# EDGAR Filing Document

**Accession Number:** 0000313807
**File Stem:** 0000313807-26-000006
**Filing Date:** 2026-3
**Character Count:** 2483056
**Document Hash:** b6edc33572bdcfe626f3ed4a239ad28d
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0000313807-26-000006.hdr.sgml**: 20260306

**ACCESSION NUMBER**: 0000313807-26-000006

**CONFORMED SUBMISSION TYPE**: 20-F

**PUBLIC DOCUMENT COUNT**: 616

**CONFORMED PERIOD OF REPORT**: 20251231

**FILED AS OF DATE**: 20260306

**DATE AS OF CHANGE**: 20260306

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** BP PLC
- **CENTRAL INDEX KEY:** 0000313807
- **STANDARD INDUSTRIAL CLASSIFICATION:** PETROLEUM REFINING [2911]
- **ORGANIZATION NAME:** 01 Energy & Transportation
- **EIN:** 000000000
- **STATE OF INCORPORATION:** X0
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** 20-F
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 001-06262
- **FILM NUMBER:** 26728391

**BUSINESS ADDRESS:**
- **STREET 1:** 1 ST JAMES'S SQUARE
- **CITY:** LONDON
- **STATE:** X0
- **ZIP:** SW1Y 4PD
- **BUSINESS PHONE:** 442074964000

**MAIL ADDRESS:**
- **STREET 1:** 1 ST JAMES'S SQUARE
- **CITY:** LONDON
- **STATE:** X0
- **ZIP:** SW1Y 4PD

**FORMER COMPANY:**
- **FORMER CONFORMED NAME:** BP AMOCO PLC
- **DATE OF NAME CHANGE:** 19990104

**FORMER COMPANY:**
- **FORMER CONFORMED NAME:** BRITISH PETROLEUM CO PLC
- **DATE OF NAME CHANGE:** 19970226

?xml version='1.0' encoding='ASCII'? bp-20251231

**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

**FORM 20-F**

(Mark One)

☐ **REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934**

**OR**

☒ **ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**

**For the fiscal year ended 31 December 2025** 

**OR**

☐ **TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**

**OR**

☐ **SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**

**Commission file number: 1-06262**

**BP p.l.c.**

**(Exact name of Registrant as specified in its charter)**

**England and Wales**

**(Jurisdiction of incorporation or organization)**

**1 St James's Square, London SW1Y 4PD**

**United Kingdom**

**(Address of principal executive offices)**

**Kate Thomson**

**BP p.l.c.**

**1 St James's Square, London SW1Y 4PD**

**United Kingdom**

**Tel +44 (0) 20 7496 4000**

**Fax +44 (0) 20 7496 4630**

**(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)**

------

**Securities registered or to be registered pursuant to Section 12(b) of the Act**

---

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

---

**\*** 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** | 16486312994 |
| **Cumulative First Preference Shares of £1 each** | 7232838 |
| **Cumulative Second Preference Shares of £1 each** | 5473414 |

---

------

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.&nbsp;&nbsp;&nbsp;&nbsp;Yes ☒&nbsp;&nbsp;&nbsp;&nbsp;No ☐

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.&nbsp;&nbsp;&nbsp;&nbsp;Yes ☐&nbsp;&nbsp;&nbsp;&nbsp;No ☒

Note—Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.&nbsp;&nbsp;&nbsp;&nbsp;Yes ☒&nbsp;&nbsp;&nbsp;&nbsp;No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).&nbsp;&nbsp;&nbsp;&nbsp;Yes ☒&nbsp;&nbsp;&nbsp;&nbsp;No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See definition of "large accelerated filer," "accelerated filer," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ☒&nbsp;&nbsp;&nbsp;&nbsp; Accelerated filer ☐ Non-accelerated filer ☐ Emerging growth company ☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐

† The term "new or revised financial accounting standard" refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. &nbsp;&nbsp;&nbsp;&nbsp;☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive- based compensation received by any of the registrant's executive oﬃcers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP ☐ &nbsp;&nbsp;&nbsp;&nbsp; International Financial Reporting Standards as issuedby the International Accounting Standards Board ☒ Other ☐

If "Other" has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.

Item 17 ☐&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Item 18 ☐

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).&nbsp;&nbsp;&nbsp;&nbsp;Yes ☐&nbsp;&nbsp;&nbsp;&nbsp;No ☒

![FrontCoverV7.jpg](bp-20251231_g1.jpg)

**bp Annual Report** 

## and Form 20-F 2025
![InsideFrontCoverV14.jpg](bp-20251231_g2.jpg)

Strong performance –

building for the future

Our primary targets

Our investor proposition

A simpler, stronger and more

valuable bp, see page <u>[19](#i0dd2ee81aac04f8c9c97c86197f0c6df_49)</u>.

Our strategy

We are growing the upstream,

focusing the downstream and

investing with discipline in

transition, see page <u>[8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31)</u>.

**Adjusted free cash flow**★ **growth**

>20%<sup>a</sup>

adjusted free cash flow compound

annual growth rate (CAGR)★ from

2024-27

**Net debt**★

$14-18bn

by end 2027

**Structural cost reduction**★

$5.5-6.5bn<sup>b</sup>

by end 2027

**Return on average capital** 

**employed (ROACE)**★

>16%<sup>a</sup>

in 2027

---

| | |
|:---|:---|
|  | Progress on our primary targets, page <u>[8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31)</u> |
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Progress on our primary targets, page <u>[8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31)</u> |

---

**Growing** 

**the upstream**

**Focusing** 

**the downstream**

**Disciplined investment** 

**in transition**

**Image:** Argos platform, US

**Image:** bp retail site, London, UK

**Image:** bp bioenergy, Brazil

aThis is on a price adjusted basis that assumes a hypothetical price environment of $70/bbl Brent, $4/mmBtu Henry Hub, and $10.3/bbl refining indicator margin (all 2024 real) and assumptions

about the impact of these marker prices on underlying replacement cost profit before tax.

bFollowing the outcome of the strategic review of *Castrol*, which resulted in the decision to divest a 65% shareholding, the $4-5 billion structural cost reduction target by end 2027, introduced

at the February 2025 Capital Markets Update, has increased.

![49789_bp_AR25_Contents_v4.jpg](bp-20251231_g4.jpg)

bp Annual Report and Form 20-F 2025<sub>1</sub>

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

---

| | |
|:---|:---|
| **Strategic report** |  |
| About bp | [2](#i0dd2ee81aac04f8c9c97c86197f0c6df_13) |
| Chair's letter | [4](#i0dd2ee81aac04f8c9c97c86197f0c6df_19) |
| Interim chief executive officer's letter | [5](#i0dd2ee81aac04f8c9c97c86197f0c6df_22) |
| The operating environment | [6](#i0dd2ee81aac04f8c9c97c86197f0c6df_25) |
| Energy outlook | [7](#i0dd2ee81aac04f8c9c97c86197f0c6df_28) |
| Our strategy  | [8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31) |
| Our strategy in action | [9](#i0dd2ee81aac04f8c9c97c86197f0c6df_5051) |
| Consistency with the Paris goals | [10](#i0dd2ee81aac04f8c9c97c86197f0c6df_34) |
| Our business model | [12](#i0dd2ee81aac04f8c9c97c86197f0c6df_37) |
| Key performance indicators | [14](#i0dd2ee81aac04f8c9c97c86197f0c6df_1099511633060) |
| Our financial frame | [18](#i0dd2ee81aac04f8c9c97c86197f0c6df_46) |
| Our investment process | [20](#i0dd2ee81aac04f8c9c97c86197f0c6df_52) |
| Group performance | [24](#i0dd2ee81aac04f8c9c97c86197f0c6df_61) |
| Gas & low carbon energy | [28](#i0dd2ee81aac04f8c9c97c86197f0c6df_67) |
| Oil production & operations | [31](#i0dd2ee81aac04f8c9c97c86197f0c6df_70) |
| Customers & products | [34](#i0dd2ee81aac04f8c9c97c86197f0c6df_73) |
| Other businesses & corporate | [36](#i0dd2ee81aac04f8c9c97c86197f0c6df_76) |
| Sustainability | [37](#i0dd2ee81aac04f8c9c97c86197f0c6df_79) |
| Climate-related financial disclosures (TCFD) | [41](#i0dd2ee81aac04f8c9c97c86197f0c6df_88) |
| Our approach to sustainability  | [55](#i0dd2ee81aac04f8c9c97c86197f0c6df_103) |
| Risk management and internal control | [60](#i0dd2ee81aac04f8c9c97c86197f0c6df_106) |
| Principal risks and uncertainties (Risk factors) | [62](#i0dd2ee81aac04f8c9c97c86197f0c6df_6396) |
| How we manage principal risks and uncertainties | [67](#i0dd2ee81aac04f8c9c97c86197f0c6df_109) |
| Compliance information | [71](#i0dd2ee81aac04f8c9c97c86197f0c6df_112) |
| Non-financial and sustainability information statement | [71](#i0dd2ee81aac04f8c9c97c86197f0c6df_115) |
| Section 172 statement | [71](#i0dd2ee81aac04f8c9c97c86197f0c6df_118) |
| **Corporate governance** |  |
| Board of directors | [73](#i0dd2ee81aac04f8c9c97c86197f0c6df_130) |
| Leadership team | [76](#i0dd2ee81aac04f8c9c97c86197f0c6df_133) |
| Governance framework | [77](#i0dd2ee81aac04f8c9c97c86197f0c6df_136) |
| Board activities | [78](#i0dd2ee81aac04f8c9c97c86197f0c6df_139) |
| Our stakeholders | [80](#i0dd2ee81aac04f8c9c97c86197f0c6df_142) |
| Key decisions | [81](#i0dd2ee81aac04f8c9c97c86197f0c6df_151) |
| Safety and sustainability committee | [82](#i0dd2ee81aac04f8c9c97c86197f0c6df_160) |
| Audit committee | [84](#i0dd2ee81aac04f8c9c97c86197f0c6df_166) |
| People, culture and governance committee | [89](#i0dd2ee81aac04f8c9c97c86197f0c6df_184) |
| Remuneration committee | [91](#ia422778a52d64a26b1673bf21b127e90_2013) |
| Directors' remuneration report | [91](#i0dd2ee81aac04f8c9c97c86197f0c6df_187) |
| Other disclosures | [126](#i0dd2ee81aac04f8c9c97c86197f0c6df_217) |
| **Financial statements** |  |
| Consolidated financial statements of the bp group | [129](#i0dd2ee81aac04f8c9c97c86197f0c6df_232) |
| Notes on the financial statements | [160](#i0dd2ee81aac04f8c9c97c86197f0c6df_268) |
| Supplementary information on oil and natural gas (unaudited) | [241](#i0dd2ee81aac04f8c9c97c86197f0c6df_397) |
| Additional disclosures | [334](#i0dd2ee81aac04f8c9c97c86197f0c6df_475) |
| Shareholder information | [364](#i0dd2ee81aac04f8c9c97c86197f0c6df_547) |
| Glossary | [375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586) |
| Non-IFRS measure reconciliations | [384](#i0dd2ee81aac04f8c9c97c86197f0c6df_589) |
| Signatures | [389](#i0dd2ee81aac04f8c9c97c86197f0c6df_592) |
| Cross-reference to Form 20-F | [390](#i0dd2ee81aac04f8c9c97c86197f0c6df_595) |
| Information about this report | [391](#i0dd2ee81aac04f8c9c97c86197f0c6df_598) |
| Exhibits | [391](#i0dd2ee81aac04f8c9c97c86197f0c6df_604) |

---

---

| | |
|:---|:---|
| **Navigating this report** | **Navigating this report** |
|  | Read more on another page of this report |
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Read more on another page of this report |
|  | Read more online |
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | Read more online |
| **Task Force on Climate-related Financial** <br>**Disclosures (TCFD)** <br>Information that supports TCFD <br>Recommendations and Recommended <br>Disclosures in relation to Metrics and Targets <br>is indicated with TCFD.<br>**Glossary**<br>Words and terms marked with ★ are defined <br>in the glossary on page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u> | **Task Force on Climate-related Financial** <br>**Disclosures (TCFD)** <br>Information that supports TCFD <br>Recommendations and Recommended <br>Disclosures in relation to Metrics and Targets <br>is indicated with TCFD.<br>**Glossary**<br>Words and terms marked with ★ are defined <br>in the glossary on page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u> |

---

---

| | |
|:---|:---|
| **More information**<br>**Online quick read**<br>A concise summary of the *bp Annual Report* <br>*and Form 20-F 2025*, highlighting strategy <br>and performance information.  | **More information**<br>**Online quick read**<br>A concise summary of the *bp Annual Report* <br>*and Form 20-F 2025*, highlighting strategy <br>and performance information.  |
|  | <u>bp.com/annualreport</u> |
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | <u>bp.com/annualreport</u> |
| **Online reporting centre**<br>All our bp corporate reports, including <br>the bp Sustainability Report and the <br>bp Energy Outlook. | **Online reporting centre**<br>All our bp corporate reports, including <br>the bp Sustainability Report and the <br>bp Energy Outlook. |
|  | <u>bp.com/reportingcentre</u> |
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | <u>bp.com/reportingcentre</u> |

---

![AboutBPPage1V4.jpg](bp-20251231_g7.jpg)

---

| | | |
|:---|:---|:---|
| 2 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**About bp**<br>

We operate at the heart of the

global energy system, helping

## countries across the world with
their energy needs and serving

millions of customers every day.

**Our purpose**

Delivering energy to the world,

today and tomorrow.

**Who we are**

Our culture frame 'Who we are' defines what

we stand for at bp, building on our best qualities

and those things that are most important to us.

It comprises three simple beliefs that can inspire

each of us at bp to be our best every day: live

our purpose, play to win, care for others.

---

| | |
|:---|:---|
|  | <u>bp.com/ourbeliefs</u> |
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | <u>bp.com/ourbeliefs</u> |

---

**Safety and sustainability**

---

| | |
|:---|:---|
| 27 | 34.3MtCO2e |
| tier 1 and 2 process <br>safety events★<br>(2024 38)<br>| GHG emissions – <br>operational control<br>(2024 33.6MtCO2e)<br>|

---

---

| | |
|:---|:---|
|  | Read more on pages <u>[55](#i0dd2ee81aac04f8c9c97c86197f0c6df_103)</u> and <u>[37](#i0dd2ee81aac04f8c9c97c86197f0c6df_82)</u> |
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Read more on pages <u>[55](#i0dd2ee81aac04f8c9c97c86197f0c6df_103)</u> and <u>[37](#i0dd2ee81aac04f8c9c97c86197f0c6df_82)</u> |

---

---

| |
|:---|
| **Performance** |
| $0.1bn<br>profit for the year attributable <br>to bp shareholders<br>(2024 $0.4bn)<br>$7.5bn<br>underlying replacement cost (RC) profit★ <br>(2024 $8.9bn)<br>2.3m <br>barrels of oil equivalent – oil and gas <br>production<sup>a</sup> <br>(2024 2.4m)<br>90% <br>proved reserves replacement ratio★<sup>a</sup><br>(2024 50%)<br>$6.28/boe <br>upstream unit production costs★<br>(2024 $6.17/boe)<br>96.1% <br>bp-operated upstream plant reliability★<br>(2024 95.2%)<br>96.3% <br>bp-operated refining availability★<br>(2024 94.3%)<br>|

---

aOn a combined basis of subsidiaries and equity-accounted entities.

![AboutBPPage2V7.jpg](bp-20251231_g8.jpg)

bp Annual Report and Form 20-F 2025<sub>3</sub>

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

**Segment performance**

At 31 December 2025, the group's reportable segments

were gas & low carbon energy, oil production &

operations and customers & products. Each is managed

separately, with decisions taken for the segment as a

whole, and represents a single operating segment that

does not result from aggregating two or more segments

(see Financial statements – Note 5).

---

| | | |
|:---|:---|:---|
| **Gas & low carbon energy**<sup>a</sup> | **Gas & low carbon energy**<sup>a</sup> | **Gas & low carbon energy**<sup>a</sup> |
| Comprises our gas & low carbon energy businesses. Our gas <br>business includes regions with upstream activities that <br>predominantly produce natural gas, gas trading and our <br>Archaea Energy business. Our low carbon business includes <br>solar, offshore wind, hydrogen and carbon capture and storage <br>(CCS), and power trading, and until its divestment in December <br>2025 also included onshore wind. Power trading includes <br>trading of both renewable and non-renewable power. | Comprises our gas & low carbon energy businesses. Our gas <br>business includes regions with upstream activities that <br>predominantly produce natural gas, gas trading and our <br>Archaea Energy business. Our low carbon business includes <br>solar, offshore wind, hydrogen and carbon capture and storage <br>(CCS), and power trading, and until its divestment in December <br>2025 also included onshore wind. Power trading includes <br>trading of both renewable and non-renewable power. | Comprises our gas & low carbon energy businesses. Our gas <br>business includes regions with upstream activities that <br>predominantly produce natural gas, gas trading and our <br>Archaea Energy business. Our low carbon business includes <br>solar, offshore wind, hydrogen and carbon capture and storage <br>(CCS), and power trading, and until its divestment in December <br>2025 also included onshore wind. Power trading includes <br>trading of both renewable and non-renewable power. |
| $1.3bn<br>replacement cost (RC) profit <br>before interest and tax<sup>b</sup><br>(2024 $3.1bn<sup>c</sup>) | $1.3bn<br>replacement cost (RC) profit <br>before interest and tax<sup>b</sup><br>(2024 $3.1bn<sup>c</sup>) | $5.4bn<br>underlying RC profit before <br>interest and tax★<br>(2024 $6.8bn)<br>|
|  | Segment performance, page <u>[28](#i0dd2ee81aac04f8c9c97c86197f0c6df_67)</u> | Segment performance, page <u>[28](#i0dd2ee81aac04f8c9c97c86197f0c6df_67)</u> |
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Segment performance, page <u>[28](#i0dd2ee81aac04f8c9c97c86197f0c6df_67)</u> | Segment performance, page <u>[28](#i0dd2ee81aac04f8c9c97c86197f0c6df_67)</u> |

---

---

| | | |
|:---|:---|:---|
| **Oil production & operations**<sup>a</sup> | **Oil production & operations**<sup>a</sup> | **Oil production & operations**<sup>a</sup> |
| Comprises regions with upstream activities that predominantly <br>produce crude oil, including bpx energy. | Comprises regions with upstream activities that predominantly <br>produce crude oil, including bpx energy. | Comprises regions with upstream activities that predominantly <br>produce crude oil, including bpx energy. |
| $8.6bn<br>RC profit before interest <br>and tax<sup>b</sup><br>(2024 $10.8bn) | $8.6bn<br>RC profit before interest <br>and tax<sup>b</sup><br>(2024 $10.8bn) | $9.4bn<br>underlying RC profit before <br>interest and tax<br>(2024 $11.9bn)<br>|
|  | Segment performance, page <u>[31](#i0dd2ee81aac04f8c9c97c86197f0c6df_70)</u> | Segment performance, page <u>[31](#i0dd2ee81aac04f8c9c97c86197f0c6df_70)</u> |
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Segment performance, page <u>[31](#i0dd2ee81aac04f8c9c97c86197f0c6df_70)</u> | Segment performance, page <u>[31](#i0dd2ee81aac04f8c9c97c86197f0c6df_70)</u> |

---

---

| | | |
|:---|:---|:---|
| **Customers & products** | **Customers & products** | **Customers & products** |
| Comprises customer-focused businesses, which include <br>convenience and retail fuels, EV charging, as well as *Castrol*, <br>aviation, B2B, midstream and bp bioenergy. It also comprises <br>our products businesses which include refining and oil trading. | Comprises customer-focused businesses, which include <br>convenience and retail fuels, EV charging, as well as *Castrol*, <br>aviation, B2B, midstream and bp bioenergy. It also comprises <br>our products businesses which include refining and oil trading. | Comprises customer-focused businesses, which include <br>convenience and retail fuels, EV charging, as well as *Castrol*, <br>aviation, B2B, midstream and bp bioenergy. It also comprises <br>our products businesses which include refining and oil trading. |
| $4.1bn<br>RC profit before interest <br>and tax<sup>b</sup><br>(2024 loss $(1.0)bn<sup>c</sup>) | $4.1bn<br>RC profit before interest <br>and tax<sup>b</sup><br>(2024 loss $(1.0)bn<sup>c</sup>) | $5.3bn<br>underlying RC profit before <br>interest and tax<br>(2024 $2.5bn)<br>|
|  | Segment performance, page <u>[34](#i0dd2ee81aac04f8c9c97c86197f0c6df_73)</u> | Segment performance, page <u>[34](#i0dd2ee81aac04f8c9c97c86197f0c6df_73)</u> |
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Segment performance, page <u>[34](#i0dd2ee81aac04f8c9c97c86197f0c6df_73)</u> | Segment performance, page <u>[34](#i0dd2ee81aac04f8c9c97c86197f0c6df_73)</u> |

---

---

| | | |
|:---|:---|:---|
| **Other businesses & corporate** | **Other businesses & corporate** | **Other businesses & corporate** |
| Comprises technology; bp ventures; shipping; our corporate <br>activities and functions; and any residual costs of the Gulf of <br>America oil spill. | Comprises technology; bp ventures; shipping; our corporate <br>activities and functions; and any residual costs of the Gulf of <br>America oil spill. | Comprises technology; bp ventures; shipping; our corporate <br>activities and functions; and any residual costs of the Gulf of <br>America oil spill. |
| $(40)m<br>RC loss before interest <br>and tax<sup>b</sup><br>(2024 loss $(1.0)bn) | $(40)m<br>RC loss before interest <br>and tax<sup>b</sup><br>(2024 loss $(1.0)bn) | $(0.6)bn<br>underlying RC loss before <br>interest and tax<br>(2024 loss $(0.6)bn)<br>|
|  | Segment performance, page <u>[36](#i0dd2ee81aac04f8c9c97c86197f0c6df_76)</u> | Segment performance, page <u>[36](#i0dd2ee81aac04f8c9c97c86197f0c6df_76)</u> |
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Segment performance, page <u>[36](#i0dd2ee81aac04f8c9c97c86197f0c6df_76)</u> | Segment performance, page <u>[36](#i0dd2ee81aac04f8c9c97c86197f0c6df_76)</u> |

---

**Image:** Colleagues at our Houston headquarters, US

aThe Azerbaijan-Georgia-Türkiye and Middle East and North Africa (MENA) regions have been further subdivided by asset.

bIFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker. For bp, this measure of profit

or loss is replacement cost profit before interest and tax, which reflects the replacement cost of inventories sold in the period and is arrived at by excluding inventory holding gains and losses★

from profit before interest and tax. Replacement cost profit for the group is not a recognized measure under IFRS. For further information see Financial statements – Note 5.

cRestated for material items to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment.

---

| | | |
|:---|:---|:---|
| 4 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Chair's letter**<br>

![ChairLetterV5.jpg](bp-20251231_g9.jpg)

**Dear shareholders,**

bp is one of the world's great energy

companies, with a strong team, high quality

assets and distinctive strengths in key

business areas. I was honoured to be

appointed as chair in 2025, joining a company

that is making progress on a reset strategy,

albeit with challenges to overcome. With the

environment in which we operate continuing

to be shaped by geopolitical uncertainty and

complex market dynamics, we need to

accelerate delivery, reduce complexity and

increase our financial resilience in order to

realise the full value of the business for

shareholders.

**Appointment of Meg O'Neill** 

One of my first tasks, working with fellow

board members, was to identify an

outstanding leader to take the company

forward. Murray Auchincloss stepped down in

December 2025 after more than three

decades of service to bp, the last five as a

member of our board, first as chief financial

officer and then as chief executive. I would like

to thank him for his contribution and

commitment to bp.

In December 2025 we appointed Meg O'Neill

as chief executive who will join bp on 1 April

2026. Meg's track record of driving

transformation and growth with disciplined

capital allocation makes her the right leader

for bp as we pursue significant strategic and

financial opportunities. And her relentless

focus on business improvement and financial

discipline gives us high confidence in her

ability to shape the company for its next phase

of growth.

**Safety and performance in 2025** 

The board plays a critical role in monitoring the

organization's culture and setting the tone

from the top. This is particularly important on

safety. Employees and contractors at bp face a

complex range of risks across the business.

Sadly in 2025, four colleagues working in bp's

US retail operations lost their lives. On behalf

of the board, I would like to extend our sincere

condolences to their families, friends and

colleagues.

Safety will always be the board's highest

priority. That's why we continue to work with

the leadership team to ensure every incident is

thoroughly investigated and the lessons

learned are applied.

On process safety, I commend the teams that

contributed to a decrease in serious process

safety events of about one third, compared

with 2024.

Ongoing improvement in safety is the

foundation for strong operational

performance. In 2025 the teams set new

records for plant reliability on the upstream

side of the business and availability in refining.

Strategic progress was also strong with seven

major projects★ delivered in the year and

significant exploration success, including the

world's largest offshore discovery. Carol

provides more detail on safety and

performance in her letter overleaf.

**Governance**

In early 2025 the board's focus moved from

the resetting of strategy to overseeing

disciplined performance and the delivery of

our four primary financial targets. Together

with Meg O'Neill's appointment, the board's

composition and capability have been further

strengthened during 2025 deepening its

expertise in key strategic areas: oil and gas,

disciplined capital allocation and the oversight

of performance and risk.

Our governance framework remains a

foundation for delivering sustainable

long-term value for shareholders. That

framework has also evolved, recognizing the

changing needs of the business and external

developments, including the implementation

of provision 29 of the UK Corporate

Governance Code, relating to risk

management and internal control. And it will

continue to evolve, informed by a further

review, to ensure the framework and the board

that oversees it are best placed for the bp we

want to be, rather than the bp we have been

over recent years.

Engagement with stakeholders remained a

priority in 2025. On joining the board, I initiated

an extensive dialogue with our largest

shareholders, complemented by a continued

focus by the board on workforce engagement.

**More to do**

Over the course of 2026, you will see bp taking

concerted action to strengthen the company

and position it to grow and deliver sustainable

value for the long term. One such step was the

board's decision earlier this year to suspend

the share buyback and fully allocate excess

cash to our balance sheet. And you will see bp

continue to take action to simplify and high-

grade the portfolio, reduce the cost base and

make disciplined investments in the best and

highest-returning opportunities. Most

importantly, you will see the board supporting

a management team focused on growing cash

flow and returns.

**A better bp**

I offer my thanks to the bp teams, whose

dedication, skill and determination continue to

shine through, no matter the challenge. And

thank you to you, bp's owners, for your

guidance and your trust. The board and I will

continue to actively engage with you and

communicate with increasing clarity and

transparency. With your support we can and

will become a stronger bp. One that is more

sustainable in every way, especially in the

creation of value for shareholders.

![AlbertManifold_SigBLACK.jpg](bp-20251231_g10.jpg)

**Albert Manifold**

Chair

6 March 2026

bp Annual Report and Form 20-F 2025<sub>5</sub>

---

| | |
|:---|:---|
|  | ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
|  | **Strategic report** |
| **Interim chief executive officer's letter** |  |

---

![ChiefExecLetterV5.jpg](bp-20251231_g11.jpg)

**Dear fellow shareholders,**

As interim CEO, I want to thank our teams for

their outstanding commitment through a

period of transition for bp. Operational

performance in 2025 was consistently strong

and we made significant progress following

the resetting of our strategy.

Our new chair, Albert Manifold, has set us a

challenge to fulfil bp's true potential – and

I know the team will rise to this. We're focused,

we're in action, we're determined to make bp

the strongest it can be, and we look forward to

welcoming Meg O'Neill as CEO in April 2026.

**Safety comes first**

Tragically, in 2025, four people died while

working in our US retail business. Three were

employees in our TravelCenters of America

business. Two of them were killed in separate

incidents where they were struck by passing

vehicles as they carried out emergency

roadside assistance, highlighting the complex

range of risks faced across our business. In

response, this service on active highways has

been permanently withdrawn to protect our

employees. The fourth was a contractor, in our

*Thorntons* business. Our thoughts are with

their families, friends and colleagues.

In the high-hazard industry we work in, nothing

is more important than safety. We seek to

learn from every incident, no matter how big or

small – and we expect everyone in bp to work

safely. On process safety, we made strong

progress, with 29% fewer combined tier 1 and 2

process safety events★ in 2025, but we have

much more to do.

It is important to say that safety is more than

robust controls and systems. It is also about

having a culture where every decision reflects

care in our work – and care for others. Day in,

day out, we must continue to work towards our

goal: eliminating fatalities, life-changing

injuries and the most serious process safety

incidents.

**Financial and operating performance** 

In 2025 we delivered a strong underlying

financial performance with an underlying RC

profit★ of $7.5 billion<sup>a</sup>, despite a weaker price

environment, and operating cash flow★ of

$24.5 billion.

We also had a strong operational performance

across bp.

In 2025 we:

• Delivered record upstream plant

reliability★ and refining availability★,

with both above 96%.

• Produced 2.3 million barrels of oil and gas

a day, beating our guidance at the start

of 2025.

• Started up seven major projects★ safely,

five ahead of schedule.

• Made 12 discoveries – including bp's

biggest offshore discovery in 25 years,

Bumerangue in Brazil.

• Increased our proved reserves replacement

ratio★ to 90% – up from an average of

around 50% in the previous two years.

**Strategic progress**

We took decisive action to high-grade our

portfolio and strengthen our company in 2025,

including our $20 billion disposal programme

and the subsequent decision to suspend the

share buyback and fully allocate excess cash★

to our balance sheet. These are choices

designed to position us for long-term growth.

We also made progress on our four primary

targets, increasing adjusted free cash flow★<sup>bc</sup>

and returns (ROACE★)<sup>bd</sup>, both on an adjusted

price basis. We reduced net debt★ to $22.2

billion<sup>e</sup> and made progress strengthening our

balance sheet, achieving $2.8 billion<sup>f</sup> of our

$4-5 billion structural cost reduction★ target,

which we have now increased to $5.5-6.5

billion<sup>g</sup>.

In addition, we have announced or completed

over $11 billion of divestments in the first year.

**Looking forward and thanks** 

bp is a great company with huge potential. We

have outstanding technology and engineering

skills, excellent resources and exceptional

global partnerships. And, most of all, we have

brilliant people whose performance across the

year was key to producing strong results.

It is an honour to represent bp as interim CEO,

and the leadership team and I look forward to

the year ahead. My deepest thanks go to our

teams, our partners and our owners. We are

grateful for your support and your challenge,

and together, under Meg's leadership, we will

make bp go from strength to strength.

![49789_bp_CarolHowleSig.jpg](bp-20251231_g12.jpg)

**Carol Howle** 

Interim chief executive officer

6 March 2026

---

| |
|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
| **Nearest IFRS-equivalent** <br>**measures**<br>$0.1bn<br>profit for 2025 attributable to bp <br>shareholders<sup>a</sup><br>$58.0bn<br>finance debt at the end of 2025<sup>e</sup><br>|
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

aUnderlying RC profit for the group is a non-IFRS measure and its nearest IFRS equivalent measure is profit for the year attributable to bp shareholders.

bThis is on a price adjusted basis and is assuming a hypothetical price environment of $70/bbl Brent, $4/mmBtu Henry Hub, and $10.3/bbl refining indicator margin (all 2024 real) and

assumptions about the impact of these marker prices on underlying replacement cost profit before tax.

cAdjusted free cash flow on a price adjusted basis is a non-IFRS measure. The nearest IFRS equivalent measures to calculate adjusted free cash flow on a price adjusted basis CAGR are net cash

provided by operating activities and total cash capital expenditure.

d ROACE on a price adjusted basis is a non-IFRS measure. The nearest IFRS measures of the numerator and denominator are profit for the period attributable to bp shareholders and total equity

respectively.

eNet debt is a non-IFRS measure and its nearest IFRS equivalent measure is finance debt at the end of 2025. See Note 27 for more information.

f Cumulative structural cost reduction since 2023, of which $2 billion in 2025 and $750 million in 2024. Structural cost reduction is decreases in underlying operating expenditure★.

A reconciliation is provided on page [386](#i8d8183dbb7704a419cda8a463c63183a_7089).

g Following the outcome of the strategic review of *Castrol*, which resulted in the decision to divest a 65% shareholding, the $4-5 billion structural cost reduction target by end 2027, introduced at

the February 2025 Capital Markets Update, has increased.

---

| | | |
|:---|:---|:---|
| 6 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Energy markets**<br>

**The operating environment**

bp operates across volatile energy markets.

Here we discuss broader economic trends

we have observed that influence our sector

as a whole.

The world economy grew by around 3.3%<sup>a</sup> in

2025, stronger than had been expected in April

2025<sup>b</sup>. Growth rates varied across economies,

with US GDP estimated to have grown by 2.1%,

while the eurozone economy expanded by only

1.4%<sup>a</sup>. China's growth in 2025 is estimated to

have been 5%<sup>a</sup>, achieving the government

'around 5%' target.

Inflation continued to ease globally, moving

closer to central banks' target levels in most

major economies. This disinflationary trend

allowed several central banks, including the

US Federal Reserve and the European

Central Bank, to cut interest rates. In the

case of the Federal Reserve, further rate

cuts are expected in 2026, based on financial

market pricing.

**Oil** 

Oil prices trended lower during 2025,

amid strong supply and relatively weak

demand growth.

Non-OPEC+ supply grew by 1.8mmb/d<sup>c</sup> in

2025, led by offshore projects, oil sands, tight

oil and NGLs, mostly from the Americas.

OPEC+ supply grew by 1.3mmb/d<sup>c</sup> in 2025,

largely due to unwinding of production cuts

from OPEC+8, especially Saudi Arabia. That

steadily increasing supply meant that global

oil supply is estimated to have been 3mmb/d<sup>c</sup>

higher over the year as a whole than in 2024.

That contrasted with demand growth of only

0.8mmb/d, taking demand to 104mmb/d, and

leading to a supply/demand imbalance of

around 2.2mmb/d over the year as a whole<sup>c</sup>.

The imbalance weighed on prices, with Dated

Brent averaging $69/bbl in 2025, down from

$81/bbl in 2024<sup>d</sup>. OECD commercial

inventories grew by 3% over the course of the

year, compared to a 1% fall last year<sup>e</sup>.

Significant government stockpiling in China of

around 550kb/d in 2Q25 and 3Q25 absorbed

some of the supply/demand imbalance, and

there was also an increase in the amount of oil

being held in tankers at sea, which reached

2,006mmb, 232mmb higher than the five-year

average, as sanctioned Russian and Iranian

barrels were held off the market<sup>c</sup>.

**Natural gas**

In the US, Henry Hub (HH) gas prices

rebounded to their highest level since 2022<sup>f</sup>

due to a 26%<sup>g</sup> year-on-year increase in LNG

export demand and colder-than-normal start

to the year. Higher gas prices supported a

recovery in drilling activity in non-associated

(dry) shale plays which, combined with well

productivity gains, increasing gas-to-oil ratios

in the Permian, and increased pipeline

connectivity, meant that gas production grew

by 4%<sup>g</sup>, reaching record high levels.

Outside of North America, global gas demand

grew by less than 1% in 2025<sup>h</sup>. TTF and JKM

increased 9%<sup>i</sup> and 3%<sup>j</sup>respectively. A further

reduction in Russian supply to the EU at the

onset of 2025 contributed to the higher gas

prices, reducing gas demand growth in Asia in

particular. LNG supply from new liquefaction

projects ramped up through the year and

drove a near 7%<sup>h</sup> increase in global LNG

production.

**Refining indicator margin**

We have updated the metric used to track the

refining margin environment to the refining

indicator margin (RIM)<sup>k</sup>. After a weak 1Q25,

RIM increased over the rest of the year,

supported by lower crude prices, relatively

resilient product demand, tight product

inventories and unplanned capacity outages

and disruptions. RIM averaged $12.8/bbl over

2025 as a whole, up $2.1/bbl (19%) from

its average level in 2024<sup>k</sup>.

**Power and renewables**

Electricity demand growth continued to

outpace total energy demand growth, driven

by increasing electrification in China and by

growing prosperity and industrialization in

emerging economies. Growing demand from

data centres looks set to increase electricity

demand materially in the coming years,

particularly in the US.

Total solar and wind capacity additions in 2025

are estimated to have exceeded 600GW,

breaking the previous record set in 2024<sup>l</sup>.

Bioenergy growth also maintained

momentum, supported by resilient demand

for liquid biofuels in road transport, rising

biomethane output, and a growing pipeline

of announced sustainable aviation fuel

(SAF) capacity.

**Hydrogen and carbon capture** 

**and storage**

Persistent high costs and the slow pace of

enabling policy continued to challenge the

decarbonization of many harder-to-abate

processes, including through technologies

such as low carbon hydrogen and

carbon capture.

The project pipeline for production of low

carbon hydrogen has contracted recently

and only around 4Mtpa<sup>m</sup> is either currently

operational or under construction. Growth of

the global carbon capture and storage project

pipeline slowed significantly in 2025.

Operational and under-construction projects

have now reached just over 100Mtpa<sup>n</sup> in

total capacity.

aIMF World Economic Outlook update, January 2026, measured

on a Purchasing Power Parity basis.

bIMF World Economic Outlook, April 2025, measured on a

Purchasing Power Parity basis.

cIEA Oil Market Report, January 2026.

dLSEG Data Management Solution (Dated Brent spot price).

eIEA Monthly Oil Data Service, January 2026.

fS&P Global Energy Platts Henry Hub spot price.

gEIA Short-term Energy Outlook, January 2026.

hIEA Gas Market Report, Q1-2026.

iS&P Global Energy Platts Dutch TTF day ahead price.

jS&P Global Energy Platts JKM spot price.

k bp has retired the refining marker margin (RMM) and replaced it

with the bp refining indicator margin (RIM). The bp RIM reflects a

broader set of crudes and products, and is more representative

of bp's refining portfolio and realized refining margin per barrel.

Actual margins realized by bp may vary due to a variety of

factors, including the actual mix of crude and product for a

given quarter.

lIEA Renewable Energy Progress Tracker. PV capacity additions

are converted from DC to AC basis.

mIEA Global Hydrogen Review, September 2025.

nGCCSI Global Status of CCS 2025, October 2025.

oLSEG Data Management Solution (West Texas Intermediate).

---

| | | |
|:---|:---|:---|
| **Market activity** | **2025** | 2024 |
| Global oil consumption<sup>c</sup> | **104.0mmb/d** | 103.2mmb/d |
| Global oil production<sup>c</sup> | **106.2mmb/d** | 103.1mmb/d |
| Natural gas consumption<sup>h</sup> | **4,286bcm** | 4,251bcm |
| Natural gas production<sup>h</sup> | **4,264bcm** | 4,224bcm |
| Dated Brent average<sup>d</sup> | **$69.10/bbl** | $80.76/bbl |
| West Texas Intermediate (WTI)★ average<sup>o</sup> | **$64.87/bbl** | $75.87/bbl |
| Henry Hub average<sup>f</sup> | **$3.52/mmBtu** | $2.19/mmBtu |
| Dutch Title Transfer Facility (TTF)★ average<sup>i</sup> | **36.2 Euros per MWh** <br>**($11.9/mmBtu)**<br>| 34.4 Euros per MWh <br>($10.9/mmBtu)<br>|
| Japan-Korea (Asian) LNG average<sup>j</sup> | **$12.2/mmBtu** | $11.9/mmBtu |
| Refining indicator margin<sup>k</sup>★ | **$12.8/bbl** | $10.7/bbl |

---

bp Annual Report and Form 20-F 2025<sub>7</sub>

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

**Energy outlook**

The *bp Energy Outlook 2025 (2025 Outlook)* 

explores the trends and uncertainties

surrounding the energy transition out to 2050.

The *2025 Outlook* helps inform bp's views of

the risks and opportunities posed by the

energy transition. The scenarios within it

explore the possible implications of different

judgements and assumptions concerning the

nature of the energy transition. The uncertainty

associated with the transition is substantial,

and these scenarios are not predictions of

what is likely to happen or what bp would like

to see happen. We use the output from these

scenarios to help inform our strategic thinking.

We published the *2025 Outlook* in September

2025, designed around two scenarios

informed by recent trends and developments

in the global energy system. The *2025 Outlook* 

provides key insights about how the energy

system may evolve over the next 25 years.

The two scenarios – Current Trajectory and

Below 2°C (see 'Two scenarios to explore the

energy transition', below) – explore the speed

and shape of the energy transition out to 2050

and help to inform a resilient strategy for bp.

A new section in the *2025 Outlook* uses

sensitivity analysis to discuss several key

issues affecting the energy transition,

including the possible implications of

increased geopolitical fragmentation and

sustained weakness in energy efficiency. Each

sensitivity analysis examined possible impacts

on the global energy system.

**Scenarios for strategic** 

**decision making**

We use scenarios to inform strategy, manage

risk, and improve decision making.

Some of these scenarios are based on climate

and other policies currently in force, and on

current global aims and pledges around the

energy transition. Other scenarios are based

on achieving a certain pace or degree of

transition, and consider how the energy

system might change to achieve that.

In thinking about appropriate scenarios to

inform our strategy, we use both approaches.

**How scenarios inform our strategy** 

The use of scenarios described in the *2025* 

*Outlook*, and those from other organizations,

aids our understanding of the energy

transition and helps us to think about how

different outcomes might impact our strategy.

The use of a broad range of scenarios to

inform our strategy supports our efforts to

make it robust and resilient to the range of

uncertainty we face.

By considering various time horizons we can

identify key milestones or signposts which

might emerge over the next five, 10 or 25 years

and inform our view of the key sources of

uncertainty affecting the global energy system.

We actively monitor changes in the

external environment and refresh or review

the scenarios as needed in response to

these signals.

For the purposes of testing the resilience

of our strategy to the range of uncertainty in

the energy transition, we have used scenarios

drawn from other credible sources such as the

International Energy Agency (IEA), the Network

for Greening the Financial System (NGFS) and

the UN Principles for Responsible Investment

(UN PRI) to compile a catalogue of scenarios

(our Transition Scenario Catalogue★). These

include some scenarios considered by these

data providers to be consistent with 1.5°C and

well-below 2°C.

Read more on the Transition Scenario

Catalogue, our resilience analysis and the

outcome of that work on page <u>[49](#i0dd2ee81aac04f8c9c97c86197f0c6df_4576)</u>.

**How we create scenarios**

We quantify the scenarios in the *2025 Outlook* 

using our global energy modelling system.

This comprises a suite of models to help us

understand the supply and demand dynamics

of the global energy system.

---

| | | | |
|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Two scenarios to explore the energy transition**<br>Carbon emissions Gt CO2e<sup>a</sup> | **Two scenarios to explore the energy transition**<br>Carbon emissions Gt CO2e<sup>a</sup> |  |
|  | **Current Trajectory** ![CarbonEmissionsKeyGreen.gif](bp-20251231_g15.gif)<br>| **Below 2°** ![CarbonEmissionsKeyDeepBlue.gif](bp-20251231_g16.gif)<br>|  |
|  | is designed to capture the broad pathway <br>along which the global energy system is <br>currently travelling. It places weight on climate <br>policies already in force and on global aims <br>and pledges for future decarbonization. At the <br>same time, it recognizes the myriad <br>challenges associated with meeting these <br>aims. CO2 equivalent (CO2e) emissions in <br>Current Trajectory peak in the mid-2020s and <br>by 2050 are around 25% below 2023 levels.<br>| explores how different elements of the energy <br>system might change to achieve a substantial <br>reduction in carbon emissions (a net 90% fall <br>in CO2e emissions by 2050). It assumes a <br>significant tightening of climate policies <br>alongside shifts in societal behaviour and <br>preferences, which together support more <br>rapid adoption of low carbon energy alongside <br>faster gains in energy efficiency.<br>|  |
|  |  | History![CarbonEmissionsKeyBPDeepGreenRule_Key_Graphic.gif](bp-20251231_g17.gif)<br>|  |
|  | a Carbon emissions include CO2 emissions from energy use, industrial processes, natural gas flaring and methane <br>emissions from energy production. | a Carbon emissions include CO2 emissions from energy use, industrial processes, natural gas flaring and methane <br>emissions from energy production. |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

The modelling framework uses historical data

based on the Energy Institute's Statistical

Review of World Energy, the IEA's World

Energy Balances data and a range of other

data sets.

Each scenario is determined by a set of key

assumptions, including population and

economic growth, pace of technological

change, resource constraints and government

policies. These are informed by expert analysis

from external organizations including the

United Nations, Oxford Economics and Rystad

Energy. We benchmark our scenarios against

external organizations including the IEA, the

IPCC, and S&P Global.

The modelling techniques used vary by sector

![14](bp-20251231_g18.gif)

and include a combination of econometric

![46810_bp_CarbonEmissionsKeyBPDashRule_Graphic.gif](bp-20251231_g19.gif)

modelling, adoption curves and consumer

choice modelling.

---

| | |
|:---|:---|
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | *bp Energy Outlook 2025* <br><u>bp.com/energyoutlook</u><br>|

---

![](bp-20251231_g20.gif)

---

| | | |
|:---|:---|:---|
| 8 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Our strategy**<br>

Our strategy helps bp compete and grow value as energy demand evolves and continues to grow,

all in service of growing shareholder value and returns.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ![BPGreenTopRoundCorner.gif](bp-20251231_g21.gif) |  |  |  |  |  | ![BPGreenTopRoundCorner.gif](bp-20251231_g21.gif) |
|  | ![BPLightGreen-SMALL-TopRoundCornerV2.gif](bp-20251231_g22.gif) |  | ![BPLightGreen-SMALL-TopRoundCornerV2.gif](bp-20251231_g22.gif) |  | ![BPLightGreen-SMALL-TopRoundCornerV2.gif](bp-20251231_g22.gif) |  |
|  |  | **Growing** <br>**upstream**<br>|  | **Focusing**<br>**downstream**<br>|  |  |
|  | ![BPLightGreen-SMALL-BottomRoundCornerV2.gif](bp-20251231_g23.gif) |  | ![BPLightGreen-SMALL-BottomRoundCornerV2.gif](bp-20251231_g23.gif) |  | ![BPLightGreen-SMALL-BottomRoundCornerV2.gif](bp-20251231_g23.gif) |  |
|  |  | Disciplined investment in transition | Disciplined investment in transition | Disciplined investment in transition |  |  |
| ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |  |  |  |  |  | ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |

---

**Growing the upstream: our oil and gas business**

We are growing upstream production and cash flow through disciplined

investment. We have a deep upstream resource base, and combined

with disciplined investment criteria, we are well positioned to deliver

medium and long-term organic growth.

**Focusing the downstream:** 

**our customers and products business**

We continue to reshape the portfolio to focus on markets and businesses

where we have advantaged and integrated positions. We are taking clear

actions to drive improved performance, including addressing costs in our

customers business, and improving operations in refining.

**Investing with discipline in transition**

We are investing with discipline: with selective investment in biogas,

biofuels and EV charging, where we see strong demand growth;

adopting innovative capital-light partnerships in renewables; and

focusing investment on hydrogen and carbon capture projects to

support us in decarbonizing our operations, and position us for

growth through the next decade.

**All while continuing to drive value through our** 

**distinctive strengths in trading, technology** 

**and partnerships.**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Progress on our primary targets**<br>We use four primary targets to measure our progress and how we are improving performance. These targets, <br>alongside the guidance and financial frame (see page <u>[18](#i0dd2ee81aac04f8c9c97c86197f0c6df_46)</u>), support our strategy. Taken together, we believe <br>our primary targets will underpin growth in the value of bp. Our progress in 2025 is set out below: | **Progress on our primary targets**<br>We use four primary targets to measure our progress and how we are improving performance. These targets, <br>alongside the guidance and financial frame (see page <u>[18](#i0dd2ee81aac04f8c9c97c86197f0c6df_46)</u>), support our strategy. Taken together, we believe <br>our primary targets will underpin growth in the value of bp. Our progress in 2025 is set out below: | **Progress on our primary targets**<br>We use four primary targets to measure our progress and how we are improving performance. These targets, <br>alongside the guidance and financial frame (see page <u>[18](#i0dd2ee81aac04f8c9c97c86197f0c6df_46)</u>), support our strategy. Taken together, we believe <br>our primary targets will underpin growth in the value of bp. Our progress in 2025 is set out below: | **Nearest** <br>**IFRS-equivalent** <br>**measures**<br>|  |
|  | Primary targets | 2025 | Targets | 2025 |  |
|  | **Adjusted free cash** <br>**flow growth**★<br>|  | **>20%**<sup>a</sup> <br>compound annual growth rate <br>from 2024-27<br>|  |  |
|  | **Net debt**★ | **$22.2bn**<sup>b</sup> | **$14-18bn** <br>by end 2027<br>| **$58.0bn**<sup>b</sup> <br>finance debt<br>|  |
|  | **Structural cost** <br>**reduction**★<br>| **$2.8bn**<sup>c</sup><br>(cumulative since 2023)<br>| **$5.5-6.5bn**<sup>d</sup> <br>by end 2027<br>| **n/a** |  |
|  | **Return on average capital** <br>**employed (ROACE)**★<br>| **13.9%**<sup>e</sup> | **>16%**<sup>a</sup><br>in 2027<br>| **0.1%**<sup>e</sup><br>profit for 2025 attributable to bp <br>shareholders divided by total <br>equity at 31 December 2025<br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

aThis is on a price adjusted basis that assumes a hypothetical price environment of $70/bbl Brent, $4/mmBtu Henry Hub, and $10.3/bbl refining indicator margin (all 2024 real) and assumptions

about the impact of these marker prices on underlying replacement cost profit before tax.

bNet debt is a non-IFRS measure. The nearest IFRS equivalent measure is finance debt at the end of 2025. See Note 27 for more information.

cCumulative structural cost reduction since 2023, of which $2 billion in 2025 and $750 million in 2024. Structural cost reduction is decreases in underlying operating expenditure★. A reconciliation

is provided on page [386](#i8d8183dbb7704a419cda8a463c63183a_7089).

dFollowing the outcome of the strategic review of *Castrol*, which resulted in the decision to divest a 65% shareholding, the $4-5 billion structural cost reduction target by end 2027, introduced at

the February 2025 Capital Markets Update, has increased.

eReturn on average capital employed (ROACE) is a non-IFRS measure. The nearest IFRS measures of the numerator and denominator are profit for 2025 attributable to bp shareholders of $0.1

billion and total equity at the end of 2025 of $74.0 billion respectively. A reconciliation is provided on page [385](#i8d8183dbb7704a419cda8a463c63183a_7088).

![49789_bp_AR25_Page9OurStrategyInActionV4.jpg](bp-20251231_g25.jpg)

bp Annual Report and Form 20-F 2025<sub>9</sub>

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

**Our strategy in action**

---

| | | |
|:---|:---|:---|
| **Growing** <br>**upstream** <br>In 2025 we advanced our upstream strategy <br>and delivered seven major project start-ups, <br>five of which were ahead of schedule. Start-ups <br>included GTA, in Mauritania and Senegal, Cypre <br>in Trinidad and Murlach in the UK North Sea. We <br>also announced 12 discoveries, including <br>Bumerangue in Brazil, our largest exploration <br>discovery in 25 years, plus further finds in Brazil, <br>Egypt, the Gulf of America, Libya and Trinidad, <br>as well as discoveries in Namibia and Angola <br>through Azule Energy, our 50-50 joint venture <br>with Eni.<br>In upstream oil and gas production, we achieved <br>our best wells reliability in years at 98% and <br>a record full-year plant reliability★ at >96%%. <br>Our proved reserves replacement ratio★ was <br>90% – up from an average of around 50% in the <br>prior two years. | In April we announced a Miocene oil discovery at <br>the Far South prospect in Green Canyon Block <br>584, 120 miles off the coast of Louisiana. Drilled <br>to 23,830 feet in 4,092 feet of water, the <br>discovery signals potentially commercial <br>volumes and helps to strengthen our <br>upstream portfolio.<br>In August we announced the start-up of the <br>Argos Southwest Extension project, seven <br>months ahead of schedule. From appraisal to <br>first oil, the project was developed in about 25 <br>months – a record for bp. Argos has a gross <br>production capacity of up to 140,000 barrels of <br>oil per day (boe/d). <br>In December the development programme for <br>the Karabagh field in the Caspian Sea, offshore <br>Azerbaijan, was approved by the management <br>committee (joint venture) and subsequently by <br>State Oil Company of the Azerbaijan Republic <br>(SOCAR) as the State representative. Seismic <br>acquisition commenced thereafter. <br>We also completed the divestment of the <br>Culzean gas field in the UK North Sea to NEO <br>Next in December. <br>**Image:** Argos Southwest Extension project, US | In April we announced a Miocene oil discovery at <br>the Far South prospect in Green Canyon Block <br>584, 120 miles off the coast of Louisiana. Drilled <br>to 23,830 feet in 4,092 feet of water, the <br>discovery signals potentially commercial <br>volumes and helps to strengthen our <br>upstream portfolio.<br>In August we announced the start-up of the <br>Argos Southwest Extension project, seven <br>months ahead of schedule. From appraisal to <br>first oil, the project was developed in about 25 <br>months – a record for bp. Argos has a gross <br>production capacity of up to 140,000 barrels of <br>oil per day (boe/d). <br>In December the development programme for <br>the Karabagh field in the Caspian Sea, offshore <br>Azerbaijan, was approved by the management <br>committee (joint venture) and subsequently by <br>State Oil Company of the Azerbaijan Republic <br>(SOCAR) as the State representative. Seismic <br>acquisition commenced thereafter. <br>We also completed the divestment of the <br>Culzean gas field in the UK North Sea to NEO <br>Next in December. <br>**Image:** Argos Southwest Extension project, US |
| **Growing** <br>**upstream** <br>In 2025 we advanced our upstream strategy <br>and delivered seven major project start-ups, <br>five of which were ahead of schedule. Start-ups <br>included GTA, in Mauritania and Senegal, Cypre <br>in Trinidad and Murlach in the UK North Sea. We <br>also announced 12 discoveries, including <br>Bumerangue in Brazil, our largest exploration <br>discovery in 25 years, plus further finds in Brazil, <br>Egypt, the Gulf of America, Libya and Trinidad, <br>as well as discoveries in Namibia and Angola <br>through Azule Energy, our 50-50 joint venture <br>with Eni.<br>In upstream oil and gas production, we achieved <br>our best wells reliability in years at 98% and <br>a record full-year plant reliability★ at >96%%. <br>Our proved reserves replacement ratio★ was <br>90% – up from an average of around 50% in the <br>prior two years. | ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Read more on page <u>[28](#i0dd2ee81aac04f8c9c97c86197f0c6df_67)</u><u>-</u><u>[33](#i45ed17c2274b431982b2501af8d1cd2c_0-0-1-3-939845)</u> |

---

---

| | | |
|:---|:---|:---|
| **Focusing** <br>**downstream**<br>2025 was also a strong year for the downstream, <br>delivering a significant step up in performance. <br>We achieved around $1.6 billion in cumulative <br>structural cost reductions★ (2024-25) and <br>sustained refinery availability★ above 96%, <br>strengthening commercial performance across <br>refining, trading, midstream and fuels. <br>Customers reported its highest underlying RC <br>profit before interest and tax★ since 2019, with <br>growth across all businesses.<br>As we continue streamlining our portfolio, in <br>2025 we reached an agreement to sell a 65%  | stake in *Castrol*, completed the sale of the <br>Netherlands mobility, convenience and *bp pulse* <br>businesses, and announced plans to sell the <br>Gelsenkirchen refinery and the Austria retail <br>business. <br>As part of our broader retail network high-<br>grading programme, in 2025 we exited around <br>5% of our company owned retail sites★, <br>supporting our plan to exit around 10% by 2027. <br>In EV charging, we are focusing investment on <br>four core markets and utilising our retail <br>network to maximise returns. <br>**Image:** Rotterdam refinery, Netherlands | stake in *Castrol*, completed the sale of the <br>Netherlands mobility, convenience and *bp pulse* <br>businesses, and announced plans to sell the <br>Gelsenkirchen refinery and the Austria retail <br>business. <br>As part of our broader retail network high-<br>grading programme, in 2025 we exited around <br>5% of our company owned retail sites★, <br>supporting our plan to exit around 10% by 2027. <br>In EV charging, we are focusing investment on <br>four core markets and utilising our retail <br>network to maximise returns. <br>**Image:** Rotterdam refinery, Netherlands |
| **Focusing** <br>**downstream**<br>2025 was also a strong year for the downstream, <br>delivering a significant step up in performance. <br>We achieved around $1.6 billion in cumulative <br>structural cost reductions★ (2024-25) and <br>sustained refinery availability★ above 96%, <br>strengthening commercial performance across <br>refining, trading, midstream and fuels. <br>Customers reported its highest underlying RC <br>profit before interest and tax★ since 2019, with <br>growth across all businesses.<br>As we continue streamlining our portfolio, in <br>2025 we reached an agreement to sell a 65%  | ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Read more on page <u>[34](#i0dd2ee81aac04f8c9c97c86197f0c6df_73)</u> |

---

---

| | | |
|:---|:---|:---|
| **Disciplined** <br>**investment in** <br>**transition**<br>We focused our low carbon energy portfolio in <br>2025, prioritizing investment choices that deliver <br>value for shareholders. <br>We formed JERA Nex bp, a 50:50 offshore wind <br>joint venture between JERA and bp. The new <br>joint venture brings together each parties' <br>complementary expertise for a balanced mix of <br>operating assets and development projects.  | We sold our US onshore wind business to <br>LS Power. And we continued to manage the <br>pace of investment in biogas and refine and <br>high-grade our hydrogen and carbon, capture <br>and storage (CCS) portfolio. This included <br>decisions not to progress H2Teesside and to <br>end participation in projects in Oman, Australia <br>and the US Gulf Coast. In 2025 we focused on <br>delivering four sanctioned projects in 2024: <br>Lingen green hydrogen project, Castellón <br>green hydrogen project, the Northern <br>Endurance Partnership (NEP), and Net Zero <br>Teesside Power (NZT) – and the UCC project <br>in Indonesia. | We sold our US onshore wind business to <br>LS Power. And we continued to manage the <br>pace of investment in biogas and refine and <br>high-grade our hydrogen and carbon, capture <br>and storage (CCS) portfolio. This included <br>decisions not to progress H2Teesside and to <br>end participation in projects in Oman, Australia <br>and the US Gulf Coast. In 2025 we focused on <br>delivering four sanctioned projects in 2024: <br>Lingen green hydrogen project, Castellón <br>green hydrogen project, the Northern <br>Endurance Partnership (NEP), and Net Zero <br>Teesside Power (NZT) – and the UCC project <br>in Indonesia. |
| **Disciplined** <br>**investment in** <br>**transition**<br>We focused our low carbon energy portfolio in <br>2025, prioritizing investment choices that deliver <br>value for shareholders. <br>We formed JERA Nex bp, a 50:50 offshore wind <br>joint venture between JERA and bp. The new <br>joint venture brings together each parties' <br>complementary expertise for a balanced mix of <br>operating assets and development projects.  | ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Read more on page <u>[28](#i0dd2ee81aac04f8c9c97c86197f0c6df_67)</u> |

---

**Delivering operational value** <br>From predictive analytics to seismic imaging, <br>we are applying technological solutions to <br>deliver operational value. In our upstream, <br>technology has helped to lift plant reliability <br>to 96.1%. Advances in seismic imaging are <br>helping us explore more accurately, <br>contributing to one of our best recorded <br>years for exploration with 12 new discoveries, <br>including through our joint ventures. And <br>digital tools such as our asset and wells <br>trajectory optimizer (AWTO) help plan safe <br>routes from the surface to the reservoir in <br>days instead of weeks or months.<br>

**Digital-led marketing** <br>**transformation**<br>As part of our global marketing <br>transformation programme, we <br>consolidated 19 digital platforms into <br>six and activated a global marketing and <br>communications hub in Mumbai in 2025. <br>The programme also includes deploying <br>AI-driven technology to develop investment <br>insights in more than 40 markets and <br>tools to support segmentation and <br>personalization. These changes have <br>helped to streamline operations, <br>accelerate delivery, and strengthen <br>customer engagement.<br>

---

| | | |
|:---|:---|:---|
| 10 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Consistency with the Paris goals**<br>

Pursuing a strategy that is consistent

with the Paris goals

**What we mean by Paris-consistent** 

The 2019 CA100+ resolution★ requires us

to disclose the strategy that the board

considers in good faith to be consistent

with the Paris goals.

When we refer to 'consistency with Paris' we

consider this to mean consistency with the

world meeting the temperature goal set out in

Articles 2.1(a) and 4.1 of the Paris Agreement on

Climate Change★.

The Paris goals, which we support, were

restated in the Global Mutirão at COP30 in

Belém in November 2025.

We believe the world is on an unsustainable

path, and the carbon budget to meet the Paris

goals is running out.

bp's strategy is informed by these

considerations. It is designed to create long-

term value for shareholders, while enabling

delivery of our net zero ambition. It is tested

for resilience to the uncertainty of the energy

transition across many different potential

pathways, including various Paris-consistent

pathways.

In the *bp Annual Report and Form 20-F 2021* 

we set out, based on **three key principles**, why

the board considers our strategy to be

consistent with the Paris goals. Here we set

out, on the same three grounds, why the board

continues to consider this to be the case.

**Informed by Paris-consistent energy** 

**transition scenarios**

The speed and nature of the energy transition

are uncertain, and so we consider a range of

scenarios from multiple sources including the

*bp Energy Outlook 2025* (see page <u>[7](#i0dd2ee81aac04f8c9c97c86197f0c6df_28)</u>) to

develop and test our strategic thinking. This

helps to reinforce our confidence in the

robustness and resilience of our strategy to

the range of uncertainty we face.

We are confident that our approach is science

based. We see the Intergovernmental Panel on

Climate Change (IPCC) as the most

authoritative source of information on the

science of climate change, and we use it and

other sources such as the IEA World Energy

Outlook to inform our strategy. The IPCC

highlights that there are a range of global

pathways by which the world can meet the

Paris goals, with differing implications for

regions, industry sectors and sources

of energy.

**Strategic resilience**

We believe our strategy positions bp for

success and resilience in a Paris-consistent

world – a world that is progressing on one of

the many global trajectories considered to be

Paris-consistent, and ultimately meets the

Paris goals.

The strategy diversifies bp's portfolio and

business interests, reducing the risk that

challenges facing a single business area might

adversely affect bp's strategic resilience.

In addition, within the inevitable constraints

associated with factors such as long-term

capital investments, contractual commitments

and organizational capabilities at any given

time, bp's ability to maintain its strategic

resilience rests, in part, on the governance

used to keep the strategy and associated

targets and aims under review in light of new

information and changes in circumstances.

In our climate-related financial disclosures on

page <u>[49](#i0dd2ee81aac04f8c9c97c86197f0c6df_4576)</u>, we describe how we have conducted

an analysis to test our view of the resilience of

our strategy, based on the Capital Markets

Update presented on 26 February 2025 (and

the financial frame presented with bp's fourth-

quarter and full-year 2025 results on 10

February 2026), to different climate-related

scenarios.

For the purposes of testing the resilience

of our strategy to the range of uncertainty in

the energy transition, we have used scenarios

drawn from other credible sources such as the

International Energy Agency (IEA), the Network

for Greening the Financial System (NGFS) and

the UN Principles for Responsible Investment

(UN PRI) to compile a catalogue of scenarios

(our Transition Scenario Catalogue★). These

include scenarios considered by these data

providers to be consistent with well-below 2°C

and 1.5°C outcomes<sup>a</sup>.

As further explained on page <u>[50](#i0e463dddb5f34cbb8013af453c074d8c_40553)</u>, while the

results of any such analysis must be treated

with caution overall, this resilience test again

reinforced our confidence in the continued

resilience of our strategy to a wide range of

ways in which the energy system could evolve

throughout this decade, including in scenarios

consistent with limiting temperature rise

to 1.5°C.

The analysis also again highlighted that, while

within the Transition Scenario Catalogue

lowest oil prices are associated with 1.5°C

scenarios, there is considerable uncertainty –

demonstrated by the range within, and overlap

between, the prices indicated for each

scenario family.

In the Transition Scenario Catalogue used for

the analysis, while the lowest oil price is

associated with a 1.5°C scenario, a number of

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

prices in 2030 that are substantially higher

than this – and when compared to bp's own

central case oil price planning assumption for

2030, the oil price in a number of the well-

below 2°C and 1.5°C scenarios is also higher.

Taking this into account, the analysis

supported our belief that our strategy is

financially resilient against the lowest prices

associated with a Paris-consistent world in the

Transition Scenario Catalogue. This in turn

supports our view that our strategy is resilient

to such a Paris-consistent world.

aOur 2025 analysis used data from our Transition Scenario Catalogue★ which is based on the WBCSD Climate Scenario Catalogue version 3.0, published on 16-05-2024 and downloaded on

13-11-2024, with updates made for scenario updates subsequently published by relevant underlying data providers – such as IEA, UN PRI and NGFS. For more details on this see page [54](#i0dd2ee81aac04f8c9c97c86197f0c6df_100).

bp Annual Report and Form 20-F 2025<sub>11</sub>

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

**Contributes to net zero** 

We believe that our strategy enables bp to

make a positive contribution to the world

achieving net zero greenhouse gas (GHG)

emissions and meeting the Paris goals –

outcomes which we believe to be in the

best interests of bp as well as beneficial to

society generally.

We continue to see opportunity in the energy

transition – and there are many ways bp can

contribute to the world getting to net zero

outside of our aims to be net zero across our

operations and sales by 2050 or sooner.

In addition to our transition businesses★ such

as Archaea Energy and bp bioenergy, we aim

to make a meaningful contribution to the

world getting to net zero through investing

with discipline in low carbon energy in ways

that are capital light for bp. These investments

are not readily quantifiable by metrics

associated with bp's net zero aims. Examples

of investments:

• Lightsource bp operates with a develop,

engineer, construct and farm-down

business model that creates value through

selling majority interests in assets it has

developed to strategic partners. Our net

zero aims only recognize the impact of

power when we sell it, rather than the

power produced by assets we have

farmed down.

• In 2025 JERA and bp completed the

formation of JERA Nex bp, a 50:50-owned

joint venture (JV), see page <u>[9](#i0dd2ee81aac04f8c9c97c86197f0c6df_5051)</u>. The

development of renewable power

generation often helps to displace more

carbon intensive alternatives and thus

supports decarbonization of the

power grid.

• In 2025 in the UK, bp and partners

continued to develop the Net Zero

Teesside Power (NZT Power) and Northern

Endurance Partnership (NEP) projects.

The NZT and NEP projects have started

construction on-site, with commercial

operations expected in 2028. Once fully

operational NZT will have the ability to

capture up to 2 million tonnes of CO2 per

annum for storage via the NEP storage

infrastructure which is sized for an initial

4 million tonnes of CO2 per annum within

the East Coast Cluster, with the ability

to expand in the future. Where CO2 is

transported offshore for permanent

storage on behalf of other entities (such

as local heavy industries), this will not

show up in bp's GHG metrics.

We also support collective action through

participation in external initiatives, low carbon

collaboration and support for others in their

own decarbonization efforts. We seek to use

the company's influence with trade

associations that conduct climate-related

advocacy.

As part of our broader advocacy efforts in

connection with bp's strategy, we continue to

advocate for well-designed policies that

enable an energy transition consistent with the

goals of the Paris Agreement.

Helping policymakers to design and put in

place scalable low carbon policies that

support the transition to net zero can help

deliver our strategy and capitalize on the

opportunities associated with the world

achieving the Paris goals, but the benefit of

such actions, if successful, extends well

beyond any implications for bp's own GHG

metrics. That is because well-designed low

carbon policies can advance the

decarbonization of a whole economy –

something of potentially greater impact than

a single company can achieve through its

own portfolio.

---

| | | |
|:---|:---|:---|
| **Responding to shareholder interest in Paris consistency**<br>In 2019 the board recommended that shareholders support a special resolution requisitioned by <br>Climate Action 100+ (CA100+) on climate change disclosures. The CA100+ resolution passed with <br>more than 99% of votes cast. This is the seventh year we have included responses throughout <br>the Annual Report and we have adopted a similar approach to previous years. <br>The CA100+ resolution, which includes safeguards such as protections for commercially <br>confidential and competitively sensitive information, is on page <u>[376](#ic1bd6a858b574c36a4546a99df7ac8f6_67007)</u>. Key terms related to this <br>resolution response are indicated with ★ and defined in the glossary on page <u>[376](#ic1bd6a858b574c36a4546a99df7ac8f6_67007)</u>. These should <br>be reviewed with the following information: | **Responding to shareholder interest in Paris consistency**<br>In 2019 the board recommended that shareholders support a special resolution requisitioned by <br>Climate Action 100+ (CA100+) on climate change disclosures. The CA100+ resolution passed with <br>more than 99% of votes cast. This is the seventh year we have included responses throughout <br>the Annual Report and we have adopted a similar approach to previous years. <br>The CA100+ resolution, which includes safeguards such as protections for commercially <br>confidential and competitively sensitive information, is on page <u>[376](#ic1bd6a858b574c36a4546a99df7ac8f6_67007)</u>. Key terms related to this <br>resolution response are indicated with ★ and defined in the glossary on page <u>[376](#ic1bd6a858b574c36a4546a99df7ac8f6_67007)</u>. These should <br>be reviewed with the following information: | **Responding to shareholder interest in Paris consistency**<br>In 2019 the board recommended that shareholders support a special resolution requisitioned by <br>Climate Action 100+ (CA100+) on climate change disclosures. The CA100+ resolution passed with <br>more than 99% of votes cast. This is the seventh year we have included responses throughout <br>the Annual Report and we have adopted a similar approach to previous years. <br>The CA100+ resolution, which includes safeguards such as protections for commercially <br>confidential and competitively sensitive information, is on page <u>[376](#ic1bd6a858b574c36a4546a99df7ac8f6_67007)</u>. Key terms related to this <br>resolution response are indicated with ★ and defined in the glossary on page <u>[376](#ic1bd6a858b574c36a4546a99df7ac8f6_67007)</u>. These should <br>be reviewed with the following information: |
| **Element of the CA100+ resolution** | **Related content** | **Where** |
| Strategy that the board considers in good <br>faith to be consistent with the Paris goals. | Our strategy and business model | [8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31) & [12](#i0dd2ee81aac04f8c9c97c86197f0c6df_37) |
| Strategy that the board considers in good <br>faith to be consistent with the Paris goals. | Pursuing a strategy that is <br>consistent with the Paris goals<br>| [10](#i0dd2ee81aac04f8c9c97c86197f0c6df_34) |
| How bp evaluates each new material capex <br>investment★ for consistency with the <br>Paris goals and other outcomes relevant to <br>bp strategy.<br>| Our investment process | [20](#i0dd2ee81aac04f8c9c97c86197f0c6df_52) |
| Disclosure of bp's principal metrics and <br>relevant targets or goals over the short, <br>medium and long term, consistent with the <br>Paris goals. | Key performance indicators | [14](#i0dd2ee81aac04f8c9c97c86197f0c6df_1099511633060) |
| Disclosure of bp's principal metrics and <br>relevant targets or goals over the short, <br>medium and long term, consistent with the <br>Paris goals. | Sustainability: net zero aims and <br>targets<br>| [37](#i0dd2ee81aac04f8c9c97c86197f0c6df_82) |
| Disclosure of bp's principal metrics and <br>relevant targets or goals over the short, <br>medium and long term, consistent with the <br>Paris goals. | See 'TCFD Metrics & Targets' for an <br>overview<br>| [54](#i0dd2ee81aac04f8c9c97c86197f0c6df_100) |
| Anticipated levels of investment in:<br>(i) Oil and gas resources and reserves.<br>(ii) Other energy sources and technologies. | Our strategy | [8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31) |
| Anticipated levels of investment in:<br>(i) Oil and gas resources and reserves.<br>(ii) Other energy sources and technologies. | Financial frame: disciplined <br>investment allocation<br>| [18](#i0dd2ee81aac04f8c9c97c86197f0c6df_46) |
| Anticipated levels of investment in:<br>(i) Oil and gas resources and reserves.<br>(ii) Other energy sources and technologies. | Transition business★ investment | [21](#i0dd2ee81aac04f8c9c97c86197f0c6df_55) |
| bp's targets to promote operational <br>GHG reductions.<br>| Sustainability: net zero★ aims | [37](#i0dd2ee81aac04f8c9c97c86197f0c6df_82) |
| Estimated carbon intensity of bp's energy <br>products and progress over time.<br>| Sustainability: net zero sales aim★  | [38](#ia533d1b86ea04772b2fd02ae3d1c8da0_9654) |
| Any linkage between above targets and <br>executive pay remuneration. | Directors' remuneration report | [91](#i0dd2ee81aac04f8c9c97c86197f0c6df_187) |
| Any linkage between above targets and <br>executive pay remuneration. | 2025 annual bonus outcome | [99](#i0dd2ee81aac04f8c9c97c86197f0c6df_205) |
| Any linkage between above targets and <br>executive pay remuneration. | 2026 remuneration policy | [106](#i0dd2ee81aac04f8c9c97c86197f0c6df_211) |

---

![BusinessModelPage12V3.jpg](bp-20251231_g26.jpg)

---

| | | |
|:---|:---|:---|
| 12 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Our business model**<br>

An integrated energy company

We believe we have a world-class portfolio – a top-tier oil and gas

business in attractive basins, and leading integrated positions and

brands across the value chain. All underpinned by distinctive

capabilities in trading, technology and partnerships.

---

| | |
|:---|:---|
|  | Read more about our strategy, page <u>[8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31)</u> |
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Read more about our strategy, page <u>[8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31)</u> |

---

---

| | |
|:---|:---|
| **People and** <br>**resources**<sup>a</sup><br>| **Our organization** |
| 61 <br>countries of operation<br>93,700<br>employees<br>~11,300<br>engineers<br>$14.5bn <br>capital expenditure★<br>$274m <br>invested in research <br>and development<br>2,958<br>granted and pending patent <br>applications held by bp and its <br>subsidiaries<br>6,191mmboe<br>proved hydrocarbon <br>reserves for the group<sup>b</sup><br>>110 years<br>energy sector experience<br>a Data as at 31 December 2025.<br>b On a combined basis of subsidiaries and <br>equity-accounted entities. See page [248](#i0dd2ee81aac04f8c9c97c86197f0c6df_403) <br>for more information on bp's oil and <br>gas reserves. | We have three main businesses – <br>gas & low carbon energy, production & <br>operations, and customers & products – <br>enabled by supply, trading & shipping <br>and technology.<br>And three teams serve as enablers of <br>business delivery: finance; legal; and <br>people, culture & communications.<br>|
| 61 <br>countries of operation<br>93,700<br>employees<br>~11,300<br>engineers<br>$14.5bn <br>capital expenditure★<br>$274m <br>invested in research <br>and development<br>2,958<br>granted and pending patent <br>applications held by bp and its <br>subsidiaries<br>6,191mmboe<br>proved hydrocarbon <br>reserves for the group<sup>b</sup><br>>110 years<br>energy sector experience<br>a Data as at 31 December 2025.<br>b On a combined basis of subsidiaries and <br>equity-accounted entities. See page [248](#i0dd2ee81aac04f8c9c97c86197f0c6df_403) <br>for more information on bp's oil and <br>gas reserves. |  |
| 61 <br>countries of operation<br>93,700<br>employees<br>~11,300<br>engineers<br>$14.5bn <br>capital expenditure★<br>$274m <br>invested in research <br>and development<br>2,958<br>granted and pending patent <br>applications held by bp and its <br>subsidiaries<br>6,191mmboe<br>proved hydrocarbon <br>reserves for the group<sup>b</sup><br>>110 years<br>energy sector experience<br>a Data as at 31 December 2025.<br>b On a combined basis of subsidiaries and <br>equity-accounted entities. See page [248](#i0dd2ee81aac04f8c9c97c86197f0c6df_403) <br>for more information on bp's oil and <br>gas reserves. |  |
| 61 <br>countries of operation<br>93,700<br>employees<br>~11,300<br>engineers<br>$14.5bn <br>capital expenditure★<br>$274m <br>invested in research <br>and development<br>2,958<br>granted and pending patent <br>applications held by bp and its <br>subsidiaries<br>6,191mmboe<br>proved hydrocarbon <br>reserves for the group<sup>b</sup><br>>110 years<br>energy sector experience<br>a Data as at 31 December 2025.<br>b On a combined basis of subsidiaries and <br>equity-accounted entities. See page [248](#i0dd2ee81aac04f8c9c97c86197f0c6df_403) <br>for more information on bp's oil and <br>gas reserves. | **Enabled by** |
| 61 <br>countries of operation<br>93,700<br>employees<br>~11,300<br>engineers<br>$14.5bn <br>capital expenditure★<br>$274m <br>invested in research <br>and development<br>2,958<br>granted and pending patent <br>applications held by bp and its <br>subsidiaries<br>6,191mmboe<br>proved hydrocarbon <br>reserves for the group<sup>b</sup><br>>110 years<br>energy sector experience<br>a Data as at 31 December 2025.<br>b On a combined basis of subsidiaries and <br>equity-accounted entities. See page [248](#i0dd2ee81aac04f8c9c97c86197f0c6df_403) <br>for more information on bp's oil and <br>gas reserves. |  |
| 61 <br>countries of operation<br>93,700<br>employees<br>~11,300<br>engineers<br>$14.5bn <br>capital expenditure★<br>$274m <br>invested in research <br>and development<br>2,958<br>granted and pending patent <br>applications held by bp and its <br>subsidiaries<br>6,191mmboe<br>proved hydrocarbon <br>reserves for the group<sup>b</sup><br>>110 years<br>energy sector experience<br>a Data as at 31 December 2025.<br>b On a combined basis of subsidiaries and <br>equity-accounted entities. See page [248](#i0dd2ee81aac04f8c9c97c86197f0c6df_403) <br>for more information on bp's oil and <br>gas reserves. |  |
| 61 <br>countries of operation<br>93,700<br>employees<br>~11,300<br>engineers<br>$14.5bn <br>capital expenditure★<br>$274m <br>invested in research <br>and development<br>2,958<br>granted and pending patent <br>applications held by bp and its <br>subsidiaries<br>6,191mmboe<br>proved hydrocarbon <br>reserves for the group<sup>b</sup><br>>110 years<br>energy sector experience<br>a Data as at 31 December 2025.<br>b On a combined basis of subsidiaries and <br>equity-accounted entities. See page [248](#i0dd2ee81aac04f8c9c97c86197f0c6df_403) <br>for more information on bp's oil and <br>gas reserves. | Supply, trading & shipping<br>Connects energy producers, suppliers, <br>markets and customers to keep <br>energy flowing and help build out <br>tomorrow's energy system.<br>**Image:** Traders at our Canary Wharf office, London, UK<br>|

---

![BusinessModelPage13V4.jpg](bp-20251231_g27.jpg)

bp Annual Report and Form 20-F 2025<sub>13</sub>

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

---

| | |
|:---|:---|
|  | **Delivering value for** <br>**stakeholders** |
| **Gas & low carbon energy**<br>Combining and integrating our existing natural gas <br>capabilities with power trading and growth in low <br>carbon businesses and markets (see page <u>[28](#i0dd2ee81aac04f8c9c97c86197f0c6df_67)</u>).<br>**Production & operations**<br>The operational heart of bp, producing the <br>hydrocarbon energy and products the world wants <br>and needs – safely and efficiently (see page <u>[31](#i0dd2ee81aac04f8c9c97c86197f0c6df_70)</u>). <br>**Customers & products**<br>Innovating with new business models and service <br>platforms to deliver the future of mobility, energy <br>and services for our customers (see page <u>[34](#i0dd2ee81aac04f8c9c97c86197f0c6df_73)</u>). | **Investors and shareholders**<br>$5.1bn<br>total dividends distributed to bp <br>shareholders (2024 $5.0bn)<br>**Employees**<br>66% <br>employee engagement score<sup>c</sup> <br>(2024 70%)<br>**Customers**<br>1,113mb/d <br>retail fuel volumes★ (2024 1,125mb/d<sup>d</sup>)<br>**Society**<br>$64m<br>supporting additional initiatives <br>to benefit communities (2024 $76m)<br>**Governments and regulators**<br>$8.3bn<br>corporate income and <br>production tax paid (2024 $10.6bn)<br>**Partners and suppliers**<br>$142.5bn <br>in payments to suppliers <br>for goods and services (2024 $146.6bn)<br>c As a result of changes to the question set and the <br>inclusion of employees from our retail business in <br>the 2025 Pulse survey, the engagement score for <br>2025 is not comparable with prior years. <br>d 2024 baseline adjusted for portfolio changes to <br>show underlying trend. |
|  | **Investors and shareholders**<br>$5.1bn<br>total dividends distributed to bp <br>shareholders (2024 $5.0bn)<br>**Employees**<br>66% <br>employee engagement score<sup>c</sup> <br>(2024 70%)<br>**Customers**<br>1,113mb/d <br>retail fuel volumes★ (2024 1,125mb/d<sup>d</sup>)<br>**Society**<br>$64m<br>supporting additional initiatives <br>to benefit communities (2024 $76m)<br>**Governments and regulators**<br>$8.3bn<br>corporate income and <br>production tax paid (2024 $10.6bn)<br>**Partners and suppliers**<br>$142.5bn <br>in payments to suppliers <br>for goods and services (2024 $146.6bn)<br>c As a result of changes to the question set and the <br>inclusion of employees from our retail business in <br>the 2025 Pulse survey, the engagement score for <br>2025 is not comparable with prior years. <br>d 2024 baseline adjusted for portfolio changes to <br>show underlying trend. |
|  | **Investors and shareholders**<br>$5.1bn<br>total dividends distributed to bp <br>shareholders (2024 $5.0bn)<br>**Employees**<br>66% <br>employee engagement score<sup>c</sup> <br>(2024 70%)<br>**Customers**<br>1,113mb/d <br>retail fuel volumes★ (2024 1,125mb/d<sup>d</sup>)<br>**Society**<br>$64m<br>supporting additional initiatives <br>to benefit communities (2024 $76m)<br>**Governments and regulators**<br>$8.3bn<br>corporate income and <br>production tax paid (2024 $10.6bn)<br>**Partners and suppliers**<br>$142.5bn <br>in payments to suppliers <br>for goods and services (2024 $146.6bn)<br>c As a result of changes to the question set and the <br>inclusion of employees from our retail business in <br>the 2025 Pulse survey, the engagement score for <br>2025 is not comparable with prior years. <br>d 2024 baseline adjusted for portfolio changes to <br>show underlying trend. |
|  | **Investors and shareholders**<br>$5.1bn<br>total dividends distributed to bp <br>shareholders (2024 $5.0bn)<br>**Employees**<br>66% <br>employee engagement score<sup>c</sup> <br>(2024 70%)<br>**Customers**<br>1,113mb/d <br>retail fuel volumes★ (2024 1,125mb/d<sup>d</sup>)<br>**Society**<br>$64m<br>supporting additional initiatives <br>to benefit communities (2024 $76m)<br>**Governments and regulators**<br>$8.3bn<br>corporate income and <br>production tax paid (2024 $10.6bn)<br>**Partners and suppliers**<br>$142.5bn <br>in payments to suppliers <br>for goods and services (2024 $146.6bn)<br>c As a result of changes to the question set and the <br>inclusion of employees from our retail business in <br>the 2025 Pulse survey, the engagement score for <br>2025 is not comparable with prior years. <br>d 2024 baseline adjusted for portfolio changes to <br>show underlying trend. |
|  | **Investors and shareholders**<br>$5.1bn<br>total dividends distributed to bp <br>shareholders (2024 $5.0bn)<br>**Employees**<br>66% <br>employee engagement score<sup>c</sup> <br>(2024 70%)<br>**Customers**<br>1,113mb/d <br>retail fuel volumes★ (2024 1,125mb/d<sup>d</sup>)<br>**Society**<br>$64m<br>supporting additional initiatives <br>to benefit communities (2024 $76m)<br>**Governments and regulators**<br>$8.3bn<br>corporate income and <br>production tax paid (2024 $10.6bn)<br>**Partners and suppliers**<br>$142.5bn <br>in payments to suppliers <br>for goods and services (2024 $146.6bn)<br>c As a result of changes to the question set and the <br>inclusion of employees from our retail business in <br>the 2025 Pulse survey, the engagement score for <br>2025 is not comparable with prior years. <br>d 2024 baseline adjusted for portfolio changes to <br>show underlying trend. |
|  | **Investors and shareholders**<br>$5.1bn<br>total dividends distributed to bp <br>shareholders (2024 $5.0bn)<br>**Employees**<br>66% <br>employee engagement score<sup>c</sup> <br>(2024 70%)<br>**Customers**<br>1,113mb/d <br>retail fuel volumes★ (2024 1,125mb/d<sup>d</sup>)<br>**Society**<br>$64m<br>supporting additional initiatives <br>to benefit communities (2024 $76m)<br>**Governments and regulators**<br>$8.3bn<br>corporate income and <br>production tax paid (2024 $10.6bn)<br>**Partners and suppliers**<br>$142.5bn <br>in payments to suppliers <br>for goods and services (2024 $146.6bn)<br>c As a result of changes to the question set and the <br>inclusion of employees from our retail business in <br>the 2025 Pulse survey, the engagement score for <br>2025 is not comparable with prior years. <br>d 2024 baseline adjusted for portfolio changes to <br>show underlying trend. |
| Technology<br>Drives digital and innovations with <br>our science, engineering and digital <br>capabilities.<br>**Image:** Colleagues at our Rotterdam refinery, <br>Netherlands | **Investors and shareholders**<br>$5.1bn<br>total dividends distributed to bp <br>shareholders (2024 $5.0bn)<br>**Employees**<br>66% <br>employee engagement score<sup>c</sup> <br>(2024 70%)<br>**Customers**<br>1,113mb/d <br>retail fuel volumes★ (2024 1,125mb/d<sup>d</sup>)<br>**Society**<br>$64m<br>supporting additional initiatives <br>to benefit communities (2024 $76m)<br>**Governments and regulators**<br>$8.3bn<br>corporate income and <br>production tax paid (2024 $10.6bn)<br>**Partners and suppliers**<br>$142.5bn <br>in payments to suppliers <br>for goods and services (2024 $146.6bn)<br>c As a result of changes to the question set and the <br>inclusion of employees from our retail business in <br>the 2025 Pulse survey, the engagement score for <br>2025 is not comparable with prior years. <br>d 2024 baseline adjusted for portfolio changes to <br>show underlying trend. |
| Technology<br>Drives digital and innovations with <br>our science, engineering and digital <br>capabilities.<br>**Image:** Colleagues at our Rotterdam refinery, <br>Netherlands | **Investors and shareholders**<br>$5.1bn<br>total dividends distributed to bp <br>shareholders (2024 $5.0bn)<br>**Employees**<br>66% <br>employee engagement score<sup>c</sup> <br>(2024 70%)<br>**Customers**<br>1,113mb/d <br>retail fuel volumes★ (2024 1,125mb/d<sup>d</sup>)<br>**Society**<br>$64m<br>supporting additional initiatives <br>to benefit communities (2024 $76m)<br>**Governments and regulators**<br>$8.3bn<br>corporate income and <br>production tax paid (2024 $10.6bn)<br>**Partners and suppliers**<br>$142.5bn <br>in payments to suppliers <br>for goods and services (2024 $146.6bn)<br>c As a result of changes to the question set and the <br>inclusion of employees from our retail business in <br>the 2025 Pulse survey, the engagement score for <br>2025 is not comparable with prior years. <br>d 2024 baseline adjusted for portfolio changes to <br>show underlying trend. |
| Technology<br>Drives digital and innovations with <br>our science, engineering and digital <br>capabilities.<br>**Image:** Colleagues at our Rotterdam refinery, <br>Netherlands | **Investors and shareholders**<br>$5.1bn<br>total dividends distributed to bp <br>shareholders (2024 $5.0bn)<br>**Employees**<br>66% <br>employee engagement score<sup>c</sup> <br>(2024 70%)<br>**Customers**<br>1,113mb/d <br>retail fuel volumes★ (2024 1,125mb/d<sup>d</sup>)<br>**Society**<br>$64m<br>supporting additional initiatives <br>to benefit communities (2024 $76m)<br>**Governments and regulators**<br>$8.3bn<br>corporate income and <br>production tax paid (2024 $10.6bn)<br>**Partners and suppliers**<br>$142.5bn <br>in payments to suppliers <br>for goods and services (2024 $146.6bn)<br>c As a result of changes to the question set and the <br>inclusion of employees from our retail business in <br>the 2025 Pulse survey, the engagement score for <br>2025 is not comparable with prior years. <br>d 2024 baseline adjusted for portfolio changes to <br>show underlying trend. |

---

---

| | | |
|:---|:---|:---|
| 14 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Key performance indicators**<br>

We assess the performance of the group across a wide range of

measures and indicators that are consistent with our strategy.

In addition to our four financial primary targets, as described on page <u>[8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31)</u>, our key performance

indicators (KPIs) set out the metrics that help the board and leadership team assess bp's

performance. Our leadership team uses all these measures to evaluate operating performance

and inform its financial, strategic and operating decisions.

**Financial**

---

| | |
|:---|:---|
| **Total shareholder return** (%) ● |  |
| **2025** | **24.4**<br>**16.7** |
| 2024 | (11.9)<br>(11.0) |
| 2023 | 5.9<br>2.6 |
| 2022 | 36.9<br>50.1 |
| 2021 | 36.4<br>36.4 |

---

![52](bp-20251231_g28.gif)

&nbsp;&nbsp;&nbsp;&nbsp;

ADS basis Ordinary share basis![ChartKeyLozengeGreen.jpg](bp-20251231_g29.jpg)<br>![ChartKeyLozengeWarmGrey3.jpg](bp-20251231_g30.jpg)<br>

Total shareholder return (TSR) represents the

change in value of a bp shareholding over a

calendar year (American Depositary Share

(ADS) in USD, ordinary share in GBP). It

assumes that dividends are reinvested to

purchase additional shares at the closing

price on the ex-dividend date.

**2025 performance**

Improved TSR reflects year-on-year growth

in dividend per share and an increase in the

share price.

**Operational**

---

| | |
|:---|:---|
| **Oil and gas production** (mboe/d) | **Oil and gas production** (mboe/d) |
| **2025** | **2,312** |
| 2024 | 2,358 |
| 2023 | 2,313 |
| 2022 | 2,253 |
| 2021 | 2,218 |

---

![5497558139229](bp-20251231_g31.gif)

Oil and gas production tracks how our projects

are helping grow our business. We report

production of crude oil, condensate, natural

gas liquids (NGLs), natural bitumen and natural

gas on a volume per day basis for our

subsidiaries and equity-accounted entities.

Natural gas is converted to barrels of oil

equivalent at 5,800 standard cubic feet of

natural gas = 1 boe.

**2025 performance**

2025 reported production was down

compared with 2024 mainly due to the

divestments in Egypt and Trinidad in the fourth

quarter of 2024 and base decline, partly offset

by major projects★ start-ups and growth in

bpx energy.

---

| | |
|:---|:---|
| **Upstream unit production** <br>**costs** ($/boe)  |  |
| **2025** | **6.28** |
| 2024 | 6.17 |
| 2023 | 5.78 |
| 2022 | 6.07 |
| 2021 | 6.82 |

---

![6047313953489](bp-20251231_g32.gif)

The upstream unit production cost is

calculated as production cost divided by units

of production. Production cost does not

include ad valorem and severance taxes. Units

of production are barrels for liquids★ and

thousands of cubic feet for gas. Amounts

disclosed are for bp subsidiaries only and do

not include bp's share of equity-accounted

entities.

**2025 performance**

Unit production costs was slightly higher,

mainly due to portfolio mix.

---

| | |
|:---|:---|
| **Key** | **Key** |
| ●  | Used for remuneration policy |
| TCFD | TCFD Recommendations and <br>Recommended Disclosures |
| **Remuneration**<br>To help align the focus of the bp leadership <br>team and executive directors with the <br>interests of our shareholders, certain <br>measures are used for executive <br>remuneration. | **Remuneration**<br>To help align the focus of the bp leadership <br>team and executive directors with the <br>interests of our shareholders, certain <br>measures are used for executive <br>remuneration. |
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Directors' remuneration report, page <u>[91](#i0dd2ee81aac04f8c9c97c86197f0c6df_187)</u> |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 15 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

---

| | |
|:---|:---|
| **Upstream**★ **plant reliability** (%) | **Upstream**★ **plant reliability** (%) |
| **2025** | **96.1** |
| 2024 | 95.2 |
| 2023 | 95.0 |
| 2022 | 96.0 |
| 2021 | 94.0 |

---

![6047313953517](bp-20251231_g33.gif)

bp-operated upstream plant reliability is

calculated taking 100% less the ratio of total

unplanned plant deferrals divided by installed

production capacity, excluding non-operated

assets and bpx energy. Unplanned plant

deferrals are associated with the topside plant

and, where applicable, the subsea equipment

(excluding wells and reservoirs). Unplanned

plant deferrals include breakdowns, which

does not include Gulf of America weather-

related downtime.

**2025 performance**

Delivered our record upstream plant reliability

in 2025.

---

| | |
|:---|:---|
| **Refining availability** (%) | **Refining availability** (%) |
| **2025** | **96.3** |
| 2024 | 94.3 |
| 2023 | 96.1 |
| 2022 | 94.5 |
| 2021 | 94.8 |

---

![76](bp-20251231_g34.gif)

bp-operated refining availability represents

Solomon Associates' operational availability

for bp-operated refineries. The measure shows

the percentage of the year that a unit is

available for processing after subtracting the

annualized time lost due to turnaround activity

and all mechanical, process and regulatory

downtime.

Refining availability is an important indicator

of the operational performance of our

downstream businesses.

**2025 performance**

2025 refining availability was the best availability

on record at 96.3%, driven by strengthened

maintenance programmes, enhanced digital

monitoring and improved outage recovery.

Compared with 2024, it reflected improved

reliability and notably the absence of the

Whiting refinery power outage.

---

| | |
|:---|:---|
| **Refining throughputs** (mb/d) | **Refining throughputs** (mb/d) |
| **2025** | **1,440** |
| 2024 | 1,394 |
| 2023 | 1,411 |
| 2022 | 1,504 |
| 2021 | 1,594 |

---

![112](bp-20251231_g35.gif)

Refinery throughputs are based on the

quantity of crude and condensate processed

per day. It represents the actual volume fed

into the refinery's distillation units.

**2025 performance**

Refining throughputs in 2025 increased

compared with 2024, reflecting the absence of

the Whiting refinery power outage in 2024.

---

| | | |
|:---|:---|:---|
| 16 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Key performance indicators** continued<br>

**Safety and non-financial**

---

| | |
|:---|:---|
| **Tier 1 and 2 process safety** <br>**events**★<sup>ab</sup>● | **Tier 1 and 2 process safety** <br>**events**★<sup>ab</sup>● |
| **2025** | **27** |
| 2024 | 38 |
| 2023 | 39 |
| 2022 | 50 |
| 2021 | 62 |

---

![6047313953371](bp-20251231_g36.gif)

&nbsp;&nbsp;&nbsp;&nbsp;

Tier 1 process Tier 2 process ![ChartKeyLozengeGreen.jpg](bp-20251231_g29.jpg)<br>![ChartKeyLozengeWarmGrey3.jpg](bp-20251231_g30.jpg)<br>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;safety events safety events<br>

We track tier 1 and tier 2 events and report the

aggregated outcome. Tier 1 events are losses

of primary containment from a process of

greatest consequence – causing harm to a

member of the workforce, damage to

equipment from a fire or explosion, a

community impact or exceeding defined

quantities (per API RP 754 tier 1 definitions). Tier

2 events are those of lesser consequence (per

API RP 754 tier 2 definitions).

**2025 performance**

Our combined tier 1 and tier 2 process safety

events (PSEs) have decreased for the last 12

years, apart from in 2019. In 2025 there were

27 PSEs, down from 38 in 2024. Tier 1 events

increased to five (2024 three) and

tier 2 events decreased to 22 (2024 35),

see **page** <u>[55](#i87f52fc5efef4a16865a4af06e1e7987_26441)</u>.

---

| | |
|:---|:---|
| **Reported recordable injury** <br>**frequency**★<sup>a</sup> | **Reported recordable injury** <br>**frequency**★<sup>a</sup> |
| **2025** | **0.234** |
| 2024 | 0.297 |
| 2023 | 0.274 |
| 2022 | 0.187 |
| 2021 | 0.164 |

---

![6047313953265](bp-20251231_g37.gif)

Reported recordable injury frequency (RIF)

measures the number of reported work-

related employee and contractor incidents

that result in a fatality or injury per 200,000

hours worked.

**2025 performance**

In 2025 our RIF decreased by 21%. This

reduction is encouraging, but we know we

must continue improving our safety

performance, including through applying the

IOGP Life-Saving Rules and our Safety

Leadership Principles. For more on safety,

see page <u>[55](#i87f52fc5efef4a16865a4af06e1e7987_26441)</u>.

---

| | |
|:---|:---|
| **Women in group leadership**<sup>cd</sup> (%) |  |
| **2025** | **37** |
| 2024 | 35 |
| 2023 | 34 |
| 2022 | 33 |
| 2021 | 32 |

---

![25](bp-20251231_g38.gif)

Our people are crucial to delivering our

purpose and strategy. We aim to recruit

talented people with diverse perspectives,

backgrounds, skills and experiences, invest

in their development and promote an

inclusive culture.

Each year we report the percentage of women

in group leadership.

**2025 performance**

The percentage of women in group leadership

increased to 37% in 2025, continuing an

upward trend over the previous five years.

---

| | |
|:---|:---|
| **Employee engagement**<sup>ce</sup> (%) |  |
| **2025** | **66** |
| 2024 | 70 |
| 2023 | 73 |
| 2022 | 70 |
| 2021 | 64 |

---

![37](bp-20251231_g39.gif)

We conduct a Pulse annual employee survey

to understand and monitor levels of

employee engagement and identify areas

for improvement.

**2025 performance**

---

| | |
|:---|:---|
| **Key** | **Key** |
| ● | Used for remuneration policy |
| TCFD | TCFD Recommendations and <br>Recommended Disclosures |

---

The 2025 Pulse annual survey, which ran in

September, saw our engagement score

decrease. The results reflect the significant

organizational changes happening across bp.

We continue to build engagement plans based

aExclusions to safety metrics – tier 1 and 2 process safety events and recordable injuries may occur in entities that have

been recently acquired or where bp has recently taken full ownership have been granted a deviation from specific

reporting requirements in bp's Operating Management System (OMS)★ for an initial transitional period. As such, data from

Archaea Energy, TravelCenters of America, Lightsource bp, bp bioenergy, X Convenience and new Eagle Ford assets in bpx

energy are not included in 2025 reported data.

bThe metric includes reported PSEs occurring within bp's operational HSSE reporting boundary. That boundary includes

bp's own operated facilities and joint ventures where bp is the operator. In some cases, we may also provide information

about some joint venture activities where bp is not the operator.

cRelates to bp employees.

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

eAs a result of changes to the question set and the inclusion of employees from our retail business in the 2025 Pulse survey,

the engagement score for 2025 is not comparable with prior years.

on survey feedback and on real-time updates

from our monthly snapshot, Pulse live, see

page <u>[57](#i87f52fc5efef4a16865a4af06e1e7987_26450)</u>**.**

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 17 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

---

| | |
|:---|:---|
| **GHG emissions**<sup>abcde</sup> **–** <br>**operational control** (MtCO2e) ● <sup>TCFD</sup> | **GHG emissions**<sup>abcde</sup> **–** <br>**operational control** (MtCO2e) ● <sup>TCFD</sup> |
| **2025** | **34.3** |
| 2024 | 33.6 |
| 2023 | 32.1 |
| 2022 | 31.9 |
| 2021 | 35.6 |

---

![6047313953223](bp-20251231_g40.gif)

&nbsp;&nbsp;&nbsp;&nbsp;

Scope 1 (direct) Scope 2 (indirect)![ChartKeyLozengeGreen.jpg](bp-20251231_g29.jpg)<br>![ChartKeyLozengeWarmGrey3.jpg](bp-20251231_g30.jpg)<br>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;emissions emissions<br>

We report Scope 1 and Scope 2 greenhouse

gas (GHG) emissions material to our business

on a carbon dioxide-equivalent basis. This KPI

comprises Scope 1 (from running the assets

within our operational control boundary) and

Scope 2 (associated with importing electricity,

heating and cooling that is bought in to run

those operations) data covered by our net zero

operations★ aim (to be net zero★ across our

operations by 2050 or sooner). It comprises

100% of Scope 1 and 2 emissions or activities

within bp's operational control boundary.

**2025 performance**

In 2025 our combined Scope 1 and 2 emissions

increased due to growth in our portfolio and

project start-ups. Scope 1 (direct) emissions

were 33.7MtCO2e<sup>de</sup> – an overall increase from

32.8MtCO2e in 2024.

Of these Scope 1 emissions, 32.8MtCO2e were

carbon dioxide and 0.9MtCO2e were from

methane. In 2025 our Scope 2f (indirect)

emissions decreased by 0.1MtCO2e, to

0.7MtCO2e, compared with 2024, see page <u>[37](#i0dd2ee81aac04f8c9c97c86197f0c6df_82)</u>.

**Basis of calculation**<sup>b</sup>

bp's reported GHG emissions include methane

(CH4) and carbon dioxide (CO2). Other GHGs

are not included as they are not material to our

operations. CH4 emissions are converted to

CO2 equivalent using the 100-year global

warming potential recommended by the

Fifth Assessment Report (AR5) of the

Intergovernmental Panel on Climate

Change (IPCC).

Data are required to be submitted into the bp

group reporting tool in accordance with bp's

Operating Management System★ (OMS)

requirements, broadly following the GHG

Protocol Corporate Standard and the Ipieca

Petroleum Industry Guidelines for Reporting

Greenhouse Gas Emissions 2nd Edition, May

2011. The responsibility for quantifying and

submitting GHG emissions for reporting is

assigned to individual bp facilities and

business departments, which are termed

reporting units (RUs).

---

| | |
|:---|:---|
| **Methane intensity**<sup>ag</sup> (%) <sup>TCFD</sup> | **Methane intensity**<sup>ag</sup> (%) <sup>TCFD</sup> |
| **2025** | **0.04** |
| 2024 | 0.07 |
| 2023 | 0.05 |
| 2022 | 0.05 |
| 2021 | 0.07 |

---

![6047313953241](bp-20251231_g41.gif)

We define methane intensity★ as the amount

of methane emissions from our upstream oil

and gas operations as a percentage of the gas

that goes to market from those operations.

This applies to methane emissions within our

operational control boundary, where we have

the highest degree of control. Methane

emissions from non-producing activities, such

as exploration drilling, are excluded. In 2024

we started reporting methane intensity based

on our new measurement approach across our

major operated oil and gas assets.

**2025 performance**

Our methane intensity was 0.04% in 2025. and

the methane emissions from our upstream

operations used to calculate this intensity

were 25kt (2024 46kt), see page <u>[38](#ia533d1b86ea04772b2fd02ae3d1c8da0_9654)</u>.

**Basis of calculation**<sup>b</sup>

All operated upstream assets report methane

(CH4) emissions on a 100% basis, including

emissions from operated upstream oil and gas

and also includes terminals and LNG facilities.

Marketed gas production: all upstream gas

reaching a market from bp-operated upstream

assets, whether or not this is bp-owned

product, and includes gas production from

natural gas wells and associated gas from oil

production wells. Throughput from bp-

operated oil and gas terminals is excluded to

avoid double counting despite their associated

CH4 emissions being included in the metric.

CH4 data are required to be submitted into the

bp group reporting tool, in accordance with

aThese are our KPIs for the purposes of our disclosures pursuant to the UK CFD Regulations 2022 and Section 414CB (2A) (h) of

the Companies Act 2006.

bIncluded as part of disclosures pursuant to the UK CFD Regulations.

cTotal (100%) Scope 1 (direct) GHG emissions from source activities operated by bp or otherwise within bp's operational control

boundary. bp's reported GHG emissions include CH4 and CO2.

dDue to rounding some totals may not agree exactly to the sum of their component parts..

e In 2025 bp made an adjustment to the operational control boundary for Scope 1 and 2 GHG emissions. This means certain

operations, assets or sources which were previously included such as power generation on contractor-operated drilling rigs

are now excluded. This change has a less than 1% impact on reported operational emissions. For more information on the

scope of bp's operational control boundary see bp.com/basisofreporting.

fScope 2 emissions on a market basis, covered by bp's net zero operations aim.

gPrior to 2024 these emissions were calculated using a different methodology and therefore the methane intensity reported in

those years and calculated using that data does not directly correlate to progress towards delivering the 2025 target. Prior

year data is provided for information purposes, and we do not seek to directly compare prior years.

OMS requirements, broadly following the GHG

Protocol Corporate Standard and the Ipieca

Petroleum Industry Guidelines for Reporting

Greenhouse Gas Emissions 2nd Edition, May

2011. The responsibility for quantifying and

submitting CH4 emissions for reporting is

assigned to individual bp facilities and

business departments (RUs).

---

| | | |
|:---|:---|:---|
| 18 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Our financial frame** <br>

## S trengthening the balance sheet to
manage and grow the business

Our financial frame sets out how we allocate the cash we generate to deliver dividends to

shareholders, strengthen our balance sheet and invest with discipline to grow the value of bp.

**Dividend**

The resilient dividend is our first capital

allocation priority. For the second quarter

2025, our dividend per ordinary share

increased by 4% from 8.000 to 8.320 cents.

Based on our current forecasts and subject to

the board's discretion each quarter, the

dividend is expected to increase by at least 4%

per ordinary share a year.

**Strengthening the balance sheet**

We are committed to strengthening the

balance sheet and continue to target

improving credit metrics within an 'A' grade

credit range. We reiterate our primary target

for net debt★ of $14-18 billion by the end

of 2027.

During 2025, finance debt decreased from

$59.5 billion to $58.0 billion and net debt

decreased from $23.0 billion to $22.2 billion.

When considering our capital structure, we

also look at other instruments including hybrid

bonds and securities or obligations such as

leases and Gulf of America settlement

liabilities. At year-end 2025 the total of net

debt, hybrid bonds and securities, leases and

Gulf of America settlement liabilities was

$57.8 billion.

Following a decision by the board at the fourth

quarter 2025 results announcement to

suspend share buybacks, excess cash★ will

now be fully allocated to the balance sheet, in

service of optimizing financing costs and to

accelerate strengthening of the balance sheet.

**Disciplined investment** 

We will continue to invest with discipline,

driven by value, and focused on delivering

returns.

Investment is allocated across our businesses

based on a set of criteria that balances

strategic alignment, hurdle rates, volatility,

integration value, sustainability and risk

(see page <u>[22](#i2249540127db4d059a13c9b841c3712c_11131)</u>).

In 2025 capital expenditure★ was $14.5 billion.

We expect capital expenditure to be $13.0-13.5

billion in 2026. This includes expenditure on

inorganic opportunities. We believe this level

of capital expenditure supports progressively

growing earnings per ordinary share in the

long term.

**Share buybacks**

We announced share buybacks of $2.25 billion

for 2025 and shareholder distributions,

comprising dividends and buybacks, were

around 30%<sup>b</sup> of our 2025 operating

cash flow★.

At the fourth quarter 2025 results in February

2026, the board decided to suspend share

buybacks and fully allocate excess cash to

accelerate strengthening of the balance sheet,

optimizing financing costs and improving

cash flow.

---

| | | | | |
|:---|:---|:---|:---|:---|
| ![BPGreenTopRoundCorner.gif](bp-20251231_g21.gif) |  |  |  | ![BPGreenTopRoundCorner.gif](bp-20251231_g21.gif) |
|  | **Our financial frame** |  |  |  |
|  | **Shareholder distributions** | **Balance sheet**  | **Capital expenditure** |  |
|  | Resilient dividend<br>Expect annual increase of the <br>dividend per ordinary share of <br>at least 4%<sup>a</sup> | $14-18bn<br>Net debt target <br>by end 2027 | $13.0-13.5bn <br>in 2026 |  |
|  | Resilient dividend<br>Expect annual increase of the <br>dividend per ordinary share of <br>at least 4%<sup>a</sup> | $14-18bn<br>Net debt target <br>by end 2027 | $13.0-13.5bn <br>in 2026 |  |
|  | Resilient dividend<br>Expect annual increase of the <br>dividend per ordinary share of <br>at least 4%<sup>a</sup> | $14-18bn<br>Net debt target <br>by end 2027 | $13.0-13.5bn <br>in 2026 |  |
|  | Resilient dividend<br>Expect annual increase of the <br>dividend per ordinary share of <br>at least 4%<sup>a</sup> | $14-18bn<br>Net debt target <br>by end 2027 | $13.0-13.5bn <br>in 2026 |  |
|  |  | 'A' range credit metrics through cycle | Disciplined investment <br>allocation, assessed against <br>a set of balanced criteria<br>|  |
| ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |  |  |  | ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |

---

aShareholder distribution decisions, including dividends and share buybacks, are subject to board discretion, taking into account factors including, but not limited to, current forecasts

and credit metrics.

bIncludes all share buybacks and dividends announced for 2025. The dividend announced for the fourth quarter 2025 amount is estimated.

