BP
BP
#186
Rank
HK$890.36 B
Marketcap
HK$347.57
Share price
1.13%
Change (1 day)
36.62%
Change (1 year)

BP p.l.c., formerly British Petroleum, is an international British petroleum company headquartered in London. Worldwide, BP had consolidated sales of $396 billion in 2012 and employed 83,900 people. The company has proven reserves of 17.0 billion barrels of oil equivalent worldwide. The company owns around 20,700 petrol stations and serves 13 million customers every day. Due to an oil spill - triggered on April 20, 2010 by the BP-operated Deepwater Horizon drilling platform in the Gulf of Mexico - the company was sentenced in 2015 by the US environmental agency USEPA to pay a record fine of $20.8 billion. A 2019 survey found that BP, with an emissions of 34.02 billion tonnes of CO2 equivalent since 1965, was the world's sixth-highest in that period.

With sales of $251.9 billion and a profit of $4.3 billion, BP ranks 36th among the world's largest companies according to Forbes Global 2000 (as of 2017). BP had a market cap of approximately $152.6 billion in early 2018.

BP - 20-F annual report 2025


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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)

1 St James’s Square, London SW1Y 4PD
United Kingdom
(Address of principal executive offices)

Kate Thomson
BP p.l.c.
1 St James’s Square, London SW1Y 4PD
United Kingdom
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 classTrading Symbol(s)Name of each exchange on which registered
American Depositary SharesBPNew York Stock Exchange
Ordinary Shares of 25c eachNew York Stock Exchange*
3.017% Guaranteed Notes due 2027BP/27DNew York Stock Exchange
3.279% Guaranteed Notes due 2027BP/27BNew York Stock Exchange
3.543% Guaranteed Notes due 2027BP/27ENew York Stock Exchange
3.588% Guaranteed Notes due 2027BP/27A
BP/27C
New York Stock Exchange
5.017% Guaranteed Notes due 2027
BP/27
New York Stock Exchange
3.723% Guaranteed Notes due 2028BP/28New York Stock Exchange
3.937% Guaranteed Notes due 2028BP/28ANew York Stock Exchange
4.234% Guaranteed Notes due 2028BP/28BNew York Stock Exchange
4.868% Guaranteed Notes due 2029BP/29CNew York Stock Exchange
4.970% Guaranteed Notes due 2029
BP/29A
New York Stock Exchange
4.699% Guaranteed Notes due 2029BP/29New York Stock Exchange
1.749% Guaranteed Notes due 2030BP/30ANew York Stock Exchange
3.633% Guaranteed Notes due 2030BP/30New York Stock Exchange
2.721% Guaranteed Notes due 2032BP/32ANew York Stock Exchange
4.812% Guaranteed Notes due 2033BP/33New York Stock Exchange
4.893% Guaranteed Notes due 2033BP/33ANew York Stock Exchange
4.989% Guaranteed Notes due 2034BP/34New York Stock Exchange
5.227% Guaranteed Notes due 2034
BP/34A
New York Stock Exchange
3.060% Guaranteed Notes due 2041BP/41New York Stock Exchange
2.772% Guaranteed Notes due 2050BP/50BNew York Stock Exchange
3.000% Guaranteed Notes due 2050BP/50ANew York Stock Exchange
3.067% Guaranteed Notes due 2050BP/50New York Stock Exchange
2.939% Guaranteed Notes due 2051BP/51New York Stock Exchange
3.001% Guaranteed Notes due 2052BP/52New York Stock Exchange
3.379% Guaranteed Notes due 2061BP/61New York Stock Exchange
4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset NotesBP/P2New York Stock Exchange
6.125% Perpetual Subordinated Fixed Rate Reset NotesBP/P4New York Stock Exchange
6.450% Perpetual Subordinated Fixed Rate Reset NotesBP/P3New York Stock Exchange
 
*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 each16,486,312,994 
Cumulative First Preference Shares of £1 each7,232,838 
Cumulative Second Preference Shares of £1 each5,473,414 
 



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):

Large accelerated filer       Accelerated filer      Non-accelerated filer   Emerging growth company

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  
    
International Financial Reporting Standards as issued
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  

FrontCoverV7.jpg
 
bp Annual Report
and Form 20-F 2025
InsideFrontCoverV14.jpg
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
ReadMoreArrowBPGreen.gif
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.
49789_bp_AR25_Contents_v4.jpg
bp Annual Report and Form 20-F 2025
1
NavigtionTabCornerV1.jpg
Strategic report
Strategic report
About bp
Chair’s letter
Interim chief executive officer’s letter
The operating environment
Energy outlook
Our strategy
Our strategy in action
Consistency with the Paris goals
Our business model
Key performance indicators
Our financial frame
Our investment process
Group performance
Gas & low carbon energy
Oil production & operations
Customers & products
Other businesses & corporate
Sustainability
Climate-related financial disclosures (TCFD)
Our approach to sustainability
Risk management and internal control
Principal risks and uncertainties (Risk factors)
How we manage principal risks and uncertainties
Compliance information
Non-financial and sustainability information statement
Section 172 statement
Corporate governance
Board of directors
Leadership team
Governance framework
Board activities
Our stakeholders
Key decisions
Safety and sustainability committee
Audit committee
People, culture and governance committee
Remuneration committee
Directors’ remuneration report
Other disclosures
Financial statements
Consolidated financial statements of the bp group
Notes on the financial statements
Supplementary information on oil and natural gas (unaudited)
Additional disclosures
Shareholder information
Glossary
Non-IFRS measure reconciliations
Signatures
Cross-reference to Form 20-F
Information about this report
Exhibits
Navigating this report
Read more on another page of this report
ReadMoreArrowBPGreen.gif
Read more online
ReadMoreOnlineBPGreen.gif
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
ReadMoreOnlineBPGreen.gif
Online reporting centre
All our bp corporate reports, including
the bp Sustainability Report and the
bp Energy Outlook.
bp.com/reportingcentre
ReadMoreOnlineBPGreen.gif
AboutBPPage1V4.jpg
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
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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
ReadMoreArrowBPGreen.gif
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.
AboutBPPage2V7.jpg
bp Annual Report and Form 20-F 2025
3
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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
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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
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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
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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
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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
ChairLetterV5.jpg
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.
AlbertManifold_SigBLACK.jpg
Albert Manifold
Chair
6 March 2026
bp Annual Report and Form 20-F 2025
5
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Strategic report
Interim chief executive officer’s letter
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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.
49789_bp_CarolHowleSig.jpg
Carol Howle
Interim chief executive officer
6 March 2026
WarmGrey2-50-TopRoundCorner.gif
WarmGrey2-50-TopRoundCorner.gif
Nearest IFRS-equivalent
measures
$0.1bn
profit for 2025 attributable to bp
shareholdersa
$58.0bn
finance debt at the end of 2025e
WarmGrey2-50-BottomRoundCorner.gif
WarmGrey2-50-BottomRoundCorner.gif
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
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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.
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Two scenarios to explore the energy transition
Carbon emissions Gt CO2ea
Current Trajectory 
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Below 2° 
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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
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a  Carbon emissions include CO2 emissions from energy use, industrial processes, natural gas flaring and methane
emissions from energy production.
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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
14
and include a combination of econometric
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modelling, adoption curves and consumer
choice modelling.
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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.
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Growing
upstream
Focusing
downstream
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Disciplined investment in transition
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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.
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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
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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.
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bp Annual Report and Form 20-F 2025
9
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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
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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
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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.
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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
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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
How bp evaluates each new material capex
investment« for consistency with the
Paris goals and other outcomes relevant to
bp strategy.
Our investment process
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
Sustainability: net zero aims and
targets
See ‘TCFD Metrics & Targets’ for an
overview
Anticipated levels of investment in:
(i) Oil and gas resources and reserves.
(ii) Other energy sources and technologies.
Our strategy
Financial frame: disciplined
investment allocation
Transition business« investment
bp’s targets to promote operational
GHG reductions.
Sustainability: net zero« aims
Estimated carbon intensity of bp’s energy
products and progress over time.
Sustainability: net zero sales aim«
Any linkage between above targets and
executive pay remuneration.
Directors’ remuneration report
2025 annual bonus outcome
2026 remuneration policy
BusinessModelPage12V3.jpg
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
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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
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bp Annual Report and Form 20-F 2025
13
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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
52
  ADS basis      Ordinary share basis
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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
5497558139229
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
6047313953489
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.
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Directors’ remuneration report, page 91
bp Annual Report and Form 20-F 2025
15
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Strategic report
Upstream« plant reliability (%)
2025
96.1
2024
95.2
2023
95.0
2022
96.0
2021
94.0
6047313953517
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
76
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
112
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
6047313953371
  Tier 1 process      Tier 2 process
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    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
6047313953265
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
25
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
37
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
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Strategic report
GHG emissionsabcde
operational control (MtCO2e) l TCFD
2025
34.3
2024
33.6
2023
32.1
2022
31.9
2021
35.6
6047313953223
  Scope 1 (direct)    Scope 2 (indirect)
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    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
6047313953241
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.
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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
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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.
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bp Annual Report and Form 20-F 2025
19
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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.
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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.
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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.
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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
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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.
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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.
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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.
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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).
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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.
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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.
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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
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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.
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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
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13
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.
1
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.
GroupPeformanceCFOV4.jpg
BPGreenTopRoundCorner.gif
BPGreenTopRoundCorner.gif
$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)
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BPGreenBottomRoundCorner.gif
bp Annual Report and Form 20-F 2025
25
NavigtionTabCornerV1.jpg
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
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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
NavigtionTabCornerV1.jpg
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.
49789_bp_AR25_LNGMilestonesGTAv2.jpg
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 
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BPDarkGreenBottomRoundCorner.gif
49789_bp_AR25_TriumphsTrinidadTobagoMentoV1.jpg
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
BPGreenBottomRoundCorner.gif
BPGreenBottomRoundCorner.gif
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.
49789_bp_CaseStudyImage090225.jpg
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
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bp Annual Report and Form 20-F 2025
31
NavigtionTabCornerV1.jpg
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.
49789_bp_AR25_BumerangueDiscoveryV2.jpg
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
BPGreenBottomRoundCorner.gif
BPGreenBottomRoundCorner.gif
BPDarkGreenTopRoundCorner.gif
BPDarkGreenTopRoundCorner.gif
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.
BPDarkGreenBottomRoundCorner.gif
BPDarkGreenBottomRoundCorner.gif
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.
49789_bp_AR25_PRINT_PermianBasinProgressv1.jpg
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 $20 billion
by 2027.
Image: bpx energy midstream
facility, US
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bp Annual Report and Form 20-F 2025
33
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Strategic report
Estimated net proved reserves and productiona (net of royalties)
2025
2024
2023
Estimated net proved reserves (net of royalties)
Crude oilb (mmb)
2,908
3,112
3,193
Natural gas liquids (mmb)
439
472
426
Total liquids
3,346
3,584
3,618
Natural gas (bcf)
9,550
7,821
8,836
Total hydrocarbons« (mmboe)
4,993
4,932
5,142
Of which equity-accounted entitiesc:
Liquids (mmb)
885
917
1,001
Natural gas (bcf)
2,410
2,467
2,527
Total hydrocarbons (mmboe)
1,301
1,342
1,437
Production (net of royalties)
Crude oilb (mb/d)
993
953
910
Natural gas liquids (mb/d)
121
117
100
Total liquids (mb/d)
1,114
1,070
1,010
Natural gas (mmcf/d)
2,391
2,318
2,165
Total hydrocarbons (mboe/d)
1,527
1,470
1,383
Of which equity-accounted entitiesd:
Liquids (mb/d)
272
272
269
Natural gas (mmcf/d)
438
431
432
Total hydrocarbons (mboe/d)
347
346
343
Average realizations«e
Liquids ($/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.
49789_bp_AR25_NorthSeaStartupV2.jpg
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
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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.
CaseStudy_XConvenienceV2.jpg
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
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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.
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bp Annual Report and Form 20-F 2025
35
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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.
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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.
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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
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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.
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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.
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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.
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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.
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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
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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.
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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
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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
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TCFD Recommendation:
Disclose the organization’s governance around
climate-related issues and opportunities.
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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.
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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.
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The board: pages 73-75
Safety and sustainability
committee: pages 82-83
Audit committee: pages 84-88
Remuneration committee:
pages 91-117
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bp Annual Report and Form 20-F 2025
43
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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.
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Acquired businesses
Integration plans are developed to
transition acquired businesses into bp’s
system of internal control, over an
appropriate timeframe.
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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
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TCFD Recommendation:
Disclose how the organization identifies,
assesses and manages climate-related risks.
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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
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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
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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.
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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.
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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.
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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
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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
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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
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« 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.
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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
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bp Annual Report and Form 20-F 2025
53
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Strategic report
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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.
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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
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TCFD Recommendation:
Disclose the metrics and targets used to
assess and manage relevant climate-related
risks and opportunities where such information
is material.
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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.
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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.
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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.
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People, culture and governance
committee report, page 89
bp Annual Report and Form 20-F 2025
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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%).
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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.
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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.
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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%).
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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.
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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.
I2025 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
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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).
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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.
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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.
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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.
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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.
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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.
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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.
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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
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Acquired businesses
Integration plans are developed to
transition acquired businesses into
bp’s system of internal control,
over an appropriate timeframe.
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bp governance framework, page 77, board activities, page 78, and committee reports, pages 82-91.
bp Annual Report and Form 20-F 2025
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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.
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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
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« 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.
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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.
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Energy markets, page 6
Liquidity and capital resources, page 338
Liquidity, financial capacity and
financial, including credit, exposure,
page 68
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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Climate-related financial disclosures,
page 41 and Financial statements –
Note 1 and Note 33
bp Annual Report and Form 20-F 2025
69
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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’.
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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.
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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.
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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
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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.
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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.
CorporateGovernanceDividerV7-LEFT.jpg
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
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Read Albert’s letter on page 4
Board of directors
Leadership team
Governance framework
Board activities
Our stakeholders
Key decisions
Safety and sustainability committee
Audit committee
People, culture and governance committee
Remuneration committee
Directors’ remuneration report
Other disclosures
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
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bp Annual Report and Form 20-F 2025
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Corporate governance
Board of directors
As at 6 March 2026
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BoD_CarolHowleV2.jpg
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.
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Key
BoDKeyExecDirV1.jpg
Executive director
BoDKeyNonExecDirV1.jpg
Non-executive director
BoDKeyLeadershipV1.jpg
Leadership team member
Committee members key
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Committee chair
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Safety and sustainability committee
BoDKeyAuditCommV1.jpg
Audit committee
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People, culture and governance committee
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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
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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.
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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
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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.
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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.
BoD_SatisPaiV3.jpg
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.
BoD_DaveHagerV5.jpg
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
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Corporate governance
BoD_KarenRichardsonV4.jpg
BoD_SimonHenryV5.jpg
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.
BoDBenMathewsV3.jpg
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
Leadership_GordonBirrellV3.jpg
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.
Leadership_EmekaEmemboiuV3.jpg
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.
Leadership_CarolHowiesV5.jpg
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.
Leaderhip_EmmaDelaneyV3.jpg
Leadership_KerryDryburghV3.jpg
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.
Leadership_WilliamLinV3.jpg
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.
Leadership_MikeSossoV3.jpg
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.
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bp Annual Report and Form 20-F 2025
77
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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.
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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).
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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.
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bp Annual Report and Form 20-F 2025
79
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Corporate governance
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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.
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Image: Members of the board at our Canary Wharf office, London, UK
Key: TCFD Recommendations and Recommended Disclosures
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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. 
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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.
OurStakeholders_WhitingV2.jpg
Image: Members of the board during their tour of
Whiting refinery, US
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Stakeholders key
ò  Investors and shareholders
ò  Customers
ò  Workforce
ò  Governments and regulators
ò  Partners and suppliers
ò  Society
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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.
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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
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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
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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.
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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
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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
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82
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Safety and sustainability committee
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“The committee
provided disciplined
oversight of safety,
security and
sustainability across
the business.”
Melody Meyer
Safety and sustainability
committee chair
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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
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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.
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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
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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
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Audit committee
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“The committee had
particular focus on
advancing digital
transformation
initiatives.”
Tushar Morzaria
Audit committee chair
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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
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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.
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bp Annual Report and Form 20-F 2025
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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
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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
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TCFD Information that supports TCFD Recommendations and Recommended Disclosures in relation to governance (see pages 41-44)
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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
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Corporate governance
Examples of how key accounting judgements and estimates were considered and addressed,
and how relevant accounting policies have been applied
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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.
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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
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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.
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bp Annual Report and Form 20-F 2025
89
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Corporate governance
People, culture and governance committee
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“2025 has been a
busy year for the
committee, with a
strong focus on board
succession.”
Albert Manifold
People, culture and governance
committee chair
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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
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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.
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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
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Corporate governance
Directors’ remuneration report
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“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
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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.
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Contents
Remuneration at a glance
Engaging with our workforce
Executive directors’ pay for 2025
2025 annual bonus outcome
2023-25 performance share plan outcome
Policy implementation for 2026
Stewardship and executive director interests
Chair and non-executive director interests
2026 directors’ remuneration policy
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TCFD Information that supports TCFD Recommendations and Recommended Disclosures in relation to governance (see pages 41-44)
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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
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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
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Single figure
Chief executive officer
(outgoing)
35% Fixed
65% Variable pay
Single figure
Chief financial officer
36% Fixed
64% Variable pay
2. Cash allowance
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in lieu of pension
3. Annual bonus
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£5.3m
£3.0m
4. Performance shares
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30786325578241
30786325578253
Pay outcomes in 2025
Annual bonus
(2025 ACB)
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Performance shares
(2023-25 EDIP)
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81.5% of
maximum
formulaic outcome
23.3% of
maximum
formulaic outcome
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79.5% of
maximum
formulaic outcome
actual outcome
after exercise
of discretion
Safety and sustainability 
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Operations  Financials
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Strategic progress  Sustainability 
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rTSR  Financials
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33
45
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
DRR_SingleLozenge_ShareOwnership.gif
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   
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bp Annual Report and Form 20-F 2025
95
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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.
DRR_RemPolicyArrow1.gif
1-year
performance period
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3-year
deferral period
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3-year
performance period
3-year
holding period
DRR_RemPolicyArrow5.gif
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.
DRR_SIngleLozenge_AnnualBonus.gif
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
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Cumulative reduction % in operated carbon emissions (20%)
ò
Adjusted free cash flow CAGR« (25%)
ò
ò
ROACE« (25%)
ò
ò
Relative TSR (30%)
ò
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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.
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Element of remuneration
All employees
Executive directors
WorkforceSalaryV2.gif
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.
WorkforcePensionsAndBenefitsV1.gif
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.
WorkforceAnnualBonusV1.gif
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.
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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.
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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.
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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
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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
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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)
Carol
Howleb
thousand
2025
Murray
Auchinclossc
thousand
2025
Kate
Thomson
thousand
2025
Murray
Auchincloss
thousand
2024
Kate
Thomson
thousand
2024
DRR_SIngleLozenge_SalaryV3.gif
£57
£1,434
£845
£1,450
£731
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£2
£138
£82
£132
£67
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£11
£287
£169
£290
£146
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£83
£2,594
£1,545
£734
£370
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£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.
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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
26
6047313953092
6047313953239
6047313953280
110
86
98
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.
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Framework on fatalities
  1. Operations (15%)
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  2. Safety and sustainability (30%)
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  3. Financial (55%)
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65
Safety and sustainability committee
Influence
Foreseen
Nature
of deficiency
Remuneration committee
Collective
responsibility
Meaningful
adjustment
Judgement
within a frame
Treatment of new assets
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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.
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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
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102
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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.
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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%
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61
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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:
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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. 
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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.
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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«.
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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.
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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.
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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
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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)
DRR_SIngleLozenge_PolicyImp-PenAndBenV2.gif
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.
DRR_SIngleLozenge_PolicyImp-AnnBon.gif
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
DRR_SIngleLozenge_PolicyImp-PerfShare.gif
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.
DRR_SIngleLozenge_PolicyImp-ShareReq.gif
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.
DRR_SIngleLozenge_PolicyImp-MalClaw.gif
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.
DRR_SIngleLozenge_PolicyImp-ComFlex.gif
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.
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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.
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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
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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.
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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%
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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.
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rTSR
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Financials
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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
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Rank
Percentile
Vesting
1
100th %ile
100%
3
50th %ile
25%
Below median
0%
13
25
37
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
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rTSR
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Financials
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ESG
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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
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85
73
61
49
Measures for 2024-26 performance shares
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rTSR
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Financials
ArrowRightWarmGrey4.gif
ESG
ArrowRightWarmGrey4.gif
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
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109
97
121
133
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
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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
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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
ChartKeyLozengeGreen.jpg
ChartKeyLozengesWarmGrey3.gif
a  Organic capital expenditure«.
1
13
37
25
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
DRR_SIngleLozenge_PolicyImp-SalaryBenV2.gif
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.
DRR_SIngleLozenge_PolicyImp-RetireBen.gif
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
DRR_SIngleLozenge_PolicyImp-AnnBon.gif
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.
DRR_SIngleLozenge_PolicyImp-PerfShare.gif
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.
DRR_SIngleLozenge_PolicyImp-ShareReq.gif
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?
DRR_SIngleLozenge_PolicyImp-AnnBon.gif
Bonus aligned with
company performance
ArrowRightWarmGrey4.gif
<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
DRR_SIngleLozenge_PolicyImp-PerfShare.gif
Share award for meeting
three-year targets
ArrowRightWarmGrey4.gif
Six-years; three-year performance period
+ three-year holding period
DRR_SIngleLozenge_PolicyImp-ShareOwn.gif
Long-term shareholding
ArrowRightWarmGrey4.gif
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
1
  Fixed pay    Annual bonus    Performance shares  * 50% share price increase
ChartKeyLozengeAmber2.gif
ChartKeyLozengeGreen.gif
ChartKeyLozengeLightGreen.gif
Kate Thomson
Min
100%
£1.2m
Mid
28%
24%
48%
£4.2m
Max
16%
28%
56%
£7.2m
SPI*
13%
22%
66%
£9.2m
13
  Fixed pay    Annual bonus    Performance shares  * 50% share price increase
ChartKeyLozengeAmber2.gif
ChartKeyLozengeGreen.gif
ChartKeyLozengeLightGreen.gif
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).
DRR_SIngleLozenge_PolicyImp-SalaryV2.gif
CEO (O’Neill)
£1,600,000
Meg’s salary, upon appointment
CFO (Thomson)
£894,000
Kate’s salary, effective from the 2026 AGM
DRR_SIngleLozenge_PolicyImp-PenAndBenV2.gif
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
DRR_SIngleLozenge_PolicyImp-AnnBon.gif
(including cash and deferred elements)
Threshold not met
50% of maximum
100% of maximum
Nil
112.5% of salary
225% of salary
DRR_SIngleLozenge_PolicyImp-PerfShare.gif
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
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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
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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
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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
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Financial statements
Consolidated financial statements of the bp group
Independent auditor's reports (PCAOB ID 1147)
149
Group statement of changes in equity
Group income statement
Group balance sheet
Group statement of comprehensive income
Group cash flow statement
Notes on financial statements
1.
Significant accounting policies
22.
Trade and other payables
2.
Non-current assets held for sale
23.
Provisions
3.
Business combinations
24.
Pensions and other post-employment
benefits
4.
Disposals and impairment
5.
Segmental analysis
25.
Cash and cash equivalents
6.
Sales and other operating revenues
26.
Finance debt
7.
Income statement analysis
27.
Capital disclosures and net debt
8.
Exploration for and evaluation of oil and
natural gas resources
28.
Leases
29.
Financial instruments and financial risk
factors
9.
Taxation
10.
Dividends
30.
Derivative financial instruments
11.
Earnings per share
31.
Called-up share capital
12.
Property, plant and equipment
32.
Capital and reserves
13.
Capital commitments
33.
Contingent liabilities and legal
proceedings
14.
Goodwill
34.
Remuneration of senior management
and non-executive directors
15.
Intangible assets
16.
Investments in joint ventures
35.
Employee costs and numbers
17.
Investments in associates
36.
Auditor's remuneration
18.
Other investments
37.
Subsidiaries, joint arrangements and
associates
19.
Inventories
20.
Trade and other receivables
21.
Valuation and qualifying accounts
Supplementary information on oil and natural gas (unaudited)
Oil and natural gas exploration and production
activities
Standardized measure of discounted future net
cash flows and changes therein relating to
proved oil and gas reserves
Movements in estimated net proved reserves
Operational and statistical information
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
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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
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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.
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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
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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.
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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
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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.
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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
London, United Kingdom
6 March 2026
bp Annual Report and Form 20-F 2025
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Financial statements
Group income statement
For the year ended 31 December
$ million
Note
2025
2024
2023
Sales and other operating revenues
6
189,335
189,185
210,130
Earnings from joint ventures – after interest and tax
16
(300)
909
67
Earnings from associates – after interest and tax
17
918
1,084
831
Interest and other income
7
1,609
2,773
1,635
Gains on sale of businesses and fixed assets
4
987
678
369
Total revenues and other income
192,549
194,629
213,032
Purchases
19
110,640
113,941
119,307
Production and manufacturing expenses
25,646
26,584
25,044
Production and similar taxes
5
1,698
1,799
1,779
Depreciation, depletion and amortization
5
17,822
16,622
15,928
Net impairment and losses on sale of businesses and fixed assets
4
6,037
6,995
5,857
Exploration expense
8
570
974
997
Distribution and administration expenses
17,494
16,417
16,772
Profit (loss) before interest and taxation
12,642
11,297
27,348
Finance costs
7
5,106
4,683
3,840
Net finance (income) expense relating to pensions and other post-employment benefits
24
(210)
(168)
(241)
Profit (loss) before taxation
7,746
6,782
23,749
Taxation
9
6,451
5,553
7,869
Profit (loss) for the year
1,295
1,229
15,880
Attributable to
  bp shareholders
55
381
15,239
  Non-controlling interests
1,240
848
641
1,295
1,229
15,880
Earnings per share
Profit (loss) for the year attributable to bp shareholders
Per ordinary share (cents)
  Basic
11
0.35
2.38
87.78
  Diluted
11
0.34
2.32
85.85
Per ADS (dollars)
Basic
11
0.02
0.14
5.27
Diluted
11
0.02
0.14
5.15
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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
1,295
1,229
15,880
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differencesa
1,863
(1,292)
585
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on
sale of businesses and fixed assetsa
41
1,004
(2)
Cash flow hedges marked to market
30
287
155
1,065
Cash flow hedges reclassified to the income statement
30
(127)
(686)
(428)
Costs of hedging marked to market
30
27
(2)
(67)
Costs of hedging reclassified to the income statement
30
34
(2)
(11)
Share of items relating to equity-accounted entities, net of tax
16, 17
(4)
(12)
(192)
Income tax relating to items that may be reclassified
9
(22)
48
(10)
2,099
(787)
940
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-employment benefit liability or asset
24
(221)
(360)
(2,262)
Remeasurements of equity investments
(6)
(47)
51
Cash flow hedges that will subsequently be transferred to the balance sheet
30
5
(1)
15
Income tax relating to items that will not be reclassifieda
9
55
734
745
(167)
326
(1,451)
Other comprehensive income
1,932
(461)
(511)
Total comprehensive income
3,227
768
15,369
Attributable to
bp shareholders
1,872
7
14,702
Non-controlling interests
1,355
761
667
3,227
768
15,369
aSee Note 32 for further information.
bp Annual Report and Form 20-F 2025
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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
48,229
(9,030)
(2,196)
(288)
22,531
59,246
16,649
2,423
78,318
Profit for the year
55
55
799
441
1,295
Other comprehensive income
1,804
183
(170)
1,817
115
1,932
Total comprehensive income
1,804
183
(115)
1,872
799
556
3,227
Dividendsb
(5,087)
(5,087)
(524)
(5,611)
Cash flow hedges transferred to the balance
sheet, net of tax
(6)
(6)
(6)
Repurchase of ordinary share capital
(3,558)
(454)
(4,012)
(4,012)
Share-based payments, net of tax
35
3,917
(2,840)
1,112
1,112
Share of equity-accounted entities’ changes
in equity, net of tax
1
1
1
Issue of perpetual hybrid bonds
500
500
Redemption of perpetual hybrid bonds, net
    of tax
(1,200)
(1,200)
Payments on perpetual hybrid bonds
(9)
(9)
(793)
(802)
Transactions involving non-controlling
interests, net of tax
(65)
(65)
2,538
2,473
At 31 December 2025
48,264
(8,671)
(401)
(111)
13,971
53,052
15,955
4,993
74,000
At 1 January 2024
48,013
(11,323)
(1,920)
174
35,339
70,283
13,566
1,644
85,493
Profit for the year
381
381
641
207
1,229
Other comprehensive income
(276)
(452)
354
(374)
(87)
(461)
Total comprehensive income
(276)
(452)
735
7
641
120
768
Dividendsb
(5,018)
(5,018)
(375)
(5,393)
Cash flow hedges transferred to the balance
sheet, net of tax
(10)
(10)
(10)
Repurchase of ordinary share capital
(7,302)
(7,302)
(7,302)
Share-based payments, net of tax
216
2,293
(1,426)
1,083
1,083
Issue of perpetual hybrid bonds
(22)
(22)
4,352
4,330
Redemption of perpetual hybrid bonds, net
    of tax
9
9
(1,300)
(1,291)
Payments on perpetual hybrid bonds
(610)
(610)
Transactions involving non-controlling
interests, net of tax
216
216
1,034
1,250
At 31 December 2024
48,229
(9,030)
(2,196)
(288)
22,531
59,246
16,649
2,423
78,318
At 1 January 2023
47,873
(12,153)
(2,643)
(256)
34,732
67,553
13,390
2,047
82,990
Profit for the year
15,239
15,239
586
55
15,880
Other comprehensive income
728
431
(1,696)
(537)
26
(511)
Total comprehensive income
728
431
13,543
14,702
586
81
15,369
Dividendsb
(4,831)
(4,831)
(403)
(5,234)
Cash flow hedges transferred to the balance
sheet, net of tax
(1)
(1)
(1)
Repurchase of ordinary share capital
(8,167)
(8,167)
(8,167)
Share-based payments, net of tax
140
830
(301)
669
669
Share of equity-accounted entities’ changes
in equity, net of tax
1
1
1
Issue of perpetual hybrid bonds
(1)
(1)
176
175
Payments on perpetual hybrid bonds
(5)
(5)
(586)
(591)
Transactions involving non-controlling
interests, net of tax
363
363
(81)
282
At 31 December 2023
48,013
(11,323)
(1,920)
174
35,339
70,283
13,566
1,644
85,493
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
98,633
100,238
Goodwill
14
10,300
14,888
Intangible assets
15
8,197
9,646
Investments in joint ventures
16
13,400
12,291
Investments in associates
17
7,325
7,741
Other investments
18
857
1,292
Fixed assets
138,712
146,096
Loans
1,991
1,961
Trade and other receivables
20
2,376
1,815
Derivative financial instruments
30
20,957
16,114
Prepayments
608
548
Deferred tax assets
9
4,325
5,403
Defined benefit pension plan surpluses
24
7,771
7,457
176,740
179,394
Current assets
Loans
457
223
Inventories
19
22,499
23,232
Trade and other receivables
20
26,014
27,127
Derivative financial instruments
30
5,180
5,112
Prepayments
3,422
2,594
Current tax receivable
1,153
1,096
Other investments
18
158
165
Cash and cash equivalents
25
36,556
39,204
95,439
98,753
Assets classified as held for sale
2
6,347
4,081
101,786
102,834
Total assets
278,526
282,228
Current liabilities
Trade and other payables
22
56,843
58,411
Derivative financial instruments
30
4,413
4,347
Accruals
5,572
6,071
Lease liabilities
28
2,832
2,660
Finance debt
26
3,356
4,474
Current tax payable
1,262
1,573
Provisions
23
4,709
3,600
78,987
81,136
Liabilities directly associated with assets classified as held for sale
2
1,594
1,105
80,581
82,241
Non-current liabilities
Other payables
22
7,975
9,409
Derivative financial instruments
30
19,667
18,532
Accruals
1,834
1,326
Lease liabilities
28
11,739
9,340
Finance debt
26
54,602
55,073
Deferred tax liabilities
9
7,642
8,428
Provisions
23
15,670
14,688
Defined benefit pension plan and other post-employment benefit plan deficits
24
4,816
4,873
123,945
121,669
Total liabilities
204,526
203,910
Net assets
74,000
78,318
Equity
bp shareholders’ equity
32
53,052
59,246
Non-controlling interests
32
20,948
19,072
Total equity
32
74,000
78,318
Albert Manifold Chair
Carol Howle Interim Chief executive officer
6 March 2026
bp Annual Report and Form 20-F 2025
159
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Financial statements
Group cash flow statement
For the year ended 31 December
$ million
Note
2025
2024
2023
Operating activities
Profit (loss) before taxation
7,746
6,782
23,749
Adjustments to reconcile profit before taxation to net cash provided by operating activities
Exploration expenditure written off
8
343
767
746
Depreciation, depletion and amortization
5
17,822
16,622
15,928
Impairment and (gain) loss on sale of businesses and fixed assets
4
5,050
6,317
5,488
Earnings from joint ventures and associates
(618)
(1,993)
(898)
Dividends received from joint ventures and associates
2,111
2,023
2,092
Remeasurement of joint ventures
3
(917)
Interest receivable
(1,352)
(1,512)
(1,265)
Interest received
1,223
1,450
1,119
Finance costs
7
5,106
4,683
3,840
Interest paid
(3,538)
(2,811)
(2,950)
Net finance expense relating to pensions and other post-employment benefits
24
(210)
(168)
(241)
Share-based payments
1,077
1,174
616
Net operating charge for pensions and other post-employment benefits, less contributions
and benefit payments for unfunded plans
24
(152)
(182)
(193)
Net charge for provisions, less payments
1,294
(152)
(2,481)
(Increase) decrease in inventories
1,622
808
5,634
(Increase) decrease in other current and non-current assets
(4,286)
3,355
4,620
Increase (decrease) in other current and non-current liabilities
(2,156)
(188)
(13,592)
Income taxes paid
(6,589)
(8,761)
(10,173)
Net cash provided by operating activities
24,493
27,297
32,039
Investing activities
Expenditure on property, plant and equipment, intangible and other assets
(13,221)
(15,297)
(14,285)
Acquisitions, net of cash acquired
3
(935)
53
(799)
Investment in joint ventures
(267)
(850)
(1,039)
Investment in associates
(110)
(143)
(130)
Total cash capital expenditure
(14,533)
(16,237)
(16,253)
Proceeds from disposals of fixed assets
4
1,142
328
133
Proceeds from disposals of businesses, net of cash disposed
4
1,714
2,578
1,193
Proceeds from loan repayments
173
81
55
Net cash used in investing activities
(11,504)
(13,250)
(14,872)
Financing activities
Repurchase of shares
(4,486)
(7,127)
(7,918)
Lease liability payments
(3,091)
(2,833)
(2,560)
Proceeds from long-term financing
2,724
10,656
7,568
Repayments of long-term financing
(5,695)
(2,970)
(3,902)
Net increase (decrease) in short-term debt
(343)
(2,966)
(861)
Issue of perpetual hybrid bonds
500
4,330
175
Redemption of perpetual hybrid bonds
32
(1,200)
(1,288)
Payments relating to perpetual hybrid bonds
(1,196)
(1,053)
(1,008)
Payments relating to transactions involving non-controlling interests (other)
(2)
(21)
(187)
Receipts relating to transactions involving non-controlling interests (other)
2,474
1,353
546
Dividends paid
bp shareholders
10
(5,059)
(5,003)
(4,809)
Non-controlling interests
(506)
(375)
(403)
Net cash provided by (used in) financing activities
(15,880)
(7,297)
(13,359)
Currency translation differences relating to cash and cash equivalents
246
(511)
27
Increase (decrease) in cash and cash equivalents
(2,645)
6,239
3,835
Cash and cash equivalents at beginning of year
39,269
33,030
29,195
Cash and cash equivalents at end of yeara
36,624
39,269
33,030
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
Authorization of financial statements and statement of compliance with International Financial Reporting Standards
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.
Material accounting policy information: use of judgements, estimates and assumptions
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 $60 per barrel in 2050 continuing to reflect the assumption that the energy system decarbonises but at a slower rate. The price
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 $4.50 per mmBtu up to 2050. The revised assumptions for Brent
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 £65/tCO2e in 2026
gradually increasing to £243/tCO2e in 2050.
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.
Basis of consolidation
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
related to these hybrid bonds whether or not such distribution has been deferred.
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
Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities assumed are recognized at
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
recognized is the excess of the consideration transferred over the group's share of the net fair value of the identifiable assets and liabilities.
Interests in joint arrangements
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 15.9% of the voting shares at 31 December 2025. bp’s senior vice president North Sea, Doris Reiter, was appointed a member of the Aker
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 zero when determining the measurement of the interest in Rosneft and the other businesses with Rosneft within Russia as at 31
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.
This includes unrealized gains arising on contribution of a business on formation of an equity-accounted entity.
Segmental reporting
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.
Foreign currency translation
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 held for sale
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
ceased once classified as held for sale.
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
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.
Exploration and appraisal expenditure
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
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.
Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life. The typical useful lives of the group’s other
property, plant and equipment on initial recognition are as follows:
Land improvements
15 to 25 years
Buildings
20 to 50 years
Refineries
20 to 30 years
Pipelines
10 to 50 years
Service stations
15 years
Office equipment
3 to 10 years
Fixtures and fittings
5 to 15 years
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
the period in which the item is derecognized.
bp Annual Report and Form 20-F 2025
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Financial statements
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Impairment of property, plant and equipment, intangible assets, goodwill, and equity-accounted entities
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.
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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 8% (2024 8%) other than for
renewable power assets. Where the CGU is located in a country that was judged to be higher risk, an additional premium of 1% to 3% was reflected
in the post-tax discount rate (2024 1% to 3%). The judgement of classifying a country as higher risk and the applicable premium takes into account
various economic and geopolitical factors. The pre-tax discount rate, other than for renewable power assets, typically ranged from 9% to 18%
(2024 9% to 20%) depending on the risk premium and applicable tax rate in the geographic location of the CGU. For renewable power assets
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 7% was used. For renewable power assets tested on a fair-value basis, primarily offshore wind assets (including those in
equity accounted entities), a post-tax cost of equity-based discount rate range of 8.75% to 9.5% (2024 8.75% to 9.5%) was used.
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 $20,341 million (2024 $17,853 million) where
the headroom, based on the most recent impairment test performed in the year on those assets, was less than or equal to 20% of the carrying
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 $70 per barrel. Medium to long term prices steadily decline to a
higher price of $60 per barrel by 2050 continuing to reflect the assumption that the energy system decarbonizes but at a slower rate. The price
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 $4.50 per mmBtu up to 2050. These price assumptions are derived from the central
case investment appraisal assumptions. A summary of the group’s revised price assumptions for Brent oil and Henry Hub gas, applied in 2025 and
2024, in real 2024 terms, is provided below. The assumptions represent management’s best estimate of future prices at the balance sheet date,
which sit within the range of external scenarios considered as appropriate for the purpose. They are considered by bp to be in line with a range of
transition paths, as collated into the Transition Scenario Catalogue we use in our TCFD assessment, that are considered by source data providers
(such as IEA, UN PRI IPR and NGFS) to be consistent with holding the increase in the global average temperature to well below 2°C above pre-
industrial levels and pursuing efforts to limit the temperature increase to 1.5°C above pre-industrial levels. However, they do not correspond to
any specific Paris-consistent scenario. An inflation rate of 2.0% - 3.0% (2024 2.0%-2.5%) is applied to determine the price assumptions in nominal
terms.
The majority of bp’s reserves and resources that support the carrying value of the group’s existing oil and gas properties are expected to be
produced over the next 12 years.
The recoverability of deferred tax assets is also affected by the group’s oil and natural gas price assumptions as these could impact the estimate
of future taxable profits. See Note 9 for further information.
2025 price assumptions
2026
2030
2040
2050
Brent oil ($/bbl)
70
70
67
60
Henry Hub gas ($/mmBtu)
3.80
4.10
4.50
4.50
2024 price assumptions
2025
2030
2040
2050
Brent oil ($/bbl)
71
71
64
50
Henry Hub gas ($/mmBtu)
4.07
4.04
4.04
4.04
bp Annual Report and Form 20-F 2025
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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 $20-21 billion which is approximately 34% of the associated net book value of property, plant and equipment
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 $1-2 billion which is approximately 2-3% of the associated net book value of property, plant and equipment
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 $0.2 billion higher. If the discount rate was one percentage point lower, the net impairment loss recognized would have been
approximately $0.5 billion lower.
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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 10% would have resulted in an additional impairment charge of $0.5 billion. It is estimated that an
increase in revenue of 10% would have resulted in a reduction to the impairment charge of $0.8 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 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 1% would have resulted in an additional impairment charge to Archaea Energy assets of
$0.3 billion. It is estimated that a decrease in the discount rate of 1% would have resulted in a reduction to the impairment charge of $0.4 billion.
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 $1-2 billion.
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 $10.3 billion on its balance sheet (2024 $14.9 billion), principally relating to the Atlantic Richfield,
Devon Energy, Reliance transactions and its transition businesses. Of this, $7.1 billion relates to goodwill in the oil production & operations
segment and to hydrocarbon CGUs within the gas & low carbon energy segment (2024 $7.2 billion), for which oil and gas price and production
assumptions are key sources of estimation uncertainty. A further $0.9 billion relates to the transition businesses in the gas & low carbon energy
segment (2024 $2.9 billion), for which project development revenues and margins, terminal value growth rate and discount rate are key sources of
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
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Financial statements
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Inventories
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.
Leases
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.
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Financial assets
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
to exchange financial assets or financial liabilities with another entity that are potentially unfavourable are classified as equity.
bp Annual Report and Form 20-F 2025
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1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Financial liabilities
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:
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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
over the term of the hedging relationship.
Fair value measurement
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.
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1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Offsetting of financial assets and liabilities
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 and contingencies
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.
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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 $0.6 billion of decommissioning
provisions recognized as at 31 December 2025 (2024 $0.7 billion) for assets previously sold to third parties where the sale transferred the
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 4.5% (2024 4.5%), which was based on long-dated US government bonds interpolated to reflect the expected weighted average time to
decommissioning. The weighted average period over which decommissioning and environmental costs are generally expected to be incurred is
estimated to be approximately 16 years (2024 17 years) and 7 years (2024 7 years) respectively. Costs at future prices are typically determined by
applying an inflation rate of 1.5% (2024 1.5%) to decommissioning costs and 2% (2024 2%) for all other provisions. A lower rate is typically applied to
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 $5.7 billion (2024 $5.5 billion)
within the next 10 years, $6.0 billion (2024 $6.2 billion) in 10 to 20 years and the remainder of approximately $7.0 billion (2024 $6.7 billion) after 20
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 1.0 percentage point increase in the nominal discount rate applied
could decrease the group’s provision balances by approximately $1.4 billion (2024 $1.5 billion). The pre-tax impact on the group income statement
would be a credit of approximately $0.3 billion (2024 $0.4 billion). This level of change reflects past experience of a reasonable change in rate that
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 $0.7 billion (2024
$0.3 billion). Management currently does not consider a change of greater than two years to be reasonably possible in the next financial year and
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
$1.2 billion (2024 $1.2 billion) and a pre-tax charge of approximately $0.3 billion (2024 $0.4 billion) would be recognized. A one percentage point
increase in the inflation rate applied to upstream decommissioning costs to determine the nominal cash flows could increase the
decommissioning provision by approximately $1.8 billion (2024 $1.7 billion) with a pre-tax charge of approximately $0.4 billion (2024 $0.5 billion).
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.
Employee benefits
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
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Financial statements
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Pensions and other post-employment benefits
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 taxes
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
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
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Financial statements
1. Material accounting policy information, significant judgements, estimates and assumptions – continued
Own equity instruments – treasury shares
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 and other income
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
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.
Updates to material accounting policy information
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
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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.
The total assets and liabilities held for sale at 31 December 2025 and 2024, which are in the gas & low carbon energy and customers & products
segments, are set out in the table below.
$ million
2025
2024
Property, plant and equipment
2,542
1,981
Goodwill
2,817
Intangible assets
165
333
Investments in associates
20
Investments in joint ventures
18
1,182
Other investments
65
Inventories
11
Cash
68
65
Trade and other receivables
292
520
Deferred tax assets
349
Assets classified as held for sale
6,347
4,081
Trade and other payables
(87)
(264)
Lease liabilities
(109)
(58)
Finance debt
(1,143)
(720)
Provisions
(75)
(63)
Deferred tax liabilities
(11)
Defined benefit pension plan and other post-employment benefit plan deficits
(169)
Liabilities directly associated with assets classified as held for sale
(1,594)
(1,105)
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
The following amounts were recognized in the income statement in respect of disposals and impairments.
$ million
2025
2024
2023
Gains on sale of businesses and fixed assets
gas & low carbon energy
258
297
19
oil production & operations
407
144
297
customers & products
317
190
44
other businesses & corporate
5
47
9
987
678
369
$ million
2025
2024
2023
Losses on sale of businesses and fixed assets, and closures
gas & low carbon energy
410
303
9
oil production & operations
110
19
5
customers & products
118
1,457
143
other businesses & corporate
4
27
(1)
642
1,806
156
Impairment losses
gas & low carbon energya
4,146
3,310
2,213
oil production & operations
454
1,155
1,840
customers & productsa
926
1,144
1,614
other businesses & corporate
3
24
80
5,529
5,633
5,747
Impairment reversals
gas & low carbon energy
(108)
(44)
(1)
oil production & operations
(12)
(384)
(26)
customers & products
(14)
(1)
other businesses & corporate
(15)
(19)
(134)
(444)
(46)
Impairment and losses on sale of businesses and fixed assets, and closures
6,037
6,995
5,857
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
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Financial statements
4. Disposals and impairment – continued
Disposals
Disposal proceeds and principal gains and losses on disposals by segment are described below.
$ million
2025
2024
2023
Proceeds from disposals of fixed assets
1,142
328
133
Proceeds from disposals of businesses, net of cash disposed
1,714
2,578
1,193
2,856
2,906
1,326
By business
gas & low carbon energy
1,702
840
536
oil production & operations
272
1,699
333
customers & products
840
291
436
other businesses & corporate
42
76
21
2,856
2,906
1,326
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
3,998
1,775
1,145
Current assets
571
1,985
557
Non-current liabilities
(320)
(548)
(60)
Current liabilities
(213)
(424)
(454)
Total carrying amount of net assets disposed
4,036
2,788
1,188
Recycling of foreign exchange on disposal
41
943
Costs on disposal
54
123
57
4,131
3,854
1,245
Gains (losses) on sale of businesses
358
(888)
158
Total consideration
4,489
2,966
1,403
Non-cash consideration
(3,133)
(1,003)
(51)
Consideration received (receivable)
358
615
(159)
Proceeds from the sale of businesses, net of cash disposeda
1,714
2,578
1,193
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
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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 accounting policies of the operating segments are the same as the group’s accounting policies described in Note 1. However, 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 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
40,333
24,527
148,783
2,232
(26,540)
189,335
Less: sales and other operating revenues between segments
(1,832)
(22,876)
(43)
(1,789)
26,540
Third party sales and other operating revenues
38,501
1,651
148,740
443
189,335
Earnings from joint ventures and associates – after interest
and tax
(501)
690
430
(1)
618
Segment results
Replacement cost profit (loss) before interest and taxation
1,330
8,558
4,100
(40)
45
13,993
Inventory holding gains (losses)a
2
(1,353)
(1,351)
Profit (loss) before interest and taxation
1,330
8,560
2,747
(40)
45
12,642
Finance costs
(5,106)
Net finance income relating to pensions and other post-
employment benefits
210
Profit before taxation
7,746
Other income statement items
Depreciation, depletion and amortization
US
235
4,992
1,994
89
7,310
Non-US
4,734
2,727
2,151
900
10,512
Charges for provisions, net of write-back of unused
provisions, including change in discount rate
37
302
3,180
666
4,185
Segment assets
Investments in joint ventures and associates
7,005
10,488
3,230
2
20,725
Additions to non-current assetsb
7,188
9,782
4,617
885
22,472
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
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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
32,628
25,637
155,401
2,290
(26,771)
189,185
Less: sales and other operating revenues between segments
(1,585)
(23,237)
(317)
(1,632)
26,771
Third party sales and other operating revenues
31,043
2,400
155,084
658
189,185
Earnings from joint ventures and associates – after interest
and tax
504
1,100
393
(4)
1,993
Segment results
 
 
 
 
Replacement cost profit (loss) before interest and taxationa
3,052
10,789
(1,043)
(988)
(25)
11,785
Inventory holding gains (losses)b
(9)
(479)
(488)
Profit (loss) before interest and taxationa
3,052
10,780
(1,522)
(988)
(25)
11,297
Finance costs
(4,683)
Net finance income relating to pensions and other post-
  employment benefits
 
 
 
168
Profit before taxation
 
 
 
6,782
Other income statement items
 
 
 
 
Depreciation, depletion and amortization
US
95
4,421
2,142
89
6,747
Non-US
4,740
2,376
1,815
944
9,875
Charges for provisions, net of write-back of unused
provisions, including change in discount rate
38
92
2,602
231
2,963
Segment assets
 
 
 
 
Investments in joint ventures and associatesa
6,111
10,730
3,183
8
20,032
Additions to non-current assetsa c
12,098
7,296
6,700
1,045
27,139
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
50,297
24,904
160,215
2,657
(27,943)
210,130
Less: sales and other operating revenues between segments
(1,808)
(23,708)
(367)
(2,060)
27,943
Third party sales and other operating revenues
48,489
1,196
159,848
597
210,130
Earnings from joint ventures and associates – after interest
and tax
(677)
1,164
427
(16)
898
Segment results
Replacement cost profit (loss) before interest and taxation
14,080
11,191
4,230
(903)
(14)
28,584
Inventory holding gains (losses)b
1
(1,237)
(1,236)
Profit (loss) before interest and taxation
14,081
11,191
2,993
(903)
(14)
27,348
Finance costs
(3,840)
Net finance income relating to pensions and other post-
employment benefits
241
Profit before taxation
23,749
Other income statement items
 
 
 
 
Depreciation, depletion and amortization
US
96
3,554
1,883
85
5,618
Non-US
5,584
2,138
1,665
923
10,310
Charges for provisions, net of write-back of unused
provisions, including change in discount rate
139
35
2,007
152
2,333
Segment assets
Investments in joint ventures and associatesa
5,404
10,721
4,096
28
20,249
Additions to non-current assetsa c
5,451
7,384
8,791
1,075
22,701
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
56,703
132,632
189,335
Other income statement items
Production and similar taxes
175
1,523
1,698
Non-current assets
Non-current assetsb c
61,269
77,194
138,463
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
58,804
130,381
189,185
Other income statement items
Production and similar taxes
149
1,650
1,799
Non-current assets
Non-current assetsb c
63,415
81,937
145,352
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
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Financial statements
5. Segmental analysis – continued
$ million
2023
By geographical area
US
Non-US
Total
Revenues
 
 
 
