Bp PLC 6-K, filed Aug 5, 2025
Bp PLC (BP)
6-K
2025-08-05
For: 2025-08-05
View Original
Added on
April 08, 2026
About this 6-K
Bp PLC filed this 6-K on August 5, 2025.
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
05
August, 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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2Q25
SEA Part 1 of 1 dated 05 August 2025
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Exhibit 1.1
Top of page 1
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FOR IMMEDIATE RELEASE
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London 5 August 2025
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BP p.l.c. Group results
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Second quarter and first half 2025(a)
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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"
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Delivering our plan
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Financial summary
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Second
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First
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Second
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First
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First
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quarter
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quarter
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quarter
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half
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half
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$ million
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2025
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2025
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2024
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2025
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2024
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Profit (loss) for the period attributable to bp
shareholders
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1,629
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687
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(129)
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2,316
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2,134
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Inventory holding (gains) losses*, net of tax
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407
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(118)
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113
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289
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(544)
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Replacement cost (RC) profit (loss)*
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2,036
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569
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(16)
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2,605
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1,590
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Net (favourable) adverse impact of adjusting items*, net of
tax
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317
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812
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2,772
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1,129
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3,889
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Underlying RC profit*
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2,353
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1,381
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2,756
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3,734
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5,479
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Operating cash flow*
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6,271
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2,834
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8,100
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9,105
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13,109
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Capital expenditure*
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(3,361)
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(3,623)
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(3,691)
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(6,984)
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(7,969)
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Divestment and other proceeds(b)
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1,356
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328
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760
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1,684
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1,173
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Net issue (repurchase) of shares
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(1,063)
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(1,847)
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(1,751)
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(2,910)
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(3,501)
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Net debt*(c)
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26,043
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26,968
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22,614
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26,043
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22,614
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Adjusted
EBITDA*
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9,972
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8,701
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9,639
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18,673
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19,945
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Underlying
operating expenditure*
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5,457
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5,304
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5,441
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10,761
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10,952
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Announced dividend per ordinary share (cents per
share)
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8.320
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8.000
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8.000
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16.320
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15.270
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Underlying RC profit per ordinary share* (cents)
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15.03
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8.75
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16.61
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23.76
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32.86
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Underlying RC profit per ADS* (dollars)
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0.90
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0.53
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1.00
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1.43
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1.97
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Highlights
●
Strong operational performance: 2Q25 underlying RC profit $2.4bn;
2Q25 operating cash flow $6.3bn; 2Q25 refining availability* 96.4%;
2Q25 plant reliability* 96.8%
●
Enhancing our portfolio and progressing
divestments: 5 major project* start-ups and 10
exploration discoveries year-to-date; agreement to sell Netherlands
integrated mobility business and US onshore wind business; JERA Nex
bp JV formation complete
●
Delivering structural cost reductions: $0.9bn 1H25 structural cost
reductions*; $1.7bn now delivered against 2023
baseline.
●
Growing resilient dividend: 2Q25 dividend per ordinary share
of 8.32 cents; in addition, announced $750 million share buyback
for 2Q25
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This has been another strong quarter for bp operationally and
strategically. We are delivering on our plan to grow the upstream
and focus the downstream with reliability across both at >96%.
So far this year we've brought five new oil and gas major projects
onstream, sanctioned four more and made ten exploration
discoveries, including the significant discovery in Bumerangue
block in Brazil. Underlying earnings in our customers business are
up around 50% compared to a year ago and trading has delivered well
quarter-on-quarter during challenging conditions. Expected proceeds
from completed or announced divestments have reached around $3
billion for the year and we have now delivered around $1.7 billion
of structural cost reductions since the start of our programme. We
have announced a dividend per ordinary share of 8.32 cents, an
increase of 4%, and a further $750 million share buyback for the
second quarter. We remain fully focused on delivering safely and
reliably, investing with discipline and driving performance
improvement - all in service of growing cash flow, returns and
long-term shareholder value.
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Murray Auchincloss
Chief executive officer
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(a)
This results announcement also represents bp's half-yearly
financial report (see page 14).
(b)
Divestment proceeds are disposal proceeds as per the condensed
group cash flow statement. See page 3 for more information on other
proceeds.
(c)
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 35.
Top of page 2
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We are two quarters into a twelve-quarter plan and are
laser-focused on delivery of our four key targets - and while we
should be encouraged by our early progress, we know there's much
more to do. In advance of chair elect, Albert Manifold joining the
board on 1 September, he and I have been in discussions and have
agreed that we will conduct a thorough review of our portfolio of
businesses to ensure we are maximizing shareholder value moving
forward - allocating capital effectively. We are also initiating a
further cost review and, whilst we will not compromise on safety,
we are doing this with a view to being best in class in our
industry. We reaffirm our commitment to ensure that there is an
embedded process of continuous business improvement across our
operations. This is all in service of accelerating the delivery of
our strategy. bp can and will do better for its
investors.
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Murray Auchincloss Chief executive
officer
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Highlights
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2Q25 underlying replacement cost (RC) profit* $2.4
billion
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●
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Underlying RC profit for the quarter was $2.4 billion, compared
with $1.4 billion for the previous quarter. Compared with the first
quarter 2025, the underlying result reflects an average gas
marketing and trading result, stronger realized refining margins,
stronger customers result, a strong oil trading result, partly
offset by lower liquids and gas realizations and significantly
higher level of refinery turnaround activity. The underlying
effective tax rate (ETR)* in the quarter was 36%, compared with 50%
for the previous quarter, which reflects changes in the
geographical mix of profits.
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●
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Reported profit for the quarter was $1.6 billion, compared
with $0.7 billion for the first quarter 2025. The reported result
for the second quarter is adjusted for inventory holding losses* of
$0.6 billion (pre-tax) and a net adverse impact of adjusting items*
of $0.7 billion (pre-tax) to derive the underlying RC profit.
Adjusting items include pre-tax net impairments of
$1.1 billion and favourable fair value accounting effects* of
$0.6 billion. See page 28 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 second quarter 2025 was $1.0 billion, compared with
$1.4 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 second quarter was
$1.5 billion, compared with $1.0 billion in the first
quarter 2025. The second quarter underlying result before interest
and tax reflects an average gas marketing and trading result
compared with a weak result in the first quarter, and higher
volumes, partly offset by lower realizations and a higher
depreciation, depletion and amortization charge.
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●
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Oil production & operations: The RC profit before interest and
tax for the second quarter 2025 was $1.9 billion, compared
with $2.8 billion for the previous quarter. After adjusting RC
profit before interest and tax for a net adverse impact of
adjusting items of $0.3 billion, the underlying RC profit
before interest and tax for the second quarter was
$2.3 billion, compared with $2.9 billion in the first
quarter 2025. The second quarter underlying result before interest
and tax reflects lower realizations and a higher depreciation,
depletion and amortization charge partly offset by higher
production.
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●
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Customers & products: The RC profit before interest and tax for
the second quarter 2025 was $1.0 billion, compared with $0.1
billion for the previous quarter. After adjusting RC profit before
interest and tax for a net adverse impact of adjusting items of
$0.6 billion, the underlying RC profit before interest and tax
(underlying result) for the second quarter was $1.5 billion,
compared with $0.7 billion in the first quarter 2025. The customers
second quarter underlying result was higher by $0.4 billion,
reflecting seasonally higher volumes and stronger fuels margins.
The products second quarter underlying result was higher by $0.5
billion, reflecting stronger realized refining margins and a strong
oil trading contribution, partly offset by a significantly higher
level of refinery turnaround activity.
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Operating cash flow $6.3 billion and net debt $26.0
billion
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●
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Operating cash flow of $6.3 billion, which includes the $1.1
billion settlement payment for the Gulf of America (see page 29),
was around $3.4 billion higher than the previous quarter,
reflecting higher earnings and lower working capital* build. Net
debt reduced to $26.0 billion in the second quarter as cash inflows
from higher operating cash flow and divestment and other proceeds
exceeded cash outflows during the period.
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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 second quarter, bp has announced a dividend per ordinary
share of 8.32 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 second
quarter results, bp intends to execute a $0.75 billion share
buyback prior to reporting the third quarter results. The $0.75
billion share buyback programme announced with the first quarter
results was completed on 1 August 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.
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The commentary above contains forward-looking statements and should
be read in conjunction with the cautionary statement on page
41.
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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 second quarter and half year was $1.6 billion and
$2.3 billion respectively, compared with a loss of
$0.1 billion and a profit of $2.1 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 second quarter and half year
was $2.4 billion and $3.7 billion respectively, compared
with $2.8 billion and $5.5 billion for the same periods of 2024. The
underlying RC profit for the second quarter compared with the same
period in 2024 mainly reflects lower liquids realizations, offset
by a stronger customers result and oil trading contribution. The
gas marketing and trading result was average. The underlying RC
profit for the half year compared with the same period in 2024
mainly reflects lower refining margins, lower liquids realizations
and a lower gas marketing and trading result, partly offset by the
absence of the Whiting refinery outage and a stronger customers
result. Underlying operating expenditure* for the half year,
compared with the same period in 2024, was slightly lower, with
structural cost reductions* offset by growth and
inflation.
-
Adjusting items in the second quarter and half year had a net
adverse pre-tax impact of $0.7 billion and $1.1 billion
respectively, compared with a net adverse pre-tax impact of
$3.1 billion and $4.3 billion in the same periods of
2024.
-
Adjusting items for the second quarter and half year include a
favourable pre-tax impact of fair value accounting effects*,
relative to management's internal measure of performance, of $0.6
billion and $1.5 billion respectively, compared with an adverse
pre-tax impact of $1.0 billion and $1.2 billion in the
same periods of 2024. This is primarily due to little movement in
the LNG forward price in the second quarter 2025 compared with an
increase in the second quarter 2024 and a decline in the price in
the first half of 2025 compared to an increase in the comparative
period of 2024. In addition there has been a favourable impact of
the fair value accounting effects relating to the hybrid bonds in
the 2025 periods compared to adverse impacts in the 2024
comparative periods.
- Adjusting
items for the second quarter and half year of 2025 include an
adverse pre-tax impact of asset impairments of $1.1 billion and
$1.6 billion respectively, compared with an adverse pre-tax impact
of $1.3 billion and $1.9 billion in the same periods of
2024.
●
The effective tax rate (ETR) on RC profit or loss* for the second
quarter and half year was 32% and 50% respectively, compared with
87% and 63% for the same periods in 2024. Excluding adjusting
items, the underlying ETR* for the second quarter and half year was
36% and 43%, compared with 33% and 38% for the same periods in
2024. The higher underlying ETR for the second quarter and half
year reflects the absence of the impact of the reassessment of the
recognition of deferred tax assets. The higher underlying ETR for
the half year also 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 second quarter and half year was
$6.3 billion and $9.1 billion respectively, compared with
$8.1 billion and $13.1 billion for the same periods in
2024. The reduction in operating cash flow reflects the differing
impact of working capital* movements (after adjusting for
inventory holding gains or losses, fair value accounting effects
and other adjusting items) for both periods and the lower
underlying replacement cost profit in the first half 2025 compared
with 2024.
● Capital expenditure* in
the second quarter and half year was $3.4 billion and
$7.0 billion, compared with $3.7 billion and
$8.0 billion in the same periods of 2024
reflecting the lower capital frame in place for
2025.
●
Total divestment and other proceeds for the second quarter and half
year were $1.4 billion and $1.7 billion respectively,
compared with $0.8 billion and $1.2 billion for the same
periods in 2024. Other proceeds for the second quarter and half
year 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 second quarter and half year 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 second quarter, net debt* was $26.0 billion,
compared with $27.0 billion at the end of the first quarter
2025 and $22.6 billion at the end of the second 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
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
RC profit (loss) before interest and tax
|
|
|
|
|
|
|
|
|
gas
& low carbon energy
|
|
1,047
|
1,358
|
(315)
|
|
2,405
|
721
|
|
oil
production & operations
|
|
1,916
|
2,788
|
3,267
|
|
4,704
|
6,327
|
|
customers
& products
|
|
972
|
103
|
(133)
|
|
1,075
|
855
|
|
other
businesses & corporate
|
|
645
|
(22)
|
(180)
|
|
623
|
(480)
|
|
Consolidation
adjustment - UPII*
|
|
30
|
13
|
(73)
|
|
43
|
(41)
|
|
RC profit before interest and tax
|
|
4,610
|
4,240
|
2,566
|
|
8,850
|
7,382
|
|
Finance
costs and net finance expense relating to pensions and other
post-employment benefits
|
|
(1,173)
|
(1,269)
|
(1,176)
|
|
(2,442)
|
(2,210)
|
|
Taxation on a RC basis
|
|
(1,101)
|
(2,107)
|
(1,207)
|
|
(3,208)
|
(3,237)
|
|
Non-controlling interests
|
|
(300)
|
(295)
|
(199)
|
|
(595)
|
(345)
|
|
RC profit (loss) attributable to bp shareholders*
|
|
2,036
|
569
|
(16)
|
|
2,605
|
1,590
|
|
Inventory holding gains (losses)*
|
|
(554)
|
159
|
(136)
|
|
(395)
|
715
|
|
Taxation (charge) credit on inventory holding gains and
losses
|
|
147
|
(41)
|
23
|
|
106
|
(171)
|
|
Profit (loss) for the period attributable to bp
shareholders
|
|
1,629
|
687
|
(129)
|
|
2,316
|
2,134
|
Analysis of underlying RC profit (loss) before interest and
tax
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Underlying RC profit (loss) before interest and tax
|
|
|
|
|
|
|
|
|
gas
& low carbon energy
|
|
1,462
|
997
|
1,402
|
|
2,459
|
3,060
|
|
oil
production & operations
|
|
2,262
|
2,895
|
3,094
|
|
5,157
|
6,219
|
|
customers
& products
|
|
1,533
|
677
|
1,149
|
|
2,210
|
2,438
|
|
other
businesses & corporate
|
|
(38)
|
(117)
|
(158)
|
|
(155)
|
(312)
|
|
Consolidation
adjustment - UPII
|
|
30
|
13
|
(73)
|
|
43
|
(41)
|
|
Underlying RC profit before interest and tax
|
|
5,249
|
4,465
|
5,414
|
|
9,714
|
11,364
|
|
Finance costs on an underlying RC
basis(a) and
net finance expense relating to pensions and other post-employment
benefits
|
|
(1,095)
|
(1,082)
|
(971)
|
|
(2,177)
|
(1,913)
|
|
Taxation on an underlying RC basis
|
|
(1,501)
|
(1,707)
|
(1,488)
|
|
(3,208)
|
(3,627)
|
|
Non-controlling interests
|
|
(300)
|
(295)
|
(199)
|
|
(595)
|
(345)
|
|
Underlying RC profit attributable to bp shareholders*
|
|
2,353
|
1,381
|
2,756
|
|
3,734
|
5,479
|
(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 28).