![InvestorPropositionBackgroundV6-RIGHT.jpg](bp-20251231_g42.jpg)

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 19 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

**Our investor proposition: a simpler, stronger and more valuable bp**<br>As we reflect on our progress in 2025 and look forward to the future, we are aligned around our conviction in bp's potential to grow <br>significant long-term shareholder value and we are in action to simplify and strengthen the company. <br>

---

| | | | | |
|:---|:---|:---|:---|:---|
| **Strong operational** <br>**performance** | **Strengthening** <br>**the balance sheet** | **Improving** <br>**capital discipline** | **Driving to top** <br>**quartile on costs** | **Growing cash** <br>**flow and returns** |
| **Strong operational** <br>**performance** | **Strengthening** <br>**the balance sheet** | **Improving** <br>**capital discipline** | **Driving to top** <br>**quartile on costs** | **Growing cash** <br>**flow and returns** |
| **Strong operational** <br>**performance** | **Strengthening** <br>**the balance sheet** | **Improving** <br>**capital discipline** | **Driving to top** <br>**quartile on costs** | **Growing cash** <br>**flow and returns** |

---

---

| | | |
|:---|:---|:---|
| **A simpler bp**<br>Continuing to focus on high grading <br>the portfolio.<br>Record asset uptime; exploration <br>success; focusing downstream; <br>seven project start-ups; <br>driving deeper and faster on <br>cost and capital efficiency.<br>Performance interventions <br>delivered in 2025, giving us strong <br>momentum into 2026.<br>| **A stronger bp**<br>Fully allocate excess cash★ to the <br>balance sheet.<br>Target to reduce net debt★ to <br>$14-18 billion by end 2027.<br>Target $5.5-6.5 billion<sup>a</sup> of structural <br>cost reductions★ by end 2027.<br>| **A more valuable bp**<br>Target of >20%<sup>b</sup> CAGR adjusted free <br>cash flow growth★ from 2024-2027 <br>and expected progressive dividend <br>growth of at least 4%<sup>c</sup> per annum. <br>Group ROACE★ target of >16%<sup>b</sup> by <br>end 2027.<br>Deep upstream resource base <br>combined with disciplined <br>investment criteria – well positioned <br>to deliver medium and long-term <br>organic growth.<br>|
| **All underpinned by our commitment to safety in everything we do.**  | **All underpinned by our commitment to safety in everything we do.**  | **All underpinned by our commitment to safety in everything we do.**  |

---

![](bp-20251231_g43.gif)

![](bp-20251231_g43.gif)

![](bp-20251231_g43.gif)

![](bp-20251231_g43.gif)

![](bp-20251231_g43.gif)

![](bp-20251231_g43.gif)

![](bp-20251231_g43.gif)

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Our strategy and primary targets, page <u>[8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31)</u>  |

---

**2026 guidance**

---

| | | |
|:---|:---|:---|
|  | **2026 guidance** | 2025 actual |
| Upstream reported production <br>(guidance is both reported and underlying production★)<br>| Reported production to be slightly lower/underlying<br>production to be broadly flat compared with 2025<br>| 2.3mmboe/d |
| Total capital expenditure★ | $13-13.5bn, weighted to the first half | $14.5bn |
| Depreciation, depletion and amortization | Broadly flat compared with 2025 | $17.8bn |
| Divestments and other proceeds<sup>d</sup> | $9-10bn, including approximately $6bn from the <br>announced *Castrol* transaction, all significantly <br>weighted to the second half<br>| $5.3bn |
| Gulf of America oil spill payments<sup>e</sup> (pre-tax) | Around $1.6bn pre-tax, of which $0.4bn in the first <br>quarter and $1.1bn in the second quarter<br>| $1.2bn |
| Other businesses & corporate underlying annual charge | Around $1bn | $0.6bn |
| Underlying effective tax rate★ | Around 40%<sup>f</sup> | 42%<sup>g</sup> |

---

aFollowing the outcome of the strategic review of *Castrol*, which resulted in the decision to divest a 65% shareholding, the $4-5 billion structural cost reduction target by end 2027, introduced at the

February 2025 Capital Markets Update, has increased.

bThis is on a price adjusted basis that assumes a hypothetical price environment of $70/bbl Brent, $4/mmBtu Henry Hub, and $10.3/bbl refining indicator margin (all 2024 real) and assumptions

about the impact of these marker prices on underlying replacement cost profit before tax.

cShareholder distribution decisions, including dividends and share buybacks, are subject to board discretion, taking into account factors including, but not limited to, current forecasts and credit metrics.

dDivestment proceeds are disposal proceeds as per the group cash flow statement. See page [26](#i206636e2799e4007a8d53df7096c2ef3_11631) for more information on divestment and other proceeds.

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

fUnderlying effective tax rate is sensitive to the impact that volatility in the current price environment may have on the geographical mix of the group's profits and losses.

gNon-IFRS measure and its nearest IFRS equivalent measure for 2025 is effective tax rate of **83%**.

The guidance above contains forward-looking statements and should be read in conjunction with the cautionary statement on page <u>[362](#i0dd2ee81aac04f8c9c97c86197f0c6df_541)</u>.

---

| | | |
|:---|:---|:---|
| 20 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Our investment process**<br>

**How we use price assumptions** 

Our price assumptions are used for our

investment appraisal processes. They are also

used to inform decisions about internal

planning and for value-in-use impairment

testing of assets for financial reporting.

**The role of price assumptions** 

Our decisions on individual investments are

informed by our view of the price environment

and consider the balanced investment criteria

discussed below.

Our price assumptions continue to reflect a

range of possibilities, including that the

transition to a lower carbon economy and

energy system could accelerate. Our

investment appraisal assumptions, which take

a long-term perspective, focus on the

fundamental trends affecting the energy

sector and our businesses.

From February 2025 until January 2026, we

held our key investment appraisal price

assumptions constant at the levels set out in

the *bp Annual Report and Form 20-F 2024*. For

relevant investment cases assessed from

February 2026, we have applied and plan to

apply the prices shown in the key investment

appraisal assumptions table (right) for our

central price case. Brent oil and Henry Hub gas

assumptions average around $67/bbl and

$4.4/mmBtu respectively (2024 $ real) from

2026 to 2050.

We consider these prices to be broadly

consistent with a range of transition paths

compatible with meeting the Paris goals, but

they do not correspond to any specific Paris-

consistent scenario. We also consider a

range of other price assumptions in

investment appraisals, including product

and market-specific prices relevant to

individual investment cases.

We apply carbon prices rising from $67/tCO2e

in 2026 to $135/tCO2e in 2030 and $200/

tCO2e by 2050 (2024 $ real) in certain cases

(see box, right).

**Impairment testing**

Our best estimate of future prices for use in

value-in-use impairment testing continues to

be based on our investment appraisal price

assumptions, with quarterly review of near-

term prices to confirm that the assumptions

appropriately reflect any changes to

expectations due to short-term market trends.

Impairment price assumptions were held

constant in 2025 at the levels disclosed in the

*bp Annual Report and Form 20-F 2024* until

the fourth quarter, when the updated

investment appraisal price assumptions

shown below were used for value-in-use

impairment testing.

---

| | | | |
|:---|:---|:---|:---|
| **Key investment appraisal assumptions**<sup>a</sup> <sup>TCFD</sup> | **Key investment appraisal assumptions**<sup>a</sup> <sup>TCFD</sup> | **Key investment appraisal assumptions**<sup>a</sup> <sup>TCFD</sup> | **Key investment appraisal assumptions**<sup>a</sup> <sup>TCFD</sup> |
| 2024 $ real | 2030 | 2040 | 2050 |
| Brent oil ($/bbl) | 70 | 67 | 60 |
| Henry Hub gas ($/mmBtu) | 4.1 | 4.5 | 4.5 |
| Refining indicator margin (RIM)<sup>b</sup>★ ($/bbl) | 12.0 | 8.5 | 5.0 |
| In addition to the prices shown we also test whether investments meet our return expectations (see page [22](#i2249540127db4d059a13c9b841c3712c_11131)) using $60/bbl <br>Brent oil price series. | In addition to the prices shown we also test whether investments meet our return expectations (see page [22](#i2249540127db4d059a13c9b841c3712c_11131)) using $60/bbl <br>Brent oil price series. | In addition to the prices shown we also test whether investments meet our return expectations (see page [22](#i2249540127db4d059a13c9b841c3712c_11131)) using $60/bbl <br>Brent oil price series. | In addition to the prices shown we also test whether investments meet our return expectations (see page [22](#i2249540127db4d059a13c9b841c3712c_11131)) using $60/bbl <br>Brent oil price series. |
| **Carbon price** <sup>TCFD</sup> | **Carbon price** <sup>TCFD</sup> | **Carbon price** <sup>TCFD</sup> | **Carbon price** <sup>TCFD</sup> |
| 2024 $ real | 2030 | 2040 | 2050 |
| Carbon ($/tCO2e) | 135 | 175 | 200 |
| a The values in the table represent the central case. <br>b The disclosed RIM assumptions in the table exclude carbon pricing impacts and assume a normalized cost of renewable <br>identification numbers (RINs). | a The values in the table represent the central case. <br>b The disclosed RIM assumptions in the table exclude carbon pricing impacts and assume a normalized cost of renewable <br>identification numbers (RINs). | a The values in the table represent the central case. <br>b The disclosed RIM assumptions in the table exclude carbon pricing impacts and assume a normalized cost of renewable <br>identification numbers (RINs). | a The values in the table represent the central case. <br>b The disclosed RIM assumptions in the table exclude carbon pricing impacts and assume a normalized cost of renewable <br>identification numbers (RINs). |

---

For investment appraisal, potential future

operational emissions costs that may be borne

by bp as a result of an investment are included

as bp costs, as described in the box below

(generally without assuming incremental

revenue associated with those emissions), in

order to incentivize engineering solutions that

reduce operational carbon emissions from

projects. For the treatment of emission cost

assumptions in value-in-use impairment

testing, see Financial statements – Note 1.

---

| | | | |
|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Investment process price assumptions** | **Investment process price assumptions** |  |
|  | All investments are evaluated against <br>relevant price assumptions for oil, <br>natural gas, refining margins or other <br>commodities across a range of <br>alternative price or margin series <br>(typically a central, upper and lower <br>series). In addition, all investment cases <br>with anticipated annual operational GHG <br>emissions (Scope 1 and 2) above 20,000 <br>tonnes of CO2 equivalent (bp net), must <br>estimate those anticipated GHG <br>emissions and include an associated <br>carbon cost in the investment <br>economics, using the carbon <br>prices above. <br>Our investment price assumptions place <br>some weight on scenarios in which the <br>transition to a low carbon energy system <br>is sufficiently rapid to meet the goals of <br>the Paris Agreement, as well as <br>scenarios in which the transition may not <br>be sufficiently rapid. They also place <br>some weight on a range of other factors <br>that can drive prices, and which are not <br>directly related to the Paris goals. <br>| These price assumptions do not link to <br>specific scenarios or outcomes, but <br>instead try to capture the range of <br>different possibilities surrounding the <br>future path of the global energy system. <br>The nature of the uncertainty means that <br>the price ranges inevitably reflect <br>considerable judgement. The ranges are <br>reviewed and updated as necessary, as <br>our understanding of and judgements <br>about the energy transition evolve. <br>In addition to consideration of a range of <br>price assumptions, investment cases <br>also assess the impact of alternative <br>assumptions covering other selected <br>variables relevant to the economics of <br>the investment. These variables may <br>include cost, schedule, resources, policy <br>changes, or other areas of uncertainty, <br>to assess the robustness of investment <br>cases to a range of other factors.<br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

---

| | |
|:---|:---|
| **Key** | **Key** |
| TCFD | Information that supports TCFD <br>Recommendations and <br>Recommended Disclosures in relation <br>to Metrics and Targets |
| TCFD | Information that supports TCFD <br>Recommendations and <br>Recommended Disclosures in relation <br>to Metrics and Targets |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 21 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

**Investment governance and** 

**evaluating consistency with the** 

**Paris goals**

**Governance framework**

bp's framework for investment governance

seeks to ensure that investments align with

our strategy, can be accommodated within our

prevailing financial frame, and add shareholder

value. It enables investments to be assessed in

a consistent way against a range of criteria

relevant to our strategy, including

sustainability criteria.

Investments follow an integrated stage-gate

process designed to enable our businesses

to choose and develop the most attractive

investment cases. A balanced set of

investment criteria are considered (see

page <u>[22](#i2249540127db4d059a13c9b841c3712c_11131)</u>). This allows for the comparison and

prioritization of investments across a diverse

range of business models.

The governance framework specifies that

proposed investments are evaluated using

relevant assumptions, including carbon prices

for projected operational emissions where

applicable. It also sets out requirements for

assurance by functions independent of the

business before a final investment decision

(FID) is taken.

Our investment framework also includes

processes to review investment outcomes.

During construction, and for two years after

start-up, major project investments are

included in an annual effectiveness of

investment review, which tracks investments'

delivery against the assumptions used in their

investment cases. Key findings are shared with

the board. Around two years after completion,

investments above defined financial

thresholds also prepare a post project

evaluation to share lessons learned across bp

businesses – including reviews of strategic,

commercial, and technical assumptions,

decisions, and delivery.

**The role of the board**

The board assesses capital allocation across

the bp portfolio, including the level and mix of

capital expenditures★ and divestments,

strategic acquisitions, distribution choices and

deleveraging, as well as reviewing certain

investment cases for approval.

**Resource commitment meeting** 

For acquisitions and organic capital

investments above defined financial

thresholds, investment approval is conducted

through the executive-level resource

commitment meeting (RCM), which is chaired

by the chief executive officer. The RCM reviews

the merits of each investment case against a

balanced set of criteria (see page <u>[22](#i2249540127db4d059a13c9b841c3712c_11131)</u>) and

considers any key issues raised in the

assurance process.

The CA100+ resolution★ requires bp to

disclose how we evaluate the consistency of

new material capex investments★ with (i) the

Paris goals and (ii) a range of other outcomes

relevant to bp's strategy.

bp's evaluation of the consistency of such

investments with the Paris goals was

undertaken by the RCM for new material capex

investments sanctioned in 2025 (see page <u>[23](#i2249540127db4d059a13c9b841c3712c_11132)</u>).

bp's evaluation of an investment's consistency

with 'a range of other relevant outcomes' is

achieved by considering its merits against bp's

balanced investment criteria, described on

page <u>[22](#i2249540127db4d059a13c9b841c3712c_11131)</u>.

---

| | | |
|:---|:---|:---|
| ![BPGreenTopRoundCorner.gif](bp-20251231_g21.gif) |  | ![BPGreenTopRoundCorner.gif](bp-20251231_g21.gif) |
|  | **bp board**<br>Reviews and approves investment cases <br>of more than $3 billion for resilient <br>hydrocarbons, more than $1 billion for all <br>transition or low carbon investments★ <br>and any significant inorganic acquisition <br>that is exceptional or unique in nature.<br>|  |
|  | ![bpWhiteDownArrowV2.gif](bp-20251231_g44.gif) |  |
|  | **Resource commitment meeting**<br>Forum for executive management's <br>review and approval of investments <br>related to existing and new lines <br>of business above $250 million, or $25 <br>million for acquisitions, or which exceed <br>the relevant EVP's financial authority, <br>and any project considered strategically <br>important such as a new market entry.<br>|  |
|  | ![bpWhiteDownArrowV2.gif](bp-20251231_g44.gif) |  |
|  | **Investment allocation committees**<br>EVP-level forums to review and approve <br>investment cases within a business <br>group as per individual EVP financial <br>authority (up to $250 million, or typically <br>$25 million for acquisitions).<br>|  |
|  | ![bpWhiteDownArrowV2.gif](bp-20251231_g44.gif) |  |
|  | **Business group investment** <br>**governance meetings**<br>SVP-level forums that review and <br>approve investment cases within a <br>business group or function, up to the <br>individual SVP's financial authority.<br>|  |
|  | ![bpWhiteDownArrowV2.gif](bp-20251231_g44.gif) |  |
|  | **Cross-group meetings**<br>Forums that facilitate discussions <br>across businesses and functions, to <br>support project development, sensitivity <br>analysis, integration opportunities and <br>risk assessment ahead of investment <br>committee meetings.<br>|  |
| ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |  | ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |

---

**Transition business investment** 

bp set out anticipated investment in transition

businesses★ through to 2027 as part of our

reset strategy in February 2025. This

investment was $2.3 billion in 2025 including

$0.8 billion of inorganic spend.

**EV charging:** In EV charging, we are focusing

investment in four core markets – Germany,

UK, China and the US, with joint ventures in the

Iberian region and India. We are utilizing our

retail network to maximise returns. And we

opened new ultra-fast★ charging hubs at

major airports in the US.

**Bioenergy:** We completed the commercial

integration of bp bioenergy, including the final

deferred capital payment. We continued to

scale biofuels but allocated capital only where

projects are economically robust and aligned

with demand progression. Consistent with this

approach, we took the decision to stop further

work on the development of a standalone

biofuels production (HEFA) facility at our

Rotterdam refinery in the Netherlands. In

January 2026, we also announced the launch

of Etlas, a new 50:50 joint venture with

Corteva to produce oil from crops for use in

the production of biofuels such as sustainable

aviation fuel (SAF) and renewable diesel (RD),

see page <u>[35](#i80dcc41ba7e94abeb6689385129c3e79_1-1-1-1-936338)</u>.

Our biogas business, Archaea Energy,

continued its growth, starting up eight new

renewable natural gas (RNG)★ landfill plants

in 2025.

**Low carbon energy:** We focused our low

carbon energy portfolio, prioritizing

investment choices that deliver value for

shareholders. In December we completed the

sale of our US onshore wind business, bp Wind

Energy, to LS Power. And we formed JERA Nex

bp, a 50:50 joint venture between JERA and

bp, focused on offshore wind development,

ownership and operations, see page <u>[9](#i0dd2ee81aac04f8c9c97c86197f0c6df_5051)</u>.

**Hydrogen and carbon capture and storage** 

**(CCS):** We continued to refine our portfolio,

including the decisions not to progress

H2Teesside and to end our participation in

projects in Oman, Australia and the US Gulf

Coast. In 2025 we focused on delivering four

projects sanctioned in 2024: Lingen green

hydrogen★ project, Castellón green hydrogen

project, the Northern Endurance Partnership

(NEP), and Net Zero Teesside Power (NZT).

---

| | | |
|:---|:---|:---|
| 22 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Our investment process** continued<br>

**Balanced investment criteria**

All investment cases must set out their

investment merits and are considered against

a set of six balanced investment criteria –

although investment decisions may also take

other factors into account as appropriate. This

standardized approach is intended to create a

level playing field for decision making and

allows portfolio-wide comparisons of

investment cases. The decision to endorse an

investment based on the information provided

represents our evaluation that it is consistent

with what the 2019 CA100+ resolution★ refers

to as "a range of other outcomes relevant to

bp's strategy".

The **six** balanced investment criteria are:

**Strategic alignment:** For all investment cases,

we consider whether the investment supports

delivery of our strategy, including our net zero

aims. We also assess if the investment case

involves distinctive capability that bp has, or

intends to develop, and whether it adds to an

existing 'scale' business within the portfolio or

could help us create one.

**Safety and risks:** For all investment cases, we

provide an assessment of the key risks to the

investment that have a significantly higher

probability than usual or have a significantly

greater impact (relative to the size of the

project) were they to occur. Safety risk

management at bp is underpinned by our

Operating Management System★ (OMS), which

is designed to help us sustainably deliver safe,

reliable and compliant bp operations.

**Sustainability:** For all investment cases,

we consider how any proposed business

opportunity is connected to the energy

transition, societal needs and the environment.

This approach is underpinned by our purpose

and sustainability frame. All RCM cases must

consider significant impacts of an investment

on bp's sustainability aims, informed by our

sustainability assessment template for

investment cases (for our use of carbon prices,

see box on page <u>[20](#iaa9f5ec2f5544670b4a71dc5d5bce3a9_0-0-1-5-725324)</u>).

**Investment economics:** For all investment

cases, we consider investment economics

against a range of relevant measures.

Depending on the nature of the investment

case, these may include return expectations

(e.g. internal rate of return or IRR), net present

value, discounted payback and profitability

index, reflecting assumptions about relevant

commodity prices, margins and carbon prices

(see page <u>[20](#iaa9f5ec2f5544670b4a71dc5d5bce3a9_0-0-1-5-725324)</u>). The forward economics of an

investment case are considered against

relevant economic indicators at the time of the

investment decision. We may also refer to

these expectations as hurdle rates, although

as noted, each case is assessed according to

its combined merit against our full set of

balanced criteria.

1. For our upstream business (including

biogas), we seek an IRR of 15%.

2. For our downstream business (including EV

charging and biofuels), we seek portfolio-

level returns in excess of 15%.

For investments in hydrogen and CCS, we

expect levered returns in the mid-teens,

including farm-down and integration value.

For any investment, the relevant return

expectations above are assessed using our

central price assumptions. For additional

capital discipline for investments in oil and gas

production, we also compare the central price

hurdle above (15%) to a case in which the Brent

oil price starts at $60/bbl and later declines

to the level of our key appraisal assumptions

by 2050 (see page <u>[20](#iaa9f5ec2f5544670b4a71dc5d5bce3a9_0-0-1-5-725324)</u>). In addition, for

investments in our oil and gas and refined

products businesses, as well as any other

investments that do not fall within one of

the specific businesses set out above, we

compare the IRR in our lower-price case

to a cost of capital hurdle rate.

**Volatility and rateability:** Our investment

economics metrics also consider the degree

of uncertainty of the cash flows when

considering investment cases. For example,

some cases have more certainty of future

costs and revenue projections. Variation in

net present values for the key variables in an

investment case are quantified by sensitivity

analysis to give a range of potential outcomes

against our key investment hurdles.

**Optionality and integration:** Our assessment

considers the degree of optionality offered by

a project – the ability to adapt our business to

changing circumstances. This could be an

option to sell a product with a floor price, or

the right to purchase additional equity in a

joint venture at specific terms. Other types of

options include the right to develop (or not

develop) extensions to existing projects, or to

change the course of a project's development

depending on market circumstances. We

likewise seek out integration along value

chains across multiple products, services,

geographies and customers. For example, our

gas production can supply liquefaction plants

whose LNG is monetized by our trading

business. Likewise, carbon sequestration

projects may allow us to add value to our gas

production by reducing carbon intensity.

**Paris consistency evaluation process**

Our new material capex investments★

are intended to support the delivery of

bp's strategy.

For evaluations conducted in 2025,

investments in scope for evaluation were

defined as:

• **New:** investment in a new project, or

extension of an existing project/asset, or

share of an entity that is new to bp, or a

substantial increase in bp's share.

**•Material:** more than $250 million capex

investment.

**Quantitative evaluations**

For our investment economics and

sustainability investment criteria we

considered quantitative guide levels, as set

out below, to inform the evaluation of each

investment's consistency with the goals of the

Paris Agreement. For evaluations in 2025 we

used the central price IRR and other economic

hurdles, as set out in the *bp Annual Report and* 

*Form 20-F 2024* (page 22). As in previous years,

we used our operational carbon intensity★ as a

guide level, reflecting our portfolio average.

As our approach matures with experience, we

may continue to adjust or supplement our

methodology. There may be instances when

new material capex investments are evaluated

as consistent with the Paris goals despite

either the economic or sustainability guide

levels not being met. The RCM may also take

account, in its Paris consistency evaluation, of

the six balanced investment criteria using

qualitative assessments.

**Investment economics:** We calculated

economic indicators using our central price,

and where applicable, our lower price cases,

and applying our carbon price assumptions to

relevant operational GHG emissions. (For our

current key central case oil and natural gas

price assumptions, see page <u>[20](#iaa9f5ec2f5544670b4a71dc5d5bce3a9_0-0-1-5-725324)</u>, where we also

set out our view on their consistency with

achieving the Paris goals). We then compared

the economic indicators to the relevant

economic guide level (see below), based on

the corresponding hurdles. We typically target

a threshold of >1.0x the relevant IRR guide

level, as set out in the *bp Annual Report and* 

*Form 20-F 2024* (page 22).

**Sustainability:** Where appropriate, we

compared the operational carbon intensity of

the investment (on the basis of equity share)

to the portfolio average equity share GHG

emissions intensity shown in the *bp ESG* 

*Datasheet 2024* for the relevant business

activity (Exploration, production and LNG).

We normally target a ratio of less than 100%,

meaning that the investment is expected to

reduce the average operational carbon

intensity of the relevant portfolio. The potential

impact of new material capex investments on

bp's net zero aims is a further consideration.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 23 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

**Evaluation outcome** 

In 2025 eight new material capex investments were approved. All were evaluated as being consistent with the Paris goals, taking into account both

quantitative and qualitative evaluations and the balanced criteria above.

---

| | | | | |
|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Evaluation of investment** <br>**performance against** <br>**quantitative guide levels**<br>All eight investments exceeded the IRR guide <br>level as shown in the chart. <br>Six of the eight investments had emissions <br>intensities below the relevant intensity guide <br>level. Of the remaining two investments, one <br>produces gas that is processed at an existing <br>LNG facility, with overall emissions intensity <br>(including midstream onshore processing) <br>higher than our overall portfolio average, but <br>upstream-only emissions that are below <br>portfolio average. This investment was <br>supported taking into account our qualitative <br>assessment, including the role LNG plays in the <br>energy transition – especially in the Asia Pacific <br>region – and the strength of the investment <br>economics. We do not show a carbon intensity <br>for the eighth investment because bp does not <br>have any ownership interest in the asset or any <br>right to the production.  | **Investment economics**<br>Against central price IRR hurdle<br>| **Sustainability**<br>Against operational carbon intensity |  |
|  | **Evaluation of investment** <br>**performance against** <br>**quantitative guide levels**<br>All eight investments exceeded the IRR guide <br>level as shown in the chart. <br>Six of the eight investments had emissions <br>intensities below the relevant intensity guide <br>level. Of the remaining two investments, one <br>produces gas that is processed at an existing <br>LNG facility, with overall emissions intensity <br>(including midstream onshore processing) <br>higher than our overall portfolio average, but <br>upstream-only emissions that are below <br>portfolio average. This investment was <br>supported taking into account our qualitative <br>assessment, including the role LNG plays in the <br>energy transition – especially in the Asia Pacific <br>region – and the strength of the investment <br>economics. We do not show a carbon intensity <br>for the eighth investment because bp does not <br>have any ownership interest in the asset or any <br>right to the production.  |  |  |  |
|  | **Evaluation of investment** <br>**performance against** <br>**quantitative guide levels**<br>All eight investments exceeded the IRR guide <br>level as shown in the chart. <br>Six of the eight investments had emissions <br>intensities below the relevant intensity guide <br>level. Of the remaining two investments, one <br>produces gas that is processed at an existing <br>LNG facility, with overall emissions intensity <br>(including midstream onshore processing) <br>higher than our overall portfolio average, but <br>upstream-only emissions that are below <br>portfolio average. This investment was <br>supported taking into account our qualitative <br>assessment, including the role LNG plays in the <br>energy transition – especially in the Asia Pacific <br>region – and the strength of the investment <br>economics. We do not show a carbon intensity <br>for the eighth investment because bp does not <br>have any ownership interest in the asset or any <br>right to the production.  |  |  |  |
|  | **Evaluation of investment** <br>**performance against** <br>**quantitative guide levels**<br>All eight investments exceeded the IRR guide <br>level as shown in the chart. <br>Six of the eight investments had emissions <br>intensities below the relevant intensity guide <br>level. Of the remaining two investments, one <br>produces gas that is processed at an existing <br>LNG facility, with overall emissions intensity <br>(including midstream onshore processing) <br>higher than our overall portfolio average, but <br>upstream-only emissions that are below <br>portfolio average. This investment was <br>supported taking into account our qualitative <br>assessment, including the role LNG plays in the <br>energy transition – especially in the Asia Pacific <br>region – and the strength of the investment <br>economics. We do not show a carbon intensity <br>for the eighth investment because bp does not <br>have any ownership interest in the asset or any <br>right to the production.  |  |  |  |
|  | **Evaluation of investment** <br>**performance against** <br>**quantitative guide levels**<br>All eight investments exceeded the IRR guide <br>level as shown in the chart. <br>Six of the eight investments had emissions <br>intensities below the relevant intensity guide <br>level. Of the remaining two investments, one <br>produces gas that is processed at an existing <br>LNG facility, with overall emissions intensity <br>(including midstream onshore processing) <br>higher than our overall portfolio average, but <br>upstream-only emissions that are below <br>portfolio average. This investment was <br>supported taking into account our qualitative <br>assessment, including the role LNG plays in the <br>energy transition – especially in the Asia Pacific <br>region – and the strength of the investment <br>economics. We do not show a carbon intensity <br>for the eighth investment because bp does not <br>have any ownership interest in the asset or any <br>right to the production.  |  |  |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

![13](bp-20251231_g45.gif)

![](bp-20251231_g46.gif)

![](bp-20251231_g47.gif)

**Decisions taken in 2025**

In 2025 there were eight new material capex

investment decisions evaluated for Paris

consistency, described here approximately

in the order the investment decisions

were made:

**Ginger:** We sanctioned the Ginger gas

development in Trinidad and Tobago. Ginger

will be our fourth subsea project in the country

and will be tied back to our existing Mahogany

B platform. First gas from the project is

expected in 2027, making Ginger one of

bp's 10 major projects expected to start up

between 2025 and 2027. At peak, the

development is expected to have the capacity

to produce average gas production of 62,000

barrels of oil equivalent per day.

**KGD6 Infill Wells:** We approved investment

in drilling four offshore infill gas wells in the

KGD6 block in India to be brought online

in 2028. The infill wells target incremental

production, benefiting from the use of

existing infrastructure.

![1](bp-20251231_g48.gif)

Guide

**Shah Deniz Compression:** In June bp and its

partners agreed the final investment decision

for the $2.9 billion Shah Deniz Compression

project. The project is designed to access and

produce low pressure gas resources from the

field, increasing resource recovery and

extending production life. The project is

expected to allow production of around an

additional gross 50 billion cubic metres of gas

and 25 million barrels of condensate. The

project is expected to receive first gas in 2029.

**Atlantis Major Facility Expansion:** The Atlantis

Major Facility Expansion project aims to

enhance production at the Atlantis field by

injecting water into targeted reservoirs to help

access harder-to-reach barrels. We plan to

start up the facility in 2027.

**Kirkuk redevelopment:** In 2025 bp agreed

with the government of Iraq to help redevelop

several fields in Kirkuk, in the north of Iraq.

We will work initially with Iraq's North Oil

Company and North Gas Company to

stabilize and grow production. Work will

include a drilling programme, rehabilitation

of existing wells and facilities, and

construction of new infrastructure,

including gas expansion projects.

Guide

![](bp-20251231_g49.gif)

**Tiber and Guadalupe:** In September we took

a final investment decision on bp's Tiber and

Guadalupe developments in the Gulf of

America, approving its second new production

platform in less than two years in the critical

US offshore region. Production from the new

floating production platform, which is

expected to have the capacity to produce

80,000 barrels of crude oil per day, is

expected to start in 2030.

**Greater Western Flank 4:** We approved infill

investment in the Greater Western Flank 4

development in Australia's North West Shelf.

This is a five-well subsea programme tied back

to existing infrastructure to help sustain

reliable gas supply to regional markets.

**Juniper Wells:** We approved investment in

decompletion of three existing wells, along

with drilling and completion of three single

zone sidetracks in Trinidad and Tobago. The

infill programme is expected to deliver around

19mmboe, with the first gas expected in 2027.

---

| | | |
|:---|:---|:---|
| 24 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Group performance**<br>

Building for the future

---

| | | | |
|:---|:---|:---|:---|
| **Financial and operating performance** | **Financial and operating performance** | **Financial and operating performance** | **Financial and operating performance** |
|  | $ million except per share amounts | $ million except per share amounts | $ million except per share amounts |
|  | **2025** | 2024 | 2023 |
| **Sales and other operating revenues** | **189335** | 189185 | 210130 |
| Profit before interest and tax | **12642** | 11297 | 27348 |
| Finance costs and net finance income/expense relating to <br>pensions and other post-employment benefits<br>| **(4896)** | (4515) | (3599) |
| Taxation | **(6451)** | (5553) | (7869) |
| **Profit (loss) for the year** | **1295** | 1229 | 15880 |
| Non-controlling interest | **(1240)** | (848) | (641) |
| **Profit (loss) for the year attributable to bp shareholders** | **55** | 381 | 15239 |
| Inventory holding (gains) losses★, before tax | **1351** | 488 | 1236 |
| Taxation charge (credit) on inventory holding gains and losses | **(334)** | (119) | (292) |
| Replacement cost (RC) profit (loss)★ | **1072** | 750 | 16183 |
| Net (favourable) adverse impact of adjusting items★<sup>a</sup>, <br>before tax<br>| **5885** | 9344 | (1143) |
| Total taxation charge (credit) on adjusting items | **528** | (1179) | (1204) |
| **Underlying RC profit** | **7485** | 8915 | 13836 |
| **Adjusted EBITDA**★ | **37615** | 38012 | 43710 |
| **Dividend paid per ordinary share** (cents) | **32.640** | 30.540 | 27.760 |
| **Dividend paid per ordinary share** (pence) | **24.509** | 23.720 | 22.328 |
| **Profit per ordinary share** (cents) | **0.35** | 2.38 | 87.78 |
| **Profit per ADS** (dollars) | **0.02** | 0.14 | 5.27 |
| **Underlying RC profit per ordinary share**★ (cents) | **48.02** | 54.40 | 79.69 |
| **Underlying RC profit per ADS**★ (dollars) | **2.88** | 3.26 | 4.78 |
| **Adjusting items**<sup>a</sup> |  |  |  |
| Gains on sale of businesses and fixed assets | **987** | 670 | 361 |
| Net impairment and losses on sale of businesses and <br>fixed assets<br>| **(6035)** | (6930) | (5838) |
| Environmental and related provisions | **(656)** | (181) | (647) |
| Restructuring, integration and rationalization costs | **(520)** | (222) | 37 |
| Fair value accounting effects (FVAEs)<sup>b</sup> | **2220** | (1852) | 9403 |
| Gulf of America oil spill | **(31)** | (51) | (57) |
| Other | **(1422)** | (273) | (1711) |
| Total before interest and taxation | **(5457)** | (8839) | 1548 |
| Finance costs | **(428)** | (505) | (405) |
|  | **(5885)** | (9344) | 1143 |
| Adjusting items total taxation | **(528)** | 1179 | 1204 |
|  | **(6413)** | (8165) | 2347 |
| aSee page [336](#i70cb1abed366405bb4de86a8f38af0b7_5994) for more information.<br>bSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs. | aSee page [336](#i70cb1abed366405bb4de86a8f38af0b7_5994) for more information.<br>bSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs. | aSee page [336](#i70cb1abed366405bb4de86a8f38af0b7_5994) for more information.<br>bSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs. | aSee page [336](#i70cb1abed366405bb4de86a8f38af0b7_5994) for more information.<br>bSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs. |

---

![GroupPeformanceCFOV4.jpg](bp-20251231_g50.jpg)

---

| | | |
|:---|:---|:---|
| ![BPGreenTopRoundCorner.gif](bp-20251231_g21.gif) |  | ![BPGreenTopRoundCorner.gif](bp-20251231_g21.gif) |
|  | $0.1bn<br>profit attributable to bp <br>shareholders <br>(2024 profit $0.4bn)<br>$7.5bn<br>underlying replacement <br>cost (RC) profit★<br>(2024 profit $8.9bn)<br>$24.5bn<br>operating cash flow★<br>(2024 $27.3bn)<br>|  |
| ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |  | ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 25 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

At 31 December 2025 the group's reportable

segments are gas & low carbon energy, oil

production & operations and customers &

products. Each is managed separately, with

decisions taken for the segment as a whole,

and represent a single operating segment that

does not result from aggregating two or more

segments. See Financial statements – Note 5

Segmental analysis.

**Results** 

The profit for the year ended 31 December

2025 attributable to bp shareholders was $0.1

billion, compared with $0.4 billion in 2024.

After adjusting profit attributable to bp

shareholders for inventory holding losses and

a net adverse impact of adjusting items,

underlying RC profit for the year ended

31 December 2025 was $7.5 billion. The result

reflected lower liquids realizations, lower gas

marketing and trading result, partly offset by

stronger performance in customers &

products. The oil trading contribution was

broadly flat.

For 2024, after adjusting profit attributable to

bp shareholders for inventory holding losses

and a net adverse impact of adjusting items

underlying RC profit was $8.9 billion. The result

reflected lower refining margins, lower

realizations, a lower gas marketing and trading

result and a lower oil trading contribution,

partly offset by lower taxation.

For a discussion of bp's financial and

operating performance for the years ending

31 December 2023 and 31 December 2024,

see *bp Annual Report and Form 20-F* 2024,

pages 24-37.

**Adjusting items**

In 2025 the net adverse pre-tax impact of

items, which bp has classified as adjusting

(adjusting items) was $5.9 billion including:

• Favourable fair value accounting effects

(FVAEs) relative to management's measure

of performance of $2.2 billion primarily

related to a favourable impact of FVAEs

relating to the hybrid bonds and to the

relative decline in LNG forward prices over

the period in addition to the realization of

gains as cargoes were delivered. The

impacts of FVAEs relative to management's

internal measure of performance are

provided on page <u>[337](#i70cb1abed366405bb4de86a8f38af0b7_5992)</u>.

• Net impairment and losses on sale of

businesses and fixed assets includes net

impairment charges of $5.4 billion which

primarily relate to Lightsource bp and

Archaea Energy.

• In addition, $1.4 billion net impairment

charges, of which $1.1 billion primarily

relates to the Archaea Energy and offshore

wind businesses, were reported through

equity-accounted earnings (reported within

the 'other' category).

In 2024 the net adverse pre-tax impact of

adjusting items was $9.3 billion including:

• Adverse FVAEs relative to management's

measure of performance of $1.9 billion

primarily due to an increase in the forward

price of LNG during 2024, compared to a

decline in 2023, and the adverse impact

of the FVAEs relating to the hybrid bonds

in 2024.

• Net impairment and losses on sale of

businesses and fixed assets includes a loss

of $1.1 billion relating to the sale of the

ground fuels business in Türkiye (see

Financial statements – Note 2) and net

impairment charges of $5.1 billion (see

Financial statements – Note 4).

• In addition, $0.5 billion net impairment

charges were reported through equity-

accounted earnings (reported within the

'other' category).

• The 'other' category also includes a $0.5

billion gain relating to the remeasurement

of bp's pre-existing 49.97% interest in

Lightsource bp and a $0.5 billion gain

relating to the remeasurement of certain

US assets excluded from the Lightsource

bp acquisition (see Financial statements –

Note 3 for further information); and

recognition of onerous contract provisions

related to the Gelsenkirchen refinery. The

unwind of these provisions will be reported

as an adjusting item as the contractual

obligations are settled.

See Financial statements – Note 4 for more

information on impairments, and pages <u>[336](#i70cb1abed366405bb4de86a8f38af0b7_5994)</u> 

and <u>[337](#i70cb1abed366405bb4de86a8f38af0b7_5992)</u> for more information on adjusting

items and FVAEs.

**Taxation**

The charge for corporate income taxes was

$6,451 million in 2025 compared with $5,553

million in 2024. The effective tax rate (ETR) on

the profit before taxation for the year in 2025

was 83%, compared with 82% in 2024. The ETR

on the profit before taxation for the year in

2025 and 2024 was impacted by fair value

accounting effects and other adjusting items,

including limited tax relief on impairment

charges. Excluding inventory holding gains or

losses and adjusting items, the underlying

ETR★ in 2025 was 42% compared with 41%

in 2024.

Underlying ETR is a non-IFRS measure. A

reconciliation to IFRS information is provided

on page <u>[384](#i8d8183dbb7704a419cda8a463c63183a_7148)</u>.

**Outlook for 2026** 

2026 guidance

• bp expects reported upstream★ production

to be slightly lower and underlying

upstream production★ to be broadly flat

compared with 2025. Within this, bp

expects underlying production from oil

production & operations to be broadly flat

and production from gas & low carbon

energy to be lower.

• In its customers business, bp expects to

make continued progress growing cash

flows, supported by lower underlying

operating expenditure★ driven by

structural cost reductions★. These benefits

will be partly offset by the earnings impact

of completed and announced divestments.

Reported earnings will benefit from lower

depreciation as a result of the assets held

for sale accounting treatment of *Castrol* 

following the planned divestment. Fuel

margins are expected to remain sensitive to

movements in the cost of supply.

• In products, bp expects significantly lower

level of turnaround activity.

• bp expects other businesses & corporate

underlying annual charge to be around

$1.0 billion for 2026. The charge may vary

from quarter to quarter.

• The underlying ETR for 2026 is expected to

be around 40% but it is sensitive to a range

of factors, including the volatility of the

price environment and its impact on the

geographical mix of the group's profits

and losses.

---

| | | |
|:---|:---|:---|
| 26 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Group performance** continued<br>

---

| | | | |
|:---|:---|:---|:---|
| **Cash flow and debt information** |  |  |  |
|  | $ million | $ million | $ million |
|  | **2025** | 2024 | 2023 |
| **Cash flow** |  |  |  |
| Operating cash flow★ | **24493** | 27297 | 32039 |
| Net cash used in investing activities | **(11504)** | (13250) | (14872) |
| Net cash provided by (used in) financing activities | **(15880)** | (7297) | (13359) |
| Cash and cash equivalents at end of year<sup>a</sup> | **36624** | 39269 | 33030 |
| **Capital expenditure**★<sup>b</sup> | **(14533)** | (16237) | (16253) |
| **Divestment and other proceeds**<sup>c</sup> | **5314** | 4224 | 1843 |
| **Debt** |  |  |  |
| Finance debt | **57958** | 59547 | 51954 |
| Net debt★ | **22182** | 22997 | 20912 |
| Net debt including leases★ | **35686** | 34909 | 31902 |
| Finance debt ratio★ (%) | **43.9%** | 43.2% | 37.8% |
| Gearing★ (%) | **23.1%** | 22.7% | 19.7% |
| Gearing including leases★ (%) | **32.5%** | 30.8% | 27.2% |
| a2025 and 2024 include $68 million and $65 million respectively of cash and cash equivalents classified as assets held for sale <br>in the group balance sheet.<br>bAn analysis of capital expenditure by segment and region is provided on page [335](#i70cb1abed366405bb4de86a8f38af0b7_5993).<br>cDivestment proceeds are disposal proceeds as per the group cash flow statement. See below for more information on <br>divestment and other proceeds. | a2025 and 2024 include $68 million and $65 million respectively of cash and cash equivalents classified as assets held for sale <br>in the group balance sheet.<br>bAn analysis of capital expenditure by segment and region is provided on page [335](#i70cb1abed366405bb4de86a8f38af0b7_5993).<br>cDivestment proceeds are disposal proceeds as per the group cash flow statement. See below for more information on <br>divestment and other proceeds. | a2025 and 2024 include $68 million and $65 million respectively of cash and cash equivalents classified as assets held for sale <br>in the group balance sheet.<br>bAn analysis of capital expenditure by segment and region is provided on page [335](#i70cb1abed366405bb4de86a8f38af0b7_5993).<br>cDivestment proceeds are disposal proceeds as per the group cash flow statement. See below for more information on <br>divestment and other proceeds. | a2025 and 2024 include $68 million and $65 million respectively of cash and cash equivalents classified as assets held for sale <br>in the group balance sheet.<br>bAn analysis of capital expenditure by segment and region is provided on page [335](#i70cb1abed366405bb4de86a8f38af0b7_5993).<br>cDivestment proceeds are disposal proceeds as per the group cash flow statement. See below for more information on <br>divestment and other proceeds. |

---

**Operating cash flow**

Operating cash flow for the year ended

31 December 2025 was $24.5 billion, $2.8 billion

lower than 2024. Compared with 2024,

operating cash flows in 2025 primarily reflected

working capital movements partly offset by

higher profits from operations and lower

tax payments.

Movements in working capital★ adversely

impacted cash flow in the year by $4.8 billion,

including an adverse impact from the Gulf of

America oil spill of $1.1 billion. Other working

capital effects were principally an increase in

derivative assets. bp actively manages its

working capital balances to optimize and

reduce volatility in cash flow.

Operating cash flow for the year ended

31 December 2024 was $27.3 billion, $4.7 billion

lower than 2023. Compared with 2023,

operating cash flows in 2024 primarily reflected

lower profits from operations partly offset by

working capital movements.

Movements in working capital favourably

impacted cash flow in 2024 by $4.0 billion,

including an adverse impact from the Gulf of

America oil spill of $1.1 billion. Other working

capital effects were principally a decrease in

other current assets.

**Net cash used in investing activities**

Net cash used in investing activities for the

year ended 31 December 2025 decreased by

$1.7 billion compared with 2024.

The decrease mainly reflected a decrease in

expenditure on fixed assets reflecting the

phasing of spend within the lower capital frame

for 2025 partly offset by deferred acquisition

payments.

Total capital expenditure for 2025 was $14.5

billion (2024 $16.2 billion), of which organic

capital expenditure★ was $13.6 billion (2024

$16.1 billion). Inorganic capital expenditure for

2025 includes the final payment for the bp

Bunge Bioenergia 2024 acquisition. Inorganic

capital expenditure for 2024 includes the cash

acquired net of acquisition payments on

completion of the bp Bunge Bioenergia and

Lightsource bp acquisitions. Sources of funding

are fungible, but the majority of the group's

funding requirements for new investment

comes from cash generated by existing

operations. bp expects capital expenditure of

around $13-13.5 billion in 2026.

Total divestment and other proceeds for 2025

amounted to $5.3 billion, including amounts

received from the sale of the US onshore wind,

Netherlands mobility & convenience and *bp* 

*pulse* businesses. Other proceeds for 2025

consist of $1.5 billion from the sale of non-

controlling interests in the Permian and Eagle

Ford midstream assets and $1.0 billion from the

sale of a non-controlling interest in the

subsidiary that holds our 12% share in the Trans-

Anatolian natural gas pipeline (TANAP).

Total divestment and other proceeds for 2024

amounted to $4.2 billion, including $0.9 billion

from the sale of receivables and $0.7 billion cash

received, both relating to prior divestments, and

$0.6 billion relating to the formation of Arcius

Energy. Other proceeds for 2024 consist of

$0.8 billion of proceeds from the sale of a non-

controlling interest in the subsidiary that holds

our 20% share in Trans Adriatic Pipeline AG (TAP)

and $0.5 billion of proceeds from the sale of a

49% interest in a controlled affiliate holding

certain midstream assets offshore US.

bp expects divestment and other proceeds to

be $9-10 billion in 2026, including approximately

$6 billion from the announced *Castrol* 

transaction.

**Net cash provided by (used in)** 

**financing activities**

Net cash used in financing activities for the year

ended 31 December 2025 was $15.9 billion,

compared with $7.3 billion in 2024. Compared

with 2024, financing cash flows in 2025 primarily

reflected net repayments compared to net

proceeds from the issuance and repayment of

finance debt, and lower receipts from the issue

of perpetual hybrid bonds, partly offset by a

decrease in share buybacks, and an increase in

receipts relating to transactions involving non-

controlling interests.

In 2025, 836 million ordinary shares (2024

1,238 million) were repurchased for a total cost

of $4.5 billion (2024 $7.1 billion), including

transaction costs of $24 million (2024 $38

million). Of these, 176 million shares repurchased

were cancelled and 659 million shares were held

as treasury shares.

Total dividends paid to shareholders in 2025

were 32.640 cents per share, 2.10 cents higher

than 2024. This amounted to total dividends

paid to shareholders of $5.1 billion in 2025 (2024

$5.0 billion). The board decided not to offer a

scrip dividend alternative in respect of the 2025

and 2024 dividends.

**Debt**

Finance debt at the end of 2025 decreased by

$1.6 billion from the end of 2024 primarily

reflecting net repayments of long-term finance

debt, partly offset by changes in fair value where

hedge accounting is applied. The finance debt

ratio at the end of 2025 increased to 43.9% from

43.2% at the end of 2024.

Net debt at the end of 2025 decreased by $0.8

billion from the 2024 year-end position. Gearing

at the end of 2025 increased to 23.1% from 22.7%

at the end of 2024. Net debt and gearing are

non-IFRS measures. See Financial statements –

Notes 26 and 27 for further information on

finance debt and net debt.

For information on financing the group's

activities see Financial statements – Note 29

and Liquidity and capital resources on page <u>[338](#i0dd2ee81aac04f8c9c97c86197f0c6df_484)</u>.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 27 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

---

| | | | |
|:---|:---|:---|:---|
| **Group reserves and production**<sup>a</sup> | **Group reserves and production**<sup>a</sup> | **Group reserves and production**<sup>a</sup> | **Group reserves and production**<sup>a</sup> |
|  | **2025** | 2024 | 2023 |
| **Estimated net proved reserves** (net of royalties) |  |  |  |
| Liquids (mmb) | **3447** | 3699 | 3747 |
| Natural gas (bcf) | **15916** | 14786 | 17471 |
| Total hydrocarbons<sup>b</sup> (mmboe) | **6191** | 6248 | 6759 |
| *Of which:* |  |  |  |
| Equity-accounted entities<sup>b</sup> | **1330** | 1377 | 1437 |
| **Production** (net of royalties) |  |  |  |
| Liquids (mb/d) | **1199** | 1166 | 1115 |
| Natural gas (mmcf/d) | **6450** | 6914 | 6944 |
| Total hydrocarbons (mboe/d) | **2312** | 2358 | 2313 |
| *Of which:* |  |  |  |
| Subsidiaries | **1931** | 2008 | 1967 |
| Equity-accounted entities | **380** | 350 | 345 |
| aBecause of rounding, some totals may not agree exactly with the sum of their component parts.<br>bSee Supplementary information on oil and natural gas on page [241](#i0dd2ee81aac04f8c9c97c86197f0c6df_397) for further information. | aBecause of rounding, some totals may not agree exactly with the sum of their component parts.<br>bSee Supplementary information on oil and natural gas on page [241](#i0dd2ee81aac04f8c9c97c86197f0c6df_397) for further information. | aBecause of rounding, some totals may not agree exactly with the sum of their component parts.<br>bSee Supplementary information on oil and natural gas on page [241](#i0dd2ee81aac04f8c9c97c86197f0c6df_397) for further information. | aBecause of rounding, some totals may not agree exactly with the sum of their component parts.<br>bSee Supplementary information on oil and natural gas on page [241](#i0dd2ee81aac04f8c9c97c86197f0c6df_397) for further information. |

---

Total hydrocarbon proved reserves at

31 December 2025, on an oil equivalent basis

including equity-accounted entities,

decreased by 1% compared with 31 December

2024 (0.2% decrease for subsidiaries and 3%

decrease for equity-accounted entities).

Natural gas increased by 8% (10% increase for

subsidiaries and 3% decrease for equity-

accounted entities).

There was a net increase from acquisitions and

disposals of 27mmboe within our US and North

Sea subsidiaries.

Total hydrocarbon production for the group

was 2% lower compared with 2024. The

decrease comprised a 3.8% decrease (3.5%

increase for liquids and 9.7% decrease for gas)

for subsidiaries and an 8.6% increase (0.8%

increase for liquids and 37.0% increase for gas)

for equity-accounted entities.

---

| | | |
|:---|:---|:---|
| 28 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Gas & low carbon energy**<br>

Gas & low carbon energy segment comprises our gas & low carbon businesses. Our gas business

includes regions<sup>a</sup> with upstream activities that predominantly produce natural gas, gas trading and

our Archaea Energy business. Our low carbon business includes solar, offshore wind, hydrogen

and CCS, and power trading, and until its divestment in December 2025 also included onshore

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

---

| | | | |
|:---|:---|:---|:---|
| **Financial and operating performance** | **Financial and operating performance** | **Financial and operating performance** | **Financial and operating performance** |
|  | $ million | $ million | $ million |
|  | **2025** | 2024 | 2023 |
| **Sales and other operating revenues**<sup>b</sup> | **40333** | 32628 | 50297 |
| Profit before interest and tax<sup>c</sup> | **1330** | 3052 | 14081 |
| Inventory holding (gains) losses★ | **—** |  | (1) |
| **RC profit before interest and tax**<sup>c</sup> | **1330** | 3052 | 14080 |
| Net (favourable) adverse impact of adjusting items★<sup>cd</sup> | **4037** | 3751 | (5358) |
| **Underlying RC profit before interest and tax**★ | **5367** | 6803 | 8722 |
| Taxation on an underlying RC basis | **(1972)** | (2137) | (2730) |
| **Underlying RC profit before interest** | **3395** | 4666 | 5992 |
| **Depreciation, depletion and amortization** | **4969** | 4835 | 5680 |
| **Exploration write-offs** | **30** | 222 | 362 |
| **Adjusted EBITDA**★<sup>e</sup> | **10366** | 11860 | 14764 |
| **Capital expenditure**★ |  |  |  |
| Gas<sup>f</sup> | **2946** | 4246 | 3517 |
| Low carbon energy | **464** | 1596 | 1256 |
|  | **3410** | 5842 | 4773 |
| aThe Azerbaijan-Georgia-Türkiye and Middle East and North Africa (MENA) regions have been further subdivided by asset to <br>allow reporting in either gas & low carbon or oil production & operations as appropriate.<br>bIncludes sales to other segments.<br>c2024 has been restated for material items to reflect the move of our Archaea Energy business from the customers & <br>products segment to the gas & low carbon energy segment.<br>dSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs.<br>eA reconciliation to RC profit before interest and tax is provided on page [388](#i8d8183dbb7704a419cda8a463c63183a_7145).<br>f2024 and 2023 have been restated to reflect the move of our Archaea Energy business from the customers & products <br>segment to the gas & low carbon energy segment. | aThe Azerbaijan-Georgia-Türkiye and Middle East and North Africa (MENA) regions have been further subdivided by asset to <br>allow reporting in either gas & low carbon or oil production & operations as appropriate.<br>bIncludes sales to other segments.<br>c2024 has been restated for material items to reflect the move of our Archaea Energy business from the customers & <br>products segment to the gas & low carbon energy segment.<br>dSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs.<br>eA reconciliation to RC profit before interest and tax is provided on page [388](#i8d8183dbb7704a419cda8a463c63183a_7145).<br>f2024 and 2023 have been restated to reflect the move of our Archaea Energy business from the customers & products <br>segment to the gas & low carbon energy segment. | aThe Azerbaijan-Georgia-Türkiye and Middle East and North Africa (MENA) regions have been further subdivided by asset to <br>allow reporting in either gas & low carbon or oil production & operations as appropriate.<br>bIncludes sales to other segments.<br>c2024 has been restated for material items to reflect the move of our Archaea Energy business from the customers & <br>products segment to the gas & low carbon energy segment.<br>dSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs.<br>eA reconciliation to RC profit before interest and tax is provided on page [388](#i8d8183dbb7704a419cda8a463c63183a_7145).<br>f2024 and 2023 have been restated to reflect the move of our Archaea Energy business from the customers & products <br>segment to the gas & low carbon energy segment. | aThe Azerbaijan-Georgia-Türkiye and Middle East and North Africa (MENA) regions have been further subdivided by asset to <br>allow reporting in either gas & low carbon or oil production & operations as appropriate.<br>bIncludes sales to other segments.<br>c2024 has been restated for material items to reflect the move of our Archaea Energy business from the customers & <br>products segment to the gas & low carbon energy segment.<br>dSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs.<br>eA reconciliation to RC profit before interest and tax is provided on page [388](#i8d8183dbb7704a419cda8a463c63183a_7145).<br>f2024 and 2023 have been restated to reflect the move of our Archaea Energy business from the customers & products <br>segment to the gas & low carbon energy segment. |

---

**Financial results**

Sales and other operating revenues for 2025

are higher than 2024 mainly due to higher gas

marketing and trading revenues partly offset

by lower volumes.

RC profit before interest and tax for 2025 was

$1,330 million compared with $3,052 million

for 2024.

In 2025 items which bp has classified as

adjusting had a net adverse impact of $4,037

million including favourable fair value

accounting effects (FVAEs)★ of $1,270 million,

relative to management's view of performance,

and net impairment charges of $4,038 million,

primarily relating to Lightsource bp and

Archaea Energy. In addition, $1,082 million

impairment charge was recognized through

equity-accounted earnings, primarily relating

to Archaea Energy and offshore wind

businesses.

After adjusting RC profit for the net impact of

items which bp has classified as adjusting,

underlying RC profit before interest and tax for

2025 was $5,367 million, compared with $6,803

million for 2024. The decrease reflects the

divestments in Egypt and Trinidad in the fourth

quarter of 2024, a lower gas marketing and

trading result, and a higher depreciation,

depletion and amortization charge, partly

offset by lower exploration write-offs and the

absence of the foreign exchange loss in Egypt

in the first quarter of 2024.

In 2024 items which bp has classified as

adjusting had a net adverse impact of $3,751

million including adverse FVAEs of $1,550

million, relative to management's view of

performance, partly offset by a gain of $1,006

million as a result of remeasurement of our

previously existing interest and related assets

on the step-acquisition of Lightsource bp

(LSbp).

See Financial statements – Note 4 and Note 16

for further information on net impairment

charges.

**Operational update** 

Reported production for 2025 was 785mboe/d,

11.6% lower than the same period in 2024.

Underlying production★ for the full year was

2.1% lower, mainly due to base decline partly

offset by major projects★ start-ups.

**Strategic progress**

Gas

In April we safely loaded the first cargo of

liquefied natural gas (LNG) for export from its

GTA Phase 1 project offshore Mauritania and

Senegal – see the case study on page <u>[29](#ic5b66e4a2537412fa0a80e8a46092335_2-1-1-1-936103)</u> for

more information.

In May we made the final investment decision

(FID) to invest in an infill wells programme at the

offshore KG D6 gas block located offshore

India.

In June together with our partners, we

announced the FID for the new Shah Deniz

Compression project, the next stage of

development of the giant Shah Deniz gas field

in the Azerbaijan sector of the Caspian Sea (bp

operator 29.99%).

In Trinidad and Tobago we have made progress

on our growth projects – see the case study, on

page <u>[29](#ic5b66e4a2537412fa0a80e8a46092335_2-1-1-1-936103)</u> for more information.

In Egypt we have made progress on growing

our portfolio:

• In February we began production from

the second development phase of the

Raven field.

• In March we announced the successful

completion of drilling operations at the El

Fayoum-5 gas discovery well in the North

Alexandria Offshore Concession. This was

the final well in our four-slot drilling

campaign in the West Nile Delta (WND) and

our second consecutive gas discovery

following El King-2 well in the North King

Mariout Offshore Concession.

• In September we signed a memorandum of

understanding (MoU) to evaluate

opportunities for a five-well programme in

the Mediterranean Sea.

• In January 2026 we were awarded two

offshore exploration concession: North-East

El Alamein Offshore and West El Hammad

Offshore, advancing our exploration

portfolio and long-term growth ambitions.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 29 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

In November the Greater Western Flank 4

project in the North West Shelf, offshore

Australia (bp 16.67%, operator Woodside)

reached FID. The project involves five subsea

tieback wells with start-up targeted for 2028.

**Biogas**

In December Archaea Energy and Osaka Gas

Trading and Export entered into an agreement

for the procurement of approximately

26,000Nm³ of biomethane derived from landfill

gas, produced at Archaea Energy's facilities

operating in the US.

During the fourth quarter Archaea Energy

started up two renewable natural gas (RNG)★

landfill plants (Middle Point and NW Tennessee)

bringing the total to eight landfill plants started-

up in 2025, with a total capacity of more than 6

million mmBtu. Since 2023 Archaea Energy has

added a total of 19 landfill plants and total

capacity of 18 million mmBtu per year.

LNG portfolio

On the supply side, bp has had strong growth in

2025 with the start-up commissioning and

subsequent strong performance at the Greater

Tortue Ahmeyim Phase 1 LNG export project in

Mauritania and Senegal, in which bp is the

operator. 19 cargoes were lifted by bp's ST&S

organization – which has 100% offtake rights

from the project.

Venture Global announced Commercial

Operations Date for bp's long-term contract

from Calcasieu Pass as 15 April, since which bp

has lifted all the long-term cargoes made

available to it under this agreement.

Portfolio growth also occurred in the sales

portfolio with the start-up of the second power

plant within the GNA JV's integrated regas

terminal and power plant at Porto do Acu in

Brazil's Rio de Janeiro state, owned by bp,

Prumo and Siemens. The project is owned by

bp, Prumo, Siemens and SPIC and bp has 100%

supply rights to this facility.

A number of globally diverse long term sales to

third parties were also signed in 2025, for

example a long-term sale with A2A into Italy –

increasing diversification to our portfolio; a

long-term sale agreed with Torrent Power into

India – expanding customer portfolio; a long

term sale with Zhejiang Energy in China –

building on our regional experience; and a

three-year sale to Türkiye's Botas – deepening

customer relationships in key demand centres.

See Oil and gas disclosures for the group on

page <u>[340](#i0dd2ee81aac04f8c9c97c86197f0c6df_490)</u> for more information on oil and gas

operations in the regions.

Low carbon energy

In 2025 we took action to focus our portfolio

and further high-grade our projects – both

through partnerships, to create capital light

joint ventures – and through divestments,

making strong progress on the programmes

that are driving focus and reducing costs.

**Hydrogen and carbon capture and storage** 

In 2025 we focused on delivering four projects

sanctioned in 2024: Lingen green hydrogen★

project, Castellón green hydrogen project, the

Northern Endurance Partnership (NEP), and Net

Zero Teesside Power (NZT).

We continued to refine our hydrogen and

carbon, capture and storage (CCS) portfolio.

This included decisions not to progress

H2Teesside and to end participation in projects

in Oman, Australia and the US Gulf Coast.

**Renewables and power**

Offshore wind

In August 2025 we formed JERA Nex bp, a

50:50 offshore wind joint venture between

JERA and bp. The new JV brings together each

parties' complementary expertise for a

balanced mix of operating assets and

development projects.

Onshore renewables

In February 2025 we announced our intention

to bring a strategic partner into our solar

business, LSbp.

LSbp continues to be a leading global onshore

renewable developer in markets with attractive

sector returns.

In June Shafag (Jabrayil) Solar Ltd, bp's joint

venture with SOCAR Green and the Azerbaijan

Business Development Fund, announced FID on

the 240MW AC Shafag solar plant in the Jabrayil

district of Azerbaijan. In parallel, investors in the

Sangachal terminal sanctioned the linked

Sangachal terminal electrification project.

In December we completed the sale of our US

onshore wind business, bp Wind Energy, to LS

Power. The transaction included 10 operating

assets across seven US states.

---

| | | |
|:---|:---|:---|
| ![49789_bp_AR25_LNGMilestonesGTAv2.jpg](bp-20251231_g51.jpg) | ![49789_bp_AR25_LNGMilestonesGTAv2.jpg](bp-20251231_g51.jpg) | ![49789_bp_AR25_LNGMilestonesGTAv2.jpg](bp-20251231_g51.jpg) |
|  | LNG milestone<br>We safely loaded the first cargo of <br>LNG for export from our Greater <br>Tortue Ahmeyim (GTA) Phase 1 <br>project offshore Mauritania and <br>Senegal. By the end of 2025 we <br>delivered 19 cargoes for export. <br>Phase 1 includes one of Africa's <br>deepest subsea structures, with <br>wells located in water depths of up <br>to 2,850 metres (9,350 feet). <br>**Image:** Aerial image of GTA in the <br>Atlantic Ocean <br>|  |
| ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |  | ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |

---

---

| | | |
|:---|:---|:---|
| ![49789_bp_AR25_TriumphsTrinidadTobagoMentoV1.jpg](bp-20251231_g53.jpg) | ![49789_bp_AR25_TriumphsTrinidadTobagoMentoV1.jpg](bp-20251231_g53.jpg) | ![49789_bp_AR25_TriumphsTrinidadTobagoMentoV1.jpg](bp-20251231_g53.jpg) |
|  | Progress in Trinidad <br>and Tobago <br>We marked four major milestones <br>in Trinidad and Tobago in 2025. In <br>March we sanctioned the Ginger <br>gas development and confirmed <br>exploration success at Frangipani. <br>The Cypre project delivered first <br>gas in April. And Mento, a joint <br>venture with EOG Resources, <br>delivered first gas in May.<br>**Image:** Mento platform, Trinidad <br>and Tobago <br>|  |
| ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |  | ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |

---

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

---

| | | |
|:---|:---|:---|
| 30 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Gas & low carbon energy** continued<br>

---

| | | | |
|:---|:---|:---|:---|
| **Estimated net proved reserves and production**<sup>a</sup> **(net of royalties)** | **Estimated net proved reserves and production**<sup>a</sup> **(net of royalties)** | **Estimated net proved reserves and production**<sup>a</sup> **(net of royalties)** | **Estimated net proved reserves and production**<sup>a</sup> **(net of royalties)** |
|  | **2025** | 2024 | 2023 |
| **Estimated net proved reserves** (net of royalties) |  |  |  |
| Crude oil<sup>b</sup> (mmb) | **100** | 113 | 128 |
| Natural gas liquids (mmb) | **—** | 1 | 1 |
| Total liquids★<sup>c</sup> | **101** | 115 | 129 |
| Natural gas<sup>c</sup> (bcf) | **6366** | 6965 | 8635 |
| Total hydrocarbons★<sup>c</sup> (mmboe) | **1198** | 1316 | 1618 |
| *Of which equity-accounted entities*<sup>d</sup>: |  |  |  |
| Liquids (mmb) | **1** | 1 |  |
| Natural gas (bcf) | **162** | 196 |  |
| Total hydrocarbons (mmboe) | **29** | 35 |  |
| **Production** (net of royalties) |  |  |  |
| Crude oil<sup>b</sup> (mb/d) | **75** | 88 | 96 |
| Natural gas liquids (mb/d) | **10** | 8 | 9 |
| Total liquids (mb/d) | **85** | 96 | 105 |
| Natural gas (mmcf/d) | **4059** | 4596 | 4778 |
| Total hydrocarbons (mboe/d) | **785** | 888 | 929 |
| *Of which equity-accounted entities*<sup>e</sup>: |  |  |  |
| Liquids (mb/d) | **5** | 2 | 2 |
| Natural gas (mmcf/d) | **165** | 9 |  |
| Total hydrocarbons (mboe/d) | **34** | 4 | 2 |
| **Average realizations**★<sup>f</sup> |  |  |  |
| Liquids ($/bbl) | **65.50** | 75.37 | 77.03 |
| Natural gas ($/mcf) | **6.60** | 5.90 | 6.13 |
| Total hydrocarbons ($/boe) | **41.34** | 38.57 | 40.21 |
| aBecause of rounding, some totals may not agree exactly with the sum of their component parts.<br>bIncludes condensate and bitumen.<br>cIncludes 1.7 million barrels of total liquids (1.7 million barrels at 31 December 2024 and 2.2 million barrels at 31 December <br>2023) and 231 billion cubic feet of natural gas (219 billion cubic feet at 31 December 2024 and 430 billion cubic feet at <br>31 December 2023) in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. <br>dbp's share of reserves of equity-accounted entities in the gas & low carbon energy segment.<br>ebp's share of production of equity-accounted entities in the gas & low carbon energy segment.<br>fRealizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities. | aBecause of rounding, some totals may not agree exactly with the sum of their component parts.<br>bIncludes condensate and bitumen.<br>cIncludes 1.7 million barrels of total liquids (1.7 million barrels at 31 December 2024 and 2.2 million barrels at 31 December <br>2023) and 231 billion cubic feet of natural gas (219 billion cubic feet at 31 December 2024 and 430 billion cubic feet at <br>31 December 2023) in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. <br>dbp's share of reserves of equity-accounted entities in the gas & low carbon energy segment.<br>ebp's share of production of equity-accounted entities in the gas & low carbon energy segment.<br>fRealizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities. | aBecause of rounding, some totals may not agree exactly with the sum of their component parts.<br>bIncludes condensate and bitumen.<br>cIncludes 1.7 million barrels of total liquids (1.7 million barrels at 31 December 2024 and 2.2 million barrels at 31 December <br>2023) and 231 billion cubic feet of natural gas (219 billion cubic feet at 31 December 2024 and 430 billion cubic feet at <br>31 December 2023) in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. <br>dbp's share of reserves of equity-accounted entities in the gas & low carbon energy segment.<br>ebp's share of production of equity-accounted entities in the gas & low carbon energy segment.<br>fRealizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities. | aBecause of rounding, some totals may not agree exactly with the sum of their component parts.<br>bIncludes condensate and bitumen.<br>cIncludes 1.7 million barrels of total liquids (1.7 million barrels at 31 December 2024 and 2.2 million barrels at 31 December <br>2023) and 231 billion cubic feet of natural gas (219 billion cubic feet at 31 December 2024 and 430 billion cubic feet at <br>31 December 2023) in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC. <br>dbp's share of reserves of equity-accounted entities in the gas & low carbon energy segment.<br>ebp's share of production of equity-accounted entities in the gas & low carbon energy segment.<br>fRealizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities. |

---

---

| | | |
|:---|:---|:---|
| ![49789_bp_CaseStudyImage090225.jpg](bp-20251231_g54.jpg) | ![49789_bp_CaseStudyImage090225.jpg](bp-20251231_g54.jpg) | ![49789_bp_CaseStudyImage090225.jpg](bp-20251231_g54.jpg) |
|  | Operations in Oman<br>Block 61 in Oman (bp operated <br>with a 40% equity stake) delivered <br>strong operational performance <br>in 2025. Technical enhancements <br>enabled the site to reach its <br>highest-ever gas flow rate. <br>We operate two drilling rigs, <br>underpinning our development <br>programme and acquiring key <br>data to inform the reservoir's <br>potential. A major turnaround was <br>delivered eight days earlier than <br>the scheduled time, supported by <br>new robotic tools that reduced <br>confined-space work and <br>improved reliability and efficiency. <br>Block 61 has the capacity to supply <br>a third of Oman's domestic natural <br>gas demand.<br>**Image:** Block 61, Oman <br>|  |
| ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |  | ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 31 |

---

---

| | |
|:---|:---|
|  | ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
|  | **Strategic report** |
| **Oil production & operations** |  |

---

---

| | | | |
|:---|:---|:---|:---|
| Oil production & operations segment comprises regions<sup>a</sup> <br>with upstream activities that predominantly produce crude oil, <br>including bpx energy. | Oil production & operations segment comprises regions<sup>a</sup> <br>with upstream activities that predominantly produce crude oil, <br>including bpx energy. | Oil production & operations segment comprises regions<sup>a</sup> <br>with upstream activities that predominantly produce crude oil, <br>including bpx energy. | Oil production & operations segment comprises regions<sup>a</sup> <br>with upstream activities that predominantly produce crude oil, <br>including bpx energy. |
| **Financial and operating performance** | **Financial and operating performance** | **Financial and operating performance** | **Financial and operating performance** |
|  | **$ million** | **$ million** | **$ million** |
|  | **2025** | 2024 | 2023 |
| **Sales and other operating revenues**<sup>b</sup> | **24527** | 25637 | 24904 |
| Profit before interest and tax | **8560** | 10780 | 11191 |
| Inventory holding (gains) losses★ | **(2)** | 9 |  |
| **RC profit before interest and tax** | **8558** | 10789 | 11191 |
| Net (favourable) adverse impact of adjusting items★ | **856** | 1148 | 1590 |
| **Underlying RC profit before interest and tax**★ | **9414** | 11937 | 12781 |
| Taxation on an underlying RC basis | **(4409)** | (5165) | (5998) |
| **Underlying RC profit before interest** | **5005** | 6772 | 6783 |
| **Depreciation, depletion and amortization** | **7719** | 6797 | 5692 |
| **Exploration write-offs** | **313** | 544 | 384 |
| **Adjusted EBITDA**★<sup>c</sup> | **17446** | 19278 | 18857 |
| **Capital expenditure**★ | **6760** | 6198 | 6278 |
| aThe Azerbaijan-Georgia-Türkiye and Middle East and North Africa (MENA) regions have been further subdivided by asset to <br>allow reporting in either gas & low carbon or oil production & operations as appropriate.<br>bIncludes sales to other segments.<br>cA reconciliation to RC profit before interest and tax is provided on page [388](#i8d8183dbb7704a419cda8a463c63183a_7145). | aThe Azerbaijan-Georgia-Türkiye and Middle East and North Africa (MENA) regions have been further subdivided by asset to <br>allow reporting in either gas & low carbon or oil production & operations as appropriate.<br>bIncludes sales to other segments.<br>cA reconciliation to RC profit before interest and tax is provided on page [388](#i8d8183dbb7704a419cda8a463c63183a_7145). | aThe Azerbaijan-Georgia-Türkiye and Middle East and North Africa (MENA) regions have been further subdivided by asset to <br>allow reporting in either gas & low carbon or oil production & operations as appropriate.<br>bIncludes sales to other segments.<br>cA reconciliation to RC profit before interest and tax is provided on page [388](#i8d8183dbb7704a419cda8a463c63183a_7145). | aThe Azerbaijan-Georgia-Türkiye and Middle East and North Africa (MENA) regions have been further subdivided by asset to <br>allow reporting in either gas & low carbon or oil production & operations as appropriate.<br>bIncludes sales to other segments.<br>cA reconciliation to RC profit before interest and tax is provided on page [388](#i8d8183dbb7704a419cda8a463c63183a_7145). |

---

**Financial results**

Sales and other operating revenues for 2025

were lower than 2024 mainly due to lower

realizations partially offset by higher volumes.

RC profit before interest and tax for 2025 was

$8,558 million compared with $10,789 million

for 2024.

Adjusting items for 2025 had a net adverse

impact of $856 million principally relating to

net impairment charges. See Financial

statements – Note 4 and Note 16 for further

information on net impairment charges.

After adjusting RC profit for the net adverse

impact of adjusting items, underlying RC profit

before interest and tax for 2025 was $9,414

million, compared with $11,937 million for 2024.

The lower profit reflects lower liquids

realizations, lower share of net income of

equity-accounted entities, a higher

depreciation, depletion and amortization

charge, partly offset by higher volumes and

lower exploration write-offs.

Adjusting items for 2024 had a net adverse

impact of $1,148 million mainly relating to net

impairment charges. See Financial statements

– Note 4 and Note 16 for further information on

net impairment charges.

**Operational update** 

Reported production for 2025 was

1,527mboe/d, 3.8% higher than the same

period of 2024. Underlying production★ for the

year was 2.6% higher compared with the same

period of 2024 reflecting bpx energy

performance.

**Strategic progress**

• In April bp announced a Miocene oil

discovery at the Far South prospect in the

US Gulf of America. bp drilled the

exploration well in Green Canyon Block 584

approximately 120 miles off the coast of

Louisiana in 4,092 feet of water. The well

was drilled to a total depth of 23,830 feet.

The Far South co-owners are bp (operator,

57.5%) and Chevron U.S.A. Inc. (42.5%).

• In June bp announced it had signed fully

termed agreements with the State Oil

Company of the Azerbaijan Republic

(SOCAR) to acquire 35% participating

interests and become the operator of two

exploration and development blocks in the

Caspian Sea – the Karabagh oil field and the

Ashrafi-Dan Ulduzu-Aypara (ADUA) area. In

December the development programme

for the Karabagh field in the Caspian Sea,

offshore Azerbaijan, was approved by the

management committee (joint venture) and

subsequently by State Oil Company of the

Azerbaijan Republic (SOCAR) as the State

representative. Seismic acquisition

commenced thereafter.

---

| | | |
|:---|:---|:---|
| ![49789_bp_AR25_BumerangueDiscoveryV2.jpg](bp-20251231_g55.jpg) | ![49789_bp_AR25_BumerangueDiscoveryV2.jpg](bp-20251231_g55.jpg) | ![49789_bp_AR25_BumerangueDiscoveryV2.jpg](bp-20251231_g55.jpg) |
|  | Bumerangue <br>discovery <br>In August 2025 bp reported a <br>significant hydrocarbon discovery <br>at the Bumerangue well in Brazil's <br>Santos Basin. Bumerangue is one <br>of 12 exploration discoveries we <br>made in 2025, across several <br>basins, including the Gulf of <br>America and Namibia, through <br>Azule Energy, our 50:50 <br>independent joint venture with Eni. <br>**Image:** Valaris renaissance drill ship<br>|  |
| ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |  | ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |

---

---

| | | |
|:---|:---|:---|
| ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) |  | ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) |
|  | Kirkuk contract <br>goes live <br>In October 2025 bp's contract with <br>Iraq's North Oil Company and <br>North Gas Company became <br>effective, after agreeing an initial <br>baseline production rate of <br>328,000 barrels per day. Under the <br>contract we will invest in the <br>redevelopment of several giant oil <br>fields in Kirkuk, in the north of Iraq.<br>|  |
| ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |  | ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |

---

---

| | | |
|:---|:---|:---|
| 32 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Oil production & operations** continued <br>

• Azule Energy, bp's 50% joint venture, made

the following progress during the year:

–In April Rhino Resources (42.5%) along with

co-venturers Azule Energy (42.5%), Namcor

(10%), and Korres Investments (5%)

announced the successful drilling of the

Capricornus 1-X exploration well in block

PEL-85 in the Orange Basin.

–In July Azule Energy, operator of Block

15/06 in Angola, together with its partners,

announced the successful start-up of the

Agogo Integrated West Hub Project, which

aims to fully develop the Agogo and

Ndungu fields in Block 15/06.

–In July Azule Energy, operator of Block 1/14,

and its partners announced a gas discovery

at the Gajajeira-01 exploration well, located

offshore in the Lower Congo Basin, Angola.

–In October Rhino Resources, operator of

the Petroleum Exploration Licence 85 in the

Orange Basin offshore Namibia, partnering

with Azule Energy, announced a discovery

at the Volans 1-X well.

• In August bp announced the start-up of the

Argos Southwest Extension project in the

Gulf of America. The project consists of

three wells and a new drill centre tied back

to the Argos platform and is expected to

add 20,000 barrels of oil equivalent per day

of gross peak annualized average

production. bp is operator of Argos with

60.5% working interest, with co-owners

Woodside Energy (23.9%) and Union Oil

Company of California, an affiliate of

Chevron U.S.A. Inc. (15.6%).

• In September bp announced it has reached

a final investment decision (FID) on the

Tiber-Guadalupe project in the Gulf of

America. The 100% bp-owned Tiber-

Guadalupe will be bp's seventh operated oil

and gas production hub in the Gulf of

America, featuring a new floating

production platform with the capacity to

produce 80,000 barrels of crude oil per

day. The project includes six wells in the

Tiber field and a two-well tieback from the

Guadalupe field. Production is expected to

start in 2030.

• In October bp agreed to sell its 32% non-

operated working interest in the Culzean

development in the central North Sea to

Serica Energy. NEO Next exercised its

option to acquire bp's stake on the same

terms as those agreed by Serica. In

December bp completed the divestment of

the Culzean gas field in the UK North Sea to

NEO Next.

• In December bp successfully delivered first

oil from the Atlantis Drill Center 1 expansion

project in the US Gulf of America, its

seventh global upstream major project★

start-up of the year. The two-well subsea

tieback to the existing Atlantis platform is

expected to add 15,000boe/d gross peak

annualized average production.

See Oil and gas disclosures for the group on

page <u>[340](#i0dd2ee81aac04f8c9c97c86197f0c6df_490)</u> for more information on oil and gas

operations in the regions.

---

| | | |
|:---|:---|:---|
| ![49789_bp_AR25_PRINT_PermianBasinProgressv1.jpg](bp-20251231_g57.jpg) | ![49789_bp_AR25_PRINT_PermianBasinProgressv1.jpg](bp-20251231_g57.jpg) | ![49789_bp_AR25_PRINT_PermianBasinProgressv1.jpg](bp-20251231_g57.jpg) |
|  | Permian basin <br>progress <br>Our US onshore oil and gas <br>business, bpx energy, completed <br>Crossroads, its fourth central <br>delivery facility in the Permian <br>Basin. We also completed the sale <br>of our non-controlling interests in <br>Permian and Eagle Ford midstream <br>assets to Sixth Street for $1.5 <br>billion, while bpx energy remains <br>the operator. The transaction <br>supports our divestment <br>programme targeting $20 billion <br>by 2027.<br>**Image:** bpx energy midstream <br>facility, US<br>|  |
| ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |  | ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 33 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

---

| | | | |
|:---|:---|:---|:---|
| **Estimated net proved reserves and production**<sup>a</sup> **(net of royalties)** | **Estimated net proved reserves and production**<sup>a</sup> **(net of royalties)** | **Estimated net proved reserves and production**<sup>a</sup> **(net of royalties)** | **Estimated net proved reserves and production**<sup>a</sup> **(net of royalties)** |
|  | **2025** | 2024 | 2023 |
| **Estimated net proved reserves** (net of royalties) |  |  |  |
| Crude oil<sup>b</sup> (mmb) | **2908** | 3112 | 3193 |
| Natural gas liquids (mmb) | **439** | 472 | 426 |
| Total liquids | **3346** | 3584 | 3618 |
| Natural gas (bcf) | **9550** | 7821 | 8836 |
| Total hydrocarbons★ (mmboe) | **4993** | 4932 | 5142 |
| *Of which equity-accounted entities*<sup>c</sup>: |  |  |  |
| Liquids (mmb) | **885** | 917 | 1001 |
| Natural gas (bcf) | **2410** | 2467 | 2527 |
| Total hydrocarbons (mmboe) | **1301** | 1342 | 1437 |
| **Production** (net of royalties) |  |  |  |
| Crude oil<sup>b</sup> (mb/d) | **993** | 953 | 910 |
| Natural gas liquids (mb/d) | **121** | 117 | 100 |
| Total liquids (mb/d) | **1114** | 1070 | 1010 |
| Natural gas (mmcf/d) | **2391** | 2318 | 2165 |
| Total hydrocarbons (mboe/d) | **1527** | 1470 | 1383 |
| *Of which equity-accounted entities*<sup>d</sup>: |  |  |  |
| Liquids (mb/d) | **272** | 272 | 269 |
| Natural gas (mmcf/d) | **438** | 431 | 432 |
| Total hydrocarbons (mboe/d) | **347** | 346 | 343 |
| **Average realizations**★<sup>e</sup> |  |  |  |
| Liquids ($/bbl) | **60.64** | 69.85 | 72.09 |
| Natural gas ($/mcf) | **3.69** | 2.55 | 4.17 |
| Total hydrocarbons ($/boe) | **49.45** | 53.96 | 58.34 |
| aBecause of rounding, some totals may not agree exactly with the sum of their component parts.<br>bIncludes condensate and bitumen.<br>cbp's share of reserves of equity-accounted entities in the oil production & operations segment. During 2025 gas operations <br>in Angola, Argentina, Bolivia, Mexico and Norway were conducted through equity-accounted entities.<br>dbp's share of production of equity-accounted entities in the oil production & operations segment. <br>eRealizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities. | aBecause of rounding, some totals may not agree exactly with the sum of their component parts.<br>bIncludes condensate and bitumen.<br>cbp's share of reserves of equity-accounted entities in the oil production & operations segment. During 2025 gas operations <br>in Angola, Argentina, Bolivia, Mexico and Norway were conducted through equity-accounted entities.<br>dbp's share of production of equity-accounted entities in the oil production & operations segment. <br>eRealizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities. | aBecause of rounding, some totals may not agree exactly with the sum of their component parts.<br>bIncludes condensate and bitumen.<br>cbp's share of reserves of equity-accounted entities in the oil production & operations segment. During 2025 gas operations <br>in Angola, Argentina, Bolivia, Mexico and Norway were conducted through equity-accounted entities.<br>dbp's share of production of equity-accounted entities in the oil production & operations segment. <br>eRealizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities. | aBecause of rounding, some totals may not agree exactly with the sum of their component parts.<br>bIncludes condensate and bitumen.<br>cbp's share of reserves of equity-accounted entities in the oil production & operations segment. During 2025 gas operations <br>in Angola, Argentina, Bolivia, Mexico and Norway were conducted through equity-accounted entities.<br>dbp's share of production of equity-accounted entities in the oil production & operations segment. <br>eRealizations are based on sales by consolidated subsidiaries only – this excludes equity-accounted entities. |

---

---

| | | |
|:---|:---|:---|
| ![49789_bp_AR25_NorthSeaStartupV2.jpg](bp-20251231_g58.jpg) | ![49789_bp_AR25_NorthSeaStartupV2.jpg](bp-20251231_g58.jpg) | ![49789_bp_AR25_NorthSeaStartupV2.jpg](bp-20251231_g58.jpg) |
|  | North Sea start-up<br>We safely started up production <br>from the Murlach field in the UK <br>North Sea in 2025. The two-well <br>subsea tieback is expected to <br>deliver peak net production of <br>approximately 15,000 barrels of oil <br>equivalent per day to the Eastern <br>Trough Area Project (ETAP) hub, <br>which has been operating for <br>27 years. Murlach was our sixth <br>of seven major project start-ups <br>in 2025.<br>**Image:** Murlach in the North Sea<br>|  |
| ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |  | ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |

---

---

| | | |
|:---|:---|:---|
| 34 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Customers & products**<br>

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

convenience and retail fuels, EV charging, as well as *Castrol*, aviation, B2B, midstream and bp

bioenergy. It also comprises our products businesses which include refining and oil trading.

---

| | | | |
|:---|:---|:---|:---|
| **Financial and operating performance** | **Financial and operating performance** | **Financial and operating performance** | **Financial and operating performance** |
|  | **$ million** | **$ million** | **$ million** |
|  | **2025** | 2024 | 2023 |
| **Sales and other operating revenues**<sup>a</sup> | **148783** | 155401 | 160215 |
| Profit (loss) before interest and tax<sup>b</sup> | **2747** | (1522) | 2993 |
| Inventory holding (gains) losses★ | **1353** | 479 | 1237 |
| **Replacement cost (RC) profit (loss) before interest and tax**<sup>b</sup> | **4100** | (1043) | 4230 |
| Net (favourable) adverse impact of adjusting items★<sup>bc</sup> | **1172** | 3560 | 2183 |
| **Underlying RC profit before interest and tax**★ | **5272** | 2517 | 6413 |
| *Of which:* |  |  |  |
| customers – convenience & mobility | **3764** | 2584 | 2644 |
| *Castrol – included in customers* | ***971*** | *831* | *730* |
| products – refining & trading | **1508** | (67) | 3769 |
| Taxation on an underlying RC basis | **(1066)** | (452) | (1454) |
| **Underlying RC profit before interest** | **4206** | 2065 | 4959 |
| **Depreciation, depletion and amortization** | **4145** | 3957 | 3548 |
| *Of which:* |  |  |  |
| customers – convenience & mobility | **2443** | 2135 | 1736 |
| *Castrol – included in customers* | ***179*** | *176* | *167* |
| products – refining & trading | **1702** | 1822 | 1812 |
| **Adjusted EBITDA**★<sup>d</sup> | **9417** | 6474 | 9961 |
| *Of which:* |  |  |  |
| customers – convenience & mobility | **6207** | 4719 | 4380 |
| *Castrol – included in customers* | ***1150*** | *1007* | *897* |
| products – refining & trading | **3210** | 1755 | 5581 |
| **Capital expenditure**★ | **4071** | 3789 | 4761 |
| *Of which:* |  |  |  |
| customers – convenience & mobility | **2480** | 2059 | 3135 |
| *Castrol – included in customers* | ***161*** | *227* | *262* |
| products – refining & trading<sup>e</sup> | **1591** | 1730 | 1626 |
| aIncludes sales to other segments.<br>b2024 has been restated for material items to reflect the move of our Archaea Energy business from the customers & <br>products segment to the gas & low carbon energy segment.<br>cSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs.<br>dA reconciliation to RC profit before interest and tax by business is provided on page [350](#i07755ba02df142ddbe272479a28d7a7a_5878).<br>e2024 and 2023 have been restated to reflect the move of our Archaea Energy business from the customers & products <br>segment to the gas & low carbon energy segment. | aIncludes sales to other segments.<br>b2024 has been restated for material items to reflect the move of our Archaea Energy business from the customers & <br>products segment to the gas & low carbon energy segment.<br>cSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs.<br>dA reconciliation to RC profit before interest and tax by business is provided on page [350](#i07755ba02df142ddbe272479a28d7a7a_5878).<br>e2024 and 2023 have been restated to reflect the move of our Archaea Energy business from the customers & products <br>segment to the gas & low carbon energy segment. | aIncludes sales to other segments.<br>b2024 has been restated for material items to reflect the move of our Archaea Energy business from the customers & <br>products segment to the gas & low carbon energy segment.<br>cSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs.<br>dA reconciliation to RC profit before interest and tax by business is provided on page [350](#i07755ba02df142ddbe272479a28d7a7a_5878).<br>e2024 and 2023 have been restated to reflect the move of our Archaea Energy business from the customers & products <br>segment to the gas & low carbon energy segment. | aIncludes sales to other segments.<br>b2024 has been restated for material items to reflect the move of our Archaea Energy business from the customers & <br>products segment to the gas & low carbon energy segment.<br>cSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs.<br>dA reconciliation to RC profit before interest and tax by business is provided on page [350](#i07755ba02df142ddbe272479a28d7a7a_5878).<br>e2024 and 2023 have been restated to reflect the move of our Archaea Energy business from the customers & products <br>segment to the gas & low carbon energy segment. |

---

---

| | | |
|:---|:---|:---|
| ![CaseStudy_XConvenienceV2.jpg](bp-20251231_g59.jpg) | ![CaseStudy_XConvenienceV2.jpg](bp-20251231_g59.jpg) | ![CaseStudy_XConvenienceV2.jpg](bp-20251231_g59.jpg) |
|  | X Convenience <br>in Australia<br>bp acquired X Convenience, an <br>Australian fuel and convenience <br>retailer. The move significantly <br>increases our presence as a <br>national network in Australia, with <br>almost 50 additional sites <br>strategically located in the south <br>and west of the country. X <br>Convenience gives fleets and <br>consumers access to our bp fuel, <br>convenience, and loyalty <br>programmes, while retaining the <br>strong X Convenience brand.<br>**Image:** X Convenience site, Australia<br>|  |
| ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |  | ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |

---

---

| | | |
|:---|:---|:---|
| ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) |  | ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) |
|  | Engaging customers <br>with *earnify*<br>*earnify* — bp's unified digital loyalty <br>and rewards platform in the US —<br>grew rapidly in 2025, surpassing <br>8 million members as active <br>membership doubled since launch. <br>By simplifying rewards, enhancing <br>digital engagement, and improving <br>margin delivery, *earnify* is <br>becoming a scalable ecosystem <br>strengthening customer loyalty <br>and fueling future retail growth.<br>|  |
| ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |  | ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 35 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

**Financial results**

Sales and other operating revenues in 2025

were lower than in 2024, mainly due to lower

product prices.

RC profit before interest and tax for 2025

was $4,100 million, compared with a loss of

$1,043 million for 2024.

In 2025 items which bp has classified as

adjusting had a net adverse impact of $1,172

million (including adverse fair value accounting

effects of $207 million – relative to

management's view of performance), of which

$913 million related to impairments of assets,

primarily in the products business, offset by

$317 million of gains on disposal of assets

and businesses. See Financial statements –

Note 4 for further information on disposals

and impairments.

After adjusting RC profit for the net adverse

impact of items, which bp classified as

adjusting, underlying RC profit before interest

and tax (underlying result) was $5,272 million,

compared with $2,517 million for 2024. The

result was significantly higher, reflecting

stronger performance both in customers

and products.

In 2024 items which bp has classified as

adjusting had a net adverse impact of $3,560

million (including adverse fair value accounting

effects of $81 million – relative to

management's view of performance), of which

$1,143 million related to impairments of assets,

which included an impairment of the

Gelsenkirchen refinery and $1,267 million

related to loss on disposal, mainly related to

the Türkiye ground fuels business disposal.

Customers – the convenience and mobility

underlying result for 2025 was higher than

2024. The 2025 underlying result benefited

from stronger integrated performance across

fuels and midstream and lower underlying

operating expenditure★ supported by

structural cost reductions★, as well as a

more than 15% increase in *Castrol's* 

earnings with year-on-year growth for

10 consecutive quarters.

Products – the underlying result for 2025 was

significantly higher than 2024, primarily driven

by higher realized margins, the absence of the

first quarter 2024 plant-wide power outage at

the Whiting refinery and higher commercial

optimization. The results also benefited from

lower underlying operating expenditure driven

by structural cost reductions. The oil trading

contribution was broadly flat compared

with 2024.

**Operational update** 

bp-operated refining availability for 2025 was

96.3%, higher compared with 94.3% in 2024,

mainly due to the absence of the Whiting

refinery power outage.

**Strategic progress**

In 2025 clear strategic focus and improved

execution strengthened returns and materially

increased our competitiveness. Early in 2025

we committed to growing our customers &

products adjusted operating cash flows★

having delivered around 60%<sup>a</sup> of our 2027

adjusted operating cash flow growth target

in 2025.

Reshaping our integrated portfolio

Alongside the divestments we completed or

announced, including *Castrol*, Netherlands

mobility, convenience and *bp pulse* 

businesses, Austria retail, and Gelsenkirchen

refinery, we continued to focus on markets

where our integrated businesses provide the

greatest advantage. This included further high

grading of our retail network, exiting around

5% of our company owned sites as we

progress towards our target of around 10%

by 2027.

**Focusing EV charging in priority markets**

*bp pulse* continued to make progress with EV

charging investment now focusing primarily in

four core markets Germany, UK, China and the

US, with joint ventures in the Iberian region and

India. *Aral pulse* was named Germany's best

charge point operator for the third

consecutive year and in the UK *bp pulse* 

advanced its network reset programme and

extended its long-standing partnership with

Transport for London through 2029.

**Progressing strategic choices in biofuels**

Alongside the commercial integration of bp

bioenergy, in 2025 we continued to scale

biofuels but allocated capital only where

projects are economically robust and aligned

with demand progression.

We took the decision to stop further work on

development of a standalone biofuels

production (HEFA) facility at our Rotterdam

refinery in the Netherlands.

In action to improve performance

Customers delivered its highest underlying RC

profit before interest and tax since 2019 with

all businesses growing year-on-year.

Customers' strong 2025 performance was

underpinned by a reduction in structural costs.

These reductions reflect sustained execution

across procurement, supply chain efficiencies,

organizational simplification and operating

model changes.

In 2025 air bp delivered sustainable aviation

fuel (SAF) in over 60 locations in 22 countries

driven by the requirement of both European

SAF mandates and customer voluntary

SAF demand.

**Realizing value from recent customers** 

**acquisitions**

We continued to integrate and optimize our

recent acquisitions:

• We have completed the commercial

integration of bp bioenergy, a leading

sugarcane bioethanol producer – creating

a strong platform to deliver synergies and

improve value realization with trading.

• In our TravelCenters of America business,

we are progressing a targeted business

improvement plan, focused on

strengthening safety and operational

performance, sharpening commercial

discipline, and improving customer

delivery.

**Strengthening refining availability and** 

**competitiveness**

In 2025 refining delivered the best availability

on record at 96.3%, driven by strengthened

maintenance programmes, enhanced digital

monitoring and improved outage recovery.

Higher availability has supported stronger

and more consistent margin capture across

the portfolio.

In refining structural cost reductions were

delivered through optimizing maintenance

activities and driving efficiencies across the

supply chain.

Taken together, these improvements resulted

in delivery of around 80% of our 2027 $3/bbl

cash breakeven reduction ambition<sup>b</sup>.

---

| | | |
|:---|:---|:---|
| ![BPGreenTopRoundCorner.gif](bp-20251231_g21.gif) |  | ![BPGreenTopRoundCorner.gif](bp-20251231_g21.gif) |
|  | Partnering in <br>biofuels<br>bp and Corteva, one of the world's <br>leading agriscience companies, <br>launched Etlas – a new biofuels <br>50:50 joint venture. Etlas works <br>with farmers to grow canola, <br>mustard and sunflower crops for <br>use in sustainable aviation fuel and <br>renewable diesel. Etlas aims to <br>grow a million tonnes of feedstock <br>per year by the mid-2030s, enough <br>for around 800,000 tonnes of <br>biofuel. <br>|  |
| ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |  | ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |

---

aTaking growth against 2024 normalized for 2025 environmental conditions (refining margins and foreign exchange).

b2027 $3/bbl cash breakeven reduction ambition is defined as refining margin per barrel required to attain pre-tax breakeven operating cash flow excluding working capital movements,

normalized for turnaround activity levels, foreign exchange and energy prices; like-for-like portfolio.

---

| | | |
|:---|:---|:---|
| 36 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Other businesses & corporate**<br>

Other businesses & corporate comprises technology, bp ventures, shipping, our corporate

activities & functions and any residual costs of the Gulf of America oil spill.

---

| | | | |
|:---|:---|:---|:---|
| **Financial and operating performance** | **Financial and operating performance** | **Financial and operating performance** | **Financial and operating performance** |
|  | $ million | $ million | $ million |
|  | **2025** | 2024 | 2023 |
| **Sales and other operating revenues**<sup>a</sup> | **2232** | 2290 | 2657 |
| Profit (loss) before interest and tax | **(40)** | (988) | (903) |
| Inventory holding (gains) losses★ | **—** |  |  |
| **Replacement cost (RC) profit (loss) before interest and tax** | **(40)** | (988) | (903) |
| Net (favourable) adverse impact of adjusting items★<sup>b</sup> | **(608)** | 380 | 37 |
| **Underlying RC profit (loss) before interest and tax**★ | **(648)** | (608) | (866) |
| Taxation on an underlying RC basis | **399** | 292 | 322 |
| **Underlying RC profit (loss) before interest** | **(249)** | (316) | (544) |
| **Depreciation, depletion and amortization** | **989** | 1033 | 1008 |
| **Capital expenditure**★ | **292** | 408 | 441 |
| aIncludes sales to other segments.<br>bSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs. | aIncludes sales to other segments.<br>bSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs. | aIncludes sales to other segments.<br>bSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs. | aIncludes sales to other segments.<br>bSee page [337](#i70cb1abed366405bb4de86a8f38af0b7_5992) for information on the cumulative impact of FVAEs. |

---

**Financial results**

RC loss before interest and tax for 2025 was

$40 million, compared with $988 million

for 2024.

Adjusting items for 2025 had a net favourable

impact of $608 million. Adjusting items

include impacts of fair value accounting

effects, which had a favourable impact of

$1,157 million.

Adjusting items for 2024 had a net adverse

impact of $380 million. Adjusting items

include impacts of fair value accounting

effects, which had an adverse impact of

$221 million.

After adjusting RC loss for the adjusting items,

underlying RC loss before interest and tax for

2025 was $648 million, compared with a loss

of $608 million for 2024.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 37 |

---

---

| | |
|:---|:---|
|  | ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
|  | **Strategic report** |
| **Sustainability** |  |

---

Sustainability at bp

Our sustainability frame focuses on three areas – getting to net zero, improving people's lives and caring for our planet.

**Reporting on sustainability**

In this section, we cover selected sustainability issues along with information in the following areas:

• Performance on our net zero aims, see page <u>[37](#i0dd2ee81aac04f8c9c97c86197f0c6df_82)</u><u>.</u>

• Climate-related financial disclosures, see pages <u>[41](#i0dd2ee81aac04f8c9c97c86197f0c6df_88)</u><u>-</u><u>[54](#i0dd2ee81aac04f8c9c97c86197f0c6df_100)</u><u>.</u>

• Our approach – safety, ethics and compliance, our people, biodiversity, water, and 'Who we are' (our beliefs), see pages <u>[55](#i0dd2ee81aac04f8c9c97c86197f0c6df_103)</u><u>-</u><u>[59](#i87f52fc5efef4a16865a4af06e1e7987_26443)</u><u>.</u>

We provide an update on our actions on our aims, and our wider progress in relation to embedding sustainability,

in our latest Sustainability Report <u>bp.com/sustainabilityreport</u>.

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Our sustainability aims**<br>We have five sustainability aims, focused on the areas we believe are most relevant to the long-term success of our business. |  |
| **Net zero operations**<br>Our aim is to reach net zero★ by 2050 <br>or sooner for Scope 1 and 2 emissions <br>within bp's operational control<sup>a</sup>, <br>including by maintaining 'near-zero' <br>methane intensity★ across our operated <br>producing assets, enabled by supportive <br>government policies. See page <u>[38](#ia533d1b86ea04772b2fd02ae3d1c8da0_9654)</u>.<br>| **Net zero sales**<br>Our aim is to reduce to net zero the average <br>lifecycle carbon intensity of the energy <br>products★ we sell by 2050 or sooner, <br>enabled by supportive government policies <br>and the decarbonization of energy demand. <br>See page <u>[38](#ia533d1b86ea04772b2fd02ae3d1c8da0_9654)</u>.<br>**People**<br>Our aim is to support our employees and <br>local communities through the energy <br>transition. See page <u>[59](#i87f52fc5efef4a16865a4af06e1e7987_26434)</u>.<br>**Biodiversity**<br>Our aim is to support biodiversity where <br>we operate<sup>b</sup>. See page <u>[59](#i87f52fc5efef4a16865a4af06e1e7987_26434)</u>.<br>**Water**<br>Our aim is to reduce our net freshwater <br>use in stressed catchments where we <br>operate. See page <u>[59](#i87f52fc5efef4a16865a4af06e1e7987_26434)</u>.<br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

**Net zero**

Our ambition remains to be a net zero

company by 2050 or sooner, and to help the

world get to net zero.

Both our net zero aims make explicit what is

needed to enable their delivery – and delivery

of the associated interim targets or aims.

Our future business and investment decisions,

which will affect the outcomes for these aims,

will be intended to facilitate delivery of our

strategy and investor proposition, applying our

balanced investment criteria, one of which

relates to sustainability.

We believe our net zero ambition and aims,

taken together, are consistent with the goals

of the Paris Agreement.

By setting a path that enables us to make a

positive contribution, working to build out and

participate in many of the new energy value

chains the world will need, and through our

efforts to reduce our overall operational

emissions, our ambition and aims support the

world's progress towards the goals of the

Paris Agreement.

**Net zero aims 2025 performance**

---

| | | | | |
|:---|:---|:---|:---|:---|
| **Aims** | **Measure/coverage** | **2019** | **2025** <br>**targets**<br>| **Aims for 2050** <br>**or sooner**<br>|
| Net zero operations★ | Scope 1+2 | Baseline 54.5MtCO2e<br> 37%<sup>cd</sup> | 20%<sup>c</sup><br> 45-50%<sup>c</sup> | Net zero★ |
|  | Methane intensity★ | 0.14%<br> 0.04%<sup>e</sup> | 0.20% | Near zero |
| Net zero sales★ | Average lifecycle carbon intensity of <br>sold energy products★<br>| Baseline 84gCO2e/MJ<br> 7%<sup>f</sup> | 5%<sup>f</sup><br> 8-10%<sup>f</sup> | Net zero |

---

aOn a CO2e basis.

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

cReduction in absolute emissions against 2019 baseline.

dIn 2025 bp made an adjustment to the operational control boundary for Scope 1 and 2 GHG emissions. This means certain operations, assets or sources which were previously included, such

as power generation on contractor-operated drilling rigs, are now excluded. This change has a less than 1% impact on reported operational emissions. For more information on the scope of bp's

operational control boundary see bp.com/basisofreporting.

eSince 2024 reported absolute methane emissions from major operated oil and gas processing sites are based on our new measurement approach. Prior to 2024 these emissions were

calculated using a different methodology and therefore the methane intensity reported in those years and calculated using that data does not directly correlate to progress towards delivering

the 2025 target.

fReduction in the average lifecycle carbon intensity of sold energy products against the 2019 baseline. The percentage change is calculated from the source data instead of the rounded carbon

intensity number.

---

| | | |
|:---|:---|:---|
| 38 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Sustainability** continued<br>

**Net zero operations** <sup>TCFD</sup>

Our aim is to reach net zero by 2050 or sooner

for Scope 1 and Scope 2 emissions within bp's

operational control including by maintaining

'near-zero' methane intensity★ across our

operated producing assets, enabled by

supportive government policies.

We achieved a reduction of 37% against a

targeted 20% reduction in our operational

emissions by end-2025 and are aiming for a

45-50% reduction by the end of 2030, both

against our 2019 baseline.

New projects coming online add to the

challenge of reducing our operational

emissions. Continued investment in

abatement and further portfolio optimization

will be needed to meet our 2030 aim.

We also achieved our 2025 target for methane

intensity of 0.20%. Our methane intensity

for 2025 was 0.04%, compared with 0.07%

in 2024.

Scope 1 and 2 emissions

Our combined Scope 1 and 2 emissions were

34.3MtCO2e<sup>ab</sup> in 2025 – an increase from

33.6MtCO2e in 2024 due to growth in our

portfolio and seven major project start-ups.

The total decrease in emissions to 2025

includes 18MtCO2e attributable to divestments

and 5.7MtCO2e in emissions reductions

activity.

In 2025 our Scope 1 (direct) emissions were

33.7MtCO2e – an overall increase from

32.8MtCO2e in 2024. Of these Scope 1

emissions, 32.8MtCO2e were from carbon

dioxide and 0.9MtCO2e from methane<sup>c</sup>.

In 2025 our Scope 2 (indirect) emissions<sup>d</sup>

decreased by 0.1MtCO2e, to 0.7MtCO2e,

compared with 2024. The enhanced use of

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| **Average carbon intensity of sold energy products** (gCO2e/MJ)<sup>f</sup> | **Average carbon intensity of sold energy products** (gCO2e/MJ)<sup>f</sup> | **Average carbon intensity of sold energy products** (gCO2e/MJ)<sup>f</sup> | **Average carbon intensity of sold energy products** (gCO2e/MJ)<sup>f</sup> | **Average carbon intensity of sold energy products** (gCO2e/MJ)<sup>f</sup> | **Average carbon intensity of sold energy products** (gCO2e/MJ)<sup>f</sup> |  |
|  | **2025** | 2024 | 2023 | 2022 | 2021 | 2019 |
| Average carbon intensity of sold <br>energy products<br>| **79** | 79 | 80 | 81 | 81 | 84 |
| Oil/refined products | **91** | 91 | 91 | 92 | 92 | 95 |
| Gas/NGLs | **67** | 67 | 67 | 67 | 67 | 68 |
| Bioproducts<sup>g</sup> | **38** | 41 | 44 | 43 | 44 | 47 |
| Power/heat<sup>h</sup> | **51** | 50 | 56 | 29 | 27 | 28 |

---

lower carbon power agreements contributed

to this decrease.

We report our Scope 1 and 2 emissions on an

operational control and equity share basis in

the *bp ESG Datasheet 2025*.

---

| | |
|:---|:---|
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | <u>bp.com/ESGdata</u> |

---

Scope 3 emissions <sup>TCFD</sup>

In 2025 our Scope 3 category 11 emissions

were 471MtCO2e<sup>e</sup>. These are the end-use

emissions associated with sales of energy

products, as determined in bp's calculation

of the average carbon intensity of our sold

energy products★.

Methane

Since 2024 absolute methane emissions have

been reported based on our new methane

measurement approach across our major

operated oil and gas processing sites. Using

this approach, our methane intensity was

0.04% in 2025 (2024 0.07%<sup>c</sup>). Methane

emissions from our upstream★ operations

used to calculate this methane intensity

were 25kt in 2025 (46kt in 2024<sup>c</sup>).

Marketed gas volumes were broadly flat at

3,637bcf in 2025.

The lower emissions and intensity in 2025 were

primarily from improved management of

abnormal plant conditions in our Tangguh

operations, Indonesia, reported in 2024.

We remain on track to reach zero routine

flaring by 2030 in line with our aim under the

World Bank's Zero Routine Flaring Initiative.

**Net zero sales** <sup>TCFD</sup>

Our aim is to reduce to net zero the average

lifecycle carbon intensity of the energy

products★ we sell by 2050 or sooner, enabled

by supportive government policies and the

decarbonization of energy demand.

We have achieved our target to reduce the

intensity of our sold energy products by 5%

from the 2019 baseline by the end of 2025. We

are aiming for an 8-10% reduction by the end

of 2030 compared to our 2019 baseline.

