (25) (69) (143)
Total cash capital expenditure (3,381) (3,361) (4,542) (10,365) (12,511)
Proceeds from disposal of fixed assets 30 322 16 644 117
Proceeds from disposal of businesses, net of cash disposed (2) 76 274 110 840
Proceeds from loan repayments 48 31 19 110 59
Cash provided from investing activities 76 429 309 864 1,016
Net cash used in investing activities (3,305) (2,932) (4,233) (9,501) (11,495)
Financing activities
Net issue (repurchase) of shares (Note 7) (750) (1,063) (2,001) (3,660) (5,502)
Lease liability payments (816) (784) (703) (2,327) (2,076)
Proceeds from long-term financing 1,028 1,155 2,401 2,237 7,396
Repayments of long-term financing (1,250) (848) (956) (3,464) (2,253)
Net increase (decrease) in short-term debt 104 39 (73) 18 (8)
Issue of perpetual hybrid bonds(a) - - - 500 1,296
Redemption of perpetual hybrid bonds(a) (1,200) - - (1,200) (1,288)
Payments relating to perpetual hybrid bonds (284) (332) (271) (888) (798)
Payments relating to transactions involving non-controlling interests (Other (2) - - (2) -
interest)
Receipts relating to transactions involving non-controlling interests (Other 8 965 (7) 973 517
interest)
Dividends paid - bp shareholders (1,288) (1,238) (1,297) (3,783) (3,720)
- non-controlling interests (155) (127) (96) (356) (282)
Net cash provided by (used in) financing activities (4,605) (2,233) (3,003) (11,952) (6,718)
Currency translation differences relating to cash and cash equivalents (51) 193 179 248 (92)
Increase (decrease) in cash and cash equivalents (175) 1,299 (296) (4,314) 1,565
Cash and cash equivalents at beginning of period 35,130 33,831 34,891 39,269 33,030
Cash and cash equivalents at end of period(b) 34,955 35,130 34,595 34,955 34,595
(a) See Condensed group statement of changes in equity - footnotes (a) and
(b) for further information.
(b) Third quarter and nine months 2025 includes $46 million (second
quarter 2025 $63 million) of cash and cash equivalents classified as assets
held for sale in the group balance sheet.
Top of page 18
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 2024
included in bp Annual Report and Form 20-F 2024.
bp prepares its consolidated financial statements included within bp Annual
Report and Form 20-F on the basis of United Kingdom adopted international
accounting standards and IFRS Accounting Standards® (IFRS) as issued by the
International Accounting Standards Board (IASB), IFRS as adopted by the
European Union (EU), and in accordance with the provisions of the UK Companies
Act 2006 as applicable to companies reporting under international accounting
standards. IFRS as adopted by the UK does not differ from IFRS as adopted by
the EU. 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 2025 which are the same as those used in preparing bp Annual Report and
Form 20-F 2024.
There are no new or amended standards or interpretations adopted from 1
January 2025 onwards that have a significant impact on the financial
information.
UK Energy Profits Levy
In October 2024, the UK government announced changes (effective from 1
November 2024) to the Energy Profits Levy including a 3% increase in the rate
taking the headline rate of tax on North Sea profits to 78%, an extension to
the period of application of the Levy to 31 March 2030 and the removal of the
Levy's main investment allowance. The changes to the rate and to the
investment allowance were substantively enacted in 2024. The extension of the
Levy to 31 March 2030 was substantively enacted in the first quarter 2025,
resulting in a non-cash deferred charge of $539 million.
Germany tax legislation
On 11 July 2025, the German federal government substantively enacted a number
of changes to its tax legislation, including a 5% reduction in the corporate
income tax rate by 2032. The reduction in the tax rate will be phased in by
means of a 1% reduction each year between 2028 and 2032 and has resulted in a
non-cash deferred tax charge of $233 million in the third quarter 2025.
Change in segmentation
During the first quarter of 2025, our Archaea business has moved from the
customers & products segment to the gas & low carbon energy segment.
The change in segmentation is consistent with a change in the way that
resources are allocated, and performance is assessed by the chief operating
decision maker, who for bp is the group chief executive.
Comparative information for 2024 has been restated where material to reflect
the changes in reportable segments.
Significant accounting judgements and estimates
bp's significant accounting judgements and estimates were disclosed in bp
Annual Report and Form 20-F 2024. These have been subsequently considered at
the end of this quarter to determine if any changes were required to those
judgements and estimates. No significant changes were identified.
Top of page 19
Note 2. Non-current assets held for sale
The carrying amount of assets classified as held for sale at 30 September
2025 is $2,831 million, with associated liabilities of $1,334 million.
Gas & low carbon energy
On 18 July 2025, bp announced that it plans to sell its US onshore wind energy
business, bp Wind Energy to LS Power. bp Wind Energy has interests in ten
operating onshore wind energy assets across seven US states. The transaction
is expected to complete by the end of 2025, subject to regulatory approval.
