BP 20-F Report ended Dec. 31, 2024
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
20-F
(Mark One)
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REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
OR
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the fiscal year ended
31 December
2024
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
OR
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SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
Commission file number:
1-06262
BP p.l.c.
(Exact name of Registrant as specified in its charter)
England and Wales
(Jurisdiction of incorporation or organization)
(Address of principal executive offices)
BP p.l.c.
Tel
+44
(0) 20 7496 4000
Fax
+44 (0) 20 7496 4630
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)
Securities registered or to be registered pursuant to Section 12(b) of the Act
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| * | Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission | ||||
Securities registered or to be registered pursuant to Section 12(g) of the Act.
None
Securities for which there is a reporting obligation pursuant to Section
15(d)
of the Act.
None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
| Ordinary Shares of 25c each |
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| Cumulative First Preference Shares of £1 each |
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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
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No
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If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes
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No
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Note—Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
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No
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Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act.
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† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
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If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
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Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive- based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).
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Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
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U.S. GAAP
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by the International Accounting Standards Board
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Other
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If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.
Item 17
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Item 18
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If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
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No
☒
bp Annual Report
and Form 20-F 2024
Growing shareholder value
We are fundamentally resetting bp’s strategy.
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.
We believe bp has a compelling investor proposition, sustainably
delivering long-term shareholder value through the energy
Our reset strategy
We plan to grow the upstream, focus the downstream and
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Navigating this report
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More information
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Online quick read
A concise summary of the
bp Annual Report and
Form 20-F
2024
, highlighting strategy, performance
and sustainability information.
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Read more on another page of this report
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Read more online
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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
«
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bp.com/annualreport
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Online reporting centre
All our bp corporate reports, including the
bp Sustainability Report
and the
bp Energy Outlook
.
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bp.com/reportingcentre
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bp Annual Report and Form 20-F 2024
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1
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Strategic report
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2024
at a
glance
As at
31 December 2024
Scale
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100,500
a
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61
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employees
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countries of operation
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(
2023
87,800
)
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(
2023
61
)
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2.4
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>39,000
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million barrels of oil equivalent
– upstream
«
production
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electric vehicle charge points
«
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(
2023
>29,000
)
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(
2023
2.3
mmboe/d)
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21,200
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retail sites
«
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(
2023
21,100
)
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Performance
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$0.4bn
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$8.9bn
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l
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profit for the year attributable
to bp shareholders
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underlying replacement cost
(RC) profit
«
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(
2023
$15.2bn
)
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(
2023
$13.8bn
)
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95.2%
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l
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94.3%
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l
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bp-operated upstream plant
reliability
«
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bp-operated refining
availability
«
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(
2023
95.0%
)
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(
2023
96.1%
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2,950
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8.2
GW
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strategic convenience sites
«
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developed renewables
to FID
«
(net)
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(
2023
2,850
)
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(
2023
6.2
GW)
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$
6.17
/boe
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l
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upstream unit production
costs
«
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(
2023
$5.78
/boe)
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Safety and sustainability
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38
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l
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33.6
MtCO
2
e
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l
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tier 1 and 2 process safety
events
«
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GHG emissions – operational
control
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(
2023
39
)
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(
2023
32.1
MtCO
2
e)
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Key
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l
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a
This figure reflects new acquisitions and companies we have taken full ownership of including bp bioenergy and Lightsource bp.
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Strategic report
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2024
at a glance
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About bp
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Chair’s letter
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Chief executive officer’s letter
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The operating environment
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Energy outlook
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Our strategy
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2024 performance
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Consistency with the Paris goals
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Our business model
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Key performance indicators
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Our financial frame
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Our investment process
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Group performance
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Gas & low carbon energy
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Oil production & operations
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Customers & products
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Other businesses & corporate
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Sustainability
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Climate-related financial disclosures (TCFD)
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Our approach to sustainability
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How we manage risk
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Risk factors
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Compliance information
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Non-financial and sustainability information statement
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Section 172 statement
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Corporate governance
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Introduction from the chair
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Board of directors
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Leadership team
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Governance framework
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Board activities
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Our stakeholders
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Key decisions
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Safety and sustainability committee
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Audit committee
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People, culture and governance committee
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Remuneration committee
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Directors’ remuneration report
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Other disclosures
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Financial statements
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Consolidated financial statements of the bp group
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Notes on the financial statements
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Supplementary information on oil and natural gas (unaudited)
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Additional disclosures
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Shareholder information
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Glossary
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Non-IFRS measure reconciliations
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Signatures
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Cross-reference to Form 20-F
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Information about this report
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Exhibits
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2
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bp Annual Report and Form 20-F 2024
|
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About bp
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||
We are an integrated energy
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Block 61 Khazzan gas field in Oman
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Valaris DS-12 drillship at bp’s Raven gas field, offshore Egypt
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company
, one of only a few that
can deliver energy at global scale
through a decades-long energy
transition.
We are in action to grow
shareholder value, strengthen bp
and build our resilience to deliver
energy to the world, today and
tomorrow.
We have operations in
Europe, North and South
America, Australasia, Asia and Africa
.
Our purpose
Our
purpose is to deliver energy to the world,
today and tomorrow.
Who we are
‘Who we are’ defines what we stand for at bp,
building on our best qualities and those things
that are most important to us. It comprises three
simple beliefs that can inspire each of us at bp
to be our best every day: live our purpose, play to
win, care for others.
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bp.com/ourbeliefs
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bp Annual Report and Form 20-F 2024
|
3
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Strategic report
|
||
Financial reporting segment performance
At
31 December 2024
, the group’s reportable segments were gas & low
car
bon energy, oil production & operations and cust
omers & 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 energy
a
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.
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$3.6bn
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$6.8bn
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replacement cost (RC) profit
before interest and tax
b
|
underlying RC profit before
interest and tax
«
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(
2023
$14.1bn
)
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(
2023
$8.7bn
)
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Oil production & operations
a
Comprises regions with upstream activities that predominantly produce
crude oil, including bpx energy.
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$10.8bn
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$11.9bn
|
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RC profit before interest
and tax
b
|
underlying RC profit before
interest and tax
|
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(
2023
$11.2bn
)
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(
2023
$12.8bn
)
|
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Customers & products
Comprises customer-focused businesses, which include convenience
and retail fuels, EV charging, as well as
Castrol
, aviation and B2B and
midstream. It also includes our products businesses, refining & oil trading,
as well as our bioenergy
c
businesses.
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$(1.6)bn
|
$2.5bn
|
|
|
RC loss before interest and tax
b
|
underlying RC profit before
interest and tax
|
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(
2023
profit
$4.2bn
)
|
(
2023
$6.4bn
)
|
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Other businesses & corporate
Comprises technology; bp ventures; our corporate activities and functions;
and any residual costs of the Gulf of America oil spill.
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$(1.0)bn
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$(0.6)bn
|
|
|
RC loss before interest
and tax
b
|
underlying RC loss before
interest and tax
|
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(
2023
loss
$(0.9)bn
)
|
(
2023
loss
$(0.9)bn
)
|
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a
The Azerbaijan-Georgia-Türkiye and Middle East regions have been further subdivided by asset.
b
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 Financial statements – Note
5
.
c
In 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
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bp’s Xazar Centre office in Baku, Azerbaijan
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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
prosperit
y in e
merging 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
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
|
|
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
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 billion
a
(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 billion
c
.
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
a
Adjusted EBITDA for the group is a non-IFRS measure and its nearest IFRS-equivalent measure is profit for the year
2024
.
b
ROACE 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.
c
Net debt is a non-IFRS measure and its nearest IFRS-equivalent measure is finance debt at the end of
2024
.
d
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
«
.
e
Excludes 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, o
ne 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
savings
d
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 2027
e
– more
than $5 billion lower per year than our
previous guidance.
All while
contin
uing 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-
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 2024
a
|
|
0.5%
|
|
profit for 2024 attributable to bp
shareholders divided by total equity
at 31 December 2024
b
|
|
$59.5bn
|
|
finance debt at the end of 2024
c
|
|
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
year
b
.
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%’ target
a
.
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/bbl
c
i
n
2024, broadly unchanged from $83/bbl
c
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/d
d
.
The
slowdown
in demand growth and
outperformance of non-OPEC+ supply led to
production cuts from OPEC+ in 2024. OPEC+
output averaged
49.8mm
b/d
in 2024 – around
900k
b/d
d
lower than 2023. Saudi Arabia cut its
output to just 9.0mm
b/d
in 2024, over 1mm
b/d
lower than its levels in the first half of 2023
d
.
These reductions were more than offset by
strong growth in non-OPEC+ supplies which
increased by 1.5mm
b/d
in 2024
d
, with the US
accounting for almost half of that increase
d
.
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
2024
f
.
In the US, Henry Hub (HH) gas prices
averaged
$2.2/mmBtu
g
, 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 num
ber of US
gas rigs in key
shale basins declined by 47% from its peak in
202
2
i
.
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
$1
7.7/bbl ($8.1/bbl
lower than in
2023)
j
.
Power and renewables
Electricity demand growth continues to outpace
total energy demand gro
wth, 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
202
3
k
.
This surge was
associated with significant overcapacity in solar
manufacturing in Chin
a.
Bioenergy growth also maintained momentum,
with resilient deman
d for l
iquid 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
4M
tpa
l
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
doub
le t
o
100Mtpa
m
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
scenarios
n
.
|
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 consumption
d
|
102.9mmb/d
|
102.0mmb/d
q
|
|||
|
Global oil production
d
|
102.9mmb/d
|
102.3mmb/d
q
|
|||
|
Natural gas consumption
f
|
4,212bcm
|
4,097bcm
r
|
|||
|
Natural gas production
f
|
4,190bcm
|
4,134bcm
r
|
|||
|
Dated Brent average
c
|
$80.76/bbl
|
$82.64/bbl
|
|||
|
West Texas Intermediate (WTI)
«
average
o
|
$75.87/bbl
|
$77.67/bbl
|
|||
|
Henry Hub average
g
|
$2.19/mmBtu
|
$2.53/mmBtu
|
|||
|
Dutch Title Transfer Facility (TTF)
«
average
e
|
34.4 euros per
MWh ($10.9/
mmBtu)
|
40.5 euros per
MWh ($12.8/
mmBtu)
|
|||
|
Japan-Korea (Asian) LNG average
p
|
$11.9/mmBtu
|
$13.8/mmBtu
|
|||
|
Refining marker margin
j
|
$17.7/bbl
|
$25.8/bbl
|
|||
|
|
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.
W
e 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 CO
2
e
a
|
||||
|
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. CO
2
equivalent
(CO
2
e) 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 CO
2
e emissions to fall by around 95%
by 2050.
|
|||
|
History
|
||||
|
a
Carbon emissions include CO
2
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
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 2027
a
–
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
|
$14-18bn
c
|
|||||
|
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
|
a
Excludes deferred consideration for 2024 acquisition of bp bioenergy in 2025.
b
At $70/bbl Brent, $4/mmBtu Henry Hub, and $17/bbl refining marker margin, all 2024 real.
c
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.
|
|
bp Annual Report and Form 20-F 2024
|
9
|
|
Strategic report
|
||
|
2024 performance
|
||
On 26 February 2025 we announced a new strategy and retired
our previous
strategic pillars
,
together
with the associated strategic targets and aims.
To help stakeholders
understand progress against our previous strategy
in 2024,
we have included the
following
metrics reported under the previous strategy
for the year ended 31 December here
a
. From
|
Metrics
TCFD
|
2024
|
2023
|
|
|
Upstream
«
production
|
2.4
mmboe/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
«
|
35
kb/d
|
32kb/d
|
|
|
Biogas supply volumes
«
b
|
23
mboe/d
|
22mboe/d
|
|
|
LNG portfolio
«
|
23
Mtpa
|
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)
|
8.2
GW
|
6.2GW
|
|
|
Installed renewables capacity
«
(net)
|
4.0
GW
|
2.7GW
|
|
Key
|
|
|
TCFD
|
TCFD Recommendations and
Recommended Disclosures
|
a
In 2024 we revised our strategic targets and aims, retiring customer touchpoints per day.
b
Conversion to mboe based on gasoline gallon equivalent (1mmbtu = 8.04 gallons).
|
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.
a
Our 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.
|
|
|
|
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
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 outcomes
a
.
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.
|
|
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 4MtCO
2
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
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
|
||
|
Pursuing a strategy that is consistent
with the Paris goals
|
|||
|
How bp evaluates each new material capex
investment
«
for consistency with the
Paris goals and other outcomes relevant to
bp strategy.
|
Our investment process
|
||
|
Disclosure of bp’s principal metrics and
relevant targets or goals over the short,
medium and long term, consistent with the
Paris goals.
|
Key performance indicators
|
||
|
Sustainability: net zero aims and targets
|
|||
|
See ‘TCFD Metrics & Targets’ for an
overview
|
|||
|
Anticipated levels of investment in:
(i) Oil and gas resources and reserves.
(ii) Other energy sources and technologies.
|
Our strategy
|
||
|
Financial frame: disciplined
investment allocation
|
|||
|
Investment in non-oil and gas
|
|||
|
Transition investment
|
|||
|
bp’s targets to promote operational
GHG reductions.
|
Sustainability: net zero
«
aims
|
||
|
Estimated carbon intensity of bp’s energy
products and progress over time.
|
Sustainability: net zero sales aim
«
|
||
|
Any linkage between above targets and
executive pay remuneration.
|
Directors’ remuneration report
|
||
|
2024 annual bonus outcome
|
|||
|
2025 remuneration policy
|
|||
Where the CO
2
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.
|
12
|
bp Annual Report and Form 20-F 2024
|
|
Our business model
|
||
What makes us different
As an integrated energy company, we believe we have a world-class portfolio – a top-tier oil and gas
business in attractive basins, and leading integrated positions and brands across the value chain. All
underpinned by distinctive capabilities in trading, technology and partnerships.
Our purpose
Guiding what we do and how we operate.
Our purpose is to deliver energy to the world,
today and tomorrow.
Our reset strategy
Our new strategy plays to our distinctive strengths
and capabilities.
•
Growing the
upstream
•
Focusing the downstream
•
Investing with discipline in transition
|
|
|
|
|
People and resources
a
These are some of the people and resources in our business model that support how we create and preserve value for our stakeholders.
|
Incumbent capability
|
|||
|
~11,600
|
~1,100
|
||
|
engineers
|
employees on graduate
schemes
|
||
|
|
|||
|
|
|||
|
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
|
||
|
|
|||
|
|
|||
|
Financial resources
|
|||
|
$16.2bn
|
$27.3bn
|
||
|
capital expenditure
«
|
operating cash flow
«
|
||
|
|
|||
|
|
|||
a
Data as at
31 December 2024
.
b
On a combined basis of subsidiaries and equity-accounted entities. See page
323
for more information on bp’s oil and gas reserves.
|
|
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 stakeholders
a
We are committed to delivering long-term value for stakeholders.
|
Investors and shareholders
|
|
|
Includes our institutional and retail investors.
|
|
|
$
5.0
bn
|
|
|
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
)
|
|
c
This figure reflects new acquisitions and companies we have taken full ownership of including bp bioenergy and Lightsource bp.
|
Employees
|
|
|
Our
100,500
c
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.
|
|
|
$10.6
bn
|
|
|
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.
|
|
|
$76
m
|
|
|
supporting additional initiatives
to benefit communities
(
2023
$117m
)
|
|
|
Partners and suppliers
|
|
|
Includes relationships with academia,
industry and cities.
|
|
|
$
146.6
bn
|
|
|
in payments to suppliers
for goods and services
(
2023
$151.7bn
)
|
|
|
|
|
|
bp.com/sustainability
|
|
|
14
|
bp Annual Report and Form 20-F 2024
|
Key perf
ormance 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
|
|||
|
2024
|
38
|
||
|
2023
|
39
|
||
|
2022
|
50
|
||
|
2021
|
62
|
||
|
2020
|
70
|
||
|
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
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 t
o 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.
|
|
|
|
|
|
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%
. Ou
r
a
Exclusions 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 specificall
y noted. For the full year 2024 reporting period this includes Archaea Energy, TravelCenters of
America, bp bioenergy and Lightsource bp.
b
The 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
|
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.
|
|
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)
|
||
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
(%)
|
|||
|
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
|
||
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)
(%)
|
|||
|
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) 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
|
TCFD
l
|
|||
|
Greenhouse gas emissions
abcde
– operational control
(MtCO
2
e)
|
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
|
||
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
32.8MtCO
2
e – an overall increase from
31.1MtCO
2
e in 2023. Of these Scope 1
emissions, 31.4MtCO
2
e were carbon dioxide and
1.5MtCO
2
e were methane
c
. 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
2
d
(indirect) emissions, covered by bp’s net zero
operations
«
aim, decreased by 0.2MtCO
2
e, to
0.8MtCO
2
e, 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
Basis of calculation
e
bp’s reported GHG emissions include methane
(CH
4
) and carbon dioxide (CO
2
). Other GHGs are
not included as they are not material to our
operations. CH
4
emissions are converted to CO
2
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 intensity
af
(%)
|
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 2024
f
.
Methane emissions from upstream operations
used to calculate this methane intensity
increased by
around 48%
from 31kt in 2023 to
Basis of calculation
e
All operated upstream assets report methane
(CH
4
) 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 CH
4
emissions being
included in the metric.
CH
4
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 CH
4
emissions for reporting is assigned to individual
bp facilities and business departments (RUs).
|
|
bp Annual Report and Form 20-F 2024
|
17
|
|
Strategic report
|
|
Diversity and inclusion
g
(%)
|
|||
|
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
|
||
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
a
These 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.
b
Total (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 CH
4
and CO
2
.
c
Due to rounding some totals may not equal the sum of their component parts. This does not affect the underlying values.
d
Scope 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).
f
In 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.
g
Relates 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.
|
|
|
|
|
|
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 2027
a
|
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 buybacks
bc
|
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
billio
n 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 issuan
ces, and n
et 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
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, w
e
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.
|
|
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 2024-27
a
|
ROACE
«
in 2027
a
|
|||||
|
Resilient distributions
|
Stronger balance sheet
|
Lower operational emissions
|
||
|
30-40%
|
$14-18bn
|
45-50%
|
||
|
Total distribution of operating cash flow
bc
|
Net debt target by end 2027
d
|
Reduction aim across Scope 1 and 2
by 2030
e
|
|
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 proceeds
f
|
$4.2bn
|
Around $3bn, weighted towards
the second half
|
|
|
Gulf of America oil spill payments
g
(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
|
a
At $70/bbl Bren
t, $4/mmBtu Henry Hub, and $17/bbl refining marker margin,
all 2024 real
.
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
In
cludes offsetting any dilution from employee share
schemes over tim
e.
d
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.
e
Reduction in emissions against 2019 baseline, on a CO
2
e basis.
f
Divestment proceeds
«
are disposal proceeds as per the group cash flow statement. See page
26
for more information on divestment and other proceeds.
g
See Financial statements –
Note 22
for more information on payables related to the Gulf of America oil spill.
h
Nearest equivalent GAAP IFRS measure: effective tax rate 82%.
i
Underlyin
g 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
O
ur 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/mm
Btu
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/tCO
2
e
in 2025
to $135/tCO
2
e in 2030 and $200/tCO
2
e
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 CO
2
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 assumptions
a
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 pa
ge
22
) using $
60/bbl Brent oil
price series.
|
||||
|
Carbon price
TCFD
|
||||
|
2023 $ real
|
2030
|
2040
|
2050
|
|
|
Carbon ($/tCO
2
e)
|
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
|
|
|
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
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
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
|
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.
|
||
â
â
â
â
Investment in non-oil and gas
In
2024
transition growth investment
«
a
was
$
3.7
billion, compared to $
3.8
billion in
2023
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
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. I
n 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
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
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
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
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
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,
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
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
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.
|
|
bp Annual Report and Form 20-F 2024
|
23
|
|
Strategic report
|
||
Evaluation outcome
In
2024
eight new material capex investments were approved
a
. All were evaluated as being consistent with the Paris
goals, taking into account both
quantitative and qualitative evaluations and the balanced criteria above
.
|
Evaluation of investment performance against quantitative guide levels
b
|
|||||||||||||
|
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
|
Guide
|
||||||||||||
n/a
n/a
n/a
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.
a
The 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.
b
The 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
15Mt
CO
2
during its
initial phase from Tangguh’s natural gas
production, reducing overall CO
2
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 CO
2
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 CO
2
Capture. We expect
around 4MtCO
2
per year from these projects will
be transported and stored from 2027.
Net Zero Te
esside Power (N
ZT Power):
Also in December bp and partners took a final
investment decision in NZT Power, a joint venture
between bp and Equino
r, which c
ould generate
up to 742MW of flexible, dispatchable low carbon
power. Up to
2Mt
CO
2
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
|
$0.4
bn
|
$8.9
bn
|
$27.3
bn
|
||
|
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 items
a
|
||||
|
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)
|
||
|
a
See
page 313
for more information.
b
See
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
|
|
|
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).
•
Th
e o
ther
ca
tegory 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 relatin
g 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
•
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
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
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.
•
I
n its
customers business, bp expects growth
i
ncluding 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 year
a
|
39,269
|
33,030
|
29,195
|
|
|
Capital expenditure
«
b
|
(16,237)
|
(16,253)
|
(16,330)
|
|
|
Divestment and other proceeds
c
|
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%
|
|
|
a
2024 includes $65 million of cash and cash equivalents classified as assets held for sale in the group balance sheet.
c
Divestment 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
acquisiti
ons.
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
onshor
e 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 sec
ur
ities
. 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
|
|
bp Annual Report and Form 20-F 2024
|
27
|
|
Strategic report
|
||
|
Group reserves and production
a
|
||||
|
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 hydrocarbons
b
(mmboe)
|
6,248
|
6,759
|
7,183
|
|
|
Of which:
|
||||
|
Equity-accounted entities
b
|
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 hydrocarbons
c
(mboe/d)
|
2,358
|
2,313
|
2,438
|
|
|
Of which:
|
||||
|
Subsidiaries
|
2,008
|
1,967
|
2,000
|
|
|
Equity-accounted entities
c
|
350
|
345
|
439
|
|
|
a
Because of rounding, some totals may not agree exactly with the sum of their component parts.
b
See 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.
c
2022 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.
|
||||
T
otal 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 f
o
r
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.
Total hydrocarbon production for the group was
2.0% higher compared with
2023
. The increase
comprised a 2.1% increase (5.6% increase for
liquids and 0.6% decrease for gas) for
subsidiaries and a 1.4% increase (1.3% increase
for liquids and 2.0% increase for gas) for equity-
accounted entities.
|
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 regions
a
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
|
2022
b
|
||
|
Sales and other operating revenues
c
|
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
|
||
|
a
The 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.
b
2022 includes bp Bunge Bioenergia. From the first quarter of 2023, bp Bunge Bioenergia is reported within customers
& products.
c
Includes sales to other segments.
d
See
page 314
for information on the cumulative impact of FVAEs.
e
A 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 re
sult, 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
60.6
GW (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.
I
n renewables by the end of 2024 we had
cumulatively brought
8.2
GW (bp net) developed
renewables to FID
«
.
Strategic progress
Gas
I
n 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 formatio
n 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.
I
n 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.
|
|
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
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 h
igh-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).
a
From 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 production
a
(net of royalties)
|
||||
|
2024
|
2023
|
2022
|
||
|
Estimated net proved reserves
(net of royalties)
|
||||
|
Crude oil
b
(mmb)
|
113
|
128
|
151
|
|
|
Natural gas liquids (mmb)
|
1
|
1
|
9
|
|
|
Total liquids
«
c
|
115
|
129
|
160
|
|
|
Natural gas
c
(bcf)
|
6,965
|
8,635
|
9,708
|
|
|
Total hydrocarbons
«
c
(mmboe)
|
1,316
|
1,618
|
1,834
|
|
|
Of which equity-accounted entities
d
:
|
||||
|
Liquids (mmb)
|
1
|
—
|
—
|
|
|
Natural gas (bcf)
|
196
|
—
|
—
|
|
|
Total hydrocarbons (mmboe)
|
35
|
—
|
—
|
|
|
Production
(net of royalties)
|
||||
|
Crude oil
be
(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 entities
f
:
|
||||
|
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
|
|
|
a
Because of rounding, some totals may not agree exactly with the sum of their component parts.
b
Includes condensate and bitumen.
c
Includes
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.
d
bp’s share of reserves of equity-accounted entities in the gas & low carbon energy segment.
e
2023 restated, 4mb/d previously reported in NGLs.
f
bp’s share of production of equity-accounted entities in the gas & low carbon energy segment.
g
Realizations 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 15MtCO
2
in its
initial phase, reducing overall CO
2
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 2MtCO
2
annually. NEP will
develop the infrastructure to transport and
store up to an initial 4MtCO
2
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.
|
||
|
|
bp Annual Report and Form 20-F 2024
|
31
|
|
Strategic report
|
||
|
Oil production & operations
|
||
|
Oil production & operations segment comprises regions
a
with
upstream activities that predominantly produce crude oil,
including bpx energy.
|
||||
|
Financial and operating performance
|
||||
|
$ million
|
||||
|
2024
|
2023
|
2022
|
||
|
Sales and other operating revenues
b
|
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
|
|
|
a
The 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.
b
Includes sales to other segments.
c
A 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
operations in the regions.
|
32
|
bp Annual Report and Form 20-F 2024
|
|
Oil production & operations
continued
|
||
|
Estimated net proved reserves and production
a
(net of royalties)
|
||||
|
2024
|
2023
|
2022
|
||
|
Estimated net proved reserves
(net of royalties)
|
||||
|
Crude oil
b
(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 entities
c
:
|
||||
|
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 oil
b
(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 entities
d
:
|
||||
|
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
|
|
|
a
Because of rounding, some totals may not agree exactly with the sum of their component parts.
b
Includes condensate and bitumen.
c
bp’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.
d
bp’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.
e
Realizations 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
|
||
|
|
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 revenues
a
|
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
|
|
|
a
Includes sales to other segments.
b
See
page 314
for information on the cumulative impact of FVAEs.
c
A 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
ad
v
erse fair value accounting effects
of
$81 million
– relative to management’s vi
ew 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 d
ue to
the first quarter Whiting refinery
power outa
ge.
Strategic progress
Convenience & retail fuels
I
n F
ebruary 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 inc
rease 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.
a
FIA 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
.
•
I
n September 2024, bp signed a deal with LAZ
parking in the US, to roll-out ultra-fast
charging hubs in 20 citie
s.
In addition:
•
I
n 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 fuel
a
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
|
||
|
|
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 Netherland
s.
•
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 i
n 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, inclu
ding 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 revenues
a
|
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
|
|
|
a
Includes sales to other segments.
b
See
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.
•
I
n 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.
|
|
bp Annual Report and Form 20-F 2024
|
37
|
|
Strategic report
|
||
|
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)
|
|
|
Rosneft
|
||||
|
$ million
|
||||
|
2024
|
2023
|
2022
|
||
|
Profit (loss) before interest and tax
|
—
|
—
|
(24,033)
|
|
|
Inventory holding (gains) losses
|
—
|
—
|
—
|
|
|
Replacement cost (RC) profit (loss) before interest and tax
|
—
|
—
|
(24,033)
|
|
|
Net (favourable) adverse impact of adjusting items
|
—
|
—
|
24,033
|
|
|
Underlying RC profit (loss) before interest and tax
|
—
|
—
|
—
|
|
|
Taxation on an underlying RC basis
|
—
|
—
|
—
|
|
|
Underlying RC profit (loss) before interest
|
—
|
—
|
—
|
|
|
2024
|
2023
|
2022
|
||
|
Estimated net proved reserves
(net of royalties) (bp share)
|
||||
|
Crude oil
a
(mmb)
|
—
|
—
|
—
|
|
|
Natural gas liquids (mmb)
|
—
|
—
|
—
|
|
|
Total liquids
«
|
—
|
—
|
—
|
|
|
Natural gas (bcf)
|
—
|
—
|
—
|
|
|
Total hydrocarbons
«
(mmboe)
|
—
|
—
|
—
|
|
|
Production
b
(net of royalties)
|
||||
|
Crude oil
a
(mb/d)
|
—
|
—
|
144
|
|
|
Natural gas liquids (mb/d)
|
—
|
—
|
—
|
|
|
Total liquids (mb/d)
|
—
|
—
|
144
|
|
|
Natural gas (mmcf/d)
|
—
|
—
|
238
|
|
|
Total hydrocarbons (mboe/d)
|
—
|
—
|
185
|
|
|
a
Includes condensate.
b
2022 reflects bp's estimated share of Rosneft production for the period 1 January to 27 February only. The estimated share of
production for that period has been averaged over the full year.
|
||||
|
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 control
a
,
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 operate
b
.
|
Our aim is to reduce our
net freshwater use in
stressed catchments
where we operate.
|
|||||||||||||||
|
|
|
|
|
|
|||||||||||||||
|
See
below
|
|
|
|
|
|||||||||||||||
Reporting on sustainability
In this section, we cover selected sustainability issues along with information in the following areas:
•
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 a
nd to achieving our overall net
zero ambition. These are: net zero operations
c
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
a
O
n a CO
2
e basis
.
b
At our new in-scope bp
-
operated projects and major operating sites
.
c
This aim is a combination of bp
’
s previous
net zero aims (
‘
aim 1
’
a
nd
‘
aim
4
’
)
.
d
Due 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
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 54.5MtCO
2
e. 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
33.6
MtCO
2
e – a decrease of 38% from our 2019
baseline
.
The total decrease includes 18MtCO
2
e
attributable to divestments and 5.4MtCO
2
e in
emissions reductions activity.
In 2024 our Scope 1 (direct) emissions were
32.8
MtCO
2
e – an overall increase from
31.1MtCO
2
e in 2023.