In 2025 the average carbon intensity of our

sold energy products was 79gCO2e/MJ.

This represents a 7% reduction from our

2019 baseline.

The incremental improvement in performance

from 2024 was primarily driven by a growth in

retail power sales across our utility businesses

– bp Energy Retail and GETEC, our trading

business, and our renewable businesses –

Lightsource bp and JERA Nex bp. It was

supported by the high grading of our retail

portfolio and improved identification of

end-user sales volumes within the refined

product category.

Details of our net zero sales methodology are

in the *bp Basis of Reporting 2025.*

---

| | |
|:---|:---|
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | <u>bp.com/basisofreporting</u> |

---

As announced in February 2025, we plan to

invest selectively and with discipline in

transition businesses★, see page <u>[21](#i0dd2ee81aac04f8c9c97c86197f0c6df_55)</u>.

Our disciplined approach to capital investment

means that individual investments will be

made when we consider there to be a clear

and compelling business case, in line with our

balanced set of investment criteria, see

page <u>[22](#i0dd2ee81aac04f8c9c97c86197f0c6df_58)</u>.

**Advocacy related to net zero**

We regularly advocate for or comment on the

development of policy that is relevant to bp

and our sustainability aims. In 2025 our

advocacy activities focused on various aspects

including bioenergy, hydrogen and carbon

pricing. We publish examples of our activity

online at <u>bp.com/advocacyactivities</u>.

aIn 2025 bp made an adjustment to the operational control boundary for Scope 1 and 2 GHG emissions. This means certain operations, assets or sources which were previously included, such as

power generation on contractor-operated drilling rigs, are now excluded. This change has a less than 1% impact on reported operational emissions. For more information on the scope of bp's

operational control boundary see bp.com/basisofreporting.

bDue to rounding some totals may not agree exactly to the sum of their component parts.

cSince 2024 reported absolute methane emissions from upstream major operated oil and gas processing sites are based on our new measurement approach. Prior to 2024 these emissions were

calculated using a different methodology and therefore the methane intensity reported in those years and calculated using that data does not directly correlate to progress towards delivering

the 2025 target. Prior year data is provided for information purposes, and we do not seek to directly compare prior years.

d Scope 2 emissions on a market basis.

b eThis Scope 3 category 11 metric follows a different methodology and boundary to the Scope 3 category 11 emissions from the carbon in bp's upstream oil and gas production (known previously as

bp's aim 2 (net zero production), which was retired in February 2025), so is not directly comparable to prior years of data for that retired aim and does not correlate to progress towards any

retired targets associated with it. Although these emissions are a subset of the lifecycle emissions under bp's net zero sales aim, there is no target or aim associated with them. See bp.com/

basisofreporting for more detail on methodology.

fThe aggregate lifecycle emissions and energy values used in the calculation of the average lifecycle carbon intensity of sold energy products★ are provided in the *bp ESG Datasheet 2025*.

gIncludes biofuels and biogas.

hCovers all power, including renewable and non-renewable.

TCFD Information that supports TCFD Recommendations and Recommended Disclosures in relation to governance (see pages <u>[41](#i64435a2b74134bf69d5c362d53a40cc9_7984)</u><u>-</u><u>[44](#i0dd2ee81aac04f8c9c97c86197f0c6df_94)</u>)

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 39 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  |  |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Streamlined energy and carbon reporting (SECR) information**<br>Further information on our greenhouse gas (GHG) emissions, energy consumption and energy efficiency is set out here and on the <br>following page. It includes disclosures in respect of the SECR requirements. Further breakdown of our GHG and energy data is available <br>in the *bp ESG Datasheet 2025* at <u>bp.com/ESG</u>. | **Streamlined energy and carbon reporting (SECR) information**<br>Further information on our greenhouse gas (GHG) emissions, energy consumption and energy efficiency is set out here and on the <br>following page. It includes disclosures in respect of the SECR requirements. Further breakdown of our GHG and energy data is available <br>in the *bp ESG Datasheet 2025* at <u>bp.com/ESG</u>. | **Streamlined energy and carbon reporting (SECR) information**<br>Further information on our greenhouse gas (GHG) emissions, energy consumption and energy efficiency is set out here and on the <br>following page. It includes disclosures in respect of the SECR requirements. Further breakdown of our GHG and energy data is available <br>in the *bp ESG Datasheet 2025* at <u>bp.com/ESG</u>. | **Streamlined energy and carbon reporting (SECR) information**<br>Further information on our greenhouse gas (GHG) emissions, energy consumption and energy efficiency is set out here and on the <br>following page. It includes disclosures in respect of the SECR requirements. Further breakdown of our GHG and energy data is available <br>in the *bp ESG Datasheet 2025* at <u>bp.com/ESG</u>. | **Streamlined energy and carbon reporting (SECR) information**<br>Further information on our greenhouse gas (GHG) emissions, energy consumption and energy efficiency is set out here and on the <br>following page. It includes disclosures in respect of the SECR requirements. Further breakdown of our GHG and energy data is available <br>in the *bp ESG Datasheet 2025* at <u>bp.com/ESG</u>. |  |
|  | Operational control<sup>ab</sup> | Unit | **2025** | 2024 | 2023 |  |
|  | **Scope 1 (direct) emissions**<sup>c</sup> | MtCO2e | **33.7** | 32.8 | 31.1 |  |
|  | UK and offshore | MtCO2e | **1.0** | 1.0 | 1.0 |  |
|  | Global (excluding UK and offshore) | MtCO2e | **32.6** | 31.8 | 30.1 |  |
|  | **Scope 2 (indirect) emissions – location-based**<sup>c</sup> | MtCO2e | **1.7** | 2.4 | 2.0 |  |
|  | UK and offshore | MtCO2e | **0.02** | 0.02 | 0.02 |  |
|  | Global (excluding UK and offshore) | MtCO2e | **1.7** | 2.4 | 1.9 |  |
|  | **Scope 2 (indirect) emissions – market-based**<sup>c</sup> | MtCO2e | **0.7** | 0.8 | 1.0 |  |
|  | UK and offshore<sup>d</sup> | MtCO2e | **0.03** | 0.02 | 0.0 |  |
|  | Global (excluding UK and offshore) | MtCO2e | **0.7** | 0.8 | 1.0 |  |
|  | **Energy consumption**<sup>e</sup> | GWh | **134448** | 129872 | 124770 |  |
|  | UK and offshore | GWh | **4718** | 4526 | 4688 |  |
|  | Global (excluding UK and offshore) | GWh | **129730** | 125347 | 120082 |  |
|  | **Ratio of Scope 1 (direct) and Scope 2 (indirect) emissions to gross production**<sup>f</sup> | teCO2e/te | **0.16** | 0.16 | 0.16 |  |
|  | UK and offshore | teCO2e/te | **0.12** | 0.13 | 0.13 |  |
|  | Global (excluding UK and offshore) | teCO2e/te | **0.16** | 0.16 | 0.16 |  |
|  | a Operational control data comprises 100% of emissions from activities operated by bp / where bp or its subsidiaries has full authority to introduce and implement its OMS★. Read <br>more at bp.com/basisofreporting.<br>b Due to rounding, some totals may not agree exactly to the sum of their component parts.<br>c In 2025 bp made an adjustment to the operational control boundary for Scope 1 and 2 GHG emissions. This means certain operations, assets or sources which were previously <br>included such as power generation on contractor-operated drilling rigs are now excluded. This change has a less than 1% impact on reported operational emissions. For more <br>information on the scope of bp's operational control boundary see bp.com/basisofreporting.<br>d REGOs and other instruments reflected in our data had not been retired at the time of publication but are expected to be retired subject to business decisions at the end of the <br>compliance period.<br>e Energy content of flared or vented gas is excluded from energy consumption reported as although it reflects loss of energy resources, it does not reflect energy use required for <br>production or manufacturing of products.<br>f Gross production comprises upstream production, refining throughput and petrochemicals produced. | a Operational control data comprises 100% of emissions from activities operated by bp / where bp or its subsidiaries has full authority to introduce and implement its OMS★. Read <br>more at bp.com/basisofreporting.<br>b Due to rounding, some totals may not agree exactly to the sum of their component parts.<br>c In 2025 bp made an adjustment to the operational control boundary for Scope 1 and 2 GHG emissions. This means certain operations, assets or sources which were previously <br>included such as power generation on contractor-operated drilling rigs are now excluded. This change has a less than 1% impact on reported operational emissions. For more <br>information on the scope of bp's operational control boundary see bp.com/basisofreporting.<br>d REGOs and other instruments reflected in our data had not been retired at the time of publication but are expected to be retired subject to business decisions at the end of the <br>compliance period.<br>e Energy content of flared or vented gas is excluded from energy consumption reported as although it reflects loss of energy resources, it does not reflect energy use required for <br>production or manufacturing of products.<br>f Gross production comprises upstream production, refining throughput and petrochemicals produced. | a Operational control data comprises 100% of emissions from activities operated by bp / where bp or its subsidiaries has full authority to introduce and implement its OMS★. Read <br>more at bp.com/basisofreporting.<br>b Due to rounding, some totals may not agree exactly to the sum of their component parts.<br>c In 2025 bp made an adjustment to the operational control boundary for Scope 1 and 2 GHG emissions. This means certain operations, assets or sources which were previously <br>included such as power generation on contractor-operated drilling rigs are now excluded. This change has a less than 1% impact on reported operational emissions. For more <br>information on the scope of bp's operational control boundary see bp.com/basisofreporting.<br>d REGOs and other instruments reflected in our data had not been retired at the time of publication but are expected to be retired subject to business decisions at the end of the <br>compliance period.<br>e Energy content of flared or vented gas is excluded from energy consumption reported as although it reflects loss of energy resources, it does not reflect energy use required for <br>production or manufacturing of products.<br>f Gross production comprises upstream production, refining throughput and petrochemicals produced. | a Operational control data comprises 100% of emissions from activities operated by bp / where bp or its subsidiaries has full authority to introduce and implement its OMS★. Read <br>more at bp.com/basisofreporting.<br>b Due to rounding, some totals may not agree exactly to the sum of their component parts.<br>c In 2025 bp made an adjustment to the operational control boundary for Scope 1 and 2 GHG emissions. This means certain operations, assets or sources which were previously <br>included such as power generation on contractor-operated drilling rigs are now excluded. This change has a less than 1% impact on reported operational emissions. For more <br>information on the scope of bp's operational control boundary see bp.com/basisofreporting.<br>d REGOs and other instruments reflected in our data had not been retired at the time of publication but are expected to be retired subject to business decisions at the end of the <br>compliance period.<br>e Energy content of flared or vented gas is excluded from energy consumption reported as although it reflects loss of energy resources, it does not reflect energy use required for <br>production or manufacturing of products.<br>f Gross production comprises upstream production, refining throughput and petrochemicals produced. | a Operational control data comprises 100% of emissions from activities operated by bp / where bp or its subsidiaries has full authority to introduce and implement its OMS★. Read <br>more at bp.com/basisofreporting.<br>b Due to rounding, some totals may not agree exactly to the sum of their component parts.<br>c In 2025 bp made an adjustment to the operational control boundary for Scope 1 and 2 GHG emissions. This means certain operations, assets or sources which were previously <br>included such as power generation on contractor-operated drilling rigs are now excluded. This change has a less than 1% impact on reported operational emissions. For more <br>information on the scope of bp's operational control boundary see bp.com/basisofreporting.<br>d REGOs and other instruments reflected in our data had not been retired at the time of publication but are expected to be retired subject to business decisions at the end of the <br>compliance period.<br>e Energy content of flared or vented gas is excluded from energy consumption reported as although it reflects loss of energy resources, it does not reflect energy use required for <br>production or manufacturing of products.<br>f Gross production comprises upstream production, refining throughput and petrochemicals produced. |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  |  |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

---

| | | |
|:---|:---|:---|
| 40 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Sustainability** continued<br>

![](bp-20251231_g60.gif)

**Streamlined energy and carbon reporting (SECR) information**

**Energy efficiency measures**

**Operational efficiency**

We take a portfolio view of our project

improvement activities at individual sites.

This allows us to prioritize the most

effective projects, supporting energy

efficiency, reduced carbon emissions, and

lower costs.

During 2025 we completed energy

efficiency reviews across four production

regions: the North Sea, Oman, Egypt and

Asia Pacific. Our refining business also

completed the energy efficiency

programme launch in 2024. Additional

reviews were carried out at the Cherry

Point (US), Castellón (Spain) and

Gelsenkirchen (Germany) refineries. The

opportunities identified through these

reviews will be progressed through our

established business processes and plans

that support our net zero ambition.

In 2025 a total of 14 new emissions

reduction projects and actions

contributed to reductions of 0.27MtCO2e,

including low carbon energy consumption

projects. This is in addition to the 27

emissions reduction projects delivered in

2024, which achieved a reduction of

0.42MtCO2e. These projects are tracked

based on GHG reductions and include

energy efficiency improvements.

Archaea Energy purchased renewable

energy certificates (RECs) equivalent to

125ktCO2e in emissions savings on a

market basis.

A further 144ktCO2e of emissions

reductions were achieved through energy

efficiency improvements in production

processes and flaring optimization

projects during 2025. These included:

• Three projects at our Tangguh facility

delivering 45ktCO2e in reductions,

including flare purge rate

rationalization and boil-off gas flaring

minimalization.

• A power synchronization project

between two platforms in Trinidad and

Tobago which reduced spinning

reserve through an electrical tie-over

enabling load sharing, delivering

14ktCO2e reductions.

• Ongoing programmes at bpx energy

including replacement of natural-gas

driven pneumatic controllers,

installation of solar air compressors,

electrification measures and

reductions in fugitive emissions,

delivering 80ktCO2e.

In addition, our Castellón, Rotterdam

(Netherlands), and Whiting (US) refineries

have implemented further actions to drive

energy efficiency and reduce carbon

emissions, including steam trap repair

and replacement programmes. At Cherry

Point the restoration of cooling water

infrastructure improved reliability in

meeting refinery needs and enhanced the

efficiency of compressor operations.

As part of managing energy efficiency, we

take a portfolio-wide approach to

assessing and prioritizing spinning

reserve reduction opportunities. Spinning

reserve involves running additional power

generation machines to provide an excess

of energy supply. This can help to protect

production from plant vulnerabilities,

including power generation reliability.

Reducing spinning reserve can increase

exposure to power fluctuations for

production. We take a risk-based

approach when considering reducing the

number of running machines. This

allows bp to realise emissions and

maintenance cost reductions from fewer

running machines, while managing the

associated production risk.

bp is involved in several external groups

working on energy efficiency, including

the Oil & Gas Climate Initiative (OGCI), the

International Association of Oil & Gas

Producers (IOGP) and Energy Star. We

continue to run an annual training course

for new chemical engineers, which

includes energy efficiency upskilling, and

we offer GHG emissions and energy

efficiency training for more experienced

engineers and practitioners.

**Reporting methodology**

Our approach to reporting GHG emissions

broadly follows the GHG Protocol

Corporate Standard and the Ipieca

Petroleum Industry Guidelines for

Reporting Greenhouse Gas Emissions 2nd

Edition, May 2011. We calculate GHG

emissions based on fuel consumption and

fuel properties for major sources, such

as flares.

We report CO2 and methane. We do not

include nitrous oxide, hydrofluorocarbons,

perfluorocarbons and sulphur

hexafluoride as they are not material to

our operations.

Energy consumption is monitored and

reported centrally from all operated sites

by fuel type. This includes all energy, both

imported and self-produced, used to run

our operations and aligned with our GHG

reporting boundary, but excludes energy

content of flared or vented gas. Although

flaring and venting reflects loss of energy

resources, it does not reflect energy use

required for production or manufacturing

of products.

**Ratio of Scope 1 and Scope 2** 

**emissions to gross production**

bp reports a ratio of Scope 1 and Scope 2

emissions to gross production, see the

SECR table on page <u>[39](#i0dd2ee81aac04f8c9c97c86197f0c6df_85)</u>. This covers all our

Scope 1 and Scope 2 emissions on an

operational control boundary basis and

uses gross operated sales from our

operated oil and gas facilities, refinery

throughput and petrochemicals

produced. The denominator uses output

from production businesses, refineries

and petrochemical facilities, which

account for 96% of total operated

emissions. The intensity ratio has

remained the same as 2024.

The ratio provided in the SECR table uses

production and throughput from our

operated upstream, refining and

chemicals businesses as a measure of

output which can be consistently

reported against. We report data on a

consolidated basis in the Annual Report

and Form 20-F and this differs to the

production and throughput used for the

ratio in the SECR table, which aligns with

the operational control boundary basis.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 41 |

---

---

| | |
|:---|:---|
|  | ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
|  | **Strategic report** |
| **Climate-related financial disclosures**<sup>a</sup> |  |

---

We want to continue to work constructively

with the IFRS Foundation's International

Sustainability Standards Board (ISSB) and

others as they develop good practices and

standards for transparent climate-related

reporting.

In 2025 we continued to engage with the

World Business Council for Sustainable

Development (WBCSD) in relation to its

ongoing 'Climate Scenario Analysis Reference

Approach for Companies in the Energy

System'. Read about how we have used the

WBCSD Scenario Catalogue<sup>b</sup> as the start point

for consolidating our Transition Scenario

Catalogue★, which was used to inform our

own scenario analysis, on page <u>[52](#idfd02045cd904558886b64b741d9bf83_2-1-1-5-781302)</u>.

**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 2025<sup>c</sup>.

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<sup>d</sup>.

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 Rules<sup>e</sup>. In the Strategy (b)

section on page <u>[46](#i0dd2ee81aac04f8c9c97c86197f0c6df_97)</u>, we describe elements of

our plans for the transition to a lower carbon

economy as we execute our strategy.

As explained on page <u>[10](#i0dd2ee81aac04f8c9c97c86197f0c6df_34)</u>**,** we explain why we

consider our strategy to be consistent with the

goals of the Paris Agreement.

The strategy has been developed taking into

consideration, among other things, the bp

Energy Outlook scenarios, which take account

of climate commitments and pledges made by

countries in which we operate alongside a

range of other factors.

In preparing our disclosures we have made

several judgements, and while we are satisfied

that they are consistent with the TCFD

Recommendations, Recommended

Disclosures and reporting requirements under

the UK CFD Regulations, we will continue to

monitor guidance as it evolves and consider

opportunities to enhance our disclosures.

aThis section provides disclosures pursuant to the FCA Listing Rule UKLR 6.6.6R(8) and in line with the Companies (Strategic Report) (Climate-related Financial Disclosure) Regulations 2022 (The

UK CFD Regulations). In the main, we consider our TCFD disclosures achieve UK CFD compliance. Where additional information has been provided beyond our TCFD disclosures to achieve

compliance with the CFD Regulations, this has been specifically called out.

bOur 2025 analysis used a suite of external scenarios from various providers – this took as its start point the latest WBCSD (World Business Council for Sustainable Development) Scenario

Catalogue (V3, published in 2024), which we then updated for relevant metrics where underlying source data providers (IEA, NGFS, UN PRI) have published more recent (or withdrawn older)

transition scenarios. We have referred to this as our Transition Scenario Catalogue★ – for more detail see page [52](#idfd02045cd904558886b64b741d9bf83_2-1-1-5-781302).

cIn considering the consistency of our disclosures with the TCFD Recommendations and Recommended Disclosures we have had regard to, among other things, the documents referred to in

UKLR 6.6.8G and 6.6.9G, as applicable to the financial year 2025.

dIn preparing the disclosures we have referred to the TCFD implementation guidance 'Annex: Implementing the Recommendations of the Task Force on Climate-related Financial Disclosures

(October 2021)', available from fsb-tcfd.org/publications.

eUKLR 6.6.8G and UKLR 6.6.9G.

fWe interpret the term 'climate-related issues' to relate primarily to those climate-related risks and opportunities for bp that are relevant to the delivery of long-term shareholder value in the

context of the energy transition.

**Governance**

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-SMALL-TopRoundCornerV2.gif](bp-20251231_g61.gif) |  | ![WarmGrey2-50-SMALL-TopRoundCornerV2.gif](bp-20251231_g61.gif) |
|  | **TCFD Recommendation:**<br>Disclose the organization's governance around <br>climate-related issues and opportunities.<br>|  |
| ![WarmGrey2-50-SMALL-BottomRoundCornerV2.gif](bp-20251231_g62.gif) |  | ![WarmGrey2-50-SMALL-BottomRoundCorner.gif](bp-20251231_g63.gif) |

---

**Recommended Disclosure:**<br>a. Describe the board's oversight of climate-<br>related risks and opportunities. <br>b. Describe management's role in assessing <br>and managing climate-related risks and <br>opportunities.<br>

![](bp-20251231_g64.gif)

**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 <u>bp.com/governance</u>.

The board considers that our strategy allows

bp to be flexible to adapt to the evolution of

the external environment, including market

changes, to remain consistent with the

Paris goals.

The board and its committees have oversight

of climate-related issues<sup>f</sup>, which include

climate-related risks and opportunities.

Related board and committee activities are set

out within the board activities section and

committee reports respectively, which can be

found on the pages detailed in the table on

page <u>[42](#id79cb37ee10946c4a41582f6faafe602_2-1-1-2-725324)</u>.

Climate-related risks and opportunities were

discussed at each relevant board meeting

covering strategy in 2025, and the

committees considered climate-related

issues where appropriate to do so in fulfilling

their responsibilities. Verbal reports from

each of the committee chairs are given at

board meetings to keep the board apprised

of the relevant matters discussed including,

where applicable, climate-related risks and

opportunities.

Our company secretary's office manages the

process by which board and committee

agendas are set and works closely with teams

in bp to develop materials that assist the

board to discharge its responsibilities,

including in respect of climate-related issues.

The board also reviewed documents

containing climate-related disclosures –

including these TCFD disclosures.

---

| | | |
|:---|:---|:---|
| 42 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Climate-related financial disclosures** continued<br>

**Learning and development**

The board continues to develop its knowledge and expertise on climate-related and sustainability matters. For example, in 2025, the board took

part in the following:

---

| | |
|:---|:---|
| **Renewables and power update** | Included recent progress on, and plans for, offshore wind. Update provided to assist the board in remaining <br>abreast of key energy transition risks and opportunities.<br>|
| **Hydrogen and carbon capture** <br>**and storage transition growth**★ <br>**engine update**<br>| Update provided on bp-led projects including the Northern Endurance Partnership and Net Zero Teesside <br>Power. Assisted the board in remaining abreast of key energy transition risks and opportunities.<br>|
| **Energy and economic update** | The briefing was given by our chief economist on developments shaping the key political and societal <br>trends currently affecting the energy transition, in advance of publication of the *bp Energy Outlook* 2025 <br>in September 2025. Briefing assisted the board in remaining abreast of key developments.<br>|

---

The board is due to receive further updates on bp's strategic process and sustainability frame in 2026.

**Climate and sustainability expertise**

The board believes its members possess the

necessary expertise related to climate change

and sustainability to support the group's

strategy. In particular, eight of our non-

executive directors have specific climate

change and sustainability expertise, as set

out below.

This determination is based on an assessment

of their background and experience, with a

focus on their background in the energy

sector, experience in executive roles and

depth of experience in sustainability and

climate change, including climate-related

risks and opportunities.

For more general director skills information,

see page <u>[73](#i0dd2ee81aac04f8c9c97c86197f0c6df_130)</u>.

• **Dame Amanda Blanc** is the Group CEO of

Aviva plc, and has held several executive

roles across the industry. She was Co-Chair

of the UK Transition Plan Taskforce.

**•Dave Hager** has over 40 years' experience

in the oil and gas industry. During his time

as CEO of Devon Energy Corporation, he

was instrumental in developing its

approach to climate and sustainability. He

also served on the American Petroleum

Institute Executive Committee as the

organization set out its positions on climate

and sustainability. He has served on the bp

safety and sustainability committee since

December 2025.

**•Simon Henry** has significant climate and

sustainability experience from senior roles

across the energy and financial sectors. As

CFO of Shell, he oversaw group strategy

through the period of the 2015 Paris

Agreement. He contributed to Lloyds

Bank's first climate strategy, supported the

development of PetroChina's Sustainability

Report, and, while a Non-Executive director

at Rio Tinto, helped shape its emissions

reduction plans. He has served on the

sustainability committees at Rio Tinto and

Harbour Energy, and was a contributing

member of Chapter Zero and the Energy

Transition Commission.

**•Albert Manifold** has a strong track record

of strategic leadership and operational

delivery. As CEO of CRH plc, the global

building materials company, he embedded

decarbonization, circularity and water

efficiency into the company's strategy and,

under his leadership, CRH made recognized

progress in climate performance.

**•Melody Meyer** has deep-rooted operational

experience in the energy sector which

equips her to advise on climate-related

risks and opportunities. She has chaired

bp's safety and sustainability committee

since November 2019, which oversees the

implementation of bp's sustainability frame

and net zero ambition.

**•Hina Nagarajan** has over 30 years'

experience in senior roles within the

customer-focused FMCG sector. Through

her executive roles at Diageo, she is

responsible for assessing and mitigating

risks related to climate and sustainability,

as well as delivery of ESG targets for her

region and Diageo plc. During her time as

CEO of United Spirits Limited (Diageo plc's

listed Indian subsidiary), she oversaw

the implementation of Diageo India's 10-

year ESG action plan, and its Society 2030

mission, in addition to a number of other

sustainability initiatives.

**•Satish Pai** has extensive experience in the

resource and energy industries. He is

managing director of metals company

Hindalco Industries Limited, and leads the

company's Sustainability Board in

overseeing sustainability initiatives – such

as sustainable mining practices, energy

conservation and recycling. He has served

on the bp safety and sustainability

committee since March 2023.

**•Johannes Teyssen** brings CEO experience

from his time at E.ON, where under his

leadership, it split its hydrocarbons and

non-hydrocarbons businesses – giving him

significant experience of considering

climate-related risks and opportunities. He

has sat on bp's safety and sustainability

committee since 2021. He is a director of

Alpiq Holding AG, a Swiss energy services

provider and electricity producer in Europe.

---

| | | | |
|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Board and committees'** <br>**consideration of climate-**<br>**related issues**<br>For examples from the year ended <br>31 December 2025, see the text <br>indicated with TCFD on the pages <br>set out below. | **Board and committees'** <br>**consideration of climate-**<br>**related issues**<br>For examples from the year ended <br>31 December 2025, see the text <br>indicated with TCFD on the pages <br>set out below. |  |
|  | ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | The board: pages <u>[73](#i0dd2ee81aac04f8c9c97c86197f0c6df_130)</u><u>-</u><u>[75](#i770b8be3d6ca45a2a60c885c7a1db815_1-1-1-1-931545)</u> |  |
|  |  | Safety and sustainability <br>committee: pages <u>[82](#i0dd2ee81aac04f8c9c97c86197f0c6df_160)</u><u>-</u><u>[83](#i0dd2ee81aac04f8c9c97c86197f0c6df_163)</u><br>|  |
|  |  | Audit committee: pages <u>[84](#i0dd2ee81aac04f8c9c97c86197f0c6df_166)</u><u>-</u><u>[88](#i5f462ba57f614b0d990dbbed68c97d89_1109)</u> |  |
|  |  | Remuneration committee: <br>pages <u>[91](#i0dd2ee81aac04f8c9c97c86197f0c6df_187)</u><u>-</u><u>[117](#ica0492c0e311472fbb0fabe968d4aa83_11506)</u><br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 43 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

**The role of management** 

The board, subject to certain conditions and

limitations, delegates day-to-day management

of the business of the company to the CEO.

The CEO is responsible for proposing bp's

strategy and annual plan to the board for

approval and leading the bp leadership team in

delivering bp's strategy and annual plan.

Under this delegation, the CEO is responsible

for overseeing the implementation of a

comprehensive system of internal controls

that are designed to, among other things (a)

identify and manage risks that are material to

bp, (b) protect bp's assets, and (c) monitor the

application of bp's resources in a manner that

meets external regulatory standards. Risks, for

these purposes, include the climate-related

risks and opportunities for bp associated with

the issue of climate change and the transition

to a lower carbon economy. This is set out in

the CEO role profile at <u>bp.com/board</u>.

The assessment and management of climate-

related risks and opportunities are embedded

across bp at various levels and delegated

authority flows down from the board through

the CEO. See page <u>[60](#i0dd2ee81aac04f8c9c97c86197f0c6df_106)</u> for more information on

risk governance and oversight.

**2025 activity** 

Where considered appropriate, climate-

related risks and opportunities were discussed

at bp leadership team meetings in 2025 as

part of regular business performance updates

prepared for these meetings.

The bp leadership team provides oversight of

risk, including climate-related risk, through the

various committees described on page <u>[60](#i0dd2ee81aac04f8c9c97c86197f0c6df_106)</u>.

They are informed about and monitor

emerging risks over the short, medium and

longer term via emerging risk papers

produced by our SVP treasury. Members of the

leadership team receive information on the

longer-term risks and opportunities

associated with the energy transition via

updates produced by our chief economist.

These papers are shared with the board.

**SVP level and beyond** 

The bp leadership team is supported by bp's

senior-level leadership and their respective

teams, with dedicated business and functional

expertise focused on climate-related risks and

opportunities or on matters which may be

affected by such risks and opportunities. This

includes: health, safety, environment and

carbon; risk; and strategy and sustainability

(which includes our carbon ambition, policy

and economics teams). Alignment between

group, business and functional leaders is

fostered through other meetings, such as the

TCFD working group which leads the

preparation of bp's climate-related financial

disclosures.

**Management consideration of climate-related risks and opportunities is organized as follows:** 

---

| | |
|:---|:---|
| **Resource commitment meeting** | Forum for approval of investments related to existing and new lines of business above $250 <br>million or $25 million for acquisitions, or which exceed the relevant EVP financial authority, and <br>any project considered strategically important such as a new market entry, see page <u>[21](#i3021f407d0ca49208d2bbf6f9f773c48_5170)</u>.<br>|
| **Group operational risk committee** | Provides oversight of safety and operational risk management performance for the group, <br>where appropriate. Climate-related factors may affect certain sources of safety and <br>operational risk, such as severe weather events.<br>|
| **Group operational risk committee** <br>**(sustainability)**<br>| In October 2025 our executive-level group sustainability committee (GSC), was replaced by the <br>group operational risk committee (sustainability) (GORC(S)). This executive-level committee, <br>chaired by the chief financial officer, provides oversight, challenge and support in the <br>implementation of our sustainability frame and aims, and oversight of the management of <br>potentially significant sustainability risks and opportunities, including those related to <br>climate change. <br>Between the GSC and GORC(S) there were four scheduled meetings in 2025 with ad hoc <br>discussions held as needed. In both committees, members considered bp's sustainability aims, <br>progress against targets and bp's position on certain strategic sustainability issues.<br>The outputs from the committee are shared with the board and its committees, including the <br>safety and sustainability committee, as appropriate.<br>|
| **Group financial risk committee** | Monitors the effectiveness of bp's financial reporting, systems of internal control and financial <br>risk management, namely material group financial risks. Where appropriate, it considers the <br>planned approach to assurance and verification of non-financial reporting ahead of updating <br>the audit committee.<br>|

---

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Acquired businesses**<br>Integration plans are developed to <br>transition acquired businesses into bp's <br>system of internal control, over an <br>appropriate timeframe.<br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

![SR_ClimateGovernanceManagementClimateRelatedMattersV3-LEFT.jpg](bp-20251231_g65.jpg)

---

| | | |
|:---|:---|:---|
| 44 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Climate-related financial disclosures** continued<br>

---

| | | | | |
|:---|:---|:---|:---|:---|
| **Climate governance: management of climate-related matters**<br>As at 1 January 2026 | **Climate governance: management of climate-related matters**<br>As at 1 January 2026 | **Climate governance: management of climate-related matters**<br>As at 1 January 2026 | **Climate governance: management of climate-related matters**<br>As at 1 January 2026 | **Climate governance: management of climate-related matters**<br>As at 1 January 2026 |
| **bp board level** | **bp board level** | **bp board level** | **bp board level** | **bp board level** |
| **Board** | **Audit committee** | **Safety and sustainability** <br>**committee**<br>| **People, culture and** <br>**governance committee** | **Remuneration** <br>**committee** <br>|
| **EVP level** | **EVP level** | **EVP level** | **EVP level** | **EVP level** |
| **CEO** | **Group financial** <br>**risk committee**<br>Chair: CFO | **Resource** <br>**commitment meeting** <br>Chair: CEO  | **Group operational** <br>**risk committee** <br>Chair: CEO | **Group operational** <br>**risk committee** <br>**(sustainability)**<br>Chair: CFO |
|  | **Group financial** <br>**risk committee**<br>Chair: CFO | **Resource** <br>**commitment meeting** <br>Chair: CEO  | **Group operational** <br>**risk committee** <br>Chair: CEO | **Group operational** <br>**risk committee** <br>**(sustainability)**<br>Chair: CFO |
| **bp leadership team** | **Group financial** <br>**risk committee**<br>Chair: CFO | **Resource** <br>**commitment meeting** <br>Chair: CEO  | **Group operational** <br>**risk committee** <br>Chair: CEO | **Group operational** <br>**risk committee** <br>**(sustainability)**<br>Chair: CFO |

---

---

| | |
|:---|:---|
| **SVP level** |  |
| **Sustainability forum**<br>Chair: SVP strategy & sustainability<br>Focuses on sustainability plans and progress.<br>| **Production & operations sustainability table** <br>Chair: SVP HSE & carbon, P&O<br>Focuses on the delivery of lower carbon plans in P&O <br>– particularly in relation to net zero aims.<br>|
| **Cross-bp forums and meetings** | **Cross-bp forums and meetings** |
| **Meetings and forums to allow cross-group discussions, integration and implementation.** | **Meetings and forums to allow cross-group discussions, integration and implementation.** |

---

**Risk Management**

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-SMALL-TopRoundCornerV2.gif](bp-20251231_g61.gif) |  | ![WarmGrey2-50-SMALL-TopRoundCornerV2.gif](bp-20251231_g61.gif) |
|  | **TCFD Recommendation:**<br>Disclose how the organization identifies, <br>assesses and manages climate-related risks.<br>|  |
| ![WarmGrey2-50-SMALL-BottomRoundCornerV2.gif](bp-20251231_g62.gif) |  | ![WarmGrey2-50-SMALL-BottomRoundCorner.gif](bp-20251231_g63.gif) |

---

![](bp-20251231_g66.gif)

**Recommended Disclosure:**<br>a. Describe the organization's processes for <br>identifying and assessing climate-related risks.<br>

bp's risk management system and policy,

described on page <u>[60](#i0dd2ee81aac04f8c9c97c86197f0c6df_106)</u>, are designed to address

all types of risks including our principal risks

and uncertainties, described on page <u>[62](#i2c22b8305ec34b5b8e60614e24ee2d2d_30015)</u>.

As part of this system, our businesses and

functions are responsible for identifying,

assessing, managing and monitoring

risks associated with their business or

functional area.

The process for identifying risks is outlined on

page <u>[61](#i66ba511fa7d84f48831e48e9b68edd3e_19833)</u> and guidance to support consistency

has been made available to our businesses to

provide them with a climate-related taxonomy,

which they are able to use as they see fit in

their identification and assessment of risk.

Where risks – including climate-related risks –

are identified, businesses and functions are

required to assess them, in line with our risk

management policy. This includes an impact

and likelihood assessment which supports the

consideration of relative significance and

prioritization of risk management activities.

The impact criteria outlined on page <u>63</u> include

health and safety, environmental, financial and

non-financial (such as regulatory impact)

criteria and are used for assessing risks,

including climate-related risks. This provides a

consistent basis for assessment across bp.

For the purposes of our TCFD disclosures, we

use the TCFD's distinction between 'physical'

and 'transition' climate-related risks.

**Identification, assessment and** 

**management of climate-related** 

**opportunities**<sup>a</sup>

As set out in our TCFD Strategy a and b

disclosures on page <u>[46](#i0dd2ee81aac04f8c9c97c86197f0c6df_97)</u>, we have identified

potentially material climate-related

opportunities and our strategy has been

informed by these. We identify climate-related

opportunities by considering a range of

information sources, including the bp Energy

Outlook*,* which helps to inform our thinking

about how the energy system might evolve.

Business opportunities continue to be

originated across bp, and taken forward

through bp's investment governance

framework. For example, our gas & low carbon

energy and customers & products businesses

support the delivery of low carbon and

transition opportunities through organic and

inorganic growth.

Our investment governance framework (see

page <u>[21](#i3021f407d0ca49208d2bbf6f9f773c48_5170)</u>) provides the mechanism by which

alignment of these opportunities with our

strategy is assessed and decisions on which

to progress are made.

aInformation added to satisfy the UK CFD Regulations.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 45 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

![](bp-20251231_g67.gif)

**Recommended Disclosure:**<br>b. Describe the organization's processes for <br>managing climate-related risks.<br>c. Describe how processes for identifying, <br>assessing and managing climate-related risks <br>are integrated into the organization's overall <br>Risk Management.<br>

**Risk Management process**

Risks which may be identified include

potential effects on operations at asset

level, performance at business level and

developments at regional level from

extreme weather or the transition to a

lower carbon economy.

As part of our annual process the bp

leadership team and board review the group's

principal risks and uncertainties. Climate

change and the transition to a lower carbon

economy continues to be identified as a

principal risk, see page <u>[64](#i2c22b8305ec34b5b8e60614e24ee2d2d_30018)</u>. It covers various

aspects of how risks associated with the

energy transition could manifest. Physical risks

such as extreme weather, which may be

affected or intensified by climate change, are

covered in our principal risks related to safety

and operations.

**Physical risk**

Physical risks are typically identified at the

asset or project level and managed depending

on the level of risk assessed.

In the North Sea and Gulf of America, regions

more prone to severe weather conditions, our

offshore facilities monitor meteorological and

oceanographic conditions through the

collection of measurements. This data is

collated and periodically compared against

the 'Basis of Design' for the facility. If

significant differences are observed, then this

may trigger an update to the 'Basis of Design',

prompting action to reassess risks such as

structural integrity and station-keeping and if

necessary, implement additional risk

mitigations, for example updating procedures

for shutting down and removing personnel

from facilities ahead of severe weather events.

Updates may also be made as a result of other

new knowledge, analysis methods and data,

including climate projections where

appropriate.

Our major projects★ are required to assess the

potential impact of severe weather and

projected climate-related physical impacts.

Where relevant, potential changes in

environmental conditions, such as sea level

rise and ambient temperatures, over the

expected lifetime of a project are to be

considered as part of the design process.

Building on a modelling exercise conducted

in 2022, a screening approach to support

identification of potential severe weather and

physical climate-related hazards at operational

sites across bp has been rolled out since 2024

as part of our operational management

system. Since 2024 screening has been

conducted for a number of sites each year.

Where potential hazards are identified, and as

appropriate, this enables further work to be

carried out to assess potential risks and

implement appropriate

management measures.

For other assets, such as our retail sites★, that

are typically not exposed to a comparable

level of severe weather risk, climate-related

risks such as flooding or wind damage may be

managed where appropriate through the

emergency response plans and business

continuity plans which are mandated through

bp-wide policies.

Additionally, at a group level we recognize risk

associated with the potential for increased

water stress due to climate change and other

factors and the impact this could have on our

operations and in the catchments where we

operate. In order to understand the water-

related challenges that we face, we review our

water impacts, risks and opportunities at our

major operating sites. These reviews consider

the quantity and quality of water used as well

as any regulatory requirements. We anticipate

adopting site-level activities as part of our aim

to reduce our net freshwater use in stressed

catchments where we operate. We anticipate

adopting a focused freshwater management

approach, addressing water-related business

risk where it is greatest, and we anticipate that

our freshwater withdrawal in stressed

catchments will be covered by freshwater

management plans by 2028. For more about

water, see page <u>[59](#i87f52fc5efef4a16865a4af06e1e7987_26443)</u>.

**Transition risk**

The board appraises bp's strategy and

monitors bp's management and operations to

obtain assurance over the delivery of its

strategy. This approach enables the effective

management of climate-related transition

risks and opportunities facing bp associated

with the energy transition. For the purposes of

our TCFD disclosures, we group transition risks

identified by our businesses and functions into

the three broad material climate-related

transition risks to bp, see page <u>[52](#idfd02045cd904558886b64b741d9bf83_2-1-1-5-781302)</u>. However,

we continue to assess and manage the

component parts of those broad transition

risks, including:

Policy and legal risks

Our strategy and sustainability team leads the

definition of policy positions in line with bp's

strategy and bp's sustainability aims.

They work with our regional organizations as

well as corporate entities to discuss regional

and global policy trends and support external

positioning and interactions relating to policy

and advocacy topics.

Our group operational risk committee

(sustainability) provides oversight of

sustainability matters and our issues and

advocacy meeting covers emerging

advocacy issues.

Our legal team manages bp's litigation,

including climate-related litigation, and

advises on the management of associated

risks. This includes the use of internal lawyers

and, where appropriate, external counsel.

Market risks

In developing our business strategies, we

consider market risks, controls and

mitigations, including future demand in the

different geographies in which we might

operate, the competitive landscape and the

potential value proposition. We manage these

risks through our investment decisions, our

hedging and optimization activity, and through

key business processes, including the group

investment assurance and approval process.

Reputational risks

Our investor relations, communications and

external affairs teams work to mitigate

reputation-related risks, which include the risk

of shareholder action. Our investor relations

team co-ordinates engagement with key

investors on both a bilateral basis and through

investor initiatives to support understanding

of bp's strategy and gain insights to inform

feedback they provide to the group.

Our communications and external affairs

teams help to manage corporate reputation

through identification and monitoring of key

issues and both proactive and reactive

engagement with relevant stakeholder groups.

The teams also advocate for policies that

support our strategy and sustainability aims,

see page <u>[38](#ia533d1b86ea04772b2fd02ae3d1c8da0_9651)</u>.

Technology risks

Our technology team works to both mitigate

risks and identify opportunities associated

with evolving and emerging technologies that

play a role in the changing global energy

system. The team generates technology

reports for review by bp senior leaders and the

recommendations are overseen by the

relevant leadership teams, through the

Innovation Advisory Council. In appropriate

cases this helps to underpin and appraise the

business case for new investments, new

partnerships and new technology tools/

methods where these are being driven by

technology innovation.

---

| | | |
|:---|:---|:---|
| 46 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Climate-related financial disclosures** continued<br>

**Strategy** 

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-SMALL-TopRoundCornerV2.gif](bp-20251231_g61.gif) |  | ![WarmGrey2-50-SMALL-TopRoundCornerV2.gif](bp-20251231_g61.gif) |
|  | **TCFD Recommendation:**<br>Disclose the actual and potential impacts of <br>climate-related risks and opportunities on the <br>organization's business, strategy and financial <br>planning where such information is material.<br>|  |
| ![WarmGrey2-50-SMALL-BottomRoundCornerV2.gif](bp-20251231_g62.gif) |  | ![WarmGrey2-50-SMALL-BottomRoundCorner.gif](bp-20251231_g63.gif) |

---

![](bp-20251231_g68.gif)

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

In setting and monitoring delivery of bp's

strategy, the board and leadership team

consider climate-related risks and

opportunities across the:

**•Short term** (to 2026): aligning with our near-

term business and financial planning

timeframe.

**•Medium term** (to 2030): aligning with our

group business outlook timeframe, and

enabling us to think beyond our short-term

targets and adjust course if appropriate.

**•Long term** (to 2050): using scenarios to help

explore the wide range of uncertainties

surrounding the energy transition over the

next 25 years. For more detail on our

approach, see page <u>[7](#i2d9917956e054227bf45d4fb2848bf6e_4072)</u>.

TCFD categorizes climate-related transition

risk and opportunity as follows: policy and

legal, market, reputation and technology. It

also refers to climate-related acute and

chronic physical risks and opportunities. Risks

in each of these categories have been

identified using a risk management process

that our businesses and functions are required

to follow. For more about how the relative

significance of identified risks is evaluated, see

Risk Management on page <u>[44](#i0dd2ee81aac04f8c9c97c86197f0c6df_94)</u>.

The risks and opportunities identified have

been considered in relation to bp's reset

strategy, as announced in February 2025.

**Climate-related transition risks** 

**and opportunities**

At a group level, we have identified three

broad, material climate-related transition risks,

outlined on page <u>[52](#idfd02045cd904558886b64b741d9bf83_2-1-1-5-781302)</u>, 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<sup>a</sup>. We also see significant potential

for upside – or opportunity – associated with

some of these risks. These are discussed

under each risk on page <u>[52](#idfd02045cd904558886b64b741d9bf83_2-1-1-5-781302)</u> and in relation to

Recommended Disclosure (b) we also describe

the potential impacts of both the risks and

opportunities to bp.

**Climate-related physical risks**

The physical risks identified primarily relate to

severe weather and often represent potential

for increased drivers for safety and operational

risks to our operations, particularly process

safety, personal safety, and environmental

risks, see Risk factors page <u>[62](#i0dd2ee81aac04f8c9c97c86197f0c6df_6396)</u>. In addition, we

have identified the potential for changes in the

availability of freshwater, including as a result

of climate change, as a risk to some of our

operations. Higher instances of extreme

weather also have the potential to impact

supply chains and critical infrastructure, such

as air and sea ports, as well as our customers.

We recognize that we could also face other

forms of physical climate-related risk over the

longer term, for example associated with

changes in sea level, extreme temperatures

and flooding, which could impact our

operations. As these risks are primarily

operational, and location-specific, they are not

grouped in the same way as transition risks.

Like other businesses around the world, in the

longer term we could face adverse market or

value chain conditions associated with large-

scale cumulative impacts of physical climate

change if global mitigation and adaptation

efforts are insufficient or unsuccessful.

Offshore facilities

In the case of our offshore facilities, climate

change could create greater uncertainty

around frequency and/or intensity of severe

weather events, such as extreme waves, loop

currents, and storms, particularly in the

medium to long term. These factors could

affect the future risk profile of an asset over

its lifetime, and could also impact production

or costs.

Water resources

Water resources are increasingly under

pressure from various factors, including

climate change, and this poses a potential risk

to some of our operations that depend on the

availability of freshwater. Based on analysis

using the World Resources Institute (WRI)

Aqueduct Global Water Risk Atlas, and in

certain cases review of site-specific local data

sources, six of our 16 major operating sites in

2025 were located in regions with high to

extremely high water stress. Using WRI data,

we have identified the potential for this risk to

increase in the medium term. For more on

water consumption, see page <u>[59](#i87f52fc5efef4a16865a4af06e1e7987_26443)</u>.

We do not currently foresee any material

opportunities arising from changes in the

physical environment as a result of climate

change. However, the actions we are taking to

make our operations more resilient, for

example through improving efficiency of our

freshwater use, may also bring about benefits

such as reduced costs.

aUnderlying risks are specific, for example, local or business-specific risks identified by specific bp entities through the risk processes described above under Risk Management.

bThis is not intended to be an exhaustive list of our plans for the transition, but rather illustrative of some of the core elements of our plans.

![](bp-20251231_g69.gif)

**Recommended Disclosure:**<br>b. Describe the impact of climate-related risks <br>and opportunities on the organization's <br>businesses, strategy, and financial planning.<br>

---

| |
|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
| **bp's plans for the** <br>**energy transition**<br>In this section we talk about some of <br>our plans for the transition across <br>bp's business areas and where we <br>do so we have identified these with <br>TP<sup>b</sup>. We describe below how we <br>believe our strategy and net zero <br>ambition are both good for business <br>and support society's drive towards <br>the Paris goals.<br>Throughout the strategic report we <br>set out bp's strategy and plans for <br>the energy transition. This includes <br>our progress against 2025 <br>performance, see page <u>[21](#i0dd2ee81aac04f8c9c97c86197f0c6df_55)</u>.<br>Our progress against our net zero <br>aims are described on pages <u>[37](#ia533d1b86ea04772b2fd02ae3d1c8da0_9653)</u><u>-</u><u>[38](#ia533d1b86ea04772b2fd02ae3d1c8da0_9651)</u>.<br>|
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

**TP** 

Our strategy, business and financial plans are

informed by a range of inputs including the

climate-related risks and opportunities

associated with the energy transition outlined

above. We describe how we use scenarios to

inform our strategy on page <u>[7](#i2d9917956e054227bf45d4fb2848bf6e_4072)</u>.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 47 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

**Climate-related transition risks and opportunities**

---

| | |
|:---|:---|
| **1** |  |
| **The value of our hydrocarbon business could** <br>**be impacted by climate change and the** <br>**energy transition.**<br>| **Changes in policy, legislation, consumer preferences or markets as a result of growing concerns about** <br>**climate change and the energy transition could reduce demand for fossil fuels or lower their price relative to** <br>**our financial planning assumptions, particularly in the medium to long term, negatively impacting returns** <br>**from or the value of our hydrocarbon businesses. Changes in regulations, including carbon pricing and fossil** <br>**fuel policies, could also impact compliance and operating costs in our oil and natural gas production and** <br>**refining businesses.**<br>Alternatively, prices (such as Brent oil and Henry Hub natural gas) during the next decade could be higher than <br>our financial planning assumptions under certain transition pathways, including those aligned with the Paris <br>Agreement. This could strengthen returns from our hydrocarbon businesses (including securing higher <br>proceeds from assets we choose to divest) which may enable us to deliver enhanced shareholder value, <br>further strengthen our balance sheet and grow investment in the transition, in line with our financial frame.<br>|
| **2** |  |
| **Our ability to grow or deliver expected returns from** <br>**our transition businesses**★ **could be impacted by** <br>**the energy transition.**<br>| **Several factors could restrict the growth of our transition businesses**★ **or returns from them. These factors** <br>**include: lack of, or insufficient development and application of, policies, regulations and frameworks that** <br>**support low carbon businesses; insufficient consumer demand for our low carbon offering; strong** <br>**competition in the market; or the insufficiently rapid development of supporting technologies and** <br>**infrastructure or constraints on supply chains for low carbon energies. This could particularly impact bp** <br>**in the short to medium term as new markets and technologies develop but could also represent a longer-**<br>**term risk.**<br>Alternatively, demand, policy support or enabling technology and supply chain growth for renewables <br>could support a more rapid portfolio shift with expansion of our low carbon businesses and higher returns <br>from them.<br>Some low carbon businesses, including renewable power, bioenergy and emerging technologies such as <br>hydrogen and carbon capture and storage (CCS), rely on policy support to promote growth. We support well-<br>designed, robust public policy that enables this. <br>Changes in customer preferences, pace of technology and infrastructure development and deployment and <br>costs could impact the markets for low carbon products and services. For example, the pace of adoption of <br>electric vehicles (EV) could impact utilization rates, and consequently returns, from our EV charging networks. <br>We recognize that the pace of our transition relative to our core low carbon target sectors and regions is <br>important. If we move more slowly than those markets, we may miss investment opportunities and customers <br>may prefer different suppliers with potential negative consequences to demand for our products and to our <br>reputation. If we move faster than these markets, we risk investing in technologies or low carbon products <br>that are unsuccessful because there is insufficient demand for them. However, our investment may also help <br>to stimulate demand and provide us with a leading position in growth markets.<br>|
| **3** |  |
| **Our ability to implement our strategy could be** <br>**impacted by changing stakeholder attitudes** <br>**towards the energy sector, climate change and** <br>**the energy transition.**<br>| **Negative perceptions of the energy sector, or bp, could have a number of consequences, for example:** <br>**adverse litigation; reputational impacts, including our ability to attract and retain talent; and shareholder** <br>**action. These consequences could affect us in the short, medium or long term.** <br>Alternatively, increased support from our stakeholders could enable access to additional capital and new <br>investors, strengthening our ability to deliver our strategy and enabling faster growth of our low carbon <br>businesses. <br>The world is in an 'energy addition' phase of the energy transition in which it is consuming increasing amounts <br>of both low carbon energy and fossil fuels. The *bp Energy Outlook 2025* highlights that, although the structure <br>of energy demand will likely change over the long term, with the importance of fossil fuels declining, replaced <br>by a growing share of low carbon energy, led by wind and solar power, oil and natural gas continue to play a <br>significant role in the global energy system for at least the next 10-15 years. This requires continuing <br>investment in upstream oil and natural gas. <br>The insights from the *bp Energy Outlook 2025* support our view that investment into oil and gas will be <br>needed for decades to come and also that, while the pace and shape of the transition in the long run is <br>uncertain, we continue to see the energy transition as a significant opportunity to grow value. <br>Perceived inconsistencies between the pace of bp's transition and societal expectations could have <br>reputational and commercial impacts that might impair our ability to deliver our strategy. However, we also <br>see potential to positively differentiate bp, by delivering against our strategy, net zero ambition and <br>sustainability aims.<br>|

---

---

| | | |
|:---|:---|:---|
| 48 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Climate-related financial disclosures** continued<br>

**Oil and gas**

In February 2025 we announced an increase in

upstream investment versus our prior

guidance. This additional investment allows us

to strengthen the portfolio, for example we are

building our US portfolio to around 1 million

boe/d by 2030, increasing production in our

US onshore business and developing our Gulf

of America Paleogene resource. In the Middle

East we are now partnered in the

redevelopment of several giant oilfields in

Kirkuk, page <u>[31](#i77676f5f94e94867b962146ac9a379f0_1-1-1-1-939835)</u>, alongside our existing position

in Rumaila, Iraq. These examples, alongside

other investment in our existing portfolio,

additional access and exploration underpin

expected growth in underlying production to

2.3-2.5mmboe/d in 2030, excluding future

potential divestments.

We recognize that the transition presents

uncertainty for our upstream business,

including the possibility of lower oil and gas

prices. In recent years we have maintained top

quartile unit production cost at around $6 per

barrel, made strong progress on operational

reliability and commerciality across our

portfolio, and we retain optionality to divest

lower margin barrels. We intend to maintain

the disciplined application of our balanced

investment criteria, which include the

consideration of applicable economic hurdle

rates and operational emissions intensity

levels, from a portfolio across oil and gas.

Read more about our investment process on

page <u>[20](#i0dd2ee81aac04f8c9c97c86197f0c6df_52)</u>.

As an outcome of our strategy and informed

by our current outlook, and its underlying

assumptions, which may change over time,

we are aiming for the Scope 1 and 2 emissions

from our operations – the majority of which

are associated with the operating assets in our

hydrocarbons portfolio (refining and upstream

oil and gas combined) – to be 45-50% lower at

the end of 2030 than in 2019 and we plan to

maintain 'near zero' methane intensity★

across our operated producing assets, see

pages <u>[37](#i0dd2ee81aac04f8c9c97c86197f0c6df_82)</u><u>-</u><u>[38](#ia533d1b86ea04772b2fd02ae3d1c8da0_9654)</u>.

<sup>TP</sup> **Customers and products** 

As announced in February 2025, we are

focusing the downstream – our customers &

products business – reshaping the portfolio to

focus on markets and businesses where we

have advantaged and integrated positions.

We recognize the risk of a decline in demand

for conventional vehicle fuels and products

due to the energy transition and are working to

increase the efficiency and resilience of our

existing fuels and lubricants businesses

through operating cost reductions and margin

optimization. In December 2025, we

announced an agreement to divest a 65%

shareholding in *Castrol*, strengthening our

balance sheet while retaining exposure to

future growth and optionality. We are also

increasing the resilience of our existing fuels

network and high-grading our regional

footprint. Since 2020 we have exited our

Switzerland, Turkey and Netherlands mobility

and convenience businesses, and in the past

year have announced our exit from our

mobility businesses in Austria. We are

reallocating capital into our most advantaged

positions such as major transit routes in key

markets where we see sustained demand for

fuels and EV growth, e.g. EV charging

investments on our sites near the German

Autobahn road network.

Our integrated mobility model across fuels

(hydrocarbons and biofuels), convenience and

EV charging provides resilience to the pace of

transition by allowing us to flex our offer to

meet customer demand.

In aviation, we will make selected high-return

investments to build our footprint; and see

strong growth potential in sustainable aviation

fuel through the transition.

Our biofuels business is already playing a key

role in building resilience to the energy

transition – helping to decarbonize the

mobility value chain using existing

infrastructure. In Q4 2024 we took full

ownership of bp bioenergy in Brazil, accessing

around 50kb/d of production and see

potential for future growth with support from

policy and market conditions. Our feedstock

positions also provide opportunity to

additional resilience to anticipated supply

shortages in the transition. In Q1 2026 we

launched Etlas, a joint venture with Corteva,

continuing our momentum in feedstocks with

the aim to produce one million metric tonnes

of feedstock per year by the mid-2030s (see

page <u>[35](#i80dcc41ba7e94abeb6689385129c3e79_1-1-1-1-936338)</u>).

At our refineries, the energy transition could

impact demand for certain products in the

future and raise costs. We expect the impacts

to be region- and asset-specific and are

difficult to fully anticipate, Consequently,

we are continuing to drive greater

competitiveness and value from our refineries,

aiming for 96% or above Solomon refining

availability. We are also repositioning our

refining portfolio and building resilience

through value chain integration, co-production

of biofuels alongside traditional products and

selective decarbonization initiatives.

<sup>TP</sup> **Low carbon energy**

Ongoing volatility and uncertainty continues to

impact low carbon energy businesses globally,

underlining the need to be aligned with and

flexible to market and policy development. As

announced in February 2025, we are changing

our model for low carbon – delivering with

partners and with external financing that will

be capital-light for bp and help improve our

equity returns.

In offshore wind, we established the JERA Nex

bp joint venture in Q3 2025. Recognizing the

exposure to transition volatility seen in recent

years, JERA Nex bp plans to focus on highly

disciplined, capital efficient growth, with bp

retaining an option to our equity share of

power offtake.

In solar, Lightsource bp continues to be a

leading global onshore renewable developer

in markets with attractive sector returns.

In our hydrogen and CCS businesses, we are

prioritizing fewer, higher value projects in the

near term while building capability and future

optionality to scale and grow as the market

develops. By focusing on projects in

jurisdictions where we have an adequate

regulatory framework, access to the value

chain including our own or customer demand

and leveraging access to advantaged carbon

capture and renewable power, we aim, over

time, to decarbonize our operations and help

our customers decarbonize. We sanctioned

four projects, for example, Lingen, Germany

in 2024 which is in line with our focus on

decarbonizing bp operations.

Through Archaea Energy, we believe we are

uniquely positioned in the US to meet growing

demand for renewable natural gas★ as the

transition progresses. We are building

resilience by improving capital efficiency and

reducing operating costs and continue to

assess and develop new routes to market

and customer solutions to create future

optionality.

<sup>TP</sup> **Supply, trading & shipping (ST&S)**

Our ST&S business provides risk management,

flow and optimization services for our bp

equity and assets and third-party customers,

with a proven track record of resilience to

commodity cycles and the ability to capture

upside when market conditions present

opportunities.

The diversification of our traditional oil

business helps mitigate the risk of falling

demand in the US and Europe by providing

access to growing demand centres such as

Latin America and Sub-Saharan Africa and in

growth markets such as petrochemicals,

biofuels and adjacent agricultural

commodities.

Our gas and power business spans regional

and global markets. Our LNG portfolio offers

exposure to a lower carbon growth market

combined with flexibility through our

advantaged key global positions. Additionally,

with the acquisition of BP Energy Retail in the

US and GETEC in Europe, ST&S is building

resilience by participating further down the

value chain towards end consumers. Our

power trading business allows us to optimize

across the value chain from generation to

wholesale markets to customers. This helps

position us for further electrification of the

energy system as well as further

decarbonization of electricity.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 49 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

**Impact on technology**

We are investing in digital and technology

solutions that can help to generate value for

bp, manage risk and help accelerate the

transition through focused scale-up and

innovation. This investment includes targeted

focus on research and development where bp

is and can be differentiated and growing

partnerships to increase leverage. We expect

our research and development spend to be

increasingly focused on technologies with the

potential to help identify and access new oil

and gas opportunities at lower cost, reduce

GHG emissions and enable our transition

businesses★. See page <u>[9](#i0dd2ee81aac04f8c9c97c86197f0c6df_5051)</u> for examples of

technology investments in 2025.

We recognize the potential for disruptive

technologies to impact our strategy. Alongside

our research and development investments,

our bp ventures portfolio also includes

investments in emerging technologies and

business models that can help support our

businesses and deliver our strategy.

**Physical risk**

The potential impacts of the types of physical

risks we have identified could include reduced

production, throughput or sales – for example

as a result of damage to facilities or supply

chain disruption – or in a most extreme case

loss of life or an asset. Due to uncertainties

associated with the impact of climate change

on severe weather events in the future, it is

difficult to quantify the potential impacts

associated with any increase in these risks as a

result of climate change.

Having considered both geographic factors

and the ability of climate models to adequately

represent future trends in physical climate

parameters, we seek to take the uncertainties

concerning climate-related physical risk into

account in our approach to design and

operating criteria for existing assets and new

major projects★. Where appropriate, we have

updated our metocean design criteria to

include consideration of both forward-looking

and historical models, including climate and

synthetic models, in an attempt to mitigate

both models and extrapolation uncertainty.

The particular models chosen will depend in

part on geographic location. See Risk

Management, page <u>[44](#i0dd2ee81aac04f8c9c97c86197f0c6df_94)</u>, for how we manage

these uncertainties.

As a step in seeking to improve the resilience

of our operations to the physical changes that

might result from climate change that we have

described above, we have continued to

undertake screening of present-day and future

potential physical risk exposure for selected

key assets and identified those sites with

potential for heightened exposure to physical

risks in order to prioritize these for further site-

based assessment.

Recognizing the potential impact of climate

change and other factors on water resources,

as part of our water aim, we are taking steps to

be more efficient in operational freshwater use

(read more about water use on page <u>[59](#i87f52fc5efef4a16865a4af06e1e7987_26443)</u>).

**Impacts on our financial planning** 

**Capital allocation:** We plan to invest sufficient

capital to execute our strategy, enabling us to

mitigate the risks and capture the

opportunities we have identified. As part of our

annual planning processes, we assess the

distribution of capital across our business

areas, including consideration of market

evolution. In February 2026 we announced

that we expect capital expenditure★ to be

$13.0-13.5 billion in 2026. To help maintain

resilience to the pace of transition and access

opportunities, we will continue to flex capital

as policies, technologies and markets evolve.

**Access to capital:** While there is potential for

concerns about the energy transition to

impact banks' or debt investors' appetite to

finance hydrocarbon activity, we do not

anticipate any material change to funding in

the short to medium term. We are committed

to strengthening the balance sheet and

continue to target improving credit metrics

within an 'A' grade credit range. We reiterate

our primary target for net debt of $14-18 billion

by the end of 2027. Net debt decreased from

$23.0 billion to $22.2 billion during 2025.

Since the end of 2019 we have repurchased

around $26 billion of short-dated existing

bonds and issued over $12 billion of new bonds

with a duration of 20 years or longer, doubling

the duration of our debt book.

We provide further information on financial

frame elements related to capital expenditure,

balance sheet management and buybacks on

page <u>[18](#i0dd2ee81aac04f8c9c97c86197f0c6df_46)</u>.

We provide more detail on financial risk

factors, including liquidity risk in Financial

statements – Note 29.

**Investment criteria:** Investments are evaluated

against a balanced set of six investment

criteria, including sustainability (see page <u>[22](#i2249540127db4d059a13c9b841c3712c_11131)</u>).

The assessment of economics includes a set

of price assumptions that reflect our view of

market evolution (for our key investment

appraisal price assumptions, see page <u>[20](#iaa9f5ec2f5544670b4a71dc5d5bce3a9_0-0-1-5-725324)</u>). In

addition, the investment economics for all

investment cases where bp's share of annual

greenhouse gas (GHG) emissions from

operations are anticipated to exceed specific

thresholds include a carbon price for those

emissions, which rises from $67/tCO2e

in 2026 to $135/tCO2e (2024 $ real) in 2030.

**Impacts on financial performance** 

**and position**

Assessing the impact of climate change and

the energy transition requires the use of a

number of judgements and estimates.

We have set out the significant accounting

policies, judgements and estimates used in

assessing the impact of climate change in

Financial statements – Note 1.

This includes information on pricing, useful

economic lives, timing of implementation of

policies or decommissioning provisions, and

assumptions related to how each might

change over time and how such assumptions

may impact our currently reported assets

and liabilities.

Our price assumptions, including those set out

on page <u>[20](#iaa9f5ec2f5544670b4a71dc5d5bce3a9_0-0-1-5-725324)</u>, reflect a range of future possible

scenarios and take account of the potential

impact of climate-related risks and

opportunities as well as current economic and

geopolitical factors. Consequently,

impairment losses and impairment reversals

consider inputs that arise from climate change

and the energy transition. It is not possible to

quantify separately the impact of these

different inputs on our impairments. However,

in conducting our impairment sensitivity tests,

that in part reflect transition downside risk, we

consider reductions in revenue that, if driven

by price alone, would be consistent with prices

within the range covered by the 1.5°C scenario

family within the Transition Scenario

Catalogue★ data sets used for TCFD resilience

testing below.

Financial statements – Note 1 provides

information on impairment assumptions and

sensitivities. Note 4 provides information on

gains and losses on disposal or closure of

business and operations, and impairments and

impairment reversals, and Note 8 provides

information on impairment losses relating to

exploration for and evaluation of oil and

natural gas resources. See Financial

statements – Note 1, Note 4 and Note 8 for

more information.

a Potential proceeds from any transactions related to *Castrol* strategic review and announcement to bring a strategic partner into Lightsource bp will be allocated to reduce net debt.

![](bp-20251231_g70.gif)

**Recommended Disclosure:**<br>c. Describe the resilience of the organization's <br>strategy, taking into consideration different <br>climate-related scenarios, including a 2°C or <br>lower scenario.<br>

We believe our strategy positions bp for

success and resilience in a Paris-consistent

world – a world that is progressing on one of

the many global trajectories considered to be

Paris-consistent, and ultimately meets the

Paris goals, see pages <u>[10](#i0dd2ee81aac04f8c9c97c86197f0c6df_34)</u><u>-</u><u>[11](#i4d89c132c5af47358ba22de9e159aee6_8200)</u>.

As in 2024, to help test our view of this, we

have assessed the resilience of our strategy to

different climate-related scenarios, including

1.5°C consistent scenarios.

---

| | | |
|:---|:---|:---|
| 50 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Climate-related financial disclosures** continued<br>

We did this in three steps:

1. First, we evaluated all business areas in our

portfolio by i) quantitatively assessing their

financial significance, in the context of bp's

total financial outlook, to understand the

potential scale of financial/strategic impact

that could be put at risk if exposed to

transition uncertainty, including 1.5°C; and ii)

considering whether there is a key variable

– such as price or demand – which would

represent a transition driver of such risk.

2. Second, we quantitatively assessed the

impact, to each business area, of potential

transition exposure scenarios in 2030 – the

point in our planning horizon at which there

is widest transition uncertainty.

–For each of those business areas with

both sufficient scale and for which a

specific transition risk driver was

identified – which collectively represent

over 70% of our 2030 adjusted EBITDA★

outlook – we performed a scenario

analysis focused on that transition risk

driver, across a range of transition

pathways<sup>a</sup>, including 1.5°C, as set out

below and in our methodology summary

on page <u>[52](#idfd02045cd904558886b64b741d9bf83_2-1-1-5-781302)</u>.

–For each of the remaining business

areas we performed a simplified

quantitative scenario analysis, by testing

the financial impact of a scenario in

which each business area's expected

2030 adjusted EBITDA is assumed to be

reduced to zero – an outcome at least as

detrimental to that business area's

adjusted EBITDA as could reasonably be

expected to result from business-as-

usual (BAU), well-below-2°C and 1.5°C

transition pathways.

–In this way, all business areas were

quantitatively tested to downside

impacts at, or beyond, a range of

transition scenarios.

3. Finally, on the basis of the results of steps 1

and 2, we identified those business areas

for which the possible consequences of the

downside scenario(s) were sufficiently

significant to potentially jeopardize group

strategic resilience – as in prior years, the

only business areas for which this was

found to be the case were oil and gas

production with respect to their exposure

to oil price. For these business areas we

assessed the potential implications for bp's

strategic resilience (as defined below) over

the period from 2027 to 2030.

To undertake steps 2 and 3, we identified

financial criteria which can be modelled as

proxies for strategic resilience – choosing to

do this through three lenses consistent with

our financial frame (as set out on page <u>[18](#i0dd2ee81aac04f8c9c97c86197f0c6df_46)</u>),

being our ability to deliver:

i.a resilient dividend;

ii.a stronger balance sheet that continues to

target improving our credit metrics within

the 'A' grade range; and

iii.disciplined investment allocation.

This is not intended to represent a 'definition'

of resilience beyond the purposes of this

exercise, and a core assumption of this

analysis is necessarily that, aside from any

implications of the scenarios being tested,

including potential mitigations (such as capital

or cost management) that we might naturally

expect to take in response, bp will deliver the

assumed underlying strategic and financial

priorities out to 2030.

To undertake the modelling in steps 2 and 3,

we used a suite of external scenarios from

various providers (for example, IEA's World

Energy Outlook (WEO 2024) Net Zero

Emissions by 2050 (NZE) scenario.

This suite of scenarios took as its start point

the latest WBCSD (World Business Council for

Sustainable Development) Scenario Catalogue

(V3, published in May 2024), which we then

updated for relevant metrics where underlying

source data providers (IEA, NGFS, UN PRI IPR)

have published more recent (or withdrawn

older) transition scenarios. We refer to this as

our Transition Scenario Catalogue★, with more

detail on its preparation provided on page <u>[53](#i37f5f0f2ee4e45afa2448273fb7b6bb9_1-0-1-6-781302)</u>.

When considering the long term (post-2030 to

2050), attention is drawn to the sensitivity

analysis conducted as part of our value-in-use

impairment testing for oil and gas assets,

outlined in Financial statements – Note 1. While

not intended to extend the strategic resilience

test as outlined above to the long term, it

provides an indication of how we monitor

potential longer-term financial impact to

revenue downside which, if resultant from

reductions in price in isolation, may be

associated with prices towards the bottom of

the range of trajectories in the Transition

Scenario Catalogue.

Our approach, described in more detail on

page <u>[52](#idfd02045cd904558886b64b741d9bf83_2-1-1-5-781302)</u>, is directly applicable to transition

risks #1 and #2 – as well as their associated

opportunities – as these lend themselves to a

financially quantified scenario-based analysis.

The approach does not directly address

transition risk #3 – however, we believe that

some of the potential drivers for transition risk

#3, namely policy and societal trends, may be

implicit in these scenarios, and we believe that

the successful execution of our strategy will,

over time, help to mitigate this risk to bp as

well as positioning us to take advantage of the

potential associated opportunities. This

scenario analysis exercise also does not

directly address climate-related physical risk,

our strategic resilience to which is further

discussed below.

**Key insights from our scenario analysis** 

**and resilience test**

While the results of any such analysis must be

treated with caution (being necessarily

dependent on numerous assumptions and

methodological choices, and having its own

limitations) overall this analysis and resilience

test reinforced our confidence in the

continued resilience of our strategy to a wide

range of transition scenarios, including those

consistent with limiting temperature rise

to 1.5°C.

In summary, the modelling indicated once

again that oil prices consistent with a 1.5°C

transition scenario remain our greatest

transition exposure to 2030, but that

nonetheless bp remains resilient to the lowest

oil price scenarios tested.

In undertaking this analysis we observed:

• There is considerable uncertainty across,

and often within, each Transition Scenario

Catalogue family in the pace and nature of

the transition to 2030 – and therefore

considerable range of potential financial

impact across some of the variables

selected for the analysis, reflecting the

complexity and interdependencies of the

energy transition (see table on page <u>[53](#i37f5f0f2ee4e45afa2448273fb7b6bb9_1-0-1-6-781302)</u>).

Generally, we observed that the faster the

pace of transition, the greater the

uncertainty in the exact shape of the

resulting energy system in 2030.

• Oil price<sup>b</sup> is likely to remain the main source

of climate-related transition uncertainty for

our strategy through to 2030, reflecting

both the wide range of potential pathways

and the expected contribution to our total

adjusted EBITDA★ over this period, that oil-

price-linked businesses represent<sup>c</sup>.

• In the 1.5°C family, the potential downside in

2030 suggested by the lowest oil prices in

the Catalogue (the IEA WEO 2024 Net Zero

Emissions by 2050 (NZE) scenario) is

around 23% of group adjusted EBITDA in

2030. Scenarios from other scenario

families and providers (e.g. NGFS) indicated

higher prices in this time period.

aAlthough such scenarios do not and cannot represent all possible futures, we value them as a simplified and schematic way to consider the potential implications of, and uncertainty inherent

within, a range of possible energy transition pathways to a future bp portfolio mix.

bOur multi-year (2027-30) oil price resilience test considered 2030 low oil prices consistent with the most extreme scenario in the Transition Scenario Catalogue – the IEA WEO 2024 Net Zero

Emissions by 2050 (NZE) scenario at $42/bbl (2023 $ real – inflated in line with bp's other planning assumptions). Intervening years are interpolated from 2025 average actual Brent oil price.

cNote that for the purposes of our scenario analysis and resilience test, we have assessed the impact of oil price across both our oil production businesses and those natural gas businesses for

which commercial outcomes are linked to oil price.

---

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| bp Annual Report and Form 20-F 2025 | 51 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

• Even with the most extreme 1.5°C-

consistent low oil price environment in any

of the scenarios, over the period from

2027-30, taking into account our ability to

optimize within the frames set out in our

strategy, and the mitigations that we would

naturally be expected to make in a lower

oil-price world, in our analysis we are able

to deliver across the three lenses we use to

consider strategic resilience for TCFD

purposes, described above.

• Furthermore, in several of the source

scenarios within the Transition Scenario

Catalogue tested, including those

consistent with 1.5°C, well-below 2°C and

BAU families, oil price could potentially

offer a financial upside relative to our

reference 2030 group business outlook.

• The maximum potential scale of downside

impact on our 2030 group adjusted EBITDA

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

scenarios) from our other natural gas and

our refining businesses was modelled to be

around 5%, while from each of our fuels and

low carbon energy business areas was <3%.

• It is reasonable to consider each potential

outcome in isolation since the outcomes

for different business areas vary across

scenarios (see table on page <u>[53](#i37f5f0f2ee4e45afa2448273fb7b6bb9_1-0-1-6-781302)</u>). Our

diversified portfolio helps mitigate the

implications for our strategic resilience of

the exposure of any individual business

area to the identified risk.

• In a BAU scenario, we believe our strategy

mitigates the risk of what we and others

have referred to as a 'delayed and

disorderly' transition, which might follow in

the medium to long term. Should the

earnings of any one of our in-scope

transition business★ areas be challenged in

the modelled timeframe, our analysis

suggests that the impact of this on group

adjusted EBITDA in 2030 would not be

sufficient to impact the resilience of our

strategy, as described above.

• When considering the long term, the

outcome of impairment sensitivity analysis

is detailed in the Financial statements –

Note 1, which indicates the magnitude of

the reduction in the carrying amount of bp's

currently held upstream oil and gas

properties.

It is important to note that insights from this

analysis are necessarily limited by the

scenarios, methodologies and business

assumptions used. The analysis should not be

taken as a prediction of the future.

**Maintaining strategic resilience** 

**to the transition**

Taking into consideration potential constraints

associated with factors such as long-term

capital investment, contractual commitments

and organizational capabilities at any given

time, bp's ability to maintain strategic

resilience rests, in part, on the governance

used to keep the strategy under review in

light of new information and changing

circumstances.

To enable us to understand and respond to the

changing pace of the energy transition, we

monitor and assess key indicators and metrics,

such as policy development, renewables

installed capacity, EV sales and low carbon

technology costs.

Our strategy and capital allocation, the

associated risks, opportunities and (by

association) their implications for our

resilience are all reviewed by the bp leadership

team and the board and updated as they

consider appropriate.

**Resilience to physical risk**

As described on page <u>[49](#i2aa09724bda449efa410cee334279cee_28648)</u>, we have identified a

number of physical risks which may affect our

business and assets, the frequency or severity

of which could be affected by climate change.

Exposure to physical climate-related risk is

highly dependent on geographical location

and on factors such as asset design, and we

seek to manage these risks accordingly. We

consider that our approach to managing these

risks, described in Risk Management

Recommended Disclosure b) on page <u>[46](#i2310ffbb1f074f18860bfb29c400955e_32501)</u>,

supports our strategic resilience to them.

For the purposes of this Recommended

Disclosure, we have considered the potential

for physical risks to bp-operated assets to

increase as a result of climate change (namely,

increases in the potential frequency or

intensity of extreme weather events) to such

an extent as to have the potential to impact

the resilience of our strategy. We have

undertaken analysis of potential changes in

certain physical conditions, such as air

temperature, precipitation, sea level rise and

wave heights, for our onshore and offshore

major operating sites, based on Shared

Socioeconomic Pathway<sup>a</sup>(SSP) emission

scenarios 1-2.6, 2-4.5 and 5-8.5.

Even in the highest emissions pathway

(SSP5-8.5) the results of our analysis suggest

that, on the basis of the 50th percentile values

and compared to the baseline used

(1991-2020), changes in the physical

parameters considered are generally unlikely

to be significant over the medium term.

There is, however, uncertainty across different

scenarios and wider variances were observed

when looking at the 5th and 95th percentile

values. Where the data does suggest greater

potential for climate-related changes in

physical conditions, we intend to consider

whether further work is necessary to

understand the potential for those changes to

adversely impact our operations. For example,

modelled changes in extreme precipitation by

2030 (50th percentile values) are less than 10%

across all onshore major operating sites apart

from Oman – where we have already

undertaken hydrological studies and flood risk

assessments that have supported the

development of our operations there.

Our transition risk scenario analysis identified

impacts on the earnings of our oil-priced

businesses as having the most potential to

impact the resilience of our strategy in 2030.

Therefore, and viewing resilience through the

same lenses that we describe above, we have

considered the extent to which our oil and gas

production business would need to be

impacted by evolving physical risk over the

same timeframe for the scale of financial

impact to be sufficient to jeopardize the

resilience of our strategy out to 2030.

We concluded that a significant proportion

of our oil and gas assets would need to be

permanently or temporarily shut in for

resilience to be jeopardized in this way.

Historically, severe weather risks to our

operated assets have not occurred at a scale

which could reduce earnings so significantly

as to jeopardize the resilience of our strategy.

As reflected in the latest science from the

IPCC, it is in the nature of climate-induced

severe weather events that their occurrence,

intensity and severity are unpredictable and

uncertain. Our own analysis on major

operating sites, described above, is consistent

with this IPCC view.

Despite this uncertainty, we have found no

definitive basis in either the IPCC report or the

limited number of detailed studies we have

undertaken (see page <u>[49](#i0dd2ee81aac04f8c9c97c86197f0c6df_4576)</u>), to conclude that

climate-change-induced increases in the

frequency or severity of severe weather events

would be likely to result, at any point in time

out to 2030, in disruption and shutdowns

across our oil and gas portfolio on a scale that

would reduce earnings so significantly as to

jeopardize the resilience of our strategy.

For the purposes of this Recommended

Disclosure, the resilience of our strategy was

considered separately for the relevant

transition and physical risks; accordingly, we

did not seek to take account of any

interdependencies or cumulative effects

between the two types of climate-related risk,

aSSPs have been developed by the climate change research community to describe plausible major global developments that together would lead in the future to different challenges for

mitigation and adaptation to climate change. The SSPs are based on five narratives describing alternative socioeconomic developments, including sustainable development, regional rivalry,

inequality, fossil-fuelled development and middle-of-the-road development.

and the associated potential financial impact.

---

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|:---|:---|:---|
| 52 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Climate-related financial disclosures** continued<br>

---

| | | | |
|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Our approach to testing resilience to transition risk** | **Our approach to testing resilience to transition risk** |  |
|  | Most of our analysis focused on our medium-<br>term time horizon (2030) – far enough ahead <br>to provide a divergent range of scenarios, <br>while not so far ahead that it is unrealistic to <br>attempt to generate credible financial <br>metrics for bp, or an individual business area <br>within bp. For the variable(s) considered <br>most significant, we also assessed resilience <br>over the period 2027-30. Beyond 2030 we <br>highlight the impairment sensitivities in the <br>Financial statements – Note 1.<br>Our analysis sought to quantify the potential <br>impact of a range of scenarios, including <br>those consistent with 1.5°C, on bp's currently <br>held (at the time the analysis was completed) <br>internal reference group business outlook to <br>2030. This outlook is used for internal <br>corporate planning and holds a deterministic <br>view of our portfolio, activity set, cost and <br>capital frame – this aligned with the strategic <br>direction shared at the February 2025 Capital <br>Markets Update. <br>We have additionally validated the <br>conclusions of step 3, below, using our most <br>recent internally-held financial outlook (as at <br>10 February 2026). <br>Resilience is assessed against the financial <br>priorities set out in the 4Q/full year 2025 <br>results update (10 February 2026).<br>**A high-level summary of the steps taken as** <br>**part of our scenario analysis is as follows:**<br>**1.Whole company assessment:** We defined, <br>through quantitative analysis, which <br>business areas could have both the <br>financial scale and clear transition <br>exposures to potentially impact bp's <br>strategic resilience.<br>a.We assessed the business areas in our <br>portfolio by i) quantitatively evaluating <br>each business area's 'potential <br>significance' by its expected contribution <br>to bp group adjusted EBITDA★ in 2030 <br>and therefore the quantum of financial <br>impact that might be put at risk by <br>transition uncertainty (including pathways <br>consistent with 1.5°C); and ii) by <br>identifying, for each, whether there were <br>primary potential value driver(s) that <br>different transition pathways might <br>impact ('transition risk driver(s)').<br>b.Three broad business areas (see table <br>below), representing over 70% of 2030 <br>adjusted EBITDA, were identified as both <br>providing a potentially significant <br>financial contribution and facing clear <br>primary transition risk drivers, and so <br>were subjected to the driver-based <br>analysis set out in steps 2a-2b below. <br>c.The remaining business areas followed a <br>simplified approach – step 2c.<br>| **2.Scenario analysis:** We tested the financial <br>impact of transition on all of bp's <br>business areas in 2030 through either <br>specific 'driver-based' scenario modelling <br>(a-b), or 'simplified' scenario analysis (c). <br>a.For the driver-based scenario analysis, <br>we selected the primary transition risk <br>driver(s) for each business area – the <br>variable(s) from the Transition Scenario <br>Catalogue★ (see below) representing <br>what we consider to be the primary <br>driver(s) of that business area's primary <br>exposure to the energy transition. For <br>each transition risk driver, we extracted <br>the full range of 2030 outcomes within <br>each scenario 'family'. Given the global <br>nature of the transition risks and <br>opportunities we have identified, we used <br>the 'world' values in the Catalogue except <br>for gas price (see table on page <u>[53](#i37f5f0f2ee4e45afa2448273fb7b6bb9_1-0-1-6-781302)</u>).<br>b.By calibrating the Catalogue's 2030 <br>scenarios to relevant business metrics <br>underpinning our strategic planning (for <br>example, oil price or primary energy <br>demand for oil), we modelled the impact <br>of each variable, across the full range of <br>scenarios and each scenario family, <br>including the most extreme downside <br>scenarios, on the 2030 expected <br>earnings (adjusted EBITDA) for the <br>associated business area. For example, <br>we applied an underlying RC profit★ rule <br>of thumb to the deviation of oil prices in <br>the Catalogue versus our reference case <br>price. This analysis was 'unmitigated' (see <br>'Other key considerations', below).<br>c.For the simplified scenario analysis, used <br>for the remaining business areas <br>identified in step 1c, we took a simpler <br>conservative approach, by evaluating <br>whether a scenario in which each <br>business area's expected 2030 adjusted <br>EBITDA is assumed to be reduced to <br>zero (an outcome considered to be at <br>least as detrimental as could be expected <br>to result from ranges associated with <br>1.5°C, 2°C or BAU scenario families) could <br>have the potential to impact strategic <br>resilience (as defined below).<br>d.This analysis enabled us to assess the <br>potential for each business area to <br>impact group adjusted EBITDA (and by <br>implication associated cash flows) in <br>2030, when compared to the reference <br>group business outlook, to identify which <br>(if any) businesses, variables and <br>scenarios may have the potential to most <br>materially impact strategic resilience (as <br>defined below), and as such, which <br>business areas should be carried forward <br>into a multi-year resilience assessment.<br>**3.Multi-year resilience test:** This step tested <br>bp's resilience to the exposure of any <br>sufficiently material business areas to <br>downside scenarios that may have the <br>potential to jeopardize the ability to <br>generate excess cash flow★ and a strong <br>cash cover ratio – financial metrics that <br>were treated for the purposes of this <br>analysis as representing financial <br>evidence of delivery of bp's strategic <br>financial priorities (see below).<br>From step 2, in 2025, only the exposure to <br>oil price was assessed as sufficiently <br>material in this sense. Our multi-year <br>(2027-30) oil price resilience test <br>considered sustained low oil prices <br>interpolated from 2025 actual Brent price <br>to the most extreme 2030 Transition <br>Scenario Catalogue case (IEA WEO 2024 <br>NZE by 2050 Scenario) – falling to a 2030 <br>minimum price of $42/bbl (2023 $ real). <br>Other scenarios, from providers such as <br>UN PRI IPR and NGFS, formed part of the <br>Catalogue, but indicated higher prices <br>than the IEA WEO NZE case used. <br>For information about the approach to <br>impairment sensitivity testing see <br>Financial statements – Note 1.<br>**Transition Scenario Catalogue data** <br>•The latest WBCSD<sup>a</sup> Energy Climate <br>Scenario Catalogue which was Version 3.0 <br>published May 2024, has been used as a <br>starting point for compiling a suite of <br>transition scenarios. While there has been <br>no more recent update to the WBCSD <br>Catalogue (at the time of preparation), <br>certain underlying source providers (IEA<sup>b</sup>, <br>NGFS<sup>c</sup>, UN PRI IPR<sup>d</sup>) have since published <br>updated scenarios for key transition <br>variables or have 'retired' older scenarios. <br>•To reflect this more recent information, <br>the Transition Scenario Catalogue we used <br>is therefore based on variables and <br>scenario families from WBCSD V3, <br>updated for amended IEA, NGFS and UN <br>PRI IPR data where available (see <br>footnotes on the next page for details).<br>•For updated variables, oil and gas price <br>and primary energy demand for oil (used <br>for oil, gas and refining) were directly <br>available in the published data. 'Final <br>energy demand for liquid oil in road <br>transport'; used for bp's road transport-<br>related business areas, was not directly <br>available from updated publications and <br>so required some simple derivation by bp: <br>'Total final consumption in road <br>transport' (IEA) and 'Final energy demand <br>in road transport' (NGFS) were <br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

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|:---|:---|
| bp Annual Report and Form 20-F 2025 | 53 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

---

| | | | | |
|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | disaggregated to estimate the proportion <br>associated with liquid oil based on the <br>published breakdown of 'Road transport <br>final energy demand by energy source' <br>published in WBCSD V3. We believe that <br>this disaggregation of source data was <br>similarly required in previous years to be <br>conducted by WBCSD and its partners in <br>preparing their Scenario catalogues.<br>**Other key considerations**<br>•For the purposes of steps 2 and 3, we <br>considered the resilience of our strategy <br>to climate-related transition risk through <br>the three lenses described on page <u>[52](#idfd02045cd904558886b64b741d9bf83_2-1-1-5-781302)</u>. <br>We defined the following as proxy <br>indicators for these lenses:<br>–Positive group excess cash flow (in <br>2024 termed 'surplus cash flow'), to <br>demonstrate whether after funding, <br>among other things, capital spend <br>within our disclosed capital frame to <br>2027 (February 2025 Capital Markets <br>Update) and a resilient dividend per <br>ordinary share, sufficient excess <br>cash flow remains to maintain or <br>reduce net debt over the period.<br>–Healthy cash cover ratio as an <br>indicator of the ability to maintain a <br>strong investment grade credit <br>rating.<br>•For steps 2 and 3, we made the <br>simplifying assumption that, aside from <br>the driver being modelled, our strategy, <br>operating model, volumes, margins, sales <br>proceeds and tax rates would remain <br>unchanged out to 2030. <br>| •There are a range of mitigations or actions <br>that we might naturally be expected to <br>experience (e.g. through deflation) or to <br>take in response to external market, price <br>and demand trends, including cost <br>reductions, portfolio adjustments, <br>shareholder distribution and balance <br>sheet choices, capital reallocation or <br>capital reductions within the frames set <br>out in our strategy.<br>•For step 3, given we would seek to make <br>use of opportunities to maintain our <br>strategic flexibility in the face of the many <br>uncertainties of the energy transition, our <br>methodology retains the optionality in <br>downside scenario modelling to apply <br>some or all of these mitigations.<br>•As outlined above, we utilized our latest <br>internal reference group business <br>outlooks as the basis against which <br>resilience has been tested, as this forms a <br>deterministic view against which to model <br>the transition sensitivities to 2030 and <br>aligns to the strategic updates provided <br>to investors in February 2025 (and <br>February 2026). Alongside disclosed <br>elements such as the capital frame range <br>to 2027, this includes shaping <br>assumptions such as future distributions <br>and net debt management. <br>•Rules of thumb applied to convert <br>variance in hydrocarbon price to variance <br>in adjusted EBITDA, these are considered <br>appropriate to the period in question – i.e. <br>they reflect the portfolio's changing price <br>leverage over the period to 2030. Due to <br>the evolution of bp's portfolio, these rules <br>of thumb may diverge from any short-<br>term rule of thumb that we publish.<br>| •Through conducting this analysis, we do <br>not intend to imply or commit to a <br>specific forward trajectory of usage of <br>cash, beyond any disclosed in the investor <br>update in February 2025 (and 4Q/full year <br>2025 results on 10 February 2026) or other <br>published strategy updates. While we <br>cannot disclose, for confidentiality <br>reasons, the detail of the deterministic <br>case, the test assesses whether the <br>resilience indicators in our reference <br>group business outlook are impacted by <br>the transition uncertainties tested. <br>Further, by the nature of the timeframes <br>considered, a variety of uncertainties exist <br>around this deterministic case (including <br>transition risk itself). <br>•The design of a strategic resilience <br>analysis involves numerous <br>methodological choices and assumptions <br>any one of which could reasonably have <br>been different, leading to different <br>outcomes. We have found value in <br>conducting this analysis; however, we are <br>mindful of the limitations to any such <br>exercise and the highly qualified nature of <br>any conclusions which may be drawn <br>from it. The disclosures provided here <br>should be read in conjunction with the <br>rest of our strategic report, where we <br>discuss how we have developed, and <br>continue to evolve, our approach to <br>strategy. <br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

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| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| **Transition Scenario Catalogue**★ **family ranges for 2030 key transition variables** | **Transition Scenario Catalogue**★ **family ranges for 2030 key transition variables** | **Transition Scenario Catalogue**★ **family ranges for 2030 key transition variables** | **Transition Scenario Catalogue**★ **family ranges for 2030 key transition variables** | **Transition Scenario Catalogue**★ **family ranges for 2030 key transition variables** |  |  |  |
| Scenario families (as categorised by WBCSD/source providers): | Scenario families (as categorised by WBCSD/source providers): | **BAU** | **BAU** | **Below 2°C** | **Below 2°C** | **1.5°C** | **1.5°C** |
| **Business area** | **Transition variable** | **Min** | **Max** | **Min** | **Max** | **Min** | **Max** |
| **Oil and natural gas production** | Oil price<sup>e</sup> ($2023/bbl) | 65.2 | 81.2 | 65.4 | 81.2 | 42.0 | 72.3 |
| **Oil and natural gas production** | Natural gas price<sup>f</sup> ($2023/mmbtu) | 3.81 | 4.38 | 2.59 | 4.38 | 2.10 | 4.62 |
| **Refining – refined oil demand** | Primary energy demand for oil (% change vs 2020) | -2.4 | 14.4 | -4.2 | 8.7 | -21.3 | -5.9 |
| **Conventional fuels retail and** <br>**midstream**<br>| Final energy demand for liquid oil in road transport <br>(EJ/yr)<br>| 74.3 | 88.7 | 71.9 | 88.7 | 63.5 | 72.1 |

---

For the other business areas not shown above<sup>g</sup>, we applied the generic scenario analysis methodology described in point 2d, above, thereby

ensuring coverage of all of bp's business areas.

aWorld Business Council for Sustainable Development; for the WBCSD Energy Climate Scenario Catalogue 3.0 (2024) see https://climate-scenario-catalogue.shinyapps.io/final_2024/.

bIEA World Energy Outlook (WEO) 2023, in WBCSD V3, updated with relevant data from IEA WEO 2024 (published October 2024); see https://www.iea.org/reports/world-energy-outlook-2024.

cNGFS v4.2, in WBCSD V3, updated with relevant data from NGFS v5.0 (released November 2024); see https://www.ngfs.net/ngfs-scenarios-portal/data-resources.

dUN PRI Inevitable Policy Response Forecast Policy Scenario (2023), in WBCSD V3, updated with relevant data from UN PRI IPR Transition Forecast Scenario (2025); UN PRI IPR Required Policy

Scenario (2021), in WBCSD V3, removed (now regarded as outdated); see https://ipr.transitionmonitor.com.

eOil price sensitivities have been applied to the oil and gas production portfolio that is linked to oil marker prices – as such it not only reflects oil production exposure, but also a proportion of bp's

natural gas production that is contracted off oil marker prices.

fGas prices shown reflect Henry Hub price ranges. Where available, Asian and UK gas price sensitivities have also been selected and compared to the Henry Hub sensitivity percentages with the

maximum deviation selected and applied to the respective Asian and NBP rules of thumb for these parts of the gas portfolio, in order to provide the most conservative uncertainty range.

gIn 2025 this included, for example, biogas and biojet production, aviation fuel sales, EV charging, renewables and hydrogen production, as well as convenience and trading and shipping.

---

| | | |
|:---|:---|:---|
| 54 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Climate-related financial disclosures** continued<br>

**Metrics and targets**

---

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|:---|:---|:---|
| ![WarmGrey2-50-SMALL-TopRoundCornerV2.gif](bp-20251231_g61.gif) |  | ![WarmGrey2-50-SMALL-TopRoundCornerV2.gif](bp-20251231_g61.gif) |
|  | **TCFD Recommendation:**<br>Disclose the metrics and targets used to <br>assess and manage relevant climate-related <br>risks and opportunities where such information <br>is material.<br>|  |
| ![WarmGrey2-50-SMALL-BottomRoundCornerV2.gif](bp-20251231_g62.gif) |  | ![WarmGrey2-50-SMALL-BottomRoundCorner.gif](bp-20251231_g63.gif) |

---

We present the principal group-wide metrics

and targets used to assess and manage

climate-related risks and opportunities in line

with our strategy and risk management

process below, with metrics and targets

mapped to the most relevant of TCFD's

cross-industry, climate-related metric

categories (such as 'transition risks').

The metrics and targets themselves are

disclosed at the most appropriate locations

in this strategic report.

---

| | | | |
|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **TCFD recommended disclosures –** <br>**metrics and associated targets/goals** | **TCFD recommended disclosures –** <br>**metrics and associated targets/goals** |  |
|  | **a) Disclose the metrics used by the organization to assess** <br>**material climate-related risks and opportunities in line with its** <br>**strategy and risk management process.**<br>**Transition risks**<br>•Note 5 to Financial statements: Segmental analysis. Segment revenue <br>(in table), pages <u>[185](#i0dd2ee81aac04f8c9c97c86197f0c6df_286)</u><u>-</u><u>[189](#i0dd2ee81aac04f8c9c97c86197f0c6df_289)</u><br>•Estimated net proved reserves and production (net of royalties), <br>page <u>[27](#i663cb5fa041d40c8a97de3b033d71c39_0-0-1-5-725324)</u><br>•Note 4 to Financial statements: Disposals and impairments, page <u>[182](#i0dd2ee81aac04f8c9c97c86197f0c6df_283)</u><br>•Note 8 to Financial statements: Impairment losses (in table), page <u>[190](#i0dd2ee81aac04f8c9c97c86197f0c6df_295)</u><br>•Oil and natural gas prices used for value-in-use impairment testing and <br>recoverability of asset carrying values, page <u>[168](#ic789f8edd80e492d9564a861966b11d4_0-0-1-1-725324)</u><br>**Physical risks**<br>•Number of major operating sites in regions with high to extremely high <br>water stress, page <u>[59](#i87f52fc5efef4a16865a4af06e1e7987_79392)</u><br>•Freshwater withdrawals and consumption at major operating sites in <br>regions with high or extremely high water stress, page <u>[59](#i87f52fc5efef4a16865a4af06e1e7987_26443)</u><br>**Climate-related opportunities**<br>•Note 5 to Financial statements: Segmental analysis. Segment revenue <br>(in table), pages <u>[185](#i0dd2ee81aac04f8c9c97c86197f0c6df_286)</u>-<u>[189](#i0dd2ee81aac04f8c9c97c86197f0c6df_289)</u><br>•Gas & low carbon energy, page <u>[28](#i0dd2ee81aac04f8c9c97c86197f0c6df_67)</u><br>**Capital deployment**<br>•Financial frame, page <u>[18](#i0dd2ee81aac04f8c9c97c86197f0c6df_46)</u><br>•Price assumptions, key investment appraisal assumptions, page <u>[20](#i0dd2ee81aac04f8c9c97c86197f0c6df_52)</u> <br>(in table, indicated with TCFD)<br>•Amount invested in transition businesses★, page <u>[21](#i0dd2ee81aac04f8c9c97c86197f0c6df_55)</u><br>•Additional information – capital expenditure by segment, page <u>[335](#i0dd2ee81aac04f8c9c97c86197f0c6df_478)</u><br>•Note 7 to Financial statements: expenditure on research and <br>development (in table), page <u>[189](#i0dd2ee81aac04f8c9c97c86197f0c6df_292)</u><br>•Note 8 to Financial statements: exploration and evaluation costs (in <br>table), page <u>[190](#i0dd2ee81aac04f8c9c97c86197f0c6df_295)</u><br>**Internal carbon prices**<br>•Internal carbon price, page <u>[20](#i0dd2ee81aac04f8c9c97c86197f0c6df_52)</u><br>**Remuneration**<br>•Directors' remuneration report metrics: operated carbon emissions, <br>page <u>[99](#i0dd2ee81aac04f8c9c97c86197f0c6df_205)</u> | **b) Disclose Scope 1, Scope 2, and, if appropriate, Scope 3** <br>**greenhouse gas (GHG) emissions, and the related risks**<br>**GHG emissions**<br>•Key performance indicators (relevant KPIs shown with TCFD), page <u>[17](#ie8ae9c8ba6884c1b8f828963987874b3_1-0-1-3-939849)</u><sup>a</sup><br>•Scope 1 and 2, in SECR table page <u>[39](#i0dd2ee81aac04f8c9c97c86197f0c6df_85)</u><br>•Ratio of Scope 1 and 2 emissions: gross production, in SECR table <br>page <u>[39](#i0dd2ee81aac04f8c9c97c86197f0c6df_85)</u><br>•Scope 3 (related to category 11) emissions page <u>[38](#ia533d1b86ea04772b2fd02ae3d1c8da0_39091)</u><sup>b</sup><br>•TCFD: risks as described in Strategy a, page <u>[46](#i0dd2ee81aac04f8c9c97c86197f0c6df_97)</u><br>•Risk factors, page <u>[67](#i0dd2ee81aac04f8c9c97c86197f0c6df_109)</u><br>•A further breakdown of our GHG and energy data by business group is <br>available in the *bp ESG Datasheet 2025* at <u>bp.com/ESG</u><br>|  |
|  | **a) Disclose the metrics used by the organization to assess** <br>**material climate-related risks and opportunities in line with its** <br>**strategy and risk management process.**<br>**Transition risks**<br>•Note 5 to Financial statements: Segmental analysis. Segment revenue <br>(in table), pages <u>[185](#i0dd2ee81aac04f8c9c97c86197f0c6df_286)</u><u>-</u><u>[189](#i0dd2ee81aac04f8c9c97c86197f0c6df_289)</u><br>•Estimated net proved reserves and production (net of royalties), <br>page <u>[27](#i663cb5fa041d40c8a97de3b033d71c39_0-0-1-5-725324)</u><br>•Note 4 to Financial statements: Disposals and impairments, page <u>[182](#i0dd2ee81aac04f8c9c97c86197f0c6df_283)</u><br>•Note 8 to Financial statements: Impairment losses (in table), page <u>[190](#i0dd2ee81aac04f8c9c97c86197f0c6df_295)</u><br>•Oil and natural gas prices used for value-in-use impairment testing and <br>recoverability of asset carrying values, page <u>[168](#ic789f8edd80e492d9564a861966b11d4_0-0-1-1-725324)</u><br>**Physical risks**<br>•Number of major operating sites in regions with high to extremely high <br>water stress, page <u>[59](#i87f52fc5efef4a16865a4af06e1e7987_79392)</u><br>•Freshwater withdrawals and consumption at major operating sites in <br>regions with high or extremely high water stress, page <u>[59](#i87f52fc5efef4a16865a4af06e1e7987_26443)</u><br>**Climate-related opportunities**<br>•Note 5 to Financial statements: Segmental analysis. Segment revenue <br>(in table), pages <u>[185](#i0dd2ee81aac04f8c9c97c86197f0c6df_286)</u>-<u>[189](#i0dd2ee81aac04f8c9c97c86197f0c6df_289)</u><br>•Gas & low carbon energy, page <u>[28](#i0dd2ee81aac04f8c9c97c86197f0c6df_67)</u><br>**Capital deployment**<br>•Financial frame, page <u>[18](#i0dd2ee81aac04f8c9c97c86197f0c6df_46)</u><br>•Price assumptions, key investment appraisal assumptions, page <u>[20](#i0dd2ee81aac04f8c9c97c86197f0c6df_52)</u> <br>(in table, indicated with TCFD)<br>•Amount invested in transition businesses★, page <u>[21](#i0dd2ee81aac04f8c9c97c86197f0c6df_55)</u><br>•Additional information – capital expenditure by segment, page <u>[335](#i0dd2ee81aac04f8c9c97c86197f0c6df_478)</u><br>•Note 7 to Financial statements: expenditure on research and <br>development (in table), page <u>[189](#i0dd2ee81aac04f8c9c97c86197f0c6df_292)</u><br>•Note 8 to Financial statements: exploration and evaluation costs (in <br>table), page <u>[190](#i0dd2ee81aac04f8c9c97c86197f0c6df_295)</u><br>**Internal carbon prices**<br>•Internal carbon price, page <u>[20](#i0dd2ee81aac04f8c9c97c86197f0c6df_52)</u><br>**Remuneration**<br>•Directors' remuneration report metrics: operated carbon emissions, <br>page <u>[99](#i0dd2ee81aac04f8c9c97c86197f0c6df_205)</u> | **c) Describe the targets used by the organization to manage** <br>**climate-related risks and opportunities and performance against** <br>**targets.**<br>**Transition risks**<br>•Net zero operations★ (including methane), page <u>[38](#ia533d1b86ea04772b2fd02ae3d1c8da0_54145)</u><br>•Net zero sales★, page <u>[38](#ia533d1b86ea04772b2fd02ae3d1c8da0_9656)</u><br>**Physical risks**<br>•Water, page <u>[59](#i87f52fc5efef4a16865a4af06e1e7987_26443)</u><br>**Climate-related opportunities**<br>•Net zero operations (including methane), page <u>[38](#ia533d1b86ea04772b2fd02ae3d1c8da0_54145)</u><br>•Net zero sales, page <u>[38](#ia533d1b86ea04772b2fd02ae3d1c8da0_9656)</u><br>**Capital deployment**<br>•Transition business investment, page <u>[21](#i0dd2ee81aac04f8c9c97c86197f0c6df_55)</u><br>**Remuneration**<br>•Incentivizing employees, page <u>[58](#i87f52fc5efef4a16865a4af06e1e7987_26433)</u><br>**GHG emissions**<br>•Net zero operations (including methane), page <u>[38](#ia533d1b86ea04772b2fd02ae3d1c8da0_54145)</u><br>•Net zero sales, page <u>[38](#ia533d1b86ea04772b2fd02ae3d1c8da0_9656)</u><br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

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aThese are our KPIs for the purposes of our disclosures pursuant to the UK CFD Regulations and Section 414CB (2A) (h) of the Companies Act 2006.

bIn determining the Scope 3 emissions that are 'appropriate' to be disclosed for the purposes of this Recommended Disclosure, we have considered this term in the context of the

recommendation to disclose the metrics and targets used to assess and manage relevant climate-related risks and opportunities.

---

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|:---|:---|
| bp Annual Report and Form 20-F 2025 | 55 |

---

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| | |
|:---|:---|
|  | ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
|  | **Strategic report** |
| **Sustainability** continued |  |

---

**Our approach to sustainability**

Our approach to sustainability is built on

strong foundations. They guide the way we

work, underpin our focus on safety and

support our net zero, people and planet aims.

**Safety comes first**

At bp, safety comes first. We want to improve

our safety performance and work towards our

goal to eliminate fatalities, life-changing

injuries and tier 1 process safety events.

We deeply regret the four fatalities and three

life-changing injuries that occurred in 2025.

Three employees in our TravelCenters of

America business<sup>a</sup> died at work – two while

carrying out emergency roadside assistance in

separate incidents and one while servicing a

truck. In response, we have permanently

stopped roadside assistance next to active

traffic lanes. A contractor in our *Thorntons* 

retail business died after falling from a ladder.

One employee and two contractors suffered

life-changing injuries. Two were hand injuries –

one in our TravelCenters of America business<sup>a</sup>,

the other in our Mauritania and Senegal

business. The third was a head injury which

occurred during a crane lifting activity in the

North Sea (UK).

We have offered our support to the bereaved

families and the injured workers. We know we

have more work to do to improve our safety

culture and performance.

**Keeping people safe**

We remain focused on risks that have the

potential to cause fatalities or significant

injuries and we monitor and report on key

workforce personal safety metrics in line with

industry standards. We include both

employees and contractors in our data.

Life-changing injuries decreased from six in

2024 to three in 2025<sup>ab</sup>. Our recordable injury

frequency (RIF) also decreased by 21%

compared to 2024, see page <u>[16](#i0dd2ee81aac04f8c9c97c86197f0c6df_43)</u>. These

reductions are encouraging, but we know we

must maintain our efforts to continue

improving our safety performance, by applying

the International Association of Oil & Gas

Producers' (IOGP) Life-Saving Rules and our

own Safety Leadership Principles.

In 2025 we gained new insights about the

effectiveness of the IOGP's Life-Saving Rules

in bp, due to the introduction of conformance

checklists tailored to the needs of specific

businesses.

aAt the time of publication (March 2026), as part of the transition period for recently acquired businesses, the safety reporting processes were still being integrated into bp's safety reporting

processes. As such, data from Archaea Energy, TravelCenters of America, Lightsource bp, bp bioenergy, X Convenience and new Eagle Ford assets in bpx energy are not included in 2025

reported data.

bIn addition to the four life-changing injuries reported in the *bp Annual Report 2024*, two additional injuries that occurred in late 2024 were later classified as life-changing after the publication of

the 2024 report, in accordance with the 180-day classification window for life-changing injuries, bringing the total to six life-changing injuries in 2024.

cFor recently acquired businesses, there is typically a transition period while bp's operating standards, as set out in OMS, are integrated or aligned.

dThe number of accidental or unplanned losses of hydrocarbon from primary containment from a bp or contractor operation, irrespective of any secondary containment or recovery. Oil spills >

1bbl are defined as any liquid hydrocarbon release of more than, or equal to, one barrel (159 litres, equivalent to 42 US gallons).

**Driving safety**

Driving continues to be one of the biggest

personal safety risks we face at bp. In 2025

five severe vehicle accidents occurred (2024

5). The number of kilometres driven fell by 19%

during the same period.

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| | | | |
|:---|:---|:---|:---|
|  | **2025** | 2024 | 2023 |
| Severe vehicle <br>accident rate <br>per million km <br>driven<br>| **0.03** | 0.02 | 0.02 |

---

**Our Operating Management System**<sup>c</sup>

Our Operating Management System (OMS)★

provides a single framework for delivering

safe, reliable and compliant operations. Our

OMS sets out the way in which our businesses

within our operational control around the

world are expected to understand and manage

their environmental and social impacts,

including requirements on engaging with

stakeholders who may be affected by

our activities.

We review and amend these requirements

from time to time to reflect our priorities. Any

variations in the application of our OMS, in

order to reflect the specific circumstances of

a bp entity or meet local regulations or

circumstances, are subject to a governance

process.

Our OMS requires each of bp's operating

businesses to create and maintain its own

OMS handbook, describing how it will carry out

its local operating activities.

