BPAQF 6-K
Bp PLC (BP)
6-K
2025-11-04
For: 2025-11-04
View Original
Added on
April 08, 2026
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 6-K
Report of Foreign Issuer
Pursuant to Rule 13a-16 or 15d-16 of
the Securities Exchange Act of 1934
04
November, 2025
BP p.l.c.
(Translation
of registrant's name into English)
1 ST JAMES'S SQUARE, LONDON, SW1Y 4PD, ENGLAND
(Address
of principal executive offices)
Indicate
by check mark whether the registrant files or will file
annual
reports
under cover Form 20-F or Form 40-F.
Form
20-F |X| Form 40-F
---------------
----------------
Indicate
by check mark whether the registrant by furnishing the
information
contained
in this Form is also thereby furnishing the information to
the
Commission
pursuant to Rule 12g3-2(b) under the Securities Exchange Act
of
1934.
Yes No
|X|
---------------
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Exhibit
1.1
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3Q25
SEA Part 1 of 1 dated 04 November 2025
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Exhibit 1.1
Top of page 1
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FOR IMMEDIATE RELEASE
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London 4 November 2025
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 |
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BP p.l.c. Group results
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Third quarter and nine months 2025
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“For
a printer friendly version of this announcement please click on the
link below to open a PDF version of the
announcement”
http://www.rns-pdf.londonstockexchange.com/rns/0057G_1-2025-11-3.pdf
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Strong operations and strategic progress
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Financial summary
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Third
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Second
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Third
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Nine
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Nine
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quarter
|
quarter
|
quarter
|
|
months
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months
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$ million
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|
2025
|
2025
|
2024
|
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2025
|
2024
|
|
Profit (loss) for the period attributable to bp
shareholders
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|
1,161
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1,629
|
206
|
|
3,477
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2,340
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Inventory holding (gains) losses*, net of tax
|
|
62
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407
|
906
|
|
351
|
362
|
|
Replacement cost (RC) profit (loss)*
|
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1,223
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2,036
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1,112
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3,828
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2,702
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Net (favourable) adverse impact of adjusting items*, net of
tax
|
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987
|
317
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1,155
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2,116
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5,044
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Underlying RC profit*
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2,210
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2,353
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2,267
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5,944
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7,746
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Operating cash flow*
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7,786
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6,271
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6,761
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16,891
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19,870
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Capital expenditure*
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(3,381)
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(3,361)
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(4,542)
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(10,365)
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(12,511)
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Divestment and other proceeds(a)
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|
28
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1,356
|
290
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1,712
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1,463
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Net issue (repurchase) of shares
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(750)
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(1,063)
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(2,001)
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(3,660)
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(5,502)
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Net debt*(b)
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26,054
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26,043
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24,268
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26,054
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24,268
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Adjusted
EBITDA*
|
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9,981
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9,972
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9,654
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28,654
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29,599
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Underlying
operating expenditure*
|
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5,487
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5,457
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5,590
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16,248
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16,542
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Announced dividend per ordinary share (cents per
share)
|
|
8.320
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8.320
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8.000
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24.640
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23.270
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Underlying RC profit per ordinary share* (cents)
|
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14.24
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15.03
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13.89
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37.98
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46.79
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Underlying RC profit per ADS* (dollars)
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0.85
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0.90
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0.83
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2.28
|
2.81
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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.
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"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."
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Murray Auchincloss
Chief executive officer
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(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.
Top of
page 2
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Highlights
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3Q25 underlying replacement cost (RC) profit* $2.2
billion
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●
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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.
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●
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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).
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Segment results
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●
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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.
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●
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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.
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●
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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.
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Operating cash flow* $7.8 billion and net debt* $26.1
billion
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●
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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.
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Financial frame
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●
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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).
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●
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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.
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●
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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.
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●
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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.
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(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.
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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.
Top of
page 4
Analysis of RC profit (loss) before interest and tax and
reconciliation to profit (loss) for the period
|
|
|
Third
|
Second
|
Third
|
|
Nine
|
Nine
|
|
|
|
quarter
|
quarter
|
quarter
|
|
months
|
months
|
|
$ million
|
|
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
post-employment benefits
|
|
(1,212)
|
(1,173)
|
(1,059)
|
|
(3,654)
|
(3,269)
|
|
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 to
pensions and other post-employment benefits
|
|
(1,129)
|
(1,095)
|
(1,001)
|
|
(3,306)
|
(2,914)
|
|
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.
Top of
page 5
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 benefits
|
|
(55)
|
(56)
|
(42)
|
|
(163)
|
(123)
|
|
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
gain or loss on sale of businesses and fixed assets
|
|
22
|
—
|
—
|
|
22
|
—
|
|
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 or
asset
|
|
(447)
|
(214)
|
(51)
|
|
(330)
|
(357)
|
|
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 2)
|
|
1,334
|
1,105
|
|
|
|
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
off
|
|
4,655
|
4,723
|
4,427
|
|
13,614
|
13,008
|
|
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 contributions and benefit payments for unfunded
plans
|
|
(96)
|
(36)
|
(52)
|
|
(143)
|
(118)
|
|
Net
charge for provisions, less payments
|
|
(60)
|
666
|
(48)
|
|
1,710
|
33
|
|
Movements
in inventories and other current and non-current assets and
liabilities
|
|
494
|
(2,030)
|
1,798
|
|
(6,605)
|
1,223
|
|
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
interest)
|
|
(2)
|
—
|
—
|
|
(2)
|
—
|
|
Receipts
relating to transactions involving non-controlling interests (Other
interest)
|
|
8
|
965
|
(7)
|
|
973
|
517
|
|
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 benefits
|
|
(55)
|
(56)
|
(42)
|
|
(163)
|
(123)
|
|
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
earnings per share
|
|
15,735,029
|
15,854,588
|
16,709,108
|
|
15,968,108
|
16,980,519
|
|
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 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.
Top of
page 26
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 operations
|
|
(1,082)
|
(1,030)
|
(98)
|
|
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 liabilities as per condensed group cash flow
statement(a)
|
|
494
|
(2,030)
|
1,798
|
|
(6,605)
|
1,223
|
|
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
gains (losses), fair value accounting effects and other adjusting
items
|
|
911
|
(1,384)
|
1,386
|
|
(3,823)
|
(471)
|
(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 benefits
|
|
(55)
|
(56)
|
(42)
|
|
(163)
|
(123)
|
|
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 bonds
|
|
13
|
(740)
|
(494)
|
|
(1,096)
|
(272)
|
|
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 &
products
|
|
1,716
|
1,533
|
381
|
|
3,926
|
2,819
|
|
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.
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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.
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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
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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
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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
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Contacts
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Investor Relations
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BP p.l.c.’s LEI Code 213800LH1BZH3D16G760
SIGNATURES
Pursuant
to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
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BP
p.l.c.
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(Registrant)
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Dated: 04
November 2025
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/s/ Ben
J. S. Mathews
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Ben J.
S. Mathews
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Company
Secretary
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