bp-20241231

Resetting our strategy

The board approved a reset of bp’s strategy
and reallocation of capital to drive growth and
improved performance, as announced at the
Capital Markets Update on 26 February 2025.
This announcement followed extended
workshops and board discussions with
members of the bp leadership team at each
board meeting since September 2023, leading
to what the board believes is a clear and
distinctive strategic direction, an investable
financial proposition, with a simpler narrative,
sustainability framework, financial frame and
metrics.
Throughout the process, the board explored
what drives valuation growth across three
quantitative pillars – growth, profitability, and
risk – along with qualitative factors like
investor proposition, market confidence, and
the company’s performance during the year.

bp’s investors want to see consistent
operational and financial performance, together
with strategic clarity with less complexity. The
board discussed choices on capital allocation
and efficiency, balance sheet resilience and
share buyback guidance.
When looking at the potential strategic options,
the board also considered bp’s sustainability
framework.
Recognizing the feedback to become a simpler
and more understandable organization, the
board considered the perspectives of various
stakeholders including investors and our
employees before approving the five focused
sustainability aims of net zero operations«, net
zero sales«, people, water and biodiversity.

Throughout the process the board explored
potential scenarios, opportunities, and risks.
This ultimately led to decisions being taken
that the board believes will best maximize bp’s
prospect of achieving its objectives and
fulfilling its purpose. The board believes the
strategy remains consistent with the goals of
the Paris Agreement. Recognizing that the
component parts of this update are important
to many stakeholder groups, the board
remains committed to the energy transition.
Stakeholders considered
òòòòòò


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
American Depositary Shares	BP	New York Stock Exchange
Ordinary Shares of 25c each		New York Stock Exchange	*
3.796% Guaranteed Notes due 2025	BP/25A	New York Stock Exchange
3.119% Guaranteed Notes due 2026	BP/26A	New York Stock Exchange
3.410% Guaranteed Notes due 2026	BP/26C	New York Stock Exchange
3.017% Guaranteed Notes due 2027	BP/27D	New York Stock Exchange
3.279% Guaranteed Notes due 2027	BP/27B	New York Stock Exchange
3.543% Guaranteed Notes due 2027	BP/27E	New York Stock Exchange
3.588% Guaranteed Notes due 2027	BP/27A BP/27C	New York Stock Exchange
5.017% Guaranteed Notes due 2027	BP/27	New York Stock Exchange
3.723% Guaranteed Notes due 2028	BP/28	New York Stock Exchange
3.937% Guaranteed Notes due 2028	BP/28A	New York Stock Exchange
4.234% Guaranteed Notes due 2028	BP/28B	New York Stock Exchange
4.868% Guaranteed Notes due 2029	BP/29C	New York Stock Exchange
4.970% Guaranteed Notes due 2029	BP/29A	New York Stock Exchange
4.699% Guaranteed Notes due 2029	BP/29	New York Stock Exchange
1.749% Guaranteed Notes due 2030	BP/30A	New York Stock Exchange
3.633% Guaranteed Notes due 2030	BP/30	New York Stock Exchange
2.721% Guaranteed Notes due 2032	BP/32A	New York Stock Exchange
4.812% Guaranteed Notes due 2033	BP/33	New York Stock Exchange
4.893% Guaranteed Notes due 2033	BP/33A	New York Stock Exchange
4.989% Guaranteed Notes due 2034	BP/34	New York Stock Exchange
5.227% Guaranteed Notes due 2034	BP/34A	New York Stock Exchange
3.060% Guaranteed Notes due 2041	BP/41	New York Stock Exchange
2.772% Guaranteed Notes due 2050	BP/50B	New York Stock Exchange
3.000% Guaranteed Notes due 2050	BP/50A	New York Stock Exchange
3.067% Guaranteed Notes due 2050	BP/50	New York Stock Exchange
2.939% Guaranteed Notes due 2051	BP/51	New York Stock Exchange
3.001% Guaranteed Notes due 2052	BP/52	New York Stock Exchange
3.379% Guaranteed Notes due 2061	BP/61	New York Stock Exchange
4.375% Perpetual Subordinated Non-Call 5.25 Fixed Rate Reset Notes	BP/P1	New York Stock Exchange
4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes	BP/P2	New York Stock Exchange
6.125% Perpetual Subordinated Fixed Rate Reset Notes	BP/P4	New York Stock Exchange
6.450% Perpetual Subordinated Fixed Rate Reset Notes	BP/P3	New York Stock Exchange


« See glossary on page 351		bp Annual Report and Form 20-F 2024		1




		Strategic report

2024 at a glance

As at 31 December 2024

Scale


100,500a		61
employees		countries of operation
(2023 87,800)		(2023 61)


2.4			>39,000
million barrels of oil equivalent – upstream« production			electric vehicle charge points«
million barrels of oil equivalent – upstream« production			(2023 >29,000)
(2023 2.3mmboe/d)


21,200
retail sites«
(2023 21,100)

Performance


$0.4bn	$8.9bn	l
profit for the year attributable to bp shareholders	underlying replacement cost (RC) profit«
(2023 $15.2bn)	(2023 $13.8bn)


95.2%	l	94.3%	l
bp-operated upstream plant reliability«		bp-operated refining availability«
(2023 95.0%)		(2023 96.1%)


2,950			8.2GW
strategic convenience sites«			developed renewables to FID« (net)
(2023 2,850)			developed renewables to FID« (net)
			(2023 6.2GW)


$6.17/boe	l
upstream unit production costs«
(2023 $5.78/boe)

Safety and sustainability


38	l	33.6MtCO2e	l
tier 1 and 2 process safety events«		GHG emissions – operational control
(2023 39)		(2023 32.1MtCO2e)


Key
l	Key performance indicator, page 14

aThis figure reflects new acquisitions and companies we have taken full ownership of including bp bioenergy and Lightsource bp.


Strategic report
2024 at a glance	1
About bp	2
Chair’s letter	4
Chief executive officer’s letter	5
The operating environment	6
Energy outlook	7
Our strategy	8
2024 performance	9
Consistency with the Paris goals	10
Our business model	12
Key performance indicators	14
Our financial frame	18
Our investment process	20
Group performance	24
Gas & low carbon energy	28
Oil production & operations	31
Customers & products	33
Other businesses & corporate	36
Sustainability	38
Climate-related financial disclosures (TCFD)	42
Our approach to sustainability	56
How we manage risk	61
Risk factors	65
Compliance information	68
Non-financial and sustainability information statement	68
Section 172 statement	68

Corporate governance
Introduction from the chair	70
Board of directors	72
Leadership team	74
Governance framework	75
Board activities	76
Our stakeholders	78
Key decisions	79
Safety and sustainability committee	80
Audit committee	82
People, culture and governance committee	86
Remuneration committee	88
Directors’ remuneration report	88
Other disclosures	111


Financial statements
Consolidated financial statements of the bp group	115
Notes on the financial statements	145
Supplementary information on oil and natural gas (unaudited)	223


Additional disclosures	311
Shareholder information	341
Glossary	351
Non-IFRS measure reconciliations	360
Signatures	364
Cross-reference to Form 20-F	365
Information about this report	366
Exhibits	366


« See glossary on page 351		bp Annual Report and Form 20-F 2024		3




		Strategic report

Financial reporting segment performance

At 31 December 2024, 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, integrated gas and power, and gas trading. Our low carbon

business includes solar, offshore and onshore wind, hydrogen and carbon

capture and storage (CCS), and power trading. Power trading includes

trading of both renewable and non-renewable power.


$3.6bn		$6.8bn
replacement cost (RC) profit before interest and taxb		underlying RC profit before interest and tax«
(2023 $14.1bn)		(2023 $8.7bn)



	Segment performance, page 28

Oil production & operationsa

Comprises regions with upstream activities that predominantly produce

crude oil, including bpx energy.


$10.8bn		$11.9bn
RC profit before interest and taxb		underlying RC profit before interest and tax
(2023 $11.2bn)		(2023 $12.8bn)



	Segment performance, page 31

Customers & products

Comprises customer-focused businesses, which include convenience

and retail fuels, EV charging, as well as Castrol, aviation and B2B and

midstream. It also includes our products businesses, refining & oil trading,

as well as our bioenergyc businesses.


$(1.6)bn		$2.5bn
RC loss before interest and taxb		underlying RC profit before interest and tax
(2023 profit $4.2bn)		(2023 $6.4bn)



	Segment performance, page 33

Other businesses & corporate

Comprises technology; bp ventures; our corporate activities and functions;

and any residual costs of the Gulf of America oil spill.


$(1.0)bn		$(0.6)bn
RC loss before interest and taxb		underlying RC loss before interest and tax
(2023 loss $(0.9)bn)		(2023 loss $(0.9)bn)



	Segment performance, page 36

aThe Azerbaijan-Georgia-Türkiye and Middle East 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.

cIn February 2025 bp announced its intention to move its biogas business to the gas & low carbon energy segment.



	The Gigahub EV charging hub at the NEC in Birmingham, UK
		Customers & products, page 33



	bp’s Xazar Centre office in Baku, Azerbaijan
		Other businesses & corporate, page 36


4		bp Annual Report and Form 20-F 2024






Chair’s letter

Dear fellow shareholders,

Chief executive transition

The world bp operates in continues to change at

pace. The past year has seen numerous

elections, complex geopolitics and ongoing

conflict, as well as significant climate events. At

the same time, there has been progress in AI and

technology and some signs of growth and

prosperity in emerging economies. As a result,

energy demand continues to rise with the supply

of oil and gas, and renewable energy, reaching an

all-time high.

For bp, there was leadership change, with a new

CEO and CFO, and 2024 was a year of reshaping

the portfolio and laying the foundation for growth

and sustainable shareholder returns. Under

Murray Auchincloss’s leadership, bp has made

significant moves, continuing to play its part in

supplying the energy the world needs today and

helping build out the energy system of tomorrow.

We strengthened our oil and gas portfolio,

expanded in biogas and bioenergy, and focused

our hydrogen and wind projects – all leading to

the fundamental strategy reset announced at our

Capital Markets Update in February 2025.

Performance

Safety continues to be at the forefront of

everything bp does, and the board and I would

again like to recognize bp’s teams for their work

to reduce the most serious process safety

incidents. This requires constant vigilance,

robust processes and a willingness to speak up

and act.

However, whether it is on the front line or on the

board, bp can never take safety for granted. We

were tragically reminded of this in October 2024 by

the fatality in our bp bioenergy business in Brazil.

Many of bp’s businesses performed well,

including higher upstream« production and

strong plant reliability«, but it was a difficult year

in parts of our customers & products business,

particularly in refining. bp cannot control a tough

price environment but it can address underlying

performance – and the board believes that the

comprehensive update of our strategy that we

announced in February, combined with strong

performance management processes, will help

bp to do this.

Strategy reset

A lot has changed since we launched our

strategy in 2020 – and bp has learned a lot. The

pandemic has altered consumer behaviour,

geopolitical tensions have increased the focus on

security of supply, and although energy demand

has risen to a high point, overall, growth has been

weaker. Globally, inflation and rising interest

rates have had an impact on the economics of

major projects, particularly low carbon

investments.

Because of all these factors, combined with our

engagement with our shareholders and other

important stakeholders, we reworked our

strategy. Murray sets out how on the next page.

This is a new direction for bp. The board has

worked closely with Murray and his leadership

team throughout this reset, which has our full

support. The reset builds on bp’s distinctive

strengths, learns from its challenges and

represents deliberate choices and a conviction

about the way forward. The next steps are clear.

Now is about rigorous performance, and the

board has an important role to play in overseeing

the delivery of the strategy we have set out.

Culture and values

The board believes that the changes bp is

making are positive and necessary for the future

of the company, but we know change itself can

be unsettling. This makes it more crucial than

ever that bp maintains a strong culture and

strong values. bp is rigorous about operational

and safety processes, and must continue to be

rigorous about care for others, our speak-up

culture and psychological safety. As a board, we

provide oversight and constructive challenge,

and in doing so we routinely monitor bp’s culture.

I say more about this in the governance section

on page 70.

Closing thanks

Thank you, particularly to bp’s owners and bp’s

teams, in a year where bp has faced numerous

challenges and worked hard to improve its

performance and focus the organization. We are

grateful to everyone who has given us their time,

expertise, support – and challenged us too. This

is your company and we believe it is now set to

grow – and win – in a changing energy market.

Helge Lund

Chair

6 March 2025


« See glossary on page 351		bp Annual Report and Form 20-F 2024		5




		Strategic report

Chief executive officer’s letter

Dear fellow shareholders,

We’ve been in action throughout the past year

materially reshaping bp’s portfolio and laying the

foundations for February’s Capital Markets

Update. This fundamental reset of our strategy

demonstrates a clear focus on actions to drive

performance improvement and grow cash flow

and returns for bp’s shareholders.

Safety first

In 2024, we made progress on safety, reducing

the number of combined tier 1 and 2 process

safety events« for a second year in a row, with

the most serious tier 1 events down significantly

– but we have more to do. Our goal is to

eliminate fatalities, life-changing injuries and the

most serious process safety incidents. Tragically,

one person died while working in our newly

acquired bp bioenergy business in Brazil in

October 2024. We must continue to embed and

reinforce our Operating Management System«,

Lifesaving Rules and Safety Leadership

Principles across bp (see page 56). Nothing

matters more than safety.

Financial and operating performance

We delivered strong performance in some areas

in 2024 but had some challenges in others. For

example, our upstream« production was 2%

higher than in 2023, and plant reliability« was

strong at over 95%, but there were difficulties in

refining. Margins were lower and the power

outage at Whiting in the first quarter contributed

to a dip to 94.3% in our refining availability«.

This contributed to earnings of $38 billiona

(adjusted EBITDA«) in 2024 and operating cash

flow« of $27.3 billion and resulted in:

•Profit for the year attributable to

shareholders of $0.4 billion.

•Underlying replacement cost profit«

of $8.9 billion.

•Return on average capital employed«

of 14.2%b.

•And net debt« of $23 billionc.

This allowed us to raise the dividend per ordinary

share by 10% and announce $7 billion of share

buybacks for the year.

Reshaping the portfolio

We’ve done more to reshape bp’s portfolio in the

aAdjusted EBITDA for the group is a non-IFRS measure and its nearest IFRS-equivalent measure is profit for the year 2024.

bROACE is a non-IFRS measure and its nearest IFRS measures of numerator and denominator are profit for 2024 attributable to bp

shareholders of $0.4 billion and total equity at the end of 2024 of $78.3 billion respectively.

cNet debt is a non-IFRS measure and its nearest IFRS-equivalent measure is finance debt at the end of 2024.

dTarget first introduced in bp’s first quarter 2024 group results announcement referred to as cash costs savings. Cash costs has the

same meaning as underlying operating expenditure«.

eExcludes deferred consideration for 2024 acquisition of bp bioenergy in 2025.

last 12 months than in any year in the past 20

years. We started up a major project« and

sanctioned 10. We agreed new access in regions

we know well, including in Iraq and India – at

material scale. We formed a new joint venture,

Arcius Energy, to develop gas in the Middle East

with ADNOC’s investment arm XRG. And we

announced plans for JERA Nex bp, joining forces

with one of the world’s major power companies

to create a leader in offshore wind development

– and helping to grow the scale of the business

in a capital-light way for bp. We also now own

100% of bp bioenergy, one of the top-three

sugarcane bioethanol producers in Brazil,

and Lightsource bp, one of the world’s leading

solar developers. And we're investing with

discipline in hydrogen and carbon capture,

sanctioning four projects in 2024.

At the same time, we introduced our target to

deliver at least $2 billion of savingsd by the end of

2026, relative to 2023. We made strong progress

on this, achieving structural cost reduction« of

$0.8 billion since the start of 2024.

Growing shareholder value

Having laid the foundations, we have

fundamentally reset our strategy. This is a new

direction. We’ve drawn on everything we’ve

learned since 2020, while reflecting substantial

changes to the external environment and using

our deep-seated industrial skills and experience.

The key elements are:

•First, a growing upstream. We’re increasing

planned investment by 20% to around $10

billion a year in oil and gas to help build more

higher-returning major projects and increase

exploration.

•Second, a focused downstream. We’re

focusing our portfolio around core integrated

positions and taking action to improve

performance. We expect to invest around

$3 billion by 2027.

•Third, investing with discipline in the

transition. We plan to pursue fewer and

higher-returning opportunities, and access

growth more efficiently. We now expect to

invest between $1.5-2.0 billion per year into

transition businesses« through 2027e – more

than $5 billion lower per year than our

previous guidance.

All while continuing to drive value through our

distinctive strengths in trading, technology and

partnerships. And we are now guided by a more

focused set of sustainability aims, the ones most

relevant to our net zero ambition and the long-

term success of bp (see page 38).

Thank you

There are very few companies of scale that can

adapt at pace with society to meet demand from

countries, companies and customers for more

energy and lower carbon products. bp is one

of them. I’m excited about our new direction and

the significant opportunity we have to grow value

for our shareholders.

I want to thank our brilliant team for their hard

work, commitment and resilience through a

period of extensive change. I also want to thank

you, the owners of our business, for continuing to

put your trust in our company.

Murray Auchincloss

Chief executive officer

6 March 2025

Nearest IFRS-equivalent measures

$1.2bn

profit for 2024a

0.5%

profit for 2024 attributable to bp

shareholders divided by total equity

at 31 December 2024b

$59.5bn

finance debt at the end of 2024c


6		bp Annual Report and Form 20-F 2024






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%a in 2024.

Growth rates varied widely across economies,

with US GDP estimated to have grown by 2.8%a,

much stronger than had been expected at the

start of the yearb. By contrast, the eurozone

economy expanded by only 0.8%a. China’s growth

is estimated to have been close to the

government’s ‘around 5%’ targeta.

Inflation continued to moderate around the world

in 2024, moving towards central banks’ target

rates in most major economies. Cooling inflation

allowed several central banks, including the US

Federal Reserve, the European Central Bank and

the Bank of England, to cut interest rates.

Financial market prices suggest further interest

rate reductions are expected during 2025.

Oil

Oil prices were elevated across much of 2024,

supported by oil demand growth and OPEC

production cuts. Dated Brent averaged $81/bblc in

2024, broadly unchanged from $83/bblc in 2023.

A slowdown in Chinese oil demand growth to a

quarter of its pre-COVID trend lowered global

annual oil demand growth to 0.94mmb/d, causing

total oil demand in 2024 to be 102.9mmb/dd.

The slowdown in demand growth and

outperformance of non-OPEC+ supply led to

production cuts from OPEC+ in 2024. OPEC+

output averaged 49.8mmb/d in 2024 – around

900kb/dd lower than 2023. Saudi Arabia cut its

output to just 9.0mmb/d in 2024, over 1mmb/d

lower than its levels in the first half of 2023d.

These reductions were more than offset by

strong growth in non-OPEC+ supplies which

increased by 1.5mmb/d in 2024d, with the US

accounting for almost half of that increased.

Natural gas

A relatively warm European winter in 2023-24 and

muted European gas demand caused European

and Asian natural gas prices to fall in early 2024.

Prices troughed in February but had increased by

70%e by the end of December following strong

Asian LNG demand growth and weak LNG

supply growth.

Industry, power generation and transportation

were the main sectoral drivers of that Asian LNG

demand growth. European gas demand

continued to decline due to lower power demand.

Outages and project delays meant global LNG

supply grew at a slow pace of 2.5% in 2024f.

In the US, Henry Hub (HH) gas prices averaged

$2.2/mmBtug, the lowest price level, in real terms,

in the last 25 years. A warm US winter (2023-24)

resulted in natural gas stocks 40%h above the five-

year average by the end of March. Consequently,

HH declined to levels needed to incentivize power

sector coal-to-gas switching and lower natural

gas production. Increases in power demand for

air conditioning and data centres aided this

rebalancing. The number of US gas rigs in key

shale basins declined by 47% from its peak in

2022i.

Refining marker margin

We use a global refining marker margin (RMM)«

to track the refining margin environment. Global

RMM in 2024 continued the downward trajectory

from 2023. An increase in refining capacity and a

slowdown in demand growth for refined products

meant RMM values averaged significantly lower in

2024 at $17.7/bbl ($8.1/bbl lower than in 2023) j.

Power and renewables

Electricity demand growth continues to outpace

total energy demand growth, driven by increasing

electrification in developed economies 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.

Total solar and wind capacity additions in 2024

are estimated to have exceeded 600GW, breaking

the record set in 2023k. This surge was

associated with significant overcapacity in solar

manufacturing in China.

Bioenergy growth also maintained momentum,

with resilient demand for liquid biofuels in road

transport, increasing biomethane production, and

increasing announced capacity of sustainable

aviation fuel projects.

Hydrogen and carbon capture

and storage

Persistent high costs, the slow pace of enabling

policy and insufficient demand continue to

challenge the decarbonization of costlier-to-abate

processes with low carbon hydrogen. The project

pipeline for production of low carbon hydrogen

operational by 2030 remains significant, but only

around 4Mtpal is either currently operational or

under construction. Green hydrogen« costs are

expected to be higher than those for blue

hydrogen« in many countries through this

decade and beyond.

Carbon capture and storage (CCS) is increasingly

being recognized as critical to the energy

transition, and the global pipeline of CCS projects

continued to grow in 2024. Operational and

under-construction projects are expected to

double to 100Mtpam over the next few years.

While this represents progress, the current project

pipeline, taking into account relatively low

historical success rates, appears insufficient to

meet the CCS deployment rates in Paris-

consistent transition scenariosn.


Market activity	2024	2023	a IMF World Economic Outlook, October 2024, measured on a Purchasing Power Parity basis. b IMF World Economic Outlook Update, January 2024. c Refinitiv Data Service (Dated Brent spot price). d IEA Oil Market Report, January 2025. e Platts Dutch TTF Day Ahead price. f IEA Gas Market Report, Q1 2025. g Platts Henry Hub cash price. h Weekly Natural Gas Storage Report, EIA. i EIA Short Term Energy Outlook, Appalachia and Haynesville regions. j The RMM may not be representative of the margin achieved by bp in any period because of bp’s particular refinery configurations and crude and product slates. In addition, the RMM does not include estimates of energy or other variable costs. k bp Energy Outlook 2024; IRENA Stats; Wood Mackenzie Global Solar Forecasts. PV capacity additions are converted from DC to AC basis by dividing by ~1.2. l WoodMac Lens; Hydrogen Project Pipeline data, October 2024. m WoodMac Lens; CCUS Project Pipeline data, October 2024. n Projects include capture projects either on a standalone basis or as part of a hub (sharing transport and storage facilities). o Refinitiv Data Service (West Texas Intermediate). p Platts JKM spot price. q This number is restated from the bp Annual Report and Form 20-F 2023 to reflect revisions made in the IEA Oil Market Report, January 2025. r This number is restated from the bp Annual Report and Form 20-F 2023 to reflect revisions made in the IEA Gas Market Report, Q1 2025.
Global oil consumptiond	102.9mmb/d	102.0mmb/dq
Global oil productiond	102.9mmb/d	102.3mmb/dq
Natural gas consumptionf	4,212bcm	4,097bcmr
Natural gas productionf	4,190bcm	4,134bcmr
Dated Brent averagec	$80.76/bbl	$82.64/bbl
West Texas Intermediate (WTI)« averageo	$75.87/bbl	$77.67/bbl
Henry Hub averageg	$2.19/mmBtu	$2.53/mmBtu
Dutch Title Transfer Facility (TTF)« averagee	34.4 euros per MWh ($10.9/ mmBtu)	40.5 euros per MWh ($12.8/ mmBtu)
Japan-Korea (Asian) LNG averagep	$11.9/mmBtu	$13.8/mmBtu
Refining marker marginj	$17.7/bbl	$25.8/bbl


« See glossary on page 351		bp Annual Report and Form 20-F 2024		7




		Strategic report

Energy outlook

The bp Energy Outlook 2024 (2024 Outlook)

explores the trends and uncertainties

surrounding the energy transition out to 2050.

The bp Energy Outlook helps inform bp’s core

beliefs about 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 inform our strategic

thinking.

We published the 2024 Outlook in July 2024,

designed around two scenarios informed by

recent trends and developments in the global

energy system. The 2024 Outlook provides key

insights about how the energy system may

evolve over the next 25 years.

The two scenarios – Current Trajectory and Net

Zero (see ‘Two scenarios to explore the energy

transition’, below) – explore the speed and shape

of the energy transition out to 2050 and help to

shape a resilient strategy for bp.



	Read the bp Energy Outlook 2024 bp.com/energyoutlook



	Two scenarios to explore the energy transition
	Carbon emissions Gt of CO2ea
	Current Trajectory		Net Zero
	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 also 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 2022 levels.		explores how different elements of the energy system might change to achieve a substantial reduction in carbon emissions. In that sense, Net Zero can be viewed as a ‘what if’ scenario: what elements of the energy system might change, and how, if the world collectively acts for CO2e emissions to fall by around 95% by 2050.
			History

	a Carbon emissions include CO2 emissions from energy use, industrial processes, natural gas flaring and methane emissions from energy production.

A new theme discussed throughout the 2024

Outlook centres on the challenge of moving from

the current ‘energy addition’ phase of the energy

transition to an ‘energy substitution’ phase. In

this second phase, low carbon energy increases

sufficiently quickly to more than match increases

in global energy demand, allowing the

consumption of fossil fuels, and their associated

emissions, to decline.

Scenarios for strategic

decision making

We use scenarios to inform strategy, manage

risk, and improve decision making.

Some of the 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 used both approaches.

How scenarios inform our strategy

The use of scenarios described in the 2024

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 for 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

UN Principles for Responsible Investment (UN

PRI) and the International Energy Agency (IEA).

Read more on our resilience analysis and the

outcome of that work on page 50.

How we create scenarios

We quantify a range of scenarios in the 2024

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.

The modelling framework uses historical data

based on the Energy Institute’s Statistical Review

of World Energy, the IEA’s World Energy Balances

data and a range of other data sets.

Each scenario is determined by a set of key

assumptions, including population and economic

growth, pace of technological change, resource

constraints and government policies. These are

informed by expert analysis from external

organizations including the United Nations,

Oxford Economics and Rystad Energy. We

benchmark our scenarios against external

organizations including the IEA, the IPCC, and

S&P Global.

The modelling techniques used vary by sector

and include a combination of econometric

modelling, adoption curves and consumer

choice modelling.


8		bp Annual Report and Form 20-F 2024






Our strategy

Resetting strategy




	Growing upstream	Focusing downstream


Disciplined investment in transition

Growing the upstream: our oil and gas business

We plan to increase investment to grow production while also growing cash

flow, in addition to disciplined expansion of biogas. Maintaining strong and

safe operations throughout.

Focusing the downstream: our customers and

products business

We are reshaping the portfolio to focus on markets and businesses where

we have advantaged and integrated positions. We have clear actions to

drive improved performance, including addressing costs in our customers

business, and improving operations in refining.

Investing with discipline in transition

We plan to invest 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. We

now expect capital investment into transition businesses« to be between

$1.5-2.0 billion per year through 2027a – more than $5 billion lower per year

than our previous guidance.

All while continuing to drive value through our distinctive strengths in trading, technology and partnerships.

Our primary targets

We have set out four primary targets that we will use to measure our progress and how we are improving

performance. These targets, alongside the guidance and financial frame (see page 18), support our reset.

Taken together, we believe our primary targets will underpin growth in the value of bp.



	Adjusted free cash flow« growth				Net debt«
	>20%b				$14-18bnc

	adjusted free cash flow compound annual growth rate (CAGR)« from 2024-27				by end 2027


	Structural cost reduction«				Return on average capital employed (ROACE)«
	$4-5bn				>16%b

	by end 2027				in 2027

aExcludes deferred consideration for 2024 acquisition of bp bioenergy in 2025.

bAt $70/bbl Brent, $4/mmBtu Henry Hub, and $17/bbl refining marker margin, all 2024 real.

cPotential 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.


10		bp Annual Report and Form 20-F 2024






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 Baku Climate Pact at COP29 in Baku in

November 2024.

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 2024 to inform our beliefs about

the energy transition and 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.

aOur 2024 analysis used data from the WBCSD Climate Scenario Catalogue version 3.0, published on 16-05-2024 and downloaded on 13-11-2024.

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 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.

The bp Energy Outlook 2024 examined recent

developments and emerging trends in the global

energy system, exploring the key uncertainties

surrounding the energy transition. It included two

main scenarios – one of which, Net Zero, we

regard as Paris-consistent.



	Energy outlook page 7 and bp.com/energyoutlook

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 50, 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, to different

climate-related scenarios. This includes some

scenarios that are classified by the World

Business Council for Sustainable Development

(WBCSD) to be consistent with well-below 2°C

and 1.5°C outcomesa.

As further explained on page 51, 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 WBCSD scenarios 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 version of the WBCSD catalogue used for

the analysis, the lowest oil price is associated

with a 1.5°C scenario; however a number of the

1.5°C and well-below 2°C scenarios have oil

prices in 2030 that are substantially higher than

these – 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 WBCSD catalogue.

This in turn supports our view that our strategy is

resilient to such a Paris-consistent world.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		11




		Strategic report

Contributes to net zero

We believe that our strategy enables bp to make

a positive contribution to the world achieving net

zero greenhouse gas (GHG) emissions and

meeting the Paris goals – outcomes which we

believe to be in the best interests of bp as well as

beneficial to society generally.

We see huge opportunity in the energy transition

– the transformation of the energy system that

we believe to be a necessary feature of the

world’s efforts to meet the Paris goals. There are

many ways a company at the heart of the energy

sector can make a meaningful contribution to the

world getting to net zero. In addition to investing

in our transition businesses«, these include:

supporting collective action through participation

in external initiatives and seeking to use the

company’s influence with trade associations that

conduct climate-related advocacy; low carbon

collaboration and support for others in their own

decarbonization efforts (such as cities and

corporates).

For example, we continue to advocate for

policies that support net zero. Helping

policymakers to design and put in place low

carbon policies that support the transition to net

zero can help deliver our strategy and capitalize

on the opportunities associated with 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 also advance

the decarbonization of a whole economy –

something potentially of far greater impact than

anything a single company can achieve through

its own portfolio. We publish examples of our

activity online at bp.com/advocacyactivities.

Some ways of contributing to helping the world

get to net zero are more readily measured by

quantitative metrics than others – but all can be

important, whether or not they translate into GHG

reductions for bp. For example, 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.

Where Lightsource bp helps bp meet its own

demand for cost competitive, low carbon power,

including for power trading, EV charging, biofuels

and green hydrogen« this would show up in GHG

metrics. However, where we do not directly sell

that power, our development of the renewables is

effectively ‘invisible’ in terms of our GHG metrics.

In December 2024, in Teesside, UK, bp and

partners reached financial close on the Net Zero

Teesside Power (NZT Power) and Northern

Endurance Partnership (NEP) projects. The NEP

aims to develop the infrastructure to transport

and store up to an initial 4MtCO2 annually from

three Teesside-based carbon capture projects

within the East Coast Cluster, with the ability to

expand in the future.


Responding to increased 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 sixth 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 352. Key terms related to this resolution response are indicated with « and defined in the glossary on page 352. These should be reviewed with the following information:
Element of the CA100+ resolution	Related content	Where
Strategy that the board considers in good faith to be consistent with the Paris goals.	Our strategy and business model	8 & 12
	Pursuing a strategy that is consistent with the Paris goals	10
How bp evaluates each new material capex investment« for consistency with the Paris goals and other outcomes relevant to bp strategy.	Our investment process	20
Disclosure of bp’s principal metrics and relevant targets or goals over the short, medium and long term, consistent with the Paris goals.	Key performance indicators	14
	Sustainability: net zero aims and targets	38
	See ‘TCFD Metrics & Targets’ for an overview	55
Anticipated levels of investment in: (i) Oil and gas resources and reserves. (ii) Other energy sources and technologies.	Our strategy	8
	Financial frame: disciplined investment allocation	18
	Investment in non-oil and gas	21
	Transition investment	39
bp’s targets to promote operational GHG reductions.	Sustainability: net zero« aims	38
Estimated carbon intensity of bp’s energy products and progress over time.	Sustainability: net zero sales aim«	39
Any linkage between above targets and executive pay remuneration.	Directors’ remuneration report	88
	2024 annual bonus outcome	96
	2025 remuneration policy	102

Where the CO2 being taken offshore for

permanent storage is from local heavy industries

this will not show up in bp’s GHG metrics.

So while Lightsource bp, NZT Power and NEP

projects support the Paris goals by increasing

the low carbon options available to energy

consumers, not all of their activities will be

reflected in the metrics associated with bp’s net

zero aims.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		13




		Strategic report

Our business groups

This is how we are organized to deliver our strategy and deliver long-term shareholder value. Our three business groups are enabled by supply, trading &

shipping and supported by five functions: finance; technology; strategy, sustainability & ventures; people, culture & communications; and legal.


Gas & low carbon energy		Production & operations		Customers & products
Integrating our existing natural gas capabilities with power trading and growth in low carbon businesses and markets, including wind, solar, hydrogen and carbon capture and storage.		The operational heart of bp, producing the hydrocarbon energy and products the world wants and needs – safely and efficiently.		Focusing on customers as the driving force for innovating new business models and service platforms to deliver the convenience, mobility and energy products and services of today and the future.

	page 28		page 31		page 33

Delivering value for stakeholdersa

We are committed to delivering long-term value for stakeholders.


Investors and shareholders
Includes our institutional and retail investors.


$5.0bn
total dividends distributed to bp shareholders (2023 $4.8bn)


Customers
Including end-use consumers, B2B customers, and distributors.


2,950
strategic convenience sites« (2023 2,850)

cThis figure reflects new acquisitions and companies we have taken full ownership of including bp bioenergy and Lightsource bp.


Employees
Our 100,500c people worldwide.


70%
employee engagement score from the Pulse annual employee survey (2023 73%)

	page 58


Governments and regulators
In the countries where we have existing or planned activities.


$10.6bn
corporate income tax and production tax paid (2023 $11.9bn)

	bp.com/tax


Society
The people, businesses and environment in the communities where we work.


$76m
supporting additional initiatives to benefit communities (2023 $117m)


Partners and suppliers
Includes relationships with academia, industry and cities.


$146.6bn
in payments to suppliers for goods and services (2023 $151.7bn)

	bp.com/sustainability


14		bp Annual Report and Form 20-F 2024

Key performance indicators

We assess the performance of

the group across a wide range of

measures and indicators that

are consistent with our strategy.

Our key performance indicators (KPIs) provide a

balanced set of metrics that give emphasis to

both financial and non-financial measures.

These help the board and leadership team

assess bp’s performance. Our leadership team

uses these measures to evaluate operating

performance and inform its financial,

strategic and operating decisions.

Safety


		l
Tier 1 and 2 process safety events«ab		l

2024	38
2023	39
2022	50
2021	62
2020	70


	Tier 1 process safety events		Tier 2 process safety events
	Tier 1 process safety events		Tier 2 process 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).

2024 performance

Our combined process safety events (PSEs) have

generally decreased over the last 12 years, apart

from in 2019. In 2024 we reported our lowest

number of tier 1 PSEs – three, down from nine in

2023. However, our tier 2 PSEs increased to 35

(2023 30). Our total reported PSEs for 2024

were 38 (2023 39), see page 56.

Sustainable operations



Refining availability (%)

2024		94.3
2023		96.1
2022		94.5
2021		94.8
2020		96.0

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.

2024 performance

bp-operated refining availability decreased to

94.3% in 2024, mainly due to the impact of a

power outage at our Whiting refinery.


Remuneration	l

To help align the focus of our executive

management and executive directors with the

interests of our shareholders, certain measures

are used for executive remuneration.



	Directors’ remuneration report, page 88


Key
l	Used for remuneration policy
TCFD	TCFD Recommendations and Recommended Disclosures



Reported recordable injury frequency«ab

2024		0.297
2023		0.274
2022		0.187
2021		0.164
2020		0.132

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.

2024 performance

In 2024, our RIF increased by 8.5%. Our

aExclusions to safety metrics – tier 1 and 2 process safety events may exist and recordable injury frequency may exist where 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 and data are not included in the

reported metrics unless specifically noted. For the full year 2024 reporting period this includes Archaea Energy, TravelCenters of

America, bp bioenergy and Lightsource bp.

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.

businesses have identified underlying themes for

these injuries and have developed plans intended

to help reduce them in future. For more on

safety, see page 56.



Upstream« plant reliability (%)

2024		95.2
2023		95.0
2022		96.0
2021		94.0
2020		94.0

bp-operated upstream plant reliability is

calculated taking 100% less the ratio of total

unplanned plant deferrals divided by installed

production capacity, excluding non-operated

assets and bpx energy. Unplanned plant deferrals

are associated with the topside plant and, where

applicable, the subsea equipment (excluding

wells and reservoirs). Unplanned plant deferrals

include breakdowns, which does not include Gulf

of America weather-related downtime.

2024 performance

Upstream plant reliability in 2024 was marginally

higher than in 2023.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		15




		Strategic report



Major project delivery

2024		1
2023		4
2022		2
2021		7
2020		4

We monitor the progress of our major projects to

gauge whether we are delivering our core

pipeline of projects under construction on time.

Projects take many years to complete, requiring

differing amounts of resource, so a smooth or

increasing trend should not be anticipated.

Major projects are defined as those with a bp net

investment of at least $250 million, or considered

to be of strategic importance to bp, or of a high

degree of complexity.

2024 performance

We started up one major oil and gas project

in 2024 – the Azeri Central East project in

Azerbaijan. Furthermore, on 31 December

first gas flowed to the FPSO at the Greater

Tortue Ahmeyim project in Mauritania

and Senegal.

Financial



Underlying replacement cost (RC) profit ($ billion)

2024		0.4 8.9
2023		15.2 13.8
2022		(2.5) 27.7
2021		7.6 12.8
2020		(20.3) (5.7)


	Profit (loss) for the year attributable to bp shareholders		Underlying RC profit for the year (non-IFRS)
	Profit (loss) for the year attributable to bp shareholders		Underlying RC profit for the year (non-IFRS)

Underlying RC profit« (non-IFRS) is a useful

measure for investors because it is one of the

profitability measures bp management uses to

assess performance. It assists management in

understanding the underlying trends in operational

performance on a comparable year-on-year basis. It

reflects the replacement cost of inventories sold in

the period and is arrived at by adjusting for inventory

holding gains and losses«, net impact of adjusting

items« and related taxation from profit or loss

attributable to bp shareholders.

2024 performance

Profit for 2024 attributable to bp shareholders

includes pre-tax net impairment charges of

$5.1 billion. Reduction in the underlying RC profit

reflects lower refining margins, lower

realizations«, a lower gas marketing and trading

result and a lower oil trading contribution, partly

offset by lower taxation.



Operating cash flow ($ billion)

2024		27.3
2023		32.0
2022		40.9
2021		23.6
2020		12.2

Operating cash flow is net cash flow provided by

operating activities, as reported in the group cash

flow statement.

2024 performance

2024 primarily reflects lower profits from

operations, partly offset by working capital

movements.



Upstream unit production costs ($/boe)

2024		6.17
2023		5.78
2022		6.07
2021		6.82
2020		6.39

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.

2024 performance

Unit production costs increased, mainly

reflecting the impact of portfolio changes.


		l
Total shareholder return (%)		l

2024	(11.9) (11.0)
2023	5.9 2.6
2022	36.9 50.1
2021	36.4 36.4
2020	(41.4) (41.7)


	ADS basis		Ordinary share basis
	ADS basis		Ordinary share basis

Total shareholder return (TSR) represents the

change in value of a bp shareholding over a

calendar year (American Depositary Share (ADS)

in USD, ordinary share in GBP). It assumes that

dividends are reinvested to purchase additional

shares at the closing price on the ex-dividend

date.

2024 performance

Reduced TSR reflects a reduction in the

share price.


		l
Return on average capital employed (ROACE) (%)		l

2024	0.5 14.2
2023	17.8 18.1
2022	(3.0) 30.5
2021	8.4 13.3
2020	(23.7) (3.8)


	Profit (loss) for the period attributable to bp shareholders divided by total equity		ROACE (non-IFRS)
			ROACE (non-IFRS)

ROACE« (non-IFRS) gives an indication of a

company’s capital efficiency, dividing the

underlying RC profit (loss) after adding back

non-controlling interest and interest expense net

of tax 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.

2024 performance

Profit for 2024 attributable to bp shareholders

was $0.4 billion and total equity at 31 December

2024 was $78.3 billion. ROACE for 2024 reflected

lower refining margins, lower realizations, a

lower gas marketing and trading result and a

lower oil trading contribution, partly offset by

lower taxation.


16		bp Annual Report and Form 20-F 2024

Key performance indicators

continued


Key
l	Used for remuneration policy
TCFD	TCFD Recommendations and Recommended Disclosures

Non-financial


		TCFDl
Greenhouse gas emissionsabcde – operational control (MtCO2e)		TCFD l

2024		33.6
2023		32.1
2022		31.8
2021		35.6
2020		45.5


	Scope 1 (direct) emissions		Scope 2 (indirect) emissions
	Scope 1 (direct) emissions		Scope 2 (indirect) 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.

2024 performance

In 2024 our Scope 1 (direct) emissions were

32.8MtCO2e – an overall increase from

31.1MtCO2e in 2023. Of these Scope 1

emissions, 31.4MtCO2e were carbon dioxide and

1.5MtCO2e were methanec. Overall emissions

increased due to project start-ups, operational

growth in our low carbon businesses, temporary

operational changes and operational issues in

Tangguh, partially offset by the delivery of

emissions reduction projects. In 2024 our Scope

2d (indirect) emissions, covered by bp’s net zero

operations« aim, decreased by 0.2MtCO2e, to

0.8MtCO2e, compared with 2023. The continued

use of lower carbon power agreements and a

project at our Gelsenkirchen refinery to replace

imported steam contributed to this decrease, see

page 38.

Basis of calculatione

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 is required to be submitted into the bp

group reporting tool, OneCSR, in accordance

with bp’s Operating Management System

(OMS)« requirements, broadly based on 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 intensityaf (%)		TCFD

2024	0.07
2023	0.05
2022	0.05
2021	0.07
2020	0.12

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.

2024 performance

Our methane intensity was 0.07% in 2024f.

Methane emissions from upstream operations

used to calculate this methane intensity

increased by around 48% from 31kt in 2023 to

46kt in 2024, see page 39.

Basis of calculatione

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 is required to be

submitted into the bp group reporting tool,

OneCSR, in accordance with OMS requirements,

broadly based on 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).


« See glossary on page 351		bp Annual Report and Form 20-F 2024		17




		Strategic report



Diversity and inclusiong (%)

2024		35 35
2023		34 33
2022		33 33
2021		32 31
2020		29 30


	Women in group leadership		People from beyond the UK and US in group leadership
	Women in group leadership		People from beyond the UK and US in group leadership

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

and individuals from countries other than the UK

and the US among bp’s group leaders.

2024 performance

The percentage of women in group leadership

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.

bTotal (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.

cDue to rounding some totals may not equal the sum of their component parts. This does not affect the underlying values.

dScope 2 emissions on a market basis.

e Included as part of reporting under the Companies (Strategic Report) Climate-related Financial Disclosure Regulations 2022 (the UK CFD Regulations).

fIn 2024 reported absolute methane emissions from upstream major 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.

gRelates to bp employees.

increased in 2024, continuing an upward trend

over the previous five years. The percentage of

people from beyond the UK and US in group

leadership also increased by 2 points.



Employee engagement (%)

2024		70
2023		73
2022		70
2021		64
2020		64

We conduct a Pulse annual employee survey to

understand and monitor levels of employee

engagement and identify areas for improvement.

2024 performance

The 2024 Pulse annual survey, which ran in

August and September, saw our engagement

score decrease by 3 points to 70%, in line with

2022 levels, and a completion rate of 82%. We

also extended the survey to retail where we

achieved an engagement score of 68% and

completion rate of 77%. We continue to build

engagement plans based on survey feedback

and on real-time updates from our monthly

snapshot, Pulse live.



	Employee engagement, page 58


18		bp Annual Report and Form 20-F 2024






Our financial frame

Operating within a resilient and disciplined financial frame

Our financial frame sets out how we allocate cash that we generate to strengthen our balance sheet,

invest with discipline to grow the value of bp and deliver resilient shareholder distributions.

Our financial frame

Balance sheet

Shareholder distributions

Capital expenditure

Resilient dividend

Share buybacks

$14-18bn

Net debt« target

by end 2027a

Expect annual increase of the

dividend per ordinary share of

at least 4%b

Excess cash shared

through buybacks

over time

~$15bn

in 2025

$13-15bn

in 2026-27

‘A’ range credit metrics

through cycle

30-40%

of operating cash flow« distributed as

dividends and share buybacksbc

Disciplined investment

allocation, assessed against

a set of balanced criteria

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.

b Subject to board discretion each quarter, taking into account factors including outlook for cash flow, share count reduction from buybacks and maintaining ‘A’ range credit metrics.

c Includes offsetting any dilution from employee share schemes over time.

Resilient dividend

We continue to maintain a resilient dividend

policy within our disciplined financial frame.

Since the fourth quarter of 2023 our dividend per

ordinary share has grown by 10% to 8.00 cents.

Based on our current forecasts and subject to

the board’s discretion each quarter, we expect

increases in the dividend per ordinary share of

at least 4% per annum.

Stronger balance sheet

We are committed to strengthening the balance

sheet and are now targeting net debt of between

$14-18 billion by the end of 2027. Any potential

proceeds from the strategic review of Castrol

and Lightsource bp transactions will be

dedicated to strengthening the balance sheet.

For the full-year 2024, finance debt increased

from $52.0 billion at the end of 2023 to

$59.5 billion, primarily reflecting net long-term

debt issuances, and net debt increased from

$20.9 billion to $23.0 billion.

Disciplined investment allocation

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 2024 capital expenditure« was $16.2 billion.

We expect capital expenditure to be around

$15 billion in 2025 and our capital expenditure

frame for 2026 and 2027 is reduced to $13-15

billion per annum. This includes expenditure on

inorganic opportunities. Within the capital frame,

on average ~$10 billion per year will be allocated

to oil and gas, of which ~70% is expected to be

allocated to oil and 30% to gas. In customers and

products, we are progressively focusing capital

expenditure from ~$4 billion in 2024 to ~$3

billion by 2027. In low carbon energy, we expect

capital expenditure, on average, will be less than

$800 million per year through 2027, around half

of which is allocated to hydrogen and CCS

projects already through FID.

Share buybacks

Share buybacks remain a core part of our

investor proposition. Our intention remains

to share excess cash with investors through

buybacks. Subject to board discretion, we

expect total distributions, including dividend

and buyback, to be in the range of 30-40% of

operating cash flow over time, including

buybacks to offset dilution from employee

share schemes.

We announced share buybacks of $7 billion for

2024 and between the end of the first quarter

2021 and 31 December 2024, we have reduced

our shares in issue by 22%.

In setting the dividend per ordinary share and

buyback each quarter, the board will continue

to take into account factors including the

cumulative level of and outlook for cash flow,

share count reduction from buybacks and

maintaining 'A’ range credit rating metrics.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		19




		Strategic report

Our investor proposition

Our strategy is being fundamentally reset. We are reallocating capital to drive growth from our highest returning businesses. And we are focused on driving

improved performance. This is all in service of growing long-term shareholder value. It’s underpinned by a plan to deliver compelling adjusted free cash

flow« and strong returns growth, supporting resilient distributions and a stronger balance sheet. We believe bp has a compelling investor proposition.



Resetting strategy •Growing upstream •Disciplined transition investment	Reallocating capital •Reallocating and reducing capital expenditure« •Significant divestment programme	Driving performance •Improving downstream •Cost efficiency



	Compelling adjusted free cash flow growth				Strong returns growth
	>20%				>16%

	Compound annual growth rate (CAGR)« from 2024-27a				ROACE« in 2027a



Resilient distributions	Stronger balance sheet	Lower operational emissions
30-40%	$14-18bn	45-50%

Total distribution of operating cash flowbc	Net debt target by end 2027d	Reduction aim across Scope 1 and 2 by 2030e



	More information Our strategy and primary targets, page 8 Sustainability, page 38

2025 guidance


	2024 actual	2025 guidance
Upstream reported production (guidance is both reported and underlying production«)	2.4mmboe/d	Reported production to be lower/underlying production to be slightly lower than 2024
Total capital expenditure«	$16.2bn	Around $15bn
Depreciation, depletion and amortization	$16.6bn	Broadly flat compared with 2024
Divestments and other proceedsf	$4.2bn	Around $3bn, weighted towards the second half
Gulf of America oil spill paymentsg (pre-tax)	$1.2bn	Around $1.2bn including $1.1bn pre-tax to be paid during the second quarter
Other businesses & corporate underlying annual charge	$0.6bn	Around $1.0bn
Underlying effective tax rate«	41%h	Around 40%i

aAt $70/bbl Brent, $4/mmBtu Henry Hub, and $17/bbl refining marker margin, all 2024 real.

bSubject to board discretion each quarter taking into account factors including outlook for cash flow, share count reduction from buybacks and maintaining ‘A’ range credit metrics.

cIncludes offsetting any dilution from employee share schemes over time.

dPotential 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.

eReduction in emissions against 2019 baseline, on a CO2e basis.

fDivestment proceeds« are disposal proceeds as per the group cash flow statement. See page 26 for more information on divestment and other proceeds.

gSee Financial statements – Note 22 for more information on payables related to the Gulf of America oil spill.

hNearest equivalent GAAP IFRS measure: effective tax rate 82%.

iUnderlying 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.


20		bp Annual Report and Form 20-F 2024






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 the 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 January 2024 until January 2025, we held

our key investment appraisal price assumptions

constant at the levels set out in the bp Annual

Report and Form 20-F 2023. For relevant

investment cases assessed from February 2025,

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 $64/bbl and $4.0/mmBtu

respectively (2023 $ real) from 2025 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 $50/tCO2e

in 2025 to $135/tCO2e in 2030 and $200/tCO2e

by 2050 (2023 $ real) in certain cases (see

box, right).

Impairment testing

Our best estimate of future prices for use in




	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.

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 2024 at the levels disclosed in the bp

Annual Report and Form 20-F 2023 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
2023 $ real	up to 2030	2040	2050
Brent oil ($/bbl)	70	63	50
Henry Hub gas ($/mmBtu)	4.0	4.0	4.0
Refining marker margin (RMM)b« ($/bbl)	14	12	9
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
2023 $ real	2030	2040	2050
Carbon ($/tCO2e)	135	175	200
a The values in the table represent the central case. b The disclosed RMM assumption in the table excludes carbon pricing impacts and assumes 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 on projects. For

the treatment of emission cost assumptions in

value-in-use impairment testing, see Financial

statements – Note 1.


Key
TCFD	Information that supports TCFD Recommendations and Recommended Disclosures in relation to Metrics and Targets


« See glossary on page 351		bp Annual Report and Form 20-F 2024		21




		Strategic report

Investment governance and

evaluating consistency with the

Paris goals

Governance framework

bp’s framework for investment governance seeks

to ensure that investments align with our

strategy, can be accommodated within our

prevailing financial frame, and add shareholder

value. It enables investments to be assessed in a

consistent way against a range of criteria

relevant to our strategy, including environmental

and other 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 is used (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.

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 2024 (see page 23).

bp’s evaluation of an investment’s consistency

a In February 2025 bp announced that we have retired the concept of transition growth« engines going forward.

with ‘a range of other relevant outcomes’ is

achieved by considering its merits against bp’s

balanced investment criteria, described on

page 22.



	bp board Reviews and approves investment cases of more than $3 billion for resilient hydrocarbons, more than $1 billion for all transition or low carbon investments« and any significant inorganic acquisition that is exceptional or unique in nature.



	Resource commitment meeting Forum for executive management’s review and approval of investments related to existing and new lines of business above $250 million, or $25 million for acquisitions, or which exceed the relevant EVP’s financial authority, and any project considered strategically important such as a new market entry.



	Investment allocation committees EVP-level forums to review and approve investment cases within a business group as per individual EVP financial authority (up to $250 million, or typically $25 million for acquisitions).



	Business group investment governance meetings SVP-level forums that review and approve investment cases within a business group or function, up to the individual SVP’s financial authority.



	Cross-group meetings Forums that facilitate discussions across businesses and functions, to support project development, sensitivity analysis, integration opportunities and risk assessment ahead of investment committee meetings.

Investment in non-oil and gas

In 2024 transition growth investment«a was

$3.7 billion, compared to $3.8 billion in 2023

(see page 39).

Bioenergy: Our biogas operation, Archaea

Energy, continued its growth and using its

modular plant design it started up nine new

renewable natural gas (RNG)« plants in 2024

(see page 33).

EV charging: Together with our strategic

convenience site« networks, our investment in

EV charging is helping us to offer lower carbon

mobility solutions to more customers. In 2024

examples include the opening of our standalone

Aral EV charging Gigahub, in Germany, with 28

charge points. And in China, bp pulse installed

2MWh batteries at a charging hub in Shenzhen.

We continue to build scale in our EV charging

network in key markets (see page 33).

Convenience: In 2024 we continued strategic

investment in support of high-grading our

retail fuels and convenience portfolio, including

continued investment in TravelCenters of

America, which bp acquired in 2023 (see

page 33).

Hydrogen and CCS: We are high-grading and

focusing our hydrogen portfolio – prioritizing

projects in jurisdictions where we have an

adequate regulatory framework, access to

the value chain – including our own or customer

demand – linkage to carbon capture and

access to competitive renewable power.

In 2024 we made final investment decisions

on four hydrogen/CCS projects (see page 29).

For example we were granted funding to help

support the development of a 100MW green

hydrogen« project next to our Lingen refinery

in Germany. The plant could produce up to

11,000 tonnes of green hydrogen annually.

The final investment decision was taken in

December 2024.

Renewables & power: In April 2024 we

announced that we took ownership of Equinor’s

50% stake in the Beacon Wind US offshore wind

projects. In December we announced that bp

and JERA Co., Inc will, subject to regulatory

approvals and closing conditions being met, join

forces to create a global wind joint

venture« (see page 28).

Low carbon activity investment

In 2024 low carbon activity investment«,

a subset of our total transition growth

investment, accounted for 80% of our total

transition growth investment (67% in 2023).

It increased from $2.5 billion in 2023 to

$3.0 billion in 2024, reflecting higher investment

in bioenergy, EV charging and wind businesses.


22		bp Annual Report and Form 20-F 2024






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 key 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 the differentiated IRRs

applicable to that case at the time of the

investment decision, depending on the business.

We 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%.

3.For hydrogen and CCS, we expect levered

returns in the mid-teens including farm-down

and integration value.

For each 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 2024, 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 2024 we used the central price IRR and other

economic hurdles as set out in the bp Annual

Report and Form 20-F 2023 (page 32). As in

previous years, we reduced our operational

carbon intensity« guide levels, in line with our

decreasing 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, and <1.0x any relevant

payback guide level, as set out in the bp Annual

Report and Form 20-F 2023 (page 32).

Sustainability: Where appropriate, we compared

the expected operational carbon intensity of the

investment relative to that of the portfolio

average shown in the bp ESG Datasheet 2023 for

the segment or the related business activity

(upstream and refining). 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.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		23




		Strategic report

Evaluation outcome

In 2024 eight new material capex investments were approveda. All were evaluated as being consistent with the Paris goals, taking into account both

quantitative and qualitative evaluations and the balanced criteria above.

Evaluation of investment performance against quantitative guide levelsb

Seven of the eight investments exceeded the relevant IRR guide level as shown in the chart. The IRR of the remaining investment was slightly below

its central price IRR hurdle.

Three of the four upstream hydrocarbon projects had emissions intensities below the relevant upstream intensity guide level. The other upstream

investment had an emissions intensity above the guide level, but was expected to reduce our operational emissions intensity in the region. The four

other investments were in businesses for which there was no applicable carbon intensity guide. These latter investments are shown as ‘n/a’ in the

operational carbon intensity chart.

Investment economics

Sustainability

Against IRR guide level

Against operational carbon intensity

Investments with

intensity guide level

No intensity

guide level

Guide

n/a

Decisions taken in 2024

In 2024 there were eight new material capex investment decisions evaluated for Paris consistency, shown here in the order the investment decisions were made:

Brazilian biofuels: In June bp agreed to take full

ownership of our Brazilian biofuels joint venture,

acquiring Bunge’s 50% interest. The acquisition is

expected to have capacity to produce around

50,000 barrels a day of ethanol equivalent from

sugar cane through the business’s 11 agro-

industrial units across five Brazilian states.

Kaskida: In July bp approved its final investment

decision in the Kaskida project in the US Gulf of

America. The new floating platform is expected to

have nameplate production capacity of 80,000

barrels of oil per day. It will leverage simplified,

standardized and cost-efficient design, which is

expected to be replicated in future projects.

Ruwais LNG: In July bp announced we had

agreed to take a 10% interest in a new ADNOC-

operated LNG facility in Abu Dhabi, deepening our

relationship with our longstanding partner. The

project has a planned total capacity of 9.6Mtpa.

The investment is consistent with bp’s strategy to

develop competitive gas positions as we grow our

LNG portfolio.

aThe RCM also approved two investment cases in our low carbon energy business with capital investment above $250 million, which are not included in the evaluation information presented above.

This is because one did not reach a final investment decision during 2024 and the other was a transaction to progress certain bp low carbon energy assets by contributing them to a joint venture. All of

the assets that were material had been previously disclosed as new material capex investments in bp’s Annual Report and Form 20-F for the relevant year.

bThe 2024 investments have been compared to relevant guides (as applicable to the evaluation of each investment) and are presented here in order of the ratio to the relevant central-price case IRR

guide level (or where there was no relevant central price IRR guide level, the lower price one), and separately in order of the ratio to the relevant emissions intensity guide level. As a result, the

evaluations against the economic and sustainability benchmarks do not necessarily follow the same order.

Coconut gas development: In August bp and

EOG agreed to form a 50:50 joint venture for the

Coconut development with EOG as operator. This

partnership for the Coconut development is part

of bpTT’s strategy to grow its gas business and

help to unlock the energy future of Trinidad

and Tobago.

Tangguh UCC: In November bp and partners

gave the go-ahead for the Tangguh UCC project in

Papua Barat, Indonesia. The project has three

components: the Ubadari field; a gas compression

facility; and a carbon capture, use and storage

(CCUS) project. It has the potential to unlock

around 3 trillion cubic feet of additional gas

resources in Indonesia to help meet growing

energy demand in Asia. The CCUS component is

expected to sequester around 15MtCO2 during its

initial phase from Tangguh’s natural gas

production, reducing overall CO2 emissions

intensity from operations at Tangguh.

Northern Endurance Partnership (NEP):

In December bp and partners made their final

investment decision for NEP, a joint venture

between bp, Equinor and TotalEnergies, which is

the CO2 transportation and storage provider for

the UK’s East Coast Cluster (ECC).

The Teesside onshore NEP infrastructure is

expected to serve the Teesside-based carbon

capture projects – NZT Power, H2Teesside and

Teesside Hydrogen CO2 Capture. We expect

around 4MtCO2 per year from these projects will

be transported and stored from 2027.

Net Zero Teesside Power (NZT Power):

Also in December bp and partners took a final

investment decision in NZT Power, a joint venture

between bp and Equinor, which could generate

up to 742MW of flexible, dispatchable low carbon

power. Up to 2MtCO2 per year will be captured at

the plant, and then transported and securely

stored in subsea storage sites in the North Sea.

Lingen Green Hydrogen: In December bp

made a final investment decision for the Lingen

Green Hydrogen project in Germany, which will be

its first fully-owned and operated large-scale green

hydrogen« facility. The project is expected to

install a 100MW electrolyser capacity capable of

producing an average of 10-11kt of green

hydrogen per year from 2027. The renewable

power needed for the electrolyser is expected to

be supplied by offshore wind generation.


24		bp Annual Report and Form 20-F 2024






Group performance

Laying the foundation for growth


$0.4bn	$8.9bn	$27.3bn
profit attributable to bp shareholders (2023 profit $15.2bn)	underlying replacement cost (RC) profit« (2023 profit $13.8bn)	operating cash flow« (2023 $32.0bn)


Financial and operating performance
	$ million except per share amounts
	2024	2023	2022
Sales and other operating revenues	189,185	210,130	241,392
Profit before interest and tax	11,297	27,348	18,039
Finance costs and net finance income/expense relating to pensions and other post-employment benefits	(4,515)	(3,599)	(2,634)
Taxation	(5,553)	(7,869)	(16,762)
Profit (loss) for the year	1,229	15,880	(1,357)
Non-controlling interest	(848)	(641)	(1,130)
Profit (loss) for the year attributable to bp shareholders	381	15,239	(2,487)
Inventory holding (gains) losses«, before tax	488	1,236	(1,351)
Taxation charge (credit) on inventory holding gains and losses	(119)	(292)	332
Replacement cost (RC) profit (loss)«	750	16,183	(3,506)
Net (favourable) adverse impact of adjusting items«a, before tax	9,344	(1,143)	29,781
Total taxation charge (credit) on adjusting items	(1,179)	(1,204)	1,378
Underlying RC profit	8,915	13,836	27,653
Adjusted EBIDA«	31,161	34,345	45,695
Adjusted EBITDA«	38,012	43,710	60,747
Dividend paid per ordinary share (cents)	30.540	27.760	22.932
Dividend paid per ordinary share (pence)	23.720	22.328	18.624
Profit (loss) per ordinary share (cents)	2.38	87.78	(13.10)
Profit (loss) per ADS (dollars)	0.14	5.27	(0.79)
Underlying RC profit per ordinary share« (cents)	54.40	79.69	145.63
Underlying RC profit per ADS« (dollars)	3.26	4.78	8.74
Adjusting itemsa
Gains on sale of businesses and fixed assets	670	361	3,866
Net impairment and losses on sale of businesses and fixed assets	(6,930)	(5,838)	(5,920)
Environmental and related provisions	(181)	(647)	325
Restructuring, integration and rationalization costs	(222)	37	34
Fair value accounting effects (FVAEs)b	(1,852)	9,403	(3,501)
Rosneft	—	—	(24,033)
Gulf of America oil spill	(51)	(57)	(84)
Other	(273)	(1,711)	(43)
Total before interest and taxation	(8,839)	1,548	(29,356)
Finance costs	(505)	(405)	(425)
	(9,344)	1,143	(29,781)
Adjusting items total taxation	1,179	1,204	(1,378)
	(8,165)	2,347	(31,159)

aSee page 313 for more information. bSee page 314 for information on the cumulative impact of FVAEs.

bp delivered operating cash

flow of $27.3 billion. During

the year, we made strong

progress on cost savings,

achieving $0.8 billion of

structural cost reduction«.

We raised the dividend per

ordinary share by 10% and

delivered $7 billion of share

buybacks. Our focus on

capital discipline and

strengthening the balance

sheet continues into 2025.

Kate Thomson

Chief financial officer


« See glossary on page 351		bp Annual Report and Form 20-F 2024		25




		Strategic report

At 31 December 2024 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 2024

attributable to bp shareholders was $0.4 billion,

compared with $15.2 billion in 2023. Adjusting

for inventory holding losses, RC profit was $0.8

billion, compared with $16.2 billion in 2023.

After adjusting RC profit for a net adverse impact

of items, which bp has classified as adjusting

(adjusting items) of $8.2 billion (on a post-tax

basis), underlying RC profit for the year ended

31 December 2024 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 2023, after adjusting RC profit for a net

favourable impact of adjusting items of $2.3

billion (on a post-tax basis), underlying RC profit

was $13.8 billion. The result reflected lower

realizations, the impact of portfolio changes, the

impact of lower refining margins and a lower oil

trading performance.

For a discussion of bp’s financial and operating

performance for the years ending 31 December

2022 and 31 December 2023, see bp Annual

Report and Form 20-F 2023, pages 35-47.

Adjusting items

In 2024 the net adverse pre-tax impact of items,

which bp has classified as adjusting (adjusting

items) was $9.3 billion including:

•Adverse fair value accounting effects (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 fair value accounting

effects relating to the hybrid bonds in 2024

compared to the favourable impact in 2023.

•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.

In 2023 the net favourable pre-tax impact of

adjusting items was $1.1 billion including:

•Favourable FVAEs relative to management’s

measure of performance of $9.4 billion

primarily due to a decline in the forward price

of LNG during 2023. Under IFRS, reported

earnings include the mark-to-market value of

the hedges used to risk-manage LNG

contracts, but not of the LNG contracts

themselves. The underlying result includes

the mark-to-market value of the hedges but

also recognizes changes in value of the LNG

contracts being risk managed. The impacts of

FVAEs relative to management’s internal

measure of performance are provided on

page 314.

•Net impairment charges of $5.7 billion largely

as a result of changes in the group’s price and

discount rate assumptions, activity phasing

and economic forecasts (in particular related

to the Gelsenkirchen refinery).

•In addition, $1.3 billion net impairment

charges were reported through equity-

accounted earnings (reported within the

‘other’ category), of which $1.1 billion relates

to our US offshore wind projects.

See Financial statements – Note 4 for more

information on impairments, and pages 313

and 314 for more information on adjusting

items and FVAEs.

Taxation

The charge for corporate income taxes was

$5,553 million in 2024 compared with $7,869

million in 2023. The effective tax rate (ETR) on

the profit before taxation for the year in 2024

was 82%, compared with 33% in 2023. The ETR

on the profit before taxation for the year in 2024

and in 2023 was impacted by fair value

accounting effects and other adjusting items.