We use a 'three lines of defence' model to

facilitate the effective management of all

types of risk, including safety. The nature and

extent of first, second and third lines of

defence activities are based on the type and

level of risk.

**Preventing incidents**

We plan our operations carefully to identify

potential hazards and manage risks at every

stage through rigorous operating and

maintenance practices applied by capable

people. We design our new facilities in line

with process safety, good design and

engineering principles. We track our process

safety performance using industry-aligned

metrics such as those found in the American

Petroleum Institute recommended practice

754 and the IOGP recommended practice 456.

Our combined reported tier 1 and tier 2

process safety events★ (PSEs) have decreased

for the past 12 years, apart from in 2019. There

were 27 PSEs in 2025 (2024 38), of which five

were tier 1 (2024 3) and 22 were tier 2 (2024 35).

In 2025 the number of oil spills<sup>d</sup> increased to

110, compared with 96 in 2024.

Our operating sites share examples of good

practice, while our central health, safety, and

environment incident investigations team

reviews serious or complex incidents, which

may include near misses. Supported by the

use of leading indicators, such as inspections

and equipment tests, these activities help us

monitor and strengthen controls and identify

and address systemic gaps to prevent

incidents.

---

| | | | |
|:---|:---|:---|:---|
|  | **2025** | 2024 | 2023 |
| Tier 1 and tier 2 <br>process safety <br>events★<br>| **27** | 38 | 39 |
| Oil spills – <br>number<br>| **110** | 96 | 100 |
| Oil spills – <br>contained<br>| **57** | 49 | 52 |

---

**Emergency preparedness**

We have disaster recovery, crisis and business

continuity management plans and work to

build day-to-day response capabilities to

support local management of incidents. We

test our plans and preparedness through

exercises that simulate real-life scenarios. In

2025 we conducted 37 exercises in countries

including India and the US.

**Security**

We protect our people, assets and operations,

and manage security through a threat-driven,

risk-based approach. We continuously monitor

threats from activism, civil unrest or political

instability, terrorism, armed conflict, and

criminal and cyber activity. Our 24-hour

intelligence and response information centre

in the UK monitors global security risk in real

time. It helps us to assess the safety of our

people and provide them with practical advice

if there is an emergency.

**Cyber security**

The severity, sophistication and scale of cyber

attacks continue to evolve. Increasing

digitization, the emergence of new technology

such as generative artificial intelligence, and

reliance on IT systems and cloud platforms

---

| | | |
|:---|:---|:---|
| 56 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Sustainability** continued<br>

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.

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | How we manage risk, page <u>[60](#i0dd2ee81aac04f8c9c97c86197f0c6df_106)</u><br>Additional disclosures – <br>cyber security, page <u>[360](#i0dd2ee81aac04f8c9c97c86197f0c6df_529)</u><br>|

---

**Working with contractors**

Through documents that help bridge our

health, safety and environmental policies and

those of our contractors, we define the way

our OMS co-exists with systems used by our

contractors to manage risk on a site. We

conduct risk-based quality, technical, health,

safety and security audits before awarding

contracts. Once contractors start work, we

continue to monitor their safety performance.

Our OMS includes requirements and practices

for working with contractors. Our standard

model contracts include health, safety and

security requirements. We expect and

encourage our contractors and their

employees to act in a way that is consistent

with our code of conduct and take appropriate

action if those expectations, or their

contractual obligations, are not met.

**Our partners in joint arrangements**

We monitor performance and how risk is

managed in our joint arrangements★,

whether we are the operator or not. In joint

arrangements where we are the operator,

our OMS, code of conduct and other

policies apply.

**Our people**

**Workforce by gender**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| As at 31 December 2025 | Male | Male | Female | Female | Female % | Female % |
| As at 31 December 2025 | **2025** | 2024 | **2025** | 2024 | **2025** | 2024 |
| Board directors | **7** | 5 | **6** | 6 | **46** | 55 |
| Leadership team | **4** | 5 | **4** | 5 | **50** | 50 |
| Group leaders | **169** | 186 | **99** | 100 | **37** | **35** |
| Subsidiary★ directors | **473** | 519 | **294** | 253 | **38** | 33 |
| All employees<sup>a</sup> | **58400** | 62000 | **35100** | 38300 | **37** | 38 |

---

**Number of employees**

---

| | | | |
|:---|:---|:---|:---|
| As at 31 December 2025 | **2025** | 2024 | 2023 |
| Gas & low carbon energy | **5600** | 6500 | 4800 |
| Oil production & operations | **9300** | 9200 | 8800 |
| Customers & products | **66900** | 73100 | 63400 |
| Other businesses & corporate | **11800** | 11700 | 10800 |
| Total | **93700** | 100500 | 87800 |
| a Some employees have not disclosed gender, therefore are not included in this total. | a Some employees have not disclosed gender, therefore are not included in this total. | a Some employees have not disclosed gender, therefore are not included in this total. | a Some employees have not disclosed gender, therefore are not included in this total. |

---

We aim to report on aspects of our business

where we are the operator – as we directly

manage the performance of these operations.

Where we are not the operator, our OMS is

available as a reference point for bp

businesses when engaging with other

operators and co-venturers. We have a group

framework to assess and manage bp's

exposure risks from our participation in these

types of arrangements.

Where appropriate, we may seek to influence

how risk is managed in arrangements where

we are not the operator.

The people, culture and governance

committee reviews workforce policies and

practices and their alignment with bp's

strategy, purpose, beliefs and culture, and

conducts workforce engagement measures.

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | People, culture and governance <br>committee report, page <u>[89](#i0dd2ee81aac04f8c9c97c86197f0c6df_184)</u><br>|

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 57 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

**Our culture**

We want to build a culture that supports all of

our employees and promotes inclusion,

wellbeing and development.

Our culture frame, 'Who we are', defines what

we stand for and is integrated into our code of

conduct and our approach to inclusion. We

maintain oversight of our culture by measuring

employee sentiment and encouraging

employees to use our speak-up channels.

Read more about the board's role in

overseeing bp's culture on page <u>[90](#i372e476394b943ee83d7eb667cf64e6f_272219)</u>.

**Developing our people**

Our people are crucial to delivering our

strategy and aims. We invest to ensure we

have the right people with the right skills

from diverse backgrounds, and we provide

training, development and competitive

rewards for them.

In 2025 bp employees collectively completed

around 2.1 million hours of formal learning

(2024 1.2 million hours). bp's learning and

development framework is applicable to all

employees and covers safety, technical and

operational skills, leadership, and future skills.

Our mandatory training curriculum covers

conformance with our internal standards and

applicable laws and regulations.

**Building an inclusive culture**

Part of our people aim is to foster an inclusive

culture with an employee workforce that

reflects the communities where we work. To

deliver our strategy we believe we need to

capitalize on the diversity of perspectives,

backgrounds, skills and experiences within

our workforce.

**Improving representation**

We make all employment decisions based on

merit without regard to gender, race, age,

disability, or any other protected status.

In 2025 global female representation in bp was

37% (2024 38%), four of the eight positions in

our leadership team were held by women, and

37% of group leader roles were filled by

women (2024 35%).

In 2025 our ethnic minority representation in

the UK remained steady at 22% of our overall

workforce (2024 22%).

---

| | |
|:---|:---|
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | *bp Gender and Ethnicity Pay Gap* <br>*Report*, <u>bp.com/ukgenderpaygap</u><br>|

---

In line with UK reporting requirements, we

disclose information against external targets

on the representation of women and ethnic

minorities on our board and executive

management. Read more on diversity

reporting in line with the Listing Rules on

page <u>126</u>.

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Composition of the board, page <u>[73](#i0dd2ee81aac04f8c9c97c86197f0c6df_130)</u> |

---

**Promoting inclusion**

To promote an inclusive culture, we support

employee-run business resource groups

(BRGs) in areas such as age diversity, social

mobility, gender, ethnicity, and disability.

As well as bringing employees together, these

groups contribute to our inclusive culture,

provide a representative voice for employees

and highlight and celebrate the achievements

of different groups. Each group is sponsored

by a senior leader and open to all employees.

**Improving accessibility**

We continue to take steps to progress

inclusion for our neurodivergent employees

and those with disabilities. We offer access to

support including assistive technology, such

as immersive readers and peripheral

accessories.

To help meet the requirements of our

employees we work closely with our

employee-led disability BRGs.

If existing employees become disabled, our

policy is to engage and use reasonable

accommodations or adjustments to enable

continued employment.

We have partnerships to help us implement

best practice methods to support

neurodivergent employees and those with

disabilities. Our partners include the Business

Disability Forum in the UK.

**Employee engagement**

Our managers hold team and one-to-one

meetings with their team members,

complemented by formal processes through

works councils in parts of Europe.

We regularly communicate with employees on

factors that affect bp's performance, and seek

to maintain constructive relationships with

labour unions formally representing our

employees.

In 2025 we reset our approach to performance

management to reflect our organizational

focus on delivering bp's strategy<sup>a</sup> by

introducing clearer, more transparent

processes – aligned goals, business

scorecards, a new annual review cycle and a

simple individual rating system. These changes

will help embed a stronger performance

culture that supports our strategy.

We monitor employee sentiment through

several channels including our Pulse annual

employee survey, which is sent to all eligible

employees, and through our Pulse live survey,

which is sent to a representative sample of

employees weekly. In 2025 our overall

engagement metric, employee engagement,

decreased to 66%<sup>b</sup> (2024 70%).

We will continue to develop engagement plans

based on feedback from the annual and

weekly surveys to help us deliver on safety,

and meet our strategic objectives. The 2025

Pulse survey results highlight three priority

areas for engagement in 2026: two of these –

emphasizing psychological safety, and

strategy and performance – were also

priorities in 2025. The third – career and

development – is new.

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Our employee engagement key <br>performance indicator, page <u>[16](#ib54d6b38bb6948778850777118379af1_1-0-1-1-725324)</u><br>How the board engaged with the <br>workforce, page <u>[80](#i0dd2ee81aac04f8c9c97c86197f0c6df_142)</u><br>|

---

**Workforce health and wellbeing**

We include an employee wellbeing index in our

Pulse annual employee survey and weekly

Pulse live surveys. Results from 2025 showed

that employee wellbeing decreased to 69%<sup>b</sup>

(2024 73%) generally because of organizational

transformation.

During bp's transformation programme, we

have offered comprehensive mental health

support to employees which has been

developed through listening forums and

employee feedback.

Our approach to workforce health and

wellbeing combines globally available services

that can be tailored to meet local needs. All

employees have access to our global digital

health and wellbeing hub, Thrive@bp.

aThis reset approach to performance management is subject to local law, including consultation where required.

bAs a result of changes to the question set and the inclusion of employees from our retail business in the 2025 Pulse survey, the engagement and wellbeing scores for 2025 are not comparable

with prior years.

TCFD TCFD Recommendations and Recommended Disclosures

---

| | | |
|:---|:---|:---|
| 58 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Sustainability** continued<br>

**Linking remuneration to** 

**sustainability** <sup>TCFD</sup>

The bonus scorecard for 2025 against which

eligible employees<sup>a</sup> are measured incentivized

them through three themes: safety and

sustainability (30%); operational performance

(15%); and financial performance (55%). For

2025 our sustainability measure was linked to

our operated carbon emissions. This measure

covers Scope 1 and 2 emissions based on our

net zero operations★ aim. Our 2023-25 long-

term incentive plan scorecard was linked to

emissions reductions against our 2019

baseline (15%).

For 2026, progress towards our aim to achieve

net zero operations by 2050 or sooner will

continue to be rewarded through our long-

term performance share plans rather than the

annual bonus. For 2026-28 the scorecard

measure will focus on reducing Scope 1 and 2

operational emissions (20%).

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Directors' remuneration report, page <u>[91](#i0dd2ee81aac04f8c9c97c86197f0c6df_187)</u> |

---

**Share ownership**

We encourage employee share ownership and

have a number of employee share plans in

place. For example, we operate a ShareMatch

plan, matching bp shares purchased by our

employees. We also make annual share awards

as part of our total reward package for all

senior and mid-level employees globally, and

a portion of our more junior professional

grade employees.

**Ethics and compliance**

**Our code of conduct**

Our code sets out the principles and

expectations that guide our daily activities. It

provides a framework to support safe and

ethical decision making, sets the standards for

how we do the right thing and empowers us to

speak up without fear of retaliation. Our code

is the foundation of 'Who we are', our culture

frame, and it puts safety first. Together with

our Safety Leadership Principles and OMS★,

it helps us act responsibly, comply with

applicable laws, and implement our

sustainability frame.

Our code applies to all bp employees, officers

and board members<sup>b</sup>. Regular mandatory

training and communications help employees

understand how to apply it and how to raise

questions or concerns.

All bp employees are required to confirm

annually that they have read and understand

our code and act in accordance with its

principles. We expect and encourage all our

contractors and their employees to act in

ways that are consistent with it.

Any concerns or enquiries can be raised

through multiple speak-up channels. These

include line managers, senior leaders, and

contacts in our people & culture, ethics &

compliance, safety & operational risk

assurance or legal teams. We also have a

confidential global helpline, OpenTalk. It is

available for bp employees, the wider

workforce, communities, business partners

and other stakeholders and can be accessed

all day, every day by telephone or internet and

in 75 languages. Anyone has the right to

contact OpenTalk anonymously, except where

prohibited by law.

We take potential misconduct seriously and

thoroughly review allegations and respond,

conducting investigations where appropriate.

We may take action in response to reported

concerns to help proactively mitigate issues

around misconduct. We follow a defined

disciplinary process and will take action or

issue sanctions where appropriate. These may

include coaching or training, formal

reprimands or dismissal.

Nearly 5,000 concerns or enquiries were

reported in 2025 (2024 ~2,800). In 2025

around 1,300 separations resulted from non-

conformance with our code, including

unethical behaviour. Almost 90% of these

separations were from our retail business.

The most frequently raised concerns in 2025

related to alleged bullying, harassment and

discrimination, with these accounting for

around half of all concerns. The second

most common concerns related to allegations

concerning assets and financial integrity.

The 2025 mandatory code of conduct

training assigned to all bp employees

included a specific section on non-

harassment. Additionally, employees were

assigned a separate training module aimed

at preventing fraud.

---

| | |
|:---|:---|
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | <u>bp.com/codeofconduct</u> |

---

**Anti-financial crime**

We operate in parts of the world where bribery

and corruption present a high risk, so it is

important that we engage with our employees,

contractors, suppliers and others to

emphasize that our commitment to ethical and

compliant operations is unwavering.

Our code of conduct explicitly prohibits

engaging in any form of bribery, corruption or

money laundering and promotes lawful and

ethical business practices. It includes an

expectation that we work to make sure our

business partners comply with our

requirements.

Our group-wide policies covering anti-bribery

and corruption, anti-money laundering, anti-

fraud and anti-tax evasion all include measures

and guidance to assess risks, understand

relevant laws and report concerns. They apply

to all bp-operated businesses.

We provide appropriate training including

for those employees in locations or roles

assessed to be at a higher risk of bribery and

corruption, money laundering and fraud that

could benefit bp.

In 2025 around 8,100 employees completed

anti-bribery and corruption training as part of

our ethics and compliance risk-based learning.

This is higher than the 5,900 employees

trained in 2024, due to the rolling cadence we

use to assign training.

We also conduct anti-bribery compliance

audits on selected suppliers to assess their

conformance with our anti-bribery and

corruption contractual requirements. We take

corrective action with suppliers and business

partners who fail to meet our expectations,

which may include terminating contracts. In

2025 we issued 19 ABC supplier audit reports

(2024 32).

**Political donations and activity**

We prohibit the use of bp funds or resources

to support any political candidate or party.

We recognize the rights of our employees to

participate in the political process and these

rights are governed by the applicable laws in

the countries where we operate. Our stance

on political activity is set out in our code

of conduct.

In the US we provide administrative support

for the bp employee political action

committee (PAC) – a non-partisan, employee-

led committee that encourages voluntary

employee participation in the political process.

The bp employee PAC is governed by a board

of directors and administrative by-laws. All

contributions made by the bp employee PAC

are weighed against its criteria for candidate

support and reviewed for legal compliance

before funds are sent to the recipients

requested by our employees, and are publicly

reported in accordance with US election laws.

Contributions made by the PAC are from

employee contributions and not bp funds.

aThe number of employees eligible for a cash bonus in 2025 was around 43,500.

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

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 59 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

**Tax transparency**

We take a responsible and transparent

approach to tax, guided by our responsible tax

principles which align with our code of

conduct and our beliefs.

We comply with the tax legislation of the

countries in which we operate and we do not

tolerate the facilitation of tax evasion by

people who act for or on behalf of bp.

We are committed to transparency around

our tax principles and the taxes we pay. We

paid $8.3 billion in corporate income and

production taxes to governments in 2025

(2024 $10.6 billion).

---

| | |
|:---|:---|
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | *bp Tax Report*, <u>bp.com/tax</u> |

---

**Trade associations**

Trade associations and industry initiatives play

a key role in fostering collaboration, sharing

knowledge and bringing stakeholders

together.

We made changes to the way we review our

trade association memberships in 2025. We

reviewed those with membership fees of

$100,000 or more to identify any significant

misalignments or lack of influence on

relevant policy between the association

reviewed and bp.

---

| | |
|:---|:---|
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | <u>bp.com/tradeassociations</u> |

---

**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<sup>a</sup>

for select assets or regions, that help

manage potential impacts on and

opportunities for people as we transition.

• Fostering an inclusive culture with an

employee workforce that reflects the

communities where we work (read more

on page <u>[57](#i87f52fc5efef4a16865a4af06e1e7987_26448)</u>).

We recognize the importance of a just energy

transition – one that delivers decent work,

quality jobs and supports the livelihoods of

local communities. We report on our work to

equip employees with the skills they need now

and for the energy transition, and on how we

are supporting local communities in the *bp* 

*Sustainability Report 2025*.

**Human rights**

We believe everyone deserves to be treated

with fairness, respect and dignity. We respect

the rights of our workforce and those living in

communities where we operate, who are

potentially affected by our activities.

We set out our commitments in our human

rights policy and code of conduct. Our policy

aligns with the UN Guiding Principles on

Business and Human Rights.

It is underpinned by the International Bill of

Human Rights and the International Labour

Organization's Declaration on Fundamental

Principles and Rights at Work, including its

core conventions.

To support our teams, we provide human

rights training and other awareness-raising

activities.

---

| | |
|:---|:---|
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | <u>bp.com/humanrights</u> |

---

**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<sup>b</sup>, by:

• Aiming to achieve a net positive impact

(NPI) on all new in-scope<sup>c</sup> projects.

• Implementing biodiversity enhancement

plans at our major operating sites.

• Collaborating with others to support

selected biodiversity restoration projects.

Building on the work we did in 2022 to finalize

our NPI methodology for use on new, in-scope

projects, we have made consistent progress

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

By the end of 2025 six of our projects were

either implementing or developing NPI plans.

In addition, all our major operating sites in

biodiversity-sensitive areas had developed or

started to implement biodiversity

enhancement plans.

---

| | |
|:---|:---|
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | <u>bp.com/biodiversity</u> |

---

**Water**

We aim to reduce our net freshwater use in

stressed catchments where we operate<sup>b</sup>, by:

• Being more efficient with freshwater use in

our operations.

• Collaborating with others to replenish

freshwater in stressed<sup>d</sup> catchments. We

anticipate that by 2028, our freshwater

withdrawal in stressed catchments will be

covered by freshwater management plans.

To understand our water-related challenges,

we review water impacts, risks and

opportunities at our operating sites. These

reviews consider the quantity and quality of

water used as well as any applicable

regulatory requirements.

**Our water consumption in 2025**

Since 2020 we have reduced freshwater

withdrawals (excluding once through cooling

water) by 15% and freshwater consumption

by 15% against the baseline<sup>f</sup>. Reductions in

2025 were the result of operational

efficiencies at our Lingen refinery in Germany,

and at Whiting refinery and bpx energy Eagle

Ford facilities in the US.

At our major operating sites, 13% (2024 11%) of

our total freshwater withdrawals and 22%

(2024 20%) of freshwater consumption were

from regions with high or extremely high water

stress in 2025.

**Air emissions**

We monitor our air emissions – sulphur oxides,

nitrogen oxides and non-methane

hydrocarbons – and, where possible, put

measures in place to reduce the potential

impact of our operational activities on local

communities and the environment. In 2025 our

total air emissions were flat compared to 2024.

---

| | |
|:---|:---|
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | <u>bp.com/ESGdata</u> |

---

aWe will work to develop just transition plans with input from potentially affected stakeholders to help manage social risks and opportunities.

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

cNew bp-operated in-scope projects where planned activities have the potential for significant direct impacts on biodiversity are required to develop NPI action plans for those activities.

dThe threshold bp uses for stress is based on a water stress level of 'high' or above, as defined by the WRI Aqueduct Water Risk Atlas. bp determines areas of water stress using either the WRI

Aqueduct Water Risk Atlas or using site-specific local data sources.

eFollowing an update in 2024 to the basis for calculating freshwater withdrawal to align with the basis for calculating freshwater consumption and improve clarity and consistency, metrics based on

freshwater withdrawal data have been restated for the years 2020-23 to reflect the exclusion of once through cooling water, including the 2020 baseline.

fThe 2020 baseline for freshwater withdrawal is 96.4 million m<sup>3</sup> per year and for freshwater consumption is 55.9 million m<sup>3</sup> per year.

---

| | | |
|:---|:---|:---|
| 60 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Risk management and internal control**<br>

Risk management and

internal control

bp identifies, manages, monitors and reports

on the principal risks and uncertainties that

can impact our ability to deliver our strategy.

These are described in Risk factors on page <u>[67](#i0dd2ee81aac04f8c9c97c86197f0c6df_109)</u>.

**bp's system of internal control** 

**and risk management**

bp's system of internal control is a holistic set

of internal controls that includes policies,

processes, management systems,

organizational structures, culture and

standards of conduct employed to manage

bp's business and associated risks. Risk

management forms an integral part of this

system and operates as one of the key

mechanisms through which internal controls

are designed, implemented and monitored.

An effective approach to risk management is

central to how bp operates, supporting safe,

compliant, and reliable operations as well as

greater efficiency and sustainable financial

results that contribute to long-term business

resilience. Within the system of internal

control, bp's risk management system and risk

management policy are tailored to our

business model and governance structure and

align with the expectations of the regulatory

and governance regimes applicable to bp.

Where appropriate, they draw on recognized

international standards, including ISO 31000

and the COSO Enterprise Risk Management

framework, and are designed to provide a

consistent and clear framework for identifying,

assessing, managing (including responding to),

monitoring and reviewing, and reporting risks

from the group's business activities and

operations to management and the board.

The system seeks to avoid incidents and

enhance business outcomes by allowing us to:

• Understand the risk environment, identify

the specific risks and assess the potential

exposure for bp.

• Determine how best to deal with these risks

to manage overall potential exposure.

• Manage the identified risks in

appropriate ways.

• Monitor and seek assurance over the

effectiveness of the management of these

risks and intervene for improvement

where necessary.

• Report clearly and consistently to

management, the leadership team and the

board on how principal risks are being

managed, monitored and assured, with

any identified enhancements that are

being made.

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Risk oversight** <br>**and governance**<br>Our key risk oversight and <br>governance committees include:<br>**Board and committees**<br>•bp board.<br>•Audit committee.<br>•Safety and sustainability <br>committee.<br>•Remuneration committee.<br>•People, culture and governance <br>committee.<br>**Leadership team and** <br>**committees**<br>•Leadership team meeting – for <br>oversight and for strategic and <br>commercial risks.<br>•Group operational risk <br>committee – for health, safety, <br>security, environment and <br>operations integrity risks. Group <br>operational risk committee <br>(sustainability) – for <br>sustainability-related risks.<br>•Group financial risk committee – <br>for finance, treasury, trading <br>and cyber risks.<br>•Group disclosure committee – <br>for financial and non-financial <br>reporting risks.<br>•People and culture committee – <br>for employee risks.<br>•Group ethics and compliance <br>committee – for legal and <br>regulatory compliance and <br>ethics risks.<br>•Resource commitment meeting <br>– for investment decision risks.<br>•bp quarterly internal audit <br>meeting – for assurance on the <br>oversight of bp's principal risks. |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

![RiskManagementAndInternalControlV2.jpg](bp-20251231_g71.jpg)

---

| | |
|:---|:---|
| **Our risk management activities** | **Our risk management activities** |
|  | **Oversight and governance**<br>Set policy and monitor principal risks |
| The board and <br>committees<br>Leadership team <br>and committees<br>Businesses <br>and functions<br>Facilities, assets <br>and operations | **Oversight and governance**<br>Set policy and monitor principal risks |
| The board and <br>committees<br>Leadership team <br>and committees<br>Businesses <br>and functions<br>Facilities, assets <br>and operations |  |
| The board and <br>committees<br>Leadership team <br>and committees<br>Businesses <br>and functions<br>Facilities, assets <br>and operations | **Business and strategic risk management**<br>Plan, manage performance and assure<br>|
| The board and <br>committees<br>Leadership team <br>and committees<br>Businesses <br>and functions<br>Facilities, assets <br>and operations |  |
| The board and <br>committees<br>Leadership team <br>and committees<br>Businesses <br>and functions<br>Facilities, assets <br>and operations | **Day-to-day risk management**<br>Identify, manage and report risks<br>|

---

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Acquired businesses**<br>Integration plans are developed to <br>transition acquired businesses into <br>bp's system of internal control, <br>over an appropriate timeframe. |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | bp governance framework, page <u>[77](#i0dd2ee81aac04f8c9c97c86197f0c6df_136)</u>, board activities, page <u>[78](#i0dd2ee81aac04f8c9c97c86197f0c6df_139)</u>, and committee reports, pages <u>[82](#i0dd2ee81aac04f8c9c97c86197f0c6df_160)</u><u>-</u><u>[91](#ia422778a52d64a26b1673bf21b127e90_9184)</u>. |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 61 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Divested businesses**<br>Separation and transition plans are <br>used to divest businesses in a <br>controlled manner, with clear <br>allocation of responsibilities, <br>appropriate oversight of <br>transitional service arrangements, <br>and continued management of any <br>retained liabilities or obligations. |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

**Day-to-day risk management**

Management and employees at our facilities,

assets, and within our businesses (including

supply, trading & shipping) and functions seek

to identify and manage risk, promoting safe,

compliant and reliable operations. bp

requirements, which take into account

applicable laws and regulations, underpin the

practical plans developed to help reduce risk

and deliver safe, compliant and reliable

operations as well as greater efficiency and

sustainable financial results.

**Business and strategic** 

**risk management**

Our businesses and functions integrate risk

management into key business processes

such as strategy, planning, performance

management, resource and capital allocation

and project appraisal. They apply this by using

a standard framework for collating risk data,

assessing risk management activities, driving

further improvements, and informing

decisions on new or changing activities.

**Board oversight of risk and** 

**internal control** 

The board is responsible for establishing and

maintaining an effective risk management and

internal control framework, and for

determining the nature and extent of the

principal risks it is willing to take in order to

achieve its long-term strategic objectives.

Throughout 2025, management, the leadership

team, the board and relevant committees

provided oversight of how principal risks to bp

were identified, assessed, and managed. They

supported appropriate governance of risk

management, including having relevant

policies in place to help manage risks.

Such oversight may include internal audit

reports, group risk reports and reviews of the

outcomes of business processes including

strategy, planning and resource and capital

allocation. bp's group risk team analyses the

group's risk profile and maintains the group's

risk management system.

**Risk management processes**

bp's risk management processes help

underpin the long-term resilience of our

business model by promoting transparent,

risk-informed decision making and the

identification and management of risks and

potential opportunities aligned with bp's

strategic priorities. These include existing

processes and sources of insight to consider

emerging risks or opportunities, such as

emerging risk communications to the board,

bp's risk management system, the *bp Energy* 

*Outlook*, bp's technology-related news and

insights, ongoing emerging technology

scanning and strategy reviews. They also

include ongoing enhancements to our system

of internal control and risk management,

which are informed by lessons learned and

evolving governance expectations.

We aim for a consistent basis of measuring

risk to:

• Establish a common understanding of risks

on a like-for-like basis, taking into account

potential impact and likelihood.

• Report risks and their management to the

appropriate levels of the group.

• Inform prioritization of specific risk

management activities and resource

allocation.

bp's risk management policy sets out

requirements for the group to follow. These

requirements support the consideration of

three risk types:

• Strategic and commercial.

• Safety and operational.

• Compliance and control.

**Risk identification** – our businesses and

functions identify risks across these risk types

on an ongoing basis, using a range of

approaches including risk workshops, subject-

matter expertise, hazard identification

processes and engineering requirements.

**Risk assessment** – identified risks are

assessed for potential impact and likelihood

on a worst credible and net (residual) basis

across a number of criteria, including health

and safety, environmental, financial and non-

financial (including reputation and regulatory

impact levels). This provides a consistent basis

for evaluating and comparing risks.

**Risk response, monitoring, and reviewing** –

risk management activities are prioritized

where improvements are needed based on

a number of factors, including the risk

assessment, strength of existing risk

management measures, strategy and plans

and legal and regulatory requirements. Risk

management measures, including mitigations,

are identified for each risk and monitored to

the extent considered appropriate. To

support leadership oversight of decisions

relating to risk management, the appropriate

organizational levels (EVP, SVP, VP) are

notified of risks and asked to endorse risk

management plans, depending on the

assessed potential impact and likelihood.

As part of bp's annual planning process, the

leadership team and the board review the

group's principal risks and uncertainties.

These may be updated during the year in

response to changes in internal and external

circumstances. Emerging risks are also

considered when determining whether

updates to the group's principal risks

are required.

**Risk reporting** – risk information is reported

through a structured cadence that supports

timely escalation and oversight. Businesses

and functions provide updates on changes in

risk exposure, progress of planned risk

management actions, and the strength of risk

management measures, including mitigations.

This enables consistent aggregation across

the group and supports management, the

leadership team and the board in monitoring

and reviewing bp's principal and emerging

risks and overall risk profile.

**Assurance and internal audit**

bp's internal audit team provides independent

and objective assurance to the chief executive

and the board on the adequacy and operating

effectiveness of bp's system of internal

control, including risk management

arrangements. Internal audit reports, thematic

findings, and improvement recommendations

are considered by the board and committees

as part of their oversight.

The group risk team maintains the risk

management and internal control framework,

analyses the group's risk profile, and provides

further oversight and reporting.

Assurance activities across management,

specialist risk and control functions and

internal audit are aligned with bp's principal

risks and underpin the effectiveness of bp's

risk management and internal control

framework.

---

| | | |
|:---|:---|:---|
| 62 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Principal risks and uncertainties (Risk factors)**<br>

Principal risks and uncertainties

The risks discussed below, individually or in combination, could have a material adverse effect

on the implementation of our strategy and business model, financial performance and financial

condition, cash flows and liquidity, operational delivery, reputation, and long-term shareholder

value. These are the risks the board considers to be bp's principal risks and uncertainties

(or Risk factors).

**Our risk profile** 

The nature of our business is long term,

meaning many of our risks are enduring in

nature. However, risks can develop and evolve

over time, and their potential impact or

likelihood may vary in response to internal and

external events.

During 2025, the board conducted a review of

the group's principal risks, informed by bp's

updated strategy, changes in our operating

environment, stakeholder expectations, and

the board's commitment to maintaining clear

and effective oversight. Following this review,

the board approved a streamlined set of 16

principal risks (previously 20).

The reduction does not reflect a change in bp's

underlying risk exposure; rather, the principal

risks have been reorganized to align with how

risks are governed and managed across the

group. Certain items previously presented as

standalone risks, such as insurance, and crisis

and business continuity management, are now

reflected within broader control and response

capabilities that support multiple principal

risks. In addition, some risks have been

combined, where appropriate, to remove

duplication and present a single view of

related drivers, accountability, and impacts.

**Strategic and commercial risks**

**Commodity prices and market** 

**environment**

Our financial performance is impacted by

fluctuations in the prices of oil, natural gas,

refined products, and emerging energy

commodities due to factors such as volatile

energy markets, exchange rates, or structural

shifts in demand and supply, policy, or trade

(such as carbon pricing or LNG flows).

These prices are affected by factors such as

global supply and demand dynamics, the

actions of key market participants (including

OPEC+), and a range of external factors such

as geopolitical instability, public health

situations (including the outbreak of an

epidemic or pandemic), sanctions, trade

tariffs, and policy interventions that impact

energy flows.

Prolonged periods of low commodity prices

may reduce revenue, margins, and cash flow,

potentially requiring asset impairments, or a

reprioritization of strategic activity and may

also impact our ability to work within our

financial frame including potential reductions

in capital investment. Conversely, higher

prices do not always translate into improved

returns due to fiscal regimes, cost inflation, or

constrained market access.

In refining, profitability can be volatile and

is affected by regional supply and demand

imbalances (including regional oversupply

or tightness, demand shifts, shifts in product

mix, feedstock availability, and crack

spread volatility).

Currency movements – particularly where

revenues and capital costs are denominated

in different currencies – also impact project

economics and reported earnings.

Broader structural shifts, such as the pace of

the energy transition, evolving climate policy,

carbon pricing mechanisms, consumer

preferences, and the realignment of global

energy trade (e.g. LNG flows, carbon border

adjustments) may lead to enduring changes

in market conditions. These shifts could

affect the long-term competitiveness or

economic viability of existing assets and

investment plans.

**Accessing and producing** 

**hydrocarbon resources**

Failure to adequately access, develop or

sustain production of hydrocarbon resources

may result in delivery delays, missed strategic

targets and adversely impact our financial

performance and undermine our reputation.

Our ability to generate value depends on

successfully identifying, accessing,

developing, and sustaining reliable production

of hydrocarbon resources at pace and scale.

This requires securing access; navigating

geopolitical and regulatory complexity;

effective and timely development and

deployment of technologies; delivering

projects on time; and executing with

operational and commercial discipline.

Delivery risks may arise from joint venture

misalignment, production reliability issues,

or extended unplanned outages across the

hydrocarbon value chain. Our activities are

sometimes conducted in challenging

environments such as those prone to natural

disasters and extreme weather events, which

heightens the risks of technical integrity

failure. The physical characteristics of an oil

or natural gas field, and cost of drilling,

completing or operating wells are inherently

uncertain. We may be required to curtail, delay

or cancel drilling operations or stop

production because of a variety of factors,

including unexpected drilling conditions,

pressure or irregularities in geological

formations, equipment failures or accidents,

adverse weather conditions and compliance

with governmental requirements. Such

outages can materially impact value,

erode investor confidence, and delay

strategic delivery.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 63 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

This risk is increased in politically sensitive

jurisdictions, under volatile fiscal regimes, or

where accountability for portfolio progression

is unclear following divestments – near to

medium-term value remains heavily

dependent on competitive, reliable

hydrocarbon delivery. Sustained

underperformance, partner misalignment, or

high-profile project delays could limit reserve

replacement and constrain growth.

**Major project delivery**

Failure to invest in the best opportunities or

deliver major projects★ successfully could

adversely affect our financial performance and

long-term competitiveness.

Our ability to select, define, execute, and

deliver large-scale, capital intensive, physical

projects (such as field developments,

refineries and infrastructure expansions) is

critical to our financial performance and

resilience. These projects are often complex

and executed in technically demanding,

geopolitically sensitive or geographically

challenging environments. Additional factors

such as extreme weather events or regulatory

constraints can affect schedule and cost

performance.

Major projects are often delivered through

joint ventures, strategic partnerships, or third-

party-led models, which can constrain our

control and influence over delivery,

governance, and standards.

The selection and design of our major projects

need to be resilient to the impact of severe

weather events (e.g. metocean criteria) and

other environmental factors (e.g. water

scarcity).

Potential risks include ineffective investment

prioritization, subsurface uncertainty,

capability constraints, supply chain disruption,

inflationary pressure or delays in permitting,

regulatory approval, commercial agreements,

or execution.

A failure to deliver key projects to schedule,

scope, budget, quality, or HSE standards may

lead to cost overruns, delays in production or

revenue, reputational harm, impairment, or

loss of licence to operate.

**Geopolitical exposure**

The diverse locations of our business activities

and operations around the world expose us to

a wide range of geopolitical developments

(including sanctions, trade route restrictions,

civil unrest, conflict, or government

intervention).

Geopolitical risks arise from operating in

jurisdictions undergoing political, regulatory,

or economic transition – and from broader

societal, ideological, and technological shifts –

including changes to taxation or regulatory

regimes, international sanctions, trade

restrictions, expropriation or nationalization of

property, civil strife, strikes, insurrections, acts

of terrorism, acts of war, and public health

situations (including the outbreak of an

epidemic or pandemic).

These events have, and can, disrupt business

activities and operations, restrict access to key

markets, and adversely affect financial

performance, long-term growth opportunities,

or reputation.

Rising bloc politics, energy nationalism, and

alliance-driven policy divergence could further

fragment global trade and investment

patterns, influencing where bp may operate,

partner, pursue business opportunities and

compete. Competition over critical minerals

and low carbon technologies is increasingly

geopolitical, shaping access to resources

and markets.

Geopolitical rivalry extends into technology

and cyber domains, exposing potential

operational and reputational vulnerabilities

linked to supply-chain sovereignty, data

integrity, and industrial security. Political

instability, shifts in alliances, or increased

government intervention may lead to barriers

to market access, disruptions in supply chains,

or challenges in executing existing or planned

operations. Divergent or extraterritorial

regulations (including sanctions, data, and

carbon border mechanisms) may create

conflicting legal obligations and compliance

complexity across jurisdictions.

Such events may also affect investor

sentiment, financing conditions, and access to

capital. Growing fragmentation of global trade

and regulation, coupled with rising energy

nationalism and polarized international

alliances, may exacerbate volatility in energy

supply, demand, and prices. Our exposure to

particular jurisdictions, vendors, and

technologies exposes us to the potential for

geopolitical tensions to intersect with

performance delivery, investor sentiment,

and stakeholder trust.

**Liquidity, capital access and** 

**financial resilience**

External market conditions can impact our

ability to maintain liquidity, credit strength, or

access to capital markets which could impair

our ability to operate, meet financial

commitments, or deliver our strategy.

Market volatility, operational incidents, legal

proceedings, regulatory actions, or

geopolitical crises could reduce access to

funding or trigger unexpected calls on cash,

even where insurance or other risk transfer

mechanisms exist. A significant liquidity event

or credit rating downgrade could lead to

higher financing costs, constrained access to

capital, and reduced financial flexibility,

forcing us to reprioritize investment, reduce

expenditure, or accelerate planned or

unplanned divestments or dilutions,

potentially at less than the full market value.

We are also exposed to credit risk through

financial counterparties, joint ventures, trading

partners, receivables, customers, delays in

settlements, receipt of divestment proceeds,

or divestments not completing when planned.

All can impact cash flow and our ability to work

within our financial frame and in more severe

cases, we may need to review and reallocate

financial commitments or long-term

obligations such as pension funding

arrangements.

Maintaining confidence with investors, lenders,

and credit rating agencies is essential to

preserving financial resilience and access to

affordable funding, especially during periods

of capital scarcity or policy uncertainty.

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Energy markets, page <u>[6](#i0dd2ee81aac04f8c9c97c86197f0c6df_25)</u> <br>Liquidity and capital resources, page <u>[338](#i0dd2ee81aac04f8c9c97c86197f0c6df_484)</u> <br>Liquidity, financial capacity and <br>financial, including credit, exposure, <br>page <u>68</u><br>|

---

---

| | | |
|:---|:---|:---|
| 64 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Principal risks and uncertainties (Risk factors)** continued<br>

**Partner and third-party risk** 

The performance, standards, or compliance of

non-operated joint ventures, strategic

partners, contractors, sub-contractors, or

other third parties could expose bp to legal,

operational, financial, or reputational harm.

Many of our business activities are conducted

through partners and third parties – including

non-operated joint ventures, strategic

partners, contractors, sub-contractors, and

suppliers – where we may have limited

influence and control over performance

or compliance.

Our partners and contractors are responsible

for the adequacy of their resources and

capabilities, and there may be financial,

reputational, operational or safety exposures

and consequences for bp if their performance,

risk management or governance standards are

inadequate, including their safety practices,

cyber-attacks, quality or delivery of work,

financial management, legal compliance,

advocacy positions, and environmental, social

and governance (ESG) standards.

In some cases, third parties may not be able or

may not be willing to compensate us against

all of the costs we may incur on their behalf, or

pay their share of losses and liabilities which

may arise in connection with the activities in

which they have participated. Irrespective of

whether or not bp controls or has direct

oversight of third parties, we may still be

pursued by regulators or claimants, and may

still be the focus for interest groups or media

attention in the event of an incident.

**Digital, cyber security and data risk**

Increasing reliance on digital infrastructure,

growing AI adoption, and evolving cyber

threats exposes bp and our third-party

suppliers and contractors to data loss,

infrastructure failures, or system compromise

which could result in operational disruption,

regulatory breaches, significant fines and

reputational harm.

bp's digital infrastructure, data platforms,

applications and connected technologies are

core enablers to our businesses, operations,

trading activities, customer engagement,

and corporate functions. These systems face

fast-evolving cyber threats – including

ransomware, nation-state interference,

and insider attacks – amplified by complex

third-party ecosystems and AI-enabled

technologies.

A breach or failure of our third-party supplier's

or contractor's digital systems, including

operational technology and cloud

environments, could result in the loss, misuse,

or compromise of sensitive data – including

personal, operational, or commercial

information.

The loss or misuse of data or sensitive

information, including employees' and

customers' personal data, injury to people,

disruption to our business, harm to the

environment or our assets, legal or regulatory

breaches, may result in legal liability and

significant costs including fines, cost of

remediation or reputational consequences.

At the same time, the rapid advancement and

scaling of generative and agentic AI – including

predictive technologies – presents both

significant opportunities and emerging

systemic risk. Without clear organization-wide

governance, bp may underperform, miss

strategic upside, or fall behind on safe and

compliant AI deployment.

Critical national infrastructure, data protection

and privacy regulations – particularly in

sensitive geographies – continue to grow,

increasing expectations on security, data

sovereignty, ethical use of AI, and

accountability for data handling. This reflects

the strategic importance of establishing and

maintaining resilience, trust, and performance

in a fast-digitizing environment. For more on

cyber security see page <u>[360](#ib863958fc308431f86668b4296ac7c85_2895)</u>.

**Climate change and the transition to a** 

**lower carbon economy**

Developments in policy, law, regulation,

technology and markets, including societal

and investor sentiment, related to the issue of

climate change and the transition to a lower

carbon economy could increase costs, reduce

revenues, constrain our operations and affect

our business plans and financial performance.

Laws, regulations, policies, obligations,

government actions, social attitudes and

customer preferences relating to climate

change and the transition to a lower carbon

economy, including the pace of change to any

of these factors, and also the pace of the

transition itself, could have adverse impacts

on our business including on our access to and

realization of competitive opportunities, a

decline in demand for, or constraints on our

ability to sell certain products, constraints on

production and supply, adverse litigation and

regulatory or litigation outcomes, increased

costs from compliance and increased

provisions for environmental and legal

liabilities.

Investor preferences and sentiment are

influenced by ESG considerations including

climate change and the transition to a lower

carbon economy. Changes in those

preferences and sentiment could affect our

access to capital markets and our

attractiveness to potential investors,

potentially resulting in reduced access to

financing, increased financing costs and

impacts upon our business plans and

financial performance.

Technological improvements or innovations

that support the transition to a lower carbon

economy, and customer preferences or

regulatory incentives that alter fuel or power

choices, could impact demand for our

products (including low carbon energy).

Depending on the nature and speed of any

such changes and our response, these

changes could increase costs, reduce our

profitability, reduce demand for certain

products, limit our access to new

opportunities, require us to write down certain

assets or curtail or cease certain operations,

and affect investor sentiment, our access to

capital markets, our competitiveness and

financial performance.

Policy, legal, regulatory, technological and

market developments related to climate

change could also affect future price

assumptions used in the assessment of

recoverability of asset-carrying values. This

may affect whether there is continued intent

to develop exploration and appraisal of

intangible assets; the timing of

decommissioning of assets; and the useful

economic lives of assets used for the

calculation of depreciation and amortization.

**Competitiveness**

Failure to maintain a competitive strategy,

underpinned by a strong portfolio of assets,

cost performance, innovative technology,

projects and long-term growth opportunities,

could negatively impact our investors'

confidence in our ability to grow long-term

shareholder value and returns.

We operate in an increasingly complex, fast-

paced, ever-changing, competitive global

energy market with evolving competitor

strategies. As an integrated energy company,

our ability to remain competitive with a

compelling, differentiated proposition for

stakeholders depends on the quality and

agility of our strategic, commercial, and

operational decisions and the execution of

those decisions including those related to

costs, capital allocation, innovation,

technology adoption, portfolio development,

customer propositions, and talent

deployment.

We could be adversely affected if we fail to

anticipate or respond effectively to rapid shifts

in policy, consumer preferences, investor

expectations, and disruptive competitor

activity or fail to protect our intellectual

property, increasing the risk of constrained

operations and diminished returns, and

shareholder expectations.

Ineffective communication of our strategic

direction and a compelling value proposition

could undermine stakeholder confidence and

investor expectations of bp's long-term value.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 65 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

**Talent, leadership and** 

**organizational capability**

Failure to retain, develop, and attract the

talent, leadership, capabilities and behaviours

required to deliver our strategy could weaken

performance, culture, and long-term value

creation.

To manage our costs competitively and build

our resilience, we look to simplify and digitalize

our processes while evolving our skills and

capabilities, in line with our strategy and global

market trends. Failure to manage change and

transfer knowledge appropriately could

decrease efficiency, weaken performance and

increase costs.

We face growing competition for high-calibre

talent across a diverse set of business and

function portfolios, and a broad set of

geographies.

Expectations around organizational culture,

ways of working, leadership behaviours, and

career development opportunities must be

balanced with disciplined performance and

shared values and behaviours. Failure to

attract, develop and retain the right talent,

could result in delivery shortfalls, diminished

competitiveness, and erosion of stakeholder

trust. For more on our people see page <u>[56](#i87f52fc5efef4a16865a4af06e1e7987_46404)</u>.

**Safety and operational risks**

**Process safety, personal safety and** 

**environmental risks**

bp's operations and business activities are

exposed to a wide range of safety, operational

integrity, and environmental risks – particularly

under growing complexity and delivery

intensity – which could result in major

incidents that harm people or the

environment, disrupted operations, damage

to bp's reputation, legal liability, undermine

our financial standing or threaten our licence

to operate.

bp operates in complex and high-risk

environments where process safety, personal

safety, occupational health, technical integrity,

transportation, marine operations, and

environmental risks could result in major

incidents with significant human,

environmental, financial, and reputational

consequences. As a result, we could face

regulatory action and legal liability, including

penalties and remediation obligations,

increased costs and, potentially, denial of our

licence to operate.

Despite safety controls, barriers, and

management systems, failures may still occur

due to technical breakdowns, equipment

failure, human error, extreme (acute or

chronic) weather and climate-related factors,

or third-party actions.

Risk exposure is heightened during drilling,

production, marine transport and logistics,

pipeline operations, project construction or

maintenance activities – especially in

environmentally sensitive (e.g. areas of water

scarcity, biodiversity), remote or geologically

complex locations, or where infrastructure

reliability and emergency response

capabilities are constrained. These risks

extend to both the public and our workforce

and contractors, including physical safety, life-

saving rule violations, and occupational health

exposures such as chemical, biological,

psychosocial, or infectious risks.

Past incidents across the industry have

resulted in fatalities, significant spills, long-

term environmental damage, large-scale

remediation costs, and lasting reputational

harm. bp's ability to maintain the technical

integrity of its assets, retain its licence to

operate and meet stakeholder expectations,

depends on consistently high performance in

safety and environmental execution across

the portfolio.

As bp continues to scale delivery across a

more diversified portfolio it remains essential

that safety systems, controls, and

organizational safety culture are maintained

and strengthened at every level of the

business to prevent serious failures, provide

operational continuity, and uphold trust with

stakeholders.

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Safety, page <u>[55](#i87f52fc5efef4a16865a4af06e1e7987_26441)</u>  |

---

**Security**

Hostile acts such as terrorism, civil unrest,

armed conflict, sabotage, activism, piracy,

insider threats, workplace violence, cyber-

enabled physical attacks, or threats to

personnel security such as kidnapping or

detention could harm our people, disrupt

operations, compromise critical assets, or

damage our reputation.

Security threats may emerge or intensify in

response to geopolitical instability, conflict, or

state-linked activity that could target critical

infrastructure or supply chains. They may also

be politically, ideologically, or financially

motivated and influenced by regional

instability, activism, social unrest, or bp's

presence in higher-risk geographies.

Increasing interdependence between cyber,

information, and physical domains may create

additional vulnerabilities across operational

technology, logistics, and data-driven systems.

Assets such as pipelines, terminals,

transportation routes, offshore platforms, and

operational-technology systems could be

particularly exposed. The risk of insider activity

– including unauthorized data access,

sabotage, or information leakage – is also a

continuing concern, particularly in complex

joint ventures or politically sensitive

environments.

The consequences of a major security incident

could include operational shutdown, financial

loss, workforce harm, legal costs and liabilities

or reputational damage. More broadly, a

significant incident could disrupt supply

chains, invite regulatory scrutiny, or adversely

affect confidence in bp's ability to operate

safely and reliably in challenging

environments.

**Product quality**

Failure to supply products to customers, meet

technical specifications or regulatory

standards could lead to harm, operational

disruption, reputational damage, or legal and

financial consequences.

bp provides products – including fuels,

lubricants, petrochemicals, biofuels, and

consumables – that meet technical

specifications, regulatory requirements, and

customer expectations. We operate a complex

global value chain spanning production,

refining, blending, transportation, and delivery.

Failures may arise at any point in this chain due

to contamination, formulation errors, process

deviation, mislabelling, equipment failure, or

inadequate quality assurance.

Product quality risks may originate upstream

(e.g. formation variability, production

chemistry), midstream (e.g. blending

inconsistencies, custody transfer), or

downstream (e.g. additives, packaging,

distribution). Failures can result in safety

incidents, environmental harm, damage to

customer equipment, product recalls, legal

liability, and loss of brand trust.

As customer expectations and regulatory

regimes evolve – particularly regarding

decarbonized and high-integrity products –

maintaining end-to-end product integrity is

critical to safeguarding our reputation,

maintaining brand trust, securing market

access, and protecting long-term commercial

relationships. Widespread or high-profile

failures could result in product recalls, legal

exposure, or reputational harm – especially in

regulated or safety-critical sectors.

---

| | | |
|:---|:---|:---|
| 66 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Principal risks and uncertainties (Risk factors)** continued<br>

**Compliance and control risks**

**Legal, regulatory and ethical compliance**

Ethical misconduct, non-compliance with law

and regulation or changes in law and

regulation could increase costs, constrain our

operations and affect our strategy, business

plans and financial performance. Incidents of

ethical misconduct or non-compliance could

also damage our reputation and result in

litigation, regulatory action, penalties and

potentially affect our licence to operate.

Incidents of ethical misconduct or non-

compliance with applicable laws and

regulations, including anti-bribery and

corruption, competition and antitrust, data

privacy, and anti-fraud laws, trade restrictions

or other sanctions, could damage our

reputation, and result in litigation, regulatory

action, penalties and potentially affect our

licence to operate. In relation to trade

restrictions or other sanctions, current

geopolitical factors have increased these risks.

Our businesses and operations are subject to

the laws and regulations applicable in each

country, state or other regional or local area in

which they occur. These laws and regulations

result in an often complex, uncertain and

changing legal and regulatory environment for

our global businesses and operations.

Changes in laws or regulations, including how

they are interpreted and enforced, can and do

impact all aspects of our business.

Royalties and taxes, particularly those applied

to our hydrocarbon activities, tend to be high

compared with those imposed on similar

commercial activities. In certain jurisdictions

there is also a degree of uncertainty relating to

tax law interpretation and changes.

Governments may change their fiscal and

regulatory frameworks in response to public

pressure on finances or for other policy

reasons, resulting in increased amounts

payable to them or their agencies.

Changes in law or regulation could increase

the compliance and litigation risk and costs,

reduce our profitability, reduce demand for or

constrain our ability to sell certain products,

limit our access to new opportunities, require

us to divest or write down certain assets or

curtail or cease certain operations, or affect

the adequacy of our provisions for pensions,

tax, decommissioning, environmental and

legal liabilities.

Changes in laws or regulations could result in

the nationalization, expropriation, cancellation,

non-renewal or renegotiation of our interests,

assets and related rights. Potential changes to

pension or financial market regulation could

also impact funding requirements of the

group. Following the Gulf of America oil spill,

we may be subjected to a higher level of fines

or penalties imposed in relation to any alleged

breaches of laws or regulations, which could

result in increased costs.

**Financial and physical commodity** 

**trading activities**

We undertake physical and financial trading

across global commodity and financial

markets. Risk associated with our trading

activities could arise from a failure to maintain

robust oversight, controls, and disciplined

execution in our trading activities which could

result in business disruption, financial loss,

regulatory action, or reputational damage.

We conduct physical and financial trading

across global commodity and financial

markets, both on exchange and 'over the

counter', some of which are financially

regulated activities. Our trading activities

expose us to multiple risks, including market,

credit, operational, conduct, liquidity and

regulatory risks. Failure to maintain effective

oversight and controls, and disciplined

execution in our trading activities, could result

in business disruption, financial loss,

reputational harm, regulatory intervention,

and/or impair our ability to operate.

There is a risk that a single trader or a group of

traders could act outside of our delegations

and controls, leading to regulatory

intervention and resulting in financial loss,

fines and potentially damaging our reputation,

and could affect our permissions to trade.

**Integrity of financial and non-financial** 

**reporting**

Failure to maintain integrity in financial and

non-financial reporting may result in material

misstatement or regulatory breach, which

could lead to regulatory action, legal liability

and reputational damage.

The accuracy and reliability of our external

reporting depends on the strength of our

internal control environment, the robustness

of our systems and data governance, and

our people.

Failure to accurately report our data –

including financial results, sustainability and

environmental, social and governance

disclosures, reserves estimates, and

operational performance – could lead to

regulatory action, legal liability, investor action

and reputational damage.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 67 |

---

---

| | |
|:---|:---|
|  | ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
|  | **Strategic report** |
| **How we manage principal risks and uncertainties** | **How we manage principal risks and uncertainties** |

---

## How we manage principal risks
and uncertainties

bp manages its principal risks and uncertainties through our system of internal control

(described earlier in this section). The following pages set out the key risk management

activities for each principal risk.

There can be no certainty that our risk

management activities will mitigate or prevent

these, or other risks, from occurring. Further

details of the principal risks and uncertainties

faced are set out on page <u>[62](#i0dd2ee81aac04f8c9c97c86197f0c6df_6396)</u>.

**Strategic and commercial risks**

**Commodity prices and market environment:** 

We seek to manage this risk through market

analysis and strategic scenario planning, which

inform our portfolio, business development,

and capital allocation decisions. This analysis

draws on internal and external data sources

provided by our global energy and trading

insights teams (supply, trading & shipping

(ST&S) and economics & energy insights).

Outputs are integrated into our planning and

investment governance processes and

reviewed regularly by management.

We assess the implications of price, margin,

and exchange rate volatility across a range

of scenarios and test the robustness of

investment cases against changing

macroeconomic and regulatory assumptions.

The *bp Energy Outlook* is updated annually

to reflect shifts in policy, demand, and

trade patterns.

Our strategy is designed to remain resilient

across a wide range of market conditions. This

is supported by a diversified portfolio, a

disciplined financial frame, and an ongoing

focus on capital efficiency and investment

flexibility.

**Accessing and producing hydrocarbon** 

**resources:** We seek to manage this risk

through our subsurface teams in production &

operations (P&O) and gas & low carbon energy,

who have responsibility for accessing and

progressing hydrocarbons resources. The

teams are accountable for delivering high-

value resources to support our strategic and

financial goals. They work closely with

technology and other enabling functions to

assess resource potential, prioritize

opportunities, and advance viable projects.

P&O executes capital and operational activities

and is accountable for safe, competitive, and

efficient delivery.

Risk management is embedded through our

Operating Management System★ (OMS) and a

suite of supporting frameworks embed quality,

control, and investment discipline. These

include the Exploration Common Process,

Discovered Resource Management, Area

Development Planning, and the Group

Investment Assurance and Approvals Process

(GIAAP). Together, they guide how we identify,

evaluate, approve and deliver access and

development opportunities. Data often

enables our ability to pivot and adjust plans

after a materialized risk.

This risk is monitored through established

governance and management processes,

including regular review of performance

indicators, assurance outcomes, and incident

learnings, with escalation through appropriate

executive and board-level forums where

required.

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Our strategy, page <u>[8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31)</u> |

---

**Major project delivery:** We seek to manage

this risk through a structured, disciplined

approach to investment appraisal, project

execution, and performance governance. Our

projects organization exists to assess, develop,

and execute projects across bp, providing

deep technical expertise in capital delivery,

design, execution, and integration. It operates

under a globally aligned Project Delivery

Common Process, adapted to project size,

complexity, and risk.

Major projects are subject to rigorous

assurance throughout the lifecycle – from

early framing and appraisal through to

commissioning and performance evaluation.

Defined stage gates, verification reviews, and

central investment governance provide

disciplined decision making and alignment to

strategic objectives.

A structured management of change process

enables any technical, commercial, or scope

variations can be assessed, approved and

documented through appropriate governance

channels, helping to protect cost, schedule

and safety integrity.

Within the design phase of our projects, we

consider metocean criteria against historic

and projected models and environmental

impact factors.

Investments are evaluated against a balanced

set of investment criteria – for example,

assessment of economics includes a set of

price assumptions that reflects our view of

market evolution and the economics of all

investment cases where bp's share of annual

greenhouse gas (GHG) emissions from

operations are anticipated to exceed certain

thresholds include a carbon price for those

emissions.

Oversight is maintained through performance

reviews, supplemented by discipline checks,

post-project evaluations, and capital

forecasting cycles. Cross-functional forums

provide alignment between project,

commercial, and procurement functions. This

governance framework enables consistent

assurance, early identification of delivery

challenges, and investment decisions aligned

with strategic and performance expectations.

Note: Large-scale digital or transformation

programmes that interface with capital

delivery are assessed through equivalent

governance and assurance to protect

schedule, cost, and performance integrity.

---

| | | |
|:---|:---|:---|
| 68 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**How we manage principal risks and uncertainties** continued<br>

**Geopolitical exposure:** We seek to manage this

risk through intelligence and international

advisory, which integrates geopolitical horizon

scanning, strategic and baseline threat

assessments, deal-specific risk support, and

the New Country Entry process. Together,

these mechanisms support real-time decision

making, portfolio resilience, and longer-term

strategic investments.

Our geopolitical advisory council provides an

independent perspective on macro-level

geopolitical trends.

At an operational level, we have defined

government-relations and stakeholder-

engagement processes that seek to maintain

trusted relationships in host countries. Where

appropriate, risk mitigation and contingency

plans are developed, and ongoing monitoring

is overseen through intelligence, security and

crisis management.

**Liquidity, capital access and financial** 

**resilience:** We seek to manage this risk

through a combination of governance,

planning, and treasury controls, including:

Financial frame governance provides a

disciplined approach to capital allocation,

balance sheet strength, and investment

priorities. This helps bp maintain a resilient

dividend, a strong investment-grade credit

rating, and a clear hierarchy of capital uses,

supported by regular board and group

financial risk committee review.

Our disciplined Liquidity Management

Framework (LMF), which is embedded within

the treasury function and reviewed regularly

by senior management, defines clear

thresholds for undrawn committed credit

facilities, minimum cash buffers, liquidity

stress testing parameters, and monitoring

routines. The LMF also integrates our

Commercial Paper (CP) programme, governs

the investment of treasury cash with defined

exposure limits, and connects with the capital

markets team to issue securities that sustain

cash levels.

Together, these frameworks help create a

strong, flexible balance sheet, preserve access

to capital markets, and enable us to respond

effectively to external shocks or market

disruptions.

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Liquidity and capital resources, page <u>[338](#i69d6ea66cd0c4b60ad7705231f2bc986_13053)</u> <br>Financial statements – Note 29<br>|

---

**Partner and third-party risk:** We seek to

manage partner and third-party risk, including

exposure from non-operated joint ventures,

contractors, and sub-contractors, through a

combination of governance, self-verification &

oversight, assurance, and commercial controls

designed to provide proportionate oversight

and influence where bp does not have

operational control.

For joint ventures, accountability for day-to-

day oversight rests with the business unit or

function holding bp's equity interest,

supported by non-operated joint venture

solutions, which provides guidance on risk

exposure management, strategic governance,

self-verification & oversight, and assurance.

Exposure in non-operated joint ventures is

monitored through a risk barometer, periodic

risk reviews, and targeted assurance activities,

with escalation to executive or board-level

committees where appropriate.

For contractors, suppliers, and other third

parties, we apply a structured procurement

framework. This includes pre-engagement and

ongoing due diligence covering financial

stability, legal compliance, anti-bribery and

corruption (ABC), labour practices, cyber

security, and sustainability performance.

Supplier relationships are tiered (transactional,

core, strategic) to provide proportionate

oversight, and key contracts embed our

expectations and standards on safety, ethics,

and operational integrity.

We review and, where appropriate, enhance

governance arrangements for strategic

partnerships, capital-light ventures, and high-

exposure third parties as part of our

established oversight cycle to confirm that

assurance and engagement are

commensurate with bp's level of influence and

potential exposure.

Together, these measures support informed

oversight of our third-party relationships and

help protect bp's delivery, integrity, and

reputation where operational control is limited.

**Digital, cyber security and data risk:** We seek

to manage this risk through an approach

aligned with global standards, including the

National Institute of Standards and

Technology Cybersecurity Framework, as well

as our internal requirements for cyber security,

digital infrastructure, data privacy, and

responsible AI. Our controls span cyber

defence tools, resilience testing, third-party

oversight, and ethical data governance.

We continuously monitor the evolving threat

landscape and emerging technologies –

including AI, quantum computing, and cloud

infrastructure – to identify potential

vulnerabilities and disruptors. Cyber threat

detection, security testing, and ethical hacking

are supported by incident response protocols

and a delegated authority model to isolate or

disconnect operations when needed. We

actively manage our resilience capability and

maturity, with the ability to activate protocols

to restore systems and data to protect

prioritized critical business outcomes while

minimizing disruption.

We collaborate with government bodies, law

enforcement, and industry peers to track and

respond to fast-evolving threats. We reinforce

a culture of digital responsibility through

employee training, exercises (including

prolonged IT outage scenarios) to test

response and recovery procedures, and

executive-level briefings. Regular maturity

assessments and operational reviews help

track organizational resilience across

infrastructure, data, and third-party digital

dependencies.

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Cyber security disclosures, page <u>[360](#ib863958fc308431f86668b4296ac7c85_2895)</u> |

---

**Climate change and the transition to a** 

**lower carbon economy:** Developments in

policy, law, regulation, technology and

markets, including societal and investor

sentiment, related to the issue of climate

change and the transition to a lower carbon

economy could increase costs, reduce

revenues, constrain our operations and affect

our business plans and financial performance.

Risks associated with climate change and the

transition to a lower carbon economy impact

many elements of our strategy and, as such,

these risks are managed through key business

processes including setting the bp strategy

and annual plan, capital allocation and

investment decisions. The outputs of these key

business processes are reviewed in line with

the cadence of these activities. See page <u>[47](#i2aa09724bda449efa410cee334279cee_28642)</u> for

more information on how transition risks and

opportunities are managed.

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Climate-related financial disclosures, <br>page <u>[41](#i0dd2ee81aac04f8c9c97c86197f0c6df_88)</u> and Financial statements –<br>Note 1 and Note 33<br>|

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 69 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Strategic report** |

---

**Competitiveness:** We seek to manage this

risk jointly through our investor relations

and competitor insights (IR&CI) and

strategy teams.

The IR&CI and strategy teams work closely

with communications and external affairs

teams, business teams and functions to

support the shaping of our future strategy by

gathering and synthesizing market and sector

intelligence and investor sentiment and

analysing our performance through

competitor benchmarking.

Our strategy team evaluates longer-term

trends and monitors macro themes as we seek

to maintain a distinct competitive advantage

that underpins our value proposition.

Through market updates, analyst calls,

investor meetings, media outreach and our

corporate reporting, IR&CI communicates and

engages with investors and stakeholders to

gather feedback, address concerns, and

monitor shifts in investor sentiment. This

informs any necessary adjustments to our

portfolio, capital allocation, technology and

performance required to keep pace with

current and future market demands.

The articulation of our unique value

proposition and strategic priorities to

investors, analysts, and other stakeholders

builds understanding and confidence in how

we are seeking to grow value and returns, and

navigate risks, by adapting and capitalizing on

opportunities in a fast-changing environment.

**Talent, leadership and organizational** 

**capability:** We seek to manage this risk

through global, scalable talent strategies,

which can effectively adapt and support the

resourcing needs of bp's strategy. Our people,

culture & communications team works in

partnership with business leaders to attract,

develop and retain the capabilities needed to

deliver our strategy.

Strategic workforce planning is supported by

market intelligence, people analytics, and

scenario modelling to assess talent supply,

demand, and future skills needs. Robust talent

acquisition frameworks and early careers

programmes help to build a pipeline of diverse

and critical skills, while targeted learning

platforms and leadership offers support

continuous development.

We embed clear succession planning and

performance development processes to

identify and support high-potential individuals,

with emphasis on building leadership depth

and capability across the organization.

Employee listening mechanisms such as the

annual Pulse survey, culture assessments, and

behavioural insight tools help assess

engagement, cultural alignment, and

employees' resilience to change.

Knowledge transfer and changes in

accountability are managed through a robust

management of change process. bp's culture

is embedded with bp's code of conduct and

our culture frame 'Who we are'.

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | People, page <u>[55](#i0dd2ee81aac04f8c9c97c86197f0c6df_103)</u> |

---

**Safety and operational risks**

**Process safety, personal safety, and** 

**environmental risks:** We seek to manage

process safety, personal safety, and

environmental risks through our Operating

Management System★ (OMS), which defines

the standards and systematic practices for

safe, reliable, and compliant operations. Key

activities include inspection, maintenance,

testing, incident investigation, and workforce

competency development. It provides a risk-

based framework for identifying, assessing,

and mitigating hazards throughout the

lifecycle of our operations.

Our dedicated wells organization applies

consistent processes for well design,

construction, and management. Production &

operations plays a central role in managing

safety and environmental risks across

hydrocarbon operations. It is accountable for

maintaining safe, compliant, and reliable

performance and promotes a strong safety

culture across sites and partners.

These activities are supported by regular

monitoring, assurance and review through

bp's established management and governance

processes, with escalation where exposure

changes or issues arise.

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Safety, page <u>[55](#i0dd2ee81aac04f8c9c97c86197f0c6df_103)</u> |

---

**Security:** We seek to manage this risk through

bp's global Security Risk Management

Framework, which provides structured

processes for identifying, assessing, and

mitigating security threats (including those

linked to geopolitical instability or hybrid

conflict) at both strategic and operational

levels. The framework integrates oversight

from intelligence, security and crisis

management (ISC) and is supported by our

network of business security representatives.

Key components include the Unified Risk

Picture threat assessment methodology,

which provides consistent visibility of priority

risks and vulnerabilities across the group;

insider risk management processes

addressing unauthorized access, sabotage,

and data exfiltration; executive protection

protocols for high-profile personnel; security

governance and policy standards aligned with

industry best practice; technology

assessments that keep site security

infrastructure fit-for-purpose, and rigorous

compliance with the Voluntary Principles on

Security and Human Rights.

The framework operates under a defined

governance structure with regular reviews by

the ISC, annual risk assessments, and periodic

assurance reviews. It also supports bp's crisis

management and business continuity

planning, which provides co-ordinated

preparedness and response to potential

security incidents across regions and assets.

Where appropriate, emerging activism,

misinformation, or social unrest trends are

monitored to anticipate and manage potential

threats to bp's people and operations.

**Product quality:** We seek to manage product

quality risk across our global value chain by

our operating businesses, working in close

partnership with the applied sciences quality

assurance team. We use a structured Product

Quality Framework aligned with our Operating

Management System, which includes quality

standards, risk assessments, incident

management, and assurance processes.

Where necessary, we apply industry-specific

or enhanced internal standards, particularly in

sectors such as aviation.

This risk is monitored through established

governance and management processes,

including regular review of performance

indicators, assurance outcomes, and incident

learnings, with escalation through appropriate

executive and board-level forums where

required.

---

| | | |
|:---|:---|:---|
| 70 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**How we manage principal risks and uncertainties** continued<br>

**Compliance and control risks**

**Legal, regulatory and ethical compliance:** With

support of our businesses and functions, we

seek to identify, assess and manage legal and

regulatory risks relevant to bp's operations,

strategy, business plans and financial

performance. To support this work, we seek to

develop co-operative relationships with

governmental authorities in line with our code

of conduct, to allow appropriate focus on

areas of potential risk or uncertainty, while

also protecting bp's interests within the law.

Our code of conduct, the foundation of our

culture frame 'Who we are', is applicable to all

employees and central to managing this risk.

Additionally, we have group requirements and

training covering areas such as anti-bribery

and corruption, anti-money laundering,

competition/anti-trust law, data privacy and

international trade regulations. We offer an

independent confidential helpline, 'OpenTalk',

for employees, contractors and other third

parties, with the option to raise concerns

anonymously.

**Financial and physical commodity trading** 

**activities:** We seek to manage risks associated

with financial and physical commodity trading

through dedicated risk control frameworks

with defined delegated authorities,

monitoring, and oversight structures.

Trading is conducted by authorized personnel

operating within approved mandates and limit

structures. Activities and associated risks are

actively managed and monitored, in line with

the group-wide three lines of defence model

which includes independent risk and

compliance functions. As part of this risk

model, robust control frameworks, risk-based

monitoring, exception reporting and escalation

protocols are in place.

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Financial statements – Note 29 |

---

**Integrity of financial and non-financial** 

**reporting:** We seek to manage this risk

through group-wide financial and non-financial

reporting, control and assurance frameworks

designed by our finance organization. The

control operation and assurance activities

within these frameworks are executed at

multiple levels within our businesses and

functions, following a 'line-of-defence' model.

For financial reporting, we apply bp's Sarbanes

Oxley (SOx) Management Assessment

Framework, which includes annual control

testing; deficiency evaluations and reporting;

an annual acknowledgement process

confirming performance of control owner

accountabilities; quarterly representations

from our businesses and functions; and

enterprise-level control assessments.

For non-financial reporting, we follow our ESG

and non-financial reporting (ESG-NFR) control

and assurance framework, which includes help

to determine the appropriate level of control

and assurance activity to be applied, annual

due diligence with control owners and pre-

publication reviews.

We also maintain a Fraud Risk Management

Governance Framework to identify, assess and

mitigate the risk of fraudulent activity.

As reporting expectations and requirements

evolve under various frameworks and

regulations in the UK and in other jurisdictions,

we continue to review and enhance, as

needed, our reporting controls, approach to

assurance and approach to disclosure.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 71 |

---

---

| | |
|:---|:---|
|  | ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
|  | **Strategic report** |
| **Compliance information** |  |

---

**bp non-financial and sustainability information statement**

Produced in compliance with Sections 414CA and 414CB of the Companies Act. Information incorporated by cross reference.

---

| | | |
|:---|:---|:---|
| **Requirement** | **Relevant policies and standards** | **Information related to policies and any due diligence processes** |
| a Environmental matters | •Net zero aims<br>•TCFD<br>•Sustainability frame<br>•Biodiversity position (online)<br>| •Climate-related financial disclosures - pages <u>[41](#i0dd2ee81aac04f8c9c97c86197f0c6df_88)</u>-<u>[54](#id3047d206d7b4fb1a6b06f37106b73eb_445)</u><br>•People and planet – **page <u>[59](#i87f52fc5efef4a16865a4af06e1e7987_26440)</u>**<br>•Our Operating Management System★ (OMS) – **page <u>[55](#i87f52fc5efef4a16865a4af06e1e7987_26445)</u>**<br>•Decision making by the board – **page <u>[81](#i0dd2ee81aac04f8c9c97c86197f0c6df_151)</u>**<br>|
| b Employees | •bp values and code of conduct (online) | •Our people – **page <u>[56](#i87f52fc5efef4a16865a4af06e1e7987_46404)</u>**<br>•Safety – **page <u>[55](#i87f52fc5efef4a16865a4af06e1e7987_26441)</u>**<br>**•**Our values ('Who we are') and code of conduct – **pages <u>[57](#i87f52fc5efef4a16865a4af06e1e7987_26442)</u><u>-</u><u>[58](#i87f52fc5efef4a16865a4af06e1e7987_26446)</u>**<br>•Employee engagement (Pulse annual and Pulse live employee surveys) – **page <u>[57](#i87f52fc5efef4a16865a4af06e1e7987_26450)</u>**<br>•How the board engaged with stakeholders (workforce) – **page <u>[80](#i0e1c9c18aad14259ba08133d542166ec_2269)</u>**<br>|
| c Social matters | •Sustainability frame | •Our Operating Management System★ (OMS) – **page <u>[55](#i87f52fc5efef4a16865a4af06e1e7987_26445)</u>**<br>•Improving people's lives – **page <u>[59](#i87f52fc5efef4a16865a4af06e1e7987_26434)</u>**<br>•Decision making by the board – **page <u>[81](#i0dd2ee81aac04f8c9c97c86197f0c6df_151)</u>**<br>|
| d Respect for human rights | •Business and human rights policy (online)<br>•Modern slavery statement (online)<br>•Labour rights and modern slavery principles (online)<br>•Code of conduct (online)<br>| •Improving people's lives – **page <u>[59](#i87f52fc5efef4a16865a4af06e1e7987_26434)</u>**<br>•Human rights – **page <u>[59](#i87f52fc5efef4a16865a4af06e1e7987_26434)</u>**<br>**•**Our values ('Who we are') and code of conduct – **pages <u>[57](#i87f52fc5efef4a16865a4af06e1e7987_26442)</u><u>-</u><u>[58](#i87f52fc5efef4a16865a4af06e1e7987_26446)</u>**<br>|
| e Anti-corruption and anti-bribery | •Anti-bribery and corruption policy<br>•Code of conduct (online)<br>| •Ethics and compliance – **page <u>[58](#i87f52fc5efef4a16865a4af06e1e7987_26446)</u>**<br>•Our partners in joint arrangements – **page <u>[56](#i87f52fc5efef4a16865a4af06e1e7987_26449)</u>**<br>|
| Description of principal risks relating <br>to matters (a-e above)<br>|  | •How we manage risk – **pages <u>[67](#ibab2aaffe10844329441f47f933e27b0_113952)</u><u>-</u><u>[70](#ibab2aaffe10844329441f47f933e27b0_113954)</u>**<br>•Risk factors – **page <u>[62](#i0dd2ee81aac04f8c9c97c86197f0c6df_6396)</u>**<br>•TCFD (climate-related risk management) – **pages <u>[44](#i0dd2ee81aac04f8c9c97c86197f0c6df_94)</u><u>-</u><u>[45](#iaba63c89451f4319921f913f763af6c1_9158)</u>**<br>|
|  | **Relevant information** |  |
| Business model description | •Business model – page <u>[12](#i0dd2ee81aac04f8c9c97c86197f0c6df_37)</u> |  |
| Description of non-financial KPIs | •Measuring our progress – **pages <u>[16](#i0dd2ee81aac04f8c9c97c86197f0c6df_43)</u><u>-</u><u>[17](#i0a945a9bfb024778b87fd44881629b51_1-0-1-3-904218)</u>** |  |

---

**TCFD index table**<sup>a</sup>

Our TCFD disclosures can be found on the following pages.

---

| | | |
|:---|:---|:---|
| **TCFD Recommendation** | **TCFD Recommended Disclosure** | **Where reported** |
| **Governance**<br>Disclose the organization's <br>governance around climate-related <br>issues and opportunities. | a Describe the board's oversight of climate-related risks <br>and opportunities.<br>| •Page <u>[44](#iaba63c89451f4319921f913f763af6c1_9157)</u> |
| **Governance**<br>Disclose the organization's <br>governance around climate-related <br>issues and opportunities. | b Describe management's role in assessing and managing <br>climate-related risks and opportunities.<br>| •Page <u>[45](#iaba63c89451f4319921f913f763af6c1_9161)</u> |
| **Strategy**<br>Disclose the actual and potential <br>impacts of climate-related risks and <br>opportunities on the organization's <br>business, strategy and financial <br>planning where such information is <br>material. | a Describe the climate-related risks and opportunities the <br>organization has identified over the short, medium, and <br>long term.<br>| •TCFD Strategy a, page <u>[46](#i0dd2ee81aac04f8c9c97c86197f0c6df_97)</u><br>•Pursuing a strategy that is consistent with the Paris goals, page <u>[10](#i0dd2ee81aac04f8c9c97c86197f0c6df_34)</u><br>•Strategy, page <u>[8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31)</u><br>•Risk factors, page <u>[67](#i0dd2ee81aac04f8c9c97c86197f0c6df_109)</u><br>|
| **Strategy**<br>Disclose the actual and potential <br>impacts of climate-related risks and <br>opportunities on the organization's <br>business, strategy and financial <br>planning where such information is <br>material. | b Describe the impact of climate-related risks and <br>opportunities on the organization's businesses, strategy, <br>and financial planning.<br>| •TCFD Strategy b, **page <u>[46](#i0dd2ee81aac04f8c9c97c86197f0c6df_97)</u>**<br>•Risk factors, **page <u>[67](#i0dd2ee81aac04f8c9c97c86197f0c6df_109)</u>** – description of principal risks<br>•Strategy, **page <u>[8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31)</u>**<br>|
| **Strategy**<br>Disclose the actual and potential <br>impacts of climate-related risks and <br>opportunities on the organization's <br>business, strategy and financial <br>planning where such information is <br>material. | c Describe the resilience of the organization's strategy, <br>taking into consideration different climate-related <br>scenarios, including a 2°C or lower scenario.<br>| •TCFD Strategy c, **page <u>[49](#i1bf312295c9240f297e3bbf5c49a0824_1-1-1-1-781302)</u>**<br>•Strategy, **page <u>[8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31)</u>**<br>•Pursuing a strategy that is consistent with the Paris goals, **page <u>[10](#i0dd2ee81aac04f8c9c97c86197f0c6df_34)</u>**<br>|
| **Risk management** <br>Disclose how the organization <br>identifies, assesses and manages <br>climate-related risks. | a Describe the organization's processes for identifying <br>and assessing climate-related risks.<br>| •Risk Management, page <u>[44](#iaba63c89451f4319921f913f763af6c1_9157)</u><br>•How we manage risk, **page <u>[60](#i0dd2ee81aac04f8c9c97c86197f0c6df_106)</u>**<br>•Risk factors, **page <u>[67](#i0dd2ee81aac04f8c9c97c86197f0c6df_109)</u>**<br>|
| **Risk management** <br>Disclose how the organization <br>identifies, assesses and manages <br>climate-related risks. | b Describe the organization's processes for managing <br>climate-related risks.<br>| •Risk Management, page <u>[44](#iaba63c89451f4319921f913f763af6c1_9157)</u><br>•How we manage risk, **page <u>[60](#i0dd2ee81aac04f8c9c97c86197f0c6df_106)</u>**<br>|
| **Risk management** <br>Disclose how the organization <br>identifies, assesses and manages <br>climate-related risks. | c Describe how processes for identifying, assessing, and <br>managing climate-related risks are integrated into the <br>organization's overall risk management.<br>| •Risk Management, **page <u>[44](#iaba63c89451f4319921f913f763af6c1_9157)</u>**<br>•How we manage risk, page <u>[60](#i0dd2ee81aac04f8c9c97c86197f0c6df_106)</u><br>•Risk factors, page <u>[67](#i0dd2ee81aac04f8c9c97c86197f0c6df_109)</u><br>|
| **Metrics and targets** <br>Disclose the metrics and targets <br>used to assess and manage relevant <br>climate-related risks and <br>opportunities where such <br>information is material. | a Disclose the metrics used by the organization to assess <br>climate-related risks and opportunities in line with its <br>strategy and risk management process.<br>| •TCFD metrics and targets, page <u>[54](#i0dd2ee81aac04f8c9c97c86197f0c6df_100)</u> |
| **Metrics and targets** <br>Disclose the metrics and targets <br>used to assess and manage relevant <br>climate-related risks and <br>opportunities where such <br>information is material. | b Disclose Scope 1, Scope 2, and, if appropriate, Scope 3 <br>GHG emissions, and the related risks.<br>| •GHG emissions data, **page <u>[38](#ia533d1b86ea04772b2fd02ae3d1c8da0_54064)</u>** |
| **Metrics and targets** <br>Disclose the metrics and targets <br>used to assess and manage relevant <br>climate-related risks and <br>opportunities where such <br>information is material. | c Describe the targets used by the organization to manage <br>climate-related risks and opportunities and <br>performance against targets.<br>| •Our net zero aims and targets, **pages <u>[37](#i0dd2ee81aac04f8c9c97c86197f0c6df_82)</u><u>-</u><u>[38](#ia533d1b86ea04772b2fd02ae3d1c8da0_9654)</u>** |

---

aWe consider the information in our TCFD disclosures, taken together with our climate-related non-financial KPIs on pages [16](#i0dd2ee81aac04f8c9c97c86197f0c6df_43)-[17](#i0a945a9bfb024778b87fd44881629b51_1-0-1-3-904218) of this report, to be compliant with the disclosure requirements of

Section 414CB of the Companies Act, as amended by the UK CFD Regulations.

**Section 172 statement**

In accordance with the requirements of Section 172 of the Companies Act 2006 (the Act), the directors consider that, during the financial year ended

31 December 2025, they have acted in a way that they consider, in good faith, would most likely promote the success of the company for the

benefit of its members as a whole, having regard to the likely consequences of any decision in the long term and the broader interests of other

stakeholders, as required by the Act.

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | For more information in support of this statement, see board activities, page <u>[78](#i0dd2ee81aac04f8c9c97c86197f0c6df_139)</u>, our stakeholders, page <u>[80](#i0dd2ee81aac04f8c9c97c86197f0c6df_142)</u> and key decisions, page <u>[81](#i0dd2ee81aac04f8c9c97c86197f0c6df_151)</u> |

---

The strategic report was approved by the board and signed on its behalf by Ben J.S. Mathews, company secretary, on 6 March 2026.

![CorporateGovernanceDividerV7-LEFT.jpg](bp-20251231_g72.jpg)

---

| | | |
|:---|:---|:---|
| 72 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

Corporate

governance

"In early 2025 the board's focus

moved from the resetting of strategy

to overseeing disciplined performance

and the delivery of our four primary

financial targets."

**Albert Manifold**

Chair

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Read Albert's letter on page <u>[4](#i0dd2ee81aac04f8c9c97c86197f0c6df_19)</u> |

---

---

| | |
|:---|:---|
| Board of directors | [73](#i0dd2ee81aac04f8c9c97c86197f0c6df_130) |
| Leadership team | [76](#i0dd2ee81aac04f8c9c97c86197f0c6df_133) |
| Governance framework | [77](#i0dd2ee81aac04f8c9c97c86197f0c6df_136) |
| Board activities | [78](#i0dd2ee81aac04f8c9c97c86197f0c6df_139) |
| Our stakeholders | [80](#i0dd2ee81aac04f8c9c97c86197f0c6df_142) |
| Key decisions | [81](#i0dd2ee81aac04f8c9c97c86197f0c6df_151) |
| Safety and sustainability committee | [82](#i0dd2ee81aac04f8c9c97c86197f0c6df_160) |
| Audit committee | [84](#i0dd2ee81aac04f8c9c97c86197f0c6df_166) |
| People, culture and governance committee | [89](#i0dd2ee81aac04f8c9c97c86197f0c6df_184) |
| Remuneration committee | [91](#i0dd2ee81aac04f8c9c97c86197f0c6df_187) |
| Directors' remuneration report | [91](#i0dd2ee81aac04f8c9c97c86197f0c6df_187) |
| Other disclosures | [126](#i0dd2ee81aac04f8c9c97c86197f0c6df_217) |

---

**Image:** Rotterdam refinery, Netherlands

---

| | | |
|:---|:---|:---|
| **Board composition** | **Board composition** | **Board composition** |
| **Board gender diversity** | **Board gender diversity** | **Board gender diversity** |
|  | **March** <br>**2026**<br>| March <br>2025<br>|
| Female | **6** | 6 |
| Male | **7** | 5 |
| 46%<br>of directors are female | 46%<br>of directors are female | 46%<br>of directors are female |

---

---

| | | |
|:---|:---|:---|
| **Board ethnic diversity** | **Board ethnic diversity** | **Board ethnic diversity** |
|  | **March** <br>**2026**<br>| March <br>2025<br>|
| White | 10 | 8 |
| Asian | 3 | 3 |
| 3<br>directors who identify as from a <br>minority ethnic background | 3<br>directors who identify as from a <br>minority ethnic background | 3<br>directors who identify as from a <br>minority ethnic background |

---

---

| | | |
|:---|:---|:---|
| **Non-executive directors' tenure** | **Non-executive directors' tenure** | **Non-executive directors' tenure** |
|  | **March** <br>**2026**<br>| March <br>2025<br>|
| 1-3 years | 4 | 3 |
| 4-6 years | 6 | 5 |
| 7-9 years | 1 | 1 |

---

---

| | |
|:---|:---|
|  | Board biographies, page <u>[73](#i0dd2ee81aac04f8c9c97c86197f0c6df_130)</u> |
| ![ReadMoreArrowWhite.gif](bp-20251231_g73.gif) | Board biographies, page <u>[73](#i0dd2ee81aac04f8c9c97c86197f0c6df_130)</u> |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 73 |

---

---

| | |
|:---|:---|
|  | ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
|  | **Corporate governance** |
| **Board of directors** |  |

---

As at 6 March 2026

![BoD_AlbertManifoldV4.jpg](bp-20251231_g74.jpg)

![BoD_CarolHowleV2.jpg](bp-20251231_g75.jpg)

---

| |
|:---|
| **Albert Manifold** <br>Chair<br>|
| **Appointed** Board: 1 September 2025; <br>chair: 1 October 2025 |
| **Nationality** Irish |
| **External appointments** |
| •Non-executive director at LyondellBasell Industries. <br>•Non-executive director at Mercury Engineering.<br>•Adviser to Clayton Dubilier & Rice.  |
| **Significant past appointments** |
| •A number of senior positions at CRH plc over a 28-<br>year career, including chief executive officer from <br>January 2014 to December 2024. <br>•Chief operating officer of Allen McGuire & Partners.  |
| **Key skills and experience** |
| •Extensive experience of driving a business through <br>exceptional growth and strategic transformations, <br>leading to profitability and cash generation, and <br>consistently improving returns to shareholders.<br>•Certified public accountant and a chartered <br>accountant. Holds a master of business <br>administration and a master's in business studies, <br>both from Dublin City University.  |

---

![BoD_AmandaBlancV5.jpg](bp-20251231_g76.jpg)

---

| | |
|:---|:---|
| **Key** | **Key** |
| ![BoDKeyExecDirV1.jpg](bp-20251231_g77.jpg) | Executive director |
| ![BoDKeyNonExecDirV1.jpg](bp-20251231_g78.jpg) | Non-executive director  |
| ![BoDKeyLeadershipV1.jpg](bp-20251231_g79.jpg) | Leadership team member |
| **Committee members key** | **Committee members key** |
| ![BoDKeyCommChairV1.jpg](bp-20251231_g80.jpg) | Committee chair |
| ![BoDKeySafetySusCommV1.jpg](bp-20251231_g81.jpg) | Safety and sustainability committee |
| ![BoDKeyAuditCommV1.jpg](bp-20251231_g82.jpg) | Audit committee |
| ![BoDKeyPeopleCultGovCommV1.jpg](bp-20251231_g83.jpg) | People, culture and governance committee |
| ![BoDKeyRemCommV1.jpg](bp-20251231_g84.jpg) | Remuneration committee |
| For further detail on the directors' <br>climate change and sustainability <br>experience, see the TCFD section <br>on page <u>41</u>, and further <br>biographical information for each <br>director is available online at: <br><u>bp.com/whoweare</u> | For further detail on the directors' <br>climate change and sustainability <br>experience, see the TCFD section <br>on page <u>41</u>, and further <br>biographical information for each <br>director is available online at: <br><u>bp.com/whoweare</u> |

---

![BoD_KateThomsonV4.jpg](bp-20251231_g85.jpg)

---

| |
|:---|
| **Carol Howle** <br>Interim chief <br>executive officer<br>|
| **Appointed** 18 December 2025  |
| **Nationality** British |
| **External appointments** |
| •Non-executive board member of the Royal Navy. |
| **Significant past appointments** |
| •Various senior leadership roles at bp, including <br>executive vice president, supply, trading & shipping <br>and chief operating officer for integrated supply and <br>trading, oil.  |
| **Key skills and experience** |
| •With 25 years at bp, Carol has a deep knowledge of <br>the company and extensive experience in the energy <br>industry. Carol is also a non-executive board <br>member of the Royal Navy and chair of the Navy <br>Audit and Risk Assurance Committee.  |

---

---

| |
|:---|
| **Dame Amanda Blanc**<br>Independent <br>non-executive director<br>|
| **Appointed** 1 September 2022 |
| **Nationality** British |
| **External appointments** |
| •Group CEO of Aviva plc. <br>•Member of the Association of British Insurers Board.<br>•Member of the UK Government's British Infrastructure <br>Taskforce.  |
| **Significant past appointments** |
| •CEO of Europe, Middle East, Africa & Global Banking <br>at Zurich Insurance Group.<br>•Group CEO at AXA UK, PPP & Ireland. <br>•Several senior executive roles across the insurance <br>industry.<br>•Member of the Prime Minister's Business Council. <br>•Member of HMT National Wealth Fund Taskforce. |
| **Key skills and experience** |
| •Brings wide-ranging board experience with strong <br>industry and regulatory connections having <br>previously been Chair of the Association of British <br>Insurers. <br>•Combines the experience of leading insurance <br>businesses in the UK and Europe with being a <br>member of HM Treasury's Business Infrastructure <br>Taskforce. |

---

---

| |
|:---|
| **Kate Thomson**<br>Chief financial officer<br>|
| **Appointed** 2 February 2024 |
| **Nationality** British |
| **External appointments** |
| •Board member of Aker BP since 2016. <br>•Main committee member of The 100 Group.  |
| **Significant past appointments** |
| •Joined bp in 2004. <br>•Group head of tax, BP p.l.c. <br>•Group treasurer, BP p.l.c. <br>•SVP finance for production & operations, BP p.l.c.  |
| **Key skills and experience** |
| •Has a detailed understanding and experience of the <br>energy sector and provides deep technical insight <br>from her broad experience of leading teams across <br>the bp group in tax, treasury and commercial <br>finance.  |

---

![BoD_TusharMorzariaV5.jpg](bp-20251231_g86.jpg)

---

| |
|:---|
| **Tushar Morzaria**<br>Independent <br>non-executive director<br>|
| **Appointed** 1 September 2020 |
| **Nationality** British |
| **External appointments** |
| •Non-executive director of BT Group plc. <br>•Non-executive director of Legal & General Group plc. |
| **Significant past appointments** |
| •Various senior roles at JP Morgan, including CFO of <br>its Corporate & Investment Bank. <br>•Group finance director and member of the board of <br>Barclays PLC, 2013 to 2022. <br>•Non-executive chairman of EMEA Investment <br>Banking, Barclays until 2024.  |
| **Key skills and experience** |
| •Over 25 years of strategic financial management, <br>investment banking, operational and regulatory <br>experience. <br>•Breadth of knowledge and insight into financial, tax, <br>treasury, investor relations and strategic matters <br>and strong experience in delivering corporate <br>change programmes while maintaining a focus on <br>performance.  |

---

---

| | | |
|:---|:---|:---|
| 74 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Board of directors** continued<br>

![BoD_IanTylerV4.jpg](bp-20251231_g87.jpg)

![BoD_MelodyMayerV4.jpg](bp-20251231_g88.jpg)

---

| |
|:---|
| **Ian Tyler**<br>Independent <br>non-executive director<br>|
| **Appointed** 1 April 2025 |
| **Nationality** British |
| **External appointments** |
| •Chair of Grafton Group plc.<br>•Senior Independent Director of Anglo American plc.<br>•Chair of BMT Group Ltd.<br>•Member of KPMG Public Interest Committee  |
| **Significant past appointments** |
| •Served as chair of Affinity Water Limited, AWE <br>Management Limited, Al Noor plc, Amey UK plc, <br>Vistry Group plc (formerly Bovis Homes Group) and <br>of Cairn Energy plc. <br>•Non-executive director of BAE Systems plc, VT <br>Group plc, Mediclinic plc, Cable & Wireless <br>Communications plc, and Synthomer plc. <br>•CEO and finance director positions at Balfour Beatty <br>plc.  |
| **Key skills and experience** |
| •Extensive executive and non-executive experience <br>across multiple industries.<br>•Recent experience leading the remuneration <br>committees of some of the UK's largest quoted <br>companies. |

---

![BoD_HinaNagarajanV4.jpg](bp-20251231_g89.jpg)

![BoDJohannesTeyssenV3.jpg](bp-20251231_g90.jpg)

---

| |
|:---|
| **Dr Johannes Teyssen**<br>Independent <br>non-executive director<br>|
| **Appointed** 1 January 2021 |
| **Nationality** German |
| **External appointments** |
| •Senior advisor to Kohlberg Kravis Roberts.<br>•President of Alpiq Holding Ltd.<br>•Senior advisor to Viridor Limited. |
| **Significant past appointments** |
| •Several leadership positions at VEBA AG (merged <br>with VIAG AG in 2000 and renamed to E.ON AG and <br>later to E.ON SE).<br>•Member of the board of management of the E.ON <br>Group's central management company in Munich in <br>2001 and E.ON SE in 2004. <br>•Vice-chair of E.ON SE, 2008 and CEO, 2010 to 2021. <br>•President of Eurelectric, 2013 to 2015. <br>•Vice-chair of the World Energy Council, responsible <br>for Europe, 2006 to 2012. <br>•Member of the supervisory board of Salzgitter AG, <br>2006 to 2016, and Deutsche Bank AG, 2008 to 2018. |
| **Key skills and experience** |
| •Extensive experience and deep knowledge of the <br>energy sector and its continuing transformation. <br>•Considerable knowledge and experience of climate-<br>related risk oversight.  |

---

![BoD_SatisPaiV3.jpg](bp-20251231_g91.jpg)

---

| |
|:---|
| **Melody Meyer**<br>Independent <br>non-executive director<br>|
| **Appointed** 17 May 2017 |
| **Nationality** American |
| **External appointments** |
| •Non-executive director of AbbVie Inc. <br>•Non-executive director of Airswift Parent LLC. <br>•President of Melody Meyer Energy LLC and Women <br>with Energy LLC. <br>•Director of the National Bureau of Asian Research. <br>•Advisory board member of McKinsey Advancing <br>With Excellence.<br>•Trustee of Trinity University.  |
| **Significant past appointments** |
| •President of Chevron Asia Pacific E&P until 2016 <br>after 37 years of service in key leadership roles in <br>global exploration and production.  |
| **Key skills and experience** |
| •Deep understanding of the factors influencing safe, <br>efficient and commercially high-performing projects <br>in a global organization. <br>•Expertise in the execution of major capital projects, <br>technology, R&D, creation of businesses in new <br>countries, strategic business planning, merger <br>integration, leading change, and safe and reliable <br>operations.  |

---

![BoD_DaveHagerV5.jpg](bp-20251231_g92.jpg)

---

| |
|:---|
| **Hina Nagarajan**<br>Independent <br>non-executive director<br>|
| **Appointed** 1 March 2023 |
| **Nationality** Indian |
| **External appointments** |
| •President of Diageo Africa. <br>•Executive Director and Vice Chairperson of East <br>African Breweries PLC and Member of Board <br>Nomination and Remuneration Committee. <br>•Member of the Global Executive Committee of <br>Diageo plc. |
| **Significant past appointments** |
| •Leadership positions at United Spirits Limited <br>(Diageo India), Reckitt, Mary Kay India and Nestlé <br>India with over 30 years' experience in the fast-<br>moving consumer goods (FMCG) industry. <br>•Non-executive director at two companies which <br>were publicly quoted at the time: Guinness Ghana <br>Breweries Plc and Seychelles Breweries Limited. <br>•Board member of The Advertising Standards Council <br>of India. <br>•Director and Co-Chair of International Spirits and <br>Wines Association of India.  |
| **Key skills and experience** |
| •Deep and wide-ranging experience in customer-<br>focused FMCG businesses in complex emerging <br>markets. <br>•Extensive experience in assessing climate-related <br>risks and opportunities.  |

---

---

| |
|:---|
| **Satish Pai**<br>Independent <br>non-executive director<br>|
| **Appointed** 1 March 2023 |
| **Nationality** Indian |
| **External appointments** |
| •Managing Director of Hindalco Industries Limited.<br>•Director of Novelis Inc.<br>•Non-executive director, Aditya Birla Management <br>Corporation Ltd.<br>•Director, Indian Institute of Metals.  |
| **Significant past appointments** |
| •Executive vice president, worldwide operations and <br>other engineering and management roles at <br>Schlumberger across 28 years of service.  |
| **Key skills and experience** |
| •Accomplished and transformative executive with <br>operations and technology experience in the <br>resources and energy industries. <br>•Strong digital capability and experience.  |

---

---

| |
|:---|
| **Dave Hager**<br>Independent <br>non-executive director<br>|
| **Appointed** 2 June 2025 |
| **Nationality** American |
| **External appointments** |
| •none. |
| **Significant past appointments** |
| •Leadership positions at the Oryx Energy Company.<br>•Executive vice president and later chief operating <br>officer of Kerr-McGee. <br>•Board memberships with EnLink Midstream and <br>Pride International Inc. <br>•Various senior leadership roles at the Devon Energy <br>Corporation, including executive chairman, 2021 to <br>2013.<br>•Director of MRC Global Inc. |
| **Key skills and experience** |
| •Over 40 years' experience in the oil and gas industry.<br>•Deep-rooted knowledge of the US upstream oil and <br>gas industry.  |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 75 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

![BoD_KarenRichardsonV4.jpg](bp-20251231_g93.jpg)

![BoD_SimonHenryV5.jpg](bp-20251231_g94.jpg)

---

| |
|:---|
| **Karen Richardson**<br>Independent <br>non-executive director<br>|
| **Appointed** 1 January 2021 |
| **Nationality** American |
| **External appointments** |
| •Partner at Artius Capital Partners.<br>•Non-executive director of Artius II Acquisition Inc.<br>•Non-executive director (lead independent director) <br>of Exponent Inc. |
| **Significant past appointments** |
| •Senior operating roles in the public and private <br>technology sectors. <br>•Vice president of sales at Netscape <br>Communications Corporation, 1995 to 1998. <br>•Senior executive roles at E.piphany from 1998, <br>including CEO, 2003 to 2006. <br>•Non-executive director of BT plc, 2011 to 2018.<br>•Director of Worldpay Inc. (Worldpay Group plc), 2016 <br>to 2019. <br>•Chair of Origin Materials Inc., 2021 to 2024.  |
| **Key skills and experience** |
| •Extensive digital, technology, cyber and IT security <br>knowledge. <br>•30 years' technology industry experience including <br>working with innovative Silicon Valley companies.  |

---

![BoDBenMathewsV3.jpg](bp-20251231_g95.jpg)

---

| |
|:---|
| **Simon Henry**<br>Independent <br>non-executive director<br>|
| **Appointed** 1 September 2025 |
| **Nationality** British |
| **External appointments** |
| •Advisor to the Board of Oxford Flow Ltd. <br>•Member of the Board of the Audit Committee Chairs' <br>Independent Forum.  |
| **Significant past appointments** |
| •Non-executive director of Rio Tinto plc between 2017 <br>and 2025.<br>•Directorships with Harbour Energy plc, Lloyds <br>Banking Group plc and PetroChina Ltd.<br>•Various senior executive and leadership roles at <br>Shell, including chief financial officer from 2009 to <br>2017. |
| **Key skills and experience** |
| •Extensive career in energy industry internationally <br>with broad experience of the global upstream and <br>downstream energy industry.<br>•Wide-ranging expertise and experience with <br>financial and commercial understanding of global <br>markets. |

---

---

| |
|:---|
| **Ben J S Mathews**<br>Company secretary<br>|
| **Appointed** 7 May 2019 |
| **Role and career summary** |
| Ben joined bp as company secretary in May 2019. He is <br>co-chair of the Corporate Governance Council of the <br>Conference Board and is a Fellow of the Chartered <br>Governance Institute. Ben serves on the executive <br>committee of the Association of General Counsel and <br>Company Secretaries of the FTSE 100 (GC100), having <br>previously served as its chair for four years.<br>Ben's global company secretary team is responsible <br>for providing independent advice and support to the <br>plc board and the boards of all other legal entities in <br>the bp group. The team's vision is to enhance <br>stakeholder value through dynamic corporate <br>governance.<br>Former appointments include group company <br>secretary of HSBC Holdings plc and Rio Tinto plc. |

---

---

| | | | | | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | **Board** <br>**meeting**<br>**attendance** | **Board** <br>**meeting**<br>**attendance** | **Committee** <br>**membership** | **Committee** <br>**membership** | **Committee** <br>**membership** | **Committee** <br>**membership** | **Skills and**<br>**experience** | **Skills and**<br>**experience** | **Skills and**<br>**experience** | **Skills and**<br>**experience** | **Skills and**<br>**experience** | **Skills and**<br>**experience** | **Skills and**<br>**experience** | **Skills and**<br>**experience** |
|  | Scheduled | Ad hoc | Audit | Remuneration | People, culture <br>and governance<br>| Safety and <br>sustainability<br>| Society, politics <br>and geopolitics<br>| Technology, <br>digital and <br>innovation<br>| People leadership <br>and organizational <br>transformation<br>| Operational <br>excellence <br>and risk <br>management<br>| Global business <br>leadership <br>and governance<br>| Finance, <br>risk and <br>trading<br>| Energy <br>markets<br>| Climate <br>change and <br>sustainability<br>|
| Non-executive directors |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Albert Manifold (Chair)<sup>a b</sup> | 3/3 | 2/2 |  |  | 🟇 |  | 🟇 |  | 🟇 | 🟇 | 🟇 | 🟇 |  | 🟇 |
| Helge Lund (Chair)<sup>a</sup> | 6/6 | 2/2 |  |  | 🟇 |  | 🟇 |  | 🟇 | 🟇 | 🟇 |  | 🟇 | 🟇 |
| Dame Amanda Blanc | 8/8 | 5/5 |  | 🟇 | 🟇 |  | 🟇 |  | 🟇 | 🟇 | 🟇 | 🟇 |  | 🟇 |
| Pamela Daley<sup>a c</sup> | 2/4 | 1/2 | 🟇 | 🟇 |  |  |  |  |  |  | 🟇 | 🟇 | 🟇 |  |
| Dave Hager<sup>a b</sup> | 4/4 | 2/2 |  |  |  | 🟇 |  |  | 🟇 | 🟇 | 🟇 | 🟇 | 🟇 | 🟇 |
| Simon Henry<sup>a</sup> | 3/3 | 2/2 |  |  |  |  | 🟇 | 🟇 | 🟇 | 🟇 | 🟇 | 🟇 | 🟇 | 🟇 |
| Tushar Morzaria<sup>b c</sup> | 8/8 | 4/5 | 🟇 | 🟇 |  |  |  |  | 🟇 | 🟇 | 🟇 | 🟇 |  |  |
| Melody Meyer<sup>c</sup> | 8/8 | 4/5 |  | 🟇 |  | 🟇 |  |  |  | 🟇 | 🟇 |  | 🟇 | 🟇 |
| Hina Nagarajan<sup>c</sup> | 6/8 | 5/5 | 🟇 |  | 🟇 |  |  | 🟇 | 🟇 | 🟇 | 🟇 |  |  | 🟇 |
| Satish Pai<sup>c</sup> | 8/8 | 4/5 |  |  |  | 🟇 |  | 🟇 | 🟇 | 🟇 | 🟇 |  | 🟇 | 🟇 |
| Karen Richardson<sup>c</sup> | 8/8 | 4/5 | 🟇 |  |  |  |  | 🟇 | 🟇 | 🟇 | 🟇 | 🟇 |  |  |
| Dr Johannes Teyssen | 8/8 | 5/5 |  |  | 🟇 | 🟇 |  |  | 🟇 | 🟇 | 🟇 | 🟇 | 🟇 | 🟇 |
| Ian Tyler<sup>a b</sup> | 6/6 | 3/3 | 🟇 | 🟇 |  |  |  |  | 🟇 | 🟇 | 🟇 | 🟇 |  |  |
| Executive directors |  |  |  |  |  |  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  |
| Carol Howle (CEO)<sup>a</sup> | 0/0 | 0/0 |  |  |  |  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  |
| Murray Auchincloss (CEO)<sup>a</sup> | 8/8 | 5/5 |  |  |  |  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  |
| Kate Thomson (CFO) | 8/8 | 5/5 |  |  |  |  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  |
|  |  |  |  |  |  |  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  |
| 🟇 Chair of the committee 🟇 Member of the committee | 🟇 Chair of the committee 🟇 Member of the committee | 🟇 Chair of the committee 🟇 Member of the committee | 🟇 Chair of the committee 🟇 Member of the committee | 🟇 Chair of the committee 🟇 Member of the committee | 🟇 Chair of the committee 🟇 Member of the committee | 🟇 Chair of the committee 🟇 Member of the committee | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  |
|  |  |  |  |  |  |  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  | a Board changes: The appointments to the board were Ian Tyler (1 April 2025), Dave Hager (2 June 2025), Simon Henry (1 September <br>2025), Albert Manifold (1 September 2025; chair of the board from 1 October 2025) and Carol Howle (18 December 2025). Pamela <br>Daley (7 July 2025), Helge Lund (30 September 2025), and Murray Auchincloss (18 December 2025) stepped down. Each director <br>attended all board meetings following their appointment or prior to their retirement from the board, as applicable.<br>b Committee changes: Tushar Morzaria chaired the remuneration committee until 16 April 2025; Ian Tyler became remuneration <br>committee chair from 17 April 2025 and joined the audit committee from 2 June 2025; Helge Lund chaired the people, culture and <br>governance committee (PCGC) until 30 September 2025; Albert Manifold was appointed chair of the PCGC from 1 October 2025; <br>and Dave Hager joined the safety and sustainability committee from 10 December 2025.<br>c Attendance exceptions: Pamela Daley was unable to attend the scheduled meetings in April and May, and the ad hoc meeting in <br>February due to personal reasons; Tushar Morzaria was unable to attend the ad hoc meeting in February due to a pre-existing <br>external commitment; Melody Meyer was unable to attend the ad hoc meeting in October due to a pre-existing external <br>commitment; Hina Nagarajan was unable to attend the scheduled meetings in March and September due to pre-existing external <br>commitments; Satish Pai was unable to attend the ad hoc meeting in February due to a pre-existing external commitment; and <br>Karen Richardson was unable to attend the ad hoc meeting in December due to a pre-existing external commitment.  |

---

![](bp-20251231_g96.gif)

---

| | | |
|:---|:---|:---|
| 76 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Leadership team**<br>

![Leadership_GordonBirrellV3.jpg](bp-20251231_g97.jpg)

---

| |
|:---|
| **Gordon Birrell**<br>EVP production <br>& operations<br>|
| **Leadership team tenure** Appointed on 1 July 2020 |
| **Nationality** British |
| **Board memberships** |
| Gordon is a non-executive director of Azule Energy <br>Holdings Ltd. |
| **Career summary** |
| Before being appointed to his new role, Gordon was <br>chief operating officer for production, transformation <br>and carbon. In his bp career, Gordon has spent time in <br>various leadership, technical, safety and operational risk <br>roles, including four years as bp president Azerbaijan, <br>Georgia and Türkiye. Gordon is a fellow of the Royal <br>Academy of Engineering. |

---

![Leadership_EmekaEmemboiuV3.jpg](bp-20251231_g98.jpg)

---

| |
|:---|
| **Emeka Emembolu** <br>EVP technology<br>|
| **Leadership team tenure** Appointed on 18 April 2024 |
| **Nationality** British |
| **Board memberships** |
| **Career summary** |
| Emeka is EVP of Technology at bp, leading digital, safety, <br>security and science to advance innovation and <br>safeguard the business. He has spent over 25 years with <br>bp, previously serving as chief of staff to the CEO and <br>leading the North Sea business as regional SVP. His <br>earlier roles span senior technical roles across the Gulf <br>of America, Canada, North Africa and Alaska. |

---

![Leadership_CarolHowiesV5.jpg](bp-20251231_g75.jpg)

---

| | |
|:---|:---|
|  | **Carol Howle**<br>EVP supply, trading<br>& shipping<br>|
| Carol Howle is also part of the bp leadership team in her <br>role as EVP supply, trading & shipping.<br>You can read her bio on **page <u>[73](#i0dd2ee81aac04f8c9c97c86197f0c6df_130)</u>**. | Carol Howle is also part of the bp leadership team in her <br>role as EVP supply, trading & shipping.<br>You can read her bio on **page <u>[73](#i0dd2ee81aac04f8c9c97c86197f0c6df_130)</u>**. |

---

![Leaderhip_EmmaDelaneyV3.jpg](bp-20251231_g99.jpg)

![Leadership_KerryDryburghV3.jpg](bp-20251231_g100.jpg)

---

| |
|:---|
| **Emma Delaney**<br>EVP customers <br>& products<br>|
| **Leadership team tenure** Appointed on 1 July 2020 |
| **Nationality** Irish |
| **Board memberships** |
| Director of RBML limited  |
| **Career summary** |
| Emma has spent 30 years working in bp, both in the <br>upstream and the downstream. Prior to joining bp's <br>executive team on 1 April 2020, she was regional <br>president for West Africa. She has held a variety of <br>senior roles including upstream chief financial officer for <br>Asia Pacific and head of business development for gas <br>value chains. In downstream she held roles in retail and <br>commercial fuels and planning. |

---

![Leadership_WilliamLinV3.jpg](bp-20251231_g101.jpg)

---

| |
|:---|
| **William Lin**<br>EVP gas & low <br>carbon energy<br>|
| **Leadership team tenure** Appointed on 1 July 2020 |
| **Nationality** American |
| **Board memberships** |
| William serves on the supervisory board of Corbion, a <br>publicly listed biotechnology company where he chairs <br>the sustainability & safety committee and sits on the <br>audit committee. He also chairs the board of JERA Nex <br>bp, a global offshore wind developer and is vice-chair at <br>Pan American Energy Group, Argentina's largest <br>independent energy company. |
| **Career summary** |
| William has worked at bp for 30 years and now leads the <br>group's global natural gas and low carbon businesses <br>and markets. Prior to this role, he held other senior <br>management positions including the chief operating <br>officer for upstream regions, regional president for Asia <br>Pacific, and vice president for gas developments and <br>operations for Egypt.  |

---

![Leadership_MikeSossoV3.jpg](bp-20251231_g102.jpg)

---

| |
|:---|
| **Kerry Dryburgh**<br>EVP people, culture <br>& communications<br>|
| **Leadership team tenure** Appointed on 1 July 2020 |
| **Nationality** British |
| **Board memberships** |
| **Career summary** |
| Kerry leads people, culture & communications, which <br>also includes brand, global transformation, health and <br>wellbeing and workplace. Prior to her current role, she <br>headed HR for bp's upstream business and served as <br>group chief talent officer, alongside senior HR roles in <br>supply, trading and corporate functions. Kerry began <br>her career with an apprenticeship and worked across <br>several sectors in Europe and Asia before joining bp <br>in 2010.  |

---

---

| |
|:---|
| **Mike Sosso**<br>EVP legal<br>|
| **Leadership team tenure** Appointed on 1 January <br>2024 |
| **Nationality** American |
| **Board memberships** |
| **Career summary** |
| Mike took on the role of EVP legal in January 2024. In his <br>role, Mike is accountable for leading the legal function <br>and executing the legal strategy for the group. Mike <br>joined bp in 2011 and has held a number of leadership <br>positions across legal. He also previously held the role <br>of VP ethics and compliance. Prior to joining bp, Mike <br>practised law in the Washington, DC office of Skadden, <br>Arps, Slate, Meagher & Flom. |

---

![GovernanceFrameworkV4-RIGHT.jpg](bp-20251231_g103.jpg)

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 77 |

---

---

| | |
|:---|:---|
|  | ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
|  | **Corporate governance** |
| **Governance framework** |  |

---

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| **Board of directors** | **Board of directors** | **Board of directors** |  |  |  |  |
| **Non-executive directors** | **Non-executive directors** | **Non-executive directors** | **Executive directors** | **Executive directors** | **Executive directors** |  |
| **Chair** | **Senior** <br>**independent** <br>**director**<br>| **Independent** <br>**non-executive**<br>**directors**<br>|  | **Chief executive**<br>**officer**<br>| **Chief financial** <br>**officer**<br>| **Company** <br>**secretary**<br>|
| **Board committees** |  |  |  |  |  |  |

---

---

| | | | |
|:---|:---|:---|:---|
| **Safety and sustainability**<br>**committee**<br>| **Audit**<br>**committee**<br>| **People, culture and** <br>**governance committee**<br>| **Remuneration**<br>**committee**<br>|
| Report from page [82](#i0dd2ee81aac04f8c9c97c86197f0c6df_160) | Report from page [84](#i0dd2ee81aac04f8c9c97c86197f0c6df_166) | Report from page [89](#i0dd2ee81aac04f8c9c97c86197f0c6df_184) | Report from page [91](#i0dd2ee81aac04f8c9c97c86197f0c6df_187) |
| **Executive leadership** | **Executive leadership** |  |  |
| **bp leadership team** | **bp leadership team** | **bp leadership team** | **bp leadership team** |

---

bp's governance framework helps to drive

informed and efficient decision making

through a clear division of responsibilities.