Third party sales and other operating revenuesa
60,577
149,553
210,130
Other income statement items
Production and similar taxes
136
1,643
1,779
Non-current assets
Non-current assetsb c
64,238
83,816
148,054
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
2,063
2,219
2,413
Oil products
114,207
121,019
128,969
Natural gas, LNG and NGLs
27,477
24,464
29,541
Non-oil products and other revenues from contracts with customers
15,132
13,362
10,298
Revenue from contracts with customers
158,879
161,064
171,221
Other operating revenuesa
30,456
28,121
38,909
Total sales and other operating revenues
189,335
189,185
210,130
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
1,203
1,308
1,034
Financial assets measured at fair value through profit or loss
129
181
215
Other incomea
277
1,284
386
1,609
2,773
1,635
Currency exchange losses charged to the income statementb
(295)
541
74
Expenditure on research and development
274
301
298
Costs relating to the Gulf of America oil spill (pre-interest and tax)c
31
51
57
Finance costs
Interest expense on lease liabilities
704
468
363
Interest expense on other liabilities measured at amortized costd
3,419
3,483
3,115
Capitalized at 4.69% (2024 4.94% and 2023 4.88%)e
(142)
(382)
(514)
Finance debt risk management activitiesf
(22)
104
(35)
Unwinding of discount on provisions
675
617
504
Unwinding of discount on other payables measured at amortized cost
472
393
407
5,106
4,683
3,840
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
343
767
746
Other exploration costs
227
207
251
Exploration expense for the year
570
974
997
Impairment losses
26
6
20
Intangible assets – exploration and appraisal expenditurea
3,963
4,438
4,328
Liabilities
33
76
109
Net assets
3,930
4,362
4,219
Cash used in operating activities
227
207
251
Cash used in investing activities
1,169
1,513
1,039
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
Tax on profit
$ million
2025
2024
2023
Current tax
Charge for the yeara
6,501
7,187
9,048
Adjustment in respect of prior years
(188)
234
(373)
6,313
7,421
8,675
Deferred tax
Origination and reversal of temporary differences in the current yearb
(537)
(1,851)
(238)
Adjustment in respect of prior yearsc
675
(17)
(568)
138
(1,868)
(806)
Tax charge on profit
6,451
5,553
7,869
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
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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
7,746
6,782
23,749
Tax charge (credit) on profit or loss
6,451
5,553
7,869
Effective tax rate
83%
82%
33%
%
Tax rate computed at the weighted average statutory ratea
55
66
34
Increase (decrease) resulting from
Tax reported in equity-accounted entities
(5)
(7)
(2)
Adjustments in respect of prior years
6
3
(4)
Deferred tax not recognized
5
5
2
Disposal impacts
5
Foreign exchange
(4)
5
Items not deductible for tax purposesb
11
5
2
Tax rate change effect of UK Energy Profits Levyc
7
1
Impact of Germany tax rate change
3
Otherd
5
(1)
1
Effective tax rate
83
82
33
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
3,025
5,349
Exchange adjustments
(63)
57
Charge (credit) for the year in the income statement
138
(1,868)
Charge (credit) for the year in other comprehensive income
(33)
(807)
Charge (credit) for the year in equity
(33)
167
Acquisitions and disposals
283
127
At 31 December
3,317
3,025
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
(897)
(1,337)
(1,552)
15,474
16,333
Pension plan surpluses
(3)
62
133
1,860
1,789
Derivative financial instruments
37
40
12
106
58
Other taxable temporary differencesa
37
(352)
10
824
663
(826)
(1,587)
(1,397)
18,264
18,843
Deferred tax asset
Depreciation
993
(229)
(166)
(1,544)
(2,373)
Lease liabilities
(395)
(209)
(176)
(2,375)
(1,952)
Pension plan and other post-employment benefit plan deficits
48
28
(60)
(552)
(623)
Decommissioning, environmental and other provisions
(314)
425
563
(5,981)
(5,623)
Derivative financial instruments
(48)
(9)
(14)
(277)
(268)
Tax credits
(111)
(43)
(67)
(1,047)
(937)
Loss carry forward
580
194
296
(1,852)
(2,285)
Other deductible temporary differencesb
211
(438)
215
(1,319)
(1,757)
964
(281)
591
(14,947)
(15,818)
Net deferred tax charge (credit) and net deferred tax liability
138
(1,868)
(806)
3,317
3,025
Of which – deferred tax liabilities
7,642
8,428
– deferred tax assets
4,325
5,403
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.
A summary of temporary differences, unused tax credits and unused tax losses for which deferred tax has not been recognized is shown in the
table below.
$ billion
At 31 December
2025
2024
Unused US state tax lossesa
2.9
2.3
Unused tax losses – other jurisdictionsb
9.4
7.3
Unused tax credits
36.7
33.3
of which – arising in the UKc
33.2
29.1
               – arising in the USd
3.5
4.2
Deductible temporary differencese
28.3
23.4
Taxable temporary differences associated with investments in subsidiaries and equity-accounted entities
0.7
0.7
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
101
87
360
Deferred tax benefit arising from the reversal of a previous write-down of deferred tax assets
11
14
3
Deferred tax benefit relating to the recognition of previously unrecognized deferred tax assets
156
280
332
Deferred tax expense arising from the write-down of a previously recognized deferred tax asset
725
111
54
bp Annual Report and Form 20-F 2025
193
NavigtionTabCornerV1.jpg
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
1
1
1
Ordinary shares
March
6.1761
5.6922
5.5507
8.000
7.270
6.610
1,257
1,218
1,183
June
5.8993
5.6825
5.3089
8.000
7.270
6.610
1,237
1,204
1,152
September
6.1942
6.0498
5.7320
8.320
8.000
7.270
1,288
1,297
1,249
December
6.2394
6.2959
5.7367
8.320
8.000
7.270
1,276
1,283
1,224
24.5090
23.7204
22.3283
32.640
30.540
27.760
5,059
5,003
4,809
Dividend announced, paid in March 2026
8.320
1,280
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
0.35
2.38
87.78
Diluted earnings per share
0.34
2.32
85.85
Dollars per share
Per American Depositary Share (ADS)a
2025
2024
2023
Basic earnings per share
0.02
0.14
5.27
Diluted earnings per share
0.02
0.14
5.15
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
55
381
15,239
Less: dividend requirements on preference shares
1
1
1
Less: (gain) loss on redemption of perpetual hybrid bondsa
(10)
Profit (loss) for the year attributable to bp ordinary shareholders
54
390
15,238
Shares thousand
2025
2024
2023
Basic weighted average number of ordinary sharesb
15,586,782
16,385,535
17,360,288
Potential dilutive effect of ordinary shares issuable under employee share-based payment
    plans
326,218
431,129
389,790
Weighted average number of ordinary shares outstanding used to calculate diluted earnings
per share
15,913,000
16,816,664
17,750,078
Shares thousand
2025
2024
2023
Basic weighted average number of ordinary shares – ADS equivalent
2,597,797
2,730,922
2,893,381
Potential dilutive effect of ordinary shares (ADS equivalent) issuable under employee share-
    based payment plans
54,369
71,855
64,965
Weighted average number of ordinary shares (ADS equivalent) outstanding used to calculate
diluted earnings per share
2,652,166
2,802,777
2,958,346
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.
The following table shows the number of shares potentially issuable under equity-settled employee share option plans, including the number of
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
382,873
4.21
533,895
4.15
Exercisable
345,112
4.23
2,931
3.38
Dilutive effect
80,562
n/a
140,971
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
155,555
271,216
1 to 2 years
116,997
134,342
2 to 3 years
105,074
102,525
3 to 4 years
366
956
Over 4 years
43
118
378,035
509,157
Dilutive effect
161,105
269,796
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
NavigtionTabCornerV1.jpg
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
4,060
1,167
184,304
48,731
2,315
2,687
12,417
255,681
Exchange adjustments
299
47
1,403
78
19
1,011
2,857
Additions
23
131
9,896
2,667
89
125
784
13,715
Acquisitions
18
68
3
89
Transfers from intangible assets
3,593
3,593
Reclassified as assets held for sale
(72)
(69)
(923)
(1,755)
(137)
(3)
(314)
(3,273)
Deletions and disposals
(299)
(4)
(2,074)
(1,047)
(176)
(38)
(693)
(4,331)
At 31 December 2025
4,011
1,290
194,796
50,067
2,169
2,790
13,208
268,331
Depreciation - owned PP&E
At 1 January 2025
876
520
128,091
26,929
1,716
1,933
6,561
166,626
Exchange adjustments
60
17
961
50
8
629
1,725
Charge for the year
47
60
11,458
1,741
138
102
771
14,317
Impairment losses
11
5
568
1,224
11
42
1,861
Impairment reversals
(10)
(9)
(3)
(4)
(2)
(28)
Transfers from intangible assets
2,285
2,285
Reclassified as assets held for sale
(9)
(41)
(423)
(967)
(102)
(2)
(187)
(1,731)
Deletions and disposals
(28)
(4)
(1,843)
(795)
(167)
(36)
(472)
(3,345)
At 31 December 2025
947
557
140,127
29,090
1,635
2,012
7,342
181,710
Owned PP&E - net book amount at 31 December
2025
3,064
733
54,669
20,977
534
778
5,866
86,621
Right-of-use assets - net book amount at 31
December 2025b
1,894
748
1,863
2,311
5,196
12,012
Total PP&E - net book amount at 31 December
2025
3,064
2,627
55,417
22,840
534
3,089
11,062
98,633
Cost - owned PP&E
At 1 January 2024
3,924
992
185,346
47,384
2,290
2,958
12,224
255,118
Exchange adjustments
(213)
(35)
(864)
(43)
(23)
(637)
(1,815)
Additions
352
222
7,899
3,039
138
144
1,042
12,836
Acquisitions
60
148
1,235
57
80
70
1,650
Transfers from intangible assets
391
391
Reclassified as assets held for sale
(25)
(41)
(3,210)
(747)
(1)
(4,024)
Deletions and disposals
(38)
(119)
(6,122)
(1,316)
(126)
(472)
(282)
(8,475)
At 31 December 2024
4,060
1,167
184,304
48,731
2,315
2,687
12,417
255,681
Depreciation - owned PP&E
At 1 January 2024
838
553
123,442
25,671
1,684
2,292
6,363
160,843
Exchange adjustments
(52)
(9)
(536)
(24)
(9)
(388)
(1,018)
Charge for the year
58
43
10,626
1,553
157
91
731
13,259
Impairment losses
70
2,418
1,260
1
9
82
3,840
Impairment reversals
(420)
(4)
(3)
(427)
Reclassified as assets held for sale
(6)
(4)
(2,168)
(367)
(1)
(2,546)
Deletions and disposals
(32)
(63)
(5,807)
(648)
(101)
(447)
(227)
(7,325)
At 31 December 2024
876
520
128,091
26,929
1,716
1,933
6,561
166,626
Owned PP&E - net book amount at 31 December
2024
3,184
647
56,213
21,802
599
754
5,856
89,055
Right-of-use assets - net book amount at 31
December 2024b
1,613
41
1,431
10
2,589
5,499
11,183
Total PP&E - net book amount at 31 December
2024
3,184
2,260
56,254
23,233
609
3,343
11,355
100,238
Assets under construction included above
At 31 December 2025
11,653
At 31 December 2024
10,722
Depreciation charge for the year on right-of-use assets
2025
342
55
728
3
1,026
874
3,028
2024
215
30
640
3
1,109
882
2,878
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
15,530
13,176
Exchange adjustments
397
(179)
Acquisitions and other additions
(89)
2,734
Reclassified as assets held for sale
(2,756)
(79)
Deletions and disposals
(133)
(122)
At 31 December
12,949
15,530
Impairment losses
At 1 January
642
704
Exchange adjustments
30
(2)
Impairment losses for the year
2,009
Deletions and disposals
(32)
(60)
At 31 December
2,649
642
Net book amount at 31 December
10,300
14,888
Net book amount at 1 January
14,888
12,472
Impairment review of goodwill
$ million
Goodwill at 31 December
2025
2024
gas & low carbon energya
3,185
5,166
oil production & operations
4,870
4,925
customers & productsa
2,245
4,797
other businesses & corporate
10,300
14,888
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.
gas & low carbon energy and oil production & operations
$ 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
2,260
925
3,185
2,228
2,938
5,166
4,870
4,925
Excess of recoverable amount over carrying
amount
2,917
2,917
2,026
n/a
2,026
13,748
12,432
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
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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.
customers & products
$ million
2025
2024
Castrol
US Fuels
European
Fuels
Other
Total
Castrol
US Fuels
European
Fuels
Other
Totala
Goodwilla
844
823
578
2,245
2,615
828
801
553
4,797
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
The goodwill associated with Castrol was reclassified to assets held for sale during the year.
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
13,053
2,990
7,550
23,593
13,075
2,989
7,117
23,181
Exchange adjustments
350
350
(171)
(171)
Acquisitionsb
28
28
351
351
Additions
1,213
1
544
1,758
1,539
193
904
2,636
Transfers to property, plant and equipment
(3,593)
(3,593)
(391)
(391)
Reclassified as assets held for sale
(667)
(667)
(1)
(385)
(386)
Deletions and disposals
(3,057)
(8)
(311)
(3,376)
(1,169)
(192)
(266)
(1,627)
At 31 December
7,616
2,983
7,494
18,093
13,053
2,990
7,550
23,593
Amortization
At 1 January
8,615
557
4,775
13,947
8,747
105
4,338
13,190
Exchange adjustments
215
215
(97)
(97)
Exploration expenditure written off
343
343
767
767
Charge for the year
93
736
829
114
717
831
Impairment losses
26
710
41
777
6
344
108
458
Impairment reversals
(84)
(84)
(2)
(2)
Transfers to property, plant and equipment
(2,285)
(2,285)
Reclassified as assets held for sale
(502)
(502)
(53)
(53)
Deletions and disposals
(3,046)
(7)
(291)
(3,344)
(903)
(6)
(238)
(1,147)
At 31 December
3,653
1,269
4,974
9,896
8,615
557
4,775
13,947
Net book amount at 31 December
3,963
1,714
2,520
8,197
4,438
2,433
2,775
9,646
Net book amount at 1 January
4,438
2,433
2,775
9,646
4,328
2,884
2,779
9,991
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
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Financial statements
16. Investments in joint ventures
The following table provides aggregated summarized financial information for the group's joint ventures as it relates to the amounts recognized in
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
406
504
700
5,080
5,109
Other joint ventures
(706)
405
(633)
8,320
7,182
(300)
909
67
13,400
12,291
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
4,426
5,410
5,164
Profit (loss) before interest and taxation
1,266
1,896
2,146
Finance costs
304
512
400
Profit (loss) before taxationa
962
1,384
1,746
Taxation
150
376
346
Profit (loss) for the year
812
1,008
1,400
Other comprehensive income
Total comprehensive income
812
1,008
1,400
Non-current assets
22,564
20,584
Current assetsb
4,010
3,384
Total assets
26,574
23,968
Current liabilitiesc
5,056
3,576
Non-current liabilitiesd
11,358
10,174
Total liabilities
16,414
13,750
Net assets
10,160
10,218
Less: non-controlling interests
10,160
10,218
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
2,213
10,030
12,243
2,705
12,164
14,869
2,582
13,705
16,287
Profit (loss) before interest and taxation
633
(61)
572
948
(74)
874
1,073
8
1,081
Finance costs
152
398
550
256
249
505
200
421
621
Profit (loss) before taxation
481
(459)
22
692
(323)
369
873
(413)
460
Taxation
75
247
322
188
(729)
(541)
173
219
392
Non-controlling interest
1
1
1
1
Profit (loss) for the year
406
(706)
(300)
504
405
909
700
(633)
67
Other comprehensive income
(3)
(3)
45
45
Total comprehensive income
406
(706)
(300)
504
402
906
700
(588)
112
Non-current assets
11,282
18,162
29,444
10,292
13,871
24,163
Current assets
2,005
3,960
5,965
1,692
4,363
6,055
Total assets
13,287
22,122
35,409
11,984
18,234
30,218
Current liabilities
2,528
3,398
5,926
1,788
2,914
4,702
Non-current liabilities
5,679
7,244
12,923
5,087
5,057
10,144
Total liabilities
8,207
10,642
18,849
6,875
7,971
14,846
Net assets
5,080
11,480
16,560
5,109
10,263
15,372
Less: non-controlling interests
(90)
(90)
(11)
(11)
5,080
11,390
16,470
5,109
10,252
15,361
Group investment in joint ventures
Group share of net assets (as above)
5,080
11,390
16,470
5,109
10,252
15,361
Cumulative impairment charge
(3,066)
(3,066)
(3,066)
(3,066)
Loans made by group companies to joint ventures
(4)
(4)
(4)
(4)
5,080
8,320
13,400
5,109
7,182
12,291
Transactions between the group and its joint ventures are summarized below.
$ 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
2,470
469
3,653
507
3,585
501
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
2,230
426
2,952
468
3,328
427
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
group's US offshore wind investments.
bp Annual Report and Form 20-F 2025
201
NavigtionTabCornerV1.jpg
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.
Summarized financial information for the group’s share of associates is shown below.
$ million
bp share
2025
2024
2023
Sales and other operating revenues
13,374
12,859
11,396
Profit before interest and taxation
1,940
2,389
2,279
Finance costs
32
41
41
Profit (loss) before taxation
1,908
2,348
2,238
Taxation
990
1,264
1,407
Profit (loss) for the year
918
1,084
831
Other comprehensive income
(4)
(9)
(237)
Total comprehensive income
914
1,075
594
Non-current assets
12,089
11,395
Current assets
3,915
4,230
Total assets
16,004
15,625
Current liabilities
2,997
3,009
Non-current liabilities
5,714
4,886
Total liabilities
8,711
7,895
Net assets
7,293
7,730
Group investment in associates
Group share of net assets (as above)
7,293
7,730
Loans made by group companies to associates
32
11
7,325
7,741
Transactions between the group and its associates are summarized below.
$ 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
1,034
348
844
148
1,009
368
$ 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
6,708
2,052
7,034
2,223
5,473
2,607
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
816
1,095
Contingent consideration
60
25
55
136
Other
98
16
110
61
158
857
165
1,292
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
2,789
3,007
Natural gas
697
548
Emissions allowances
843
549
Refined petroleum and petrochemical products
5,803
6,627
10,132
10,731
Trading inventories
8,665
8,977
Supplies
2,105
1,946
Biological assets
112
178
Solar projects
1,485
1,400
22,499
23,232
Cost of inventories expensed in the income statement
110,640
113,941
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
21,107
6
21,659
502
Amounts receivable from joint ventures and associates
817
655
Other receivables
2,882
1,755
3,524
808
24,806
1,761
25,838
1,310
Non-financial assets
Sales taxes and production taxes
1,032
509
1,165
356
Other receivables
176
106
124
149
1,208
615
1,289
505
26,014
2,376
27,127
1,815
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
NavigtionTabCornerV1.jpg
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
995
3,298
1,424
3,183
636
3,050
Charged to costs and expenses
23
179
(90)
140
866
176
Charged to other accountsa
10
(7)
1
(1)
Deductions
(90)
(62)
(332)
(25)
(79)
(42)
At 31 December
938
3,415
995
3,298
1,424
3,183
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
37,082
38,636
Amounts payable to joint ventures and associates
2,477
1
2,690
1
Payables for capital expenditure and acquisitions
3,054
85
3,670
309
Payables related to the Gulf of America oil spill
1,520
5,735
1,126
6,830
Other payables
7,771
457
7,358
678
51,904
6,278
53,480
7,818
Non-financial liabilities
Sales taxes, customs duties, production taxes and social security
2,001
55
2,121
54
Other payables
2,938
1,642
2,810
1,537
4,939
1,697
4,931
1,591
56,843
7,975
58,411
9,409
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
11,758
1,518
701
2,330
1,981
18,288
Exchange adjustments
159
15
6
99
144
423
Acquisitions
26
3
29
New and increase in existing provisionsa
528
325
362
3,052
1,329
5,596
Write-back of unused provisionsa
(2)
(73)
(20)
(83)
(707)
(885)
Unwinding of discountb
530
63
20
62
675
Utilization
(17)
(297)
(188)
(1,834)
(522)
(2,858)
Reclassified to other payables
(540)
(2)
(108)
(2)
(652)
Reclassified as liabilities directly associated with
assets held for sale
(21)
(31)
(2)
(21)
(75)
Deletions
(142)
(18)
(1)
(1)
(162)
At 31 December 2025
12,253
1,500
796
3,564
2,266
20,379
Of which – current
824
319
100
2,709
757
4,709
– non-current
11,429
1,181
696
855
1,509
15,670
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
NavigtionTabCornerV1.jpg
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
5.6
5.5
4.8
5.4
5.6
5.0
4.2
3.5
3.6
Rate of increase for pensions in payment
2.7
2.9
2.8
1.8
1.8
2.1
Rate of increase in deferred pensions
2.7
2.9
2.8
0.6
0.6
0.7
Inflation for plan liabilities
2.9
3.1
3.0
2.0
2.0
2.0
2.0
2.0
2.4
%
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
5.7
5.0
5.2
3.7
3.7
4.3
Discount rate for plan other finance expense
5.5
4.8
5.0
5.6
5.0
5.2
3.5
3.6
4.2
Inflation for plan service costa
N/A
N/A
N/A
2.0
2.0
2.0
2.0
2.4
2.1
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
27.1
27.0
27.4
25.2
25.1
25.0
26.4
26.2
26.1
Life expectancy at age 60 for a male currently
aged 40
28.9
28.9
29.2
26.9
26.8
26.7
28.9
28.6
28.6
Life expectancy at age 60 for a female
currently aged 60
28.9
29.0
29.2
28.2
28.1
28.1
29.5
29.5
29.3
Life expectancy at age 60 for a female
currently aged 40
30.4
30.5
30.6
29.7
29.6
29.6
31.7
31.7
31.6
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
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Financial statements
24. Pensions and other post-employment benefits – continued
The current asset allocation policy for the major plans at 31 December 2025 was as follows:
UK
US
Asset category
%
%
Total equity (including private equity)
8
19
Bonds/cash (including LDI)
85
81
Property/real estate
7
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.
The fair values of the various categories of assets held by the defined benefit plans at 31 December are presented in the table below, including the
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
725
137
84
181
1,127
– emerging markets
29
17
10
70
126
Private equityc
1,871
910
2,781
Government issued nominal bondsd
3,761
1,369
901
214
6,245
Government issued index-linked bondsd
10,805
85
8
10,898
Corporate bondsd
5,383
2,790
70
236
8,479
Propertye
2,487
6
13
2,506
Cash
574
83
912
106
1,675
Otherf
3,232
46
(58)
11
3,231
Debt (repurchase agreements) used to fund liability driven investments
(4,278)
(4,278)
24,589
5,352
2,010
839
32,790
At 31 December 2024
Listed equities – developed markets
963
113
341
230
1,647
– emerging markets
32
13
55
75
175
Private equityc
1,916
950
2
2,868
Government issued nominal bondsd
5,027
1,317
690
223
7,257
Government issued index-linked bondsd
11,105
78
7
11,190
Corporate bondsd
6,088
2,763
605
261
9,717
Propertye
2,344
84
19
2,447
Cash
416
67
100
78
661
Otherf
1,039
36
54
14
1,143
Debt (repurchase agreements) used to fund liability driven investments
(5,664)
(5,664)
23,266
5,259
2,007
909
31,441
At 31 December 2023
Listed equities – developed markets
862
97
333
232
1,524
– emerging markets
28
12
51
66
157
Private equityc
2,022
1,014
2
3,038
Government issued nominal bondsd
6,285
1,457
746
285
8,773
Government issued index-linked bondsd
13,177
88
13,265
Corporate bondsd
6,144
2,802
605
166
9,717
Propertye
2,437
92
17
2,546
Cash
453
59
82
85
679
Otherf
1,123
33
55
391
1,602
Debt (repurchase agreements) used to fund liability driven investments
(6,485)
(6,485)
26,046
5,474
2,052
1,244
34,816
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.
Completion of a buy-out in 2024 reduced these amounts to $nil.
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
47
157
56
25
285
Past service costb
(39)
(39)
Settlementb
11
11
Operating charge (credit) relating to defined benefit plans
47
157
28
25
257
Payments to defined contribution plans
180
179
7
35
401
Total operating charge (credit)
227
336
35
60
658
Interest income on plan assetsa
(1,322)
(286)
(78)
(38)
(1,724)
Interest on plan liabilities
976
300
190
48
1,514
Other finance (income) expense
(346)
14
112
10
(210)
Analysis of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assets
(613)
120
(225)
(1)
(719)
Change in financial assumptions underlying the present value of the plan liabilities
453
(242)
436
8
655
Change in demographic assumptions underlying the present value of the plan liabilities
(26)
(1)
(27)
Experience gains and losses arising on the plan liabilities
15
(40)
(102)
(3)
(130)
Remeasurements recognized in other comprehensive income
(171)
(162)
109
3
(221)
Movements in benefit obligation during the year
Benefit obligation at 1 January
17,324
5,524
5,002
1,007
28,857
Exchange adjustments
1,301
646
50
1,997
Operating charge relating to defined benefit plans
47
157
28
25
257
Interest cost
976
300
190
48
1,514
Contributions by plan participants
8
2
5
15
Benefit payments (funded plans)c
(1,160)
(313)
(95)
(64)
(1,632)
Benefit payments (unfunded plans)c
(10)
(145)
(246)
(11)
(412)
Reclassified as assets held for sale
(24)
(161)
(77)
(262)
Disposals
(1)
(1)
Remeasurements
(442)
282
(334)
(4)
(498)
Benefit obligation at 31 Decembera d e
18,020
5,805
5,031
979
29,835
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
23,266
5,259
2,007
909
31,441
Exchange adjustments
1,757
257
43
2,057
Interest income on plan assetsa e
1,322
286
78
38
1,724
Contributions by plan participants
8
2
5
15
Contributions by and refunds to employers (funded plans)
9
16
(28)
(3)
Benefit payments (funded plans)c
(1,160)
(313)
(95)
(64)
(1,632)
Reclassified as assets held for sale
(30)
(63)
(93)
Remeasurementsf
(613)
120
(225)
(1)
(719)
Fair value of plan assets at 31 Decemberg
24,589
5,352
2,010
839
32,790
Surplus (deficit) at 31 December
6,569
(453)
(3,021)
(140)
2,955
Represented by
Asset recognized
6,697
921
93
60
7,771
Liability recognized
(128)
(1,374)
(3,114)
(200)
(4,816)
6,569
(453)
(3,021)
(140)
2,955
The surplus (deficit) may be analysed between funded and unfunded plans as follows
Funded
6,696
921
84
29
7,730
Unfunded
(127)
(1,374)
(3,105)
(169)
(4,775)
6,569
(453)
(3,021)
(140)
2,955
The defined benefit obligation may be analysed between funded and unfunded plans as
follows
Funded
(17,893)
(4,431)
(1,926)
(810)
(25,060)
Unfunded
(127)
(1,374)
(3,105)
(169)
(4,775)
(18,020)
(5,805)
(5,031)
(979)
(29,835)
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
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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
48
160
62
23
293
Past service costb
(1)
(1)
Settlementb
(1)
(1)
Operating charge (credit) relating to defined benefit plans
47
160
61
23
291
Payments to defined contribution plans
161
192
8
35
396
Total operating charge (credit)
208
352
69
58
687
Interest income on plan assetsa
(1,218)
(267)
(70)
(49)
(1,604)
Interest on plan liabilities
909
283
184
60
1,436
Other finance (income) expense
(309)
16
114
11
(168)
Analysis of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assets
(2,388)
(239)
65
83
(2,479)
Change in financial assumptions underlying the present value of the plan liabilities
1,496
403
103
(48)
1,954
Change in demographic assumptions underlying the present value of the plan liabilities
194
(8)
1
2
189
Experience gains and losses arising on the plan liabilities
15
(34)
2
(7)
(24)
Remeasurements recognized in other comprehensive income
(683)
122
171
30
(360)
Movements in benefit obligation during the year
Benefit obligation at 1 January
19,579
5,837
5,537
1,371
32,324
Exchange adjustments
(352)
(355)
(66)
(773)
Operating charge relating to defined benefit plans
47
160
61
23
291
Interest cost
909
283
184
60
1,436
Contributions by plan participants
7
2
7
16
Benefit payments (funded plans)c
(1,153)
(243)
(89)
(427)
(1,912)
Benefit payments (unfunded plans)c
(8)
(152)
(232)
(12)
(404)
Disposals
(2)
(2)
Remeasurements
(1,705)
(361)
(106)
53
(2,119)
Benefit obligation at 31 Decembera d
17,324
5,524
5,002
1,007
28,857
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
26,046
5,474
2,052
1,244
34,816
Exchange adjustments
(473)
(139)
(61)
(673)
Interest income on plan assetsa e
1,218
267
70
49
1,604
Contributions by plan participants
7
2
7
16
Contributions by employers (funded plans)
9
46
14
69
Benefit payments (funded plans)c
(1,153)
(243)
(89)
(427)
(1,912)
Remeasurementse
(2,388)
(239)
65
83
(2,479)
Fair value of plan assets at 31 Decemberf
23,266
5,259
2,007
909
31,441
Surplus (deficit) at 31 December
5,942
(265)
(2,995)
(98)
2,584
Represented by
Asset recognized
6,083
1,009
273
92
7,457
Liability recognized
(141)
(1,274)
(3,268)
(190)
(4,873)
5,942
(265)
(2,995)
(98)
2,584
The surplus (deficit) may be analysed between funded and unfunded plans as follows
Funded
6,083
1,009
261
48
7,401
Unfunded
(141)
(1,274)
(3,256)
(146)
(4,817)
5,942
(265)
(2,995)
(98)
2,584
The defined benefit obligation may be analysed between funded and unfunded plans as
follows
Funded
(17,183)
(4,250)
(1,746)
(861)
(24,040)
Unfunded
(141)
(1,274)
(3,256)
(146)
(4,817)
(17,324)
(5,524)
(5,002)
(1,007)
(28,857)
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
44
156
47
21
268
Past service costb
4
5
(2)
7
Settlementb
3
3
Operating charge (credit) relating to defined benefit plans
48
156
52
22
278
Payments to defined contribution plans
132
158
7
36
333
Total operating charge (credit)
180
314
59
58
611
Interest income on plan assetsa
(1,259)
(274)
(78)
(56)
(1,667)
Interest on plan liabilities
869
297
194
66
1,426
Other finance (income) expense
(390)
23
116
10
(241)
Analysis of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assets
(677)
45
82
28
(522)
Change in financial assumptions underlying the present value of the plan liabilities
(649)
28
(508)
(24)
(1,153)
Change in demographic assumptions underlying the present value of the plan liabilities
(230)
(5)
8
(227)
Experience gains and losses arising on the plan liabilities
(320)
45
(84)
(1)
(360)
Remeasurements recognized in other comprehensive income
(1,876)
113
(502)
3
(2,262)
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
termination benefits arising as a result of early retirements.
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
(186)
168
(44)
46
(2)
(5)
Effect on obligation at 31 December 2025
(1,803)
2,185
(465)
614
(497)
604
Inflation rateb
Effect on expense in 2026
90
(82)
8
(6)
22
(20)
Effect on obligation at 31 December 2025
1,613
(1,464)
39
(33)
480
(414)
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
33
4
9
Effect on obligation at 31 December 2025
593
60
189
bp Annual Report and Form 20-F 2025
211
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Financial statements
24. Pensions and other post-employment benefits – continued
Estimated future benefit payments and the weighted average duration of defined benefit obligations
The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, and the weighted average
duration of the defined benefit obligations at 31 December 2025 are as follows:
$ million
Estimated future benefit payments
UK
US
Eurozone
Other
Total
2026
1,190
467
324
61
2,042
2027
1,212
463
325
55
2,055
2028
1,219
458
320
56
2,053
2029
1,233
467
319
55
2,074
2030
1,234
473
312
54
2,073
2031 - 2035
6,214
2,383
1,431
285
10,313
Years
Weighted average duration
11.1
9.2
12.5
12.6
25. Cash and cash equivalents
$ million
2025
2024
Cash
17,158
16,414
Triparty repos and term bank deposits
12,691
14,453
Other cash equivalents
6,707
8,337
36,556
39,204
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
3,356
54,602
57,958
4,474
55,073
59,547
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.
The following table shows the weighted-average interest rates achieved through a combination of borrowings and derivative financial instruments
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
5
8
41,018
4
16,486
57,504
Other currencies
6
4
246
6
208
454
41,264
16,694
57,958
2024
US dollar
4
8
41,145
5
17,847
58,992
Other currencies
6
3
396
6
159
555
41,541
18,006
59,547
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 carrying amount of the group’s short-term borrowings, comprising mainly of commercial paper, approximates their fair value. The fair values of
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
353
353
681
681
Long-term borrowings
54,582
57,605
54,285
58,866
Total finance debt
54,935
57,958
54,966
59,547
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.
At 31 December 2025, gearing was 23.1% (2024 22.7%).
$ million
At 31 December
2025
2024
Finance debt
57,958
59,547
Less: fair value asset (liability) of hedges related to finance debta
(780)
(2,654)
58,738
62,201
Less: cash and cash equivalents
36,556
39,204
Net debt
22,182
22,997
Total equity
74,000
78,318
Gearing
23.1%
22.7%
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
$166 million) are not included in the calculation of net debt shown above as hedge accounting was not applied for these instruments.
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
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Financial statements
27. Capital disclosures and net debt - continued
An analysis of changes in liabilities arising from financing activities is provided below.
$ 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
59,547
4,113
12,000
37
75,697
Exchange adjustments
127
399
2
528
Net financing cash flow
(3,290)
(22)
(3,091)
(2)
(6,405)
Fair value (gains) losses
1,664
(3,044)
(1,380)
New and remeasured leases/joint operations payables
5,449
(4)
5,445
Other movements
(90)
(186)
(2)
(278)
At 31 December 2025
57,958
1,047
14,571
31
73,607
At 1 January 2024
51,954
2,978
11,121
30
66,083
Exchange adjustments
(39)
(272)
(1)
(312)
Net financing cash flow
4,761
(27)
(2,833)
(14)
1,887
Fair value (gains) losses
(840)
1,162
322
New and remeasured leases/joint operations payables
3,441
24
3,465
Other movementsb
3,711
543
(2)
4,252
At 31 December 2024
59,547
4,113
12,000
37
75,697
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.
The table below shows the timing of the undiscounted cash outflows for the lease liabilities included on the balance sheet.
$ million
2025
2024
Undiscounted lease liability cash flows due:
Within 1 year
3,596
3,237
1 to 2 years
2,906
2,418
2 to 3 years
2,222
1,798
3 to 4 years
1,620
1,394
4 to 5 years
1,481
1,099
5 to 10 years
4,076
3,039
Over 10 years
3,435
1,283
19,336
14,268
Impact of discounting
(4,765)
(2,268)
Lease liabilities at 31 December
14,571
12,000
Of which – current
2,832
2,660
– non-current
11,739
9,340
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
3,727
3,283
Expense for variable payments not included in the lease liabilitya
61
45
Short-term lease expensea
286
499
Additions to right-of-use assets in the period
4,349
3,781
Gain (loss) on sale and leaseback transactions
1
aThe cash outflows for amounts not included in lease liabilities approximate the income statement expenses disclosed above.
An analysis of right-of-use assets and depreciation is provided in Note 12. An analysis of lease interest expense is provided in Note 7.
29. Financial instruments and financial risk factors
The accounting classification of each category of financial instruments and their carrying amounts are set out below.
$ 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
1,015
1,015
Loans
1,991
457
2,448
Trade and other receivables
20
26,567
26,567
Derivative financial instruments
30
25,892
245
26,137
Cash and cash equivalents
25
31,777
4,779
36,556
Financial liabilities
Trade and other payables
22
(58,182)
(58,182)
Derivative financial instruments
30
(23,056)
(1,024)
(24,080)
Accruals
(7,406)
(7,406)
Lease liabilities
28
(14,571)
(14,571)
Finance debt
26
(57,958)
(57,958)
(77,782)
9,087
(779)
(69,474)
$ 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
26
1,431
1,457
Loans
1,807
377
2,184
Trade and other receivables
20
27,148
27,148
Derivative financial instruments
30
21,226
21,226
Cash and cash equivalents
25
32,547
6,657
39,204
Financial liabilities
Trade and other payables
22
(61,298)
(61,298)
Derivative financial instruments
30
(20,224)
(2,655)
(22,879)
Accruals
(7,397)
(7,397)
Lease liabilities
28
(12,000)
(12,000)
Finance debt
26
(59,547)
(59,547)
(78,714)
9,467
(2,655)
(71,902)
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
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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
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Financial statements
29. Financial instruments and financial risk factors – continued
Management information used to monitor credit risk, which reflects the impact of credit enhancements, indicates that the risk profile of financial
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-
14%
12%
A+ to A-
52%
50%
BBB+ to BBB-
13%
16%
BB+ to BB-
11%
10%
B+ to B-
6%
8%
CCC+ and below
4%
4%
Movements in the impairment provision for trade and other receivables are shown in Note 21.
Financial instruments subject to offsetting, enforceable master netting arrangements and similar agreements
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
28,414
(2,277)
26,137
(7,491)
(544)
18,102
Derivative liabilities
(26,357)
2,277
(24,080)
7,491
101
(16,488)
Trade and other receivables
14,055
(6,385)
7,670
(1,555)
(170)
5,945
Trade and other payables
(17,308)
6,385
(10,923)
1,555
8
(9,360)
At 31 December 2024
Derivative assets
23,779
(2,553)
21,226
(5,624)
(362)
15,240
Derivative liabilities
(25,432)
2,553
(22,879)
5,624
294
(16,961)
Trade and other receivables
17,832
(9,445)
8,387
(1,532)
(206)
6,649
Trade and other payables
(20,289)
9,445
(10,844)
1,532
12
(9,300)
(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.
Additional information about the group’s trade payables that are subject to supplier finance arrangements is provided in the table below.
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
5,596
1,356
1,018
7,431
1,778
390
of which suppliers have received payment from the
financial institution
5,247
1,356
1,018
7,016
1,778
390
Range of payment due dates (days)
Liabilities that are part of the arrangement
6 to 60
30 to 60
30 to 60
8 to 57
30 to 60
30 to 60
Trade payables that are not part of the arrangement
8 to 60
6 to 60
7 to 60
6 to 60
6 to 60
6 to 60
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
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Financial statements
29. Financial instruments and financial risk factors – continued
The table below shows the timing of undiscounted cash outflows relating to finance debt, trade and other payables and accruals. As part of actively
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
51,907
5,572
3,312
2,227
53,663
6,071
4,402
2,490
1 to 2 years
1,331
319
6,628
1,995
1,670
260
4,716
2,217
2 to 3 years
1,203
181
6,007
1,717
1,177
150
6,449
1,947
3 to 4 years
1,190
161
4,235
1,480
1,139
130
5,649
1,678
4 to 5 years
1,186
172
3,680
1,312
1,138
125
3,928
1,447
5 to 10 years
2,413
496
15,775
4,136
3,889
375
17,301
4,877
Over 10 years
126
505
13,292
5,347
157
286
13,947
6,198
59,356
7,406
52,929
18,214
62,833
7,397
56,392
20,854
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
$758 million within 4-5 years, $4,070 million within 5-10 years and $719 million over 10 years. For 2024 the equivalent amounts were $528 million within 2-3 years and $3,283 million in 5-10 years.
The table below shows the timing of cash outflows for derivative financial instruments entered into for the purpose of managing interest rate and
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
1,812
3,324
5,136
1,718
1,718
1 to 2 years
2,009
1,068
3,077
5,136
5,136
2 to 3 years
1,085
658
1,743
3,077
3,077
3 to 4 years
3,696
3,696
1,743
1,743
4 to 5 years
1,330
225
1,555
3,696
3,696
5 to 10 years
3,071
4,443
7,514
8,307
8,307
Over 10 years
498
1,465
1,963
2,486
2,486
 
9,805
14,879
24,684
26,163
26,163
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.
The fair values of derivative financial instruments at 31 December are set out below.
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
549
(720)
343
(1,738)
Oil price derivatives
1,509
(1,315)
1,350
(1,071)
Natural gas price derivatives
14,974
(13,781)
11,533
(10,506)
Power price derivatives
8,605
(7,046)
7,905
(6,893)
Other derivatives
255
(194)
95
(16)
25,892
(23,056)
21,226
(20,224)
Cash flow hedges
Currency forwards
Fair value hedges
Currency swaps
245
(1,022)
(2,651)
Interest rate swaps
(2)
(4)
245
(1,024)
(2,655)
26,137
(24,080)
21,226
(22,879)
Of which – current
5,180
(4,413)
5,112
(4,347)
– non-current
20,957
(19,667)
16,114
(18,532)
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.
Derivative assets held for trading have the following fair values and maturities.
$ million
2025
Less than
1 year
1-2 years
2-3 years
3-4 years
4-5 years
Over
5 years
Total
Currency derivatives
130
90
32
26
63
208
549
Oil price derivatives
1,277
130
52
42
6
2
1,509
Natural gas price derivatives
2,116
1,057
857
747
662
9,535
14,974
Power price derivatives
1,653
1,211
790
531
408
4,012
8,605
Other derivatives
1
2
226
1
25
255
5,177
2,490
1,957
1,347
1,139
13,782
25,892
$ million
2024
Less than
1 year
1-2 years
2-3 years
3-4 years
4-5 years
Over
5 years
Total
Currency derivatives
197
19
10
7
7
103
343
Oil price derivatives
1,004
156
78
53
55
4
1,350
Natural gas price derivatives
2,337
923
628
556
503
6,586
11,533
Power price derivatives
1,571
990
627
426
396
3,895
7,905
Other derivatives
4
4
85
2
95
5,113
2,092
1,343
1,127
961
10,590
21,226
bp Annual Report and Form 20-F 2025
221
NavigtionTabCornerV1.jpg
Financial statements
30. Derivative financial instruments – continued
Derivative liabilities held for trading have the following fair values and maturities.
$ million
2025
Less than
1 year
1-2 years
2-3 years
3-4 years
4-5 years
Over
5 years
Total
Currency derivatives
(192)
(20)
(14)
(196)
(12)
(286)
(720)
Oil price derivatives
(1,155)
(138)
(15)
(6)
(1)
(1,315)
Natural gas price derivatives
(1,748)
(917)
(705)
(605)
(545)
(9,261)
(13,781)
Power price derivatives
(1,268)
(996)
(677)
(504)
(336)
(3,265)
(7,046)
Other derivatives
(18)
(7)
(169)
(194)
(4,381)
(2,078)
(1,580)
(1,311)
(894)
(12,812)
(23,056)
$ million
2024
Less than
1 year
1-2 years
2-3 years
3-4 years
4-5 years
Over
5 years
Total
Currency derivatives
(111)
(529)
(172)
(4)
(562)
(360)
(1,738)
Oil price derivatives
(975)
(65)
(16)
(6)
(9)
(1,071)
Natural gas price derivatives
(2,075)
(836)
(515)
(409)
(363)
(6,308)
(10,506)
Power price derivatives
(1,062)
(779)
(569)
(401)
(471)
(3,611)
(6,893)
Other derivatives
(6)
(1)
(9)
(16)
(4,229)
(2,210)
(1,272)
(829)
(1,405)
(10,279)
(20,224)
The following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by
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
131
17
6
154
Level 2
4,813
1,541
940
296
198
156
7,944
Level 3
1,585
1,339
1,199
1,105
983
13,860
20,071
6,529
2,897
2,145
1,401
1,181
14,016
28,169
Less: netting by counterparty
(1,352)
(407)
(188)
(54)
(42)
(234)
(2,277)
5,177
2,490
1,957
1,347
1,139
13,782
25,892
Fair value of derivative liabilities
Level 1
(131)
(18)
(5)
(1)
(1)
(156)
Level 2
(4,337)
(1,284)
(700)
(395)
(59)
(235)
(7,010)
Level 3
(1,265)
(1,183)
(1,063)
(969)
(876)
(12,811)
(18,167)
(5,733)
(2,485)
(1,768)
(1,365)
(936)
(13,046)
(25,333)
Less: netting by counterparty
1,352
407
188
54
42
234
2,277
(4,381)
(2,078)
(1,580)
(1,311)
(894)
(12,812)
(23,056)
Net fair value
796
412
377
36
245
970
2,836
$ 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
157
35
7
2
201
Level 2
5,037
1,457
551
330
134
107
7,616
Level 3
1,516
1,175
948
839
858
10,626
15,962
6,710
2,667
1,506
1,171
992
10,733
23,779
Less: netting by counterparty
(1,597)
(575)
(163)
(44)
(31)
(143)
(2,553)
5,113
2,092
1,343
1,127
961
10,590
21,226
Fair value of derivative liabilities
Level 1
(124)
(20)
(7)
(2)
(153)
Level 2
(4,491)
(1,868)
(625)
(189)
(717)
(289)
(8,179)
Level 3
(1,211)
(897)
(803)
(682)
(719)
(10,133)
(14,445)
(5,826)
(2,785)
(1,435)
(873)
(1,436)
(10,422)
(22,777)
Less: netting by counterparty
1,597
575
163
44
31
143
2,553
(4,229)
(2,210)
(1,272)
(829)
(1,405)
(10,279)
(20,224)
Net fair value
884
(118)
71
298
(444)
311
1,002
222
bp Annual Report and Form 20-F 2025
30. Derivative financial instruments – continued
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
30
394
(306)
12
2
132
Gains (losses) recognized in the income statement
85
62
466
115
23
751
Sales
84
84
Settlements
(50)
(113)
(113)
(18)
(294)
Transfers out of level 3
(8)
(412)
(146)
1
(565)
Net fair value of contracts at 31 December 2025
57
(69)
(15)
109
26
108
Deferred day-one gains (losses)
1,796
Derivative asset (liability)
1,904
$ million
Oil
price
Natural gas
price
Power
price
Currency
Other
Total
Fair value contracts at 1 January 2024
107
599
(120)
219
2
807
Gains (losses) recognized in the income statement
(26)
(90)
129
(193)
(180)
Purchases
31
31
Settlements
(38)
(100)
(377)
(14)
(529)
Transfers out of level 3
(13)
(15)
31
3
Net fair value of contracts at 31 December 2024
30
394
(306)
12
2
132
Deferred day-one gains (losses)
1,385
Derivative asset (liability)
1,517
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
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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.
The tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the
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
287
(287)
At 31 December 2024
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure
Commodity price risk
Highly probable forecast sales
155
(155)
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
87
Commodity price risk
Highly probable forecast sales
(686)
At 31 December 2024
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure
95
Commodity price risk
Highly probable forecast sales
(209)
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
266 mmBtu matures within one to two years of the balance sheet date (2024 $nil).
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
1.35
1.25
Euro/US dollar
1.04
Australian dollar/US dollar
0.67
Henry Hub $/mmBtu
4.01
3.38
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
NavigtionTabCornerV1.jpg
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.
The tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the
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
(2)
2
Interest rate and foreign currency risk on finance debt
(1,850)
1,797
53
At 31 December 2024
Fair value hedges
Interest rate risk on finance debt
1
(1)
Interest rate and foreign currency risk on finance debt
927
(772)
(155)
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
(2)
149
Interest rate and foreign currency risk on finance debt
245
(1,022)
16,304
At 31 December 2024
Fair value hedges
Interest rate risk on finance debt
(4)
132
Interest rate and foreign currency risk on finance debt
(2,651)
15,887
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
149
149
Interest rate and foreign currency risk on
finance debt
2,045
1,525
1,843
1,166
1,095
7,099
1,531
16,304
At 31 December 2024
Fair value hedges
Interest rate risk on finance debt
132
132
Interest rate and foreign currency risk on
finance debt
1,614
1,819
1,346
1,627
1,047
6,521
1,913
15,887
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
4.84%
5.64%
5.45%
6.34%
Sterling/US dollar
1.28
1.28
Euro/US dollar
1.13
1.13
Hong Kong dollar/US dollar
0.13
Canadian dollar/US dollar
0.78
Australian dollar/ US dollar
0.67
0.67
Japanese Yen/ US dollar
0.01
0.01
Swiss Franc/US dollar
1.18
1.18
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
(149)
1
(85)
Interest rate and foreign currency risk on finance debt
(16,281)
1,201
(35)
134
At 31 December 2024
Fair value hedges
Interest rate risk on finance debt
(156)
3
(160)
Interest rate and foreign currency risk on finance debt
(16,295)
1,017
143
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
NavigtionTabCornerV1.jpg
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
3
(2)
(186)
(185)
Recognized in other comprehensive income
Cash flow hedges marked to market
5
287
292
Cash flow hedges reclassified to the income statement - hedged item affected profit
or loss
(127)
(127)
Costs of hedging marked to market
27
27
Costs of hedging reclassified to the income statement
34
34
5
160
61
226
Cash flow hedges transferred to the balance sheet
(6)
(6)
At 31 December 2025
2
158
(125)
35
$ 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
14
529
(182)
361
Recognized in other comprehensive income
Cash flow hedges marked to market
(1)
155
154
Cash flow hedges reclassified to the income statement - hedged item affected profit
or loss
(686)
(686)
Costs of hedging marked to market
(2)
(2)
Costs of hedging reclassified to the income statement
(2)
(2)
(1)
(531)
(4)
(536)
Cash flow hedges transferred to the balance sheet
(10)
(10)
At 31 December 2024
3
(2)
(186)
(185)
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
The allotted, called up and fully paid share capital at 31 December was as follows:
2025
2024
2023
Issued
Shares
thousand
$ million
Shares
thousand
$ million
Shares
thousand
$ million
8% cumulative first preference shares of £1 eacha
7,233
12
7,233
12
7,233
12
9% cumulative second preference shares of £1 eacha
5,473
9
5,473
9
5,473
9
21
21
21
Ordinary shares of 25 cents each
At 1 January
16,662,465
4,165
17,900,800
4,475
19,097,783
4,774
Issue of new shares for employee share-based payment plans
66,000
17
Repurchase of ordinary share capital
(835,649)
(209)
(1,238,335)
(310)
(1,262,983)
(316)
Repurchases transferred to treasury shares
659,497
165
At 31 December
16,486,313
4,121
16,662,465
4,165
17,900,800
4,475
4,142
4,186
4,496
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.
Treasury sharesa
2025
2024
2023
Shares
thousand
Nominal value
$ million
Shares
thousand
Nominal value
$ million
Shares
thousand
Nominal value
$ million
At 1 January
812,021
204
1,077,079
271
1,124,927
281
Purchases for settlement of employee share plans
660,765
165
8,302
2
24,688
6
Issue of new shares for employee share-based payment plans
71,039
19
Shares re-issued for employee share-based payment plans
(363,198)
(92)
(273,360)
(69)
(143,575)
(35)
At 31 December
1,109,588
277
812,021
204
1,077,079
271
Of which – shares held in treasury by bp
857,433
214
481,474
121
726,339
183
– shares held in ESOP trusts
252,118
63
330,510
83
350,704
88
– shares held by bp’s US share plan administratorb
37
37
36
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
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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
4,186
14,031
2,806
27,206
48,229
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
(44)
44
Share-based payments, net of taxb
35
35
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
4,142
14,066
2,850
27,206
48,264
At 1 January 2024
4,496
13,815
2,496
27,206
48,013
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
(310)
310
Share-based payments, net of taxb
216
216
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
4,186
14,031
2,806
27,206
48,229
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
NavigtionTabCornerV1.jpg
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
(9,030)
(2,196)
(3)
(98)
(187)
(288)
22,531
59,246
16,649
2,423
78,318
55
55
799
441
1,295
1,804
1
1
1,805
115
1,920
122
61
183
183
183
(4)
(4)
(4)
(166)
(166)
(166)
(6)
(6)
(6)
(6)
5
5
5
5
1,804
(5)
127
61
183
(115)
1,872
799
556
3,227
(5,087)
(5,087)
(524)
(5,611)
(6)
(6)
(6)
(6)
(3,558)
(454)
(4,012)
(4,012)
3,917
(2,840)
1,112
1,112
1
1
1
500
500
(1,200)
(1,200)
(9)
(9)
(793)
(802)
(65)
(65)
2,538
2,473
(8,671)
(401)
(8)
23
(126)
(111)
13,971
53,052
15,955
4,993
74,000
(11,323)
(1,920)
38
319
(183)
174
35,339
70,283
13,566
1,644
85,493
381
381
641
207
1,229
(276)
(1)
(1)
(277)
(87)
(364)
(406)
(4)
(410)
(410)
(410)
(12)
(12)
(12)
(1)
(1)
(1)
367
367
367
(40)
(40)
(40)
(40)
(1)
(1)
(1)
(1)
(276)
(41)
(407)
(4)
(452)
735
7
641
120
768
(5,018)
(5,018)
(375)
(5,393)
(10)
(10)
(10)
(10)
(7,302)
(7,302)
(7,302)
2,293
(1,426)
1,083
1,083
(22)
(22)
4,352
4,330
9
9
(1,300)
(1,291)
(610)
(610)
216
216
1,034
1,250
(9,030)
(2,196)
(3)
(98)
(187)
(288)
22,531
59,246
16,649
2,423
78,318
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
4,795
13,692
2,180
27,206
47,873
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
(316)
316
Share-based payments, net of taxa
17
123
140
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
4,496
13,815
2,496
27,206
48,013
aMovements in treasury shares relate to employee share-based payment plans.
bp Annual Report and Form 20-F 2025
233
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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
(12,153)
(2,643)
(183)
(73)
(256)
34,732
67,553
13,390
2,047
82,990
15,239
15,239
586
55
15,880
728
728
26
754
488
(110)
378
378
378
(192)
(192)
(192)
(1,504)
(1,504)
(1,504)
38
38
38
38
15
15
15
15
728
38
503
(110)
431
13,543
14,702
586
81
15,369
(4,831)
(4,831)
(403)
(5,234)
(1)
(1)
(1)
(1)
(8,167)
(8,167)
(8,167)
830
(301)
669
669
1
1
1
(1)
(1)
176
175
(5)
(5)
(586)
(591)
363
363
(81)
282
(11,323)
(1,920)
38
319
(183)
174
35,339
70,283
13,566
1,644
85,493
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
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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).
The pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below.
$ million
2025
Pre-tax
Tax
Net of tax
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including reclassifications)
1,904
16
1,920
Cash flow hedges (including reclassifications)
160
(38)
122
Costs of hedging (including reclassifications)
61
61
Share of items relating to equity-accounted entities, net of tax
(4)
(4)
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-employment benefit liability or asset
(221)
55
(166)
Remeasurements of equity investments
(6)
(6)
Cash flow hedges that will subsequently be transferred to the balance sheet
5
5
Other comprehensive income
1,899
33
1,932
$ million
2024
Pre-tax
Tax
Net of tax
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including reclassifications)
(288)
(76)
(364)
Cash flow hedges (including reclassifications)
(531)
125
(406)
Costs of hedging (including reclassifications)
(4)
(4)
Share of items relating to equity-accounted entities, net of tax
(12)
(12)
Other
(1)
(1)
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-employment benefit liability or asseta
(360)
727
367
Remeasurements of equity investments
(47)
7
(40)
Cash flow hedges that will subsequently be transferred to the balance sheet
(1)
(1)
Other comprehensive income
(1,243)
782
(461)
$ million
2023
Pre-tax
Tax
Net of tax
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including reclassifications)
583
171
754
Cash flow hedges (including reclassifications)
637
(149)
488
Costs of hedging (including reclassifications)
(78)
(32)
(110)
Share of items relating to equity-accounted entities, net of tax
(192)
(192)
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-employment benefit liability or asset
(2,262)
758
(1,504)
Remeasurements of equity investments
51
(13)
38
Cash flow hedges that will subsequently be transferred to the balance sheet
15
15
Other comprehensive income
(1,246)
735
(511)
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
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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
Six coastal parishes and the State of Louisiana have filed over 40 separate lawsuits in state courts in Louisiana against various oil and gas
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
actions vigorously.
238
bp Annual Report and Form 20-F 2025
34. Remuneration of senior management and non-executive directors
Remuneration of directors
$ million
2025
2024
2023
Total for all directors
Emoluments
11
8
8
Amounts received under incentive schemesa
3
5
6
Total
14
13
14
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.
Remuneration of directors and senior management
$ million
2025
2024
2023
Total for all senior management and non-executive directors
Short-term employee benefits
34
22
31
Pensions and other post-employment benefits
Share-based paymentsa
28
26
12
Termination benefits
3
Total
62
51
43
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
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Financial statements
35. Employee costs and numbers
$ million
Employee costs
2025
2024
2023
Wages and salariesa
9,295
8,601
7,835
Social security costs
1,166
1,032
943
Share-based paymentsb
847
1,088
1,131
Pension and other post-employment benefit costs
448
519
370
11,756
11,240
10,279
2025
2024
2023
Average number of employeesc
US
Non-US
Total
US
Non-US
Total
US
Non-US
Total
gas & low carbon energy
1,000
5,200
6,200
900
4,400
5,300
900
3,700
4,600
oil production & operations
3,300
6,000
9,300
3,300
5,700
9,000
3,100
5,500
8,600
customers & productsd e
27,100
43,700
70,800
27,500
38,000
65,500
19,500
36,300
55,800
other businesses and corporate
1,200
10,700
11,900
1,400
9,800
11,200
1,400
9,000
10,400
32,600
65,600
98,200
33,100
57,900
91,000
24,900
54,500
79,400
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
42
40
38
The audit of accounts of subsidiaries of the company
17
17
15
Total audit
59
57
53
Audit-related assurance servicesb
5
4
4
Total audit and audit-related assurance services
64
61
57
Non-audit and other assurance services
9
4
3
Services relating to bp pension plans
1
1
1
74
66
61
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
The more important subsidiaries, joint arrangements and associates of the group at 31 December 2025 and the group percentage of ordinary share
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
100
England & Wales
Investment holding
BP Exploration Operating Company Limited
100
England & Wales
Exploration and production
*BP Gamma Holdings Limited
100
England & Wales
Investment holding
*BP Global Investments Limited
100
England & Wales
Investment holding
*BP International Limited
100
England & Wales
Integrated oil operations
BP Oil International Limited
100
England & Wales
Integrated oil operations
*Castrol Group Holdings Limited
100
Scotland
Investment holding
Azerbaijan
BP Exploration (Caspian Sea) Limited
100
England & Wales
Exploration and production
BP Exploration (Azerbaijan) Limited
100
England & Wales
Exploration and production
Germany
BP Europa SE
100
Germany
Refining and marketing
Trinidad and Tobago
BP Trinidad and Tobago LLC
70
US
Exploration and production
UK
BP Capital Markets p.l.c.
100
England & Wales
Finance
Lightsource BP Renewable Energy Investments Limited
100
England & Wales
Onshore renewables
US
*BP Holdings North America Limited
100
England & Wales
Investment holding
Atlantic Richfield Company
100
US
Exploration and production, refining and
marketing
BP America Inc.
100
US
BP America Production Company
100
US
BP Company North America Inc.
100
US
BP Corporation North America Inc.
100
US
BP Products North America Inc.
100
US
The Standard Oil Company
100
US
Archaea Energy Inc.
100
US
Bioenergy
BP Capital Markets America Inc.
100
US
Finance
Joint arrangements
%
Country of
incorporation
Principal activities
Angola
Azule Energy Holdings Limited
50
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
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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
NavigtionTabCornerV1.jpg
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
NavigtionTabCornerV1.jpg
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.
fSouth America third parties sales and sales between businesses split has been restated.
gAfrica other costs (income) have been restated and consequently the allocable taxes.
246
bp Annual Report and Form 20-F 2025
Oil and natural gas exploration and production activities – continued
$ million
2023
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
29,127
70,404
6
17,475
20,763
41,351
6,331
185,457
Unproved properties
369
3,057
1,917
2,565
2,739
1,691
737
13,075
29,496
73,461
1,923
20,040
23,502
43,042
7,068
198,532
Accumulated depreciation
22,018
42,364
1,592
15,712
21,132
24,431
4,998
132,247
Net capitalized costs
7,478
31,097
331
4,328
2,370
18,611
2,070
66,285
Costs incurred for the year ended 31 Decembera b
Acquisition of properties
Proved
13
13
Unproved
51
2
6
59
64
2
6
72
Exploration and appraisal costsc
123
356
123
114
270
145
100
1,231
Development
484
4,690
713
863
1,424
32
8,206
Total costs
607
5,110
123
829
1,139
1,569
132
9,509
Results of operations for the year ended 31 Decembera
Sales and other operating revenuesd
Third parties
206
665
1,348
3,227
4,801
1,765
12,012
Sales between businesses
3,483
12,705
20
22
7,731
412
24,373
3,689
13,370
1,368
3,249
12,532
2,177
36,385
Exploration expenditure
46
348
93
54
413
25
18
997
Production costs
477
2,382
2
360
232
588
111
4,152
Production taxes
13
136
229
1,357
44
1,779
Other costs (income)e
(171)
2,144
13
115
304
(35)
145
2,515
Depreciation, depletion and amortization
1,063
3,532
1,351
1,546
2,844
412
10,748
Net impairments and (gains) losses on sale of
businesses and fixed assets
819
(18)
701
(100)
671
1,430
(1)
(4)
3,498
2,247
(18)
9,243
8
2,780
3,925
4,778
726
23,689
Profit (loss) before taxationf
1,442
18
4,127
(8)
(1,412)
(676)
7,754
1,451
12,696
Allocable taxes
365
19
889
(3)
(565)
439
5,317
451
6,912
Results of operations
1,077
(1)
3,238
(5)
(847)
(1,115)
2,437
1,000
5,784
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 $287-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 $390 million which is included in finance costs in the group income statement.
bp Annual Report and Form 20-F 2025
247
NavigtionTabCornerV1.jpg
Financial statements
Oil and natural gas exploration and production activities – continued
$ million
2023
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
4,432
12,530
8,590
9,947
35,499
Unproved properties
652
125
372
1,149
5,084
12,655
8,962
9,947
36,648
Accumulated depreciation
2,420
6,807
1,812
1,696
12,735
Net capitalized costs
2,664
5,848
7,150
8,251
23,913
Costs incurred for the year ended 31 Decembera c d
Acquisition of propertiesb
Proved
Unproved
Exploration and appraisal costsc
42
7
44
93
Development
584
687
844
942
3,057
Total costs
626
694
888
942
3,150
Results of operations for the year ended 31 Decembera
Sales and other operating revenuese
Third partiesf
2,159
963
2,550
1,716
7,388
Sales between businessesf
1,107
1,107
 