Excluding inventory holding impacts and

adjusting items, the underlying ETR« in 2024

was 41% compared with 39% in 2023. The

underlying ETR in 2024 is higher due to changes

in the geographical mix of profits. The underlying

ETR for 2025 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. Underlying ETR is a non-IFRS

measure. A reconciliation to IFRS information is

provided on page 360.

Outlook for 2025

2025 guidance

•bp expects reported upstream« production to

be lower and underlying upstream

production« to be slightly lower compared

with 2024. Within this, bp expects underlying

production from oil production & operations

to be broadly flat and production from gas &

low carbon energy to be lower.

•In its customers business, bp expects growth

including a full year contribution from bp

bioenergy and a higher contribution from

TravelCenters of America in part supported by

a partial recovery from the US freight

recession. Earnings growth is expected to be

supported by structural cost reduction. bp

continues to expect fuels margins to remain

sensitive to the cost of supply and earnings

delivery to remain sensitive to the relative

strength of the US dollar.

•In products, bp expects broadly flat refining

margins relative to 2024 and stronger

underlying performance underpinned by the

absence of the plant-wide power outage at

Whiting refinery, and improvement plans

across the portfolio. bp expects similar levels

of refinery turnaround activity, with phasing of

turnaround activity in 2025 heavily weighted

towards the first half, with the highest impact

in the second quarter.

•bp expects other businesses & corporate

underlying annual charge to be around $1.0

billion for 2025. The charge may vary from

quarter to quarter.


26		bp Annual Report and Form 20-F 2024






Group performance continued


Cash flow and debt information
	$ million
	2024	2023	2022
Cash flow
Operating cash flow«	27,297	32,039	40,932
Net cash used in investing activities	(13,250)	(14,872)	(13,713)
Net cash provided by (used in) financing activities	(7,297)	(13,359)	(28,021)
Cash and cash equivalents at end of yeara	39,269	33,030	29,195
Capital expenditure«b	(16,237)	(16,253)	(16,330)
Divestment and other proceedsc	4,224	1,843	3,123
Debt
Finance debt	59,547	51,954	46,944
Net debt«	22,997	20,912	21,422
Net debt including leases«	34,909	31,902	29,990
Finance debt ratio« (%)	43.2%	37.8%	36.1%
Gearing« (%)	22.7%	19.7%	20.5%
Gearing including leases« (%)	30.8%	27.2%	26.5%
a2024 includes $65 million 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 312. 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 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 the year 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. bp actively manages its

working capital balances to optimize and reduce

volatility in cash flow.

Operating cash flow for the year ended

31 December 2023 was $32.0 billion, $8.9 billion

lower than 2022. Compared with 2022, operating

cash flows in 2023 primarily reflected lower

realizations, refining margins and oil trading

performance and the impact of portfolio

changes.

Movements in working capital adversely

impacted cash flow in 2023 by $3.3 billion,

including an adverse impact from the Gulf of

America oil spill of $1.2 billion. Other working

capital effects were principally a decrease in

other current liabilities, partly offset by decreases

in inventory and other current assets.

Net cash used in investing activities

Net cash used in investing activities for the year

ended 31 December 2024 decreased by $1.6

billion compared with 2023.

The decrease mainly reflected an increase in

divestment proceeds and a net cash inflow from

acquisitions, partly offset by an increase in

expenditure on fixed assets.

Total capital expenditure for 2024 was $16.2

billion (2023 $16.3 billion), of which organic

capital expenditure« was $16.1 billion (2023

$15.0 billion). Inorganic capital expenditure for

2024 includes the cash acquired net of

acquisition payments on completion of the bp

Bunge Bioenergia and Lightsource bp

acquisitions. Inorganic capital expenditure for

2023 includes $1.1 billion, net of adjustments, in

respect of the TravelCenters of America

acquisition. 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 $15 billion in 2025 and a

range of $13-15 billion per annum from 2026 to

2027.

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.

Total divestment and other proceeds for 2023

amounted to $1.8 billion, including $0.5 billion

relating to the sale of the upstream business in

Algeria and $0.3 billion relating to the disposal of

bp’s interest in the bp-Husky Toledo refinery.

Other proceeds for 2023 consist of $0.5 billion of

proceeds from the sale of a 49% interest in a

controlled affiliate holding certain midstream

assets onshore US.

As at 31 December 2024, $22.0 billion of

proceeds were received against our target of $25

billion of divestment and other proceeds between

the second half of 2020 and 2025. bp expects

divestment and other proceeds to be around $3

billion in 2025.

Net cash provided by (used in)

financing activities

Net cash used in financing activities for the year

ended 31 December 2024 was $7.3 billion,

compared with $13.4 billion in 2023. Compared

with 2023, financing cash flows in 2024 primarily

reflected higher receipts from the issue of

perpetual hybrid bonds and higher net proceeds

from the issuance and repayment of finance

debt.

In 2024, 1,238 million of ordinary shares (2023

1,263 million) were repurchased for cancellation

for a total cost of $7.1 billion (2023 $7.9 billion),

including transaction costs of $38 million (2023

$43 million).

Total dividends paid to shareholders in 2024

were 30.540 cents per share, 2.78 cents higher

than 2023. This amounted to total dividends paid

to shareholders of $5.0 billion in 2024 (2023 $4.8

billion). The board decided not to offer a scrip

dividend alternative in respect of the 2024 and

2023 dividends.

Debt

Finance debt at the end of 2024 increased by

$7.6 billion from the end of 2023 primarily

reflecting net long-term debt issuances. The

finance debt ratio at the end of 2024 increased to

43.2% from 37.8% at the end of 2023.

Net debt at the end of 2024 increased by $2.1

billion from the 2023 year-end position. Gearing

at the end of 2024 increased to 22.7% from

19.7% at the end of 2023. The increase in net

debt and gearing primarily reflects the net debt

acquired from the completion of the bp Bunge

Bioenergia and Lightsource bp transactions

partially offset by the issuance of perpetual

hybrid securities. 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 316.


28		bp Annual Report and Form 20-F 2024






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, integrated gas and

power, and gas trading. Our low carbon business includes solar, offshore and onshore wind, hydrogen

and CCS, and power trading. Power trading and marketing includes trading of both renewable and non-

renewable power.


Financial and operating performance
	$ million
	2024	2023	2022b
Sales and other operating revenuesc	32,628	50,297	56,255
Profit before interest and tax	3,569	14,081	14,688
Inventory holding (gains) losses«	—	(1)	8
RC profit before interest and tax	3,569	14,080	14,696
Net (favourable) adverse impact of adjusting items«d	3,234	(5,358)	1,367
Underlying RC profit before interest and tax«	6,803	8,722	16,063
Taxation on an underlying RC basis	(2,137)	(2,730)	(4,367)
Underlying RC profit before interest	4,666	5,992	11,696
Depreciation, depletion and amortization	4,835	5,680	5,008
Exploration write-offs	222	362	2
Adjusted EBITDA«e	11,860	14,764	21,073
Capital expenditure«
Gas	3,615	3,025	3,227
Low carbon energy	1,596	1,256	1,024
	5,211	4,281	4,251
aThe AGT and Middle East regions have been further subdivided by asset to allow reporting in either gas & low carbon or oil production & operations as appropriate. b2022 includes bp Bunge Bioenergia. From the first quarter of 2023, bp Bunge Bioenergia is reported within customers & products. cIncludes sales to other segments. dSee page 314 for information on the cumulative impact of FVAEs. eA reconciliation to RC profit before interest and tax is provided on page 362.

Financial results

Sales and other operating revenues for 2024 are

lower than 2023 due to materially lower trading

results, lower gas prices and lower volumes.

RC profit before interest and tax for 2024 was

$3,569 million compared with $14,080 million

for 2023.

Items which bp has classified as adjusting for

2024 had a net adverse impact of $3,234 million

including adverse fair value accounting effects

(FVAEs)« of $1,550 million, relative to

management’s view of performance, net

impairment charges of $3,004 million, 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).

After adjusting RC profit for the net impact of

items which bp has classified as adjusting,

underlying RC profit before interest and tax for

2024 was $6,803 million, compared with $8,722

million for 2023. The decrease reflects a lower

gas marketing and trading result, lower

realizations and lower production partly offset by

a lower depreciation, depletion and amortization

charge and lower exploration write-offs.

Items which bp has classified as adjusting for

2023 had a net favourable impact of $5,358

million including favourable FVAEs of $8,859

million, relative to management’s view of

performance, partially offset by a net impairment

charges.

See Financial statements – Note 4 and Note 16

for further information on net impairment

charges.

Operational update

Reported production for 2024 was 888mboe/d,

4.4% lower than the same period in 2023.

Underlying production« for the full year was 2.8%

lower, mainly due to base decline in Egypt,

partially offset by major projects« ramp-up.

Renewables pipeline« at the end of the year was

60.6GW (bp net), including 38.7GW of LSbp’s

pipeline. The renewables pipeline showed a net

increase of 2.3GW during the year as a result of

the LSbp acquisition (20.5GW), offset by

reductions as a result of high-grading and focus

on proposed hydrogen projects and the US solar

business.

In renewables by the end of 2024 we had

cumulatively brought 8.2GW (bp net) developed

renewables to FID«.

Strategic progress

Gas

In Indonesia, we announced the final investment

decision on the $7 billion Tangguh Ubadari,

carbon capture, utilization and storage (CCUS)

Compression project (UCC), which has the

potential to unlock around 3 trillion cubic feet of

additional gas resources in Indonesia. Tangguh

CCUS aims to be the first CCUS project

developed at scale in Indonesia.

In Trinidad, we have made progress on our

growth projects and high graded our portfolio:

•In June we sanctioned the Coconut project

and in August we agreed to partner with EOG

Resources Trinidad Limited to develop the

Coconut gas field.

• In July, together with our partner NGC, we

were awarded an exploration and production

licence by the Bolivarian Republic of

Venezuela for the development of the cross-

border Cocuina gas discovery.

•In December we completed the sale of four

mature offshore gas fields and associated

production facilities to Perenco T&T.

In Egypt, we completed the formation of a new

joint venture, Arcius Energy (51% bp, 49% XRG).

The JV will initially operate in Egypt, and includes

interests assigned by bp across

two development concessions, as well as

exploration agreements.

In December, we completed a sale of a non-

controlling stake in bp Pipelines TAP Limited,

the bp subsidiary that holds a 20% share in

Trans Adriatic Pipeline AG (TAP), to Apollo-

managed funds.

In January 2025 we announced that we have

begun flowing gas from wells at the Greater

Tortue Ahmeyim (GTA) project off the coast of

West Africa. Once fully commissioned, it is

expected to produce 2.4Mtpa of LNG.

In February 2025 we signed an agreement with

ONGC as the technical services provider for the

largest offshore oil field in India, which accounts

for around 25% of the country's oil production.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		29




		Strategic report

LNG portfolio

In April bp and Korea Gas Corporation (KOGAS)

announced the signing of a long-term agreement

to supply up to 9.8Mt of LNG over 11 years on a

delivered ex-ship (DES) basis from 2026. This

builds on the existing long-term sale to KOGAS

and further adds to bp’s global LNG market

presence in key demand regions.

In July bp confirmed it would take 10% interest in

the new ADNOC-operated LNG facility in Abu

Dhabi (Ruwais LNG), further deepening bp’s

longstanding partnership with ADNOC. The

project has planned total LNG production

capacity of 9.6mmtpa.

bp and its partners concluded the restructured

ownership and commercial framework of

Atlantic LNG in Trinidad and Tobago effective 1

October, which allows for an intensified focus on

operational efficiency and reliability and provides

the certainty required for sanctioning the next

wave of upstream gas projects.

See Oil and gas disclosures for the group on

page 318 for more information on oil and gas

operations in the regions.

Low carbon energy

In 2024 we have initiated a significant portfolio

reset of low carbon energy businesses and we

are making strong progress on the programmes

that are driving focus and reducing costs.a

Hydrogen and carbon capture and storage

In 2024 we have refocused our H2CCS business

by reducing the number of projects from 30 to

five to seven high-quality hydrogen/CCS projects

this decade, four of which have taken FID

in 2024:

•In September together with our partner

Iberdrola, we sanctioned construction of a

25MW green hydrogen« project at bp's

Castellón refinery in Spain which is expected

to be operational in the second half of 2026.

•In December financial close was reached for

two major projects in Teesside, UK: the

Northern Endurance Partnership (NEP)

carbon capture and storage project and the

Net Zero Teesside Power (NZT Power)

project.

•We also announced in December the final

investment decision for 100MW Lingen Green

Hydrogen project (see case study, right).

aFrom 2025 we intend to report our biogas business as part of the gas & low carbon energy segment.

Renewables and power

Offshore wind

We have changed our model for offshore wind –

delivering with partners and with external

financing that will be capital-light for bp and

improve our equity returns.

In December we announced our agreement with

JERA Co., Inc. to combine our global offshore

wind businesses to form a new standalone,

equally-owned joint venture JERA Nex bp (see

case study, right).

In December the Japanese government

selected a consortium involving bp, Tokyo Gas,

Marubeni Corporation, Kansai Electric Power

and Marutaka Corporation to build a 450MW

offshore wind farm.

Onshore renewables

In October we completed the acquisition of the

remaining 50.03% interest in LSbp, one of the

world’s leading developers and operators of

utility-scale solar and battery storage assets

operators. LSbp has developed 12GW to date

including 3GW of projects to FID in 2024. In 2024

it also constructed over 2GW with total cost

under budget as well as significantly developing

battery energy storage systems capabilities and

footprint. In February 2025 we announced our

intention to bring a strategic partner into the

business.

In September we announced our plans to sell our

existing US onshore wind energy business, bp

Wind Energy (10 operating wind assets, net total

generating capacity 1.3GW) and aim to bring

together the development of onshore renewable

power projects through Lightsource bp.

Power trading

In August we announced we have completed the

acquisition of GETEC ENERGIE GmbH, a leading

independent supplier of energy to commercial

and industrial customers in Germany. This deal

will accelerate the growth of bp’s European gas

and power presence.


	LiDAR buoys help inform offshore wind farm development, Liverpool, UK



	Partnering for offshore wind bp and JERA Co., Inc., Japan’s largest power generation company, have agreed to set up a new 50:50 joint venture, JERA Nex bp, that will become one of the largest global offshore wind developers, owners and operators. The joint venture aims to create a strategic platform for growth by combining a balanced mix of operating assets and development projects with total 13GW potential net generating capacity. Subject to regulatory and other approvals, we aim to complete the formation of JERA Nex bp by the end of the third quarter of 2025.



	Green hydrogen in Germany In December 2024 bp announced the final investment decision for its 100MW Lingen Green Hydrogen (LGH2) project in Germany. It is expected to be bp’s largest industrial green hydrogen plant and the first that we will fully own and operate. The project is expected to produce around 11,000 tonnes of green hydrogen annually, with commissioning expected in 2027.


	bp’s Lingen refinery, Germany


30		bp Annual Report and Form 20-F 2024






Gas & low carbon energy continued


Estimated net proved reserves and productiona (net of royalties)
	2024	2023	2022
Estimated net proved reserves (net of royalties)
Crude oilb (mmb)	113	128	151
Natural gas liquids (mmb)	1	1	9
Total liquids«c	115	129	160
Natural gasc (bcf)	6,965	8,635	9,708
Total hydrocarbons«c (mmboe)	1,316	1,618	1,834
Of which equity-accounted entitiesd:
Liquids (mmb)	1	—	—
Natural gas (bcf)	196	—	—
Total hydrocarbons (mmboe)	35	—	—
Production (net of royalties)
Crude oilbe (mb/d)	88	96	103
Natural gas liquids (mb/d)	8	9	15
Total liquids (mb/d)	96	105	118
Natural gas (mmcf/d)	4,596	4,778	4,866
Total hydrocarbons (mboe/d)	888	929	957
Of which equity-accounted entitiesf:
Liquids (mb/d)	2	2	2
Natural gas (mmcf/d)	9	—	—
Total hydrocarbons (mboe/d)	4	2	2
Average realizations«g
Liquids ($/bbl)	75.37	77.03	89.86
Natural gas ($/mcf)	5.90	6.13	8.91
Total hydrocarbons ($/boe)	38.57	40.21	56.34
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 (2.2 million barrels at 31 December 2023 and 3 million barrels at 31 December 2022) and 219 billion cubic feet of natural gas (430 billion cubic feet at 31 December 2023 and 547 billion cubic feet at 31 December 2022) 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. e2023 restated, 4mb/d previously reported in NGLs. fbp’s share of production of equity-accounted entities in the gas & low carbon energy segment. gRealizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.

Renewables


	2024	2023	2022
Renewables (bp net, GW)
Installed renewables capacity«	4.0	2.7	2.2
Developed renewables to FID«	8.2	6.2	5.8
Renewables pipeline	60.6	58.3	37.2
of which by geographical area:
Renewables pipeline – Americas	21.2	18.8	17.0
Renewables pipeline – Asia Pacific	15.1	21.3	11.8
Renewables pipeline – Europe	23.6	14.6	8.3
Renewables pipeline – Other	0.7	3.5	0.1
of which by technology:
Renewables pipeline – offshore wind	9.7	9.3	5.2
Renewables pipeline – onshore wind	6.6	12.7	6.3
Renewables pipeline – solar	44.3	36.3	25.7
Total developed renewables to FID and renewables pipeline	68.8	64.5	43.0


	The potential site of NZT Power, UK



	Natural gas in Indonesia bp and its partners approved the $7 billion Tangguh UCC project in Papua Barat, Indonesia. This initiative will help unlock around 3 trillion cubic feet of natural gas and help meet growing energy demand in Asia. Through the use of CCUS for enhanced gas recovery, the project has the potential to sequester around 15MtCO2 in its initial phase, reducing overall CO2 emissions intensity from operations at Tangguh.


	Tangguh LNG facility, Papua Barat, Indonesia



	Teesside carbon capture milestone In December 2024, bp and partners reached financial close on the Net Zero Teesside Power (NZT Power) and Northern Endurance Partnership (NEP) projects. NZT Power aims to be one of the world’s first gas-fired power stations with carbon capture, and could generate up to 742MW of flexible, dispatchable low carbon power and could capture up to 2MtCO2 annually. NEP will develop the infrastructure to transport and store up to an initial 4MtCO2 annually from three Teesside-based carbon capture projects within the East Coast Cluster, with the ability to expand in the future. Both projects are expected to support thousands of jobs and help advance the UK's journey to net zero.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		31




		Strategic report

Oil production & operations


Oil production & operations segment comprises regionsa with upstream activities that predominantly produce crude oil, including bpx energy.
Financial and operating performance
	$ million
	2024	2023	2022
Sales and other operating revenuesb	25,637	24,904	33,193
Profit before interest and tax	10,780	11,191	19,714
Inventory holding (gains) losses«	9	—	7
RC profit before interest and tax	10,789	11,191	19,721
Net (favourable) adverse impact of adjusting items«	1,148	1,590	503
Underlying RC profit before interest and tax«	11,937	12,781	20,224
Taxation on an underlying RC basis	(5,165)	(5,998)	(9,143)
Underlying RC profit before interest	6,772	6,783	11,081
Depreciation, depletion and amortization	6,797	5,692	5,564
Exploration write-offs	544	384	383
Adjusted EBITDA«c	19,278	18,857	26,171
Capital expenditure«	6,198	6,278	5,278

aThe AGT and Middle East 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 362.

Financial results

Sales and other operating revenues for 2024

were higher than 2023 mainly due to higher

volumes partially offset by lower realizations.

RC profit before interest and tax for 2024 was

$10,789 million compared with $11,191 million

for 2023.

Adjusting items for 2024 had a net adverse

impact of $1,148 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 2024 was $11,937

million, compared with $12,781 million for 2023.

The lower profit reflects lower realizations, and

the impact of increased depreciation charges

and higher exploration write-offs, partly offset by

higher volumes.

Adjusting items for 2023 had a net adverse

impact of $1,590 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 2024 was 1,470mboe/d,

6.3% higher than the same period of 2023.

Underlying production« for the year was 6.2%

higher compared with the same period of 2023

reflecting bpx energy performance and major

projects« partly offset by base performance.

Strategic progress

•Aker BP announced oil production had started

from the Tyrving field, which is part of the life

extension of the Alvheim field.

•ACG joint venture partners announced the

signing of an addendum to the existing PSA

which enables the parties to progress the

exploration, appraisal, development of and

production from the non-associated natural

gas reservoirs of the ACG field (bp operator

with 30.37% equity).

•Azule Energy completed the acquisition of a

42.5% interest in exploration block 2914A

(PEL85), Orange Basin, offshore Namibia.

•bp sanctioned the Atlantis Drill Center

Expansion in the Gulf of America (bp

share 56%).



	Growth in the Permian In 2024, bp’s US onshore oil and gas business, bpx energy, achieved its 30-40% growth target, set for 2025, a year early. And it brought online Checkmate, its third central processing facility in the Permian Basin in April. The electrified facility is designed to support further production growth for bpx energy in the basin.


	bpx energy, Permian Basin processing facility in Texas, US

•Aker BP was awarded interests in 19 licences



	Growth in the Permian In 2024, bp’s US onshore oil and gas business, bpx energy, achieved its 30-40% growth target, set for 2025, a year early. And it brought online Checkmate, its third central processing facility in the Permian Basin in April. The electrified facility is designed to support further production growth for bpx energy in the basin.


	bpx energy, Permian Basin processing facility in Texas, US

(of which it will operate 16) in the North Sea

and Norwegian Sea (bp 15.9%).

•bp was awarded a licence for two blocks in

the central North Sea, consolidating our

position around our Eastern Trough Area

Project (ETAP) central processing facility.

•The Production Sharing Contract for the

Tupinamba block in Brazil was executed

(bp 100%).

See Oil and gas disclosures for the group on

page 318 for more information on oil and gas

operations in the regions.


32		bp Annual Report and Form 20-F 2024






Oil production & operations continued


Estimated net proved reserves and productiona (net of royalties)
	2024	2023	2022
Estimated net proved reserves (net of royalties)
Crude oilb (mmb)	3,112	3,193	3,380
Natural gas liquids (mmb)	472	426	457
Total liquids	3,584	3,618	3,836
Natural gas (bcf)	7,821	8,836	8,774
Total hydrocarbons« (mmboe)	4,932	5,142	5,349
Of which equity-accounted entitiesc:
Liquids (mmb)	917	1,001	968
Natural gas (bcf)	2,467	2,527	2,394
Total hydrocarbons (mmboe)	1,342	1,437	1,381
Production (net of royalties)
Crude oilb (mb/d)	953	910	866
Natural gas liquids (mb/d)	117	100	86
Total liquids (mb/d)	1,070	1,010	952
Natural gas (mmcf/d)	2,318	2,165	1,998
Total hydrocarbons (mboe/d)	1,470	1,383	1,297
Of which equity-accounted entitiesd:
Liquids (mb/d)	272	269	176
Natural gas (mmcf/d)	431	432	436
Total hydrocarbons (mboe/d)	346	343	251
Average realizations«e
Liquids ($/bbl)	69.85	72.09	89.62
Natural gas ($/mcf)	2.55	4.17	10.46
Total hydrocarbons ($/boe)	53.96	58.34	82.23
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 2024 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. 2022 includes bp’s share of production of Russia joint ventures. eRealizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities.



	Expansion in the Gulf We took a final investment decision on the Kaskida project in the US Gulf of America in July. The floating production platform is expected to have a capacity of 80,000 barrels of oil per day from six wells in its first phase. Kaskida will be bp’s sixth hub in the Gulf of America and production is expected to start in 2029.



	Progress in Azerbaijan In April we started up oil production from the Azeri Central East (ACE) platform, as part of the Azeri-Chirag-Gunashli development in the Caspian Sea. ACE is bp’s first fully remotely operated offshore platform. Its innovative engineering helps automate labour-intensive processes, supporting safer and more efficient operations as well as helping lower operational emissions.



	Redevelopment of Kirkuk On 25 February 2025 bp reached agreement on all contractual terms with the government of the Republic of Iraq to invest in several giant oil fields in Kirkuk providing for the rehabilitation and redevelopment of the fields, spanning oil, gas, power and water with potential for investment in exploration. The agreement is subject to final governmental ratification.


	ACE platform in the Caspian Sea, Azerbaijan


« See glossary on page 351		bp Annual Report and Form 20-F 2024		33




		Strategic report

Customers & products

Customers & products segment comprises our customer-focused businesses, which include



	Scaling up biofuels We took full ownership of bp bioenergy, one of Brazil’s leading biofuels-producing companies, in October. The acquisition means bp now has the capacity to produce around 50,000 barrels a day of ethanol equivalent from sugar cane through the business’s 11 agro-industrial units across five Brazilian states.



	Epic expansion In 2024 we launched our own line of private label consumer-packaged products in the US – epic goods. Initially featuring a few products, the range expanded to over 50 SKUs by the end of 2024. epic goods is available in 1,500 locations across our ampm, TravelCenters of America, Thorntons brands and many of our franchised locations, offering a range of nuts, juices and bottled water.


	bp bioenergy, Brazil

convenience and retail fuels, EV charging, as well as Castrol, aviation and B2B and midstream. It also

includes our products businesses, refining & oil trading, as well as our bioenergy businesses.


Financial and operating performance
	$ million
	2024	2023	2022
Sales and other operating revenuesa	155,401	160,215	188,623
Profit (loss) before interest and tax	(2,039)	2,993	10,235
Inventory holding (gains) losses«	479	1,237	(1,366)
Replacement cost (RC) profit (loss) before interest and tax	(1,560)	4,230	8,869
Net (favourable) adverse impact of adjusting items«b	4,077	2,183	1,920
Underlying RC profit before interest and tax«	2,517	6,413	10,789
Of which:
customers – convenience & mobility	2,584	2,644	2,966
Castrol – included in customers	831	730	700
products – refining & trading	(67)	3,769	7,823
Taxation on an underlying RC basis	(452)	(1,454)	(2,308)
Underlying RC profit before interest	2,065	4,959	8,481
Depreciation, depletion and amortization	3,957	3,548	2,870
Of which:
customers – convenience & mobility	2,135	1,736	1,286
Castrol – included in customers	176	167	153
products – refining & trading	1,822	1,812	1,584
Adjusted EBITDA«c	6,474	9,961	13,659
Of which:
customers – convenience & mobility	4,719	4,380	4,252
Castrol – included in customers	1,007	897	853
products – refining & trading	1,755	5,581	9,407
Capital expenditure«	4,420	5,253	6,252
Of which:
customers – convenience & mobility	2,059	3,135	1,779
Castrol – included in customers	227	262	235
products – refining & trading	2,361	2,118	4,473
aIncludes sales to other segments. bSee page 314 for information on the cumulative impact of FVAEs. cA reconciliation to RC profit before interest and tax by business is provided on page 327.

Financial results

Sales and other operating revenues in 2024

were lower than in 2023, mainly due to lower

product prices.

RC loss before interest and tax for 2024 was

$1,560 million, compared with a profit of $4,230

million for 2023.

Items which bp has classified as adjusting for

2024 had a net adverse impact of $4,077 million

(including adverse fair value accounting effects

of $81 million – relative to management’s view of

performance), of which $1,660 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 grounds fuels business

disposal. See Financial statements – Note 4 for

further information on disposals and

impairments.

After adjusting RC loss for the net adverse

impact of items, which bp classified as adjusting,

underlying RC profit before interest and tax

(underlying result) was $2,517 million, compared

with $6,413 million for 2023. The result was

significantly lower, primarily reflecting the impact

of lower refining margins and a lower oil trading

contribution.

Items which bp has classified as adjusting for

2023 had a net adverse impact of $2,183 million

(including adverse fair value accounting effects

of $86 million – relative to management’s view of

performance), of which $1,614 million related to

impairment of assets, which included an

impairment of the Gelsenkirchen refinery.

Customers – the convenience and mobility

underlying result for 2024 was lower than 2023.

The 2024 underlying result benefited from a

continued stronger performance in Castrol,

driven by higher unit margins and volumes and

lower costs. In addition, the continued momentum

in EV charging, convenience and retail fuels


34		bp Annual Report and Form 20-F 2024






Customers & products continued

margins was more than offset by a significantly

weaker European midstream performance driven

by biofuels margins. The contribution of

TravelCenters of America continues to be

impacted by the US freight recession.

Products – the underlying result for 2024 was

significantly lower than 2023. In refining, the

result was lower, primarily due to lower realized

refining margins and the first quarter plant-wide

power outage at the Whiting refinery, partly offset

by a lower impact from turnaround activity. The

contribution from oil trading was also

significantly lower than 2023.

Operational update

bp-operated refining availability« for 2024 was

94.3%, lower compared with 96.1% in 2023,

mainly due to the first quarter Whiting refinery

power outage.

Strategic progress

Convenience & retail fuels

In February 2025, bp completed the acquisition

of fuel and convenience retailer, X Convenience,

expanding its network with the addition of 49

sites in South and Western Australia.

Strategic convenience sites« grew to 2,950,

an increase of more than 100 sites compared

to 2023.

In support of high-grading our retail fuels and

convenience portfolio, in October 2024, bp

completed the sale of Türkiye ground fuels

business to Petrol Ofisi, including the group's

interest in three joint venture terminals in Türkiye

and in November 2024, announced its intention

to sell its mobility and convenience and bp pulse

businesses in the Netherlands, with completion

of the sale by the end of 2025.

In addition:

•In October 2024, bp announced the launch of

earnify, a loyalty programme designed to

provide customers with a seamless,

integrated and rewarding experience,

including exclusive discounts on retail store

products and fuel purchases in around 5,500

bp, Amoco and ampm branded stores across

the US.

aFIA advanced sustainable fuel must achieve at least 65% greenhouse gas emissions savings relative to fossil-derived petrol produced at installations operating since 2021. See 2026 F1 Technical

Regulations for details.

EV charging

EV charging continued to show strong

momentum. Energy sold and EV charge points«

installed in the year grew by around 75% and 35%

respectively, compared to 2023, with charge

points now around 39,100.

bp continued to advance its future network

growth:

•In July 2024 bp signed a deal with Simon

Property Group to install and operate up to

900 ultra-fast charging« bays at up to 75

sites across the US, with initial sites expected

to open to the public in early 2026.

•In September 2024, bp signed a deal with LAZ

parking in the US, to roll-out ultra-fast

charging hubs in 20 cities.

In addition:

•In March 2024 bp acquired the freehold of

one of the largest truck stops in Europe,

Ashford International Truckstop in Kent. The

acquisition presents bp with the opportunity

to help meet the comprehensive needs of

UK and European HGV operators transitioning

to EVs.

•In April, bp opened its first bp pulse branded

Gigahub in Houston, Texas, with 24 ultra-

fast« charge points, building momentum in

our US charging business offering.

Castrol

Castrol continued to diversify beyond its core

lubricants and fluids business under a new

‘Onward, Upward, Forward’ strategy. Establishing

a strong presence as a Data Center liquid cooling

solution provider with continuous expansion to

cover the full range of technology. Strong

collaboration with leading AI Server/Chips

players such as Supermicro and Intel.

In addition:

•In June 2024 Castrol announced an

investment in Gogoro Inc., a global

technology leader in two-wheeler battery-

swapping ecosystems that enable smart

mobility solutions for cities.

•Castrol continued to grow its independent

branded workshops, adding around 4,000

workshops in 2024, compared to 2023, with

workshops now over 38,000 in total.

As announced in February 2025, bp is carrying

out a strategic review of its Castrol business with

the intention of accelerating Castrol’s next phase

of value creation.



	Fuelling innovation In July we announced a new strategic partnership with Audi for Formula 1. Through the partnership, we plan to develop the FIA- specified advanced sustainable fuela for Audi's 2026 entry into Formula 1 and through Castrol, we plan to develop lubricants and EV fluids for Audi's V6 turbo engine and electric motor and battery. The collaboration also includes long-term sponsorship, making bp the first official partner of Audi's future Formula 1 factory team.



	Charging ahead ADAC, Germany’s leading automobile association with over 20 million members, announced Aral pulse, bp’s EV charging brand in Germany, as their new exclusive EV charging partner from 1 August. The partnership supports Aral pulse’s aim to expand its existing network. Additionally, bp opened our first standalone Aral EV charging Gigahub in Mönchengladbach in November 2024, featuring 28 charge points and a 24/7 smart store.


	Audi bp partnership


« See glossary on page 351		bp Annual Report and Form 20-F 2024		35




		Strategic report

Bioenergy

bp’s Archaea Energy started up nine renewable

natural gas (RNG) landfill plants in 2024, with a

total capacity of more than 10 million mmBtu per

annum. This includes one of its largest Archaea

Modular Design plants in Shawnee, Kansas in

April. Located next to a large private owned

landfill, the Shawnee plant captures landfill gas

and converts it to RNG with a total capacity of

9,600 standard cubic feet. In February 2025 bp

announced its intention to move its biogas

business to the gas & low carbon energy

segment.

In biofuels, bp took full ownership of bp

bioenergy in Brazil in October 2024. In January

2025, bp announced the decision to rephase its

biofuels project in Kwinana, Australia, with the

objective of improving capital productivity. In

addition, as announced in February 2025, bp will

continue to assess options for investment in

standalone biofuels plants, co-located with our

existing refineries with the potential to move one

project to FID by 2027. However, we will only

proceed when project economics are supportive.

In addition:

•In April 2024, bp launched its new

hydrotreated vegetable oil (HVO) bioenergy

brand, marketed as bp bioenergy HVO, and

commencing with roll-out at sites across the

UK and the Netherlands.

•During the fourth quarter bp continued to

progress its strategic plans to access

feedstock for biofuels, announcing a 10-year

agreement with agri-food group MIGASA for

the supply of up to 40,000 tonnes per year of

vegetable oil waste, and announcing a

collaboration with Corteva, with the intent of

forming a JV, on novel feedstocks.

Refining

bp continued to high grade its refining portfolio,

announcing in February 2025 bp’s 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. This is in

addition to bp’s plans, announced in March 2024,

to transform the Gelsenkirchen refinery site by

the end of the decade. The plans include

simplification of the site to improve its

competitiveness, including a controlled reduction

in total production capacity from 2025 and

increased production of lower-emission fuels

using co-processing.

In addition:

•On 19 June 2024 bp completed the sale of its

8.3% shareholding in Channel Infrastructure,

which owns and operates New Zealand’s

Marsden Point fuel import terminal. Our long-

term terminal storage agreements with

Channel Infrastructure to meet bp’s

foreseeable import and supply requirements

are unaffected by the sale of these shares.

•On 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.


36		bp Annual Report and Form 20-F 2024






Other businesses & corporate

Other businesses & corporate comprises technology, bp ventures, our corporate activities & functions

and any residual costs of the Gulf of America oil spill. From the first quarter 2022 the results of Rosneft,

previously reported as a separate segment, are also included in other businesses & corporate. For

more information see Financial statements – Note 1 Significant accounting policies, judgements,

estimates and assumptions – Investment in Rosneft.


Financial and operating performance
	$ million
	2024	2023	2022
Sales and other operating revenuesa	2,290	2,657	2,299
Profit (loss) before interest and tax	(988)	(903)	(26,737)
Inventory holding (gains) losses«	—	—	—
Replacement cost (RC) profit (loss) before interest and tax	(988)	(903)	(26,737)
Net (favourable) adverse impact of adjusting items«b	380	37	25,566
Underlying RC profit (loss) before interest and tax«	(608)	(866)	(1,171)
Taxation on an underlying RC basis	292	322	439
Underlying RC profit (loss) before interest	(316)	(544)	(732)
Depreciation, depletion and amortization	1,033	1,008	876
Capital expenditure«	408	441	549
aIncludes sales to other segments. bSee page 314 for information on the cumulative impact of FVAEs.

Financial results

RC loss before interest and tax for 2024 was

$988 million, compared with $903 million

for 2023.

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.

Adjusting items for 2023 had a net adverse

impact of $37 million. Adjusting items include

impacts of fair value accounting effects, which

had a favourable impact of $630 million.

Adjusting items also include impacts of

environmental charges, which had an adverse

impact of $604 million.

After adjusting RC loss for the adjusting items,

underlying RC loss before interest and tax for

2024 was $608 million, compared with a loss of

$866 million for 2023, mainly reflecting increased

interest income.

Strategic progress

We continued to invest in a portfolio of

technology businesses, which we see as having

the potential for high growth, through bp

ventures. Strategically significant investments

made through 2024 include:

•In May bp ventures announced the

investment of $10 million in Hysata to expand

the production of its high efficiency

electrolyser technology.

•In December, bp invested in Snowfox

Discovery Ltd alongside co-investors Rio

Tinto and Oxford Science Enterprises.

Snowfox Ltd is a natural hydrogen exploration

company, whose mission is to unlock the

potential of natural hydrogen to contribute to

a net zero future.

•In December, bp ventures announced an

investment into Oxford Flow alongside

Energy Impact Partners. Oxford Flow

engineers and manufactures unique valve

technology designed to be more reliable

and cost-effective.

•In December, bp ventures invested in India’s

leading intercity bus platform, Zingbus, to

scale operations and work to electrify India’s

intercity bus routes. Zingbus’ platform is

designed to make intercity travel more

affordable, accessible and reliable.


38		bp Annual Report and Form 20-F 2024






Sustainability

Sustainability at bp

Our sustainability frame underpins the delivery of our strategy. It focuses on three areas – getting to

net zero, improving people’s lives and caring for our planet.

In February 2025, as part of our strategy reset, we announced we would simplify the aims we have set as part of our sustainability frame to focus on the

areas that we believe are most relevant to bp’s long-term success. We now have five aims: net zero operations«, net zero sales«, people, biodiversity and

water. In some areas we have retired aims we had previously set; however, in many cases work continues in those areas. We provide an update on our

actions on those aims, and our wider progress in relation to embedding sustainability, in our latest Sustainability Report bp.com/sustainability.

Sustainability aims

Net zero operations

Net zero sales

People

Biodiversity

Water

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.

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.

Our aim is to support our

employees and local

communities through the

energy transition.

Our aim is to support

biodiversity where

we operateb.

Our aim is to reduce our

net freshwater use in

stressed catchments

where we operate.

See below

See page 39

See page 60

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 38

•Climate-related financial disclosures, see pages 42-55

•Our approach – safety, ethics and compliance, our people, ‘Who we are’ (our beliefs), see pages 56-60

Net zero

Our ambition remains to be a net zero company

by 2050 or sooner, and to help the world get to

net zero.

We have retired some of our previous net zero

aims and are focusing our aims on the two areas

that we believe are most relevant to our long-

term success and to achieving our overall net

zero ambition. These are: net zero operationsc

and net zero sales. Both of these aims make

explicit what is needed to enable their delivery –

and the delivery of the associated interim targets

and aims. Our future business and investment

decisions, intended to facilitate delivery of our

strategy and investor proposition, will also affect

the outcomes for these aims.

We believe our net zero ambition and aims, taken

aOn a CO2e basis.

bAt our new in-scope bp-operated projects and major operating sites.

cThis aim is a combination of bp’s previous net zero aims (‘aim 1’ and ‘aim 4’).

dDue to rounding some totals may not equal the sum of their component parts. This does not affect the underlying values.

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, our ambition and aims

support the world’s progress towards the Paris

Agreement.

We provide updates on some retired net zero

aims as follows: net zero production« page 39,

investment in transition page 39, advocacy page

39, incentivizing employees page 59, and our

participation in trade associations page 60.

Net zero operations TCFD

Our aim is to reach net zero by 2050 or sooner

for Scope 1 and 2 emissions within bp’s

operational control.

Our interim target is a 20% reduction in our

Scope 1 and 2 operational emissions by the end

of 2025 against the 2019 baseline. Our current

outlook for the end of 2030 is a reduction of

around 45% against the baseline.

Informed by this outlook, and the assumptions

underpinning it, which may change over time,

we have adjusted our previous 50% reduction

aim for the end of 2030 to a range of 45-50%,

against the 2019 baseline of 54.5MtCO2e. Our

methane intensity target remains 0.20% by the

end of 2025.

Scope 1 and 2 emissions

Our combined Scope 1 and 2 emissions were

33.6MtCO2e – a decrease of 38% from our 2019

baseline. The total decrease includes 18MtCO2e

attributable to divestments and 5.4MtCO2e in

emissions reductions activity.

In 2024 our Scope 1 (direct) emissions were

32.8MtCO2e – an overall increase from

31.1MtCO2e in 2023. Of these Scope 1

emissions, 31.4MtCO2e were from carbon

dioxide and 1.5MtCO2e from methaned. The

increase was due to project ramp-ups,

operational growth in our low carbon businesses

and some temporary operational changes such

as turnaround activity and operational issues.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		39




		Strategic report

These were partially offset by the delivery of


Average carbon intensity of sold energy products (gCO2e/MJ)cd
	2024	2023	2022	2021	2020	2019
Average carbon intensity of sold energy products	79	80	81	81	81	84
Oil/refined products	91	91	92	92	93	95
Gas/NGLs	67	67	67	67	67	68
Bioproductse	41	44	43	44	44	47
Power/heatf	50	56	29	27	33	28

emissions reduction projects.

In 2024 our Scope 2a (indirect) emissions,

decreased by 0.2MtCO2e, to 0.8MtCO2e,

compared with 2023. The continued use of lower

carbon power agreements and a project at our

Gelsenkirchen refinery to replace imported steam

from a coal-fired power plant with steam

produced in our own gas-fired boilers 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 2024.



	bp.com/ESGdata

Methane

In 2024, we started reporting on the basis of our

new methane measurement approach across

our major operated upstream oil and gas assets.

Using this approach, our methane intensity was

0.07% in 2024 (2023 0.05%b). Methane

emissions from our upstream« operations used

to calculate this methane intensity were 46kt in

2024 (31kt in 2023b).

The higher emissions and intensity in 2024 are

primarily from flaring due to operational issues in

our Tangguh operations and increases as a

result of a temporary operating mode, which

were quantified as a result of improvements in

our measurement methodology. Our real-time

methane emissions data, together with our

increased technical understanding of methane in

flares allowed us to identify this abnormal

situation in Tangguh, but, generally, analysis of

our 2024 measured data shows that overall

methane emissions from upstream operational

flaring were lower than previously reported using

conventional methodologies (including those

mandated by some countries). Marketed gas

volumes increased by 8.5% to 3,614bcf in 2024.

We continue to work to reduce operational

methane emissions. 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

aScope 2 emissions on a market basis.

bIn 2024 reported absolute methane emissions from upstream major 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.

cPreviously reported figures for the period 2019-2023 have been restated to update the 2019 baseline and the years 2020-2023 in line with the updated methodology for the net zero sales metric. For

more detail on how this metric is calculated see the Basis of Reporting: bp.com/basisofreporting.

dThe 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 2024.

eIncludes biofuels and biogas.

fCovers all power, including renewable and non-renewable.

gCommodity groups in 2024 are Oil/Refined Products, Gas/NGLs, Biofuels, Biogas, Power/Heat.

hOn the updated methodology basis.

iIn February 2025 bp announced that we have retired the concept of transition growth« engines going forward.

jExcludes deferred consideration for 2024 acquisition of bp bioenergy in 2025.

lifecycle carbon intensity of the energy

products« we sell by 2050 or sooner. We are

targeting a reduction in intensity of 5% by the end

of 2025. Informed by our strategy reset, and a

range of assumptions, we are aiming for an

8-10% reduction by the end of 2030 compared to

the 2019 baseline. This is an adjustment to

our previous aim of 15-20% against the 2019

baseline.

We have updated our net zero sales

methodology to follow a net volume accounting

approach, guided by Ipieca’s sectoral guidance

(2016) for Scope 3 reporting. The approach

focuses on identifying the point, for bp, where the

largest amount of sold energy products is

transferred within a given commodity’s value

chaing. We believe this will better reflect and

track our strategic progress over time, see

bp.com/basisofreporting.

In 2024 the average carbon intensity of our sold

energy products« was 79gCO2e/MJh. This

represents a 6% reduction from our 2019

baseline, driven by improvements in the well to

tank (WTT) emissions of sold products and

changes in the sold product mix, which have

included strategic investment activities such

as the addition of a signification retail power

volume as a result of the EDF Energy Services

acquisition in 2022 in the US.

Net zero production and

transition investment

We have retired our aim related to the estimated

Scope 3 (category 11) emissions from the

carbon in our upstream oil and gas production«.

The estimated Scope 3 emissions from the

carbon in our upstream oil and gas production

were 322MtCO2 in 2024 – an 11% reduction

relative to our 2019 baseline and a slight

increase from 315MtCO2 in 2023. This increase

was mainly associated with an increase in

underlying production due to the ramp-up of

major projects« and higher asset performance.

We have retired our aim for more investment into

the transition. In 2024 transition growth

investment« i was $3.7 billion, compared

with $0.6 billion in 2019 and $3.8 billion in 2023.

It represents around 23% of total capital

expenditure« in both 2023 and 2024, compared

with around 3% in 2019.

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 20.

We will continue to provide guidance on a


Khazzan gas field, Oman

periodic basis about production volumes and our

capital frame. As announced in February 2025,

we now expect to invest between $1.5-2.0 billion

per year through 2027j in what we now refer to

as our transition businesses« TCFD.

Advocacy related to net zero

While we have retired our previous advocacy aim,

our work in 2024 focused on several themes in

support of our net zero ambition, including

carbon pricing, and policy frameworks that

support growth in low carbon hydrogen, carbon

capture and storage (CCS), renewables,

decarbonizing transport (including EV charging)

and bioenergy.

We publish examples of our activity online at

bp.com/advocacyactivities.


Key
TCFD	TCFD Recommendations and Recommended Disclosures


40		bp Annual Report and Form 20-F 2024






Sustainability continued

Net zero aims 2024 performance


Aims	Measure/coverage	2024 performance	2025 targets	2030 aims	Aims for 2050 or sooner

Net zero operations«	Scope 1 and 2«	38%a	20%a	45-50%a	Net zero«

Net zero production«	Scope 3«	11%a	–

Net zero sales«	Average lifecycle carbon intensityb	6%cd	5%d	8-10%d	Net zero«

Reducing methane	Methane intensity«	0.07%e	0.20%	Now embedded into net zero operations

More $ into transition	Transition growth investment«	$3.7bn	–

aReduction in absolute emissions against 2019 baseline.

bAverage lifecycle carbon intensity of our sold energy products«.

cPreviously reported figures for the period 2019-2023 have been restated to update the 2019 baseline and the years 2020-2023 in line with the updated methodology for the Net zero sales metric. For more

detail on how this metric is calculated see the Basis of Reporting: bp.com/basisofreporting.

dReduction 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.

eIn 2024 reported absolute methane emissions from upstream major 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.




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 2024 at bp.com/ESG.
Operational controlab	Unit	2024	2023	2022
Scope 1 (direct) emissions	MtCO2e	32.8	31.1	30.4
UK and offshore	MtCO2e	1.0	1.0	1.0
Global (excluding UK and offshore)	MtCO2e	31.8	30.1	29.4
Scope 2 (indirect) emissions – location-based	MtCO2e	2.4	2.0	2.1
UK and offshore	MtCO2e	0.02	0.02	0.02
Global (excluding UK and offshore)c	MtCO2e	2.4	1.9	2.0
Scope 2 (indirect) emissions – market-based	MtCO2e	0.8	1.0	1.4
UK and offshorede	MtCO2e	0.02	0.0	0.0
Global (excluding UK and offshore)f	MtCO2e	0.8	1.0	1.4
Energy consumptiongb	GWh	129,872	124,770	121,697
UK and offshore	GWh	4,526	4,688	4,376
Global (excluding UK and offshore)	GWh	125,347	120,082	117,321
Ratio of Scope 1 (direct) and Scope 2 (indirect) emissions to gross productionh	teCO2e/te	0.16	0.16	0.15
UK and offshore	teCO2e/te	0.13	0.13	0.12
Global (excluding UK and offshore)	teCO2e/te	0.16	0.16	0.15

a Operational control data comprises 100% of emissions from activities operated by bp, going beyond the Ipieca guidelines by including emissions from certain other activities such as contracted drilling activities. Read more at bp.com/basisofreporting. b Due to rounding, some totals may not agree exactly to the sum of their component parts. c 2022 restated due to IEA emission factor library update. d 2023 reflects REGOs that 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 31 July 2024. e 2024 reflects REGOs that 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 31 July 2025. f 2022 restated due to consistency of rounding. g 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. h Gross production comprises upstream production, refining throughput and petrochemicals produced.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		41




		Strategic report




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 2024 we completed energy efficiency reviews in three production regions: Azerbaijan, Georgia and Türkiye, Trinidad and Tobago, and the Gulf of America, US. We started an energy efficiency programme in our refining business, and two refineries, Whiting, US and Rotterdam, Netherlands, have completed it. We expect to complete reviews for the remaining production regions and refineries in 2025. Identified opportunities will be advanced through our existing business processes and plans that support our net zero ambition. In 2024, a total of 27 new emission reduction projects contributed to reductions of 0.42MtCO2e. This is in addition to the 172 emissions reduction projects and the associated reduction of 0.9MtCO2e in 2023. These projects are tracked based on GHG reductions and include energy efficiency improvements. Emission reduction projects implemented by our businesses in 2024, included low carbon energy consumption projects, which delivered 102ktCO2e in emissions savings. These reductions were primarily delivered in bpx energy, US and included electrification projects and installation of solar pumps. Emission savings of ~262ktCO2e were achieved through energy efficiency improvements in production processes and flaring process optimization projects during 2024. These included: •Our Gelsenkirchen refinery replaced imported steam from a coal-fired power plant with steam produced in our own gas- fired boilers, reducing emissions by 19ktCO2e. •bpx energy’s central distribution projects, Karnes and Bingo, enabled decommissioning of legacy natural gas- driven equipment, resulting in reduced flare volumes and the switch from natural gas to instrument air in pneumatic devices. •Restoration of cooling water infrastructure at Cherry Point to reliably meet refinery needs and improve the efficiency of compressor operations.	Other types of reduction projects delivered a total reduction of 56ktCO2e, including the hydrocracker improvement project at Cherry Point, US, which saved 26ktCO2e of emissions. 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 realize 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 Ipieca, API, IOGP Petroleum Industry Guidelines and the GHG Protocol for Reporting GHG Emissions. 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 40. 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 2023. 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.


42		bp Annual Report and Form 20-F 2024






Climate-related financial disclosuresa

We support the recommendations of the Task Force on Climate-related Financial Disclosures

(TCFD), established by the Financial Stability Board to improve the reporting of climate-related

risks and opportunities.

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 2024 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 to inform our own scenario analysis

on page 53.

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 2024c.

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 47, 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 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 2024 scenarios (described on page 7),

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.

Governance



	TCFD Recommendation: Disclose the organization’s governance around climate-related issues and opportunities.



	Recommended Disclosure: a. Describe the board’s oversight of climate-related risks and opportunities. b. Describe management’s role in assessing and managing climate- related risks and opportunities.

The board’s role

One of the core roles of the board is to promote

the success of the company for the benefit of its

shareholders as a whole while having regard to

various factors, including the interests of our

other stakeholders and the impact of our

operations on the environment and the

communities where we operate.

In performing this role, the board sets and

monitors bp’s strategy. It is responsible for

monitoring bp’s management and operations

and obtaining assurance about the delivery of

its strategy.

Any changes to the company’s purpose, strategy

and values (which we call ‘Who we are’) are

reserved for the board for approval in

accordance with the board-approved corporate

governance framework.

The board’s responsibilities extend to oversight

of bp’s internal control and risk management

framework, including climate-related risks

and opportunities, as set out in the terms of

reference of the board, available online at

bp.com/governance.

The board considers that our strategy allows bp

to be flexible to adapt to the evolution of the

external environment, including market changes,

to remain consistent with the Paris goals, see

page 21.

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 43.

Climate-related risks and opportunities were

discussed at each board meeting covering

strategy in 2024, and the committees considered

climate-related issues where appropriate to do so

in fulfilling their responsibilities. Oral 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.

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 2024 analysis used data from the WBCSD Climate Scenario Catalogue version 3.0, published on 16-05-2024 and downloaded on 13-11-2024.

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 2024.

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/publication.

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 low carbon transition.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		43




		Strategic report

Learning and development

The board continues to develop its knowledge and expertise on climate-related and sustainability matters. For example, in 2024, 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, Net Zero Teesside Power and H2Teesside. 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 2024 in July 2024. 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 2025.

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, six 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 71.

•Dame Amanda Blanc is the current serving

CEO at Aviva plc and has held several

executive roles across the industry. She was

co-chair of the UK Transition Taskforce and

Principals Group Member of Glasgow

Financial Alliance for Net Zero (GFANZ).

•Helge Lund has extensive experience in the

energy sector and deep knowledge and global

experience including stakeholder

considerations regarding climate change risk

and opportunities. He has chaired the board

through the development of bp’s strategy and

net zero ambition and continues to have

oversight of the delivery of that strategy. He

served as a member of the UN Secretary-

General’s Advisory Group on Sustainable

Energy from 2011 to 2014.

•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. As CEO of United Spirits

Limited (Diageo plc’s listed Indian subsidiary),

she has overseen 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 energies 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 EoN, where under his

leadership, it split its hydrocarbons and non-

hydrocarbons businesses – giving him

significant experience of considering climate-

related risks and opportunities. He has sat on

bp’s safety and sustainability committee

since 2021. He is a director of Alpiq Holding

AG, a Swiss energy services provider and

electricity producer in Europe.




	Board and committees’ consideration of climate-related issues For examples from the year ended 31 December 2024, see the text indicated with TCFD on the pages set out below.
	The board

		pages 76-77
	Safety and sustainability committee

		pages 80-81
	Audit committee

		pages 82-85
	Remuneration committee

		pages 88-110


44		bp Annual Report and Form 20-F 2024






Climate-related financial disclosures continued

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 61 for more information on risk

governance and oversight.

2024 activity

Where considered appropriate, climate-related

risks and opportunities were discussed at bp

leadership team meetings in 2024 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 61. 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 TCFD 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 sustainability committee		Provides oversight, challenge and support in the implementation of bp’s sustainability frame and the management of potentially significant non-operational sustainability (including climate-related) risks and opportunities. It met four times in 2024. During 2024 the committee considered progress embedding sustainability, performance against targets and bp’s position on certain strategic sustainability issues that present risks or opportunities to delivery. This committee is chaired by the EVP strategy, sustainability & ventures (SS&V) and comprises members of the bp leadership team. The outputs from the committee are shared with the board and its committees, including the safety and sustainability committee, as appropriate.
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 financial risk committee		Monitors the effectiveness of bp’s financial reporting, systems of internal control and financial risk management, namely material group financial risks. Where appropriate, it considers the planned approach to assurance and verification of non-financial reporting ahead of updating the audit committee.




	Acquired businesses
	Integration plans are developed to transition acquired businesses into bp’s system of internal control, over an appropriate timeframe.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		45




		Strategic report

Climate governance: management of climate-related matters

As at 1 January 2025

bp board level

Board

Safety and sustainability

committee

Audit committee

People, culture and

governance committee

Remuneration committee

EVP level

CEO

Group sustainability

committee

Chair: EVP SS&V

Resource commitment

meeting

Chair: CEO

Group operational

risk committee

Chair: CEO

Group financial

risk committee

Chair: CFO

bp leadership team

SVP level

Sustainability forum

Chair: SVP sustainability

Focuses on sustainability plans and progress.

Production & operations carbon 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.

Issues and advocacy meeting

Chair: SVP external affairs, C&EA

Focuses on policy and advocacy issues, including those

related to climate matters.

Cross bp forums and meetings

Meetings and forums to allow cross-group discussions, integration and implementation.

Risk Management



	TCFD Recommendation: Disclose how the organization identifies, assesses and manages climate-related risks.



	Recommended Disclosure: a. Describe the organization’s processes for identifying and assessing climate-related risks.

bp’s risk management system and policy,

described on page 61, 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.

aInformation added to satisfy the UK CFD Regulations.

The process for identifying risks is outlined on

page 62 and guidance to support consistency

has been made available to our businesses to

provide them with a climate-related framework

and 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 62 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 47, 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 2024 (see page

7), which helps inform our core beliefs about the

energy transition. Business opportunities

continue to be originated across bp, and taken

forward through bp’s investment governance

framework, see page 21.

Our gas & low carbon energy business is

accountable for the delivery of many of our low

carbon opportunities through both organic and

inorganic growth (see page 62). 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.


46		bp Annual Report and Form 20-F 2024






Climate-related financial disclosures continued



	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 63. 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, in 2024 we implemented a screening

approach to support identification of potential

severe weather and physical climate-related

hazards at operational sites. Screening was

conducted for a number of onshore sites and,

where potential hazards have been 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

scarcity 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 60.

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 48. However, we continue to assess and

manage the component parts of those broad

transition risks, including:

Policy and legal risks

Our policy team monitors policy trends and

leads the definition of policy positions in line

with bp’s strategy and sustainability aims.

They work with our regional organization 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 sustainability committee 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

manage corporate reputation through

identification and monitoring of key issues and

both proactive and reactive engagement with

relevant stakeholder groups to communicate

bp’s positions. The team also leads advocacy

campaigns for policies that support net zero, see

page 39.

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 assessments and

disruptive technology reports for review by bp

senior executives and the recommendations are

overseen by the bp leadership team, through the

Innovation Advisory Council. In appropriate cases

this helps to underpin and appraise the business

case for new investments, new partnerships, new

customer offers or new business models where

these are being driven by technology innovation.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		47




		Strategic report

Strategy



	TCFD Recommendation: Disclose the actual and potential impacts of climate-related risks and opportunities on the organization’s business, strategy and financial planning where such information is material.



	Recommended Disclosure: a. Describe the climate-related risk and opportunities that the organization has identified over the short, medium, and long term.

In setting and monitoring delivery of bp’s strategy,

the board and leadership team consider climate-

related risks and opportunities across the:

•Short term (to 2025): 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 45.

Climate-related transition risks

and opportunities

At a group level, we have identified three broad,

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.

material climate-related transition risks, outlined

on page 48, 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 48 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 65. 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 rise, 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 2024 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 60.

We support the goals of the Paris Agreement and

believe that the best mitigation against these

types of physical risk is to seek to contribute

along with others to the success of global

climate mitigation efforts. Our strategy seeks to

position us to make such a positive contribution.

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.



	Recommended Disclosure: b. Describe the impact of climate- related risks and opportunities on the organization’s businesses, strategy, and financial planning.




	bp’s plans for the energy transition
	In this section we talk about some of our plans for the transition across bp’s business areas and where we do so we have identified these with TP.b 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 2024 performance, see page 9. Our progress against our net zero aims are described on pages 38-39.

TP Our strategy, together with our net zero

ambition and aims (see page 40), has been

informed by various inputs, including the

climate-related risks and opportunities

associated with the energy transition

described above; the same is true of our

financial and business processes. We

describe how we use scenarios to inform

our strategy on page 7.


48		bp Annual Report and Form 20-F 2024






Climate-related financial disclosures continued

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, demand and/or prices for oil and natural gas and refined products 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 we seek to grow our low carbon businesses 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 aim to advocate more actively for policies that support net zero, including carbon pricing (see page 39). 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 2024 (as described on page 7) 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 the next 10-15 years. This requires continuing investment in upstream oil and natural gas. The insights from the bp Energy Outlook 2024 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.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		49




		Strategic report

Oil and gas

As announced in February 2025, we are

increasing upstream investment versus our prior

guidance. This additional investment allows us to

strengthen the portfolio, for example the

redevelopment of several giant oilfields in Kirkuk,

Iraq, page 32, underpinning 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, but in

recent years we have made strong progress

improving operational reliability and

commerciality across our portfolio, and we retain

optionality to divest some lower margin barrels

by 2030. We intend to maintain the disciplined

application of our balanced investment criteria,

which include the consideration of hurdle rates of

15% from a balanced 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 38-39.

TP Customers and products

As announced in February 2025, we are focusing

the downstream – our customer and 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. We are

also increasing the resilience of our existing fuels

network, high-grading our regional footprint and

reallocating capital into our most advantaged

positions on major transit routes where we see

sustained demand for fuels and EV growth. Since

2020 we have announced our exit from two retail

markets, and the sale of another. 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.

We are also leveraging our brand in the fast-

growing synthetics segment and building

exposure to the growing industrial segment. 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. We recently 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 (such as our strategic collaboration

with Corteva aimed at producing and delivering

crop-based biofuel feedstocks) also provide

additional resilience and opportunity to

anticipated supply shortages in the transition,

see page 35.

At our refineries, the energy transition could

impact demand for certain products in the future,

potentially leading to lower margins and requiring

less efficient refineries to be retired.

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 (see our announced plans to market the

Gelsenkirchen complex for example (page 35))

and building resilience through value chain

integration (US, Spain) and future biofuels.

TP Low carbon energy

Recent volatility and uncertainty has impacted

low carbon energy businesses globally,

demonstrating 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 renewable power we now have the

Lightsource bp platform, and have announced an

agreement to form another – JERA Nex bp.

Recognizing the exposure to transition volatility

seen in recent years, JERA Nex bp plans to focus

on highly disciplined, capital efficient growth. We

will also maintain access to our equity share of

power offtake to support our own growing

internal demand. Lightsource bp is now scaled to

deliver 3-5GW annually, backed by around 50GW

mature pipeline with further potential to scale

while remaining capital-light for bp.

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

(see page 23) and have a strong pipeline with

which to respond to future demand growth.

TP Supply, trading and shipping (ST&S)

Our ST&S business provides risk management,

flow and optimization services to our bp equity

and assets, with a proven track record of

resilience to commodity cycles and the ability to

capture upside when market conditions present

greater opportunities.

Our diversified 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,

while our LNG portfolio offers flexibility through

our advantaged key global positions.

Together with traditional hydrocarbons, we are

positioned to access growth markets, creating

diversification and greater resilience across

power, biogas, biofuels and adjacent agriculture

commodities. Our power trading business allows

us to optimize across the value chain from

generation across grid markets to customers.

This helps position us for further electrification of

the energy system as well as further

decarbonization of electricity.

Through Archaea, we believe we are uniquely

positioned in the US to meet growing demand for

biogas as the transition progresses. Our

business is integrated across the value chain,

enabling us to capture rent as the market

evolves. 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.

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 low carbon energy businesses. See page 36

for examples of technology investments in 2024.

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 may help enable the transition to a low

carbon economy, including increasing focus on

oil and gas technologies.


50		bp Annual Report and Form 20-F 2024






Climate-related financial disclosures continued

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

historic 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 45 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 undertaken 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 (see page 60), we are

taking steps to be more efficient in operational

freshwater use (read more about water use on

page 60).

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

2025 we announced that we expect capital

expenditure to be around $15 billion in 2025; and

in a range of $13-15 billion through 2026 to 2027.

To help maintain resilience to the pace of

transition and access opportunities, we will

continue to flex capital as policies, technologies

and markets evolve.

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.

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 our balance sheet, introducing a

net debt target of $14-18 billiona by the end of

2027 to further improve credit metrics within the

‘A’ range. In 2022 we reduced our net debt by

over $9 billion and by a further $0.5 billion in

2023. In 2024 net debt increased from

$20.9 billion to $23.0 billion, reflecting acquired

debt from the bp Bunge Bioenergia and

Lightsource bp transactions. Since the end of

2019 we have repurchased around $24 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.

Additionally, we have continued to have good

access to the commercial paper markets. 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 investment criteria - for

example 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, that rises from 2025 levels to $135/

teCO2e (2023 $ real) in 2030.

When taking investment decisions we continue

to consider six balanced investment criteria –

including sustainability (see page 22).

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 WBCSD 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.



	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 2023, 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. 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, margin or demand – which

would represent a principal transition driver

of such risk.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		51




		Strategic report

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 80% 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 53.

–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 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 – 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 full period from 2026 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 stronger balance sheet that improves our

credit metrics within the ‘A’ grade range;

ii.resilient dividend and sharing of excess cash

with shareholders through buybacks over

time; and

iii.disciplined investment allocations within our

capital frame.

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.

bNote 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.

cOur multi-year (2026-30) oil price resilience test considered sustained low oil prices consistent with the most extreme WBCSD Scenario Catalogue 2025 and 2030 scenarios – for 2025 the UN PRI

(Inevitable Policy Response Forecast Policy Scenario) at $54/bbl, and for 2030 the UN PRI (Inevitable Policy Response Required Policy Scenario) at $34.2/bbl (both 2022 $ real, and then inflated in line

with bp’s other planning assumptions, and intervening years interpolated between the two years).

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

controllable 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.

Our approach, described in more detail on

page 53, 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 – each is necessarily

dependent on numerous assumptions and

methodological choices, and each has 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, and in

particular, as our greatest transition exposure, to

oil price scenarios, tested to 2030.

In undertaking this analysis we observed:

•There is considerable uncertainty across,

and often within, each WBCSD 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 54). 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 price 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

contribution to our expected total adjusted

EBITDA over this period, that oil-price-linked

businesses representa. In the 1.5°C family, the

potential downside suggested by the lowest

oil prices is around 30% of group adjusted

EBITDA in 2030. However, in a number of the

scenarios based on the WBCSD Scenario

Catalogue ranges, including those consistent

with 1.5°C, well-below 2°C and BAU families,

oil price could offer a financial upside relative

to our reference 2030 group business

outlook.

•Even with the most extreme low oil price

environment in any of the scenarios,

sustained over the period from 2026-30b and

taking into account our ability to optimize

within the frames set out in our strategy

(above), and the spend mitigations that we

would naturally be expected to see or 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.