The carrying amount of assets classified as held for sale at 30 September 2025
is $570 million, with associated liabilities of $39 million.
On 24 October 2024, bp completed the acquisition of the remaining 50.03% of
Lightsource bp. The acquisition included certain assets for which sales
processes were in progress at the acquisition date. Completion of the sale of
a significant majority of these assets is expected to complete by the end of
2025, whilst sale of the remaining assets is now expected to complete within
the first half of 2026. The carrying amount of assets classified as held for
sale at 30 September 2025 is $1,868 million, with associated liabilities of
$1,200 million.
On 1 August 2025, bp and JERA Co., Inc. completed formation of a new offshore
wind joint venture - JERA Nex bp. bp contributed its development projects in
the UK, Germany and US into the joint venture. The related assets and
liabilities of those projects, previously classified as held for sale, were
derecognised on that date.
Customers & products
On 9 July 2025, bp announced the sale of its Netherlands mobility &
convenience and bp pulse businesses to Catom BV. The transaction includes bp's
Dutch retail sites, EV charging hubs and the associated fleet business.
Completion of the disposal is expected by the end of 2025 subject to
regulatory approvals. The carrying amount of assets classified as held for
sale at 30 September 2025 is $393 million, with associated liabilities of $95
million.
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 $753 million and $2,413 million
respectively, compared with net charges of $1,842 million and $3,888 million
for the same periods in 2024 and include net impairment charges for the third
quarter and nine months of $370 million and $1,931 million respectively,
compared with net impairment charges of $1,730 million and $3,675 million
for the same periods in 2024.
Gas & low carbon energy
Third quarter and nine months 2025 impairments includes a net impairment
charge of $135 million and $881 million respectively, compared with net
charges of $734 million and $1,859 million for the same periods in 2024 in
the gas & low carbon energy segment.
Oil production & operations
Third quarter and nine months 2025 impairments includes a reversal of $7
million and a net impairment charge of $329 million respectively, compared
with net charges of $767 million and $900 million for the same periods in 2024
in the oil production & operations segment.
Customers & products
Third quarter and nine months 2025 impairments includes a net impairment
charge of $242 million and $719 million respectively, compared with net
charges of $223 million and $914 million for the same periods in 2024 in the
customers & products segment.
Top of page 20
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 2025 2025 2024 2025 2024
gas & low carbon energy 1,097 1,047 1,007 3,502 1,728
oil production & operations 2,119 1,916 1,891 6,823 8,218
customers & products 1,610 972 23 2,685 878
other businesses & corporate (277) 645 653 346 173
4,549 4,580 3,574 13,356 10,997
Consolidation adjustment - UPII* (19) 30 65 24 24
RC profit (loss) before interest and tax 4,530 4,610 3,639 13,380 11,021
Inventory holding gains (losses)*
gas & low carbon energy - - - - -
oil production & operations (3) (2) (2) 2 (2)
customers & products (79) (552) (1,180) (479) (465)
Profit (loss) before interest and tax 4,448 4,056 2,457 12,903 10,554
Finance costs 1,267 1,229 1,101 3,817 3,392
Net finance expense/(income) relating to pensions and other post-employment (55) (56) (42) (163) (123)
benefits
Profit (loss) before taxation 3,236 2,883 1,398 9,249 7,285
RC profit (loss) before interest and tax*
US 632 1,417 1,122 3,582 4,277
Non-US 3,898 3,193 2,517 9,798 6,744
4,530 4,610 3,639 13,380 11,021
Top of page 21
Note 5. Sales and other operating revenues
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
By segment
gas & low carbon energy 9,655 9,172 8,526 29,605 23,010
oil production & operations 6,232 6,053 6,468 18,787 19,559
customers & products 38,697 37,449 38,437 112,309 119,432
other businesses & corporate 627 539 614 1,650 1,746
55,211 53,213 54,045 162,351 163,747
Less: sales and other operating revenues between segments
gas & low carbon energy 310 337 385 1,378 1,026
oil production & operations 5,908 5,818 5,860 17,544 17,755
customers & products 70 (55) (138) 57 180
other businesses & corporate 503 486 684 1,420 1,353
6,791 6,586 6,791 20,399 20,314
External sales and other operating revenues
gas & low carbon energy 9,345 8,835 8,141 28,227 21,984
oil production & operations 324 235 608 1,243 1,804
customers & products 38,627 37,504 38,575 112,252 119,252
other businesses & corporate 124 53 (70) 230 393
Total sales and other operating revenues 48,420 46,627 47,254 141,952 143,433
By geographical area
US 18,968 18,890 19,388 56,947 59,586
Non-US 37,877 36,233 36,712 109,811 112,752
56,845 55,123 56,100 166,758 172,338
Less: sales and other operating revenues between areas 8,425 8,496 8,846 24,806 28,905
48,420 46,627 47,254 141,952 143,433
Revenues from contracts with customers
Sales and other operating revenues include the following in relation to
revenues from contracts with customers:
Crude oil 635 421 618 1,471 1,704
Oil products 30,274 28,572 30,997 86,008 93,385
Natural gas, LNG and NGLs 7,192 6,049 6,458 20,504 17,196
Non-oil products and other revenues from contracts with customers 3,528 3,697 3,213 10,858 9,249
Revenue from contracts with customers 41,629 38,739 41,286 118,841 121,534
Other operating revenues((a)) 6,791 7,888 5,968 23,111 21,899
Total sales and other operating revenues 48,420 46,627 47,254 141,952 143,433
(a) Principally relates to commodity derivative transactions including
sales of bp own production in trading books.