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 6-13 for the
segments.
Operating Metrics
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Tier 1 and tier 2 process safety events*
|
|
5
|
10
|
7
|
|
15
|
21
|
|
upstream*
production(a) (mboe/d)
|
|
2,300
|
2,239
|
2,379
|
|
2,270
|
2,379
|
|
upstream unit production
costs*(b) ($/boe)
|
|
6.81
|
6.34
|
6.34
|
|
6.58
|
6.17
|
|
bp-operated upstream plant reliability*
|
|
96.8%
|
95.4%
|
96.1%
|
|
96.1%
|
95.5%
|
|
bp-operated refining
availability*(a)
|
|
96.4%
|
96.2%
|
96.4%
|
|
96.3%
|
93.4%
|
(a)
See Operational updates on pages 6, 9 and 11. Because of rounding,
upstream production may not agree exactly with the sum of gas &
low carbon energy and oil production &
operations.
(b)
The increase in the first half 2025, compared with the first half
2024 mainly reflects portfolio mix.
Top of page 5
Outlook & Guidance
3Q 2025 guidance
●
Looking ahead, bp expects third quarter 2025 reported upstream*
production to be slightly lower compared with the second quarter
2025.
●
In its customers business, bp expects seasonally higher volumes
compared to the second quarter and fuels margins to remain
sensitive to movements in the cost of supply.
●
In products, bp expects, compared to the second quarter, a
significantly lower level of planned refinery turnaround activity,
partly offset by seasonal effects of environmental compliance
costs.
●
bp expects income taxes paid in the third quarter to be around $1
billion higher than the second quarter 2025 mainly due to the
timing of instalment payments, which are typically higher in the
third quarter each year.
●
On 4 August bp elected to redeem $1.2 billion of its perpetual
hybrid bonds, representing the remaining amount callable from June
2025. The hybrid bonds will be redeemed on 1 September 2025 using
proceeds from bp's November 2024 hybrid bond issuance.
2025 guidance
In
addition to the guidance on page 2:
●
bp continues to expect reported upstream* production to be lower
and underlying upstream production* to be slightly lower compared
with 2024. Within this, bp expects underlying production from oil
production & operations to be broadly flat 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 $0.5-1.0 billion for 2025, subject to foreign
exchange impacts. The charge may vary from quarter to
quarter.
●
bp now expects 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 continues to expect divestment and other proceeds to be around
$3-4 billion in 2025, with the remaining proceeds weighted to the
fourth quarter 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.
New refining rule of thumb
bp has retired the refining marker margin* (RMM) and replaced it
with the bp refining indicator margin* (RIM), and updated the
associated refining rule of thumb (RoT). The bp RIM RoT reflects
the sensitivity of the group's 2025 underlying replacement cost
profit before interest and tax* to changes in bp's RIM at normal
operating conditions, and will not fully explain all quarter on
quarter movements in Products.
The bp RIM reflects a broader set of crudes and products, and is
more representative of bp's refining portfolio and realized
refining margin per barrel. As a result, we believe this weekly
disclosure will enhance the understanding of our realized margin
delivery and refining profitability. For further information, see
Supplementary information refining indicator margin
(bp.com/supplementaryinformationRIM).
|
Refining RoT for +/- $1/bbl change
|
|
Impact on 2025 underlying RC profit before interest and
tax
|
|
bp RIM (new)
|
|
$550m
|
|
bp RMM (retired)
|
|
$400m
|
As a consequence of this change, the refining price assumptions
applicable to bp's CMU Cash Flow and ROACE Targets* have been
updated by replacing the RMM price assumption with a RIM price
assumption. The updated price assumptions are: at $70/bbl Brent,
$4/mmBtu Henry Hub and $10.3/bbl refining indicator margin, all
2024 real. There is no change to the CMU Cash Flow and ROACE
Targets or to the prices used for impairment testing as a
consequence of this update. Price assumptions are not intended to
reflect management's forecasts for future prices.
|
The commentary above contains forward-looking statements and should
be read in conjunction with the cautionary statement on page
41.
|
Top of page 6
gas & low carbon energy*
Financial results
● The
replacement cost (RC) profit before interest and tax for the second
quarter and half year was $1,047 million and $2,405 million
respectively, compared with a loss of $315 million and a profit of
$721 million for the same periods in 2024. The second quarter and
half year are adjusted by an adverse impact of net adjusting items*
of $415 million and $54 million respectively, compared with an
adverse impact of net adjusting items of $1,717 million and $2,339
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 $18
million and $686 million for the second quarter and half year in
2025 and an adverse impact of $1,011 million and $898
million for
the same periods in 2024. See page 28 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
second quarter and half year was $1,462 million and $2,459 million
respectively, compared with $1,402 million and $3,060 million for
the same periods in 2024.
●
The underlying RC profit before interest and tax for the second
quarter compared with the same period in 2024, reflects
higher-margin production offset by a higher depreciation, depletion
and amortization charge and the divestments in Trinidad and Egypt
in the fourth quarter of 2024. The gas marketing and trading result
was average.
●
The underlying RC profit for the half year, compared with the same
period in 2024, reflects a lower gas marketing and trading result,
the divestments in Trinidad and Egypt in the fourth quarter of
2024, and a higher depreciation, depletion and amortization charge,
partly offset by higher-margin production and the absence of the
foreign exchange loss in Egypt and exploration write-offs in the
first half of 2024. Underlying operating expenditure for the half
year, compared with the same period in 2024, was higher, with
structural cost reductions more than offset by growth and
inflation.
Operational update
●
Reported production for the quarter was 782mboe/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
2.1% lower due to base decline, partly offset by major project
startups.
●
Reported production for the half year was 773mboe/d, 14.8% lower
than the same period in 2024. Underlying production was 4.1% lower,
mainly due to base decline partly offset by major project
startups.
Strategic progress gas
●
In May bp announced the Mento development in Trinidad & Tobago
has safely delivered its first gas. Mento is a 50:50 joint venture
between EOG Resources Trinidad Ltd (EOG) and bp, with EOG as the
operator.
●
In May and June, bp signed sale and purchase agreements (SPA) for
liquefied natural gas (LNG) with: Zhejiang, under which bp has
agreed to supply of 1 million mt/year of LNG to Zhejiang Energy for
a duration of 10 years; approximately 0.7 million mt/year of LNG to
A2A from 2027 to 2044.
●
In May bp made the final investment decision (FID) to invest in an
infill wells programme at the offshore KG D6 gas block located
offshore India.
●
In June Gás Natural Açu (GNA) II, the largest gas fired
power plant in Brazil has started commercial operations of its 1.7
gigawatts capacity plant. bp is the exclusive LNG supplier for GNA
II and holds a 33.5% stake in the project alongside Siemens Energy
(33.5%) and SPIC Brazil (33%).
●
In June bp and its partners, announced the final investment
decision (FID) for the new Shah Deniz Compression project, the next
stage of development of the giant Shah Deniz gas field in the
Azerbaijan sector of the Caspian Sea (bp operator
29.99%).
●
In June bp, State Oil Company of the Azerbaijan Republic (SOCAR)
and TPAO signed agreements enabling TPAO to join the
production-sharing agreement* (PSA) for the Shafag-Asiman offshore
block in the Azerbaijan sector of the Caspian Sea. The agreement
provides for the drilling of a well into the Lower Surakhany
reservoir and the extension of the term of the PSA. The deal is
expected to be completed by the end of the third quarter of
2025.
●
In June Shafag (Jabrayil) Solar Ltd, bp's joint venture with SOCAR
Green and the Azerbaijan Business Development Fund, announced FID
on the 240MWAC Shafag
solar plant in the Jabrayil district of Azerbaijan. In parallel the
investors in the Sangachal terminal sanctioned the linked Sangachal
terminal electrificaton project.
●
In July bp and Libya's National Oil Corporation (NOC) signed a
memorandum of understanding to explore redevelopment of the mature
giant Sarir and Messla oilfields in Libya's Sirte basin and assess
the wider unconventional potential within the country.
●
These events build on the progress announced in our first-quarter
results, which comprised the following:
bp
announced: the Raven Infills project in the West Nile Delta (WND)
had started production ahead of schedule (bp 82.75% operator,
Harbour Energy 17.25%); the successful completion of the "El
Fayoum-5" gas discovery well in the North Alexandria Offshore
Concession in WND; it has agreed for Apollo-managed funds to
purchase a 25% non-controlling stake in bp Pipelines TANAP Limited,
the bp subsidiary that holds a 12% share in the TANAP pipeline, for
consideration of approximately $1.0 billion; it achieved two major
milestones in Trinidad & Tobago, sanctioning the Ginger gas
development and exploration success at its Frangipani well; its
Cypre development (located in Trinidad & Tobago) safely
delivered its first gas; and it safely loaded the first cargo of
LNG for export from its GTA Phase 1 project offshore Mauritania and
Senegal.
Top of page 7
gas
& low carbon energy (continued)
low carbon energy
●
In August bp and JERA Co., Inc. completed formation of a new joint
venture (JV) called JERA Nex bp. The JV will aim to become one of
the largest global offshore wind developers and operators (total
13GW potential net generating capacity).
●
In June bp completed the sale of 100% of its interest in a parcel
of land located at Astoria, in the City and State of New York, to
the Power Authority of the State of New York.
●
In July bp and EnBW were granted development consent for the 1.5GW
Mona offshore wind project in the Irish Sea from the UK Secretary
of State for Energy Security and Net Zero. Mona is one of three
proposed offshore wind projects in the UK, alongside Morgan and
Morven. Following deal completion, the projects will move to JERA
Nex bp - bp's 50:50 offshore wind joint venture with
JERA.
●
In July bp announced that it has agreed to sell its US onshore wind
business, BP Wind Energy North America Inc., to LS Power, a leading
development, investment and operating company focused on the North
American power and energy infrastructure sector. Subject to
regulatory approvals the deal is expected to complete by the end of
2025.
●
In July bp informed its partners in the Australian Renewable Energy
Hub in the Pilbara region of Western Australia that it intends to
exit the project as operator and equity holder. bp will work with
its partners to ensure a safe and efficient transition of
operatorship.
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Profit (loss) before interest and tax
|
|
1,047
|
1,358
|
(315)
|
|
2,405
|
721
|
|
Inventory holding (gains) losses*
|
|
-
|
-
|
-
|
|
-
|
-
|
|
RC profit (loss) before interest and tax
|
|
1,047
|
1,358
|
(315)
|
|
2,405
|
721
|
|
Net (favourable) adverse impact of adjusting items
|
|
415
|
(361)
|
1,717
|
|
54
|
2,339
|
|
Underlying RC profit before interest and tax
|
|
1,462
|
997
|
1,402
|
|
2,459
|
3,060
|
|
Taxation on an underlying RC basis
|
|
(509)
|
(471)
|
(369)
|
|
(980)
|
(887)
|
|
Underlying RC profit before interest
|
|
953
|
526
|
1,033
|
|
1,479
|
2,173
|
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
Total depreciation, depletion and amortization
|
|
1,407
|
1,166
|
1,209
|
|
2,573
|
2,502
|
|
|
|
|
|
|
|
|
|
|
Exploration write-offs
|
|
|
|
|
|
|
|
|
Exploration write-offs
|
|
1
|
-
|
28
|
|
1
|
231
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA*
|
|
|
|
|
|
|
|
|
Total adjusted EBITDA
|
|
2,870
|
2,163
|
2,639
|
|
5,033
|
5,793
|
|
|
|
|
|
|
|
|
|
|
Capital expenditure*
|
|
|
|
|
|
|
|
|
gas(a)
|
|
688
|
774
|
1,016
|
|
1,462
|
1,770
|
|
low carbon energy
|
|
102
|
129
|
136
|
|
231
|
795
|
|
Total capital expenditure(a)
|
|
790
|
903
|
1,152
|
|
1,693
|
2,565
|
(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 8
gas & low carbon energy (continued)
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Production (net of
royalties)(b)
|
|
|
|
|
|
|
|
|
Liquids* (mb/d)
|
|
85
|
83
|
98
|
|
84
|
100
|
|
Natural gas (mmcf/d)
|
|
4,043
|
3,950
|
4,648
|
|
3,997
|
4,678
|
|
Total hydrocarbons* (mboe/d)
|
|
782
|
764
|
899
|
|
773
|
907
|
|
|
|
|
|
|
|
|
|
|
Average realizations*(c)
|
|
|
|
|
|
|
|
|
Liquids ($/bbl)
|
|
64.15
|
70.74
|
79.92
|
|
67.21
|
78.38
|
|
Natural gas ($/mcf)
|
|
6.50
|
7.26
|
5.47
|
|
6.86
|
5.46
|
|
Total hydrocarbons ($/boe)
|
|
40.84
|
45.38
|
36.85
|
|
43.00
|
36.75
|
(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 9
oil production & operations
Financial results
●
The replacement cost (RC) profit before interest and tax for the
second quarter and half year was $1,916 million and $4,704 million
respectively, compared with $3,267 million and $6,327 million for
the same periods in 2024. The second quarter and half year are
adjusted by an adverse impact of net adjusting items* of $346
million and $453 million respectively, compared with a favourable
impact of net adjusting items of $173 million and $108 million for
the same periods in 2024. See page 28 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
second quarter and half year was $2,262 million and $5,157 million
respectively, compared with $3,094 million and $6,219 million for
the same periods in 2024.