•The maximum potential scale of downside

impact on our 2030 expected group adjusted

EBITDA (across the 1.5°C, well-below 2°C and

BAU scenarios) from our other natural gas

businesses was around 5%, while from each

of our conventional refining, fuels and low

carbon activities« was modelled to be <3%.

•Our diversified portfolio helps mitigate the

implications for our strategic resilience of the

exposure of any one of the individual

business areas to the identified risk. It is

reasonable to consider each potential

outcome in isolation since the outcomes for

different business areas vary across

scenarios (see table on page 54).

•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 growth of any one of

our in-scope transition business« areas be

challenged by the downside range in the

relevant variable, 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, in that timeframe.

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.


52		bp Annual Report and Form 20-F 2024






Climate-related financial disclosures continued

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 50, 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 47, 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 do 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

combined oil and gas portfolio would need to be

either permanently or temporarily shut in for

strategic 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 50), 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, and the associated potential

financial impact.

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.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		53




		Strategic report




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 (see below), we also assessed resilience over the period 2026-30. 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 current deterministic view of our portfolio, activity set, cost and capital frame. The outlook used in our analysis aligned to the strategic direction shared at the 26 February 2025 Capital Markets Update, and the financials are assessed against the financial priorities set out in that announcement. The steps we took as part of our scenario analysis approach are outlined here at a high level. 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)’). This was performed to allocate the most appropriate analysis technique to that business (see 1b and 1c). b.Eleven business areas (see table on page 54), representing over 80% of our expected 2030 adjusted EBITDA, were identified as both providing a potentially significant financial contribution and facing primary transition risk drivers, and accordingly were subjected to the driver- based scenario analysis set out in steps 2a-2c below. c.The remaining business areas were taken forward to a simplified scenario analysis, per step 2d below.	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 (that includes 1.5°C and current policies), or by ’simplified’ conservative scenario analysis, that modelled cases likely to be beyond these ranges. a.For the driver-based scenario analysis, we selected the primary transition risk driver(s) for each business area – the variable(s) from the WBCSD Scenario Catalogue representing what we consider to be the primary driver(s) of that business area’s 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 54). b.By calibrating the WBCSD Scenario Catalogue 2030 scenarios to relevant business metrics underpinning our strategic planning (for example, oil price or EV demand/utilization), we modelled the impact of each variable, across the full range of scenarios and each scenario family, on the 2030 expected earnings (adjusted EBITDA) for the associated business area(s). For example, we applied an earnings rule of thumb deemed appropriate to the period in question to the deviation of oil prices in WBCSD versus our reference case price. This analysis was unmitigated (see ’Other key considerations’). c.This enabled us to assess the potential for each scenario to materially impact group adjusted EBITDA in 2030 (and by implication associated cash flows), against the reference group business outlook. By modelling the specific business area within the reference group business outlook (described in step 1b above), its exposure to the most extreme range of the respective scenario could be assessed to identify which (if any) variables(s) and scenario(s) could have the potential to impact strategic resilience (as defined below) most materially, and as such, which business areas should be carried forward into a multi-year resilience assessment. d.For the simplified scenario analysis, 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 at least	as detrimental to that business area’s adjusted EBITDA as could reasonably be expected to result from ranges associated with the trajectory of each of the 1.5°C, 2°C or BAU scenario families – could have the potential to impact strategic resilience (as defined below) materially. 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 surplus cash flow« and a strong cash cover ratio and gearing level – financial metrics that were treated for the purposes of the analysis as representing financial evidence of delivery of bp’s strategic financial priorities (see below). From step 2, in 2024, only the exposure to oil price was assessed as sufficiently material in this sense, and hence carried forward for multi-year resilience analysis. Our multi- year (2026-30) oil price resilience test considered sustained low oil prices consistent with the most extreme WBCSD Scenario Catalogue scenarios – interpolating between the minimum price for 2025 (the UN PRI Inevitable Policy Response Forecast Policy Scenario) at $55.0/bbl, and the minimum for 2030 (the UN PRI Inevitable Policy Response Required Policy Scenario) at $34.2/bbl (both 2022 $ real). Other scenarios, from providers such as IEA and NGFS, formed part of the WBCSD data set, but indicated higher prices than the UN PRI cases used. 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 51. We defined the following as proxy indicators for these lenses: –Positive group surplus cash flow, to demonstrate whether after funding, among other things, capital spend within our disclosed capital frame (26 February 2025 Capital Markets Update) and a resilient dividend per ordinary share, sufficient surplus cash flow remains to maintain or reduce net debt and such that excess cash can be shared with investors through share buybacks over the period. –Healthy cash cover ratio and gearing« as indicators of the ability to maintain a strong investment grade credit rating.


54		bp Annual Report and Form 20-F 2024






Climate-related financial disclosures continued



•For steps 2 and 3, we made the simplifying assumption that, aside from the driver being modelled, our strategy, operating model, cost basis, volumes, margins, sales proceeds and tax rates would remain unchanged out to 2030a. •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, distributions, 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.	•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. •As outlined above, we utilized our latest internal reference group business outlook as the basis against which resilience has been tested, as this is our latest deterministic view against which to model the transition sensitivities to 2030 and aligns to the strategic update provided to investors in February 2025. Alongside disclosed elements such as the capital frame range to 2030, this includes shaping assumptions such as future distribution and net debt management.	•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 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). •Where rules of thumb have been applied, to convert variance in hydrocarbon price to variance in adjusted EBITDA, these are deemed appropriate to the period in question – i.e. they reflect the portfolio’s 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.



WBCSD Scenario Catalogue family ranges for 2030 key transition variables
			BAU		Below 2°C		1.5°C
Business area		TCFD/WBCSD variable	Min	Max	Min	Max	Min	Max
Oil and natural gas production		Oil priceb ($2022/bbl)	63.67	85.00	50.00	77.34	34.2	71.12
Oil and natural gas production		Natural gas pricec ($2022/mmbtu)	3.77	4.38	2.50	4.38	2.40	5.24
Refining	– refined oil demand	Primary energy demand for oil (% vs 2020)	-0.2	14.2	1.6	6.4	-18	-1
Refining	– biojet demand	Final demand for liquid biofuels in aviation (EJ/yr)	0.16	0.5	0.16	1.01	0.25	1.51
Biogas		Biogas demand in road transport (EJ/yr)	0.00	0.19	0.01	0.29	0.00	0.35
bp bioenergy		Biofuel consumption in transport (EJ/yr)	0.84	6.05	0.84	7.08	1.45	7.12
EV charging		Final energy demand for electricity in road transport (EJ/yr)	3.02	6.97	3.86	6.90	3.64	7.08
Aviation fuel sales		Liquid fuel consumption in aviation (EJ/yr)	14.67	16.99	13.85	16.91	11.94	14.61
Conventional fuels retail		Final energy demand for liquid oil in road transport (EJ/yr)	75.09	81.65	74.35	76.82	59.00	73.41
Conventional fuels midstream
Conventional road lubricants
Renewables		Renewable capacity additions (GW vs 2020)	3,969	7,217	3,024	8,223	4,002	10,473
Hydrogen production		Hydrogen consumption (Mt/yr)	3.97	12.67	4.18	25.45	5.68	70.00

For the other business areas not shown above, we applied the generic scenario analysis methodology described in point 2d on page 53, thereby ensuring

coverage of all of bp’s business areas.

aFor the purposes of resilience testing, Castrol is included in the underlying reference plan being assessed, pending the outcome of its strategic review.

bOil 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.

cGas prices shown reflect Henry Hub price ranges. Where available in the TCFD/WBCSD data sets 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.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		55




		Strategic report

Metrics and targets



	TCFD Recommendation: Disclose the metrics and targets used to assess and manage relevant climate- related risks and opportunities where such information is material.

We present the principal group-wide metrics and

targets used to assess and manage climate-

related risks and opportunities in line with our

strategy and risk management process below,

with metrics and targets mapped to the most

relevant of TCFD’s cross-industry, climate-related

metric categories (such as ‘transition risks’).

The metrics and targets themselves are

disclosed at the most appropriate locations in

this strategic report.




	TCFD recommended disclosures – metrics and associated targets/goals
	a) Disclose the metrics used by the organization to assess material climate-related risks and opportunities in line with its strategy and risk management process.		c) Describe the targets used by the organization to manage climate-related risks and opportunities and performance against targets.
	Transition risks
	•Note 5 to Financial statements: Segmental analysis. Segment revenue (in table), pages 167-171 •Estimated net proved reserves and production (net of royalties), page 37 •Note 4 to Financial statements: Disposals and impairments, page 164 •Note 8 to Financial statements: Impairment losses (in table), page 172 •Oil and natural gas prices used for value-in-use impairment testing and recoverability of asset carrying values, page 152.		Net zero operations« (including methane), page 38 Net zero sales«, page 39
	Physical risks
	•Number of major operating sites in regions with high to extremely high water stress, page 47 •Freshwater withdrawals and consumption at major operating sites in regions with high or extremely high water stress, page 60		Water, page 60
	Climate-related opportunities
	•2024 metrics, page 9 (in table with TCFD) •Note 5 to Financial statements: Segmental analysis. Segment revenue (in table), pages 167-171 •Renewables – installed capacity, developed to final investment decision and pipeline, page 28		Net zero operations (including methane), page 38 Net zero sales, page 39
	Capital deployment
	•Financial frame, page 18 •Price assumptions, key investment appraisal assumptions, page 20 (in table, indicated with TCFD) •Amount invested in transition, page 39 •Additional information – capital expenditure by segment, page 312 •Note 7 to Financial statements: expenditure on research and development (in table), page 171 •Note 8 to Financial statements: exploration and evaluation costs (in table), page 172		Investment in non-oil and gas, page 21 Transition investment, page 39
	Internal carbon prices
	•Internal carbon price, page 20
	Remuneration
	•Directors’ remuneration report metrics: operated carbon emissions, page 96		Incentivizing employees, page 59
	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 14a •Scope 1 and 2, in SECR table page 40 •Ratio of Scope 1 and 2 emissions: gross production, in SECR table page 41 •Scope 3 (related to category 11) emissions page 39b •TCFD: risks as described in Strategy A, page 47 •Risk factors, page 65 •A further breakdown of our GHG and energy data by business group is available in the bp ESG Datasheet 2024 at bp.com/ESG.		Net zero operations (including methane), page 38 Net zero sales, page 39

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. For 2024, the relevant target that we used in respect of Scope 3 emissions was bp’s net

zero production« aim (aim 2), which was aligned to category 11 of Scope 3.


56		bp Annual Report and Form 20-F 2024






Sustainability continued

Our approach to sustainability

Our approach to sustainability is built on strong foundations that guide the way we work 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 fatality and four life-

changing injuries that occurred at bp in 2024. In

October, an employee of our recently acquired bp

bioenergy business in Brazila was fatally injured

during an operational activity. In May, a

contractor in our wells business in Trinidad and

Tobago and an employee at our TravelCenters of

America business in the USb suffered life-

changing injuries during manual activities. In

September, at our Thorntons retail business in

the US, two employees suffered life-changing

injuries during an incident with a member of the

public who was carrying a firearm.

We have offered our support to the employees

and families affected. We want to learn from

these incidents to help drive further

improvements in safety.

Keeping people safe

We monitor and report on key workforce

personal safety metrics in line with industry

standards. We include both employees and

contractors in our data.

In 2024 our recordable injury frequency (RIF)

increased by 8.5% compared to 2023. bp

businesses have identified underlying themes for

these injuries and developed plans intended to

help reduce then in the future.

In 2024 following the roll-out of International

Association of Oil & Gas Producers’ (IOGP)

Life-Saving Rules to help improve safety

performance, we started measuring their

effectiveness in operational businesses that

implemented them in 2023, and work continued

to embed them in other operational businesses

through safety inductions, team talks and control

of work systems.



	RIF key performance indicator, page 14

aIn October 2024 bp acquired the remaining 50% of bp Bunge Bioenergia. Shortly after the acquisition was completed, an incident occurred which resulted in a fatality. At the time of publication,

bp bioenergy safety processes were still being integrated into bp’s reporting processes, during an initial transition period for acquired businesses, and as such, this fatality is not included in reported

fatality data for 2024.

bAt the time of publication, during an initial transition period for these acquired businesses, Archaea Energy, TravelCenters of America, Lightsource bp and bp bioenergy safety reporting processes were

still being integrated into bp’s safety reporting processes and as such, their safety performance data is not included in reported data for 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.

Driving safety

Driving continues to be one of the biggest

personal safety risks we face at bp. In 2024 five

severe vehicle accidents occurred, a decrease

from seven in 2023. The number of kilometres

driven fell by 11% over the same period.


	2024	2023	2022
Severe vehicle accident rate per million km driven	0.022	0.023	0.037

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 meet local regulations or circumstances, are

subject to a governance processc.

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 carefully plan our operations with the aim of

identifying potential hazards and having rigorous

operating and maintenance practices applied by

capable people to manage risks at every stage.

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 generally decreased

over the last 12 years, apart from in 2019. Our

total reported PSEs for 2024 was 38 compared

to 39 in 2023. Although we reported more tier 2

PSEs, 35 compared with 30 in 2023, we reported

our lowest number of tier 1 PSEs in 2024 as 3

(2023 9).

Our central health, safety, and environment

incident investigations team investigates serious

or complex incidents, which may include near

misses, and we also use leading indicators, such

as inspections and equipment tests, to monitor

the strength of controls to prevent incidents.

In 2024 we made further progress in preventing

and reducing oil spills. There were 96 oil spills,

compared with 100 in 2023. Although portfolio

changes may affect the overall baseline of our

operations, our goal is still the elimination of

tier 1 PSEs.


	2024	2023	2022
Tier 1 and tier 2 process safety events«	38	39	50
Oil spills – number	96	100	108
Oil spills – contained	49	52	57


« See glossary on page 351		bp Annual Report and Form 20-F 2024		57




		Strategic report

Emergency preparedness

The scale and geographical spread of our

operations mean we must be prepared to

respond to a range of possible disruptions,

including emergency events. We maintain

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 2024 we conducted in the

region of 25 exercises in countries including

Indonesia 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

makes managing cyber risk a priority for many

industries, including our own. Direct or collateral

impact can come from a variety of cyber threat

actors, including nation states, criminals,

terrorists, hacktivists and insiders. As in previous

years, we have experienced threats to the

security of our digital systems and our barriers

have worked well to mitigate and contain them to

minimize any impact on our business.

We have a range of measures to manage this

risk, including the use of cyber security policies

and procedures, security protection tools, threat

monitoring and event detection capabilities, and

incident response plans. We conduct exercises

to test our response to, and recovery from, cyber

attacks. We collaborate closely with

governments, law enforcement and industry

peers to understand and respond to threats.

To encourage vigilance among our employees,

our extensive cyber security training courses and

awareness programmes provide regular

education on a wide range of topics such as

phishing and the correct classification and

handling of our information. We also use a

cyber barometer tool to empower individual

risk mitigation.



	How we manage risk, page 61 Additional disclosures – cyber security, page 336

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 2024	Male		Female		Female %
As at 31 December 2024	2024	2023	2024	2023	2024	2023
Board directors	5	6	6	6	55	50
Leadership team	5	4	5	7	50	64
Group leaders	186	193	100	102	35	34
Subsidiary« directors	519	384	253	174	33	31
All employeesa	62,000	51,800	38,300	35,900	38	41

Number of employees


As at 31 December 2024	2024	2023	2022
Gas & low carbon energy	6,500	4,800	4,200
Oil production & operations	9,200	8,800	8,600
Customers & productsb	73,100	63,400	44,700
Other businesses & corporate	11,700	10,800	10,100
Totalc	100,500	87,800	67,600
a Some employees have not disclosed gender, therefore are not included in this total. b This figure includes bp bioenergy, which bp took full ownership of in 2024. c For 2024, this figure reflects new acquisitions and companies we have taken full ownership of including bp bioenergy and Lightsource bp.

We aim to report on aspects of our business

where we are the operator – as we directly

manage the performance of these operations.

Where we are not the operator, our OMS is

available as a reference point for bp businesses

when engaging with other operators and co-

venturers. We have a group framework to assess

and manage bp’s exposure risks from our

participation in these types of arrangements.

Where appropriate, we may seek to influence

how risk is managed in arrangements where we

are not the operator.

The people, culture and governance committee

reviews workforce policies and practices and

their alignment with bp’s strategy, purpose,

beliefs and culture, and conducts workforce

engagement measures.



	People, culture and governance committee report, page 86


58		bp Annual Report and Form 20-F 2024






Sustainability continued

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 diversity, equity and

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 87.

Developing our people

Our people are crucial to delivering our purpose

and strategy. 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 2024 bp employees collectively completed

more than 1.2 million hours of formal learning

(2023 1.3 million hours). This learning takes

place within a development frame applicable

to all employees. It covers safety, technical,

leadership, digital and skills training relevant

to our businesses. Our development offer

also includes our mandatory curriculum

focused on compliance with applicable laws

and regulations as well as conformance with

bp’s internal standards.

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 December 2024 five of the 10 positions in our

leadership team were held by women. Our global

ambition is to reach gender parity for the top

levels of leadership (top 120 roles) by 2025 and

parity for all executive-level employees (group

leaders) by 2030. We also have a global ambition

of 40% female representation for the next layer of

senior leadership (senior-level leaders) by 2030.

In 2024 35% of group leader roles were filled by

women (2023 34%). We have made progress on

our ambition to increase minority representation.

In 2024 35% of our group leaders came from

countries other than the UK and the US

(2023 33%).



	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

and the Parker Review on page 71.



	Composition of the board, page 72 Diversity reporting in line with the Listing Rules, page 111

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

member of the bp leadership team and open to

all employees.

We aim to provide equal opportunity in

recruitment, career development, promotion,

training and reward for all employees –

regardless of ethnicity, national origin, religion,

gender, age, sexual orientation, marital status,

disability or any other characteristic protected by

applicable laws.

Supporting disabled employees

We continue to take steps to help improve

the experience of the workplace for our

neurodivergent employees and those with

disabilities, offering:

•Inclusive recruitment training, disability and

neurodiversity awareness sessions, as well as

specific internships and apprenticeships.

•Access to assistive technology support (such

as voice recognition software, screen readers

and AI software) for all employees.

•Improved accessibility in communications,

ensuring bp’s brand visual standards are

more accessible.

To help meet the requirements of our employees

we work closely with our employee-led disability,

neurodiversity and mental wellbeing 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 source talent,

assist with research and training and support

students with disabilities to build the skills they

need to access the workplace. Our partners

include the National Organization on Disability in

the US, and 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.

We monitor employee sentiment through 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 2024 our overall

engagement metric, employee engagement,

decreased to 70%, in line with 2022 levels

(2023 73%).

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 and our 2025 targets,

focusing on three areas to drive improvement –

psychological safety, competitiveness and

understanding of our strategy and performance.



	Our employee engagement key performance indicator, page 17 How the board engaged with the workforce, page 78

Workforce health and wellbeing

We include an employee wellbeing index in our

Pulse annual employee survey and weekly

Pulse live surveys. Results from 2024 showed

that employee wellbeing increased to 73%

(2023 72%).

We continued to take action to create

workplaces where people can talk openly about

mental health and get help if they need it, with

campaigns focused on wellbeing and inclusion.

We continued the roll-out of mental health

training targeted at group leaders, to progress

our 2025 aim to train 100% of leaders on key

mental health challenges.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		59




		Strategic report

Linking remuneration to

sustainability TCFD

Our annual bonus for all eligible employeesa,

including the bp leadership team, has been linked

to a sustainability measure since 2019.

The bonus scorecard for 2025 against which our

eligible employees are measured incentivizes

them through three themes: safety and

sustainability (30%, of which sustainability makes

up 15%); operational performance (15%); and

financial performance (55%). For 2025 our

sustainability measure is linked to our operated

carbon emissions. This measure covers Scope 1

and 2 emissions reported as part of our net zero

operations« aim (see page 38).

Our 2022-24 long-term incentive plan scorecard

also linked to our operated carbon emissions

performance and, for group leadersb, two social

measures were included.

As with the bonus scorecard, for 2025-27 we use

an absolute percentage reduction in operational

emissions against our 2019 baseline as the basis

for measuring progress against our net zero

operations aim in our long-term scorecard.



	Directors’ remuneration report, page 88

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 all for 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 standards and expectations

for how we do the right thing and empowers

our employees to speak up without fear

of retaliation. It is the foundation of ‘Who we are’,

our culture frame and puts safety first. Together

with our Safety Leadership Principles and OMS«,

our code helps us make safe and ethical

decisions, act responsibly, comply with

applicable laws and deliver on our sustainability

frame.

Our code applies to all bp employees, officers

and board membersc. Regular mandatory

training and communications help employees

understand how to apply our code and how to

raise questions or concerns.

All bp employees are required to confirm annually

aThe number of employees eligible for a cash bonus in 2024 was around 38,000.

bGroup leaders are our most senior leaders. Their roles include operational, functional and regional leadership.

cFor recently acquired businesses, there is typically a transition period while bp’s ethics and compliance standards, as required in our code, are integrated or aligned.

dSenior leaders are the leadership tier below group leaders. They typically manage larger teams or are recognized as technical or functional experts.

eThis total excludes exits of contractors, suppliers and vendors.

that they have read and understand our code and

complied 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 leadersd, and contacts in our

people & culture, ethics & compliance or legal

teams. We also have a confidential global

helpline, OpenTalk. It is available for 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. In most locations,

anyone has the right to contact OpenTalk

anonymously except where this is prohibited

by law.

Any instances where we believe individuals have

fallen short of our expectations, set out in our

beliefs, ‘Who we are’ and our code of conduct,

are taken very seriously and, where appropriate,

a formal investigation is carried out.

We may take action in response to reported

concerns to help proactively mitigate issues

around misconduct. We follow a defined

disciplinary process and will issue sanctions

where appropriate. These may include measures

ranging from coaching or training, formal

reprimands to dismissal.

We received more than 2,800 concerns or

enquiries through these channels in 2024 (2023

2,250). In 2024 around 250 separations resulted

from non-conformance with our code or

unethical behavioure.

As in 2023 the most frequently raised concerns

in 2024 related to bullying, harassment and

discrimination, with these accounting for

around 60% of all concerns. The second most

common concerns related to health, safety,

security and environment.



	bp.com/codeofconduct

Anti-bribery and corruption

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

our commitment to ethical and compliant

operations is unwavering.

Our code of conduct explicitly prohibits

engaging in bribery or corruption in any form.

Our group-wide anti-bribery and corruption

policies and procedures 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.

In 2024 around 5,900 employees completed anti-

bribery and corruption training as part of our

ethics and compliance risk-based learning. This

is lower than the 10,500 employees trained in

2023, 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 2024 we issued 32 ABC

supplier audit reports (2023 31).

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 the bp 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.

Tax transparency

Our code of conduct informs the responsible

approach we take to managing taxes. We have

adopted the B Team responsible tax principles

and we engage in open and constructive

dialogue with governments and tax authorities.

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 $10.6 billion in corporate income and

production taxes to governments in 2024

(2023 $11.9 billion).



	bp Tax Report, bp.com/tax


Key
TCFD	TCFD Recommendations and Recommended Disclosures


60		bp Annual Report and Form 20-F 2024






Sustainability continued

Trade associations

Trade associations play a key role in fostering

collaboration, sharing learning and bringing

stakeholders together. We periodically assess

the alignment of key associations with our

position on climate. In 2024 we reviewed 36 of

our most significant trade associations

memberships. We found that 29 associations

aligned with our climate positions, and seven

were ‘partially aligned’. Our priority is to influence

within trade associations, but we may publicly

dissent or resign our membership if there is

material misalignment on high-priority issues.



	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 58).

We support the goals of the Paris Agreement,

which recognize the importance of a just

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

through the energy transition and how we are

helping enable a just transition in the bp

Sustainability Report 2024.

Human rights

We believe everyone deserves to be treated

with fairness, respect and dignity. We strive to

conduct our business in a responsible way,

respecting the human rights of our workforce

and those living in communities potentially

affected by our activities.

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 is now using for stress is based on a water stress level of ‘high’ or above, as defined by the WRI Aqueduct Water Atlas. bp determines areas of water stress using either the WRI Aqueduct

Water 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 2020-2023 to reflect the exclusion of once through cooling water, including the 2020 baseline.

fThe restated 2020 baseline for freshwater withdrawal is 96.4 million m3 per year and for freshwater consumption is 55.9 million m3 per year.

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. In

2024 this included training for our procurement

teams to identify suppliers in high-risk goods and

high-risk services categories.



	bp.com/humanrights

Caring for the planet

We want to make a positive difference to the

environment in which we operate.

Biodiversity

We understand international concern regarding

the global decline in biodiversity and recognize

that our businesses can have impacts and

dependencies on nature.

We aim to support biodiversity where we

operateb, by:

•Aiming to achieve a net positive impact (NPI)

on all new in-scopec projects.

•Implementing biodiversity enhancement

plans at our major operating sites.

•Collaborating with others to support selected

biodiversity restoration projects.

Building on the work we did in 2022 to finalize

our NPI methodology for use on new, in-scope

projects, we have made consistent progress over

the past few years in our work to apply it. By the

end of 2024 seven of our projects were

developing NPI plans.



	bp.com/biodiversity

Water

We aim to reduce our net freshwater use in

stressed catchments where we operateb, by:

•Being more efficient with freshwater use in

our operations.

•Collaborating with others to replenish

freshwater in stressedd catchments.

We anticipate that by 2028, our freshwater

withdrawal in stressed catchments will be

covered by freshwater management plans.

To understand our water-related challenges, we

review water impacts, risks and opportunities at

our operating sites. These reviews consider the

quantity and quality of water used as well as any

applicable regulatory requirements.

Our water consumption in 2024

We saw a 15% fall in freshwater withdrawals

(excluding once through cooling water)e

and a 17% fall in freshwater consumption,

compared with our 2020 baselinef. Reductions in

2024 were achieved through the use of non-

freshwater sources in bpx energy Eagle Ford, US.

At our major operating sites, 11% (2023 73%) of

our total freshwater withdrawals and 20% (2023

36%) of freshwater consumption were from

regions with high or extremely high water stress

in 2024. This is significantly lower than 2023 due

to two changes. One refinery is in a region of

medium-high water stress and therefore no

longer reaches the threshold. Separately, we

reviewed the status of two other refineries using

site-specific local data sources in 2024, this

resulted in one of those refineries being

reclassified as not being in an area of high water

stress, the other reviewed refinery remained in an

area of high water stress.

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 2024 our total air emissions

were 9% lower compared to 2023.



	bp.com/ESGdata


« See glossary on page 351		bp Annual Report and Form 20-F 2024		61




		Strategic report

How we manage risk and risk factors

How we manage risk




	Our risk management activities
	The board and committees		Oversight and governance Set policy and monitor principal risks

	Leadership team and committees
	Leadership team and committees		Business and strategic risk management Plan, manage performance and assure

	Businesses and functions
	Businesses and functions
			Day-to-day risk management Identify, manage and report risks
	Facilities, assets and operations

bp manages, monitors and reports on the principal risks and uncertainties we have identified that can

impact our ability to deliver our strategy. These are described in Risk factors on page 65.

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.

bp’s risk management system

bp’s risk management system and risk

management policy are designed to provide a

consistent and clear framework for managing

and reporting risks from the group’s business

activities and operations to management and to

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 up the management chain and to the

board on a periodic basis on how principal

risks are being managed, monitored and

assured, with any identified enhancements

that are being made.

Risk oversight and governance

Our key risk oversight and governance

committees include:




	Board and committees
	•bp board. •Audit committee. •Safety and sustainability committee. •Remuneration committee. •People, culture and governance committee.


	Leadership team and committees
	•Leadership team meeting – for oversight and for strategic and commercial risks. •Group operations risk committee – for health, safety, security, environment and operations integrity 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. •Group sustainability committee – for non-operational sustainability risks. •Resource commitment meeting – for investment decision risks. •bp quarterly internal audit meeting – for assurance on the oversight of bp’s principal risks.


		bp governance framework, page 75, board activities, page 76 and committee reports, pages 80-90.




	Acquired businesses
	Integration plans are developed to transition acquired businesses into bp’s system of internal control and risk management framework, over an appropriate timeframe.


62		bp Annual Report and Form 20-F 2024






How we manage risk and risk factors continued

Day-to-day risk management

Management and employees at our facilities,

assets, and within our businesses (including

supply, trading and 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 do this by using a standard

framework for collating risk data, assessing risk

management activities, making further

improvements and in connection with planning

new activities.

Oversight and governance

Throughout 2024, 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. bp’s internal audit team provides

independent assurance to the chief executive

and board as to 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.

Risk management processes

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 organization.

•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 – businesses and functions

identify risks across the risk types. Risks are

identified on an ongoing basis – this can be done

using a range of approaches including

workshops, subject-matter expertise, hazard

identification processes and engineering

requirements.

Risk assessment – identified risks are

assessed for potential impact and likelihood

across a number of criteria, including health

and safety, environmental, financial and non-

financial (includes reputation and regulatory

impact levels).

This aims to provide a consistent basis for the

evaluation of potential impact and likelihood,

facilitating a comparison across different risks.

Risk management and monitoring – 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 level (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.

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 in Risk factors on page 65.

Our risk profile

The nature of our business operations is long

term, resulting in many of our risks being

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. These may include emerging

risks which are considered through existing

processes, including emerging risk

communications to the board, bp’s risk

management system, bp Energy Outlook,

bp’s technology-related news and insights

publications, ongoing emerging technology

scanning and group strategic reviews.

We describe above how risks are managed.

The following section provides examples of the

particular risk management activities for each of

bp’s principal risks.

Strategic and commercial risks

Prices and markets

Our financial performance is impacted by

fluctuating prices of oil, gas and refined products,

technological change, climate policies and

regulations, exchange rate fluctuations, and the

general macroeconomic outlook.

Our strategy is designed to accommodate

a range of scenarios and be resilient to the

volatility in the energy markets. This is

supported through a diversified portfolio, a

strong balance sheet and operating within a

resilient and disciplined financial frame. We

test our investment and project development

costs against a range of pricing and

exchange assumptions.

Accessing and progressing hydrocarbon

resources and low carbon opportunities

Inability to access and progress hydrocarbon

resources and low carbon opportunities could

adversely affect delivery of our strategy.

For hydrocarbon resources our subsurface team

is accountable for the delivery of high-value,

carbon-efficient resources to deliver predictable

and reliable investments today, as well as the

long-term renewal of our hydrocarbon resources.

Additionally, the subsurface team partners with

technology to prioritize development needs for

the future. Our gas & low carbon energy business

is accountable for the delivery of many of our low

carbon opportunities through both organic and

inorganic growth. This includes the development

of wind, solar, hydrogen and carbon capture, use

and storage businesses.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		63




		Strategic report

Major project delivery

Failure to invest in the best opportunities or

deliver major projects« successfully could

adversely affect our financial performance.

We seek to manage the risk through our projects

organization which exists to assess, develop and

execute projects across bp. The organization

contains capability which includes the centre of

expertise for appraisal and optimization,

expertise to manage the design and build of

projects and integrates with our businesses and

functions to ensure project objectives are met.

The projects organization utilises a major

projects common process.

Geopolitical

The diverse locations of our business activities

and operations around the world expose us to a

wide range of political developments and

consequent changes to the economic and

operating environment. Geopolitical risk is

inherent to many regions in which we operate,

and heightened political or social tensions or

changes in key relationships could adversely

affect the group.

We seek to manage this risk at multiple

levels, through:

•Identifying macro-level geopolitical trends in

the geopolitical advisory council.

•Providing a clear focal point for political risk

management.

•Monitoring how geopolitical trends create risk

at the country level through changes to our

baseline threat assessments.

More broadly, we manage the risk on a day-to-

day basis through the development and

maintenance of relationships with governments

and stakeholders, and by being trusted partners

in each country and region. In addition, we

closely monitor events and implement risk

mitigation plans where deemed appropriate.

Liquidity, financial capacity and financial,

including credit, exposure

External market conditions can impact our

financial performance. Supply and demand and

the prices achieved for our products can be

affected by a wide range of factors including

political developments, interest rates, consumer

preferences for low carbon energy, global

economic conditions, access to capital markets

and the influence of OPEC+.

We seek to manage this risk through bp’s

diversified portfolio, our financial frame, liquidity

stress testing, maintaining a significant cash

buffer, liquidity facilities, regular reviews of

market conditions and our planning and

investment processes.



	Energy markets, page 7 Liquidity and capital resources, page 316 Liquidity, financial capacity and financial, including credit, exposure, page 65

Joint arrangements« and contractors

Varying levels of control over the standards,

operations and compliance of our partners

including non-operated joint ventures (NOJVs),

contractors and sub-contractors could result in

legal liability and reputational damage.

bp’s exposure in NOJVs is primarily managed by

the NOJV-facing business team in the business

or entity where ownership of bp’s interest in the

NOJV sits.

Support, verification and assurance are provided

by the NOJV solutions team, safety and

operational risk assurance, ethics & compliance

functional assurance and group internal audit to

drive a focused, deliberate and systematic

approach to the set-up and management of bp’s

interests and exposure in NOJVs.

Our relationships with contractors are managed

through the bp procurement processes with

appropriate requirements incorporated into

contractual arrangements.

Digital infrastructure, cyber security and

data protection

Both targeted and indiscriminate threats to

the security and resilience of our digital

infrastructure and those of third parties continue

to evolve rapidly and are increasingly prevalent

across industries worldwide.

We seek to manage this risk through a range of

measures, which include alignment to the

National Institute of Standards and Technology

Cyber Security Framework 2.0, cyber security,

data protection and artificial intelligence

standards, security protection tools, ongoing

detection and monitoring of threats and testing

of digital response and recovery procedures. We

collaborate with governments, law enforcement

agencies and industry peers to understand and

respond to new and emerging cyber threats.

We build awareness with our employees, share

information on incidents with leadership for

continuous learning, and conduct annual cyber

training and regular exercises, including with the

leadership team, to test response and recovery

procedures. For further detail on cyber security

disclosures see page 336.

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 48 for more

information on how transition risks and

opportunities are managed.

Competition

Inability to remain efficient, maintain a high-

quality portfolio of assets and innovate could

negatively impact delivery of our strategy in a

highly competitive market.

We seek to manage this risk through our

strategy, sustainability and ventures function by

providing external insights on the economic,

energy, market and competitive environment.

These insights are used to help define a resilient

strategy for bp, including decisions related to

portfolio, business development and resource

allocation. The ventures team provides

commercial innovation capacity that allows us

to build new businesses.

Talent and capability

Inability to attract, develop and retain people with

necessary skills, capabilities could negatively

impact delivery of our strategy.

Our people, culture and communications team’s

responsibilities include talent activity for bp

globally, including hiring, development,

succession planning, and embedding of bp’s

‘Who we are’ culture frame. They help to ensure

that the right talent and people capability are in

place, using local market intelligence, people

analytics and insights to underpin our strategic

workforce planning. See page 57 for more

information.


64		bp Annual Report and Form 20-F 2024






How we manage risk and risk factors continued

Crisis management and business

continuity

Failure to address an incident effectively could

potentially disrupt our business or exacerbate the

legal, financial or operational impacts of the

crisis event.

Incidents that could potentially disrupt our

business are addressed using emergency

response and business continuity plans which

are mandated through our policies. We use

internationally recognized incident command

structures, and for significant events business

support teams and executive support teams are

established to provide oversight and

management. In addition, we provide a trained

group of crisis professionals and niche expertise

for deployment across bp through our mutual

response team.

Insurance

Our insurance strategy could expose the group to

material uninsured losses.

Our insurance team is accountable for aligning

our insurance approach with bp’s strategy and

engaging with the businesses and functions to

determine the appropriate level of insurance.

We retain in-house expertise and partner with

insurance industry leaders. Our captive insurance

companies are regulated within the jurisdictions

in which they operate.

Safety and operational risks

Process safety, personal safety and

environmental risks

Exposure to a wide range of health, safety and

environmental risks could cause harm to people,

the environment and our assets and result in

regulatory action, legal liability, business

interruption, increased costs, damage to our

reputation and potentially denial of our licence

to operate.

Our Operating Management System (OMS)«

helps us manage these risks and drive

performance improvements. It sets out the

standards and requirements which govern key

risk management activities such as inspection,

maintenance, testing, business continuity and

crisis response planning and competency

development. In addition, we conduct our drilling

activity through a wells organization in order to

promote a consistent approach for designing,

constructing and managing wells.

Drilling and production

Challenging operational environments and other

uncertainties could impact drilling and

production activities.

Our production and operations business

group brings together all our hydrocarbon

operations and our distinctive capabilities in

one place to safely deliver competitive returns.

The functions, in particular wells and

production, are accountable for safety, risk,

quality and operational delivery. They execute

capital and operational activity and manage

associated expenditure.

Security

Hostile acts such as terrorism, activism, insider

acts or piracy could harm our people and disrupt

our operations. We monitor for emerging threats

and vulnerabilities to manage our physical and

information security.

Our intelligence, security and crisis management

teams provide strategic and operational risk

management to our businesses through a

network of regional security managers who

provide front-line risk management as well as

conduct assurance activities through a team

independent of the business.

We continue to monitor threats globally and

maintain disaster recovery, crisis and business

continuity management plans.

Product quality

Supplying customers with off-specification

products could damage our reputation, lead to

regulatory action and legal liability, and impact

our financial performance.

bp’s product quality policy is aligned with our

OMS and sets requirements for our business to

meet specifications and applicable legal and

regulatory requirements.

Compliance and control risks

Ethical misconduct and legal or regulatory

non-compliance

Ethical misconduct or breaches of applicable

laws or regulations could damage our reputation,

result in litigation, regulatory action and penalties,

adversely affect results and shareholder value,

and potentially affect our licence to operate.

Our code of conduct, the foundation of ‘Who we

are’, is applicable to all employees and central to

managing this risk. Additionally, we have various

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.

Regulation

Changes in the law and regulation could

increase costs, constrain our operations and

affect our strategy, business plans and

financial performance.

Our businesses and functions all 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.

Trading and treasury trading activities

In the normal course of business, we are subject

to risks around our trading activities which could

arise from shortcomings or failures in our

systems, risk management methodology, internal

control processes or employee conduct.

We have specific operating standards and

control processes to manage these risks,

including guidelines specific to trading, and seek

to monitor compliance through our dedicated

compliance teams. We also seek to maintain a

positive and collaborative relationship with

regulators and the industry at large.

Reporting

Failure to accurately report our data could

lead to regulatory action, legal liability and

reputational damage.

Our accounting reporting and control team

provides assurance of the control environment

and is accountable for building control and

compliance of finance processes and

digital systems.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		65




		Strategic report

Risk factors

The risks discussed below, separately or in combination, could have a material adverse effect on the

implementation of our strategy, business, financial performance, results of operations, cash flow,

liquidity, prospects, shareholder value and returns and reputation.

Strategic and commercial risks

Prices and markets: our financial performance

is impacted by fluctuating prices of oil, gas

and refined products, technological change,

climate policies and regulations, exchange

rate fluctuations, and the general

macroeconomic outlook.

Oil, gas and product prices are subject to

international supply and demand and margins

can be volatile.

Political developments, fluctuations to the supply

of either oil or natural gas or to alternative low

carbon energy sources, technological change,

global economic conditions, public health

situations (including the outbreak of an epidemic

or pandemic), the introduction of new (or

amendment to existing) carbon costs and the

influence of OPEC+ can impact supply and

demand and prices for our products (including

low carbon investments).

Decreases in the price of energy outputs we

produce could have an adverse effect on

revenue, margins, profitability and cash flows.

If these reductions are significant or for a

prolonged period, we may have to write down

assets and reassess the viability of certain

projects, which may impact future cash flows,

profit, capital expenditure«, the ability to work

within our financial frame and maintain our long-

term investment programme. Conversely, an

increase in the prices of the energy outputs we

produce may not improve margin performance

as there could be increased fiscal take, cost

inflation and more onerous terms for access to

resources. The profitability of our refining

activities can be volatile, with periodic oversupply

or supply tightness in regional markets and

fluctuations in demand.

Exchange rate fluctuations can create currency

exposures and impact underlying costs and

revenues. Crude oil prices are generally set in US

dollars, while products vary in currency. Many of

our major project« development costs are

denominated in local currencies, which may be

subject to fluctuations against the US dollar.

Accessing and progressing hydrocarbon

resources and low carbon opportunities:

inability to access and progress hydrocarbon

resources and low carbon opportunities could

adversely affect delivery of our strategy.

Delivery of our strategy depends partly on our

ability to progress hydrocarbon resources from

our existing portfolio and access new resources.

Our ability to progress upstream« resources and

develop technologies at a level in line with our

strategic outlook for hydrocarbon production

could impact our future production and financial

performance. Furthermore, our ability to access

low carbon opportunities and the commercial

terms associated with those opportunities could

impact our financial performance while moving

at pace with society and its changing wants

and needs.



	Our strategy, page 8

Major project delivery: failure to invest in the

best opportunities or deliver major projects

successfully could adversely affect our

financial performance.

We face challenges in developing major projects,

particularly in geographically and technically

challenging areas. Poor investment choice,

efficiency or delivery, inflation, supply chain, or

operational challenges at any major project that

underpins production or production growth,

could adversely affect our financial performance.

Geopolitical: exposure to a range of political

developments and consequent changes to the

operating and regulatory environment could

cause business disruption.

We operate and may seek new opportunities in

countries, regions and cities where political,

economic and social transition may take place.

Political instability, changes to the regulatory

environment or taxation, international trade

disputes and barriers to free trade, international

sanctions, 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) may disrupt or curtail our

operations, business activities or investments.

These may in turn cause production to decline,

limit our ability to pursue new opportunities,

affect the recoverability of our assets and our

related earnings and cash flow or cause us to

incur additional costs, particularly due to the

long-term nature of many of our projects and

significant capital expenditure required.

Trade restrictions, international sanctions or any

other actions taken by governmental authorities

or other relevant persons have had and could

continue to have an impact on global energy

supply and demand, market volatility and the

prices of oil, gas and products.

Liquidity, financial capacity and financial,

including credit, exposure: failure to work within

our financial frame could impact our ability to

operate and result in financial loss.

Trade and other receivables, including overdue

receivables, may not be recovered, divestments

may not be successfully completed and a

substantial and unexpected cash call or funding

request could disrupt our financial frame or

overwhelm our ability to meet our obligations.

An event such as a significant operational

incident, legal proceedings or a geopolitical event

in an area where we have significant activities,

could reduce our financial liquidity and our credit

ratings. Credit rating downgrades could

potentially increase financing costs and limit

access to financing or engagement in our trading

activities on acceptable terms, which could put

pressure on the group’s liquidity.

They could also potentially require the company

to review the funding arrangements with the bp

pension trustees. In the event of extended

constraints on our ability to obtain financing, we

could be required to reduce capital expenditure

or increase asset disposals in order to provide

additional liquidity.



	Liquidity and capital resources, page 316 Financial statements – Note 29

Joint arrangements« and contractors: varying

levels of control over the standards, operations

and compliance of our partners, including non-

operated joint ventures (NOJVs), contractors and

sub-contractors could result in legal liability and

reputational damage.


66		bp Annual Report and Form 20-F 2024






How we manage risk and risk factors continued

We conduct many of our activities through joint

arrangements, partners or with contractors and

sub-contractors where we may have limited

influence and control over the performance of

such activities.

Our partners and contractors are responsible for

the adequacy of their resources and capabilities.

If these are found to be lacking, there may be

financial, reputational, operational or safety

exposures for bp. Should an incident occur in an

activity that bp participates in, our partners and

contractors may be unable or unwilling to fully

compensate us against costs we may incur on

their behalf or on behalf of the arrangement.

Where we do not have operational control of a

joint arrangement or direct oversight of

contractor activity, 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 infrastructure, cyber security and data

protection: breach or failure of our or third

parties’ digital infrastructure or cyber security,

including loss or misuse of sensitive information

could damage our operations, increase costs and

damage our reputation.

The energy industry is subject to fast-evolving

risks, including ransomware, from cyber threat

actors, including nation states, criminals,

terrorists, hacktivists and insiders. Current

geopolitical factors have increased these risks.

There is also growing regulation around data

protection and data privacy, critical national

infrastructure and the evolving opportunities and

threats from artificial intelligence. A breach or

failure of our or third parties’ digital infrastructure

– including control systems – due to breaches of

our cyber defences, or those of third parties,

negligence, intentional misconduct or other

reasons, could seriously disrupt our operations.

This could result in 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, legal liability and significant costs

including fines, cost of remediation or

reputational consequences. Furthermore, the

rapid detection of attempts to gain unauthorized

access to our digital infrastructure, often through

the use of sophisticated and co-ordinated

means, is a challenge and any delay or failure to

detect could compound these potential harms.



	Cyber security disclosures, page 336

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 environmental, social and

governance (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 intangible assets; the timing of

decommissioning of assets; and the useful

economic lives of assets used for the calculation

of depreciation and amortization.



	Climate-related financial disclosures, page 42 and Financial statements – Note 1 and Note 33

Competition: inability to remain efficient,

maintain a high-quality portfolio of assets and

innovate could negatively impact delivery of our

strategy in a highly competitive market.

Our strategic progress and performance could

be impeded if we are unable to control our

development and operating costs and margins,

if we fail to scale our businesses at pace, or to

sustain, develop and operate a high-quality

portfolio of assets efficiently. Furthermore, as an

integrated energy company, we face an

expanded and rapidly evolving range of

competitors in the sectors in which we operate.

We could be adversely affected if competitors

offer superior terms for access rights or licences,

or if our innovation in areas such as new low

carbon technologies, digital, customer offer,

exploration, production, refining, manufacturing

or renewable energy lags behind those of our

competitors. Our performance could also be

negatively impacted if we fail to protect our

intellectual property.

Talent and capability: inability to attract, develop

and retain people with necessary skills,

capabilities and behaviours could negatively

impact delivery of our strategy.

The sectors in which we operate face increasing

challenges to attract and retain diverse, skilled

and capable talent. An inability to successfully

recruit, develop and retain core skills and

capabilities and to reskill existing talent could

impact delivery of our strategy.

Crisis management and business continuity:

failure to address an incident effectively could

potentially disrupt our business.

Our reputation and business activities could be

negatively impacted if we do not respond, or are

perceived not to respond, in an appropriate

manner to any major crisis.

Insurance: our insurance strategy could expose

the group to material uninsured losses.

bp insures in situations where this is legally and

contractually required. Some risks are insured

with third parties and reinsured by group

insurance companies. Uninsured losses could

have a material adverse effect on our financial

position, particularly if they arise at a time when

we are facing material costs as a result of a

significant operational event which could put

pressure on our liquidity and cash flows.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		67




		Strategic report

Safety and operational risks

Process safety, personal safety, and

environmental risks: exposure to a wide range

of health, safety and environmental risks could

cause harm to people, the environment and our

assets and result in regulatory action, legal

liability, business interruption, increased costs,

damage to our reputation and potentially denial

of our licence to operate.

Technical integrity failure, natural disasters,

extreme weather or a change in its frequency or

severity, human error and other adverse events

or conditions, including breach of digital security,

could lead to loss of containment of hazardous

materials, including hydrocarbons«. This could

also lead to fires, explosions or other personal

and process safety incidents when drilling wells,

constructing and operating facilities; in addition

to activities associated with transportation by

road, sea or pipeline. There can be no certainty

that our OMS or other policies and procedures

will adequately identify all process safety,

personal safety and environmental risks or that

all our operating activities, including acquired

businesses, will be conducted in conformance

with these systems.



	Safety, page 56

Such events or conditions or inability to provide

safe environments for our workforce and the

public while at our facilities, premises or during

transportation, could lead to injuries, loss of life

or environmental damage. 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. Our activities are sometimes conducted

in hazardous, remote or environmentally

sensitive locations, where the consequences of

such events or conditions could be greater than

in other locations.

Drilling and production: challenging operational

environments and other uncertainties could

impact drilling and production activities.

Our activities require high levels of investment

and are sometimes conducted in challenging

environments such as those prone to natural

disasters and extreme weather, 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 often 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.

Security: hostile acts against our employees and

activities could cause harm to people and disrupt

our operations.

Acts of terrorism, piracy, sabotage, activism and

similar activities directed against our operations

and facilities, pipelines, transportation or digital

infrastructure could cause harm to people and

severely disrupt operations. Our activities could

also be severely affected by conflict, civil strife or

political unrest.

Product quality: supplying customers with off-

specification products could damage our

reputation, lead to regulatory action and legal

liability, and impact our financial performance.

Failure to meet product quality specifications

could cause harm to people and the

environment, damage our reputation, result in

regulatory action and legal liability, and impact

financial performance.

Compliance and control risks

Ethical misconduct and non-compliance: ethical

misconduct or breaches of applicable laws by

our businesses or our employees could be

damaging to our reputation, and could result in

litigation, regulatory action and penalties.

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.

Regulation: changes in the law and regulation

could increase costs, constrain our operations

and affect our strategy, business plans and

financial performance.

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.



	Regulation of the group’s business, pages 329-334

Trading and treasury trading activities:

ineffective oversight of trading and treasury

trading activities could lead to business

disruption, financial loss, regulatory intervention

or damage to our reputation and affect our

permissions to trade.

We are subject to operational risk around our

trading and treasury trading activities in financial

and commodity markets, some of which are

regulated. Failure to process, manage and

monitor a large number of complex transactions

across many markets and currencies while

complying with all regulatory requirements could

hinder profitable trading opportunities. 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.



	Financial statements – Note 29

Reporting: failure to accurately report our data

could lead to regulatory action, legal liability and

reputational damage.

External reporting of financial and non-financial

data, including reserves estimates, relies on the

integrity of the control environment, our systems

and people operating them. Failure to report data

accurately and in compliance with applicable

standards could result in regulatory action, legal

liability and damage to our reputation.


68		bp Annual Report and Form 20-F 2024






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 42-55 •People and planet – page 60 •Our Operating Management System« (OMS) – page 56 •Decision making by the board – page 79
b Employees	•bp values and code of conduct (online)	•Our people – page 57 •Safety – page 56 •Our values (Who we are) and code of conduct – pages 58-59 •Employee engagement (Pulse annual and Pulse live employee surveys) – page 58 •How the board engaged with stakeholders (workforce) – page 78
c Social matters	•Sustainability frame	•Our Operating Management System« (OMS) – page 56 •Improving people’s lives – page 60 •Decision making by the board – page 79
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 60 •Human rights – page 60 •Our values (Who we are) and code of conduct – pages 58-59
e Anti-corruption and anti-bribery	•Anti-bribery and corruption policy •Code of conduct (online)	•Ethics and compliance – page 59 •Our partners in joint arrangements – page 57
Description of principal risks relating to matters (a-e above)		•How we manage risk – pages 61-64 •Risk factors – pages 65-67 •TCFD (climate-related risk management) – pages 45-46
	Relevant information
Business model description	•Business model – page 12
Description of non-financial KPIs	•Measuring our progress – page 14 and 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 45
	b Describe management’s role in assessing and managing climate-related risks and opportunities.	•Page 46
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.	•Pursuing a strategy that is consistent with the Paris goals, page 10 •Strategy, page 8 •Risk factors, page 65
	b Describe the impact of climate-related risks and opportunities on the organization’s businesses, strategy, and financial planning.	•Risk factors, page 65 – 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.	•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 45 •How we manage risk, page 61 •Risk factors, page 65
	b Describe the organization’s processes for managing climate-related risks.	•Risk Management, page 45 •How we manage risk, page 61
	c Describe how processes for identifying, assessing, and managing climate-related risks are integrated into the organization’s overall risk management.	•Risk Management, page 45 •How we manage risk, page 61 •Risk factors, page 65
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 55
	b Disclose Scope 1, Scope 2, and, if appropriate, Scope 3 GHG emissions, and the related risks.	•GHG emissions data, page 40
	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 38-39

aWe consider the information in our TCFD disclosures, taken together with our climate-related non-financial KPIs on pages 14-17 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 2024, they have acted in a way that they consider, in good faith, would most likely promote the success of the company for the benefit of its members as a whole, having regard to the likely consequences of any decision in the long term and the broader interests of other stakeholders, as required by the Act.

		For more information in support of this statement, see board activities, page 76, our stakeholders, page 78 and key decisions, page 79.

The Strategic report was approved by the board and signed on its behalf by Ben J.S. Mathews, company secretary, on 6 March 2025.


70		bp Annual Report and Form 20-F 2024






Introduction from the chair




Our governance framework is designed to be dynamic, flexible and robust.

Dear fellow shareholders,

The role of a board as custodian of the

company’s assets has even greater significance

in times of volatility, uncertainty and change. The

unpredictable macro environment in 2024

offered both opportunities and challenges for

global energy companies. Many of bp’s

businesses performed well but there were also

challenges in parts of the customers & products

business. Overall, it was a year of reshaping the

portfolio and laying the foundations for bp’s

strategy reset in February 2025. The strategy we

have set out provides clarity about direction and

priorities, and the board will now focus its

attention overseeing strategic execution and

performance management.

Evolving governance framework

The board’s corporate governance framework is

a robust basis to challenge and guide the

leadership team in good times, but also in the

tougher times we have experienced. It has been

instrumental in helping the board to navigate

multiple, rigorous discussions and – ultimately –

the decisions we took in 2024, culminating, more

recently, in February’s strategy reset.

Our governance framework is designed to be

dynamic, flexible and robust. This meant that

when the new UK Corporate Governance Code

was published at the start of 2024, we could

largely deploy our existing processes to plan for

meeting its requirements, adding elements

where appropriate while avoiding duplication and

minimizing extra work.

The terms of reference for the board and the

board committees were updated in July, with

further changes to the board and audit

committee terms of reference in January 2025,

reflecting the staggered timetable of the changes

coming into force under the new code.

Considering the new requirement for an internal

control effectiveness statement, we intend to

make this statement in 2027 in respect of our

2026 annual report, having sought appropriate

external assurance.

Meaningful engagement

Every year, we seek to engage widely with you,

our shareholders, but also with our own people,

partners, advisers and governments.

A highlight of 2024 was the board’s trip to India.

This was an invaluable experience for the board

in a strategically significant region for bp. We

travelled to three cities, meeting partners,

suppliers and the government – and bp’s teams

working on lubricants, developing technical

solutions and helping to run our operations

safely (see page 78).

The board also met many other teams across

the world, through our bespoke workforce

engagement programme. This is designed to

allow our directors to meet our people directly,

throughout bp (see page 78).

Our 2024 workforce engagement agenda was

aligned closely with the topics we discussed in

reviewing and considering our strategic options

at board meetings during the year. The views and

feedback obtained played an important part in

informing the board’s decisions. This programme

of listening to and working with our people will

continue through 2025 – especially during an

ongoing transformation programme.

Progress on culture

The board places great importance in assessing

and monitoring bp’s culture. Whenever

necessary, it seeks the leadership team’s

assurance that action will be taken should

practices or behaviours not align with the

company’s culture frame, which sets out ‘Who

we are’. The board set up a temporary committee

in 2023 to provide direct oversight on culture. It

served bp well and its responsibilities have now

been assumed by the people, culture and

governance committee.

As chair of this committee, I am pleased with the

start we have made in 2024 with the committee’s

expanded scope on culture and, in particular,

with a focus on psychological safety and

speaking up. We will seek to make further

progress on this area during 2025 (for more on

the people, culture and governance committee’s

work, see page 86).

Board composition

The people, culture and governance committee is

continuously working to identify potential

candidates to join the board. The reset strategy

bp announced in February 2025 provides the

committee with a clear framework to identify

new board members who will bring the additional

skills and experience bp needs as it embarks on

the next chapter.

Closing thanks

I am grateful to my fellow board members for

everything they have done this year – and

everything they continue to do. On behalf of the

board, I would also like to thank the leadership

team and bp teams across the world for what

they achieved in 2024, for their relentless focus

on safety and their commitment to bp. And I will

close by thanking you, fellow shareholders, for

your support and your challenges. Your

contributions improve the board’s decision

making – and help to improve bp.

Helge Lund

Chair

6 March 2025


« See glossary on page 351		bp Annual Report and Form 20-F 2024		71




		Corporate governance

Board at a glance

Board

meeting

attendance

Committee

membership

Skills and

experience

8 scheduled

2 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 directorsa

Helge Lund (Chair)

8/8

2/2

Dame Amanda Blanc

8/8

2/2

Tushar Morzaria

8/8

2/2

Melody Meyerb

8/8

1/2

Pamela Daley

8/8

2/2

Hina Nagarajan

8/8

2/2

Satish Paic

7/8

2/2

Karen Richardsonc

7/8

2/2

Dr Johannes Teyssen

8/8

2/2

Executive directors

Murray Auchincloss (CEO)

8/8

2/2

Kate Thomson (CFO)d

7/7

1/1

ò Chair of the committee

ò Member of the committee


Non-executive directors’ tenure			Board ethnic diversity			Board gender diversity

	March 2025	March 2024		March 2025	March 2024		March 2025	March 2024
¢ 1. 1-3 years	3	6	¢ 1. White British or other white (including minority-white groups)	8	10	¢ 1. Female	6	7
¢ 2. 4-6 years	5	3	¢ 2. Asian/Asian British	3	3	¢ 2. Male	5	6
¢ 3. 7-9 years	1	2

			3			55%
			directors who identify as from a minority ethnic background			of directors are female
a Paula Rosput Reynolds and Sir John Sawers stepped down from the board on 25 April 2024 and attended all meetings held prior to this date. b Melody was unable to attend the ad hoc meeting in June due to an existing external commitment. c Satish and Karen were unable to attend the scheduled meeting in June due to existing external commitments. d Kate was appointed to the board on 2 February 2024 and attended all meetings held after this date.


72		bp Annual Report and Form 20-F 2024






Board of directors

Helge Lund

Chair

Appointed Board: 26 July 2018; chair: 1 January 2019

Nationality Norwegian

External appointments

•Chair of Novo Nordisk AS.

•Operating advisor to Clayton Dubilier & Rice.

•Member of the Board of Trustees of the International

Crisis Group.

•Member of the European Round Table for Industry.

Significant past appointments

•Chief executive of BG Group.

•President and chief executive officer of Equinor and

Aker Kvaerner.

•Executive of Aker RGI and Hafslund Nycomed.

•Non-executive director of Schlumberger and Nokia.

•Consultant at McKinsey & Company.

•Parliamentary group political advisor of the Conservative

party, Norway.

Key skills and experience

•Distinguished career as a leader in the energy sector with

deep industry knowledge and global business experience.

•Drives cohesion, constructive challenge and oversight of

bp’s strategy through forward looking leadership of the

board.

As at 6 March 2025

Dame Amanda Blanc

Senior independent

director

Appointed 1 September 2022

Nationality British

External appointments

•CEO of Aviva plc.

•Member of the Association of British Insurers Board.

Significant past appointments

•Began career as a graduate at Commercial Union, one of

Aviva’s ancestor companies, and held several senior

executive roles across the insurance industry.

•Group CEO at AXA UK, PPP & Ireland.

•CEO of Europe, Middle East, Africa & Global Banking at

Zurich Insurance Group.

•Leadership positions at Groupama Insurance Company

and Commercial Union.

•Member of the Prime Minister’s Business Council.

Key skills and experience

•Experience leading insurance businesses in the UK and

across Europe.

•Wide-ranging board, industry and regulatory experience.


Committee members key
	Chair	Audit committee	Safety and sustainability committee	Remuneration committee	People, culture and governance committee
	Chair	Audit committee	Safety and sustainability committee	Remuneration committee	People, culture and governance committee

Murry Auchincloss

Chief executive officer

Appointed Executive director: 1 July 2020; chief

executive officer: 17 January 2024

Nationality Canadian and British

Significant past appointments

•Joined Amoco in 1992 and then bp when the two

companies merged in 1998.

•Senior roles in finance and management at bp, across tax,

business development, mergers and acquisitions and

performance management.

•Chief of staff to bp chief executive officer.

•CFO BP p.l.c.

Key skills and experience

•Drives bp’s strategy as an integrated energy company and

has extensive experience and knowledge of the energy

sector.

•Provides deep insight into bp’s assets and businesses

through broad experience across the group, extensive

financial expertise and experience.

Tushar Morzaria

Independent non-executive

director

Appointed 1 September 2020

Nationality British

External appointments

•Non-executive director of Legal & General Group plc.

•Non-executive director of BT 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.

Kate Thomson

Chief financial officer

Appointed 2 February 2024

Nationality British

External appointments

•Board member of Aker BP ASA.

•Member of the European Round Table for CFOs.

•Member of the 100 Group Main Committee.

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 group in tax,

treasury and commercial finance.

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.

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.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		73




		Corporate governance

Pamela Daley

Independent non-executive

director

Appointed 26 July 2018

Nationality American

External appointments

•Director of BlackRock, Inc.

Significant past appointments

•Various senior executive roles at General Electric

Company (GE), including senior vice president of business

development 2004 to 2013.

•Senior vice president and senior advisor to the chair at GE

in 2013.

•Director of BG Group plc 2014 to 2016.

•Director of Patheon N.V. 2016 to 2017.

•Partner at Morgan, Lewis & Bockius.

•Director of SecureWorks, Inc. 2016 to 2025.

Key skills and experience

•Board-level experience of the UK oil and gas industry and

executive experience in highly regulated industries.

•Qualified lawyer with a wealth of global business and

strategic experience.

Hina Nagarajan

Independent non-executive

director

Appointed 1 March 2023

Nationality Indian

External appointments

•Managing director and CEO of United Spirits Limited

(Diageo India).

•Member of the global executive committee of Diageo plc.

•Board member of The Advertising Standards Council

of India.

•Director and co-chair of International Spirits and Wines

Association of India.

Significant past appointments

•Leadership positions at Reckitt, Mary Kay India and Nestlé

India with over 30 years 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.

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.

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 sector.

•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 knowledge of digital, technology, cyber and IT

security matters.

•30 years’ technology industry experience including working

with innovative Silicon Valley companies.

Dr Johannes Teyssen

Independent non-executive

director

Appointed 1 January 2021

Nationality German

External appointments

•Senior advisor to Kohlberg Kravis Roberts.

•President of Alpiq Holding Ltd.

•Senior advisor to Viridor Limited.

Significant past appointments

•Several leadership positions at VEBA AG (merged with

VIAG AG in 2000 and renamed to E.ON AG and later to

E.ON SE).

•Member of the board of management of the E.ON Group’s

central management company in Munich in 2001 and

E.ON SE in 2004.

•Vice-chair of E.ON SE, 2008 and CEO, 2010 to 2021.

•President of Eurelectric 2013 to 2015.

•Vice-chair of the World Energy Council, responsible for

Europe, 2006 to 2012.

•Member of the supervisory board of Salzgitter AG 2006 to

2016 and Deutsche Bank AG 2008 to 2018.

Key skills and experience

•Extensive experience and deep knowledge of the energy

sector and its continuing transformation.

•Considerable knowledge and experience of climate-related

risk oversight.

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.

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

the 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 advice and support to the plc board and the

boards of 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.




	For further detail on the directors’ climate change and sustainability experience, see the TCFD section on page 43 and further biographical information for each director is available online at bp.com/whoweare.


74		bp Annual Report and Form 20-F 2024






Leadership team

William Lin

EVP gas & low

carbon energy

Leadership team tenure Appointed on 1 July 2020

Nationality American

Board memberships

William is a non-executive director of Pan American

Energy Group, the largest independent energy company

in Argentina. He is also a member of the supervisory board

for Corbion, a Dutch-listed global food ingredients and

biochemicals company. He chairs Corbion’s Sustainability

& Safety Committee and is a member of the Audit

Committee.

Career summary

William has worked at bp for 29 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.

Gordon Birrell

EVP production & operations

Leadership team tenure Appointed on 1 July 2020

Gordon previously served on bp’s executive team starting

on 12 February 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.

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 at bp. Kerry

previously headed HR for bp’s upstream business while

also serving as group chief talent officer. She has held a

series of senior HR positions across the company,

including running HR for bp’s shipping, integrated supply

and trading, and corporate functions. She brings vast

experience from other sectors in Europe and Asia, having

worked at both BT and Honeywell.

Emma Delaney

EVP customers & products

Leadership team tenure Appointed on 1 July 2020

Emma previously served on bp’s executive team starting

on 1 April 2020

Nationality Irish

Board memberships

None

Career summary

Emma has spent 28 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.

Emeka Emembolu

EVP technology

Leadership team tenure Appointed on 18 April 2024

Nationality British

Board memberships

None

Career summary

Emeka started his career working offshore as an engineer

and has spent 25 years with bp. Prior to being appointed

EVP technology, Emeka spent two years as chief of staff

to the CEO. Before joining the executive office, he led bp's

North Sea business as region SVP spearheading

improvements in operational safety, driving efficiencies

and growing the value of the business. Prior to that, he

held a range of senior technical leadership roles in the Gulf

of America, Canada, North Africa and Alaska and in the

subsurface function.

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.

Giulia Chierchia

EVP strategy, sustainability

& ventures

Leadership team tenure Appointed on 1 July 2020

Nationality Belgian and Italian

Board memberships

Giulia is a non-executive director of Schneider Electric.

Career summary

Giulia joined bp in April 2020 as EVP strategy,

sustainability & ventures. In her role, Giulia drives bp’s

strategy and sustainability agenda and embeds the

group’s ethics and compliance within the organization.

She oversees bp’s venturing investments business, which

supports bp’s transition and net zero ambition. Prior to bp,

she worked for McKinsey, where she was a senior partner.