( )
Top of page 22
Note 6. Depreciation, depletion and amortization
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Total depreciation, depletion and amortization by segment
gas & low carbon energy 1,223 1,407 1,180 3,796 3,682
oil production & operations 1,961 1,933 1,708 5,681 5,063
customers & products 1,045 1,060 963 3,090 2,846
other businesses & corporate 243 241 266 729 774
4,472 4,641 4,117 13,296 12,365
Total depreciation, depletion and amortization by geographical area
US 1,898 1,897 1,735 5,531 5,008
Non-US 2,574 2,744 2,382 7,765 7,357
4,472 4,641 4,117 13,296 12,365
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 2025 annual general meeting,
138 million ordinary shares repurchased were settled during the third quarter
2025 for a total cost of $750 million. All of these shares were held as
treasury shares. A further 91 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 $522 million. This
amount has been accrued at 30 September 2025. 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 2025 2025 2024 2025 2024
Results for the period
Profit (loss) for the period attributable to bp shareholders 1,161 1,629 206 3,477 2,340
Less: preference dividend - 1 - 1 1
Less: (gain) loss on redemption of perpetual hybrid bonds - - - - (10)
Profit (loss) attributable to bp ordinary shareholders 1,161 1,628 206 3,476 2,349
Number of shares (thousand)((a))
Basic weighted average number of shares outstanding 15,518,940 15,645,561 16,321,349 15,646,554 16,553,408
ADS equivalent((b)) 2,586,490 2,607,593 2,720,224 2,607,759 2,758,901
Weighted average number of shares outstanding used to calculate diluted 15,735,029 15,854,588 16,709,108 15,968,108 16,980,519
earnings per share
ADS equivalent((b)) 2,622,504 2,642,431 2,784,851 2,661,351 2,830,086
Shares in issue at period-end 15,487,180 15,596,112 16,155,806 15,487,180 16,155,806
ADS equivalent((b)) 2,581,196 2,599,352 2,692,634 2,581,196 2,692,634
(a) Excludes treasury shares and includes certain shares that will be
issued in the future under employee share-based payment plans.
(b) One ADS is equivalent to six ordinary shares.
Top of page 23
Note 8. Dividends
Dividends payable
bp today announced an interim dividend of 8.320 cents per ordinary share which
is expected to be paid on 19 December 2025 to ordinary shareholders and
American Depositary Share (ADS) holders on the register on 14 November 2025.
The ex-dividend date will be 13 November 2025 for ordinary shareholders and 14
November 2025 for ADS holders. The corresponding amount in sterling is due to
be announced on 9 December 2025, calculated based on the average of the market
exchange rates over three dealing days between 3 December 2025 and 5 December
2025. Holders of ADSs are expected to receive $0.4992 per ADS (less applicable
fees). The board has decided not to offer a scrip dividend alternative in
respect of the third quarter 2025 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
2025 2025 2024 2025 2024
Dividends paid per ordinary share
cents 8.320 8.000 8.000 24.320 22.540
pence 6.194 5.899 6.050 18.270 17.425
Dividends paid per ADS (cents) 49.92 48.00 48.00 145.92 135.24
Note 9. Net debt
Net debt* 30 September 30 June 30 September
$ million 2025 2025 2024
Finance debt((a)) 60,188 60,346 57,470
Fair value (asset) liability of hedges related to finance debt((b)) 775 764 1,393
60,963 61,110 58,863
Less: cash and cash equivalents 34,909 35,067 34,595
Net debt((c)) 26,054 26,043 24,268
Total equity 77,645 79,780 79,946
Gearing* 25.1% 24.6% 23.3%
(a) The fair value of finance debt at 30 September 2025 was
$57,113 million (30 June 2025 $57,135 million, 30 September 2024 $54,324
million).
(b) Derivative financial instruments entered into for the purpose of
managing foreign currency exchange risk associated with net debt with a fair
value liability position of $94 million at 30 September 2025 (second quarter
2025 liability of $96 million and third quarter 2024 liability of
$123 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.
