[20-F] BP PLC Files Annual Report (Foreign Issuer)
Filing Impact
Filing Sentiment
Form Type
20-F
BP reports 2025 results that mix weaker headline profit with strong cash generation and operational records. Profit attributable to shareholders was
Operating cash flow was
Operationally, BP delivered record upstream plant reliability of 96.1% and refining availability of 96.3%, while cutting combined tier 1 and 2 process safety events to 27. The group advanced a reset strategy focused on growing upstream, high-grading downstream, disciplined transition investment, a larger structural cost reduction target of
Positive
- None.
Negative
- None.
Insights
BP pairs modest headline profit with strong cash, deleveraging focus and strategic reset.
BP generated underlying replacement cost profit of
Net debt declined to
Operational metrics were strong: upstream plant reliability reached 96.1%, refining availability 96.3%, and the proved reserves replacement ratio was
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 20-F
(Mark One)
| REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
OR
| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the fiscal year ended 31 December 2025
OR
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
OR
| SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
Commission file number: 1-06262
BP p.l.c.
(Exact name of Registrant as specified in its charter)
England and Wales
(Jurisdiction of incorporation or organization)
(Address of principal executive offices)
BP p.l.c.
Tel +44 (0) 20 7496 4000
Fax +44 (0) 20 7496 4630
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)
Securities registered or to be registered pursuant to Section 12(b) of the Act
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | |||||||||
| * | |||||||||||
BP/27C | |||||||||||
| * | Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission | ||||
Securities registered or to be registered pursuant to Section 12(g) of the Act.
None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
| Ordinary Shares of 25c each | |||||
| Cumulative First Preference Shares of £1 each | |||||
| Cumulative Second Preference Shares of £1 each | |||||
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes ☐ No ☒
Note—Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐
† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive- based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
U.S. GAAP ☐ | by the International Accounting Standards Board ☒ | Other ☐ | ||||||||||||
If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.
Item 17 ☐ Item 18 ☐
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
bp Annual Report
and Form 20-F 2025
Strong performance –
building for the future
Our primary targets
Our investor proposition
A simpler, stronger and more
valuable bp, see page 19.
Our strategy
We are growing the upstream,
focusing the downstream and
investing with discipline in
transition, see page 8.
Adjusted free cash flow« growth
>20%a
adjusted free cash flow compound
annual growth rate (CAGR)« from
2024-27
Net debt«
$14-18bn
by end 2027
Structural cost reduction«
$5.5-6.5bnb
by end 2027
Return on average capital
employed (ROACE)«
>16%a
in 2027
Progress on our primary targets, page 8 | |
 |
Growing
the upstream
Focusing
the downstream
Disciplined investment
in transition
Image: Argos platform, US
Image: bp retail site, London, UK
Image: bp bioenergy, Brazil
aThis is on a price adjusted basis that assumes a hypothetical price environment of $70/bbl Brent, $4/mmBtu Henry Hub, and $10.3/bbl refining indicator margin (all 2024 real) and assumptions
about the impact of these marker prices on underlying replacement cost profit before tax.
bFollowing the outcome of the strategic review of Castrol, which resulted in the decision to divest a 65% shareholding, the $4-5 billion structural cost reduction target by end 2027, introduced
at the February 2025 Capital Markets Update, has increased.
bp Annual Report and Form 20-F 2025 | 1 |
 | ||||
Strategic report | ||||
Strategic report | |
About bp | 2 |
Chair’s letter | 4 |
Interim chief executive officer’s letter | 5 |
The operating environment | 6 |
Energy outlook | 7 |
Our strategy | 8 |
Our strategy in action | 9 |
Consistency with the Paris goals | 10 |
Our business model | 12 |
Key performance indicators | 14 |
Our financial frame | 18 |
Our investment process | 20 |
Group performance | 24 |
Gas & low carbon energy | 28 |
Oil production & operations | 31 |
Customers & products | 34 |
Other businesses & corporate | 36 |
Sustainability | 37 |
Climate-related financial disclosures (TCFD) | 41 |
Our approach to sustainability | 55 |
Risk management and internal control | 60 |
Principal risks and uncertainties (Risk factors) | 62 |
How we manage principal risks and uncertainties | 67 |
Compliance information | 71 |
Non-financial and sustainability information statement | 71 |
Section 172 statement | 71 |
Corporate governance | |
Board of directors | 73 |
Leadership team | 76 |
Governance framework | 77 |
Board activities | 78 |
Our stakeholders | 80 |
Key decisions | 81 |
Safety and sustainability committee | 82 |
Audit committee | 84 |
People, culture and governance committee | 89 |
Remuneration committee | 91 |
Directors’ remuneration report | 91 |
Other disclosures | 126 |
Financial statements | |
Consolidated financial statements of the bp group | 129 |
Notes on the financial statements | 160 |
Supplementary information on oil and natural gas (unaudited) | 241 |
Additional disclosures | 334 |
Shareholder information | 364 |
Glossary | 375 |
Non-IFRS measure reconciliations | 384 |
Signatures | 389 |
Cross-reference to Form 20-F | 390 |
Information about this report | 391 |
Exhibits | 391 |
Navigating this report | |||
Read more on another page of this report | |||
| |||
Read more online | |||
 | |||
Task Force on Climate-related Financial Disclosures (TCFD) Information that supports TCFD Recommendations and Recommended Disclosures in relation to Metrics and Targets is indicated with TCFD. Glossary Words and terms marked with « are defined in the glossary on page 375 | |||
More information Online quick read A concise summary of the bp Annual Report and Form 20-F 2025, highlighting strategy and performance information. | |||
bp.com/annualreport | |||
| |||
Online reporting centre All our bp corporate reports, including the bp Sustainability Report and the bp Energy Outlook. | |||
bp.com/reportingcentre | |||
| |||
2 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
About bp | ||
We operate at the heart of the
global energy system, helping
countries across the world with
their energy needs and serving
millions of customers every day.
Our purpose
Delivering energy to the world,
today and tomorrow.
Who we are
Our culture frame ‘Who we are’ defines what
we stand for at bp, building on our best qualities
and those things that are most important to us.
It comprises three simple beliefs that can inspire
each of us at bp to be our best every day: live
our purpose, play to win, care for others.
bp.com/ourbeliefs | |
|
Safety and sustainability
27 | 34.3MtCO2e | |
tier 1 and 2 process safety events« (2024 38) | GHG emissions – operational control (2024 33.6MtCO2e) |
Read more on pages 55 and 37 | |
|
Performance | ||
$0.1bn profit for the year attributable to bp shareholders (2024 $0.4bn) $7.5bn underlying replacement cost (RC) profit« (2024 $8.9bn) 2.3m barrels of oil equivalent – oil and gas productiona (2024 2.4m) 90% proved reserves replacement ratio«a (2024 50%) $6.28/boe upstream unit production costs« (2024 $6.17/boe) 96.1% bp-operated upstream plant reliability« (2024 95.2%) 96.3% bp-operated refining availability« (2024 94.3%) |
aOn a combined basis of subsidiaries and equity-accounted entities.
bp Annual Report and Form 20-F 2025 | 3 |
| ||||
Strategic report | ||||
Segment performance
At 31 December 2025, the group’s reportable segments
were gas & low carbon energy, oil production &
operations and customers & products. Each is managed
separately, with decisions taken for the segment as a
whole, and represents a single operating segment that
does not result from aggregating two or more segments
(see Financial statements – Note 5).
Gas & low carbon energya | |||||
Comprises our gas & low carbon energy businesses. Our gas business includes regions with upstream activities that predominantly produce natural gas, gas trading and our Archaea Energy business. Our low carbon business includes solar, offshore wind, hydrogen and carbon capture and storage (CCS), and power trading, and until its divestment in December 2025 also included onshore wind. Power trading includes trading of both renewable and non-renewable power. | |||||
$1.3bn replacement cost (RC) profit before interest and taxb (2024 $3.1bnc) | $5.4bn underlying RC profit before interest and tax« (2024 $6.8bn) | ||||
Segment performance, page 28 | |||||
| |||||
Oil production & operationsa | |||||
Comprises regions with upstream activities that predominantly produce crude oil, including bpx energy. | |||||
$8.6bn RC profit before interest and taxb (2024 $10.8bn) | $9.4bn underlying RC profit before interest and tax (2024 $11.9bn) | ||||
Segment performance, page 31 | |||||
| |||||
Customers & products | |||||
Comprises customer-focused businesses, which include convenience and retail fuels, EV charging, as well as Castrol, aviation, B2B, midstream and bp bioenergy. It also comprises our products businesses which include refining and oil trading. | |||||
$4.1bn RC profit before interest and taxb (2024 loss $(1.0)bnc) | $5.3bn underlying RC profit before interest and tax (2024 $2.5bn) | ||||
Segment performance, page 34 | |||||
| |||||
Other businesses & corporate | |||||
Comprises technology; bp ventures; shipping; our corporate activities and functions; and any residual costs of the Gulf of America oil spill. | |||||
$(40)m RC loss before interest and taxb (2024 loss $(1.0)bn) | $(0.6)bn underlying RC loss before interest and tax (2024 loss $(0.6)bn) | ||||
Segment performance, page 36 | |||||
| |||||
Image: Colleagues at our Houston headquarters, US
aThe Azerbaijan-Georgia-Türkiye and Middle East and North Africa (MENA) regions have been further subdivided by asset.
bIFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker. For bp, this measure of profit
or loss is replacement cost profit before interest and tax, which reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses«
from profit before interest and tax. Replacement cost profit for the group is not a recognized measure under IFRS. For further information see Financial statements – Note 5.
cRestated for material items to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment.
4 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Chair’s letter | ||
Dear shareholders,
bp is one of the world’s great energy
companies, with a strong team, high quality
assets and distinctive strengths in key
business areas. I was honoured to be
appointed as chair in 2025, joining a company
that is making progress on a reset strategy,
albeit with challenges to overcome. With the
environment in which we operate continuing
to be shaped by geopolitical uncertainty and
complex market dynamics, we need to
accelerate delivery, reduce complexity and
increase our financial resilience in order to
realise the full value of the business for
shareholders.
Appointment of Meg O’Neill
One of my first tasks, working with fellow
board members, was to identify an
outstanding leader to take the company
forward. Murray Auchincloss stepped down in
December 2025 after more than three
decades of service to bp, the last five as a
member of our board, first as chief financial
officer and then as chief executive. I would like
to thank him for his contribution and
commitment to bp.
In December 2025 we appointed Meg O’Neill
as chief executive who will join bp on 1 April
2026. Meg’s track record of driving
transformation and growth with disciplined
capital allocation makes her the right leader
for bp as we pursue significant strategic and
financial opportunities. And her relentless
focus on business improvement and financial
discipline gives us high confidence in her
ability to shape the company for its next phase
of growth.
Safety and performance in 2025
The board plays a critical role in monitoring the
organization’s culture and setting the tone
from the top. This is particularly important on
safety. Employees and contractors at bp face a
complex range of risks across the business.
Sadly in 2025, four colleagues working in bp’s
US retail operations lost their lives. On behalf
of the board, I would like to extend our sincere
condolences to their families, friends and
colleagues.
Safety will always be the board’s highest
priority. That’s why we continue to work with
the leadership team to ensure every incident is
thoroughly investigated and the lessons
learned are applied.
On process safety, I commend the teams that
contributed to a decrease in serious process
safety events of about one third, compared
with 2024.
Ongoing improvement in safety is the
foundation for strong operational
performance. In 2025 the teams set new
records for plant reliability on the upstream
side of the business and availability in refining.
Strategic progress was also strong with seven
major projects« delivered in the year and
significant exploration success, including the
world’s largest offshore discovery. Carol
provides more detail on safety and
performance in her letter overleaf.
Governance
In early 2025 the board’s focus moved from
the resetting of strategy to overseeing
disciplined performance and the delivery of
our four primary financial targets. Together
with Meg O’Neill’s appointment, the board’s
composition and capability have been further
strengthened during 2025 deepening its
expertise in key strategic areas: oil and gas,
disciplined capital allocation and the oversight
of performance and risk.
Our governance framework remains a
foundation for delivering sustainable
long‑term value for shareholders. That
framework has also evolved, recognizing the
changing needs of the business and external
developments, including the implementation
of provision 29 of the UK Corporate
Governance Code, relating to risk
management and internal control. And it will
continue to evolve, informed by a further
review, to ensure the framework and the board
that oversees it are best placed for the bp we
want to be, rather than the bp we have been
over recent years.
Engagement with stakeholders remained a
priority in 2025. On joining the board, I initiated
an extensive dialogue with our largest
shareholders, complemented by a continued
focus by the board on workforce engagement.
More to do
Over the course of 2026, you will see bp taking
concerted action to strengthen the company
and position it to grow and deliver sustainable
value for the long term. One such step was the
board’s decision earlier this year to suspend
the share buyback and fully allocate excess
cash to our balance sheet. And you will see bp
continue to take action to simplify and high-
grade the portfolio, reduce the cost base and
make disciplined investments in the best and
highest-returning opportunities. Most
importantly, you will see the board supporting
a management team focused on growing cash
flow and returns.
A better bp
I offer my thanks to the bp teams, whose
dedication, skill and determination continue to
shine through, no matter the challenge. And
thank you to you, bp’s owners, for your
guidance and your trust. The board and I will
continue to actively engage with you and
communicate with increasing clarity and
transparency. With your support we can and
will become a stronger bp. One that is more
sustainable in every way, especially in the
creation of value for shareholders.
Albert Manifold
Chair
6 March 2026
bp Annual Report and Form 20-F 2025 | 5 |
| ||||
Strategic report | ||||
Interim chief executive officer’s letter | ||||
Dear fellow shareholders,
As interim CEO, I want to thank our teams for
their outstanding commitment through a
period of transition for bp. Operational
performance in 2025 was consistently strong
and we made significant progress following
the resetting of our strategy.
Our new chair, Albert Manifold, has set us a
challenge to fulfil bp’s true potential – and
I know the team will rise to this. We’re focused,
we’re in action, we’re determined to make bp
the strongest it can be, and we look forward to
welcoming Meg O’Neill as CEO in April 2026.
Safety comes first
Tragically, in 2025, four people died while
working in our US retail business. Three were
employees in our TravelCenters of America
business. Two of them were killed in separate
incidents where they were struck by passing
vehicles as they carried out emergency
roadside assistance, highlighting the complex
range of risks faced across our business. In
response, this service on active highways has
been permanently withdrawn to protect our
employees. The fourth was a contractor, in our
Thorntons business. Our thoughts are with
their families, friends and colleagues.
In the high-hazard industry we work in, nothing
is more important than safety. We seek to
learn from every incident, no matter how big or
small – and we expect everyone in bp to work
safely. On process safety, we made strong
progress, with 29% fewer combined tier 1 and 2
process safety events« in 2025, but we have
much more to do.
It is important to say that safety is more than
robust controls and systems. It is also about
having a culture where every decision reflects
care in our work – and care for others. Day in,
day out, we must continue to work towards our
goal: eliminating fatalities, life-changing
injuries and the most serious process safety
incidents.
Financial and operating performance
In 2025 we delivered a strong underlying
financial performance with an underlying RC
profit« of $7.5 billiona, despite a weaker price
environment, and operating cash flow« of
$24.5 billion.
We also had a strong operational performance
across bp.
In 2025 we:
•Delivered record upstream plant
reliability« and refining availability«,
with both above 96%.
•Produced 2.3 million barrels of oil and gas
a day, beating our guidance at the start
of 2025.
•Started up seven major projects« safely,
five ahead of schedule.
•Made 12 discoveries – including bp’s
biggest offshore discovery in 25 years,
Bumerangue in Brazil.
•Increased our proved reserves replacement
ratio« to 90% – up from an average of
around 50% in the previous two years.
Strategic progress
We took decisive action to high-grade our
portfolio and strengthen our company in 2025,
including our $20 billion disposal programme
and the subsequent decision to suspend the
share buyback and fully allocate excess cash«
to our balance sheet. These are choices
designed to position us for long-term growth.
We also made progress on our four primary
targets, increasing adjusted free cash flow«bc
and returns (ROACE«)bd, both on an adjusted
price basis. We reduced net debt« to $22.2
billione and made progress strengthening our
balance sheet, achieving $2.8 billionf of our
$4-5 billion structural cost reduction« target,
which we have now increased to $5.5-6.5
billiong.
In addition, we have announced or completed
over $11 billion of divestments in the first year.
Looking forward and thanks
bp is a great company with huge potential. We
have outstanding technology and engineering
skills, excellent resources and exceptional
global partnerships. And, most of all, we have
brilliant people whose performance across the
year was key to producing strong results.
It is an honour to represent bp as interim CEO,
and the leadership team and I look forward to
the year ahead. My deepest thanks go to our
teams, our partners and our owners. We are
grateful for your support and your challenge,
and together, under Meg’s leadership, we will
make bp go from strength to strength.
Carol Howle
Interim chief executive officer
6 March 2026
 | | |
Nearest IFRS-equivalent measures $0.1bn profit for 2025 attributable to bp shareholdersa $58.0bn finance debt at the end of 2025e | ||
 | |
aUnderlying RC profit for the group is a non-IFRS measure and its nearest IFRS equivalent measure is profit for the year attributable to bp shareholders.
bThis is on a price adjusted basis and is assuming a hypothetical price environment of $70/bbl Brent, $4/mmBtu Henry Hub, and $10.3/bbl refining indicator margin (all 2024 real) and
assumptions about the impact of these marker prices on underlying replacement cost profit before tax.
cAdjusted free cash flow on a price adjusted basis is a non-IFRS measure. The nearest IFRS equivalent measures to calculate adjusted free cash flow on a price adjusted basis CAGR are net cash
provided by operating activities and total cash capital expenditure.
d ROACE on a price adjusted basis is a non-IFRS measure. The nearest IFRS measures of the numerator and denominator are profit for the period attributable to bp shareholders and total equity
respectively.
eNet debt is a non-IFRS measure and its nearest IFRS equivalent measure is finance debt at the end of 2025. See Note 27 for more information.
f Cumulative structural cost reduction since 2023, of which $2 billion in 2025 and $750 million in 2024. Structural cost reduction is decreases in underlying operating expenditure«.
A reconciliation is provided on page 386.
g Following the outcome of the strategic review of Castrol, which resulted in the decision to divest a 65% shareholding, the $4-5 billion structural cost reduction target by end 2027, introduced at
the February 2025 Capital Markets Update, has increased.
6 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Energy markets | ||
The operating environment
bp operates across volatile energy markets.
Here we discuss broader economic trends
we have observed that influence our sector
as a whole.
The world economy grew by around 3.3%a in
2025, stronger than had been expected in April
2025b. Growth rates varied across economies,
with US GDP estimated to have grown by 2.1%,
while the eurozone economy expanded by only
1.4%a. China’s growth in 2025 is estimated to
have been 5%a, achieving the government
‘around 5%’ target.
Inflation continued to ease globally, moving
closer to central banks’ target levels in most
major economies. This disinflationary trend
allowed several central banks, including the
US Federal Reserve and the European
Central Bank, to cut interest rates. In the
case of the Federal Reserve, further rate
cuts are expected in 2026, based on financial
market pricing.
Oil
Oil prices trended lower during 2025,
amid strong supply and relatively weak
demand growth.
Non-OPEC+ supply grew by 1.8mmb/dc in
2025, led by offshore projects, oil sands, tight
oil and NGLs, mostly from the Americas.
OPEC+ supply grew by 1.3mmb/dc in 2025,
largely due to unwinding of production cuts
from OPEC+8, especially Saudi Arabia. That
steadily increasing supply meant that global
oil supply is estimated to have been 3mmb/dc
higher over the year as a whole than in 2024.
That contrasted with demand growth of only
0.8mmb/d, taking demand to 104mmb/d, and
leading to a supply/demand imbalance of
around 2.2mmb/d over the year as a wholec.
The imbalance weighed on prices, with Dated
Brent averaging $69/bbl in 2025, down from
$81/bbl in 2024d. OECD commercial
inventories grew by 3% over the course of the
year, compared to a 1% fall last yeare.
Significant government stockpiling in China of
around 550kb/d in 2Q25 and 3Q25 absorbed
some of the supply/demand imbalance, and
there was also an increase in the amount of oil
being held in tankers at sea, which reached
2,006mmb, 232mmb higher than the five-year
average, as sanctioned Russian and Iranian
barrels were held off the marketc.
Natural gas
In the US, Henry Hub (HH) gas prices
rebounded to their highest level since 2022f
due to a 26%g year-on-year increase in LNG
export demand and colder-than-normal start
to the year. Higher gas prices supported a
recovery in drilling activity in non-associated
(dry) shale plays which, combined with well
productivity gains, increasing gas-to-oil ratios
in the Permian, and increased pipeline
connectivity, meant that gas production grew
by 4%g, reaching record high levels.
Outside of North America, global gas demand
grew by less than 1% in 2025h. TTF and JKM
increased 9%i and 3%j respectively. A further
reduction in Russian supply to the EU at the
onset of 2025 contributed to the higher gas
prices, reducing gas demand growth in Asia in
particular. LNG supply from new liquefaction
projects ramped up through the year and
drove a near 7%h increase in global LNG
production.
Refining indicator margin
We have updated the metric used to track the
refining margin environment to the refining
indicator margin (RIM)k. After a weak 1Q25,
RIM increased over the rest of the year,
supported by lower crude prices, relatively
resilient product demand, tight product
inventories and unplanned capacity outages
and disruptions. RIM averaged $12.8/bbl over
2025 as a whole, up $2.1/bbl (19%) from
its average level in 2024k.
Power and renewables
Electricity demand growth continued to
outpace total energy demand growth, driven
by increasing electrification in China and by
growing prosperity and industrialization in
emerging economies. Growing demand from
data centres looks set to increase electricity
demand materially in the coming years,
particularly in the US.
Total solar and wind capacity additions in 2025
are estimated to have exceeded 600GW,
breaking the previous record set in 2024l.
Bioenergy growth also maintained
momentum, supported by resilient demand
for liquid biofuels in road transport, rising
biomethane output, and a growing pipeline
of announced sustainable aviation fuel
(SAF) capacity.
Hydrogen and carbon capture
and storage
Persistent high costs and the slow pace of
enabling policy continued to challenge the
decarbonization of many harder-to-abate
processes, including through technologies
such as low carbon hydrogen and
carbon capture.
The project pipeline for production of low
carbon hydrogen has contracted recently
and only around 4Mtpam is either currently
operational or under construction. Growth of
the global carbon capture and storage project
pipeline slowed significantly in 2025.
Operational and under-construction projects
have now reached just over 100Mtpan in
total capacity.
aIMF World Economic Outlook update, January 2026, measured
on a Purchasing Power Parity basis.
bIMF World Economic Outlook, April 2025, measured on a
Purchasing Power Parity basis.
cIEA Oil Market Report, January 2026.
dLSEG Data Management Solution (Dated Brent spot price).
eIEA Monthly Oil Data Service, January 2026.
fS&P Global Energy Platts Henry Hub spot price.
gEIA Short-term Energy Outlook, January 2026.
hIEA Gas Market Report, Q1-2026.
iS&P Global Energy Platts Dutch TTF day ahead price.
jS&P Global Energy Platts JKM spot price.
k bp has retired the refining marker margin (RMM) and replaced it
with the bp refining indicator margin (RIM). 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.
Actual margins realized by bp may vary due to a variety of
factors, including the actual mix of crude and product for a
given quarter.
lIEA Renewable Energy Progress Tracker. PV capacity additions
are converted from DC to AC basis.
mIEA Global Hydrogen Review, September 2025.
nGCCSI Global Status of CCS 2025, October 2025.
oLSEG Data Management Solution (West Texas Intermediate).
Market activity | 2025 | 2024 | |
Global oil consumptionc | 104.0mmb/d | 103.2mmb/d | |
Global oil productionc | 106.2mmb/d | 103.1mmb/d | |
Natural gas consumptionh | 4,286bcm | 4,251bcm | |
Natural gas productionh | 4,264bcm | 4,224bcm | |
Dated Brent averaged | $69.10/bbl | $80.76/bbl | |
West Texas Intermediate (WTI)« averageo | $64.87/bbl | $75.87/bbl | |
Henry Hub averagef | $3.52/mmBtu | $2.19/mmBtu | |
Dutch Title Transfer Facility (TTF)« averagei | 36.2 Euros per MWh ($11.9/mmBtu) | 34.4 Euros per MWh ($10.9/mmBtu) | |
Japan-Korea (Asian) LNG averagej | $12.2/mmBtu | $11.9/mmBtu | |
Refining indicator margink« | $12.8/bbl | $10.7/bbl |
bp Annual Report and Form 20-F 2025 | 7 |
| ||||
Strategic report | ||||
Energy outlook
The bp Energy Outlook 2025 (2025 Outlook)
explores the trends and uncertainties
surrounding the energy transition out to 2050.
The 2025 Outlook helps inform bp’s views of
the risks and opportunities posed by the
energy transition. The scenarios within it
explore the possible implications of different
judgements and assumptions concerning the
nature of the energy transition. The uncertainty
associated with the transition is substantial,
and these scenarios are not predictions of
what is likely to happen or what bp would like
to see happen. We use the output from these
scenarios to help inform our strategic thinking.
We published the 2025 Outlook in September
2025, designed around two scenarios
informed by recent trends and developments
in the global energy system. The 2025 Outlook
provides key insights about how the energy
system may evolve over the next 25 years.
The two scenarios – Current Trajectory and
Below 2°C (see ‘Two scenarios to explore the
energy transition’, below) – explore the speed
and shape of the energy transition out to 2050
and help to inform a resilient strategy for bp.
A new section in the 2025 Outlook uses
sensitivity analysis to discuss several key
issues affecting the energy transition,
including the possible implications of
increased geopolitical fragmentation and
sustained weakness in energy efficiency. Each
sensitivity analysis examined possible impacts
on the global energy system.
Scenarios for strategic
decision making
We use scenarios to inform strategy, manage
risk, and improve decision making.
Some of these scenarios are based on climate
and other policies currently in force, and on
current global aims and pledges around the
energy transition. Other scenarios are based
on achieving a certain pace or degree of
transition, and consider how the energy
system might change to achieve that.
In thinking about appropriate scenarios to
inform our strategy, we use both approaches.
How scenarios inform our strategy
The use of scenarios described in the 2025
Outlook, and those from other organizations,
aids our understanding of the energy
transition and helps us to think about how
different outcomes might impact our strategy.
The use of a broad range of scenarios to
inform our strategy supports our efforts to
make it robust and resilient to the range of
uncertainty we face.
By considering various time horizons we can
identify key milestones or signposts which
might emerge over the next five, 10 or 25 years
and inform our view of the key sources of
uncertainty affecting the global energy system.
We actively monitor changes in the
external environment and refresh or review
the scenarios as needed in response to
these signals.
For the purposes of testing the resilience
of our strategy to the range of uncertainty in
the energy transition, we have used scenarios
drawn from other credible sources such as the
International Energy Agency (IEA), the Network
for Greening the Financial System (NGFS) and
the UN Principles for Responsible Investment
(UN PRI) to compile a catalogue of scenarios
(our Transition Scenario Catalogue« ). These
include some scenarios considered by these
data providers to be consistent with 1.5°C and
well-below 2°C.
Read more on the Transition Scenario
Catalogue, our resilience analysis and the
outcome of that work on page 49.
How we create scenarios
We quantify the scenarios in the 2025 Outlook
using our global energy modelling system.
This comprises a suite of models to help us
understand the supply and demand dynamics
of the global energy system.
| | |||
Two scenarios to explore the energy transition Carbon emissions Gt CO2ea | ||||
Current Trajectory  | Below 2°  | |||
is designed to capture the broad pathway along which the global energy system is currently travelling. It places weight on climate policies already in force and on global aims and pledges for future decarbonization. At the same time, it recognizes the myriad challenges associated with meeting these aims. CO2 equivalent (CO2e) emissions in Current Trajectory peak in the mid-2020s and by 2050 are around 25% below 2023 levels. | explores how different elements of the energy system might change to achieve a substantial reduction in carbon emissions (a net 90% fall in CO2e emissions by 2050). It assumes a significant tightening of climate policies alongside shifts in societal behaviour and preferences, which together support more rapid adoption of low carbon energy alongside faster gains in energy efficiency. | |||
History  | ||||
a Carbon emissions include CO2 emissions from energy use, industrial processes, natural gas flaring and methane emissions from energy production. | ||||
| | |||
The modelling framework uses historical data
based on the Energy Institute’s Statistical
Review of World Energy, the IEA’s World
Energy Balances data and a range of other
data sets.
Each scenario is determined by a set of key
assumptions, including population and
economic growth, pace of technological
change, resource constraints and government
policies. These are informed by expert analysis
from external organizations including the
United Nations, Oxford Economics and Rystad
Energy. We benchmark our scenarios against
external organizations including the IEA, the
IPCC, and S&P Global.
The modelling techniques used vary by sector
and include a combination of econometric
modelling, adoption curves and consumer
choice modelling.
| bp Energy Outlook 2025 bp.com/energyoutlook |
8 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Our strategy | ||
Our strategy helps bp compete and grow value as energy demand evolves and continues to grow,
all in service of growing shareholder value and returns.
 | | |||||||||
 | | | | |||||||
Growing upstream | Focusing downstream | |||||||||
 | | | | |||||||
Disciplined investment in transition | ||||||||||
 | | |||||||||
Growing the upstream: our oil and gas business
We are growing upstream production and cash flow through disciplined
investment. We have a deep upstream resource base, and combined
with disciplined investment criteria, we are well positioned to deliver
medium and long-term organic growth.
Focusing the downstream:
our customers and products business
We continue to reshape the portfolio to focus on markets and businesses
where we have advantaged and integrated positions. We are taking clear
actions to drive improved performance, including addressing costs in our
customers business, and improving operations in refining.
Investing with discipline in transition
We are investing with discipline: with selective investment in biogas,
biofuels and EV charging, where we see strong demand growth;
adopting innovative capital-light partnerships in renewables; and
focusing investment on hydrogen and carbon capture projects to
support us in decarbonizing our operations, and position us for
growth through the next decade.
All while continuing to drive value through our
distinctive strengths in trading, technology
and partnerships.
| | ||||||||
Progress on our primary targets We use four primary targets to measure our progress and how we are improving performance. These targets, alongside the guidance and financial frame (see page 18), support our strategy. Taken together, we believe our primary targets will underpin growth in the value of bp. Our progress in 2025 is set out below: | Nearest IFRS-equivalent measures | ||||||||
Primary targets | 2025 | Targets | 2025 | ||||||
Adjusted free cash flow growth« | >20%a compound annual growth rate from 2024-27 | ||||||||
Net debt« | $22.2bnb | $14-18bn by end 2027 | $58.0bnb finance debt | ||||||
Structural cost reduction« | $2.8bnc (cumulative since 2023) | $5.5-6.5bnd by end 2027 | n/a | ||||||
Return on average capital employed (ROACE)« | 13.9%e | >16%a in 2027 | 0.1%e profit for 2025 attributable to bp shareholders divided by total equity at 31 December 2025 | ||||||
| | ||||||||
aThis is on a price adjusted basis that assumes a hypothetical price environment of $70/bbl Brent, $4/mmBtu Henry Hub, and $10.3/bbl refining indicator margin (all 2024 real) and assumptions
about the impact of these marker prices on underlying replacement cost profit before tax.
bNet debt is a non-IFRS measure. The nearest IFRS equivalent measure is finance debt at the end of 2025. See Note 27 for more information.
cCumulative structural cost reduction since 2023, of which $2 billion in 2025 and $750 million in 2024. Structural cost reduction is decreases in underlying operating expenditure«. A reconciliation
is provided on page 386.
dFollowing the outcome of the strategic review of Castrol, which resulted in the decision to divest a 65% shareholding, the $4-5 billion structural cost reduction target by end 2027, introduced at
the February 2025 Capital Markets Update, has increased.
eReturn on average capital employed (ROACE) is a non-IFRS measure. The nearest IFRS measures of the numerator and denominator are profit for 2025 attributable to bp shareholders of $0.1
billion and total equity at the end of 2025 of $74.0 billion respectively. A reconciliation is provided on page 385.
bp Annual Report and Form 20-F 2025 | 9 |
| ||||
Strategic report | ||||
Our strategy in action
Growing upstream In 2025 we advanced our upstream strategy and delivered seven major project start-ups, five of which were ahead of schedule. Start-ups included GTA, in Mauritania and Senegal, Cypre in Trinidad and Murlach in the UK North Sea. We also announced 12 discoveries, including Bumerangue in Brazil, our largest exploration discovery in 25 years, plus further finds in Brazil, Egypt, the Gulf of America, Libya and Trinidad, as well as discoveries in Namibia and Angola through Azule Energy, our 50-50 joint venture with Eni. In upstream oil and gas production, we achieved our best wells reliability in years at 98% and a record full-year plant reliability« at >96%%. Our proved reserves replacement ratio« was 90% – up from an average of around 50% in the prior two years. | In April we announced a Miocene oil discovery at the Far South prospect in Green Canyon Block 584, 120 miles off the coast of Louisiana. Drilled to 23,830 feet in 4,092 feet of water, the discovery signals potentially commercial volumes and helps to strengthen our upstream portfolio. In August we announced the start-up of the Argos Southwest Extension project, seven months ahead of schedule. From appraisal to first oil, the project was developed in about 25 months – a record for bp. Argos has a gross production capacity of up to 140,000 barrels of oil per day (boe/d). In December the development programme for the Karabagh field in the Caspian Sea, offshore Azerbaijan, was approved by the management committee (joint venture) and subsequently by State Oil Company of the Azerbaijan Republic (SOCAR) as the State representative. Seismic acquisition commenced thereafter. We also completed the divestment of the Culzean gas field in the UK North Sea to NEO Next in December. Image: Argos Southwest Extension project, US | |||
| Read more on page 28-33 | |||
Focusing downstream 2025 was also a strong year for the downstream, delivering a significant step up in performance. We achieved around $1.6 billion in cumulative structural cost reductions« (2024-25) and sustained refinery availability« above 96%, strengthening commercial performance across refining, trading, midstream and fuels. Customers reported its highest underlying RC profit before interest and tax« since 2019, with growth across all businesses. As we continue streamlining our portfolio, in 2025 we reached an agreement to sell a 65% | stake in Castrol, completed the sale of the Netherlands mobility, convenience and bp pulse businesses, and announced plans to sell the Gelsenkirchen refinery and the Austria retail business. As part of our broader retail network high- grading programme, in 2025 we exited around 5% of our company owned retail sites«, supporting our plan to exit around 10% by 2027. In EV charging, we are focusing investment on four core markets and utilising our retail network to maximise returns. Image: Rotterdam refinery, Netherlands | |||
| Read more on page 34 | |||
Disciplined investment in transition We focused our low carbon energy portfolio in 2025, prioritizing investment choices that deliver value for shareholders. We formed JERA Nex bp, a 50:50 offshore wind joint venture between JERA and bp. The new joint venture brings together each parties’ complementary expertise for a balanced mix of operating assets and development projects. | We sold our US onshore wind business to LS Power. And we continued to manage the pace of investment in biogas and refine and high-grade our hydrogen and carbon, capture and storage (CCS) portfolio. This included decisions not to progress H2Teesside and to end participation in projects in Oman, Australia and the US Gulf Coast. In 2025 we focused on delivering four sanctioned projects in 2024: Lingen green hydrogen project, Castellón green hydrogen project, the Northern Endurance Partnership (NEP), and Net Zero Teesside Power (NZT) – and the UCC project in Indonesia. | |||
| Read more on page 28 | |||
Delivering operational value From predictive analytics to seismic imaging, we are applying technological solutions to deliver operational value. In our upstream, technology has helped to lift plant reliability to 96.1%. Advances in seismic imaging are helping us explore more accurately, contributing to one of our best recorded years for exploration with 12 new discoveries, including through our joint ventures. And digital tools such as our asset and wells trajectory optimizer (AWTO) help plan safe routes from the surface to the reservoir in days instead of weeks or months. | |||
Digital-led marketing transformation As part of our global marketing transformation programme, we consolidated 19 digital platforms into six and activated a global marketing and communications hub in Mumbai in 2025. The programme also includes deploying AI-driven technology to develop investment insights in more than 40 markets and tools to support segmentation and personalization. These changes have helped to streamline operations, accelerate delivery, and strengthen customer engagement. | |||
10 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Consistency with the Paris goals | ||
Pursuing a strategy that is consistent
with the Paris goals
What we mean by Paris-consistent
The 2019 CA100+ resolution« requires us
to disclose the strategy that the board
considers in good faith to be consistent
with the Paris goals.
When we refer to ‘consistency with Paris’ we
consider this to mean consistency with the
world meeting the temperature goal set out in
Articles 2.1(a) and 4.1 of the Paris Agreement on
Climate Change«.
The Paris goals, which we support, were
restated in the Global Mutirão at COP30 in
Belém in November 2025.
We believe the world is on an unsustainable
path, and the carbon budget to meet the Paris
goals is running out.
bp’s strategy is informed by these
considerations. It is designed to create long-
term value for shareholders, while enabling
delivery of our net zero ambition. It is tested
for resilience to the uncertainty of the energy
transition across many different potential
pathways, including various Paris-consistent
pathways.
In the bp Annual Report and Form 20-F 2021
we set out, based on three key principles, why
the board considers our strategy to be
consistent with the Paris goals. Here we set
out, on the same three grounds, why the board
continues to consider this to be the case.
Informed by Paris-consistent energy
transition scenarios
The speed and nature of the energy transition
are uncertain, and so we consider a range of
scenarios from multiple sources including the
bp Energy Outlook 2025 (see page 7) to
develop and test our strategic thinking. This
helps to reinforce our confidence in the
robustness and resilience of our strategy to
the range of uncertainty we face.
We are confident that our approach is science
based. We see the Intergovernmental Panel on
Climate Change (IPCC) as the most
authoritative source of information on the
science of climate change, and we use it and
other sources such as the IEA World Energy
Outlook to inform our strategy. The IPCC
highlights that there are a range of global
pathways by which the world can meet the
Paris goals, with differing implications for
regions, industry sectors and sources
of energy.
Strategic resilience
We believe our strategy positions bp for
success and resilience in a Paris-consistent
world – a world that is progressing on one of
the many global trajectories considered to be
Paris-consistent, and ultimately meets the
Paris goals.
The strategy diversifies bp’s portfolio and
business interests, reducing the risk that
challenges facing a single business area might
adversely affect bp’s strategic resilience.
In addition, within the inevitable constraints
associated with factors such as long-term
capital investments, contractual commitments
and organizational capabilities at any given
time, bp’s ability to maintain its strategic
resilience rests, in part, on the governance
used to keep the strategy and associated
targets and aims under review in light of new
information and changes in circumstances.
In our climate-related financial disclosures on
page 49, we describe how we have conducted
an analysis to test our view of the resilience of
our strategy, based on the Capital Markets
Update presented on 26 February 2025 (and
the financial frame presented with bp’s fourth-
quarter and full-year 2025 results on 10
February 2026), to different climate-related
scenarios.
For the purposes of testing the resilience
of our strategy to the range of uncertainty in
the energy transition, we have used scenarios
drawn from other credible sources such as the
International Energy Agency (IEA), the Network
for Greening the Financial System (NGFS) and
the UN Principles for Responsible Investment
(UN PRI) to compile a catalogue of scenarios
(our Transition Scenario Catalogue« ). These
include scenarios considered by these data
providers to be consistent with well-below 2°C
and 1.5°C outcomesa.
As further explained on page 50, while the
results of any such analysis must be treated
with caution overall, this resilience test again
reinforced our confidence in the continued
resilience of our strategy to a wide range of
ways in which the energy system could evolve
throughout this decade, including in scenarios
consistent with limiting temperature rise
to 1.5°C.
The analysis also again highlighted that, while
within the Transition Scenario Catalogue
lowest oil prices are associated with 1.5°C
scenarios, there is considerable uncertainty –
demonstrated by the range within, and overlap
between, the prices indicated for each
scenario family.
In the Transition Scenario Catalogue used for
the analysis, while the lowest oil price is
associated with a 1.5°C scenario, a number of
the 1.5°C and well-below 2°C scenarios have oil
prices in 2030 that are substantially higher
than this – and when compared to bp’s own
central case oil price planning assumption for
2030, the oil price in a number of the well-
below 2°C and 1.5°C scenarios is also higher.
Taking this into account, the analysis
supported our belief that our strategy is
financially resilient against the lowest prices
associated with a Paris-consistent world in the
Transition Scenario Catalogue. This in turn
supports our view that our strategy is resilient
to such a Paris-consistent world.
aOur 2025 analysis used data from our Transition Scenario Catalogue« which is based on the WBCSD Climate Scenario Catalogue version 3.0, published on 16-05-2024 and downloaded on
13-11-2024, with updates made for scenario updates subsequently published by relevant underlying data providers – such as IEA, UN PRI and NGFS. For more details on this see page 54.
bp Annual Report and Form 20-F 2025 | 11 |
| ||||
Strategic report | ||||
Contributes to net zero
We believe that our strategy enables bp to
make a positive contribution to the world
achieving net zero greenhouse gas (GHG)
emissions and meeting the Paris goals –
outcomes which we believe to be in the
best interests of bp as well as beneficial to
society generally.
We continue to see opportunity in the energy
transition – and there are many ways bp can
contribute to the world getting to net zero
outside of our aims to be net zero across our
operations and sales by 2050 or sooner.
In addition to our transition businesses« such
as Archaea Energy and bp bioenergy, we aim
to make a meaningful contribution to the
world getting to net zero through investing
with discipline in low carbon energy in ways
that are capital light for bp. These investments
are not readily quantifiable by metrics
associated with bp’s net zero aims. Examples
of investments:
•Lightsource bp operates with a develop,
engineer, construct and farm-down
business model that creates value through
selling majority interests in assets it has
developed to strategic partners. Our net
zero aims only recognize the impact of
power when we sell it, rather than the
power produced by assets we have
farmed down.
•In 2025 JERA and bp completed the
formation of JERA Nex bp, a 50:50-owned
joint venture (JV), see page 9. The
development of renewable power
generation often helps to displace more
carbon intensive alternatives and thus
supports decarbonization of the
power grid.
•In 2025 in the UK, bp and partners
continued to develop the Net Zero
Teesside Power (NZT Power) and Northern
Endurance Partnership (NEP) projects.
The NZT and NEP projects have started
construction on-site, with commercial
operations expected in 2028. Once fully
operational NZT will have the ability to
capture up to 2 million tonnes of CO2 per
annum for storage via the NEP storage
infrastructure which is sized for an initial
4 million tonnes of CO2 per annum within
the East Coast Cluster, with the ability
to expand in the future. Where CO2 is
transported offshore for permanent
storage on behalf of other entities (such
as local heavy industries), this will not
show up in bp’s GHG metrics.
We also support collective action through
participation in external initiatives, low carbon
collaboration and support for others in their
own decarbonization efforts. We seek to use
the company’s influence with trade
associations that conduct climate-related
advocacy.
As part of our broader advocacy efforts in
connection with bp’s strategy, we continue to
advocate for well-designed policies that
enable an energy transition consistent with the
goals of the Paris Agreement.
Helping policymakers to design and put in
place scalable low carbon policies that
support the transition to net zero can help
deliver our strategy and capitalize on the
opportunities associated with the world
achieving the Paris goals, but the benefit of
such actions, if successful, extends well
beyond any implications for bp’s own GHG
metrics. That is because well-designed low
carbon policies can advance the
decarbonization of a whole economy –
something of potentially greater impact than
a single company can achieve through its
own portfolio.
Responding to shareholder interest in Paris consistency In 2019 the board recommended that shareholders support a special resolution requisitioned by Climate Action 100+ (CA100+) on climate change disclosures. The CA100+ resolution passed with more than 99% of votes cast. This is the seventh year we have included responses throughout the Annual Report and we have adopted a similar approach to previous years. The CA100+ resolution, which includes safeguards such as protections for commercially confidential and competitively sensitive information, is on page 376. Key terms related to this resolution response are indicated with « and defined in the glossary on page 376. These should be reviewed with the following information: | |||
Element of the CA100+ resolution | Related content | Where | |
Strategy that the board considers in good faith to be consistent with the Paris goals. | Our strategy and business model | 8 & 12 | |
Pursuing a strategy that is consistent with the Paris goals | 10 | ||
How bp evaluates each new material capex investment« for consistency with the Paris goals and other outcomes relevant to bp strategy. | Our investment process | 20 | |
Disclosure of bp’s principal metrics and relevant targets or goals over the short, medium and long term, consistent with the Paris goals. | Key performance indicators | 14 | |
Sustainability: net zero aims and targets | 37 | ||
See ‘TCFD Metrics & Targets’ for an overview | 54 | ||
Anticipated levels of investment in: (i) Oil and gas resources and reserves. (ii) Other energy sources and technologies. | Our strategy | 8 | |
Financial frame: disciplined investment allocation | 18 | ||
Transition business« investment | 21 | ||
bp’s targets to promote operational GHG reductions. | Sustainability: net zero« aims | 37 | |
Estimated carbon intensity of bp’s energy products and progress over time. | Sustainability: net zero sales aim« | 38 | |
Any linkage between above targets and executive pay remuneration. | Directors’ remuneration report | 91 | |
2025 annual bonus outcome | 99 | ||
2026 remuneration policy | 106 | ||
12 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Our business model | ||
An integrated energy company
We believe we have a world-class portfolio – a top-tier oil and gas
business in attractive basins, and leading integrated positions and
brands across the value chain. All underpinned by distinctive
capabilities in trading, technology and partnerships.
Read more about our strategy, page 8 | |
|
People and resourcesa | Our organization | |||||
61 countries of operation 93,700 employees ~11,300 engineers $14.5bn capital expenditure« $274m invested in research and development 2,958 granted and pending patent applications held by bp and its subsidiaries 6,191mmboe proved hydrocarbon reserves for the groupb >110 years energy sector experience a Data as at 31 December 2025. b On a combined basis of subsidiaries and equity-accounted entities. See page 248 for more information on bp’s oil and gas reserves. | We have three main businesses – gas & low carbon energy, production & operations, and customers & products – enabled by supply, trading & shipping and technology. And three teams serve as enablers of business delivery: finance; legal; and people, culture & communications. | |||||
Enabled by | ||||||
Supply, trading & shipping Connects energy producers, suppliers, markets and customers to keep energy flowing and help build out tomorrow’s energy system. Image: Traders at our Canary Wharf office, London, UK | ||||||
bp Annual Report and Form 20-F 2025 | 13 |
| ||||
Strategic report | ||||
Delivering value for stakeholders | |||||||
Gas & low carbon energy Combining and integrating our existing natural gas capabilities with power trading and growth in low carbon businesses and markets (see page 28). Production & operations The operational heart of bp, producing the hydrocarbon energy and products the world wants and needs – safely and efficiently (see page 31). Customers & products Innovating with new business models and service platforms to deliver the future of mobility, energy and services for our customers (see page 34). | Investors and shareholders $5.1bn total dividends distributed to bp shareholders (2024 $5.0bn) Employees 66% employee engagement scorec (2024 70%) Customers 1,113mb/d retail fuel volumes« (2024 1,125mb/dd) Society $64m supporting additional initiatives to benefit communities (2024 $76m) Governments and regulators $8.3bn corporate income and production tax paid (2024 $10.6bn) Partners and suppliers $142.5bn in payments to suppliers for goods and services (2024 $146.6bn) c As a result of changes to the question set and the inclusion of employees from our retail business in the 2025 Pulse survey, the engagement score for 2025 is not comparable with prior years. d 2024 baseline adjusted for portfolio changes to show underlying trend. | ||||||
Technology Drives digital and innovations with our science, engineering and digital capabilities. Image: Colleagues at our Rotterdam refinery, Netherlands | |||||||
14 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Key performance indicators | ||
We assess the performance of the group across a wide range of
measures and indicators that are consistent with our strategy.
In addition to our four financial primary targets, as described on page 8, our key performance
indicators (KPIs) set out the metrics that help the board and leadership team assess bp’s
performance. Our leadership team uses all these measures to evaluate operating performance
and inform its financial, strategic and operating decisions.
Financial
Total shareholder return (%) l | |||
2025 | 24.4 16.7 | ||
2024 | (11.9) (11.0) | ||
2023 | 5.9 2.6 | ||
2022 | 36.9 50.1 | ||
2021 | 36.4 36.4 | ||
ADS basis Ordinary share basis   |
Total shareholder return (TSR) represents the
change in value of a bp shareholding over a
calendar year (American Depositary Share
(ADS) in USD, ordinary share in GBP). It
assumes that dividends are reinvested to
purchase additional shares at the closing
price on the ex-dividend date.
2025 performance
Improved TSR reflects year-on-year growth
in dividend per share and an increase in the
share price.
Operational
Oil and gas production (mboe/d) | |||
2025 | 2,312 | ||
2024 | 2,358 | ||
2023 | 2,313 | ||
2022 | 2,253 | ||
2021 | 2,218 | ||
Oil and gas production tracks how our projects
are helping grow our business. We report
production of crude oil, condensate, natural
gas liquids (NGLs), natural bitumen and natural
gas on a volume per day basis for our
subsidiaries and equity-accounted entities.
Natural gas is converted to barrels of oil
equivalent at 5,800 standard cubic feet of
natural gas = 1 boe.
2025 performance
2025 reported production was down
compared with 2024 mainly due to the
divestments in Egypt and Trinidad in the fourth
quarter of 2024 and base decline, partly offset
by major projects« start-ups and growth in
bpx energy.
Upstream unit production costs ($/boe) | |||
2025 | 6.28 | ||
2024 | 6.17 | ||
2023 | 5.78 | ||
2022 | 6.07 | ||
2021 | 6.82 | ||
The upstream unit production cost is
calculated as production cost divided by units
of production. Production cost does not
include ad valorem and severance taxes. Units
of production are barrels for liquids« and
thousands of cubic feet for gas. Amounts
disclosed are for bp subsidiaries only and do
not include bp’s share of equity-accounted
entities.
2025 performance
Unit production costs was slightly higher,
mainly due to portfolio mix.
Key | ||
l | Used for remuneration policy | |
TCFD | TCFD Recommendations and Recommended Disclosures | |
Remuneration To help align the focus of the bp leadership team and executive directors with the interests of our shareholders, certain measures are used for executive remuneration. | ||
| Directors’ remuneration report, page 91 | |
bp Annual Report and Form 20-F 2025 | 15 |
| ||||
Strategic report | ||||
Upstream« plant reliability (%) | |||
2025 | 96.1 | ||
2024 | 95.2 | ||
2023 | 95.0 | ||
2022 | 96.0 | ||
2021 | 94.0 | ||
bp-operated upstream plant reliability 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 reservoirs). Unplanned
plant deferrals include breakdowns, which
does not include Gulf of America weather-
related downtime.
2025 performance
Delivered our record upstream plant reliability
in 2025.
Refining availability (%) | |||
2025 | 96.3 | ||
2024 | 94.3 | ||
2023 | 96.1 | ||
2022 | 94.5 | ||
2021 | 94.8 | ||
bp-operated refining availability represents
Solomon Associates’ operational availability
for bp-operated refineries. The measure shows
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 availability is an important indicator
of the operational performance of our
downstream businesses.
2025 performance
2025 refining availability was the best availability
on record at 96.3%, driven by strengthened
maintenance programmes, enhanced digital
monitoring and improved outage recovery.
Compared with 2024, it reflected improved
reliability and notably the absence of the
Whiting refinery power outage.
Refining throughputs (mb/d) | |||
2025 | 1,440 | ||
2024 | 1,394 | ||
2023 | 1,411 | ||
2022 | 1,504 | ||
2021 | 1,594 | ||
Refinery throughputs are based on the
quantity of crude and condensate processed
per day. It represents the actual volume fed
into the refinery’s distillation units.
2025 performance
Refining throughputs in 2025 increased
compared with 2024, reflecting the absence of
the Whiting refinery power outage in 2024.
16 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Key performance indicators continued | ||||
Safety and non-financial
Tier 1 and 2 process safety events«ab l | |||
2025 | 27 | ||
2024 | 38 | ||
2023 | 39 | ||
2022 | 50 | ||
2021 | 62 | ||
Tier 1 process Tier 2 process safety events safety events |
We track tier 1 and tier 2 events and report the
aggregated outcome. 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 (per API RP 754 tier 1 definitions). Tier
2 events are those of lesser consequence (per
API RP 754 tier 2 definitions).
2025 performance
Our combined tier 1 and tier 2 process safety
events (PSEs) have decreased for the last 12
years, apart from in 2019. In 2025 there were
27 PSEs, down from 38 in 2024. Tier 1 events
increased to five (2024 three) and
tier 2 events decreased to 22 (2024 35),
see page 55.
Reported recordable injury frequency«a | |||
2025 | 0.234 | ||
2024 | 0.297 | ||
2023 | 0.274 | ||
2022 | 0.187 | ||
2021 | 0.164 | ||
Reported recordable injury frequency (RIF)
measures the number of reported work-
related employee and contractor incidents
that result in a fatality or injury per 200,000
hours worked.
2025 performance
In 2025 our RIF decreased by 21%. This
reduction is encouraging, but we know we
must continue improving our safety
performance, including through applying the
IOGP Life-Saving Rules and our Safety
Leadership Principles. For more on safety,
see page 55.
Women in group leadershipcd (%) | |||
2025 | 37 | ||
2024 | 35 | ||
2023 | 34 | ||
2022 | 33 | ||
2021 | 32 | ||
Our people are crucial to delivering our
purpose and strategy. We aim to recruit
talented people with diverse perspectives,
backgrounds, skills and experiences, invest
in their development and promote an
inclusive culture.
Each year we report the percentage of women
in group leadership.
2025 performance
The percentage of women in group leadership
increased to 37% in 2025, continuing an
upward trend over the previous five years.
Employee engagementce (%) | |||
2025 | 66 | ||
2024 | 70 | ||
2023 | 73 | ||
2022 | 70 | ||
2021 | 64 | ||
We conduct a Pulse annual employee survey
to understand and monitor levels of
employee engagement and identify areas
for improvement.
2025 performance
Key | |||
l | Used for remuneration policy | ||
TCFD | TCFD Recommendations and Recommended Disclosures | ||
The 2025 Pulse annual survey, which ran in
September, saw our engagement score
decrease. The results reflect the significant
organizational changes happening across bp.
We continue to build engagement plans based
aExclusions to safety metrics – tier 1 and 2 process safety events and recordable injuries may occur in entities that have
been recently acquired or where bp has recently taken full ownership have been granted a deviation from specific
reporting requirements in bp’s Operating Management System (OMS)★ for an initial transitional period. As such, data from
Archaea Energy, TravelCenters of America, Lightsource bp, bp bioenergy, X Convenience and new Eagle Ford assets in bpx
energy are not included in 2025 reported data.
bThe metric includes reported PSEs occurring within bp’s operational HSSE reporting boundary. That boundary includes
bp’s own operated facilities and joint ventures where bp is the operator. In some cases, we may also provide information
about some joint venture activities where bp is not the operator.
cRelates to bp employees.
dGroup leaders are our most senior leaders. Their roles include operational, functional and regional leadership.
eAs a result of changes to the question set and the inclusion of employees from our retail business in the 2025 Pulse survey,
the engagement score for 2025 is not comparable with prior years.
on survey feedback and on real-time updates
from our monthly snapshot, Pulse live, see
page 57.
bp Annual Report and Form 20-F 2025 | 17 |
| ||||
Strategic report | ||||
GHG emissionsabcde – operational control (MtCO2e) l TCFD | |||
2025 | 34.3 | ||
2024 | 33.6 | ||
2023 | 32.1 | ||
2022 | 31.9 | ||
2021 | 35.6 | ||
Scope 1 (direct) Scope 2 (indirect) emissions emissions |
We report Scope 1 and Scope 2 greenhouse
gas (GHG) emissions material to our business
on a carbon dioxide-equivalent basis. This KPI
comprises Scope 1 (from running the assets
within our operational control boundary) and
Scope 2 (associated with importing electricity,
heating and cooling that is bought in to run
those operations) data covered by our net zero
operations« aim (to be net zero« across our
operations by 2050 or sooner). It comprises
100% of Scope 1 and 2 emissions or activities
within bp’s operational control boundary.
2025 performance
In 2025 our combined Scope 1 and 2 emissions
increased due to growth in our portfolio and
project start-ups. Scope 1 (direct) emissions
were 33.7MtCO2ede – an overall increase from
32.8MtCO2e in 2024.
Of these Scope 1 emissions, 32.8MtCO2e were
carbon dioxide and 0.9MtCO2e were from
methane. In 2025 our Scope 2f (indirect)
emissions decreased by 0.1MtCO2e, to
0.7MtCO2e, compared with 2024, see page 37.
Basis of calculationb
bp’s reported GHG emissions include methane
(CH4) and carbon dioxide (CO2). Other GHGs
are not included as they are not material to our
operations. CH4 emissions are converted to
CO2 equivalent using the 100-year global
warming potential recommended by the
Fifth Assessment Report (AR5) of the
Intergovernmental Panel on Climate
Change (IPCC).
Data are required to be submitted into the bp
group reporting tool in accordance with bp’s
Operating Management System« (OMS)
requirements, broadly following the GHG
Protocol Corporate Standard and the Ipieca
Petroleum Industry Guidelines for Reporting
Greenhouse Gas Emissions 2nd Edition, May
2011. The responsibility for quantifying and
submitting GHG emissions for reporting is
assigned to individual bp facilities and
business departments, which are termed
reporting units (RUs).
Methane intensityag (%) TCFD | |||
2025 | 0.04 | ||
2024 | 0.07 | ||
2023 | 0.05 | ||
2022 | 0.05 | ||
2021 | 0.07 | ||
We define methane intensity« as the amount
of methane emissions from our upstream oil
and gas operations as a percentage of the gas
that goes to market from those operations.
This applies to methane emissions within our
operational control boundary, where we have
the highest degree of control. Methane
emissions from non-producing activities, such
as exploration drilling, are excluded. In 2024
we started reporting methane intensity based
on our new measurement approach across our
major operated oil and gas assets.
2025 performance
Our methane intensity was 0.04% in 2025. and
the methane emissions from our upstream
operations used to calculate this intensity
were 25kt (2024 46kt), see page 38.
Basis of calculationb
All operated upstream assets report methane
(CH4) emissions on a 100% basis, including
emissions from operated upstream oil and gas
and also includes terminals and LNG facilities.
Marketed gas production: all upstream gas
reaching a market from bp-operated upstream
assets, whether or not this is bp-owned
product, and includes gas production from
natural gas wells and associated gas from oil
production wells. Throughput from bp-
operated oil and gas terminals is excluded to
avoid double counting despite their associated
CH4 emissions being included in the metric.
CH4 data are required to be submitted into the
bp group reporting tool, in accordance with
aThese are our KPIs for the purposes of our disclosures pursuant to the UK CFD Regulations 2022 and Section 414CB (2A) (h) of
the Companies Act 2006.
bIncluded as part of disclosures pursuant to the UK CFD Regulations.
cTotal (100%) Scope 1 (direct) GHG emissions from source activities operated by bp or otherwise within bp’s operational control
boundary. bp’s reported GHG emissions include CH4 and CO2.
dDue to rounding some totals may not agree exactly to the sum of their component parts..
e In 2025 bp made an adjustment to the operational control boundary for Scope 1 and 2 GHG emissions. This means certain
operations, assets or sources which were previously included such as power generation on contractor-operated drilling rigs
are now excluded. This change has a less than 1% impact on reported operational emissions. For more information on the
scope of bp’s operational control boundary see bp.com/basisofreporting.
fScope 2 emissions on a market basis, covered by bp’s net zero operations aim.
gPrior to 2024 these emissions were calculated using a different methodology and therefore the methane intensity reported in
those years and calculated using that data does not directly correlate to progress towards delivering the 2025 target. Prior
year data is provided for information purposes, and we do not seek to directly compare prior years.
OMS requirements, broadly following the GHG
Protocol Corporate Standard and the Ipieca
Petroleum Industry Guidelines for Reporting
Greenhouse Gas Emissions 2nd Edition, May
2011. The responsibility for quantifying and
submitting CH4 emissions for reporting is
assigned to individual bp facilities and
business departments (RUs).
18 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Our financial frame | ||
Strengthening the balance sheet to
manage and grow the business
Our financial frame sets out how we allocate the cash we generate to deliver dividends to
shareholders, strengthen our balance sheet and invest with discipline to grow the value of bp.
Dividend
The resilient dividend is our first capital
allocation priority. For the second quarter
2025, our dividend per ordinary share
increased by 4% from 8.000 to 8.320 cents.
Based on our current forecasts and subject to
the board’s discretion each quarter, the
dividend is expected to increase by at least 4%
per ordinary share a year.
Strengthening the balance sheet
We are committed to strengthening the
balance sheet and continue to target
improving credit metrics within an ‘A’ grade
credit range. We reiterate our primary target
for net debt« of $14-18 billion by the end
of 2027.
During 2025, finance debt decreased from
$59.5 billion to $58.0 billion and net debt
decreased from $23.0 billion to $22.2 billion.
When considering our capital structure, we
also look at other instruments including hybrid
bonds and securities or obligations such as
leases and Gulf of America settlement
liabilities. At year-end 2025 the total of net
debt, hybrid bonds and securities, leases and
Gulf of America settlement liabilities was
$57.8 billion.
Following a decision by the board at the fourth
quarter 2025 results announcement to
suspend share buybacks, excess cash« will
now be fully allocated to the balance sheet, in
service of optimizing financing costs and to
accelerate strengthening of the balance sheet.
Disciplined investment
We will continue to invest with discipline,
driven by value, and focused on delivering
returns.
Investment is allocated across our businesses
based on a set of criteria that balances
strategic alignment, hurdle rates, volatility,
integration value, sustainability and risk
(see page 22).
In 2025 capital expenditure« was $14.5 billion.
We expect capital expenditure to be $13.0-13.5
billion in 2026. This includes expenditure on
inorganic opportunities. We believe this level
of capital expenditure supports progressively
growing earnings per ordinary share in the
long term.
Share buybacks
We announced share buybacks of $2.25 billion
for 2025 and shareholder distributions,
comprising dividends and buybacks, were
around 30%b of our 2025 operating
cash flow«.
At the fourth quarter 2025 results in February
2026, the board decided to suspend share
buybacks and fully allocate excess cash to
accelerate strengthening of the balance sheet,
optimizing financing costs and improving
cash flow.
| | ||||||||||
Our financial frame | |||||||||||
Shareholder distributions | Balance sheet | Capital expenditure | |||||||||
Resilient dividend Expect annual increase of the dividend per ordinary share of at least 4%a | $14-18bn Net debt target by end 2027 | $13.0-13.5bn in 2026 | |||||||||
‘A’ range credit metrics through cycle | Disciplined investment allocation, assessed against a set of balanced criteria | ||||||||||
| | ||||||||||
aShareholder distribution decisions, including dividends and share buybacks, are subject to board discretion, taking into account factors including, but not limited to, current forecasts
and credit metrics.
bIncludes all share buybacks and dividends announced for 2025. The dividend announced for the fourth quarter 2025 amount is estimated.
bp Annual Report and Form 20-F 2025 | 19 |
| ||||
Strategic report | ||||
Our investor proposition: a simpler, stronger and more valuable bp As we reflect on our progress in 2025 and look forward to the future, we are aligned around our conviction in bp’s potential to grow significant long-term shareholder value and we are in action to simplify and strengthen the company. |
Strong operational performance | Strengthening the balance sheet | Improving capital discipline | Driving to top quartile on costs | Growing cash flow and returns | ||||||||||
A simpler bp Continuing to focus on high grading the portfolio. Record asset uptime; exploration success; focusing downstream; seven project start-ups; driving deeper and faster on cost and capital efficiency. Performance interventions delivered in 2025, giving us strong momentum into 2026. | A stronger bp Fully allocate excess cash« to the balance sheet. Target to reduce net debt« to $14-18 billion by end 2027. Target $5.5-6.5 billiona of structural cost reductions« by end 2027. | A more valuable bp Target of >20%b CAGR adjusted free cash flow growth« from 2024-2027 and expected progressive dividend growth of at least 4%c per annum. Group ROACE« target of >16%b by end 2027. Deep upstream resource base combined with disciplined investment criteria – well positioned to deliver medium and long-term organic growth. | ||||
All underpinned by our commitment to safety in everything we do. | ||||||
| Our strategy and primary targets, page 8 |
2026 guidance
2026 guidance | 2025 actual | ||
Upstream reported production (guidance is both reported and underlying production«) | Reported production to be slightly lower/underlying production to be broadly flat compared with 2025 | 2.3mmboe/d | |
Total capital expenditure« | $13-13.5bn, weighted to the first half | $14.5bn | |
Depreciation, depletion and amortization | Broadly flat compared with 2025 | $17.8bn | |
Divestments and other proceedsd | $9-10bn, including approximately $6bn from the announced Castrol transaction, all significantly weighted to the second half | $5.3bn | |
Gulf of America oil spill paymentse (pre-tax) | Around $1.6bn pre-tax, of which $0.4bn in the first quarter and $1.1bn in the second quarter | $1.2bn | |
Other businesses & corporate underlying annual charge | Around $1bn | $0.6bn | |
Underlying effective tax rate« | Around 40%f | 42%g |
aFollowing the outcome of the strategic review of Castrol, which resulted in the decision to divest a 65% shareholding, the $4-5 billion structural cost reduction target by end 2027, introduced at the
February 2025 Capital Markets Update, has increased.
bThis is on a price adjusted basis that assumes a hypothetical price environment of $70/bbl Brent, $4/mmBtu Henry Hub, and $10.3/bbl refining indicator margin (all 2024 real) and assumptions
about the impact of these marker prices on underlying replacement cost profit before tax.
cShareholder distribution decisions, including dividends and share buybacks, are subject to board discretion, taking into account factors including, but not limited to, current forecasts and credit metrics.
dDivestment proceeds are disposal proceeds as per the group cash flow statement. See page 26 for more information on divestment and other proceeds.
eSee Financial statements – Note 22 for more information on payables related to the Gulf of America oil spill.
fUnderlying effective tax rate is sensitive to the impact that volatility in the current price environment may have on the geographical mix of the group’s profits and losses.
gNon-IFRS measure and its nearest IFRS equivalent measure for 2025 is effective tax rate of 83%.
The guidance above contains forward-looking statements and should be read in conjunction with the cautionary statement on page 362.
20 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Our investment process | ||
How we use price assumptions
Our price assumptions are used for our
investment appraisal processes. They are also
used to inform decisions about internal
planning and for value-in-use impairment
testing of assets for financial reporting.
The role of price assumptions
Our decisions on individual investments are
informed by our view of the price environment
and consider the balanced investment criteria
discussed below.
Our price assumptions continue to reflect a
range of possibilities, including that the
transition to a lower carbon economy and
energy system could accelerate. Our
investment appraisal assumptions, which take
a long-term perspective, focus on the
fundamental trends affecting the energy
sector and our businesses.
From February 2025 until January 2026, we
held our key investment appraisal price
assumptions constant at the levels set out in
the bp Annual Report and Form 20-F 2024. For
relevant investment cases assessed from
February 2026, we have applied and plan to
apply the prices shown in the key investment
appraisal assumptions table (right) for our
central price case. Brent oil and Henry Hub gas
assumptions average around $67/bbl and
$4.4/mmBtu respectively (2024 $ real) from
2026 to 2050.
We consider these prices to be broadly
consistent with a range of transition paths
compatible with meeting the Paris goals, but
they do not correspond to any specific Paris-
consistent scenario. We also consider a
range of other price assumptions in
investment appraisals, including product
and market-specific prices relevant to
individual investment cases.
We apply carbon prices rising from $67/tCO2e
in 2026 to $135/tCO2e in 2030 and $200/
tCO2e by 2050 (2024 $ real) in certain cases
(see box, right).
Impairment testing
Our best estimate of future prices for use in
value-in-use impairment testing continues to
be based on our investment appraisal price
assumptions, with quarterly review of near-
term prices to confirm that the assumptions
appropriately reflect any changes to
expectations due to short-term market trends.
Impairment price assumptions were held
constant in 2025 at the levels disclosed in the
bp Annual Report and Form 20-F 2024 until
the fourth quarter, when the updated
investment appraisal price assumptions
shown below were used for value-in-use
impairment testing.
Key investment appraisal assumptionsa TCFD | ||||
2024 $ real | 2030 | 2040 | 2050 | |
Brent oil ($/bbl) | 70 | 67 | 60 | |
Henry Hub gas ($/mmBtu) | 4.1 | 4.5 | 4.5 | |
Refining indicator margin (RIM)b« ($/bbl) | 12.0 | 8.5 | 5.0 | |
In addition to the prices shown we also test whether investments meet our return expectations (see page 22) using $60/bbl Brent oil price series. | ||||
Carbon price TCFD | ||||
2024 $ real | 2030 | 2040 | 2050 | |
Carbon ($/tCO2e) | 135 | 175 | 200 | |
a The values in the table represent the central case. b The disclosed RIM assumptions in the table exclude carbon pricing impacts and assume a normalized cost of renewable identification numbers (RINs). | ||||
For investment appraisal, potential future
operational emissions costs that may be borne
by bp as a result of an investment are included
as bp costs, as described in the box below
(generally without assuming incremental
revenue associated with those emissions), in
order to incentivize engineering solutions that
reduce operational carbon emissions from
projects. For the treatment of emission cost
assumptions in value-in-use impairment
testing, see Financial statements – Note 1.
| | |||
Investment process price assumptions | ||||
All investments are evaluated against relevant price assumptions for oil, natural gas, refining margins or other commodities across a range of alternative price or margin series (typically a central, upper and lower series). In addition, all investment cases with anticipated annual operational GHG emissions (Scope 1 and 2) above 20,000 tonnes of CO2 equivalent (bp net), must estimate those anticipated GHG emissions and include an associated carbon cost in the investment economics, using the carbon prices above. Our investment price assumptions place some weight on scenarios in which the transition to a low carbon energy system is sufficiently rapid to meet the goals of the Paris Agreement, as well as scenarios in which the transition may not be sufficiently rapid. They also place some weight on a range of other factors that can drive prices, and which are not directly related to the Paris goals. | These price assumptions do not link to specific scenarios or outcomes, but instead try to capture the range of different possibilities surrounding the future path of the global energy system. The nature of the uncertainty means that the price ranges inevitably reflect considerable judgement. The ranges are reviewed and updated as necessary, as our understanding of and judgements about the energy transition evolve. In addition to consideration of a range of price assumptions, investment cases also assess the impact of alternative assumptions covering other selected variables relevant to the economics of the investment. These variables may include cost, schedule, resources, policy changes, or other areas of uncertainty, to assess the robustness of investment cases to a range of other factors. | |||
| | |||
Key | |
TCFD | Information that supports TCFD Recommendations and Recommended Disclosures in relation to Metrics and Targets |
bp Annual Report and Form 20-F 2025 | 21 |
| ||||
Strategic report | ||||
Investment governance and
evaluating consistency with the
Paris goals
Governance framework
bp’s framework for investment governance
seeks to ensure that investments align with
our strategy, can be accommodated within our
prevailing financial frame, and add shareholder
value. It enables investments to be assessed in
a consistent way against a range of criteria
relevant to our strategy, including
sustainability criteria.
Investments follow an integrated stage-gate
process designed to enable our businesses
to choose and develop the most attractive
investment cases. A balanced set of
investment criteria are considered (see
page 22). This allows for the comparison and
prioritization of investments across a diverse
range of business models.
The governance framework specifies that
proposed investments are evaluated using
relevant assumptions, including carbon prices
for projected operational emissions where
applicable. It also sets out requirements for
assurance by functions independent of the
business before a final investment decision
(FID) is taken.
Our investment framework also includes
processes to review investment outcomes.
During construction, and for two years after
start-up, major project investments are
included in an annual effectiveness of
investment review, which tracks investments’
delivery against the assumptions used in their
investment cases. Key findings are shared with
the board. Around two years after completion,
investments above defined financial
thresholds also prepare a post project
evaluation to share lessons learned across bp
businesses – including reviews of strategic,
commercial, and technical assumptions,
decisions, and delivery.
The role of the board
The board assesses capital allocation across
the bp portfolio, including the level and mix of
capital expenditures« and divestments,
strategic acquisitions, distribution choices and
deleveraging, as well as reviewing certain
investment cases for approval.
Resource commitment meeting
For acquisitions and organic capital
investments above defined financial
thresholds, investment approval is conducted
through the executive-level resource
commitment meeting (RCM), which is chaired
by the chief executive officer. The RCM reviews
the merits of each investment case against a
balanced set of criteria (see page 22) and
considers any key issues raised in the
assurance process.
The CA100+ resolution« requires bp to
disclose how we evaluate the consistency of
new material capex investments« with (i) the
Paris goals and (ii) a range of other outcomes
relevant to bp’s strategy.
bp’s evaluation of the consistency of such
investments with the Paris goals was
undertaken by the RCM for new material capex
investments sanctioned in 2025 (see page 23).
bp’s evaluation of an investment’s consistency
with ‘a range of other relevant outcomes’ is
achieved by considering its merits against bp’s
balanced investment criteria, described on
page 22.
| | |
bp board Reviews and approves investment cases of more than $3 billion for resilient hydrocarbons, more than $1 billion for all transition or low carbon investments« and any significant inorganic acquisition that is exceptional or unique in nature. | ||
 | ||
Resource commitment meeting Forum for executive management’s review and approval of investments related to existing and new lines of business above $250 million, or $25 million for acquisitions, or which exceed the relevant EVP’s financial authority, and any project considered strategically important such as a new market entry. | ||
| ||
Investment allocation committees EVP-level forums to review and approve investment cases within a business group as per individual EVP financial authority (up to $250 million, or typically $25 million for acquisitions). | ||
| ||
Business group investment governance meetings SVP-level forums that review and approve investment cases within a business group or function, up to the individual SVP’s financial authority. | ||
| ||
Cross-group meetings Forums that facilitate discussions across businesses and functions, to support project development, sensitivity analysis, integration opportunities and risk assessment ahead of investment committee meetings. | ||
| |
Transition business investment
bp set out anticipated investment in transition
businesses« through to 2027 as part of our
reset strategy in February 2025. This
investment was $2.3 billion in 2025 including
$0.8 billion of inorganic spend.
EV charging: In EV charging, we are focusing
investment in four core markets – Germany,
UK, China and the US, with joint ventures in the
Iberian region and India. We are utilizing our
retail network to maximise returns. And we
opened new ultra-fast« charging hubs at
major airports in the US.
Bioenergy: We completed the commercial
integration of bp bioenergy, including the final
deferred capital payment. We continued to
scale biofuels but allocated capital only where
projects are economically robust and aligned
with demand progression. Consistent with this
approach, we took the decision to stop further
work on the development of a standalone
biofuels production (HEFA) facility at our
Rotterdam refinery in the Netherlands. In
January 2026, we also announced the launch
of Etlas, a new 50:50 joint venture with
Corteva to produce oil from crops for use in
the production of biofuels such as sustainable
aviation fuel (SAF) and renewable diesel (RD),
see page 35.
Our biogas business, Archaea Energy,
continued its growth, starting up eight new
renewable natural gas (RNG)« landfill plants
in 2025.
Low carbon energy: We focused our low
carbon energy portfolio, prioritizing
investment choices that deliver value for
shareholders. In December we completed the
sale of our US onshore wind business, bp Wind
Energy, to LS Power. And we formed JERA Nex
bp, a 50:50 joint venture between JERA and
bp, focused on offshore wind development,
ownership and operations, see page 9.
Hydrogen and carbon capture and storage
(CCS): We continued to refine our portfolio,
including the decisions not to progress
H2Teesside and to end our participation in
projects in Oman, Australia and the US Gulf
Coast. In 2025 we focused on delivering four
projects sanctioned in 2024: Lingen green
hydrogen« project, Castellón green hydrogen
project, the Northern Endurance Partnership
(NEP), and Net Zero Teesside Power (NZT).
22 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Our investment process continued | ||
Balanced investment criteria
All investment cases must set out their
investment merits and are considered against
a set of six balanced investment criteria –
although investment decisions may also take
other factors into account as appropriate. This
standardized approach is intended to create a
level playing field for decision making and
allows portfolio-wide comparisons of
investment cases. The decision to endorse an
investment based on the information provided
represents our evaluation that it is consistent
with what the 2019 CA100+ resolution« refers
to as “a range of other outcomes relevant to
bp’s strategy”.
The six balanced investment criteria are:
Strategic alignment: For all investment cases,
we consider whether the investment supports
delivery of our strategy, including our net zero
aims. We also assess if the investment case
involves distinctive capability that bp has, or
intends to develop, and whether it adds to an
existing ‘scale’ business within the portfolio or
could help us create one.
Safety and risks: For all investment cases, we
provide an assessment of the key risks to the
investment that have a significantly higher
probability than usual or have a significantly
greater impact (relative to the size of the
project) were they to occur. Safety risk
management at bp is underpinned by our
Operating Management System« (OMS), which
is designed to help us sustainably deliver safe,
reliable and compliant bp operations.
Sustainability: For all investment cases,
we consider how any proposed business
opportunity is connected to the energy
transition, societal needs and the environment.
This approach is underpinned by our purpose
and sustainability frame. All RCM cases must
consider significant impacts of an investment
on bp’s sustainability aims, informed by our
sustainability assessment template for
investment cases (for our use of carbon prices,
see box on page 20).
Investment economics: For all investment
cases, we consider investment economics
against a range of relevant measures.
Depending on the nature of the investment
case, these may include return expectations
(e.g. internal rate of return or IRR), net present
value, discounted payback and profitability
index, reflecting assumptions about relevant
commodity prices, margins and carbon prices
(see page 20). The forward economics of an
investment case are considered against
relevant economic indicators at the time of the
investment decision. We may also refer to
these expectations as hurdle rates, although
as noted, each case is assessed according to
its combined merit against our full set of
balanced criteria.
1.For our upstream business (including
biogas), we seek an IRR of 15%.
2.For our downstream business (including EV
charging and biofuels), we seek portfolio-
level returns in excess of 15%.
For investments in hydrogen and CCS, we
expect levered returns in the mid-teens,
including farm-down and integration value.
For any investment, the relevant return
expectations above are assessed using our
central price assumptions. For additional
capital discipline for investments in oil and gas
production, we also compare the central price
hurdle above (15%) to a case in which the Brent
oil price starts at $60/bbl and later declines
to the level of our key appraisal assumptions
by 2050 (see page 20). In addition, for
investments in our oil and gas and refined
products businesses, as well as any other
investments that do not fall within one of
the specific businesses set out above, we
compare the IRR in our lower-price case
to a cost of capital hurdle rate.
Volatility and rateability: Our investment
economics metrics also consider the degree
of uncertainty of the cash flows when
considering investment cases. For example,
some cases have more certainty of future
costs and revenue projections. Variation in
net present values for the key variables in an
investment case are quantified by sensitivity
analysis to give a range of potential outcomes
against our key investment hurdles.
Optionality and integration: Our assessment
considers the degree of optionality offered by
a project – the ability to adapt our business to
changing circumstances. This could be an
option to sell a product with a floor price, or
the right to purchase additional equity in a
joint venture at specific terms. Other types of
options include the right to develop (or not
develop) extensions to existing projects, or to
change the course of a project’s development
depending on market circumstances. We
likewise seek out integration along value
chains across multiple products, services,
geographies and customers. For example, our
gas production can supply liquefaction plants
whose LNG is monetized by our trading
business. Likewise, carbon sequestration
projects may allow us to add value to our gas
production by reducing carbon intensity.
Paris consistency evaluation process
Our new material capex investments«
are intended to support the delivery of
bp’s strategy.
For evaluations conducted in 2025,
investments in scope for evaluation were
defined as:
•New: investment in a new project, or
extension of an existing project/asset, or
share of an entity that is new to bp, or a
substantial increase in bp’s share.
•Material: more than $250 million capex
investment.
Quantitative evaluations
For our investment economics and
sustainability investment criteria we
considered quantitative guide levels, as set
out below, to inform the evaluation of each
investment’s consistency with the goals of the
Paris Agreement. For evaluations in 2025 we
used the central price IRR and other economic
hurdles, as set out in the bp Annual Report and
Form 20-F 2024 (page 22). As in previous years,
we used our operational carbon intensity« as a
guide level, reflecting our portfolio average.
As our approach matures with experience, we
may continue to adjust or supplement our
methodology. There may be instances when
new material capex investments are evaluated
as consistent with the Paris goals despite
either the economic or sustainability guide
levels not being met. The RCM may also take
account, in its Paris consistency evaluation, of
the six balanced investment criteria using
qualitative assessments.
Investment economics: We calculated
economic indicators using our central price,
and where applicable, our lower price cases,
and applying our carbon price assumptions to
relevant operational GHG emissions. (For our
current key central case oil and natural gas
price assumptions, see page 20, where we also
set out our view on their consistency with
achieving the Paris goals). We then compared
the economic indicators to the relevant
economic guide level (see below), based on
the corresponding hurdles. We typically target
a threshold of >1.0x the relevant IRR guide
level, as set out in the bp Annual Report and
Form 20-F 2024 (page 22).
Sustainability: Where appropriate, we
compared the operational carbon intensity of
the investment (on the basis of equity share)
to the portfolio average equity share GHG
emissions intensity shown in the bp ESG
Datasheet 2024 for the relevant business
activity (Exploration, production and LNG).
We normally target a ratio of less than 100%,
meaning that the investment is expected to
reduce the average operational carbon
intensity of the relevant portfolio. The potential
impact of new material capex investments on
bp’s net zero aims is a further consideration.
bp Annual Report and Form 20-F 2025 | 23 |
| ||||
Strategic report | ||||
Evaluation outcome
In 2025 eight new material capex investments were approved. All were evaluated as being consistent with the Paris goals, taking into account both
quantitative and qualitative evaluations and the balanced criteria above.
| | ||||||||||
Evaluation of investment performance against quantitative guide levels All eight investments exceeded the IRR guide level as shown in the chart. Six of the eight investments had emissions intensities below the relevant intensity guide level. Of the remaining two investments, one produces gas that is processed at an existing LNG facility, with overall emissions intensity (including midstream onshore processing) higher than our overall portfolio average, but upstream-only emissions that are below portfolio average. This investment was supported taking into account our qualitative assessment, including the role LNG plays in the energy transition – especially in the Asia Pacific region – and the strength of the investment economics. We do not show a carbon intensity for the eighth investment because bp does not have any ownership interest in the asset or any right to the production. | Investment economics Against central price IRR hurdle | Sustainability Against operational carbon intensity | |||||||||
| | ||||||||||
Decisions taken in 2025
In 2025 there were eight new material capex
investment decisions evaluated for Paris
consistency, described here approximately
in the order the investment decisions
were made:
Ginger: We sanctioned the Ginger gas
development in Trinidad and Tobago. Ginger
will be our fourth subsea project in the country
and will be tied back to our existing Mahogany
B platform. First gas from the project is
expected in 2027, making Ginger one of
bp’s 10 major projects expected to start up
between 2025 and 2027. At peak, the
development is expected to have the capacity
to produce average gas production of 62,000
barrels of oil equivalent per day.
KGD6 Infill Wells: We approved investment
in drilling four offshore infill gas wells in the
KGD6 block in India to be brought online
in 2028. The infill wells target incremental
production, benefiting from the use of
existing infrastructure.
Guide
Shah Deniz Compression: In June bp and its
partners agreed the final investment decision
for the $2.9 billion Shah Deniz Compression
project. The project is designed to access and
produce low pressure gas resources from the
field, increasing resource recovery and
extending production life. The project is
expected to allow production of around an
additional gross 50 billion cubic metres of gas
and 25 million barrels of condensate. The
project is expected to receive first gas in 2029.
Atlantis Major Facility Expansion: The Atlantis
Major Facility Expansion project aims to
enhance production at the Atlantis field by
injecting water into targeted reservoirs to help
access harder-to-reach barrels. We plan to
start up the facility in 2027.
Kirkuk redevelopment: In 2025 bp agreed
with the government of Iraq to help redevelop
several fields in Kirkuk, in the north of Iraq.
We will work initially with Iraq’s North Oil
Company and North Gas Company to
stabilize and grow production. Work will
include a drilling programme, rehabilitation
of existing wells and facilities, and
construction of new infrastructure,
including gas expansion projects.
Guide
Tiber and Guadalupe: In September we took
a final investment decision on bp’s Tiber and
Guadalupe developments in the Gulf of
America, approving its second new production
platform in less than two years in the critical
US offshore region. Production from the new
floating production platform, which is
expected to have the capacity to produce
80,000 barrels of crude oil per day, is
expected to start in 2030.
Greater Western Flank 4: We approved infill
investment in the Greater Western Flank 4
development in Australia’s North West Shelf.
This is a five‑well subsea programme tied back
to existing infrastructure to help sustain
reliable gas supply to regional markets.
Juniper Wells: We approved investment in
decompletion of three existing wells, along
with drilling and completion of three single
zone sidetracks in Trinidad and Tobago. The
infill programme is expected to deliver around
19mmboe, with the first gas expected in 2027.
24 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Group performance | ||
Building for the future
Financial and operating performance | ||||
$ million except per share amounts | ||||
2025 | 2024 | 2023 | ||
Sales and other operating revenues | 189,335 | 189,185 | 210,130 | |
Profit before interest and tax | 12,642 | 11,297 | 27,348 | |
Finance costs and net finance income/expense relating to pensions and other post-employment benefits | (4,896) | (4,515) | (3,599) | |
Taxation | (6,451) | (5,553) | (7,869) | |
Profit (loss) for the year | 1,295 | 1,229 | 15,880 | |
Non-controlling interest | (1,240) | (848) | (641) | |
Profit (loss) for the year attributable to bp shareholders | 55 | 381 | 15,239 | |
Inventory holding (gains) losses«, before tax | 1,351 | 488 | 1,236 | |
Taxation charge (credit) on inventory holding gains and losses | (334) | (119) | (292) | |
Replacement cost (RC) profit (loss)« | 1,072 | 750 | 16,183 | |
Net (favourable) adverse impact of adjusting items«a, before tax | 5,885 | 9,344 | (1,143) | |
Total taxation charge (credit) on adjusting items | 528 | (1,179) | (1,204) | |
Underlying RC profit | 7,485 | 8,915 | 13,836 | |
Adjusted EBITDA« | 37,615 | 38,012 | 43,710 | |
Dividend paid per ordinary share (cents) | 32.640 | 30.540 | 27.760 | |
Dividend paid per ordinary share (pence) | 24.509 | 23.720 | 22.328 | |
Profit per ordinary share (cents) | 0.35 | 2.38 | 87.78 | |
Profit per ADS (dollars) | 0.02 | 0.14 | 5.27 | |
Underlying RC profit per ordinary share« (cents) | 48.02 | 54.40 | 79.69 | |
Underlying RC profit per ADS« (dollars) | 2.88 | 3.26 | 4.78 | |
Adjusting itemsa | ||||
Gains on sale of businesses and fixed assets | 987 | 670 | 361 | |
Net impairment and losses on sale of businesses and fixed assets | (6,035) | (6,930) | (5,838) | |
Environmental and related provisions | (656) | (181) | (647) | |
Restructuring, integration and rationalization costs | (520) | (222) | 37 | |
Fair value accounting effects (FVAEs)b | 2,220 | (1,852) | 9,403 | |
Gulf of America oil spill | (31) | (51) | (57) | |
Other | (1,422) | (273) | (1,711) | |
Total before interest and taxation | (5,457) | (8,839) | 1,548 | |
Finance costs | (428) | (505) | (405) | |
(5,885) | (9,344) | 1,143 | ||
Adjusting items total taxation | (528) | 1,179 | 1,204 | |
(6,413) | (8,165) | 2,347 | ||
aSee page 336 for more information. bSee page 337 for information on the cumulative impact of FVAEs. | ||||
| | |
$0.1bn profit attributable to bp shareholders (2024 profit $0.4bn) $7.5bn underlying replacement cost (RC) profit« (2024 profit $8.9bn) $24.5bn operating cash flow« (2024 $27.3bn) | ||
| |
bp Annual Report and Form 20-F 2025 | 25 |
| ||||
Strategic report | ||||
At 31 December 2025 the group’s reportable
segments are gas & low carbon energy, oil
production & operations and customers &
products. Each is managed separately, with
decisions taken for the segment as a whole,
and represent a single operating segment that
does not result from aggregating two or more
segments. See Financial statements – Note 5
Segmental analysis.
Results
The profit for the year ended 31 December
2025 attributable to bp shareholders was $0.1
billion, compared with $0.4 billion in 2024.
After adjusting profit attributable to bp
shareholders for inventory holding losses and
a net adverse impact of adjusting items,
underlying RC profit for the year ended
31 December 2025 was $7.5 billion. The result
reflected lower liquids realizations, lower gas
marketing and trading result, partly offset by
stronger performance in customers &
products. The oil trading contribution was
broadly flat.
For 2024, after adjusting profit attributable to
bp shareholders for inventory holding losses
and a net adverse impact of adjusting items
underlying RC profit was $8.9 billion. The result
reflected lower refining margins, lower
realizations, a lower gas marketing and trading
result and a lower oil trading contribution,
partly offset by lower taxation.
For a discussion of bp’s financial and
operating performance for the years ending
31 December 2023 and 31 December 2024,
see bp Annual Report and Form 20-F 2024,
pages 24-37.
Adjusting items
In 2025 the net adverse pre-tax impact of
items, which bp has classified as adjusting
(adjusting items) was $5.9 billion including:
•Favourable fair value accounting effects
(FVAEs) relative to management’s measure
of performance of $2.2 billion primarily
related to a favourable impact of FVAEs
relating to the hybrid bonds and to the
relative decline in LNG forward prices over
the period in addition to the realization of
gains as cargoes were delivered. The
impacts of FVAEs relative to management’s
internal measure of performance are
provided on page 337.
•Net impairment and losses on sale of
businesses and fixed assets includes net
impairment charges of $5.4 billion which
primarily relate to Lightsource bp and
Archaea Energy.
•In addition, $1.4 billion net impairment
charges, of which $1.1 billion primarily
relates to the Archaea Energy and offshore
wind businesses, were reported through
equity-accounted earnings (reported within
the ‘other’ category).
In 2024 the net adverse pre-tax impact of
adjusting items was $9.3 billion including:
•Adverse FVAEs relative to management’s
measure of performance of $1.9 billion
primarily due to an increase in the forward
price of LNG during 2024, compared to a
decline in 2023, and the adverse impact
of the FVAEs relating to the hybrid bonds
in 2024.
•Net impairment and losses on sale of
businesses and fixed assets includes a loss
of $1.1 billion relating to the sale of the
ground fuels business in Türkiye (see
Financial statements – Note 2) and net
impairment charges of $5.1 billion (see
Financial statements – Note 4).
•In addition, $0.5 billion net impairment
charges were reported through equity-
accounted earnings (reported within the
‘other’ category).
•The ‘other’ category also includes a $0.5
billion gain relating to the remeasurement
of bp’s pre-existing 49.97% interest in
Lightsource bp and a $0.5 billion gain
relating to the remeasurement of certain
US assets excluded from the Lightsource
bp acquisition (see Financial statements –
Note 3 for further information); and
recognition of onerous contract provisions
related to the Gelsenkirchen refinery. The
unwind of these provisions will be reported
as an adjusting item as the contractual
obligations are settled.
See Financial statements – Note 4 for more
information on impairments, and pages 336
and 337 for more information on adjusting
items and FVAEs.
Taxation
The charge for corporate income taxes was
$6,451 million in 2025 compared with $5,553
million in 2024. The effective tax rate (ETR) on
the profit before taxation for the year in 2025
was 83%, compared with 82% in 2024. The ETR
on the profit before taxation for the year in
2025 and 2024 was impacted by fair value
accounting effects and other adjusting items,
including limited tax relief on impairment
charges. Excluding inventory holding gains or
losses and adjusting items, the underlying
ETR« in 2025 was 42% compared with 41%
in 2024.
Underlying ETR is a non-IFRS measure. A
reconciliation to IFRS information is provided
on page 384.
Outlook for 2026
2026 guidance
•bp expects reported upstream« production
to be slightly lower and underlying
upstream production« to be broadly flat
compared with 2025. 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 expects to
make continued progress growing cash
flows, supported by lower underlying
operating expenditure« driven by
structural cost reductions«. These benefits
will be partly offset by the earnings impact
of completed and announced divestments.
Reported earnings will benefit from lower
depreciation as a result of the assets held
for sale accounting treatment of Castrol
following the planned divestment. Fuel
margins are expected to remain sensitive to
movements in the cost of supply.
•In products, bp expects significantly lower
level of turnaround activity.
•bp expects other businesses & corporate
underlying annual charge to be around
$1.0 billion for 2026. The charge may vary
from quarter to quarter.
•The underlying ETR for 2026 is expected 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.
26 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Group performance continued | ||
Cash flow and debt information | ||||
$ million | ||||
2025 | 2024 | 2023 | ||
Cash flow | ||||
Operating cash flow« | 24,493 | 27,297 | 32,039 | |
Net cash used in investing activities | (11,504) | (13,250) | (14,872) | |
Net cash provided by (used in) financing activities | (15,880) | (7,297) | (13,359) | |
Cash and cash equivalents at end of yeara | 36,624 | 39,269 | 33,030 | |
Capital expenditure«b | (14,533) | (16,237) | (16,253) | |
Divestment and other proceedsc | 5,314 | 4,224 | 1,843 | |
Debt | ||||
Finance debt | 57,958 | 59,547 | 51,954 | |
Net debt« | 22,182 | 22,997 | 20,912 | |
Net debt including leases« | 35,686 | 34,909 | 31,902 | |
Finance debt ratio« (%) | 43.9% | 43.2% | 37.8% | |
Gearing« (%) | 23.1% | 22.7% | 19.7% | |
Gearing including leases« (%) | 32.5% | 30.8% | 27.2% | |
a2025 and 2024 include $68 million and $65 million respectively of cash and cash equivalents classified as assets held for sale in the group balance sheet. bAn analysis of capital expenditure by segment and region is provided on page 335. cDivestment proceeds are disposal proceeds as per the group cash flow statement. See below for more information on divestment and other proceeds. | ||||
Operating cash flow
Operating cash flow for the year ended
31 December 2025 was $24.5 billion, $2.8 billion
lower than 2024. Compared with 2024,
operating cash flows in 2025 primarily reflected
working capital movements partly offset by
higher profits from operations and lower
tax payments.
Movements in working capital« adversely
impacted cash flow in the year by $4.8 billion,
including an adverse impact from the Gulf of
America oil spill of $1.1 billion. Other working
capital effects were principally an increase in
derivative assets. bp actively manages its
working capital balances to optimize and
reduce volatility in cash flow.
Operating cash flow for the year ended
31 December 2024 was $27.3 billion, $4.7 billion
lower than 2023. Compared with 2023,
operating cash flows in 2024 primarily reflected
lower profits from operations partly offset by
working capital movements.
Movements in working capital favourably
impacted cash flow in 2024 by $4.0 billion,
including an adverse impact from the Gulf of
America oil spill of $1.1 billion. Other working
capital effects were principally a decrease in
other current assets.
Net cash used in investing activities
Net cash used in investing activities for the
year ended 31 December 2025 decreased by
$1.7 billion compared with 2024.
The decrease mainly reflected a decrease in
expenditure on fixed assets reflecting the
phasing of spend within the lower capital frame
for 2025 partly offset by deferred acquisition
payments.
Total capital expenditure for 2025 was $14.5
billion (2024 $16.2 billion), of which organic
capital expenditure« was $13.6 billion (2024
$16.1 billion). Inorganic capital expenditure for
2025 includes the final payment for the bp
Bunge Bioenergia 2024 acquisition. Inorganic
capital expenditure for 2024 includes the cash
acquired net of acquisition payments on
completion of the bp Bunge Bioenergia and
Lightsource bp acquisitions. Sources of funding
are fungible, but the majority of the group’s
funding requirements for new investment
comes from cash generated by existing
operations. bp expects capital expenditure of
around $13-13.5 billion in 2026.
Total divestment and other proceeds for 2025
amounted to $5.3 billion, including amounts
received from the sale of the US onshore wind,
Netherlands mobility & convenience and bp
pulse businesses. Other proceeds for 2025
consist of $1.5 billion from the sale of non-
controlling interests in the Permian and Eagle
Ford midstream assets and $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).
Total divestment and other proceeds for 2024
amounted to $4.2 billion, including $0.9 billion
from the sale of receivables and $0.7 billion cash
received, both relating to prior divestments, and
$0.6 billion relating to the formation of Arcius
Energy. Other proceeds for 2024 consist of
$0.8 billion of proceeds from the sale of a non-
controlling interest in the subsidiary that holds
our 20% share in Trans Adriatic Pipeline AG (TAP)
and $0.5 billion of proceeds from the sale of a
49% interest in a controlled affiliate holding
certain midstream assets offshore US.
bp expects divestment and other proceeds to
be $9-10 billion in 2026, including approximately
$6 billion from the announced Castrol
transaction.
Net cash provided by (used in)
financing activities
Net cash used in financing activities for the year
ended 31 December 2025 was $15.9 billion,
compared with $7.3 billion in 2024. Compared
with 2024, financing cash flows in 2025 primarily
reflected net repayments compared to net
proceeds from the issuance and repayment of
finance debt, and lower receipts from the issue
of perpetual hybrid bonds, partly offset by a
decrease in share buybacks, and an increase in
receipts relating to transactions involving non-
controlling interests.
In 2025, 836 million ordinary shares (2024
1,238 million) were repurchased for a total cost
of $4.5 billion (2024 $7.1 billion), including
transaction costs of $24 million (2024 $38
million). Of these, 176 million shares repurchased
were cancelled and 659 million shares were held
as treasury shares.
Total dividends paid to shareholders in 2025
were 32.640 cents per share, 2.10 cents higher
than 2024. This amounted to total dividends
paid to shareholders of $5.1 billion in 2025 (2024
$5.0 billion). The board decided not to offer a
scrip dividend alternative in respect of the 2025
and 2024 dividends.
Debt
Finance debt at the end of 2025 decreased by
$1.6 billion from the end of 2024 primarily
reflecting net repayments of long-term finance
debt, partly offset by changes in fair value where
hedge accounting is applied. The finance debt
ratio at the end of 2025 increased to 43.9% from
43.2% at the end of 2024.
Net debt at the end of 2025 decreased by $0.8
billion from the 2024 year-end position. Gearing
at the end of 2025 increased to 23.1% from 22.7%
at the end of 2024. Net debt and gearing are
non-IFRS measures. See Financial statements –
Notes 26 and 27 for further information on
finance debt and net debt.
For information on financing the group’s
activities see Financial statements – Note 29
and Liquidity and capital resources on page 338.
bp Annual Report and Form 20-F 2025 | 27 |
| ||||
Strategic report | ||||
Group reserves and productiona | ||||
2025 | 2024 | 2023 | ||
Estimated net proved reserves (net of royalties) | ||||
Liquids (mmb) | 3,447 | 3,699 | 3,747 | |
Natural gas (bcf) | 15,916 | 14,786 | 17,471 | |
Total hydrocarbonsb (mmboe) | 6,191 | 6,248 | 6,759 | |
Of which: | ||||
Equity-accounted entitiesb | 1,330 | 1,377 | 1,437 | |
Production (net of royalties) | ||||
Liquids (mb/d) | 1,199 | 1,166 | 1,115 | |
Natural gas (mmcf/d) | 6,450 | 6,914 | 6,944 | |
Total hydrocarbons (mboe/d) | 2,312 | 2,358 | 2,313 | |
Of which: | ||||
Subsidiaries | 1,931 | 2,008 | 1,967 | |
Equity-accounted entities | 380 | 350 | 345 | |
aBecause of rounding, some totals may not agree exactly with the sum of their component parts. bSee Supplementary information on oil and natural gas on page 241 for further information. | ||||
Total hydrocarbon proved reserves at
31 December 2025, on an oil equivalent basis
including equity-accounted entities,
decreased by 1% compared with 31 December
2024 (0.2% decrease for subsidiaries and 3%
decrease for equity-accounted entities).