●
The underlying RC profit before interest and tax for the second
quarter and half year, compared with the same periods in 2024,
primarily reflects lower realizations and a higher depreciation,
depletion and amortization charge, partially offset by higher
production. Underlying operating expenditure* for the half year,
compared with the same period in 2024, was broadly flat, with
structural cost reductions offset by growth and
inflation.
Operational update
●
Reported production for the quarter was 1,518mboe/d, 2.5% higher
than the same period in 2024. Underlying production* for the
quarter was 0.8% higher reflecting higher production in bpx, partly
offset by planned maintenance.
●
Reported production for the half year was 1,497mboe/d, 1.7% higher
than the same period in 2024. Underlying production was 1.1% higher
reflecting improved base performance partly offset by planned
maintenance.
Strategic progress
●
In June bp announced it had signed fully termed agreements with the
State Oil Company of the Azerbaijan Republic (SOCAR) to acquire 35%
participating interests and become the operator of two exploration
and development blocks in the Caspian Sea - the Karabagh oil field
and the Ashrafi-Dan Ulduzu-Aypara (ADUA) area.
●
In July, Azule Energy, bp's 50% joint venture (Azule), and operator
of Block 15/06 in Angola, together with its partners, announced the
successful start-up of the Agogo Integrated West Hub Project, which
aims to fully develop the Agogo and Ndungu fields in Block
15/06.
●
In July Azule, operator of Block 1/14, and its partners announced a
gas discovery at the Gajajeira-01 exploration well, located
offshore in the Lower Congo Basin, Angola. The well was spudded on
1 April 2025 in a water depth of 95 metres, approximately 60
kilometres off the coast. Initial assessments suggest gas volumes
in place could exceed 1 trillion cubic feet, with up to 100 million
barrels of associated condensate.
●
In June bpx Energy started up the Crossroads facility in the
Permian Basin, bpx's fourth and final central delivery facility to
be built, following the earlier Grand Slam, Checkmate and Bingo
facilities.
●
In July bpx Energy took over operations from Devon Energy of
certain assets in the Eagle Ford Shale following the dissolution of
their joint venture in the Blackhawk Field.
●
In June bp took the final investment decision on the Atlantis Major
Facility Expansion Project, which is expected to increase water
injection capacity. First water injection is targeted for
2027.
● In August bp
announced an exploration discovery at the Bumerangue prospect in
the deepwater offshore Brazil. bp drilled exploration well
1-BP-13-SPS at the Bumerangue block, located in the Santos Basin,
404 kilometres (218 nautical miles) from Rio de Janeiro, in a water
depth of 2,372 metres. The well was drilled to a total depth of
5,855 metres. The well intersected the reservoir about 500
metres below the crest of the structure and penetrated an estimated
500 metre gross hydrocarbon column, in high-quality pre-salt
carbonate reservoir with an areal extent of greater than
300km2.
Results from the rig-site analysis indicate elevated levels of
carbon dioxide. bp will now begin laboratory analysis to further
characterize the reservoir and fluids discovered, which will
provide additional insight into the potential of the Bumerangue
block. bp holds a 100% participation in the block with Pré-Sal
Petróleo S.A. as the Production Sharing Contract manager. bp
secured the block in December 2022 during the 1st Cycle of the Open
Acreage of Production Sharing of the Brazilian national petroleum
agency (ANP).
●
In August bp announced the start-up of the Argos Southwest
Extension project in the Gulf of America. The project consists of
three wells and a new drill centre tied back to the Argos platform
and is expected to add 20,000 barrels of oil equivalent per day of
gross peak annualized average production. bp is operator of Argos
with 60.5% working interest, with co-owners Woodside Energy (23.9%)
and Union Oil Company of California, an affiliate of Chevron U.S.A.
Inc. (15.6%).
●
These events build on the progress announced in our first-quarter
results, which comprised the following: bp received final
government ratification for its contract to invest in the
redevelopment of several giant oil fields in Kirkuk, in the north
of Iraq; bp announced a Miocene oil discovery at the Far South
prospect in the US Gulf of America (bp 57.5% operator); in January
the initial producer well from West Chirag, Azerbaijan, in the
deeper non-associated gas reservoirs encountered hydrocarbons;
Azule Energy, in collaboration with its New Gas Consortium (NGC)
partners, completed installation of the jacket and deck of the
Quiluma offshore platform, a key step in Angola's first
non-associated gas development; and in April, Rhino Resources
(42.5%) along with co-venturers Azule Energy (42.5%), Namcor (10%),
and Korres Investments (5%) announced the successful drilling of
the Capricornus 1-X exploration well in block PEL-85 in the Orange
basin, Namibia.
Top
of page 10
oil production & operations (continued)
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Profit before interest and tax
|
|
1,914
|
2,795
|
3,268
|
|
4,709
|
6,327
|
|
Inventory holding (gains) losses*
|
|
2
|
(7)
|
(1)
|
|
(5)
|
-
|
|
RC profit before interest and tax
|
|
1,916
|
2,788
|
3,267
|
|
4,704
|
6,327
|
|
Net (favourable) adverse impact of adjusting items
|
|
346
|
107
|
(173)
|
|
453
|
(108)
|
|
Underlying RC profit before interest and tax
|
|
2,262
|
2,895
|
3,094
|
|
5,157
|
6,219
|
|
Taxation on an underlying RC basis
|
|
(1,062)
|
(1,375)
|
(1,171)
|
|
(2,437)
|
(2,680)
|
|
Underlying RC profit before interest
|
|
1,200
|
1,520
|
1,923
|
|
2,720
|
3,539
|
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
Total depreciation, depletion and amortization
|
|
1,933
|
1,787
|
1,698
|
|
3,720
|
3,355
|
|
|
|
|
|
|
|
|
|
|
Exploration write-offs
|
|
|
|
|
|
|
|
|
Exploration write-offs
|
|
81
|
53
|
99
|
|
134
|
102
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA*
|
|
|
|
|
|
|
|
|
Total adjusted EBITDA
|
|
4,276
|
4,735
|
4,891
|
|
9,011
|
9,676
|
|
|
|
|
|
|
|
|
|
|
Capital expenditure*
|
|
|
|
|
|
|
|
|
Total capital expenditure
|
|
1,706
|
1,696
|
1,534
|
|
3,402
|
3,310
|
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Production (net of
royalties)(a)
|
|
|
|
|
|
|
|
|
Liquids* (mb/d)
|
|
1,115
|
1,086
|
1,085
|
|
1,101
|
1,071
|
|
Natural gas (mmcf/d)
|
|
2,338
|
2,258
|
2,292
|
|
2,298
|
2,328
|
|
Total hydrocarbons* (mboe/d)
|
|
1,518
|
1,475
|
1,481
|
|
1,497
|
1,472
|
|
|
|
|
|
|
|
|
|
|
Average realizations*(b)
|
|
|
|
|
|
|
|
|
Liquids ($/bbl)
|
|
59.74
|
67.50
|
73.01
|
|
63.54
|
71.79
|
|
Natural gas ($/mcf)
|
|
3.66
|
4.74
|
2.02
|
|
4.18
|
2.35
|
|
Total hydrocarbons ($/boe)
|
|
49.03
|
56.45
|
55.78
|
|
52.66
|
54.94
|
(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 11
customers & products
Financial results
●
The replacement cost (RC) profit before interest and tax for the
second quarter and half year was $972 million and $1,075
million respectively, compared with a loss of $133 million and a
profit of $855 million for the same periods in 2024. The second
quarter and half year are adjusted by an adverse impact of net
adjusting items* of $561 million and $1,135 million respectively,
compared with an adverse impact of net adjusting items of $1,282
million and $1,583 million for the same periods in 2024. See page
28 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 second quarter and half year was $1,533
million and $2,210 million respectively, compared with $1,149
million and $2,438 million for the same periods in
2024.
●
The customers & products underlying result for the second
quarter was higher than the same period in 2024, primarily
reflecting a stronger customers result and oil trading
contribution, partly offset by a lower refining performance. The
result for the half year was lower than the same period in 2024,
primarily reflecting a lower refining performance, partly offset by
a higher customers result and lower underlying operating
expenditure* across customers and products as we build momentum in
our structural cost reduction programme.
● customers -
the customers underlying result for the second quarter and half
year was higher compared with the same periods in 2024. The
underlying result benefited from stronger integrated performance
across fuels and midstream, with Castrol's earnings in the first
half of 2025 more than 20% higher compared to the same period last
year, driven by higher volumes and margins. The first half also
benefited from lower underlying operating
expenditure.
● products -
the products underlying result for the second quarter was higher
compared with the same period in 2024, mainly due to a strong oil
trading contribution. In refining, the second quarter was impacted
by significantly higher turnaround activity and lower realized
margins reflecting narrower North American heavy crude oil
differentials, partly offset by stronger operations and commercial
delivery. The products result for the first half was lower compared
with the same period in 2024, primarily reflecting significantly
lower realized refining margins and higher turnaround activity,
partly offset by the absence of the first quarter 2024 plant-wide
power outage at the Whiting refinery and lower underlying operating
expenditure.
Operational update
● bp-operated
refining availability* for the second quarter and half year was
96.4% and 96.3%, compared with 96.4% and 93.4% for the same periods
in 2024. The half year was higher reflecting strong performance and
notably the absence of the Whiting refinery power
outage.
Strategic progress
●
In July, bp announced the sale of its Netherlands mobility &
convenience and bp pulse businesses to Catom BV. The sale is
expected to complete by the end of 2025 subject to regulatory
approvals.
● During the
second quarter, bp opened three EV fast charging Gigahubs near
airports in Los Angeles, Boston and San Francisco, and signed a
strategic agreement with Waffle House, in the US, to expand
ultrafast(a) EV
charging network at its locations.
●
These events build on the progress announced in our first-quarter
results, which comprised the following:
◦
bp announced a strategic review of its Castrol business with the
intention of accelerating Castrol's next phase of value
delivery.
◦
bp announced plans to sell its mobility and convenience business in
Austria. bp is targeting to close the divestment by the end of
2025.
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Profit (loss) before interest and tax
|
|
420
|
255
|
(270)
|
|
675
|
1,570
|
|
Inventory holding (gains) losses*
|
|
552
|
(152)
|
137
|
|
400
|
(715)
|
|
RC profit (loss) before interest and tax
|
|
972
|
103
|
(133)
|
|
1,075
|
855
|
|
Net (favourable) adverse impact of adjusting items
|
|
561
|
574
|
1,282
|
|
1,135
|
1,583
|
|
Underlying RC profit before interest and tax
|
|
1,533
|
677
|
1,149
|
|
2,210
|
2,438
|
|
Of which:(b)
|
|
|
|
|
|
|
|
|
customers
- convenience & mobility
|
|
1,056
|
664
|
790
|
|
1,720
|
1,160
|
|
Castrol - included in customers
|
|
245
|
238
|
211
|
|
483
|
395
|
|
products
- refining & trading
|
|
477
|
13
|
359
|
|
490
|
1,278
|
|
Taxation on an underlying RC basis
|
|
(251)
|
(76)
|
(125)
|
|
(327)
|
(458)
|
|
Underlying RC profit before interest
|
|
1,282
|
601
|
1,024
|
|
1,883
|
1,980
|
(a)
'ultra-fast' includes charger capacity of
≥150kW.
(b)
A reconciliation to RC profit before interest and tax by business
is provided on page 32.
Top of page 12
customers & products (continued)
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Adjusted EBITDA*(C)
|
|
|
|
|
|
|
|
|
customers - convenience & mobility
|
|
1,698
|
1,231
|
1,281
|
|
2,929
|
2,135
|
|
Castrol - included in customers
|
|
295
|
284
|
253
|
|
579
|
479
|
|
products - refining & trading
|
|
895
|
431
|
807
|
|
1,326
|
2,186
|
|
|
|
2,593
|
1,662
|
2,088
|
|
4,255
|
4,321
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
Total depreciation, depletion and amortization
|
|
1,060
|
985
|
939
|
|
2,045
|
1,883
|
|
|
|
|
|
|
|
|
|
|
Capital expenditure*
|
|
|
|
|
|
|
|
|
customers - convenience & mobility
|
|
387
|
585
|
497
|
|
972
|
1,063
|
|
Castrol - included in customers
|
|
36
|
37
|
74
|
|
73
|
117
|
|
products - refining & trading(d)
|
|
410
|
358
|
401
|
|
768
|
840
|
|
Total capital expenditure(d)
|
|
797
|
943
|
898
|
|
1,740
|
1,903
|
(c)
A reconciliation to RC profit before interest and tax by business
is provided on page 32.
(d)
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.
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
Marketing sales of refined products (mb/d)
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
US
|
|
1,248
|
1,201
|
1,271
|
|
1,225
|
1,177
|
|
Europe
|
|
1,006
|
946
|
1,077
|
|
976
|
1,008
|
|
Rest of World
|
|
466
|
466
|
462
|
|
466
|
465
|
|
|
|
2,720
|
2,613
|
2,810
|
|
2,667
|
2,650
|
|
Trading/supply sales of refined products
|
|
478
|
441
|
387
|
|
460
|
370
|
|
Total sales volume of refined products
|
|
3,198
|
3,054
|
3,197
|
|
3,127
|
3,020
|
|
bp average refining
marker margin* (RMM) ($/bbl)
|
|
21.1
|
15.2
|
20.6
|
|
18.2
|
20.6
|
|
bp average refining
indicator margin* (RIM) ($/bbl)
|
|
11.9
|
8.1
|
11.8
|
|
10.0
|
13.6
|
|
Refinery throughputs (mb/d)
|
|
|
|
|
|
|
|
|
US
|
|
573
|
674
|
670
|
|
623
|
598
|
|
Europe
|
|
715
|
822
|
722
|
|
768
|
775
|
|
Total refinery throughputs
|
|
1,288
|
1,496
|
1,392
|
|
1,391
|
1,373
|
|
|
|
|
|
|
|
|
|
|
bp-operated refining availability* (%)
|
|
96.4
|
96.2
|
96.4
|
|
96.3
|
93.4
|
Top of page 13
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) profit before interest and tax for the
second quarter and half year was $645 million and $623
million respectively,
compared with a loss of $180 million and $480 million for the same
periods in 2024. The second quarter and half year are adjusted by a
favourable impact of net adjusting items* of $683 million and $778
million respectively, compared with an adverse impact of net
adjusting items of $22 million and $168 million for the same
periods in 2024. Adjusting items include favourable impacts of fair
value accounting effects* of $740 million for the quarter and
$1,109 million for the half year in 2025, and an
adverse impact of $29 million and $222 million for the same periods
in 2024. See page 28 for more information on adjusting
items.