Of these Scope 1
emissions,
31.4
MtCO
2
e were from carbon
dioxide and 1.5MtCO
2
e from methane
d
. 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.
|
|
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 (gCO
2
e/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
|
|
|
Bioproducts
e
|
41
|
44
|
43
|
44
|
44
|
47
|
|
|
Power/heat
f
|
50
|
56
|
29
|
27
|
33
|
28
|
|
emissions reduction projects.
In 2024 our Scope 2
a
(indirect) emissions,
decreased by 0.2MtCO
2
e, to
0.8
MtCO
2
e,
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, o
ur 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 2023
b
).
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 methodolo
gy
.
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
3,614
bcf 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
a
Scope 2 emissions on a market basis.
b
In 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
.
c
Previously 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.
d
The 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
.
e
Includes biofuels and biogas.
f
Covers all power, including renewable and non-renewable.
g
Commodity groups in 2024 are Oil/Refined Products, Gas/NGLs, Biofuels, Biogas, Power/Heat.
h
On the updated methodology basis.
i
In February 2025 bp announced that we have retired the concept of transition growth
«
engines going forward.
j
Excludes 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
chain
g
. 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
79
gCO
2
e/MJ
h
. 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 322MtCO
2
in
2024 – an 11% reduction
relative to our 2019 baseline and a slight
increase from 315MtCO
2
in 20
23
. 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 an
d $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
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 2027
j
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 intensity
b
|
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
«
|
$
3.7
bn
|
–
|
||||||||
a
Reduction in absolute emissions against 2019 baseline.
b
Average lifecycle carbon intensity of our sold energy products
«
.
c
Previously 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.
d
Reduction 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
.
e
In 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 control
ab
|
Unit
|
2024
|
2023
|
2022
|
||
|
Scope 1 (direct) emissions
|
MtCO
2
e
|
32.8
|
31.1
|
30.4
|
||
|
UK and offshore
|
MtCO
2
e
|
1.0
|
1.0
|
1.0
|
||
|
Global (excluding UK and offshore)
|
MtCO
2
e
|
31.8
|
30.1
|
29.4
|
||
|
Scope 2 (indirect) emissions – location-based
|
MtCO
2
e
|
2.4
|
2.0
|
2.1
|
||
|
UK and offshore
|
MtCO
2
e
|
0.02
|
0.02
|
0.02
|
||
|
Global (excluding UK and offshore)
c
|
MtCO
2
e
|
2.4
|
1.9
|
2.0
|
||
|
Scope 2 (indirect) emissions – market-based
|
MtCO
2
e
|
0.8
|
1.0
|
1.4
|
||
|
UK and offshore
de
|
MtCO
2
e
|
0.02
|
0.0
|
0.0
|
||
|
Global (excluding UK and offshore)
f
|
MtCO
2
e
|
0.8
|
1.0
|
1.4
|
||
|
Energy consumption
gb
|
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 production
h
|
teCO
2
e/te
|
0.16
|
0.16
|
0.15
|
||
|
UK and offshore
|
teCO
2
e/te
|
0.13
|
0.13
|
0.12
|
||
|
Global (excluding UK and offshore)
|
teCO
2
e/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.
|
||||||
|
|
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 0.42MtCO
2
e. This is in addition to the
172 emissions reduction projects and the
associated reduction of 0.9MtCO
2
e 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
102ktCO
2
e in emissions savings. These
reductions were primarily delivered in bpx
energy, US and included electrification
projects and installation of solar pumps.
Emission savings of ~262ktCO
2
e 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
19ktCO
2
e.
•
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 56ktCO
2
e, including
the hydrocracker improvement project at
Cherry Point, US, which saved 26ktCO
2
e
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 CO
2
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
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 disclosures
a
|
||
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
Catalogue
b
to inform our own scenario analysis
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 2024
c
.
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 Recommendation
d
. 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
describe elements of our plans for the transition
to a lower carbon economy as we execute
our strategy.
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
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, w
e 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
The board and its committees have oversight of
climate-related issues
f
, 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
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 disclosure
s – including these
TCFD disclosures.
a
This 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.
b
Our 2024 analysis used data from the WBCSD Climate Scenario Catalogue version 3.0, published on 16-05-2024 and downloaded on 13-11-2024.
c
In 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.
d
In 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.
e
UKLR 6.6.8G and UKLR 6.6.9G.
f
We 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.
|
|
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
•
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 su
stainability frame and net
zero ambition.
•
Hina Nagarajan
has over 30 years’ experience
in senior r
oles 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
|
|||
|
|
|||
|
Safety and sustainability committee
|
|||
|
|
|||
|
Audit committee
|
|||
|
|
|||
|
Remuneration committee
|
|||
|
|
|||
|
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
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
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
|
|
|
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.
|
||
|
|
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,
all types of risks including our principal risks and
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.
a
Information added to satisfy the UK CFD Regulations.
The process for identifying risks is outlined on
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.
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
opportunities
a
As set out in our TCFD Strategy A and B
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
Our gas & low carbon energy business is
accountable for the delivery of many of our low
carbon opportunities through both organic and
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
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
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 functio
ns i
nto the
three broad
material climate-related transition risks to bp, see
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
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.
|
|
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
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
Climate-related
transition risks
and opportunities
At a group level, we have identified three broad,
a
Underlying risks are specific, for example, local or business-specific risks identified by specific bp entities through the risk processes described above under Risk Management.
b
This 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
appropriate
a
. We also see significant potential for
upside – or opportunity – associated with some
of these risks. These are
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
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
|
||
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
Our progress against our net zero aims are
|
||
|
|
TP
Our strategy, together with our net zero
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
|
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
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.
|
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bp Annual Report and Form 20-F 2024
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49
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Strategic report
|
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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
,
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
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
TP
Customers
and produc
ts
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,
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
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
3-5
GW
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
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 developmen
t 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
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.
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|
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
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
taking steps to be more efficient in operational
freshwater use (read more about water use on
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
billion
a
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
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/
teCO
2
e (2023 $ real) in 2030
.
When taking investment decisions we continue
to consider six balanced investment criteria –
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
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,
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.
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|
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 pathways
a
, including 1.5°C, as
set out below and in our methodology
–
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
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
.
a
Although 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.
b
Note 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.
c
Our 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
#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
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 represent
a
. 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 2026-30
b
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
•
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.
T
he analysis should not be taken as a prediction
of the future.
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Climate-related financial disclosures
continued
|
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Maintaining strategi
c 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
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
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 ou
r 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 Pathway
a
(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
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.
a
SSPs 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.
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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
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
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
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 2030
a
.
•
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 price
b
($2022/bbl)
|
63.67
|
85.00
|
50.00
|
77.34
|
34.2
|
71.12
|
|
|
Natural gas price
c
($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
|
|
– 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.
a
For the purposes of resilience testing,
Castrol
is included in the underlying reference plan being assessed, pending the outcome of its strategic review.
b
Oil 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.
c
Gas 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.
|
|
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 cl
imate-
related risks and opportunities
in line with our
strategy and risk management process below,
with metrics and targets mapped to the most
relevan
t 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
|
||||
|
•
Oil and natural gas prices used for value-in-use impairment testing and recoverability of asset
|
||||
|
Physical risks
|
||||
|
|
||||
|
Climate-related opportunities
|
||||
|
Capital deployment
|
||||
|
|
||||
|
Internal carbon prices
|
||||
|
|
||||
|
Remuneration
|
||||
|
|
|
|||
|
b) Disclose Scope 1, Scope 2, and, if appropriate, Scope 3 greenhouse gas (GHG) emissions, and the related risks
|
||||
|
GHG emissions
|
||||
|
•
A further breakdown of our GHG and energy data by business group is available in the
bp ESG
Datasheet 2024
at
bp.com/ESG
.
|
||||
a
These 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.
b
In 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 Brazil
a
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 US
b
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 b
y 8.5
% compared t
o
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.
|
|
|
|
|
a
In 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.
b
At 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
.
c
For 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 per
iod
.
|
2024
|
2023
|
2022
|
||
|
Severe vehicle
accident rate per
million km driven
|
0.022
|
0.023
|
0.037
|
Our Operating Management
System
c
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 process
c
.
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
.
P
reventing incident
s
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
|
|
|
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.
I
n
2024
we conducted in the
region of 25
exercis
es 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.
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.
O
ur 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 %
|
||||
|
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 employees
a
|
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 & products
b
|
73,100
|
63,400
|
44,700
|
|
|
Other businesses & corporate
|
11,700
|
10,800
|
10,100
|
|
|
Total
c
|
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
|
|
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
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
ambitio
n
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
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.
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.
|
|
bp Annual Report and Form 20-F 2024
|
59
|
|
Strategic report
|
||
Linking remuneration to
sustainability
TCFD
Our annual bonus for all eligible employees
a
,
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
Our 2022-24 long-term incentive plan scorecard
also linked to our operated carbon emissions
performance
and, for group leaders
b
, 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
.
|
|
|
|
|
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 t
o
all bp employees, officers
and board members
c
. 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
a
The number of employees eligible for a cash bonus in 2024 was around 38,000
.
b
Group leaders are our most senior leaders. Their roles include operational, functional and regional leadership.
c
For 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.
d
Senior leaders are the leadership tier below group leaders. They typically manage larger teams or are recognized as technical or functional experts.
e
This 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 leaders
d
, 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 w
here 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).
I
n
2024
around
250
separations resulted
from non-conformance with our code or
unethical behaviour
e
.
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 tha
n 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 plans
a
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
We support the goa
ls 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.
a
We will work to develop just transition plans with input from potentially affected stakeholders to help manage social risks and opportunities.
b
At our new in-scope bp-operated projects and major operating sites.
c
New 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.
d
The 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
.
e
Following 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.
f
The restated 2020 baseline for freshwater withdrawal is 96.4 million m
3
per year and for freshwater consumption is 55.9 million m
3
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
operate
b
, by
:
•
Aiming to achieve a net positive impact (NPI)
on all new in-scope
c
projects.
•
Implementing biodiversity enhancement
plans at our major op
erating sites.
•
Collaboratin
g with others
to support selected
biodiversity r
estoration 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 opera
t
e
b
, by:
•
Being more efficient with freshwater use in
our operations.
•
Collaborating with others to replenish
freshwater in stressed
d
catchme
nts.
We anticipate that by 2028, our fresh
water
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
o
perating 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 baseline
f
.
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
|
|
|
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
|
||||||
|
Business and strategic risk management
Plan, manage performance and assure
|
||||||
|
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
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.
á
á
à
à
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 i
n
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.
â
â
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.
|
|||
|
|
|||
|
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. b
p’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
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.
|
|
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 businesse
s 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 throu
gh the dev
elopment 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.
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
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
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
functio
n
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
I
nability 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
information
.
|
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|
|
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 ‘W
ho 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.
|
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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
.
|
|
|
|
|
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
investment
s
.
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.
L
iquidity, 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.
|
|
|
|
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.
|
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|
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.
|
|
|
|
|
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.
|
|
|
|
|
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.
|
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|
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.
|
|
|
|
|
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.
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 ou
r reputation.
|
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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)
|
|||||
|
b Employees
|
•
bp values and code of conduct (online)
|
|||||
|
c Social matters
|
•
Sustainability frame
|
|||||
|
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)
|
|||||
|
e Anti-corruption and anti-bribery
|
•
Anti-bribery and corruption policy
•
Code of conduct (online)
|
|||||
|
Description of principal risks relating
to matters (a-e above)
|
||||||
|
Relevant information
|
||||||
|
Business model description
|
|
|||||
|
Description of non-financial KPIs
|
||||||
|
TCFD index table
a
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.
|
|
||||
|
b Describe management’s role in assessing and managing
climate-related risks and opportunities.
|
|
|||||
|
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.
|
|||||
|
b Describe the impact of climate-related risks and
opportunities on the organization’s businesses, strategy,
and financial planning.
|
||||||
|
c Describe the resilience of the organization’s strategy, taking
into consideration different climate-related scenarios,
including a 2°C or lower scenario.
|
||||||
|
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.
|
|||||
|
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.
|
||||||
|
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.
|
|
||||
|
b Disclose Scope 1, Scope 2, and, if appropriate, Scope 3
GHG emissions, and the related risks.
|
|
|||||
|
c Describe the targets used by the organization to manage
climate-related risks and opportunities and performance
against targets.
|
||||||
a
We 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.
|
||||||
|
|
||||||
The Strategic report was approved by the board and signed on its behalf by Ben J.S. Mathews, company secretary, on 6 March 2025.
|
|
bp Annual Report and Form 20-F 2024
|
69
|
|
Corporate governance
|
||
Corporate
governance
|
Thunderhorse, US Gulf of America
|
|
Introduction from the chair
|
|
|
Board at a glance
|
71
|
|
Board of directors
|
|
|
Leadership team
|
|
|
Governance framework
|
|
|
Board activities
|
|
|
Our stakeholders
|
|
|
Key decisions
|
|
|
Safety and sustainability committee
|
|
|
Audit committee
|
|
|
People, culture and governance committee
|
|
|
Remuneration committee
|
|
|
Directors’ remuneration report
|
|
|
Other disclosures
|
|
|
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
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,
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
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
|
|
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 directors
a
|
||||||||||||||||||
|
Helge Lund (Chair)
|
8/8
|
2/2
|
ò
|
ò
|
ò
|
ò
|
ò
|
ò
|
ò
|
|||||||||
|
Dame Amanda Blanc
|
8/8
|
2/2
|
ò
|
ò
|
ò
|
ò
|
ò
|
ò
|
ò
|
ò
|
||||||||
|
Tushar Morzaria
|
8/8
|
2/2
|
ò
|
ò
|
ò
|
ò
|
ò
|
ò
|
||||||||||
|
Melody Meyer
b
|
8/8
|
1/2
|
ò
|
ò
|
ò
|
ò
|
ò
|
ò
|
||||||||||
|
Pamela Daley
|
8/8
|
2/2
|
ò
|
ò
|
ò
|
ò
|
ò
|
|||||||||||
|
Hina Nagarajan
|
8/8
|
2/2
|
ò
|
ò
|
ò
|
ò
|
ò
|
ò
|
ò
|
|||||||||
|
Satish Pai
c
|
7/8
|
2/2
|
ò
|
ò
|
ò
|
ò
|
ò
|
ò
|
ò
|
|||||||||
|
Karen Richardson
c
|
7/8
|
2/2
|
ò
|
ò
|
ò
|
ò
|
ò
|
ò
|
||||||||||
|
Dr Johannes Teyssen
|
8/8
|
2/2
|
ò
|
ò
|
ò
|
ò
|
ò
|
ò
|
ò
|
ò
|
||||||||
|
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
|
|||||
|
|
|
|
|
|||||
|
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.
|
|
|
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
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 l
ed 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.
|
|
|
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
|
|||||||||||
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
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
•
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
|
||||||
|
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
|
|||||||
|
|
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
•
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
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
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
ò
ò
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, f
or employee
s,
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
ò
ò
ò
ò
In 2024, engagements included sessions with
em
ployees 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
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
ò
ò
ò
ò
ò
ò
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. Thi
s engagement
supported the board’s confidence that their
decisions had taken account of evolving
stakeholder expectations.
|
|
|
|
|
Building trust in bp
ò
ò
ò
Two important themes in helping to maintain and
enhance organizational trust are
safety
performance and culture.
On safety, v
aluable 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
Opportunities for
collaboration
ò
ò
ò
ò
ò
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
ò
ò
ò
ò
ò
ò
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)
Further information on the board’s
activities and key decisions, including how
stakeholder interests have been
|
||
|
|
||
|
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
|
|
|
|
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 main
tain 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.
|
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
ò
ò
ò
ò
ò
ò
|
||||
|
An integrated energy company
|
||||||
|
As an integrated energy company, bp
continues to invest with discipline in both the
upstream
«
and low carbon energy. In 2024,
the board approved key investment decisions
in each of these segments.
In July, bp took a final investment decision for
a sixth operated hub, Kaskida, in the US Gulf
of America. This strategic growth project
represents bp’s ongoing commitment to
invest in this prolific high-margin basin, and
makes up an important element of growing
the value of bp. This platform is expected to
have production capacity of 80,000 barrels of
oil per day and will embrace a more simplified,
standardized and cost-efficient platform
design that we plan to replicate in future
projects, unlocking potential for the
development of 10 billion barrels of discovered
resources in place in the Paleogene, Gulf of
America.
|
Together with our partners we reached financial
close for two major carbon capture and storage
(CCS) projects in Teeside in the north-east of
England: the Northern Endurance Partnership
(NEP) and Net Zero Teesside Power (NZT
Power). NEP, through its CO
2
transport and
storage system, will help develop and underpin
a lower carbon future for industry in the region.
NZT Power, a gas-fired power station with CCS,
will provide flexible low carbon power into the
UK national power grid. The two projects will
capture and transport millions of tonnes of CO
2
and the board noted the potential from these
projects to support thousands of jobs through
their construction and operation.
|
The NZT Power and NEP decisions were taken
following extensive dialogue with multiple
stakeholders, including discussions with
governments regarding local policies and with
our customers to ensure an accessible
market. The board recognized the contribution
of the NZT Power and NEP decisions to bp’s
strategic priorities, including the high grading
of our hydrogen and CCS projects and the role
these projects can play in helping advance the
UK’s journey to net zero.
In the US, the board was supportive of the
high-value growth opportunity presented by
Kaskida and the contribution it could make to
deliver secure, reliable and affordable energy.
Stakeholders considered
ò
ò
ò
ò
ò
ò
|
||||
|
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: member
a
|
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
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
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
materia
l 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
i
ncidents (
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, i
ncluding 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
resultin
g
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.
|
|
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
i
mproved 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 b
p’s plans for compliance
with the EU
Corporate Sustainability
Reporting Directive and EU Taxonomy
Regulation.
ß
•
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 reduction
s
(see remuneration
â
|
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: member
a
|
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
shareholder
s,
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
savings
b
, 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.
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 can be viewed a
t
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.
|
||
|
|
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 statement
s 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.
•
T
he 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 inp
ut 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 mit
igat
e
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
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.
|
|||
|
84
|
bp Annual Report and Form 20-F 2024
|
|
Audit committee
continued
|
||
Overseeing the relationship with
exte
rnal 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,
in
dependence 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
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.
|
||||
|
|
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
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:
member
a
|
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
|
|
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 leader
ship team structure
was effective from April 2024. Read more on
•
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 roles
a
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.
D
iversity
:
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
a
The committee engaged Heidrick & Struggles, Korn Ferry, Spencer St
u
art, Egon Zehnder and MWM Consulting in support of search activity for new board candidates. None of the search agents
have
a
ny connection wi
th the company or individual directors,
save tha
t Spencer Stuart supports on executive recruitment and Egon Zehnder provides advice and support on bp’s executive
development programme.
b
There is no connection
between I
ndependent
B
oard
E
valuation
and
either
b
p
or the
individual dir
ectors
.
a
The committee engaged Heidrick & Struggles, Korn Ferry, Spencer St
u
art, Egon Zehnder and MWM Consulting in support of search activity for new board candidates. None of the search agents
have
a
ny connection wi
th the company or individual directors,
save tha
t Spencer Stuart supports on executive recruitment and Egon Zehnder provides advice and support on bp’s executive
development programme.
b
There is no connection
between I
ndependent
B
oard
E
valuation
and
either
b
p
or the
individual dir
ectors
.
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
concl
uded that the WFEP is the appropriate
mechanism for workforce engagement, given
the activities and structure of bp
. Read more
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
performan
ce review was facilitated externally
by Independent Board Evaluation
b
(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
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
|
|
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.
|
|
|
Meeting
s 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.
|
||
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
|
|||
|
Engaging with our workforce
|
|||
|
Executive directors’ pay for
2024
|
|||
|
2024
annual bonus outcome
|
|||
|
2022-24 performance share plan outcome
|
|||
|
Policy implementation for
2025
|
|||
|
Stewardship and executive director interests
|
|||
|
Chair and non-executive director
outcomes and interests
|
|||
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.
|
|
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
a
The 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
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
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
|
|
bp Annual Report and Form 20-F 2024
|
91
|
|
Corporate governance
|
||
|
Remuneration at a glance
|
||
|
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
|
£
5.4
m
|
£
1.9
m
|
||||
|
¢
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
|
||||||
Application of discretion
The committee determined not to exercise discretion in determining the outcomes for the annual bonus and performance shares, reflecting
on
performance and the broader shareholder experience during the
performance
period.
|
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
|
||||
|
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 bonus
a
|
•
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
a
Half 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
|
|||
|
|
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
|
|
||||||
|
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
business
a
.
a
For 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.
ß
|
|
bp Annual Report and Form 20-F 2024
|
95
|
|
Corporate governance
|
||
Executive directors’ pay for
2024
Single figure table – executive directors (audited)
a
|
Murray
Auchincloss
b
thousand
2024
|
Kate
Thomson
c
thousand
2024
|
Murray
Auchincloss
b
thousand
2023
|
||
|
Salary
|
£1,450
|
£731
|
£1,015
|
|
|
Benefits
|
£132
|
£67
|
£338
|
|
|
Cash allowance in lieu of pension
|
£290
|
£146
|
£190
|
|
|
Annual bonus
d
|
£734
|
£370
|
£1,839
|
|
|
Performance shares
e,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
|
a
Due to rounding, the totals may not agree exactly with the sum of the component parts.
b
Murray Auchincloss was appointed interim CEO on 12 September 2023, having previously been CFO. He was appointed as the permanent CEO on 17 January 2024.
c
Kate 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.
d
In 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.
e
For 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.
f
For 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.
|
96
|
bp Annual Report and Form 20-F 2024
|
|
Directors’ remuneration report
continued
|
||
Annual bonus
For 2024, the committee assessed performance against a bonus scorecard of measures across three categories: safety and sustainability, operations and
financials. These measures were aligned with our strategy and investor proposition as set out at the beginning of the year.
2024
annual bonus scorecard and outcome
|
|
|
|||||||
|
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 (MtCO
2
e)
|
38.2
|
35.5
|
32.8
|
15%
|
12.5%
|
|||||
|
Actual:
33.7
a
|
||||||||||
|
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
(
ou
t of 100%)
|
22.5%
|
|||||||||
|
Formulaic scorecard
outcome
22.5%
out of 100%
|
|
Application of framework
on fatalities
No reduction
(
see
page 98
)
|
|
Remuneration committee
judgement
No adjustment
|
|
22.5% out of 100%
|
a Operated carbon emissions for bonus calculation purposes (33.7MtCO
2
e) slightly differs from the figure reported elsewhere in the
bp Annual Report and Form 20-F 2024
(33.6MtCO
2
e) due to the timing of the
committee’s bonus outcome decision.
|
|
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, o
perated
carbon emissions of
33.7
MtCO
2
e 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 0.42MtCO
2
e 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
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 y
ear-on-
yea
r
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
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?
|
||||||||
|
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
|
|||||
|
|
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%
|
|||||||||
|
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.
|
||
|
|
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
|
2023
a
|
2024
|
2025
target
a
|
|
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
Thornton
s
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
target
b
|
|
$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
.
|
||
a
2023 excludes the acquisition of TravelCenters of America. The 2025 target represents the wider aim of achieving ~10% CAGR by 2030 (as set in 2023).
b
The
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 overal
l
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 outcom
e 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
change
a
|
|
|
Murray Auchincloss
|
937,500
|
704,790
|
£2,749,950
|
£-317,649
|
|
Kate Thomson
b
|
89,300
|
147,391
|
£575,090
|
£15,815
|
a
These 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.
b
Kate 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 a
nnual
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
«
.
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
|
||
|
|
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.
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.
|
|
|||||
|
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
|
ROACE
b
«
|
Adjusted free cash flow
CAGR
c
|
Cumulative reduction %
in operated carbon
emissions
d
|
Holistic review of progress
against strategy set out in
the Ca
pital 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.
a
Nil vesting for fifth place or lower.
b
Based 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.
d
Scope 1 and 2 GHG emission reductions vs. 2019 baseline from operated carbon emissions including portfolio change.
a
Nil vesting for fifth place or lower.
b
Based 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.
d
Scope 1 and 2 GHG emission reductions vs. 2019 baseline from operated carbon emissions including portfolio change.
|
|
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 progress
a
|
|||||||||||||||||||||||||||||||||||||||||||||
|
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
|
||||||||||||||||||||||||||||||||||||||||||||||||
a
Performance 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 MSR
b
|
Value of current
shareholding
c
, £
|
Multiple of
salary
achieved
|
|||||||||
|
Unvested awards not subject
to performance conditions
|
Unvested awards subject to
performance conditions
|
||||||||||||
|
Shares
a
|
Options
|
Shares
|
Options
|
||||||||||
|
Murray Auchincloss
d
|
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
|
|||||
a
Includes deferred and restricted shares, and performance shares prior to application of the performance factor.
b
Includes ordinary shares or equivalents and unvested awards not subject to performance conditions on a net-of-tax basis, excluding dividends.
c
Based on ordinary share price at 14 February 2025 of £4.68.
d
Includes 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 award
a
, £
|
Vesting date
|
|
|
Murray Auchincloss
|
2024-26 EDIP Performance
b
|
1,482,617
|
7 May 2024
|
7,472,390
|
May 2027
|
|
Kate Thomson
|
736,196
|
7 May 2024
|
3,710,428
|
May 2027
|
|
|
Murray Auchincloss
|
2024 EDIP Deferred
c
|
124,128
|
7 May 2024
|
625,605
|
May 2027
|
a
The 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).
b
Performance 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.
c
There 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.
|
|
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 Meyer
a
|
182
|
184
|
9
|
29
|
191
|
213
|
||
|
Tushar Morzaria
|
189
|
174
|
1
|
3
|
190
|
177
|
||
|
Hina Nagarajan
b
|
157
|
116
|
17
|
32
|
174
|
148
|
||
|
Satish Pai
b
|
144
|
116
|
5
|
39
|
149
|
155
|
||
|
Paula Rosput Reynolds
b
|
72
|
220
|
6
|
20
|
78
|
240
|
||
|
Karen Richardson
c
|
169
|
178
|
16
|
18
|
185
|
196
|
||
|
Sir John Sawers
b
|
57
|
174
|
12
|
7
|
68
|
181
|
||
|
Dr Johannes Teyssen
a
|
160
|
149
|
5
|
15
|
165
|
164
|
||
a
Fee 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.
b
Hina Nagarajan and Satish Pai were appointed on 1 March 2023. Paula Rosput Reynolds and Sir John Sawers retired on 25 April 2024.
c
Fee 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 equivalents
a
|
||||||
|
At 1 Jan
2024
|
At 31 Dec
2024
|
Changes to 14
Feb
2025
|
At 14 Feb
2025
|
Value of current
shareholding
b
|
% 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 Reynolds
c
|
78,378
|
—
|
—
|
—
|
—
|
—
|
|
Karen Richardson
|
29,316
|
35,316
|
—
|
35,316
|
$206,010
|
128%
|
|
Sir John Sawers
c
|
24,242
|
—
|
—
|
—
|
—
|
—
|
|
Dr Johannes Teyssen
|
35,000
|
35,000
|
—
|
35,000
|
£163,800
|
131%
|
a
Includes interests of persons closely associated.
b
Based 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.
c
Paula 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
investment
a
|
|||||||||||||||||||||
|
£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
|
||||||||||||||||||||||||
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
|
|
2020
a
|
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
|
|
2023
a,b
|
Bernard Looney
|
£1,175
|
n/a
|
n/a
|
|
Murray Auchincloss
|
£
5,391
|
79.5
|
75
|
|
|
2024
c
|
Murray Auchincloss
|
£
5,356
|
22.5
|
66.5
|
a
2020 and 2023 figures show remuneration for the periods of qualifying service as CEO during the respective years.
b
As 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.
c
Share price has been based on the average share price over Q4 of the 2024 FY of £3.90.
|
|
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)
|
|
2019
a
|
Option A
|
543:1
|
188:1
|
82:1
|
|
2020
a
|
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
|
|
2023
b
|
Option A
|
268:1
|
103:1
|
45:1
|
|
2024
c
|
Option A
|
196
:1
|
74
:1
|
37
:1
|
|
£
27,343
|
£
72,678
|
£
143,202
|
||
|
(£
25,304
)
|
(£
54,106
)
|
(£
92,900
)
|
a
Bob Dudley’s pay has been converted from US dollars as per the ratios reported in the
bp Annual Report and Form 20-F 2020
.
b
For 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.
c
Share 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 20
24 are shown below
.
|
Appointee
company
|
Additional position held at
appointee company
|
Total fees, £
|
|
|
Murray Auchincloss
a
|
Aker BP ASA
b
|
Director
|
0
|
|
Kate Thomson
|
Aker BP ASA
b
|
Director
|
0
|
a
Murray resigned from this position during 2024.
b
Held 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.
|
|
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
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
For information on board meetings held during
2024 and director attendance at board meetings,
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
|
–
|
–
|
–
|
–
|
–
|
|
112
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Independent auditor's reports (PCAOB ID
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Notes on financial statements
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1.
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Significant accounting policies
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22.
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Trade and other payables
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2.
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Non-current assets held for sale
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23.
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Provisions
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Business combinations
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24.
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Pensions and other post-employment
benefits
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Disposals and impairment
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5.
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Segmental analysis
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25.
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Cash and cash equivalents
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6.
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Sales and other operating revenues
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26.
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Finance debt
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7.
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Income statement analysis
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27.
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Capital disclosures and net debt
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8.
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Exploration for and evaluation of oil and
natural gas resources
|
28.
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Leases
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29.
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Financial instruments and financial risk
factors
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9.
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Taxation
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10.
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Dividends
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30.
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Derivative financial instruments
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11.
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Earnings per share
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31.
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Called-up share capital
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12.
|
Property, plant and equipment
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32.
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Capital and reserves
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13.
|
Capital commitments
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33.