2,159
2,070
2,550
1,716
8,495
Exploration expenditure
41
44
85
Production costs
169
715
427
374
1,685
Production taxes
332
52
384
Other costs (income)g
21
257
42
8
328
Depreciation, depletion and amortization
455
451
1,344
1,144
3,394
Net impairments and losses on sale of businesses and
fixed assets
141
15
156
 
827
1,755
1,924
1,526
6,032
Profit (loss) before taxation
1,332
315
626
190
2,463
Allocable taxesg
1,124
127
280
117
1,648
Results of operations
208
188
346
73
815
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.
fSouth America third parties sales and sales between businesses split has been restated.
gAfrica other costs (income) have been restated and consequently the allocable taxes.
248
bp Annual Report and Form 20-F 2025
Movements in estimated net proved reserves
million barrels
Crude oila b
2025
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
At 1 January
Developed
104
653
1
1
716
9
1,483
Undeveloped
63
472
4
305
1
846
167
1,125
5
1
1,021
10
2,329
Changes attributable to
Revisions of previous estimates
(40)
39
2
3
75
1
80
Improved recovery
13
13
Purchases of reserves-in-place
40
40
Discoveries and extensions
1
1
3
5
Production
(29)
(146)
(2)
(3)
(110)
(3)
(292)
Sales of reserves-in-place
(1)
(31)
(33)
(70)
(84)
1
(32)
(2)
(186)
At 31 Decemberc
Developed
56
599
1
2
691
6
1,354
Undeveloped
41
443
4
298
3
788
97
1,042
6
2
989
8
2,143
Equity-accounted entities (bp share)d
At 1 January
Developed
76
10
271
94
107
558
Undeveloped
42
217
77
3
339
118
10
488
170
110
896
Changes attributable to
Revisions of previous estimates
14
(40)
21
35
30
Improved recovery
1
3
4
Purchases of reserves-in-place
Discoveries and extensions
4
29
1
34
Production
(20)
(1)
(19)
(29)
(29)
(98)
Sales of reserves-in-place
(1)
(1)
(3)
(1)
(26)
(7)
6
(31)
At 31 December
Developed
70
9
278
97
113
566
Undeveloped
45
184
67
4
299
115
9
461
163
117
865
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
104
76
653
10
271
95
823
9
2,041
Undeveloped
63
42
472
221
77
308
1
1,184
167
118
1,125
10
493
171
1,131
10
3,225
At 31 December
Developed
56
70
599
9
279
98
804
6
1,920
Undeveloped
41
45
443
188
67
302
3
1,088
97
115
1,042
9
467
165
1,105
8
3,008
aCrude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying
production and the option and ability to make lifting and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
cIncludes 1.7 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
dVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
bp Annual Report and Form 20-F 2025
249
NavigtionTabCornerV1.jpg
Financial statements
Movements in estimated net proved reserves – continued
million barrels
Natural gas liquidsa b
2025
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
At 1 January
Developed
2
202
1
1
206
Undeveloped
246
246
3
447
1
1
452
Changes attributable to
Revisions of previous estimates
1
(1)
2
1
Improved recovery
1
1
Purchases of reserves-in-place
25
25
Discoveries and extensions
Productionc
(1)
(41)
(2)
(45)
Sales of reserves-in-place
(1)
(16)
(17)
(1)
(32)
(1)
(35)
At 31 December
Developed
1
204
1
206
Undeveloped
212
212
1
415
1
417
Equity-accounted entities (bp share)d
At 1 January
Developed
3
3
10
16
Undeveloped
5
6
8
4
10
22
Changes attributable to
Revisions of previous estimates
1
2
3
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
(1)
(2)
(3)
Sales of reserves-in-place
At 31 December
Developed
3
4
10
17
Undeveloped
5
5
8
4
10
22
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
2
3
202
4
10
1
222
Undeveloped
5
246
252
3
8
447
4
10
1
474
At 31 December
Developed
1
3
204
4
10
1
222
Undeveloped
5
212
217
1
8
415
4
10
1
439
aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
cExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
dVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
250
bp Annual Report and Form 20-F 2025
Movements in estimated net proved reserves – continued
million barrels
Total liquidsa b
2025
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
At 1 January
Developed
106
855
1
1
716
10
1,689
Undeveloped
63
718
4
305
1
1,092
169
1,573
6
1
1,021
11
2,781
Changes attributable to
Revisions of previous estimates
(40)
37
4
3
75
1
81
Improved recovery
14
14
Purchases of reserves-in-place
65
65
Discoveries and extensions
2
1
3
6
Productionc
(30)
(186)
(4)
(3)
(110)
(3)
(337)
Sales of reserves-in-place
(2)
(48)
(49)
(72)
(116)
(32)
(2)
(221)
At 31 Decemberd
Developed
57
802
1
2
691
7
1,560
Undeveloped
41
655
4
298
3
1,000
98
1,457
5
2
989
9
2,560
Equity-accounted entities (bp share)e
At 1 January
Developed
78
10
274
103
107
573
Undeveloped
47
217
77
3
344
125
10
491
180
110
918
Changes attributable to
Revisions of previous estimates
14
(39)
22
35
33
Improved recovery
1
3
4
Purchases of reserves-in-place
Discoveries and extensions
4
29
1
34
Production
(21)
(1)
(19)
(31)
(29)
(101)
Sales of reserves-in-place
(1)
(1)
(3)
(1)
(26)
(7)
6
(31)
At 31 December
Developed
73
9
282
106
113
582
Undeveloped
50
184
67
4
304
123
9
465
173
117
887
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
106
78
855
10
275
105
823
10
2,263
Undeveloped
63
47
718
222
77
308
1
1,436
169
125
1,573
10
497
182
1,131
11
3,699
At 31 December
Developed
57
73
802
9
283
108
804
7
2,143
Undeveloped
41
50
655
188
67
302
3
1,304
98
123
1,457
9
471
175
1,105
9
3,447
aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
cExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
dAlso includes 1.7 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
eVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
bp Annual Report and Form 20-F 2025
251
NavigtionTabCornerV1.jpg
Financial statements
Movements in estimated net proved reserves – continued
billion cubic feet
Natural gasa b
2025
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
At 1 January
Developed
162
2,600
379
161
3,026
1,254
7,582
Undeveloped
29
2,412
350
1,320
431
4,542
190
5,012
730
161
4,346
1,685
12,124
Changes attributable to
Revisions of previous estimates
24
2,419
257
74
172
51
2,996
Improved recovery
8
8
Purchases of reserves-in-place
208
208
Discoveries and extensions
1
170
65
111
2
349
Productionc
(84)
(664)
(385)
(177)
(602)
(293)
(2,205)
Sales of reserves-in-place
(42)
(93)
(135)
(102)
1,878
41
(38)
(318)
(240)
1,220
At 31 Decemberd
Developed
76
3,009
413
123
2,660
947
7,227
Undeveloped
12
3,881
358
1,368
498
6,117
88
6,890
771
123
4,028
1,445
13,344
Equity-accounted entities (bp share)e
At 1 January
Developed
49
4
1,053
536
43
1,686
Undeveloped
111
651
215
976
160
4
1,704
751
43
2,662
Changes attributable to
Revisions of previous estimates
17
(36)
48
(1)
27
Improved recovery
1
1
2
Purchases of reserves-in-place
Discoveries and extensions
2
141
2
145
Productionc
(21)
(126)
(113)
(3)
(263)
Sales of reserves-in-place
(1)
(1)
(2)
(1)
(20)
(64)
(4)
(90)
At 31 December
Developed
51
4
1,000
516
39
1,610
Undeveloped
108
684
171
962
158
4
1,684
687
39
2,572
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
162
49
2,600
4
1,433
697
3,070
1,254
9,268
Undeveloped
29
111
2,412
1,001
215
1,320
431
5,518
190
160
5,012
4
2,434
911
4,390
1,685
14,786
At 31 December
Developed
76
51
3,009
4
1,413
639
2,699
947
8,837
Undeveloped
12
108
3,881
1,042
171
1,368
498
7,079
88
158
6,890
4
2,455
810
4,067
1,445
15,916
aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
cIncludes 114 billion cubic feet of natural gas consumed in operations, 71 billion cubic feet in subsidiaries, 43 billion cubic feet in equity-accounted entities.
dIncludes 231 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
eVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
252
bp Annual Report and Form 20-F 2025
Movements in estimated net proved reserves – continued
million barrels of oil equivalentc
Total hydrocarbonsa b
2025
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
At 1 January
Developed
134
1,303
67
29
1,237
226
2,997
Undeveloped
68
1,134
65
533
76
1,875
202
2,437
131
29
1,770
302
4,871
Changes attributable to
Revisions of previous estimates
(36)
454
48
15
105
10
597
Improved recovery
15
15
Purchases of reserves-in-place
101
101
Discoveries and extensions
2
29
12
22
66
Productiond e
(44)
(301)
(71)
(34)
(214)
(54)
(717)
Sales of reserves-in-place
(9)
(64)
(73)
(89)
208
7
(6)
(87)
(43)
(10)
At 31 Decemberf
Developed
70
1,321
73
23
1,150
170
2,806
Undeveloped
43
1,324
66
534
88
2,055
113
2,645
138
23
1,683
258
4,861
Equity-accounted entities (bp share)g
At 1 January
Developed
87
11
456
196
115
864
Undeveloped
66
330
114
3
513
153
11
785
310
118
1,377
Changes attributable to
Revisions of previous estimates
17
(45)
31
35
37
Improved recovery
2
3
5
Purchases of reserves-in-place
Discoveries and extensions
4
53
1
59
Productione
(25)
(1)
(41)
(50)
(29)
(146)
Sales of reserves-in-place
(1)
(1)
(3)
(1)
(29)
(18)
6
(47)
At 31 December
Developed
81
10
454
195
120
860
Undeveloped
68
302
96
4
470
150
10
756
292
123
1,330
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
134
87
1,303
11
522
225
1,352
226
3,860
Undeveloped
68
66
1,134
394
114
535
76
2,387
202
153
2,437
11
917
339
1,888
302
6,248
At 31 December
Developed
70
81
1,321
10
527
218
1,269
170
3,666
Undeveloped
43
68
1,324
367
96
537
88
2,525
113
150
2,645
10
894
315
1,807
258
6,191
aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
c5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
dExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
eIncludes 20 million barrels of oil equivalent of natural gas consumed in operations, 12 million barrels of oil equivalent in subsidiaries, 7 million barrels of oil equivalent in equity-accounted entities.
fIncludes 41 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
gVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
bp Annual Report and Form 20-F 2025
253
NavigtionTabCornerV1.jpg
Financial statements
Movements in estimated net proved reserves – continued
million barrels
Crude oila b
2024
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
At 1 January
Developed
129
713
3
5
729
11
1,590
Undeveloped
74
352
5
323
1
755
203
1,065
7
6
1,052
12
2,345
Changes attributable to
Revisions of previous estimates
(12)
54
2
5
77
1
128
Improved recovery
2
2
Purchases of reserves-in-place
1
1
2
Discoveries and extensions
143
143
Production
(25)
(138)
(2)
(7)
(109)
(3)
(284)
Sales of reserves-in-place
(1)
(3)
(4)
(7)
(36)
61
(2)
(5)
(31)
(2)
(16)
At 31 Decemberc
Developed
104
653
1
1
716
9
1,483
Undeveloped
63
472
4
305
1
846
167
1,125
5
1
1,021
10
2,329
Equity-accounted entities (bp share)d
At 1 January
Developed
89
11
275
99
115
588
Undeveloped
45
253
88
2
387
133
11
528
187
117
976
Changes attributable to
Revisions of previous estimates
4
(25)
10
19
8
Improved recovery
1
1
Purchases of reserves-in-place
5
5
Discoveries and extensions
18
18
Production
(21)
(1)
(20)
(30)
(25)
(97)
Sales of reserves-in-place
(14)
(15)
(16)
(1)
(41)
(16)
(6)
(80)
At 31 December
Developed
76
10
271
94
107
558
Undeveloped
42
217
77
3
339
118
10
488
170
110
896
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
129
89
713
11
278
104
844
11
2,179
Undeveloped
74
45
352
258
88
324
1
1,142
203
133
1,065
11
536
192
1,168
12
3,321
At 31 December
Developed
104
76
653
10
271
95
823
9
2,041
Undeveloped
63
42
472
221
77
308
1
1,184
167
118
1,125
10
493
171
1,131
10
3,225
aCrude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying
production and the option and ability to make lifting and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
cIncludes 1.5 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
dVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
254
bp Annual Report and Form 20-F 2025
Movements in estimated net proved reserves – continued
million barrels
Natural gas liquidsa b
2024
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
At 1 January
Developed
3
180
1
184
Undeveloped
217
217
3
397
1
401
Changes attributable to
Revisions of previous estimates
89
2
1
93
Improved recovery
Purchases of reserves-in-place
1
1
Discoveries and extensions
4
4
Productionc
(1)
(39)
(2)
(1)
(43)
Sales of reserves-in-place
(4)
(4)
(1)
51
51
At 31 Decemberd
Developed
2
202
1
1
206
Undeveloped
246
246
3
447
1
1
452
Equity-accounted entities (bp share)e
At 1 January
Developed
3
3
14
19
Undeveloped
5
1
6
8
4
14
25
Changes attributable to
Revisions of previous estimates
1
(2)
(1)
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
(1)
(2)
(3)
Sales of reserves-in-place
(4)
(4)
At 31 December
Developed
3
3
10
16
Undeveloped
5
6
8
4
10
22
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
3
3
180
3
14
1
204
Undeveloped
5
217
1
223
3
8
397
4
14
1
427
At 31 December
Developed
2
3
202
4
10
1
222
Undeveloped
5
246
252
3
8
447
4
10
1
474
aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
cExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
dIncludes 0.2 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
eVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
bp Annual Report and Form 20-F 2025
255
NavigtionTabCornerV1.jpg
Financial statements
Movements in estimated net proved reserves – continued
million barrels
Total liquidsa b
2024
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
At 1 January
Developed
132
893
3
6
729
11
1,775
Undeveloped
75
568
5
323
1
971
207
1,462
7
6
1,052
13
2,746
Changes attributable to
Revisions of previous estimates
(11)
144
4
6
77
2
221
Improved recovery
2
2
Purchases of reserves-in-place
1
1
1
3
Discoveries and extensions
146
147
Productionc
(27)
(177)
(3)
(7)
(109)
(4)
(326)
Sales of reserves-in-place
(5)
(3)
(4)
(11)
(37)
111
(2)
(5)
(31)
(1)
35
At 31 Decemberd
Developed
106
855
1
1
716
10
1,689
Undeveloped
63
718
4
305
1
1,092
169
1,573
6
1
1,021
11
2,781
Equity-accounted entities (bp share)e
At 1 January
Developed
92
11
278
113
115
608
Undeveloped
49
254
88
2
393
141
11
532
200
117
1,001
Changes attributable to
Revisions of previous estimates
5
(25)
8
19
8
Improved recovery
1
1
Purchases of reserves-in-place
5
5
Discoveries and extensions
18
18
Production
(22)
(1)
(20)
(32)
(25)
(100)
Sales of reserves-in-place
(14)
(15)
(16)
(1)
(41)
(20)
(6)
(84)
At 31 December
Developed
78
10
274
103
107
573
Undeveloped
47
217
77
3
344
125
10
491
180
110
918
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
132
92
893
11
281
118
844
11
2,382
Undeveloped
75
49
568
259
88
324
1
1,365
207
141
1,462
11
540
206
1,168
13
3,747
At 31 December
Developed
106
78
855
10
275
105
823
10
2,263
Undeveloped
63
47
718
222
77
308
1
1,436
169
125
1,573
10
497
182
1,131
11
3,699
aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
cExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
dAlso includes 1.7 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
eVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
256
bp Annual Report and Form 20-F 2025
Movements in estimated net proved reserves – continued
billion cubic feet
Natural gasa b
2024
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
At 1 January
Developed
221
2,672
931
518
3,051
1,550
8,942
Undeveloped
34
3,229
503
207
1,672
358
6,003
255
5,901
1,434
724
4,722
1,907
14,944
Changes attributable to
Revisions of previous estimates
12
(241)
(174)
133
237
(40)
(73)
Improved recovery
1
1
Purchases of reserves-in-place
3
34
46
83
Discoveries and extensions
32
8
11
142
193
Productionc
(80)
(639)
(423)
(340)
(625)
(325)
(2,432)
Sales of reserves-in-place
(76)
(115)
(402)
(594)
(65)
(889)
(704)
(564)
(376)
(222)
(2,821)
At 31 Decemberd
Developed
162
2,600
379
161
3,026
1,254
7,582
Undeveloped
29
2,412
350
1,320
431
4,542
190
5,012
730
161
4,346
1,685
12,124
Equity-accounted entities (bp share)e
At 1 January
Developed
67
4
1,027
463
46
1,608
Undeveloped
110
621
188
919
177
4
1,648
651
46
2,527
Changes attributable to
Revisions of previous estimates
1
(32)
(59)
(89)
Improved recovery
2
2
Purchases of reserves-in-place
205
205
Discoveries and extensions
221
221
Productionc
(20)
(129)
(46)
(2)
(199)
Sales of reserves-in-place
(4)
(5)
(18)
56
100
(2)
135
At 31 December
Developed
49
4
1,053
536
43
1,686
Undeveloped
111
651
215
976
160
4
1,704
751
43
2,662
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
221
67
2,672
4
1,958
981
3,096
1,550
10,549
Undeveloped
34
110
3,229
1,125
394
1,672
358
6,922
255
177
5,901
4
3,082
1,375
4,768
1,907
17,471
At 31 December
Developed
162
49
2,600
4
1,433
697
3,070
1,254
9,268
Undeveloped
29
111
2,412
1,001
215
1,320
431
5,518
190
160
5,012
4
2,434
911
4,390
1,685
14,786
aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
cIncludes 100 billion cubic feet of natural gas consumed in operations, 62 billion cubic feet in subsidiaries, 38 billion cubic feet in equity-accounted entities.
dIncludes 219 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
eVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
bp Annual Report and Form 20-F 2025
257
NavigtionTabCornerV1.jpg
Financial statements
Movements in estimated net proved reserves – continued
million barrels of oil equivalentc
Total hydrocarbonsa b
2024
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
At 1 January
Developed
170
1,354
163
95
1,255
279
3,316
Undeveloped
81
1,125
91
36
611
63
2,006
251
2,479
255
131
1,866
341
5,323
Changes attributable to
Revisions of previous estimates
(9)
102
(26)
28
118
(5)
208
Improved recovery
2
2
Purchases of reserves-in-place
1
7
9
17
Discoveries and extensions
152
1
2
25
180
Productiond e
(41)
(287)
(76)
(66)
(216)
(60)
(746)
Sales of reserves-in-place
(18)
(22)
(73)
(113)
(49)
(42)
(123)
(102)
(96)
(40)
(451)
At 31 Decemberf
Developed
134
1,303
67
29
1,237
226
2,997
Undeveloped
68
1,134
65
533
76
1,875
202
2,437
131
29
1,770
302
4,871
Equity-accounted entities (bp share)g
At 1 January
Developed
103
12
455
192
123
885
Undeveloped
68
361
120
2
552
172
12
816
313
124
1,437
Changes attributable to
Revisions of previous estimates
5
(30)
(2)
19
(8)
Improved recovery
1
1
Purchases of reserves-in-place
40
40
Discoveries and extensions
56
56
Productione
(26)
(1)
(42)
(40)
(26)
(135)
Sales of reserves-in-place
(15)
(16)
(19)
(1)
(31)
(3)
(7)
(60)
At 31 December
Developed
87
11
456
196
115
864
Undeveloped
66
330
114
3
513
153
11
785
310
118
1,377
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
170
103
1,354
12
618
287
1,378
279
4,201
Undeveloped
81
68
1,125
453
156
613
63
2,558
251
172
2,479
12
1,071
444
1,991
341
6,759
At 31 December
Developed
134
87
1,303
11
522
225
1,352
226
3,860
Undeveloped
68
66
1,134
394
114
535
76
2,387
202
153
2,437
11
917
339
1,888
302
6,248
aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
c5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
dExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
eIncludes 17 million barrels of oil equivalent of natural gas consumed in operations, 11 million barrels of oil equivalent in subsidiaries, 6 million barrels of oil equivalent in equity-accounted entities.
fIncludes 41 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
gVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
258
bp Annual Report and Form 20-F 2025
Movements in estimated net proved reserves – continued
million barrels
Crude oila b
2023
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
At 1 January
Developed
153
679
4
24
717
20
1,596
Undeveloped
109
527
5
2
356
1
1,000
 
261
1,206
9
26
1,073
21
2,596
Changes attributable to
Revisions of previous estimates
(32)
(60)
(1)
(3)
85
(6)
(15)
Improved recovery
14
14
Purchases of reserves-in-place
14
14
Discoveries and extensions
17
1
18
Production
(27)
(123)
(1)
(11)
(107)
(4)
(274)
Sales of reserves-in-place
(1)
(6)
(7)
 
(58)
(141)
(2)
(20)
(21)
(9)
(252)
At 31 Decemberc
Developed
129
713
3
5
729
11
1,590
Undeveloped
74
352
5
323
1
755
 
203
1,065
7
6
1,052
12
2,345
Equity-accounted entities (bp share)d
At 1 January
Developed
90
5
276
127
95
592
Undeveloped
16
7
244
74
1
342
 
106
12
520
201
96
935
Changes attributable to
Revisions of previous estimates
6
7
15
43
71
Improved recovery
21
4
24
Purchases of reserves-in-place
Discoveries and extensions
22
19
41
Production
(22)
(1)
(20)
(30)
(23)
(95)
Sales of reserves-in-place
 
27
(1)
9
(14)
20
41
At 31 December
Developed
89
11
275
99
115
588
Undeveloped
45
253
88
2
387
 
133
11
528
187
117
976
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
153
90
679
5
279
151
812
20
2,188
Undeveloped
109
16
527
7
249
76
358
1
1,343
 
261
106
1,206
12
529
227
1,169
21
3,531
At 31 December
Developed
129
89
713
11
278
104
844
11
2,179
Undeveloped
74
45
352
258
88
324
1
1,142
 
203
133
1,065
11
536
192
1,168
12
3,321
aCrude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying
production and the option and ability to make lifting and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
cIncludes 2.2 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
dVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
bp Annual Report and Form 20-F 2025
259
NavigtionTabCornerV1.jpg
Financial statements
Movements in estimated net proved reserves – continued
million barrels
Natural gas liquidsa b
2023
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
At 1 January
Developed
6
181
1
6
1
196
Undeveloped
236
1
237
6
417
1
7
1
432
Changes attributable to
Revisions of previous estimates
(1)
(14)
1
(14)
Improved recovery
15
16
Purchases of reserves-in-place
12
12
Discoveries and extensions
Productionc
(2)
(31)
(1)
(1)
(1)
(35)
Sales of reserves-in-place
(3)
(6)
(9)
(3)
(20)
(1)
(7)
(31)
At 31 Decemberd
Developed
3
180
1
184
Undeveloped
217
217
 
3
397
1
401
Equity-accounted entities (bp share)e
At 1 January
Developed
4
3
17
23
Undeveloped
1
9
10
 
4
4
26
34
Changes attributable to
Revisions of previous estimates
1
(11)
(10)
Improved recovery
1
1
Purchases of reserves-in-place
Discoveries and extensions
4
4
Production
(1)
(1)
(3)
Sales of reserves-in-place
 
4
(12)
(8)
At 31 December
Developed
3
3
14
19
Undeveloped
5
1
6
 
8
4
14
25
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
6
4
181
4
23
1
219
Undeveloped
236
1
10
247
 
6
4
417
5
33
1
466
At 31 December
Developed
3
3
180
3
14
1
204
Undeveloped
5
217
1
223
 
3
8
397
4
14
1
427
aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
cExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
dIncludes 0 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
260
bp Annual Report and Form 20-F 2025
Movements in estimated net proved reserves – continued
million barrels
Total liquidsa b
2023
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
At 1 January
Developed
159
860
5
30
717
20
1,791
Undeveloped
109
763
5
3
356
1
1,237
267
1,623
11
33
1,073
22
3,029
Changes attributable to
Revisions of previous estimates
(33)
(74)
(1)
(3)
85
(5)
(30)
Improved recovery
29
29
Purchases of reserves-in-place
25
25
Discoveries and extensions
17
1
18
Productionc
(29)
(154)
(3)
(12)
(107)
(4)
(309)
Sales of reserves-in-place
(4)
(12)
(17)
(61)
(161)
(3)
(27)
(21)
(9)
(283)
At 31 Decemberd
Developed
132
893
3
6
729
11
1,775
Undeveloped
75
568
5
323
1
971
207
1,462
7
6
1,052
13
2,746
Equity-accounted entities (bp share)e
At 1 January
Developed
94
5
278
144
95
616
Undeveloped
16
7
245
83
1
352
110
12
523
227
96
968
Changes attributable to
Revisions of previous estimates
6
7
4
43
61
Improved recovery
22
4
26
Purchases of reserves-in-place
Discoveries and extensions
26
19
45
Production
(23)
(1)
(20)
(31)
(23)
(98)
Sales of reserves-in-place
31
(1)
9
(27)
20
33
At 31 December
Developed
92
11
278
113
115
608
Undeveloped
49
254
88
2
393
 
141
11
532
200
117
1,001
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
159
94
860
5
283
174
812
20
2,407
Undeveloped
109
16
763
7
250
86
358
1
1,590
 
267
110
1,623
12
534
260
1,169
22
3,997
At 31 December
Developed
132
92
893
11
281
118
844
11
2,382
Undeveloped
75
49
568
259
88
324
1
1,365
 
207
141
1,462
11
540
206
1,168
13
3,747
aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
cExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
dAlso includes 2.2 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
eVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
bp Annual Report and Form 20-F 2025
261
NavigtionTabCornerV1.jpg
Financial statements
Movements in estimated net proved reserves – continued
billion cubic feet
Natural gasa b
2023
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
At 1 January
Developed
360
2,655
1,077
1,021
2,594
1,684
9,392
Undeveloped
41
3,154
748
221
2,125
407
6,696
401
5,809
1,825
1,242
4,719
2,091
16,087
Changes attributable to
Revisions of previous estimates
(54)
212
34
42
563
100
897
Improved recovery
9
254
263
Purchases of reserves-in-place
206
206
Discoveries and extensions
5
14
34
53
Productionc
(100)
(560)
(439)
(462)
(594)
(284)
(2,439)
Sales of reserves-in-place
(25)
(97)
(123)
(146)
92
(391)
(518)
3
(184)
(1,143)
At 31 Decemberd
Developed
221
2,672
931
518
3,051
1,550
8,942
Undeveloped
34
3,229
503
207
1,672
358
6,003
 
255
5,901
1,434
724
4,722
1,907
14,944
Equity-accounted entities (bp share)e
At 1 January
Developed
72
3
974
534
43
1,627
Undeveloped
5
2
606
154
767
 