Natural gas increased by 8% (10% increase for
subsidiaries and 3% decrease for equity-
accounted entities).
There was a net increase from acquisitions and
disposals of 27mmboe within our US and North
Sea subsidiaries.
Total hydrocarbon production for the group
was 2% lower compared with 2024. The
decrease comprised a 3.8% decrease (3.5%
increase for liquids and 9.7% decrease for gas)
for subsidiaries and an 8.6% increase (0.8%
increase for liquids and 37.0% increase for gas)
for equity-accounted entities.
28 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Gas & low carbon energy | ||
Gas & low carbon energy segment comprises our gas & low carbon businesses. Our gas business
includes regionsa with upstream activities that predominantly produce natural gas, gas trading and
our Archaea Energy business. Our low carbon business includes solar, offshore wind, hydrogen
and CCS, and power trading, and until its divestment in December 2025 also included onshore
wind. Power trading and marketing includes trading of both renewable and non-renewable power.
Financial and operating performance | ||||
$ million | ||||
2025 | 2024 | 2023 | ||
Sales and other operating revenuesb | 40,333 | 32,628 | 50,297 | |
Profit before interest and taxc | 1,330 | 3,052 | 14,081 | |
Inventory holding (gains) losses« | — | — | (1) | |
RC profit before interest and taxc | 1,330 | 3,052 | 14,080 | |
Net (favourable) adverse impact of adjusting items«cd | 4,037 | 3,751 | (5,358) | |
Underlying RC profit before interest and tax« | 5,367 | 6,803 | 8,722 | |
Taxation on an underlying RC basis | (1,972) | (2,137) | (2,730) | |
Underlying RC profit before interest | 3,395 | 4,666 | 5,992 | |
Depreciation, depletion and amortization | 4,969 | 4,835 | 5,680 | |
Exploration write-offs | 30 | 222 | 362 | |
Adjusted EBITDA«e | 10,366 | 11,860 | 14,764 | |
Capital expenditure« | ||||
Gasf | 2,946 | 4,246 | 3,517 | |
Low carbon energy | 464 | 1,596 | 1,256 | |
3,410 | 5,842 | 4,773 | ||
aThe Azerbaijan-Georgia-Türkiye and Middle East and North Africa (MENA) regions have been further subdivided by asset to allow reporting in either gas & low carbon or oil production & operations as appropriate. bIncludes sales to other segments. c2024 has been restated for material items to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment. dSee page 337 for information on the cumulative impact of FVAEs. eA reconciliation to RC profit before interest and tax is provided on page 388. f2024 and 2023 have been restated to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment. | ||||
Financial results
Sales and other operating revenues for 2025
are higher than 2024 mainly due to higher gas
marketing and trading revenues partly offset
by lower volumes.
RC profit before interest and tax for 2025 was
$1,330 million compared with $3,052 million
for 2024.
In 2025 items which bp has classified as
adjusting had a net adverse impact of $4,037
million including favourable fair value
accounting effects (FVAEs)« of $1,270 million,
relative to management’s view of performance,
and net impairment charges of $4,038 million,
primarily relating to Lightsource bp and
Archaea Energy. In addition, $1,082 million
impairment charge was recognized through
equity-accounted earnings, primarily relating
to Archaea Energy and offshore wind
businesses.
After adjusting RC profit for the net impact of
items which bp has classified as adjusting,
underlying RC profit before interest and tax for
2025 was $5,367 million, compared with $6,803
million for 2024. The decrease reflects the
divestments in Egypt and Trinidad in the fourth
quarter of 2024, a lower gas marketing and
trading result, and a higher depreciation,
depletion and amortization charge, partly
offset by lower exploration write-offs and the
absence of the foreign exchange loss in Egypt
in the first quarter of 2024.
In 2024 items which bp has classified as
adjusting had a net adverse impact of $3,751
million including adverse FVAEs of $1,550
million, relative to management’s view of
performance, partly offset by a gain of $1,006
million as a result of remeasurement of our
previously existing interest and related assets
on the step-acquisition of Lightsource bp
(LSbp).
See Financial statements – Note 4 and Note 16
for further information on net impairment
charges.
Operational update
Reported production for 2025 was 785mboe/d,
11.6% lower than the same period in 2024.
Underlying production« for the full year was
2.1% lower, mainly due to base decline partly
offset by major projects« start-ups.
Strategic progress
Gas
In April we safely loaded the first cargo of
liquefied natural gas (LNG) for export from its
GTA Phase 1 project offshore Mauritania and
Senegal – see the case study on page 29 for
more information.
In May we 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 together with our partners, we
announced the 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 Trinidad and Tobago we have made progress
on our growth projects – see the case study, on
page 29 for more information.
In Egypt we have made progress on growing
our portfolio:
•In February we began production from
the second development phase of the
Raven field.
•In March we announced the successful
completion of drilling operations at the El
Fayoum-5 gas discovery well in the North
Alexandria Offshore Concession. This was
the final well in our four-slot drilling
campaign in the West Nile Delta (WND) and
our second consecutive gas discovery
following El King-2 well in the North King
Mariout Offshore Concession.
•In September we signed a memorandum of
understanding (MoU) to evaluate
opportunities for a five-well programme in
the Mediterranean Sea.
•In January 2026 we were awarded two
offshore exploration concession: North-East
El Alamein Offshore and West El Hammad
Offshore, advancing our exploration
portfolio and long-term growth ambitions.
bp Annual Report and Form 20-F 2025 | 29 |
| ||||
Strategic report | ||||
In November the Greater Western Flank 4
project in the North West Shelf, offshore
Australia (bp 16.67%, operator Woodside)
reached FID. The project involves five subsea
tieback wells with start-up targeted for 2028.
Biogas
In December Archaea Energy and Osaka Gas
Trading and Export entered into an agreement
for the procurement of approximately
26,000Nm³ of biomethane derived from landfill
gas, produced at Archaea Energy’s facilities
operating in the US.
During the fourth quarter Archaea Energy
started up two renewable natural gas (RNG)«
landfill plants (Middle Point and NW Tennessee)
bringing the total to eight landfill plants started-
up in 2025, with a total capacity of more than 6
million mmBtu. Since 2023 Archaea Energy has
added a total of 19 landfill plants and total
capacity of 18 million mmBtu per year.
LNG portfolio
On the supply side, bp has had strong growth in
2025 with the start-up commissioning and
subsequent strong performance at the Greater
Tortue Ahmeyim Phase 1 LNG export project in
Mauritania and Senegal, in which bp is the
operator. 19 cargoes were lifted by bp’s ST&S
organization – which has 100% offtake rights
from the project.
Venture Global announced Commercial
Operations Date for bp’s long-term contract
from Calcasieu Pass as 15 April, since which bp
has lifted all the long-term cargoes made
available to it under this agreement.
Portfolio growth also occurred in the sales
portfolio with the start-up of the second power
plant within the GNA JV’s integrated regas
terminal and power plant at Porto do Acu in
Brazil’s Rio de Janeiro state, owned by bp,
Prumo and Siemens. The project is owned by
bp, Prumo, Siemens and SPIC and bp has 100%
supply rights to this facility.
A number of globally diverse long term sales to
third parties were also signed in 2025, for
example a long-term sale with A2A into Italy –
increasing diversification to our portfolio; a
long-term sale agreed with Torrent Power into
India – expanding customer portfolio; a long
term sale with Zhejiang Energy in China –
building on our regional experience; and a
three-year sale to Türkiye’s Botas – deepening
customer relationships in key demand centres.
See Oil and gas disclosures for the group on
page 340 for more information on oil and gas
operations in the regions.
Low carbon energy
In 2025 we took action to focus our portfolio
and further high-grade our projects – both
through partnerships, to create capital light
joint ventures – and through divestments,
making strong progress on the programmes
that are driving focus and reducing costs.
Hydrogen and carbon capture and storage
In 2025 we focused on delivering four projects
sanctioned in 2024: Lingen green hydrogen«
project, Castellón green hydrogen project, the
Northern Endurance Partnership (NEP), and Net
Zero Teesside Power (NZT).
We continued to refine our hydrogen and
carbon, capture and storage (CCS) portfolio.
This included decisions not to progress
H2Teesside and to end participation in projects
in Oman, Australia and the US Gulf Coast.
Renewables and power
Offshore wind
In August 2025 we formed JERA Nex bp, a
50:50 offshore wind joint venture between
JERA and bp. The new JV brings together each
parties’ complementary expertise for a
balanced mix of operating assets and
development projects.
Onshore renewables
In February 2025 we announced our intention
to bring a strategic partner into our solar
business, LSbp.
LSbp continues to be a leading global onshore
renewable developer in markets with attractive
sector returns.
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, investors in the
Sangachal terminal sanctioned the linked
Sangachal terminal electrification project.
In December we completed the sale of our US
onshore wind business, bp Wind Energy, to LS
Power. The transaction included 10 operating
assets across seven US states.
 | ||
LNG milestone We safely loaded the first cargo of LNG for export from our Greater Tortue Ahmeyim (GTA) Phase 1 project offshore Mauritania and Senegal. By the end of 2025 we delivered 19 cargoes for export. Phase 1 includes one of Africa’s deepest subsea structures, with wells located in water depths of up to 2,850 metres (9,350 feet). Image: Aerial image of GTA in the Atlantic Ocean | ||
 | | |
 | ||
Progress in Trinidad and Tobago We marked four major milestones in Trinidad and Tobago in 2025. In March we sanctioned the Ginger gas development and confirmed exploration success at Frangipani. The Cypre project delivered first gas in April. And Mento, a joint venture with EOG Resources, delivered first gas in May. Image: Mento platform, Trinidad and Tobago | ||
| | |
aFrom 2025 we intend to report our biogas business as part of the gas & low carbon energy segment.
30 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Gas & low carbon energy continued | ||
Estimated net proved reserves and productiona (net of royalties) | ||||
2025 | 2024 | 2023 | ||
Estimated net proved reserves (net of royalties) | ||||
Crude oilb (mmb) | 100 | 113 | 128 | |
Natural gas liquids (mmb) | — | 1 | 1 | |
Total liquids«c | 101 | 115 | 129 | |
Natural gasc (bcf) | 6,366 | 6,965 | 8,635 | |
Total hydrocarbons«c (mmboe) | 1,198 | 1,316 | 1,618 | |
Of which equity-accounted entitiesd: | ||||
Liquids (mmb) | 1 | 1 | — | |
Natural gas (bcf) | 162 | 196 | — | |
Total hydrocarbons (mmboe) | 29 | 35 | — | |
Production (net of royalties) | ||||
Crude oilb (mb/d) | 75 | 88 | 96 | |
Natural gas liquids (mb/d) | 10 | 8 | 9 | |
Total liquids (mb/d) | 85 | 96 | 105 | |
Natural gas (mmcf/d) | 4,059 | 4,596 | 4,778 | |
Total hydrocarbons (mboe/d) | 785 | 888 | 929 | |
Of which equity-accounted entitiese: | ||||
Liquids (mb/d) | 5 | 2 | 2 | |
Natural gas (mmcf/d) | 165 | 9 | — | |
Total hydrocarbons (mboe/d) | 34 | 4 | 2 | |
Average realizations«f | ||||
Liquids ($/bbl) | 65.50 | 75.37 | 77.03 | |
Natural gas ($/mcf) | 6.60 | 5.90 | 6.13 | |
Total hydrocarbons ($/boe) | 41.34 | 38.57 | 40.21 | |
aBecause of rounding, some totals may not agree exactly with the sum of their component parts. bIncludes condensate and bitumen. cIncludes 1.7 million barrels of total liquids (1.7 million barrels at 31 December 2024 and 2.2 million barrels at 31 December 2023) and 231 billion cubic feet of natural gas (219 billion cubic feet at 31 December 2024 and 430 billion cubic feet at 31 December 2023) in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. dbp’s share of reserves of equity-accounted entities in the gas & low carbon energy segment. ebp’s share of production of equity-accounted entities in the gas & low carbon energy segment. fRealizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities. | ||||
 | ||
Operations in Oman Block 61 in Oman (bp operated with a 40% equity stake) delivered strong operational performance in 2025. Technical enhancements enabled the site to reach its highest-ever gas flow rate. We operate two drilling rigs, underpinning our development programme and acquiring key data to inform the reservoir’s potential. A major turnaround was delivered eight days earlier than the scheduled time, supported by new robotic tools that reduced confined‑space work and improved reliability and efficiency. Block 61 has the capacity to supply a third of Oman’s domestic natural gas demand. Image: Block 61, Oman | ||
| | |
bp Annual Report and Form 20-F 2025 | 31 |
| ||||
Strategic report | ||||
Oil production & operations | ||||
Oil production & operations segment comprises regionsa with upstream activities that predominantly produce crude oil, including bpx energy. | ||||
Financial and operating performance | ||||
$ million | ||||
2025 | 2024 | 2023 | ||
Sales and other operating revenuesb | 24,527 | 25,637 | 24,904 | |
Profit before interest and tax | 8,560 | 10,780 | 11,191 | |
Inventory holding (gains) losses« | (2) | 9 | — | |
RC profit before interest and tax | 8,558 | 10,789 | 11,191 | |
Net (favourable) adverse impact of adjusting items« | 856 | 1,148 | 1,590 | |
Underlying RC profit before interest and tax« | 9,414 | 11,937 | 12,781 | |
Taxation on an underlying RC basis | (4,409) | (5,165) | (5,998) | |
Underlying RC profit before interest | 5,005 | 6,772 | 6,783 | |
Depreciation, depletion and amortization | 7,719 | 6,797 | 5,692 | |
Exploration write-offs | 313 | 544 | 384 | |
Adjusted EBITDA«c | 17,446 | 19,278 | 18,857 | |
Capital expenditure« | 6,760 | 6,198 | 6,278 | |
aThe Azerbaijan-Georgia-Türkiye and Middle East and North Africa (MENA) regions have been further subdivided by asset to allow reporting in either gas & low carbon or oil production & operations as appropriate. bIncludes sales to other segments. cA reconciliation to RC profit before interest and tax is provided on page 388. | ||||
Financial results
Sales and other operating revenues for 2025
were lower than 2024 mainly due to lower
realizations partially offset by higher volumes.
RC profit before interest and tax for 2025 was
$8,558 million compared with $10,789 million
for 2024.
Adjusting items for 2025 had a net adverse
impact of $856 million principally relating to
net impairment charges. See Financial
statements – Note 4 and Note 16 for further
information on net impairment charges.
After adjusting RC profit for the net adverse
impact of adjusting items, underlying RC profit
before interest and tax for 2025 was $9,414
million, compared with $11,937 million for 2024.
The lower profit reflects lower liquids
realizations, lower share of net income of
equity-accounted entities, a higher
depreciation, depletion and amortization
charge, partly offset by higher volumes and
lower exploration write-offs.
Adjusting items for 2024 had a net adverse
impact of $1,148 million mainly relating to net
impairment charges. See Financial statements
– Note 4 and Note 16 for further information on
net impairment charges.
Operational update
Reported production for 2025 was
1,527mboe/d, 3.8% higher than the same
period of 2024. Underlying production« for the
year was 2.6% higher compared with the same
period of 2024 reflecting bpx energy
performance.
Strategic progress
•In April bp announced a Miocene oil
discovery at the Far South prospect in the
US Gulf of America. bp drilled the
exploration well in Green Canyon Block 584
approximately 120 miles off the coast of
Louisiana in 4,092 feet of water. The well
was drilled to a total depth of 23,830 feet.
The Far South co-owners are bp (operator,
57.5%) and Chevron U.S.A. Inc. (42.5%).
•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
December the development programme
for the Karabagh field in the Caspian Sea,
offshore Azerbaijan, was approved by the
management committee (joint venture) and
subsequently by State Oil Company of the
Azerbaijan Republic (SOCAR) as the State
representative. Seismic acquisition
commenced thereafter.
 | ||
Bumerangue discovery In August 2025 bp reported a significant hydrocarbon discovery at the Bumerangue well in Brazil’s Santos Basin. Bumerangue is one of 12 exploration discoveries we made in 2025, across several basins, including the Gulf of America and Namibia, through Azule Energy, our 50:50 independent joint venture with Eni. Image: Valaris renaissance drill ship | ||
| | |
 | | |
Kirkuk contract goes live In October 2025 bp’s contract with Iraq’s North Oil Company and North Gas Company became effective, after agreeing an initial baseline production rate of 328,000 barrels per day. Under the contract we will invest in the redevelopment of several giant oil fields in Kirkuk, in the north of Iraq. | ||
| |
32 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Oil production & operations continued | ||
•Azule Energy, bp’s 50% joint venture, made
the following progress during the year:
–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.
–In July Azule Energy, 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 Energy, 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.
–In October Rhino Resources, operator of
the Petroleum Exploration Licence 85 in the
Orange Basin offshore Namibia, partnering
with Azule Energy, announced a discovery
at the Volans 1-X well.
•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%).
•In September bp announced it has reached
a final investment decision (FID) on the
Tiber-Guadalupe project in the Gulf of
America. The 100% bp-owned Tiber-
Guadalupe will be bp’s seventh operated oil
and gas production hub in the Gulf of
America, featuring a new floating
production platform with the capacity to
produce 80,000 barrels of crude oil per
day. The project includes six wells in the
Tiber field and a two-well tieback from the
Guadalupe field. Production is expected to
start in 2030.
•In October bp agreed to sell its 32% non-
operated working interest in the Culzean
development in the central North Sea to
Serica Energy. NEO Next exercised its
option to acquire bp’s stake on the same
terms as those agreed by Serica. In
December bp completed the divestment of
the Culzean gas field in the UK North Sea to
NEO Next.
•In December bp successfully delivered first
oil from the Atlantis Drill Center 1 expansion
project in the US Gulf of America, its
seventh global upstream major project«
start-up of the year. The two-well subsea
tieback to the existing Atlantis platform is
expected to add 15,000boe/d gross peak
annualized average production.
See Oil and gas disclosures for the group on
page 340 for more information on oil and gas
operations in the regions.
 | ||
Permian basin progress Our US onshore oil and gas business, bpx energy, completed Crossroads, its fourth central delivery facility in the Permian Basin. We also completed the sale of our non-controlling interests in Permian and Eagle Ford midstream assets to Sixth Street for $1.5 billion, while bpx energy remains the operator. The transaction supports our divestment programme targeting $20 billion by 2027. Image: bpx energy midstream facility, US | ||
| | |
bp Annual Report and Form 20-F 2025 | 33 |
| ||||
Strategic report | ||||
Estimated net proved reserves and productiona (net of royalties) | ||||
2025 | 2024 | 2023 | ||
Estimated net proved reserves (net of royalties) | ||||
Crude oilb (mmb) | 2,908 | 3,112 | 3,193 | |
Natural gas liquids (mmb) | 439 | 472 | 426 | |
Total liquids | 3,346 | 3,584 | 3,618 | |
Natural gas (bcf) | 9,550 | 7,821 | 8,836 | |
Total hydrocarbons« (mmboe) | 4,993 | 4,932 | 5,142 | |
Of which equity-accounted entitiesc: | ||||
Liquids (mmb) | 885 | 917 | 1,001 | |
Natural gas (bcf) | 2,410 | 2,467 | 2,527 | |
Total hydrocarbons (mmboe) | 1,301 | 1,342 | 1,437 | |
Production (net of royalties) | ||||
Crude oilb (mb/d) | 993 | 953 | 910 | |
Natural gas liquids (mb/d) | 121 | 117 | 100 | |
Total liquids (mb/d) | 1,114 | 1,070 | 1,010 | |
Natural gas (mmcf/d) | 2,391 | 2,318 | 2,165 | |
Total hydrocarbons (mboe/d) | 1,527 | 1,470 | 1,383 | |
Of which equity-accounted entitiesd: | ||||
Liquids (mb/d) | 272 | 272 | 269 | |
Natural gas (mmcf/d) | 438 | 431 | 432 | |
Total hydrocarbons (mboe/d) | 347 | 346 | 343 | |
Average realizations«e | ||||
Liquids ($/bbl) | 60.64 | 69.85 | 72.09 | |
Natural gas ($/mcf) | 3.69 | 2.55 | 4.17 | |
Total hydrocarbons ($/boe) | 49.45 | 53.96 | 58.34 | |
aBecause of rounding, some totals may not agree exactly with the sum of their component parts. bIncludes condensate and bitumen. cbp’s share of reserves of equity-accounted entities in the oil production & operations segment. During 2025 gas operations in Angola, Argentina, Bolivia, Mexico and Norway were conducted through equity-accounted entities. dbp’s share of production of equity-accounted entities in the oil production & operations segment. eRealizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities. | ||||
 | ||
North Sea start-up We safely started up production from the Murlach field in the UK North Sea in 2025. The two-well subsea tieback is expected to deliver peak net production of approximately 15,000 barrels of oil equivalent per day to the Eastern Trough Area Project (ETAP) hub, which has been operating for 27 years. Murlach was our sixth of seven major project start-ups in 2025. Image: Murlach in the North Sea | ||
| | |
34 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Customers & products | ||||
Customers & products segment comprises our customer-focused businesses, which include
convenience and retail fuels, EV charging, as well as Castrol, aviation, B2B, midstream and bp
bioenergy. It also comprises our products businesses which include refining and oil trading.
Financial and operating performance | ||||
$ million | ||||
2025 | 2024 | 2023 | ||
Sales and other operating revenuesa | 148,783 | 155,401 | 160,215 | |
Profit (loss) before interest and taxb | 2,747 | (1,522) | 2,993 | |
Inventory holding (gains) losses« | 1,353 | 479 | 1,237 | |
Replacement cost (RC) profit (loss) before interest and taxb | 4,100 | (1,043) | 4,230 | |
Net (favourable) adverse impact of adjusting items«bc | 1,172 | 3,560 | 2,183 | |
Underlying RC profit before interest and tax« | 5,272 | 2,517 | 6,413 | |
Of which: | ||||
customers – convenience & mobility | 3,764 | 2,584 | 2,644 | |
Castrol – included in customers | 971 | 831 | 730 | |
products – refining & trading | 1,508 | (67) | 3,769 | |
Taxation on an underlying RC basis | (1,066) | (452) | (1,454) | |
Underlying RC profit before interest | 4,206 | 2,065 | 4,959 | |
Depreciation, depletion and amortization | 4,145 | 3,957 | 3,548 | |
Of which: | ||||
customers – convenience & mobility | 2,443 | 2,135 | 1,736 | |
Castrol – included in customers | 179 | 176 | 167 | |
products – refining & trading | 1,702 | 1,822 | 1,812 | |
Adjusted EBITDA«d | 9,417 | 6,474 | 9,961 | |
Of which: | ||||
customers – convenience & mobility | 6,207 | 4,719 | 4,380 | |
Castrol – included in customers | 1,150 | 1,007 | 897 | |
products – refining & trading | 3,210 | 1,755 | 5,581 | |
Capital expenditure« | 4,071 | 3,789 | 4,761 | |
Of which: | ||||
customers – convenience & mobility | 2,480 | 2,059 | 3,135 | |
Castrol – included in customers | 161 | 227 | 262 | |
products – refining & tradinge | 1,591 | 1,730 | 1,626 | |
aIncludes sales to other segments. b2024 has been restated for material items to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment. cSee page 337 for information on the cumulative impact of FVAEs. dA reconciliation to RC profit before interest and tax by business is provided on page 350. e2024 and 2023 have been restated to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment. | ||||
 | ||
X Convenience in Australia bp acquired X Convenience, an Australian fuel and convenience retailer. The move significantly increases our presence as a national network in Australia, with almost 50 additional sites strategically located in the south and west of the country. X Convenience gives fleets and consumers access to our bp fuel, convenience, and loyalty programmes, while retaining the strong X Convenience brand. Image: X Convenience site, Australia | ||
| | |
| | |
Engaging customers with earnify earnify — bp’s unified digital loyalty and rewards platform in the US — grew rapidly in 2025, surpassing 8 million members as active membership doubled since launch. By simplifying rewards, enhancing digital engagement, and improving margin delivery, earnify is becoming a scalable ecosystem strengthening customer loyalty and fueling future retail growth. | ||
| |
bp Annual Report and Form 20-F 2025 | 35 |
| ||||
Strategic report | ||||
Financial results
Sales and other operating revenues in 2025
were lower than in 2024, mainly due to lower
product prices.
RC profit before interest and tax for 2025
was $4,100 million, compared with a loss of
$1,043 million for 2024.
In 2025 items which bp has classified as
adjusting had a net adverse impact of $1,172
million (including adverse fair value accounting
effects of $207 million – relative to
management’s view of performance), of which
$913 million related to impairments of assets,
primarily in the products business, offset by
$317 million of gains on disposal of assets
and businesses. See Financial statements –
Note 4 for further information on disposals
and impairments.
After adjusting RC profit for the net adverse
impact of items, which bp classified as
adjusting, underlying RC profit before interest
and tax (underlying result) was $5,272 million,
compared with $2,517 million for 2024. The
result was significantly higher, reflecting
stronger performance both in customers
and products.
In 2024 items which bp has classified as
adjusting had a net adverse impact of $3,560
million (including adverse fair value accounting
effects of $81 million – relative to
management’s view of performance), of which
$1,143 million related to impairments of assets,
which included an impairment of the
Gelsenkirchen refinery and $1,267 million
related to loss on disposal, mainly related to
the Türkiye ground fuels business disposal.
Customers – the convenience and mobility
underlying result for 2025 was higher than
2024. The 2025 underlying result benefited
from stronger integrated performance across
fuels and midstream and lower underlying
operating expenditure« supported by
structural cost reductions«, as well as a
more than 15% increase in Castrol's
earnings with year-on-year growth for
10 consecutive quarters.
Products – the underlying result for 2025 was
significantly higher than 2024, primarily driven
by higher realized margins, the absence of the
first quarter 2024 plant-wide power outage at
the Whiting refinery and higher commercial
optimization. The results also benefited from
lower underlying operating expenditure driven
by structural cost reductions. The oil trading
contribution was broadly flat compared
with 2024.
Operational update
bp-operated refining availability for 2025 was
96.3%, higher compared with 94.3% in 2024,
mainly due to the absence of the Whiting
refinery power outage.
Strategic progress
In 2025 clear strategic focus and improved
execution strengthened returns and materially
increased our competitiveness. Early in 2025
we committed to growing our customers &
products adjusted operating cash flows«
having delivered around 60%a of our 2027
adjusted operating cash flow growth target
in 2025.
Reshaping our integrated portfolio
Alongside the divestments we completed or
announced, including Castrol, Netherlands
mobility, convenience and bp pulse
businesses, Austria retail, and Gelsenkirchen
refinery, we continued to focus on markets
where our integrated businesses provide the
greatest advantage. This included further high
grading of our retail network, exiting around
5% of our company owned sites as we
progress towards our target of around 10%
by 2027.
Focusing EV charging in priority markets
bp pulse continued to make progress with EV
charging investment now focusing primarily in
four core markets Germany, UK, China and the
US, with joint ventures in the Iberian region and
India. Aral pulse was named Germany’s best
charge point operator for the third
consecutive year and in the UK bp pulse
advanced its network reset programme and
extended its long-standing partnership with
Transport for London through 2029.
Progressing strategic choices in biofuels
Alongside the commercial integration of bp
bioenergy, in 2025 we continued to scale
biofuels but allocated capital only where
projects are economically robust and aligned
with demand progression.
We took the decision to stop further work on
development of a standalone biofuels
production (HEFA) facility at our Rotterdam
refinery in the Netherlands.
In action to improve performance
Customers delivered its highest underlying RC
profit before interest and tax since 2019 with
all businesses growing year-on-year.
Customers’ strong 2025 performance was
underpinned by a reduction in structural costs.
These reductions reflect sustained execution
across procurement, supply chain efficiencies,
organizational simplification and operating
model changes.
In 2025 air bp delivered sustainable aviation
fuel (SAF) in over 60 locations in 22 countries
driven by the requirement of both European
SAF mandates and customer voluntary
SAF demand.
Realizing value from recent customers
acquisitions
We continued to integrate and optimize our
recent acquisitions:
•We have completed the commercial
integration of bp bioenergy, a leading
sugarcane bioethanol producer – creating
a strong platform to deliver synergies and
improve value realization with trading.
•In our TravelCenters of America business,
we are progressing a targeted business
improvement plan, focused on
strengthening safety and operational
performance, sharpening commercial
discipline, and improving customer
delivery.
Strengthening refining availability and
competitiveness
In 2025 refining delivered the best availability
on record at 96.3%, driven by strengthened
maintenance programmes, enhanced digital
monitoring and improved outage recovery.
Higher availability has supported stronger
and more consistent margin capture across
the portfolio.
In refining structural cost reductions were
delivered through optimizing maintenance
activities and driving efficiencies across the
supply chain.
Taken together, these improvements resulted
in delivery of around 80% of our 2027 $3/bbl
cash breakeven reduction ambitionb.
| | |
Partnering in biofuels bp and Corteva, one of the world’s leading agriscience companies, launched Etlas – a new biofuels 50:50 joint venture. Etlas works with farmers to grow canola, mustard and sunflower crops for use in sustainable aviation fuel and renewable diesel. Etlas aims to grow a million tonnes of feedstock per year by the mid-2030s, enough for around 800,000 tonnes of biofuel. | ||
| |
aTaking growth against 2024 normalized for 2025 environmental conditions (refining margins and foreign exchange).
b2027 $3/bbl cash breakeven reduction ambition is defined as refining margin per barrel required to attain pre-tax breakeven operating cash flow excluding working capital movements,
normalized for turnaround activity levels, foreign exchange and energy prices; like-for-like portfolio.
36 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Other businesses & corporate | ||
Other businesses & corporate comprises technology, bp ventures, shipping, our corporate
activities & functions and any residual costs of the Gulf of America oil spill.
Financial and operating performance | ||||
$ million | ||||
2025 | 2024 | 2023 | ||
Sales and other operating revenuesa | 2,232 | 2,290 | 2,657 | |
Profit (loss) before interest and tax | (40) | (988) | (903) | |
Inventory holding (gains) losses« | — | — | — | |
Replacement cost (RC) profit (loss) before interest and tax | (40) | (988) | (903) | |
Net (favourable) adverse impact of adjusting items«b | (608) | 380 | 37 | |
Underlying RC profit (loss) before interest and tax« | (648) | (608) | (866) | |
Taxation on an underlying RC basis | 399 | 292 | 322 | |
Underlying RC profit (loss) before interest | (249) | (316) | (544) | |
Depreciation, depletion and amortization | 989 | 1,033 | 1,008 | |
Capital expenditure« | 292 | 408 | 441 | |
aIncludes sales to other segments. bSee page 337 for information on the cumulative impact of FVAEs. | ||||
Financial results
RC loss before interest and tax for 2025 was
$40 million, compared with $988 million
for 2024.
Adjusting items for 2025 had a net favourable
impact of $608 million. Adjusting items
include impacts of fair value accounting
effects, which had a favourable impact of
$1,157 million.
Adjusting items for 2024 had a net adverse
impact of $380 million. Adjusting items
include impacts of fair value accounting
effects, which had an adverse impact of
$221 million.
After adjusting RC loss for the adjusting items,
underlying RC loss before interest and tax for
2025 was $648 million, compared with a loss
of $608 million for 2024.
bp Annual Report and Form 20-F 2025 | 37 |
| ||||
Strategic report | ||||
Sustainability | ||||
Sustainability at bp
Our sustainability frame focuses on three areas – getting to net zero, improving people’s lives and caring for our planet.
Reporting on sustainability
In this section, we cover selected sustainability issues along with information in the following areas:
•Performance on our net zero aims, see page 37.
•Climate-related financial disclosures, see pages 41-54.
•Our approach – safety, ethics and compliance, our people, biodiversity, water, and ‘Who we are’ (our beliefs), see pages 55-59.
We provide an update on our actions on our aims, and our wider progress in relation to embedding sustainability,
in our latest Sustainability Report bp.com/sustainabilityreport.
| | |||||
Our sustainability aims We have five sustainability aims, focused on the areas we believe are most relevant to the long-term success of our business. | ||||||
Net zero operations Our aim is to reach net zero« by 2050 or sooner for Scope 1 and 2 emissions within bp’s operational controla, including by maintaining ‘near-zero’ methane intensity« across our operated producing assets, enabled by supportive government policies. See page 38. | Net zero sales Our aim is to reduce to net zero the average lifecycle carbon intensity of the energy products« we sell by 2050 or sooner, enabled by supportive government policies and the decarbonization of energy demand. See page 38. People Our aim is to support our employees and local communities through the energy transition. See page 59. | Biodiversity Our aim is to support biodiversity where we operateb. See page 59. Water Our aim is to reduce our net freshwater use in stressed catchments where we operate. See page 59. | ||||
| | |||||
Net zero
Our ambition remains to be a net zero
company by 2050 or sooner, and to help the
world get to net zero.
Both our net zero aims make explicit what is
needed to enable their delivery – and delivery
of the associated interim targets or aims.
Our future business and investment decisions,
which will affect the outcomes for these aims,
will be intended to facilitate delivery of our
strategy and investor proposition, applying our
balanced investment criteria, one of which
relates to sustainability.
We believe our net zero ambition and aims,
taken together, are consistent with the goals
of the Paris Agreement.
By setting a path that enables us to make a
positive contribution, working to build out and
participate in many of the new energy value
chains the world will need, and through our
efforts to reduce our overall operational
emissions, our ambition and aims support the
world’s progress towards the goals of the
Paris Agreement.
Net zero aims 2025 performance
Aims | Measure/coverage | 2019 | 2025 performance | 2025 targets | 2030 aims | Aims for 2050 or sooner | |
Net zero operations« | Scope 1+2 | Baseline 54.5MtCO2e | 37%cd | 20%c | 45-50%c | Net zero« | |
Methane intensity« | 0.14% | 0.04%e | 0.20% | Near zero | |||
Net zero sales« | Average lifecycle carbon intensity of sold energy products« | Baseline 84gCO2e/MJ | 7%f | 5%f | 8-10%f | Net zero | |
aOn a CO2e basis.
bAt our new in-scope bp-operated projects and major operating sites.
cReduction in absolute emissions against 2019 baseline.
dIn 2025 bp made an adjustment to the operational control boundary for Scope 1 and 2 GHG emissions. This means certain operations, assets or sources which were previously included, such
as power generation on contractor-operated drilling rigs, are now excluded. This change has a less than 1% impact on reported operational emissions. For more information on the scope of bp’s
operational control boundary see bp.com/basisofreporting.
eSince 2024 reported absolute methane emissions from major operated oil and gas processing sites are based on our new measurement approach. Prior to 2024 these emissions were
calculated using a different methodology and therefore the methane intensity reported in those years and calculated using that data does not directly correlate to progress towards delivering
the 2025 target.
fReduction in the average lifecycle carbon intensity of sold energy products against the 2019 baseline. The percentage change is calculated from the source data instead of the rounded carbon
intensity number.
38 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Sustainability continued | ||
Net zero operations TCFD
Our aim is to reach net zero by 2050 or sooner
for Scope 1 and Scope 2 emissions within bp’s
operational control including by maintaining
‘near-zero’ methane intensity« across our
operated producing assets, enabled by
supportive government policies.
We achieved a reduction of 37% against a
targeted 20% reduction in our operational
emissions by end-2025 and are aiming for a
45-50% reduction by the end of 2030, both
against our 2019 baseline.
New projects coming online add to the
challenge of reducing our operational
emissions. Continued investment in
abatement and further portfolio optimization
will be needed to meet our 2030 aim.
We also achieved our 2025 target for methane
intensity of 0.20%. Our methane intensity
for 2025 was 0.04%, compared with 0.07%
in 2024.
Scope 1 and 2 emissions
Our combined Scope 1 and 2 emissions were
34.3MtCO2eab in 2025 – an increase from
33.6MtCO2e in 2024 due to growth in our
portfolio and seven major project start-ups.
The total decrease in emissions to 2025
includes 18MtCO2e attributable to divestments
and 5.7MtCO2e in emissions reductions
activity.
In 2025 our Scope 1 (direct) emissions were
33.7MtCO2e – an overall increase from
32.8MtCO2e in 2024. Of these Scope 1
emissions, 32.8MtCO2e were from carbon
dioxide and 0.9MtCO2e from methanec.
In 2025 our Scope 2 (indirect) emissionsd
decreased by 0.1MtCO2e, to 0.7MtCO2e,
compared with 2024. The enhanced use of
Average carbon intensity of sold energy products (gCO2e/MJ)f | |||||||
2025 | 2024 | 2023 | 2022 | 2021 | 2019 | ||
Average carbon intensity of sold energy products | 79 | 79 | 80 | 81 | 81 | 84 | |
Oil/refined products | 91 | 91 | 91 | 92 | 92 | 95 | |
Gas/NGLs | 67 | 67 | 67 | 67 | 67 | 68 | |
Bioproductsg | 38 | 41 | 44 | 43 | 44 | 47 | |
Power/heath | 51 | 50 | 56 | 29 | 27 | 28 | |
lower carbon power agreements contributed
to this decrease.
We report our Scope 1 and 2 emissions on an
operational control and equity share basis in
the bp ESG Datasheet 2025.
| bp.com/ESGdata |
Scope 3 emissions TCFD
In 2025 our Scope 3 category 11 emissions
were 471MtCO2ee. These are the end-use
emissions associated with sales of energy
products, as determined in bp’s calculation
of the average carbon intensity of our sold
energy products«.
Methane
Since 2024 absolute methane emissions have
been reported based on our new methane
measurement approach across our major
operated oil and gas processing sites. Using
this approach, our methane intensity was
0.04% in 2025 (2024 0.07%c). Methane
emissions from our upstream« operations
used to calculate this methane intensity
were 25kt in 2025 (46kt in 2024c).
Marketed gas volumes were broadly flat at
3,637bcf in 2025.
The lower emissions and intensity in 2025 were
primarily from improved management of
abnormal plant conditions in our Tangguh
operations, Indonesia, reported in 2024.
We remain on track to reach zero routine
flaring by 2030 in line with our aim under the
World Bank’s Zero Routine Flaring Initiative.
Net zero sales TCFD
Our aim is to reduce to net zero the average
lifecycle carbon intensity of the energy
products« we sell by 2050 or sooner, enabled
by supportive government policies and the
decarbonization of energy demand.
We have achieved our target to reduce the
intensity of our sold energy products by 5%
from the 2019 baseline by the end of 2025. We
are aiming for an 8-10% reduction by the end
of 2030 compared to our 2019 baseline.
In 2025 the average carbon intensity of our
sold energy products was 79gCO2e/MJ.
This represents a 7% reduction from our
2019 baseline.
The incremental improvement in performance
from 2024 was primarily driven by a growth in
retail power sales across our utility businesses
– bp Energy Retail and GETEC, our trading
business, and our renewable businesses –
Lightsource bp and JERA Nex bp. It was
supported by the high grading of our retail
portfolio and improved identification of
end-user sales volumes within the refined
product category.
Details of our net zero sales methodology are
in the bp Basis of Reporting 2025.
| bp.com/basisofreporting |
As announced in February 2025, we plan to
invest selectively and with discipline in
transition businesses«, see page 21.
Our disciplined approach to capital investment
means that individual investments will be
made when we consider there to be a clear
and compelling business case, in line with our
balanced set of investment criteria, see
page 22.
Advocacy related to net zero
We regularly advocate for or comment on the
development of policy that is relevant to bp
and our sustainability aims. In 2025 our
advocacy activities focused on various aspects
including bioenergy, hydrogen and carbon
pricing. We publish examples of our activity
online at bp.com/advocacyactivities.
aIn 2025 bp made an adjustment to the operational control boundary for Scope 1 and 2 GHG emissions. This means certain operations, assets or sources which were previously included, such as
power generation on contractor-operated drilling rigs, are now excluded. This change has a less than 1% impact on reported operational emissions. For more information on the scope of bp’s
operational control boundary see bp.com/basisofreporting.
bDue to rounding some totals may not agree exactly to the sum of their component parts.
cSince 2024 reported absolute methane emissions from upstream major operated oil and gas processing sites are based on our new measurement approach. Prior to 2024 these emissions were
calculated using a different methodology and therefore the methane intensity reported in those years and calculated using that data does not directly correlate to progress towards delivering
the 2025 target. Prior year data is provided for information purposes, and we do not seek to directly compare prior years.
d Scope 2 emissions on a market basis.
b eThis Scope 3 category 11 metric follows a different methodology and boundary to the Scope 3 category 11 emissions from the carbon in bp’s upstream oil and gas production (known previously as
bp’s aim 2 (net zero production), which was retired in February 2025), so is not directly comparable to prior years of data for that retired aim and does not correlate to progress towards any
retired targets associated with it. Although these emissions are a subset of the lifecycle emissions under bp’s net zero sales aim, there is no target or aim associated with them. See bp.com/
basisofreporting for more detail on methodology.
fThe aggregate lifecycle emissions and energy values used in the calculation of the average lifecycle carbon intensity of sold energy products« are provided in the bp ESG Datasheet 2025.
gIncludes biofuels and biogas.
hCovers all power, including renewable and non-renewable.
TCFD Information that supports TCFD Recommendations and Recommended Disclosures in relation to governance (see pages 41-44)
bp Annual Report and Form 20-F 2025 | 39 |
| ||||
Strategic report | ||||
| | |||||
Streamlined energy and carbon reporting (SECR) information Further information on our greenhouse gas (GHG) emissions, energy consumption and energy efficiency is set out here and on the following page. It includes disclosures in respect of the SECR requirements. Further breakdown of our GHG and energy data is available in the bp ESG Datasheet 2025 at bp.com/ESG. | ||||||
Operational controlab | Unit | 2025 | 2024 | 2023 | ||
Scope 1 (direct) emissionsc | MtCO2e | 33.7 | 32.8 | 31.1 | ||
UK and offshore | MtCO2e | 1.0 | 1.0 | 1.0 | ||
Global (excluding UK and offshore) | MtCO2e | 32.6 | 31.8 | 30.1 | ||
Scope 2 (indirect) emissions – location-basedc | MtCO2e | 1.7 | 2.4 | 2.0 | ||
UK and offshore | MtCO2e | 0.02 | 0.02 | 0.02 | ||
Global (excluding UK and offshore) | MtCO2e | 1.7 | 2.4 | 1.9 | ||
Scope 2 (indirect) emissions – market-basedc | MtCO2e | 0.7 | 0.8 | 1.0 | ||
UK and offshored | MtCO2e | 0.03 | 0.02 | 0.0 | ||
Global (excluding UK and offshore) | MtCO2e | 0.7 | 0.8 | 1.0 | ||
Energy consumptione | GWh | 134,448 | 129,872 | 124,770 | ||
UK and offshore | GWh | 4,718 | 4,526 | 4,688 | ||
Global (excluding UK and offshore) | GWh | 129,730 | 125,347 | 120,082 | ||
Ratio of Scope 1 (direct) and Scope 2 (indirect) emissions to gross productionf | teCO2e/te | 0.16 | 0.16 | 0.16 | ||
UK and offshore | teCO2e/te | 0.12 | 0.13 | 0.13 | ||
Global (excluding UK and offshore) | teCO2e/te | 0.16 | 0.16 | 0.16 | ||
a Operational control data comprises 100% of emissions from activities operated by bp / where bp or its subsidiaries has full authority to introduce and implement its OMS«. Read more at bp.com/basisofreporting. b Due to rounding, some totals may not agree exactly to the sum of their component parts. c In 2025 bp made an adjustment to the operational control boundary for Scope 1 and 2 GHG emissions. This means certain operations, assets or sources which were previously included such as power generation on contractor-operated drilling rigs are now excluded. This change has a less than 1% impact on reported operational emissions. For more information on the scope of bp’s operational control boundary see bp.com/basisofreporting. d REGOs and other instruments reflected in our data had not been retired at the time of publication but are expected to be retired subject to business decisions at the end of the compliance period. e Energy content of flared or vented gas is excluded from energy consumption reported as although it reflects loss of energy resources, it does not reflect energy use required for production or manufacturing of products. f Gross production comprises upstream production, refining throughput and petrochemicals produced. | ||||||
| | |||||
40 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Sustainability continued | ||
Streamlined energy and carbon reporting (SECR) information
Energy efficiency measures
Operational efficiency
We take a portfolio view of our project
improvement activities at individual sites.
This allows us to prioritize the most
effective projects, supporting energy
efficiency, reduced carbon emissions, and
lower costs.
During 2025 we completed energy
efficiency reviews across four production
regions: the North Sea, Oman, Egypt and
Asia Pacific. Our refining business also
completed the energy efficiency
programme launch in 2024. Additional
reviews were carried out at the Cherry
Point (US), Castellón (Spain) and
Gelsenkirchen (Germany) refineries. The
opportunities identified through these
reviews will be progressed through our
established business processes and plans
that support our net zero ambition.
In 2025 a total of 14 new emissions
reduction projects and actions
contributed to reductions of 0.27MtCO2e,
including low carbon energy consumption
projects. This is in addition to the 27
emissions reduction projects delivered in
2024, which achieved a reduction of
0.42MtCO2e. These projects are tracked
based on GHG reductions and include
energy efficiency improvements.
Archaea Energy purchased renewable
energy certificates (RECs) equivalent to
125ktCO2e in emissions savings on a
market basis.
A further 144ktCO2e of emissions
reductions were achieved through energy
efficiency improvements in production
processes and flaring optimization
projects during 2025. These included:
•Three projects at our Tangguh facility
delivering 45ktCO2e in reductions,
including flare purge rate
rationalization and boil-off gas flaring
minimalization.
•A power synchronization project
between two platforms in Trinidad and
Tobago which reduced spinning
reserve through an electrical tie-over
enabling load sharing, delivering
14ktCO2e reductions.
•Ongoing programmes at bpx energy
including replacement of natural-gas
driven pneumatic controllers,
installation of solar air compressors,
electrification measures and
reductions in fugitive emissions,
delivering 80ktCO2e.
In addition, our Castellón, Rotterdam
(Netherlands), and Whiting (US) refineries
have implemented further actions to drive
energy efficiency and reduce carbon
emissions, including steam trap repair
and replacement programmes. At Cherry
Point the restoration of cooling water
infrastructure improved reliability in
meeting refinery needs and enhanced the
efficiency of compressor operations.
As part of managing energy efficiency, we
take a portfolio-wide approach to
assessing and prioritizing spinning
reserve reduction opportunities. Spinning
reserve involves running additional power
generation machines to provide an excess
of energy supply. This can help to protect
production from plant vulnerabilities,
including power generation reliability.
Reducing spinning reserve can increase
exposure to power fluctuations for
production. We take a risk-based
approach when considering reducing the
number of running machines. This
allows bp to realise emissions and
maintenance cost reductions from fewer
running machines, while managing the
associated production risk.
bp is involved in several external groups
working on energy efficiency, including
the Oil & Gas Climate Initiative (OGCI), the
International Association of Oil & Gas
Producers (IOGP) and Energy Star. We
continue to run an annual training course
for new chemical engineers, which
includes energy efficiency upskilling, and
we offer GHG emissions and energy
efficiency training for more experienced
engineers and practitioners.
Reporting methodology
Our approach to reporting GHG emissions
broadly follows the GHG Protocol
Corporate Standard and the Ipieca
Petroleum Industry Guidelines for
Reporting Greenhouse Gas Emissions 2nd
Edition, May 2011. We calculate GHG
emissions based on fuel consumption and
fuel properties for major sources, such
as flares.
We report CO2 and methane. We do not
include nitrous oxide, hydrofluorocarbons,
perfluorocarbons and sulphur
hexafluoride as they are not material to
our operations.
Energy consumption is monitored and
reported centrally from all operated sites
by fuel type. This includes all energy, both
imported and self-produced, used to run
our operations and aligned with our GHG
reporting boundary, but excludes energy
content of flared or vented gas. Although
flaring and venting reflects loss of energy
resources, it does not reflect energy use
required for production or manufacturing
of products.
Ratio of Scope 1 and Scope 2
emissions to gross production
bp reports a ratio of Scope 1 and Scope 2
emissions to gross production, see the
SECR table on page 39. This covers all our
Scope 1 and Scope 2 emissions on an
operational control boundary basis and
uses gross operated sales from our
operated oil and gas facilities, refinery
throughput and petrochemicals
produced. The denominator uses output
from production businesses, refineries
and petrochemical facilities, which
account for 96% of total operated
emissions. The intensity ratio has
remained the same as 2024.
The ratio provided in the SECR table uses
production and throughput from our
operated upstream, refining and
chemicals businesses as a measure of
output which can be consistently
reported against. We report data on a
consolidated basis in the Annual Report
and Form 20-F and this differs to the
production and throughput used for the
ratio in the SECR table, which aligns with
the operational control boundary basis.
bp Annual Report and Form 20-F 2025 | 41 |
| ||||
Strategic report | ||||
Climate-related financial disclosuresa | ||||
We want to continue to work constructively
with the IFRS Foundation’s International
Sustainability Standards Board (ISSB) and
others as they develop good practices and
standards for transparent climate-related
reporting.
In 2025 we continued to engage with the
World Business Council for Sustainable
Development (WBCSD) in relation to its
ongoing ’Climate Scenario Analysis Reference
Approach for Companies in the Energy
System’. Read about how we have used the
WBCSD Scenario Catalogueb as the start point
for consolidating our Transition Scenario
Catalogue«, which was used to inform our
own scenario analysis, on page 52.
TCFD statement
We report in line with the FCA Listing Rule
UKLR 6.6.6R(8), which requires us to report on
a ‘comply or explain’ basis against the TCFD
Recommendations and Recommended
Disclosures in respect of the financial year
ended 31 December 2025c.
We consider our climate-related financial
disclosures to be consistent with all of the
TCFD Recommendations and Recommended
Disclosures and that they are therefore
compliant with UKLR 6.6.6R(8). We have set
out our disclosures against each TCFD
Recommended Disclosure and in doing so
have covered both the Recommended
Disclosure and the related Recommendationd.
We have made disclosures that take into
consideration references made to the
materiality of information in the
Recommendations related to Strategy and
Metrics and Targets. In determining materiality
for these purposes, we considered whether
particular information may have the potential
to influence the economic decisions of our
shareholders. We have also, where
appropriate, considered the TCFD guidance
and other supporting materials referred to in
the UK Listing Rulese. In the Strategy (b)
section on page 46, we describe elements of
our plans for the transition to a lower carbon
economy as we execute our strategy.
As explained on page 10, we explain why we
consider our strategy to be consistent with the
goals of the Paris Agreement.
The strategy has been developed taking into
consideration, among other things, the bp
Energy Outlook scenarios, which take account
of climate commitments and pledges made by
countries in which we operate alongside a
range of other factors.
In preparing our disclosures we have made
several judgements, and while we are satisfied
that they are consistent with the TCFD
Recommendations, Recommended
Disclosures and reporting requirements under
the UK CFD Regulations, we will continue to
monitor guidance as it evolves and consider
opportunities to enhance our disclosures.
aThis section provides disclosures pursuant to the FCA Listing Rule UKLR 6.6.6R(8) and in line with the Companies (Strategic Report) (Climate-related Financial Disclosure) Regulations 2022 (The
UK CFD Regulations). In the main, we consider our TCFD disclosures achieve UK CFD compliance. Where additional information has been provided beyond our TCFD disclosures to achieve
compliance with the CFD Regulations, this has been specifically called out.
bOur 2025 analysis used a suite of external scenarios from various providers – this took as its start point the latest WBCSD (World Business Council for Sustainable Development) Scenario
Catalogue (V3, published in 2024), which we then updated for relevant metrics where underlying source data providers (IEA, NGFS, UN PRI) have published more recent (or withdrawn older)
transition scenarios. We have referred to this as our Transition Scenario Catalogue« – for more detail see page 52.
cIn considering the consistency of our disclosures with the TCFD Recommendations and Recommended Disclosures we have had regard to, among other things, the documents referred to in
UKLR 6.6.8G and 6.6.9G, as applicable to the financial year 2025.
dIn preparing the disclosures we have referred to the TCFD implementation guidance ’Annex: Implementing the Recommendations of the Task Force on Climate-related Financial Disclosures
(October 2021)’, available from fsb-tcfd.org/publications.
eUKLR 6.6.8G and UKLR 6.6.9G.
fWe interpret the term ’climate-related issues’ to relate primarily to those climate-related risks and opportunities for bp that are relevant to the delivery of long-term shareholder value in the
context of the energy transition.
Governance
 | | |
TCFD Recommendation: Disclose the organization’s governance around climate-related issues and opportunities. | ||
 |  |
Recommended Disclosure: a. Describe the board’s oversight of climate- related risks and opportunities. b. Describe management’s role in assessing and managing climate-related risks and opportunities. | ||
The board’s role
One of the core roles of the board is to
promote the success of the company for the
benefit of its shareholders as a whole while
having regard to various factors, including the
interests of our other stakeholders and the
impact of our operations on the environment
and the communities where we operate.
In performing this role, the board sets and
monitors bp’s strategy. It is responsible for
monitoring bp’s management and operations
and obtaining assurance about the delivery of
its strategy.
Any changes to the company’s purpose,
strategy and values (which we call ‘Who we
are’) are reserved for the board for approval in
accordance with the board-approved
corporate governance framework.
The board’s responsibilities extend to
oversight of bp’s internal control and risk
management framework, including climate-
related risks and opportunities, as set out in
the terms of reference of the board, available
online at bp.com/governance.
The board considers that our strategy allows
bp to be flexible to adapt to the evolution of
the external environment, including market
changes, to remain consistent with the
Paris goals.
The board and its committees have oversight
of climate-related issuesf, which include
climate-related risks and opportunities.
Related board and committee activities are set
out within the board activities section and
committee reports respectively, which can be
found on the pages detailed in the table on
page 42.
Climate-related risks and opportunities were
discussed at each relevant board meeting
covering strategy in 2025, and the
committees considered climate-related
issues where appropriate to do so in fulfilling
their responsibilities. Verbal reports from
each of the committee chairs are given at
board meetings to keep the board apprised
of the relevant matters discussed including,
where applicable, climate-related risks and
opportunities.
Our company secretary’s office manages the
process by which board and committee
agendas are set and works closely with teams
in bp to develop materials that assist the
board to discharge its responsibilities,
including in respect of climate-related issues.
The board also reviewed documents
containing climate-related disclosures –
including these TCFD disclosures.
42 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Climate-related financial disclosures continued | ||
Learning and development
The board continues to develop its knowledge and expertise on climate-related and sustainability matters. For example, in 2025, the board took
part in the following:
Renewables and power update | Included recent progress on, and plans for, offshore wind. Update provided to assist the board in remaining abreast of key energy transition risks and opportunities. | |
Hydrogen and carbon capture and storage transition growth« engine update | Update provided on bp-led projects including the Northern Endurance Partnership and Net Zero Teesside Power. Assisted the board in remaining abreast of key energy transition risks and opportunities. | |
Energy and economic update | The briefing was given by our chief economist on developments shaping the key political and societal trends currently affecting the energy transition, in advance of publication of the bp Energy Outlook 2025 in September 2025. Briefing assisted the board in remaining abreast of key developments. |
The board is due to receive further updates on bp’s strategic process and sustainability frame in 2026.
Climate and sustainability expertise
The board believes its members possess the
necessary expertise related to climate change
and sustainability to support the group’s
strategy. In particular, eight of our non-
executive directors have specific climate
change and sustainability expertise, as set
out below.
This determination is based on an assessment
of their background and experience, with a
focus on their background in the energy
sector, experience in executive roles and
depth of experience in sustainability and
climate change, including climate-related
risks and opportunities.
For more general director skills information,
see page 73.
•Dame Amanda Blanc is the Group CEO of
Aviva plc, and has held several executive
roles across the industry. She was Co-Chair
of the UK Transition Plan Taskforce.
•Dave Hager has over 40 years’ experience
in the oil and gas industry. During his time
as CEO of Devon Energy Corporation, he
was instrumental in developing its
approach to climate and sustainability. He
also served on the American Petroleum
Institute Executive Committee as the
organization set out its positions on climate
and sustainability. He has served on the bp
safety and sustainability committee since
December 2025.
•Simon Henry has significant climate and
sustainability experience from senior roles
across the energy and financial sectors. As
CFO of Shell, he oversaw group strategy
through the period of the 2015 Paris
Agreement. He contributed to Lloyds
Bank’s first climate strategy, supported the
development of PetroChina’s Sustainability
Report, and, while a Non-Executive director
at Rio Tinto, helped shape its emissions
reduction plans. He has served on the
sustainability committees at Rio Tinto and
Harbour Energy, and was a contributing
member of Chapter Zero and the Energy
Transition Commission.
•Albert Manifold has a strong track record
of strategic leadership and operational
delivery. As CEO of CRH plc, the global
building materials company, he embedded
decarbonization, circularity and water
efficiency into the company’s strategy and,
under his leadership, CRH made recognized
progress in climate performance.
•Melody Meyer has deep-rooted operational
experience in the energy sector which
equips her to advise on climate-related
risks and opportunities. She has chaired
bp’s safety and sustainability committee
since November 2019, which oversees the
implementation of bp’s sustainability frame
and net zero ambition.
•Hina Nagarajan has over 30 years’
experience in senior roles within the
customer-focused FMCG sector. Through
her executive roles at Diageo, she is
responsible for assessing and mitigating
risks related to climate and sustainability,
as well as delivery of ESG targets for her
region and Diageo plc. During her time as
CEO of United Spirits Limited (Diageo plc’s
listed Indian subsidiary), she oversaw
the implementation of Diageo India’s 10-
year ESG action plan, and its Society 2030
mission, in addition to a number of other
sustainability initiatives.
•Satish Pai has extensive experience in the
resource and energy industries. He is
managing director of metals company
Hindalco Industries Limited, and leads the
company’s Sustainability Board in
overseeing sustainability initiatives – such
as sustainable mining practices, energy
conservation and recycling. He has served
on the bp safety and sustainability
committee since March 2023.
•Johannes Teyssen brings CEO experience
from his time at E.ON, where under his
leadership, it split its hydrocarbons and
non-hydrocarbons businesses – giving him
significant experience of considering
climate-related risks and opportunities. He
has sat on bp’s safety and sustainability
committee since 2021. He is a director of
Alpiq Holding AG, a Swiss energy services
provider and electricity producer in Europe.
| | ||
Board and committees’ consideration of climate- related issues For examples from the year ended 31 December 2025, see the text indicated with TCFD on the pages set out below. | |||
| The board: pages 73-75 | ||
Safety and sustainability committee: pages 82-83 | |||
Audit committee: pages 84-88 | |||
Remuneration committee: pages 91-117 | |||
| | ||
bp Annual Report and Form 20-F 2025 | 43 |
| ||||
Strategic report | ||||
The role of management
The board, subject to certain conditions and
limitations, delegates day-to-day management
of the business of the company to the CEO.
The CEO is responsible for proposing bp’s
strategy and annual plan to the board for
approval and leading the bp leadership team in
delivering bp’s strategy and annual plan.
Under this delegation, the CEO is responsible
for overseeing the implementation of a
comprehensive system of internal controls
that are designed to, among other things (a)
identify and manage risks that are material to
bp, (b) protect bp’s assets, and (c) monitor the
application of bp’s resources in a manner that
meets external regulatory standards. Risks, for
these purposes, include the climate-related
risks and opportunities for bp associated with
the issue of climate change and the transition
to a lower carbon economy. This is set out in
the CEO role profile at bp.com/board.
The assessment and management of climate-
related risks and opportunities are embedded
across bp at various levels and delegated
authority flows down from the board through
the CEO. See page 60 for more information on
risk governance and oversight.
2025 activity
Where considered appropriate, climate-
related risks and opportunities were discussed
at bp leadership team meetings in 2025 as
part of regular business performance updates
prepared for these meetings.
The bp leadership team provides oversight of
risk, including climate-related risk, through the
various committees described on page 60.
They are informed about and monitor
emerging risks over the short, medium and
longer term via emerging risk papers
produced by our SVP treasury. Members of the
leadership team receive information on the
longer-term risks and opportunities
associated with the energy transition via
updates produced by our chief economist.
These papers are shared with the board.
SVP level and beyond
The bp leadership team is supported by bp’s
senior-level leadership and their respective
teams, with dedicated business and functional
expertise focused on climate-related risks and
opportunities or on matters which may be
affected by such risks and opportunities. This
includes: health, safety, environment and
carbon; risk; and strategy and sustainability
(which includes our carbon ambition, policy
and economics teams). Alignment between
group, business and functional leaders is
fostered through other meetings, such as the
TCFD working group which leads the
preparation of bp’s climate-related financial
disclosures.
Management consideration of climate-related risks and opportunities is organized as follows:
Resource commitment meeting | Forum for approval of investments related to existing and new lines of business above $250 million or $25 million for acquisitions, or which exceed the relevant EVP financial authority, and any project considered strategically important such as a new market entry, see page 21. | |
Group operational risk committee | Provides oversight of safety and operational risk management performance for the group, where appropriate. Climate-related factors may affect certain sources of safety and operational risk, such as severe weather events. | |
Group operational risk committee (sustainability) | In October 2025 our executive-level group sustainability committee (GSC), was replaced by the group operational risk committee (sustainability) (GORC(S)). This executive-level committee, chaired by the chief financial officer, provides oversight, challenge and support in the implementation of our sustainability frame and aims, and oversight of the management of potentially significant sustainability risks and opportunities, including those related to climate change. Between the GSC and GORC(S) there were four scheduled meetings in 2025 with ad hoc discussions held as needed. In both committees, members considered bp’s sustainability aims, progress against targets and bp’s position on certain strategic sustainability issues. The outputs from the committee are shared with the board and its committees, including the safety and sustainability committee, as appropriate. | |
Group financial risk committee | Monitors the effectiveness of bp’s financial reporting, systems of internal control and financial risk management, namely material group financial risks. Where appropriate, it considers the planned approach to assurance and verification of non-financial reporting ahead of updating the audit committee. |
| | |
Acquired businesses Integration plans are developed to transition acquired businesses into bp’s system of internal control, over an appropriate timeframe. | ||
| |
44 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Climate-related financial disclosures continued | ||
Climate governance: management of climate-related matters As at 1 January 2026 | ||||||||||||||
bp board level | ||||||||||||||
Board | Audit committee | Safety and sustainability committee | People, culture and governance committee | Remuneration committee | ||||||||||
EVP level | ||||||||||||||
CEO | Group financial risk committee Chair: CFO | Resource commitment meeting Chair: CEO | Group operational risk committee Chair: CEO | Group operational risk committee (sustainability) Chair: CFO | ||||||||||
bp leadership team | ||||||||||||||
SVP level | ||||
Sustainability forum Chair: SVP strategy & sustainability Focuses on sustainability plans and progress. | Production & operations sustainability table Chair: SVP HSE & carbon, P&O Focuses on the delivery of lower carbon plans in P&O – particularly in relation to net zero aims. | |||
Cross-bp forums and meetings | ||||
Meetings and forums to allow cross-group discussions, integration and implementation. | ||||
Risk Management
| | |
TCFD Recommendation: Disclose how the organization identifies, assesses and manages climate-related risks. | ||
| |
Recommended Disclosure: a. Describe the organization’s processes for identifying and assessing climate-related risks. | ||
bp’s risk management system and policy,
described on page 60, are designed to address
all types of risks including our principal risks
and uncertainties, described on page 62.
As part of this system, our businesses and
functions are responsible for identifying,
assessing, managing and monitoring
risks associated with their business or
functional area.
The process for identifying risks is outlined on
page 61 and guidance to support consistency
has been made available to our businesses to
provide them with a climate-related taxonomy,
which they are able to use as they see fit in
their identification and assessment of risk.
Where risks – including climate-related risks –
are identified, businesses and functions are
required to assess them, in line with our risk
management policy. This includes an impact
and likelihood assessment which supports the
consideration of relative significance and
prioritization of risk management activities.
The impact criteria outlined on page 63 include
health and safety, environmental, financial and
non-financial (such as regulatory impact)
criteria and are used for assessing risks,
including climate-related risks. This provides a
consistent basis for assessment across bp.
For the purposes of our TCFD disclosures, we
use the TCFD’s distinction between ‘physical’
and ‘transition’ climate-related risks.
Identification, assessment and
management of climate-related
opportunitiesa
As set out in our TCFD Strategy a and b
disclosures on page 46, we have identified
potentially material climate-related
opportunities and our strategy has been
informed by these. We identify climate-related
opportunities by considering a range of
information sources, including the bp Energy
Outlook, which helps to inform our thinking
about how the energy system might evolve.
Business opportunities continue to be
originated across bp, and taken forward
through bp’s investment governance
framework. For example, our gas & low carbon
energy and customers & products businesses
support the delivery of low carbon and
transition opportunities through organic and
inorganic growth.
Our investment governance framework (see
page 21) provides the mechanism by which
alignment of these opportunities with our
strategy is assessed and decisions on which
to progress are made.
aInformation added to satisfy the UK CFD Regulations.
bp Annual Report and Form 20-F 2025 | 45 |
| ||||
Strategic report | ||||
Recommended Disclosure: b. Describe the organization’s processes for managing climate-related risks. c. Describe how processes for identifying, assessing and managing climate-related risks are integrated into the organization’s overall Risk Management. | ||
Risk Management process
Risks which may be identified include
potential effects on operations at asset
level, performance at business level and
developments at regional level from
extreme weather or the transition to a
lower carbon economy.
As part of our annual process the bp
leadership team and board review the group’s
principal risks and uncertainties. Climate
change and the transition to a lower carbon
economy continues to be identified as a
principal risk, see page 64. It covers various
aspects of how risks associated with the
energy transition could manifest. Physical risks
such as extreme weather, which may be
affected or intensified by climate change, are
covered in our principal risks related to safety
and operations.
Physical risk
Physical risks are typically identified at the
asset or project level and managed depending
on the level of risk assessed.
In the North Sea and Gulf of America, regions
more prone to severe weather conditions, our
offshore facilities monitor meteorological and
oceanographic conditions through the
collection of measurements. This data is
collated and periodically compared against
the ‘Basis of Design’ for the facility. If
significant differences are observed, then this
may trigger an update to the ‘Basis of Design’,
prompting action to reassess risks such as
structural integrity and station-keeping and if
necessary, implement additional risk
mitigations, for example updating procedures
for shutting down and removing personnel
from facilities ahead of severe weather events.
Updates may also be made as a result of other
new knowledge, analysis methods and data,
including climate projections where
appropriate.
Our major projects« are required to assess the
potential impact of severe weather and
projected climate-related physical impacts.
Where relevant, potential changes in
environmental conditions, such as sea level
rise and ambient temperatures, over the
expected lifetime of a project are to be
considered as part of the design process.
Building on a modelling exercise conducted
in 2022, a screening approach to support
identification of potential severe weather and
physical climate-related hazards at operational
sites across bp has been rolled out since 2024
as part of our operational management
system. Since 2024 screening has been
conducted for a number of sites each year.
Where potential hazards are identified, and as
appropriate, this enables further work to be
carried out to assess potential risks and
implement appropriate
management measures.
For other assets, such as our retail sites«, that
are typically not exposed to a comparable
level of severe weather risk, climate-related
risks such as flooding or wind damage may be
managed where appropriate through the
emergency response plans and business
continuity plans which are mandated through
bp-wide policies.
Additionally, at a group level we recognize risk
associated with the potential for increased
water stress due to climate change and other
factors and the impact this could have on our
operations and in the catchments where we
operate. In order to understand the water-
related challenges that we face, we review our
water impacts, risks and opportunities at our
major operating sites. These reviews consider
the quantity and quality of water used as well
as any regulatory requirements. We anticipate
adopting site-level activities as part of our aim
to reduce our net freshwater use in stressed
catchments where we operate. We anticipate
adopting a focused freshwater management
approach, addressing water-related business
risk where it is greatest, and we anticipate that
our freshwater withdrawal in stressed
catchments will be covered by freshwater
management plans by 2028. For more about
water, see page 59.
Transition risk
The board appraises bp’s strategy and
monitors bp’s management and operations to
obtain assurance over the delivery of its
strategy. This approach enables the effective
management of climate-related transition
risks and opportunities facing bp associated
with the energy transition. For the purposes of
our TCFD disclosures, we group transition risks
identified by our businesses and functions into
the three broad material climate-related
transition risks to bp, see page 52. However,
we continue to assess and manage the
component parts of those broad transition
risks, including:
Policy and legal risks
Our strategy and sustainability team leads the
definition of policy positions in line with bp’s
strategy and bp’s sustainability aims.
They work with our regional organizations as
well as corporate entities to discuss regional
and global policy trends and support external
positioning and interactions relating to policy
and advocacy topics.
Our group operational risk committee
(sustainability) provides oversight of
sustainability matters and our issues and
advocacy meeting covers emerging
advocacy issues.
Our legal team manages bp’s litigation,
including climate-related litigation, and
advises on the management of associated
risks. This includes the use of internal lawyers
and, where appropriate, external counsel.
Market risks
In developing our business strategies, we
consider market risks, controls and
mitigations, including future demand in the
different geographies in which we might
operate, the competitive landscape and the
potential value proposition. We manage these
risks through our investment decisions, our
hedging and optimization activity, and through
key business processes, including the group
investment assurance and approval process.
Reputational risks
Our investor relations, communications and
external affairs teams work to mitigate
reputation-related risks, which include the risk
of shareholder action. Our investor relations
team co-ordinates engagement with key
investors on both a bilateral basis and through
investor initiatives to support understanding
of bp’s strategy and gain insights to inform
feedback they provide to the group.
Our communications and external affairs
teams help to manage corporate reputation
through identification and monitoring of key
issues and both proactive and reactive
engagement with relevant stakeholder groups.
The teams also advocate for policies that
support our strategy and sustainability aims,
see page 38.
Technology risks
Our technology team works to both mitigate
risks and identify opportunities associated
with evolving and emerging technologies that
play a role in the changing global energy
system. The team generates technology
reports for review by bp senior leaders and the
recommendations are overseen by the
relevant leadership teams, through the
Innovation Advisory Council. In appropriate
cases this helps to underpin and appraise the
business case for new investments, new
partnerships and new technology tools/
methods where these are being driven by
technology innovation.
46 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Climate-related financial disclosures continued | ||
Strategy
| | |
TCFD Recommendation: Disclose the actual and potential impacts of climate-related risks and opportunities on the organization’s business, strategy and financial planning where such information is material. | ||
| |
Recommended Disclosure: a. Describe the climate-related risk and opportunities that the organization has identified over the short, medium, and long term. | ||
In setting and monitoring delivery of bp’s
strategy, the board and leadership team
consider climate-related risks and
opportunities across the:
•Short term (to 2026): aligning with our near-
term business and financial planning
timeframe.
•Medium term (to 2030): aligning with our
group business outlook timeframe, and
enabling us to think beyond our short-term
targets and adjust course if appropriate.
•Long term (to 2050): using scenarios to help
explore the wide range of uncertainties
surrounding the energy transition over the
next 25 years. For more detail on our
approach, see page 7.
TCFD categorizes climate-related transition
risk and opportunity as follows: policy and
legal, market, reputation and technology. It
also refers to climate-related acute and
chronic physical risks and opportunities. Risks
in each of these categories have been
identified using a risk management process
that our businesses and functions are required
to follow. For more about how the relative
significance of identified risks is evaluated, see
Risk Management on page 44.
The risks and opportunities identified have
been considered in relation to bp’s reset
strategy, as announced in February 2025.
Climate-related transition risks
and opportunities
At a group level, we have identified three
broad, material climate-related transition risks,
outlined on page 52, underpinned by
underlying risks that are assessed and
managed through the risk process outlined.
These transition risks may cut across our
short-, medium- and long-term time horizons;
however, we indicate below wherever there is
a particular time horizon in which the risk has
been considered. The transition risks are also
global in nature, so we do not discuss specific
geographies here, but the underlying risks
refer to specific geographies where
appropriatea. We also see significant potential
for upside – or opportunity – associated with
some of these risks. These are discussed
under each risk on page 52 and in relation to
Recommended Disclosure (b) we also describe
the potential impacts of both the risks and
opportunities to bp.
Climate-related physical risks
The physical risks identified primarily relate to
severe weather and often represent potential
for increased drivers for safety and operational
risks to our operations, particularly process
safety, personal safety, and environmental
risks, see Risk factors page 62. In addition, we
have identified the potential for changes in the
availability of freshwater, including as a result
of climate change, as a risk to some of our
operations. Higher instances of extreme
weather also have the potential to impact
supply chains and critical infrastructure, such
as air and sea ports, as well as our customers.
We recognize that we could also face other
forms of physical climate-related risk over the
longer term, for example associated with
changes in sea level, extreme temperatures
and flooding, which could impact our
operations. As these risks are primarily
operational, and location-specific, they are not
grouped in the same way as transition risks.
Like other businesses around the world, in the
longer term we could face adverse market or
value chain conditions associated with large-
scale cumulative impacts of physical climate
change if global mitigation and adaptation
efforts are insufficient or unsuccessful.
Offshore facilities
In the case of our offshore facilities, climate
change could create greater uncertainty
around frequency and/or intensity of severe
weather events, such as extreme waves, loop
currents, and storms, particularly in the
medium to long term. These factors could
affect the future risk profile of an asset over
its lifetime, and could also impact production
or costs.
Water resources
Water resources are increasingly under
pressure from various factors, including
climate change, and this poses a potential risk
to some of our operations that depend on the
availability of freshwater. Based on analysis
using the World Resources Institute (WRI)
Aqueduct Global Water Risk Atlas, and in
certain cases review of site-specific local data
sources, six of our 16 major operating sites in
2025 were located in regions with high to
extremely high water stress. Using WRI data,
we have identified the potential for this risk to
increase in the medium term. For more on
water consumption, see page 59.
We do not currently foresee any material
opportunities arising from changes in the
physical environment as a result of climate
change. However, the actions we are taking to
make our operations more resilient, for
example through improving efficiency of our
freshwater use, may also bring about benefits
such as reduced costs.
aUnderlying risks are specific, for example, local or business-specific risks identified by specific bp entities through the risk processes described above under Risk Management.
bThis is not intended to be an exhaustive list of our plans for the transition, but rather illustrative of some of the core elements of our plans.
Recommended Disclosure: b. Describe the impact of climate-related risks and opportunities on the organization’s businesses, strategy, and financial planning. | ||
| | |
bp’s plans for the energy transition In this section we talk about some of our plans for the transition across bp’s business areas and where we do so we have identified these with TPb. We describe below how we believe our strategy and net zero ambition are both good for business and support society’s drive towards the Paris goals. Throughout the strategic report we set out bp’s strategy and plans for the energy transition. This includes our progress against 2025 performance, see page 21. Our progress against our net zero aims are described on pages 37-38. | ||
| |
TP
Our strategy, business and financial plans are
informed by a range of inputs including the
climate-related risks and opportunities
associated with the energy transition outlined
above. We describe how we use scenarios to
inform our strategy on page 7.
bp Annual Report and Form 20-F 2025 | 47 |
| ||||
Strategic report | ||||
Climate-related transition risks and opportunities
1 | ||
The value of our hydrocarbon business could be impacted by climate change and the energy transition. | Changes in policy, legislation, consumer preferences or markets as a result of growing concerns about climate change and the energy transition could reduce demand for fossil fuels or lower their price relative to our financial planning assumptions, particularly in the medium to long term, negatively impacting returns from or the value of our hydrocarbon businesses. Changes in regulations, including carbon pricing and fossil fuel policies, could also impact compliance and operating costs in our oil and natural gas production and refining businesses. Alternatively, prices (such as Brent oil and Henry Hub natural gas) during the next decade could be higher than our financial planning assumptions under certain transition pathways, including those aligned with the Paris Agreement. This could strengthen returns from our hydrocarbon businesses (including securing higher proceeds from assets we choose to divest) which may enable us to deliver enhanced shareholder value, further strengthen our balance sheet and grow investment in the transition, in line with our financial frame. | |
2 | ||
Our ability to grow or deliver expected returns from our transition businesses« could be impacted by the energy transition. | Several factors could restrict the growth of our transition businesses« or returns from them. These factors include: lack of, or insufficient development and application of, policies, regulations and frameworks that support low carbon businesses; insufficient consumer demand for our low carbon offering; strong competition in the market; or the insufficiently rapid development of supporting technologies and infrastructure or constraints on supply chains for low carbon energies. This could particularly impact bp in the short to medium term as new markets and technologies develop but could also represent a longer- term risk. Alternatively, demand, policy support or enabling technology and supply chain growth for renewables could support a more rapid portfolio shift with expansion of our low carbon businesses and higher returns from them. Some low carbon businesses, including renewable power, bioenergy and emerging technologies such as hydrogen and carbon capture and storage (CCS), rely on policy support to promote growth. We support well- designed, robust public policy that enables this. Changes in customer preferences, pace of technology and infrastructure development and deployment and costs could impact the markets for low carbon products and services. For example, the pace of adoption of electric vehicles (EV) could impact utilization rates, and consequently returns, from our EV charging networks. We recognize that the pace of our transition relative to our core low carbon target sectors and regions is important. If we move more slowly than those markets, we may miss investment opportunities and customers may prefer different suppliers with potential negative consequences to demand for our products and to our reputation. If we move faster than these markets, we risk investing in technologies or low carbon products that are unsuccessful because there is insufficient demand for them. However, our investment may also help to stimulate demand and provide us with a leading position in growth markets. | |
3 | ||
Our ability to implement our strategy could be impacted by changing stakeholder attitudes towards the energy sector, climate change and the energy transition. | Negative perceptions of the energy sector, or bp, could have a number of consequences, for example: adverse litigation; reputational impacts, including our ability to attract and retain talent; and shareholder action. These consequences could affect us in the short, medium or long term. Alternatively, increased support from our stakeholders could enable access to additional capital and new investors, strengthening our ability to deliver our strategy and enabling faster growth of our low carbon businesses. The world is in an ‘energy addition’ phase of the energy transition in which it is consuming increasing amounts of both low carbon energy and fossil fuels. The bp Energy Outlook 2025 highlights that, although the structure of energy demand will likely change over the long term, with the importance of fossil fuels declining, replaced by a growing share of low carbon energy, led by wind and solar power, oil and natural gas continue to play a significant role in the global energy system for at least the next 10-15 years. This requires continuing investment in upstream oil and natural gas. The insights from the bp Energy Outlook 2025 support our view that investment into oil and gas will be needed for decades to come and also that, while the pace and shape of the transition in the long run is uncertain, we continue to see the energy transition as a significant opportunity to grow value. Perceived inconsistencies between the pace of bp’s transition and societal expectations could have reputational and commercial impacts that might impair our ability to deliver our strategy. However, we also see potential to positively differentiate bp, by delivering against our strategy, net zero ambition and sustainability aims. |
48 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Climate-related financial disclosures continued | ||
Oil and gas
In February 2025 we announced an increase in
upstream investment versus our prior
guidance. This additional investment allows us
to strengthen the portfolio, for example we are
building our US portfolio to around 1 million
boe/d by 2030, increasing production in our
US onshore business and developing our Gulf
of America Paleogene resource. In the Middle
East we are now partnered in the
redevelopment of several giant oilfields in
Kirkuk, page 31, alongside our existing position
in Rumaila, Iraq. These examples, alongside
other investment in our existing portfolio,
additional access and exploration underpin
expected growth in underlying production to
2.3-2.5mmboe/d in 2030, excluding future
potential divestments.
We recognize that the transition presents
uncertainty for our upstream business,
including the possibility of lower oil and gas
prices. In recent years we have maintained top
quartile unit production cost at around $6 per
barrel, made strong progress on operational
reliability and commerciality across our
portfolio, and we retain optionality to divest
lower margin barrels. We intend to maintain
the disciplined application of our balanced
investment criteria, which include the
consideration of applicable economic hurdle
rates and operational emissions intensity
levels, from a portfolio across oil and gas.
Read more about our investment process on
page 20.
As an outcome of our strategy and informed
by our current outlook, and its underlying
assumptions, which may change over time,
we are aiming for the Scope 1 and 2 emissions
from our operations – the majority of which
are associated with the operating assets in our
hydrocarbons portfolio (refining and upstream
oil and gas combined) – to be 45-50% lower at
the end of 2030 than in 2019 and we plan to
maintain ‘near zero’ methane intensity«
across our operated producing assets, see
pages 37-38.
TP Customers and products
As announced in February 2025, we are
focusing the downstream – our customers &
products business – reshaping the portfolio to
focus on markets and businesses where we
have advantaged and integrated positions.
We recognize the risk of a decline in demand
for conventional vehicle fuels and products
due to the energy transition and are working to
increase the efficiency and resilience of our
existing fuels and lubricants businesses
through operating cost reductions and margin
optimization. In December 2025, we
announced an agreement to divest a 65%
shareholding in Castrol, strengthening our
balance sheet while retaining exposure to
future growth and optionality. We are also
increasing the resilience of our existing fuels
network and high-grading our regional
footprint. Since 2020 we have exited our
Switzerland, Turkey and Netherlands mobility
and convenience businesses, and in the past
year have announced our exit from our
mobility businesses in Austria. We are
reallocating capital into our most advantaged
positions such as major transit routes in key
markets where we see sustained demand for
fuels and EV growth, e.g. EV charging
investments on our sites near the German
Autobahn road network.
Our integrated mobility model across fuels
(hydrocarbons and biofuels), convenience and
EV charging provides resilience to the pace of
transition by allowing us to flex our offer to
meet customer demand.
In aviation, we will make selected high-return
investments to build our footprint; and see
strong growth potential in sustainable aviation
fuel through the transition.
Our biofuels business is already playing a key
role in building resilience to the energy
transition – helping to decarbonize the
mobility value chain using existing
infrastructure. In Q4 2024 we took full
ownership of bp bioenergy in Brazil, accessing
around 50kb/d of production and see
potential for future growth with support from
policy and market conditions. Our feedstock
positions also provide opportunity to
additional resilience to anticipated supply
shortages in the transition. In Q1 2026 we
launched Etlas, a joint venture with Corteva,
continuing our momentum in feedstocks with
the aim to produce one million metric tonnes
of feedstock per year by the mid-2030s (see
page 35).
At our refineries, the energy transition could
impact demand for certain products in the
future and raise costs. We expect the impacts
to be region- and asset-specific and are
difficult to fully anticipate, Consequently,
we are continuing to drive greater
competitiveness and value from our refineries,
aiming for 96% or above Solomon refining
availability. We are also repositioning our
refining portfolio and building resilience
through value chain integration, co-production
of biofuels alongside traditional products and
selective decarbonization initiatives.
TP Low carbon energy
Ongoing volatility and uncertainty continues to
impact low carbon energy businesses globally,
underlining the need to be aligned with and
flexible to market and policy development. As
announced in February 2025, we are changing
our model for low carbon – delivering with
partners and with external financing that will
be capital-light for bp and help improve our
equity returns.
In offshore wind, we established the JERA Nex
bp joint venture in Q3 2025. Recognizing the
exposure to transition volatility seen in recent
years, JERA Nex bp plans to focus on highly
disciplined, capital efficient growth, with bp
retaining an option to our equity share of
power offtake.
In solar, Lightsource bp continues to be a
leading global onshore renewable developer
in markets with attractive sector returns.
In our hydrogen and CCS businesses, we are
prioritizing fewer, higher value projects in the
near term while building capability and future
optionality to scale and grow as the market
develops. By focusing on projects in
jurisdictions where we have an adequate
regulatory framework, access to the value
chain including our own or customer demand
and leveraging access to advantaged carbon
capture and renewable power, we aim, over
time, to decarbonize our operations and help
our customers decarbonize. We sanctioned
four projects, for example, Lingen, Germany
in 2024 which is in line with our focus on
decarbonizing bp operations.
Through Archaea Energy, we believe we are
uniquely positioned in the US to meet growing
demand for renewable natural gas« as the
transition progresses. We are building
resilience by improving capital efficiency and
reducing operating costs and continue to
assess and develop new routes to market
and customer solutions to create future
optionality.
TP Supply, trading & shipping (ST&S)
Our ST&S business provides risk management,
flow and optimization services for our bp
equity and assets and third-party customers,
with a proven track record of resilience to
commodity cycles and the ability to capture
upside when market conditions present
opportunities.
The diversification of our traditional oil
business helps mitigate the risk of falling
demand in the US and Europe by providing
access to growing demand centres such as
Latin America and Sub-Saharan Africa and in
growth markets such as petrochemicals,
biofuels and adjacent agricultural
commodities.
Our gas and power business spans regional
and global markets. Our LNG portfolio offers
exposure to a lower carbon growth market
combined with flexibility through our
advantaged key global positions. Additionally,
with the acquisition of BP Energy Retail in the
US and GETEC in Europe, ST&S is building
resilience by participating further down the
value chain towards end consumers. Our
power trading business allows us to optimize
across the value chain from generation to
wholesale markets to customers. This helps
position us for further electrification of the
energy system as well as further
decarbonization of electricity.
bp Annual Report and Form 20-F 2025 | 49 |
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Strategic report | ||||
Impact on technology
We are investing in digital and technology
solutions that can help to generate value for
bp, manage risk and help accelerate the
transition through focused scale-up and
innovation. This investment includes targeted
focus on research and development where bp
is and can be differentiated and growing
partnerships to increase leverage. We expect
our research and development spend to be
increasingly focused on technologies with the
potential to help identify and access new oil
and gas opportunities at lower cost, reduce
GHG emissions and enable our transition
businesses«. See page 9 for examples of
technology investments in 2025.
We recognize the potential for disruptive
technologies to impact our strategy. Alongside
our research and development investments,
our bp ventures portfolio also includes
investments in emerging technologies and
business models that can help support our
businesses and deliver our strategy.
Physical risk
The potential impacts of the types of physical
risks we have identified could include reduced
production, throughput or sales – for example
as a result of damage to facilities or supply
chain disruption – or in a most extreme case
loss of life or an asset. Due to uncertainties
associated with the impact of climate change
on severe weather events in the future, it is
difficult to quantify the potential impacts
associated with any increase in these risks as a
result of climate change.
Having considered both geographic factors
and the ability of climate models to adequately
represent future trends in physical climate
parameters, we seek to take the uncertainties
concerning climate-related physical risk into
account in our approach to design and
operating criteria for existing assets and new
major projects«. Where appropriate, we have
updated our metocean design criteria to
include consideration of both forward-looking
and historical models, including climate and
synthetic models, in an attempt to mitigate
both models and extrapolation uncertainty.
The particular models chosen will depend in
part on geographic location. See Risk
Management, page 44, for how we manage
these uncertainties.
As a step in seeking to improve the resilience
of our operations to the physical changes that
might result from climate change that we have
described above, we have continued to
undertake screening of present-day and future
potential physical risk exposure for selected
key assets and identified those sites with
potential for heightened exposure to physical
risks in order to prioritize these for further site-
based assessment.
Recognizing the potential impact of climate
change and other factors on water resources,
as part of our water aim, we are taking steps to
be more efficient in operational freshwater use
(read more about water use on page 59).
Impacts on our financial planning
Capital allocation: We plan to invest sufficient
capital to execute our strategy, enabling us to
mitigate the risks and capture the
opportunities we have identified. As part of our
annual planning processes, we assess the
distribution of capital across our business
areas, including consideration of market
evolution. In February 2026 we announced
that we expect capital expenditure« to be
$13.0-13.5 billion in 2026. To help maintain
resilience to the pace of transition and access
opportunities, we will continue to flex capital
as policies, technologies and markets evolve.
Access to capital: While there is potential for
concerns about the energy transition to
impact banks’ or debt investors’ appetite to
finance hydrocarbon activity, we do not
anticipate any material change to funding in
the short to medium term. We are committed
to strengthening the balance sheet and
continue to target improving credit metrics
within an ‘A’ grade credit range. We reiterate
our primary target for net debt of $14-18 billion
by the end of 2027. Net debt decreased from
$23.0 billion to $22.2 billion during 2025.
Since the end of 2019 we have repurchased
around $26 billion of short-dated existing
bonds and issued over $12 billion of new bonds
with a duration of 20 years or longer, doubling
the duration of our debt book.
We provide further information on financial
frame elements related to capital expenditure,
balance sheet management and buybacks on
page 18.
We provide more detail on financial risk
factors, including liquidity risk in Financial
statements – Note 29.
Investment criteria: Investments are evaluated
against a balanced set of six investment
criteria, including sustainability (see page 22).
The assessment of economics includes a set
of price assumptions that reflect our view of
market evolution (for our key investment
appraisal price assumptions, see page 20). In
addition, the investment economics for all
investment cases where bp’s share of annual
greenhouse gas (GHG) emissions from
operations are anticipated to exceed specific
thresholds include a carbon price for those
emissions, which rises from $67/tCO2e
in 2026 to $135/tCO2e (2024 $ real) in 2030.
Impacts on financial performance
and position
Assessing the impact of climate change and
the energy transition requires the use of a
number of judgements and estimates.
We have set out the significant accounting
policies, judgements and estimates used in
assessing the impact of climate change in
Financial statements – Note 1.
This includes information on pricing, useful
economic lives, timing of implementation of
policies or decommissioning provisions, and
assumptions related to how each might
change over time and how such assumptions
may impact our currently reported assets
and liabilities.
Our price assumptions, including those set out
on page 20, reflect a range of future possible
scenarios and take account of the potential
impact of climate-related risks and
opportunities as well as current economic and
geopolitical factors. Consequently,
impairment losses and impairment reversals
consider inputs that arise from climate change
and the energy transition. It is not possible to
quantify separately the impact of these
different inputs on our impairments. However,
in conducting our impairment sensitivity tests,
that in part reflect transition downside risk, we
consider reductions in revenue that, if driven
by price alone, would be consistent with prices
within the range covered by the 1.5°C scenario
family within the Transition Scenario
Catalogue« data sets used for TCFD resilience
testing below.
Financial statements – Note 1 provides
information on impairment assumptions and
sensitivities. Note 4 provides information on
gains and losses on disposal or closure of
business and operations, and impairments and
impairment reversals, and Note 8 provides
information on impairment losses relating to
exploration for and evaluation of oil and
natural gas resources. See Financial
statements – Note 1, Note 4 and Note 8 for
more information.
a Potential proceeds from any transactions related to Castrol strategic review and announcement to bring a strategic partner into Lightsource bp will be allocated to reduce net debt.
Recommended Disclosure: c. Describe the resilience of the organization’s strategy, taking into consideration different climate-related scenarios, including a 2°C or lower scenario. | ||
We believe our strategy positions bp for
success and resilience in a Paris-consistent
world – a world that is progressing on one of
the many global trajectories considered to be
Paris-consistent, and ultimately meets the
Paris goals, see pages 10-11.
As in 2024, to help test our view of this, we
have assessed the resilience of our strategy to
different climate-related scenarios, including
1.5°C consistent scenarios.
50 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Climate-related financial disclosures continued | ||
We did this in three steps:
1.First, we evaluated all business areas in our
portfolio by i) quantitatively assessing their
financial significance, in the context of bp’s
total financial outlook, to understand the
potential scale of financial/strategic impact
that could be put at risk if exposed to
transition uncertainty, including 1.5°C; and ii)
considering whether there is a key variable
– such as price or demand – which would
represent a transition driver of such risk.
2.Second, we quantitatively assessed the
impact, to each business area, of potential
transition exposure scenarios in 2030 – the
point in our planning horizon at which there
is widest transition uncertainty.
–For each of those business areas with
both sufficient scale and for which a
specific transition risk driver was
identified – which collectively represent
over 70% of our 2030 adjusted EBITDA«
outlook – we performed a scenario
analysis focused on that transition risk
driver, across a range of transition
pathwaysa, including 1.5°C, as set out
below and in our methodology summary
on page 52.
–For each of the remaining business
areas we performed a simplified
quantitative scenario analysis, by testing
the financial impact of a scenario in
which each business area’s expected
2030 adjusted EBITDA is assumed to be
reduced to zero – an outcome at least as
detrimental to that business area’s
adjusted EBITDA as could reasonably be
expected to result from business-as-
usual (BAU), well-below-2°C and 1.5°C
transition pathways.
–In this way, all business areas were
quantitatively tested to downside
impacts at, or beyond, a range of
transition scenarios.
3.Finally, on the basis of the results of steps 1
and 2, we identified those business areas
for which the possible consequences of the
downside scenario(s) were sufficiently
significant to potentially jeopardize group
strategic resilience – as in prior years, the
only business areas for which this was
found to be the case were oil and gas
production with respect to their exposure
to oil price. For these business areas we
assessed the potential implications for bp’s
strategic resilience (as defined below) over
the period from 2027 to 2030.
To undertake steps 2 and 3, we identified
financial criteria which can be modelled as
proxies for strategic resilience – choosing to
do this through three lenses consistent with
our financial frame (as set out on page 18),
being our ability to deliver:
i.a resilient dividend;
ii.a stronger balance sheet that continues to
target improving our credit metrics within
the ‘A’ grade range; and
iii.disciplined investment allocation.
This is not intended to represent a ‘definition’
of resilience beyond the purposes of this
exercise, and a core assumption of this
analysis is necessarily that, aside from any
implications of the scenarios being tested,
including potential mitigations (such as capital
or cost management) that we might naturally
expect to take in response, bp will deliver the
assumed underlying strategic and financial
priorities out to 2030.
To undertake the modelling in steps 2 and 3,
we used a suite of external scenarios from
various providers (for example, IEA’s World
Energy Outlook (WEO 2024) Net Zero
Emissions by 2050 (NZE) scenario.
This suite of scenarios took as its start point
the latest WBCSD (World Business Council for
Sustainable Development) Scenario Catalogue
(V3, published in May 2024), which we then
updated for relevant metrics where underlying
source data providers (IEA, NGFS, UN PRI IPR)
have published more recent (or withdrawn
older) transition scenarios. We refer to this as
our Transition Scenario Catalogue«, with more
detail on its preparation provided on page 53.
When considering the long term (post-2030 to
2050), attention is drawn to the sensitivity
analysis conducted as part of our value-in-use
impairment testing for oil and gas assets,
outlined in Financial statements – Note 1. While
not intended to extend the strategic resilience
test as outlined above to the long term, it
provides an indication of how we monitor
potential longer-term financial impact to
revenue downside which, if resultant from
reductions in price in isolation, may be
associated with prices towards the bottom of
the range of trajectories in the Transition
Scenario Catalogue.
Our approach, described in more detail on
page 52, is directly applicable to transition
risks #1 and #2 – as well as their associated
opportunities – as these lend themselves to a
financially quantified scenario-based analysis.
The approach does not directly address
transition risk #3 – however, we believe that
some of the potential drivers for transition risk
#3, namely policy and societal trends, may be
implicit in these scenarios, and we believe that
the successful execution of our strategy will,
over time, help to mitigate this risk to bp as
well as positioning us to take advantage of the
potential associated opportunities. This
scenario analysis exercise also does not
directly address climate-related physical risk,
our strategic resilience to which is further
discussed below.
Key insights from our scenario analysis
and resilience test
While the results of any such analysis must be
treated with caution (being necessarily
dependent on numerous assumptions and
methodological choices, and having its own
limitations) overall this analysis and resilience
test reinforced our confidence in the
continued resilience of our strategy to a wide
range of transition scenarios, including those
consistent with limiting temperature rise
to 1.5°C.
In summary, the modelling indicated once
again that oil prices consistent with a 1.5°C
transition scenario remain our greatest
transition exposure to 2030, but that
nonetheless bp remains resilient to the lowest
oil price scenarios tested.
In undertaking this analysis we observed:
•There is considerable uncertainty across,
and often within, each Transition Scenario
Catalogue family in the pace and nature of
the transition to 2030 – and therefore
considerable range of potential financial
impact across some of the variables
selected for the analysis, reflecting the
complexity and interdependencies of the
energy transition (see table on page 53).
Generally, we observed that the faster the
pace of transition, the greater the
uncertainty in the exact shape of the
resulting energy system in 2030.
•Oil priceb is likely to remain the main source
of climate-related transition uncertainty for
our strategy through to 2030, reflecting
both the wide range of potential pathways
and the expected contribution to our total
adjusted EBITDA« over this period, that oil-
price-linked businesses representc.
•In the 1.5°C family, the potential downside in
2030 suggested by the lowest oil prices in
the Catalogue (the IEA WEO 2024 Net Zero
Emissions by 2050 (NZE) scenario) is
around 23% of group adjusted EBITDA in
2030. Scenarios from other scenario
families and providers (e.g. NGFS) indicated
higher prices in this time period.
aAlthough such scenarios do not and cannot represent all possible futures, we value them as a simplified and schematic way to consider the potential implications of, and uncertainty inherent
within, a range of possible energy transition pathways to a future bp portfolio mix.
bOur multi-year (2027-30) oil price resilience test considered 2030 low oil prices consistent with the most extreme scenario in the Transition Scenario Catalogue – the IEA WEO 2024 Net Zero
Emissions by 2050 (NZE) scenario at $42/bbl (2023 $ real – inflated in line with bp’s other planning assumptions). Intervening years are interpolated from 2025 average actual Brent oil price.
cNote that for the purposes of our scenario analysis and resilience test, we have assessed the impact of oil price across both our oil production businesses and those natural gas businesses for
which commercial outcomes are linked to oil price.
bp Annual Report and Form 20-F 2025 | 51 |
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Strategic report | ||||
•Even with the most extreme 1.5°C-
consistent low oil price environment in any
of the scenarios, over the period from
2027-30, taking into account our ability to
optimize within the frames set out in our
strategy, and the mitigations that we would
naturally be expected to make in a lower
oil-price world, in our analysis we are able
to deliver across the three lenses we use to
consider strategic resilience for TCFD
purposes, described above.
•Furthermore, in several of the source
scenarios within the Transition Scenario
Catalogue tested, including those
consistent with 1.5°C, well-below 2°C and
BAU families, oil price could potentially
offer a financial upside relative to our
reference 2030 group business outlook.
•The maximum potential scale of downside
impact on our 2030 group adjusted EBITDA
(across the 1.5°C, well-below 2°C and BAU
scenarios) from our other natural gas and
our refining businesses was modelled to be
around 5%, while from each of our fuels and
low carbon energy business areas was <3%.
•It is reasonable to consider each potential
outcome in isolation since the outcomes
for different business areas vary across
scenarios (see table on page 53). Our
diversified portfolio helps mitigate the
implications for our strategic resilience of
the exposure of any individual business
area to the identified risk.
•In a BAU scenario, we believe our strategy
mitigates the risk of what we and others
have referred to as a ‘delayed and
disorderly’ transition, which might follow in
the medium to long term. Should the
earnings of any one of our in-scope
transition business« areas be challenged in
the modelled timeframe, our analysis
suggests that the impact of this on group
adjusted EBITDA in 2030 would not be
sufficient to impact the resilience of our
strategy, as described above.
•When considering the long term, the
outcome of impairment sensitivity analysis
is detailed in the Financial statements –
Note 1, which indicates the magnitude of
the reduction in the carrying amount of bp’s
currently held upstream oil and gas
properties.
It is important to note that insights from this
analysis are necessarily limited by the
scenarios, methodologies and business
assumptions used. The analysis should not be
taken as a prediction of the future.
Maintaining strategic resilience
to the transition
Taking into consideration potential constraints
associated with factors such as long-term
capital investment, contractual commitments
and organizational capabilities at any given
time, bp’s ability to maintain strategic
resilience rests, in part, on the governance
used to keep the strategy under review in
light of new information and changing
circumstances.