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Contingent liabilities and legal proceedings
|
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|
14.
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Goodwill
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34.
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Remuneration of senior management and
non-executive directors
|
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15.
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Intangible assets
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16.
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Investments in joint ventures
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35.
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Employee costs and numbers
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17.
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Investments in associates
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36.
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Auditor's remuneration
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18.
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Other investments
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37.
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Subsidiaries, joint arrangements and
associates
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19.
|
Inventories
|
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|
20.
|
Trade and other receivables
|
38.
|
Events after the reporting period
|
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|
21.
|
Valuation and qualifying accounts
|
|||||||
|
Supplementary information on oil and natural gas (unaudited)
|
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|
Oil and natural gas exploration and production
activities
|
Standardized measure of discounted future net
cash flows and changes therein relating to proved
oil and gas reserves
|
|||||||
|
Movements in estimated net proved reserves
|
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|
Operational and statistical information
|
||||||||
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|
116
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Consolidated financial statements of the bp group
Pages 116-133
have been removed as they do not form part of bp's Annual Report on Form 20-F as filed with the SEC.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
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Financial statements
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Pages 116-133
have been removed as they do not form part of bp's Annual Report on Form 20-F as filed with the SEC.
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134
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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 i
s 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.
|
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|
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
6 March 2025
|
140
|
bp Annual Report and Form 20-F 2024
|
Group income statement
|
For the year ended 31 December
|
$ million
|
||||
|
|
Note
|
2024
|
2023
|
2022
|
|
|
Sales and other operating revenues
|
6
|
|
|
|
|
|
Earnings from joint ventures – after interest and tax
|
16
|
|
|
|
|
|
Earnings from associates – after interest and tax
|
17
|
|
|
|
|
|
Interest and other income
|
7
|
|
|
|
|
|
Gains on sale of businesses and fixed assets
|
4
|
|
|
|
|
|
Total revenues and other income
|
|
|
|
||
|
Purchases
|
19
|
|
|
|
|
|
Production and manufacturing expenses
|
|
|
|
||
|
Production and similar taxes
|
5
|
|
|
|
|
|
Depreciation, depletion and amortization
|
5
|
|
|
|
|
|
Net impairment and losses on sale of businesses and fixed assets
|
4
|
|
|
|
|
|
Exploration expense
|
8
|
|
|
|
|
|
Distribution and administration expenses
|
|
|
|
||
|
Profit (loss) before interest and taxation
|
|
|
|
||
|
Finance costs
|
7
|
|
|
|
|
|
Net finance (income) expense relating to pensions and other post-employment benefits
|
24
|
(
|
(
|
(
|
|
|
Profit (loss) before taxation
|
|
|
|
||
|
Taxation
|
9
|
|
|
|
|
|
Profit (loss) for the year
|
|
|
(
|
||
|
Attributable to
|
|||||
|
bp shareholders
|
|
|
(
|
||
|
Non-controlling interests
|
|
|
|
||
|
|
|
(
|
|||
|
Earnings per share
|
|||||
|
Profit (loss) for the year attributable to bp shareholders
|
|||||
|
Per ordinary share (cents)
|
|||||
|
Basic
|
11
|
|
|
(
|
|
|
Diluted
|
11
|
|
|
(
|
|
|
Per ADS (dollars)
|
|||||
|
Basic
|
11
|
|
|
(
|
|
|
Diluted
|
11
|
|
|
(
|
|
bp Annual Report and Form 20-F 2024
|
141
|
|
Financial statements
|
Group statement of comprehensive income
|
For the year ended 31 December
|
$ million
|
||||
|
Note
|
2024
|
2023
|
2022
|
||
|
Profit (loss) for the year
|
|
|
(
|
||
|
Other comprehensive income
|
|||||
|
Items that may be reclassified subsequently to profit or loss
|
|||||
|
Currency translation differences
a
|
(
|
|
(
|
||
|
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale of
businesses and fixed assets
a
|
|
(
|
|
||
|
Cash flow hedges marked to market
|
30
|
|
|
(
|
|
|
Cash flow hedges reclassified to the income statement
|
30
|
(
|
(
|
|
|
|
Costs of hedging marked to market
|
30
|
(
|
(
|
|
|
|
Costs of hedging reclassified to the income statement
|
30
|
(
|
(
|
|
|
|
Share of items relating to equity-accounted entities, net of tax
|
16, 17
|
(
|
(
|
|
|
|
Income tax relating to items that may be reclassified
|
9
|
|
(
|
(
|
|
|
(
|
|
|
|||
|
Items that will not be reclassified to profit or loss
|
|||||
|
Remeasurements of the net pension and other post-employment benefit liability or asset
|
24
|
(
|
(
|
|
|
|
Remeasurements of equity investments
|
(
|
|
|
||
|
Cash flow hedges that will subsequently be transferred to the balance sheet
|
30
|
(
|
|
(
|
|
|
Income tax relating to items that will not be reclassified
a
|
9
|
|
|
|
|
|
|
(
|
|
|||
|
Other comprehensive income
|
(
|
(
|
|
||
|
Total comprehensive income
|
|
|
|
||
|
Attributable to
|
|||||
|
bp shareholders
|
|
|
|
||
|
Non-controlling interests
|
|
|
|
||
|
|
|
|
a
See Note 32 for further information.
|
142
|
bp Annual Report and Form 20-F 2024
|
Group statement of changes in equity
a
|
$ million
|
||||||||||
|
Share
capital and
capital
reserves
|
Treasury
shares
|
Foreign
currency
translation
reserve
|
Fair value
reserves
|
Profit and
loss account
|
bp
shareholders'
equity
|
Non-controlling interests
|
Total equity
|
|||
|
Hybrid
bonds
|
Other
interest
|
|||||||||
|
At 1 January 2024
|
|
(
|
(
|
|
|
|
|
|
|
|
|
Profit for the year
|
—
|
—
|
—
|
—
|
|
|
|
|
|
|
|
Other comprehensive income
|
—
|
—
|
(
|
(
|
|
(
|
—
|
(
|
(
|
|
|
Total comprehensive income
|
—
|
—
|
(
|
(
|
|
|
|
|
|
|
|
Dividends
b
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
(
|
(
|
|
|
Cash flow hedges transferred to the balance
sheet, net of tax
|
—
|
—
|
—
|
(
|
—
|
(
|
—
|
—
|
(
|
|
|
Repurchase of ordinary share capital
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
—
|
(
|
|
|
Share-based payments, net of tax
|
|
|
—
|
—
|
(
|
|
—
|
—
|
|
|
|
Issue of perpetual hybrid bonds
|
—
|
—
|
—
|
—
|
(
|
(
|
|
—
|
|
|
|
Redemption of perpetual hybrid bonds, net of
tax
|
—
|
—
|
—
|
—
|
|
|
(
|
—
|
(
|
|
|
Payments on perpetual hybrid bonds
|
—
|
—
|
|
—
|
—
|
|
(
|
—
|
(
|
|
|
Transactions involving non-controlling interests,
net of tax
|
—
|
—
|
—
|
—
|
|
|
—
|
|
|
|
|
At 31 December 2024
|
|
(
|
(
|
(
|
|
|
|
|
|
|
|
At 1 January 2023
|
|
(
|
(
|
(
|
|
|
|
|
|
|
|
Profit for the year
|
—
|
—
|
—
|
—
|
|
|
|
|
|
|
|
Other comprehensive income
|
—
|
—
|
|
|
(
|
(
|
—
|
|
(
|
|
|
Total comprehensive income
|
—
|
—
|
|
|
|
|
|
|
|
|
|
Dividends
b
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
(
|
(
|
|
|
Cash flow hedges transferred to the balance
sheet, net of tax
|
—
|
—
|
—
|
(
|
—
|
(
|
—
|
—
|
(
|
|
|
Repurchase of ordinary share capital
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
—
|
(
|
|
|
Share-based payments, net of tax
|
|
|
—
|
—
|
(
|
|
—
|
—
|
|
|
|
Share of equity-accounted entities’ changes in
equity, net of tax
|
—
|
—
|
—
|
—
|
|
|
—
|
—
|
|
|
|
Issue of perpetual hybrid bonds
|
—
|
—
|
—
|
—
|
(
|
(
|
|
—
|
|
|
|
Payments on perpetual hybrid bonds
|
—
|
—
|
(
|
—
|
—
|
(
|
(
|
—
|
(
|
|
|
Transactions involving non-controlling interests,
net of tax
|
—
|
—
|
—
|
—
|
|
|
—
|
(
|
|
|
|
At 31 December 2023
|
|
(
|
(
|
|
|
|
|
|
|
|
|
At 1 January 2022
|
|
(
|
(
|
(
|
|
|
|
|
|
|
|
Profit for the year
|
—
|
—
|
—
|
—
|
(
|
(
|
|
|
(
|
|
|
Other comprehensive income
|
—
|
—
|
|
|
|
|
—
|
(
|
|
|
|
Total comprehensive income
|
—
|
—
|
|
|
(
|
|
|
|
|
|
|
Dividends
b
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
(
|
(
|
|
|
Cash flow hedges transferred to the balance
sheet, net of tax
|
—
|
—
|
—
|
|
—
|
|
—
|
—
|
|
|
|
Issue of ordinary share capital
|
|
—
|
—
|
—
|
—
|
|
—
|
—
|
|
|
|
Repurchase of ordinary share capital
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
—
|
(
|
|
|
Share-based payments, net of tax
|
|
|
—
|
—
|
|
|
—
|
—
|
|
|
|
Issue of perpetual hybrid bonds
|
—
|
—
|
—
|
—
|
(
|
(
|
|
—
|
|
|
|
Payments on perpetual hybrid bonds
|
—
|
—
|
|
—
|
—
|
|
(
|
—
|
(
|
|
|
Transactions involving non-controlling interests,
net of tax
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
(
|
(
|
|
|
At 31 December 2022
|
|
(
|
(
|
(
|
|
|
|
|
|
|
a
See
Note 32
for further information.
b
See
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
|
|
|
|
|
Goodwill
|
14
|
|
|
|
|
Intangible assets
|
15
|
|
|
|
|
Investments in joint ventures
|
16
|
|
|
|
|
Investments in associates
|
17
|
|
|
|
|
Other investments
|
18
|
|
|
|
|
Fixed assets
|
|
|
||
|
Loans
|
|
|
||
|
Trade and other receivables
|
20
|
|
|
|
|
Derivative financial instruments
|
30
|
|
|
|
|
Prepayments
|
|
|
||
|
Deferred tax assets
|
9
|
|
|
|
|
Defined benefit pension plan surpluses
|
24
|
|
|
|
|
|
|
|||
|
Current assets
|
||||
|
Loans
|
|
|
||
|
Inventories
|
19
|
|
|
|
|
Trade and other receivables
|
20
|
|
|
|
|
Derivative financial instruments
|
30
|
|
|
|
|
Prepayments
|
|
|
||
|
Current tax receivable
|
|
|
||
|
Other investments
|
18
|
|
|
|
|
Cash and cash equivalents
|
25
|
|
|
|
|
|
|
|||
|
Assets classified as held for sale
|
2
|
|
|
|
|
|
|
|||
|
Total assets
|
|
|
||
|
Current liabilities
|
||||
|
Trade and other payables
|
22
|
|
|
|
|
Derivative financial instruments
|
30
|
|
|
|
|
Accruals
|
|
|
||
|
Lease liabilities
|
28
|
|
|
|
|
Finance debt
|
26
|
|
|
|
|
Current tax payable
|
|
|
||
|
Provisions
|
23
|
|
|
|
|
|
|
|||
|
Liabilities directly associated with assets classified as held for sale
|
2
|
|
|
|
|
|
|
|||
|
Non-current liabilities
|
||||
|
Other payables
|
22
|
|
|
|
|
Derivative financial instruments
|
30
|
|
|
|
|
Accruals
|
|
|
||
|
Lease liabilities
|
28
|
|
|
|
|
Finance debt
|
26
|
|
|
|
|
Deferred tax liabilities
|
9
|
|
|
|
|
Provisions
|
23
|
|
|
|
|
Defined benefit pension plan and other post-employment benefit plan deficits
|
24
|
|
|
|
|
|
|
|||
|
Total liabilities
|
|
|
||
|
Net assets
|
|
|
||
|
Equity
|
||||
|
bp shareholders’ equity
|
32
|
|
|
|
|
Non-controlling interests
|
32
|
|
|
|
|
Total equity
|
32
|
|
|
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
|
|
|
|
||
|
Adjustments to reconcile profit before taxation to net cash provided by operating activities
|
|||||
|
Exploration expenditure written off
|
8
|
|
|
|
|
|
Depreciation, depletion and amortization
|
5
|
|
|
|
|
|
Impairment and (gain) loss on sale of businesses and fixed assets
|
4
|
|
|
|
|
|
Earnings from joint ventures and associates
|
(
|
(
|
(
|
||
|
Dividends received from joint ventures and associates
|
|
|
|
||
|
Remeasurement of joint ventures
|
3
|
(
|
|
|
|
|
Interest receivable
|
(
|
(
|
(
|
||
|
Interest received
|
|
|
|
||
|
Finance costs
|
7
|
|
|
|
|
|
Interest paid
|
(
|
(
|
(
|
||
|
Net finance expense relating to pensions and other post-employment benefits
|
24
|
(
|
(
|
(
|
|
|
Share-based payments
|
|
|
|
||
|
Net operating charge for pensions and other post-employment benefits, less contributions and
benefit payments for unfunded plans
|
24
|
(
|
(
|
(
|
|
|
Net charge for provisions, less payments
|
(
|
(
|
|
||
|
(Increase) decrease in inventories
|
|
|
(
|
||
|
(Increase) decrease in other current and non-current assets
|
|
|
(
|
||
|
Increase (decrease) in other current and non-current liabilities
|
(
|
(
|
|
||
|
Income taxes paid
|
(
|
(
|
(
|
||
|
Net cash provided by operating activities
|
|
|
|
||
|
Investing activities
|
|||||
|
Expenditure on property, plant and equipment, intangible and other assets
|
(
|
(
|
(
|
||
|
Acquisitions, net of cash acquired
|
3
|
|
(
|
(
|
|
|
Investment in joint ventures
|
(
|
(
|
(
|
||
|
Investment in associates
|
(
|
(
|
(
|
||
|
Total cash capital expenditure
|
(
|
(
|
(
|
||
|
Proceeds from disposals of fixed assets
|
4
|
|
|
|
|
|
Proceeds from disposals of businesses, net of cash disposed
|
4
|
|
|
|
|
|
Proceeds from loan repayments
|
|
|
|
||
|
Net cash used in investing activities
|
(
|
(
|
(
|
||
|
Financing activities
|
|||||
|
Repurchase of shares
|
(
|
(
|
(
|
||
|
Lease liability payments
|
(
|
(
|
(
|
||
|
Proceeds from long-term financing
|
|
|
|
||
|
Repayments of long-term financing
|
(
|
(
|
(
|
||
|
Net increase (decrease) in short-term debt
|
(
|
(
|
(
|
||
|
Issue of perpetual hybrid bonds
|
|
|
|
||
|
Redemption of perpetual hybrid bonds
|
32
|
(
|
|
|
|
|
Payments relating to perpetual hybrid bonds
|
(
|
(
|
(
|
||
|
Payments relating to transactions involving non-controlling interests (other)
|
(
|
(
|
(
|
||
|
Receipts relating to transactions involving non-controlling interests (other)
|
|
|
|
||
|
Dividends paid
|
|||||
|
bp shareholders
|
10
|
(
|
(
|
(
|
|
|
Non-controlling interests
|
(
|
(
|
(
|
||
|
Net cash provided by (used in) financing activities
|
(
|
(
|
(
|
||
|
Currency translation differences relating to cash and cash equivalents
|
(
|
|
(
|
||
|
Increase (decrease) in cash and cash equivalents
|
|
|
(
|
||
|
Cash and cash equivalents at beginning of year
|
|
|
|
||
|
Cash and cash equivalents at end of year
a
|
|
|
|
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
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.
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
$
before declining after 2030 to
$
cause oil prices to decline. The price assumptions for Henry Hub gas up to 2050 were held constant at
$
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
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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
£
gradually increasing to
£
However, as bp’s forecast future prices are producer prices, the group considers it reasonable to assume that if, in addition to the costs already in place,
further scope 1 and 2 emission costs were partially to be borne directly by oil and gas producers including bp in future and the prevalence of such costs
were to become widespread, the gross oil and gas prices realized by producers would be correspondingly higher over the long term, resulting in no
expected overall materially negative impacts on the group’s net cash flows. See significant judgements and estimates: recoverability of asset carrying
values for further information including sensitivity analysis in relation to reasonably possible changes in the price assumptions and carbon costs.
Production assumptions within upstream property, plant and equipment and goodwill value-in-use impairment tests reflect management’s current best
estimate of future production of the existing upstream portfolio. See significant judgements and estimates: recoverability of asset carrying values and
Note 14 for sensitivity analyses in relation to reasonably possible changes in production for upstream oil and gas properties and goodwill respectively.
For the customers & products segment, though the energy transition may impact demand for certain refined products in the future, management
anticipates sufficiently robust demand for the remainder of each refinery’s useful life.
Management will continue to review price assumptions as the energy transition progresses and this may result in impairment charges or reversals in the
future.
|
|
Exploration and appraisal intangible assets
|
|
The energy transition may affect the future development or viability of exploration prospects. The recoverability of the group's exploration and appraisal
intangible assets was considered during 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
$
equipment of
$
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.
|
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
Interests in other entities
Business combinations and goodwill
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
|
148
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bp Annual Report and Form 20-F 2024
|
1
.
Material accounting policy information, significant judgements, estimates and assumptions
– continued
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
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
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
|
bp Annual Report and Form 20-F 2024
|
149
|
|
Financial statements
|
1
.
Material accounting policy information, significant judgements, estimates and assumptions
– continued
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
.
In individual subsidiaries, joint ventures and associates, transactions
in foreign currencies are initially recorded in the functional currency of those entities
at the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated into the
functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange differences are included in the income statement
,
unless
hedge accounting is applied.
Non-monetary items, other than those measured at fair value, are not retranslated subsequent to initial recognition.
In the consolidated financial statements, the assets and liabilities of non-US dollar functional currency subsidiaries, joint ventures, associates, and related
goodwill, are translated into US dollars at the spot exchange rate on the balance sheet date. The results and cash flows of non-US dollar functional
currency subsidiaries, joint ventures and associates are translated into US dollars using average rates of exchange. In the consolidated financial
statements, exchange
adjustments arising when the opening net assets and the profits for the year retained by non-US dollar functional currency
subsidiaries, joint ventures and associates
are translated into US dollars are recognized in a separate component of equity and reported in other
comprehensive income.
Exchange gains and losses arising on long-term intra-group foreign currency borrowings used to finance the
group’s
non-US dollar
investments are also reported in other comprehensive income if the borrowings form part of the net investment in the subsidiary, joint venture or
associate. On disposal or for certain partial disposals of a non-US dollar functional currency subsidiary, joint venture or associate, the related accumulated
exchange gains and losses recognized in equity are reclassified from equity to the income statement.
Non-current assets and disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell.
Significant non-current assets and disposal groups are classified as held for sale if their carrying amounts will be recovered through a sale transaction
rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available for
immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets. Management must be committed to
the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification as held for sale, and
actions required to complete the plan of sale should indicate that it is unlikely that significant changes to the plan will be made or that the plan will be
withdrawn.
Property, plant and equipment and intangible assets are not depreciated or amortized, and equity accounting of associates and joint ventures is ceased
once classified as held for sale.
Intangible assets, other than goodwill, include expenditure on the exploration for and evaluation of oil and natural gas resources, biogas rights agreements,
digital assets, patents,
licences
and trademarks and are stated at the amount initially recognized, less accumulated amortization and accumulated
impairment losses.
Intangible assets are carried initially at cost unless acquired as part of a business combination. Any such asset is measured at fair value at the date of the
business combination and is recognized separately from goodwill if the asset is separable or arises from contractual or other legal rights.
Intangible assets with a finite life, other than capitalized exploration and appraisal costs as described below, are amortized on a straight-line basis over
their expected useful lives. For patents
, licences
and trademarks, expected useful life is the shorter of the duration of the legal agreement and economic
useful life, and can range from
three
to
fifteen years
. The expected useful life of biogas rights agreements is the shorter of the duration of the legal
agreement and economic useful life and can be up to
50
years
. Digital asset costs generally have a useful life of
three
to
five years
.
The expected useful lives of assets and the amortization method are reviewed on an annual basis and, if necessary, changes in useful lives or the
amortization method are accounted for prospectively.
Oil and natural gas exploration and appraisal expenditure
Oil and natural gas exploration and appraisal expenditure is accounted for using the principles of the successful efforts method of accounting as described
below.
Licence
and property acquisition costs
Exploration
licence
and leasehold property acquisition costs are capitalized within intangible assets and are reviewed at each reporting date to confirm
that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration drilling is still under
way or planned or that it has been determined, or work is under way to determine, that the discovery is economically viable based on a range of technical
and commercial considerations, and sufficient progress is being made on establishing development plans and timing. If no future activity is planned, the
remaining balance of the
licence
and property acquisition costs is written off. Lower value
licences
are pooled and amortized on a straight-line basis over
the estimated period of exploration. Upon internal approval for development and recognition of proved or sanctioned probable reserves of oil and natural
gas, the relevant expenditure is transferred to property, plant and equipment.
Geological and geophysical exploration costs are recognized as an expense as incurred. Costs directly associated with an exploration well are initially
capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration,
materials and fuel used, rig costs and payments made to contractors. If potentially commercial quantities of hydrocarbons are not found, the exploration
well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs
continue to be carried as an asset. If it is determined that development will not occur, that is, the efforts are not successful, then the costs are expensed
.
|
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 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
.
property, plant and equipment on initial recognition are as follows:
|
Land improvements
|
|
|
Buildings
|
|
|
Refineries
|
|
|
Pipelines
|
|
|
Service stations
|
|
|
Office equipment
|
|
|
Fixtures and fittings
|
|
|
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.
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.
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1
.
Material accounting policy information, significant judgements, estimates and assumptions
– continued
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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
renewable power assets. Where the CGU is located in a country that was judged to be higher risk, an additional premium of
post-tax discount rate (2023
economic and geopolitical factors. The pre-tax discount rate, other than for renewable power assets, typically ranged from
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
|
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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
$
headroom, based on the most recent impairment test performed in the year on those assets, was less than or equal to
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
$
barrel to reflect near term supply constraints before declining after 2030 to
$
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
$
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
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 ($/bbl)
|
|
|
|
|
||
|
Henry Hub gas ($/mmBtu)
|
|
|
|
|
|
2023 price assumptions
|
2024
|
2025
|
2030
|
2040
|
2050
|
|
|
Brent oil ($/bbl)
|
|
|
|
|
|
|
|
Henry Hub gas ($/mmBtu)
|
|
|
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|
|
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
$
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
$
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
$
higher. If the discount rate was one percentage point lower, the net impairment loss recognized would have been approximately
$
|
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154
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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 $
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
$
Castrol, Devon Energy, Reliance and Lightsource bp transactions. Of this,
$
hydrocarbon CGUs within the gas & low carbon energy segment (2023
$
sources of estimation uncertainty. Sensitivities and additional information relating to impairment testing of goodwill in these segments are provided in
Note 14.
|
Inventories, other than inventories held for short-term trading purposes, are stated at the lower of cost and net realizable value. Cost is typically determined
by the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses. Net realizable value
is determined by reference to prices existing at the balance sheet date, adjusted where the sale of inventories after the reporting period gives evidence
about their net realizable value at the end of the period.
Inventories held for short-term trading purposes are stated at fair value less costs to sell and any changes in fair value are recognized in the income
statement.
Supplies are valued at the lower of cost on a weighted-average basis and net realizable value.
Agreements that convey the right to control the use of an identified asset for a period of time in exchange for consideration are accounted for as leases.
The right to control is conveyed if
bp
has both the right to obtain substantially all of the economic benefits from, and the right to direct the use of, the
identified asset throughout the period of use. An asset is identified if it is explicitly or implicitly specified by the agreement and any substitution rights held
by the lessor over the asset are not considered substantive.
Agreements that convey the right to control the use of an intangible asset including rights to explore for or use hydrocarbons are not accounted for as
leases. See material accounting policy information: intangible assets.
A lease liability is recognized on the balance sheet on the lease commencement date at the present value of future lease payments over the lease term.
The discount rate applied is the rate implicit in the lease if readily determinable, otherwise an incremental borrowing rate is used. For the majority of the
leases in the
group,
there is not sufficient information available to readily determine the rate implicit in the lease, and therefore the incremental borrowing
rate is used. The incremental borrowing rate is determined based on factors such as the
group’s
cost of borrowing, lessee legal entity credit risk, currency
and lease term. The lease term is the non-cancellable period of a lease together with any periods covered by an extension option that
bp
is reasonably
certain to exercise, or periods covered by a termination option that
bp i
s 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.
|
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|
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 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
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|
1
.
Material accounting policy information, significant judgements, estimates and assumptions
– continued
Financial liabilities are recognized when
the group
becomes party to the contractual provisions of the instrument.
The group
derecognizes financial
liabilities when the obligation specified in the contract is discharged, cancelled or expired. The measurement of financial liabilities depends on their
classification, as follows:
Financial liabilities measured at fair value through profit or loss
Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are carried on
the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as effective hedging
instruments, are included in this category.
Derivatives designated as hedging instruments in an effective hedge
Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and losses
arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities.
Financial liabilities measured at amortized cost
All other financial liabilities are initially recognized at fair value, net of directly attributable transaction costs. For interest-bearing loans and borrowings this
is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing.
After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is
calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or
cancellation of liabilities are recognized in interest and other income and finance costs respectively.
This category of financial liabilities includes trade and other payables and finance debt.
|
Significant judgement: supplier financing arrangements
|
|
The group’s trade payables include some supplier financing arrangements that utilize letter of credit facilities, promissory notes and reverse factoring.
Judgement is required to assess the payables subject to these arrangements to determine whether they should continue to be classified as trade
payables and give rise to operating cash flows or finance debt and financing cash flows. The criteria used in making this assessment include the
payment terms for the amount due relative to terms commonly seen in the markets in which bp operates and whether the arrangements significantly
change the nature of the liability. Liabilities subject to these arrangements with payment terms of up to approximately 60 days are generally considered
to be trade payables and give rise to operating cash flows. See Note 29 - Liquidity risk for further information.
|
Financial guarantees
The group
issues financial guarantee contracts to make specified payments to reimburse holders for losses incurred if certain associates, joint ventures or
third-party entities fail to make payments when due in accordance with the original or modified terms of a debt instrument such as a loan.
The liability for a
financial guarantee contract is initially measured at fair value and subsequently measured at the higher of the contract’s estimated expected credit loss
and the amount initially recognized less, where appropriate, cumulative amortization.
Derivative financial instruments and hedging activities
The group
uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and
commodity prices, as well as for trading purposes. These derivative financial instruments are recognized initially at fair value on the date on which a
derivative contract is entered into and subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as
liabilities when the fair value is negative.
Contracts to buy or sell a non-financial item (for example, oil, oil products, gas or power) that can be settled net in cash, with the exception of contracts
that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the
group’s
expected
purchase, sale or usage requirements, are accounted for as financial instruments. Gains or losses arising from changes in the fair value of derivatives that
are not designated as effective hedging instruments are recognized in the income statement.
If, at inception of a contract, the valuation cannot be supported by observable market data, any gain or loss determined by the valuation methodology is
not recognized in the income statement but is deferred on the balance sheet and is commonly known as a ‘day-one gain or loss’. This deferred gain or loss
is recognized in the income statement over the life of the contract until substantially all the remaining contractual cash flows can be valued using
observable market data at which point any remaining deferred gain or loss is recognized in the income statement. Changes in valuation subsequent to the
initial valuation at inception of a contract are recognized immediately in the income statement.
For the purpose of hedge accounting, hedges are classified as:
•
Fair value hedges when hedging exposure to changes in the fair value of a recognized asset or liability.
•
Cash flow hedges when hedging exposure to variability in cash flows that is attributable to either a particular risk associated with a recognized asset or
liability or a highly probable forecast transaction.
Hedge relationships are formally designated and documented at inception, together with the risk management objective and strategy for undertaking the
hedge. The documentation includes identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the
existence at inception of an economic relationship and subsequent measurement of the hedging instrument's effectiveness in offsetting the exposure to
changes in the hedged item’s fair value or cash flows attributable to the hedged risk, the hedge ratio and sources of hedge ineffectiveness. Hedges
meeting the criteria for hedge accounting are accounted for as follows:
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.
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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
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.
|
Financial assets and liabilities are presented gross in the balance sheet unless both of the following criteria are met:
the group
currently has a legally
enforceable right to set off the recognized amounts; and
the group
intends to either settle on a net basis or realize the asset and settle the liability
simultaneously. A right of set off is
the group’s
legal right to settle an amount payable to a creditor by applying against it an amount receivable from the
same counterparty. The relevant legal jurisdiction and laws applicable to the relationships between the parties are considered when assessing whether a
current legally enforceable right to set off exists.
Provisions are recognized when the
group
has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of
resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.
Where appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability.
If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax risk-free rate that
reflects current market assessments of the time value of money. Where discounting is used, the increase in the provision due to the passage of time is
recognized within finance costs. Provisions are discounted using a nominal discount rate of
4.5
%
(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.
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158
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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.