77
5
1,580
689
43
2,394
Changes attributable to
Revisions of previous estimates
12
8
4
5
29
Improved recovery
25
22
47
Purchases of reserves-in-place
132
132
Discoveries and extensions
85
118
203
Productionc
(22)
(128)
(41)
(2)
(194)
Sales of reserves-in-place
(84)
(84)
101
(1)
68
(38)
3
133
At 31 December
Developed
67
4
1,027
463
46
1,608
Undeveloped
110
621
188
919
177
4
1,648
651
46
2,527
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
360
72
2,655
3
2,051
1,556
2,637
1,684
11,018
Undeveloped
41
5
3,154
2
1,355
375
2,125
407
7,463
401
77
5,809
5
3,405
1,931
4,762
2,091
18,481
At 31 December
Developed
221
67
2,672
4
1,958
981
3,096
1,550
10,549
Undeveloped
34
110
3,229
1,125
394
1,672
358
6,922
255
177
5,901
4
3,082
1,375
4,768
1,907
17,471
aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
cIncludes 99 billion cubic feet of natural gas consumed in operations, 62 billion cubic feet in subsidiaries, 36 billion cubic feet in equity-accounted entities.
dIncludes 430 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
eVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
262
bp Annual Report and Form 20-F 2025
Movements in estimated net proved reserves – continued
million barrels of oil equivalentc
Total hydrocarbonsa b
2023
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
At 1 January
Developed
221
1,318
191
206
1,164
311
3,411
Undeveloped
116
1,306
134
41
723
72
2,392
337
2,624
325
247
1,887
382
5,802
Changes attributable to
Revisions of previous estimates
(42)
(37)
5
5
182
12
125
Improved recovery
2
73
75
Purchases of reserves-in-place
61
61
Discoveries and extensions
18
2
7
27
Productiond e
(46)
(251)
(78)
(92)
(210)
(53)
(730)
Sales of reserves-in-place
(9)
(29)
(38)
(86)
(145)
(71)
(116)
(21)
(41)
(480)
At 31 Decemberf
Developed
170
1,354
163
95
1,255
279
3,316
Undeveloped
81
1,125
91
36
611
63
2,006
251
2,479
255
131
1,866
341
5,323
Equity-accounted entities (bp share)g
At 1 January
Developed
106
6
446
236
102
896
Undeveloped
17
7
349
110
1
485
123
13
796
346
103
1,381
Changes attributable to
Revisions of previous estimates
8
9
5
44
66
Improved recovery
26
7
34
Purchases of reserves-in-place
23
23
Discoveries and extensions
41
39
80
Productione
(27)
(1)
(42)
(38)
(23)
(131)
Sales of reserves-in-place
(15)
(15)
48
(1)
(2)
(11)
21
56
At 31 December
Developed
103
12
455
192
123
885
Undeveloped
68
361
120
2
552
172
12
816
313
124
1,437
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
221
106
1,318
6
637
442
1,266
311
4,307
Undeveloped
116
17
1,306
7
484
151
724
72
2,877
337
123
2,624
13
1,121
593
1,990
382
7,183
At 31 December
Developed
170
103
1,354
12
618
287
1,378
279
4,201
Undeveloped
81
68
1,125
453
156
613
63
2,558
251
172
2,479
12
1,071
444
1,991
341
6,759
aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
c5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
dExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
eIncludes 17 million barrels of oil equivalent of natural gas consumed in operations, 11 million barrels of oil equivalent in subsidiaries, 6 million barrels of oil equivalent in equity-accounted entities.
fIncludes 41 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
gVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
bp Annual Report and Form 20-F 2025
263
NavigtionTabCornerV1.jpg
Financial statements
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas
reserves
The following tables set out the standardized measure of discounted future net cash flows, and changes therein, relating to crude oil and natural
gas production from the group’s estimated proved reserves. This information is prepared in compliance with FASB Oil and Gas Disclosures
requirements.
Future net cash flows have been prepared on the basis of certain assumptions which may or may not be realized. These include the timing of future
production, the estimation of crude oil and natural gas reserves and the application of average crude oil and natural gas prices and exchange rates
from the previous 12 months. Furthermore, both proved reserves estimates and production forecasts are subject to revision as further technical
information becomes available and economic conditions change. bp cautions against relying on the information presented because of the highly
arbitrary nature of the assumptions on which it is based and its lack of comparability with the historical cost information presented in the financial
statements.
$ million
2025
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
At 31 December
Subsidiaries
Future cash inflowsa
7,600
93,300
5,000
600
93,300
11,500
211,300
Future production costb
8,500
39,300
3,300
200
34,500
3,600
89,400
Future development costb
800
15,300
1,200
100
13,500
1,600
32,500
Future taxationc
(100)
6,000
100
33,100
1,600
40,700
Future net cash flows
(1,600)
32,700
400
300
12,200
4,700
48,700
10% annual discountd
(700)
12,900
(500)
4,300
1,600
17,600
Standardized measure of discounted future net cash
flowse
(900)
19,800
900
300
7,900
3,100
31,100
Equity-accounted entities (bp share)f
Future cash inflowsa
10,100
36,800
12,300
8,100
67,300
Future production costb
4,300
18,500
4,800
4,100
31,700
Future development costb
1,300
3,900
1,000
2,800
9,000
Future taxationc
3,500
3,700
1,800
400
9,400
Future net cash flows
1,000
10,700
4,700
800
17,200
10% annual discountd
100
6,300
1,100
200
7,700
Standardized measure of discounted future net cash
flows
900
4,400
3,600
600
9,500
Total subsidiaries and equity-accounted entities
Standardized measure of discounted future net cash
flows
(900)
900
19,800
5,300
3,900
8,500
3,100
40,600
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
$ million
Subsidiaries
Equity-accounted
entities (bp share)
Total subsidiaries and
equity-accounted
entities
Sales and transfers of oil and gas produced, net of production costs
(21,400)
(5,400)
(26,800)
Development costs for the current year as estimated in previous year
6,000
3,200
9,200
Extensions, discoveries and improved recovery, less related costs
1,000
800
1,800
Net changes in prices and production cost
(11,100)
(3,100)
(14,200)
Revisions of previous reserves estimates
4,200
600
4,800
Net change in taxation
11,300
1,700
13,000
Future development costs
(1,100)
100
(1,000)
Net change in purchase and sales of reserves-in-place
(100)
(100)
Addition of 10% annual discount
3,800
1,100
4,900
Total change in the standardized measure during the yearg
(7,300)
(1,100)
(8,400)
aThe marker prices used were Brent $69.5/bbl, Henry Hub $3.4/mmBtu.
bProduction costs, which include production taxes and also fixed commitment costs associated with probable/contingent volumes, and development costs relating to future production of proved
reserves are based on the continuation of existing economic conditions. Future decommissioning costs are included.
cTaxation is computed with reference to appropriate year-end statutory corporate income tax rates.
dFuture net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.
eNon-controlling interests in BP Trinidad and Tobago LLC amounted to $271 million.
fThe standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments
of those entities.
gTotal change in the standardized measure during the year includes the effect of exchange rate movements.
264
bp Annual Report and Form 20-F 2025
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas
reserves – continued 
$ million
2024
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
At 31 December
Subsidiaries
Future cash inflowsa
15,100
99,300
3,700
600
107,300
15,200
241,200
Future production costb
11,800
39,100
2,900
100
37,800
3,900
95,600
Future development costb
1,000
15,300
500
100
11,200
2,100
30,200
Future taxationc
2,200
7,100
100
100
42,800
2,400
54,700
Future net cash flows
100
37,800
200
300
15,500
6,800
60,700
10% annual discountd
100
15,400
(300)
4,900
2,200
22,300
Standardized measure of discounted future net cash
flowse
22,400
500
300
10,600
4,600
38,400
Equity-accounted entities (bp share)f
Future cash inflowsa
11,700
41,600
15,100
8,400
76,800
Future production costb
4,100
20,900
5,400
4,200
34,600
Future development costb
2,000
4,100
2,200
2,900
11,200
Future taxationc
4,300
4,600
2,200
400
11,500
Future net cash flows
1,300
12,000
5,300
900
19,500
10% annual discountd
300
7,000
1,400
200
8,900
Standardized measure of discounted future net cash
flows
1,000
5,000
3,900
700
10,600
Total subsidiaries and equity-accounted entities
Standardized measure of discounted future net cash
flows
1,000
22,400
5,500
4,200
11,300
4,600
49,000
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
$ million
Subsidiaries
Equity-accounted
entities (bp share)
Total subsidiaries and
equity-accounted
entities
Sales and transfers of oil and gas produced, net of production costs
(25,700)
(5,300)
(31,000)
Development costs for the current year as estimated in previous year
5,100
2,900
8,000
Extensions, discoveries and improved recovery, less related costs
400
300
700
Net changes in prices and production cost
(7,300)
(1,800)
(9,100)
Revisions of previous reserves estimates
2,500
300
2,800
Net change in taxation
11,200
2,100
13,300
Future development costs
(1,400)
(600)
(2,000)
Net change in purchase and sales of reserves-in-place
(1,400)
800
(600)
Addition of 10% annual discount
5,000
1,100
6,100
Total change in the standardized measure during the yearg
(11,600)
(200)
(11,800)
aThe marker prices used were Brent $81.17/bbl, Henry Hub $2.07/mmBtu.
bProduction costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future
decommissioning costs are included.
cTaxation is computed with reference to appropriate year-end statutory corporate income tax rates.
dFuture net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.
eNon-controlling interests in BP Trinidad and Tobago LLC amounted to $164 million.
fThe standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments
of those entities.
gTotal change in the standardized measure during the year includes the effect of exchange rate movements.
bp Annual Report and Form 20-F 2025
265
NavigtionTabCornerV1.jpg
Financial statements
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas
reserves – continued
$ million
2023
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
At 31 December
Subsidiaries
Future cash inflowsa
19,400
100,200
6,800
4,400
118,300
18,000
267,100
Future production costb
11,900
37,500
4,300
600
39,600
4,500
98,400
Future development costb
1,200
12,100
1,000
500
8,500
1,400
24,700
Future taxationc
4,100
8,400
500
1,100
49,900
3,800
67,800
Future net cash flows
2,200
42,200
1,000
2,200
20,300
8,300
76,200
10% annual discountd
900
16,300
(300)
400
6,300
2,600
26,200
Standardized measure of discounted future net cash
flowse
1,300
25,900
1,300
1,800
14,000
5,700
50,000
Equity-accounted entities (bp share)f
Future cash inflowsa
13,700
44,600
15,200
9,000
82,500
Future production costb
3,700
20,700
5,500
4,700
34,600
Future development costb
2,100
5,200
2,300
3,100
12,700
Future taxationc
6,000
5,900
2,100
400
14,400
Future net cash flows
1,900
12,800
5,300
800
20,800
10% annual discountd
500
7,600
1,700
200
10,000
Standardized measure of discounted future net cash
flows
1,400
5,200
3,600
600
10,800
Total subsidiaries and equity-accounted entities
Standardized measure of discounted future net cash
flows
1,300
1,400
25,900
6,500
5,400
14,600
5,700
60,800
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
$ million
Subsidiaries
Equity-accounted
entities (bp share)
Total subsidiaries and
equity-accounted
entities
Sales and transfers of oil and gas produced, net of production costs
(36,500)
(6,500)
(43,000)
Development costs for the current year as estimated in previous year
6,000
2,200
8,200
Extensions, discoveries and improved recovery, less related costs
500
800
1,300
Net changes in prices and production cost
(50,800)
(7,100)
(57,900)
Revisions of previous reserves estimates
2,500
1,300
3,800
Net change in taxation
30,000
5,100
35,100
Future development costs
(1,000)
(300)
(1,300)
Net change in purchase and sales of reserves-in-place
(800)
(800)
Addition of 10% annual discount
9,100
1,400
10,500
Total change in the standardized measure during the yearg
(41,000)
(3,100)
(44,100)
aThe marker prices used were Brent $83.27/bbl, Henry Hub $2.58/mmBtu.
bProduction costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future
decommissioning costs are included.
cTaxation is computed with reference to appropriate year-end statutory corporate income tax rates.
dFuture net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.
eNon-controlling interests in BP Trinidad and Tobago LLC amounted to $392 million.
fThe standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments
of those entities.
gTotal change in the standardized measure during the year includes the effect of exchange rate movements.
266
bp Annual Report and Form 20-F 2025
Operational and statistical information
The following tables present operational and statistical information related to production, drilling, productive wells and acreage. Figures include
amounts attributable to assets held for sale.
Crude oil and natural gas production
The following table shows crude oil, natural gas liquids and natural gas production for the years ended 31 December 2025, 2024 and 2023.
Production for the yeara b
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
US
Rest of
North
America
Subsidiariesc
Crude oild
thousand barrels per day
2025
78
399
5
8
302
8
800
2024
70
376
4
19
297
9
775
2023
74
335
4
29
293
10
745
Natural gas liquids
thousand barrels per day
2025
4
111
6
1
123
2024
4
107
4
1
2
117
2023
5
88
4
2
2
100
Natural gase
million cubic feet per day
2025
203
1,751
1,045
453
1,597
799
5,847
2024
197
1,690
1,145
904
1,655
882
6,474
2023
247
1,486
1,191
1,236
1,578
774
6,512
Equity-accounted entities (bp share)
Crude oild
thousand barrels per day
2025
55
56
78
79
268
2024
58
56
82
69
266
2023
60
57
82
62
261
Natural gas liquids
thousand barrels per day
2025
2
1
5
8
2024
2
1
6
9
2023
3
1
6
9
Natural gase
million cubic feet per day
2025
54
284
264
603
2024
55
300
85
440
2023
58
299
74
432
aProduction excludes royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
bBecause of rounding, some totals may not exactly agree with the sum of their component parts.
cAll of the oil and liquid production from Canada is bitumen.
dCrude oil includes condensate.
eNatural gas production excludes gas consumed in operations.
bp Annual Report and Form 20-F 2025
267
NavigtionTabCornerV1.jpg
Financial statements
Operational and statistical information – continued
Productive oil and gas wells and acreage
The following tables show the number of gross and net productive oil and natural gas wells and total gross and net developed and undeveloped oil
and natural gas acreage in which the group and its equity-accounted entities had interests as at 31 December 2025. A ‘gross’ well or acre is one in
which a whole or fractional working interest is owned, while the number of ‘net’ wells or acres is the sum of the whole or fractional working
interests in gross wells or acres. Productive wells are producing wells and wells capable of production. Developed acreage is the acreage within the
boundary of a field, on which development wells have been drilled, which could produce the reserves; while undeveloped acres are those on which
wells have not been drilled or completed to a point that would permit the production of commercial quantities, whether or not such acres contain
proved reserves.
Europe
North
America
South
America
Africa
Asia
Australasia
Totala
UK
Rest of
Europe
US
Rest of
North
America
Number of productive wells at 31 December 2025
Oil wellsb
– gross
120
126
973
8
4,927
807
3,004
9,965
– net
69
20
631
2
2,417
77
667
3,883
Gas wellsc
– gross
31
9
3,819
1,233
92
197
91
5,472
– net
7
1
2,163
402
41
74
22
2,710
Oil and natural gas acreage at 31 December 2025
thousands of acres
Developed
– gross
72
83
1,504
8
1,242
626
1,355
838
5,727
– net
44
13
972
2
370
125
286
157
1,969
Undevelopedd
– gross
434
2,257
3,771
9,237
9,950
21,019
10,641
7,998
65,308
– net
339
358
3,253
6,193
4,801
8,408
5,805
3,364
32,521
aBecause of rounding, some totals may not exactly agree with the sum of their component parts.
bIncludes approximately 169 gross (32 net) multiple completion wells (more than one formation producing into the same well bore).
cIncludes approximately 11 gross (5 net) multiple completion wells. If one of the multiple completions in a well is an oil completion, the well is classified as an oil well.
dUndeveloped acreage includes leases and concessions.
Net oil and gas wells completed or abandoned
The following table shows the number of net productive and dry exploratory and development oil and natural gas wells completed or abandoned in
the years indicated by the group and its equity-accounted entities. Productive wells include wells in which hydrocarbons were encountered and the
drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well is one found
to be incapable of producing hydrocarbons in sufficient quantities to justify completion.
Europe
North
America
South
America
Africa
Asia
Australasia
Totala
UK
Rest of
Europe
US
Rest of
North
America
2025
Exploratory
Productive
0.3
0.6
2.9
2.7
0.4
6.9
Dry
0.6
0.3
1.0
0.6
2.6
Development
Productive
4.4
0.3
172.2
68.5
6.1
51.4
0.2
303.0
Dry
4.9
0.6
0.4
1.2
7.1
2024
Exploratory
Productive
0.7
0.5
0.4
0.7
2.3
Dry
1.0
0.8
0.5
0.5
2.8
Development
Productive
1.5
0.5
149.0
69.3
2.5
55.1
277.8
Dry
15.0
1.1
0.5
16.6
2023
Exploratory
Productive
2.0
0.8
0.4
3.2
Dry
0.5
0.8
0.5
0.2
2.0
Development
Productiveb
2.6
0.6
141.9
0.1
85.2
4.2
39.7
0.4
274.7
Dry
0.4
0.4
aBecause of rounding, some totals may not exactly agree with the sum of their component parts.
bIncludes correction of 2023 productive wells
268
bp Annual Report and Form 20-F 2025
Operational and statistical information – continued
Drilling and production activities in progress
The following table shows the number of exploratory and development oil and natural gas wells in the process of being drilled by the group and its
equity-accounted entities as of 31 December 2025. Suspended development wells and long-term suspended exploratory wells are also included in
the table.
Europe
North
America
South
America
Africa
Asia
Australasia
Totala
UK
Rest of
Europe
US
Rest of
North
America
At 31 December 2025
Exploratory
Gross
2.0
1.0
1.0
4.0
Net
0.8
0.5
0.1
1.4
Development
Gross
3.0
9.5
49.0
29.0
14.0
63.0
167.5
Net
1.8
1.5
36.4
11.3
1.8
21.3
74.1
aBecause of rounding, some totals may not exactly agree with the sum of their component parts.
bp Annual Report and Form 20-F 2025
269
NavigtionTabCornerV1.jpg
Financial statements
Pages 269-333 have been removed as they do not form part of bp's Annual Report on Form 20-F as filed with the SEC.
334
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Additional disclosures
Additional information
Liquidity and capital resources
Oil and gas disclosures for the group
Additional information for customers &
products
Environmental expenditure
Regulation of the group’s business
International trade sanctions
Material contracts
Property, plant and equipment
Related party transactions
Corporate governance practices
Code of ethics
Controls and procedures
Cyber security
Principal accountant’s fees and services
Additional Directors’ report disclosures
Disclosures required under Listing Rule 6.6.1R
Cautionary statement
bp Annual Report and Form 20-F 2025
335
NavigtionTabCornerV1.jpg
Additional disclosures
Additional information
Capital expenditure«
$ million
2025
2024
2023
Capital expenditure
Organic capital expenditure«
13,613
16,135
14,998
Inorganic capital expenditureab«
920
102
1,255
14,533
16,237
16,253
Capital expenditure by segment
gas & low carbon energyac
3,410
5,842
4,773
oil production & operations
6,760
6,198
6,278
customers & productsabc
4,071
3,789
4,761
other businesses & corporate
292
408
441
14,533
16,237
16,253
Capital expenditure by geographical area
US
6,129
6,566
8,105
Non-US
8,404
9,671
8,148
14,533
16,237
16,253
a2025 includes the final payment for the bp Bunge Bioenergia acquisition. 2024 includes the cash acquired net of acquisition payments on completion of the bp Bunge Bioenergia and Lightsource
bp acquisitions.
b2023 includes $1.1 billion in respect of the TravelCenters of America acquisition.
c2024 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.
336
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Adjusting items
Adjusting items are items that bp discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are
items that management considers to be important to period-on-period analysis of the group's results and are disclosed in order to enable investors
to better understand and evaluate the group’s reported financial performance. An analysis of adjusting items is shown in the table below.
$ million
2025
2024
2023
gas & low carbon energy
Gain on sale of businesses and fixed assetsa
258
297
19
Net impairment and losses on sale of businesses and fixed assetsab
(4,448)
(3,521)
(2,221)
Environmental and related provisions
Restructuring, integration and rationalization costsc
(2)
(25)
Fair value accounting effectsde«
1,270
(1,550)
8,859
Otherf
(1,115)
1,048
(1,299)
(4,037)
(3,751)
5,358
oil production & operations
Gain on sale of businesses and fixed assetsa
407
144
297
Net impairment and losses on sale of businesses and fixed assetsa
(552)
(790)
(1,819)
Environmental and related provisions
(268)
5
54
Restructuring, integration and rationalization costsc
(67)
(15)
(1)
Fair value accounting effects
Otherg
(376)
(492)
(121)
(856)
(1,148)
(1,590)
customers & products
Gain on sale of businesses and fixed assetsa
317
190
44
Net impairment and losses on sale of businesses and fixed assetsabh
(1,030)
(2,600)
(1,757)
Environmental and related provisions
(68)
(99)
(97)
Restructuring, integration and rationalization costsc
(241)
(123)
Fair value accounting effectse
(207)
(81)
(86)
Otheri
57
(847)
(287)
(1,172)
(3,560)
(2,183)
other businesses & corporate
Gain on sale of businesses and fixed assetsa
5
39
1
Net impairment and losses on sale of businesses and fixed assetsa
(5)
(19)
(41)
Environmental and related provisionsj
(320)
(87)
(604)
Restructuring, integration and rationalization costsc
(210)
(59)
38
Fair value accounting effectse
1,157
(221)
630
Gulf of America oil spill
(31)
(51)
(57)
Other
12
18
(4)
608
(380)
(37)
Total before interest and taxation
(5,457)
(8,839)
1,548
Finance costsk
(428)
(505)
(405)
Total before taxation
(5,885)
(9,344)
1,143
Taxation on adjusting itemslm
246
1,495
972
Taxationtax rate change effectn
(774)
(316)
232
Total after taxationo
(6,413)
(8,165)
2,347
aSee Financial statements – Note 4 for further information.
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.
cRestructuring charges are classified as adjusting items where they relate to an announced major group restructuring. A major group restructuring is a restructuring programme affecting more
than one of the group’s operating segments that is expected to result in charges of more than $1 billion over a defined period. 2024 includes charges for provisions arising from the groups
transformation project that was announced on 16 January 2024.
dUnder IFRS bp marks-to-market the value of the hedges used to risk-manage LNG contracts, but not the contracts themselves, resulting in a mismatch in accounting treatment. The fair value
accounting effect includes the change in value of LNG contracts that are being risk-managed, and the underlying result reflects how bp risk-manages its LNG contracts.
eFor further information, including the nature of fair value accounting effects reported in each segment, see page 379.
f2025 includes $1,082 million of impairment charges recognized through equity-accounted earnings primarily relating to the Archaea Energy and offshore wind businesses. 2024 includes a $508
million gain relating to the remeasurement of bp's pre-existing 49.97% interest in 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). 2023 includes $1,140 million of impairment charges recognized through equity-accounted earnings relating to our US offshore wind
projects.
g2024 includes $429 million of impairment charges recognized through equity-accounted earnings relating to our interest in Pan American Energy Group.
hFor 2024, see Financial statements – Note 2 for further information.
i2024 includes 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.
j2023 primarily relates to charges related to the control, abatement, clean-up or elimination of environmental pollution and legal settlements.
kAll periods presented include the unwinding of discounting effects relating to Gulf of America oil spill payables and the income statement impact of temporary valuation differences related to
the group's interest rate and foreign currency exchange risk management associated with finance debt. 2025 and 2024 include the unwinding of discounting effects relating to certain onerous
contract provisions. 2023 includes the income statement impact associated with the buyback of finance debt.
lAll periods include certain foreign exchange effects on tax as adjusting items. These amounts represent the impact of: (i) foreign exchange on deferred tax balances arising from the conversion of
local currency tax base amounts into functional currency; and (ii) taxable gains and losses from the retranslation of US dollar-denominated intra-group loans to local currency.
m2025 includes limited tax relief on impairment charges and the impact of the reassessment of the recognition of deferred tax assets.
nAll periods include revisions to the deferred tax impact of the introduction of the UK Energy Profits Levy (EPL) on temporary differences existing at the opening balance sheet date. The EPL
increases the headline rate of tax on taxable profits from bp’s North Sea business to 78%. In 2025 a two-year extension of the EPL to 31 March 2030 was substantively enacted. 2025 also includes
the deferred tax impact of a change in the tax rate in Germany. See Note 1 for further information.
bp Annual Report and Form 20-F 2025
337
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Additional disclosures
o2023 includes a $146-million charge for the EU Solidarity Contribution.
Non-IFRS information on fair value accounting effects
The impacts of fair value accounting effects, relative to management’s internal measure of performance, are set out below. Further information on
fair value accounting effects is provided on page 379.
$ million
2025
2024
2023
gas & low carbon energy
Unrecognized (gains) losses brought forward from previous period
(2,674)
(1,125)
(9,960)
Favourable (adverse) impact relative to management’s measure of performance
1,270
(1,550)
8,859
Exchange translation gains (losses) on fair value accounting effects
(5)
1
(24)
Unrecognized (gains) losses carried forward
(1,409)
(2,674)
(1,125)
customers & products
Unrecognized (gains) losses brought forward from previous period
(96)
(17)
79
Favourable (adverse) impact relative to management’s measure of performance
(207)
(81)
(86)
Exchange translation gains (losses) on fair value accounting effects
2
(10)
Unrecognized (gains) losses carried forward
(303)
(96)
(17)
other businesses & corporate
Unrecognized (gains) losses brought forward from previous period
(1,146)
(925)
(1,555)
Favourable (adverse) impact relative to management’s measure of performancea
1,157
(221)
630
Unrecognized (gains) losses carried forward
11
(1,146)
(925)
Group
Unrecognized (gains) losses brought forward from previous period
(3,916)
(2,067)
(11,436)
Favourable (adverse) impact relative to management’s measure of performance
2,220
(1,852)
9,403
Exchange translation gains (losses) on fair value accounting effects
(5)
3
(34)
Unrecognized (gains) losses carried forward
(1,701)
(3,916)
(2,067)
Favourable (adverse) impact relative to management’s measure of performance – by region
gas & low carbon energy
US
376
(582)
900
Non-US
894
(968)
7,959
1,270
(1,550)
8,859
customers & products
US
(58)
(214)
(18)
Non-US
(149)
133
(68)
(207)
(81)
(86)
other businesses & corporate
US
Non-US
1,157
(221)
630
1,157
(221)
630
2,220
(1,852)
9,403
Taxation credit (charge)
(206)
325
(915)
2,014
(1,527)
8,488
aIncludes changes in the fair value of derivatives entered into by the group to manage currency exposure and interest rate risks relating to hybrid bonds to their respective first call periods. For
further information see page 379.
Net debt including leases
Net debt including leases« is shown in the table below.
$ million
At 31 December
2025
2024
Net debta«
22,182
22,997
Lease liabilities
14,571
12,000
Net partner (receivable) payable for leases entered into on behalf of joint operations«
(1,067)
(88)
Net debt including leases
35,686
34,909
Total equity
74,000
78,318
Gearing including leases«
32.5%
30.8%
aSee Financial statements – Note 27 for a reconciliation of net debt to finance debt, which is the nearest equivalent measure to net debt on an IFRS basis.
338
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Liquidity and capital resources
Financial framework
The financial framework 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.
A resilient dividend is our first capital allocation priority. 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.
Net debt« at 31 December 2025 was $22.2 billiona and is expected to
reduce over time to a targeted range of $14-18 billion by the end of 2027,
reflecting the full allocation of excess cash« to the balance sheet, in
service of optimizing financing costs and to accelerate strengthening of
the balance sheet. bp is committed to strengthening the balance sheet
and we continue to target improving our credit metrics within an A’
grade credit range.
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 net debt, hybrid bonds and securities, leases and Gulf of
America settlement liabilities was $57.8 billion.
Capital expenditure in 2025 was $14.5 billion, including $0.9 billion of
inorganic capital expenditure«. We expect capital expenditure of
around $13.0-13.5 billion in 2026 including inorganic expenditure. We
believe this level of capital expenditure supports progressively growing
earnings per ordinary share in the long term. Within this frame we are
allocating capital to our highest returning opportunities across the
portfolio.
In 2025 the return on average capital employed« was 13.9%b at an
average of $69 per barrel. The return on average capital employed is
targeted to be over 16%c in 2027 at $70 per barrel in 2024 real terms,
and assuming bp planning assumptions, as we execute our reset
strategy. This is supported by a target compound annual growth rate in
adjusted free cash flow« of over 20%c from 2024 to 2027 and subject to
the same price and planning assumptions.
aThe nearest equivalent IFRS measure is finance debt at the end of 2025 of $58.0 billion.
bThe nearest equivalent IFRS measures of numerator and denominator are profit for the year
attributable to bp shareholders for 2025 of $0.1 billion and total equity at the end of 2025 of
$74.0 billion respectively. Profit for attributable to bp shareholders divided by total equity at
31 December 2025 was 0.1%.
cThis 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.
Distributions to shareholders
The dividend is determined in US dollars, the economic currency of bp,
and the dividend level is reviewed by the board each quarter. The
quarterly dividend was increased from 8.000 to 8.320 cents per
ordinary share per quarter in the second quarter of 2025.
The total dividend distributed to bp shareholders in 2025 was $5.1 billion
(2024 $5.0 billion). This dividend was all paid in cash to shareholders.
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.
At the fourth quarter 2025 results in February 2026, the board decided
to suspend share buybacks; excess cash is now fully allocated to the
balance sheet, in service of optimizing financing costs and
strengthening the balance sheet.
In 2025 bp executed $4.5 billion of share buybacks (2024 $7.1 billion),
including fees and stamp duty. Since 1 January 2026 an additional
$450 million shares have been repurchased up to 13 February 2026,
including fees and stamp duty.
Financing the group’s activities
The group’s principal commodities, oil and gas, are priced
internationally in US dollars. Group policy has generally been to
minimize economic exposure to currency movements by financing
operations with US dollar debt. Where debt and hybrid bonds are issued
in other currencies, they are generally swapped back to US dollars using
derivative contracts, or else hedged by maintaining offsetting cash
positions in the same currency. Cash balances of the group are mainly
held in US dollars or swapped to US dollars, and holdings are well
diversified to reduce concentration risk. The group is not, therefore,
exposed to significant currency risk regarding its cash or borrowings.
Also see Risk factors on page 67 for further information on risks
associated with prices and markets, and Financial statements – Note 29.
The group’s finance debt at 31 December 2025 amounted to $58.0
billion (2024 $59.5 billion). Of the total finance debt, $3.4 billion is
classified as short term at the end of 2025 (2024 $4.5 billion). See
Financial statements – Note 26 for more information on the short-term
balance. Net debt was $22.2 billion at the end of 2025, a decrease of
$0.8 billion from the 2024 year-end position of $23.0 billion. BP p.l.c.
fully and unconditionally guarantees securities issued by BP Capital
Markets p.l.c. and BP Capital Markets America Inc., which are 100%-
owned finance subsidiaries of BP p.l.c.
At 31 December 2025 the group held a balance of $16.0 billion (2024
$16.6 billion) issued perpetual subordinated hybrid instruments
consisting of $13.5 billion (2024 $14.6 billion) hybrid bonds and $2.5
billion (2024 $2.0 billion) hybrid securities. Proceeds from hybrid
securities are typically earmarked to fund specific project or investment
activities. As the group has the unconditional right to avoid transfer of
cash or another financial asset in relation to these hybrid instruments,
which were issued by group subsidiaries, they are classified as equity
instruments and reported within non-controlling interest.
The ratio of finance debt to finance debt plus total equity at
31 December 2025 was 43.9% (2024 43.2%). Gearing was 23.1% at the
end of 2025 (2024 22.7%). See Financial statements – Note 27 for finance
debt, which is the nearest equivalent measure on an IFRS basis, and for
further information on net debt.
Cash and cash equivalents of $36.6 billion at 31 December 2025 (2024
$39.2 billion) are included in net debt. We manage our cash position so
that the group has adequate cover to respond to potential short-term
market liquidity, short-term price environment volatility, and expect to
maintain a robust cash position.
The group also has an undrawn committed $8 billion credit facility and
undrawn committed standby facilities of $4 billion (see Financial
statements – Note 29 for more information).
We believe that the group's resilient balance sheet and strong
investment grade credit rating will allow the group to meet its known
contractual and other obligations in both the short and long term with
the group having sufficient working capital, taking into account the
amounts of undrawn borrowing facilities, access to capital markets,
levels of cash and cash equivalents and its ongoing ability to generate
cash through operations. This belief is subject to a degree of
uncertainty that can be expected to increase looking out over time and,
accordingly, that future outcomes cannot be guaranteed or predicted
with certainty.
bp utilizes various arrangements in order to manage its working capital
including discounting of receivables and, in the supply and trading
business, the active management of supplier payment terms, inventory
and collateral.
Standard & Poor’s Ratings’ long-term credit rating for BP p.l.c. is A-
(stable), the Moody’s Investors Service rating is A1 (stable) and the Fitch
Ratings’ long-term credit rating is A+ (stable).
The group’s sources of funding, its access to capital markets and
maintaining a strong cash position are described in Financial
statements – Note 25 and Note 29. Further information on the
management of liquidity risk and credit risk, and the maturity profile
and fixed/floating rate characteristics of the group’s debt are also
provided in Financial statements – Note 26 and Note 29.
The information above contains forward-looking statements, which by
their nature involve risk and uncertainty because they relate to events
and depend on circumstances that will or may occur in the future and
are outside the control of bp. You are urged to read the Cautionary
statement on page 362 and Risk factors on page 67, which describe the
bp Annual Report and Form 20-F 2025
339
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Additional disclosures
risks and uncertainties that may cause actual results and
developments to differ materially from those expressed or implied by
these forward-looking statements.
Off-balance sheet arrangements
At 31 December 2025, the group’s share of third-party finance debt and
lease liabilities of equity-accounted entities was $10.8 billion (2024 $8.0
billion). These amounts are not reflected in the group’s debt on the
balance sheet. The group has issued third-party guarantees under
which amounts outstanding, incremental to amounts recognized on the
balance sheet at 31 December 2025, were $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. Of these amounts, $708 million (2024 $655 million) of the joint
ventures and associates guarantees relate to borrowings and, for other
third-party guarantees, $408 million (2024 $430 million) relate to
guarantees of borrowings.
Contractual obligations
The following table summarizes the group’s capital expenditure
commitments for property, plant and equipment at 31 December 2025
and the proportion of that expenditure for which contracts have been
placed.
$ million
Payments due by period
Capital expenditure
Less than 1
year
More than 1
year
Total
Committed
13,049
16,724
29,773
of which is contracted
7,517
7,122
14,639
Capital expenditure is considered to be committed when the project
has received the appropriate level of internal management approval.
For joint operations«, the net bp share is included in the amounts
above.
In addition, at 31 December 2025 the group had committed to capital
expenditure relating to investments in equity-accounted entities
amounting to $2,896 million. Contracts were in place for $2,327 million
of this total.
The following table summarizes the group’s principal contractual
obligations at 31 December 2025, distinguishing between those for
which a liability is recognized on the balance sheet and those for which
no liability is recognized. See Financial framework above for bp’s
approach to capital allocation and Financing the group’s activities
above for bp’s plan and ability to generate and obtain cash in the short
and long term. Also see Financial statements – Note 23 for more
information on provisions, Note 24 on pensions and other post-
employment benefits, Note 26 on borrowings, Note 28 on leases, Note
29 and Note 30 on derivatives and financial instruments.
$ million
Payments due by period
Expected payments by period under
contractual obligations
Less than 1
year
More than 1
year
Total
Balance sheet obligations
Borrowingsa
5,539
65,604
71,143
Lease liabilitiesb
3,596
15,740
19,336
Decommissioning liabilitiesc
812
23,759
24,571
Environmental liabilitiesc
318
1,611
1,929
Gulf of America oil spill
liabilitiesd
1,533
6,834
8,367
Pensions and other post-
employment benefitse
490
11,864
12,354
12,288
125,412
137,700
Off-balance sheet obligations
Unconditional purchase
obligationsf
Crude oil and oil products
48,271
2,689
50,960
Natural gas and LNG
16,685
50,880
67,565
Chemicals and other refinery
feedstocks
1,290
1,695
2,985
Power
6,693
13,802
20,495
Utilities
56
324
380
Transportation
1,993
14,118
16,111
Use of facilities and services
3,124
16,762
19,886
78,112
100,270
178,382
Total
90,400
225,682
316,082
aExpected payments include interest totalling $18,214 million (less than 1 year $2,227 million,
more than 1 year $15,987 million).
bExpected payments include interest totalling $4,765 million (less than 1 year $728 million,
more than 1 year $4,037 million).
cThe amounts presented are undiscounted.
dThe amounts presented are undiscounted. Gulf of America oil spill liabilities are included in
the group balance sheet, on a discounted basis, within other payables. See Financial
statements – Note 22 for further information.
eRepresents the expected future contributions to funded pension plans and payments by the
group for unfunded pension plans, and the expected future payments for other post-
employment benefits.
fRepresents any agreement to purchase goods or services that is enforceable and legally
binding and that specifies all significant terms (such as fixed or minimum purchase volumes,
timing of purchase and pricing provisions). Agreements that do not specify all significant
terms, or that are not enforceable, are excluded. The amounts shown include arrangements
to secure long-term access to supplies of crude oil, natural gas, feedstocks and pipeline
systems. In addition, the amounts shown for 2026 include purchase commitments existing at
31 December 2025 entered into principally to meet the group’s short-term manufacturing and
marketing requirements. The price risk associated with these crude oil, natural gas and power
contracts is discussed in Financial statements – Note 29.
Commitments for the delivery of oil and gas
We sell crude oil, natural gas and liquefied natural gas under a variety of
contractual obligations. Some of these contracts specify the delivery of
fixed and determinable quantities. For the period from 2026 to 2028
worldwide, we are contractually committed to deliver approximately
288 million barrels of oil, 6,288 billion cubic feet of natural gas, and
70Mt of liquefied natural gas. The commitments principally relate to
group subsidiaries« based in Azerbaijan, Oman, Trinidad and Tobago,
the UK and the US. We expect to fulfil these delivery commitments with
production from our proved developed reserves and supplies from
existing contracts, supplemented by market purchases as necessary.
340
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Oil and gas disclosures for the group
Analysis by region
Our oil and gas operations are set out below by geographical area, with
associated significant events for 2025. bp’s percentage working
interest in oil and gas assets is shown in brackets. Working interest is
the cost-bearing ownership share of an oil or gas lease. Consequently,
the percentages disclosed for certain agreements do not necessarily
reflect the percentage interests in proved reserves, production or
revenue.
In addition to exploration, development and production activities, our oil
production & operations (OP&O) and gas businesses also include
certain midstream and liquefied natural gas (LNG) supply activities.
Midstream activities involve the management of crude oil and natural
gas pipelines, processing facilities and export terminals, LNG
processing facilities and transportation, and our natural gas liquids
(NGLs) processing business.
Our upstream LNG production activities are located in Abu Dhabi,
Angola, Australia, Indonesia, Mauritania and Senegal and Trinidad and
Tobago. In 2025 our production was 12 million tonnes (Mt) of LNG from
these assets, of which 5.2Mt were optimized and delivered through
supply, trading and shipping (ST&S), which supplements equity
production with merchant third-party volumes leading to a global long-
term strategic LNG portfolio of 26.8Mtpa. In addition to the long-term
equity and merchant supply portfolio, bp delivered 14.7Mtpa in 2025 of
incremental merchant volumes through short and mid-term cargoes
managed through the ST&S LNG business. These supplement the long-
term portfolio and allow generation of short-term value when
opportunities exist.
The LNG is marketed through contractual rights to access import
terminal capacity in the liquid markets of Europe and UK, and
relationships to market directly to end-user customers or trading
entities. LNG is supplied to all major LNG demand centres for example
Argentina, Bangladesh, Brazil, Caribbean, China, Croatia, Iberia and
North West Europe, India, Japan, Mediterranean, Philippines, Singapore,
South Korea, Taiwan, Thailand, Türkiye and the UK.
Europe
bp has interest in offshore oil and gas activities in the UK and Norway. In
2025 bp’s UK production came from two key areas: the Shetland area
comprising the Clair and Schiehallion fields; and the central area
comprising the Andrew area, Culzean, Vorlich and ETAP fields. In
Norway, production was through our equity-accounted 15.9% interest in
Aker BP.
Aker BP achieved its strongest exploration year since 2010,
highlighted by three major 2025 discoveries: the Lofn and
Langemann gas and condensate find near Sleipner, the large Omega
Alfa oil discovery in the Yggdrasil area and the Kjøttkake oil and gas
discovery in the Northern North Sea.
In October bp agreed to sell its 32% non-operated working interest
in the Culzean development in the central North Sea to Serica
Energy. The sale was subject to a pre-emption period of 30 days,
with each of the Culzean field partners (TotalEnergies, 49.99%, and
NEO NEXT, 18.01%) having the option to acquire bp’s stake on the
same terms as those agreed by Serica. In November NEO NEXT
exercised its preemption rights and acquired bp’s working interest
on the conditions agreed with Serica. The deal completed in
December.
In October bp announced it had safely started up production from
the Murlach field in the UK North Sea. The two-well subsea tieback is
expected to add a peak net production of around 15,000 barrels of
oil equivalent per day.
North America
Our oil and gas activities in North America are located in four areas:
deepwater Gulf of America, the Lower 48 states, Canada and Mexico.
bp has around 300 lease blocks in the Gulf of America and operates five
production hubs.
In April bp announced an oil discovery at the Far South prospect in
the deepwater US Gulf of America. Both the initial well and a
subsequent sidetrack encountered oil in high-quality Miocene
reservoirs. Preliminary data supports a potentially commercial
volume of hydrocarbons.
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 had 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 December bp was the apparent highest bidder on 51 lease blocks
in the US Gulf of America Federal Lease Sale BBG1, which included
219 leases.
In December bp successfully delivered first oil from the Atlantis Drill
Center 1 expansion in the US Gulf of America. The two-well subsea
tieback to the existing Atlantis platform is expected to add
15,000boe/d gross peak annualized average production.
bpx energy, bp's onshore oil and gas business in the Lower 48 states,
has significant operated and non-operated activities across Louisiana
and Texas producing natural gas, oil, NGLs and condensate, with
primary focus on developing unconventional resources. It had a 1.8
billion boe proved reserve base at 31 December 2025, predominantly in
unconventional reservoirs (tight gas, shale gas and shale oil). bpx
energy's core assets span over 0.8 million net developed acres with
over 2,400 operated gross wells at 31 December 2025. Daily net
production averaged 466mboe/d in 2025.
bpx energy continues to operate as a separate business while
remaining part of the OP&O segment. With its own governance,
systems, and processes, it is structured to increase competitive
performance through swift decision making and innovation, while
maintaining bp’s commitment to safe, reliable and compliant
operations.
In June bpx energy started up the Crossroads facility in the Permian
Basin, bpx's fourth and final central delivery facility to be built,
following the earlier Grand Slam, Checkmate and Bingo facilities.
In July bpx energy took over operations from Devon Energy of
certain assets in the Eagle Ford Shale following the April dissolution
of their joint venture in the Blackhawk field.
In November and December bp completed a two-phase divestment
of non-controlling interests in Permian and Eagle Ford midstream
assets to investor Sixth Street for a total of $1.5 billion.
bp’s onshore US crude oil and product pipelines and related
transportation assets were included in the customers & products
segment.
In Canada, bp is focused on pursuing offshore exploration and
development opportunities and conducts trading and marketing
activities across various energy commodities. We hold exploration and
significant discovery licenses in offshore Newfoundland and Labrador,
including an interest in the Equinor-operated Bay du Nord project. bp
also holds offshore exploration licenses in the Arctic, where the
moratorium has been extended until 31 December 2028.
In Mexico, bp holds interests in an exploration block in the Salina Basin