To enable us to understand and respond to the
changing pace of the energy transition, we
monitor and assess key indicators and metrics,
such as policy development, renewables
installed capacity, EV sales and low carbon
technology costs.
Our strategy and capital allocation, the
associated risks, opportunities and (by
association) their implications for our
resilience are all reviewed by the bp leadership
team and the board and updated as they
consider appropriate.
Resilience to physical risk
As described on page 49, we have identified a
number of physical risks which may affect our
business and assets, the frequency or severity
of which could be affected by climate change.
Exposure to physical climate-related risk is
highly dependent on geographical location
and on factors such as asset design, and we
seek to manage these risks accordingly. We
consider that our approach to managing these
risks, described in Risk Management
Recommended Disclosure b) on page 46,
supports our strategic resilience to them.
For the purposes of this Recommended
Disclosure, we have considered the potential
for physical risks to bp-operated assets to
increase as a result of climate change (namely,
increases in the potential frequency or
intensity of extreme weather events) to such
an extent as to have the potential to impact
the resilience of our strategy. We have
undertaken analysis of potential changes in
certain physical conditions, such as air
temperature, precipitation, sea level rise and
wave heights, for our onshore and offshore
major operating sites, based on Shared
Socioeconomic Pathwaya (SSP) emission
scenarios 1-2.6, 2-4.5 and 5-8.5.
Even in the highest emissions pathway
(SSP5-8.5) the results of our analysis suggest
that, on the basis of the 50th percentile values
and compared to the baseline used
(1991-2020), changes in the physical
parameters considered are generally unlikely
to be significant over the medium term.
There is, however, uncertainty across different
scenarios and wider variances were observed
when looking at the 5th and 95th percentile
values. Where the data does suggest greater
potential for climate-related changes in
physical conditions, we intend to consider
whether further work is necessary to
understand the potential for those changes to
adversely impact our operations. For example,
modelled changes in extreme precipitation by
2030 (50th percentile values) are less than 10%
across all onshore major operating sites apart
from Oman – where we have already
undertaken hydrological studies and flood risk
assessments that have supported the
development of our operations there.
Our transition risk scenario analysis identified
impacts on the earnings of our oil-priced
businesses as having the most potential to
impact the resilience of our strategy in 2030.
Therefore, and viewing resilience through the
same lenses that we describe above, we have
considered the extent to which our oil and gas
production business would need to be
impacted by evolving physical risk over the
same timeframe for the scale of financial
impact to be sufficient to jeopardize the
resilience of our strategy out to 2030.
We concluded that a significant proportion
of our oil and gas assets would need to be
permanently or temporarily shut in for
resilience to be jeopardized in this way.
Historically, severe weather risks to our
operated assets have not occurred at a scale
which could reduce earnings so significantly
as to jeopardize the resilience of our strategy.
As reflected in the latest science from the
IPCC, it is in the nature of climate-induced
severe weather events that their occurrence,
intensity and severity are unpredictable and
uncertain. Our own analysis on major
operating sites, described above, is consistent
with this IPCC view.
Despite this uncertainty, we have found no
definitive basis in either the IPCC report or the
limited number of detailed studies we have
undertaken (see page 49), to conclude that
climate-change-induced increases in the
frequency or severity of severe weather events
would be likely to result, at any point in time
out to 2030, in disruption and shutdowns
across our oil and gas portfolio on a scale that
would reduce earnings so significantly as to
jeopardize the resilience of our strategy.
For the purposes of this Recommended
Disclosure, the resilience of our strategy was
considered separately for the relevant
transition and physical risks; accordingly, we
did not seek to take account of any
interdependencies or cumulative effects
between the two types of climate-related risk,
aSSPs have been developed by the climate change research community to describe plausible major global developments that together would lead in the future to different challenges for
mitigation and adaptation to climate change. The SSPs are based on five narratives describing alternative socioeconomic developments, including sustainable development, regional rivalry,
inequality, fossil-fuelled development and middle-of-the-road development.
and the associated potential financial impact.
52 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Climate-related financial disclosures continued | ||
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Our approach to testing resilience to transition risk | ||||||
Most of our analysis focused on our medium- term time horizon (2030) – far enough ahead to provide a divergent range of scenarios, while not so far ahead that it is unrealistic to attempt to generate credible financial metrics for bp, or an individual business area within bp. For the variable(s) considered most significant, we also assessed resilience over the period 2027-30. Beyond 2030 we highlight the impairment sensitivities in the Financial statements – Note 1. Our analysis sought to quantify the potential impact of a range of scenarios, including those consistent with 1.5°C, on bp’s currently held (at the time the analysis was completed) internal reference group business outlook to 2030. This outlook is used for internal corporate planning and holds a deterministic view of our portfolio, activity set, cost and capital frame – this aligned with the strategic direction shared at the February 2025 Capital Markets Update. We have additionally validated the conclusions of step 3, below, using our most recent internally-held financial outlook (as at 10 February 2026). Resilience is assessed against the financial priorities set out in the 4Q/full year 2025 results update (10 February 2026). A high-level summary of the steps taken as part of our scenario analysis is as follows: 1.Whole company assessment: We defined, through quantitative analysis, which business areas could have both the financial scale and clear transition exposures to potentially impact bp’s strategic resilience. a.We assessed the business areas in our portfolio by i) quantitatively evaluating each business area’s ‘potential significance’ by its expected contribution to bp group adjusted EBITDA« in 2030 and therefore the quantum of financial impact that might be put at risk by transition uncertainty (including pathways consistent with 1.5°C); and ii) by identifying, for each, whether there were primary potential value driver(s) that different transition pathways might impact (‘transition risk driver(s)’). b.Three broad business areas (see table below), representing over 70% of 2030 adjusted EBITDA, were identified as both providing a potentially significant financial contribution and facing clear primary transition risk drivers, and so were subjected to the driver-based analysis set out in steps 2a-2b below. c.The remaining business areas followed a simplified approach – step 2c. | 2.Scenario analysis: We tested the financial impact of transition on all of bp’s business areas in 2030 through either specific ‘driver-based’ scenario modelling (a-b), or ’simplified’ scenario analysis (c). a.For the driver-based scenario analysis, we selected the primary transition risk driver(s) for each business area – the variable(s) from the Transition Scenario Catalogue« (see below) representing what we consider to be the primary driver(s) of that business area’s primary exposure to the energy transition. For each transition risk driver, we extracted the full range of 2030 outcomes within each scenario ’family’. Given the global nature of the transition risks and opportunities we have identified, we used the ‘world’ values in the Catalogue except for gas price (see table on page 53). b.By calibrating the Catalogue’s 2030 scenarios to relevant business metrics underpinning our strategic planning (for example, oil price or primary energy demand for oil), we modelled the impact of each variable, across the full range of scenarios and each scenario family, including the most extreme downside scenarios, on the 2030 expected earnings (adjusted EBITDA) for the associated business area. For example, we applied an underlying RC profit« rule of thumb to the deviation of oil prices in the Catalogue versus our reference case price. This analysis was ‘unmitigated’ (see ’Other key considerations’, below). c.For the simplified scenario analysis, used for the remaining business areas identified in step 1c, we took a simpler conservative approach, by evaluating whether a scenario in which each business area’s expected 2030 adjusted EBITDA is assumed to be reduced to zero (an outcome considered to be at least as detrimental as could be expected to result from ranges associated with 1.5°C, 2°C or BAU scenario families) could have the potential to impact strategic resilience (as defined below). d.This analysis enabled us to assess the potential for each business area to impact group adjusted EBITDA (and by implication associated cash flows) in 2030, when compared to the reference group business outlook, to identify which (if any) businesses, variables and scenarios may have the potential to most materially impact strategic resilience (as defined below), and as such, which business areas should be carried forward into a multi-year resilience assessment. | 3.Multi-year resilience test: This step tested bp’s resilience to the exposure of any sufficiently material business areas to downside scenarios that may have the potential to jeopardize the ability to generate excess cash flow« and a strong cash cover ratio – financial metrics that were treated for the purposes of this analysis as representing financial evidence of delivery of bp’s strategic financial priorities (see below). From step 2, in 2025, only the exposure to oil price was assessed as sufficiently material in this sense. Our multi-year (2027-30) oil price resilience test considered sustained low oil prices interpolated from 2025 actual Brent price to the most extreme 2030 Transition Scenario Catalogue case (IEA WEO 2024 NZE by 2050 Scenario) – falling to a 2030 minimum price of $42/bbl (2023 $ real). Other scenarios, from providers such as UN PRI IPR and NGFS, formed part of the Catalogue, but indicated higher prices than the IEA WEO NZE case used. For information about the approach to impairment sensitivity testing see Financial statements – Note 1. Transition Scenario Catalogue data •The latest WBCSDa Energy Climate Scenario Catalogue which was Version 3.0 published May 2024, has been used as a starting point for compiling a suite of transition scenarios. While there has been no more recent update to the WBCSD Catalogue (at the time of preparation), certain underlying source providers (IEAb, NGFSc, UN PRI IPRd) have since published updated scenarios for key transition variables or have ‘retired’ older scenarios. •To reflect this more recent information, the Transition Scenario Catalogue we used is therefore based on variables and scenario families from WBCSD V3, updated for amended IEA, NGFS and UN PRI IPR data where available (see footnotes on the next page for details). •For updated variables, oil and gas price and primary energy demand for oil (used for oil, gas and refining) were directly available in the published data. ‘Final energy demand for liquid oil in road transport’; used for bp’s road transport- related business areas, was not directly available from updated publications and so required some simple derivation by bp: ‘Total final consumption in road transport’ (IEA) and ‘Final energy demand in road transport’ (NGFS) were | ||||
| | |||||
bp Annual Report and Form 20-F 2025 | 53 |
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Strategic report | ||||
| | |||||
disaggregated to estimate the proportion associated with liquid oil based on the published breakdown of ‘Road transport final energy demand by energy source’ published in WBCSD V3. We believe that this disaggregation of source data was similarly required in previous years to be conducted by WBCSD and its partners in preparing their Scenario catalogues. Other key considerations •For the purposes of steps 2 and 3, we considered the resilience of our strategy to climate-related transition risk through the three lenses described on page 52. We defined the following as proxy indicators for these lenses: –Positive group excess cash flow (in 2024 termed ‘surplus cash flow’), to demonstrate whether after funding, among other things, capital spend within our disclosed capital frame to 2027 (February 2025 Capital Markets Update) and a resilient dividend per ordinary share, sufficient excess cash flow remains to maintain or reduce net debt over the period. –Healthy cash cover ratio as an indicator of the ability to maintain a strong investment grade credit rating. •For steps 2 and 3, we made the simplifying assumption that, aside from the driver being modelled, our strategy, operating model, volumes, margins, sales proceeds and tax rates would remain unchanged out to 2030. | •There are a range of mitigations or actions that we might naturally be expected to experience (e.g. through deflation) or to take in response to external market, price and demand trends, including cost reductions, portfolio adjustments, shareholder distribution and balance sheet choices, capital reallocation or capital reductions within the frames set out in our strategy. •For step 3, given we would seek to make use of opportunities to maintain our strategic flexibility in the face of the many uncertainties of the energy transition, our methodology retains the optionality in downside scenario modelling to apply some or all of these mitigations. •As outlined above, we utilized our latest internal reference group business outlooks as the basis against which resilience has been tested, as this forms a deterministic view against which to model the transition sensitivities to 2030 and aligns to the strategic updates provided to investors in February 2025 (and February 2026). Alongside disclosed elements such as the capital frame range to 2027, this includes shaping assumptions such as future distributions and net debt management. •Rules of thumb applied to convert variance in hydrocarbon price to variance in adjusted EBITDA, these are considered appropriate to the period in question – i.e. they reflect the portfolio’s changing price leverage over the period to 2030. Due to the evolution of bp’s portfolio, these rules of thumb may diverge from any short- term rule of thumb that we publish. | •Through conducting this analysis, we do not intend to imply or commit to a specific forward trajectory of usage of cash, beyond any disclosed in the investor update in February 2025 (and 4Q/full year 2025 results on 10 February 2026) or other published strategy updates. While we cannot disclose, for confidentiality reasons, the detail of the deterministic case, the test assesses whether the resilience indicators in our reference group business outlook are impacted by the transition uncertainties tested. Further, by the nature of the timeframes considered, a variety of uncertainties exist around this deterministic case (including transition risk itself). •The design of a strategic resilience analysis involves numerous methodological choices and assumptions any one of which could reasonably have been different, leading to different outcomes. We have found value in conducting this analysis; however, we are mindful of the limitations to any such exercise and the highly qualified nature of any conclusions which may be drawn from it. The disclosures provided here should be read in conjunction with the rest of our strategic report, where we discuss how we have developed, and continue to evolve, our approach to strategy. | ||||
| |
Transition Scenario Catalogue« family ranges for 2030 key transition variables | |||||||
Scenario families (as categorised by WBCSD/source providers): | BAU | Below 2°C | 1.5°C | ||||
Business area | Transition variable | Min | Max | Min | Max | Min | Max |
Oil and natural gas production | Oil pricee ($2023/bbl) | 65.2 | 81.2 | 65.4 | 81.2 | 42.0 | 72.3 |
Natural gas pricef ($2023/mmbtu) | 3.81 | 4.38 | 2.59 | 4.38 | 2.10 | 4.62 | |
Refining – refined oil demand | Primary energy demand for oil (% change vs 2020) | -2.4 | 14.4 | -4.2 | 8.7 | -21.3 | -5.9 |
Conventional fuels retail and midstream | Final energy demand for liquid oil in road transport (EJ/yr) | 74.3 | 88.7 | 71.9 | 88.7 | 63.5 | 72.1 |
For the other business areas not shown aboveg, we applied the generic scenario analysis methodology described in point 2d, above, thereby
ensuring coverage of all of bp’s business areas.
aWorld Business Council for Sustainable Development; for the WBCSD Energy Climate Scenario Catalogue 3.0 (2024) see https://climate-scenario-catalogue.shinyapps.io/final_2024/.
bIEA World Energy Outlook (WEO) 2023, in WBCSD V3, updated with relevant data from IEA WEO 2024 (published October 2024); see https://www.iea.org/reports/world-energy-outlook-2024.
cNGFS v4.2, in WBCSD V3, updated with relevant data from NGFS v5.0 (released November 2024); see https://www.ngfs.net/ngfs-scenarios-portal/data-resources.
dUN PRI Inevitable Policy Response Forecast Policy Scenario (2023), in WBCSD V3, updated with relevant data from UN PRI IPR Transition Forecast Scenario (2025); UN PRI IPR Required Policy
Scenario (2021), in WBCSD V3, removed (now regarded as outdated); see https://ipr.transitionmonitor.com.
eOil price sensitivities have been applied to the oil and gas production portfolio that is linked to oil marker prices – as such it not only reflects oil production exposure, but also a proportion of bp’s
natural gas production that is contracted off oil marker prices.
fGas prices shown reflect Henry Hub price ranges. Where available, Asian and UK gas price sensitivities have also been selected and compared to the Henry Hub sensitivity percentages with the
maximum deviation selected and applied to the respective Asian and NBP rules of thumb for these parts of the gas portfolio, in order to provide the most conservative uncertainty range.
gIn 2025 this included, for example, biogas and biojet production, aviation fuel sales, EV charging, renewables and hydrogen production, as well as convenience and trading and shipping.
54 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Climate-related financial disclosures continued | ||
Metrics and targets
| | |
TCFD Recommendation: Disclose the metrics and targets used to assess and manage relevant climate-related risks and opportunities where such information is material. | ||
| |
We present the principal group-wide metrics
and targets used to assess and manage
climate-related risks and opportunities in line
with our strategy and risk management
process below, with metrics and targets
mapped to the most relevant of TCFD’s
cross-industry, climate-related metric
categories (such as ‘transition risks’).
The metrics and targets themselves are
disclosed at the most appropriate locations
in this strategic report.
| | |||
TCFD recommended disclosures – metrics and associated targets/goals | ||||
a) Disclose the metrics used by the organization to assess material climate-related risks and opportunities in line with its strategy and risk management process. Transition risks •Note 5 to Financial statements: Segmental analysis. Segment revenue (in table), pages 185-189 •Estimated net proved reserves and production (net of royalties), page 27 •Note 4 to Financial statements: Disposals and impairments, page 182 •Note 8 to Financial statements: Impairment losses (in table), page 190 •Oil and natural gas prices used for value-in-use impairment testing and recoverability of asset carrying values, page 168 Physical risks •Number of major operating sites in regions with high to extremely high water stress, page 59 •Freshwater withdrawals and consumption at major operating sites in regions with high or extremely high water stress, page 59 Climate-related opportunities •Note 5 to Financial statements: Segmental analysis. Segment revenue (in table), pages 185-189 •Gas & low carbon energy, page 28 Capital deployment •Financial frame, page 18 •Price assumptions, key investment appraisal assumptions, page 20 (in table, indicated with TCFD) •Amount invested in transition businesses«, page 21 •Additional information – capital expenditure by segment, page 335 •Note 7 to Financial statements: expenditure on research and development (in table), page 189 •Note 8 to Financial statements: exploration and evaluation costs (in table), page 190 Internal carbon prices •Internal carbon price, page 20 Remuneration •Directors’ remuneration report metrics: operated carbon emissions, page 99 | b) Disclose Scope 1, Scope 2, and, if appropriate, Scope 3 greenhouse gas (GHG) emissions, and the related risks GHG emissions •Key performance indicators (relevant KPIs shown with TCFD), page 17a •Scope 1 and 2, in SECR table page 39 •Ratio of Scope 1 and 2 emissions: gross production, in SECR table page 39 •Scope 3 (related to category 11) emissions page 38b •TCFD: risks as described in Strategy a, page 46 •Risk factors, page 67 •A further breakdown of our GHG and energy data by business group is available in the bp ESG Datasheet 2025 at bp.com/ESG | |||
c) Describe the targets used by the organization to manage climate-related risks and opportunities and performance against targets. Transition risks •Net zero operations« (including methane), page 38 •Net zero sales«, page 38 Physical risks •Water, page 59 Climate-related opportunities •Net zero operations (including methane), page 38 •Net zero sales, page 38 Capital deployment •Transition business investment, page 21 Remuneration •Incentivizing employees, page 58 GHG emissions •Net zero operations (including methane), page 38 •Net zero sales, page 38 | ||||
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aThese are our KPIs for the purposes of our disclosures pursuant to the UK CFD Regulations and Section 414CB (2A) (h) of the Companies Act 2006.
bIn determining the Scope 3 emissions that are ‘appropriate’ to be disclosed for the purposes of this Recommended Disclosure, we have considered this term in the context of the
recommendation to disclose the metrics and targets used to assess and manage relevant climate-related risks and opportunities.
bp Annual Report and Form 20-F 2025 | 55 |
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Strategic report | ||||
Sustainability continued | ||||
Our approach to sustainability
Our approach to sustainability is built on
strong foundations. They guide the way we
work, underpin our focus on safety and
support our net zero, people and planet aims.
Safety comes first
At bp, safety comes first. We want to improve
our safety performance and work towards our
goal to eliminate fatalities, life-changing
injuries and tier 1 process safety events.
We deeply regret the four fatalities and three
life-changing injuries that occurred in 2025.
Three employees in our TravelCenters of
America businessa died at work – two while
carrying out emergency roadside assistance in
separate incidents and one while servicing a
truck. In response, we have permanently
stopped roadside assistance next to active
traffic lanes. A contractor in our Thorntons
retail business died after falling from a ladder.
One employee and two contractors suffered
life-changing injuries. Two were hand injuries –
one in our TravelCenters of America businessa,
the other in our Mauritania and Senegal
business. The third was a head injury which
occurred during a crane lifting activity in the
North Sea (UK).
We have offered our support to the bereaved
families and the injured workers. We know we
have more work to do to improve our safety
culture and performance.
Keeping people safe
We remain focused on risks that have the
potential to cause fatalities or significant
injuries and we monitor and report on key
workforce personal safety metrics in line with
industry standards. We include both
employees and contractors in our data.
Life‑changing injuries decreased from six in
2024 to three in 2025ab. Our recordable injury
frequency (RIF) also decreased by 21%
compared to 2024, see page 16. These
reductions are encouraging, but we know we
must maintain our efforts to continue
improving our safety performance, by applying
the International Association of Oil & Gas
Producers’ (IOGP) Life-Saving Rules and our
own Safety Leadership Principles.
In 2025 we gained new insights about the
effectiveness of the IOGP’s Life-Saving Rules
in bp, due to the introduction of conformance
checklists tailored to the needs of specific
businesses.
aAt the time of publication (March 2026), as part of the transition period for recently acquired businesses, the safety reporting processes were still being integrated into bp’s safety reporting
processes. As such, data from Archaea Energy, TravelCenters of America, Lightsource bp, bp bioenergy, X Convenience and new Eagle Ford assets in bpx energy are not included in 2025
reported data.
bIn addition to the four life-changing injuries reported in the bp Annual Report 2024, two additional injuries that occurred in late 2024 were later classified as life-changing after the publication of
the 2024 report, in accordance with the 180-day classification window for life-changing injuries, bringing the total to six life-changing injuries in 2024.
cFor recently acquired businesses, there is typically a transition period while bp’s operating standards, as set out in OMS, are integrated or aligned.
dThe number of accidental or unplanned losses of hydrocarbon from primary containment from a bp or contractor operation, irrespective of any secondary containment or recovery. Oil spills >
1bbl are defined as any liquid hydrocarbon release of more than, or equal to, one barrel (159 litres, equivalent to 42 US gallons).
Driving safety
Driving continues to be one of the biggest
personal safety risks we face at bp. In 2025
five severe vehicle accidents occurred (2024
5). The number of kilometres driven fell by 19%
during the same period.
2025 | 2024 | 2023 | ||
Severe vehicle accident rate per million km driven | 0.03 | 0.02 | 0.02 |
Our Operating Management Systemc
Our Operating Management System (OMS)«
provides a single framework for delivering
safe, reliable and compliant operations. Our
OMS sets out the way in which our businesses
within our operational control around the
world are expected to understand and manage
their environmental and social impacts,
including requirements on engaging with
stakeholders who may be affected by
our activities.
We review and amend these requirements
from time to time to reflect our priorities. Any
variations in the application of our OMS, in
order to reflect the specific circumstances of
a bp entity or meet local regulations or
circumstances, are subject to a governance
process.
Our OMS requires each of bp’s operating
businesses to create and maintain its own
OMS handbook, describing how it will carry out
its local operating activities.
We use a ‘three lines of defence’ model to
facilitate the effective management of all
types of risk, including safety. The nature and
extent of first, second and third lines of
defence activities are based on the type and
level of risk.
Preventing incidents
We plan our operations carefully to identify
potential hazards and manage risks at every
stage through rigorous operating and
maintenance practices applied by capable
people. We design our new facilities in line
with process safety, good design and
engineering principles. We track our process
safety performance using industry-aligned
metrics such as those found in the American
Petroleum Institute recommended practice
754 and the IOGP recommended practice 456.
Our combined reported tier 1 and tier 2
process safety events« (PSEs) have decreased
for the past 12 years, apart from in 2019. There
were 27 PSEs in 2025 (2024 38), of which five
were tier 1 (2024 3) and 22 were tier 2 (2024 35).
In 2025 the number of oil spillsd increased to
110, compared with 96 in 2024.
Our operating sites share examples of good
practice, while our central health, safety, and
environment incident investigations team
reviews serious or complex incidents, which
may include near misses. Supported by the
use of leading indicators, such as inspections
and equipment tests, these activities help us
monitor and strengthen controls and identify
and address systemic gaps to prevent
incidents.
2025 | 2024 | 2023 | ||
Tier 1 and tier 2 process safety events« | 27 | 38 | 39 | |
Oil spills – number | 110 | 96 | 100 | |
Oil spills – contained | 57 | 49 | 52 |
Emergency preparedness
We have disaster recovery, crisis and business
continuity management plans and work to
build day-to-day response capabilities to
support local management of incidents. We
test our plans and preparedness through
exercises that simulate real-life scenarios. In
2025 we conducted 37 exercises in countries
including India and the US.
Security
We protect our people, assets and operations,
and manage security through a threat-driven,
risk-based approach. We continuously monitor
threats from activism, civil unrest or political
instability, terrorism, armed conflict, and
criminal and cyber activity. Our 24-hour
intelligence and response information centre
in the UK monitors global security risk in real
time. It helps us to assess the safety of our
people and provide them with practical advice
if there is an emergency.
Cyber security
The severity, sophistication and scale of cyber
attacks continue to evolve. Increasing
digitization, the emergence of new technology
such as generative artificial intelligence, and
reliance on IT systems and cloud platforms
56 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Sustainability continued | ||
makes managing cyber risk a priority for many
industries, including our own. Direct or
collateral impact can come from a variety of
cyber threat actors, including nation states,
criminals, terrorists, hacktivists and insiders.
As in previous years, we have experienced
threats to the security of our digital systems
and our barriers have worked well to mitigate
and contain them to minimize any impact on
our business.
We have a range of measures to manage this
risk, including the use of cyber security
policies and procedures, security protection
tools, threat monitoring and event detection
capabilities, and incident response plans. We
conduct exercises to test our response to, and
recovery from, cyber attacks. We collaborate
closely with governments, law enforcement
and industry peers to understand and respond
to threats.
To encourage vigilance among our employees,
our extensive cyber security training courses
and awareness programmes provide regular
education on a wide range of topics such as
phishing and the correct classification and
handling of our information. We also use a
cyber barometer tool to empower individual
risk mitigation.
| How we manage risk, page 60 Additional disclosures – cyber security, page 360 |
Working with contractors
Through documents that help bridge our
health, safety and environmental policies and
those of our contractors, we define the way
our OMS co-exists with systems used by our
contractors to manage risk on a site. We
conduct risk-based quality, technical, health,
safety and security audits before awarding
contracts. Once contractors start work, we
continue to monitor their safety performance.
Our OMS includes requirements and practices
for working with contractors. Our standard
model contracts include health, safety and
security requirements. We expect and
encourage our contractors and their
employees to act in a way that is consistent
with our code of conduct and take appropriate
action if those expectations, or their
contractual obligations, are not met.
Our partners in joint arrangements
We monitor performance and how risk is
managed in our joint arrangements«,
whether we are the operator or not. In joint
arrangements where we are the operator,
our OMS, code of conduct and other
policies apply.
Our people
Workforce by gender
As at 31 December 2025 | Male | Female | Female % | ||||
2025 | 2024 | 2025 | 2024 | 2025 | 2024 | ||
Board directors | 7 | 5 | 6 | 6 | 46 | 55 | |
Leadership team | 4 | 5 | 4 | 5 | 50 | 50 | |
Group leaders | 169 | 186 | 99 | 100 | 37 | 35 | |
Subsidiary« directors | 473 | 519 | 294 | 253 | 38 | 33 | |
All employeesa | 58,400 | 62,000 | 35,100 | 38,300 | 37 | 38 | |
Number of employees
As at 31 December 2025 | 2025 | 2024 | 2023 | |
Gas & low carbon energy | 5,600 | 6,500 | 4,800 | |
Oil production & operations | 9,300 | 9,200 | 8,800 | |
Customers & products | 66,900 | 73,100 | 63,400 | |
Other businesses & corporate | 11,800 | 11,700 | 10,800 | |
Total | 93,700 | 100,500 | 87,800 | |
a Some employees have not disclosed gender, therefore are not included in this total. | ||||
We aim to report on aspects of our business
where we are the operator – as we directly
manage the performance of these operations.
Where we are not the operator, our OMS is
available as a reference point for bp
businesses when engaging with other
operators and co-venturers. We have a group
framework to assess and manage bp’s
exposure risks from our participation in these
types of arrangements.
Where appropriate, we may seek to influence
how risk is managed in arrangements where
we are not the operator.
The people, culture and governance
committee reviews workforce policies and
practices and their alignment with bp’s
strategy, purpose, beliefs and culture, and
conducts workforce engagement measures.
| People, culture and governance committee report, page 89 |
bp Annual Report and Form 20-F 2025 | 57 |
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Strategic report | ||||
Our culture
We want to build a culture that supports all of
our employees and promotes inclusion,
wellbeing and development.
Our culture frame, ‘Who we are’, defines what
we stand for and is integrated into our code of
conduct and our approach to inclusion. We
maintain oversight of our culture by measuring
employee sentiment and encouraging
employees to use our speak-up channels.
Read more about the board’s role in
overseeing bp’s culture on page 90.
Developing our people
Our people are crucial to delivering our
strategy and aims. We invest to ensure we
have the right people with the right skills
from diverse backgrounds, and we provide
training, development and competitive
rewards for them.
In 2025 bp employees collectively completed
around 2.1 million hours of formal learning
(2024 1.2 million hours). bp’s learning and
development framework is applicable to all
employees and covers safety, technical and
operational skills, leadership, and future skills.
Our mandatory training curriculum covers
conformance with our internal standards and
applicable laws and regulations.
Building an inclusive culture
Part of our people aim is to foster an inclusive
culture with an employee workforce that
reflects the communities where we work. To
deliver our strategy we believe we need to
capitalize on the diversity of perspectives,
backgrounds, skills and experiences within
our workforce.
Improving representation
We make all employment decisions based on
merit without regard to gender, race, age,
disability, or any other protected status.
In 2025 global female representation in bp was
37% (2024 38%), four of the eight positions in
our leadership team were held by women, and
37% of group leader roles were filled by
women (2024 35%).
In 2025 our ethnic minority representation in
the UK remained steady at 22% of our overall
workforce (2024 22%).
| bp Gender and Ethnicity Pay Gap Report, bp.com/ukgenderpaygap |
In line with UK reporting requirements, we
disclose information against external targets
on the representation of women and ethnic
minorities on our board and executive
management. Read more on diversity
reporting in line with the Listing Rules on
page 126.
| Composition of the board, page 73 |
Promoting inclusion
To promote an inclusive culture, we support
employee-run business resource groups
(BRGs) in areas such as age diversity, social
mobility, gender, ethnicity, and disability.
As well as bringing employees together, these
groups contribute to our inclusive culture,
provide a representative voice for employees
and highlight and celebrate the achievements
of different groups. Each group is sponsored
by a senior leader and open to all employees.
Improving accessibility
We continue to take steps to progress
inclusion for our neurodivergent employees
and those with disabilities. We offer access to
support including assistive technology, such
as immersive readers and peripheral
accessories.
To help meet the requirements of our
employees we work closely with our
employee-led disability BRGs.
If existing employees become disabled, our
policy is to engage and use reasonable
accommodations or adjustments to enable
continued employment.
We have partnerships to help us implement
best practice methods to support
neurodivergent employees and those with
disabilities. Our partners include the Business
Disability Forum in the UK.
Employee engagement
Our managers hold team and one-to-one
meetings with their team members,
complemented by formal processes through
works councils in parts of Europe.
We regularly communicate with employees on
factors that affect bp’s performance, and seek
to maintain constructive relationships with
labour unions formally representing our
employees.
In 2025 we reset our approach to performance
management to reflect our organizational
focus on delivering bp’s strategya by
introducing clearer, more transparent
processes – aligned goals, business
scorecards, a new annual review cycle and a
simple individual rating system. These changes
will help embed a stronger performance
culture that supports our strategy.
We monitor employee sentiment through
several channels including our Pulse annual
employee survey, which is sent to all eligible
employees, and through our Pulse live survey,
which is sent to a representative sample of
employees weekly. In 2025 our overall
engagement metric, employee engagement,
decreased to 66%b (2024 70%).
We will continue to develop engagement plans
based on feedback from the annual and
weekly surveys to help us deliver on safety,
and meet our strategic objectives. The 2025
Pulse survey results highlight three priority
areas for engagement in 2026: two of these –
emphasizing psychological safety, and
strategy and performance – were also
priorities in 2025. The third – career and
development – is new.
| Our employee engagement key performance indicator, page 16 How the board engaged with the workforce, page 80 |
Workforce health and wellbeing
We include an employee wellbeing index in our
Pulse annual employee survey and weekly
Pulse live surveys. Results from 2025 showed
that employee wellbeing decreased to 69%b
(2024 73%) generally because of organizational
transformation.
During bp’s transformation programme, we
have offered comprehensive mental health
support to employees which has been
developed through listening forums and
employee feedback.
Our approach to workforce health and
wellbeing combines globally available services
that can be tailored to meet local needs. All
employees have access to our global digital
health and wellbeing hub, Thrive@bp.
aThis reset approach to performance management is subject to local law, including consultation where required.
bAs a result of changes to the question set and the inclusion of employees from our retail business in the 2025 Pulse survey, the engagement and wellbeing scores for 2025 are not comparable
with prior years.
TCFD TCFD Recommendations and Recommended Disclosures
58 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Sustainability continued | ||
Linking remuneration to
sustainability TCFD
The bonus scorecard for 2025 against which
eligible employeesa are measured incentivized
them through three themes: safety and
sustainability (30%); operational performance
(15%); and financial performance (55%). For
2025 our sustainability measure was linked to
our operated carbon emissions. This measure
covers Scope 1 and 2 emissions based on our
net zero operations« aim. Our 2023-25 long-
term incentive plan scorecard was linked to
emissions reductions against our 2019
baseline (15%).
For 2026, progress towards our aim to achieve
net zero operations by 2050 or sooner will
continue to be rewarded through our long-
term performance share plans rather than the
annual bonus. For 2026-28 the scorecard
measure will focus on reducing Scope 1 and 2
operational emissions (20%).
| Directors’ remuneration report, page 91 |
Share ownership
We encourage employee share ownership and
have a number of employee share plans in
place. For example, we operate a ShareMatch
plan, matching bp shares purchased by our
employees. We also make annual share awards
as part of our total reward package for all
senior and mid-level employees globally, and
a portion of our more junior professional
grade employees.
Ethics and compliance
Our code of conduct
Our code sets out the principles and
expectations that guide our daily activities. It
provides a framework to support safe and
ethical decision making, sets the standards for
how we do the right thing and empowers us to
speak up without fear of retaliation. Our code
is the foundation of ‘Who we are’, our culture
frame, and it puts safety first. Together with
our Safety Leadership Principles and OMS«,
it helps us act responsibly, comply with
applicable laws, and implement our
sustainability frame.
Our code applies to all bp employees, officers
and board membersb. Regular mandatory
training and communications help employees
understand how to apply it and how to raise
questions or concerns.
All bp employees are required to confirm
annually that they have read and understand
our code and act in accordance with its
principles. We expect and encourage all our
contractors and their employees to act in
ways that are consistent with it.
Any concerns or enquiries can be raised
through multiple speak-up channels. These
include line managers, senior leaders, and
contacts in our people & culture, ethics &
compliance, safety & operational risk
assurance or legal teams. We also have a
confidential global helpline, OpenTalk. It is
available for bp employees, the wider
workforce, communities, business partners
and other stakeholders and can be accessed
all day, every day by telephone or internet and
in 75 languages. Anyone has the right to
contact OpenTalk anonymously, except where
prohibited by law.
We take potential misconduct seriously and
thoroughly review allegations and respond,
conducting investigations where appropriate.
We may take action in response to reported
concerns to help proactively mitigate issues
around misconduct. We follow a defined
disciplinary process and will take action or
issue sanctions where appropriate. These may
include coaching or training, formal
reprimands or dismissal.
Nearly 5,000 concerns or enquiries were
reported in 2025 (2024 ~2,800). In 2025
around 1,300 separations resulted from non-
conformance with our code, including
unethical behaviour. Almost 90% of these
separations were from our retail business.
The most frequently raised concerns in 2025
related to alleged bullying, harassment and
discrimination, with these accounting for
around half of all concerns. The second
most common concerns related to allegations
concerning assets and financial integrity.
The 2025 mandatory code of conduct
training assigned to all bp employees
included a specific section on non-
harassment. Additionally, employees were
assigned a separate training module aimed
at preventing fraud.
| bp.com/codeofconduct |
Anti-financial crime
We operate in parts of the world where bribery
and corruption present a high risk, so it is
important that we engage with our employees,
contractors, suppliers and others to
emphasize that our commitment to ethical and
compliant operations is unwavering.
Our code of conduct explicitly prohibits
engaging in any form of bribery, corruption or
money laundering and promotes lawful and
ethical business practices. It includes an
expectation that we work to make sure our
business partners comply with our
requirements.
Our group-wide policies covering anti-bribery
and corruption, anti-money laundering, anti-
fraud and anti-tax evasion all include measures
and guidance to assess risks, understand
relevant laws and report concerns. They apply
to all bp-operated businesses.
We provide appropriate training including
for those employees in locations or roles
assessed to be at a higher risk of bribery and
corruption, money laundering and fraud that
could benefit bp.
In 2025 around 8,100 employees completed
anti-bribery and corruption training as part of
our ethics and compliance risk-based learning.
This is higher than the 5,900 employees
trained in 2024, due to the rolling cadence we
use to assign training.
We also conduct anti-bribery compliance
audits on selected suppliers to assess their
conformance with our anti-bribery and
corruption contractual requirements. We take
corrective action with suppliers and business
partners who fail to meet our expectations,
which may include terminating contracts. In
2025 we issued 19 ABC supplier audit reports
(2024 32).
Political donations and activity
We prohibit the use of bp funds or resources
to support any political candidate or party.
We recognize the rights of our employees to
participate in the political process and these
rights are governed by the applicable laws in
the countries where we operate. Our stance
on political activity is set out in our code
of conduct.
In the US we provide administrative support
for the bp employee political action
committee (PAC) – a non-partisan, employee-
led committee that encourages voluntary
employee participation in the political process.
The bp employee PAC is governed by a board
of directors and administrative by-laws. All
contributions made by the bp employee PAC
are weighed against its criteria for candidate
support and reviewed for legal compliance
before funds are sent to the recipients
requested by our employees, and are publicly
reported in accordance with US election laws.
Contributions made by the PAC are from
employee contributions and not bp funds.
aThe number of employees eligible for a cash bonus in 2025 was around 43,500.
bFor recently acquired businesses, there is a transition period while bp’s ethics and compliance standards, as required in our code, are integrated or aligned.
bp Annual Report and Form 20-F 2025 | 59 |
| ||||
Strategic report | ||||
Tax transparency
We take a responsible and transparent
approach to tax, guided by our responsible tax
principles which align with our code of
conduct and our beliefs.
We comply with the tax legislation of the
countries in which we operate and we do not
tolerate the facilitation of tax evasion by
people who act for or on behalf of bp.
We are committed to transparency around
our tax principles and the taxes we pay. We
paid $8.3 billion in corporate income and
production taxes to governments in 2025
(2024 $10.6 billion).
| bp Tax Report, bp.com/tax |
Trade associations
Trade associations and industry initiatives play
a key role in fostering collaboration, sharing
knowledge and bringing stakeholders
together.
We made changes to the way we review our
trade association memberships in 2025. We
reviewed those with membership fees of
$100,000 or more to identify any significant
misalignments or lack of influence on
relevant policy between the association
reviewed and bp.
| bp.com/tradeassociations |
People and planet
Improving people’s lives
We want to support employees, our wider
workforce and local communities.
People
Our aim is to support our employees and local
communities through the energy transition by:
•Equipping employees with skills that can
improve their access to opportunities in the
energy transition.
•Developing targeted just transition plansa
for select assets or regions, that help
manage potential impacts on and
opportunities for people as we transition.
•Fostering an inclusive culture with an
employee workforce that reflects the
communities where we work (read more
on page 57).
We recognize the importance of a just energy
transition – one that delivers decent work,
quality jobs and supports the livelihoods of
local communities. We report on our work to
equip employees with the skills they need now
and for the energy transition, and on how we
are supporting local communities in the bp
Sustainability Report 2025.
Human rights
We believe everyone deserves to be treated
with fairness, respect and dignity. We respect
the rights of our workforce and those living in
communities where we operate, who are
potentially affected by our activities.
We set out our commitments in our human
rights policy and code of conduct. Our policy
aligns with the UN Guiding Principles on
Business and Human Rights.
It is underpinned by the International Bill of
Human Rights and the International Labour
Organization’s Declaration on Fundamental
Principles and Rights at Work, including its
core conventions.
To support our teams, we provide human
rights training and other awareness-raising
activities.
| bp.com/humanrights |
Caring for the planet
We want to make a positive difference to the
environment in which we operate.
Biodiversity
We understand international concern
regarding the global decline in biodiversity
and recognize that our businesses can have
impacts and dependencies on nature.
We aim to support biodiversity where we
operateb, by:
•Aiming to achieve a net positive impact
(NPI) on all new in-scopec projects.
•Implementing biodiversity enhancement
plans at our major operating sites.
•Collaborating with others to support
selected biodiversity restoration projects.
Building on the work we did in 2022 to finalize
our NPI methodology for use on new, in-scope
projects, we have made consistent progress
over the past few years in our work to apply it.
By the end of 2025 six of our projects were
either implementing or developing NPI plans.
In addition, all our major operating sites in
biodiversity-sensitive areas had developed or
started to implement biodiversity
enhancement plans.
| bp.com/biodiversity |
Water
We aim to reduce our net freshwater use in
stressed catchments where we operateb, by:
•Being more efficient with freshwater use in
our operations.
•Collaborating with others to replenish
freshwater in stressedd catchments. We
anticipate that by 2028, our freshwater
withdrawal in stressed catchments will be
covered by freshwater management plans.
To understand our water-related challenges,
we review water impacts, risks and
opportunities at our operating sites. These
reviews consider the quantity and quality of
water used as well as any applicable
regulatory requirements.
Our water consumption in 2025
Since 2020 we have reduced freshwater
withdrawals (excluding once through cooling
water) by 15% and freshwater consumption
by 15% against the baselinef. Reductions in
2025 were the result of operational
efficiencies at our Lingen refinery in Germany,
and at Whiting refinery and bpx energy Eagle
Ford facilities in the US.
At our major operating sites, 13% (2024 11%) of
our total freshwater withdrawals and 22%
(2024 20%) of freshwater consumption were
from regions with high or extremely high water
stress in 2025.
Air emissions
We monitor our air emissions – sulphur oxides,
nitrogen oxides and non-methane
hydrocarbons – and, where possible, put
measures in place to reduce the potential
impact of our operational activities on local
communities and the environment. In 2025 our
total air emissions were flat compared to 2024.
| bp.com/ESGdata |
aWe will work to develop just transition plans with input from potentially affected stakeholders to help manage social risks and opportunities.
bAt our new in-scope bp-operated projects and major operating sites.
cNew bp-operated in-scope projects where planned activities have the potential for significant direct impacts on biodiversity are required to develop NPI action plans for those activities.
dThe threshold bp uses for stress is based on a water stress level of ‘high’ or above, as defined by the WRI Aqueduct Water Risk Atlas. bp determines areas of water stress using either the WRI
Aqueduct Water Risk Atlas or using site-specific local data sources.
eFollowing an update in 2024 to the basis for calculating freshwater withdrawal to align with the basis for calculating freshwater consumption and improve clarity and consistency, metrics based on
freshwater withdrawal data have been restated for the years 2020-23 to reflect the exclusion of once through cooling water, including the 2020 baseline.
fThe 2020 baseline for freshwater withdrawal is 96.4 million m3 per year and for freshwater consumption is 55.9 million m3 per year.
60 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Risk management and internal control | ||||
Risk management and
internal control
bp identifies, manages, monitors and reports
on the principal risks and uncertainties that
can impact our ability to deliver our strategy.
These are described in Risk factors on page 67.
bp’s system of internal control
and risk management
bp’s system of internal control is a holistic set
of internal controls that includes policies,
processes, management systems,
organizational structures, culture and
standards of conduct employed to manage
bp’s business and associated risks. Risk
management forms an integral part of this
system and operates as one of the key
mechanisms through which internal controls
are designed, implemented and monitored.
An effective approach to risk management is
central to how bp operates, supporting safe,
compliant, and reliable operations as well as
greater efficiency and sustainable financial
results that contribute to long-term business
resilience. Within the system of internal
control, bp’s risk management system and risk
management policy are tailored to our
business model and governance structure and
align with the expectations of the regulatory
and governance regimes applicable to bp.
Where appropriate, they draw on recognized
international standards, including ISO 31000
and the COSO Enterprise Risk Management
framework, and are designed to provide a
consistent and clear framework for identifying,
assessing, managing (including responding to),
monitoring and reviewing, and reporting risks
from the group’s business activities and
operations to management and the board.
The system seeks to avoid incidents and
enhance business outcomes by allowing us to:
•Understand the risk environment, identify
the specific risks and assess the potential
exposure for bp.
•Determine how best to deal with these risks
to manage overall potential exposure.
•Manage the identified risks in
appropriate ways.
•Monitor and seek assurance over the
effectiveness of the management of these
risks and intervene for improvement
where necessary.
•Report clearly and consistently to
management, the leadership team and the
board on how principal risks are being
managed, monitored and assured, with
any identified enhancements that are
being made.
| | ||
Risk oversight and governance Our key risk oversight and governance committees include: Board and committees •bp board. •Audit committee. •Safety and sustainability committee. •Remuneration committee. •People, culture and governance committee. Leadership team and committees •Leadership team meeting – for oversight and for strategic and commercial risks. •Group operational risk committee – for health, safety, security, environment and operations integrity risks. Group operational risk committee (sustainability) – for sustainability-related risks. •Group financial risk committee – for finance, treasury, trading and cyber risks. •Group disclosure committee – for financial and non-financial reporting risks. •People and culture committee – for employee risks. •Group ethics and compliance committee – for legal and regulatory compliance and ethics risks. •Resource commitment meeting – for investment decision risks. •bp quarterly internal audit meeting – for assurance on the oversight of bp’s principal risks. | |||
| | ||
Our risk management activities | ||||
Oversight and governance Set policy and monitor principal risks | ||||
The board and committees Leadership team and committees Businesses and functions Facilities, assets and operations | ||||
Business and strategic risk management Plan, manage performance and assure | ||||
Day-to-day risk management Identify, manage and report risks | ||||
| | ||
Acquired businesses Integration plans are developed to transition acquired businesses into bp’s system of internal control, over an appropriate timeframe. | |||
| | ||
| bp governance framework, page 77, board activities, page 78, and committee reports, pages 82-91. |
bp Annual Report and Form 20-F 2025 | 61 |
| ||||
Strategic report | ||||
| | ||
Divested businesses Separation and transition plans are used to divest businesses in a controlled manner, with clear allocation of responsibilities, appropriate oversight of transitional service arrangements, and continued management of any retained liabilities or obligations. | |||
| | ||
Day-to-day risk management
Management and employees at our facilities,
assets, and within our businesses (including
supply, trading & shipping) and functions seek
to identify and manage risk, promoting safe,
compliant and reliable operations. bp
requirements, which take into account
applicable laws and regulations, underpin the
practical plans developed to help reduce risk
and deliver safe, compliant and reliable
operations as well as greater efficiency and
sustainable financial results.
Business and strategic
risk management
Our businesses and functions integrate risk
management into key business processes
such as strategy, planning, performance
management, resource and capital allocation
and project appraisal. They apply this by using
a standard framework for collating risk data,
assessing risk management activities, driving
further improvements, and informing
decisions on new or changing activities.
Board oversight of risk and
internal control
The board is responsible for establishing and
maintaining an effective risk management and
internal control framework, and for
determining the nature and extent of the
principal risks it is willing to take in order to
achieve its long-term strategic objectives.
Throughout 2025, management, the leadership
team, the board and relevant committees
provided oversight of how principal risks to bp
were identified, assessed, and managed. They
supported appropriate governance of risk
management, including having relevant
policies in place to help manage risks.
Such oversight may include internal audit
reports, group risk reports and reviews of the
outcomes of business processes including
strategy, planning and resource and capital
allocation. bp’s group risk team analyses the
group’s risk profile and maintains the group’s
risk management system.
Risk management processes
bp’s risk management processes help
underpin the long-term resilience of our
business model by promoting transparent,
risk-informed decision making and the
identification and management of risks and
potential opportunities aligned with bp’s
strategic priorities. These include existing
processes and sources of insight to consider
emerging risks or opportunities, such as
emerging risk communications to the board,
bp’s risk management system, the bp Energy
Outlook, bp’s technology-related news and
insights, ongoing emerging technology
scanning and strategy reviews. They also
include ongoing enhancements to our system
of internal control and risk management,
which are informed by lessons learned and
evolving governance expectations.
We aim for a consistent basis of measuring
risk to:
•Establish a common understanding of risks
on a like-for-like basis, taking into account
potential impact and likelihood.
•Report risks and their management to the
appropriate levels of the group.
•Inform prioritization of specific risk
management activities and resource
allocation.
bp’s risk management policy sets out
requirements for the group to follow. These
requirements support the consideration of
three risk types:
•Strategic and commercial.
•Safety and operational.
•Compliance and control.
Risk identification – our businesses and
functions identify risks across these risk types
on an ongoing basis, using a range of
approaches including risk workshops, subject-
matter expertise, hazard identification
processes and engineering requirements.
Risk assessment – identified risks are
assessed for potential impact and likelihood
on a worst credible and net (residual) basis
across a number of criteria, including health
and safety, environmental, financial and non-
financial (including reputation and regulatory
impact levels). This provides a consistent basis
for evaluating and comparing risks.
Risk response, monitoring, and reviewing –
risk management activities are prioritized
where improvements are needed based on
a number of factors, including the risk
assessment, strength of existing risk
management measures, strategy and plans
and legal and regulatory requirements. Risk
management measures, including mitigations,
are identified for each risk and monitored to
the extent considered appropriate. To
support leadership oversight of decisions
relating to risk management, the appropriate
organizational levels (EVP, SVP, VP) are
notified of risks and asked to endorse risk
management plans, depending on the
assessed potential impact and likelihood.
As part of bp’s annual planning process, the
leadership team and the board review the
group’s principal risks and uncertainties.
These may be updated during the year in
response to changes in internal and external
circumstances. Emerging risks are also
considered when determining whether
updates to the group’s principal risks
are required.
Risk reporting – risk information is reported
through a structured cadence that supports
timely escalation and oversight. Businesses
and functions provide updates on changes in
risk exposure, progress of planned risk
management actions, and the strength of risk
management measures, including mitigations.
This enables consistent aggregation across
the group and supports management, the
leadership team and the board in monitoring
and reviewing bp’s principal and emerging
risks and overall risk profile.
Assurance and internal audit
bp’s internal audit team provides independent
and objective assurance to the chief executive
and the board on the adequacy and operating
effectiveness of bp’s system of internal
control, including risk management
arrangements. Internal audit reports, thematic
findings, and improvement recommendations
are considered by the board and committees
as part of their oversight.
The group risk team maintains the risk
management and internal control framework,
analyses the group’s risk profile, and provides
further oversight and reporting.
Assurance activities across management,
specialist risk and control functions and
internal audit are aligned with bp’s principal
risks and underpin the effectiveness of bp’s
risk management and internal control
framework.
62 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Principal risks and uncertainties (Risk factors) | ||||
Principal risks and uncertainties
The risks discussed below, individually or in combination, could have a material adverse effect
on the implementation of our strategy and business model, financial performance and financial
condition, cash flows and liquidity, operational delivery, reputation, and long-term shareholder
value. These are the risks the board considers to be bp’s principal risks and uncertainties
(or Risk factors).
Our risk profile
The nature of our business is long term,
meaning many of our risks are enduring in
nature. However, risks can develop and evolve
over time, and their potential impact or
likelihood may vary in response to internal and
external events.
During 2025, the board conducted a review of
the group’s principal risks, informed by bp’s
updated strategy, changes in our operating
environment, stakeholder expectations, and
the board’s commitment to maintaining clear
and effective oversight. Following this review,
the board approved a streamlined set of 16
principal risks (previously 20).
The reduction does not reflect a change in bp’s
underlying risk exposure; rather, the principal
risks have been reorganized to align with how
risks are governed and managed across the
group. Certain items previously presented as
standalone risks, such as insurance, and crisis
and business continuity management, are now
reflected within broader control and response
capabilities that support multiple principal
risks. In addition, some risks have been
combined, where appropriate, to remove
duplication and present a single view of
related drivers, accountability, and impacts.
Strategic and commercial risks
Commodity prices and market
environment
Our financial performance is impacted by
fluctuations in the prices of oil, natural gas,
refined products, and emerging energy
commodities due to factors such as volatile
energy markets, exchange rates, or structural
shifts in demand and supply, policy, or trade
(such as carbon pricing or LNG flows).
These prices are affected by factors such as
global supply and demand dynamics, the
actions of key market participants (including
OPEC+), and a range of external factors such
as geopolitical instability, public health
situations (including the outbreak of an
epidemic or pandemic), sanctions, trade
tariffs, and policy interventions that impact
energy flows.
Prolonged periods of low commodity prices
may reduce revenue, margins, and cash flow,
potentially requiring asset impairments, or a
reprioritization of strategic activity and may
also impact our ability to work within our
financial frame including potential reductions
in capital investment. Conversely, higher
prices do not always translate into improved
returns due to fiscal regimes, cost inflation, or
constrained market access.
In refining, profitability can be volatile and
is affected by regional supply and demand
imbalances (including regional oversupply
or tightness, demand shifts, shifts in product
mix, feedstock availability, and crack
spread volatility).
Currency movements – particularly where
revenues and capital costs are denominated
in different currencies – also impact project
economics and reported earnings.
Broader structural shifts, such as the pace of
the energy transition, evolving climate policy,
carbon pricing mechanisms, consumer
preferences, and the realignment of global
energy trade (e.g. LNG flows, carbon border
adjustments) may lead to enduring changes
in market conditions. These shifts could
affect the long-term competitiveness or
economic viability of existing assets and
investment plans.
Accessing and producing
hydrocarbon resources
Failure to adequately access, develop or
sustain production of hydrocarbon resources
may result in delivery delays, missed strategic
targets and adversely impact our financial
performance and undermine our reputation.
Our ability to generate value depends on
successfully identifying, accessing,
developing, and sustaining reliable production
of hydrocarbon resources at pace and scale.
This requires securing access; navigating
geopolitical and regulatory complexity;
effective and timely development and
deployment of technologies; delivering
projects on time; and executing with
operational and commercial discipline.
Delivery risks may arise from joint venture
misalignment, production reliability issues,
or extended unplanned outages across the
hydrocarbon value chain. Our activities are
sometimes conducted in challenging
environments such as those prone to natural
disasters and extreme weather events, which
heightens the risks of technical integrity
failure. The physical characteristics of an oil
or natural gas field, and cost of drilling,
completing or operating wells are inherently
uncertain. We may be required to curtail, delay
or cancel drilling operations or stop
production because of a variety of factors,
including unexpected drilling conditions,
pressure or irregularities in geological
formations, equipment failures or accidents,
adverse weather conditions and compliance
with governmental requirements. Such
outages can materially impact value,
erode investor confidence, and delay
strategic delivery.
bp Annual Report and Form 20-F 2025 | 63 |
| ||||
Strategic report | ||||
This risk is increased in politically sensitive
jurisdictions, under volatile fiscal regimes, or
where accountability for portfolio progression
is unclear following divestments – near to
medium-term value remains heavily
dependent on competitive, reliable
hydrocarbon delivery. Sustained
underperformance, partner misalignment, or
high-profile project delays could limit reserve
replacement and constrain growth.
Major project delivery
Failure to invest in the best opportunities or
deliver major projects« successfully could
adversely affect our financial performance and
long-term competitiveness.
Our ability to select, define, execute, and
deliver large-scale, capital intensive, physical
projects (such as field developments,
refineries and infrastructure expansions) is
critical to our financial performance and
resilience. These projects are often complex
and executed in technically demanding,
geopolitically sensitive or geographically
challenging environments. Additional factors
such as extreme weather events or regulatory
constraints can affect schedule and cost
performance.
Major projects are often delivered through
joint ventures, strategic partnerships, or third-
party-led models, which can constrain our
control and influence over delivery,
governance, and standards.
The selection and design of our major projects
need to be resilient to the impact of severe
weather events (e.g. metocean criteria) and
other environmental factors (e.g. water
scarcity).
Potential risks include ineffective investment
prioritization, subsurface uncertainty,
capability constraints, supply chain disruption,
inflationary pressure or delays in permitting,
regulatory approval, commercial agreements,
or execution.
A failure to deliver key projects to schedule,
scope, budget, quality, or HSE standards may
lead to cost overruns, delays in production or
revenue, reputational harm, impairment, or
loss of licence to operate.
Geopolitical exposure
The diverse locations of our business activities
and operations around the world expose us to
a wide range of geopolitical developments
(including sanctions, trade route restrictions,
civil unrest, conflict, or government
intervention).
Geopolitical risks arise from operating in
jurisdictions undergoing political, regulatory,
or economic transition – and from broader
societal, ideological, and technological shifts –
including changes to taxation or regulatory
regimes, international sanctions, trade
restrictions, expropriation or nationalization of
property, civil strife, strikes, insurrections, acts
of terrorism, acts of war, and public health
situations (including the outbreak of an
epidemic or pandemic).
These events have, and can, disrupt business
activities and operations, restrict access to key
markets, and adversely affect financial
performance, long-term growth opportunities,
or reputation.
Rising bloc politics, energy nationalism, and
alliance-driven policy divergence could further
fragment global trade and investment
patterns, influencing where bp may operate,
partner, pursue business opportunities and
compete. Competition over critical minerals
and low carbon technologies is increasingly
geopolitical, shaping access to resources
and markets.
Geopolitical rivalry extends into technology
and cyber domains, exposing potential
operational and reputational vulnerabilities
linked to supply-chain sovereignty, data
integrity, and industrial security. Political
instability, shifts in alliances, or increased
government intervention may lead to barriers
to market access, disruptions in supply chains,
or challenges in executing existing or planned
operations. Divergent or extraterritorial
regulations (including sanctions, data, and
carbon border mechanisms) may create
conflicting legal obligations and compliance
complexity across jurisdictions.
Such events may also affect investor
sentiment, financing conditions, and access to
capital. Growing fragmentation of global trade
and regulation, coupled with rising energy
nationalism and polarized international
alliances, may exacerbate volatility in energy
supply, demand, and prices. Our exposure to
particular jurisdictions, vendors, and
technologies exposes us to the potential for
geopolitical tensions to intersect with
performance delivery, investor sentiment,
and stakeholder trust.
Liquidity, capital access and
financial resilience
External market conditions can impact our
ability to maintain liquidity, credit strength, or
access to capital markets which could impair
our ability to operate, meet financial
commitments, or deliver our strategy.
Market volatility, operational incidents, legal
proceedings, regulatory actions, or
geopolitical crises could reduce access to
funding or trigger unexpected calls on cash,
even where insurance or other risk transfer
mechanisms exist. A significant liquidity event
or credit rating downgrade could lead to
higher financing costs, constrained access to
capital, and reduced financial flexibility,
forcing us to reprioritize investment, reduce
expenditure, or accelerate planned or
unplanned divestments or dilutions,
potentially at less than the full market value.
We are also exposed to credit risk through
financial counterparties, joint ventures, trading
partners, receivables, customers, delays in
settlements, receipt of divestment proceeds,
or divestments not completing when planned.
All can impact cash flow and our ability to work
within our financial frame and in more severe
cases, we may need to review and reallocate
financial commitments or long-term
obligations such as pension funding
arrangements.
Maintaining confidence with investors, lenders,
and credit rating agencies is essential to
preserving financial resilience and access to
affordable funding, especially during periods
of capital scarcity or policy uncertainty.
| Energy markets, page 6 Liquidity and capital resources, page 338 Liquidity, financial capacity and financial, including credit, exposure, page 68 |
64 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Principal risks and uncertainties (Risk factors) continued | ||||
Partner and third-party risk
The performance, standards, or compliance of
non-operated joint ventures, strategic
partners, contractors, sub-contractors, or
other third parties could expose bp to legal,
operational, financial, or reputational harm.
Many of our business activities are conducted
through partners and third parties – including
non-operated joint ventures, strategic
partners, contractors, sub-contractors, and
suppliers – where we may have limited
influence and control over performance
or compliance.
Our partners and contractors are responsible
for the adequacy of their resources and
capabilities, and there may be financial,
reputational, operational or safety exposures
and consequences for bp if their performance,
risk management or governance standards are
inadequate, including their safety practices,
cyber-attacks, quality or delivery of work,
financial management, legal compliance,
advocacy positions, and environmental, social
and governance (ESG) standards.
In some cases, third parties may not be able or
may not be willing to compensate us against
all of the costs we may incur on their behalf, or
pay their share of losses and liabilities which
may arise in connection with the activities in
which they have participated. Irrespective of
whether or not bp controls or has direct
oversight of third parties, we may still be
pursued by regulators or claimants, and may
still be the focus for interest groups or media
attention in the event of an incident.
Digital, cyber security and data risk
Increasing reliance on digital infrastructure,
growing AI adoption, and evolving cyber
threats exposes bp and our third-party
suppliers and contractors to data loss,
infrastructure failures, or system compromise
which could result in operational disruption,
regulatory breaches, significant fines and
reputational harm.
bp’s digital infrastructure, data platforms,
applications and connected technologies are
core enablers to our businesses, operations,
trading activities, customer engagement,
and corporate functions. These systems face
fast-evolving cyber threats – including
ransomware, nation-state interference,
and insider attacks – amplified by complex
third-party ecosystems and AI-enabled
technologies.
A breach or failure of our third-party supplier’s
or contractor’s digital systems, including
operational technology and cloud
environments, could result in the loss, misuse,
or compromise of sensitive data – including
personal, operational, or commercial
information.
The loss or misuse of data or sensitive
information, including employees’ and
customers’ personal data, injury to people,
disruption to our business, harm to the
environment or our assets, legal or regulatory
breaches, may result in legal liability and
significant costs including fines, cost of
remediation or reputational consequences.
At the same time, the rapid advancement and
scaling of generative and agentic AI – including
predictive technologies – presents both
significant opportunities and emerging
systemic risk. Without clear organization-wide
governance, bp may underperform, miss
strategic upside, or fall behind on safe and
compliant AI deployment.
Critical national infrastructure, data protection
and privacy regulations – particularly in
sensitive geographies – continue to grow,
increasing expectations on security, data
sovereignty, ethical use of AI, and
accountability for data handling. This reflects
the strategic importance of establishing and
maintaining resilience, trust, and performance
in a fast-digitizing environment. For more on
cyber security see page 360.
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.
Laws, regulations, policies, obligations,
government actions, social attitudes and
customer preferences relating to climate
change and the transition to a lower carbon
economy, including the pace of change to any
of these factors, and also the pace of the
transition itself, could have adverse impacts
on our business including on our access to and
realization of competitive opportunities, a
decline in demand for, or constraints on our
ability to sell certain products, constraints on
production and supply, adverse litigation and
regulatory or litigation outcomes, increased
costs from compliance and increased
provisions for environmental and legal
liabilities.
Investor preferences and sentiment are
influenced by ESG considerations including
climate change and the transition to a lower
carbon economy. Changes in those
preferences and sentiment could affect our
access to capital markets and our
attractiveness to potential investors,
potentially resulting in reduced access to
financing, increased financing costs and
impacts upon our business plans and
financial performance.
Technological improvements or innovations
that support the transition to a lower carbon
economy, and customer preferences or
regulatory incentives that alter fuel or power
choices, could impact demand for our
products (including low carbon energy).
Depending on the nature and speed of any
such changes and our response, these
changes could increase costs, reduce our
profitability, reduce demand for certain
products, limit our access to new
opportunities, require us to write down certain
assets or curtail or cease certain operations,
and affect investor sentiment, our access to
capital markets, our competitiveness and
financial performance.
Policy, legal, regulatory, technological and
market developments related to climate
change could also affect future price
assumptions used in the assessment of
recoverability of asset-carrying values. This
may affect whether there is continued intent
to develop exploration and appraisal of
intangible assets; the timing of
decommissioning of assets; and the useful
economic lives of assets used for the
calculation of depreciation and amortization.
Competitiveness
Failure to maintain a competitive strategy,
underpinned by a strong portfolio of assets,
cost performance, innovative technology,
projects and long-term growth opportunities,
could negatively impact our investors’
confidence in our ability to grow long-term
shareholder value and returns.
We operate in an increasingly complex, fast-
paced, ever-changing, competitive global
energy market with evolving competitor
strategies. As an integrated energy company,
our ability to remain competitive with a
compelling, differentiated proposition for
stakeholders depends on the quality and
agility of our strategic, commercial, and
operational decisions and the execution of
those decisions including those related to
costs, capital allocation, innovation,
technology adoption, portfolio development,
customer propositions, and talent
deployment.
We could be adversely affected if we fail to
anticipate or respond effectively to rapid shifts
in policy, consumer preferences, investor
expectations, and disruptive competitor
activity or fail to protect our intellectual
property, increasing the risk of constrained
operations and diminished returns, and
shareholder expectations.
Ineffective communication of our strategic
direction and a compelling value proposition
could undermine stakeholder confidence and
investor expectations of bp’s long-term value.
bp Annual Report and Form 20-F 2025 | 65 |
| ||||
Strategic report | ||||
Talent, leadership and
organizational capability
Failure to retain, develop, and attract the
talent, leadership, capabilities and behaviours
required to deliver our strategy could weaken
performance, culture, and long-term value
creation.
To manage our costs competitively and build
our resilience, we look to simplify and digitalize
our processes while evolving our skills and
capabilities, in line with our strategy and global
market trends. Failure to manage change and
transfer knowledge appropriately could
decrease efficiency, weaken performance and
increase costs.
We face growing competition for high-calibre
talent across a diverse set of business and
function portfolios, and a broad set of
geographies.
Expectations around organizational culture,
ways of working, leadership behaviours, and
career development opportunities must be
balanced with disciplined performance and
shared values and behaviours. Failure to
attract, develop and retain the right talent,
could result in delivery shortfalls, diminished
competitiveness, and erosion of stakeholder
trust. For more on our people see page 56.
Safety and operational risks
Process safety, personal safety and
environmental risks
bp’s operations and business activities are
exposed to a wide range of safety, operational
integrity, and environmental risks – particularly
under growing complexity and delivery
intensity – which could result in major
incidents that harm people or the
environment, disrupted operations, damage
to bp's reputation, legal liability, undermine
our financial standing or threaten our licence
to operate.
bp operates in complex and high-risk
environments where process safety, personal
safety, occupational health, technical integrity,
transportation, marine operations, and
environmental risks could result in major
incidents with significant human,
environmental, financial, and reputational
consequences. As a result, we could face
regulatory action and legal liability, including
penalties and remediation obligations,
increased costs and, potentially, denial of our
licence to operate.
Despite safety controls, barriers, and
management systems, failures may still occur
due to technical breakdowns, equipment
failure, human error, extreme (acute or
chronic) weather and climate-related factors,
or third-party actions.
Risk exposure is heightened during drilling,
production, marine transport and logistics,
pipeline operations, project construction or
maintenance activities – especially in
environmentally sensitive (e.g. areas of water
scarcity, biodiversity), remote or geologically
complex locations, or where infrastructure
reliability and emergency response
capabilities are constrained. These risks
extend to both the public and our workforce
and contractors, including physical safety, life-
saving rule violations, and occupational health
exposures such as chemical, biological,
psychosocial, or infectious risks.
Past incidents across the industry have
resulted in fatalities, significant spills, long-
term environmental damage, large-scale
remediation costs, and lasting reputational
harm. bp’s ability to maintain the technical
integrity of its assets, retain its licence to
operate and meet stakeholder expectations,
depends on consistently high performance in
safety and environmental execution across
the portfolio.
As bp continues to scale delivery across a
more diversified portfolio it remains essential
that safety systems, controls, and
organizational safety culture are maintained
and strengthened at every level of the
business to prevent serious failures, provide
operational continuity, and uphold trust with
stakeholders.
| Safety, page 55 |
Security
Hostile acts such as terrorism, civil unrest,
armed conflict, sabotage, activism, piracy,
insider threats, workplace violence, cyber-
enabled physical attacks, or threats to
personnel security such as kidnapping or
detention could harm our people, disrupt
operations, compromise critical assets, or
damage our reputation.
Security threats may emerge or intensify in
response to geopolitical instability, conflict, or
state-linked activity that could target critical
infrastructure or supply chains. They may also
be politically, ideologically, or financially
motivated and influenced by regional
instability, activism, social unrest, or bp’s
presence in higher-risk geographies.
Increasing interdependence between cyber,
information, and physical domains may create
additional vulnerabilities across operational
technology, logistics, and data-driven systems.
Assets such as pipelines, terminals,
transportation routes, offshore platforms, and
operational-technology systems could be
particularly exposed. The risk of insider activity
– including unauthorized data access,
sabotage, or information leakage – is also a
continuing concern, particularly in complex
joint ventures or politically sensitive
environments.
The consequences of a major security incident
could include operational shutdown, financial
loss, workforce harm, legal costs and liabilities
or reputational damage. More broadly, a
significant incident could disrupt supply
chains, invite regulatory scrutiny, or adversely
affect confidence in bp’s ability to operate
safely and reliably in challenging
environments.
Product quality
Failure to supply products to customers, meet
technical specifications or regulatory
standards could lead to harm, operational
disruption, reputational damage, or legal and
financial consequences.
bp provides products – including fuels,
lubricants, petrochemicals, biofuels, and
consumables – that meet technical
specifications, regulatory requirements, and
customer expectations. We operate a complex
global value chain spanning production,
refining, blending, transportation, and delivery.
Failures may arise at any point in this chain due
to contamination, formulation errors, process
deviation, mislabelling, equipment failure, or
inadequate quality assurance.
Product quality risks may originate upstream
(e.g. formation variability, production
chemistry), midstream (e.g. blending
inconsistencies, custody transfer), or
downstream (e.g. additives, packaging,
distribution). Failures can result in safety
incidents, environmental harm, damage to
customer equipment, product recalls, legal
liability, and loss of brand trust.
As customer expectations and regulatory
regimes evolve – particularly regarding
decarbonized and high-integrity products –
maintaining end-to-end product integrity is
critical to safeguarding our reputation,
maintaining brand trust, securing market
access, and protecting long-term commercial
relationships. Widespread or high-profile
failures could result in product recalls, legal
exposure, or reputational harm – especially in
regulated or safety-critical sectors.
66 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Principal risks and uncertainties (Risk factors) continued | ||||
Compliance and control risks
Legal, regulatory and ethical compliance
Ethical misconduct, non-compliance with law
and regulation or changes in law and
regulation could increase costs, constrain our
operations and affect our strategy, business
plans and financial performance. Incidents of
ethical misconduct or non-compliance could
also damage our reputation and result in
litigation, regulatory action, penalties and
potentially affect our licence to operate.
Incidents of ethical misconduct or non-
compliance with applicable laws and
regulations, including anti-bribery and
corruption, competition and antitrust, data
privacy, and anti-fraud laws, trade restrictions
or other sanctions, could damage our
reputation, and result in litigation, regulatory
action, penalties and potentially affect our
licence to operate. In relation to trade
restrictions or other sanctions, current
geopolitical factors have increased these risks.
Our businesses and operations are subject to
the laws and regulations applicable in each
country, state or other regional or local area in
which they occur. These laws and regulations
result in an often complex, uncertain and
changing legal and regulatory environment for
our global businesses and operations.
Changes in laws or regulations, including how
they are interpreted and enforced, can and do
impact all aspects of our business.
Royalties and taxes, particularly those applied
to our hydrocarbon activities, tend to be high
compared with those imposed on similar
commercial activities. In certain jurisdictions
there is also a degree of uncertainty relating to
tax law interpretation and changes.
Governments may change their fiscal and
regulatory frameworks in response to public
pressure on finances or for other policy
reasons, resulting in increased amounts
payable to them or their agencies.
Changes in law or regulation could increase
the compliance and litigation risk and costs,
reduce our profitability, reduce demand for or
constrain our ability to sell certain products,
limit our access to new opportunities, require
us to divest or write down certain assets or
curtail or cease certain operations, or affect
the adequacy of our provisions for pensions,
tax, decommissioning, environmental and
legal liabilities.
Changes in laws or regulations could result in
the nationalization, expropriation, cancellation,
non-renewal or renegotiation of our interests,
assets and related rights. Potential changes to
pension or financial market regulation could
also impact funding requirements of the
group. Following the Gulf of America oil spill,
we may be subjected to a higher level of fines
or penalties imposed in relation to any alleged
breaches of laws or regulations, which could
result in increased costs.
Financial and physical commodity
trading activities
We undertake physical and financial trading
across global commodity and financial
markets. Risk associated with our trading
activities could arise from a failure to maintain
robust oversight, controls, and disciplined
execution in our trading activities which could
result in business disruption, financial loss,
regulatory action, or reputational damage.
We conduct physical and financial trading
across global commodity and financial
markets, both on exchange and ‘over the
counter’, some of which are financially
regulated activities. Our trading activities
expose us to multiple risks, including market,
credit, operational, conduct, liquidity and
regulatory risks. Failure to maintain effective
oversight and controls, and disciplined
execution in our trading activities, could result
in business disruption, financial loss,
reputational harm, regulatory intervention,
and/or impair our ability to operate.
There is a risk that a single trader or a group of
traders could act outside of our delegations
and controls, leading to regulatory
intervention and resulting in financial loss,
fines and potentially damaging our reputation,
and could affect our permissions to trade.
Integrity of financial and non-financial
reporting
Failure to maintain integrity in financial and
non-financial reporting may result in material
misstatement or regulatory breach, which
could lead to regulatory action, legal liability
and reputational damage.
The accuracy and reliability of our external
reporting depends on the strength of our
internal control environment, the robustness
of our systems and data governance, and
our people.
Failure to accurately report our data –
including financial results, sustainability and
environmental, social and governance
disclosures, reserves estimates, and
operational performance – could lead to
regulatory action, legal liability, investor action
and reputational damage.
bp Annual Report and Form 20-F 2025 | 67 |
| ||||
Strategic report | ||||
How we manage principal risks and uncertainties | ||||
How we manage principal risks
and uncertainties
bp manages its principal risks and uncertainties through our system of internal control
(described earlier in this section). The following pages set out the key risk management
activities for each principal risk.
There can be no certainty that our risk
management activities will mitigate or prevent
these, or other risks, from occurring. Further
details of the principal risks and uncertainties
faced are set out on page 62.
Strategic and commercial risks
Commodity prices and market environment:
We seek to manage this risk through market
analysis and strategic scenario planning, which
inform our portfolio, business development,
and capital allocation decisions. This analysis
draws on internal and external data sources
provided by our global energy and trading
insights teams (supply, trading & shipping
(ST&S) and economics & energy insights).
Outputs are integrated into our planning and
investment governance processes and
reviewed regularly by management.
We assess the implications of price, margin,
and exchange rate volatility across a range
of scenarios and test the robustness of
investment cases against changing
macroeconomic and regulatory assumptions.
The bp Energy Outlook is updated annually
to reflect shifts in policy, demand, and
trade patterns.
Our strategy is designed to remain resilient
across a wide range of market conditions. This
is supported by a diversified portfolio, a
disciplined financial frame, and an ongoing
focus on capital efficiency and investment
flexibility.
Accessing and producing hydrocarbon
resources: We seek to manage this risk
through our subsurface teams in production &
operations (P&O) and gas & low carbon energy,
who have responsibility for accessing and
progressing hydrocarbons resources. The
teams are accountable for delivering high-
value resources to support our strategic and
financial goals. They work closely with
technology and other enabling functions to
assess resource potential, prioritize
opportunities, and advance viable projects.
P&O executes capital and operational activities
and is accountable for safe, competitive, and
efficient delivery.
Risk management is embedded through our
Operating Management System« (OMS) and a
suite of supporting frameworks embed quality,
control, and investment discipline. These
include the Exploration Common Process,
Discovered Resource Management, Area
Development Planning, and the Group
Investment Assurance and Approvals Process
(GIAAP). Together, they guide how we identify,
evaluate, approve and deliver access and
development opportunities. Data often
enables our ability to pivot and adjust plans
after a materialized risk.
This risk is monitored through established
governance and management processes,
including regular review of performance
indicators, assurance outcomes, and incident
learnings, with escalation through appropriate
executive and board-level forums where
required.
| Our strategy, page 8 |
Major project delivery: We seek to manage
this risk through a structured, disciplined
approach to investment appraisal, project
execution, and performance governance. Our
projects organization exists to assess, develop,
and execute projects across bp, providing
deep technical expertise in capital delivery,
design, execution, and integration. It operates
under a globally aligned Project Delivery
Common Process, adapted to project size,
complexity, and risk.
Major projects are subject to rigorous
assurance throughout the lifecycle – from
early framing and appraisal through to
commissioning and performance evaluation.
Defined stage gates, verification reviews, and
central investment governance provide
disciplined decision making and alignment to
strategic objectives.
A structured management of change process
enables any technical, commercial, or scope
variations can be assessed, approved and
documented through appropriate governance
channels, helping to protect cost, schedule
and safety integrity.
Within the design phase of our projects, we
consider metocean criteria against historic
and projected models and environmental
impact factors.
Investments are evaluated against a balanced
set of investment criteria – for example,
assessment of economics includes a set of
price assumptions that reflects our view of
market evolution and the economics of all
investment cases where bp’s share of annual
greenhouse gas (GHG) emissions from
operations are anticipated to exceed certain
thresholds include a carbon price for those
emissions.
Oversight is maintained through performance
reviews, supplemented by discipline checks,
post-project evaluations, and capital
forecasting cycles. Cross-functional forums
provide alignment between project,
commercial, and procurement functions. This
governance framework enables consistent
assurance, early identification of delivery
challenges, and investment decisions aligned
with strategic and performance expectations.
Note: Large-scale digital or transformation
programmes that interface with capital
delivery are assessed through equivalent
governance and assurance to protect
schedule, cost, and performance integrity.
68 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
How we manage principal risks and uncertainties continued | ||||
Geopolitical exposure: We seek to manage this
risk through intelligence and international
advisory, which integrates geopolitical horizon
scanning, strategic and baseline threat
assessments, deal-specific risk support, and
the New Country Entry process. Together,
these mechanisms support real-time decision
making, portfolio resilience, and longer-term
strategic investments.
Our geopolitical advisory council provides an
independent perspective on macro-level
geopolitical trends.
At an operational level, we have defined
government-relations and stakeholder-
engagement processes that seek to maintain
trusted relationships in host countries. Where
appropriate, risk mitigation and contingency
plans are developed, and ongoing monitoring
is overseen through intelligence, security and
crisis management.
Liquidity, capital access and financial
resilience: We seek to manage this risk
through a combination of governance,
planning, and treasury controls, including:
Financial frame governance provides a
disciplined approach to capital allocation,
balance sheet strength, and investment
priorities. This helps bp maintain a resilient
dividend, a strong investment-grade credit
rating, and a clear hierarchy of capital uses,
supported by regular board and group
financial risk committee review.
Our disciplined Liquidity Management
Framework (LMF), which is embedded within
the treasury function and reviewed regularly
by senior management, defines clear
thresholds for undrawn committed credit
facilities, minimum cash buffers, liquidity
stress testing parameters, and monitoring
routines. The LMF also integrates our
Commercial Paper (CP) programme, governs
the investment of treasury cash with defined
exposure limits, and connects with the capital
markets team to issue securities that sustain
cash levels.
Together, these frameworks help create a
strong, flexible balance sheet, preserve access
to capital markets, and enable us to respond
effectively to external shocks or market
disruptions.
| Liquidity and capital resources, page 338 Financial statements – Note 29 |
Partner and third-party risk: We seek to
manage partner and third-party risk, including
exposure from non-operated joint ventures,
contractors, and sub-contractors, through a
combination of governance, self-verification &
oversight, assurance, and commercial controls
designed to provide proportionate oversight
and influence where bp does not have
operational control.
For joint ventures, accountability for day-to-
day oversight rests with the business unit or
function holding bp’s equity interest,
supported by non-operated joint venture
solutions, which provides guidance on risk
exposure management, strategic governance,
self-verification & oversight, and assurance.
Exposure in non-operated joint ventures is
monitored through a risk barometer, periodic
risk reviews, and targeted assurance activities,
with escalation to executive or board-level
committees where appropriate.
For contractors, suppliers, and other third
parties, we apply a structured procurement
framework. This includes pre-engagement and
ongoing due diligence covering financial
stability, legal compliance, anti-bribery and
corruption (ABC), labour practices, cyber
security, and sustainability performance.
Supplier relationships are tiered (transactional,
core, strategic) to provide proportionate
oversight, and key contracts embed our
expectations and standards on safety, ethics,
and operational integrity.
We review and, where appropriate, enhance
governance arrangements for strategic
partnerships, capital-light ventures, and high-
exposure third parties as part of our
established oversight cycle to confirm that
assurance and engagement are
commensurate with bp’s level of influence and
potential exposure.
Together, these measures support informed
oversight of our third-party relationships and
help protect bp’s delivery, integrity, and
reputation where operational control is limited.
Digital, cyber security and data risk: We seek
to manage this risk through an approach
aligned with global standards, including the
National Institute of Standards and
Technology Cybersecurity Framework, as well
as our internal requirements for cyber security,
digital infrastructure, data privacy, and
responsible AI. Our controls span cyber
defence tools, resilience testing, third-party
oversight, and ethical data governance.
We continuously monitor the evolving threat
landscape and emerging technologies –
including AI, quantum computing, and cloud
infrastructure – to identify potential
vulnerabilities and disruptors. Cyber threat
detection, security testing, and ethical hacking
are supported by incident response protocols
and a delegated authority model to isolate or
disconnect operations when needed. We
actively manage our resilience capability and
maturity, with the ability to activate protocols
to restore systems and data to protect
prioritized critical business outcomes while
minimizing disruption.
We collaborate with government bodies, law
enforcement, and industry peers to track and
respond to fast-evolving threats. We reinforce
a culture of digital responsibility through
employee training, exercises (including
prolonged IT outage scenarios) to test
response and recovery procedures, and
executive-level briefings. Regular maturity
assessments and operational reviews help
track organizational resilience across
infrastructure, data, and third-party digital
dependencies.
| Cyber security disclosures, page 360 |
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.
Risks associated with climate change and the
transition to a lower carbon economy impact
many elements of our strategy and, as such,
these risks are managed through key business
processes including setting the bp strategy
and annual plan, capital allocation and
investment decisions. The outputs of these key
business processes are reviewed in line with
the cadence of these activities. See page 47 for
more information on how transition risks and
opportunities are managed.
| Climate-related financial disclosures, page 41 and Financial statements – Note 1 and Note 33 |
bp Annual Report and Form 20-F 2025 | 69 |
| ||||
Strategic report | ||||
Competitiveness: We seek to manage this
risk jointly through our investor relations
and competitor insights (IR&CI) and
strategy teams.
The IR&CI and strategy teams work closely
with communications and external affairs
teams, business teams and functions to
support the shaping of our future strategy by
gathering and synthesizing market and sector
intelligence and investor sentiment and
analysing our performance through
competitor benchmarking.
Our strategy team evaluates longer-term
trends and monitors macro themes as we seek
to maintain a distinct competitive advantage
that underpins our value proposition.
Through market updates, analyst calls,
investor meetings, media outreach and our
corporate reporting, IR&CI communicates and
engages with investors and stakeholders to
gather feedback, address concerns, and
monitor shifts in investor sentiment. This
informs any necessary adjustments to our
portfolio, capital allocation, technology and
performance required to keep pace with
current and future market demands.
The articulation of our unique value
proposition and strategic priorities to
investors, analysts, and other stakeholders
builds understanding and confidence in how
we are seeking to grow value and returns, and
navigate risks, by adapting and capitalizing on
opportunities in a fast-changing environment.
Talent, leadership and organizational
capability: We seek to manage this risk
through global, scalable talent strategies,
which can effectively adapt and support the
resourcing needs of bp’s strategy. Our people,
culture & communications team works in
partnership with business leaders to attract,
develop and retain the capabilities needed to
deliver our strategy.
Strategic workforce planning is supported by
market intelligence, people analytics, and
scenario modelling to assess talent supply,
demand, and future skills needs. Robust talent
acquisition frameworks and early careers
programmes help to build a pipeline of diverse
and critical skills, while targeted learning
platforms and leadership offers support
continuous development.
We embed clear succession planning and
performance development processes to
identify and support high-potential individuals,
with emphasis on building leadership depth
and capability across the organization.
Employee listening mechanisms such as the
annual Pulse survey, culture assessments, and
behavioural insight tools help assess
engagement, cultural alignment, and
employees’ resilience to change.
Knowledge transfer and changes in
accountability are managed through a robust
management of change process. bp’s culture
is embedded with bp’s code of conduct and
our culture frame ‘Who we are’.
| People, page 55 |
Safety and operational risks
Process safety, personal safety, and
environmental risks: We seek to manage
process safety, personal safety, and
environmental risks through our Operating
Management System« (OMS), which defines
the standards and systematic practices for
safe, reliable, and compliant operations. Key
activities include inspection, maintenance,
testing, incident investigation, and workforce
competency development. It provides a risk-
based framework for identifying, assessing,
and mitigating hazards throughout the
lifecycle of our operations.
Our dedicated wells organization applies
consistent processes for well design,
construction, and management. Production &
operations plays a central role in managing
safety and environmental risks across
hydrocarbon operations. It is accountable for
maintaining safe, compliant, and reliable
performance and promotes a strong safety
culture across sites and partners.
These activities are supported by regular
monitoring, assurance and review through
bp’s established management and governance
processes, with escalation where exposure
changes or issues arise.
| Safety, page 55 |
Security: We seek to manage this risk through
bp’s global Security Risk Management
Framework, which provides structured
processes for identifying, assessing, and
mitigating security threats (including those
linked to geopolitical instability or hybrid
conflict) at both strategic and operational
levels. The framework integrates oversight
from intelligence, security and crisis
management (ISC) and is supported by our
network of business security representatives.
Key components include the Unified Risk
Picture threat assessment methodology,
which provides consistent visibility of priority
risks and vulnerabilities across the group;
insider risk management processes
addressing unauthorized access, sabotage,
and data exfiltration; executive protection
protocols for high-profile personnel; security
governance and policy standards aligned with
industry best practice; technology
assessments that keep site security
infrastructure fit-for-purpose, and rigorous
compliance with the Voluntary Principles on
Security and Human Rights.
The framework operates under a defined
governance structure with regular reviews by
the ISC, annual risk assessments, and periodic
assurance reviews. It also supports bp’s crisis
management and business continuity
planning, which provides co-ordinated
preparedness and response to potential
security incidents across regions and assets.
Where appropriate, emerging activism,
misinformation, or social unrest trends are
monitored to anticipate and manage potential
threats to bp’s people and operations.
Product quality: We seek to manage product
quality risk across our global value chain by
our operating businesses, working in close
partnership with the applied sciences quality
assurance team. We use a structured Product
Quality Framework aligned with our Operating
Management System, which includes quality
standards, risk assessments, incident
management, and assurance processes.
Where necessary, we apply industry-specific
or enhanced internal standards, particularly in
sectors such as aviation.
This risk is monitored through established
governance and management processes,
including regular review of performance
indicators, assurance outcomes, and incident
learnings, with escalation through appropriate
executive and board-level forums where
required.
70 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
How we manage principal risks and uncertainties continued | ||||
Compliance and control risks
Legal, regulatory and ethical compliance: With
support of our businesses and functions, we
seek to identify, assess and manage legal and
regulatory risks relevant to bp’s operations,
strategy, business plans and financial
performance. To support this work, we seek to
develop co-operative relationships with
governmental authorities in line with our code
of conduct, to allow appropriate focus on
areas of potential risk or uncertainty, while
also protecting bp’s interests within the law.
Our code of conduct, the foundation of our
culture frame ‘Who we are’, is applicable to all
employees and central to managing this risk.
Additionally, we have group requirements and
training covering areas such as anti-bribery
and corruption, anti-money laundering,
competition/anti-trust law, data privacy and
international trade regulations. We offer an
independent confidential helpline, ‘OpenTalk’,
for employees, contractors and other third
parties, with the option to raise concerns
anonymously.
Financial and physical commodity trading
activities: We seek to manage risks associated
with financial and physical commodity trading
through dedicated risk control frameworks
with defined delegated authorities,
monitoring, and oversight structures.
Trading is conducted by authorized personnel
operating within approved mandates and limit
structures. Activities and associated risks are
actively managed and monitored, in line with
the group-wide three lines of defence model
which includes independent risk and
compliance functions. As part of this risk
model, robust control frameworks, risk-based
monitoring, exception reporting and escalation
protocols are in place.
| Financial statements – Note 29 |
Integrity of financial and non-financial
reporting: We seek to manage this risk
through group-wide financial and non-financial
reporting, control and assurance frameworks
designed by our finance organization. The
control operation and assurance activities
within these frameworks are executed at
multiple levels within our businesses and
functions, following a ‘line-of-defence’ model.
For financial reporting, we apply bp’s Sarbanes
Oxley (SOx) Management Assessment
Framework, which includes annual control
testing; deficiency evaluations and reporting;
an annual acknowledgement process
confirming performance of control owner
accountabilities; quarterly representations
from our businesses and functions; and
enterprise-level control assessments.
For non-financial reporting, we follow our ESG
and non-financial reporting (ESG-NFR) control
and assurance framework, which includes help
to determine the appropriate level of control
and assurance activity to be applied, annual
due diligence with control owners and pre-
publication reviews.
We also maintain a Fraud Risk Management
Governance Framework to identify, assess and
mitigate the risk of fraudulent activity.
As reporting expectations and requirements
evolve under various frameworks and
regulations in the UK and in other jurisdictions,
we continue to review and enhance, as
needed, our reporting controls, approach to
assurance and approach to disclosure.
bp Annual Report and Form 20-F 2025 | 71 |
| ||||
Strategic report | ||||
Compliance information | ||||
bp non-financial and sustainability information statement
Produced in compliance with Sections 414CA and 414CB of the Companies Act. Information incorporated by cross reference.
Requirement | Relevant policies and standards | Information related to policies and any due diligence processes | ||
a Environmental matters | •Net zero aims •TCFD •Sustainability frame •Biodiversity position (online) | •Climate-related financial disclosures - pages 41-54 •People and planet – page 59 •Our Operating Management System« (OMS) – page 55 •Decision making by the board – page 81 | ||
b Employees | •bp values and code of conduct (online) | •Our people – page 56 •Safety – page 55 •Our values (‘Who we are’) and code of conduct – pages 57-58 •Employee engagement (Pulse annual and Pulse live employee surveys) – page 57 •How the board engaged with stakeholders (workforce) – page 80 | ||
c Social matters | •Sustainability frame | •Our Operating Management System« (OMS) – page 55 •Improving people’s lives – page 59 •Decision making by the board – page 81 | ||
d Respect for human rights | •Business and human rights policy (online) •Modern slavery statement (online) •Labour rights and modern slavery principles (online) •Code of conduct (online) | •Improving people’s lives – page 59 •Human rights – page 59 •Our values (‘Who we are’) and code of conduct – pages 57-58 | ||
e Anti-corruption and anti-bribery | •Anti-bribery and corruption policy •Code of conduct (online) | •Ethics and compliance – page 58 •Our partners in joint arrangements – page 56 | ||
Description of principal risks relating to matters (a-e above) | •How we manage risk – pages 67-70 •Risk factors – page 62 •TCFD (climate-related risk management) – pages 44-45 | |||
Relevant information | ||||
Business model description | •Business model – page 12 | |||
Description of non-financial KPIs | •Measuring our progress – pages 16-17 |
TCFD index tablea
Our TCFD disclosures can be found on the following pages.
TCFD Recommendation | TCFD Recommended Disclosure | Where reported | ||
Governance Disclose the organization’s governance around climate-related issues and opportunities. | a Describe the board’s oversight of climate-related risks and opportunities. | •Page 44 | ||
b Describe management’s role in assessing and managing climate-related risks and opportunities. | •Page 45 | |||
Strategy Disclose the actual and potential impacts of climate-related risks and opportunities on the organization’s business, strategy and financial planning where such information is material. | a Describe the climate-related risks and opportunities the organization has identified over the short, medium, and long term. | •TCFD Strategy a, page 46 •Pursuing a strategy that is consistent with the Paris goals, page 10 •Strategy, page 8 •Risk factors, page 67 | ||
b Describe the impact of climate-related risks and opportunities on the organization’s businesses, strategy, and financial planning. | •TCFD Strategy b, page 46 •Risk factors, page 67 – description of principal risks •Strategy, page 8 | |||
c Describe the resilience of the organization’s strategy, taking into consideration different climate-related scenarios, including a 2°C or lower scenario. | •TCFD Strategy c, page 49 •Strategy, page 8 •Pursuing a strategy that is consistent with the Paris goals, page 10 | |||
Risk management Disclose how the organization identifies, assesses and manages climate-related risks. | a Describe the organization’s processes for identifying and assessing climate-related risks. | •Risk Management, page 44 •How we manage risk, page 60 •Risk factors, page 67 | ||
b Describe the organization’s processes for managing climate-related risks. | •Risk Management, page 44 •How we manage risk, page 60 | |||
c Describe how processes for identifying, assessing, and managing climate-related risks are integrated into the organization’s overall risk management. | •Risk Management, page 44 •How we manage risk, page 60 •Risk factors, page 67 | |||
Metrics and targets Disclose the metrics and targets used to assess and manage relevant climate-related risks and opportunities where such information is material. | a Disclose the metrics used by the organization to assess climate-related risks and opportunities in line with its strategy and risk management process. | •TCFD metrics and targets, page 54 | ||
b Disclose Scope 1, Scope 2, and, if appropriate, Scope 3 GHG emissions, and the related risks. | •GHG emissions data, page 38 | |||
c Describe the targets used by the organization to manage climate-related risks and opportunities and performance against targets. | •Our net zero aims and targets, pages 37-38 |
aWe consider the information in our TCFD disclosures, taken together with our climate-related non-financial KPIs on pages 16-17 of this report, to be compliant with the disclosure requirements of
Section 414CB of the Companies Act, as amended by the UK CFD Regulations.
Section 172 statement
In accordance with the requirements of Section 172 of the Companies Act 2006 (the Act), the directors consider that, during the financial year ended
31 December 2025, they have acted in a way that they consider, in good faith, would most likely promote the success of the company for the
benefit of its members as a whole, having regard to the likely consequences of any decision in the long term and the broader interests of other
stakeholders, as required by the Act.
| For more information in support of this statement, see board activities, page 78, our stakeholders, page 80 and key decisions, page 81 | |||
The strategic report was approved by the board and signed on its behalf by Ben J.S. Mathews, company secretary, on 6 March 2026.
72 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Corporate
governance
“In early 2025 the board’s focus
moved from the resetting of strategy
to overseeing disciplined performance
and the delivery of our four primary
financial targets.”