She led the global downstream oil and gas practice and

was a key member of the chemicals, and electricity, power

and natural gas practices, helping companies shape their

strategies for the energy transition.

Carol Howle

EVP supply, trading & shipping

Leadership team tenure Appointed on 1 July 2020

Nationality British

Board memberships

None

Career summary

Before taking on her current role, Carol ran bp shipping

and was the chief operating officer for integrated supply

and trading, oil. She has more than 20 years’ experience in

the energy industry, and many in integrated supply and

trading. Her previous roles include chief operating officer

for natural gas liquids, regional leader of global oil Europe

and finance. Carol also served as the head of the group

chief executive’s office.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		75




		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 80	Report from page 82	Report from page 86	Report from page 88




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 for the company’s

stakeholders and the consequences of decisions 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 includes

monitoring culture and the effectiveness of the

company’s system of internal control.

More detailed information about board activities is

available from page 76.

Delegation of authority

The board delegates certain responsibilities

to its principal committees, which are outlined

in their respective terms of reference at

bp.com/governance.

Day-to-day management of the business is

delegated to the chief executive officer (CEO), who in

turn is advised and supported by a leadership team

(bpLT) comprising of nine individuals who are

accountable to him for their respective business and

functional areas, with appropriate financial authority

levels. Ultimately, decisions are taken by the CEO in

the execution of the delegations to him by the board.

For example, the CEO’s authority includes a limit on

investments, capital expenditure« and financial

commitments. Any matters in excess of this limit, or

those that go beyond the annual plan or agreed

strategy, remain 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 principal board committees operate

under terms of reference which are reviewed

at least annually. Full details can be found at

bp.com/governance.

Each committee reports to the board as a whole,

providing updates on their activities and, where

applicable, making 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 good governance in matters such as

remuneration and succession planning.

Chair

•Helge Lund leads the board and is responsible

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)

•Dame Amanda Blanc acts as a sounding board

for the chair and, if necessary, as an intermediary

for other directors and investors.

•This includes overseeing the performance

evaluation and succession planning for the chair.

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)

•As CEO, Murray Auchincloss proposes

bp’s strategy and annual plan for

endorsement by the board, and leads the bpLT

in delivering them.

•This involves overseeing the implementation of

the system of internal controls and responsibility

for setting policies, standards and procedures

that foster bp’s culture and values.

Chief financial officer (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, change to and compliance with

board procedures, and monitors regulatory

requirements. He also supports the chair in ensuring

the timely flow of accurate and clear information to

the board.


76		bp Annual Report and Form 20-F 2024






Board activities: promoting long-term sustainable success


In 2024 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 these pillars. Notably, overseas trips to both Houston, US, and across India allowed the board to engage directly with a range of stakeholders. Highlights of the board’s activities, discussions and approvals during the year are provided below.


	Strategy		Performance
	Strategic direction TCFD •Worked closely with the CEO and his leadership team to establish a new purpose and strategy reset for bp. •Discussed strategic progress and options at every board meeting, including deep-dives into our transition businesses«. Macroeconomics TCFD •The review of our strategic direction was informed by regular updates on macroeconomic and geopolitical factors affecting our strategy, plan and performance. Mergers and acquisitions pipeline •Regular reviews of potential merger, acquisition and divestment opportunities, including transition and low carbon. TCFD •Approved the acquisition of transition business, bp Bunge Bioenergia (see page 33). TCFD •Approved the final investment decision for Kaskida which will be bp’s sixth hub in the Gulf of America. Offsites •The board's site visits this year included: –Permian Basin, Gulf of America. –bp Houston in the US. –The Castellón refinery in Spain. –Castrol Patalganga plant and bp’s business and technology centers in Pune, in India. –Our Reliance-operated KG D6 gas facility in India. Technology •Received an update on digital, including its functional reorganization, the development of new strategic partnerships (Palantir, Infosys) and priorities for 2025. •Participated in a deep-dive session on the potential deployment of generative artificial intelligence solutions across bp businesses. Safety and sustainability TCFD •Reviewed ongoing updates on safety measures and performance. •Focused its sustainability aims on those most relevant to the long- term success of its businesses and to its net zero ambition		Annual plan •Reviewed and approved the 2024 annual plan that considered capital allocation (including transition businesses) to improve the balance sheet. TCFD •Reviewed full-year delivery against the 2023 plan, and monitored progress against 2024 objectives. Financial frame and distributions •Evaluated potential enhancements and simplifications to 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 or divestment opportunities of more than $100 million. Acquisition reviews •Evaluated progress on the integration of transition businesses, Archaea Energy and TravelCenters of America. TCFD Principal risks •Analysed trends and themes arising from risk management reports. •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. •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 61).

		Key
		TCFD		TCFD Recommendations and Recommended Disclosure


Highlights of the year
January – March		April – June

February: •Site visit to bpx energy and Archaea, US. •People, culture and governance; remuneration; audit; and safety and sustainability committee meetings, including Q4 results, London. •Board meeting, London. March: •People, culture and governance; remuneration; and audit committee meetings, virtual. •Board meeting, virtual.		April: •People, culture and governance committee meeting, virtual •Remuneration committee meeting, virtual •Annual General Meeting, London May: •Audit committee and board meetings, including Q1 results, virtual. June: •Houston, US, board programme including a safety and sustainability committee site visit to the Permian Basin and Gulf of America and a trading and shipping floor walk with the audit committee. •Ad-hoc board meeting, virtual.

	Permian Basin, US		Argos platform, US Gulf of America


« See glossary on page 351		bp Annual Report and Form 20-F 2024		77




		Corporate governance





	People				Governance
	Engagement •Participated in the workforce engagement programme (WFEP), bringing employee feedback into the boardroom and therefore allowing board decisions to be better informed of stakeholder views (see page 78). •Met with high-potential employees to help improve the board's visibility of the executive succession pipeline. •Held town halls and undertook site visits to increase director interaction with the workforce in those locations (further information on in-person site visits on page 78). 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. •Approved the scope of the newly named people, culture and governance committee. Conflicts of interest •Approved an amended conflicts of interest policy that integrated mandatory disclosure and reporting requirements for relationships at work. Succession planning •Supported by the people, culture and governance committee, the board received updates on succession plans for the board, and undertook a review of leadership development initiatives, including succession plans for the bp leadership team.				Corporate governance framework •Approved changes to the terms of reference for the board and committees to align with regulatory changes under the revised UK Corporate Governance Code and to reflect evolving governance practices at bp. Board composition / director changes •Following a comprehensive selection process, appointed Murray Auchincloss as the permanent chief executive officer with effect from 17 January 2024, and Kate Thomson as chief financial officer and board member on 2 February 2024. •Appointed Dame Amanda Blanc as senior independent director (SID) with effect from 25 April 2024. •Appointed Tushar Morzaria as interim remuneration committee chair with effect from 25 April 2024. •Appointed Hina Nagarajan and Johannes Teyssen as additional members of the people, culture and governance committee with effect from 6 May 2024. Director training and knowledge sessions •Completed online training on topics including the code of conduct and cyber security. •Participated in a number of deep-dive sessions during the year on relevant topics such as artificial intelligence. Board effectiveness review •Conducted an externally facilitated board and committee performance review led by the chair and company secretary (see page 87). Investor engagement •The chair, senior independent director, remuneration committee chair, SVP investor relations and company secretary held a number of investor meetings with shareholders representing around 30% of the share capital.



July – September		October – December

July: •People, culture and governance; remuneration, audit; and safety and sustainability committee meetings, including Q2 results, London. •Board meeting, London. •Safety and sustainability committee site visit to Castellón refinery, Spain. September: •India board programme, including safety and sustainability committee site visit to Castrol Patalganga and audit committee site visit to Pune.		October: •Audit committee; board; and results committee meetings, including Q3 results. November: •People, culture and governance; remuneration; audit and safety and sustainability committee meetings, London. •Board meeting, London. December: •Audit committee meeting, virtual

	bp office in Pune, India		Castrol, Pangbourne, UK


78		bp Annual Report and Form 20-F 2024






Our stakeholders

Regular stakeholder engagement allows directors to gain a wide range of different insights, giving the board a comprehensive and rounded perspective in

support of the decisions it takes. Engagement of this nature helps the directors to fulfil their statutory duties and build greater trust within, across, and

outside of bp. In turn this helps improve how the strategy is formed and overseen to promote bp’s long-term success.

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 that they take and to the continuing

evolution of bp’s strategy.

For the non-executive directors (NEDs), one of

the key mechanisms for engagement is the

workforce engagement programme (WFEP).

Every NED takes part in the WFEP, joining small

group roundtable sessions with employees on a

specific topic. Key themes addressed through

the WFEP in 2024 included safety, innovation and

technology, remuneration, and culture.

In addition, for employees, directors have been

involved in town hall events and webcasts during

the year.

For investors, engagement mechanisms

included roadshows, results calls, one-to-one

and group meetings.

bp’s financial and operational performance was

an important topic for both investors and the

workforce in 2024, with directors seeking to

enhance each group’s understanding of the

factors affecting the company’s overall

performance.

Promoting balanced perspectives

òòòò

In 2024, engagements included sessions with

employees in Australia, India, Spain, the UK and

US; summits and meetings with governments

and regulators from Azerbaijan, Germany,

Kuwait, India and Iraq; and customer-focused

visits to sites in the UK, US and India.

In particular, the board’s visit to our business and

technology centers in Pune, India in September

provided a breadth of stakeholder engagement

opportunities, supporting the delivery of bp’s

ambitions. For more on the visit to Pune see

page 83.

In addition to regular meetings with investors in

2024, bp held its first hybrid retail shareholder

engagement event outside of the AGM, hosted by

the company secretary. Feedback from this

event was used to enhance engagement by the

board at the AGM.

Focusing strategic direction

òòòòòò

The strategy reset announced in February 2025

was developed through a comprehensive

engagement programme undertaken in 2024 and

early 2025. The perspectives of various

stakeholders were considered including investors

and our employees. Wide-ranging views helped

to inform the decisions taken by the board

regarding the strategy reset. This engagement

supported the board’s confidence that their

decisions had taken account of evolving

stakeholder expectations.



	See more on key decisions, page 79

Building trust in bp

òòò

Two important themes in helping to maintain and

enhance organizational trust are safety

performance and culture.

On safety, valuable insights were gained from

investors, employees and business partners via

in-person meetings, online meetings and director

site visits. Examples this year included visits to

the Castellón refinery in Spain and operations in

the Permian Basin in the US.

Culture was a prominent theme of WFEP

sessions in 2024 with valuable feedback shared

on culture at bp, including the impact of agile

working and leadership training programmes.

In addition, directors continued to advocate for

bp’s culture of speaking up, and the board

reviewed an anonymized summary of Pulse

employee survey reports and OpenTalk reports

(bp’s whistleblowing service). For more on

culture see page 87.

Opportunities for collaboration

òòòòò

By attending talks, events and site visits with our

partners and suppliers (such as Reliance, Infosys

and Aviation Fuelling Services at Heathrow

airport (UK)), the board had the opportunity to

discuss and learn more about safety, technology

and the future of the energy sector.

Similarly, engagements with governments and

regulators and consideration of wider society’s

interests focused on generating shared value.

For example, investment opportunities (Kaskida

platform, Gulf of America), redevelopment

opportunities (Kirkuk Field, Iraq) and exploration

of lower carbon energy solutions (Net Zero

Teesside Power, UK).

The directors also reflected on integration, safety

and customer-centricity on their visits to retail

sites such as TravelCenters of America in the

US and the Hemel Hempstead fuel terminal in

the UK.

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.



	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 68. Further information on the board’s activities and key decisions, including how stakeholder interests have been considered, can be found on pages 76-78 and page 79.




bp office in Pune, India



Stakeholders key ò Investors and shareholders ò Customers ò Workforce ò Governments and regulators ò Partners and suppliers ò Society


« See glossary on page 351		bp Annual Report and Form 20-F 2024		79




		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. They must 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 key decisions taken by the board during 2024 and how stakeholder considerations have been taken into account in the board’s

discussions and decision making.


80		bp Annual Report and Form 20-F 2024






Safety and sustainability committee



Melody Meyer Safety and sustainability committee chair

The committee undertook

a number of site visits to

engage with employees

and observe bp’s safety

and sustainability culture

and performance in person.



Meetings and attendance
The committee met five times during 2024. Regular attendees included SVP internal audit, EVP production & operations, EVP strategy, sustainability & ventures, SVP HSE and carbon, SVP safety and operational risk assurance, SVP sustainability and VP internal audit – safety and sustainability.
Non-executive directors	Five scheduled meetings
Melody Meyer: member (from May 2017), chair of the committee (from November 2019)	5/5
Satish Pai: membera	4/5
Sir John Sawers: member (until April 2024)	1/1
Johannes Teyssen: member	5/5
a Satish Pai was unable to attend the scheduled meeting in June 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 2024.

Safety performance remained a focal point for

the committee during the year, with the

committee observing significant progress made

in reducing tier 1 process safety incidents. This

included overseeing management’s progress in

the implementation of Process Safety

Improvement Plans (PSIPs) across the company,

with deeper dives on personal safety, operational

integrity and threat risk across a number of our

businesses and operations.

Tragically, we lost a colleague in our recently

acquired bp bioenergy business in Brazil from

injuries sustained during an operational activity.

We extend our deep condolences to his family

and colleagues. Management reported on the

actions being taken to embed the bp Operational

Management System across bp bioenergy and to

learn from this incident.

The committee undertook a number of site visits

to engage with employees and observe bp’s

safety and sustainability culture and

performance in person. The committee members

appreciated the candour and culture experienced

at each site visited, details on page 81.

Looking forward to 2025, the committee will

focus its oversight on maintaining the good

progress and continuous improvement in safety

performance and implementation of the updated

sustainability aims (further detail on page 38).

Role of the committee

The committee oversees the management of

safety and sustainability matters, including

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 2025

Activities during the year

Overseeing improved safety

performance

•One primary focus of the committee is the

oversight of safety performance, critically

analysing management’s progress in the

reduction of tier 1 and 2 process safety

events«. During 2024, the committee

oversaw improved tier 1 safety performance,

with tier 1 safety events being 67% lower than

in 2023.

•Additionally, the committee oversaw the

implementation of PSIPs to address a 17%

increase in tier 2 safety events in the year.

This included overseeing the continued

embedding of the Refining, Terminals and

Pipelines 5-Point Plan, created as a priority

initiative following fatalities at the Toledo

refinery in September 2022.

•In addition, the committee received:

–Routine updates from the EVP production

& operations on safety and operational

performance and key safety moments

from around the business.

–Reports on major operational, security

(including crisis management and

business continuity) and cyber security

incidents (for example, detail on learnings

from the global CrowdStrike outage in

July 2024).

–Deep-dive updates regarding significant or

material events and specific risk areas

within the business, including a fatality at

Guariroba mill in our recently acquired bp

bioenergy business in Brazil from

exposure to steam at extreme

temperature, and a full shutdown at

Whiting refinery in the US resulting from a

power outage. The committee challenged

management on the root cause and

learnings from these incidents and how

learnings are embedded into existing

safety processes.

–The committee also made

recommendations to the remuneration

committee regarding safety remuneration

targets and outcomes. This included

critically analysing current methodologies

for the setting of targets to ensure they

are appropriately achievable while

remaining stretching.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		81




		Corporate governance

Providing challenge on risk

management

•The committee plays an important role in the

bp risk management process, providing

independent challenge to management on the

processes and procedures implemented to

manage safety and sustainability risk. This is

achieved by reviewing and monitoring the

principal risks allocated to it by the board

through deep-dive updates, for example

related to wells, product quality and ethical

misconduct and non-compliance.

•Proactive deep-dives are made into specific

areas of risk within the business. For

example, the committee began receiving

enhanced reporting on risk management

within the bpx energy business, which

continued into 2024. This reporting has

allowed the committee to challenge the

business on the cascading of safety learnings

and implementation of process safety

improvement plans, demonstrated by

improved safety performance within bpx

energy during 2024.



			Sustainability initiatives at Castrol, India – September 2024 The committee observed first-hand several of Castrol’s innovative sustainability initiatives, including ambient temperature blending, electricity optimization measures and its strategy to use 100% renewable energy from the local grid. The trip was also an opportunity to hear from the local team how it has improved safety performance through digitization, including automated maintenance management.
		The local team provided the S&SC with an insight into its implementation of the 5-Point Plan and other PSIPs.

Castellón refinery, Spain

Insights from Castellón refinery, Spain – July 2024 During the S&SC’s trip to Castellón refinery the team provided an insight into its implementation of the 5-Point Plan and other PSIPs. The team also briefed the committee on the cascading of learnings following a fatality on-site in 2021, including consequent reinforcement of the Life Saving Rules on-site and piloting of a bespoke safety programme (Safety in Mind) to embed human performance principles of safety on-site. In addition, the committee was briefed on plans to develop the asset’s green hydrogen« operations.



	Castrol plant, India

•Routine updates on the activity of internal

audit are received by the committee, including

an annual report on bp’s system of internal

control. This supports the committee by

providing an independent view on

management’s safety and sustainability

performance, helping to draw out where key

challenges and risk areas may lie.

Guiding delivery against strategy

and aims TCFD

•The committee oversees progress against

bp’s sustainability aims through receiving

routine updates from the SVP sustainability.

During 2024, deep-dives were undertaken into

each pillar of the sustainability frame, with

regular focus on management’s plans to

address areas of more challenged delivery.

•The committee remains abreast of the

current global sustainability reporting

environment, including bp’s plans for

compliance. For example, in November, the

committee received a joint update with the

audit committee on bp’s plans for compliance

with the EU Corporate Sustainability

Reporting Directive and EU Taxonomy

Regulation.

•Recommendations were made to the

remuneration committee regarding

sustainability-linked remuneration targets and

outcomes. For example, the committee made

a recommendation to the remuneration

committee to move the 2024 annual cash

bonus target from sustainable emissions

reductions to one based on operational

emissions reductions (see remuneration

report on page 88).


Key
TCFD	Information that supports TCFD Recommendations and Recommended Disclosures in relation to governance (see pages 42-45)


82		bp Annual Report and Form 20-F 2024






Audit committee



Tushar Morzaria Audit committee chair

The committee oversaw

significant change in bp’s

reporting processes in

the year.



Meetings and attendance
The committee met nine times during 2024. Regular attendees included the chief financial officer (CFO), SVP accounting, reporting and control, SVP internal audit, EVP legal, and the external auditor.
Non-executive directors	Nine scheduled meetings
Tushar Morzaria: member (from September 2020), chair of the committee (from May 2021)	9/9
Pamela Daley: member	9/9
Paula Reynolds: member (until April 2024)	2/2
Karen Richardson: member	9/9
Hina Nagarajan: membera	8/9

a Hina was unable to attend the meeting in December due to an

b Target first introduced in bp’s first quarter 2024 group results announcement referred to as cash costs savings. Cash costs has the same meaning as underlying operating expenditure«.

existing external commitment.

Chair’s introduction

Dear fellow shareholders,

I am pleased to present the audit committee

report for the year ended 31 December 2024.

At the heart of the committee’s role is bp’s

financial reporting – monitoring its continued

integrity, overseeing management’s control

procedures and assessing 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 is work we

undertake on behalf of the board, co-ordinating

with some of the board’s other committees for

their relevant input and ultimately making

recommendations to the board in support of the

governance processes we have established.

In pursuit of this agenda, the committee oversaw

significant change in bp’s reporting processes in

the year, with the introduction of trading

statements which are now issued shortly after

the end of the quarter to provide up-to-date

performance insights.

A highlight of our activity during the year has

included monitoring progress against bp’s target

relating to the delivery of savingsb, and the

committee will continue to monitor progress in

2025 following the announcement on 26

February 2025 to deliver between $4-5 billion of

structural cost reductions« by the end of 2027.

An additional highlight was a deep-dive into how

bp manages risks associated with the integration

of acquisitions.

Against the backdrop of an ever-changing

regulatory environment, the committee has

engaged with management to assess bp’s

approach to new sustainability reporting and the

requirements of the new UK Corporate

Governance Code 2024, receiving regular

updates on implementation and plans for

compliance.

We spent time with the trading and shipping

team (now the supply, trading and shipping

team) in Houston, US and our business and

technology centers in Pune, India, both being

strategically significant areas of bp’s business.

Read more on page 83. 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 2025.

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 335 and the full terms of

reference can be viewed at bp.com/governance.

Tushar Morzaria

Committee chair

6 March 2025




	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. •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.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		83




		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 oversaw change in bp’s

reporting processes, playing a key role in

reviewing the governance, assurance and

reporting arrangements for trading

statements, which were introduced for the

first quarter of 2024 with the aim of providing

performance insights to investors ahead of

the release of quarterly results.

•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 considered carefully (and challenged

constructively where appropriate) for example

certain enhancements to the longer-term viability

statement.

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 annual

report was fair, balanced and understandable.

The bp Annual Report and Form 20-F was

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

discussed bp’s approach to acquisition

integration. The session focused on the

implementation of revised policies and

requirements to manage risk and reduce

complexity in aligning new acquisitions with

bp’s control environment.

•Through supply, trading and shipping

updates, the committee reviewed risks to

trading such as market, liquidity, credit,

operational and people risks and control

items. In light of the changing macro and

energy price environment, the committee

considered the LNG hedging strategy ahead

of the winter period, and reviewed and

challenged the longer-term outlook for energy

prices against bp’s price assumptions.

•The committee reviewed the affordability of

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.

–an update on compliance with business

regulations, together with additional

briefings during the year on technical

accounting updates and developing ESG

disclosures. TCFD

•The committee remained prepared for

regulatory developments, including receiving

updates on the consideration of

enhancements to bp's risk management and

internal control framework as a result of the

new 2024 UK Corporate Governance Code,

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 and

subsequent actions to remediate, and reviewed

progress towards addressing deficiencies that

had been previously identified in relation to

manual journal controls. Further details on

internal controls in place for financial reporting

can be found on page 336.

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, to

take into account the expected increase in new

reporting obligations. TCFD




	bp North American headquarters, Houston, US

	US site visit – June 2024 The committee engaged with a range of internal stakeholders during the board’s visit to the US in 2024. They toured the supply, trading and shipping activities in Houston, an important part of bp’s portfolio, with a focus on biogas, natural gas and power, and met with the local leadership team.




	bp office in Pune, India

	India site visit – September 2024 During the committee’s visit to India, the directors met internal stakeholders based in Pune, ending with a session with the local leadership team. As part of their floor walks across bp’s sites, the committee engaged with the finance, business and technology team on their growth story, portfolio and accomplishments.


Key
TCFD	Information that supports TCFD Recommendations and Recommended Disclosures in relation to Governance (see pages 42-45)


84		bp Annual Report and Form 20-F 2024






Audit committee continued

Overseeing the relationship with

external and internal audit

•On the recommendation of the committee,

the board will propose the reappointment of

Deloitte as our external auditor to

shareholders at the 2025 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 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. 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

and discussing an update on actions taken in

response to the recommendations of an

external quality assessment conducted by

PwC in 2022. 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). It is anticipated

that a re-tender will be completed by 2026, for

the 2028 audit. The committee believes that the

timeline is in the best interests of shareholders,

providing an appropriate balance between

knowledge of controls and risks, maintaining

audit quality, independence and objectivity and

value for money.

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 2024 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 SVP accounting, reporting and

control or the CFO. More information is outlined

in the principal accountant’s fees and services on

page 337.

Examples of how key accounting judgements and estimates were considered and addressed,

and how relevant accounting policies have been applied




Key accounting judgements and estimates	Audit committee activity	Conclusions/outcomes
Impact of climate change and the energy transition TCFD
Climate change and the transition to a lower carbon economy may have significant impacts on the currently reported amounts of the group’s assets and liabilities and on similar assets and liabilities that may be recognized in the future.	•Reviewed management’s best estimate of oil and natural gas price assumptions for value-in-use impairment testing and investment appraisal. •Reviewed management’s determination that its best estimate of oil and natural gas prices is in line with a range of transition paths consistent with the goals of the Paris climate change agreement.	•Management’s revised best estimate 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.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		85




		Corporate governance




Key accounting judgements and estimates	Audit committee activity	Conclusions/outcomes
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 $11.8 billion were recognized on the balance sheet at 31 December 2024. •The discount rate used by bp to determine the balance sheet obligation at the end of 2024 was a nominal rate of 4.5% based on long-dated US government bonds, an increase of 0.5% from 2023.
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 $4.4 billion at 31 December 2024.
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 $5.4 billion were recognized on the balance sheet at 31 December 2024. •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 2024, surpluses of $7.5 billion and deficits of $4.9 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 2023. 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.
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 $7.4 billion, $1.8 billion and $0.4 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 2024. • 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 $16.0 billion and $14.4 billion, respectively, recognized on the balance sheet for level 3 derivative financial instruments at 31 December 2024, mainly relating to the activities of the 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.


86		bp Annual Report and Form 20-F 2024






People, culture and governance committee



Helge Lund People, culture and governance committee chair

2024 has been a busy year

for the committee, with a

strong focus on leadership

succession and

development.



Meetings and attendance
The committee met seven times during 2024. The CEO and EVP people, culture & communications regularly attend these meetings.
Non-executive directors	Six scheduled meetings	One ad hoc meeting
Helge Lund: member (from July 2018), chair of the committee (from September 2018)	6/6	1/1
Dame Amanda Blanc: membera	6/6	0/1
Dr Johannes Teyssen: member (from April 2024)	3/3	1/1
Hina Nagarajan: member (from April 2024)	3/3	1/1
Paula Rosput Reynolds: member (until April 2024)b	2/3	0/0
Sir John Sawers: member (until April 2024)	3/3	0/0
a Dame Amanda was unable to attend the ad hoc meeting in October due to an existing external commitment. b Paula was unable to attend the scheduled meeting in February due to an existing external commitment.

Chair’s introduction

Dear fellow shareholders,

I am pleased to present the people, culture and

governance committee (PCGC) report for the

year ended 31 December 2024.

2024 has been a busy year for the committee,

with a strong focus on leadership succession

and development. This is to position bp to

leverage the skills and experience we have in

pursuit of our strategy.

In 2023 our emergency executive succession

plans were tested – successfully – with the

appointments of Murray Auchincloss and Kate

Thomson into interim positions, prior to their

permanent appointments as CEO and CFO in

January and February 2024 respectively.

Following the board’s decision in January 2024

to appoint Murray Auchincloss as our permanent

CEO, the committee oversaw the launch of a new

leadership team structure.

Succession and development plans for executive

roles across the short, medium and long term

have been refreshed and are routinely reviewed

by the committee. The committee also revised

emergency succession plans, which will continue

to be assessed and reviewed for the key CEO

and CFO roles.

Non-executive director succession was also at

the forefront of the committee’s agenda in 2024,

seeking candidates who will fulfil the agreed

criteria for emerging vacancies on our board,

with a particular focus on a permanent

successor with the experience to take on the

chairmanship of the remuneration committee

and former executives with global,

transformation experience in large, complex

industrial companies both from within and

outside of the sector. This helps us to ensure we

can maintain an effective board with the

necessary skills and experience to drive forward

bp’s strategy.

We recognize that a strong culture – particularly

a culture of caring for others and speaking up –

is vital in times of change. In 2024, the

committee changed its name from the people

and governance committee to the PCGC to

reflect its broader remit in relation to culture and

engagement, including the monitoring of bp’s

‘Who we are’ culture frame and how it is being

embedded.

A strong culture requires continuous focus and

the committee’s enhanced oversight of the

effectiveness and continual embedding of bp’s

culture frame will provide valuable insight about

bp’s culture and areas where further focus is

required.

On behalf of my colleagues on the committee,

I would like to thank the management team

working to support and advise us in the delivery

of the committee's priorities and look forward to

building on the substantial progress made.

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 required. The PCGC

oversees the development of a diverse pipeline

for succession to the board and leadership team

through succession planning and monitoring

development plans for bp leaders and beyond.

The committee provides oversight of 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.

Helge Lund

Committee chair

6 March 2025


« See glossary on page 351		bp Annual Report and Form 20-F 2024		87




		Corporate governance

Activities during the year

Planning for the future: the board and

bp’s leadership team

•As set out in our 2023 report, the committee

endorsed the appointments of Murray

Auchincloss and Kate Thomson as CEO and

CFO, respectively in 2024. By routinely

reviewing succession plans for the board, bp

leadership team and senior leadership

positions, and also taking into account the

skills and diversity profiles we aspire to

achieve for our leaders, the PCGC prepares

and shapes bp’s leadership structure to be fit

for the future.

•The committee oversaw a proposed

restructuring of bp’s leadership team under

the new CEO, reflecting the importance of

organizational focus, simplification, and value

growth. The new leadership team structure

was effective from April 2024. Read more on

page 74.

•Through updates from the EVP people,

culture & communications, the committee

oversees development plans for bp’s senior

leaders and emerging talent and their

alignment with executive succession planning

over different timescales. Development

plans identify critical experience and roles

to bolster the skills of individuals with

executive potential.

•The committee assessed non-executive

candidates against agreed criteria for non-

executive rolesa to equip the board with the

skills and diversity needed to meet current

and future needs, focusing on candidates

primarily from the UK and US with industry,

safety, operational and remuneration

committee experience.

Diversity: continued progress

•Early in 2024, the committee recommended

the appointment of Kate Thomson as CFO for

approval by the board. Kate is bp’s first

female CFO. Dame Amanda Blanc was also

appointed as SID, meaning that 50% of senior

positions on bp’s board are now represented

by women, and as a whole the board has 55%

female representation – this aligns with our

board diversity, equity and inclusion (DE&I)

policy aspiration towards gender parity on

the board.

•The committee proposed amendments to the

board DE&I policy to better inform the board

and committee's approach to succession

planning, recognising the benefits of diversity

to decision-making and outcomes.

•The board DE&I policy applies to the board

aThe committee engaged Heidrick & Struggles, Korn Ferry, Spencer Stuart, Egon Zehnder and MWM Consulting in support of search activity for new board candidates. None of the search agents

have any connection with the company or individual directors, save that Spencer Stuart supports on executive recruitment and Egon Zehnder provides advice and support on bp’s executive

development programme.

bThere is no connection between Independent Board Evaluation and either bp or the individual directors.

aThe committee engaged Heidrick & Struggles, Korn Ferry, Spencer Stuart, Egon Zehnder and MWM Consulting in support of search activity for new board candidates. None of the search agents

have any connection with the company or individual directors, save that Spencer Stuart supports on executive recruitment and Egon Zehnder provides advice and support on bp’s executive

development programme.

bThere is no connection between Independent Board Evaluation and either bp or the individual directors.

and its committees, and complements bp’s

wider diversity policies, the group’s values,

code of conduct and sustainability frame.

It includes board gender and ethnicity

representation targets aligned with the UK

Listing Rules and a commitment by directors

to increase their understanding of all aspects

of diversity, equity and inclusion. Read more

at bp.com/governance.

Strengthening oversight of culture

and the voice of the workforce

•Following the standing down of the culture-

focused ‘Who we are’ oversight committee,

the PCGC oversaw the roll-out of the

refreshed bp conflicts of interest policy, which

incorporates bp’s requirements on

relationships at work.

•The committee has undertaken work relating

to its broadened oversight of engagement,

culture, and how culture has been embedded,

which included monitoring feedback from the

workforce on the refreshed conflicts of

interest policy.

•The committee’s oversight of bp’s culture was

enhanced through private sessions with bp’s

head of ethics and compliance (E&C) who has

accountability to, and direct channels of

communication with, the PCGC. The

committee approves the appointment and

termination of the head of E&C and reviews

and recommends their remuneration to the

remuneration committee.

•The workforce engagement programme

(WFEP) was refined to incorporate culture-

related questions, and quarterly culture-

focused sessions were implemented to help

the committee understand the workforce’s

experience of the ‘Who we are’ culture frame.

The committee provided workforce views and

feedback to the board, strengthening

consideration of workforce views in board

discussions and decisions. The committee

concluded that the WFEP is the appropriate

mechanism for workforce engagement, given

the activities and structure of bp. Read more

on page 78.

Enhancing the effectiveness

of the board

•The board performance review in 2023

highlighted the importance of the board’s role

in monitoring culture as an important

underpin of the company’s performance. This

led to the broadening of the committee’s

remit in relation to culture and engagement

as already discussed within this report. The

2023 review also triggered a comprehensive

programme of strategy workshops,

comprising discussions between the board

and members of the bp leadership team at

each board meeting during 2024. This

concluded with the announcement on 26

February 2025 that presented a fundamental

reset of the company’s strategy.

•For 2024, the annual board and committee

performance review was facilitated externally

by Independent Board Evaluationb (IBE).

Inputs were sought by IBE from board

members, key executives and advisors,

culminating in a discussion about the report

at our board meeting in March 2025.

•Following this discussion, the board agreed to

implement actions across the following four

areas, with the monitoring and tracking of

these actions delegated to the company

secretary:

–Succession planning, induction and

leadership interactions: succession

planning will focus on the key roles and

skills required within the board and senior

management for the new strategy. This

will include the creation of further

opportunities or interactions with

management who have high leadership

potential.

–Performance management culture: ensure

that bp has a culture where members of

the leadership team are held to account

for performance delivery and capital

allocation.

–Risk management and governance: more

in-depth discussions around emerging

risks and their potential impact on

organizational resilience and

sustainability.




	Diversity statistics and outcomes
	As at 31 December 2024, 55% of the board were women, two senior board positions were held by women and three directors identified as being from a minority ethnic background, which exceeds the UK Listing Rules targets. For further numerical data on the ethnic background and gender identity or sex of bp's board and executive management, in line with the UK Listing Rules, see page 111. As at 31 December 2024, senior management, defined as the leadership team (being the first layer of management below board level) and the company secretary, in accordance with the UK Corporate Governance Code 2018, and their direct reports comprised 50% women (2023 51%) and 29% Black, Asian and other ethnic minority individuals (2023 26%). bp has an ethnicity ambition to 2025, read more about this on page 58.


88		bp Annual Report and Form 20-F 2024






Directors’ remuneration report



Tushar Morzaria Interim remuneration committee chair



2024 has been a challenging year operationally but one in which bp has set the foundations for growth as a simpler, more efficient business.



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 remuneration of the chief financial officer (CFO) and 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 seven times during 2024 and all directors attended each meeting.
Non-executive directors	Six scheduled meetings	One ad-hoc meeting
Tushar Morzaria: member (September 2020), interim chair of the committee (April 2024)a	6/6	1/1
Paula Rosput Reynolds: member (September 2017), chair of the committee (May 2018 to April 2024)a	2/2	1/1
Dame Amanda Blanc: member	6/6	1/1
Pamela Daley: member	6/6	1/1
Melody Meyer: member	6/6	1/1

a Paula Rosput Reynolds stepped down from the board at the 2024 AGM. Tushar Morzaria was appointed as interim remuneration committee chair from this date.


Key
TCFD	Information that supports TCFD Recommendations and Recommended Disclosures in relation to Governance (see pages 42-45)

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




	Contents
	Remuneration at a glance	91
	Engaging with our workforce	93
	Executive directors’ pay for 2024	95
	2024 annual bonus outcome	96
	2022-24 performance share plan outcome	99
	Policy implementation for 2025	102
	Stewardship and executive director interests	106
	Chair and non-executive director outcomes and interests	107

reference is on page 335 and the full terms can

be reviewed at bp.com/governance.

Key areas of focus in 2024

•Change in leadership – set the remuneration

terms for the CEO and CFO, who were

appointed to their respective roles on 17

January 2024 and 2 February 2024.

•Workforce engagement – engaged with the

wider workforce on performance, reward and

wellbeing. This included holding a workforce

engagement programme session in May

2024, 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

2024 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 introduced a framework to

help guide decisions going forward.

•Merit-based reviews – reviewed pay for

performance arrangements for the leadership

population in line with bp’s reward principles.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		89




		Corporate governance

Chair’s introduction

Dear fellow shareholders,

On behalf of the board, I am pleased to present

our 2024 directors’ remuneration report.

This report provides an overview of our current

remuneration policy, details the remuneration

decisions we have made in respect of the year

ended 31 December 2024 and provides a

summary of how the policy is being implemented

this year.

As this is my first report since being appointed as

interim chair of the remuneration committee in

April 2024, I would like to take this opportunity to

thank my predecessor, Paula Rosput Reynolds,

for her exemplary leadership since 2018.

I intend to continue in my interim role until at

least the 2025 AGM in order to provide a robust

and timely handover with the incoming

remuneration committee chair once appointed to

the board.

Business performance

2024 has been a challenging year operationally

but one in which bp has set the foundations for

growth as a simpler, more efficient business.

Significant progress has been made in 2024 to

focus, high grade and reshape bp’s portfolio. bp

delivered operating cash flow« of $27.3 billion

and adjusted EBITDA« of $38.0 billion with

upstream production 2.0% higher than in 2023.

There were also a number of strategic

milestones, with final investment decision (FID)

taken on 10 major projects« and establishing

key strategic partnerships.

In July 2024, bp made the FID on the Kaskida

project in the Gulf of America, demonstrating our

long-term commitment to delivering reliable and

affordable energy. Further, progress was made in

Iraq and India, where we agreed new access on a

material scale. We have also made progress with

our renewables business. Significant among

them were our holdings in Lightsource bp and bp

Bunge Bioenergia being raised to 100%. In

addition, the proposed joint venture with JERA

Co., Inc. will create a leader in offshore wind

development and help grow the scale of the

business in a capital-light way for bp.

Alongside this strategic progress, bp delivered

a $0.8 billion reduction in structural costs«

during the year, creating a strong platform

for 2025.

Nevertheless, it was a difficult year in parts of our

customers & products businesses, particularly in

refining. Margins were lower and the significant

power outage at our refinery in Whiting had a

direct impact on our operational and financial

performance during the year, which is in turn

reflected in remuneration outcomes.

The macroeconomic environment and lower

aThe directors’ remuneration report in the bp Annual Report and Form 20-F 2023 refers to an ‘adjusted free cash flow’ measure in the 2024 annual bonus scorecard. This has the same definition as the

‘modified free cash flow’ measure reported here.

prices added to a challenging backdrop.

Incentive outcomes

2024 annual bonus

The 2024 annual bonus was based on a

scorecard of performance measures across

three categories: safety and sustainability (30%

weight), operations (20% weight) and financials

(50% weight).

Safety and sustainability

Safety continues to come first in everything we

do at bp and we place extensive focus on

ensuring that our operations run safely every day.

Safety performance is measured against the

number of tier 1 and tier 2 process safety

events« (7.5% weight each). The measures are

assessed independently by the safety and

sustainability committee, thus providing

appropriate focus on tier 1 delivery.

The committee is pleased to report that the

number of tier 1 events was lower in 2024

compared to the prior year and continues the

positive trend we have seen in recent years. In

contrast, there was an increase in the number of

tier 2 events compared to the prior year, with 35

events in 2024. This increase has negatively

impacted results delivering a combined outcome

of 67% of maximum.

At the start of 2024, a framework was introduced

to help guide the committee's decisions on the

impact of fatalities on remuneration outcomes.

The framework was intended to avoid formulaic

outcomes vis-à-vis fatalities, instead providing

guardrails for informed judgement in the

conclusions we make, while also recognizing that

every incident is different and should be reflected

upon individually.

I am saddened to report that there was a fatality

in October 2024 in the newly acquired bp

bioenergy business. Details of how the

framework has been applied in respect of this

year's bonus outcomes are provided on page 98.

We continue our focus on sustainability. This

was the first year that sustainability performance

was measured against operated carbon

emissions (15% weight). bp's performance was

strong, delivering 1.8Mte ahead of our scorecard

target, which resulted in an outcome of 84%

of maximum.

Operations

The reliability« and availability« of our plants

and refineries were impacted by operational

challenges throughout the year, including the

power outage at Whiting in February. This was

partly offset by strong performance in other

areas of the business, such as North Africa.

The bonus outcome, however, was nil for

this measure.

For 2024, we introduced a new operations

measure that focused on earnings growth in our

transition growth« engines. Significant

headwinds in certain parts of the business, along

with the continued operational challenges within

our customers & products businesses, resulted

in this component of the scorecard yielding a nil

outcome.

Financials

We have two measures of financial performance:

annual adjusted EBITDA« and modified free cash

flow«a.

In line with policy, we reflect underlying

performance and hence the targets for both

financial measures are adjusted for the actual

price environment.

Despite recovery in the latter half of the year,

financial performance was impacted by the

operational challenges cited elsewhere. Adjusted

EBITDA delivery at $38.0 billion and modified free

cash flow at $12.5 billion were both below

threshold resulting in nil bonus outcomes.

Overall result

The formulaic outcome of the annual bonus was

below target at 0.45 out of 2.00 (22.5% of

maximum).

The committee reflected on this score and

determined it was appropriate for executive

directors and the senior leadership of the

company covering approximately 300

employees. We did, however, apply discretion

and award a higher score (but below target) to

the wider workforce covering over 38,000 eligible

employees in recognition of motivation and

engagement levels. bp is undergoing enormous

transformation and a shrinking workforce will

carry significant accountability.

2022-24 performance shares

The 2022-24 performance shares were

measured against relative TSR (20% weight),

return on average capital employed« (ROACE)

(20% weight), adjusted EBIDA per share

compound annual growth rate (CAGR)« (20%

weight) and strategic progress (40% weight).

rTSR

For relative TSR, bp placed sixth in the

comparator group which resulted in nil vesting

for this measure.

Financials

Financial performance was strong over the three-

year performance period and both performance

measures achieved full vesting. The 2022-24

average ROACE was 20.9%, significantly

outperforming expectations. Similarly, adjusted

EBIDA per share CAGR performance of 11.1%

exceeded the level required for maximum

vesting.


90		bp Annual Report and Form 20-F 2024






Directors’ remuneration report continued

Strategic progress

Strategic progress was measured based on a

balance of quantitative assessment and

qualitative judgement against the three strategic

pillars set in 2022. This was supplemented with

the committee’s judgement on overall progress

in the three years of this plan, especially in the

final year of the plan.

As set out in the 2023 directors' remuneration

report, in terms of the quantitative assessment,

the committee also took into account value

generation over the period, rather than focusing

solely on volume metrics for each pillar of this

measure. Further, the committee also considered

the various actions taken by management,

contextual to our evolving strategy during the

three-year period.

We provide a detailed view of the committee’s

review of strategic progress on pages 100-101.

Having considered the above, the committee

determined that while commitments set out in

early 2022 were not fully realized, good progress

had been made. An outcome of 66% of

maximum was felt appropriate for this measure.

Overall result

Overall, performance share vesting for the

2022-24 cycle was 66.5% of maximum. The

committee believes that this final outcome is an

appropriate reflection of actual performance

during the period and therefore has not applied

any further discretion.

In determining the bonus and equity outcomes

the committee has reviewed incentives

holistically taking into consideration the total

remuneration for Murray and Kate (2024 single

figures of £5.4 million and £1.9 million

respectively). We determined that this quantum

for individuals managing a company of bp’s size

and scale felt appropriate for 2024, taking into

account both the performance of the company

and shareholder experience.

Looking ahead to 2025

Annual pay review

Kate Thomson was appointed to the board on

2 February 2024 and her remuneration

arrangements were set in line with our policy. Her

base pay was set at £800,000, which was at a

lower level than her predecessor and was based

on her being newly appointed to the board, while

also allowing for progression in role over time.

In last year’s report, we noted that any future

adjustment to Kate’s base pay may exceed the

percentage for the wider workforce subject to

performance in role. Since then, the committee

has reflected on Kate's performance and her

competitive positioning against the policy-

determined peer group. During a period of

significant change for bp, Kate performed

strongly and displayed impressive leadership

skills. She has clearly proven her capability over

the course of the year.

In light of Kate’s progression in role and very

strong performance to date, the committee

decided that it would be appropriate to increase

her base pay by 8%. This will be effective from

the 2025 AGM.

For Murray Auchincloss, his base pay will

increase by 4%, which is in line with the increase

being awarded to the wider workforce.

When reflecting on pay decisions for executive

directors, the committee remains mindful of the

transformation drive in the company as well as

the approach being taken for our wider workforce

pay. For 2025, the average salary increase in the

UK will be 4%. Adjustments in other jurisdictions

vary by local conditions. All employees in the UK

earn at least the UK Living Wage.

Review of performance measures

For 2025, in line with policy, we have reviewed

and aligned the measures of the bonus and

performance share plan against our reset

strategy, as set out on 26 February.

Alignment with strategy and financial

frame

As outlined by Murray and Kate at the Capital

Markets Update in February, bp has reset its

strategy, simplifying our forward-looking

commitments with four primary targets; adjusted

free cash flow« growth, structural cost

reduction, ROACE and net debt«. You will see

that, where appropriate, these targets form the

basis for our incentive scorecards.

Consequently, the earnings measure in the

annual bonus scorecard will be replaced with a

structural cost reduction measure (25% weight).

By way of balance, and to signal the importance

of cash delivery, the modified free cash flow

measure will increase in weight from 25% to

30%.

Reflecting the focus of our strategy, we have

removed the transition growth engine growth

measure, and in its place increased the weighting

of bp-operated reliability and availability from

10% to 15%. In doing so, we have simplified the

scorecard from 6 to 5 measures.

Our focus on safety and emissions has not

changed and therefore the current measures and

weightings under this category will remain the

same.

For performance share awards, we reflected on

the appropriate mix of financial measures in the

scorecard for 2025-27 – taking into

consideration the priorities set out in the strategy

update.

To better reflect the importance of cash

generation, we have replaced the earnings

measure with adjusted free cash flow CAGR« in

our scorecard (20% weight). The committee

believes the dual focus of modified free cash

flow in the short term and adjusted free cash

flow CAGR over the long term is appropriate for

the scorecards as they bring focus and are

aligned to bp’s strategy.

Further, we are proposing to align the ROACE

measure with our external commitments, with

performance being assessed to the end of 2027

and adjusted for the environment.

All other measures from the 2024-26 plan remain

unchanged.

Alignment with stakeholders

During the year, we continued our practice of

regular engagement with shareholders. We

engaged with our top shareholders and investor

bodies, accounting for over 35% of issued share

capital, and have taken into consideration their

views when determining the 2024 remuneration

outcomes and 2025 performance measures. We

have tried to strike a balance between broader

shareholder experience and executive motivation

in determining the overall bonus and share plan

outcomes.

Concluding remarks

I hope that you find this year’s report a clear

account of the committee’s application of the

remuneration policy during the year.

On behalf of the committee, I would like to

extend my thanks to our various advisors,

shareholders and investor bodies for their input

and engagement during the year. While 2024

was a year of mixed performance, we are

thankful for the support received and look

forward to continuing this journey in 2025.

At the forthcoming AGM there will be an advisory

vote in respect of the directors’ remuneration

report and I look forward to your continued

support of remuneration at bp.

Tushar Morzaria

Interim chair of the remuneration committee

6 March 2025


92		bp Annual Report and Form 20-F 2024






Remuneration at a glance continued


Application of remuneration policy for 2025

Set out below is an illustration of how the remuneration policy will be implemented for 2025.


	2025	2026	2027	2028	2029	2030	2031
Fixed pay (salary, pension and benefits)								•Upon appointment in 2024, the CEO’s and CFO’s salaries were set at £1.45  million and £0.8 million respectively. Their salaries remained unchanged in respect of 2024. •For 2025, Murray's salary will increase by 4% in line with the wider workforce. Kate’s salary will increase by 8%, reflecting her performance and development in role since appointment.
Annual bonusa								•CEO’s max opportunity: 225% of salary. •CFO’s max opportunity: 225% of salary. •For 2025, a structural cost reduction measure has been introduced to the bonus scorecard (see below).
Performance shares								•CEO’s max opportunity: 500% of salary. •CFO’s max opportunity: 450% of salary. •For 2025-27, an adjusted free cash flow CAGR measure has been introduced to the performance shares scorecard (see below).
Shareholding requirement								•In-employment and post-employment guidelines will continue to apply.

1-year

performance period

3-year

deferral period

3-year

performance period

3-year

holding period

aHalf the bonus is paid in cash, and half is deferred into bp shares for three years up until ‘minimum shareholding requirement’ is met. At this point, 67% is paid in cash and 33% is deferred into bp shares.




Alignment of 2025 variable remuneration with strategy

Each year, the committee aims to set a remuneration framework for executive directors that supports and incentivizes the execution of our strategy.

For 2025, the performance measures in the annual bonus and performance shares scorecards have been refined to align with our reset strategy. Measures

that have been introduced for 2025 have been marked with below. Further details on the rationale for their inclusion can be found on pages 104-105.


		Net zero by 2050 or sooner	Financial frame	Strategy
Annual bonus
Safety and sustainability (30%)
	Tier 1 and tier 2 process safety events«			ò
	Operated carbon emissions	ò		ò
Financials and operations (70%)
	Modified free cash flow« ($bn)		ò	ò
	Structural cost reductions« ($bn)		ò	ò
	bp-operated reliability« and availability«			ò
Performance shares
	Cumulative reduction % in operated carbon emissions (15%)	ò
	Relative TSR (25%)		ò
	ROACE« (20%)		ò	ò
	Adjusted free cash flow CAGR« (20%)		ò	ò
	Strategic progress (20%)			ò


« See glossary on page 351		bp Annual Report and Form 20-F 2024		93




		Corporate governance

Directors’ remuneration report continued

Engaging with our workforce

As a committee, we spend considerable time on matters relating to performance and remuneration arrangements across

the wider 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.


Alignment of executive and workforce remuneration
All employees	Element of remuneration	Executive directors

Salary is the basis for a competitive total reward package for all employees, and 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.	Salary	The salaries of our executive directors are reviewed annually, along the same timeline as the wider workforce. The review of salaries will take into account the same factors considered for the wider workforce. Salary increases for executive directors will typically be at or below the workforce rate, other than in specific circumstances.


We operate different pension plans by location and for those parts of our business where market practice is markedly different, e.g. our retail business. For our population of non-retail employees in the UK, we provide a flexible cash benefits allowance of 20% of salary. The benefits available are aligned with competitive market practice in our different jurisdictions.	Pensions and benefits	Executive directors receive a cash allowance in lieu of pension aligned with the wider workforce (currently 20% of salary). Other than the provisions of car, security and tax preparation related benefits, benefit packages are broadly aligned with those of other employees in the UK.


More than half of the eligible workforce participate in an annual cash bonus plan that multiplies a grade-based target bonus amount by a bp performance factor derived from the bonus scorecard. Select participants may be nominated to receive an uplift to their bonus outcome, reflecting their personal contribution and impact. We operate different bonus plans for those distinct parts of our business where market practice is markedly different.	Annual bonus	The annual bonus for the executive directors is linked to the same bp performance factor as for the wider workforce. Executive directors are not entitled to a bonus uplift linked to individual performance. For executive directors, a portion of any award is deferred into shares for three years. The deferral rate depends on whether the executive director has met their minimum shareholding requirement.


We operate share plans with three-year vesting for all our senior leaders. Opportunity varies across two broad tiers: group leaders (approximately 300) and senior-level leaders (approximately 4,500).	Performance shares	Executive directors are eligible for performance share awards, which are subject to stretching performance targets over a three-year period. An additional three-year post-vesting holding period applies for executive directors.

Other elements of pay

Recognition

energize!, our global recognition platform,

is open to all employees for peer-to-peer

recognition. The scheme aims to celebrate

employee’s contributions, highlight behaviours

vital to our success and drive a performance

edge. In 2024, a total of 38,800 energize! awards

were made.

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.

Senior leaders and our executive directors fully

participate in the programmes, typically by giving

recognition.

Focus@bp

At 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 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 2024, the participation rate in the

scheme was 65% of eligible employees.


94		bp Annual Report and Form 20-F 2024






Directors’ remuneration report continued

Workforce highlights in 2024

Supporting employees during transformation

Health and wellbeing

Within the context of our ongoing organizational transformation, we have

deepened our global wellbeing resources to help support our employees

during this time.

We have created new education modules for leaders to help support their

teams through change, hosted sessions to help equip our people with tools

to navigate change, worked collaboratively with our employee assistance

programme partner to deepen their support resources including introducing

a new product to offer proactive check-ins with a counsellor and offering a

broad range of webinars and educational material.

Fostering a high-performance and inclusive culture

We remain focused on building a performance-based organization, that is

representative of the world around us and an inclusive culture that creates

a sense of belonging where people can perform at their best.

As part of organizational transformation, we have embedded assurance

processes within the selection process centred around promoting fairness

and inclusivity for all. In addition, we have engaged with our business

resource groups, using listening sessions and regular feedback channels to

understand concerns and requests for support.

Workforce engagement

bp places particular importance on engaging

with employees, recognizing that it is critical to

have an engaged workforce to deliver our

strategy.

We aim to have an open dialogue between the

board, senior management and the wider

workforce and encourage employees to share

their views. For example, employees are kept

regularly informed of matters of interest to

them through bp's intranet, social media

channels, town halls, site visits and webinars.

During 2024, we continued to actively seek

employee views through a variety of discussion

groups. We held a number of employee-led

forums and consulted our business resource

groups, with a board-led session as part of the

workforce engagement programme (WFEP) in

May 2024 (see right).

More detail on bp's WFEP can be found on

page 78.

We have worked to develop a

bp where our people can be

themselves and work in a

company that cares while

also delivering results...

Employees at our Cherry Point refinery, US

Shareholder views

We are committed to ongoing engagement with

our shareholders. We believe it is important to

meet regularly to understand their views on our

remuneration arrangements and their evolving

expectations.

Feedback received frames our decisions on

executive pay and other topics.

Employee forum

In May 2024 we held a WFEP session with

selected employees from different locations

across the globe.

The session was led by Dame Amanda Blanc,

senior independent director, and Kerry

Dryburgh, EVP people, culture &

communications.

The focus of the session was on performance,

reward and employee engagement, with

employees taking the opportunity to share

their personal views and experiences of

working at bp.

In the session, individuals commented on the

strong sense of culture at bp, referencing how

our values are clearly present in day-to-day

activities. The recent changes to reward, such

as the introduction of a bonus uplift relating to

individual performance, were also well received

and considered motivational.

Key themes of the session were shared

with the committee and have provided

valuable insight.

bp.com/reportingcentre

Oak Tree retail site, Surrey, UK

Reward in our new businesses

As we have acquired a number of new businesses – including

TravelCenters of America in May 2023 and more recently Lightsource bp

and bp bionergy in October 2024 – we have reviewed the reward framework

of each new business on an individual basis. As part of these reviews, it is

recognized that a universal approach may not meet the unique needs of the

business.

As part of this process, consideration is given to the local market and talent

pool in which the new business predominately operates. For example, the

acquisition of TravelCenters of America fundamentally changed our US

footprint. The deal added a network of around 290 retail sites across the US

and over 20,000 employees to bp’s population. Therefore, when reflecting

on our reward offering the focus has been on simplification and aligning

incentives with the US retail market.

This differs from the approach taken at bp bioenergy, where the workforce

consists of over 8,800 employees and 5,600 contractors across our

operated mills in Brazil and the annual reward cycle is based on a March

year-end in line with the local crop season.

From a safety perspective, our intention is to embed bp’s safety culture,

operating systems and practices across all our businesses. We

acknowledge this can take time depending on the complexity of the newly

acquired businessa.

aFor recently acquired businesses, there is typically a transition period while bp’s operating standards, as set out in our Operating Management System«, are integrated or aligned.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		95




		Corporate governance

Executive directors’ pay for 2024

Single figure table – executive directors (audited)a


	Murray Auchinclossb thousand 2024	Kate Thomsonc thousand 2024	Murray Auchinclossb thousand 2023
Salary	£1,450	£731	£1,015
Benefits	£132	£67	£338
Cash allowance in lieu of pension	£290	£146	£190
Annual bonusd	£734	£370	£1,839
Performance sharese,f	£2,750	£575	£4,362
Total remuneration	£5,356	£1,889	£7,744
Total fixed remuneration	£1,872	£944	£1,543
Total variable remuneration	£3,484	£945	£6,201

aDue to rounding, the totals may not agree exactly with the sum of the component parts.

bMurray Auchincloss was appointed interim CEO on 12 September 2023, having previously been CFO. He was appointed as the permanent CEO on 17 January 2024.

cKate Thomson was appointed as permanent CFO and joined the board effective from 2 February 2024. The amounts disclosed reflect her service in the 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 97 for further detail on the approach taken for the 2024 annual bonus.

eFor Murray Auchincloss, the value of the performance share award has been calculated using the average share price in the last three months of 2024 of £3.90 and includes notional dividends accrued up

to 14 February 2025. For 2023, the performance shares have been restated to reflect the share price on the date of vesting of £4.52 and actual dividends received.

fFor Kate Thomson, the value of the performance share award relates to her previous role prior to her appointment to the board, but has been included in the table above for transparency. The award has

been calculated using the average share price in the last three months of 2024 of £3.90 and includes notional dividends up to 14 February 2025. For 2022-24, performance share awards below board had a

different scorecard to executive directors, which resulted in an outcome of 73% of maximum.

Overview of single figure outcomes

Salary

On 12 September 2023, Murray Auchincloss was appointed as CEO on an interim basis and his base pay was set at £1.45 million. This remained

unchanged upon appointment to CEO on 17 January 2024. Kate Thomson was appointed CFO on 2 February 2024 and her base pay was set at £800,000.

Given their recent appointments, neither executive director received an increase in respect of 2024 as part of the annual salary review.

Benefits

Executive directors received car-related benefits, coverage of tax return preparation, security assistance, insurance and medical cover.

Murray Auchincloss’s taxable benefits materially decreased year-on-year due to the phasing out of transitional car-related benefits as reported in the 2023

directors’ remuneration report.

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.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		97




		Corporate governance

Summary of performance

Safety performance, as measured by tier 1 and 2 process safety events«,

was strong with a mechanical outcome achieving between target and

maximum performance. The number of tier 1 events is less than the prior

year, with 3 events in total for 2024 (9 in 2023). This is our lowest recorded

number on record and continues the downward trend seen in recent years.

For tier 2 events, there was an increase compared to the same period last

year, with 35 events in total for 2024 (30 in 2023).

Sustainability performance was previously assessed against sustainable

emissions reductions (SER). bp transitioned to use operated carbon

emissions from 2024, as it is a more holistic and inclusive measure that

represents the full breadth of possible operational movements and is better

suited to driving ownership and delivery across the business.

For 2024, operated carbon emissions of 33.7MtCO2e achieved an outcome

between target and maximum and is reflective of our strong progress

against net zero operations milestones. The most significant reductions in

the year came from flaring reductions and increased reliability in the

Azerbaijan, Georgia and Türkiye region and efficient project start-ups.

Emission reduction projects totalling 0.42MtCO2e implemented by our

business in 2024 included: our Gelsenkirchen refinery replaced imported

steam from a coal-fired power plant with steam produced in our own gas-

fired boilers; bpx energy’s central distribution projects, Karnes and Bingo,

which enabled decommissioning of legacy natural gas-driven equipment;

and restoration of cooling water infrastructure at Cherry Point to reliably

meet refinery needs and improve the efficiency of compressor operations.

Further detail on safety and sustainability performance over the year is

provided in the safety and sustainability committee (S&SC) report on

page 80.

Reliability and availability is a combined measure of bp-operated refining

availability« and bp-operated plant reliability« with a performance outcome

of 94.7% – achieving a nil outcome. Plant reliability strengthened year-on-

year to 95.2% (95.0% in 2023). However, refining availability was impacted

by the Whiting power outage in Q1 2024 and was below threshold at 94.3%.

Transition growth« engine adjusted EBITDA« (% growth) was introduced

as a more holistic measure focused on transition growth engine financial

delivery over the year. The measure is assessed based on annual growth

against a 2023 baseline and has achieved a nil vesting outcome. This was

primarily driven by lower than expected delivery in bioenergy, convenience

and power trading.

Financial performance, as measured by modified free cash flow« and

adjusted EBITDA, was below target. bp generated modified free cash flow

of $12.5 billion and adjusted EBITDA of $38.0 billion, which resulted in a nil

outcome for both measures. Our targets are environment-adjusted at year-

end and the revised targets for modified free cash flow and adjusted

EBITDA were $14.7 billion and $40.9 billion respectively.

Overall outcome

The formulaic score for the 2024 annual bonus was 22.5% of maximum.

The committee considered bp’s framework on fatalities when reflecting on

the formulaic outcome. Sadly, there was one fatality during the year within

our recently acquired biofuels business. Full details on the application of

the framework have been provided on page 98.

Having considered the above, alongside a holistic review of performance,

the committee determined that no discretion would be applied to the

formulaic outcome for executive directors.

Approach to deferral

In relation to the policy on deferral requirements, the committee reviewed

the executive directors’ shareholding during the year to assess if the

minimum shareholding requirement had been met.

As at 14 February 2025, the CEO’s shareholding represented 6.1x salary.

This is above the minimum shareholding requirement for the CEO of 5x

salary and his 2024 award will therefore be subject to a deferral rate of

33%. While the CFO has made strong progress towards her minimum

shareholding requirement since her appointment last year, her shareholding

represented 2.6x salary on 14 February 2025. This is below her requirement

of 4.5x of salary and her 2024 award will therefore be subject to a deferral

rate of 50%.


98		bp Annual Report and Form 20-F 2024






Directors’ remuneration report continued

bp's framework on fatalities

We are working towards our goal of eliminating

workplace fatalities. We have implemented a new

framework on fatalities. This framework,

developed in consultation with shareholders and

the safety and sustainability committee, links

safety performance directly to the bonus

scorecard.

Full details of our framework on fatalities can be found in the

2023 directors’ remuneration report.



	bp.com/investors



Framework on fatalities
¢ 1. Operations (20%)
¢ 2. Safety and sustainability (30%)
¢ 3. Financial (50%)



Safety and sustainability committee
Influence	Foreseen	Nature of deficiency


Remuneration committee
Collective responsibility	Meaningful adjustment	Judgement within a frame

Treatment of new assets




What happened during the year?	How was the framework applied?
Our goal is eliminating fatalities, life-changing injuries and tier 1 process safety events. Safety performance in 2024 During the year, we made good progress in reducing the number of tier 1 events with our lowest recorded number on record – continuing the downward trend we have seen in recent years. For tier 2 events, there was an increase compared to 2023. This result is reflective of our efforts to improve process safety at bp. However, this positive performance was overshadowed by the sad news of a fatality in our newly acquired biofuels business (acquired on 1 October 2024) during the year. The incident occurred in mid-October 2024 in Brazil during maintenance activities. While there were no other fatalities during 2024, there were four life-changing injuries. We are taking action to learn from these incidents to help us make further improvements from a personal safety perspective.	The committee consulted the framework in determining the impact of the individual fatality on the 2024 bonus outcome. Treatment of new assets The framework allows for major acquisitions to be excluded for an initial period to enable the embedding of bp’s safety culture, operating systems and practices. While a fatality in an excluded new asset will not impact the group bonus score during this transition period, there will be consideration of safety performance within this business during the year – with any adjustments being made locally. Biofuels incident In September 2024, prior to the completion of the acquisition, the committee determined that the biofuels business should be excluded for three bonus performance years (i.e. up to the 2026 performance year) for bp employees. This is reflective of the complexity of the business, with over 8,800 employees and 5,600 contractors operating in 11 mills across Brazil. The acquisition completed on 1 October 2024. From this date, bp had direct operational accountability and was able to start the process of onboarding our Operating Management System (OMS)«. The fatality occurred mid-October and therefore within the exclusion period for the group scorecard.



		No adjustment
What was the outcome?		No adjustment
In line with our framework, the committee determined that applying a discretionary adjustment to the formulaic outcome on group-wide bp staff for the fatality in the newly acquired biofuels business would not be appropriate. The incident is, however, expected to have a material impact on local bonus outcomes – with final determinations being made after the business’ year-end in March.
		resulting in a final bonus score of 22.5% for executive directors.


Process safety events over past five years
80
60
40
20
0
	2020	2021	2022	2023	2024
¢ Tier 1 process safety events ¢ Tier 2 process safety events


« See glossary on page 351		bp Annual Report and Form 20-F 2024		99




		Corporate governance

2022-24 performance share plan scorecard and outcome

2022-24 performance shares were granted under the executive directors’ incentive plan (EDIP). The scorecard for this cycle consists of 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 (40% weighting).

2022-24 performance share plan scorecard (audited)





rTSR	ROACE	Adjusted EBIDA per share CAGR	Strategic progress	Formulaic score
0%	20%	20%	26.5%	66.5% out of 100%


Categories	Measures	Threshold performance		Maximum performance	Weight	Outcome


rTSR (20% weight)	rTSR	Fourth		First	20%	0%


			Actual: Sixth

Financials (40% weight)	ROACE (average 2022-24)	13.7%		14.7%	20%	20%


			Actual: 20.9%

	Adjusted EBIDA per share CAGR	7.7%		9.7%	20%	20%


			Actual: 11.1%
			Qualitative and quantitative assessment by the committee, see pages 100-101.
Strategic progress (40% weight)	Deliver value through resilient hydrocarbon business				40%	26.5%




	Demonstrate track record, scale and value in low carbon energy




	Accelerate growth in convenience and mobility




	Formulaic outcome (out of 100%)					66.5%




Formulaic vesting 66.5% 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 66.5% out of 100%

Relative TSR

During the performance period, bp’s rTSR performance placed it sixth out of eight in the comparator group which resulted in nil vesting.

Financials

Performance for ROACE and adjusted EBIDA per share CAGR were both strong, at 20.9% and 11.1% respectively over the period, and resulted in maximum

vesting of these measures.