Note 10. Events after the reporting period
On 8 October 2025, the International Chamber of Commerce International Court
of Arbitration issued a partial final award in bp's favour against Venture
Global ("VG"). The arbitration tribunal found that VG had breached its
obligations to declare Commercial Operations Date of its Calcasieu Project in
a timely manner and act as a "Reasonable and Prudent Operator" pursuant to the
long-term LNG Sale and Purchase Agreement ("SPA") with bp. Throughout the
breach, VG sold LNG cargos on the spot market rather than to bp as required
under the SPA.
The next phase of the arbitration proceedings is a damages hearing, most
likely to occur in 2026. Due to the uncertainty of the final amount to be
received, management has not recognised a receivable in the quarter.
Note 11. Statutory accounts
The financial information shown in this publication, which was approved by the
Board of Directors on 3 November 2025, is unaudited and does not constitute
statutory financial statements. Audited financial information will be
published in bp Annual Report and Form 20-F 2025. bp Annual Report and Form
20-F 2024 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 24
Additional information
Capital expenditure*
Capital expenditure is a measure that provides useful information to
understand how bp's management allocates resources including the investment of
funds in projects which expand the group's activities through acquisition.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Capital expenditure
Organic capital expenditure* 3,328 3,321 4,341 10,089 11,906
Inorganic capital expenditure* 53 40 201 276 605
3,381 3,361 4,542 10,365 12,511
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Capital expenditure by segment
gas & low carbon energy((a)) 828 790 2,156 2,521 4,721
oil production & operations 1,722 1,706 1,410 5,124 4,720
customers & products((a)) 770 797 871 2,510 2,774
other businesses & corporate 61 68 105 210 296
3,381 3,361 4,542 10,365 12,511
Capital expenditure by geographical area
US 1,591 1,576 1,389 4,600 4,801
Non-US 1,790 1,785 3,153 5,765 7,710
3,381 3,361 4,542 10,365 12,511
(a) Comparative periods in 2024 have been restated to reflect the move of
our Archaea business from the customers & products segment to the gas
& low carbon energy segment.
Top of page 25
Adjusting items*
Adjusting items 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 are used as a reconciling adjustment to
derive underlying RC profit or loss and related underlying measures which are
non-IFRS measures.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
gas & low carbon energy
Gains on sale of businesses and fixed assets - 69 19 68 29
Net impairment and losses on sale of businesses and fixed assets((a)) (489) (439) (772) (1,294) (1,898)
Environmental and related provisions - - - - -
Restructuring, integration and rationalization costs 8 3 (24) (3) (24)
Fair value accounting effects((b)(c)) 131 18 (275) 817 (1,173)
Other (72) (66) 303 (64) (22)
(422) (415) (749) (476) (3,088)
oil production & operations
Gains on sale of businesses and fixed assets (29) 196 (82) 176 109
Net impairment and losses on sale of businesses and fixed assets((a)) 10 (330) (770) (335) (919)
Environmental and related provisions (145) (55) (53) (231) 65
Restructuring, integration and rationalization costs 9 (46) (1) (78) (1)
Fair value accounting effects - - - - -
Other (25) (111) 3 (165) (49)
(180) (346) (903) (633) (795)
customers & products
Gains on sale of businesses and fixed assets 10 16 12 29 21
Net impairment and losses on sale of businesses and fixed assets((a)) (274) (389) (295) (777) (1,069)
Environmental and related provisions (1) (1) (4) (2) 3
Restructuring, integration and rationalization costs (17) (86) (39) (194) (38)
Fair value accounting effects((c)) 42 (201) 157 (241) 38
Other((d)) 134 100 (189) (56) (896)
(106) (561) (358) (1,241) (1,941)
other businesses & corporate
Gains on sale of businesses and fixed assets 2 - 3 2 35
Net impairment and losses on sale of businesses and fixed assets - - (6) (5) 9
Environmental and related provisions (48) (18) (8) (138) 11
Restructuring, integration and rationalization costs (8) (39) (50) (245) (38)
Fair value accounting effects((c)) (13) 740 494 1,096 272
Gulf of America oil spill (9) (9) (20) (27) (39)
Other (12) 9 9 7 4
(88) 683 422 690 254
Total before interest and taxation (796) (639) (1,588) (1,660) (5,570)
Finance costs((e)) (83) (78) (58) (348) (355)
Total before taxation (879) (717) (1,646) (2,008) (5,925)
Taxation on adjusting items((f)) 125 400 535 664 1,229
Taxation - tax rate change effect((g)) (233) - (44) (772) (348)
Total after taxation for period (987) (317) (1,155) (2,116) (5,044)
(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) Nine months 2024 includes the initial recognition of onerous contract
provisions related to Gelsenkirchen refinery. The unwind of these provisions
in the subsequent quarters are reported as an adjusting item as the
contractual obligations are settled.