with Equinor and Total, Block 1 (bp 33% operator) and an exploration
block in the Sureste Basin, Block 34 (bp 42.5% operator), with Total, QPI
Mexico and Hokchi Energy. Hokchi Energy is a subsidiary of Pan
American Energy Group (PAEG, see below). bp holds 50% of PAEG and
PAEG holds 55% of Hokchi Energy. Separate to the above holdings in
Mexico, Hokchi Energy also holds an interest in two other blocks.
bp Annual Report and Form 20-F 2025
341
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Additional disclosures
Formal relinquishment of Block 1 and Block 34 licences is still pending
regulatory approval.
South America
bp has oil and gas activities in Brazil and Trinidad and Tobago and,
through PAEG, in Argentina and Bolivia.
In Brazil bp has interests in six exploration areas across three basins:
Petrobras as the operator of Alto de Cabo Frio Central block (bp
50%) drilled an appraisal well completed in July, as part of the
appraisal plan (PAD) filed in 2023, with indication of hydrocarbon
shows. The block strategy is under development and will be finalized
following completion of post-well analyses, expected by end 2026.
In June GNA II started commercial operation, a 1.7 gigawatts capacity
gas fired power plant, the largest in Brazil. bp is the exclusive LNG
supplier for GNA II and holds a 33.5% stake in the project alongside
Siemens Energy (33.5%) and SPIC Brazil (33%).
In August bp announced an exploration discovery at the
Bumerangue prospect in the deepwater offshore Brazil. bp drilled
exploration well 1-BP-13-SPS at the Bumerangue block, located in the
Santos Basin, 404 kilometres (218 nautical miles) off the coast of
Brazil, in a water depth of 2,372 metres. bp holds a 100% participation
in the block with Pré-Sal Petróleo S.A. as the Production Sharing
Contract manager. bp secured the block in December 2022 during
the first cycle of the Open Acreage of Production Sharing of the
Brazilian national petroleum agency (ANP). bp is now putting plans in
place for an appraisal programme which is expected to start around
the end of the year. This will provide data from locations across the
reservoir, to enable us to describe the fluid characteristics and
resource potential.
PAEG, a joint venture that is owned by bp (50%) and BC E&P Uruguay
S.A. (50%), has activities mainly in Argentina and as noted above, Mexico,
and is also present in Bolivia.
In Trinidad and Tobago bp holds interests in exploration and production
licences and production-sharing contracts (PSCs)« covering 2.1 million
acres offshore the east and north-east coast. Facilities include 12
offshore platforms, 3 subsea tiebacks and 2 onshore processing
facilities. Production comprises gas and associated liquids.
bp also holds interests in the Atlantic LNG facility. The total gross
capacity of the LNG facility is approximately 12Mtpa, with three trains in
operation. bp’s shareholding averages 43% across the companies which
own the LNG trains comprising the LNG facility. Upon expiration of the
Train 4 contract on 1 May 2027, and completion of full restructuring bp’s
shareholding will increase to 45%.
In March FID was taken on the Ginger project which will become
bpTT’s fourth subsea project and will include four subsea wells and
subsea trees tied back to bpTT’s existing Mahogany B platform. First
gas from the project is expected in 2027.
In May bp announced first gas from the Mento project. Mento is a
50:50 joint venture between EOG Resources Trinidad Ltd (EOG) and
bpTT, with EOG as the operator. The development features a 12-slot
attended facility that is located in acreage jointly licensed by bpTT
and EOG off Trinidad’s south-east coast.
In November bp announced that it had safely completed the Cypre
seven-well drilling programme in Trinidad, the second phase of the
Cypre project, following delivery of first gas in April 2025. Cypre is
bpTT’s third subsea development. It comprises seven wells tied back
into bpTT’s existing Juniper platform.
bpTT and EOG are also currently working on the Coconut gas
development under a similar joint venture arrangement. 
Construction is in progress with start-up expected in 2027.
The seismic processing activity over the joint Manakin-Cocuina field
was successfully completed in September 2024. bp is operator of
the Manakin block which was discovered in 2000. bp and NGC also
hold an exploration and production licence for the development of
the Cocuina gas discovery, which is the Venezuelan portion of the
cross-border Manakin-Cocuina gas field. Activity ceased in April
2025 with the revocation of its specific OFAC license. In February
2026 General Licences 48, 49 and 50 were issued by OFAC which
authorized contractors and certain companies including bp plc and
its subsidiaries to progress with oil and gas projects in Venezuela. bp
is therefore authorized to progress with the development of the
Manakin-Cocuina project subject to the conditions contained in the
General Licences.
Seismic processing activity was completed and interpretation of results
underway on deepwater blocks Blocks 25a, 25b and 27 in Trinidad and
Tobago. These blocks are a 50:50 joint venture between bp and Shell,
with bp operating Blocks 25a and 25b, and Shell operating Block 27.
Africa
bp’s oil and gas activities in Africa are located in Angola, Namibia, Egypt,
Libya, Mauritania and Senegal.
In Angola, bp and Eni each own a 50% interest in the Azule Energy
(Azule) joint venture. Azule is Angola’s largest independent equity
producer of oil and gas, holding stakes in 18 licences, as well as an
interest in the Angola LNG plant.
In July Azule, operator of Block 15/06 in Angola, together with its
partners, announced the successful start-up of the Agogo Integrated
West Hub Project, which aims to fully develop the Agogo and
Ndungu fields in Block 15/06.
In July Azule, operator of Block 1/14, and its partners announced a
gas discovery at the Gajajeira-01 exploration well, located offshore in
the Lower Congo Basin, Angola. Initial assessments suggest gas
volumes in place could exceed 1 trillion cubic feet, with up to 100
million barrels of associated condensate.
In October Rhino Resources, operator of the Petroleum Exploration
Licence 85 in the Orange Basin offshore Namibia, partnering with
Azule, announced a discovery at the Volans 1-X well. The well found
26 metres of net pay in rich-gas condensate bearing reservoirs with
excellent quality petrophysical properties and a high condensate to
gas ratio. This discovery builds on the announcement in April of a
discovery in the Capricornus 1-X exploration well in the same license
block.
In December Azule announced the signing of a Sale and Purchase
Agreement (SPA) with a consortium of Etablissements Maurel &
Prom S.A. (M&P) and BW Energy (BWE) for the sale of Azule's
participating interest in offshore Blocks 14 and 14K located in the
Lower Congo Basin. Azule holds a 20% interest in Block 14 and a 10%
interest in Block 14K. The offshore blocks have been producing since
1999. Net working interest production to Azule from both the blocks
combined was 9600 barrels of oil per day in 2024. Completion of the
transaction is expected to occur mid-2026 and is subject to
customary adjustments and approvals by the partners and Angolan
authorities.
In Egypt, bp holds an investment in Nile Delta. Through its joint ventures
with Egyptian Natural Gas Holding Company (EGAS), Egyptian General
Petroleum Corporation (EGPC), International Egyptian Oil Company
(IEOC), Eni, the Pharaonic Petroleum Company (PhPC), ADNOC, and
through collaboration with Belayim Petroleum Company (Petrobel), bp
and its partners now produce more than 60% of Egypt's total gas
supply. In addition, bp owns interest in other exploration projects.
In February bp successfully completed the drilling activity at the El
King-2 exploration well in the North King Mariout Offshore
Concession as part of its West Nile Delta (WND) drilling campaign
Also in February bp announced the Raven Infills project in the West
Nile Delta (WND) had started production ahead of schedule. bp, the
operator, holds an 82.75% stake in the project, while Harbour Energy
owns the remaining 17.25%.
In March bp announced successful completion of the El Fayoum-5
gas discovery well in the North Alexandria Offshore Concession. It is
planned to be tied-back to bp’s operated WND Gas Development.
In September bp announced the signing of a memorandum of
understanding (MoU) to evaluate opportunities for a five-well
programme at water depths ranging from 300 to 1,500 metres in the
Mediterranean Sea, offshore Egypt. Drilling operations are expected
to start in 2026.
In January 2026 bp was awarded two offshore exploration
concessions in Egypt: North-East El Alamein Offshore and West El
342
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Hammad Offshore, advancing our exploration portfolio and long-
term growth ambitions. The North-East El Alamein Offshore
Concession (bp 100% equity) covers 3,336km² near bp's West Nile
Delta assets. The West El Hammad Offshore Concession (Eni 75%
operator, bp 25%) covers 1,894km² in the East Nile Delta, also near
existing infrastructure.
In Libya, bp partners with the Libyan Investment Authority (LIA) and Eni
(operator) in an exploration and production-sharing agreement (EPSA)
to explore acreage in the onshore Ghadames and offshore Sirt basins
(bp 42.5%).
Exploration operations under the EPSA resumed in 2023, following the
period of force majeure between 2012 and 2022.
In Mauritania and Senegal, bp retains the exploitation licences in the
respective C8 and Saint Louis Offshore Profond blocks pertinent to the
Greater Tortue Ahmeyim (GTA) Unit cross-border development (bp
56.3%).
In April bp announced that it had safely loaded the first cargo of LNG
for export from GTA.
Asia
bp has activities in Abu Dhabi, Azerbaijan, China, India, Indonesia, Iraq,
Kuwait and Oman.
In China, we have a 30% equity stake in the Guangdong LNG
regasification terminal and trunkline project (GDLNG) with a total
storage capacity of 640,000 cubic metres. bp also has 0.6Mtpa of
regasification capacity at GDLNG for up to 12 years starting from the
beginning of 2021. bp imports LNG from our global portfolio and
delivers regasified natural gas via the terminal to power plant and city
gas customers in Guangdong province under long-term sales contracts.
In May bp announced it had entered into a long-term LNG sale and
purchase agreement with Zhejiang Energy. Under the agreement, bp
will provide Zhejiang Energy with up to 1 million tonnes per annum of
LNG for over 10 years on a delivered ex-ship (DES) basis from bp’s
diverse portfolio of LNG sources.
In Azerbaijan, bp operates two production-sharing agreements (PSAs)«,
Azeri-Chirag-Gunashli (ACG) (bp 30.37%) and Shah Deniz (SD) (bp
29.99%) and also holds a number of other exploration and development
licenses.
In March bp announced it has agreed for Apollo-managed funds to
purchase a 25% non-controlling stake in BP Pipelines (TANAP)
Limited, the bp subsidiary that holds a 12% share in the Trans
Anatolian Natural Gas Pipeline (TANAP) that carries natural gas from
Azerbaijan across Türkiye, for consideration of approximately $1.0
billion. bp remains the controlling shareholder of BP Pipelines
(TANAP) Limited. A similar deal on purchase by Apollo of a 20% non-
controlling interest in BP Pipelines TAP Limited was completed in
2024.
In June bp and its partners, 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.
In June bp, State Oil Company of the Azerbaijan Republic (SOCAR)
and TPAO signed agreements enabling TPAO to join the PSA for the
Shafag-Asiman offshore block in the Azerbaijan sector of the
Caspian Sea. Following completion, bp and SOCAR each holds 35%,
while TPAO will hold 30% participating interest in the PSA.
In June bp announced it had signed fully termed agreements with
SOCAR to acquire 35% participating interests and become the
operator of each of the Karabagh development block and the
Ashrafi-Dan Ulduzu-Aypara (ADUA) exploration area in the Azerbaijan
sector of the Caspian Sea.
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 SOCAR
as the State representative. Seismic acquisition commenced
thereafter.
Naftiran Intertrade Co Ltd (NICO), a subsidiary of the National Iranian Oil
Company, and LUKOIL Overseas Shah Deniz Limited, a subsidiary of
PJSC LUKOIL, hold a 10% and 19.99% participating interest respectively
in the Shah Deniz PSA. For information on the compliance of this project
with the EU, UK and US trade sanctions, see International trade
sanctions on page 358.
bp holds a 30.1% interest in and operates the Baku-Tbilisi-Ceyhan (BTC)
oil pipeline. The 1,768-kilometre pipeline transports oil from the ACG
oilfield and condensate from the Shah Deniz gas and condensate field in
the Caspian Sea, along with other third-party oil, to the eastern
Mediterranean port of Ceyhan. The pipeline has a capacity of
1mmboe/d, with an average throughput in 2025 of 565mboe/d.
bp as operator of Azerbaijan International Operating Company and the
Georgian Pipeline Company for the Georgian section also operates the
Western Route Export Pipeline (WREP) that transports ACG oil to Supsa
on the Black Sea coast of Georgia. Exports through the pipeline have
been suspended since May 2022 (with occasional short-term exports
driven by operational needs) due to lack of nominations from the
shipper group. In current market conditions WREP serves as a
contingency export route for ACG crude oil.
bp holds a 29.99% interest in and operates certain parts of the 693-
kilometre South Caucasus Pipeline (SCP). The pipeline takes gas from
the Shah Deniz field in Azerbaijan through Georgia to the Turkish border
and has a capacity of 440mboe/d (including expansion), with average
throughput in 2025 of 392mboe/d.
bp also holds a 12% interest in the Trans Anatolian Natural Gas Pipeline
(TANAP). The pipeline takes Shah Deniz gas from the Turkish border and
transports it to Eskisehir in Türkiye and to the Greek border where it
connects with the Trans Adriatic Pipeline (TAP). The current capacity of
TANAP is 275mboe/d and the average throughput in 2025 was
260mboe/d.
bp has a 20% interest in Trans Adriatic Pipeline (TAP), which takes gas
through Greece and Albania into Italy. The current capacity of TAP is
167mboe/d and the total average throughput in 2025 was 173mboe/d.
In Oman, bp operates Block 61 in which bp holds 40% interest. bp also
has a 50% interest in Block 77 operated by Eni.
In Abu Dhabi, bp holds a 10% interest in the ADNOC Onshore
concession and 10% shareholding in the shipping company NGSCO and
10% in Ruwais LNG. ADNOC LNG supplied approximately 5Mt of LNG
(0.7bcfe/d regasified) in 2025. bp’s interest in the ADNOC Onshore
concession expires at the end of 2054.
In June bp acquired a 10% interest in ADNOC’s planned LNG project
in Al Ruwais Industrial City, Abu Dhabi, joining ADNOC Gas (60%
stake), Mitsu & Co, Shell and TotalEnergies (also 10% each). Ruwais
LNG is planned to have two liquefaction trains with a total annual
capacity of 9.6Mt per annum.
In February 2026 bp and the Kuwait Oil Company signed a two-year
extension of the enhanced technical service agreement to support
production optimization of the Burgan oil field.
In Iraq, bp holds a 49% participating interest in Basra Energy Company
Limited (BECL). BECL is an incorporated joint venture (IJV) company
owned by bp (49%) and PetroChina (51%) and acts as Rumaila lead
contractor since 2022.
In March bp received final government ratification for its contract to
invest in the redevelopment of several giant oil fields in Kirkuk, in the
north of Iraq. The contract between North Oil Company, North Gas
Company (NGC) and bp includes the rehabilitation and redevelopment
of the fields, spanning oil, gas, power and water with potential for
investment in exploration. In October this contract became effective,
after agreeing an initial baseline production rate.
In India, bp holds a participating interest in two oil and gas PSAs, KG D6
33.33% and NEC25 33.33%, operated by Reliance Industries Limited
(RIL), and three oil and gas blocks under revenue-sharing contracts, 40%
in KG-UDWHP-2018/1 and 40% in KG-UDWHP-2022/1, operated by RIL;
and 30% in GS-OSHP-2022/2 operated by Oil and Natural Gas
Corporation Limited (ONGC). bp also holds a 50% stake in India Gas
Solutions Private Limited, a joint venture with RIL, for the sourcing and
marketing of gas in India.
bp Annual Report and Form 20-F 2025
343
NavigtionTabCornerV1.jpg
Additional disclosures
In May bp made the FID to invest in an infill wells programme at the
KG D6 block located offshore India
In February bp and ONGC signed agreement under which bp will serve
as the technical services provider for ONGC’s Mumbai High field.
In April bp, RIL and ONGC were awarded a shallow water block GS-
OSHP-2022/2 (ONGC operator 40%, RIL 30%, bp 30%) in Gujarat-
Saurashtra basin, in India's Open Acreage Licensing Policy Bid Round IX.
In the Asian part of Indonesia, bp holds an interest in the Andaman II
PSC exploration block (operated by Harbour Energy), located offshore
North Sumatra, and in Agung I and Agung II exploration blocks offshore
Indonesia. Agung I covers over 6,000km2 off the coast of Bali and East
Java and Agung II spans almost 8,000km2 offshore South Sulawesi,
West Nusa Tenggara and East Java.
Australasia
bp has activities in Australia and Eastern Indonesia.
In Australia bp is one of six participants in the North West Shelf (NWS)
venture, which has been producing LNG, pipeline gas, condensate, LPG
and oil since the 1980s. Five partners hold interest in the gas
infrastructure (bp 16.67%) and six partners hold interest in the gas and
condensate reserves (bp 15.78%). The NWS venture is one of the largest
LNG export projects in the region, with four LNG trains currently in
operation following retirement of one LNG train in late 2024, and also
supplies domestic gas into the Western Australia market. bp’s net share
of the capacity of NWS LNG trains is 2.26Mt (15.78% of 14.3Mtpa gross) of
LNG per year.
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.
bp is one of four participants in Browse LNG Joint Venture, operated by
Woodside (bp 44.33%). The project is aimed at developing natural gas
resources located in the offshore Browse basin.
bp has a 50% interest in the WA-541-P exploration title in Western
Australia's offshore Northern Carnarvon basin. The joint venture,
operated by Santos, is working towards the drilling of two commitment
wells.
bp also has a 100% interest in the WA-551-P exploration title adjacent to
WA-541-P and is currently carrying out prospect maturation activities.
In Papua Barat, Eastern Indonesia, bp operates the Tangguh LNG plant
(bp 40.22%). The plant consists of three trains with total production
capacity of 11.4Mtpa. The Tangguh asset comprises 30 production wells,
four offshore platforms, three LNG processing trains, and two LNG
loading facilities. Tangguh supplies LNG to customers in Indonesia,
Mexico, China, South Korea, Taiwan and Japan through a combination of
long, medium and spot contracts.
In August a consortium of bp (16.09%), its Tangguh partners (23.91%),
operator EnQuest (40%), and Agra (20%) secured the right to explore
the Gaea and Gaea II cover onshore and offshore gas blocks near our
Tangguh LNG facility with the signing of government-backed
contracts
Oil and natural gas
Resource progression
bp manages its hydrocarbon resources in three major categories:
prospect inventory, contingent resources and reserves. When a
discovery is made, volumes usually transfer from the prospect
inventory to the contingent resources category. The contingent
resources move through various sub-categories as their technical and
commercial maturity increases through appraisal activity.
At the point of final investment decision, most proved reserves will be
categorized as proved undeveloped (PUD). Volumes will subsequently
be recategorized from PUD to proved developed (PD) as a consequence
of development activity. When part of a well’s proved reserves depends
on a later phase of activity, only that portion of proved reserves
associated with existing, available facilities and infrastructure moves to
PD. The first PD bookings will typically occur at the point of first oil or
gas production. Major development projects typically take one to five
years from the time of initial booking of PUD to the start of production.
Changes to proved reserves bookings may be made due to analysis of
new or existing data concerning production, reservoir performance,
commercial factors and additional reservoir development activity.
Volumes can also be added or removed from our portfolio through
acquisition or divestment of properties and projects. When we dispose
of an interest in a property or project, the volumes associated with our
adopted plan of development for which we have a final investment
decision will be removed from our proved reserves upon completion of
the transaction. When we acquire an interest in a property or project,
the volumes associated with the existing development and any
committed projects will be added to our proved reserves if bp has
made a final investment decision and they satisfy the SEC’s criteria for
attribution of proved status. Following the acquisition, additional
volumes may be progressed to proved reserves from non-proved
reserves or contingent resources.
Non-proved reserves and contingent resources in a field will only be
recategorized as proved reserves when all the criteria for attribution of
proved status have been met and the volumes are included in the
business plan and scheduled for development, typically within five
years. bp will only book proved reserves where development is
scheduled to commence after more than five years if these proved
reserves satisfy the SEC’s criteria for attribution of proved status and
bp management has reasonable certainty that these proved reserves
will be produced.
At the end of 2025 bp had no proved undeveloped reserves held for
more than five years in our onshore US developments.
Over the past five years, bp has annually progressed a five-year average
of 20% (19% for 2024 five-year average) of our group proved
undeveloped reserves (including the impact of disposals and price
acceleration effects in PSAs) to proved developed reserves. This
equates to a turnover time of five years.
Proved reserves as estimated at the end of 2025 meet bp’s criteria for
project sanctioning and SEC tests for proved reserves. We have not
halted or changed our commitment to proceed with any material
project to which proved undeveloped reserves have been attributed.
In 2025 we progressed 481mmboe of proved undeveloped reserves
(412mmboe for our subsidiaries« alone) to proved developed reserves
through ongoing investment in our subsidiaries’ and equity-accounted
entities’ development activities. Total development expenditure,
excluding midstream activities, was $13,336 million in 2025 ($8,387
million for subsidiaries and $4,949 million for equity-accounted entities).
Of the $8,387 million of total development expenditure for our
subsidiaries, approximately $4,900 million was used for development
activity to progress proved undeveloped reserves to proved developed.
Of the $4,949 million development expenditure for our equity-
accounted entities, approximately $1,800 million was used for
development activity to progress proved undeveloped reserves to
proved developed. The major areas with progressed volumes in 2025
were the US, Azerbaijan, Trinidad and Tobago, Southern Cone and
Middle East.
344
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Revisions of previous estimates for proved undeveloped reserves are
due to changes relating to field performance, well results, revisions to
future activity plans (including alignment with our investment criteria
and changes to the macroeconomic climate) or changes in commercial
conditions including price impacts. The net revisions to previous
estimates across both our subsidiaries and our equity-accounted
entities include net positive revisions driven by revisions to activity
plans, revisions due to well results and revisions driven by price, and net
negative revisions driven by field performance. The net revisions to
previous estimates across only our subsidiaries include net positive
revisions driven by revisions to activity plans, revisions due to well
results and revisions driven by price, and net negative revisions driven
by field performance. In each case, none of these factors resulted in
revisions that were material to the group as a whole. The following
tables describe the changes to our proved undeveloped reserves
position through the year for our subsidiaries and equity-accounted
entities, and for our subsidiaries alone.
volumes in mmboea
Subsidiaries and equity-accounted entities
Group
Proved undeveloped reserves at 1 January 2025
2,387
Revisions of previous estimates
380
Price
78
Revision of future activity plans
409
Field performance
(119)
Well results
12
Improved recovery
20
Discoveries and extensions
125
Purchases
59
Sales
(42)
Total in year proved undeveloped reserves changes
542
Proved developed reserves reclassified as
undeveloped
77
Progressed to proved developed reserves by
development activities (e.g. drilling/completion)
(481)
Proved undeveloped reserves at 31 December 2025
2,525
Subsidiaries only
volumes in mmboea
Proved undeveloped reserves at 1 January 2025
1,875
Revisions of previous estimates
418
Price
88
Revision of future activity plans
416
Field performance
(107)
Well results
22
Improved recovery
15
Discoveries and extensions
66
Purchases
59
Sales
(41)
Total in year proved undeveloped reserves changes
518
Proved developed reserves reclassified as
undeveloped
75
Progressed to proved developed reserves by
development activities (e.g. drilling/completion)
(412)
Proved undeveloped reserves at 31 December 2025
2,055
aBecause of rounding, some totals may not agree exactly with the sum of their component
parts.
bp bases its proved reserves estimates on the requirement of
reasonable certainty, with rigorous technical and commercial
assessments based on conventional industry practice and regulatory
requirements. bp only applies technologies that have been field-tested
and have been demonstrated to provide reasonably certain results with
consistency and repeatability in the formation being evaluated or in an
analogous formation. bp applies high-resolution seismic data for the
identification of reservoir extent and fluid contacts only where there is
an overwhelming track record of success in its local application. In
certain cases bp uses numerical simulation as part of a holistic
assessment of recovery factor for its fields, where these simulations
have been field-tested and have been demonstrated to provide
reasonably certain results with consistency and repeatability in the
formation being evaluated or in an analogous formation. In certain
deepwater fields bp has booked proved reserves before production
flow tests are conducted, in part because of the significant safety, cost
and environmental implications of conducting these tests. The industry
has made substantial technological improvements in understanding,
measuring and delineating reservoir properties without the need for
flow tests. To determine reasonable certainty of commercial recovery,
bp employs a general method of reserves assessment that relies on the
integration of three types of data:
Well data used to assess the local characteristics and conditions of
reservoirs and fluids.
Field-scale seismic data to allow the interpolation and extrapolation
of these characteristics outside the immediate area of the local well
control.
Data from relevant analogous fields.
Well data includes appraisal wells or sidetrack holes, full logging suites,
core data and fluid samples. bp considers the integration of this data in
certain cases to be superior to a flow test in providing understanding of
overall reservoir performance. The collection of data from logs, cores,
wireline formation testers, pressures and fluid samples calibrated to
each other and to the seismic data can allow reservoir properties to be
determined over a greater volume than the localized volume of
investigation associated with a short-term flow test. There is a strong
track record of proved reserves recorded using these methods,
validated by actual production levels.
Governance
bp’s centrally controlled process for proved reserves estimation
approval forms part of a holistic and integrated system of internal
control. It consists of the following elements:
Accountabilities of certain officers of the group to ensure that there
is review and approval of proved reserves bookings independent of
the operating business, and that there are effective controls in the
approval process and verification that the proved reserves estimates
and the related financial impacts are reported in a timely manner.
Capital allocation processes, whereby delegated authority is
exercised to commit to capital projects that are consistent with the
delivery of the group’s business plan. A formal review process exists
to ensure that both technical and commercial criteria are met prior
to the commitment of capital to projects.
Internal audit, whose role is to consider whether the group’s system
of internal control is adequately designed and operating effectively
to respond appropriately to the risks that are significant to bp.
Approval hierarchy, whereby proved reserves changes above certain
threshold volumes require immediate review and all proved reserves
require annual central authorization and have scheduled periodic
reviews. The frequency of periodic reviews ensures that 100% of the
bp proved reserves base undergoes central review every three years.
bp’s vice president of reserves is the individual primarily responsible for
overseeing the preparation of the reserves estimate. He has more than
30 years of diversified industry experience in reserves estimation with
the past five years managing the governance and compliance. He is a
past chairman of the Society of Petroleum Engineers (Russia & Caspian).
No specific portion of compensation bonuses for senior management is
directly related to proved reserves targets. Additions to proved reserves
is one of several indicators by which the performance of the gas & low
carbon energy and oil production & operations segments is assessed by
the remuneration committee for the purposes of determining
compensation bonuses for the executive directors. Other indicators
include a number of financial and operational measures.
bp’s variable pay programme for the other senior managers in the gas &
low carbon energy and oil production & operations segments is based
on individual performance contracts. Individual performance contracts
are based on agreed items from the business performance plan, one of
which, if chosen, could relate to proved reserves.
bp Annual Report and Form 20-F 2025
345
NavigtionTabCornerV1.jpg
Additional disclosures
Compliance
International Financial Reporting Standards (IFRS) do not provide
specific guidance on reserves disclosures. bp estimates proved
reserves in accordance with SEC Rule 4-10 (a) of Regulation S-X and
relevant Compliance and Disclosure Interpretations (C&DI) and Staff
Accounting Bulletins as issued by the SEC staff.
By their nature, there is always risk involved in the ultimate
development and production of proved reserves including, but not
limited to: final regulatory approval; the installation of new or additional
infrastructure, as well as changes in oil and gas prices; changes in
operating and development costs; and the continued availability of
additional development capital. All the group’s proved reserves held in
subsidiaries and equity-accounted entities are estimated by the group’s
petroleum engineers, or by independent petroleum engineering
consulting firms and then assured by the group’s petroleum engineers.
Netherland, Sewell & Associates (NSAI), an independent petroleum
engineering consulting firm, has estimated the net proved crude oil,
condensate, natural gas liquids (NGLs) and natural gas reserves, as of
31 December 2025, of certain properties owned by bp in the US Lower
48. The properties evaluated by NSAI account for 100% of bp’s net
proved reserves in the US Lower 48 as of 31 December 2025. The net
proved reserves estimates prepared by NSAI were prepared in
accordance with the reserves definitions of Rule 4-10(a)(1)-(32) of
Regulation S-X. All reserves estimates involve some degree of
uncertainty. bp has filed NSAI’s independent report on its reserves
estimates as an exhibit to this Annual Report and Form 20-F 2025 filed
with the SEC.
Our proved reserves are associated with both concessions (tax and
royalty arrangements) and agreements where the group is exposed to
the upstream risks and rewards of ownership, but where our
entitlement to the hydrocarbons is calculated using a more complex
formula, such as with PSAs. In a concession, the consortium of which we
are a part is entitled to the proved reserves that can be produced over
the licence period, which may be the life of the field. In a PSA, we are
entitled to recover volumes that equate to costs incurred to develop
and produce the proved reserves, and an agreed share of the remaining
volumes or the economic equivalent. As part of our entitlement is driven
by the monetary amount of costs to be recovered, price fluctuations will
have an impact on both production volumes and reserves.
We disclose our share of proved reserves held in equity-accounted
entities (joint ventures« and associates«), although we do not control
these entities or the assets held by such entities.
bp’s estimated net proved reserves and proved reserves
replacement
94% of our total proved reserves of subsidiaries at 31 December 2025
were held through joint operations« (94% in 2024), and 22% of the
proved reserves were held through such joint operations where we
were not the operator (23% in 2024).
Estimated net proved reserves of crude oil at 31 December
2025abc
million barrels
Developed
Undeveloped
Total
UK
56
41
97
US
599
443
1,042
Rest of North America
South Americad
1
4
6
Africa
2
2
Rest of Asia
691
298
989
Australasia
6
3
8
Subsidiaries
1,354
788
2,143
Equity-accounted entities
566
299
865
Total
1,920
1,088
3,008
Estimated net proved reserves of natural gas liquids at
31 December 2025ab
million barrels
Developed
Undeveloped
Total
UK
1
1
US
204
212
415
Rest of North America
South America
Africa
Rest of Asia
Australasia
1
1
Subsidiaries
206
212
417
Equity-accounted entities
17
5
22
Total
222
217
439
Estimated net proved reserves of liquidsd«
million barrels
Developed
Undeveloped
Total
Subsidiaries
1,560
1,000
2,560
Equity-accounted entities
582
304
887
Total
2,143
1,304
3,447
Estimated net proved reserves of natural gas at 31 December
2025ab
billion cubic feet
Developed
Undeveloped
Total
UK
76
12
88
US
3,009
3,881
6,890
Rest of North America
South Americae
413
358
771
Africa
123
123
Rest of Asia
2,660
1,368
4,028
Australasia
947
498
1,445
Subsidiaries
7,227
6,117
13,344
Equity-accounted entities
1,610
962
2,572
Total
8,837
7,079
15,916
Estimated net proved reserves on an oil equivalent basis
million barrels of oil equivalent
Developed
Undeveloped
Total
Subsidiaries
2,806
2,055
4,861
Equity-accounted entities
860
470
1,330
Total
3,666
2,525
6,191
aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the
royalty owner has a direct interest in the underlying production and the option and ability to
make lifting and sales arrangements independently, and include non-controlling interests in
consolidated operations. We disclose our share of reserves held in joint ventures and
associates that are accounted for by the equity method, although we do not control these
entities or the assets held by such entities.
bThe 2025 marker prices used were Brent $69.512/bbl (2024 $81.171/bbl and 2023 $83.27/bbl)
and Henry Hub $3.409/mmBtu (2024 $2.065/mmBtu and 2023 $2.58/mmBtu).
cIncludes condensate.
dIncludes 1.7 million barrels of liquids in respect of the 30% non-controlling interest in BP
Trinidad and Tobago LLC.
eIncludes 231 billion cubic feet of natural gas in respect of the 30% non-controlling interest in
BP Trinidad and Tobago LLC.
Because of rounding, some totals may not agree exactly with the sum of their
component parts.
Proved reserves replacement
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.
346
bp Annual Report and Form 20-F 2025
« See glossary on page 375
The proved reserves replacement ratio« is the extent to which
production is replaced by proved reserves additions. This ratio is
expressed in oil equivalent terms and includes changes resulting from
revisions to previous estimates, improved recovery, and extensions and
discoveries. For 2025, the proved reserves replacement ratio excluding
acquisitions and disposals was 90% (50% in 2024 and 47% in 2023) for
subsidiaries and equity-accounted entities, 95% for subsidiaries alone
and 69% for equity-accounted entities alone. There was a net increase
(126mmboe) of reserves due to higher gas prices, primarily in our US
subsidiaries, partly offset by a decrease in reserves in some of our PSAs
in Angola.
In 2025 net additions to the group’s proved reserves (excluding
production, sales and purchases of reserves-in-place) amounted to
780mmboe (679mmboe for subsidiaries and 101mmboe for equity-
accounted entities), through revisions to previous estimates including
price, improved recovery from, and extensions to, existing fields, and
discoveries of new fields. The majority of subsidiary additions were
through revisions to previous estimates and extensions to existing
fields and discoveries of new fields, where they represented a mixture
of proved developed and proved undeveloped reserves. The principal
proved reserves additions in our subsidiaries by region were in the US,
Trinidad and the Middle East. The principal reserves additions in our
equity-accounted entities were in Iraq, Angola and Norway.
In January 2024 it was reported that the Oslo District Court had
determined that certain development permits granted by the
Norwegian government during 2023 were invalid. This includes
development permits for two fields in which Aker bp has an interest. The
court’s decision is not final and could be appealed. If bp’s equity-
accounted share of the reserves attributable to these two fields is
removed from the calculation of bp’s 2025 proved reserves ratio, that
ratio would remain the same. Removal of the same reserves from bp’s
2025 reporting would impact proved hydrocarbon reserves for the
group, proved undeveloped reserves and estimated net proved
reserves on an oil equivalent basis, amongst other reported measures,
both for equity-accounted entities and group.
24% of our proved reserves are associated with PSAs. The countries in
which we produced under PSAs in 2025 were Angola, Azerbaijan, Egypt,
India, Indonesia, Mexico and Oman, and includes the technical service
contract (TSC)« governing our investment in the Rumaila field in Iraq
that functions as a PSA.
The group holds no licences in our PSAs or TSCs due to expire within the
next three years that would have a significant impact on bp’s reserves
or production, including undeveloped acreage.
For further information on our reserves see page 248.
bp Annual Report and Form 20-F 2025
347
NavigtionTabCornerV1.jpg
Additional disclosures
bp’s net production by country – crude oila and natural gas liquids
thousand barrels per day
bp net share of productionb
Crude oil
Natural gas
liquids
2025
2024
2023
2025
2024
2023
Subsidiaries
UK
78
70
74
4
4
5
Total Europe
78
70
74
4
4
5
Lower 48 onshorec
108
86
69
87
84
66
Gulf of America deepwater
291
290
266
24
23
22
Total US
399
376
335
111
107
88
Total North America
399
376
335
111
107
88
Trinidad and Tobago
5
4
4
6
4
4
Total South America
5
4
4
6
4
4
Egyptd
7
19
28
1
1
Algeriac
1
1
Mauritania
1
Total Africa
8
19
29
1
2
Abu Dhabi
208
202
197
Azerbaijan
66
66
70
India
6
6
4
Oman
22
23
22
Total Rest of Asia
302
297
293
Total Asia
302
297
293
Australia
6
7
8
1
2
2
Eastern Indonesia
2
2
2
Total Australasia
8
9
10
1
2
2
Total subsidiaries
800
775
745
123
117
100
Equity-accounted entities (bp share)
Argentina
51
52
51
1
1
1
Mexico
4
3
5
Bolivia
1
1
1
Egyptd
3
2
2
2
Norway
55
58
60
2
2
3
Iraq
79
69
62
Angola
75
82
82
3
4
4
Total equity-accounted entities
268
266
261
8
9
9
Total subsidiaries and equity-accounted entitiese
1,069
1,041
1,006
131
126
109
aIncludes condensate.
bProduction excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
cIn 2024 bp disposed of certain Lower 48 onshore interests in the US. In 2023 bp disposed of its interests in Algeria.
dIn 2024 bp disposed of certain interests in Egypt to form Arcius Energy.
eIncludes 2 net mboe/d of NGLs from processing plants in which bp has an interest (2024 2mboe/d and 2023 2mboe/d).
Because of rounding, some totals may not agree exactly with the sum of their component parts.
348
bp Annual Report and Form 20-F 2025
« See glossary on page 375
bp’s net production by country – natural gas
million cubic feet per day
bp net share of productiona
2025
2024
2023
Subsidiaries
UK
203
197
247
Total Europe
203
197
247
Lower 48 onshoreb
1,573
1,530
1,338
Gulf of America deepwater
177
160
149
Total US
1,751
1,690
1,486
Total North America
1,751
1,690
1,486
Trinidad and Tobagob
1,045
1,145
1,191
Total South America
1,045
1,145
1,191
Egyptc
353
904
1,220
Mauritaniad
53
Senegald
48
Algeriab
16
Total Africa
453
904
1,236
Azerbaijan
731
748
714
India
275
303
283
Oman
590
604
582
Total Rest of Asia
1,597
1,655
1,578
Total Asia
1,597
1,655
1,578
Australia
227
276
301
Eastern Indonesia
572
606
473
Total Australasia
799
882
774
Total subsidiariese
5,847
6,474
6,512
Equity-accounted entities (bp share)
Argentina
246
267
247
Bolivia
37
33
50
Mexico
1
1
2
Egyptc
165
9
Norway
54
55
58
Angola
99
76
74
Total equity-accounted entitiese
603
440
432
Total subsidiaries and equity-accounted entities
6,450
6,914
6,944
aProduction excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
bIn 2024 bp disposed of certain interests in Trinidad and Tobago. In 2023 bp disposed of its interests in Algeria and certain Lower 48 onshore interests in the US.
cIn 2024 bp disposed of certain interests in Egypt to form Arcius Energy.
dIn 2025 the Greater Tortue Ahmeyim LNG project in Mauritania and Senegal has begun flowing gas.
eNatural gas production volumes exclude gas consumed in operations within the lease boundaries of the producing field, but the related reserves are included in the group’s reserves.
Because of rounding, some totals may not agree exactly with the sum of their component parts.
bp Annual Report and Form 20-F 2025
349
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Additional disclosures
The following tables provide additional data and disclosures in relation to our oil and gas operations.
Average sales price per unit of production (realizations«)a
$ per unit of production
Europe
North
America
South
America
Africa
Asia
Australasia
Total
group
average
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
2025
Crude oilb
69.20
63.79
70.05
64.50
70.53
63.87
66.92
Natural gas liquids
38.80
20.74
36.08
48.71
22.35
Gas
12.76
2.63
5.20
4.14
7.01
9.36
5.61
2024
Crude oilb
80.81
74.73
81.89
75.21
81.28
70.21
77.77
Natural gas liquids
43.45
20.09
20.46
49.25
21.25
Gas
11.65
1.49
3.42
4.68
6.83
8.95
4.91
2023
Crude oilb
82.99
75.28
84.36
76.30
83.86
68.27
79.37
Natural gas liquids
46.52
19.26
30.76
44.41
33.47
23.79
Gas
16.71
2.08
3.58
4.82
7.72
8.89
5.60
Equity-accounted entitiesc
2025
Crude oilb
68.90
62.47
67.07
61.82
64.90
Natural gas liquids
25.50
49.02
36.90
Gas
11.99
3.69
4.98
2024
Crude oilb
80.10
79.21
78.60
73.86
77.84
Natural gas liquids
27.84
27.84
Gas
10.83
3.38
4.54
2023
Crude oilb
81.61
75.49
80.21
75.21
78.33
Natural gas liquids
30.95
42.89
36.70
Gas
12.80
3.66
5.15
Average production cost per unit of productiond
$ per unit of production
Europe
North
America
South
America
Africa
Asia
Australasia
Total
group
average
UK
Rest of
Europe
US
Rest of
North
America
Subsidiaries
2025
12.82
8.61
4.45
11.19
2.68
1.85
6.28
2024
13.74
9.33
5.27
3.57
2.89
1.78
6.17
2023
10.69
9.61
4.53
2.52
2.81
2.09
5.78
Equity-accounted entities
2025
7.31
20.07
18.42
22.51
17.64
2024
6.16
20.40
18.30
22.88
17.37
2023
6.22
17.87
15.46
16.41
14.38
aUnits of production are barrels for liquids and thousands of cubic feet for gas. Realizations include transfers between businesses.
bIncludes condensate.
cIn certain countries it is common for equity-accounted entities’ agreements to include pricing clauses that require selling a significant portion of the entitled production to local governments or
markets at discounted prices.
dUnits of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes.
350
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Additional information for customers & products
Reconciliation of customers & products RC profit before
interest and tax to underlying RC profit before interest
and tax to adjusted EBITDA« by business
$ million
2025
2024
2023
RC profit (loss) before interest and
tax for customers & productsa
4,100
(1,043)
4,230
Less: Adjusting items gains
(charges)a
(1,172)
(3,560)
(2,183)
Underlying RC profit before interest
and tax for customers & products
5,272
2,517
6,413
By business:
customers – convenience &
mobility
3,764
2,584
2,644
Castrol – included in customers
971
831
730
products – refining & trading
1,508
(67)
3,769
Add back: Depreciation, depletion
and amortization
4,145
3,957
3,548
By business:
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 for customers &
products
9,417
6,474
9,961
By business:
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
a2024 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.
Sales volume
thousand
barrels per
day
2025
2024
2023
Marketing salesa
2,696
2,714
2,718
Trading/supply salesb
494
373
358
Total refined product sales
3,190
3,087
3,076
Crude oilc
72
86
102
Total
3,262
3,173
3,178
aMarketing sales include branded and unbranded sales of refined fuel products and lubricants
to business-to-business and business-to-consumer customers, including service station
dealers, jobbers, airlines, small and large resellers such as hypermarkets, and the military.
bTrading/supply sales are fuel sales to large unbranded resellers and other oil companies.
cCrude oil sales relate to third-party transactions executed primarily by supply, trading and
shipping. In addition, reported crude oil sales in 2025 includes 37 thousand barrels per day
(2024 52 thousand barrels per day and 2023 68 thousand barrels per day) relating to volumes
sold directly by the gas & low carbon energy and oil production & operations segments.
In the table above, volumes of crude oil and refined product trading/
supply sales are presented on a basis consistent with income statement
presentation. These figures do not correspond to actual volumes of
physically traded energy products and are not intended for use in
assessing emissions volumes or carbon intensity. Marketing volumes
shown represent physically delivered transactions regardless of income
statement presentation of such transactions.
Retail sitesa
Number of
bp-branded
retail sites
2025
2024
2023
US
8,750
8,500
8,200
Europe
7,150
7,750
8,050
Rest of world
5,150
4,950
4,850
Total
21,050
21,200
21,100
aReported to the nearest 50. Includes sites operated by dealers, jobbers, franchisees or brand
licensees or joint venture (JV) partners, under the bp brand. These may move to and from the
bp brand as their fuel supply agreement or brand licence agreement expires and is
renegotiated in the normal course of business. Retail sites are primarily branded bp, ARCO,
Amoco, Aral, Thorntons and TravelCenters of America, and also include sites in India through
our Jio-bp JV.
Refinery throughputsabcde
thousand
barrels per
day
2025
2024
2023
US
635
612
662
Europe
805
782
749
Total
1,440
1,394
1,411
%
Refining availability«
96.3
94.3
96.1
aThis does not include bp’s interest in Pan American Energy Group.
bRefinery throughputs reflect crude oil and other feedstock volumes.
cOn 28 February 2023, bp completed the sale of its 50% interest in the bp-Husky Toledo
refinery in Ohio, US to Cenovus Energy, its partner in the facility.
dOn 1 December 2024, bp completed the sale of its 50% ownership in the SAPREF refinery to
the South African state-owned entity Central Energy Fund SOC Ltd.
eOn 6 February 2025 bp announced its intention to market its Ruhr Oel GmbH – BP
Gelsenkirchen operation in Germany for potential sale, including its refinery in Gelsenkirchen
and DHC Solvent Chemie GmbH in Mülheim an der Ruhr.
bp Annual Report and Form 20-F 2025
351
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Additional disclosures
Refinery capacity
The following tablea summarizes bp's average daily crude distillation capacities as at 31 December 2025.
Crude distillation
capacitiesb
Country
Refinery
thousand barrels
per day
US
US North West
US
Cherry Point
251
US Mid West
Whiting
440
 