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 2022-24 cycle.


100		bp Annual Report and Form 20-F 2024






Directors’ remuneration report continued

Strategic progress

Overview of strategic progress (2022-24)

Performance of this measure has been challenging to assess as it spans a three-year period that has seen significant change. Our strategy has continued

to evolve and update and the criteria we set back at the start of the performance period (2022) to judge progress do not fully reflect current expectations.

Alongside assessment against three key pillars (established in 2022), the committee have also taken a broader review of the shareholder experience over

the performance period. Further, there has been consideration of mid-cycle changes we have experienced during the performance period, such as bp’s

updated transition strategy in February 2023 and the key strategic initiatives during 2024 which have laid our foundation for growth. In summary:

•Resilient hydrocarbons: Performed well across the board, with strong production delivery, plant reliability« and unit costs. This was offset by

operational challenges during the period which primarily impacted refining availability«. Ultimately, financial performance was strong against this pillar.

•Low carbon energy: Progress was mixed with a number of key initiatives completed as management adapted to our evolving strategy and tough

market conditions.

•Convenience and mobility: bp performed well across our suite of volume measures, but a very challenging market meant financial delivery was lower

than expected.

Overall performance: During the period, bp has achieved a number of strategic milestones – particularly in the last year of the performance period – and is

well positioned to drive future growth.

1. Deliver value through a resilient hydrocarbon business KPIs (as set in 2022)

Unit production cost ò On track

Unit production costs remain on track against

2025 target of $6.00/boe, with an average of

$6.01/boe over the three-year period.


2022	2023	2024	2025 target
$6.1/boe	$5.8/boe	$6.2/boe	$6.0/boe

Plant reliability ò On track

Average delivery over performance on track to

meet the 2025 target of 96.0%. Focus remains on

production management and delivering higher

reliability targets.


2022	2023	2024	2025 target
96.0%	95.0%	95.2%	96.0%

Refining availability ò Improvement required

For 2024, performance was affected by the plant-

wide power outage at Whiting. Excluding this

event would have meant we were on track to

reach target.


2022	2023	2024	2025 target
94.5%	96.1%	94.3%	96.0%



	Overview •Continued high grading of portfolio to drive higher margins. Completed joint venture conversions in Angola and Iraq, extended Indonesia production-sharing contract, completed 10 major projects and increased bpx production by 33%. •Production on track with 2024 progress broadly on plan. 2022 and 2023 production were +2% vs. plan. •The hydrocarbon business performed well against adjusted EBITDA and free cash flow measures – with actual performance ahead of expectations for both measures.

2. Demonstrate track record, scale and value in low carbon energy KPIs (as set in 2022)

Developed renewables to FID« ò Improvement required

To the end of 2024, bp has delivered 8.2GW to FID (bp net). The main

contributions have come from Lightsource bp and the 100% bp solar

pipeline (Cygnus). The solar sector has been significantly impacted by

increased interest rates, inflation and supply issues. Offshore wind has

been materially impacted by supply chain inflation across all sub-sectors

including turbines and vessels.

While good progress has been made, 2025 targets were challenging and

performance under this measure is tracking behind expectations.


2022	2023	2024	2025 target
5.8GW	6.2GW	8.2GW	20GW

Renewables pipeline« ò Strong progress

Over the three-year period, there has been substantial growth in our

renewables pipeline. This has largely been driven by Lightsource bp and

success in our bids within offshore wind.

In hydrogen, projects portfolio has been prioritised based on returns and

feasibility, with the business achieving four recent FIDs.


2022	2023	2024
37.2GW	58.3GW	60.6GW



	Overview •The low carbon energy pillar has materially transformed since the setting of targets in 2022. From a period of volume-driven origination, bp has moved into a stage of consolidation, portfolio reset and focus across all businesses within a more constrained capital frame. •Low carbon energy delivered lower adjusted EBITDA than expected over the period. This was attributable to the challenging solar market in the US in 2023 and rapid ramp-up in hydrogen and offshore wind.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		101




		Corporate governance

3. Accelerate growth in convenience and mobility KPIs (as set in 2022)

Convenience margin growth« ò On track

In 2023, the acquisition of TravelCenters of

America was completed. This is expected to

substantially grow bp’s global convenience gross

margin« in coming years and bring growth

opportunities – as seen by strong performance

in 2024 (17% vs. 2025 target of 10%).


2022	2023a	2024	2025 targeta
9%	9%	17%	10%

Strategic convenience sites« ò Ahead

We remain on track to meet our 2025 target of

3,000 sites. This has been supported by the full

ownership of Thorntons in 2021 and acquisition

of TravelCenters of America.


2022	2023	2024	2025 target
2,400	2,850	2,950	3,000

Castrol performance (revenue) ò On track

Castrol has continued to demonstrate year-on-

year earnings and volume growth, as well as

completing a number of strategic initiatives,

including a new strategic partnership with Audi

in Formula 1 and diversifying into battery-

swapping ecosystems.


2022	2023	2024	2025 targetb
$6.9bn	$7.0bn	$6.9bn	n/a



	Overview •Performance across the convenience and mobility pillar has been strong versus the targets we set at the beginning of 2022. However, market conditions have been challenging which has impacted financial delivery, leading to mixed performance. •During the period, financial performance was impacted by cost inflation, challenging market environments and prolonged impact of COVID-19 on businesses such as Castrol.

a2023 excludes the acquisition of TravelCenters of America. The 2025 target represents the wider aim of achieving ~10% CAGR by 2030 (as set in 2023).

bThe 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.



Overall assessment
In progressing our strategic agenda, we have not only reviewed performance against the three strategic pillars of our previous strategy but also key strategic highlights, many of which culminated in the last year of the performance period, including:
Low carbon energy •Completed transactions for 100% ownership of bp Bunge Bioenergia and Lightsource bp. •New joint ventures including JERA Nex bp with JERA Co., Inc. Resilient hydrocarbons •Sanctioning 10 higher value major projects – including Kaskida and Tangguh UCC. •Agreeing new access to resources in regions we know well, like the Middle East and India, where we are now technical services providers for the country’s largest offshore oil and gas field. •Gas is now flowing at our Greater Tortue Ahmeyim (GTA) project off the coast of	West Africa. Once fully commissioned, it is set to produce 2.4 million tonnes of LNG annually. Convenience and mobility •In 2024, Castrol grew underlying earnings by 14% and has demonstrated six consecutive quarters of year-on-year underlying earnings growth. Financial •Delivery of structural cost reductions of around $0.8 billion in 2024. This more than offsets significant increases from inflation, foreign exchange and costs associated with growing the business. Overall, we reduced our underlying operating expenditure by	$300 million towards our target of $4-5 billion of structural cost reductions by end-2027. Resulting score Accounting for delivery (volume and value), bp’s evolving strategic context and the above strategic milestones, the committee determined performance against this measure should result in 66% of maximum vesting (2021-23: 75% of maximum). Strategic progress remains a key component of our long-term scorecard for outstanding awards and the committee will continue to apply judgement within the context of broader strategic delivery.

Other vesting considerations

Along with the results from the scorecard measures, the committee considers an ‘underpin’ to the formulaic outcome in order to determine the final

vesting percentage. The underpin broadens our performance assessment, allowing us to consider vesting outcomes with overall alignment to absolute

shareholder returns, environmental and safety factors and progress in matters relating to low carbon and climate change. Where relevant, we take input

from the safety and sustainability committee and the audit committee to deepen and enhance our perspective.

Having considered the above, the committee concluded that the vesting outcome was suitably reflective of the company’s underlying performance and the

experience of shareholders overall. The committee agreed it was not necessary to apply discretion to the formulaic outcome and approved vesting of

66.5% for the 2022-24 EDIP award. This decision yields the outcome shown in the table below for the CEO. The scorecard detail is shown on page 99.

2022-24 performance share plan outcome (audited)


	Shares awarded	Unvested shares following application of performance factor	Value of unvested shares following application of performance factor	Impact of share price changea
Murray Auchincloss	937,500	704,790	£2,749,950	£-317,649
Kate Thomsonb	89,300	147,391	£575,090	£15,815

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

14 February 2025. The face values of these awards were calculated using a market price of ordinary shares at close on the dates of award, as follows: £4.35 on 26 May 2022 and £3.79 on 17 June 2022

respectively. The average share price during Q4 2024 was £3.90. The amount reported as 2024 income in the single figure is therefore £2.750 million for Murray and £0.575 million for Kate.

bKate Thomson's award was 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 2022-24, performance

share awards below board had a different scorecard to executive directors, which resulted in an outcome of 73% of maximum.


102		bp Annual Report and Form 20-F 2024






Directors’ remuneration report continued

Policy implementation for 2025

The current remuneration policy was approved by shareholders at the 2023 annual general meeting on 27 April 2023. The full policy is displayed on the

company’s website at bp.com/remuneration. The table below shows how the remuneration policy will be implemented in 2025, alongside a summary of

key features.


Element	Policy feature	2025 implementation
Salary	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.	•Murray Auchincloss's salary will increase by 4%, in line with the wider workforce, to £1,508,000 following the 2025 AGM. •Kate Thomson's salary will increase by 8% to £864,000 following the 2025 AGM. This is to reflect her development in role and leadership for the Finance function since appointment in February 2024. •The budgeted increase to our UK salaried staff effective from 1 April 2025, our annual salary review date, will be 4%.

Pensions and benefits	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.	•Murray and Kate’s cash allowance in lieu of pension is 20% of base pay (in line with the wider workforce). •Prior to their appointment as executive directors, Murray received a US deferred pension and Kate received a UK deferred pension. No further pension is accrued under either plan. •Benefits will remain unchanged for 2025 and include car- related provisions, security assistance, insurance and medical cover.

Annual bonus	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 2025, our scorecard will be assessed against the following categories: safety and sustainability (30%) and financials and operations (70%). •We intend to make the following changes to performance measures for 2025: –Introduce a structural cost reduction measure that is aligned with our forward-looking commitments. This replaces the earnings measures in the scorecard. –Replace the measure focused on transition growth« engines with increased weighting on modified free cash flow« and bp-operated reliability« and availability«. •See page 104 for further details on measures for the 2025 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 98.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		103




		Corporate governance


Element	Policy feature	2025 implementation
Performance shares	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 2025-27 cycle, the scorecard categories will remain unchanged from the 2024-26 cycle and will be assessed against the following: rTSR (25%), financials (40%), environmental, social and governance (15%) and strategic progress (20%). •The only change being made to the chosen performance measures for the 2025-27 cycle is the introduction of an adjusted free cash flow CAGR« measure. This replaces adjusted EBIDA CAGR per share«. All other measures are to remain the same. •See page 104 for further details on measures for the 2025-27 EDIP. •The award will continue to be subject to an underpin that takes into consideration in-year safety outcomes and long-term trends in safety outcomes over the performance period. •The 2025-27 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 2025 AGM.

Shareholding requirement	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 post-employment.	•Murray’s shareholding has reached 6.1 times salary, above his minimum shareholding requirement of 5 times of salary. •Kate’s shareholding has reached 2.6 times salary. Over the next four years, to 2029, Kate will work towards reaching her minimum shareholding requirement of 4.5 times of salary.

Malus and clawback	Operationally robust and effective malus and clawback provisions apply to our incentive awards. Malus provisions may be applied where there is: a material safety or environmental failure; 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 other exceptional circumstances that the committee considers similar in nature. Clawback provisions may apply where there is: an incorrect outcome due to miscalculation or incorrect information; a restatement due to financial reporting failure or misstatement of audited results; or material misconduct.

Committee flexibility	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 them to take broad views on alignment with shareholder experience, environmental, societal and other relevant considerations e.g. portfolio changes.


104		bp Annual Report and Form 20-F 2024






Directors’ remuneration report continued

Measures for the 2025 annual bonus

Provided below is a summary of the performance measures we have chosen for the 2025 annual bonus plan scorecard. The targets are commercially sensitive and

will be disclosed in the 2025 directors’ remuneration report.

We are replacing our earnings (adjusted EBITDA«) measure with structural cost reductions« to better align with the financial priorities set out in the Capital Markets

Update announcement in February 2025. This measure will be assessed against a 2023 baseline and is positioned to capture sustainable cost reductions that can

be maintained beyond 2027.

In line with our reset strategy, the measure on transition growth« engines has been removed from the scorecard for 2025. In the interest of simplification, the

committee determined that the scorecard should be kept to five measures. The weighting of modified free cash flow« and bp-operated reliability« and availability«

will be increased – from 25% to 30% and 10% to 15% respectively. This change mirrors our focus on cash generation and driving strong operations for 2025.

Importantly, the framework on fatalities will continue to apply to the 2025 annual bonus and will be considered at year-end if a fatality occurs during the year.

See page 98 for further detail on its application in 2024.



Safety and sustainability 30%		Financials and operations 70%
Measures include	Weighting	Measures include	Weighting
Tier 1 and tier 2 process safety events« (measured separately)	15%	Modified free cash flow	30%
Operated carbon emissions	15%	Structural cost reduction	25%
		bp-operated reliability and availability	15%

Measures for the 2025-27 performance shares (EDIP)

Provided below is a summary of the measures we have chosen for the 2025-27 performance share plan. The four categories remain unchanged from the prior year

and there has been no change to respective weightings.

Under our financials category, we are proposing to introduce an adjusted free cash flow CAGR measure (20% weight) and to modify the ROACE measure to align

with our strategic commitments. The committee reflected on the dual focus of free cash flow in the short and long-term incentive scorecards and determined it was

appropriate given our strategic focus on cash generation – with adjusted free cash flow being a primary target in bp’s reset strategy. The two cash measures;

modified free cash flow and adjusted free cash flow CAGR are different, with the former covering a holistic view of in-year cash generation (including working capital

and proceeds) and the latter representing underlying free cash flow growth, removing more volatile items, in line with our external targets. The ROACE measure now

fully aligns with our external targets with measurement at the end of 2027.

For strategic progress, the measure will remain subject to the committee’s judgement at the end of the three-year period. The judgement of performance will take

into account progress against the financial targets set under our reset strategy – including reference to measures such as divestments, net debt« and structural

cost reductions. This will be alongside our holistic review of progress against our strategy, to ensure that outcomes are aligned with the shareholder experience.



	rTSR										Financials												Environmental, social and governance						Strategic progress
	25%										20%						20%						15%						20%
	Peer group of seven companies: Chevron, Eni, Equinor, ExxonMobil, Repsol, Shell and TotalEnergies (and bp)a										ROACEb«						Adjusted free cash flow CAGRc						Cumulative reduction % in operated carbon emissionsd						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 36.5%	37.5%	38.5%	39.5%	Above 40.5%
		rTSR ranking									ROACE						Adjusted free cash flow CAGR						Cumulative reduction % in operated carbon emissions

•Underpin will take into account safety outcomes prior to determining final vesting percentage.

•Remuneration committee discretion will reflect shareholder experience, environment, societal and other inputs.

•Robust malus and clawback may apply in certain circumstances.

aNil vesting for fifth place or lower.

bBased on ROACE at the end of the three-year period. Targets will be adjusted for the environment.

c Annualised growth rate of adjusted free cash flow vs. 2024 baseline. Targets will be adjusted for the environment.

dScope 1 and 2 GHG emission reductions vs. 2019 baseline from operated carbon emissions including portfolio change.

aNil vesting for fifth place or lower.

bBased on ROACE at the end of the three-year period. Targets will be adjusted for the environment.

c Annualised growth rate of adjusted free cash flow vs. 2024 baseline. Targets will be adjusted for the environment.

dScope 1 and 2 GHG emission reductions vs. 2019 baseline from operated carbon emissions including portfolio change.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		105




		Corporate governance

Provided below is an overview of the performance measures and weightings of each of our in-flight awards.

Measures for 2023-25 performance shares



	rTSR										Financials												Environmental, social and governance						Strategic progressa
	20%										20%						20%						15%						25%
	Peer group of seven companies: Chevron, Eni, Equinor, ExxonMobil, Repsol, Shell and TotalEnergies (and bp)										ROACE (average 2023-25)						Adjusted EBIDA per share CAGR						Net zero across entire bp operations by 2050 (Scope 1 + 2)						Weighting of measures subject to remuneration committee judgement: •Deliver value through a resilient hydrocarbon business. •Demonstrate track record, scale and value in low carbon energy. •Accelerate growth in convenience and mobility.

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 20.2%	20.7%	21.2%	21.7%	Above 22.2%		Below 12.5%	13.0%	13.5%	14.0%	Above 14.5%		Below 12%	13%	14%	15%	Above 16%
		rTSR ranking									ROACE						Adjusted EBIDA per share CAGR						Net zero

Measures for 2024-26 performance shares



	rTSR										Financials												Environmental, social and governance						Strategic progress
	25%										20%						20%						15%						20%
	Peer group of seven companies: Chevron, Eni, Equinor, ExxonMobil, Repsol, Shell and TotalEnergies (and bp)										ROACE (average 2024-26)						Adjusted EBIDA per share CAGR						Cumulative reduction % in operated carbon emissions						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 39%	40%	41%	42%	Above 43%
		rTSR ranking									ROACE						Adjusted EBIDA per share CAGR						Cumulative reduction % in operated carbon emissions

aPerformance against the three pillars will be reviewed and scored in the context of the strategic changes announced in 2023 and the Capital Markets Update in February 2025.


106		bp Annual Report and Form 20-F 2024






Directors’ remuneration report continued

Stewardship and executive director interests

We believe that our executive directors should build and maintain a material 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)

The table below details the personal shareholdings of each executive director. These figures include all beneficial and non-beneficial ownership of shares

of bp (or calculated equivalents) that have been disclosed to the company. Murray Auchincloss has met the minimum shareholding requirement (MSR)

under the policy. Kate Thomson is expected to satisfy the policy requirement that applies five years from her date of appointment, 2 February 2024. The

committee has reviewed and confirmed this position and will continue to monitor compliance with this policy.


	Directors’ ordinary shares or equivalents at 14 Feb 2025	Aggregated interests at 14 Feb 2025, all plans				Current shareholding for MSRb	Value of current shareholdingc, £	Multiple of salary achieved
		Unvested awards not subject to performance conditions		Unvested awards subject to performance conditions
		Sharesa	Options	Shares	Options
Murray Auchinclossd	1,319,688	1,387,250	152,301	2,200,575	—	1,888,476	8,838,068	6.1
Kate Thomson	230,357	350,322	500,000	808,846	—	437,799	2,048,899	2.6

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 14 February 2025 of £4.68.

dIncludes interests of a person closely associated with Murray Auchincloss.

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 2024 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
Murray Auchincloss	2024-26 EDIP Performanceb	1,482,617	7 May 2024	7,472,390	May 2027
Kate Thomson	2024-26 EDIP Performanceb	736,196	7 May 2024	3,710,428	May 2027
Murray Auchincloss	2024 EDIP Deferredc	124,128	7 May 2024	625,605	May 2027

aThe face value of awards granted during 2024 have been calculated using a market price of ordinary shares at close on the date of award, as follows: £5.04 on 7 May 2024. 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 that was held

on 25 April 2024 (£4.89).

bPerformance 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 averaged over the performance period, 20% adjusted EBIDA per share CAGR measured vs. year ended June 2020 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 2024 to 31 December 2026.

The 2025 performance share awards under EDIP are expected to be made following the conclusion of the 2025 annual general meeting.

cThere is no identified minimum vesting threshold level. The 2024 bonus year deferred share awards under EDIP are expected to be made following the conclusion of the 2025 annual general meeting.

Directors and leadership team

No directors or other leadership team members own more than 1% of the shares in issue. At 14 February 2025, our directors and leadership team

members collectively held interests of 6,288,180 ordinary shares or their calculated equivalents, 4,339,104 restricted share units (with or without

conditions) or their calculated equivalents, 7,399,346 performance shares or their calculated equivalents and 6,174,714 options over ordinary shares or

their calculated equivalents, under bp group share option schemes.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		107




		Corporate governance

Chair and non-executive director outcomes and 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 and any changes are put into effect from 1 April. Taking all

factors into consideration, for 2025 the board agreed to implement a 4% increase to the base fee for NEDs and for the SID, aligned with the salary increase

budget for the UK wider workforce. Determination of the fees payable to the chair falls to the remuneration committee, which agreed to align the

percentage increase of the chair's fee with the other NEDs. Following board and remuneration committee approval, the remuneration arrangements for the

chair and NEDs will be adjusted with effect from 1 April 2025.


£ thousand per annum	2025/26 fees	2024/25 fees
Chair	888	854
Senior independent director	181.5	174.5
Board member	130.5	125.5
Audit, remuneration and safety and sustainability committees chairship	35	35
Committee membership	20	20

2024 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, Helge Lund 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	2024	2023	2024	2023	2024	2023
Dame Amanda Blanc	198	159	1	2	198	161
Pamela Daley	164	159	17	67	181	226
Helge Lund (chair)	845	809	38	66	882	875
Melody Meyera	182	184	9	29	191	213
Tushar Morzaria	189	174	1	3	190	177
Hina Nagarajanb	157	116	17	32	174	148
Satish Paib	144	116	5	39	149	155
Paula Rosput Reynoldsb	72	220	6	20	78	240
Karen Richardsonc	169	178	16	18	185	196
Sir John Sawersb	57	174	12	7	68	181
Dr Johannes Teyssena	160	149	5	15	165	164

aFee includes £10,000 p.a. for being a member of the bp geopolitical advisory council. The fee for this role ceased effective 1 April 2024.

bHina Nagarajan and Satish Pai were appointed on 1 March 2023. Paula Rosput Reynolds and Sir John Sawers retired on 25 April 2024.

cFee includes £25,000 p.a. for chairing the bp digital advisory council.

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 Jan 2024	At 31 Dec 2024	Changes to 14 Feb 2025	At 14 Feb 2025	Value of current shareholdingb	% of guideline achieved
Dame Amanda Blanc	23,500	23,500	—	23,500	£109,980	88%
Pamela Daley	40,332	40,332	—	40,332	$235,270	147%
Helge Lund (chair)	600,000	600,000	—	600,000	£2,808,000	329%
Melody Meyer	20,646	38,646	—	38,646	$225,435	141%
Tushar Morzaria	71,972	71,972	—	71,972	£336,829	268%
Hina Nagarajan	10,000	25,944	—	25,944	£121,418	97%
Satish Pai	12,000	33,000	—	33,000	$192,500	120%
Paula Rosput Reynoldsc	78,378	—	—	—	—	—
Karen Richardson	29,316	35,316	—	35,316	$206,010	128%
Sir John Sawersc	24,242	—	—	—	—	—
Dr Johannes Teyssen	35,000	35,000	—	35,000	£163,800	131%

aIncludes interests of persons closely associated.

bBased on ordinary share and ADS prices at 14 February 2025 of £4.68 and $35.00. Where a US$ value is provided these shares are held as ADSs.

cPaula Rosput Reynolds and Sir John Sawers retired on 25 April 2024.


108		bp Annual Report and Form 20-F 2024






Directors’ remuneration report continued

Past directors

Payments for loss of office (audited)

No payments were made during the financial year for loss of office, except as already disclosed in the 2023 directors’ remuneration report.

Payments to past directors (audited)

No payments were made during the financial year to past directors, except as already disclosed in the 2023 directors’ remuneration report.

Post-employment benefits (audited)

Bob Dudley and Brian Gilvary were provided with tax return preparation support amounting to £1,779 and £11,455 respectively.

We made no other payments within the scope of the disclosure requirements to any past director of bp during 2024 (we have no de minimis threshold for

such disclosures).

Other disclosures


Historical TSR performance												Relative importance of spend on pay ($ million)

£250												Distribution to bp shareholders			Remuneration paid to all employees			Capital investmenta
£250												Distribution to bp shareholders			Remuneration paid to all employees			Capital investmenta
£200
£150
£100
£50
£0

	2014	2015	2016	2017	2018	2019	2020	2021	2022	2023	2024		2023	2024		2023	2024		2023	2024
¢ BP												a Organic capital expenditure.
¢ FTSE 100												a Organic capital expenditure.

The graph above shows the growth in value of hypothetical £100 investments in BP p.l.c. ordinary shares, and in the FTSE 100 index (of which bp is a

constituent), over 10 years from 31 December 2014 to 31 December 2024.

History of chief executive officer remuneration


Year	Chief executive officer	Total remuneration, thousand	Annual bonus % of maximum	Performance shares % of maximum
2015	Bob Dudley	$19,376	100	74.3
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
2023a,b	Bernard Looney	£1,175	n/a	n/a
	Murray Auchincloss	£5,391	79.5	75
2024c	Murray Auchincloss	£5,356	22.5	66.5

a2020 and 2023 figures show remuneration for the periods of qualifying service as CEO during the respective years.

bAs reported in the 2023 directors’ remuneration report, Bernard Looney stepped down as CEO and from the board of directors with immediate effect on 12 September 2023 and was succeeded by Murray

Auchincloss as interim CEO on the same date. In 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. For Murray Auchincloss, the 2023 figure has been updated based on the actual share price used for vesting of £4.52.

cShare price has been based on the average share price over Q4 of the 2024 FY of £3.90.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		109




		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
2024c	Option A	196:1	74:1	37:1
		£27,343	£72,678	£143,202
		(£25,304)	(£54,106)	(£92,900)

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, 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. 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 2024 FY of £3.90.

This is our sixth year reporting the CEO pay ratio following the requirements introduced in 2018. As per the past five 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 2024.

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 six 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 2024, the 50th percentile pay

ratio decreased from 103:1 to 74:1. This was largely driven by the outcomes of the CEO’s variable awards, with the lowest bonus outcome in the past 10

years (excluding nil bonus for 2020) and the performance share award being granted at a lower multiple of salary when he was in position as CFO.

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 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.

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.


	2024 vs. 2023			2023 vs. 2022			2022 vs. 2021			2021 vs. 2020			2020 vs. 2019
Percentage change for:	a	b	c	a	b	c	a	b	c	a	b	c	a	b	c
Employees	4%	0%	-65%	6%	1%	4%	2%	1%	45%	7%	-9%	100%	0%	0%	-100%
Murray Auchincloss	43%	-61%	-60%	30%	283%	31%	7%	530%	3%	5%	5%	100%	—	—	—
Kate Thomson	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Dame Amanda Blanc	24%	-72%	n/a	38%	100%	n/a	—	—	n/a	—	—	n/a	—	—	n/a
Pamela Daley	3%	-75%	n/a	2%	2%	n/a	7%	43%	n/a	4%	1385%	n/a	-15%	-92%	n/a
Helge Lund (chair)	4%	-43%	n/a	3%	78%	n/a	0%	97%	n/a	0%	-24%	n/a	0%	-74%	n/a
Melody Meyer	-1%	-68%	n/a	2%	-14%	n/a	13%	139%	n/a	-4%	283%	n/a	9%	-77%	n/a
Tushar Morzaria	9%	-73%	n/a	2%	-46%	n/a	25%	100%	n/a	5%	0%	n/a	—	—	n/a
Hina Nagarajan	13%	-46%	n/a	—	—	n/a	—	—	n/a	—	—	n/a	—	—	n/a
Satish Pai	3%	-88%	n/a	—	—	n/a	—	—	n/a	—	—	n/a	—	—	n/a
Paula Rosput Reynolds	3%	-70%	n/a	2%	-14%	n/a	16%	145%	n/a	—	228%	n/a	2%	-92%	n/a
Karen Richardson	-5%	-12%	n/a	11%	-20%	n/a	30%	96%	n/a	—	—	n/a	—	—	n/a
Sir John Sawers	3%	63%	n/a	2%	105%	n/a	17%	1%	n/a	—	1588%	n/a	—	-83%	n/a
Johannes Teyssen	7%	-68%	n/a	3%	12%	n/a	21%	65%	n/a	—	—	n/a	—	—	n/a


110		bp Annual Report and Form 20-F 2024






Directors’ remuneration report continued

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 2024 is set out in the remuneration committee report on page 88.

During 2024 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, SVP reward.

PricewaterhouseCoopers LLP (PwC) continued to provide independent advice to the committee in 2024. PwC advice included, for example, support with

remuneration benchmarking and updates on market practice. PwC is a member of the Remuneration Consulting Group and, as such, operates 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 the PwC engagement partner 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 2024 (save in respect of legal advice)

were £88,751 to PwC. Freshfields LLP (Freshfields) provided legal advice on specific compliance matters to the committee. PwC and Freshfields provide

other advice in their respective areas to the group.

Considerations related to the UK Corporate Governance Code

When setting the 2023 policy, the committee concluded that a scorecard-based approach to setting targets and measuring outcomes helps it to engage

transparently with shareholders and the wider workforce on remuneration. Thus, bp continues to operate a simple, clear structure of market-aligned salary

with annual and three-year performance-based incentives. Risks are managed through careful setting of performance measures and targets and the

committee retains the exercise of its discretion in assessing outcomes. These are complemented with robust malus and clawback measures.

Remuneration outcomes are predictable, as shown in the implementation charts of the 2023 policy, and proportional by virtue of the challenging

performance levels required to achieve target pay outcomes. Through material weighting in measures related to safety, sustainability and strategy, as

shown on page 104, remuneration aligns closely with bp’s culture, as expressed through our purpose and ambition.

Shareholder engagement

Throughout 2024 the committee engaged frequently on remuneration policy and approach with bp’s largest shareholders, as well as their representative

bodies. This dialogue will continue throughout 2025. The table below shows the recent votes on the directors’ remuneration report and policy.


Year	% vote ‘for’	% vote ‘against’	Votes withheld
2024 – Directors’ remuneration report	95.88%	4.12%	37,229,024
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
Murray Auchincloss	17 Jan 2024	17 Jan 2024
Kate Thomson	2 Feb 2024	2 Feb 2024

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 directors are subject to annual re-election by shareholders at the annual general meeting. Normally, NEDs will be encouraged to serve for up to

nine years from their appointment in line with the provisions of the 2018 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 2024 are shown below.


	Appointee company	Additional position held at appointee company	Total fees, £
Murray Auchinclossa	Aker BP ASAb	Director	0
Kate Thomson	Aker BP ASAb	Director	0

aMurray resigned from this position during 2024.

bHeld as a result of the company’s shareholding in Aker BP ASA.

This directors’ remuneration report was approved by the board and signed on its behalf by Ben J.S. Mathews, company secretary, on 6 March 2025.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		111




		Corporate governance

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), bp proposes all

directors for 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 87 and board at a glance

disclosure on page 71, 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 2024 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 2024 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

72-73.

For information on board meetings held during

2024 and director attendance at board meetings,

see page 71.

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 2024, 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 2024, 55% of the board

comprises women, our senior independent director

(SID) and 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 2024. 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	5	45%	2	6	55%
Women	6	55%	2	5	45%
Other categories	–	–	–	–	–
Not specified/prefer not to say	–	–	–	–	–


Ethnic background
White British or other white (including minority-white groups)	8	73%	100%	9	82%
Mixed/Multiple Ethnic Groups	–	–	–	–	–
Asian/Asian British	3	27%	–	1	9%
Black/African/Caribbean/Black British	–	–	–	1	9%
Other ethnic group	–	–	–	–	–
Not specified/prefer not to say	–	–	–	–	–


« See glossary on page 351		bp Annual Report and Form 20-F 2024		115




	Financial statements




Consolidated financial statements of the bp group

Independent auditor's reports (PCAOB ID 1147)		134	Group statement of changes in equity		142
Group income statement		140	Group balance sheet		143
Group statement of comprehensive income		141	Group cash flow statement		144



Notes on financial statements
1.	Significant accounting policies	145	22.	Trade and other payables	185
2.	Non-current assets held for sale	163	23.	Provisions	186
3.	Business combinations	164	24.	Pensions and other post-employment benefits	187
4.	Disposals and impairment	164	24.	Pensions and other post-employment benefits	187
5.	Segmental analysis	167	25.	Cash and cash equivalents	193
6.	Sales and other operating revenues	171	26.	Finance debt	193
7.	Income statement analysis	171	27.	Capital disclosures and net debt	194
8.	Exploration for and evaluation of oil and natural gas resources	172	28.	Leases	195
8.		172	29.	Financial instruments and financial risk factors	195
9.	Taxation	172	29.	Financial instruments and financial risk factors	195
10.	Dividends	175	30.	Derivative financial instruments	201
11.	Earnings per share	175	31.	Called-up share capital	210
12.	Property, plant and equipment	177	32.	Capital and reserves	212
13.	Capital commitments	178	33.	Contingent liabilities and legal proceedings	217
14.	Goodwill	178	34.	Remuneration of senior management and non-executive directors	220
15.	Intangible assets	180	34.		220
16.	Investments in joint ventures	180	35.	Employee costs and numbers	221
17.	Investments in associates	182	36.	Auditor's remuneration	221
18.	Other investments	184	37.	Subsidiaries, joint arrangements and associates	222
19.	Inventories	184	37.	Subsidiaries, joint arrangements and associates	222
20.	Trade and other receivables	184	38.	Events after the reporting period	222
21.	Valuation and qualifying accounts	185



Supplementary information on oil and natural gas (unaudited)

Oil and natural gas exploration and production activities		224	Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves		245
Movements in estimated net proved reserves		230			245
			Operational and statistical information		248


134		bp Annual Report and Form 20-F 2024

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 2024

and 2023, 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 2024, 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

2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended 31 December 2024, 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 2024, based on criteria established in the UK Financial Reporting Council’s Guidance on Risk Management,

Internal Control and Related Financial and Business reporting relating to internal control over financial reporting and our report dated 6 March 2025

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 2024 includes PP&E, of which $56 billion is oil and gas properties.

Management’s best estimate oil and gas price assumptions for value-in-use impairment tests were revised in 2024 as set out in Note 1 on page 152,

although the revisions were not significant.

Management have also determined bp’s ‘best estimate’ discount rate assumptions, as set out in Note 1 on page 152. Bp’s post-tax discount rate used for

impairment testing for oil and gas assets in 2024 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.

Management judged that in aggregate, the year-end oil and gas price assumption revisions, changes to pre-tax discount rates for certain regions due to

country risk premium or tax rate changes and changes to other input assumptions including reserves reductions on several key fields, all combined to

constitute an impairment trigger for all oil and gas cash generating units (CGUs). As a result of testing performed during 2024, $2.0 billion of oil and gas

CGU net impairment charges were recognised, principally due to certain discount rate revisions, 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; and 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.


		bp Annual Report and Form 20-F 2024		135




	Financial statements

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.

We also identified CGUs which were less sensitive as they would be potentially at risk, in aggregate, to a material impairment by a reasonably possible

change in some or all of the key assumptions.

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, 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 29 in Baku during

November 2024. 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

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, capabilities 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 $11.8 billion is recorded in the financial statements as at 31 December 2024. 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 159. 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 increased the discount rate used in calculating its decommissioning provisions from 4.0% as at 31 December 2023 to 4.5% as at 31 December 2024.

The increase was primarily driven by increased US treasury bond rates.


136		bp Annual Report and Form 20-F 2024

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, capabilities 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 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 evaluated the reasonableness of changes in 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.


		bp Annual Report and Form 20-F 2024		137




	Financial statements

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 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 2024,

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 2024, the group’s total level 3 derivative financial assets were $16.0 billion and level 3 derivative financial liabilities were $14.4 billion.

How the Critical Audit Matter was addressed in the Audit

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 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 to consensus data; and

–analysing whether there was any indication of management bias through evaluating the distribution of valuation differences where relevant.


138		bp Annual Report and Form 20-F 2024

4.Impairment of E&A assets and refinery PP&E as a consequence, among other things, of climate change and the energy transition –

Notes 1, 4, 8 and 15 to the financial statements

Critical Audit Matter Description

Intangible Assets

The recoverability of certain of the group’s $4.4 billion total exploration and appraisal (E&A) assets capitalised as at 31 December 2024 is potentially

exposed to climate change and the global energy transition 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.

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 identified impairment indicators in respect of the Gelsenkirchen

refinery in Germany during the year and, as a result, an impairment test was performed to assess the recoverability of the Gelsenkirchen refinery carrying

value. As disclosed in Note 4 to the accounts on page 166, management has recorded an impairment charge of $0.8 billion in respect of the Gelsenkirchen

refinery, primarily driven by changes in economic assumptions. At 31 December 2024 management identified an impairment indicator for all of its other

refineries due to a reduction in the local marker margins. The impairment tests performed by management to assess the recoverability of the carrying

value of these refineries did not result in any additional impairment charges being recognised.

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 2024:

•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.

PP&E

We considered the impact of potential changes in supply and demand on the group’s refining portfolio and assessed internal and external market studies

of future supply and demand. In relation to 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 refining 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; and

•Evaluating management’s ability to forecast future cash flows and margins by comparing actual results with historical forecasts and tested

management’s internal controls over the impairment test and related inputs.

/s/ Deloitte LLP

London

United Kingdom

6 March 2025

We have served as bp’s auditor since 2018.


		bp Annual Report and Form 20-F 2024		139




	Financial statements

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 2024, based on the criteria

established in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting relating

to internal control over financial reporting (UK FRC Guidance). In our opinion, the group maintained, in all material respects, effective internal control over

financial reporting as of 31 December 2024, based on the criteria established in the UK FRC Guidance.

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 2024, of the group and our report dated 6 March 2025 expressed an unqualified opinion on

those financial statements.

As described in management’s report on internal control over financial reporting, management excluded from its assessment the internal control over

financial reporting at bp bioenergy (formerly called Bunge Bioenergia) and Lightsource bp which were acquired on 1 October 2024, and 24 October 2024,

respectively. bp bioenergy financial statement line items comprise 2.1% and 0.9% of net and total assets respectively, 0.3% of sales and other operating

revenues, and (4.5)% of profit (loss) for the year of the consolidated financial statement amounts as of and for the year ended 31 December 2024.

Lightsource bp’s financial statement line items comprise 6.3% and 2.4% of net and total assets respectively, 0.1% of sales and other operating revenues,

and (5.7)% of profit (loss) for the year of the consolidated financial statement amounts as of and for the year ended 31 December 2024. Accordingly, our

audit did not include the internal control over financial reporting at bp bioenergy and Lightsource bp.

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 2025


142		bp Annual Report and Form 20-F 2024

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
	Share capital and capital reserves	Treasury shares	Foreign currency translation reserve	Fair value reserves	Profit and loss account	bp shareholders' equity	Hybrid bonds	Other interest	Total equity
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

At 1 January 2022	46,871	(12,624)	(9,572)	(1,027)	51,815	75,463	13,041	1,935	90,439
Profit for the year	—	—	—	—	(2,487)	(2,487)	519	611	(1,357)
Other comprehensive income	—	—	6,914	770	585	8,269	—	(61)	8,208
Total comprehensive income	—	—	6,914	770	(1,902)	5,782	519	550	6,851
Dividendsb	—	—	—	—	(4,365)	(4,365)	—	(294)	(4,659)
Cash flow hedges transferred to the balance sheet, net of tax	—	—	—	1	—	1	—	—	1
Issue of ordinary share capital	820	—	—	—	—	820	—	—	820
Repurchase of ordinary share capital	—	—	—	—	(10,493)	(10,493)	—	—	(10,493)
Share-based payments, net of tax	182	471	—	—	194	847	—	—	847
Issue of perpetual hybrid bonds	—	—	—	—	(4)	(4)	374	—	370
Payments on perpetual hybrid bonds	—	—	15	—	—	15	(544)	—	(529)
Transactions involving non-controlling interests, net of tax	—	—	—	—	(513)	(513)	—	(144)	(657)
At 31 December 2022	47,873	(12,153)	(2,643)	(256)	34,732	67,553	13,390	2,047	82,990

aSee Note 32 for further information.

bSee Note 10 for further information.


		bp Annual Report and Form 20-F 2024		143




	Financial statements

Group balance sheet


At 31 December			$ million
	Note	2024	2023
Non-current assets
Property, plant and equipment	12	100,238	104,719
Goodwill	14	14,888	12,472
Intangible assets	15	9,646	9,991
Investments in joint ventures	16	12,291	12,435
Investments in associates	17	7,741	7,814
Other investments	18	1,292	2,189
Fixed assets		146,096	149,620
Loans		1,961	1,942
Trade and other receivables	20	1,815	1,767
Derivative financial instruments	30	16,114	9,980
Prepayments		548	623
Deferred tax assets	9	5,403	4,268
Defined benefit pension plan surpluses	24	7,457	7,948
		179,394	176,148
Current assets
Loans		223	240
Inventories	19	23,232	22,819
Trade and other receivables	20	27,127	31,123
Derivative financial instruments	30	5,112	12,583
Prepayments		2,594	2,520
Current tax receivable		1,096	837
Other investments	18	165	843
Cash and cash equivalents	25	39,204	33,030
		98,753	103,995
Assets classified as held for sale	2	4,081	151
		102,834	104,146
Total assets		282,228	280,294
Current liabilities
Trade and other payables	22	58,411	61,155
Derivative financial instruments	30	4,347	5,250
Accruals		6,071	6,527
Lease liabilities	28	2,660	2,650
Finance debt	26	4,474	3,284
Current tax payable		1,573	2,732
Provisions	23	3,600	4,418
		81,136	86,016
Liabilities directly associated with assets classified as held for sale	2	1,105	62
		82,241	86,078
Non-current liabilities
Other payables	22	9,409	10,076
Derivative financial instruments	30	18,532	10,402
Accruals		1,326	1,310
Lease liabilities	28	9,340	8,471
Finance debt	26	55,073	48,670
Deferred tax liabilities	9	8,428	9,617
Provisions	23	14,688	14,721
Defined benefit pension plan and other post-employment benefit plan deficits	24	4,873	5,456
		121,669	108,723
Total liabilities		203,910	194,801
Net assets		78,318	85,493
Equity
bp shareholders’ equity	32	59,246	70,283
Non-controlling interests	32	19,072	15,210
Total equity	32	78,318	85,493

Helge Lund Chair

Murray Auchincloss Chief executive officer

6 March 2025


144		bp Annual Report and Form 20-F 2024

Group cash flow statement


For the year ended 31 December				$ million
	Note	2024	2023	2022
Operating activities
Profit (loss) before taxation		6,782	23,749	15,405
Adjustments to reconcile profit before taxation to net cash provided by operating activities
Exploration expenditure written off	8	767	746	385
Depreciation, depletion and amortization	5	16,622	15,928	14,318
Impairment and (gain) loss on sale of businesses and fixed assets	4	6,317	5,488	26,656
Earnings from joint ventures and associates		(1,993)	(898)	(2,530)
Dividends received from joint ventures and associates		2,023	2,092	1,700
Remeasurement of joint ventures	3	(917)	—	—
Interest receivable		(1,512)	(1,265)	(444)
Interest received		1,450	1,119	414
Finance costs	7	4,683	3,840	2,703
Interest paid		(2,811)	(2,950)	(2,208)
Net finance expense relating to pensions and other post-employment benefits	24	(168)	(241)	(69)
Share-based payments		1,174	616	795
Net operating charge for pensions and other post-employment benefits, less contributions and benefit payments for unfunded plans	24	(182)	(193)	(257)
Net charge for provisions, less payments		(152)	(2,481)	440
(Increase) decrease in inventories		808	5,634	(5,492)
(Increase) decrease in other current and non-current assets		3,355	4,620	(18,584)
Increase (decrease) in other current and non-current liabilities		(188)	(13,592)	17,806
Income taxes paid		(8,761)	(10,173)	(10,106)
Net cash provided by operating activities		27,297	32,039	40,932
Investing activities
Expenditure on property, plant and equipment, intangible and other assets		(15,297)	(14,285)	(12,069)
Acquisitions, net of cash acquired	3	53	(799)	(3,530)
Investment in joint ventures		(850)	(1,039)	(600)
Investment in associates		(143)	(130)	(131)
Total cash capital expenditure		(16,237)	(16,253)	(16,330)
Proceeds from disposals of fixed assets	4	328	133	709
Proceeds from disposals of businesses, net of cash disposed	4	2,578	1,193	1,841
Proceeds from loan repayments		81	55	67
Net cash used in investing activities		(13,250)	(14,872)	(13,713)
Financing activities
Repurchase of shares		(7,127)	(7,918)	(9,996)
Lease liability payments		(2,833)	(2,560)	(1,961)
Proceeds from long-term financing		10,656	7,568	2,013
Repayments of long-term financing		(2,970)	(3,902)	(11,697)
Net increase (decrease) in short-term debt		(2,966)	(861)	(1,392)
Issue of perpetual hybrid bonds		4,330	175	370
Redemption of perpetual hybrid bonds	32	(1,288)	—	—
Payments relating to perpetual hybrid bonds		(1,053)	(1,008)	(708)
Payments relating to transactions involving non-controlling interests (other)		(21)	(187)	(9)
Receipts relating to transactions involving non-controlling interests (other)		1,353	546	11
Dividends paid
bp shareholders	10	(5,003)	(4,809)	(4,358)
Non-controlling interests		(375)	(403)	(294)
Net cash provided by (used in) financing activities		(7,297)	(13,359)	(28,021)
Currency translation differences relating to cash and cash equivalents		(511)	27	(684)
Increase (decrease) in cash and cash equivalents		6,239	3,835	(1,486)
Cash and cash equivalents at beginning of year		33,030	29,195	30,681
Cash and cash equivalents at end of yeara		39,269	33,030	29,195

a 2024 includes cash and cash equivalents classified as assets held for sale in the group balance sheet. See Note 2 for further information.


		bp Annual Report and Form 20-F 2024		145




	Financial statements

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 chief

executive officer and chairman on 6 March 2025 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 United Kingdom adopted

international accounting standards and IFRS Accounting Standards (IFRSs) as issued by the International Accounting Standards Board (IASB) and as

adopted by the European Union (EU) and in accordance with the provisions of the UK Companies Act 2006 as applicable to companies reporting under

international accounting standards. IFRS as adopted by the UK does not differ from IFRS as adopted by the EU. IFRS as adopted by the UK and EU 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 2024. 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 (see page 20) 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 2024.

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 2024. The revised price assumptions have been rebased in real 2023 terms and are materially consistent with

the disclosed prices in real 2022 terms. The near term Brent oil assumption was held constant at $70 per barrel to reflect near-term supply constraints

before declining after 2030 to $50 per barrel by 2050 continuing to reflect the assumption that as the energy system decarbonizes, falling oil demand will

cause oil prices to decline. The price assumptions for Henry Hub gas up to 2050 were held constant at $4.00 per mmBtu reflecting an assumption that

declining domestic demand in the US is offset by higher LNG exports. 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 consistent with the temperature goal of the Paris climate

change agreement, 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.


146		bp Annual Report and Form 20-F 2024

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 2024

value-in-use impairment tests is for the UK North Sea and the Gelsenkirchen refinery. The assumptions for UK North Sea were £59/tCO2e in 2025

gradually increasing to £231/tCO2e in 2050. The assumption applied for the Gelsenkirchen refinery was an average of approximately $97/tCO2e.

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 2024. 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 2024 that are subject to depreciation, will be depreciated within the next 12

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.


		bp Annual Report and Form 20-F 2024		147




	Financial statements

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 2024 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 for inflation and have been rebased in real 2023 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 nominal discount rate applied to provisions was increased during the year to reflect higher US Treasury yields. The principal impact of this rate

increase was a $0.9 billion decrease in the decommissioning provision with an associated decrease in the carrying amount of property, plant and

equipment of $0.7 billion and a pre-tax credit to the income statement of $0.2 billion. The post-tax impairment discount rate applicable to assets other

than renewable power assets remained consistent with 2023 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

The volatility in the financial markets during 2024 impacted the 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 securities 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 securities whether or not such distribution has been deferred.

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.


148		bp Annual Report and Form 20-F 2024

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

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 2024. 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 2024.

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 2024. 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 2022, 31 December 2023 and 31

December 2024 have not been met.

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.


		bp Annual Report and Form 20-F 2024		149




	Financial statements

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

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.

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.

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.


150		bp Annual Report and Form 20-F 2024

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

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.

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.

The estimation of oil and natural gas reserves and bp’s process to manage reserves bookings is described in Supplementary information on oil and natural

gas on page 223, which is unaudited. Details on bp’s proved reserves and production compliance and governance processes are provided on page 322.

The 2024 movements in proved reserves are reflected in the tables showing movements in oil and natural gas reserves by region in Supplementary

information on oil and natural gas (unaudited) on page 223.

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


		bp Annual Report and Form 20-F 2024		151




	Financial statements

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

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.

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 2024 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.


152		bp Annual Report and Form 20-F 2024

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 2024, the post-tax discount rate was 8% (2023 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 (2023 1% to 4%). 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 20% (2023 9% to 20%)

depending on the risk premium and applicable tax rate in the geographic location of the CGU. For renewable power assets, which were tested primarily

on a fair-value basis in 2024 (including those in equity accounted entities) tests were performed using a post-tax cost of equity-based discount rate range

of 8.75% to 9.5%. In 2023, tests were performed on a value-in-use basis using a post-tax WACC-based discount rate of 6.5%.

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 2024, the group identified oil and gas properties in these segments with carrying amounts totalling $17,853 million (2023 $18,374 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 145. The investment appraisal price assumptions are 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 are 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

2023 terms and are materially consistent with the disclosed prices in real 2022 terms. The near term Brent oil assumption was held constant at $70 per

barrel to reflect near term supply constraints before declining after 2030 to $50 per barrel by 2050 continuing to reflect the assumption that as the energy

system decarbonizes, falling oil demand will cause oil prices to decline. The price assumptions for Henry Hub gas up to 2050 were held constant at $4.00

per mmBtu reflecting an assumption that declining domestic demand in the US is offset by higher LNG exports. These price assumptions are derived

from the central case investment appraisal assumptions (see page 20). A summary of the group’s revised price assumptions for Brent oil and Henry Hub

gas, applied in 2024 and 2023, in real 2023 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 consistent with the temperature goal of the Paris climate change agreement, 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.

However, they do not correspond to any specific Paris-consistent scenario. Inflation rate of 2% - 2.5% (2023 2%) 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.


2024 price assumptions	2025	2030	2040	2050
Brent oil ($/bbl)	70	70	63	50
Henry Hub gas ($/mmBtu)	4.00	4.00	4.00	4.00


2023 price assumptions	2024	2025	2030	2040	2050
Brent oil ($/bbl)	71	71	71	59	46
Henry Hub gas ($/mmBtu)	4.06	4.05	4.05	4.05	4.05


		bp Annual Report and Form 20-F 2024		153




	Financial statements

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

Global oil production increased by 1.4% in 2024 with this growth predominantly coming from non-OPEC countries as OPEC+ continued its output

reductions. Global oil demand growth slowed, increasing by 0.9% in 2024 as we leave the post-Covid recovery period and Chinese demand fell short of

forecasts. Brent dropped by nearly $2 per barrel in 2024 in response to lacklustre demand growth and increasing supply. 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 2024 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.

US Henry Hub spot prices averaged $2.2/mmBtu in 2024 from $2.5/mmBtu in 2023. Prices fell further in order to reduce output and stimulate demand in

the power sector. Milder than normal winter weather during winter 2023/2024 left US gas storage levels over 20% above historic average levels at the end

of winter 2023/2024, causing prices to fall below $2/mmBtu. Meanwhile, after growing by 4 Bcf/d in 2023, low prices caused natural gas production to

fall by 0.4 Bcf/d in 2024, helping to bring the market back into balance. The level of US gas prices in 2024 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 $19-20 billion which is approximately 30% of the associated net book value of property, plant and equipment as at 31

December 2024. 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 World Business Council for Sustainable

Development (WBCSD) 'family' of scenarios considered to be consistent with limiting global average temperature to 1.5°C above pre-industrial levels.

This ‘family’ of scenarios is also used in bp's TCFD scenario analysis (see page 42).

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 2024. This potential increase in the carrying amount would arise due to reversals of previously recognized impairments and represents

approximately one fifth of the total impairment reversal capacity available at 31 December 2024. 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 towards the top end

until 2040, and then towards the mean average at 2050, of the range of prices associated with the WBCSD 'family' of scenarios considered to be

consistent with limiting global average temperature to 1.5°C above pre-industrial levels. This ‘family’ of scenarios is also used in bp's TCFD scenario

analysis.

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 2024 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.


154		bp Annual Report and Form 20-F 2024

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

Management considers refining margins to be the key source 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/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.

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 $14.9 billion on its balance sheet (2023 $12.5 billion), principally relating to the Atlantic Richfield, Burmah

Castrol, Devon Energy, Reliance and Lightsource bp transactions. Of this, $7.2 billion relates to goodwill in the oil production & operations segment and to

hydrocarbon CGUs within the gas & low carbon energy segment (2023 $7.0 billion), for which oil and gas price and production assumptions are key

sources of estimation uncertainty. Sensitivities and additional information relating to impairment testing of goodwill in these segments are provided in

Note 14.

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.


		bp Annual Report and Form 20-F 2024		155




	Financial statements

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

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.

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. Equity instruments issued by the group

are recognized at the proceeds received, net of directly attributable issue costs.


156		bp Annual Report and Form 20-F 2024

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:

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.


		bp Annual Report and Form 20-F 2024		157




	Financial statements

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

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.

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% (2023 4%).

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.


158		bp Annual Report and Form 20-F 2024

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

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.


		bp Annual Report and Form 20-F 2024		159




	Financial statements

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 $0.7 billion of decommissioning provisions recognized as at 31 December

2024 (2023 $0.6 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 2024 was 4.5%

(2023 4%), 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

17 years (2023 17 years) and 7 years (2023 6 years) respectively. Costs at future prices are typically determined by applying an inflation rate of 1.5%

(2023 1.5%) to decommissioning costs and 2% (2023 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 $5.5 billion (2023 $5.5 billion) within

the next 10 years, $6.2 billion (2023 $5.8 billion) in 10 to 20 years and the remainder of approximately $6.7 billion (2023 $6.6 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 $1.5 billion (2023 $1.6 billion). The pre-tax impact on the group income statement would be a

credit of approximately $0.4 billion (2023 $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 $0.3 billion (2023 $0.6 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 (2023 $1.1 billion) and a pre-tax charge of approximately $0.4 billion (2023 $0.2 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 $1.7 billion (2023 $1.9 billion) with a pre-tax charge of approximately $0.5 billion (2023 $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.


160		bp Annual Report and Form 20-F 2024

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.


		bp Annual Report and Form 20-F 2024		161




	Financial statements

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'.

In July 2023, the UK government enacted legislation to implement the Pillar Two Model rules. The legislation is effective for bp from 1 January 2024 and

includes an income inclusion rule and a domestic minimum tax, which together are designed to ensure a minimum effective tax rate of 15% in each

country in which the group operates. Similar legislation is being enacted by other governments around the world. 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 and have been applied in

accounting for current tax and deferred tax in the year, resulting in an additional non-cash deferred tax charge of approximately $0.1 billion. The extension

of the Levy to 31 March 2030 was substantively enacted after 31 December 2024 and will result in a non-cash deferred tax charge of around $0.5 billion in

the year ended 31 December 2025.

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.

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 under the share buy-back programme which are 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.


162		bp Annual Report and Form 20-F 2024

1. Material accounting policy information, significant judgements, estimates and assumptions – continued

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.

Contract asset and contract liability balances are included within amounts presented for trade receivables and other payables respectively.

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

Amendments to IAS 7 ' Statement of Cash Flows' and IFRS 7 'Financial Instruments: disclosures' relating to supplier finance have been adopted for the

consolidated financial statements for 2024, the additional required disclosures are provided in the Liquidity risk section of Note 29.

There are no new or other amended standards or interpretations adopted from 1 January 2024 onwards, that have a significant impact on the

consolidated financial statements for 2024.

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 subject to endorsement by the UK Endorsement Board. The potential impact on cash and banking operations and

amounts reported in cash and cash equivalents on adoption of the amendments is currently being assessed.

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 subject to endorsement by the UK Endorsement Board. 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 2024		163




	Financial statements

2. Non-current assets held for sale

The carrying amount of assets classified as held for sale at 31 December 2024 is $4,081 million (2023 $151 million), with associated liabilities of

$1,105 million (2023 $62 million).

gas & low carbon energy

On 16 September 2024, bp announced that it plans to sell its US onshore wind energy business, bp Wind Energy. bp Wind Energy has interests in ten

operating onshore wind energy assets across seven US states. As a result of progression of the disposal process during the fourth quarter of 2024,

completion of a disposal in 2025 is now considered to be highly probable. The carrying amount of assets classified as held for sale at 31 December 2024

is $569 million, with associated liabilities of $41 million.

On 24 October, bp completed the acquisition of the remaining 50.03% of Lightsource bp. The acquisition included certain assets for which sales processes

were in progress at the acquisition date. Completion of the sale of these assets within one year of the acquisition date is considered to be highly probable.

The carrying amount of assets classified as held for sale at 31 December 2024 is $1,702 million, with associated liabilities of $1,050 million.

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. The parties have agreed to work to complete formation of JERA Nex bp, subject to regulatory and other approvals, by end of the third quarter

of 2025. bp will contribute its development projects in the UK, Japan, Germany and US into the new joint venture. The related assets and liabilities of those

projects have, therefore, been classified as held for sale. The carrying amount of assets classified as held for sale at 31 December 2024 is $1,793 million,

with associated liabilities of $14 million.

Transactions that have been classified as held for sale during 2024, but were completed by 31 December 2024, are described below.

gas & low carbon energy

On 14 February 2024, bp and ADNOC announced that they had agreed to form a new joint venture (JV) in Egypt. On 16 December bp and XRG (ADNOC’s

international energy investment company) announced they had completed formation of Arcius Energy (51% bp, 49% XRG, ADNOC's international energy

investment company). As part of the agreement, bp contributed its interests in three development concessions, as well as exploration agreements, in

Egypt to the new JV. XRG made a proportionate cash contribution.

oil production & operations

On 4 October 2024, bp completed the sale of receivables relating to a prior divestment receiving proceeds of $890 million.

customers & products

At 31 December 2023 assets of $151 million and associated liabilities of $62 million were classified as held for sale relating to the sale of bp's Türkiye

ground fuels business to Petrol Ofisi. This included the group's interest in three joint venture terminals in Türkiye. The sale completed on 31 October 2024

and resulted in a loss on disposal of $1,132 million including recycling of cumulative foreign exchange losses from reserves of $942 million.

The total assets and liabilities held for sale at 31 December 2024 and 2023, which are in the gas & low carbon energy and customers & products segments,

are set out in the table below.


		$ million
	2024	2023
Property, plant and equipment	1,981	49
Intangible assets	333	3
Investments in joint ventures	1,182	—
Loans	—	1
Cash	65	—
Trade and other receivables	520	98
Assets classified as held for sale	4,081	151
Trade and other payables	(264)	(1)
Lease liabilities	(58)	(40)
Finance debt	(720)	—
Provisions	(63)	(10)
Defined benefit pension plan and other post-employment benefit plan deficits	—	(11)
Liabilities directly associated with assets classified as held for sale	(1,105)	(62)


164		bp Annual Report and Form 20-F 2024

3. Business combinations and other significant transactions

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 provisional 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.

Business combinations

2023

The group undertook a number of business combinations during 2023. Total consideration paid in cash amounted to $1,282 million, offset by cash

acquired of $484 million.

The fair value of the net assets (including goodwill) recognized from business combinations in the full year, inclusive of measurement period adjustments

for business combinations in previous periods, was $1,228 million. This principally related to the acquisition of TravelCenters of America.

4. Disposals and impairment

The following amounts were recognized in the income statement in respect of disposals and impairments.


			$ million
	2024	2023	2022
Gains on sale of businesses and fixed assets
gas & low carbon energy	297	19	45
oil production & operations	144	297	3,446
customers & products	190	44	374
other businesses & corporate	47	9	1
	678	369	3,866

			$ million
	2024	2023	2022
Losses on sale of businesses and fixed assets, and closures
gas & low carbon energy	303	9	—
oil production & operations	19	5	921
customers & products	1,457	143	177
other businesses & corporate	27	(1)	11,083
	1,806	156	12,181
Impairment losses
gas & low carbon energy	2,793	2,213	745
oil production & operations	1,155	1,840	4,480
customers & products	1,661	1,614	1,874
other businesses & corporate	24	80	13,536
	5,633	5,747	20,635
Impairment reversals
gas & low carbon energy	(44)	(1)	(1,333)
oil production & operations	(384)	(26)	(893)
customers & products	(1)	—	(68)
other businesses & corporate	(15)	(19)	—
	(444)	(46)	(2,294)
Impairment and losses on sale of businesses and fixed assets, and closures	6,995	5,857	30,522


		bp Annual Report and Form 20-F 2024		165




	Financial statements

4. Disposals and impairment – continued

Disposals

Disposal proceeds and principal gains and losses on disposals by segment are described below.


			$ million
	2024	2023	2022
Proceeds from disposals of fixed assets	328	133	709
Proceeds from disposals of businesses, net of cash disposed	2,578	1,193	1,841
	2,906	1,326	2,550
By business
gas & low carbon energy	840	536	22
oil production & operations	1,699	333	1,935
customers & products	291	436	592
other businesses & corporate	76	21	1
	2,906	1,326	2,550

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 2024, deferred consideration relating to

disposals amounted to $112 million receivable within one year (2023 $141 million and 2022 $191 million) and $244 million receivable after one year (2023

$217 million and 2022 $194 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 $190 million at 31 December 2024 (2023 $1,694

million and 2022 $1,896 million). The contingent consideration at 31 December 2024 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

oil production & operations

In 2023 gains principally related to prior period disposals in the US and Canada.

In 2022 gains principally related to a gain of $1,932 million arising from the contribution of bp's Angolan business to Azule Energy, a gain of $904 million

related to the deemed disposal of 12% of the group's interest in Aker BP, an associate of bp, following completion of Aker BP's acquisition of Lundin

Energy, and $349 million in relation to the disposal of the group's interest in the Rumaila field in Iraq to Basra Energy Company, an associate of bp.

2022 losses included $479 million of accumulated exchange losses previously charged to equity and taken to the income statement as a result of the

decision to exit bp's other businesses with Rosneft within Russia.

customers & products

In 2024 losses principally related to a loss of $1,132 million arising from the divestment of our Türkiye ground fuels business.

In 2022 gains principally related to a gain of $268 million arising from the divestment of our Swiss retail assets.

other businesses and corporate

In 2022 the losses on disposal of businesses and fixed assets was $11,082 million in respect of the decision to exit our holding in Rosneft which resulted

in the reclassification to the income statement of $10,372 million of accumulated exchange losses, a cash flow hedge reserve of $651 million relating to

the original acquisition of Rosneft shares and bp's cumulative share of Rosneft's other comprehensive income of $59 million which were all previously

charged to equity.

Summarized financial information relating to the sale of businesses is shown in the table below.

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.

The principal transactions categorized as a business disposal in 2022 were the formation of Azule Energy, the formation of Basra Energy Company and the

sale of our 50% interest in the Sunrise oil sands project in Canada.


166		bp Annual Report and Form 20-F 2024

4. Disposals and impairment – continued


			$ million
	2024	2023	2022

Non-current assets	1,775	1,145	3,681
Current assets	1,985	557	2,972
Non-current liabilities	(548)	(60)	(1,869)
Current liabilities	(424)	(454)	(1,074)
Total carrying amount of net assets disposed	2,788	1,188	3,710
Recycling of foreign exchange on disposal	943	—	(26)
Costs on disposal	123	57	488
	3,854	1,245	4,172
Gains (losses) on sale of businesses	(888)	158	6,219
Total consideration	2,966	1,403	10,391
Non-cash consideration	(1,003)	(51)	(8,999)
Consideration received (receivable)	615	(159)	449
Proceeds from the sale of businesses, net of cash disposeda	2,578	1,193	1,841

aProceeds are stated net of cash and cash equivalents disposed of $500 million (2023 $33 million and 2022 $318 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 2024 impairment loss of $2,793 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 $3,423 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.

The 2022 impairment loss of $745 million primarily relates to losses incurred in respect of certain assets in Mauritania & Senegal ($729 million) and

principally arose as a result of increased forecast future expenditure. The 2022 impairment reversal of $1,333 million primarily relates to the Trinidad CGU

($1,331 million) and principally arose as a result of changes to the group's oil and gas price assumptions. The recoverable amount of all CGUs for which

impairment charges or reversals were recognized in 2022 in total, based on their value in use, is $9,609 million.

oil production & operations

Impairment losses and reversals in all years relate primarily to producing assets and, in 2022, equity accounted investments.

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.

The 2022 impairment loss of $4,480 million primarily relates to impairment of the Pan American Energy Group S.L. joint venture as a result of expected

portfolio changes ($2,900 million) and the decision to exit bp's other businesses with Rosneft within Russia ($1,043 million). The 2022 impairment reversal

of $893 million principally relates to changes in price and reserves assumptions in the North Sea ($643 million). The recoverable amount of all CGUs for

which impairment charges or reversals were recognized in 2022 in total, based on their value in use, is $7,831 million.

customers & products

The 2024 impairment loss of $1,661 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 $1,659 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.

The 2022 impairment loss of $1,874 million primarily relates to changes in economic assumptions in the products business including an impairment of the

Gelsenkirchen refinery in Germany ($1,366 million), and announced portfolio changes. 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 2022 in total, based on their value in use,

is $1,648 million.


		bp Annual Report and Form 20-F 2024		167




	Financial statements

4. Disposals and impairment – continued

other businesses and corporate

The 2022 impairment loss of $13,536 million arises primarily a result of bp's decision to exit its shareholding in Rosneft ($13,479 million, including

$528 million which relates to estimated earnings in the first two months of the year prior to the loss of significant influence). The recoverable amount of

the CGU which comprises Rosneft is estimated to be $nil.