Albert Manifold
Chair
| Read Albert’s letter on page 4 |
Board of directors | 73 | ||
Leadership team | 76 | ||
Governance framework | 77 | ||
Board activities | 78 | ||
Our stakeholders | 80 | ||
Key decisions | 81 | ||
Safety and sustainability committee | 82 | ||
Audit committee | 84 | ||
People, culture and governance committee | 89 | ||
Remuneration committee | 91 | ||
Directors’ remuneration report | 91 | ||
Other disclosures | 126 | ||
Image: Rotterdam refinery, Netherlands
Board composition | ||
Board gender diversity | ||
March 2026 | March 2025 | |
Female | 6 | 6 |
Male | 7 | 5 |
46% of directors are female | ||
Board ethnic diversity | ||
March 2026 | March 2025 | |
White | 10 | 8 |
Asian | 3 | 3 |
3 directors who identify as from a minority ethnic background | ||
Non-executive directors’ tenure | ||
March 2026 | March 2025 | |
1-3 years | 4 | 3 |
4-6 years | 6 | 5 |
7-9 years | 1 | 1 |
Board biographies, page 73 | |
 |
bp Annual Report and Form 20-F 2025 | 73 |
| ||||
Corporate governance | ||||
Board of directors | ||||
As at 6 March 2026
Albert Manifold Chair | |
Appointed Board: 1 September 2025; chair: 1 October 2025 | |
Nationality Irish | |
External appointments | |
•Non-executive director at LyondellBasell Industries. •Non-executive director at Mercury Engineering. •Adviser to Clayton Dubilier & Rice. | |
Significant past appointments | |
•A number of senior positions at CRH plc over a 28- year career, including chief executive officer from January 2014 to December 2024. •Chief operating officer of Allen McGuire & Partners. | |
Key skills and experience | |
•Extensive experience of driving a business through exceptional growth and strategic transformations, leading to profitability and cash generation, and consistently improving returns to shareholders. •Certified public accountant and a chartered accountant. Holds a master of business administration and a master’s in business studies, both from Dublin City University. | |
Key | |
 | Executive director |
 | Non-executive director |
 | Leadership team member |
Committee members key | |
 | Committee chair |
 | Safety and sustainability committee |
 | Audit committee |
 | People, culture and governance committee |
 | Remuneration committee |
For further detail on the directors’ climate change and sustainability experience, see the TCFD section on page 41, and further biographical information for each director is available online at: bp.com/whoweare | |
Carol Howle Interim chief executive officer | |
Appointed 18 December 2025 | |
Nationality British | |
External appointments | |
•Non-executive board member of the Royal Navy. | |
Significant past appointments | |
•Various senior leadership roles at bp, including executive vice president, supply, trading & shipping and chief operating officer for integrated supply and trading, oil. | |
Key skills and experience | |
•With 25 years at bp, Carol has a deep knowledge of the company and extensive experience in the energy industry. Carol is also a non-executive board member of the Royal Navy and chair of the Navy Audit and Risk Assurance Committee. | |
Dame Amanda Blanc Independent non‑executive director | |
Appointed 1 September 2022 | |
Nationality British | |
External appointments | |
•Group CEO of Aviva plc. •Member of the Association of British Insurers Board. •Member of the UK Government’s British Infrastructure Taskforce. | |
Significant past appointments | |
•CEO of Europe, Middle East, Africa & Global Banking at Zurich Insurance Group. •Group CEO at AXA UK, PPP & Ireland. •Several senior executive roles across the insurance industry. •Member of the Prime Minister’s Business Council. •Member of HMT National Wealth Fund Taskforce. | |
Key skills and experience | |
•Brings wide-ranging board experience with strong industry and regulatory connections having previously been Chair of the Association of British Insurers. •Combines the experience of leading insurance businesses in the UK and Europe with being a member of HM Treasury’s Business Infrastructure Taskforce. | |
Kate Thomson Chief financial officer | |
Appointed 2 February 2024 | |
Nationality British | |
External appointments | |
•Board member of Aker BP since 2016. •Main committee member of The 100 Group. | |
Significant past appointments | |
•Joined bp in 2004. •Group head of tax, BP p.l.c. •Group treasurer, BP p.l.c. •SVP finance for production & operations, BP p.l.c. | |
Key skills and experience | |
•Has a detailed understanding and experience of the energy sector and provides deep technical insight from her broad experience of leading teams across the bp group in tax, treasury and commercial finance. | |
Tushar Morzaria Independent non-executive director | |
Appointed 1 September 2020 | |
Nationality British | |
External appointments | |
•Non-executive director of BT Group plc. •Non-executive director of Legal & General Group plc. | |
Significant past appointments | |
•Various senior roles at JP Morgan, including CFO of its Corporate & Investment Bank. •Group finance director and member of the board of Barclays PLC, 2013 to 2022. •Non-executive chairman of EMEA Investment Banking, Barclays until 2024. | |
Key skills and experience | |
•Over 25 years of strategic financial management, investment banking, operational and regulatory experience. •Breadth of knowledge and insight into financial, tax, treasury, investor relations and strategic matters and strong experience in delivering corporate change programmes while maintaining a focus on performance. | |
74 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Board of directors continued | ||
Ian Tyler Independent non-executive director | |
Appointed 1 April 2025 | |
Nationality British | |
External appointments | |
•Chair of Grafton Group plc. •Senior Independent Director of Anglo American plc. •Chair of BMT Group Ltd. •Member of KPMG Public Interest Committee | |
Significant past appointments | |
•Served as chair of Affinity Water Limited, AWE Management Limited, Al Noor plc, Amey UK plc, Vistry Group plc (formerly Bovis Homes Group) and of Cairn Energy plc. •Non-executive director of BAE Systems plc, VT Group plc, Mediclinic plc, Cable & Wireless Communications plc, and Synthomer plc. •CEO and finance director positions at Balfour Beatty plc. | |
Key skills and experience | |
•Extensive executive and non-executive experience across multiple industries. •Recent experience leading the remuneration committees of some of the UK’s largest quoted companies. | |
Dr Johannes Teyssen Independent non-executive director | |
Appointed 1 January 2021 | |
Nationality German | |
External appointments | |
•Senior advisor to Kohlberg Kravis Roberts. •President of Alpiq Holding Ltd. •Senior advisor to Viridor Limited. | |
Significant past appointments | |
•Several leadership positions at VEBA AG (merged with VIAG AG in 2000 and renamed to E.ON AG and later to E.ON SE). •Member of the board of management of the E.ON Group’s central management company in Munich in 2001 and E.ON SE in 2004. •Vice-chair of E.ON SE, 2008 and CEO, 2010 to 2021. •President of Eurelectric, 2013 to 2015. •Vice-chair of the World Energy Council, responsible for Europe, 2006 to 2012. •Member of the supervisory board of Salzgitter AG, 2006 to 2016, and Deutsche Bank AG, 2008 to 2018. | |
Key skills and experience | |
•Extensive experience and deep knowledge of the energy sector and its continuing transformation. •Considerable knowledge and experience of climate- related risk oversight. | |
Melody Meyer Independent non-executive director | |
Appointed 17 May 2017 | |
Nationality American | |
External appointments | |
•Non-executive director of AbbVie Inc. •Non-executive director of Airswift Parent LLC. •President of Melody Meyer Energy LLC and Women with Energy LLC. •Director of the National Bureau of Asian Research. •Advisory board member of McKinsey Advancing With Excellence. •Trustee of Trinity University. | |
Significant past appointments | |
•President of Chevron Asia Pacific E&P until 2016 after 37 years of service in key leadership roles in global exploration and production. | |
Key skills and experience | |
•Deep understanding of the factors influencing safe, efficient and commercially high-performing projects in a global organization. •Expertise in the execution of major capital projects, technology, R&D, creation of businesses in new countries, strategic business planning, merger integration, leading change, and safe and reliable operations. | |
Hina Nagarajan Independent non-executive director | |
Appointed 1 March 2023 | |
Nationality Indian | |
External appointments | |
•President of Diageo Africa. •Executive Director and Vice Chairperson of East African Breweries PLC and Member of Board Nomination and Remuneration Committee. •Member of the Global Executive Committee of Diageo plc. | |
Significant past appointments | |
•Leadership positions at United Spirits Limited (Diageo India), Reckitt, Mary Kay India and Nestlé India with over 30 years’ experience in the fast- moving consumer goods (FMCG) industry. •Non-executive director at two companies which were publicly quoted at the time: Guinness Ghana Breweries Plc and Seychelles Breweries Limited. •Board member of The Advertising Standards Council of India. •Director and Co-Chair of International Spirits and Wines Association of India. | |
Key skills and experience | |
•Deep and wide-ranging experience in customer- focused FMCG businesses in complex emerging markets. •Extensive experience in assessing climate-related risks and opportunities. | |
Satish Pai Independent non-executive director | |
Appointed 1 March 2023 | |
Nationality Indian | |
External appointments | |
•Managing Director of Hindalco Industries Limited. •Director of Novelis Inc. •Non-executive director, Aditya Birla Management Corporation Ltd. •Director, Indian Institute of Metals. | |
Significant past appointments | |
•Executive vice president, worldwide operations and other engineering and management roles at Schlumberger across 28 years of service. | |
Key skills and experience | |
•Accomplished and transformative executive with operations and technology experience in the resources and energy industries. •Strong digital capability and experience. | |
Dave Hager Independent non‑executive director | |
Appointed 2 June 2025 | |
Nationality American | |
External appointments | |
•none. | |
Significant past appointments | |
•Leadership positions at the Oryx Energy Company. •Executive vice president and later chief operating officer of Kerr-McGee. •Board memberships with EnLink Midstream and Pride International Inc. •Various senior leadership roles at the Devon Energy Corporation, including executive chairman, 2021 to 2013. •Director of MRC Global Inc. | |
Key skills and experience | |
•Over 40 years’ experience in the oil and gas industry. •Deep-rooted knowledge of the US upstream oil and gas industry. | |
bp Annual Report and Form 20-F 2025 | 75 |
| ||||
Corporate governance | ||||
Karen Richardson Independent non-executive director | |
Appointed 1 January 2021 | |
Nationality American | |
External appointments | |
•Partner at Artius Capital Partners. •Non-executive director of Artius II Acquisition Inc. •Non-executive director (lead independent director) of Exponent Inc. | |
Significant past appointments | |
•Senior operating roles in the public and private technology sectors. •Vice president of sales at Netscape Communications Corporation, 1995 to 1998. •Senior executive roles at E.piphany from 1998, including CEO, 2003 to 2006. •Non-executive director of BT plc, 2011 to 2018. •Director of Worldpay Inc. (Worldpay Group plc), 2016 to 2019. •Chair of Origin Materials Inc., 2021 to 2024. | |
Key skills and experience | |
•Extensive digital, technology, cyber and IT security knowledge. •30 years’ technology industry experience including working with innovative Silicon Valley companies. | |
Simon Henry Independent non‑executive director | |
Appointed 1 September 2025 | |
Nationality British | |
External appointments | |
•Advisor to the Board of Oxford Flow Ltd. •Member of the Board of the Audit Committee Chairs’ Independent Forum. | |
Significant past appointments | |
•Non-executive director of Rio Tinto plc between 2017 and 2025. •Directorships with Harbour Energy plc, Lloyds Banking Group plc and PetroChina Ltd. •Various senior executive and leadership roles at Shell, including chief financial officer from 2009 to 2017. | |
Key skills and experience | |
•Extensive career in energy industry internationally with broad experience of the global upstream and downstream energy industry. •Wide-ranging expertise and experience with financial and commercial understanding of global markets. | |
Ben J S Mathews Company secretary | |
Appointed 7 May 2019 | |
Role and career summary | |
Ben joined bp as company secretary in May 2019. He is co-chair of the Corporate Governance Council of the Conference Board and is a Fellow of the Chartered Governance Institute. Ben serves on the executive committee of the Association of General Counsel and Company Secretaries of the FTSE 100 (GC100), having previously served as its chair for four years. Ben’s global company secretary team is responsible for providing independent advice and support to the plc board and the boards of all other legal entities in the bp group. The team's vision is to enhance stakeholder value through dynamic corporate governance. Former appointments include group company secretary of HSBC Holdings plc and Rio Tinto plc. | |
Board meeting attendance | Committee membership | Skills and experience | ||||||||||||||||
Scheduled | Ad hoc | Audit | Remuneration | People, culture and governance | Safety and sustainability | Society, politics and geopolitics | Technology, digital and innovation | People leadership and organizational transformation | Operational excellence and risk management | Global business leadership and governance | Finance, risk and trading | Energy markets | Climate change and sustainability | |||||
Non-executive directors | ||||||||||||||||||
Albert Manifold (Chair)a b | 3/3 | 2/2 | ò | ò | ò | ò | ò | ò | ò | |||||||||
Helge Lund (Chair)a | 6/6 | 2/2 | ò | ò | ò | ò | ò | ò | ò | |||||||||
Dame Amanda Blanc | 8/8 | 5/5 | ò | ò | ò | ò | ò | ò | ò | ò | ||||||||
Pamela Daleya c | 2/4 | 1/2 | ò | ò | ò | ò | ò | |||||||||||
Dave Hagera b | 4/4 | 2/2 | ò | ò | ò | ò | ò | ò | ò | |||||||||
Simon Henry a | 3/3 | 2/2 | ò | ò | ò | ò | ò | ò | ò | ò | ||||||||
Tushar Morzariab c | 8/8 | 4/5 | ò | ò | ò | ò | ò | ò | ||||||||||
Melody Meyer c | 8/8 | 4/5 | ò | ò | ò | ò | ò | ò | ||||||||||
Hina Nagarajanc | 6/8 | 5/5 | ò | ò | ò | ò | ò | ò | ò | |||||||||
Satish Pai c | 8/8 | 4/5 | ò | ò | ò | ò | ò | ò | ò | |||||||||
Karen Richardson c | 8/8 | 4/5 | ò | ò | ò | ò | ò | ò | ||||||||||
Dr Johannes Teyssen | 8/8 | 5/5 | ò | ò | ò | ò | ò | ò | ò | ò | ||||||||
Ian Tylera b | 6/6 | 3/3 | ò | ò | ò | ò | ò | ò | ||||||||||
Executive directors | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September 2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director attended all board meetings following their appointment or prior to their retirement from the board, as applicable. b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; and Dave Hager joined the safety and sustainability committee from 10 December 2025. c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment. | |||||||||||||||||
Carol Howle (CEO)a | 0/0 | 0/0 | ||||||||||||||||
Murray Auchincloss (CEO)a | 8/8 | 5/5 | ||||||||||||||||
Kate Thomson (CFO) | 8/8 | 5/5 | ||||||||||||||||
ò Chair of the committee ò Member of the committee | ||||||||||||||||||
76 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Leadership team | ||||
Gordon Birrell EVP production & operations | |
Leadership team tenure Appointed on 1 July 2020 | |
Nationality British | |
Board memberships | |
Gordon is a non-executive director of Azule Energy Holdings Ltd. | |
Career summary | |
Before being appointed to his new role, Gordon was chief operating officer for production, transformation and carbon. In his bp career, Gordon has spent time in various leadership, technical, safety and operational risk roles, including four years as bp president Azerbaijan, Georgia and Türkiye. Gordon is a fellow of the Royal Academy of Engineering. | |
Emeka Emembolu EVP technology | |
Leadership team tenure Appointed on 18 April 2024 | |
Nationality British | |
Board memberships | |
None | |
Career summary | |
Emeka is EVP of Technology at bp, leading digital, safety, security and science to advance innovation and safeguard the business. He has spent over 25 years with bp, previously serving as chief of staff to the CEO and leading the North Sea business as regional SVP. His earlier roles span senior technical roles across the Gulf of America, Canada, North Africa and Alaska. | |
Carol Howle EVP supply, trading & shipping | |
Carol Howle is also part of the bp leadership team in her role as EVP supply, trading & shipping. You can read her bio on page 73. | |
Emma Delaney EVP customers & products | |
Leadership team tenure Appointed on 1 July 2020 | |
Nationality Irish | |
Board memberships | |
Director of RBML limited | |
Career summary | |
Emma has spent 30 years working in bp, both in the upstream and the downstream. Prior to joining bp’s executive team on 1 April 2020, she was regional president for West Africa. She has held a variety of senior roles including upstream chief financial officer for Asia Pacific and head of business development for gas value chains. In downstream she held roles in retail and commercial fuels and planning. | |
William Lin EVP gas & low carbon energy | |
Leadership team tenure Appointed on 1 July 2020 | |
Nationality American | |
Board memberships | |
William serves on the supervisory board of Corbion, a publicly listed biotechnology company where he chairs the sustainability & safety committee and sits on the audit committee. He also chairs the board of JERA Nex bp, a global offshore wind developer and is vice-chair at Pan American Energy Group, Argentina’s largest independent energy company. | |
Career summary | |
William has worked at bp for 30 years and now leads the group’s global natural gas and low carbon businesses and markets. Prior to this role, he held other senior management positions including the chief operating officer for upstream regions, regional president for Asia Pacific, and vice president for gas developments and operations for Egypt. | |
Kerry Dryburgh EVP people, culture & communications | |
Leadership team tenure Appointed on 1 July 2020 | |
Nationality British | |
Board memberships | |
None | |
Career summary | |
Kerry leads people, culture & communications, which also includes brand, global transformation, health and wellbeing and workplace. Prior to her current role, she headed HR for bp’s upstream business and served as group chief talent officer, alongside senior HR roles in supply, trading and corporate functions. Kerry began her career with an apprenticeship and worked across several sectors in Europe and Asia before joining bp in 2010. | |
Mike Sosso EVP legal | |
Leadership team tenure Appointed on 1 January 2024 | |
Nationality American | |
Board memberships | |
None | |
Career summary | |
Mike took on the role of EVP legal in January 2024. In his role, Mike is accountable for leading the legal function and executing the legal strategy for the group. Mike joined bp in 2011 and has held a number of leadership positions across legal. He also previously held the role of VP ethics and compliance. Prior to joining bp, Mike practised law in the Washington, DC office of Skadden, Arps, Slate, Meagher & Flom. | |
bp Annual Report and Form 20-F 2025 | 77 |
| ||||
Corporate governance | ||||
Governance framework | ||||
Board of directors | ||||||||||||
Non-executive directors | Executive directors | |||||||||||
Chair | Senior independent director | Independent non-executive directors | Chief executive officer | Chief financial officer | Company secretary | |||||||
Board committees | ||||||||||||
Safety and sustainability committee | Audit committee | People, culture and governance committee | Remuneration committee | |||||
Report from page 82 | Report from page 84 | Report from page 89 | Report from page 91 | |||||
Executive leadership | ||||||||
bp leadership team | ||||||||
bp’s governance framework helps to drive
informed and efficient decision making
through a clear division of responsibilities.
This enables bp to operate effectively and
in alignment with the strategy as set by
the board.
Responsibilities of the board
The board is appointed by shareholders. Its
responsibility, through the directors, is to
promote the success of the company, to drive
value for shareholders, having regard to the
company’s stakeholders and the
consequences of the decisions it takes in the
long term. Fulfilling this role, the board is
responsible for setting and overseeing the
implementation of the company’s strategy,
purpose and values. The board’s oversight role
includes monitoring culture and reviewing the
effectiveness of the company’s system of
internal control.
More detailed information about the board’s
activities is available from page 78.
Delegation of authority
There are four main committees of the board,
each operating under delegated
responsibilities which are outlined in their
respective terms of reference available at
bp.com/governance.
Day-to-day management of the business is
delegated by the board to the chief executive
officer (CEO), who in turn is advised and
supported by a leadership team (bpLT)
comprising seven individuals who are
accountable to her for their respective
business or functional areas, with defined
financial authority levels. Decisions are taken
by the CEO in the execution of the operational
responsibilities delegated to her by the board.
For example, the CEO’s authority includes a
limit on the nature and type of investments,
capital expenditure« and financial
commitments she may take in isolation. Any
matters that exceed this limit, or that go
beyond the annual plan or approved strategy,
constitute a matter reserved for the board as
a whole.
Further delegations of authority are maintained
throughout the business in a consistent way.
Board committees
The four board committees operate under
terms of reference which are reviewed
periodically.
The chair of each committee routinely reports
to the full board on their activities and, where
applicable, makes recommendations for the
board’s approval.
Board roles
Non-executive directors (NEDs)
Provide independent oversight, mentoring and
constructive challenge to the executive
directors and bpLT. NEDs bring valuable
external perspective and support effective
governance in matters such as performance
management and succession planning.
Chair
•As chair, Albert Manifold leads the board
and is accountable to shareholders for its
overall effectiveness.
•This includes shaping and managing the
culture of the boardroom, facilitating the
board’s ability to hear the views of
stakeholders, and overseeing the
composition and development of
the board.
Senior independent director (SID)
•Amanda Blanc acts as a sounding board
for the chair and, if necessary, as an
intermediary for other directors
and investors.
Executive directors
Executive directors are tasked with the
implementation of bp’s strategy and are
responsible for all executive management
matters affecting the company.
Chief executive officer (CEO)
•In her capacity as interim CEO, Carol Howle
is responsible for the design and
implementation of bp’s strategy and annual
plan, which are ultimately approved by
the board.
•In accordance with the authorities
delegated to her, the CEO implements the
system of internal control and is
responsible for setting policies, standards
and procedures that foster bp’s culture
and values. In this regard, she is
accountable to the board which oversees
the effectiveness of the internal control
framework.
Chief financial officer (CFO)
•Our CFO Kate Thomson provides financial
leadership for the business and supports
the CEO in the development and
implementation of the strategy.
Company secretary
Ben Mathews advises the board on corporate
governance matters, changes to and
compliance with board procedures, and
monitors regulatory requirements. He also
supports the chair in providing timely,
accurate and clear information to the board.
Further information on specific board roles is
available at bp.com/governance.
78 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Board activities: promoting long-term sustainable success | ||
In 2025, the board and its committees held regular meetings as needed, to address business requirements. Agendas were set in advance by the
chair, CEO, and company secretary, focusing on four pillars of strategy, performance, people, and governance. The board’s activities, supported by
its committees, spanned each of these pillars. In 2025 this included visits to bp Washington DC, US and the Whiting refinery in Chicago, US,
facilitating direct engagement with a range of stakeholders. Highlights are provided below.
| | |||
Strategy and performance Strategic direction TCFD •Worked closely with the CEO and the leadership team to approve a new purpose and reset strategy for bp, as announced in February 2025. •Established a routine of discussing progress against the primary targets included in the reset strategy with management, including insights into specific areas of the business with the greatest impact on delivery. Macroeconomics TCFD •Received regular updates on macroeconomic and geopolitical factors affecting our strategy, plan and performance. Annual plan •Reviewed full-year delivery against the 2024 plan and monitored progress against 2025 objectives, enhanced by regular performance insight sessions with leadership from key business areas. ▪Reviewed and approved the 2025 annual plan that focused on capital allocation, cost reduction and initiatives to improve the balance sheet and reduce net debt. Financial frame and distributions •Reviewed and approved a refreshed financial frame to support the reset strategy, covering capital allocation, a targeted reduction of net debt, and the delivery of resilient shareholder distributions. •Regularly reviewed performance against the financial frame. •Regularly reviewed shareholder distribution options in alignment with the financial frame. Capital expenditure •Received an update from the CEO at every board meeting covering projects across all bp’s businesses and, where appropriate, climate-related considerations.TCFD These updates included any inorganic acquisition or divestment opportunities of more than $1 billion. Mergers and acquisitions pipeline •Regularly reviewed divestment opportunities in support of the net debt target set out as part of the reset strategy. •Reached a final investment decision for the Tiber and Guadalupe projects in the Gulf of America, approving bp’s second new production platform in less than two years. •Approved the divestment of bp’s majority interest in Castrol. | Acquisition reviews •Evaluated progress on the integration of transition businesses, Archaea Energy and TravelCenters of America. TCFD Offsites •Board members visited three US sites: Whiting refinery, bpx energy operations in Denver and bp Washington DC. Technology •Received an update on progress and delivery of the technology functional reorganization, digital transformation programme, the continued development and impact of strategic partnerships and priorities for 2026. •Participated in deep-dive sessions on the use of breakthrough imaging and robotic automation, and the deployment of generative artificial intelligence solutions across bp businesses. Safety and sustainability TCFD •Routine reviews of safety performance undertaken, including measurement against targets and ad hoc reporting, as required. •Focused the sustainability aims on those most relevant to the long-term success of our businesses and to our net zero ambition. Principal risks •Analysed trends and themes arising from risk management processes. •Performed mid-year and full-year reviews of bp’s principal and emerging risks, including those related to climate. TCFD Internal controls •Evaluated the group’s internal control and risk management systems as part of the review and approval of the bp Annual Report and Form 20-F. •Routinely received reports from group risk and internal audit – no specific concerns were identified and the board concluded that the systems remain resilient, fit for purpose, and aligned with external expectations (see how we manage risk on page 60). | |||
| |
| | ||||
Board activity highlights | January and February: •Board meeting, virtual. •Board and committee meetings (audit; people, culture and governance; remuneration; and safety and sustainability) including Q4 results, London, UK. | March and April: •Board and committee meetings (audit and remuneration) including Q1 results, virtual. •2025 Annual General Meeting, Sunbury, UK. •Workforce engagement session with employees from the US and UK. | May and June: •Board and committee meetings (audit; people, culture and governance; remuneration; and safety and sustainability), Washington DC, US. •Visit to Whiting refinery, US. •Workforce engagement sessions with employees from Brazil; Canada; Gulf of America; US; and UK. | ||
| | ||||
bp Annual Report and Form 20-F 2025 | 79 |
| ||||
Corporate governance | ||||
| | | | |||
People Engagement •Undertook the board’s workforce engagement programme (WFEP), using it to bring employee feedback into the boardroom to allow for board decisions to be better informed of stakeholder views (see page 80). •Through the board’s site visits, directors met with high- potential employees to improve visibility and profile of the executive succession pipeline and to increase director interaction with the workforce in those locations (further information on in-person site visits on page 80). Culture •Received feedback from Pulse employee surveys, agreeing actions and initiatives in response. •Reviewed the annual ethics and compliance report, and the function’s priorities and objectives. Succession planning •Supported by the people, culture and governance committee, the board received updates on succession plans for the board (see page 90 for further information on board succession). •Undertook a review of leadership development initiatives, including succession plans for the bp leadership team. | Governance Board composition and director changes •Following a comprehensive selection process, appointed: –Albert Manifold as non-executive director with effect from 1 September 2025 and as chair of the board and chair of the people, culture and governance committee with effect from 1 October 2025. –Ian Tyler as a non-executive director and member of the remuneration committee with effect from 1 April 2025, and as chair of the remuneration committee with effect from 17 April 2025. –Dave Hager as a non-executive director with effect from 2 June 2025, and as a member of the safety and sustainability committee with effect from 10 December 2025. –Simon Henry as a non-executive director with effect from 1 September 2025. –Carol Howle as interim CEO with effect from 18 December 2025 and Meg O’Neill as CEO with effect from 1 April 2026. Corporate governance framework ▪Considered the corporate governance framework, including the terms of reference for the board and each committee. Director training and knowledge sessions •Completed online training on topics including the code of conduct and cyber security. Board performance review •Conducted an internally facilitated board and committee performance review led by the chair and company secretary (see page 90). Investor engagement •The chair, executive directors, senior independent director, remuneration committee chair, company secretary and members of senior management engaged with investors through meetings, roadshows, quarterly results calls, presentations and the Annual General Meeting. Reports on such engagement was shared with the full board. | |||||
| | |||||
 | ||||||
| | |||||
Image: Members of the board at our Canary Wharf office, London, UK | Key: TCFD Recommendations and Recommended Disclosures |
| | ||||
Board activity highlights | July and August: •Board and committee meetings (audit; people, culture and governance; remuneration; and safety and sustainability), including Q2 results, London, UK. •Visit to bpx energy, Denver, US. •Workforce engagement session with employees from Greece; Hungary; Spain; UK; and US. | September and October: •Board and committee meetings (audit; remuneration; and safety and sustainability) London, UK. •Visit to bp supply, trading and shipping floor, London, UK by the audit committee. •Workforce engagement sessions with employees from India; Malaysia; and UK. | November and December: •Board and audit committee meetings, including Q3 results, virtual. •Board and Committee meetings (people, culture and governance; remuneration; audit and safety and sustainability) London, UK. •Workforce engagement sessions with employees from Hungary; India; UAE; and UK. | ||
| | ||||
80 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Our stakeholders | ||
Directors regularly engage with a wide range
of stakeholders to gain different insights,
giving the board a more rounded perspective
in support of the decisions it takes. This
engagement helps the directors fulfil their
statutory duties and build greater trust inside
and outside of bp. It also helps improve the
board’s understanding of stakeholder views on
bp’s strategy, performance, operations and
governance – all in support of the long-term
success of the company.
Image: Members of the board during their tour of
Whiting refinery, US
| | |
Stakeholders key ò Investors and shareholders ò Customers ò Workforce ò Governments and regulators ò Partners and suppliers ò Society | ||
| |
| | |
Our Section 172(1) statement describes how the directors have had regard to the matters set out in Section 172(1)(a) to (f) of the Companies Act 2006; see page 71. Further information on the board’s activities and key decisions, including how stakeholder interests have been considered, can be found on pages 78-80 and page 81. | ||
| |
Fostering mutual understanding
òò
The board’s approach to stakeholder
engagement allows for a better understanding
of matters that are important and relevant to
the decisions it takes and to support the
delivery of bp’s strategy.
For the non-executive directors (NEDs), one of
the key mechanisms for engagement with
colleagues is the workforce engagement
programme (WFEP). NEDs participate in
roundtable sessions with selected individuals
on a specific topic. In 2025 these sessions
included safety, culture, remuneration
and technology.
To engage bp colleagues, directors were
involved in bp’s webcasts during the year.
Additionally, on becoming chair of bp,
Albert Manifold gave a video message to
introduce himself to bp employees and
set out his priorities.
bp’s financial and operational performance
was an important topic for both investors and
the workforce in 2025, with directors seeking
to enhance each group’s understanding of the
factors affecting the company’s overall
performance through their engagements.
Promoting balanced perspectives
òòòò
In 2025 board engagements included eight
WFEP sessions, and meetings with local
businesses, partners, governments and
regulators from key jurisdictions.
The audit committee participated in a floor
walk of the supply, trading & shipping function
at bp’s Canary Wharf site in the UK.
Several director engagements were held with
leadership teams from Archaea Energy, bpx
energy and the Gulf of America, in addition to a
dedicated session with the US leadership team
as part of the board programme in May.
In addition to the AGM, results calls,
roadshows, one-to-one and group meetings
with investors in 2025, bp held a retail
shareholder engagement event, hosted by the
company secretary. Feedback from this event
was used by the board to inform future
investor engagements. As with all shareholder
engagement activity, including votes received
from shareholders at the AGM, the feedback
received is taken into account in helping to
inform board discussion and debate and areas
of particular focus for management.
Delivery of strategy guided by
stakeholder perspectives
òòòòòò
The bp strategy reset announced in February
2025 was developed following a
comprehensive stakeholder engagement
programme undertaken throughout 2024. In
2025 the board’s focus was on overseeing
management’s performance in its delivery of
the strategy.
See more on key decisions, page 81 | |
|
Building trust in bp
òòò
Two themes for the board in helping to
maintain and enhance organizational trust
continue to be safety performance and culture.
On safety, directors gained valuable insights
from employees, suppliers and partners as
part of board meetings, company-wide
engagements and site visits. Examples in 2025
included presentations by refining, bpx energy
and Gulf of America on safety plans and
performance. Notably, the safety and
sustainability committee’s visit to the Whiting
refinery in the US provided direct insights on
the site’s approach to safety, operational
reliability and its ongoing commitment to
continuous performance improvement.
Related to culture, feedback was shared on
progress against bp’s organizational
transformation. The Pulse employee
engagement survey reports and OpenTalk
reports (bp’s whistleblowing service) continue
to be a feature of board discussions. Looking
to the future of bp, the board reviewed the
talent pipeline and leadership development.
Board member participation in the
bpChallenge, bp’s flagship early‑careers event,
offered valuable perspectives into the
company’s talent development programme.
For more on culture see page 90.
Opportunities for collaboration
òòòòò
By attending meetings and events with
external stakeholders, and bp’s partners and
suppliers, the board gained insight into market
trends and development opportunities.
Engagements with governments and
regulators, together with consideration
of wider society’s interests, focused on
long‑term, sustainable value. For example,
capital investment (Argos expansion in
US Gulf of America), and portfolio growth
opportunities (Egypt, Trinidad and Tobago,
Mauritania and Senegal).
bp’s success in collaboration with partners
has led to several joint venture discoveries,
including in Namibia’s Orange Basin and
Gajajeira-01 in Angola. A key highlight in 2025
was the Bumerangue (Brazil) discovery –
the biggest for bp in 25 years.
Benchmarking progress
òòòòòò
Stakeholder engagement enhances the
board’s ability to benchmark our progress
against peers and to innovate, ultimately
benefiting our shareholders, workforce,
customers, suppliers and business partners,
and the communities where bp operates.
bp Annual Report and Form 20-F 2025 | 81 |
| ||||
Corporate governance | ||||
Key decisions | ||||
Section 172 of the Companies Act 2006 requires directors to act in a way they believe will promote the success of the company for the benefit of
its shareholders. The directors are required to consider the long-term impact of their decisions, the interests of employees, relationships with
stakeholders, the community and environment and maintain high standards of business conduct. Set out below are four of the key decisions taken
by the board during 2025 reflecting the directors’ consideration of these requirements.
| | | | |||
Strategy and performance TCFD | Leadership transition | |||||
In support of the strategy reset, announced in February 2025, the board approved a refreshed financial frame with four primary financial targets: growing free cash flow, increasing the cost reduction target, reducing net debt and generating higher returns on investment. Five focused sustainability aims were also approved: net zero operations, net zero sales, people, biodiversity, and water. Having taken these decisions, the board wanted to closely monitor and oversee the implementation of the reset strategy and the delivery of the primary targets. During 2025, the board engaged in an extensive dialogue with the bpLT, with more granular reporting reviewed at every board meeting. This approach was supplemented by a programme of insight sessions where the leaders of the businesses with the greatest potential impact on delivery of the targets provided deeper insight on their plans and targets and tools that could be used to mitigate any risk to delivery into those business areas. The board, through the remuneration committee, sought to achieve alignment of performance measures for the group’s long and short-term incentive arrangements with the reset strategy, ensuring that the four primary financial targets form part of the basis for internal performance management and remuneration outcomes through to 2027. Stakeholders considered òòòòòò | After more than three decades with bp, Murray Auchincloss informed the chair of his openness to step down as CEO were an appropriate leader identified who could accelerate delivery of bp’s strategy. A committee of the board was established and undertook a comprehensive search process which led to the appointment of Meg O’Neill as CEO with effect from 1 April 2026, with Carol Howle serving as interim CEO from 18 December 2025 until Meg’s appointment takes effect. When reviewing the recommendations from the committee to appoint Meg, the board considered how the leadership transition could accelerate bp’s strategic vision to become a simpler, leaner, and more profitable company, and created an opportunity to make the necessary transformative changes to maximize value for shareholders. The board considered Meg to be the most appropriate candidate given her proven track record of driving transformation, growth, and disciplined capital allocation. Her relentless focus on business improvement and financial discipline positions her well in leading bp through its next phase of growth. Stakeholders considered òòòòòò | |||||
| | | | |||
| | | | |||
Expanding production capacity | Castrol divestment approval | |||||
In September 2025 the board took a final investment decision (FID) for a seventh operated oil and gas production hub, Tiber- Guadalupe, in the US Gulf of America. The new hub, which features a floating production platform and includes six wells in the Tiber field and a two-well tieback from the Guadalupe field, is expected to have a production capacity of 80,000 barrels of oil per day. Production is expected to start in 2030. In reviewing the FID proposal, the board considered how existing platform and subsea equipment designs could be utilized to drive cost efficiencies across the production hub’s construction, commissioning and operations. The board concluded that the hub’s strategically advantaged location, ability to deploy enhanced high-pressure drilling technology and synergies identified from using more than 85% of the design from bp’s Kaskida project (another board-approved oil and gas production hub in the Gulf of America, announced in July 2024) combined to make a strong economic case for sanctioning this project. Stakeholders considered òòòò | In December 2025 the board approved the sale of a 65% shareholding in Castrol to Stonepeak, at an enterprise value of $10.1 billion. This represents an implied EV / LTM EBITDA of around 8.6x reflecting the strength of the business and future growth potential. The decision followed a comprehensive strategic review of Castrol, through which the board considered how the transaction would accelerate delivery of bp’s reset strategy, including focusing the downstream, and strengthening the balance sheet. With the transaction expected to generate approximately $6.0 billion in net proceeds for bp upon completion, the board decided to fully utilize the proceeds to reduce net debt. Completion is anticipated by the end of 2026, subject to regulatory approvals. The board decided to retain a 35% interest in the new joint venture, providing continued exposure to Castrol’s growth while maintaining the option to divest its remaining stake after a two‑year lock‑up period. Stakeholders considered òòòò | |||||
| | | |
82 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Safety and sustainability committee | ||
| | |
“The committee provided disciplined oversight of safety, security and sustainability across the business.” Melody Meyer Safety and sustainability committee chair | ||
| |
Meetings and attendance
The committee met five times during 2025.
Regular attendees included EVP production
and operations; SVP safety and operational
risk assurance; SVP intelligence, security and
crisis management; SVP digital security; SVP
HSE and carbon; and SVP global ethics and
compliance.
Non-executive directors | Five scheduled meetings |
Melody Meyer: member (from May 2017), chair of the committee (from November 2019) | 5/5 |
Dave Hager: member (from December 2025) | 0/0 |
Satish Pai: member | 5/5 |
Johannes Teyssen: membera | 4/5 |
aJohannes Teyssen was unable to attend the scheduled
meeting in September 2025 due to an existing external
commitment.
Chair’s introduction
Dear fellow shareholders,
I am pleased to present the safety and
sustainability committee report for the year
ended 31 December 2025.
During 2025, the committee provided
disciplined oversight of safety, security, and
sustainability across the business, with a
strong emphasis on risk management and
operational excellence. This included
overseeing progress in the implementation of
Process Safety Improvement Plans (PSIPs) in
certain businesses, conducting deeper dives
on both process and personal safety,
reviewing personal and cyber security, and
considering operational integrity. The
committee also reviewed the principal safety
risks and associated mitigations, and received
updates on the integration of bp’s safety
standards into newly acquired businesses.
Tragically, four colleagues lost their lives
during 2025. We extend our sincere
condolences to the families, friends and
colleagues of all of those impacted.
One fatality occurred in our Thorntons retail
business and three occurred in separate
incidents in our TravelCenters of America (TA)
business during roadside assistance activities.
During the incident investigation, and
permanently thereafter, all highway roadside
assistance activities were suspended in our TA
business. As with all major incidents, the
committee received reports on the incident
investigation findings and the actions taken
in response.
Following the company’s strategy reset in
February 2025, the committee provided
oversight on the implementation of the five
refreshed sustainability aims: net zero
operations; net zero sales; people; biodiversity;
and water. For more information see page 37.
During 2025, members of the committee
participated in a site visit to Whiting refinery in
the US. This site visit provided the opportunity
to have open and constructive dialogue with
employees and observe bp’s safety and
sustainability culture and performance
in action.
As I reach the end of my nine-year term on the
board and as chair of the committee, I want to
express my sincere appreciation for the high
level of engagement, transparency and
commitment demonstrated across bp in
advancing safety performance, sustainability
and operational excellence.
Looking forward to 2026, the committee will
focus its oversight on maintaining the good
progress and continuous improvement in
safety performance and the implementation of
bp’s Operating Management System« within
recently acquired businesses.
Role of the committee
The committee oversees the management of
safety and sustainability matters, including
physical and cyber security and relevant
systems and processes, focusing on those
which it considers to be most potentially
material from time to time.
Key responsibilities
The committee’s full terms of reference can be
viewed at bp.com/governance.
Melody Meyer
Committee chair
6 March 2026
bp Annual Report and Form 20-F 2025 | 83 |
| ||||
Corporate governance | ||||
Activities during the year
Overseeing improved safety
performance
The committee continued to oversee safety
performance, supporting management’s
progress in reducing combined tier 1 and 2
process safety events«. During 2025,
combined tier 1 and tier 2 safety performance
improved, with combined process safety
events being 29% lower than in 2024.
The committee received regular reports from
the EVP production and operations on safety
and operational performance, incident
reviews, and on the mitigation of principal and
emerging safety risks around the business. It
also received updates from management on
the implementation of PSIPs in certain
businesses and updates on personal security
improvements, including the integrity of crisis
management and business continuity
processes.
Deep-dive updates regarding significant or
material events and specific risk areas within
the business were also received. The
committee challenged management on the
root cause and learnings from these incidents
and how learnings are embedded into existing
safety processes.
Providing challenge on risk
management
The committee provides independent
challenge to management on the
effectiveness of the processes and
procedures implemented to manage safety
and sustainability risk. This is achieved through
regular review and monitoring of the principal
risks allocated to it by the board and through
deep-dives on key risk areas including wells,
process safety, marine risk, product quality,
pipeline risk, transportation risk, maintenance
integrity, cyber security, ethics and
compliance, and regulatory compliance.
Further deep-dives were undertaken into
specific areas of risk within the business
covering risk management and safety
performance in newly acquired businesses,
such as TravelCenters of America, Archaea
Energy and bp bioenergy. This provided the
committee with enhanced oversight of the
integration of bp’s Operating Management
System« into newly acquired businesses.
The committee routinely received:
•Updates on the activities of internal audit,
focused on operational safety audits,
together with an annual report on bp’s
system of internal control. This provides an
independent view on management’s safety
and sustainability performance, as well as
an independent assessment of key
challenges and risk areas.
•Briefings from the SVP global ethics and
compliance on emerging areas of risk and
associated mitigations, including increased
reports of external threats affecting retail
operations.
•Reports on cyber security risks and the
effectiveness of mitigation processes,
including identification of emerging cyber
risks from AI and geopolitical events.
The committee also continued its joint
engagement with the audit committee
through combined updates on non-operated
joint venture safety and sustainability.
Oversight of sustainability matters
Refreshing bp’s sustainability frame TCFD
The committee reviewed and endorsed a
refreshed sustainability frame with five aims:
net zero operations; net zero sales; people;
biodiversity; and water. Progress against these
aims was monitored through regular updates
from management. In 2025 focused deep-
dives were undertaken into each pillar of the
sustainability frame, with focus on
management’s plans to address areas of more
challenged delivery.
Human rights and global reporting
landscape
The committee reviewed progress on
mitigations in human rights and modern
slavery. It also kept abreast of the current
global sustainability reporting environment,
including bp’s plans for compliance through
reporting from management.
Sustainability and safety linked
remuneration targets
The committee made recommendations to the
remuneration committee regarding safety and
sustainability targets and outcomes that are
tied to remuneration. This included critically
analyzing current methodologies for the
setting of targets to ensure they remain
appropriately stretching, and incorporated
changes to the sustainability frame announced
in February 2025.
 | ||
Whiting refinery visit During the visit to the Whiting refinery, the S&SC members were briefed on infrastructure upgrades, with particular emphasis on enhancements to electrical systems and the refinery’s continued focus on safety, reliability and continuous improvement. The S&SC members also took a driving tour of the refinery to gain a deeper understanding of its operational footprint and integration with the local community. The visit provided an opportunity for the Whiting team to demonstrate their critical role in bp’s integrated value chain and commitment to operational excellence. Image: Whiting refinery, US | ||
| | |
TCFD Information that supports TCFD Recommendations and Recommended Disclosures in relation to governance (see pages 41-44)
84 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Audit committee | ||||
| | |
“The committee had particular focus on advancing digital transformation initiatives.” Tushar Morzaria Audit committee chair | ||
| |
Meetings and attendance
The committee met eight times during 2025.
Regular attendees included the chief financial
officer (CFO), group controller, SVP internal
audit, EVP legal and the external auditor.
Non-executive directors | Eight scheduled meetings |
Tushar Morzaria: member (from September 2020), chair of the committee (from May 2021) | 8/8 |
Pamela Daleya: member (until 7 July 2025) | 2/4 |
Karen Richardson: member | 8/8 |
Hina Nagarajanb: member | 7/8 |
Ian Tyler: member (from 2 June 2025) | 4/4 |
aPamela was unable to attend the meetings in April and May
due to personal reasons.
bHina was unable to attend the meeting in September due to
pre-existing external commitments.
Chair’s introduction
Dear fellow shareholders,
I am pleased to present the audit committee
report for the year ended 31 December 2025.
Financial reporting remains central to the
committee’s responsibilities – monitoring its
integrity, overseeing management’s control
procedures and evaluating their effectiveness
and working with internal and external
auditors to ensure that what you – our
shareholders – rely on in our reporting has
been appropriately challenged and reviewed.
This involves acting on behalf of the board and
co-ordinating input from other committees as
needed, including reporting and making
recommendations to the board.
In 2025 the committee maintained its
oversight of bp’s reporting processes, with
particular emphasis on advancing digital
transformation initiatives and monitoring their
implementation progress.
Among its many activities during the year, the
committee has monitored progress against
bp’s 2027 $4-5 billion structural cost reduction
target. In addition, the committee is
overseeing the mandatory external audit
tender, with the tender process expected to
conclude during 2026.
As the regulatory environment evolves, the
committee remains engaged with
management to oversee bp’s approach to new
reporting requirements, with particular focus
on the new UK Corporate Governance Code
2024, provision 29 readiness. The committee
also monitored management’s plans for the
implementation of financial and non-financial
reporting developments.
In September 2025 the committee visited bp’s
supply, trading and shipping business in
Canary Wharf, London. The visit included a tour
of the trading floors and business briefings,
with a particular focus on the energy and
commodities trading operations. Read more
on page 85. The committee continues to
engage with other stakeholders where
appropriate, including through regulatory
inspections when they occur.
On behalf of my colleagues on the committee,
I would like to extend my thanks for the
continued professional support and focus of
effort by management and our various
advisers during a year where bp delivered
strong performance in some areas but had
some challenges in others. We look forward to
continuing this journey through 2026.
Role of the committee
The committee monitors the effectiveness of
the group’s financial reporting, including ESG
and climate-related financial disclosures, as
well as systems of internal control and risk
management as allocated by the board. It also
monitors the integrity of the external and
internal audit processes.
This report describes how bp has approached
compliance with the provisions of the FRC’s
Audit Committees and the External Audit:
Minimum Standard.
Key responsibilities
A summary of the committee’s terms of
reference is on page 359 and the full
terms of reference can be viewed at
bp.com/governance.
Tushar Morzaria
Committee chair
6 March 2026
| | |
Financial expertise The board is satisfied that •Tushar Morzaria, the chair of the committee, has recent and relevant financial experience as required by the UK Corporate Governance Code and that he is competent in accounting and auditing in accordance with the FCA’s Disclosure Guidance and Transparency Rules. •The committee has an appropriate and experienced blend of commercial, financial and audit expertise to assess the issues it is required to address, as well as competence in the relevant sector in which bp operates. During 2025, Ian Tyler was appointed as a member of the committee, further strengthening the committee’s financial expertise. •As a US foreign private issuer, the committee meets the independence criteria provisions of Rule 10A-3 of the US Securities Exchange Act of 1934, and Tushar Morzaria can be regarded as an audit committee financial expert as defined in Item 16A of Form 20-F. | ||
| |
bp Annual Report and Form 20-F 2025 | 85 |
| ||||
Corporate governance | ||||
Activities during the year
Monitoring the integrity of financial
reporting and assurance
•Through monitoring and reviewing that bp’s
financial statements and formal
announcements relating to bp’s financial
performance are clear and appropriate, the
committee oversees the integrity of our
financial reporting.
•Management’s application of key
accounting policies and recommendations
on financial reporting judgements was
carefully considered, with the committee
concluding that these matters were
appropriately addressed in the financial
statements.
•The committee monitored progress and
reporting on cost savings.
Going concern, viability and fair,
balanced and understandable
considerations
The committee reviewed the company’s going
concern assumption and longer-term viability
statement. In determining and recommending
to the board that it was appropriate to adopt
the going concern basis of accounting and the
longer-term viability of the company, the
committee carefully considered and, where
appropriate, constructively challenged
relevant underlying assumptions and
supporting analysis.
The committee received an update from
management on the verification process for
the bp Annual Report and Form 20-F in
support of its recommendation to the board
that the report was fair, balanced and
understandable. These documents were
comprehensively reviewed with input from
subject matter experts and the external
auditors. The committee’s review included
consideration of bp’s non-financial disclosures
such as the Task Force on Climate-related
Financial Disclosures (TCFD) that are made in
compliance with the UK Listing Rules. TCFD
Maintaining resilience through
systems of internal control and
risk management
•The committee oversaw risk management
and internal control processes, routinely
reviewing and monitoring principal risks
allocated to it by the board through a
combination of business or function
reviews and focused engagement with
key stakeholders.
•Through a deep-dive update, the
committee reviewed supply, trading
and shipping business performance.
The session focused on the refined
products trading and shipping interface,
LNG and power benches as well as key and
emerging market, operational and
geopolitical risks.
•The committee reviewed the affordability of
proposed distributions, taking into account
factors such as whether sufficient
distributable reserves are available.
•In addition, the committee received:
–updates on the systems in place to assess
fraud risk and the controls in place to
manage and mitigate identified risks,
reflecting developments such as to the
UK’s Economic Crime and Corporate
Transparency Act.
–an update on compliance with new
business regulations, together with
additional briefings during the year on
technical accounting updates and
developing ESG disclosures. TCFD
•The committee remained focused on
regulatory developments, including
receiving updates on the consideration of
enhancements to bp’s risk management
and internal control framework as a result
of the UK Corporate Governance Code
2024, and received updates on
implementation progress.
Effectiveness of risk management and
systems of internal control
The committee reviewed and challenged
management on the effectiveness of the
system of internal control and agreed that it
did not require further action nor were there
any significant failings or weaknesses to
report. As part of this assessment the
committee considered internal audit’s annual
review of internal control and risk
management, together with an assessment of
it from management. The committee also
discussed internal controls and financial
reporting processes during the year,
challenging control gaps identified, root cause
analysis and remediation actions, and
reviewing progress towards addressing
deficiencies that had previously been
identified in relation to manual journal
controls. Tier II control gap reporting was
introduced at each scheduled meeting.
Further details on internal controls in place for
financial reporting can be found on page 360.
In addition, the committee received updates
on the evolution and enhancement of non-
financial reporting controls and assurance,
such as first and second line of defence
activities. TCFD
 | ||
Canary Wharf site visit During the audit committee’s tour in September of the supply, trading and shipping (ST&S) floors in Canary Wharf, London, the directors met internal stakeholders based there, hearing from colleagues in gas & power and refining & products trading. Image: Audit committee members at our Canary Wharf office, London, UK | ||
| | |
TCFD Information that supports TCFD Recommendations and Recommended Disclosures in relation to governance (see pages 41-44)
86 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Audit committee continued | ||||
Overseeing the relationship with
external and internal audit
•During the year, the FRC’s Audit Quality
Review (AQR) team selected Deloitte’s
audit of the Company’s Annual Report and
Accounts for the year ended 31 December
2024 as part of its annual inspection of
audit firms. The review was assessed as
‘limited improvements required’ with only
one other finding identified. The chair of the
committee received a full copy of the FRC’s
report, and discussed it with Deloitte. The
committee confirmed that there were no
significant areas for improvement
identified, no key findings within the report
and was satisfied that there is nothing
within the report which might have a
bearing on the audit appointment.
•On the recommendation of the committee,
the board will propose the reappointment
of Deloitte as the company’s external
auditor to shareholders at the 2026 annual
general meeting. The external auditor’s
independence and objectivity were
reviewed and monitored by the committee
using a combination of factors, including
assurances provided to it by the external
auditor, the level of non-audit fees, and the
timeline for lead audit partner rotation and
re-tender of audit services. The committee
concluded that it was satisfied with the
audit team’s effectiveness, service quality
and commitment, including that the
external auditor provides constructive
challenge to management. In support of
this, the committee received reports from
the external auditor that covered insights
from their audit work, actions taken to
address the FRC’s annual report on the
external auditor, and the inspection results
of the external auditor’s quality control
procedures. During 2025, following the
2024 audit, the external auditor undertook
an auditor effectiveness review. The
process comprised a series of interviews
with senior stakeholders within bp who
engage with the audit team on a regular
basis. Stakeholder feedback reflected a
positive view of the quality and
effectiveness of the audit. In addition,
the committee received reports from
management, which included a survey
seeking internal stakeholder feedback on
the external auditor’s performance and bp’s
commitment to the audit. The main
measurement criteria covered planning and
scope, robustness of audit, independence
and objectivity, quality of delivery, quality of
people and service, and value-added
advice.
•The committee met privately with the
external auditor during the year and, in
addition, reviewed, approved and
monitored progress against the external
audit plan, considering materiality levels,
audit risks, scoping changes, and
resourcing. The committee is satisfied that
the external auditor has full access to staff
and records. The committee continued to
monitor and review the effectiveness and
capabilities of the internal audit function.
This included, for example, reviewing and
approving the internal audit plan in the
context of bp’s principal risks. The
committee concluded that the function had
independent, unrestricted scope, access to
information, and sufficient resources to
fulfil its mandate. They met privately with
the SVP internal audit, discussed regular
updates on internal audit activities and
where appropriate challenged
management’s response and progress
made on the closure of findings.
Lead audit partner rotation and
re-tender of audit services
The external auditor must rotate the lead audit
partner every five years and other senior staff
every five to seven years.
The company complies with the Statutory
Audit Services for Large Companies Market
Investigation (Mandatory Use of Competitive
Tender Processes and Audit Committee
Responsibilities) Order 2014, which requires
bp to tender the audit at least every 10 years.
External audit services were last tendered in
2016, and the external auditor has been in that
role since 2018 (seven years). During the year
the committee agreed an approach, timeline
and selection criteria for a re-tendering of
audit services that is anticipated will be
completed by the end of 2026, for the
2028 audit.
Oversight of audit fees and
non-audit services
The committee reviewed and approved the
audit services fee and terms of engagement
for the external auditor while retaining
oversight of bp’s policy on non-audit services
and the review and approval of non-audit
services.
The total amount of audit and non-audit
fees paid to Deloitte for 2025 is set out in
Financial statements – Note 36. The
committee is satisfied that the audit fee is
appropriate in respect of the audit services
provided. The majority of non-audit fees relate
to work of an assurance nature.
The non-audit services policy safeguards audit
objectivity and independence through the
prohibition of non-audit tax services being
provided by the external auditor, the limitation
of audit-related work which falls within defined
categories, and by stating that the auditor may
not perform non-audit services that are
prohibited by the SEC, Public Company
Accounting Oversight Board (PCAOB),
International Auditing and Assurance
Standards Board (IAASB) or the FRC.
The external auditor is considered for
permitted non-audit services only when its
expertise and experience of bp are important.
Approvals for individual engagements of pre-
approved permitted services below certain
thresholds are delegated to the group
controller or the CFO. More information is
outlined in the principal accountant’s fees and
services on page 361.
bp Annual Report and Form 20-F 2025 | 87 |
| ||||
Corporate governance | ||||
Examples of how key accounting judgements and estimates were considered and addressed,
and how relevant accounting policies have been applied
| | |||||
Key accounting judgements and estimates | Audit committee activity | Conclusions/outcomes | ||||
Impact of climate change and the energy transition TCFD | ||||||
Climate change and the transition to a lower carbon economy may have significant impacts on the currently reported amounts of the group’s assets and liabilities and on similar assets and liabilities that may be recognized in the future. | •Reviewed management’s best estimate of oil and natural gas price assumptions for value-in- use impairment testing and investment appraisal. •Reviewed management’s determination that its best estimate of oil and natural gas prices is in line with a range of transition paths consistent with the goals of the Paris climate change agreement. | •Management’s revised best estimates of oil and natural gas prices are in line with a range of transition paths consistent with the goals of the Paris climate change agreement. •See Financial statements – Note 1 for more details on how bp applies carbon pricing in its impairment testing, sensitivity analyses estimating effects of changes in net revenue and changes in the expected timing of decommissioning. | ||||
Provisions | ||||||
The group holds provisions primarily for decommissioning, environmental remediation and litigation. The most significant provision is for the future decommissioning of oil and natural gas production facilities and pipelines. Estimation uncertainty exists as most of these events are many years in the future. Assumptions are made by bp in relation to cost estimation, settlement dates, technology, legal requirements and discount rates. There is also a risk that decommissioning obligations from previously divested assets revert to bp. | •Received briefings on decommissioning (including the process for managing the risk of decommissioning reversion), environmental, asbestos and litigation provisions. These included the requirements, governance and controls for the development and approval of cost estimates and provisions in the financial statements. •Reviewed and challenged the group’s discount rates for calculating provisions. | •Decommissioning provisions of $12.3 billion were recognized on the balance sheet at 31 December 2025. •The discount rate used by bp to determine the balance sheet obligation at the end of 2025 was a nominal rate of 4.5% based on long-dated US government bonds. The discount rate remains unchanged from the prior year. | ||||
Recoverability of asset carrying values | ||||||
Determination as to whether and how much an asset (including exploration intangibles), cash generating unit (CGU) or group of CGUs containing goodwill is impaired involves management judgement and estimates on uncertain matters such as future commodity prices, discount rates, production profiles, reserves and the impact of inflation on operating expenses. Judgement is required to determine whether it is appropriate to continue to carry intangible assets related to exploration costs on the balance sheet. | •Reviewed policy and guidelines for compliance with oil and gas reserves disclosure regulation, including the group’s reserves governance framework and controls. •Reviewed and challenged the group’s oil and gas price assumptions. •Reviewed and challenged the group’s discount rates for impairment testing purposes. •Impairment charges, reversals and ‘watch-list’ items were reviewed in the quarterly due diligence process. | •The group’s price assumption for Brent oil and for Henry Hub gas were updated as set out on page 20 and Financial statements – Note 1. •Sensitivity analyses estimating the effect of changes in net revenue and discount rate assumptions have been disclosed in Financial statements – Note 1. •Net impairment charges of $5.2 billion as disclosed in Financial statements – Note 4. •Exploration intangibles totalled $4.0 billion at 31 December 2025. | ||||
Taxation | ||||||
Computation of the group’s income tax expense and liability, the provisioning for potential tax liabilities and the level of deferred tax asset recognition are underpinned by management judgement and estimation of the amounts which could be payable. Judgement is also required when determining whether a particular tax is an income tax or another tax type. | •Received regular updates on the group’s tax risk exposures and deferred tax asset recognition. •Reviewed the judgements exercised over tax risk provisioning as part of its annual review of key provisions. | •Deferred tax assets of $4.3 billion were recognized on the balance sheet at 31 December 2025. •The calculation of tax risk provisions is consistent with IAS 37 and IFRIC 23. | ||||
Pensions | ||||||
Accounting for pensions and other post- employment benefits involves making estimates when measuring the group’s pension plan surpluses and deficits. These estimates require assumptions to be made about uncertain events, including discount rates, inflation and life expectancy. | •Reviewed and challenged the group’s assumptions used to determine the projected benefit obligation at the year end, including the discount rate, rate of inflation, salary growth and mortality levels. | •At 31 December 2025, surpluses of $7.8 billion and deficits of $4.8 billion were recognized on the balance sheet in relation to pensions and other post-employment benefits. •The method for determining the group’s assumptions remained largely unchanged from 2024. The values of these assumptions and a sensitivity analysis of the impact of possible changes on the benefit expense and obligation are provided in Financial Statements – Note 24. | ||||
| | |||||
88 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Audit committee continued | ||
Examples of how key accounting judgements and estimates were considered and addressed,
and how relevant accounting policies have been applied continued
| | |||||
Key accounting judgements and estimates | Audit committee activity | Conclusions/outcomes | ||||
Supplier finance arrangements | ||||||
The group’s trade payables include certain supplier finance arrangements that utilize letter of credit facilities and promissory notes. Judgement is required to assess trade payables subject to supplier financing arrangements to determine whether they should continue to be classified as trade payables and give rise to operating cash flows or finance debt and financing cash flows. | •Received a briefing on the group’s supplier finance arrangements. •Reviewed the group’s proposed enhanced disclosures in relation to Amendments to IAS 7 ‘Statement of Cash Flows’ and IFRS 7 ‘Financial Instruments: disclosures’ relating to supplier finance arrangements. | •bp had liabilities of $5.6 billion, $1.4 billion and $1.0 billion, respectively, in respect of letters of credit, promissory notes and reverse factoring arrangements that are presented within trade and other payables at 31 December 2025. •The disclosures required by the Amendments to IAS 7 ‘Statement of Cash Flows’ and IFRS 7 'Financial Instruments: disclosures’ relating to supplier finance arrangements are included in Financial Statements – Note 29. | ||||
Derivatives | ||||||
For its level 3 derivative financial instruments, bp estimates their fair values using internal models due to the absence of quoted market pricing or other observable, market-corroborated data. Judgement may be required to determine whether contracts to buy or sell commodities meet the definition of a derivative, in particular LNG contracts. | •Received a briefing on the group’s trading risks and reviewed the system of risk management and controls in place. •Reviewed the control process and risks relating to the trading business. •Received updates on accounting judgements on LNG contracts. | •bp has assets and liabilities of $20.1 billion and $18.2 billion, respectively, recognized on the balance sheet for level 3 derivative financial instruments at 31 December 2025, mainly relating to the activities of the supply, trading & shipping function. bp’s use of internal models to value certain of these contracts has been disclosed in Financial Statements – Note 1. •bp considers that contracts to buy or sell LNG do not meet the definition of a derivative under IFRS. | ||||
| | |||||
bp Annual Report and Form 20-F 2025 | 89 |
| ||||
Corporate governance | ||||
People, culture and governance committee | ||||
| | |
“2025 has been a busy year for the committee, with a strong focus on board succession.” Albert Manifold People, culture and governance committee chair | ||
| |
Meetings and attendance
The committee met five times during 2025.
The CEO and EVP people, culture &
communications regularly attend these
meetings.
Non-executive directors | Five scheduled meetings |
Albert Manifold: member (from September 2025); chair of the committee (from October 2025) | 1/1 |
Helge Lund: member (until September 2025); chair of the committee (until September 2025) | 4/4 |
Dame Amanda Blanc: member | 5/5 |
Dr Johannes Teyssen: member | 5/5 |
Hina Nagarajan: member | 5/5 |
Chair’s introduction
Dear shareholders,
I am pleased to present the people, culture
and governance committee report for the year
ended 31 December 2025, my first since being
appointed as board chair and as chair of the
committee on 1 October 2025.
2025 has been a particularly busy year for the
committee, with a strong focus on board
succession.
In support of the strategy reset in February
2025 and to fill current and anticipated
vacancies on the board, the committee
undertook a search process to identify new
board members who would bring the
additional skills and experience required as bp
embarked on its next chapter. The search
process resulted in three new non-executive
directors being appointed:
•Ian Tyler was appointed on 1 April 2025,
succeeding Tushar Morzaria as chair of the
remuneration committee with effect from
17 April 2025 and becoming a member of
the audit committee from 2 June 2025.
•Dave Hager joined the board on 2 June
2025 and became a member of the safety
and sustainability committee with effect
from 10 December 2025.
•Simon Henry joined the board on
1 September 2025.
In April 2025, Helge Lund informed the board
of his intention to step down as chair. Pamela
Daley informed the board in July 2025 that she
would also be standing down from the board.
During the year, Murray Auchincloss also
informed the board of his openness to step
down as CEO.
Comprehensive search processes were
undertaken by separate committees of the
board in connection with these decisions.
In turn, this led to my own appointment as a
non-executive director from 1 September
2025, succeeding Helge as chair of the board
and of this committee on 1 October 2025. It
also resulted in the appointment of Meg
O’Neill as CEO with effect from 1 April 2026,
with Carol Howle being appointed as interim
CEO with effect from 18 December 2025 until
Meg joins the board.
Further information on these search processes
is provided on page 90.
In addition to board succession matters,
during 2025, the committee continued its
focus on culture, reviewing feedback from the
workforce engagement sessions that took
place during the year and the results of the
annual and live employee pulse surveys to
gauge employee sentiment.
Role of the committee
The committee seeks to ensure that the
composition and structure of the board and
leadership team remain effective. It also
monitors the balance of skills, knowledge,
experience and diversity of the board. The
committee oversees the development of a
diverse pipeline for executive succession to
the board and leadership team through
continuous succession planning and
monitoring development plans for bp leaders
and beyond.
The committee tracks bp’s culture and its
alignment with our ‘Who we are’ culture frame,
and monitors sentiment of the workforce.
The process for the nomination, induction
and orderly succession of candidates for the
board, the leadership team and the company
secretary role are led by the committee,
as is the annual board and committee
performance review.
Key responsibilities
The committee’s full terms of reference can be
viewed at bp.com/governance.
Albert Manifold
Committee chair
6 March 2026
| | |
Diversity statistics and outcomes As at 31 December 2025, 46% of the board were women, three senior board positions were held by women and three directors identified as being from a minority ethnic background. For further details on board and leadership team diversity, in line with the UK Listing Rules, see page 126. As at 31 December 2025, senior management, defined as the leadership team (being the first layer of management below board level) and the company secretarya, and their direct reports, comprised 44% women (2024 50%) and 22% Black, Asian and other ethnic minority individuals (2024 29%). a As defined in the UK Corporate Governance Code 2024. | ||
| |
90 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
People, culture and governance committee continued | ||
Activities during the year
Succession planning
Chair and CEO succession
The board established two committees to lead
the selection processes for the company’s next
chair and CEO. The committee that led the search
process for the new chair was chaired by Dame
Amanda Blanc, joined by Melody Meyer, Hina
Nagarajan and Johannes Teyssen as members.
The committee that led the search process for
the CEO was chaired by Albert Manifold, joined
by Dame Amanda Blanc, Dave Hager, Karen
Richardson, and Ian Tyler as members.
Executive search consultants, Egon Zehndera,
were appointed to support both processes by
identifying suitable candidates to replace Helge
Lund and Murray Auchincloss against role
specifications agreed by the respective
committees and the board. Each role
specification set out the skills, experience,
diversity and knowledge required for each role,
including leadership capability, industry, sector,
safety and operational expertise.
Shortlisted candidates were invited to interviews
with members of each committee. The preferred
candidates for each role were then invited to
meet the full board.
The board appointed Albert Manifold as a non-
executive director and chair designate with
effect from 1 September 2025 and as chair of
the board and this committee with effect from
1 October 2025.
The board appointed Meg O’Neill as CEO with
effect from 1 April 2026. Carol Howle was
appointed as interim CEO with effect from 18
December 2025 until Meg joins the board. See
page 81 for further information on the decision-
making process and stakeholder considerations.
The board and committees
As part of the ongoing process to refresh the
board and to ensure it has the right balance of
skills, experience, and diversity needed to meet
the company’s current and future priorities, the
committee agreed the criteria for three new non-
executive roles. The criteria focused on
candidates primarily from the UK and US with
industry, sector, safety and operational
experience, including, in the case of the
remuneration committee leadership,
remuneration committee expertise and the ability
to lead complex remuneration considerations for
a complex global company such as bp.
Suitable candidates for each role were identified
against the agreed role profiles with support
from Egon Zehndera and shortlisted candidates
were invited to interview with members of
the committee.
This process resulted in the board approving the
committee’s recommendations to appoint
Ian Tyler, Dave Hager, and Simon Henry as new
non-executive directors.
During the year, the membership of the board
committees was also reviewed. As a result, Ian
Tyler was appointed as chair of the remuneration
committee with effect from 17 April 2025 and as a
member of the audit committee from 17 April
2025. Dave Hager was appointed as a member of
the safety and sustainability committee with
effect from 10 December 2025.
bp’s leadership team
The committee oversees development plans for
bp’s senior leaders and emerging talent and their
alignment with executive succession planning
over various timescales. Development plans
identify the desired breadth and depth of
experience and roles required to bolster the skills
of individuals with executive potential.
Diversity
Better decision making and outcomes are
achieved when people with differences of
opinion and with different backgrounds come
together with a common ambition. The
committee periodically reviews the board’s
diversity, equity and inclusion (DE&I) policy.
The board’s DE&I policy applies to the board and
its committees, and complements bp’s wider
diversity policies, the group’s values, code of
conduct and sustainability frame. It includes
gender and ethnicity representation targets for
the board that are aligned with the UK Listing
Rules. Read more at bp.com/governance.
Oversight of culture and the voice of
the workforce
The committee oversees employee engagement,
leading and lagging indicators of culture, and
how culture is being embedded. This includes
monitoring feedback from the workforce
engagement programme (WFEP) and private
sessions with bp’s SVP, ethics and compliance
(E&C), who has accountability to, and direct
channels of communication with, the committee.
The committee is responsible for approving the
appointment and termination of the SVP, E&C
and reviews and recommends their remuneration
to the remuneration committee.
The WFEP continued during 2025 with directors
engaging with employees across multiple
regions and from different disciplines on topics
including leadership and culture, safety (including
retail safety), transformation, and remuneration.
Insights from these sessions are collated and
shared with the board, strengthening its
consideration of workforce views in board
discussions and the decisions it ultimately takes.
The committee continues to consider that the
WFEP is the most appropriate mechanism for
workforce engagement, given the activities and
structure of bp. Read more on page 80.
Board performance
The externally facilitated board performance
review in 2024 highlighted the continuing
importance of succession planning to drive the
delivery of the reset strategy. Building on the
outputs from the 2024 review, the board
appointed three new non-executive directors and
introduced enhanced performance reporting by
management during the year. This reporting was
supplemented by a programme of insight
sessions, providing the board with in-depth
briefings from leaders of the businesses with the
greatest impact on the delivery of strategy.
The CEO’s performance review is conducted by
the chair, with input from the senior independent
director. Given the short tenure of Albert
Manifold, a performance review of the chair was
not undertaken in 2025. This process is usually
led by the senior independent director.
Helge Lund’s decision to step down from the
board in April 2025 and the appointment in
September 2025 of his successor offered an
opportunity, alongside the board’s established
performance-evaluation processes, for the
continuing directors to reflect on the roles and
performance of the board and its committees.
This in turn influenced the skills, experience and
leadership credentials that were sought from the
new board chair and, then also, the new CEO.
Ultimately, having appointed Albert Manifold as
chair from 1 October 2025 and Meg O’Neill as
new CEO from 1 April 2026, the board concluded
that the process of the 2025 performance review
for the board and its committees had been
comprehensively undertaken. In view of this, a
standalone supplementary performance review
was therefore not warranted. Additionally, and
since his appointment to the role, the chair held a
series of one-to-one meetings with each non-
executive director to discuss their reflections on
the board’s performance and that of its
committees and individual board members.
Overall, the insights gathered from the 2025
performance review will inform the future needs
and roles of the board and its respective
committees, how they operate and the optimal
composition of the board over the longer term.
Among the changes already in motion as a result
of this review process, members of the
leadership team routinely join board meetings to
discuss safety, operational and financial
performance, major projects and delivery of the
four primary targets set out in the reset strategy.
The introduction of a reporting dashboard during
the year strengthened this enhanced board
oversight of performance at a more granular
level, by business group and against key metrics.
This is being supplemented with additional
scheduled board time for in-depth discussions
on performance and portfolio composition.
aThe committee engaged Egon Zehnder in support of search activity for new board candidates. Egon Zehnder does not have any connection with the company or individual directors, save that
Egon Zehnder provides advice and support on bp’s executive development programme.
bp Annual Report and Form 20-F 2025 | 91 |
| ||||
Corporate governance | ||||
Directors’ remuneration report | ||||
| | |
“2025 was a year of strong underlying financial and operational performance and we have made meaningful progress towards the strategic priorities announced in February 2025.” Ian Tyler Remuneration committee chair | ||
| |
Meetings and attendance
The chair and the chief executive officer (CEO)
are standing attendees, except for matters
relating to their own remuneration. The CEO is
consulted on the remuneration of the chief
financial officer (CFO) and other members of
the leadership team, and receives input from
the committee on remuneration across the
wider workforce. Both the CEO and CFO are
consulted on matters relating to the group’s
performance and the metrics adopted for
each performance cycle.
bp’s EVP people, culture & communications,
SVP reward, external advisors and other
executives may attend where necessary. The
committee consults other board committees
on the group’s performance and on issues
relating to the exercise of judgement or
discretion as necessary.
The committee met nine times during 2025.
Meeting attendance can be found below.
Non-executive directors | Seven scheduled meetings | Two ad hoc meetings |
Ian Tyler: chair of the committeea | 4/4 | 2/2 |
Tushar Morzaria: membera | 7/7 | 2/2 |
Dame Amanda Blanc: member | 7/7 | 2/2 |
Pamela Daley: memberb | 2/4 | 0/0 |
Melody Meyer: member | 7/7 | 2/2 |
aIan Tyler was appointed as remuneration committee chair
from the conclusion of the 2025 AGM. Tushar Morzaria
stepped down as interim remuneration committee chair
from this date.
bPamela Daley stepped down as a non-executive director
and member of the remuneration committee on 7 July 2025.
Role of the committee
The role of the committee is to determine and
recommend to the board the remuneration
policy and to set chair, executive director and
leadership team remuneration. In determining
the policy, the committee takes into account
various factors, including wider workforce
remuneration, structures and alignment of
reward with performance, thus promoting the
long-term success of the company. The
committee also reviews workforce
remuneration and monitors related policies,
satisfying itself that incentives and rewards
are aligned with bp’s goals and culture.
Key responsibilities
A summary of the committee’s terms of
reference is on page 359 and the full terms
can be reviewed at bp.com/governance.
Key areas of focus in 2025
•Workforce engagement – engaged with the
wider workforce on performance, reward
and wellbeing. This included holding a
workforce engagement programme
session in July 2025, where selected
employees were invited to discuss bp’s
approach to reward and employee
engagement.
•Remuneration outcomes – agreed the
outcomes of incentive awards for executive
directors, including reviewing performance
‘in the round’ and determining whether
discretion should be exercised. Monitored
in-flight progress of equity and bonus
awards.
•Performance measures – discussed and
agreed the performance measures for the
2025 annual and long-term performance
scorecards to ensure alignment with
bp’s strategy. This included reflecting on
our sustainability measures and seeking
input from the safety and sustainability
committee. TCFD
•Framework on fatalities – reflected on the
impact of fatalities on annual bonus
outcomes and the framework that was
introduced in 2024 to help guide decisions
going forward.
•Change in leadership – set the
remuneration terms for the interim CEO
and incoming CEO. Agreed the exit
arrangements for the outgoing CEO.
•Merit-based reviews – reviewed pay for
performance arrangements for the
leadership population in line with bp’s
reward principles.
| | ||
Contents | |||
Remuneration at a glance | 94 | ||
Engaging with our workforce | 96 | ||
Executive directors’ pay for 2025 | 98 | ||
2025 annual bonus outcome | 99 | ||
2023-25 performance share plan outcome | 102 | ||
Policy implementation for 2026 | 106 | ||
Stewardship and executive director interests | 111 | ||
Chair and non-executive director interests | 112 | ||
2026 directors’ remuneration policy | 118 | ||
| |
TCFD Information that supports TCFD Recommendations and Recommended Disclosures in relation to governance (see pages 41-44)
92 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
Chair’s introduction
Dear shareholders,
I am pleased to present the directors’
remuneration report for the year ended
31 December 2025.
This is my first report as chair of the
remuneration committee, having taken on the
role from Tushar Morzaria on 17 April 2025.
Having agreed to step into the role on an interim
basis, I would like to thank Tushar for his
leadership of the committee during this period.
The committee remains focused on ensuring our
remuneration policy supports the delivery of
bp’s strategic priorities, aligning executive
reward outcomes with sustainable long‑term
value creation for our shareholders. Constructive
dialogue with our shareholders has been an
important part of this process, and we are
grateful for the insights shared during 2025.
We are asking shareholders to vote on two
remuneration resolutions at bp’s 2026 AGM:
•Our remuneration report, which presents
remuneration outcomes for 2025 and how
we intend to apply the policy in 2026.
•Our remuneration policy (the policy), which
outlines the framework that will apply to our
executive directors, non-executive directors
and chair of the board.
Business performance
While performance over the three-year
performance period for the EDIP was mixed,
2025 was a year of strong underlying financial
and operational performance. bp delivered
operating cash flow« of $24.5 billion,
underpinned by disciplined capital allocation
and efficiency with a 10% reduction in capital
expenditure« compared with 2024.
Operationally, plant reliability« and refining
availability« both exceeded 96%, reaching their
highest levels on record.
We also made meaningful progress towards the
strategic priorities set out in our reset strategy
announced in February 2025. We established
four primary targets through to the end of 2027:
growing cash flow, improving returns,
reducing costs and strengthening the balance
sheet. We remain on track to deliver against
these objectives.
During the year, we agreed the sale of a 65%
shareholding in Castrol, which we expect to
generate net proceeds of approximately $6
billion, and completed the sale of our US onshore
wind business. We also delivered $2.0 billion of
structural cost reductions«, strengthening our
financial position and supporting continued
delivery into 2026.
Incentive outcomes
2025 annual bonus
The scorecard for this cycle consisted of five
measures; tier 1 and tier 2 process safety
events«(15% of award), operated carbon
emissions (15%), reliability and availability (15%),
modified free cash flow« (30%) and structural
cost reductions (25%).
Safety and sustainability
Within the annual bonus scorecard, safety
performance is measured against the number of
tier 1 and tier 2 process safety events each year
(7.5% weighting each).
For 2025, we achieved a combined outcome
of 87.5% of maximum for this measure. We
reported five tier 1 process safety events during
the year resulting in an outcome between target
and maximum. Tier 2 performance was strong
with a significant reduction in the number of
events compared to prior year (22 events in 2025
compared to 35 events in 2024), resulting in a
maximum outcome for this measure. This
reflects our continued focus on process and
personal safety.
However, we are deeply saddened by the four
workforce fatalities during the year – three at
TravelCenters of America and one at Thorntons.
Further details of these fatalities are set out on
page 55.
In assessing the impact of the fatalities during
the year, the committee was mindful of the total
number of fatalities across the group and, with
input from the safety and sustainability
committee, reflected on the circumstances of
each fatality. However, in line with our
framework, the three fatalities at TravelCenters
of America have been dealt with predominately
at a local level – see page 101 for further details.
In respect of the group score, it was agreed that
that a downward adjustment was justified when
reflecting on the fatality at Thorntons and
broader safety performance, and the entire
bonus score was reduced by 4 points for all
participants.
Sustainability performance was assessed
against operated carbon emissions, which
covers Scope 1 and 2 emissions based on bp’s
net zero operations aim. Our performance was
strong and we delivered 1.6MteCO2e ahead of
our scorecard target, which resulted in an
outcome of 73% of maximum.
Financial and operational
Under our financial and operational categories,
bp delivered strong performance across all
measures.
From an operational perspective, our
performance was assessed against both plant
reliability and refining availability. We achieved
an outcome of 96.2% which resulted in an above
target outcome.
Our financial performance was assessed against
modified free cash flow and structural cost
reduction. Modified free cash flow was $12.4
billion, which resulted in the maximum outcome,
reflecting our continued focus on strong capital
discipline during 2025.
In line with our remuneration policy, the targets
for modified free cash flow are adjusted for the
actual commodity price environment to reflect
underlying performance.
This was the first year that structural cost
reductions were included in our scorecard.
We delivered $2.0 billion of cost reductions
which resulted in performance between
target and maximum.
Overall result
The formulaic annual bonus outcome, reflecting
safety, operational and financial performance
was therefore 1.63 out of a maximum of 2 (81.5%
of maximum).
As described previously, the committee
exercised its discretion to account for the
fatalities during 2025 and reduced the formulaic
outcome by 4 points to 1.59 out of 2 (79.5% of
maximum).
2023-25 performance shares
The 2023-25 performance share scorecard was
measured against relative TSR (20% weighting),
return on average capital employed
(ROACE)« (20%), adjusted EBIDA per share
compound annual growth rate (CAGR)« (20%),
sustainable emissions reductions (15%) and
strategic progress (25%).
rTSR
bp placed fifth in the comparator group,
resulting in nil vesting for this measure.
Financials
Financial performance was assessed against our
returns and earnings measures and performed
below the targets set at the start of the
performance period, achieving nil vesting. The
2023-25 average ROACE was 15.4% and adjusted
EBIDA per share CAGR was 9.8%.
Sustainability performance
We delivered Scope 1 and 2 greenhouse gas
emissions reductions of 12.9% against our 2019
baseline. This resulted in an outcome between
threshold and target, with vesting of 22% of
maximum.
Strategic progress
Strategic progress was assessed using a
combination of quantitative assessment (via
financial KPIs) and qualitative judgement against
the three strategic pillars set in 2023.
As set out in the 2024 directors’ remuneration
report, the committee also considered the
strategic changes announced in 2023 and the
Capital Markets Update in February 2025 when
scoring performance against the original criteria.
bp Annual Report and Form 20-F 2025 | 93 |
| ||||
Corporate governance | ||||
We provide a detailed view of the committee’s
review of strategic progress on pages 103-105.
Having considered the above, the committee
determined that bp made strong progress over
the three-year period and an outcome of 80% of
maximum was felt appropriate for this measure.
Overall results
Overall, performance share vesting for the
2023-25 cycle was 23.3% of maximum. The
committee believes that, given a large
component of the strategic progress measures
comprise financial KPIs, this outcome properly
reflects achievement over the period and
therefore has not applied any further discretion.
Board changes
In December 2025, Murray Auchincloss stepped
down as CEO, and from the board, by mutual
agreement. Remuneration decisions relating to
Murray have been made in accordance with our
shareholder-approved policy and contractual
obligations, with full details provided on page 113.
Carol Howle assumed the role of interim CEO on
18 December 2025, having previously served as
EVP supply, trading & shipping. She will be
succeeded by Meg O’Neill whose appointment
as CEO takes effect from 1 April 2026.
Incoming CEO: Meg O’Neill
The committee has determined the
remuneration package for the incoming CEO in
line with our shareholder-approved
remuneration policy, considering Meg’s
experience, external market benchmarks,
shareholder expectations and broader operating
environment.
Meg will receive a base salary of £1.6 million on
appointment. This has been set at 2.5% above
the salary level of her predecessor when taking
into account the workforce salary increase that
he would have been eligible for in April 2026.
In reaching this decision, the committee
considered Meg’s proven track record as a high
performing CEO within the sector and the
experience and leadership credentials she will
bring to lead bp through the next phase of its
transformation journey.
Meg will receive standard benefits for an
executive director, as provided for in the
remuneration policy. These include a pension
allowance of 20% of base salary aligned with the
wider UK workforce. She will also participate in
bp’s annual incentive plans. There will be no
change to the operation of our minimum
shareholding requirement.
In line with our policy, Meg will receive relocation
support to facilitate her move from Australia to
the UK. She will also receive compensation for
incentive awards forfeited on leaving her
previous employer. Further details of Meg’s
joining arrangements are set out on page 108.
Interim CEO: Carol Howle
Upon assuming the role of interim CEO on
18 December 2025, Carol’s salary was set at
£1.508 million aligned with the level of her
predecessor. She will not be entitled to a salary
increase in respect of 2026 and she will receive
our standard executive benefits and pension
provisions.
For 2026, Carol will be eligible to receive awards
in line with our policy. She is also subject to bp’s
in- and post-employment minimum
shareholding requirement from the date of
appointment.
Looking ahead to 2026
Policy review
Our current remuneration policy was last
approved in 2023 with 94% shareholder support.
In line with the normal three-year cycle, we will
be seeking approval for a revised policy at the
2026 AGM.
Over the past year, the committee has
undertaken a detailed review of each element of
the existing policy, assessing its effectiveness in
incentivizing and rewarding the delivery of bp’s
strategy. We concluded that the current
framework continues to allow us to set
stretching, relevant and motivating short- and
long-term performance measures, that are
clearly aligned to the strategic priorities we
expect leadership to deliver.
Accordingly, beyond a small number of updates
to ensure continued alignment with evolving
market practice, we are not proposing any
significant changes at this time. We consulted
with our top 30 shareholders, representing over
40% of our register, who were generally
supportive of this approach for the 2026 AGM.
However, the committee is mindful that bp is
progressing through the next stage of its
transformation and therefore it is possible that
further changes to our remuneration approach
may be needed. Within this context, it may be
that we will ask shareholders for approval of an
updated policy ahead of the next required
triennial vote. The remuneration committee will
engage with bp’s major shareholders on any
such proposals in advance.
Annual pay review
Kate Thomson’s base pay will increase by 3.5%,
in line with the average increase in the UK.
Adjustments in other jurisdictions will vary by
local conditions.
Review of performance measures
As part of the broader policy review, the
committee reflected on the performance
measures used in our incentive scorecards and
considered whether they remain aligned to the
reset strategy announced in February 2025.
2026 annual bonus
To support the stretching goals within bp’s reset
strategy, the committee believes focus should
be on sustained financial performance over the
next year, with a particular lens on cash
generation and cost reduction.
The scorecard categories and weightings have
therefore been simplified, placing financial
performance at the forefront (65% of award),
supported by strong and sustained operational
delivery (20%) and a continued focus on safety
(15%). The underlying measures within the
categories remain broadly unchanged from prior
years and our framework on fatalities will
continue to apply.
Progress towards bp’s net zero operations
aim will continue to be rewarded through our
performance share plans rather than the
annual bonus.
2026-28 performance shares
In line with the simplified structure of the annual
bonus, the performance share plan has also
been streamlined to ensure focus on the
measures most critical to delivering our
reset strategy.
For 2026-28, the scorecard will focus on the
following key measures: shareholder returns
(30% of award), cash generation (25%), ROACE
(25%) and a continued focus on reducing Scope 1
and 2 operational emissions in line with bp’s
aim to reach net zero operations by 2050, or
sooner (20%).
For the shareholder returns measure, the peer
group has been reviewed for alignment with
the reset strategy. The 2026-28 group will be
simplified to five companies, focusing on the
oil super majors who are considered our
closest peers.
We have also broadened the underpin for our
performance share awards. Going forward, the
committee will take into consideration overall
safety performance as well as ongoing progress
towards a strong and resilient balance sheet
when assessing final outcomes, providing
further alignment with bp’s long-term priorities.
Conclusion
2025 was a year of strong progress. Taking all
circumstances into account, the committee
believes that the overall remuneration outcomes
are appropriate.
The committee remains committed to
maintaining an open and transparent
dialogue on remuneration matters with our
shareholders. I would like to thank you for
another year of constructive engagement
and your continued support ahead of the
2026 AGM.
Ian Tyler
Chair of the remuneration committee
6 March 2026
94 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
Key performance highlights in 2025 | ||||||||
$24.5bn | $14.5bn | 2.3mmboed | •Refining availability of 96.3% and plant reliability of 96.1% were highest on record. •7 major projects started up, 5 ahead of schedule. •$11bn completed or signed divestments, including $6bn Castrol transaction. •On track against primary targets set out in Capital Markets Update (February 2025). | |||||
operating cash flow« improved cash conversion | capital expenditure« 10% YoY reduction | upstream« production exceeded plan | ||||||
Total remuneration in 2025 | ||||||||
1. Salary and benefits  | Single figure Chief executive officer (outgoing) 35% Fixed 65% Variable pay | Single figure Chief financial officer 36% Fixed 64% Variable pay | ||||||
2. Cash allowance  in lieu of pension | ||||||||
3. Annual bonus  | £5.3m | £3.0m | ||||||
4. Performance shares  | ||||||||
Pay outcomes in 2025 | ||||||||||
Annual bonus (2025 ACB) |  | | Performance shares (2023-25 EDIP) | | | |||||
81.5% of maximum formulaic outcome | 23.3% of maximum formulaic outcome | |||||||||
 | | | | |||||||
 | ||||||||||
 | | |||||||||
79.5% of maximum formulaic outcome actual outcome after exercise of discretion | ||||||||||
Safety and sustainability Operations Financials   | Strategic progress Sustainability  rTSR Financials | |||||||||
 | |
Application of discretion
The committee may exercise discretion in determining the outcomes of the annual bonus and performance shares, reflecting the broader stakeholder
experience during the performance period. For 2025, downward discretion was applied and the 2025 ACB has been reduced by 4 points. Further details
of the application of discretion have been set out on page 101.
Alignment with shareholders | ||||||
 Share ownership aligns the interests of executive directors with those of shareholders. | ||||||
Murray Auchincloss (outgoing CEO) | 5.9 times salary, 2,104,355 shares | |||||
Kate Thomson (CFO) | 2.9 times salary, 550,831 shares | |||||
Actual Policy requirement  | ||||||
bp Annual Report and Form 20-F 2025 | 95 |
| ||||
Corporate governance | ||||
Application of remuneration policy for 2026 | ||||||||||
Set out below is an illustration of how the remuneration policy will be implemented for 2026.
2026 | 2027 | 2028 | 2029 | 2030 | 2031 | 2032 | |||||||
Fixed pay (salary, pension and benefits) | •Upon appointment, the incoming CEO’s salary will be £1.6 million. •For 2026, the CFO’s salary will increase by 3.5%, from £864k to £894k, in line with the wider workforce average. | ||||||||||||
Annual bonusa | •CEO max opportunity: 225% of salary. •CFO max opportunity: 225% of salary. •For 2026, the scorecard has been simplified to focus on safety, operational and financial performance (see below). | ||||||||||||
Performance shares | •CEO max opportunity: 500% of salary. •CFO max opportunity: 450% of salary. •Similarly to the annual bonus, the 2026-28 scorecard has been simplified with an increased focus on emissions reductions, financial and shareholder return measures (see below). | ||||||||||||
Shareholding requirement | •In-employment and post-employment guidelines will continue to apply. |
1-year
performance period
3-year
deferral period
3-year
performance period
3-year
holding period
aHalf the bonus is paid in cash, and half is deferred into bp shares for three years until ‘minimum shareholding requirement’ is met. At this point, 67% is paid in cash and 33% is deferred into
bp shares.
Alignment of 2026 variable remuneration with strategy | |||||
Each year, the committee sets a remuneration framework for executive directors that supports and incentivizes the execution of our
strategy. For 2026, the scorecards have been simplified to reflect our business priorities, supported by strong safety and operational
performance, with financial measures at the forefront. Further details on the rationale for their inclusion can be found on pages 109-110.
 | Strategy (upstream, downstream, transition) | Primary targets | KPIs | |||
Safety (15%) | ||||||
Tier 1 and tier 2 process safety events« | ò | ò | ||||
Financials and operations (85%) | ||||||
bp-operated reliability« and availability« | ò | ò | ||||
Structural cost reductions« ($bn) | ò | ò | ò | |||
Modified free cash flow« ($bn) | ò | |||||
 | ||||||
Cumulative reduction % in operated carbon emissions (20%) | ò | |||||
Adjusted free cash flow CAGR« (25%) | ò | ò | ||||
ROACE« (25%) | ò | ò | ||||
Relative TSR (30%) | ò |
| Strategy and primary targets page 8, KPIs page 14 |
96 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
Engaging with our workforce
We believe that our people are the key to bp’s success and our approach to performance and reward should be fair and consistent across the
organization. As a committee, we spend considerable time on matters relating to performance and remuneration arrangements across the
wider workforce.
| | |||||
Element of remuneration | All employees | Executive directors | ||||
 | Salary is the basis for a competitive total reward package for all employees. We conduct an annual salary review for all non-unionized employees. In setting pay budgets, we assess how employee pay is currently positioned relative to market rates, wage inflation, forecasts and business context. | The salaries of our executive directors are reviewed annually. The review will take into account the same factors considered for the wider workforce. Salary increases for executive directors will typically be at or below the workforce rate, other than in specific circumstances. | ||||
 | We operate different pension plans by location and for those parts of our business where market practice is markedly different, e.g. our retail business. For our population of non-retail employees in the UK, we provide a flexible cash benefits allowance of 20% of salary. The benefits available are aligned with competitive market practice in our different jurisdictions. | Executive directors receive a cash allowance in lieu of pension aligned with the wider workforce (currently 20% of salary). Other than the provisions of car, security and tax preparation related benefits, benefit packages are broadly aligned with those of other employees in the UK. | ||||
 | More than half of the eligible workforce participate in an annual cash bonus plan that multiplies a grade-based target bonus amount by a bp performance factor derived from the bonus scorecards. From 2025, business scorecards have been introduced for certain parts of bp. Individual performance is assessed through a performance rating which may result in an uplift or decrease to bonus outcomes. We operate different bonus plans for those parts of our business where market practice is markedly different. | The annual bonus for the executive directors is linked to the same bp performance factor as for the wider workforce. Executive directors are not entitled to a bonus uplift linked to individual performance. For executive directors, a portion of any award is deferred into shares for three years. The deferral rate depends on whether the executive director has met their minimum shareholding requirement. | ||||
 | We operate share plans with three-year vesting for all our senior leaders. Opportunity varies across two broad tiers: group leaders (approximately 300) and senior-level leaders (approximately 4,000). | Executive directors are eligible for performance share awards, which are subject to stretching performance targets over a three-year period. An additional three-year post-vesting holding period applies for executive directors. | ||||
| |
Other elements of pay
Recognition
energize!, our global recognition platform, is open to all employees for
peer-to-peer recognition. The scheme aims to celebrate employees’
contributions, highlight behaviours vital to our success and drive
performance. In 2025, a total of 39,900 employees received
energize! awards.
We also operate a spot bonus programme, where individuals or teams
can be nominated to receive a one-off cash award to recognize their
achievements or particular initiatives. Senior leaders actively participate
in the programmes, often by recognizing the contributions of their team
members. In 2025, 6,600 employees were awarded spot bonuses in
recognition of their contributions.
Focus@bp
focus@bp is our internal platform that helps support performance
development. The platform enables employees to set dynamic goals,
have regular check-ins, give and receive meaningful feedback and grow
skills to enable our teams to develop and deliver.
We believe that performance matters, both individually and collectively,
and development is key in helping to improve our performance as
a business. focus@bp forms the basis of discussions relating to
development or progression and the achievement of goals is factored
in when making decisions in relation to an individual’s remuneration.
All-employee share plan
bp operates an award-winning global ShareMatch programme which is
available to over 18,000 employees in 46 countries. This plan offers our
employees the opportunity to invest and share in bp’s success,
fostering a culture of shared ownership. At the end of 2025, the
participation rate in the scheme was 64% of eligible employees.
bp Annual Report and Form 20-F 2025 | 97 |
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Corporate governance | ||||
Workforce highlights in 2025
Driving our performance culture
Following the strategy reset announced in February 2025, bp is
undertaking a broad transformation to become a more competitive,
focused and value-driven organization.
As part of this, we reviewed and updated our approach to performance
management to make it clearer, more consistent and better aligned
with bp’s strategic goals. This evolution represents a culture shift and
an operational change, influencing how our employees support bp in
delivering its ambitions.
To date, four changes have been introduced:
•Aligned goals: Common goals are now set at an entity or sub-entity
level, giving employees a clearer line of sight to organizational
priorities and how their work contributes to bp’s strategy.
•Business scorecards: Business-level scorecards have been
introduced alongside the group scorecard, strengthening the link
between business performance and reward outcomes.
•Annual review cycle: The performance cycle now incorporates
quarterly check-ins, alongside our existing mid-year and year-end
conversations, to support more regular, meaningful conversations.
•Individual ratings: A simple rating system has been introduced to
assess individual performance over the year, with outcomes directly
impacting reward decisions.
Together, these changes will help embed a stronger performance
culture that supports our strategy.
Supporting employees during organizational transformation
Our approach to workforce health and wellbeing is centred around the
needs of our people, combining globally available services that can be
tailored to meet specific local needs. All employees have access to our
global digital health and wellbeing hub, Thrive@bp.
During bp’s transformation programme, we have offered
comprehensive mental health support to employees which has been
developed through listening forums and employee feedback.
Recognizing the pivotal role of our leaders, we have also offered
tailored resources to help them support their teams and look after
their own mental health.
Support has included on-site counselling, check-ins with counsellors
and advice from psychologists, coaching and access to other
specialists through webinars. We offered bespoke mental health
training on ‘thriving’ through change, which has been completed more
than 4,000 times and included a leader-specific module.
Healthy minds
Our bespoke mental health education programme, Healthy Minds,
provides elearning modules for all bp employees.
Since its launch in 2024, more than 14,000 modules have been
completed and more than 75% of our senior leaders have engaged in
the programme.
 | ||
Workforce engagement Receiving feedback from our employees remains an important way in which the board stays connected to the broader employee experience. On remuneration specifically, as part of the board-led workforce engagement programme (WEFP), a dedicated session was held in July 2025 to hear employee views on changes to performance management, including the introduction of business scorecards and performance ratings. The discussion provided valuable insight into how these changes are being received across the organization. Image: Retail colleague at our Oak Tree service station in Surrey, UK | ||
| | |
 | ||
Shareholder views The committee is committed to maintaining an open dialogue with our shareholders. During the year, we engaged with our top 30 shareholders (representing over 40% of our shareholder register). The insights shared during this engagement play an important role in shaping our decisions. We value the feedback received, helping us to understand evolving expectations on reward matters. Image: Trading and shipping colleagues at our Canary Wharf office in London, UK | ||
| | |
98 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
Executive directors’ pay for 2025
Single figure table – executive directors (audited)a
Carol Howleb thousand 2025 | Murray Auchinclossc thousand 2025 | Kate Thomson thousand 2025 | Murray Auchincloss thousand 2024 | Kate Thomson thousand 2024 | ||
 | £57 | £1,434 | £845 | £1,450 | £731 | |
 | £2 | £138 | £82 | £132 | £67 | |
 | £11 | £287 | £169 | £290 | £146 | |
 | £83 | £2,594 | £1,545 | £734 | £370 | |
 | £733 | £854 | £387 | £2,573 | £697 | |
Total remuneration | £886 | £5,307 | £3,029 | £5,179 | £2,011 | |
Total fixed remuneration | £70 | £1,859 | £1,096 | £1,872 | £944 | |
Total variable remuneration | £816 | £3,448 | £1,932 | £3,307 | £1,067 |
aDue to rounding, the totals may not agree exactly with the sum of the component parts.
bCarol Howle was appointed interim CEO on 18 December 2025, having previously been EVP supply, trading & shipping. The amounts disclosed reflect her service in the year as an
executive director.
cMurray Auchincloss stepped down as CEO on 18 December 2025, having been appointed as permanent CEO on 17 January 2024. The amounts disclosed reflect his service in year as an
executive director.
dIn line with the 2023 policy, annual bonus is subject to deferral into shares for three years at a rate of 33% or 50%, depending on whether an individual has met their minimum shareholding
requirement. See page 100 for further detail on the approach taken for the 2025 annual bonus.
e For Carol Howle, a portion of the annual bonus relates to performance within her capacity as EVP supply, trading & shipping. The pro-rated value of this award amounts to £36k of the figure
disclosed, of which half is to be delivered in cash and half is to be deferred into bp shares for three years. The remuneration committee has determined that the measures and targets linked to
this portion of the award are commercially sensitive and therefore have not been disclosed. The remaining portion of the annual bonus relates to group performance, as set out on page 99, and
in line with the terms of that award will not be subject to deferral requirements in respect of 2025.
fFor Murray Auchincloss, the value of the performance share award has been calculated using the average share price in the last three months of 2025 of £4.40 and includes notional dividends
accrued up to 13 February 2026. For 2024, the performance shares have been restated to reflect the share price on the date of vesting of £3.60 and actual dividends received.
gFor Carol Howle and Kate Thomson, the value of the performance share award relates to their roles prior to their appointment to the board. For 2023-25, the awards have been calculated using
the average share price in the last three months of 2025 of £4.40 and includes notional dividends up to 13 February 2026. For 2023-25, performance share awards below board had a different
scorecard to executive directors, which resulted in an outcome of 52.8% of maximum. For 2024, the performance shares have been restated to reflect the share price on the date of vesting of
£4.63 and actual dividends received.
Overview of single figure outcomes
Salary
In respect of 2025, Murray Auchincloss received a salary increase in line with the wider workforce and his base pay was set at £1.508 million. Kate
Thomson received a salary increase of 8%, reflecting her development in role and leadership of the finance function, which increased her base pay
to £864,000. These changes were effective from the 2025 AGM on 17 April 2025.
Carol Howle was appointed as interim CEO on 18 December 2025. From the date of appointment, her base pay was set in line with that of her
predecessor at £1.508 million.
Benefits
Executive directors received car-related benefits, coverage of tax return preparation, security assistance, insurance and medical cover.
Cash allowance in lieu of pension
In line with the 2023 directors’ remuneration policy, executive directors receive a cash allowance in lieu of pension of 20% of salary. This is in line
with the wider workforce in the UK.
bp Annual Report and Form 20-F 2025 | 99 |
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Corporate governance | ||||
Annual bonus
For 2025, the committee assessed performance against a bonus scorecard of measures across three categories: safety and sustainability,
operations and financials. These measures were aligned with our strategy and investor proposition as set out at the beginning of the year.
2025 annual bonus scorecard and outcome
Annual bonus scorecard | ||||||||||||||||
Threshold (0) | Target (1) | Maximum (2) | ||||||||||||||
Categories | Measures | Weighting | Outcomes | |||||||||||||
Safety and sustainability (30%) | Tier 1 process safety events« | 9 | 6 | 4 | 7.5% | 0.11 | ||||||||||
Actual: 5 | ||||||||||||||||
Tier 2 process safety events« | 39 | 30 | 27 | 7.5% | 0.15 | |||||||||||
Actual: 22 | ||||||||||||||||
Operated carbon emissions (MtCO2e) | 38.9 | 35.5 | 32.1 | 15% | 0.22 | |||||||||||
Actual: 33.9a | ||||||||||||||||
Operations (15%) | bp-operated reliability« and availability« | 95.1% | 95.9% | 96.7% | 15% | 0.21 | ||||||||||
Actual: 96.2% | ||||||||||||||||
Financials (55%) | Modified free cash flow« ($bn) | 6.5 | 8.5 | 10.5 | 30% | 0.60 | ||||||||||
Actual: 12.4 | ||||||||||||||||
Structural cost reductions«($bn) | 0.6 | 1.4 | 3 | 25% | 0.34 | |||||||||||
Actual: 2 | ||||||||||||||||
Formulaic outcome | 1.63 out of 2.00 | |||||||||||||||
Formulaic scorecard outcome 1.63 out of 2.00 | Application of framework on fatalities 4 point reduction (see page 101) | Overriding committee judgement No adjustment | 1.59 out of 2.00 | |||||||||||||
aThe actual operated carbon emissions outcomes used for bonus calculation purposes (33.9MteCO2e) is based on the agreed portfolio scope at beginning of the plan year and differs from the
figure reported elsewhere in the bp Annual Report and Form 20-F 2025 (34.3MteCO2e) due to portfolio changes.
100 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
Summary of performance
Safety performance, as measured by tier 1 and 2 process safety
events«, was strong with the mechanical outcome achieving between
target and maximum performance. The total number of events is less
than prior year, with 27 tier 1 and tier 2 events in 2025 (38 in 2024). This
year-on-year improvement underpins the importance of our process
safety improvement plans and the delivery of the actions they outline.
Operated carbon emissions performance is measured against the
anticipated emissions based on the business plan and activity set
identified at the beginning of the year. For 2025, operated carbon
emissions of 33.9MtCO2e (footnote a) resulted in an outcome between
target and maximum. This holds underlying operated emissions broadly
flat compared to the 2024 result, after accounting for previously
identified portfolio growth and full year impact of project start-ups.
The most significant contributions to emissions performance of
1.6MtCO2e below 2025 plan came from improved management of
abnormal plant conditions in the Asia Pacific region; continuation of
previously implemented efficiencies across refining sites; and flaring
reductions and operational stability in the Azerbaijan, Georgia and
Türkiye region.
Emission reduction projects totalling 0.27MtCO2e implemented by our
business in 2025 included: Archaea Energy renewable natural gas
switching to low carbon power; bpx energy’s central distribution
project, which enabled decommissioning of legacy natural gas-driven
equipment; focus on flare system and practices improvements at
Tangguh, and synchronization of power and power management
strategy implementation in Trinidad and Tobago.
Reliability and availability is a combined measure of bp-operated
refining availability« and bp-operated plant reliability« with a
performance outcome of 96.2% – between target and maximum.
Refining availability and plant reliability both strengthened year-on-
year, with refining availability of 96.3% (94.3% in 2024) and plant
reliability of 96.1% (95.2% in 2024).
Financial performance, as measured by modified free cash flow« and
structural cost reduction«, was strong. bp generated modified free
cash flow of $12.4 billion, which resulted in the maximum outcome.
Similarly, steady progress was made against our structural cost
reduction measure, delivering $2.0 billion of reductions which was
between target and maximum.