691
Europe
North West Europe
Germany
Gelsenkirchenc
265
Lingen
97
Netherlands
Rotterdam
394
Mediterranean
Spain
Castellón
110
 
866
Total capacity at 31 December 2025
1,557
aThis does not include bp’s interest in Pan American Energy Group.
bCrude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period under normal operational conditions.
cOn 6 February 2025 bp announced its intention to market its Ruhr Oel GmbH – BP Gelsenkirchen operation in Germany for potential sale, including its refinery in Gelsenkirchen and DHC Solvent
Chemie GmbH in Mülheim an der Ruhr.
352
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Environmental expenditure
$ million
2025
2024
2023
Operating expenditure
435
575
524
Capital expenditure
443
393
329
Clean-ups
16
20
23
Additions to environmental
remediation provision
325
254
228
Increase (decrease) in
decommissioning provision
528
942
920
Operating and capital expenditure on the prevention, control, treatment
or elimination of air and water emissions and solid waste is often not
incurred as a separately identifiable transaction. Instead, it forms part of
a larger transaction that includes, for example, normal operations and
maintenance expenditure. The figures for environmental operating and
capital expenditure in the table are therefore estimates, based on the
definitions and guidelines of the American Petroleum Institute.
Environmental operating expenditure of $435 million in 2025 (2024 $575
million) showed an overall decrease of 24%, largely due to decreased
expenditure in BP Products North America.
Environmental capital expenditure of $443 million in 2025 (2024 $393
million) showed an overall increase of 13%, largely due to increased
expenditure for BP Products North America.
Clean-up costs were $16 million in 2025 (2024 $20 million), representing
oil spill clean-up costs and other associated remediation and disposal
costs.
In addition to operating and capital expenditure, we also establish
provisions for future environmental remediation work. Expenditure
against such provisions normally occurs in subsequent periods and is
not included in environmental operating expenditure reported for such
periods.
Provisions for environmental remediation are made when a clean-up is
probable and the amount of the obligation can be reliably estimated.
Generally, this coincides with the commitment to a formal plan of action
or, if earlier, on divestment or on closure of inactive sites.
The extent and cost of future environmental restoration, remediation
and abatement programmes are inherently difficult to estimate. They
often depend on the extent of contamination, and the associated
impact and timing of the corrective actions required, technological
feasibility and bp’s share of liability. Though the costs of future
programmes could be significant and may be material to the results of
operations in the period in which they are recognized, it is not expected
that such costs will be material to the group’s overall results of
operations or financial position. For further information, see Note 1
Significant judgements and estimates: provisions.
Additions to our environmental remediation provision reflect new
liabilities and scope/cost reassessments of the remediation plans of a
number of our sites, primarily in the US. The charge for environmental
remediation provisions in 2025 arising from new and acquired sites was
$4 million (2024 $24 million and 2023 $37 million).
In addition, we make provisions on installation of our oil and gas
producing assets and related pipelines to meet the cost of eventual
decommissioning. On installation of an oil or natural gas production
facility, a provision is established that represents the discounted value
of the expected future cost of decommissioning the asset.
In 2025 the net increase in the decommissioning provision was primarily
due to recognition of additional provisions from new infrastructure and
changes in cost estimate assumptions. .
We undertake periodic reviews of existing provisions. These reviews
take account of revised cost assumptions, changes in decommissioning
requirements and any technological developments.
Provisions for environmental remediation and decommissioning are
usually established on a discounted basis, as required by IAS 37
‘Provisions, Contingent Liabilities and Contingent Assets’.
Further details of decommissioning and environmental provisions
appear in Financial statements – Note 23.
Regulation of the group’s business
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 cover virtually all aspects of bp’s activities and
include matters such as the acquisition of rights to develop and operate
projects, production rates, royalties, environmental, health and safety
protection, fuel specifications and transportation, trading, pricing, anti-
trust, export, taxes, and foreign exchange.
Oil and gas contractual and regulatory framework
The terms and conditions of the leases, licences and contracts under
which our upstream oil and gas interests are held vary from country to
country. These leases, licences and contracts are generally granted by
or entered into with a government entity or state-owned or controlled
company and are sometimes entered into with private property owners.
Arrangements with governmental or state entities usually take the form
of licences or production-sharing agreements (PSAs)«, although
arrangements with private entities and US government entities are
usually by lease.
Licences (or concessions) give the holder the right to explore for,
develop and produce a commercial discovery. Under a licence, the
holder bears the risk of exploration, development and production
activities and provides the financing for these operations. In principle,
the licence holder is entitled to all production, minus any royalties that
are payable in kind. A licence holder is generally required to pay
production taxes or royalties, which may be in cash or in kind.
In certain countries, separate licences are required for exploration and
production activities, and in some cases production licences are limited
to only a portion of the area covered by the original exploration licence.
PSAs entered into with a government entity or state-owned or state-
controlled company generally require bp (alone or with other
contracting companies) to provide all the financing and bear the risk of
exploration and production activities in exchange for a share of the
production remaining after royalties, if any. Less typically, bp may
explore for, develop and produce hydrocarbons under a service
agreement with the host entity in exchange for reimbursement of costs
and/or a fee paid in cash rather than production.
bp frequently conducts its exploration and production activities in joint
arrangements or co-ownership arrangements with other international
oil companies, state-owned or -controlled companies and/or private
companies. Conventionally, all costs, benefits, rights, obligations,
liabilities and risks incurred in carrying out joint arrangement or co-
ownership operations under a lease, licence or PSA are shared among
the joint arrangement or co-owning parties according to agreed
ownership interests which are set out in a joint operating agreement. To
the extent that any liabilities arise, whether to governments or third
parties, or between the joint arrangement parties or co-owners
themselves, each joint arrangement party or co-owner will generally be
liable under the terms of a joint operating agreement to meet these in
proportion to its ownership interest. Any agreed allocation of liability
amongst the joint arrangement parties is, however, often different to
the position under the relevant licence, lease or PSA, which may provide
for joint and several liability of the joint arrangement parties including
for decommissioning obligations. In many upstream operations, a party
(known as the operator) will be appointed (pursuant to a joint operating
agreement) to carry out day-to-day operations on behalf of the joint
arrangement or co-ownership. The operator is typically one of the joint
arrangement parties or a co-owner and will carry out its duties either
through its own staff, or by contracting out various elements to third-
party contractors or service providers. bp acts as operator on behalf of
joint arrangements and co-ownerships in a number of countries.
Frequently, work (including drilling and related activities) will be
contracted out to third-party service providers. The relevant contract
will specify the work, the remuneration, and typically the risk allocation
between the parties. Depending on the service to be provided, the
bp Annual Report and Form 20-F 2025
353
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Additional disclosures
contract may also contain provisions allocating risks and liabilities
associated with pollution and environmental damage, damage to a well
or hydrocarbon reservoirs and for claims from third parties or other
losses. The allocation of those risks varies among contracts and is
determined through negotiation between the parties.
In general, bp incurs income tax on income generated from production
activities (whether under a licence or PSA). In addition, depending on the
area, bp’s production activities may be subject to a range of other taxes,
levies and assessments, including special petroleum taxes and revenue
taxes. The taxes imposed on oil and gas production profits and activities
may be substantially higher than those imposed on other activities, for
example in Egypt, the UK, the US and the United Arab Emirates.
Low carbon energy – renewables contractual and
regulatory framework
The majority of our renewable assets are held indirectly through
interests in incorporated joint ventures or special purpose entities (in
either case, a Project Company). The renewables contractual and
regulatory framework and the rights granted in relation to a renewable
asset significantly vary from country to country. In some countries, the
regulatory framework is still under development or subject to
significant change as the renewables industry evolves.
In general terms the rights to a renewable asset are usually held by a
Project Company through a package of assets that together form the
renewable project owned by such Project Company, including:
one or more leases, easements or licences over land or seabed
granted by a public or private individual or entity that grant the
Project Company rights to develop, build and operate the renewable
asset in such areas of land or seabed;
one or more generation licences that grant the Project Company the
right to produce and sell the electricity to the market;
an interconnection agreement that grants the Project Company the
right to connect the power project into the grid;
an offtake agreement which, depending on the country’s electricity
market, is entered into with a utility company, a corporate buyer or a
public entity; and
potentially, a subsidy mechanism in the form of a feed in tariff,
contract for difference, hedging mechanism or renewable energy
certificate to support the development of the project.
The risk allocation between the developer/generator and the host
government or private entity has not been standardized in the industry.
However, in general terms the Project Company bears the risk of the
development, construction and operation of the renewable energy
project and secures the financing for these operations and receives any
profit from the revenue generated through the offtake agreement and/
or subsidy mechanism (if available).
Greenhouse gas regulation
In December 2015, nearly 200 nations at the United Nations climate
change conference in Paris (COP21) agreed to the Paris Agreement
which aims to hold the increase in the global average temperature to
well below 2°C above pre-industrial levels and to pursue efforts to limit
the temperature increase to 1.5°C above pre-industrial levels.
Signatories aim to reach global peaking of greenhouse gas (GHG)
emissions as soon as possible and to undertake rapid reductions
thereafter, so as to achieve a balance between human caused
emissions and removals by sinks of GHGs in the second half of this
century. The Paris Agreement commits all signatories to submit
Nationally Determined Contributions (NDCs) (i.e. pledges or plans of
climate action) and pursue domestic measures aimed at achieving the
objectives of their NDCs. Signatories are required to submit revised
NDCs every five years, and the revised NDCs are expected to be more
ambitious with each revision. The first global stocktake of progress was
published by the United Nations in September 2023 and further
assessments will occur every five years. The UAE conference (COP28) in
Dubai, which took place in November and December 2023, marked the
conclusion and outcome of this first stocktake and reached a
consensus which includes calls for an acceleration of efforts towards
the phase-down of unabated coal power and to transition away from
fossil fuels in energy systems. The 2024 Baku conference (COP 29)
included agreements in relation to finance and carbon markets. The
2025 Belém conference (COP30) included agreement to triple
adaptation finance by 2035, and emphasized accelerating the shift to
renewable energy sources, and ensuring a just transition.
More stringent national and regional measures relating to the transition
to a lower carbon economy, such as the UK's 2050 net zero carbon
emissions commitment, can be expected in the future. These measures
could increase bp’s production costs for certain products, increase
compliance and litigation costs, increase demand for competing energy
alternatives or products with lower-carbon intensity, and affect the
sales and specifications of many of bp’s products. Further, such
measures could lead to constraints on production and supply and
access to new reserves, particularly due to the long-term nature of
many of bp’s projects.
Certain current and announced GHG measures and developments
potentially affecting bp’s businesses in various markets in which bp
operates are summarized below. For information on steps that bp is
taking in relation to climate change issues and for details of bp’s GHG
reporting, see page 37.
United States
In the US, bp's operations are affected by the regulation of GHGs in a
number of ways. The federal Clean Air Act (CAA) and its various
amendments regulate air emissions, permitting, fuel specifications and
other aspects of our production, refining, distribution and marketing
activities.
GHG Reporting Rule
The federal GHG Mandatory Reporting Rule requires operators of
certain facilities and producers and importers/exporters of petroleum
products to file annual GHG emissions reports with EPA quantifying
direct GHG emissions from affected facilities, as well as the GHG
emissions that would result from the release or combustion of the
petroleum products imported, exported or produced. In addition,
several states have their own GHG reporting rules.
Our US businesses are subject to GHG and other environmental
requirements and regulatory uncertainty, including that the current or
any future US administration could revise or revoke current or prior
administration programmes, as well as the possibility of increased
expenditures in having to comply with numerous diverse and non-
uniform regulatory initiatives at the state and local levels. In September
2025, the United States Environmental Protection Agency (US EPA)
proposed regulations that would revoke or suspend GHG reporting
requirements for the oil and gas sector for 10 years.
US Inflation Reduction Act
The 2022 US Inflation Reduction Act (IRA) included a significant package
of largely supply-side measures supporting low carbon energy sources
and decarbonization technologies in the US. In 2023, bp applied for
various DOE and FAA grants related to certain of bp’s low carbon
energy and decarbonization projects. In 2024 DOE and FAA notified bp
of its grant awards and bp and its co-applicants executed award
agreements with the DOE. On 20 January 2025, the Trump
Administration issued an Executive Order directing agencies to pause
the disbursement of IRA funding for review. This Order is subject to
legal challenges that have resulted in the effective suspension of
implementation pending judicial resolution.
Methane
In 2024 the EPA promulgated the “Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review.” These
regulations focused on methane and volatile organic compound
emissions from oil and gas production at new and existing facilities and
include significant requirements in the areas of fugitive emissions
monitoring and repair, flaring, emission event reporting, process
controller and pump emissions, and storage vessels. In March 2025, the
EPA announced reconsideration of the 2024 regulations, and, in
December 2025, finalized the Interim Final Rule extending many of the
original compliance deadlines in the 2024 regulations.
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Separate from the above, the IRA required EPA to collect an annual
Waste Emissions Charge (WEC) on methane emissions from oil and
natural gas facilities that exceed specific levels of emissions and
methane intensity. In November 2024, EPA promulgated regulations to
implement the WEC provisions of the IRA, but those regulations were
disapproved by the US Congress in March 2025 and are no longer in
place.
Climate Resilience Funds
Several US states, including New York and Vermont, have enacted laws
seeking recovery from historical GHG emitters to create climate
resilience funds to address climate change impacts by financing
infrastructure upgrades, disaster preparation, and other resilience
projects. Other states, including New Jersey, California, Maryland and
Massachusetts, are considering similar legislation. The extent and cost
of such future environmental climate fund programmes are difficult to
estimate at this time.
Electricity
Other EPA GHG and environmental regulations affect electricity
generation practices and prices and have an impact on the market for
fuels used to generate electricity and on renewable energy installations.
These regulations are in flux due to changes in approach between
presidential administrations, as well as lawsuits challenging those
regulations.
The 2022 Supreme Court decision in West Virginia v. EPA limited EPA’s
regulatory authority to require electricity 'generation shifting' (e.g. from
coal to natural gas or renewable sources). In response to the West
Virginia v. EPA decision, in April 2024 EPA promulgated new carbon
pollution standards for coal and gas-fired power plants. The regulations
significantly tighten emissions limits for those plants and will require
some plants to install carbon capture technology. In 2025 EPA
proposed repealing those regulations.
Renewable Fuel Standard
EPA’s Renewable Fuel Standard (RFS) regulations require transportation
fuel sold in the US to contain a minimum volume of renewable fuels. In
2023, EPA announced a final rule establishing biofuel volume
requirements and associated percentage standards (renewable volume
obligations or RVOs) for cellulosic biofuel, biomass-based diesel,
advanced biofuel, and total renewable fuel for 2023-2025, which was
remanded to EPA and the wildlife agencies for further explanation. EPA
is delayed in promulgating RVOs for 2026, but in a deadline lawsuit
challenging the agency’s delay, EPA stated its intention to finalize the
regulations in the first quarter of 2026.
State Low Carbon Fuel Standards
A number of states, municipalities and regional organizations continue
to advance climate initiatives that affect our US operations. For
example, California, Oregon, and Washington impose carbon-intensity
reduction requirements on transportation fuels sold in those states. In
November 2024, California updated its Low Carbon Fuel Standard
(LCFS) to achieve a 30% reduction in carbon intensity by 2030 and a
90% reduction in carbon intensity by 2045. In 2024 New Mexico became
the latest US state to enact LCFS legislation, with regulations likely to
take effect in 2026.
Mobile Source Emissions
US fuel markets are affected by EPA and National Highway Traffic
Safety Administration (NHTSA) regulation of light, medium and heavy-
duty vehicle emissions (both fuel economy and tailpipe standards) as
well as for non-road engines and vehicles and certain large GHG
stationary emission sources. In August 2025, EPA issued a proposed
recission of all federal GHG emission standards and the Endangerment
Finding that provides the legal justification for such GHG standards for
light-, medium- and heavy-duty vehicles. EPA has not yet finalized the
proposed recissions and legal challenges to rescinding the 2009
Endangerment Finding are expected. In December 2025, NHTSA
proposed to reduce the stringency of fuel economy standards for light-
duty vehicles. Relatedly, in July 2025, the US Congress eliminated civil
penalties for non-compliance with corporate average fuel economy
standards.
Light-duty and Medium Duty Vehicles
In March 2024, EPA promulgated a final rule entitled “Multi-Pollutant
Emissions Standards for Model Year 2027 and Later Light-Duty and
Medium-Duty Vehicles,” which significantly tightens emissions
standards for light- and medium-duty vehicles for model year (MY) 2027
and beyond and imposes new warranty, durability, and certification
requirements, including for electric vehicles. The regulations are
intended to spur emissions reductions technology on hydrocarbon-
powered vehicles and to encourage the transition to electric vehicles.
The regulations will phase in over MY 2027-2032. In March 2025, EPA
announced that it would reconsider the regulations.
Heavy-Duty Vehicles
In 2022, EPA promulgated a final rule entitled “Control of Air Pollution
from New Motor Vehicles: Heavy Duty Engine and Vehicle Standards,”
which established new emission standards for oxides of nitrogen (NOx)
and other pollutants for highway heavy-duty engines. In March 2025,
EPA announced that it would re-evaluate that final rule.
California Mobile Sources
The CAA authorizes the state of California to set its own separate
vehicle emissions regulations, stricter than those at the federal level.
Under CAA Section 209, California can apply to EPA for a waiver of
federal pre-emption, and EPA is to grant this waiver absent certain
disqualifying conditions. Under CAA Section 177, other states can adopt
California standards or follow federal standards but cannot set their
own. In May 2025, the US Congress passed resolutions under the
Congressional Review Act (CRA) rescinding EPA waivers covering
California’s Advanced Clean Cars (ACC) II, Advanced Clean Trucks (ACT),
and Heavy-Duty Low NOx Omnibus (Omnibus) regulations, which set
emissions standards and sales mandates for zero-emission vehicles
(ZEVs) in the state. California and other states have sued to challenge
these CRA recissions, and California has offered manufacturers
alternative paths for certification of new vehicles in the state – including
continued compliance with the regulations subject to CRA disapproval,
compliance with superseded California standards, or compliance with
EPA standards and certification requirements. Meanwhile, EPA and
other parties have contested whether California can fall back on pre-
existing standards or else require certification within the state for
current and future model years.
In October 2025, a federal district court issued a preliminary injunction
barring California from attempting to enforce the Clean Truck
Partnership – a 2023 agreement between California and the heavy-duty
vehicle and engine manufacturers under which the manufacturers
agreed to comply with California regulations in exchange for more lead
time and other measures. Claims challenging California’s continued
enforcement of ACC II, ACT and Omnibus remain pending in the case.
California Advanced Clean Cars Program
California’s ACC regulations were originally enacted in 2012 for MY 2015
to 2025. The ACC program is a package of state regulations that set
emissions standards for criteria pollutants, GHG emission standards for
light-duty vehicles, and a ZEV sales mandate. In 2019, EPA and NHTSA
jointly promulgated the “Safer Affordable Fuel-Efficient Vehicles Rule
Part One: One National Program (SAFE-1),” which effectively disallowed
the ACC program. In 2021, EPA revoked SAFE-1, and the ACC program
went back into force. In response to a legal challenge, the US Court of
Appeals for the DC Circuit upheld EPA’s decision to restore the
California waiver. That decision was appealed to the Supreme Court,
which did not review the waiver itself but held that fuel producers had
standing to challenge the waiver. That litigation is now stayed as EPA
again reconsiders the waiver decision. In 2022, California finalized the
next generation of its GHG and ZEV standards ACC II sets annual ZEV
and plug-in hybrid vehicle (PHEV) sales requirements from MY 2026 to
2035 and increasingly more stringent emission standards to ensure
automakers gradually phase out new sales of internal combustion
engine vehicles.
In 2023 California filed a CAA Section 209 waiver of federal pre-emption
application with EPA. In December 2024, EPA granted California’s
waiver under ACC II that requires that by MY 2035, all new light-duty
vehicles sold in California must be ZEVs or PHEVs. As noted above, in
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Additional disclosures
May 2025, Congress passed the CRA resolution rescinding the ACC II waiver,
which California and other states have challenged.
California Advanced Clean Trucks Program
In 2023, EPA granted California’s request for a waiver of federal
preemption covering, in part, ACT regulations, which mandate
increasing quantities of ZEV sales for medium- and heavy-duty vehicles
in the state. As noted above, in May 2025, the US Congress passed a
resolution under the CRA that purports to void that waiver. Legal
challenges to the CRA resolution, as well as legal challenges to
continuing efforts to enforce the ACT Program, have been filed and are
pending.
EPA Proposal to Rescind Endangerment Finding
In 2025 EPA proposed to rescind the 2009 Endangerment Finding,
which forms the statutory basis for GHG emissions regulations for
motor vehicles and engines under the Clean Air Act, including the Biden
Administration electric vehicle mandates. If finalized, the proposal
would remove all GHG standards for light-, medium- and heavy-duty
vehicles and heavy-duty engines. EPA indicated it will solicit public
comment on the proposal.
These and other initiatives regarding GHG emissions create significant
regulatory uncertainty and may have a significant effect on the
production, sale and profitability of many of bp’s products in the US.
European Union
The EU has adopted a goal of achieving climate neutrality by 2050 as
part of the European Green Deal and, subsequently, a 55% GHG
reduction target by 2030 and a 90% target by 2040, both compared to
1990 levels. To achieve the 2030 target, EU member states and
Parliament adopted most measures proposed as part of the so-called
‘Fit for 55’ package. These include: revisions of the EU Emissions Trading
Scheme (EU ETS) and a newly created Carbon Border Adjustment
Mechanism (CBAM); the Renewable Energy Directive (RED) – including
an obligation on transport fuel suppliers to increase the share of
renewables of their fuel supply; a sustainable aviation fuel (SAF)
blending mandate from 2025; and CO2 targets for the sales of new
vehicles which are expected to accelerate the decarbonization of the
transport sector and impact fuel demand despite certain flexibilities for
vehicle manufacturers currently under discussion. We expect changes
to some of these laws as part of planned reviews and to bring them in
line with the recently agreed 2040 GHG reduction target.
Pending full implementation and ongoing and future revisions of these
laws, this would inter alia lead to higher shares of renewables across all
sectors (including transport), higher cost to supply fuels due to a cap-
and-trade system for the road transport and buildings sector starting in
2028, a continuously reduced number of GHG emission allowances and
associated free allocation under the EU ETS, and a continued decline of
fuel demand from new cars and trucks linked to CO2 targets for vehicle
manufacturers. The EU also adopted measures that may impact the
ability to import certain crude oils and natural gas into the region.
Some EU member states have adopted national targets above and
beyond current EU climate goals, such as Germany, with a climate
neutrality target by 2045.
United Kingdom
In November 2024, the UK government announced a nationally
determined contribution target to reduce all greenhouse gas emissions
by at least 81% by 2035 compared to 1990 levels.
The UK Emissions Trading System (UK ETS) launched on 1 January 2021
following the end of the Brexit transition period and the UK’s
participation in the EU ETS. It seeks to provide a carbon pricing
mechanism as a tool for helping achieve the UK's net zero target and
covers the same GHGs and sectors as the EU ETS. bp’s North Sea
operations are subject to the UK ETS.
In July 2023, the UK government published a response to a 2022
consultation on proposed changes to the UK ETS rules. That response
included decisions to expand the scope of the scheme to include
domestic maritime transport from 2026, waste incineration and energy
from waste from 2028 and process emissions from carbon dioxide
venting from the upstream oil and gas sector from 2025.
In November 2025, the UK government and the UK ETS Authority
published their combined response to the December 2023 Free
Allocation Review and the December  2024 Carbon Leakage
consultations. In relation to data and benchmarking, the UK ETS
Authority decided that operators can choose to have their activity data
for either 2020 only, or 2020 and 2021, excluded from determining their
historical activity level for the 2027-30 allocation period. Current
benchmarks for 2027 are retained, with the intention of adopting
updated EU benchmark values from 2028-30. In relation to carbon
leakage, the UK ETS Authority decided that: (i) The current list of sectors
subject to carbon leakage is retained; (ii) It will not introduce the tiering
of free allocations of UK ETS allowances for sectors at risk of carbon
leakage based on the carbon leakage exposure factor or cross-sectoral
correction factor; (iii) It will not bring forward the phase out of free
allocations for sectors not at risk of carbon leakage; (iv) No additional
benchmarking methodologies will be introduced in 2027, which would
have introduced conditions on the provision of free allocation to
installations with exceptional access to decarbonisation technologies.
Their introduction may be reconsidered for future allocation periods;
and (v) It will gradually phase out free allocations for sectors covered by
the UK Carbon Border Adjustment Mechanism (UK CBAM) beginning in
2027, with an indicative phase out trajectory of nine years.
In December 2025, the UK ETS published the response to its December
2023 Future Markets Policy consultation. The response indicates that
the UK ETS Authority will retain and inflation-proof the auction reserve
price to maintain its real value, implementing an inflation-based
increase since its introduction in 2026, and increasing the value yearly
by inflation from 2027. It will retain the existing design and operation of
the cost containment mechanism and retain its discretion. It will also
discount the implementation of a quantity-triggered supply adjustment
mechanism for a standalone UK ETS.
In December 2025, UK government also published a response to the UK
ETS Authority’s consultation to extend the UK ETS beyond 2030. The
response confirmed it will be extended into a Phase II from 2031, which
will run for 10 years from 1 January 2031 to 31 December 2040, and
banking of allowances will be permitted between Phase I and Phase II.
Other countries and regions
China is operating emissions trading pilot programmes in a number of
cities and provinces. One of bp's subsidiaries in China is participating in
these programmes. In February 2021 China introduced a national
emissions trading market (National ETS). The National ETS is intended to
be an essential tool for China to fulfil its commitment to reach peak
emissions by 2030 and carbon neutrality by 2060. On 9 September
2024, the Ministry for Ecology and Environment of China (the MEE)
released a draft work plan to expand the sectoral coverage of the
National ETS. Currently covering only the power sector, the plan
proposes to extend the National ETS to include the cement, steel, and
aluminium industries. In March 2025, the MEE officially expanded the
sectoral coverage of the National ETS to include the cement, steel, and
aluminium industries. The expansion would bring an additional
approximately 1,500 companies into the National ETS. For now, the
National ETS participants are limited to the key emission entities
identified by each provincial-level government authority based on the
standard set out by the MEE. bp is not participating in the National ETS.
In October 2021, as part of its ‘1+N’ climate policy framework, China
issued working guidance setting out specific targets and measures for
achieving peak carbon emissions and carbon neutrality, and an action
plan which sets out the main objectives for the next decade to achieve
peak carbon emissions by 2030. The working guidance is the '1' (i.e. a
long-term approach to combating climate change), while 'N' are various
policies starting with the action plan. In June 2022, 17 government
authorities jointly released the National Climate Change Adaptation
Strategy 2035 making overall plans to prepare the country to adapt to
climate change from the present to 2035.
China's domestic voluntary carbon mechanism called the China
Certified Emission Reduction (CCER) programme has been suspended
since 2017. In 2023, significant progress towards relaunching the CCER
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has been made by relevant authorities, including the promulgation of a
regulation on CCER trading for trial implementation and the publication
of methodologies that will be used to quantify net emission reductions
or removals for four types of projects (forestation, solar thermal power,
offshore wind power generation and mangrove revegetation). CCER
programme was relaunched on 22 January 2024 and the first CCER
project after the relaunch was registered on 3 December 2024. On 3
January 2025, two new CCER methodologies were released – for
issuing carbon credits to projects utilizing coal mine gas and energy
efficient highway tunnel lighting. First batch of new CCERs was issued
in March 2025 and more CCER methodologies were released in 2025.
On 5 January 2024, China’s State Council approved an interim
regulation for the national emissions trading scheme. The final version
was issued on 4 February 2024 which has provisions on defining the
scale of the national carbon market, determining allocation of
emissions allowances and data quality supervision.
Other environmental regulation
In addition to the GHG regulations referred to above, climate change
programmes and regulation of unconventional oil and gas extraction
under a number of environmental laws may have a significant effect on
the production, sale and profitability of many of bp’s products.
Environmental laws also require bp to remediate and restore areas
affected by the release of hazardous substances or hydrocarbons
associated with our operations or properties. These laws may apply to
sites that bp currently owns or operates, sites that it previously owned
or operated, or sites used for the disposal of its and other parties’
waste. See Financial statements – Note 23 for information on provisions
for environmental restoration and remediation.
A number of pending or anticipated governmental proceedings against
certain bp group companies under environmental laws could result in
monetary or other sanctions. Group companies are also subject to
environmental claims for personal injury and property damage alleging
the release of, or exposure to, hazardous substances. The costs
associated with future environmental remediation obligations,
governmental proceedings and claims could be significant and may be
material to the results of operations in the period in which they are
recognized. We cannot accurately predict the effects of future
developments, such as stricter environmental laws and regulations or
enforcement policies, or future events at our facilities on the group, and
there can be no assurance that material liabilities and costs will not be
incurred in the future. For a discussion of the group’s environmental
expenditure, see page 352 and for a discussion of legal proceedings,
see page 236.
Significant health, safety and environmental legislation and regulation
affecting our businesses and profitability, in addition to those referred
to above, include the following:
United States
The Clean Water Act regulates wastewater and other effluent
discharges from bp’s facilities, and bp is required to obtain
discharge permits, install control equipment and implement
operational controls and preventative measures.
The Resource Conservation and Recovery Act (RCRA) regulates the
generation, storage, transportation and disposal of wastes
associated with our operations and can require corrective action at
locations where such wastes have been disposed of or released. bp
has incurred, or is likely to incur, liability under RCRA or similar state
laws in connection with sites bp operates or previously operated.
The Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA) can, in certain circumstances, impose the
entire cost of investigation and remediation on a party who owned or
operated a site contaminated with a hazardous substance, or who
arranged for disposal of a hazardous substance at a site. bp has
incurred, or is likely to incur, liability under CERCLA or similar state
laws, including costs attributed to insolvent or unidentified parties.
bp is also subject to claims for remediation costs and natural
resource damages under CERCLA and other federal and state laws.
CERCLA also requires reporting on the releases of certain quantities
of listed hazardous substances to designated government agencies.
In April 2024, EPA listed PFOA and PFOS (types of perfluoroalkyl
substances (PFAS) used in fire-fighting foam and many consumer
products) as hazardous substances under CERCLA. This listing may
impact remediation costs and result in additional reporting and
other environmental obligations. Several states have passed
legislation limiting the use of PFAS in fire-fighting foam, and other
states may do so in the future.
The Emergency Planning and Community Right-to-Know Act
requires reporting on the storage, use and releases of certain
quantities of listed extremely hazardous substances to designated
government agencies.
The Toxic Substances Control Act regulates bp’s manufacture,
import, export, sale and use of chemical substances and products. In
addition, EPA has revised processes and procedures for prioritization
of existing chemicals for risk evaluation, assessment and
management. Agency actions and announcements are monitored
regularly to identify developments with potential impacts on
chemical substances important to bp products and operations.
The Occupational Safety and Health Act imposes workplace safety
and health requirements on bp operations along with significant
process safety management obligations, requiring continuous
evaluation and improvement of operational practices to enhance
safety and reduce workplace emissions at gas processing, refining
and other regulated facilities.
The Oil Pollution Act 1990 imposes operational requirements, liability
standards and other obligations governing the transportation of
petroleum products in US waters. States may impose additional
obligations. Alaska, West Coast and certain East Coast states impose
additional requirements and stricter liability standards.
The Outer Continental Continental Shelf Land Act, the Mineral
Leasing Act and other statutes give the Department of Interior (DOI)
and the Bureau of Land Management authority to regulate
operations and air emissions, including equipment and testing, at
offshore and onshore operations on federal lands subject to DOI
authority.
The Endangered Species Act (ESA) and Marine Mammal Protection
Act protect certain species’ habitats from adverse human impacts
by restricting operations or development at certain times and in
certain places. In 2020, the US Fish and Wildlife Service (FWS)
published regulatory definitions impacting habitat designations
under the ESA, but in 2022 the Biden administration rescinded those
definitions. The Biden administration rescission of those definitions
could expand the geographic areas subject to habitat protections. In
November 2025, the FWS proposed to reinstate the 2020 version of
the habitat designation regulations.
European Union
The Industrial Emissions Directive (IED) 2010 provides the framework
for granting permits for major industrial sites. Revised IED entered
into force in August 2024, strengthening the application of Best
Available Techniques (BATs) and introducing stricter emission limit
values and binding environmental performance levels, among other
changes. It will impact bp refineries across Europe.
The EU Registration, Evaluation Authorization and Restriction of
Chemicals (REACH) Regulation 2006 requires registration of
chemical substances manufactured in or imported into the EU,
together with the submission of relevant hazard and risk data.
REACH affects our manufacturing or trading/import operations in
the EU. bp maintains compliance by checking whether imports are
covered by the registrations of non-EU suppliers’ representatives,
preparing and submitting registration dossiers to cover new
manufactured and imported substances, and updating previously
submitted registrations as required.
The Water Framework Directive (WFD) published in 2000 aims to
protect the quantity and quality of ground and surface waters of the
EU member states. The transposition into national laws is still
ongoing and planned to be finalized by 2027. Future proceedings on
the determination of pollutants/priority substances as well as
environmental quality standards in line with the WFD may require
additional compliance efforts and increased costs for managing
freshwater withdrawals and discharges from bp’s EU operations.
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Additional disclosures
The Corporate Sustainability Reporting Directive (CSRD) entered into
force on 5 January 2023 introducing new requirements for certain
EU and non-EU companies, to include disclosures related to climate,
the environment and wider sustainability issues. The CSRD also
expands to in-scope entities the requirements introduced by the EU
Taxonomy Regulation, to identify environmentally sustainable
activities and then disclose metrics related to capital and operating
expenditure and turnover associated with those activities. Under the
2025 Omnibus simplification package, the application of CSRD
reporting requirements has been delayed by two years for many in-
scope companies, with reporting expected to begin in 2027 for
FY2026.
The Corporate Sustainability Due Diligence Directive (CSDDD)
entered into force in July 2024 but has undergone targeted
amendments as part of the Omnibus package. It still requires certain
EU and non-EU companies to conduct due diligence on human rights
and environmental risks but no longer includes the obligation to
adopt a climate transition plan. In-scope companies are expected to
comply in July 2029 for FY2028.
United Kingdom
Following the UK’s exit from the European Union, operative EU laws
were retained in UK law by the European Union (Withdrawal) Act 2018
(EUWA). In June 2023, the Retained EU Law (Revocation and Reform)
Act 2023 received Royal Assent. From 1 January 2024, retained EU
law is now termed “assimilated law,” and the Act removed the
principle of EU law supremacy and direct effect. The Act allows for
significant changes to the status, operation and content of retained
EU law, including through amendments to the EUWA. This may mean
that over time there will be amendments to and deviations from
retained EU law including in respect of environmental matters.
Since the end of the transition period on 31 December 2020, there
has been a parallel UK REACH regime which applies in Great Britain
only, with EU REACH continuing to apply in Northern Ireland. UK
REACH contains equivalent requirements to EU REACH, although
future developments and potential divergences are uncertain.
The Environment Act 2021 comprises various key parts including
governance, waste and resource efficiency, air quality and
environmental recall, water, nature and biodiversity and
conservation covenants. The governance parts include a
comprehensive framework for legally binding environmental
improvement targets; to establish a framework for future policy
statements on environmental principles to protect the environment
by making environmental considerations a key part of policy
development process across government; and to establish the
Office for Environmental Protection, an independent public body to
have oversight of environmental matters. The UK government’s first
suite of environmental targets became law in January 2023, but
these have not had a material impact on bp.
Other countries and regions
Regulations governing the discharge of treated water have also been
developed in countries outside the US and EU, including in Trinidad and
Tobago where bp commissioned a new wastewater treatment plant in
2020 to meet consent levels agreed with the regulators to apply
relevant water discharge rules.
The Abidjan Convention, together with its Additional Protocols, sets
environmental quality standards for the discharge of chemicals to the
marine environment. Mauritania and Senegal are both signatories to the
Abidjan Convention. bp's offshore facilities have implemented water
management systems which are designed to meet the environmental
quality standards for their gas operations in Mauritania and Senegal.
The Convention for the Protection of the Marine Environment of the
North-East Atlantic (OSPAR) aims to protect the marine environment of
the North-East Atlantic. The OSPAR 2012 recommendation and guideline
for the implementation of a risk-based approach to the management of
produced water discharges from offshore installations in the North Sea
supports a key goal of working towards eliminating harmful discharges.
In 2020 the International Association of Oil and Gas Producers issued a
report 'Oil And Gas Risk Based Assessment of Offshore Produced Water
Discharges' which presents industry good practice and aims to broaden
the understanding and acceptance of Risk Based Assessment (RBA)
techniques internationally and improve consistency in the application of
assumptions, levels of conservatism, and selection of risk endpoints.
At OSPAR’s Offshore Industry Committee (OIC) meeting in March 2024,
the Committee agreed changes to OSPAR’s List of Substances/
Preparations Used and Discharged Offshore which are Considered to
Pose Little or No Risk to the Environment (PLONOR). This includes two
inorganic substances, calcium bromide and sodium bromide which are
used in Completion fluid formulations. Further work is progressing on
the harmonisation of OSPAR’s approach to offshore chemicals and the
REACH Regulation, now focused on the potential impact of adjustments
to the current Harmonised Mandatory Control System (HCMS) for
regulators and industry. OIC also agreed the report on the
implementation of OSPAR Recommendation 2006/3 on Environmental
Goals for the Discharge by the Offshore Industry of Chemicals that Are,
or Which Contain Substances Identified as Candidates for Substitution –
Technical and Safety Obstacles.
Environmental maritime regulations
bp’s shipping operations are subject to extensive national and
international regulations governing operations, training, pollution
prevention, liability, and insurance. These include:
Liability and spill prevention and planning requirements governing,
among others, tankers, barges, and offshore facilities are imposed
by OPA in US waters. OPA also mandates a levy on imported and
domestically produced oil to fund oil spill responses. Some states,
including Alaska, Washington, Oregon and California, impose
additional liability for oil spills. Outside US territorial waters, bp
shipping tankers are subject to international pollution prevention,
liability, spill response and preparedness regulations developed
through the UN’s International Maritime Organization (IMO),
including the International Convention on Civil Liability for Oil
Pollution Damage, the International Convention for the Prevention of
Pollution from Ships (MARPOL), the International Convention on Oil
Pollution, Preparedness, Response and Co-operation, and the
International Convention on Civil Liability for Bunker Oil Pollution
Damage. In April 2010, a Protocol was adopted to address issues that
have inhibited ratification of the International Convention on Liability
and Compensation for Damage in Connection with the Carriage of
Hazardous and Noxious Substances by Sea 1996 (HNS Convention).
As at 31 December 2025, the HNS Convention had not entered into
force.
A global sulphur cap of 0.5% applies to marine fuel under MARPOL
with a stricter 0.1% cap in environmentally sensitive areas. In order to
comply, ships either need to consume low sulphur marine fuels,
operate on alternative low sulphur fuels such as LNG or implement
approved abatement technology to enable them to meet the low
sulphur emissions requirements while continuing to use higher
sulphur fuel. Certain regional and local authorities also enforce
sulphur caps outside of the MARPOL framework.
From 2023 all vessels over 400 gross tonnage became subject to
IMO requirements as to energy efficiency design (EEXI) and the
carbon intensity of operations (CII).
Under EU legislation, maritime transport has been brought into the
scope of the EU ETS from 2024, applicable to all vessels of 5,000
gross tonnage and above calling at EU ports regardless of a vessel’s
flag.
Under the Fuel EU Maritime Regulation, from 2025 ship owners are
required to reduce the GHG intensity of their fuel use gradually over
time, initially by 2%, increasing to 6% by 2030 and 80% by 2050.
From 2025 tankers calling at California’s major ports must comply
with emission reduction and reporting requirements set by the
California Air Resources Board (CARB), aimed at limiting emission of
pollutants including oxides of nitrogen (Nox) and diesel particulate
matter.
To meet its financial responsibility requirements, bp shipping maintains
marine oil pollution liability insurance in respect of its operated ships to
a maximum limit of $1 billion for each occurrence through mutual
insurance associations (P&I Clubs), although there can be no assurance
that a spill would necessarily be adequately covered by insurance or
that liabilities would not exceed insurance recoveries.
358
bp Annual Report and Form 20-F 2025
« See glossary on page 375
International trade sanctions
During the period covered by this report, non-US subsidiaries, or other
non-US entities of bp, conducted limited activities in, or with persons
from, certain countries identified by the US Department of State as
State Sponsors of Terrorism or otherwise subject to US, EU and UK
sanctions (Sanctioned Countries). In 2025 sanctions restrictions were
insignificant to the group’s financial condition and results of operations.
bp monitors its activities with Sanctioned Countries, persons from
Sanctioned Countries and individuals and companies subject to US, EU
and UK sanctions and seeks to comply with applicable sanctions laws
and regulations.
bp has a 29.99% interest in and operates the Shah Deniz field in
Azerbaijan (Shah Deniz), has a 29.99% interest in and performs some
operations for a related gas pipeline entity, South Caucasus Pipeline
Company Limited (SCPC), and has a 23.99% non-operating interest in a
related gas marketing entity, Azerbaijan Gas Supply Company Limited
(AGSC). Naftiran Intertrade Co. Limited and NICO SPV Limited
(collectively, NICO) have a 10% non-operating interest in each of Shah
Deniz and SCPC and an 8% non-operating interest in AGSC. LUKOIL
Overseas Shah Deniz Limited and LUKOIL Overseas Shah Deniz
Midstream Limited (collectively, LUKOIL Shah Deniz) have a 19.99% non-
operating interest in each of Shah Deniz and SCPC and a 15.99% non-
operating interest in AGSC.
Shah Deniz, SCPC and AGSC continue in operation as they were
excluded from the application of US Iran sanctions as they fall within the
exception for certain natural gas projects under Section 603 of the Iran
Threat Reduction and Syria Human Rights Act of 2012 (ITRA). Shah Deniz
was excluded from the main operative provisions of the EU sanctions
regulations following the snap-back of the EU Iran sanctions in
September 2025. In September and October 2025, the UK issued two
general licences permitting UK persons to conduct activities relating to
Shah Deniz, SCPC and AGSC that would otherwise be prohibited by UK
Iran and Russia sanctions respectively.
On 3 December 2018 bp entered into an agreement with, among others,
SOCAR and NICO pursuant to which SOCAR pays to BP Exploration
(Shah Deniz) Limited (BPXSD), as the Shah Deniz operator, compensation
for NICO’s waiver of its right to lift its share of Shah Deniz condensate.
Such amounts are used to cover cash calls to NICO in respect of
operating costs due from NICO to BPXSD. On 20 November 2025, a
similar arrangement was entered into among bp, SOCAR and LUKOIL
Shah Deniz. In November 2025, OFAC issued a licence in relation to
these arrangements which is subject to further renewal before its expiry
in April 2026.
In 2025 international sanctions against Syria were significantly lifted. bp
terminated all sales of crude oil and petroleum products into Syria
following the imposition in 2011 of further US and EU sanctions against
Syria at the time, though bp continues to supply aviation fuel to non-
governmental Syrian resellers outside of Syria.
bp has a joint arrangement in Cuba which imports, manufactures,
markets and sells lubricants.
Since 2014, the US and the EU have imposed sanctions on certain
sectors of the Russian economy (energy, finance and defence/military)
and on certain individuals and entities, including Rosneft. These sectoral
sanctions include restrictions on certain oil and gas activities in Russia
including the provision of financial assistance, technical assistance,
goods and services.
In response to Russia’s military action in Ukraine in 2022, the US, EU, UK
and many other countries have imposed broad economic and trade
sanctions. The scope of these sanctions includes restrictions on dealing
with designated individuals and entities (including Rosneft and Lukoil as
of 2025); restrictions on the Russian financial sector; blocking economic
activity in certain areas of Ukraine not controlled by the Ukrainian
government; prohibitions in relation to investment in Russia;
prohibitions and restrictions relating to Russian origin oil and oil
products; prohibitions and restrictions relating to Russian origin iron
and steel products, prohibitions and restrictions relating to Russian
origin metals, prohibitions and restrictions on the provision of certain
legal advisory services, prohibitions and restrictions in relation to
transportation, including shipping and aircraft; trade controls limiting
the purchase and import of a wide range of goods from Russia, and
export controls limiting the export of a wide range of goods and
technical assistance to Russia.
In response, Russia has implemented counter-sanctions including
restrictions on the divestment from Russian assets by foreign investors
and 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.
The bp group does not source any materials directly from Russia. In
2022 bp discontinued sales of our products to customers in Russia.
Such sales were not material to the bp group. As a result, outside of our
shareholding in Rosneft and related businesses in Russia, direct
impacts due to exposure to Russia have not been material and are not
expected to be material in the future. bp continues to monitor Russia
related sanctions and other international restrictions for any impacts on
our businesses and the exit of our shareholding in Rosneft.
bp maintains bank accounts and has registered and paid required fees
to maintain registrations of patents and trademarks in certain
Sanctioned Countries.
bp has equity interests in non-operated joint arrangements with air fuel
sellers, resellers, and fuel delivery services around the world. From time
to time, the joint arrangement operator or other partners may sell or
deliver fuel to airlines from Sanctioned Countries or flights to
Sanctioned Countries, without bp’s involvement.
bp has no control over the activities non-controlled associates may
undertake in Sanctioned Countries or with persons from Sanctioned
Countries.
Disclosure pursuant to ITRA Section 219
To our knowledge, none of bp’s activities, transactions or dealings are
required to be disclosed pursuant to ITRA Section 219, with the following
possible exceptions.
In 2025 payments in relation to tax with an aggregate US dollar
equivalent value of approximately $3,000 were made from a bp trust
account held with Tadvin Co. to Iranian public entities on behalf of BP
Iran. No gross revenues or net profits are attributable to BP Iran's
activities.
During 2025 the International Bank of Yemen (IBY) was sanctioned by
the US. bp holds two bank accounts at IBY which were used to support
historical operations in Yemen. Both accounts were dormant prior to
the time IBY was sanctioned, became blocked accounts from that time
and remain blocked as at the date of this report. Together, the accounts
hold around $60,000. In 2025, bp did not operate in Yemen and no
gross revenues or net profits are attributable to any bp activities in
Yemen.
Material contracts
On 4 April 2016 the district court approved the Consent Decree among
BP Exploration & Production Inc., BP Corporation North America Inc., BP
p.l.c., the United States and the states of Alabama, Florida, Louisiana,
Mississippi and Texas (the Gulf states) which fully and finally resolved
any and all natural resource damages (NRD) claims of the United States,
the Gulf states, and their respective natural resource trustees and all
Clean Water Act (CWA) penalty claims, and certain other claims of the
United States and the Gulf states.
Concurrently, the definitive Settlement Agreement that bp entered into
with the Gulf states (Settlement Agreement) with respect to State
claims for economic, property and other losses became effective.
bp has filed the Consent Decree and the Settlement Agreement as
exhibits to its Annual Report and Form 20-F 2020 filed with the SEC. For
further details of the Consent Decree and the Settlement Agreement,
see Legal proceedings in bp Annual Report and Form 20-F 2015.
bp Annual Report and Form 20-F 2025
359
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Additional disclosures
Property, plant and equipment
bp has freehold and leasehold interests in real estate and other tangible
assets in numerous countries, but no individual property is significant to
the group as a whole. For more on the significant subsidiaries« of the
group at 31 December 2025 and the group percentage of ordinary share
capital see Financial statements – Note 37. For information on
significant joint ventures« and associates« of the group see Financial
statements – Note 16 and 17.
Related party transactions
Transactions between the group and its significant joint ventures and
associates are summarized in Financial statements – Note 16 and 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.
Corporate governance practices
In the US, bp ADSs are listed on the New York Stock Exchange (NYSE).
The significant differences between bp’s corporate governance
practices as a UK company and those required by NYSE listing
standards for US companies are listed as follows:
Independence
As set out on page 77, bp has adopted separate terms of reference for
the board and each of its committees as part of its corporate
governance framework. The terms of reference for the board and each
of its committees are reviewed periodically. The board and audit
committee terms of reference were last updated with effect from 1
January 2025, while the other three principal committees were last
updated with effect from 25 July 2024. The terms of reference reflect
the UK Corporate Governance Code approach to corporate governance.
As such, the way in which bp makes determinations of directors'
independence differs from the NYSE approach.
bp’s corporate governance framework requires that all non-executive
directors (NEDs) be determined by the board to be ‘independent in
character and judgement and free from any business or other
relationship which could materially interfere with the exercise of their
judgement’. The bp board has determined that, in its judgement, all of
the NEDs are independent. In doing so, however, the board did not
explicitly take into consideration the independence requirements
outlined in the NYSE’s listing standards.
Committees
bp has a number of board committees that are broadly comparable in
purpose and composition to those required by NYSE rules for domestic
US companies. For instance, bp has a remuneration (rather than a
compensation) committee. bp also has an audit committee, which NYSE
rules require for both US companies and foreign private issuers. These
committees are composed solely of NEDs whom the board has
determined to be independent, in the manner described above.
Each committee operates under its own terms of reference together
with a set of terms applicable to all the committees (see the board
committee reports on pages 82-125 and bp.com/governance.
Under US securities law and the listing standards of the NYSE, bp is
required to have an audit committee that satisfies the requirements of
Rule 10A-3 under the Exchange Act and Section 303A.06 of the NYSE
Listed Company Manual. bp’s audit committee complies with these
requirements. The bp audit committee does not have direct
responsibility for the appointment, reappointment or removal of the
independent auditors. Instead, it follows the UK Companies Act 2006
and the UK Corporate Governance Code by making recommendations
to the board on these matters for it to put forward for shareholder
approval at the AGM.
One of the NYSE’s additional requirements for the audit committee
states that at least one member of the audit committee is to have
‘accounting or related financial management expertise’. The board
determined that Tushar Morzaria possesses such expertise and also
possesses the financial and audit committee experience set forth in
both the UK Corporate Governance Code and the SEC rules (see audit
committee report on page 84). Mr Morzaria is the audit committee
financial expert as defined in Item 16A of Form 20-F.
Summary of terms of reference for audit committee and
remuneration committee
The audit committee’s full terms of reference are available on our
website at bp.com/governance. A summary of the committee’s key
responsibilities is provided below:
Monitor and critically assess bp’s financial statements and financial
information, including the integrity of the financial reporting and
related processes, context in which statements are made,
compliance with relevant legal and regulatory requirements and
financial reporting standards, including the Task Force on Climate-
related Financial Disclosures (TCFD).
Assess the going concern assumption and the longer-term viability
statement as to bp’s ability to continue to operate and meet its
liabilities.
Review and challenge the application and appropriateness of
significant accounting policies and financial reporting estimates and
judgements.
Evaluate the risk to quality and effectiveness of the financial
reporting process and, where requested by the board, advise
whether the Annual Report and Accounts are fair, balanced and
understandable.
Review the affordability of distributions to shareholders.
Oversee the appointment, remuneration, independence and
performance of the external auditor and the integrity of the audit
process as a whole, including the engagement of the external
auditor to supply non-audit services to bp.
Review the effectiveness of the internal audit function, bp’s internal
financial controls and its systems of internal control and risk
management.
Monitor the principal risks allocated to the committee by the board
and review the mitigations proposed by management in respect of
risks associated with bp internal financial controls and reporting
responsibilities and such emerging risks that may fall within scope.
Review the systems in place to enable those who work for bp to raise
concerns about improprieties in financial reporting or other issues,
and for those matters to be investigated.
The remuneration committee’s full terms of reference are available on
our website at bp.com/governance. A summary of the committee’s key
responsibilities is provided below:
Recommend to the board the remuneration principles for the
executive directors while considering remuneration and related
policies for the employees below the board and leadership team.
Set and approve the terms of appointment, fees and benefits for the
chair of the board in accordance with the policy.
Set and approve the terms of engagement, remuneration, benefits
and termination of employment for the executive directors,
leadership team, chief internal auditor, head of ethics and
compliance and the company secretary in accordance with the
policy.
Prepare the annual remuneration report to shareholders to outline
policy implementation.
Approve the principles of any equity plan that requires shareholder
approval.
Ensure termination terms and payments to executive directors and
the leadership team are appropriate and fair.
Receive and consider regular updates on workforce views and
engagement initiatives related to remuneration, insights and data
from pay ratios and potential pay gaps as appropriate.
Maintain appropriate dialogue with shareholders on remuneration
matters.
360
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Shareholder approval of equity compensation plans
The NYSE rules for US companies require that shareholders must be
given the opportunity to vote on all equity-compensation plans and
material revisions to those plans. bp complies with UK requirements
that are similar to the NYSE rules. The board, however, does not
explicitly take into consideration the NYSE’s detailed definition of what
are considered ‘material revisions’.
Item 16J insider trading policy
The board has approved a share dealing policy governing the
acquisition, sale and other dispositions of the company's securities by
employees, contractors, officers and members of the board of the
company.
The bp share dealing policy is included in this Form 20-F as Exhibit 11.2.
Code of ethics
The company has adopted a code of ethics for its chief executive
officer, chief financial officer, group controller, and SVP internal audit
whose roles are equivalent to the SEC roles as required by the
provisions of Section 406 of the Sarbanes-Oxley Act of 2002 and the
rules issued by the SEC. There have been no waivers from the code of
ethics relating to any officers. A copy of the code of ethics can be found
at bp.com/codeofethics.
The NYSE rules require that US companies adopt and disclose a code of
business conduct and ethics for directors, officers and employees. bp
has adopted a code of conduct, which applies to all employees, officers
and members of the board. This was updated and published in January
2023, with certain elements further updated and published in October
2025. In addition, bp has adopted a code of ethics as described above
for the chief executive officer, chief financial officer, group controller,
and SVP internal audit as required by the SEC. bp considers that these
codes and policies address the matters specified in the NYSE rules for
US companies. During 2021 the board adopted a diversity, equity and
inclusion policy, which requires it to encourage a diverse and inclusive
working environment in the boardroom. The policy was most recently
reviewed by the board in 2024, and amendments were made to reflect
regulatory changes and market practice. The updated policy was then
approved with effect from 1 January 2025.
Controls and procedures
Evaluation of disclosure controls and procedures
The company maintains ‘disclosure controls and procedures’, as such
term is defined in Exchange Act Rule 13a-15(e), that are designed to
ensure that information required to be disclosed in reports the
company files or submits under the Exchange Act is recorded,
processed, summarized and reported within the time periods specified
in the Securities and Exchange Commission rules and forms, and that
such information is accumulated and communicated to management,
including the company’s group chief executive and chief financial
officer, as appropriate, to allow timely decisions regarding required
disclosure.
In designing and evaluating our disclosure controls and procedures, our
management, including the group chief executive and chief financial
officer, recognize that any controls and procedures, no matter how well
designed and operated, can provide only reasonable, not absolute,
assurance that the objectives of the disclosure controls and procedures
are met. Because of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all control
issues and instances of fraud within the company, if any, have been
detected. Further, in the design and evaluation of our disclosure
controls and procedures our management necessarily was required to
apply its judgement in evaluating the costs and benefits of possible
control and procedure design options. Also, we have investments in
unconsolidated entities. As we do not control these entities, our
disclosure controls and procedures with respect to such entities are
necessarily substantially more limited than those we maintain with
respect to our consolidated subsidiaries«. Because of the inherent
limitations in a cost-effective control system, misstatements due to
error or fraud may occur and not be detected. The company’s
disclosure controls and procedures have been designed to meet, and
management believes that they meet, reasonable assurance standards.
The company’s management, with the participation of the company’s
interim group chief executive and chief financial officer, has evaluated
the effectiveness of the company’s disclosure controls and procedures
pursuant to Exchange Act Rule 13a-15(b) as of the end of the period
covered by this annual report. Based on that evaluation, the interim
group chief executive and chief financial officer have concluded that
the company’s disclosure controls and procedures were effective at a
reasonable assurance level.
Management’s report on internal control over financial
reporting
Management of bp is responsible for establishing and maintaining
adequate internal control over financial reporting. bp’s internal control
over financial reporting is a process designed under the supervision of
the principal executive and financial officers to provide reasonable
assurance regarding the reliability of financial reporting and the
preparation of bp’s financial statements for external reporting purposes
in accordance with IFRS.
As of the end of the 2025 fiscal year, management conducted an
assessment of the effectiveness of internal control over financial
reporting in accordance with the criteria in the Internal Control
Integrated Framework issued in 2013 by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). Based on this
assessment, management has determined that bp’s internal control
over financial reporting as of 31 December 2025 was effective.
The company’s internal control over financial reporting includes policies
and procedures that pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect transactions and
dispositions of assets; provide reasonable assurances that transactions
are recorded as necessary to permit preparation of financial statements
in accordance with IFRS and that receipts and expenditures are being
made only in accordance with authorizations of management and the
directors of bp; and provide reasonable assurance regarding prevention
or timely detection of unauthorized acquisition, use or disposition of
bp’s assets that could have a material effect on our financial
statements. bp’s internal control over financial reporting as of
31 December 2025 has been audited by Deloitte LLP, an independent
registered public accounting firm, as stated in their report appearing on
page 154 of bp Annual Report and Form 20-F 2025.
Changes in internal control over financial reporting
There were no changes in the group’s internal control over financial
reporting that occurred during the period covered by the Form 20-F
that have materially affected or are reasonably likely to materially affect
our internal control over financial reporting.
Cyber security
Governance
The board oversees bp’s internal control and risk management
framework. The board is supported by the safety and sustainability
committee which oversees cyber security risk and received reports
from bp’s chief information security officer (CISO) on cyber security
incidents at every committee meeting in 2025, including information on
bp’s response to incidents. This allows an ongoing assessment by the
committee of the effectiveness of bp’s overall cyber security
programme. A session is held once a year to review bp’s roadmap and
progress for addressing cyber security risk. Read more in the safety and
sustainability committee report on page 82.
At management level, assessment and management of material risks
from cyber security threats is led by bp’s executive vice president of
technology, a member of bp’s leadership team with deep experience in
bp’s engineering and operations functions, with support from bp’s
CISO, who has over 20 years of experience in the information
technology industry. bp’s digital safety operational risk committee
brings together additional senior members of bp’s digital leadership
team to assist in ensuring that cyber security risks across bp are
bp Annual Report and Form 20-F 2025
361
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Additional disclosures
identified, understood, accurately quantified and are managed in
accordance with bp’s internal controls framework.
Risk management and strategy
bp has implemented a threat-focused strategy to assess cyber security
risks and protect against, detect, respond to, and recover from cyber
attacks. bp maintains internal teams focused on cyber security
intelligence and emergency response to monitor the external threat
landscape and the threats to bp’s IT and operational technology
infrastructure. bp partners with third-party specialists to augment its in-
house capabilities as necessary. bp has a defined protocol for cyber
incident notification based on severity and bp’s internal cyber security
teams brief the CISO, technology EVP, other senior leadership and
relevant board and management committees about incidents on an as
needed basis.
Cyber security risk management is integrated into bp’s overall risk
management process. bp’s entities are required to identify, assess and
report key risks, including cyber security risks, to relevant members of
senior leadership. bp maintains additional procedures to manage cyber
security risks related to third-party service providers, including
conducting information security assessments for certain providers,
providing relevant trainings for bp employees, and maintaining
information security requirements for suppliers.
Our business strategy, results of operations and financial condition
have not been materially affected by risks from cyber security threats,
including as a result of previously identified cyber security incidents. For
more information on our cyber security related risks, see Risk Factors
on page 67.
Principal accountant's fees and services
The audit committee has established policies and procedures for the
engagement of the independent registered public accounting firm,
Deloitte LLP, to render audit and certain assurance services. The policy
provides for pre-approval by the audit committee of specifically defined
audit, audit-related, non-audit and other services that are not prohibited
by regulatory or other professional requirements. Deloitte is engaged
for these services when its expertise and experience of bp are
important. Most of this work is of an audit nature.The audit committee,
CFO and group controller monitor overall compliance with bp’s policy
on audit-related and non-audit services, including whether the
necessary pre-approvals have been obtained. The committee regularly
reviews the policy, including in 2025, when it was updated to include
clarification regarding bp’s employment of current and former
employees or partners of the auditor.
Under the policy, pre-approval is given for specific services within the
following categories: i) audit-related services, such as those required by
law or where the auditor is best placed to undertake such work on
similar terms, ii) non-audit services required by law, such as reporting
required by a regulatory authority, and iii) other services, such as
additional assurance or updates on applicable law and accounting
standards. bp operates a two-tier system for audit and non-audit
services. For audit-related services, the audit committee has a pre-
approved aggregate level, within which specific work may be approved
by management. Non-audit services are pre-approved for management
to authorize per individual engagement, but above a defined level must
be approved by the chair of the audit committee or the full committee.
The audit committee has delegated to the chair of the audit committee
authority to approve permitted services provided that any decisions are
reported to the committee at its next scheduled meeting. Any proposed
service not included in the approved service list must be approved in
advance of commencing the engagement by the audit committee chair
or the full audit committee, depending on the level of fee payable.
The audit committee evaluates the performance of the auditor each
year. The audit fees payable to Deloitte are reviewed by the committee
in the context of other global companies for cost-effectiveness. The
committee keeps under review the scope and results of audit work and