●
After adjusting RC profit before interest and tax for adjusting
items, the underlying RC loss before interest and tax* for the
second quarter and half year was $38 million and $155 million
respectively, compared with a loss of $158 million and $312 million
for the same periods in 2024.
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Profit (loss) before interest and tax
|
|
645
|
(22)
|
(180)
|
|
623
|
(480)
|
|
Inventory holding (gains) losses*
|
|
-
|
-
|
-
|
|
-
|
-
|
|
RC profit (loss) before interest and tax
|
|
645
|
(22)
|
(180)
|
|
623
|
(480)
|
|
Net (favourable) adverse impact of adjusting
items(a)
|
|
(683)
|
(95)
|
22
|
|
(778)
|
168
|
|
Underlying RC profit (loss) before interest and tax
|
|
(38)
|
(117)
|
(158)
|
|
(155)
|
(312)
|
|
Taxation on an underlying RC basis
|
|
109
|
33
|
3
|
|
142
|
102
|
|
Underlying RC profit (loss) before interest
|
|
71
|
(84)
|
(155)
|
|
(13)
|
(210)
|
(a)
Includes fair value accounting effects relating to hybrid bonds.
See page 36 for more information.
Top of page 14
This results announcement also represents bp's half-yearly
financial report for the purposes of the Disclosure Guidance and
Transparency Rules made by the UK Financial Conduct Authority. In
this context: (i) the condensed set of financial statements can be
found on pages 16-26; (ii) pages 1-13, and 27-41 comprise the
interim management report; and (iii) the directors' responsibility
statement and auditors' independent review report can be found on
pages 14-15.
Statement of directors' responsibilities
The directors confirm that, to the best of their knowledge, the
condensed set of financial statements on pages 16-26 has been
prepared in accordance with United Kingdom adopted IAS 34 'Interim
Financial Reporting', and that the interim management report on
pages 1-13, and 27-41 includes a fair review of the information
required by the Disclosure Guidance and Transparency
Rules.
The directors of BP p.l.c. are listed on pages 72-73
of bp
Annual Report and Form 20-F 2024, with the following exceptions: Pamela Daley
stepped down as a non-executive director with effect from 7 July
2025, Ian Tyler was appointed as a non-executive director with
effect from 1 April 2025 and David Hager was appointed as a
non-executive director with effect from 2 June
2025.
By order of the board
|
Murray Auchincloss
|
Kate Thomson
|
|
Chief Executive Officer
|
Chief Financial Officer
|
|
4 August 2025
|
4 August 2025
|
Top of page 15
Independent review report to BP p.l.c.
Conclusion
We have been engaged by the company to review the condensed set of
financial statements in the half-yearly financial report for the
six months ended 30 June 2025 which comprises the group income
statement, the condensed group statement of comprehensive income,
the group balance sheet, the condensed group statement of changes
in equity, the condensed group cash flow statement and related
notes 1 to 10.
Based on our review, nothing has come to our attention that causes
us to believe that the condensed set of financial statements in the
half-yearly financial report for the six months ended 30 June 2025
is not prepared, in all material respects, in accordance with
United Kingdom adopted International Accounting Standard 34 and the
Disclosure Guidance and Transparency Rules of the United Kingdom's
Financial Conduct Authority.
Basis for Conclusion
We conducted our review in accordance with International Standard
on Review Engagements (UK) 2410 'Review of Interim Financial
Information Performed by the Independent Auditor of the Entity'
issued by the Financial Reporting Council for use in the United
Kingdom (ISRE (UK) 2410). A review of interim financial information
consists of making inquiries, primarily of persons responsible for
financial and accounting matters, and applying analytical and other
review procedures. A review is substantially less in scope than an
audit conducted in accordance with International Standards on
Auditing (UK) and consequently does not enable us to obtain
assurance that we would become aware of all significant matters
that might be identified in an audit. Accordingly, we do not
express an audit opinion.
As disclosed in note 1, the annual financial statements of the
group are prepared in accordance with IFRS Accounting Standards
(IFRS) as issued by the International Accounting Standards Board
(IASB), IFRS as adopted by the UK, and European Union (EU), and in
accordance with the provisions of the UK Companies Act 2006 as
applicable to companies reporting under international accounting
standards. The condensed set of financial statements included in
this half-yearly financial report has been prepared in accordance
with United Kingdom adopted International Accounting Standard 34,
'Interim Financial Reporting'.
Conclusion Relating to Going Concern
Based on our review procedures, which are less extensive than those
performed in an audit as described in the Basis for Conclusion
section of this report, nothing has come to our attention to
suggest that the directors have inappropriately adopted the going
concern basis of accounting or that the directors have identified
material uncertainties relating to going concern that are not
appropriately disclosed.
This Conclusion is based on the review procedures performed in
accordance with ISRE (UK) 2410; however future events or conditions
may cause the entity to cease to continue as a going
concern.
Responsibilities of the directors
The directors are responsible for preparing the half-yearly
financial report in accordance with the Disclosure Guidance and
Transparency Rules of the United Kingdom's Financial Conduct
Authority.
In preparing the half-yearly financial report, the directors are
responsible for assessing the group's ability to continue as a
going concern, disclosing as applicable, matters related to going
concern and using the going concern basis of accounting unless the
directors either intend to liquidate the company or to cease
operations, or have no realistic alternative but to do
so.
Auditor's Responsibilities for the review of the financial
information
In reviewing the half-yearly financial report, we are responsible
for expressing to the company a conclusion on the condensed set of
financial statements in the half-yearly financial report. Our
Conclusion, including our Conclusion Relating to Going Concern, are
based on procedures that are less extensive than audit procedures,
as described in the Basis for Conclusion paragraph of this
report.
Use of our report
This report is made solely to the company in accordance with ISRE
(UK) 2410. Our work has been undertaken so that we might state to
the company those matters we are required to state to it in an
independent review report and for no other purpose. To the fullest
extent permitted by law, we do not accept or assume responsibility
to anyone other than the company, for our review work, for this
report, or for the conclusions we have formed.
Deloitte LLP
Statutory Auditor
London, United Kingdom
4 August 2025
The maintenance and integrity of the BP p.l.c. website are the
responsibility of the directors; the review work carried out by the
statutory auditors does not involve consideration of these matters
and, accordingly, the statutory auditors accept no responsibility
for any changes that may have occurred to the financial information
since it was initially presented on the website.
Legislation in the United Kingdom governing the preparation and
dissemination of financial statements may differ from legislation
in other jurisdictions.
Top of page 16
Financial statements
Group income statement
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues (Note 5)
|
|
46,627
|
46,905
|
47,299
|
|
93,532
|
96,179
|
|
Earnings from joint ventures - after interest and
tax
|
|
241
|
327
|
250
|
|
568
|
428
|
|
Earnings from associates - after interest and
tax
|
|
155
|
249
|
266
|
|
404
|
564
|
|
Interest and other income
|
|
375
|
385
|
414
|
|
760
|
795
|
|
Gains on sale of businesses and fixed assets
|
|
279
|
14
|
21
|
|
293
|
245
|
|
Total revenues and other income
|
|
47,677
|
47,880
|
48,250
|
|
95,557
|
98,211
|
|
Purchases
|
|
26,875
|
27,720
|
28,891
|
|
54,595
|
56,538
|
|
Production and manufacturing expenses
|
|
6,153
|
6,114
|
6,692
|
|
12,267
|
13,539
|
|
Production and similar taxes
|
|
414
|
447
|
484
|
|
861
|
928
|
|
Depreciation, depletion and amortization (Note 6)
|
|
4,641
|
4,183
|
4,098
|
|
8,824
|
8,248
|
|
Net impairment and losses on sale of businesses and fixed assets
(Note 3)
|
|
1,157
|
503
|
1,309
|
|
1,660
|
2,046
|
|
Exploration expense
|
|
139
|
103
|
179
|
|
242
|
426
|
|
Distribution and administration expenses
|
|
4,242
|
4,411
|
4,167
|
|
8,653
|
8,389
|
|
Profit (loss) before interest and taxation
|
|
4,056
|
4,399
|
2,430
|
|
8,455
|
8,097
|
|
Finance costs
|
|
1,229
|
1,321
|
1,216
|
|
2,550
|
2,291
|
|
Net
finance (income) expense relating to pensions and other
post-employment benefits
|
|
(56)
|
(52)
|
(40)
|
|
(108)
|
(81)
|
|
Profit (loss) before taxation
|
|
2,883
|
3,130
|
1,254
|
|
6,013
|
5,887
|
|
Taxation
|
|
954
|
2,148
|
1,184
|
|
3,102
|
3,408
|
|
Profit (loss) for the period
|
|
1,929
|
982
|
70
|
|
2,911
|
2,479
|
|
Attributable to
|
|
|
|
|
|
|
|
|
bp
shareholders
|
|
1,629
|
687
|
(129)
|
|
2,316
|
2,134
|
|
Non-controlling
interests
|
|
300
|
295
|
199
|
|
595
|
345
|
|
|
|
1,929
|
982
|
70
|
|
2,911
|
2,479
|
|
|
|
|
|
|
|
|
|
|
Earnings per share (Note 7)
|
|
|
|
|
|
|
|
|
Profit (loss) for the period attributable to bp
shareholders
|
|
|
|
|
|
|
|
|
Per
ordinary share (cents)
|
|
|
|
|
|
|
|
|
Basic
|
|
10.41
|
4.35
|
(0.78)
|
|
14.73
|
12.85
|
|
Diluted
|
|
10.27
|
4.27
|
(0.78)
|
|
14.44
|
12.54
|
|
Per
ADS (dollars)
|
|
|
|
|
|
|
|
|
Basic
|
|
0.62
|
0.26
|
(0.05)
|
|
0.88
|
0.77
|
|
Diluted
|
|
0.62
|
0.26
|
(0.05)
|
|
0.87
|
0.75
|
Top of page 17
Condensed group statement of comprehensive income
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
|
|
|
|
|
|
|
|
|
Profit (loss) for the period
|
|
1,929
|
982
|
70
|
|
2,911
|
2,479
|
|
Other comprehensive income
|
|
|
|
|
|
|
|
|
Items that may be reclassified subsequently to profit or
loss
|
|
|
|
|
|
|
|
|
Currency translation
differences(a)
|
|
1,323
|
819
|
(142)
|
|
2,142
|
(590)
|
|
Cash
flow hedges and costs of hedging
|
|
235
|
(185)
|
(100)
|
|
50
|
(215)
|
|
Share
of items relating to equity-accounted entities, net of
tax
|
|
3
|
1
|
10
|
|
4
|
2
|
|
Income
tax relating to items that may be reclassified
|
|
(57)
|
42
|
40
|
|
(15)
|
36
|
|
|
|
1,504
|
677
|
(192)
|
|
2,181
|
(767)
|
|
Items that will not be reclassified to profit or loss
|
|
|
|
|
|
|
|
|
Remeasurements
of the net pension and other post-employment benefit liability or
asset
|
|
(214)
|
331
|
(240)
|
|
117
|
(306)
|
|
Remeasurements
of equity investments
|
|
2
|
(1)
|
(17)
|
|
1
|
(30)
|
|
Cash
flow hedges that will subsequently be transferred to the balance
sheet
|
|
2
|
2
|
-
|
|
4
|
(3)
|
|
Income tax relating to items that will not be
reclassified(b)
|
|
52
|
(95)
|
59
|
|
(43)
|
733
|
|
|
|
(158)
|
237
|
(198)
|
|
79
|
394
|
|
Other comprehensive income
|
|
1,346
|
914
|
(390)
|
|
2,260
|
(373)
|
|
Total comprehensive income
|
|
3,275
|
1,896
|
(320)
|
|
5,171
|
2,106
|
|
Attributable to
|
|
|
|
|
|
|
|
|
bp
shareholders
|
|
2,883
|
1,556
|
(520)
|
|
4,439
|
1,783
|
|
Non-controlling
interests
|
|
392
|
340
|
200
|
|
732
|
323
|
|
|
|
3,275
|
1,896
|
(320)
|
|
5,171
|
2,106
|
(a)
Second and first quarter and first half 2025 are principally
affected by movements in the Pound Sterling against the US
dollar.
(b)
First half 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 18
Condensed group statement of changes in equity
|
|
|
bp shareholders'
|
Non-controlling interests
|
Total
|
|
|
$ million
|
|
equity
|
Hybrid bonds(a)
|
Other interest
|
equity
|
|
At 1 January 2025
|
|
59,246
|
16,649
|
2,423
|
78,318
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
4,439
|
402
|
330
|
5,171
|
|
Dividends
|
|
(2,515)
|
-
|
(219)
|
(2,734)
|
|
Cash
flow hedges transferred to the balance sheet, net of
tax
|
|
(4)
|
-
|
-
|
(4)
|
|
Repurchase of ordinary share capital
|
|
(2,511)
|
-
|
-
|
(2,511)
|
|
Share-based payments, net of tax
|
|
594
|
-
|
-
|
594
|
|
Issue of perpetual hybrid bonds(b)
|
|
-
|
500
|
-
|
500
|
|
Payments on perpetual hybrid bonds
|
|
(9)
|
(511)
|
-
|
(520)
|
|
Transactions involving non-controlling interests,
net of tax(c)
|
|
-
|
-
|
966
|
966
|
|
At 30 June 2025
|
|
59,240
|
17,040
|
3,500
|
79,780
|
|
|
|
|
|
|
|
|
|
|
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
|
|
1,783
|
310
|
13
|
2,106
|
|
Dividends
|
|
(2,431)
|
-
|
(186)
|
(2,617)
|
|
Cash
flow hedges transferred to the balance sheet, net of
tax
|
|
(4)
|
-
|
-
|
(4)
|
|
Repurchase of ordinary share capital
|
|
(3,502)
|
-
|
-
|
(3,502)
|
|
Share-based payments, net of tax
|
|
654
|
-
|
-
|
654
|
|
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
|
|
-
|
(419)
|
-
|
(419)
|
|
Transactions
involving non-controlling interests, net of tax
|
|
236
|
-
|
247
|
483
|
|
At 30 June 2024
|
|
67,024
|
13,457
|
1,718
|
82,199
|
(a)
On 4 August 2025 BP Capital Markets p.l.c. issued notice to
voluntarily redeem $1.2 billion of hybrid bonds effective 1
September 2025. This is expected to reduce non-controlling interest
and increase net debt in the third quarter.