Overall outcome
The formulaic score for the 2025 annual bonus was 1.63 out of 2 (81.5%
of maximum).
The committee considered bp’s framework on fatalities when reflecting
on the formulaic outcome. Sadly, there were four workforce fatalities
during the year. Full details on the application of the framework have
been provided on page 101.
Having considered the above, alongside a holistic review of
performance, the committee determined that the formulaic score
should be reduced by 4 points to 1.59 out of 2 (79.5% of maximum).
a The actual operated carbon emissions outcomes used for bonus calculation purposes (33.9MteCO2e) is based on the agreed portfolio scope at beginning of the plan year and differs from the
figure reported elsewhere in the bp Annual Report and Form 20-F 2025 (34.3MteCO2e) due to portfolio changes.
Approach to deferral
In relation to the policy on deferral requirements, the committee
reviewed the executive directors’ shareholdings during the year to
assess if the minimum shareholding requirement had been met.
As at 18 December 2025, the date Murray Auchincloss stepped down
from the board, his shareholding represented 5.87x salary. This is above
the minimum shareholding requirement for the CEO of 5x salary and his
pro-rated 2025 award will therefore be subject to a deferral rate of 33%.
While Kate Thomson has made strong progress towards her minimum
shareholding requirement since her appointment in 2024, her
shareholding represented 2.94x salary (as at 13 February 2026). This is
below the minimum shareholding requirement for the CFO of 4.5x
salary and her 2025 award will therefore be subject to a deferral rate
of 50%.
As Carol Howle was only appointed interim CEO on 18 December 2025,
the committee agreed that her 2025 award would be calculated based
on her salary and award opportunity level prior to appointment. Her
bonus award in respect of group performance will therefore not be
subject to any deferral requirements.
bp Annual Report and Form 20-F 2025 | 101 |
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Corporate governance | ||||
bp’s framework on fatalities
We are working towards our goal of eliminating workplace
fatalities. In 2024 we implemented a new framework on
fatalities. This framework, developed in consultation with
shareholders and the safety and sustainability committee
(S&SC), links safety performance directly to the bonus
scorecard.
Full details of our framework on fatalities can be found in the
2023 directors’ remuneration report.
| bp.com/investors |
Framework on fatalities | ||||
1. Operations (15%) | ||||
2. Safety and sustainability (30%)  | ||||
3. Financial (55%) | ||||
Safety and sustainability committee | ||||
Influence | Foreseen | Nature of deficiency | ||
Remuneration committee | ||||
Collective responsibility | Meaningful adjustment | Judgement within a frame | ||
Treatment of new assets | ||||
| | | | |||
What happened during the year? At bp, safety remains our top priority and we are deeply committed to ensuring that our operations are carried out safely every single day. Safety performance in 2025 During 2025, we recorded five tier 1 events, a slight increase compared with the prior year. Tier 1 events represent our more serious incidents and it remains essential that we stay focused on reducing these incidents. Encouragingly, the number of tier 2 events fell significantly, with 22 events compared to 35 in 2024. However, there were sadly four workforce fatalities during the year – three at our recently acquired TravelCenters of America facilities and one at Thorntons. | How was the framework applied? The committee made reference to the framework in determining the impact of fatalities on the 2025 bonus outcome. Fatality at Thorntons In April 2025, a contractor had a fatal incident while repairing one of our facilities. Since then, a thorough investigation has been undertaken to understand the underlying causes and to ensure that appropriate measures are put in place to prevent similar occurrences in the future. The committee has reflected on this event, receiving input from the S&SC, and the reward impact is summarized below. Fatalities at TravelCenters of America When bp acquires a new asset, it determines whether an initial transition period (typically 1 to 3 years) is required to allow for full embedding of bp OMS systems. During this period, assets are not consolidated into bp group safety systems and are managed using local performance tracking and scorecards. This is consistent with the approach taken under the fatality framework for the ACB. For TravelCenters of America, it was agreed that this acquisition should be treated as an excluded new asset for three performance years (i.e. to the end of 2025) – reflecting the scale and complexity of the business, with ~20,000 employees and an inherently different risk profile to bp’s core operations. The fatalities have, however, been considered at a local level and detail of the reward impact is set out below. Further details of these fatalities are set out on page 55. | |||||
| | | | |||
Process safety events over past five years | |||||
80 | |||||
60 | |||||
40 | |||||
20 | |||||
0 | |||||
2021 | 2022 | 2023 | 2024 | 2025 | |
Tier 1 process safety events Tier 2 process safety events | |||||
| | | | |||
What was the outcome? In line with the framework, the committee reflected on the fatality at Thorntons. While the S&SC confirmed that the incident was unforeseeable and not indicative of a systemic issue, we believe that any loss of life is unacceptable and have decided to reduce the outcome by 4 points for all participants. Regarding the fatalities in TravelCenters of America, a more material reduction has been made to the local bonus plan. The S&SC has also advised that corrective action has been undertaken to prevent similar occurrences in the future. The committee is mindful of the need to ensure that the fatality framework continues to support our determination to eliminate workforce fatalities. During 2026, the committee will reflect on this and make any necessary changes to the framework. | 4 point reduction resulting in a final bonus score of 1.59 out of 2 for all participants of the group ACB. | |||||
| | | | |||
102 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
2023-25 performance share plan scorecard and outcome
2023-25 performance shares were granted under the executive directors’ incentive plan (EDIP). The scorecard for this cycle consists of sustainable
emissions reductions (15% weighting), relative total shareholder return (rTSR) (20% weighting), return on average capital employed (ROACE)« (20%
weighting), adjusted EBIDA per share CAGR« (20% weighting) and strategic progress (25% weighting).
2023-25 performance share plan scorecard (audited)
Share plan scorecard | ||||||||||||||||
Threshold | Maximum | |||||||||||||||
Categories | Measures | Weighting | Outcomes | |||||||||||||
Net zero (15%) | Net zero across entire bp operations by 2050 (Scope 1 + 2) | 12% | 16% | 15% | 3.3% | |||||||||||
Actual: 12.9% | ||||||||||||||||
rTSR (20%) | rTSR | Fourth | First | 20% | 0% | |||||||||||
Actual: Fifth | ||||||||||||||||
Financials (40%) | ROACE (average 2023-25) | 20.2% | 22.2% | 20% | 0% | |||||||||||
Actual: 15.4% | ||||||||||||||||
Adjusted EBIDA per share CAGR | 12.5% | 14.5% | 20% | 0% | ||||||||||||
Actual: 9.8% | ||||||||||||||||
Strategic progress (25%) | Deliver value through resilient hydrocarbon business | 25% | 20% | |||||||||||||
Qualitative and quantitative assessment by the committee, see pages 103-105. | ||||||||||||||||
Demonstrate track record, scale and value in low carbon energy | ||||||||||||||||
Accelerate growth in convenience and mobility | ||||||||||||||||
Assessed outcome | 23.3% out of 100% | |||||||||||||||
Assessed outcome 23.3% out of 100% | Underpin: Committee review of absolute shareholder returns, long-term safety and environmental performance, low carbon and climate change considerations. No adjustment | Final vesting after committee judgement 23.3% out of 100% | ||||||||||||||
bp Annual Report and Form 20-F 2025 | 103 |
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Corporate governance | ||||
Sustainability performance
To the end of 2025, actions or interventions that have led to ongoing
reductions in Scope 1 and 2 emissions have totalled 12.9% relative to the
baseline year of 2019. The main contributions during the performance
period have come from centralization and electrification of bpx energy
processing infrastructure, refineries switching to low carbon power,
and a focus on flare system and practices improvements across
production sites.
Relative TSR
During the performance period, bp’s rTSR performance placed it fifth
out of eight in the comparator group which resulted in nil vesting.
Financials
Performance of ROACE and adjusted EBIDA per share CAGR, at 15.4%
and 9.8% respectively, were below the targets set at the start of the
performance period and achieved nil vesting.
As part of the review of outcomes, the committee considers the impact
of the external environment with respect to ROACE outcomes, and in
respect of adjusted EBIDA per share CAGR the committee reviews
share buyback activity outside of plan during the performance period.
It determined that, in line with past practice, no further adjustments
should be made to either of these elements for the 2023-25 cycle.
Strategic progress
Overview of strategic progress (2023-25)
Assessing performance against this measure has been challenging
as it spans a three-year period that has been marked by significant
strategic change.
The criteria, including financial KPIs, set at the start of the performance
period (2023) were intended to measure delivery against the three
strategic pillars at that time: resilient hydrocarbons, low carbon energy
and convenience and mobility. However, as our strategy has continued
to evolve, these original objectives no longer fully reflect the strategic
performance achieved over the period.
The committee has therefore assessed performance against the
original criteria, including the financial KPIs, whilst also considering the
broader strategic milestones delivered during the period. In particular,
progress against the reset strategy outlined as part of the Capital
Markets Update in February 2025 has been taken into account.
In summary:
| Pillar 1: Resilient hydrocarbons Delivered strong operational and financial performance over the period with 2025 refining availability« and plant reliability« both exceeding 96%, delivering unit production costs in line with target and production above our plan. We brought 17 major projects« across oil, gas and refining online and had significant exploration success, including Bumerangue in Brazil. | |
| |
| Pillar 2: Low carbon energy Since setting targets in 2023, bp's low carbon energy business has undergone significant transformation, leading to the retirement of the original objectives. The business has delivered a robust set of results within the context of the reset strategy and shifting priorities focused on value. | |
| |
| Pillar 3: Convenience and mobility Strong operational growth, with 21% convenience gross margin CAGR 2023-25 (inclusive) including the acquisition of TravelCenters of America in 2023. With some of the measures being retired under the reset strategy, financial performance has remained strong with modified free cash flow for 2025 above the plan we set in 2023, underpinned by significant year-on-year growth in operating cash flow«. | |
| |
| | |
Overall performance: Considering delivery against both the original pillars and progress against our reset strategy to date, an outcome of 80% of maximum was deemed appropriate for 2023-25. | ||
| |
104 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
Key ò On track ò Strong progress ò Improvement required
1. Deliver value through a resilient hydrocarbon business KPIs (KPIs as set in 2023) | ||||||
Unit production cost ò Average unit production cost over the period was $6.08/boe with 2025 delivered at $6.28/boe, in line with our 2025 target, representing strong progress on this target while making value-based portfolio choices. | Plant reliability ò 2025 plant reliability of 96.1% was a record high, reflecting our focus on operational delivery and supporting our production exceeding plans. | Refining availability ò Refining availability was high in 2025 with all four quarters above 96% and a full year average of 96.3%, reflecting strong progress on this KPI, with 2024 impacted by the plant-wide power outage at Whiting. | ||||
2023 | 2024 | 2025 | 2025 target | 2023 | 2024 | 2025 | 2025 target | 2023 | 2024 | 2025 | 2025 target | ||||
$5.8/boe | $6.2/boe | $6.3/boe | $6.0/boe | 95.0% | 95.2% | 96.1% | 96.0% | 96.1% | 94.3% | 96.3% | 96.0% |
Overview •Continued to high-grade our portfolio and drive higher margins. •Delivered 17 major projects (15 in oil and gas, two in refining) including seven in 2025 of which five were ahead of schedule. •Continued to high-grade our portfolio, including growing bpx energy production by 43% and being selected to help governments develop their resources. •Exceptional exploration year with 12 discoveries in 2025, including in the Gulf of America, Namibia and Brazil. •The hydrocarbon business performed well against financial measures. | ||
2. Demonstrate track record, scale and value in low carbon energy KPIs (KPIs as set in 2023) | ||||
Developed renewables to FID« ò Growth has been driven by Lightsource bp. Tracking below target as the solar sector has been significantly impacted by higher interest rates, inflation and supply chain constraints. As a result, the portfolio has been high-graded based on value, managed pace of development and decapitalization. No outcome for 2025 following bp’s reset strategy and subsequent retirement of our strategic pillars and associated targets. | Renewables pipeline« ò Growth has been driven by Lightsource bp as well as successful offshore wind bids, which now sit within the JERA Nex bp joint venture. The hydrogen and CCS portfolio has been prioritized based on deliverability, value and returns – with four sanctioned projects in development. Similar to developed renewables to FID, no outcome is shown for 2025 following bp’s reset strategy and subsequent retirement of measures. | |||
2023 | 2024 | 2025 | 2025 target | 2023 | 2024 | 2025 | 2025 target | |||
6.2GW | 8.2GW | n/a | 20GW | 58.3GW | 60.6GW | n/a | n/a |
Overview •The low carbon energy business underwent a significant portfolio reset and rationalization – driving down costs and improving capital efficiency to support the group’s modified free cash flow delivery. •JERA and bp completed the formation of JERA Nex bp in August 2025, establishing a top-tier global offshore wind joint venture. The sale of bp’s onshore wind business to LS Power completed in December 2025. •Adjusted EBITDA over the period was lower than expected, reflecting a challenging US solar market and increased ramp up and origination spend in hydrogen, CCS and offshore wind to progress previous growth targets. 2025 reflects effective delivery of portfolio high-grading and the decapitalization strategy. | ||
3. Accelerate growth in convenience and mobility KPIs (KPIs as set in 2023) | ||||||
Convenience margin growth« ò The acquisition of TravelCenters of America completed in 2023 underpinning 21% convenience gross margin CAGR over the period. | Strategic convenience sites« ò As the target was retired at the start of 2025, in line with our reset strategy, the measure was not tracked during 2025. However, performance was close to target at end of 2024. | Castrol performance (revenue) ò Castrol had a strong 2025, and now has 10 quarters of consecutive year-on-year earnings growth. Castrol continued strategic growth initiatives, including expansion of its thermal management portfolio beyond cooling fluids into integrated full-service solutions. | ||||
2023 | 2024 | 2025 | 2025 target | 2023 | 2024 | 2025 | 2025 target | 2023 | 2024 | 2025 | 2025 targeta | ||||
60% | 17% | (5)% | 10% | 2,850 | 2,950 | n/a | 3,000 | $7.0bn | $6.9bn | $7.1bn | n/a |
Overview •Despite the 2025 strategy reset focussing on downstream, the convenience and mobility business made strong progress against the objectives set back in 2023 — providing the platform to grow the business. •Convenience and mobility delivered adjusted EBITDA below plan, reflecting the more challenging market backdrop and refocused capital frame. However, modified free cash flow was ahead of target. | ||
aThe Castrol performance KPI was retired during the performance period and performance has therefore been considered ‘in the round’ including reference to earnings and volume growth.
bp Annual Report and Form 20-F 2025 | 105 |
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Corporate governance | ||||
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Overall assessment | ||||||
As set out in the 2024 directors’ remuneration report, the committee has assessed performance against the original three strategic pillars within the context of bp’s reset strategy: | ||||||
In February 2025, bp introduced a fundamentally reset strategy as part of its Capital Markets Update (CMU). The strategy focuses on strengthening performance by growing free cash flow, returns and building long‑term shareholder value, supported by four primary targets to be delivered by the end of 2027. For all the primary targets, performance is currently on track or ahead of plan with strong underlying financial performance during 2025. | Growing free cash flow ò CMU target: >20% CAGR (2024-27) •Adjusted free cash flow« was increased by c.55% in 2025, based on CMU price assumptions, which is ahead of plan. Reducing net debt ò CMU target: $14-$18bn (end of 2027) Net debt« at the end of 2025 was $22.2 billion, which is $800 million lower than at the end of 2024. During 2025, $1.2 billion of perpetual hybrid bonds were redeemed and bp made $1.2 billion of pre-tax payments against our Gulf of America settlement liability. | Structural cost reductions« ò CMU target: $4-$5bn (end of 2027) Since the start of the programme, bp has delivered $2.8 billion of the cost reduction target. Having reflected on the outcome of the strategic review to divest Castrol, the CMU target was increased (to $5.5-$6.5 billion). Generating higher returns ò CMU target: >16% ROACE« (end of 2027) ROACE was around 14%, based on CMU price assumptions, an increase from around 12% in 2024. | ||||
Conclusion Taking into account delivery against the targets set under the original pillars, alongside bp’s evolving strategic context and the progress made on our reset strategy to date, the committee concluded that performance on this measure supports vesting of the strategic progress measure at 80% of maximum. Strategic progress remains a key measure for outstanding awards and the committee will continue to apply judgement in the context of broader strategic delivery. | ||||||
| | |||||
Other vesting considerations
Along with the results from the scorecard measures, the committee considers an ‘underpin’ to the formulaic outcome in order to determine the
final vesting percentage. The underpin broadens our performance assessment, allowing us to consider vesting outcomes with overall alignment to
absolute shareholder returns, environmental and safety factors and progress in matters relating to low carbon and climate change. Where relevant,
we take input from the safety and sustainability committee and the audit committee to deepen and enhance our perspective.
Having considered the above, the committee concluded that the vesting outcome was suitably reflective of the company’s underlying performance
and the experience of shareholders overall through the performance period. The committee agreed it was not necessary to apply discretion to the
formulaic outcome and therefore approved vesting of 23.3% for the 2023-25 EDIP award. This decision yields the outcome shown in the table
below for the former CEO. The scorecard detail is shown on page 102.
The committee was satisfied that the remuneration policy had operated as intended and therefore no further changes were required. No malus and
clawback provisions were applied in respect of the annual bonus or EDIP awards in the previous financial year.
2023-25 performance share plan outcome (audited)
Shares awarded | Unvested shares following application of performance factor | Value of unvested shares following application of performance factora | Impact of share price changea | |
Carol Howleb | 137,610 | 166,594 | £733,014 | (£56,642) |
Murray Auchincloss | 717,958 | 194,018 | £853,679 | (£93,129) |
Kate Thomsonb | 72,650 | 87,951 | £386,984 | (£29,903) |
aThese values reflect the impact of the change in share price since grant related to the number of shares which are no longer subject to performance conditions, including dividend equivalents
accrued at 13 February 2026. The face values of these awards were calculated using a market price of ordinary shares at close on the dates of award, as follows: £4.88 on 2 May 2023 and £4.74 on
7 June 2023 respectively. The average share price during Q4 2025 was £4.40. The amount reported as 2025 income in the single figure is therefore £0.854 million for Murray, £0.733 million for
Carol and £0.387 million for Kate.
bCarol Howle’s and Kate Thomson’s awards were made under the below board performance share plan where grants are made at 50% of maximum, rather than at 100% of maximum as for the
EDIP. For 2023-25, performance share awards below board had a different scorecard to executive directors, which resulted in an outcome of 52.8% of maximum.
106 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
Policy implementation for 2026
The table below shows how the remuneration policy, being submitted to shareholders for approval at the 2026 annual general meeting on 23 April
2026, will be implemented. As outlined in the chair’s statement, the 2023 policy has been broadly rolled forward for 2026. Full details of the policy
being submitted for shareholder approval can be found on pages 118-125.
Policy feature | 2026 implementation | |
 | ||
To provide fixed remuneration to reflect the scale and complexity of both the business and the role, and to be competitive with the external market. When setting salaries, the committee considers practice in other energy majors, as well as European and US companies of a similar size, geographic spread and business dynamic to bp. Percentage increases for executive directors will not exceed that for the wider workforce, other than in specific circumstances identified by the committee (e.g. in response to a substantial change in responsibilities). Salaries are normally set in the home currency of the executive director and are reviewed annually. They may be reviewed at other times where appropriate. | •The budgeted increase to our UK salaried staff effective from 1 April 2026, our annual salary review date, will be 3.5%. •For 2026, the executive director’s salaries will be: •Meg O’Neill: £1,600,000 (from appointment) •Carol Howle: £1,508,000 (from appointment) •Kate Thomson: £894,000 (3.5% increase, effective 2026 AGM) | |
 | ||
Executive directors normally participate in the company retirement plans that operate in their home country. New appointees from within the bp group retain previously accrued benefits related to service prior to appointment as executive director. For their service as a director, cash allowance in lieu of pension will be up to 20% of base salary. For future appointments, the committee will carefully review any retirement benefits to be granted to a new director, taking account of retirement policies across the wider group and any arrangements currently in place. | •Executive directors’ cash allowance in lieu of pension is 20% of base pay (in line with the wider workforce). •Prior to their appointment as executive directors, Carol and Kate received a UK deferred pension. No further pension is accrued under either plan. •Benefits will remain unchanged for 2026 and include car-related provisions, security assistance, assistance with tax preparation, insurance and medical cover. | |
 | ||
Bonus is measured against an annual scorecard. The committee holds discretion to choose the specific measures and the relative weightings adopted in the annual scorecard, to reflect the annual plan as agreed with the board. Numeric scales are set for each measure, to score outcomes relative to targets. A scorecard outcome of 1.0 reflects the target outcome and 2.0 is the maximum outcome. Target bonus is 112.5% of salary, and maximum bonus is 225% of salary. Half the bonus is paid in cash, and half is deferred into bp shares for three years up until the ’minimum shareholding requirement’ is met. At this point, 67% is paid in cash and 33% is paid in bp shares. Dividends (or equivalents, including the value of any reinvestment) may accrue in respect of any deferred shares. Awards are subject to operationally robust and effective malus and clawback provisions as described below. | •For 2026, our scorecard will be assessed against the following categories: safety (15%), operations (20%) and financials (65%). •See page 109 for further details on measures for the 2026 annual bonus. •The framework on fatalities, which helps guide decisions on adjustments to the bonus outcome in relation to fatalities, will continue to be applied. Further detail has been provided on page 101. |
bp Annual Report and Form 20-F 2025 | 107 |
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Corporate governance | ||||
Policy feature | 2026 implementation | |
 | ||
Performance shares are granted with a three-year performance period, measured against a scorecard. The committee holds discretion to choose the specific measures and the relative weightings adopted in the scorecard, to ensure they are focused on the near-term priorities for delivering the bp strategy in the interests of shareholders. Annual grants are 500% of salary for the CEO, and 450% of salary for any other executive director. Awards will vest in proportion to the outcomes measured through the performance scorecard, subject to any adjustment by the committee, and will be subject to a three-year post-vesting holding period. Awards are subject to operationally robust and effective malus and clawback provisions as described below. | •For our 2026-28 cycle, the scorecard categories will be rTSR (30%), financials (50%) and environmental, social and governance (20%). •See page 109 for further details on measures for the 2026-28 EDIP. •The award will be subject to an underpin that takes into consideration overall safety performance and ongoing progress towards a strong and resilient balance sheet over the performance period. •The 2026-28 awards will be granted based on the average closing share price of each calendar day in the 90-day period ending on the date of bp’s 2026 AGM. | |
 | ||
CEO to build a shareholding of at least five times salary, and other executive directors four and a half times salary, within five years of appointment. Executive directors are required to maintain that level for at least two years after they cease to be a director. | ||
 | ||
Operationally robust and effective malus and clawback provisions apply to our incentive awards. The following events can trigger either malus or clawback: a material safety or environmental failure; material reputational damage; an incorrect award outcome due to miscalculation or incorrect information; a restatement due to financial reporting failure or misstatement of audited results; material misconduct; or fraud. In addition, malus may be triggered by the following events: material downturn in performance of the group or any part of it and conduct leading to significant losses; or other exceptional circumstances that the committee considers similar in nature. The period during which malus and/or clawback may be applied is generally three years from vesting or, if longer, until the expiry of any retention or holding period applicable to an award, which is considered a sufficient period for any issues that might give rise to malus or clawback to be identified. | ||
 | ||
The committee has discretion to adjust performance measures and weightings, and to revise the peer group for the rTSR measure. This discretion allows appropriate realignment, throughout the policy term, for changes in the annual plan and for the anticipated evolution of the low carbon business environment. The committee also holds discretion in determining the outcomes for annual bonus and performance shares, allowing it to take broad views on alignment with shareholder experience, environmental, societal and other relevant considerations e.g. portfolio changes. | ||
108 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
Incoming CEO’s arrangements
As announced on 17 December 2025, Meg O’Neill will join bp as CEO on 1 April 2026. Her salary has been set at £1,600,000 and she will not be
eligible to receive a salary increase until the conclusion of the wider annual pay review process in April 2027. She is eligible for a cash allowance in
lieu of pension which will be 20% of salary in line with the wider workforce and her other benefits will be in line with policy.
Regarding her incentive awards, Meg’s opportunity levels will align with the maximums outlined in the table above. For 2026, both her annual bonus
and performance share award will be pro-rated to reflect the portion of the year she serves as an executive director. The awards will be subject to
the deferral requirements, holding periods and malus and clawback provisions outlined under our policy.
Relocation support
Meg will be relocating from Australia where her previous employer was headquartered and she will receive relocation assistance to support her
move. This includes – among other elements – immigration support, temporary accommodation for up to six months and shipping. The cost of the
relocation assistance is subject to clawback if Meg was to resign within two years of appointment to the role. Limited repatriation support will be
provided at the end of Meg’s tenure.
Buy-out awards
On appointment, Meg will be granted cash and share-based awards to replace remuneration foregone when leaving her previous employer. In line
with the policy, the committee took into account the nature, timing and value of the awards being forfeited when determining the structure and
size of the buy-out awards offered. The committee is satisfied that the buy-out awards are consistent with the policy and reflect like-for-like
replacement, noting the complexities in Meg’s foregone awards such as a mix of standard performance awards, non-performance awards, and pre-
grant performance awards, each with overlapping five-year vesting periods. The buy-out awards will take three forms:
•Cash awards: To replace the 2025 annual bonus, 2026 annual bonus (pro-rated to 31 March 2026), and share awards where the full vesting period
would have elapsed or would substantially have elapsed prior to Meg joining. The value of the annual bonus and performance shares will be based on
her previous employer’s actual performance where possible. For foregone performance and restricted shares due to vest in the first half of 2026, the
value will be based on the 30-day average share price of her previous employer up to the vesting date. Full details of the value of this cash award will
be disclosed in the 2026 directors’ remuneration report.
•Restricted share awards: To replace the forfeited restricted share awards (outstanding and to be granted in respect of 2025 pre-grant performance).
This buy-out award will also cover performance share awards due to vest in 2027 and 2028 where in-flight performance has been valued at 50% of
maximum. The awards will be aligned with the vesting schedules of Meg’s foregone awards and have an expected value of £8.3 million.
•Performance share awards: To replace the forfeited performance share awards due to vest in 2029, 2030 and 2031 following their respective five-
year periods. These awards will be subject to bp’s relative TSR performance, with the start of the performance period being 1 April 2026. The awards
will be aligned with the vesting schedules of her foregone awards and have an expected value of £1.8 million.
| | |||
Buy-out awards | Estimated valuea | Vesting date | ||
Cash awards | ||||
Replacement cash award | £1.7mb | Paid upon joiningc | ||
Restricted share awards | ||||
Tranche 1 | £0.5m | April 2027 | ||
Tranche 2 | £1.0m | May 2027 | ||
Tranche 3 | £0.4m | March 2028 | ||
Tranche 4 | £1.5m | April 2028 | ||
Tranche 5 | £0.9m | March 2029 | ||
Tranche 6 | £0.8m | April 2029 | ||
Tranche 7 | £1.8m | March 2030 | ||
Tranche 8 | £1.4m | March 2031 | ||
Performance share awards (expected value, subject to TSR performance) | ||||
Tranche 1 | £0.4m | April 2029 | ||
Tranche 2 | £0.7m | March 2030 | ||
Tranche 3 | £0.7m | March 2031 | ||
a Estimated value is based on an illustrative share price of £12.50 for Woodside Energy and exchange rate of 1:0.5 (AUD:GBP). Performance share awards have been shown at target (i.e. 50% of max). b Estimated value of the 2026 annual bonus (pro-rated to 31 March 2026) not included as value is currently unknown. c Or, if later, following the date the award from the previous employer would have been paid. | ||||
| | |||
Where awards are being replaced with shares, this will be calculated using the 90-day average of bp’s and Woodside Energy’s share prices, and
foreign exchange rate, prior to 1 April 2026.
A significant proportion of the buy-outs will be delivered in shares (over 85%), aligning Meg with shareholders from appointment and representing a
value equivalent to 6.3x of salary over a 5-year period. In line with the policy, Meg will be expected to retain shares vesting from share awards
(including buy-outs) until her shareholding requirement of 5x salary has been met.
bp Annual Report and Form 20-F 2025 | 109 |
| ||||
Corporate governance | ||||
Measures for the 2026 annual bonus
For 2026, the scorecard has been simplified and performance will now be assessed against four measures across three categories: safety (15%),
operations (20%) and financials (65%). This change reflects our continued focus on delivering sustained financial performance, supported by strong
safety and operational outcomes.
As part of this simplification, the emissions measure has been removed from the short‑term scorecard. To maintain appropriate balance, the
weighting of emissions within the long‑term incentive award has been increased from 15% to 20% (see below). Our ambition to reach net zero by
2050 remains unchanged, but we believe that progress towards this long‑term objective is more appropriately evaluated through our performance
share award rather than the annual bonus.
Across the remaining categories, the underlying measures remain unchanged from prior year. For safety, however, we will revert to assessing
performance on a combined tier 1 and tier 2 basis. In recent years, the number of tier 1 process safety events has continued to decline, which is a
positive trajectory to report. However, the number of events has made it increasingly difficult to set robust and meaningful standalone targets for
tier 1 performance and it is no longer practicable to assess performance independently.
Importantly, the framework on fatalities will continue to apply to the 2026 annual bonus and will be considered at year-end if a fatality occurs
during the year. The targets are commercially sensitive and will be disclosed in the 2026 directors’ remuneration report.
 | | ||||||||
Safety 15% | Operations 20% | Financials 65% | |||||||
Measures include | Weighting | Measures include | Weighting | Measures include | Weighting | ||||
Tier 1 and tier 2 process safety events« | 15% | bp-operated reliability and availability« | 20% | Modified free cash flowa« | 35% | ||||
Structural cost reduction« | 30% | ||||||||
| | ||||||||
Measures for the 2026-28 performance shares (EDIP)
Provided below is a summary of the measures we have chosen for the 2026-28 performance share plan. The number of measures has been
reduced, with the scorecard now focused on shareholder returns, financial delivery and progress against our external emissions targets.
For relative TSR, the peer group has been reviewed to ensure alignment with the reset strategy. The committee has agreed to reduce the number
of comparator companies, concentrating on the oil super majors who represent our closest and most strategically aligned peers. In light of the
reduced peer group, the committee reviewed the approach to assessing relative TSR performance and agreed to adopt a percentile-based
methodology for the 2026-28 cycle. This approach provides a more proportionate assessment of performance across the peer group and greater
alignment with the shareholder experience.
Within the financials category, the underlying measures remain unchanged. For the 2025–27 cycle, targets were set in line with our external
ambitions to the end of 2027, as outlined at the Capital Markets Day in February 2025. Looking ahead, ROACE« will revert to being assessed on an
average basis — consistent with past practice — while adjusted free cash flow« will be assessed based on performance through to the end of 2028.
Lastly, the underpin has been broadened to include progress towards a strong and resilient balance sheet, reflecting our long-term priorities.
| | ||||||||||||||||||||||||||||||||||||
rTSR |  | Financials | | ESG | |||||||||||||||||||||||||||||||||
30% | 25% | 25% | 20% | ||||||||||||||||||||||||||||||||||
ROACE (average 2026-28)ce | Adjusted free cash flowdef | Cumulative reduction % in operated carbon emissionsg | |||||||||||||||||||||||||||||||||||
Vesting % for each element | 100% | 100% | 100% | ||||||||||||||||||||||||||||||||||
75% | 75% | 75% | |||||||||||||||||||||||||||||||||||
50% | 50% | 50% | |||||||||||||||||||||||||||||||||||
Peer group of five companies: Chevron, Eni, ExxonMobil, Shell and TotalEnergies (and bp)b | 25% | 25% | 25% | ||||||||||||||||||||||||||||||||||
0% | 0% | 0% | |||||||||||||||||||||||||||||||||||
Below 13% | 14% | 15% | 16% | Above 17% | Targets not disclosed | Below 40% | 42% | 43% | 46% | Above 48% | |||||||||||||||||||||||||||
ROACE | Adjusted free cash flow | Cumulative reduction % in operated carbon emissions | |||||||||||||||||||||||||||||||||||
| | ||||||||||||||||||||||||||||||||||||
Rank | Percentile | Vesting |
1 | 100th %ile | 100% |
3 | 50th %ile | 25% |
Below median | 0% | |
•Underpin will take into account overall safety performance as well as ongoing progress towards a strong and resilient balance sheet.
•Remuneration committee discretion will reflect shareholder experience, environment, societal and other inputs.
•Subject to usual malus and clawback provisions.
aTarget set includes receipt of Castrol proceeds prior to finalization of year-end results.
bStraight-line vesting between median and maximum.
cBased on the average ROACE over 2026, 2027 and 2028.
dBased on adjusted free cash flow at the end of the three-year period.
eAdjustments may be required in certain circumstances. The external environment to be a considered judgement in final outcomes.
f Targets are considered to be commercially sensitive and will be disclosed in full at the end of the performance period.
gScope 1 and 2 GHG emissions reductions vs. 2019 baseline from operated carbon emissions including portfolio change. Corporate activity unknown at the time that targets are set to be a
considered judgement in final outcomes.
110 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
Provided below is an overview of the performance measures and weightings of each of our in-flight awards.
Measures for 2025-27 performance shares
| | |||||||||||||||||||||||||||||||||||||||||||||
rTSR | | Financials | | ESG | | Strategic progress | ||||||||||||||||||||||||||||||||||||||||
25% | 20% | 20% | 15% | 20% | ||||||||||||||||||||||||||||||||||||||||||
Peer group of seven companiesa | ROACE | Adjusted free cash flow CAGR« | Cumulative reduction % in operated carbon emissionsb | Holistic review of progress against strategy set out in the Capital Markets Update in February 2025. Subject to the remuneration committee’s judgement. Consideration may be given to the following measures: •Divestments. •Net debt. •Structural cost reduction. | ||||||||||||||||||||||||||||||||||||||||||
Vesting % for each element | 100% | 100% | 100% | 100% | ||||||||||||||||||||||||||||||||||||||||||
75% | 75% | 75% | 75% | |||||||||||||||||||||||||||||||||||||||||||
50% | 50% | 50% | 50% | |||||||||||||||||||||||||||||||||||||||||||
25% | 25% | 25% | 25% | |||||||||||||||||||||||||||||||||||||||||||
0% | 0% | 0% | 0% | |||||||||||||||||||||||||||||||||||||||||||
8 | 7 | 6 | 5 | 4 | 3 | 2 | 1 | Below 14% | 15% | 16% | 17% | Above 18% | Below 15% | 17.5% | 20% | 22.5% | Above 25% | Below 35.5% | 37% | 38.5% | 41% | Above 43.5% | ||||||||||||||||||||||||
rTSR ranking | ROACE | Adjusted free cash flow CAGR | Cumulative reduction % in operated carbon emissions | |||||||||||||||||||||||||||||||||||||||||||
| | |||||||||||||||||||||||||||||||||||||||||||||
Measures for 2024-26 performance shares
| | |||||||||||||||||||||||||||||||||||||||||||||
rTSR | | Financials | | ESG | | Strategic progress | ||||||||||||||||||||||||||||||||||||||||
25% | 20% | 20% | 15% | 20% | ||||||||||||||||||||||||||||||||||||||||||
Peer group of seven companiesa | ROACE (average 2024-26) | Adjusted EBIDA per share CAGR« | Cumulative reduction % in operated carbon emissionsb | Subject to remuneration committee judgement. Following the Capital Markets Update in February 2025, judgement of strategic progress will adopt the same frame as set out for the 2025-27 cycle. | ||||||||||||||||||||||||||||||||||||||||||
Vesting % for each element | 100% | 100% | 100% | 100% | ||||||||||||||||||||||||||||||||||||||||||
75% | 75% | 75% | 75% | |||||||||||||||||||||||||||||||||||||||||||
50% | 50% | 50% | 50% | |||||||||||||||||||||||||||||||||||||||||||
25% | 25% | 25% | 25% | |||||||||||||||||||||||||||||||||||||||||||
0% | 0% | 0% | 0% | |||||||||||||||||||||||||||||||||||||||||||
8 | 7 | 6 | 5 | 4 | 3 | 2 | 1 | Below 15.7% | 16.2% | 16.7% | 17.2% | Above 17.7% | Below 9.3% | 9.8% | 10.3% | 10.8% | Above 11.3% | Below 36% | 38% | 39% | 42% | Above 44% | ||||||||||||||||||||||||
rTSR ranking | ROACE | Adjusted EBIDA per share CAGR | Cumulative reduction % in operated carbon emissions | |||||||||||||||||||||||||||||||||||||||||||
| | |||||||||||||||||||||||||||||||||||||||||||||
aPeer group includes Chevron, Eni, Equinor, ExxonMobil, Repsol, Shell and TotalEnergies (and bp).
bThe committee determined that the operated carbon emissions targets under the above EDIP awards should be adjusted in order to align with the strategy reset at the start of 2025 (2024-26
only) and subsequent recalibration of internal goals and principles around emissions (2024-26 and 2025-27). The effect of this change, which was made in conjunction with the safety and
sustainability committee, is to widen the target range by reducing the threshold and increasing the maximum under both awards.
bp Annual Report and Form 20-F 2025 | 111 |
| ||||
Corporate governance | ||||
Stewardship and executive director interests
We believe that our executive directors should build and maintain a meaningful interest in the company. Our policy therefore requires the CEO and
CFO to build a personal shareholding of five times and four and a half times, respectively, their salary within five years of their appointment. They
are expected to maintain this level of personal shareholdings for two years post-employment.
Directors’ shareholdings and aggregated interests (audited)
Directors’ ordinary shares or equivalents at 13 February 2026 | Aggregated interests at 13 February 2026, all plans | Current shareholding for MSRb,d | Value of current shareholdingc,d £ | Multiple of salary achievedd | |||||||||
Unvested awards not subject to performance conditions | Unvested awards subject to performance conditions | ||||||||||||
Sharesa | Options | Shares | Options | ||||||||||
Carol Howle | 491,903 | 1,040,861 | 750,000 | 381,825 | — | 1,047,640 | 4,829,622 | 3.20 | |||||
Murray Auchinclossd | 1,816,006 | 1,094,742 | 152,301 | 3,273,590 | — | 2,104,355 | 8,847,761 | 5.87 | |||||
Kate Thomson | 432,482 | 219,236 | 500,000 | 1,659,711 | — | 550,831 | 2,539,331 | 2.94 | |||||
aIncludes deferred and restricted shares, and performance shares prior to application of the performance factor.
bIncludes ordinary shares or equivalents and unvested awards not subject to performance conditions on a net-of-tax basis, excluding dividends.
cBased on ordinary share price at 13 February 2026 of £4.61 (close price).
dMurray Auchincloss stepped down on 18 December 2025. The shareholding disclosed reflects his individual holding and includes interests of a person closely associated with him as at that date.
The shareholding for MSR purposes, the value of his shareholding and multiple of salary achieved are each presented as at 18 December 2025. In accordance with the plan rules, his unvested
performance share awards will be pro-rated to 17 December 2026.
Executive directors have additional interests in performance and deferred bonus shares. These interests are shown in aggregate in the table above,
and interests awarded during 2025 in the tables below. For performance shares, the figures reflect maximum possible vesting levels (excluding the
addition of reinvested dividends) even though the actual number of shares that vest will depend on the extent to which performance conditions
are satisfied.
Performance and deferred shares (audited)
Award | Number of shares granted | Grant date | Face value of the awarda, £ | Vesting date | |
Carol Howleb | 2025-27 EDIP Performancec | — | — | — | — |
Murray Auchinclossb | 1,790,973 | 30 April 2025 | 6,268,406 | April 2028 | |
Kate Thomson | 923,515 | 30 April 2025 | 3,232,303 | April 2028 | |
Carol Howleb | 2025 EDIP Deferredd | — | — | — | — |
Murray Auchinclossb | 59,840 | 30 April 2025 | 209,440 | April 2028 | |
Kate Thomson | 51,947 | 30 April 2025 | 181,815 | April 2028 |
aThe face value of awards granted during 2025 have been calculated using a market price of ordinary shares at close on the date of award, as follows: £3.50 on 30 April 2025. In calculating the
number of ordinary shares over which these awards were made, the committee applied the average price of ordinary shares over the 90 calendar days up to and including the annual general
meeting held on 17 April 2025 (£4.21).
bMurray Auchincloss stepped down as CEO effective 18 December 2025 and Carol Howle was appointed as interim CEO on the same date. As Carol was a below board employee when her
2025-27 GSVP award was granted, detail of this award has not been disclosed as it is considered to be commercially sensitive.
cPerformance conditions are measured 15% on cumulative reduction % in operated carbon emissions, 25% on TSR relative to Chevron, ExxonMobil, Shell, TotalEnergies, Eni, Equinor and Repsol
over three years, 20% ROACE measured to the end of 2027, 20% adjusted free cash flow CAGR vs. 2024 baseline and 20% strategic progress assessed over the performance period. Minimum
vesting under this award (below threshold performance) is 0%. At threshold performance, vesting would be 6.25% of maximum.
Since 2010, vesting of the performance shares under EDIP has been subject to a safety underpin. If the committee assesses that there has been a material deterioration in safety performance,
or there have been major incidents, either of which reveal underlying weaknesses in safety management, then it may conclude that shares should vest only in part, or not at all. In reaching its
conclusion, the committee obtains advice from the S&SC.
The performance period is 1 January 2025 to 31 December 2027.
The 2026 performance share awards under EDIP are expected to be made following the conclusion of the 2026 annual general meeting.
dThere is no identified minimum vesting threshold level. The 2025 bonus year deferred share awards under EDIP are expected to be made following the conclusion of the 2026 annual
general meeting.
Directors and leadership team
No directors or other leadership team members own more than 1% of the shares in issue. At 13 February 2026, our directors and leadership team
members collectively held interests of 5,127,004 ordinary shares or their calculated equivalents, 3,840,510 restricted share units (with or without
conditions) or their calculated equivalents, 4,964,919 performance shares or their calculated equivalents and 4,027,241 options over ordinary shares
or their calculated equivalents, under bp group share option schemes.
112 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
Chair and non-executive director interests
Fee structure
The table below shows the fee structure for the chair and non-executive directors (NEDs). The chair is not eligible for committee chairship and
membership fees. The senior independent director (SID) is eligible for committee chairship and membership fees, and their fee includes the board
member fee. Committee chairs do not receive a membership fee for the committee they chair.
Under the 2023 policy, fee levels are reviewed annually alongside wider workforce salaries with any changes taking effect from 1 April. For the
2026-27 year, no changes are being made to the base fee for NEDs and for the SID. In accordance with the policy, the remuneration committee is
responsible for determining the chair’s fee. Following the appointment of Albert Manifold as chair on 1 September 2025, the committee approved
his fees and benefits at that time. No further changes to the chair’s fee are being made for 2026-27.
£ thousand per annum | 2026/27 fees | 2025/26 fees |
Chair | 1,000 | 888 |
Senior independent director | 181.5 | 181.5 |
Board member | 130.5 | 130.5 |
Audit, remuneration and safety and sustainability committees chairship | 35 | 35 |
Committee membership | 20 | 20 |
2025 remuneration (audited)
The table below shows the fees paid and applicable benefits. Benefits include travel and other expenses relating to the attendance at board and
other meetings. Under the terms of his engagement with the company, Albert Manifold has the use of a fully maintained office for company
business, a car and driver, and security advice in London. Benefits values have been grossed up using a tax rate of 45%, where relevant, as an
estimation of tax due.
Fees | Benefits | Total | ||||||
£ thousand | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | ||
Dame Amanda Blanc | 220 | 198 | — | 1 | 220 | 198 | ||
Pamela Daleya | 87 | 164 | 5 | 17 | 93 | 181 | ||
Dave Hagerb | 78 | — | 37 | — | 114 | — | ||
Simon Henryc | 44 | — | 1 | — | 44 | — | ||
Helge Lundd | 658 | 845 | 28 | 38 | 686 | 882 | ||
Albert Manifold (chair)d | 333 | — | 50 | — | 384 | — | ||
Melody Meyer | 184 | 182 | 56 | 9 | 240 | 191 | ||
Tushar Morzaria | 189 | 189 | 32 | 1 | 221 | 190 | ||
Hina Nagarajan | 169 | 157 | 39 | 17 | 208 | 174 | ||
Satish Pai | 149 | 144 | 5 | 5 | 154 | 149 | ||
Karen Richardsone | 194 | 169 | 15 | 16 | 209 | 185 | ||
Dr Johannes Teyssen | 169 | 160 | 6 | 5 | 175 | 165 | ||
Ian Tylerf | 135 | — | 34 | — | 169 | — | ||
aPamela Daley stepped down as a non-executive director on 7 July 2025.
bDave Hager was appointed as a non-executive director on 2 June 2025.
cSimon Henry was appointed as a non-executive director on 1 September 2025.
dAlbert Manifold was appointed as a non-executive director and chair-elect on 1 September 2025, and assumed the role of chair on 1 October 2025, succeeding Helge Lund, who stepped down as
chair on 30 September 2025.
eFee includes £25,000 p.a. for chairing the bp digital advisory council and £20,000 p.a. for chairing innovation advisory council.
fIan Tyler was appointed as a non-executive director on 1 April 2025.
bp Annual Report and Form 20-F 2025 | 113 |
| ||||
Corporate governance | ||||
Chair and non-executive directors’ interests (audited)
The figures below include all the interests of the chair and each NED of the company in shares of bp (or calculated equivalents) that have been
disclosed to bp. Our 2023 policy encourages NEDs to establish a holding in bp shares of the equivalent value of one year's base fee during their
tenure.
Ordinary shares or equivalentsa | ||||||
At 1 January 2025 | At 31 December 2025 | Changes to 13 February 2026 | At 13 February 2026 | Value of current shareholdingb | % of guideline achieved | |
Dame Amanda Blanc | 23,500 | 47,100 | — | 47,100 | £217,131 | 166% |
Pamela Daleyc | 40,332 | n/a | n/a | n/a | n/a | n/a |
Dave Hagerd | n/a | 45,000 | — | 45,000 | $282,450 | 164% |
Simon Henrye | n/a | — | — | — | — | —% |
Helge Lundf | 600,000 | n/a | n/a | n/a | n/a | n/a |
Albert Manifold (chair)f | n/a | — | — | — | — | —% |
Melody Meyer | 38,646 | 38,646 | — | 38,646 | $242,568 | 141% |
Tushar Morzaria | 71,972 | 71,972 | — | 71,972 | £331,791 | 254% |
Hina Nagarajan | 25,944 | 30,944 | — | 30,944 | £142,652 | 109% |
Satish Pai | 33,000 | 33,000 | — | 33,000 | $207,130 | 120% |
Karen Richardson | 35,316 | 35,316 | — | 35,316 | $221,667 | 129% |
Dr Johannes Teyssen | 35,000 | 35,000 | — | 35,000 | £161,350 | 124% |
Ian Tylerg | n/a | — | — | — | — | —% |
aIncludes interests of persons closely associated.
bBased on ordinary share and ADS prices at 13 February 2026 of £4.61 and $37.66. Where a US$ value is provided these shares are held as ADSs.
cPamela Daley stepped down as a non-executive director on 7 July 2025.
dDave Hager was appointed as a non-executive director on 2 June 2025.
eSimon Henry was appointed as a non-executive director on 1 September 2025.
fAlbert Manifold was appointed as a non-executive director and chair-elect on 1 September 2025, and assumed the role of chair on 1 October 2025, succeeding Helge Lund, who stepped down as
chair on 30 September 2025.
gIan Tyler was appointed as a non-executive director on 1 April 2025.
Payments to past directors and for loss of office
Departure terms for Murray Auchincloss (audited)
As set out elsewhere in the report, Murray Auchincloss stepped down from the board by mutual agreement on 18 December 2025. Details of his
departure terms have been set out below and are consistent with the company’s shareholder-approved policy.
In line with his 12-month notice period, Murray will remain an employee on his existing terms until 17 December 2026. During this period, he will
continue to receive his contractual salary and benefits.
In respect of his incentive awards, Murray will remain eligible to receive a pro-rata annual bonus in respect of his services during 2025, of which
33% will be deferred into bp shares in line with the policy. He will not be entitled to a bonus in respect of 2026. Outstanding deferred bonus awards
will vest in line with normal timescales.
Murray’s unvested performance share awards under the EDIP will be pro-rated up to 17 December 2026 but will continue to vest on their normal
dates subject to the achievement of the relevant performance conditions. The resulting shares are subject to a 12-month holding period following
vesting. Vested shares already in a holding period will be released 12 months following his cessation of employment, i.e. 17 December 2027, or on
their original release date, if earlier. He will not be eligible for a 2026 EDIP grant.
He is entitled to receive ongoing tax filing support in respect of any trailing income from the company and a contribution towards his legal fees
incurred in connection with stepping down to the total of £10,000 (plus VAT). He will continue to be covered by D&O insurance and will benefit from
an indemnity in respect of third-party liabilities.
Post-employment benefits (audited)
We made no payments within the scope of the disclosure requirements to any past director of bp during 2025.
114 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
Other disclosures
Historical TSR performance | Relative importance of spend on pay ($ million) | |||||||||||||||||||||||
£250 | Distribution to bp shareholders | Remuneration paid to all employees | Capital investmenta | |||||||||||||||||||||
£200 | ||||||||||||||||||||||||
£150 | ||||||||||||||||||||||||
£100 | ||||||||||||||||||||||||
£50 | ||||||||||||||||||||||||
£0 | ||||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | 2025 | ||||||||
BP FTSE 100 | a Organic capital expenditure«. | |||||||||||||||||||||||
The graph above shows the growth in value of hypothetical £100 investments in BP p.l.c. ordinary shares, and in the FTSE 100 index (of which bp is a
constituent), over 10 years from 31 December 2015 to 31 December 2025.
History of chief executive officer remuneration
Year | Chief executive officer | Total remuneration, thousand | Annual bonus % of maximum | Performance shares % of maximum |
2016 | Bob Dudley | $11,904 | 61 | 40 |
2017 | Bob Dudley | $15,108 | 71.5 | 70 |
2018 | Bob Dudley | $15,253 | 40.5 | 80 |
2019 | Bob Dudley | $13,234 | 67.5 | 71.2 |
2020a | Bob Dudley | $188 | 0 | 32.5 |
Bernard Looney | £1,735 | 0 | 32.5 | |
2021 | Bernard Looney | £4,457 | 80.5 | 30 |
2022 | Bernard Looney | £10,331 | 75.5 | 54 |
2023ab | Bernard Looney | £1,175 | n/a | n/a |
Murray Auchincloss | £5,391 | 79.5 | 75 | |
2024 | Murray Auchincloss | £5,179 | 22.5 | 66.5 |
2025acd | Murray Auchincloss | £5,307 | 79.5 | 23.3 |
Carol Howle | £886 | 79.5 | 52.8 |
a2020, 2023 and 2025 figures show remuneration for the periods of qualifying service as CEO during the respective years.
bIn respect of 2023, Bernard Looney did not receive any variable pay awards and his single figure shown in the table above excludes the impact of malus and clawback.
cMurray Auchincloss stepped down from his position as CEO on 18 December 2025 and was succeeded by Carol Howle as interim CEO on 18 December 2025. For 2025, Carol’s performance share
award was granted when she was below board level and is therefore based on a different scorecard to executive directors.
dShare price has been based on the average share price over Q4 of the 2025 FY of £4.40.
bp Annual Report and Form 20-F 2025 | 115 |
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Corporate governance | ||||
Chief executive officer to employee pay ratio
Year | Method | 25th percentile: pay ratio, total pay and benefits, (salary) | 50th percentile: pay ratio, total pay and benefits, (salary) | 75th percentile: pay ratio, total pay and benefits, (salary) |
2019a | Option A | 543:1 | 188:1 | 82:1 |
2020a | Option A | 99:1 | 40:1 | 19:1 |
2021 | Option A | 208:1 | 87:1 | 35:1 |
2022 | Option A | 421:1 | 172:1 | 69:1 |
2023b | Option A | 268:1 | 103:1 | 45:1 |
2024 | Option A | 196:1 | 74:1 | 37:1 |
2025bc | Option A | 219:1 | 79:1 | 39:1 |
£28,331 | £78,644 | £160,265 | ||
(£26,237) | (£55,675) | (£97,425) |
aBob Dudley’s pay has been converted from US dollars as per the ratios reported in the bp Annual Report and Form 20-F 2020.
bFor 2023 and 2025, the total single figure used to derive the CEO pay ratio is a combination of the two individuals in position of CEO during the year. For 2023, in respect of the former CEO, the
calculation has been based on the total single figure excluding the impact of malus and clawback in order to provide a comparison with prior years. Appropriate pro-rating of fixed and variable
pay has been applied.
cShare price for the CEO share plan vesting has been based on the average share price over Q4 of the 2025 FY of £4.40.
This is our seventh year reporting the CEO pay ratio following the requirements introduced in 2018. As per the past six years, we have selected
Option A as our reporting basis, being the most accurate approach available, and we confirm that no broadly applicable components of pay have
been omitted. Where necessary, full-time equivalent pay has been calculated by simple engrossment of part-year values. Employee values relate to
pay and benefits for the year ended 31 December 2025.
Changes in the pay ratio over time reflect the fact that CEO remuneration is more heavily weighted to variable pay, resulting in larger year-on-year
swings than wider workforce pay. This is evidenced by the variability of the CEO pay ratio over the past seven years. This volatility in the pay ratio
reporting from year to year is expected, and illustrates one of the challenges in commenting on whether the pay differentials are appropriate. In
2025, the pay ratios have remained broadly consistent year-on-year, with the 50th percentile pay ratio increasing from 74:1 to 79:1. While the annual
bonus was higher in 2025 (79.5% compared to 22.5% in 2024), this was partly offset by a significantly lower EDIP outcome for the former CEO
(23.3% compared to 66.5% for the 2022-24 cycle).
The committee believes in performance-based remuneration. For all employees eligible to participate in the annual cash bonus plan, there is an
individual uplift available each year which allows managers to nominate exceptional individuals based on their personal contributions during the
year. For senior leaders, a significant portion of the remuneration package continues to be linked to performance-based reward. It is therefore the
view of the committee that the remuneration frameworks we have in place for executive directors and the wider workforce are fit for purpose and
deliver pay outcomes appropriate to the circumstances of the year, with differentials that reflect the relative contributions made at different levels
of the organization.
The committee is satisfied that the median pay ratio reported this year is consistent with bp’s pay policies for employees and does not constitute a
reason to modify our pay programmes.
116 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
Percentage change comparisons: directors’ remuneration versus employees
In the table below, values in column ‘a’ represent the percentage change in salary and fees; values in column ‘b’ represent the percentage change in
taxable benefits; and values in column ‘c’ represent the percentage change in bonus outcomes for performance periods in respect of each financial
year. For the purposes of comparison, the employee percentages shown below represent the relative change between the median full-time
equivalent pay for every employee employed at BP p.l.c. at any point during the relevant financial year, and the equivalent median value for the
preceding financial year. Where increases are infinite relative to the preceding year, we have shown them as 100% for illustration; where a director
was appointed or retired part-way through the year, we have annualized pay except for one-time items; and where comparison to the prior year is
not possible, we have used dashes.
2025 vs. 2024 | 2024 vs. 2023 | 2023 vs. 2022 | 2022 vs. 2021 | 2021 vs. 2020 | |||||||||||||||
Percentage change for: | a | b | c | a | b | c | a | b | c | a | b | c | a | b | c | ||||
Employees | 6% | —% | 124% | 4% | —% | -65% | 6% | 1% | 4% | 2% | 1% | 45% | 7% | -9% | 100% | ||||
Carol Howle | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | ||||
Murray Auchincloss | -1% | 5% | 253% | 43% | -61% | -60% | 30% | 283% | 31% | 7% | 530% | 3% | 5% | 5% | 100% | ||||
Kate Thomsona | 16% | 23% | 318% | —% | — | — | — | — | — | — | — | — | — | — | — | ||||
Dame Amanda Blanc | 11% | (89)% | n/a | 24% | -72% | n/a | 38% | 100% | n/a | — | — | n/a | — | — | n/a | ||||
Pamela Daley | 3% | (68)% | n/a | 3% | -75% | n/a | 2% | 2% | n/a | 7% | 43% | n/a | 4% | 1385% | n/a | ||||
Dave Hager | — | — | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | ||||
Simon Henry | — | — | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | ||||
Helge Lund | 4% | (25)% | n/a | 4% | -43% | n/a | 3% | 78% | n/a | —% | 97% | n/a | —% | -24% | n/a | ||||
Albert Manifold (Chair) | — | — | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | ||||
Melody Meyer | 1% | 512% | n/a | -1% | -68% | n/a | 2% | -14% | n/a | 13% | 139% | n/a | -4% | 283% | n/a | ||||
Tushar Morzaria | — | 3,559% | n/a | 9% | -73% | n/a | 2% | -46% | n/a | 25% | 100% | n/a | 5% | —% | n/a | ||||
Hina Nagarajan | 8% | 129% | n/a | 13% | -46% | n/a | — | — | n/a | — | — | n/a | — | — | n/a | ||||
Satish Pai | 4% | 11% | n/a | 3% | -88% | n/a | — | — | n/a | — | — | n/a | — | — | n/a | ||||
Paula Rosput Reynolds | (100)% | (100)% | n/a | 3% | -70% | n/a | 2% | -14% | n/a | 16% | 145% | n/a | — | 228% | n/a | ||||
Karen Richardson | 15% | (6%) | n/a | -5% | -12% | n/a | 11% | -20% | n/a | 30% | 96% | n/a | — | — | n/a | ||||
Sir John Sawers | (100)% | (100)% | n/a | 3% | 63% | n/a | 2% | 105% | n/a | 17% | 1% | n/a | — | 1588% | n/a | ||||
Johannes Teyssen | 6% | 14% | n/a | 7% | -68% | n/a | 3% | 12% | n/a | 21% | 65% | n/a | — | — | n/a | ||||
Ian Tyler | —% | —% | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | ||||
a Kate Thomson’s increase in salary reflects the adjustment from her previous role to the salary level for an Executive Director following her appointment on 2 February 2024.
Independence and advice
The board considers all committee members to be independent with no personal financial interest, other than as shareholders, in the committee’s
decisions. Further detail on the activities of the committee in 2025 is set out in the remuneration committee report on page 91.
During 2025, Ben Mathews, who was employed by the company and reported to the chair of the board, acted as secretary to the remuneration
committee.
The committee also received advice on various matters relating to the remuneration of executive directors and senior management from Kerry
Dryburgh, EVP people, culture & communications, and Ashok Pillai and Clare Peake, SVP reward.
Following a competitive tender process, Willis Towers Watson (WTW) replaced PwC as independent advisors to the committee in 2025. PwC
and WTW advice included, for example, support with remuneration benchmarking and updates on market practice. Both are members of the
Remuneration Consulting Group and, as such, operate under the code of conduct in relation to executive remuneration in the UK. The committee
is satisfied that the advice received is objective and independent. The committee is comfortable that both the PwC and WTW engagement
partners and team who provide remuneration advice to the committee do not have connections with the company or its directors that may
impair their independence.
Total fees or other charges (based on an hourly rate) for the provision of remuneration advice to the committee in 2025 (save in respect of legal
advice) were £67,683 and £64,800 to PwC and WTW respectively. Freshfields LLP (Freshfields) provided legal advice on specific compliance matters
to the committee. PwC, WTW and Freshfields provided other advice in their respective areas to the group.
bp Annual Report and Form 20-F 2025 | 117 |
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Corporate governance | ||||
Shareholder engagement
Throughout 2025 the committee engaged regularly on remuneration policy and approach with bp’s largest shareholders, as well as their
representative bodies. This dialogue will continue throughout 2026. The table below shows the recent votes on the directors’ remuneration report
and policy.
Year | % vote ‘for’ | % vote ‘against’ | Votes withheld |
2025 – Directors’ remuneration report | 95.54% | 4.46% | 36,686,921 |
2023 – Directors’ remuneration policy | 94.23% | 5.77% | 36,921,641 |
Service contracts and letters of appointment
The service contracts of executive directors do not have a fixed term. Service contracts for each executive director are available for shareholders to
view upon request at the company’s registered office. Each executive director’s service contract contains a 12-month notice period. Consistent with
the best interests of the group, the committee will seek to minimize termination payments.
Date of contract | Effective date | |
Carol Howlea | 17 December 2025 | 18 December 2025 |
Murray Auchinclossa | 17 January 2024 | 17 January 2024 |
Kate Thomson | 2 February 2024 | 2 February 2024 |
a Murray Auchincloss stepped down as CEO effective 18 December 2025. Carol Howle was appointed interim CEO on the same date.
The non-executive directors (NEDs) have letters of appointment, which are available for shareholders to view upon request at the company’s
registered office. All continuing directors are subject to annual re-election by shareholders at the annual general meeting. Normally, NEDs will be
encouraged to serve for up to six years from their appointment, and for a further three years by invitation, in line with the provisions of the 2024
Code, subject to annual re-election.
External appointments
The board supports executive directors taking up appointments outside the company to broaden their knowledge and experience. Each executive
director is permitted to retain any fee from their external appointments. Such external appointments are subject to agreement by the chair and
reported to the board. Any external appointment must not conflict with a director’s duties and commitments to bp. Details of appointments as
NEDs of publicly listed companies during 2025 are shown below.
Appointee company | Additional position held at appointee company | Total fees, £ | |
Kate Thomson | Aker BP ASAa | Director | 0 |
aHeld as a result of the company’s shareholding in Aker BP ASA.
This directors’ remuneration report, including the 2026 remuneration policy set out on the pages 118 to 125, has been approved by the board and
signed on its behalf by Ben J.S. Mathews, company secretary, on 6 March 2026.
118 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
Directors’ remuneration report – the 2026 remuneration policy
This section of the report sets out the remuneration policy for executive directors and non-executive directors, which shareholders will be asked
to approve at the AGM on 23 April 2026 and, if approved, will take effect for any payments made or awarded after that date. The company will
continue to honour any arrangements granted under previous remuneration policies which were consistent with the policy in force at the time
of grant.
As outlined in the chair’s statement, the committee undertook an initial review of the policy during 2025 and agreed to defer a more detailed review
of the policy until after the 2026 AGM. The policy set out on the following pages has therefore largely been rolled forward from the previous policy,
which was approved at the 2023 AGM and received strong support from shareholders with a vote of 94% in favour.
While no material changes are being proposed to the 2026 remuneration policy, minor changes have been made to the wording in certain areas to
increase clarity and effective operation.
Policy table – executive directors
 | ||||
Purpose | To provide fixed remuneration to reflect the scale and complexity of both the business and the role, and to be competitive with the external market. | |||
Operation and opportunity | Salary Salary levels will relate to the nature of the role, performance of the business and the individual, market positioning and pay conditions in the wider bp group. There is no maximum salary under the policy. When setting salaries, the committee considers practice in other energy majors as well as European and US companies of a similar size, geographic spread and business dynamic to bp. The committee will also consider salary increases for the most senior management and the wider workforce. In particular, percentage increases for executive directors will not exceed increases for the broader employee population, other than in specific circumstances identified by the committee (e.g. in response to a substantial change in responsibilities). Salaries are normally set in the home currency of the executive director and are reviewed annually. They may be reviewed at other times where appropriate, for example following a major role change. | Benefits Executive directors are entitled to receive those benefits available to a majority of the wider workforce in their home country. These include participation in all-employee share plans, sickness pay, relocation assistance and parental leave. Benefits are not pensionable. Executive directors may receive other benefits that are judged to be cost-effective and appropriate in terms of the individual’s role, time and/or security. These may include car-related benefits and/or cash in lieu, security, assistance with tax return preparation, insurance and medical benefits. The company may meet any tax charges arising on benefits provided to directors. The taxable value of benefits provided may fluctuate during the period of this policy, depending on the cost of provision and a director’s personal circumstances. | ||
 | ||||
Purpose | To recognize competitive practice in the directors’ home country while being aligned with the majority of the workforce. | |||
Operation and opportunity | Executive directors normally participate in the company retirement plans that operate in their home country. New appointees from within bp group retain previously accrued benefits. For future appointments, the committee will carefully review any retirement benefits to be granted to a new director, taking account of retirement policies across the wider workforce and any arrangements currently in place. | Retirement benefits for executive directors will be limited to the allowance offered to the majority of the workforce in the executive's home country (the maximum allowance in the UK is currently 20% of salary). | ||
bp Annual Report and Form 20-F 2025 | 119 |
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Corporate governance | ||||
| ||||
Purpose | To provide variable remuneration dependent on the execution of the business strategy on an annual basis. Bonus is subject to a mandatory deferral into bp shares which are held for three years to reinforce the long-term nature of the business and alignment with shareholders. | |||
Operation and opportunity | The bonus is based on performance against annual measures and targets set at the start of the year, evaluated over the financial year and assessed following the year-end. The target annual bonus is half of the maximum available, and typically relates to delivery of performance in line with targets in the annual plan. Executive directors may earn a maximum annual bonus of 225% of salary. This maximum level would relate to performance at or above the highest end of the performance scale for every measure. The committee intends to set demanding requirements for maximum payment. Achievement of threshold performance would normally result in a payout of 0% of the maximum opportunity. Bonus calculation is typically based on salary as at 31 December in each performance year. | The final bonus outcome, following the formulaic assessment of performance relative to targets, is specifically reserved as a matter for the committee’s judgement. Accordingly, the committee may exercise its discretion to adjust the formulaic outcome either upwards or downwards. Half the bonus is paid in cash, and half is deferred into bp shares for three years up until ’minimum shareholding requirement’ (MSR) is met, as determined by the committee under the shareholding guidelines. Once met, 67% is paid in cash and 33% is deferred into bp shares. Dividends (or equivalents, including the value of any reinvestment) may accrue in respect of any deferred shares. Awards are subject to malus provisions before they are delivered and to clawback thereafter for a period of three years. Further detail is set out on page 121. | ||
Performance framework | The committee determines a scorecard of specific measures, weightings and targets each year to reflect the priorities in the annual plan, as agreed with the board, and thus deliver the group’s strategy. | The scorecard will typically include a balance of financial and non-financial measures. Details of the measures and weighting will typically be reported in advance each year in the annual report on remuneration, while targets, where commercially sensitive, will be disclosed retrospectively. | ||
| ||||
Purpose | To link the largest part of remuneration opportunity with the long-term performance of the business. | |||
Operation and opportunity | The maximum annual award level for the chief executive officer will be 500% of salary and 450% of salary for other executive directors. Annual awards of shares will vest based on performance relative to measures and targets that reflect the delivery of bp’s strategy over a performance period of typically three years. For each measure, the threshold level at which vesting is first triggered is not expected to yield vesting above 25% of the maximum. | The final performance shares outcome, following the formulaic assessment of performance relative to targets, is specifically reserved as a matter for the committee’s judgement. Accordingly, the committee may exercise its discretion to adjust the formulaic outcome either upwards or downwards. The shares that vest are subject to a three-year post-vesting holding period. Dividends (or equivalents, including the value of reinvestment) may accrue in respect of share awards to the extent that they vest. Awards are subject to malus provisions before vesting and to clawback provisions thereafter for a period of three years. Further detail is set out on page 121. | ||
Performance framework | At the outset of each performance cycle, the committee determines a scorecard of specific measures, weightings and targets to reflect the group’s long-term strategic priorities and shareholder interests. | The scorecard will typically include a balance of financial and non-financial measures (including sustainability). The committee will assess overall safety performance as well as progress towards the reduction of net debt as an underpin in determining the final vesting percentage. | ||
| ||||
Purpose | To provide alignment between the interests of executive directors and our other shareholders. | |||
Operation and opportunity | The chief executive officer is required to build and maintain a minimum shareholding of five times base salary within five years of appointment, and to maintain that minimum shareholding for at least two years after they cease to be a director. | Other executive directors are required to build and maintain a minimum shareholding of four and a half times base salary within five years of appointment, and to maintain that minimum shareholding for at least two years after they cease to be a director. | ||
120 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
Notes to the policy table
1. How is variable pay linked to performance?
| Bonus aligned with company performance | | <100% MSRa: 50% paid in cash; 50% in bp shares deferred for three years | ||||
>100% MSRa: 67% paid in cash: 33% in bp shares deferred for three years | |||||||
| Share award for meeting three-year targets | | Six-years; three-year performance period + three-year holding period | ||||
 | Long-term shareholding | | Built up over five years and maintained for a further two years post-employment | ||||
aMSR: group chief executive to build a shareholding of at least five times salary, and other executive directors four and a half times salary, within five years of appointment.
The three elements described above provide a balance between a focus on short-term, medium-term and long-term performance, while
encouraging behaviours which are in the long-term interests of shareholders. The operation of variable pay is supported by a focus on stewardship.
There is a requirement that the chief executive officer will build up a holding of five times salary, and other executive directors a holding of four and
a half times salary, over a period of five years following appointment and maintain that level during employment and for a further two years post-
employment.
2. How are performance measures linked to strategy?
Variable pay is linked to performance measures designed to deliver the bp strategy. At the start of each year, the remuneration committee reviews
the measures, targets and weightings to ensure they remain consistent with the priorities in the annual plan and the group strategy. For the annual
bonus and performance shares, the approach to performance measurement is intended to provide a balance of measures to assess performance
reflecting the global scale of the business, the unique characteristics of the energy sector, and progress in transitioning to an integrated energy
company.
3. Our use of flexibility, judgement and discretion
The committee reviews bp’s performance against specific measures and targets, and in doing so may make both quantitative and qualitative
assessments of performance in reaching its decisions. This involves the application of judgement and discretion, in which the committee also seeks
relevant input from the board’s audit and safety and sustainability committees. Accordingly, the committee may decide to adjust the formulaic
outcome derived from the relevant scorecards, either upwards or downwards, to reflect broader considerations. The committee continues to
consider that the powers of flexibility, judgement and discretion are critical to the successful execution of the policy.
In framing the policy, the committee has taken care to ensure that these important powers continue to be available:
•Sufficient flexibility to take account of future changes in the industry environment and in remuneration practice generally. This allows the
committee to respond to changes in circumstances, for example in applying particular performance measures and/or weightings within the
plans, or in broadening the comparator group for the relative returns measure, in order to evolve with the company’s strategy, without the need
for specific shareholder approval.
•Power to exercise judgement in making a qualitative assessment in certain circumstances. A number of measures are used for annual or long-
term incentive awards, many of which are numerical in nature and require a quantitative assessment of performance. Others may require a
qualitative assessment, such as the strategic progress measures in the performance share plan.
•Scope for the committee to exercise discretion, mainly where it is desirable to vary a formulaic outcome that would otherwise arise from the
policy’s implementation. The committee considers that the ability to exercise discretion, upwards or downwards, is important to ensure that a
particular outcome is fair in light of the director’s own performance, the company’s overall performance and positioning under particular
performance measures and outcomes for shareholders.
The committee may make minor amendments to the remuneration policy to aid its operation or implementation without seeking shareholder
approvals (e.g. for regulatory, exchange control, tax or administrative purposes or to take account of a change in legislation).
The committee intends to provide appropriate disclosure on the use of flexibility, judgement and discretion so that shareholders can understand
the basis for its decisions.
bp Annual Report and Form 20-F 2025 | 121 |
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Corporate governance | ||||
4. How will we safeguard against payments for failure?
Performance-based pay | A significant portion of remuneration varies with performance – where performance targets are not achieved, lower or no payments will be made under the plans. | ||
Discretion | The committee may vary formulaic outcomes where these do not suitably reflect performance or other circumstances over the relevant performance period. | ||
Malus and clawback | The robust malus provisions enable the committee to reduce the size of award, cancel an unvested award, or impose further conditions on an award made under this policy, while the robust clawback provisions enable the committee to require participants to return some or all of an award after payment or vesting. The following events will trigger the application of either malus or clawback: •Material failure impacting safety or environmental sustainability. •Material damage to the reputation of the group, or conduct by a participant which results in or is reasonably likely to result in such material damage. •Incorrect award outcomes due to miscalculation or based on incorrect information. •Restatement due to financial reporting failure or misstatement of audited results. •Material misconduct by a participant. •Fraud effected by or with the knowledge of a participant. In addition, the following events will trigger the application of malus, where the event takes place prior to the vesting or payment of an award: •Material downturn in financial performance of the group, or any part of it. •Conduct effected by or with the knowledge of a participant which resulted in significant losses to the group, or any part of it. •Such other exceptional circumstances that the committee consider to be similar in nature. The company also operates a mandatory clawback policy that complies with the US Securities and Exchange Commission (SEC) requirements. | ||
122 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
5. Differences from remuneration policy in the wider group
This executive director remuneration policy is structurally similar to remuneration for the majority of the wider workforce, but naturally differs in
quantum, reflecting market norms for the differing size and complexity of roles, see page 96 for more detail on these differences.
Illustrations of application of remuneration policy
The total remuneration opportunity for executive directors is strongly performance based and weighted to the long term. The charts below provide
scenarios for the total remuneration of each individual who is an executive director at the date the policy comes into effect, at different levels of
performance. The scenarios are calculated as prescribed by UK regulations.
Meg O’Neill | |||||||
Min | 100% | £2.1m | |||||
Mid | 26% | 23% | 51% | £7.9m | |||
Max | 15% | 26% | 59% | £13.7m | |||
SPI* | 12% | 20% | 68% | £17.7m | |||
Fixed pay Annual bonus Performance shares * 50% share price increase
Kate Thomson | |||||||
Min | 100% | £1.2m | |||||
Mid | 28% | 24% | 48% | £4.2m | |||
Max | 16% | 28% | 56% | £7.2m | |||
SPI* | 13% | 22% | 66% | £9.2m | |||
Fixed pay Annual bonus Performance shares * 50% share price increase
Due to rounding, the sum of the parts may not equal 100%.
Fixed components
For these illustrations salary, benefits and pension are the same in each scenario (annual values shown).
| ||||
CEO (O’Neill) | £1,600,000 | Meg’s salary, upon appointment | ||
CFO (Thomson) | £894,000 | Kate’s salary, effective from the 2026 AGM | ||
| ||||
CEO (O’Neill) | £458,170 | Based on cash in lieu of retirement benefits at 20% of salary, with an estimated £138k total for other benefits. | ||
CFO (Thomson) | £261,179 | Based on cash in lieu of retirement benefits at 20% of salary, with an estimated £82k total for other benefits. | ||
Variable components
Variable pay under the policy comprises annual bonus and performance shares.
Scenario | Minimum | Mid | Maximum | |||
â | â | â | ||||
(including cash and deferred elements) | Threshold not met | 50% of maximum | 100% of maximum | |||
Nil | 112.5% of salary | 225% of salary | ||||
| Threshold not met | 50% vesting | 100% vesting | |||
CEO – Nil CFO – Nil | CEO – 250% of salary CFO – 225% of salary | CEO – 500% of salary CFO – 450% of salary | ||||
bp Annual Report and Form 20-F 2025 | 123 |
| ||||
Corporate governance | ||||
Recruitment policy
The committee expects any new executive director to be engaged on terms that are consistent with the policy. However, it recognizes that it
cannot anticipate all circumstances in which any new executive director may be recruited. The committee may determine that it is in the interests
of the company and shareholders to secure the services of a particular individual which may require it to take account of the terms of that
individual’s existing employment and/or their personal circumstances.
Accordingly, the committee will consider the following:
•The salary level of any new director is appropriate to their role and the competitive environment at the time of appointment. Where appropriate,
it may appoint an individual on a lower salary (relative to any previous incumbent), then gradually increase salary levels as the individual gains
experience in the role.
•Variable remuneration will be awarded within the parameters of the policy for current executive directors.
•The committee may tailor the vesting criteria for initial incentive awards depending on the specific circumstances.
•Where an existing employee is promoted to the board, the company may honour any existing commitments including maintaining any
outstanding share awards.
•The committee would expect any new director to participate in the company pension and benefit schemes that are open to other employees
(where appropriate, referencing the candidate’s home country).
•Where an individual is relocating in order to take up the role, the company may provide certain benefits such as reasonable relocation expenses,
accommodation for a period following appointment, assistance with visa applications or other immigration issues and ongoing arrangements
such as repatriation assistance, tax filing assistance, annual flights home and a housing/utilities allowance. The company may meet any tax
charges arising on relocation benefits.
•Where an individual would be forfeiting remuneration or employment terms in order to join the company, the committee may award appropriate
compensation. The committee would require reasonable evidence of the nature and value of any forfeited arrangements and would, to the
extent practicable, ensure any compensation was of comparable commercial value and capped as appropriate, considering the terms of the
previous arrangement being forfeited (for example, the form and structure of award, timeframe, performance criteria and likelihood of vesting).
Where appropriate, the committee prefers to deliver buy-outs in the form of restricted shares in the company.
•To facilitate any share awards on recruitment, the committee may rely on the Listing Rules exemption, which permits the grant of share awards,
in unusual circumstances, to support the recruitment of an executive director, without seeking prior shareholder approval or making such
awards under any other existing share plan.
In making any decision on the remuneration of a new director, the committee would balance shareholder expectations, current best practice and
the circumstances of any new director. It would strive not to pay more than is necessary to recruit the right candidate and would give full details in
the next remuneration report.
Service contract
Meg O’Neill’s and Kate Thomson’s service contracts are with BP p.l.c.
Each executive director is entitled to retirement benefits, as outlined on page 118.
Each executive director is also entitled to the following contractual benefits:
•If appropriate for security reasons, a company car and driver is provided for business and private use, with the company bearing all normal
employment, servicing, insurance and running costs. Alternatively, where not required for security reasons, a cash allowance may be
paid instead.
•Medical and dental benefits, sick pay during periods of absence and assistance with the preparation of tax returns.
•Indemnification in accordance with applicable law.
•Participation in bonus or incentive arrangements at the committee’s sole discretion.
In line with bp’s policy on notice periods for executive directors, each executive director may terminate their employment by giving 12 months’
written notice. In this event, for business reasons, the employer may not necessarily hold the executive director to their full notice period.
The employer may lawfully terminate the executive director’s employment in the following ways:
•By giving the director 12 months’ written notice.
•Without compensation, in circumstances where the employer is entitled to terminate for cause, as defined for the purposes of their
service contract.
The company may lawfully terminate employment by making a lump sum payment in lieu of notice equal to 12 months’ salary, or by monthly
instalments rather than as a lump sum.
The lawful termination mechanisms described above are without prejudice to the employer’s ability in appropriate circumstances to terminate in
breach of the notice period referred to above, and thereby to be liable for damages to the executive director.
In the event of termination by the company, each executive director may have an entitlement to compensation in respect of their statutory rights
under employment protection legislation in the UK and potentially elsewhere. Where appropriate, the company may also meet a director’s
reasonable legal expenses in connection with either their appointment or termination of their appointment.
Copies of the executive directors’ service contracts, along with the non-executive director appointment letters, are available for inspection at the
registered office of BP p.l.c.
124 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Directors’ remuneration report continued | ||
Termination payments
In determining overall termination arrangements, the committee will distinguish between types of leaver and the circumstances of their leaving.
The committee would also consider all relevant circumstances, including whether a contractual provision in the director’s arrangements complied
with best practice at the time of termination and the date the provision was agreed, as well as the performance of the director in certain respects.
Where appropriate, the committee may consider providing certain benefits relating to termination including the provision of outplacement support
or reasonable costs associated with relocation back to an individual’s home country. Should it become necessary to terminate an executive
director’s employment, and therefore to determine a termination payment, the committee’s policy is as follows:
Termination payments | The director’s primary entitlement would be a termination payment in respect of their service agreement, as set out above. However the committee will consider mitigation to reduce the termination payment where appropriate to do so, taking into account the circumstances for leaving and the terms of the agreement. Mitigation would not be applicable where a contractual payment in lieu of notice is made. | If the departing director is eligible for an early retirement pension, the committee would consider, if relevant under the terms of the appropriate plan, the extent of any actuarial reduction that should be applied. UK directors who leave in circumstances approved by the committee may have a favourable actuarial reduction applied to their pensions (which to date has been 3%). Departing directors who leave in other circumstances may be subject to a greater reduction. | |
Annual bonus | The committee would consider whether the director should be entitled to an annual bonus in respect of the financial year in which the termination occurs. | Normally, any such bonus would be restricted to the director’s actual period of service in that financial year and would be subject to deferral unless the committee determines otherwise. | |
Share awards | Share awards will be treated in accordance with the relevant plan rules. For awards granted under the executive directors’ incentive plan (EDIP), the treatment can only be made in accordance with the framework approved by shareholders. The committee would consider whether conditional share awards held by the director should lapse on leaving or should, at the committee’s discretion, be preserved. If awards are preserved, the award would normally continue until the vesting date. Awards may be pro-rated based on service over the performance period. | In deciding whether to exercise discretion to preserve EDIP awards, the committee would also consider the proximity of the award to its maturity date. To the extent that any such share award vests, the release of those shares to the former director will normally be made approximately one year after their date of termination (even if they would have been subject to a longer holding period had the executive remained in employment with bp). |
Remuneration in the wider group
The committee considers employment conditions in the bp group when establishing and implementing policy for executive directors to ensure the
alignment of and context for principles and approach. In particular, the committee reviews the policy and makes decisions for the most senior
leaders (the bp leadership team that reports to the CEO). Decisions regarding remuneration for employees outside the most senior leaders are the
responsibility of the chief executive officer. The committee does not consult directly with employees when formulating the policy. However,
feedback from employee focus groups and employee surveys, that are regularly reported to the board, provide views on a wide range of employee
matters including pay.
The wider employee group participates in performance-based incentives. Throughout the group, salary and benefit levels are set in accordance
with the prevailing relevant market conditions and practice in the countries in which employees are based. Differences between executive director
pay policy and that of other employees reflect the senior position of the individuals, prevailing market conditions and corporate governance
practices in respect of executive director remuneration. The key difference in policy for executive directors is that a greater proportion of total
remuneration is delivered as performance-based incentives.
Engaging with shareholders
The committee carefully considers shareholder feedback each year and this input has been instrumental in shaping the current remuneration
policy. As outlined in the chair’s letter, for the 2026 policy review, over 40% of bp’s shareholder register were consulted and the vast majority
expressed support for broadly retaining the 2023 policy. The committee remains committed to maintaining an open and constructive dialogue
with shareholders and will continue to consult before introducing any material changes to the remuneration policy.
bp Annual Report and Form 20-F 2025 | 125 |
| ||||
Corporate governance | ||||
Policy table – non-executive directors
The following table sets out the framework that will be used to determine the fees for non-executive directors during the term of this policy.
Non-executive chair | ||
Fees | ||
Approach | Remuneration is in the form of fees. Fees are currently paid in cash but the company may pay part or all of the fees in the form of shares. The level and structure of the chair’s fee will primarily be compared against UK best practice. | |
Operation and opportunity | The quantum and structure of the non-executive chair’s fee is reviewed annually by the remuneration committee, which makes a recommendation to the board. | |
Benefits and expenses | ||
Approach | The chair is provided with support and reasonable travelling expenses. | |
Operation and opportunity | The chair is provided with an office and full-time secretarial and administrative support in London and a contribution to an office and secretarial support in his home country as appropriate. A car and the use of a driver is provided in London, together with security assistance. All reasonable travelling and other expenses (including any relevant tax) incurred in carrying out his duties are reimbursed. | |
Non-executive directors | ||
Fees | ||
Approach | Remuneration is in the form of fees. Fees are currently paid in cash but the company may pay part or all of the fees in the form of shares. Remuneration practice is consistent with recognized best practice standards for non-executive directors and, as a UK-listed company, the level and structure of non-executive directors’ remuneration will primarily be compared against UK best practice. Additional fees may be payable to reflect additional board responsibilities, for example, committee chairship and membership and for the role of senior independent director. | |
Operation and opportunity | The level and structure of non-executive directors’ remuneration is reviewed by the chair, the CEO and the company secretary, who make a recommendation to the board. Non-executive directors do not vote on their own remuneration. Fee levels for non-executive directors are reviewed annually. | |
Benefits and expenses | ||
Approach | Non-executive directors are provided with administrative support and reasonable travelling expenses. Professional fees are reimbursed in the form of cash, payable following the provision of advice and assistance. | |
Operation and opportunity | Non-executive directors are reimbursed for all reasonable travelling and subsistence expenses (including any relevant tax) incurred in carrying out their duties. Professional fees incurred by non-executive directors based outside the UK in connection with advice and assistance on UK tax compliance matters are reimbursed. | |
Shareholding guidelines | ||
Approach | Chair and non-executive directors are encouraged to establish a holding in bp shares of the equivalent value of one year’s base fee. | |
Letters of appointment for chair and non-executive directors | ||
Approach | The chair and non-executive directors each have letters of appointment. There is no term limit on a director’s service, as bp proposes all directors for annual re-election by shareholders. There are no obligations arising from the non-executive directors’ letters of appointment for remuneration or payments for loss of office, except for the chair whose appointment may be terminated in the following ways: •By either party giving three months’ written notice, or •By the company for cause (as set out in the letter of appointment) and without compensation. The company may lawfully terminate the appointment by making a lump sum payment in lieu of notice equal to three months’ fees. Copies of the executive directors’ service contracts and non-executive directors’ letters of appointment are available for inspection at the registered office of the company. | |
The maximum fees for non-executive directors are set in accordance with the Articles of Association.
126 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Other disclosures | ||
Appointment and succession plans
The chair, senior independent director (SID) and
other independent non-executive directors (NEDs)
each have letters of appointment with BP p.l.c. and
do not serve, nor are they employed, in any
executive capacity by bp. In line with the UK
Corporate Governance Code (Code), all continuing
directors are subject to annual re-election by
shareholders at the Annual General Meeting (AGM),
where letters of appointment for each NED are
available for inspection. Details on the skills and
experience of each director seeking election or re-
election, as well as their individual contributions to
the long-term success of the company, are set out
in the Notice of AGM. In accordance with the Code,
NEDs would not be expected to serve beyond nine
years unless there are exceptional circumstances.
On behalf of the board, the people, culture and
governance committee reviews the formal
appointment process and succession plans for the
board. Appointments and succession plans are
both based on merit and assessed against
objective criteria with the promotion of diversity,
equity and inclusion as central considerations. This
includes diversity of gender, social and ethnic
backgrounds as well as cognitive and personal
strengths. In reviewing appointments and
succession plans, due consideration is given to
ensure the smooth transition of board members
with specific responsibilities (e.g. committee chair
roles) by allowing sufficient time for a detailed
handover. This is balanced by the need to have new
board members join at regular intervals such that,
over time, there is a controlled approach to board
members reaching the end of their tenure. All new
directors receive a formal induction, tailored to
their individual needs, skills and experience, taking
account of any committees they join. These
inductions include one-to-one meetings with
members of the board and leadership team
together with select members of senior
management. Feedback is sought from directors
undertaking their induction programmes to ensure
they are continually updated and improved.
Further detail on board succession and tenure can
be found in the people, culture and governance
committee report on page 89 and board
composition disclosure on page 72, respectively.
Time commitments
The expectation regarding time commitment for
NEDs to effectively discharge their duties is set out
in the directors’ letters of appointment. The time
commitment varies with the demands of bp
business and other events. The NEDs’ external time
commitments – whether through executive, non-
executive, advisory or other roles – are regularly
reviewed by the company secretary to ensure that
directors are able to allocate appropriate time to
bp. A register of directors’ time commitments and
conflicts is maintained and is also reviewed
annually by the people, culture and governance
committee. The review process takes into account
outside appointments and other external
commitments and considers the complexity of the
organization, the nature of the role, the sector
(especially regulated and/or potentially competing
sectors) and any leadership roles (e.g. a chair
position). NEDs are also required to consult with
the company secretary and chair before accepting
any other role that may impact their ability to
commit appropriate time to bp. The process for the
approval of any new external appointment,
significant or otherwise, for an existing director
assesses the impact of that appointment on the
director’s time in order to ensure the director has
sufficient capacity for their role with bp. As part of
that same review process, a review of
independence and potential conflicts of interest is
undertaken, taking account of institutional investor
and proxy advisor guidance and market best
practice. Any external proposed commitments that
could exceed the mandates set out in such
guidance are given particular consideration. The
board was satisfied that significant appointments
undertaken during 2025 did not impact the
directors’ ability to prepare for and attend
meetings, engage with stakeholders and
participate in learning and development
opportunities. The board has concluded that,
notwithstanding external appointments held, each
director is able to dedicate sufficient time to fulfil
their bp duties. In compliance with the Code, none
of the executive directors who served during 2025
held more than one non-executive directorship in a
FTSE 100 company or other significant
appointment throughout their tenure on the board.
For more information on the external
commitments of bp’s directors, see pages 73-75.
For information on board meetings held during
2025 and director attendance at board meetings,
see page 75.
Independence and conflicts
of interest
All directors have a statutory duty to exercise
independent judgement. Independence of NEDs is
crucial in bringing constructive challenge to the
chief executive officer (CEO) and the leadership
team at board meetings, while providing support
and guidance to promote meaningful discussion
and, ultimately, informed and effective decision-
making. In accordance with the criteria set out in
the Code, the chair was considered independent at
the time he was appointed. NEDs are required to
provide sufficient information to allow the board to
evaluate their independence prior to and following
their appointment. In addition, each director has a
statutory duty to disclose actual or potential
conflicts of interest. Formal procedures are in
place for new potential conflicts to be reported
and recorded during the year. As a consequence of
regular reviews in 2025, the board is satisfied that
there were no matters giving rise to conflicts of
interest which could not be authorized by the
board. It has therefore concluded that all bp NEDs
are independent.
Reporting in line with UK Listing
Rule 6.6.6R(9)
As at 31 December 2025, 46% of the board
comprises women, our senior independent
director (SID), chief executive officer (CEO), chief
financial officer (CFO) are women and three
directors identify as from an ethnic minority
background. Data for the below tables is
collected on an annual basis through a
standardized process under which each member
of the board and executive management is asked
to self-declare, or elect not to declare, their ethnic
background and gender identity or sex. The
information is correct as at 31 December 2025.
For the purposes of this table, executive
management includes bp’s leadership team
and the company secretary.
Gender identity or sex | Number of board members | Percentage of the board | Number of senior positions on the board (CEO, CFO, SID and chair) | Number in executive management | Percentage of executive management |
Men | 7 | 54% | 1 | 5 | 55% |
Women | 6 | 46% | 3 | 4 | 45% |
Other categories | – | – | – | – | – |
Not specified/prefer not to say | – | – | – | – | – |
Ethnic background | |||||
White British or other white (including minority-white groups) | 10 | 77% | 100% | 7 | 78% |
Mixed/Multiple Ethnic Groups | – | – | – | – | – |
Asian/Asian British | 3 | 23% | – | 1 | 11% |
Black/African/Caribbean/Black British | – | – | – | 1 | 11% |
Other ethnic group | – | – | – | – | – |
Not specified/prefer not to say | – | – | – | – | – |
bp Annual Report and Form 20-F 2025 | 127 |
| ||||
Corporate governance | ||||
Pages 127-128 have been removed as they do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
128 | bp Annual Report and Form 20-F 2025 | « See glossary on page 375 |
Pages 127-128 have been removed as they do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2025 | 129 |
| ||||
Financial statements | ||||
Consolidated financial statements of the bp group | ||||||||
Independent auditor's reports (PCAOB ID | 149 | Group statement of changes in equity | 157 | |||||
Group income statement | 155 | Group balance sheet | 158 | |||||
Group statement of comprehensive income | 156 | Group cash flow statement | 159 | |||||
Notes on financial statements | ||||||||
1. | Significant accounting policies | 160 | 22. | Trade and other payables | 203 | |||
2. | Non-current assets held for sale | 181 | 23. | Provisions | 204 | |||
3. | Business combinations | 182 | 24. | Pensions and other post-employment benefits | 205 | |||
4. | Disposals and impairment | 182 | ||||||
5. | Segmental analysis | 185 | 25. | Cash and cash equivalents | 211 | |||
6. | Sales and other operating revenues | 189 | 26. | Finance debt | 211 | |||
7. | Income statement analysis | 189 | 27. | Capital disclosures and net debt | 212 | |||
8. | Exploration for and evaluation of oil and natural gas resources | 190 | 28. | Leases | 213 | |||
29. | Financial instruments and financial risk factors | 214 | ||||||
9. | Taxation | 190 | ||||||
10. | Dividends | 193 | 30. | Derivative financial instruments | 219 | |||
11. | Earnings per share | 193 | 31. | Called-up share capital | 228 | |||
12. | Property, plant and equipment | 195 | 32. | Capital and reserves | 230 | |||
13. | Capital commitments | 196 | 33. | Contingent liabilities and legal proceedings | 236 | |||
14. | Goodwill | 196 | 34. | Remuneration of senior management and non-executive directors | 238 | |||
15. | Intangible assets | 198 | ||||||
16. | Investments in joint ventures | 199 | 35. | Employee costs and numbers | 239 | |||
17. | Investments in associates | 201 | 36. | Auditor's remuneration | 239 | |||
18. | Other investments | 202 | 37. | Subsidiaries, joint arrangements and associates | 240 | |||
19. | Inventories | 202 | ||||||
20. | Trade and other receivables | 202 | ||||||
21. | Valuation and qualifying accounts | 203 | ||||||
Supplementary information on oil and natural gas (unaudited) | ||||||||
Oil and natural gas exploration and production activities | 242 | Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves | 263 | |||||
Movements in estimated net proved reserves | 248 | |||||||
Operational and statistical information | 266 | |||||||
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
130 | bp Annual Report and Form 20-F 2025 |
Consolidated financial statements of the bp group
| ||||
Financial statements | ||||
Pages 130-148 have been removed as they do not form part of bp's Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2025 | 149 |
| ||||
Financial statements | ||||
Report of Independent Registered Public Accounting Firm
To the shareholders and board of directors of BP p.l.c.
Opinion on the financial statements
We have audited the accompanying consolidated group balance sheets of BP p.l.c. and subsidiaries (together ‘bp’ or ‘the group’) as at 31 December
2025 and 2024, the related consolidated group income statements, group statements of comprehensive income, group statements of changes in
equity and group cash flow statements, for each of the three years in the period ended 31 December 2025, and the related notes (collectively
referred to as the ‘financial statements’). In our opinion, the financial statements present fairly, in all material respects, the financial position of the
group as at 31 December 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended
31 December 2025, in accordance with United Kingdom adopted international accounting standards and IFRS Accounting Standards as issued by
the International Accounting Standards Board (IASB) and as adopted by the European Union (EU).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), bp's internal
control over financial reporting as of 31 December 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by
the Committee of Sponsoring Organizations of the Treadway Commission and our report dated 6 March 2026 expressed an unqualified opinion on
bp's internal control over financial reporting.
Basis for opinion
These financial statements are the responsibility of bp’s management. Our responsibility is to express an opinion on bp’s financial statements
based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to bp in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included
performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing
procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in
the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as
well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were
communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the
financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters
does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters
below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
1.Impairment of upstream oil and gas property, plant and equipment (PP&E) assets – Notes 1, 4 and 12 to the financial statements
Critical Audit Matter Description
The group balance sheet as at 31 December 2025 includes PP&E, of which $55 billion is oil and gas properties.
Management’s best estimate oil and gas price assumptions for value-in-use impairment tests were revised in 2025 as set out in Note 1 on pages
168-169.
Management has also determined bp’s ‘best estimate’ discount rate assumptions, as set out in Note 1 on page 168. bp’s post-tax discount rate used
for impairment testing for oil and gas assets in 2025 remained unchanged from prior year at 8%. Pre-tax discount rates applied in impairment tests
were revised in some regions to reflect changes in local tax rates and country risk premiums. Reserves estimates for all oil and gas fields were also
reviewed and updated where necessary at year-end.
As required by International Accounting Standard (IAS) 36 ‘Impairment of Assets’, management performed a review of all oil and gas cash
generating units (CGUs) for indicators of impairment and impairment reversal as at 31 December 2025. As a result of management identifying
impairment indicators during 2025, $1 billion of oil and gas CGU net impairment charges were recognised, principally due to an increase in certain
capital expenditure forecasts and operating expenditure forecasts and certain reserves write downs.
We identified three key management estimates in management’s determination of the level of impairment charge and/or impairment reversal.
These are:
Oil and gas prices – bp’s oil and gas price assumptions have a significant impact on many CGU impairment assessments performed across
the OP&O and G&LCE segments and are inherently uncertain. The estimation of future prices is subject to increased uncertainty given climate
change, the global energy transition, macro-economic factors and disruption in global supply due to ongoing geo-political conflicts. There is a
risk that management do not forecast reasonable ‘best estimate’ oil and gas price forecasts when assessing CGUs for impairment charge
and/or impairment reversal, leading to material misstatements. These price assumptions are highly judgmental and are pervasive inputs to
bp’s oil and gas CGU valuation. There is also a risk that management’s oil and gas price related disclosures are not reasonable.
Discount rates – Given the long timeframes involved, certain CGU impairment assessments are sensitive to the discount rate applied.
Discount rates should reflect the return required by the market and the risks inherent in the cash flows being discounted. There is a risk that
management does not assume reasonable discount rates, adjusted as applicable for country risks and relevant tax rates, leading to material
misstatements. Determining a reasonable discount rate is highly judgmental and, consistent with price assumptions above, the discount rate
assumption is also a pervasive input across bp’s oil and gas CGU valuations, before adjustments for asset specific risks and tax rates.
Reserves and resources estimates – A key input to certain CGU impairment assessments is the oil and gas production forecast, which is
based on underlying reserves estimates and field specific development assumptions. Certain CGU production forecasts include specific risk
adjusted resource volumes, in addition to proven and/or probable reserves estimates, that are inherently less certain than reserves;
assumptions related to these volumes can be particularly judgemental. There is a risk that material misstatements could arise from
unreasonable production forecasts for individually material CGUs and/or from the aggregation of systematic flaws in bp’s reserves and
resources estimation policies across the OP&O and G&LCE segments.
150 | bp Annual Report and Form 20-F 2025 |
We identified certain individual CGUs which we determined would be most at risk of material impairment charges as a result of a reasonably
possible change in the oil and gas price assumptions. This population includes previously impaired assets which are also at risk of material
impairment reversal resulting from potential oil and gas price assumption changes. We identified that a subset of these CGUs was also individually
materially sensitive to the discount rate assumption. Further information regarding these sensitivities is given in Note 1 on page 169.
Impairment charge and/or impairment reversal assessments of upstream oil and gas PP&E assets remain a critical audit matter because
recoverable values are reliant on forecast assumptions such as oil and gas prices, discount rates and reserves estimates, which are inherently
judgemental and complex for management to estimate and challenging to audit. Additionally, the magnitude of the potential misstatement risk
remains material to the group.
How the Critical Audit Matter was addressed in the Audit
We tested relevant internal controls over the estimation of oil and gas prices, discount rates, and reserve and resources estimates, as well as
relevant internal controls over the performance of the impairment charge and/or impairment reversal assessments where we identified audit risks.
In addition, we conducted the following substantive procedures.
Oil and gas prices
•We independently developed a reasonable range of forecasts based on external data obtained, against which we compared management’s oil
and gas price assumptions in order to challenge whether they are reasonable.
•In developing this range, we obtained a variety of reputable and reliable third-party forecasts, peer information and other relevant market data.
•In challenging and evaluating management’s price assumptions, we considered the extent to which they and each of the forecast pricing
scenarios obtained from third parties reflect the impact of lower oil and gas demand due to climate change and the energy transition.
•The 2015 Conference of the Parties (CoP) 21 Paris Agreement goals of ‘holding the increase in the global average temperature to well below 2°C
above pre-industrial levels and pursuing efforts to limit the temperature increase to 1.5°C above pre-industrial levels’ was reaffirmed at CoP 30
in Brazil during November 2025. We specifically analysed third party forecasts stated, or interpreted by us, as being consistent with scenarios
achieving the Paris ‘well below 2°C goal’ and/or ‘1.5°C ambition’ and evaluated whether they presented contradictory audit evidence.