This enables bp to operate effectively and

in alignment with the strategy as set by

the board.

**Responsibilities of the board** 

The board is appointed by shareholders. Its

responsibility, through the directors, is to

promote the success of the company, to drive

value for shareholders, having regard to the

company's stakeholders and the

consequences of the decisions it takes in the

long term. Fulfilling this role, the board is

responsible for setting and overseeing the

implementation of the company's strategy,

purpose and values. The board's oversight role

includes monitoring culture and reviewing the

effectiveness of the company's system of

internal control.

More detailed information about the board's

activities is available from page <u>[78](#i0dd2ee81aac04f8c9c97c86197f0c6df_139)</u>.

**Delegation of authority**

There are four main committees of the board,

each operating under delegated

responsibilities which are outlined in their

respective terms of reference available at

<u>bp.com/governance</u>.

Day-to-day management of the business is

delegated by the board to the chief executive

officer (CEO), who in turn is advised and

supported by a leadership team (bpLT)

comprising seven individuals who are

accountable to her for their respective

business or functional areas, with defined

financial authority levels. Decisions are taken

by the CEO in the execution of the operational

responsibilities delegated to her by the board.

For example, the CEO's authority includes a

limit on the nature and type of investments,

capital expenditure★ and financial

commitments she may take in isolation. Any

matters that exceed this limit, or that go

beyond the annual plan or approved strategy,

constitute a matter reserved for the board as

a whole.

Further delegations of authority are maintained

throughout the business in a consistent way.

**Board committees**

The four board committees operate under

terms of reference which are reviewed

periodically.

The chair of each committee routinely reports

to the full board on their activities and, where

applicable, makes recommendations for the

board's approval.

**Board roles**

**Non-executive directors (NEDs)**

Provide independent oversight, mentoring and

constructive challenge to the executive

directors and bpLT. NEDs bring valuable

external perspective and support effective

governance in matters such as performance

management and succession planning.

Chair

• As chair, Albert Manifold leads the board

and is accountable to shareholders for its

overall effectiveness.

• This includes shaping and managing the

culture of the boardroom, facilitating the

board's ability to hear the views of

stakeholders, and overseeing the

composition and development of

the board.

Senior independent director (SID)

• Amanda Blanc acts as a sounding board

for the chair and, if necessary, as an

intermediary for other directors

and investors.

**Executive directors**

Executive directors are tasked with the

implementation of bp's strategy and are

responsible for all executive management

matters affecting the company.

Chief executive officer (CEO)

• In her capacity as interim CEO, Carol Howle

is responsible for the design and

implementation of bp's strategy and annual

plan, which are ultimately approved by

the board.

• In accordance with the authorities

delegated to her, the CEO implements the

system of internal control and is

responsible for setting policies, standards

and procedures that foster bp's culture

and values. In this regard, she is

accountable to the board which oversees

the effectiveness of the internal control

framework.

Chief financial officer (CFO)

• Our CFO Kate Thomson provides financial

leadership for the business and supports

the CEO in the development and

implementation of the strategy.

**Company secretary**

Ben Mathews advises the board on corporate

governance matters, changes to and

compliance with board procedures, and

monitors regulatory requirements. He also

supports the chair in providing timely,

accurate and clear information to the board.

Further information on specific board roles is

available at <u>bp.com/governance</u>.

---

| | | |
|:---|:---|:---|
| 78 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Board activities: promoting long-term sustainable success**<br>

In 2025, the board and its committees held regular meetings as needed, to address business requirements. Agendas were set in advance by the

chair, CEO, and company secretary, focusing on four pillars of strategy, performance, people, and governance. The board's activities, supported by

its committees, spanned each of these pillars. In 2025 this included visits to bp Washington DC, US and the Whiting refinery in Chicago, US,

facilitating direct engagement with a range of stakeholders. Highlights are provided below.

---

| | | | |
|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) | **Strategy and performance** <br>**Strategic direction** <sup>TCFD</sup><br>•Worked closely with the CEO and the leadership team to <br>approve a new purpose and reset strategy for bp, as <br>announced in February 2025.<br>•Established a routine of discussing progress against the <br>primary targets included in the reset strategy with <br>management, including insights into specific areas of the <br>business with the greatest impact on delivery. <br>**Macroeconomics** <sup>TCFD</sup><br>•Received regular updates on macroeconomic and geopolitical <br>factors affecting our strategy, plan and performance.<br>**Annual plan** <br>•Reviewed full-year delivery against the 2024 plan and <br>monitored progress against 2025 objectives, enhanced by <br>regular performance insight sessions with leadership from key <br>business areas.<br>▪Reviewed and approved the 2025 annual plan that focused on <br>capital allocation, cost reduction and initiatives to improve the <br>balance sheet and reduce net debt. <br>**Financial frame and distributions**<br>•Reviewed and approved a refreshed financial frame to <br>support the reset strategy, covering capital allocation, a <br>targeted reduction of net debt, and the delivery of resilient <br>shareholder distributions. <br>•Regularly reviewed performance against the financial frame.<br>•Regularly reviewed shareholder distribution options in <br>alignment with the financial frame. <br>**Capital expenditure**<br><sup>•</sup>Received an update from the CEO at every board meeting <br>covering projects across all bp's businesses and, where <br>appropriate, climate-related considerations.<sup>TCFD</sup> These updates <br>included any inorganic acquisition or divestment <br>opportunities of more than $1 billion.<br>**Mergers and acquisitions pipeline** <br>•Regularly reviewed divestment opportunities in support of the <br>net debt target set out as part of the reset strategy.<br>•Reached a final investment decision for the Tiber and <br>Guadalupe projects in the Gulf of America, approving bp's <br>second new production platform in less than two years.<br>•Approved the divestment of bp's majority interest in *Castrol*. | **Acquisition reviews** <br>•Evaluated progress on the integration of transition <br>businesses, Archaea Energy and TravelCenters of America. <sup>TCFD</sup><br>**Offsites** <br>•Board members visited three US sites: Whiting refinery, bpx <br>energy operations in Denver and bp Washington DC.<br>**Technology** <br>•Received an update on progress and delivery of the <br>technology functional reorganization, digital transformation <br>programme, the continued development and impact of <br>strategic partnerships and priorities for 2026.<br>•Participated in deep-dive sessions on the use of breakthrough <br>imaging and robotic automation, and the deployment of <br>generative artificial intelligence solutions across bp <br>businesses.<br>**Safety and sustainability** <sup>TCFD</sup><br>•Routine reviews of safety performance undertaken, including <br>measurement against targets and ad hoc reporting, as <br>required. <br>•Focused the sustainability aims on those most relevant to the <br>long-term success of our businesses and to our net zero <br>ambition.<br>**Principal risks** <br>•Analysed trends and themes arising from risk management <br>processes. <br>•Performed mid-year and full-year reviews of bp's principal <br>and emerging risks, including those related to climate. <sup>TCFD</sup> <br>**Internal controls**<br>•Evaluated the group's internal control and risk management <br>systems as part of the review and approval of the *bp Annual* <br>*Report and Form 20-F*. <br>•Routinely received reports from group risk and internal audit – <br>no specific concerns were identified and the board concluded <br>that the systems remain resilient, fit for purpose, and aligned <br>with external expectations (see how we manage risk on <br>page <u>[60](#i0dd2ee81aac04f8c9c97c86197f0c6df_106)</u>). | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Strategy and performance** <br>**Strategic direction** <sup>TCFD</sup><br>•Worked closely with the CEO and the leadership team to <br>approve a new purpose and reset strategy for bp, as <br>announced in February 2025.<br>•Established a routine of discussing progress against the <br>primary targets included in the reset strategy with <br>management, including insights into specific areas of the <br>business with the greatest impact on delivery. <br>**Macroeconomics** <sup>TCFD</sup><br>•Received regular updates on macroeconomic and geopolitical <br>factors affecting our strategy, plan and performance.<br>**Annual plan** <br>•Reviewed full-year delivery against the 2024 plan and <br>monitored progress against 2025 objectives, enhanced by <br>regular performance insight sessions with leadership from key <br>business areas.<br>▪Reviewed and approved the 2025 annual plan that focused on <br>capital allocation, cost reduction and initiatives to improve the <br>balance sheet and reduce net debt. <br>**Financial frame and distributions**<br>•Reviewed and approved a refreshed financial frame to <br>support the reset strategy, covering capital allocation, a <br>targeted reduction of net debt, and the delivery of resilient <br>shareholder distributions. <br>•Regularly reviewed performance against the financial frame.<br>•Regularly reviewed shareholder distribution options in <br>alignment with the financial frame. <br>**Capital expenditure**<br><sup>•</sup>Received an update from the CEO at every board meeting <br>covering projects across all bp's businesses and, where <br>appropriate, climate-related considerations.<sup>TCFD</sup> These updates <br>included any inorganic acquisition or divestment <br>opportunities of more than $1 billion.<br>**Mergers and acquisitions pipeline** <br>•Regularly reviewed divestment opportunities in support of the <br>net debt target set out as part of the reset strategy.<br>•Reached a final investment decision for the Tiber and <br>Guadalupe projects in the Gulf of America, approving bp's <br>second new production platform in less than two years.<br>•Approved the divestment of bp's majority interest in *Castrol*. | **Acquisition reviews** <br>•Evaluated progress on the integration of transition <br>businesses, Archaea Energy and TravelCenters of America. <sup>TCFD</sup><br>**Offsites** <br>•Board members visited three US sites: Whiting refinery, bpx <br>energy operations in Denver and bp Washington DC.<br>**Technology** <br>•Received an update on progress and delivery of the <br>technology functional reorganization, digital transformation <br>programme, the continued development and impact of <br>strategic partnerships and priorities for 2026.<br>•Participated in deep-dive sessions on the use of breakthrough <br>imaging and robotic automation, and the deployment of <br>generative artificial intelligence solutions across bp <br>businesses.<br>**Safety and sustainability** <sup>TCFD</sup><br>•Routine reviews of safety performance undertaken, including <br>measurement against targets and ad hoc reporting, as <br>required. <br>•Focused the sustainability aims on those most relevant to the <br>long-term success of our businesses and to our net zero <br>ambition.<br>**Principal risks** <br>•Analysed trends and themes arising from risk management <br>processes. <br>•Performed mid-year and full-year reviews of bp's principal <br>and emerging risks, including those related to climate. <sup>TCFD</sup> <br>**Internal controls**<br>•Evaluated the group's internal control and risk management <br>systems as part of the review and approval of the *bp Annual* <br>*Report and Form 20-F*. <br>•Routinely received reports from group risk and internal audit – <br>no specific concerns were identified and the board concluded <br>that the systems remain resilient, fit for purpose, and aligned <br>with external expectations (see how we manage risk on <br>page <u>[60](#i0dd2ee81aac04f8c9c97c86197f0c6df_106)</u>). |  |
|  | **Strategy and performance** <br>**Strategic direction** <sup>TCFD</sup><br>•Worked closely with the CEO and the leadership team to <br>approve a new purpose and reset strategy for bp, as <br>announced in February 2025.<br>•Established a routine of discussing progress against the <br>primary targets included in the reset strategy with <br>management, including insights into specific areas of the <br>business with the greatest impact on delivery. <br>**Macroeconomics** <sup>TCFD</sup><br>•Received regular updates on macroeconomic and geopolitical <br>factors affecting our strategy, plan and performance.<br>**Annual plan** <br>•Reviewed full-year delivery against the 2024 plan and <br>monitored progress against 2025 objectives, enhanced by <br>regular performance insight sessions with leadership from key <br>business areas.<br>▪Reviewed and approved the 2025 annual plan that focused on <br>capital allocation, cost reduction and initiatives to improve the <br>balance sheet and reduce net debt. <br>**Financial frame and distributions**<br>•Reviewed and approved a refreshed financial frame to <br>support the reset strategy, covering capital allocation, a <br>targeted reduction of net debt, and the delivery of resilient <br>shareholder distributions. <br>•Regularly reviewed performance against the financial frame.<br>•Regularly reviewed shareholder distribution options in <br>alignment with the financial frame. <br>**Capital expenditure**<br><sup>•</sup>Received an update from the CEO at every board meeting <br>covering projects across all bp's businesses and, where <br>appropriate, climate-related considerations.<sup>TCFD</sup> These updates <br>included any inorganic acquisition or divestment <br>opportunities of more than $1 billion.<br>**Mergers and acquisitions pipeline** <br>•Regularly reviewed divestment opportunities in support of the <br>net debt target set out as part of the reset strategy.<br>•Reached a final investment decision for the Tiber and <br>Guadalupe projects in the Gulf of America, approving bp's <br>second new production platform in less than two years.<br>•Approved the divestment of bp's majority interest in *Castrol*. | **Acquisition reviews** <br>•Evaluated progress on the integration of transition <br>businesses, Archaea Energy and TravelCenters of America. <sup>TCFD</sup><br>**Offsites** <br>•Board members visited three US sites: Whiting refinery, bpx <br>energy operations in Denver and bp Washington DC.<br>**Technology** <br>•Received an update on progress and delivery of the <br>technology functional reorganization, digital transformation <br>programme, the continued development and impact of <br>strategic partnerships and priorities for 2026.<br>•Participated in deep-dive sessions on the use of breakthrough <br>imaging and robotic automation, and the deployment of <br>generative artificial intelligence solutions across bp <br>businesses.<br>**Safety and sustainability** <sup>TCFD</sup><br>•Routine reviews of safety performance undertaken, including <br>measurement against targets and ad hoc reporting, as <br>required. <br>•Focused the sustainability aims on those most relevant to the <br>long-term success of our businesses and to our net zero <br>ambition.<br>**Principal risks** <br>•Analysed trends and themes arising from risk management <br>processes. <br>•Performed mid-year and full-year reviews of bp's principal <br>and emerging risks, including those related to climate. <sup>TCFD</sup> <br>**Internal controls**<br>•Evaluated the group's internal control and risk management <br>systems as part of the review and approval of the *bp Annual* <br>*Report and Form 20-F*. <br>•Routinely received reports from group risk and internal audit – <br>no specific concerns were identified and the board concluded <br>that the systems remain resilient, fit for purpose, and aligned <br>with external expectations (see how we manage risk on <br>page <u>[60](#i0dd2ee81aac04f8c9c97c86197f0c6df_106)</u>). |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) |  |  |  |  | ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) |
| ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) | **Board activity** <br>**highlights**  | **January and February:** <br>•Board meeting, virtual.<br>•Board and committee meetings (audit; <br>people, culture and governance; <br>remuneration; and safety and <br>sustainability) including Q4 results, <br>London, UK. | **March and April:**<br>•Board and committee meetings (audit <br>and remuneration) including Q1 <br>results, virtual.<br>•2025 Annual General Meeting, <br>Sunbury, UK. <br>•Workforce engagement session with <br>employees from the US and UK.  | **May and June:**<br>•Board and committee meetings (audit; <br>people, culture and governance; <br>remuneration; and safety and <br>sustainability), Washington DC, US.<br>•Visit to Whiting refinery, US.<br>•Workforce engagement sessions with <br>employees from Brazil; Canada; Gulf of <br>America; US; and UK. | ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) |
|  | **Board activity** <br>**highlights**  | **January and February:** <br>•Board meeting, virtual.<br>•Board and committee meetings (audit; <br>people, culture and governance; <br>remuneration; and safety and <br>sustainability) including Q4 results, <br>London, UK. | **March and April:**<br>•Board and committee meetings (audit <br>and remuneration) including Q1 <br>results, virtual.<br>•2025 Annual General Meeting, <br>Sunbury, UK. <br>•Workforce engagement session with <br>employees from the US and UK.  | **May and June:**<br>•Board and committee meetings (audit; <br>people, culture and governance; <br>remuneration; and safety and <br>sustainability), Washington DC, US.<br>•Visit to Whiting refinery, US.<br>•Workforce engagement sessions with <br>employees from Brazil; Canada; Gulf of <br>America; US; and UK. |  |
| ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) | **Board activity** <br>**highlights**  | **January and February:** <br>•Board meeting, virtual.<br>•Board and committee meetings (audit; <br>people, culture and governance; <br>remuneration; and safety and <br>sustainability) including Q4 results, <br>London, UK. | **March and April:**<br>•Board and committee meetings (audit <br>and remuneration) including Q1 <br>results, virtual.<br>•2025 Annual General Meeting, <br>Sunbury, UK. <br>•Workforce engagement session with <br>employees from the US and UK.  | **May and June:**<br>•Board and committee meetings (audit; <br>people, culture and governance; <br>remuneration; and safety and <br>sustainability), Washington DC, US.<br>•Visit to Whiting refinery, US.<br>•Workforce engagement sessions with <br>employees from Brazil; Canada; Gulf of <br>America; US; and UK. | ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |
| ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |  |  |  |  | ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 79 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

---

| | | | | |
|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) | **People**<br>**Engagement**<br>•Undertook the board's workforce engagement <br>programme (WFEP), using it to bring employee feedback <br>into the boardroom to allow for board decisions to be <br>better informed of stakeholder views (see page <u>[80](#i0dd2ee81aac04f8c9c97c86197f0c6df_142)</u>).<br>•Through the board's site visits, directors met with high-<br>potential employees to improve visibility and profile of <br>the executive succession pipeline and to increase <br>director interaction with the workforce in those locations <br>(further information on in-person site visits on page <u>[80](#i0e1c9c18aad14259ba08133d542166ec_2268)</u>).<br>**Culture**<br>•Received feedback from Pulse employee surveys, <br>agreeing actions and initiatives in response.<br>•Reviewed the annual ethics and compliance report, and <br>the function's priorities and objectives.<br>**Succession planning**<br>•Supported by the people, culture and governance <br>committee, the board received updates on succession <br>plans for the board (see page <u>[90](#i372e476394b943ee83d7eb667cf64e6f_168957)</u> for further information <br>on board succession). <br>•Undertook a review of leadership development initiatives, <br>including succession plans for the bp leadership team. | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) | **Governance**<br>**Board composition and director changes**<br>•Following a comprehensive selection process, appointed: <br>–Albert Manifold as non-executive director with effect <br>from 1 September 2025 and as chair of the board and <br>chair of the people, culture and governance committee <br>with effect from 1 October 2025.<br>–Ian Tyler as a non-executive director and member of the <br>remuneration committee with effect from 1 April 2025, <br>and as chair of the remuneration committee with effect <br>from 17 April 2025.<br>–Dave Hager as a non-executive director with effect from <br>2 June 2025, and as a member of the safety and <br>sustainability committee with effect from 10 December <br>2025. <br>–Simon Henry as a non-executive director with effect from <br>1 September 2025.<br>–Carol Howle as interim CEO with effect from 18 <br>December 2025 and Meg O'Neill as CEO with effect <br>from 1 April 2026.<br>**Corporate governance framework**<br>▪Considered the corporate governance framework, <br>including the terms of reference for the board and each <br>committee.<br>**Director training and knowledge sessions**<br>•Completed online training on topics including the code of <br>conduct and cyber security.<br>**Board performance review**<br>•Conducted an internally facilitated board and committee <br>performance review led by the chair and company <br>secretary (see page <u>[90](#i372e476394b943ee83d7eb667cf64e6f_235260)</u>). <br>**Investor engagement**<br>•The chair, executive directors, senior independent <br>director, remuneration committee chair, company <br>secretary and members of senior management engaged <br>with investors through meetings, roadshows, quarterly <br>results calls, presentations and the Annual General <br>Meeting. Reports on such engagement was shared with <br>the full board. | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **People**<br>**Engagement**<br>•Undertook the board's workforce engagement <br>programme (WFEP), using it to bring employee feedback <br>into the boardroom to allow for board decisions to be <br>better informed of stakeholder views (see page <u>[80](#i0dd2ee81aac04f8c9c97c86197f0c6df_142)</u>).<br>•Through the board's site visits, directors met with high-<br>potential employees to improve visibility and profile of <br>the executive succession pipeline and to increase <br>director interaction with the workforce in those locations <br>(further information on in-person site visits on page <u>[80](#i0e1c9c18aad14259ba08133d542166ec_2268)</u>).<br>**Culture**<br>•Received feedback from Pulse employee surveys, <br>agreeing actions and initiatives in response.<br>•Reviewed the annual ethics and compliance report, and <br>the function's priorities and objectives.<br>**Succession planning**<br>•Supported by the people, culture and governance <br>committee, the board received updates on succession <br>plans for the board (see page <u>[90](#i372e476394b943ee83d7eb667cf64e6f_168957)</u> for further information <br>on board succession). <br>•Undertook a review of leadership development initiatives, <br>including succession plans for the bp leadership team. |  | **Governance**<br>**Board composition and director changes**<br>•Following a comprehensive selection process, appointed: <br>–Albert Manifold as non-executive director with effect <br>from 1 September 2025 and as chair of the board and <br>chair of the people, culture and governance committee <br>with effect from 1 October 2025.<br>–Ian Tyler as a non-executive director and member of the <br>remuneration committee with effect from 1 April 2025, <br>and as chair of the remuneration committee with effect <br>from 17 April 2025.<br>–Dave Hager as a non-executive director with effect from <br>2 June 2025, and as a member of the safety and <br>sustainability committee with effect from 10 December <br>2025. <br>–Simon Henry as a non-executive director with effect from <br>1 September 2025.<br>–Carol Howle as interim CEO with effect from 18 <br>December 2025 and Meg O'Neill as CEO with effect <br>from 1 April 2026.<br>**Corporate governance framework**<br>▪Considered the corporate governance framework, <br>including the terms of reference for the board and each <br>committee.<br>**Director training and knowledge sessions**<br>•Completed online training on topics including the code of <br>conduct and cyber security.<br>**Board performance review**<br>•Conducted an internally facilitated board and committee <br>performance review led by the chair and company <br>secretary (see page <u>[90](#i372e476394b943ee83d7eb667cf64e6f_235260)</u>). <br>**Investor engagement**<br>•The chair, executive directors, senior independent <br>director, remuneration committee chair, company <br>secretary and members of senior management engaged <br>with investors through meetings, roadshows, quarterly <br>results calls, presentations and the Annual General <br>Meeting. Reports on such engagement was shared with <br>the full board. |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) | **Governance**<br>**Board composition and director changes**<br>•Following a comprehensive selection process, appointed: <br>–Albert Manifold as non-executive director with effect <br>from 1 September 2025 and as chair of the board and <br>chair of the people, culture and governance committee <br>with effect from 1 October 2025.<br>–Ian Tyler as a non-executive director and member of the <br>remuneration committee with effect from 1 April 2025, <br>and as chair of the remuneration committee with effect <br>from 17 April 2025.<br>–Dave Hager as a non-executive director with effect from <br>2 June 2025, and as a member of the safety and <br>sustainability committee with effect from 10 December <br>2025. <br>–Simon Henry as a non-executive director with effect from <br>1 September 2025.<br>–Carol Howle as interim CEO with effect from 18 <br>December 2025 and Meg O'Neill as CEO with effect <br>from 1 April 2026.<br>**Corporate governance framework**<br>▪Considered the corporate governance framework, <br>including the terms of reference for the board and each <br>committee.<br>**Director training and knowledge sessions**<br>•Completed online training on topics including the code of <br>conduct and cyber security.<br>**Board performance review**<br>•Conducted an internally facilitated board and committee <br>performance review led by the chair and company <br>secretary (see page <u>[90](#i372e476394b943ee83d7eb667cf64e6f_235260)</u>). <br>**Investor engagement**<br>•The chair, executive directors, senior independent <br>director, remuneration committee chair, company <br>secretary and members of senior management engaged <br>with investors through meetings, roadshows, quarterly <br>results calls, presentations and the Annual General <br>Meeting. Reports on such engagement was shared with <br>the full board. |  |
|  |  |  | **Governance**<br>**Board composition and director changes**<br>•Following a comprehensive selection process, appointed: <br>–Albert Manifold as non-executive director with effect <br>from 1 September 2025 and as chair of the board and <br>chair of the people, culture and governance committee <br>with effect from 1 October 2025.<br>–Ian Tyler as a non-executive director and member of the <br>remuneration committee with effect from 1 April 2025, <br>and as chair of the remuneration committee with effect <br>from 17 April 2025.<br>–Dave Hager as a non-executive director with effect from <br>2 June 2025, and as a member of the safety and <br>sustainability committee with effect from 10 December <br>2025. <br>–Simon Henry as a non-executive director with effect from <br>1 September 2025.<br>–Carol Howle as interim CEO with effect from 18 <br>December 2025 and Meg O'Neill as CEO with effect <br>from 1 April 2026.<br>**Corporate governance framework**<br>▪Considered the corporate governance framework, <br>including the terms of reference for the board and each <br>committee.<br>**Director training and knowledge sessions**<br>•Completed online training on topics including the code of <br>conduct and cyber security.<br>**Board performance review**<br>•Conducted an internally facilitated board and committee <br>performance review led by the chair and company <br>secretary (see page <u>[90](#i372e476394b943ee83d7eb667cf64e6f_235260)</u>). <br>**Investor engagement**<br>•The chair, executive directors, senior independent <br>director, remuneration committee chair, company <br>secretary and members of senior management engaged <br>with investors through meetings, roadshows, quarterly <br>results calls, presentations and the Annual General <br>Meeting. Reports on such engagement was shared with <br>the full board. |  |
| ![BoardActivitiesV4.jpg](bp-20251231_g104.jpg) | ![BoardActivitiesV4.jpg](bp-20251231_g104.jpg) | ![BoardActivitiesV4.jpg](bp-20251231_g104.jpg) | **Governance**<br>**Board composition and director changes**<br>•Following a comprehensive selection process, appointed: <br>–Albert Manifold as non-executive director with effect <br>from 1 September 2025 and as chair of the board and <br>chair of the people, culture and governance committee <br>with effect from 1 October 2025.<br>–Ian Tyler as a non-executive director and member of the <br>remuneration committee with effect from 1 April 2025, <br>and as chair of the remuneration committee with effect <br>from 17 April 2025.<br>–Dave Hager as a non-executive director with effect from <br>2 June 2025, and as a member of the safety and <br>sustainability committee with effect from 10 December <br>2025. <br>–Simon Henry as a non-executive director with effect from <br>1 September 2025.<br>–Carol Howle as interim CEO with effect from 18 <br>December 2025 and Meg O'Neill as CEO with effect <br>from 1 April 2026.<br>**Corporate governance framework**<br>▪Considered the corporate governance framework, <br>including the terms of reference for the board and each <br>committee.<br>**Director training and knowledge sessions**<br>•Completed online training on topics including the code of <br>conduct and cyber security.<br>**Board performance review**<br>•Conducted an internally facilitated board and committee <br>performance review led by the chair and company <br>secretary (see page <u>[90](#i372e476394b943ee83d7eb667cf64e6f_235260)</u>). <br>**Investor engagement**<br>•The chair, executive directors, senior independent <br>director, remuneration committee chair, company <br>secretary and members of senior management engaged <br>with investors through meetings, roadshows, quarterly <br>results calls, presentations and the Annual General <br>Meeting. Reports on such engagement was shared with <br>the full board. |  |
| ![BoardActivitiesV4.jpg](bp-20251231_g104.jpg) | ![BoardActivitiesV4.jpg](bp-20251231_g104.jpg) | ![BoardActivitiesV4.jpg](bp-20251231_g104.jpg) | **Governance**<br>**Board composition and director changes**<br>•Following a comprehensive selection process, appointed: <br>–Albert Manifold as non-executive director with effect <br>from 1 September 2025 and as chair of the board and <br>chair of the people, culture and governance committee <br>with effect from 1 October 2025.<br>–Ian Tyler as a non-executive director and member of the <br>remuneration committee with effect from 1 April 2025, <br>and as chair of the remuneration committee with effect <br>from 17 April 2025.<br>–Dave Hager as a non-executive director with effect from <br>2 June 2025, and as a member of the safety and <br>sustainability committee with effect from 10 December <br>2025. <br>–Simon Henry as a non-executive director with effect from <br>1 September 2025.<br>–Carol Howle as interim CEO with effect from 18 <br>December 2025 and Meg O'Neill as CEO with effect <br>from 1 April 2026.<br>**Corporate governance framework**<br>▪Considered the corporate governance framework, <br>including the terms of reference for the board and each <br>committee.<br>**Director training and knowledge sessions**<br>•Completed online training on topics including the code of <br>conduct and cyber security.<br>**Board performance review**<br>•Conducted an internally facilitated board and committee <br>performance review led by the chair and company <br>secretary (see page <u>[90](#i372e476394b943ee83d7eb667cf64e6f_235260)</u>). <br>**Investor engagement**<br>•The chair, executive directors, senior independent <br>director, remuneration committee chair, company <br>secretary and members of senior management engaged <br>with investors through meetings, roadshows, quarterly <br>results calls, presentations and the Annual General <br>Meeting. Reports on such engagement was shared with <br>the full board. | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

---

| | |
|:---|:---|
| **Image:** Members of the board at our Canary Wharf office, London, UK | **Key:** TCFD Recommendations and Recommended Disclosures  |

---

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) |  |  |  |  | ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) |
| ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) | **Board activity** <br>**highlights** | **July and August:** <br>•Board and committee meetings (audit; <br>people, culture and governance; <br>remuneration; and safety and <br>sustainability), including Q2 results, <br>London, UK.<br>•Visit to bpx energy, Denver, US.<br>•Workforce engagement session with <br>employees from Greece; Hungary; <br>Spain; UK; and US.  | **September and October:** <br>•Board and committee meetings (audit; <br>remuneration; and safety and <br>sustainability) London, UK.<br>•Visit to bp supply, trading and shipping <br>floor, London, UK by the audit committee.<br>•Workforce engagement sessions with <br>employees from India; Malaysia; and UK.  | **November and December:** <br>•Board and audit committee meetings, <br>including Q3 results, virtual.<br>•Board and Committee meetings (people, <br>culture and governance; remuneration; <br>audit and safety and sustainability) <br>London, UK.<br>•Workforce engagement sessions with <br>employees from Hungary; India; UAE; <br>and UK.  | ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) |
|  | **Board activity** <br>**highlights** | **July and August:** <br>•Board and committee meetings (audit; <br>people, culture and governance; <br>remuneration; and safety and <br>sustainability), including Q2 results, <br>London, UK.<br>•Visit to bpx energy, Denver, US.<br>•Workforce engagement session with <br>employees from Greece; Hungary; <br>Spain; UK; and US.  | **September and October:** <br>•Board and committee meetings (audit; <br>remuneration; and safety and <br>sustainability) London, UK.<br>•Visit to bp supply, trading and shipping <br>floor, London, UK by the audit committee.<br>•Workforce engagement sessions with <br>employees from India; Malaysia; and UK.  | **November and December:** <br>•Board and audit committee meetings, <br>including Q3 results, virtual.<br>•Board and Committee meetings (people, <br>culture and governance; remuneration; <br>audit and safety and sustainability) <br>London, UK.<br>•Workforce engagement sessions with <br>employees from Hungary; India; UAE; <br>and UK.  |  |
| ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) | **Board activity** <br>**highlights** | **July and August:** <br>•Board and committee meetings (audit; <br>people, culture and governance; <br>remuneration; and safety and <br>sustainability), including Q2 results, <br>London, UK.<br>•Visit to bpx energy, Denver, US.<br>•Workforce engagement session with <br>employees from Greece; Hungary; <br>Spain; UK; and US.  | **September and October:** <br>•Board and committee meetings (audit; <br>remuneration; and safety and <br>sustainability) London, UK.<br>•Visit to bp supply, trading and shipping <br>floor, London, UK by the audit committee.<br>•Workforce engagement sessions with <br>employees from India; Malaysia; and UK.  | **November and December:** <br>•Board and audit committee meetings, <br>including Q3 results, virtual.<br>•Board and Committee meetings (people, <br>culture and governance; remuneration; <br>audit and safety and sustainability) <br>London, UK.<br>•Workforce engagement sessions with <br>employees from Hungary; India; UAE; <br>and UK.  | ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |
| ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |  |  |  |  | ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |

---

---

| | | |
|:---|:---|:---|
| 80 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Our stakeholders**<br>

Directors regularly engage with a wide range

of stakeholders to gain different insights,

giving the board a more rounded perspective

in support of the decisions it takes. This

engagement helps the directors fulfil their

statutory duties and build greater trust inside

and outside of bp. It also helps improve the

board's understanding of stakeholder views on

bp's strategy, performance, operations and

governance – all in support of the long-term

success of the company.

![OurStakeholders_WhitingV2.jpg](bp-20251231_g105.jpg)

**Image:** Members of the board during their tour of

Whiting refinery, US

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Stakeholders key** <br>🟇 Investors and shareholders<br>🟇 Customers<br>🟇 Workforce<br>🟇 Governments and regulators<br>🟇 Partners and suppliers<br>🟇 Society<br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

---

| | | |
|:---|:---|:---|
| ![BPGreenTopRoundCorner.gif](bp-20251231_g21.gif) |  | ![BPGreenTopRoundCorner.gif](bp-20251231_g21.gif) |
|  | Our Section 172(1) statement <br>describes how the directors have <br>had regard to the matters set out in <br>Section 172(1)(a) to (f) of the <br>Companies Act 2006; see page <u>[71](#i0dd2ee81aac04f8c9c97c86197f0c6df_118)</u>.<br>Further information on the board's <br>activities and key decisions, <br>including how stakeholder <br>interests have been considered, <br>can be found on pages <u>[78](#i0dd2ee81aac04f8c9c97c86197f0c6df_139)</u><u>-</u><u>[80](#i54193e928abd4aab9179415c637df771_1974)</u> and <br>page <u>[81](#ibb1035e027d14d6a8c8a91d24b2b3e89_550)</u>. <br>|  |
| ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |  | ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |

---

**Fostering mutual understanding**

🟇🟇

The board's approach to stakeholder

engagement allows for a better understanding

of matters that are important and relevant to

the decisions it takes and to support the

delivery of bp's strategy.

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

the key mechanisms for engagement with

colleagues is the workforce engagement

programme (WFEP). NEDs participate in

roundtable sessions with selected individuals

on a specific topic. In 2025 these sessions

included safety, culture, remuneration

and technology.

To engage bp colleagues, directors were

involved in bp's webcasts during the year.

Additionally, on becoming chair of bp,

Albert Manifold gave a video message to

introduce himself to bp employees and

set out his priorities.

bp's financial and operational performance

was an important topic for both investors and

the workforce in 2025, with directors seeking

to enhance each group's understanding of the

factors affecting the company's overall

performance through their engagements.

**Promoting balanced perspectives**

🟇🟇🟇🟇

In 2025 board engagements included eight

WFEP sessions, and meetings with local

businesses, partners, governments and

regulators from key jurisdictions.

The audit committee participated in a floor

walk of the supply, trading & shipping function

at bp's Canary Wharf site in the UK.

Several director engagements were held with

leadership teams from Archaea Energy, bpx

energy and the Gulf of America, in addition to a

dedicated session with the US leadership team

as part of the board programme in May.

In addition to the AGM, results calls,

roadshows, one-to-one and group meetings

with investors in 2025, bp held a retail

shareholder engagement event, hosted by the

company secretary. Feedback from this event

was used by the board to inform future

investor engagements. As with all shareholder

engagement activity, including votes received

from shareholders at the AGM, the feedback

received is taken into account in helping to

inform board discussion and debate and areas

of particular focus for management.

**Delivery of strategy guided by** 

**stakeholder perspectives**

🟇🟇🟇🟇🟇🟇

The bp strategy reset announced in February

2025 was developed following a

comprehensive stakeholder engagement

programme undertaken throughout 2024. In

2025 the board's focus was on overseeing

management's performance in its delivery of

the strategy.

---

| | |
|:---|:---|
|  | See more on key decisions, page <u>[81](#i0dd2ee81aac04f8c9c97c86197f0c6df_151)</u> |
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | See more on key decisions, page <u>[81](#i0dd2ee81aac04f8c9c97c86197f0c6df_151)</u> |

---

**Building trust in bp**

🟇🟇🟇

Two themes for the board in helping to

maintain and enhance organizational trust

continue to be safety performance and culture.

On safety, directors gained valuable insights

from employees, suppliers and partners as

part of board meetings, company-wide

engagements and site visits. Examples in 2025

included presentations by refining, bpx energy

and Gulf of America on safety plans and

performance. Notably, the safety and

sustainability committee's visit to the Whiting

refinery in the US provided direct insights on

the site's approach to safety, operational

reliability and its ongoing commitment to

continuous performance improvement.

Related to culture, feedback was shared on

progress against bp's organizational

transformation. The Pulse employee

engagement survey reports and OpenTalk

reports (bp's whistleblowing service) continue

to be a feature of board discussions. Looking

to the future of bp, the board reviewed the

talent pipeline and leadership development.

Board member participation in the

bpChallenge, bp's flagship early-careers event,

offered valuable perspectives into the

company's talent development programme.

For more on culture see page <u>[90](#i372e476394b943ee83d7eb667cf64e6f_272219)</u>.

**Opportunities for collaboration**

🟇🟇🟇🟇🟇

By attending meetings and events with

external stakeholders, and bp's partners and

suppliers, the board gained insight into market

trends and development opportunities.

Engagements with governments and

regulators, together with consideration

of wider society's interests, focused on

long-term, sustainable value. For example,

capital investment (Argos expansion in

US Gulf of America), and portfolio growth

opportunities (Egypt, Trinidad and Tobago,

Mauritania and Senegal).

bp's success in collaboration with partners

has led to several joint venture discoveries,

including in Namibia's Orange Basin and

Gajajeira-01 in Angola. A key highlight in 2025

was the Bumerangue (Brazil) discovery –

the biggest for bp in 25 years.

**Benchmarking progress**

🟇🟇🟇🟇🟇🟇

Stakeholder engagement enhances the

board's ability to benchmark our progress

against peers and to innovate, ultimately

benefiting our shareholders, workforce,

customers, suppliers and business partners,

and the communities where bp operates.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 81 |

---

---

| | |
|:---|:---|
|  | ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
|  | **Corporate governance** |
| **Key decisions** |  |

---

Section 172 of the Companies Act 2006 requires directors to act in a way they believe will promote the success of the company for the benefit of

its shareholders. The directors are required to consider the long-term impact of their decisions, the interests of employees, relationships with

stakeholders, the community and environment and maintain high standards of business conduct. Set out below are four of the key decisions taken

by the board during 2025 reflecting the directors' consideration of these requirements.

---

| | | | | |
|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | Strategy and performance <sup>TCFD</sup> |  | Leadership transition |  |
|  | In support of the strategy reset, announced in February 2025, <br>the board approved a refreshed financial frame with four <br>primary financial targets: growing free cash flow, increasing <br>the cost reduction target, reducing net debt and generating <br>higher returns on investment. Five focused sustainability aims <br>were also approved: net zero operations, net zero sales, people, <br>biodiversity, and water.<br>Having taken these decisions, the board wanted to closely <br>monitor and oversee the implementation of the reset strategy <br>and the delivery of the primary targets. During 2025, the board <br>engaged in an extensive dialogue with the bpLT, with more <br>granular reporting reviewed at every board meeting. This <br>approach was supplemented by a programme of insight <br>sessions where the leaders of the businesses with the greatest <br>potential impact on delivery of the targets provided deeper <br>insight on their plans and targets and tools that could be used <br>to mitigate any risk to delivery into those business areas. <br>The board, through the remuneration committee, sought to <br>achieve alignment of performance measures for the group's <br>long and short-term incentive arrangements with the reset <br>strategy, ensuring that the four primary financial targets form <br>part of the basis for internal performance management and <br>remuneration outcomes through to 2027.<br>**Stakeholders considered**<br>🟇🟇🟇🟇🟇🟇<br>|  | After more than three decades with bp, Murray Auchincloss <br>informed the chair of his openness to step down as CEO were <br>an appropriate leader identified who could accelerate delivery <br>of bp's strategy. A committee of the board was established <br>and undertook a comprehensive search process which led <br>to the appointment of Meg O'Neill as CEO with effect from <br>1 April 2026, with Carol Howle serving as interim CEO from <br>18 December 2025 until Meg's appointment takes effect. <br>When reviewing the recommendations from the committee <br>to appoint Meg, the board considered how the leadership <br>transition could accelerate bp's strategic vision to become <br>a simpler, leaner, and more profitable company, and created <br>an opportunity to make the necessary transformative <br>changes to maximize value for shareholders.<br>The board considered Meg to be the most appropriate <br>candidate given her proven track record of driving <br>transformation, growth, and disciplined capital allocation. <br>Her relentless focus on business improvement and financial <br>discipline positions her well in leading bp through its next <br>phase of growth.<br>**Stakeholders considered**<br>🟇🟇🟇🟇🟇🟇<br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | Expanding production capacity |  | *Castrol* divestment approval |  |
|  | In September 2025 the board took a final investment decision <br>(FID) for a seventh operated oil and gas production hub, Tiber-<br>Guadalupe, in the US Gulf of America. The new hub, which <br>features a floating production platform and includes six wells <br>in the Tiber field and a two-well tieback from the Guadalupe <br>field, is expected to have a production capacity of 80,000 <br>barrels of oil per day. Production is expected to start in 2030.<br>In reviewing the FID proposal, the board considered how <br>existing platform and subsea equipment designs could be <br>utilized to drive cost efficiencies across the production hub's <br>construction, commissioning and operations. The board <br>concluded that the hub's strategically advantaged location, <br>ability to deploy enhanced high-pressure drilling technology <br>and synergies identified from using more than 85% of the <br>design from bp's Kaskida project (another board-approved oil <br>and gas production hub in the Gulf of America, announced in <br>July 2024) combined to make a strong economic case for <br>sanctioning this project.<br>**Stakeholders considered**<br>🟇🟇🟇🟇<br>|  | In December 2025 the board approved the sale of a 65% <br>shareholding in *Castrol* to Stonepeak, at an enterprise value <br>of $10.1 billion. This represents an implied EV / LTM EBITDA of <br>around 8.6x reflecting the strength of the business and future <br>growth potential. <br>The decision followed a comprehensive strategic review <br>of *Castrol*, through which the board considered how the <br>transaction would accelerate delivery of bp's reset strategy, <br>including focusing the downstream, and strengthening the <br>balance sheet. With the transaction expected to generate <br>approximately $6.0 billion in net proceeds for bp upon <br>completion, the board decided to fully utilize the proceeds <br>to reduce net debt. Completion is anticipated by the end of <br>2026, subject to regulatory approvals. The board decided <br>to retain a 35% interest in the new joint venture, providing <br>continued exposure to *Castrol's* growth while maintaining <br>the option to divest its remaining stake after a two-year <br>lock-up period. <br>**Stakeholders considered**<br>🟇🟇🟇🟇<br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

---

| | | |
|:---|:---|:---|
| 82 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Safety and sustainability committee**<br>

![SafeSusCommitteeMelodyV4.jpg](bp-20251231_g106.jpg)

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | "The committee <br>provided disciplined <br>oversight of safety, <br>security and <br>sustainability across <br>the business."<br>**Melody Meyer**<br>Safety and sustainability <br>committee chair<br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

**Meetings and attendance**

The committee met five times during 2025.

Regular attendees included EVP production

and operations; SVP safety and operational

risk assurance; SVP intelligence, security and

crisis management; SVP digital security; SVP

HSE and carbon; and SVP global ethics and

compliance.

---

| | |
|:---|:---|
| **Non-executive directors** | Five <br>scheduled <br>meetings<br>|
| Melody Meyer: member (from May <br>2017), chair of the committee (from <br>November 2019)<br>| 5/5 |
| Dave Hager: member (from December <br>2025)<br>| 0/0 |
| Satish Pai: member | 5/5 |
| Johannes Teyssen: member<sup>a</sup> | 4/5 |

---

aJohannes Teyssen was unable to attend the scheduled

meeting in September 2025 due to an existing external

commitment.

**Chair's introduction**

**Dear fellow shareholders,** 

I am pleased to present the safety and

sustainability committee report for the year

ended 31 December 2025.

During 2025, the committee provided

disciplined oversight of safety, security, and

sustainability across the business, with a

strong emphasis on risk management and

operational excellence. This included

overseeing progress in the implementation of

Process Safety Improvement Plans (PSIPs) in

certain businesses, conducting deeper dives

on both process and personal safety,

reviewing personal and cyber security, and

considering operational integrity. The

committee also reviewed the principal safety

risks and associated mitigations, and received

updates on the integration of bp's safety

standards into newly acquired businesses.

Tragically, four colleagues lost their lives

during 2025. We extend our sincere

condolences to the families, friends and

colleagues of all of those impacted.

One fatality occurred in our *Thorntons* retail

business and three occurred in separate

incidents in our TravelCenters of America (*TA*)

business during roadside assistance activities.

During the incident investigation, and

permanently thereafter, all highway roadside

assistance activities were suspended in our *TA* 

business. As with all major incidents, the

committee received reports on the incident

investigation findings and the actions taken

in response.

Following the company's strategy reset in

February 2025, the committee provided

oversight on the implementation of the five

refreshed sustainability aims: net zero

operations; net zero sales; people; biodiversity;

and water. For more information see page <u>[37](#i0dd2ee81aac04f8c9c97c86197f0c6df_82)</u>.

During 2025, members of the committee

participated in a site visit to Whiting refinery in

the US. This site visit provided the opportunity

to have open and constructive dialogue with

employees and observe bp's safety and

sustainability culture and performance

in action.

As I reach the end of my nine-year term on the

board and as chair of the committee, I want to

express my sincere appreciation for the high

level of engagement, transparency and

commitment demonstrated across bp in

advancing safety performance, sustainability

and operational excellence.

Looking forward to 2026, the committee will

focus its oversight on maintaining the good

progress and continuous improvement in

safety performance and the implementation of

bp's Operating Management System★ within

recently acquired businesses.

**Role of the committee**

The committee oversees the management of

safety and sustainability matters, including

physical and cyber security and relevant

systems and processes, focusing on those

which it considers to be most potentially

material from time to time.

**Key responsibilities**

The committee's full terms of reference can be

viewed at <u>bp.com/governance</u>.

**Melody Meyer**

Committee chair

6 March 2026

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 83 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

**Activities during the year** 

**Overseeing improved safety** 

**performance**

The committee continued to oversee safety

performance, supporting management's

progress in reducing combined tier 1 and 2

process safety events★. During 2025,

combined tier 1 and tier 2 safety performance

improved, with combined process safety

events being 29% lower than in 2024.

The committee received regular reports from

the EVP production and operations on safety

and operational performance, incident

reviews, and on the mitigation of principal and

emerging safety risks around the business. It

also received updates from management on

the implementation of PSIPs in certain

businesses and updates on personal security

improvements, including the integrity of crisis

management and business continuity

processes.

Deep-dive updates regarding significant or

material events and specific risk areas within

the business were also received. The

committee challenged management on the

root cause and learnings from these incidents

and how learnings are embedded into existing

safety processes.

**Providing challenge on risk** 

**management**

The committee provides independent

challenge to management on the

effectiveness of the processes and

procedures implemented to manage safety

and sustainability risk. This is achieved through

regular review and monitoring of the principal

risks allocated to it by the board and through

deep-dives on key risk areas including wells,

process safety, marine risk, product quality,

pipeline risk, transportation risk, maintenance

integrity, cyber security, ethics and

compliance, and regulatory compliance.

Further deep-dives were undertaken into

specific areas of risk within the business

covering risk management and safety

performance in newly acquired businesses,

such as TravelCenters of America, Archaea

Energy and bp bioenergy. This provided the

committee with enhanced oversight of the

integration of bp's Operating Management

System★ into newly acquired businesses.

The committee routinely received:

• Updates on the activities of internal audit,

focused on operational safety audits,

together with an annual report on bp's

system of internal control. This provides an

independent view on management's safety

and sustainability performance, as well as

an independent assessment of key

challenges and risk areas.

• Briefings from the SVP global ethics and

compliance on emerging areas of risk and

associated mitigations, including increased

reports of external threats affecting retail

operations.

• Reports on cyber security risks and the

effectiveness of mitigation processes,

including identification of emerging cyber

risks from AI and geopolitical events.

The committee also continued its joint

engagement with the audit committee

through combined updates on non-operated

joint venture safety and sustainability.

**Oversight of sustainability matters**

**Refreshing bp's sustainability frame** <sup>TCFD</sup>

The committee reviewed and endorsed a

refreshed sustainability frame with five aims:

net zero operations; net zero sales; people;

biodiversity; and water. Progress against these

aims was monitored through regular updates

from management. In 2025 focused deep-

dives were undertaken into each pillar of the

sustainability frame, with focus on

management's plans to address areas of more

challenged delivery.

**Human rights and global reporting** 

**landscape**

The committee reviewed progress on

mitigations in human rights and modern

slavery. It also kept abreast of the current

global sustainability reporting environment,

including bp's plans for compliance through

reporting from management.

**Sustainability and safety linked** 

**remuneration targets**

The committee made recommendations to the

remuneration committee regarding safety and

sustainability targets and outcomes that are

tied to remuneration. This included critically

analyzing current methodologies for the

setting of targets to ensure they remain

appropriately stretching, and incorporated

changes to the sustainability frame announced

in February 2025.

---

| | | |
|:---|:---|:---|
| ![49789_bp_WhitingRefineryVisitV1.jpg](bp-20251231_g107.jpg) | ![49789_bp_WhitingRefineryVisitV1.jpg](bp-20251231_g107.jpg) | ![49789_bp_WhitingRefineryVisitV1.jpg](bp-20251231_g107.jpg) |
|  | Whiting refinery visit<br>During the visit to the Whiting <br>refinery, the S&SC members were <br>briefed on infrastructure upgrades, <br>with particular emphasis on <br>enhancements to electrical <br>systems and the refinery's <br>continued focus on safety, <br>reliability and continuous <br>improvement. <br>The S&SC members also took a <br>driving tour of the refinery to gain <br>a deeper understanding of its <br>operational footprint and <br>integration with the local <br>community. The visit provided an <br>opportunity for the Whiting team <br>to demonstrate their critical role in <br>bp's integrated value chain and <br>commitment to operational <br>excellence. <br>**Image:** Whiting refinery, US<br>|  |
| ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |  | ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |

---

TCFD Information that supports TCFD Recommendations and Recommended Disclosures in relation to governance (see pages <u>[41](#i64435a2b74134bf69d5c362d53a40cc9_7984)</u><u>-</u><u>[44](#i0dd2ee81aac04f8c9c97c86197f0c6df_94)</u>)

---

| | | |
|:---|:---|:---|
| 84 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Audit committee**<br>

![AuditCommitteeTulsharV4.jpg](bp-20251231_g108.jpg)

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | "The committee had <br>particular focus on <br>advancing digital <br>transformation <br>initiatives."<br>**Tushar Morzaria**<br>Audit committee chair<br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

**Meetings and attendance**

The committee met eight times during 2025.

Regular attendees included the chief financial

officer (CFO), group controller, SVP internal

audit, EVP legal and the external auditor.

---

| | |
|:---|:---|
| **Non-executive directors** | Eight <br>scheduled <br>meetings<br>|
| Tushar Morzaria: member (from <br>September 2020), chair of the <br>committee (from May 2021)<br>| 8/8 |
| Pamela Daley<sup>a</sup>: member (until 7 July <br>2025)<br>| 2/4 |
| Karen Richardson: member | 8/8 |
| Hina Nagarajan<sup>b</sup>: member | 7/8 |
| Ian Tyler: member (from 2 June 2025) | 4/4 |

---

aPamela was unable to attend the meetings in April and May

due to personal reasons.

bHina was unable to attend the meeting in September due to

pre-existing external commitments.

**Chair's introduction**

**Dear fellow shareholders,** 

I am pleased to present the audit committee

report for the year ended 31 December 2025.

Financial reporting remains central to the

committee's responsibilities – monitoring its

integrity, overseeing management's control

procedures and evaluating their effectiveness

and working with internal and external

auditors to ensure that what you – our

shareholders – rely on in our reporting has

been appropriately challenged and reviewed.

This involves acting on behalf of the board and

co-ordinating input from other committees as

needed, including reporting and making

recommendations to the board.

In 2025 the committee maintained its

oversight of bp's reporting processes, with

particular emphasis on advancing digital

transformation initiatives and monitoring their

implementation progress.

Among its many activities during the year, the

committee has monitored progress against

bp's 2027 $4-5 billion structural cost reduction

target. In addition, the committee is

overseeing the mandatory external audit

tender, with the tender process expected to

conclude during 2026.

As the regulatory environment evolves, the

committee remains engaged with

management to oversee bp's approach to new

reporting requirements, with particular focus

on the new UK Corporate Governance Code

2024, provision 29 readiness. The committee

also monitored management's plans for the

implementation of financial and non-financial

reporting developments.

In September 2025 the committee visited bp's

supply, trading and shipping business in

Canary Wharf, London. The visit included a tour

of the trading floors and business briefings,

with a particular focus on the energy and

commodities trading operations. Read more

on page <u>[85](#i860bf9c1ea294cb8a6d18fd9e54a3223_2-1-1-1-846290)</u>. The committee continues to

engage with other stakeholders where

appropriate, including through regulatory

inspections when they occur.

On behalf of my colleagues on the committee,

I would like to extend my thanks for the

continued professional support and focus of

effort by management and our various

advisers during a year where bp delivered

strong performance in some areas but had

some challenges in others. We look forward to

continuing this journey through 2026.

**Role of the committee** 

The committee monitors the effectiveness of

the group's financial reporting, including ESG

and climate-related financial disclosures, as

well as systems of internal control and risk

management as allocated by the board. It also

monitors the integrity of the external and

internal audit processes.

This report describes how bp has approached

compliance with the provisions of the FRC's

Audit Committees and the External Audit:

Minimum Standard.

**Key responsibilities** 

A summary of the committee's terms of

reference is on page <u>[359](#i5dbbfb2777b74b258b4fefa82a7dce3a_7231)</u> and the full

terms of reference can be viewed at

<u>bp.com/governance</u>.

**Tushar Morzaria**

Committee chair

6 March 2026

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Financial expertise**<br>The board is satisfied that<br>•Tushar Morzaria, the chair of the <br>committee, has recent and <br>relevant financial experience as <br>required by the UK Corporate <br>Governance Code and that he is <br>competent in accounting and <br>auditing in accordance with the <br>FCA's Disclosure Guidance and <br>Transparency Rules.<br>•The committee has an <br>appropriate and experienced <br>blend of commercial, financial <br>and audit expertise to assess <br>the issues it is required to <br>address, as well as competence <br>in the relevant sector in which <br>bp operates. During 2025, Ian <br>Tyler was appointed as a <br>member of the committee, <br>further strengthening the <br>committee's financial expertise.<br>•As a US foreign private issuer, <br>the committee meets the <br>independence criteria <br>provisions of Rule 10A-3 of the <br>US Securities Exchange Act of <br>1934, and Tushar Morzaria can <br>be regarded as an audit <br>committee financial expert <br>as defined in Item 16A of <br>Form 20-F. <br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 85 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

**Activities during the year**

**Monitoring the integrity of financial** 

**reporting and assurance**

• Through monitoring and reviewing that bp's

financial statements and formal

announcements relating to bp's financial

performance are clear and appropriate, the

committee oversees the integrity of our

financial reporting.

• Management's application of key

accounting policies and recommendations

on financial reporting judgements was

carefully considered, with the committee

concluding that these matters were

appropriately addressed in the financial

statements.

• The committee monitored progress and

reporting on cost savings.

**Going concern, viability and fair,** 

**balanced and understandable** 

**considerations**

The committee reviewed the company's going

concern assumption and longer-term viability

statement. In determining and recommending

to the board that it was appropriate to adopt

the going concern basis of accounting and the

longer-term viability of the company, the

committee carefully considered and, where

appropriate, constructively challenged

relevant underlying assumptions and

supporting analysis.

The committee received an update from

management on the verification process for

the bp *Annual Report and Form 20-F* in

support of its recommendation to the board

that the report was fair, balanced and

understandable. These documents were

comprehensively reviewed with input from

subject matter experts and the external

auditors. The committee's review included

consideration of bp's non-financial disclosures

such as the Task Force on Climate-related

Financial Disclosures (TCFD) that are made in

compliance with the UK Listing Rules. <sup>TCFD</sup>

**Maintaining resilience through** 

**systems of internal control and** 

**risk management**

• The committee oversaw risk management

and internal control processes, routinely

reviewing and monitoring principal risks

allocated to it by the board through a

combination of business or function

reviews and focused engagement with

key stakeholders.

• Through a deep-dive update, the

committee reviewed supply, trading

and shipping business performance.

The session focused on the refined

products trading and shipping interface,

LNG and power benches as well as key and

emerging market, operational and

geopolitical risks.

• The committee reviewed the affordability of

proposed distributions, taking into account

factors such as whether sufficient

distributable reserves are available.

• In addition, the committee received:

–updates on the systems in place to assess

fraud risk and the controls in place to

manage and mitigate identified risks,

reflecting developments such as to the

UK's Economic Crime and Corporate

Transparency Act.

–an update on compliance with new

business regulations, together with

additional briefings during the year on

technical accounting updates and

developing ESG disclosures. <sup>TC</sup><sup>FD</sup>

• The committee remained focused on

regulatory developments, including

receiving updates on the consideration of

enhancements to bp's risk management

and internal control framework as a result

of the UK Corporate Governance Code

2024, and received updates on

implementation progress.

**Effectiveness of risk management and** 

**systems of internal control**

The committee reviewed and challenged

management on the effectiveness of the

system of internal control and agreed that it

did not require further action nor were there

any significant failings or weaknesses to

report. As part of this assessment the

committee considered internal audit's annual

review of internal control and risk

management, together with an assessment of

it from management. The committee also

discussed internal controls and financial

reporting processes during the year,

challenging control gaps identified, root cause

analysis and remediation actions, and

reviewing progress towards addressing

deficiencies that had previously been

identified in relation to manual journal

controls. Tier II control gap reporting was

introduced at each scheduled meeting.

Further details on internal controls in place for

financial reporting can be found on page <u>[360](#i984213dc492a461bbcdf2c7de91382f0_5873)</u>.

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. <sup>TCFD</sup>

---

| | | |
|:---|:---|:---|
| ![AuditReport-CanaryWharfV3.jpg](bp-20251231_g109.jpg) | ![AuditReport-CanaryWharfV3.jpg](bp-20251231_g109.jpg) | ![AuditReport-CanaryWharfV3.jpg](bp-20251231_g109.jpg) |
|  | Canary Wharf <br>site visit <br>During the audit committee's tour <br>in September of the supply, trading <br>and shipping (ST&S) floors in <br>Canary Wharf, London, the <br>directors met internal stakeholders <br>based there, hearing from <br>colleagues in gas & power and <br>refining & products trading. <br>**Image**: Audit committee members at our <br>Canary Wharf office, London, UK<br>|  |
| ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |  | ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |

---

TCFD Information that supports TCFD Recommendations and Recommended Disclosures in relation to governance (see pages <u>[41](#i64435a2b74134bf69d5c362d53a40cc9_7984)</u><u>-</u><u>[44](#i0dd2ee81aac04f8c9c97c86197f0c6df_94)</u>)

---

| | | |
|:---|:---|:---|
| 86 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Audit committee** continued<br>

**Overseeing the relationship with** 

**external and internal audit**

• During the year, the FRC's Audit Quality

Review (AQR) team selected Deloitte's

audit of the Company's Annual Report and

Accounts for the year ended 31 December

2024 as part of its annual inspection of

audit firms. The review was assessed as

'limited improvements required' with only

one other finding identified. The chair of the

committee received a full copy of the FRC's

report, and discussed it with Deloitte. The

committee confirmed that there were no

significant areas for improvement

identified, no key findings within the report

and was satisfied that there is nothing

within the report which might have a

bearing on the audit appointment.

• On the recommendation of the committee,

the board will propose the reappointment

of Deloitte as the company's external

auditor to shareholders at the 2026 annual

general meeting. The external auditor's

independence and objectivity were

reviewed and monitored by the committee

using a combination of factors, including

assurances provided to it by the external

auditor, the level of non-audit fees, and the

timeline for lead audit partner rotation and

re-tender of audit services. The committee

concluded that it was satisfied with the

audit team's effectiveness, service quality

and commitment, including that the

external auditor provides constructive

challenge to management. In support of

this, the committee received reports from

the external auditor that covered insights

from their audit work, actions taken to

address the FRC's annual report on the

external auditor, and the inspection results

of the external auditor's quality control

procedures. During 2025, following the

2024 audit, the external auditor undertook

an auditor effectiveness review. The

process comprised a series of interviews

with senior stakeholders within bp who

engage with the audit team on a regular

basis. Stakeholder feedback reflected a

positive view of the quality and

effectiveness of the audit. In addition,

the committee received reports from

management, which included a survey

seeking internal stakeholder feedback on

the external auditor's performance and bp's

commitment to the audit. The main

measurement criteria covered planning and

scope, robustness of audit, independence

and objectivity, quality of delivery, quality of

people and service, and value-added

advice.

• The committee met privately with the

external auditor during the year and, in

addition, reviewed, approved and

monitored progress against the external

audit plan, considering materiality levels,

audit risks, scoping changes, and

resourcing. The committee is satisfied that

the external auditor has full access to staff

and records. The committee continued to

monitor and review the effectiveness and

capabilities of the internal audit function.

This included, for example, reviewing and

approving the internal audit plan in the

context of bp's principal risks. The

committee concluded that the function had

independent, unrestricted scope, access to

information, and sufficient resources to

fulfil its mandate. They met privately with

the SVP internal audit, discussed regular

updates on internal audit activities and

where appropriate challenged

management's response and progress

made on the closure of findings.

**Lead audit partner rotation and** 

**re-tender of audit services**

The external auditor must rotate the lead audit

partner every five years and other senior staff

every five to seven years.

The company complies with the Statutory

Audit Services for Large Companies Market

Investigation (Mandatory Use of Competitive

Tender Processes and Audit Committee

Responsibilities) Order 2014, which requires

bp to tender the audit at least every 10 years.

External audit services were last tendered in

2016, and the external auditor has been in that

role since 2018 (seven years). During the year

the committee agreed an approach, timeline

and selection criteria for a re-tendering of

audit services that is anticipated will be

completed by the end of 2026, for the

2028 audit.

**Oversight of audit fees and**

**non-audit services**

The committee reviewed and approved the

audit services fee and terms of engagement

for the external auditor while retaining

oversight of bp's policy on non-audit services

and the review and approval of non-audit

services.

The total amount of audit and non-audit

fees paid to Deloitte for 2025 is set out in

**Financial statements –** Note 36. The

committee is satisfied that the audit fee is

appropriate in respect of the audit services

provided. The majority of non-audit fees relate

to work of an assurance nature.

The non-audit services policy safeguards audit

objectivity and independence through the

prohibition of non-audit tax services being

provided by the external auditor, the limitation

of audit-related work which falls within defined

categories, and by stating that the auditor may

not perform non-audit services that are

prohibited by the SEC, Public Company

Accounting Oversight Board (PCAOB),

International Auditing and Assurance

Standards Board (IAASB) or the FRC.

The external auditor is considered for

permitted non-audit services only when its

expertise and experience of bp are important.

Approvals for individual engagements of pre-

approved permitted services below certain

thresholds are delegated to the group

controller or the CFO. More information is

outlined in the principal accountant's fees and

services on page <u>[361](#i0dd2ee81aac04f8c9c97c86197f0c6df_532)</u>.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 87 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

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

**and how relevant accounting policies have been applied** 

---

| | | | | |
|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Key accounting judgements and estimates** | **Audit committee activity** | **Conclusions/outcomes** |  |
|  | **Impact of climate change and the energy transition** <sup>TCFD</sup> | **Impact of climate change and the energy transition** <sup>TCFD</sup> | **Impact of climate change and the energy transition** <sup>TCFD</sup> |  |
|  | Climate change and the transition to a lower <br>carbon economy may have significant impacts on <br>the currently reported amounts of the group's <br>assets and liabilities and on similar assets and <br>liabilities that may be recognized in the future.<br>| •Reviewed management's best estimate of oil <br>and natural gas price assumptions for value-in-<br>use impairment testing and investment <br>appraisal. <br>•Reviewed management's determination that its <br>best estimate of oil and natural gas prices is in <br>line with a range of transition paths consistent <br>with the goals of the Paris climate change <br>agreement.<br>| **•Management's revised best estimates of oil and** <br>**natural gas prices are in line with a range of** <br>**transition paths consistent with the goals of the** <br>**Paris climate change agreement.**<br>**•See Financial statements –** Note 1 **for more** <br>**details on how bp applies carbon pricing in its** <br>**impairment testing, sensitivity analyses** <br>**estimating effects of changes in net revenue** <br>**and changes in the expected timing of** <br>**decommissioning.**<br>|  |
|  | **Provisions** | **Provisions** |  |  |
|  | The group holds provisions primarily for <br>decommissioning, environmental remediation <br>and litigation. The most significant provision is for <br>the future decommissioning of oil and natural gas <br>production facilities and pipelines. Estimation <br>uncertainty exists as most of these events are <br>many years in the future. Assumptions are made <br>by bp in relation to cost estimation, settlement <br>dates, technology, legal requirements and <br>discount rates. There is also a risk that <br>decommissioning obligations from previously <br>divested assets revert to bp.<br>| •Received briefings on decommissioning <br>(including the process for managing the risk of <br>decommissioning reversion), environmental, <br>asbestos and litigation provisions. These <br>included the requirements, governance and <br>controls for the development and approval of <br>cost estimates and provisions in the financial <br>statements.<br>•Reviewed and challenged the group's discount <br>rates for calculating provisions.<br>| •Decommissioning provisions of $12.3 billion <br>were recognized on the balance sheet at 31 <br>December 2025.<br>•The discount rate used by bp to determine the <br>balance sheet obligation at the end of 2025 was <br>a nominal rate of 4.5% based on long-dated US <br>government bonds. The discount rate remains <br>unchanged from the prior year.<br>|  |
|  | **Recoverability of asset carrying values** | **Recoverability of asset carrying values** | **Recoverability of asset carrying values** |  |
|  | Determination as to whether and how much an <br>asset (including exploration intangibles), cash <br>generating unit (CGU) or group of CGUs <br>containing goodwill is impaired involves <br>management judgement and estimates on <br>uncertain matters such as future commodity <br>prices, discount rates, production profiles, <br>reserves and the impact of inflation on operating <br>expenses. Judgement is required to determine <br>whether it is appropriate to continue to carry <br>intangible assets related to exploration costs on <br>the balance sheet.<br>| •Reviewed policy and guidelines for compliance <br>with oil and gas reserves disclosure regulation, <br>including the group's reserves governance <br>framework and controls.<br>•Reviewed and challenged the group's oil and <br>gas price assumptions.<br>•Reviewed and challenged the group's discount <br>rates for impairment testing purposes.<br>•Impairment charges, reversals and 'watch-list' <br>items were reviewed in the quarterly due <br>diligence process. <br>| •The group's price assumption for Brent oil and <br>for Henry Hub gas were updated as set out on <br>page <u>[20](#iaa9f5ec2f5544670b4a71dc5d5bce3a9_0-0-1-5-725324)</u> and Financial statements – Note 1.<br>•Sensitivity analyses estimating the effect of <br>changes in net revenue and discount rate <br>assumptions have been disclosed in Financial <br>statements – Note 1.<br>•Net impairment charges of $5.2 billion as <br>disclosed in Financial statements – Note 4.<br>•Exploration intangibles totalled $4.0 billion at <br>31 December 2025.<br>|  |
|  | **Taxation** | **Taxation** | **Taxation** |  |
|  | Computation of the group's income tax expense <br>and liability, the provisioning for potential tax <br>liabilities and the level of deferred tax asset <br>recognition are underpinned by management <br>judgement and estimation of the amounts which <br>could be payable. Judgement is also required <br>when determining whether a particular tax is an <br>income tax or another tax type.<br>| •Received regular updates on the group's tax risk <br>exposures and deferred tax asset recognition.<br>•Reviewed the judgements exercised over tax <br>risk provisioning as part of its annual review of <br>key provisions.<br>| •Deferred tax assets of $4.3 billion were <br>recognized on the balance sheet at 31 December <br>2025. <br>•The calculation of tax risk provisions is <br>consistent with IAS 37 and IFRIC 23.<br>|  |
|  | **Pensions** | **Pensions** | **Pensions** |  |
|  | Accounting for pensions and other post-<br>employment benefits involves making estimates <br>when measuring the group's pension plan <br>surpluses and deficits. These estimates require <br>assumptions to be made about uncertain events, <br>including discount rates, inflation and life <br>expectancy.<br>| •Reviewed and challenged the group's <br>assumptions used to determine the projected <br>benefit obligation at the year end, including the <br>discount rate, rate of inflation, salary growth <br>and mortality levels.<br>| •At 31 December 2025, surpluses of $7.8 billion <br>and deficits of $4.8 billion were recognized on <br>the balance sheet in relation to pensions and <br>other post-employment benefits.<br>•The method for determining the group's <br>assumptions remained largely unchanged from <br>2024. The values of these assumptions and a <br>sensitivity analysis of the impact of possible <br>changes on the benefit expense and obligation <br>are provided in Financial Statements – Note 24.<br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

---

| | | |
|:---|:---|:---|
| 88 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Audit committee** continued<br>

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

**and how relevant accounting policies have been applied continued**

---

| | | | | |
|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Key accounting judgements and estimates** | **Audit committee activity** | **Conclusions/outcomes** |  |
|  | **Supplier finance arrangements** | **Supplier finance arrangements** | **Supplier finance arrangements** |  |
|  | The group's trade payables include certain <br>supplier finance arrangements that utilize letter <br>of credit facilities and promissory notes. <br>Judgement is required to assess trade payables <br>subject to supplier financing arrangements to <br>determine whether they should continue to be <br>classified as trade payables and give rise to <br>operating cash flows or finance debt and <br>financing cash flows. <br>| •Received a briefing on the group's supplier <br>finance arrangements.<br>•Reviewed the group's proposed enhanced <br>disclosures in relation to Amendments to IAS 7 <br>'Statement of Cash Flows' and IFRS 7 'Financial <br>Instruments: disclosures' relating to supplier <br>finance arrangements.<br>| •bp had liabilities of $5.6 billion, $1.4 billion and <br>$1.0 billion, respectively, in respect of letters of <br>credit, promissory notes and reverse factoring <br>arrangements that are presented within trade <br>and other payables at 31 December 2025.<br>•The disclosures required by the Amendments to <br>IAS 7 'Statement of Cash Flows' and IFRS 7 <br>'Financial Instruments: disclosures' relating to <br>supplier finance arrangements are included in <br>Financial Statements – Note 29.<br>|  |
|  | **Derivatives** | **Derivatives** | **Derivatives** |  |
|  | For its level 3 derivative financial instruments, bp <br>estimates their fair values using internal models <br>due to the absence of quoted market pricing or <br>other observable, market-corroborated data. <br>Judgement may be required to determine <br>whether contracts to buy or sell commodities <br>meet the definition of a derivative, in particular <br>LNG contracts.<br>| •Received a briefing on the group's trading risks <br>and reviewed the system of risk management <br>and controls in place. <br>•Reviewed the control process and risks relating <br>to the trading business. <br>•Received updates on accounting judgements <br>on LNG contracts.<br>| •bp has assets and liabilities of $20.1 billion and <br>$18.2 billion, respectively, recognized on the <br>balance sheet for level 3 derivative financial <br>instruments at 31 December 2025, mainly <br>relating to the activities of the supply, trading & <br>shipping function. bp's use of internal models to <br>value certain of these contracts has been <br>disclosed in Financial Statements – Note 1. <br>•bp considers that contracts to buy or sell LNG <br>do not meet the definition of a derivative <br>under IFRS.<br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 89 |

---

---

| | |
|:---|:---|
|  | ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
|  | **Corporate governance** |
| **People, culture and governance committee** |  |

---

![PeopleCultGovernCommitteeAlbertV5.jpg](bp-20251231_g9.jpg)

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | "2025 has been a <br>busy year for the <br>committee, with a <br>strong focus on board <br>succession."<br>**Albert Manifold**<br>People, culture and governance <br>committee chair<br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

**Meetings and attendance**

The committee met five times during 2025.

The CEO and EVP people, culture &

communications regularly attend these

meetings.

---

| | |
|:---|:---|
| **Non-executive directors** | Five scheduled <br>meetings<br>|
| Albert Manifold: member (from <br>September 2025); chair of the <br>committee (from October 2025)<br>| 1/1 |
| Helge Lund: member (until <br>September 2025); chair of the <br>committee (until September <br>2025)<br>| 4/4 |
| Dame Amanda Blanc: member  | 5/5 |
| Dr Johannes Teyssen: member  | 5/5 |
| Hina Nagarajan: member  | 5/5 |

---

**Chair's introduction**

**Dear shareholders,**

I am pleased to present the people, culture

and governance committee report for the year

ended 31 December 2025, my first since being

appointed as board chair and as chair of the

committee on 1 October 2025.

2025 has been a particularly busy year for the

committee, with a strong focus on board

succession.

In support of the strategy reset in February

2025 and to fill current and anticipated

vacancies on the board, the committee

undertook a search process to identify new

board members who would bring the

additional skills and experience required as bp

embarked on its next chapter. The search

process resulted in three new non-executive

directors being appointed:

• Ian Tyler was appointed on 1 April 2025,

succeeding Tushar Morzaria as chair of the

remuneration committee with effect from

17 April 2025 and becoming a member of

the audit committee from 2 June 2025.

• Dave Hager joined the board on 2 June

2025 and became a member of the safety

and sustainability committee with effect

from 10 December 2025.

• Simon Henry joined the board on

1 September 2025.

In April 2025, Helge Lund informed the board

of his intention to step down as chair. Pamela

Daley informed the board in July 2025 that she

would also be standing down from the board.

During the year, Murray Auchincloss also

informed the board of his openness to step

down as CEO.

Comprehensive search processes were

undertaken by separate committees of the

board in connection with these decisions.

In turn, this led to my own appointment as a

non-executive director from 1 September

2025, succeeding Helge as chair of the board

and of this committee on 1 October 2025. It

also resulted in the appointment of Meg

O'Neill as CEO with effect from 1 April 2026,

with Carol Howle being appointed as interim

CEO with effect from 18 December 2025 until

Meg joins the board.

Further information on these search processes

is provided on page <u>[90](#i372e476394b943ee83d7eb667cf64e6f_168957)</u>.

In addition to board succession matters,

during 2025, the committee continued its

focus on culture, reviewing feedback from the

workforce engagement sessions that took

place during the year and the results of the

annual and live employee pulse surveys to

gauge employee sentiment.

**Role of the committee**

The committee seeks to ensure that the

composition and structure of the board and

leadership team remain effective. It also

monitors the balance of skills, knowledge,

experience and diversity of the board. The

committee oversees the development of a

diverse pipeline for executive succession to

the board and leadership team through

continuous succession planning and

monitoring development plans for bp leaders

and beyond.

The committee tracks bp's culture and its

alignment with our 'Who we are' culture frame,

and monitors sentiment of the workforce.

The process for the nomination, induction

and orderly succession of candidates for the

board, the leadership team and the company

secretary role are led by the committee,

as is the annual board and committee

performance review.

**Key responsibilities**

The committee's full terms of reference can be

viewed at <u>bp.com/governance</u>.

**Albert Manifold**

Committee chair

6 March 2026

---

| |
|:---|
| ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) |
| **Diversity statistics** <br>**and outcomes**<br>As at 31 December 2025, 46% of the <br>board were women, three senior <br>board positions were held by <br>women and three directors <br>identified as being from a minority <br>ethnic background. For further <br>details on board and leadership <br>team diversity, in line with the UK <br>Listing Rules, see page <u>[126](#ie62ba8781b2d437eada41bd6b6242422_19270)</u>.<br>As at 31 December 2025, senior <br>management, defined as the <br>leadership team (being the first <br>layer of management below board <br>level) and the company secretary<sup>a</sup>, <br>and their direct reports, comprised <br>44% women (2024 50%) and 22% <br>Black, Asian and other ethnic <br>minority individuals (2024 29%).<br>a As defined in the UK Corporate Governance <br>Code 2024.<br>|
| ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |

---

---

| | | |
|:---|:---|:---|
| 90 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**People, culture and governance committee** continued<br>

**Activities during the year** 

**Succession planning**

**Chair and CEO succession** 

The board established two committees to lead

the selection processes for the company's next

chair and CEO. The committee that led the search

process for the new chair was chaired by Dame

Amanda Blanc, joined by Melody Meyer, Hina

Nagarajan and Johannes Teyssen as members.

The committee that led the search process for

the CEO was chaired by Albert Manifold, joined

by Dame Amanda Blanc, Dave Hager, Karen

Richardson, and Ian Tyler as members.

Executive search consultants, Egon Zehnder<sup>a</sup>,

were appointed to support both processes by

identifying suitable candidates to replace Helge

Lund and Murray Auchincloss against role

specifications agreed by the respective

committees and the board. Each role

specification set out the skills, experience,

diversity and knowledge required for each role,

including leadership capability, industry, sector,

safety and operational expertise.

Shortlisted candidates were invited to interviews

with members of each committee. The preferred

candidates for each role were then invited to

meet the full board.

The board appointed Albert Manifold as a non-

executive director and chair designate with

effect from 1 September 2025 and as chair of

the board and this committee with effect from

1 October 2025.

The board appointed Meg O'Neill as CEO with

effect from 1 April 2026. Carol Howle was

appointed as interim CEO with effect from 18

December 2025 until Meg joins the board. See

page <u>[81](#ibb1035e027d14d6a8c8a91d24b2b3e89_550)</u> for further information on the decision-

making process and stakeholder considerations.

**The board and committees**

As part of the ongoing process to refresh the

board and to ensure it has the right balance of

skills, experience, and diversity needed to meet

the company's current and future priorities, the

committee agreed the criteria for three new non-

executive roles. The criteria focused on

candidates primarily from the UK and US with

industry, sector, safety and operational

experience, including, in the case of the

remuneration committee leadership,

remuneration committee expertise and the ability

to lead complex remuneration considerations for

a complex global company such as bp.

Suitable candidates for each role were identified

against the agreed role profiles with support

from Egon Zehnder<sup>a</sup> and shortlisted candidates

were invited to interview with members of

the committee.

This process resulted in the board approving the

committee's recommendations to appoint

Ian Tyler, Dave Hager, and Simon Henry as new

non-executive directors.

During the year, the membership of the board

committees was also reviewed. As a result, Ian

Tyler was appointed as chair of the remuneration

committee with effect from 17 April 2025 and as a

member of the audit committee from 17 April

2025. Dave Hager was appointed as a member of

the safety and sustainability committee with

effect from 10 December 2025.

**bp's leadership team**

The committee oversees development plans for

bp's senior leaders and emerging talent and their

alignment with executive succession planning

over various timescales. Development plans

identify the desired breadth and depth of

experience and roles required to bolster the skills

of individuals with executive potential.

**Diversity**

Better decision making and outcomes are

achieved when people with differences of

opinion and with different backgrounds come

together with a common ambition. The

committee periodically reviews the board's

diversity, equity and inclusion (DE&I) policy.

The board's DE&I policy applies to the board and

its committees, and complements bp's wider

diversity policies, the group's values, code of

conduct and sustainability frame. It includes

gender and ethnicity representation targets for

the board that are aligned with the UK Listing

Rules. Read more at <u>bp.com/governance</u>.

**Oversight of culture and the voice of** 

**the workforce**

The committee oversees employee engagement,

leading and lagging indicators of culture, and

how culture is being embedded. This includes

monitoring feedback from the workforce

engagement programme (WFEP) and private

sessions with bp's SVP, ethics and compliance

(E&C), who has accountability to, and direct

channels of communication with, the committee.

The committee is responsible for approving the

appointment and termination of the SVP, E&C

and reviews and recommends their remuneration

to the remuneration committee.

The WFEP continued during 2025 with directors

engaging with employees across multiple

regions and from different disciplines on topics

including leadership and culture, safety (including

retail safety), transformation, and remuneration.

Insights from these sessions are collated and

shared with the board, strengthening its

consideration of workforce views in board

discussions and the decisions it ultimately takes.

The committee continues to consider that the

WFEP is the most appropriate mechanism for

workforce engagement, given the activities and

structure of bp. Read more on page **<u>[80](#i54193e928abd4aab9179415c637df771_1974)</u>**.

**Board performance** 

The externally facilitated board performance

review in 2024 highlighted the continuing

importance of succession planning to drive the

delivery of the reset strategy. Building on the

outputs from the 2024 review, the board

appointed three new non-executive directors and

introduced enhanced performance reporting by

management during the year. This reporting was

supplemented by a programme of insight

sessions, providing the board with in-depth

briefings from leaders of the businesses with the

greatest impact on the delivery of strategy.

The CEO's performance review is conducted by

the chair, with input from the senior independent

director. Given the short tenure of Albert

Manifold, a performance review of the chair was

not undertaken in 2025. This process is usually

led by the senior independent director.

Helge Lund's decision to step down from the

board in April 2025 and the appointment in

September 2025 of his successor offered an

opportunity, alongside the board's established

performance-evaluation processes, for the

continuing directors to reflect on the roles and

performance of the board and its committees.

This in turn influenced the skills, experience and

leadership credentials that were sought from the

new board chair and, then also, the new CEO.

Ultimately, having appointed Albert Manifold as

chair from 1 October 2025 and Meg O'Neill as

new CEO from 1 April 2026, the board concluded

that the process of the 2025 performance review

for the board and its committees had been

comprehensively undertaken. In view of this, a

standalone supplementary performance review

was therefore not warranted. Additionally, and

since his appointment to the role, the chair held a

series of one-to-one meetings with each non-

executive director to discuss their reflections on

the board's performance and that of its

committees and individual board members.

Overall, the insights gathered from the 2025

performance review will inform the future needs

and roles of the board and its respective

committees, how they operate and the optimal

composition of the board over the longer term.

Among the changes already in motion as a result

of this review process, members of the

leadership team routinely join board meetings to

discuss safety, operational and financial

performance, major projects and delivery of the

four primary targets set out in the reset strategy.

The introduction of a reporting dashboard during

the year strengthened this enhanced board

oversight of performance at a more granular

level, by business group and against key metrics.

This is being supplemented with additional

scheduled board time for in-depth discussions

on performance and portfolio composition.

aThe committee engaged Egon Zehnder in support of search activity for new board candidates. Egon Zehnder does not have any connection with the company or individual directors, save that

Egon Zehnder provides advice and support on bp's executive development programme.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 91 |

---

---

| | |
|:---|:---|
|  | ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
|  | **Corporate governance** |
| **Directors' remuneration report** |  |

---

![RemunerationReportIanV4.jpg](bp-20251231_g110.jpg)

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | "2025 was a year of strong <br>underlying financial and <br>operational performance <br>and we have made <br>meaningful progress <br>towards the strategic <br>priorities announced in <br>February 2025."<br>**Ian Tyler**<br>Remuneration committee chair<br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

**Meetings and attendance**

The chair and the chief executive officer (CEO)

are standing attendees, except for matters

relating to their own remuneration. The CEO is

consulted on the remuneration of the chief

financial officer (CFO) and other members of

the leadership team, and receives input from

the committee on remuneration across the

wider workforce. Both the CEO and CFO are

consulted on matters relating to the group's

performance and the metrics adopted for

each performance cycle.

bp's EVP people, culture & communications,

SVP reward, external advisors and other

executives may attend where necessary. The

committee consults other board committees

on the group's performance and on issues

relating to the exercise of judgement or

discretion as necessary.

The committee met nine times during 2025.

Meeting attendance can be found below.

---

| | | |
|:---|:---|:---|
| **Non-executive** <br>**directors**<br>| Seven <br>scheduled <br>meetings<br>| Two<br>ad hoc <br>meetings<br>|
| Ian Tyler: chair of the <br>committee<sup>a</sup><br>| 4/4 | 2/2 |
| Tushar Morzaria: <br>member<sup>a</sup><br>| 7/7 | 2/2 |
| Dame Amanda Blanc: <br>member <br>| 7/7 | 2/2 |
| Pamela Daley: member<sup>b</sup> | 2/4 | 0/0 |
| Melody Meyer: member | 7/7 | 2/2 |

---

aIan Tyler was appointed as remuneration committee chair

from the conclusion of the 2025 AGM. Tushar Morzaria

stepped down as interim remuneration committee chair

from this date.

bPamela Daley stepped down as a non-executive director

and member of the remuneration committee on 7 July 2025.

**Role of the committee** 

The role of the committee is to determine and

recommend to the board the remuneration

policy and to set chair, executive director and

leadership team remuneration. In determining

the policy, the committee takes into account

various factors, including wider workforce

remuneration, structures and alignment of

reward with performance, thus promoting the

long-term success of the company. The

committee also reviews workforce

remuneration and monitors related policies,

satisfying itself that incentives and rewards

are aligned with bp's goals and culture.

**Key responsibilities** 

A summary of the committee's terms of

reference is on page <u>[359](#i5dbbfb2777b74b258b4fefa82a7dce3a_7231)</u> and the full terms

can be reviewed at <u>bp.com/governance</u>.

**Key areas of focus in 2025**

**•Workforce engagement** – engaged with the

wider workforce on performance, reward

and wellbeing. This included holding a

workforce engagement programme

session in July 2025, where selected

employees were invited to discuss bp's

approach to reward and employee

engagement.

**•Remuneration outcomes** – agreed the

outcomes of incentive awards for executive

directors, including reviewing performance

'in the round' and determining whether

discretion should be exercised. Monitored

in-flight progress of equity and bonus

awards.

**•Performance measures** – discussed and

agreed the performance measures for the

2025 annual and long-term performance

scorecards to ensure alignment with

bp's strategy. This included reflecting on

our sustainability measures and seeking

input from the safety and sustainability

committee. <sup>T</sup><sup>CFD</sup>

**•Framework on fatalities** – reflected on the

impact of fatalities on annual bonus

outcomes and the framework that was

introduced in 2024 to help guide decisions

going forward.

**•Change in leadership** – set the

remuneration terms for the interim CEO

and incoming CEO. Agreed the exit

arrangements for the outgoing CEO.

**•Merit-based reviews** – reviewed pay for

performance arrangements for the

leadership population in line with bp's

reward principles.

---

| | | | |
|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Contents** |  |  |
|  | Remuneration at a glance | [94](#i0dd2ee81aac04f8c9c97c86197f0c6df_196) |  |
|  | Engaging with our workforce | [96](#i0dd2ee81aac04f8c9c97c86197f0c6df_199) |  |
|  | Executive directors' pay for 2025 | [98](#i0dd2ee81aac04f8c9c97c86197f0c6df_202) |  |
|  | 2025 annual bonus outcome | [99](#i0dd2ee81aac04f8c9c97c86197f0c6df_205) |  |
|  | 2023-25 performance share plan outcome | [102](#i0dd2ee81aac04f8c9c97c86197f0c6df_208) |  |
|  | Policy implementation for 2026 | [106](#i0dd2ee81aac04f8c9c97c86197f0c6df_211) |  |
|  | Stewardship and executive director interests | [111](#i0dd2ee81aac04f8c9c97c86197f0c6df_214) |  |
|  | Chair and non-executive director interests | [112](#ica0492c0e311472fbb0fabe968d4aa83_11505) |  |
|  | 2026 directors' remuneration policy  | [118](#i0dd2ee81aac04f8c9c97c86197f0c6df_4635) |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

TCFD Information that supports TCFD Recommendations and Recommended Disclosures in relation to governance (see pages <u>[41](#i64435a2b74134bf69d5c362d53a40cc9_7984)</u><u>-</u><u>[44](#i0dd2ee81aac04f8c9c97c86197f0c6df_94)</u>)

---

| | | |
|:---|:---|:---|
| 92 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

**Chair's introduction**

**Dear shareholders,** 

I am pleased to present the directors'

remuneration report for the year ended

31 December 2025.

This is my first report as chair of the

remuneration committee, having taken on the

role from Tushar Morzaria on 17 April 2025.

Having agreed to step into the role on an interim

basis, I would like to thank Tushar for his

leadership of the committee during this period.

The committee remains focused on ensuring our

remuneration policy supports the delivery of

bp's strategic priorities, aligning executive

reward outcomes with sustainable long-term

value creation for our shareholders. Constructive

dialogue with our shareholders has been an

important part of this process, and we are

grateful for the insights shared during 2025.

We are asking shareholders to vote on two

remuneration resolutions at bp's 2026 AGM:

• Our remuneration report, which presents

remuneration outcomes for 2025 and how

we intend to apply the policy in 2026.

• Our remuneration policy (the policy), which

outlines the framework that will apply to our

executive directors, non-executive directors

and chair of the board.

**Business performance**

While performance over the three-year

performance period for the EDIP was mixed,

2025 was a year of strong underlying financial

and operational performance. bp delivered

operating cash flow★ of $24.5 billion,

underpinned by disciplined capital allocation

and efficiency with a 10% reduction in capital

expenditure★ compared with 2024.

Operationally, plant reliability★ and refining

availability★ both exceeded 96%, reaching their

highest levels on record.

We also made meaningful progress towards the

strategic priorities set out in our reset strategy

announced in February 2025. We established

four primary targets through to the end of 2027:

growing cash flow, improving returns,

reducing costs and strengthening the balance

sheet. We remain on track to deliver against

these objectives.

During the year, we agreed the sale of a 65%

shareholding in *Castrol*, which we expect to

generate net proceeds of approximately $6

billion, and completed the sale of our US onshore

wind business. We also delivered $2.0 billion of

structural cost reductions★, strengthening our

financial position and supporting continued

delivery into 2026.

**Incentive outcomes**

**2025 annual bonus** 

The scorecard for this cycle consisted of five

measures; tier 1 and tier 2 process safety

events★(15% of award), operated carbon

emissions (15%), reliability and availability (15%),

modified free cash flow★ (30%) and structural

cost reductions (25%).

Safety and sustainability

Within the annual bonus scorecard, safety

performance is measured against the number of

tier 1 and tier 2 process safety events each year

(7.5% weighting each).

For 2025, we achieved a combined outcome

of 87.5% of maximum for this measure. We

reported five tier 1 process safety events during

the year resulting in an outcome between target

and maximum. Tier 2 performance was strong

with a significant reduction in the number of

events compared to prior year (22 events in 2025

compared to 35 events in 2024), resulting in a

maximum outcome for this measure. This

reflects our continued focus on process and

personal safety.

However, we are deeply saddened by the four

workforce fatalities during the year – three at

TravelCenters of America and one at *Thorntons*.

Further details of these fatalities are set out on

page <u>[55](#i0dd2ee81aac04f8c9c97c86197f0c6df_103)</u>.

In assessing the impact of the fatalities during

the year, the committee was mindful of the total

number of fatalities across the group and, with

input from the safety and sustainability

committee, reflected on the circumstances of

each fatality. However, in line with our

framework, the three fatalities at TravelCenters

of America have been dealt with predominately

at a local level – see page <u>[101](#i7d5790f11031478c88ae8875d181caff_35364)</u> for further details.

In respect of the group score, it was agreed that

that a downward adjustment was justified when

reflecting on the fatality at *Thorntons* and

broader safety performance, and the entire

bonus score was reduced by 4 points for all

participants.

Sustainability performance was assessed

against operated carbon emissions, which

covers Scope 1 and 2 emissions based on bp's

net zero operations aim. Our performance was

strong and we delivered 1.6MteCO2e ahead of

our scorecard target, which resulted in an

outcome of 73% of maximum.

Financial and operational

Under our financial and operational categories,

bp delivered strong performance across all

measures.

From an operational perspective, our

performance was assessed against both plant

reliability and refining availability. We achieved

an outcome of 96.2% which resulted in an above

target outcome.

Our financial performance was assessed against

modified free cash flow and structural cost

reduction. Modified free cash flow was $12.4

billion, which resulted in the maximum outcome,

reflecting our continued focus on strong capital

discipline during 2025.

In line with our remuneration policy, the targets

for modified free cash flow are adjusted for the

actual commodity price environment to reflect

underlying performance.

This was the first year that structural cost

reductions were included in our scorecard.

We delivered $2.0 billion of cost reductions

which resulted in performance between

target and maximum.

Overall result

The formulaic annual bonus outcome, reflecting

safety, operational and financial performance

was therefore 1.63 out of a maximum of 2 (81.5%

of maximum).

As described previously, the committee

exercised its discretion to account for the

fatalities during 2025 and reduced the formulaic

outcome by 4 points to 1.59 out of 2 (79.5% of

maximum).

**2023-25 performance shares** 

The 2023-25 performance share scorecard was

measured against relative TSR (20% weighting),

return on average capital employed

(ROACE)★ (20%), adjusted EBIDA per share

compound annual growth rate (CAGR)★ (20%),

sustainable emissions reductions (15%) and

strategic progress (25%).

rTSR

bp placed fifth in the comparator group,

resulting in nil vesting for this measure.

Financials

Financial performance was assessed against our

returns and earnings measures and performed

below the targets set at the start of the

performance period, achieving nil vesting. The

2023-25 average ROACE was 15.4% and adjusted

EBIDA per share CAGR was 9.8%.

Sustainability performance

We delivered Scope 1 and 2 greenhouse gas

emissions reductions of 12.9% against our 2019

baseline. This resulted in an outcome between

threshold and target, with vesting of 22% of

maximum.

Strategic progress

Strategic progress was assessed using a

combination of quantitative assessment (via

financial KPIs) and qualitative judgement against

the three strategic pillars set in 2023.

As set out in the 2024 directors' remuneration

report, the committee also considered the

strategic changes announced in 2023 and the

Capital Markets Update in February 2025 when

scoring performance against the original criteria.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 93 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

We provide a detailed view of the committee's

review of strategic progress on pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.

Having considered the above, the committee

determined that bp made strong progress over

the three-year period and an outcome of 80% of

maximum was felt appropriate for this measure.

Overall results

Overall, performance share vesting for the

2023-25 cycle was 23.3% of maximum. The

committee believes that, given a large

component of the strategic progress measures

comprise financial KPIs, this outcome properly

reflects achievement over the period and

therefore has not applied any further discretion.

**Board changes** 

In December 2025, Murray Auchincloss stepped

down as CEO, and from the board, by mutual

agreement. Remuneration decisions relating to

Murray have been made in accordance with our

shareholder-approved policy and contractual

obligations, with full details provided on page <u>[113](#ica0492c0e311472fbb0fabe968d4aa83_59975)</u>.

Carol Howle assumed the role of interim CEO on

18 December 2025, having previously served as

EVP supply, trading & shipping. She will be

succeeded by Meg O'Neill whose appointment

as CEO takes effect from 1 April 2026.

**Incoming CEO: Meg O'Neill** 

The committee has determined the

remuneration package for the incoming CEO in

line with our shareholder-approved

remuneration policy, considering Meg's

experience, external market benchmarks,

shareholder expectations and broader operating

environment.

Meg will receive a base salary of £1.6 million on

appointment. This has been set at 2.5% above

the salary level of her predecessor when taking

into account the workforce salary increase that

he would have been eligible for in April 2026.

In reaching this decision, the committee

considered Meg's proven track record as a high

performing CEO within the sector and the

experience and leadership credentials she will

bring to lead bp through the next phase of its

transformation journey.

Meg will receive standard benefits for an

executive director, as provided for in the

remuneration policy. These include a pension

allowance of 20% of base salary aligned with the

wider UK workforce. She will also participate in

bp's annual incentive plans. There will be no

change to the operation of our minimum

shareholding requirement.

In line with our policy, Meg will receive relocation

support to facilitate her move from Australia to

the UK. She will also receive compensation for

incentive awards forfeited on leaving her

previous employer. Further details of Meg's

joining arrangements are set out on page <u>[108](#i533d31c765ee497e837b4fed830a1b6a_67039)</u>.

**Interim CEO: Carol Howle** 

Upon assuming the role of interim CEO on

18 December 2025, Carol's salary was set at

£1.508 million aligned with the level of her

predecessor. She will not be entitled to a salary

increase in respect of 2026 and she will receive

our standard executive benefits and pension

provisions.

For 2026, Carol will be eligible to receive awards

in line with our policy. She is also subject to bp's

in- and post-employment minimum

shareholding requirement from the date of

appointment.

**Looking ahead to 2026** 

**Policy review** 

Our current remuneration policy was last

approved in 2023 with 94% shareholder support.

In line with the normal three-year cycle, we will

be seeking approval for a revised policy at the

2026 AGM.

Over the past year, the committee has

undertaken a detailed review of each element of

the existing policy, assessing its effectiveness in

incentivizing and rewarding the delivery of bp's

strategy. We concluded that the current

framework continues to allow us to set

stretching, relevant and motivating short- and

long-term performance measures, that are

clearly aligned to the strategic priorities we

expect leadership to deliver.

Accordingly, beyond a small number of updates

to ensure continued alignment with evolving

market practice, we are not proposing any

significant changes at this time. We consulted

with our top 30 shareholders, representing over

40% of our register, who were generally

supportive of this approach for the 2026 AGM.

However, the committee is mindful that bp is

progressing through the next stage of its

transformation and therefore it is possible that

further changes to our remuneration approach

may be needed. Within this context, it may be

that we will ask shareholders for approval of an

updated policy ahead of the next required

triennial vote. The remuneration committee will

engage with bp's major shareholders on any

such proposals in advance.

**Annual pay review**

Kate Thomson's base pay will increase by 3.5%,

in line with the average increase in the UK.

Adjustments in other jurisdictions will vary by

local conditions.

**Review of performance measures** 

As part of the broader policy review, the

committee reflected on the performance

measures used in our incentive scorecards and

considered whether they remain aligned to the

reset strategy announced in February 2025.

2026 annual bonus

To support the stretching goals within bp's reset

strategy, the committee believes focus should

be on sustained financial performance over the

next year, with a particular lens on cash

generation and cost reduction.

The scorecard categories and weightings have

therefore been simplified, placing financial

performance at the forefront (65% of award),

supported by strong and sustained operational

delivery (20%) and a continued focus on safety

(15%). The underlying measures within the

categories remain broadly unchanged from prior

years and our framework on fatalities will

continue to apply.

Progress towards bp's net zero operations

aim will continue to be rewarded through our

performance share plans rather than the

annual bonus.

2026-28 performance shares

In line with the simplified structure of the annual

bonus, the performance share plan has also

been streamlined to ensure focus on the

measures most critical to delivering our

reset strategy.

For 2026-28, the scorecard will focus on the

following key measures: shareholder returns

(30% of award), cash generation (25%), ROACE

(25%) and a continued focus on reducing Scope 1

and 2 operational emissions in line with bp's

aim to reach net zero operations by 2050, or

sooner (20%).

For the shareholder returns measure, the peer

group has been reviewed for alignment with

the reset strategy. The 2026-28 group will be

simplified to five companies, focusing on the

oil super majors who are considered our

closest peers.

We have also broadened the underpin for our

performance share awards. Going forward, the

committee will take into consideration overall

safety performance as well as ongoing progress

towards a strong and resilient balance sheet

when assessing final outcomes, providing

further alignment with bp's long-term priorities.

**Conclusion** 

2025 was a year of strong progress. Taking all

circumstances into account, the committee

believes that the overall remuneration outcomes

are appropriate.

The committee remains committed to

maintaining an open and transparent

dialogue on remuneration matters with our

shareholders. I would like to thank you for

another year of constructive engagement

and your continued support ahead of the

2026 AGM.

**Ian Tyler**

Chair of the remuneration committee

6 March 2026

---

| | | |
|:---|:---|:---|
| 94 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

![](bp-20251231_g111.gif)

---

| | | | |
|:---|:---|:---|:---|
| **Key performance highlights in 2025** | **Key performance highlights in 2025** | **Key performance highlights in 2025** | **Key performance highlights in 2025** |
| **$24.5bn** | **$14.5bn** | **2.3mmboed** | •Refining availability of 96.3% and plant <br>reliability of 96.1% were highest on record.<br>•7 major projects started up, 5 ahead of <br>schedule.<br>•$11bn completed or signed divestments, <br>including $6bn *Castrol* transaction.<br>•On track against primary targets set out in <br>Capital Markets Update (February 2025). |
| operating cash flow★<br>improved cash conversion <br>| capital expenditure★<br>10% YoY reduction <br>| upstream★ production <br>exceeded plan<br>| •Refining availability of 96.3% and plant <br>reliability of 96.1% were highest on record.<br>•7 major projects started up, 5 ahead of <br>schedule.<br>•$11bn completed or signed divestments, <br>including $6bn *Castrol* transaction.<br>•On track against primary targets set out in <br>Capital Markets Update (February 2025). |

---

---

| | | | | |
|:---|:---|:---|:---|:---|
| **Total remuneration in 2025** | **Total remuneration in 2025** | **Total remuneration in 2025** | **Total remuneration in 2025** | **Total remuneration in 2025** |
| 1. Salary and benefits![ChartKeyLozengeAmber2.gif](bp-20251231_g112.gif)<br>| **Single figure**<br>Chief executive officer <br>(outgoing)<br>35% Fixed<br>65% Variable pay |  | **Single figure**<br>Chief financial officer <br>36% Fixed<br>64% Variable pay |  |
| 2. Cash allowance ![ChartKeyLozengeDeepOrange2.gif](bp-20251231_g113.gif)<br>in lieu of pension<br>| **Single figure**<br>Chief executive officer <br>(outgoing)<br>35% Fixed<br>65% Variable pay |  | **Single figure**<br>Chief financial officer <br>36% Fixed<br>64% Variable pay |  |
| 3. Annual bonus![ChartKeyLozengeGreen.gif](bp-20251231_g114.gif)<br>| **Single figure**<br>Chief executive officer <br>(outgoing)<br>35% Fixed<br>65% Variable pay | £5.3m | **Single figure**<br>Chief financial officer <br>36% Fixed<br>64% Variable pay | £3.0m |
| 4. Performance shares![ChartKeyLozengeLightGreen.gif](bp-20251231_g115.gif)<br>| **Single figure**<br>Chief executive officer <br>(outgoing)<br>35% Fixed<br>65% Variable pay | £5.3m | **Single figure**<br>Chief financial officer <br>36% Fixed<br>64% Variable pay | £3.0m |
|  | **Single figure**<br>Chief executive officer <br>(outgoing)<br>35% Fixed<br>65% Variable pay | £5.3m | **Single figure**<br>Chief financial officer <br>36% Fixed<br>64% Variable pay | £3.0m |
|  | **Single figure**<br>Chief executive officer <br>(outgoing)<br>35% Fixed<br>65% Variable pay |  | **Single figure**<br>Chief financial officer <br>36% Fixed<br>64% Variable pay |  |
|  | **Single figure**<br>Chief executive officer <br>(outgoing)<br>35% Fixed<br>65% Variable pay |  | **Single figure**<br>Chief financial officer <br>36% Fixed<br>64% Variable pay |  |

---

![30786325578241](bp-20251231_g116.gif)

![30786325578253](bp-20251231_g117.gif)

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| **Pay outcomes in 2025** |  |  |  |  |  |  |  |
| **Annual bonus** <br>(2025 ACB) | ![White-SMALL-TopRoundCornerV2.gif](bp-20251231_g118.gif) |  | ![White-SMALL-TopRoundCornerV2.gif](bp-20251231_g118.gif) | **Performance shares** <br>(2023-25 EDIP) | ![White-SMALL-TopRoundCornerV2.gif](bp-20251231_g118.gif) |  | ![White-SMALL-TopRoundCornerV2.gif](bp-20251231_g118.gif) |
| **Annual bonus** <br>(2025 ACB) |  | **81.5% of** <br>**maximum**<br>formulaic outcome<br>|  | **Performance shares** <br>(2023-25 EDIP) |  | **23.3% of** <br>**maximum** <br>formulaic outcome<br>|  |
|  | ![White-SMALL-BottomRoundCornerV2.gif](bp-20251231_g119.gif) |  | ![White-SMALL-BottomRoundCornerV2.gif](bp-20251231_g119.gif) |  | ![White-SMALL-BottomRoundCornerV2.gif](bp-20251231_g119.gif) |  | ![White-SMALL-BottomRoundCornerV2.gif](bp-20251231_g119.gif) |
|  |  | ![WarmGrey4DownArrow.gif](bp-20251231_g120.gif) |  |  |  |  |  |
|  | ![BPGreen-SMALL-TopRoundCornerV2.gif](bp-20251231_g121.gif) |  | ![BPGreen-SMALL-TopRoundCornerV2.gif](bp-20251231_g121.gif) |  |  |  |  |
|  |  | **79.5% of** <br>**maximum**<br>formulaic outcome<br>actual outcome <br>after exercise <br>of discretion |  |  |  |  |  |
| Safety and sustainability ![ChartKeyLozengeGreen.gif](bp-20251231_g114.gif)<br>Operations Financials![ChartKeyLozengesWarmGrey6.gif](bp-20251231_g122.gif)<br>![ChartKeyLozengesWarmGrey3.gif](bp-20251231_g123.gif) |  | **79.5% of** <br>**maximum**<br>formulaic outcome<br>actual outcome <br>after exercise <br>of discretion |  | Strategic progress Sustainability ![ChartKeyLozengesDarkGreen.gif](bp-20251231_g124.gif)<br>![ChartKeyLozengeGreen.gif](bp-20251231_g114.gif)<br>rTSR Financials![ChartKeyLozengesWarmGrey6.gif](bp-20251231_g122.gif)<br>![ChartKeyLozengesWarmGrey3.gif](bp-20251231_g123.gif) |  |  |  |
| Safety and sustainability ![ChartKeyLozengeGreen.gif](bp-20251231_g114.gif)<br>Operations Financials![ChartKeyLozengesWarmGrey6.gif](bp-20251231_g122.gif)<br>![ChartKeyLozengesWarmGrey3.gif](bp-20251231_g123.gif) | ![BPGreen-SMALL-BottomRoundCornerV2.gif](bp-20251231_g125.gif) |  | ![BPGreen-SMALL-BottomRoundCornerV2.gif](bp-20251231_g125.gif) | Strategic progress Sustainability ![ChartKeyLozengesDarkGreen.gif](bp-20251231_g124.gif)<br>![ChartKeyLozengeGreen.gif](bp-20251231_g114.gif)<br>rTSR Financials![ChartKeyLozengesWarmGrey6.gif](bp-20251231_g122.gif)<br>![ChartKeyLozengesWarmGrey3.gif](bp-20251231_g123.gif) |  |  |  |

---

![33](bp-20251231_g126.gif)

![45](bp-20251231_g127.gif)

**Application of discretion**

The committee may exercise discretion in determining the outcomes of the annual bonus and performance shares, reflecting the broader stakeholder

experience during the performance period. For 2025, downward discretion was applied and the 2025 ACB has been reduced by 4 points. Further details

of the application of discretion have been set out on page <u>[101](#i7d5790f11031478c88ae8875d181caff_35364)</u>.