(b)
During the first half 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.
(c)
In the first half 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 19
Group balance sheet
|
|
|
30 June
|
31 December
|
|
$ million
|
|
2025
|
2024
|
|
Non-current assets
|
|
|
|
|
Property, plant and equipment
|
|
100,862
|
100,238
|
|
Goodwill
|
|
15,180
|
14,888
|
|
Intangible assets
|
|
9,271
|
9,646
|
|
Investments in joint ventures
|
|
12,299
|
12,291
|
|
Investments in associates
|
|
7,579
|
7,741
|
|
Other investments
|
|
1,227
|
1,292
|
|
Fixed assets
|
|
146,418
|
146,096
|
|
Loans
|
|
2,371
|
1,961
|
|
Trade and other receivables
|
|
2,712
|
1,815
|
|
Derivative financial instruments
|
|
16,540
|
16,114
|
|
Prepayments
|
|
555
|
548
|
|
Deferred tax assets
|
|
5,936
|
5,403
|
|
Defined benefit pension plan surpluses
|
|
8,132
|
7,457
|
|
|
|
182,664
|
179,394
|
|
Current assets
|
|
|
|
|
Loans
|
|
224
|
223
|
|
Inventories
|
|
24,752
|
23,232
|
|
Trade and other receivables
|
|
27,583
|
27,127
|
|
Derivative financial instruments
|
|
4,959
|
5,112
|
|
Prepayments
|
|
2,875
|
2,594
|
|
Current tax receivable
|
|
966
|
1,096
|
|
Other investments
|
|
245
|
165
|
|
Cash and cash equivalents
|
|
35,067
|
39,204
|
|
|
|
96,671
|
98,753
|
|
Assets classified as held for sale (Note 2)
|
|
5,402
|
4,081
|
|
|
|
102,073
|
102,834
|
|
Total assets
|
|
284,737
|
282,228
|
|
Current liabilities
|
|
|
|
|
Trade and other payables
|
|
57,324
|
58,411
|
|
Derivative financial instruments
|
|
4,093
|
4,347
|
|
Accruals
|
|
5,244
|
6,071
|
|
Lease liabilities
|
|
2,865
|
2,660
|
|
Finance debt
|
|
5,843
|
4,474
|
|
Current tax payable
|
|
2,243
|
1,573
|
|
Provisions
|
|
5,101
|
3,600
|
|
|
|
82,713
|
81,136
|
|
Liabilities directly associated with assets classified as held for
sale (Note 2)
|
|
1,378
|
1,105
|
|
|
|
84,091
|
82,241
|
|
Non-current liabilities
|
|
|
|
|
Other payables
|
|
8,016
|
9,409
|
|
Derivative financial instruments
|
|
15,670
|
18,532
|
|
Accruals
|
|
1,565
|
1,326
|
|
Lease liabilities
|
|
11,771
|
9,340
|
|
Finance debt
|
|
54,503
|
55,073
|
|
Deferred tax liabilities
|
|
8,654
|
8,428
|
|
Provisions
|
|
15,613
|
14,688
|
|
Defined benefit pension plan and other post-employment benefit plan
deficits
|
|
5,074
|
4,873
|
|
|
|
120,866
|
121,669
|
|
Total liabilities
|
|
204,957
|
203,910
|
|
Net assets
|
|
79,780
|
78,318
|
|
Equity
|
|
|
|
|
bp shareholders' equity
|
|
59,240
|
59,246
|
|
Non-controlling interests
|
|
20,540
|
19,072
|
|
Total equity
|
|
79,780
|
78,318
|
Top of page 20
Condensed group cash flow statement
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Operating activities
|
|
|
|
|
|
|
|
|
Profit (loss) before taxation
|
|
2,883
|
3,130
|
1,254
|
|
6,013
|
5,887
|
|
Adjustments
to reconcile profit (loss) before taxation to net cash provided by
operating activities
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization and exploration expenditure written
off
|
|
4,723
|
4,236
|
4,225
|
|
8,959
|
8,581
|
|
Net
impairment and (gain) loss on sale of businesses and fixed
assets
|
|
878
|
489
|
1,288
|
|
1,367
|
1,801
|
|
Earnings
from equity-accounted entities, less dividends
received
|
|
40
|
(200)
|
19
|
|
(160)
|
(77)
|
|
Net
charge for interest and other finance expense, less net interest
paid
|
|
126
|
147
|
524
|
|
273
|
716
|
|
Share-based
payments
|
|
215
|
401
|
507
|
|
616
|
668
|
|
Net
operating charge for pensions and other post-employment benefits,
less contributions and benefit payments for unfunded
plans
|
|
(36)
|
(11)
|
(34)
|
|
(47)
|
(66)
|
|
Net
charge for provisions, less payments
|
|
666
|
1,104
|
764
|
|
1,770
|
81
|
|
Movements
in inventories and other current and non-current assets and
liabilities
|
|
(2,030)
|
(5,069)
|
1,556
|
|
(7,099)
|
(575)
|
|
Income
taxes paid
|
|
(1,194)
|
(1,393)
|
(2,003)
|
|
(2,587)
|
(3,907)
|
|
Net cash provided by operating activities
|
|
6,271
|
2,834
|
8,100
|
|
9,105
|
13,109
|
|
Investing activities
|
|
|
|
|
|
|
|
|
Expenditure on property, plant and equipment, intangible and other
assets
|
|
(3,236)
|
(3,351)
|
(3,463)
|
|
(6,587)
|
(7,181)
|
|
Acquisitions, net of cash acquired
|
|
(39)
|
(202)
|
(116)
|
|
(241)
|
(222)
|
|
Investment in joint ventures
|
|
(59)
|
(58)
|
(95)
|
|
(117)
|
(448)
|
|
Investment in associates
|
|
(27)
|
(12)
|
(17)
|
|
(39)
|
(118)
|
|
Total cash capital expenditure
|
|
(3,361)
|
(3,623)
|
(3,691)
|
|
(6,984)
|
(7,969)
|
|
Proceeds from disposal of fixed assets
|
|
322
|
292
|
35
|
|
614
|
101
|
|
Proceeds from disposal of businesses, net of cash
disposed
|
|
76
|
36
|
219
|
|
112
|
566
|
|
Proceeds from loan repayments
|
|
31
|
31
|
24
|
|
62
|
40
|
|
Cash provided from investing activities
|
|
429
|
359
|
278
|
|
788
|
707
|
|
Net cash used in investing activities
|
|
(2,932)
|
(3,264)
|
(3,413)
|
|
(6,196)
|
(7,262)
|
|
Financing activities
|
|
|
|
|
|
|
|
|
Net issue (repurchase) of shares (Note 7)
|
|
(1,063)
|
(1,847)
|
(1,751)
|
|
(2,910)
|
(3,501)
|
|
Lease liability payments
|
|
(784)
|
(727)
|
(679)
|
|
(1,511)
|
(1,373)
|
|
Proceeds from long-term financing
|
|
1,155
|
54
|
2,736
|
|
1,209
|
4,995
|
|
Repayments of long-term financing
|
|
(848)
|
(1,366)
|
(623)
|
|
(2,214)
|
(1,297)
|
|
Net increase (decrease) in short-term debt
|
|
39
|
(125)
|
49
|
|
(86)
|
65
|
|
Issue of perpetual hybrid bonds
|
|
-
|
500
|
-
|
|
500
|
1,296
|
|
Redemption of perpetual hybrid bonds
|
|
-
|
-
|
-
|
|
-
|
(1,288)
|
|
Payments relating to perpetual hybrid bonds
|
|
(332)
|
(272)
|
(271)
|
|
(604)
|
(527)
|
|
Receipts
relating to transactions involving non-controlling interests (Other
interest)
|
|
965
|
-
|
508
|
|
965
|
524
|
|
Dividends paid - bp shareholders
|
|
(1,238)
|
(1,257)
|
(1,204)
|
|
(2,495)
|
(2,423)
|
|
-
non-controlling interests
|
|
(127)
|
(74)
|
(60)
|
|
(201)
|
(186)
|
|
Net cash provided by (used in) financing activities
|
|
(2,233)
|
(5,114)
|
(1,295)
|
|
(7,347)
|
(3,715)
|
|
Currency translation differences relating to cash and cash
equivalents
|
|
193
|
106
|
(11)
|
|
299
|
(271)
|
|
Increase (decrease) in cash and cash equivalents
|
|
1,299
|
(5,438)
|
3,381
|
|
(4,139)
|
1,861
|
|
Cash and cash equivalents at beginning of period
|
|
33,831
|
39,269
|
31,510
|
|
39,269
|
33,030
|
|
Cash and cash equivalents at end of period(a)
|
|
35,130
|
33,831
|
34,891
|
|
35,130
|
34,891
|
(a)
Second quarter and first half 2025 includes $63 million (first
quarter 2025 $57 million) of cash and cash equivalents classified
as assets held for sale in the group balance sheet.
Top of page 21
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.
The directors consider it appropriate to adopt the going concern
basis of accounting in preparing these interim financial
statements.
bp prepares its consolidated financial statements included within
bp Annual Report and Form 20-F on the basis of IFRS Accounting
Standards® (IFRS) as issued by the International Accounting
Standards Board (IASB), IFRS as adopted by the UK, and European
Union (EU), and in accordance with the provisions of the UK
Companies Act 2006 as applicable to companies reporting under
international accounting standards. IFRS as adopted by the UK does
not differ from IFRS as adopted by the EU. 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 approximately $0.5
billion.
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 is expected to result in a non-cash
deferred tax charge of approximately $300 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 22
Note 2. Non-current assets held for sale
The carrying amount of assets classified as held for sale at
30 June 2025 is $5,402 million, with associated
liabilities of $1,378 million.
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. The carrying amount of assets classified as held for sale
at 30 June 2025 is $569 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 these assets within one year of the
acquisition date is considered to be highly probable. The carrying
amount of assets classified as held for sale at 30 June 2025 is
$1,894 million, with associated liabilities of $1,244
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 have,
therefore, been classified as held for sale as at 30 June 2025. The
carrying amount of assets classified as held for sale at 30 June
2025 is $2,546 million, with associated liabilities of $9
million.
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 June
2025 is $375 million, with associated liabilities of $86
million.
Transactions that were classified as held for sale during 2025, but
completed during the second quarter, are described
below.
On 31 January 2025 bp and Devon Energy agreed to dissolve their
Eagle Ford partnership and divide up the assets. The carrying
amount of assets classified as held for sale at 31 March 2025 was
$593 million, with associated liabilities of $53 million. The
dissolution completed on 1 April 2025.
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 second quarter and half year were
$1,157 million and $1,660 million respectively, compared with
net charges of $1,309 million and $2,046 million for the
same periods in 2024 and include net impairment charges for the
second quarter and half year of $1,130 million and
$1,561 million respectively, compared with net impairment
charges of $1,296 million and
$1,945 million for the same periods in
2024.
Gas & low carbon energy
Second quarter and half year 2025 impairments includes a net
impairment charge of $431 million and $746 million
respectively, compared with net charges of $589 million and
$1,125 million for the same periods in 2024 in the gas &
low carbon energy segment.
Customers & products
Second quarter and half year 2025 impairments includes a net
impairment charge of $373 million and $477 million
respectively, compared with net charges of $681 million and
$691 million for the same periods in 2024 in the customers
& products segment.