•We assessed management’s disclosures in Note 1, including the sensitivity of forecast revenue cash inflows to lower oil and gas prices, and how
climate change and the energy transition, potential future emissions costs and/or reduced demand scenarios may impact bp to a greater extent
than currently anticipated in bp’s value-in-use estimates for oil and gas CGUs.
Discount rates
•We independently evaluated bp’s discount rates used in impairment tests with input from our valuation specialists, against relevant third-party
market and peer data.
•When performing procedures over specific assets, we assessed whether specific country risks and tax adjustments were reasonably reflected in
bp’s discount rates.
•We challenged and evaluated management’s disclosures in Note 1, including in relation to the sensitivity of discount rate assumptions.
Reserves and resources estimates
Using the outputs from our data analytics tools which we used to visualise reserves and resources volumes, and with the assistance of our oil and
gas reserves specialists, we:
•assessed bp’s reserves and resources estimation methods and policies for reasonableness;
•assessed how these policies had been applied to a sample of bp’s reserves and resources estimates;
•read and evaluated a sample of reports provided by management’s external reserves experts and assessed the scope of work and findings of
these third parties;
•assessed the competence, capability and objectivity of bp’s internal and external reserve experts, through understanding their relevant
professional qualifications and experience;
•assessed whether management’s production forecasts are consistent overall with bp’s strategy;
•compared the production forecasts used in the impairment tests with management’s approved reserves and resources estimates; and
•performed a retrospective assessment in order to assess management's ability to accurately estimate reserves and resources and to check for
indications of estimation bias over time.
2.Decommissioning provisions – Notes 1 and 23 to the financial statements
Critical Audit Matter Description
A decommissioning provision of $12.3 billion is recorded in the financial statements as at 31 December 2025. The estimation of decommissioning
provisions is a highly judgemental area as it involves a number of key estimates related to the cost and timing of decommissioning, in particular
inflation and discount rate assumptions.
Management estimates that the average rate of forecast inflation applicable to the substantial majority of bp’s decommissioning cost estimates is
1.5%, which is 0.5% lower than its estimated long term general inflation rate of 2%.
The estimated undiscounted cost of the obligations and the timing of future payments are set out in Note 1 on page 176. Economic factors, future
activities and the legislative environments that bp operates in are used to inform cost estimates, whereas the timing of decommissioning activities
is dependent on cessation of production (CoP) dates, which are sensitive to changes in bp’s price forecasts as price estimates determine economic
cut off of oil and gas reserve estimates.
bp maintained the discount rate used in calculating its decommissioning provisions at 4.5% as at 31 December 2025.
bp Annual Report and Form 20-F 2025 | 151 |
| ||||
Financial statements | ||||
How the Critical Audit Matter was addressed in the Audit
Long term inflation rate
•We tested the relevant control related to the determination of the decommissioning specific inflation rate assumption.
•We tested how management derived the decommissioning specific inflation rate assumption of 1.5%, and the evidence on which it is based, by
gaining an understanding of the process used by management, testing management’s calculations of the assumption, and evaluating the
evidence relevant to management’s assumption, both supporting and contradictory.
•As the 1.5% decommissioning specific inflation rate assumption is determined by making an adjustment to management’s 2.0% general long
term inflation rate assumption, we evaluated the general long term inflation rate assumption used of 2.0%, comparing it against latest external
market data.
•We made inquiries and evaluated the competence, capability and objectivity of management’s decommissioning experts who derived the
decommissioning specific inflation rate.
•We inspected analyst forecasts and reports in respect of the future decommissioning market and related costs for evidence of supporting and
contradictory evidence, with particular focus on the future rig market.
•We particularly considered the expectation that demand for oil and gas products and related activities will decrease, primarily in response to
climate change and energy transition effects pivoting future energy industry investment and development activity towards renewable sources.
We challenged and evaluated management’s assessment of the impact this will have on the decommissioning market and the related inflation
assumption.
•We analysed historical trends of rig market rates against oil prices and historical inflation to evaluate management’s assumption that the
decommissioning inflation assumption does not inflate at the same rate as general inflation.
Cost and timing estimates
•We tested the relevant controls over the year end decommissioning cost and timing assumptions used within management’s decommissioning
provision estimate.
•We assessed the completeness and accuracy of the assets subject to decommissioning, including understanding the process to establish
whether a legal or constructive obligation existed.
•We gained an understanding of the process and technology used to model the provision, including the use of bp’s decommissioning modelling
platform by management’s experts. We used data analytics to automatically extract and analyse cost estimate data to identify the key cost
assumptions which the decommissioning model is most materially sensitive to.
•We evaluated the reasonableness of changes in the key cost assumptions including rig rates, vessel rates, well plug and abandonment duration
and non-productive time assumptions, with reference to internal and appropriate third-party data.
•We assessed changes in assumptions for the estimated date of decommissioning and evaluated whether CoP dates used for decommissioning
estimation are aligned with CoP assumptions in other areas, including PP&E impairment testing and oil and gas reserve estimation.
•We assessed the accuracy of bp’s disclosure of the estimated undiscounted cost of its obligations and the timing of future decommissioning
payments.
Discount rates
•We tested the relevant controls related to the determination of the discount rate assumption.
•We assessed the reasonableness of management’s methodology for determining the discount rate and recalculated the discount rate with
reference to independent third-party data, most notably US treasury bond yields.
3.Valuation of commodity financial derivatives - Notes 1, 29 and 30 to the financial statements
Critical Audit Matter Description
bp’s supply, trading and shipping (ST&S) function is responsible for globally trading and risk managing the group’s owned production as well as
third party production. To discharge this responsibility, ST&S regularly executes commodity contracts, physically settled or otherwise, which are
accounted for as a derivative and fair valued under IFRS 9. These contracts, therefore, result in unrealised gains/losses that are recognised on
account of fair value movements in the associated derivative assets and liabilities.
Determining the fair value of derivative assets and liabilities can be complex and subjective, particularly where the valuation is dependent on
significant inputs which are not observable and are classified as level 3 in the fair value hierarchy set out in IFRS 13. This degree of subjectivity also
makes such fair value estimates liable to potential fraud by management incorporating bias in the inputs used in determining fair values. Given the
significant judgements, sensitivity to management assumptions, and the absolute value associated with these positions, we have identified a risk in
respect of certain financial instruments where the valuation is dependent on significant unobservable inputs.
Fair value measurements associated with unrealised commodity contracts are also impacted by the macroeconomic sentiment and outlook. In
2025, commodity markets continued to experience periods of volatility due to continuing uncertainty resulting from the planned energy transition,
macro-economic factors such as inflation and interest rates, and disruptions in global supply due to geopolitical conflicts. In response to the
volatility observed, we focused our audit efforts on the valuation of commodity derivatives and designed procedures to test for management bias.
As at 31 December 2025, the group’s total level 3 derivative financial assets were $20.1 billion and level 3 derivative financial liabilities were $18.2
billion.
How the Critical Audit Matter was addressed in the Audit
In response to the above, we analysed the population of these instruments to assess the level of unobservability of the inputs used in their
valuation and then further disaggregated the population into different risk populations which in turn drove the nature, timing and extent of our
audit procedures.
Our use of advanced data analytics tools enabled automated visualisation of valuation data providing insights into trading positions and price
curves. This allowed us to identify unusual trends, and focus our audit efforts on complex inputs, methodologies, and anomalies within the
significant volume of derivative contracts, thereby enhancing the precision and the effectiveness of our valuation testing and our assessment of
potential management bias.
152 | bp Annual Report and Form 20-F 2025 |
To address the complexities associated with auditing the valuation of instruments dependent on significant unobservable inputs, we included
valuation specialists with significant quantitative and modelling expertise to assist in performing our audit procedures. Our valuation audit work
included the following control and substantive procedures:
•We tested the group’s valuation relevant controls including:
–the model certification control, which is designed to review a model’s theoretical soundness and the appropriateness of its valuation
methodology; and
–the independent price verification control, which is designed to review the appropriateness of valuation inputs that are not observable and are
significant to the financial instrument’s valuation.
•We performed valuation testing procedures at interim and year-end balance sheet dates, including:
–evaluating management’s valuation methodologies against standard valuation practice and analysing whether a consistent framework is
applied across the business period over period;
–engaging our valuation specialists to challenge models, develop fair value estimates and evaluate consistency in management’s modelling and
input assumptions throughout the year;
–comparing management’s input assumptions against the expected assumptions of other market participants and observable market data;
–independently validating price points on pricing curves; and
–analysing whether there was any indication of management bias through evaluating the distribution of valuation differences where relevant.
4.Impairment of E&A assets, goodwill associated with the transition businesses and refinery PP&E as a consequence, among
other things, of climate change and the energy transition – Notes 1, 4, 8, 14 and 15 to the financial statements
Critical Audit Matter Description
Intangible Assets
The recoverability of certain of the group’s $4.0 billion total exploration and appraisal (E&A) assets capitalised as at 31 December 2025 is potentially
exposed to climate change and the global energy transition and macroeconomic risk factors (see Note 15). This is because a greater number of E&A
projects may not proceed as a consequence of the energy transition or lower forecast future oil and gas prices. The determination of whether and
when E&A costs should be written off, impaired, or retained on the balance sheet as E&A assets, remains complex and continues to require
significant management judgement.
Goodwill
The carrying value of goodwill associated with the transition businesses, specifically Archaea Energy and Lightsource bp, may no longer be
recoverable due to increases in cost or lower forecast production or development rate reflecting the slowdown in the pace of energy transition
adversely impacting the value of these projects, and impacting investment decisions. Management performed an annual impairment test (which
includes judgements in relation to forecast period, development rate, long term growth rate, discount rate, developer margin, capital expenditure
and renewable natural gas revenue prices) to assess the recoverability of the goodwill, resulting in an impairment of $2.0 billion as disclosed in
Note 14.
PP&E
The carrying value of bp’s refining assets within PP&E may no longer be recoverable due to changes in supply and demand which arise among other
things as a consequence of climate change and the energy transition. Management performed an assessment to identify potential impairment
indicators in respect of the refinery portfolio. This considered all potential impairment indicators, including refining margin forecast, which could be
impacted by changes in supply and demand due to climate change and the energy transition. As a result of management’s impairment assessment,
management identified indicators of impairment within the refining portfolio as at 31 December 2025 and concluded that no impairment charge
needed to be recorded.
How the Critical Audit Matter Was Addressed in the Audit
Intangible Assets
In respect of the recoverability of E&A assets capitalised as at 31 December 2025:
•We tested the relevant controls within the group’s E&A write-off and impairment assessment processes; and
•We challenged and evaluated management’s key E&A judgements with regards to the impairment criteria of IFRS 6. Where impairment
indicators were identified, we corroborated key judgements with internal and external evidence for assets that remained on the balance sheet.
This included analysing evidence of future E&A plans, budgets and capital allocation decisions, assessing management’s key accounting
judgement papers, reading meeting minutes and assessing licence documentation and evidence of active dialogue with partners and regulators
including negotiations to renew licences or modify key terms.
Goodwill
In respect of the impairment tests performed on goodwill associated with the transition businesses, specifically Archaea Energy and Lightsource
bp, performed at 31 December 2025:
•We tested the relevant controls over the impairment tests including controls over key assumptions;
•We independently evaluated bp’s discount rates used in impairment tests with input from our valuation specialists, against relevant third- party
market and peer data;
•We independently evaluated the long-term production rates for certain transition businesses with input from our Deloitte Landfill Production
Specialists;
bp Annual Report and Form 20-F 2025 | 153 |
| ||||
Financial statements | ||||
•We evaluated the appropriateness of other key assumptions including forecast period, development rate, long term growth rate, discount rate,
developer margin, capital expenditure, and renewable natural gas revenue prices through assessment of bp’s future plans and consistency with
the capital frame; and
•We tested the mechanical accuracy of the impairment models.
PP&E
In relation to the refinery impairment tests performed by management, our audit procedures included:
•Evaluating the valuation methodology and testing the integrity and mechanical accuracy of the impairment models;
•Assessing the appropriateness of key assumptions and inputs to the impairment models, notably forecast local refining marker margins,
discount rate and energy input costs;
•Challenging and evaluating management’s assumptions by reference to third party data where available and involvement of our valuation
specialists;
•Evaluating management’s ability to forecast future cash flows and margins by comparing actual results with historical forecasts; and
•Testing management’s internal controls over the impairment test and related inputs.
/s/ Deloitte LLP
London
United Kingdom
6 March 2026
We have served as bp’s auditor since 2018.
154 | bp Annual Report and Form 20-F 2025 |
Report of Independent Registered Public Accounting Firm
To the shareholders and board of directors of BP p.l.c.
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of BP p.l.c. and its subsidiaries (the group) as of 31 December 2025, based on the
criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). In our opinion, the group maintained, in all material respects, effective internal control over financial reporting as of
31 December 2025, based on the criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the
consolidated financial statements as at and for the year ended 31 December 2025, of the group and our report dated 6 March 2026 expressed an
unqualified opinion on those financial statements.
Basis for opinion
The Group’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial
reporting. Our responsibility is to express an opinion on the group’s internal control over financial reporting based on our audit. We are a public
accounting firm registered with the PCAOB and are required to be independent with respect to the group in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included
obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating
the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A
company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance
that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and
directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
/s/ Deloitte LLP
6 March 2026
bp Annual Report and Form 20-F 2025 | 155 |
| ||||
Financial statements | ||||
Group income statement
For the year ended 31 December | $ million | ||||
Note | 2025 | 2024 | 2023 | ||
Sales and other operating revenues | 6 | ||||
Earnings from joint ventures – after interest and tax | 16 | ( | |||
Earnings from associates – after interest and tax | 17 | ||||
Interest and other income | 7 | ||||
Gains on sale of businesses and fixed assets | 4 | ||||
Total revenues and other income | |||||
Purchases | 19 | ||||
Production and manufacturing expenses | |||||
Production and similar taxes | 5 | ||||
Depreciation, depletion and amortization | 5 | ||||
Net impairment and losses on sale of businesses and fixed assets | 4 | ||||
Exploration expense | 8 | ||||
Distribution and administration expenses | |||||
Profit (loss) before interest and taxation | |||||
Finance costs | 7 | ||||
Net finance (income) expense relating to pensions and other post-employment benefits | 24 | ( | ( | ( | |
Profit (loss) before taxation | |||||
Taxation | 9 | ||||
Profit (loss) for the year | |||||
Attributable to | |||||
bp shareholders | |||||
Non-controlling interests | |||||
Earnings per share | |||||
Profit (loss) for the year attributable to bp shareholders | |||||
Per ordinary share (cents) | |||||
Basic | 11 | ||||
Diluted | 11 | ||||
Per ADS (dollars) | |||||
Basic | 11 | ||||
Diluted | 11 |
156 | bp Annual Report and Form 20-F 2025 |
Group statement of comprehensive income
For the year ended 31 December | $ million | ||||
Note | 2025 | 2024 | 2023 | ||
Profit (loss) for the year | |||||
Other comprehensive income | |||||
Items that may be reclassified subsequently to profit or loss | |||||
Currency translation differencesa | ( | ||||
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of businesses and fixed assetsa | ( | ||||
Cash flow hedges marked to market | 30 | ||||
Cash flow hedges reclassified to the income statement | 30 | ( | ( | ( | |
Costs of hedging marked to market | 30 | ( | ( | ||
Costs of hedging reclassified to the income statement | 30 | ( | ( | ||
Share of items relating to equity-accounted entities, net of tax | 16, 17 | ( | ( | ( | |
Income tax relating to items that may be reclassified | 9 | ( | ( | ||
( | |||||
Items that will not be reclassified to profit or loss | |||||
Remeasurements of the net pension and other post-employment benefit liability or asset | 24 | ( | ( | ( | |
Remeasurements of equity investments | ( | ( | |||
Cash flow hedges that will subsequently be transferred to the balance sheet | 30 | ( | |||
Income tax relating to items that will not be reclassifieda | 9 | ||||
( | ( | ||||
Other comprehensive income | ( | ( | |||
Total comprehensive income | |||||
Attributable to | |||||
bp shareholders | |||||
Non-controlling interests | |||||
aSee Note 32 for further information.
bp Annual Report and Form 20-F 2025 | 157 |
| ||||
Financial statements | ||||
Group statement of changes in equitya
$ million | ||||||||||
Share capital and capital reserves | Treasury shares | Foreign currency translation reserve | Fair value reserves | Profit and loss account | bp shareholders' equity | Non-controlling interests | Total equity | |||
Hybrid bonds | Other interest | |||||||||
At 1 January 2025 | ( | ( | ( | |||||||
Profit for the year | — | — | — | — | ||||||
Other comprehensive income | — | — | ( | — | ||||||
Total comprehensive income | — | — | ( | |||||||
Dividendsb | — | — | — | — | ( | ( | — | ( | ( | |
Cash flow hedges transferred to the balance sheet, net of tax | — | — | — | ( | — | ( | — | — | ( | |
Repurchase of ordinary share capital | — | ( | — | — | ( | ( | — | — | ( | |
Share-based payments, net of tax | — | — | ( | — | — | |||||
Share of equity-accounted entities’ changes in equity, net of tax | — | — | — | — | — | — | ||||
Issue of perpetual hybrid bonds | — | — | — | — | — | |||||
Redemption of perpetual hybrid bonds, net of tax | — | — | — | — | ( | — | ( | |||
Payments on perpetual hybrid bonds | — | — | ( | — | — | ( | ( | — | ( | |
Transactions involving non-controlling interests, net of tax | — | — | — | — | ( | ( | — | |||
At 31 December 2025 | ( | ( | ( | |||||||
At 1 January 2024 | ( | ( | ||||||||
Profit for the year | — | — | — | — | ||||||
Other comprehensive income | — | — | ( | ( | ( | — | ( | ( | ||
Total comprehensive income | — | — | ( | ( | ||||||
Dividendsb | — | — | — | — | ( | ( | — | ( | ( | |
Cash flow hedges transferred to the balance sheet, net of tax | — | — | — | ( | — | ( | — | — | ( | |
Repurchase of ordinary share capital | — | — | — | — | ( | ( | — | — | ( | |
Share-based payments, net of tax | — | — | ( | — | — | |||||
Issue of perpetual hybrid bonds | — | — | — | — | ( | ( | — | |||
Redemption of perpetual hybrid bonds, net of tax | — | — | — | — | ( | — | ( | |||
Payments on perpetual hybrid bonds | — | — | — | — | ( | — | ( | |||
Transactions involving non-controlling interests, net of tax | — | — | — | — | — | |||||
At 31 December 2024 | ( | ( | ( | |||||||
At 1 January 2023 | ( | ( | ( | |||||||
Profit for the year | — | — | — | — | ||||||
Other comprehensive income | — | — | ( | ( | — | ( | ||||
Total comprehensive income | — | — | ||||||||
Dividendsb | — | — | — | — | ( | ( | — | ( | ( | |
Cash flow hedges transferred to the balance sheet, net of tax | — | — | — | ( | — | ( | — | — | ( | |
Repurchase of ordinary share capital | — | — | — | — | ( | ( | — | — | ( | |
Share-based payments, net of tax | — | — | ( | — | — | |||||
Share of equity-accounted entities’ changes in equity, net of tax | — | — | — | — | — | — | ||||
Issue of perpetual hybrid bonds | — | — | — | — | ( | ( | — | |||
Payments on perpetual hybrid bonds | — | — | ( | — | — | ( | ( | — | ( | |
Transactions involving non-controlling interests, net of tax | — | — | — | — | — | ( | ||||
At 31 December 2023 | ( | ( | ||||||||
aSee Note 32 for further information.
bSee Note 10 for further information.
158 | bp Annual Report and Form 20-F 2025 |
Group balance sheet
At 31 December | $ million | |||
Note | 2025 | 2024 | ||
Non-current assets | ||||
Property, plant and equipment | 12 | |||
Goodwill | 14 | |||
Intangible assets | 15 | |||
Investments in joint ventures | 16 | |||
Investments in associates | 17 | |||
Other investments | 18 | |||
Fixed assets | ||||
Loans | ||||
Trade and other receivables | 20 | |||
Derivative financial instruments | 30 | |||
Prepayments | ||||
Deferred tax assets | 9 | |||
Defined benefit pension plan surpluses | 24 | |||
Current assets | ||||
Loans | ||||
Inventories | 19 | |||
Trade and other receivables | 20 | |||
Derivative financial instruments | 30 | |||
Prepayments | ||||
Current tax receivable | ||||
Other investments | 18 | |||
Cash and cash equivalents | 25 | |||
Assets classified as held for sale | 2 | |||
Total assets | ||||
Current liabilities | ||||
Trade and other payables | 22 | |||
Derivative financial instruments | 30 | |||
Accruals | ||||
Lease liabilities | 28 | |||
Finance debt | 26 | |||
Current tax payable | ||||
Provisions | 23 | |||
Liabilities directly associated with assets classified as held for sale | 2 | |||
Non-current liabilities | ||||
Other payables | 22 | |||
Derivative financial instruments | 30 | |||
Accruals | ||||
Lease liabilities | 28 | |||
Finance debt | 26 | |||
Deferred tax liabilities | 9 | |||
Provisions | 23 | |||
Defined benefit pension plan and other post-employment benefit plan deficits | 24 | |||
Total liabilities | ||||
Net assets | ||||
Equity | ||||
bp shareholders’ equity | 32 | |||
Non-controlling interests | 32 | |||
Total equity | 32 |
Albert Manifold Chair
Carol Howle Interim Chief executive officer
6 March 2026
bp Annual Report and Form 20-F 2025 | 159 |
| ||||
Financial statements | ||||
Group cash flow statement
For the year ended 31 December | $ million | ||||
Note | 2025 | 2024 | 2023 | ||
Operating activities | |||||
Profit (loss) before taxation | |||||
Adjustments to reconcile profit before taxation to net cash provided by operating activities | |||||
Exploration expenditure written off | 8 | ||||
Depreciation, depletion and amortization | 5 | ||||
Impairment and (gain) loss on sale of businesses and fixed assets | 4 | ||||
Earnings from joint ventures and associates | ( | ( | ( | ||
Dividends received from joint ventures and associates | |||||
Remeasurement of joint ventures | 3 | ( | |||
Interest receivable | ( | ( | ( | ||
Interest received | |||||
Finance costs | 7 | ||||
Interest paid | ( | ( | ( | ||
Net finance expense relating to pensions and other post-employment benefits | 24 | ( | ( | ( | |
Share-based payments | |||||
Net operating charge for pensions and other post-employment benefits, less contributions and benefit payments for unfunded plans | 24 | ( | ( | ( | |
Net charge for provisions, less payments | ( | ( | |||
(Increase) decrease in inventories | |||||
(Increase) decrease in other current and non-current assets | ( | ||||
Increase (decrease) in other current and non-current liabilities | ( | ( | ( | ||
Income taxes paid | ( | ( | ( | ||
Net cash provided by operating activities | |||||
Investing activities | |||||
Expenditure on property, plant and equipment, intangible and other assets | ( | ( | ( | ||
Acquisitions, net of cash acquired | 3 | ( | ( | ||
Investment in joint ventures | ( | ( | ( | ||
Investment in associates | ( | ( | ( | ||
Total cash capital expenditure | ( | ( | ( | ||
Proceeds from disposals of fixed assets | 4 | ||||
Proceeds from disposals of businesses, net of cash disposed | 4 | ||||
Proceeds from loan repayments | |||||
Net cash used in investing activities | ( | ( | ( | ||
Financing activities | |||||
Repurchase of shares | ( | ( | ( | ||
Lease liability payments | ( | ( | ( | ||
Proceeds from long-term financing | |||||
Repayments of long-term financing | ( | ( | ( | ||
Net increase (decrease) in short-term debt | ( | ( | ( | ||
Issue of perpetual hybrid bonds | |||||
Redemption of perpetual hybrid bonds | 32 | ( | ( | ||
Payments relating to perpetual hybrid bonds | ( | ( | ( | ||
Payments relating to transactions involving non-controlling interests (other) | ( | ( | ( | ||
Receipts relating to transactions involving non-controlling interests (other) | |||||
Dividends paid | |||||
bp shareholders | 10 | ( | ( | ( | |
Non-controlling interests | ( | ( | ( | ||
Net cash provided by (used in) financing activities | ( | ( | ( | ||
Currency translation differences relating to cash and cash equivalents | ( | ||||
Increase (decrease) in cash and cash equivalents | ( | ||||
Cash and cash equivalents at beginning of year | |||||
Cash and cash equivalents at end of yeara |
a 2025 and 2024 include cash and cash equivalents classified as assets held for sale in the group balance sheet. See Note 2 for further information.
160 | bp Annual Report and Form 20-F 2025 |
Notes on financial statements
1. Material accounting policy information, significant judgements, estimates and assumptions
The consolidated financial statements of BP p.l.c and its subsidiaries (collectively referred to as bp or the group) were approved and signed by the
interim chief executive officer and chairman on 6 March 2026 having been duly authorized to do so by the board of directors. BP p.l.c. is a public
limited company incorporated and domiciled in England and Wales. The consolidated financial statements have been 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. IFRS as adopted by the UK does not differ from IFRS as adopted by the EU. IFRS as adopted by the UK and EU differs in
certain respects from IFRS as issued by the IASB. The differences have no impact on the group’s consolidated financial statements for the years
presented. The material accounting policy information and accounting judgements, estimates and assumptions of the group are set out below.
Basis of preparation
The consolidated financial statements have been prepared on a going concern basis and in accordance with IFRSs and IFRS Interpretations
Committee (IFRIC) interpretations issued and effective for the year ended 31 December 2025. The accounting policies that follow have been
consistently applied to all years presented, except where otherwise indicated.
The consolidated financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where
otherwise indicated.
Inherent in the application of many of the accounting policies used in preparing the consolidated financial statements is the need for bp
management to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of
contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and
assumptions used. The accounting judgements and estimates that have a significant impact on the results of the group are set out in boxed text
below, and should be read in conjunction with the information provided in the Notes on financial statements.
The areas requiring the most significant judgement and estimation in the preparation of the consolidated financial statements are: accounting for
the investments in Rosneft and Aker BP; exploration and appraisal intangible assets; the recoverability of asset carrying values, including the
estimation of reserves; supplier financing arrangements; derivative financial instruments; provisions and contingencies; pensions and other post-
employment benefits; and taxation. Judgements and estimates, not all of which are significant, made in assessing the impact of the current
economic and geopolitical environment, and climate change and the transition to a lower carbon economy on the consolidated financial
statements are also set out in boxed text below. Where an estimate has a significant risk of resulting in a material adjustment to the carrying
amounts of assets and liabilities within the next financial year this is specifically noted within the boxed text.
Judgements and estimates made in assessing the impact of climate change and the transition to a lower carbon economy |
Climate change and the transition to a lower carbon economy were considered in preparing the consolidated financial statements. These may have significant impacts on the currently reported amounts of the group’s assets and liabilities discussed below and on similar assets and liabilities that may be recognized in the future. The group’s assumptions for investment appraisal form part of an investment decision-making framework for currently unsanctioned future capital expenditure on property, plant and equipment, and intangibles including exploration and appraisal assets, that is designed to support the effective and resilient implementation of bp’s strategy. The price assumptions used for investment appraisal include oil and gas price assumptions, which are producer prices and are therefore net of any future carbon prices that the purchaser may be required to pay, and an assumption of a single carbon emissions cost imposed on the producer in respect of operational greenhouse gas (GHG) emissions (carbon dioxide and methane) in order to incentivize engineering solutions to mitigate GHG emissions on projects. The group's oil and gas price assumptions for value-in-use impairment testing are aligned with those investment appraisal assumptions. The assumptions for future carbon emissions costs in value-in-use impairment testing differ from the investment appraisal assumptions and are described below. Management has also not identified any off-balance sheet commodity purchase obligations to be onerous contracts as result of the transition to a lower carbon economy at 31 December 2025. |
Impairment of property, plant and equipment and goodwill |
The energy transition is likely to impact the future prices of commodities such as oil and natural gas which in turn may affect the recoverable amount of property, plant and equipment and goodwill in the oil and gas industry. Management’s best estimate of oil and natural gas price assumptions for value-in-use impairment testing were revised during 2025. The revised price assumptions have been rebased in real 2024 terms. Brent oil prices in real 2024 terms were reduced in the short-term reflecting greater crude supply. Medium to long term prices steadily decline to a higher price of $ assumptions for Henry Hub gas price have been reduced in the short term, reflecting higher supply in the market. Prices then steadily increase in the medium term, as supply and demand rebalance before remaining steady at $ oil and Henry Hub gas sit within the range of external scenarios considered by management and are in line with a range of transition paths, as collated into the Transition Scenario Catalogue we use in our TCFD assessment, that are considered by source data providers (such as IEA, UN PRI IPR and NGFS) to be consistent with holding the increase in the global average temperature to well below 2°C above pre-industrial levels and pursuing efforts to limit the temperature increase to 1.5°C above pre-industrial levels. |
bp Annual Report and Form 20-F 2025 | 161 |
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Financial statements | ||||
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
As noted above, the group’s investment appraisal process includes a carbon emissions price series for the investment economics which is applied to bp's anticipated share of bp's forecast of the investment assets' scope 1 and 2 GHG emissions where they exceed defined thresholds, and is assumed to apply whether or not bp is the asset operator. However, for value-in-use impairment testing on bp's existing cash generating units (CGUs), consistent with all other relevant cash flows estimated, bp is required to reflect management's best estimate of any expected applicable carbon emission costs payable by bp, including where bp is not the operator, in the future for each jurisdiction in which the group has interests. This requires management’s best estimate of how future changes to relevant carbon emission cost policies and/or legislation are likely to affect the future cash flows of the group’s applicable CGUs, whether currently enacted or not. Future potential carbon pricing and/or costs of carbon emissions allowances are included in the value-in-use calculations to the extent management has sufficient information to make such an estimate. Currently this results in limited application of carbon price assumptions in value-in-use impairment tests given that carbon pricing legislation in most impacted jurisdictions where the group has interests is not in place and there is not sufficient information available as to the relevant policy makers' future intentions regarding carbon pricing to support an estimate. A key input into the determination of impairment is the assumption, aligned with bp’s aim to reach net zero greenhouse gas emissions by 2050 or sooner, that the current recognized portfolio of oil and gas properties and refining assets will have an immaterial carrying value by 2050. |
Where we consider that the outcome of a value-in-use impairment test could be significantly affected by a carbon price in place in any jurisdiction, this is incorporated into the value-in use impairment testing cash flows. The most significant instances where a carbon price has been incorporated in the 2025 value-in-use impairment tests is for the UK North Sea. The assumptions for UK North Sea were £ gradually increasing to £ However, as bp’s forecast future prices are producer prices, the group considers it reasonable to assume that if, in addition to the costs already in place, further scope 1 and 2 emission costs were partially to be borne directly by oil and gas producers including bp in future and the prevalence of such costs were to become widespread, the gross oil and gas prices realized by producers would be correspondingly higher over the long term, resulting in no expected overall materially negative impacts on the group’s net cash flows. See significant judgements and estimates: recoverability of asset carrying values for further information including sensitivity analysis in relation to reasonably possible changes in the price assumptions and carbon costs. Production assumptions within upstream property, plant and equipment and goodwill value-in-use impairment tests reflect management’s current best estimate of future production of the existing upstream portfolio. See significant judgements and estimates: recoverability of asset carrying values and Note 14 for sensitivity analyses in relation to reasonably possible changes in production for upstream oil and gas properties and goodwill respectively. For the customers & products segment, though the energy transition may impact demand for certain refined products in the future, management anticipates sufficiently robust demand for the remainder of each refinery’s useful life. Management will continue to review price assumptions as the energy transition progresses and this may result in impairment charges or reversals in the future. |
Exploration and appraisal intangible assets |
The energy transition may affect the future development or viability of exploration prospects. The recoverability of the group's exploration and appraisal intangible assets was considered during 2025. No significant write-offs were identified. These assets will continue to be assessed as the energy transition progresses. See significant judgement: exploration and appraisal intangible assets and Note 8 for further information. |
Property, plant and equipment – depreciation and expected useful lives |
The energy transition may curtail the expected useful lives of oil and gas industry assets thereby accelerating depreciation charges. However, a significant majority of bp’s existing upstream oil and natural gas properties are likely to have immaterial carrying values within the next 12 years and, as outlined in bp's strategy, oil and natural gas production will remain an important part of bp’s business activities over that period. The significant majority of refining assets, recognized on the group’s balance sheet at 31 December 2025 that are subject to depreciation, will be depreciated within the next 11 years; demand for refined products is expected to remain sufficient to support the remaining useful lives of existing assets. Therefore, management does not expect the useful lives of bp’s reported property, plant and equipment to change and do not consider this to be a significant accounting judgement or estimate. Significant capital expenditure is still required for ongoing projects as well as renewal and/or replacement of aged assets and therefore the useful lives of future capital expenditure may be different. See material accounting policy: property, plant and equipment for more information. |
162 | bp Annual Report and Form 20-F 2025 |
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Provisions: decommissioning |
The energy transition may bring forward the decommissioning of oil and gas industry assets thereby increasing the present value of associated decommissioning provisions. The majority of bp’s existing upstream oil and gas properties are expected to start decommissioning within the next two decades. Currently, the expected timing of decommissioning expenditures for the upstream oil and gas assets in the group’s portfolio has not materially been brought forward. Management does not expect a reasonably possible change of two years in the expected timing of all decommissioning to have a material effect on the upstream decommissioning provisions, assuming cost assumptions remain unchanged. Decommissioning cost estimates are based on the known regulatory and external environment. These cost estimates may change in the future, including as a result of the transition to a lower carbon economy. For refineries, decommissioning provisions are generally not recognized as the associated obligations have indeterminate settlement dates, typically driven by the cessation of manufacturing. Management does not expect manufacturing to cease at refineries within a determinate period of time, as existing property, plant and equipment is expected to be renewed or replaced. Management will continue to review facts and circumstances, including where cessation of manufacturing decisions have been made, to assess if decommissioning provisions need to be recognized. Decommissioning provisions relating to refineries at 31 December 2025 are not material. See significant judgements and estimates: provisions for further information. |
Judgements and estimates made in assessing the impact of the geopolitical and economic environment |
In preparing the consolidated financial statements, the following areas involving judgement and estimates were identified as most relevant with regards to the impact of the current geopolitical and economic environment. |
Oil and gas price assumptions |
Oil and gas price assumptions applied in value-in-use impairment testing have been updated (as noted above) including for inflation and have been rebased in real 2024 terms. See significant judgements and estimates: recoverability of asset carrying values for further information. |
Discount rate assumptions |
The discount rates used for impairment testing and provisions were reassessed during the year in light of changing economic and geopolitical outlooks. The impact on the nominal discount rate applied to provisions was determined not to be significant and so the rate remained unchanged from 2024. The post-tax impairment discount rate remained consistent with 2024 as did the risk premium applied to the majority of countries classified as higher-risk. See significant judgements and estimates: recoverability of asset carrying values and provisions for further information. |
Pensions and other post-employment benefits |
Volatility in financial markets impact assumptions used for determining the fair value of plan assets and the present value of defined benefit obligations in the group’s defined benefit pension plans. See significant estimate: pensions and other post-employment benefits and Note 24 for further information. |
The group financial statements consolidate the financial statements of BP p.l.c. and its subsidiaries drawn up to 31 December each year.
Subsidiaries are consolidated from the date of their acquisition, being the date on which the group obtains control, including when control is
obtained via potential voting rights, and continue to be consolidated until the date that control ceases.
The financial statements of subsidiaries are prepared for the same reporting year as the parent company, using consistent accounting policies.
Intra-group balances and transactions, including unrealized profits arising from intra-group transactions, have been eliminated. Unrealized losses
are eliminated unless the transaction provides evidence of an impairment of the asset transferred.
Non-controlling interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to bp shareholders. Included within non-
controlling interests are perpetual subordinated hybrid bonds issued by subsidiaries and for which the group has the unconditional right to avoid
transferring cash or another financial asset to the holders. Profit or loss attributable to bp shareholders is adjusted to reflect the coupon/interest
Also, included within non-controlling interests are perpetual subordinated hybrid securities and certain equity instruments with preferred
distribution rights issued by group subsidiaries.
Non-controlling interests are present ownership interests and entitle the holders to a share of the entity’s net assets in the event of liquidation and
are initially measured at either:
(a) fair value; or
(b) the present ownership instruments’ proportionate share in the recognized amounts of the subsidiary’s’ identifiable net assets.
The group enters certain arrangements with non-controlling Interest holders that have a complex equity structure with several classes of equity
shares or are subject to other contractual arrangements. These arrangements specify different entitlements to net profit allocations, equity and
liquidation preferences that differ from an ownership interest share of the entity’s net assets. The group, for certain arrangements, also holds a
discretionary option to redeem the equity shares held by non-controlling interest shareholders, which becomes exercisable upon the occurrence of
a specified event or after a defined period. In such cases, the non-controlling Interest balance within equity is initially measured at fair value and the
non-controlling interest profit or loss allocation in line with the holders’ economic entitlement. The non-controlling interest balance within equity is
not subsequently remeasured to fair value or redemption value but is adjusted for the profit or loss allocation, dividends and other transactions
with non-controlling interest holders.
bp Annual Report and Form 20-F 2025 | 163 |
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Financial statements | ||||
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Interests in other entities
Business combinations and goodwill
their fair values at the acquisition date.
Goodwill is initially measured as the excess of the aggregate of the consideration transferred, the amount recognized for any non-controlling
interest and the acquisition-date fair values of any previously held interest in the acquiree over the fair value of the identifiable assets acquired and
liabilities assumed at the acquisition date. The amount recognized for any non-controlling interest is measured at the present ownership's
proportionate share in the recognized amounts of the acquiree’s identifiable net assets. At the acquisition date, any goodwill acquired is allocated
to each of the cash-generating units, or groups of cash-generating units, expected to benefit from the combination’s synergies. Following initial
recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill arising on business combinations prior to 1 January
2003 is stated at the previous carrying amount under UK generally accepted accounting practice, less subsequent impairments.
Goodwill may arise upon investments in joint ventures and associates, being the surplus of the cost of investment over the group’s share of the net
fair value of the identifiable assets and liabilities. Any such goodwill is recorded within the corresponding investment in joint ventures and
associates.
Goodwill may also arise upon acquisition of interests in joint operations that meet the definition of a business. The amount of goodwill separately
The results, assets and liabilities of joint ventures are incorporated in these consolidated financial statements using the equity method of
accounting as described below.
Certain of the group’s activities, particularly in the oil production & operations and gas & low carbon energy segments, are conducted through joint
operations. bp recognizes, on a line-by-line basis in the consolidated financial statements, its share of the assets, liabilities and expenses of these
joint operations incurred jointly with the other partners, along with the group’s revenue from the sale of its share of the output and any liabilities
and expenses that the group has incurred in relation to the joint operation.
For joint arrangements in a separate entity, judgement may be required as to whether the arrangement should be classified as a joint venture or if
the legal form, contractual arrangements or other facts and circumstances indicate that the group has rights to the assets and obligations for the
liabilities of the arrangement, rather than rights to the net assets, and therefore should be classified as a joint operation. No such judgement made
by the group is considered significant.
Interests in associates
The results, assets and liabilities of associates are incorporated in these consolidated financial statements using the equity method of accounting
as described below.
Significant judgement: investment in Aker BP |
Judgement is required in assessing the level of control or influence over another entity in which the group holds an interest. For bp, the judgement that the group has significant influence over Aker BP, a Norwegian oil and gas company, is significant. As a consequence of this judgement, bp uses the equity method of accounting for its investment and bp's share of Aker BP's oil and natural gas reserves is included in the group's estimated net proved reserves of equity-accounted entities. If significant influence was not present, the investment would be accounted for as an investment in an equity instrument measured at fair value as described under 'Financial assets' below and no share of Aker BP's oil and natural gas reserves would be reported. Significant influence is defined in IFRS as the power to participate in the financial and operating policy decisions of the investee but is not control or joint control of those decisions. Significant influence is presumed when an entity owns 20% or more of the voting power of the investee. Significant influence is presumed not to be present when an entity owns less than 20% of the voting power of the investee. bp owned BP board during 2024. bp’s other nominated director, group chief financial officer, Kate Thomson, has been a member of the Aker BP board since formation of that company in 2016. She is also a member of the Aker BP board’s Audit and Risk Committee. bp also holds the voting rights at general meetings of shareholders conferred by its stake in Aker BP. bp's management considers, therefore, that the group continues to have significant influence at 31 December 2025. |
Significant judgements and estimate: investment in Rosneft |
Since the first quarter 2022, bp accounts for its interest in Rosneft and its other businesses with Rosneft within Russia, as financial assets measured at fair value within ‘Other investments’. bp is not able to sell its Rosneft shares on the Moscow Stock Exchange and is unable to ascribe probabilities to possible outcomes of any exit process. It is considered by management that any measure of fair value, other than nil, would be subject to such high measurement uncertainty, considering the sanctions and restrictions implemented by Russia on Russian assets held by foreign investors, that no estimate would provide useful information even if it were accompanied by a description of the estimate made in producing it and an explanation of the uncertainties that affect the estimate. Accordingly, it is not currently possible to estimate any carrying value other than December 2025. Events or outcomes within the next financial year, that are different to those outlined above, could materially change the fair value of the investment. Russia has imposed restrictions on the payments of dividends to certain foreign shareholders, including those based in the UK, requiring such dividends to be paid in roubles into restricted bank accounts and a requirement for approval of the Russian government for transfers from any such bank accounts out of Russia. Given the restrictions applicable to such accounts, management has made the significant judgement that the criteria for recognizing any dividend income from Rosneft and its other businesses with Rosneft within Russia, for the years to 31 December 2023, 31 December 2024 and 31 December 2025 have not been met. |
164 | bp Annual Report and Form 20-F 2025 |
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
The equity method of accounting
Under the equity method, an investment is carried on the balance sheet at cost plus post-acquisition changes in the group’s share of net assets of
the entity, less distributions received and less any impairment in value of the investment. Loans advanced to equity-accounted entities that have
the characteristics of equity financing are also included in the investment on the group balance sheet. The group income statement reflects the
group’s share of the results after tax of the equity-accounted entity, adjusted to account for depreciation, amortization and any impairment of the
equity-accounted entity’s assets based on their fair values at the date of acquisition. The group statement of comprehensive income includes the
group’s share of the equity-accounted entity’s other comprehensive income. The group’s share of amounts recognized directly in equity by an
equity-accounted entity is recognized in the group’s statement of changes in equity.
Financial statements of equity-accounted entities are typically prepared for the same reporting year as the group. Where material differences arise
in the accounting policies used by the equity-accounted entity and those used by bp, adjustments are made to those financial statements to bring
the accounting policies used into line with those of the group. Unrealized gains on transactions, apart from those that meet the definition of a
derivative, between the group and its equity-accounted entities are eliminated to the extent of the group’s interest in the equity-accounted entity.
The group’s operating segments are established on the basis of those components of the group that are evaluated regularly by the chief executive
officer, bp’s chief operating decision maker, in deciding how to allocate resources and in assessing performance.
The accounting policies of the operating segments are the same as the group’s accounting policies described in this note, except that IFRS requires
that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision
maker. For bp, this measure of profit or loss is replacement cost profit before interest and tax which reflects the replacement cost of inventories
sold in the period and is arrived at by excluding inventory holding gains and losses from profit before interest and tax. Replacement cost profit for
the group is not a recognized measure under IFRS.
During the first quarter 2025, the Archaea Energy business was 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. For further information see
Note 5.
In individual subsidiaries, joint ventures and associates, transactions in foreign currencies are initially recorded in the functional currency of those
entities at the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated
into the functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange differences are included in the income
statement, unless hedge accounting is applied. Non-monetary items, other than those measured at fair value, are not retranslated subsequent to
initial recognition.
In the consolidated financial statements, the assets and liabilities of non-US dollar functional currency subsidiaries, joint ventures, associates, and
related goodwill, are translated into US dollars at the spot exchange rate on the balance sheet date. The results and cash flows of non-US dollar
functional currency subsidiaries, joint ventures and associates are translated into US dollars using average rates of exchange. In the consolidated
financial statements, exchange adjustments arising when the opening net assets and the profits for the year retained by non-US dollar functional
currency subsidiaries, joint ventures and associates are translated into US dollars are recognized in a separate component of equity and reported in
other comprehensive income. Exchange gains and losses arising on long-term intra-group foreign currency borrowings used to finance the group’s
non-US dollar investments are also reported in other comprehensive income if the borrowings form part of the net investment in the subsidiary,
joint venture or associate. On disposal or for certain partial disposals of a non-US dollar functional currency subsidiary, joint venture or associate,
the related accumulated exchange gains and losses recognized in equity are reclassified from equity to the income statement.
Non-current assets and disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell.
Significant non-current assets and disposal groups are classified as held for sale if their carrying amounts will be recovered through a sale
transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal
group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets.
Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the
date of classification as held for sale, and actions required to complete the plan of sale should indicate that it is unlikely that significant changes to
the plan will be made or that the plan will be withdrawn.
Property, plant and equipment and intangible assets are not depreciated or amortized, and equity accounting of associates and joint ventures is
bp Annual Report and Form 20-F 2025 | 165 |
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Financial statements | ||||
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Intangible assets, other than goodwill, include expenditure on the exploration for and evaluation of oil and natural gas resources, biogas rights
agreements, digital assets, patents, licences and trademarks and are stated at the amount initially recognized, less accumulated amortization and
accumulated impairment losses.
Intangible assets are carried initially at cost unless acquired as part of a business combination. Any such asset is measured at fair value at the date
of the business combination and is recognized separately from goodwill if the asset is separable or arises from contractual or other legal rights.
Intangible assets with a finite life, other than capitalized exploration and appraisal costs as described below, are amortized on a straight-line basis
over their expected useful lives. For patents, licences and trademarks, expected useful life is the shorter of the duration of the legal agreement and
economic useful life, and can range from three to fifteen years . The expected useful life of biogas rights agreements is the shorter of the duration
of the legal agreement and economic useful life and can be up to 50 years. Digital asset costs generally have a useful life of three to five years .
The expected useful lives of assets and the amortization method are reviewed on an annual basis and, if necessary, changes in useful lives or the
amortization method are accounted for prospectively.
Oil and natural gas exploration and appraisal expenditure
Oil and natural gas exploration and appraisal expenditure is accounted for using the principles of the successful efforts method of accounting as
described below.
Licence and property acquisition costs
Exploration licence and leasehold property acquisition costs are capitalized within intangible assets and are reviewed at each reporting date to
confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration
drilling is still under way or planned or that it has been determined, or work is under way to determine, that the discovery is economically viable
based on a range of technical and commercial considerations, and sufficient progress is being made on establishing development plans and
timing. If no future activity is planned, the remaining balance of the licence and property acquisition costs is written off. Lower value licences are
pooled and amortized on a straight-line basis over the estimated period of exploration. Upon internal approval for development and recognition of
proved or sanctioned probable reserves of oil and natural gas, the relevant expenditure is transferred to property, plant and equipment.
Geological and geophysical exploration costs are recognized as an expense as incurred. Costs directly associated with an exploration well are
initially capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include
employee remuneration, materials and fuel used, rig costs and payments made to contractors. If potentially commercial quantities of
hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely
to be capable of commercial development, the costs continue to be carried as an asset. If it is determined that development will not occur, that is,
the efforts are not successful, then the costs are expensed.
Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following
the initial discovery of hydrocarbons, including the costs of appraisal wells where hydrocarbons were not found, are initially capitalized as an
intangible asset. Upon internal approval for development and recognition of proved or sanctioned probable reserves, the relevant expenditure is
transferred to property, plant and equipment. If development is not approved and no further activity is expected to occur, then the costs are
expensed.
The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made within
one year of well completion, but can take longer, depending on the complexity of the geological structure. Exploration wells that discover
potentially economic quantities of oil and natural gas and are in areas where major capital expenditure (e.g. an offshore platform or a pipeline)
would be required before production could begin, and where the economic viability of that major capital expenditure depends on the successful
completion of further exploration or appraisal work in the area, remain capitalized on the balance sheet as long as such work is under way or firmly
planned.
Significant judgement: exploration and appraisal intangible assets |
Judgement is required to determine whether it is appropriate to continue to carry costs associated with exploration wells and exploratory-type stratigraphic test wells on the balance sheet. This includes costs relating to exploration licences or leasehold property acquisitions. It is not unusual to have such costs remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil and natural gas field is performed or while the optimum development plans and timing are established. The costs are carried based on the current regulatory and political environment or any known changes to that environment. All such carried costs are subject to regular technical, commercial and management review on at least an annual basis to confirm the continued intent to develop, or otherwise extract value from, the discovery. Where this is no longer the case, the costs are immediately expensed. The carrying amount of capitalized costs are included in Note 8. |
166 | bp Annual Report and Form 20-F 2025 |
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Property, plant and equipment owned by the group is stated at cost, less accumulated depreciation and accumulated impairment losses. The initial
cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into the location and
condition necessary for it to be capable of operating in the manner intended by management, the initial estimate of any decommissioning
obligation, if applicable, and, for assets that necessarily take a substantial period of time to get ready for their intended use, directly attributable
general or specific finance costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other
consideration given to acquire the asset.
Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul
costs. Where an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits associated
with the item will flow to the group, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized. Inspection costs
associated with major maintenance programmes are capitalized and amortized over the period to the next inspection. Overhaul costs for major
maintenance programmes, and all other maintenance costs are expensed as incurred.
Expenditure on the construction, installation and completion of infrastructure facilities such as platforms, pipelines and the drilling of development
wells, including service and unsuccessful development or delineation wells, is capitalized within property, plant and equipment and is depreciated
from the commencement of production.
Oil and natural gas properties, including certain related pipelines, are depreciated using a unit-of-production method. The cost of producing wells is
amortized over proved developed reserves. Licence acquisition, common facilities and future decommissioning costs are amortized over total
proved reserves. The unit-of-production rate for the depreciation of common facilities takes into account expenditures incurred to date, together
with estimated future capital expenditure expected to be incurred relating to as yet undeveloped reserves expected to be processed through these
common facilities. Information on the carrying amounts of the group’s oil and natural gas properties, together with the amounts recognized in the
income statement as depreciation, depletion and amortization is contained in Note 12 and Note 5 respectively.
Estimates of oil and natural gas reserves determined in accordance with US Securities and Exchange Commission (SEC) regulations, including the
application of prices using 12-month historical price data in assessing the commerciality of technical volumes, are typically used to calculate
depreciation, depletion and amortization charges for the group’s oil and gas properties. Therefore, where this approach is adopted, charges are not
dependent on management forecasts of future oil and gas prices.
The impact of changes in estimated proved reserves is dealt with prospectively by amortizing the remaining carrying value of the asset over the
expected future production.
property, plant and equipment on initial recognition are as follows:
Land improvements | |
Buildings | |
Refineries | |
Pipelines | |
Service stations | |
Office equipment | |
Fixtures and fittings |
The expected useful lives and depreciation method of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in
useful lives or the depreciation method are accounted for prospectively. An item of property, plant and equipment is derecognized upon disposal
or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the
asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in the income statement in
bp Annual Report and Form 20-F 2025 | 167 |
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Financial statements | ||||
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
The group assesses assets or groups of assets, called cash-generating units (CGUs), for impairment whenever events or changes in circumstances
indicate that the carrying amount of an asset or CGU may not be recoverable; for example, changes in the group’s business plans, plans to dispose
rather than retain assets, changes in the group’s assumptions about discount rates, commodity prices, low plant utilization, evidence of physical
damage or, for oil and gas assets, significant downward revisions of estimated reserves or increases in estimated future development expenditure
or decommissioning costs. If any such indication of impairment exists, the group makes an estimate of the asset’s or CGU’s recoverable amount.
Individual assets are grouped into CGUs for impairment assessment purposes at the lowest level at which there are identifiable cash inflows that
are largely independent of the cash inflows of other groups of assets. A CGU’s recoverable amount is the higher of its fair value less costs of
disposal and its value in use. If it is probable that the value of the CGU will be primarily recovered through a disposal transaction, the expected
disposal proceeds are considered in determining the recoverable amount. Where the carrying amount of a CGU exceeds its recoverable amount,
the CGU is considered impaired and is written down to its recoverable amount.
The business segment plans, which are approved on an annual basis by senior management, are the primary source of information for the
determination of value in use. They contain forecasts for oil and natural gas production, power generation, refinery throughputs, sales volumes for
various types of refined products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. Carbon taxes and costs of emissions
allowances are included in estimates of future cash flows, where applicable, based on the regulatory environment in each jurisdiction in which the
group operates. As an initial step in the preparation of these plans, various assumptions regarding market conditions, such as oil prices, natural gas
prices, power prices, refining margins, refined product margins and cost inflation rates are set by senior management. These assumptions take
account of existing prices, global supply-demand equilibrium for oil and natural gas, other macroeconomic factors and historical trends and
variability. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the asset group to the extent that they are
not already reflected in the discount rate and are discounted to their present value typically using a pre-tax discount rate that reflects current
market assessments of the time value of money.
Fair value less costs of disposal is the price that would be received to sell the asset in an orderly transaction between market participants and does
not reflect the effects of factors that may be specific to the group and not applicable to entities in general. Fair value may be determined by
reference to agreed or expected sales proceeds, recent market transactions for similar assets or using discounted cash flow analyses. Where
discounted cash flow analyses are used to calculate fair value less costs of disposal, estimates are made about the assumptions market
participants would use when pricing the asset, CGU or group of CGUs containing goodwill and the test is performed on a post-tax basis.
An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer
exist or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed
only if there has been a change in the estimates used to determine the asset’s or CGU's recoverable amount since the last impairment loss was
recognized. If that is the case, the carrying amount of the asset or CGU is increased to the lower of its recoverable amount and the carrying amount
that would have been determined, net of depreciation, had no impairment loss been recognized for the asset or CGU in prior years. Impairment
reversals are recognized in profit or loss. After a reversal, the depreciation charge is adjusted in future periods to allocate the asset’s or CGU's
revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.
Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate the recoverable amount of the
group of CGUs to which the goodwill relates should be assessed. In assessing whether goodwill has been impaired, the carrying amount of the
group of CGUs to which goodwill has been allocated is compared with its recoverable amount. Where the recoverable amount of the group of
CGUs is less than the carrying amount (including goodwill), an impairment loss is recognized. An impairment loss recognized for goodwill is not
reversed in a subsequent period.
The group assesses investments in equity-accounted entities for impairment whenever there is objective evidence that the investment is impaired,
after recognizing its share of any losses of the equity-accounted entity itself. If any such objective evidence of impairment exists, the carrying
amount of the investment is compared with its recoverable amount, being the higher of its fair value less costs of disposal and value in use. If the
carrying amount exceeds the recoverable amount, the investment is written down to its recoverable amount.
Significant judgements and estimates: recoverability of asset carrying values |
Determination as to whether, and by how much, an asset, CGU, or group of CGUs containing goodwill is impaired involves management estimates on highly uncertain matters such as the effects of inflation and deflation on operating expenses, discount rates, capital expenditure, carbon pricing (where applicable), production profiles, reserves and resources, and future commodity prices, including the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas, power and refined products. Judgement is required when determining the appropriate grouping of assets into a CGU or the appropriate grouping of CGUs for impairment testing purposes. For example, individual oil and gas properties may form separate CGUs whilst certain oil and gas properties with shared infrastructure may be grouped together to form a single CGU. Alternative groupings of assets or CGUs may result in a different outcome from impairment testing. See Note 14 for details on how these groupings have been determined in relation to the impairment testing of goodwill. As described above, the recoverable amount of an asset is the higher of its value in use and its fair value less costs of disposal. Fair value less costs of disposal may be determined based on expected sales proceeds or similar recent market transaction data. Details of impairment charges and reversals recognized in the income statement are provided in Note 4 and details on the carrying amounts of assets are shown in Note 12, Note 14 and Note 15. The estimates for assumptions made in impairment tests in 2025 relating to discount rates and oil and gas properties are discussed below. Changes in the economic environment including as a result of the energy transition or other facts and circumstances may necessitate revisions to these assumptions and could result in a material change to the carrying values of the group's assets within the next financial year. |
168 | bp Annual Report and Form 20-F 2025 |
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Discount rates |
For discounted cash flow calculations, future cash flows are adjusted for risks specific to the CGU. Value-in-use calculations are typically discounted using a pre-tax discount rate based upon the cost of funding the group derived from an established model, adjusted to a pre-tax basis and incorporating a market participant capital structure and country risk premiums. Fair value less costs of disposal discounted cash flow calculations use a post-tax discount rate. The discount rates applied in impairment tests are reassessed each year and, in 2025, the post-tax discount rate was renewable power assets. Where the CGU is located in a country that was judged to be higher risk, an additional premium of in the post-tax discount rate (2024 various economic and geopolitical factors. The pre-tax discount rate, other than for renewable power assets, typically ranged from (2024 tested on a value-in-use basis, primarily the CGUs for which goodwill was allocated following the Lightsource bp acquisition, a WACC-based post- tax discount rate of equity accounted entities), a post-tax cost of equity-based discount rate range of |
Oil and natural gas properties |
For oil and natural gas properties in the oil production & operations and gas & low carbon energy segments, expected future cash flows are estimated using management’s best estimate of future oil and natural gas prices, production and reserves and certain resources volumes. Forecast cash flows include the impact of all approved emission reduction projects. The estimated future level of production in all impairment tests is based on assumptions about future commodity prices, production and development costs, field decline rates, current fiscal regimes and other factors. In 2025, the group identified oil and gas properties in these segments with carrying amounts totalling $ the headroom, based on the most recent impairment test performed in the year on those assets, was less than or equal to value. A change in the discount rate, reserves, resources or the oil and gas price assumptions in the next financial year may result in a recoverable amount of one or more of these assets above or below the current carrying amount and therefore there is a risk of impairment reversals or charges in that period. Management considers that reasonably possible changes in the discount rate or forecast revenue, arising from a change in oil and natural gas prices and/or production could result in a material change in their carrying amounts within the next financial year, see Sensitivity analyses, below. The recoverability of intangible exploration and appraisal expenditure is covered under Oil and natural gas exploration, appraisal and development expenditure above. |
Oil and natural gas prices |
The price assumptions used for value-in-use impairment testing are based on those used for investment appraisal. bp’s carbon emissions cost assumptions and their interrelationship with oil and gas prices are described in 'Judgements and estimates made in assessing the impact of climate change and the transition to a lower carbon economy' on page 160. The investment appraisal price assumptions were recommended by the senior vice president economic & energy insights after considering a range of external price sets, and supply and demand profiles associated with various energy transition scenarios. They were reviewed and approved by management. As a result of the current uncertainty over the pace of transition to lower-carbon supply and demand and the social, political and environmental actions that will be taken to meet the goals of the Paris climate change agreement, the scenarios considered include those where those goals are met as well as those where they are not met. During the year, bp's price assumptions applied in value-in-use impairment testing were revised. The revised price assumptions have been rebased in real 2024 terms. Brent oil prices in real 2024 terms were reduced to $ higher price of $ assumptions for the Henry Hub price have been reduced in the near term, reflecting higher supply in the market. Prices then steadily increase in the medium term, as supply and demand remain steady at $ case investment appraisal assumptions. A summary of the group’s revised price assumptions for Brent oil and Henry Hub gas, applied in 2025 and 2024, in real 2024 terms, is provided below. The assumptions represent management’s best estimate of future prices at the balance sheet date, which sit within the range of external scenarios considered as appropriate for the purpose. They are considered by bp to be in line with a range of transition paths, as collated into the Transition Scenario Catalogue we use in our TCFD assessment, that are considered by source data providers (such as IEA, UN PRI IPR and NGFS) to be consistent with holding the increase in the global average temperature to well below 2°C above pre- industrial levels and pursuing efforts to limit the temperature increase to 1.5°C above pre-industrial levels. However, they do not correspond to any specific Paris-consistent scenario. An inflation rate of terms. |
The majority of bp’s reserves and resources that support the carrying value of the group’s existing oil and gas properties are expected to be produced over the next 12 years. |
The recoverability of deferred tax assets is also affected by the group’s oil and natural gas price assumptions as these could impact the estimate of future taxable profits. See Note 9 for further information. |
2025 price assumptions | 2026 | 2030 | 2040 | 2050 | |
Brent oil ($/bbl) | |||||
Henry Hub gas ($/mmBtu) |
2024 price assumptions | 2025 | 2030 | 2040 | 2050 | |
Brent oil ($/bbl) | |||||
Henry Hub gas ($/mmBtu) |
bp Annual Report and Form 20-F 2025 | 169 |
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Financial statements | ||||
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Global oil production increased by 3mmb/d (3%) in 2025, with non-OPEC+ countries contributing nearly 60% of the growth. Global oil demand grew by only 0.8% in 2025, almost entirely accounted for by non-OECD countries, following sharp fall in oil demand from Brazil, India and China. The global supply/demand imbalance of around 2.2mmb/d weighed on prices, with Dated Brent down by nearly $12 per barrel. While geopolitical risk (e.g., tariffs, sanctions) may support prices in the short-term, bp's long-term assumption for oil prices is lower than the 2025 average as oil demand is likely to fall such that the price levels needed to encourage sufficient investment to meet global oil demand will also be lower. The US Henry Hub (HH) spot price averaged $3.5 per mmBtu in 2025, up from $2.2 per mmBtu in 2024 and the highest level since 2022, driven by increased LNG export demand and a colder-than-normal start to the year. Higher gas prices supported a recovery in drilling activity in non- associated (dry) shale plays which, combined with well productivity gains, increasing gas-to-oil ratios in the Permian, and increased pipeline connectivity, meant that US dry gas production grew by 4% year on year and reached record high levels.The level of US gas prices in 2025 was below bp’s long term price assumption based on the judgment of the price level required to incentivize new production. |
Oil and natural gas reserves |
In addition to oil and natural gas prices, significant technical and commercial assessments are required to determine the group’s estimated oil and natural gas reserves. Reserves estimates are regularly reviewed and updated. Factors such as the availability of geological and engineering data, reservoir performance data, acquisition and divestment activity and drilling of new wells all impact on the determination of the group’s estimates of its oil and natural gas reserves. bp bases its reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based on conventional industry practice and regulatory requirements. Reserves assumptions for value-in-use tests reflect the reserves and resources that management currently intend to develop. The recoverable amount of oil and gas properties is determined using a combination of inputs including reserves, resources and production volumes. Risk factors may be applied to reserves and resources which do not meet the criteria to be treated as proved or probable. |
Sensitivity analyses |
Management considers discount rates, oil and natural gas prices and production to be the key sources of estimation uncertainty in determining the recoverable amount of upstream oil and gas assets. The sensitivity analyses below, in addition to covering the key sources of estimation uncertainty, also indicate how the energy transition, potential future carbon emissions costs for operational GHG emissions and/or reduced demand for oil and gas may further impact forecast revenue cash inflows to a greater extent than currently anticipated in the group’s value-in-use estimates for oil and gas CGUs, if carbon emissions costs were to be implemented as a deduction against revenue cash flows. The analyses therefore represent a net revenue sensitivity. A change in net revenue from upstream oil and gas properties can arise either due to changes in oil and natural gas prices, carbon emissions costs/carbon prices, changes in oil and natural gas production, or a combination of these. Management tested the impact of changes in net revenue cash flows in value-in-use impairment testing under the following sensitivity analyses: an increase in net revenues of 8% in all years up to 2040, and 25% in all remaining years to 2050; and a decrease in net revenues of 20% in all years up to 2030, 35% in all subsequent years to 2040 and 50% in all remaining years to 2050. Net revenue reductions of this magnitude in isolation could indicatively lead to a reduction in the carrying amount of bp’s currently held upstream oil and gas properties in the range of $ as at 31 December 2025. If this net revenue reduction was due to reductions in prices in isolation, it reflects an indicative decrease in the carrying amount of using price assumptions for Brent oil trending broadly towards the bottom of the range of prices associated with the 'family' of scenarios in our Transition Scenario Catalogue considered, by source data providers, to be consistent with limiting global average temperature to 1.5°C above pre-industrial levels. This Catalogue of scenarios is also used in bp's TCFD resilience scenario analysis. Net revenue increases of this magnitude in isolation could indicatively lead to an increase in the carrying amount of bp’s currently held upstream oil and gas properties in the range of $ as at 31 December 2025. This potential increase in the carrying amount would arise due to reversals of previously recognized impairments and represents approximately 15% of the total impairment reversal capacity available at 31 December 2025. If this net revenue increase was due to increases in prices in isolation, it reflects an indicative increase in the carrying amount of using price assumptions for Brent oil trending broadly aligned with the top end until the mid-2040s, and then towards the mean average at 2050, of the range of prices associated with the Transition Scenario Catalogue of scenarios (which included the IEA’s World Energy Outlook Net Zero Emissions by 2050 (NZE) scenario) considered by IEA to be consistent with limiting global average temperature to 1.5°C above pre-industrial levels. |
These sensitivity analyses do not, however, represent management’s best estimate of any impairment charges or reversals that might be recognized as they do not fully incorporate consequential changes that may arise, such as changes in costs and business plans and phasing of development. For example, costs across the industry are more likely to decrease as oil and natural gas prices fall. The analyses also assume the impact of increases in carbon price on operational GHG emissions are fully absorbed as a decrease in net revenue (and vice versa) rather than reflecting how carbon prices or other carbon emissions costs may ultimately be incorporated by the market. The above sensitivity analyses therefore do not reflect a linear relationship between net revenue and value that can be extrapolated. The interdependency of these inputs and factors plus the diverse characteristics of the group's upstream oil and gas properties limits the practicability of estimating the probability or extent to which the overall recoverable amount is impacted by changes to the price assumptions or production volumes. Management also tested the impact of a one percentage point change in the discount rate used for value-in-use impairment testing of upstream oil and gas properties. This level of change reflects past experience of a reasonable change in rate that could arise within the next financial year. If the discount rate was one percentage point higher across all tests performed, the net impairment loss recognized in 2025 would have been approximately $ approximately $ |
170 | bp Annual Report and Form 20-F 2025 |
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Management considers discount rate, renewable natural gas prices, and the level of capital expenditure and its consequential impact on production volumes to be the key sources of estimation uncertainty in determining the recoverable amount of the group’s renewable natural gas assets owned by Archaea Energy. A change in revenue from renewable natural gas assets could arise either due to changes in renewable natural gas prices, changes in renewable natural gas production, principally as a result of changes in capital invested, or a combination of both. Management tested the impact of changes in net revenue cash flows on its value-in-use impairment testing. It is estimated that a reduction in revenue across all Archaea Energy assets of increase in revenue of These sensitivity analyses do not, however, represent management’s best estimate of any impairment charges or reversals that might be recognized as they do not fully incorporate consequential changes that may arise, such as changes in capital and operating costs, business plans and phasing of development. The above sensitivity analyses therefore do not reflect a linear relationship between net revenue and value that can be extrapolated. The interdependency of these inputs and factors limits the practicability of estimating the probability or extent to which the overall recoverable amount is impacted by changes to the price assumptions or production volumes. It is estimated that an increase to the discount rate of $ |
Management considers discount rates and refining margins to be the key sources of estimation uncertainty in determining the recoverable amount of refinery assets. The sensitivity analysis below, in addition to covering the key sources of estimation uncertainty, also indicates how the energy transition and/or reduced demand for refined products may further impact forecast cash inflows to a greater extent than currently anticipated in the group’s value-in-use estimates for refinery CGUs. Management tested the impact of a $1 per barrel decrease in each refinery’s future margin assumption in all years of the value-in-use estimate. A reduction of this magnitude in isolation could indicatively lead to a reduction in the carrying amount of bp’s currently held refining property, plant and equipment in the range of $ This sensitivity analysis does not, however, represent management’s best estimate of any impairment charges that might be recognized as it does not fully incorporate consequential changes that may arise, such as changes in costs and business plans and crude or product slates. The above sensitivity analysis therefore does not reflect a linear relationship between margins and value that can be extrapolated. The interdependency of these inputs and factors plus the varying configurations of the group's refineries limits the practicability of estimating the probability or extent to which the overall recoverable amount is impacted by changes to the margin assumptions. Management also tested the impact of a one percentage point change in the discount rate used for value-in-use impairment testing of refinery assets. This level of change reflects past experience of a reasonable change in rate that could arise within the next financial year. If the discount rate was one percentage point higher across all tests performed, the net impairment loss recognized in 2025 would have been approximately $0.5 billion higher. If the discount rate was one percentage point lower there would have been no impact on the net impairment loss recognized in 2025. |
Goodwill |
Irrespective of whether there is any indication of impairment, bp is required to test annually for impairment of goodwill acquired in business combinations. The group carries goodwill of $ Devon Energy, Reliance transactions and its transition businesses. Of this, $ segment and to hydrocarbon CGUs within the gas & low carbon energy segment (2024 $ assumptions are key sources of estimation uncertainty. A further $ segment (2024 $ estimation uncertainty. Sensitivities and additional information relating to impairment testing of goodwill in these segments are provided in Note 14. |
bp Annual Report and Form 20-F 2025 | 171 |
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Financial statements | ||||
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Inventories, other than inventories held for short-term trading purposes, are stated at the lower of cost and net realizable value. Cost is typically
determined by the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses.
Net realizable value is determined by reference to prices existing at the balance sheet date, adjusted where the sale of inventories after the
reporting period gives evidence about their net realizable value at the end of the period.
Inventories held for short-term trading purposes are stated at fair value less costs to sell and any changes in fair value are recognized in the income
statement.
Supplies are valued at the lower of cost on a weighted-average basis and net realizable value.
Agreements that convey the right to control the use of an identified asset for a period of time in exchange for consideration are accounted for as
leases. The right to control is conveyed if bp has both the right to obtain substantially all of the economic benefits from, and the right to direct the
use of, the identified asset throughout the period of use. An asset is identified if it is explicitly or implicitly specified by the agreement and any
substitution rights held by the lessor over the asset are not considered substantive.
Agreements that convey the right to control the use of an intangible asset including rights to explore for or use hydrocarbons are not accounted for
as leases. See material accounting policy information: intangible assets.
A lease liability is recognized on the balance sheet on the lease commencement date at the present value of future lease payments over the lease
term. The discount rate applied is the rate implicit in the lease if readily determinable, otherwise an incremental borrowing rate is used. For the
majority of the leases in the group, there is not sufficient information available to readily determine the rate implicit in the lease, and therefore the
incremental borrowing rate is used. The incremental borrowing rate is determined based on factors such as the group’s cost of borrowing, lessee
legal entity credit risk, currency and lease term. The lease term is the non-cancellable period of a lease together with any periods covered by an
extension option that bp is reasonably certain to exercise, or periods covered by a termination option that bp is reasonably certain not to exercise.
The future lease payments included in the present value calculation are any fixed payments, payments that vary depending on an index or rate,
payments due for the reasonably certain exercise of options and expected residual value guarantee payments. Repayments of principal are
presented as financing cash flows and payments of interest are presented as operating cash flows.
Payments that vary based on factors other than an index or a rate such as usage, sales volumes or revenues are not included in the present value
calculation and are recognized in the income statement and presented as operating cash flows. The lease liability is recognized on an amortized
cost basis with interest expense recognized in the income statement over the lease term, except for where capitalized as exploration, appraisal or
development expenditure.
The right-of-use asset is recognized on the balance sheet as property, plant and equipment at a value equivalent to the initial measurement of the
lease liability adjusted for lease prepayments, lease incentives, initial direct costs and any restoration obligations. The right-of-use asset is
depreciated typically on a straight-line basis over the lease term. The depreciation charge is recognized in the income statement except for where
capitalized as exploration, appraisal or development expenditure. Right-of-use assets are assessed for impairment in line with the accounting
policy for impairment of property, plant and equipment, intangible assets and goodwill.
Agreements may include both lease and non-lease components. Payments for lease and non-lease components are allocated on a relative stand-
alone selling price basis except for leases of retail service stations where the group has elected not to separate non-lease payments from the
calculation of the lease liability and right-of-use asset.
If the lease term at commencement of the agreement is less than 12 months, a lease liability and right-of-use asset are not recognized, and a lease
expense is recognized in the income statement on a straight-line basis.
If a significant event or change in circumstances, within the control of bp, arises that affects the reasonably certain lease term or there are changes
to the lease payments, the present value of the lease liability is remeasured using the revised term and payments, with the right-of-use asset
adjusted by an equivalent amount.
Modifications to a lease agreement beyond the original terms and conditions are accounted for as a re-measurement of the lease liability with a
corresponding adjustment to the right-of-use asset. Any gain or loss on modification is recognized in the income statement. Modifications that
increase the scope of the lease at a price commensurate with the stand-alone selling price are accounted for as a separate new lease.
The group recognizes the full lease liability, rather than its working interest share, for leases entered into on behalf of a joint operation if the group
has the primary responsibility for making the lease payments. This may be the case if for example bp, as operator of the joint operation, is the sole
signatory to the lease agreement. In such cases, bp’s working interest share of the right-of-use asset is recognized if it is jointly controlled by the
group and the other joint operators, and a receivable is recognized for the share of the asset transferred to the other joint operators. If bp is a non-
operator, a payable to the operator is recognized if they have the primary responsibility for making the lease payments and bp has joint control over
the right-of-use asset, otherwise no balances are recognized.
172 | bp Annual Report and Form 20-F 2025 |
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Financial assets are recognized initially at fair value, normally being the transaction price. In the case of financial assets not measured at fair value
through profit or loss, directly attributable transaction costs are also included. The subsequent measurement of financial assets depends on their
classification, as set out below. The group derecognizes financial assets when the contractual rights to the cash flows expire or the rights to receive
cash flows have been transferred to a third party and either substantially all of the risks and rewards of the asset have been transferred, or
substantially all the risks and rewards of the asset have neither been retained nor transferred but control of the asset has been transferred. This
includes the derecognition of receivables for which discounting arrangements are entered into.
The group classifies its financial asset debt instruments as measured at amortized cost, fair value through other comprehensive income or fair
value through profit or loss. The classification depends on the business model for managing the financial assets and the contractual cash flow
characteristics of the financial asset.
Financial assets measured at amortized cost
Financial assets are classified as measured at amortized cost when they are held in a business model the objective of which is to collect contractual
cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortized cost using the
effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the assets are
derecognized or impaired and when interest income is recognized using the effective interest method. This category of financial assets includes
trade and other receivables.
Financial assets measured at fair value through other comprehensive income
Financial assets are classified as measured at fair value through other comprehensive income when they are held in a business model the objective
of which is both to collect contractual cash flows and sell the financial assets, and the contractual cash flows represent solely payments of
principal and interest.
Financial assets measured at fair value through profit or loss
Financial assets are classified as measured at fair value through profit or loss when the asset does not meet the criteria to be measured at
amortized cost or fair value through other comprehensive income. Such assets are carried on the balance sheet at fair value with gains or losses
recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category.
Investments in equity instruments
Investments in equity instruments are subsequently measured at fair value through profit or loss unless an election is made on an instrument-by-
instrument basis to recognize fair value gains and losses in other comprehensive income.
Derivatives designated as hedging instruments in an effective hedge
Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and
losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities.
Cash equivalents
Cash equivalents are held for the purpose of meeting short-term cash commitments and are short-term highly liquid investments that are readily
convertible to known amounts of cash, are subject to insignificant risk of changes in value and generally have a maturity of three months or less
from the date of acquisition. Cash equivalents are classified as financial assets measured at amortized cost or, in the case of certain money market
funds, fair value through profit or loss.
Impairment of financial assets measured at amortized cost
The group assesses on a forward-looking basis the expected credit losses associated with financial assets measured at amortized cost at each
balance sheet date. Expected credit losses are measured based on the maximum contractual period over which the group is exposed to credit risk.
As lifetime expected credit losses are recognized for trade receivables and the tenor of substantially all other in-scope financial assets is less than
12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses for the group. The
measurement of expected credit losses is a function of the probability of default, loss given default and exposure at default. The expected credit
loss is estimated as the difference between the asset’s carrying amount and the present value of the future cash flows the group expects to receive
discounted at the financial asset’s original effective interest rate. The carrying amount of the asset is adjusted, with the amount of the impairment
gain or loss recognized in the income statement.
A financial asset or group of financial assets classified as measured at amortized cost is considered to be credit-impaired if there is reasonable and
supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset (or group of
financial assets) have occurred. Financial assets are written off where the group has no reasonable expectation of recovering amounts due.
Equity instruments
Instruments are classified as either financial liabilities or as equity in accordance with the substance of the contractual arrangements. Instruments
that cannot be settled in the group’s own equity instruments and that include no contractual obligation to deliver cash or another financial asset or
bp Annual Report and Form 20-F 2025 | 173 |
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Financial statements | ||||
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Financial liabilities are recognized when the group becomes party to the contractual provisions of the instrument. The group derecognizes financial
liabilities when the obligation specified in the contract is discharged, cancelled or expired. The measurement of financial liabilities depends on their
classification, as follows:
Financial liabilities measured at fair value through profit or loss
Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are
carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as
effective hedging instruments, are included in this category.
Derivatives designated as hedging instruments in an effective hedge
Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and
losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities.
Financial liabilities measured at amortized cost
All other financial liabilities are initially recognized at fair value, net of directly attributable transaction costs. For interest-bearing loans and
borrowings this is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing.
After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost
is calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase,
settlement or cancellation of liabilities are recognized in interest and other income and finance costs respectively.
This category of financial liabilities includes trade and other payables and finance debt.
Significant judgement: supplier financing arrangements |
The group’s trade payables include some supplier financing arrangements that utilize letter of credit facilities, promissory notes and reverse factoring. Judgement is required to assess the payables subject to these arrangements to determine whether they should continue to be classified as trade payables and give rise to operating cash flows or finance debt and financing cash flows. The criteria used in making this assessment include the payment terms for the amount due relative to terms commonly seen in the markets in which bp operates and whether the arrangements significantly change the nature of the liability. Liabilities subject to these arrangements with payment terms of up to approximately 60 days are generally considered to be trade payables and give rise to operating cash flows. See Note 29 - Liquidity risk for further information. |
Financial guarantees
The group issues financial guarantee contracts to make specified payments to reimburse holders for losses incurred if certain associates, joint
ventures or third-party entities fail to make payments when due in accordance with the original or modified terms of a debt instrument such as a
loan. The liability for a financial guarantee contract is initially measured at fair value and subsequently measured at the higher of the contract’s
estimated expected credit loss and the amount initially recognized less, where appropriate, cumulative amortization.
Derivative financial instruments and hedging activities
The group uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and
commodity prices, as well as for trading purposes. These derivative financial instruments are recognized initially at fair value on the date on which a
derivative contract is entered into and subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as
liabilities when the fair value is negative.
Contracts to buy or sell a non-financial item (for example, oil, oil products, gas or power) that can be settled net in cash, with the exception of
contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the
group’s expected purchase, sale or usage requirements, are accounted for as financial instruments. Gains or losses arising from changes in the fair
value of derivatives that are not designated as effective hedging instruments are recognized in the income statement.
If, at inception of a contract, the valuation cannot be supported by observable market data, any gain or loss determined by the valuation
methodology is not recognized in the income statement but is deferred on the balance sheet and is commonly known as a ‘day-one gain or loss’.
This deferred gain or loss is recognized in the income statement over the life of the contract until substantially all the remaining contractual cash
flows can be valued using observable market data at which point any remaining deferred gain or loss is recognized in the income statement.
Changes in valuation subsequent to the initial valuation at inception of a contract are recognized immediately in the income statement.
For the purpose of hedge accounting, hedges are classified as:
•Fair value hedges when hedging exposure to changes in the fair value of a recognized asset or liability.
•Cash flow hedges when hedging exposure to variability in cash flows that is attributable to either a particular risk associated with a recognized
asset or liability or a highly probable forecast transaction.
Hedge relationships are formally designated and documented at inception, together with the risk management objective and strategy for
undertaking the hedge. The documentation includes identification of the hedging instrument, the hedged item or transaction, the nature of the risk
being hedged, the existence at inception of an economic relationship and subsequent measurement of the hedging instrument's effectiveness in
offsetting the exposure to changes in the hedged item’s fair value or cash flows attributable to the hedged risk, the hedge ratio and sources of
hedge ineffectiveness. Hedges meeting the criteria for hedge accounting are accounted for as follows:
174 | bp Annual Report and Form 20-F 2025 |
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Fair value hedges
The change in fair value of a hedging derivative is recognized in profit or loss. The change in the fair value of the hedged item attributable to the risk
being hedged is recorded as part of the carrying value of the hedged item and is also recognized in profit or loss, where it offsets. The group applies
fair value hedge accounting when hedging interest rate risk and certain currency risks on fixed rate finance debt.
Fair value hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This
includes when the risk management objective changes or when the hedging instrument is sold, terminated or exercised. The accumulated
adjustment to the carrying amount of a hedged item at such time is then amortized prospectively to profit or loss as finance interest expense over
the hedged item's remaining period to maturity.
Cash flow hedges
The effective portion of the gain or loss on a cash flow hedging instrument is reported in other comprehensive income, while the ineffective portion
is recognized in profit or loss. Amounts reported in other comprehensive income are reclassified to the income statement when the hedged
transaction affects profit or loss.
Where the hedged item is a highly probable forecast transaction that results in the recognition of a non-financial asset or liability, such as a
forecast foreign currency transaction for the purchase of property, plant and equipment, the amounts recognized within other comprehensive
income are transferred to the initial carrying amount of the non-financial asset or liability. Where the hedged item is an equity investment, the
amounts recognized in other comprehensive income remain in the separate component of equity until the hedged cash flows affect profit or loss
or when accounting under the equity method is discontinued. Where the hedged item is recognized directly in profit or loss, the amounts
recognized in other comprehensive income are reclassified to production and manufacturing expenses or sales and other operating revenues as
appropriate.
Cash flow hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This
includes when the designated hedged forecast transaction or part thereof is no longer considered to be highly probable to occur, or when the
hedging instrument is sold, terminated or exercised without replacement or rollover. When cash flow hedge accounting is discontinued amounts
previously recognized within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified to profit or
loss or transferred to the initial carrying amount of a non-financial asset or liability as above. If the forecast transaction is no longer expected to
occur, amounts previously recognized within other comprehensive income will be immediately reclassified to profit or loss.
Costs of hedging
The foreign currency basis spread of cross-currency interest rate swaps are excluded from hedge designations and accounted for as costs of
hedging. Changes in fair value of the foreign currency basis spread are recognized in other comprehensive income to the extent that they relate to
the hedged item.
For time-period related hedged items, the amount recognized in other comprehensive income is amortized to profit or loss on a straight line basis
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The
group categorizes assets and liabilities measured at fair value into one of three levels depending on the ability to observe inputs employed in their
measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs that are observable, either
directly or indirectly, other than quoted prices included within level 1 for the asset or liability. Level 3 inputs are unobservable inputs for the asset or
liability reflecting significant modifications to observable related market data or bp’s assumptions about pricing by market participants.
Significant estimate and judgement: derivative financial instruments | |
In some cases the fair values of derivatives are estimated using internal models due to the absence of quoted prices or other observable, market- corroborated data. This primarily applies to the group’s longer-term derivative contracts. The majority of these contracts are valued using models with inputs that include price curves for each of the different products that are built up from available active market pricing data (including volatility and correlation) and modelled using the maximum available external information. Additionally, where limited data exists for certain products, prices are determined using historical and long-term pricing relationships. The use of alternative assumptions or valuation methodologies may result in significantly different values for these derivatives. A reasonably possible change in the price assumptions used in the models relating to index price would not have a material impact on net assets and the Group income statement primarily as a result of offsetting movements between derivative assets and liabilities. In some cases, judgement is required to determine whether contracts to buy or sell commodities meet the definition of a derivative or to determine appropriate presentation and classification of transactions in certain cases. In particular, contracts to buy and sell LNG are not considered to meet the definition as they are not considered capable of being net settled due to a lack of liquidity in the LNG market and the inability or lack of history of net settlement and are accounted for on an accruals basis, rather than as a derivative. Under IFRS, bp fair values the derivative financial instruments used to risk-manage the LNG contracts themselves, resulting in a measurement mismatch. For more information, including the carrying amounts of level 3 derivatives, see Note 30. | 0 |
bp Annual Report and Form 20-F 2025 | 175 |
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Financial statements | ||||
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Financial assets and liabilities are presented gross in the balance sheet unless both of the following criteria are met: the group currently has a
legally enforceable right to set off the recognized amounts; and the group intends to either settle on a net basis or realize the asset and settle the
liability simultaneously. A right of set off is the group’s legal right to settle an amount payable to a creditor by applying against it an amount
receivable from the same counterparty. The relevant legal jurisdiction and laws applicable to the relationships between the parties are considered
when assessing whether a current legally enforceable right to set off exists.
Provisions are recognized when the group has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of
resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the
obligation. Where appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability.
If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax risk-free
rate that reflects current market assessments of the time value of money. Where discounting is used, the increase in the provision due to the
passage of time is recognized within finance costs. Provisions are discounted using a nominal discount rate of 4.5 % (2024 4.5 %).
Provisions are split between amounts expected to be settled within 12 months of the balance sheet date (current) and amounts expected to be
settled later (non-current).
Contingent liabilities are possible obligations whose existence will only be confirmed by future events not wholly within the control of the group, or
present obligations where it is not probable that an outflow of resources will be required or the amount of the obligation cannot be measured with
sufficient reliability. Contingent liabilities are not recognized in the consolidated financial statements but are disclosed, if material, unless the
possibility of an outflow of economic resources is considered remote.
Decommissioning
Liabilities for decommissioning costs are recognized when the group has an obligation to plug and abandon a well, dismantle and remove a facility
or an item of plant and to restore the site on which it is located, and when a reliable estimate of that liability can be made. Where an obligation
exists for a new facility or item of plant, such as oil and natural gas production or transportation facilities, this liability will be recognized on
construction or installation. Similarly, where an obligation exists for a well, this liability is recognized when it is drilled. An obligation for
decommissioning may also crystallize during the period of operation of a well, facility or item of plant through a change in legislation or through a
decision to terminate operations; an obligation may also arise in cases where an asset has been sold but the subsequent owner is no longer able to
fulfil its decommissioning obligations, for example due to bankruptcy. The amount recognized is the present value of the estimated future
expenditure determined in accordance with local conditions and requirements. The provision for the costs of decommissioning wells, production
facilities and pipelines at the end of their economic lives is estimated using existing technology, at future prices, depending on the expected timing
of the activity, and discounted using a nominal discount rate.
An amount equivalent to the decommissioning provision is recognized as part of the corresponding intangible asset (in the case of an exploration
or appraisal well) or property, plant and equipment. The decommissioning portion of the property, plant and equipment is subsequently
depreciated at the same rate as the rest of the asset. Other than the unwinding of discount on or utilization of the provision, any change in the
present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding asset where that asset is
generating or is expected to generate future economic benefits.
Environmental expenditures and liabilities
Environmental expenditures that are required in order for the group to obtain future economic benefits from its assets are capitalized as part of
those assets. Expenditures that relate to an existing condition caused by past operations that do not contribute to future earnings are expensed.
Liabilities for environmental costs are recognized when a clean-up is probable and the associated costs can be reliably estimated. Generally, the
timing of recognition of these provisions coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of
inactive sites.
The amount recognized is the best estimate of the expenditure required to settle the obligation. Provisions for environmental liabilities have been
estimated using existing technology, at future prices and discounted using a nominal discount rate.
Emissions
Liabilities for emissions are recognized when the cumulative volumes of gases emitted by the group at the end of the reporting period exceed the
allowances granted free of charge held for own use or a set baseline for emissions. The provision is measured at the best estimate of the
expenditure required to settle the present obligation at the balance sheet date. It is based on the excess of actual emissions over the free
allowances held or set baseline in tonnes (or other appropriate quantity) and is valued at the actual cost of any allowances that have been
purchased and held for own use on a first-in-first-out (FIFO) basis, and, if insufficient allowances are held, for the remaining requirement on the
basis of the spot market price of allowances at the balance sheet date. The majority of these provisions are typically settled within 12 months of the
balance sheet date however certain schemes may have longer compliance periods. The cost of allowances purchased to cover a shortfall is
recognized separately on the balance sheet as an intangible asset unless the emission allowances acquired or generated by the group are risk-
managed by the trading and shipping function, then they are recognized on the balance sheet as inventory.
Restructuring provisions
Restructuring provisions are recognized where a detailed formal plan exists, and a valid expectation of risk of redundancy has been made to those
affected but where the specific outcomes remain uncertain. Where formal redundancy offers have been made, the obligations for those amounts
are reported as payables and, if not, as provisions if unpaid at the year-end.
176 | bp Annual Report and Form 20-F 2025 |
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Significant judgements and estimates: provisions |
The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic lives. The largest decommissioning obligations facing bp relate to the plugging and abandonment of wells and the removal and disposal of oil and natural gas platforms and pipelines around the world. Most of these decommissioning events are many years in the future and the precise requirements that will have to be met when the removal event occurs are uncertain. Decommissioning technologies and costs are constantly changing, as are political, environmental, safety and public expectations. The timing and amounts of future cash flows are subject to significant uncertainty and estimation is required in determining the amounts of provisions to be recognized. Any changes in the expected future costs are reflected in both the provision and, where still recognized, the asset. If oil and natural gas production facilities and pipelines are sold to third parties, judgement is required to assess whether the new owner will be unable to meet their decommissioning obligations, whether bp would then be responsible for decommissioning, and if so the extent of that responsibility. This typically requires assessment of the local legal requirements and the financial standing of the owner. If the standing deteriorates significantly, for example, bankruptcy of the owner, a provision may be required. The group has $ provisions recognized as at 31 December 2025 (2024 $ decommissioning obligation to the new owner. See Note 33 for further information. Decommissioning provisions associated with refineries are generally not recognized, as the potential obligations cannot be measured, given their indeterminate settlement dates. Obligations may arise if refineries cease manufacturing operations and any such obligations would be recognized in the period when sufficient information becomes available to determine potential settlement dates. See Note 33 for further information. The group performs periodic reviews of its refineries for any changes in facts and circumstances including those relating to the energy transition, that might require the recognition of a decommissioning provision. Portfolio strength and flexibility are such that the point of cessation of manufacturing at the group’s operating refineries is not yet expected within a determinate time period, as existing property plant and equipment is expected to be renewed or replaced. The provision for environmental liabilities is estimated based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from current estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology. The timing and amount of future expenditures relating to decommissioning and environmental liabilities are reviewed annually. The interest rate used in discounting the cash flows is reviewed quarterly. The nominal interest rate used to determine the balance sheet obligations at the end of 2025 was decommissioning. The weighted average period over which decommissioning and environmental costs are generally expected to be incurred is estimated to be approximately applying an inflation rate of decommissioning as certain costs are expected to remain fixed at current or past prices. The estimated phasing of undiscounted cash flows in real terms for upstream decommissioning is approximately $ within the next 10 years, $ years. The timing and amount of decommissioning cash flows are inherently uncertain and therefore the phasing is management’s current best estimate but may not be what will ultimately occur. Further information about the group’s provisions is provided in Note 23. Changes in assumptions in relation to the group's provisions could result in a material change in their carrying amounts within the next financial year. A could decrease the group’s provision balances by approximately $ would be a credit of approximately $ could arise within the next financial year. The discounting impact on the group's decommissioning provisions for oil and gas properties in the oil productions & operations and gas & low carbon energy segments of a two-year change in the timing of expected future decommissioning expenditures is approximately $ $ therefore the timing of upstream decommissioning expenditure is not a key source of estimation uncertainty. If all expected future decommissioning expenditures were 10% higher, then these decommissioning provisions would increase by approximately $ increase in the inflation rate applied to upstream decommissioning costs to determine the nominal cash flows could increase the decommissioning provision by approximately $ As described in Note 33, the group is subject to claims and actions for which no provisions have been recognized. The facts and circumstances relating to particular cases are evaluated regularly in determining whether a provision relating to a specific litigation should be recognized or revised. Accordingly, significant management judgement relating to provisions and contingent liabilities is required, since the outcome of litigation is difficult to predict. |
Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services
are rendered by employees of the group. Deferred bonus arrangements that have a vesting date more than 12 months after the balance sheet date
are valued on an actuarial basis using the projected unit credit method and amortized on a straight-line basis over the service period until the
award vests. The material accounting policy information for pensions and other post-employment benefits are described below.
bp Annual Report and Form 20-F 2025 | 177 |
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Financial statements | ||||
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
The cost of providing benefits under the group’s defined benefit plans is determined separately for each plan using the projected unit credit
method, which attributes entitlement to benefits to the current period to determine current service cost and to the current and prior periods to
determine the present value of the defined benefit obligation. Past service costs, resulting from either a plan amendment or a curtailment (a
reduction in future obligations as a result of a material reduction in the plan membership), are recognized immediately when the company
becomes committed to a change.
Net interest expense relating to pensions and other post-employment benefits, which is recognized in the income statement, represents the net
change in present value of plan obligations and the value of plan assets resulting from the passage of time, and is determined by applying the
discount rate to the present value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year, taking
into account expected changes in the obligation or plan assets during the year.
Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding amounts
included in net interest described above) are recognized within other comprehensive income in the period in which they occur and are not
subsequently reclassified to profit and loss.
The defined benefit pension plan surplus or deficit recognized on the balance sheet for each plan comprises the difference between the present
value of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets out of which
the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid
price. Defined benefit pension plan surpluses are only recognized to the extent they are recoverable, either by way of a refund from the plan or
reductions in future contributions to the plan.
Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.
Significant estimate: pensions and other post-employment benefits |
Accounting for defined benefit pensions and other post-employment benefits involves making significant estimates when measuring the group's pension plan surpluses and deficits. These estimates require assumptions to be made about many uncertainties. Pensions and other post-employment benefit assumptions are reviewed by management at the end of each year. These assumptions are used to determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the group's balance sheet and pension and other post-employment benefit expense for the following year. The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate and mortality levels. Assumptions about these variables are based on the environment in each country. The assumptions used vary from year to year, with resultant effects on future net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation rate, could result in material changes to the carrying amounts of the group's pension and other post-employment benefit obligations within the next financial year. Any differences between these assumptions and the actual outcome will also affect future net income and net assets. The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and obligation used are provided in Note 24. |
Income tax expense represents the sum of current tax and deferred tax.
Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or
directly in equity, in which case the related tax is recognized in other comprehensive income or directly in equity.
Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is
determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense that
are taxable or deductible in other periods as well as items that are never taxable or deductible. The group’s liability for current tax is calculated
using tax rates and laws that have been enacted or substantively enacted by the balance sheet date.
Deferred tax is provided, using the liability method, on temporary differences at the balance sheet date between the tax bases of assets and
liabilities and their carrying amounts for financial reporting purposes. Deferred tax liabilities are recognized for all taxable temporary differences
except:
•Where the deferred tax liability arises on the initial recognition of goodwill.
•Where the deferred tax liability arises on the initial recognition of an asset or liability in a transaction that is not a business combination, at the
time of the transaction, affects neither accounting profit nor taxable profit or loss and, at the time of the transaction, does not give rise to equal
taxable and deductible temporary differences.
•In respect of taxable temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements,
where the group is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will
not reverse in the foreseeable future.
Deferred tax assets are recognized for deductible temporary differences, carry-forward of unused tax credits and unused tax losses, to the extent
that it is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax
credits and unused tax losses can be utilized, except where the deferred tax asset relating to the deductible temporary difference arises from the
initial recognition of an asset or liability in a transaction that is not a business combination, at the time of the transaction, affects neither accounting
profit nor taxable profit or loss and, at the time of the transaction, does not give rise to equal taxable and deductive temporary differences.
In respect of deductible temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements,
deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and
taxable profit will be available against which the temporary differences can be utilized.
The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable or
increased to the extent that it is probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilized.
178 | bp Annual Report and Form 20-F 2025 |
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the liability is
settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. Deferred tax assets and
liabilities are not discounted.
Deferred tax assets and liabilities are offset only when there is a legally enforceable right to set off current tax assets against current tax liabilities
and when the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or
different taxable entities where there is an intention to settle the current tax assets and liabilities on a net basis or to realize the assets and settle
the liabilities simultaneously.
Where tax treatments are uncertain, if it is considered probable that a taxation authority will accept the group's proposed tax treatment, income
taxes are recognized consistent with the group's income tax filings. If it is not considered probable, the uncertainty is reflected within the carrying
amount of the applicable tax asset or liability using either the most likely amount or an expected value, depending on which method better predicts
the resolution of the uncertainty.
The computation of the group’s income tax expense and liability involves the interpretation of applicable tax laws and regulations in many
jurisdictions throughout the world. The resolution of tax positions taken by the group, through negotiations with relevant tax authorities or through
litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome. Therefore, judgement is required to
determine whether provisions for income taxes are required and, if so, estimation is required of the amounts that could be payable.
In addition, the group has carry-forward tax losses and tax credits in certain taxing jurisdictions that are available to offset against future taxable
profit. However, deferred tax assets are recognized only to the extent that it is probable that taxable profit will be available against which the
unused tax losses or tax credits can be utilized. Management judgement is exercised in assessing whether this is the case and estimates are
required to be made of the amount of future taxable profits that will be available. Such judgements are inherently impacted by estimates affecting
future taxable profits such as oil and natural gas prices and decommissioning expenditure, see 'Significant judgements and estimates:
recoverability of asset carrying values and provisions'.
The group is subject to legislation which implements the OECD Pillar Two Model rules in the UK and many other countries around the world. The
legislation is designed to ensure a minimum effective tax rate of 15% in each country in which the group operates. In the UK this includes an income
inclusion rule and a domestic minimum tax. In line with the amendments to IAS 12, the exception from recognising and disclosing information about
deferred tax assets and liabilities related to Pillar Two income taxes has been applied.
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 2025 resulting in a non-cash deferred tax charge of $539 million in the year.
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 resulted in a non-cash deferred tax charge of $235 million in the year.
Significant judgement and estimate: taxation |
The value of deferred tax assets and liabilities is an area involving inherent uncertainty and estimation and balances are therefore subject to risk of material change as a result of underlying assumptions and judgements used, in particular the forecast of future profitability used to determine the recoverability of deferred tax, for example future oil and gas prices, see ‘Significant judgement and estimates - Recoverability of asset carrying values’. It is impracticable to disclose the extent of the possible effects of profitability assumptions on the group’s deferred tax assets. It is reasonably possible that to the extent that actual outcomes differ from management’s estimates, material income tax charges or credits, and material changes in current and deferred tax assets or liabilities, may arise within the next financial year and in future periods. Judgement is required when determining whether a particular tax is an income tax or another type of tax (for example, a production tax). The attributes of the tax, including whether it is calculated on profits or another measure such as production or revenues, the extent of deductibility of costs and the interaction with existing income taxes, are considered in determining the classification of the tax. Accounting for deferred tax is applied to income taxes as described above but is not applied to other types of taxes; rather such taxes are recognized in the income statement in accordance with the applicable accounting policy such as Provisions and contingencies. This judgement is considered significant only in relation to the group’s taxes payable under the fiscal terms of bp’s onshore concession in Abu Dhabi. These are principally reported as income taxes rather than as production taxes. For more information see Note 9 and Note 33. |
Customs duties and sales taxes that are passed on or charged to customers are excluded from revenues and expenses. Assets and liabilities are
recognized net of the amount of customs duties or sales tax except:
•Customs duties or sales taxes incurred on the purchase of goods and services which are not recoverable from the taxation authority are
recognized as part of the cost of acquisition of the asset.