(e) Includes the unwinding of discounting effects relating to Gulf of
America oil spill payables, the income statement impact of temporary valuation
differences related to the group's interest rate and foreign currency exchange
risk management associated with finance debt, and the unwinding of discounting
effects relating to certain onerous contract provisions.
(f) 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.
(g) Third quarter 2025 and nine months 2025 include the deferred tax
impact of a change in the tax rate in Germany, see Note 1 for further
information. Nine months 2025 and nine months 2024 include revisions to the
deferred tax impact of the introduction of the UK Energy Profits Levy (EPL) on
temporary differences existing at the opening balance sheet date. The EPL
increases the headline rate of tax on
Top of page 26
taxable profits from bp's North Sea business to 78%. In the first quarter 2025
a two-year extension of the EPL to 31 March 2030 was substantively enacted.
Net debt including leases*
Gearing including leases and net debt including leases are non-IFRS measures
that provide the impact of the group's lease portfolio on net debt and
gearing.
Net debt including leases 30 September 30 June 30 September
$ million 2025 2025 2024
Net debt* 26,054 26,043 24,268
Lease liabilities 14,629 14,636 11,018
Net partner (receivable) payable for leases entered into on behalf of joint (1,082) (1,030) (98)
operations
Net debt including leases 39,601 39,649 35,188
Total equity 77,645 79,780 79,946
Gearing including leases* 33.8% 33.2% 30.6%
Gulf of America oil spill
30 September 31 December
$ million 2025 2024
Gulf of America oil spill payables and provisions (7,172) (7,958)
Of which - current (1,512) (1,127)
Deferred tax asset 1,097 1,205
During the second quarter pre-tax payments of $1,129 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 America 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 America 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 2024 - Financial statements -
Notes 7, 22, 23, 29, and 33.
Working capital* reconciliation
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 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.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Movements in inventories and other current and non-current assets and 494 (2,030) 1,798 (6,605) 1,223
liabilities as per condensed group cash flow statement((a))
Adjusted for inventory holding gains (losses) (Note 4) (82) (554) (1,182) (477) (467)
Adjusted for fair value accounting effects relating to subsidiaries 177 554 319 1,690 (1,026)
Other adjusting items((b)) 322 646 451 1,569 (201)
Working capital release (build) after adjusting for net inventory holding 911 (1,384) 1,386 (3,823) (471)
gains (losses), fair value accounting effects and other adjusting items
(a) The movement in working capital includes outflows relating to the Gulf
of America oil spill on a pre-tax basis of $5 million and $1,136 million in
the third quarter and nine months 2025 (second quarter 2025 $1,129 million,
third quarter 2024 $4 million, nine months 2024 $1,140 million).
(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 27
Adjusted earnings before interest, taxation, depreciation and amortization
(adjusted EBITDA)*
Adjusted EBITDA is a non-IFRS measure closely tracked by bp's management to
evaluate the underlying trends in bp's operating performance on a comparable
basis, period on period.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
Profit for the period 1,509 1,929 370 4,420 2,849
Finance costs 1,267 1,229 1,101 3,817 3,392
Net finance (income) expense relating to pensions and other post-employment (55) (56) (42) (163) (123)
benefits
Taxation 1,727 954 1,028 4,829 4,436
Profit before interest and tax 4,448 4,056 2,457 12,903 10,554
Inventory holding (gains) losses*, before tax 82 554 1,182 477 467
RC profit before interest and tax 4,530 4,610 3,639 13,380 11,021
Net (favourable) adverse impact of adjusting items*, before interest and tax 796 639 1,588 1,660 5,570
Underlying RC profit before interest and tax 5,326 5,249 5,227 15,040 16,591
Add back:
Depreciation, depletion and amortization 4,472 4,641 4,117 13,296 12,365
Exploration expenditure written off 183 82 310 318 643
Adjusted EBITDA 9,981 9,972 9,654 28,654 29,599
Top of page 28
Underlying operating expenditure* reconciliation
Underlying operating expenditure is a non-IFRS measure and a subset of
production and manufacturing expenses plus distribution and administration
expenses and excludes costs that are classified as adjusting items. It
represents the majority of the remaining expenses in these line items but
excludes certain costs that are variable, primarily with volumes (such as
freight costs).
Management believes that underlying operating expenditure is a performance
measure that provides investors with useful information regarding the
company's financial performance because it considers these expenses to be the
principal operating and overhead expenses that are most directly under their
control although they also include certain foreign exchange and commodity
price effects.