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 2024, 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 and hydrogen businesses.

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 and B2B and midstream. It also includes our products businesses, refining & oil trading, as well as our bioenergya businesses.

Other businesses and corporate also comprises the group’s shipping and treasury functions, and corporate activities worldwide.

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 lossesb.

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.

aIn February 2025 bp announced its intention to move its biogas business to the gas & low carbon energy segment.

bInventory 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.


170		bp Annual Report and Form 20-F 2024

5. Segmental analysis – continued


						$ million
						2022
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	56,255	33,193	188,623	2,299	(38,978)	241,392
Less: sales and other operating revenues between segments	(5,913)	(30,294)	(1,418)	(1,353)	38,978	—
Third party sales and other operating revenues	50,342	2,899	187,205	946	—	241,392
Earnings from joint ventures and associates – after interest and tax	148	1,609	248	525	—	2,530
Segment results
Replacement cost profit (loss) before interest and taxation	14,696	19,721	8,869	(26,737)	139	16,688
Inventory holding gains (losses)a	(8)	(7)	1,366	—	—	1,351
Profit (loss) before interest and taxation	14,688	19,714	10,235	(26,737)	139	18,039

Finance costs						(2,703)
Net finance income relating to pensions and other post- employment benefits						69
Profit before taxation						15,405
Other income statement items
Depreciation, depletion and amortization
US	75	3,141	1,328	80	—	4,624
Non-US	4,933	2,423	1,542	796	—	9,694
Charges for provisions, net of write-back of unused provisions, including change in discount rate	(234)	213	3,955	143	—	4,077
Segment assets
Investments in joint ventures and associates	5,299	11,370	3,875	57	—	20,601
Additions to non-current assetsb	4,439	15,098	9,541	1,047	—	30,125

aSee explanation of inventory holding gains and losses on page 167.

bIncludes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.


			$ 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.


			$ 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.


		bp Annual Report and Form 20-F 2024		171




	Financial statements

5. Segmental analysis – continued


			$ million
			2022
By geographical area	US	Non-US	Total
Revenues
Third party sales and other operating revenuesa	71,118	170,274	241,392
Other income statement items
Production and similar taxes	194	2,131	2,325
Non-current assets
Non-current assetsb c	60,237	89,144	149,381

aNon-US region includes UK $36,541 million.

bNon-US region includes UK $24,813 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
	2024	2023	2022
Crude oil	2,219	2,413	6,309
Oil products	121,019	128,969	149,854
Natural gas, LNG and NGLs	24,464	29,541	41,770
Non-oil products and other revenues from contracts with customers	13,362	10,298	7,896
Revenue from contracts with customers	161,064	171,221	205,829
Other operating revenuesa	28,121	38,909	35,563
Total sales and other operating revenues	189,185	210,130	241,392

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
	2024	2023	2022
Interest and other income
Interest income from
Financial assets measured at amortized cost	1,308	1,034	371
Financial assets measured at fair value through profit or loss	181	215	59
Other incomea	1,284	386	673
	2,773	1,635	1,103

Currency exchange losses charged to the income statementb	541	74	160
Expenditure on research and development	301	298	274
Costs relating to the Gulf of America oil spill (pre-interest and tax)c	51	57	84

Finance costs
Interest expense on lease liabilities	468	363	245
Interest expense on other liabilities measured at amortized costd	3,483	3,115	2,070
Capitalized at 4.94% (2023 4.88% and 2022 3.56%)e	(382)	(514)	(464)
Finance debt risk management activitiesf	104	(35)	43
Unwinding of discount on provisions	617	504	369
Unwinding of discount on other payables measured at amortized cost	393	407	440
	4,683	3,840	2,703

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 and 2022 a gain of $37 million associated with the buyback of finance debt.

eTax relief on capitalized interest is approximately $53 million (2023 $130 million and 2022 $108 million).

fIncludes temporary valuation differences related to the group’s interest rate and foreign currency exchange risk management associated with finance debt.


172		bp Annual Report and Form 20-F 2024

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
	2024	2023	2022
Exploration and evaluation costs
Exploration expenditure written off	767	746	385
Other exploration costs	207	251	200
Exploration expense for the year	974	997	585
Impairment losses	6	20	2
Intangible assets – exploration and appraisal expenditurea	4,438	4,328	4,213
Liabilities	76	109	88
Net assets	4,362	4,219	4,125
Cash used in operating activities	207	251	200
Cash used in investing activities	1,513	1,039	909

aAmount capitalized at 31 December 2024, 2023 and 2022 relates to assets in various regions. This includes $746 million in the North Africa region (2023 $593 million, 2022 $410 million), $651 million in

the Azerbaijan Georgia and Turkiye region (2023 $631 million, 2022 $539 million) and $543 million in the Middle East region (2023 $589 million, 2022 $639 million).

9. Taxation

Tax on profit


			$ million
	2024	2023	2022
Current tax
Charge for the yeara	7,187	9,048	12,523
Adjustment in respect of prior years	234	(373)	145
	7,421	8,675	12,668
Deferred tax
Origination and reversal of temporary differences in the current yearb	(1,851)	(238)	4,768
Adjustment in respect of prior yearsc	(17)	(568)	(674)
	(1,868)	(806)	4,094
Tax charge on profit	5,553	7,869	16,762

a2024 includes a charge of $4 million in respect of Pillar Two income taxes.

b2024 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). 2022 includes a charge of $1,834 million in

respect of the impact of the UK Energy Profits Levy on existing temporary differences unwinding over the period 1 January 2023 to 31 March 2028.

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. 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 2024, the total tax credit recognized within other comprehensive income was $782 million (2023 $735 million credit and 2022 $266 million charge). 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%. In 2023 this primarily comprises the deferred

tax impact of the remeasurements of the net pension and other post-employment benefit liability or asset. In 2022 this primarily comprises a release of

deferred withholding tax on other comprehensive income movements relating to Rosneft. See Note 32 for further information.

The total tax charge recognized directly in equity was $167 million (2023 $56 million charge and 2022 $214 million credit). In 2024 this mainly relates to

share-based payments and transactions involving non-controlling interests. In 2023 and 2022 this mainly relates to transactions involving non-controlling

interests.


		bp Annual Report and Form 20-F 2024		173




	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. For 2022 the items presented in the reconciliation are affected by the impacts of Rosneft. In order to provide a more

meaningful analysis of the effective tax rate for 2022, the table also presents a separate reconciliation for the group excluding the impacts of Rosneft, and

for the impacts of Rosneft in isolation.


					$ million
	2024	2023	2022 excluding impact of Rosneft	2022 impact of Rosnefta	2022
Profit (loss) before taxation	6,782	23,749	40,925	(25,520)	15,405
Tax charge (credit) on profit or lossb	5,553	7,869	17,823	(1,061)	16,762
Effective tax rate	82%	33%	44%	4%	109%

					%
Tax rate computed at the weighted average statutory ratec	66	34	42	20	77
Increase (decrease) resulting from
Tax reported in equity-accounted entities	(7)	(2)	(1)	—	(4)
Adjustments in respect of prior years	3	(4)	(1)	—	(3)
Deferred tax not recognized	5	2	(1)	—	(2)
Tax incentives for investment	(2)	—	—	—	(1)
Disposal impactsd	5	—	(3)	—	(8)
Foreign exchange	5	—	1	—	3
Items not deductible for tax purposes	5	2	2	—	5
Impact of bp's decision to exit its shareholding in Rosneft	—	—	—	(16)	27
Tax rate change effect of UK Energy Profits Levye	1	—	4	—	12
Otherf	1	1	1	—	3
Effective tax rate	82	33	44	4	109

aIncludes the impact of bp's decision to exit its shareholding in Rosneft and its other businesses with Rosneft in Russia.

bThe tax credit regarding the impact of Rosneft relates to the release of deferred withholding tax on unremitted earnings.

cCalculated 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.

d2022 primarily relates to the contribution of bp's Angolan business to Azule Energy.

e2024 comprises the deferred tax impact of a 3% increase in the UK Energy Profits Levy (EPL) on existing temporary differences. 2022 includes the deferred tax impact of the introduction of the EPL.

fIncludes 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	2024	2023
At 1 January	5,349	6,618
Exchange adjustments	57	134
Charge (credit) for the year in the income statement	(1,868)	(806)
Charge (credit) for the year in other comprehensive income	(807)	(735)
Charge (credit) for the year in equity	167	56
Acquisitions and disposals	127	82
At 31 December	3,025	5,349


174		bp Annual Report and Form 20-F 2024

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
	2024	2023	2022	2024	2023
Deferred tax liability
Depreciation	(1,337)	(1,552)	1,863	16,333	17,392
Pension plan surplusesa	62	133	42	1,789	2,568
Derivative financial instruments	40	12	(21)	58	12
Other taxable temporary differencesb	(352)	10	(992)	663	1,020
	(1,587)	(1,397)	892	18,843	20,992
Deferred tax asset
Depreciation	(229)	(166)	(309)	(2,373)	(2,141)
Lease liabilities	(209)	(176)	(8)	(1,952)	(1,785)
Pension plan and other post-employment benefit plan deficits	28	(60)	47	(623)	(755)
Decommissioning, environmental and other provisions	425	563	770	(5,623)	(6,042)
Derivative financial instruments	(9)	(14)	(6)	(268)	(136)
Tax credits	(43)	(67)	1,578	(937)	(893)
Loss carry forward	194	296	1,536	(2,285)	(2,467)
Other deductible temporary differencesc	(438)	215	(406)	(1,757)	(1,424)
	(281)	591	3,202	(15,818)	(15,643)
Net deferred tax charge (credit) and net deferred tax liability	(1,868)	(806)	4,094	3,025	5,349
Of which – deferred tax liabilities				8,428	9,617
– deferred tax assets				5,403	4,268

aThe 2024 balance sheet reflects a $658 million 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%.

bThe 2022 income statement includes amounts relating to deferred withholding tax on unremitted earnings of Rosneft. The 2024 and 2023 balance sheet amounts do not include any temporary differences

that are individually significant.

cThe 2024 and 2023 balance sheet amounts include amounts relating to share based payments and other items.

Of the $5,403 million of deferred tax assets recognized on the group balance sheet at 31 December 2024 (2023 $4,268 million), $3,232 million (2023

$2,336 million) relates to entities that have suffered a loss in either the current or preceding period. For 2024, this mainly includes $1,680 million in

Germany, $744 million in Mauritania and $609 million in Senegal (2023 mainly included $1,003 million in Germany, $672 million in Mauritania and $500

million in Senegal). For 2024 these amounts are supported by forecasts consistent with bp's future oil and gas price assumptions (see Note 1 for further

information) 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	2024	2023
Unused US state tax lossesa	2.3	2.1
Unused tax losses – other jurisdictionsb	7.3	5.6
Unused tax credits	33.3	31.3
of which – arising in the UKc	29.1	27.3
– arising in the USd	4.2	4.0
Deductible temporary differencese	23.4	20.7
Taxable temporary differences associated with investments in subsidiaries and equity-accounted entities	0.7	0.7

aFor 2024 the majority of the unused tax losses have no fixed expiry date.

b2024 and 2023 mainly relate to the UK, Brazil 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 2024 these tax

credits expire in the period 2025-2034.

e2024 and 2023 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	2024	2023	2022
Current tax benefit relating to the utilization of previously unrecognized deferred tax assets	87	360	492
Deferred tax benefit arising from the reversal of a previous write-down of deferred tax assets	14	3	—
Deferred tax benefit relating to the recognition of previously unrecognized deferred tax assets	280	332	792
Deferred tax expense arising from the write-down of a previously recognized deferred tax asset	111	54	—


		bp Annual Report and Form 20-F 2024		175




	Financial statements

10. Dividends

The quarterly dividend which is expected to be paid on 28 March 2025 in respect of the fourth quarter 2024 is 8.000 cents per ordinary share ($0.48 per

American Depositary Share (ADS)). The corresponding amount in sterling will be announced on 17 March 2025.


	Pence per share			Cents per share					$ million
	2024	2023	2022	2024	2023	2022	2024	2023	2022
Dividends announced and paid in cash
Preference shares							1	1	1
Ordinary shares
March	5.6922	5.5507	4.1595	7.270	6.610	5.460	1,218	1,183	1,068
June	5.6825	5.3089	4.3556	7.270	6.610	5.460	1,204	1,152	1,061
September	6.0498	5.7320	5.1684	8.000	7.270	6.006	1,297	1,249	1,140
December	6.2959	5.7367	4.9402	8.000	7.270	6.006	1,283	1,224	1,088
	23.7204	22.3283	18.6237	30.540	27.760	22.932	5,003	4,809	4,358
Dividend announced, paid in March 2025				8.000			1,265

The amount of unclaimed dividends recognized as a liability in other payables at 31 December 2024 is $106 million (2023 $91 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

2024 dividend expected to be paid on 28 March 2025.

The financial statements for the year ended 31 December 2024 do not reflect the dividend announced on 11 February 2025 and which is expected to be

paid on 28 March 2025; this will be treated as an appropriation of profit in the year ending 31 December 2025.

11. Earnings per share


			Cents per share
Per ordinary share	2024	2023	2022
Basic earnings per share	2.38	87.78	(13.10)
Diluted earnings per share	2.32	85.85	(13.10)

		Dollars per share
Per American Depositary Share (ADS)a	2024	2023	2022
Basic earnings per share	0.14	5.27	(0.79)
Diluted earnings per share	0.14	5.15	(0.79)

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
	2024	2023	2022
Profit (loss) attributable to bp shareholders	381	15,239	(2,487)
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	390	15,238	(2,488)

			Shares thousand
	2024	2023	2022
Basic weighted average number of ordinary sharesb	16,385,535	17,360,288	18,987,936
Potential dilutive effect of ordinary shares issuable under employee share-based payment plans	431,129	389,790	—
Weighted average number of ordinary shares outstanding used to calculate diluted earnings per share	16,816,664	17,750,078	18,987,936

			Shares thousand
	2024	2023	2022
Basic weighted average number of ordinary shares – ADS equivalent	2,730,922	2,893,381	3,164,656
Potential dilutive effect of ordinary shares (ADS equivalent) issuable under employee share-based payment plans	71,855	64,965	—
Weighted average number of ordinary shares (ADS equivalent) outstanding used to calculate diluted earnings per share	2,802,777	2,958,346	3,164,656

aSee Note 32 - non-controlling interests for further information.

bExcludes treasury shares. See Note 31 for further information.


176		bp Annual Report and Form 20-F 2024

11. Earnings per share – continued

The number of ordinary shares outstanding at 31 December 2024, excluding treasury shares, and including certain shares that will be issuable in the future

under employee share-based payment plans was 15,851,028,983 (2023 16,824,651,796). Between 31 December 2024 and 14 February 2025, the latest

practicable date before the completion of these financial statements, there was a net decrease of 118,209,740 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. Information on

these plans for directors is shown in the Directors remuneration report on pages 88-110.

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		2024		2023
	Number of optionsa b thousand	Weighted average exercise price $	Number of optionsa b thousand	Weighted average exercise price $
Outstanding	533,895	4.15	545,044	4.04
Exercisable	2,931	3.38	905	3.31
Dilutive effect	140,971	n/a	166,581	n/a

aNumbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).

bAt 31 December 2024 the quoted market price of one bp ordinary share was £3.93 (2023 £4.66).

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	2024	2023
	Number of sharesa	Number of sharesa
Vesting	thousand	thousand
Within one year	271,216	226,190
1 to 2 years	134,342	257,511
2 to 3 years	102,525	114,500
3 to 4 years	956	1,176
Over 4 years	118	308
	509,157	599,685
Dilutive effect	269,796	284,908

aNumbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).

There has been a net increase of 10,925,262 in the number of potential ordinary shares relating to employee share-based payment plans between

31 December 2024 and 14 February 2025.


		bp Annual Report and Form 20-F 2024		177




	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 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
Cost - owned PP&E
At 1 January 2023	3,513	950	179,028	44,662	2,202	3,076	10,089	243,520
Exchange adjustments	112	2	—	294	31	2	342	783
Additions	134	48	8,252	2,921	221	80	1,126	12,782
Acquisitions	206	—	—	27	12	48	1,060	1,353
Transfers from intangible assets	—	—	171	—	—	—	—	171
Reclassified as assets held for sale	(7)	—	—	(3)	(3)	(1)	(74)	(88)
Deletions and disposals	(34)	(8)	(2,105)	(517)	(173)	(247)	(319)	(3,403)
At 31 December 2023	3,924	992	185,346	47,384	2,290	2,958	12,224	255,118
Depreciation - owned PP&E
At 1 January 2023	700	501	111,434	22,903	1,671	2,431	5,819	145,459
Exchange adjustments	14	3	—	200	18	2	206	443
Charge for the year	45	30	10,468	1,519	163	85	629	12,939
Impairment losses	108	22	3,628	1,467	—	10	58	5,293
Impairment reversals	—	—	(18)	—	—	(9)	—	(27)
Reclassified as assets held for sale	(1)	—	—	(2)	(1)	(1)	(74)	(79)
Deletions and disposals	(28)	(3)	(2,070)	(416)	(167)	(226)	(275)	(3,185)
At 31 December 2023	838	553	123,442	25,671	1,684	2,292	6,363	160,843
Owned PP&E - net book amount at 31 December 2023	3,086	439	61,904	21,713	606	666	5,861	94,275
Right-of-use assets - net book amount at 31 December 2023b	—	1,243	53	916	4	2,463	5,765	10,444
Total PP&E - net book amount at 31 December 2023	3,086	1,682	61,957	22,629	610	3,129	11,626	104,719

Assets under construction included above
At 31 December 2024								10,722
At 31 December 2023								13,390
Depreciation charge for the year on right-of-use assets
2024		215	30	640	3	1,109	882	2,878
2023		196	16	558	5	1,055	783	2,613

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$867 million (2023 $661 million) of drilling rig right-of-use assets and $2,455 million (2023 $2,337 million) of shipping vessel right-of-use assets are included in Plant, machinery and equipment and

Transportation respectively.


178		bp Annual Report and Form 20-F 2024

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 2024 amounted to $13,642 million (2023 $10,354 million, 2022 $9,381 million). bp has contracted capital commitments amounting

to $3,392 million (2023 $1,580 million, 2022 $1,764 million) in relation to joint ventures and $59 million (2023 $105 million, 2022 $18 million) in relation to

associates.

14. Goodwill and impairment review of goodwill


		$ million
	2024	2023
Cost
At 1 January	13,176	12,577
Exchange adjustments	(179)	184
Acquisitions and other additions	2,734	415
Reclassified as assets held for sale	(79)	—
Deletions and disposals	(122)	—
At 31 December	15,530	13,176
Impairment losses
At 1 January	704	617
Exchange adjustments	(2)	2
Impairment losses for the year	—	85
Deletions and disposals	(60)	—
At 31 December	642	704
Net book amount at 31 December	14,888	12,472
Net book amount at 1 January	12,472	11,960

Impairment review of goodwill


		$ million
Goodwill at 31 December	2024	2023
gas & low carbon energy	4,460	2,095
oil production & operations	4,925	4,925
customers & products	5,503	5,431
other businesses & corporate	—	21
	14,888	12,472

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 ('gas businesses') within the segment and to Lightsource bp (LSbp). For customers and products, goodwill

has been allocated to Castrol, US Fuels, European Fuels, Archaea 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
			2024			2023	2024	2023
	Gas	LSbp	Total	Gas	LSbp	Total
Goodwill	2,228	2,232	4,460	2,095	—	2,095	4,925	4,925
Excess of recoverable amount over carrying amount	2,026	—	2,026	5,886	—	5,886	12,432	18,854

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 amount for the gas businesses and the oil production & operations segment is

based on a pre-tax value-in-use calculation. The decrease in headroom for both of these goodwill impairment tests is due to changes in a number of

assumptions including prices and production as well as, for the oil productions & operations segment, certain tax assumptions and, for the gas

businesses, divestments. The recoverable amount for the LSbp goodwill is based on fair value less costs of disposal.

No material impairment of the goodwill balances in either gas & low carbon energy or oil production & operations was recognized during 2024 or 2023.


		bp Annual Report and Form 20-F 2024		179




	Financial statements

14. Goodwill and impairment review of goodwill – continued

Gas businesses and oil production & operations

The value in use for relevant CGUs in both the 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 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 gas businesses over the next 15 years is 154 mmboe per year (2023 185

mmboe per year) and in the oil production and operations segment is 400 mmboe per year (2023 402 mmboe per year). Production assumptions used for

the goodwill impairment tests in both the 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 (2023

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 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. Estimated future cash flows were prepared on the

basis of certain assumptions prevailing at the time of the tests. 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 a 11% (2023 22%) 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 6% (2023 15%) reduction would have the same result.

It is estimated that no reasonably possible change in the discount rate of the oil production and operations segment would cause the recoverable amount

to be equal to the carrying amount of goodwill and related net non-current assets. For the gas businesses a 2% increase would have this result (2023 no

reasonably possible change).

Lightsource bp

The Lightsource bp goodwill largely relates to the value attributed to the business’s project development capability, including the workforce in place.

Management considers the fair value of Lightsource bp at 31 December 2024 to be substantially the same as at the date of acquisition in the fourth

quarter of 2024.

customers & products


												$ million
						2024						2023
	Castrol	US Fuels	European Fuels	Archaea	Other	Total	Castrol	US Fuels	European Fuels	Archaea	Other	Total
Goodwill	2,615	828	801	706	553	5,503	2,672	792	839	707	421	5,431

Cash flows for each group of CGUs are derived from the business segment plans, which cover a period of up to five years, except for Archaea where a

business plan to 2035 is in place following the acquisition in 2022. To determine the value in use for each of the groups of cash-generating units, cash

flows for a period of 10 years (11 years for Archaea), 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, European Fuels and Archaea 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 2024 or 2023.

Castrol

The key assumptions to which the calculation of value in use for the Castrol unit is most sensitive are operating unit margins, sales volumes, and discount

rate. Operating margin and sales volumes assumptions used in the detailed impairment review of goodwill calculation are consistent with the assumptions

used in the Castrol unit’s business plan. A pre-tax discount rate of 9% (2023 9%) is applied in the test. No reasonably possible change in any of these key

assumptions would cause the unit’s recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets. Cash flows

beyond the plan period are extrapolated using a nominal 3.4% (2023 3.4%) growth rate.


180		bp Annual Report and Form 20-F 2024

15. Intangible assets


								$ million
				2024				2023
	Exploration and appraisal expenditurea	Biogas rights agreements	Other intangibles	Total	Exploration and appraisal expenditurea	Biogas rights agreements	Other intangibles	Total
Cost
At 1 January	13,075	2,989	7,117	23,181	12,571	3,398	6,817	22,786
Exchange adjustments	—	—	(171)	(171)	—	—	144	144
Acquisitionsb	—	—	351	351	—	—	130	130
Remeasurements of acquisition accountingc	—	—	—	—	—	(394)	—	(394)
Additions	1,539	193	904	2,636	1,058	23	799	1,880
Transfers to property, plant and equipment	(391)	—	—	(391)	(171)	—	—	(171)
Reclassified as assets held for sale	(1)	—	(385)	(386)	—	—	(6)	(6)
Deletions and disposals	(1,169)	(192)	(266)	(1,627)	(383)	(38)	(767)	(1,188)
At 31 December	13,053	2,990	7,550	23,593	13,075	2,989	7,117	23,181
Amortization
At 1 January	8,747	105	4,338	13,190	8,358	—	4,228	12,586
Exchange adjustments	—	—	(97)	(97)	—	—	79	79
Exploration expenditure written off	767	—	—	767	746	—	—	746
Charge for the year	—	114	717	831	—	106	642	748
Impairment losses	6	344	108	458	20	—	77	97
Impairment reversals	(2)	—	—	(2)	—	—	—	—
Reclassified as assets held for sale	—	—	(53)	(53)	—	—	(3)	(3)
Deletions and disposals	(903)	(6)	(238)	(1,147)	(377)	(1)	(685)	(1,063)
At 31 December	8,615	557	4,775	13,947	8,747	105	4,338	13,190
Net book amount at 31 December	4,438	2,433	2,775	9,646	4,328	2,884	2,779	9,991
Net book amount at 1 January	4,328	2,884	2,779	9,991	4,213	3,398	2,589	10,200

aFor further information see Intangible assets within Note 1 and Note 8.

b2024 primarily relates to the acquisition of GETEC ENERGIE GmbH.

c2023 primarily relates to the acquisition of Archaea Energy Inc.

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
	2024	2023	2022	2024	2023
Azule Energy	504	700	540	5,109	5,066
Pan American Energy Group	—	—	538	—	—
Other joint venturesa	405	(633)	50	7,182	7,369
	909	67	1,128	12,291	12,435

a2024 and 2023 includes Pan American Energy Group as no longer considered material to the group post 2022 impairment.

The joint venture that is material to the group at 31 December 2024 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.

Following the 2022 impairment of bp's investment in PAEG, this is no longer considered material to the group for 2023 and 2024 and is now included with

Other joint ventures.

The following table provides summarized financial information relating to Azule Energy for 2024, 2023 and 2022 and Pan American Energy Group for 2022.

This information is presented on a 100% basis and reflects adjustments made by bp to Azule Energy and Pan American Energy Group’s own results in

applying the equity method of accounting. bp adjusts Azule Energy Holdings Limited and Pan American Energy Group’s results for the accounting required

under IFRS relating to bp’s purchase of its interests in Azule Energy Holdings Limited and Pan American Energy Group S.L.


		bp Annual Report and Form 20-F 2024		181




	Financial statements

16. Investments in joint ventures – continued

The operational and financial information is based on preliminary operational and financial results of Azule Energy Holdings Limited for 2024, 2023 and

2022 and Pan American Energy Group S.L. for 2022. Actual results may differ from these amounts - immaterial adjustments to the 2023 and 2022

numbers for Azule Energy Holdings Limited have been included in the 2024 and 2023 numbers respectively.


				$ million
				Gross amount
	2024	2023		2022
	Azule Energy	Azule Energy	Azule Energy	PAEG
Sales and other operating revenues	5,410	5,164	2,274	6,408
Profit (loss) before interest and taxation	1,896	2,146	1,460	1,560
Finance costs	512	400	218	376
Profit (loss) before taxationa	1,384	1,746	1,242	1,184
Taxation	376	346	162	108
Profit (loss) for the year	1,008	1,400	1,080	1,076
Other comprehensive income	—	—	—	—
Total comprehensive income	1,008	1,400	1,080	1,076
Non-current assets	20,584	18,788
Current assetsb	3,384	3,928
Total assets	23,968	22,716
Current liabilitiesc	3,576	2,510
Non-current liabilitiesd	10,174	10,074
Total liabilities	13,750	12,584
Net assets	10,218	10,132
Less: non-controlling interests	—	—
	10,218	10,132

aAzule Energy includes depreciation and amortisation of $2,844 million (2023 $2,768 million and 2022 $1,145 million), interest income of $nil (2023 $nil and 2022 $11 million) and interest expense of $513

million (2023 $407 million and 2022 $218 million). For 2022 PAEG includes depreciation and amortisation of $1,039 million, interest income of $29 million and interest expense of $375 million.

bAzule Energy includes cash and cash equivalents of $570 million (2023 $603 million).

cAzule Energy includes current financial liabilities of $3,417 million (2023 $2,409 million).

dAzule Energy includes non-current financial liabilities of $3,426 million (2023 $4,735 million).

The group received dividends of $463 million from Azule Energy Holdings Limited in 2024 (2023 $708 million and 2022 $500 million).

The group received dividends, net of withholding tax, of $35 million from Pan American Energy Group S.L. in 2022.

The following table provides aggregated summarized financial information relating to the group’s share of joint ventures.


										$ million
										bp share
			2024			2023				2022
	Azule Energy	Other	Total	Azule Energy	Other	Total	Azule Energy	PAEG	Other	Total
Sales and other operating revenues	2,705	12,164	14,869	2,582	13,705	16,287	1,137	3,204	9,770	14,111
Profit (loss) before interest and taxation	948	(74)	874	1,073	8	1,081	730	780	255	1,765
Finance costs	256	249	505	200	421	621	109	188	137	434
Profit (loss) before taxation	692	(323)	369	873	(413)	460	621	592	118	1,331
Taxation	188	(729)	(541)	173	219	392	81	54	67	202
Non-controlling interest	—	1	1	—	1	1	—	—	1	1
Profit (loss) for the year	504	405	909	700	(633)	67	540	538	50	1,128
Other comprehensive income	—	(3)	(3)	—	45	45	—	—	50	50
Total comprehensive income	504	402	906	700	(588)	112	540	538	100	1,178
Non-current assets	10,292	13,871	24,163	9,394	16,505	25,899
Current assets	1,692	4,363	6,055	1,964	4,387	6,351
Total assets	11,984	18,234	30,218	11,358	20,892	32,250
Current liabilities	1,788	2,914	4,702	1,255	2,992	4,247
Non-current liabilities	5,087	5,057	10,144	5,037	7,505	12,542
Total liabilities	6,875	7,971	14,846	6,292	10,497	16,789
Net assets	5,109	10,263	15,372	5,066	10,395	15,461
Less: non-controlling interests	—	(11)	(11)	—	(15)	(15)
	5,109	10,252	15,361	5,066	10,380	15,446

Group investment in joint ventures
Group share of net assets (as above)	5,109	10,252	15,361	5,066	10,380	15,446
Cumulative impairment charge	—	(3,066)	(3,066)	—	(3,007)	(3,007)
Loans made by group companies to joint ventures	—	(4)	(4)	—	(4)	(4)
	5,109	7,182	12,291	5,066	7,369	12,435


182		bp Annual Report and Form 20-F 2024

16. Investments in joint ventures – continued

Transactions between the group and its joint ventures are summarized below.


						$ million
Sales to joint ventures		2024		2023		2022
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	3,653	507	3,585	501	4,212	316


Purchases from joint ventures		2024		2023		2022
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	2,952	468	3,328	427	1,893	574

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 2024 relate to heating oil, gasoline, diesel and lubricant product transactions with Mobene and Ocwen Energy. The

majority of purchases from joint ventures in 2024 relate to crude oil and oil products transactions with Azule Energy.

bp's share of net impairment charges recognized by joint ventures in 2024 was $477 million (2023 $1,285 million and 2022 $256 million) of which $nil

charge (2023 $1,152 million and 2022 $276 million) was in the gas and low carbon energy segment and $477 million charge (2023 $133 million charge

and 2022 reversals of $20 million) was in the oil production & operations segment. The 2023 charges in the gas and low carbon energy segment principally

relate to the group's US offshore wind investments.

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 2024. On 27 February

2022, bp announced it would exit its shareholding in Rosneft and bp's two nominated Rosneft directors both stepped down from Rosneft's board. As a

result, the significant judgement on significant influence over Rosneft was reassessed. 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’. For further information see Note

1 Significant judgements and estimate: investment in Rosneft.


					$ million
		Income statement			Balance sheet
		Earnings from associates - after interest and tax			Investments in associates
	2024	2023	2022	2024	2023
Rosneft	—	—	528	—	—
Other associates	1,084	831	874	7,741	7,814
	1,084	831	1,402	7,741	7,814

The group recognized dividends, net of withholding tax, of $nil from Rosneft in 2024 (2023 $nil and 2022 $nil).


		bp Annual Report and Form 20-F 2024		183




	Financial statements

17. Investments in associates – continued

Summarized financial information for the group’s share of associates is shown below.


			$ million
			bp share
	2024	2023	2022

Sales and other operating revenues	12,859	11,396	14,841
Profit before interest and taxation	2,389	2,279	3,053
Finance costs	41	41	73
Profit (loss) before taxation	2,348	2,238	2,980
Taxation	1,264	1,407	1,498
Non-controlling interests	—	—	80
Profit (loss) for the year	1,084	831	1,402
Other comprehensive income	(9)	(237)	352
Total comprehensive income	1,075	594	1,754
Non-current assets	11,395	11,483
Current assets	4,230	3,776
Total assets	15,625	15,259
Current liabilities	3,009	3,003
Non-current liabilities	4,886	4,473
Total liabilities	7,895	7,476
Net assets	7,730	7,783
Less: non-controlling interests	—	—
	7,730	7,783
Group investment in associates
Group share of net assets (as above)	7,730	7,783
Loans made by group companies to associates	11	31
	7,741	7,814

Transactions between the group and its associates are summarized below.


						$ million
Sales to associates		2024		2023		2022
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	844	148	1,009	368	1,042	417

						$ million
Purchases from associates		2024		2023		2022
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	7,034	2,223	5,473	2,607	6,199	2,086

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 2024, 2023 and 2022 relate to crude oil and oil products transactions with Aker BP. Sales to associates are

related to various entities.

bp has commitments amounting to $7,921 million million (2023 $8,615 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 2024 was $14 million (2023 $nil).


184		bp Annual Report and Form 20-F 2024

18. Other investments


				$ million
		2024		2023
	Current	Non-current	Current	Non-current
Equity investmentsa	—	1,095	—	1,177
Contingent consideration	55	136	754	939
Other	110	61	89	73
	165	1,292	843	2,189

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. The contingent consideration in 2023

principally relates to the disposal of our Alaskan business. On 4 October 2024, bp completed the sale of this contingent consideration.

19. Inventories


		$ million
	2024	2023
Crude oil	3,007	3,227
Natural gas	548	410
Emissions allowances	549	464
Refined petroleum and petrochemical products	6,627	7,413
	10,731	11,514
Trading inventories	8,977	9,850
Supplies	1,946	1,455
Biological assets	178	—
Solar projects	1,400	—
	23,232	22,819
Cost of inventories expensed in the income statement	113,941	119,307

The inventory valuation at 31 December 2024 is stated net of a provision of $388 million (2023 $497 million) to write down inventories to their net

realizable value, of which $199 million (2023 $310 million) relates to hydrocarbon inventories. The net credit to the income statement in the year in respect

of inventory net realizable value provisions was $77 million (2023 $87 million charge), of which $104 million credit (2023 $112 million charge) 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
		2024		2023
	Current	Non-current	Current	Non-current
Financial assets
Trade receivables	21,659	502	25,175	652
Amounts receivable from joint ventures and associates	655	—	843	26
Other receivables	3,524	808	3,936	722
	25,838	1,310	29,954	1,400
Non-financial assets
Sales taxes and production taxes	1,165	356	1,028	355
Other receivables	124	149	141	12
	1,289	505	1,169	367
	27,127	1,815	31,123	1,767

In both 2024 and 2023 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 2024		185




	Financial statements

21. Valuation and qualifying accounts


						$ million
		2024		2023		2022
	Trade and other receivables	Fixed asset investments	Trade and other receivables	Fixed asset investments	Trade and other receivables	Fixed asset investments
At 1 January	1,424	3,183	636	3,050	584	169
Charged to costs and expenses	(90)	140	866	176	143	17,471
Charged to other accountsa	(7)	—	1	(1)	(8)	(27)
Deductions	(332)	(25)	(79)	(42)	(83)	(41)
Reclassifications	—	—	—	—	—	(14,522)
At 31 December	995	3,298	1,424	3,183	636	3,050

aPrincipally exchange adjustments.

Valuation and qualifying accounts relating to trade and other receivables comprise expected credit loss allowances. The expected credit loss allowance

comprises $858 million (2023 $1,301 million, 2022 $513 million) relating to receivables that were credit-impaired at the end of the year and $137 million

(2023 $123 million, 2022 $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. The

amount charged to costs and expenses in 2022 principally relates to bp’s investments in Rosneft and Pan American Energy Group S.L.. Amounts related to

bp’s investments in Rosneft and other businesses with Rosneft within Russia were reclassified in 2022 following bp’s loss of significant influence.

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
		2024		2023
	Current	Non-current	Current	Non-current
Financial liabilities
Trade payables	38,636	—	42,406	—
Amounts payable to joint ventures and associates	2,690	1	3,034	—
Payables for capital expenditure and acquisitions	3,670	309	3,063	305
Payables related to the Gulf of America oil spill	1,126	6,830	1,130	7,602
Other payables	7,358	678	7,313	663
	53,480	7,818	56,946	8,570
Non-financial liabilities
Sales taxes, customs duties, production taxes and social security	2,121	54	2,264	134
Other payables	2,810	1,537	1,945	1,372
	4,931	1,591	4,209	1,506
	58,411	9,409	61,155	10,076

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 $3,450 million payable over 8 years,

$1,926 million payable over 9 years and $2,549 million payable over 8 years respectively at 31 December 2024. Reported within net cash provided by

operating activities in the group cash flow statement is a net cash outflow of $1,192 million (2023 outflow of $1,280 million, 2022 outflow of $1,370

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 2024 also include amounts payable for settled economic loss and property damage claims

which are payable over a period of up to three years.


186		bp Annual Report and Form 20-F 2024

23. Provisions


						$ million
	Decommissioning	Environmental	Litigation and claims	Emissions	Otherc	Total
At 1 January 2024	12,372	1,614	727	3,025	1,401	19,139
Exchange adjustments	(53)	(9)	(9)	(58)	(67)	(196)
Acquisitions	—	—	29	—	11	40
New and increase in existing provisionsa	942	254	125	1,931	1,445	4,697
Write-back of unused provisionsa	—	(35)	(18)	(339)	(333)	(725)
Unwinding of discountb	499	61	20	—	37	617
Change in discount rate	(886)	(38)	(22)	—	(7)	(953)
Utilization	(52)	(287)	(151)	(2,229)	(479)	(3,198)
Reclassified to other payables	(591)	(21)	—	—	(6)	(618)
Reclassified as liabilities directly associated with assets held for sale	(40)	—	—	—	(5)	(45)
Deletions	(433)	(21)	—	—	(16)	(470)
At 31 December 2024	11,758	1,518	701	2,330	1,981	18,288
Of which – current	641	351	109	1,877	622	3,600
– non-current	11,117	1,167	592	453	1,359	14,688

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, 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 2024		187




	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 2024 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 dependants (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.

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 2024 the aggregate level of contributions was $69 million (2023 $42 million and 2022 $74 million). The aggregate level of contributions in 2025 is

expected to be approximately $150 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 2024.

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 2024 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 2024.

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 2024. 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.


188		bp Annual Report and Form 20-F 2024

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
Financial assumptions used to determine benefit obligation	2024	2023	2022	2024	2023	2022	2024	2023	2022
Discount rate for plan liabilities	5.5	4.8	5.0	5.6	5.0	5.2	3.5	3.6	4.2
Rate of increase for pensions in payment	2.9	2.8	2.9	—	—	—	1.8	2.1	1.8
Rate of increase in deferred pensions	2.9	2.8	2.9	—	—	—	0.6	0.7	0.6
Inflation for plan liabilities	3.1	3.0	3.1	2.0	2.0	2.0	2.0	2.4	2.1
									%
Financial assumptions used to determine benefit expense			UK			US			Eurozone
Financial assumptions used to determine benefit expense	2024	2023	2022	2024	2023	2022	2024	2023	2022
Discount rate for plan service costa	N/A	N/A	N/A	5.0	5.2	2.8	3.7	4.3	1.7
Discount rate for plan other finance expense	4.8	5.0	1.8	5.0	5.2	2.7	3.6	4.2	1.3
Inflation for plan service costa	N/A	N/A	N/A	2.0	2.0	2.1	2.4	2.1	1.6

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 5.0% (2023 5.0% and 2022 2.5%) and 1.9% (2023 1.9% and 2022 2.2%) 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
	2024	2023	2022	2024	2023	2022	2024	2023	2022
Life expectancy at age 60 for a male currently aged 60	27.0	27.4	26.9	25.1	25.0	25.0	26.2	26.1	26.0
Life expectancy at age 60 for a male currently aged 40	28.9	29.2	28.5	26.8	26.7	26.6	28.6	28.6	28.5
Life expectancy at age 60 for a female currently aged 60	29.0	29.2	28.8	28.1	28.1	28.0	29.5	29.3	29.3
Life expectancy at age 60 for a female currently aged 40	30.5	30.6	30.6	29.6	29.6	29.5	31.7	31.6	31.4

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 as it matures is to invest in assets whose value changes in the same

way as the plan liabilities, in order to reduce the level of funding risk. To move towards this objective, the UK plan uses a liability driven investment (LDI)

approach for part of the portfolio, investing primarily in government bonds to achieve this matching effect for 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.

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 2024, the asset allocation policies of the

primary UK and US plans remained unchanged.

The current asset allocation policy for the major plans at 31 December 2024 was as follows:


	UK	US
Asset category	%	%
Total equity (including private equity)	8	19
Bonds/cash (including LDI)	85	81
Property/real estate	7	—


		bp Annual Report and Form 20-F 2024		189




	Financial statements

24. Pensions and other post-employment benefits – continued

The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2024 were $4,970 million (2023 $6,215 million) of

government-issued nominal bonds and $11,105 million (2023 $13,177 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 190.


					$ million
	UKa	USb	Eurozone	Other	Total
Fair value of pension plan assets
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
Other	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
At 31 December 2022
Listed equities – developed markets	1,252	127	299	213	1,891
– emerging markets	117	17	48	71	253
Private equityc	2,715	1,126	—	2	3,843
Government issued nominal bondsd	4,039	1,370	682	263	6,354
Government issued index-linked bondsd	11,945	—	79	—	12,024
Corporate bondsd	6,317	2,569	563	146	9,595
Propertye	2,297	—	89	18	2,404
Cash	567	175	61	116	919
Otherf	1,088	33	56	357	1,534
Debt (repurchase agreements) used to fund liability driven investments	(5,290)	—	—	—	(5,290)
	25,047	5,417	1,877	1,186	33,527

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 included insurance policies arising from annuity buy-in in Canada amounting to $374 million in 2023 (2022 $341 million). Completion of a buy-out in 2024 reduced these amounts to nil.


190		bp Annual Report and Form 20-F 2024

24. Pensions and other post-employment benefits – continued


					$ 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.

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 189.


		bp Annual Report and Form 20-F 2024		191




	Financial statements

24. Pensions and other post-employment benefits – continued


					$ 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)
Movements in benefit obligation during the year
Benefit obligation at 1 January	17,480	5,880	4,799	1,343	29,502
Exchange adjustments	1,056	—	215	30	1,301
Operating charge relating to defined benefit plans	48	156	52	22	278
Interest cost	869	297	194	66	1,426
Contributions by plan participants	6	—	2	5	13
Benefit payments (funded plans)c	(1,071)	(262)	(79)	(81)	(1,493)
Benefit payments (unfunded plans)c	(8)	(166)	(230)	(25)	(429)
Reclassified as assets held for sale	—	—	—	(14)	(14)
Remeasurements	1,199	(68)	584	25	1,740
Benefit obligation at 31 Decembera d	19,579	5,837	5,537	1,371	32,324
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January	25,047	5,417	1,877	1,186	33,527
Exchange adjustments	1,462	—	81	39	1,582
Interest income on plan assetsa e	1,259	274	78	56	1,667
Contributions by plan participants	6	—	2	5	13
Contributions by employers (funded plans)	20	—	11	11	42
Benefit payments (funded plans)c	(1,071)	(262)	(79)	(81)	(1,493)
Remeasurementse	(677)	45	82	28	(522)
Fair value of plan assets at 31 Decemberf	26,046	5,474	2,052	1,244	34,816
Surplus (deficit) at 31 December	6,467	(363)	(3,485)	(127)	2,492
Represented by
Asset recognized	6,631	1,133	120	64	7,948
Liability recognized	(164)	(1,496)	(3,605)	(191)	(5,456)
	6,467	(363)	(3,485)	(127)	2,492
The surplus (deficit) may be analysed between funded and unfunded plans as follows
Funded	6,631	1,133	104	29	7,897
Unfunded	(164)	(1,496)	(3,589)	(156)	(5,405)
	6,467	(363)	(3,485)	(127)	2,492
The defined benefit obligation may be analysed between funded and unfunded plans as follows
Funded	(19,415)	(4,341)	(1,948)	(1,215)	(26,919)
Unfunded	(164)	(1,496)	(3,589)	(156)	(5,405)
	(19,579)	(5,837)	(5,537)	(1,371)	(32,324)

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

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.

cThe benefit payments amount shown above comprises $1,858 million benefits and $10 million settlements, plus $54 million of plan expenses incurred in the administration of the benefit.

dThe benefit obligation for the US is made up of $4,527 million for pension liabilities and $1,310 million for other post-employment benefit liabilities (which are unfunded and are primarily retiree medical

liabilities). The benefit obligation for the Eurozone includes $3,393 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 189.


192		bp Annual Report and Form 20-F 2024

24. Pensions and other post-employment benefits – continued


					$ million
					2022
	UK	US	Eurozone	Other	Total
Analysis of the amount charged to profit or loss
Current service costa	41	219	87	25	372
Past service costb	23	—	(1)	(21)	1
Settlementb	(8)	—	—	(4)	(12)
Operating charge (credit) relating to defined benefit plans	56	219	86	—	361
Payments to defined contribution plans	110	132	6	36	284
Total operating charge (credit)	166	351	92	36	645
Interest income on plan assetsa	(694)	(189)	(34)	(44)	(961)
Interest on plan liabilities	529	217	85	61	892
Other finance (income) expense	(165)	28	51	17	(69)
Analysis of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assets	(12,955)	(1,581)	(507)	(151)	(15,194)
Change in financial assumptions underlying the present value of the plan liabilities	11,531	2,195	1,903	221	15,850
Change in demographic assumptions underlying the present value of the plan liabilities	47	—	(14)	(15)	18
Experience gains and losses arising on the plan liabilities	(146)	(15)	(159)	(14)	(334)
Remeasurements recognized in other comprehensive income	(1,523)	599	1,223	41	340

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

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 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. Settlements reflect costs associated with buyouts in Canada and in certain other small worldwide plans administered and reported through the UK.

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 2024 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 2025 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 2025	(180)	162	(41)	46	(11)	7
Effect on obligation at 31 December 2024	(1,817)	2,219	(411)	578	(567)	691
Inflation rateb
Effect on expense in 2025	81	(77)	7	(6)	32	(26)
Effect on obligation at 31 December 2024	1,460	(1,390)	38	(32)	532	(460)

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 2025	32	3	9
Effect on obligation at 31 December 2024	582	54	196

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 2024 are as follows:


					$ million
Estimated future benefit payments	UK	US	Eurozone	Other	Total
2025	1,081	464	305	80	1,930
2026	1,107	452	295	76	1,930
2027	1,127	453	293	76	1,949
2028	1,140	443	289	77	1,949
2029	1,160	446	284	77	1,967
2030 - 2034	5,892	2,260	1,317	399	9,868
					Years
Weighted average duration	11.7	8.8	13.3	12.5


		bp Annual Report and Form 20-F 2024		193




	Financial statements

25. Cash and cash equivalents


		$ million
	2024	2023
Cash	16,414	16,683
Triparty repos and term bank deposits	14,453	9,788
Other cash equivalents	8,337	6,559
	39,204	33,030

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 2024 includes $4,844 million (2023 $5,282 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 $5,774 million (2023 $7,174 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
			2024			2023
	Current	Non-current	Total	Current	Non-current	Total
Borrowings	4,474	55,073	59,547	3,284	48,670	51,954

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 $3,793 million

(2023 $2,688 million) and issued commercial paper of $500 million (2023 $456 million). Finance debt does not include accrued interest of $585 million

(2023 $495 million), which is reported within other payables.

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
						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

						2023
US dollar	4	13	33,511	8	18,134	51,645
Other currencies	6	7	205	10	104	309
			33,716		18,238	51,954

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 2024, 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
		2024		2023
	Fair value	Carrying amount	Fair value	Carrying amount
Short-term borrowings	681	681	596	596
Long-term borrowings	54,285	58,866	48,199	51,358
Total finance debt	54,966	59,547	48,795	51,954


194		bp Annual Report and Form 20-F 2024

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 2024, gearing was 22.7% (2023 19.7%).


		$ million
At 31 December	2024	2023
Finance debt	59,547	51,954
Less: fair value asset (liability) of hedges related to finance debta	(2,654)	(1,988)
	62,201	53,942
Less: cash and cash equivalents	39,204	33,030
Net debt	22,997	20,912
Total equity	78,318	85,493
Gearing	22.7%	19.7%

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 $166 million (2023 liability of $73

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.

An analysis of changes in liabilities arising from financing activities is provided below.


					$ million
	Finance debt	Currency swapsa	Lease liabilities	Net partner payable for leases entered into on behalf of joint operations	Total liabilities arising from financing activities
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

At 1 January 2023	46,944	5,312	8,549	42	60,847
Exchange adjustments	33	—	132	1	166
Net financing cash flow	3,040	(213)	(2,560)	(22)	245
Fair value (gains) losses	1,389	(2,065)	—	—	(676)
New and remeasured leases/joint operations payables	—	—	4,956	10	4,966
Other movementsc	548	(56)	44	(1)	535
At 31 December 2023	51,954	2,978	11,121	30	66,083

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.

cIncludes $545 million of finance debt acquired as part of the TravelCenters of America business combination.

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 $922 million (2023 $746 million) at the balance sheet date for shares

repurchased between the end of the reporting period and 11 February 2025. $7,127 million (2023 $7,918 million) is included in financing activities in the

group cash flow statement for the cash used to repurchase shares during the year.


		bp Annual Report and Form 20-F 2024		195




	Financial statements

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 8 years (2023 7 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
	2024	2023
Undiscounted lease liability cash flows due:
Within 1 year	3,237	3,038
1 to 2 years	2,418	2,177
2 to 3 years	1,798	1,386
3 to 4 years	1,394	1,139
4 to 5 years	1,099	947
5 to 10 years	3,039	3,045
Over 10 years	1,283	1,348
	14,268	13,080
Impact of discounting	(2,268)	(1,959)
Lease liabilities at 31 December	12,000	11,121
Of which – current	2,660	2,650
– non-current	9,340	8,471

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 2024 is $5,311

million (2023 $5,507 million). The majority of this future commitment relates to the floating LNG vessel to service the Greater Tortue Ahmeyim project

from 2025.


		$ million
	2024	2023
Total cash outflow for amounts included in lease liabilities	3,283	2,904
Expense for variable payments not included in the lease liabilitya	45	27
Short-term lease expensea	499	657
Additions to right-of-use assets in the period	3,781	5,015

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 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)


196		bp Annual Report and Form 20-F 2024

29. Financial instruments and financial risk factors – continued


					$ million
At 31 December 2023	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	3,006	—	3,032
Loans		1,725	457	—	2,182
Trade and other receivables	20	31,354	—	—	31,354
Derivative financial instruments	30	—	22,444	119	22,563
Cash and cash equivalents	25	27,804	5,226	—	33,030
Financial liabilities
Trade and other payables	22	(65,516)	—	—	(65,516)
Derivative financial instruments	30	—	(13,545)	(2,107)	(15,652)
Accruals		(7,837)	—	—	(7,837)
Lease liabilities	28	(11,121)	—	—	(11,121)
Finance debt	26	(51,954)	—	—	(51,954)
		(75,519)	17,588	(1,988)	(59,919)

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 gain of $1 million (2023 net loss of $11 million and 2022 net loss of $238 million). Dividend income of $24 million (2023

$18 million and 2022 $14 million) from investments in equity instruments classified as measured at fair value through profit or loss is presented within

other income.

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 EVP supply, trading and shipping and SVPs treasury, tax, accounting reporting control

and planning & performance management. 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


		bp Annual Report and Form 20-F 2024		197




	Financial statements

29. Financial instruments and financial risk factors – continued

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 2024 was $42 million (2023 $26

million) whereas the average value-at-risk measure for the period was $35 million (2023 $49 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 2024, the total foreign currency borrowings

not swapped into US dollars amounted to $555 million (2023 $309 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.

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 2024 the

most significant open contracts in place were for USD equivalent amounts of $92 million sterling (2023 $296 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 2024 was 30% of total finance

debt outstanding (2023 35%). The weighted average interest rate on finance debt at 31 December 2024 was 5% (2023 5%) and the weighted average

maturity of fixed rate debt was eight years (2023 thirteen 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 $18,006 million (2023 $18,238 million) (see Note 26) were to

have changed by one percentage point on 1 January 2025, it is estimated that the group’s finance costs for 2025 would change by approximately $180

million (2023 $182 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 2024 was $655 million (2023 $1,655 million) in respect of

liabilities of joint ventures and associates and $585 million (2023 $598 million) in respect of liabilities of other third parties. An amount of $146 million

(2023 $201 million) is recorded as a liability at 31 December 2024 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.


198		bp Annual Report and Form 20-F 2024

29. Financial instruments and financial risk factors – continued

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 2024, the group had in place credit enhancements designed to mitigate

approximately $9.2 billion (2023 $12.0 billion) of credit risk of which approximately $8.2 billion (2023 $10.7 billion) related to assets in the scope of IFRS 9's

impairment requirements. Credit enhancements include standby and documentary letters of credit, bank guarantees, insurance and liens which are

typically taken out with financial institutions who have investment grade credit ratings, or are liens over assets held by the counterparty of the related

receivables. 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.

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	2024	2023
AAA to AA-	12%	7%
A+ to A-	50%	59%
BBB+ to BBB-	16%	15%
BB+ to BB-	10%	7%
B+ to B-	8%	4%
CCC+ and below	4%	8%

Movements in the impairment provision for trade and other receivables are shown in Note 21.


		bp Annual Report and Form 20-F 2024		199




	Financial statements

29. Financial instruments and financial risk factors – continued

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 2024	Gross amounts of recognized financial assets (liabilities)	Amounts set off	Net amounts presented on the balance sheet	Master netting arrangements	Cash collateral (received) pledged	Net amount
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)
At 31 December 2023
Derivative assets	25,188	(2,625)	22,563	(3,436)	(1,245)	17,882
Derivative liabilities	(18,277)	2,625	(15,652)	3,436	263	(11,953)
Trade and other receivables	17,867	(7,789)	10,078	(1,141)	(633)	8,304
Trade and other payables	(16,284)	7,789	(8,495)	1,141	44	(7,310)

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 of 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 $12,130 million (2023 $13,180 million), allowing LCs to be issued for a maximum 24-month duration. The

facilities are held with 16 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 2024, 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.

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 or, 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 derecognised the original

trade payables relating to the arrangements because the original liability is not substantially modified on entering into the arrangements.


200		bp Annual Report and Form 20-F 2024

29. Financial instruments and financial risk factors – continued

Additional information about the group’s trade payables that are subject to supplier finance arrangements is provided in the table below.


			2024
	Letters of Credit	Promissory Notes	Reverse Factoring Arrangements
Carrying amount of liabilities ($ million)
Presented within trade and other payablesa	7,431	1,778	390
of which suppliers have received payment from the financial institutionb	7,016	1,778	390
Range of payment due dates (days)
Liabilities that are part of the arrangementb	8 to 57	30 to 60	30 to 60
Trade payables that are not part of the arrangement	6 to 60	6 to 60	6 to 60

aLetters of credit, promissory notes and reverse factoring arrangements related to amounts presented within trade and other payables in 2023 were $10,066 million, $953 million and $nil respectively.

bThe group applied transitional relief available under IAS 7 and has not provided comparative information in the first year of adoption.

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 2024, $9 billion (2023 $6 billion) of long-term taxable bonds were issued with terms ranging from three to twelve years. In addition the group issued

perpetual hybrid capital bonds and securities with a US dollar equivalent value of $4.3 billion (2023 $0.2 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 $39.2 billion at 31 December

2024 (2023 $33.0 billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate and short notice. As at 31

December 2024, the group had substantial amounts of undrawn borrowing facilities available, consisting of an undrawn committed $8.0 billion credit

facility and $4.0 billion of standby facilities. $7.8 billion of the credit facility was available for one year and $0.2 billion was available for less than 1 year.

$3.9 billion of the standby facilities were available for 3 years and $0.1 billion were available for 2 years. These facilities were unutilized and were held with

27 international banks. In January 2025, the committed credit facility and standby facilities were replaced by new borrowing facilities, consisting of an

undrawn committed $8.0 billion credit facility and $4.0 billion of standby facilities. These new facilities are available for 5 years, are held with 33

international banks and borrowings via these facilities would be at pre-agreed rates

For further information on the group's sources and uses of cash see Liquidity and capital resources on page 316.

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 2024		201




	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
				2024				2023
	Trade and other payablesa	Accruals	Finance debt	Interest on finance debt	Trade and other payablesa	Accruals	Finance debt	Interest on finance debt
Within one year	53,663	6,071	4,402	2,490	56,852	6,527	3,054	2,394
1 to 2 years	1,670	260	4,716	2,217	1,876	329	3,820	2,151
2 to 3 years	1,177	150	6,449	1,947	1,158	147	4,767	1,907
3 to 4 years	1,139	130	5,649	1,678	1,178	135	5,367	1,666
4 to 5 years	1,138	125	3,928	1,447	1,141	121	5,778	1,396
5 to 10 years	3,889	375	17,301	4,877	5,028	382	12,939	4,894
Over 10 years	157	286	13,947	6,198	136	196	14,586	6,890
	62,833	7,397	56,392	20,854	67,369	7,837	50,311	21,298

a2024 includes $9,520 million (2023 $10,662 million) in relation to the Gulf of America oil spill, of which $8,383 million (2023 $9,520 million) matures in greater than one year.

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 $24,206 million at 31 December 2024 (2023 $24,120 million) to be received on the same day as the related cash outflows.


		$ million
Cash outflows for derivative financial instruments at 31 December	2024	2023
Within one year	1,718	2,071
1 to 2 years	5,136	1,718
2 to 3 years	3,077	5,136
3 to 4 years	1,743	3,077
4 to 5 years	3,696	1,743
5 to 10 years	8,307	6,708
Over 10 years	2,486	4,092
	26,163	24,545

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.


202		bp Annual Report and Form 20-F 2024

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
		2024		2023
	Fair value asset	Fair value liability	Fair value asset	Fair value liability
Derivatives held for trading
Currency derivatives	343	(1,738)	478	(1,511)
Oil price derivatives	1,350	(1,071)	1,859	(1,139)
Natural gas price derivatives	11,533	(10,506)	14,750	(6,708)
Power price derivatives	7,905	(6,893)	5,355	(4,187)
Other derivatives	95	(16)	2	—
	21,226	(20,224)	22,444	(13,545)
Cash flow hedges
Currency forwards	—	—	—	(1)
	—	—	—	(1)
Fair value hedges
Currency swaps	—	(2,651)	119	(2,102)
Interest rate swaps	—	(4)	—	(4)
	—	(2,655)	119	(2,106)
	21,226	(22,879)	22,563	(15,652)
Of which – current	5,112	(4,347)	12,583	(5,250)
– non-current	16,114	(18,532)	9,980	(10,402)

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
							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

							$ million
							2023
	Less than 1 year	1-2 years	2-3 years	3-4 years	4-5 years	Over 5 years	Total
Currency derivatives	95	31	38	33	28	253	478
Oil price derivatives	1,423	206	81	52	41	56	1,859
Natural gas price derivatives	8,705	1,412	625	458	426	3,124	14,750
Power price derivatives	2,339	961	513	360	250	932	5,355
Other derivatives	—	—	—	—	—	2	2
	12,562	2,610	1,257	903	745	4,367	22,444


		bp Annual Report and Form 20-F 2024		203




	Financial statements

30. Derivative financial instruments – continued

Derivative liabilities held for trading have the following fair values and maturities.


							$ 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)

							$ million
							2023
	Less than 1 year	1-2 years	2-3 years	3-4 years	4-5 years	Over 5 years	Total
Currency derivatives	(341)	(3)	(405)	(166)	(7)	(589)	(1,511)
Oil price derivatives	(1,047)	(61)	(14)	(4)	(1)	(12)	(1,139)
Natural gas price derivatives	(2,126)	(796)	(473)	(348)	(293)	(2,672)	(6,708)
Power price derivatives	(1,692)	(666)	(413)	(306)	(227)	(883)	(4,187)
	(5,206)	(1,526)	(1,305)	(824)	(528)	(4,156)	(13,545)

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
							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

							$ million
							2023
	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	98	41	11	1	—	—	151
Level 2	12,802	1,857	557	236	124	130	15,706
Level 3	1,765	1,063	784	699	638	4,263	9,212
	14,665	2,961	1,352	936	762	4,393	25,069
Less: netting by counterparty	(2,103)	(351)	(95)	(33)	(17)	(26)	(2,625)
	12,562	2,610	1,257	903	745	4,367	22,444
Fair value of derivative liabilities
Level 1	(70)	(44)	(11)	(1)	—	—	(126)
Level 2	(6,051)	(1,127)	(844)	(365)	(93)	(500)	(8,980)
Level 3	(1,188)	(706)	(545)	(491)	(452)	(3,682)	(7,064)
	(7,309)	(1,877)	(1,400)	(857)	(545)	(4,182)	(16,170)
Less: netting by counterparty	2,103	351	95	33	17	26	2,625
	(5,206)	(1,526)	(1,305)	(824)	(528)	(4,156)	(13,545)
Net fair value	7,356	1,084	(48)	79	217	211	8,899


204		bp Annual Report and Form 20-F 2024

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 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

						$ million
	Oil price	Natural gas price	Power price	Currency	Other	Total
Fair value contracts at 1 January 2023	28	905	(524)	61	44	514
Gains (losses) recognized in the income statement	79	19	379	161	29	667
Settlements	13	(320)	86	(3)	(71)	(295)
Transfers out of level 3	(13)	(5)	(61)	—	—	(79)
Net fair value of contracts at 31 December 2023	107	599	(120)	219	2	807
Deferred day-one gains (losses)						1,341
Derivative asset (liability)						2,148

The amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at 31 December 2024 was a $193

million loss (2023 $631 million gain related to derivatives still held at 31 December 2023).

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 $9,726

million (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 recognised in the financial statements

when associated cargoes are lifted. The embedded value in these contracts is not recognised 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 year ended 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. . For additional information, details of management’s internal

measure of performance are given in the Group Performance Report on page 24 and on page 314.

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 loss of $404 million (2023 $632 million net gain and 2022 $1,280 million net loss). 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 2024, 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.

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.


		bp Annual Report and Form 20-F 2024		205




	Financial statements

30. Derivative financial instruments – continued

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 2024
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure	—	—	—
Commodity price risk
Highly probable forecast sales	155	(155)	—

At 31 December 2023
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure	1	(1)	—
Commodity price risk
Highly probable forecast sales	1,065	(1,065)	—


206		bp Annual Report and Form 20-F 2024

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	Nominal amounts of hedging instruments
At 31 December 2024	$ million	$ million	$ million	mmBtu
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure	—	—	95
Commodity price risk
Highly probable forecast sales	—	—		(209)

At 31 December 2023
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure	—	(1)	318
Commodity price risk
Highly probable forecast sales	—	—		(392)

All hedging instruments are presented within derivative financial instruments on the group balance sheet.

All of the nominal amount of hedging instruments at 31 December 2024 and 2023 relating to highly probable forecast capital expenditure matures within

12 months of the relevant balance sheet date. All of the nominal amount of hedging instruments at 31 December 2024 and 31 December 2023 relating to

highly probable forecast sales matures within 12 months of the relevant balance sheet date.

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
	2024		2023
At 31 December	Forecast capital expenditure	Forecast sales	Forecast capital expenditure	Forecast sales
Sterling/US dollar	1.25		1.27
Euro/US dollar	1.04		1.11
Henry Hub $/mmBtu		3.38		4.02

Fair value hedges

At 31 December 2024, 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, Canadian 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 2024		207




	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 2024			Hedge ineffectiveness recognized in profit or (loss)
Fair value hedges
Interest rate risk on finance debt	—	1	(1)
Interest rate and foreign currency risk on finance debt	927	(772)	(155)

At 31 December 2023
Fair value hedges
Interest rate risk on finance debt	—	—	—
Interest rate and foreign currency risk on finance debt	(1,417)	1,356	61

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 2024	Assets	Liabilities	Nominal amounts of hedging instruments
Fair value hedges
Interest rate risk on finance debt	—	(4)	132
Interest rate and foreign currency risk on finance debt	—	(2,651)	15,887

At 31 December 2023
Fair value hedges
Interest rate risk on finance debt	—	(4)	387
Interest rate and foreign currency risk on finance debt	119	(2,102)	16,862

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.


208		bp Annual Report and Form 20-F 2024

30. Derivative financial instruments – continued

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 2024	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	—	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

At 31 December 2023
Fair value hedges
Interest rate risk on finance debt	239	—	148	—	—	—	—	387
Interest rate and foreign currency risk on finance debt	1,857	1,716	1,933	1,441	1,741	4,164	4,010	16,862

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		2024		2023
	Interest rate swaps	Cross-currency interest rate swaps	Interest rate swaps	Cross-currency interest rate swaps
Interest rate	5.45%	6.34%	3.49%	7.35%
Sterling/US dollar		1.28		1.27
Euro/US dollar		1.13		1.13
Canadian dollar/US dollar		0.78		0.78
Australian dollar/ US dollar		0.67		—
Japanese Yen/ US dollar		0.01		—
Swiss Franc/US dollar		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 2024		Liabilities	Assets	Liabilities	Discontinued hedges
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

At 31 December 2023
Fair value hedges
Interest rate risk on finance debt		(426)	4	—	(237)
Interest rate and foreign currency risk on finance debt		(16,834)	1,512	—	—

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 2024		209




	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 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)

				$ 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 2023	—	(108)	(104)	(212)
Recognized in other comprehensive income
Cash flow hedges marked to market	15	1,065	—	1,080
Cash flow hedges reclassified to the income statement - hedged item affected profit or loss	—	(428)	—	(428)
Costs of hedging marked to market	—	—	(67)	(67)
Costs of hedging reclassified to the income statement	—	—	(11)	(11)
	15	637	(78)	574
Cash flow hedges transferred to the balance sheet	(1)	—	—	(1)
At 31 December 2023	14	529	(182)	361

All of the cash flow hedge reserve balances at 31 December 2024 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.