Top of page 23
Note 4. Analysis of replacement cost profit (loss) before interest
and tax and reconciliation to profit (loss) before
taxation
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
gas & low carbon energy
|
|
1,047
|
1,358
|
(315)
|
|
2,405
|
721
|
|
oil production & operations
|
|
1,916
|
2,788
|
3,267
|
|
4,704
|
6,327
|
|
customers & products
|
|
972
|
103
|
(133)
|
|
1,075
|
855
|
|
other businesses & corporate
|
|
645
|
(22)
|
(180)
|
|
623
|
(480)
|
|
|
|
4,580
|
4,227
|
2,639
|
|
8,807
|
7,423
|
|
Consolidation adjustment - UPII*
|
|
30
|
13
|
(73)
|
|
43
|
(41)
|
|
RC profit (loss) before interest and tax
|
|
4,610
|
4,240
|
2,566
|
|
8,850
|
7,382
|
|
Inventory holding gains (losses)*
|
|
|
|
|
|
|
|
|
gas
& low carbon energy
|
|
-
|
-
|
-
|
|
-
|
-
|
|
oil
production & operations
|
|
(2)
|
7
|
1
|
|
5
|
-
|
|
customers
& products
|
|
(552)
|
152
|
(137)
|
|
(400)
|
715
|
|
Profit (loss) before interest and tax
|
|
4,056
|
4,399
|
2,430
|
|
8,455
|
8,097
|
|
Finance costs
|
|
1,229
|
1,321
|
1,216
|
|
2,550
|
2,291
|
|
Net
finance expense/(income) relating to pensions and other
post-employment benefits
|
|
(56)
|
(52)
|
(40)
|
|
(108)
|
(81)
|
|
Profit (loss) before taxation
|
|
2,883
|
3,130
|
1,254
|
|
6,013
|
5,887
|
|
|
|
|
|
|
|
|
|
|
RC profit (loss) before interest and tax*
|
|
|
|
|
|
|
|
|
US
|
|
1,417
|
1,533
|
1,545
|
|
2,950
|
3,155
|
|
Non-US
|
|
3,193
|
2,707
|
1,021
|
|
5,900
|
4,227
|
|
|
|
4,610
|
4,240
|
2,566
|
|
8,850
|
7,382
|
Top of page 24
Note 5. Sales and other operating revenues
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
By segment
|
|
|
|
|
|
|
|
|
gas & low carbon energy
|
|
9,172
|
10,778
|
5,809
|
|
19,950
|
14,484
|
|
oil production & operations
|
|
6,053
|
6,502
|
6,659
|
|
12,555
|
13,091
|
|
customers & products
|
|
37,449
|
36,163
|
41,100
|
|
73,612
|
80,995
|
|
other businesses & corporate
|
|
539
|
484
|
526
|
|
1,023
|
1,132
|
|
|
|
53,213
|
53,927
|
54,094
|
|
107,140
|
109,702
|
|
|
|
|
|
|
|
|
|
|
Less: sales and other operating revenues between
segments
|
|
|
|
|
|
|
|
|
gas & low carbon energy
|
|
337
|
731
|
371
|
|
1,068
|
641
|
|
oil production & operations
|
|
5,818
|
5,818
|
5,982
|
|
11,636
|
11,895
|
|
customers & products
|
|
(55)
|
42
|
25
|
|
(13)
|
318
|
|
other businesses & corporate
|
|
486
|
431
|
417
|
|
917
|
669
|
|
|
|
6,586
|
7,022
|
6,795
|
|
13,608
|
13,523
|
|
|
|
|
|
|
|
|
|
|
External sales and other operating revenues
|
|
|
|
|
|
|
|
|
gas & low carbon energy
|
|
8,835
|
10,047
|
5,438
|
|
18,882
|
13,843
|
|
oil production & operations
|
|
235
|
684
|
677
|
|
919
|
1,196
|
|
customers & products
|
|
37,504
|
36,121
|
41,075
|
|
73,625
|
80,677
|
|
other businesses & corporate
|
|
53
|
53
|
109
|
|
106
|
463
|
|
Total sales and other operating revenues
|
|
46,627
|
46,905
|
47,299
|
|
93,532
|
96,179
|
|
|
|
|
|
|
|
|
|
|
By geographical area
|
|
|
|
|
|
|
|
|
US
|
|
18,890
|
19,089
|
20,340
|
|
37,979
|
40,198
|
|
Non-US
|
|
36,233
|
35,701
|
36,832
|
|
71,934
|
76,040
|
|
|
|
55,123
|
54,790
|
57,172
|
|
109,913
|
116,238
|
|
Less: sales and other operating revenues between areas
|
|
8,496
|
7,885
|
9,873
|
|
16,381
|
20,059
|
|
|
|
46,627
|
46,905
|
47,299
|
|
93,532
|
96,179
|
|
|
|
|
|
|
|
|
|
|
Revenues from contracts with customers
|
|
|
|
|
|
|
|
|
Sales and other operating revenues include the following in
relation to revenues from contracts with customers:
|
|
|
|
|
|
|
|
|
Crude oil
|
|
421
|
415
|
538
|
|
836
|
1,086
|
|
Oil products
|
|
28,572
|
27,162
|
32,548
|
|
55,734
|
62,388
|
|
Natural gas, LNG and NGLs
|
|
6,049
|
7,263
|
4,987
|
|
13,312
|
10,738
|
|
Non-oil products and other revenues from contracts with
customers
|
|
3,697
|
3,633
|
3,108
|
|
7,330
|
6,036
|
|
Revenue from contracts with customers
|
|
38,739
|
38,473
|
41,181
|
|
77,212
|
80,248
|
|
Other operating revenues(a)
|
|
7,888
|
8,432
|
6,118
|
|
16,320
|
15,931
|
|
Total sales and other operating revenues
|
|
46,627
|
46,905
|
47,299
|
|
93,532
|
96,179
|
(a)
Principally relates to commodity derivative transactions including
sales of bp own production in trading books.
Top of page 25
Note 6. Depreciation, depletion and amortization
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Total depreciation, depletion and amortization by
segment
|
|
|
|
|
|
|
|
|
gas & low carbon energy
|
|
1,407
|
1,166
|
1,209
|
|
2,573
|
2,502
|
|
oil production & operations
|
|
1,933
|
1,787
|
1,698
|
|
3,720
|
3,355
|
|
customers & products
|
|
1,060
|
985
|
939
|
|
2,045
|
1,883
|
|
other businesses & corporate
|
|
241
|
245
|
252
|
|
486
|
508
|
|
|
|
4,641
|
4,183
|
4,098
|
|
8,824
|
8,248
|
|
Total depreciation, depletion and amortization by geographical
area
|
|
|
|
|
|
|
|
|
US
|
|
1,897
|
1,736
|
1,703
|
|
3,633
|
3,273
|
|
Non-US
|
|
2,744
|
2,447
|
2,395
|
|
5,191
|
4,975
|
|
|
|
4,641
|
4,183
|
4,098
|
|
8,824
|
8,248
|
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. 170 million and 45 million
ordinary shares repurchased were settled during the second quarter
2025 against the authority granted at bp's 2024 and 2025 annual
general meetings respectively, for a total cost of
$1,063 million. All of these shares were held as treasury
shares. A further 98 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 June 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.
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Results for the period
|
|
|
|
|
|
|
|
|
Profit (loss) for the period attributable to bp
shareholders
|
|
1,629
|
687
|
(129)
|
|
2,316
|
2,134
|
|
Less: preference dividend
|
|
1
|
-
|
1
|
|
1
|
1
|
|
Less: (gain) loss on redemption of perpetual hybrid
bonds
|
|
-
|
-
|
-
|
|
-
|
(10)
|
|
Profit (loss) attributable to bp ordinary shareholders
|
|
1,628
|
687
|
(130)
|
|
2,315
|
2,143
|
|
|
|
|
|
|
|
|
|
|
Number of shares (thousand)(a)(b)
|
|
|
|
|
|
|
|
|
Basic
weighted average number of shares outstanding
|
|
15,645,561
|
15,778,296
|
16,590,173
|
|
15,711,554
|
16,670,999
|
|
ADS equivalent(c)
|
|
2,607,593
|
2,629,716
|
2,765,028
|
|
2,618,592
|
2,778,499
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares outstanding used to calculate diluted
earnings per share
|
|
15,854,588
|
16,097,610
|
16,590,173
|
|
16,026,670
|
17,090,967
|
|
ADS equivalent(c)
|
|
2,642,431
|
2,682,935
|
2,765,028
|
|
2,671,111
|
2,848,494
|
|
|
|
|
|
|
|
|
|
|
Shares in issue at period-end
|
|
15,596,112
|
15,785,972
|
16,491,420
|
|
15,596,112
|
16,491,420
|
|
ADS equivalent(c)
|
|
2,599,352
|
2,630,995
|
2,748,570
|
|
2,599,352
|
2,748,570
|
(a)
If the inclusion of potentially issuable shares would decrease loss
per share, the potentially issuable shares are excluded from the
weighted average number of shares outstanding used to calculate
diluted earnings per share. The numbers of potentially issuable
shares that have been excluded from the calculation for the second
quarter 2024 are 374,406 thousand (ADS equivalent 62,401
thousand).
(b)
Excludes treasury shares and includes certain shares that will be
issued in the future under employee share-based payment
plans.
(c)
One ADS is equivalent to six ordinary shares.
Top of page 26
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 September 2025 to ordinary
shareholders and American Depositary Share (ADS) holders on the
register on 15 August 2025. The ex-dividend date will be 14 August
2025 for ordinary shareholders and 15 August 2025 for ADS holders.
The corresponding amount in sterling is due to be announced on 9
September 2025, calculated based on the average of the market
exchange rates over three dealing days between 3 September 2025 and
5 September 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 second 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 second quarter dividend and timetable are
available at bp.com/dividends and
further details of the dividend reinvestment programmes are
available at bp.com/drip.
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Dividends paid per ordinary share
|
|
|
|
|
|
|
|
|
cents
|
|
8.000
|
8.000
|
7.270
|
|
16.000
|
14.540
|
|
pence
|
|
5.899
|
6.176
|
5.683
|
|
12.075
|
11.375
|
|
Dividends paid per ADS (cents)
|
|
48.00
|
48.00
|
43.62
|
|
96.00
|
87.24
|
Note 9. Net debt
|
Net debt*
|
|
30 June
|
31 March
|
30 June
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
Finance debt(a)
|
|
60,346
|
58,646
|
54,986
|
|
Fair value (asset) liability of hedges related to finance
debt(b)
|
|
764
|
2,096
|
2,519
|
|
|
|
61,110
|
60,742
|
57,505
|
|
Less: cash and cash equivalents
|
|
35,067
|
33,774
|
34,891
|
|
Net debt(c)
|
|
26,043
|
26,968
|
22,614
|
|
Total equity
|
|
79,780
|
77,952
|
82,199
|
|
Gearing*
|
|
24.6%
|
25.7%
|
21.6%
|
(a)
The fair value of finance debt at 30 June 2025 was
$57,135 million (31 March 2025 $55,064 million, 30 June 2024
$50,677 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 $96 million at
30 June 2025 (first quarter 2025 liability of
$137 million and second quarter 2024 liability of
$144 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. Statutory accounts
The financial information shown in this publication, which was
approved by the Board of Directors on 4 August 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 27
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.
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Capital expenditure
|
|
|
|
|
|
|
|
|
Organic capital expenditure*
|
|
3,321
|
3,440
|
3,586
|
|
6,761
|
7,565
|
|
Inorganic capital expenditure*
|
|
40
|
183
|
105
|
|
223
|
404
|
|
|
|
3,361
|
3,623
|
3,691
|
|
6,984
|
7,969
|
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Capital expenditure by segment
|
|
|
|
|
|
|
|
|
gas & low carbon energy(a)
|
|
790
|
903
|
1,152
|
|
1,693
|
2,565
|
|
oil production & operations
|
|
1,706
|
1,696
|
1,534
|
|
3,402
|
3,310
|
|
customers & products(a)
|
|
797
|
943
|
898
|
|
1,740
|
1,903
|
|
other businesses & corporate
|
|
68
|
81
|
107
|
|
149
|
191
|
|
|
|
3,361
|
3,623
|
3,691
|
|
6,984
|
7,969
|
|
Capital expenditure by geographical area
|
|
|
|
|
|
|
|
|
US
|
|
1,576
|
1,433
|
1,636
|
|
3,009
|
3,412
|
|
Non-US
|
|
1,785
|
2,190
|
2,055
|
|
3,975
|
4,557
|
|
|
|
3,361
|
3,623
|
3,691
|
|
6,984
|
7,969
|
(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 28
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.
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
gas & low carbon energy
|
|
|
|
|
|
|
|
|
Gains on sale of businesses and fixed assets
|
|
69
|
(1)
|
8
|
|
68
|
10
|
|
Net impairment and losses on sale of businesses and fixed
assets(a)
|
|
(439)
|
(366)
|
(590)
|
|
(805)
|
(1,126)
|
|
Environmental and related provisions
|
|
-
|
-
|
-
|
|
-
|
-
|
|
Restructuring, integration and rationalization costs
|
|
3
|
(14)
|
-
|
|
(11)
|
-
|
|
Fair value accounting effects(b)(c)
|
|
18
|
668
|
(1,011)
|
|
686
|
(898)
|
|
Other
|
|
(66)
|
74
|
(124)
|
|
8
|
(325)
|
|
|
|
(415)
|
361
|
(1,717)
|
|
(54)
|
(2,339)
|
|
oil production & operations
|
|
|
|
|
|
|
|
|
Gains on sale of businesses and fixed assets
|
|
196
|
9
|
7
|
|
205
|
191
|
|
Net impairment and losses on sale of businesses and fixed
assets
|
|
(330)
|
(15)
|
(29)
|
|
(345)
|
(149)
|
|
Environmental and related provisions
|
|
(55)
|
(31)
|
195
|
|
(86)
|
118
|
|
Restructuring, integration and rationalization costs
|
|
(46)
|
(41)
|
-
|
|
(87)
|
-
|
|
Fair value accounting effects
|
|
-
|
-
|
-
|
|
-
|
-
|
|
Other
|
|
(111)
|
(29)
|
-
|
|
(140)
|
(52)
|
|
|
|
(346)
|
(107)
|
173
|
|
(453)
|
108
|
|
customers & products
|
|
|
|
|
|
|
|
|
Gains on sale of businesses and fixed assets
|
|
16
|
3
|
4
|
|
19
|
9
|
|
Net impairment and losses on sale of businesses and fixed
assets(a)
|
|
(389)
|
(114)
|
(678)
|
|
(503)
|
(774)
|
|
Environmental and related provisions
|
|
(1)
|
-
|
7
|
|
(1)
|
7
|
|
Restructuring, integration and rationalization costs
|
|
(86)
|
(91)
|
-
|
|
(177)
|
1
|
|
Fair value accounting effects(c)
|
|
(201)
|
(82)
|
25
|
|
(283)
|
(119)
|
|
Other(d)
|
|
100
|
(290)
|
(640)
|
|
(190)
|
(707)
|
|
|
|
(561)
|
(574)
|
(1,282)
|
|
(1,135)
|
(1,583)
|
|
other businesses & corporate
|
|
|
|
|
|
|
|
|
Gains on sale of businesses and fixed assets
|
|
-
|
-
|
-
|
|
-
|
32
|
|
Net impairment and losses on sale of businesses and fixed
assets
|
|
-
|
(5)
|
(11)
|
|
(5)
|
15
|
|
Environmental and related provisions
|
|
(18)
|
(72)
|
28
|
|
(90)
|
19
|
|
Restructuring, integration and rationalization costs
|
|
(39)
|
(198)
|
1
|
|
(237)
|
12
|
|
Fair value accounting effects(c)
|
|
740
|
369
|
(29)
|
|
1,109
|
(222)
|
|
Gulf of America oil spill
|
|
(9)
|
(9)
|
(8)
|
|
(18)
|
(19)
|
|
Other
|
|
9
|
10
|
(3)
|
|
19
|
(5)
|
|
|
|
683
|
95
|
(22)
|
|
778
|
(168)
|
|
Total before interest and taxation
|
|
(639)
|
(225)
|
(2,848)
|
|
(864)
|
(3,982)
|
|
Finance costs(e)
|
|
(78)
|
(187)
|
(205)
|
|
(265)
|
(297)
|
|
Total before taxation
|
|
(717)
|
(412)
|
(3,053)
|
|
(1,129)
|
(4,279)
|
|
Taxation on adjusting items(f)
|
|
400
|
139
|
585
|
|
539
|
694
|
|
Taxation - tax rate change effect(g)
|
|
-
|
(539)
|
(304)
|
|
(539)
|
(304)
|
|
Total after taxation for period
|
|
(317)
|
(812)
|
(2,772)
|
|
(1,129)
|
(3,889)
|
(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
36.
