REG - BP PLC - 2Q25 SEA Part 1 of 1
05/08/2025 07:02
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RNS Number : 9254T BP PLC 05 August 2025
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FOR IMMEDIATE RELEASE
London 5 August 2025
BP p.l.c. Group results
Second quarter and first half 2025((a))
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Delivering our plan
Financial summary Second First Second First First
quarter quarter quarter half half
$ million 2025 2025 2024 2025 2024
Profit (loss) for the period attributable to bp shareholders 1,629 687 (129) 2,316 2,134
Inventory holding (gains) losses*, net of tax 407 (118) 113 289 (544)
Replacement cost (RC) profit (loss)* 2,036 569 (16) 2,605 1,590
Net (favourable) adverse impact of adjusting items*, net of tax 317 812 2,772 1,129 3,889
Underlying RC profit* 2,353 1,381 2,756 3,734 5,479
Operating cash flow* 6,271 2,834 8,100 9,105 13,109
Capital expenditure* (3,361) (3,623) (3,691) (6,984) (7,969)
Divestment and other proceeds((b)) 1,356 328 760 1,684 1,173
Net issue (repurchase) of shares (1,063) (1,847) (1,751) (2,910) (3,501)
Net debt*((c)) 26,043 26,968 22,614 26,043 22,614
Adjusted EBITDA* 9,972 8,701 9,639 18,673 19,945
Underlying operating expenditure* 5,457 5,304 5,441 10,761 10,952
Announced dividend per ordinary share (cents per share) 8.320 8.000 8.000 16.320 15.270
Underlying RC profit per ordinary share* (cents) 15.03 8.75 16.61 23.76 32.86
Underlying RC profit per ADS* (dollars) 0.90 0.53 1.00 1.43 1.97
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
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.
Murray Auchincloss
Chief executive officer
(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.
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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.
Murray Auchincloss Chief executive officer
Highlights
2Q25 underlying replacement cost (RC) profit* $2.4 billion
• 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.
• 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.
Segment results
• 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.
• 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.
• 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.
Operating cash flow $6.3 billion and net debt $26.0 billion
• 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.
Financial frame
• bp is committed to maintaining a strong balance sheet and maintaining 'A'
grade credit range through the cycle. We have a target of $14-18 billion of
net debt by the end of 2027((a)).
• Our policy is to maintain a resilient dividend. Subject to board approval, we
expect an increase in the dividend per ordinary share of at least 4% per
year((b)). For the second quarter, bp has announced a dividend per ordinary
share of 8.32 cents.
• Share buybacks are a mechanism to return excess cash. When added to the
resilient dividend, we expect total shareholder distributions of 30-40% of
operating cash flow, over time. Related to the 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.
• bp will continue to invest with discipline, driven by value and focused on
delivering returns. We continue to expect capital expenditure to be around
$14.5 billion in 2025. The capital frame of around $13-15 billion for 2026 and
2027 remains unchanged.
(a) Potential proceeds from any transactions related to the
Castrol strategic review and announcement to bring a strategic partner into
Lightsource bp will be allocated to reduce net debt.
(b) Subject to board discretion each quarter taking into account
factors including current forecasts, the cumulative level of and outlook for
cash flow, share count reduction from buybacks and maintaining 'A' range
credit metrics.
The commentary above contains forward-looking statements and should be read in
conjunction with the cautionary statement on page 41.
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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.
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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 (1,173) (1,269) (1,176) (2,442) (2,210)
post-employment benefits
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 (1,095) (1,082) (971) (2,177) (1,913)
to pensions and other post-employment benefits
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.
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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.
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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
240MW(AC) 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.
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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
300km(2). 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 (56) (52) (40) (108) (81)
benefits
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 (214) 331 (240) 117 (306)
or asset
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 1,378 1,105
2)
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 4,723 4,236 4,225 8,959 8,581
off
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 (36) (11) (34) (47) (66)
contributions and benefit payments for unfunded plans
Net charge for provisions, less payments 666 1,104 764 1,770 81
Movements in inventories and other current and non-current assets and (2,030) (5,069) 1,556 (7,099) (575)
liabilities
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 965 - 508 965 524
interest)
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 (56) (52) (40) (108) (81)
benefits
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 15,854,588 16,097,610 16,590,173 16,026,670 17,090,967
earnings per share
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 (1,030) (91) (112)
operations
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 (2,030) (5,069) 1,556 (7,099) (575)
liabilities as per condensed group cash flow statement((a))
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 (1,384) (3,350) 531 (4,734) (1,857)
(losses), fair value accounting effects and other adjusting items
(a) The movement in working capital includes outflows relating to
the Gulf of America oil spill on a pre-tax basis of $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 (56) (52) (40) (108) (81)
benefits
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
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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 (740) (369) 29 (1,109) 222 221 (630)
bonds
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, 747 443
exchange movements, portfolio changes and growth
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 & 1,533 677 1,149 2,210 2,438
products
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.
Contacts
London Houston
Press Office Rita Brown Paul Takahashi
+44 (0) 7787 685821 +1 713 903 9729
Investor Relations Craig Marshall Graham Collins
bp.com/investors +44 (0) 203 401 5592 +1 832 753 5116
BP p.l.c.'s LEI Code 213800LH1BZH3D16G760
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