---

| | | |
|:---|:---|:---|
| **Alignment with shareholders** | **Alignment with shareholders** | **Alignment with shareholders** |
| ![DRR_SingleLozenge_ShareOwnership.gif](bp-20251231_g128.gif)<br>Share ownership aligns the <br>interests of executive <br>directors with those <br>of shareholders. |  |  |
| ![DRR_SingleLozenge_ShareOwnership.gif](bp-20251231_g128.gif)<br>Share ownership aligns the <br>interests of executive <br>directors with those <br>of shareholders. | Murray Auchincloss (outgoing CEO) | 5.9 times salary, 2,104,355 shares |
| ![DRR_SingleLozenge_ShareOwnership.gif](bp-20251231_g128.gif)<br>Share ownership aligns the <br>interests of executive <br>directors with those <br>of shareholders. |  |  |
| ![DRR_SingleLozenge_ShareOwnership.gif](bp-20251231_g128.gif)<br>Share ownership aligns the <br>interests of executive <br>directors with those <br>of shareholders. |  |  |
| ![DRR_SingleLozenge_ShareOwnership.gif](bp-20251231_g128.gif)<br>Share ownership aligns the <br>interests of executive <br>directors with those <br>of shareholders. | Kate Thomson (CFO) | 2.9 times salary, 550,831 shares |
| ![DRR_SingleLozenge_ShareOwnership.gif](bp-20251231_g128.gif)<br>Share ownership aligns the <br>interests of executive <br>directors with those <br>of shareholders. |  |  |
| ![DRR_SingleLozenge_ShareOwnership.gif](bp-20251231_g128.gif)<br>Share ownership aligns the <br>interests of executive <br>directors with those <br>of shareholders. | Actual Policy requirement ![ChartKeyLozengeDeepBlue1.gif](bp-20251231_g129.gif) |  |

---

![](bp-20251231_g130.gif)

![](bp-20251231_g130.gif)

![](bp-20251231_g131.gif)

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 95 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

![](bp-20251231_g111.gif)

**Application of remuneration policy for 2026**<br>

Set out below is an illustration of how the remuneration policy will be implemented for 2026.

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | 2026 | 2027 | 2028 | 2029 | 2030 | 2031 | 2032 |  |
| **Fixed pay**<br>(salary, pension <br>and benefits)<br>|  |  |  |  |  |  |  | •Upon appointment, the incoming CEO's salary will be <br>£1.6 million. <br>•For 2026, the CFO's salary will increase by 3.5%, from £864k to <br>£894k, in line with the wider workforce average. <br>|
| **Annual bonus**<sup>a</sup> |  |  |  |  |  |  |  | •CEO max opportunity: 225% of salary. <br>•CFO max opportunity: 225% of salary. <br>•For 2026, the scorecard has been simplified to focus on safety, <br>operational and financial performance (see below). <br>|
| **Performance** <br>**shares**<br>|  |  |  |  |  |  |  | •CEO max opportunity: 500% of salary.<br>•CFO max opportunity: 450% of salary. <br>•Similarly to the annual bonus, the 2026-28 scorecard has been <br>simplified with an increased focus on emissions reductions, <br>financial and shareholder return measures (see below). <br>|
| **Shareholding** <br>**requirement**<br>|  |  |  |  |  |  |  | •In-employment and post-employment guidelines will continue <br>to apply.<br>|

---

![DRR_RemPolicyArrow1.gif](bp-20251231_g132.gif)

1-year

performance period

![DRR_RemPolicyArrow2.gif](bp-20251231_g133.gif)

3-year

deferral period

![DRR_RemPolicyArrow3.gif](bp-20251231_g134.gif)

![DRR_RemPolicyArrow4.gif](bp-20251231_g135.gif)

3-year

performance period

3-year

holding period

![DRR_RemPolicyArrow5.gif](bp-20251231_g136.gif)

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

bp shares.

**Alignment of 2026 variable remuneration with strategy**<br>

Each year, the committee sets a remuneration framework for executive directors that supports and incentivizes the execution of our

strategy. For 2026, the scorecards have been simplified to reflect our business priorities, supported by strong safety and operational

performance, with financial measures at the forefront. Further details on the rationale for their inclusion can be found on pages <u>[109](#i533d31c765ee497e837b4fed830a1b6a_3935)</u><u>-</u><u>[110](#i533d31c765ee497e837b4fed830a1b6a_3937)</u>.

---

| | | | |
|:---|:---|:---|:---|
| ![DRR_SIngleLozenge_AnnualBonus.gif](bp-20251231_g137.gif)<br>| Strategy <br>(upstream, <br>downstream, <br>transition) <br>| Primary <br>targets<br>| KPIs |
| **Safety** (15%) |  |  |  |
| Tier 1 and tier 2 process safety events★ | 🟇 |  | 🟇 |
| **Financials and operations** (85%) |  |  |  |
| bp-operated reliability★ and availability★  | 🟇 |  | 🟇 |
| Structural cost reductions★ ($bn)  | 🟇 | 🟇 | 🟇 |
| Modified free cash flow★ ($bn) |  |  | 🟇 |
| ![DRR_SIngleLozenge_PerformanceShares.gif](bp-20251231_g138.gif)<br>|  |  |  |
| **Cumulative reduction % in operated carbon emissions** (20%) |  |  | 🟇 |
| **Adjusted free cash flow CAGR**★ (25%)  |  | 🟇 | 🟇 |
| **ROACE**★ (25%) |  | 🟇 | 🟇 |
| **Relative TSR** (30%)  |  |  | 🟇 |

---

---

| | |
|:---|:---|
| ![ReadMoreArrowBPGreen.gif](bp-20251231_g3.gif) | Strategy and primary targets page <u>[8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31)</u>, KPIs page <u>[14](#i0dd2ee81aac04f8c9c97c86197f0c6df_1099511633060)</u> |

---

---

| | | |
|:---|:---|:---|
| 96 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

Engaging with our workforce

We believe that our people are the key to bp's success and our approach to performance and reward should be fair and consistent across the

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

wider workforce.

---

| | | | | |
|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Element of remuneration** | **All employees** | **Executive directors** |  |
|  | ![WorkforceSalaryV2.gif](bp-20251231_g139.gif) | Salary is the basis for a competitive total <br>reward package for all employees. We conduct <br>an annual salary review for all non-unionized <br>employees. In setting pay budgets, we assess <br>how employee pay is currently positioned <br>relative to market rates, wage inflation, <br>forecasts and business context.<br>| The salaries of our executive directors are <br>reviewed annually. The review will take into <br>account the same factors considered for the <br>wider workforce. Salary increases for executive <br>directors will typically be at or below the <br>workforce rate, other than in specific <br>circumstances. <br>|  |
|  | ![WorkforcePensionsAndBenefitsV1.gif](bp-20251231_g140.gif) | We operate different pension plans by location <br>and for those parts of our business where <br>market practice is markedly different, e.g. our <br>retail business. For our population of non-retail <br>employees in the UK, we provide a flexible cash <br>benefits allowance of 20% of salary. The <br>benefits available are aligned with competitive <br>market practice in our different jurisdictions.<br>| Executive directors receive a cash allowance in <br>lieu of pension aligned with the wider <br>workforce (currently 20% of salary). Other than <br>the provisions of car, security and tax <br>preparation related benefits, benefit packages <br>are broadly aligned with those of other <br>employees in the UK. <br>|  |
|  | ![WorkforceAnnualBonusV1.gif](bp-20251231_g141.gif) | More than half of the eligible workforce <br>participate in an annual cash bonus plan that <br>multiplies a grade-based target bonus amount <br>by a bp performance factor derived from the <br>bonus scorecards. From 2025, business <br>scorecards have been introduced for certain <br>parts of bp. Individual performance is assessed <br>through a performance rating which may result <br>in an uplift or decrease to bonus outcomes. We <br>operate different bonus plans for those parts <br>of our business where market practice is <br>markedly different. <br>| The annual bonus for the executive directors is <br>linked to the same bp performance factor as <br>for the wider workforce. Executive directors <br>are not entitled to a bonus uplift linked to <br>individual performance. For executive <br>directors, a portion of any award is deferred <br>into shares for three years. The deferral rate <br>depends on whether the executive director has <br>met their minimum shareholding requirement. <br>|  |
|  | ![WorkforcePerformanceSharesV1.gif](bp-20251231_g142.gif) | We operate share plans with three-year vesting <br>for all our senior leaders. Opportunity varies <br>across two broad tiers: group leaders <br>(approximately 300) and senior-level leaders <br>(approximately 4,000). <br>| Executive directors are eligible for <br>performance share awards, which are subject <br>to stretching performance targets over a <br>three-year period. An additional three-year <br>post-vesting holding period applies for <br>executive directors. <br>|  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

**Other elements of pay** 

**Recognition** 

energize!, our global recognition platform, is open to all employees for

peer-to-peer recognition. The scheme aims to celebrate employees'

contributions, highlight behaviours vital to our success and drive

performance. In 2025, a total of 39,900 employees received

energize! awards.

We also operate a spot bonus programme, where individuals or teams

can be nominated to receive a one-off cash award to recognize their

achievements or particular initiatives. Senior leaders actively participate

in the programmes, often by recognizing the contributions of their team

members. In 2025, 6,600 employees were awarded spot bonuses in

recognition of their contributions.

**Focus@bp** 

focus@bp is our internal platform that helps support performance

development. The platform enables employees to set dynamic goals,

have regular check-ins, give and receive meaningful feedback and grow

skills to enable our teams to develop and deliver.

We believe that performance matters, both individually and collectively,

and development is key in helping to improve our performance as

a business. focus@bp forms the basis of discussions relating to

development or progression and the achievement of goals is factored

in when making decisions in relation to an individual's remuneration.

**All-employee share plan**

bp operates an award-winning global ShareMatch programme which is

available to over 18,000 employees in 46 countries. This plan offers our

employees the opportunity to invest and share in bp's success,

fostering a culture of shared ownership. At the end of 2025, the

participation rate in the scheme was 64% of eligible employees.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 97 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

**Workforce highlights in 2025** 

**Driving our performance culture** 

Following the strategy reset announced in February 2025, bp is

undertaking a broad transformation to become a more competitive,

focused and value-driven organization.

As part of this, we reviewed and updated our approach to performance

management to make it clearer, more consistent and better aligned

with bp's strategic goals. This evolution represents a culture shift and

an operational change, influencing how our employees support bp in

delivering its ambitions.

To date, four changes have been introduced:

**•Aligned goals:** Common goals are now set at an entity or sub-entity

level, giving employees a clearer line of sight to organizational

priorities and how their work contributes to bp's strategy.

**•Business scorecards:** Business-level scorecards have been

introduced alongside the group scorecard, strengthening the link

between business performance and reward outcomes.

**•Annual review cycle:** The performance cycle now incorporates

quarterly check-ins, alongside our existing mid-year and year-end

conversations, to support more regular, meaningful conversations.

**•Individual ratings:** A simple rating system has been introduced to

assess individual performance over the year, with outcomes directly

impacting reward decisions.

Together, these changes will help embed a stronger performance

culture that supports our strategy.

**Supporting employees during organizational transformation** 

Our approach to workforce health and wellbeing is centred around the

needs of our people, combining globally available services that can be

tailored to meet specific local needs. All employees have access to our

global digital health and wellbeing hub, Thrive@bp.

During bp's transformation programme, we have offered

comprehensive mental health support to employees which has been

developed through listening forums and employee feedback.

Recognizing the pivotal role of our leaders, we have also offered

tailored resources to help them support their teams and look after

their own mental health.

Support has included on-site counselling, check-ins with counsellors

and advice from psychologists, coaching and access to other

specialists through webinars. We offered bespoke mental health

training on 'thriving' through change, which has been completed more

than 4,000 times and included a leader-specific module.

**Healthy minds**

Our bespoke mental health education programme, Healthy Minds,

provides elearning modules for all bp employees.

Since its launch in 2024, more than 14,000 modules have been

completed and more than 75% of our senior leaders have engaged in

the programme.

---

| | | |
|:---|:---|:---|
| ![DRR_WorkfoceHighlightsCaseStudy2V1.jpg](bp-20251231_g143.jpg) | ![DRR_WorkfoceHighlightsCaseStudy2V1.jpg](bp-20251231_g143.jpg) | ![DRR_WorkfoceHighlightsCaseStudy2V1.jpg](bp-20251231_g143.jpg) |
|  | Workforce engagement <br>Receiving feedback from our employees remains an <br>important way in which the board stays connected to the <br>broader employee experience. <br>On remuneration specifically, as part of the board-led <br>workforce engagement programme (WEFP), a dedicated <br>session was held in July 2025 to hear employee views on <br>changes to performance management, including the <br>introduction of business scorecards and performance <br>ratings. <br>The discussion provided valuable insight into how these <br>changes are being received across the organization. <br>**Image:** Retail colleague at our Oak Tree service station in Surrey, UK<br>|  |
| ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |  | ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |

---

---

| | | |
|:---|:---|:---|
| ![DRR_WorkfoceHighlightsCaseStudy1V3.jpg](bp-20251231_g144.jpg) | ![DRR_WorkfoceHighlightsCaseStudy1V3.jpg](bp-20251231_g144.jpg) | ![DRR_WorkfoceHighlightsCaseStudy1V3.jpg](bp-20251231_g144.jpg) |
|  | Shareholder views <br>The committee is committed to maintaining an open <br>dialogue with our shareholders. During the year, we <br>engaged with our top 30 shareholders (representing over <br>40% of our shareholder register).<br>The insights shared during this engagement play an <br>important role in shaping our decisions. We value the <br>feedback received, helping us to understand evolving <br>expectations on reward matters.<br>**Image:** Trading and shipping colleagues at our Canary Wharf office in <br>London, UK<br>|  |
| ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |  | ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |

---

![](bp-20251231_g145.gif)

![46810_bp_ClosingQuoteMarkWhite.gif](bp-20251231_g146.gif)

---

| | | |
|:---|:---|:---|
| 98 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

**Executive directors' pay for 2025** 

**Single figure table – executive directors (audited)**<sup>a</sup>

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  | **Carol**<br>**Howle**<sup>b</sup> <br>**thousand** <br>**2025** <br>| **Murray**<br>**Auchincloss**<sup>c</sup><br>**thousand**<br>**2025**<br>| **Kate**<br>**Thomson**<br>**thousand**<br>**2025**<br>| Murray<br>Auchincloss<br>thousand<br>2024<br>| Kate<br>Thomson<br>thousand<br>2024<br>|
| ![DRR_SIngleLozenge_SalaryV3.gif](bp-20251231_g147.gif)<br>| **£57** | **£1,434** | **£845** | £1,450 | £731 |
| ![DRR_SIngleLozenge_BenefitsV4.gif](bp-20251231_g148.gif)<br>| **£2** | **£138** | **£82** | £132 | £67 |
| ![DRR_SIngleLozenge_CashInLieuV2.gif](bp-20251231_g149.gif)<br>| **£11** | **£287** | **£169** | £290 | £146 |
| ![DRR_SIngleLozenge_AnnualBonusV4.gif](bp-20251231_g150.gif)<br>| **£83** | **£2,594** | **£1,545** | £734 | £370 |
| ![DRR_SIngleLozenge_PerformacesharesV4.gif](bp-20251231_g151.gif)<br>| **£733** | **£854** | **£387** | £2,573 | £697 |
| **Total remuneration** | **£886** | **£5,307** | **£3,029** | £5,179 | £2,011 |
| Total fixed remuneration | **£70** | **£1,859** | **£1,096** | £1,872 | £944 |
| Total variable remuneration | **£816** | **£3,448** | **£1,932** | £3,307 | £1,067 |

---

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

bCarol Howle was appointed interim CEO on 18 December 2025, having previously been EVP supply, trading & shipping. The amounts disclosed reflect her service in the year as an

executive director.

cMurray Auchincloss stepped down as CEO on 18 December 2025, having been appointed as permanent CEO on 17 January 2024. The amounts disclosed reflect his service in year as an

executive director.

dIn line with the 2023 policy, annual bonus is subject to deferral into shares for three years at a rate of 33% or 50%, depending on whether an individual has met their minimum shareholding

requirement. See page [100](#i7d5790f11031478c88ae8875d181caff_35344) for further detail on the approach taken for the 2025 annual bonus.

e For Carol Howle, a portion of the annual bonus relates to performance within her capacity as EVP supply, trading & shipping. The pro-rated value of this award amounts to £36k of the figure

disclosed, of which half is to be delivered in cash and half is to be deferred into bp shares for three years. The remuneration committee has determined that the measures and targets linked to

this portion of the award are commercially sensitive and therefore have not been disclosed. The remaining portion of the annual bonus relates to group performance, as set out on page [99](#i0dd2ee81aac04f8c9c97c86197f0c6df_205), and

in line with the terms of that award will not be subject to deferral requirements in respect of 2025.

fFor Murray Auchincloss, the value of the performance share award has been calculated using the average share price in the last three months of 2025 of £4.40 and includes notional dividends

accrued up to 13 February 2026. For 2024, the performance shares have been restated to reflect the share price on the date of vesting of £3.60 and actual dividends received.

gFor Carol Howle and Kate Thomson, the value of the performance share award relates to their roles prior to their appointment to the board. For 2023-25, the awards have been calculated using

the average share price in the last three months of 2025 of £4.40 and includes notional dividends up to 13 February 2026. For 2023-25, performance share awards below board had a different

scorecard to executive directors, which resulted in an outcome of 52.8% of maximum. For 2024, the performance shares have been restated to reflect the share price on the date of vesting of

£4.63 and actual dividends received.

**Overview of single figure outcomes**

Salary

In respect of 2025, Murray Auchincloss received a salary increase in line with the wider workforce and his base pay was set at £1.508 million. Kate

Thomson received a salary increase of 8%, reflecting her development in role and leadership of the finance function, which increased her base pay

to £864,000. These changes were effective from the 2025 AGM on 17 April 2025.

Carol Howle was appointed as interim CEO on 18 December 2025. From the date of appointment, her base pay was set in line with that of her

predecessor at £1.508 million.

Benefits

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

Cash allowance in lieu of pension

In line with the 2023 directors' remuneration policy, executive directors receive a cash allowance in lieu of pension of 20% of salary. This is in line

with the wider workforce in the UK.

![DRR_AnnualBonusScorecardV1-RIGHT.jpg](bp-20251231_g152.jpg)

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 99 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

Annual bonus

For 2025, the committee assessed performance against a bonus scorecard of measures across three categories: safety and sustainability,

operations and financials. These measures were aligned with our strategy and investor proposition as set out at the beginning of the year.

**2025 annual bonus scorecard and outcome**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| **Annual bonus scorecard** | **Annual bonus scorecard** | **Annual bonus scorecard** | **Annual bonus scorecard** | **Annual bonus scorecard** | **Annual bonus scorecard** | **Annual bonus scorecard** |
|  |  | **Threshold** (0) | **Target** (1) | **Maximum** (2) |  |  |
| **Categories** | **Measures** | | |  | **Weighting** | **Outcomes** |
| **Safety and sustainability** <br>**(30%)** | **Tier 1 process** <br>**safety events**★ | 9 | 6 | 4 | 7.5% | 0.11 |
| **Safety and sustainability** <br>**(30%)** | **Tier 1 process** <br>**safety events**★ |  |  |  |  |  |
| **Safety and sustainability** <br>**(30%)** | **Tier 1 process** <br>**safety events**★ | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 5** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 5** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 5** |  |  |
| **Safety and sustainability** <br>**(30%)** | **Tier 2 process** <br>**safety events**★ | 39 | 30 | 27 | 7.5% | 0.15 |
| **Safety and sustainability** <br>**(30%)** | **Tier 2 process** <br>**safety events**★ |  |  |  |  |  |
| **Safety and sustainability** <br>**(30%)** | **Tier 2 process** <br>**safety events**★ | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 22**  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 22**  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 22**  |  |  |
| **Safety and sustainability** <br>**(30%)** | **Operated carbon** <br>**emissions (MtCO2e)** | 38.9 | 35.5 | 32.1 | 15% | 0.22 |
| **Safety and sustainability** <br>**(30%)** | **Operated carbon** <br>**emissions (MtCO2e)** |  |  |  |  |  |
| **Safety and sustainability** <br>**(30%)** | **Operated carbon** <br>**emissions (MtCO2e)** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 33.9**<sup>a</sup> | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 33.9**<sup>a</sup> | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 33.9**<sup>a</sup> |  |  |
| **Operations**<br>**(15%)** | **bp-operated** <br>**reliability**★ <br>**and availability**★ | 95.1% | 95.9% | 96.7% | 15% | 0.21 |
| **Operations**<br>**(15%)** | **bp-operated** <br>**reliability**★ <br>**and availability**★ |  |  |  |  |  |
| **Operations**<br>**(15%)** | **bp-operated** <br>**reliability**★ <br>**and availability**★ | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 96.2%** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 96.2%** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 96.2%** |  |  |
| **Operations**<br>**(15%)** | **bp-operated** <br>**reliability**★ <br>**and availability**★ |  |  |  |  |  |
| **Financials**<br>**(55%)** | **Modified free** <br>**cash flow**★ **($bn)** | 6.5 | 8.5 | 10.5 | 30% | 0.60 |
| **Financials**<br>**(55%)** | **Modified free** <br>**cash flow**★ **($bn)** |  |  |  |  |  |
| **Financials**<br>**(55%)** | **Modified free** <br>**cash flow**★ **($bn)** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 12.4** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 12.4** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 12.4** |  |  |
| **Financials**<br>**(55%)** | **Structural cost** <br>**reductions**★**($bn)** | 0.6 | 1.4 | 3 | 25% | 0.34 |
| **Financials**<br>**(55%)** | **Structural cost** <br>**reductions**★**($bn)** |  |  |  |  |  |
| **Financials**<br>**(55%)** | **Structural cost** <br>**reductions**★**($bn)** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 2** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 2** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 2** |  |  |
|  | **Formulaic outcome** | **Formulaic outcome** |  | **1.63 out of 2.00** | **1.63 out of 2.00** | **1.63 out of 2.00** |
| Formulaic <br>scorecard<br>outcome<br>**1.63 out of 2.00** | Formulaic <br>scorecard<br>outcome<br>**1.63 out of 2.00** | Application of <br>framework on <br>fatalities<br>**4 point reduction**<br>(see page <u>[101](#i7d5790f11031478c88ae8875d181caff_35364)</u>) | Overriding <br>committee <br>judgement<br>**No adjustment**  | **1.59 out of 2.00** | **1.59 out of 2.00** | **1.59 out of 2.00** |
| Formulaic <br>scorecard<br>outcome<br>**1.63 out of 2.00** | Formulaic <br>scorecard<br>outcome<br>**1.63 out of 2.00** | Application of <br>framework on <br>fatalities<br>**4 point reduction**<br>(see page <u>[101](#i7d5790f11031478c88ae8875d181caff_35364)</u>) | Overriding <br>committee <br>judgement<br>**No adjustment**  |  |  |  |

---

![26](bp-20251231_g153.gif)

![6047313953092](bp-20251231_g154.gif)

![6047313953239](bp-20251231_g155.gif)

![6047313953280](bp-20251231_g156.gif)

![110](bp-20251231_g157.gif)

![86](bp-20251231_g158.gif)

![98](bp-20251231_g159.gif)

aThe actual operated carbon emissions outcomes used for bonus calculation purposes (33.9MteCO2e) is based on the agreed portfolio scope at beginning of the plan year and differs from the

figure reported elsewhere in the *bp Annual Report and Form 20-F 2025* (34.3MteCO2e) due to portfolio changes.

---

| | | |
|:---|:---|:---|
| 100 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

**Summary of performance** 

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

events★, was strong with the mechanical outcome achieving between

target and maximum performance. The total number of events is less

than prior year, with 27 tier 1 and tier 2 events in 2025 (38 in 2024). This

year-on-year improvement underpins the importance of our process

safety improvement plans and the delivery of the actions they outline.

**Operated carbon emissions performance** is measured against the

anticipated emissions based on the business plan and activity set

identified at the beginning of the year. For 2025, operated carbon

emissions of 33.9MtCO2e (footnote a) resulted in an outcome between

target and maximum. This holds underlying operated emissions broadly

flat compared to the 2024 result, after accounting for previously

identified portfolio growth and full year impact of project start-ups.

The most significant contributions to emissions performance of

1.6MtCO2e below 2025 plan came from improved management of

abnormal plant conditions in the Asia Pacific region; continuation of

previously implemented efficiencies across refining sites; and flaring

reductions and operational stability in the Azerbaijan, Georgia and

Türkiye region.

Emission reduction projects totalling 0.27MtCO2e implemented by our

business in 2025 included: Archaea Energy renewable natural gas

switching to low carbon power; bpx energy's central distribution

project, which enabled decommissioning of legacy natural gas-driven

equipment; focus on flare system and practices improvements at

Tangguh, and synchronization of power and power management

strategy implementation in Trinidad and Tobago.

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

refining availability★ and bp-operated plant reliability★ with a

performance outcome of 96.2% – between target and maximum.

Refining availability and plant reliability both strengthened year-on-

year, with refining availability of 96.3% (94.3% in 2024) and plant

reliability of 96.1% (95.2% in 2024).

Financial performance, as measured by **modified free cash flow**★ **and** 

**structural cost reduction**★, was strong. bp generated modified free

cash flow of $12.4 billion, which resulted in the maximum outcome.

Similarly, steady progress was made against our structural cost

reduction measure, delivering $2.0 billion of reductions which was

between target and maximum.

**Overall outcome** 

The formulaic score for the 2025 annual bonus was 1.63 out of 2 (81.5%

of maximum).

The committee considered bp's framework on fatalities when reflecting

on the formulaic outcome. Sadly, there were four workforce fatalities

during the year. Full details on the application of the framework have

been provided on page <u>[101](#i7d5790f11031478c88ae8875d181caff_35364)</u>.

Having considered the above, alongside a holistic review of

performance, the committee determined that the formulaic score

should be reduced by 4 points to 1.59 out of 2 (79.5% of maximum).

a The actual operated carbon emissions outcomes used for bonus calculation purposes (33.9MteCO2e) is based on the agreed portfolio scope at beginning of the plan year and differs from the

figure reported elsewhere in the *bp Annual Report and Form 20-F 2025* (34.3MteCO2e) due to portfolio changes.

**Approach to deferral** 

In relation to the policy on deferral requirements, the committee

reviewed the executive directors' shareholdings during the year to

assess if the minimum shareholding requirement had been met.

As at 18 December 2025, the date Murray Auchincloss stepped down

from the board, his shareholding represented 5.87x salary. This is above

the minimum shareholding requirement for the CEO of 5x salary and his

pro-rated 2025 award will therefore be subject to a deferral rate of 33%.

While Kate Thomson has made strong progress towards her minimum

shareholding requirement since her appointment in 2024, her

shareholding represented 2.94x salary (as at 13 February 2026). This is

below the minimum shareholding requirement for the CFO of 4.5x

salary and her 2025 award will therefore be subject to a deferral rate

of 50%.

As Carol Howle was only appointed interim CEO on 18 December 2025,

the committee agreed that her 2025 award would be calculated based

on her salary and award opportunity level prior to appointment. Her

bonus award in respect of group performance will therefore not be

subject to any deferral requirements.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 101 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

**bp's framework on fatalities** 

We are working towards our goal of eliminating workplace

fatalities. In 2024 we implemented a new framework on

fatalities. This framework, developed in consultation with

shareholders and the safety and sustainability committee

(S&SC), links safety performance directly to the bonus

scorecard.

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

2023 directors' remuneration report.

---

| | |
|:---|:---|
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | <u>bp.com/investors</u> |

---

![FrameworkOnFatalitiesV2.jpg](bp-20251231_g160.jpg)

![](bp-20251231_g161.gif)

![](bp-20251231_g162.gif)

---

| |
|:---|
| **Framework on fatalities**  |
| &nbsp;&nbsp;&nbsp;&nbsp;1. Operations (15%)![ChartKeyLozengeGreen.jpg](bp-20251231_g29.jpg)<br>|
| &nbsp;&nbsp;&nbsp;&nbsp;2. Safety and sustainability (30%)![ChartKeyLozengeDarkGreen.jpg](bp-20251231_g163.jpg)<br>|
| &nbsp;&nbsp;&nbsp;&nbsp;3. Financial (55%)![ChartKeyLozengeWarmGrey3.jpg](bp-20251231_g30.jpg)<br>|

---

![65](bp-20251231_g164.gif)

![](bp-20251231_g165.gif)

---

| | | |
|:---|:---|:---|
| **Safety and sustainability committee** | **Safety and sustainability committee** | **Safety and sustainability committee** |
| **Influence** | **Foreseen** | **Nature** <br>**of deficiency**<br>|
| **Remuneration committee** | **Remuneration committee** | **Remuneration committee** |
| **Collective** <br>**responsibility**<br>| **Meaningful** <br>**adjustment**<br>| **Judgement** <br>**within a frame**<br>|
| **Treatment of new assets** | **Treatment of new assets** | **Treatment of new assets** |

---

---

| | | | | |
|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) | **What happened during the year?**<br>At bp, safety remains our top priority and we are deeply <br>committed to ensuring that our operations are carried out <br>safely every single day. <br>**Safety performance in 2025** <br>During 2025, we recorded five tier 1 events, a slight increase <br>compared with the prior year. Tier 1 events represent our <br>more serious incidents and it remains essential that we stay <br>focused on reducing these incidents. Encouragingly, the <br>number of tier 2 events fell significantly, with 22 events <br>compared to 35 in 2024. <br>However, there were sadly four workforce fatalities during <br>the year – three at our recently acquired TravelCenters of <br>America facilities and one at *Thorntons*.  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) | **How was the framework applied?**<br>The committee made reference to the framework in determining the impact of <br>fatalities on the 2025 bonus outcome. <br>**Fatality at *Thorntons*** <br>In April 2025, a contractor had a fatal incident while repairing one of our <br>facilities. Since then, a thorough investigation has been undertaken to <br>understand the underlying causes and to ensure that appropriate measures <br>are put in place to prevent similar occurrences in the future. <br>The committee has reflected on this event, receiving input from the S&SC, and <br>the reward impact is summarized below. <br>**Fatalities at TravelCenters of America** <br>When bp acquires a new asset, it determines whether an initial transition period <br>(typically 1 to 3 years) is required to allow for full embedding of bp OMS systems. <br>During this period, assets are not consolidated into bp group safety systems <br>and are managed using local performance tracking and scorecards. This is <br>consistent with the approach taken under the fatality framework for the ACB. <br>For TravelCenters of America, it was agreed that this acquisition should be <br>treated as an excluded new asset for three performance years (i.e. to the end <br>of 2025) – reflecting the scale and complexity of the business, with ~20,000 <br>employees and an inherently different risk profile to bp's core operations.<br>The fatalities have, however, been considered at a local level and detail of the <br>reward impact is set out below.<br>Further details of these fatalities are set out on page <u>[55](#i0dd2ee81aac04f8c9c97c86197f0c6df_103)</u>. | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **What happened during the year?**<br>At bp, safety remains our top priority and we are deeply <br>committed to ensuring that our operations are carried out <br>safely every single day. <br>**Safety performance in 2025** <br>During 2025, we recorded five tier 1 events, a slight increase <br>compared with the prior year. Tier 1 events represent our <br>more serious incidents and it remains essential that we stay <br>focused on reducing these incidents. Encouragingly, the <br>number of tier 2 events fell significantly, with 22 events <br>compared to 35 in 2024. <br>However, there were sadly four workforce fatalities during <br>the year – three at our recently acquired TravelCenters of <br>America facilities and one at *Thorntons*.  |  | **How was the framework applied?**<br>The committee made reference to the framework in determining the impact of <br>fatalities on the 2025 bonus outcome. <br>**Fatality at *Thorntons*** <br>In April 2025, a contractor had a fatal incident while repairing one of our <br>facilities. Since then, a thorough investigation has been undertaken to <br>understand the underlying causes and to ensure that appropriate measures <br>are put in place to prevent similar occurrences in the future. <br>The committee has reflected on this event, receiving input from the S&SC, and <br>the reward impact is summarized below. <br>**Fatalities at TravelCenters of America** <br>When bp acquires a new asset, it determines whether an initial transition period <br>(typically 1 to 3 years) is required to allow for full embedding of bp OMS systems. <br>During this period, assets are not consolidated into bp group safety systems <br>and are managed using local performance tracking and scorecards. This is <br>consistent with the approach taken under the fatality framework for the ACB. <br>For TravelCenters of America, it was agreed that this acquisition should be <br>treated as an excluded new asset for three performance years (i.e. to the end <br>of 2025) – reflecting the scale and complexity of the business, with ~20,000 <br>employees and an inherently different risk profile to bp's core operations.<br>The fatalities have, however, been considered at a local level and detail of the <br>reward impact is set out below.<br>Further details of these fatalities are set out on page <u>[55](#i0dd2ee81aac04f8c9c97c86197f0c6df_103)</u>. |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) | **What happened during the year?**<br>At bp, safety remains our top priority and we are deeply <br>committed to ensuring that our operations are carried out <br>safely every single day. <br>**Safety performance in 2025** <br>During 2025, we recorded five tier 1 events, a slight increase <br>compared with the prior year. Tier 1 events represent our <br>more serious incidents and it remains essential that we stay <br>focused on reducing these incidents. Encouragingly, the <br>number of tier 2 events fell significantly, with 22 events <br>compared to 35 in 2024. <br>However, there were sadly four workforce fatalities during <br>the year – three at our recently acquired TravelCenters of <br>America facilities and one at *Thorntons*.  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) | **How was the framework applied?**<br>The committee made reference to the framework in determining the impact of <br>fatalities on the 2025 bonus outcome. <br>**Fatality at *Thorntons*** <br>In April 2025, a contractor had a fatal incident while repairing one of our <br>facilities. Since then, a thorough investigation has been undertaken to <br>understand the underlying causes and to ensure that appropriate measures <br>are put in place to prevent similar occurrences in the future. <br>The committee has reflected on this event, receiving input from the S&SC, and <br>the reward impact is summarized below. <br>**Fatalities at TravelCenters of America** <br>When bp acquires a new asset, it determines whether an initial transition period <br>(typically 1 to 3 years) is required to allow for full embedding of bp OMS systems. <br>During this period, assets are not consolidated into bp group safety systems <br>and are managed using local performance tracking and scorecards. This is <br>consistent with the approach taken under the fatality framework for the ACB. <br>For TravelCenters of America, it was agreed that this acquisition should be <br>treated as an excluded new asset for three performance years (i.e. to the end <br>of 2025) – reflecting the scale and complexity of the business, with ~20,000 <br>employees and an inherently different risk profile to bp's core operations.<br>The fatalities have, however, been considered at a local level and detail of the <br>reward impact is set out below.<br>Further details of these fatalities are set out on page <u>[55](#i0dd2ee81aac04f8c9c97c86197f0c6df_103)</u>. | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| Process safety events over past five years | Process safety events over past five years | Process safety events over past five years | Process safety events over past five years | Process safety events over past five years | Process safety events over past five years |
| 80 |  |  |  |  |  |
| 60 |  |  |  |  |  |
| 40 |  |  |  |  |  |
| 20 |  |  |  |  |  |
| 0 |  |  |  |  |  |
|  | 2021 | 2022 | 2023 | 2024 | **2025** |
| &nbsp;&nbsp;&nbsp;&nbsp;Tier 1 process safety events Tier 2 process safety events![ChartKeyLozengeGreen.jpg](bp-20251231_g29.jpg)<br>![ChartKeyLozengeWarmGrey3.jpg](bp-20251231_g30.jpg) | &nbsp;&nbsp;&nbsp;&nbsp;Tier 1 process safety events Tier 2 process safety events![ChartKeyLozengeGreen.jpg](bp-20251231_g29.jpg)<br>![ChartKeyLozengeWarmGrey3.jpg](bp-20251231_g30.jpg) | &nbsp;&nbsp;&nbsp;&nbsp;Tier 1 process safety events Tier 2 process safety events![ChartKeyLozengeGreen.jpg](bp-20251231_g29.jpg)<br>![ChartKeyLozengeWarmGrey3.jpg](bp-20251231_g30.jpg) | &nbsp;&nbsp;&nbsp;&nbsp;Tier 1 process safety events Tier 2 process safety events![ChartKeyLozengeGreen.jpg](bp-20251231_g29.jpg)<br>![ChartKeyLozengeWarmGrey3.jpg](bp-20251231_g30.jpg) | &nbsp;&nbsp;&nbsp;&nbsp;Tier 1 process safety events Tier 2 process safety events![ChartKeyLozengeGreen.jpg](bp-20251231_g29.jpg)<br>![ChartKeyLozengeWarmGrey3.jpg](bp-20251231_g30.jpg) | &nbsp;&nbsp;&nbsp;&nbsp;Tier 1 process safety events Tier 2 process safety events![ChartKeyLozengeGreen.jpg](bp-20251231_g29.jpg)<br>![ChartKeyLozengeWarmGrey3.jpg](bp-20251231_g30.jpg) |

---

![102](bp-20251231_g166.gif)

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) | ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) |  | ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) |
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) | **What was the outcome?** <br>In line with the framework, the committee reflected on the fatality at *Thorntons*. While the S&SC confirmed <br>that the incident was unforeseeable and not indicative of a systemic issue, we believe that any loss of life is <br>unacceptable and have decided to reduce the outcome by 4 points for all participants. Regarding the fatalities <br>in TravelCenters of America, a more material reduction has been made to the local bonus plan. The S&SC has <br>also advised that corrective action has been undertaken to prevent similar occurrences in the future. <br>The committee is mindful of the need to ensure that the fatality framework continues to support our <br>determination to eliminate workforce fatalities. During 2026, the committee will reflect on this and make any <br>necessary changes to the framework.  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) | ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) | **4 point reduction**<br>resulting in a final <br>bonus score of **1.59 out** <br>**of 2** for all participants <br>of the group ACB.  | ![BPDarkGreenTopRoundCorner.gif](bp-20251231_g56.gif) |
|  | **What was the outcome?** <br>In line with the framework, the committee reflected on the fatality at *Thorntons*. While the S&SC confirmed <br>that the incident was unforeseeable and not indicative of a systemic issue, we believe that any loss of life is <br>unacceptable and have decided to reduce the outcome by 4 points for all participants. Regarding the fatalities <br>in TravelCenters of America, a more material reduction has been made to the local bonus plan. The S&SC has <br>also advised that corrective action has been undertaken to prevent similar occurrences in the future. <br>The committee is mindful of the need to ensure that the fatality framework continues to support our <br>determination to eliminate workforce fatalities. During 2026, the committee will reflect on this and make any <br>necessary changes to the framework.  |  |  | **4 point reduction**<br>resulting in a final <br>bonus score of **1.59 out** <br>**of 2** for all participants <br>of the group ACB.  |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) | **What was the outcome?** <br>In line with the framework, the committee reflected on the fatality at *Thorntons*. While the S&SC confirmed <br>that the incident was unforeseeable and not indicative of a systemic issue, we believe that any loss of life is <br>unacceptable and have decided to reduce the outcome by 4 points for all participants. Regarding the fatalities <br>in TravelCenters of America, a more material reduction has been made to the local bonus plan. The S&SC has <br>also advised that corrective action has been undertaken to prevent similar occurrences in the future. <br>The committee is mindful of the need to ensure that the fatality framework continues to support our <br>determination to eliminate workforce fatalities. During 2026, the committee will reflect on this and make any <br>necessary changes to the framework.  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) | ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) | **4 point reduction**<br>resulting in a final <br>bonus score of **1.59 out** <br>**of 2** for all participants <br>of the group ACB.  | ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) | ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |  | ![BPDarkGreenBottomRoundCorner.gif](bp-20251231_g52.gif) |

---

![DRR_SharePlanScorecardV1-LEFT.jpg](bp-20251231_g167.jpg)

---

| | | |
|:---|:---|:---|
| 102 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

**2023-25 performance share plan scorecard and outcome** 

2023-25 performance shares were granted under the executive directors' incentive plan (EDIP). The scorecard for this cycle consists of sustainable

emissions reductions (15% weighting), relative total shareholder return (rTSR) (20% weighting), return on average capital employed (ROACE)★ (20%

weighting), adjusted EBIDA per share CAGR★ (20% weighting) and strategic progress (25% weighting).

**2023-25 performance share plan scorecard (audited)**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| **Share plan scorecard** | **Share plan scorecard** | **Share plan scorecard** | **Share plan scorecard** | **Share plan scorecard** | **Share plan scorecard** | **Share plan scorecard** |
|  |  |  | **Threshold**  | **Maximum** |  |  |
| **Categories** | **Measures** |  | **Threshold**  | **Maximum** | **Weighting** | **Outcomes** |
| **Net zero**<br>**(15%)** | **Net zero across entire bp** <br>**operations by 2050** <br>**(Scope 1 + 2)** | **Net zero across entire bp** <br>**operations by 2050** <br>**(Scope 1 + 2)** | 12% | 16% | 15% | 3.3% |
| **Net zero**<br>**(15%)** | **Net zero across entire bp** <br>**operations by 2050** <br>**(Scope 1 + 2)** | **Net zero across entire bp** <br>**operations by 2050** <br>**(Scope 1 + 2)** |  |  |  |  |
| **Net zero**<br>**(15%)** | **Net zero across entire bp** <br>**operations by 2050** <br>**(Scope 1 + 2)** | **Net zero across entire bp** <br>**operations by 2050** <br>**(Scope 1 + 2)** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 12.9%** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Actual: 12.9%** |  |  |
| **rTSR**<br>**(20%)** | **rTSR** | **rTSR** | Fourth | First | 20% | 0% |
| **rTSR**<br>**(20%)** | **rTSR** | **rTSR** |  |  |  |  |
| **rTSR**<br>**(20%)** | **rTSR** | **rTSR** | **Actual: Fifth** | **Actual: Fifth** |  |  |
| **Financials** <br>**(40%)** | **ROACE (average 2023-25)** | **ROACE (average 2023-25)** | 20.2% | 22.2% | 20% | 0% |
| **Financials** <br>**(40%)** | **ROACE (average 2023-25)** | **ROACE (average 2023-25)** |  |  |  |  |
| **Financials** <br>**(40%)** | **ROACE (average 2023-25)** | **ROACE (average 2023-25)** | **Actual: 15.4%** | **Actual: 15.4%** |  |  |
| **Financials** <br>**(40%)** | **Adjusted EBIDA per share** <br>**CAGR** | **Adjusted EBIDA per share** <br>**CAGR** | 12.5% | 14.5% | 20% | 0% |
| **Financials** <br>**(40%)** | **Adjusted EBIDA per share** <br>**CAGR** | **Adjusted EBIDA per share** <br>**CAGR** |  |  |  |  |
| **Financials** <br>**(40%)** | **Adjusted EBIDA per share** <br>**CAGR** | **Adjusted EBIDA per share** <br>**CAGR** | **Actual: 9.8%** | **Actual: 9.8%** |  |  |
| **Strategic progress** <br>**(25%)** | **Deliver value through** <br>**resilient hydrocarbon** <br>**business**  | **Deliver value through** <br>**resilient hydrocarbon** <br>**business**  |  |  | 25% | 20% |
| **Strategic progress** <br>**(25%)** | **Deliver value through** <br>**resilient hydrocarbon** <br>**business**  | **Deliver value through** <br>**resilient hydrocarbon** <br>**business**  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  | 25% | 20% |
| **Strategic progress** <br>**(25%)** | **Deliver value through** <br>**resilient hydrocarbon** <br>**business**  | **Deliver value through** <br>**resilient hydrocarbon** <br>**business**  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  | 25% | 20% |
| **Strategic progress** <br>**(25%)** | **Deliver value through** <br>**resilient hydrocarbon** <br>**business**  | **Deliver value through** <br>**resilient hydrocarbon** <br>**business**  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  |  |  |
| **Strategic progress** <br>**(25%)** | **Demonstrate track record,** <br>**scale and value in low** <br>**carbon energy**  | **Demonstrate track record,** <br>**scale and value in low** <br>**carbon energy**  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  |  |  |
| **Strategic progress** <br>**(25%)** | **Demonstrate track record,** <br>**scale and value in low** <br>**carbon energy**  | **Demonstrate track record,** <br>**scale and value in low** <br>**carbon energy**  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  |  |  |
| **Strategic progress** <br>**(25%)** | **Demonstrate track record,** <br>**scale and value in low** <br>**carbon energy**  | **Demonstrate track record,** <br>**scale and value in low** <br>**carbon energy**  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  |  |  |
| **Strategic progress** <br>**(25%)** | **Accelerate growth in** <br>**convenience and mobility**  | **Accelerate growth in** <br>**convenience and mobility**  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  |  |  |
| **Strategic progress** <br>**(25%)** | **Accelerate growth in** <br>**convenience and mobility**  | **Accelerate growth in** <br>**convenience and mobility**  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  |  |  |
| **Strategic progress** <br>**(25%)** | **Accelerate growth in** <br>**convenience and mobility**  | **Accelerate growth in** <br>**convenience and mobility**  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  | Qualitative and quantitative <br>assessment by the committee, <br>see pages <u>[103](#i8fc4dd5814f24f1dae54daecb3919492_24151)</u><u>-</u><u>[105](#i38c182be05a643269378aa42576d1663_4-1-1-5-956434)</u>.  |  |  |
|  | **Assessed outcome**  | **Assessed outcome**  |  |  | **23.3% out of 100%**  | **23.3% out of 100%**  |
| Assessed <br>outcome<br>**23.3% out of 100%** | Assessed <br>outcome<br>**23.3% out of 100%** | Underpin: Committee review of absolute <br>shareholder returns, long-term safety and <br>environmental performance, low carbon <br>and climate change considerations. <br>**No adjustment** | Underpin: Committee review of absolute <br>shareholder returns, long-term safety and <br>environmental performance, low carbon <br>and climate change considerations. <br>**No adjustment** | Final vesting after <br>committee judgement <br>**23.3% out of 100%** | Final vesting after <br>committee judgement <br>**23.3% out of 100%** | Final vesting after <br>committee judgement <br>**23.3% out of 100%** |
| Assessed <br>outcome<br>**23.3% out of 100%** | Assessed <br>outcome<br>**23.3% out of 100%** | Underpin: Committee review of absolute <br>shareholder returns, long-term safety and <br>environmental performance, low carbon <br>and climate change considerations. <br>**No adjustment** | Underpin: Committee review of absolute <br>shareholder returns, long-term safety and <br>environmental performance, low carbon <br>and climate change considerations. <br>**No adjustment** | Final vesting after <br>committee judgement <br>**23.3% out of 100%** | Final vesting after <br>committee judgement <br>**23.3% out of 100%** | Final vesting after <br>committee judgement <br>**23.3% out of 100%** |
| Assessed <br>outcome<br>**23.3% out of 100%** | Assessed <br>outcome<br>**23.3% out of 100%** | Underpin: Committee review of absolute <br>shareholder returns, long-term safety and <br>environmental performance, low carbon <br>and climate change considerations. <br>**No adjustment** | Underpin: Committee review of absolute <br>shareholder returns, long-term safety and <br>environmental performance, low carbon <br>and climate change considerations. <br>**No adjustment** | Final vesting after <br>committee judgement <br>**23.3% out of 100%** | Final vesting after <br>committee judgement <br>**23.3% out of 100%** | Final vesting after <br>committee judgement <br>**23.3% out of 100%** |
| Assessed <br>outcome<br>**23.3% out of 100%** | Assessed <br>outcome<br>**23.3% out of 100%** | Underpin: Committee review of absolute <br>shareholder returns, long-term safety and <br>environmental performance, low carbon <br>and climate change considerations. <br>**No adjustment** | Underpin: Committee review of absolute <br>shareholder returns, long-term safety and <br>environmental performance, low carbon <br>and climate change considerations. <br>**No adjustment** |  |  |  |

---

![5497558139173](bp-20251231_g168.gif)

![5497558139009](bp-20251231_g169.gif)

![61](bp-20251231_g170.gif)

![73](bp-20251231_g171.gif)

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 103 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

**Sustainability performance**

To the end of 2025, actions or interventions that have led to ongoing

reductions in Scope 1 and 2 emissions have totalled 12.9% relative to the

baseline year of 2019. The main contributions during the performance

period have come from centralization and electrification of bpx energy

processing infrastructure, refineries switching to low carbon power,

and a focus on flare system and practices improvements across

production sites.

**Relative TSR** 

During the performance period, bp's rTSR performance placed it fifth

out of eight in the comparator group which resulted in nil vesting.

**Financials** 

Performance of ROACE and adjusted EBIDA per share CAGR, at 15.4%

and 9.8% respectively, were below the targets set at the start of the

performance period and achieved nil vesting.

As part of the review of outcomes, the committee considers the impact

of the external environment with respect to ROACE outcomes, and in

respect of adjusted EBIDA per share CAGR the committee reviews

share buyback activity outside of plan during the performance period.

It determined that, in line with past practice, no further adjustments

should be made to either of these elements for the 2023-25 cycle.

**Strategic progress**

**Overview of strategic progress (2023-25)**

Assessing performance against this measure has been challenging

as it spans a three-year period that has been marked by significant

strategic change.

The criteria, including financial KPIs, set at the start of the performance

period (2023) were intended to measure delivery against the three

strategic pillars at that time: resilient hydrocarbons, low carbon energy

and convenience and mobility. However, as our strategy has continued

to evolve, these original objectives no longer fully reflect the strategic

performance achieved over the period.

The committee has therefore assessed performance against the

original criteria, including the financial KPIs, whilst also considering the

broader strategic milestones delivered during the period. In particular,

progress against the reset strategy outlined as part of the Capital

Markets Update in February 2025 has been taken into account.

In summary:

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) | **Pillar 1: Resilient hydrocarbons** <br>Delivered strong operational and financial performance over <br>the period with 2025 refining availability★ and plant <br>reliability★ both exceeding 96%, delivering unit production <br>costs in line with target and production above our plan. We <br>brought 17 major projects★ across oil, gas and refining online <br>and had significant exploration success, including <br>Bumerangue in Brazil.  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Pillar 1: Resilient hydrocarbons** <br>Delivered strong operational and financial performance over <br>the period with 2025 refining availability★ and plant <br>reliability★ both exceeding 96%, delivering unit production <br>costs in line with target and production above our plan. We <br>brought 17 major projects★ across oil, gas and refining online <br>and had significant exploration success, including <br>Bumerangue in Brazil.  |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) | **Pillar 2: Low carbon energy**<br>Since setting targets in 2023, bp's low carbon energy <br>business has undergone significant transformation, leading <br>to the retirement of the original objectives. The business has <br>delivered a robust set of results within the context of the <br>reset strategy and shifting priorities focused on value. | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Pillar 2: Low carbon energy**<br>Since setting targets in 2023, bp's low carbon energy <br>business has undergone significant transformation, leading <br>to the retirement of the original objectives. The business has <br>delivered a robust set of results within the context of the <br>reset strategy and shifting priorities focused on value. |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

---

| | | |
|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) | **Pillar 3: Convenience and mobility**<br>Strong operational growth, with 21% convenience gross <br>margin CAGR 2023-25 (inclusive) including the acquisition <br>of TravelCenters of America in 2023. With some of the <br>measures being retired under the reset strategy, financial <br>performance has remained strong with modified free cash <br>flow for 2025 above the plan we set in 2023, underpinned by <br>significant year-on-year growth in operating cash flow★.  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Pillar 3: Convenience and mobility**<br>Strong operational growth, with 21% convenience gross <br>margin CAGR 2023-25 (inclusive) including the acquisition <br>of TravelCenters of America in 2023. With some of the <br>measures being retired under the reset strategy, financial <br>performance has remained strong with modified free cash <br>flow for 2025 above the plan we set in 2023, underpinned by <br>significant year-on-year growth in operating cash flow★.  |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

---

| | | |
|:---|:---|:---|
| ![BPGreenTopRoundCorner.gif](bp-20251231_g21.gif) |  | ![BPGreenTopRoundCorner.gif](bp-20251231_g21.gif) |
|  | **Overall performance:** <br>Considering delivery against both the original pillars and <br>progress against our reset strategy to date, an outcome of <br>**80% of maximum** was deemed appropriate for 2023-25. <br>|  |
| ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |  | ![BPGreenBottomRoundCorner.gif](bp-20251231_g24.gif) |

---

---

| | | |
|:---|:---|:---|
| 104 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

**Key** 🟇 On track 🟇 Strong progress 🟇 Improvement required

![](bp-20251231_g172.gif)

---

| | | |
|:---|:---|:---|
| **1. Deliver value through a resilient hydrocarbon business KPIs** (KPIs as set in 2023)  | **1. Deliver value through a resilient hydrocarbon business KPIs** (KPIs as set in 2023)  | **1. Deliver value through a resilient hydrocarbon business KPIs** (KPIs as set in 2023)  |
| **Unit production cost** 🟇<br>Average unit production cost over the period was <br>$6.08/boe with 2025 delivered at $6.28/boe, in <br>line with our 2025 target, representing strong <br>progress on this target while making value-based <br>portfolio choices.<br>| **Plant reliability** 🟇<br>2025 plant reliability of 96.1% was a record high, <br>reflecting our focus on operational delivery and <br>supporting our production exceeding plans.<br>| **Refining availability** 🟇<br>Refining availability was high in 2025 with all four <br>quarters above 96% and a full year average of <br>96.3%, reflecting strong progress on this KPI, with <br>2024 impacted by the plant-wide power outage <br>at Whiting.<br>|

---

---

| | | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| 2023 | 2024 | 2025 | **2025** <br>**target**<br>| 2023 | 2024 | 2025 | **2025** <br>**target**<br>| 2023 | 2024 | 2025 | **2025** <br>**target**<br>|
| $5.8/boe | $6.2/boe | $6.3/boe | **$6.0/boe** | 95.0% | 95.2% | 96.1% | **96.0%** | 96.1% | 94.3% | 96.3% | **96.0%** |

---

**Overview** <br>•Continued to high-grade our portfolio and drive higher margins.<br>•Delivered 17 major projects (15 in oil and gas, two in refining) including seven in 2025 of which five were ahead of schedule.<br>•Continued to high-grade our portfolio, including growing bpx energy production by 43% and being selected to help governments develop their resources.<br>•Exceptional exploration year with 12 discoveries in 2025, including in the Gulf of America, Namibia and Brazil.<br>•The hydrocarbon business performed well against financial measures. <br>

![](bp-20251231_g173.gif)

---

| | |
|:---|:---|
| **2. Demonstrate track record, scale and value in low carbon energy KPIs** (KPIs as set in 2023) | **2. Demonstrate track record, scale and value in low carbon energy KPIs** (KPIs as set in 2023) |
| **Developed renewables to FID**★ 🟇 <br>Growth has been driven by Lightsource bp. Tracking below target as the solar <br>sector has been significantly impacted by higher interest rates, inflation and <br>supply chain constraints. As a result, the portfolio has been high-graded <br>based on value, managed pace of development and decapitalization.<br>No outcome for 2025 following bp's reset strategy and subsequent <br>retirement of our strategic pillars and associated targets. <br>| **Renewables pipeline**★ 🟇 <br>Growth has been driven by Lightsource bp as well as successful offshore wind <br>bids, which now sit within the JERA Nex bp joint venture. The hydrogen and <br>CCS portfolio has been prioritized based on deliverability, value and returns – <br>with four sanctioned projects in development.<br>Similar to developed renewables to FID, no outcome is shown for 2025 <br>following bp's reset strategy and subsequent retirement of measures. <br>|

---

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| 2023 | 2024 | 2025 | **2025** <br>**target**<br>| 2023 | 2024 | 2025 | **2025** <br>**target**<br>|
| 6.2GW | 8.2GW | n/a | **20GW** | 58.3GW | 60.6GW | n/a | **n/a** |

---

**Overview** <br>•The low carbon energy business underwent a significant portfolio reset and rationalization – driving down costs and improving capital efficiency to support <br>the group's modified free cash flow delivery.<br>•JERA and bp completed the formation of JERA Nex bp in August 2025, establishing a top-tier global offshore wind joint venture. The sale of bp's onshore wind <br>business to LS Power completed in December 2025.<br>•Adjusted EBITDA over the period was lower than expected, reflecting a challenging US solar market and increased ramp up and origination spend in hydrogen, <br>CCS and offshore wind to progress previous growth targets. 2025 reflects effective delivery of portfolio high-grading and the decapitalization strategy.<br>

---

| | | |
|:---|:---|:---|
| **3. Accelerate growth in convenience and mobility KPIs** (KPIs as set in 2023) | **3. Accelerate growth in convenience and mobility KPIs** (KPIs as set in 2023) | **3. Accelerate growth in convenience and mobility KPIs** (KPIs as set in 2023) |
| **Convenience margin growth**★ 🟇<br>The acquisition of TravelCenters of America <br>completed in 2023 underpinning 21% convenience <br>gross margin CAGR over the period. <br>| **Strategic convenience sites**★ 🟇 <br>As the target was retired at the start of 2025, in <br>line with our reset strategy, the measure was not <br>tracked during 2025. However, performance was <br>close to target at end of 2024.<br>| ***Castrol* performance (revenue)** 🟇<br>*Castrol* had a strong 2025, and now has 10 <br>quarters of consecutive year-on-year earnings <br>growth. *Castrol* continued strategic growth <br>initiatives, including expansion of its thermal <br>management portfolio beyond cooling fluids into <br>integrated full-service solutions.<br>|

---

![](bp-20251231_g174.gif)

---

| | | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| 2023 | 2024 | 2025 | **2025** <br>**target**<br>| 2023 | 2024 | 2025 | **2025** <br>**target**<br>| 2023 | 2024 | 2025 | **2025** <br>**target**<sup>a</sup><br>|
| 60% | 17% | (5)% | **10%** | 2850 | 2950 | n/a | **3000** | $7.0bn | $6.9bn | $7.1bn | **n/a** |

---

**Overview** <br>•Despite the 2025 strategy reset focussing on downstream, the convenience and mobility business made strong progress against the objectives set back in <br>2023 — providing the platform to grow the business. <br>•Convenience and mobility delivered adjusted EBITDA below plan, reflecting the more challenging market backdrop and refocused capital frame. However, <br>modified free cash flow was ahead of target. <br>

aThe *Castrol* performance KPI was retired during the performance period and performance has therefore been considered 'in the round' including reference to earnings and volume growth.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 105 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

---

| | | | | |
|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Overall assessment**  |  |  |  |
|  | As set out in the 2024 directors' remuneration report, the committee has assessed performance against the <br>original three strategic pillars within the context of bp's reset strategy: | As set out in the 2024 directors' remuneration report, the committee has assessed performance against the <br>original three strategic pillars within the context of bp's reset strategy: | As set out in the 2024 directors' remuneration report, the committee has assessed performance against the <br>original three strategic pillars within the context of bp's reset strategy: |  |
|  | In February 2025, bp introduced a <br>fundamentally reset strategy as part of <br>its Capital Markets Update (CMU). The <br>strategy focuses on strengthening <br>performance by growing free cash flow, <br>returns and building long-term <br>shareholder value, supported by four <br>primary targets to be delivered by the <br>end of 2027.<br>For all the primary targets, performance is <br>currently on track or ahead of plan with <br>strong underlying financial performance <br>during 2025. <br>| **Growing free cash flow** 🟇<br>CMU target: >20% CAGR (2024-27) <br>•Adjusted free cash flow★ was increased <br>by c.55% in 2025, based on CMU price <br>assumptions, which is ahead of plan. <br>**Reducing net debt** 🟇<br>CMU target: $14-$18bn (end of 2027)<br>Net debt★ at the end of 2025 was <br>$22.2 billion, which is $800 million <br>lower than at the end of 2024. <br>During 2025, $1.2 billion of perpetual <br>hybrid bonds were redeemed and bp made <br>$1.2 billion of pre-tax payments against our <br>Gulf of America settlement liability. <br>| **Structural cost reductions**★ 🟇<br>CMU target: $4-$5bn (end of 2027)<br>Since the start of the programme, bp <br>has delivered $2.8 billion of the cost <br>reduction target. Having reflected on <br>the outcome of the strategic review to <br>divest *Castrol*, the CMU target was <br>increased (to $5.5-$6.5 billion).<br>**Generating higher returns** 🟇<br>CMU target: >16% ROACE★ (end of 2027)<br>ROACE was around 14%, based on <br>CMU price assumptions, an increase from <br>around 12% in 2024. <br>|  |
|  | **Conclusion**<br>Taking into account delivery against the targets set under the original pillars, alongside bp's evolving strategic context and the progress <br>made on our reset strategy to date, the committee concluded that performance on this measure supports vesting of the strategic <br>progress measure at 80% of maximum. Strategic progress remains a key measure for outstanding awards and the committee will <br>continue to apply judgement in the context of broader strategic delivery. | **Conclusion**<br>Taking into account delivery against the targets set under the original pillars, alongside bp's evolving strategic context and the progress <br>made on our reset strategy to date, the committee concluded that performance on this measure supports vesting of the strategic <br>progress measure at 80% of maximum. Strategic progress remains a key measure for outstanding awards and the committee will <br>continue to apply judgement in the context of broader strategic delivery. | **Conclusion**<br>Taking into account delivery against the targets set under the original pillars, alongside bp's evolving strategic context and the progress <br>made on our reset strategy to date, the committee concluded that performance on this measure supports vesting of the strategic <br>progress measure at 80% of maximum. Strategic progress remains a key measure for outstanding awards and the committee will <br>continue to apply judgement in the context of broader strategic delivery. |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

**Other vesting considerations**

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

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

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

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

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

and the experience of shareholders overall through the performance period. The committee agreed it was not necessary to apply discretion to the

formulaic outcome and therefore approved vesting of 23.3% for the 2023-25 EDIP award. This decision yields the outcome shown in the table

below for the former CEO. The scorecard detail is shown on page <u>[102](#i0dd2ee81aac04f8c9c97c86197f0c6df_208)</u>.

The committee was satisfied that the remuneration policy had operated as intended and therefore no further changes were required. No malus and

clawback provisions were applied in respect of the annual bonus or EDIP awards in the previous financial year.

**2023-25 performance share plan outcome (audited)** 

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | Shares awarded | Unvested shares <br>following application <br>of performance <br>factor<br>| Value of unvested shares <br>following application of <br>performance factor<sup>a</sup><br>| Impact of<br>share price<br>change<sup>a</sup><br>|
| Carol Howle<sup>b</sup> | 137610 | 166594 | £733,014 | (£56,642) |
| Murray Auchincloss | 717958 | 194018 | £853,679 | (£93,129) |
| Kate Thomson<sup>b</sup> | 72650 | 87951 | £386,984 | (£29,903) |

---

aThese values reflect the impact of the change in share price since grant related to the number of shares which are no longer subject to performance conditions, including dividend equivalents

accrued at 13 February 2026. The face values of these awards were calculated using a market price of ordinary shares at close on the dates of award, as follows: £4.88 on 2 May 2023 and £4.74 on

7 June 2023 respectively. The average share price during Q4 2025 was £4.40. The amount reported as 2025 income in the single figure is therefore £0.854 million for Murray, £0.733 million for

Carol and £0.387 million for Kate.

bCarol Howle's and Kate Thomson's awards were made under the below board performance share plan where grants are made at 50% of maximum, rather than at 100% of maximum as for the

EDIP. For 2023-25, performance share awards below board had a different scorecard to executive directors, which resulted in an outcome of 52.8% of maximum.

---

| | | |
|:---|:---|:---|
| 106 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

**Policy implementation for 2026** 

The table below shows how the remuneration policy, being submitted to shareholders for approval at the 2026 annual general meeting on 23 April

2026, will be implemented. As outlined in the chair's statement, the 2023 policy has been broadly rolled forward for 2026. Full details of the policy

being submitted for shareholder approval can be found on pages <u>[118](#i4d0cbb9d540342d38e862c3c96b9111a_175894)</u><u>-</u><u>[125](#ice7ed01c803e4808b3b636ee225997b7_8758)</u>.

---

| | |
|:---|:---|
| Policy feature | 2026 implementation  |
| ![DRR_SIngleLozenge_PolicyImp-SalaryV2.gif](bp-20251231_g175.gif) |  |
| To provide fixed remuneration to reflect the scale and complexity of <br>both the business and the role, and to be competitive with the external <br>market.<br>When setting salaries, the committee considers practice in other <br>energy majors, as well as European and US companies of a similar size, <br>geographic spread and business dynamic to bp. Percentage increases <br>for executive directors will not exceed that for the wider workforce, <br>other than in specific circumstances identified by the committee (e.g. <br>in response to a substantial change in responsibilities).<br>Salaries are normally set in the home currency of the executive director <br>and are reviewed annually. They may be reviewed at other times where <br>appropriate.<br>| •The budgeted increase to our UK salaried staff effective from 1 April <br>2026, our annual salary review date, will be 3.5%.<br>•For 2026, the executive director's salaries will be: <br>•Meg O'Neill: £1,600,000 (from appointment)<br>•Carol Howle: £1,508,000 (from appointment)<br>•Kate Thomson: £894,000 (3.5% increase, effective 2026 AGM)<br>|
| ![DRR_SIngleLozenge_PolicyImp-PenAndBenV2.gif](bp-20251231_g176.gif) |  |
| Executive directors normally participate in the company retirement <br>plans that operate in their home country.<br>New appointees from within the bp group retain previously accrued <br>benefits related to service prior to appointment as executive director. <br>For their service as a director, cash allowance in lieu of pension will be <br>up to 20% of base salary.<br>For future appointments, the committee will carefully review any <br>retirement benefits to be granted to a new director, taking account of <br>retirement policies across the wider group and any arrangements <br>currently in place.<br>| •Executive directors' cash allowance in lieu of pension is 20% of <br>base pay (in line with the wider workforce).<br>•Prior to their appointment as executive directors, Carol and Kate <br>received a UK deferred pension. No further pension is accrued <br>under either plan.<br>•Benefits will remain unchanged for 2026 and include car-related <br>provisions, security assistance, assistance with tax preparation, <br>insurance and medical cover.<br>|
| ![DRR_SIngleLozenge_PolicyImp-AnnBon.gif](bp-20251231_g177.gif) |  |
| Bonus is measured against an annual scorecard. The committee holds <br>discretion to choose the specific measures and the relative weightings <br>adopted in the annual scorecard, to reflect the annual plan as agreed <br>with the board.<br>Numeric scales are set for each measure, to score outcomes relative to <br>targets. A scorecard outcome of 1.0 reflects the target outcome and <br>2.0 is the maximum outcome.<br>Target bonus is 112.5% of salary, and maximum bonus is 225% of salary.<br>Half the bonus is paid in cash, and half is deferred into bp shares for <br>three years up until the 'minimum shareholding requirement' is met. At <br>this point, 67% is paid in cash and 33% is paid in bp shares. Dividends <br>(or equivalents, including the value of any reinvestment) may accrue in <br>respect of any deferred shares.<br>Awards are subject to operationally robust and effective malus and <br>clawback provisions as described below.<br>| •For 2026, our scorecard will be assessed against the following <br>categories: safety (15%), operations (20%) and financials (65%).<br>•See page <u>[109](#i533d31c765ee497e837b4fed830a1b6a_3935)</u> for further details on measures for the 2026 <br>annual bonus.<br>•The framework on fatalities, which helps guide decisions on <br>adjustments to the bonus outcome in relation to fatalities, will <br>continue to be applied. Further detail has been provided on <br>page <u>[101](#i7d5790f11031478c88ae8875d181caff_35364)</u>.<br>|

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 107 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

---

| | |
|:---|:---|
| Policy feature | 2026 implementation  |
| ![DRR_SIngleLozenge_PolicyImp-PerfShare.gif](bp-20251231_g178.gif) |  |
| Performance shares are granted with a three-year performance period, <br>measured against a scorecard.<br>The committee holds discretion to choose the specific measures and <br>the relative weightings adopted in the scorecard, to ensure they are <br>focused on the near-term priorities for delivering the bp strategy in the <br>interests of shareholders.<br>Annual grants are 500% of salary for the CEO, and 450% of salary for <br>any other executive director. Awards will vest in proportion to the <br>outcomes measured through the performance scorecard, subject to <br>any adjustment by the committee, and will be subject to a three-year <br>post-vesting holding period. <br>Awards are subject to operationally robust and effective malus and <br>clawback provisions as described below.<br>| •For our 2026-28 cycle, the scorecard categories will be rTSR (30%), <br>financials (50%) and environmental, social and governance (20%). <br>•See page <u>[109](#i533d31c765ee497e837b4fed830a1b6a_3932)</u> for further details on measures for the 2026-28 EDIP. <br>•The award will be subject to an underpin that takes into <br>consideration overall safety performance and ongoing progress <br>towards a strong and resilient balance sheet over the performance <br>period. <br>•The 2026-28 awards will be granted based on the average closing <br>share price of each calendar day in the 90-day period ending on the <br>date of bp's 2026 AGM.<br>|
| ![DRR_SIngleLozenge_PolicyImp-ShareReq.gif](bp-20251231_g179.gif) |  |
| CEO to build a shareholding of at least five times salary, and other executive directors four and a half times salary, within five years of <br>appointment.<br>Executive directors are required to maintain that level for at least two years after they cease to be a director. | 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 <br>appointment.<br>Executive directors are required to maintain that level for at least two years after they cease to be a director. |
| ![DRR_SIngleLozenge_PolicyImp-MalClaw.gif](bp-20251231_g180.gif) |  |
| Operationally robust and effective malus and clawback provisions apply to our incentive awards.<br>The following events can trigger either malus or clawback: a material safety or environmental failure; material reputational damage; an incorrect <br>award outcome due to miscalculation or incorrect information; a restatement due to financial reporting failure or misstatement of audited results; <br>material misconduct; or fraud. <br>In addition, malus may be triggered by the following events: material downturn in performance of the group or any part of it and conduct leading <br>to significant losses; or other exceptional circumstances that the committee considers similar in nature. <br>The period during which malus and/or clawback may be applied is generally three years from vesting or, if longer, until the expiry of any retention <br>or holding period applicable to an award, which is considered a sufficient period for any issues that might give rise to malus or clawback to be <br>identified. | Operationally robust and effective malus and clawback provisions apply to our incentive awards.<br>The following events can trigger either malus or clawback: a material safety or environmental failure; material reputational damage; an incorrect <br>award outcome due to miscalculation or incorrect information; a restatement due to financial reporting failure or misstatement of audited results; <br>material misconduct; or fraud. <br>In addition, malus may be triggered by the following events: material downturn in performance of the group or any part of it and conduct leading <br>to significant losses; or other exceptional circumstances that the committee considers similar in nature. <br>The period during which malus and/or clawback may be applied is generally three years from vesting or, if longer, until the expiry of any retention <br>or holding period applicable to an award, which is considered a sufficient period for any issues that might give rise to malus or clawback to be <br>identified. |
| ![DRR_SIngleLozenge_PolicyImp-ComFlex.gif](bp-20251231_g181.gif) |  |
| The committee has discretion to adjust performance measures and weightings, and to revise the peer group for the rTSR measure.<br>This discretion allows appropriate realignment, throughout the policy term, for changes in the annual plan and for the anticipated evolution of the <br>low carbon business environment.<br>The committee also holds discretion in determining the outcomes for annual bonus and performance shares, allowing it to take broad views on <br>alignment with shareholder experience, environmental, societal and other relevant considerations e.g. portfolio changes. | The committee has discretion to adjust performance measures and weightings, and to revise the peer group for the rTSR measure.<br>This discretion allows appropriate realignment, throughout the policy term, for changes in the annual plan and for the anticipated evolution of the <br>low carbon business environment.<br>The committee also holds discretion in determining the outcomes for annual bonus and performance shares, allowing it to take broad views on <br>alignment with shareholder experience, environmental, societal and other relevant considerations e.g. portfolio changes. |

---

---

| | | |
|:---|:---|:---|
| 108 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

**Incoming CEO's arrangements** 

As announced on 17 December 2025, Meg O'Neill will join bp as CEO on 1 April 2026. Her salary has been set at £1,600,000 and she will not be

eligible to receive a salary increase until the conclusion of the wider annual pay review process in April 2027. She is eligible for a cash allowance in

lieu of pension which will be 20% of salary in line with the wider workforce and her other benefits will be in line with policy.

Regarding her incentive awards, Meg's opportunity levels will align with the maximums outlined in the table above. For 2026, both her annual bonus

and performance share award will be pro-rated to reflect the portion of the year she serves as an executive director. The awards will be subject to

the deferral requirements, holding periods and malus and clawback provisions outlined under our policy.

**Relocation support** 

Meg will be relocating from Australia where her previous employer was headquartered and she will receive relocation assistance to support her

move. This includes – among other elements – immigration support, temporary accommodation for up to six months and shipping. The cost of the

relocation assistance is subject to clawback if Meg was to resign within two years of appointment to the role. Limited repatriation support will be

provided at the end of Meg's tenure.

**Buy-out awards** 

On appointment, Meg will be granted cash and share-based awards to replace remuneration foregone when leaving her previous employer. In line

with the policy, the committee took into account the nature, timing and value of the awards being forfeited when determining the structure and

size of the buy-out awards offered. The committee is satisfied that the buy-out awards are consistent with the policy and reflect like-for-like

replacement, noting the complexities in Meg's foregone awards such as a mix of standard performance awards, non-performance awards, and pre-

grant performance awards, each with overlapping five-year vesting periods. The buy-out awards will take three forms:

• Cash awards: To replace the 2025 annual bonus, 2026 annual bonus (pro-rated to 31 March 2026), and share awards where the full vesting period

would have elapsed or would substantially have elapsed prior to Meg joining. The value of the annual bonus and performance shares will be based on

her previous employer's actual performance where possible. For foregone performance and restricted shares due to vest in the first half of 2026, the

value will be based on the 30-day average share price of her previous employer up to the vesting date. Full details of the value of this cash award will

be disclosed in the 2026 directors' remuneration report.

• Restricted share awards: To replace the forfeited restricted share awards (outstanding and to be granted in respect of 2025 pre-grant performance).

This buy-out award will also cover performance share awards due to vest in 2027 and 2028 where in-flight performance has been valued at 50% of

maximum. The awards will be aligned with the vesting schedules of Meg's foregone awards and have an expected value of £8.3 million.

• Performance share awards: To replace the forfeited performance share awards due to vest in 2029, 2030 and 2031 following their respective five-

year periods. These awards will be subject to bp's relative TSR performance, with the start of the performance period being 1 April 2026. The awards

will be aligned with the vesting schedules of her foregone awards and have an expected value of £1.8 million.

---

| | | | | |
|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |  |  |  | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
| ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) | **Buy-out awards**  | Estimated value<sup>a</sup> | Vesting date | ![WarmGrey2-50-TopRoundCorner.gif](bp-20251231_g13.gif) |
|  | **Cash awards**  | **Cash awards**  | **Cash awards**  |  |
|  | Replacement cash award | £1.7m<sup>b</sup> | Paid upon joining<sup>c</sup> |  |
|  | **Restricted share awards** |  |  |  |
|  | Tranche 1 | £0.5m | April 2027 |  |
|  | Tranche 2  | £1.0m | May 2027 |  |
|  | Tranche 3 | £0.4m | March 2028 |  |
|  | Tranche 4 | £1.5m | April 2028 |  |
|  | Tranche 5 | £0.9m | March 2029 |  |
|  | Tranche 6 | £0.8m | April 2029 |  |
|  | Tranche 7 | £1.8m | March 2030 |  |
|  | Tranche 8 | £1.4m | March 2031 |  |
|  | **Performance share awards** (expected value, subject to TSR performance) |  |  |  |
|  | Tranche 1 | £0.4m | April 2029 |  |
|  | Tranche 2 | £0.7m | March 2030 |  |
|  | Tranche 3 | £0.7m | March 2031 |  |
|  | a Estimated value is based on an illustrative share price of £12.50 for Woodside Energy and exchange rate of 1:0.5 (AUD:GBP). Performance share awards have been shown at target (i.e. 50% of max). <br>b Estimated value of the 2026 annual bonus (pro-rated to 31 March 2026) not included as value is currently unknown.<br>c Or, if later, following the date the award from the previous employer would have been paid. | a Estimated value is based on an illustrative share price of £12.50 for Woodside Energy and exchange rate of 1:0.5 (AUD:GBP). Performance share awards have been shown at target (i.e. 50% of max). <br>b Estimated value of the 2026 annual bonus (pro-rated to 31 March 2026) not included as value is currently unknown.<br>c Or, if later, following the date the award from the previous employer would have been paid. | a Estimated value is based on an illustrative share price of £12.50 for Woodside Energy and exchange rate of 1:0.5 (AUD:GBP). Performance share awards have been shown at target (i.e. 50% of max). <br>b Estimated value of the 2026 annual bonus (pro-rated to 31 March 2026) not included as value is currently unknown.<br>c Or, if later, following the date the award from the previous employer would have been paid. |  |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) | a Estimated value is based on an illustrative share price of £12.50 for Woodside Energy and exchange rate of 1:0.5 (AUD:GBP). Performance share awards have been shown at target (i.e. 50% of max). <br>b Estimated value of the 2026 annual bonus (pro-rated to 31 March 2026) not included as value is currently unknown.<br>c Or, if later, following the date the award from the previous employer would have been paid. | a Estimated value is based on an illustrative share price of £12.50 for Woodside Energy and exchange rate of 1:0.5 (AUD:GBP). Performance share awards have been shown at target (i.e. 50% of max). <br>b Estimated value of the 2026 annual bonus (pro-rated to 31 March 2026) not included as value is currently unknown.<br>c Or, if later, following the date the award from the previous employer would have been paid. | a Estimated value is based on an illustrative share price of £12.50 for Woodside Energy and exchange rate of 1:0.5 (AUD:GBP). Performance share awards have been shown at target (i.e. 50% of max). <br>b Estimated value of the 2026 annual bonus (pro-rated to 31 March 2026) not included as value is currently unknown.<br>c Or, if later, following the date the award from the previous employer would have been paid. | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |
| ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |  |  |  | ![WarmGrey2-50-BottomRoundCorner.gif](bp-20251231_g14.gif) |

---

Where awards are being replaced with shares, this will be calculated using the 90-day average of bp's and Woodside Energy's share prices, and

foreign exchange rate, prior to 1 April 2026.

A significant proportion of the buy-outs will be delivered in shares (over 85%), aligning Meg with shareholders from appointment and representing a

value equivalent to 6.3x of salary over a 5-year period. In line with the policy, Meg will be expected to retain shares vesting from share awards

(including buy-outs) until her shareholding requirement of 5x salary has been met.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 109 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

**Measures for the 2026 annual bonus**

For 2026, the scorecard has been simplified and performance will now be assessed against four measures across three categories: safety (15%),

operations (20%) and financials (65%). This change reflects our continued focus on delivering sustained financial performance, supported by strong

safety and operational outcomes.

As part of this simplification, the emissions measure has been removed from the short-term scorecard. To maintain appropriate balance, the

weighting of emissions within the long-term incentive award has been increased from 15% to 20% (see below). Our ambition to reach net zero by

2050 remains unchanged, but we believe that progress towards this long-term objective is more appropriately evaluated through our performance

share award rather than the annual bonus.

Across the remaining categories, the underlying measures remain unchanged from prior year. For safety, however, we will revert to assessing

performance on a combined tier 1 and tier 2 basis. In recent years, the number of tier 1 process safety events has continued to decline, which is a

positive trajectory to report. However, the number of events has made it increasingly difficult to set robust and meaningful standalone targets for

tier 1 performance and it is no longer practicable to assess performance independently.

Importantly, the framework on fatalities will continue to apply to the 2026 annual bonus and will be considered at year-end if a fatality occurs

during the year. The targets are commercially sensitive and will be disclosed in the 2026 directors' remuneration report.

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-SMALL-TopRoundCorner.gif](bp-20251231_g182.gif) |  |  |  |  |  |  | ![WarmGrey2-50-SMALL-TopRoundCorner.gif](bp-20251231_g182.gif) |
|  | **Safety**<br>15% | **Safety**<br>15% | **Operations**<br>20% | **Operations**<br>20% | **Financials** <br>65% | **Financials** <br>65% |  |
|  | Measures include | Weighting | Measures include | Weighting | Measures include | Weighting |  |
|  | Tier 1 and tier 2 process safety <br>events★ | 15% | bp-operated reliability and <br>availability★ | 20% | Modified free cash flow<sup>a</sup>★ | 35% |  |
|  | Tier 1 and tier 2 process safety <br>events★ |  | bp-operated reliability and <br>availability★ |  | Structural cost reduction★ | 30% |  |
| ![WarmGrey2-50-SMALL-BottomRoundCorner.gif](bp-20251231_g63.gif) |  |  |  |  |  |  | ![WarmGrey2-50-SMALL-BottomRoundCorner.gif](bp-20251231_g63.gif) |

---

**Measures for the 2026-28 performance shares (EDIP)** 

Provided below is a summary of the measures we have chosen for the 2026-28 performance share plan. The number of measures has been

reduced, with the scorecard now focused on shareholder returns, financial delivery and progress against our external emissions targets.

For relative TSR, the peer group has been reviewed to ensure alignment with the reset strategy. The committee has agreed to reduce the number

of comparator companies, concentrating on the oil super majors who represent our closest and most strategically aligned peers. In light of the

reduced peer group, the committee reviewed the approach to assessing relative TSR performance and agreed to adopt a percentile-based

methodology for the 2026-28 cycle. This approach provides a more proportionate assessment of performance across the peer group and greater

alignment with the shareholder experience.

Within the financials category, the underlying measures remain unchanged. For the 2025–27 cycle, targets were set in line with our external

ambitions to the end of 2027, as outlined at the Capital Markets Day in February 2025. Looking ahead, ROACE★ will revert to being assessed on an

average basis — consistent with past practice — while adjusted free cash flow★ will be assessed based on performance through to the end of 2028.

Lastly, the underpin has been broadened to include progress towards a strong and resilient balance sheet, reflecting our long-term priorities.

---

| | | | | | | | | | | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-SMALL-TopRoundCorner.gif](bp-20251231_g182.gif) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | ![WarmGrey2-50-SMALL-TopRoundCorner.gif](bp-20251231_g182.gif) |
|  | **rTSR** | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | **Financials** | **Financials** | **Financials** | **Financials** | **Financials** | **Financials** |  |  |  | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | **ESG** | **ESG** | **ESG** | **ESG** | **ESG** |  |  |
|  | 30% | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | 25% | 25% | 25% | 25% | 25% | 25% |  | 25% | 25% | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | 20% | 20% | 20% | 20% | 20% |  |  |
|  |  |  | ROACE<br>(average 2026-28)<sup>ce</sup> | ROACE<br>(average 2026-28)<sup>ce</sup> | ROACE<br>(average 2026-28)<sup>ce</sup> | ROACE<br>(average 2026-28)<sup>ce</sup> | ROACE<br>(average 2026-28)<sup>ce</sup> | ROACE<br>(average 2026-28)<sup>ce</sup> | ROACE<br>(average 2026-28)<sup>ce</sup> | Adjusted free cash flow<sup>def</sup> | Adjusted free cash flow<sup>def</sup> | Adjusted free cash flow<sup>def</sup> | Cumulative reduction % in <br>operated carbon emissions<sup>g</sup> | Cumulative reduction % in <br>operated carbon emissions<sup>g</sup> | Cumulative reduction % in <br>operated carbon emissions<sup>g</sup> | Cumulative reduction % in <br>operated carbon emissions<sup>g</sup> | Cumulative reduction % in <br>operated carbon emissions<sup>g</sup> | Cumulative reduction % in <br>operated carbon emissions<sup>g</sup> |  |
|  |  |  | Vesting % for each element | 100% | 100% |  |  |  |  | 100% | 100% |  | 100% | 100% |  |  |  |  |  |
|  |  |  | Vesting % for each element | 75% |  |  |  |  |  | 75% |  |  | 75% |  |  |  |  |  |  |
|  |  |  | Vesting % for each element | 50% |  |  |  |  |  | 50% |  |  | 50% |  |  |  |  |  |  |
|  | Peer group of five companies: <br>Chevron, Eni, ExxonMobil, Shell <br>and TotalEnergies (and bp)<sup>b</sup> | Peer group of five companies: <br>Chevron, Eni, ExxonMobil, Shell <br>and TotalEnergies (and bp)<sup>b</sup> | Vesting % for each element | 25% |  |  |  |  |  | 25% |  |  | 25% |  |  |  |  |  |  |
|  | Peer group of five companies: <br>Chevron, Eni, ExxonMobil, Shell <br>and TotalEnergies (and bp)<sup>b</sup> | Peer group of five companies: <br>Chevron, Eni, ExxonMobil, Shell <br>and TotalEnergies (and bp)<sup>b</sup> | Vesting % for each element | 0% |  |  |  |  |  | 0% |  |  | 0% |  |  |  |  |  |  |
|  | Peer group of five companies: <br>Chevron, Eni, ExxonMobil, Shell <br>and TotalEnergies (and bp)<sup>b</sup> | Peer group of five companies: <br>Chevron, Eni, ExxonMobil, Shell <br>and TotalEnergies (and bp)<sup>b</sup> |  |  | Below <br>13%<br>| 14% | 15% | 16% | Above <br>17%<br>|  | Targets not disclosed | Targets not disclosed |  | Below <br>40%<br>| 42% | 43% | 46% | Above <br>48%<br>|  |
|  | Peer group of five companies: <br>Chevron, Eni, ExxonMobil, Shell <br>and TotalEnergies (and bp)<sup>b</sup> | Peer group of five companies: <br>Chevron, Eni, ExxonMobil, Shell <br>and TotalEnergies (and bp)<sup>b</sup> |  | **ROACE** | **ROACE** | **ROACE** | **ROACE** | **ROACE** | **ROACE** | **Adjusted free cash flow** | **Adjusted free cash flow** | **Adjusted free cash flow** | **Cumulative reduction % in operated** <br>**carbon emissions** | **Cumulative reduction % in operated** <br>**carbon emissions** | **Cumulative reduction % in operated** <br>**carbon emissions** | **Cumulative reduction % in operated** <br>**carbon emissions** | **Cumulative reduction % in operated** <br>**carbon emissions** | **Cumulative reduction % in operated** <br>**carbon emissions** |  |
| ![WarmGrey2-50-SMALL-BottomRoundCorner.gif](bp-20251231_g63.gif) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | ![WarmGrey2-50-SMALL-BottomRoundCorner.gif](bp-20251231_g63.gif) |

---

---

| | |
|:---|:---|
| Rank | Vesting |
| 1<br> 100th %ile | 100% |
| 3<br> 50th %ile | 25% |
| Below median | 0% |

---

![13](bp-20251231_g184.gif)

![25](bp-20251231_g185.gif)

![37](bp-20251231_g185.gif)

• Underpin will take into account overall safety performance as well as ongoing progress towards a strong and resilient balance sheet.

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

• Subject to usual malus and clawback provisions.

aTarget set includes receipt of Castrol proceeds prior to finalization of year-end results.

bStraight-line vesting between median and maximum.

cBased on the average ROACE over 2026, 2027 and 2028.

dBased on adjusted free cash flow at the end of the three-year period.

eAdjustments may be required in certain circumstances. The external environment to be a considered judgement in final outcomes.

f Targets are considered to be commercially sensitive and will be disclosed in full at the end of the performance period.

gScope 1 and 2 GHG emissions reductions vs. 2019 baseline from operated carbon emissions including portfolio change. Corporate activity unknown at the time that targets are set to be a

considered judgement in final outcomes.

---

| | | |
|:---|:---|:---|
| 110 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

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

**Measures for 2025-27 performance shares**

---

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-SMALL-TopRoundCorner.gif](bp-20251231_g182.gif) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | ![WarmGrey2-50-SMALL-TopRoundCorner.gif](bp-20251231_g182.gif) |
|  | **rTSR** | **rTSR** | **rTSR** | **rTSR** | **rTSR** |  |  | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | **Financials** | **Financials** | **Financials** | **Financials** | **Financials** |  |  |  |  |  |  | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | **ESG** | **ESG** | **ESG** | **ESG** | **ESG** | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | **Strategic** <br>**progress** |  |
|  | 25% | 25% | 25% | 25% | 25% |  |  | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | 20% | 20% | 20% | 20% | 20% |  | 20% | 20% | 20% | 20% | 20% | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | 15% | 15% | 15% | 15% | 15% | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | 20% |  |
|  | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | ROACE | ROACE | ROACE | ROACE | ROACE | ROACE | Adjusted free cash flow <br>CAGR★ | Adjusted free cash flow <br>CAGR★ | Adjusted free cash flow <br>CAGR★ | Adjusted free cash flow <br>CAGR★ | Adjusted free cash flow <br>CAGR★ | Adjusted free cash flow <br>CAGR★ | Cumulative reduction % <br>in operated carbon <br>emissions<sup>b</sup> | Cumulative reduction % <br>in operated carbon <br>emissions<sup>b</sup> | Cumulative reduction % <br>in operated carbon <br>emissions<sup>b</sup> | Cumulative reduction % <br>in operated carbon <br>emissions<sup>b</sup> | Cumulative reduction % <br>in operated carbon <br>emissions<sup>b</sup> | Cumulative reduction % <br>in operated carbon <br>emissions<sup>b</sup> | Holistic review of <br>progress against <br>strategy set out in the <br>Capital Markets Update <br>in February 2025. <br>Subject to the <br>remuneration <br>committee's judgement.<br>Consideration may be <br>given to the following <br>measures:<br>•Divestments. <br>•Net debt.<br>•Structural cost <br>reduction.  |  |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | Holistic review of <br>progress against <br>strategy set out in the <br>Capital Markets Update <br>in February 2025. <br>Subject to the <br>remuneration <br>committee's judgement.<br>Consideration may be <br>given to the following <br>measures:<br>•Divestments. <br>•Net debt.<br>•Structural cost <br>reduction.  |  |
|  | Vesting % for each element | 100% |  |  |  |  |  |  |  | 100% | 100% |  |  |  |  | 100% | 100% |  |  |  |  | 100% | 100% |  |  |  |  | Holistic review of <br>progress against <br>strategy set out in the <br>Capital Markets Update <br>in February 2025. <br>Subject to the <br>remuneration <br>committee's judgement.<br>Consideration may be <br>given to the following <br>measures:<br>•Divestments. <br>•Net debt.<br>•Structural cost <br>reduction.  |  |
|  | Vesting % for each element | 75% |  |  |  |  |  |  |  | 75% |  |  |  |  |  | 75% |  |  |  |  |  | 75% |  |  |  |  |  | Holistic review of <br>progress against <br>strategy set out in the <br>Capital Markets Update <br>in February 2025. <br>Subject to the <br>remuneration <br>committee's judgement.<br>Consideration may be <br>given to the following <br>measures:<br>•Divestments. <br>•Net debt.<br>•Structural cost <br>reduction.  |  |
|  | Vesting % for each element | 50% |  |  |  |  |  |  |  | 50% |  |  |  |  |  | 50% |  |  |  |  |  | 50% |  |  |  |  |  | Holistic review of <br>progress against <br>strategy set out in the <br>Capital Markets Update <br>in February 2025. <br>Subject to the <br>remuneration <br>committee's judgement.<br>Consideration may be <br>given to the following <br>measures:<br>•Divestments. <br>•Net debt.<br>•Structural cost <br>reduction.  |  |
|  | Vesting % for each element | 25% |  |  |  |  |  |  |  | 25% |  |  |  |  |  | 25% |  |  |  |  |  | 25% |  |  |  |  |  | Holistic review of <br>progress against <br>strategy set out in the <br>Capital Markets Update <br>in February 2025. <br>Subject to the <br>remuneration <br>committee's judgement.<br>Consideration may be <br>given to the following <br>measures:<br>•Divestments. <br>•Net debt.<br>•Structural cost <br>reduction.  |  |
|  | Vesting % for each element | 0% |  |  |  |  |  |  |  | 0% |  |  |  |  |  | 0% |  |  |  |  |  | 0% |  |  |  |  |  | Holistic review of <br>progress against <br>strategy set out in the <br>Capital Markets Update <br>in February 2025. <br>Subject to the <br>remuneration <br>committee's judgement.<br>Consideration may be <br>given to the following <br>measures:<br>•Divestments. <br>•Net debt.<br>•Structural cost <br>reduction.  |  |
|  |  | 8 | 7 | 6 | 5 | 4 | 3 | 2 | 1 |  | Below <br>14%<br>| 15% | 16% | 17% | Above <br>18%<br>|  | Below <br>15%<br>| 17.5% | 20% | 22.5% | Above <br>25%<br>|  | Below <br>35.5%<br>| 37% | 38.5% | 41% | Above <br>43.5%<br>| Holistic review of <br>progress against <br>strategy set out in the <br>Capital Markets Update <br>in February 2025. <br>Subject to the <br>remuneration <br>committee's judgement.<br>Consideration may be <br>given to the following <br>measures:<br>•Divestments. <br>•Net debt.<br>•Structural cost <br>reduction.  |  |
|  |  | **rTSR ranking** | **rTSR ranking** | **rTSR ranking** | **rTSR ranking** | **rTSR ranking** | **rTSR ranking** | **rTSR ranking** | **rTSR ranking** | **ROACE** | **ROACE** | **ROACE** | **ROACE** | **ROACE** | **ROACE** | **Adjusted free cash flow CAGR** | **Adjusted free cash flow CAGR** | **Adjusted free cash flow CAGR** | **Adjusted free cash flow CAGR** | **Adjusted free cash flow CAGR** | **Adjusted free cash flow CAGR** | **Cumulative reduction % in** <br>**operated carbon emissions**  | **Cumulative reduction % in** <br>**operated carbon emissions**  | **Cumulative reduction % in** <br>**operated carbon emissions**  | **Cumulative reduction % in** <br>**operated carbon emissions**  | **Cumulative reduction % in** <br>**operated carbon emissions**  | **Cumulative reduction % in** <br>**operated carbon emissions**  | Holistic review of <br>progress against <br>strategy set out in the <br>Capital Markets Update <br>in February 2025. <br>Subject to the <br>remuneration <br>committee's judgement.<br>Consideration may be <br>given to the following <br>measures:<br>•Divestments. <br>•Net debt.<br>•Structural cost <br>reduction.  |  |
| ![WarmGrey2-50-SMALL-BottomRoundCorner.gif](bp-20251231_g63.gif) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | ![WarmGrey2-50-SMALL-BottomRoundCorner.gif](bp-20251231_g63.gif) |

---

![85](bp-20251231_g186.gif)

![73](bp-20251231_g187.gif)

![61](bp-20251231_g188.gif)

![49](bp-20251231_g189.gif)

**Measures for 2024-26 performance shares**

---

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| ![WarmGrey2-50-SMALL-TopRoundCorner.gif](bp-20251231_g182.gif) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | ![WarmGrey2-50-SMALL-TopRoundCorner.gif](bp-20251231_g182.gif) |
|  | **rTSR** | **rTSR** | **rTSR** | **rTSR** | **rTSR** |  |  | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | **Financials** | **Financials** | **Financials** | **Financials** | **Financials** |  |  |  |  |  |  | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | **ESG** | **ESG** | **ESG** | **ESG** | **ESG** | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | **Strategic** <br>**progress** |  |
|  | 25% | 25% | 25% | 25% | 25% |  |  | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | 20% | 20% | 20% | 20% | 20% |  | 20% | 20% | 20% | 20% | 20% | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | 15% | 15% | 15% | 15% | 15% | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | 20% |  |
|  | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | Peer group of seven <br>companies<sup>a</sup> | ROACE<br>(average 2024-26) | ROACE<br>(average 2024-26) | ROACE<br>(average 2024-26) | ROACE<br>(average 2024-26) | ROACE<br>(average 2024-26) | ROACE<br>(average 2024-26) | Adjusted EBIDA per <br>share CAGR★ | Adjusted EBIDA per <br>share CAGR★ | Adjusted EBIDA per <br>share CAGR★ | Adjusted EBIDA per <br>share CAGR★ | Adjusted EBIDA per <br>share CAGR★ | Adjusted EBIDA per <br>share CAGR★ | Cumulative reduction % <br>in operated carbon <br>emissions<sup>b</sup> | Cumulative reduction % <br>in operated carbon <br>emissions<sup>b</sup> | Cumulative reduction % <br>in operated carbon <br>emissions<sup>b</sup> | Cumulative reduction % <br>in operated carbon <br>emissions<sup>b</sup> | Cumulative reduction % <br>in operated carbon <br>emissions<sup>b</sup> | Cumulative reduction % <br>in operated carbon <br>emissions<sup>b</sup> | Subject to remuneration <br>committee judgement. <br>Following the Capital <br>Markets Update in <br>February 2025, <br>judgement of strategic <br>progress will adopt the <br>same frame as set out <br>for the 2025-27 cycle.  |  |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | Subject to remuneration <br>committee judgement. <br>Following the Capital <br>Markets Update in <br>February 2025, <br>judgement of strategic <br>progress will adopt the <br>same frame as set out <br>for the 2025-27 cycle.  |  |
|  | Vesting % for each element | 100% |  |  |  |  |  |  |  | 100% | 100% |  |  |  |  | 100% | 100% |  |  |  |  | 100% | 100% |  |  |  |  | Subject to remuneration <br>committee judgement. <br>Following the Capital <br>Markets Update in <br>February 2025, <br>judgement of strategic <br>progress will adopt the <br>same frame as set out <br>for the 2025-27 cycle.  |  |
|  | Vesting % for each element | 75% |  |  |  |  |  |  |  | 75% |  |  |  |  |  | 75% |  |  |  |  |  | 75% |  |  |  |  |  | Subject to remuneration <br>committee judgement. <br>Following the Capital <br>Markets Update in <br>February 2025, <br>judgement of strategic <br>progress will adopt the <br>same frame as set out <br>for the 2025-27 cycle.  |  |
|  | Vesting % for each element | 50% |  |  |  |  |  |  |  | 50% |  |  |  |  |  | 50% |  |  |  |  |  | 50% |  |  |  |  |  | Subject to remuneration <br>committee judgement. <br>Following the Capital <br>Markets Update in <br>February 2025, <br>judgement of strategic <br>progress will adopt the <br>same frame as set out <br>for the 2025-27 cycle.  |  |
|  | Vesting % for each element | 25% |  |  |  |  |  |  |  | 25% |  |  |  |  |  | 25% |  |  |  |  |  | 25% |  |  |  |  |  | Subject to remuneration <br>committee judgement. <br>Following the Capital <br>Markets Update in <br>February 2025, <br>judgement of strategic <br>progress will adopt the <br>same frame as set out <br>for the 2025-27 cycle.  |  |
|  | Vesting % for each element | 0% |  |  |  |  |  |  |  | 0% |  |  |  |  |  | 0% |  |  |  |  |  | 0% |  |  |  |  |  | Subject to remuneration <br>committee judgement. <br>Following the Capital <br>Markets Update in <br>February 2025, <br>judgement of strategic <br>progress will adopt the <br>same frame as set out <br>for the 2025-27 cycle.  |  |
|  |  | 8 | 7 | 6 | 5 | 4 | 3 | 2 | 1 |  | Below <br>15.7%<br>| 16.2% | 16.7% | 17.2% | Above <br>17.7%<br>|  | Below <br>9.3%<br>| 9.8% | 10.3% | 10.8% | Above <br>11.3%<br>|  | Below <br>36%<br>| 38% | 39% | 42% | Above <br>44%<br>| Subject to remuneration <br>committee judgement. <br>Following the Capital <br>Markets Update in <br>February 2025, <br>judgement of strategic <br>progress will adopt the <br>same frame as set out <br>for the 2025-27 cycle.  |  |
|  |  | **rTSR ranking** | **rTSR ranking** | **rTSR ranking** | **rTSR ranking** | **rTSR ranking** | **rTSR ranking** | **rTSR ranking** | **rTSR ranking** | **ROACE** | **ROACE** | **ROACE** | **ROACE** | **ROACE** | **ROACE** | **Adjusted EBIDA per share** <br>**CAGR** | **Adjusted EBIDA per share** <br>**CAGR** | **Adjusted EBIDA per share** <br>**CAGR** | **Adjusted EBIDA per share** <br>**CAGR** | **Adjusted EBIDA per share** <br>**CAGR** | **Adjusted EBIDA per share** <br>**CAGR** | **Cumulative reduction % in** <br>**operated carbon emissions** | **Cumulative reduction % in** <br>**operated carbon emissions** | **Cumulative reduction % in** <br>**operated carbon emissions** | **Cumulative reduction % in** <br>**operated carbon emissions** | **Cumulative reduction % in** <br>**operated carbon emissions** | **Cumulative reduction % in** <br>**operated carbon emissions** | Subject to remuneration <br>committee judgement. <br>Following the Capital <br>Markets Update in <br>February 2025, <br>judgement of strategic <br>progress will adopt the <br>same frame as set out <br>for the 2025-27 cycle.  |  |
| ![WarmGrey2-50-SMALL-BottomRoundCorner.gif](bp-20251231_g63.gif) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | ![WarmGrey2-50-SMALL-BottomRoundCorner.gif](bp-20251231_g63.gif) |

---

![109](bp-20251231_g190.gif)

![97](bp-20251231_g191.gif)

![121](bp-20251231_g192.gif)

![133](bp-20251231_g192.gif)

aPeer group includes Chevron, Eni, Equinor, ExxonMobil, Repsol, Shell and TotalEnergies (and bp).

bThe committee determined that the operated carbon emissions targets under the above EDIP awards should be adjusted in order to align with the strategy reset at the start of 2025 (2024-26

only) and subsequent recalibration of internal goals and principles around emissions (2024-26 and 2025-27). The effect of this change, which was made in conjunction with the safety and

sustainability committee, is to widen the target range by reducing the threshold and increasing the maximum under both awards.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 111 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

**Stewardship and executive director interests**

We believe that our executive directors should build and maintain a meaningful interest in the company. Our policy therefore requires the CEO and

CFO to build a personal shareholding of five times and four and a half times, respectively, their salary within five years of their appointment. They

are expected to maintain this level of personal shareholdings for two years post-employment.

**Directors' shareholdings and aggregated interests (audited)**

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | Directors' <br>ordinary shares <br>or equivalents <br>at 13 February <br>2026 | Aggregated interests at 13 February 2026, all plans | Aggregated interests at 13 February 2026, all plans | Aggregated interests at 13 February 2026, all plans | Aggregated interests at 13 February 2026, all plans | Current <br>shareholding <br>for MSR<sup>b,d</sup> | Value of current <br>shareholding<sup>c,d</sup> £ | Multiple of <br>salary <br>achieved<sup>d</sup> |
|  | Directors' <br>ordinary shares <br>or equivalents <br>at 13 February <br>2026 | Unvested awards not subject <br>to performance conditions | Unvested awards not subject <br>to performance conditions | Unvested awards subject to <br>performance conditions | Unvested awards subject to <br>performance conditions | Current <br>shareholding <br>for MSR<sup>b,d</sup> | Value of current <br>shareholding<sup>c,d</sup> £ | Multiple of <br>salary <br>achieved<sup>d</sup> |
|  | Directors' <br>ordinary shares <br>or equivalents <br>at 13 February <br>2026 | Shares<sup>a</sup> | Options | Shares | Options | Current <br>shareholding <br>for MSR<sup>b,d</sup> | Value of current <br>shareholding<sup>c,d</sup> £ | Multiple of <br>salary <br>achieved<sup>d</sup> |
| Carol Howle | 491903 | 1040861 | 750000 | 381825 |  | 1047640 | 4829622 | 3.20 |
| Murray Auchincloss<sup>d</sup> | 1816006 | 1094742 | 152301 | 3273590 |  | 2104355 | 8847761 | 5.87 |
| Kate Thomson  | 432482 | 219236 | 500000 | 1659711 |  | 550831 | 2539331 | 2.94 |

---

aIncludes deferred and restricted shares, and performance shares prior to application of the performance factor.

bIncludes ordinary shares or equivalents and unvested awards not subject to performance conditions on a net-of-tax basis, excluding dividends.

cBased on ordinary share price at 13 February 2026 of £4.61 (close price).

dMurray Auchincloss stepped down on 18 December 2025. The shareholding disclosed reflects his individual holding and includes interests of a person closely associated with him as at that date.

The shareholding for MSR purposes, the value of his shareholding and multiple of salary achieved are each presented as at 18 December 2025. In accordance with the plan rules, his unvested

performance share awards will be pro-rated to 17 December 2026.

Executive directors have additional interests in performance and deferred bonus shares. These interests are shown in aggregate in the table above,

and interests awarded during 2025 in the tables below. For performance shares, the figures reflect maximum possible vesting levels (excluding the

addition of reinvested dividends) even though the actual number of shares that vest will depend on the extent to which performance conditions

are satisfied.