Third Second Third Nine Nine
quarter quarter quarter months months
$ million 2025 2025 2024 2025 2024
From group income statement
Production and manufacturing expenses 6,620 6,153 5,004 18,887 18,543
Distribution and administration expenses 4,271 4,242 3,930 12,924 12,319
10,891 10,395 8,934 31,811 30,862
Less certain variable costs:
Transportation and shipping costs 2,579 2,634 2,426 7,659 7,516
Environmental costs 1,290 1,630 1,210 4,257 3,078
Marketing and distribution costs 358 421 400 1,206 1,532
Commission, storage and handling costs 410 405 393 1,181 1,144
Other variable costs and non-cash costs 654 435 (602) 1,386 439
Certain variable costs and non-cash costs 5,291 5,525 3,827 15,689 13,709
Adjusted operating expenditure* 5,600 4,870 5,107 16,122 17,153
Less certain adjusting items*:
Gulf of America oil spill 9 9 20 27 39
Environmental and related provisions 194 74 65 371 (79)
Restructuring, integration and rationalization costs 8 168 114 520 101
Fair value accounting effects - derivative instruments relating to the hybrid 13 (740) (494) (1,096) (272)
bonds
Other certain adjusting items (111) (98) (188) 52 822
Certain adjusting items 113 (587) (483) (126) 611
Underlying operating expenditure 5,487 5,457 5,590 16,248 16,542
Top of page 29
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 2025 2025 2024 2025 2024
RC profit (loss) before interest and tax for customers & products 1,610 972 23 2,685 878
Less: Adjusting items* gains (charges) (106) (561) (358) (1,241) (1,941)
Underlying RC profit (loss) before interest and tax for customers & 1,716 1,533 381 3,926 2,819
products
By business:
customers - convenience & mobility 1,167 1,056 897 2,887 2,057
Castrol - included in customers 261 245 216 744 611
products - refining & trading 549 477 (516) 1,039 762
Add back: Depreciation, depletion and amortization 1,045 1,060 963 3,090 2,846
By business:
customers - convenience & mobility 619 642 513 1,828 1,488
Castrol - included in customers 48 50 45 144 129
products - refining & trading 426 418 450 1,262 1,358
Adjusted EBITDA for customers & products 2,761 2,593 1,344 7,016 5,665
By business:
customers - convenience & mobility 1,786 1,698 1,410 4,715 3,545
Castrol - included in customers 309 295 261 888 740
products - refining & trading 975 895 (66) 2,301 2,120
Top of page 30
Realizations* and marker prices
Third Second Third Nine Nine
quarter quarter quarter months months
2025 2025 2024 2025 2024
Average realizations((a))
Liquids* ($/bbl)
US 54.02 53.39 63.31 56.32 63.83
Europe 69.15 64.62 75.45 69.81 80.44
Rest of World 67.20 69.69 80.79 70.36 81.39
bp average 60.02 60.16 70.68 62.55 71.89
Natural gas ($/mcf)
US 2.41 2.52 1.18 2.67 1.39
Europe 11.98 13.06 12.22 13.90 10.68
Rest of World 6.41 6.50 5.80 6.71 5.57
bp average 5.34 5.56 4.75 5.75 4.61
Total hydrocarbons* ($/boe)
US 38.91 39.51 42.18 41.41 42.65
Europe 69.25 68.02 74.03 73.19 74.73
Rest of World 47.62 48.44 47.57 49.70 47.22
bp average 45.00 45.84 46.81 47.58 46.91
Average oil marker prices ($/bbl)
Brent 69.13 67.88 80.34 70.93 82.79
West Texas Intermediate 65.07 63.81 75.28 66.74 77.71
Western Canadian Select 52.52 53.16 59.98 54.66 62.22
Alaska North Slope 70.07 68.82 78.95 71.54 82.24
Average natural gas marker prices
Henry Hub gas price((b)) ($/mmBtu) 3.07 3.44 2.15 3.39 2.10
UK Gas - National Balancing Point (p/therm) 79.84 84.53 81.77 93.38 75.75
(a) Based on sales of consolidated subsidiaries only - this excludes
equity-accounted entities.
(b) Henry Hub First of Month Index.
Exchange rates
Third Second Third Nine Nine
quarter quarter quarter months months
2025 2025 2024 2025 2024
$/£ average rate for the period 1.35 1.34 1.30 1.31 1.28
$/£ period-end rate 1.34 1.37 1.34 1.34 1.34
$/€ average rate for the period 1.17 1.13 1.10 1.12 1.09
$/€ period-end rate 1.17 1.17 1.12 1.17 1.12
$/AUD average rate for the period 0.65 0.64 0.67 0.64 0.66
$/AUD period-end rate 0.66 0.65 0.69 0.66 0.69
Top of page 31
Legal proceedings
For a full discussion of the group's material legal proceedings, see pages
218-219 of bp Annual Report and Form 20-F 2024.
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,
adjusting for 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-employment 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 27 for the
group.