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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
$
2024 (2023
$
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
(2023
weighted average period over which decommissioning and environmental costs are generally expected to be incurred is estimated to be approximately
(2023
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
$
the next 10 years,
$
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
decrease the group’s provision balances by approximately
$
credit of approximately
$
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
$
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
$
billion
(2023
$
the inflation rate applied to upstream decommissioning costs to determine the nominal cash flows could increase the decommissioning provision by
approximately
$
As described in Note 33, the group is subject to claims and actions for which no provisions have been recognized. The facts and circumstances relating
to particular cases are evaluated regularly in determining whether a provision relating to a specific litigation should be recognized or revised. Accordingly,
significant management judgement relating to provisions and contingent liabilities is required, since the outcome of litigation is difficult to predict.
|
Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services are
rendered by employees of the
group.
Deferred bonus arrangements that have a vesting date more than 12 months after the balance sheet date are valued
on an actuarial basis using the projected unit credit method and amortized on a straight-line basis over the service period until the award vests. The
material accounting policy information for pensions and other post-employment benefits are described below.
|
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bp Annual Report and Form 20-F 2024
|
1
.
Material accounting policy information, significant judgements, estimates and assumptions
– continued
The cost of providing benefits under the
group’s
defined benefit plans is determined separately for each plan using the projected unit credit method, which
attributes entitlement to benefits to the current period to determine current service cost and to the current and prior periods to determine the present value
of the defined benefit obligation. Past service costs, resulting from either a plan amendment or a curtailment (a reduction in future obligations as a result
of a material reduction in the plan membership), are recognized immediately when the company becomes committed to a change.
Net interest expense relating to pensions and other post-employment benefits, which is recognized in the income statement, represents the net change in
present value of plan obligations and the value of plan assets resulting from the passage of time, and is determined by applying the discount rate to the
present value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year, taking into account expected
changes in the obligation or plan assets during the year.
Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding amounts
included in net interest described above) are recognized within other comprehensive income in the period in which they occur and are not subsequently
reclassified to profit and loss.
The defined benefit pension plan surplus or deficit recognized on the balance sheet for each plan comprises the difference between the present value of
the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets out of which the obligations
are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price. Defined benefit
pension plan surpluses are only recognized to the extent they are recoverable, either by way of a refund from the plan or reductions in future contributions
to the plan.
Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.
|
Significant estimate: pensions and other post-employment benefits
|
|
Accounting for defined benefit pensions and other post-employment benefits involves making significant estimates when measuring the group's pension
plan surpluses and deficits. These estimates require assumptions to be made about many uncertainties.
Pensions and other post-employment benefit assumptions are reviewed by management at the end of each year. These assumptions are used to
determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the group's balance sheet and pension and
other post-employment benefit expense for the following year.
The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate and mortality levels. Assumptions about these
variables are based on the environment in each country. The assumptions used vary from year to year, with resultant effects on future net income and
net assets. Changes to some of these assumptions, in particular the discount rate and inflation rate, could result in material changes to the carrying
amounts of the group's pension and other post-employment benefit obligations within the next financial year. Any differences between these
assumptions and the actual outcome will also affect future net income and net assets.
The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and obligation
used are provided in Note 24.
|
Income tax expense represents the sum of current tax and deferred tax.
Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in
equity, in which case the related tax is recognized in other comprehensive income or directly in equity.
Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is determined
in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense that are taxable or
deductible in other periods as well as items that are never taxable or deductible. The
group’s
liability for current tax is calculated using tax rates and laws
that have been enacted or substantively enacted by the balance sheet date.
Deferred tax is provided, using the liability method, on temporary differences at the balance sheet date between the tax bases of assets and liabilities and
their carrying amounts for financial reporting purposes.
Deferred tax liabilities are recognized for all taxable temporary differences except:
•
Where the deferred tax liability arises on the initial recognition of goodwill.
•
Where the deferred tax liability arises on the initial recognition of an asset or liability in a transaction that is not a business combination, at the time of
the transaction, affects neither accounting profit nor taxable profit or loss and, at the time of the transaction, does not give rise to equal taxable and
deductible temporary differences.
•
In respect of taxable temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements, where the
group
is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the
foreseeable future.
Deferred tax assets are recognized for deductible temporary differences, carry-forward of unused tax credits and unused tax losses, to the extent that it is
probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax credits and unused
tax losses can be utilized, except where the deferred tax asset relating to the deductible temporary difference arises from the initial recognition of an asset
or liability in a transaction that is not a business combination, at the time of the transaction, affects neither accounting profit nor taxable profit or loss and,
at the time of the transaction, does not give rise to equal taxable and deductive temporary differences.
In respect of deductible temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements, deferred tax
assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be
available against which the temporary differences can be utilized.
The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable or increased to
the extent that it is probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilized.
|
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|
|
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 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.
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
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|
1
.
Material accounting policy information, significant judgements, estimates and assumptions
– continued
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 directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial
period of time to get ready for their intended use, are added to the cost of those assets until such time as the assets are substantially ready for their
intended use. All other finance costs are recognized in the income statement in the period in which they are incurred.
Impact of new International Financial Reporting Standards
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
.
are set out in the table below.
|
$ million
|
|||
|
2024
|
2023
|
||
|
Property, plant and equipment
|
|
|
|
|
Intangible assets
|
|
|
|
|
Investments in joint ventures
|
|
|
|
|
Loans
|
|
|
|
|
Cash
|
|
|
|
|
Trade and other receivables
|
|
|
|
|
Assets classified as held for sale
|
|
|
|
|
Trade and other payables
|
(
|
(
|
|
|
Lease liabilities
|
(
|
(
|
|
|
Finance debt
|
(
|
|
|
|
Provisions
|
(
|
(
|
|
|
Defined benefit pension plan and other post-employment benefit plan deficits
|
|
(
|
|
|
Liabilities directly associated with assets classified as held for sale
|
(
|
(
|
|
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
|
$ million
|
||||
|
|
2024
|
2023
|
2022
|
|
|
Gains on sale of businesses and fixed assets
|
||||
|
gas & low carbon energy
|
|
|
|
|
|
oil production & operations
|
|
|
|
|
|
customers & products
|
|
|
|
|
|
other businesses & corporate
|
|
|
|
|
|
|
|
|
||
|
|
$ million
|
|||
|
|
2024
|
2023
|
2022
|
|
|
Losses on sale of businesses and fixed assets, and closures
|
||||
|
gas & low carbon energy
|
|
|
|
|
|
oil production & operations
|
|
|
|
|
|
customers & products
|
|
|
|
|
|
other businesses & corporate
|
|
(
|
|
|
|
|
|
|
||
|
Impairment losses
|
||||
|
gas & low carbon energy
|
|
|
|
|
|
oil production & operations
|
|
|
|
|
|
customers & products
|
|
|
|
|
|
other businesses & corporate
|
|
|
|
|
|
|
|
|
||
|
Impairment reversals
|
||||
|
gas & low carbon energy
|
(
|
(
|
(
|
|
|
oil production & operations
|
(
|
(
|
(
|
|
|
customers & products
|
(
|
|
(
|
|
|
other businesses & corporate
|
(
|
(
|
|
|
|
(
|
(
|
(
|
||
|
Impairment and losses on sale of businesses and fixed assets, and closures
|
|
|
|
|
bp Annual Report and Form 20-F 2024
|
165
|
|
Financial statements
|
4
.
Disposals and impairment
– continued
Disposals
|
$ million
|
||||
|
2024
|
2023
|
2022
|
||
|
Proceeds from disposals of fixed assets
|
|
|
|
|
|
Proceeds from disposals of businesses, net of cash disposed
|
|
|
|
|
|
|
|
|
||
|
By business
|
||||
|
gas & low carbon energy
|
|
|
|
|
|
oil production & operations
|
|
|
|
|
|
customers & products
|
|
|
|
|
|
other businesses & corporate
|
|
|
|
|
|
|
|
|
Proceeds from disposals of businesses in 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 pri
ncipally 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
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
Non-current liabilities
|
(
|
(
|
(
|
|
|
Current liabilities
|
(
|
(
|
(
|
|
|
Total carrying amount of net assets disposed
|
|
|
|
|
|
Recycling of foreign exchange on disposal
|
|
|
(
|
|
|
Costs on disposal
|
|
|
|
|
|
|
|
|
||
|
Gains (losses) on sale of businesses
|
(
|
|
|
|
|
Total consideration
|
|
|
|
|
|
Non-cash consideration
|
(
|
(
|
(
|
|
|
Consideration received (receivable)
|
|
(
|
|
|
|
Proceeds from the sale of businesses, net of cash disposed
a
|
|
|
|
a
Proceeds 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. T
he 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 bioenergy
a
businesses.
Other businesses and corporate also comprises the group’s shipping and treasury functions, and corporate activities worldwide.
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 losses
b
.
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.
a
In February 2025 bp announced its intention to move its biogas business to the gas & low carbon energy segment.
b
Inventory 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.
|
168
|
bp Annual Report and Form 20-F 2024
|
5
.
Segmental analysis
– continued
|
$ million
|
|||||||
|
|
2024
|
||||||
|
By business
|
gas & low
carbon energy
|
oil production &
operations
|
customers &
products
|
other
businesses &
corporate
|
Consolidation
adjustment and
eliminations
|
Total
group
|
|
|
Segment revenues
|
|
|
|
|
|
||
|
Sales and other operating revenues
|
|
|
|
|
(
|
|
|
|
Less: sales and other operating revenues between segments
|
(
|
(
|
(
|
(
|
|
|
|
|
Third party sales and other operating revenues
|
|
|
|
|
|
|
|
|
Earnings from joint ventures and associates – after interest and
tax
|
|
|
|
(
|
|
|
|
|
Segment results
|
|||||||
|
Replacement cost profit (loss) before interest and taxation
|
|
|
(
|
(
|
(
|
|
|
|
Inventory holding gains (losses)
a
|
|
(
|
(
|
|
|
(
|
|
|
Profit (loss) before interest and taxation
|
|
|
(
|
(
|
(
|
|
|
|
Finance costs
|
(
|
||||||
|
Net finance income relating to pensions and other post-
employment benefits
|
|
||||||
|
Profit before taxation
|
|
||||||
|
Other income statement items
|
|||||||
|
Depreciation, depletion and amortization
|
|||||||
|
US
|
|
|
|
|
|
|
|
|
Non-US
|
|
|
|
|
|
|
|
|
Charges for provisions, net of write-back of unused provisions,
including change in discount rate
|
|
|
|
|
|
|
|
|
Segment assets
|
|||||||
|
Investments in joint ventures and associates
|
|
|
|
|
|
|
|
|
Additions to non-current assets
b
|
|
|
|
|
|
|
a
See explanation of inventory holding gains and losses on
page 167
.
b
Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
|
bp Annual Report and Form 20-F 2024
|
169
|
|
Financial statements
|
5
.
Segmental analysis
– continued
|
$ million
|
|||||||
|
|
|
|
|
2023
|
|||
|
By business
|
gas & low
carbon energy
|
oil production &
operations
|
customers &
products
|
other businesses
& corporate
|
Consolidation
adjustment and
eliminations
|
Total
group
|
|
|
Segment revenues
|
|
|
|
|
|||
|
Sales and other operating revenues
|
|
|
|
|
(
|
|
|
|
Less: sales and other operating revenues between segments
|
(
|
(
|
(
|
(
|
|
|
|
|
Third party sales and other operating revenues
|
|
|
|
|
|
|
|
|
Earnings from joint ventures and associates – after interest and
tax
|
(
|
|
|
(
|
|
|
|
|
Segment results
|
|
|
|
|
|||
|
Replacement cost profit (loss) before interest and taxation
|
|
|
|
(
|
(
|
|
|
|
Inventory holding gains (losses)
a
|
|
|
(
|
|
|
(
|
|
|
Profit (loss) before interest and taxation
|
|
|
|
(
|
(
|
|
|
|
Finance costs
|
(
|
||||||
|
Net finance income relating to pensions and other post-
employment benefits
|
|
|
|
|
|||
|
Profit before taxation
|
|
|
|
|
|||
|
Other income statement items
|
|
|
|
|
|||
|
Depreciation, depletion and amortization
|
|||||||
|
US
|
|
|
|
|
|
|
|
|
Non-US
|
|
|
|
|
|
|
|
|
Charges for provisions, net of write-back of unused provisions,
including change in discount rate
|
|
|
|
|
|
|
|
|
Segment assets
|
|
|
|
|
|||
|
Investments in joint ventures and associates
|
|
|
|
|
|
|
|
|
Additions to non-current assets
b
|
|
|
|
|
|
|
a
See explanation of inventory holding gains and losses on
page 167
.
b
Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
|
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
|
|
|
|
|
(
|
|
|
|
Less: sales and other operating revenues between segments
|
(
|
(
|
(
|
(
|
|
|
|
|
Third party sales and other operating revenues
|
|
|
|
|
|
|
|
|
Earnings from joint ventures and associates – after interest and
tax
|
|
|
|
|
|
|
|
|
Segment results
|
|||||||
|
Replacement cost profit (loss) before interest and taxation
|
|
|
|
(
|
|
|
|
|
Inventory holding gains (losses)
a
|
(
|
(
|
|
|
|
|
|
|
Profit (loss) before interest and taxation
|
|
|
|
(
|
|
|
|
|
Finance costs
|
(
|
||||||
|
Net finance income relating to pensions and other post-
employment benefits
|
|
||||||
|
Profit before taxation
|
|
||||||
|
Other income statement items
|
|
|
|
|
|||
|
Depreciation, depletion and amortization
|
|||||||
|
US
|
|
|
|
|
|
|
|
|
Non-US
|
|
|
|
|
|
|
|
|
Charges for provisions, net of write-back of unused provisions,
including change in discount rate
|
(
|
|
|
|
|
|
|
|
Segment assets
|
|||||||
|
Investments in joint ventures and associates
|
|
|
|
|
|
|
|
|
Additions to non-current assets
b
|
|
|
|
|
|
|
a
See explanation of inventory holding gains and losses on
page 167
.
b
Includes 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 revenues
a
|
|
|
|
|
|
Other income statement items
|
||||
|
Production and similar taxes
|
|
|
|
|
|
Non-current assets
|
||||
|
Non-current assets
b c
|
|
|
|
a
Non-US region includes UK
$
24,577
million
b
Non-US region includes UK
$
25,354
million
c
Includes 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 revenues
a
|
|
|
|
|
|
Other income statement items
|
||||
|
Production and similar taxes
|
|
|
|
|
|
Non-current assets
|
||||
|
Non-current assets
b c
|
|
|
|
a
Non-US region includes UK
$
39,975
million
.
b
Non-US region includes UK
$
23,949
million
.
c
Includes 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 revenues
a
|
|
|
|
|
|
Other income statement items
|
||||
|
Production and similar taxes
|
|
|
|
|
|
Non-current assets
|
||||
|
Non-current assets
b c
|
|
|
|
a
Non-US region includes UK
$
36,541
million
.
b
Non-US region includes UK
$
24,813
million
.
c
Includes 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
|
|
|
|
|
|
Oil products
|
|
|
|
|
|
Natural gas, LNG and NGLs
|
|
|
|
|
|
Non-oil products and other revenues from contracts with customers
|
|
|
|
|
|
Revenue from contracts with customers
|
|
|
|
|
|
Other operating revenues
a
|
|
|
|
|
|
Total sales and other operating revenues
|
|
|
|
a
Principally 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
|
|
|
|
|
|
Financial assets measured at fair value through profit or loss
|
|
|
|
|
|
Other income
a
|
|
|
|
|
|
|
|
|
||
|
Currency exchange losses charged to the income statement
b
|
|
|
|
|
|
Expenditure on research and development
|
|
|
|
|
|
Costs relating to the Gulf of America oil spill (pre-interest and tax)
c
|
|
|
|
|
|
Finance costs
|
||||
|
Interest expense on lease liabilities
|
|
|
|
|
|
Interest expense on other liabilities measured at amortized cost
d
|
|
|
|
|
|
Capitalized at
|
(
|
(
|
(
|
|
|
Finance debt risk management activities
f
|
|
(
|
|
|
|
Unwinding of discount on provisions
|
|
|
|
|
|
Unwinding of discount on other payables measured at amortized cost
|
|
|
|
|
|
|
|
|
a
2024 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.
b
Excludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss.
c
Included within production and manufacturing expenses.
d
2023
includes a loss of
$
49
million
and
2022
a gain of
$
37
million
associated with the buyback of finance debt.
e
Tax relief on capitalized interest is approximately
$
53
million
(
2023
$
130
million
and
2022
$
108
million
).
f
Includes
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
|
|
|
|
|
|
Other exploration costs
|
|
|
|
|
|
Exploration expense for the year
|
|
|
|
|
|
Impairment losses
|
|
|
|
|
|
Intangible assets – exploration and appraisal expenditure
a
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
Net assets
|
|
|
|
|
|
Cash used in operating activities
|
|
|
|
|
|
Cash used in investing activities
|
|
|
|
a
Amount 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
|
$ million
|
||||
|
|
2024
|
2023
|
2022
|
|
|
Current tax
|
||||
|
Charge for the year
a
|
|
|
|
|
|
Adjustment in respect of prior years
|
|
(
|
|
|
|
|
|
|
||
|
Deferred tax
|
||||
|
Origination and reversal of temporary differences in the current year
b
|
(
|
(
|
|
|
|
Adjustment in respect of prior years
c
|
(
|
(
|
(
|
|
|
(
|
(
|
|
||
|
Tax charge on profit
|
|
|
|
a
2024 includes a charge of
$
4
million
in respect of Pillar Two income taxes.
b
2024 includes a charge of
$
96
million
in respect of the
3% increase in the
UK Energy Profits Levy
from 1 November 2024 (see Note 1 for further information).
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.
c
The 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
Rosneft
a
|
2022
|
||
|
Profit (loss) before taxation
|
|
|
|
(
|
|
|
|
Tax charge (credit) on profit or loss
b
|
|
|
|
(
|
|
|
|
Effective tax rate
|
|
|
|
|
|
|
|
%
|
||||||
|
Tax rate computed at the weighted average statutory rate
c
|
|
|
|
|
|
|
|
Increase (decrease) resulting from
|
||||||
|
Tax reported in equity-accounted entities
|
(
|
(
|
(
|
|
(
|
|
|
Adjustments in respect of prior years
|
|
(
|
(
|
|
(
|
|
|
Deferred tax not recognized
|
|
|
(
|
|
(
|
|
|
Tax incentives for investment
|
(
|
|
|
|
(
|
|
|
Disposal impacts
d
|
|
|
(
|
|
(
|
|
|
Foreign exchange
|
|
|
|
|
|
|
|
Items not deductible for tax purposes
|
|
|
|
|
|
|
|
Impact of bp's decision to exit its shareholding in Rosneft
|
|
|
|
(
|
|
|
|
Tax rate change effect of UK Energy Profits Levy
e
|
|
|
|
|
|
|
|
Other
f
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
|
|
|
a
Includes the impact of bp's decision to exit its shareholding in Rosneft and its other businesses with Rosneft in Russia.
b
The tax credit regarding the impact of Rosneft relates to the release of deferred withholding tax on unremitted earnings.
c
Calculated 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.
d
2022 primarily relates to the contribution of bp's Angolan business to Azule Energy.
e
2024 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
.
f
Includes 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
|
|
|
|
|
Exchange adjustments
|
|
|
|
|
Charge (credit) for the year in the income statement
|
(
|
(
|
|
|
Charge (credit) for the year in other comprehensive income
|
(
|
(
|
|
|
Charge (credit) for the year in equity
|
|
|
|
|
Acquisitions and disposals
|
|
|
|
|
At 31 December
|
|
|
|
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
|
(
|
(
|
|
|
|
|
|
Pension plan surpluses
a
|
|
|
|
|
|
|
|
Derivative financial instruments
|
|
|
(
|
|
|
|
|
Other taxable temporary differences
b
|
(
|
|
(
|
|
|
|
|
(
|
(
|
|
|
|
||
|
Deferred tax asset
|
||||||
|
Depreciation
|
(
|
(
|
(
|
(
|
(
|
|
|
Lease liabilities
|
(
|
(
|
(
|
(
|
(
|
|
|
Pension plan and other post-employment benefit plan deficits
|
|
(
|
|
(
|
(
|
|
|
Decommissioning, environmental and other provisions
|
|
|
|
(
|
(
|
|
|
Derivative financial instruments
|
(
|
(
|
(
|
(
|
(
|
|
|
Tax credits
|
(
|
(
|
|
(
|
(
|
|
|
Loss carry forward
|
|
|
|
(
|
(
|
|
|
Other deductible temporary differences
c
|
(
|
|
(
|
(
|
(
|
|
|
(
|
|
|
(
|
(
|
||
|
Net deferred tax charge (credit) and net deferred tax liability
|
(
|
(
|
|
|
|
|
|
Of which – deferred tax liabilities
|
|
|
||||
|
– deferred tax assets
|
|
|
||||
a
The 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%.
b
The 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.
c
The 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.
below.
|
$ billion
|
|||
|
At 31 December
|
2024
|
2023
|
|
|
Unused US state tax losses
a
|
|
|
|
|
Unused tax losses – other jurisdictions
b
|
|
|
|
|
Unused tax credits
|
|
|
|
|
of which – arising in the UK
c
|
|
|
|
|
– arising in the US
d
|
|
|
|
|
Deductible temporary differences
e
|
|
|
|
|
Taxable temporary differences associated with investments in subsidiaries and equity-accounted entities
|
|
|
a
For 2024 the majority of the unused tax losses have no fixed expiry date.
b
2024 and 2023 mainly relate to the UK, Brazil and Canada. The majority of the unused tax losses have no fixed expiry date.
c
The 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.
d
The 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.
e
2024 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
|
|
|
|
|
|
Deferred tax benefit arising from the reversal of a previous write-down of deferred tax assets
|
|
|
|
|
|
Deferred tax benefit relating to the recognition of previously unrecognized deferred tax assets
|
|
|
|
|
|
Deferred tax expense arising from the write-down of a previously recognized deferred tax asset
|
|
|
|
|
bp Annual Report and Form 20-F 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
|
|
|
|
|||||||
|
Ordinary shares
|
||||||||||
|
March
|
|
|
|
|
|
|
|
|
|
|
|
June
|
|
|
|
|
|
|
|
|
|
|
|
September
|
|
|
|
|
|
|
|
|
|
|
|
December
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Dividend announced, paid in March 2025
|
|
|
||||||||
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
|
|
|
(
|
|
|
Diluted earnings per share
|
|
|
(
|
|
|
|
|
Dollars per share
|
||
|
Per American Depositary Share (ADS)
a
|
2024
|
2023
|
2022
|
|
|
Basic earnings per share
|
|
|
(
|
|
|
Diluted earnings per share
|
|
|
(
|
|
a
One 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
|
|
|
(
|
|
|
Less: dividend requirements on preference shares
|
|
|
|
|
|
Less: (gain) loss on redemption of perpetual hybrid bonds
a
|
(
|
|
|
|
|
Profit (loss) for the year attributable to bp ordinary shareholders
|
|
|
(
|
|
|
|
|
|
Shares thousand
|
|
|
|
2024
|
2023
|
2022
|
|
|
Basic weighted average number of ordinary shares
b
|
|
|
|
|
|
Potential dilutive effect of ordinary shares issuable under employee share-based payment plans
|
|
|
|
|
|
Weighted average number of ordinary shares outstanding used to calculate diluted earnings per
share
|
|
|
|
|
|
|
|
|
Shares thousand
|
|
|
|
2024
|
2023
|
2022
|
|
|
Basic weighted average number of ordinary shares – ADS equivalent
|
|
|
|
|
|
Potential dilutive effect of ordinary shares (ADS equivalent) issuable under employee share-based
payment plans
|
|
|
|
|
|
Weighted average number of ordinary shares (ADS equivalent) outstanding used to calculate
diluted earnings per share
|
|
|
|
a
See Note 32 -
non-controlling interests
for further information.
b
Excludes 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
.
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 options
a b
thousand
|
Weighted average
exercise price $
|
Number of options
a b
thousand
|
Weighted average
exercise price $
|
||
|
Outstanding
|
|
|
|
|
|
|
Exercisable
|
|
|
|
|
|
|
Dilutive effect
|
|
n/a
|
|
n/a
|
a
Numbers of options shown are ordinary share equivalents (one ADS is equivalent to
six
ordinary shares).
b
At
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 shares
a
|
Number of shares
a
|
||
|
Vesting
|
thousand
|
thousand
|
|
|
Within one year
|
|
|
|
|
1 to 2 years
|
|
|
|
|
2 to 3 years
|
|
|
|
|
3 to 4 years
|
|
|
|
|
Over 4 years
|
|
|
|
|
|
|
||
|
Dilutive effect
|
|
|
a
Numbers 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
properties
a
|
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
|
|
|
|
|
|
|
|
|
|
|
Exchange adjustments
|
(
|
(
|
|
(
|
(
|
(
|
(
|
(
|
|
|
Additions
|
|
|
|
|
|
|
|
|
|
|
Acquisitions
|
|
|
|
|
|
|
|
|
|
|
Transfers from intangible assets
|
|
|
|
|
|
|
|
|
|
|
Reclassified as assets held for sale
|
(
|
(
|
(
|
(
|
(
|
|
|
(
|
|
|
Deletions and disposals
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
At 31 December 2024
|
|
|
|
|
|
|
|
|
|
|
Depreciation - owned PP&E
|
|||||||||
|
At 1 January 2024
|
|
|
|
|
|
|
|
|
|
|
Exchange adjustments
|
(
|
(
|
|
(
|
(
|
(
|
(
|
(
|
|
|
Charge for the year
|
|
|
|
|
|
|
|
|
|
|
Impairment losses
|
|
|
|
|
|
|
|
|
|
|
Impairment reversals
|
|
|
(
|
(
|
|
(
|
|
(
|
|
|
Reclassified as assets held for sale
|
(
|
(
|
(
|
(
|
(
|
|
|
(
|
|
|
Deletions and disposals
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
At 31 December 2024
|
|
|
|
|
|
|
|
|
|
|
Owned PP&E - net book amount at 31 December
2024
|
|
|
|
|
|
|
|
|
|
|
Right-of-use assets - net book amount at 31
December 2024
b
|
|
|
|
|
|
|
|
|
|
|
Total PP&E - net book amount at 31 December 2024
|
|
|
|
|
|
|
|
|
|
|
Cost - owned PP&E
|
|||||||||
|
At 1 January 2023
|
|
|
|
|
|
|
|
|
|
|
Exchange adjustments
|
|
|
|
|
|
|
|
|
|
|
Additions
|
|
|
|
|
|
|
|
|
|
|
Acquisitions
|
|
|
|
|
|
|
|
|
|
|
Transfers from intangible assets
|
|
|
|
|
|
|
|
|
|
|
Reclassified as assets held for sale
|
(
|
|
|
(
|
(
|
(
|
(
|
(
|
|
|
Deletions and disposals
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
At 31 December 2023
|
|
|
|
|
|
|
|
|
|
|
Depreciation - owned PP&E
|
|||||||||
|
At 1 January 2023
|
|
|
|
|
|
|
|
|
|
|
Exchange adjustments
|
|
|
|
|
|
|
|
|
|
|
Charge for the year
|
|
|
|
|
|
|
|
|
|
|
Impairment losses
|
|
|
|
|
|
|
|
|
|
|
Impairment reversals
|
|
|
(
|
|
|
(
|
|
(
|
|
|
Reclassified as assets held for sale
|
(
|
|
|
(
|
(
|
(
|
(
|
(
|
|
|
Deletions and disposals
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
At 31 December 2023
|
|
|
|
|
|
|
|
|
|
|
Owned PP&E - net book amount at 31 December
2023
|
|
|
|
|
|
|
|
|
|
|
Right-of-use assets - net book amount at 31
December 2023
b
|
|
|
|
|
|
|
|
|
|
|
Total PP&E - net book amount at 31 December 2023
|
|
|
|
|
|
|
|
|
|
|
Assets under construction included above
|
|||||||||
|
At 31 December 2024
|
|
||||||||
|
At 31 December 2023
|
|
||||||||
|
Depreciation charge for the year on right-of-use assets
|
|||||||||
|
2024
|
|
|
|
|
|
|
|
||
|
2023
|
|
|
|
|
|
|
|
a
For 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 expendit
ure 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
14
.
Goodwill and impairment review of goodwill
|
$ million
|
|||
|
2024
|
2023
|
||
|
Cost
|
|||
|
At 1 January
|
|
|
|
|
Exchange adjustments
|
(
|
|
|
|
Acquisitions and other additions
|
|
|
|
|
Reclassified as assets held for sale
|
(
|
|
|
|
Deletions and disposals
|
(
|
|
|
|
At 31 December
|
|
|
|
|
Impairment losses
|
|||
|
At 1 January
|
|
|
|
|
Exchange adjustments
|
(
|
|
|
|
Impairment losses for the year
|
|
|
|
|
Deletions and disposals
|
(
|
|
|
|
At 31 December
|
|
|
|
|
Net book amount at 31 December
|
|
|
|
|
Net book amount at 1 January
|
|
|
Impairment review of goodwill
|
$ million
|
|||
|
Goodwill at 31 December
|
2024
|
2023
|
|
|
gas & low carbon energy
|
|
|
|
|
oil production & operations
|
|
|
|
|
customers & products
|
|
|
|
|
other businesses & corporate
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
||
|
Excess of recoverable amount over carrying amount
|
|
|
|
|
|
|
|
|
||
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.
|
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
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
|
|
|
|
|
|
|
|
|
|
|
|
|
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 followi
ng 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
expenditure
a
|
Biogas rights
agreements
|
Other
intangibles
|
Total
|
Exploration
and appraisal
expenditure
a
|
Biogas rights
agreements
|
Other
intangibles
|
Total
|
||
|
Cost
|
|||||||||
|
At 1 January
|
|
|
|
|
|
|
|
|
|
|
Exchange adjustments
|
|
|
(
|
(
|
|
|
|
|
|
|
Acquisitions
b
|
|
|
|
|
|
|
|
|
|
|
Remeasurements of acquisition accounting
c
|
|
|
|
|
|
(
|
|
(
|
|
|
Additions
|
|
|
|
|
|
|
|
|
|
|
Transfers to property, plant and equipment
|
(
|
|
|
(
|
(
|
|
|
(
|
|
|
Reclassified as assets held for sale
|
(
|
|
(
|
(
|
|
|
(
|
(
|
|
|
Deletions and disposals
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
At 31 December
|
|
|
|
|
|
|
|
|
|
|
Amortization
|
|||||||||
|
At 1 January
|
|
|
|
|
|
|
|
|
|
|
Exchange adjustments
|
|
|
(
|
(
|
|
|
|
|
|
|
Exploration expenditure written off
|
|
|
|
|
|
|
|
|
|
|
Charge for the year
|
|
|
|
|
|
|
|
|
|
|
Impairment losses
|
|
|
|
|
|
|
|
|
|
|
Impairment reversals
|
(
|
|
|
(
|
|
|
|
|
|
|
Reclassified as assets held for sale
|
|
|
(
|
(
|
|
|
(
|
(
|
|
|
Deletions and disposals
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
At 31 December
|
|
|
|
|
|
|
|
|
|
|
Net book amount at 31 December
|
|
|
|
|
|
|
|
|
|
|
Net book amount at 1 January
|
|
|
|
|
|
|
|
|
a
For further information see Intangible assets within
Note 1
and
Note 8
.
b
2024 primarily relates to the acquisition of GETEC ENERGIE GmbH.