•Receivables and payables are stated with the amount of customs duty or sales tax included.
The net amount of sales tax recoverable from, or payable to, the taxation authority is included within receivables or payables in the balance sheet.
bp Annual Report and Form 20-F 2025 | 179 |
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Financial statements | ||||
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
The group’s holdings in its own equity instruments are shown as deductions from shareholders’ equity. Treasury shares represent bp shares
repurchased and available for specific and limited purposes. For accounting purposes, shares held in Employee Share Ownership Plans (ESOPs) to
meet the future requirements of the employee share-based payment plans are treated in the same manner as treasury shares and are, therefore,
included in the consolidated financial statements as treasury shares. The cost of treasury shares subsequently sold or reissued is calculated on a
weighted-average basis. Consideration, if any, received for the sale of such shares is also recognized in equity. No gain or loss is recognized in the
income statement on the purchase, sale, issue or cancellation of equity shares. Shares repurchased and immediately cancelled are not shown as
treasury shares. Instead, the nominal amount is transferred to the capital redemption reserve and any difference to the purchase price is shown as
a deduction from the profit and loss account reserve in the group statement of changes in equity.
Revenue from contracts with customers is recognized when or as the group satisfies a performance obligation by transferring control of a
promised good or service to a customer. The transfer of control of oil, natural gas, natural gas liquids, LNG, petroleum and chemical products, and
other items usually coincides with title passing to the customer and the customer taking physical possession. The group principally satisfies its
performance obligations at a point in time; the amounts of revenue recognized relating to performance obligations satisfied over time are not
significant.
When, or as, a performance obligation is satisfied, the group recognizes as revenue the amount of the transaction price that is allocated to that
performance obligation. The transaction price is the amount of consideration to which the group expects to be entitled. The transaction price is
allocated to the performance obligations in the contract based on standalone selling prices of the goods or services promised.
Contracts for the sale of commodities are typically priced by reference to quoted prices. Revenue from term commodity contracts is recognized
based on the contractual pricing provisions for each delivery. Certain of these contracts have pricing terms based on prices at a point in time after
delivery has been made. Revenue from such contracts is initially recognized based on relevant prices at the time of delivery and subsequently
adjusted as appropriate. All revenue from these contracts, both that recognized at the time of delivery and that from post-delivery price
adjustments, is disclosed as revenue from contracts with customers.
Sales and purchase of commodities accounted for under IFRS 15 are presented on a gross basis in Revenue from contracts with customers and
Purchases respectively. Physically settled derivatives which represent trading or optimization activities are presented net alongside financially
settled derivative contracts in Other operating revenues within Sales and other operating income. Certain physically settled sale and purchase
derivative contracts which are not part of trading and optimization activities are presented gross within Other operating revenues and Purchases
respectively. Changes in the fair value of derivative assets and liabilities prior to physical delivery are also classified as other operating revenues.
Physical exchanges with counterparties in the same line of business in order to facilitate sales to customers are reported net, as are sales and
purchases made with a common counterparty, as part of an arrangement similar to a physical exchange.
Where the group acts as agent on behalf of a third party to procure or market energy commodities, any associated fee income is recognized but no
purchase or sale is recorded.
Sales and other transactions through which the group loses control of solar projects developed under Lightsource bp’s develop-to-sell business
model are accounted for as revenues from contracts with customers.
Interest income is recognized as the interest accrues (using the effective interest rate, that is, the rate that exactly discounts estimated future cash
receipts through the expected life of the financial instrument to the net carrying amount of the financial asset).
Dividend income from investments is recognized when the shareholders’ right to receive the payment is established.
Finance costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a
substantial period of time to get ready for their intended use, are added to the cost of those assets until such time as the assets are substantially
ready for their intended use. All other finance costs are recognized in the income statement in the period in which they are incurred.
Impact of new International Financial Reporting Standards
There are no new or other amended standards or interpretations adopted from 1 January 2025 onwards, that have a significant impact on the
consolidated financial statements for 2025.
180 | bp Annual Report and Form 20-F 2025 |
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Not yet adopted
Amendments to IFRS 9 ' Financial Instruments' relating to the settlement of liabilities through electronic payment systems are effective for annual
periods beginning on or after 1 January 2026. bp will adopt the amendments in the financial reporting period commencing 1 January 2026 using the
modified retrospective approach. The amendments clarify the timing of derecognition of financial instruments and whilst they permit financial
liabilities to be derecognized before the settlement date if certain criteria are met, the group is not expected to make this election. Management
has considered the amendments and does not anticipate any material effect on the Group’s financial position or results. The expected impact on
transition is a $34 million increase to cash and cash equivalents.
IFRS 18 ‘Presentation and Disclosure in Financial Statements’ will supersede IAS 1 ‘Presentation of Financial Statements’ and is effective for annual
periods beginning on or after 1 January 2027. IFRS 18 (and consequential amendments made to IAS 7 ‘Statement of Cash Flows’, IAS 8 ‘Accounting
Policies: Changes in Accounting Estimates and Errors’, IAS 33 ‘Earnings per share’ and IFRS 7 ‘Financial Instruments: Disclosures’) introduces several
new requirements that are expected to impact the presentation and disclosure of the Group’s consolidated financial statements. These new
requirements include:
•Requirements to classify all income and expenses included in the statement of profit or loss into one of five categories and to present two new
mandatory subtotals.
•Requirement to use the operating profit subtotal as the starting point for the indirect method of reporting cash flows from operating activities in
the statement of cash flows.
•Specific classification requirements for interest paid/received and dividends received in the statement of cash flows such that interest and
dividend receipts are included as investing cash flows and interest paid as financing cash flows.
•Required disclosures about certain non-GAAP measures (‘management defined performance measures’) in a single note to the financial
statements
•Enhanced guidance on the aggregation of information across all the primary financial statements and the notes.
The group’s evaluation of the effect of adopting IFRS 18 is ongoing but it is currently anticipated that IFRS 18 will have a significant impact on the
presentation of the Group’s financial statements and related disclosures.
bp Annual Report and Form 20-F 2025 | 181 |
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Financial statements | ||||
2. Non-current assets held for sale
The carrying amount of assets classified as held for sale at 31 December 2025 is $6,347 million (2024 $4,081 million), with associated liabilities of
$1,594 million (2024 $1,105 million).
gas & low carbon energy
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. The carrying amount of assets classified as held for sale at 31 December 2025 is
$1,916 million (2024 $1,702 million), with associated liabilities of $1,254 million (2024 $1,050 million). The sale of the majority of these assets and
liabilities completed in February 2026. Completions of the sales of the remaining assets and liabilities are expected to occur in 2026.
customers & products
On 24 December 2025, bp announced an agreement with Stonepeak to divest a 65 % shareholding in the Castrol business with bp retaining a 35 %
interest through a holding in a newly incorporated entity. Cash proceeds are estimated at $6 billion. The transaction is expected to complete by the
end of 2026, subject to regulatory approvals. The carrying amount of assets classified as held for sale at 31 December 2025 is $4,431 million
including $2,760 million of goodwill that arose on the acquisition of Castrol in 2000, with associated liabilities of $340 million. Net working capital,
which at 31 December 2025 was approximately $1.2 billion, has not been classified as assets and associated liabilities held for sale. The working
capital balances as at completion will be transferred to the buyer. At 31 December 2025, there are also associated cumulative foreign exchange
losses within reserves of approximately $1.6 billion. Such reserves are expected to be recycled to the group income statement at completion. The
shares to be held by Stonepeak are subject to preferred distributions, the effect of which is that bp does not expect to recognize income or
dividends from the investment in the short to medium term.
Transactions that have been either classified as held for sale at 31 December 2024 or during 2025, but were completed by 31 December 2025, are
described below.
gas & low carbon energy
On 9 December 2024, bp and JERA Co., Inc. agreed to combine their offshore wind businesses to form a new standalone, equally-owned joint
venture – JERA Nex bp. On 1 August 2025, this transaction was completed. bp contributed its development projects in the UK, Germany and US into
the joint venture. The related assets and liabilities of those projects, which had been classified as held for sale since the announcement of the
transaction, were derecognized at completion.
On 16 September 2024, bp announced that it planned to sell its US onshore wind energy business, bp Wind Energy and on 18 July 2025 the sale of
the business to LS Power was announced. bp Wind Energy has interests in ten operating onshore wind energy assets across seven US states. The
transaction completed on 9 December 2025. The related assets and liabilities of those projects, previously classified as held for sale, were
derecognized on that date.
oil production & operations
On 31 January 2025 bp and Devon Energy agreed to dissolve their Eagle Ford partnership and divide up the assets. The dissolution completed on 1
April 2025.
customers & products
On 9 July 2025, bp announced the sale of its Netherlands mobility & convenience and bp pulse businesses to Catom BV. The transaction includes
bp’s Dutch retail sites, EV charging hubs and the associated fleet business. The sale completed on 1 December 2025.
segments, are set out in the table below.
$ million | |||
2025 | 2024 | ||
Property, plant and equipment | |||
Goodwill | |||
Intangible assets | |||
Investments in associates | |||
Investments in joint ventures | |||
Other investments | |||
Inventories | |||
Cash | |||
Trade and other receivables | |||
Deferred tax assets | |||
Assets classified as held for sale | |||
Trade and other payables | ( | ( | |
Lease liabilities | ( | ( | |
Finance debt | ( | ( | |
Provisions | ( | ( | |
Deferred tax liabilities | ( | ||
Defined benefit pension plan and other post-employment benefit plan deficits | ( | ||
Liabilities directly associated with assets classified as held for sale | ( | ( |
182 | bp Annual Report and Form 20-F 2025 |
3. Business combinations and other significant transactions
Business combinations
2025
There were no material business combinations completed in 2025.
Business combinations
2024
The group undertook a number of business combinations during 2024. Total consideration was $2,119 million and the amount paid in cash in 2024
amounted to $978 million offset by cash acquired of $1,031 million.
These business combinations principally relate to the step acquisitions of bp Bunge Bioenergia and Lightsource bp. Total consideration for these
two acquisitions was $1,328 million and the amount paid in cash in 2024 was $227 million, offset by cash acquired of $589 million. The fair value of
the net assets (including goodwill) recognized from these business combinations for 2024 was $2,848 million.
The gain recognized in ‘Interest and other income’ in 2024 as a result of remeasuring the previously held interests in bp Bunge Bioenergia and
Lightsource bp, to fair value, was $427 million.
Immediately prior to the Lightsource bp business combination, certain assets in the US were transferred from Lightsource bp into a new joint
venture which remains jointly controlled by bp and certain founder shareholders of Lightsource bp, and is accordingly equity accounted for by bp.
The investment in the new joint venture was measured at bp's share of the joint venture's net assets and, as a result, income of $498 million has
been recognized in ‘Interest and other income’ in 2024.
4. Disposals and impairment
$ million | ||||
2025 | 2024 | 2023 | ||
Gains on sale of businesses and fixed assets | ||||
gas & low carbon energy | ||||
oil production & operations | ||||
customers & products | ||||
other businesses & corporate | ||||
$ million | ||||
2025 | 2024 | 2023 | ||
Losses on sale of businesses and fixed assets, and closures | ||||
gas & low carbon energy | ||||
oil production & operations | ||||
customers & products | ||||
other businesses & corporate | ( | |||
Impairment losses | ||||
gas & low carbon energya | ||||
oil production & operations | ||||
customers & productsa | ||||
other businesses & corporate | ||||
Impairment reversals | ||||
gas & low carbon energy | ( | ( | ( | |
oil production & operations | ( | ( | ( | |
customers & products | ( | ( | ||
other businesses & corporate | ( | ( | ||
( | ( | ( | ||
Impairment and losses on sale of businesses and fixed assets, and closures |
a2024 balances and related narrative has been restated to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment.
bp Annual Report and Form 20-F 2025 | 183 |
| ||||
Financial statements | ||||
4. Disposals and impairment – continued
Disposals
$ million | ||||
2025 | 2024 | 2023 | ||
Proceeds from disposals of fixed assets | ||||
Proceeds from disposals of businesses, net of cash disposed | ||||
By business | ||||
gas & low carbon energy | ||||
oil production & operations | ||||
customers & products | ||||
other businesses & corporate | ||||
Proceeds from disposals of businesses in 2025 includes proceeds relating to the sale of the US onshore wind business and the disposal of the
Netherlands mobility & convenience and bp pulse businesses, as well as other smaller amounts. Proceeds from disposals of businesses in 2024
includes $594 million relating to the formation of a new joint venture, Arcius Energy, in Egypt, as well as $1,331 million relating to Alaska and
$252 million relating to Canada, both prior period disposals. At 31 December 2025, deferred consideration relating to disposals amounted to $48
million receivable within one year (2024 $112 million and 2023 $141 million) and $247 million receivable after one year (2024 $244 million and 2023
$217 million). The amounts of deferred consideration are reported within Trade and other receivables in Other receivables in the group balance
sheet. In addition, contingent consideration receivable relating to disposals amounted to $85 million at 31 December 2025 (2024 $190 million and
2023 $1,694 million). The contingent consideration at 31 December 2025 primarily relates to the prior period disposal of certain assets in the North
Sea. These amounts of contingent consideration are reported within Other investments on the group balance sheet - see Note 18 for further
information.
Gains and losses on sale of businesses and fixed assets, and closures
gas & low carbon energy
In 2025 losses principally arose upon the formation of a new offshore wind joint venture JERA Nex bp.
oil production & operations
In 2025 gains principally relate to a disposal in the North Sea and an asset exchange in bpx.
In 2023 gains principally related to prior period disposals in the US and Canada.
customers & products
In 2024 losses principally related to a loss of $1,132 million arising from the divestment of our Türkiye ground fuels business.
Summarized financial information relating to the sale of businesses is shown in the table below.
The principal transactions categorized as a business disposal in 2025 were the formation of a new offshore wind joint venture, JERA Nex bp, in
which bp contributed its development projects in the UK, Germany and US into the joint venture; the disposal of the Netherlands mobility &
convenience and bp pulse businesses; the sale of the US onshore wind business; and an asset exchange in bpx.
The principal transactions categorized as a business disposal in 2024 were the divestment of our Türkiye ground fuels business, the new joint
venture transaction with ADNOC in Egypt and a transaction relating to the prior period disposal in Alaska.
The principal transactions categorized as a business disposal in 2023 were the sale of the upstream business in Algeria to Eni and the disposal of
the bp-Husky Toledo refinery to Cenovus Energy.
184 | bp Annual Report and Form 20-F 2025 |
4. Disposals and impairment – continued
$ million | ||||
2025 | 2024 | 2023 | ||
Non-current assets | ||||
Current assets | ||||
Non-current liabilities | ( | ( | ( | |
Current liabilities | ( | ( | ( | |
Total carrying amount of net assets disposed | ||||
Recycling of foreign exchange on disposal | ||||
Costs on disposal | ||||
Gains (losses) on sale of businesses | ( | |||
Total consideration | ||||
Non-cash consideration | ( | ( | ( | |
Consideration received (receivable) | ( | |||
Proceeds from the sale of businesses, net of cash disposeda |
aProceeds are stated net of cash and cash equivalents disposed of $61 million (2024 $500 million and 2023 $33 million).
Impairments
Impairment losses and impairment reversals in each segment are described below. For information on significant estimates and judgements made
in relation to impairments see Impairment of property, plant and equipment, intangibles, goodwill and equity-accounted entities within Note 1. See
also Note 12, and Note 15 for further information on impairments by asset category.
gas & low carbon energy
The 2025 impairment loss of $4,146 million includes $3,537 million relating to the transition businesses, principally Archaea Energy and Lightsource
bp, and $609 million relating to the upstream gas business, principally Mauritania and Senegal. The impairments arose as a result of revised
assumptions including capital and operating expenditure and the impact of market conditions on project development. The recoverable amount of
all CGUs for which impairment charges were recognized in 2025 is $8,805 million.
The 2024 impairment loss of $3,310 million includes amounts in Mauritania & Senegal ($1,495 million), which principally arose as a result of increased
forecast future expenditure, and a number of other individually immaterial impairments across the segment principally as a result of portfolio
management. The recoverable amounts of these cash generating units (CGUs) were based on value in use or fair value less costs of disposal
calculations, as appropriate. The recoverable amount of all CGUs for which impairment charges were recognized in 2024 is $5,025 million.
The 2023 impairment loss of $2,213 million primarily relates to losses incurred in respect of certain assets in Mauritania & Senegal ($1,434 million)
and principally arose as a result of increased forecast future expenditure. A further $565 million relates to producing assets in Trinidad and arose as
a result of changes to the group's oil and gas price and discount rate assumptions and activity phasing. The recoverable amount of all CGUs for
which impairment charges or reversals were recognized in 2023 in total, based on their value in use, is $4,811 million.
oil production & operations
Impairment losses and reversals in all years relate primarily to producing assets.
The 2025 impairment loss of $454 million primarily arose as a result of changes to reserves and decommissioning provisions mainly driven by
foreign exchange in the North Sea ($397 million). The recoverable amount of all CGUs for which impairment charges or reversals were recognized in
2025 in total, based on their value in use, is $2,058 million.
The 2024 impairment loss of $1,155 million primarily arose as a result of changes to reserves and tax assumptions in the North Sea ($1,035 million).
The recoverable amount of all CGUs for which impairment charges or reversals were recognized in 2024 in total, based on their value in use, is
$8,705 million.
The 2023 impairment loss of $1,840 million primarily arose as a result of changes to the group's oil and gas price and discount rate assumptions,
activity phasing and disposal decisions in relation to certain assets in North Sea ($852 million) and in bpx energy ($802 million). The recoverable
amount of all CGUs for which impairment charges or reversals were recognized in 2023 in total, based on their value in use, is $14,072 million.
customers & products
The 2025 impairment loss of $926 million primarily relates to strategy implementation in the products business. The recoverable amount of all
CGUs for which impairment charges or reversals were recognized in 2025 in total, based on their value in use, is $49 million.
The 2024 impairment loss of $1,144 million primarily arises from the ongoing review of the Gelsenkirchen refinery in Germany ($807 million) and a
number of other individually immaterial impairments across the segment, principally as a result of changes to economic assumptions. The
recoverable amount of the CGUs were based on value-in-use calculations. The recoverable amount of all CGUs for which impairment charges or
reversals were recognized in 2024 in total, based on their value-in-use, is $57 million.
The 2023 impairment loss of $1,614 million primarily relates to strategy implementation and changes to economic assumptions in the products
business including an impairment of the Gelsenkirchen refinery in Germany ($1,336 million). The recoverable amounts of the CGUs were based on
value-in-use calculations. The recoverable amount of all CGUs for which impairment charges or reversals were recognized in 2023 in total, based on
their value in use, is $327 million.
bp Annual Report and Form 20-F 2025 | 185 |
| ||||
Financial statements | ||||
5. Segmental analysis
The group’s organizational structure reflects the various activities in which bp is engaged as well as how performance and resource allocation is
evaluated by the chief operating decision maker. At 31 December 2025, bp has three reportable segments: Gas & low carbon energy, Oil production
& operations, and Customers & products. Each are managed separately, with decisions taken for the segment as a whole, and represent a single
operating segment that does not result from aggregating two or more segments.
Gas & low carbon energy comprises regions with upstream businesses that predominantly produce natural gas, gas marketing and trading
activities and the group's solar, wind, hydrogen and Archaea Energy business.
Oil production & operations comprises regions with upstream activities that predominantly produce crude oil.
Customers & products comprises the group’s customer-focused businesses, which includes convenience and retail fuels, EV charging, as well as
Castrol, aviation, B2B, midstream and bp bioenergy. It also comprises our products businesses which include refining and oil trading.
Other businesses and corporate also comprises the group’s shipping and treasury functions, and corporate activities worldwide.
Change in segmentation
For 2025, our Archaea Energy 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 and 2023 has been restated where material to reflect the changes in reportable segments.
the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker
for the purposes of performance assessment and resource allocation. For bp, this measure of profit or loss is replacement cost profit or loss before
interest and tax which reflects the replacement cost of supplies by excluding from profit or loss before interest and tax inventory holding gains and
lossesa. Replacement cost profit or loss before interest and tax for the group is not a recognized measure under IFRS.
Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues and
segment results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on
consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers by region are
based on the location of the group subsidiary which made the sale. The UK region includes the UK-based international activities of customers &
products.
All surpluses and deficits recognized on the group balance sheet in respect of pension and other post-employment benefit plans are allocated to
Other businesses and corporate. However, the periodic expense relating to these plans is allocated to the operating segments based upon the
business in which the employees work.
Certain financial information is provided separately for the US as this is an individually material country for bp, and for the UK as this is bp’s country
of domicile.
aInventory holding gains and losses 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.
•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.
186 | bp Annual Report and Form 20-F 2025 |
5. Segmental analysis – continued
$ million | |||||||
2025 | |||||||
By business | gas & low carbon energy | oil production & operations | customers & products | other businesses & corporate | Consolidation adjustment and eliminations | Total group | |
Segment revenues | |||||||
Sales and other operating revenues | ( | ||||||
Less: sales and other operating revenues between segments | ( | ( | ( | ( | |||
Third party sales and other operating revenues | |||||||
Earnings from joint ventures and associates – after interest and tax | ( | ( | |||||
Segment results | |||||||
Replacement cost profit (loss) before interest and taxation | ( | ||||||
Inventory holding gains (losses)a | ( | ( | |||||
Profit (loss) before interest and taxation | ( | ||||||
Finance costs | ( | ||||||
Net finance income relating to pensions and other post- employment benefits | |||||||
Profit before taxation | |||||||
Other income statement items | |||||||
Depreciation, depletion and amortization | |||||||
US | |||||||
Non-US | |||||||
Charges for provisions, net of write-back of unused provisions, including change in discount rate | |||||||
Segment assets | |||||||
Investments in joint ventures and associates | |||||||
Additions to non-current assetsb |
aSee explanation of inventory holding gains and losses on page 185.
bIncludes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
bp Annual Report and Form 20-F 2025 | 187 |
| ||||
Financial statements | ||||
5. Segmental analysis – continued
$ million | |||||||
2024 | |||||||
By business | gas & low carbon energya | oil production & operations | customers & productsa | other businesses & corporate | Consolidation adjustment and eliminations | Total group | |
Segment revenues | |||||||
Sales and other operating revenues | ( | ||||||
Less: sales and other operating revenues between segments | ( | ( | ( | ( | |||
Third party sales and other operating revenues | |||||||
Earnings from joint ventures and associates – after interest and tax | ( | ||||||
Segment results | |||||||
Replacement cost profit (loss) before interest and taxationa | ( | ( | ( | ||||
Inventory holding gains (losses)b | ( | ( | ( | ||||
Profit (loss) before interest and taxationa | ( | ( | ( | ||||
Finance costs | ( | ||||||
Net finance income relating to pensions and other post- employment benefits | |||||||
Profit before taxation | |||||||
Other income statement items | |||||||
Depreciation, depletion and amortization | |||||||
US | |||||||
Non-US | |||||||
Charges for provisions, net of write-back of unused provisions, including change in discount rate | |||||||
Segment assets | |||||||
Investments in joint ventures and associatesa | |||||||
Additions to non-current assetsa c |
aRestated for material items to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment.
bSee explanation of inventory holding gains and losses on page 185.
cIncludes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
188 | bp Annual Report and Form 20-F 2025 |
5. Segmental analysis – continued
$ million | |||||||
2023 | |||||||
By business | gas & low carbon energya | oil production & operations | customers & productsa | other businesses & corporate | Consolidation adjustment and eliminations | Total group | |
Segment revenues | |||||||
Sales and other operating revenues | ( | ||||||
Less: sales and other operating revenues between segments | ( | ( | ( | ( | |||
Third party sales and other operating revenues | |||||||
Earnings from joint ventures and associates – after interest and tax | ( | ( | |||||
Segment results | |||||||
Replacement cost profit (loss) before interest and taxation | ( | ( | |||||
Inventory holding gains (losses)b | ( | ( | |||||
Profit (loss) before interest and taxation | ( | ( | |||||
Finance costs | ( | ||||||
Net finance income relating to pensions and other post- employment benefits | |||||||
Profit before taxation | |||||||
Other income statement items | |||||||
Depreciation, depletion and amortization | |||||||
US | |||||||
Non-US | |||||||
Charges for provisions, net of write-back of unused provisions, including change in discount rate | |||||||
Segment assets | |||||||
Investments in joint ventures and associatesa | |||||||
Additions to non-current assetsa c |
aRestated for material items to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment.
bSee explanation of inventory holding gains and losses on page 185.
cIncludes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
$ million | ||||
2025 | ||||
By geographical area | US | Non-US | Total | |
Revenues | ||||
Third party sales and other operating revenuesa | ||||
Other income statement items | ||||
Production and similar taxes | ||||
Non-current assets | ||||
Non-current assetsb c |
aNon-US region includes UK $28,714 million
bNon-US region includes UK $21,529 million
cIncludes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.
$ million | ||||
2024 | ||||
By geographical area | US | Non-US | Total | |
Revenues | ||||
Third party sales and other operating revenuesa | ||||
Other income statement items | ||||
Production and similar taxes | ||||
Non-current assets | ||||
Non-current assetsb c |
aNon-US region includes UK $24,577 million.
bNon-US region includes UK $25,354 million.
cIncludes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.
bp Annual Report and Form 20-F 2025 | 189 |
| ||||
Financial statements | ||||
5. Segmental analysis – continued
$ million | ||||
2023 | ||||
By geographical area | US | Non-US | Total | |
Revenues | ||||
Third party sales and other operating revenuesa | ||||
Other income statement items | ||||
Production and similar taxes | ||||
Non-current assets | ||||
Non-current assetsb c |
aNon-US region includes UK $39,975 million.
bNon-US region includes UK $23,949 million.
cIncludes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.
6. Sales and other operating revenues
$ million | ||||
2025 | 2024 | 2023 | ||
Crude oil | ||||
Oil products | ||||
Natural gas, LNG and NGLs | ||||
Non-oil products and other revenues from contracts with customers | ||||
Revenue from contracts with customers | ||||
Other operating revenuesa | ||||
Total sales and other operating revenues |
aPrincipally relates to commodity derivative transactions including sales of bp own production in trading books.
An analysis of third-party sales and other operating revenues by segment and region is provided in Note 5.
The group’s sales to customers of crude oil and oil products were substantially all made by the customers & products segment. The group’s sales
to customers of natural gas, LNG and NGLs were made by the gas & low carbon energy segment. A significant majority of the group’s sales of non-
oil products and other revenues from contracts with customers were made by the customers & products segment.
7. Income statement analysis
$ million | ||||
2025 | 2024 | 2023 | ||
Interest and other income | ||||
Interest income from | ||||
Financial assets measured at amortized cost | ||||
Financial assets measured at fair value through profit or loss | ||||
Other incomea | ||||
Currency exchange losses charged to the income statementb | ( | |||
Expenditure on research and development | ||||
Costs relating to the Gulf of America oil spill (pre-interest and tax)c | ||||
Finance costs | ||||
Interest expense on lease liabilities | ||||
Interest expense on other liabilities measured at amortized costd | ||||
Capitalized at | ( | ( | ( | |
Finance debt risk management activitiesf | ( | ( | ||
Unwinding of discount on provisions | ||||
Unwinding of discount on other payables measured at amortized cost | ||||
a2024 includes a $427 million gain relating to the remeasurement of bp's previously held interests in bp Bunge Bioenergia and Lightsource bp and $498 million relating to the remeasurement of
certain US assets excluded from the Lightsource bp acquisition. See Note 3 for further information.
bExcludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss.
cIncluded within production and manufacturing expenses.
d2023 includes a loss of $49 million associated with the buyback of finance debt.
eTax relief on capitalized interest is approximately $36 million (2024 $53 million and 2023 $130 million).
fIncludes temporary valuation differences related to the group’s interest rate and foreign currency exchange risk management associated with finance debt.
190 | bp Annual Report and Form 20-F 2025 |
8. Exploration for and evaluation of oil and natural gas resources
The following financial information represents the amounts included within the group totals relating to activity associated with the exploration for
and evaluation of oil and natural gas resources. All such activity is recorded within the gas & low carbon energy and oil production & operations
segments.
For information on significant judgements made in relation to oil and natural gas accounting see Intangible assets in Note 1.
$ million | ||||
2025 | 2024 | 2023 | ||
Exploration and evaluation costs | ||||
Exploration expenditure written off | ||||
Other exploration costs | ||||
Exploration expense for the year | ||||
Impairment losses | ||||
Intangible assets – exploration and appraisal expenditurea | ||||
Liabilities | ||||
Net assets | ||||
Cash used in operating activities | ||||
Cash used in investing activities |
aAmount capitalized at 31 December 2025, 2024 and 2023 relates to assets in various regions. This includes $536 million in the Brazil region (2024 $395 million, 2023 $418 million), $776 million in
the Middle East and North Africa region (2024 $1,289 million, 2023 $1,182 million) and $609 million in the Azerbaijan Georgia and Türkiye region (2024 $651 million, 2023 $631 million).
9. Taxation
$ million | ||||
2025 | 2024 | 2023 | ||
Current tax | ||||
Charge for the yeara | ||||
Adjustment in respect of prior years | ( | ( | ||
Deferred tax | ||||
Origination and reversal of temporary differences in the current yearb | ( | ( | ( | |
Adjustment in respect of prior yearsc | ( | ( | ||
( | ( | |||
Tax charge on profit |
a2025 includes a charge of $55 million (2024 $4 million charge) in respect of Pillar Two income taxes.
b2025 includes a charge of $539 million in respect of the two-year extension of the UK Energy Profits Levy to 31 March 2030 and a charge of $235 million in respect of a change in the tax rate in
Germany. 2024 includes a charge of $96 million in respect of the 3% increase in the UK Energy Profits Levy from 1 November 2024. See Note 1 for further information.
cThe adjustment in respect of prior years reflects the reassessment of the deferred tax balances for prior periods in light of changes in facts and circumstances during the year, including changes
to price assumptions and profit forecasts (2025 $558 million charge, 2024 $190 million credit and 2023 $263 million credit). 2024 also includes a charge of $213 million (2023 $232 million credit) in
respect of a revision to the deferred tax impact of the UK Energy Profits Levy.
In 2025, the total tax credit recognized within other comprehensive income was $33 million (2024 $782 million credit and 2023 $735 million credit).
In 2025 and 2023 this primarily comprises the deferred tax impact of the remeasurements of the net pension and other post-employment benefit
liability or asset. In 2024 this primarily comprises 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%. See Note 32
for further information.
The total tax credit recognized directly in equity was $33 million (2024 $167 million charge and 2023 $56 million charge). In 2025 this relates to
share-based payments. In 2024 this mainly relates to share-based payments and transactions involving non-controlling interests. In 2023 this
mainly relates to transactions involving non-controlling interests.
bp Annual Report and Form 20-F 2025 | 191 |
| ||||
Financial statements | ||||
9. Taxation – continued
Reconciliation of the effective tax rate
The following table provides a reconciliation of the group weighted average statutory corporate income tax rate to the effective tax rate of the
group on profit or loss before taxation.
$ million | ||||
2025 | 2024 | 2023 | ||
Profit (loss) before taxation | ||||
Tax charge (credit) on profit or loss | ||||
Effective tax rate | ||||
% | ||||
Tax rate computed at the weighted average statutory ratea | ||||
Increase (decrease) resulting from | ||||
Tax reported in equity-accounted entities | ( | ( | ( | |
Adjustments in respect of prior years | ( | |||
Deferred tax not recognized | ||||
Disposal impacts | ||||
Foreign exchange | ( | |||
Items not deductible for tax purposesb | ||||
Tax rate change effect of UK Energy Profits Levyc | ||||
Impact of Germany tax rate change | ||||
Otherd | ( | |||
Effective tax rate |
aCalculated based on the statutory corporate income tax rate applicable in the countries in which the group operates, weighted by the profits and losses before tax in the respective countries.
b2025 reflects the impact of limited tax relief on impairment charges.
c2025 comprises the deferred tax impact of the two-year extension of the UK Energy Profits Levy to 31 March 2030. 2024 comprises the deferred tax impact of a 3% increase in the UK Energy
Profits Levy on existing temporary differences.
dIncludes the impact of adjustments arising in countries where income tax is paid on our behalf by our government partners for which there is no deferred tax effect. 2024 includes the impact of
the non-taxable gain relating to the remeasurement of bp's pre-existing 49.97 % interest in Lightsource bp and the remeasurement of certain US assets excluded from the Lightsource bp
acquisition.
Deferred tax
$ million | |||
Analysis of movements during the year in the net deferred tax liability | 2025 | 2024 | |
At 1 January | |||
Exchange adjustments | ( | ||
Charge (credit) for the year in the income statement | ( | ||
Charge (credit) for the year in other comprehensive income | ( | ( | |
Charge (credit) for the year in equity | ( | ||
Acquisitions and disposals | |||
At 31 December |
192 | bp Annual Report and Form 20-F 2025 |
9. Taxation – continued
The following table provides an analysis of deferred tax in the income statement and the balance sheet by category of temporary difference:
$ million | ||||||
Income statement | Balance sheet | |||||
2025 | 2024 | 2023 | 2025 | 2024 | ||
Deferred tax liability | ||||||
Depreciation | ( | ( | ( | |||
Pension plan surpluses | ( | |||||
Derivative financial instruments | ||||||
Other taxable temporary differencesa | ( | |||||
( | ( | ( | ||||
Deferred tax asset | ||||||
Depreciation | ( | ( | ( | ( | ||
Lease liabilities | ( | ( | ( | ( | ( | |
Pension plan and other post-employment benefit plan deficits | ( | ( | ( | |||
Decommissioning, environmental and other provisions | ( | ( | ( | |||
Derivative financial instruments | ( | ( | ( | ( | ( | |
Tax credits | ( | ( | ( | ( | ( | |
Loss carry forward | ( | ( | ||||
Other deductible temporary differencesb | ( | ( | ( | |||
( | ( | ( | ||||
Net deferred tax charge (credit) and net deferred tax liability | ( | ( | ||||
Of which – deferred tax liabilities | ||||||
– deferred tax assets | ||||||
aThe 2025 and 2024 balance sheet amounts do not include any temporary differences that are individually significant.
bThe 2025 and 2024 balance sheet amounts include amounts relating to share based payments and other items.
Of the $4,325 million of deferred tax assets recognized on the group balance sheet at 31 December 2025 (2024 $5,403 million), $2,795 million (2024
$3,232 million) relates to entities that have suffered a loss in either the current or preceding period. For 2025, this mainly includes $1,613 million in
Germany, $473 million in Senegal and $388 million in Mauritania (2024 mainly included $1,680 million in Germany, $744 million in Mauritania and
$609 million in Senegal). For 2025, these amounts are supported by forecasts consistent with bp's future oil and gas price assumptions (see Note 1
for further information) and other assumptions used for impairment testing, and for Germany forecast profits associated with the customers &
products businesses that indicate sufficient future taxable profits will be available to utilize such assets within any applicable expiry period.
table below.
$ billion | |||
At 31 December | 2025 | 2024 | |
Unused US state tax lossesa | |||
Unused tax losses – other jurisdictionsb | |||
Unused tax credits | |||
of which – arising in the UKc | |||
– arising in the USd | |||
Deductible temporary differencese | |||
Taxable temporary differences associated with investments in subsidiaries and equity-accounted entities |
aFor 2025 the majority of the unused tax losses have no fixed expiry date.
b2025 and 2024 mainly relate to Brazil, UK and Canada. The majority of the unused tax losses have no fixed expiry date.
cThe UK unused tax credits arise predominantly in overseas branches of UK entities based in jurisdictions with higher statutory corporate income tax rates than the UK. No deferred tax asset has
been recognized on these tax credits as they are unlikely to have value in the future; UK taxes on these overseas branches are largely mitigated by double tax relief in respect of overseas tax.
These tax credits have no fixed expiry date.
dThe US unused tax credits predominantly comprise foreign tax credits. No deferred tax asset has been recognized on these tax credits as they are unlikely to have value in the future. For 2025
these tax credits expire in the period 2026-2035.
e2025 and 2024 mainly comprise fixed asset temporary differences in overseas branches of UK entities. Substantially all of the temporary differences have no expiry date.
$ million | ||||
Impact of previously unrecognized deferred tax or write-down of deferred tax assets on tax charge | 2025 | 2024 | 2023 | |
Current tax benefit relating to the utilization of previously unrecognized deferred tax assets | ||||
Deferred tax benefit arising from the reversal of a previous write-down of deferred tax assets | ||||
Deferred tax benefit relating to the recognition of previously unrecognized deferred tax assets | ||||
Deferred tax expense arising from the write-down of a previously recognized deferred tax asset |
bp Annual Report and Form 20-F 2025 | 193 |
| ||||
Financial statements | ||||
10. Dividends
The quarterly dividend which is expected to be paid on 27 March 2026 in respect of the fourth quarter 2025 is 8.320 cents per ordinary share
($0.4992 per American Depositary Share (ADS)). The corresponding amount in sterling will be announced on 17 March 2026.
Pence per share | Cents per share | $ million | ||||||||
2025 | 2024 | 2023 | 2025 | 2024 | 2023 | 2025 | 2024 | 2023 | ||
Dividends announced and paid in cash | ||||||||||
Preference shares | ||||||||||
Ordinary shares | ||||||||||
March | ||||||||||
June | ||||||||||
September | ||||||||||
December | ||||||||||
Dividend announced, paid in March 2026 | ||||||||||
The amount of unclaimed dividends recognized as a liability in other payables at 31 December 2025 is $134 million (2024 $106 million).
The board decided not to offer a scrip dividend alternative in respect of any dividends announced since the third quarter 2019, including the fourth
quarter 2025 dividend expected to be paid on 27 March 2026.
The financial statements for the year ended 31 December 2025 do not reflect the dividend announced on 10 February 2026 and which is expected to
be paid on 27 March 2026; this will be treated as an appropriation of profit in the year ending 31 December 2026.
11. Earnings per share
Cents per share | ||||
Per ordinary share | 2025 | 2024 | 2023 | |
Basic earnings per share | ||||
Diluted earnings per share | ||||
Dollars per share | ||||
Per American Depositary Share (ADS)a | 2025 | 2024 | 2023 | |
Basic earnings per share | ||||
Diluted earnings per share | ||||
aOne ADS is equivalent to six ordinary shares.
Basic earnings per ordinary share amounts are calculated by dividing the profit for the year attributable to bp ordinary shareholders by the
weighted average number of ordinary shares outstanding during the year.
The weighted average number of shares outstanding includes certain shares that will be issuable in the future under employee share-based
payment plans and excludes treasury shares, which includes shares held by the Employee Share Ownership Plan trusts (ESOPs).
For the diluted earnings per share calculation, the weighted average number of shares outstanding during the year is adjusted for the average
number of shares that are potentially issuable in connection with employee share-based payment plans. 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.
$ million | ||||
2025 | 2024 | 2023 | ||
Profit (loss) attributable to bp shareholders | ||||
Less: dividend requirements on preference shares | ||||
Less: (gain) loss on redemption of perpetual hybrid bondsa | ( | |||
Profit (loss) for the year attributable to bp ordinary shareholders | ||||
Shares thousand | ||||
2025 | 2024 | 2023 | ||
Basic weighted average number of ordinary sharesb | ||||
Potential dilutive effect of ordinary shares issuable under employee share-based payment plans | ||||
Weighted average number of ordinary shares outstanding used to calculate diluted earnings per share | ||||
Shares thousand | ||||
2025 | 2024 | 2023 | ||
Basic weighted average number of ordinary shares – ADS equivalent | ||||
Potential dilutive effect of ordinary shares (ADS equivalent) issuable under employee share- based payment plans | ||||
Weighted average number of ordinary shares (ADS equivalent) outstanding used to calculate diluted earnings per share |
aSee Note 32 - non-controlling interests for further information.
bExcludes treasury shares. See Note 31 for further information.
194 | bp Annual Report and Form 20-F 2025 |
11. Earnings per share – continued
The number of ordinary shares outstanding at 31 December 2025, excluding treasury shares, and including certain shares that will be issuable in the
future under employee share-based payment plans was 15,377,210,044 (2024 15,851,028,983 ). Between 31 December 2025 and 13 February 2026, the
latest practicable date before the completion of these financial statements, there was a net decrease of 48,533,512 of ordinary shares primarily as a
result of share buy backs. For additional information on share buy backs see Note 31.
Employee share-based payment plans
The group operates share and share option plans for directors and certain employees to obtain ordinary shares and ADSs in the company.
options outstanding, the number of options exercisable at the end of each year, and the corresponding weighted average exercise prices. The
dilutive effect of these plans at 31 December is also shown.
Share options | 2025 | 2024 | |||
Number of optionsa b thousand | Weighted average exercise price $ | Number of optionsa b thousand | Weighted average exercise price $ | ||
Outstanding | |||||
Exercisable | |||||
Dilutive effect | n/a | n/a |
aNumbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
bAt 31 December 2025 the quoted market price of one bp ordinary share was £4.33 (2024 £3.93 ).
In addition, the group operates a number of equity-settled employee share plans under which share units are granted to the group’s senior leaders
and certain other employees. These plans typically have a three-year performance or restricted period during which the units accrue net notional
dividends which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into shares, but special
arrangements apply for participants that leave for qualifying reasons. The number of shares that are expected to vest each year under employee
share plans are shown in the table below. The dilutive effect of the employee share plans at 31 December is also shown.
Share plans | 2025 | 2024 | |
Number of sharesa | Number of sharesa | ||
Vesting | thousand | thousand | |
Within one year | |||
1 to 2 years | |||
2 to 3 years | |||
3 to 4 years | |||
Over 4 years | |||
Dilutive effect |
aNumbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
There has been a net increase of 30,497,988 in the number of potential ordinary shares relating to employee share-based payment plans between
31 December 2025 and 13 February 2026.
bp Annual Report and Form 20-F 2025 | 195 |
| ||||
Financial statements | ||||
12. Property, plant and equipment (PP&E)
$ million | |||||||||
Land and land improvements | Buildings | Oil and gas propertiesa | Plant, machinery and equipment | Fittings, fixtures and office equipment | Transportation | Oil depots, storage tanks and service stations | Total | ||
Cost - owned PP&E | |||||||||
At 1 January 2025 | |||||||||
Exchange adjustments | |||||||||
Additions | |||||||||
Acquisitions | |||||||||
Transfers from intangible assets | |||||||||
Reclassified as assets held for sale | ( | ( | ( | ( | ( | ( | ( | ( | |
Deletions and disposals | ( | ( | ( | ( | ( | ( | ( | ( | |
At 31 December 2025 | |||||||||
Depreciation - owned PP&E | |||||||||
At 1 January 2025 | |||||||||
Exchange adjustments | |||||||||
Charge for the year | |||||||||
Impairment losses | |||||||||
Impairment reversals | ( | ( | ( | ( | ( | ( | |||
Transfers from intangible assets | |||||||||
Reclassified as assets held for sale | ( | ( | ( | ( | ( | ( | ( | ( | |
Deletions and disposals | ( | ( | ( | ( | ( | ( | ( | ( | |
At 31 December 2025 | |||||||||
Owned PP&E - net book amount at 31 December 2025 | |||||||||
Right-of-use assets - net book amount at 31 December 2025b | |||||||||
Total PP&E - net book amount at 31 December 2025 | |||||||||
Cost - owned PP&E | |||||||||
At 1 January 2024 | |||||||||
Exchange adjustments | ( | ( | ( | ( | ( | ( | ( | ||
Additions | |||||||||
Acquisitions | |||||||||
Transfers from intangible assets | |||||||||
Reclassified as assets held for sale | ( | ( | ( | ( | ( | ( | |||
Deletions and disposals | ( | ( | ( | ( | ( | ( | ( | ( | |
At 31 December 2024 | |||||||||
Depreciation - owned PP&E | |||||||||
At 1 January 2024 | |||||||||
Exchange adjustments | ( | ( | ( | ( | ( | ( | ( | ||
Charge for the year | |||||||||
Impairment losses | |||||||||
Impairment reversals | ( | ( | ( | ( | |||||
Reclassified as assets held for sale | ( | ( | ( | ( | ( | ( | |||
Deletions and disposals | ( | ( | ( | ( | ( | ( | ( | ( | |
At 31 December 2024 | |||||||||
Owned PP&E - net book amount at 31 December 2024 | |||||||||
Right-of-use assets - net book amount at 31 December 2024b | |||||||||
Total PP&E - net book amount at 31 December 2024 | |||||||||
Assets under construction included above | |||||||||
At 31 December 2025 | |||||||||
At 31 December 2024 | |||||||||
Depreciation charge for the year on right-of-use assets | |||||||||
2025 | |||||||||
2024 |
aFor information on significant estimates and judgements made in relation to the estimation of oil and natural reserves see Property, plant and equipment within Note 1.
b$1,072 million (2024 $867 million) of drilling rig right-of-use assets and $2,119 million (2024 $2,455 million) of shipping vessel right-of-use assets are included in Plant, machinery and equipment
and Transportation respectively.
196 | bp Annual Report and Form 20-F 2025 |
13. Capital commitments
Authorized future capital expenditure for property, plant and equipment (excluding right-of-use assets) by group companies for which contracts
had been signed at 31 December 2025 amounted to $14,639 million (2024 $13,642 million, 2023 $10,354 million). bp has contracted capital
commitments amounting to $2,238 million (2024 $3,392 million, 2023 $1,580 million) in relation to joint ventures and $89 million (2024 $59 million,
2023 $105 million) in relation to associates.
14. Goodwill and impairment review of goodwill
$ million | |||
2025 | 2024 | ||
Cost | |||
At 1 January | |||
Exchange adjustments | ( | ||
Acquisitions and other additions | ( | ||
Reclassified as assets held for sale | ( | ( | |
Deletions and disposals | ( | ( | |
At 31 December | |||
Impairment losses | |||
At 1 January | |||
Exchange adjustments | ( | ||
Impairment losses for the year | |||
Deletions and disposals | ( | ( | |
At 31 December | |||
Net book amount at 31 December | |||
Net book amount at 1 January |
Impairment review of goodwill
$ million | |||
Goodwill at 31 December | 2025 | 2024 | |
gas & low carbon energya | |||
oil production & operations | |||
customers & productsa | |||
other businesses & corporate | |||
a2024 restated to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment.
Goodwill acquired through business combinations has been allocated to groups of cash-generating units (CGUs) that are expected to benefit from
the synergies of the acquisition. For oil production & operations goodwill is allocated to CGUs in aggregate at the segment level, for gas & low
carbon energy, goodwill is allocated to the hydrocarbon CGUs ('upstream gas businesses') within the segment and to Lightsource bp (LSbp) and
Archaea Energy (‘transition businesses’). For customers and products, goodwill has been allocated to Castrol, US Fuels, European Fuels and Other.
For information on significant estimates and judgements made in relation to impairments see Impairment of property, plant and equipment,
intangible assets and goodwill in Note 1.
$ million | $ million | |||||||||
gas & low carbon energy | oil production & operations | |||||||||
2025 | 2024 | 2025 | 2024 | |||||||
Upstream gas businesses | Transition businesses | Total | Upstream gas businesses | Transition businesses | Totala | |||||
Goodwilla | ||||||||||
Excess of recoverable amount over carrying amount | n/a | |||||||||
aRestated to reflect the move of Archaea Energy from the customers & products segment to the gas & low carbon energy segment.
The table above shows the carrying amount of goodwill for the segments at the period end and the excess of the recoverable amount over the
carrying amount (headroom) at the date of the most recent test. The recoverable amounts for the upstream gas businesses and transition
businesses are based on value-in-use calculations. The increase in headroom for the goodwill impairment tests for the upstream gas businesses is
due to the passage of time and price impacts. For oil production & operations management have rolled-forward the most recent detailed
calculation as the criteria set out in IAS 36 for doing so were met.
During 2025 impairment charges of $2,009 million were recognized against the transition businesses goodwill balance. The impairment charges
arose as a result of changes in assumptions including future capital and operating expenditure and project development. No impairment of the
goodwill in the upstream gas businesses was recognized in 2025 or 2024. No impairment of the goodwill in oil production & operations was
recognized during 2025 or 2024.
bp Annual Report and Form 20-F 2025 | 197 |
| ||||
Financial statements | ||||
14. Goodwill and impairment review of goodwill – continued
Upstream gas businesses and oil production & operations
The value in use for relevant CGUs in both the upstream gas businesses and oil production & operations is based on the cash flows expected to be
generated by the projected production profiles up to the expected dates of cessation of production of each field, based on appropriately risked
estimates of reserves and resources. Midstream and supply and trading activities and equity-accounted entities are generally not included in the
impairment reviews of goodwill, as they do not represent part of the grouping of CGUs to which the goodwill balances relate and which are used to
monitor the goodwill balances for internal management purposes. Where such activities form part of wider CGUs to which goodwill relates they are
reflected in the test. As the production profile and related cash flows can be estimated from bp’s past experience, management believes that the
cash flows generated over the estimated life of field is the appropriate basis upon which to assess goodwill and individual assets for impairment in
both the upstream gas businesses and oil & production operations. The estimated date of cessation of production depends on the interaction of a
number of variables, such as the recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of the development
of the infrastructure necessary to recover the hydrocarbons, production costs, the contractual duration of the production concession and the
selling price of the hydrocarbons produced. As each field has specific reservoir characteristics and economic circumstances, the cash flows of
each field are computed using appropriate individual economic models and key assumptions agreed by bp management.
Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis, including operating and capital
expenditure, are derived from the business segment plans. The production profiles used are consistent with the reserve and resource volumes
approved as part of bp’s centrally controlled process for the estimation of proved and probable reserves and total resources.
The average production for the purposes of goodwill impairment testing in the upstream gas businesses over the next 15 years is 146 mmboe per
year (2024 154 mmboe per year) and in the oil production and operations segment is 400 mmboe per year (2024 400 mmboe per year). Production
assumptions used for the goodwill impairment tests in both the upstream gas businesses and oil production & operations reflect management’s
best estimate of future production of the existing portfolio at the time of the calculation.
The weighted-average pre-tax discount rate used in the review for the oil production & operations segment is 17 %, and 11 % for the gas businesses
(2024 17 % for the oil production & operations segment and 11 % for the gas businesses).
The most recent reviews for impairment for the oil production & operations and the upstream gas businesses were carried out in the fourth quarter.
The key assumptions used in the value-in-use calculations are oil and natural gas prices, production volumes and the discount rate. The value-in-
use calculations have been prepared for the purposes of determining whether the goodwill balances were impaired. For the upstream gas
businesses , estimated future cash flows were prepared on the basis of certain assumptions prevailing at the time of the tests. For the oil
production & operations segment, as permitted by IAS 36, the detailed calculations for recoverable amounts performed in 2024 were used as a
basis for the 2025 impairment tests. The recoverable amounts, key assumptions and sensitivity calculations for 2025 are prepared using the
remaining future cashflows from the 2024 detailed calculations. The headrooms for 2025 do not represent the headrooms that would result if a
test was run based on discounted future cashflows estimated using 2025 data and assumptions. The actual outcomes may differ from the
assumptions made. For example, reserves and resources estimates and production forecasts are subject to revision as further technical
information becomes available and economic conditions change. Due to economic developments, regulatory change and emissions reduction
activity arising from climate concern and other factors, future commodity prices and other assumptions may differ from the forecasts used in the
calculations.
Sensitivities to different variables have been estimated using certain simplifying assumptions. For example, lower oil and gas price or production
sensitivities do not fully reflect the specific impacts for each contractual arrangement and will not capture all favourable impacts that may arise
from cost deflation or savings. A detailed calculation at any given price or production profile may, therefore, produce a different result.
It is estimated that an 11 % (2024 11 %) reduction in revenue throughout each year of the remaining life of those assets, either as a result of adverse
price or production conditions or a combination of each, would cause the recoverable amount to be equal to the carrying amount of goodwill and
related net non-current assets of the oil production and operations segment. For the gas businesses a 9 % (2024 6 %) reduction would have the
same result.
It is estimated that no reasonably possible change in the discount rate would cause the recoverable amount to be equal to the carrying amount of
goodwill and related net non-current assets.
Transition businesses
The transition businesses goodwill relates to the acquisitions of Archaea Energy and Lightsource bp. Cash flows were derived from the approved
business plans.
For Archaea Energy, cash flows are derived from the approved business plan, which covers the period up to 2050. To determine the value in use,
approved business plan cash flows were discounted and aggregated with a terminal value.
For Lightsource bp, cash flows for a period of 10 years were discounted and aggregated with a terminal value. Management considers the use of 10
years of plan cash flows before adding a terminal value to be appropriate reflecting the maturity of the business with an early stage development
portfolio and other aspects of business model changes such that 10 years reflected an appropriate ‘steady state’ of development project sales and
other income from which terminal value cash flows could be determined.
The assumptions to which the impairment tests are most sensitive are for Lightsource bp, the solar project sell-down unit margin, terminal value
growth rate and the discount rate and for Archaea Energy renewable natural gas prices, and the level of capital expenditure and its consequential
impact on production volumes and discount rate. These assumptions are affected by market conditions. Discount rate assumptions are based on
the group’s impairment discount rates as disclosed in Note 1. Other assumptions are based on management experience. The steady long-term
growth rate used in the Lightsource bp goodwill impairment test terminal value is a risk-adjusted rate reflecting assumptions about inflation and
project development growth.
It is estimated that a 1 % decrease in the discount rates applied to the transition businesses would have resulted in a reduction to the goodwill
impairment charges of $1.7 billion. It is estimated that a 1 % increase to the discount rates would have resulted in an increase to the goodwill
impairment charge of $0.9 billion.
These discount rate sensitivity analyses do not take into account any effect on the goodwill impairment test that would arise from first applying the
changes in assumptions to the underlying assets of the businesses.
198 | bp Annual Report and Form 20-F 2025 |
14. Goodwill and impairment review of goodwill – continued
Lightsource bp project development margins could change as a result of changes in sales prices achieved, development costs incurred or changes
in the number of projects sold. It is estimated that a 10 % increase to project development unit margin would have resulted in a reduction to the
goodwill impairment charge of $0.4 billion. It is estimated that a 10 % decrease in project development unit margin would have resulted in an
increase to the goodwill impairment charge of $0.5 billion. It is estimated that a 1 % increase to the terminal value growth rate would have resulted
in a reduction to the goodwill impairment charge of $1.0 billion. It is estimated that a 1 % decrease in the terminal value growth rate would have
resulted in an increase to the goodwill impairment charge of $0.6 billion.
These sensitivity analyses do not, however, represent management’s best estimate of any impairment charges or reversals that might be
recognized as they do not fully incorporate consequential changes that may arise, such as changes in capital and operating costs, business plans
and phasing of development. The above sensitivity analyses therefore do not reflect a linear relationship between development margins or growth
rate and value that can be extrapolated. The interdependency of these inputs and factors limits the practicability of estimating the probability or
extent to which the overall recoverable amount is impacted by changes to the price assumptions or production volumes.
Given the impairment charges taken in the year, the recoverable amount of the transition businesses CGUs’ goodwill is equal to its carrying
amount. Therefore, no disclosures regarding what changes in assumptions would cause headroom to be eroded have been provided. Also
reflecting that goodwill impairment reversals are not permitted by IFRS the sensitivities identified above are provided to give context to the
estimates taken at December 2025. No reversals to goodwill would arise should the estimates be changed favourably in the year ended December
2026.
$ million | |||||||||||
2025 | 2024 | ||||||||||
Castrol | US Fuels | European Fuels | Other | Total | Castrol | US Fuels | European Fuels | Other | Totala | ||
Goodwilla |
aRestated to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment.
Cash flows for each group of CGUs are derived from the business segment plans, which cover a period of up to five years . To determine the value in
use for each of the groups of cash-generating units, cash flows for a period of 10 years, are discounted and aggregated with a terminal value. Pre-
tax discount rates ranging from 10-12% are applied. It is estimated that no reasonably possible change in the key assumptions used in the US Fuels
and European Fuels goodwill impairment assessments would cause the recoverable amount to be equal to the carrying amount of goodwill and
related net non-current assets.
No material impairment of the goodwill balances in customers & products was recognized during 2025.
Castrol
15. Intangible assets
$ million | |||||||||
2025 | 2024 | ||||||||
Exploration and appraisal expenditurea | Biogas rights agreements | Other intangibles | Total | Exploration and appraisal expenditurea | Biogas rights agreements | Other intangibles | Total | ||
Cost | |||||||||
At 1 January | |||||||||
Exchange adjustments | ( | ( | |||||||
Acquisitionsb | |||||||||
Additions | |||||||||
Transfers to property, plant and equipment | ( | ( | ( | ( | |||||
Reclassified as assets held for sale | ( | ( | ( | ( | ( | ||||
Deletions and disposals | ( | ( | ( | ( | ( | ( | ( | ( | |
At 31 December | |||||||||
Amortization | |||||||||
At 1 January | |||||||||
Exchange adjustments | ( | ( | |||||||
Exploration expenditure written off | |||||||||
Charge for the year | |||||||||
Impairment losses | |||||||||
Impairment reversals | ( | ( | ( | ( | |||||
Transfers to property, plant and equipment | ( | ( | |||||||
Reclassified as assets held for sale | ( | ( | ( | ( | |||||
Deletions and disposals | ( | ( | ( | ( | ( | ( | ( | ( | |
At 31 December | |||||||||
Net book amount at 31 December | |||||||||
Net book amount at 1 January |
aFor further information see Intangible assets within Note 1 and Note 8.
b2024 primarily relates to the acquisition of GETEC ENERGIE GmbH.
bp Annual Report and Form 20-F 2025 | 199 |
| ||||
Financial statements | ||||
16. Investments in joint ventures
the group income statement and on the group balance sheet.
$ million | ||||||
Income statement | Balance sheet | |||||
Earnings from joint ventures - after interest and tax | Investments in joint ventures | |||||
2025 | 2024 | 2023 | 2025 | 2024 | ||
Azule Energy | ||||||
Other joint ventures | ( | ( | ||||
( | ||||||
The joint venture that is material to the group at 31 December 2025 is Azule Energy, which was formed during 2022 and in which bp owns a 50 %
stake.
bp classifies its investment in Azule Energy Holdings Limited as a joint venture because, per the terms of the shareholders' agreements, bp has joint
control over Azule Energy. Azule Energy Holdings Limited is based in Angola and its functional currency is USD.
The following table provides summarized financial information relating to Azule Energy for 2025, 2024 and 2023. This information is presented on a
100% basis and reflects adjustments made by bp to Azule Energy’s own results in applying the equity method of accounting. bp adjusts Azule
Energy Holdings Limited’s results for the accounting required under IFRS relating to bp’s purchase of its interests in Azule Energy Holdings Limited.
The operational and financial information is based on preliminary operational and financial results of Azule Energy Holdings Limited for 2025, 2024
and 2023. Actual results may differ from these amounts - immaterial adjustments to the 2023 numbers for Azule Energy Holdings Limited have
been included in the 2024 numbers.
$ million | ||||
Gross amount | ||||
2025 | 2024 | 2023 | ||
Sales and other operating revenues | ||||
Profit (loss) before interest and taxation | ||||
Finance costs | ||||
Profit (loss) before taxationa | ||||
Taxation | ||||
Profit (loss) for the year | ||||
Other comprehensive income | ||||
Total comprehensive income | ||||
Non-current assets | ||||
Current assetsb | ||||
Total assets | ||||
Current liabilitiesc | ||||
Non-current liabilitiesd | ||||
Total liabilities | ||||
Net assets | ||||
Less: non-controlling interests | ||||
aAzule Energy includes depreciation and amortisation of $2,729 million (2024 $2,844 million and 2023 $2,768 million), interest income of $nil (2024 $nil and 2023 $nil ) and interest expense of $303
million (2024 $513 million and 2023 $407 million).
bAzule Energy includes cash and cash equivalents of $596 million (2024 $570 million).
cAzule Energy includes current financial liabilities of $4,635 million (2024 $3,417 million).
dAzule Energy includes non-current financial liabilities of $5,827 million (2024 $3,426 million).
The group received dividends of $437 million from Azule Energy Holdings Limited in 2025 (2024 $463 million and 2023 $708 million).
200 | bp Annual Report and Form 20-F 2025 |
16. Investments in joint ventures – continued
The following table provides aggregated summarized financial information relating to the group’s share of joint ventures.
$ million | ||||||||||
bp share | ||||||||||
2025 | 2024 | 2023 | ||||||||
Azule Energy | Other | Total | Azule Energy | Other | Total | Azule Energy | Other | Total | ||
Sales and other operating revenues | ||||||||||
Profit (loss) before interest and taxation | ( | ( | ||||||||
Finance costs | ||||||||||
Profit (loss) before taxation | ( | ( | ( | |||||||
Taxation | ( | ( | ||||||||
Non-controlling interest | ||||||||||
Profit (loss) for the year | ( | ( | ( | |||||||
Other comprehensive income | ( | ( | ||||||||
Total comprehensive income | ( | ( | ( | |||||||
Non-current assets | ||||||||||
Current assets | ||||||||||
Total assets | ||||||||||
Current liabilities | ||||||||||
Non-current liabilities | ||||||||||
Total liabilities | ||||||||||
Net assets | ||||||||||
Less: non-controlling interests | ( | ( | ( | ( | ||||||
Group investment in joint ventures | ||||||||||
Group share of net assets (as above) | ||||||||||
Cumulative impairment charge | ( | ( | ( | ( | ||||||
Loans made by group companies to joint ventures | ( | ( | ( | ( | ||||||
$ million | |||||||
Sales to joint ventures | 2025 | 2024 | 2023 | ||||
Product | Sales | Amount receivable at 31 December | Sales | Amount receivable at 31 December | Sales | Amount receivable at 31 December | |
LNG, crude oil and oil products, natural gas | |||||||
Purchases from joint ventures | 2025 | 2024 | 2023 | ||||
Product | Purchases | Amount payable at 31 December | Purchases | Amount payable at 31 December | Purchases | Amount payable at 31 December | |
LNG, crude oil and oil products, natural gas, refinery operating costs, plant processing fees |
In the normal course of business, bp enters into various arm’s length transactions with joint ventures including fixed price commitments to sell and
to purchase commodities, forward sale and purchase contracts and agency agreements.
The terms of the outstanding balances receivable from joint ventures are typically 30 to 45 days. The balances are unsecured and will be settled in
cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income
statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above.
The majority of sales to joint ventures in 2025 relate to heating oil, gasoline, diesel and lubricant product transactions with Mobene and Ocwen
Energy. The majority of purchases from joint ventures in 2025 relate to crude oil and oil products transactions with Azule Energy.
bp's share of net impairment charges recognized by joint ventures in 2025 was $1,111 million (2024 $477 million and 2023 $1,285 million) of which
$1,082 million charge (2024 $nil and 2023 $1,152 million) was in the gas and low carbon energy segment and $29 million charge (2024 $477 million
charge and 2023 $133 million charge) was in the oil production & operations segment. The 2025 charges in the gas and low carbon energy segment
principally relate to Archaea Energy and offshore wind. The 2023 charges in the gas and low carbon energy segment principally related to the
bp Annual Report and Form 20-F 2025 | 201 |
| ||||
Financial statements | ||||
17. Investments in associates
The following table provides aggregated summarized financial information for the group’s associates as it relates to the amounts recognized in the
group income statement and on the group balance sheet. There were no individually material associates to the Group at 31 December 2025.
$ million | ||||
bp share | ||||
2025 | 2024 | 2023 | ||
Sales and other operating revenues | ||||
Profit before interest and taxation | ||||
Finance costs | ||||
Profit (loss) before taxation | ||||
Taxation | ||||
Profit (loss) for the year | ||||
Other comprehensive income | ( | ( | ( | |
Total comprehensive income | ||||
Non-current assets | ||||
Current assets | ||||
Total assets | ||||
Current liabilities | ||||
Non-current liabilities | ||||
Total liabilities | ||||
Net assets | ||||
Group investment in associates | ||||
Group share of net assets (as above) | ||||
Loans made by group companies to associates | ||||
$ million | |||||||
Sales to associates | 2025 | 2024 | 2023 | ||||
Product | Sales | Amount receivable at 31 December | Sales | Amount receivable at 31 December | Sales | Amount receivable at 31 December | |
LNG, crude oil and oil products, natural gas | |||||||
$ million | |||||||
Purchases from associates | 2025 | 2024 | 2023 | ||||
Product | Purchases | Amount payable at 31 December | Purchases | Amount payable at 31 December | Purchases | Amount payable at 31 December | |
Crude oil and oil products, natural gas, transportation tariff |
In the normal course of business, bp enters into various arm’s length transactions with associates including fixed price commitments to sell and to
purchase commodities, forward sale and purchase contracts and agency agreements.
The terms of the outstanding balances receivable from associates are typically 30 to 45 days. The balances are unsecured and will be settled in
cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income
statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above.
The majority of purchases from associates in 2025, 2024 and 2023 relate to crude oil and oil products transactions with Aker BP. Sales to associates
are related to various entities.
bp has commitments amounting to $6,993 million (2024 $7,921 million), primarily in relation to contracts with its associates for the purchase of
transportation capacity. For information on capital commitments in relation to associates see Note 13.
bp's share of impairment charges taken by associates in 2025 was $265 million (2024 $14 million).
202 | bp Annual Report and Form 20-F 2025 |
18. Other investments
$ million | |||||
2025 | 2024 | ||||
Current | Non-current | Current | Non-current | ||
Equity investmentsa | |||||
Contingent consideration | |||||
Other | |||||
aThe majority of equity investments are unlisted.
Unlisted equity investments are measured using observable recent market prices where available. The majority of investments are measured using
models with inputs that may include recent share price data, discounted future cash flows and other available active market pricing data using the
maximum available market information and bp’s understanding of the associated company’s performance and prospects. Contingent
consideration relates to amounts arising on disposals which are financial assets classified as measured at fair value through profit or loss.
19. Inventories
$ million | |||
2025 | 2024 | ||
Crude oil | |||
Natural gas | |||
Emissions allowances | |||
Refined petroleum and petrochemical products | |||
Trading inventories | |||
Supplies | |||
Biological assets | |||
Solar projects | |||
Cost of inventories expensed in the income statement |
The inventory valuation at 31 December 2025 is stated net of a provision of $475 million (2024 $388 million) to write down inventories to their net
realizable value, of which $277 million (2024 $199 million) relates to hydrocarbon inventories. The net charge to the income statement in the year in
respect of inventory net realizable value provisions was $137 million (2024 $77 million credit), of which $73 million charge (2024 $104 million credit)
related to hydrocarbon inventories.
Trading inventories are valued using quoted benchmark prices adjusted as appropriate for location and quality differentials. They are
predominantly categorized within level 2 of the fair value hierarchy.
20. Trade and other receivables
$ million | |||||
2025 | 2024 | ||||
Current | Non-current | Current | Non-current | ||
Financial assets | |||||
Trade receivables | |||||
Amounts receivable from joint ventures and associates | |||||
Other receivables | |||||
Non-financial assets | |||||
Sales taxes and production taxes | |||||
Other receivables | |||||
In both 2025 and 2024 the group entered into non-recourse arrangements to discount certain receivables in support of supply and trading
activities and the management of credit risk.
Trade and other receivables are predominantly non-interest bearing.
See Note 29 for further information.
bp Annual Report and Form 20-F 2025 | 203 |
| ||||
Financial statements | ||||
21. Valuation and qualifying accounts
$ million | |||||||
2025 | 2024 | 2023 | |||||
Trade and other receivables | Fixed asset investments | Trade and other receivables | Fixed asset investments | Trade and other receivables | Fixed asset investments | ||
At 1 January | |||||||
Charged to costs and expenses | ( | ||||||
Charged to other accountsa | ( | ( | |||||
Deductions | ( | ( | ( | ( | ( | ( | |
At 31 December |
aPrincipally exchange adjustments.
Valuation and qualifying accounts relating to trade and other receivables comprise expected credit loss allowances. The expected credit loss
allowance comprises $811 million (2024 $858 million, 2023 $1,301 million) relating to receivables that were credit-impaired at the end of the year and
$127 million (2024 $137 million, 2023 $123 million) relating to receivables that were not credit-impaired at the end of the year.
Valuation and qualifying accounts relating to fixed asset investments comprise impairment provisions for investments in equity-accounted entities.
Valuation and qualifying accounts are deducted in the balance sheet from the assets to which they apply. For further information on the group's
credit risk management policies and how the group recognizes and measures expected losses see Note 29.
22. Trade and other payables
$ million | |||||
2025 | 2024 | ||||
Current | Non-current | Current | Non-current | ||
Financial liabilities | |||||
Trade payables | |||||
Amounts payable to joint ventures and associates | |||||
Payables for capital expenditure and acquisitions | |||||
Payables related to the Gulf of America oil spill | |||||
Other payables | |||||
Non-financial liabilities | |||||
Sales taxes, customs duties, production taxes and social security | |||||
Other payables | |||||
Materially all of bp's trade payables have payment terms of less than 60 days and give rise to operating cash flows.
Trade and other payables, other than those relating to the Gulf of America oil spill, are predominantly interest free. See Note 29 (c) for further
information.
Payables related to the Gulf of America oil spill include amounts payable under the 2016 consent decree and settlement agreement with the United
States and five Gulf coast states, including amounts payable for natural resource damages, state claims and Clean Water Act penalties. On a
discounted basis the amounts included in payables related to the Gulf of America oil spill for these elements of the agreements are $3,207 million
payable over seven years, $1,748 million payable over eight years and $2,276 million payable over seven years respectively at 31 December 2025.
Reported within net cash provided by operating activities in the group cash flow statement is a net cash outflow of $1,169 million (2024 outflow of
$1,192 million, 2023 outflow of $1,280 million) related to the Gulf of America oil spill, which includes payments made in relation to these agreements.
For full details of these agreements, see bp Annual Report and Form 20-F 2015 - Legal Proceedings.
Payables related to the Gulf of America oil spill at 31 December 2025 also include amounts payable for settled economic loss and property damage
claims which are payable over a period of up to two years.
204 | bp Annual Report and Form 20-F 2025 |
23. Provisions
$ million | |||||||
Decommissioning | Environmental | Litigation and claims | Emissions | Otherc | Total | ||
At 1 January 2025 | |||||||
Exchange adjustments | |||||||
Acquisitions | |||||||
New and increase in existing provisionsa | |||||||
Write-back of unused provisionsa | ( | ( | ( | ( | ( | ( | |
Unwinding of discountb | |||||||
Utilization | ( | ( | ( | ( | ( | ( | |
Reclassified to other payables | ( | ( | ( | ( | ( | ||
Reclassified as liabilities directly associated with assets held for sale | ( | ( | ( | ( | ( | ||
Deletions | ( | ( | ( | ( | ( | ||
At 31 December 2025 | |||||||
Of which – current | |||||||
– non-current |
aRecognized in the Group income statement, other than changes in decommissioning provisions related to owned assets.
bRecognized in the Group income statement
cOther includes provisions for onerous contracts and restructuring costs.
The decommissioning provision primarily comprises the future cost of decommissioning oil and natural gas wells, facilities and related pipelines.
The environmental provision includes provisions for costs related to the control, abatement, clean-up or elimination of environmental pollution
relating to soil, groundwater, surface water and sediment contamination. The litigation and claims category includes provisions for matters related
to, for example, commercial disputes, product liability, and allegations of exposures of third parties to toxic substances. Emissions provisions
primarily relate to obligations under the U.S. Environmental Protection Agency Renewable Fuel Standard Program and are driven by the amount of
the obligations outstanding and current price of the related credits. The provision will principally be settled through allowances already held as
inventory in the group balance sheet.
For information on significant estimates and judgements made in relation to provisions, see Provisions and contingencies within Note 1.
Gulf of America oil spill
The group has recognized certain assets, payables and provisions and incurs certain residual costs relating to the Gulf of America oil spill that
occurred in 2010. For further information see Notes 7, 22, 29 and 33. The litigation and claims provision presented in the table above includes the
latest estimate for the remaining costs associated with the Gulf of America oil spill. The amounts payable may differ from the amount provided and
the timing of payments is uncertain.
bp Annual Report and Form 20-F 2025 | 205 |
| ||||
Financial statements | ||||
24. Pensions and other post-employment benefits
Most group companies have pension plans, the forms and benefits of which vary with conditions and practices in the countries concerned. Pension
benefits may be provided through defined contribution plans (money purchase schemes) or defined benefit plans (final salary and other types of
schemes with committed pension benefit payments). For defined contribution plans, retirement benefits are determined by the value of funds
arising from contributions paid in respect of each employee. For defined benefit plans, retirement benefits are based on such factors as an
employee’s pensionable salary and length of service. Defined benefit plans may be funded or unfunded. The assets of funded plans are generally
held in separately administered trusts.
For information on significant estimates and judgements made in relation to accounting for these plans see Pensions and other post-employment
benefits in Note 1.
The defined benefit pension obligation in the UK consists primarily of a closed funded final salary pension plan under which retired employees draw
the majority of their benefit as an annuity. This pension plan is governed by a corporate trustee whose board is composed of four member-
nominated directors, four company-nominated directors, one independent director and one independent chair nominated by the company. The
trustee board is required by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as
investment policies of the plan.
Employees in the UK are eligible for membership of defined contribution plans established with third-party providers.
In the US, all pension benefits now accrue under a cash balance formula. Benefits previously accrued under final salary formulas are legally
protected. Retiring US employees typically take their pension benefit in the form of a lump sum payment upon retirement. The plan is funded and
its assets are overseen by a fiduciary Investment Committee. At the end of 2025 the committee was composed of five bp employees appointed by
the president of bp Corporation North America Inc. (the appointing officer). The Investment Committee is required by law to act in the best
interests of the plan participants and is responsible for setting certain policies, such as the investment policies of the plan. US employees are also
eligible to participate in a defined contribution (401k) plan in which employee contributions are matched with company contributions.
In the US, group companies also provide post-employment healthcare to eligible retired employees and their dependents (and, in certain legacy
cases, life insurance coverage); the entitlement to these benefits is based on the date of hire, the employee remaining in service until a specified
age and completion of a minimum period of service.
In the Eurozone, there are defined benefit pension plans in Germany, France, the Netherlands and other countries. In Germany and France, the
majority of the pensions are unfunded. In Germany, the group’s largest Eurozone plan, employees receive a pension and also have a choice to
supplement their core pension through salary sacrifice. For employees who joined since 2002, the core pension benefit is a career average plan
with retirement benefits based on such factors as an employee’s pensionable salary and length of service. The returns on the notional contributions
made by both the company and employees are based on the interest rate which is set out in German tax law. Retired German employees take their
pension benefit typically in the form of an annuity. The German plans are governed by legal agreements between bp and the works council or
between bp and the trade union.
Following agreement with the works council, a proportion of the existing defined benefit plans covering approximately 60% of the total active
membership in Germany were closed to future accrual on 31 December 2025 resulting in a net past service cost of $6 million being recognized in
the income statement. Affected employees became eligible for new cash balance arrangements from 1 January 2026.
In the Netherlands, new legislation came into effect in 2023 for domestic pension plans requiring that new pension benefit accruals be exclusively
held in defined contribution plans from 1 January 2028 at the latest. In light of these requirements, and, following agreement with the Dutch retail
and refinery works councils, the existing defined benefit plans were closed to future accrual on 31 August 2025 resulting in a curtailment gain of
$40 million being recognized in the income statement. A new defined contribution plan for members of the defined benefits plans, as well as for
new members, came into effect on 1 September 2025.
The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they fall
due. During 2025 the aggregate level of contributions was $46 million (2024 $69 million and 2023 $42 million) along with $49 million of refunds
from closed plans (2024 $nil and 2023 $nil ). The aggregate level of contributions in 2026 is expected to be approximately $100 million and includes
contributions in all countries that we expect to be required to make contributions by law or under contractual agreements, as well as an allowance
for discretionary funding.
For the primary UK defined benefit plan there is a funding agreement between the group and the trustee. On a three year cycle, a schedule of
contributions is agreed covering the next five years . The schedule of contributions is next scheduled to be updated after the 31 December 2026
formal actuarial valuation. No contractually committed funding was due at 31 December 2025.
The surplus relating to the primary UK defined benefit pension plan is recognized on the balance sheet on the basis that the company is entitled to
a refund of any remaining assets once all members have left the plan.
Minimum pension funding in the US is determined by legislation and is supplemented by discretionary contributions. No contributions were made
into the US pension plan in 2025 and no statutory funding requirement is expected in the next 12 months.
The surplus relating to the US pension fund is recognized on the balance sheet on the basis that economic benefit can be gained from the surplus
through a reduction in future contributions.
There was no minimum funding requirement for the US plan, and no significant minimum funding requirements in other countries at 31 December
2025.
Following the closure of the Netherlands defined benefit plans to future accrual, the group’s ability to access the surplus of $277 million at
31 December 2025 is now fully restricted as the company does not have a right to a refund and can no longer gain an economic benefit through a
reduction contributions. Consequently, the net defined benefit asset recognized on the balance sheet for these plans is now fully capped at zero .
The obligation and cost of providing pensions and other post-employment benefits is assessed annually using the projected unit credit method.
The date of the most recent actuarial review was 31 December 2025. The UK defined benefit plans are subject to a formal actuarial valuation every
three years; valuations are required more frequently in many other countries. The most recent formal actuarial valuation of the primary UK defined
benefit pension plan was as at 31 December 2023. A valuation of the US plan and largest Eurozone plans are carried out annually.
206 | bp Annual Report and Form 20-F 2025 |
24. Pensions and other post-employment benefits – continued
The material financial assumptions used to estimate the benefit obligations of the various plans are set out below. The assumptions are reviewed
by management at the end of each year and are used to evaluate the accrued benefit obligation at 31 December and pension expense for the
following year.
% | ||||||||||
Financial assumptions used to determine benefit obligation | UK | US | Eurozone | |||||||
2025 | 2024 | 2023 | 2025 | 2024 | 2023 | 2025 | 2024 | 2023 | ||
Discount rate for plan liabilities | ||||||||||
Rate of increase for pensions in payment | ||||||||||
Rate of increase in deferred pensions | ||||||||||
Inflation for plan liabilities | ||||||||||
% | ||||||||||
Financial assumptions used to determine benefit expense | UK | US | Eurozone | |||||||
2025 | 2024 | 2023 | 2025 | 2024 | 2023 | 2025 | 2024 | 2023 | ||
Discount rate for plan service costa | N/A | N/A | N/A | |||||||
Discount rate for plan other finance expense | ||||||||||
Inflation for plan service costa | N/A | N/A | N/A |
aUK discount rate and inflation rate assumptions are not relevant in determining the benefit expense for the closed UK plan. Rates for the remaining small worldwide plan administered/reported
through the UK are 5.6 % (2024 5.0 % and 2023 5.0 %) and 2.1 % (2024 1.9 % and 2023 1.9 %) respectively.
The discount rate assumptions are based on third-party AA corporate bond indices and for our largest plans in the UK, US and the Eurozone we use
yields that reflect the maturity profile of the expected benefit payments. The inflation rate assumptions for our UK and US plans are based on the
difference between the yields on index-linked and fixed-interest long-term government bonds. In other countries, including the Eurozone, we use
this approach, or advice from the local actuary depending on the information available. The inflation assumptions are used to determine the rate of
increase for pensions in payment and the rate of increase in deferred pensions where there is such an increase.
In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best
practice in the countries in which we provide pensions and have been chosen with regard to applicable published tables adjusted where
appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. bp’s most substantial
pension liabilities are in the UK, the US and the Eurozone where our mortality assumptions are as follows:
Years | ||||||||||
Mortality assumptions | UK | US | Eurozone | |||||||
2025 | 2024 | 2023 | 2025 | 2024 | 2023 | 2025 | 2024 | 2023 | ||
Life expectancy at age 60 for a male currently aged 60 | ||||||||||
Life expectancy at age 60 for a male currently aged 40 | ||||||||||
Life expectancy at age 60 for a female currently aged 60 | ||||||||||
Life expectancy at age 60 for a female currently aged 40 |
Pension plan assets are generally held in trusts, the primary objective of which is to accumulate assets sufficient to meet the obligations of the
plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio
management.
A proportion of the assets are held in equities, which are expected to generate a higher level of return over the long term, with an acceptable level
of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the
investment portfolios are highly diversified.
The trustee’s long-term investment objective for the primary UK defined benefit plan is to invest the plan’s assets in a responsible manner that
considers downside risk such that the assets are expected to be sufficient to pay benefits as and when they fall due. The UK plan uses a liability
driven investment (LDI) approach for part of the portfolio, investing primarily in government bonds to economically hedge against the effect of the
most significant plan liability assumptions of interest rate and inflation rate. This is partly funded by short-term sale and repurchase agreements,
whereby the plan borrows money using existing bonds as security and which will be bought back at a specified price at an agreed future date. The
funds raised are used to invest in further bonds to increase the proportion of assets which match the plan liabilities. The borrowings are shown
separately in the analysis of pension plan assets in the table below.
During 2025, the trustee extended its derisking strategy for the primary UK defined benefit plan by completing a bulk annuity buy-in transaction
with Legal & General Assurance Society Limited covering approximately 12% of the plan’s liabilities. The buy-in was paid for by way of transfer of
$2,183 million of government issued bonds from the plan assets in exchange for a stream of cashflows to the plan replicating payments due to
relevant members.
The group was not legally relieved of the primary responsibility for the obligation and the benefits continue to be payable by the plan. The
difference of $148 million between the buy-in purchase price ($2,183 million) and the defined benefit liability covered by the policy ($2,035 million)
was accounted for in other comprehensive income.
For the primary UK defined benefit plan there is an agreement with the trustee to at least maintain the proportion of assets with liability matching
characteristics and review over time. There is a similar agreement in place for the primary US plan. During 2025, excluding qualifying insurance
policies in the UK, the asset allocation policies of the primary UK and US plans remained unchanged.
bp Annual Report and Form 20-F 2025 | 207 |
| ||||
Financial statements | ||||
24. Pensions and other post-employment benefits – continued
UK | US | ||
Asset category | % | % | |
Total equity (including private equity) | |||
Bonds/cash (including LDI) | |||
Property/real estate |
The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2025 were $3,702 million (2024 $4,970 million)
of government-issued nominal bonds and $10,805 million (2024 $11,105 million) of index-linked bonds.
Some of the group’s pension plans in the Eurozone and other countries use derivative financial instruments as part of their asset mix to manage the
level of risk. The fair value of these instruments is included in other assets in the table below.
The group’s main pension plans do not invest directly in either securities or property/real estate of the company or of any subsidiary.
effects of derivative financial instruments. Movements in the fair value of plan assets during the year are shown in detail in the table on page 208.
$ million | ||||||
UKa | USb | Eurozone | Other | Total | ||
Fair value of pension plan assets | ||||||
At 31 December 2025 | ||||||
Listed equities – developed markets | ||||||
– emerging markets | ||||||
Private equityc | ||||||
Government issued nominal bondsd | ||||||
Government issued index-linked bondsd | ||||||
Corporate bondsd | ||||||
Propertye | ||||||
Cash | ||||||
Otherf | ( | |||||
Debt (repurchase agreements) used to fund liability driven investments | ( | ( | ||||
At 31 December 2024 | ||||||
Listed equities – developed markets | ||||||
– emerging markets | ||||||
Private equityc | ||||||
Government issued nominal bondsd | ||||||
Government issued index-linked bondsd | ||||||
Corporate bondsd | ||||||
Propertye | ||||||
Cash | ||||||
Otherf | ||||||
Debt (repurchase agreements) used to fund liability driven investments | ( | ( | ||||
At 31 December 2023 | ||||||
Listed equities – developed markets | ||||||
– emerging markets | ||||||
Private equityc | ||||||
Government issued nominal bondsd | ||||||
Government issued index-linked bondsd | ||||||
Corporate bondsd | ||||||
Propertye | ||||||
Cash | ||||||
Otherf | ||||||
Debt (repurchase agreements) used to fund liability driven investments | ( | ( | ||||
aBonds held by the UK pension plans are denominated in sterling or hedged back to sterling to minimize foreign currency exposure. Property held by the UK pension plans is in the United
Kingdom.
bBonds held by the US pension plans are denominated in US dollars or hedged back to USD to minimize foreign currency exposure.
cPrivate equity is valued at fair value based on the most recent transaction price or third-party net asset, revenue or earnings based valuations that generally result in the use of significant
unobservable inputs.
dBonds held by pension plans are predominantly valued using observable market data based inputs other than quoted market prices in active markets.
eProperties are valued based on an analysis of recent market transactions supported by market knowledge derived from third-party professional valuers that generally result in the use of
significant unobservable inputs.
fOther includes qualifying insurance policies in the UK amounting to $2,159 million representing the asset associated with the buy in outlined on page 206. The fair value of these insurance policies
is equal to the value of the defined benefit obligations to which these policies relate. Other included insurance policies arising from annuity buy-in in Canada amounting to $374 million in 2023.
208 | bp Annual Report and Form 20-F 2025 |
24. Pensions and other post-employment benefits – continued
$ million | ||||||
2025 | ||||||
UK | US | Eurozone | Other | Total | ||
Analysis of the amount charged to profit or loss | ||||||
Current service costa | ||||||
Past service costb | ( | ( | ||||
Settlementb | ||||||
Operating charge (credit) relating to defined benefit plans | ||||||
Payments to defined contribution plans | ||||||
Total operating charge (credit) | ||||||
Interest income on plan assetsa | ( | ( | ( | ( | ( | |
Interest on plan liabilities | ||||||
Other finance (income) expense | ( | ( | ||||
Analysis of the amount recognized in other comprehensive income | ||||||
Actual asset return less interest income on plan assets | ( | ( | ( | ( | ||
Change in financial assumptions underlying the present value of the plan liabilities | ( | |||||
Change in demographic assumptions underlying the present value of the plan liabilities | ( | ( | ( | |||
Experience gains and losses arising on the plan liabilities | ( | ( | ( | ( | ||
Remeasurements recognized in other comprehensive income | ( | ( | ( | |||
Movements in benefit obligation during the year | ||||||
Benefit obligation at 1 January | ||||||
Exchange adjustments | ||||||
Operating charge relating to defined benefit plans | ||||||
Interest cost | ||||||
Contributions by plan participants | ||||||
Benefit payments (funded plans)c | ( | ( | ( | ( | ( | |
Benefit payments (unfunded plans)c | ( | ( | ( | ( | ( | |
Reclassified as assets held for sale | ( | ( | ( | ( | ||
Disposals | ( | ( | ||||
Remeasurements | ( | ( | ( | ( | ||
Benefit obligation at 31 Decembera d e | ||||||
Movements in fair value of plan assets during the year | ||||||
Fair value of plan assets at 1 January | ||||||
Exchange adjustments | ||||||
Interest income on plan assetsa e | ||||||
Contributions by plan participants | ||||||
Contributions by and refunds to employers (funded plans) | ( | ( | ||||
Benefit payments (funded plans)c | ( | ( | ( | ( | ( | |
Reclassified as assets held for sale | ( | ( | ( | |||
Remeasurementsf | ( | ( | ( | ( | ||
Fair value of plan assets at 31 Decemberg | ||||||
Surplus (deficit) at 31 December | ( | ( | ( | |||
Represented by | ||||||
Asset recognized | ||||||
Liability recognized | ( | ( | ( | ( | ( | |
( | ( | ( | ||||
The surplus (deficit) may be analysed between funded and unfunded plans as follows | ||||||
Funded | ||||||
Unfunded | ( | ( | ( | ( | ( | |
( | ( | ( | ||||
The defined benefit obligation may be analysed between funded and unfunded plans as follows | ||||||
Funded | ( | ( | ( | ( | ( | |
Unfunded | ( | ( | ( | ( | ( | |
( | ( | ( | ( | ( |
aThe costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of
administering other post-employment benefit plans are included in the benefit obligation. Following the closure of the primary UK pension plan, current service cost in the UK consists of
$36 million of costs of administering that plan and $11 million of current service cost from the remaining small worldwide plans administered and reported through the UK.
bPast service costs predominantly reflect curtailment impacts from the closure of plans in the Netherlands and Germany to future accrual. Settlements represent losses associated with
restructuring activity in Germany.
cThe benefit payments amount shown above comprises $1,975 million benefits and $12 million settlements, plus $57 million of plan expenses incurred in the administration of the benefit.
dThe benefit obligation for the US is made up of $4,602 million for pension liabilities and $1,203 million for other post-employment benefit liabilities (which are unfunded and are primarily retiree
medical liabilities). The benefit obligation for the Eurozone includes $2,976 million for pension liabilities in Germany which is largely unfunded.
bp Annual Report and Form 20-F 2025 | 209 |
| ||||
Financial statements | ||||
24. Pensions and other post-employment benefits – continued
eIncludes $346 million (2024 $155 million) representing assets ceilings in plans in the Netherlands (see page 205), Switzerland and the UK. Movements in the asset ceiling during 2025 were interest
cost of $8 million and remeasurements of $183 million.
fThe actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.
gThe fair value of plan assets includes borrowings related to the LDI programme as described on page 207.
$ million | ||||||
2024 | ||||||
UK | US | Eurozone | Other | Total | ||
Analysis of the amount charged to profit or loss | ||||||
Current service costa | ||||||
Past service costb | ( | ( | ||||
Settlementb | ( | ( | ||||
Operating charge (credit) relating to defined benefit plans | ||||||
Payments to defined contribution plans | ||||||
Total operating charge (credit) | ||||||
Interest income on plan assetsa | ( | ( | ( | ( | ( | |
Interest on plan liabilities | ||||||
Other finance (income) expense | ( | ( | ||||
Analysis of the amount recognized in other comprehensive income | ||||||
Actual asset return less interest income on plan assets | ( | ( | ( | |||
Change in financial assumptions underlying the present value of the plan liabilities | ( | |||||
Change in demographic assumptions underlying the present value of the plan liabilities | ( | |||||
Experience gains and losses arising on the plan liabilities | ( | ( | ( | |||
Remeasurements recognized in other comprehensive income | ( | ( | ||||
Movements in benefit obligation during the year | ||||||
Benefit obligation at 1 January | ||||||
Exchange adjustments | ( | ( | ( | ( | ||
Operating charge relating to defined benefit plans | ||||||
Interest cost | ||||||
Contributions by plan participants | ||||||
Benefit payments (funded plans)c | ( | ( | ( | ( | ( | |
Benefit payments (unfunded plans)c | ( | ( | ( | ( | ( | |
Disposals | ( | ( | ||||
Remeasurements | ( | ( | ( | ( | ||
Benefit obligation at 31 Decembera d | ||||||
Movements in fair value of plan assets during the year | ||||||
Fair value of plan assets at 1 January | ||||||
Exchange adjustments | ( | ( | ( | ( | ||
Interest income on plan assetsa e | ||||||
Contributions by plan participants | ||||||
Contributions by employers (funded plans) | ||||||
Benefit payments (funded plans)c | ( | ( | ( | ( | ( | |
Remeasurementse | ( | ( | ( | |||
Fair value of plan assets at 31 Decemberf | ||||||
Surplus (deficit) at 31 December | ( | ( | ( | |||
Represented by | ||||||
Asset recognized | ||||||
Liability recognized | ( | ( | ( | ( | ( | |
( | ( | ( | ||||
The surplus (deficit) may be analysed between funded and unfunded plans as follows | ||||||
Funded | ||||||
Unfunded | ( | ( | ( | ( | ( | |
( | ( | ( | ||||
The defined benefit obligation may be analysed between funded and unfunded plans as follows | ||||||
Funded | ( | ( | ( | ( | ( | |
Unfunded | ( | ( | ( | ( | ( | |
( | ( | ( | ( | ( |
aThe costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of
administering other post-employment benefit plans are included in the benefit obligation. Following the closure of the primary UK pension plan, current service cost in the UK consists of $38
million of costs of administering that plan and $10 million of current service cost from the remaining small worldwide plans administered and reported through the UK.
bPast service costs predominantly reflect minor plan changes in France. Settlements represent changes in small worldwide plans administered and reported throughout the UK.
cThe benefit payments amount shown above comprises $1,907 million benefits and $352 million settlements relating to the buy-out in Canada, plus $57 million of plan expenses incurred in the
administration of the benefit.
210 | bp Annual Report and Form 20-F 2025 |
24. Pensions and other post-employment benefits – continued
dThe benefit obligation for the US is made up of $4,428 million for pension liabilities and $1,096 million for other post-employment benefit liabilities (which are unfunded and are primarily retiree
medical liabilities). The benefit obligation for the Eurozone includes $3,086 million for pension liabilities in Germany which is largely unfunded.
eThe actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.
fThe fair value of plan assets includes borrowings related to the LDI programme as described on page 207.
$ million | ||||||
2023 | ||||||
UK | US | Eurozone | Other | Total | ||
Analysis of the amount charged to profit or loss | ||||||
Current service costa | ||||||
Past service costb | ( | |||||
Settlementb | ||||||
Operating charge (credit) relating to defined benefit plans | ||||||
Payments to defined contribution plans | ||||||
Total operating charge (credit) | ||||||
Interest income on plan assetsa | ( | ( | ( | ( | ( | |
Interest on plan liabilities | ||||||
Other finance (income) expense | ( | ( | ||||
Analysis of the amount recognized in other comprehensive income | ||||||
Actual asset return less interest income on plan assets | ( | ( | ||||
Change in financial assumptions underlying the present value of the plan liabilities | ( | ( | ( | ( | ||
Change in demographic assumptions underlying the present value of the plan liabilities | ( | ( | ( | |||
Experience gains and losses arising on the plan liabilities | ( | ( | ( | ( | ||
Remeasurements recognized in other comprehensive income | ( | ( | ( |
aThe costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of
administering other post-employment benefit plans are included in the benefit obligation. Following the closure of the primary UK pension plan, current service cost in the UK consists of $34
million of costs of administering that plan and $10 million of current service cost from the remaining small worldwide plans administered and reported through the UK.
bPast service costs predominantly represent largely offsetting income and costs due to the removal of some benefits for members in Turkish plans and their replacement with new arrangements
administered and reported through the UK. There was also a $5 million past service cost in France relating to statutory retirement age changes. Settlements represent charges for special
Sensitivity analysis
The discount rate, inflation and the mortality assumptions all have a significant effect on the amounts reported. A one-percentage point change, in
isolation, in certain assumptions as at 31 December 2025 for the group’s pensions and other post-employment benefit expense would have had the
effects shown in the tables below. The effects shown for the expense in 2026 comprise the total of current service cost and net finance income or
expense.
$ million | |||||||
One percentage point | |||||||
UK | US | Eurozone | |||||
Increase | Decrease | Increase | Decrease | Increase | Decrease | ||
Discount ratea | |||||||
Effect on expense in 2026 | ( | ( | ( | ( | |||
Effect on obligation at 31 December 2025 | ( | ( | ( | ||||
Inflation rateb | |||||||
Effect on expense in 2026 | ( | ( | ( | ||||
Effect on obligation at 31 December 2025 | ( | ( | ( | ||||
aThe amounts presented reflect that the discount rate is used to determine the asset interest income as well as the interest cost on the obligation.
bThe amounts presented reflect the total impact of an inflation rate change on the assumptions for rate of increase in salaries, pensions in payment and deferred pensions.
$ million | ||||
One year increase | ||||
UK | US | Eurozone | ||
Longevity | ||||
Effect on expense in 2026 | ||||
Effect on obligation at 31 December 2025 | ||||
bp Annual Report and Form 20-F 2025 | 211 |
| ||||
Financial statements | ||||
24. Pensions and other post-employment benefits – continued
Estimated future benefit payments and the weighted average duration of defined benefit obligations
duration of the defined benefit obligations at 31 December 2025 are as follows:
$ million | ||||||
Estimated future benefit payments | UK | US | Eurozone | Other | Total | |
2026 | ||||||
2027 | ||||||
2028 | ||||||
2029 | ||||||
2030 | ||||||
2031 - 2035 | ||||||
Years | ||||||
Weighted average duration |
25. Cash and cash equivalents
$ million | |||
2025 | 2024 | ||
Cash | |||
Triparty repos and term bank deposits | |||
Other cash equivalents | |||
Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; deposits and triparty repos of three months
or less with banks and similar institutions; money market funds and treasury bills. The carrying amounts of cash, triparty repos, term bank deposits
and treasury bills approximate their fair values. Substantially all of the other cash equivalents are categorized within level 1 of the fair value
hierarchy.
Cash and cash equivalents at 31 December 2025 includes $4,725 million (2024 $4,844 million) that is restricted. The restricted cash balances include
amounts required to cover initial margin on trading exchanges and certain cash balances which are subject to exchange controls.
The group holds $6,434 million (2024 $5,774 million) of cash and cash equivalents outside the UK and it is not expected that any significant tax will
arise on repatriation.
26. Finance debt
$ million | |||||||
2025 | 2024 | ||||||
Current | Non-current | Total | Current | Non-current | Total | ||
Borrowings |
The main elements of current borrowings are the current portion of long-term borrowings that is due to be repaid in the next 12 months of $3,003
million (2024 $3,793 million) and issued commercial paper of $200 million (2024 $500 million). Finance debt does not include accrued interest of
$552 million (2024 $585 million), which is reported within other payables. As part of actively managing its debt portfolio, during the year the group
bought back $2.0 billion (2024 $nil ) of finance debt consisting entirely of US dollar bonds. These transactions have no significant impact on net debt
or gearing.
entered into to manage interest rate and currency exposures.
Fixed rate debt | Floating rate debt | Total | |||||
Weighted average interest rate % | Weighted average time for which rate is fixed Years | Amount $ million | Weighted average interest rate % | Amount $ million | Amount $ million | ||
2025 | |||||||
US dollar | |||||||
Other currencies | |||||||
2024 | |||||||
US dollar | |||||||
Other currencies | |||||||
212 | bp Annual Report and Form 20-F 2025 |
26. Finance debt - continued
Fair values
The estimated fair value of finance debt is shown in the table below together with the carrying amount as reflected in the balance sheet.
Long-term borrowings in the table below include the portion of debt that matures in the 12 months from 31 December 2025, whereas in the group
balance sheet the amount is reported within current finance debt.
the significant majority of the group’s long-term borrowings are determined using quoted prices in active markets, and so fall within level 1 of the
fair value hierarchy. Where quoted prices are not available, quoted prices for similar instruments in active markets are used and such
measurements are therefore categorized in level 2 of the fair value hierarchy.
$ million | |||||
2025 | 2024 | ||||
Fair value | Carrying amount | Fair value | Carrying amount | ||
Short-term borrowings | |||||
Long-term borrowings | |||||
Total finance debt |
27. Capital disclosures and net debt
The group defines capital as total equity plus net debt. Our financial framework seeks to support the pursuit of value growth for shareholders while
maintaining a secure financial base.
The group monitors capital on the basis of gearing, that is, the ratio of net debt to the total of net debt plus total equity. 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
exchange and interest rate risks relating to finance debt for which hedge accounting is applied, less cash and cash equivalents. Net debt and
gearing are non-IFRS measures. 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’. All components of
equity are included in the denominator of the calculation.