Adjusted operating expenditure is a non-IFRS measure and a subset of
production and manufacturing expenses plus distribution and administration
expenses. It represents the majority of the remaining expenses in these line
items but excludes certain costs that are variable, primarily with volumes
(such as freight costs). Other variable costs are included in purchases in the
income statement. Management believes that adjusted operating expenditure is a
performance measure that provides investors with useful information regarding
the company's financial performance because it considers these expenses to be
the principal operating and overhead expenses that are most directly under
their control although they also include certain adjusting items*, foreign
exchange and commodity price effects. The nearest IFRS measures are production
and manufacturing expenses and distributions and administration expenses. A
reconciliation of production and manufacturing expenses plus distribution and
administration expenses to adjusted operating expenditure is provided on page
28.
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 related provisions and charges, restructuring,
integration and rationalization costs, fair value accounting effects and costs
relating to the Gulf of America 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 25.
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.
Consolidation adjustment - UPII is unrealized profit in inventory arising on
inter-segment transactions.
Divestment proceeds are disposal proceeds as per the condensed group cash flow
statement.
downstream is the customers & products segment.
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.
Top of page 32
Glossary (continued)
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 contracts 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 are classified as equity instruments were
recorded in the balance sheet at their issuance date at their USD equivalent
issued value. Under IFRS these equity instruments are not remeasured from
period to period, and do not qualify for application of hedge accounting. The
derivative instruments relating to the hybrid bonds, however, are required to
be recorded at fair value with mark to market gains and losses recognized in
the income statement. Therefore, measurement differences in relation to the
recognition of gains and losses occur. The fair value accounting effect, which
is reported in the other businesses & corporate segment, eliminates the
fair value gains and losses of these derivative financial instruments that are
recognized in the income statement. We believe that this gives a better
representation of performance, by more appropriately reflecting the economic
effect of these risk management activities, in each period.
Top of page 33
Glossary (continued)
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.
From the first quarter of 2025 it also includes our Archaea business which
prior to that was reported in the customers & products segment. 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
23.
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 26.
Hydrocarbons - Liquids and natural gas. Natural gas is converted to oil
equivalent at 5.8 billion cubic feet = 1 million barrels.
Inorganic capital expenditure is a subset of capital expenditure 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 24.
Inventory holding gains and losses are non-IFRS adjustments to our IFRS profit
(loss) and represent:
• the difference between the cost of sales calculated using the
replacement cost of inventory and the cost of sales calculated on the first-in
first-out (FIFO) method after adjusting for any changes in provisions where
the net realizable value of the inventory is lower than its cost. Under the
FIFO method, which we use for IFRS reporting 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
• an adjustment relating to certain trading inventories that are
not price risk managed which relate to a minimum inventory volume that is
required to be held to maintain underlying business activities. This
adjustment represents the movement in fair value of the inventories due to
prices, on a grade by grade basis, during the period. This is calculated from
each operation's inventory management system on a monthly basis using the
discrete monthly movement in market prices for these inventories.
The amounts disclosed are not separately reflected in the financial statements
as a gain or loss. No adjustment is made in respect of the cost of inventories
held as part of a trading position and certain other temporary inventory
positions that are price risk-managed. See Replacement cost (RC) profit or
loss definition below.
Liquids - Liquids comprises crude oil, condensate and natural gas liquids. For
the oil production & operations segment, it also includes bitumen.
Top of page 34
Glossary (continued)
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 24.
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 mechanical, process and regulatory
downtime.
Refining indicator margin (RIM) is a simple indicator of the weighted average
of bp's crude slate and product yield as deemed representative for each
refinery. Actual margins realized by bp may vary due to a variety of factors,
including the actual mix of a crude and product for a given quarter.
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.
Structural cost reduction is calculated as decreases in underlying operating
expenditure* (as defined on page 35) as a result of operational efficiencies,
divestments, workforce reductions and other cost saving measures that are
expected to be sustainable compared with 2023 levels. The total change between
periods in underlying operating expenditure will reflect both structural cost
reductions and other changes in spend, including market factors, such as
inflation and foreign exchange impacts, as well as changes in activity levels
and costs associated with new operations. Estimates of cumulative annual
structural cost reduction may be revised depending on whether cost reductions
realized in prior periods are determined to be sustainable compared with 2023
levels. Structural cost reductions are stewarded internally to support
management's oversight of spending over time.
bp believes this performance measure is useful in demonstrating how management
drives cost discipline across the entire organization, simplifying our
processes and portfolio and streamlining the way we work. The nearest IFRS
measures are production and manufacturing expenses and distributions and
administration expenses. A reconciliation of production and manufacturing
expenses plus distribution and administration expenses to underlying operating
expenditure is provided on page 28.
Top of page 35
Glossary (continued)
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 represents a more up to date reflection of the safety environment.