the independence and objectivity of the auditor. External regulation and
bp policy requires the auditor to rotate its lead audit partner every five
years. See Financial statements – Note 36 and the audit committee
report on page 84 for details of fees for services provided by the
auditor.
Additional Directors’ report disclosures
This section of bp Annual Report and Form 20-F 2025 forms part of the
Directors’ report. Certain information has been included in the Strategic
report that would otherwise be required to be disclosed in the Directors'
report, as noted below.
Indemnity provisions
In accordance with bp’s Articles of Association, on appointment each
director is granted an indemnity from the company in respect of
liabilities incurred as a result of their office, to the extent permitted by
law. These indemnities were in force throughout the financial year and
at the date of this report. In respect of those liabilities for which
directors may not be indemnified, the company maintained a directors’
and officers’ liability insurance policy throughout 2025. During the year,
a review of the terms and scope of the policy was undertaken as part of
the annual renewal. Although a director’s defence costs may be met,
neither the company’s indemnity nor insurance provides cover in the
event that the director is proved to have acted fraudulently or
dishonestly. One of the group’s subsidiaries« is a trustee of the UK
pension scheme. Each director of that subsidiary is granted an
indemnity from the company in respect of liabilities incurred as a result
of such a subsidiary’s activities as a trustee of the pension scheme, to
the extent permitted by law. These indemnities were in force
throughout the financial year and as at the date of this report.
Financial risk management objectives and policies
The disclosures in relation to financial risk management objectives and
policies, including the policy for hedging, are included in How we
manage risk on page 67, Liquidity and capital resources on page 338
and Financial statements – Notes 29 and 30.
Exposure to price risk, credit risk, liquidity risk and cash
flow risk
The disclosures in relation to exposure to price risk, credit risk, liquidity
risk and cash flow risk are included in Financial statements – Notes 29
and 30.
Important events since the end of the financial year
Disclosures of the particulars of the important events affecting bp
which have occurred since the end of the financial year are included in
the Strategic report as well as in other places in the Directors’ report.
Likely future developments in the business
An indication of the likely future developments in the business of the
company is included in the Strategic report.
Research and development
Indications of our activities in the field of research and development are
provided throughout the Strategic report and the Directors’ report. See
also pages 12 and 189 for our expenditure on research and
development.
Branches
As a global group our interests and activities are held or operated
through subsidiaries, branches, joint arrangements« or associates«
established in – and subject to the laws and regulations of – many
different jurisdictions.
Employees
Disclosures in respect of how the directors have engaged with
employees and had regard to their interests are included in Our
stakeholders and Key decisions on pages 79, 80 and 81.
The disclosures concerning policies in relation to the employment of
disabled persons and employee involvement are included in
Sustainability – our people on page 57.
362
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Employee share schemes
Certain shares held as a result of participation in some employee share
plans carry voting rights. Voting rights in respect of such shares are
exercisable via a nominee. Dividend waivers are in place in respect of
unallocated shares held in employee share plan trusts.
Suppliers, customers and others
Disclosures in respect of how the directors have engaged with
suppliers, customers and others in business relationships with the
company are included in Our stakeholders on pages 80-81.
Change of control provisions
On 5 October 2015, the United States lodged with the district court in
MDL 2179 a proposed Consent Decree between the United States, the
Gulf states, BP Exploration & Production Inc., BP Corporation North
America Inc. and BP p.l.c., to fully and finally resolve any and all natural
resource damages claims of the United States, the Gulf states and their
respective natural resource trustees and all Clean Water Act penalty
claims, and certain other claims of the United States and the Gulf states.
Concurrently, bp entered into a definitive Settlement Agreement with
the five Gulf states (Settlement Agreement) with respect to state claims
for economic, property and other losses. On 4 April 2016, the district
court approved the Consent Decree, at which time the Consent Decree
and Settlement Agreement became effective. The federal government
and the Gulf states may jointly elect to accelerate the payments under
the Consent Decree in the event of a change of control or insolvency of
BP p.l.c., and the Gulf states individually have similar acceleration rights
under the Settlement Agreement. For further details of the Consent
Decree and the Settlement Agreement, see Legal proceedings in bp
Annual Report and Form 20-F 2015.
Political donations, expenditure and contributions
Disclosures in relation to political donations, expenditure and
contributions are included on page 58.
Greenhouse gas emissions, energy consumption and
energy efficiency
Disclosures in relation to greenhouse gas emissions, energy
consumption and energy efficiency are included in Sustainability on
pages 39-40.
Disclosures required under UK Listing
Rule 6.6.1R
The information required to be disclosed by UK Listing Rule 6.6.1R can
be located as set out below:
Information required
Page
(1) Amount of interest capitalized
(2), (3)
Not applicable
(4), (5) Waiver of director emoluments
Not applicable
(6) – (10)
Not applicable
(11), (12) Dividend waivers
(13)
Not applicable
Cautionary statement
In order to utilize the ‘safe harbor’ provisions of the United States
Private Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the
general doctrine of cautionary statements, bp is providing the following
cautionary statement.
This document contains certain forecasts, projections and forward-
looking statements that is, statements related to future, not past,
events and circumstances – with respect to the financial condition,
results of operations and businesses of bp and certain of the plans and
objectives of bp with respect to these items. These statements may
generally, but not always, be identified by the use of words such as ‘will’,
‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’,
‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions.
In particular, among other statements, (i) certain statements in the
Chair’s letter (page 4), Interim chief executive officer’s letter (page 5),the
Strategic report (inside front cover and pages 1-71), Additional
disclosures (pages 334-363) and Shareholder information (pages
364-374), including but not limited to statements under the headings
‘Energy Outlook’, ‘Our strategy’, ‘Consistency with the Paris goals’, ‘Our
business model’, ‘Our financial frame’, ‘2026 guidance’ ‘Outlook for
2026’, ‘Our investment process’ and ‘2026 shareholder calendar’ and
including but not limited to statements regarding: plans and
expectations relating to business, financial performance, results of
operations, cash flow and allocation of capital expenditure; plans and
expectations regarding bp’s financial frame (including annual dividend
increases, net debt, credit rating, capital expenditures and distribution
of operating cash flow as dividends and share buybacks), balance sheet,
working capital, operating cash flow, return on average capital
employed (ROACE), liquidity, capital discipline, cost base, future
shareholder distributions, amount, timing or use of payments related to
divestments and other proceeds (including expectations and plans
relating to the Castrol divestment and allocation of the expected
proceeds), future dividend payments and progress towards our cost
saving targets; plans and expectations regarding share buybacks,
allocation and use of excess cash; plans and expectations regarding
bp’s 2026 guidance (including with respect to reported and underlying
upstream production, growth of bp’s customers businesses, products
refining margins and refinery turnaround activity); plans and
expectations regarding total capital expenditure, depreciation,
depletion and amortization, divestments and other proceeds, Gulf of
America oil spill payments, other businesses & corporate underlying
annual charge, and the effective tax rate and the underlying effective
tax rate; plans and expectations regarding bp’s engagement plans and
programs and their impact on bp’s results of operations and financial
position; plans and expectations regarding bp’s four primary targets
(including adjusted free cash flow growth, net debt, structural cost
reduction and ROACE) and reporting of bp’s progress towards those
targets; assumptions regarding interest rates and broader
macroeconomic conditions; plans and expectations relating to bp’s
investor proposition including those to grow shareholder value and
simplify and strengthen bp; plans and expectations relating to bp’s
investment process, strategy and capital investment, including future
capital investment allocation, expected IRR, access to capital and the
restructuring of certain investments; plans and expectations relating to
bp’s intra-group funding and liquidity arrangements; plans and
expectations relating to bp’s ability to meet contractual obligations;
expectations regarding inflation, price volatility, refining margins and
price assumptions; plans and expectations relating to risk, including risk
management processes and climate-related risks; plans, expectations
and projections regarding bp’s oil and gas business, including related
investment plans and their impact on production and cash flow, oil and
gas prices, operational emissions, oil and gas production targets, and
future divestments; plans and expectations regarding bp’s customers
and products business, including investment plans and growth in
aviation, biofuels and refineries; plans and expectations regarding bp’s
low carbon energy business, including the growth and decarbonization
of the offshore wind and hydrogen and CCS businesses; plans and
expectations regarding bp’s ST&S business, including relating to
electrification of the energy systems and decarbonization of electricity;
plans and expectations related to the energy transition (including
scenario analysis), investments in transition businesses, reduction of
operational carbon intensity, climate change, sustainability (including
bp’s sustainability aims), greenhouse gas emissions, management,
decarbonization, net zero ambition and aims, and related laws and
regulations; plans and expectations regarding bp’s focus on biodiversity
and water use, including bp’s freshwater use, bp’s freshwater
management approach, bp’s ability to address water-related business
risk and bp’s freshwater withdrawal in stressed catchments; plans and
expectations regarding projects, joint ventures, partnerships,
agreements and memoranda of understanding with governments,
commercial entities and other third party partners (including, but not
limited to, the Gelsenkirchen refinery, the Green Canyon Block 584, the
Tiber-Guadalupe project, the Atlantis Drill Center 1 expansion project,
the NZT and NEP projects, the Ginger project, the KGD6 infills wells
bp Annual Report and Form 20-F 2025
363
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Additional disclosures
project, the Shah Deniz Compression, the Atlantis Major Facility
Expansion, the Kirkuk redevelopment project, the Juniper Wells, the
Greater Western Flank 4 project, the Argos Southwest Extension
project, the Murlach project, the Etlas joint venture, Lightsource bp., the
Alto de Cabo Frio Central block, the Bumerangue project, the Atlantic
LNG facility, the Agogo Integrated West Hub Project, offshore Blocks
1/14, 14 and 14K in the Lower Congo Basin, the five-well programme in
the Mediterranean Sea, the agreement between State Oil Company of
the Azerbaijan Republic and bp and subsequently approved
development plans in regard to the Karabagh field, the agreement
between bp and ONGC in relation to Mumbai High field and the Browse
LNG Joint Venture); expectations regarding contingent liabilities, legal
and trial proceedings, court decisions, potential investigations and civil
actions by regulators, government entities and/or other entities or
parties, and the timing and potential impact of such proceedings,
settlement agreements relating to such proceedings and bp’s
intentions in respect thereof; plans and expectations regarding
relationships with governments, customers, partners, suppliers,
communities and key stakeholders; plans and expectations regarding
upstream production and downstream performance and returns; plans
and expectations regarding bp’s external audit tender process; plans
and expectations regarding the appointment and succession plans of
bp’s directors; plans and expectations regarding bp’s long-term
viability, including ability to continue in operation and meet liabilities;
expectations regarding bp’s refining assets, including their useful
economic lives and depreciation; expectations regarding the impact of
emissions costs on bp’s oil and gas CGU carrying values; expectations
regarding the impact of the energy transition on the recoverable
amount of property, plant and equipment and goodwill in the oil and
gas industry; expectations regarding the timing of production of bp’s
reserves and resources; expectations regarding the impact of the
German tax legislation on bp’s tax obligations; plans and expectations
regarding the adoption and impact of the amendments to IFRS and
related elections; plans and expectations regarding employee share
plans, funded defined benefit plans and other post-employment
benefits; expectations regarding impact of international trade
sanctions; plans and expectations regarding operations and safety;
expectations regarding the structure of energy demand; plans and
expectations regarding the competitiveness and value of bp’s
refineries; plans and expectations relating to bp’s research and
development spend and outcomes; expectations related to changes
laws, regulations and policies; and plans and expectations regarding
bp’s shareholder calendar.
By their nature, forward-looking statements involve risk and uncertainty
because they relate to events and depend on circumstances that will or
may occur in the future and are outside the control of bp.
Actual results or outcomes may differ materially from those expressed
in such statements, depending on a variety of factors, including: the
extent and duration of the impact of current market conditions
including the volatility of oil prices, the effects of bp’s plan to exit its
shareholding in Rosneft and other investments in Russia, overall global
economic and business conditions impacting bp’s business and
demand for bp’s products as well as the specific factors identified in the
discussions accompanying such forward-looking statements; changes
in consumer preferences and societal expectations; the pace of
development and adoption of alternative energy solutions;
developments in policy, law, regulation, technology and markets,
including societal and investor sentiment related to the issue of climate
change; the receipt of relevant third party and/or regulatory approvals
including ongoing approvals required for the continued developments
of approved projects; the timing and level of maintenance and/or
turnaround activity; the timing and volume of refinery additions and
outages; the timing of bringing new fields onstream; the timing,
quantum and nature of certain acquisitions and divestments; future
levels of industry product supply, demand and pricing, including supply
growth in North America and continued base oil and additive supply
shortages; OPEC+ quota restrictions; PSA and TSC effects; operational
and safety problems; potential lapses in product quality; economic and
financial market conditions generally or in various countries and
regions; political stability and economic growth in relevant areas of the
world; changes in laws and governmental regulations and policies,
including related to climate change; changes in social attitudes and
customer preferences; regulatory or legal actions including the types of
enforcement action pursued and the nature of remedies sought or
imposed; the actions of prosecutors, regulatory authorities and courts;
delays in the processes for resolving claims; amounts ultimately
payable and timing of payments relating to the Gulf of America oil spill;
exchange rate fluctuations; development and use of new technology;
recruitment and retention of a skilled workforce; the success or
otherwise of partnering; the actions of competitors, trading partners,
contractors, subcontractors, creditors, rating agencies and others; bp’s
access to future credit resources; business disruption and crisis
management; the impact on bp’s reputation of ethical misconduct and
non-compliance with regulatory obligations; trading losses; major
uninsured losses; the possibility that international sanctions or other
steps taken by governmental or any other relevant persons may impact
bp’s ability to sell its interests in Rosneft, or the price for which bp could
sell such interests; the actions of contractors; natural disasters and
adverse weather conditions; changes in public expectations and other
changes to business conditions; wars and acts of terrorism; cyber-
attacks or sabotage; and those factors discussed elsewhere in this
report including under Risk factors (page 62). In addition to factors set
forth elsewhere in this report, those set out above are important
factors, although not exhaustive, that may cause actual results and
developments to differ materially from those expressed or implied by
these forward-looking statements.
Statements regarding competitive
position
Statements referring to bp’s competitive position are based on the
company’s belief and, in some cases, rely on a range of sources,
including investment analysts’ reports, independent market studies and
bp’s internal assessments of the relevant market based on publicly
available information about the financial results and performance of
market participants.
364
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Shareholder information
Share prices and listings
Dividends
Shareholder taxation information
Major shareholders
Annual general meeting
Memorandum and Articles of Association
Purchases of equity securities by the issuer and
affiliated purchasers
Fees and charges payable by ADS holders
Fees and payments made by the Depositary to
the issuer
Documents on display
Shareholding administration
2026 shareholder calendar
bp Annual Report and Form 20-F 2025
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Shareholder information
Share prices and listings
Markets and market prices
The primary market for the company’s ordinary shares (trading symbol
‘BP’), 8% cumulative first preference shares (trading symbol ‘BP.A’) and
9% cumulative second preference shares (trading symbol ‘BP.B’) is the
London Stock Exchange (LSE). The company’s ordinary shares are a
constituent element of the Financial Times Stock Exchange 100 Index.
In the US, the company’s securities are listed and traded on the New
York Stock Exchange (NYSE) in the form of American Depositary Shares
(ADSs) (trading symbol ‘BP’), for which JPMorgan Chase Bank, N.A. is the
depositary (the Depositary) and transfer agent. The Depositary’s
principal office is 270 Park Avenue, Floor 8, New York, NY, 10017, US.
Each ADS represents six ordinary shares. ADSs are evidenced by
American depositary receipts (ADRs), which may be issued in either
certificated or book entry form.
The company delisted from the Frankfurt Stock Exchange on                   
23 April 2025.
On 13 February 2026, 697,484,895 ADSs (equivalent to approximately
4,184,909,371 ordinary shares or some 26.65% of the total issued share
capital, excluding shares held in treasury) were outstanding and were
held by approximately 55,047 ADS holders. Of these, about 54,410 had
registered addresses in the US at that date. One of the registered
holders of ADSs represents approximately 1,278,868 underlying holders.
On 13 February 2026, there were approximately 186,939 ordinary
shareholders. Of these shareholders, around 1,449 had registered
addresses in the US and held a total of some 3,534,557 ordinary shares.
On 13 February 2026, there were approximately 1,029 preference
shareholders. Of these shareholders, around 14 had registered
addresses in the US and held a total of some 2,773 preference shares.
Since a number of the ordinary shares and ADSs were held by brokers
and other nominees, the number of holders in the US may not be
representative of the number of beneficial holders or their respective
country of residence.
Dividends
The company’s current policy is to pay interim dividends on a quarterly
basis on its ordinary shares.
Our policy is also to announce dividends for ordinary shares in US
dollars and state an equivalent sterling dividend. Dividends on the
company's ordinary shares will be paid in sterling and on the company's
ADSs in US dollars. The rate of exchange used to determine the sterling
amount equivalent is the average of the market exchange rates in
London over three business days in advance of the sterling equivalent
announcement date. The directors may choose to declare dividends in
any currency provided that a sterling equivalent is announced. It is not
the company’s intention to change its current policy of announcing
dividends on ordinary shares in US dollars.
Information regarding dividends announced and paid by the company
on ordinary shares and preference shares is provided in the
consolidated Financial statements Note 10.
A Scrip Dividend Programme (Scrip Programme) was approved by
shareholders in 2010 and was renewed for a further three years at the
2024 AGM. It enabled the company's ordinary shareholders and ADS
holders to elect to receive dividends by way of new fully paid ordinary
shares (or ADSs in the case of ADS holders) instead of cash. The
operation of the Scrip Programme is always subject to the directors’
decision to make the Scrip Programme offer available in respect of any
particular dividend.
The company announced on 29 October 2019 and as part of all
subsequent quarterly results announcements made since, that the
board had suspended the Scrip Programme in respect of those
quarterly dividends. The company does not expect to offer a scrip
election for the foreseeable future. Ordinary shareholders and ADS
holders (subject to certain exceptions) may be able to participate in
dividend reinvestment plans. Any decisions with respect to future
dividends will be made by the board of BP p.l.c. following the end of
each quarter.
Future dividends will be dependent on future earnings, the financial
condition of the group, the Risk factors set out on page 67 and other
matters that may affect the business of the group set out in Our
strategy on page 8 and in Liquidity and capital resources on page 338.
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
($0.49920 per American Depositary Share (ADS)). The corresponding
amount in sterling will be announced on 17 March 2026.
The following table shows dividends announced and paid by the
company per ADS for the past five years.
Dividends per ADSa
March
June
September
December
Total
2021
UK pence
22.61
22.27
23.72
24.63
92.23
US cents
31.50
31.50
32.76
32.76
128.52
2022
UK pence
24.96
26.13
31.01
29.64
111.74
US cents
32.76
32.76
36.04
36.04
137.60
2023
UK pence
33.30
31.85
34.39
34.42
133.97
US cents
39.66
39.66
43.62
43.62
166.56
2024
UK pence
34.15
34.10
36.30
37.78
142.33
US cents
43.62
43.62
48.00
48.00
183.24
2025
UK pence
37.06
35.40
37.17
37.44
147.07
US cents
48.00
48.00
49.92
49.92
195.84
aDividends announced and paid by the company on ordinary and preference shares are
provided in the consolidated Financial statements – Note 10.
There are no UK foreign exchange controls or other restrictions on the
import or export of capital by, or on the payment of dividends to, non-
resident holders of BP p.l.c. shares, or that materially affect the conduct
of BP p.l.c’s operations, other than restrictions applicable to certain
countries and persons subject to UN, US, UK, or EU economic sanctions,
to the extent these restrictions can be complied with in law.
Shareholder taxation information
This section describes the material US federal income tax and UK
taxation consequences of owning ordinary shares or ADSs to a US
holder who holds the ordinary shares or ADSs as capital assets for tax
purposes. This section does not discuss tax consequences arising under
the Medicare contribution tax on net investment income or the
alternative minimum tax. It also does not apply inter alia to members of
special classes of holders some of which may be subject to other rules,
including: tax-exempt entities, life insurance companies, dealers in
securities, traders in securities that elect a mark-to-market method of
accounting for securities holdings, holders that, actually or
constructively, hold 10% or more of the company’s shares (as measured
by voting power or value), holders that hold the shares or ADSs as part
of a straddle or a hedging or conversion transaction, holders that
purchase or sell the shares or ADSs as part of a wash sale for US federal
income tax purposes, or holders whose functional currency is not the
US dollar. In addition, if a partnership holds the shares or ADSs, the US
federal income tax treatment of a partner will generally depend on the
status of the partner and the tax treatment of the partnership and may
not be described fully below.
A US holder is any beneficial owner of ordinary shares or ADSs that is for
US federal income tax purposes (1) a citizen or resident of the US, (2) a
US domestic corporation, (3) an estate whose income is subject to US
federal income taxation regardless of its source, or (4) a trust if a US
court can exercise primary supervision over the trust’s administration
and one or more US persons are authorized to control all substantial
decisions of the trust.
This section is based on the tax laws of the United States, including the
Internal Revenue Code of 1986, as amended, its legislative history,
existing and proposed US Treasury regulations thereunder, published
rulings and court decisions, and the taxation laws of the UK, all as
currently in effect, as well as the income tax convention between the US
and the UK that entered into force on 31 March 2003 (the Treaty). These
laws are subject to change, possibly on a retroactive basis. This section
further assumes that each obligation under the terms of the deposit
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« See glossary on page 375
agreement relating to bp ADSs and any related agreement will be
performed in accordance with its terms.
For purposes of the Treaty and the estate and gift tax convention
between the US and the UK that entered into force on 11 November 1979
(the Estate Tax Convention) and for US federal income tax and UK
taxation purposes, a holder of ADRs evidencing ADSs will be treated as
the owner of the company’s ordinary shares represented by those
ADRs. Exchanges of ordinary shares for ADRs and ADRs for ordinary
shares generally will not be subject to US federal income tax or to UK
taxation other than stamp duty or stamp duty reserve tax, as described
below.
Investors should consult their own tax advisor regarding the US federal,
state and local, UK and other tax consequences of owning and
disposing of ordinary shares and ADSs in their particular circumstances,
and in particular whether they are eligible for the benefits of the Treaty
in respect of their investment in the shares or ADSs.
Taxation of dividends
UK taxation
Under current UK taxation law, no withholding tax will be deducted from
dividends paid by the company, including dividends paid to US holders.
A US holder that is a company resident for tax purposes in the UK or
trading in the UK through a permanent establishment generally will not
be taxable in the UK on a dividend it receives from the company. A US
holder who is an individual resident for tax purposes in the UK is subject
to UK tax on dividends received from the company, including dividends
paid but reinvested under any dividend reinvestment plan for ordinary
shareholders, that are in excess of the annual dividend allowance.
However, if the shareholder’s dividend income is covered by their
personal allowance of £12,570 (for 2025/26) after taking into account
other sources of income, no UK tax will be payable on their dividend
income.
For 2025/26 the dividend allowance is £500 which means there is no UK
tax due on the first £500 of dividends received. Dividends above this
level are subject to tax at 8.75% for basic tax payers, 33.75% for higher
rate tax payers and 39.35% for additional rate tax payers.
Although the first £500 of dividend income is not subject to UK income
tax, it does not reduce the total income for tax purposes. Dividends
within the dividend allowance still count towards basic or higher rate
bands, and may therefore affect the rate of tax paid on dividends
received in excess of the £500 allowance. For instance, if an individual
has an annual gross salary of £55,000 and also receives a dividend of
£12,000 they will be subject to the following scenario. The individual's
personal allowance and the basic rate tax band will be used up by the
gross salary. The remaining part of the salary and the whole of the
dividend will be subject to tax at the higher rate, although the dividend
allowance will reduce the amount of dividend subject to tax. The
dividend of £12,000 will be reduced by the dividend allowance of £500
leaving taxable dividend income of £11,500. The dividend will be taxed at
33.75% so that the total tax payable on the dividends is £3,881.
An individual US holder should inform HM Revenue & Customs each
year for which that US holder receives dividends chargeable to UK tax. If
a US holder needs to report to HMRC and already files a self-
assessment tax return in the UK, the US holder should include the
dividend income in that return and submit it by the deadline. If the US
holder does not file a self-assessment return, the US holder should
inform HM Revenue & Customs by 5 October. How the income is
reported and taxed will depend on the size of the dividend income for
that tax year. If the US holder received dividend income up to £10,000,
the US holder can inform HM Revenue & Customs by either asking to
update his or her tax code or contacting the helpline. If the US holder’s
dividend income is over £10,000, he or she will need to fill out a self-
assessment tax return. For this, the US holder will need to register for
self-assessment by 5 October. A US holder will not need to report his or
her dividend income to HM Revenue & Customs if the amount is within
his or her dividend allowance for that tax year.
US federal income taxation
A US holder is subject to US federal income taxation on the gross
amount of any dividend paid by the company (including dividends paid
but reinvested under the Global Invest Direct (GID) Dividend
Reinvestment Plan for ADS holders) out of its current or accumulated
earnings and profits (as determined for US federal income tax
purposes). Dividends paid to a non-corporate US holder that constitute
qualified dividend income will be taxable to the holder at a preferential
rate, provided that the holder has a holding period in the ordinary
shares or ADSs of more than 60 days during the 121-day period
beginning 60 days before the ex-dividend date and meets other holding
period requirements. Dividends paid by the company with respect to
the ordinary shares or ADSs will generally be qualified dividend income.
For US federal income tax purposes, a dividend must be included in
income when the US holder, in the case of ordinary shares, or the
Depositary, in the case of ADSs, actually or constructively receives the
dividend and will not be eligible for the dividends-received deduction
generally allowed to US corporations in respect of dividends received
from other US corporations. US ADS holders should consult their own
tax advisor regarding the US tax treatment of the dividend fee in
respect of dividends. Dividends will generally be income from sources
outside the US and generally will be ‘passive category income’ for
purposes of computing a US holder’s foreign tax credit limitation.
As noted above in UK taxation, a US holder will not be subject to UK
withholding tax. Accordingly, the receipt of a dividend will not entitle the
US holder to a foreign tax credit.
The amount of the dividend distribution on the ordinary shares that is
paid in pounds sterling will be the US dollar value of the pounds sterling
payments made, determined at the spot pounds sterling/US dollar rate
on the date the dividend is distributed, regardless of whether the
payment is, in fact, converted into US dollars. Generally, any gain or loss
resulting from currency exchange fluctuations during the period from
the date the pounds sterling dividend payment is distributed to the date
the payment is converted into US dollars will be treated as ordinary
income or loss and will not be eligible for the preferential tax rate on
qualified dividend income. The gain or loss generally will be income or
loss from sources within the US for foreign tax credit limitation
purposes.
Distributions in excess of the company’s earnings and profits, as
determined for US federal income tax purposes, will be treated as a
return of capital to the extent of the US holder’s basis in the ordinary
shares or ADSs and thereafter as capital gain, subject to taxation as
described in 'Taxation of capital gains – US federal income taxation'
section below.
In addition, the taxation of dividends may be subject to the rules for
passive foreign investment companies (PFIC), described below under
‘Taxation of capital gains – US federal income taxation’. Distributions
made by a PFIC do not constitute qualified dividend income and are not
eligible for the preferential tax rate applicable to such income.
Taxation of capital gains
UK taxation
A US holder may be liable for both UK and US tax in respect of a gain on
the disposal of ordinary shares or ADSs if the US holder is (1) resident for
tax purposes in the UK at the date of disposal, (2) person who (a) has left
the UK; (b) was resident in the UK for four out of the seven years before
the year of departure; (c) acquired the shares before leaving the UK; (d)
sold the shares while not resident in the UK; and (e) returns to the UK
within a period not exceeding five complete tax years after departure,
(3) a US domestic corporation resident in the UK by reason of its
business being managed or controlled in the UK, or (4) a citizen of the
US that carries on a trade or profession or vocation in the UK through a
branch or agency or a corporation that carries on a trade, profession or
vocation in the UK, through a permanent establishment, and that has
used, held, or acquired the ordinary shares or ADSs for the purposes of
such trade, profession or vocation of such branch, agency or permanent
establishment.
Under the Treaty, capital gains on dispositions of ordinary shares or
ADSs generally will be subject to tax only in the jurisdiction of residence
bp Annual Report and Form 20-F 2025
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Shareholder information
of the relevant holder as determined under both the laws of the UK and
the US and as required by the terms of the Treaty.
Under the Treaty, individuals who are residents of either the UK or the
US and who have been residents of the other jurisdiction (the US or the
UK, as the case may be) at any time during the six years immediately
preceding the relevant disposal of ordinary shares or ADSs may be
subject to tax with respect to capital gains arising from a disposition of
ordinary shares or ADSs of the company not only in the jurisdiction of
which the holder is resident at the time of the disposition but also in the
other jurisdiction.
The UK Capital Gains Tax rate is dependent on the level of an individual’s
taxable income. For 2025/26, where total taxable income and gains
after all allowable deductions are less than the upper limit of the basic
rate income tax band of £37,700 (for 2025/26), the rate of Capital Gains
Tax will be 18%. For gains (and any parts of gains) above that limit the
rate will be 24%.
An individual may be entitled to a capital gains tax free allowance,
depending on that individual’s circumstances (in particular, election for
the remittance basis of taxation). For individuals who are entitled to the
allowance for 2025/26, this has been set at £3,000. Corporation tax on
chargeable gains is levied at 25% for companies from 1 April 2023.
US federal income taxation
A US holder who sells or otherwise disposes of ordinary shares or ADSs
will recognize a capital gain or loss for US federal income tax purposes
equal to the difference between the US dollar value of the amount
realized on the disposition and the US holder’s tax basis, determined in
US dollars, in the ordinary shares or ADSs. Any such capital gain or loss
generally will be long-term gain or loss, subject to tax at a preferential
rate for a non-corporate US holder, if the US holder’s holding period for
such ordinary shares or ADSs exceeds one year. The tax basis of shares
acquired through reinvested dividends under the GID Dividend
Reinvestment Plan for ADS holders is equal to the fair market value of
the stock on the investment date. The holding period for shares
acquired under the plan begins the day after the applicable investment
date.
Gain or loss from the sale or other disposition of ordinary shares or
ADSs will generally be income or loss from sources within the US for
foreign tax credit limitation purposes. The deductibility of capital losses
is subject to limitations.
We do not believe that ordinary shares or ADSs will be treated as stock
of a passive foreign investment company (PFIC) for US federal income
tax purposes, but this conclusion is a factual determination that is made
annually and thus is subject to change. If we are treated as a PFIC,
unless a US holder elects to be taxed annually on a mark-to-market
basis with respect to ordinary shares or ADSs, any gain realized on the
sale or other disposition of ordinary shares or ADSs would in general not
be treated as capital gain. Instead, a US holder would be treated as if he
or she had realized such gain rateably over the holding period for
ordinary shares or ADSs and would be taxed at the highest tax rate in
effect for each such year to which the gain was allocated, in addition to
which an interest charge in respect of the tax attributable to each such
year would apply. Certain ‘excess distributions’ would be similarly
treated if we were treated as a PFIC.
Additional tax considerations
Scrip Programme
Until the publication of the 2019 third quarter results, the company had
an optional Scrip Programme, wherein holders of bp ordinary shares or
ADSs could elect to receive any dividends in the form of new fully paid
ordinary shares or ADSs of the company instead of cash. Please consult
your tax advisor for the consequences to you.
UK inheritance tax
The Estate Tax Convention applies to UK inheritance tax. ADSs held by
an individual who is domiciled for the purposes of the Estate Tax
Convention in the US and is for the purposes of the Estate Tax
Convention a national of the US and not a national of the UK will not be
subject to UK inheritance tax on the individual’s death or on transfer
during the individual’s lifetime unless, among other things, the ADSs are
part of the business property of a permanent establishment situated in
the UK or a fixed base used for the performance of independent
personal services. In the exceptional case where ADSs are subject to
both inheritance tax and US federal gift or estate tax, the Estate Tax
Convention generally provides for tax payable in the US to be credited
against tax payable in the UK or for tax paid in the UK to be credited
against tax payable in the US, based on priority rules set forth in the
Estate Tax Convention.
UK stamp duty and stamp duty reserve tax
The statements below relate to what is understood to be the current
practice of HM Revenue & Customs in the UK under existing law.
Provided that any instrument of transfer is not executed in the UK and
remains at all times outside the UK and the transfer does not relate to
any matter or thing done or to be done in the UK, no UK stamp duty is
payable on the acquisition or transfer of ADSs. Neither will an
agreement to transfer ADSs in the form of ADRs give rise to a liability to
stamp duty reserve tax.
Purchases of ordinary shares, as opposed to ADSs, through the CREST
system of paperless share transfers will be subject to stamp duty
reserve tax at 0.5%. The charge will arise as soon as there is an
agreement for the transfer of the shares (or, in the case of a conditional
agreement, when the condition is fulfilled). The stamp duty reserve tax
will apply to agreements to transfer ordinary shares even if the
agreement is made outside the UK between two non-residents.
Purchases of ordinary shares outside the CREST system are subject
either to stamp duty at a rate of £5 per £1,000 (or part, unless the stamp
duty is less than £5, when no stamp duty is charged), or stamp duty
reserve tax at 0.5%. Stamp duty and stamp duty reserve tax are
generally the liability of the purchaser.
A subsequent transfer of ordinary shares to the Depositary’s nominee
will give rise to further stamp duty at the rate of £1.50 per £100 (or part)
or stamp duty reserve tax at the rate of 1.5% of the value of the ordinary
shares at the time of the transfer. For ADR holders electing to receive
ADSs instead of cash, after the 2012 first quarter dividend payment, HM
Revenue & Customs no longer seeks to impose 1.5% stamp duty reserve
tax on issues of UK shares and securities to non-EU clearance services
and depositary receipt systems.
Major shareholders
The disclosure of certain major and significant shareholdings in the share
capital of the company is governed by the Companies Act 2006, the UK
Financial Conduct Authority’s Disclosure Guidance and Transparency Rules
(DTR) and the US Securities Exchange Act of 1934.
Register of members holding bp ordinary shares as at
31 December 2025
Range of holdings
Number of
ordinary
shareholders
Percentage of
total
ordinary
shareholders
Percentage of
total ordinary
share capital
excluding shares
held in treasury
1-200
50,785
27.06
0.02
201-1,000
60,165
32.05
0.21
1,001-10,000
67,106
35.75
1.35
10,001-100,000
8,482
4.52
1.13
100,001-1,000,000
648
0.35
1.54
Over 1,000,000a
522
0.28
95.76
Totals
187,708
100
100
aIncludes JPMorgan Chase Bank, N.A. holding 26.40% of the total ordinary issued share capital
(excluding shares held in treasury) as the approved depositary for ADSs, a breakdown of
which is shown in the table below.
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« See glossary on page 375
Register of holders of American depositary shares (ADSs) as at
31 December 2025a
Range of holdings
Number of
ADS holders
Percentage of
 total ADS holders
Percentage of 
total ADSs
1-200
33,191
58.98
0.26
201-1,000
15,026
26.70
1.04
1,001-10,000
7,774
13.81
2.86
10,001-100,000
277
0.49
0.66
100,001-1,000,000
3
0.01
0.08
Over 1,000,000b
2
0.00
95.10
Totals
56,273
100
100
aOne ADS represents six 25 cent ordinary shares.
bOne holder of ADSs represents 1,278,163 approx. underlying shareholders.
As at 31 December 2025 there were also 1,038 preference shareholders.
Preference shareholders represented 0.54% and ordinary shareholders
represented 99.46% of the total issued nominal share capital of the
company (excluding shares held in treasury) as at that date.
As at 13 February 2026, the 8% preference shares and 9% preference
shares in issue comprised only 0.31% and 0.23% respectively of the
company’s total issued nominal share capital (excluding shares held in
treasury) the rest being ordinary shares.
Substantial shareholders
The following table shows holdings of 3% or more voting rights in
ordinary shares of 25 cents in BP p.l.c. as per the most recent
notification of each respective holder to bp under DTR 5. The
percentage of voting rights detailed below was calculated as at the
date of the relevant disclosures.
As at 31 December 2025
As at 13 February 2026
Number of voting
rights
Percentage
of capital
Number of voting
rights
Percentage
of capital
BlackRock, Inc.
1,504,412,502
7.37
1,504,412,502
7.37
Elliott
Investment
Management,
L.P.
806,743,232
5.00
806,743,232
5.00
Norges Banka
641,036,583
3.99
641,036,583
3.99
aIn the last three financial years and up to the date of this report, BP p.l.c. received six
notifications from Norges Bank relating to changes in its voting rights holdings, as follows: (1)
the percentage of voting rights exceeding 3% on 9 February 2023; (2) exceeding 4% on 12
September 2024; (3) falling below 4% on 20 September 2024; (4) exceeding 4% again on 23
September 2024; (5) falling below 4% on 11 April 2025; and (6) falling below 3% on 2 January
2026.
There are no current disclosable interests in holdings of 3% or more
voting rights in 8% cumulative first preference shares of £1 each and 9%
cumulative second preference shares of £1 each.
Largest registered shareholders
Under the US Securities Exchange Act of 1934 bp is aware of the
following interests as at 13 February 2026.
Ordinary shares of $0.25 in BP p.l.c.:
Holder
Holding of
ordinary shares
Percentage of
ordinary share capital
excluding shares held
in treasury
JPMorgan Chase Bank N.A.,
depositary for ADSs, through its
nominee Guaranty Nominees
Limited
4,184,909,371
26.65
BlackRock, Inc.
1,429,585,141
9.11
Vanguard Group Holdings
840,449,006
5.35
Norges Bank Investment
Management (NBIM)
460,072,521
2.93
8% cumulative first preference shares of £1 each in BP p.l.c.:
Holder
Holding of 8%
cumulative first
preference
shares
Percentage
of class
Hargreaves Lansdown Asset
Management Limited
1,384,537
19.14
Interactive Investor Share Dealing
Services
1,114,005
15.40
Halifax Share Dealing Services
625,928
8.65
Barclays, Plc.
547,371
7.57
Canaccord Genuity Group Inc.
532,260
7.36
AJ Bell Securities, Ltd.
482,911
6.68
Ameriprise Financials, Inc.
287,500
3.97
HSBC Holdings Plc
247,915
3.43
9% cumulative second preference shares of £1 each in BP p.l.c.:
Holder
Holding of 9%
cumulative second
preference shares
Percentage
of class
Hargreaves Lansdown Asset Management
Limited
941,599
17.20
Interactive Investor Share Dealing
Services
695,214
12.70
AJ Bell Securities, Ltd
640,890
11.71
Canaccord Genuity Group Inc.
359,000
6.56
J. Safra Sarasin Group
345,500
6.31
Halifax Share Dealing Services
337,325
6.16
Ameriprise Financial, Inc.
250,000
4.57
Barclays, PLC.
188,886
3.45
HSBC Holdings Plc
172,325
3.15
Charles Stanley Group Plc
165,697
3.03
The company’s major shareholders’ voting rights may differ to their
total interest and can be found under the ‘Substantial shareholders’
heading above where voting rights are over 3%.
Annual general meeting (AGM)
The 2026 AGM is scheduled to be held on Thursday 23 April 2026 at
11:00am BST. A separate notice convening the meeting is distributed to
shareholders, which includes an explanation of the items of business to
be considered at the meeting.
All resolutions for which notice has been given will be decided on a poll.
Deloitte LLP have expressed their willingness to continue in office as
auditors and a resolution for their reappointment is included in the
Notice of bp Annual General Meeting 2026.
Memorandum and Articles of
Association
The following summarizes certain provisions of the company’s
Memorandum and Articles of Association and applicable English law.
This summary is qualified in its entirety by reference to the UK
Companies Act 2006 (the Act) and the company’s Memorandum and
Articles of Association. The Memorandum and Articles of Association
are available online at bp.com/usefuldocs.
The company’s Articles of Association may be amended by a special
resolution at a general meeting of the shareholders. At the AGM held on
21 May 2018 shareholders voted to adopt new Articles of Association to
reflect developments in market practice and to provide clarification and
additional flexibility where necessary or appropriate.
bp Annual Report and Form 20-F 2025
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Shareholder information
Objects and purposes
BP p.l.c. is a public company limited by shares and registered in England
and Wales with the registered number 102498. The provisions
regulating the operations of the company, known as its ‘objects’, were
historically stated in a company’s memorandum. The Act abolished the
need to have object provisions and so at the AGM held on 15 April 2010
shareholders approved the removal of its objects clause together with
all other provisions of its Memorandum that, by virtue of the Act, are
treated as forming part of the company’s Articles of Association.
Directors and secretary
The business and affairs of the company shall be managed by the
directors. The company’s Articles of Association provide that any
person may be appointed by the existing directors or by the
shareholders in a general meeting either as a replacement for another
director or as an additional director. Any person appointed by the
directors will hold office only until the next general meeting, notice of
which is first given after their appointment and will then be eligible for
re-election by the shareholders. A director may be removed by the
company as provided for by applicable law and shall vacate office in
certain circumstances as set out in the Articles of Association. In
addition, the company may, by special resolution, remove a director
before the expiration of his/her period of office and, subject to the
Articles of Association, may by ordinary resolution appoint another
person to be a director instead. There is no requirement for a director to
retire on reaching any age.
The Articles of Association place a general prohibition on a director
voting in respect of any contract or arrangement in which the director
has a material interest other than by virtue of such director’s interest in
shares in the company. However, in the absence of some other material
interest not indicated below, a director is entitled to vote and to be
counted in a quorum for the purpose of any vote relating to a resolution
concerning the following matters:
The giving of security or indemnity with respect to any money lent or
obligation taken by the director at the request or benefit of the
company or any of its subsidiary undertakings.
The giving of security or indemnity to a third party with respect to
any debt or obligation of the company or any of its subsidiary
undertakings for which the director has assumed responsibility.
Any proposal in which the director is interested, concerning the
underwriting of company securities or debentures or the giving of
any security to a third party for a debt or obligation of the company
or any of its subsidiary undertakings.
Any proposal concerning any other company in which the director is
interested, directly or indirectly (whether as an officer or shareholder
or otherwise), provided that the director and persons connected with
such director are not the holder or holders of 1% or more of the
voting interest in the shares of such company.
Any proposal concerning the purchase or maintenance of any
insurance policy under which the director may benefit.
Any proposal concerning the giving to the director of any other
indemnity which is on substantially the same terms as indemnities
given or to be given to all of the other directors or to the funding by
the company of his expenditure on defending proceedings or the
doing by the company of anything to enable the director to avoid
incurring such expenditure where all other directors have been given
or are to be given substantially the same arrangements.
Any proposal concerning an arrangement for the benefit of the
employees and directors or former employees and former directors
of the company or any of its subsidiary undertakings, including but
without being limited to a retirement benefits scheme and an
employees’ share scheme, which does not accord to any director any
privilege or advantage not generally accorded to the employees or
former employees to whom the arrangement relates.
The Act requires a director of a company who is in any way interested in
a contract or proposed contract with the company to declare the nature
of the director’s interest at a meeting of the directors of the company.
The definition of ‘interest’ includes the interests of spouses, children,
companies and trusts. The Act also requires that a director must avoid a
situation where a director has, or could have, a direct or indirect interest
that conflicts, or possibly may conflict, with the company’s interests.
The Act allows directors of public companies to authorize such conflicts
where appropriate, if a company’s Articles of Association so permit. The
company’s Articles of Association permit the authorization of such
conflicts. The directors may exercise all the powers of the company to
borrow money, except that the amount remaining undischarged of all
moneys borrowed by the company shall not, without approval of the
shareholders, exceed two times the amount paid up on the share capital
plus the aggregate of the amount of the capital and revenue reserves of
the company and its subsidiary undertakings incorporated in the UK.
Variation of the borrowing power of the board may only be affected by
amending the Articles of Association.
Remuneration of non-executive directors shall be determined in the
aggregate by resolution of the shareholders. Remuneration of executive
directors is determined by the remuneration committee. This
committee is made up of non-executive directors only. There is no
requirement of share ownership for a director’s qualification.
The Articles of Association provide entitlement to the directors’
pensions and death and disability benefits to the directors’ relations
and dependants respectively.
The circumstances in which a director’s office will automatically
terminate include, among others: when a director ceases to hold an
executive office of the company and the directors resolve that they
should cease to be a director; if a medical practitioner provides an
opinion that a director has become incapable of acting as a director and
may remain so incapable for more than a further three months and the
directors resolve that they should cease to be a director; and if all of the
other directors vote in favour of a resolution stating that the person
should cease to be a director.
The company secretary has express powers to delegate any of the
powers or discretions conferred on him or her.
Dividend rights; other rights to share in company profits;
capital calls
Shareholders of the company may, by resolution, declare dividends but
no such dividend may be declared in excess of the amount
recommended by the directors. The directors may also pay interim
dividends without obtaining shareholder approval. No dividend may be
paid other than out of profits available for distribution, as determined
under IFRS and the Act. Dividends on ordinary shares are payable only
after payment of dividends on bp preference shares. Any dividend
unclaimed after a period of 10 years from the date of declaration of
such dividend shall be forfeited and reverts to bp. If the company
exercises its right to forfeit shares and sells shares belonging to an
untraced shareholder, then any entitlement to claim dividends or other
monies unclaimed in respect of those shares will be for a period of 12
months after the sale. The company may take such steps as the
directors decide are appropriate in the circumstances to trace the
member entitled and the sale may be made at such time and on such
terms as the directors may decide.
The directors have the power to declare and pay dividends in any
currency provided that a sterling equivalent is announced. It is not the
company’s intention to change its current policy of paying dividends in
US dollars. At the company’s AGM held on 15 April 2010, shareholders
approved the introduction of a Scrip Dividend Programme (Scrip
Programme) and to include provisions in the Articles of Association to
enable the company to operate the Scrip Programme. The Scrip
Programme was renewed at the company’s AGM held on 25 April 2024
for a further three years. The Scrip Programme enables ordinary
shareholders and bp ADS holders to elect to receive new fully paid
ordinary shares (or bp ADSs in the case of bp ADS holders) instead of
cash. The operation of the Scrip Programme is always subject to the
directors’ decision to make the scrip offer available in respect of any
particular dividend. Should the directors decide not to offer the scrip in
respect of any particular dividend, cash will automatically be paid
instead. The directors may determine in relation to any scrip dividend
plan or programme how the costs of the programme will be met, the
minimum number of ordinary shares required in order to be able to
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« See glossary on page 375
participate in the programme and any arrangements to deal with legal
and practical difficulties in any particular territory.
Apart from shareholders’ rights to share in bp’s profits by dividend (if
any is declared or announced), the Articles of Association provide that
the directors may set aside:
A special reserve fund out of the balance of profits each year to
make up any deficit of cumulative dividend on the bp preference
shares.
A general reserve out of the balance of profits each year, which shall
be applicable for any purpose to which the profits of the company
may properly be applied. This may include capitalization of such sum,
pursuant to an ordinary shareholders’ resolution, and distribution to
shareholders as if it were distributed by way of a dividend on the
ordinary shares or in paying up in full unissued ordinary shares for
allotment and distribution as bonus shares.
Any such sums so deposited may be distributed in accordance with the
manner of distribution of dividends as described above.
Holders of shares are not subject to calls on capital by the company,
provided that the amounts required to be paid on issue have been paid
off. All shares are fully paid.
Share transfers and share certificates
The directors may permit transfers to be effected other than by an
instrument in writing. Share certificates will not be required to be issued
by the company if they are not required by law.
The company may charge an administrative fee in the event that a
shareholder wishes to replace two or more certificates representing
shares with a single certificate or wishes to surrender a single
certificate and replace it with two or more certificates. All certificates
are sent at the member’s risk.
Voting rights
The Articles of Association of the company provide that voting on
resolutions at a shareholders’ meeting will be decided on a poll other
than resolutions of a procedural nature, which may be decided on a
show of hands. If voting is on a poll, every shareholder who is present in
person or by proxy has one vote for every ordinary share held and two
votes for every £5 in nominal amount of bp preference shares held. If
voting is on a show of hands, each shareholder who is present at the
meeting in person or whose duly appointed proxy is present in person
will have one vote, regardless of the number of shares held, unless a
poll is requested.
Shareholders do not have cumulative voting rights.
For the purposes of determining which persons are entitled to attend or
vote at a shareholders’ meeting and how many votes such persons may
cast, the company may specify in the notice of the meeting a time, not
more than 48 hours before the time of the meeting, by which a person
who holds shares in registered form must be entered on the company’s
register of members in order to have the right to attend or vote at the
meeting or to appoint a proxy to do so.
Holders on record of ordinary shares may appoint a proxy, including a
beneficial owner of those shares, to attend, speak and vote on their
behalf at any shareholders’ meeting, provided that a duly completed
proxy form is received not less than 48 hours (or such shorter time as
the directors may determine) before the time of the meeting or
adjourned meeting or, where the poll is to be taken after the date of the
meeting, not less than 24 hours (or such shorter time as the directors
may determine) before the time of the poll.
Record holders of bp ADSs are also entitled to attend, speak and vote at
any shareholders’ meeting of the company by the appointment by the
approved depositary, JPMorgan Chase Bank N.A., of them as proxies in
respect of the ordinary shares represented by their ADSs. Each such
proxy may also appoint a proxy. Alternatively, holders of bp ADSs are
entitled to vote by supplying their voting instructions to the Depositary,
who will vote the ordinary shares represented by their ADSs in
accordance with their instructions.
Proxies may be delivered electronically.
Corporations who are members of the company may appoint one or
more persons to act as their representative or representatives at any
shareholders’ meeting provided that the company may require a
corporate representative to produce a certified copy of the resolution
appointing them before they are permitted to exercise their powers.
Matters are transacted at shareholders’ meetings by the proposing and
passing of resolutions, of which there are two types: ordinary or special.
An ordinary resolution requires the affirmative vote of a majority of the
votes cast at a meeting at which there is a quorum. A special resolution
requires the affirmative vote of not less than three quarters of the votes
cast at a meeting at which there is a quorum. Any AGM requires 21 clear
days’ notice. The notice period for any other general meeting is 14 clear
days subject to the company obtaining annual shareholder approval,
failing which, a 21 clear day notice period will apply.
Liquidation rights; redemption provisions
In the event of a liquidation of bp, after payment of all liabilities and
applicable deductions under UK laws and subject to the payment of
secured creditors, the holders of bp preference shares would be
entitled to the sum of (1) the capital paid up on such shares plus,
(2) accrued and unpaid dividends and (3) a premium equal to the higher
of (a) 10% of the capital paid up on the bp preference shares and (b) the
excess of the average market price over par value of such shares on the
London Stock Exchange during the previous six months. The remaining
assets (if any) would be divided pro rata among the holders of ordinary
shares.
Without prejudice to any special rights previously conferred on the
holders of any class of shares, bp may issue any share with such
preferred, deferred or other special rights, or subject to such
restrictions as the shareholders by resolution determine (or, in the
absence of any such resolutions, by determination of the directors), and
may issue shares that are to be or may be redeemed.
Variation of rights
The rights attached to any class of shares may be varied with the
consent in writing of holders of 75% of the shares of that class or on the
adoption of a special resolution passed at a separate meeting of the
holders of the shares of that class. At every such separate meeting, all
of the provisions of the Articles of Association relating to proceedings
at a general meeting apply, except that the quorum with respect to a
meeting to change the rights attached to the preference shares is 10%
or more of the shares of that class, and the quorum to change the rights
attached to the ordinary shares is one third or more of the shares of
that class.
Shareholders’ meetings and notices
Shareholders must provide bp with a postal or electronic address in the
UK to be entitled to receive notice of shareholders’ meetings. Holders of
bp ADSs are entitled to receive notices under the terms of the deposit
agreement relating to bp ADSs. The substance and timing of notices are
described above under the heading ‘Voting rights’.
Under the Act, the AGM of shareholders must be held once every year,
within each six-month period beginning with the day following the
company’s accounting reference date. All general meetings shall be
held at a time and place determined by the directors. If any
shareholders’ meeting is adjourned for lack of quorum, notice of the
time and place of the adjourned meeting may be given in any lawful
manner, including electronically. Powers exist for action to be taken
either before or at the meeting by authorized officers to ensure its
orderly conduct and safety of those attending.
The directors have power to convene a general meeting which is a
hybrid meeting, that is to provide facilities for shareholders to attend a
meeting which is being held at a physical place by electronic means as
well (but not to convene a purely electronic meeting).
The provisions of the Articles of Association in relation to satellite
meetings permit facilities being provided by electronic means to allow
those persons at each place to participate in the meeting.
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Shareholder information
Limitations on voting and shareholding
There are no limitations, either under the laws of the UK or under the
company’s Articles of Association, restricting the right of non-resident
or foreign owners to hold or vote bp ordinary or preference shares in
the company other than limitations that would generally apply to all of
the shareholders and limitations applicable to certain countries and
persons subject to EU economic sanctions or those sanctions adopted
by the UK government which implement resolutions of the Security
Council of the United Nations.
Disclosure of interests in shares
The Act permits a public company to give notice to any person whom
the company believes to be or, at any time during the three years prior
to the issue of the notice, to have been interested in its voting shares
requiring them to disclose certain information with respect to those
interests. Failure to supply the information required may lead to
disenfranchisement of the relevant shares and a prohibition on their
transfer and receipt of dividends and other payments in respect of
those shares and any new shares in the company issued in respect of
those shares. In this context the term ‘interest’ is widely defined and will
generally include an interest of any kind whatsoever in voting shares,
including any interest of a holder of bp ADSs.
Called-up share capital
Details of the allotted, called-up and fully-paid share capital at
31 December 2025 are set out in Financial statements – Note 31. In
accordance with institutional investor guidelines, the company deems it
appropriate to grant authority to the directors to allot shares and other
securities and to disapply pre-emption rights by way of shareholders'
resolutions at each AGM in place of authority granted by virtue of the
company's Articles of Association. At the AGM on 17 April 2025,
authorization was given to the directors to allot shares in the company
and to grant rights to subscribe for, or to convert any security into,
shares in the company up to an aggregate nominal amount as set out in
the Notice of Annual General Meeting 2025. These authorities were
given for the period until the next AGM in 2026 or 17 July 2026,
whichever is the earlier. These authorities are renewed annually at       
the AGM.
Company records and service of notice
In relation to notices not covered by the Act, the reference to notice by
advertisement in a national newspaper also includes advertisements via
other means such as a public announcement.
372
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Purchases of equity securities by the issuer and affiliated purchasers
During the 2025 financial year the company repurchased 835,648,878 ordinary shares with a nominal value of $0.25 each for a total consideration
of $4,479,471,803 (including transaction costs), for the purpose of returning capital to shareholders and to offset the expected dilution from the
vesting of awards under employee share schemes. The shares repurchased in 2025 represented 5.35% of the company’s issued share capital,
excluding shares held in treasury, on 31 December 2025. Of the shares repurchased in 2025, shares purchased under the 2024 AGM authority
represented 3.27%, and shares purchased under the 2025 AGM authority represented 2.07% of bp’s issued share capital, excluding shares held in
treasury, on 31 December 2025. A further 74,395,880 ordinary shares were repurchased between the end of the financial year and 13 February 2026
at a cost of $450,225,900 (including transaction costs) representing 0.48% of the company’s issued share capital, excluding shares held in treasury,
on 31 December 2025. Of the ordinary shares repurchased in 2025 and in 2026 up to 13 February under the share buyback programme, 176,152,257
were cancelled and 733,892,501 were transferred into treasury.
Authorization for the company to make market purchases (as defined in section 693(4) of the Companies Act 2006) of ordinary shares with a
nominal value of $0.25 each in the company was renewed at the company’s 2025 AGM covering the period until the date of the company’s 2026
AGM or 17 July 2026, whichever is earlier. The maximum number of ordinary shares to be purchased under this authority will not exceed
1,600,606,341 ordinary shares. The shares purchased may be cancelled or held in treasury.
The following table provides details of ordinary share purchases made (1) under the share buyback programmes and (2) by the Employee Share
Ownership Plans (ESOPs) and other purchases of ordinary shares and ADSs made to satisfy the requirements of certain employee share-based
payment plans.
Total number of
shares
purchaseda
Average price
paid per share
$
Number of
shares
purchased by
ESOPs or for
certain
employee
share-based
plansb
Number of
shares
purchased under
buyback
programmesc
Maximum
approximate
dollar value of
shares yet to
be purchased
under the
programmes
$ million
2025
January 7 - January 31
132,132,317
5.25
1,200,000
130,932,317
N/A
February 3 - February 11
45,219,940
5.30
45,219,940
N/A
March 6 - March 31
165,553,368
5.56
68,000
165,485,368
N/A
April 1 - April 29
170,261,000
4.88
170,261,000
N/A
May 21 -May 30
11,533,500
4.88
11,533,500
N/A
June 2 - June 30
33,297,000
5.08
33,297,000
N/A
July 1 - July 31
88,997,107
5.32
88,997,107
N/A
August 1 - August 29
25,601,600
5.60
25,601,600
N/A
September 1 -September 30
22,955,250
5.80
22,955,250
N/A
October 1 - October 31
86,032,971
5.73
86,032,971
N/A
November 3 - November 28
30,171,877
6.03
30,171,877
N/A
December 1 - December 22
25,160,948
5.98
25,160,948
N/A
2026
January 7 - January 30
54,782,912
5.92
54,782,912
N/A
February  2 - February 13
37,278,988
6.31
17,666,020
19,612,968
N/A
aAll share purchases were of ordinary shares of $0.25 each and/or ADSs (each representing six ordinary shares) and were on/open market transactions.
bTransactions represent the purchases of ordinary shares and ADSs made to satisfy requirements of certain employee share-based payment plans.
cShare repurchases from 1 January to 7 February 2025 were made under a share buyback programme announced on 29 October 2024 for a period up to and including 7 February 2025. On 3 March
2025 the company announced a programme covering a period up to and including 25 April 2025. On 29 April 2025 the company announced a programme covering a period up to and including 1
August 2025. On 5 August 2025 the company announced a programme covering a period up to and including 31 October 2025. On 4 November 2025 the company announced a programme
covering a period up to and including 6 February 2026.
bp Annual Report and Form 20-F 2025
373
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Shareholder information
Fees and charges payable by ADS holders
The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of
withdrawal or from intermediaries acting for them. The Depositary collects fees for making distributions to investors by deducting those fees from
the amounts distributed or by selling a portion of the distributable property to pay the fees.
The charges of the Depositary payable by investors are as follows:
Type of service
Depositary actions
Fee
Depositing or substituting the
underlying shares
Issuance of ADSs against the deposit of shares,
including deposits and issuances in respect of:
Share distributions, stock splits, rights, merger.
Exchange of securities or other transactions or
event or other distribution affecting the ADSs or
deposited securities.
$5.00 per 100 ADSs (or portion thereof)
evidenced by the new ADSs delivered.
Selling or exercising rights
Distribution or sale of securities, the fee being an
amount equal to the fee for the execution and delivery
of ADSs that would have been charged as a result of
the deposit of such securities.
$5.00 per 100 ADSs (or portion thereof).
Withdrawing an underlying share
Acceptance of ADSs surrendered for withdrawal of
deposited securities.
$5.00 for each 100 ADSs (or portion thereof)
evidenced by the ADSs surrendered.
Expenses of the Depositary
Expenses incurred on behalf of holders in connection
with:
Stock transfer or other taxes and governmental
charges.
Delivery by cable, telex, electronic and facsimile
transmission.
Transfer or registration fees, if applicable, for the
registration of transfers of underlying shares.
Expenses of the Depositary in connection with the
conversion of foreign currency into US dollars
(which are paid out of such foreign currency).
Expenses payable are subject to agreement
between the company and the Depositary by
billing holders or by deducting charges from
one or more cash dividends or other cash
distributions.
Dividend fees
ADS holders who receive a cash dividend are charged a
fee which bp uses to offset the costs associated with
administering the ADS programme.
The Deposit Agreement provides that a fee of
$0.05 or less per ADS can be charged. The
current fee is $0.02 per bp ADS per calendar
year (equivalent to $0.005 per bp ADS per
quarter per cash distribution).
Global Invest Direct (GID) Plan
New investors and existing ADS holders can buy, sell or
reinvest dividends into further bp ADSs by enrolling in
bp’s GID Plan, sponsored and administered by the
Depositary.
Cost per transaction is $2.00 for recurring,
$2.00 for one-time automatic investments, and
$5.00 for investment made by check. Dividend
reinvestment is 5% of the dividend amount up
to a maximum of $5.00. Purchase trading
commission is $0.12 per share.
Fees and payments made by the
Depositary to the issuer
The Depositary has agreed to reimburse certain company expenses
related to the company’s ADS programme and incurred by the company
in connection with the ADS programme arising during the year ended 31
December 2025. The Depositary reimbursed to the company, or paid
amounts on the company’s behalf to third parties, or waived its fees and
expenses, of $15,033,009.99 for the year ended 31 December 2025.
The table below sets out the types of expenses that the Depositary has
agreed to reimburse and the fees it has agreed to waive for standard
costs associated with the administration of the ADS programme
relating to the year ended 31 December 2025.
Category of expense reimbursed,
waived or paid directly to third parties
Amount reimbursed, waived or
paid directly to third parties for
the year ended 31 December 2025
$
Fees for delivery and surrender of bp
ADSs
1,788,953.72
Dividend feesa
13,244,056.27
Waived fees
Total
15,033,009.99
aDividend fees are charged to ADS holders who receive a cash distribution, which bp uses to
offset the costs associated with administering the ADS programme.
Under certain circumstances, including removal of the Depositary or
termination of the ADS programme by the company, the company is
required to repay the Depositary certain amounts reimbursed and/or
expenses paid to or on behalf of the company during the 12-month
period prior to notice of removal or termination.
Documents on display
The bp Annual Report and Form 20-F 2025 is available online at
bp.com/annualreport. To obtain a hard copy of bp’s complete audited
financial statements, free of charge, UK-based shareholders should
contact bp Distribution Services by calling +44 (0) 800 037 2172 or by
emailing bpdistributionservices@bp.com. If based in the US or Canada,
shareholders should contact Equiniti by calling 1 888 301 2505 or by
emailing bpreports@equiniti.com
The company is subject to the information requirements of the US
Securities Exchange Act of 1934 applicable to foreign private issuers. In
accordance with these requirements, the company files its Annual
Report and Form 20-F and other related documents with the SEC. The
SEC maintains an internet site at sec.gov that contains reports and
other information regarding issuers, including bp, that file electronically
with the SEC. bp's SEC filings are also available at bp.com/sec. bp
discloses in this report (see Corporate governance practices (Form 20-F
Item 16G) on page 359 significant ways (if any) in which its corporate
governance practices differ from those mandated for US companies
under NYSE listing standards.
374
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Shareholding administration
If you have any queries about the administration of shareholdings, such
as change of address, change of ownership, dividend payment options
or to change the way you receive your company documents (such as
the bp Annual Report and Form 20-F and Notice of bp Annual General
Meeting) please contact the bp Registrar or the bp ADS Depositary.
Holders of American Depositary Receipts may request to inspect the
books of the Depositary and the listing of receipt holders by contacting
the bp ADS Depositary.
Ordinary and preference shareholders
The bp Registrar, MUFG Corporate Markets
Central Square,
29 Wellington Street,
Leeds, LS1 4DL
Freephone in the UK 0800 701107
From outside the UK +44 (0)371 277 1014
bp share centre mybpshares.com
ADS holders
Computershare Trust Company, N.A.
PO Box 43304, Providence, RI 02940-3304