210		bp Annual Report and Form 20-F 2024

31. Called-up share capital

The allotted, called up and fully paid share capital at 31 December was as follows:


		2024		2023		2022
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	17,900,800	4,475	19,097,783	4,774	20,778,082	5,194
Issue of new shares for employee share-based payment plans	—	—	66,000	17	55,000	14
Issue of new shares – otherb	—	—	—	—	165,105	41
Repurchase of ordinary share capital	(1,238,335)	(310)	(1,262,983)	(316)	(1,900,404)	(475)
At 31 December	16,662,465	4,165	17,900,800	4,475	19,097,783	4,774
		4,186		4,496		4,795

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.

b165 million new ordinary shares were issued in April 2022 as non-cash consideration for the acquisition of the public units of BP Midstream Partners LP.

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 2024 the company repurchased 1,238 million (2023 1,263 million) ordinary shares for a total consideration of $7,127 million (2023 $7,918 million) ,

including transaction costs of $38 million (2023 $43 million). All shares purchased were for cancellation. The repurchased shares represented 7.4% of

ordinary share capital. A further 176 million ordinary shares were repurchased between the end of the reporting period and 14 February 2025, the latest

practicable date before the completion of these financial statements, for a total cost of $927 million of which $922 million has been accrued at 31

December 2024. The number of shares in issue is reduced when shares are repurchased.

Treasury sharesa


		2024		2023		2022
	Shares thousand	Nominal value $ million	Shares thousand	Nominal value $ million	Shares thousand	Nominal value $ million
At 1 January	1,077,079	271	1,124,927	281	1,137,457	283
Purchases for settlement of employee share plans	8,302	2	24,688	6	14,150	4
Issue of new shares for employee share-based payment plans	—	—	71,039	19	55,000	14
Shares re-issued for employee share-based payment plans	(273,360)	(69)	(143,575)	(35)	(81,680)	(20)
At 31 December	812,021	204	1,077,079	271	1,124,927	281
Of which – shares held in treasury by bp	481,474	121	726,339	183	940,571	235
– shares held in ESOP trusts	330,510	83	350,704	88	184,356	46
– shares held by bp’s US share plan administratorb	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 4.1% (2023 4.9% and 2022 5.0%) of the called-up ordinary

share capital of the company.

During 2024, the movement in shares held in treasury by bp represented 1.4% (2023 1.1% and 2022 less than 0.5%) of the ordinary share capital of the

company.


212		bp Annual Report and Form 20-F 2024

32. Capital and reserves



	Share capital	Share premium account	Capital redemption reserve	Merger reserve	Total share capital and capital reserves
	Share capital	Share premium account	Capital redemption reserve	Merger reserve	Total share capital and capital reserves
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	—	—	—	—	—
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

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 taxb	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

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 2024		213




	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
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	Hybrid bonds	Other interest	Total equity
(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

(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


216		bp Annual Report and Form 20-F 2024

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. voluntarily bought back $1.3 billion of the non-call 2025 4.375% US dollar hybrid bonds issued in 2020 and issued euro, sterling and US dollar

hybrid bonds for a US dollar equivalent amount of $3.9 billion. Coupons on the new issuances are fixed for an initial period up to dates from 2030 to 2035

at rates of 4.375% to 6.45%. As at 31 December 2024 the total population of hybrid bonds include redemption options exercisable at the group’s discretion

from June 2025 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 September 2025 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 $485 million (2023 $477 million) and $517 million (2023 $473 million) respectively. The amount of hybrid bonds included in non-controlling

interests at the end of the year was $14.6 billion (2023 $12.1 billion).

Perpetual subordinated hybrid securities issued by group subsidiaries include $500 million issued during 2024, specifically earmarked to fund BP

Alternative Energy Investments Ltd including the funding of Lightsource bp. Payments made to and profit attributed to perpetual hybrid securities in the

year totalled $125 million (2023 $114 million) and $125 million (2023 $113 million) respectively. The amount of perpetual subordinated hybrid securities

included within non-controlling interests at the end of the year was $2.0 billion (2023 $1.5 billion).

Equity instruments with preferred distributions issued by group subsidiaries include $1,330 million issued during 2024 comprising $500 million of proceeds

from the sale of a 49% interest in a subsidiary that holds certain midstream assets offshore US; and $830 million of proceeds from the sale of a 25% non-

controlling interest in BP Pipelines TAP Limited, the bp subsidiary that holds a 20% share in Trans Adriatic Pipeline AG. In both 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 distributions included within non-

controlling interests at the end of the year was approximately $1.3 billion (2023 $0.3 billion).


		bp Annual Report and Form 20-F 2024		217




	Financial statements

32. Capital and reserves – continued

The pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below.


			$ 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)

			$ million
			2022
	Pre-tax	Tax	Net of tax
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including reclassifications)	6,973	(120)	6,853
Cash flow hedges (including reclassifications)	677	(6)	671
Costs of hedging (including reclassifications)	86	17	103
Share of items relating to equity-accounted entities, net of tax	402	—	402
Other	—	(225)	(225)
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-employment benefit liability or asset	340	68	408
Cash flow hedges that will subsequently be transferred to the balance sheet	(4)	—	(4)
Other comprehensive income	8,474	(266)	8,208

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%.

33. Contingent liabilities and legal proceedings

Contingent liabilities

There were contingent liabilities at 31 December 2024 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.


218		bp Annual Report and Form 20-F 2024

33. Contingent liabilities and legal proceedings – continued

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 $16 billion (2023 $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

Introduction

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 are discussed below.

Medical Benefits Class Action Settlement

In 2012 the Medical Benefits Class Action Settlement (Medical Settlement) was entered into with the plaintiffs steering committee. It includes an exclusive

remedy provision regarding class members pursuing exposure-based personal injury claims for later-manifested physical conditions (LMPCs). As of 31

December 2024, there were 26 pending lawsuits brought by class members claiming LMPCs.

Other civil complaints – personal injury

The vast majority of post-explosion clean-up, medical monitoring and personal injury claims from individuals that either opted out of the Medical

Settlement and/or were excluded from that settlement have been dismissed (including more than 620 cases in which the courts granted BPXP’s motions

for summary judgment). As of 31 December 2024, 38 cases remained pending in the district courts.

Non-US government lawsuits

Two class actions are pending in Mexican Federal District Courts against various bp group entities including BPXP and BP America Production Company

by separate plaintiff classes. Although the two actions are separate, both broadly seek penalties, damages and compensation for alleged environmental,

health and economic harm in Mexico as a result of the Incident. One of the actions also seeks an order requiring the bp defendants to repair alleged

damage to Mexican waters and land.

bp has answered the complaints in both actions by seeking dismissal on various grounds including that no oil reached Mexican waters or land and there

was no economic or environmental harm in Mexico.

These legal actions remain at a relatively early stage and while it is not possible to predict the outcome, bp believes that it has valid defences, and it intends

to defend such actions vigorously.


		bp Annual Report and Form 20-F 2024		219




	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 30 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 removed to federal courts, however Defendants’ attempts were ultimately unsuccessful.

Accordingly, 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. Defendants’ petition for writ of certiorari to the US Supreme Court seeking review of the US Fifth Circuit’s Riverwood decision was denied in early 2023.

In 2024, the US Fifth Circuit issued a further final ruling rejecting “federal officer” jurisdiction in a subset of the removed cases contested on a related

removal theory and remanded all such cases to state district court.

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 other oil & gas companies in a case, Plaquemines Parish v. Rozel, et al, set for

trial in March 2025. A state trial court in December 2024 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 have been severed from the initial March 2025 trial date, and the court has yet to establish a new

trial date for the plaintiffs’ now separate claims against Atlantic Richfield.

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.


220		bp Annual Report and Form 20-F 2024

34. Remuneration of senior management and non-executive directors

Remuneration of directors


			$ million
	2024	2023	2022
Total for all directors
Emoluments	8	8	8
Amounts received under incentive schemesa	5	6	13
Total	13	14	21

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.

Further information

Full details of individual directors’ remuneration are given in the Directors’ remuneration report on page 88.

Remuneration of directors and senior management


			$ million
	2024	2023	2022
Total for all senior management and non-executive directors
Short-term employee benefits	22	31	31
Pensions and other post-employment benefits	—	—	—
Share-based paymentsa	26	12	31
Termination benefits	3	—	—
Total	51	43	62

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, see page 74 for further information.

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 2024 to 14 February 2025.


		bp Annual Report and Form 20-F 2024		221




	Financial statements

35. Employee costs and numbers


			$ million
Employee costs	2024	2023	2022
Wages and salariesa	8,601	7,835	7,486
Social security costs	1,032	943	720
Share-based paymentsb	1,088	1,131	1,034
Pension and other post-employment benefit costs	519	370	576
	11,240	10,279	9,816


			2024			2023			2022
Average number of employeesc	US	Non-US	Total	US	Non-US	Total	US	Non-US	Total
gas & low carbon energy	900	4,400	5,300	900	3,700	4,600	700	3,400	4,100
oil production & operations	3,300	5,700	9,000	3,100	5,500	8,600	3,000	5,700	8,700
customers & productsd e	27,500	38,000	65,500	19,500	36,300	55,800	8,000	35,700	43,700
other businesses and corporate	1,400	9,800	11,200	1,400	9,000	10,400	1,300	8,500	9,800
	33,100	57,900	91,000	24,900	54,500	79,400	13,000	53,300	66,300

aIncludes termination costs of $336 million (2023 $96 million and 2022 $27 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 40,700 (2023 33,800 and 2022 23,300) service station staff.

eIncludes 1,700 (2023 0 and 2022 0) agricultural, operational and seasonal workers in Brazil.

36. Auditor’s remuneration


			$ million
Fees	2024	2023	2022
The audit of the company annual accountsa	40	38	36
The audit of accounts of subsidiaries of the company	17	15	15
Total audit	57	53	51
Audit-related assurance servicesb	4	4	4
Total audit and audit-related assurance services	61	57	55
Non-audit and other assurance services	4	3	—
Services relating to bp pension plans	1	1	1
	66	61	56

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.

2024 includes $1.3 million of additional fees for 2023. 2023 includes $0.2 million of additional fees for 2022. 2022 includes $0.3 million of additional fees

for 2021. 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 2024 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.

Under SEC regulations, the remuneration of the auditor of $66 million (2023 $61 million and 2022 $56 million) is required to be presented as follows: audit

$57 million (2023 $53 million and 2022 $51 million); other audit-related $4 million (2023 $4 million and 2022 $4 million); tax $nil (2023 $nil and 2022 $nil);

and all other fees $5 million (2023 $4 million and 2022 $1 million).


222		bp Annual Report and Form 20-F 2024

37. Subsidiaries, joint arrangements and associatesa

The more important subsidiaries, joint arrangements and associates of the group at 31 December 2024 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 14 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	Solar
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 2024.

38. Events after the reporting period

On 26 February 2025, bp announced a fundamentally reset strategy, with significant capital reallocation, and plans to drive improved performance, aimed

at growing free cash flow, returns and long-term shareholder value. This strategy will see bp grow its upstream oil and gas business, focus its downstream

business, and invest with increasing discipline into the transition. It builds on bp’s distinct strengths and competitive advantages as an integrated energy

company. There are no impacts on these financial statements related to the strategy announcements in accordance with IAS 10 ‘Events after the reporting

period’.


		bp Annual Report and Form 20-F 2024		223




	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 318-326.

aSee Note 1 - Investment in Rosneft.


224		bp Annual Report and Form 20-F 2024

Oil and natural gas exploration and production activities


									$ 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 2024		225




	Financial statements

Oil and natural gas exploration and production activities – continued


									$ million
									2024
	Europe		North America		South America	Asia Africa		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 parties	—	1,943	—	—	1,967	2,692	1,854	—	8,456
Sales between businesses	—	—	—	—	—	—	—	—	—
	—	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)	—	26	—	—	134	339	25	—	524
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	2,375	1,564	—	7,275
Profit (loss) before taxation	—	1,203	—	—	(629)	317	290	—	1,181
Allocable taxes	—	931	—	—	(766)	198	120	—	483
Results of operations	—	272	—	—	137	119	170	—	698

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.

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.


226		bp Annual Report and Form 20-F 2024

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

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

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.

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 2024		227




	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 parties	—	2,159	—	—	2,070	2,550	1,716	—	8,495
Sales between businesses	—	—	—	—	—	—	—	—	—
	—	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)	—	21	—	—	257	239	8	—	525
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	2,121	1,526	—	6,229
Profit (loss) before taxation	—	1,332	—	—	315	429	190	—	2,266
Allocable taxes	—	1,124	—	—	127	173	117	—	1,541
Results of operations	—	208	—	—	188	256	73	—	725

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.

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.


228		bp Annual Report and Form 20-F 2024

Oil and natural gas exploration and production activities – continued


										$ million
										2022
	Europe		North America		South America	Africa	Asia		Australasia	Total
	UK	Rest of Europe	USh	Rest of North America			Russia	Rest of Asia
Subsidiaries
Capitalized costs at 31 Decembera b
Gross capitalized costs
Proved properties	30,010	—	65,870	6	16,720	20,257	—	39,899	6,324	179,086
Unproved properties	397	—	2,976	1,875	2,507	2,535	—	1,622	659	12,571
	30,407	—	68,846	1,881	19,227	22,792	—	41,521	6,983	191,657
Accumulated depreciation	21,757	—	38,205	1,586	13,849	18,207	—	21,642	4,588	119,834
Net capitalized costs	8,650	—	30,641	295	5,378	4,585	—	19,879	2,395	71,823

Costs incurred for the year ended 31 Decembera b
Acquisition of properties
Proved	12	—	183	—	—	—	—	245	—	440
Unproved	—	—	37	164	2	14	—	—	—	217
	12	—	220	164	2	14	—	245	—	657
Exploration and appraisal costsc	39	—	288	137	235	103	—	73	17	892
Development	318	—	3,825	15	483	1,378	—	1,555	176	7,750
Total costs	369	—	4,333	316	720	1,495	—	1,873	193	9,299

Results of operations for the year ended 31 Decembera
Sales and other operating revenuesd
Third parties	549	—	2,101	420	2,977	3,836	—	6,551	1,588	18,022
Sales between businesses	5,747	—	12,746	—	538	2,146	—	9,932	1,472	32,581
	6,296	—	14,847	420	3,515	5,982	—	16,483	3,060	50,603
Exploration expenditure	11	—	144	109	172	57	—	94	(2)	585
Production costs	498	—	2,102	83	327	592	—	723	107	4,432
Production taxes	1	—	194	—	513	—	—	1,544	73	2,325
Other costs (income)e	(210)	(47)	2,926	63	96	206	32	(44)	300	3,322
Depreciation, depletion and amortization	1,242	—	3,122	18	680	2,075	1	2,495	384	10,017
Net impairments and (gains) losses on sale of businesses and fixed assetsf	(433)	(901)	217	(3)	1,570	(1,189)	1,523	(341)	(43)	400
	1,109	(948)	8,705	270	3,358	1,741	1,556	4,471	819	21,081
Profit (loss) before taxationg	5,187	948	6,142	150	157	4,241	(1,556)	12,012	2,241	29,522
Allocable taxes	4,443	—	1,409	50	1,814	886	(5)	6,651	842	16,090
Results of operations	744	948	4,733	100	(1,657)	3,355	(1,551)	5,361	1,399	13,432

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

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.

income as incurred.

dPresented net of transportation costs, purchases and sales taxes.

eIncludes property taxes and other government take. The UK region includes a $256-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-insurance

programme.

fRussia impairments include other businesses with Rosneft, which were reported in the oil production and operation segment. The Rosneft impairment is reported in the other businesses and corporate

segment.

gExcludes the unwinding of the discount on provisions and payables amounting to $294 million which is included in finance costs in the group income statement.

hAn amendment has been made to correctly present offsetting movements in proved properties cost and depreciation, The amendment has no impact on reported profit or net book amounts of total

proved properties.


		bp Annual Report and Form 20-F 2024		229




	Financial statements

Oil and natural gas exploration and production activities – continued


										$ million
										2022
	Europe		North America		South America	Africa	Asia		Australasia	Total
	UK	Rest of Europe	US	Rest of North America			Russiaa	Rest of Asia
Equity-accounted entities (bp share)
Capitalized costs at 31 Decemberb c
Gross capitalized costs
Proved properties	—	3,739	—	—	12,000	7,927	—	8,381	—	32,047
Unproved properties	—	611	—	—	120	371	—	—	—	1,102
	—	4,350	—	—	12,120	8,298	—	8,381	—	33,149
Accumulated depreciation	—	1,800	—	—	6,356	572	—	553	—	9,281
Net capitalized costs	—	2,550	—	—	5,764	7,726	—	7,828	—	23,868

Costs incurred for the year ended 31 Decemberb d e
Acquisition of propertiesc
Proved	—	1,224	—	—	—	—	—	—	—	1,224
Unproved	—	204	—	—	—	—	—	—	—	204
	—	1,428	—	—	—	—	—	—	—	1,428
Exploration and appraisal costsd	—	46	—	—	22	60	28	—	—	156
Developmentf	—	(24)	—	—	673	292	428	625	—	1,994
Total costs	—	1,450	—	—	695	352	456	625	—	3,578

Results of operations for the year ended 31 Decemberb
Sales and other operating revenuesg
Third parties	—	2,050	—	—	2,171	1,137	—	829	—	6,187
Sales between businesses	—	—	—	—	—	—	6,052	—	—	6,052
	—	2,050	—	—	2,171	1,137	6,052	829	—	12,239
Exploration expenditure	—	39	—	—	—	7	13	—	—	59
Production costs	—	148	—	—	628	246	411	191	—	1,624
Production taxes	—	—	—	—	397	15	4,435	—	—	4,847
Other costs (income)	—	(6)	—	—	16	152	97	20	—	279
Depreciation, depletion and amortization	—	348	—	—	462	572	535	553	—	2,470
Net impairments and losses on sale of businesses and fixed assets	—	164	—	—	—	—	—	—	—	164
	—	693	—	—	1,503	992	5,491	764	—	9,443
Profit (loss) before taxation	—	1,357	—	—	668	145	561	65	—	2,796
Allocable taxes	—	1,098	—	—	77	81	109	66	—	1,431
Results of operations	—	259	—	—	591	64	452	(1)	—	1,365

aAmounts reported for Russia in this table are bp’s estimated share of the equity-accounted entities, including Rosneft’s worldwide activities (of which insignificant amounts relate to outside Russia).

bThese 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.

cCosts of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.

dIncludes 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.

eThe 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.

fRest of Europe development costs are negative due to a true-up of prior period spend.

gPresented net of sales tax.


230		bp Annual Report and Form 20-F 2024

Movements in estimated net proved reserves


								million barrels
Crude oila b								2024
	Europe		North America		South America	Asia Africa		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.


		bp Annual Report and Form 20-F 2024		231




	Financial statements

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	USc	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.


232		bp Annual Report and Form 20-F 2024

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	USc	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

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 2024		233




	Financial statements

Movements in estimated net proved reserves – continued


								billion cubic feet
Natural gasa b								2024
	Europe		North America		South America	Asia Africa		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

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.


234		bp Annual Report and Form 20-F 2024

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	USf	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

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 39 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 2024		235




	Financial statements

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

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.


236		bp Annual Report and Form 20-F 2024

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	USc	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

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.

eVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.


		bp Annual Report and Form 20-F 2024		237




	Financial statements

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	USc	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

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.


238		bp Annual Report and Form 20-F 2024

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

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.


		bp Annual Report and Form 20-F 2024		239




	Financial statements

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	USf	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

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.

fIncludes 39 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.


240		bp Annual Report and Form 20-F 2024

Movements in estimated net proved reserves – continued


									million barrels
Crude oila b									2022
	Europe		North America		South America	Africac	Asia		Australasia	Total
	UK	Rest of Europe	US	Rest of North America			Russia	Rest of Asia
Subsidiaries
At 1 January
Developed	178	—	705	24	5	117	—	930	28	1,987
Undeveloped	101	—	601	167	7	14	—	449	4	1,343
	279	—	1,306	191	12	131	—	1,379	33	3,330
Changes attributable to
Revisions of previous estimates	9	—	(11)	—	(1)	1	—	(40)	(4)	(47)
Improved recovery	2	—	(2)	—	—	4	—	—	—	5
Purchases of reserves-in-place	—	—	—	—	—	—	—	3	—	3
Discoveries and extensions	—	—	22	—	—	1	—	—	—	23
Production	(29)	—	(108)	(5)	(2)	(31)	—	(112)	(5)	(292)
Sales of reserves-in-place	—	—	(1)	(185)	—	(80)	—	(157)	(3)	(426)
	(18)	—	(100)	(191)	(3)	(105)	—	(306)	(11)	(734)
At 31 Decemberc
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
Equity-accounted entities (bp share)d
At 1 January
Developed	—	100	—	10	275	3	3,045	1	—	3,434
Undeveloped	—	21	—	12	253	—	2,540	1	—	2,826
	—	121	—	22	527	3	5,585	1	—	6,260
Changes attributable to
Revisions of previous estimates	—	(17)	—	1	(1)	23	4	(46)	—	(37)
Improved recovery	—	1	—	—	14	25	—	—	—	40
Purchases of reserves-in-place	—	42	—	—	—	165	—	152	—	359
Discoveries and extensions	—	2	—	—	—	—	—	—	—	2
Production	—	(17)	—	(1)	(21)	(12)	(55)	(9)	—	(115)
Sales of reserves-in-placef	—	(25)	—	(10)	—	(3)	(5,535)	(1)	—	(5,574)
	—	(15)	—	(10)	(8)	198	(5,585)	95	—	(5,325)
At 31 December
Developed	—	90	—	5	276	127	—	95	—	592
Undeveloped	—	16	—	7	244	74	—	1	—	342
	—	106	—	12	520	201	—	96	—	935
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed	178	100	705	34	280	119	3,045	931	28	5,421
Undeveloped	101	21	601	179	259	14	2,540	450	4	4,169
	279	121	1,306	213	539	134	5,585	1,381	33	9,590
At 31 December
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

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 3 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.

eIncludes assets held for sale in Algeria.

fbp's decision to exit its Russia business, including its shareholding in Rosneft, is treated as sales of reserves in place.


		bp Annual Report and Form 20-F 2024		241




	Financial statements

Movements in estimated net proved reserves – continued


									million barrels
Natural gas liquidsa b									2022
	Europe		North America		South America	Africac	Asia		Australasia	Total
	UK	Rest of Europe	USd	Rest of North America			Russia	Rest of Asia
Subsidiaries
At 1 January
Developed	8	—	132	—	2	9	—	—	2	153
Undeveloped	—	—	195	—	19	1	—	—	—	215
	9	—	328	—	21	10	—	—	2	368
Changes attributable to
Revisions of previous estimates	(1)	—	101	—	(18)	(1)	—	—	—	81
Improved recovery	—	—	16	—	—	1	—	—	—	17
Purchases of reserves-in-place	—	—	—	—	—	—	—	—	—	—
Discoveries and extensions	—	—	1	—	—	1	—	—	—	2
Productiond	(2)	—	(28)	—	(2)	(2)	—	—	(1)	(34)
Sales of reserves-in-place	—	—	(1)	—	—	(1)	—	—	—	(1)
	(2)	—	90	—	(19)	(2)	—	—	(1)	64
At 31 Decembere
Developed	6	—	181	—	1	6	—	—	1	196
Undeveloped	—	—	236	—	—	1	—	—	—	237
	6	—	417	—	1	7	—	—	1	432
Equity-accounted entities (bp share)f
At 1 January
Developed	—	6	—	—	2	17	100	—	—	125
Undeveloped	—	—	—	—	—	—	41	—	—	41
	—	6	—	—	2	17	140	—	—	166
Changes attributable to
Revisions of previous estimates	—	(1)	—	—	2	7	—	—	—	8
Improved recovery	—	—	—	—	—	—	—	—	—	—
Purchases of reserves-in-place	—	2	—	—	—	20	—	—	—	21
Discoveries and extensions	—	—	—	—	—	—	—	—	—	—
Production	—	(1)	—	—	—	(1)	—	—	—	(2)
Sales of reserves-in-placeg	—	(2)	—	—	—	(17)	(140)	—	—	(159)
	—	(2)	—	—	2	9	(140)	—	—	(132)
At 31 December
Developed	—	4	—	—	3	17	—	—	—	23
Undeveloped	—	—	—	—	1	9	—	—	—	10
	—	4	—	—	4	26	—	—	—	34
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed	8	6	132	—	4	26	100	—	2	278
Undeveloped	—	—	195	—	19	1	41	—	—	256
	9	6	328	—	22	27	140	—	2	534
At 31 December
Developed	6	4	181	—	4	23	—	—	1	219
Undeveloped	—	—	236	—	1	10	—	—	—	247
	6	4	417	—	5	33	—	—	1	466

sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cIncludes assets held for sale in Algeria.

dExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.

eIncludes 0.4 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

gbp's decision to exit its Russia business, including its shareholding in Rosneft, is treated as sales of reserves in place.


242		bp Annual Report and Form 20-F 2024

Movements in estimated net proved reserves – continued


									million barrels
Total liquidsa b										2022
	Europe		North America		South America	Africac	Asia		Australasia	Total
	UK	Rest of Europe	USd	Rest of North America			Russia	Rest of Asia
Subsidiaries
At 1 January
Developed	187	—	837	24	7	125	—	930	30	2,141
Undeveloped	101	—	796	167	25	15	—	449	4	1,558
	288	—	1,634	191	32	140	—	1,379	34	3,699
Changes attributable to
Revisions of previous estimates	8	—	89	—	(19)	—	—	(40)	(4)	34
Improved recovery	2	—	14	—	—	5	—	—	—	22
Purchases of reserves-in-place	1	—	—	—	—	—	—	3	—	3
Discoveries and extensions	—	—	23	—	—	1	—	—	—	25
Productiond	(31)	—	(136)	(5)	(3)	(34)	—	(112)	(5)	(326)
Sales of reserves-in-place	—	—	(2)	(185)		(80)	—	(157)	(4)	(428)
	(20)	—	(11)	(191)	(22)	(107)	—	(306)	(13)	(670)
At 31 Decembere
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
Equity-accounted entities (bp share)f
At 1 January
Developed	—	106	—	10	276	20	3,145	1	—	3,558
Undeveloped	—	21	—	12	253	—	2,581	1	—	2,867
	—	127	—	22	529	20	5,726	1	—	6,425
Changes attributable to
Revisions of previous estimates	—	(18)	—	1	1	30	4	(46)	—	(29)
Improved recovery	—	1	—	—	14	25	—	—	—	40
Purchases of reserves-in-place	—	44	—	—	—	185	—	152	—	380
Discoveries and extensions	—	2	—	—	—	—	—	—	—	2
Production	—	(18)	—	(1)	(21)	(13)	(55)	(9)	—	(117)
Sales of reserves-in-place	—	(27)	—	(10)	—	(19)	(5,675)	(1)	—	(5,733)
	—	(17)	—	(10)	(6)	207	(5,726)	95	—	(5,457)
At 31 December
Developed	—	94	—	5	278	144	—	95	—	616
Undeveloped	—	16	—	7	245	83	—	1	—	352
	—	110	—	12	523	227	—	96	—	968
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed	187	106	837	34	284	146	3,145	931	30	5,699
Undeveloped	101	21	796	179	278	15	2,581	450	4	4,425
	288	127	1,634	213	561	161	5,726	1,381	34	10,124
At 31 December
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

sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cIncludes assets held for sale in Algeria.

dExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.

eAlso includes 3 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

fVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

gbp's decision to exit its Russia business, including its shareholding in Rosneft, is treated as sales of reserves in place.


		bp Annual Report and Form 20-F 2024		243




	Financial statements

Movements in estimated net proved reserves – continued


									billion cubic feet
Natural gasa b									2022
	Europe		North America		South America	Africac	Asia		Australasia	Total
	UK	Rest of Europe	US	Rest of North America			Russia	Rest of Asia
Subsidiaries
At 1 January
Developed	455	—	2,401	—	1,152	1,433	—	3,266	1,584	10,291
Undeveloped	45	—	3,404	—	1,147	154	—	2,522	939	8,211
	501	—	5,805	—	2,299	1,587	—	5,788	2,523	18,502
Changes attributable to
Revisions of previous estimates	6	—	449	—	2	180	—	(575)	(165)	(102)
Improved recovery	1	—	46	—	—	—	—	—	—	47
Purchases of reserves-in-place	2	—	—	—	—	—	—	92	—	94
Discoveries and extensions	—	—	10	—	—	87	—	21	10	128
Productiond	(109)	—	(493)	—	(476)	(517)	—	(561)	(276)	(2,432)
Sales of reserves-in-place	—	—	(9)	—	—	(93)	—	(47)	—	(149)
	(100)	—	4	—	(474)	(344)	—	(1,069)	(431)	(2,414)
At 31 Decembere
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
Equity-accounted entities (bp share)f
At 1 January
Developed	—	130	—	4	929	689	11,399	—	—	13,149
Undeveloped	—	11	—	4	536	133	7,279	—	—	7,964
	—	140	—	8	1,465	822	18,678	—	—	21,113
Changes attributable to
Revisions of previous estimates	—	(7)	—	1	162	131	53	—	—	340
Improved recovery	—	—	—	—	82	—	—	—	—	82
Purchases of reserves-in-place	—	14	—	—	—	575	—	45	—	634
Discoveries and extensions	—	4	—	—	—	—	—	—	—	4
Productiond	—	(25)	—	—	(128)	(36)	(86)	(2)	—	(277)
Sales of reserves-in-placeg	—	(49)	—	(4)	—	(803)	(18,645)	—	—	(19,501)
	—	(64)	—	(3)	115	(133)	(18,678)	43	—	(18,719)
At 31 December
Developed	—	72	—	3	974	534	—	43	—	1,627
Undeveloped	—	5	—	2	606	154	—	—	—	767
	—	77	—	5	1,580	689	—	43	—	2,394
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed	455	130	2,401	4	2,081	2,121	11,399	3,266	1,584	23,440
Undeveloped	45	11	3,404	4	1,683	287	7,279	2,522	939	16,174
	501	140	5,805	8	3,764	2,408	18,678	5,788	2,523	39,615
At 31 December
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

sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cIncludes assets held for sale in Algeria.

dIncludes 122 billion cubic feet of natural gas consumed in operations, 86 billion cubic feet in subsidiaries, 36 billion cubic feet in equity-accounted entities.

eIncludes 547 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

fVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

gbp's decision to exit its Russia business, including our shareholding in Rosneft, is treated as sales of reserves in place.


244		bp Annual Report and Form 20-F 2024

Movements in estimated net proved reserves – continued


								million barrels of oil equivalentc
Total hydrocarbonsa b									2022
	Europe		North America		South America	Africad	Asia		Australasia	Total
	UK	Rest of Europe	USe	Rest of North America			Russia	Rest of Asia
Subsidiaries
At 1 January
Developed	265	—	1,251	24	206	372	—	1,494	303	3,915
Undeveloped	109	—	1,383	167	223	41	—	884	166	2,973
	374	—	2,634	191	429	414	—	2,377	469	6,889
Changes attributable to
Revisions of previous estimates	9	—	167	—	(18)	31	—	(139)	(33)	17
Improved recovery	2	—	22	—	—	5	—	—	—	30
Purchases of reserves-in-place	1	—	—	—	—	—	—	18	—	19
Discoveries and extensions	—	—	25	—	—	16	—	4	2	47
Productionf g	(50)	—	(221)	(5)	(85)	(123)	—	(209)	(53)	(746)
Sales of reserves-in-place	—	—	(3)	(185)	—	(96)	—	(165)	(4)	(453)
	(37)	—	(10)	(191)	(103)	(167)	—	(491)	(87)	(1,086)
At 31 Decembere
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
Equity-accounted entities (bp share)h
At 1 January
Developed	—	128	—	11	437	139	5,110	1	—	5,825
Undeveloped	—	23	—	12	345	23	3,836	1	—	4,240
	—	151	—	23	782	162	8,946	1	—	10,065
Changes attributable to
Revisions of previous estimates	—	(19)	—	1	29	53	13	(46)	—	30
Improved recovery	—	1	—	—	28	25	—	—	—	54
Purchases of reserves-in-place	—	46	—	—	—	284	—	159	—	489
Discoveries and extensions	—	2	—	—	—	—	—	—	—	2
Productiong	—	(22)	—	(1)	(43)	(19)	(70)	(10)	—	(165)
Sales of reserves-in-placei	—	(36)	—	(10)	—	(158)	(8,890)	(1)	—	(9,095)
	—	(28)	—	(11)	14	184	(8,946)	102	—	(8,685)
At 31 December
Developed	—	106	—	6	446	236	—	102	—	896
Undeveloped	—	17	—	7	349	110	—	1	—	485
	—	123	—	13	796	346	—	103	—	1,381
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed	265	128	1,251	35	642	511	5,110	1,494	303	9,740
Undeveloped	109	23	1,383	179	568	65	3,836	884	166	7,214
	374	151	2,634	214	1,210	576	8,946	2,379	469	16,954
At 31 December
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

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.

dIncludes assets held for sale in Algeria.

eIncludes 39 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

fExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.

gIncludes 21 million barrels of oil equivalent of natural gas consumed in operations, 15 million barrels of oil equivalent in subsidiaries, 6 million barrels of oil equivalent in equity-accounted entities.

hVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

ibp's decision to exit its Russia business, including our shareholding in Rosneft, is treated as sales of reserves in place.


		bp Annual Report and Form 20-F 2024		245




	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
									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.


246		bp Annual Report and Form 20-F 2024

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.


		bp Annual Report and Form 20-F 2024		247




	Financial statements

Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas

reserves – continued


										$ million
										2022
	Europe		North America		South America	Africa	Asia		Australasia	Total
	UK	Rest of Europe	US	Rest of North America			Russia	Rest of Asia
At 31 December
Subsidiaries
Future cash inflowsa	34,900	—	154,500	—	16,400	9,400	—	151,500	23,600	390,300
Future production costb	13,600	—	36,000	—	5,300	1,300	—	42,700	5,200	104,100
Future development costb	1,100	—	12,200	—	1,400	700	—	8,800	1,900	26,100
Future taxationc	12,600	—	19,800	—	5,000	1,900	—	65,200	5,500	110,000
Future net cash flows	7,600	—	86,500	—	4,700	5,500	—	34,800	11,000	150,100
10% annual discountd	3,400	—	38,200	—	700	1,000	—	11,800	4,000	59,100
Standardized measure of discounted future net cash flowse	4,200	—	48,300	—	4,000	4,500	—	23,000	7,000	91,000
Equity-accounted entities (bp share)f
Future cash inflowsa	—	12,800	—	—	49,800	20,500	—	9,200	—	92,300
Future production costb	—	2,100	—	—	22,000	6,300	—	4,900	—	35,300
Future development costb	—	400	—	—	4,900	2,800	—	3,000	—	11,100
Future taxationc	—	8,100	—	—	7,100	4,300	—	400	—	19,900
Future net cash flows	—	2,200	—	—	15,800	7,100	—	900	—	26,000
10% annual discountd	—	400	—	—	9,300	2,200	—	200	—	12,100
Standardized measure of discounted future net cash flowsg	—	1,800	—	—	6,500	4,900	—	700	—	13,900
Total subsidiaries and equity-accounted entities
Standardized measure of discounted future net cash flowsh	4,200	1,800	48,300	—	10,500	9,400	—	23,700	7,000	104,900

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	(22,800)	(4,600)	(27,400)
Development costs for the current year as estimated in previous year	5,500	1,800	7,300
Extensions, discoveries and improved recovery, less related costs	1,600	900	2,500
Net changes in prices and production cost	80,800	11,100	91,900
Revisions of previous reserves estimates	(18,300)	(2,700)	(21,000)
Net change in taxation	(23,000)	1,400	(21,600)
Future development costs	(2,100)	(800)	(2,900)
Net change in purchase and sales of reserves-in-place	(4,300)	(34,800)	(39,100)
Addition of 10% annual discount	6,700	3,800	10,500
Total change in the standardized measure during the yeari	24,100	(23,900)	200

aThe marker prices used were Brent $101.24/bbl, Henry Hub $6.19/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 $1,216 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.

gNo reserves are reported for Russia following bp's announcement that it will exit the country. The impact of this change is primarily included within sales of reserves-in-place.

hIncludes future net cash flows for assets held for sale at 31 December 2022.

iTotal change in the standardized measure during the year includes the effect of exchange rate movements.


248		bp Annual Report and Form 20-F 2024

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 2024, 2023 and 2022.

Production for the yeara b


	Europe		North America		South America	Africa	Asia		Australasia	Total
	UK	Rest of Europe	US	Rest of North America			Russiac	Rest of Asia
Subsidiariesd
Crude oile									thousand barrels per day
2024	70	—	376	—	4	19	—	297	9	775
2023	74	—	335	—	4	29	—	293	10	745
2022	80	—	296	15	5	83	—	307	12	797
Natural gas liquids									thousand barrels per day
2024	4	—	107	—	4	1	—	—	2	117
2023	5	—	88	—	4	2	—	—	2	100
2022	5	—	76	—	4	6	—	—	2	93
Natural gasf									million cubic feet per day
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
2022	271	—	1,291	—	1,276	1,353	—	1,485	752	6,428
Equity-accounted entities (bp share)
Crude oile									thousand barrels per day
2024	—	58	—	—	56	82	—	69	—	266
2023	—	60	—	—	57	82	—	62	—	261
2022	—	47	—	—	59	33	150	25	—	314
Natural gas liquids									thousand barrels per day
2024	—	2	—	—	1	6	—	—	—	9
2023	—	3	—	—	1	6	—	—	—	9
2022	—	2	—	—	1	5	—	—	—	9
Natural gasf									million cubic feet per day
2024	—	55	—	—	300	85	—	—	—	440
2023	—	58	—	—	299	74	—	—	—	432
2022	—	66	—	—	296	64	248	—	—	674

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.

cAmounts reported for Russia include bp’s share of Rosneft worldwide activities, including insignificant amounts outside Russia.

dAll of the oil and liquid production from Canada is bitumen.

eCrude oil includes condensate.

fNatural gas production excludes gas consumed in operations.


		bp Annual Report and Form 20-F 2024		249




	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 2024. 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 Asiae		Australasiae	Totala
		UK	Rest of Europe	US	Rest of North America
Number of productive wells at 31 December 2024
Oil wellsb	– gross	115	126	1,439	8	4,823	825	2,848	—	10,184
	– net	67	20	751	2	2,368	77	625	—	3,911
Gas wellsc	– gross	36	10	3,607	—	1,209	89	185	89	5,225
	– net	8	2	1,819	—	392	37	70	21	2,348
Oil and natural gas acreage at 31 December 2024									thousands of acres
Developed	– gross	70	87	1,565	8	1,319	618	1,343	838	5,847
	– net	40	14	977	2	375	122	281	157	1,967
Undevelopedd	– gross	479	1,794	3,916	9,663	10,976	20,256	9,877	4,858	61,818
	– net	368	285	3,376	6,298	5,223	8,276	5,585	2,826	32,236

aBecause of rounding, some totals may not exactly agree with the sum of their component parts.

bIncludes approximately 164 gross (29 net) multiple completion wells (more than one formation producing into the same well bore).

cIncludes approximately 12 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.

eIncludes correction of acreage distribution between continents.

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			Russia	Rest of Asia
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
2022
Exploratory
Productive	—	—	0.5	1.0	1.0	0.6	—	0.5	0.3	4.0
Dry	—	—	—	1.2	0.3	0.1	—	0.8	—	2.3
Development
Productive	0.9	1.5	137.2	0.3	71.4	2.8	—	39.0	1.4	254.5
Dry	—	—	1.1	—	0.5	0.1	—	1.1	—	2.8

aBecause of rounding, some totals may not exactly agree with the sum of their component parts.

bIncludes correction of 2023 productive wells


« See glossary on page 351		bp Annual Report and Form 20-F 2024		313




	Additional disclosures

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
	2024	2023	2022
gas & low carbon energy
Gain on sale of businesses and fixed assetsa	297	19	45
Net impairment and losses on sale of businesses and fixed assetsa	(3,004)	(2,221)	588
Environmental and related provisions	—	—	—
Restructuring, integration and rationalization costsb	(25)	—	8
Fair value accounting effectscd«	(1,550)	8,859	(1,811)
Othere	1,048	(1,299)	(197)
	(3,234)	5,358	(1,367)
oil production & operations
Gain on sale of businesses and fixed assetsa	144	297	3,446
Net impairment and losses on sale of businesses and fixed assetsa	(790)	(1,819)	(4,508)
Environmental and related provisionsf	5	54	518
Restructuring, integration and rationalization costsb	(15)	(1)	(11)
Fair value accounting effects	—	—	—
Otherg	(492)	(121)	52
	(1,148)	(1,590)	(503)
customers & products
Gain on sale of businesses and fixed assetsa	190	44	374
Net impairment and losses on sale of businesses and fixed assetsah	(3,117)	(1,757)	(1,983)
Environmental and related provisions	(99)	(97)	(101)
Restructuring, integration and rationalization costsb	(123)	—	18
Fair value accounting effectsd	(81)	(86)	(309)
Otheri	(847)	(287)	81
	(4,077)	(2,183)	(1,920)
other businesses & corporate
Gain on sale of businesses and fixed assetsa	39	1	1
Net impairment and losses on sale of businesses and fixed assetsa	(19)	(41)	(17)
Environmental and related provisionsj	(87)	(604)	(92)
Restructuring, integration and rationalization costsb	(59)	38	19
Fair value accounting effectsd	(221)	630	(1,381)
Rosneftk	—	—	(24,033)
Gulf of America oil spill	(51)	(57)	(84)
Other	18	(4)	21
	(380)	(37)	(25,566)
Total before interest and taxation	(8,839)	1,548	(29,356)
Finance costsl	(505)	(405)	(425)
Total before taxation	(9,344)	1,143	(29,781)
Taxation on adjusting itemsm	1,495	972	456
Taxation – tax rate change effectn	(316)	232	(1,834)
Total after taxationo	(8,165)	2,347	(31,159)

aSee Financial statements – Note 4 for further information.

bRestructuring 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. 2022 includes release of provisions for the reinvent bp restructuring costs.

cUnder 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.

dFor further information, including the nature of fair value accounting effects reported in each segment, see page 355.

e2024 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.

f2022 includes a provision reversal relating to the change in discount rate on retained decommissioning provisions.

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. 2022 primarily reflects charges due to the annual update of

environmental provisions, including asbestos-related provisions for past operations, together with updates of non-Gulf of America oil spill related legal provisions.

kFor more information see Financial statements – Note 1 Significant accounting policies, judgements, estimates and assumptions – Investment in Rosneft, and Note 17 – Investments in associates.

lAll 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. 2024 includes the unwinding of discounting effects relating to certain onerous contract provisions. 2023 and

2022 include the income statement impact associated with the buyback of finance debt.

mIncludes 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.

n2024 and 2023 include revisions to the deferred tax impact of the introduction of the UK Energy Profits Levy (EPL) on temporary differences existing at 31 December 2022 that are expected to unwind

before 31 March 2028. 2022 includes the deferred tax impact of the introduction of the EPL. The EPL increases the headline rate of tax to 78% (75% until 31 October 2024) and applies to taxable profits


314		bp Annual Report and Form 20-F 2024

from bp’s North Sea business made from 1 January 2023 until 31 March 2028. In October 2024 the UK government announced changes to the EPL including a 3% increase in the rate from 1 November

2024, the removal of the Levy’s main investment allowance and an extension to 31 March 2030. 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 after 31 December 2024 and will result in a non-cash deferred tax charge of around $0.5 billion in the year ended 31 December 2025.

o2023 and 2022 include a $146-million charge and a $505-million charge respectively 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 355.


			$ million
	2024	2023	2022
gas & low carbon energy
Unrecognized (gains) losses brought forward from previous period	(1,125)	(9,960)	(8,149)
Favourable (adverse) impact relative to management’s measure of performance	(1,550)	8,859	(1,811)
Exchange translation gains (losses) on fair value accounting effects	1	(24)	—
Unrecognized (gains) losses carried forward	(2,674)	(1,125)	(9,960)
customers & products
Unrecognized (gains) losses brought forward from previous period	(17)	79	391
Favourable (adverse) impact relative to management’s measure of performance	(81)	(86)	(309)
Exchange translation gains (losses) on fair value accounting effects	2	(10)	(3)
Unrecognized (gains) losses carried forward	(96)	(17)	79
other businesses & corporate
Unrecognized (gains) losses brought forward from previous period	(925)	(1,555)	(174)
Favourable (adverse) impact relative to management’s measure of performancea	(221)	630	(1,381)
Unrecognized (gains) losses carried forward	(1,146)	(925)	(1,555)

Group
Unrecognized (gains) losses brought forward from previous period	(2,067)	(11,436)	(7,932)
Favourable (adverse) impact relative to management’s measure of performance	(1,852)	9,403	(3,501)
Exchange translation gains (losses) on fair value accounting effects	3	(34)	(3)
Unrecognized (gains) losses carried forward	(3,916)	(2,067)	(11,436)

Favourable (adverse) impact relative to management’s measure of performance – by region
gas & low carbon energy
US	(582)	900	(1,140)
Non-US	(968)	7,959	(671)
	(1,550)	8,859	(1,811)
customers & products
US	(214)	(18)	3
Non-US	133	(68)	(312)
	(81)	(86)	(309)
other businesses & corporate
US	—	—	—
Non-US	(221)	630	(1,381)
	(221)	630	(1,381)
	(1,852)	9,403	(3,501)
Taxation credit (charge)	325	(915)	434
	(1,527)	8,488	(3,067)

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 355.


316		bp Annual Report and Form 20-F 2024

Liquidity and capital resources

Financial framework

The financial framework sets out how we allocate capital, balancing

between strengthening the balance sheet, investing in the business, and

delivering resilient distributions.

Net debt« at 31 December 2024 was $23.0 billion and is expected to

reduce over time to a targeted range of $14-18 billion by the end of 2027,

reflecting the allocation of potential proceeds from any transactions related

to the Castrol strategic review and announcement to bring a strategic

partner into Lightsource bp. The exact timing of achieving our net debt

target range will therefore be impacted by the timing of any potential

transactions. bp is committed to maintaining a strong balance sheet and ‘A’

range credit metrics throughout the cycle.

Our shareholder distributions include a dividend, resilient to a lower price

environment, and we remain committed to sharing excess cash through

share buybacks over time. Our distribution policy reflects the balance

between the uses of cash alongside an ongoing consideration of factors,

including changes in the environment, the underlying performance of the

business, the outlook for the group financial framework, and other market

factors which may vary quarter to quarter.

We expect operating cash flow to cover capital expenditure« and the

dividend. Capital expenditure in 2024 was $16.2 billion, including $0.1 billion

of inorganic capital expenditure«. We expect capital expenditure of around

$15 billion in 2025 and a range of $13-15 billion per annum from 2026 to

2027 including inorganic expenditure. This is a level that maximizes cash

generation and grows the financial scale of the company. Within this frame

we are reallocating capital to our highest returning opportunities, with an

average $10 billion per year allocated to oil and gas, $3-4 billion in

customers and products and less than $800 million per year in low carbon

energy to 2027. In a period of low prices, the group has the flexibility to

reduce or defer capital investment, as appropriate.

In 2024, the return on average capital employed« was 14.2%a at an average

of $81 per barrel. The return on average capital employed is targeted to be

over 16% by 2027 at $70 per barrel in 2024 real terms, and assuming bp

planning assumptions, as we execute our reset strategy. This is supported

by an expected compound annual growth rate in adjusted free cash flow«

of over 20% from 2024 to 2027 and subject to the same price and planning

assumptions.

aNearest equivalent IFRS measures of numerator and denominator are profit for the year

attributable to bp shareholders and total equity respectively: Profit for the year attributable to bp

shareholders divided by total equity at the end of 2024 0.5%.

Dividends and other 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 7.270 to 8.000 cents per ordinary share per

quarter in the second quarter of 2024.

The total dividend distributed to bp shareholders in 2024 was $5.0 billion

(2023 $4.8 billion). This dividend was all paid in cash as shareholders no

longer have the option to receive a scrip dividend in place of receiving cash.

Our dividend is resilient to a lower price environment. Based on our current

forecasts and subject to the board’s discretion each quarter, we expect an

annual increase in the dividend per ordinary share of at least 4%.

Additionally, subject to board discretion, it is our intention to share excess

cash with investors through share buybacks over time. This policy enables

bp to share upside when the price environment is stronger, while ensuring

the balance sheet remains resilient in a lower price environment. Taken

together, our guidance is for total dividends and share buybacks to be in the

range of 30 to 40% of operating cash flow over time, including buybacks to

offset dilution from employee share schemes.

In 2024 bp executed $7.1 billion of share buybacks (2023 $7.9 billion),

including fees and stamp duty. Since 1 January 2025 an additional

$927 million shares have been repurchased up to 14 February 2025,

including fees and stamp duty.

In setting the dividend and share buybacks each quarter, the board will

continue to take into account factors including the cumulative level of and

outlook for cash flow, share count reduction from buybacks and

maintaining ‘A’ range credit metrics.

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 65 for further

information on risks associated with prices and markets, and Financial

statements – Note 29.

The group’s finance debt at 31 December 2024 amounted to $59.5 billion

(2023 $52.0 billion). Of the total finance debt, $4.5 billion is classified as

short term at the end of 2024 (2023 $3.3 billion). See Financial statements

– Note 26 for more information on the short-term balance. Net debt« was

$23.0 billion at the end of 2024, an increase of $2.1 billion from the 2023

year-end position of $20.9 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 2024 the group held a balance of $16.6 billion (2023 $13.6

billion) issued perpetual subordinated hybrid instruments consisting of

$14.6 billion (2023 $12.1 billion) hybrid bonds and $2.0 billion (2023 $1.5

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

2024 was 43.2% (2023 37.8%). Gearing was 22.7% at the end of 2024 (2023

19.7%). 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 $39.2 billion at 31 December 2024 (2023

$33.0 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.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		317




	Additional disclosures

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 338 and Risk factors on page 65, which describe the 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 2024, the group’s share of third-party finance debt and

lease liabilities of equity-accounted entities was $8.0 billion (2023 $9.9

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 2024, were $655 million (2023 $1,655 million) in respect of

liabilities of joint ventures« and associates« and $585 million (2023 $598

million) in respect of liabilities of other third parties. Of these amounts, $655

million (2023 $1,609 million) of the joint ventures and associates

guarantees relate to borrowings and, for other third-party guarantees, $430

million (2023 $527 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 2024 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	12,520	13,513	26,033
of which is contracted	7,649	5,993	13,642

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 2024 the group had committed to capital

expenditure relating to investments in equity-accounted entities amounting

to $3,976 million. Contracts were in place for $3,451 million of this total.

The following table summarizes the group’s principal contractual

obligations at 31 December 2024, 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	6,892	70,354	77,246
Lease liabilitiesb	3,237	11,031	14,268
Decommissioning liabilitiesc	643	23,967	24,610
Environmental liabilitiesc	349	1,584	1,933
Gulf of America oil spill liabilitiesd	1,137	8,383	9,520
Pensions and other post- employment benefitse	533	13,403	13,936
	12,791	128,722	141,513
Off-balance sheet obligations
Unconditional purchase obligationsf
Crude oil and oil products	61,541	7,094	68,635
Natural gas and LNG	15,350	54,579	69,929
Chemicals and other refinery feedstocks	1,011	1,509	2,520
Power	6,111	14,165	20,276
Utilities	54	393	447
Transportation	2,000	14,538	16,538
Use of facilities and services	3,189	23,918	27,107
	89,256	116,196	205,452
Total	102,047	244,918	346,965

aExpected payments include interest totalling $20,854 million (less than 1 year $2,490 million, more

than 1 year $18,364 million).

bExpected payments include interest totalling $2,268 million (less than 1 year $460 million, more

than 1 year $1,808 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 2025 include purchase commitments existing at 31 December 2024 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 2025 to 2027

worldwide, we are contractually committed to deliver approximately 444

million barrels of oil, 6,277 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.


318		bp Annual Report and Form 20-F 2024

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 2024. 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 activities are located in Abu Dhabi, Angola, Australia,

Indonesia, Trinidad and from 2025, in Mauritania and Senegal. In 2024 our

production was 11Mt of LNG from these assets, of which 4Mt were

marketed 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 23Mttpa. In addition to the long-term

equity and merchant supply portfolio, bp has delivered 14Mtpa in 2024 of

incremental merchant volumes through short and mid-term cargos

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 into the liquid gas markets of Europe, and the 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,

Brazil, the Caribbean, China, Croatia, the Mediterranean, Iberia and north-

west Europe, India, Japan, 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

2024 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.

•On 10 May bp was awarded a licence for two blocks in the central North

Sea, consolidating our position around our Eastern Trough Area Project

(ETAP) central processing facility. The award aligns with our strategic

focus on oil and gas opportunities that can be developed through

established production facilities.

•On 3 September Aker BP announced oil production had started from the

Tyrving field in the Alvheim area (bp 15.9%). Tyrving is operated by Aker

BP (61.26% working interest). The Tyrving development is part of the life

extension of the Alvheim field and is expected to increase production

while reducing both unit costs and emissions. Recoverable resources in

Tyrving are approximately 25 million barrels of oil equivalent (gross).

•On 14 January 2025 Aker BP was awarded interests in 19 licences (of

which it will operate 16) in the North Sea and Norwegian Sea (bp 15.9%).

•During the year an impairment charge of $1 billion was recognized in

respect of certain assets in the North Sea as a result of changes to

reserves and tax assumptions.

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 280 lease blocks in the Gulf of America and operates five

production hubs.

•On 9 February the final investment decision was taken on the Atlantis

Drill Center Expansion, which will be a two well tieback to the Atlantis

facility in the Gulf of America (bp share 56%).

•On 30 July bp made the final investment decision on the Kaskida project

in the deepwater Gulf of America. Kaskida will be bp's sixth hub in the

Gulf of America and is expected to have a production capacity of 80,000

barrels of crude oil per day (bp 100%). Following this decision, bp

entered into agreements with Enbridge Offshore Facilities LLC to

construct, own and operate oil and gas export pipelines to transport oil

from Kaskida to the Green Canyon 19 platform and gas to markets in

Louisiana. bp also entered into agreements with Shell Pipeline Company

LP to transport oil from Green Canyon 19 to markets in Louisiana via a

new build pipeline.

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 1.5 billion boe proved

reserve base at 31 December 2024, predominantly in unconventional

reservoirs (tight gas«, shale gas and shale oil). bpx energy's core assets

span 0.8 million net developed acres with nearly 1,600 operated gross wells

at 31 December 2024. Daily net production averaged 434mboe/d in 2024.

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 April bpx energy successfully brought online 'Checkmate', its third

central processing facility in the Permian Basin. It is a low-emission,

electrified facility that will enable further production growth for bpx

energy in the basin (bp 100% operator).

bp’s onshore US crude oil and product pipelines and related transportation

assets were included in the customers & products segment in 2024.

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 licences in offshore Newfoundland and Labrador, including an

interest in the Equinor-operated Bay du Nord project. bp also holds offshore

exploration licences in the Arctic, where the moratorium has been extended

until 31 December 2028.

In Mexico, bp held 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) in which bp owns 50%. Separate to the above

holdings in Mexico, Hokchi Energy also holds an interest in two other

blocks.

•Formal relinquishment of Block 1 and Block 34 licences is still pending

regulatory approval.

South America

bp has oil and gas activities in Argentina, Brazil and Trinidad and Tobago

and, through PAEG, in Argentina and Bolivia.

In Argentina, the bp and Total (operator) partnership on a 50:50 basis in two

offshore exploration concessions has been relinquished as per regulatory

approval received on 11 July.

In Brazil bp has interests in eight exploration areas across three basins:

•In April the appraisal plan for Alto de Cabo Frio Central block (bp 50%), in

the southern portion of the Campos Basin, was approved by the

regulator.

•In May the Production Sharing Contract for the Tupinamba block,

awarded to bp in 2023 during Brazil´s second Permanent Production

Sharing Offer bid round was executed. bp holds 100% participation

interest.

•In November bp, as operator in the BAR-M-346 block (bp 50%) filed a

request to the regulatory authorities for exemption from the unfulfilled

Minimum Work Program and Contract Termination due to delays in the

environmental licensing process and is pending approval.

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 2.8 million

acres offshore of the east and north-east coast. Facilities include 12

offshore platforms, 2 subsea tiebacks and 2 onshore processing facilities.

Production comprises gas and associated liquids.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		319




	Additional disclosures

bp also holds interests in the Atlantic LNG facility. The total gross capacity

of the LNG trains 2, 3 and 4 is approximately 12Mtpa.

The Atlantic Train 1 plant has not been operational since 2020. The Atlantic

shareholders, bp, Shell and the National Gas Company of Trinidad &

Tobago (NGC), agreed to decouple the Train from the rest of the Atlantic

facility with a view to decommissioning it. The Train has been made safe

and decoupling and decommissioning work scopes are being planned. In

2023 bp, Shell and NGC agreed to and executed the agreements for the

restructuring of the ownership and commercial framework of the Atlantic

LNG facility. The new ownership and commercial structure have been

agreed for Trains 2 and 3 and took effect from 1 October 2024. Train 4 (T4)

contracts expire on 1 May 2027, at which time, T4 will be rolled into the

restructured arrangement. bp’s shareholding averages 43% across the two

companies which own the LNG trains comprising the LNG facility.

•On 24 July bp and its partner the National Gas Company of Trinidad and

Tobago Limited were awarded an exploration and production licence by

the Bolivarian Republic of Venezuela for the development of the Cocuina

gas discovery. Cocuina is the Venezuelan portion of the cross-border

Manakin-Cocuina gas field. bp is operator of the Manakin block which

was discovered in 1998. Manakin declared commerciality in January

2018; however, cross-border discussions had not progressed due to the

impact of US sanctions. In October 2023 the US government eased

sanctions on Venezuela’s oil sector for six months and further extended

for two years until May 2026. The seismic acquisition programme over

the joint Manakin-Cocuina field was successfully completed during

September 2024.

•On 14 August bp announced it had agreed with EOG Resources Trinidad

Limited (EOG) to partner on the Coconut gas development. bp approved

the final investment decision for the project in June. Coconut is a 50/50

joint venture with EOG as operator. The first gas is expected in 2027.

•On 2 September bp announced it has entered into an agreement with

Perenco T&T to sell four mature offshore gas fields and associated

production facilities in Trinidad & Tobago (Immortelle, Flamboyant,

Amherstia and Cashima). The deal also included undeveloped resources

from the Parang area and completed in December 2024.

•On 19 November bp entered into a Production Sharing Contract (PSC)

with the Government of the Republic of Trinidad and Tobago for Block

NCMA 2, located approximately 30 miles off Trinidad’s north coast.

Seismic reprocessing activity is planned during 2025.

•Cypre, bp’s third subsea gas development in Trinidad and Tobago,

started drilling in 2024 with first gas expected in 2025. The project is

expected to have seven wells and be tied back to the Juniper platform.

•In September construction of the Ocelot project, which is a 6-inch liquids

pipeline connecting Beachfield to terminal operations at Galeota Point,

was completed.

•The Mento (bp 50%/EOG 50% and operator) platform has sailed away,

and installation was completed before the end of 2024. First gas is

expected in the second quarter of 2025.

Africa

bp’s oil and gas activities in Africa are located in Angola, Egypt, Libya,

Mauritania and Senegal.

In Angola, bp and Eni each own a 50% interest in the Azule Energy joint

venture. Azule Energy 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 December Azule Energy completed acquisition of a 42.5% interest in

exploration block 2914A (PEL85), Orange Basin, offshore Namibia.

•Azule Energy Finance Plc, a financing vehicle of Azule Energy Holdings

Limited, has issued unsecured notes in an aggregate principal amount

of $1,200 million. The notes have a term of 5 years and a coupon of

8.125% per annum.

In Egypt, bp holds an investment in West 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.

•On 14 February bp and ADNOC announced the formation of a new joint

venture in Egypt. In December bp completed the contribution of the

North Damietta and Shorouk concessions, containing the producing

Atoll and Zohr fields, and three exploration concessions in Egypt to the

newly created joint venture Arcius Energy Limited (bp 51%, XRG 49%).

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. On 26 October drilling

commenced for the first exploration well in the Onshore Ghadames

basin.

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.

•On 29 April the BirAllah gas resource exploration licence in which bp

held a 62% participating interest expired in accordance with the terms of

the applicable Production Sharing Contract, following the end of sub-

phase 2.

•On 2 January 2025 bp announced that first gas had begun flowing from

the GTA wells on 31 December 2024.

•In 2024 an impairment charge of $1.5 billion was recognized in respect

of certain assets in the region due to increased future forecast

expenditure.

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 Azerbaijan, bp operates two PSAs, Azeri-Chirag-Gunashli (ACG) (bp

30.37%) and Shah Deniz (bp 29.99%) and also holds a number of other

exploration leases.

•On 16 April bp, as operator of the Azeri-Chirag-Gunashli (ACG) field,

announced the start-up of oil production from the new Azeri Central East

(ACE) platform as part of the giant ACG field development, which is the

first remotely operated offshore platform in the Caspian.

•On 4 June a new gas sales agreement (GSA) was signed with the

Turkish state-owned company BOTAS covering the period 2025-2030.

This is the fourth GSA between Shah Deniz and BOTAS since the start of

production from the field in 2006.

•On 19 July bp and SOCAR signed a protocol to extend the Shafag-

Asiman exploration period until the end of June 2025 to allow for bp and

SOCAR to continue discussions on the terms of any potential follow-on

exploration activity.

•On 20 September the ACG joint venture partners announced the signing

of an addendum to the existing PSA which enables the parties to

progress the exploration, appraisal, development of and production from

the non-associated natural gas reservoirs of the ACG field (bp operator

with 30.37% equity).

•On 20 September bp and the State Oil Company of the Azerbaijan

Republic (SOCAR) signed a memorandum of understanding announcing

the parties’ intention for bp to join SOCAR in two exploration and

development blocks in the Azerbaijan sector of the Caspian Sea. The

first block is the Karabagh oil field, and the second block is the Ashrafi –

Dan Ulduzu – Aypara area, containing a number of existing discoveries

and prospective structures.

Naftiran Intertrade Co Ltd (NICO), a subsidiary of the National Iranian Oil

Company, holds a 10% interest in the Shah Deniz joint venture. For

information on the exclusion of this project from EU and US trade

sanctions, see International trade sanctions on page 334.

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


320		bp Annual Report and Form 20-F 2024

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 2024 of 612mboe/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, with an average throughput of 2mboe/d in

2024. 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 product.

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 2024 of 389mboe/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 2024 was 263mboe/d.

bp has a 20% interest in TAP, which takes gas through Greece and Albania

into Italy. The current capacity of TAP is 167mboe/d and the total average

throughout in 2024 was 177mboe/d. TAP throughput exceeded capacity

during 2024 due to high flow tests taking place during the year.

•On 16 September bp announced it had agreed for Apollo-managed

funds to purchase a non-controlling stake in BP Pipelines TAP Limited,

the bp subsidiary that holds a 20% share in TAP. bp remains the

controlling shareholder of BP Pipelines TAP Limited.

In Oman, bp operates Block 61, the largest tight gas development in the

Middle East (bp 40%). bp also has a 50% interest in Block 77 with Eni

(operator) in which an exploration well was spudded in October 2023.

Currently the prospect is under evaluation.

In Abu Dhabi, bp holds a 10% interest in the ADNOC Onshore concession.

We also have a 10% equity shareholding in ADNOC LNG and a 10%

shareholding in the shipping company NGSCO. ADNOC LNG supplied

approximately 5.9Mt of LNG (0.8bcfe/d regasified) in 2024. bp’s interest in

the ADNOC Onshore concession expires at the end of 2054.

•In July bp made the final investment decision to take a 10% interest in

the planned 9.6mmtpa Ruwais LNG project, subject to receipt of

appropriate merger clearances.

In 2016 bp signed an enhanced technical service agreement for the

duration of ten years for south and east Kuwait conventional oilfields, which

includes the Burgan field, with Kuwait Oil Company.

In India, we have a participating interest in two oil and gas PSAs (KG D6

33.33% and NEC25 33.33%), and two oil and gas blocks under a revenue

sharing contract (KG-UDWHP-2018/1 40% and KG-UDWHP-2022/1 40%), all

operated by Reliance Industries Limited (RIL). We also have a 50% stake in

India Gas Solutions Private Limited, a joint venture with RIL, for the sourcing

and marketing of gas in India.

•In February 2025 bp and Oil and Natural Gas Corporation Limited

(ONGC) have signed agreement under which bp will serve as the

technical services provider for ONGC’s Mumbai High field, India's largest

oil and gas field. The scope of this bid award is to review the field

performance and identify improvements in reservoir, facilities and wells

to enhance production from the Mumbai High field over a 10-year

contract period.

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.

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.

•On 25 February 2025 bp reached agreement on all contractual terms

with the government of the Republic of Iraq to invest in several giant oil

fields in Kirkuk providing for the rehabilitation and redevelopment of the

fields, spanning oil, gas, power and water with potential for investment

in exploration. The agreement is subject to final governmental

ratification.