16
.
Investments in joint ventures
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
|
|
|
|
|
|
|
|
Pan American Energy Group
|
|
|
|
|
|
|
|
Other joint ventures
a
|
|
(
|
|
|
|
|
|
|
|
|
|
|
||
a
2024 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
|
|
|
|
|
||
|
Profit (loss) before interest and taxation
|
|
|
|
|
||
|
Finance costs
|
|
|
|
|
||
|
Profit (loss) before taxation
a
|
|
|
|
|
||
|
Taxation
|
|
|
|
|
||
|
Profit (loss) for the year
|
|
|
|
|
||
|
Other comprehensive income
|
|
|
|
|
||
|
Total comprehensive income
|
|
|
|
|
||
|
Non-current assets
|
|
|
||||
|
Current assets
b
|
|
|
||||
|
Total assets
|
|
|
||||
|
Current liabilities
c
|
|
|
||||
|
Non-current liabilities
d
|
|
|
||||
|
Total liabilities
|
|
|
||||
|
Net assets
|
|
|
||||
|
Less: non-controlling interests
|
|
|
||||
|
|
|
a
A
zule 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
.
b
Azule Energy includes cash and cash equivalents of
$
570
million
(
2023
$
603
million
).
c
Azule Energy includes current financial liabilities of
$
3,417
million
(
2023
$
2,409
million
).
d
Azule 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
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit (loss) before interest and taxation
|
|
(
|
|
|
|
|
|
|
|
|
|
|
Finance costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit (loss) before taxation
|
|
(
|
|
|
(
|
|
|
|
|
|
|
|
Taxation
|
|
(
|
(
|
|
|
|
|
|
|
|
|
|
Non-controlling interest
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit (loss) for the year
|
|
|
|
|
(
|
|
|
|
|
|
|
|
Other comprehensive income
|
|
(
|
(
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
(
|
|
|
|
|
|
|
|
Non-current assets
|
|
|
|
|
|
|
|||||
|
Current assets
|
|
|
|
|
|
|
|||||
|
Total assets
|
|
|
|
|
|
|
|||||
|
Current liabilities
|
|
|
|
|
|
|
|||||
|
Non-current liabilities
|
|
|
|
|
|
|
|||||
|
Total liabilities
|
|
|
|
|
|
|
|||||
|
Net assets
|
|
|
|
|
|
|
|||||
|
Less: non-controlling interests
|
|
(
|
(
|
|
(
|
(
|
|||||
|
|
|
|
|
|
|
||||||
|
Group investment in joint ventures
|
|||||||||||
|
Group share of net assets (as above)
|
|
|
|
|
|
|
|||||
|
Cumulative impairment charge
|
|
(
|
(
|
|
(
|
(
|
|||||
|
Loans made by group companies to joint ventures
|
|
(
|
(
|
|
(
|
(
|
|||||
|
|
|
|
|
|
|
|
182
|
bp Annual Report and Form 20-F 2024
|
16
.
Investments in joint ventures
– continued
|
$ 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
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
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
17
.
Investments in associates
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
|
|
|
|
|
|
|
|
Other associates
|
|
|
|
|
|
|
|
|
|
|
|
|
||
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
|
$ million
|
||||
|
bp share
|
||||
|
2024
|
2023
|
2022
|
||
|
Sales and other operating revenues
|
|
|
|
|
|
Profit before interest and taxation
|
|
|
|
|
|
Finance costs
|
|
|
|
|
|
Profit (loss) before taxation
|
|
|
|
|
|
Taxation
|
|
|
|
|
|
Non-controlling interests
|
|
|
|
|
|
Profit (loss) for the year
|
|
|
|
|
|
Other comprehensive income
|
(
|
(
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
Non-current assets
|
|
|
||
|
Current assets
|
|
|
||
|
Total assets
|
|
|
||
|
Current liabilities
|
|
|
||
|
Non-current liabilities
|
|
|
||
|
Total liabilities
|
|
|
||
|
Net assets
|
|
|
||
|
Less: non-controlling interests
|
|
|
||
|
|
|
|||
|
Group investment in associates
|
||||
|
Group share of net assets (as above)
|
|
|
||
|
Loans made by group companies to associates
|
|
|
||
|
|
|
|
$ 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
|
|
|
|
|
|
|
|
|
$ 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
|
|
|
|
|
|
|
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, 2
023 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 investments
a
|
|
|
|
|
|
|
Contingent consideration
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
a
The 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
|
|
|
|
|
Natural gas
|
|
|
|
|
Emissions allowances
|
|
|
|
|
Refined petroleum and petrochemical products
|
|
|
|
|
|
|
||
|
Trading inventories
|
|
|
|
|
Supplies
|
|
|
|
|
Biological assets
|
|
|
|
|
Solar projects
|
|
|
|
|
|
|
||
|
Cost of inventories expensed in the income statement
|
|
|
The inventory valuation at
31 December 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
|
|
|
|
|
|
|
Amounts receivable from joint ventures and associates
|
|
|
|
|
|
|
Other receivables
|
|
|
|
|
|
|
|
|
|
|
||
|
Non-financial assets
|
|||||
|
Sales taxes and production taxes
|
|
|
|
|
|
|
Other receivables
|
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
Charged to costs and expenses
|
(
|
|
|
|
|
|
|
|
Charged to other accounts
a
|
(
|
|
|
(
|
(
|
(
|
|
|
Deductions
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
Reclassifications
|
|
|
|
|
|
(
|
|
|
At 31 December
|
|
|
|
|
|
|
a
Principally 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
|
|
|
|
|
|
|
Amounts payable to joint ventures and associates
|
|
|
|
|
|
|
Payables for capital expenditure and acquisitions
|
|
|
|
|
|
|
Payables related to the Gulf of America oil spill
|
|
|
|
|
|
|
Other payables
|
|
|
|
|
|
|
|
|
|
|
||
|
Non-financial liabilities
|
|||||
|
Sales taxes, customs duties, production taxes and social security
|
|
|
|
|
|
|
Other payables
|
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
Materially all of bp's trade payables have payment terms of less than 60 days and give rise to operating cash flows.
Trade and other payables, other than those relating to the Gulf of America oil spill, are predominantly interest free. See
Note 29
(c) for further information.
Payables related to the Gulf of America oil spill include amounts payable under the 2016 consent decree and settlement agreement with the United States
and
five
Gulf coast states, including amounts payable for natural resource damages, state claims and Clean Water Act penalties. On a discounted basis the
amounts included in payables related to the Gulf of America oil spill for these elements of the agreements are
$
3,450
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
|
Other
c
|
Total
|
||
|
At 1 January 2024
|
|
|
|
|
|
|
|
|
Exchange adjustments
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
Acquisitions
|
|
|
|
|
|
|
|
|
New and increase in existing provisions
a
|
|
|
|
|
|
|
|
|
Write-back of unused provisions
a
|
|
(
|
(
|
(
|
(
|
(
|
|
|
Unwinding of discount
b
|
|
|
|
|
|
|
|
|
Change in discount rate
|
(
|
(
|
(
|
|
(
|
(
|
|
|
Utilization
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
Reclassified to other payables
|
(
|
(
|
|
|
(
|
(
|
|
|
Reclassified as liabilities directly associated with
assets held for sale
|
(
|
|
|
|
(
|
(
|
|
|
Deletions
|
(
|
(
|
|
|
(
|
(
|
|
|
At 31 December 2024
|
|
|
|
|
|
|
|
|
Of which – current
|
|
|
|
|
|
|
|
|
– non-current
|
|
|
|
|
|
|
a
Recognized in the
G
roup income statement, other than changes in decommissioning provisions related to owned assets.
b
Recognized in the Group income statement
c
Other 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
|
|||||||
|
2024
|
2023
|
2022
|
2024
|
2023
|
2022
|
2024
|
2023
|
2022
|
||
|
Discount rate for plan liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Rate of increase for pensions in payment
|
|
|
|
|
|
|
|
|
|
|
|
Rate of increase in deferred pensions
|
|
|
|
|
|
|
|
|
|
|
|
Inflation for plan liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
%
|
|
|
Financial assumptions used to determine benefit expense
|
UK
|
US
|
Eurozone
|
|||||||
|
2024
|
2023
|
2022
|
2024
|
2023
|
2022
|
2024
|
2023
|
2022
|
||
|
Discount rate for plan service cost
a
|
N/A
|
N/A
|
N/A
|
|
|
|
|
|
|
|
|
Discount rate for plan other finance expense
|
|
|
|
|
|
|
|
|
|
|
|
Inflation for plan service cost
a
|
N/A
|
N/A
|
N/A
|
|
|
|
|
|
|
a
UK 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
|
|
|
|
|
|
|
|
|
|
|
|
Life expectancy at age 60 for a male currently
aged 40
|
|
|
|
|
|
|
|
|
|
|
|
Life expectancy at age 60 for a female currently
aged 60
|
|
|
|
|
|
|
|
|
|
|
|
Life expectancy at age 60 for a female currently
aged 40
|
|
|
|
|
|
|
|
|
|
Pension plan assets are generally held in trusts, the primary objective of which is to accumulate assets sufficient to meet the obligations of the plans. The
assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio management.
A proportion of the assets are held in equities, which are expected to generate a higher level of return over the long term, with an acceptable level of risk. In
order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the investment portfolios
are highly diversified.
The trustee’s long-term investment objective for the primary UK defined benefit plan 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.
|
UK
|
US
|
||
|
Asset category
|
%
|
%
|
|
|
Total equity (including private equity)
|
|
|
|
|
Bonds/cash (including LDI)
|
|
|
|
|
Property/real estate
|
|
|
|
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.
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
|
||||||
|
|
UK
a
|
US
b
|
Eurozone
|
Other
|
Total
|
|
|
Fair value of pension plan assets
|
||||||
|
At 31 December 2024
|
||||||
|
Listed equities – developed markets
|
|
|
|
|
|
|
|
– emerging markets
|
|
|
|
|
|
|
|
Private equity
c
|
|
|
|
|
|
|
|
Government issued nominal bonds
d
|
|
|
|
|
|
|
|
Government issued index-linked bonds
d
|
|
|
|
|
|
|
|
Corporate bonds
d
|
|
|
|
|
|
|
|
Property
e
|
|
|
|
|
|
|
|
Cash
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
Debt (repurchase agreements) used to fund liability driven investments
|
(
|
|
|
|
(
|
|
|
|
|
|
|
|
||
|
At 31 December 2023
|
||||||
|
Listed equities – developed markets
|
|
|
|
|
|
|
|
– emerging markets
|
|
|
|
|
|
|
|
Private equity
c
|
|
|
|
|
|
|
|
Government issued nominal bonds
d
|
|
|
|
|
|
|
|
Government issued index-linked bonds
d
|
|
|
|
|
|
|
|
Corporate bonds
d
|
|
|
|
|
|
|
|
Property
e
|
|
|
|
|
|
|
|
Cash
|
|
|
|
|
|
|
|
Other
f
|
|
|
|
|
|
|
|
Debt (repurchase agreements) used to fund liability driven investments
|
(
|
|
|
|
(
|
|
|
|
|
|
|
|
||
|
At 31 December 2022
|
||||||
|
Listed equities – developed markets
|
|
|
|
|
|
|
|
– emerging markets
|
|
|
|
|
|
|
|
Private equity
c
|
|
|
|
|
|
|
|
Government issued nominal bonds
d
|
|
|
|
|
|
|
|
Government issued index-linked bonds
d
|
|
|
|
|
|
|
|
Corporate bonds
d
|
|
|
|
|
|
|
|
Property
e
|
|
|
|
|
|
|
|
Cash
|
|
|
|
|
|
|
|
Other
f
|
|
|
|
|
|
|
|
Debt (repurchase agreements) used to fund liability driven investments
|
(
|
|
|
|
(
|
|
|
|
|
|
|
|
a
Bonds 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.
b
Bonds held by the US pension plans are denominated in US dollars or hedged back to USD to minimize foreign currency exposure.
c
Private 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.
d
Bonds held by pension plans are predominantly valued using observable market data based inputs other than quoted market prices in active markets.
e
Properties 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.
|
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 cost
a
|
|
|
|
|
|
|
|
Past service cost
b
|
|
|
(
|
|
(
|
|
|
Settlement
b
|
(
|
|
|
|
(
|
|
|
Operating charge (credit) relating to defined benefit plans
|
|
|
|
|
|
|
|
Payments to defined contribution plans
|
|
|
|
|
|
|
|
Total operating charge (credit)
|
|
|
|
|
|
|
|
Interest income on plan assets
a
|
(
|
(
|
(
|
(
|
(
|
|
|
Interest on plan liabilities
|
|
|
|
|
|
|
|
Other finance (income) expense
|
(
|
|
|
|
(
|
|
|
Analysis of the amount recognized in other comprehensive income
|
||||||
|
Actual asset return less interest income on plan assets
|
(
|
(
|
|
|
(
|
|
|
Change in financial assumptions underlying the present value of the plan liabilities
|
|
|
|
(
|
|
|
|
Change in demographic assumptions underlying the present value of the plan liabilities
|
|
(
|
|
|
|
|
|
Experience gains and losses arising on the plan liabilities
|
|
(
|
|
(
|
(
|
|
|
Remeasurements recognized in other comprehensive income
|
(
|
|
|
|
(
|
|
|
Movements in benefit obligation during the year
|
||||||
|
Benefit obligation at 1 January
|
|
|
|
|
|
|
|
Exchange adjustments
|
(
|
|
(
|
(
|
(
|
|
|
Operating charge relating to defined benefit plans
|
|
|
|
|
|
|
|
Interest cost
|
|
|
|
|
|
|
|
Contributions by plan participants
|
|
|
|
|
|
|
|
Benefit payments (funded plans)
c
|
(
|
(
|
(
|
(
|
(
|
|
|
Benefit payments (unfunded plans)
c
|
(
|
(
|
(
|
(
|
(
|
|
|
Disposals
|
|
|
|
(
|
(
|
|
|
Remeasurements
|
(
|
(
|
(
|
|
(
|
|
|
Benefit obligation at 31 December
a d
|
|
|
|
|
|
|
|
Movements in fair value of plan assets during the year
|
||||||
|
Fair value of plan assets at 1 January
|
|
|
|
|
|
|
|
Exchange adjustments
|
(
|
|
(
|
(
|
(
|
|
|
Interest income on plan assets
a e
|
|
|
|
|
|
|
|
Contributions by plan participants
|
|
|
|
|
|
|
|
Contributions by employers (funded plans)
|
|
|
|
|
|
|
|
Benefit payments (funded plans)
c
|
(
|
(
|
(
|
(
|
(
|
|
|
Remeasurements
e
|
(
|
(
|
|
|
(
|
|
|
Fair value of plan assets at 31 December
f
|
|
|
|
|
|
|
|
Surplus (deficit) at 31 December
|
|
(
|
(
|
(
|
|
|
|
Represented by
|
||||||
|
Asset recognized
|
|
|
|
|
|
|
|
Liability recognized
|
(
|
(
|
(
|
(
|
(
|
|
|
|
(
|
(
|
(
|
|
||
|
The surplus (deficit) may be analysed between funded and unfunded plans as follows
|
||||||
|
Funded
|
|
|
|
|
|
|
|
Unfunded
|
(
|
(
|
(
|
(
|
(
|
|
|
|
(
|
(
|
(
|
|
||
|
The defined benefit obligation may be analysed between funded and unfunded plans as follows
|
||||||
|
Funded
|
(
|
(
|
(
|
(
|
(
|
|
|
Unfunded
|
(
|
(
|
(
|
(
|
(
|
|
|
(
|
(
|
(
|
(
|
(
|
a
The 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.
b
Past service costs predominantly reflect minor plan changes in France. Settlements represent changes in small worldwide plans administered and reported throughout the UK.
c
The 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.
d
The 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.
e
The 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.
f
The 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 cost
a
|
|
|
|
|
|
|
|
Past service cost
b
|
|
|
|
(
|
|
|
|
Settlement
b
|
|
|
|
|
|
|
|
Operating charge (credit) relating to defined benefit plans
|
|
|
|
|
|
|
|
Payments to defined contribution plans
|
|
|
|
|
|
|
|
Total operating charge (credit)
|
|
|
|
|
|
|
|
Interest income on plan assets
a
|
(
|
(
|
(
|
(
|
(
|
|
|
Interest on plan liabilities
|
|
|
|
|
|
|
|
Other finance (income) expense
|
(
|
|
|
|
(
|
|
|
Analysis of the amount recognized in other comprehensive income
|
||||||
|
Actual asset return less interest income on plan assets
|
(
|
|
|
|
(
|
|
|
Change in financial assumptions underlying the present value of the plan liabilities
|
(
|
|
(
|
(
|
(
|
|
|
Change in demographic assumptions underlying the present value of the plan liabilities
|
(
|
(
|
|
|
(
|
|
|
Experience gains and losses arising on the plan liabilities
|
(
|
|
(
|
(
|
(
|
|
|
Remeasurements recognized in other comprehensive income
|
(
|
|
(
|
|
(
|
|
|
Movements in benefit obligation during the year
|
||||||
|
Benefit obligation at 1 January
|
|
|
|
|
|
|
|
Exchange adjustments
|
|
|
|
|
|
|
|
Operating charge relating to defined benefit plans
|
|
|
|
|
|
|
|
Interest cost
|
|
|
|
|
|
|
|
Contributions by plan participants
|
|
|
|
|
|
|
|
Benefit payments (funded plans)
c
|
(
|
(
|
(
|
(
|
(
|
|
|
Benefit payments (unfunded plans)
c
|
(
|
(
|
(
|
(
|
(
|
|
|
Reclassified as assets held for sale
|
|
|
|
(
|
(
|
|
|
Remeasurements
|
|
(
|
|
|
|
|
|
Benefit obligation at 31 December
a d
|
|
|
|
|
|
|
|
Movements in fair value of plan assets during the year
|
||||||
|
Fair value of plan assets at 1 January
|
|
|
|
|
|
|
|
Exchange adjustments
|
|
|
|
|
|
|
|
Interest income on plan assets
a e
|
|
|
|
|
|
|
|
Contributions by plan participants
|
|
|
|
|
|
|
|
Contributions by employers (funded plans)
|
|
|
|
|
|
|
|
Benefit payments (funded plans)
c
|
(
|
(
|
(
|
(
|
(
|
|
|
Remeasurements
e
|
(
|
|
|
|
(
|
|
|
Fair value of plan assets at 31 December
f
|
|
|
|
|
|
|
|
Surplus (deficit) at 31 December
|
|
(
|
(
|
(
|
|
|
|
Represented by
|
||||||
|
Asset recognized
|
|
|
|
|
|
|
|
Liability recognized
|
(
|
(
|
(
|
(
|
(
|
|
|
|
(
|
(
|
(
|
|
||
|
The surplus (deficit) may be analysed between funded and unfunded plans as follows
|
||||||
|
Funded
|
|
|
|
|
|
|
|
Unfunded
|
(
|
(
|
(
|
(
|
(
|
|
|
|
(
|
(
|
(
|
|
||
|
The defined benefit obligation may be analysed between funded and unfunded plans as follows
|
||||||
|
Funded
|
(
|
(
|
(
|
(
|
(
|
|
|
Unfunded
|
(
|
(
|
(
|
(
|
(
|
|
|
(
|
(
|
(
|
(
|
(
|
a
The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of
administering other post-employment benefit plans are included in the benefit obligation. Following the closure of the primary UK pension plan, current service cost in the UK consists of
$
34
million
of
costs of administering that plan and
$
10
million
of current service cost from the remaining small worldwide plans administered and reported through the UK.
b
Past 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.
c
The 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.
d
The 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.
e
The 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.
f
The 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 cost
a
|
|
|
|
|
|
|
|
Past service cost
b
|
|
|
(
|
(
|
|
|
|
Settlement
b
|
(
|
|
|
(
|
(
|
|
|
Operating charge (credit) relating to defined benefit plans
|
|
|
|
|
|
|
|
Payments to defined contribution plans
|
|
|
|
|
|
|
|
Total operating charge (credit)
|
|
|
|
|
|
|
|
Interest income on plan assets
a
|
(
|
(
|
(
|
(
|
(
|
|
|
Interest on plan liabilities
|
|
|
|
|
|
|
|
Other finance (income) expense
|
(
|
|
|
|
(
|
|
|
Analysis of the amount recognized in other comprehensive income
|
||||||
|
Actual asset return less interest income on plan assets
|
(
|
(
|
(
|
(
|
(
|
|
|
Change in financial assumptions underlying the present value of the plan liabilities
|
|
|
|
|
|
|
|
Change in demographic assumptions underlying the present value of the plan liabilities
|
|
|
(
|
(
|
|
|
|
Experience gains and losses arising on the plan liabilities
|
(
|
(
|
(
|
(
|
(
|
|
|
Remeasurements recognized in other comprehensive income
|
(
|
|
|
|
|
a
The 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
$
30
million
of
costs of administering that plan and
$
11
million
of current service cost from the remaining small worldwide plans administered and reported through the UK.
b
Past 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 rate
a
|
|||||||
|
Effect on expense in 2025
|
(
|
|
(
|
|
(
|
|
|
|
Effect on obligation at 31 December 2024
|
(
|
|
(
|
|
(
|
|
|
|
Inflation rate
b
|
|||||||
|
Effect on expense in 2025
|
|
(
|
|
(
|
|
(
|
|
|
Effect on obligation at 31 December 2024
|
|
(
|
|
(
|
|
(
|
|
a
The amounts presented reflect that the discount rate is used to determine the asset interest income as well as the interest cost on the obligation.
b
The 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
|
|
|
|
|
|
Effect on obligation at 31 December 2024
|
|
|
|
|
Estimated future benefit payments and the weighted average duration of defined benefit obligations
defined benefit obligations at
31 December 2024
are as follows:
|
$ million
|
||||||
|
Estimated future benefit payments
|
UK
|
US
|
Eurozone
|
Other
|
Total
|
|
|
2025
|
|
|
|
|
|
|
|
2026
|
|
|
|
|
|
|
|
2027
|
|
|
|
|
|
|
|
2028
|
|
|
|
|
|
|
|
2029
|
|
|
|
|
|
|
|
2030 - 2034
|
|
|
|
|
|
|
|
|
Years
|
|||||
|
Weighted average duration
|
|
|
|
|
|
bp Annual Report and Form 20-F 2024
|
193
|
|
Financial statements
|
25
.
Cash and cash equivalents
|
$ million
|
|||
|
2024
|
2023
|
||
|
Cash
|
|
|
|
|
Triparty repos and term bank deposits
|
|
|
|
|
Other cash equivalents
|
|
|
|
|
|
|
Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; deposits and triparty repos of three months or less
with banks and similar institutions; money market funds and treasury bills. The carrying amounts of cash, triparty repos, term bank deposits and treasury
bills approximate their fair values. Substantially all of the other cash equivalents are categorized within level 1 of the fair value hierarchy.
Cash and cash equivalents at
31 December 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
|
|
|
|
|
|
|
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.
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
|
|
|
|
|
|
|
|
|
Other currencies
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
2023
|
|||||||
|
US dollar
|
|
|
|
|
|
|
|
|
Other currencies
|
|
|
|
|
|
|
|
|
|
|
|
|||||
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.
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
|
|
|
|
|
|
|
Long-term borrowings
|
|
|
|
|
|
|
Total finance debt
|
|
|
|
|
|
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.
|
$ million
|
|||
|
At 31 December
|
2024
|
2023
|
|
|
Finance debt
|
|
|
|
|
Less: fair value asset (liability) of hedges related to finance debt
a
|
(
|
(
|
|
|
|
|
||
|
Less: cash and cash equivalents
|
|
|
|
|
Net debt
|
|
|
|
|
Total equity
|
|
|
|
|
Gearing
|
|
|
a
Derivative financial instruments entered into for the purpose of managing
foreign currency exchange risk associated with net debt with a fair value
liability
position of
$
166
million
(
2023
liability
of
$
73
Certain subsidiaries in the group have externally imposed capital requirements and have been in compliance with these requirements throughout the year.
|
$ million
|
||||||
|
Finance
debt
|
Currency
swaps
a
|
Lease liabilities
|
Net partner
payable for
leases entered
into on behalf of
joint operations
|
Total liabilities
arising from
financing
activities
|
||
|
At 1 January 2024
|
|
|
|
|
|
|
|
Exchange adjustments
|
(
|
|
(
|
(
|
(
|
|
|
Net financing cash flow
|
|
(
|
(
|
(
|
|
|
|
Fair value (gains) losses
|
(
|
|
|
|
|
|
|
New and remeasured leases/joint operations payables
|
|
|
|
|
|
|
|
Other movements
b
|
|
|
|
(
|
|
|
|
At 31 December 2024
|
|
|
|
|
|
|
|
At 1 January 2023
|
|
|
|
|
|
|
|
Exchange adjustments
|
|
|
|
|
|
|
|
Net financing cash flow
|
|
(
|
(
|
(
|
|
|
|
Fair value (gains) losses
|
|
(
|
|
|
(
|
|
|
New and remeasured leases/joint operations payables
|
|
|
|
|
|
|
|
Other movements
c
|
|
(
|
|
(
|
|
|
|
At 31 December 2023
|
|
|
|
|
|
a
Currency swaps include cross currency interest rate swaps.
b
I
ncludes
$
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.
c
Includes
$
545
million
of finance debt acquired as part of the TravelCenters of Ameri
ca 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.
|
$ million
|
|||
|
2024
|
2023
|
||
|
Undiscounted lease liability cash flows due:
|
|||
|
Within 1 year
|
|
|
|
|
1 to 2 years
|
|
|
|
|
2 to 3 years
|
|
|
|
|
3 to 4 years
|
|
|
|
|
4 to 5 years
|
|
|
|
|
5 to 10 years
|
|
|
|
|
Over 10 years
|
|
|
|
|
|
|
||
|
Impact of discounting
|
(
|
(
|
|
|
Lease liabilities at 31 December
|
|
|
|
|
Of which – current
|
|
|
|
|
– non-current
|
|
|
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
|
|
|
|
|
Expense for variable payments not included in the lease liability
a
|
|
|
|
|
Short-term lease expense
a
|
|
|
|
|
Additions to right-of-use assets in the period
|
|
|
29
.
Financial instruments and financial risk factors
|
$ million
|
|||||||
|
At 31 December 2024
|
Note
|
Measured at
amortized cost
|
Mandatorily
measured at fair
value through
profit or loss
|
Derivative
hedging
instruments
|
Total carrying
amount
|
||
|
Financial assets
|
|||||||
|
Other investments
|
18
|
|
|
—
|
|
||
|
Loans
|
|
|
—
|
|
|||
|
Trade and other receivables
|
20
|
|
—
|
—
|
|
||
|
Derivative financial instruments
|
30
|
—
|
|
|
|
||
|
Cash and cash equivalents
|
25
|
|
|
—
|
|
||
|
Financial liabilities
|
|||||||
|
Trade and other payables
|
22
|
(
|
—
|
—
|
(
|
||
|
Derivative financial instruments
|
30
|
—
|
(
|
(
|
(
|
||
|
Accruals
|
(
|
—
|
—
|
(
|
|||
|
Lease liabilities
|
28
|
(
|
—
|
—
|
(
|
||
|
Finance debt
|
26
|
(
|
—
|
—
|
(
|
||
|
(
|
|
(
|
(
|
|
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
|
|
|
—
|
|
||
|
Loans
|
|
|
—
|
|
|||
|
Trade and other receivables
|
20
|
|
—
|
—
|
|
||
|
Derivative financial instruments
|
30
|
—
|
|
|
|
||
|
Cash and cash equivalents
|
25
|
|
|
—
|
|
||
|
Financial liabilities
|
|||||||
|
Trade and other payables
|
22
|
(
|
—
|
—
|
(
|
||
|
Derivative financial instruments
|
30
|
—
|
(
|
(
|
(
|
||
|
Accruals
|
(
|
—
|
—
|
(
|
|||
|
Lease liabilities
|
28
|
(
|
—
|
—
|
(
|
||
|
Finance debt
|
26
|
(
|
—
|
—
|
(
|
||
|
(
|
|
(
|
(
|
The fair value of finance debt is shown in
Note 26
. For all other financial instruments within the scope of IFRS 9, the carrying amount is either the fair value,
or approximates the fair value.