**Performance and deferred shares (audited)**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  | Award | Number of <br>shares <br>granted<br>| Grant date | Face value of <br>the award<sup>a</sup>, £<br>| Vesting date |
| Carol Howle<sup>b</sup> | 2025-27 EDIP Performance<sup>c</sup> |  |  |  |  |
| Murray Auchincloss<sup>b</sup> | 2025-27 EDIP Performance<sup>c</sup> | 1790973 | 30 April 2025 | 6268406 | April 2028 |
| Kate Thomson | 2025-27 EDIP Performance<sup>c</sup> | 923515 | 30 April 2025 | 3232303 | April 2028 |
| Carol Howle<sup>b</sup> | 2025 EDIP Deferred<sup>d</sup> |  |  |  |  |
| Murray Auchincloss<sup>b</sup> | 2025 EDIP Deferred<sup>d</sup> | 59840 | 30 April 2025 | 209440 | April 2028 |
| Kate Thomson | 2025 EDIP Deferred<sup>d</sup> | 51947 | 30 April 2025 | 181815 | April 2028 |

---

aThe face value of awards granted during 2025 have been calculated using a market price of ordinary shares at close on the date of award, as follows: £3.50 on 30 April 2025. In calculating the

number of ordinary shares over which these awards were made, the committee applied the average price of ordinary shares over the 90 calendar days up to and including the annual general

meeting held on 17 April 2025 (£4.21).

bMurray Auchincloss stepped down as CEO effective 18 December 2025 and Carol Howle was appointed as interim CEO on the same date. As Carol was a below board employee when her

2025-27 GSVP award was granted, detail of this award has not been disclosed as it is considered to be commercially sensitive.

cPerformance conditions are measured 15% on cumulative reduction % in operated carbon emissions, 25% on TSR relative to Chevron, ExxonMobil, Shell, TotalEnergies, Eni, Equinor and Repsol

over three years, 20% ROACE measured to the end of 2027, 20% adjusted free cash flow CAGR vs. 2024 baseline and 20% strategic progress assessed over the performance period. Minimum

vesting under this award (below threshold performance) is 0%. At threshold performance, vesting would be 6.25% of maximum.

Since 2010, vesting of the performance shares under EDIP has been subject to a safety underpin. If the committee assesses that there has been a material deterioration in safety performance,

or there have been major incidents, either of which reveal underlying weaknesses in safety management, then it may conclude that shares should vest only in part, or not at all. In reaching its

conclusion, the committee obtains advice from the S&SC.

The performance period is 1 January 2025 to 31 December 2027.

The 2026 performance share awards under EDIP are expected to be made following the conclusion of the 2026 annual general meeting.

dThere is no identified minimum vesting threshold level. The 2025 bonus year deferred share awards under EDIP are expected to be made following the conclusion of the 2026 annual

general meeting.

**Directors and leadership team**

No directors or other leadership team members own more than 1% of the shares in issue. At 13 February 2026, our directors and leadership team

members collectively held interests of 5,127,004 ordinary shares or their calculated equivalents, 3,840,510 restricted share units (with or without

conditions) or their calculated equivalents, 4,964,919 performance shares or their calculated equivalents and 4,027,241 options over ordinary shares

or their calculated equivalents, under bp group share option schemes.

---

| | | |
|:---|:---|:---|
| 112 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

**Chair and non-executive director interests**

**Fee structure**

The table below shows the fee structure for the chair and non-executive directors (NEDs). The chair is not eligible for committee chairship and

membership fees. The senior independent director (SID) is eligible for committee chairship and membership fees, and their fee includes the board

member fee. Committee chairs do not receive a membership fee for the committee they chair.

Under the 2023 policy, fee levels are reviewed annually alongside wider workforce salaries with any changes taking effect from 1 April. For the

2026-27 year, no changes are being made to the base fee for NEDs and for the SID. In accordance with the policy, the remuneration committee is

responsible for determining the chair's fee. Following the appointment of Albert Manifold as chair on 1 September 2025, the committee approved

his fees and benefits at that time. No further changes to the chair's fee are being made for 2026-27.

---

| | | |
|:---|:---|:---|
| **£ thousand per annum** | **2026/27 fees** | 2025/26 fees |
| Chair | **1000** | 888 |
| Senior independent director | **181.5** | 181.5 |
| Board member | **130.5** | 130.5 |
| Audit, remuneration and safety and sustainability committees chairship | **35** | 35 |
| Committee membership | **20** | 20 |

---

**2025 remuneration (audited)**

The table below shows the fees paid and applicable benefits. Benefits include travel and other expenses relating to the attendance at board and

other meetings. Under the terms of his engagement with the company, Albert Manifold has the use of a fully maintained office for company

business, a car and driver, and security advice in London. Benefits values have been grossed up using a tax rate of 45%, where relevant, as an

estimation of tax due.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | Fees | Fees | Benefits | Benefits | Total | Total |
| **£ thousand** | **2025** | 2024 | **2025** | 2024 | **2025** | 2024 |
| Dame Amanda Blanc | **220** | 198 | **—** | 1 | **220** | 198 |
| Pamela Daley<sup>a</sup> | **87** | 164 | **5** | 17 | **93** | 181 |
| Dave Hager<sup>b</sup> | **78** |  | **37** |  | **114** |  |
| Simon Henry<sup>c</sup> | **44** |  | **1** |  | **44** |  |
| Helge Lund<sup>d</sup>  | **658** | 845 | **28** | 38 | **686** | 882 |
| Albert Manifold (chair)<sup>d</sup> | **333** |  | **50** |  | **384** |  |
| Melody Meyer | **184** | 182 | **56** | 9 | **240** | 191 |
| Tushar Morzaria | **189** | 189 | **32** | 1 | **221** | 190 |
| Hina Nagarajan | **169** | 157 | **39** | 17 | **208** | 174 |
| Satish Pai | **149** | 144 | **5** | 5 | **154** | 149 |
| Karen Richardson<sup>e</sup> | **194** | 169 | **15** | 16 | **209** | 185 |
| Dr Johannes Teyssen | **169** | 160 | **6** | 5 | **175** | 165 |
| Ian Tyler<sup>f</sup> | **135** |  | **34** |  | **169** |  |

---

aPamela Daley stepped down as a non-executive director on 7 July 2025.

bDave Hager was appointed as a non-executive director on 2 June 2025.

cSimon Henry was appointed as a non-executive director on 1 September 2025.

dAlbert Manifold was appointed as a non-executive director and chair-elect on 1 September 2025, and assumed the role of chair on 1 October 2025, succeeding Helge Lund, who stepped down as

chair on 30 September 2025.

eFee includes £25,000 p.a. for chairing the bp digital advisory council and £20,000 p.a. for chairing innovation advisory council.

fIan Tyler was appointed as a non-executive director on 1 April 2025.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 113 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

**Chair and non-executive directors' interests (audited)**

The figures below include all the interests of the chair and each NED of the company in shares of bp (or calculated equivalents) that have been

disclosed to bp. Our 2023 policy encourages NEDs to establish a holding in bp shares of the equivalent value of one year's base fee during their

tenure.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | Ordinary shares or equivalents<sup>a</sup> | Ordinary shares or equivalents<sup>a</sup> | Ordinary shares or equivalents<sup>a</sup> | Ordinary shares or equivalents<sup>a</sup> |  |  |
|  | At <br>1 January <br>2025<br>| At <br>31 December <br>2025<br>| Changes to <br>13 February <br>2026<br>| At <br>13 February <br>2026<br>| Value of current <br>shareholding<sup>b</sup><br>| % of guideline <br>achieved<br>|
| Dame Amanda Blanc | 23500 | 47100 |  | 47100 | £217,131 | 166% |
| Pamela Daley<sup>c</sup> | 40332 | n/a | n/a | n/a | n/a | n/a |
| Dave Hager<sup>d</sup> | n/a | 45000 |  | 45000 | $282450 | 164% |
| Simon Henry<sup>e</sup> | n/a |  |  |  |  | —% |
| Helge Lund<sup>f</sup>  | 600000 | n/a | n/a | n/a | n/a | n/a |
| Albert Manifold (chair)<sup>f</sup> | n/a |  |  |  |  | —% |
| Melody Meyer | 38646 | 38646 |  | 38646 | $242568 | 141% |
| Tushar Morzaria | 71972 | 71972 |  | 71972 | £331,791 | 254% |
| Hina Nagarajan | 25944 | 30944 |  | 30944 | £142,652 | 109% |
| Satish Pai | 33000 | 33000 |  | 33000 | $207130 | 120% |
| Karen Richardson | 35316 | 35316 |  | 35316 | $221667 | 129% |
| Dr Johannes Teyssen | 35000 | 35000 |  | 35000 | £161,350 | 124% |
| Ian Tyler<sup>g</sup> | n/a |  |  |  |  | —% |

---

aIncludes interests of persons closely associated.

bBased on ordinary share and ADS prices at 13 February 2026 of £4.61 and $37.66. Where a US$ value is provided these shares are held as ADSs.

cPamela Daley stepped down as a non-executive director on 7 July 2025.

dDave Hager was appointed as a non-executive director on 2 June 2025.

eSimon Henry was appointed as a non-executive director on 1 September 2025.

fAlbert Manifold was appointed as a non-executive director and chair-elect on 1 September 2025, and assumed the role of chair on 1 October 2025, succeeding Helge Lund, who stepped down as

chair on 30 September 2025.

gIan Tyler was appointed as a non-executive director on 1 April 2025.

**Payments to past directors and for loss of office** 

**Departure terms for Murray Auchincloss (audited)**

As set out elsewhere in the report, Murray Auchincloss stepped down from the board by mutual agreement on 18 December 2025. Details of his

departure terms have been set out below and are consistent with the company's shareholder-approved policy.

In line with his 12-month notice period, Murray will remain an employee on his existing terms until 17 December 2026. During this period, he will

continue to receive his contractual salary and benefits.

In respect of his incentive awards, Murray will remain eligible to receive a pro-rata annual bonus in respect of his services during 2025, of which

33% will be deferred into bp shares in line with the policy. He will not be entitled to a bonus in respect of 2026. Outstanding deferred bonus awards

will vest in line with normal timescales.

Murray's unvested performance share awards under the EDIP will be pro-rated up to 17 December 2026 but will continue to vest on their normal

dates subject to the achievement of the relevant performance conditions. The resulting shares are subject to a 12-month holding period following

vesting. Vested shares already in a holding period will be released 12 months following his cessation of employment, i.e. 17 December 2027, or on

their original release date, if earlier. He will not be eligible for a 2026 EDIP grant.

He is entitled to receive ongoing tax filing support in respect of any trailing income from the company and a contribution towards his legal fees

incurred in connection with stepping down to the total of £10,000 (plus VAT). He will continue to be covered by D&O insurance and will benefit from

an indemnity in respect of third-party liabilities.

**Post-employment benefits (audited)**

We made no payments within the scope of the disclosure requirements to any past director of bp during 2025.

---

| | | |
|:---|:---|:---|
| 114 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

**Other disclosures**

---

| | | | | | | | | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| **Historical TSR performance** | **Historical TSR performance** | **Historical TSR performance** | **Historical TSR performance** | **Historical TSR performance** | **Historical TSR performance** | **Historical TSR performance** | **Historical TSR performance** | **Historical TSR performance** | **Historical TSR performance** | **Historical TSR performance** | **Historical TSR performance** | **Relative importance of spend on pay ($ million)** | **Relative importance of spend on pay ($ million)** | **Relative importance of spend on pay ($ million)** | **Relative importance of spend on pay ($ million)** | **Relative importance of spend on pay ($ million)** | **Relative importance of spend on pay ($ million)** |
| £250 |  |  |  |  |  |  |  |  |  |  |  | Distribution to <br>bp shareholders | Distribution to <br>bp shareholders | Remuneration paid <br>to all employees | Remuneration paid <br>to all employees | Capital<br>investment<sup>a</sup> | Capital<br>investment<sup>a</sup> |
| £250 |  |  |  |  |  |  |  |  |  |  |  | Distribution to <br>bp shareholders | Distribution to <br>bp shareholders | Remuneration paid <br>to all employees | Remuneration paid <br>to all employees | Capital<br>investment<sup>a</sup> | Capital<br>investment<sup>a</sup> |
| £200 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| £150 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| £100 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| £50 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| £0 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | 2024 | **2025** | 2024 | **2025** | 2024 | **2025** |
| &nbsp;&nbsp;&nbsp;&nbsp;BP FTSE 100![ChartKeyLozengeGreen.jpg](bp-20251231_g29.jpg)<br>![ChartKeyLozengesWarmGrey3.gif](bp-20251231_g123.gif) | &nbsp;&nbsp;&nbsp;&nbsp;BP FTSE 100![ChartKeyLozengeGreen.jpg](bp-20251231_g29.jpg)<br>![ChartKeyLozengesWarmGrey3.gif](bp-20251231_g123.gif) | &nbsp;&nbsp;&nbsp;&nbsp;BP FTSE 100![ChartKeyLozengeGreen.jpg](bp-20251231_g29.jpg)<br>![ChartKeyLozengesWarmGrey3.gif](bp-20251231_g123.gif) | &nbsp;&nbsp;&nbsp;&nbsp;BP FTSE 100![ChartKeyLozengeGreen.jpg](bp-20251231_g29.jpg)<br>![ChartKeyLozengesWarmGrey3.gif](bp-20251231_g123.gif) |  |  |  |  |  |  |  |  | a Organic capital expenditure★. | a Organic capital expenditure★. | a Organic capital expenditure★. | a Organic capital expenditure★. |  |  |

---

![1](bp-20251231_g193.gif)

![13](bp-20251231_g194.gif)

![37](bp-20251231_g195.gif)

![25](bp-20251231_g196.gif)

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

constituent), over 10 years from 31 December 2015 to 31 December 2025.

**History of chief executive officer remuneration**

---

| | | | | |
|:---|:---|:---|:---|:---|
| Year | Chief executive officer | Total remuneration, <br>thousand<br>| Annual bonus % <br>of maximum<br>| Performance shares % <br>of maximum<br>|
| 2016 | Bob Dudley | $11904 | 61 | 40 |
| 2017 | Bob Dudley | $15108 | 71.5 | 70 |
| 2018 | Bob Dudley | $15253 | 40.5 | 80 |
| 2019 | Bob Dudley | $13234 | 67.5 | 71.2 |
| 2020<sup>a</sup> | 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<sup>ab</sup> | Bernard Looney | £1,175 | n/a | n/a |
|  | Murray Auchincloss | £5,391 | 79.5 | 75 |
| 2024 | Murray Auchincloss  | £5,179 | 22.5 | 66.5 |
| **2025**<sup>acd</sup> | **Murray Auchincloss**  | **£5,307** | **79.5** | **23.3** |
|  | **Carol Howle**  | **£886** | **79.5** | **52.8** |

---

a2020, 2023 and 2025 figures show remuneration for the periods of qualifying service as CEO during the respective years.

bIn respect of 2023, Bernard Looney did not receive any variable pay awards and his single figure shown in the table above excludes the impact of malus and clawback.

cMurray Auchincloss stepped down from his position as CEO on 18 December 2025 and was succeeded by Carol Howle as interim CEO on 18 December 2025. For 2025, Carol's performance share

award was granted when she was below board level and is therefore based on a different scorecard to executive directors.

dShare price has been based on the average share price over Q4 of the 2025 FY of £4.40.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 115 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

**Chief executive officer to employee pay ratio**

---

| | | | | |
|:---|:---|:---|:---|:---|
| Year | Method | 25th percentile:<br>pay ratio,<br>total pay and benefits, <br>(salary)<br>| 50th percentile:<br>pay ratio,<br>total pay and benefits, <br>(salary)<br>| 75th percentile:<br> pay ratio, <br>total pay and benefits, <br>(salary)<br>|
| 2019<sup>a</sup> | Option A | 543:1 | 188:1 | 82:1 |
| 2020<sup>a</sup> | 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<sup>b</sup> | Option A | 268:1 | 103:1 | 45:1 |
| 2024 | Option A | 196:1 | 74:1 | 37:1 |
| 2025<sup>bc</sup> | **Option A**  | **219:1** | **79:1** | **39:1** |
|  |  | **£28,331** | **£78,644** | **£160,265** |
|  |  | **(£26,237)** | **(£55,675)** | **(£97,425)** |

---

aBob Dudley's pay has been converted from US dollars as per the ratios reported in the *bp Annual Report and Form 20-F 2020*.

bFor 2023 and 2025, the total single figure used to derive the CEO pay ratio is a combination of the two individuals in position of CEO during the year. For 2023, in respect of the former CEO, the

calculation has been based on the total single figure excluding the impact of malus and clawback in order to provide a comparison with prior years. Appropriate pro-rating of fixed and variable

pay has been applied.

cShare price for the CEO share plan vesting has been based on the average share price over Q4 of the 2025 FY of £4.40.

This is our seventh year reporting the CEO pay ratio following the requirements introduced in 2018. As per the past six years, we have selected

Option A as our reporting basis, being the most accurate approach available, and we confirm that no broadly applicable components of pay have

been omitted. Where necessary, full-time equivalent pay has been calculated by simple engrossment of part-year values. Employee values relate to

pay and benefits for the year ended 31 December 2025.

Changes in the pay ratio over time reflect the fact that CEO remuneration is more heavily weighted to variable pay, resulting in larger year-on-year

swings than wider workforce pay. This is evidenced by the variability of the CEO pay ratio over the past seven years. This volatility in the pay ratio

reporting from year to year is expected, and illustrates one of the challenges in commenting on whether the pay differentials are appropriate. In

2025, the pay ratios have remained broadly consistent year-on-year, with the 50th percentile pay ratio increasing from 74:1 to 79:1. While the annual

bonus was higher in 2025 (79.5% compared to 22.5% in 2024), this was partly offset by a significantly lower EDIP outcome for the former CEO

(23.3% compared to 66.5% for the 2022-24 cycle).

The committee believes in performance-based remuneration. For all employees eligible to participate in the annual cash bonus plan, there is an

individual uplift available each year which allows managers to nominate exceptional individuals based on their personal contributions during the

year. For senior leaders, a significant portion of the remuneration package continues to be linked to performance-based reward. It is therefore the

view of the committee that the remuneration frameworks we have in place for executive directors and the wider workforce are fit for purpose and

deliver pay outcomes appropriate to the circumstances of the year, with differentials that reflect the relative contributions made at different levels

of the organization.

The committee is satisfied that the median pay ratio reported this year is consistent with bp's pay policies for employees and does not constitute a

reason to modify our pay programmes.

---

| | | |
|:---|:---|:---|
| 116 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

**Percentage change comparisons: directors' remuneration versus employees**

In the table below, values in column 'a' represent the percentage change in salary and fees; values in column 'b' represent the percentage change in

taxable benefits; and values in column 'c' represent the percentage change in bonus outcomes for performance periods in respect of each financial

year. For the purposes of comparison, the employee percentages shown below represent the relative change between the median full-time

equivalent pay for every employee employed at BP p.l.c. at any point during the relevant financial year, and the equivalent median value for the

preceding financial year. Where increases are infinite relative to the preceding year, we have shown them as 100% for illustration; where a director

was appointed or retired part-way through the year, we have annualized pay except for one-time items; and where comparison to the prior year is

not possible, we have used dashes.

---

| | | | | | | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | 2025 vs. 2024 | 2025 vs. 2024 | 2025 vs. 2024 | 2024 vs. 2023 | 2024 vs. 2023 | 2024 vs. 2023 | 2023 vs. 2022 | 2023 vs. 2022 | 2023 vs. 2022 | 2022 vs. 2021 | 2022 vs. 2021 | 2022 vs. 2021 | 2021 vs. 2020 | 2021 vs. 2020 | 2021 vs. 2020 |
| Percentage change <br>for:<br>| a | b | c | a | b | c | a | b | c | a | b | c | a | b | c |
| Employees | 6% | —% | 124% | 4% | —% | -65% | 6% | 1% | 4% | 2% | 1% | 45% | 7% | -9% | 100% |
| Carol Howle |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Murray Auchincloss | -1% | 5% | 253% | 43% | -61% | -60% | 30% | 283% | 31% | 7% | 530% | 3% | 5% | 5% | 100% |
| Kate Thomson<sup>a</sup> | 16% | 23% | 318% | —% |  |  |  |  |  |  |  |  |  |  |  |
| Dame Amanda Blanc | 11% | (89)% | n/a | 24% | -72% | n/a | 38% | 100% | n/a |  |  | n/a |  |  | n/a |
| Pamela Daley | 3% | (68)% | n/a | 3% | -75% | n/a | 2% | 2% | n/a | 7% | 43% | n/a | 4% | 1385% | n/a |
| Dave Hager |  |  | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a |
| Simon Henry |  |  | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a |
| Helge Lund  | 4% | (25)% | n/a | 4% | -43% | n/a | 3% | 78% | n/a | —% | 97% | n/a | —% | -24% | n/a |
| Albert Manifold (Chair) |  |  | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a |
| Melody Meyer | 1% | 512% | n/a | -1% | -68% | n/a | 2% | -14% | n/a | 13% | 139% | n/a | -4% | 283% | n/a |
| Tushar Morzaria |  | 3,559% | n/a | 9% | -73% | n/a | 2% | -46% | n/a | 25% | 100% | n/a | 5% | —% | n/a |
| Hina Nagarajan | 8% | 129% | n/a | 13% | -46% | n/a |  |  | n/a |  |  | n/a |  |  | n/a |
| Satish Pai | 4% | 11% | n/a | 3% | -88% | n/a |  |  | n/a |  |  | n/a |  |  | n/a |
| Paula Rosput Reynolds | (100)% | (100)% | n/a | 3% | -70% | n/a | 2% | -14% | n/a | 16% | 145% | n/a |  | 228% | n/a |
| Karen Richardson | 15% | (6%) | n/a | -5% | -12% | n/a | 11% | -20% | n/a | 30% | 96% | n/a |  |  | n/a |
| Sir John Sawers | (100)% | (100)% | n/a | 3% | 63% | n/a | 2% | 105% | n/a | 17% | 1% | n/a |  | 1588% | n/a |
| Johannes Teyssen | 6% | 14% | n/a | 7% | -68% | n/a | 3% | 12% | n/a | 21% | 65% | n/a |  |  | n/a |
| Ian Tyler | —% | —% | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a | n/a |

---

a Kate Thomson's increase in salary reflects the adjustment from her previous role to the salary level for an Executive Director following her appointment on 2 February 2024.

**Independence and advice**

The board considers all committee members to be independent with no personal financial interest, other than as shareholders, in the committee's

decisions. Further detail on the activities of the committee in 2025 is set out in the remuneration committee report on page <u>[91](#ia422778a52d64a26b1673bf21b127e90_2013)</u>.

During 2025, Ben Mathews, who was employed by the company and reported to the chair of the board, acted as secretary to the remuneration

committee.

The committee also received advice on various matters relating to the remuneration of executive directors and senior management from Kerry

Dryburgh, EVP people, culture & communications, and Ashok Pillai and Clare Peake, SVP reward.

Following a competitive tender process, Willis Towers Watson (WTW) replaced PwC as independent advisors to the committee in 2025. PwC

and WTW advice included, for example, support with remuneration benchmarking and updates on market practice. Both are members of the

Remuneration Consulting Group and, as such, operate under the code of conduct in relation to executive remuneration in the UK. The committee

is satisfied that the advice received is objective and independent. The committee is comfortable that both the PwC and WTW engagement

partners and team who provide remuneration advice to the committee do not have connections with the company or its directors that may

impair their independence.

Total fees or other charges (based on an hourly rate) for the provision of remuneration advice to the committee in 2025 (save in respect of legal

advice) were £67,683 and £64,800 to PwC and WTW respectively. Freshfields LLP (Freshfields) provided legal advice on specific compliance matters

to the committee. PwC, WTW and Freshfields provided other advice in their respective areas to the group.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 117 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

**Shareholder engagement** 

Throughout 2025 the committee engaged regularly on remuneration policy and approach with bp's largest shareholders, as well as their

representative bodies. This dialogue will continue throughout 2026. The table below shows the recent votes on the directors' remuneration report

and policy.

---

| | | | |
|:---|:---|:---|:---|
| **Year** | % vote 'for' | % vote 'against' | Votes withheld |
| 2025 – Directors' remuneration report | 95.54% | 4.46% | 36686921 |
| 2023 – Directors' remuneration policy | 94.23% | 5.77% | 36921641 |

---

**Service contracts and letters of appointment**

The service contracts of executive directors do not have a fixed term. Service contracts for each executive director are available for shareholders to

view upon request at the company's registered office. Each executive director's service contract contains a 12-month notice period. Consistent with

the best interests of the group, the committee will seek to minimize termination payments.

---

| | | |
|:---|:---|:---|
|  | Date of contract | Effective date |
| Carol Howle<sup>a</sup> | 17 December 2025 | 18 December 2025 |
| Murray Auchincloss<sup>a</sup> | 17 January 2024 | 17 January 2024 |
| Kate Thomson | 2 February 2024 | 2 February 2024 |

---

a Murray Auchincloss stepped down as CEO effective 18 December 2025. Carol Howle was appointed interim CEO on the same date.

The non-executive directors (NEDs) have letters of appointment, which are available for shareholders to view upon request at the company's

registered office. All continuing directors are subject to annual re-election by shareholders at the annual general meeting. Normally, NEDs will be

encouraged to serve for up to six years from their appointment, and for a further three years by invitation, in line with the provisions of the 2024

Code, subject to annual re-election.

**External appointments**

The board supports executive directors taking up appointments outside the company to broaden their knowledge and experience. Each executive

director is permitted to retain any fee from their external appointments. Such external appointments are subject to agreement by the chair and

reported to the board. Any external appointment must not conflict with a director's duties and commitments to bp. Details of appointments as

NEDs of publicly listed companies during 2025 are shown below.

---

| | | | |
|:---|:---|:---|:---|
|  | Appointee <br>company<br>| Additional position held at <br>appointee company<br>| Total fees, £ |
| Kate Thomson | Aker BP ASA<sup>a</sup> | Director | 0 |

---

aHeld as a result of the company's shareholding in Aker BP ASA.

This directors' remuneration report, including the 2026 remuneration policy set out on the pages <u>118</u> to <u>125</u>, has been approved by the board and

signed on its behalf by Ben J.S. Mathews, company secretary, on 6 March 2026.

---

| | | |
|:---|:---|:---|
| 118 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

**Directors' remuneration report – the 2026 remuneration policy**

This section of the report sets out the remuneration policy for executive directors and non-executive directors, which shareholders will be asked

to approve at the AGM on 23 April 2026 and, if approved, will take effect for any payments made or awarded after that date. The company will

continue to honour any arrangements granted under previous remuneration policies which were consistent with the policy in force at the time

of grant.

As outlined in the chair's statement, the committee undertook an initial review of the policy during 2025 and agreed to defer a more detailed review

of the policy until after the 2026 AGM. The policy set out on the following pages has therefore largely been rolled forward from the previous policy,

which was approved at the 2023 AGM and received strong support from shareholders with a vote of 94% in favour.

While no material changes are being proposed to the 2026 remuneration policy, minor changes have been made to the wording in certain areas to

increase clarity and effective operation.

**Policy table – executive directors**

---

| | | |
|:---|:---|:---|
| ![DRR_SIngleLozenge_PolicyImp-SalaryBenV2.gif](bp-20251231_g197.gif) | ![DRR_SIngleLozenge_PolicyImp-SalaryBenV2.gif](bp-20251231_g197.gif) |  |
| **Purpose** | To provide fixed remuneration to reflect the scale and complexity of both the business and the role, and to be competitive with <br>the external market. | To provide fixed remuneration to reflect the scale and complexity of both the business and the role, and to be competitive with <br>the external market. |
| **Operation and** <br>**opportunity**<br>| **Salary**<br>Salary levels will relate to the nature of the role, performance <br>of the business and the individual, market positioning and <br>pay conditions in the wider bp group. There is no maximum <br>salary under the policy.<br>When setting salaries, the committee considers practice in <br>other energy majors as well as European and US companies <br>of a similar size, geographic spread and business dynamic to <br>bp. The committee will also consider salary increases for the <br>most senior management and the wider workforce. In <br>particular, percentage increases for executive directors will <br>not exceed increases for the broader employee population, <br>other than in specific circumstances identified by the <br>committee (e.g. in response to a substantial change in <br>responsibilities).<br>Salaries are normally set in the home currency of the <br>executive director and are reviewed annually. They may be <br>reviewed at other times where appropriate, for example <br>following a major role change.<br>| **Benefits**<br>Executive directors are entitled to receive those benefits <br>available to a majority of the wider workforce in their home <br>country. These include participation in all-employee share <br>plans, sickness pay, relocation assistance and parental leave. <br>Benefits are not pensionable.<br>Executive directors may receive other benefits that are <br>judged to be cost-effective and appropriate in terms of the <br>individual's role, time and/or security. These may include <br>car-related benefits and/or cash in lieu, security, assistance <br>with tax return preparation, insurance and medical benefits. <br>The company may meet any tax charges arising on benefits <br>provided to directors.<br>The taxable value of benefits provided may fluctuate during <br>the period of this policy, depending on the cost of provision <br>and a director's personal circumstances.<br>|

---

---

| | | |
|:---|:---|:---|
| ![DRR_SIngleLozenge_PolicyImp-RetireBen.gif](bp-20251231_g198.gif) | ![DRR_SIngleLozenge_PolicyImp-RetireBen.gif](bp-20251231_g198.gif) |  |
| **Purpose** | To recognize competitive practice in the directors' home country while being aligned with the majority of the workforce. | To recognize competitive practice in the directors' home country while being aligned with the majority of the workforce. |
| **Operation and** <br>**opportunity**<br>| Executive directors normally participate in the company <br>retirement plans that operate in their home country.<br>New appointees from within bp group retain previously <br>accrued benefits. For future appointments, the committee <br>will carefully review any retirement benefits to be granted to <br>a new director, taking account of retirement policies across <br>the wider workforce and any arrangements currently <br>in place.<br>| Retirement benefits for executive directors will be limited to <br>the allowance offered to the majority of the workforce in the <br>executive's home country (the maximum allowance in the UK <br>is currently 20% of salary).<br>|

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 119 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

---

| | | |
|:---|:---|:---|
| ![DRR_SIngleLozenge_PolicyImp-AnnBon.gif](bp-20251231_g177.gif) | ![DRR_SIngleLozenge_PolicyImp-AnnBon.gif](bp-20251231_g177.gif) |  |
| **Purpose** | To provide variable remuneration dependent on the execution of the business strategy on an annual basis. Bonus is subject to <br>a mandatory deferral into bp shares which are held for three years to reinforce the long-term nature of the business and <br>alignment with shareholders. | To provide variable remuneration dependent on the execution of the business strategy on an annual basis. Bonus is subject to <br>a mandatory deferral into bp shares which are held for three years to reinforce the long-term nature of the business and <br>alignment with shareholders. |
| **Operation and** <br>**opportunity**<br>| The bonus is based on performance against annual <br>measures and targets set at the start of the year, evaluated <br>over the financial year and assessed following the year-end.<br>The target annual bonus is half of the maximum available, <br>and typically relates to delivery of performance in line with <br>targets in the annual plan.<br>Executive directors may earn a maximum annual bonus <br>of 225% of salary. This maximum level would relate <br>to performance at or above the highest end of the <br>performance scale for every measure. The committee <br>intends to set demanding requirements for maximum <br>payment.<br>Achievement of threshold performance would normally <br>result in a payout of 0% of the maximum opportunity. <br>Bonus calculation is typically based on salary as at <br>31 December in each performance year.<br>| The final bonus outcome, following the formulaic <br>assessment of performance relative to targets, is specifically <br>reserved as a matter for the committee's judgement. <br>Accordingly, the committee may exercise its discretion to <br>adjust the formulaic outcome either upwards or downwards.<br>Half the bonus is paid in cash, and half is deferred into bp <br>shares for three years up until 'minimum shareholding <br>requirement' (MSR) is met, as determined by the committee <br>under the shareholding guidelines. Once met, 67% is paid in <br>cash and 33% is deferred into bp shares. Dividends (or <br>equivalents, including the value of any reinvestment) may <br>accrue in respect of any deferred shares.<br>Awards are subject to malus provisions before they are <br>delivered and to clawback thereafter for a period of three <br>years. Further detail is set out on page <u>[121](#iec7de57031af47ca83791eb2efcfa2da_2-0-1-1-956229)</u>.<br>|
| **Performance** <br>**framework**<br>| The committee determines a scorecard of specific <br>measures, weightings and targets each year to reflect the <br>priorities in the annual plan, as agreed with the board, and <br>thus deliver the group's strategy.<br>| The scorecard will typically include a balance of financial and <br>non-financial measures. Details of the measures and <br>weighting will typically be reported in advance each year in <br>the annual report on remuneration, while targets, where <br>commercially sensitive, will be disclosed retrospectively. <br>|

---

---

| | | |
|:---|:---|:---|
| ![DRR_SIngleLozenge_PolicyImp-PerfShare.gif](bp-20251231_g178.gif) | ![DRR_SIngleLozenge_PolicyImp-PerfShare.gif](bp-20251231_g178.gif) |  |
| **Purpose** | To link the largest part of remuneration opportunity with the long-term performance of the business.  | To link the largest part of remuneration opportunity with the long-term performance of the business.  |
| **Operation and** <br>**opportunity**<br>| The maximum annual award level for the chief executive <br>officer will be 500% of salary and 450% of salary for other <br>executive directors. <br>Annual awards of shares will vest based on performance <br>relative to measures and targets that reflect the delivery <br>of bp's strategy over a performance period of typically <br>three years. <br>For each measure, the threshold level at which vesting is <br>first triggered is not expected to yield vesting above 25% <br>of the maximum.<br>| The final performance shares outcome, following the <br>formulaic assessment of performance relative to targets, <br>is specifically reserved as a matter for the committee's <br>judgement. Accordingly, the committee may exercise its <br>discretion to adjust the formulaic outcome either upwards <br>or downwards.<br>The shares that vest are subject to a three-year post-vesting <br>holding period. <br>Dividends (or equivalents, including the value of <br>reinvestment) may accrue in respect of share awards to the <br>extent that they vest. <br>Awards are subject to malus provisions before vesting and <br>to clawback provisions thereafter for a period of three years. <br>Further detail is set out on page <u>[121](#iec7de57031af47ca83791eb2efcfa2da_2-0-1-1-956229)</u>.<br>|
| **Performance** <br>**framework**<br>| At the outset of each performance cycle, the committee <br>determines a scorecard of specific measures, weightings <br>and targets to reflect the group's long-term strategic <br>priorities and shareholder interests. <br>| The scorecard will typically include a balance of financial and <br>non-financial measures (including sustainability). The <br>committee will assess overall safety performance as well as <br>progress towards the reduction of net debt as an underpin in <br>determining the final vesting percentage.<br>|

---

---

| | | |
|:---|:---|:---|
| ![DRR_SIngleLozenge_PolicyImp-ShareReq.gif](bp-20251231_g179.gif) | ![DRR_SIngleLozenge_PolicyImp-ShareReq.gif](bp-20251231_g179.gif) |  |
| **Purpose** | To provide alignment between the interests of executive directors and our other shareholders. | To provide alignment between the interests of executive directors and our other shareholders. |
| **Operation and** <br>**opportunity**<br>| The chief executive officer is required to build and maintain a <br>minimum shareholding of five times base salary within five <br>years of appointment, and to maintain that minimum <br>shareholding for at least two years after they cease to be <br>a director. <br>| Other executive directors are required to build and maintain <br>a minimum shareholding of four and a half times base salary <br>within five years of appointment, and to maintain that <br>minimum shareholding for at least two years after they <br>cease to be a director.<br>|

---

---

| | | |
|:---|:---|:---|
| 120 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

**Notes to the policy table**

**1. How is variable pay linked to performance?**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| ![DRR_SIngleLozenge_PolicyImp-AnnBon.gif](bp-20251231_g177.gif) | Bonus aligned with <br>company performance | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) |  |  | <100% MSR<sup>a</sup>: 50% paid in cash; 50% in bp <br>shares deferred for three years<br>|
| ![DRR_SIngleLozenge_PolicyImp-AnnBon.gif](bp-20251231_g177.gif) | Bonus aligned with <br>company performance | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) |  |  | >100% MSR<sup>a</sup>: 67% paid in cash: 33% in bp <br>shares deferred for three years<br>|
|  |  | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) |  |  |  |
| ![DRR_SIngleLozenge_PolicyImp-PerfShare.gif](bp-20251231_g178.gif) | Share award for meeting <br>three-year targets<br>|  | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) |  | Six-years; three-year performance period <br>+ three-year holding period<br>|
|  |  |  | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) |  |  |
| ![DRR_SIngleLozenge_PolicyImp-ShareOwn.gif](bp-20251231_g199.gif) | Long-term shareholding |  |  | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) | Built up over five years and maintained for <br>a further two years post-employment<br>|
|  |  |  |  | ![ArrowRightWarmGrey4.gif](bp-20251231_g183.gif) |  |

---

aMSR: group chief executive to build a shareholding of at least five times salary, and other executive directors four and a half times salary, within five years of appointment.

The three elements described above provide a balance between a focus on short-term, medium-term and long-term performance, while

encouraging behaviours which are in the long-term interests of shareholders. The operation of variable pay is supported by a focus on stewardship.

There is a requirement that the chief executive officer will build up a holding of five times salary, and other executive directors a holding of four and

a half times salary, over a period of five years following appointment and maintain that level during employment and for a further two years post-

employment.

**2. How are performance measures linked to strategy?**

Variable pay is linked to performance measures designed to deliver the bp strategy. At the start of each year, the remuneration committee reviews

the measures, targets and weightings to ensure they remain consistent with the priorities in the annual plan and the group strategy. For the annual

bonus and performance shares, the approach to performance measurement is intended to provide a balance of measures to assess performance

reflecting the global scale of the business, the unique characteristics of the energy sector, and progress in transitioning to an integrated energy

company.

**3. Our use of flexibility, judgement and discretion**

The committee reviews bp's performance against specific measures and targets, and in doing so may make both quantitative and qualitative

assessments of performance in reaching its decisions. This involves the application of judgement and discretion, in which the committee also seeks

relevant input from the board's audit and safety and sustainability committees. Accordingly, the committee may decide to adjust the formulaic

outcome derived from the relevant scorecards, either upwards or downwards, to reflect broader considerations. The committee continues to

consider that the powers of flexibility, judgement and discretion are critical to the successful execution of the policy.

In framing the policy, the committee has taken care to ensure that these important powers continue to be available:

• Sufficient flexibility to take account of future changes in the industry environment and in remuneration practice generally. This allows the

committee to respond to changes in circumstances, for example in applying particular performance measures and/or weightings within the

plans, or in broadening the comparator group for the relative returns measure, in order to evolve with the company's strategy, without the need

for specific shareholder approval.

• Power to exercise judgement in making a qualitative assessment in certain circumstances. A number of measures are used for annual or long-

term incentive awards, many of which are numerical in nature and require a quantitative assessment of performance. Others may require a

qualitative assessment, such as the strategic progress measures in the performance share plan.

• Scope for the committee to exercise discretion, mainly where it is desirable to vary a formulaic outcome that would otherwise arise from the

policy's implementation. The committee considers that the ability to exercise discretion, upwards or downwards, is important to ensure that a

particular outcome is fair in light of the director's own performance, the company's overall performance and positioning under particular

performance measures and outcomes for shareholders.

The committee may make minor amendments to the remuneration policy to aid its operation or implementation without seeking shareholder

approvals (e.g. for regulatory, exchange control, tax or administrative purposes or to take account of a change in legislation).

The committee intends to provide appropriate disclosure on the use of flexibility, judgement and discretion so that shareholders can understand

the basis for its decisions.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 121 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

**4. How will we safeguard against payments for failure?**

---

| | |
|:---|:---|
| **Performance-based pay** | A significant portion of remuneration varies with performance – where performance targets are not achieved, lower or <br>no payments will be made under the plans. |
| **Discretion** | The committee may vary formulaic outcomes where these do not suitably reflect performance or other circumstances <br>over the relevant performance period. |
| **Malus and clawback** | The robust malus provisions enable the committee to reduce the size of award, cancel an unvested award, or impose <br>further conditions on an award made under this policy, while the robust clawback provisions enable the committee to <br>require participants to return some or all of an award after payment or vesting. <br>The following events will trigger the application of either malus or clawback: <br>•Material failure impacting safety or environmental sustainability.<br>•Material damage to the reputation of the group, or conduct by a participant which results in or is reasonably likely to <br>result in such material damage. <br>•Incorrect award outcomes due to miscalculation or based on incorrect information.<br>•Restatement due to financial reporting failure or misstatement of audited results.<br>•Material misconduct by a participant.<br>•Fraud effected by or with the knowledge of a participant. <br>In addition, the following events will trigger the application of malus, where the event takes place prior to the vesting or <br>payment of an award:<br>•Material downturn in financial performance of the group, or any part of it.<br>•Conduct effected by or with the knowledge of a participant which resulted in significant losses to the group, or any <br>part of it. <br>•Such other exceptional circumstances that the committee consider to be similar in nature.<br>The company also operates a mandatory clawback policy that complies with the US Securities and Exchange <br>Commission (SEC) requirements. |

---

---

| | | |
|:---|:---|:---|
| 122 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

**5. Differences from remuneration policy in the wider group** 

This executive director remuneration policy is structurally similar to remuneration for the majority of the wider workforce, but naturally differs in

quantum, reflecting market norms for the differing size and complexity of roles, see page <u>[96](#i0dd2ee81aac04f8c9c97c86197f0c6df_199)</u> for more detail on these differences.

Illustrations of application of remuneration policy

The total remuneration opportunity for executive directors is strongly performance based and weighted to the long term. The charts below provide

scenarios for the total remuneration of each individual who is an executive director at the date the policy comes into effect, at different levels of

performance. The scenarios are calculated as prescribed by UK regulations.

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| **Meg O'Neill** | **Meg O'Neill** | **Meg O'Neill** | **Meg O'Neill** | **Meg O'Neill** | **Meg O'Neill** | **Meg O'Neill** | **Meg O'Neill** |
| Min | 100% | £2.1m | £2.1m |  |  |  |  |
| Mid | 26% | 23% | 51% |  | £7.9m |  |  |
| Max | 15% | 26% |  | 59% |  | £13.7m |  |
| SPI\* | 12% | 20% |  | 68% |  |  | £17.7m |

---

![1](bp-20251231_g200.gif)

Fixed pay Annual bonus Performance shares \* 50% share price increase

![ChartKeyLozengeAmber2.gif](bp-20251231_g112.gif)

![ChartKeyLozengeGreen.gif](bp-20251231_g114.gif)

![ChartKeyLozengeLightGreen.gif](bp-20251231_g115.gif)

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| **Kate Thomson** | **Kate Thomson** | **Kate Thomson** | **Kate Thomson** | **Kate Thomson** | **Kate Thomson** | **Kate Thomson** | **Kate Thomson** |
| Min | 100% | £1.2m | £1.2m |  |  |  |  |
| Mid | 28% | 24% | 48% |  | £4.2m |  |  |
| Max | 16% | 28% |  | 56% |  | £7.2m |  |
| SPI\* | 13% | 22% |  | 66% |  |  | £9.2m |

---

![13](bp-20251231_g201.gif)

Fixed pay Annual bonus Performance shares \* 50% share price increase

![ChartKeyLozengeAmber2.gif](bp-20251231_g112.gif)

![ChartKeyLozengeGreen.gif](bp-20251231_g114.gif)

![ChartKeyLozengeLightGreen.gif](bp-20251231_g115.gif)

Due to rounding, the sum of the parts may not equal 100%.

Fixed components

For these illustrations salary, benefits and pension are the same in each scenario (annual values shown).

---

| | | |
|:---|:---|:---|
| ![DRR_SIngleLozenge_PolicyImp-SalaryV2.gif](bp-20251231_g175.gif) | ![DRR_SIngleLozenge_PolicyImp-SalaryV2.gif](bp-20251231_g175.gif) | ![DRR_SIngleLozenge_PolicyImp-SalaryV2.gif](bp-20251231_g175.gif) |
| CEO (O'Neill) | £1,600,000 | Meg's salary, upon appointment  |
| CFO (Thomson) | £894,000 | Kate's salary, effective from the 2026 AGM |

---

---

| | | |
|:---|:---|:---|
| ![DRR_SIngleLozenge_PolicyImp-PenAndBenV2.gif](bp-20251231_g176.gif) | ![DRR_SIngleLozenge_PolicyImp-PenAndBenV2.gif](bp-20251231_g176.gif) | ![DRR_SIngleLozenge_PolicyImp-PenAndBenV2.gif](bp-20251231_g176.gif) |
| CEO (O'Neill) | £458,170 | Based on cash in lieu of retirement benefits at 20% of salary, with an estimated £138k total for <br>other benefits. <br>|
| CFO (Thomson) | £261,179 | Based on cash in lieu of retirement benefits at 20% of salary, with an estimated £82k total for <br>other benefits.<br>|

---

Variable components

Variable pay under the policy comprises annual bonus and performance shares.

---

| | | | |
|:---|:---|:---|:---|
| **Scenario** | **Minimum** | **Mid** | **Maximum** |
|  | 🡫 | 🡫 | 🡫 |
| ![DRR_SIngleLozenge_PolicyImp-AnnBon.gif](bp-20251231_g177.gif)<br>(including cash and deferred elements) | Threshold not met | 50% of maximum | 100% of maximum |
| ![DRR_SIngleLozenge_PolicyImp-AnnBon.gif](bp-20251231_g177.gif)<br>(including cash and deferred elements) | Nil | 112.5% of salary | 225% of salary |
| ![DRR_SIngleLozenge_PolicyImp-PerfShare.gif](bp-20251231_g178.gif) | Threshold not met | 50% vesting | 100% vesting |
| ![DRR_SIngleLozenge_PolicyImp-PerfShare.gif](bp-20251231_g178.gif) | CEO – Nil <br>CFO – Nil<br>| CEO – 250% of salary <br>CFO – 225% of salary<br>| CEO – 500% of salary <br>CFO – 450% of salary<br>|

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 123 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

Recruitment policy

The committee expects any new executive director to be engaged on terms that are consistent with the policy. However, it recognizes that it

cannot anticipate all circumstances in which any new executive director may be recruited. The committee may determine that it is in the interests

of the company and shareholders to secure the services of a particular individual which may require it to take account of the terms of that

individual's existing employment and/or their personal circumstances.

Accordingly, the committee will consider the following:

• The salary level of any new director is appropriate to their role and the competitive environment at the time of appointment. Where appropriate,

it may appoint an individual on a lower salary (relative to any previous incumbent), then gradually increase salary levels as the individual gains

experience in the role.

• Variable remuneration will be awarded within the parameters of the policy for current executive directors.

• The committee may tailor the vesting criteria for initial incentive awards depending on the specific circumstances.

• Where an existing employee is promoted to the board, the company may honour any existing commitments including maintaining any

outstanding share awards.

• The committee would expect any new director to participate in the company pension and benefit schemes that are open to other employees

(where appropriate, referencing the candidate's home country).

• Where an individual is relocating in order to take up the role, the company may provide certain benefits such as reasonable relocation expenses,

accommodation for a period following appointment, assistance with visa applications or other immigration issues and ongoing arrangements

such as repatriation assistance, tax filing assistance, annual flights home and a housing/utilities allowance. The company may meet any tax

charges arising on relocation benefits.

• Where an individual would be forfeiting remuneration or employment terms in order to join the company, the committee may award appropriate

compensation. The committee would require reasonable evidence of the nature and value of any forfeited arrangements and would, to the

extent practicable, ensure any compensation was of comparable commercial value and capped as appropriate, considering the terms of the

previous arrangement being forfeited (for example, the form and structure of award, timeframe, performance criteria and likelihood of vesting).

Where appropriate, the committee prefers to deliver buy-outs in the form of restricted shares in the company.

• To facilitate any share awards on recruitment, the committee may rely on the Listing Rules exemption, which permits the grant of share awards,

in unusual circumstances, to support the recruitment of an executive director, without seeking prior shareholder approval or making such

awards under any other existing share plan.

In making any decision on the remuneration of a new director, the committee would balance shareholder expectations, current best practice and

the circumstances of any new director. It would strive not to pay more than is necessary to recruit the right candidate and would give full details in

the next remuneration report.

Service contract

Meg O'Neill's and Kate Thomson's service contracts are with BP p.l.c.

Each executive director is entitled to retirement benefits, as outlined on page <u>[118](#i4d0cbb9d540342d38e862c3c96b9111a_175895)</u>.

Each executive director is also entitled to the following contractual benefits:

• If appropriate for security reasons, a company car and driver is provided for business and private use, with the company bearing all normal

employment, servicing, insurance and running costs. Alternatively, where not required for security reasons, a cash allowance may be

paid instead.

• Medical and dental benefits, sick pay during periods of absence and assistance with the preparation of tax returns.

• Indemnification in accordance with applicable law.

• Participation in bonus or incentive arrangements at the committee's sole discretion.

In line with bp's policy on notice periods for executive directors, each executive director may terminate their employment by giving 12 months'

written notice. In this event, for business reasons, the employer may not necessarily hold the executive director to their full notice period.

The employer may lawfully terminate the executive director's employment in the following ways:

• By giving the director 12 months' written notice.

• Without compensation, in circumstances where the employer is entitled to terminate for cause, as defined for the purposes of their

service contract.

The company may lawfully terminate employment by making a lump sum payment in lieu of notice equal to 12 months' salary, or by monthly

instalments rather than as a lump sum.

The lawful termination mechanisms described above are without prejudice to the employer's ability in appropriate circumstances to terminate in

breach of the notice period referred to above, and thereby to be liable for damages to the executive director.

In the event of termination by the company, each executive director may have an entitlement to compensation in respect of their statutory rights

under employment protection legislation in the UK and potentially elsewhere. Where appropriate, the company may also meet a director's

reasonable legal expenses in connection with either their appointment or termination of their appointment.

Copies of the executive directors' service contracts, along with the non-executive director appointment letters, are available for inspection at the

registered office of BP p.l.c.

---

| | | |
|:---|:---|:---|
| 124 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Directors' remuneration report** continued<br>

Termination payments

In determining overall termination arrangements, the committee will distinguish between types of leaver and the circumstances of their leaving.

The committee would also consider all relevant circumstances, including whether a contractual provision in the director's arrangements complied

with best practice at the time of termination and the date the provision was agreed, as well as the performance of the director in certain respects.

Where appropriate, the committee may consider providing certain benefits relating to termination including the provision of outplacement support

or reasonable costs associated with relocation back to an individual's home country. Should it become necessary to terminate an executive

director's employment, and therefore to determine a termination payment, the committee's policy is as follows:

---

| | | |
|:---|:---|:---|
| **Termination payments** | The director's primary entitlement would be a termination <br>payment in respect of their service agreement, as set out <br>above. However the committee will consider mitigation to <br>reduce the termination payment where appropriate to do <br>so, taking into account the circumstances for leaving and <br>the terms of the agreement.<br>Mitigation would not be applicable where a contractual <br>payment in lieu of notice is made.<br>| If the departing director is eligible for an early retirement <br>pension, the committee would consider, if relevant under <br>the terms of the appropriate plan, the extent of any <br>actuarial reduction that should be applied. UK directors <br>who leave in circumstances approved by the committee <br>may have a favourable actuarial reduction applied to their <br>pensions (which to date has been 3%). Departing directors <br>who leave in other circumstances may be subject to a <br>greater reduction.<br>|
| **Annual bonus** | The committee would consider whether the director <br>should be entitled to an annual bonus in respect of the <br>financial year in which the termination occurs.<br>| Normally, any such bonus would be restricted to the <br>director's actual period of service in that financial year <br>and would be subject to deferral unless the committee <br>determines otherwise.<br>|
| **Share awards** | Share awards will be treated in accordance with the <br>relevant plan rules. For awards granted under the <br>executive directors' incentive plan (EDIP), the treatment <br>can only be made in accordance with the framework <br>approved by shareholders.<br>The committee would consider whether conditional share <br>awards held by the director should lapse on leaving or <br>should, at the committee's discretion, be preserved. If <br>awards are preserved, the award would normally continue <br>until the vesting date. Awards may be pro-rated based on <br>service over the performance period.<br>| In deciding whether to exercise discretion to preserve <br>EDIP awards, the committee would also consider the <br>proximity of the award to its maturity date.<br>To the extent that any such share award vests, the release <br>of those shares to the former director will normally be <br>made approximately one year after their date of <br>termination (even if they would have been subject to a <br>longer holding period had the executive remained in <br>employment with bp).<br>|

---

Remuneration in the wider group

The committee considers employment conditions in the bp group when establishing and implementing policy for executive directors to ensure the

alignment of and context for principles and approach. In particular, the committee reviews the policy and makes decisions for the most senior

leaders (the bp leadership team that reports to the CEO). Decisions regarding remuneration for employees outside the most senior leaders are the

responsibility of the chief executive officer. The committee does not consult directly with employees when formulating the policy. However,

feedback from employee focus groups and employee surveys, that are regularly reported to the board, provide views on a wide range of employee

matters including pay.

The wider employee group participates in performance-based incentives. Throughout the group, salary and benefit levels are set in accordance

with the prevailing relevant market conditions and practice in the countries in which employees are based. Differences between executive director

pay policy and that of other employees reflect the senior position of the individuals, prevailing market conditions and corporate governance

practices in respect of executive director remuneration. The key difference in policy for executive directors is that a greater proportion of total

remuneration is delivered as performance-based incentives.

Engaging with shareholders

The committee carefully considers shareholder feedback each year and this input has been instrumental in shaping the current remuneration

policy. As outlined in the chair's letter, for the 2026 policy review, over 40% of bp's shareholder register were consulted and the vast majority

expressed support for broadly retaining the 2023 policy. The committee remains committed to maintaining an open and constructive dialogue

with shareholders and will continue to consult before introducing any material changes to the remuneration policy.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 125 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

**Policy table – non-executive directors**

The following table sets out the framework that will be used to determine the fees for non-executive directors during the term of this policy.

---

| | |
|:---|:---|
| **Non-executive chair** | **Non-executive chair** |
| Fees | Fees |
| **Approach** | Remuneration is in the form of fees. Fees are currently paid in cash but the company may pay part or all of the fees in the <br>form of shares. The level and structure of the chair's fee will primarily be compared against UK best practice.<br>|
| **Operation and** <br>**opportunity**<br>| The quantum and structure of the non-executive chair's fee is reviewed annually by the remuneration committee, which <br>makes a recommendation to the board.<br>|
| Benefits and expenses | Benefits and expenses |
| **Approach** | The chair is provided with support and reasonable travelling expenses. |
| **Operation and** <br>**opportunity**<br>| The chair is provided with an office and full-time secretarial and administrative support in London and a contribution to <br>an office and secretarial support in his home country as appropriate. A car and the use of a driver is provided in London, <br>together with security assistance. All reasonable travelling and other expenses (including any relevant tax) incurred in <br>carrying out his duties are reimbursed.<br>|

---

---

| | |
|:---|:---|
| **Non-executive directors** | **Non-executive directors** |
| Fees | Fees |
| **Approach** | Remuneration is in the form of fees. Fees are currently paid in cash but the company may pay part or all of the fees in the <br>form of shares. Remuneration practice is consistent with recognized best practice standards for non-executive directors <br>and, as a UK-listed company, the level and structure of non-executive directors' remuneration will primarily be compared <br>against UK best practice.<br>Additional fees may be payable to reflect additional board responsibilities, for example, committee chairship and <br>membership and for the role of senior independent director.<br>|
| **Operation and** <br>**opportunity**<br>| The level and structure of non-executive directors' remuneration is reviewed by the chair, the CEO and the company <br>secretary, who make a recommendation to the board. Non-executive directors do not vote on their own remuneration.<br>Fee levels for non-executive directors are reviewed annually.<br>|
| Benefits and expenses | Benefits and expenses |
| **Approach** | Non-executive directors are provided with administrative support and reasonable travelling expenses. Professional fees <br>are reimbursed in the form of cash, payable following the provision of advice and assistance.<br>|
| **Operation and** <br>**opportunity**<br>| Non-executive directors are reimbursed for all reasonable travelling and subsistence expenses (including any relevant <br>tax) incurred in carrying out their duties. Professional fees incurred by non-executive directors based outside the UK in <br>connection with advice and assistance on UK tax compliance matters are reimbursed.<br>|
| Shareholding guidelines | Shareholding guidelines |
| **Approach** | Chair and non-executive directors are encouraged to establish a holding in bp shares of the equivalent value of one <br>year's base fee.<br>|

---

---

| | |
|:---|:---|
| **Letters of appointment for chair and non-executive directors** | **Letters of appointment for chair and non-executive directors** |
| **Approach** | The chair and non-executive directors each have letters of appointment. There is no term limit on a director's service, as <br>bp proposes all directors for annual re-election by shareholders. There are no obligations arising from the non-executive <br>directors' letters of appointment for remuneration or payments for loss of office, except for the chair whose <br>appointment may be terminated in the following ways:<br>•By either party giving three months' written notice, or<br>•By the company for cause (as set out in the letter of appointment) and without compensation.<br>The company may lawfully terminate the appointment by making a lump sum payment in lieu of notice equal to three <br>months' fees. Copies of the executive directors' service contracts and non-executive directors' letters of appointment <br>are available for inspection at the registered office of the company.<br>|

---

The maximum fees for non-executive directors are set in accordance with the Articles of Association.

---

| | | |
|:---|:---|:---|
| 126 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Other disclosures**<br>

**Appointment and succession plans**

The chair, senior independent director (SID) and

other independent non-executive directors (NEDs)

each have letters of appointment with BP p.l.c. and

do not serve, nor are they employed, in any

executive capacity by bp. In line with the UK

Corporate Governance Code (Code), all continuing

directors are subject to annual re-election by

shareholders at the Annual General Meeting (AGM),

where letters of appointment for each NED are

available for inspection. Details on the skills and

experience of each director seeking election or re-

election, as well as their individual contributions to

the long-term success of the company, are set out

in the Notice of AGM. In accordance with the Code,

NEDs would not be expected to serve beyond nine

years unless there are exceptional circumstances.

On behalf of the board, the people, culture and

governance committee reviews the formal

appointment process and succession plans for the

board. Appointments and succession plans are

both based on merit and assessed against

objective criteria with the promotion of diversity,

equity and inclusion as central considerations. This

includes diversity of gender, social and ethnic

backgrounds as well as cognitive and personal

strengths. In reviewing appointments and

succession plans, due consideration is given to

ensure the smooth transition of board members

with specific responsibilities (e.g. committee chair

roles) by allowing sufficient time for a detailed

handover. This is balanced by the need to have new

board members join at regular intervals such that,

over time, there is a controlled approach to board

members reaching the end of their tenure. All new

directors receive a formal induction, tailored to

their individual needs, skills and experience, taking

account of any committees they join. These

inductions include one-to-one meetings with

members of the board and leadership team

together with select members of senior

management. Feedback is sought from directors

undertaking their induction programmes to ensure

they are continually updated and improved.

Further detail on board succession and tenure can

be found in the people, culture and governance

committee report on **page** <u>[89](#i372e476394b943ee83d7eb667cf64e6f_236812)</u> and board

composition disclosure on page <u>[72](#i50951c1f0ef9438ab39a916851bf28b4_0-0-1-3-938780)</u>, respectively.

**Time commitments** 

The expectation regarding time commitment for

NEDs to effectively discharge their duties is set out

in the directors' letters of appointment. The time

commitment varies with the demands of bp

business and other events. The NEDs' external time

commitments – whether through executive, non-

executive, advisory or other roles – are regularly

reviewed by the company secretary to ensure that

directors are able to allocate appropriate time to

bp. A register of directors' time commitments and

conflicts is maintained and is also reviewed

annually by the people, culture and governance

committee. The review process takes into account

outside appointments and other external

commitments and considers the complexity of the

organization, the nature of the role, the sector

(especially regulated and/or potentially competing

sectors) and any leadership roles (e.g. a chair

position). NEDs are also required to consult with

the company secretary and chair before accepting

any other role that may impact their ability to

commit appropriate time to bp. The process for the

approval of any new external appointment,

significant or otherwise, for an existing director

assesses the impact of that appointment on the

director's time in order to ensure the director has

sufficient capacity for their role with bp. As part of

that same review process, a review of

independence and potential conflicts of interest is

undertaken, taking account of institutional investor

and proxy advisor guidance and market best

practice. Any external proposed commitments that

could exceed the mandates set out in such

guidance are given particular consideration. The

board was satisfied that significant appointments

undertaken during 2025 did not impact the

directors' ability to prepare for and attend

meetings, engage with stakeholders and

participate in learning and development

opportunities. The board has concluded that,

notwithstanding external appointments held, each

director is able to dedicate sufficient time to fulfil

their bp duties. In compliance with the Code, none

of the executive directors who served during 2025

held more than one non-executive directorship in a

FTSE 100 company or other significant

appointment throughout their tenure on the board.

For more information on the external

commitments of bp's directors, see **pages** <u>[73](#i37a3d214193b4b7c8713c4ffbce5e765_33)</u><u>-</u><u>[75](#i9312239844dc4004ac1977b1c87b673f_4-0-1-2-889666)</u>.

For information on board meetings held during

2025 and director attendance at board meetings,

see **page** <u>[75](#i770b8be3d6ca45a2a60c885c7a1db815_1-2-1-2-889650)</u>.

**Independence and conflicts** 

**of interest**

All directors have a statutory duty to exercise

independent judgement. Independence of NEDs is

crucial in bringing constructive challenge to the

chief executive officer (CEO) and the leadership

team at board meetings, while providing support

and guidance to promote meaningful discussion

and, ultimately, informed and effective decision-

making. In accordance with the criteria set out in

the Code, the chair was considered independent at

the time he was appointed. NEDs are required to

provide sufficient information to allow the board to

evaluate their independence prior to and following

their appointment. In addition, each director has a

statutory duty to disclose actual or potential

conflicts of interest. Formal procedures are in

place for new potential conflicts to be reported

and recorded during the year. As a consequence of

regular reviews in 2025, the board is satisfied that

there were no matters giving rise to conflicts of

interest which could not be authorized by the

board. It has therefore concluded that all bp NEDs

are independent.

**Reporting in line with UK Listing** 

**Rule 6.6.6R(9)**

As at 31 December 2025, 46% of the board

comprises women, our senior independent

director (SID), chief executive officer (CEO), chief

financial officer (CFO) are women and three

directors identify as from an ethnic minority

background. Data for the below tables is

collected on an annual basis through a

standardized process under which each member

of the board and executive management is asked

to self-declare, or elect not to declare, their ethnic

background and gender identity or sex. The

information is correct as at 31 December 2025.

For the purposes of this table, executive

management includes bp's leadership team

and the company secretary.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **Gender identity or sex** | Number of board <br>members<br>| Percentage of the <br>board<br>| Number of senior <br>positions on the board <br>(CEO, CFO, SID and <br>chair)<br>| Number in executive <br>management<br>| Percentage of <br>executive <br>management<br>|
| Men | 7 | 54% | 1 | 5 | 55% |
| Women | 6 | 46% | 3 | 4 | 45% |
| Other categories | – | – | – | – | – |
| Not specified/prefer not to say | – | – | – | – | – |

---

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **Ethnic background** |  |  |  |  |  |
| White British or other white (including minority-white groups) | 10 | 77% | 100% | 7 | 78% |
| Mixed/Multiple Ethnic Groups | – | – | – | – | – |
| Asian/Asian British | 3 | 23% | – | 1 | 11% |
| Black/African/Caribbean/Black British | – | – | – | 1 | 11% |
| Other ethnic group | – | – | – | – | – |
| Not specified/prefer not to say | – | – | – | – | – |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 127 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Corporate governance** |

---

Pages 127-128 have been removed as they do not form part of bp's Annual Report on Form 20-F as filed with the SEC.

---

| | | |
|:---|:---|:---|
| 128 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

Pages 127-128 have been removed as they do not form part of bp's Annual Report on Form 20-F as filed with the SEC.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 129 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **Consolidated financial statements of the bp group** | **Consolidated financial statements of the bp group** | **Consolidated financial statements of the bp group** | **Consolidated financial statements of the bp group** | **Consolidated financial statements of the bp group** | **Consolidated financial statements of the bp group** |
| Independent auditor's reports (PCAOB ID 1147) | Independent auditor's reports (PCAOB ID 1147) | **149** | Group statement of changes in equity | Group statement of changes in equity | **[157](#i0dd2ee81aac04f8c9c97c86197f0c6df_259)** |
| Group income statement | Group income statement | **[155](#i0dd2ee81aac04f8c9c97c86197f0c6df_253)** | Group balance sheet | Group balance sheet | **[158](#i0dd2ee81aac04f8c9c97c86197f0c6df_262)** |
| Group statement of comprehensive income | Group statement of comprehensive income | **[156](#i0dd2ee81aac04f8c9c97c86197f0c6df_256)** | Group cash flow statement | Group cash flow statement | **[159](#i0dd2ee81aac04f8c9c97c86197f0c6df_265)** |
| **Notes on financial statements** | **Notes on financial statements** | **Notes on financial statements** | **Notes on financial statements** | **Notes on financial statements** | **Notes on financial statements** |
| 1. | Significant accounting policies | **[160](#i0dd2ee81aac04f8c9c97c86197f0c6df_271)** | 22. | Trade and other payables | **[203](#i0dd2ee81aac04f8c9c97c86197f0c6df_337)** |
| 2. | Non-current assets held for sale | **[181](#i0dd2ee81aac04f8c9c97c86197f0c6df_277)** | 23. | Provisions | **[204](#i0dd2ee81aac04f8c9c97c86197f0c6df_340)** |
| 3. | Business combinations | **[182](#i0dd2ee81aac04f8c9c97c86197f0c6df_280)** | 24. | Pensions and other post-employment <br>benefits | **[205](#i0dd2ee81aac04f8c9c97c86197f0c6df_343)** |
| 4. | Disposals and impairment | **[182](#i0dd2ee81aac04f8c9c97c86197f0c6df_283)** | 24. | Pensions and other post-employment <br>benefits | **[205](#i0dd2ee81aac04f8c9c97c86197f0c6df_343)** |
| 5. | Segmental analysis | **[185](#i0dd2ee81aac04f8c9c97c86197f0c6df_286)** | 25. | Cash and cash equivalents | **[211](#i0dd2ee81aac04f8c9c97c86197f0c6df_346)** |
| 6. | Sales and other operating revenues | **[189](#i0dd2ee81aac04f8c9c97c86197f0c6df_289)** | 26. | Finance debt | **[211](#i0dd2ee81aac04f8c9c97c86197f0c6df_349)** |
| 7. | Income statement analysis | **[189](#i0dd2ee81aac04f8c9c97c86197f0c6df_292)** | 27. | Capital disclosures and net debt | **[212](#i0dd2ee81aac04f8c9c97c86197f0c6df_352)** |
| 8. | Exploration for and evaluation of oil and <br>natural gas resources  | **[190](#i0dd2ee81aac04f8c9c97c86197f0c6df_295)** | 28. | Leases | **[213](#i0dd2ee81aac04f8c9c97c86197f0c6df_355)** |
| 8. | Exploration for and evaluation of oil and <br>natural gas resources  | **[190](#i0dd2ee81aac04f8c9c97c86197f0c6df_295)** | 29. | Financial instruments and financial risk <br>factors | **[214](#i0dd2ee81aac04f8c9c97c86197f0c6df_358)** |
| 9. | Taxation | **[190](#i0dd2ee81aac04f8c9c97c86197f0c6df_298)** | 29. | Financial instruments and financial risk <br>factors | **[214](#i0dd2ee81aac04f8c9c97c86197f0c6df_358)** |
| 10. | Dividends | **[193](#i0dd2ee81aac04f8c9c97c86197f0c6df_301)** | 30. | Derivative financial instruments | **[219](#i0dd2ee81aac04f8c9c97c86197f0c6df_364)** |
| 11. | Earnings per share | **[193](#i0dd2ee81aac04f8c9c97c86197f0c6df_304)** | 31. | Called-up share capital | **[228](#i0dd2ee81aac04f8c9c97c86197f0c6df_367)** |
| 12. | Property, plant and equipment | **[195](#i0dd2ee81aac04f8c9c97c86197f0c6df_307)** | 32. | Capital and reserves | **[230](#i0dd2ee81aac04f8c9c97c86197f0c6df_376)** |
| 13. | Capital commitments | **[196](#i0dd2ee81aac04f8c9c97c86197f0c6df_310)** | 33. | Contingent liabilities and legal <br>proceedings<br>| **[236](#i0dd2ee81aac04f8c9c97c86197f0c6df_379)** |
| 14. | Goodwill | **[196](#i0dd2ee81aac04f8c9c97c86197f0c6df_313)** | 34. | Remuneration of senior management <br>and non-executive directors | **[238](#i0dd2ee81aac04f8c9c97c86197f0c6df_382)** |
| 15. | Intangible assets | **[198](#i0dd2ee81aac04f8c9c97c86197f0c6df_316)** | 34. | Remuneration of senior management <br>and non-executive directors | **[238](#i0dd2ee81aac04f8c9c97c86197f0c6df_382)** |
| 16. | Investments in joint ventures | **[199](#i0dd2ee81aac04f8c9c97c86197f0c6df_319)** | 35. | Employee costs and numbers | **[239](#i0dd2ee81aac04f8c9c97c86197f0c6df_385)** |
| 17. | Investments in associates | **[201](#i0dd2ee81aac04f8c9c97c86197f0c6df_322)** | 36. | Auditor's remuneration | **[239](#i0dd2ee81aac04f8c9c97c86197f0c6df_388)** |
| 18. | Other investments | **[202](#i0dd2ee81aac04f8c9c97c86197f0c6df_325)** | 37. | Subsidiaries, joint arrangements and <br>associates | **[240](#i0dd2ee81aac04f8c9c97c86197f0c6df_391)** |
| 19. | Inventories | **[202](#i0dd2ee81aac04f8c9c97c86197f0c6df_328)** | 37. | Subsidiaries, joint arrangements and <br>associates | **[240](#i0dd2ee81aac04f8c9c97c86197f0c6df_391)** |
| 20. | Trade and other receivables | **[202](#i0dd2ee81aac04f8c9c97c86197f0c6df_331)** |  |  |  |
| 21. | Valuation and qualifying accounts | **[203](#i0dd2ee81aac04f8c9c97c86197f0c6df_334)** |  |  |  |
| **Supplementary information on oil and natural gas (unaudited)** | **Supplementary information on oil and natural gas (unaudited)** | **Supplementary information on oil and natural gas (unaudited)** | **Supplementary information on oil and natural gas (unaudited)** | **Supplementary information on oil and natural gas (unaudited)** | **Supplementary information on oil and natural gas (unaudited)** |
| Oil and natural gas exploration and production <br>activities | Oil and natural gas exploration and production <br>activities | **[242](#i0dd2ee81aac04f8c9c97c86197f0c6df_400)** | Standardized measure of discounted future net <br>cash flows and changes therein relating to <br>proved oil and gas reserves | Standardized measure of discounted future net <br>cash flows and changes therein relating to <br>proved oil and gas reserves | **[263](#i0dd2ee81aac04f8c9c97c86197f0c6df_406)** |
| Movements in estimated net proved reserves | Movements in estimated net proved reserves | **[248](#i0dd2ee81aac04f8c9c97c86197f0c6df_403)** | Standardized measure of discounted future net <br>cash flows and changes therein relating to <br>proved oil and gas reserves | Standardized measure of discounted future net <br>cash flows and changes therein relating to <br>proved oil and gas reserves | **[263](#i0dd2ee81aac04f8c9c97c86197f0c6df_406)** |
|  |  |  | Operational and statistical information | Operational and statistical information | **[266](#i0dd2ee81aac04f8c9c97c86197f0c6df_409)** |

---

This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.

---

| | |
|:---|:---|
| 130 | bp Annual Report and Form 20-F 2025 |

---

**Consolidated financial statements of the bp group** 

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

Pages 130-148 have been removed as they do not form part of bp's Annual Report on Form 20-F as filed with the SEC.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 149 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

Report of Independent Registered Public Accounting Firm

**To the shareholders and board of directors of BP p.l.c.**

**Opinion on the financial statements** 

We have audited the accompanying consolidated group balance sheets of BP p.l.c. and subsidiaries (together 'bp' or 'the group') as at 31 December

2025 and 2024, the related consolidated group income statements, group statements of comprehensive income, group statements of changes in

equity and group cash flow statements, for each of the three years in the period ended 31 December 2025, and the related notes (collectively

referred to as the 'financial statements'). In our opinion, the financial statements present fairly, in all material respects, the financial position of the

group as at 31 December 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended

31 December 2025, in accordance with United Kingdom adopted international accounting standards and IFRS Accounting Standards as issued by

the International Accounting Standards Board (IASB) and as adopted by the European Union (EU).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), bp's internal

control over financial reporting as of 31 December 2025, based on criteria established in *Internal Control — Integrated Framework (2013)* issued by

the Committee of Sponsoring Organizations of the Treadway Commission and our report dated 6 March 2026 expressed an unqualified opinion on

bp's internal control over financial reporting.

**Basis for opinion**

These financial statements are the responsibility of bp's management. Our responsibility is to express an opinion on bp's financial statements

based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to bp in

accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the

PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain

reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included

performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing

procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in

the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as

well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

**Critical Audit Matters**

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were

communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the

financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters

does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters

below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

**1. Impairment of upstream oil and gas property, plant and equipment (PP&E) assets – Notes 1, 4 and 12 to the financial statements** 

Critical Audit Matter Description

The group balance sheet as at 31 December 2025 includes PP&E, of which $55 billion is oil and gas properties.

Management's best estimate oil and gas price assumptions for value-in-use impairment tests were revised in 2025 as set out in Note 1 on pages

168-169.

Management has also determined bp's 'best estimate' discount rate assumptions, as set out in Note 1 on page 168. bp's post-tax discount rate used

for impairment testing for oil and gas assets in 2025 remained unchanged from prior year at 8%. Pre-tax discount rates applied in impairment tests

were revised in some regions to reflect changes in local tax rates and country risk premiums. Reserves estimates for all oil and gas fields were also

reviewed and updated where necessary at year-end.

As required by International Accounting Standard (IAS) 36 'Impairment of Assets', management performed a review of all oil and gas cash

generating units (CGUs) for indicators of impairment and impairment reversal as at 31 December 2025. As a result of management identifying

impairment indicators during 2025, $1 billion of oil and gas CGU net impairment charges were recognised, principally due to an increase in certain

capital expenditure forecasts and operating expenditure forecasts and certain reserves write downs.

We identified three key management estimates in management's determination of the level of impairment charge and/or impairment reversal.

These are:

**Oil and gas prices** – bp's oil and gas price assumptions have a significant impact on many CGU impairment assessments performed across

the OP&O and G&LCE segments and are inherently uncertain. The estimation of future prices is subject to increased uncertainty given climate

change, the global energy transition, macro-economic factors and disruption in global supply due to ongoing geo-political conflicts. There is a

risk that management do not forecast reasonable 'best estimate' oil and gas price forecasts when assessing CGUs for impairment charge

and/or impairment reversal, leading to material misstatements. These price assumptions are highly judgmental and are pervasive inputs to

bp's oil and gas CGU valuation. There is also a risk that management's oil and gas price related disclosures are not reasonable.

**Discount rates** – Given the long timeframes involved, certain CGU impairment assessments are sensitive to the discount rate applied.

Discount rates should reflect the return required by the market and the risks inherent in the cash flows being discounted. There is a risk that

management does not assume reasonable discount rates, adjusted as applicable for country risks and relevant tax rates, leading to material

misstatements. Determining a reasonable discount rate is highly judgmental and, consistent with price assumptions above, the discount rate

assumption is also a pervasive input across bp's oil and gas CGU valuations, before adjustments for asset specific risks and tax rates.

**Reserves and resources estimates** – A key input to certain CGU impairment assessments is the oil and gas production forecast, which is

based on underlying reserves estimates and field specific development assumptions. Certain CGU production forecasts include specific risk

adjusted resource volumes, in addition to proven and/or probable reserves estimates, that are inherently less certain than reserves;

assumptions related to these volumes can be particularly judgemental. There is a risk that material misstatements could arise from

unreasonable production forecasts for individually material CGUs and/or from the aggregation of systematic flaws in bp's reserves and

resources estimation policies across the OP&O and G&LCE segments.

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| 150 | bp Annual Report and Form 20-F 2025 |

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We identified certain individual CGUs which we determined would be most at risk of material impairment charges as a result of a reasonably

possible change in the oil and gas price assumptions. This population includes previously impaired assets which are also at risk of material

impairment reversal resulting from potential oil and gas price assumption changes. We identified that a subset of these CGUs was also individually

materially sensitive to the discount rate assumption. Further information regarding these sensitivities is given in Note 1 on page 169.

Impairment charge and/or impairment reversal assessments of upstream oil and gas PP&E assets remain a critical audit matter because

recoverable values are reliant on forecast assumptions such as oil and gas prices, discount rates and reserves estimates, which are inherently

judgemental and complex for management to estimate and challenging to audit. Additionally, the magnitude of the potential misstatement risk

remains material to the group.

How the Critical Audit Matter was addressed in the Audit

We tested relevant internal controls over the estimation of oil and gas prices, discount rates, and reserve and resources estimates, as well as

relevant internal controls over the performance of the impairment charge and/or impairment reversal assessments where we identified audit risks.

In addition, we conducted the following substantive procedures.

**Oil and gas prices** 

• We independently developed a reasonable range of forecasts based on external data obtained, against which we compared management's oil

and gas price assumptions in order to challenge whether they are reasonable.

• In developing this range, we obtained a variety of reputable and reliable third-party forecasts, peer information and other relevant market data.

• In challenging and evaluating management's price assumptions, we considered the extent to which they and each of the forecast pricing

scenarios obtained from third parties reflect the impact of lower oil and gas demand due to climate change and the energy transition.

• The 2015 Conference of the Parties (CoP) 21 Paris Agreement goals of 'holding the increase in the global average temperature to well below 2°C

above pre-industrial levels and pursuing efforts to limit the temperature increase to 1.5°C above pre-industrial levels' was reaffirmed at CoP 30

in Brazil during November 2025. We specifically analysed third party forecasts stated, or interpreted by us, as being consistent with scenarios

achieving the Paris 'well below 2°C goal' and/or '1.5°C ambition' and evaluated whether they presented contradictory audit evidence.

• We assessed management's disclosures in Note 1, including the sensitivity of forecast revenue cash inflows to lower oil and gas prices, and how

climate change and the energy transition, potential future emissions costs and/or reduced demand scenarios may impact bp to a greater extent

than currently anticipated in bp's value-in-use estimates for oil and gas CGUs.

**Discount rates**

• We independently evaluated bp's discount rates used in impairment tests with input from our valuation specialists, against relevant third-party

market and peer data.

• When performing procedures over specific assets, we assessed whether specific country risks and tax adjustments were reasonably reflected in

bp's discount rates.

• We challenged and evaluated management's disclosures in Note 1, including in relation to the sensitivity of discount rate assumptions.

**Reserves and resources estimates**

Using the outputs from our data analytics tools which we used to visualise reserves and resources volumes, and with the assistance of our oil and

gas reserves specialists, we:

• assessed bp's reserves and resources estimation methods and policies for reasonableness;

• assessed how these policies had been applied to a sample of bp's reserves and resources estimates;

• read and evaluated a sample of reports provided by management's external reserves experts and assessed the scope of work and findings of

these third parties;

• assessed the competence, capability and objectivity of bp's internal and external reserve experts, through understanding their relevant

professional qualifications and experience;

• assessed whether management's production forecasts are consistent overall with bp's strategy;

• compared the production forecasts used in the impairment tests with management's approved reserves and resources estimates; and

• performed a retrospective assessment in order to assess management's ability to accurately estimate reserves and resources and to check for

indications of estimation bias over time.

**2. Decommissioning provisions – Notes 1 and 23 to the financial statements**

Critical Audit Matter Description

A decommissioning provision of $12.3 billion is recorded in the financial statements as at 31 December 2025. The estimation of decommissioning

provisions is a highly judgemental area as it involves a number of key estimates related to the cost and timing of decommissioning, in particular

inflation and discount rate assumptions.

Management estimates that the average rate of forecast inflation applicable to the substantial majority of bp's decommissioning cost estimates is

1.5%, which is 0.5% lower than its estimated long term general inflation rate of 2%.

The estimated undiscounted cost of the obligations and the timing of future payments are set out in Note 1 on page 176. Economic factors, future

activities and the legislative environments that bp operates in are used to inform cost estimates, whereas the timing of decommissioning activities

is dependent on cessation of production (CoP) dates, which are sensitive to changes in bp's price forecasts as price estimates determine economic

cut off of oil and gas reserve estimates.

bp maintained the discount rate used in calculating its decommissioning provisions at 4.5% as at 31 December 2025.

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|:---|:---|
| bp Annual Report and Form 20-F 2025 | 151 |

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| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

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How the Critical Audit Matter was addressed in the Audit

**Long term inflation rate**

• We tested the relevant control related to the determination of the decommissioning specific inflation rate assumption.

• We tested how management derived the decommissioning specific inflation rate assumption of 1.5%, and the evidence on which it is based, by

gaining an understanding of the process used by management, testing management's calculations of the assumption, and evaluating the

evidence relevant to management's assumption, both supporting and contradictory.

• As the 1.5% decommissioning specific inflation rate assumption is determined by making an adjustment to management's 2.0% general long

term inflation rate assumption, we evaluated the general long term inflation rate assumption used of 2.0%, comparing it against latest external

market data.

• We made inquiries and evaluated the competence, capability and objectivity of management's decommissioning experts who derived the

decommissioning specific inflation rate.

• We inspected analyst forecasts and reports in respect of the future decommissioning market and related costs for evidence of supporting and

contradictory evidence, with particular focus on the future rig market.

• We particularly considered the expectation that demand for oil and gas products and related activities will decrease, primarily in response to

climate change and energy transition effects pivoting future energy industry investment and development activity towards renewable sources.

We challenged and evaluated management's assessment of the impact this will have on the decommissioning market and the related inflation

assumption.

• We analysed historical trends of rig market rates against oil prices and historical inflation to evaluate management's assumption that the

decommissioning inflation assumption does not inflate at the same rate as general inflation.

**Cost and timing estimates**

• We tested the relevant controls over the year end decommissioning cost and timing assumptions used within management's decommissioning

provision estimate.

• We assessed the completeness and accuracy of the assets subject to decommissioning, including understanding the process to establish

whether a legal or constructive obligation existed.

• We gained an understanding of the process and technology used to model the provision, including the use of bp's decommissioning modelling

platform by management's experts. We used data analytics to automatically extract and analyse cost estimate data to identify the key cost

assumptions which the decommissioning model is most materially sensitive to.

• We evaluated the reasonableness of changes in the key cost assumptions including rig rates, vessel rates, well plug and abandonment duration

and non-productive time assumptions, with reference to internal and appropriate third-party data.

• We assessed changes in assumptions for the estimated date of decommissioning and evaluated whether CoP dates used for decommissioning

estimation are aligned with CoP assumptions in other areas, including PP&E impairment testing and oil and gas reserve estimation.

• We assessed the accuracy of bp's disclosure of the estimated undiscounted cost of its obligations and the timing of future decommissioning

payments.

**Discount rates**

• We tested the relevant controls related to the determination of the discount rate assumption.

• We assessed the reasonableness of management's methodology for determining the discount rate and recalculated the discount rate with

reference to independent third-party data, most notably US treasury bond yields.

**3. Valuation of commodity financial derivatives - Notes 1, 29 and 30 to the financial statements**

Critical Audit Matter Description

bp's supply, trading and shipping (ST&S) function is responsible for globally trading and risk managing the group's owned production as well as

third party production. To discharge this responsibility, ST&S regularly executes commodity contracts, physically settled or otherwise, which are

accounted for as a derivative and fair valued under IFRS 9. These contracts, therefore, result in unrealised gains/losses that are recognised on

account of fair value movements in the associated derivative assets and liabilities.

Determining the fair value of derivative assets and liabilities can be complex and subjective, particularly where the valuation is dependent on

significant inputs which are not observable and are classified as level 3 in the fair value hierarchy set out in IFRS 13. This degree of subjectivity also

makes such fair value estimates liable to potential fraud by management incorporating bias in the inputs used in determining fair values. Given the

significant judgements, sensitivity to management assumptions, and the absolute value associated with these positions, we have identified a risk in

respect of certain financial instruments where the valuation is dependent on significant unobservable inputs.

Fair value measurements associated with unrealised commodity contracts are also impacted by the macroeconomic sentiment and outlook. In

2025, commodity markets continued to experience periods of volatility due to continuing uncertainty resulting from the planned energy transition,

macro-economic factors such as inflation and interest rates, and disruptions in global supply due to geopolitical conflicts. In response to the

volatility observed, we focused our audit efforts on the valuation of commodity derivatives and designed procedures to test for management bias.

As at 31 December 2025, the group's total level 3 derivative financial assets were $20.1 billion and level 3 derivative financial liabilities were $18.2

billion.

How the Critical Audit Matter was addressed in the Audit

In response to the above, we analysed the population of these instruments to assess the level of unobservability of the inputs used in their

valuation and then further disaggregated the population into different risk populations which in turn drove the nature, timing and extent of our

audit procedures.

Our use of advanced data analytics tools enabled automated visualisation of valuation data providing insights into trading positions and price

curves. This allowed us to identify unusual trends, and focus our audit efforts on complex inputs, methodologies, and anomalies within the

significant volume of derivative contracts, thereby enhancing the precision and the effectiveness of our valuation testing and our assessment of

potential management bias.

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| 152 | bp Annual Report and Form 20-F 2025 |

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To address the complexities associated with auditing the valuation of instruments dependent on significant unobservable inputs, we included

valuation specialists with significant quantitative and modelling expertise to assist in performing our audit procedures. Our valuation audit work

included the following control and substantive procedures:

• We tested the group's valuation relevant controls including:

–the model certification control, which is designed to review a model's theoretical soundness and the appropriateness of its valuation

methodology; and

–the independent price verification control, which is designed to review the appropriateness of valuation inputs that are not observable and are

significant to the financial instrument's valuation.

• We performed valuation testing procedures at interim and year-end balance sheet dates, including:

–evaluating management's valuation methodologies against standard valuation practice and analysing whether a consistent framework is

applied across the business period over period;

–engaging our valuation specialists to challenge models, develop fair value estimates and evaluate consistency in management's modelling and

input assumptions throughout the year;

–comparing management's input assumptions against the expected assumptions of other market participants and observable market data;

–independently validating price points on pricing curves; and

–analysing whether there was any indication of management bias through evaluating the distribution of valuation differences where relevant.

**4. Impairment of E&A assets, goodwill associated with the transition businesses and refinery PP&E as a consequence, among** 

**other things, of climate change and the energy transition – Notes 1, 4, 8, 14 and 15 to the financial statements**

Critical Audit Matter Description

**Intangible Assets**

The recoverability of certain of the group's $4.0 billion total exploration and appraisal (E&A) assets capitalised as at 31 December 2025 is potentially

exposed to climate change and the global energy transition and macroeconomic risk factors (see Note 15). This is because a greater number of E&A

projects may not proceed as a consequence of the energy transition or lower forecast future oil and gas prices. The determination of whether and

when E&A costs should be written off, impaired, or retained on the balance sheet as E&A assets, remains complex and continues to require

significant management judgement.

**Goodwill**

The carrying value of goodwill associated with the transition businesses, specifically Archaea Energy and Lightsource bp, may no longer be

recoverable due to increases in cost or lower forecast production or development rate reflecting the slowdown in the pace of energy transition

adversely impacting the value of these projects, and impacting investment decisions. Management performed an annual impairment test (which

includes judgements in relation to forecast period, development rate, long term growth rate, discount rate, developer margin, capital expenditure

and renewable natural gas revenue prices) to assess the recoverability of the goodwill, resulting in an impairment of $2.0 billion as disclosed in

Note 14.

**PP&E**

The carrying value of bp's refining assets within PP&E may no longer be recoverable due to changes in supply and demand which arise among other

things as a consequence of climate change and the energy transition. Management performed an assessment to identify potential impairment

indicators in respect of the refinery portfolio. This considered all potential impairment indicators, including refining margin forecast, which could be

impacted by changes in supply and demand due to climate change and the energy transition. As a result of management's impairment assessment,

management identified indicators of impairment within the refining portfolio as at 31 December 2025 and concluded that no impairment charge

needed to be recorded.

How the Critical Audit Matter Was Addressed in the Audit

**Intangible Assets** 

In respect of the recoverability of E&A assets capitalised as at 31 December 2025:

• We tested the relevant controls within the group's E&A write-off and impairment assessment processes; and

• We challenged and evaluated management's key E&A judgements with regards to the impairment criteria of IFRS 6. Where impairment

indicators were identified, we corroborated key judgements with internal and external evidence for assets that remained on the balance sheet.

This included analysing evidence of future E&A plans, budgets and capital allocation decisions, assessing management's key accounting

judgement papers, reading meeting minutes and assessing licence documentation and evidence of active dialogue with partners and regulators

including negotiations to renew licences or modify key terms.

**Goodwill**

In respect of the impairment tests performed on goodwill associated with the transition businesses, specifically Archaea Energy and Lightsource

bp, performed at 31 December 2025:

• We tested the relevant controls over the impairment tests including controls over key assumptions;

• We independently evaluated bp's discount rates used in impairment tests with input from our valuation specialists, against relevant third- party

market and peer data;

• We independently evaluated the long-term production rates for certain transition businesses with input from our Deloitte Landfill Production

Specialists;

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| bp Annual Report and Form 20-F 2025 | 153 |

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|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

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• We evaluated the appropriateness of other key assumptions including forecast period, development rate, long term growth rate, discount rate,

developer margin, capital expenditure, and renewable natural gas revenue prices through assessment of bp's future plans and consistency with

the capital frame; and

• We tested the mechanical accuracy of the impairment models.

**PP&E**

In relation to the refinery impairment tests performed by management, our audit procedures included:

• Evaluating the valuation methodology and testing the integrity and mechanical accuracy of the impairment models;

• Assessing the appropriateness of key assumptions and inputs to the impairment models, notably forecast local refining marker margins,

discount rate and energy input costs;

• Challenging and evaluating management's assumptions by reference to third party data where available and involvement of our valuation

specialists;

• Evaluating management's ability to forecast future cash flows and margins by comparing actual results with historical forecasts; and

• Testing management's internal controls over the impairment test and related inputs.

/s/ Deloitte LLP

London

United Kingdom

6 March 2026

We have served as bp's auditor since 2018.

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| 154 | bp Annual Report and Form 20-F 2025 |

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Report of Independent Registered Public Accounting Firm

**To the shareholders and board of directors of BP p.l.c.**

**Opinion on internal control over financial reporting** 

We have audited the internal control over financial reporting of BP p.l.c. and its subsidiaries (the group) as of 31 December 2025, based on the

criteria established in *Internal Control — Integrated Framework (2013*) issued by the Committee of Sponsoring Organizations of the Treadway

Commission (COSO). In our opinion, the group maintained, in all material respects, effective internal control over financial reporting as of

31 December 2025, based on the criteria established in *Internal Control - Integrated Framework (2013)* issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the

consolidated financial statements as at and for the year ended 31 December 2025, of the group and our report dated 6 March 2026 expressed an

unqualified opinion on those financial statements.

**Basis for opinion**

The Group's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the

effectiveness of internal control over financial reporting, included in the accompanying Management's report on internal control over financial

reporting. Our responsibility is to express an opinion on the group's internal control over financial reporting based on our audit. We are a public

accounting firm registered with the PCAOB and are required to be independent with respect to the group in accordance with the U.S. federal

securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain

reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included

obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating

the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered

necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

**Definition and limitations of internal control over financial reporting** 

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial

reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A

company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in

reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance

that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting

principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and

directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or

disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any

evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that

the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte LLP

London, United Kingdom

6 March 2026

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| bp Annual Report and Form 20-F 2025 | 155 |

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|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

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Group income statement

---

| | | | | |
|:---|:---|:---|:---|:---|
| For the year ended 31 December |  |  |  | $ million |
|  | Note | **2025** | 2024 | 2023 |
| Sales and other operating revenues | 6 | **189335** | 189185 | 210130 |
| Earnings from joint ventures – after interest and tax | 16 | **(300)** | 909 | 67 |
| Earnings from associates – after interest and tax | 17 | **918** | 1084 | 831 |
| Interest and other income | 7 | **1609** | 2773 | 1635 |
| Gains on sale of businesses and fixed assets | 4 | **987** | 678 | 369 |
| **Total revenues and other income** |  | **192549** | 194629 | 213032 |
| Purchases | 19 | **110640** | 113941 | 119307 |
| Production and manufacturing expenses |  | **25646** | 26584 | 25044 |
| Production and similar taxes | 5 | **1698** | 1799 | 1779 |
| Depreciation, depletion and amortization | 5 | **17822** | 16622 | 15928 |
| Net impairment and losses on sale of businesses and fixed assets | 4 | **6037** | 6995 | 5857 |
| Exploration expense | 8 | **570** | 974 | 997 |
| Distribution and administration expenses |  | **17494** | 16417 | 16772 |
| **Profit (loss) before interest and taxation** |  | **12642** | 11297 | 27348 |
| Finance costs | 7 | **5106** | 4683 | 3840 |
| Net finance (income) expense relating to pensions and other post-employment benefits | 24 | **(210)** | (168) | (241) |
| **Profit (loss) before taxation** |  | **7746** | 6782 | 23749 |
| Taxation | 9 | **6451** | 5553 | 7869 |
| **Profit (loss) for the year** |  | **1295** | 1229 | 15880 |
| Attributable to |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;bp shareholders |  | **55** | 381 | 15239 |
| &nbsp;&nbsp;&nbsp;&nbsp;Non-controlling interests |  | **1240** | 848 | 641 |
|  |  | **1295** | 1229 | 15880 |
| **Earnings per share** |  |  |  |  |
| Profit (loss) for the year attributable to bp shareholders |  |  |  |  |
| Per ordinary share (cents) |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Basic | 11 | **0.35** | 2.38 | 87.78 |
| &nbsp;&nbsp;&nbsp;&nbsp;Diluted | 11 | **0.34** | 2.32 | 85.85 |
| Per ADS (dollars) |  |  |  |  |
| Basic | 11 | **0.02** | 0.14 | 5.27 |
| Diluted | 11 | **0.02** | 0.14 | 5.15 |

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|:---|:---|
| 156 | bp Annual Report and Form 20-F 2025 |

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Group statement of comprehensive income

---

| | | | | |
|:---|:---|:---|:---|:---|
| For the year ended 31 December |  |  |  | $ million  |
|  | Note | **2025** | 2024 | 2023 |
| Profit (loss) for the year |  | **1295** | 1229 | 15880 |
| Other comprehensive income |  |  |  |  |
| **Items that may be reclassified subsequently to profit or loss** |  |  |  |  |
| Currency translation differences<sup>a</sup> |  | **1863** | (1292) | 585 |
| Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on <br>sale of businesses and fixed assets<sup>a</sup><br>|  | **41** | 1004 | (2) |
| Cash flow hedges marked to market | 30 | **287** | 155 | 1065 |
| Cash flow hedges reclassified to the income statement | 30 | **(127)** | (686) | (428) |
| Costs of hedging marked to market | 30 | **27** | (2) | (67) |
| Costs of hedging reclassified to the income statement | 30 | **34** | (2) | (11) |
| Share of items relating to equity-accounted entities, net of tax | 16, 17 | **(4)** | (12) | (192) |
| Income tax relating to items that may be reclassified | 9 | **(22)** | 48 | (10) |
|  |  | **2099** | (787) | 940 |
| **Items that will not be reclassified to profit or loss** |  |  |  |  |
| Remeasurements of the net pension and other post-employment benefit liability or asset | 24 | **(221)** | (360) | (2262) |
| Remeasurements of equity investments |  | **(6)** | (47) | 51 |
| Cash flow hedges that will subsequently be transferred to the balance sheet | 30 | **5** | (1) | 15 |
| Income tax relating to items that will not be reclassified<sup>a</sup> | 9 | **55** | 734 | 745 |
|  |  | **(167)** | 326 | (1451) |
| Other comprehensive income |  | **1932** | (461) | (511) |
| **Total comprehensive income** |  | **3227** | 768 | 15369 |
| Attributable to |  |  |  |  |
| bp shareholders |  | **1872** | 7 | 14702 |
| Non-controlling interests |  | **1355** | 761 | 667 |
|  |  | **3227** | 768 | 15369 |

---

aSee Note 32 for further information.

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| bp Annual Report and Form 20-F 2025 | 157 |

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|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

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Group statement of changes in equity<sup>a</sup>

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  |  | $ million |
| | **Share** <br>**capital and** <br>**capital** <br>**reserves** | **Treasury** <br>**shares** | **Foreign** <br>**currency** <br>**translation** <br>**reserve** | **Fair value** <br>**reserves** | **Profit and** <br>**loss** <br>**account** | **bp** <br>**shareholders'** <br>**equity** | **Non-controlling interests** | **Non-controlling interests** | **Total equity** |
| | **Share** <br>**capital and** <br>**capital** <br>**reserves** | **Treasury** <br>**shares** | **Foreign** <br>**currency** <br>**translation** <br>**reserve** | **Fair value** <br>**reserves** | **Profit and** <br>**loss** <br>**account** | **bp** <br>**shareholders'** <br>**equity** | **Hybrid** <br>**bonds**<br>| **Other** <br>**interest**<br>| **Total equity** |
| **At 1 January 2025** | **48229** | **(9030)** | **(2196)** | **(288)** | **22531** | **59246** | **16649** | **2423** | **78318** |
| Profit for the year | **—** | **—** | **—** | **—** | **55** | **55** | **799** | **441** | **1295** |
| Other comprehensive income | **—** | **—** | **1804** | **183** | **(170)** | **1817** | **—** | **115** | **1932** |
| **Total comprehensive income** | **—** | **—** | **1804** | **183** | **(115)** | **1872** | **799** | **556** | **3227** |
| Dividends<sup>b</sup> | **—** | **—** | **—** | **—** | **(5087)** | **(5087)** | **—** | **(524)** | **(5611)** |
| Cash flow hedges transferred to the balance <br>sheet, net of tax<br>| **—** | **—** | **—** | **(6)** | **—** | **(6)** | **—** | **—** | **(6)** |
| Repurchase of ordinary share capital | **—** | **(3558)** | **—** | **—** | **(454)** | **(4012)** | **—** | **—** | **(4012)** |
| Share-based payments, net of tax | **35** | **3917** | **—** | **—** | **(2840)** | **1112** | **—** | **—** | **1112** |
| Share of equity-accounted entities' changes <br>in equity, net of tax<br>| **—** | **—** | **—** | **—** | **1** | **1** | **—** | **—** | **1** |
| Issue of perpetual hybrid bonds | **—** | **—** | **—** | **—** | **—** | **—** | **500** | **—** | **500** |
| Redemption of perpetual hybrid bonds, net <br>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;of tax<br>| **—** | **—** | **—** | **—** | **—** | **—** | **(1200)** | **—** | **(1200)** |
| Payments on perpetual hybrid bonds | **—** | **—** | **(9)** | **—** | **—** | **(9)** | **(793)** | **—** | **(802)** |
| Transactions involving non-controlling <br>interests, net of tax<br>| **—** | **—** | **—** | **—** | **(65)** | **(65)** | **—** | **2538** | **2473** |
| **At 31 December 2025** | **48264** | **(8671)** | **(401)** | **(111)** | **13971** | **53052** | **15955** | **4993** | **74000** |
| **At 1 January 2024** | 48013 | (11323) | (1920) | 174 | 35339 | 70283 | 13566 | 1644 | 85493 |
| Profit for the year |  |  |  |  | 381 | 381 | 641 | 207 | 1229 |
| Other comprehensive income |  |  | (276) | (452) | 354 | (374) |  | (87) | (461) |
| **Total comprehensive income** |  |  | (276) | (452) | 735 | 7 | 641 | 120 | 768 |
| Dividends<sup>b</sup> |  |  |  |  | (5018) | (5018) |  | (375) | (5393) |
| Cash flow hedges transferred to the balance <br>sheet, net of tax<br>|  |  |  | (10) |  | (10) |  |  | (10) |
| Repurchase of ordinary share capital |  |  |  |  | (7302) | (7302) |  |  | (7302) |
| Share-based payments, net of tax | 216 | 2293 |  |  | (1426) | 1083 |  |  | 1083 |
| Issue of perpetual hybrid bonds |  |  |  |  | (22) | (22) | 4352 |  | 4330 |
| Redemption of perpetual hybrid bonds, net <br>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;of tax<br>|  |  |  |  | 9 | 9 | (1300) |  | (1291) |
| Payments on perpetual hybrid bonds |  |  |  |  |  |  | (610) |  | (610) |
| Transactions involving non-controlling <br>interests, net of tax <br>|  |  |  |  | 216 | 216 |  | 1034 | 1250 |
| **At 31 December 2024** | 48229 | (9030) | (2196) | (288) | 22531 | 59246 | 16649 | 2423 | 78318 |
| **At 1 January 2023** | 47873 | (12153) | (2643) | (256) | 34732 | 67553 | 13390 | 2047 | 82990 |
| Profit for the year |  |  |  |  | 15239 | 15239 | 586 | 55 | 15880 |
| Other comprehensive income |  |  | 728 | 431 | (1696) | (537) |  | 26 | (511) |
| **Total comprehensive income** |  |  | 728 | 431 | 13543 | 14702 | 586 | 81 | 15369 |
| Dividends<sup>b</sup> |  |  |  |  | (4831) | (4831) |  | (403) | (5234) |
| Cash flow hedges transferred to the balance <br>sheet, net of tax<br>|  |  |  | (1) |  | (1) |  |  | (1) |
| Repurchase of ordinary share capital |  |  |  |  | (8167) | (8167) |  |  | (8167) |
| Share-based payments, net of tax | 140 | 830 |  |  | (301) | 669 |  |  | 669 |
| Share of equity-accounted entities' changes <br>in equity, net of tax<br>|  |  |  |  | 1 | 1 |  |  | 1 |
| Issue of perpetual hybrid bonds |  |  |  |  | (1) | (1) | 176 |  | 175 |
| Payments on perpetual hybrid bonds |  |  | (5) |  |  | (5) | (586) |  | (591) |
| Transactions involving non-controlling <br>interests, net of tax<br>|  |  |  |  | 363 | 363 |  | (81) | 282 |
| **At 31 December 2023** | 48013 | (11323) | (1920) | 174 | 35339 | 70283 | 13566 | 1644 | 85493 |

---

aSee Note 32 for further information.

bSee Note 10 for further information.

---

| | |
|:---|:---|
| 158 | bp Annual Report and Form 20-F 2025 |

---

Group balance sheet

---

| | | | |
|:---|:---|:---|:---|
| At 31 December |  |  | $ million |
|  | Note | **2025** | 2024 |
| **Non-current assets** |  |  |  |
| Property, plant and equipment | 12 | **98633** | 100238 |
| Goodwill | 14 | **10300** | 14888 |
| Intangible assets | 15 | **8197** | 9646 |
| Investments in joint ventures | 16 | **13400** | 12291 |
| Investments in associates | 17 | **7325** | 7741 |
| Other investments | 18 | **857** | 1292 |
| **Fixed assets** |  | **138712** | 146096 |
| Loans |  | **1991** | 1961 |
| Trade and other receivables | 20 | **2376** | 1815 |
| Derivative financial instruments | 30 | **20957** | 16114 |
| Prepayments |  | **608** | 548 |
| Deferred tax assets | 9 | **4325** | 5403 |
| Defined benefit pension plan surpluses | 24 | **7771** | 7457 |
|  |  | **176740** | 179394 |
| **Current assets** |  |  |  |
| Loans |  | **457** | 223 |
| Inventories | 19 | **22499** | 23232 |
| Trade and other receivables | 20 | **26014** | 27127 |
| Derivative financial instruments | 30 | **5180** | 5112 |
| Prepayments |  | **3422** | 2594 |
| Current tax receivable |  | **1153** | 1096 |
| Other investments | 18 | **158** | 165 |
| Cash and cash equivalents | 25 | **36556** | 39204 |
|  |  | **95439** | 98753 |
| Assets classified as held for sale | 2 | **6347** | 4081 |
|  |  | **101786** | 102834 |
| **Total assets** |  | **278526** | 282228 |
| **Current liabilities** |  |  |  |
| Trade and other payables | 22 | **56843** | 58411 |
| Derivative financial instruments | 30 | **4413** | 4347 |
| Accruals |  | **5572** | 6071 |
| Lease liabilities | 28 | **2832** | 2660 |
| Finance debt | 26 | **3356** | 4474 |
| Current tax payable |  | **1262** | 1573 |
| Provisions | 23 | **4709** | 3600 |
|  |  | **78987** | 81136 |
| Liabilities directly associated with assets classified as held for sale | 2 | **1594** | 1105 |
|  |  | **80581** | 82241 |
| **Non-current liabilities** |  |  |  |
| Other payables | 22 | **7975** | 9409 |
| Derivative financial instruments | 30 | **19667** | 18532 |
| Accruals |  | **1834** | 1326 |
| Lease liabilities | 28 | **11739** | 9340 |
| Finance debt | 26 | **54602** | 55073 |
| Deferred tax liabilities | 9 | **7642** | 8428 |
| Provisions | 23 | **15670** | 14688 |
| Defined benefit pension plan and other post-employment benefit plan deficits | 24 | **4816** | 4873 |
|  |  | **123945** | 121669 |
| **Total liabilities** |  | **204526** | 203910 |
| **Net assets** |  | **74000** | 78318 |
| Equity |  |  |  |
| bp shareholders' equity | 32 | **53052** | 59246 |
| Non-controlling interests | 32 | **20948** | 19072 |
| **Total equity** | 32 | **74000** | 78318 |

---

Albert Manifold Chair

Carol Howle Interim Chief executive officer

6 March 2026

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 159 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

Group cash flow statement

---

| | | | | |
|:---|:---|:---|:---|:---|
| For the year ended 31 December |  |  |  | $ million |
|  | Note | **2025** | 2024 | 2023 |
| **Operating activities** |  |  |  |  |
| Profit (loss) before taxation |  | **7746** | 6782 | 23749 |
| Adjustments to reconcile profit before taxation to net cash provided by operating activities |  |  |  |  |
| Exploration expenditure written off | 8 | **343** | 767 | 746 |
| Depreciation, depletion and amortization | 5 | **17822** | 16622 | 15928 |
| Impairment and (gain) loss on sale of businesses and fixed assets | 4 | **5050** | 6317 | 5488 |
| Earnings from joint ventures and associates |  | **(618)** | (1993) | (898) |
| Dividends received from joint ventures and associates |  | **2111** | 2023 | 2092 |
| Remeasurement of joint ventures | 3 | **—** | (917) |  |
| Interest receivable |  | **(1352)** | (1512) | (1265) |
| Interest received |  | **1223** | 1450 | 1119 |
| Finance costs | 7 | **5106** | 4683 | 3840 |
| Interest paid |  | **(3538)** | (2811) | (2950) |
| Net finance expense relating to pensions and other post-employment benefits | 24 | **(210)** | (168) | (241) |
| Share-based payments |  | **1077** | 1174 | 616 |
| Net operating charge for pensions and other post-employment benefits, less contributions <br>and benefit payments for unfunded plans<br>| 24 | **(152)** | (182) | (193) |
| Net charge for provisions, less payments |  | **1294** | (152) | (2481) |
| (Increase) decrease in inventories |  | **1622** | 808 | 5634 |
| (Increase) decrease in other current and non-current assets |  | **(4286)** | 3355 | 4620 |
| Increase (decrease) in other current and non-current liabilities |  | **(2156)** | (188) | (13592) |
| Income taxes paid |  | **(6589)** | (8761) | (10173) |
| **Net cash provided by operating activities** |  | **24493** | 27297 | 32039 |
| **Investing activities** |  |  |  |  |
| Expenditure on property, plant and equipment, intangible and other assets |  | **(13221)** | (15297) | (14285) |
| Acquisitions, net of cash acquired | 3 | **(935)** | 53 | (799) |
| Investment in joint ventures |  | **(267)** | (850) | (1039) |
| Investment in associates |  | **(110)** | (143) | (130) |
| **Total cash capital expenditure** |  | **(14533)** | (16237) | (16253) |
| Proceeds from disposals of fixed assets | 4 | **1142** | 328 | 133 |
| Proceeds from disposals of businesses, net of cash disposed | 4 | **1714** | 2578 | 1193 |
| Proceeds from loan repayments |  | **173** | 81 | 55 |
| **Net cash used in investing activities** |  | **(11504)** | (13250) | (14872) |
| **Financing activities** |  |  |  |  |
| Repurchase of shares |  | **(4486)** | (7127) | (7918) |
| Lease liability payments |  | **(3091)** | (2833) | (2560) |
| Proceeds from long-term financing |  | **2724** | 10656 | 7568 |
| Repayments of long-term financing |  | **(5695)** | (2970) | (3902) |
| Net increase (decrease) in short-term debt |  | **(343)** | (2966) | (861) |
| Issue of perpetual hybrid bonds |  | **500** | 4330 | 175 |
| Redemption of perpetual hybrid bonds | 32 | **(1200)** | (1288) |  |
| Payments relating to perpetual hybrid bonds |  | **(1196)** | (1053) | (1008) |
| Payments relating to transactions involving non-controlling interests (other) |  | **(2)** | (21) | (187) |
| Receipts relating to transactions involving non-controlling interests (other) |  | **2474** | 1353 | 546 |
| Dividends paid |  |  |  |  |
| bp shareholders | 10 | **(5059)** | (5003) | (4809) |
| Non-controlling interests |  | **(506)** | (375) | (403) |
| **Net cash provided by (used in) financing activities** |  | **(15880)** | (7297) | (13359) |
| Currency translation differences relating to cash and cash equivalents |  | **246** | (511) | 27 |
| Increase (decrease) in cash and cash equivalents |  | **(2645)** | 6239 | 3835 |
| Cash and cash equivalents at beginning of year |  | **39269** | 33030 | 29195 |
| **Cash and cash equivalents at end of year**<sup>a</sup> |  | **36624** | 39269 | 33030 |

---

a 2025 and 2024 include cash and cash equivalents classified as assets held for sale in the group balance sheet. See Note 2 for further information.