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 operating expenditure is a non-IFRS measure and a subset of
production and manufacturing expenses plus distribution and administration
expenses and excludes costs that are classified as adjusting items. It
represents the majority of the remaining expenses in these line items but
excludes certain costs that are variable, primarily with volumes (such as
freight costs). Other variable costs are included in purchases in the income
statement. Management believes that underlying operating expenditure is a
performance measure that provides investors with useful information regarding
the company's financial performance because it considers these expenses to be
the principal operating and overhead expenses that are most directly under
their control although they also include certain foreign exchange and
commodity price effects. The nearest IFRS measures are production and
manufacturing expenses and distribution and administration expenses. A
reconciliation of production and manufacturing expenses plus distribution and
administration expenses to underlying operating expenditure is provided on
page 28.
Underlying production - 2025 underlying production, when compared with 2024,
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 25
for additional information on the adjusting items that are used to arrive at
underlying RC profit or loss in order to enable a full understanding of the
items and their financial impact.
Underlying RC profit or loss before interest and tax for the operating
segments or customers & products businesses is calculated as RC profit or
loss (as defined above) including profit or loss attributable to
non-controlling interests before interest and tax for the operating segments
and excluding net adjusting items for the respective operating segment or
business.
bp believes that underlying RC profit or loss is a useful measure for
investors because it is a measure closely tracked by management to evaluate
bp's operating performance and to make financial, strategic and operating
decisions and because it may help investors to understand and evaluate, in the
same manner as management, the underlying trends in bp's operational
performance on a comparable basis, period on period, by adjusting for the
effects of these adjusting items. The nearest equivalent measure on an IFRS
basis for the group is profit or loss attributable to bp shareholders. The
nearest equivalent measure on an IFRS basis for segments and businesses is RC
profit or loss before interest and taxation. A reconciliation to IFRS
information is provided on page 1 for the group and pages 6-12 for the
segments.
Top of page 36
Glossary (continued)
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 ordinary
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 ordinary 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 America weather related
downtime.
upstream unit production costs are 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, ampm, bp pulse, Castrol, PETRO, TA, 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 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', 'focus on' 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 production and volumes;
expectations regarding turnaround and maintenance activity; plans and
expectations regarding bp's balance sheet, financial performance, results of
operations, cost reduction, cash flows, and shareholder returns; plans and
expectations regarding the amount and timing of dividends, share buybacks, and
dividend reinvestment programs; plans and expectations regarding bp's upstream
production; plans and expectations regarding the amount, timing, quantum and
nature of certain acquisitions, divestments and related payments and proceeds,
including expectations regarding bp Wind Energy, Lightsource bp and other bp
businesses and assets subject to disposal or divestment; plans and
expectations regarding bp's net debt, credit rating, investment strategy,
capital expenditures, capital frame, underlying effective tax rate, and
depreciation, depletion and amortization; expectations regarding bp's
customers business, including with respect to earnings growth, fuels margins
and the impact of structural cost reduction; expectations regarding bp's
products, including underlying performance and refinery turnaround activity;
expectations regarding bp's other businesses & corporate underlying annual
charge; expectations regarding Gulf of America settlement payments; plans and
expectations regarding the Tiber-Guadalupe project as well as bp's projects in
the Mediterranean Sea, the Bumerangue block, the UK's North Sea, and Aker BP's
project in the Yggdrasil area; plans and expectations regarding bp's
partnerships and other collaborations and agreements with BOTAS, Iraq's North
Oil Company and North Gas Company and others; expectations regarding bp's tax
liabilities and obligations; and expectations regarding the pending legal
proceedings involving bp.
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. Recent global
developments have caused significant uncertainty and volatility in
macroeconomic conditions and commodity markets. Each item of outlook and
guidance set out in this announcement is based on bp's current expectations
but actual outcomes and results may be impacted by these evolving
macroeconomic and market conditions.
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, 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
including ongoing approvals required for the continued developments of
approved projects; 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 America 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 governmental
authorities or any other relevant persons may impact bp's ability to sell its
interests in Rosneft, or the price for which bp 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 2025 as filed with the US
Securities and Exchange Commission (the "SEC") as well as "Risk factors" in
bp's Annual Report and Form 20-F for fiscal year 2024 as filed with the SEC.
Cautionary note to U.S. investors - This document contains references to
non-proved reserves and production outlooks based on non-proved reserves that
the SEC's rules prohibit us from including in our filings with the SEC. U.S.
investors are urged to consider closely the disclosures in our Form 20-F, SEC
File No. 1-06262. This form is available on our website at www.bp.com. You can
also obtain this form from the SEC's website at www.sec.gov.
Top of page 38
Contacts
London Houston
Press Office Rita Brown Paul Takahashi
+44 (0) 7787 685821 +1 713 903 9729
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
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