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 five LNG trains in operation, and also supplies domestic gas

into the Western Australia market. bp’s net share of the capacity of NWS

LNG trains 1-5 is 2.67Mt (15.78% of 16.9mtpa gross) of LNG per year. This

will be reduced in 2025 as one LNG train was taken offline in late 2024. bp

is also one of four participants in the Browse LNG venture (bp 44.33%).

•In December Woodside and Chevron agreed to an asset swap under

which Woodside will acquire Chevron’s interest in the North West Shelf

(NWS) Project, the NWS Oil Project and the Angel Carbon Capture and

Storage (CCS) Project. This will reduce the number of NWS venture

partners to five upon expected completion in 2026.

bp also has a 50% interest in the WA-541 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.

In Papua Barat, Eastern Indonesia, bp operates the Tangguh LNG plant (bp

40.22%). The plant consists of 3 trains with total production capacity of

11.4Mtpa. The Tangguh asset comprises thirty 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.

•On 21 November bp, on behalf of the Tangguh production sharing

contract partners, announced a final investment decision on the $7

billion Tangguh Ubadari, CCUS, Compression project (UCC), which has

the potential to unlock around 3 trillion cubic feet of additional gas

resources in Indonesia to help meet growing energy demand in Asia.

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


« See glossary on page 351		bp Annual Report and Form 20-F 2024		321




	Additional disclosures

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 2024 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

19% (17% for 2023 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 2024 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 2024 we progressed 402mmboe of proved undeveloped reserves

(325mmboe 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 $11,541 million in 2024 ($7,953 million for

subsidiaries and $3,588 million for equity-accounted entities). Of the $7,953

million of total development expenditure for our subsidiaries, approximately

$2,800 million was used for development activity to progress proved

undeveloped reserves to proved developed. Of the $3,588 million

development expenditure for our equity-accounted entities, approximately

$1,100 million was used for development activity to progress proved

undeveloped reserves to proved developed. The major areas with

progressed volumes in 2024 were the US, Azerbaijan, Southern Cone and

Middle East.

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 and revisions due to field

performance, and net negative revisions driven by price and well results.

The net revisions to previous estimates across only our subsidiaries include

net positive revisions driven by revisions to activity plans and net negative

revisions driven by price, field performance and well results. 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 2024	2,558
Revisions of previous estimates	(5)
Price	(100)
Revision of future activity plans	130
Field performance	1
Well results	(37)
Improved recovery	4
Discoveries and extensions	237
Purchases	13
Sales	(19)
Total in year proved undeveloped reserves changes	229
Proved developed reserves reclassified as undeveloped	3
Progressed to proved developed reserves by development activities (e.g. drilling/completion)	(402)
Proved undeveloped reserves at 31 December 2024	2,387


Subsidiaries only	volumes in mmboea
Proved undeveloped reserves at 1 January 2024	2,006
Revisions of previous estimates	18
Price	(99)
Revision of future activity plans	152
Field performance	(3)
Well results	(33)
Improved recovery	2
Discoveries and extensions	180
Purchases	6
Sales	(15)
Total in year proved undeveloped reserves changes	191
Proved developed reserves reclassified as undeveloped	2
Progressed to proved developed reserves by development activities (e.g. drilling/completion)	(325)
Proved undeveloped reserves at 31 December 2024	1,875

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,


322		bp Annual Report and Form 20-F 2024

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

four years managing the governance and compliance. He is a past

Chairman of the Society of Petroleum Engineers (Russia & Caspian) and a

member of the United Nations Economic Commission for Europe Expert

Group on Resource Management.

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

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 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.

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 2024, 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 2024. 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 2024 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 2024 were

held through joint operations« (94% in 2023), and 23% of the proved

reserves were held through such joint operations where we were not the

operator (25% in 2023).

Estimated net proved reserves of crude oil at 31 December

2024abc


		million barrels
	Developed	Undeveloped	Total
UK	104	63	167
US	653	472	1,125
Rest of North America	—	—	—
South Americad	1	4	5
Africa	1	—	1
Rest of Asia	716	305	1,021
Australasia	9	1	10
Subsidiaries	1,483	846	2,329
Equity-accounted entities	558	339	896
Total	2,041	1,184	3,225

Estimated net proved reserves of natural gas liquids at

31 December 2024ab


		million barrels
	Developed	Undeveloped	Total
UK	2	—	3
US	202	246	447
Rest of North America	—	—	—
South America	1	—	1
Africa	—	—	—
Rest of Asia	—	—	—
Australasia	1	—	1
Subsidiaries	206	246	452
Equity-accounted entities	16	6	22
Total	222	252	474

Estimated net proved reserves of liquidsd«


		million barrels
	Developed	Undeveloped	Total
Subsidiaries	1,689	1,092	2,781
Equity-accounted entities	573	344	918
Total	2,263	1,436	3,699


« See glossary on page 351		bp Annual Report and Form 20-F 2024		323




	Additional disclosures

Estimated net proved reserves of natural gas at 31 December

2024ab


	billion cubic feet
	Developed	Undeveloped	Total
UK	162	29	190
US	2,600	2,412	5,012
Rest of North America	—	—	—
South Americae	379	350	730
Africa	161	—	161
Rest of Asia	3,026	1,320	4,346
Australasia	1,254	431	1,685
Subsidiaries	7,582	4,542	12,124
Equity-accounted entities	1,686	976	2,662
Total	9,268	5,518	14,786

Estimated net proved reserves on an oil equivalent basis


	million barrels of oil equivalent
	Developed	Undeveloped	Total
Subsidiaries	2,997	1,875	4,871
Equity-accounted entities	864	513	1,377
Total	3,860	2,387	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, 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 2024 marker prices used were Brent $81.171/bbl (2023 $83.27/bbl and 2022 $101.24/bbl)

and Henry Hub $2.065/mmBtu (2023 $2.58/mmBtu and 2022 $6.19/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 219 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 2024, on an oil

equivalent basis including equity-accounted entities, decreased by 8%

compared with 31 December 2023 (8% decrease for subsidiaries and 4%

decrease for equity-accounted entities). Natural gas decreased by 15%

(19% decrease for subsidiaries and 5% increase for equity-accounted

entities).

There was a net decrease from acquisitions and disposals of 72mmboe

within our US, Trinidad and North Africa subsidiaries.

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 2024,

the proved reserves replacement ratio excluding acquisitions and disposals

was 50% (47% in 2023 and 20% in 2022) for subsidiaries and equity-

accounted entities, 52% for subsidiaries alone and 37% for equity-

accounted entities alone. There was a net decrease (96mmboe) of reserves

due to lower gas and oil prices, primarily in our US subsidiaries, partly offset

by an increase in reserves in some of our PSAs in Azerbaijan.

In 2024 net additions to the group’s proved reserves (excluding production,

sales and purchases of reserves-in-place) amounted to 441mmboe

(391mmboe for subsidiaries and 50mmboe 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 and the Middle East. The principal

reserves additions in our equity-accounted entities were in PAEG.

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 2024 proved

reserves ratio, that ratio would remain the same. Removal of the same

reserves from bp’s 2024 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.

25% of our proved reserves are associated with PSAs. The countries in

which we produced under PSAs in 2024 were Angola, Azerbaijan, Egypt,

India, Indonesia, Mexico and Oman. In addition, the technical service

contract (TSC)« governing our investment in the Rumaila field in Iraq

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 230.


324		bp Annual Report and Form 20-F 2024

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
	2024	2023	2022	2024	2023	2022
Subsidiaries
UK	70	74	80	4	5	5
Total Europe	70	74	80	4	5	5
Lower 48 onshorec	86	69	71	84	66	56
Gulf of America deepwater	290	266	225	23	22	19
Total US	376	335	296	107	88	76
Canadacd	—	—	15	—	—	—
Total Rest of North America	—	—	15	—	—	—
Total North America	376	335	311	107	88	76
Trinidad and Tobago	4	4	5	4	4	4
Total South America	4	4	5	4	4	4
Angolac	—	—	49	—	—	—
Egypt	19	28	28	1	1	—
Algeriac	—	1	5	—	1	6
Total Africa	19	29	83	1	2	6
Abu Dhabi	202	197	195	—	—	—
Azerbaijan	66	70	73	—	—	—
Iraqc	—	—	15	—	—	—
Indiag	6	4	—	—	—	—
Oman	23	22	24	—	—	—
Total Rest of Asia	297	293	307	—	—	—
Total Asia	297	293	307	—	—	—
Australiac	7	8	11	2	2	2
Eastern Indonesia	2	2	1	—	—	—
Total Australasia	9	10	12	2	2	2
Total subsidiaries	775	745	797	117	100	93
Equity-accounted entities (bp share)
Rosnefte (Russia, Egypt)	—	—	144	—	—	—
Argentina	52	51	51	1	1	1
Mexico	3	5	6	—	—	—
Bolivia	1	1	2	—	—	—
Egypt	—	—	—	2	2	3
Norway	58	60	47	2	3	2
Russia	—	—	7	—	—	—
Iraq	69	62	25	—	—	—
Angola	82	82	33	4	4	2
Total equity-accounted entities	266	261	314	9	9	9
Total subsidiaries and equity-accounted entitiesf	1,041	1,006	1,111	126	109	102

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. In 2022, bp disposed of its interests in Angola, its interest in Sunrise Oil Sands in

Canada, its interest in Rumaila in Iraq, and certain Lower 48 onshore interests in the US and certain offshore interests in Australia.

dAll of the production from Canada in subsidiaries is bitumen.

e2022 reflects bp's estimated share of Rosneft production for the period 1 January to 27 February, averaged over the year (see Financial statements – Note 1). Includes production in respect of the non-

controlling interest in Rosneft, including production held through bp’s interests in Russia other than Rosneft.

fIncludes 2 net mboe/d of NGLs from processing plants in which bp has an interest (2023 2mboe/d and 2022 2mboe/d).

g2023 restated, previously reported in NGLs.

Because of rounding, some totals may not agree exactly with the sum of their component parts.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		325




	Additional disclosures

bp’s net production by country – natural gas


	million cubic feet per day
	bp net share of productiona
	2024	2023	2022
Subsidiaries
UK	197	247	271
Total Europe	197	247	271
Lower 48 onshoreb	1,530	1,338	1,148
Gulf of America deepwater	160	149	143
Total US	1,690	1,486	1,291
Canada	—	—	—
Total Rest of North America	—	—	—
Total North America	1,690	1,486	1,291
Trinidad and Tobagob	1,145	1,191	1,276
Total South America	1,145	1,191	1,276
Egyptb	904	1,220	1,272
Algeriab	—	16	81
Total Africa	904	1,236	1,353
Azerbaijan	748	714	670
India	303	283	216
Oman	604	582	599
Total Rest of Asia	1,655	1,578	1,485
Total Asia	1,655	1,578	1,485
Australia	276	301	331
Eastern Indonesia	606	473	421
Total Australasia	882	774	752
Total subsidiariesc	6,474	6,512	6,428
Equity-accounted entities (bp share)
Rosneftd (Russia, Canada, Egypt, Vietnam)	—	—	238
Argentina	267	247	238
Bolivia	33	50	56
Mexico	1	2	2
Egypt	9	—	—
Norway	55	58	66
Russia	—	—	10
Angola	76	74	64
Total equity-accounted entitiesc	440	432	674
Total subsidiaries and equity-accounted entities	6,914	6,944	7,101

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 Egypt and Trinidad and Tobago. In 2023, bp disposed of its interests in Algeria and certain Lower 48 onshore interests in the US. In 2022, bp disposed of certain

Lower 48 onshore interests in the US.

cNatural 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.

d2022 reflects bp's estimated share of Rosneft production for the period 1 January to 27 February, averaged over the year (see Financial statements – Note 1). Includes production in respect of the non-

controlling interest in Rosneft, including production held through bp’s interests in Russia other than Rosneft.

Because of rounding, some totals may not agree exactly with the sum of their component parts.


326		bp Annual Report and Form 20-F 2024

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			Russia	Rest of Asia
Subsidiaries
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
2022
Crude oilb	102.54	—	90.05	84.88	99.09	102.00	—	98.74	86.11	95.70
Natural gas liquids	60.41	—	31.72	—	60.55	54.78	—	—	54.20	37.00
Gas	33.45	—	5.61	3.68	7.65	5.21	—	11.81	12.33	9.29
Equity-accounted entitiesc
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 liquidsd	—	—	—	—	30.95	42.89	N/A	—	—	36.70
Gas	—	12.80	—	—	3.66	—	—	—	—	5.15
2022
Crude oilb	—	71.14	—	—	78.05	86.73	102.84	90.16	—	90.18
Natural gas liquidsd	—	—	—	—	46.64	—	N/A	—	—	46.64
Gas	—	24.23	—	—	4.75	—	4.35	—	—	6.91

Average production cost per unit of productione


									$ per unit of production
	Europe		North America		South America	Africa	Asia		Australasia	Total group average
	UK	Rest of Europe	US	Rest of North America			Russia	Rest of Asia
Subsidiaries
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
2022	10.36	—	9.70	15.36	3.92	5.02	—	3.52	2.04	6.07
Equity-accounted entities
2024	—	6.16	—	—	20.40	18.30	—	22.88	—	17.37
2023	—	6.22	—	—	17.87	15.46	—	16.41	—	14.38
2022	—	6.01	—	—	15.55	21.01	7.39	20.81	—	11.47

aUnits of production are barrels for liquids and thousands of cubic feet for gas. Realizations include transfers between businesses, except in the case of Russia.

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.

dNatural gas liquids for Russia are included in crude oil.

eUnits of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		327




	Additional disclosures

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
	2024	2023	2022
RC profit (loss) before interest and tax for customers & products	(1,560)	4,230	8,869
Less: Adjusting items gains (charges)	(4,077)	(2,183)	(1,920)
Underlying RC profit before interest and tax for customers & products	2,517	6,413	10,789
By business:
customers – convenience & mobility	2,584	2,644	2,966
Castrol – included in customers	831	730	700
products – refining & trading	(67)	3,769	7,823

Add back: Depreciation, depletion and amortization	3,957	3,548	2,870
By business:
customers – convenience & mobility	2,135	1,736	1,286
Castrol – included in customers	176	167	153
products – refining & trading	1,822	1,812	1,584

Adjusted EBITDA for customers & products	6,474	9,961	13,659
By business:
customers – convenience & mobility	4,719	4,380	4,252
Castrol – included in customers	1,007	897	853
products – refining & trading	1,755	5,581	9,407

Sales volume


			thousand barrels per day
	2024	2023	2022
Marketing salesa	2,714	2,718	2,613
Trading/supply salesb	373	358	350
Total refined product sales	3,087	3,076	2,963
Crude oilc	86	102	184
Total	3,173	3,178	3,147

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 2024 includes 52 thousand barrels per day (2023

68 thousand barrels per day and 2022 67 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
	2024	2023	2022
US	8,500	8,200	7,750
Europe	7,750	8,050	8,150
Rest of world	4,950	4,850	4,750
Total	21,200	21,100	20,650

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
	2024	2023	2022
US	612	662	678
Europe	782	749	804
Rest of world	—	—	22
Total	1,394	1,411	1,504

			%
Refining availability«	94.3	96.1	94.5

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.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		329




	Additional disclosures

Environmental expenditure


			$ million
	2024	2023	2022
Operating expenditure	575	524	416
Capital expenditure	393	329	224
Clean-ups	20	23	16
Additions to environmental remediation provision	254	228	502
Increase (decrease) in decommissioning provision	942	920	1,248

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 $575 million in 2024 (2023 $524

million) showed an overall increase of 10%, largely due to increased

expenditure in BP Products North America.

Environmental capital expenditure of $393 million in 2024 (2023 $329

million) showed an overall increase of 19%, largely due to increased

expenditure for BP Products North America.

Clean-up costs were $20 million in 2024 (2023 $23 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 2024 arising from new and acquired sites was $24 million

(2023 $37 million and 2022 $67 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 2024, the net increase in the decommissioning provision was primarily

due to recognition of additional provisions 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 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


330		bp Annual Report and Form 20-F 2024

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.

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 Sustainability – Net zero aims on page 48.

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 increased 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.

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. The impact of the IRA both on bp’s

businesses and more widely on the US economy is likely to depend on

various factors that are currently uncertain, including the implementation of

the incentive programmes by the US authorities through the Department of

Energy (DOE), the Federal Aviation Administration (FAA), and other

agencies, as well as regulatory initiatives at the federal, state and local

levels.

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; bp and its co-applicants executed

award agreements with the DOE, and bp is currently working with FAA on

its award agreement. Regulatory uncertainty due to a change in U.S.

administrations may significantly affect the implementation of IRA

programmes.

Methane

In November 2023, 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 are focused on methane 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.

The IRA requires 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. The WEC is $900/

metric ton of methane emissions occurring in 2024, $1,200/metric ton for

emissions occurring in 2025, and $1,500/metric ton for emissions

occurring in 2026 and thereafter. In November 2024, EPA promulgated

regulations to implement the WEC provisions of the IRA.

Climate Resilience Funds

Several U.S. states, including New York, New Jersey and Vermont have

enacted laws seeking recovery from historical greenhouse gas emitters to


« See glossary on page 351		bp Annual Report and Form 20-F 2024		331




	Additional disclosures

create climate resilience funds to address climate change impacts by

financing infrastructure upgrades, disaster preparation, and other resilience

projects. Other states, including California, Maryland and Massachusetts,

are considering similar legislation. The extent and cost of to us 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.

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 for cellulosic biofuel, biomass-based

diesel, advanced biofuel, and total renewable fuel for 2023-2025. Lawsuits

were filed challenging this final rule and are ongoing.

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,

certain state initiatives 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 2021, Washington enacted state-wide carbon cap and invest

legislation and a Clean Fuels Program (similar to California’s LCFS) and

finalized regulations implementing both of those programmes in 2022.

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.

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.

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.

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 2020, California

entered into voluntary framework agreements with several carmakers to

meet more demanding vehicle emissions standards in California through

MY 2026.

California Advanced Clean Cars Program

California’s Advanced Clean Cars (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 NTSA 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

U.S. Court of Appeals upheld EPA’s decision to restore the California waiver,

although that court ruling has been appealed to the United States Supreme

Court and is pending.

In 2022, California finalized the next generation of its GHG and ZEV

standards (referred to as 'ACC II'). The 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. These regulations may impact bp’s

product mix and demand for particular products.

California Advanced Clean Trucks Program

In 2023, EPA granted California’s request for a waiver of federal preemption

covering, in part, its Advanced Clean Trucks Program, which mandates

increasing quantities of ZEV sales for medium- and heavy-duty vehicles in

the state. Legal challenges to that decision have been filed and are pending.

These and other initiatives to reduce GHG emissions 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 compared to 1990 levels. To achieve this 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.

Once fully adopted and implemented, this would inter alia lead to higher

shares of renewables across all sectors (including transport), a reduced

number of GHG emission allowances under the EU ETS, and a target of

zero gramme of CO2 per km for new passenger cars by 2035. The EU also

adopted measures to reduce methane emissions.

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


332		bp Annual Report and Form 20-F 2024

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 December 2023, the UK ETS Authority published two consultations. One

covers a review of the UK ETS markets policy and the other relates to a

review of free allocation methodology for the stationary sectors under the

UK ETS to better target those most at risk of carbon leakage.

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. For now, the National

ETS participants are limited to the key emission entities identified by each

provincial-level government authority and approved by the Ministry for

Ecology and Environment of China. bp is not participating in the National

ETS. On 9 September 2024, the Ministry for Ecology and Environment of

China 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 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 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.

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 329 and for

a discussion of legal proceedings, see page 218.

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 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 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.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		333




	Additional disclosures

European Union

•The Industrial Emissions Directive (IED) 2010 provides the framework

for granting permits for major industrial sites. A recently agreed revision

of the IED could, once formally adopted and implemented, potentially set

more stringent permitting requirements, and lead to a further tightening

of emission limit values.

•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 implementation in the EU member states is still

ongoing, planned to be finalised 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.

•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. Disclosure requirements will

be phased in from 2025, in respect of the 2024 financial year.

•The Corporate Sustainability Due Diligence Directive (CSDDD) entered

into force in July 2024 and requires certain EU and non-EU companies

to conduct due diligence on human rights and environmental risks,

adopt a transition plan aligned with the Paris Agreement, and comply

with enforcement by EU authorities from July 2027.

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. That 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 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, along with the Additional Protocol published in

2012, sets environmental quality standards for the discharge of chemicals

to the marine environment. Mauritania and Senegal are both signatories to

the Abidjan Convention. bp is currently constructing the offshore facilities

to include produced water management systems to meet the

environmental quality standards for our future 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, the Hazardous and Noxious Substance (HNS)

Protocol 2010 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. As at 31 December

2023, 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. This

global cap does not alter the lower 0.1% limits that apply in the sulphur

oxides Emissions Control Areas established by the IMO.

•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 over 5,000

gross tonnage calling at EU ports regardless of a vessel’s flag.


334		bp Annual Report and Form 20-F 2024

•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% 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.

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 2024, 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. Shah Deniz, SCPC and AGSC continue in

operation as they were excluded from the application of US sanctions and

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).

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. OFAC has issued a licence in relation to these

arrangements which expires on 15 April 2026.

Following the imposition in 2011 of further US and EU sanctions against

Syria, bp terminated all sales of crude oil and petroleum products into Syria,

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; 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, except

deliveries of LNG from Russian sources under a small number of contracts

predating the Russia and Ukraine conflict in compliance with all applicable

sanctions. bp has also 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. See page 173 for

further information in relation to bp’s 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 2024, 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.

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.

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 2024 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 – Notes

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 Note 17.

In the ordinary course of its business, the group enters into transactions


« See glossary on page 351		bp Annual Report and Form 20-F 2024		335




	Additional disclosures

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 2024 to 14 February 2025.

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 75, 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 at least annually. 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 80-110 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 82). 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.

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, SVP accounting, reporting and control 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.


336		bp Annual Report and Form 20-F 2024

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 June 2024. In

addition, bp has adopted a code of ethics as described above for the chief

executive officer, chief financial officer, SVP accounting, reporting and

control 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 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 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 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 2024 fiscal year, management conducted an

assessment of the effectiveness of internal control over financial reporting

in accordance with the criteria in the UK Financial Reporting Council’s

Guidance on Risk Management, Internal Control and Related Financial and

Business Reporting relating to internal control over financial reporting.

Based on this assessment, management has determined that bp’s internal

control over financial reporting as of 31 December 2024 was effective.

Management’s assessment of the effectiveness of internal control over

financial reporting excluded bp bioenergy (formerly called bp Bunge

Bioenergia) and Lightsource bp which were acquired on 1 October 2024,

and 24 October 2024, respectively. bp bioenergy’s financial statement line

items comprise 2.1% and 0.9% of net and total assets respectively, 0.3% of

sales and other operating revenues, and (4.5)% of profit (loss) for the year

of the consolidated financial statement amounts as of and for the year

ended 31 December 2024. Lightsource bp’s financial statement line items

comprise 6.3% and 2.4% of net and total assets respectively, 0.1% of sales

and other operating revenues, and (5.7)% of profit (loss) for the year of the

consolidated financial statement amounts as of and for the year ended 31

December 2024. These exclusions are in accordance with the general

guidance issued by the SEC that an assessment of a recent business

combination may be omitted from managements report on internal control

over financial reporting in the first year of consolidation.

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 2024 has been audited by Deloitte

LLP, an independent registered public accounting firm, as stated in their

report appearing on page 139 of bp Annual Report and Form 20-F 2024.

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 2024, 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 80.

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 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,


« See glossary on page 351		bp Annual Report and Form 20-F 2024		337




	Additional disclosures

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 (pages

79-67).

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 SVP accounting, reporting

and control, 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

2022, when it was updated to remove restrictions on EY following bp's

announcement on 27 February 2022 of its intention to exit its interests in

Rosneft and capture additional detail for the processes applicable to

separately listed bp entities.

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 audit committee report on page 82

for details of fees for services provided by the auditor.

Additional Directors’ report disclosures

This section of bp Annual Report and Form 20-F 2024 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 2024. During the year, a review of the terms

and scope of the policy was undertaken as part of the annual renewal.

Although their 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 61, Liquidity and capital resources on page 316 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 171 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 77, 78 and 79.

The disclosures concerning policies in relation to the employment of

disabled persons and employee involvement are included in Sustainability –

our people on page 58.

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 78 and 79.

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


338		bp Annual Report and Form 20-F 2024

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 59.

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 40-41.

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	171
(2), (3)	Not applicable
(4), (5) Waiver of director emoluments	Not applicable
(6) – (10)	Not applicable
(11), (12) Dividend waivers	337
(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), Chief

executive officer’s letter (page 5),the Strategic report (inside cover and

pages 1-68), Additional disclosures (pages 311-339) and Shareholder

information (pages 341-350),including but not limited to statements under

the headings ‘Energy Outlook’, ‘Our strategy’, ‘Consistency with the Paris

goals’, ‘Our business model’, ‘Our financial frame’, ‘2025 guidance’ ‘Outlook

for 2025’, ‘Our investment process’ and ‘2025 shareholder calendar’ and

including but not limited to statements regarding: plans and expectations

relating to business, financial performance, results of operations, cash flow,

allocation of capital expenditure and bp’s ability to maintain a robust cash

position; 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),

working capital, operating cash flow (and its ability to cover capital

expenditure and the dividend), return on average capital employed, liquidity,

capital discipline, credit rating, future shareholder distributions including

future dividend payments and share buybacks, amount or timing of

payments related to divestments and other proceeds, net debt, use of

proceeds and progress towards our cost saving targets; plans and

expectations regarding bp’s 2025 targets, 2025 guidance (including with

respect to reported and underlying upstream production, 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), 2030 aims, 2050 or sooner net zero aims; plan

and expectations regarding bp’s engagement plans and programs and their

impact on bp’s ability to meet its aims, targets and strategic objectives;

plans and expectations regarding bp’s primary targets (including adjusted

free cash flow growth, group ROACE, structural cost reduction, net debt)

and reporting of bp’s progress towards those targets; plans and

expectations regarding the impact on underlying performance of bp’s

comprehensive February update; plans and expectations for growth in bp’s

customers businesses, products refining margins, underlying performance,

improvement plans, refinery turnaround activity plans and expectations

regarding interest rate reductions during 2025; 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, oil and gas production targets, growth in underlying production,

divestment plans, and oil and gas resources and reserves; plans and

expectations regarding underlying replacement cost profit before interest,

tax, depreciation and amortization, ROACE, adjusted EBITDA and adjusted

EBIDA per share; plans and expectations regarding bp’s convenience and

mobility business, including earnings and the development of EV charging;

plans and expectations regarding bp’s ability to make focused high-return

investments in aviation and their impact; plans and expectations for the

timing of bp’s energy efficiency reviews and their outcomes; plans and

expectations regarding renewable power, including plans regarding

renewable gas, wind and solar projects, green and blue hydrogen costs and

production and EV charging; plans and expectations regarding carbon

capture and storage; plans and expectations regarding bp’s investments in

resilient hydrocarbons; bp’s plans and expectations related to the energy

transition (including its scenario analysis), climate change, sustainability

(including bp’s sustainability aims), greenhouse gas emissions, and

management, decarbonization, and net zero aims; 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, JERA Nex bp, the Northern Endurance Partnership

projects, the Arcius Energy joint venture, the new ADNOC-operated LNG

facility in Abu Dhabi, the long-term LNG supply agreement with KOGAS, the

Kaskida project, the Coconut gas development, the Tangguh UCC project,

the Northern Endurance Partnership, Net Zero Teesside Power, Cypre, the

Tyrving development, projects in the North Sea and Norwegian Sea, the

Lingen Green Hydrogen project, the Atlantis Drill Center Expansion, bp's

Castellón refinery, the Kirkuk project, the deal with Simon Property Group,

the Greater Tortue Ahmeyim project, the North West Shelf project and the

Mento platform); plans and expectations regarding the timing of the sale of

bp’s mobility and convenience and bp pulse businesses in the Netherlands

and bp Wind Energy; plans regarding transformation of the Gelsenkirchen

refinery site; plans and expectations in relation to the strategic review of

Castrol; plans and expectations in relation to Lightsource bp; 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, expected improved

downstream performance and returns; plans and expectations regarding

the growth of bp’s European gas and power presence; plans and


« See glossary on page 351		bp Annual Report and Form 20-F 2024		339




	Additional disclosures

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; plans and

expectations relating to a re-tender of external audit services; expectations

related to changes laws, regulations and policies; plans and expectations

regarding bp’s shareholder calendar; and plans regarding seismic

reprocessing activity.

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 65). 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.


342		bp Annual Report and Form 20-F 2024

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 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 383 Madison Avenue, Floor 11,

New York, NY, 10179, 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’s ordinary shares are also traded in the form of a global

depositary certificate representing the company’s ordinary shares on the

Frankfurt Stock Exchange. The company delisted from the Hamburg and

Düsseldorf Stock Exchanges on 20 December 2024 and announced its

intention to delist from the Frankfurt Stock Exchange on 18 April 2024.

On 14 February 2025, 698,589,844 ADSs (equivalent to approximately

4,191,539,064 ordinary shares or some 26.19% of the total issued share

capital, excluding shares held in treasury) were outstanding and were held

by approximately 58,929 ADS holders. Of these, about 58,209 had

registered addresses in the US at that date. One of the registered holders of

ADSs represents approximately 1,371,412 underlying holders.

On 14 February 2025, there were approximately 192,951 ordinary

shareholders. Of these shareholders, around 1,464 had registered

addresses in the US and held a total of some 3,840,494 ordinary shares. On

14 February 2025, there were approximately 1,074 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 the

three business days prior to 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 2021

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 65 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 316.

The quarterly dividend which is expected to be paid on 28 March 2025 in

respect of the fourth quarter 2024 is 8.000 cents per ordinary share

($0.48000 per American Depositary Share (ADS)). The corresponding

amount in sterling will be announced on 17 March 2025.

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
2020	UK pence	48.94	50.05	24.26	23.50	146.75
2020	US cents	63.00	63.00	31.50	31.50	189.00
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
2022	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
2023	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
2024	US cents	43.62	43.62	48.00	48.00	183.24

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 agreement relating to bp ADSs

and any related agreement will be performed in accordance with its terms.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		343




	Shareholder information

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 2024/25) after taking into account other sources of income, no

UK tax will be payable on their dividend income.

For 2024/25 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 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 2024/25, the revised rates are as follows:


344		bp Annual Report and Form 20-F 2024

Gains up until 29 October 2024, 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 2024/25), the rate of Capital Gains Tax will

be 10%. For gains (and any parts of gains) above that limit the rate will be

20%.

Gains from 30 October 2024 onwards, 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 2024/25), 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 2024/25, 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.

31 December 2024


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	51,042	26.34	0.02
201-1,000	62,834	32.42	0.21
1,001-10,000	69,939	36.09	1.36
10,001-100,000	8,749	4.51	1.12
100,001-1,000,000	677	0.35	1.50
Over 1,000,000a	555	0.29	95.79
Totals	193,796	100	100

aIncludes JPMorgan Chase Bank, N.A. holding 25.92% 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.

31 December 2024a


Range of holdings	Number of ADS holders	Percentage of total ADS holders	Percentage of total ADSs
1-200	35,241	59.39	0.18
201-1,000	15,660	26.39	0.71
1,001-10,000	8,136	13.71	1.96
10,001-100,000	299	0.50	0.47
100,001-1,000,000	4	0.01	0.07
Over 1,000,000b	2	0.00	96.63
Totals	59,342	100	100

aOne ADS represents six 25 cent ordinary shares.

bOne holder of ADSs represents 1,365,801 approx. underlying shareholders.

As at 31 December 2024 there were also 1,077 preference shareholders.

Preference shareholders represented 0.52% and ordinary shareholders

represented 99.48% of the total issued nominal share capital of the

company (excluding shares held in treasury) as at that date.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		345




	Shareholder information

As at 14 February 2025, the 8% preference shares and 9% preference

shares in issue comprised only 0.30% 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 2024		As at 14 February 2025
	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
Norges Banka	651,587,439	4.00	651,587,439	4.00

aIn the last three financial years, BP p.l.c. received five notifications from Norges Bank relating to its

voting rights. 1 - the percentage of voting rights falling below 3% on 16 March 2022; 2 - the

percentage of voting rights exceeding 3% on 9 February 2023; 3 - the percentage of voting rights

exceeding 4% on 12 September 2024; 4 - the percentage of voting rights falling below 4% on 20

September 2024; 5 - the percentage of voting rights exceeding 4% on 23 September 2024.

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 14 February 2025.

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	4,191,539,064	26.19
BlackRock, Inc.	1,478,584,810	9.24
Vanguard Group Holdings	792,582,730	4.95
Norges Bank	722,312,781	4.51

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	1,370,985	18.96
Interactive Investor Share Dealing Services	968,752	13.39
Barclays, Plc.	682,038	9.43
Halifax Share Dealing Services	625,009	8.64
Canaccord Genuity Group Inc.	541,185	7.48
AJ Bell Securities, Ltd.	379,756	5.25
Ameriprise Financials, Inc.	287,500	3.97

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	907,748	16.58
AJ Bell Securities, Ltd.	622,328	11.37
Interactive Investor Share Dealing Services	527,194	9.63
Canaccord Genuity Group Inc.	413,605	7.56
Safra Group	345,500	6.31
Halifax Share Dealing Services	292,679	5.35
Ameriprise Financials, Inc.	250,000	4.57
abrdn plc	215,000	3.93
Redmayne-Bentley LLP	179,725	3.28
Barclays, Plc.	174,656	3.19

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 2025 AGM is scheduled to be held on Thursday 17 April 2025 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 2025.

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.

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.


346		bp Annual Report and Form 20-F 2024

•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, amongst 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 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.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		347




	Shareholder information

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.

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

2024 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 25 April 2024, 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 2024.

These authorities were given for the period until the next AGM in 2025 or 25

July 2025, 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.


348		bp Annual Report and Form 20-F 2024

Purchases of equity securities by the issuer and affiliated purchasers

During the 2024 financial year the company repurchased 1,238,335,234 ordinary shares with a nominal value of $0.25 each for a total consideration of

$7,127,061,186 (including transaction costs), for the purpose of reducing the issued share capital of the company in order to return capital to shareholders

and to offset the expected dilution from the vesting of awards under employee share schemes. The shares repurchased in 2024 represented 7.65% of the

company’s issued share capital, excluding shares held in treasury, on 31 December 2024. Of the shares repurchased in 2024, shares purchased under the

2023 AGM authority represented 2.51%, and shares purchased under the 2024 AGM authority represented 5.14% of bp’s issued share capital, excluding

shares held in treasury, on 31 December 2024. A further 176,152,257 ordinary shares were repurchased between the end of the financial year and 14

February 2025 at a cost of $927,491,733 (including transaction costs) representing 1.09% of the company’s issued share capital, excluding shares held in

treasury, on 31 December 2024. All ordinary shares repurchased in 2024 and in 2025 up to 14 February under the share buyback programmes were

cancelled.

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 2024 AGM covering the period until the date of the company’s 2025 AGM or 25 July

2025, whichever is earlier. The maximum number of ordinary shares to be purchased under this authority will not exceed 1,701,953,274 ordinary shares.

The shares purchased will be cancelled.

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
2024
January 02 - January 31	113,923,673	5.87	7,312,257	106,611,416	N/A
February 1 - February 28	93,027,315	5.99		93,027,315	N/A
March 1 - March 28	91,984,194	6.18		91,984,194	N/A
April 2 - April 30	93,129,453	6.50		93,129,453	N/A
May 1 -May 31	90,477,384	6.34		90,477,384	N/A
June 3 - June 28	95,154,515	6.01		95,154,515	N/A
July 1- July 30	125,439,524	5.99		125,439,524	N/A
August 2 - August 30	102,310,465	5.68		102,310,465	N/A
September 02 -September 30	123,588,247	5.45	990,000	122,598,247	N/A
October 01 - October 31	154,431,981	5.32		154,431,981	N/A
November 1 - November 29	90,683,490	4.90		90,683,490	N/A
December 2 - December 20	72,487,250	4.96		72,487,250	N/A
2025
January 03 - January 31	132,132,317	5.25	1,200,000	130,932,317	N/A
February 03 - February 11	45,219,940	5.30		45,219,940	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 2 February 2024 were made under a share buyback programme announced on 31 October 2023 for a period up to and including 2 February 2024. On 6 February 2024

the company announced a programme covering a period up to and including 3 May 2024. On 7 May 2024 the company announced a programme covering a period up to and including 26 July 2024. The

company announced two programmes in one announcement on 30 July 2024. One covered a period up to and including 25 October 2024 and the other, relating to employee share schemes, was for a

period up to and including 30 September 2024. On 29 October 2024 the company announced a programme covering a period up to and including 7 February 2025. On 11 February 2025 the company

announced its intent to execute a $1.75 billion share buyback prior to reporting its first quarter 2025 company and group results.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		349




	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 2024. The Depositary reimbursed to the company, or paid

amounts on the company’s behalf to third parties, or waived its fees and

expenses, of $15,748,804.07 for the year ended 31 December 2024.

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 2024.


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 2024 $
Fees for delivery and surrender of bp ADSs	2,071,528.80
Dividend fees	13,677,275.27
Waived fees	—
Total	15,748,804.07

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 2024 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 Issuer Direct by calling +1 855 656 2750 or by emailing

bpreports@issuerdirect.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

335) significant ways (if any) in which its corporate governance practices

differ from those mandated for US companies under NYSE listing

standards.


352		bp Annual Report and Form 20-F 2024

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:

a.The anticipated levels of investment in (i) oil and gas resources and

reserves; and (ii) other energy sources and technologies.

b.The company’s targets to promote reductions in its operational

greenhouse gas emissions, to be reviewed in line with changing

protocols and other relevant factors.

c.The estimated carbon intensity of the company’s energy products

and progress on carbon intensity over time.

d.Any 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.

Material capex evaluation: Paris-consistency quantitative tests.

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.

Emissions from the carbon in our upstream oil and gas

production

Estimated CO2 emissions from the combustion of upstream production of

crude oil, natural gas and natural gas liquids (NGLs) based on bp’s net

share of production, excluding bp’s share of Rosneft production and

assuming that all produced volumes undergo full stoichiometric

combustion to CO2.

Energy products

For the purposes of our 2024 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 2024

net zero sales aim reporting see the Basis of Reporting 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« production

In relation to bp’s now retired (as of February 2025) ‘aim 2’, to reach net

zero CO2 emissions from the carbon in our upstream oil and gas

production, in respect of the estimated CO2 emissions from the combustion

of upstream production of crude oil, natural gas and natural gas liquids

(based on bp’s net share of production, excluding bp’s share of Rosneft

production and assuming that all produced volumes undergo full

stoichiometric combustion to CO2). This aim previously related to Scope 3


« See glossary on page 351		bp Annual Report and Form 20-F 2024		353




	Glossary

category 11 emissions within the selected boundary of bp’s net share of

upstream production of oil and gas.

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.

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 Basis of Reporting

bp.com/basisofreporting.

Adjusted EBIDA

Adjusted EBIDA is a non-IFRS measure and 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 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). bp believes that

adjusted EBIDA 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. The nearest equivalent measure on an

IFRS basis is profit or loss for the period. A reconciliation of profit or loss

for the period to adjusted EBIDA is provided on page 361.

Adjusted EBIDA per share compound annual growth rate (CAGR)

Non-IFRS measure. Adjusted EBIDA per share 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 327 and

362.

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 362.

Adjusted free cash flow

Non-IFRS measure. It is defined as adjusted operating cash flow« (see

below) less 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. It is annualized growth rate of adjusted free cash

flow« (defined above) at $70/bbl Brent, $4/mmBtu Henry Hub, and $17/

bbl refining marker margin, all 2024 real.

bp believes the measure provides useful information to investors. Adjusted

free cash flow CAGR enables investors to measure our progress on

delivering growth and improving our performance. The nearest IFRS

measure is the annualized growth rate of net cash provided by (used in)

operating activities.

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.

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 313.

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.

Biofuels production

Biofuels production is average thousands of barrels of biofuel production

per day during the period covered net to bp. This includes equivalent

ethanol production, bp bioenergy biopower for grid export, refining co-

processing and standalone hydrogenated vegetable oil (HVO).


354		bp Annual Report and Form 20-F 2024

Biogas supply volumes

Biogas supply volumes is the average thousands of barrels of oil equivalent

per day of production and offtakes during the period covered net to bp.

Bio-refinery

A facility that is dedicated to processing biological materials (including

waste oil and crop waste) to produce biofuels such as biodiesel and

sustainable aviation fuel, which may be blended to customer specifications

with other components such as hydrocarbons at co-located or adjacent

terminals and tanks.

Blue hydrogen

Hydrogen made from natural gas in combination with carbon captured and

stored (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.

Cash balance point

Cash balance point is defined as the implied Brent oil price 2021 real to

balance bp’s sources and uses of cash assuming an average bp refining

marker margin around $11/bbl and Henry Hub at $3/mmBtu in 2021 real

terms.

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.

Convenience gross margin growth

Non-IFRS measure. See convenience gross margin definition above.

Convenience gross margin growth at constant foreign exchange is a non-

IFRS measure. This metric requires a calculation of the comparative

convenience gross 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. bp believes the convenience gross margin

growth at constant foreign exchange are useful measures because these

measures may help investors to understand and evaluate, in the same way

as management, our progress against our strategic objectives of redefining

convenience. The nearest IFRS measure to convenience gross margin is RC

profit before interest and tax for the customer & products segment.

Convenience & EV gross margin growth (%)

Non-IFRS measure. See convenience gross margin and EV gross margin

definitions. Convenience and EV 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


« See glossary on page 351		bp Annual Report and Form 20-F 2024		355




	Glossary

comparative convenience and EV gross 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 and EV 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.

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.

Effective tax rate (ETR) on replacement cost (RC) profit or loss

Non-IFRS measure. The ETR on RC profit or loss is calculated by dividing

taxation on a RC basis by RC profit or loss before tax. Taxation on a RC

basis for the group is calculated as taxation as stated on the group income

statement adjusted for taxation on inventory holding gains and losses.

Information on RC profit or loss is provided below. bp believes it is helpful

to disclose the ETR on RC profit or loss because this measure excludes the

impact of price changes on the replacement of inventories and allows for

more meaningful comparisons between reporting periods. Taxation on a

RC basis and ETR on RC profit or loss are non-IFRS measures. The nearest

equivalent measure on an IFRS basis is the ETR on profit or loss for the

period. A reconciliation to IFRS information is provided on page 360.

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.

EV gross margin

Non-IFRS measure. EV gross margin, as applicable to the directors’

remuneration performance measure, 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 convenience

and retail fuels, aviation, B2B and midstream businesses. The nearest IFRS

measure to EV gross margin is RC profit before interest and tax for the

customer & products segment.

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 recorded at fair value with mark to market gains

and losses recognized in the income statement. Therefore, measurement


356		bp Annual Report and Form 20-F 2024

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.

Fast / Fast charging

Fast charging comprises rapid charging« and ultra-fast charging«.

Finance debt ratio

Finance debt ratio is defined as the ratio of finance debt to the total of

finance debt plus total equity.

Gearing and net debt

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.

Gearing including leases and net debt 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 315.

Green hydrogen

Hydrogen produced by electrolysis of water using renewable power.

Grey hydrogen

Produced via natural gas or coal without CCUS.

Hydrocarbons

Liquids and natural gas. Natural gas is converted to oil equivalent at

5.8 billion cubic feet = 1 million barrels.

Hydrogen pipeline

Hydrogen projects which have not been developed to final investment

decision (FID) but which have advanced to the concept development stage.

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 312.

Installed renewables capacity

Installed renewables capacity is bp's share of capacity for operating assets

owned by entities where bp has an equity share.

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.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		357




	Glossary

Low carbon activity

For the purposes of FY24 and FY23 reporting an activity relating to low

carbon including: renewable electricity; bioenergy; electric vehicles and

other future mobility solutions; trading and marketing low carbon products;

blue or green hydrogen« and carbon capture, use and storage (CCUS).

Note that, while there is some overlap of activities, these terms do not

mean the same as low carbon energy or our low carbon energy sub-

segment, reported within the gas & low carbon energy segment.

Low carbon activity investment

Capital investment in relation to low carbon activity«.

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.

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 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 operating expenditure is a performance

measure that provides investors with useful information regarding the

company’s financial performance because it considers these expenses to

be the principal operating and overhead expenses that are most directly

under their control although they also include certain adjusting items«,

foreign exchange and commodity price effects. The nearest IFRS measures

are production and manufacturing expenses and distributions and

administration expenses. A reconciliation of production and manufacturing

expense plus distribution and administration expenses to operating

expenditure is provided on page 363.

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 312.

We are unable to present reconciliations of forward-looking information for

organic capital expenditure to total cash capital expenditure, because

without unreasonable efforts, we are unable to forecast accurately the

adjusting item, inorganic capital expenditure, that is difficult to predict in

advance in order to derive the nearest IFRS estimate.

Production-sharing agreement / contract (PSA / PSC)

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.

Rapid / Rapid charging

Rapid charging includes electric vehicle charging of greater or equal to

50kW and less than 150kW.

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 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.

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 360.

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.

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.


358		bp Annual Report and Form 20-F 2024

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.

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.

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

361.

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.

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 363.

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.

Surplus cash flow

Surplus cash flow does not represent the residual cash flow available for

discretionary expenditures. It is a non-IFRS financial measure that should

be considered in addition to, not as a substitute for or superior to, net cash

provided by operating activities, reported in accordance with IFRS.

Surplus cash flow refers to the net surplus of sources of cash over 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.

Technical service contract (TSC)

Technical service contract is an arrangement through which an oil and gas

company bears the risks and costs of exploration, development and

production. In return, the oil and gas company receives entitlement to

variable physical volumes of hydrocarbons, representing recovery of the

costs incurred and a profit margin which reflects incremental production

added to the oilfield.

Tier 1 and tier 2 process safety events

Tier 1 events are losses of primary containment from a process of greatest

consequence – causing harm to a member of the workforce, damage to

equipment from a fire or explosion, a community impact or exceeding

defined quantities. Tier 2 events are those of lesser consequence. These

represent reported incidents occurring within bp’s operational HSSE

reporting boundary. That boundary includes bp’s own operated facilities

and certain other locations or situations.

Tight oil and gas

Natural oil and gas reservoirs locked in hard sandstone rocks with low

permeability, making the underground formation extremely tight.

Transition growth

Activities, represented by a set of now retired (as of February 2025)

transition growth engines, that transition bp toward its objective to be an

integrated energy company, and that comprise our low carbon activity«

alongside other businesses that support transition, such as our power

trading and marketing business and convenience.

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.


« See glossary on page 351		bp Annual Report and Form 20-F 2024		359




	Glossary

Transition growth investment

Capital investment in relation to transition growth«.

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 / 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, 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 360.

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 363.

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 313 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 360 for the group

and pages 28-37 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 360.

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, Castrol ON, Gigahub, PETRO,

TA, Thorntons, epic goods and earnify

Trade marks:

REWE to Go – a registered trade mark of REWE.


360		bp Annual Report and Form 20-F 2024

Non-IFRS measures reconciliations

Reconciliation of profit or loss for the period to underlying RC profit or loss«


	$ million
	2024	2023	2022	2021	2020
Profit (loss) for the year attributable to bp shareholders	381	15,239	(2,487)	7,565	(20,305)
Inventory holding (gains) losses«, before tax	488	1,236	(1,351)	(3,655)	2,868
Taxation charge (credit) on inventory holding gains and losses	(119)	(292)	332	829	(667)
RC profit (loss)« for the year	750	16,183	(3,506)	4,739	(18,104)
Net (favourable) adverse impact of adjusting items«, before tax	9,344	(1,143)	29,781	8,697	16,649
Adjusting items total taxation	(1,179)	(1,204)	1,378	(621)	(4,235)
Underlying RC profit or loss for the year	8,915	13,836	27,653	12,815	(5,690)

Reconciliation of basic earnings per ordinary share to underlying RC profit per ordinary share«


	Per ordinary share – cents
	2024	2023	2022
Profit (loss) for the year attributable to bp shareholders	2.38	87.78	(13.10)
Inventory holding (gains) losses, before tax	2.98	7.12	(7.12)
Taxation charge (credit) on inventory holding gains and losses	(0.73)	(1.69)	1.75
	4.63	93.21	(18.47)
Net (favourable) adverse impact of adjusting items, before tax	56.95	(6.58)	156.84
Taxation charge (credit) on adjusting items	(7.18)	(6.94)	7.26
Underlying RC profit for the year	54.40	79.69	145.63

Reconciliation of basic earnings per ADS to underlying RC profit per ADS«


	Per ADS – dollars
	2024	2023	2022
Profit (loss) for the year attributable to bp shareholders	0.14	5.27	(0.79)
Inventory holding (gains) losses, before tax	0.18	0.43	(0.43)
Taxation charge (credit) on inventory holding gains and losses	(0.04)	(0.11)	0.11
	0.28	5.59	(1.11)
Net (favourable) adverse impact of adjusting items, before tax	3.42	(0.40)	9.41
Taxation charge (credit) on adjusting items	(0.44)	(0.41)	0.44
Underlying RC profit for the year	3.26	4.78	8.74

Reconciliation of effective tax rate (ETR) to ETR on RC profit or loss and underlying ETR«

Taxation (charge) credit


	$ million
	2024	2023	2022
Taxation on profit or loss before taxation for the year	(5,553)	(7,869)	(16,762)
Adjusted for taxation on inventory holding gains and losses	119	292	(332)
Taxation on a RC profit or loss basis	(5,672)	(8,161)	(16,430)
Adjusted for adjusting items total taxation	1,179	1,204	(1,378)
Taxation on an underlying RC basis	(6,851)	(9,365)	(15,052)

Effective tax rate


	%
	2024	2023	2022
ETR on profit or loss before taxation for the year	82	33	109
Adjusted for inventory holding gains and losses	(4)	—	8
ETR on RC profit or loss	78	33	117
Adjusted for adjusting items total taxation	(37)	6	(83)
Underlying ETR	41	39	34


« See glossary on page 351		bp Annual Report and Form 20-F 2024		361




	Non-IFRS measures reconciliations

Return on average capital employed (ROACE)«


					$ million
	2024	2023	2022	2021	2020
Profit (loss) for the year attributable to bp shareholders	381	15,239	(2,487)	7,565	(20,305)
Inventory holding (gains) losses, before tax	488	1,236	(1,351)	(3,655)	2,868
Taxation charge (credit) on inventory holding gains and losses	(119)	(292)	332	829	(667)
Adjusting items, before tax	9,344	(1,143)	29,781	8,697	16,649
Taxation charge (credit) on adjusting items	(1,179)	(1,204)	1,378	(621)	(4,235)
Underlying RC profit	8,915	13,836	27,653	12,815	(5,690)
Interest expensea	3,113	2,569	1,632	1,322	1,808
Taxation on interest expense	(404)	(661)	(296)	(195)	(406)
Non-controlling interests (NCI)	848	641	1,130	922	(424)
	12,472	16,385	30,119	14,864	(4,712)
Total equity	78,318	85,493	82,990	90,439	85,568
Finance debt	59,547	51,954	46,944	61,176	72,664
Capital employed	137,865	137,447	129,934	151,615	158,232
Less: Goodwill	14,888	12,472	11,960	12,373	12,480
Cash and cash equivalents	39,204	33,030	29,195	30,681	31,111
	83,773	91,945	88,779	108,561	114,641
Average capital employed excluding goodwill and cash and cash equivalents	87,859	90,362	98,670	111,601	124,367

Profit (loss) for the year attributable to bp shareholders divided by total equity	0.5%	17.8%	(3.0)%	8.4%	(23.7)%
ROACE	14.2%	18.1%	30.5%	13.3%	(3.8)%

aFinance costs, as reported in the Group income statement, were $4,683 million (2023 $3,840 million, 2022 $2,703 million, 2021 $2,857 million, 2020

$3,115 million). Interest expense is finance costs excluding lease interest of $441 million (2023 $346 million, 2022 $257 million, 2021 $306 million, 2020

$350 million), unwinding of discount on provisions and other payables of $1,013 million (2023 $912 million, 2022 $808 million, 2021 $890 million, 2020

$957 million) and other adjusting items related to finance costs of $116 million (2023 $13 million, 2022 $6 million, 2021 $339 million).

Adjusted EBIDA«


			$ million
	2024	2023	2022
Profit (loss) for the period	1,229	15,880	(1,357)
Finance costs	4,683	3,840	2,703
Net finance (income) expense relating to pensions and other post-employment benefits	(168)	(241)	(69)
Taxation	5,553	7,869	16,762
Profit before interest and tax	11,297	27,348	18,039
Inventory holding (gains) losses, before tax	488	1,236	(1,351)
	11,785	28,584	16,688
Net (favourable) adverse impact of adjusting items, before interest and tax	8,839	(1,548)	29,356
	20,624	27,036	46,044
Taxation on an underlying RC basisa	(6,851)	(9,365)	(15,052)
	13,773	17,671	30,992
Add back: Depreciation, depletion and amortization	16,622	15,928	14,318
Exploration expenditure written off	766	746	385
Adjusted EBIDA	31,161	34,345	45,695

aA definition for taxation on an underlying RC basis is included under Underlying ETR in the glossary on page 359.


		bp Annual Report and Form 20-F 2024		365

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	65-67
Item 4.		Information on the Company
	A.	History and development of the company	23-27, 164-167, 172, 178, 180-184, 318-328, 345, 349
	B.	Business overview	6-7, 24-32, 33-35, 167-171, 318-334, 339
	C.	Organizational structure	222
	D.	Property, plants and equipment	14, 28-35, 177-178, 248-250, 317-329, 334
Item 4A.		Unresolved Staff Comments	None
Item 5.		Operating and Financial Review and Prospects
	A.	Operating results	6-9, 12-13, 18-27, 65-67, 182-183, 193, 195-210, 318-334
	B.	Liquidity and capital resources	142, 178, 193-201, 316-317
	C.	Research and development, patent and licenses, etc.	12, 171
	D.	Trend information	6-9, 12-13, 18-27, 318-328
	E.	Critical Accounting Estimates	n/a
Item 6.		Directors, Senior Management and Employees
	A.	Directors and senior management	72-74
	B.	Compensation	88-110, 187-192, 220-221
	C.	Board practices	72-73, 82-85
	D.	Employees	57-59, 221
	E.	Share ownership	57-59, 88-110, 187-192, 220
	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	344-345
	B.	Related party transactions	180-184, 334-335
	C.	Interests of experts and counsel	n/a
Item 8.		Financial Information
	A.	Consolidated Statements and Other Financial Information	140, 142-222, 251-253, 316, 342
	B.	Significant Changes	n/a
Item 9.		The Offer and Listing
	A.	Offer and listing details	342
	B.	Plan of distribution	n/a
	C.	Markets	342
	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	345-347
	C.	Material contracts	334
	D.	Exchange controls	342
	E.	Taxation	342-344
	F.	Dividends and paying agents	n/a
	G.	Statements by experts	n/a
	H.	Documents on display	349
	I.	Subsidiary information	n/a
	J.	Annual Report to Security Holders	n/a
Item 11.		Quantitative and Qualitative Disclosures About Market Risk	195-201
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	349
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	139, 336
Item 16.		[Reserved]	n/a
Item 16A.		Audit committee financial expert	82
Item 16B.		Code of Ethics	335-336
Item 16C.		Principal Accountant Fees and Services	84, 221, 337
Item 16D.		Exemptions from the Listing Standards for Audit Committees	n/a
Item 16E.		Purchases of Equity Securities by the Issuer and Affiliated Purchasers	348
Item 16F.		Change in Registrant’s Certifying Accountant	n/a
Item 16G.		Corporate Governance	335
Item 16H.		Mine Safety Disclosure	n/a
Item 16I.		Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	n/a
Item 16J.		Insider Trading Policies.	335
Item 16K.		Cybersecurity	336-337
Item 17.		Financial Statements	n/a
Item 18.		Financial Statements	140-144
Item 19.		Exhibits	366


366		bp Annual Report and Form 20-F 2024

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 2024. A cross reference to Form 20-F requirements is

included on page 365.

This document contains the Strategic report on the inside front cover and

pages 1-68 and the Directors’ report on pages 69-87, 88 (in part only), 111,

223-250 and 311-363. 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 88-110. The

consolidated financial statements of the group are on pages 115-222 and

the corresponding reports of the auditor are on pages 134-139.

bp Annual Report and Form 20-F 2024 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 2024, forms any part of this document.

References in this document to other documents on the bp website, such

as bp Energy Outlook 2024, 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 342 for more details) and in Germany

in the form of a global depositary certificate representing bp ordinary

shares traded on the Frankfurt Stock Exchange. The company delisted from

the Hamburg and Düsseldorf Stock Exchanges on 20 December 2024 and

announced its intention to delist from the Frankfurt Stock Exchange on 18

April 2024.

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.


Exhibit 1		Memorandum and Articles of Association of BP p.l.c.†
Exhibit 2		Description of rights of each class of securities registered under Section 12 of the Securities Exchange Act of 1934†
Exhibit 4.1		The BP Executive Directors’ Incentive Plan†
Exhibit 4.4		Director’s Service Agreement for K Thomson***†
Exhibit 4.7		Director’s Service Agreement for M Auchincloss***†
Exhibit 4.10		The BP Share Award Plan 2015**†
Exhibit 8		Subsidiaries (included as Note 37 to the Financial Statements)
Exhibit 11.1		Code of Ethics*†
Exhibit 11.2		Insider trading policy and procedure
Exhibit 12		Rule 13a – 14(a) Certifications†
Exhibit 13		Rule 13a – 14(b) Certifications#†
Exhibit 15.1		Consent of Netherland, Sewell & Associates†
Exhibit 15.2		Report of Netherland, Sewell & Associates†
Exhibit 15.3		Consent Decree**†
Exhibit 15.4		Gulf states Settlement Agreement**†
Exhibit 15.5		Consent of Deloitte LLP†
Exhibit 17		Guaranteed Securities†
Exhibit 97		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.
#		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.



Ordinary Shares of 25c each			16,662,465,251
Cumulative First Preference Shares of £1 each			7,232,838
Cumulative Second Preference Shares of £1 each			5,473,414



Navigating this report		More information
		Online quick read A concise summary of the bp Annual Report and Form 20-F 2024, highlighting strategy, performance and sustainability information.
	Read more on another page of this report

	Read more online

Task Force on Climate-related Financial Disclosures (TCFD) Information that supports TCFD Recommendations and Recommended Disclosures in relation to Metrics and Targets is indicated with TCFD. Glossary Words and terms marked with « are defined in the glossary on page 351			bp.com/annualreport
		Online reporting centre All our bp corporate reports, including the bp Sustainability Report and the bp Energy Outlook.

			bp.com/reportingcentre


Incumbent capability
~11,600		~1,100
engineers		employees on graduate schemes

	Sustainability at bp, page 38


Research and development
$301m		~2,200
invested in research and development		granted and pending patent applications held by bp and its subsidiaries

	page 171


Energy sector experience
>110 years		~15 years
in energy		of bp Energy Outlook publications

	The operating environment, page 6


☐			REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934


☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


☐			SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


*			Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission



	Block 61 Khazzan gas field in Oman
		Gas & low carbon energy, page 28



	Valaris DS-12 drillship at bp’s Raven gas field, offshore Egypt
		Oil production & operations, page 31


Metrics TCFD	2024	2023
Upstream« production	2.4mmboe/d	2.3mmboe/d
bp-operated upstream plant reliability«	95.2%	95.0%
Upstream unit production costs«	$6.17/boe	$5.78/boe
bp-operated refining availability«	94.3%	96.1%
Biofuels production«	35kb/d	32kb/d
Biogas supply volumes«b	23mboe/d	22mboe/d
LNG portfolio«	23Mtpa	23Mtpa
Strategic convenience sites«	2,950	2,850
Electric vehicle charge points«	>39,000	>29,000
Hydrogen production (net)	–	–
Developed renewables to final investment decision« (net)	8.2GW	6.2GW
Installed renewables capacity« (net)	4.0GW	2.7GW


Financial resources
$16.2bn		$27.3bn
capital expenditure«		operating cash flow«

	Group performance, page 24


Energy resources
6,248mmboe		8.2GW
proved hydrocarbon reserves for the groupb		developed renewables to FID« (net)

	Gas & low carbon energy, page 28 Supplementary information on oil and natural gas, page 223



	bp.com/ourbeliefs


Group reserves and productiona
	2024	2023	2022
Estimated net proved reserves (net of royalties)
Liquids (mmb)	3,699	3,747	3,997
Natural gas (bcf)	14,786	17,471	18,481
Total hydrocarbonsb (mmboe)	6,248	6,759	7,183
Of which:
Equity-accounted entitiesb	1,377	1,437	1,381
Production (net of royalties)
Liquids (mb/d)	1,166	1,115	1,214
Natural gas (mmcf/d)	6,914	6,944	7,101
Total hydrocarbonsc (mboe/d)	2,358	2,313	2,438
Of which:
Subsidiaries	2,008	1,967	2,000
Equity-accounted entitiesc	350	345	439
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 223 for further information. See page 322 for more information on bp’s oil and gas reserves including the impact of events occurring after the end of the reporting period. c2022 includes bp’s share of Rosneft and Russia joint ventures (193mboe/d). See Oil and gas disclosures for the group on page 324 for further information.


Other businesses & corporate excluding Rosneft
	$ million
	2024	2023	2022
Profit (loss) before interest and tax	(988)	(903)	(2,704)
Inventory holding (gains) losses	—	—	—
Replacement cost (RC) profit (loss) before interest and tax	(988)	(903)	(2,704)
Net (favourable) adverse impact of adjusting items	380	37	1,533
Underlying RC profit (loss) before interest and tax	(608)	(866)	(1,171)
Taxation on an underlying RC basis	292	322	439
Underlying RC profit (loss) before interest	(316)	(544)	(732)


Key performance highlights in 2024

$27.3bn	$38.0bn	+2%	•Agreed to form offshore wind JV with JERA Co., Inc., divesting non-core assets. •100% ownership of bp bioenergy and Lightsource bp. •Delivered $0.8 billion structural cost reduction«. •Start-up of a major project« and sanctioned a further 10 projects.

operating cash flow« Resilient financial performance	adjusted EBITDA«	upstream production 2,358mboe/d 2024 production




Total remuneration in 2024
	Single figure
	Chief executive officer		Chief financial officer
¢ 1. Salary and benefits	£5.4m		£1.9m
¢ 2. Cash allowance in lieu of pension		35% Fixed pay		50% Fixed pay
¢ 3. Annual bonus
¢ 4. Performance shares

		65% Variable pay		50% Variable pay




Pay outcomes in 2024
Annual bonus 2024		Performance shares 2022-24
	22.5% of maximum formulaic outcome		66.5% of maximum formulaic outcome




¢ Safety and sustainability ¢ Operations ¢ Financials		¢ Strategic progress ¢ rTSR ¢ Financials




Alignment with shareholders
Share ownership Share ownership is a key means by which the interests of executive directors are aligned with those of shareholders.	Murray Auchincloss (CEO)	6.1 times salary, 1,888,476 shares
	Kate Thomson (CFO)	2.6 times salary, 437,799 shares

	¢ Actual Policy requirement





Safety and sustainability	Operations	Financials	Formulaic score
22.5%	0%	0%	22.5% out of 100%


Categories	Measures	Threshold (0%)		Target (50%)	Maximum (100%)	Weight	Outcome


Safety and sustainability (30% weight)	Tier 1 process safety events«	14		9	5	7.5%	7.5%


			Actual: 3

	Tier 2 process safety events«	39		33	26	7.5%	2.5%


			Actual: 35

	Operated carbon emissions (MtCO2e)	38.2		35.5	32.8	15%	12.5%


			Actual: 33.7a

Operations (20% weight)	bp-operated reliability« and availability«	95.1%		95.9%	96.7%	10%	0%


			Actual: 94.7%

	Transition growth« engine adjusted EBITDA % growth (vs. 2023)		50%	100%	150%	10%	0%


			Actual: Below threshold

Financials (50% weight)	Modified free cash flow« ($bn)	13.2		14.7	16.2	25%	0%


			Actual: 12.5

	Adjusted EBITDA« ($bn)	39.4		40.9	42.4	25%	0%


			Actual: 38.0

	Formulaic outcome (out of 100%)						22.5%


			Crude distillation capacitiesc
	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	Gelsenkirchend		265
		Lingen		97
	Netherlands	Rotterdam		394
Mediterranean	Spain	Castellón		110
				866
Total capacity at 31 December 2024				1,557


28 Mar 2025	Fourth quarter interim dividend payment for 2024
17 Apr 2025	Annual general meeting
29 Apr 2025	First quarter results announced
16 May 2025	Record date (to be eligible for the first quarter interim dividend)
27 Jun 2025	First quarter interim dividend payment for 2025 and 8% and 9% preference shares record date
31 Jul 2025	8% and 9% preference shares dividend payment
05 Aug 2025	Second quarter results announced
15 Aug 2025	Record date (to be eligible for the second quarter interim dividend)
19 Sep 2025	Second quarter interim dividend payment for 2025
04 Nov 2025	Third quarter results announced
14 Nov 2025	Record date (to be eligible for the third quarter interim dividend)
19 Dec 2025	Third quarter interim dividend payment for 2025