Information on gains and losses on derivative financial assets and financial liabilities classified as measured at fair value through profit or loss is provided
in the derivative gains and losses section of
Note 30
. Fair value gains and losses related to other assets and liabilities classified as measured at fair value
through profit or loss totalled a net 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.
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-
|
|
|
|
|
A+ to A-
|
|
|
|
|
BBB+ to BBB-
|
|
|
|
|
BB+ to BB-
|
|
|
|
|
B+ to B-
|
|
|
|
|
CCC+ and below
|
|
|
Movements in the impairment provision for trade and other receivables are shown in
Note 21
.
|
bp Annual Report and Form 20-F 2024
|
199
|
|
Financial statements
|
29
.
Financial instruments and financial risk factors
– continued
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
|
Master
netting
arrangements
|
Cash
collateral
(received)
pledged
|
|||||
|
Derivative assets
|
|
(
|
|
(
|
(
|
|
|
|
Derivative liabilities
|
(
|
|
(
|
|
|
(
|
|
|
Trade and other receivables
|
|
(
|
|
(
|
(
|
|
|
|
Trade and other payables
|
(
|
|
(
|
|
|
(
|
|
|
At 31 December 2023
|
|||||||
|
Derivative assets
|
|
(
|
|
(
|
(
|
|
|
|
Derivative liabilities
|
(
|
|
(
|
|
|
(
|
|
|
Trade and other receivables
|
|
(
|
|
(
|
(
|
|
|
|
Trade and other payables
|
(
|
|
(
|
|
|
(
|
|
(c) Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the group’s business activities may not be available. The group’s liquidity is managed centrally
with operating units forecasting their cash and currency requirements to the central treasury function. Unless restricted by local regulations, generally
subsidiaries pool their cash surpluses to the treasury function, which will then arrange to fund other subsidiaries’ requirements, or invest any net surplus in
the market or arrange for necessary external borrowings, while managing the group’s overall net currency positions. While there is the potential for
concerns about the energy transition to impact banks’ or debt investors’ appetite to finance hydrocarbon activity, we do not anticipate any material change
to the group's funding or liquidity in the short to medium term as a result of such concerns.
T
he 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 s
elects 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
|
2024
|
||||
|
Letters of Credit
|
Promissory
Notes
|
Reverse
Factoring
Arrangements
|
||
|
Carrying amount of liabilities ($ million)
|
||||
|
Presented within trade and other payables
a
|
|
|
|
|
|
of which suppliers have received payment from the financial institution
b
|
|
|
|
|
|
Range of payment due dates (days)
|
||||
|
Liabilities that are part of the arrangement
b
|
|
|
|
|
|
Trade payables that are not part of the arrangement
|
|
|
|
a
Letters 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.
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
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
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
payables
a
|
Accruals
|
Finance
debt
|
Interest on
finance debt
|
Trade and
other
payables
a
|
Accruals
|
Finance
debt
|
Interest on
finance debt
|
||
|
Within one year
|
|
|
|
|
|
|
|
|
|
|
1 to 2 years
|
|
|
|
|
|
|
|
|
|
|
2 to 3 years
|
|
|
|
|
|
|
|
|
|
|
3 to 4 years
|
|
|
|
|
|
|
|
|
|
|
4 to 5 years
|
|
|
|
|
|
|
|
|
|
|
5 to 10 years
|
|
|
|
|
|
|
|
|
|
|
Over 10 years
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
a
2024
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.
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 to 2 years
|
|
|
|
|
2 to 3 years
|
|
|
|
|
3 to 4 years
|
|
|
|
|
4 to 5 years
|
|
|
|
|
5 to 10 years
|
|
|
|
|
Over 10 years
|
|
|
|
|
|
|
|
For further information on our derivative financial instruments, see
Note 30
.
30
.
Derivative financial instruments
In the ordinary course of business
the group
enters into derivative financial instruments (derivatives) to manage its normal business exposures in relation
to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating rate and fixed rate debt,
consistent with its risk management policies and objectives. An outline of
the group’s
financial risks and the objectives and policies pursued in relation to
those risks is set out in
Note 29
. Additionally, the group
has a well-established entrepreneurial trading operation that is undertaken in conjunction with
these activities using a similar range of contracts.
For information on significant estimates and judgements made in relation to the valuation of derivatives see Derivative financial instruments within
Note 1
.
Exchange traded derivatives are valued using closing prices provided by the exchange as at the balance sheet date. These derivatives are categorized
within level 1 of the fair value hierarchy. Exchange traded derivatives are typically considered settled through the (normally daily) payment or receipt of
variation margin.
Over-the-counter (OTC) financial swaps, forwards and physical commodity sale and purchase contracts are generally valued using readily available
information in the public markets and quotations provided by brokers and price index developers. These quotes are corroborated with market data and are
categorized within level 2 of the fair value hierarchy.
In certain less liquid markets, or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC financial swaps and
physical commodity sale and purchase contracts are valued using internally developed methodologies that consider historical relationships between
various commodities, and that result in management’s best estimate of fair value. These contracts are categorized within level 3 of the fair value hierarchy.
|
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
|
|
(
|
|
(
|
|
|
Oil price derivatives
|
|
(
|
|
(
|
|
|
Natural gas price derivatives
|
|
(
|
|
(
|
|
|
Power price derivatives
|
|
(
|
|
(
|
|
|
Other derivatives
|
|
(
|
|
|
|
|
|
(
|
|
(
|
||
|
Cash flow hedges
|
|||||
|
Currency forwards
|
|
|
|
(
|
|
|
|
|
|
(
|
||
|
Fair value hedges
|
|||||
|
Currency swaps
|
|
(
|
|
(
|
|
|
Interest rate swaps
|
|
(
|
|
(
|
|
|
|
(
|
|
(
|
||
|
|
(
|
|
(
|
||
|
Of which – current
|
|
(
|
|
(
|
|
|
– non-current
|
|
(
|
|
(
|
Derivatives held for trading
The group
maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to satisfy supply
requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original business objective, and are
recognized at fair value with changes in fair value recognized in the income statement. Trading activities are undertaken by using a range of contract types
in combination to create incremental gains by arbitraging prices between markets, locations and time periods. The net of these exposures is monitored
using market value-at-risk techniques as described in
Note 29
.
The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes.
|
$ million
|
||||||||
|
2024
|
||||||||
|
Less than
1 year
|
1-2 years
|
2-3 years
|
3-4 years
|
4-5 years
|
Over
5 years
|
Total
|
||
|
Currency derivatives
|
|
|
|
|
|
|
|
|
|
Oil price derivatives
|
|
|
|
|
|
|
|
|
|
Natural gas price derivatives
|
|
|
|
|
|
|
|
|
|
Power price derivatives
|
|
|
|
|
|
|
|
|
|
Other derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
$ million
|
||||||||
|
2023
|
||||||||
|
Less than
1 year
|
1-2 years
|
2-3 years
|
3-4 years
|
4-5 years
|
Over
5 years
|
Total
|
||
|
Currency derivatives
|
|
|
|
|
|
|
|
|
|
Oil price derivatives
|
|
|
|
|
|
|
|
|
|
Natural gas price derivatives
|
|
|
|
|
|
|
|
|
|
Power price derivatives
|
|
|
|
|
|
|
|
|
|
Other derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
bp Annual Report and Form 20-F 2024
|
203
|
|
Financial statements
|
30
.
Derivative financial instruments
– continued
|
$ million
|
||||||||
|
2024
|
||||||||
|
Less than
1 year
|
1-2 years
|
2-3 years
|
3-4 years
|
4-5 years
|
Over
5 years
|
Total
|
||
|
Currency derivatives
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
Oil price derivatives
|
(
|
(
|
(
|
(
|
(
|
|
(
|
|
|
Natural gas price derivatives
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
Power price derivatives
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
Other derivatives
|
(
|
(
|
|
(
|
|
|
(
|
|
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
||
|
$ million
|
||||||||
|
2023
|
||||||||
|
Less than
1 year
|
1-2 years
|
2-3 years
|
3-4 years
|
4-5 years
|
Over
5 years
|
Total
|
||
|
Currency derivatives
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
Oil price derivatives
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
Natural gas price derivatives
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
Power price derivatives
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
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
|
|
|
|
|
|
|
|
|
|
Level 2
|
|
|
|
|
|
|
|
|
|
Level 3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Less: netting by counterparty
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
|
|
|
|
|
|
|
||
|
Fair value of derivative liabilities
|
||||||||
|
Level 1
|
(
|
(
|
(
|
(
|
|
|
(
|
|
|
Level 2
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
Level 3
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
||
|
Less: netting by counterparty
|
|
|
|
|
|
|
|
|
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
||
|
Net fair value
|
|
(
|
|
|
(
|
|
|
|
|
|
$ million
|
|||||||
|
|
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
|
|
|
|
|
|
|
|
|
|
Level 2
|
|
|
|
|
|
|
|
|
|
Level 3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Less: netting by counterparty
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
|
|
|
|
|
|
|
||
|
Fair value of derivative liabilities
|
||||||||
|
Level 1
|
(
|
(
|
(
|
(
|
|
|
(
|
|
|
Level 2
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
Level 3
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
||
|
Less: netting by counterparty
|
|
|
|
|
|
|
|
|
|
(
|
(
|
(
|
(
|
(
|
(
|
(
|
||
|
Net fair value
|
|
|
(
|
|
|
|
|
|
204
|
bp Annual Report and Form 20-F 2024
|
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
|
|
|
(
|
|
|
|
|
|
Gains (losses) recognized in the income statement
|
(
|
(
|
|
(
|
|
(
|
|
|
Purchases
|
|
|
|
|
|
|
|
|
Settlements
|
(
|
(
|
(
|
(
|
|
(
|
|
|
Transfers out of level 3
|
(
|
(
|
|
|
|
|
|
|
Net fair value of contracts at 31 December 2024
|
|
|
(
|
|
|
|
|
|
Deferred day-one gains (losses)
|
|
||||||
|
Derivative asset (liability)
|
|
||||||
|
$ million
|
|||||||
|
Oil
price
|
Natural gas
price
|
Power
price
|
Currency
|
Other
|
Total
|
||
|
Fair value contracts at 1 January 2023
|
|
|
(
|
|
|
|
|
|
Gains (losses) recognized in the income statement
|
|
|
|
|
|
|
|
|
Settlements
|
|
(
|
|
(
|
(
|
(
|
|
|
Transfers out of level 3
|
(
|
(
|
(
|
|
|
(
|
|
|
Net fair value of contracts at 31 December 2023
|
|
|
(
|
|
|
|
|
|
Deferred day-one gains (losses)
|
|
||||||
|
Derivative asset (liability)
|
|
The amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at
31 December 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.
|
$ 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
|
|
(
|
|
|
|
At 31 December 2023
|
||||
|
Cash flow hedges
|
||||
|
Foreign exchange risk
|
||||
|
Highly probable forecast capital expenditure
|
|
(
|
|
|
|
Commodity price risk
|
||||
|
Highly probable forecast sales
|
|
(
|
|
|
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
|
||||
|
At 31 December 2024
|
$ million
|
$ million
|
$ million
|
mmBtu
|
|
|
Cash flow hedges
|
|||||
|
Foreign exchange risk
|
|||||
|
Highly probable forecast capital expenditure
|
|
|
|
||
|
Commodity price risk
|
|||||
|
Highly probable forecast sales
|
|
|
(
|
||
|
At 31 December 2023
|
|||||
|
Cash flow hedges
|
|||||
|
Foreign exchange risk
|
|||||
|
Highly probable forecast capital expenditure
|
|
(
|
|
||
|
Commodity price risk
|
|||||
|
Highly probable forecast sales
|
|
|
(
|
||
All hedging instruments are presented within derivative financial instruments on the group balance sheet.
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
|
|
|
|||
|
Euro/US dollar
|
|
|
|||
|
Henry Hub $/mmBtu
|
|
|
|||
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.
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
|
||||
|
Fair value hedges
|
||||
|
Interest rate risk on finance debt
|
|
|
(
|
|
|
Interest rate and foreign currency risk on finance debt
|
|
(
|
(
|
|
|
At 31 December 2023
|
||||
|
Fair value hedges
|
||||
|
Interest rate risk on finance debt
|
|
|
|
|
|
Interest rate and foreign currency risk on finance debt
|
(
|
|
|
The tables below summarize the carrying amount of the derivatives designated as hedging instruments in fair value hedge relationships at 31 December.
|
$ million
|
||||
|
Carrying amount of hedging
instrument
|
Nominal amounts
of hedging
instruments
|
|||
|
At 31 December 2024
|
Assets
|
Liabilities
|
||
|
Fair value hedges
|
||||
|
Interest rate risk on finance debt
|
|
(
|
|
|
|
Interest rate and foreign currency risk on finance debt
|
|
(
|
|
|
|
At 31 December 2023
|
||||
|
Fair value hedges
|
||||
|
Interest rate risk on finance debt
|
|
(
|
|
|
|
Interest rate and foreign currency risk on finance debt
|
|
(
|
|
|
All hedging instruments are presented within derivative financial instruments on
the group balance sheet
and are categorized within level 2 of the fair
value hierarchy. Ineffectiveness arising on fair value hedges is included within finance costs in the income statement.
|
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
|
|
|
|
|
|
|
|
|
|
|
Interest rate and foreign currency risk on
finance debt
|
|
|
|
|
|
|
|
|
|
|
At 31 December 2023
|
|||||||||
|
Fair value hedges
|
|||||||||
|
Interest rate risk on finance debt
|
|
|
|
|
|
|
|
|
|
|
Interest rate and foreign currency risk on
finance debt
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
Sterling/US dollar
|
|
|
|||
|
Euro/US dollar
|
|
|
|||
|
Canadian dollar/US dollar
|
|
|
|||
|
Australian dollar/ US dollar
|
|
|
|||
|
Japanese Yen/ US dollar
|
|
|
|||
|
Swiss Franc/US dollar
|
|
|
The tables below summarize the carrying amount, and the accumulated fair value adjustments included within the carrying amount, of the hedged items
designated in fair value hedge relationships at 31 December.
|
$ million
|
|||||
|
Carrying amount
of hedged item
|
Accumulated fair value adjustment included in the
carrying amount of hedged items
|
||||
|
At 31 December 2024
|
Liabilities
|
Assets
|
Liabilities
|
Discontinued
hedges
|
|
|
Fair value hedges
|
|||||
|
Interest rate risk on finance debt
|
(
|
|
|
(
|
|
|
Interest rate and foreign currency risk on finance debt
|
(
|
|
|
|
|
|
At 31 December 2023
|
|||||
|
Fair value hedges
|
|||||
|
Interest rate risk on finance debt
|
(
|
|
|
(
|
|
|
Interest rate and foreign currency risk on finance debt
|
(
|
|
|
|
|
The hedged item for all fair value hedges is presented within finance debt on the group balance sheet.
|
bp Annual Report and Form 20-F 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
|
|
|
(
|
|
|
|
Recognized in other comprehensive income
|
|||||
|
Cash flow hedges marked to market
|
(
|
|
—
|
|
|
|
Cash flow hedges reclassified to the income statement - hedged item affected profit or
loss
|
|
(
|
—
|
(
|
|
|
Costs of hedging marked to market
|
—
|
—
|
(
|
(
|
|
|
Costs of hedging reclassified to the income statement
|
—
|
—
|
(
|
(
|
|
|
(
|
(
|
(
|
(
|
||
|
Cash flow hedges transferred to the balance sheet
|
(
|
|
—
|
(
|
|
|
At 31 December 2024
|
|
(
|
(
|
(
|
|
|
$ 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
|
|
(
|
(
|
(
|
|
|
Recognized in other comprehensive income
|
|||||
|
Cash flow hedges marked to market
|
|
|
—
|
|
|
|
Cash flow hedges reclassified to the income statement - hedged item affected profit or
loss
|
|
(
|
—
|
(
|
|
|
Costs of hedging marked to market
|
—
|
—
|
(
|
(
|
|
|
Costs of hedging reclassified to the income statement
|
—
|
—
|
(
|
(
|
|
|
|
|
(
|
|
||
|
Cash flow hedges transferred to the balance sheet
|
(
|
|
—
|
(
|
|
|
At 31 December 2023
|
|
|
(
|
|
|
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
|
2024
|
2023
|
2022
|
|||||
|
Issued
|
Shares
thousand
|
$ million
|
Shares
thousand
|
$ million
|
Shares
thousand
|
$ million
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Ordinary shares of
|
|||||||
|
At 1 January
|
|
|
|
|
|
|
|
|
Issue of new shares for employee share-based payment plans
|
|
|
|
|
|
|
|
|
Issue of new shares – other
b
|
|
|
|
|
|
|
|
|
Repurchase of ordinary share capital
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
At 31 December
|
|
|
|
|
|
|
|
|
|
|
|
a
The 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.
b
165
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.
|
2024
|
2023
|
2022
|
|||||
|
Shares
thousand
|
Nominal value
$ million
|
Shares
thousand
|
Nominal value
$ million
|
Shares
thousand
|
Nominal value
$ million
|
||
|
At 1 January
|
|
|
|
|
|
|
|
|
Purchases for settlement of employee share plans
|
|
|
|
|
|
|
|
|
Issue of new shares for employee share-based payment plans
|
|
|
|
|
|
|
|
|
Shares re-issued for employee share-based payment plans
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
At 31 December
|
|
|
|
|
|
|
|
|
Of which – shares held in treasury by bp
|
|
|
|
|
|
|
|
|
– shares held in ESOP trusts
|
|
|
|
|
|
|
|
|
– shares held by bp’s US share plan administrator
b
|
|
|
|
|
|
|
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 represe
nted
1.4
%
(
2023
1.1
%
and
2022
less than
0.5
%
) of the ordinary share capital of the
|
bp Annual Report and Form 20-F 2024
|
211
|
|
Financial statements
|
THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY
|
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
|
||
|
At 1 January 2024
|
|
|
|
|
|
|
|
Profit (loss) for the year
|
|
|
|
|
|
|
|
Items that may be reclassified subsequently to profit or loss
|
||||||
|
Currency translation differences (including reclassifications)
a
|
—
|
—
|
—
|
—
|
—
|
|
|
Cash flow hedges and costs of hedging (including reclassifications)
|
—
|
—
|
—
|
—
|
—
|
|
|
Share of items relating to equity-accounted entities, net of tax
|
—
|
—
|
—
|
—
|
—
|
|
|
Other
|
—
|
—
|
—
|
—
|
—
|
|
|
Items that will not be reclassified to profit or loss
|
||||||
|
Remeasurements of the net pension and other post-employment benefit liability or asset
|
—
|
—
|
—
|
—
|
—
|
|
|
Remeasurements of equity investments
|
—
|
—
|
—
|
—
|
—
|
|
|
Cash flow hedges that will subsequently be transferred to the balance sheet
|
—
|
—
|
—
|
—
|
—
|
|
|
Total comprehensive income
|
—
|
—
|
—
|
—
|
—
|
|
|
Dividends
|
—
|
—
|
—
|
—
|
—
|
|
|
Cash flow hedges transferred to the balance sheet, net of tax
|
—
|
—
|
—
|
—
|
—
|
|
|
Repurchases of ordinary share capital
|
(
|
—
|
|
—
|
|
|
|
Share-based payments, net of tax
b
|
|
|
—
|
—
|
|
|
|
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
|
|
|
|
|
|
|
|
At 1 January 2023
|
|
|
|
|
|
|
|
Profit (loss) for the year
|
|
|
|
|
|
|
|
Items that may be reclassified subsequently to profit or loss
|
||||||
|
Currency translation differences (including reclassifications)
|
—
|
—
|
—
|
—
|
—
|
|
|
Cash flow hedges and costs of hedging (including reclassifications)
|
—
|
—
|
—
|
—
|
—
|
|
|
Share of items relating to equity-accounted entities, net of tax
|
—
|
—
|
—
|
—
|
—
|
|
|
Items that will not be reclassified to profit or loss
|
||||||
|
Remeasurements of the net pension and other post-employment benefit liability or asset
|
—
|
—
|
—
|
—
|
—
|
|
|
Remeasurements of equity investments
|
—
|
—
|
—
|
—
|
—
|
|
|
Cash flow hedges that will subsequently be transferred to the balance sheet
|
—
|
—
|
—
|
—
|
—
|
|
|
Total comprehensive income
|
—
|
—
|
—
|
—
|
—
|
|
|
Dividends
|
—
|
—
|
—
|
—
|
—
|
|
|
Cash flow hedges transferred to the balance sheet, net of tax
|
—
|
—
|
—
|
—
|
—
|
|
|
Repurchases of ordinary share capital
|
(
|
|
|
|
|
|
|
Share-based payments, net of tax
b
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
a
Includes
$
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.
b
Movements 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
|
|
|
Hybrid bonds
|
Other interest
|
|||||||||
|
(
|
(
|
|
|
(
|
|
|
|
|
|
|
|
—
|
—
|
—
|
—
|
—
|
—
|
|
|
|
|
|
|
—
|
(
|
(
|
—
|
—
|
(
|
—
|
(
|
—
|
(
|
(
|
|
—
|
—
|
—
|
(
|
(
|
(
|
—
|
(
|
—
|
—
|
(
|
|
—
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
—
|
(
|
|
—
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
—
|
(
|
|
—
|
—
|
—
|
—
|
—
|
—
|
|
|
—
|
—
|
|
|
—
|
—
|
(
|
—
|
—
|
(
|
—
|
(
|
—
|
—
|
(
|
|
—
|
—
|
—
|
(
|
—
|
(
|
—
|
(
|
—
|
—
|
(
|
|
—
|
(
|
(
|
(
|
(
|
(
|
|
|
|
|
|
|
—
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
(
|
(
|
|
—
|
—
|
—
|
(
|
—
|
(
|
—
|
(
|
—
|
—
|
(
|
|
—
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
—
|
(
|
|
|
—
|
—
|
—
|
—
|
—
|
(
|
|
—
|
—
|
|
|
—
|
—
|
—
|
—
|
—
|
—
|
|
|
—
|
—
|
|
|
—
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
|
—
|
|
|
—
|
—
|
—
|
—
|
—
|
—
|
|
|
(
|
—
|
(
|
|
—
|
|
—
|
—
|
—
|
—
|
—
|
|
(
|
—
|
(
|
|
—
|
—
|
—
|
—
|
—
|
—
|
|
|
—
|
|
|
|
(
|
(
|
(
|
(
|
(
|
(
|
|
|
|
|
|
|
(
|
(
|
|
(
|
(
|
(
|
|
|
|
|
|
|
—
|
—
|
—
|
—
|
—
|
—
|
|
|
|
|
|
|
—
|
|
—
|
—
|
—
|
—
|
—
|
|
—
|
|
|
|
—
|
—
|
—
|
|
(
|
|
—
|
|
—
|
—
|
|
|
—
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
—
|
(
|
|
—
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
—
|
(
|
|
—
|
—
|
|
—
|
—
|
|
—
|
|
—
|
—
|
|
|
—
|
—
|
—
|
|
—
|
|
—
|
|
—
|
—
|
|
|
—
|
|
|
|
(
|
|
|
|
|
|
|
|
—
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
(
|
(
|
|
—
|
—
|
—
|
(
|
—
|
(
|
—
|
(
|
—
|
—
|
(
|
|
—
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
—
|
(
|
|
|
—
|
—
|
—
|
—
|
—
|
(
|
|
—
|
—
|
|
|
—
|
—
|
—
|
—
|
—
|
—
|
|
|
—
|
—
|
|
|
—
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
|
—
|
|
|
—
|
(
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
(
|
|
—
|
—
|
—
|
—
|
—
|
—
|
|
|
—
|
(
|
|
|
(
|
(
|
|
|
(
|
|
|
|
|
|
|
|
214
|
bp Annual Report and Form 20-F 2024
|
32
.
Capital and reserves
– continued
|
Share
capital
|
Share
premium
account
|
Capital
redemption
reserve
|
Merger
reserve
|
Total
share capital
and capital
reserves
|
||
|
At 1 January 2022
|
|
|
|
|
|
|
|
Profit (loss) for the year
|
|
|
|
|
|
|
|
Items that may be reclassified subsequently to profit or loss
|
||||||
|
Currency translation differences (including reclassifications)
b
|
—
|
—
|
—
|
—
|
—
|
|
|
Cash flow hedges and costs of hedging (including reclassifications)
c
|
—
|
—
|
—
|
—
|
—
|
|
|
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
|
—
|
—
|
—
|
—
|
—
|
|
|
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
|
—
|
—
|
—
|
—
|
—
|
|
|
Issue of ordinary share capital
|
|
|
—
|
—
|
|
|
|
Repurchases of ordinary share capital
|
(
|
—
|
|
—
|
—
|
|
|
Share-based payments, net of tax
a
|
|
|
—
|
—
|
|
|
|
Issue of perpetual hybrid bonds
|
—
|
—
|
—
|
—
|
—
|
|
|
Payments on perpetual hybrid bonds
|
—
|
—
|
—
|
—
|
—
|
|
|
Transactions involving non-controlling interests, net of tax
|
—
|
—
|
—
|
—
|
—
|
|
|
At 31 December 2022
|
|
|
|
|
|
a
Movements in treasury shares relate to employee share-based payment plans.
b
Following bp’s decision to exit its shareholding in Rosneft on 27 February 2022,
$
10,372
million
was reclassified to the income statement.
c
Following bp’s decision to exit its shareholding in Rosneft on 27 February 2022
$
651
million
was reclassified to the income statement.
|
bp Annual Report and Form 20-F 2024
|
215
|
|
Financial statements
|
32
.
Capital and reserves
– continued
|
$ million
|
|||||||||
|
Treasury
shares
|
Foreign
currency
translation
reserve
|
Cash flow
hedges
|
Costs of hedging
|
Total
fair value
reserves
|
Profit and
loss
account
|
bp
shareholders’
equity
|
Non-controlling interests
|
Total equity
|
|
|
Hybrid bonds
|
Other interest
|
||||||||
|
(
|
(
|
(
|
(
|
(
|
|
|
|
|
|
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
|
|
(
|
|
—
|
|
—
|
—
|
—
|
—
|
|
—
|
(
|
|
|
—
|
—
|
|
|
|
—
|
|
—
|
—
|
|
|
—
|
—
|
—
|
—
|
—
|
|
|
—
|
—
|
|
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
—
|
(
|
|
—
|
—
|
—
|
—
|
—
|
|
|
—
|
—
|
|
|
—
|
—
|
(
|
—
|
(
|
—
|
(
|
—
|
—
|
(
|
|
—
|
|
|
|
|
(
|
|
|
|
|
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
(
|
(
|
|
—
|
—
|
|
—
|
|
—
|
|
—
|
—
|
|
|
—
|
—
|
—
|
—
|
—
|
—
|
|
—
|
—
|
|
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
—
|
(
|
|
|
—
|
—
|
—
|
—
|
|
|
—
|
—
|
|
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
|
—
|
|
|
—
|
|
—
|
—
|
—
|
—
|
|
(
|
—
|
(
|
|
—
|
—
|
—
|
—
|
—
|
(
|
(
|
—
|
(
|
(
|
|
(
|
(
|
(
|
(
|
(
|
|
|
|
|
|
|
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
o
f
3.25
%
to
6.45
%
an
d 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 subsidia
ries 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
|
$ million
|
||||
|
2024
|
||||
|
Pre-tax
|
Tax
|
Net of tax
|
||
|
Items that may be reclassified subsequently to profit or loss
|
||||
|
Currency translation differences (including reclassifications)
|
(
|
(
|
(
|
|
|
Cash flow hedges (including reclassifications)
|
(
|
|
(
|
|
|
Costs of hedging (including reclassifications)
|
(
|
|
(
|
|
|
Share of items relating to equity-accounted entities, net of tax
|
(
|
|
(
|
|
|
Other
|
|
(
|
(
|
|
|
Items that will not be reclassified to profit or loss
|
||||
|
Remeasurements of the net pension and other post-employment benefit liability or asset
a
|
(
|
|
|
|
|
Remeasurements of equity investments
|
(
|
|
(
|
|
|
Cash flow hedges that will subsequently be transferred to the balance sheet
|
(
|
|
(
|
|
|
Other comprehensive income
|
(
|
|
(
|
|
|
$ million
|
||||
|
2023
|
||||
|
Pre-tax
|
Tax
|
Net of tax
|
||
|
Items that may be reclassified subsequently to profit or loss
|
||||
|
Currency translation differences (including reclassifications)
|
|
|
|
|
|
Cash flow hedges (including reclassifications)
|
|
(
|
|
|
|
Costs of hedging (including reclassifications)
|
(
|
(
|
(
|
|
|
Share of items relating to equity-accounted entities, net of tax
|
(
|
|
(
|
|
|
Items that will not be reclassified to profit or loss
|
||||
|
Remeasurements of the net pension and other post-employment benefit liability or asset
|
(
|
|
(
|
|
|
Remeasurements of equity investments
|
|
(
|
|
|
|
Cash flow hedges that will subsequently be transferred to the balance sheet
|
|
|
|
|
|
Other comprehensive income
|
(
|
|
(
|
|
|
$ million
|
||||
|
2022
|
||||
|
Pre-tax
|
Tax
|
Net of tax
|
||
|
Items that may be reclassified subsequently to profit or loss
|
||||
|
Currency translation differences (including reclassifications)
|
|
(
|
|
|
|
Cash flow hedges (including reclassifications)
|
|
(
|
|
|
|
Costs of hedging (including reclassifications)
|
|
|
|
|
|
Share of items relating to equity-accounted entities, net of tax
|
|
|
|
|
|
Other
|
|
(
|
(
|
|
|
Items that will not be reclassified to profit or loss
|
||||
|
Remeasurements of the net pension and other post-employment benefit liability or asset
|
|
|
|
|
|
Cash flow hedges that will subsequently be transferred to the balance sheet
|
(
|
|
(
|
|
|
Other comprehensive income
|
|
(
|
|
a
2024 includes a
$
658
-million
credit
in respect of the reduction in the deferred tax liability on defined benefit pension plan surpluses following the reduction in the rate of the authorized surplus payments tax
charge in the UK from 35% to 25%.