(d)
Second quarter and first half 2024 include 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 and 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. All periods presented for 2025 include 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)
First quarter 2025 and first half 2025 and second quarter
2024 and first half 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
Top
of page 29
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.
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 June
|
31 March
|
30 June
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
Net debt*
|
|
26,043
|
26,968
|
22,614
|
|
Lease liabilities
|
|
14,636
|
12,484
|
10,697
|
|
Net
partner (receivable) payable for leases entered into on behalf of
joint operations
|
|
(1,030)
|
(91)
|
(112)
|
|
Net debt including leases
|
|
39,649
|
39,361
|
33,199
|
|
Total
equity
|
|
79,780
|
77,952
|
82,199
|
|
Gearing including leases
|
|
33.2%
|
33.6%
|
28.8%
|
Gulf of America oil spill
|
|
|
30 June
|
31 December
|
|
$ million
|
|
2025
|
2024
|
|
Gulf of America oil spill payables and provisions
|
|
(7,100)
|
(7,958)
|
|
Of
which - current
|
|
(1,500)
|
(1,127)
|
|
|
|
|
|
|
Deferred tax asset
|
|
1,086
|
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.
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ 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)
|
|
(2,030)
|
(5,069)
|
1,556
|
|
(7,099)
|
(575)
|
|
Adjusted for inventory holding gains (losses) (Note 4)
|
|
(554)
|
159
|
(136)
|
|
(395)
|
715
|
|
Adjusted for fair value accounting effects relating to
subsidiaries
|
|
554
|
959
|
(1,071)
|
|
1,513
|
(1,345)
|
|
Other adjusting items(b)
|
|
646
|
601
|
182
|
|
1,247
|
(652)
|
|
Working capital release (build) after adjusting for net inventory
gains (losses), fair value accounting effects and other adjusting
items
|
|
(1,384)
|
(3,350)
|
531
|
|
(4,734)
|
(1,857)
|
(a)
The movement in working capital includes outflows relating to the
Gulf of America oil spill on a pre-tax basis of $1,129 million
and $1,131 million in the second quarter and first
half 2025 (first quarter 2025 $2 million, second quarter 2024
$1,129 million, first half 2024
$1,136 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 30
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.
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Profit for the period
|
|
1,929
|
982
|
70
|
|
2,911
|
2,479
|
|
Finance costs
|
|
1,229
|
1,321
|
1,216
|
|
2,550
|
2,291
|
|
Net finance (income) expense relating to pensions and other
post-employment benefits
|
|
(56)
|
(52)
|
(40)
|
|
(108)
|
(81)
|
|
Taxation
|
|
954
|
2,148
|
1,184
|
|
3,102
|
3,408
|
|
Profit before interest and tax
|
|
4,056
|
4,399
|
2,430
|
|
8,455
|
8,097
|
|
Inventory holding (gains) losses*, before tax
|
|
554
|
(159)
|
136
|
|
395
|
(715)
|
|
RC profit before interest and tax
|
|
4,610
|
4,240
|
2,566
|
|
8,850
|
7,382
|
|
Net (favourable) adverse impact of adjusting items*, before
interest and tax
|
|
639
|
225
|
2,848
|
|
864
|
3,982
|
|
Underlying RC profit before interest and tax
|
|
5,249
|
4,465
|
5,414
|
|
9,714
|
11,364
|
|
Add back:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
4,641
|
4,183
|
4,098
|
|
8,824
|
8,248
|
|
Exploration expenditure written off
|
|
82
|
53
|
127
|
|
135
|
333
|
|
Adjusted EBITDA
|
|
9,972
|
8,701
|
9,639
|
|
18,673
|
19,945
|
Top of page 31
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.
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
Year
|
Year
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
2024
|
2023
|
|
From group income statement
|
|
|
|
|
|
|
|
|
|
|
|
Production and manufacturing expenses
|
|
6,153
|
6,114
|
6,692
|
|
12,267
|
13,539
|
|
26,584
|
25,044
|
|
Distribution and administration expenses
|
|
4,242
|
4,411
|
4,167
|
|
8,653
|
8,389
|
|
16,417
|
16,772
|
|
|
|
10,395
|
10,525
|
10,859
|
|
20,920
|
21,928
|
|
43,001
|
41,816
|
|
Less certain variable costs:
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and shipping
costs(a)
|
|
2,634
|
2,446
|
2,199
|
|
5,080
|
5,090
|
|
10,516
|
9,650
|
|
Environmental costs(a)
|
|
1,630
|
1,337
|
1,309
|
|
2,967
|
1,868
|
|
3,987
|
4,271
|
|
Marketing
and distribution costs
|
|
421
|
427
|
501
|
|
848
|
1,132
|
|
1,882
|
2,430
|
|
Commission,
storage and handling costs
|
|
405
|
366
|
391
|
|
771
|
751
|
|
1,519
|
1,633
|
|
Other
variable costs and non-cash costs
|
|
435
|
297
|
445
|
|
732
|
1,041
|
|
1,495
|
743
|
|
Certain variable costs and non-cash costs
|
|
5,525
|
4,873
|
4,845
|
|
10,398
|
9,882
|
|
19,399
|
18,727
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted operating expenditure*
|
|
4,870
|
5,652
|
6,014
|
|
10,522
|
12,046
|
|
23,602
|
23,089
|
|
Less certain adjusting items*:
|
|
|
|
|
|
|
|
|
|
|
|
Gulf
of America oil spill
|
|
9
|
9
|
8
|
|
18
|
19
|
|
51
|
57
|
|
Environmental
and related provisions
|
|
74
|
103
|
(230)
|
|
177
|
(144)
|
|
181
|
647
|
|
Restructuring,
integration and rationalization costs
|
|
168
|
344
|
(1)
|
|
512
|
(13)
|
|
222
|
(37)
|
|
Fair
value accounting effects - derivative instruments relating to the
hybrid bonds
|
|
(740)
|
(369)
|
29
|
|
(1,109)
|
222
|
|
221
|
(630)
|
|
Other
certain adjusting items
|
|
(98)
|
261
|
767
|
|
163
|
1,010
|
|
601
|
419
|
|
Certain adjusting items
|
|
(587)
|
348
|
573
|
|
(239)
|
1,094
|
|
1,276
|
456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Underlying operating expenditure
|
|
5,457
|
5,304
|
5,441
|
|
10,761
|
10,952
|
|
22,326
|
22,633
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Decrease) increase in underlying operating
expenditure
|
|
(191)
|
|
|
(307)
|
|
||||
|
Of which:
|
|
|
|
|
|
|
|
|
|
|
|
Structural cost reduction*
|
|
|
|
|
|
(938)
|
|
|
(750)
|
|
|
Increase/(decrease) in underlying operating expenditure due to
inflation, exchange movements, portfolio changes and
growth
|
|
747
|
|
|
443
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Structural cost reduction at 30 June 2025 compared with
2023
|
|
|
|
|
||||||
|
Structural cost reduction in 2024
|
|
|
|
|
|
(750)
|
|
|
|
|
|
Structural cost reduction in the first half 2025
|
|
|
|
|
|
(938)
|
|
|
|
|
|
Total structural cost reduction
|
|
|
|
|
|
(1,688)
|
|
|
|
|
(a)
Comparatives have been restated for a reclassification in costs
from transportation and shipping to environmental.
Top
of page 32
Reconciliation of customers & products RC profit before
interest and tax to underlying RC profit before interest and tax*
to adjusted EBITDA* by business
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
$ million
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
RC profit (loss) before interest and tax for customers &
products
|
|
972
|
103
|
(133)
|
|
1,075
|
855
|
|
Less: Adjusting items* gains (charges)
|
|
(561)
|
(574)
|
(1,282)
|
|
(1,135)
|
(1,583)
|
|
Underlying RC profit (loss) before interest and tax for
customers & products
|
|
1,533
|
677
|
1,149
|
|
2,210
|
2,438
|
|
By business:
|
|
|
|
|
|
|
|
|
customers
- convenience & mobility
|
|
1,056
|
664
|
790
|
|
1,720
|
1,160
|
|
Castrol - included in customers
|
|
245
|
238
|
211
|
|
483
|
395
|
|
products
- refining & trading
|
|
477
|
13
|
359
|
|
490
|
1,278
|
|
|
|
|
|
|
|
|
|
|
Add back: Depreciation, depletion and amortization
|
|
1,060
|
985
|
939
|
|
2,045
|
1,883
|
|
By business:
|
|
|
|
|
|
|
|
|
customers
- convenience & mobility
|
|
642
|
567
|
491
|
|
1,209
|
975
|
|
Castrol - included in customers
|
|
50
|
46
|
42
|
|
96
|
84
|
|
products
- refining & trading
|
|
418
|
418
|
448
|
|
836
|
908
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA for customers & products
|
|
2,593
|
1,662
|
2,088
|
|
4,255
|
4,321
|
|
By business:
|
|
|
|
|
|
|
|
|
customers
- convenience & mobility
|
|
1,698
|
1,231
|
1,281
|
|
2,929
|
2,135
|
|
Castrol - included in customers
|
|
295
|
284
|
253
|
|
579
|
479
|
|
products
- refining & trading
|
|
895
|
431
|
807
|
|
1,326
|
2,186
|
Top of page 33
Realizations* and marker prices
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
Average realizations(a)
|
|
|
|
|
|
|
|
|
Liquids* ($/bbl)
|
|
|
|
|
|
|
|
|
US
|
|
53.39
|
62.01
|
65.88
|
|
57.54
|
64.11
|
|
Europe
|
|
64.62
|
75.31
|
80.55
|
|
70.09
|
82.90
|
|
Rest of World
|
|
69.69
|
74.59
|
83.58
|
|
72.09
|
81.67
|
|
bp average
|
|
60.16
|
67.79
|
73.73
|
|
63.88
|
72.49
|
|
Natural gas ($/mcf)
|
|
|
|
|
|
|
|
|
US
|
|
2.52
|
3.15
|
1.29
|
|
2.82
|
1.49
|
|
Europe
|
|
13.06
|
16.47
|
9.49
|
|
14.81
|
9.94
|
|
Rest of World
|
|
6.50
|
7.26
|
5.47
|
|
6.86
|
5.46
|
|
bp average
|
|
5.56
|
6.40
|
4.47
|
|
5.97
|
4.55
|
|
Total hydrocarbons* ($/boe)
|
|
|
|
|
|
|
|
|
US
|
|
39.51
|
46.26
|
44.26
|
|
42.77
|
42.90
|
|
Europe
|
|
68.02
|
81.48
|
73.21
|
|
74.91
|
75.08
|
|
Rest of World
|
|
48.44
|
53.39
|
47.49
|
|
50.82
|
47.05
|
|
bp average
|
|
45.84
|
52.28
|
47.49
|
|
48.95
|
46.95
|
|
Average oil marker prices ($/bbl)
|
|
|
|
|
|
|
|
|
Brent
|
|
67.88
|
75.73
|
84.97
|
|
71.87
|
84.06
|
|
West Texas Intermediate
|
|
63.81
|
71.47
|
80.82
|
|
67.60
|
78.95
|
|
Western Canadian Select
|
|
53.16
|
58.29
|
67.20
|
|
55.74
|
63.56
|
|
Alaska North Slope
|
|
68.82
|
75.83
|
86.42
|
|
72.30
|
83.91
|
|
Mars
|
|
64.89
|
72.55
|
81.37
|
|
68.69
|
79.17
|
|
Urals (NWE - cif)
|
|
57.08
|
64.21
|
72.79
|
|
60.71
|
70.55
|
|
Average natural gas marker prices
|
|
|
|
|
|
|
|
|
Henry Hub gas price(b) ($/mmBtu)
|
|
3.44
|
3.65
|
1.89
|
|
3.55
|
2.07
|
|
UK Gas - National Balancing Point (p/therm)
|
|
84.53
|
115.91
|
76.57
|
|
100.47
|
72.62
|
(a)
Based on sales of consolidated subsidiaries only - this excludes equity-accounted
entities.
(b)
Henry Hub First of Month Index.
Exchange rates
|
|
|
Second
|
First
|
Second
|
|
First
|
First
|
|
|
|
quarter
|
quarter
|
quarter
|
|
half
|
half
|
|
|
|
2025
|
2025
|
2024
|
|
2025
|
2024
|
|
$/£ average rate for the period
|
|
1.34
|
1.26
|
1.26
|
|
1.30
|
1.26
|
|
$/£ period-end rate
|
|
1.37
|
1.29
|
1.27
|
|
1.37
|
1.27
|
|
|
|
|
|
|
|
|
|
|
$/€ average rate for the period
|
|
1.13
|
1.05
|
1.08
|
|
1.09
|
1.08
|
|
$/€ period-end rate
|
|
1.17
|
1.08
|
1.07
|
|
1.17
|
1.07
|
|
|
|
|
|
|
|
|
|
|
$/AUD average rate for the period
|
|
0.64
|
0.63
|
0.66
|
|
0.63
|
0.66
|
|
$/AUD period-end rate
|
|
0.65
|
0.63
|
0.67
|
|
0.65
|
0.67
|
|
|
|
|
|
|
|
|
|
Top of page 34
Principal risks and uncertainties
The principal risks and uncertainties affecting bp are described in
the Risk factors section of bp Annual Report and Form 20-F
2024 (pages 65-67) and are
summarized below. There are no material changes expected in those
risk factors for the remaining six months of the financial
year.
The risks and uncertainties summarized below, separately or in
combination, could have a material adverse effect on the
implementation of our strategy, business, financial performance,
results of operations, cash flows, liquidity, prospects,
shareholder value and returns and reputation.