$ million | |||
At 31 December | 2025 | 2024 | |
Finance debt | |||
Less: fair value asset (liability) of hedges related to finance debta | ( | ( | |
Less: cash and cash equivalents | |||
Net debt | |||
Total equity | |||
Gearing |
aDerivative financial instruments entered into for the purpose of managing foreign currency exchange risk associated with net debt with a fair value liability position of $94 million (2024 liability of
Certain subsidiaries in the group have externally imposed capital requirements and have been in compliance with these requirements throughout
the year.
bp Annual Report and Form 20-F 2025 | 213 |
| ||||
Financial statements | ||||
27. Capital disclosures and net debt - continued
$ million | ||||||
Finance debt | Currency swapsa | Lease liabilities | Partner payable for leases entered into on behalf of joint operations | Total liabilities arising from financing activities | ||
At 1 January 2025 | ||||||
Exchange adjustments | ||||||
Net financing cash flow | ( | ( | ( | ( | ( | |
Fair value (gains) losses | ( | ( | ||||
New and remeasured leases/joint operations payables | ( | |||||
Other movements | ( | ( | ( | ( | ||
At 31 December 2025 | ||||||
At 1 January 2024 | ||||||
Exchange adjustments | ( | ( | ( | ( | ||
Net financing cash flow | ( | ( | ( | |||
Fair value (gains) losses | ( | |||||
New and remeasured leases/joint operations payables | ||||||
Other movementsb | ( | |||||
At 31 December 2024 |
aCurrency swaps include cross currency interest rate swaps.
bIncludes $3,726 million of finance debt and $585 million of lease liabilities acquired as part of the Lightsource bp and bp Bunge Bioenergia business combinations.
The finance debt and currency swap balances above do 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. The
currency swaps are reported on the balance sheet within the headings 'Derivative financial instruments' and are subsets of both derivatives held for
trading and derivatives designated in fair value hedge relationships as detailed in Note 30. When hedge accounting is applied to these derivatives
they are included in the calculation of net debt shown above.
In addition to the liabilities included in the table above the group has accrued $448 million (2024 $922 million) at the balance sheet date for shares
repurchased between the end of the reporting period and 10 February 2026 (2024 11 February 2025). $4,486 million (2024 $7,127 million) is included
in financing activities in the group cash flow statement for the cash used to repurchase shares during the year.
28. Leases
The group leases a number of assets as part of its activities. This primarily includes drilling rigs in the oil production & operations and gas & low
carbon energy segments and retail service stations, oil depots and storage tanks in the customer & products segment as well as office
accommodation and vessel charters across the group. The weighted-average remaining lease term for the total lease portfolio is around nine years
(2024 eight years ). Some leases have payments that vary with market interest or inflation rates. Certain leases contain residual value guarantees,
which may be triggered in certain circumstances such as if market values have significantly declined at the conclusion of the lease.
$ million | |||
2025 | 2024 | ||
Undiscounted lease liability cash flows due: | |||
Within 1 year | |||
1 to 2 years | |||
2 to 3 years | |||
3 to 4 years | |||
4 to 5 years | |||
5 to 10 years | |||
Over 10 years | |||
Impact of discounting | ( | ( | |
Lease liabilities at 31 December | |||
Of which – current | |||
– non-current |
214 | bp Annual Report and Form 20-F 2025 |
28. Leases - continued
The group may enter into lease arrangements a number of years before taking control of the underlying asset due to construction lead times or to
secure future operational requirements. The total undiscounted amount for future commitments for leases not yet commenced as at 31 December
2025 is $2,953 million (2024 $5,311 million). The majority of this future commitment relates to pipelines that are under construction in the Gulf of
America from 2026.
$ million | |||
2025 | 2024 | ||
Total cash outflow for amounts included in lease liabilities | |||
Expense for variable payments not included in the lease liabilitya | |||
Short-term lease expensea | |||
Additions to right-of-use assets in the period | |||
Gain (loss) on sale and leaseback transactions |
29. Financial instruments and financial risk factors
$ million | |||||||
At 31 December 2025 | Note | Measured at amortized cost | Mandatorily measured at fair value through profit or loss | Derivative hedging instruments | Total carrying amount | ||
Financial assets | |||||||
Other investments | 18 | — | |||||
Loans | — | ||||||
Trade and other receivables | 20 | — | — | ||||
Derivative financial instruments | 30 | — | |||||
Cash and cash equivalents | 25 | — | |||||
Financial liabilities | |||||||
Trade and other payables | 22 | ( | — | — | ( | ||
Derivative financial instruments | 30 | — | ( | ( | ( | ||
Accruals | ( | — | — | ( | |||
Lease liabilities | 28 | ( | — | — | ( | ||
Finance debt | 26 | ( | — | — | ( | ||
( | ( | ( |
$ million | |||||||
At 31 December 2024 | Note | Measured at amortized cost | Mandatorily measured at fair value through profit or loss | Derivative hedging instruments | Total carrying amount | ||
Financial assets | |||||||
Other investments | 18 | — | |||||
Loans | — | ||||||
Trade and other receivables | 20 | — | — | ||||
Derivative financial instruments | 30 | — | |||||
Cash and cash equivalents | 25 | — | |||||
Financial liabilities | |||||||
Trade and other payables | 22 | ( | — | — | ( | ||
Derivative financial instruments | 30 | — | ( | ( | ( | ||
Accruals | ( | — | — | ( | |||
Lease liabilities | 28 | ( | — | — | ( | ||
Finance debt | 26 | ( | — | — | ( | ||
( | ( | ( |
The fair value of finance debt is shown in Note 26. For all other financial instruments within the scope of IFRS 9, the carrying amount is either the fair
value, or approximates the fair value.
Information on gains and losses on derivative financial assets and financial liabilities classified as measured at fair value through profit or loss is
provided in the derivative gains and losses section of Note 30. Fair value gains and losses related to other assets and liabilities classified as
measured at fair value through profit or loss totalled a net loss of $354 million (2024 net gain of $1 million and 2023 net loss of $11 million). Dividend
income of $19 million (2024 $24 million and 2023 $18 million) from investments in equity instruments classified as measured at fair value through
profit or loss is presented within other income.
bp Annual Report and Form 20-F 2025 | 215 |
| ||||
Financial statements | ||||
29. Financial instruments and financial risk factors – continued
Interest income and expenses arising on financial instruments are disclosed in Note 7.
Financial risk factors
The group is exposed to a number of different financial risks arising from ordinary business exposures as well as its use of financial instruments
including market risks relating to commodity prices; foreign currency exchange rates and interest rates; credit risk; and liquidity risk.
The group financial risk committee (GFRC) advises the chief financial officer (CFO) who oversees the management of these risks. The GFRC is
chaired by the CFO and consists of a group of senior managers including the SVPs tax and treasury, central financial planning & analysis, mergers &
acquisitions and business development, finance supply, trading and shipping, and the group controller. The purpose of the committee is to advise
on financial risks and the appropriate financial risk governance framework for the group. The committee provides assurance to the CFO and the
chief executive officer (CEO), and via the CEO to the board, that the group’s financial risk-taking activity is governed by appropriate policies and
procedures and that financial risks are identified, measured and managed in accordance with group policies and group risk appetite.
The group’s trading activities in the oil, natural gas, LNG and power markets are managed within the supply, trading and shipping business. Treasury
holds foreign exchange and interest-rate products in the financial markets to hedge group exposures related to debt and hybrid bond issuance; the
compliance, control and risk management processes for these activities are managed within the treasury business. All other foreign exchange and
interest rate activities within financial markets are performed within the supply, trading and shipping business and are also underpinned by the
compliance, control and risk management infrastructure common to the activities of bp’s supply, trading and shipping business. All derivative
activity is carried out by specialist teams that have the appropriate skills, experience and supervision. These teams are subject to close financial and
management control.
The supply, trading and shipping business maintains formal governance processes that provide oversight of market risk, credit risk and operational
risk associated with trading activity. A policy and risk committee approves value-at-risk delegations, reviews incidents and validates risk-related
policies, methodologies and procedures. A commitments committee approves the trading of new products, instruments and strategies and
material commitments.
In addition, the supply, trading and shipping business undertakes derivative activity for risk management purposes under a control framework as
described more fully below.
(a) Market risk
Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The
primary commodity price risks that the group is exposed to include oil, natural gas and power prices that could adversely affect the value of the
group’s financial assets, liabilities or expected future cash flows. The group has developed a control framework aimed at managing the volatility
inherent in certain of its ordinary business exposures. In accordance with the control framework the group enters into various transactions using
derivatives for risk management purposes.
The major components of market risk are commodity price risk, foreign currency exchange risk and interest rate risk, each of which is discussed
below.
(i) Commodity price risk
The group’s supply, trading and shipping business is responsible for delivering value across the overall crude, oil products, gas, LNG and power
supply chains. As such, it routinely enters into spot and term physical commodity contracts in addition to optimising physical storage, pipeline and
transportation capacity. These activities expose the group to commodity price risk which is managed by entering into oil, natural gas and power
swaps, options and futures.
The group measures market risk exposure arising from its risk managed trading positions using value-at-risk techniques based on Monte Carlo
simulation models. These techniques make a statistical assessment of the market risk arising from possible future changes in market prices over a
one-day holding period within a 95% confidence level. Risk managed trading activity is subject to value-at-risk and other limits for each trading
activity and the aggregate of all trading activity. The calculation of potential changes in value within the risk managed period considers positions,
historical price movements and the correlation of these price movements. Models are regularly reviewed against actual fair value movements to
ensure integrity is maintained. The value-at-risk measure is supplemented by stress testing and scenario analysis through simulating the financial
impact of certain physical, economic and geo-political scenarios. The value-at-risk measure in respect of the aggregated risk managed trading
positions at 31 December 2025 was $34 million (2024 $42 million) whereas the average value-at-risk measure for the period was $49 million (2024
$35 million). This measure incorporates the effect of diversification reflecting the offsetting risks across the trading portfolio. Alternative measures
are used to monitor exposures which are not risk managed and for which value-at-risk techniques are not appropriate.
(ii) Foreign currency exchange risk
Since bp has global operations, fluctuations in foreign currency exchange rates can have a significant effect on the group’s reported results and
future expenditure commitments. The effects of most exchange rate fluctuations are absorbed in business operating results through changing
cost competitiveness, lags in market adjustment to movements in rates and translation differences accounted for on specific transactions. For this
reason, the total effect of exchange rate fluctuations is not identifiable separately in the group’s reported results. The main underlying economic
currency of the group’s cash flows is the US dollar. This is because bp’s major product, oil, is priced internationally in US dollars. bp’s foreign
currency exchange management policy is to limit economic and material transactional exposures arising from currency movements against the US
dollar. The group co-ordinates the handling of foreign currency exchange risks centrally, by netting off naturally-occurring opposite exposures
wherever possible and then managing any material residual foreign currency exchange risks.
Most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2025, the total foreign currency
borrowings not swapped into US dollars amounted to $454 million (2024 $555 million). The group also has in issue perpetual subordinated hybrid
bonds in euro, sterling and US dollars. Whilst the contractual terms of these instruments allow the group to defer coupon payments and the
repayment of principal indefinitely, the group has chosen to manage the foreign currency exposure relating to the non-US dollar hybrid bonds to
their respective first call periods.
The group manages the net residual foreign currency exposures by constantly reviewing the foreign currency economic value at risk and aims to
manage such risk to keep the 12-month foreign currency value at risk below $400 million. At no point over the past three years did the value at risk
exceed the maximum risk limit. A continuous assessment is made in respect of the group’s foreign currency exposures to capture hedging
requirements.
216 | bp Annual Report and Form 20-F 2025 |
29. Financial instruments and financial risk factors – continued
During the year, hedge accounting was applied to foreign currency exposure to highly probable forecast capital expenditure commitments. The
group fixes the US dollar cost of non-US dollar supplies by using currency forwards for the highly probable forecast capital expenditure. At
31 December 2025 the most significant open contracts in place were for USD equivalent amounts of $84 million Australian dollars (2024 $92 million
sterling).
Where the group enters into foreign currency exchange contracts for entrepreneurial trading purposes the activity is controlled using trading
value-at-risk techniques as explained in (i) commodity price risk above.
(iii) Interest rate risk
bp is also exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its financial
instruments, principally finance debt. While the group issues debt and hybrid bonds in a variety of currencies based on market opportunities, it uses
derivatives to swap the economic exposure to a floating rate basis, mainly to US dollar floating, but in certain defined circumstances maintains a US
dollar fixed rate exposure for a proportion of debt. The proportion of floating rate debt net of interest rate swaps at 31 December 2025 was 29 % of
total finance debt outstanding (2024 30 %). The weighted average interest rate on finance debt at 31 December 2025 was 5 % (2024 5 %) and the
weighted average maturity of fixed rate debt was eight years (2024 eight years ).
The group’s earnings are sensitive to changes in interest rates on the element of the group’s finance debt that is contractually floating rate or has
been swapped to floating rates. If the interest rates applicable to these floating rate instruments of $16,694 million (2024 $18,006 million) (see Note
26) were to have changed by one percentage point on 1 January 2026, it is estimated that the group’s finance costs for 2026 would change by
approximately $167 million (2024 $180 million).
(b) Credit risk
Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing financial loss
to the group and arises from cash and cash equivalents, derivative financial instruments and deposits with financial institutions and principally
from credit exposures to customers relating to outstanding receivables. Credit exposure also exists in relation to guarantees issued by group
companies under which the outstanding exposure incremental to that recognized on the balance sheet at 31 December 2025 was $708 million
(2024 $655 million) in respect of liabilities of joint ventures and associates and $659 million (2024 $585 million) in respect of liabilities of other third
parties. An amount of $170 million (2024 $146 million) is recorded as a liability at 31 December 2025 in relation to these guarantees. For all
guarantees, maturity dates vary, and the guarantees will terminate on payment and/or cancellation of the obligation. In general, a payment under
the guarantee contract would be triggered by failure of the guaranteed party to fulfil its obligation covered by the guarantee.
The group has a credit policy, approved by the CFO, that is designed to ensure that consistent processes are in place throughout the group to
measure and control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business
contract the extent to which the arrangement exposes the group to credit risk is considered. Key requirements of the policy include segregation of
credit approval authorities from any sales, marketing or trading teams authorized to incur credit risk; the establishment of credit systems and
processes to ensure that all counterparty exposure is rated and that all counterparty exposure and limits can be monitored and reported; and the
timely identification and reporting of any non-approved credit exposures and credit losses. While each segment is responsible for its own credit
risk management and reporting consistent with group policy, treasury holds group-wide credit risk authority and oversight responsibility for
exposure to banks and financial institutions.
For the purposes of financial reporting the group calculates expected loss allowances based on the maximum contractual period over which the
group is exposed to credit risk. Lifetime expected credit losses are recognized for trade receivables and the credit risk associated with the
significant majority of financial assets measured at amortized cost is considered to be low. Since the tenor of substantially all of the group's in-
scope financial assets is less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit
losses. Expected loss allowances for financial guarantee contracts are typically lower than their initial fair value less, where appropriate,
amortization. Financial assets are considered to be credit-impaired when there is reasonable and supportable evidence that one or more events
that have a detrimental impact on the estimated future cash flows of the financial asset have occurred. This includes observable data concerning
significant financial difficulty of the counterparty; a breach of contract; concession being granted to the counterparty for economic or contractual
reasons relating to the counterparty’s financial difficulty, that would not otherwise be considered; it becoming probable that the counterparty will
enter bankruptcy or other financial re-organization or an active market for the financial asset disappearing because of financial difficulties. The
group also applies a rebuttable presumption that an asset is credit-impaired when contractual payments are more than 30 days past due. Where
the group has no reasonable expectation of recovering a financial asset in its entirety or a portion thereof, for example where all legal avenues for
collection of amounts due have been exhausted, the financial asset (or relevant portion) is written off.
The measurement of expected credit losses is a function of the probability of default, loss given default (i.e. the magnitude of the loss after
recovery if there is a default) and the exposure at default (i.e. the asset's carrying amount). The group allocates a credit risk rating to exposures
based on data that is determined to be predictive of the risk of loss, including but not limited to external ratings. Probabilities of default derived
from historical, current and future-looking market data are assigned by credit risk rating with a loss given default based on historical experience
and relevant market and academic research applied by exposure type. Experienced credit judgement is applied to ensure probabilities of default
are reflective of the credit risk associated with the group's exposures. Credit enhancements that would reduce the group's credit losses in the
event of default are reflected in the calculation when they are considered integral to the related asset.
The maximum credit exposure associated with financial assets is equal to the carrying amount. The group does not aim to remove credit risk
entirely but expects to experience a certain level of credit losses. As at 31 December 2025, the group had in place credit enhancements designed to
mitigate approximately $9.3 billion (2024 $8.2 billion) of credit risk related to assets in the scope of IFRS 9's impairment requirements. Credit
enhancements include standby and documentary letters of credit, bank guarantees, and insurance which are typically taken out with financial
institutions who have investment grade credit ratings. Reports are regularly prepared and presented to the GFRC that cover the group’s overall
credit exposure and expected loss trends, exposure by segment, and overall quality of the portfolio.
bp Annual Report and Form 20-F 2025 | 217 |
| ||||
Financial statements | ||||
29. Financial instruments and financial risk factors – continued
assets which are subject to review for impairment under IFRS 9 is as set out in the table below.
% | |||
As at 31 December | 2025 | 2024 | |
AAA to AA- | |||
A+ to A- | |||
BBB+ to BBB- | |||
BB+ to BB- | |||
B+ to B- | |||
CCC+ and below |
Movements in the impairment provision for trade and other receivables are shown in Note 21.
The following table shows the amounts recognized for financial assets and liabilities which are subject to offsetting arrangements on a gross basis,
and the amounts offset in the balance sheet.
Amounts which cannot be offset under IFRS, but which could be settled net under the terms of master netting agreements if certain conditions
arise, and collateral received or pledged, are also presented in the table to show the total net exposure of the group.
$ million | |||||||
Gross amounts of recognized financial assets (liabilities) | Amounts set off | Net amounts presented on the balance sheet | Related amounts not set off in the balance sheet | Net amount | |||
At 31 December 2025 | Master netting arrangements | Cash collateral (received) pledged | |||||
Derivative assets | ( | ( | ( | ||||
Derivative liabilities | ( | ( | ( | ||||
Trade and other receivables | ( | ( | ( | ||||
Trade and other payables | ( | ( | ( | ||||
At 31 December 2024 | |||||||
Derivative assets | ( | ( | ( | ||||
Derivative liabilities | ( | ( | ( | ||||
Trade and other receivables | ( | ( | ( | ||||
Trade and other payables | ( | ( | ( | ||||
(c) Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the group’s business activities may not be available. The group’s liquidity is managed
centrally with operating units forecasting their cash and currency requirements to the central treasury function. Unless restricted by local
regulations, generally subsidiaries pool their cash surpluses to the treasury function, which will then arrange to fund other subsidiaries’
requirements, or invest any net surplus in the market or arrange for necessary external borrowings, while managing the group’s overall net
currency positions. While there is the potential for concerns about the energy transition to impact banks’ or debt investors’ appetite to finance
hydrocarbon activity, we do not anticipate any material change to the group's funding or liquidity in the short to medium term as a result of such
concerns.
The group benefits from open credit provided by suppliers who generally sell on five to 60-day payment terms in accordance with industry norms.
bp utilizes various arrangements in order to manage its working capital and reduce volatility in cash flow. This includes discounting receivables and,
in the supply and trading businesses, managing inventory, collateral and supplier payment terms within a maximum of 60 days.
It is normal practice in the oil and gas supply and trading business for customers and suppliers to utilize letters of credit (LCs) facilities to mitigate
credit and non-performance risk. Consequently, LCs facilitate active trading in a global market where credit and performance risk can be
significant. In common with the industry, bp routinely provides LCs to some of its suppliers.
The group has committed LC facilities totalling $10,350 million (2024 $12,130 million), allowing LCs to be issued for a maximum 24 -month duration.
The facilities are held with 17 international banks.
In certain circumstances, the supplier has the option to request accelerated payment from the LC provider in order to further reduce their
exposure. bp’s payments are made to the provider of the LC rather than the supplier according to the original contractual payment terms. At 31
December 2025, a portion of the group’s trade payables which were subject to the LC arrangements were payable to LC providers, with no material
exposure to any individual provider. If these facilities were not available, this could result in renegotiation of payment terms with suppliers such that
payment terms were shorter.
The group sometimes uses promissory notes to pay its suppliers and other counterparties. This is primarily done to facilitate the counterparty
accelerating its cash inflow without also accelerating the group’s related cash outflow. For instance, if a supplier to the group’s supply, trading and
shipping business would like prepayment or early-payment for a supply of goods, the group may issue a promissory note (payable at a future date)
in favour of that supplier on the supplier’s desired cash inflow date, which that supplier can then convert to cash by selling it to a finance provider
on the same-day. The majority of promissory notes the group issues accrue interest on the principal amount of the note at a fixed rate stated on the
note from issuance to maturity. This is done to give the supplier or other counterparty certainty about the amount they will receive when they sell
the note. It also gives the group flexibility to select the maturity date of the note without that impacting the net present value of the note on its
issuance date. The maturity date the group selects for any promissory note that is for the purchase of goods by its supply and trading business will
be no more than 60 days after the group takes (or expects to take) title to those goods.
218 | bp Annual Report and Form 20-F 2025 |
29. Financial instruments and financial risk factors – continued
A portion of the group's trade payables form part of a reverse factoring arrangement with select suppliers.
Suppliers’ participation in the reverse factoring arrangement is voluntary. Suppliers that participate have the option to receive early payment on
invoices from the group’s external finance provider. If suppliers choose to receive early payment, they pay a fee to the finance provider. If they opt
not to receive early payment, they will pay no fee to the finance provider and will be paid the full invoice amount on the invoice due date. The group
provides data about invoices subject to the arrangement directly to the finance provider. This data includes the invoice due date and the maturity
date for each invoice. The invoice due date is the date the supplier would have been entitled to receive payment from the group had the invoice not
been made subject to the reverse factoring arrangement. The maturity date, which is the date the group will settle that invoice by paying the
finance provider, will, in some cases, be the same as the invoice due date. In other cases, it will be a date selected by the group that is no more than
60 days after the group has taken title to the goods to which the invoice relates. If the group selects a maturity date that is after the invoice due
date, the group pays the finance provider a fee.
Management does not consider the reverse factoring arrangement to result in excessive concentrations of liquidity risk, in part because the finance
provider has the option to (and does) sub-participate portions of the financings to other finance providers. The arrangements have been
established for a variety of reasons, including to ease the administrative burden of managing high volumes of invoices from some suppliers, to
facilitate some suppliers having the option to accelerate when they receive payment, often at a lower cost than that supplier’s usual cost of
borrowing, and, in some cases, to manage the working capital and reduce volatility in cash flow of the group’s supply and trading business. The
group has not derecognized the original trade payables relating to the arrangements because the original liability is not substantially modified on
entering into the arrangements.
2025 | 2024 | ||||||
Letters of Credit | Promissory Notes | Reverse Factoring Arrangements | Letters of Credit | Promissory Notes | Reverse Factoring Arrangements | ||
Carrying amount of liabilities ($ million) | |||||||
Presented within trade and other payables | |||||||
of which suppliers have received payment from the financial institution | |||||||
Range of payment due dates (days) | |||||||
Liabilities that are part of the arrangement | |||||||
Trade payables that are not part of the arrangement |
The group does not provide any collateral to the external finance provider.
There were no material business combinations or foreign exchange differences that would affect the liabilities under the supplier finance
arrangement in either period.
There were no significant non-cash changes in the carrying amount of financial liabilities subject to the supplier finance arrangements. The
payments to the bank are included within operating cash flows because they continue to be part of the normal operating cycle of the group and
their principal nature remains operating – i.e., payment for the purchase of goods and services.
If these facilities were not available, this could result in renegotiation of payment terms with suppliers such that settlement periods were shorter.
Standard & Poor’s Ratings long-term credit rating for bp is A- (stable) and Moody’s Investors Service rating is A1 (stable) and the Fitch Ratings' long-
term credit rating is A+ (stable).
During 2025, $239 million (2024 $9 billion) of long-term taxable bonds were issued with terms of nine years. In addition the group issued perpetual
hybrid capital securities with a US dollar equivalent value of $500 million (2024 $4.3 billion). Commercial paper is issued at competitive rates to
meet short-term borrowing requirements as and when needed.
As a further liquidity measure, the group continues to maintain suitable levels of cash and cash equivalents, amounting to $36.6 billion at
31 December 2025 (2024 $39.2 billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate and
short notice. As at 31 December 2025, the group had substantial amounts of undrawn borrowing facilities available, consisting of a committed
$8.0 billion credit facility and $4.0 billion of standby facilities, available for five years . These facilities are held with 33 international banks and
borrowings via these facilities would be at pre-agreed rates.
The group manages liquidity risk associated with derivative contracts, other than derivative hedging instruments, based on the expected maturities
of both derivative assets and liabilities as indicated in Note 30. Management does not currently anticipate any cash flows, other than noted below,
that could be of a significantly different amount or could occur earlier than the expected maturity analysis provided.
bp Annual Report and Form 20-F 2025 | 219 |
| ||||
Financial statements | ||||
29. Financial instruments and financial risk factors – continued
managing the group’s debt portfolio it is possible that cash flows in relation to finance debt could be accelerated from the profile provided.
$ million | |||||||||
2025 | 2024 | ||||||||
Trade and other payablesa | Accruals | Finance debtb | Interest on finance debt | Trade and other payablesa | Accruals | Finance debtb | Interest on finance debt | ||
Within one year | |||||||||
1 to 2 years | |||||||||
2 to 3 years | |||||||||
3 to 4 years | |||||||||
4 to 5 years | |||||||||
5 to 10 years | |||||||||
Over 10 years | |||||||||
a2025 includes $8,367 million (2024 $9,520 million) in relation to the Gulf of America oil spill, of which $6,834 million (2024 $8,383 million) matures in greater than one year.
bNot included in the table above are amounts not expected to be paid in cash but for which a cash flow could occur in specific circumstances and for which the earliest repayment periods are
foreign currency exchange risk, whether or not hedge accounting is applied, based upon contractual payment dates. As part of actively managing
the group’s debt portfolio it is possible that cash flows in relation to associated derivatives could be accelerated from the profile provided. The
amounts reflect the gross settlement amount where the pay leg of a derivative will be settled separately from the receive leg, as in the case of
cross-currency swaps hedging non-US dollar finance debt or hybrid bonds. The swaps are with high investment-grade counterparties and
therefore the settlement-day risk exposure is considered to be negligible. Not shown in the table are the gross settlement amounts (inflows) for the
receive leg of derivatives that are settled separately from the pay leg, which amount to $25,612 million at 31 December 2025 (2024 $24,206 million)
to be received on the same day as the related cash outflows.
$ million | |||||||
2025 | 2024 | ||||||
Cash outflows for derivative financial instruments at 31 December | Derivative assets | Derivative liabilities | Total | Derivative assets | Derivative liabilities | Total | |
Within one year | |||||||
1 to 2 years | |||||||
2 to 3 years | |||||||
3 to 4 years | |||||||
4 to 5 years | |||||||
5 to 10 years | |||||||
Over 10 years | |||||||
For further information on our derivative financial instruments, see Note 30.
30. Derivative financial instruments
In the ordinary course of business the group enters into derivative financial instruments (derivatives) to manage its normal business exposures in
relation to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating rate and
fixed rate debt, consistent with its risk management policies and objectives. An outline of the group’s financial risks and the objectives and policies
pursued in relation to those risks is set out in Note 29. Additionally, the group has a well-established entrepreneurial trading operation that is
undertaken in conjunction with these activities using a similar range of contracts.
For information on significant estimates and judgements made in relation to the valuation of derivatives see Derivative financial instruments within
Note 1.
Exchange traded derivatives are valued using closing prices provided by the exchange as at the balance sheet date. These derivatives are
categorized within level 1 of the fair value hierarchy. Exchange traded derivatives are typically considered settled through the (normally daily)
payment or receipt of variation margin.
Over-the-counter (OTC) financial swaps, forwards and physical commodity sale and purchase contracts are generally valued using readily available
information in the public markets and quotations provided by brokers and price index developers. These quotes are corroborated with market data
and are categorized within level 2 of the fair value hierarchy.
In certain less liquid markets, or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC financial swaps
and physical commodity sale and purchase contracts are valued using internally developed methodologies that consider historical relationships
between various commodities, and that result in management’s best estimate of fair value. These contracts are categorized within level 3 of the fair
value hierarchy.
220 | bp Annual Report and Form 20-F 2025 |
30. Derivative financial instruments – continued
Financial OTC and physical commodity options are valued using industry standard models that consider various assumptions, including quoted
forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant
economic factors. The degree to which these inputs are observable in the forward markets determines whether the option is categorized within
level 2 or level 3 of the fair value hierarchy.
$ million | |||||
2025 | 2024 | ||||
Fair value asset | Fair value liability | Fair value asset | Fair value liability | ||
Derivatives held for trading | |||||
Currency derivatives | ( | ( | |||
Oil price derivatives | ( | ( | |||
Natural gas price derivatives | ( | ( | |||
Power price derivatives | ( | ( | |||
Other derivatives | ( | ( | |||
( | ( | ||||
Cash flow hedges | |||||
Currency forwards | |||||
Fair value hedges | |||||
Currency swaps | ( | ( | |||
Interest rate swaps | ( | ( | |||
( | ( | ||||
( | ( | ||||
Of which – current | ( | ( | |||
– non-current | ( | ( |
Derivatives held for trading
The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to satisfy
supply requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original business
objective, and are recognized at fair value with changes in fair value recognized in the income statement. Trading activities are undertaken by using
a range of contract types in combination to create incremental gains by arbitraging prices between markets, locations and time periods. The net of
these exposures is monitored using market value-at-risk techniques as described in Note 29.
The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes.
$ million | ||||||||
2025 | ||||||||
Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5 years | Total | ||
Currency derivatives | ||||||||
Oil price derivatives | ||||||||
Natural gas price derivatives | ||||||||
Power price derivatives | ||||||||
Other derivatives | ||||||||
$ million | ||||||||
2024 | ||||||||
Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5 years | Total | ||
Currency derivatives | ||||||||
Oil price derivatives | ||||||||
Natural gas price derivatives | ||||||||
Power price derivatives | ||||||||
Other derivatives | ||||||||
bp Annual Report and Form 20-F 2025 | 221 |
| ||||
Financial statements | ||||
30. Derivative financial instruments – continued
$ million | ||||||||
2025 | ||||||||
Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5 years | Total | ||
Currency derivatives | ( | ( | ( | ( | ( | ( | ( | |
Oil price derivatives | ( | ( | ( | ( | ( | ( | ||
Natural gas price derivatives | ( | ( | ( | ( | ( | ( | ( | |
Power price derivatives | ( | ( | ( | ( | ( | ( | ( | |
Other derivatives | ( | ( | ( | ( | ||||
( | ( | ( | ( | ( | ( | ( | ||
$ million | ||||||||
2024 | ||||||||
Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5 years | Total | ||
Currency derivatives | ( | ( | ( | ( | ( | ( | ( | |
Oil price derivatives | ( | ( | ( | ( | ( | ( | ||
Natural gas price derivatives | ( | ( | ( | ( | ( | ( | ( | |
Power price derivatives | ( | ( | ( | ( | ( | ( | ( | |
Other derivatives | ( | ( | ( | ( | ||||
( | ( | ( | ( | ( | ( | ( |
methodology of fair value estimation. This information is presented on a gross basis, that is, before netting by counterparty.
$ million | ||||||||
2025 | ||||||||
Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5 years | Total | ||
Fair value of derivative assets | ||||||||
Level 1 | ||||||||
Level 2 | ||||||||
Level 3 | ||||||||
Less: netting by counterparty | ( | ( | ( | ( | ( | ( | ( | |
Fair value of derivative liabilities | ||||||||
Level 1 | ( | ( | ( | ( | ( | ( | ||
Level 2 | ( | ( | ( | ( | ( | ( | ( | |
Level 3 | ( | ( | ( | ( | ( | ( | ( | |
( | ( | ( | ( | ( | ( | ( | ||
Less: netting by counterparty | ||||||||
( | ( | ( | ( | ( | ( | ( | ||
Net fair value | ||||||||
$ million | ||||||||
2024 | ||||||||
Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over 5 years | Total | ||
Fair value of derivative assets | ||||||||
Level 1 | ||||||||
Level 2 | ||||||||
Level 3 | ||||||||
Less: netting by counterparty | ( | ( | ( | ( | ( | ( | ( | |
Fair value of derivative liabilities | ||||||||
Level 1 | ( | ( | ( | ( | ( | |||
Level 2 | ( | ( | ( | ( | ( | ( | ( | |
Level 3 | ( | ( | ( | ( | ( | ( | ( | |
( | ( | ( | ( | ( | ( | ( | ||
Less: netting by counterparty | ||||||||
( | ( | ( | ( | ( | ( | ( | ||
Net fair value | ( | ( |
222 | bp Annual Report and Form 20-F 2025 |
Level 3 derivatives
The following table shows the changes during the year in the net fair value of derivatives held for trading purposes within level 3 of the fair value
hierarchy.
$ million | |||||||
Oil price | Natural gas price | Power price | Currency | Other | Total | ||
Fair value contracts at 1 January 2025 | ( | ||||||
Gains (losses) recognized in the income statement | |||||||
Sales | |||||||
Settlements | ( | ( | ( | ( | ( | ||
Transfers out of level 3 | ( | ( | ( | ( | |||
Net fair value of contracts at 31 December 2025 | ( | ( | |||||
Deferred day-one gains (losses) | |||||||
Derivative asset (liability) | |||||||
$ million | |||||||
Oil price | Natural gas price | Power price | Currency | Other | Total | ||
Fair value contracts at 1 January 2024 | ( | ||||||
Gains (losses) recognized in the income statement | ( | ( | ( | ( | |||
Purchases | |||||||
Settlements | ( | ( | ( | ( | ( | ||
Transfers out of level 3 | ( | ( | |||||
Net fair value of contracts at 31 December 2024 | ( | ||||||
Deferred day-one gains (losses) | |||||||
Derivative asset (liability) |
The amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at 31 December 2025 was a
$514 million gain (2024 $193 million loss related to derivatives still held at 31 December 2024).
Derivative gains and losses
The group enters into derivative contracts including futures, options, swaps and certain forward sales and forward purchases contracts, relating to
both currency and commodity trading activities. Gains or losses arise on contracts entered into for risk management purposes, optimization
activity and entrepreneurial trading. They also arise on certain contracts that are for normal procurement or sales activity for the group but that are
required to be fair valued under accounting standards. These gains and losses are included within sales and other operating revenues in the income
statement. Also included within this line item are gains and losses on inventory held for trading purposes. The total amount relating to all these
items was a net gain of $11,206 million (2024 $9,726 million net gain and 2023 $19,786 million net gain). This number does not include gains and
losses on the change in value of contracts which are not recognized under IFRS such as transportation and storage contracts, but does include the
associated financially settled contracts. The net amounts for actual gains and losses relating to these derivative contracts and all related items
therefore differ significantly from the amounts disclosed above.
As outlined in Note 1 - Significant estimate and judgement: derivative financial instruments, LNG contracts are only recognized in the financial
statements when associated cargoes are lifted. The embedded value in these contracts is not recognized and is subject to underlying commodity
price volatility. bp generally price risk manages the exposure to LNG cargoes due for delivery in the near term where there is a liquid market. It does
so on a portfolio basis using derivative instruments amongst other price risk management strategies. Under IFRS, these derivative instruments,
which are subject to similar price volatility, are recorded at fair value through profit and loss at each reporting period, which creates an accounting
mismatch in the financial statements between the accounting for LNG contracts and the derivatives used for risk management. For the years
ended 31 December 2025 and 31 December 2024, there were no material gains or losses recorded on the associated derivative positions. For the
year ended 31 December 2023, there were material gains recognized on the associated derivative positions due to the movement in the underlying
commodity prices.
The group also enters into derivative contracts relating to foreign currency risk management activities including contracts that the group has
entered into to manage the foreign currency exposure relating to the non-US dollar hybrid bonds to their respective first call periods. The change in
the unrealized value of these contracts was a net gain of $1,187 million (2024 $404 million net loss and 2023 $632 million net gain). Where the
derivative is economically hedging finance debt, gains and losses on such derivative contracts are included within finance costs. Where the
derivative is managing non-US hybrid bond exposure gains and loss are included within production and manufacturing expenses. Where these
gains and losses arise on derivatives hedging finance debt they are largely offset by opposing net foreign exchange differences on retranslation of
the associated non-US dollar debt. The net amounts for actual gains and losses relating to these derivative contracts and all related items therefore
differ significantly from the amounts disclosed above.
Cash flow hedges
(i) Foreign currency risk of highly probable forecast capital expenditure
At 31 December 2025, the group held currency forwards designated as hedging instruments in cash flow hedge relationships of highly probable
forecast non-US dollar capital expenditure. Note 29 outlines the group’s approach to foreign currency exchange risk management. When the highly
probable forecast capital expenditure designated as a hedged item occurs, a non-financial asset is recognized and is presented within the fixed
asset section of the balance sheet.
bp Annual Report and Form 20-F 2025 | 223 |
| ||||
Financial statements | ||||
30. Derivative financial instruments – continued
The group claims hedge accounting only for the spot value of the currency exposure in line with the strategy to fix the volatility in the spot
exchange rate element. The fair value on the instrument attributable to forward points and foreign currency basis spreads is taken immediately to
the income statement.
The group applies hedge accounting where there is an economic relationship between the hedged item and hedging instrument. The existence of
an economic relationship is determined at inception and prospectively by comparing the critical terms of the hedging instrument and those of the
hedged item. The group enters into hedging derivatives that match the currency and notional of the hedged items on a 1:1 hedge ratio basis. The
hedge ratio is determined by comparing the notional amount of the derivative with the notional designated on the forecast transaction. The group
determines the extent to which it hedges highly probable forecast capital expenditures on a project by project basis.
The group has identified the following sources of ineffectiveness, which are not expected to be material:
•counterparty's credit risk, the group mitigates counterparty credit risk by entering into derivative transactions with high credit quality
counterparties; and
•differences in settlement timing between the derivative and hedged items. The latter impacts the discount factor used in the calculation of the
hedge ineffectiveness. The group mitigates differences in timing between the derivatives and hedged items by applying a rolling strategy and
by hedging currency pairs from stable economies. The group's cash flow hedge designations are highly effective as the sources of
ineffectiveness identified are expected to result in minimal hedge ineffectiveness.
The group has not designated any net positions as hedged items in cash flow hedges of foreign currency risk.
(ii) Commodity price risk of highly probable forecast sales
During the period the group held Henry Hub NYMEX futures designated as hedging instruments in cash flow hedge relationships of certain highly
probable forecast future sales. Henry Hub NYMEX futures are subject to daily settlement, where their fair value at the end of each day is required to
be cash settled, such that the carrying amount of these hedging instruments within continuing hedge relationships is always zero at the end of
each day.
The group is exposed to the variability in the gas price, but only applied hedge accounting to the risk of Henry Hub price movements for a
percentage of future gas sales from its BPX Energy business.
The group applied hedge accounting in relation to these highly probable future sales where there was an economic relationship between the
hedged item and hedging instrument. The existence of an economic relationship was determined at inception and prospectively by comparing the
critical terms of the hedging instrument and those of the hedged item. The group entered into hedging derivatives that matched the notional
amounts of the hedged items on a 1:1 hedge ratio basis. The hedge ratio was determined by comparing the notional amount of the derivative with
the notional amount designated on the forecast transaction.
The hedge was highly effective due to the price index of the hedging instruments matching the price index of the hedged item. The group did not
designate any net positions as hedged items in cash flow hedges of commodity price risk.
period.
$ million | ||||
Change in fair value of hedging instrument used to calculate ineffectiveness | Change in fair value of hedged item used to calculate ineffectiveness | Hedge ineffectiveness recognized in profit or (loss) | ||
At 31 December 2025 | ||||
Cash flow hedges | ||||
Foreign exchange risk | ||||
Highly probable forecast capital expenditure | ||||
Commodity price risk | ||||
Highly probable forecast sales | ( | |||
At 31 December 2024 | ||||
Cash flow hedges | ||||
Foreign exchange risk | ||||
Highly probable forecast capital expenditure | ||||
Commodity price risk | ||||
Highly probable forecast sales | ( |
224 | bp Annual Report and Form 20-F 2025 |
30. Derivative financial instruments – continued
The tables below summarize the carrying amount and nominal amount of the derivatives designated as hedging instruments in cash flow hedge
relationships.
Carrying amount of hedging instrument | Nominal amounts of hedging instruments | ||||
Assets | Liabilities | ||||
At 31 December 2025 | $ million | $ million | $ million | mmBtu | |
Cash flow hedges | |||||
Foreign exchange risk | |||||
Highly probable forecast capital expenditure | |||||
Commodity price risk | |||||
Highly probable forecast sales | ( | ||||
At 31 December 2024 | |||||
Cash flow hedges | |||||
Foreign exchange risk | |||||
Highly probable forecast capital expenditure | |||||
Commodity price risk | |||||
Highly probable forecast sales | ( | ||||
All hedging instruments are presented within derivative financial instruments on the group balance sheet.
Of the nominal amount of hedging instruments at 31 December 2025 relating to highly probable forecast capital expenditure, $67 million matures
within 12 months (2024 $95 million) and $20 million matures within one to two years of the balance sheet date (2024 $nil ). Of the nominal amount of
hedging instruments at 31 December 2025 relating to highly probable forecast sales, 420 mmBtu matures within 12 months (2024 209 mmBtu) and
The table below summarizes the weighted average exchange rates and the weighted average sales price in relation to the derivatives designated as
hedging instruments in cash flow hedge relationships at 31 December.
Weighted average price/rate | |||||
2025 | 2024 | ||||
At 31 December | Forecast capital expenditure | Forecast sales | Forecast capital expenditure | Forecast sales | |
Sterling/US dollar | |||||
Euro/US dollar | |||||
Australian dollar/US dollar | |||||
Henry Hub $/mmBtu | |||||
Fair value hedges
At 31 December 2025, the group held interest rate and cross-currency interest rate swap contracts as fair value hedges of the interest rate risk and
foreign currency risk arising from group fixed rate debt issuances. Note 29 outlines the group’s approach to interest rate and foreign currency
exchange risk management. The interest rate swaps are used to convert US dollar denominated fixed rate borrowings into floating rate debt. The
cross-currency interest rate swaps are used to convert sterling, euro, Australian dollar, Japanese yen, Swiss franc, Hong Kong dollar and Norwegian
krone denominated fixed rate borrowings into US dollar floating rate debt. The group manages all risks derived from debt issuance, such as credit
risk, however, the group applies hedge accounting only to certain components of interest rate and foreign currency risk in order to minimize hedge
ineffectiveness. The interest rate and foreign currency exposures are identified and hedged on an instrument-by-instrument basis.
For interest rate exposures, the group designates as a fair value hedge the benchmark interest rate component only. This is an observable and
reliably measurable component of interest rate risk. For foreign currency exposures, the group excludes from the designation the foreign currency
basis spread component implicit in the cross-currency interest rate swaps. This is separately calculated at hedge designation, is recognized in
other comprehensive income over the life of the hedge and amortized to the income statement on a straight-line basis, in accordance with the
group’s policy on costs of hedging.
bp Annual Report and Form 20-F 2025 | 225 |
| ||||
Financial statements | ||||
30. Derivative financial instruments – continued
The group applies hedge accounting where there is an economic relationship between the hedged item and the hedging instrument. The existence
of an economic relationship is determined initially by comparing the critical terms of the hedging instrument and those of the hedged item and it is
prospectively assessed using linear regression analysis. The group issues fixed rate debt and enters into interest rate and cross-currency interest
rate swaps with critical terms that match those of the debt and on a 1:1 hedge ratio basis. The hedge ratio is determined by comparing the notional
amount of the derivative with the notional amount of the debt. The hedge relationship is designated for the full term and notional value of the debt.
Both the hedging instrument and the hedged item are expected to be held to maturity.
The group has identified the following sources of ineffectiveness, which are not expected to be material:
•derivative counterparty’s credit risk which is not offset by the hedged item. This risk is mitigated by entering into derivative transactions only
with high credit quality counterparties; and
•sensitivity to interest rate between the hedged item and the derivatives. This is driven by differences in payment frequencies between the
instrument and the bond.
period. The signage convention for changes in fair value presented in this table is consistent with that presented in Note 27.
$ million | ||||
Change in fair value of hedging instrument used to calculate ineffectiveness | Change in fair value of hedged item used to calculate ineffectiveness | Hedge ineffectiveness recognized in profit or (loss) | ||
At 31 December 2025 | ||||
Fair value hedges | ||||
Interest rate risk on finance debt | ( | |||
Interest rate and foreign currency risk on finance debt | ( | |||
At 31 December 2024 | ||||
Fair value hedges | ||||
Interest rate risk on finance debt | ( | |||
Interest rate and foreign currency risk on finance debt | ( | ( |
The tables below summarize the carrying amount of the derivatives designated as hedging instruments in fair value hedge relationships at 31
December.
$ million | ||||
Carrying amount of hedging instrument | Nominal amounts of hedging instruments | |||
At 31 December 2025 | Assets | Liabilities | ||
Fair value hedges | ||||
Interest rate risk on finance debt | ( | |||
Interest rate and foreign currency risk on finance debt | ( | |||
At 31 December 2024 | ||||
Fair value hedges | ||||
Interest rate risk on finance debt | ( | |||
Interest rate and foreign currency risk on finance debt | ( | |||
All hedging instruments are presented within derivative financial instruments on the group balance sheet and are categorized within level 2 of the
fair value hierarchy. Ineffectiveness arising on fair value hedges is included within finance costs in the income statement.
The tables below summarize the profile by tenor of the nominal amount of the derivatives designated as hedging instruments in fair value hedge
relationships at 31 December.
$ million | |||||||||
At 31 December 2025 | Less than 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | 5-10 years | Over 10 years | Total | |
Fair value hedges | |||||||||
Interest rate risk on finance debt | |||||||||
Interest rate and foreign currency risk on finance debt | |||||||||
At 31 December 2024 | |||||||||
Fair value hedges | |||||||||
Interest rate risk on finance debt | |||||||||
Interest rate and foreign currency risk on finance debt |
226 | bp Annual Report and Form 20-F 2025 |
30. Derivative financial instruments – continued
The table below summarizes the weighted average floating interest rate and the weighted average exchange rates in relation to the derivatives
designated as hedging instruments in fair value hedge relationships at 31 December.
At 31 December | 2025 | 2024 | |||
Interest rate swaps | Cross-currency interest rate swaps | Interest rate swaps | Cross-currency interest rate swaps | ||
Interest rate | |||||
Sterling/US dollar | |||||
Euro/US dollar | |||||
Hong Kong dollar/US dollar | |||||
Canadian dollar/US dollar | |||||
Australian dollar/ US dollar | |||||
Japanese Yen/ US dollar | |||||
Swiss Franc/US dollar |
The tables below summarize the carrying amount, and the accumulated fair value adjustments included within the carrying amount, of the hedged
items designated in fair value hedge relationships at 31 December.
$ million | |||||
Carrying amount of hedged item | Accumulated fair value adjustment included in the carrying amount of hedged items | ||||
At 31 December 2025 | Liabilities | Assets | Liabilities | Discontinued hedges | |
Fair value hedges | |||||
Interest rate risk on finance debt | ( | ( | |||
Interest rate and foreign currency risk on finance debt | ( | ( | |||
At 31 December 2024 | |||||
Fair value hedges | |||||
Interest rate risk on finance debt | ( | ( | |||
Interest rate and foreign currency risk on finance debt | ( | ||||
The hedged item for all fair value hedges is presented within finance debt on the group balance sheet.
bp Annual Report and Form 20-F 2025 | 227 |
| ||||
Financial statements | ||||
30. Derivative financial instruments – continued
Movement in reserves related to hedge accounting
The table below provides a reconciliation of the cash flow hedge and costs of hedging reserves on a pre-tax basis by risk category. The signage
convention of this table is consistent with that presented in Note 32.
$ million | |||||
Cash flow hedge reserve | |||||
Highly probable forecast capital expenditure | Highly probable forecast sales | Interest rate and foreign currency risk on finance debt | Total | ||
At 1 January 2025 | ( | ( | ( | ||
Recognized in other comprehensive income | |||||
Cash flow hedges marked to market | — | ||||
Cash flow hedges reclassified to the income statement - hedged item affected profit or loss | ( | — | ( | ||
Costs of hedging marked to market | — | — | |||
Costs of hedging reclassified to the income statement | — | — | |||
Cash flow hedges transferred to the balance sheet | ( | — | ( | ||
At 31 December 2025 | ( | ||||
$ million | |||||
Cash flow hedge reserve | |||||
Highly probable forecast capital expenditure | Highly probable forecast sales | Interest rate and foreign currency risk on finance debt | Total | ||
At 1 January 2024 | ( | ||||
Recognized in other comprehensive income | |||||
Cash flow hedges marked to market | ( | — | |||
Cash flow hedges reclassified to the income statement - hedged item affected profit or loss | ( | — | ( | ||
Costs of hedging marked to market | — | — | ( | ( | |
Costs of hedging reclassified to the income statement | — | — | ( | ( | |
( | ( | ( | ( | ||
Cash flow hedges transferred to the balance sheet | ( | — | ( | ||
At 31 December 2024 | ( | ( | ( | ||
All of the cash flow hedge reserve balances at 31 December 2025 and amounts reclassified from these cash flow hedge reserves into profit or loss
during the year relate to continuing hedge relationships. The amounts reclassified are presented in sales and other operating revenues in the
income statement.
Costs of hedging relates to the foreign currency basis spreads of hedging instruments used to hedge the group's interest rate and foreign currency
risk on debt which is a time-period related item.
228 | bp Annual Report and Form 20-F 2025 |
31. Called-up share capital
2025 | 2024 | 2023 | |||||
Issued | Shares thousand | $ million | Shares thousand | $ million | Shares thousand | $ million | |
Ordinary shares of | |||||||
At 1 January | |||||||
Issue of new shares for employee share-based payment plans | |||||||
Repurchase of ordinary share capital | ( | ( | ( | ( | ( | ( | |
Repurchases transferred to treasury shares | |||||||
At 31 December | |||||||
aThe nominal amount of 8 % cumulative first preference shares and 9 % cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of
preference shares.
Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for
every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands vote on
other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each.
In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference
shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10 % of the capital paid up on the
preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over
par value.
During 2025 the company repurchased 836 million (2024 1,238 million) ordinary shares for a total consideration of $4,486 million (2024 $7,127
million, including transaction costs of $24 million (2024 $38 million). 176 million shares repurchased were cancelled and 659 million shares were
held as treasury shares. The repurchased shares represented 5.1 % of ordinary share capital. A further 74 million ordinary shares were repurchased
between the end of the reporting period and 13 February 2026, the latest practicable date before the completion of these financial statements, for
a total cost of $450 million of which $448 million has been accrued at 31 December 2025. The number of shares in issue is reduced when shares are
repurchased and cancelled, but is not reduced in respect of the repurchases transferred to treasury shares.
2025 | 2024 | 2023 | |||||
Shares thousand | Nominal value $ million | Shares thousand | Nominal value $ million | Shares thousand | Nominal value $ million | ||
At 1 January | |||||||
Purchases for settlement of employee share plans | |||||||
Issue of new shares for employee share-based payment plans | |||||||
Shares re-issued for employee share-based payment plans | ( | ( | ( | ( | ( | ( | |
At 31 December | |||||||
Of which – shares held in treasury by bp | |||||||
– shares held in ESOP trusts | |||||||
– shares held by bp’s US share plan administratorb |
a See Note 32 for definition of treasury shares.
b Held in the form of ADSs to meet the requirements of employee share-based payment plans in the US.
For each year presented, the balance of shares held in treasury by bp at 1 January represents 2.9 % (2024 4.1 % and 2023 4.9 %) of the called-up
ordinary share capital of the company.
bp Annual Report and Form 20-F 2025 | 229 |
| ||||
Financial statements | ||||
THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY
230 | bp Annual Report and Form 20-F 2025 |
32. Capital and reserves
Share capital | Share premium account | Capital redemption reserve | Merger reserve | Total share capital and capital reserves | ||
At 1 January 2025 | ||||||
Profit (loss) for the year | ||||||
Items that may be reclassified subsequently to profit or loss | ||||||
Currency translation differences (including reclassifications) | — | — | — | — | — | |
Cash flow hedges and costs of hedging (including reclassifications) | — | — | — | — | — | |
Share of items relating to equity-accounted entities, net of tax | — | — | — | — | — | |
Items that will not be reclassified to profit or loss | ||||||
Remeasurements of the net pension and other post-employment benefit liability or asset | — | — | — | — | — | |
Remeasurements of equity investments | — | — | — | — | — | |
Cash flow hedges that will subsequently be transferred to the balance sheet | — | — | — | — | — | |
Total comprehensive income | — | — | — | — | — | |
Dividends | — | — | — | — | — | |
Cash flow hedges transferred to the balance sheet, net of tax | — | — | — | — | — | |
Repurchases of ordinary share capital | ( | — | — | |||
Share-based payments, net of taxb | — | — | — | |||
Share of equity-accounted entities’ changes in equity, net of tax | — | — | — | — | — | |
Issue of perpetual hybrid bonds | — | — | — | — | — | |
Redemption of perpetual hybrid bonds, net of tax | — | — | — | — | — | |
Payments on perpetual hybrid bonds | — | — | — | — | — | |
Transactions involving non-controlling interests, net of tax | — | — | — | — | — | |
At 31 December 2025 | ||||||
At 1 January 2024 | ||||||
Profit (loss) for the year | ||||||
Items that may be reclassified subsequently to profit or loss | ||||||
Currency translation differences (including reclassifications)a | — | — | — | — | — | |
Cash flow hedges and costs of hedging (including reclassifications) | — | — | — | — | — | |
Share of items relating to equity-accounted entities, net of tax | — | — | — | — | — | |
Other | — | — | — | — | — | |
Items that will not be reclassified to profit or loss | ||||||
Remeasurements of the net pension and other post-employment benefit liability or asset | — | — | — | — | — | |
Remeasurements of equity investments | — | — | — | — | — | |
Cash flow hedges that will subsequently be transferred to the balance sheet | — | — | — | — | — | |
Total comprehensive income | — | — | — | — | — | |
Dividends | — | — | — | — | — | |
Cash flow hedges transferred to the balance sheet, net of tax | — | — | — | — | — | |
Repurchases of ordinary share capital | ( | |||||
Share-based payments, net of taxb | ||||||
Issue of perpetual hybrid bonds | — | — | — | — | — | |
Redemption of perpetual hybrid bonds, net of tax | — | — | — | — | — | |
Payments on perpetual hybrid bonds | — | — | — | — | — | |
Transactions involving non-controlling interests, net of tax | — | — | — | — | — | |
At 31 December 2024 |
aIncludes $942 million recycling of cumulative foreign exchange losses from reserves relating to the sale of bp's Türkiye ground fuels business to Petrol Ofisi, offset by movements in Pound
Sterling against the US dollar.
bMovements in treasury shares relate to employee share-based payment plans.
bp Annual Report and Form 20-F 2025 | 231 |
| ||||
Financial statements | ||||
32. Capital and reserves – continued
$ million | ||||||||||
Treasury shares | Foreign currency translation reserve | Investments in equity instruments | Cash flow hedges | Costs of hedging | Total fair value reserves | Profit and loss account | bp shareholders’ equity | Non-controlling interests | Total equity | |
Hybrid bonds | Other interest | |||||||||
( | ( | ( | ( | ( | ( | |||||
— | — | — | — | — | — | |||||
— | — | — | — | — | ||||||
— | — | — | — | — | — | |||||
— | — | — | — | — | — | ( | ( | — | — | ( |
— | — | — | — | — | — | ( | ( | — | — | ( |
— | — | ( | — | — | ( | — | ( | — | — | ( |
— | — | — | — | — | — | — | ||||
— | ( | ( | ||||||||
— | — | — | — | — | — | ( | ( | — | ( | ( |
— | — | — | ( | — | ( | — | ( | — | — | ( |
( | — | — | — | — | — | ( | ( | — | — | ( |
— | — | — | — | — | ( | — | — | |||
— | — | — | — | — | — | — | — | |||
— | — | — | — | — | — | — | — | — | ||
— | — | — | — | — | — | — | — | ( | — | ( |
— | ( | — | — | — | — | — | ( | ( | — | ( |
— | — | — | — | — | — | ( | ( | — | ||
( | ( | ( | ( | ( | ||||||
( | ( | ( | ||||||||
— | — | — | — | — | — | |||||
— | ( | ( | — | — | ( | — | ( | — | ( | ( |
— | — | — | ( | ( | ( | — | ( | — | — | ( |
— | — | — | — | — | — | ( | ( | — | — | ( |
— | — | — | — | — | — | ( | ( | — | — | ( |
— | — | — | — | — | — | — | — | |||
— | — | ( | — | — | ( | — | ( | — | — | ( |
— | — | — | ( | — | ( | — | ( | — | — | ( |
— | ( | ( | ( | ( | ( | |||||
— | — | — | — | — | — | ( | ( | — | ( | ( |
— | — | — | ( | — | ( | — | ( | — | — | ( |
— | — | — | — | — | — | ( | ( | — | — | ( |
— | — | — | — | — | ( | — | — | |||
— | — | — | — | — | — | ( | ( | — | ||
— | — | — | — | — | — | ( | — | ( | ||
— | — | — | — | — | — | ( | — | ( | ||
— | — | — | — | — | — | — | ||||
( | ( | ( | ( | ( | ( | |||||
232 | bp Annual Report and Form 20-F 2025 |
32. Capital and reserves – continued
Share capital | Share premium account | Capital redemption reserve | Merger reserve | Total share capital and capital reserves | ||
At 1 January 2023 | ||||||
Profit (loss) for the year | ||||||
Items that may be reclassified subsequently to profit or loss | ||||||
Currency translation differences (including reclassifications) | — | — | — | — | — | |
Cash flow hedges and costs of hedging (including reclassifications) | — | — | — | — | — | |
Share of items relating to equity-accounted entities, net of tax | — | — | — | — | — | |
Items that will not be reclassified to profit or loss | ||||||
Remeasurements of the net pension and other post-employment benefit liability or asset | — | — | — | — | — | |
Remeasurements of equity investments | — | — | — | — | — | |
Cash flow hedges that will subsequently be transferred to the balance sheet | — | — | — | — | — | |
Total comprehensive income | — | — | — | — | — | |
Dividends | — | — | — | — | — | |
Cash flow hedges transferred to the balance sheet, net of tax | — | — | — | — | — | |
Repurchases of ordinary share capital | ( | — | — | — | ||
Share-based payments, net of taxa | — | — | ||||
Share of equity-accounted entities’ changes in equity, net of tax | — | — | — | — | — | |
Issue of perpetual hybrid bonds | — | — | — | — | — | |
Payments on perpetual hybrid bonds | — | — | — | — | — | |
Transactions involving non-controlling interests, net of tax | — | — | — | — | — | |
At 31 December 2023 |
aMovements in treasury shares relate to employee share-based payment plans.
bp Annual Report and Form 20-F 2025 | 233 |
| ||||
Financial statements | ||||
32. Capital and reserves – continued
$ million | ||||||||||
Treasury shares | Foreign currency translation reserve | Investments in equity instruments | Cash flow hedges | Costs of hedging | Total fair value reserves | Profit and loss account | bp shareholders’ equity | Non-controlling interests | Total equity | |
Hybrid bonds | Other interest | |||||||||
( | ( | ( | ( | ( | ||||||
— | — | — | — | — | — | |||||
— | — | — | — | — | — | — | ||||
— | — | — | ( | — | — | — | ||||
— | — | — | — | — | — | ( | ( | — | — | ( |
— | — | — | — | — | — | ( | ( | — | — | ( |
— | — | — | — | — | — | — | ||||
— | — | — | — | — | — | — | ||||
— | ( | |||||||||
— | — | — | — | — | — | ( | ( | — | ( | ( |
— | — | — | ( | — | ( | — | ( | — | — | ( |
— | — | — | — | — | — | ( | ( | — | — | ( |
— | — | — | — | — | ( | — | — | |||
— | — | — | — | — | — | — | ||||
— | — | — | — | — | — | ( | ( | — | ||
— | ( | — | — | — | — | — | ( | ( | — | ( |
— | — | — | — | — | — | ( | ||||
( | ( | ( | ||||||||
234 | bp Annual Report and Form 20-F 2025 |
32. Capital and reserves – continued
Share capital
The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury
shares.
Share premium account
The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares.
Capital redemption reserve
The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled.
Merger reserve
The balance on the merger reserve represents the premium arising where the fair value of the consideration given is in excess of the nominal value
of the ordinary shares issued in an acquisition made by the issue of shares where merger relief under the Companies Act applies.
Treasury shares
Treasury shares represent bp shares repurchased and available for specific and limited purposes. For accounting purposes shares held in
Employee Share Ownership Plans (ESOPs) and bp’s US share plan administrator to meet the future requirements of the employee share-based
payment plans are treated in the same manner as treasury shares and are, therefore, included in the financial statements as treasury shares. The
ESOPs are funded by the group and have waived their rights to dividends in respect of such shares held for future awards. Until such time as the
shares held by the ESOPs vest unconditionally to employees, the amount paid for those shares is shown as a reduction in shareholders’ equity.
Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group.
Investments in equity instruments
This reserve records the change in fair value of investments in equity instruments for which the group has elected to recognize fair value gains and
losses in other comprehensive income.
Foreign currency translation reserve
The foreign currency translation reserve records exchange differences arising from the translation of the financial statements of foreign
operations. Upon disposal of foreign operations, the related accumulated exchange differences are reclassified to the income statement.
Cash flow hedges
This reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. For
further information on the accounting for cash flow hedges see Note 1 - Derivative financial instruments and hedging activities.
Costs of hedging
This reserve records the change in fair value of the foreign currency basis spread of financial instruments to which cost of hedge accounting has
been applied. The accumulated amount relates to time-period related hedged items and is amortized to profit or loss over the term of the hedging
relationship. For further information on the accounting for costs of hedging see Note 1 - Derivative financial instruments and hedging activities.
Profit and loss account
The balance held on this reserve is the accumulated retained profits of the group.
Non-controlling interests
Non-controlling interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to bp shareholders. Included within non-
controlling interests are perpetual subordinated hybrid bonds, perpetual subordinated hybrid securities and certain equity instruments with
preferred distributions issued by group subsidiaries. The contractual terms of these instruments allow the group to defer coupon payments, equity
distributions and repayment of principal indefinitely. However, the terms and conditions of each instrument stipulate the circumstances in which
deferred payments and/or the principal amount of the instrument becomes payable. These circumstances, which include the announcement of a
bp p.l.c. ordinary share or parity equity dividend distribution, are within the group’s control.
Perpetual subordinated hybrid bonds are issued by BP Capital Markets p.l.c., a group subsidiary, in euro, sterling and US dollars. During the year BP
Capital Markets p.l.c. redeemed $1.2 billion of the non-call 2025 4.375 % US dollar hybrid bonds issued in 2020. As at 31 December 2025 the total
population of hybrid bonds include redemption options exercisable at the group’s discretion from March 2026 to March 2035 (the first ‘call date’),
on specified dates thereafter, or in the event of specific circumstances (such as a change in IFRS or tax regime) as set out in the individual terms of
each issue. Coupons are fixed for an initial period up to dates from June 2026 to June 2035 at rates of 3.25 % to 6.45 % and reset to rates determined
by the contractual terms of each instrument on certain dates thereafter. Whilst the contractual terms of these instruments allow the group to defer
coupon payments and the repayment of principal indefinitely, the group has chosen to swap the non-US dollar hybrid bonds to a USD floating
interest rate up to their respective first call periods. Payments made to and profit attributed to these hybrid bonds in the year totalled $644 million
(2024 $485 million) and $640 million (2024 $517 million) respectively. The amount of hybrid bonds included in non-controlling interests at the end of
the year was $13.5 billion (2024 $14.6 billion).
Perpetual subordinated hybrid securities issued by group subsidiaries include $1,000 million (2024 $500 million), specifically earmarked to fund BP
Alternative Energy Investments Ltd including the funding of Lightsource bp and $1,500 million (2024 $1500 million) specifically earmarked to fund a
floating, production, storage and offloading vessel (FPSO) used in one of the group’s major projects. Payments made to and profit attributed to
perpetual hybrid securities in the year totalled $158 million (2024 $125 million) and $159 million (2024 $125 million) respectively. The amount of
perpetual subordinated hybrid securities included within non-controlling interests at the end of the year was $2.5 billion (2024 $2.0 billion).
bp Annual Report and Form 20-F 2025 | 235 |
| ||||
Financial statements | ||||
32. Capital and reserves – continued
Equity instruments with preferred distributions issued by group subsidiaries include $958 million of proceeds in 2025 from the sale of a 25 % non-
controlling interest in the subsidiary that holds bp’s 12 % interest in the entity that owns Trans-Anatolian natural gas pipeline and proceeds of $1,500
million the sale of a 49 % and 50 %, respectively, in non-controlling interests in the group subsidiaries that hold interests in Permian and Eagle Ford
midstream assets. Proceeds in 2024 of $1,330 million comprise $500 million of proceeds from the sale of a 49 % interest in a subsidiary that holds
certain Gulf of America midstream assets; and $830 million of proceeds from the sale of a 25 % non-controlling interest in the subsidiary that holds
bp’s 20 % interest in the entity that holds the Trans Adriatic natural gas pipeline. In these transactions, the group retains control over the ability to
defer equity distributions which are not guaranteed, and investors have no right to redeem their shares other than in certain circumstances that are
within the group’s control. The amount associated with equity instruments with preferred or other structured distributions included within non-
controlling interests at the end of the year was approximately $4.5 billion (2024 $1.6 billion).
$ million | ||||
2025 | ||||
Pre-tax | Tax | Net of tax | ||
Items that may be reclassified subsequently to profit or loss | ||||
Currency translation differences (including reclassifications) | ||||
Cash flow hedges (including reclassifications) | ( | |||
Costs of hedging (including reclassifications) | ||||
Share of items relating to equity-accounted entities, net of tax | ( | ( | ||
Items that will not be reclassified to profit or loss | ||||
Remeasurements of the net pension and other post-employment benefit liability or asset | ( | ( | ||
Remeasurements of equity investments | ( | ( | ||
Cash flow hedges that will subsequently be transferred to the balance sheet | ||||
Other comprehensive income | ||||
$ million | ||||
2024 | ||||
Pre-tax | Tax | Net of tax | ||
Items that may be reclassified subsequently to profit or loss | ||||
Currency translation differences (including reclassifications) | ( | ( | ( | |
Cash flow hedges (including reclassifications) | ( | ( | ||
Costs of hedging (including reclassifications) | ( | ( | ||
Share of items relating to equity-accounted entities, net of tax | ( | ( | ||
Other | ( | ( | ||
Items that will not be reclassified to profit or loss | ||||
Remeasurements of the net pension and other post-employment benefit liability or asseta | ( | |||
Remeasurements of equity investments | ( | ( | ||
Cash flow hedges that will subsequently be transferred to the balance sheet | ( | ( | ||
Other comprehensive income | ( | ( | ||
$ million | ||||
2023 | ||||
Pre-tax | Tax | Net of tax | ||
Items that may be reclassified subsequently to profit or loss | ||||
Currency translation differences (including reclassifications) | ||||
Cash flow hedges (including reclassifications) | ( | |||
Costs of hedging (including reclassifications) | ( | ( | ( | |
Share of items relating to equity-accounted entities, net of tax | ( | ( | ||
Items that will not be reclassified to profit or loss | ||||
Remeasurements of the net pension and other post-employment benefit liability or asset | ( | ( | ||
Remeasurements of equity investments | ( | |||
Cash flow hedges that will subsequently be transferred to the balance sheet | ||||
Other comprehensive income | ( | ( |
a2024 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%.
236 | bp Annual Report and Form 20-F 2025 |
33. Contingent liabilities and legal proceedings
Contingent liabilities
There were contingent liabilities at 31 December 2025 in respect of guarantees and indemnities entered into as part of the ordinary course of the
group’s business. No material losses are likely to arise from such contingent liabilities. Further information on financial guarantees is included in
Note 29.
In the normal course of the group’s business, bp group entities are subject to legal and regulatory proceedings arising out of current and past
operations, including matters related to commercial disputes, product liability, antitrust, commodities trading, premises-liability claims, consumer
protection, general health, safety, climate change and environmental claims and allegations of exposures of third parties to toxic substances, such
as lead pigment in paint, asbestos and other chemicals. The amounts claimed could be significant and could be material to the group’s results of
operations, financial position or liquidity. While it is difficult to predict the ultimate outcome in some cases, bp expects that the impact of current
legal and regulatory proceedings on the group‘s results of operations, liquidity or financial position will not be material.
The group files tax returns in many jurisdictions across the world. Various tax authorities are currently examining these returns, which contain
matters that could be subject to differing interpretations of applicable tax laws and regulations. The resolution of tax positions through
negotiations with relevant tax authorities, or through litigation, can take several years to complete and the amounts could be significant and could,
in aggregate, be material to the group’s results of operations, financial position or liquidity. While it is difficult to predict the ultimate outcome in
some cases, bp does not expect there to be any material impact upon the group‘s results of operations, financial position or liquidity.
The group is subject to numerous national and local health, safety and environmental laws and regulations concerning its products, operations and
other activities. These laws and regulations may require the group to take future action to remediate the effects on the environment of prior
disposal or release of chemicals or petroleum substances by the group or other parties. Such contingencies may exist for various sites including
refineries, chemical plants, oil fields, commodities extraction sites, service stations, terminals and waste disposal sites. In addition, the group may
have obligations relating to prior asset sales or closed facilities. The ultimate requirement for remediation and its costs are inherently difficult to
estimate. However, the estimated cost of environmental obligations has been provided in these accounts in accordance with the group‘s
accounting policies. While the amounts of future possible costs that are not provided for could be significant and material to the group‘s results of
operations in the period in which they are recognized, it is not possible to estimate the amounts involved. bp does not expect these costs to have a
material impact on the group’s results of operations, financial position or liquidity.
If production and manufacturing facilities and pipelines are sold to third parties and the subsequent owner is unable to meet their
decommissioning obligations it is possible that, in certain circumstances, bp could be partially or wholly responsible for decommissioning. The
group estimates that for production facilities, approximately $17 billion (2024 $16 billion) of associated decommissioning obligations were
previously transferred to third parties. While the amounts associated with decommissioning provisions reverting to the group could be material, bp
is not currently aware of any such material cases that have a greater than remote chance of reverting to the group. Furthermore, as described in
Provisions and contingencies within Note 1, decommissioning provisions associated with customers & products facilities are not generally
recognized as the potential obligations cannot be measured given their indeterminate settlement dates.
By their nature, it is not practicable to estimate the potential financial impact or possible timing of the above contingencies as there are significant
uncertainties that are dependent on various factors that are not within the group’s control.
Contingent liabilities related to the Gulf of America oil spill
For information on legal proceedings relating to the Deepwater Horizon oil spill, see Legal proceedings below. Any outstanding Deepwater Horizon
related claims are not expected to have a material impact on the group's financial performance.
Legal proceedings
Proceedings relating to the Deepwater Horizon oil spill
BP Exploration & Production Inc. (BPXP) was lease operator of Mississippi Canyon, Block 252 in the Gulf of America, where the semi-submersible rig
Deepwater Horizon was deployed at the time of the 20 April 2010 explosion and fire and resulting oil spill (the Incident). Lawsuits and claims arising
from the Incident were brought principally in US federal and state courts. The remaining proceedings arising from the Incident broadly seek
penalties, costs, damages and compensation for alleged environmental, personal injury, health and economic harm as a result of the Incident. bp
believes that impact of the remaining proceedings on the group’s financial position or liquidity will not be material and in future reports will not
report on legal proceedings relating to the Incident absent any material developments.
bp Annual Report and Form 20-F 2025 | 237 |
| ||||
Financial statements | ||||
33. Contingent liabilities and legal proceedings – continued
Other legal proceedings
Climate change
BP p.l.c., BP America Inc. and BP Products North America Inc. are co-defendants with other oil and gas companies in approximately 32 lawsuits
brought in various state and federal courts on behalf of various governmental and private parties. The lawsuits generally assert claims under a
variety of legal theories seeking to hold the defendant companies responsible for impacts allegedly caused by and/or relating to climate change.
Underlying many of the legal theories are allegations regarding deceptive communication and disinformation to the public. The lawsuits seek
remedies including payment of money and other forms of equitable relief. If such suits were successful, the cost of the remedies sought in the
various cases could be substantial. Defendants spent several years seeking to have the cases filed in state court removed to federal courts,
however Defendants’ attempts were ultimately unsuccessful. Accordingly, nearly all the cases are proceeding in various state courts. As a group,
the lawsuits generally remain at relatively early stages in the litigation process. While it is not possible to predict the outcome of these legal actions,
bp believes that it has valid defences, and it intends to defend such actions vigorously.
Louisiana Coastal restoration
companies seeking damages for coastal erosion. bp entities were named defendants in 17 of these cases. The lawsuits allege that the defendants'
historical operations in oil and gas fields within the Louisiana onshore coastal zone failed to comply with state permits and/or were conducted
without the required coastal use permits. The scope and scale of plaintiffs’ damages demands are significant and unprecedented, including
substantial remediation costs, natural resource (ecological impact) damages and the claimed costs for restoring coastal wetlands allegedly
impacted by oil and gas field operations.
Defendants removed all of these lawsuits to federal court and the removals were contested by plaintiffs, eventually resulting in a decision from the
US Fifth Circuit Court of Appeals rejecting defendants’ “federal officer” jurisdiction removal grounds in one of two lead cases – Plaquemines Parish
v. Riverwood, et al. At the time, the US Supreme Court declined to hear defendants’ petition challenging the ruling. In 2024, the US Fifth Circuit
issued a further ruling rejecting “federal officer” jurisdiction in a subset of the removed cases contested on a related removal theory. Co-defendant
Chevron filed a renewed writ of certiorari petition with the US Supreme Court challenging the US Fifth Circuit’s remand decision. On 16 June 2025,
the US Supreme Court granted Chevron’s petition in Chevron USA Inc. v. Plaquemines Parish. Oral argument was held on January 12, 2026 and a
decision in the appeal is expected during the Court’s current term which ends in June.
Following remand of the other lead removal case, Cameron Parish v. Auster, et. al., in which bp was the principal defendant, bp entered into a
settlement agreement and release with the plaintiffs in late 2023 in respect of all state and local governmental claims arising within Cameron
Parish. The terms of the settlement agreement and release are confidential and have not had and are not expected to have in the future, a
significant effect on the company’s financial position or profitability.
Atlantic Richfield Company, a bp affiliate, was a named defendant along with Chevron in Plaquemines Parish v. Rozel, et al, another costal
restoration damages case set for trial in March 2025. A state trial court initially ruled in favour of Atlantic Richfield’s motion for summary judgment
and dismissed it from the case, but following a motion by plaintiffs for reconsideration, the court reversed its summary judgment ruling and
reinstated Atlantic Richfield as a defendant. The plaintiffs’ claims against Atlantic Richfield were severed from the March 2025 trial, and the case
proceeded to trial against Chevron alone. In April 2025 , following a three-week trial, the jury returned a verdict against Chevron awarding plaintiffs
$745 million. The court has yet to establish a new trial date for the plaintiffs’ now separate claims against Atlantic Richfield. All other post-trial
activity in the case has been paused pending a decision from the US Supreme Court on Chevron’s petition.
No bp entity is a named defendant in any of the other active Louisiana Coastal restoration docket cases with a trial date, all of which remain in the
early stages of litigation. In addition, four private landowners have filed separate claims in the state courts in Jefferson and Plaquemines Parishes
of Louisiana for restoration damages related to alleged impacts to their marshlands associated with historic oil field operations. bp entities are
defendants in two of these private landowner cases, having been previously dismissed from a third.
While it is not possible to predict the outcomes of these novel legal actions, bp believes that it has valid defences, and it intends to defend such
238 | bp Annual Report and Form 20-F 2025 |
34. Remuneration of senior management and non-executive directors
$ million | ||||
2025 | 2024 | 2023 | ||
Total for all directors | ||||
Emoluments | ||||
Amounts received under incentive schemesa | ||||
Total |
aExcludes amounts relating to past directors.
Emoluments
These amounts comprise fees paid to the non-executive chair and the non-executive directors and, for executive directors, salary and benefits
earned during the relevant financial year, plus cash bonuses awarded for the year.
$ million | ||||
2025 | 2024 | 2023 | ||
Total for all senior management and non-executive directors | ||||
Short-term employee benefits | ||||
Pensions and other post-employment benefits | ||||
Share-based paymentsa | ||||
Termination benefits | ||||
Total |
a2023 includes a reversal of $14 million relating to the lapse of Bernard Looney's outstanding share awards in prior years.
Senior management comprises members of the leadership team.
Short-term employee benefits
These amounts comprise fees and benefits paid to the non-executive chair and non-executive directors, as well as salary, benefits and cash
bonuses for senior management. Deferred annual bonus awards, to be settled in shares, are included in share-based payments.
Pensions and other post-employment benefits
The amounts represent the estimated cost to the group of providing pensions and other post-employment benefits to senior management in
respect of the current year of service measured in accordance with IAS 19 ‘Employee Benefits’.
Share-based payments
This is the cost to the group of senior management’s participation in share-based payment plans, as measured by the fair value of options and
shares granted, accounted for in accordance with IFRS 2 ‘Share-based Payments’.
Termination benefits
Termination benefits include compensation to senior management for loss of office.
Related party transactions
Transactions between the group and its significant joint ventures and associates are summarized in Financial statements – Note 16 and Note 17. In
the ordinary course of its business, the group enters into transactions with various organizations with which some of its directors or executive
officers are associated. Except as described in this report, the group did not have any material transactions or transactions of an unusual nature
with, and did not make loans to, related parties in the period commencing 1 January 2025 to 13 February 2026.
bp Annual Report and Form 20-F 2025 | 239 |
| ||||
Financial statements | ||||
35. Employee costs and numbers
$ million | ||||
Employee costs | 2025 | 2024 | 2023 | |
Wages and salariesa | ||||
Social security costs | ||||
Share-based paymentsb | ||||
Pension and other post-employment benefit costs | ||||
2025 | 2024 | 2023 | ||||||||
Average number of employeesc | US | Non-US | Total | US | Non-US | Total | US | Non-US | Total | |
gas & low carbon energy | ||||||||||
oil production & operations | ||||||||||
customers & productsd e | ||||||||||
other businesses and corporate | ||||||||||
aIncludes termination costs of $467 million (2024 $336 million and 2023 $96 million).
bThe group provides certain employees with shares and share options as part of their remuneration packages. The majority of these share-based payment arrangements are equity-settled.
cReported to the nearest 100.
dIncludes 38,900 (2024 40,700 and 2023 33,800 ) service station staff.
eIncludes 9,100 (2024 1,700 and 2023 0 ) agricultural, operational and seasonal workers in Brazil.
36. Auditor’s remuneration
$ million | ||||
Fees | 2025 | 2024 | 2023 | |
The audit of the company annual accountsa | ||||
The audit of accounts of subsidiaries of the company | ||||
Total audit | ||||
Audit-related assurance servicesb | ||||
Total audit and audit-related assurance services | ||||
Non-audit and other assurance services | ||||
Services relating to bp pension plans | ||||
aFees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements.
bIncludes interim reviews and audit of internal control over financial reporting and non-statutory audit services.
2025 includes $0.5 million of additional fees for 2024. 2024 includes $1.3 million of additional fees for 2023. 2023 includes $0.2 million of additional
fees for 2022. Auditor's remuneration is included in the income statement within distribution and administration expenses.
Tax services (in relation to income tax, indirect tax compliance, employee tax services and tax advisory services) were $nil in all periods presented.
The audit committee has established pre-approval policies and procedures for the engagement of Deloitte to render audit and certain assurance
and other services. The audit fees payable to Deloitte were considered as part of the audit tender process in 2016 and challenged by the audit
committee through comparison with the audit pricing proposals of the other bidding firms. Changes in audit fees subsequent to the audit tender,
including matters relevant to the 2025 audit, have been reviewed and challenged by the Audit Committee, before being approved. Deloitte
performed further assurance services that were not prohibited by regulatory or other professional requirements and were pre-approved by the
Committee. Deloitte is engaged for these services when its expertise and experience of bp are important. Most of this work is of an audit-related or
assurance nature. During 2025, no audit-related fees, tax fees or other non-audit fees were approved by the audit committee pursuant to the de
minimis exception to the pre-approval requirement provided by paragraph (c)(7)(i) (C) of Rule 2-01 of Regulation S-X.
Under SEC regulations, the remuneration of the auditor of $74 million (2024 $66 million and 2023 $61 million) is required to be presented as follows:
audit $59 million (2024 $57 million and 2023 $53 million); other audit-related $5 million (2024 $4 million and 2023 $4 million); tax $nil (2024 $nil and
2023 $nil ); and all other fees $10 million (2024 $5 million and 2023 $4 million).
240 | bp Annual Report and Form 20-F 2025 |
37. Subsidiaries, joint arrangements and associatesa
capital (to nearest whole number) are set out below. The group's share of the assets and liabilities of the more important unincorporated joint
arrangements are held by subsidiaries listed in the table below. Those subsidiaries held directly by the parent company are marked with an asterisk
(*), the percentage owned being that of the group unless otherwise indicated. A complete list of undertakings of the group is included in Note 13 in
the parent company financial statements of BP p.l.c. which are filed with the Registrar of Companies in the UK, along with the group’s annual report.
Subsidiaries | % | Country of incorporation | Principal activities | ||
International | |||||
BP Corporate Holdings Limited | England & Wales | Investment holding | |||
BP Exploration Operating Company Limited | England & Wales | Exploration and production | |||
*BP Gamma Holdings Limited | England & Wales | Investment holding | |||
*BP Global Investments Limited | England & Wales | Investment holding | |||
*BP International Limited | England & Wales | Integrated oil operations | |||
BP Oil International Limited | England & Wales | Integrated oil operations | |||
*Castrol Group Holdings Limited | Scotland | Investment holding | |||
Azerbaijan | |||||
BP Exploration (Caspian Sea) Limited | England & Wales | Exploration and production | |||
BP Exploration (Azerbaijan) Limited | England & Wales | Exploration and production | |||
Germany | |||||
BP Europa SE | Germany | Refining and marketing | |||
Trinidad and Tobago | |||||
BP Trinidad and Tobago LLC | US | Exploration and production | |||
UK | |||||
BP Capital Markets p.l.c. | England & Wales | Finance | |||
Lightsource BP Renewable Energy Investments Limited | England & Wales | Onshore renewables | |||
US | |||||
*BP Holdings North America Limited | England & Wales | Investment holding | |||
Atlantic Richfield Company | US | Exploration and production, refining and marketing | |||
BP America Inc. | US | ||||
BP America Production Company | US | ||||
BP Company North America Inc. | US | ||||
BP Corporation North America Inc. | US | ||||
BP Products North America Inc. | US | ||||
The Standard Oil Company | US | ||||
Archaea Energy Inc. | US | Bioenergy | |||
BP Capital Markets America Inc. | US | Finance | |||
Joint arrangements | % | Country of incorporation | Principal activities | ||
Angola | |||||
Azule Energy Holdings Limited | England & Wales | Exploration and production |
aThere were no important associates in the group at 31 December 2025.
bp Annual Report and Form 20-F 2025 | 241 |
| ||||
Financial statements | ||||
Supplementary information on oil and natural gas (unaudited)
The regional analysis presented below is on a continent basis, with separate disclosure for countries that contain 15% or more of the total proved
reserves (for subsidiaries plus equity-accounted entitiesa), in accordance with SEC and FASB requirements.
Oil and gas reserves – certain definitions
Unless the context indicates otherwise, the following terms have the meanings shown below:
Proved oil and gas reserves
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions,
operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence
indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project
to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a
reasonable time.
(i)The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any; and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain
economically producible oil or gas on the basis of available geoscience and engineering data.
(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well
penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable
certainty.
(iii)Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas
cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance
data and reliable technology establish the higher contact with reasonable certainty.
(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid
injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favourable than in the reservoir as a whole, the
operation of an installed programme in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the
reasonable certainty of the engineering analysis on which the project or programme was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall
be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted
arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual
arrangements, excluding escalations based upon future conditions.
Undeveloped oil and gas reserves
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required for recompletion.
(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of
production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at
greater distances.
(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are
scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection
or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same
reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Developed oil and gas reserves
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor
compared to the cost of a new well; and
(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not
involving a well.
For details on bp’s proved reserves and production compliance and governance processes, see pages 340-349.
aSee Note 1 - Investment in Rosneft.
242 | bp Annual Report and Form 20-F 2025 |
Oil and natural gas exploration and production activities
$ million | ||||||||||
2025 | ||||||||||
Europe | North America | South America | Africa Asia | Australasia | Total | |||||
UK | Rest of Europe | US | Rest of North America | |||||||
Subsidiaries | ||||||||||
Capitalized costs at 31 Decembera b | ||||||||||
Gross capitalized costs | ||||||||||
Proved properties | 28,834 | — | 79,193 | 10 | 15,476 | 19,635 | 44,989 | 6,793 | 194,930 | |
Unproved properties | 418 | — | 632 | 1,981 | 1,188 | 968 | 1,633 | 796 | 7,616 | |
29,252 | — | 79,825 | 1,991 | 16,664 | 20,603 | 46,622 | 7,589 | 202,546 | ||
Accumulated depreciation | 24,342 | — | 48,293 | 1,604 | 13,017 | 19,949 | 30,750 | 5,945 | 143,900 | |
Net capitalized costs | 4,910 | — | 31,532 | 387 | 3,647 | 654 | 15,872 | 1,644 | 58,646 | |
Costs incurred for the year ended 31 Decembera b | ||||||||||
Acquisition of properties | ||||||||||
Proved | — | — | 957 | — | — | — | 5 | — | 962 | |
Unproved | — | — | 13 | — | 1 | — | 4 | — | 18 | |
— | — | 970 | — | 1 | — | 9 | — | 980 | ||
Exploration and appraisal costsc | 46 | — | 519 | 38 | 473 | 249 | 41 | 43 | 1,409 | |
Development | 581 | — | 4,461 | — | 686 | 226 | 2,180 | 253 | 8,387 | |
Total costs | 627 | — | 5,950 | 38 | 1,160 | 475 | 2,230 | 296 | 10,776 | |
Results of operations for the year ended 31 Decembera | ||||||||||
Sales and other operating revenuesd | ||||||||||
Third parties | 107 | — | 1,136 | — | 942 | 656 | 4,282 | 1,409 | 8,532 | |
Sales between businesses | 2,705 | — | 13,187 | — | 790 | 139 | 6,558 | 540 | 23,919 | |
2,812 | — | 14,323 | — | 1,732 | 795 | 10,840 | 1,949 | 32,451 | ||
Exploration expenditure | 36 | — | 321 | (6) | 154 | 20 | 32 | 13 | 570 | |
Production costs | 547 | — | 2,552 | 1 | 311 | 353 | 565 | 99 | 4,428 | |
Production taxes | (62) | — | 175 | — | 318 | — | 1,241 | 26 | 1,698 | |
Other costs (income)e | (95) | 9 | 2,571 | 23 | 28 | (56) | 39 | 90 | 2,609 | |
Depreciation, depletion and amortization | 1,454 | — | 4,966 | 3 | 1,178 | 530 | 3,224 | 436 | 11,791 | |
Net impairments and (gains) losses on sale of businesses and fixed assets | 249 | 4 | (74) | — | (19) | 121 | 11 | (2) | 290 | |
2,129 | 13 | 10,511 | 21 | 1,970 | 968 | 5,112 | 662 | 21,386 | ||
Profit (loss) before taxationf | 683 | (13) | 3,812 | (21) | (238) | (173) | 5,728 | 1,287 | 11,065 | |
Allocable taxes | 703 | — | 882 | (11) | 18 | 678 | 4,228 | 460 | 6,958 | |
Results of operations | (20) | (13) | 2,930 | (10) | (256) | (851) | 1,500 | 827 | 4,107 | |
aThese tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes bp's share of oil and natural gas exploration and production
activities of joint operations. They do not include any costs relating to the Gulf of America oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG
liquefaction and transportation operations are excluded. In addition, bp's midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and Europe are
excluded. The most significant midstream pipeline interests include the South Caucasus Pipeline, the Baku-Tbilisi-Ceyhan pipeline, the Trans Adriatic Pipeline and the Trans Anatolian Pipeline.
Major LNG activities are located in Trinidad, Indonesia and Australia.
bCosts of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
cIncludes exploration and appraisal drilling expenditures and pre development studies, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are
charged to income as incurred.
dPresented net of transportation costs, purchases and sales taxes.
eIncludes property taxes and other government take. The UK region includes a $275-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-
insurance programme.
fExcludes the unwinding of the discount on provisions and payables amounting to $480 million which is included in finance costs in the group income statement.
bp Annual Report and Form 20-F 2025 | 243 |
| ||||
Financial statements | ||||
Oil and natural gas exploration and production activities – continued
$ million | ||||||||||
2025 | ||||||||||
Europe | North America | South America | Africa Asia | Australasia | Total | |||||
UK | Rest of Europe | US | Rest of North America | |||||||
Equity-accounted entities (bp share) | ||||||||||
Capitalized costs at 31 Decembera b | ||||||||||
Gross capitalized costs | ||||||||||
Proved properties | — | 6,480 | — | — | 13,188 | 11,832 | 11,654 | — | 43,154 | |
Unproved properties | — | 767 | — | — | 97 | 533 | — | — | 1,397 | |
— | 7,247 | — | — | 13,285 | 12,365 | 11,654 | — | 44,551 | ||
Accumulated depreciation | — | 3,805 | — | — | 7,393 | 4,251 | 3,477 | — | 18,926 | |
Net capitalized costs | — | 3,442 | — | — | 5,892 | 8,114 | 8,177 | — | 25,625 | |
Costs incurred for the year ended 31 Decembera c d | ||||||||||
Acquisition of propertiesb | ||||||||||
Proved | — | — | — | — | — | — | — | — | — | |
Unproved | — | — | — | — | — | — | — | — | — | |
— | — | — | — | — | — | — | — | — | ||
Exploration and appraisal costsc | — | 55 | — | — | 3 | 153 | — | — | 211 | |
Development | — | 1,193 | — | — | 571 | 2,379 | 806 | — | 4,949 | |
Total costs | — | 1,248 | — | — | 574 | 2,532 | 806 | — | 5,160 | |
Results of operations for the year ended 31 Decembera | ||||||||||
Sales and other operating revenuese | ||||||||||
Third parties | — | 1,698 | — | — | 853 | 2,700 | 1,777 | — | 7,028 | |
Sales between businesses | — | — | — | — | 955 | — | — | — | 955 | |
— | 1,698 | — | — | 1,808 | 2,700 | 1,777 | — | 7,983 | ||
Exploration expenditure | — | 55 | — | — | — | 18 | — | — | 73 | |
Production costs | — | 186 | — | — | 483 | 651 | 647 | — | 1,967 | |
Production taxes | — | — | — | — | 267 | 27 | — | — | 294 | |
Other costs (income) | — | 2 | — | — | 116 | (124) | 24 | — | 18 | |
Depreciation, depletion and amortization | — | 481 | — | — | 451 | 1,484 | 816 | — | 3,232 | |
Net impairments and losses on sale of businesses and fixed assets | — | 321 | — | — | — | 129 | — | — | 450 | |
— | 1,045 | — | — | 1,317 | 2,185 | 1,487 | — | 6,034 | ||
Profit (loss) before taxation | — | 653 | — | — | 491 | 515 | 290 | — | 1,949 | |
Allocable taxes | — | 651 | — | — | 76 | 343 | 121 | — | 1,191 | |
Results of operations | — | 2 | — | — | 415 | 172 | 169 | — | 758 | |
aThese tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude
oil and natural gas pipelines, LNG liquefaction, transportation operations as well as downstream and other activities are excluded.
bCosts of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
cIncludes exploration and appraisal drilling expenditures and pre development studies, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are
charged to income as incurred.
dThe amounts shown reflect bp’s share of equity-accounted entities’ costs incurred, and not the costs incurred by bp in acquiring an interest in equity-accounted entities.
ePresented net of sales tax.
244 | bp Annual Report and Form 20-F 2025 |
Oil and natural gas exploration and production activities – continued
$ million | ||||||||||
2024 | ||||||||||
Europe | North America | South America | Africa | Asia | Australasia | Total | ||||
UK | Rest of Europe | US | Rest of North America | |||||||
Subsidiaries | ||||||||||
Capitalized costs at 31 Decembera b | ||||||||||
Gross capitalized costs | ||||||||||
Proved properties | 29,781 | — | 72,248 | 8 | 14,427 | 18,756 | 42,709 | 6,504 | 184,433 | |
Unproved properties | 411 | — | 3,012 | 1,936 | 2,760 | 2,471 | 1,701 | 762 | 13,053 | |
30,192 | — | 75,260 | 1,944 | 17,187 | 21,227 | 44,410 | 7,266 | 197,486 | ||
Accumulated depreciation | 24,269 | — | 44,067 | 1,602 | 13,450 | 20,373 | 27,528 | 5,506 | 136,795 | |
Net capitalized costs | 5,923 | — | 31,193 | 342 | 3,737 | 854 | 16,882 | 1,760 | 60,691 | |
Costs incurred for the year ended 31 Decembera b | ||||||||||
Acquisition of properties | ||||||||||
Proved | — | — | 52 | — | — | — | — | — | 52 | |
Unproved | — | — | 21 | — | 2 | — | — | — | 23 | |
— | — | 73 | — | 2 | — | — | — | 75 | ||
Exploration and appraisal costsc | 57 | — | 655 | 102 | 294 | 508 | 82 | 59 | 1,757 | |
Development | 629 | — | 3,829 | — | 661 | 1,334 | 1,363 | 137 | 7,953 | |
Total costs | 686 | — | 4,557 | 102 | 957 | 1,842 | 1,445 | 196 | 9,785 | |
Results of operations for the year ended 31 Decembera | ||||||||||
Sales and other operating revenuesd | ||||||||||
Third parties | 182 | — | 1,859 | — | 1,090 | 2,094 | 4,515 | 1,888 | 11,628 | |
Sales between businesses | 2,762 | — | 13,035 | — | 163 | — | 7,410 | 362 | 23,732 | |
2,944 | — | 14,894 | — | 1,253 | 2,094 | 11,925 | 2,250 | 35,360 | ||
Exploration expenditure | 1 | — | 463 | 97 | 137 | 188 | 55 | 33 | 974 | |
Production costs | 539 | — | 2,645 | 1 | 399 | 230 | 617 | 106 | 4,537 | |
Production taxes | (4) | — | 149 | — | 248 | — | 1,366 | 40 | 1,799 | |
Other costs (income)e | (221) | (8) | 2,455 | 23 | 47 | 49 | (59) | 116 | 2,402 | |
Depreciation, depletion and amortization | 1,234 | — | 4,394 | 3 | 1,206 | 543 | 3,116 | 477 | 10,973 | |
Net impairments and (gains) losses on sale of businesses and fixed assets | 1,058 | 14 | (471) | (19) | (259) | 2,312 | (1) | (1) | 2,633 | |
2,607 | 6 | 9,635 | 105 | 1,778 | 3,322 | 5,094 | 771 | 23,318 | ||
Profit (loss) before taxationf | 337 | (6) | 5,259 | (105) | (525) | (1,228) | 6,831 | 1,479 | 12,042 | |
Allocable taxes | 195 | (1) | 1,194 | (14) | (203) | 291 | 5,003 | 557 | 7,022 | |
Results of operations | 142 | (5) | 4,065 | (91) | (322) | (1,519) | 1,828 | 922 | 5,020 | |
aThese tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes bp's share of oil and natural gas exploration and production
activities of joint operations. They do not include any costs relating to the Gulf of America oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG
liquefaction and transportation operations are excluded. In addition, bp's midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and Europe are
excluded. The most significant midstream pipeline interests include the South Caucasus Pipeline, the Baku-Tbilisi-Ceyhan pipeline, the Trans Adriatic Pipeline and the Trans Anatolian Pipeline.
Major LNG activities are located in Trinidad, Indonesia and Australia.
bCosts of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
cIncludes exploration and appraisal drilling expenditures and pre development studies, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are
charged to income as incurred.
dPresented net of transportation costs, purchases and sales taxes.
eIncludes property taxes and other government take. The UK region includes a $313-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-
insurance programme.
fExcludes the unwinding of the discount on provisions and payables amounting to $460 million which is included in finance costs in the group income statement.
bp Annual Report and Form 20-F 2025 | 245 |
| ||||
Financial statements | ||||
Oil and natural gas exploration and production activities – continued
$ million | ||||||||||
2024 | ||||||||||
Europe | North America | South America | Africa | Asia | Australasia | Total | ||||
UK | Rest of Europe | US | Rest of North America | |||||||
Equity-accounted entities (bp share) | ||||||||||
Capitalized costs at 31 Decembera b | ||||||||||
Gross capitalized costs | ||||||||||
Proved properties | — | 5,211 | — | — | 12,185 | 10,181 | 10,848 | — | 38,425 | |
Unproved properties | — | 705 | — | — | 130 | 344 | — | — | 1,179 | |
— | 5,916 | — | — | 12,315 | 10,525 | 10,848 | — | 39,604 | ||
Accumulated depreciation | — | 2,968 | — | — | 7,284 | 3,209 | 2,661 | — | 16,122 | |
Net capitalized costs | — | 2,948 | — | — | 5,031 | 7,316 | 8,187 | — | 23,482 | |
Costs incurred for the year ended 31 Decembera c d | ||||||||||
Acquisition of propertiesb | ||||||||||
Proved | — | — | — | — | — | — | — | — | — | |
Unproved | — | — | — | — | — | 26 | — | — | 26 | |
— | — | — | — | — | 26 | — | — | 26 | ||
Exploration and appraisal costsc | — | 58 | — | — | 5 | 54 | — | — | 117 | |
Development | — | 761 | — | — | 821 | 1,105 | 901 | — | 3,588 | |
Total costs | — | 819 | — | — | 826 | 1,185 | 901 | — | 3,731 | |
Results of operations for the year ended 31 Decembera | ||||||||||
Sales and other operating revenuese | ||||||||||
Third partiesf | — | 1,943 | — | — | 840 | 2,692 | 1,854 | — | 7,329 | |
Sales between businessesf | — | — | — | — | 1,127 | — | — | — | 1,127 | |
— | 1,943 | — | — | 1,967 | 2,692 | 1,854 | — | 8,456 | ||
Exploration expenditure | — | 51 | — | — | — | 8 | — | — | 59 | |
Production costs | — | 145 | — | — | 812 | 560 | 574 | — | 2,091 | |
Production taxes | — | — | — | — | 324 | 37 | — | — | 361 | |
Other costs (income)g | — | 26 | — | — | 134 | 142 | 25 | — | 327 | |
Depreciation, depletion and amortization | — | 453 | — | — | 477 | 1,431 | 965 | — | 3,326 | |
Net impairments and losses on sale of businesses and fixed assets | — | 65 | — | — | 849 | — | — | — | 914 | |
— | 740 | — | — | 2,596 | 2,178 | 1,564 | — | 7,078 | ||
Profit (loss) before taxation | — | 1,203 | — | — | (629) | 514 | 290 | — | 1,378 | |
Allocable taxesg | — | 931 | — | — | (766) | 296 | 120 | — | 581 | |
Results of operations | — | 272 | — | — | 137 | 218 | 170 | — | 797 | |
aThese tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude
oil and natural gas pipelines, LNG liquefaction, transportation operations as well as downstream and other activities are excluded.
bCosts of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
cIncludes exploration and appraisal drilling expenditures and pre development studies, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are
charged to income as incurred.
dThe amounts shown reflect bp’s share of equity-accounted entities’ costs incurred, and not the costs incurred by bp in acquiring an interest in equity-accounted entities.
ePresented net of sales tax.
f
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Filing: 20-F - BP PLC (BP,BPAQF,BPPFF)
Accession Number: 0000313807-26-000006
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