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
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
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
|
$ million
|
||||
|
2024
|
2023
|
2022
|
||
|
Total for all directors
|
||||
|
Emoluments
|
|
|
|
|
|
Amounts received under incentive schemes
a
|
|
|
|
|
|
Total
|
|
|
|
a
Excludes 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
.
|
$ million
|
||||
|
2024
|
2023
|
2022
|
||
|
Total for all senior management and non-executive directors
|
||||
|
Short-term employee benefits
|
|
|
|
|
|
Pensions and other post-employment benefits
|
|
|
|
|
|
Share-based payments
a
|
|
|
|
|
|
Termination benefits
|
|
|
|
|
|
Total
|
|
|
|
a
2023 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 salaries
a
|
|
|
|
|
|
Social security costs
|
|
|
|
|
|
Share-based payments
b
|
|
|
|
|
|
Pension and other post-employment benefit costs
|
|
|
|
|
|
|
|
|
|
2024
|
2023
|
2022
|
||||||||
|
Average number of employees
c
|
US
|
Non-US
|
Total
|
US
|
Non-US
|
Total
|
US
|
Non-US
|
Total
|
|
|
gas & low carbon energy
|
|
|
|
|
|
|
|
|
|
|
|
oil production & operations
|
|
|
|
|
|
|
|
|
|
|
|
customers & products
d e
|
|
|
|
|
|
|
|
|
|
|
|
other businesses and corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
a
Includes termination costs of
$
336
million
(
2023
$
96
million
and
2022
$
27
million
).
b
The 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.
c
Reported to the nearest 100.
d
Includes
40,700
(
2023
33,800
and
2022
23,300
) service station staff.
e
Includes
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 accounts
a
|
|
|
|
|
|
The audit of accounts of subsidiaries of the company
|
|
|
|
|
|
Total audit
|
|
|
|
|
|
Audit-related assurance services
b
|
|
|
|
|
|
Total audit and audit-related assurance services
|
|
|
|
|
|
Non-audit and other assurance services
|
|
|
|
|
|
Services relating to bp pension plans
|
|
|
|
|
|
|
|
|
a
Fees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements.
b
Includes 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 associates
a
(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
|
|
England & Wales
|
Investment holding
|
||
|
BP Exploration Operating Company Limited
|
|
England & Wales
|
Exploration and production
|
||
|
*BP Gamma Holdings Limited
|
|
England & Wales
|
Investment holding
|
||
|
*BP Global Investments Limited
|
|
England & Wales
|
Investment holding
|
||
|
*BP International Limited
|
|
England & Wales
|
Integrated oil operations
|
||
|
BP Oil International Limited
|
|
England & Wales
|
Integrated oil operations
|
||
|
*Castrol Group Holdings Limited
|
|
Scotland
|
Investment holding
|
||
|
Azerbaijan
|
|||||
|
BP Exploration (Caspian Sea) Limited
|
|
England & Wales
|
Exploration and production
|
||
|
BP Exploration (Azerbaijan) Limited
|
|
England & Wales
|
Exploration and production
|
||
|
Germany
|
|||||
|
BP Europa SE
|
|
Germany
|
Refining and marketing
|
||
|
Trinidad and Tobago
|
|||||
|
BP Trinidad and Tobago LLC
|
|
US
|
Exploration and production
|
||
|
UK
|
|||||
|
BP Capital Markets p.l.c.
|
|
England & Wales
|
Finance
|
||
|
Lightsource BP Renewable Energy Investments Limited
|
|
England & Wales
|
Solar
|
||
|
US
|
|||||
|
*BP Holdings North America Limited
|
|
England & Wales
|
Investment holding
|
||
|
Atlantic Richfield Company
|
|
US
|
Exploration and production, refining and
marketing
|
||
|
BP America Inc.
|
|
US
|
|||
|
BP America Production Company
|
|
US
|
|||
|
BP Company North America Inc.
|
|
US
|
|||
|
BP Corporation North America Inc.
|
|
US
|
|||
|
BP Products North America Inc.
|
|
US
|
|||
|
The Standard Oil Company
|
|
US
|
|||
|
Archaea Energy Inc.
|
|
US
|
Bioenergy
|
||
|
BP Capital Markets America Inc.
|
|
US
|
Finance
|
||
|
Joint arrangements
|
%
|
Country of
incorporation
|
Principal activities
|
||
|
Angola
|
|||||
|
Azule Energy Holdings Limited
|
|
England & Wales
|
Exploration and production
|
a
There 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 entities
a
), 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
.
a
See
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 December
a 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 December
a b
|
||||||||||
|
Acquisition of properties
|
||||||||||
|
Proved
|
—
|
—
|
52
|
—
|
—
|
—
|
—
|
—
|
52
|
|
|
Unproved
|
—
|
—
|
21
|
—
|
2
|
—
|
—
|
—
|
23
|
|
|
—
|
—
|
73
|
—
|
2
|
—
|
—
|
—
|
75
|
||
|
Exploration and appraisal costs
c
|
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 December
a
|
||||||||||
|
Sales and other operating revenues
d
|
||||||||||
|
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 taxation
f
|
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
|
|
a
These 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.
b
Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c
Includes 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.
d
Presented net of transportation costs, purchases and sales taxes.
e
Includes 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.
f
Excludes 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 December
a 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 December
a c d
|
||||||||||
|
Acquisition of properties
b
|
||||||||||
|
Proved
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
|
|
Unproved
|
—
|
—
|
—
|
—
|
—
|
26
|
—
|
—
|
26
|
|
|
—
|
—
|
—
|
—
|
—
|
26
|
—
|
—
|
26
|
||
|
Exploration and appraisal costs
c
|
—
|
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 December
a
|
||||||||||
|
Sales and other operating revenues
e
|
||||||||||
|
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
|
|
a
These 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.
b
Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c
Includes 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.
d
The 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.
e
Presented 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 December
a 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 December
a b
|
||||||||||
|
Acquisition of properties
|
||||||||||
|
Proved
|
—
|
—
|
13
|
—
|
—
|
—
|
—
|
—
|
13
|
|
|
Unproved
|
—
|
—
|
51
|
—
|
2
|
6
|
—
|
—
|
59
|
|
|
—
|
—
|
64
|
—
|
2
|
6
|
—
|
—
|
72
|
||
|
Exploration and appraisal costs
c
|
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 December
a
|
||||||||||
|
Sales and other operating revenues
d
|
||||||||||
|
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 taxation
f
|
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
|
|
a
These 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.
b
Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c
Includes 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.
d
Presented net of transportation costs, purchases and sales taxes.
e
Includes 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.
f
Excludes 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 December
a 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 December
a c d
|
||||||||||
|
Acquisition of properties
b
|
||||||||||
|
Proved
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
|
|
Unproved
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
|
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
||
|
Exploration and appraisal costs
c
|
—
|
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 December
a
|
||||||||||
|
Sales and other operating revenues
e
|
||||||||||
|
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
|
|
a
These 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.
b
Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c
Includes 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.
d
The 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.
e
Presented 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
|
US
h
|
Rest of
North
America
|
Russia
|
Rest of
Asia
|
||||||
|
Subsidiaries
|
|||||||||||
|
Capitalized costs at 31 December
a 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 December
a 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 costs
c
|
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 December
a
|
|||||||||||
|
Sales and other operating revenues
d
|
|||||||||||
|
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 assets
f
|
(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 taxation
g
|
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
|
|
a
These 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.
b
Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c
Includes 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.
d
Presented net of transportation costs, purchases and sales taxes.
e
Includes 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.
f
Russia 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.
g
Excludes the unwinding of the discount on provisions and payables amounting to $294 million which is included in finance costs in the group income statement.
h
An 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
|
Russia
a
|
Rest of
Asia
|
||||||
|
Equity-accounted entities (bp share)
|
|||||||||||
|
Capitalized costs at 31 December
b 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 December
b d e
|
|||||||||||
|
Acquisition of properties
c
|
|||||||||||
|
Proved
|
—
|
1,224
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
1,224
|
|
|
Unproved
|
—
|
204
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
204
|
|
|
—
|
1,428
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
1,428
|
||
|
Exploration and appraisal costs
d
|
—
|
46
|
—
|
—
|
22
|
60
|
28
|
—
|
—
|
156
|
|
|
Development
f
|
—
|
(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 December
b
|
|||||||||||
|
Sales and other operating revenues
g
|
|||||||||||
|
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
|
|
a
Amounts 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).
b
These 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.
c
Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
d
Includes 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.
e
The 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.
f
Rest of Europe development costs are negative due to a true-up of prior period spend.
g
Presented net of sales tax.
|
230
|
bp Annual Report and Form 20-F 2024
|
Movements in estimated net proved reserves
|
million barrels
|
||||||||||
|
Crude oil
a 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 December
c
|
||||||||||
|
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
|
||
a
Crude 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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
Includes
1.5
million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
d
Volumes 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 liquids
a b
|
2024
|
|||||||||
|
Europe
|
North
America
|
South
America
|
Africa
Asia
|
Australasia
|
Total
|
|||||
|
UK
|
Rest of
Europe
|
US
c
|
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
|
|
|
Production
c
|
(1)
|
—
|
(39)
|
—
|
(2)
|
—
|
—
|
(1)
|
(43)
|
|
|
Sales of reserves-in-place
|
—
|
—
|
(4)
|
—
|
—
|
—
|
—
|
—
|
(4)
|
|
|
(1)
|
—
|
51
|
—
|
—
|
—
|
—
|
—
|
51
|
||
|
At 31 December
d
|
||||||||||
|
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
|
||
a
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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
Excludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
d
Includes 0.2 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e
Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
|
232
|
bp Annual Report and Form 20-F 2024
|
Movements in estimated net proved reserves – continued
|
million barrels
|
||||||||||
|
Total liquids
a b
|
2024
|
|||||||||
|
Europe
|
North
America
|
South
America
|
Africa
Asia
|
Australasia
|
Total
|
|||||
|
UK
|
Rest of
Europe
|
US
c
|
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
|
|
|
Production
c
|
(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 December
d
|
||||||||||
|
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
|
||
a
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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
Excludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
d
Also includes
1.7
million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e
Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
|
bp Annual Report and Form 20-F 2024
|
233
|
|
Financial statements
|
Movements in estimated net proved reserves – continued
|
billion cubic feet
|
||||||||||
|
Natural gas
a 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
|
|
|
Production
c
|
(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 December
d
|
||||||||||
|
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
|
|
|
Production
c
|
—
|
(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
|
||
a
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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
Includes 100 billion cubic feet of natural gas consumed in operations, 62 billion cubic feet in subsidiaries, 38 billion cubic feet in equity-accounted entities.
d
Includes
219
billion cubic feet
of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e
Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
|
234
|
bp Annual Report and Form 20-F 2024
|
Movements in estimated net proved reserves – continued
|
million barrels of oil equivalentc
|
||||||||||
|
Total hydrocarbons
a b
|
2024
|
|||||||||
|
Europe
|
North
America
|
South
America
|
Africa
Asia
|
Australasia
|
Total
|
|||||
|
UK
|
Rest of
Europe
|
US
f
|
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
|
|
|
Production
d 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 December
f
|
||||||||||
|
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
|
|
|
Production
e
|
—
|
(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
|
||
a
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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
d
Excludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
e
Includes 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.
f
Includes
39
million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
g
Volumes 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 oil
a 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 December
c
|
||||||||||
|
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
|
||
a
Crude 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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
Includes 2.2 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
d
Volumes 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 liquids
a b
|
2023
|
|||||||||
|
Europe
|
North
America
|
South
America
|
Africa
|
Asia
|
Australasia
|
Total
|
||||
|
UK
|
Rest of
Europe
|
US
c
|
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
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
—
|
|
|
Production
c
|
(2)
|
—
|
(31)
|
—
|
(1)
|
(1)
|
—
|
(1)
|
(35)
|
|
|
Sales of reserves-in-place
|
—
|
—
|
(3)
|
—
|
—
|
(6)
|
—
|
—
|
(9)
|
|
|
(3)
|
—
|
(20)
|
—
|
(1)
|
(7)
|
—
|
—
|
(31)
|
||
|
At 31 December
d
|
||||||||||
|
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
|
||
a
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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
Excludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
d
Includes 0 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e
Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
|
bp Annual Report and Form 20-F 2024
|
237
|
|
Financial statements
|
Movements in estimated net proved reserves – continued
|
million barrels
|
||||||||||
|
Total liquids
a b
|
2023
|
|||||||||
|
Europe
|
North
America
|
South
America
|
Africa
|
Asia
|
Australasia
|
Total
|
||||
|
UK
|
Rest of
Europe
|
US
c
|
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
|
|
|
Production
c
|
(29)
|
—
|
(154)
|
—
|
(3)
|
(12)
|
(107)
|
(4)
|
(309)
|
|
|
Sales of reserves-in-place
|
—
|
—
|
(4)
|
—
|
—
|
(12)
|
—
|
—
|
(17)
|
|
|
(61)
|
—
|
(161)
|
—
|
(3)
|
(27)
|
(21)
|
(9)
|
(283)
|
||
|
At 31 December
d
|
||||||||||
|
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
|
||
a
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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
Excludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
d
Also includes 2.2 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e
Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
|
238
|
bp Annual Report and Form 20-F 2024
|
Movements in estimated net proved reserves – continued
|
billion cubic feet
|
||||||||||
|
Natural gas
a 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
|
|
|
Production
c
|
(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 December
d
|
||||||||||
|
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
|
|
|
Production
c
|
—
|
(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
|
||
a
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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
Includes 99 billion cubic feet of natural gas consumed in operations, 62 billion cubic feet in subsidiaries, 36 billion cubic feet in equity-accounted entities.
d
Includes 430 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e
Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
|
bp Annual Report and Form 20-F 2024
|
239
|
|
Financial statements
|
Movements in estimated net proved reserves – continued
|
million barrels of oil equivalent
c
|
||||||||||
|
Total hydrocarbons
a b
|
2023
|
|||||||||
|
Europe
|
North
America
|
South
America
|
Africa
|
Asia
|
Australasia
|
Total
|
||||
|
UK
|
Rest of
Europe
|
US
f
|
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
|
|
|
Production
d 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 December
f
|
||||||||||
|
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
|
|
|
Production
e
|
—
|
(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
|
||
a
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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
d
Excludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
e
Includes 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.
f
Includes
39
million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
g
Volumes 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 oil
a b
|
2022
|
||||||||||
|
Europe
|
North
America
|
South
America
|
Africa
c
|
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 December
c
|
|||||||||||
|
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-place
f
|
—
|
(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
|
|
a
Crude 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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
Includes 3 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
d
Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
e
Includes assets held for sale in Algeria.
f
bp'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 liquids
a b
|
2022
|
||||||||||
|
Europe
|
North
America
|
South
America
|
Africa
c
|
Asia
|
Australasia
|
Total
|
|||||
|
UK
|
Rest of
Europe
|
US
d
|
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
|
|
|
Production
d
|
(2)
|
—
|
(28)
|
—
|
(2)
|
(2)
|
—
|
—
|
(1)
|
(34)
|
|
|
Sales of reserves-in-place
|
—
|
—
|
(1)
|
—
|
—
|
(1)
|
—
|
—
|
—
|
(1)
|
|
|
(2)
|
—
|
90
|
—
|
(19)
|
(2)
|
—
|
—
|
(1)
|
64
|
||
|
At 31 December
e
|
|||||||||||
|
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-place
g
|
—
|
(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
|
|
a
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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
Includes assets held for sale in Algeria.
d
Excludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
e
Includes 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.
g
bp'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 liquids
a b
|
2022
|
||||||||||
|
Europe
|
North
America
|
South
America
|
Africa
c
|
Asia
|
Australasia
|
Total
|
|||||
|
UK
|
Rest of
Europe
|
US
d
|
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
|
|
|
Production
d
|
(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 December
e
|
|||||||||||
|
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
|
|
a
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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
Includes assets held for sale in Algeria.
d
Excludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
e
Also includes 3 million barrels 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.
g
bp'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 gas
a b
|
2022
|
||||||||||
|
Europe
|
North
America
|
South
America
|
Africa
c
|
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
|
|
|
Production
d
|
(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 December
e
|
|||||||||||
|
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
|
|
|
Production
d
|
—
|
(25)
|
—
|
—
|
(128)
|
(36)
|
(86)
|
(2)
|
—
|
(277)
|
|
|
Sales of reserves-in-place
g
|
—
|
(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
|
||
a
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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
Includes assets held for sale in Algeria.
d
Includes 122 billion cubic feet of natural gas consumed in operations, 86 billion cubic feet in subsidiaries, 36 billion cubic feet in equity-accounted entities.
e
Includes 547 billion cubic feet of natural gas 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.
g
bp'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 equivalent
c
|
|||||||||||
|
Total hydrocarbons
a b
|
2022
|
||||||||||
|
Europe
|
North
America
|
South
America
|
Africa
d
|
Asia
|
Australasia
|
Total
|
|||||
|
UK
|
Rest of
Europe
|
US
e
|
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
|
|
|
Production
f 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 December
e
|
|||||||||||
|
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
|
|
|
Production
g
|
—
|
(22)
|
—
|
(1)
|
(43)
|
(19)
|
(70)
|
(10)
|
—
|
(165)
|
|
|
Sales of reserves-in-place
i
|
—
|
(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
|
||
a
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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
d
Includes assets held for sale in Algeria.
e
Includes
39
million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f
Excludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.
g
Includes 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.
h
Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
i
bp'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 inflows
a
|
15,100
|
—
|
99,300
|
—
|
3,700
|
600
|
107,300
|
15,200
|
241,200
|
|
|
Future production cost
b
|
11,800
|
—
|
39,100
|
—
|
2,900
|
100
|
37,800
|
3,900
|
95,600
|
|
|
Future development cost
b
|
1,000
|
—
|
15,300
|
—
|
500
|
100
|
11,200
|
2,100
|
30,200
|
|
|
Future taxation
c
|
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 discount
d
|
100
|
—
|
15,400
|
—
|
(300)
|
—
|
4,900
|
2,200
|
22,300
|
|
|
Standardized measure of discounted future net cash
flows
e
|
—
|
—
|
22,400
|
—
|
500
|
300
|
10,600
|
4,600
|
38,400
|
|
|
Equity-accounted entities (bp share)
f
|
||||||||||
|
Future cash inflows
a
|
—
|
11,700
|
—
|
—
|
41,600
|
15,100
|
8,400
|
—
|
76,800
|
|
|
Future production cost
b
|
—
|
4,100
|
—
|
—
|
20,900
|
5,400
|
4,200
|
—
|
34,600
|
|
|
Future development cost
b
|
—
|
2,000
|
—
|
—
|
4,100
|
2,200
|
2,900
|
—
|
11,200
|
|
|
Future taxation
c
|
—
|
4,300
|
—
|
—
|
4,600
|
2,200
|
400
|
—
|
11,500
|
|
|
Future net cash flows
|
—
|
1,300
|
—
|
—
|
12,000
|
5,300
|
900
|
—
|
19,500
|
|
|
10% annual discount
d
|
—
|
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 year
g
|
(11,600)
|
(200)
|
(11,800)
|
a
The marker prices used were Brent
$81.17/bbl
, Henry Hub
$2.07/mmBtu
.
b
Production 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.
c
Taxation is computed with reference to appropriate year-end statutory corporate income tax rates.
d
Future 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.
e
Non-controlling interests in BP Trinidad and Tobago LLC amounted to
$164 million
.
f
The 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.
g
Total 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 inflows
a
|
19,400
|
—
|
100,200
|
—
|
6,800
|
4,400
|
118,300
|
18,000
|
267,100
|
|
|
Future production cost
b
|
11,900
|
—
|
37,500
|
—
|
4,300
|
600
|
39,600
|
4,500
|
98,400
|
|
|
Future development cost
b
|
1,200
|
—
|
12,100
|
—
|
1,000
|
500
|
8,500
|
1,400
|
24,700
|
|
|
Future taxation
c
|
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 discount
d
|
900
|
—
|
16,300
|
—
|
(300)
|
400
|
6,300
|
2,600
|
26,200
|
|
|
Standardized measure of discounted future net cash
flows
e
|
1,300
|
—
|
25,900
|
—
|
1,300
|
1,800
|
14,000
|
5,700
|
50,000
|
|
|
Equity-accounted entities (bp share)
f
|
||||||||||
|
Future cash inflows
a
|
—
|
13,700
|
—
|
—
|
44,600
|
15,200
|
9,000
|
—
|
82,500
|
|
|
Future production cost
b
|
—
|
3,700
|
—
|
—
|
20,700
|
5,500
|
4,700
|
—
|
34,600
|
|
|
Future development cost
b
|
—
|
2,100
|
—
|
—
|
5,200
|
2,300
|
3,100
|
—
|
12,700
|
|
|
Future taxation
c
|
—
|
6,000
|
—
|
—
|
5,900
|
2,100
|
400
|
—
|
14,400
|
|
|
Future net cash flows
|
—
|
1,900
|
—
|
—
|
12,800
|
5,300
|
800
|
—
|
20,800
|
|
|
10% annual discount
d
|
—
|
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 year
g
|
(41,000)
|
(3,100)
|
(44,100)
|
a
The marker prices used were Brent $83.27/bbl, Henry Hub $2.58/mmBtu.
b
Production 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.
c
Taxation is computed with reference to appropriate year-end statutory corporate income tax rates.
d
Future 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.
e
Non-controlling interests in BP Trinidad and Tobago LLC amounted to $392 million.
f
The 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.
g
Total 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 inflows
a
|
34,900
|
—
|
154,500
|
—
|
16,400
|
9,400
|
—
|
151,500
|
23,600
|
390,300
|
|
|
Future production cost
b
|
13,600
|
—
|
36,000
|
—
|
5,300
|
1,300
|
—
|
42,700
|
5,200
|
104,100
|
|
|
Future development cost
b
|
1,100
|
—
|
12,200
|
—
|
1,400
|
700
|
—
|
8,800
|
1,900
|
26,100
|
|
|
Future taxation
c
|
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 discount
d
|
3,400
|
—
|
38,200
|
—
|
700
|
1,000
|
—
|
11,800
|
4,000
|
59,100
|
|
|
Standardized measure of discounted future net
cash flows
e
|
4,200
|
—
|
48,300
|
—
|
4,000
|
4,500
|
—
|
23,000
|
7,000
|
91,000
|
|
|
Equity-accounted entities (bp share)
f
|
|||||||||||
|
Future cash inflows
a
|
—
|
12,800
|
—
|
—
|
49,800
|
20,500
|
—
|
9,200
|
—
|
92,300
|
|
|
Future production cost
b
|
—
|
2,100
|
—
|
—
|
22,000
|
6,300
|
—
|
4,900
|
—
|
35,300
|
|
|
Future development cost
b
|
—
|
400
|
—
|
—
|
4,900
|
2,800
|
—
|
3,000
|
—
|
11,100
|
|
|
Future taxation
c
|
—
|
8,100
|
—
|
—
|
7,100
|
4,300
|
—
|
400
|
—
|
19,900
|
|
|
Future net cash flows
|
—
|
2,200
|
—
|
—
|
15,800
|
7,100
|
—
|
900
|
—
|
26,000
|
|
|
10% annual discount
d
|
—
|
400
|
—
|
—
|
9,300
|
2,200
|
—
|
200
|
—
|
12,100
|
|
|
Standardized measure of discounted future net
cash flows
g
|
—
|
1,800
|
—
|
—
|
6,500
|
4,900
|
—
|
700
|
—
|
13,900
|
|
|
Total subsidiaries and equity-accounted entities
|
|||||||||||
|
Standardized measure of discounted future net
cash flows
h
|
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 year
i
|
24,100
|
(23,900)
|
200
|
a
The marker prices used were Brent $101.24/bbl, Henry Hub $6.19/mmBtu.
b
Production 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.
c
Taxation is computed with reference to appropriate year-end statutory corporate income tax rates.
d
Future 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.
e
Non-controlling interests in BP Trinidad and Tobago LLC amounted to $1,216 million.
f
The 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.
g
No 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.
h
Includes future net cash flows for assets held for sale at 31 December 2022.
i
Total 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 year
a b
|
Europe
|
North
America
|
South
America
|
Africa
|
Asia
|
Australasia
|
Total
|
|||||
|
UK
|
Rest of
Europe
|
US
|
Rest of
North
America
|
Russia
c
|
Rest of
Asia
|
||||||
|
Subsidiaries
d
|
|||||||||||
|
Crude oil
e
|
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 gas
f
|
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 oil
e
|
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 gas
f
|
|
million cubic feet per day
|
|||||||||
|
2024
|
—
|
55
|
—
|
—
|
300
|
85
|
—
|
—
|
—
|
440
|
|
|
2023
|
—
|
58
|
—
|
—
|
299
|
74
|
—
|
—
|
—
|
432
|
|
|
2022
|
—
|
66
|
—
|
—
|
296
|
64
|
248
|
—
|
—
|
674
|
|
a
Production 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.
b
Because of rounding, some totals may not exactly agree with the sum of their component parts.
c
Amounts reported for Russia include bp’s share of Rosneft worldwide activities, including insignificant amounts outside Russia.
d
All of the oil and liquid production from Canada is bitumen.
e
Crude oil includes condensate.
f
Natural 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
Asia
e
|
Australasia
e
|
Total
a
|
||||||
|
UK
|
Rest of
Europe
|
US
|
Rest of
North
America
|
||||||||
|
Number of productive wells at 31 December 2024
|
|||||||||||
|
Oil wells
b
|
– 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 wells
c
|
– 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
|
||
|
Undeveloped
d
|
– 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
|
||
a
Because of rounding, some totals may not exactly agree with the sum of their component parts.
b
Includes approximately
164 gross
(29
net
) multiple completion wells (more than one formation producing into the same well bore).
c
Includes 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.
d
Undeveloped acreage includes leases and concessions.
e
Includes 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
|
Total
a
|
|||||
|
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
|
|||||||||||
|
Productive
b
|
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
|
|
a
Because of rounding, some totals may not exactly agree with the sum of their component parts.
b
Includes correction of 2023 productive wells
|
250
|
bp Annual Report and Form 20-F 2024
|
Operational and statistical information – continued
Drilling and production activities in progress
The following table shows the number of exploratory and development oil and natural gas wells in the process of being drilled by the group and its equity-
accounted entities as of
31 December 2024
. Suspended development wells and long-term suspended exploratory wells are also included in the table.
|
Europe
|
North
America
|
South
America
|
Africa
Asia
|
Australasia
|
Total
a
|
|||||
|
UK
|
Rest of
Europe
|
US
|
Rest of
North
America
|
|||||||
|
At 31 December 2024
|
||||||||||
|
Exploratory
|
||||||||||
|
Gross
|
—
|
—
|
2.0
|
—
|
3.0
|
2.0
|
4.0
|
—
|
11.0
|
|
|
Net
|
—
|
—
|
0.9
|
—
|
1.9
|
0.6
|
1.0
|
—
|
4.4
|
|
|
Development
|
||||||||||
|
Gross
|
7.0
|
2.1
|
56.0
|
—
|
29.0
|
9.0
|
90.0
|
—
|
193.1
|
|
|
Net
|
3.7
|
0.3
|
36.4
|
—
|
10.9
|
4.4
|
20.5
|
—
|
76.1
|
|
a
Because of rounding, some totals may not exactly agree with the sum of their component parts.
|
bp Annual Report and Form 20-F 2024
|
251
|
|
Financial statements
|
Pages 251-310
have been removed as they do not form part of bp's Annual Report on Form 20-F as filed with the SEC.
|
252
|
bp Annual Report and Form 20-F 2024
|
Pages 251-310
have been removed as they do not form part of bp's Annual Report on Form 20-F as filed with the SEC.
|
|
bp Annual Report and Form 20-F 2024
|
311
|
|
Additional disclosures
|
|
Additional disclosures
|
||||
|
Additional information
|
||||
|
Liquidity and capital resources
|
||||
|
Oil and gas disclosures for the group
|
||||
|
Additional information for customers & products
|
||||
|
Environmental expenditure
|
||||
|
Regulation of the group’s business
|
||||
|
International trade sanctions
|
||||
|
Material contracts
|
||||
|
Property, plant and equipment
|
||||
|
Related party transactions
|
||||
|
Corporate governance practices
|
||||
|
Code of ethics
|
||||
|
Controls and procedures
|
||||
|
Cyber security
|
||||
|
Principal accountant’s fees and services
|
||||
|
Additional Directors’ report disclosures
|
||||
|
Disclosures required under Listing Rule 6.6.1R
|
||||
|
Cautionary statement
|
||||
|
312
|
bp Annual Report and Form 20-F 2024
|
Additional information
Capital expenditure
«
|
$ million
|
||||
|
2024
|
2023
|
2022
|
||
|
Capital expenditure
|
||||
|
Organic capital expenditure
«
|
16,135
|
14,998
|
12,470
|
|
|
Inorganic capital expenditure
abc
«
|
102
|
1,255
|
3,860
|
|
|
16,237
|
16,253
|
16,330
|
||
|
Capital expenditure by segment
|
||||
|
gas & low carbon energy
a
|
5,211
|
4,281
|
4,251
|
|
|
oil production & operations
|
6,198
|
6,278
|
5,278
|
|
|
customers & products
abc
|
4,420
|
5,253
|
6,252
|
|
|
other businesses & corporate
|
408
|
441
|
549
|
|
|
16,237
|
16,253
|
16,330
|
||
|
Capital expenditure by geographical area
|
||||
|
US
|
6,566
|
8,105
|
8,656
|
|
|
Non-US
|
9,671
|
8,148
|
7,674
|
|
|
16,237
|
16,253
|
16,330
|
a
2024 includes
the cash acquired net of acquisition payments on completion of the bp Bunge Bioenergia and Lightsource bp acquisitions.