Strategic and commercial risks
●
Prices and markets - our financial performance is
impacted by fluctuating prices of oil, gas and refined products,
technological change, climate policies and regulations, exchange
rate fluctuations, and the general macroeconomic
outlook.
●
Accessing and progressing hydrocarbon resources and low carbon
opportunities - inability to access and
progress hydrocarbon resources and low carbon opportunities could
adversely affect delivery of our strategy.
●
Major project* delivery - failure to invest in the best
opportunities or deliver major projects successfully could
adversely affect our financial performance.
●
Geopolitical - exposure to a range of
political developments and consequent changes to the operating and
regulatory environment could cause business
disruption.
●
Liquidity, financial capacity and financial, including credit,
exposure - failure to work within our
financial frame could impact our ability to operate and result in
financial loss.
●
Joint arrangements and contractors - varying levels of control over
the standards, operations and compliance of our partners, including
non-operated joint ventures (NOJVs), contractors and
sub-contractors could result in legal liability and reputational
damage.
●
Digital infrastructure, cyber security and data
protection - breach or failure of our or
third parties' digital infrastructure or cyber security, including
loss or misuse of sensitive information could damage our
operations, increase costs and damage our
reputation.
●
Climate change and the transition to a lower carbon
economy -
developments in policy, law, regulation, technology and markets,
including societal and investor sentiment, related to the issue of
climate change and the transition to a lower carbon economy could
increase costs, reduce revenues, constrain our operations and
affect our business plans and financial
performance.
●
Competition - inability to remain efficient,
maintain a high-quality portfolio of assets and innovate could
negatively impact delivery of our strategy in a highly competitive
market.
●
Talent and capability - inability to attract, develop
and retain people with necessary skills, capabilities and
behaviours could negatively impact delivery of our
strategy.
●
Crisis management and business continuity - failure to address an incident
effectively could potentially disrupt our
business.
●
Insurance - our insurance strategy could
expose the group to material uninsured losses.
Safety and operational risks
●
Process safety, personal safety, and environmental
risks - exposure to a wide range of
health, safety and environmental risks could cause harm to people,
the environment and our assets and result in regulatory action,
legal liability, business interruption, increased costs, damage to
our reputation and potentially denial of our licence to
operate.
●
Drilling and production - challenging operational
environments and other uncertainties could impact drilling and
production activities.
●
Security - hostile acts against our
employees and activities could cause harm to people and disrupt our
operations.
●
Product quality - supplying customers with
off-specification products could damage our reputation, lead to
regulatory action and legal liability, and impact our financial
performance.
Compliance and control risks
●
Ethical misconduct and non-compliance - ethical misconduct or breaches
of applicable laws by our businesses or our employees could be
damaging to our reputation, and could result in litigation,
regulatory action and penalties.
●
Regulation - changes in the law and
regulation could increase costs, constrain our operations and
affect our strategy, business plans and financial
performance.
●
Trading and treasury trading activities - ineffective oversight of
trading and treasury trading activities could lead to business
disruption, financial loss, regulatory intervention or damage to
our reputation and affect our permissions to
trade.
●
Reporting - failure to accurately report
our data could lead to regulatory action, legal liability and
reputational damage.
Top
of page 35
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 32
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 30 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
31.
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
28.
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.
CMU Cash Flow and ROACE Targets are the following targets first
announced by bp on 26 February 2025: (i) bp's target for adjusted
free cash flow compound annual growth of greater than 20% from
2024-2027; and (ii) bp's target for group ROACE above 16% in
2027.
●
Adjusted free cash flow is a non-IFRS measure and defined as
operating cash flow* excluding working capital* (after adjusting
for inventory holding gains/losses*, fair value accounting effects*
and other adjusting items) less cash capital
expenditure*.
●
ROACE is a non-IFRS measure and is defined as underlying
replacement cost profit* after adding back non-controlling interest
and interest expense net of tax, divided by the average of the
beginning and ending balances of total equity plus finance debt
excluding cash and cash equivalents and goodwill as presented on
the group balance sheet over the periods. Interest expense before
tax is finance costs as presented on the group income statement,
excluding lease interest, the unwinding of the discount on
provisions and other payables and other adjusting items reported in
finance costs.
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.
Top of page 36
Glossary (continued)
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.
Fair value accounting effects are non-IFRS adjustments to our
IFRS profit (loss). They reflect the difference between the way bp
manages the economic exposure and internally measures performance
of certain activities and the way those activities are measured
under IFRS. Fair value accounting effects are included within
adjusting items. They relate to certain of the group's commodity,
interest rate and currency risk exposures as detailed below. Other
than as noted below, the fair value accounting effects described
are reported in both the gas & low carbon energy and customer
& products segments.
bp uses derivative instruments to manage the economic exposure
relating to inventories above normal operating requirements of
crude oil, natural gas and petroleum products. Under IFRS, these
inventories are recorded at historical cost. The related derivative
instruments, however, are required to be recorded at fair value
with gains and losses recognized in the income statement. This is
because hedge accounting is either not permitted or not followed,
principally due to the impracticality of effectiveness-testing
requirements. Therefore, measurement differences in relation to
recognition of gains and losses occur. Gains and losses on these
inventories, other than net realizable value provisions, are not
recognized until the commodity is sold in a subsequent accounting
period. Gains and losses on the related derivative commodity
contracts are recognized in the income statement, from the time the
derivative commodity contract is entered into, on a fair value
basis using forward prices consistent with the contract
maturity.
bp enters into physical commodity contracts to meet certain
business requirements, such as the purchase of crude for a refinery
or the sale of bp's gas production. Under IFRS these physical
contracts are treated as derivatives and are required to be fair
valued when they are managed as part of a larger portfolio of
similar transactions. Gains and losses arising are recognized in
the income statement from the time the derivative commodity
contract is entered into.
IFRS require that inventory held for trading is recorded at its
fair value using period-end spot prices, whereas any related
derivative commodity instruments are required to be recorded at
values based on forward prices consistent with the contract
maturity. Depending on market conditions, these forward prices can
be either higher or lower than spot prices, resulting in
measurement differences.
bp enters into contracts for pipelines and other transportation,
storage capacity, oil and gas processing, liquefied natural gas
(LNG) and certain gas and power contracts that, under IFRS, are
recorded on an accruals basis. These contracts are risk-managed
using a variety of derivative instruments that are fair valued
under IFRS. This results in measurement differences in relation to
recognition of gains and losses.
The way that bp manages the economic exposures described above, and
measures performance internally, differs from the way these
activities are measured under IFRS. bp calculates this difference
for consolidated entities by comparing the IFRS result with
management's internal measure of performance. We believe that
disclosing management's estimate of this difference provides useful
information for investors because it enables investors to see the
economic effect of these activities as a whole.
These include:
●
Under management's internal measure of performance the inventory,
transportation and capacity contracts in question are valued based
on fair value using relevant forward prices prevailing at the end
of the period.
●
Fair value accounting effects also include changes in the fair
value of the near-term portions of LNG contracts that fall within
bp's risk management framework. LNG contracts are not considered
derivatives, because there is insufficient market liquidity, and
they are therefore accrual accounted under IFRS. However, oil and
natural gas derivative financial instruments used to risk manage
the near-term portions of the LNG contracts are fair valued under
IFRS. The fair value accounting effect, which is reported in the
gas and low carbon energy segment, represents the change in value
of LNG contracts that are being risk managed and which is reflected
in the underlying result, but not in reported earnings. Management
believes that this gives a better representation of performance in
each period.
Furthermore, the fair values of derivative instruments used to risk
manage certain other oil, gas, power and other contracts, are
deferred to match with the underlying exposure. The commodity
contracts for business requirements are accounted for on an
accruals basis.
In addition, fair value accounting effects include changes in the
fair value of derivatives entered into by the group to manage
currency exposure and interest rate risks relating to hybrid bonds
to their respective first call periods. The hybrid bonds which are
classified as equity instruments were recorded in the balance sheet
at their issuance date at their USD equivalent issued value. Under
IFRS these equity instruments are not remeasured from period to
period, and do not qualify for application of hedge accounting. The
derivative instruments relating to the hybrid bonds, however, are
required to be recorded at fair value with mark to market gains and
losses recognized in the income statement. Therefore,
measurement differences in relation to the recognition of gains and
losses occur. The fair value accounting effect, which is reported
in the other businesses & corporate segment, eliminates the
fair value gains and losses of these derivative financial
instruments that are recognized in the income statement. We
believe that this gives a better representation of performance, by
more appropriately reflecting the economic effect of these risk
management activities, in each period.
Top of page 37
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
26.
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 29.
Hydrocarbons - Liquids and natural gas.
Natural gas is converted to oil equivalent at 5.8 billion cubic
feet = 1 million barrels.
Inorganic capital expenditure is a subset of capital
expenditure 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 27.
Inventory holding gains and losses are non-IFRS adjustments to our
IFRS profit (loss) and represent:
●
the difference between the cost of sales calculated using the
replacement cost of inventory and the cost of sales calculated on
the first-in first-out (FIFO) method after adjusting for any
changes in provisions where the net realizable value of the
inventory is lower than its cost. Under the FIFO method, which we
use for IFRS reporting of inventories other than for trading
inventories, the cost of inventory charged to the income statement
is based on its historical cost of purchase or manufacture, rather
than its replacement cost. In volatile energy markets, this can
have a significant distorting effect on reported income. The
amounts disclosed as inventory holding gains and losses represent
the difference between the charge to the income statement for
inventory on a FIFO basis (after adjusting for any related
movements in net realizable value provisions) and the charge that
would have arisen based on the replacement cost of inventory. For
this purpose, the replacement cost of inventory is calculated using
data from each operation's production and manufacturing system,
either on a monthly basis, or separately for each transaction where
the system allows this approach; and
●
an adjustment relating to certain trading inventories that are not
price risk managed which relate to a minimum inventory volume that
is required to be held to maintain underlying business activities.
This adjustment represents the movement in fair value of the
inventories due to prices, on a grade by grade basis, during the
period. This is calculated from each operation's inventory
management system on a monthly basis using the discrete monthly
movement in market prices for these inventories.
The amounts disclosed are not separately reflected in the financial
statements as a gain or loss. No adjustment is made in respect of
the cost of inventories held as part of a trading position and
certain other temporary inventory positions that are price
risk-managed. See Replacement cost (RC) profit or loss definition
below.
Liquids -
Liquids comprises crude oil, condensate and natural gas liquids.
For the oil production & operations segment, it also includes
bitumen.
Top of page 38
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 27.
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.
The Refining
marker margin (RMM) is the average of regional
indicator margins weighted for bp's crude refining capacity in each
region. Each regional marker margin is based on product yields and
a marker crude oil deemed appropriate for the region. The regional
indicator margins may not be representative of the margins achieved
by bp in any period because of bp's particular refinery
configurations and crude and product slate.
Replacement cost (RC) profit or loss / 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.
Solomon availability - See Refining availability
definition.
Structural cost reduction is calculated as decreases in
underlying operating expenditure* (as defined on page 39) 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 31.
Top of page 39
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 31.
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 38) after excluding net
adjusting items and related taxation. See page 28 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 6-13 for the segments.
Underlying RC profit or loss per share / underlying RC profit or
loss per ADS is a non-IFRS measure. Earnings
per share is defined in Note 7. Underlying RC profit or loss per
ordinary share is calculated using the same denominator as earnings
per share as defined in the consolidated financial statements. The
numerator used is underlying RC profit or loss attributable to bp
shareholders, rather than profit or loss attributable to bp
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.
Top of page 40
Glossary (continued)
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 41
Cautionary statement
In order to utilize the 'safe harbor' provisions of the United
States Private Securities Litigation Reform Act of 1995 (the
'PSLRA') and the general doctrine of cautionary statements, bp is
providing the following cautionary statement:
The discussion in this 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; plans
and expectations regarding bp's net debt , investment strategy,
capital expenditures, capital frame, underlying effective tax rate,
and depreciation, depletion and amortization; plans and
expectations regarding Albert Manifold joining bp's board and
related timing; plans and expectations regarding a review of bp's
portfolio of businesses and a further cost review including the
outcomes of those reviews; expectations regarding bp's tax
liabilities and future impact of German tax legislation on bp's
results of operations, financial position and tax obligations;
expectations regarding bp's customers business, including with
respect to volumes and fuel margins; expectations regarding bp's
products, including underlying performance, refinery turnaround
activity, refining margins and operations; expectations regarding
bp's other businesses & corporate underlying annual charge;
expectations regarding Gulf of America settlement payments;
expectations regarding improvements associated with bp's transition
to a refining indicator margin (RIM) and the associated refining
rule of thumb (RoT); expectations regarding TPAO's participation in
the Shafag-Asiman production-sharing agreement; expectations
regarding bp's low carbon energy business, including the JERA Nex
bp offshore wind joint venture, bp's plans to sell its US onshore
wind business and timing of completion, and bp's plans to exit the
Australian Renewable Energy Hub project; expectations regarding the
Agogo Integrated West Hub Project; expectations regarding the
Gajajeira-01 exploration well, including initial assessments of the
gas volumes in place; plans and expectations in relation to the
discovery in the Bumerangue block including the outcome of
laboratory testing of hydrocarbon samples and the potential of the
discovery; expectations regarding bp's investment in the Atlantis
Major Facility Expansion Project; expectations regarding bp's plans
to sell its Netherlands mobility & convenience and bp pulse
businesses, including timing of completion of the divestment;
expectations regarding bp's plans to sell its mobility and
convenience business in Austria, including timing of the
divestment; expectations regarding sale of certain assets of
Lightsource bp, including timing of completion of the sale; and
expectations regarding the principal risks and uncertainties
affecting 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 "Risk
factors" in bp's Annual Report and Form 20-F for fiscal year 2024
as filed with the US Securities and Exchange
Commission.
Top of page 42
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.
The contents of websites referred to in this announcement do not
form part of this announcement.
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Contacts
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London
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Houston
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Press Office
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Rita Brown
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Paul Takahashi
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+44 (0) 7787 685821
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+1 713 903 9729
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Investor Relations
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Craig Marshall
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Graham Collins
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bp.com/investors
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+44 (0) 203 401 5592
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+1 832 753 5116
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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: 05
August 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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