Toll-free in the US +1 877 638 5672
From outside the US +1 651 306 4383
2026 shareholder calendara
27 Mar 2026
Fourth quarter interim dividend payment for 2025
23 Apr 2026
Annual general meeting
28 April 2026
First quarter results announced
15 May 2026
Record date (to be eligible for the first quarter interim
dividend)
26 June 2026
First quarter interim dividend payment for 2025 and 8%
and 9% preference shares record date
31 Jul 2026
8% and 9% preference shares dividend payment
04 Aug 2026
Second quarter results announced
14 Aug 2026
Record date (to be eligible for the second quarter
interim dividend)
18 Sep 2026
Second quarter interim dividend payment for 2025
27 Oct 2026
Third quarter results announced
6 Nov 2026
Record date (to be eligible for the third quarter interim
dividend)
18 Dec 2026
Third quarter interim dividend payment for 2025
aAll future dates are provisional and may be subject to change. For the full calendar see
bp.com/financialcalendar.
bp Annual Report and Form 20-F 2025
375
NavigtionTabCornerV1.jpg
Glossary
Glossary
Abbreviations
ADR
American depositary receipt.
ADS
American depositary share. 1 ADS = 6 ordinary shares.
Barrel (bbl)
159 litres, 42 US gallons.
bcf
Billion cubic feet.
bcfe
Billion cubic feet equivalent.
boe
Barrels of oil equivalent.
CAGR
Compound annual growth rate.
EJ/yr
Exajoules per year.
EVP
Executive vice president.
FPSO
Floating production, storage and offloading.
GAAP
Generally accepted accounting practice.
Gas
Natural gas.
gCO2e/MJ
Grams of carbon dioxide equivalent per megajoule of energy.
GHG
Greenhouse gas.
GRI
Global Reporting Initiative.
GtCO2
Gigatonnes of carbon dioxide.
GW
Gigawatt.
GWh
Gigawatt hour.
HSSE
Health, safety, security and environment.
IFRS
International Financial Reporting Standards.
kb/d
Thousand barrels per day.
KPIs
Key performance indicators.
kt
Thousand tonnes.
LNG
Liquefied natural gas.
LPG
Liquefied petroleum gas.
mb/d
Thousand barrels per day.
Mbbl
Million barrels.
mboe/d
Thousand barrels of oil equivalent per day.
mmb/d
Million barrels per day.
mmboe/d
Million barrels of oil equivalent per day.
mmBtu
Million British thermal units.
mmcf/d
Million cubic feet per day.
Mt
Million tonnes.
MtCO2e
Million tonnes of CO2 equivalent.
Mtpa
Million tonnes per annum.
MW
Megawatt.
MWe
Megawatt electrical.
MWp
Megawatt peak.
NGLs
Natural gas liquids.
PSA
Production-sharing agreement.
PTA
Purified terephthalic acid.
RC
Replacement cost.
SEC
The United States Securities and Exchange Commission.
TWh
Terawatt hour.
SVP
Senior vice president.
scfm
Standard cubic feet per minute.
376
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Definitions
Unless the context indicates otherwise, the definitions for the following
glossary terms are given below.
Non-IFRS measures are sometimes referred to as alternative
performance measures.
CA100+ resolution glossary
CA100+ resolution
The CA100+ resolution means the special resolution requisitioned by
Climate Action 100+ and passed at bp’s 2019 Annual General Meeting,
the text of which is set out below.
Special resolution: Climate Action 100+ shareholder resolution on
climate change disclosures.
That in order to promote the long-term success of the company, given
the recognized risks and opportunities associated with climate change,
we as shareholders direct the company to include in its strategic report
and/or other corporate reports, as appropriate, for the year ending 2019
onwards, a description of its strategy which the board considers, in
good faith, to be consistent with the goals of Articles 2.1(a)(1) and 4.1(2) of
the Paris Agreement (3) (the Paris goals), as well as:
(1) Capital expenditure: how the company evaluates the consistency of
each new material capex investment, including in the exploration,
acquisition or development of oil and gas resources and reserves and
other energy sources and technologies, with (a) the Paris goals and
separately (b) a range of other outcomes relevant to its strategy.
(2) Metrics and targets: the company’s principal metrics and relevant
targets or goals over the short, medium and/or long term, consistent
with the Paris goals, together with disclosure of:
aThe anticipated levels of investment in (i) oil and gas resources and
reserves; and (ii) other energy sources and technologies.
bThe company’s targets to promote reductions in its operational
greenhouse gas emissions, to be reviewed in line with changing
protocols and other relevant factors.
cThe estimated carbon intensity of the company’s energy products and
progress on carbon intensity over time.
dAny linkage between the above targets and executive remuneration.
(3) Progress reporting: an annual review of progress against (1) and (2)
above.
Such disclosure and reporting to include the criteria and summaries of
the methodology and core assumptions used, and to omit commercially
confidential or competitively sensitive information and be prepared at
reasonable cost; and provided that nothing in this resolution shall limit
the company’s powers to set and vary its strategy, or associated targets
or metrics, or to take any action which it believes in good faith, would
best promote the long-term success of the company.
The Paris goals
(1)Article 2.1(a) of the Paris Agreement states the goal 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, recognizing that this
would significantly reduce the risks and impacts of climate change’.
(2)Article 4.1 of the Paris Agreement: In order to achieve the long-term
temperature goal set out in Article 2, parties aim to reach global
peaking of greenhouse gas emissions as soon as possible,
recognizing that peaking will take longer for developing country
parties, and to undertake rapid reductions thereafter in accordance
with best available science, so as to achieve a balance between
anthropogenic emissions by sources and removals by sinks of
greenhouse gases in the second half of this century, on the basis of
equity, and in the context of sustainable development and efforts to
eradicate poverty.
(3)U.N. Framework Convention on Climate Change Conference of
Parties, Twenty-First Session, Adoption of the Paris Agreement, U.N.
Doc. FCCC/CP/2015/L.9/Rev.1 (Dec. 12, 2015).
New material capex investment
For the purposes of the 2024 evaluation discussed on pages 20-23, ‘new
material capex investment’ means a decision taken by the resource
commitment meeting (RCM) in 2024 to incur inorganic or organic
investments greater than $250 million that relate to a new project or
asset, extending an existing project or asset, or acquiring or increasing a
share in a project, asset or entity.
For the purposes of evaluating material capex investments for
consistency with the Paris goals, two quantitative tests were applied,
see page 22.
Operational carbon intensity (CI)
The annual average operational GHG emissions (TeCO2e/unit), divided
by the relevant unit of output:
Per thousand barrels of oil equivalent in upstream.
Per utilized equivalent distillation capacity in refining.
per thousand tonnes of petrochemicals production.
Net zero aims and ambition glossary
Average carbon intensity of sold energy products
The rate of GHG emissions per unit of energy delivered (in grams CO2e/
MJ) estimated in respect of sold energy products«. GHG emissions are
estimated on a lifecycle basis covering use, production, and distribution
of sold energy products.
Energy products
For the purposes of our 2025 disclosures relating to net zero sales« we
consider an energy product to be one that is emissive or provides
energy in its end use case. For further information on products included
in bp’s 2025 net zero sales aim reporting see the bp Basis of Reporting
2025, bp.com/basisofreporting.
Methane intensity
Methane intensity refers to the amount of methane emissions from bp’s
operated upstream oil and gas assets as a percentage of the total gas
that goes to market from those operations. Our methodology is aligned
with the Oil and Gas Climate Initiative (OGCI) methodology.
Net zero
References to global net zero in the phrase, ‘to help the world get to net
zero’, means achieving ‘...a balance between anthropogenic emissions
by sources and removals by sinks of greenhouse gases...on the basis of
equity, and in the context of sustainable development and efforts to
eradicate poverty’, as set out in Article 4(1) of the Paris Agreement.
References to net zero for bp in the context of our ambition and net
zero operations and net zero sales aims mean achieving a balance
between (a) the relevant Scope 1 and 2 emissions (for net zero
operations) and product lifecycle emissions (for net zero sales) and (b)
the aggregate of applicable deductions from qualifying activities such
as sinks under our methodology at the applicable time.
Net zero« operations
bp’s aim to reach net zero operational greenhouse gas (CO2 and
methane) emissions by 2050 or sooner, on a gross operational control
basis, in accordance with bp’s net zero operations aim, which relates to
our reported Scope 1 and 2 emissions. Any interim target or aim in
respect of bp’s net zero operations aim is defined in terms of absolute
reductions relative to the baseline year of 2019.
Net zero sales
bp’s aim to reach net zero for the carbon intensity of sold energy
products«. Any interim target or aim in respect of bp’s net zero sales
aim is defined in terms of reductions in the carbon intensity of the
energy products we sell (in grams CO2e/MJ) relative to the baseline
year of 2019.
bp Annual Report and Form 20-F 2025
377
NavigtionTabCornerV1.jpg
Glossary
Sold energy products
For the purposes of bp’s net zero sales aim, sold energy products
represent sales by a bp group subsidiary, joint operation or bp equity
accounted entity (EAE). For further information see the bp Basis of
Reporting 2025 bp.com/basisofreporting.
Adjusted EBIDA
Adjusted EBIDA is a non-IFRS measure. This metric, as applicable to the
directors’ remuneration performance measure, requires a calculation of
profit or loss for the period, adjusting for finance costs and net finance
(income) or expense relating to pensions and other post-employment
benefits and taxation, inventory holding gains or losses before tax, net
adjusting items« before interest and tax, and taxation on an underlying
RC basis, and adding back depreciation, depletion and amortization
(pre-tax) and exploration expenditure written-off (net of adjusting items,
pre-tax). The nearest equivalent measure on an IFRS basis is profit or
loss for the period.
Adjusted EBIDA per share compound annual growth rate
(CAGR)
Adjusted EBIDA per share is a non-IFRS measure. This metric, as
applicable to the directors’ remuneration performance measure, is
calculated based on the shares in issue at period end.
Adjusted EBITDA
Adjusted EBITDA is a non-IFRS measure presented for bp's operating
segments and the group. Adjusted EBITDA for bp's operating segments
is defined as replacement cost (RC) profit before interest and tax,
excluding net adjusting items before interest and tax, and adding back
depreciation, depletion and amortization and exploration write-offs (net
of adjusting items). Adjusted EBITDA by business is a further analysis of
adjusted EBITDA for the customers & products businesses. bp believes
it is helpful to disclose adjusted EBITDA by operating segment and by
business because it reflects how the segments measure underlying
business delivery. The nearest equivalent measure on an IFRS basis for
the segment is RC profit or loss before interest and tax, which is bp's
measure of profit or loss that is required to be disclosed for each
operating segment under IFRS. A reconciliation to IFRS information is
provided on pages 350 and 388.
Adjusted EBITDA for the group is defined as profit or loss for the period,
adjusting for finance costs and net finance (income) or expense relating
to pensions and other post-employment benefits and taxation,
inventory holding gains or losses before tax, net adjusting items before
interest and tax, and adding back depreciation, depletion and
amortization (pre-tax) and exploration expenditure written-off (net of
adjusting items, pre-tax). The nearest equivalent measure on an IFRS
basis for the group is profit or loss for the period. A reconciliation to
IFRS information is provided on page 387.
Adjusted free cash flow
Non-IFRS measure. It is defined as adjusted operating cash flow« (see
below) less total cash capital expenditure«.
bp believes the measure provides useful information to investors.
Adjusted free cash flow enables investors to measure our progress on
delivering growth and improving our performance. The nearest IFRS
measures are net cash provided by (used in) operating activities and
total cash capital expenditure.
We are unable to present reconciliations of forward-looking information
for adjusted free cash flow to net cash provided by operating activities,
because without unreasonable efforts, we are unable to forecast
accurately certain adjusting items required to present a meaningful
comparable IFRS forward-looking financial measure. These items
include inventory holding gains or losses, fair value accounting effects
and other adjusting items, that are difficult to predict in advance in
order to include in an IFRS estimate.
Adjusted free cash flow compound annual growth rate (CAGR)
Non-IFRS measure. Adjusted free cash flow compound annual growth is
the annualized growth rate of adjusted free cash flow (defined above).
bp believes adjusted free cash flow CAGR is useful information to
investors to compare with adjusted free cash flow on a price adjusted
basis CAGR. The nearest IFRS measures to calculate adjusted free cash
flow CAGR are net cash provided by (used in) operating activities and
total cash capital expenditure.
Adjusted free cash flow compound annual growth rate (CAGR)
(primary target)
Non-IFRS measure. Our primary target adjusted free cash flow CAGR is
on a price adjusted basis and is the annualized growth rate of adjusted
free cash flow (defined above), 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.
bp believes adjusted free cash flow on a price adjusted basis compound
annual growth rate helps investors to measure our progress on
delivering growth and improving our performance on a normalized price
environment basis. The nearest IFRS measures to calculate adjusted
free cash flow CAGR are net cash provided by (used in) operating
activities and total capital expenditure.
We are unable to present reconciliations of forward-looking information
for adjusted free cash flow to net cash provided by operating activities,
because without unreasonable efforts, we are unable to forecast
accurately certain adjusting items required to present a meaningful
comparable IFRS forward-looking financial measure. These items
include inventory holding gains or losses, fair value accounting effects
and other adjusting items, that are difficult to predict in advance in
order to include in an IFRS estimate.
Adjusted operating cash flow
Non-IFRS measure. It is defined as net cash provided by (used in)
operating activities as presented in the group cash flow statement,
excluding movements in inventories and other current and non-current
assets and liabilities as presented in the group cash flow statement,
adjusted for inventory holding gains/losses, fair value accounting
effects (FVAEs) relating to subsidiaries and other adjusting items
relating to the non-cash movement of US emissions obligations carried
as a provision that will be settled by allowances held as inventory. When
used in the context of a segment or subset of businesses rather than
the group, the terms refer to the segment or business' estimated share
thereof.
bp believes the measure provides useful information to investors.
Adjusted operating cash flow enables investors to measure our
progress on delivering growth and improving our performance. The
nearest IFRS measure is net cash provided by (used in) operating
activities.
We are unable to present reconciliations of forward-looking information
for adjusted operating cash flow to net cash provided by operating
activities, because without unreasonable efforts, we are unable to
forecast accurately certain adjusting items required to present a
meaningful comparable IFRS forward-looking financial measure. These
items include inventory holding gains or losses, FVAEs and other
adjusting items, that are difficult to predict in advance in order to
include in an IFRS estimate.
Adjusted operating expenditure
Non IFRS measure and a subset of production and manufacturing
expenses plus distribution and administration expenses. It represents
the majority of the remaining expenses in these line items but excludes
certain costs that are variable, primarily with volumes (such as freight
costs). Other variable costs are included in purchases in the income
statement. Management believes that adjusted operating expenditure
is a performance measure that provides investors with useful
information regarding the company’s financial performance because it
considers these expenses to be the principal operating and overhead
expenses that are most directly under their control although they also
378
bp Annual Report and Form 20-F 2025
« See glossary on page 375
include certain adjusting items«, foreign exchange and commodity
price effects. The nearest IFRS measures are production and
manufacturing expenses and distributions and administration
expenses. A reconciliation of production and manufacturing expense
plus distribution and administration expenses to adjusted operating
expenditure is provided on page 386.
Adjusting items
Adjusting items are items that bp discloses separately because it
considers such disclosures to be meaningful and relevant to investors.
They are items that management considers to be important to period-
on-period analysis of the group's results and are disclosed in order to
enable investors to better understand and evaluate the group’s
reported financial performance. Adjusting items include gains and
losses on the sale of businesses and fixed assets, impairments,
environmental and related provisions and charges, restructuring,
integration and rationalization costs, fair value accounting effects, costs
relating to the Gulf of America oil spill and other items. Adjusting items
within equity-accounted earnings are reported net of incremental
income tax reported by the equity-accounted entity. Adjusting items are
used as a reconciling adjustment to derive underlying RC profit or loss
and related underlying measures which are non-IFRS measures. An
analysis of adjusting items by segment and type is shown on page 336.
Associate
An entity over which the group has significant influence and that is
neither a subsidiary nor a joint arrangement of the group. Significant
influence is the power to participate in the financial and operating
policy decisions of the investee but is not control or joint control over
those policies.
Blue hydrogen
Hydrogen made from natural gas or coal in combination with carbon
capture and storage (CCS).
Capital employed
Non-IFRS measure. It is defined as total equity plus finance debt.
Capital expenditure
Total cash capital expenditure as stated in the group cash flow
statement. Capital expenditure for the operating segments, gas & low
carbon energy businesses and customers & products businesses is
presented on the same basis.
Commodity trading contracts
bp participates in regional and global commodity trading markets in
order to manage, transact and hedge the crude oil, refined products
and natural gas that the group either produces or consumes in its
manufacturing operations. The range of contracts the group enters into
in its commodity trading operations is described below. Using these
contracts, in combination with rights to access storage and
transportation capacity, allows the group to access advantageous
pricing differences between locations, time periods and grades.
Exchange-traded commodity derivatives
Contracts that are typically in the form of futures and options traded on
a recognized exchange, such as Nymex and ICE. Such contracts are
traded in standard specifications for the main marker crude oils, such
as Brent and West Texas Intermediate; the main product grades, such
as gasoline and gasoil; and for natural gas and power. Gains and losses,
otherwise referred to as variation margin, are generally settled on a
daily basis with the relevant exchange. These contracts are used for the
trading and risk management of crude oil, refined products, and natural
gas and power. Realized and unrealized gains and losses on exchange-
traded commodity derivatives are included in sales and other operating
revenues for accounting purposes.
Over-the-counter (OTC) contracts
Contracts that are typically in the form of forwards, swaps and options.
Some of these contracts are traded bilaterally between counterparties
or through brokers, others may be cleared by a central clearing
counterparty. These contracts can be used both for trading and risk
management activities. Realized and unrealized gains and losses on
OTC contracts are included in sales and other operating revenues for
accounting purposes. Many grades of crude oil bought and sold use
standard contracts including US domestic light sweet crude oil,
commonly referred to as West Texas Intermediate, and a standard
North Sea crude blend – Brent, Forties, Oseberg and Ekofisk (BFOE).
Forward contracts are used in connection with the purchase of crude oil
supplies for refineries and for marketing and sales of the group’s oil
production and refined products. The contracts typically contain
standard delivery and settlement terms. These transactions call for
physical delivery of oil with consequent operational and price risk.
However, various means exist and are used from time to time, to settle
obligations under the contracts in cash rather than through physical
delivery. Physically settled BFOE contracts delivered by cargo
additionally specify a standard volume and tolerance.
Gas and power OTC markets are highly developed in North America and
the UK, where commodities can be bought and sold for delivery in
future periods. These contracts are negotiated between two parties to
purchase and sell gas and power at a specified price, with delivery and
settlement at a future date. Typically, the contracts specify delivery
terms for the underlying commodity. Some of these transactions are
not settled physically as they can be net settled by transacting
offsetting sale or purchase contracts for the same location and delivery
period. The contracts contain standard terms such as delivery point,
pricing mechanism, settlement terms and specification of the
commodity. Typically, volume, price and term (e.g. daily, monthly and
balance of month) are the main variable contract terms.
Swaps are typically contractual obligations to exchange cash flows
between two parties. A typical swap transaction usually references a
floating price and a fixed price with the net difference of the cash flows
being settled. Options give the holder the right, but not the obligation,
to buy or sell crude, oil products, natural gas or power at a specified
price on or before a specific future date. Amounts under these
derivative financial instruments are settled at expiry. Typically, netting
agreements are used to limit credit exposure and support liquidity.
Spot and term contracts
Spot contracts are contracts to purchase or sell a commodity at the
market price prevailing on or around the delivery date when title to the
inventory is taken. Term contracts are contracts to purchase or sell a
commodity at regular intervals over an agreed term. Though spot and
term contracts may have a standard form, there is no offsetting
mechanism in place. As such, these transactions result in physical
delivery with operational and price risk. Spot and term contracts
typically relate to purchases of crude for a refinery, products for
marketing, or third-party natural gas, or sales of the group’s oil
production, oil products or gas production to third parties. For
accounting purposes, spot and term sales are included in sales and
other operating revenues when title passes. Similarly, spot and term
purchases are included in purchases for accounting purposes.
Consolidation adjustment – UPII
Unrealized profit in inventory arising on inter-segment transactions.
Convenience gross margin
Non-IFRS measure. Convenience gross margin is calculated as RC profit
before interest and tax for the customers & products segment,
excluding RC profit before interest and tax for the refining & trading
business (a non-IFRS measure), and adjusting items« (as defined above)
for the convenience & mobility business to derive underlying RC profit
before interest and tax for the convenience & mobility business;
subtracting underlying RC profit before interest and tax for the Castrol
business; adding back depreciation, depletion and amortization,
production and manufacturing, distribution and administration
expenses for convenience & mobility (excluding Castrol); subtracting
earnings from equity-accounted entities in the convenience & mobility
business (excluding Castrol) and gross margin for the retail fuels, EV
charging, aviation, B2B and midstream businesses. bp believes it is
helpful because this measure may help investors to understand and
evaluate, in the same way as management, our progress against our
strategic objectives of convenience growth. The nearest IFRS measure
is RC profit before interest and tax for the customers & products
segment.
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Glossary
Convenience gross margin growth (%)
Non-IFRS measure. See convenience gross margin definition.
Convenience gross margin growth at constant foreign exchange is a
non-IFRS measure. This metric, as applicable to the directors’
remuneration performance measure, requires a calculation of the
comparative convenience margin ($ million) at current period foreign
exchange rates (constant foreign exchange) and compares the current
period value with the restated comparative period value, which results
in the growth % at constant foreign exchange rates. The nearest IFRS
measure to convenience gross margin is RC profit before interest and
tax for the customer & products segment.
Developed renewables to final investment decision (FID)
Total generating capacity for assets developed to FID by all entities
where bp has an equity share (proportionate to equity share). If asset is
subsequently sold bp will continue to record capacity as developed to
FID. If bp equity share increases developed capacity to FID will increase
proportionately to share increase for any assets where bp held equity at
the point of FID.
Divestment proceeds
Disposal proceeds as per the group cash flow statement.
Dividend yield
Sum of the four quarterly dividends announced in respect of the year as
a percentage of the year-end share price.
Downstream
Downstream is the customers & products segment. It 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.
Dutch Title Transfer Facility
The TTF (Title Transfer Facility) is the virtual trading point for natural gas
in the Netherlands. It is commonly used as a benchmark hub for gas
prices in Europe.
Electric vehicle charge points / EV charge points
Defined as the number of connectors on a charging device, operated by
either bp or a bp joint venture, as adjusted to be reflective of bp’s
accounting share of joint arrangements.
Excess cash
Non-IFRS measure. It refers to the net of sources and uses of cash.
Sources of cash include net cash provided by operating activities, cash
provided from investing activities and cash receipts relating to
transactions involving non-controlling interests. Uses of cash include
lease liability payments, payments on perpetual hybrid bonds, dividends
paid, cash capital expenditure, the cash cost of share buybacks to offset
the dilution from vesting of awards under employee share schemes,
cash payments relating to transactions involving non-controlling
interests and currency translation differences relating to cash and cash
equivalents as presented on the condensed group cash flow statement.
Fair value accounting effects
Non-IFRS adjustments to our IFRS profit (loss).They reflect the
difference between the way bp manages the economic exposure and
internally measures performance of certain activities and the way those
activities are measured under IFRS. Fair value accounting effects are
included within adjusting items. They relate to certain of the group's
commodity, interest rate and currency risk exposures as detailed below.
Other than as noted below, the fair value accounting effects described
are reported in both the gas & low carbon energy and customer &
products segments.
bp uses derivative instruments to manage the economic exposure
relating to inventories above normal operating requirements of crude
oil, natural gas and petroleum products. Under IFRS, these inventories
are recorded at historical cost. The related derivative instruments,
however, are required to be recorded at fair value with gains and losses
recognized in the income statement. This is because hedge accounting
is either not permitted or not followed, principally due to the
impracticality of effectiveness-testing requirements. Therefore,
measurement differences in relation to recognition of gains and losses
occur. Gains and losses on these inventories, other than net realizable
value provisions, are not recognized until the commodity is sold in a
subsequent accounting period. Gains and losses on the related
derivative commodity contracts are recognized in the income
statement, from the time the derivative commodity contract is entered
into, on a fair value basis using forward prices consistent with the
contract maturity.
bp enters into physical commodity contracts to meet certain business
requirements, such as the purchase of crude for a refinery or the sale of
bp’s gas production. Under IFRS these physical contracts are treated as
derivatives and are required to be fair valued when they are managed as
part of a larger portfolio of similar transactions. Gains and losses arising
are recognized in the income statement from the time the derivative
commodity contract is entered into.
IFRS require that inventory held for trading is recorded at its fair value
using period-end spot prices, whereas any related derivative
commodity instruments are required to be recorded at values based on
forward prices consistent with the contract maturity. Depending on
market conditions, these forward prices can be either higher or lower
than spot prices, resulting in measurement differences.
bp enters into contracts for pipelines and other transportation, storage
capacity, oil and gas processing, liquefied natural gas (LNG) and certain
gas and power contracts that, under IFRS, are recorded on an accruals
basis. These contracts are risk-managed using a variety of derivative
instruments that are fair valued under IFRS. This results in measurement
differences in relation to recognition of gains and losses.
The way that bp manages the economic exposures described above,
and measures performance internally, differs from the way these
activities are measured under IFRS. bp calculates this difference for
consolidated entities by comparing the IFRS result with management’s
internal measure of performance. We believe that disclosing
management’s estimate of this difference provides useful information
for investors because it enables investors to see the economic effect of
these activities as a whole.
These include:
Under management’s internal measure of performance the
inventory, transportation and capacity contracts in question are
valued based on fair value using relevant forward prices prevailing at
the end of the period.
Fair value accounting effects also include changes in the fair value of
the near-term portions of LNG contracts that fall within bp’s risk
management framework. LNG contracts are not considered
derivatives, because there is insufficient market liquidity, and they
are therefore accrual accounted under IFRS. However, oil and natural
gas derivative financial instruments used to risk manage the near-
term portions of the LNG contracts are fair valued under IFRS. The
fair value accounting effect, which is reported in the gas and low
carbon energy segment, represents the change in value of LNG
contracts that are being risk managed and which is reflected in the
underlying result, but not in reported earnings. Management
believes that this gives a better representation of performance in
each period.
Furthermore, the fair values of derivative instruments used to risk
manage certain other oil, gas, power and other contracts, are deferred
to match with the underlying exposure. The commodity contracts for
business requirements are accounted for on an accruals basis.
In addition, fair value accounting effects include changes in the fair
value of derivatives entered into by the group to manage currency
exposure and interest rate risks relating to hybrid bonds to their
respective first call periods. The hybrid bonds which are classified as
equity instruments and were recorded in the balance sheet at their
issuance date at their USD equivalent issued value. Under IFRS these
equity instruments are not remeasured from period to period, and do
not qualify for application of hedge accounting. The derivative
instruments relating to the hybrid bonds, however, are required to be
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« See glossary on page 375
recorded at fair value with mark to market gains and losses recognized
in the income statement. Therefore, measurement differences in
relation to the recognition of gains and losses occur. The fair value
accounting effect, which is reported in the other businesses &
corporate segment, eliminates the fair value gains and losses of these
derivative financial instruments that are recognized in the income
statement. We believe that this gives a better representation of
performance, by more appropriately reflecting the economic effect of
these risk management activities, in each period.
Finance debt ratio
Finance debt ratio is defined as the ratio of finance debt to the total of
finance debt plus total equity.
Gearing
See net debt and gearing below.
Gearing including leases
See net debt including leases and gearing including leases below.
Green hydrogen
Hydrogen produced by electrolysis of water using renewable power.
Hydrocarbons
Liquids and natural gas. Natural gas is converted to oil equivalent at
5.8 billion cubic feet = 1 million barrels.
Inorganic capital expenditure
A subset of capital expenditure on a cash basis and a non-IFRS measure.
Inorganic capital expenditure comprises consideration in business
combinations and certain other significant investments made by the
group. It is reported on a cash basis. bp believes that this measure
provides useful information as it allows investors to understand how
bp’s management invests funds in projects which expand the group’s
activities through acquisition. The nearest equivalent measure on an
IFRS basis is capital expenditure on a cash basis. Further information
and a reconciliation to IFRS information is provided on page 335.
Inventory holding gains and losses
Inventory holding gains and losses are non-IFRS adjustments to our
IFRS profit (loss) and represent:
The difference between the cost of sales calculated using the
replacement cost of inventory and the cost of sales calculated on
the first-in first-out (FIFO) method after adjusting for any changes in
provisions where the net realizable value of the inventory is lower
than its cost. Under the FIFO method, which we use for IFRS
reporting of inventories other than for trading inventories, the cost
of inventory charged to the income statement is based on its
historical cost of purchase or manufacture, rather than its
replacement cost. In volatile energy markets, this can have a
significant distorting effect on reported income. The amounts
disclosed as inventory holding gains and losses represent the
difference between the charge to the income statement for
inventory on a FIFO basis (after adjusting for any related movements
in net realizable value provisions) and the charge that would have
arisen based on the replacement cost of inventory. For this purpose,
the replacement cost of inventory is calculated using data from each
operation’s production and manufacturing system, either on a
monthly basis, or separately for each transaction where the system
allows this approach.
An adjustment relating to certain trading inventories that are not
price risk managed which relate to a minimum inventory volume that
is required to be held to maintain underlying business activities. This
adjustment represents the movement in fair value of the inventories
due to prices, on a grade-by-grade basis, during the period. This is
calculated from each operation’s inventory management system on
a monthly basis using the discrete monthly movement in market
prices for these inventories.
The amounts disclosed are not separately reflected in the financial
statements as a gain or loss. No adjustment is made in respect of the
cost of inventories held as part of a trading position and certain other
temporary inventory positions that are price risk-managed. See
Replacement cost (RC) profit or loss definition below.
Joint arrangement
An arrangement in which two or more parties have joint control.
Joint control
Contractually agreed sharing of control over an arrangement, which
exists only when decisions about the relevant activities require the
unanimous consent of the parties sharing control.
Joint operation
A joint arrangement whereby the parties that have joint control of the
arrangement have rights to the assets, and obligations for the liabilities,
relating to the arrangement.
Joint venture
A joint arrangement whereby the parties that have joint control of the
arrangement have rights to the net assets of the arrangement.
Liquids
Comprises crude oil, condensate and natural gas liquids. For the oil
production & operations segment, it also includes bitumen.
LNG portfolio
LNG portfolio refers to bp group’s LNG equity production plus
additional long-term merchant LNG volumes.
LNG train
An LNG train is a processing facility used to liquefy and purify natural
gas in the formation of LNG.
Major projects
Have a bp net investment of at least $250 million, or are considered to
be of strategic importance to bp or of a high degree of complexity.
Modified free cash flow
A non-IFRS measure. It is defined as operating cash flow less: (1) net
cash used in investing activities as presented in the group cash flow
statement; and (2) lease liability payments included in financing
activities and adjusting for receipts relating to transactions involving
non-controlling interests reported within financing activities in the
group cash flow statement and movements in lease creditor.
Net debt and gearing
Non-IFRS measures. Net debt is calculated as finance debt, as shown in
the balance sheet, plus the fair value of associated derivative financial
instruments that are used to hedge foreign currency exchange and
interest rate risks relating to finance debt, for which hedge accounting
is applied, less cash and cash equivalents. Net debt does not include
accrued interest, which is reported within other receivables and other
payables on the balance sheet and for which the associated cash flows
are presented as operating cash flows in the group cash flow
statement. Gearing is defined as the ratio of net debt to the total of net
debt plus total equity. bp believes these measures provide useful
information to investors. Net debt enables investors to see the
economic effect of finance debt, related hedges and cash and cash
equivalents in total. Gearing enables investors to see how significant
net debt is relative to total equity. The derivatives are reported on the
balance sheet within the headings ‘Derivative financial instruments’. See
Financial statements – Note 27 for information on finance debt, which is
the nearest equivalent measure to net debt on an IFRS basis. The
nearest equivalent IFRS measure to gearing on an IFRS basis is finance
debt ratio.
We are unable to present reconciliations of forward-looking information
for net debt or gearing to finance debt and total equity, because
without unreasonable efforts, we are unable to forecast accurately
certain adjusting items required to present a meaningful comparable
IFRS forward-looking financial measure. These items include fair value
asset (liability) of hedges related to finance debt and cash and cash
equivalents, that are difficult to predict in advance in order to include in
an IFRS estimate.
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Glossary
Net debt including leases and gearing including leases
Non-IFRS measures. Net debt including leases is calculated as net debt
plus lease liabilities, less the net amount of partner receivables and
payables relating to leases entered into on behalf of joint operations.
Gearing including leases is defined as the ratio of net debt including
leases to the total of net debt including leases plus total equity. bp
believes these measures provide useful information to investors as they
enable investors to understand the impact of the group’s lease portfolio
on net debt and gearing. See Financial statements – Note 27 for
information on finance debt, which is the nearest equivalent measure to
net debt including leases on an IFRS basis. The nearest equivalent IFRS
measure to gearing including leases on an IFRS basis is finance debt
ratio. A reconciliation to IFRS information is provided on page 337.
Operating cash flow
Net cash provided by (used in) operating activities as stated in the
group cash flow statement. When used in the context of a segment
rather than the group, the terms refer to the segment’s share thereof.
Operating management system (OMS)
bp’s OMS helps us manage risks in our operating activities by setting
out bp’s principles for good operating practice. It brings together bp
requirements on health, safety, security, the environment, social
responsibility and operational reliability, as well as related issues, such
as maintenance, contractor relations and organizational learning, into a
common management system.
Organic capital expenditure
Non-IFRS measure. Organic capital expenditure comprises capital
expenditure on a cash basis less inorganic capital expenditure. bp
believes that this measure provides useful information as it allows
investors to understand how bp’s management invests funds in
developing and maintaining the group’s assets. The nearest equivalent
measure on an IFRS basis is capital expenditure on a cash basis. An
analysis of organic capital expenditure by segment and region, and a
reconciliation to IFRS information is provided on page 335.
We are unable to present reconciliations of forward-looking information
for organic capital expenditure to total cash capital expenditure,
because without unreasonable efforts, we are unable to forecast
accurately the adjusting item, inorganic capital expenditure, that is
difficult to predict in advance in order to derive the nearest IFRS
estimate.
Plant reliability
This metric, as applicable to the directors’ remuneration performance
measure, see Upstream / hydrocarbon plant reliability.
Production-sharing agreement/contract (PSA/PSC)
An arrangement through which an oil and gas company bears the risks
and costs of exploration, development and production. In return, if
exploration is successful, the oil company receives entitlement to
variable physical volumes of hydrocarbons, representing recovery of
the costs incurred and a stipulated share of the production remaining
after such cost recovery.
Proved reserves replacement ratio
The extent to which the year’s production has been replaced by proved
reserves added to our reserve base. The ratio is expressed in oil-
equivalent terms and includes changes resulting from discoveries,
improved recovery and extensions and revisions to previous estimates,
but excludes changes resulting from acquisitions and disposals.
Realizations
Realizations are the result of dividing revenue generated from
hydrocarbon sales, excluding revenue generated from purchases made
for resale and royalty volumes, by revenue generating hydrocarbon
production volumes. Revenue generating hydrocarbon production
reflects the bp share of production as adjusted for any production
which does not generate revenue. Adjustments may include losses due
to shrinkage, amounts consumed during processing, and contractual or
regulatory host committed volumes such as royalties. For the gas & low
carbon energy and oil production & operations segments, realizations
include transfers between businesses.
Refining availability
Represents Solomon Associates’ operational availability for bp-
operated refineries, which is defined as the percentage of the year that
a unit is available for processing after subtracting the annualized time
lost due to turnaround activity and all mechanical, process and
regulatory downtime.
Refining indicator margin (RIM)
A simple indicator of the weighted average of bp’s crude slate and
product yield as deemed representative for each refinery. Actual
margins realized by bp may vary due to a variety of factors, including
the actual mix of a crude and product for a given quarter.
Refining marker margin (RMM)
The average of regional indicator margins weighted for bp’s crude
refining capacity in each region. Each regional marker margin is based
on product yields and a marker crude oil deemed appropriate for the
region. The regional indicator margins may not be representative of the
margins achieved by bp in any period because of bp’s particular refinery
configurations and crude and product slate.
Renewable natural gas (RNG)
RNG is a pipeline-quality, lower carbon fuel that is interchangeable with
traditional natural gas. It is a form of biogas and a product of
decomposing organic material at sites including landfills, farms and
wastewater treatment facilities.
Renewables pipeline
Renewable projects satisfying the criteria below until the point they can
be considered developed to FID:
Site-based projects that have obtained land exclusivity rights, or for
power purchase agreement based projects an offer has been made to
the counterparty, or for auction projects pre-qualification criteria have
been met, or for acquisition projects post a binding offer has been
accepted.
Replacement cost (RC) profit or loss/RC profit or loss
attributable to bp shareholders
Reflects the replacement cost of inventories sold in the period and is
calculated as profit or loss attributable to bp shareholders, adjusting for
inventory holding gains and losses (net of tax). RC profit or loss for the
group is not a recognized IFRS measure. bp believes this measure is
useful to illustrate to investors the fact that crude oil and product prices
can vary significantly from period to period and that the impact on our
reported result under IFRS can be significant. Inventory holding gains
and losses vary from period to period due to changes in prices as well
as changes in underlying inventory levels. In order for investors to
understand the operating performance of the group excluding the
impact of price changes on the replacement of inventories, and to make
comparisons of operating performance between reporting periods, bp’s
management believes it is helpful to disclose this measure. The nearest
equivalent measure on an IFRS basis is profit or loss attributable to bp
shareholders. See Financial statements – Note 5. A reconciliation to IFRS
information is provided on page 24.
Reported recordable injury frequency
Reported recordable injury frequency measures the number of
reported work-related employee and contractor incidents that result in
a fatality or injury per 200,000 hours worked. This represents reported
incidents occurring within bp’s operational HSSE reporting boundary.
That boundary includes bp’s own operated facilities and certain other
locations or situations.
Retail fuel volumes
Retail fuel volumes are fuel volumes sold from bp branded retail sites
and includes gasoline, diesel, LPG sales and other fuel sales (e.g. ad blue
sold at the pump). Does not include fuels volume for equity accounted
entities.
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Retail sites
Retail sites include sites operated by dealers, jobbers, franchisees or
brand licensees or joint venture (JV) partners, under the bp brand. These
may move to and from the bp brand as their fuel supply agreement or
brand licence agreement expires and are renegotiated in the normal
course of business.
Retail sites are primarily branded BP, Arco, Amoco, Aral, Thorntons, and
TravelCenters of America and also includes sites in India through our
Jio-bp JV.
Return on average capital employed (ROACE)
Non-IFRS measure. ROACE is defined as underlying replacement cost
profit, which is defined as profit or loss attributable to bp shareholders
adjusted for inventory holding gains and losses, adjusting items and
related taxation on inventory holding gains and losses and adjusting
items total taxation, after adding back non-controlling interest and
interest expense net of tax, divided by the average of the beginning and
ending balances of total equity plus finance debt, excluding cash and
cash equivalents and goodwill as presented on the group balance sheet
over the periods presented. Interest expense before tax is finance costs
as presented on the group income statement, excluding lease interest,
the unwinding of the discount on provisions and other payables and
other adjusting items reported in finance costs. bp believes it is helpful
to disclose the ROACE because this measure gives an indication of the
company's capital efficiency. The nearest IFRS measures of the
numerator and denominator are profit or loss for the period attributable
to bp shareholders and total equity respectively. The reconciliation of
the numerator and denominator is provided on page 385.
We are unable to present forward-looking information of the nearest
IFRS measures of the numerator and denominator for ROACE, because
without unreasonable efforts, we are unable to forecast accurately
certain adjusting items required to calculate a meaningful comparable
IFRS forward-looking financial measure. These items include inventory
holding gains or losses and interest net of tax, that are difficult to
predict in advance in order to include in an IFRS estimate.
Return on average capital employed (ROACE) on a price
adjusted basis
Non-IFRS measure. ROACE on a price adjusted basis is adjusted ROACE
(defined above), calculated assuming a hypothetical price environment
of $70/bbl Brent, $4/mmBtu Henry Hub, and a $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.
bp believes ROACE on a price adjusted basis helps investors to assess
the company’s capital efficiency and underlying performance on a
normalized price environment basis. The nearest IFRS measures of the
numerator and denominator are profit or loss for the period attributable
to bp shareholders and total equity respectively.
Strategic convenience sites
Strategic convenience sites are retail sites, within the bp portfolio,
which sell bp-supplied vehicle energy (e.g. BP, Aral, Arco, Amoco,
Thorntons, bp pulse, TravelCenters of America and PETRO) and either
carry one of the strategic convenience brands (e.g. M&S, Rewe to Go) or
a differentiated bp-controlled convenience offer. To be considered a
strategic convenience site, the convenience offer should have a
demonstrable level of differentiation in the market in which it operates.
Strategic convenience site count includes sites under a pilot phase.
Structural cost reduction
Non-IFRS measure. It is calculated as decreases in underlying operating
expenditure« (as defined below) as a result of operational efficiencies,
divestments, workforce reductions and other cost saving measures that
are expected to be sustainable compared with 2023 levels. The total
change between periods in underlying operating expenditure will
reflect both structural cost reductions and other changes in spend,
including market factors, such as inflation and foreign exchange
impacts, as well as changes in activity levels and costs associated with
new operations. Estimates of cumulative annual structural cost
reduction may be revised depending on whether cost reductions
realized in prior periods are determined to be sustainable compared
with 2023 levels. Structural cost reductions are stewarded internally to
support management’s oversight of spending over time.
bp believes this performance measure is useful in demonstrating how
management drives cost discipline across the entire organization,
simplifying our processes and portfolio and streamlining the way we
work. The nearest IFRS measures are production and manufacturing
expenses and distributions and administration expenses. A
reconciliation of production and manufacturing expenses plus
distribution and administration expenses to underlying operating
expenditure is provided on page 386.
We are unable to present forward-looking information of the nearest
IFRS measures, because without unreasonable efforts, we are unable to
forecast accurately certain adjusting items required to calculate a
meaningful comparable IFRS forward-looking financial measure.
Subsidiary
An entity that is controlled by the bp group. Control of an investee
exists when an investor is exposed, or has rights, to variable returns
from its involvement with the investee and has the ability to affect
those returns through its power over the investee.
Technical service contract (TSC)
Technical service contract is an arrangement through which an oil and
gas company bears the risks and costs of exploration, development and
production. In return, the oil and gas company receives entitlement to
variable physical volumes of hydrocarbons, representing recovery of
the costs incurred and a profit margin which reflects incremental
production added to the oilfield.
Tier 1 and tier 2 process safety events
Tier 1 events are losses of primary containment from a process of
greatest consequence – such as causing harm to a member of the
workforce, damage to equipment from a fire or explosion, a community
impact or exceeding defined quantities. Tier 2 events are those of lesser
consequence. These represent reported incidents occurring within bp’s
operational HSSE reporting boundary. That boundary includes bp’s own
operated facilities and certain other locations or situations.
Tight oil and gas
Natural oil and gas reservoirs locked in hard sandstone rocks with low
permeability, making the underground formation extremely tight.
Transition businesses
Business activities (including development, production/manufacture/
generation and marketing, distribution and trading) associated with
products and services that support energy transition, including in the
areas of biogas, biofuels, EV charging, renewable power generation,
hydrogen and carbon capture.
Transition Scenario Catalogue
A catalogue of third-party transition scenarios, compiled by bp to
support TCFD transition resilience analysis and to help inform
impairment sensitivity analysis. This catalogue takes as its start point
data from the most recent (at the time of preparation) World Business
Council for Sustainable Development (WBCSD) Energy Climate Scenario
Catalogue Version 3.0, published May 2024, which we have updated for
amended IEA, NGFS and UN PRI IPR data where these source providers
have since published updated scenarios for key transition variables or
have ‘retired’ older scenarios. For further details see page 53.
UK National Balancing Point
A virtual trading location for sale, purchase and exchange of UK natural
gas. It is the pricing and delivery point for the Intercontinental Exchange
natural gas futures contract.
Ultra-fast charging
Electric vehicle charging of greater than or equal to 150kW.
Unconventionals
Resources found in geographic accumulations over a large area, that
usually present additional challenges to development such as low
permeability or high viscosity. Examples include shale gas and oil,
bp Annual Report and Form 20-F 2025
383
NavigtionTabCornerV1.jpg
Glossary
coalbed methane, gas hydrates and natural bitumen deposits. These
typically require specialized extraction technology such as hydraulic
fracturing or steam injection.
Underlying effective tax rate (ETR)
Non-IFRS measure. The underlying ETR is calculated by dividing taxation
on an underlying replacement cost (RC) basis by underlying RC profit or
loss before tax. Taxation on an underlying RC basis for the group is
calculated as taxation as stated on the group income statement
adjusted for taxation on inventory holding gains and losses and
adjusting items total taxation. Information on underlying RC profit or
loss is provided below. Taxation on an underlying RC basis presented
for the operating segments is calculated through an allocation of
taxation on an underlying RC basis to each segment. bp believes it is
helpful to disclose the underlying ETR because this measure may help
investors to understand and evaluate, in the same manner as
management, the underlying trends in bp’s operational performance on
a comparable basis, period on period. Taxation on an underlying RC
basis and underlying ETR are non-IFRS measures. The nearest
equivalent measure on an IFRS basis is the ETR on profit or loss for the
period.
We are unable to present reconciliations of forward-looking information
for underlying ETR to ETR on profit or loss for the period, because
without unreasonable efforts, we are unable to forecast accurately
certain adjusting items required to present a meaningful comparable
IFRS forward-looking financial measure. These items include the
taxation on inventory holding gains and losses and adjusting items, that
are difficult to predict in advance in order to include in an IFRS estimate.
A reconciliation to IFRS information is provided on page 384.
Underlying operating expenditure
Non-IFRS measure. A subset of production and manufacturing
expenses plus distribution and administration expenses and excludes
costs that are classified as adjusting items. It represents the majority of
the remaining expenses in these line items but excludes certain costs
that are variable, primarily with volumes (such as freight costs). Other
variable costs are included in purchases in the income statement.
Management believes that underlying operating expenditure is a
performance measure that provides investors with useful information
regarding the company’s financial performance because it considers
these expenses to be the principal operating and overhead expenses
that are most directly under their control although they also include
certain foreign exchange and commodity price effects. The nearest IFRS
measures are production and manufacturing expenses and
distributions and administration expenses. A reconciliation of
production and manufacturing expense plus distribution and
administration expenses to underlying operating expenditure is
provided on page 386.
Underlying production
Production after adjusting for acquisitions and divestments and
entitlement impacts in our production-sharing agreements (PSAs). 2024
underlying production, when compared with 2023, is production after
adjusting for acquisitions and divestments, curtailments, and
entitlement impacts in our production-sharing agreements/contracts
and technical service contract.
Underlying replacement cost (RC) profit or loss / underlying
RC profit or loss attributable to bp shareholders
Non-IFRS measure. RC profit or loss« (as defined above) after excluding
net adjusting items and related taxation. See page 336 for additional
information on the adjusting items that are used to arrive at underlying
RC profit or loss in order to enable a full understanding of the items and
their financial impact. Underlying RC profit or loss before interest and
tax for the operating segments or customers & products businesses is
calculated as RC profit or loss (as defined above) including profit or loss
attributable to non-controlling interests before interest and tax for the
operating segments and excluding net adjusting items for the
respective operating segment or business.
bp believes that underlying RC profit or loss is a useful measure for
investors because it is a measure closely tracked by management to
evaluate bp’s operating performance and to make financial, strategic
and operating decisions and because it may help investors to
understand and evaluate, in the same manner as management, the
underlying trends in bp’s operational performance on a comparable
basis, period on period, by adjusting for the effects of these adjusting
items.
The nearest equivalent measure on an IFRS basis for the group is profit
or loss attributable to bp shareholders. The nearest equivalent measure
on an IFRS basis for segments and businesses is RC profit or loss before
interest and taxation. A reconciliation to IFRS information is provided on
page 24 for the group and pages 28-36 for the segments.
Underlying RC profit or loss per share and underlying RC profit
or loss per ADS
Non-IFRS measures. Earnings per share is defined in Note 11. Underlying
RC profit or loss per ordinary share is calculated using the same
denominator as earnings per share as defined in the consolidated
financial statements. The numerator used is underlying RC profit or loss
attributable to bp shareholders rather than profit or loss attributable to
bp shareholders. Underlying RC profit or loss per ADS is calculated as
outlined above for underlying RC profit or loss per share except the
denominator is adjusted to reflect one ADS equivalent to six ordinary
shares. bp believes it is helpful to disclose the underlying RC profit or
loss per ordinary share and per ADS because these measures may help
investors to understand and evaluate, in the same manner as
management, the underlying trends in bp’s operational performance on
a comparable basis, period on period. The nearest equivalent measure
on an IFRS basis is basic earnings per share based on profit or loss for
the period attributable to bp shareholders. A reconciliation to IFRS
information is provided on page 384.
Upstream
Upstream includes oil and natural gas field development and
production within the gas & low carbon energy and oil production &
operations segments. References to upstream exclude Rosneft.
Upstream / hydrocarbon plant reliability
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.
Upstream unit production costs
Upstream unit production costs are calculated as production costs
divided by units of production. Production costs do 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.
West Texas Intermediate (WTI)
A light sweet crude oil, priced at Cushing, Oklahoma, which serves as a
benchmark price for purchases of oil in the US.
Working capital
Movements in inventories and other current and non-current assets and
liabilities as stated in the group cash flow statement.
Trade marks
Trade marks of the bp group appear throughout this report. They
include:
Amoco, Aral, Aral pulse, BP, bp pulse, Castrol, Gigahub, PETRO, TA,
Thorntons, epic goods and earnify
Trade marks:
REWE to Go – a registered trade mark of REWE
384
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Non-IFRS measures reconciliations
Reconciliation of basic earnings per ordinary share to underlying RC profit« per ordinary share«
Per ordinary share – cents
2025
2024
2023
Profit (loss) for the year attributable to bp shareholders
0.35
2.38
87.78
Inventory holding (gains) losses«, before tax
8.67
2.98
7.12
Taxation charge (credit) on inventory holding gains and losses
(2.15)
(0.73)
(1.69)
6.87
4.63
93.21
Net (favourable) adverse impact of adjusting items«, before tax
37.76
56.95
(6.58)
Taxation charge (credit) on adjusting items
3.39
(7.18)
(6.94)
Underlying RC profit for the year
48.02
54.40
79.69
Reconciliation of basic earnings per ADS to underlying RC profit per ADS«
Per ADS – dollars
2025
2024
2023
Profit (loss) for the year attributable to bp shareholders
0.02
0.14
5.27
Inventory holding (gains) losses, before tax
0.52
0.18
0.43
Taxation charge (credit) on inventory holding gains and losses
(0.13)
(0.04)
(0.11)
0.41
0.28
5.59
Net (favourable) adverse impact of adjusting items, before tax
2.27
3.42
(0.40)
Taxation charge (credit) on adjusting items
0.20
(0.44)
(0.41)
Underlying RC profit for the year
2.88
3.26
4.78
Reconciliation of effective tax rate (ETR) to underlying ETR«
Taxation (charge) credit
$ million
2025
2024
2023
Taxation on profit or loss before taxation for the year
(6,451)
(5,553)
(7,869)
Adjusted for taxation on inventory holding gains and losses
334
119
292
Adjusted for adjusting items total taxation
(528)
1,179
1,204
Taxation on an underlying RC basis
(6,257)
(6,851)
(9,365)
Effective tax rate
%
2025
2024
2023
ETR on profit or loss before taxation for the year
83
82
33
Adjusted for inventory holding gains and losses
(8)
(4)
Adjusted for adjusting items total taxation
(33)
(37)
6
Underlying ETR
42
41
39
bp Annual Report and Form 20-F 2025
385
NavigtionTabCornerV1.jpg
Non-IFRS measures reconciliations
Return on average capital employed (ROACE)«
$ million
2025
2024
Profit for the year attributable to bp shareholders
55
381
Inventory holding (gains) losses, before tax
1,351
488
Taxation charge (credit) on inventory holding gains and losses
(334)
(119)
Adjusting items, before tax
5,885
9,344
Taxation charge (credit) on adjusting items
528
(1,179)
Underlying RC profit
7,485
8,915
Interest expensea
3,339
3,113
Taxation on interest expense
(539)
(404)
Non-controlling interests (NCI)
1,240
848
11,525
12,472
Total equity
74,000
78,318
Finance debt
57,958
59,547
Capital employed
131,958
137,865
Less: Goodwillb
13,056
14,888
Cash and cash equivalents
36,556
39,204
82,346
83,773
Average capital employed excluding goodwill and cash and cash equivalents
83,059
87,859
Profit for the year attributable to bp shareholders divided by total equity
0.1%
0.5%
ROACE
13.9%
14.2%
aFinance costs, as reported in the Group income statement, were $5,106 million (2024 $4,683 million). Interest expense is finance costs excluding lease interest of $672 million (2024 $441 million),
unwinding of discount on provisions and other payables of $1,147 million (2024 $1,013 million) and other adjusting items related to finance costs $52 million gain (2024 $116 million expense).
b2025 includes the amount of goodwill classified as held for sale at 31 December 2025.
386
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Underlying operating expenditure« reconciliation
$ million
$ million
2025
2024
2023
From group income statement
Production and manufacturing expenses
25,646
26,584
25,044
Distribution and administration expenses
17,494
16,417
16,772
43,140
43,001
41,816
Less certain variable costs:
Transportation and shipping costsa
10,456
10,516
9,650
Environmental costsa
5,713
3,987
4,271
Marketing and distribution costs
1,692
1,882
2,430
Commission, storage and handling costs
1,594
1,519
1,633
Other variable costs and non-cash costs
1,819
1,495
743
Certain variable costs
21,274
19,399
18,727
Adjusted operating expenditure«
21,866
23,602
23,089
Less certain adjusting items«:
Gulf of America oil spill
31
51
57
Environmental and related provisions
656
181
647
Restructuring, integration and rationalization costs
520
222
(37)
Fair value accounting effects – derivative instruments relating to the hybrid bonds
(1,157)
221
(630)
Other certain adjusting items
(71)
601
419
Certain adjusting items
(21)
1,276
456
Underlying operating expenditure
21,887
22,326
22,633
Underlying operating expenditure reduction relative to 2023
(439)
(307)
Increase/(decrease) in underlying operating expenditure due to inflation, exchange, portfolio changes
and organic growth
1,572
443
Structural cost reduction«
(2,011)
(750)
aComparative periods have been restated for a reclassification in costs from transportation and shipping to environmental.
bp Annual Report and Form 20-F 2025
387
NavigtionTabCornerV1.jpg
Non-IFRS measures reconciliations
Adjusted EBITDA«
$ million
2025
2024
2023
Profit (loss) for the period
1,295
1,229
15,880
Finance costs
5,106
4,683
3,840
Net finance (income) expense relating to pensions and other post-employment benefits
(210)
(168)
(241)
Taxation
6,451
5,553
7,869
Profit before interest and tax
12,642
11,297
27,348
Inventory holding (gains) losses, before tax
1,351
488
1,236
13,993
11,785
28,584
Net (favourable) adverse impact of adjusting items, before interest and tax
5,457
8,839
(1,548)
19,450
20,624
27,036
Add back: Depreciation, depletion and amortization
17,822
16,622
15,928
Exploration expenditure written off
343
766
746
Adjusted EBITDA
37,615
38,012
43,710
388
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Reconciliation of RC profit before interest and tax for gas & low carbon energy and oil production & operations to
adjusted EBITDA
$ million
2025
2024
2023
gas & low carbon energy
RC profit before interest and taxa
1,330
3,052
14,080
Less: Net favourable (adverse) impact of adjusting itemsa
(4,037)
(3,751)
5,358
Underlying RC profit before interest and tax
5,367
6,803
8,722
Add back: Depreciation, depletion and amortization
4,969
4,835
5,680
Exploration expenditure written off
30
222
362
Adjusted EBITDA
10,366
11,860
14,764
oil production & operations
RC profit before interest and tax
8,558
10,789
11,191
Less: 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
Add back: Depreciation, depletion and amortization
7,719
6,797
5,692
Exploration expenditure written off
313
544
384
Adjusted EBITDA
17,446
19,278
18,857
a2024 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.
The Directors’ report on pages 72-90, 91 (in respect of the remuneration committee), 126, 241-268 and 334-388 was approved by the board and
signed on its behalf by Ben J. S. Mathews, company secretary on 6 March 2026.
BP p.l.c.
Registered in England and Wales No. 102498
bp Annual Report and Form 20-F 2025
389
Signatures
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the
undersigned to sign this annual report on its behalf.
BP p.l.c.
(Registrant)
/s/ Ben J. S. Mathews
Company secretary
6 March 2026
390
bp Annual Report and Form 20-F 2025
« See glossary on page 375
Cross reference to Form 20-F
Item 1.
Identity of Directors, Senior Management and Advisers
n/a
Item 2.
Offer Statistics and Expected Timetable
n/a
Item 3.
Key Information
A.
[Reserved]
n/a
B.
Capitalization and indebtedness
n/a
C.
Reasons for the offer and use of proceeds
n/a
D.
Risk factors
62-66
Item 4.
Information on the Company
A.
History and development of the company
23-27, 182-184, 190, 196, 199-202, 340-346, 350-351, 368-369, 373, 391
B.
Business overview
6-7, 12-13, 18-35, 185-189, 340-358, 363
C.
Organizational structure
240, 391
D.
Property, plants and equipment
14-15, 28-35, 160-161, 175, 266-268, 339-352, 359
Item 4A.
Unresolved Staff Comments
None
Item 5.
Operating and Financial Review and Prospects
A.
Operating results
6-9, 12-13, 18-27, 62-66, 201, 211-212, 214-228, 338-345, 350-358
B.
Liquidity and capital resources
159, 196, 211-219, 338-339
C.
Research and development, patent and licenses, etc.
12, 189
D.
Trend information
6-9, 12-13, 18-27, 340-351
E.
Critical Accounting Estimates
n/a
Item 6.
Directors, Senior Management and Employees
A.
Directors and senior management
73-76
B.
Compensation
91-125, 205-211, 238-239
C.
Board practices
73-75, 84-88
D.
Employees
56-58, 239
E.
Share ownership
56-58, 91-125, 205-211, 238
F.
Disclosure of a registrant’s action to recover erroneously awarded
compensation
n/a
Item 7.
Major Shareholders and Related Party Transactions
A.
Major shareholders
367-368
B.
Related party transactions
199-202, 359
C.
Interests of experts and counsel
n/a
Item 8.
Financial Information
A.
Consolidated Statements and Other Financial Information
155-240, 338, 365
B.
Significant Changes
n/a
Item 9.
The Offer and Listing
A.
Offer and listing details
365
B.
Plan of distribution
n/a
C.
Markets
365
D.
Selling shareholders
n/a
E.
Dilution
n/a
F.
Expenses of the issue
n/a
Item 10.
Additional Information
A.
Share capital
n/a
B.
Memorandum and articles of association
368-371
C.
Material contracts
358
D.
Exchange controls
365
E.
Taxation
365-367
F.
Dividends and paying agents
n/a
G.
Statements by experts
n/a
H.
Documents on display
373
I.
Subsidiary information
n/a
J.
Annual Report to Security Holders
n/a
Item 11.
Quantitative and Qualitative Disclosures About Market Risk
214-219
Item 12.
Description of Securities Other than Equity Securities
A.
Debt Securities
n/a
B.
Warrants and Rights
n/a
C.
Other Securities
n/a
D.
American Depositary Shares
373
Item 13.
Defaults, Dividend Arrearages and Delinquencies
None
Item 14.
Material Modifications to the Rights of Security Holders and Use of Proceeds
None
Item 15.
Controls and Procedures
154, 360
Item 16.
[Reserved]
n/a
Item 16A.
Audit committee financial expert
84, 359
Item 16B.
Code of Ethics
360
Item 16C.
Principal Accountant Fees and Services
239, 361
Item 16D.
Exemptions from the Listing Standards for Audit Committees
n/a
Item 16E.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
372
Item 16F.
Change in Registrant’s Certifying Accountant
n/a
Item 16G.
Corporate Governance
359-360
Item 16H.
Mine Safety Disclosure
n/a
Item 16I.
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
n/a
Item 16J.
Insider Trading Policies.
360
Item 16K.
Cyber security
55-56, 64, 68, 360-361
Item 17.
Financial Statements
n/a
Item 18.
Financial Statements
155-159
Item 19.
Exhibits
391
bp Annual Report and Form 20-F 2025
391
Information about this report
This document constitutes the Annual Report and Accounts in
accordance with UK requirements and the Annual Report on Form 20-F
in accordance with the US Securities Exchange Act of 1934, for BP p.l.c.
for the year ended 31 December 2025. A cross reference to Form 20-F
requirements is included on page 390.
This document contains the Strategic report on the inside front cover
and pages 1-71 and the Directors’ report on pages 72-90, 91 (in part only),
126, 241-268 and 334-388. The Strategic report and the Directors’ report
together include the management report required by DTR 4.1 of the UK
Financial Conduct Authority’s Disclosure Guidance and Transparency
Rules. The Directors’ remuneration report is on pages 91-125. The
consolidated financial statements of the group are on pages 129-240
and the corresponding reports of the auditor are on pages 149-154.
bp Annual Report and Form 20-F 2025 may be downloaded from
bp.com/annualreport. No material on the bp website, other than the
items identified as bp Annual Report and Form 20-F 2025, forms any
part of this document. References in this document to other documents
on the bp website, such as bp Energy Outlook 2025, and bp
Sustainability Report are included as an aid to their location and are not
incorporated by reference into this document.
BP p.l.c. is the parent company of the bp group of companies. The
company was incorporated in 1909 in England and Wales and changed
its name to BP p.l.c. in 2001. Where we refer to the company, we mean
BP p.l.c. The company and each of its subsidiaries« are separate legal
entities. Unless otherwise stated or the context otherwise requires, the
term “BP” or "bp" and terms such as “we”, “us” and “our” are used in this
report for convenience to refer to one or more of the members of the
bp group instead of identifying a particular entity or entities.
Information in this document reflects 100% of the assets and operations
of the company and its subsidiaries that were consolidated at the date
or for the periods indicated, including non-controlling interests.
The company’s primary share listing is the London Stock Exchange. In
the US, the company’s securities are traded on the New York Stock
Exchange (NYSE) in the form of ADSs (see page 365 for more details).
The term ‘shareholder’ in this report means, unless the context
otherwise requires, investors in the equity capital of BP p.l.c., both direct
and indirect. As the company's shares, in the form of ADSs, are listed on
the NYSE, an Annual Report on Form 20-F is filed with the SEC. Ordinary
shares are ordinary fully paid shares in BP p.l.c. of 25 cents each.
Preference shares are cumulative first preference shares and
cumulative second preference shares in BP p.l.c. of £1 each.
Registered office and
our worldwide headquarters:
BP p.l.c.
1 St James’s Square
London SW1Y 4PD
UK
Tel +44 (0)20 7496 4000
Our agent in the US:
BP America Inc.
501 Westlake Park Boulevard
Houston, Texas 77079
US
Tel +1 281 366 2000
Registered in England and Wales No. 102498.
London Stock Exchange symbol ‘BP.’
Exhibits
The following documents are filed in the Securities and Exchange
Commission (SEC) EDGAR system, as part of this Annual Report on
Form 20-F, and can be viewed on the SEC’s website.
Memorandum and Articles of Association of
BP p.l.c.****†
Description of rights of each class of
securities registered under Section 12 of the
Securities Exchange Act of 1934†
The BP Executive Directors’ Incentive
Plan****†
Director’s Service Agreement for K
Thomson***†
Director’s Service Agreement for C Howle†
The BP Share Award Plan 2025†
Subsidiaries (included as Note 37 to the
Financial Statements)
Code of Ethics*†
Insider trading policy and procedure****†
Rule 13a – 14(a) Certifications†
Rule 13a – 14(b) Certifications#†
Consent of Netherland, Sewell & Associates†
Report of Netherland, Sewell & Associates†
Consent Decree**†
Gulf states Settlement Agreement**†
Consent of Deloitte LLP†
Guaranteed Securities†
Executive Compensation Clawback
Policy****†
Exhibit 101
Inline XBRL data files
Exhibit 104
Cover page interactive data file (formatted as
Inline XBRL and contained in Exhibit 101)
*
Incorporated by reference to the company’s Annual Report on Form 20-F
for the year ended 31 December 2009.
**
Incorporated by reference to the company’s Annual Report on Form 20-F
for the year ended 31 December 2015.
***
Incorporated by reference to the company’s Annual Report on Form 20-F
for the year ended 31 December 2023.
****
Incorporated by reference to the company’s Annual Report on Form 20-F
for the year ended 31 December 2024.
#
Furnished only.
Included only in the annual report filed in the Securities and Exchange
Commission EDGAR system.
The total amount of long-term securities of BP p.l.c. and its subsidiaries
under any one instrument does not exceed 10% of their total assets on a
consolidated basis.
The company agrees to furnish copies of any or all such instruments to
the SEC on request.
392
bp Annual Report and Form 20-F 2025
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Council® (FSC®) certified paper sourced from well-managed forests and other
controlled sources. The paper is Elemental Chlorine Free (ECF) and Acid Free.
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