b
2023 includes $1.1 billion in respect of the TravelCenters of America acquisition.
c
2022 includes $3,030 million in respect of the Archaea Energy acquisition.
|
|
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 assets
a
|
297
|
19
|
45
|
|
|
Net impairment and losses on sale of businesses and fixed assets
a
|
(3,004)
|
(2,221)
|
588
|
|
|
Environmental and related provisions
|
—
|
—
|
—
|
|
|
Restructuring, integration and rationalization costs
b
|
(25)
|
—
|
8
|
|
|
Fair value accounting effects
cd
«
|
(1,550)
|
8,859
|
(1,811)
|
|
|
Other
e
|
1,048
|
(1,299)
|
(197)
|
|
|
(3,234)
|
5,358
|
(1,367)
|
||
|
oil production & operations
|
||||
|
Gain on sale of businesses and fixed assets
a
|
144
|
297
|
3,446
|
|
|
Net impairment and losses on sale of businesses and fixed assets
a
|
(790)
|
(1,819)
|
(4,508)
|
|
|
Environmental and related provisions
f
|
5
|
54
|
518
|
|
|
Restructuring, integration and rationalization costs
b
|
(15)
|
(1)
|
(11)
|
|
|
Fair value accounting effects
|
—
|
—
|
—
|
|
|
Other
g
|
(492)
|
(121)
|
52
|
|
|
(1,148)
|
(1,590)
|
(503)
|
||
|
customers & products
|
||||
|
Gain on sale of businesses and fixed assets
a
|
190
|
44
|
374
|
|
|
Net impairment and losses on sale of businesses and fixed assets
ah
|
(3,117)
|
(1,757)
|
(1,983)
|
|
|
Environmental and related provisions
|
(99)
|
(97)
|
(101)
|
|
|
Restructuring, integration and rationalization costs
b
|
(123)
|
—
|
18
|
|
|
Fair value accounting effects
d
|
(81)
|
(86)
|
(309)
|
|
|
Other
i
|
(847)
|
(287)
|
81
|
|
|
(4,077)
|
(2,183)
|
(1,920)
|
||
|
other businesses & corporate
|
||||
|
Gain on sale of businesses and fixed assets
a
|
39
|
1
|
1
|
|
|
Net impairment and losses on sale of businesses and fixed assets
a
|
(19)
|
(41)
|
(17)
|
|
|
Environmental and related provisions
j
|
(87)
|
(604)
|
(92)
|
|
|
Restructuring, integration and rationalization costs
b
|
(59)
|
38
|
19
|
|
|
Fair value accounting effects
d
|
(221)
|
630
|
(1,381)
|
|
|
Rosneft
k
|
—
|
—
|
(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 costs
l
|
(505)
|
(405)
|
(425)
|
|
|
Total before taxation
|
(9,344)
|
1,143
|
(29,781)
|
|
|
Taxation on adjusting items
m
|
1,495
|
972
|
456
|
|
|
Taxation
–
tax rate change effect
n
|
(316)
|
232
|
(1,834)
|
|
|
Total after taxation
o
|
(8,165)
|
2,347
|
(31,159)
|
a
See Financial statements –
Note 4
for further information.
b
Restructuring 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.
c
Under IFRS bp marks-to-market the value of the hedges used to risk-manage LNG contracts, but not the contracts themselves, resulting in a mismatch in accounting treatment. The fair value accounting
effect includes the change in value of LNG contracts that are being risk-managed, and the underlying result reflects how bp risk-manages its LNG contracts.
d
For further information, including the nature of fair value accounting effects reported in each segment, see
page 355
.
e
2024 i
ncludes 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.
f
2022 includes a provision reversal relating to the change in discount rate on retained decommissioning provisions.
g
2024 includes
$429 million of impairment charges recognized through equity-accounted earnings relating to our interest in Pan American Energy Group.
h
For 2024, see Financial statements
–
Note 2
for further information.
i
2024 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.
j
2023 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.
k
For more information see Financial statements –
Note 1
Significant accounting policies, judgements, estimates and assumptions – Investment in Rosneft, and
Note 17
– Investments in associates.
l
All 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.
m
Includes certain foreign exchange effects on tax as adjusting items. These amounts represent the impact of: (i) foreign exchange on deferred tax balances arising from the conversion of local currency tax
base amounts into functional currency; and (ii) taxable gains and losses from the retranslation of US dollar-denominated intra-group loans to local currency.
n
2024 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.
o
2023 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 performance
a
|
(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)
|
a
Includes 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
.
|
|
bp Annual Report and Form 20-F 2024
|
315
|
|
Additional disclosures
|
Net debt including leases
Net debt including leases
«
is shown in the table below.
|
$ million
|
|||
|
At 31 December
|
2024
|
2023
|
|
|
Net debt
a
«
|
22,997
|
20,912
|
|
|
Lease liabilities
|
12,000
|
11,121
|
|
|
Net partner (receivable) payable for leases entered into on behalf of joint operations
«
|
(88)
|
(131)
|
|
|
Net debt including leases
|
34,909
|
31,902
|
|
|
Total equity
|
78,318
|
85,493
|
|
|
Gearing including leases
«
|
30.8
%
|
27.2
%
|
a
See Financial statements – Note
27
for a reconciliation of net debt to finance debt, which is the nearest equivalent measure to net debt on an IFRS ba
sis.
|
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
d
elivering resilient distributions.
N
et 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 C
astrol 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
en
vironment, 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
f
actors which may vary quarter to quarter.
We ex
pect 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
r
educe 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.
a
Nearest 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 o
f at least 4%.
Add
itionally, 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 s
etting 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.
T
he 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
.
|
|
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
|
||||
|
Borrowings
a
|
6,892
|
70,354
|
77,246
|
|
|
Lease liabilities
b
|
3,237
|
11,031
|
14,268
|
|
|
Decommissioning liabilities
c
|
643
|
23,967
|
24,610
|
|
|
Environmental liabilities
c
|
349
|
1,584
|
1,933
|
|
|
Gulf of America oil spill
liabilities
d
|
1,137
|
8,383
|
9,520
|
|
|
Pensions and other post-
employment benefits
e
|
533
|
13,403
|
13,936
|
|
|
12,791
|
128,722
|
141,513
|
||
|
Off-balance sheet obligations
|
||||
|
Unconditional purchase
obligations
f
|
||||
|
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
|
|
a
Ex
pect
ed payments include interest totalling
$20,854 million
(less than 1 year
$2,490 million
, more
than 1 year
$18,364 million
).
b
Expected payments include interest totalling
$2,268 million
(less than 1 year
$460 million
, more
than 1 year
$1,808 million
).
c
The amounts presented are undiscounted.
d
The 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.
e
Represents 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.
f
Represents 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
70
Mt 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.
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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.
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Additional disclosures
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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
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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 6,000km
2
off the coast of Bali and East Java
and Agung II spans almost 8,000km
2
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
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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 mmboe
a
|
|
|
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 mmboe
a
|
|
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
|
a
Because 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
replacemen
t
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
2024
abc
|
million barrels
|
|||
|
Developed
|
Undeveloped
|
Total
|
|
|
UK
|
104
|
63
|
167
|
|
US
|
653
|
472
|
1,125
|
|
Rest of North America
|
—
|
—
|
—
|
|
South America
d
|
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 2024
ab
|
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 liquids
d
«
|
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
|
|
|
bp Annual Report and Form 20-F 2024
|
323
|
|
Additional disclosures
|
Estimated net proved reserves of natural gas at
31 December
2024
ab
|
billion cubic feet
|
|||
|
Developed
|
Undeveloped
|
Total
|
|
|
UK
|
162
|
29
|
190
|
|
US
|
2,600
|
2,412
|
5,012
|
|
Rest of North America
|
—
|
—
|
—
|
|
South America
e
|
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
|
a
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, 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.
b
The
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).
c
Includes condensate.
d
Includes
1.7
million barrels of liquids in respect of the 30% non-controlling interest in BP Trinidad
and Tobago LLC.
e
Includes
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 oil
a
and natural gas liquids
|
thousand barrels per day
|
|||||||
|
bp net share of production
b
|
|||||||
|
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 onshore
c
|
86
|
69
|
71
|
84
|
66
|
56
|
|
|
Gulf of America deepwater
|
290
|
266
|
225
|
23
|
22
|
19
|
|
|
Total US
|
376
|
335
|
296
|
107
|
88
|
76
|
|
|
Canada
cd
|
—
|
—
|
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
|
|
|
Angola
c
|
—
|
—
|
49
|
—
|
—
|
—
|
|
|
Egypt
|
19
|
28
|
28
|
1
|
1
|
—
|
|
|
Algeria
c
|
—
|
1
|
5
|
—
|
1
|
6
|
|
|
Total Africa
|
19
|
29
|
83
|
1
|
2
|
6
|
|
|
Abu Dhabi
|
202
|
197
|
195
|
—
|
—
|
—
|
|
|
Azerbaijan
|
66
|
70
|
73
|
—
|
—
|
—
|
|
|
Iraq
c
|
—
|
—
|
15
|
—
|
—
|
—
|
|
|
India
g
|
6
|
4
|
—
|
—
|
—
|
—
|
|
|
Oman
|
23
|
22
|
24
|
—
|
—
|
—
|
|
|
Total Rest of Asia
|
297
|
293
|
307
|
—
|
—
|
—
|
|
|
Total Asia
|
297
|
293
|
307
|
—
|
—
|
—
|
|
|
Australia
c
|
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)
|
|||||||
|
Rosneft
e
(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 entities
f
|
1,041
|
1,006
|
1,111
|
126
|
109
|
102
|
|
a
Includes condensate.
b
Production 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.
c
In 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.
d
All of the production from Canada in subsidiaries is bitumen.
e
2022 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.
f
Includes 2 net mboe/d of NGLs from processing plants in which bp has an interest (
2023
2mboe/d and
2022
2mboe/d).
g
2023 restated, previously reported in NGLs.
Because of rounding, some totals may not agree exactly with the sum of their component parts.
|
|
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 production
a
|
|||
|
2024
|
2023
|
2022
|
|
|
Subsidiaries
|
|||
|
UK
|
197
|
247
|
271
|
|
Total Europe
|
197
|
247
|
271
|
|
Lower 48 onshore
b
|
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 Tobago
b
|
1,145
|
1,191
|
1,276
|
|
Total South America
|
1,145
|
1,191
|
1,276
|
|
Egypt
b
|
904
|
1,220
|
1,272
|
|
Algeria
b
|
—
|
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 subsidiaries
c
|
6,474
|
6,512
|
6,428
|
|
Equity-accounted entities (bp share)
|
|||
|
Rosneft
d
(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 entities
c
|
440
|
432
|
674
|
|
Total subsidiaries and equity-accounted entities
|
6,914
|
6,944
|
7,101
|
a
Production 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.
b
In 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.
c
Natural 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.
d
2022 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 oil
b
|
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 oil
b
|
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 oil
b
|
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 entities
c
|
|||||||||||
|
2024
|
|||||||||||
|
Crude oil
b
|
—
|
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 oil
b
|
—
|
81.61
|
—
|
—
|
75.49
|
80.21
|
—
|
75.21
|
—
|
78.33
|
|
|
Natural gas liquids
d
|
—
|
—
|
—
|
—
|
30.95
|
42.89
|
N/A
|
—
|
—
|
36.70
|
|
|
Gas
|
—
|
12.80
|
—
|
—
|
3.66
|
—
|
—
|
—
|
—
|
5.15
|
|
|
2022
|
|||||||||||
|
Crude oil
b
|
—
|
71.14
|
—
|
—
|
78.05
|
86.73
|
102.84
|
90.16
|
—
|
90.18
|
|
|
Natural gas liquids
d
|
—
|
—
|
—
|
—
|
46.64
|
—
|
N/A
|
—
|
—
|
46.64
|
|
|
Gas
|
—
|
24.23
|
—
|
—
|
4.75
|
—
|
4.35
|
—
|
—
|
6.91
|
|
Average production cost per unit of production
e
|
$ 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
|
|
a
Units of production are barrels for liquids and thousands of cubic feet for gas. Realizations include transfers between businesses, except in the case of Russia.
b
Includes condensate.
c
In 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.
d
Natural gas liquids for Russia are included in crude oil.
e
Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes.
|
|
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 sales
a
|
2,714
|
2,718
|
2,613
|
|
|
Trading/supply sales
b
|
373
|
358
|
350
|
|
|
Total refined product sales
|
3,087
|
3,076
|
2,963
|
|
|
Crude oil
c
|
86
|
102
|
184
|
|
|
Total
|
3,173
|
3,178
|
3,147
|
a
Marketing 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.
b
Trading/supply sales are fuel sales to large unbranded resellers and other oil companies.
c
Crude 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.
R
etail sit
es
a
|
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
|
a
Reported 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 throughputs
abc
de
|
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
|
a
This does not include bp’s interest in Pan American Energy Group.
b
Refinery throughputs reflect crude oil and other feedstock volumes.
c
On 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.
d
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.
e
On 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.
|
328
|
bp Annual Report and Form 20-F 2024
|
Refinery capacity
The following table
ab
summarizes bp's average daily crude distillation capacities as at
31 December 2024
.
|
Crude distillation
capacities
c
|
||||
|
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
|
Gelsenkirchen
d
|
265
|
|
|
Lingen
|
97
|
|||
|
Netherlands
|
Rotterdam
|
394
|
||
|
Mediterranean
|
Spain
|
Castellón
|
110
|
|
|
|
866
|
|||
|
Total capacity at
31 December 2024
|
1,557
|
a
This does not include bp’s interest in Pan American Energy Group.
b
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.
c
Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period under normal operational conditions.
d
On 6 February 2025 bp announced its intention to market its Ruhr Oel GmbH – BP Gelsenkirchen operation in Germany for potential sale, including its refinery in Gelsenkirchen and DHC Solvent Chemie
GmbH in Mülheim an der Ruhr.
|
|
bp Annual Report and Form 20-F 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
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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
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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 CO
2
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 CO
2
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
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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.
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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.
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•
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 Gu
lf 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 pe
rcentage of ordinary share capital see
Financial statements –
Note 37
. For information on significant joint
ventures
«
and associates
«
of the group see Financial statements – No
tes
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
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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 a
nnually. 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 corpor
ate 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
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 recom
mendations 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
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.
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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. T
his 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
oversees cyber security risk and received reports from
bp’s chief
committee meeting in 2024, including information on bp’s response to
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
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
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.
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,
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|
|
Additional disclosures
|
technology EVP, other senior leadership and relevant board and
management committees about incidents on an as needed basis.
report key risks, including cyber security risks, to relevant members of
information security assessments for certain providers, providing relevant
trainings for bp employees, and maintaining information security
requirements for suppliers.
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
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 audito
r.
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
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
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
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|
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
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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.
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Purchases of equity securities by the issuer and
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Fees and charges payable by ADS holders
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Fees and payments made by the Depositary to the
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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 Februar
y 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
matters that may affect the business of the group set out in Our strategy on
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 ADS
a
|
March
|
June
|
September
|
December
|
Total
|
|
|
2020
|
UK pence
|
48.94
|
50.05
|
24.26
|
23.50
|
146.75
|
|
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
|
|
US cents
|
32.76
|
32.76
|
36.04
|
36.04
|
137.60
|
|
|
2023
|
UK pence
|
33.30
|
31.85
|
34.39
|
34.42
|
133.97
|
|
US cents
|
39.66
|
39.66
|
43.62
|
43.62
|
166.56
|
|
|
2024
|
UK pence
|
34.15
|
34.10
|
36.30
|
37.78
|
142.33
|
|
US cents
|
43.62
|
43.62
|
48.00
|
48.00
|
183.24
|
|
a
Dividends 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.
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|
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:
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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.
Register of members holding bp ordinary shares as at
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 1,000,000
a
|
555
|
0.29
|
95.79
|
|
Totals
|
193,796
|
100
|
100
|
a
Includes JPMorgan Chase Bank, N.A. holding
25.92
%
of the total ordinary issued share capital
(excluding shares held in treasury) as the app
roved depositary for ADSs, a breakdown of which is
shown in the table below.
Regi
ster of holders of American depositary shares (ADSs) as at
31 December
2024
a
|
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 1,000,000
b
|
2
|
0.00
|
96.63
|
|
Totals
|
59,342
|
100
|
100
|
a
One ADS represents
six
25 cent
ordinary
shares.
b
One 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.
|
|
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 d
isclosures.
|
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 Bank
a
|
651,587,439
|
4.00
|
651,587,439
|
4.00
|
a
In 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.
|
|
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
purchased
a
|
Average price
paid per share
$
|
Number of
shares
purchased by
ESOPs or for
certain employee
share-based
plans
b
|
Number of shares
purchased under
buyback
programmes
c
|
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
|
a
All share purchases were of ordinary shares of
$0.25
each and/or ADSs (each representing
six
ordinary shares) and were on/open market transactions.
b
Transactions represent the purchases of ordinary shares and ADSs made to satisfy requirements of certain employee share-based payment plans.
c
Share 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.
|
|
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
|
a
Dividend 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.
|
350
|
bp Annual Report and Form 20-F 2024
|
Shareholding administration
If you have any queries about the administration of shareholdings, such as
change of address, change of ownership, dividend payment options or to
change the way you receive your company documents (such as the
bp
Annual Report and Form 20-F
and
Notice of bp Annual General Meeting
)
please contact the bp Registrar or the bp ADS Depositary.
Holders of American Depositary Receipts may request to inspect the books
of the Depositary and the listing of receipt holders by contacting the bp ADS
Depositary.
Ordinary and preference shareholders
The bp Registrar, MUFG Corporate Markets
Central Square,
29 Wellington Street,
Leeds, LS1 4DL
Freephone in the UK 0800 701107
From outside the UK +44 (0)371 277 1014
bp share centre mybpshares.com
ADS holders
bp Shareowner Services
PO Box 64504, St Paul, MN 55164-0504, US
Toll-free in the US +1 877 638 5672
From outside the US +1 651 306 4383
2025
shareholder calendar
a
|
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
|
a
All future dates are provisional and may be subject to change. For the full calendar see bp.com/
financialcalendar.
|
|
bp Annual Report and Form 20-F 2024
|
351
|
|
Glossary
|
Glossary
Abbreviations
ADR
American depositary receipt.
ADS
American depositary share. 1 ADS = 6 ordinary shares.
Barrel (bbl)
159 litres, 42 US gallons.
bcf
Billion cubic feet.
bcfe
Billion cubic feet equivalent.
boe
Barrels of oil equivalent.
CAGR
Compound annual growth rate.
EJ/yr
Exajoules per year.
EVP
Executive vice president.
FPSO
Floating production, storage and offloading.
GAAP
Generally accepted accounting practice.
Gas
Natural gas.
gCO
2
e/MJ
Grams of carbon dioxide equivalent per megajoule of energy.
GHG
Greenhouse gas.
GRI
Global Reporting Initiative.
GtCO
2
Gigatonnes of carbon dioxide.
GW
Gigawatt.
GWh
Gigawatt hour.
HSSE
Health, safety, security and environment.
IFRS
International Financial Reporting Standards.
kb/d
Thousand barrels per day.
KPIs
Key performance indicators.
kt
Thousand tonnes.
LNG
Liquefied natural gas.
LPG
Liquefied petroleum gas.
mb/d
Thousand barrels per day.
Mbbl
Million barrels.
mboe/d
Thousand barrels of oil equivalent per day.
mmb/d
Million barrels per day.
mmboe/d
Million barrels of oil equivalent per day.
mmBtu
Million British thermal units.
mmcf/d
Million cubic feet per day.
Mt
Million tonnes.
MtCO
2
e
Million tonnes of CO
2
equivalent.
Mtpa
Million tonnes per annum.
MW
Megawatt.
MWe
Megawatt electrical.
MWp
Megawatt peak.
NGLs
Natural gas liquids.
PSA
Production-sharing agreement.
PTA
Purified terephthalic acid.
RC
Replacement cost.
SEC
The United States Securities and Exchange Commission.
TWh
Terawatt hour.
SVP
Senior vice president.
scfm
Standard cubic feet per minute
|
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
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
Operational carbon intensity (CI)
The annual average operational GHG emissions (TeCO
2
e/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 CO
2
e/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 CO
2
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 CO
2
.
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 (CO
2
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 CO
2
emissions from the carbon in our upstream oil and gas
production, in respect of the estimated CO
2
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 CO
2
). This aim previously related to Scope 3
|
|
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 CO
2
e/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).
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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
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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
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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.
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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.
|
|
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
|
|
|
|
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 expense
a
|
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)
%
|
|
a
Finance 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 basis
a
|
(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
|
a
A definition for taxation on an underlying RC basis is included under Underlying ETR in the glossary on
page 359
.
|
362
|
bp Annual Report and Form 20-F 2024
|
Adjusted EBITDA
«
|
$ 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
|
||
|
Add back: Depreciation, depletion and amortization
|
16,622
|
15,928
|
14,318
|
|
|
Exploration expenditure written off
|
766
|
746
|
385
|
|
|
Adjusted EBITDA
|
38,012
|
43,710
|
60,747
|
Reconciliation of RC profit before interest and tax for gas & low carbon energy and oil production & operations to
adjusted EBITDA
|
$ million
|
||||
|
2024
|
2023
|
2022
|
||
|
gas & low carbon energy
|
||||
|
RC profit before interest and tax
|
3,569
|
14,080
|
14,696
|
|
|
Less: Net favourable (adverse) impact of adjusting items
|
(3,234)
|
5,358
|
(1,367)
|
|
|
Underlying RC profit before interest and tax
|
6,803
|
8,722
|
16,063
|
|
|
Add back: Depreciation, depletion and amortization
|
4,835
|
5,680
|
5,008
|
|
|
Exploration expenditure written off
|
222
|
362
|
2
|
|
|
Adjusted EBITDA
|
11,860
|
14,764
|
21,073
|
|
|
oil production & operations
|
||||
|
RC profit before interest and tax
|
10,789
|
11,191
|
19,721
|
|
|
Less: 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
|
|
|
Add back: Depreciation, depletion and amortization
|
6,797
|
5,692
|
5,564
|
|
|
Exploration expenditure written off
|
544
|
384
|
383
|
|
|
Adjusted EBITDA
|
19,278
|
18,857
|
26,171
|
|
|
bp Annual Report and Form 20-F 2024
|
363
|
|
Non-IFRS measures reconciliations
|
Underlying operating expenditure
«
reconciliation
|
$ million
|
|||
|
2024
|
2023
|
||
|
From group income statement
|
|||
|
Production and manufacturing expenses
|
26,584
|
25,044
|
|
|
Distribution and administration expenses
|
16,417
|
16,772
|
|
|
43,001
|
41,816
|
||
|
Less certain variable costs:
|
|||
|
Transportation and shipping costs
|
11,531
|
10,752
|
|
|
Environmental costs
|
2,972
|
3,169
|
|
|
Marketing and distribution costs
|
1,882
|
2,430
|
|
|
Commission, storage and handling costs
|
1,519
|
1,633
|
|
|
Other variable costs and non-cash costs
|
1,495
|
743
|
|
|
Certain variable costs
|
19,399
|
18,727
|
|
|
Operating expenditure
«
|
23,602
|
23,089
|
|
|
Less certain adjusting items
«
:
|
|||
|
Gulf of America oil spill
|
51
|
57
|
|
|
Environmental and related provisions
|
181
|
647
|
|
|
Restructuring, integration and rationalization costs
|
222
|
(37)
|
|
|
Fair value accounting effects – derivative instruments relating to the hybrid bonds
|
221
|
(630)
|
|
|
Other certain adjusting items
|
601
|
419
|
|
|
Certain adjusting items
|
1,276
|
456
|
|
|
Underlying operating expenditure
|
22,326
|
22,633
|
|
|
Underlying operating expenditure reduction relative to 2023
|
(307)
|
||
|
Increase/(decrease) in underlying operating expenditure due to inflation, exchange, portfolio changes and organic growth
|
443
|
||
|
Structural cost reduction
«
|
(750)
|
The Directors’ report on
pages 69-87
,
88
(in respect of the remuneration committee),
111
,
223-250
and
311-363
was approved by the board and signed on
its behalf by Ben J. S. Mathews, company secretary on
6 March 2025
.
BP p.l.c.
Registered in England and Wales No. 102498
|
364
|
bp Annual Report and Form 20-F 2024
|
Signatures
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to
sign this annual report on its behalf.
BP p.l.c.
(Registrant)
/s/ Ben J. S. Mathews
Company secretary
6 March 2025
|
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.
|
Memorandum and Articles of Association of BP
p.l.c.†
|
||
|
Description of rights of each class of securities
registered under Section 12 of the Securities
Exchange Act of 1934†
|
||
|
The BP Executive Directors’ Incentive Plan†
|
||
|
Director’s Service Agreement for K
Thomson***†
|
||
|
Director’s Service Agreement for M
Auchincloss***†
|
||
|
The BP Share Award Plan 2015**†
|
||
|
Subsidiaries (included as Note 37 to the
Financial Statements)
|
||
|
Code of Ethics*†
|
||
|
Insider trading policy and procedure
|
||
|
Rule 13a – 14(a) Certifications†
|
||
|
Rule 13a – 14(b) Certifications#†
|
||
|
Consent of Netherland, Sewell & Associates†
|
||
|
Report of Netherland, Sewell & Associates†
|
||
|
Consent Decree**†
|
||
|
Gulf states Settlement Agreement**†
|
||
|
Consent of Deloitte LLP†
|
||
|
Guaranteed Securities†
|
||
|
Executive Compensation Clawback Policy†
|
||
|
Exhibit 101
|
Inline XBRL data files
|
|
|
Exhibit 104
|
Cover page interactive data file (formatted as
Inline XBRL and contained in Exhibit 101)
|
|
*
|
Incorporated by reference to the company’s Annual Report on Form 20-F for
the year ended 31 December 2009.
|
|
|
**
|
Incorporated by reference to the company’s Annual Report on Form 20-F for
the year ended 31 December 2015.
|
|
|
***
|
Incorporated by reference to the company’s Annual Report on Form 20-F for
the year ended 31 December 2023.
|
|
|
#
|
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.
|
368
|
bp Annual Report and Form 20-F 2024
|
This report is printed on Arena White Smooth paper and board. Forest Stewardship Council®
(FSC®) certified paper sourced from well-managed forests and other controlled sources.
The paper is Elemental Chlorine Free (ECF) and Acid Free.
Printed in the UK by Pureprint Group, CarbonNeutral®, ISO14001 and FSC® certified.
bp’s corporate reporting suite
includes information about
our financial and operating
performance, sustainability
performance and global
energy trends and projections.
|
|
|
bp.com
|
© BP p.l.c. 2025
bp Annual Report and Form 20-F
2024
Details of our financial and operating
performance in print and online.
|
|
|
|
bp.com/annualreport
|
bp Sustainability Report
2024
Details of our sustainability
performance with additional
information online.
|
|
|
|
bp.com/sustainability
|
bp Energy Outlook
2024
Provides our projections of future
energy trends and factors that could
affect them out to 2040.
|
|
|
|
bp.com/energyoutlook
|
Group databook
2020
-
2024
Five-year financial and operating data
in PDF and Excel format.
|
|
|
|
bp.com/financial-disclosure
|
Copies
You can order selected bp printed
publications free of charge from
|
|
|
|
bp.com/printedcopies
|
US and Canada
Issuer Direct
Toll-free: +1 888 301 2505
|
|
|
|
bpreports@issuerdirect.com
|
UK and rest of world
bp Distribution Services
Tel: +44 (0) 800 037 2172
|
|
|
|
bpdistributionservices@bp.com
|
Feedback
Your feedback is important
to us. You can contact the
corporate reporting team at
|
|
|
|
corporatereporting@bp.com
|
TABLE OF CONTENTS
Item 17 Item 18Item As The Contractual Obligations AreNote 4 and Note 16 For Further Information onItem Used ToNote 25 and Note 29. Further Information on The Management Of LiquidityNote 22 For Further InformationItem 16J Insider Trading PolicyItem 1. Identity Of Directors, Senior Management and Advisersn/aItem 2. Offer Statistics and Expected Timetablen/aItem 3. Key InformationItem 4. Information on The CompanyItem 4A. Unresolved Staff CommentsnoneItem 5. Operating and Financial Review and ProspectsItem 6. Directors, Senior Management and EmployeesItem 7. Major Shareholders and Related Party TransactionsItem 8. Financial InformationItem 9. The Offer and ListingItem 10. Additional InformationItem 11. Quantitative and Qualitative Disclosures About Market Risk195-201Item 12. Description Of Securities Other Than Equity SecuritiesItem 13. Defaults, Dividend Arrearages and DelinquenciesnoneItem 14. Material Modifications To The Rights Of Security Holders and Use Of ProceedsnoneItem 15. Controls and Procedures139, 336Item 16. [reserved]n/aItem 16A. Audit Committee Financial Expert82Item 16B. Code Of Ethics335-336Item 16C. Principal Accountant Fees and Services84, 221, 337Item 16D. Exemptions From The Listing Standards For Audit Committeesn/aItem 16E. Purchases Of Equity Securities By The Issuer and Affiliated Purchasers348Item 16F. Change in Registrant S Certifying Accountantn/aItem 16G. Corporate Governance335Item 16H. Mine Safety Disclosuren/aItem 16I. Disclosure Regarding Foreign Jurisdictions That Prevent Inspectionsn/aItem 16J. Insider Trading Policies.335Item 16K. Cybersecurity336-337Item 17. Financial Statementsn/aItem 18. Financial Statements140-144Item 19. Exhibits366