---

| | |
|:---|:---|
| 160 | bp Annual Report and Form 20-F 2025 |

---

Notes on financial statements

**1. Material accounting policy information, significant judgements, estimates and assumptions** 

**Authorization of financial statements and statement of compliance with International Financial Reporting Standards**

The consolidated financial statements of BP p.l.c and its subsidiaries (collectively referred to as bp or the group) were approved and signed by the

interim chief executive officer and chairman on 6 March 2026 having been duly authorized to do so by the board of directors. BP p.l.c. is a public

limited company incorporated and domiciled in England and Wales. The consolidated financial statements have been prepared in accordance with

IFRS Accounting Standards® (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the UK, and European

Union (EU), and in accordance with the provisions of the UK Companies Act 2006 as applicable to companies reporting under international

accounting standards. IFRS as adopted by the UK does not differ from IFRS as adopted by the EU. IFRS as adopted by the UK and EU differs in

certain respects from IFRS as issued by the IASB. The differences have no impact on the group's consolidated financial statements for the years

presented. The material accounting policy information and accounting judgements, estimates and assumptions of the group are set out below.

**Basis of preparation**

The consolidated financial statements have been prepared on a going concern basis and in accordance with IFRSs and IFRS Interpretations

Committee (IFRIC) interpretations issued and effective for the year ended 31 December 2025. The accounting policies that follow have been

consistently applied to all years presented, except where otherwise indicated.

The consolidated financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where

otherwise indicated.

**Material accounting policy information: use of judgements, estimates and assumptions**

Inherent in the application of many of the accounting policies used in preparing the consolidated financial statements is the need for bp

management to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of

contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and

assumptions used. The accounting judgements and estimates that have a significant impact on the results of the group are set out in boxed text

below, and should be read in conjunction with the information provided in the Notes on financial statements.

The areas requiring the most significant judgement and estimation in the preparation of the consolidated financial statements are: accounting for

the investments in Rosneft and Aker BP; exploration and appraisal intangible assets; the recoverability of asset carrying values, including the

estimation of reserves; supplier financing arrangements; derivative financial instruments; provisions and contingencies; pensions and other post-

employment benefits; and taxation. Judgements and estimates, not all of which are significant, made in assessing the impact of the current

economic and geopolitical environment, and climate change and the transition to a lower carbon economy on the consolidated financial

statements are also set out in boxed text below. Where an estimate has a significant risk of resulting in a material adjustment to the carrying

amounts of assets and liabilities within the next financial year this is specifically noted within the boxed text.

---

| |
|:---|
| Judgements and estimates made in assessing the impact of climate change and the transition to a lower carbon economy |
| Climate change and the transition to a lower carbon economy were considered in preparing the consolidated financial statements. These may <br>have significant impacts on the currently reported amounts of the group's assets and liabilities discussed below and on similar assets and <br>liabilities that may be recognized in the future. The group's assumptions for investment appraisal form part of an investment decision-making <br>framework for currently unsanctioned future capital expenditure on property, plant and equipment, and intangibles including exploration and <br>appraisal assets, that is designed to support the effective and resilient implementation of bp's strategy. The price assumptions used for <br>investment appraisal include oil and gas price assumptions, which are producer prices and are therefore net of any future carbon prices that the <br>purchaser may be required to pay, and an assumption of a single carbon emissions cost imposed on the producer in respect of operational <br>greenhouse gas (GHG) emissions (carbon dioxide and methane) in order to incentivize engineering solutions to mitigate GHG emissions on <br>projects. The group's oil and gas price assumptions for value-in-use impairment testing are aligned with those investment appraisal assumptions. <br>The assumptions for future carbon emissions costs in value-in-use impairment testing differ from the investment appraisal assumptions and are <br>described below. <br>Management has also not identified any off-balance sheet commodity purchase obligations to be onerous contracts as result of the transition to <br>a lower carbon economy at 31 December 2025.<br>|
| **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 <br>amount of property, plant and equipment and goodwill in the oil and gas industry. Management's best estimate of oil and natural gas price <br>assumptions for value-in-use impairment testing were revised during 2025. The revised price assumptions have been rebased in real 2024 terms. <br>Brent oil prices in real 2024 terms were reduced in the short-term reflecting greater crude supply. Medium to long term prices steadily decline to <br>a higher price of $60 per barrel in 2050 continuing to reflect the assumption that the energy system decarbonises but at a slower rate. The price <br>assumptions for Henry Hub gas price have been reduced in the short term, reflecting higher supply in the market. Prices then steadily increase in <br>the medium term, as supply and demand rebalance before remaining steady at $4.50 per mmBtu up to 2050. The revised assumptions for Brent <br>oil and Henry Hub gas sit within the range of external scenarios considered by management and are in line with a range of transition paths, as <br>collated into the Transition Scenario Catalogue we use in our TCFD assessment, that are considered by source data providers (such as IEA, UN PRI <br>IPR and NGFS) to be consistent with holding the increase in the global average temperature to well below 2°C above pre-industrial levels and <br>pursuing efforts to limit the temperature increase to 1.5°C above pre-industrial levels.<br>|

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 161 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

---

| |
|:---|
| As noted above, the group's investment appraisal process includes a carbon emissions price series for the investment economics which is applied <br>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 <br>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 <br>(CGUs), consistent with all other relevant cash flows estimated, bp is required to reflect management's best estimate of any expected applicable <br>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. <br>This requires management's best estimate of how future changes to relevant carbon emission cost policies and/or legislation are likely to affect <br>the future cash flows of the group's applicable CGUs, whether currently enacted or not. Future potential carbon pricing and/or costs of carbon <br>emissions allowances are included in the value-in-use calculations to the extent management has sufficient information to make such an <br>estimate. Currently this results in limited application of carbon price assumptions in value-in-use impairment tests given that carbon pricing <br>legislation in most impacted jurisdictions where the group has interests is not in place and there is not sufficient information available as to the <br>relevant policy makers' future intentions regarding carbon pricing to support an estimate. A key input into the determination of impairment is the <br>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 <br>gas properties and refining assets will have an immaterial carrying value by 2050. <br>|
| 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 <br>jurisdiction, this is incorporated into the value-in use impairment testing cash flows. The most significant instances where a carbon price has been <br>incorporated in the 2025 value-in-use impairment tests is for the UK North Sea. The assumptions for UK North Sea were £65/tCO2e in 2026 <br>gradually increasing to £243/tCO2e in 2050. <br>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 <br>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 <br>of such costs were to become widespread, the gross oil and gas prices realized by producers would be correspondingly higher over the long <br>term, resulting in no expected overall materially negative impacts on the group's net cash flows. See significant judgements and estimates: <br>recoverability of asset carrying values for further information including sensitivity analysis in relation to reasonably possible changes in the price <br>assumptions and carbon costs. <br>Production assumptions within upstream property, plant and equipment and goodwill value-in-use impairment tests reflect management's <br>current best estimate of future production of the existing upstream portfolio. See significant judgements and estimates: recoverability of asset <br>carrying values and Note 14 for sensitivity analyses in relation to reasonably possible changes in production for upstream oil and gas properties <br>and goodwill respectively.<br>For the customers & products segment, though the energy transition may impact demand for certain refined products in the future, management <br>anticipates sufficiently robust demand for the remainder of each refinery's useful life.<br>Management will continue to review price assumptions as the energy transition progresses and this may result in impairment charges or <br>reversals in the future. <br>|
| **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 <br>appraisal intangible assets was considered during 2025. No significant write-offs were identified. These assets will continue to be assessed as the <br>energy transition progresses. See significant judgement: exploration and appraisal intangible assets and Note 8 for further information. <br>|
| **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 <br>significant majority of bp's existing upstream oil and natural gas properties are likely to have immaterial carrying values within the next 12 years <br>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 <br>significant majority of refining assets, recognized on the group's balance sheet at 31 December 2025 that are subject to depreciation, will be <br>depreciated within the next 11 years; demand for refined products is expected to remain sufficient to support the remaining useful lives of existing <br>assets. Therefore, management does not expect the useful lives of bp's reported property, plant and equipment to change and do not consider <br>this to be a significant accounting judgement or estimate. Significant capital expenditure is still required for ongoing projects as well as renewal <br>and/or replacement of aged assets and therefore the useful lives of future capital expenditure may be different. See material accounting policy: <br>property, plant and equipment for more information. <br>|

---

---

| | |
|:---|:---|
| 162 | bp Annual Report and Form 20-F 2025 |

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**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 <br>decommissioning provisions. The majority of bp's existing upstream oil and gas properties are expected to start decommissioning within the next <br>two decades. Currently, the expected timing of decommissioning expenditures for the upstream oil and gas assets in the group's portfolio has <br>not materially been brought forward. Management does not expect a reasonably possible change of two years in the expected timing of all <br>decommissioning to have a material effect on the upstream decommissioning provisions, assuming cost assumptions remain unchanged. <br>Decommissioning cost estimates are based on the known regulatory and external environment. These cost estimates may change in the future, <br>including as a result of the transition to a lower carbon economy. For refineries, decommissioning provisions are generally not recognized as the <br>associated obligations have indeterminate settlement dates, typically driven by the cessation of manufacturing. Management does not expect <br>manufacturing to cease at refineries within a determinate period of time, as existing property, plant and equipment is expected to be renewed or <br>replaced. Management will continue to review facts and circumstances, including where cessation of manufacturing decisions have been made, <br>to assess if decommissioning provisions need to be recognized. Decommissioning provisions relating to refineries at 31 December 2025 are not <br>material. See significant judgements and estimates: provisions for further information.<br>|
| 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 <br>regards to the impact of the current geopolitical and economic environment. <br>|
| **Oil and gas price assumptions** |
| Oil and gas price assumptions applied in value-in-use impairment testing have been updated (as noted above) including for inflation and have <br>been rebased in real 2024 terms. See significant judgements and estimates: recoverability of asset carrying values for further information.<br>|
| **Discount rate assumptions** |
| The discount rates used for impairment testing and provisions were reassessed during the year in light of changing economic and geopolitical <br>outlooks. The impact on the nominal discount rate applied to provisions was determined not to be significant and so the rate remained <br>unchanged from 2024. The post-tax impairment discount rate remained consistent with 2024 as did the risk premium applied to the majority of <br>countries classified as higher-risk. See significant judgements and estimates: recoverability of asset carrying values and provisions for further <br>information. <br>|
| **Pensions and other post-employment benefits** |
| Volatility in financial markets impact assumptions used for determining the fair value of plan assets and the present value of defined benefit <br>obligations in the group's defined benefit pension plans. See significant estimate: pensions and other post-employment benefits and Note 24 for <br>further information.<br>|

---

**Basis of consolidation**

The group financial statements consolidate the financial statements of BP p.l.c. and its subsidiaries drawn up to 31 December each year.

Subsidiaries are consolidated from the date of their acquisition, being the date on which the group obtains control, including when control is

obtained via potential voting rights, and continue to be consolidated until the date that control ceases.

The financial statements of subsidiaries are prepared for the same reporting year as the parent company, using consistent accounting policies.

Intra-group balances and transactions, including unrealized profits arising from intra-group transactions, have been eliminated. Unrealized losses

are eliminated unless the transaction provides evidence of an impairment of the asset transferred.

Non-controlling interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to bp shareholders. Included within non-

controlling interests are perpetual subordinated hybrid bonds issued by subsidiaries and for which the group has the unconditional right to avoid

transferring cash or another financial asset to the holders. Profit or loss attributable to bp shareholders is adjusted to reflect the coupon/interest

related to these hybrid bonds whether or not such distribution has been deferred.

Also, included within non-controlling interests are perpetual subordinated hybrid securities and certain equity instruments with preferred

distribution rights issued by group subsidiaries.

Non-controlling interests are present ownership interests and entitle the holders to a share of the entity's net assets in the event of liquidation and

are initially measured at either:

(a) fair value; or

(b) the present ownership instruments' proportionate share in the recognized amounts of the subsidiary's' identifiable net assets.

The group enters certain arrangements with non-controlling Interest holders that have a complex equity structure with several classes of equity

shares or are subject to other contractual arrangements. These arrangements specify different entitlements to net profit allocations, equity and

liquidation preferences that differ from an ownership interest share of the entity's net assets. The group, for certain arrangements, also holds a

discretionary option to redeem the equity shares held by non-controlling interest shareholders, which becomes exercisable upon the occurrence of

a specified event or after a defined period. In such cases, the non-controlling Interest balance within equity is initially measured at fair value and the

non-controlling interest profit or loss allocation in line with the holders' economic entitlement. The non-controlling interest balance within equity is

not subsequently remeasured to fair value or redemption value but is adjusted for the profit or loss allocation, dividends and other transactions

with non-controlling interest holders.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 163 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

**Interests in other entities**

Business combinations and goodwill

Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities assumed are recognized at

their fair values at the acquisition date.

Goodwill is initially measured as the excess of the aggregate of the consideration transferred, the amount recognized for any non-controlling

interest and the acquisition-date fair values of any previously held interest in the acquiree over the fair value of the identifiable assets acquired and

liabilities assumed at the acquisition date. The amount recognized for any non-controlling interest is measured at the present ownership's

proportionate share in the recognized amounts of the acquiree's identifiable net assets. At the acquisition date, any goodwill acquired is allocated

to each of the cash-generating units, or groups of cash-generating units, expected to benefit from the combination's synergies. Following initial

recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill arising on business combinations prior to 1 January

2003 is stated at the previous carrying amount under UK generally accepted accounting practice, less subsequent impairments.

Goodwill may arise upon investments in joint ventures and associates, being the surplus of the cost of investment over the group's share of the net

fair value of the identifiable assets and liabilities. Any such goodwill is recorded within the corresponding investment in joint ventures and

associates.

Goodwill may also arise upon acquisition of interests in joint operations that meet the definition of a business. The amount of goodwill separately

recognized is the excess of the consideration transferred over the group's share of the net fair value of the identifiable assets and liabilities.

Interests in joint arrangements

The results, assets and liabilities of joint ventures are incorporated in these consolidated financial statements using the equity method of

accounting as described below.

Certain of the group's activities, particularly in the oil production & operations and gas & low carbon energy segments, are conducted through joint

operations. bp recognizes, on a line-by-line basis in the consolidated financial statements, its share of the assets, liabilities and expenses of these

joint operations incurred jointly with the other partners, along with the group's revenue from the sale of its share of the output and any liabilities

and expenses that the group has incurred in relation to the joint operation.

For joint arrangements in a separate entity, judgement may be required as to whether the arrangement should be classified as a joint venture or if

the legal form, contractual arrangements or other facts and circumstances indicate that the group has rights to the assets and obligations for the

liabilities of the arrangement, rather than rights to the net assets, and therefore should be classified as a joint operation. No such judgement made

by the group is considered significant.

Interests in associates

The results, assets and liabilities of associates are incorporated in these consolidated financial statements using the equity method of accounting

as described below.

---

| |
|:---|
| Significant judgement: investment in Aker BP |
| Judgement is required in assessing the level of control or influence over another entity in which the group holds an interest. For bp, the <br>judgement that the group has significant influence over Aker BP, a Norwegian oil and gas company, is significant. <br>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 <br>reserves is included in the group's estimated net proved reserves of equity-accounted entities. If significant influence was not present, the <br>investment would be accounted for as an investment in an equity instrument measured at fair value as described under 'Financial assets' below <br>and no share of Aker BP's oil and natural gas reserves would be reported.<br>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 <br>or joint control of those decisions. Significant influence is presumed when an entity owns 20% or more of the voting power of the investee. <br>Significant influence is presumed not to be present when an entity owns less than 20% of the voting power of the investee. <br>bp owned 15.9% of the voting shares at 31 December 2025. bp's senior vice president North Sea, Doris Reiter, was appointed a member of the Aker <br>BP board during 2024. bp's other nominated director, group chief financial officer, Kate Thomson, has been a member of the Aker BP board since <br>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 <br>general meetings of shareholders conferred by its stake in Aker BP. bp's management considers, therefore, that the group continues to have <br>significant influence at 31 December 2025.<br>|

---

---

| |
|:---|
| 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 <br>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 <br>probabilities to possible outcomes of any exit process. It is considered by management that any measure of fair value, other than nil, would be <br>subject to such high measurement uncertainty, considering the sanctions and restrictions implemented by Russia on Russian assets held by <br>foreign investors, that no estimate would provide useful information even if it were accompanied by a description of the estimate made in <br>producing it and an explanation of the uncertainties that affect the estimate. Accordingly, it is not currently possible to estimate any carrying <br>value other than zero when determining the measurement of the interest in Rosneft and the other businesses with Rosneft within Russia as at 31 <br>December 2025. Events or outcomes within the next financial year, that are different to those outlined above, could materially change the fair <br>value of the investment.<br>Russia has imposed restrictions on the payments of dividends to certain foreign shareholders, including those based in the UK, requiring such <br>dividends to be paid in roubles into restricted bank accounts and a requirement for approval of the Russian government for transfers from any <br>such bank accounts out of Russia. Given the restrictions applicable to such accounts, management has made the significant judgement that the <br>criteria for recognizing any dividend income from Rosneft and its other businesses with Rosneft within Russia, for the years to 31 December 2023, <br>31 December 2024 and 31 December 2025 have not been met. <br>|

---

---

| | |
|:---|:---|
| 164 | bp Annual Report and Form 20-F 2025 |

---

**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

**The equity method of accounting**

Under the equity method, an investment is carried on the balance sheet at cost plus post-acquisition changes in the group's share of net assets of

the entity, less distributions received and less any impairment in value of the investment. Loans advanced to equity-accounted entities that have

the characteristics of equity financing are also included in the investment on the group balance sheet. The group income statement reflects the

group's share of the results after tax of the equity-accounted entity, adjusted to account for depreciation, amortization and any impairment of the

equity-accounted entity's assets based on their fair values at the date of acquisition. The group statement of comprehensive income includes the

group's share of the equity-accounted entity's other comprehensive income. The group's share of amounts recognized directly in equity by an

equity-accounted entity is recognized in the group's statement of changes in equity.

Financial statements of equity-accounted entities are typically prepared for the same reporting year as the group. Where material differences arise

in the accounting policies used by the equity-accounted entity and those used by bp, adjustments are made to those financial statements to bring

the accounting policies used into line with those of the group. Unrealized gains on transactions, apart from those that meet the definition of a

derivative, between the group and its equity-accounted entities are eliminated to the extent of the group's interest in the equity-accounted entity.

This includes unrealized gains arising on contribution of a business on formation of an equity-accounted entity.

**Segmental reporting**

The group's operating segments are established on the basis of those components of the group that are evaluated regularly by the chief executive

officer, bp's chief operating decision maker, in deciding how to allocate resources and in assessing performance.

The accounting policies of the operating segments are the same as the group's accounting policies described in this note, except that IFRS requires

that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision

maker. For bp, this measure of profit or loss is replacement cost profit before interest and tax which reflects the replacement cost of inventories

sold in the period and is arrived at by excluding inventory holding gains and losses from profit before interest and tax. Replacement cost profit for

the group is not a recognized measure under IFRS.

During the first quarter 2025, the Archaea Energy business was moved from the customers & products segment to the gas & low carbon energy

segment. The change in segmentation is consistent with a change in the way that resources are allocated, and performance is assessed by the

chief operating decision maker, who for bp is the group chief executive.

Comparative information for 2024 has been restated where material to reflect the changes in reportable segments. For further information see

Note 5.

**Foreign currency translation**

In individual subsidiaries, joint ventures and associates, transactions in foreign currencies are initially recorded in the functional currency of those

entities at the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated

into the functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange differences are included in the income

statement, unless hedge accounting is applied. Non-monetary items, other than those measured at fair value, are not retranslated subsequent to

initial recognition.

In the consolidated financial statements, the assets and liabilities of non-US dollar functional currency subsidiaries, joint ventures, associates, and

related goodwill, are translated into US dollars at the spot exchange rate on the balance sheet date. The results and cash flows of non-US dollar

functional currency subsidiaries, joint ventures and associates are translated into US dollars using average rates of exchange. In the consolidated

financial statements, exchange adjustments arising when the opening net assets and the profits for the year retained by non-US dollar functional

currency subsidiaries, joint ventures and associates are translated into US dollars are recognized in a separate component of equity and reported in

other comprehensive income. Exchange gains and losses arising on long-term intra-group foreign currency borrowings used to finance the group's

non-US dollar investments are also reported in other comprehensive income if the borrowings form part of the net investment in the subsidiary,

joint venture or associate. On disposal or for certain partial disposals of a non-US dollar functional currency subsidiary, joint venture or associate,

the related accumulated exchange gains and losses recognized in equity are reclassified from equity to the income statement.

**Non-current assets held for sale**

Non-current assets and disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell.

Significant non-current assets and disposal groups are classified as held for sale if their carrying amounts will be recovered through a sale

transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal

group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets.

Management must be committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the

date of classification as held for sale, and actions required to complete the plan of sale should indicate that it is unlikely that significant changes to

the plan will be made or that the plan will be withdrawn.

Property, plant and equipment and intangible assets are not depreciated or amortized, and equity accounting of associates and joint ventures is

ceased once classified as held for sale.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 165 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

**Intangible assets**

Intangible assets, other than goodwill, include expenditure on the exploration for and evaluation of oil and natural gas resources, biogas rights

agreements, digital assets, patents, licences and trademarks and are stated at the amount initially recognized, less accumulated amortization and

accumulated impairment losses.

Intangible assets are carried initially at cost unless acquired as part of a business combination. Any such asset is measured at fair value at the date

of the business combination and is recognized separately from goodwill if the asset is separable or arises from contractual or other legal rights.

Intangible assets with a finite life, other than capitalized exploration and appraisal costs as described below, are amortized on a straight-line basis

over their expected useful lives. For patents, licences and trademarks, expected useful life is the shorter of the duration of the legal agreement and

economic useful life, and can range from three to fifteen years. The expected useful life of biogas rights agreements is the shorter of the duration

of the legal agreement and economic useful life and can be up to 50 years. Digital asset costs generally have a useful life of three to five years.

The expected useful lives of assets and the amortization method are reviewed on an annual basis and, if necessary, changes in useful lives or the

amortization method are accounted for prospectively.

**Oil and natural gas exploration and appraisal expenditure**

Oil and natural gas exploration and appraisal expenditure is accounted for using the principles of the successful efforts method of accounting as

described below.

**Licence and property acquisition costs**

Exploration licence and leasehold property acquisition costs are capitalized within intangible assets and are reviewed at each reporting date to

confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration

drilling is still under way or planned or that it has been determined, or work is under way to determine, that the discovery is economically viable

based on a range of technical and commercial considerations, and sufficient progress is being made on establishing development plans and

timing. If no future activity is planned, the remaining balance of the licence and property acquisition costs is written off. Lower value licences are

pooled and amortized on a straight-line basis over the estimated period of exploration. Upon internal approval for development and recognition of

proved or sanctioned probable reserves of oil and natural gas, the relevant expenditure is transferred to property, plant and equipment.

**Exploration and appraisal expenditure**

Geological and geophysical exploration costs are recognized as an expense as incurred. Costs directly associated with an exploration well are

initially capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include

employee remuneration, materials and fuel used, rig costs and payments made to contractors. If potentially commercial quantities of

hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely

to be capable of commercial development, the costs continue to be carried as an asset. If it is determined that development will not occur, that is,

the efforts are not successful, then the costs are expensed.

Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following

the initial discovery of hydrocarbons, including the costs of appraisal wells where hydrocarbons were not found, are initially capitalized as an

intangible asset. Upon internal approval for development and recognition of proved or sanctioned probable reserves, the relevant expenditure is

transferred to property, plant and equipment. If development is not approved and no further activity is expected to occur, then the costs are

expensed.

The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made within

one year of well completion, but can take longer, depending on the complexity of the geological structure. Exploration wells that discover

potentially economic quantities of oil and natural gas and are in areas where major capital expenditure (e.g. an offshore platform or a pipeline)

would be required before production could begin, and where the economic viability of that major capital expenditure depends on the successful

completion of further exploration or appraisal work in the area, remain capitalized on the balance sheet as long as such work is under way or firmly

planned.

---

| |
|:---|
| Significant judgement: exploration and appraisal intangible assets |
| Judgement is required to determine whether it is appropriate to continue to carry costs associated with exploration wells and exploratory-type <br>stratigraphic test wells on the balance sheet. This includes costs relating to exploration licences or leasehold property acquisitions. It is not <br>unusual to have such costs remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the <br>potential oil and natural gas field is performed or while the optimum development plans and timing are established. The costs are carried based <br>on the current regulatory and political environment or any known changes to that environment. All such carried costs are subject to regular <br>technical, commercial and management review on at least an annual basis to confirm the continued intent to develop, or otherwise extract value <br>from, the discovery. Where this is no longer the case, the costs are immediately expensed.<br>The carrying amount of capitalized costs are included in Note 8.<br>|

---

---

| | |
|:---|:---|
| 166 | bp Annual Report and Form 20-F 2025 |

---

**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

**Property, plant and equipment**

Property, plant and equipment owned by the group is stated at cost, less accumulated depreciation and accumulated impairment losses. The initial

cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into the location and

condition necessary for it to be capable of operating in the manner intended by management, the initial estimate of any decommissioning

obligation, if applicable, and, for assets that necessarily take a substantial period of time to get ready for their intended use, directly attributable

general or specific finance costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other

consideration given to acquire the asset.

Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul

costs. Where an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits associated

with the item will flow to the group, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized. Inspection costs

associated with major maintenance programmes are capitalized and amortized over the period to the next inspection. Overhaul costs for major

maintenance programmes, and all other maintenance costs are expensed as incurred.

Expenditure on the construction, installation and completion of infrastructure facilities such as platforms, pipelines and the drilling of development

wells, including service and unsuccessful development or delineation wells, is capitalized within property, plant and equipment and is depreciated

from the commencement of production.

Oil and natural gas properties, including certain related pipelines, are depreciated using a unit-of-production method. The cost of producing wells is

amortized over proved developed reserves. Licence acquisition, common facilities and future decommissioning costs are amortized over total

proved reserves. The unit-of-production rate for the depreciation of common facilities takes into account expenditures incurred to date, together

with estimated future capital expenditure expected to be incurred relating to as yet undeveloped reserves expected to be processed through these

common facilities. Information on the carrying amounts of the group's oil and natural gas properties, together with the amounts recognized in the

income statement as depreciation, depletion and amortization is contained in Note 12 and Note 5 respectively.

Estimates of oil and natural gas reserves determined in accordance with US Securities and Exchange Commission (SEC) regulations, including the

application of prices using 12-month historical price data in assessing the commerciality of technical volumes, are typically used to calculate

depreciation, depletion and amortization charges for the group's oil and gas properties. Therefore, where this approach is adopted, charges are not

dependent on management forecasts of future oil and gas prices.

The impact of changes in estimated proved reserves is dealt with prospectively by amortizing the remaining carrying value of the asset over the

expected future production.

Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life. The typical useful lives of the group's other

property, plant and equipment on initial recognition are as follows:

---

| | |
|:---|:---|
| Land improvements | 15 to 25 years |
| Buildings | 20 to 50 years |
| Refineries | 20 to 30 years |
| Pipelines | 10 to 50 years |
| Service stations | 15 years |
| Office equipment | 3 to 10 years |
| Fixtures and fittings | 5 to 15 years |

---

The expected useful lives and depreciation method of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in

useful lives or the depreciation method are accounted for prospectively. An item of property, plant and equipment is derecognized upon disposal

or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the

asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in the income statement in

the period in which the item is derecognized.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 167 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

**Impairment of property, plant and equipment, intangible assets, goodwill, and equity-accounted entities**

The group assesses assets or groups of assets, called cash-generating units (CGUs), for impairment whenever events or changes in circumstances

indicate that the carrying amount of an asset or CGU may not be recoverable; for example, changes in the group's business plans, plans to dispose

rather than retain assets, changes in the group's assumptions about discount rates, commodity prices, low plant utilization, evidence of physical

damage or, for oil and gas assets, significant downward revisions of estimated reserves or increases in estimated future development expenditure

or decommissioning costs. If any such indication of impairment exists, the group makes an estimate of the asset's or CGU's recoverable amount.

Individual assets are grouped into CGUs for impairment assessment purposes at the lowest level at which there are identifiable cash inflows that

are largely independent of the cash inflows of other groups of assets. A CGU's recoverable amount is the higher of its fair value less costs of

disposal and its value in use. If it is probable that the value of the CGU will be primarily recovered through a disposal transaction, the expected

disposal proceeds are considered in determining the recoverable amount. Where the carrying amount of a CGU exceeds its recoverable amount,

the CGU is considered impaired and is written down to its recoverable amount.

The business segment plans, which are approved on an annual basis by senior management, are the primary source of information for the

determination of value in use. They contain forecasts for oil and natural gas production, power generation, refinery throughputs, sales volumes for

various types of refined products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. Carbon taxes and costs of emissions

allowances are included in estimates of future cash flows, where applicable, based on the regulatory environment in each jurisdiction in which the

group operates. As an initial step in the preparation of these plans, various assumptions regarding market conditions, such as oil prices, natural gas

prices, power prices, refining margins, refined product margins and cost inflation rates are set by senior management. These assumptions take

account of existing prices, global supply-demand equilibrium for oil and natural gas, other macroeconomic factors and historical trends and

variability. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the asset group to the extent that they are

not already reflected in the discount rate and are discounted to their present value typically using a pre-tax discount rate that reflects current

market assessments of the time value of money.

Fair value less costs of disposal is the price that would be received to sell the asset in an orderly transaction between market participants and does

not reflect the effects of factors that may be specific to the group and not applicable to entities in general. Fair value may be determined by

reference to agreed or expected sales proceeds, recent market transactions for similar assets or using discounted cash flow analyses. Where

discounted cash flow analyses are used to calculate fair value less costs of disposal, estimates are made about the assumptions market

participants would use when pricing the asset, CGU or group of CGUs containing goodwill and the test is performed on a post-tax basis.

An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer

exist or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed

only if there has been a change in the estimates used to determine the asset's or CGU's recoverable amount since the last impairment loss was

recognized. If that is the case, the carrying amount of the asset or CGU is increased to the lower of its recoverable amount and the carrying amount

that would have been determined, net of depreciation, had no impairment loss been recognized for the asset or CGU in prior years. Impairment

reversals are recognized in profit or loss. After a reversal, the depreciation charge is adjusted in future periods to allocate the asset's or CGU's

revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.

Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate the recoverable amount of the

group of CGUs to which the goodwill relates should be assessed. In assessing whether goodwill has been impaired, the carrying amount of the

group of CGUs to which goodwill has been allocated is compared with its recoverable amount. Where the recoverable amount of the group of

CGUs is less than the carrying amount (including goodwill), an impairment loss is recognized. An impairment loss recognized for goodwill is not

reversed in a subsequent period.

The group assesses investments in equity-accounted entities for impairment whenever there is objective evidence that the investment is impaired,

after recognizing its share of any losses of the equity-accounted entity itself. If any such objective evidence of impairment exists, the carrying

amount of the investment is compared with its recoverable amount, being the higher of its fair value less costs of disposal and value in use. If the

carrying amount exceeds the recoverable amount, the investment is written down to its recoverable amount.

---

| |
|:---|
| Significant judgements and estimates: recoverability of asset carrying values |
| Determination as to whether, and by how much, an asset, CGU, or group of CGUs containing goodwill is impaired involves management estimates <br>on highly uncertain matters such as the effects of inflation and deflation on operating expenses, discount rates, capital expenditure, carbon <br>pricing (where applicable), production profiles, reserves and resources, and future commodity prices, including the outlook for global or regional <br>market supply-and-demand conditions for crude oil, natural gas, power and refined products. Judgement is required when determining the <br>appropriate grouping of assets into a CGU or the appropriate grouping of CGUs for impairment testing purposes. For example, individual oil and <br>gas properties may form separate CGUs whilst certain oil and gas properties with shared infrastructure may be grouped together to form a single <br>CGU. Alternative groupings of assets or CGUs may result in a different outcome from impairment testing. See Note 14 for details on how these <br>groupings have been determined in relation to the impairment testing of goodwill.<br>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 <br>costs of disposal may be determined based on expected sales proceeds or similar recent market transaction data.<br>Details of impairment charges and reversals recognized in the income statement are provided in Note 4 and details on the carrying amounts of <br>assets are shown in Note 12, Note 14 and Note 15.<br>The estimates for assumptions made in impairment tests in 2025 relating to discount rates and oil and gas properties are discussed below. <br>Changes in the economic environment including as a result of the energy transition or other facts and circumstances may necessitate revisions to <br>these assumptions and could result in a material change to the carrying values of the group's assets within the next financial year.<br>|

---

---

| | |
|:---|:---|
| 168 | bp Annual Report and Form 20-F 2025 |

---

**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

---

| |
|:---|
| **Discount rates** |
| For discounted cash flow calculations, future cash flows are adjusted for risks specific to the CGU. Value-in-use calculations are typically <br>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 <br>and incorporating a market participant capital structure and country risk premiums. Fair value less costs of disposal discounted cash flow <br>calculations use a post-tax discount rate.<br>The discount rates applied in impairment tests are reassessed each year and, in 2025, the post-tax discount rate was 8% (2024 8%) other than for <br>renewable power assets. Where the CGU is located in a country that was judged to be higher risk, an additional premium of 1% to 3% was reflected <br>in the post-tax discount rate (2024 1% to 3%). The judgement of classifying a country as higher risk and the applicable premium takes into account <br>various economic and geopolitical factors. The pre-tax discount rate, other than for renewable power assets, typically ranged from 9% to 18% <br>(2024 9% to 20%) depending on the risk premium and applicable tax rate in the geographic location of the CGU. For renewable power assets <br>tested on a value-in-use basis, primarily the CGUs for which goodwill was allocated following the Lightsource bp acquisition, a WACC-based post-<br>tax discount rate of 7% was used. For renewable power assets tested on a fair-value basis, primarily offshore wind assets (including those in <br>equity accounted entities), a post-tax cost of equity-based discount rate range of 8.75% to 9.5% (2024 8.75% to 9.5%) was used. <br>|
| **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 <br>estimated using management's best estimate of future oil and natural gas prices, production and reserves and certain resources volumes. <br>Forecast cash flows include the impact of all approved emission reduction projects. The estimated future level of production in all impairment <br>tests is based on assumptions about future commodity prices, production and development costs, field decline rates, current fiscal regimes and <br>other factors.<br>In 2025, the group identified oil and gas properties in these segments with carrying amounts totalling $20,341 million (2024 $17,853 million) where <br>the headroom, based on the most recent impairment test performed in the year on those assets, was less than or equal to 20% of the carrying <br>value. A change in the discount rate, reserves, resources or the oil and gas price assumptions in the next financial year may result in a recoverable <br>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 <br>charges in that period. Management considers that reasonably possible changes in the discount rate or forecast revenue, arising from a change in <br>oil and natural gas prices and/or production could result in a material change in their carrying amounts within the next financial year, see <br>Sensitivity analyses, below.<br>The recoverability of intangible exploration and appraisal expenditure is covered under Oil and natural gas exploration, appraisal and <br>development expenditure above.<br>|
| **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 <br>assumptions and their interrelationship with oil and gas prices are described in 'Judgements and estimates made in assessing the impact of <br>climate change and the transition to a lower carbon economy' on page <u>160</u>. The investment appraisal price assumptions were recommended by <br>the senior vice president economic & energy insights after considering a range of external price sets, and supply and demand profiles associated <br>with various energy transition scenarios. They were reviewed and approved by management. As a result of the current uncertainty over the pace <br>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 <br>Paris climate change agreement, the scenarios considered include those where those goals are met as well as those where they are not met. <br>During the year, bp's price assumptions applied in value-in-use impairment testing were revised. The revised price assumptions have been <br>rebased in real 2024 terms. Brent oil prices in real 2024 terms were reduced to $70 per barrel. Medium to long term prices steadily decline to a <br>higher price of $60 per barrel by 2050 continuing to reflect the assumption that the energy system decarbonizes but at a slower rate. The price <br>assumptions for the Henry Hub price have been reduced in the near term, reflecting higher supply in the market. Prices then steadily increase in <br>the medium term, as supply and demand remain steady at $4.50 per mmBtu up to 2050. These price assumptions are derived from the central <br>case investment appraisal assumptions. A summary of the group's revised price assumptions for Brent oil and Henry Hub gas, applied in 2025 and <br>2024, in real 2024 terms, is provided below. The assumptions represent management's best estimate of future prices at the balance sheet date, <br>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 <br>transition paths, as collated into the Transition Scenario Catalogue we use in our TCFD assessment, that are considered by source data providers <br>(such as IEA, UN PRI IPR and NGFS) to be consistent with holding the increase in the global average temperature to well below 2°C above pre-<br>industrial levels and pursuing efforts to limit the temperature increase to 1.5°C above pre-industrial levels. However, they do not correspond to <br>any specific Paris-consistent scenario. An inflation rate of 2.0% - 3.0% (2024 2.0%-2.5%) is applied to determine the price assumptions in nominal <br>terms.<br>|
| 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 <br>produced over the next 12 years. <br>|
| 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 <br>of future taxable profits. See Note 9 for further information.<br>|

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| | | | | |
|:---|:---|:---|:---|:---|
| **2025 price assumptions** | **2026** | **2030** | **2040** | **2050** |
| Brent oil ($/bbl) | 70 | 70 | 67 | 60 |
| Henry Hub gas ($/mmBtu) | 3.80 | 4.10 | 4.50 | 4.50 |

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| | | | | |
|:---|:---|:---|:---|:---|
| **2024 price assumptions** | **2025** | **2030** | **2040** | **2050** |
| Brent oil ($/bbl) | 71 | 71 | 64 | 50 |
| Henry Hub gas ($/mmBtu) | 4.07 | 4.04 | 4.04 | 4.04 |

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| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 169 |

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| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

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**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

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| |
|:---|
| Global oil production increased by 3mmb/d (3%) in 2025, with non-OPEC+ countries contributing nearly 60% of the growth. Global oil demand <br>grew by only 0.8% in 2025, almost entirely accounted for by non-OECD countries, following sharp fall in oil demand from Brazil, India and China. <br>The global supply/demand imbalance of around 2.2mmb/d weighed on prices, with Dated Brent down by nearly $12 per barrel. While geopolitical <br>risk (e.g., tariffs, sanctions) may support prices in the short-term, bp's long-term assumption for oil prices is lower than the 2025 average as oil <br>demand is likely to fall such that the price levels needed to encourage sufficient investment to meet global oil demand will also be lower. <br>The US Henry Hub (HH) spot price averaged $3.5 per mmBtu in 2025, up from $2.2 per mmBtu in 2024 and the highest level since 2022, driven by <br>increased LNG export demand and a colder-than-normal start to the year. Higher gas prices supported a recovery in drilling activity in non-<br>associated (dry) shale plays which, combined with well productivity gains, increasing gas-to-oil ratios in the Permian, and increased pipeline <br>connectivity, meant that US dry gas production grew by 4% year on year and reached record high levels.The level of US gas prices in 2025 was <br>below bp's long term price assumption based on the judgment of the price level required to incentivize new production.<br>|
| 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 <br>and natural gas reserves. Reserves estimates are regularly reviewed and updated. Factors such as the availability of geological and engineering <br>data, reservoir performance data, acquisition and divestment activity and drilling of new wells all impact on the determination of the group's <br>estimates of its oil and natural gas reserves. bp bases its reserves estimates on the requirement of reasonable certainty with rigorous technical <br>and commercial assessments based on conventional industry practice and regulatory requirements. <br>Reserves assumptions for value-in-use tests reflect the reserves and resources that management currently intend to develop. The recoverable <br>amount of oil and gas properties is determined using a combination of inputs including reserves, resources and production volumes. Risk factors <br>may be applied to reserves and resources which do not meet the criteria to be treated as proved or probable.<br>|
| Sensitivity analyses |
| Management considers discount rates, oil and natural gas prices and production to be the key sources of estimation uncertainty in determining <br>the recoverable amount of upstream oil and gas assets. The sensitivity analyses below, in addition to covering the key sources of estimation <br>uncertainty, also indicate how the energy transition, potential future carbon emissions costs for operational GHG emissions and/or reduced <br>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 <br>estimates for oil and gas CGUs, if carbon emissions costs were to be implemented as a deduction against revenue cash flows. The analyses <br>therefore represent a net revenue sensitivity. <br>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 <br>costs/carbon prices, changes in oil and natural gas production, or a combination of these.<br>Management tested the impact of changes in net revenue cash flows in value-in-use impairment testing under the following sensitivity analyses: <br>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 <br>up to 2030, 35% in all subsequent years to 2040 and 50% in all remaining years to 2050.<br>Net revenue reductions of this magnitude in isolation could indicatively lead to a reduction in the carrying amount of bp's currently held upstream <br>oil and gas properties in the range of $20-21 billion which is approximately 34% of the associated net book value of property, plant and equipment <br>as at 31 December 2025. If this net revenue reduction was due to reductions in prices in isolation, it reflects an indicative decrease in the carrying <br>amount of using price assumptions for Brent oil trending broadly towards the bottom of the range of prices associated with the 'family' of <br>scenarios in our Transition Scenario Catalogue considered, by source data providers, to be consistent with limiting global average temperature to <br>1.5°C above pre-industrial levels. This Catalogue of scenarios is also used in bp's TCFD resilience scenario analysis.<br>Net revenue increases of this magnitude in isolation could indicatively lead to an increase in the carrying amount of bp's currently held upstream <br>oil and gas properties in the range of $1-2 billion which is approximately 2-3% of the associated net book value of property, plant and equipment <br>as at 31 December 2025. This potential increase in the carrying amount would arise due to reversals of previously recognized impairments and <br>represents approximately 15% of the total impairment reversal capacity available at 31 December 2025. If this net revenue increase was due to <br>increases in prices in isolation, it reflects an indicative increase in the carrying amount of using price assumptions for Brent oil trending broadly <br>aligned with the top end until the mid-2040s, and then towards the mean average at 2050, of the range of prices associated with the Transition <br>Scenario Catalogue of scenarios (which included the IEA's World Energy Outlook Net Zero Emissions by 2050 (NZE) scenario) considered by IEA to <br>be consistent with limiting global average temperature to 1.5°C above pre-industrial levels. <br>|
| These sensitivity analyses do not, however, represent management's best estimate of any impairment charges or reversals that might be <br>recognized as they do not fully incorporate consequential changes that may arise, such as changes in costs and business plans and phasing of <br>development. For example, costs across the industry are more likely to decrease as oil and natural gas prices fall. The analyses also assume the <br>impact of increases in carbon price on operational GHG emissions are fully absorbed as a decrease in net revenue (and vice versa) rather than <br>reflecting how carbon prices or other carbon emissions costs may ultimately be incorporated by the market. The above sensitivity analyses <br>therefore do not reflect a linear relationship between net revenue and value that can be extrapolated. The interdependency of these inputs and <br>factors plus the diverse characteristics of the group's upstream oil and gas properties limits the practicability of estimating the probability or <br>extent to which the overall recoverable amount is impacted by changes to the price assumptions or production volumes.<br>Management also tested the impact of a one percentage point change in the discount rate used for value-in-use impairment testing of upstream <br>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 <br>the discount rate was one percentage point higher across all tests performed, the net impairment loss recognized in 2025 would have been <br>approximately $0.2 billion higher. If the discount rate was one percentage point lower, the net impairment loss recognized would have been <br>approximately $0.5 billion lower.<br>|

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|:---|:---|
| 170 | bp Annual Report and Form 20-F 2025 |

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**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

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| |
|:---|
| Management considers discount rate, renewable natural gas prices, and the level of capital expenditure and its consequential impact on <br>production volumes to be the key sources of estimation uncertainty in determining the recoverable amount of the group's renewable natural gas <br>assets owned by Archaea Energy.<br>A change in revenue from renewable natural gas assets could arise either due to changes in renewable natural gas prices, changes in renewable <br>natural gas production, principally as a result of changes in capital invested, or a combination of both.<br>Management tested the impact of changes in net revenue cash flows on its value-in-use impairment testing. It is estimated that a reduction in <br>revenue across all Archaea Energy assets of 10% would have resulted in an additional impairment charge of $0.5 billion. It is estimated that an <br>increase in revenue of 10% would have resulted in a reduction to the impairment charge of $0.8 billion. <br>These sensitivity analyses do not, however, represent management's best estimate of any impairment charges or reversals that might be <br>recognized as they do not fully incorporate consequential changes that may arise, such as changes in capital and operating costs, business plans <br>and phasing of development. The above sensitivity analyses therefore do not reflect a linear relationship between net revenue and value that can <br>be extrapolated. The interdependency of these inputs and factors limits the practicability of estimating the probability or extent to which the <br>overall recoverable amount is impacted by changes to the price assumptions or production volumes.<br>It is estimated that an increase to the discount rate of 1% would have resulted in an additional impairment charge to Archaea Energy assets of <br>$0.3 billion. It is estimated that a decrease in the discount rate of 1% would have resulted in a reduction to the impairment charge of $0.4 billion. <br>|
| Management considers discount rates and refining margins to be the key sources of estimation uncertainty in determining the recoverable <br>amount of refinery assets. The sensitivity analysis below, in addition to covering the key sources of estimation uncertainty, also indicates how the <br>energy transition and/or reduced demand for refined products may further impact forecast cash inflows to a greater extent than currently <br>anticipated in the group's value-in-use estimates for refinery CGUs. <br>Management tested the impact of a $1 per barrel decrease in each refinery's future margin assumption in all years of the value-in-use estimate. A <br>reduction of this magnitude in isolation could indicatively lead to a reduction in the carrying amount of bp's currently held refining property, plant <br>and equipment in the range of $1-2 billion.<br>This sensitivity analysis does not, however, represent management's best estimate of any impairment charges that might be recognized as it does <br>not fully incorporate consequential changes that may arise, such as changes in costs and business plans and crude or product slates. The above <br>sensitivity analysis therefore does not reflect a linear relationship between margins and value that can be extrapolated. The interdependency of <br>these inputs and factors plus the varying configurations of the group's refineries limits the practicability of estimating the probability or extent to <br>which the overall recoverable amount is impacted by changes to the margin assumptions.<br>Management also tested the impact of a one percentage point change in the discount rate used for value-in-use impairment testing of refinery <br>assets. This level of change reflects past experience of a reasonable change in rate that could arise within the next financial year. If the discount <br>rate was one percentage point higher across all tests performed, the net impairment loss recognized in 2025 would have been approximately <br>$0.5 billion higher. If the discount rate was one percentage point lower there would have been no impact on the net impairment loss recognized in <br>2025.<br>|
| **Goodwill** |
| Irrespective of whether there is any indication of impairment, bp is required to test annually for impairment of goodwill acquired in business <br>combinations. The group carries goodwill of $10.3 billion on its balance sheet (2024 $14.9 billion), principally relating to the Atlantic Richfield, <br>Devon Energy, Reliance transactions and its transition businesses. Of this, $7.1 billion relates to goodwill in the oil production & operations <br>segment and to hydrocarbon CGUs within the gas & low carbon energy segment (2024 $7.2 billion), for which oil and gas price and production <br>assumptions are key sources of estimation uncertainty. A further $0.9 billion relates to the transition businesses in the gas & low carbon energy <br>segment (2024 $2.9 billion), for which project development revenues and margins, terminal value growth rate and discount rate are key sources of <br>estimation uncertainty. Sensitivities and additional information relating to impairment testing of goodwill in these segments are provided in Note <br>14. <br>|

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| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 171 |

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| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

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**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

**Inventories**

Inventories, other than inventories held for short-term trading purposes, are stated at the lower of cost and net realizable value. Cost is typically

determined by the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses.

Net realizable value is determined by reference to prices existing at the balance sheet date, adjusted where the sale of inventories after the

reporting period gives evidence about their net realizable value at the end of the period.

Inventories held for short-term trading purposes are stated at fair value less costs to sell and any changes in fair value are recognized in the income

statement.

Supplies are valued at the lower of cost on a weighted-average basis and net realizable value.

**Leases**

Agreements that convey the right to control the use of an identified asset for a period of time in exchange for consideration are accounted for as

leases. The right to control is conveyed if bp has both the right to obtain substantially all of the economic benefits from, and the right to direct the

use of, the identified asset throughout the period of use. An asset is identified if it is explicitly or implicitly specified by the agreement and any

substitution rights held by the lessor over the asset are not considered substantive.

Agreements that convey the right to control the use of an intangible asset including rights to explore for or use hydrocarbons are not accounted for

as leases. See material accounting policy information: intangible assets.

A lease liability is recognized on the balance sheet on the lease commencement date at the present value of future lease payments over the lease

term. The discount rate applied is the rate implicit in the lease if readily determinable, otherwise an incremental borrowing rate is used. For the

majority of the leases in the group, there is not sufficient information available to readily determine the rate implicit in the lease, and therefore the

incremental borrowing rate is used. The incremental borrowing rate is determined based on factors such as the group's cost of borrowing, lessee

legal entity credit risk, currency and lease term. The lease term is the non-cancellable period of a lease together with any periods covered by an

extension option that bp is reasonably certain to exercise, or periods covered by a termination option that bp is reasonably certain not to exercise.

The future lease payments included in the present value calculation are any fixed payments, payments that vary depending on an index or rate,

payments due for the reasonably certain exercise of options and expected residual value guarantee payments. Repayments of principal are

presented as financing cash flows and payments of interest are presented as operating cash flows.

Payments that vary based on factors other than an index or a rate such as usage, sales volumes or revenues are not included in the present value

calculation and are recognized in the income statement and presented as operating cash flows. The lease liability is recognized on an amortized

cost basis with interest expense recognized in the income statement over the lease term, except for where capitalized as exploration, appraisal or

development expenditure.

The right-of-use asset is recognized on the balance sheet as property, plant and equipment at a value equivalent to the initial measurement of the

lease liability adjusted for lease prepayments, lease incentives, initial direct costs and any restoration obligations. The right-of-use asset is

depreciated typically on a straight-line basis over the lease term. The depreciation charge is recognized in the income statement except for where

capitalized as exploration, appraisal or development expenditure. Right-of-use assets are assessed for impairment in line with the accounting

policy for impairment of property, plant and equipment, intangible assets and goodwill.

Agreements may include both lease and non-lease components. Payments for lease and non-lease components are allocated on a relative stand-

alone selling price basis except for leases of retail service stations where the group has elected not to separate non-lease payments from the

calculation of the lease liability and right-of-use asset.

If the lease term at commencement of the agreement is less than 12 months, a lease liability and right-of-use asset are not recognized, and a lease

expense is recognized in the income statement on a straight-line basis.

If a significant event or change in circumstances, within the control of bp, arises that affects the reasonably certain lease term or there are changes

to the lease payments, the present value of the lease liability is remeasured using the revised term and payments, with the right-of-use asset

adjusted by an equivalent amount.

Modifications to a lease agreement beyond the original terms and conditions are accounted for as a re-measurement of the lease liability with a

corresponding adjustment to the right-of-use asset. Any gain or loss on modification is recognized in the income statement. Modifications that

increase the scope of the lease at a price commensurate with the stand-alone selling price are accounted for as a separate new lease.

The group recognizes the full lease liability, rather than its working interest share, for leases entered into on behalf of a joint operation if the group

has the primary responsibility for making the lease payments. This may be the case if for example bp, as operator of the joint operation, is the sole

signatory to the lease agreement. In such cases, bp's working interest share of the right-of-use asset is recognized if it is jointly controlled by the

group and the other joint operators, and a receivable is recognized for the share of the asset transferred to the other joint operators. If bp is a non-

operator, a payable to the operator is recognized if they have the primary responsibility for making the lease payments and bp has joint control over

the right-of-use asset, otherwise no balances are recognized.

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|:---|:---|
| 172 | bp Annual Report and Form 20-F 2025 |

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**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

**Financial assets**

Financial assets are recognized initially at fair value, normally being the transaction price. In the case of financial assets not measured at fair value

through profit or loss, directly attributable transaction costs are also included. The subsequent measurement of financial assets depends on their

classification, as set out below. The group derecognizes financial assets when the contractual rights to the cash flows expire or the rights to receive

cash flows have been transferred to a third party and either substantially all of the risks and rewards of the asset have been transferred, or

substantially all the risks and rewards of the asset have neither been retained nor transferred but control of the asset has been transferred. This

includes the derecognition of receivables for which discounting arrangements are entered into.

The group classifies its financial asset debt instruments as measured at amortized cost, fair value through other comprehensive income or fair

value through profit or loss. The classification depends on the business model for managing the financial assets and the contractual cash flow

characteristics of the financial asset.

Financial assets measured at amortized cost

Financial assets are classified as measured at amortized cost when they are held in a business model the objective of which is to collect contractual

cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortized cost using the

effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the assets are

derecognized or impaired and when interest income is recognized using the effective interest method. This category of financial assets includes

trade and other receivables.

Financial assets measured at fair value through other comprehensive income

Financial assets are classified as measured at fair value through other comprehensive income when they are held in a business model the objective

of which is both to collect contractual cash flows and sell the financial assets, and the contractual cash flows represent solely payments of

principal and interest.

Financial assets measured at fair value through profit or loss

Financial assets are classified as measured at fair value through profit or loss when the asset does not meet the criteria to be measured at

amortized cost or fair value through other comprehensive income. Such assets are carried on the balance sheet at fair value with gains or losses

recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category.

Investments in equity instruments

Investments in equity instruments are subsequently measured at fair value through profit or loss unless an election is made on an instrument-by-

instrument basis to recognize fair value gains and losses in other comprehensive income.

Derivatives designated as hedging instruments in an effective hedge

Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and

losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities.

Cash equivalents

Cash equivalents are held for the purpose of meeting short-term cash commitments and are short-term highly liquid investments that are readily

convertible to known amounts of cash, are subject to insignificant risk of changes in value and generally have a maturity of three months or less

from the date of acquisition. Cash equivalents are classified as financial assets measured at amortized cost or, in the case of certain money market

funds, fair value through profit or loss.

Impairment of financial assets measured at amortized cost

The group assesses on a forward-looking basis the expected credit losses associated with financial assets measured at amortized cost at each

balance sheet date. Expected credit losses are measured based on the maximum contractual period over which the group is exposed to credit risk.

As lifetime expected credit losses are recognized for trade receivables and the tenor of substantially all other in-scope financial assets is less than

12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses for the group. The

measurement of expected credit losses is a function of the probability of default, loss given default and exposure at default. The expected credit

loss is estimated as the difference between the asset's carrying amount and the present value of the future cash flows the group expects to receive

discounted at the financial asset's original effective interest rate. The carrying amount of the asset is adjusted, with the amount of the impairment

gain or loss recognized in the income statement.

A financial asset or group of financial assets classified as measured at amortized cost is considered to be credit-impaired if there is reasonable and

supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset (or group of

financial assets) have occurred. Financial assets are written off where the group has no reasonable expectation of recovering amounts due.

**Equity instruments**

Instruments are classified as either financial liabilities or as equity in accordance with the substance of the contractual arrangements. Instruments

that cannot be settled in the group's own equity instruments and that include no contractual obligation to deliver cash or another financial asset or

to exchange financial assets or financial liabilities with another entity that are potentially unfavourable are classified as equity.

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| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 173 |

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|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

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**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

**Financial liabilities**

Financial liabilities are recognized when the group becomes party to the contractual provisions of the instrument. The group derecognizes financial

liabilities when the obligation specified in the contract is discharged, cancelled or expired. The measurement of financial liabilities depends on their

classification, as follows:

Financial liabilities measured at fair value through profit or loss

Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are

carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as

effective hedging instruments, are included in this category.

Derivatives designated as hedging instruments in an effective hedge

Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and

losses arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities.

Financial liabilities measured at amortized cost

All other financial liabilities are initially recognized at fair value, net of directly attributable transaction costs. For interest-bearing loans and

borrowings this is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing.

After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost

is calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase,

settlement or cancellation of liabilities are recognized in interest and other income and finance costs respectively.

This category of financial liabilities includes trade and other payables and finance debt.

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| |
|:---|
| 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 <br>factoring. Judgement is required to assess the payables subject to these arrangements to determine whether they should continue to be <br>classified as trade payables and give rise to operating cash flows or finance debt and financing cash flows. The criteria used in making this <br>assessment include the payment terms for the amount due relative to terms commonly seen in the markets in which bp operates and whether <br>the arrangements significantly change the nature of the liability. Liabilities subject to these arrangements with payment terms of up to <br>approximately 60 days are generally considered to be trade payables and give rise to operating cash flows. See Note 29 - Liquidity risk for further <br>information.<br>|

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**Financial guarantees**

The group issues financial guarantee contracts to make specified payments to reimburse holders for losses incurred if certain associates, joint

ventures or third-party entities fail to make payments when due in accordance with the original or modified terms of a debt instrument such as a

loan. The liability for a financial guarantee contract is initially measured at fair value and subsequently measured at the higher of the contract's

estimated expected credit loss and the amount initially recognized less, where appropriate, cumulative amortization.

**Derivative financial instruments and hedging activities**

The group uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and

commodity prices, as well as for trading purposes. These derivative financial instruments are recognized initially at fair value on the date on which a

derivative contract is entered into and subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as

liabilities when the fair value is negative.

Contracts to buy or sell a non-financial item (for example, oil, oil products, gas or power) that can be settled net in cash, with the exception of

contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the

group's expected purchase, sale or usage requirements, are accounted for as financial instruments. Gains or losses arising from changes in the fair

value of derivatives that are not designated as effective hedging instruments are recognized in the income statement.

If, at inception of a contract, the valuation cannot be supported by observable market data, any gain or loss determined by the valuation

methodology is not recognized in the income statement but is deferred on the balance sheet and is commonly known as a 'day-one gain or loss'.

This deferred gain or loss is recognized in the income statement over the life of the contract until substantially all the remaining contractual cash

flows can be valued using observable market data at which point any remaining deferred gain or loss is recognized in the income statement.

Changes in valuation subsequent to the initial valuation at inception of a contract are recognized immediately in the income statement.

For the purpose of hedge accounting, hedges are classified as:

• Fair value hedges when hedging exposure to changes in the fair value of a recognized asset or liability.

• Cash flow hedges when hedging exposure to variability in cash flows that is attributable to either a particular risk associated with a recognized

asset or liability or a highly probable forecast transaction.

Hedge relationships are formally designated and documented at inception, together with the risk management objective and strategy for

undertaking the hedge. The documentation includes identification of the hedging instrument, the hedged item or transaction, the nature of the risk

being hedged, the existence at inception of an economic relationship and subsequent measurement of the hedging instrument's effectiveness in

offsetting the exposure to changes in the hedged item's fair value or cash flows attributable to the hedged risk, the hedge ratio and sources of

hedge ineffectiveness. Hedges meeting the criteria for hedge accounting are accounted for as follows:

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|:---|:---|
| 174 | bp Annual Report and Form 20-F 2025 |

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**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

Fair value hedges

The change in fair value of a hedging derivative is recognized in profit or loss. The change in the fair value of the hedged item attributable to the risk

being hedged is recorded as part of the carrying value of the hedged item and is also recognized in profit or loss, where it offsets. The group applies

fair value hedge accounting when hedging interest rate risk and certain currency risks on fixed rate finance debt.

Fair value hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This

includes when the risk management objective changes or when the hedging instrument is sold, terminated or exercised. The accumulated

adjustment to the carrying amount of a hedged item at such time is then amortized prospectively to profit or loss as finance interest expense over

the hedged item's remaining period to maturity.

Cash flow hedges

The effective portion of the gain or loss on a cash flow hedging instrument is reported in other comprehensive income, while the ineffective portion

is recognized in profit or loss. Amounts reported in other comprehensive income are reclassified to the income statement when the hedged

transaction affects profit or loss.

Where the hedged item is a highly probable forecast transaction that results in the recognition of a non-financial asset or liability, such as a

forecast foreign currency transaction for the purchase of property, plant and equipment, the amounts recognized within other comprehensive

income are transferred to the initial carrying amount of the non-financial asset or liability. Where the hedged item is an equity investment, the

amounts recognized in other comprehensive income remain in the separate component of equity until the hedged cash flows affect profit or loss

or when accounting under the equity method is discontinued. Where the hedged item is recognized directly in profit or loss, the amounts

recognized in other comprehensive income are reclassified to production and manufacturing expenses or sales and other operating revenues as

appropriate.

Cash flow hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This

includes when the designated hedged forecast transaction or part thereof is no longer considered to be highly probable to occur, or when the

hedging instrument is sold, terminated or exercised without replacement or rollover. When cash flow hedge accounting is discontinued amounts

previously recognized within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified to profit or

loss or transferred to the initial carrying amount of a non-financial asset or liability as above. If the forecast transaction is no longer expected to

occur, amounts previously recognized within other comprehensive income will be immediately reclassified to profit or loss.

Costs of hedging

The foreign currency basis spread of cross-currency interest rate swaps are excluded from hedge designations and accounted for as costs of

hedging. Changes in fair value of the foreign currency basis spread are recognized in other comprehensive income to the extent that they relate to

the hedged item.

For time-period related hedged items, the amount recognized in other comprehensive income is amortized to profit or loss on a straight line basis

over the term of the hedging relationship.

Fair value measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The

group categorizes assets and liabilities measured at fair value into one of three levels depending on the ability to observe inputs employed in their

measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs that are observable, either

directly or indirectly, other than quoted prices included within level 1 for the asset or liability. Level 3 inputs are unobservable inputs for the asset or

liability reflecting significant modifications to observable related market data or bp's assumptions about pricing by market participants.

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| | |
|:---|:---|
| 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-<br>corroborated data. This primarily applies to the group's longer-term derivative contracts. The majority of these contracts are valued using models <br>with inputs that include price curves for each of the different products that are built up from available active market pricing data (including <br>volatility and correlation) and modelled using the maximum available external information. Additionally, where limited data exists for certain <br>products, prices are determined using historical and long-term pricing relationships. The use of alternative assumptions or valuation <br>methodologies may result in significantly different values for these derivatives. A reasonably possible change in the price assumptions used in the <br>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 <br>movements between derivative assets and liabilities. <br>In some cases, judgement is required to determine whether contracts to buy or sell commodities meet the definition of a derivative or to <br>determine appropriate presentation and classification of transactions in certain cases. In particular, contracts to buy and sell LNG are not <br>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 <br>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 <br>derivative financial instruments used to risk-manage the LNG contracts themselves, resulting in a measurement mismatch.<br>For more information, including the carrying amounts of level 3 derivatives, see Note 30.<br>| 0 |

---

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| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 175 |

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---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

**Offsetting of financial assets and liabilities**

Financial assets and liabilities are presented gross in the balance sheet unless both of the following criteria are met: the group currently has a

legally enforceable right to set off the recognized amounts; and the group intends to either settle on a net basis or realize the asset and settle the

liability simultaneously. A right of set off is the group's legal right to settle an amount payable to a creditor by applying against it an amount

receivable from the same counterparty. The relevant legal jurisdiction and laws applicable to the relationships between the parties are considered

when assessing whether a current legally enforceable right to set off exists.

**Provisions and contingencies**

Provisions are recognized when the group has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of

resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the

obligation. Where appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability.

If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax risk-free

rate that reflects current market assessments of the time value of money. Where discounting is used, the increase in the provision due to the

passage of time is recognized within finance costs. Provisions are discounted using a nominal discount rate of 4.5% (2024 4.5%).

Provisions are split between amounts expected to be settled within 12 months of the balance sheet date (current) and amounts expected to be

settled later (non-current).

Contingent liabilities are possible obligations whose existence will only be confirmed by future events not wholly within the control of the group, or

present obligations where it is not probable that an outflow of resources will be required or the amount of the obligation cannot be measured with

sufficient reliability. Contingent liabilities are not recognized in the consolidated financial statements but are disclosed, if material, unless the

possibility of an outflow of economic resources is considered remote.

Decommissioning

Liabilities for decommissioning costs are recognized when the group has an obligation to plug and abandon a well, dismantle and remove a facility

or an item of plant and to restore the site on which it is located, and when a reliable estimate of that liability can be made. Where an obligation

exists for a new facility or item of plant, such as oil and natural gas production or transportation facilities, this liability will be recognized on

construction or installation. Similarly, where an obligation exists for a well, this liability is recognized when it is drilled. An obligation for

decommissioning may also crystallize during the period of operation of a well, facility or item of plant through a change in legislation or through a

decision to terminate operations; an obligation may also arise in cases where an asset has been sold but the subsequent owner is no longer able to

fulfil its decommissioning obligations, for example due to bankruptcy. The amount recognized is the present value of the estimated future

expenditure determined in accordance with local conditions and requirements. The provision for the costs of decommissioning wells, production

facilities and pipelines at the end of their economic lives is estimated using existing technology, at future prices, depending on the expected timing

of the activity, and discounted using a nominal discount rate.

An amount equivalent to the decommissioning provision is recognized as part of the corresponding intangible asset (in the case of an exploration

or appraisal well) or property, plant and equipment. The decommissioning portion of the property, plant and equipment is subsequently

depreciated at the same rate as the rest of the asset. Other than the unwinding of discount on or utilization of the provision, any change in the

present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding asset where that asset is

generating or is expected to generate future economic benefits.

Environmental expenditures and liabilities

Environmental expenditures that are required in order for the group to obtain future economic benefits from its assets are capitalized as part of

those assets. Expenditures that relate to an existing condition caused by past operations that do not contribute to future earnings are expensed.

Liabilities for environmental costs are recognized when a clean-up is probable and the associated costs can be reliably estimated. Generally, the

timing of recognition of these provisions coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of

inactive sites.

The amount recognized is the best estimate of the expenditure required to settle the obligation. Provisions for environmental liabilities have been

estimated using existing technology, at future prices and discounted using a nominal discount rate.

Emissions

Liabilities for emissions are recognized when the cumulative volumes of gases emitted by the group at the end of the reporting period exceed the

allowances granted free of charge held for own use or a set baseline for emissions. The provision is measured at the best estimate of the

expenditure required to settle the present obligation at the balance sheet date. It is based on the excess of actual emissions over the free

allowances held or set baseline in tonnes (or other appropriate quantity) and is valued at the actual cost of any allowances that have been

purchased and held for own use on a first-in-first-out (FIFO) basis, and, if insufficient allowances are held, for the remaining requirement on the

basis of the spot market price of allowances at the balance sheet date. The majority of these provisions are typically settled within 12 months of the

balance sheet date however certain schemes may have longer compliance periods. The cost of allowances purchased to cover a shortfall is

recognized separately on the balance sheet as an intangible asset unless the emission allowances acquired or generated by the group are risk-

managed by the trading and shipping function, then they are recognized on the balance sheet as inventory.

Restructuring provisions

Restructuring provisions are recognized where a detailed formal plan exists, and a valid expectation of risk of redundancy has been made to those

affected but where the specific outcomes remain uncertain. Where formal redundancy offers have been made, the obligations for those amounts

are reported as payables and, if not, as provisions if unpaid at the year-end.

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| | |
|:---|:---|
| 176 | bp Annual Report and Form 20-F 2025 |

---

**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

---

| |
|:---|
| Significant judgements and estimates: provisions |
| The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic <br>lives. The largest decommissioning obligations facing bp relate to the plugging and abandonment of wells and the removal and disposal of oil and <br>natural gas platforms and pipelines around the world. Most of these decommissioning events are many years in the future and the precise <br>requirements that will have to be met when the removal event occurs are uncertain. Decommissioning technologies and costs are constantly <br>changing, as are political, environmental, safety and public expectations. The timing and amounts of future cash flows are subject to significant <br>uncertainty and estimation is required in determining the amounts of provisions to be recognized. Any changes in the expected future costs are <br>reflected in both the provision and, where still recognized, the asset. <br>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 <br>unable to meet their decommissioning obligations, whether bp would then be responsible for decommissioning, and if so the extent of that <br>responsibility. This typically requires assessment of the local legal requirements and the financial standing of the owner. If the standing <br>deteriorates significantly, for example, bankruptcy of the owner, a provision may be required. The group has $0.6 billion of decommissioning <br>provisions recognized as at 31 December 2025 (2024 $0.7 billion) for assets previously sold to third parties where the sale transferred the <br>decommissioning obligation to the new owner. See Note 33 for further information.<br>Decommissioning provisions associated with refineries are generally not recognized, as the potential obligations cannot be measured, given their <br>indeterminate settlement dates. Obligations may arise if refineries cease manufacturing operations and any such obligations would be <br>recognized in the period when sufficient information becomes available to determine potential settlement dates. See Note 33 for further <br>information.<br>The group performs periodic reviews of its refineries for any changes in facts and circumstances including those relating to the energy transition, <br>that might require the recognition of a decommissioning provision. Portfolio strength and flexibility are such that the point of cessation of <br>manufacturing at the group's operating refineries is not yet expected within a determinate time period, as existing property plant and equipment <br>is expected to be renewed or replaced.<br>The provision for environmental liabilities is estimated based on current legal and constructive requirements, technology, price levels and <br>expected plans for remediation. Actual costs and cash outflows can differ from current estimates because of changes in laws and regulations, <br>public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology. <br>The timing and amount of future expenditures relating to decommissioning and environmental liabilities are reviewed annually. The interest rate <br>used in discounting the cash flows is reviewed quarterly. The nominal interest rate used to determine the balance sheet obligations at the end of <br>2025 was 4.5% (2024 4.5%), which was based on long-dated US government bonds interpolated to reflect the expected weighted average time to <br>decommissioning. The weighted average period over which decommissioning and environmental costs are generally expected to be incurred is <br>estimated to be approximately 16 years (2024 17 years) and 7 years (2024 7 years) respectively. Costs at future prices are typically determined by <br>applying an inflation rate of 1.5% (2024 1.5%) to decommissioning costs and 2% (2024 2%) for all other provisions. A lower rate is typically applied to <br>decommissioning as certain costs are expected to remain fixed at current or past prices.<br>The estimated phasing of undiscounted cash flows in real terms for upstream decommissioning is approximately $5.7 billion (2024 $5.5 billion) <br>within the next 10 years, $6.0 billion (2024 $6.2 billion) in 10 to 20 years and the remainder of approximately $7.0 billion (2024 $6.7 billion) after 20 <br>years. The timing and amount of decommissioning cash flows are inherently uncertain and therefore the phasing is management's current best <br>estimate but may not be what will ultimately occur.<br>Further information about the group's provisions is provided in Note 23. Changes in assumptions in relation to the group's provisions could result <br>in a material change in their carrying amounts within the next financial year. A 1.0 percentage point increase in the nominal discount rate applied <br>could decrease the group's provision balances by approximately $1.4 billion (2024 $1.5 billion). The pre-tax impact on the group income statement <br>would be a credit of approximately $0.3 billion (2024 $0.4 billion). This level of change reflects past experience of a reasonable change in rate that <br>could arise within the next financial year.<br>The discounting impact on the group's decommissioning provisions for oil and gas properties in the oil productions & operations and gas & low <br>carbon energy segments of a two-year change in the timing of expected future decommissioning expenditures is approximately $0.7 billion (2024 <br>$0.3 billion). Management currently does not consider a change of greater than two years to be reasonably possible in the next financial year and <br>therefore the timing of upstream decommissioning expenditure is not a key source of estimation uncertainty.<br>If all expected future decommissioning expenditures were 10% higher, then these decommissioning provisions would increase by approximately <br>$1.2 billion (2024 $1.2 billion) and a pre-tax charge of approximately $0.3 billion (2024 $0.4 billion) would be recognized. A one percentage point <br>increase in the inflation rate applied to upstream decommissioning costs to determine the nominal cash flows could increase the <br>decommissioning provision by approximately $1.8 billion (2024 $1.7 billion) with a pre-tax charge of approximately $0.4 billion (2024 $0.5 billion).<br>As described in Note 33, the group is subject to claims and actions for which no provisions have been recognized. The facts and circumstances <br>relating to particular cases are evaluated regularly in determining whether a provision relating to a specific litigation should be recognized or <br>revised. Accordingly, significant management judgement relating to provisions and contingent liabilities is required, since the outcome of <br>litigation is difficult to predict. <br>|

---

Employee benefits

Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services

are rendered by employees of the group. Deferred bonus arrangements that have a vesting date more than 12 months after the balance sheet date

are valued on an actuarial basis using the projected unit credit method and amortized on a straight-line basis over the service period until the

award vests. The material accounting policy information for pensions and other post-employment benefits are described below.

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| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 177 |

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| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

**Pensions and other post-employment benefits**

The cost of providing benefits under the group's defined benefit plans is determined separately for each plan using the projected unit credit

method, which attributes entitlement to benefits to the current period to determine current service cost and to the current and prior periods to

determine the present value of the defined benefit obligation. Past service costs, resulting from either a plan amendment or a curtailment (a

reduction in future obligations as a result of a material reduction in the plan membership), are recognized immediately when the company

becomes committed to a change.

Net interest expense relating to pensions and other post-employment benefits, which is recognized in the income statement, represents the net

change in present value of plan obligations and the value of plan assets resulting from the passage of time, and is determined by applying the

discount rate to the present value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year, taking

into account expected changes in the obligation or plan assets during the year.

Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding amounts

included in net interest described above) are recognized within other comprehensive income in the period in which they occur and are not

subsequently reclassified to profit and loss.

The defined benefit pension plan surplus or deficit recognized on the balance sheet for each plan comprises the difference between the present

value of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets out of which

the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid

price. Defined benefit pension plan surpluses are only recognized to the extent they are recoverable, either by way of a refund from the plan or

reductions in future contributions to the plan.

Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.

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| |
|:---|
| 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 <br>pension plan surpluses and deficits. These estimates require assumptions to be made about many uncertainties.<br>Pensions and other post-employment benefit assumptions are reviewed by management at the end of each year. These assumptions are used to <br>determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the group's balance sheet and <br>pension and other post-employment benefit expense for the following year.<br>The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate and mortality levels. Assumptions <br>about these variables are based on the environment in each country. The assumptions used vary from year to year, with resultant effects on future <br>net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation rate, could result in material <br>changes to the carrying amounts of the group's pension and other post-employment benefit obligations within the next financial year. Any <br>differences between these assumptions and the actual outcome will also affect future net income and net assets.<br>The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and <br>obligation used are provided in Note 24.<br>|

---

**Income taxes**

Income tax expense represents the sum of current tax and deferred tax.

Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or

directly in equity, in which case the related tax is recognized in other comprehensive income or directly in equity.

Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is

determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense that

are taxable or deductible in other periods as well as items that are never taxable or deductible. The group's liability for current tax is calculated

using tax rates and laws that have been enacted or substantively enacted by the balance sheet date.

Deferred tax is provided, using the liability method, on temporary differences at the balance sheet date between the tax bases of assets and

liabilities and their carrying amounts for financial reporting purposes. Deferred tax liabilities are recognized for all taxable temporary differences

except:

• Where the deferred tax liability arises on the initial recognition of goodwill.

• Where the deferred tax liability arises on the initial recognition of an asset or liability in a transaction that is not a business combination, at the

time of the transaction, affects neither accounting profit nor taxable profit or loss and, at the time of the transaction, does not give rise to equal

taxable and deductible temporary differences.

• In respect of taxable temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements,

where the group is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will

not reverse in the foreseeable future.

Deferred tax assets are recognized for deductible temporary differences, carry-forward of unused tax credits and unused tax losses, to the extent

that it is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax

credits and unused tax losses can be utilized, except where the deferred tax asset relating to the deductible temporary difference arises from the

initial recognition of an asset or liability in a transaction that is not a business combination, at the time of the transaction, affects neither accounting

profit nor taxable profit or loss and, at the time of the transaction, does not give rise to equal taxable and deductive temporary differences.

In respect of deductible temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements,

deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and

taxable profit will be available against which the temporary differences can be utilized.

The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable or

increased to the extent that it is probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilized.

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| | |
|:---|:---|
| 178 | bp Annual Report and Form 20-F 2025 |

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**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the liability is

settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. Deferred tax assets and

liabilities are not discounted.

Deferred tax assets and liabilities are offset only when there is a legally enforceable right to set off current tax assets against current tax liabilities

and when the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or

different taxable entities where there is an intention to settle the current tax assets and liabilities on a net basis or to realize the assets and settle

the liabilities simultaneously.

Where tax treatments are uncertain, if it is considered probable that a taxation authority will accept the group's proposed tax treatment, income

taxes are recognized consistent with the group's income tax filings. If it is not considered probable, the uncertainty is reflected within the carrying

amount of the applicable tax asset or liability using either the most likely amount or an expected value, depending on which method better predicts

the resolution of the uncertainty.

The computation of the group's income tax expense and liability involves the interpretation of applicable tax laws and regulations in many

jurisdictions throughout the world. The resolution of tax positions taken by the group, through negotiations with relevant tax authorities or through

litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome. Therefore, judgement is required to

determine whether provisions for income taxes are required and, if so, estimation is required of the amounts that could be payable.

In addition, the group has carry-forward tax losses and tax credits in certain taxing jurisdictions that are available to offset against future taxable

profit. However, deferred tax assets are recognized only to the extent that it is probable that taxable profit will be available against which the

unused tax losses or tax credits can be utilized. Management judgement is exercised in assessing whether this is the case and estimates are

required to be made of the amount of future taxable profits that will be available. Such judgements are inherently impacted by estimates affecting

future taxable profits such as oil and natural gas prices and decommissioning expenditure, see 'Significant judgements and estimates:

recoverability of asset carrying values and provisions'.

The group is subject to legislation which implements the OECD Pillar Two Model rules in the UK and many other countries around the world. The

legislation is designed to ensure a minimum effective tax rate of 15% in each country in which the group operates. In the UK this includes an income

inclusion rule and a domestic minimum tax. In line with the amendments to IAS 12, the exception from recognising and disclosing information about

deferred tax assets and liabilities related to Pillar Two income taxes has been applied.

In October 2024, the UK government announced changes (effective from 1 November 2024) to the Energy Profits Levy including a 3% increase in

the rate taking the headline rate of tax on North Sea profits to 78%, an extension to the period of application of the Levy to 31 March 2030 and the

removal of the Levy's main investment allowance. The changes to the rate and to the investment allowance were substantively enacted in 2024. The

extension of the Levy to 31 March 2030 was substantively enacted in 2025 resulting in a non-cash deferred tax charge of $539 million in the year.

On 11 July 2025, the German federal government substantively enacted a number of changes to its tax legislation, including a 5% reduction in the

corporate income tax rate by 2032. The reduction in the tax rate will be phased in by means of a 1% reduction each year between 2028 and 2032

and resulted in a non-cash deferred tax charge of $235 million in the year.

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| |
|:---|
| 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 <br>material change as a result of underlying assumptions and judgements used, in particular the forecast of future profitability used to determine <br>the recoverability of deferred tax, for example future oil and gas prices, see 'Significant judgement and estimates - Recoverability of asset <br>carrying values'. It is impracticable to disclose the extent of the possible effects of profitability assumptions on the group's deferred tax assets. It <br>is reasonably possible that to the extent that actual outcomes differ from management's estimates, material income tax charges or credits, and <br>material changes in current and deferred tax assets or liabilities, may arise within the next financial year and in future periods. <br>Judgement is required when determining whether a particular tax is an income tax or another type of tax (for example, a production tax). The <br>attributes of the tax, including whether it is calculated on profits or another measure such as production or revenues, the extent of deductibility of <br>costs and the interaction with existing income taxes, are considered in determining the classification of the tax. Accounting for deferred tax is <br>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 <br>accordance with the applicable accounting policy such as Provisions and contingencies. <br>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 <br>Dhabi. These are principally reported as income taxes rather than as production taxes.<br>For more information see Note 9 and Note 33.<br>|

---

**Customs duties and sales taxes**

Customs duties and sales taxes that are passed on or charged to customers are excluded from revenues and expenses. Assets and liabilities are

recognized net of the amount of customs duties or sales tax except:

• Customs duties or sales taxes incurred on the purchase of goods and services which are not recoverable from the taxation authority are

recognized as part of the cost of acquisition of the asset.

• Receivables and payables are stated with the amount of customs duty or sales tax included.

The net amount of sales tax recoverable from, or payable to, the taxation authority is included within receivables or payables in the balance sheet.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 179 |

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| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

**Own equity instruments – treasury shares**

The group's holdings in its own equity instruments are shown as deductions from shareholders' equity. Treasury shares represent bp shares

repurchased and available for specific and limited purposes. For accounting purposes, shares held in Employee Share Ownership Plans (ESOPs) to

meet the future requirements of the employee share-based payment plans are treated in the same manner as treasury shares and are, therefore,

included in the consolidated financial statements as treasury shares. The cost of treasury shares subsequently sold or reissued is calculated on a

weighted-average basis. Consideration, if any, received for the sale of such shares is also recognized in equity. No gain or loss is recognized in the

income statement on the purchase, sale, issue or cancellation of equity shares. Shares repurchased and immediately cancelled are not shown as

treasury shares. Instead, the nominal amount is transferred to the capital redemption reserve and any difference to the purchase price is shown as

a deduction from the profit and loss account reserve in the group statement of changes in equity.

**Revenue and other income**

Revenue from contracts with customers is recognized when or as the group satisfies a performance obligation by transferring control of a

promised good or service to a customer. The transfer of control of oil, natural gas, natural gas liquids, LNG, petroleum and chemical products, and

other items usually coincides with title passing to the customer and the customer taking physical possession. The group principally satisfies its

performance obligations at a point in time; the amounts of revenue recognized relating to performance obligations satisfied over time are not

significant.

When, or as, a performance obligation is satisfied, the group recognizes as revenue the amount of the transaction price that is allocated to that

performance obligation. The transaction price is the amount of consideration to which the group expects to be entitled. The transaction price is

allocated to the performance obligations in the contract based on standalone selling prices of the goods or services promised.

Contracts for the sale of commodities are typically priced by reference to quoted prices. Revenue from term commodity contracts is recognized

based on the contractual pricing provisions for each delivery. Certain of these contracts have pricing terms based on prices at a point in time after

delivery has been made. Revenue from such contracts is initially recognized based on relevant prices at the time of delivery and subsequently

adjusted as appropriate. All revenue from these contracts, both that recognized at the time of delivery and that from post-delivery price

adjustments, is disclosed as revenue from contracts with customers.

Sales and purchase of commodities accounted for under IFRS 15 are presented on a gross basis in Revenue from contracts with customers and

Purchases respectively. Physically settled derivatives which represent trading or optimization activities are presented net alongside financially

settled derivative contracts in Other operating revenues within Sales and other operating income. Certain physically settled sale and purchase

derivative contracts which are not part of trading and optimization activities are presented gross within Other operating revenues and Purchases

respectively. Changes in the fair value of derivative assets and liabilities prior to physical delivery are also classified as other operating revenues.

Physical exchanges with counterparties in the same line of business in order to facilitate sales to customers are reported net, as are sales and

purchases made with a common counterparty, as part of an arrangement similar to a physical exchange.

Where the group acts as agent on behalf of a third party to procure or market energy commodities, any associated fee income is recognized but no

purchase or sale is recorded.

Sales and other transactions through which the group loses control of solar projects developed under Lightsource bp's develop-to-sell business

model are accounted for as revenues from contracts with customers.

Interest income is recognized as the interest accrues (using the effective interest rate, that is, the rate that exactly discounts estimated future cash

receipts through the expected life of the financial instrument to the net carrying amount of the financial asset).

Dividend income from investments is recognized when the shareholders' right to receive the payment is established.

**Finance costs**

Finance costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a

substantial period of time to get ready for their intended use, are added to the cost of those assets until such time as the assets are substantially

ready for their intended use. All other finance costs are recognized in the income statement in the period in which they are incurred.

**Updates to material accounting policy information**

Impact of new International Financial Reporting Standards

There are no new or other amended standards or interpretations adopted from 1 January 2025 onwards, that have a significant impact on the

consolidated financial statements for 2025.

---

| | |
|:---|:---|
| 180 | bp Annual Report and Form 20-F 2025 |

---

**1. Material accounting policy information, significant judgements, estimates and assumptions – continued**

**Not yet adopted**

Amendments to IFRS 9 ' Financial Instruments' relating to the settlement of liabilities through electronic payment systems are effective for annual

periods beginning on or after 1 January 2026. bp will adopt the amendments in the financial reporting period commencing 1 January 2026 using the

modified retrospective approach. The amendments clarify the timing of derecognition of financial instruments and whilst they permit financial

liabilities to be derecognized before the settlement date if certain criteria are met, the group is not expected to make this election. Management

has considered the amendments and does not anticipate any material effect on the Group's financial position or results. The expected impact on

transition is a $34 million increase to cash and cash equivalents.

IFRS 18 'Presentation and Disclosure in Financial Statements' will supersede IAS 1 'Presentation of Financial Statements' and is effective for annual

periods beginning on or after 1 January 2027. IFRS 18 (and consequential amendments made to IAS 7 'Statement of Cash Flows', IAS 8 'Accounting

Policies: Changes in Accounting Estimates and Errors', IAS 33 'Earnings per share' and IFRS 7 'Financial Instruments: Disclosures') introduces several

new requirements that are expected to impact the presentation and disclosure of the Group's consolidated financial statements. These new

requirements include:

• Requirements to classify all income and expenses included in the statement of profit or loss into one of five categories and to present two new

mandatory subtotals.

• Requirement to use the operating profit subtotal as the starting point for the indirect method of reporting cash flows from operating activities in

the statement of cash flows.

• Specific classification requirements for interest paid/received and dividends received in the statement of cash flows such that interest and

dividend receipts are included as investing cash flows and interest paid as financing cash flows.

• Required disclosures about certain non-GAAP measures ('management defined performance measures') in a single note to the financial

statements

• Enhanced guidance on the aggregation of information across all the primary financial statements and the notes.

The group's evaluation of the effect of adopting IFRS 18 is ongoing but it is currently anticipated that IFRS 18 will have a significant impact on the

presentation of the Group's financial statements and related disclosures.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 181 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**2. Non-current assets held for sale** 

The carrying amount of assets classified as held for sale at 31 December 2025 is $6,347 million (2024 $4,081 million), with associated liabilities of

$1,594 million (2024 $1,105 million).

**gas & low carbon energy**

On 24 October 2024, bp completed the acquisition of the remaining 50.03% of Lightsource bp. The acquisition included certain assets for which

sales processes were in progress at the acquisition date. The carrying amount of assets classified as held for sale at 31 December 2025 is

$1,916 million (2024 $1,702 million), with associated liabilities of $1,254 million (2024 $1,050 million). The sale of the majority of these assets and

liabilities completed in February 2026. Completions of the sales of the remaining assets and liabilities are expected to occur in 2026.

**customers & products**

On 24 December 2025, bp announced an agreement with Stonepeak to divest a 65% shareholding in the Castrol business with bp retaining a 35%

interest through a holding in a newly incorporated entity. Cash proceeds are estimated at $6 billion. The transaction is expected to complete by the

end of 2026, subject to regulatory approvals. The carrying amount of assets classified as held for sale at 31 December 2025 is $4,431 million

including $2,760 million of goodwill that arose on the acquisition of Castrol in 2000, with associated liabilities of $340 million. Net working capital,

which at 31 December 2025 was approximately $1.2 billion, has not been classified as assets and associated liabilities held for sale. The working

capital balances as at completion will be transferred to the buyer. At 31 December 2025, there are also associated cumulative foreign exchange

losses within reserves of approximately $1.6 billion. Such reserves are expected to be recycled to the group income statement at completion. The

shares to be held by Stonepeak are subject to preferred distributions, the effect of which is that bp does not expect to recognize income or

dividends from the investment in the short to medium term.

Transactions that have been either classified as held for sale at 31 December 2024 or during 2025, but were completed by 31 December 2025, are

described below.

**gas & low carbon energy**

On 9 December 2024, bp and JERA Co., Inc. agreed to combine their offshore wind businesses to form a new standalone, equally-owned joint

venture – JERA Nex bp. On 1 August 2025, this transaction was completed. bp contributed its development projects in the UK, Germany and US into

the joint venture. The related assets and liabilities of those projects, which had been classified as held for sale since the announcement of the

transaction, were derecognized at completion.

On 16 September 2024, bp announced that it planned to sell its US onshore wind energy business, bp Wind Energy and on 18 July 2025 the sale of

the business to LS Power was announced. bp Wind Energy has interests in ten operating onshore wind energy assets across seven US states. The

transaction completed on 9 December 2025. The related assets and liabilities of those projects, previously classified as held for sale, were

derecognized on that date.

**oil production & operations**

On 31 January 2025 bp and Devon Energy agreed to dissolve their Eagle Ford partnership and divide up the assets. The dissolution completed on 1

April 2025.

**customers & products**

On 9 July 2025, bp announced the sale of its Netherlands mobility & convenience and bp pulse businesses to Catom BV. The transaction includes

bp's Dutch retail sites, EV charging hubs and the associated fleet business. The sale completed on 1 December 2025.

The total assets and liabilities held for sale at 31 December 2025 and 2024, which are in the gas & low carbon energy and customers & products

segments, are set out in the table below.

---

| | | |
|:---|:---|:---|
|  |  | $ million |
|  | **2025** | 2024 |
| Property, plant and equipment | **2542** | 1981 |
| Goodwill | **2817** |  |
| Intangible assets | **165** | 333 |
| Investments in associates | **20** |  |
| Investments in joint ventures | **18** | 1182 |
| Other investments | **65** |  |
| Inventories | **11** |  |
| Cash  | **68** | 65 |
| Trade and other receivables | **292** | 520 |
| Deferred tax assets | **349** |  |
| **Assets classified as held for sale** | **6347** | 4081 |
| Trade and other payables | **(87)** | (264) |
| Lease liabilities | **(109)** | (58) |
| Finance debt | **(1143)** | (720) |
| Provisions | **(75)** | (63) |
| Deferred tax liabilities | **(11)** |  |
| Defined benefit pension plan and other post-employment benefit plan deficits | **(169)** |  |
| **Liabilities directly associated with assets classified as held for sale** | **(1594)** | (1105) |

---

---

| | |
|:---|:---|
| 182 | bp Annual Report and Form 20-F 2025 |

---

**3. Business combinations and other significant transactions** 

**Business combinations** 

**2025**

There were no material business combinations completed in 2025.

**Business combinations** 

**2024**

The group undertook a number of business combinations during 2024. Total consideration was $2,119 million and the amount paid in cash in 2024

amounted to $978 million offset by cash acquired of $1,031 million.

These business combinations principally relate to the step acquisitions of bp Bunge Bioenergia and Lightsource bp. Total consideration for these

two acquisitions was $1,328 million and the amount paid in cash in 2024 was $227 million, offset by cash acquired of $589 million. The fair value of

the net assets (including goodwill) recognized from these business combinations for 2024 was $2,848 million.

The gain recognized in 'Interest and other income' in 2024 as a result of remeasuring the previously held interests in bp Bunge Bioenergia and

Lightsource bp, to fair value, was $427 million.

Immediately prior to the Lightsource bp business combination, certain assets in the US were transferred from Lightsource bp into a new joint

venture which remains jointly controlled by bp and certain founder shareholders of Lightsource bp, and is accordingly equity accounted for by bp.

The investment in the new joint venture was measured at bp's share of the joint venture's net assets and, as a result, income of $498 million has

been recognized in 'Interest and other income' in 2024.

**4. Disposals and impairment** 

The following amounts were recognized in the income statement in respect of disposals and impairments.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| **Gains on sale of businesses and fixed assets** |  |  |  |
| gas & low carbon energy | **258** | 297 | 19 |
| oil production & operations | **407** | 144 | 297 |
| customers & products | **317** | 190 | 44 |
| other businesses & corporate | **5** | 47 | 9 |
|  | **987** | 678 | 369 |
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| **Losses on sale of businesses and fixed assets, and closures** |  |  |  |
| gas & low carbon energy | **410** | 303 | 9 |
| oil production & operations | **110** | 19 | 5 |
| customers & products | **118** | 1457 | 143 |
| other businesses & corporate | **4** | 27 | (1) |
|  | **642** | 1806 | 156 |
| **Impairment losses** |  |  |  |
| gas & low carbon energy<sup>a</sup> | **4146** | 3310 | 2213 |
| oil production & operations | **454** | 1155 | 1840 |
| customers & products<sup>a</sup> | **926** | 1144 | 1614 |
| other businesses & corporate | **3** | 24 | 80 |
|  | **5529** | 5633 | 5747 |
| **Impairment reversals** |  |  |  |
| gas & low carbon energy | **(108)** | (44) | (1) |
| oil production & operations | **(12)** | (384) | (26) |
| customers & products | **(14)** | (1) |  |
| other businesses & corporate | **—** | (15) | (19) |
|  | **(134)** | (444) | (46) |
| **Impairment and losses on sale of businesses and fixed assets, and closures** | **6037** | 6995 | 5857 |

---

a2024 balances and related narrative has been restated to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 183 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**4. Disposals and impairment – continued**

**Disposals**

Disposal proceeds and principal gains and losses on disposals by segment are described below.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| Proceeds from disposals of fixed assets | **1142** | 328 | 133 |
| Proceeds from disposals of businesses, net of cash disposed | **1714** | 2578 | 1193 |
|  | **2856** | 2906 | 1326 |
| **By business** |  |  |  |
| gas & low carbon energy | **1702** | 840 | 536 |
| oil production & operations | **272** | 1699 | 333 |
| customers & products | **840** | 291 | 436 |
| other businesses & corporate | **42** | 76 | 21 |
|  | **2856** | 2906 | 1326 |

---

Proceeds from disposals of businesses in 2025 includes proceeds relating to the sale of the US onshore wind business and the disposal of the

Netherlands mobility & convenience and bp pulse businesses, as well as other smaller amounts. Proceeds from disposals of businesses in 2024

includes $594 million relating to the formation of a new joint venture, Arcius Energy, in Egypt, as well as $1,331 million relating to Alaska and

$252 million relating to Canada, both prior period disposals. At 31 December 2025, deferred consideration relating to disposals amounted to $48

million receivable within one year (2024 $112 million and 2023 $141 million) and $247 million receivable after one year (2024 $244 million and 2023

$217 million). The amounts of deferred consideration are reported within Trade and other receivables in Other receivables in the group balance

sheet. In addition, contingent consideration receivable relating to disposals amounted to $85 million at 31 December 2025 (2024 $190 million and

2023 $1,694 million). The contingent consideration at 31 December 2025 primarily relates to the prior period disposal of certain assets in the North

Sea. These amounts of contingent consideration are reported within Other investments on the group balance sheet - see Note 18 for further

information.

**Gains and losses on sale of businesses and fixed assets, and closures**

gas & low carbon energy

In 2025 losses principally arose upon the formation of a new offshore wind joint venture JERA Nex bp.

oil production & operations

In 2025 gains principally relate to a disposal in the North Sea and an asset exchange in bpx.

In 2023 gains principally related to prior period disposals in the US and Canada.

customers & products

In 2024 losses principally related to a loss of $1,132 million arising from the divestment of our Türkiye ground fuels business.

Summarized financial information relating to the sale of businesses is shown in the table below.

The principal transactions categorized as a business disposal in 2025 were the formation of a new offshore wind joint venture, JERA Nex bp, in

which bp contributed its development projects in the UK, Germany and US into the joint venture; the disposal of the Netherlands mobility &

convenience and bp pulse businesses; the sale of the US onshore wind business; and an asset exchange in bpx.

The principal transactions categorized as a business disposal in 2024 were the divestment of our Türkiye ground fuels business, the new joint

venture transaction with ADNOC in Egypt and a transaction relating to the prior period disposal in Alaska.

The principal transactions categorized as a business disposal in 2023 were the sale of the upstream business in Algeria to Eni and the disposal of

the bp-Husky Toledo refinery to Cenovus Energy.

---

| | |
|:---|:---|
| 184 | bp Annual Report and Form 20-F 2025 |

---

**4. Disposals and impairment – continued**

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| Non-current assets | **3998** | 1775 | 1145 |
| Current assets | **571** | 1985 | 557 |
| Non-current liabilities | **(320)** | (548) | (60) |
| Current liabilities | **(213)** | (424) | (454) |
| **Total carrying amount of net assets disposed** | **4036** | 2788 | 1188 |
| Recycling of foreign exchange on disposal | **41** | 943 |  |
| Costs on disposal | **54** | 123 | 57 |
|  | **4131** | 3854 | 1245 |
| Gains (losses) on sale of businesses | **358** | (888) | 158 |
| **Total consideration** | **4489** | 2966 | 1403 |
| Non-cash consideration | **(3133)** | (1003) | (51) |
| Consideration received (receivable) | **358** | 615 | (159) |
| **Proceeds from the sale of businesses, net of cash disposed**<sup>a</sup> | **1714** | 2578 | 1193 |

---

aProceeds are stated net of cash and cash equivalents disposed of $61 million (2024 $500 million and 2023 $33 million).

**Impairments**

Impairment losses and impairment reversals in each segment are described below. For information on significant estimates and judgements made

in relation to impairments see Impairment of property, plant and equipment, intangibles, goodwill and equity-accounted entities within Note 1. See

also Note 12, and Note 15 for further information on impairments by asset category.

gas & low carbon energy

The 2025 impairment loss of $4,146 million includes $3,537 million relating to the transition businesses, principally Archaea Energy and Lightsource

bp, and $609 million relating to the upstream gas business, principally Mauritania and Senegal. The impairments arose as a result of revised

assumptions including capital and operating expenditure and the impact of market conditions on project development. The recoverable amount of

all CGUs for which impairment charges were recognized in 2025 is $8,805 million.

The 2024 impairment loss of $3,310 million includes amounts in Mauritania & Senegal ($1,495 million), which principally arose as a result of increased

forecast future expenditure, and a number of other individually immaterial impairments across the segment principally as a result of portfolio

management. The recoverable amounts of these cash generating units (CGUs) were based on value in use or fair value less costs of disposal

calculations, as appropriate. The recoverable amount of all CGUs for which impairment charges were recognized in 2024 is $5,025 million.

The 2023 impairment loss of $2,213 million primarily relates to losses incurred in respect of certain assets in Mauritania & Senegal ($1,434 million)

and principally arose as a result of increased forecast future expenditure. A further $565 million relates to producing assets in Trinidad and arose as

a result of changes to the group's oil and gas price and discount rate assumptions and activity phasing. The recoverable amount of all CGUs for

which impairment charges or reversals were recognized in 2023 in total, based on their value in use, is $4,811 million.

oil production & operations

Impairment losses and reversals in all years relate primarily to producing assets.

The 2025 impairment loss of $454 million primarily arose as a result of changes to reserves and decommissioning provisions mainly driven by

foreign exchange in the North Sea ($397 million). The recoverable amount of all CGUs for which impairment charges or reversals were recognized in

2025 in total, based on their value in use, is $2,058 million.

The 2024 impairment loss of $1,155 million primarily arose as a result of changes to reserves and tax assumptions in the North Sea ($1,035 million).

The recoverable amount of all CGUs for which impairment charges or reversals were recognized in 2024 in total, based on their value in use, is

$8,705 million.

The 2023 impairment loss of $1,840 million primarily arose as a result of changes to the group's oil and gas price and discount rate assumptions,

activity phasing and disposal decisions in relation to certain assets in North Sea ($852 million) and in bpx energy ($802 million). The recoverable

amount of all CGUs for which impairment charges or reversals were recognized in 2023 in total, based on their value in use, is $14,072 million.

customers & products

The 2025 impairment loss of $926 million primarily relates to strategy implementation in the products business. The recoverable amount of all

CGUs for which impairment charges or reversals were recognized in 2025 in total, based on their value in use, is $49 million.

The 2024 impairment loss of $1,144 million primarily arises from the ongoing review of the Gelsenkirchen refinery in Germany ($807 million) and a

number of other individually immaterial impairments across the segment, principally as a result of changes to economic assumptions. The

recoverable amount of the CGUs were based on value-in-use calculations. The recoverable amount of all CGUs for which impairment charges or

reversals were recognized in 2024 in total, based on their value-in-use, is $57 million.

The 2023 impairment loss of $1,614 million primarily relates to strategy implementation and changes to economic assumptions in the products

business including an impairment of the Gelsenkirchen refinery in Germany ($1,336 million). The recoverable amounts of the CGUs were based on

value-in-use calculations. The recoverable amount of all CGUs for which impairment charges or reversals were recognized in 2023 in total, based on

their value in use, is $327 million.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 185 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**5. Segmental analysis** 

The group's organizational structure reflects the various activities in which bp is engaged as well as how performance and resource allocation is

evaluated by the chief operating decision maker. At 31 December 2025, bp has three reportable segments: Gas & low carbon energy, Oil production

& operations, and Customers & products. Each are managed separately, with decisions taken for the segment as a whole, and represent a single

operating segment that does not result from aggregating two or more segments.

Gas & low carbon energy comprises regions with upstream businesses that predominantly produce natural gas, gas marketing and trading

activities and the group's solar, wind, hydrogen and Archaea Energy business.

Oil production & operations comprises regions with upstream activities that predominantly produce crude oil.

Customers & products comprises the group's customer-focused businesses, which includes convenience and retail fuels, EV charging, as well as

Castrol, aviation, B2B, midstream and bp bioenergy. It also comprises our products businesses which include refining and oil trading.

Other businesses and corporate also comprises the group's shipping and treasury functions, and corporate activities worldwide.

Change in segmentation

For 2025, our Archaea Energy business has moved from the customers & products segment to the gas & low carbon energy segment. The change

in segmentation is consistent with a change in the way that resources are allocated, and performance is assessed by the chief operating decision

maker, who for bp is the group chief executive.

Comparative information for 2024 and 2023 has been restated where material to reflect the changes in reportable segments.

The accounting policies of the operating segments are the same as the group's accounting policies described in Note 1. However, IFRS requires that

the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker

for the purposes of performance assessment and resource allocation. For bp, this measure of profit or loss is replacement cost profit or loss before

interest and tax which reflects the replacement cost of supplies by excluding from profit or loss before interest and tax inventory holding gains and

losses<sup>a</sup>. Replacement cost profit or loss before interest and tax for the group is not a recognized measure under IFRS.

Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues and

segment results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on

consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers by region are

based on the location of the group subsidiary which made the sale. The UK region includes the UK-based international activities of customers &

products.

All surpluses and deficits recognized on the group balance sheet in respect of pension and other post-employment benefit plans are allocated to

Other businesses and corporate. However, the periodic expense relating to these plans is allocated to the operating segments based upon the

business in which the employees work.

Certain financial information is provided separately for the US as this is an individually material country for bp, and for the UK as this is bp's country

of domicile.

aInventory holding gains and losses represent:

• the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any

changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting of inventories other than for trading

inventories, the cost of inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this

can have a significant distorting effect on reported income. The amounts disclosed as inventory holding gains and losses represent the difference between the charge to the income statement

for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For

this purpose, the replacement cost of inventory is calculated using data from each operation's production and manufacturing system, either on a monthly basis, or separately for each

transaction where the system allows this approach.

• an adjustment relating to certain trading inventories that are not price risk managed which relate to a minimum inventory volume that is required to be held to maintain underlying business

activities. This adjustment represents the movement in fair value of the inventories due to prices, on a grade-by-grade basis, during the period. This is calculated from each operation's inventory

management system on a monthly basis using the discrete monthly movement in market prices for these inventories.

The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part

of a trading position and certain other temporary inventory positions that are price risk-managed.

---

| | |
|:---|:---|
| 186 | bp Annual Report and Form 20-F 2025 |

---

**5. Segmental analysis – continued**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  | $ million |
|  |  |  |  |  |  | **2025** |
| By business | **gas & low** <br>**carbon energy**<br>| **oil production &** <br>**operations**<br>| **customers &** <br>**products**<br>| **other**<br> **businesses &**<br>**corporate**<br>| **Consolidation** <br>**adjustment and** <br>**eliminations**<br>| **Total** <br>**group**<br>|
| **Segment revenues** |  |  |  |  |  |  |
| Sales and other operating revenues | **40333** | **24527** | **148783** | **2232** | **(26540)** | **189335** |
| Less: sales and other operating revenues between segments | **(1832)** | **(22876)** | **(43)** | **(1789)** | **26540** | **—** |
| Third party sales and other operating revenues | **38501** | **1651** | **148740** | **443** | **—** | **189335** |
| Earnings from joint ventures and associates – after interest <br>and tax<br>| **(501)** | **690** | **430** | **(1)** | **—** | **618** |
| **Segment results** |  |  |  |  |  |  |
| Replacement cost profit (loss) before interest and taxation | **1330** | **8558** | **4100** | **(40)** | **45** | **13993** |
| Inventory holding gains (losses)<sup>a</sup> | **—** | **2** | **(1353)** | **—** | **—** | **(1351)** |
| **Profit (loss) before interest and taxation** | **1330** | **8560** | **2747** | **(40)** | **45** | **12642** |
| Finance costs |  |  |  |  |  | **(5106)** |
| Net finance income relating to pensions and other post-<br>employment benefits<br>|  |  |  |  |  | **210** |
| **Profit before taxation** |  |  |  |  |  | **7746** |
| **Other income statement items** |  |  |  |  |  |  |
| Depreciation, depletion and amortization |  |  |  |  |  |  |
| US | **235** | **4992** | **1994** | **89** | **—** | **7310** |
| Non-US | **4734** | **2727** | **2151** | **900** | **—** | **10512** |
| Charges for provisions, net of write-back of unused <br>provisions, including change in discount rate<br>| **37** | **302** | **3180** | **666** | **—** | **4185** |
| **Segment assets** |  |  |  |  |  |  |
| Investments in joint ventures and associates | **7005** | **10488** | **3230** | **2** | **—** | **20725** |
| Additions to non-current assets<sup>b</sup> | **7188** | **9782** | **4617** | **885** | **—** | **22472** |

---

aSee explanation of inventory holding gains and losses on page [185](#i52a2201c1e4d4ffd913f5ac1bb26a505_10392).

bIncludes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 187 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**5. Segmental analysis – continued**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  | $ million |
|  |  |  |  |  |  | 2024 |
| By business | gas & low <br>carbon energy<sup>a</sup><br>| oil production & <br>operations<br>| customers & <br>products<sup>a</sup><br>| other <br>businesses & <br>corporate<br>| Consolidation <br>adjustment and <br>eliminations<br>| Total <br>group<br>|
| **Segment revenues** |  |  |  |  |  |  |
| Sales and other operating revenues | 32628 | 25637 | 155401 | 2290 | (26771) | 189185 |
| Less: sales and other operating revenues between segments | (1585) | (23237) | (317) | (1632) | 26771 |  |
| Third party sales and other operating revenues | 31043 | 2400 | 155084 | 658 |  | 189185 |
| Earnings from joint ventures and associates – after interest <br>and tax<br>| 504 | 1100 | 393 | (4) |  | 1993 |
| **Segment results** |  |  |  |  |  |  |
| Replacement cost profit (loss) before interest and taxation<sup>a</sup> | 3052 | 10789 | (1043) | (988) | (25) | 11785 |
| Inventory holding gains (losses)<sup>b</sup> |  | (9) | (479) |  |  | (488) |
| **Profit (loss) before interest and taxation**<sup>a</sup> | 3052 | 10780 | (1522) | (988) | (25) | 11297 |
| Finance costs |  |  |  |  |  | (4683) |
| Net finance income relating to pensions and other post- <br>&nbsp;&nbsp;&nbsp;&nbsp;employment benefits<br>|  |  |  |  |  | 168 |
| **Profit before taxation** |  |  |  |  |  | 6782 |
| **Other income statement items** |  |  |  |  |  |  |
| Depreciation, depletion and amortization |  |  |  |  |  |  |
| US | 95 | 4421 | 2142 | 89 |  | 6747 |
| Non-US | 4740 | 2376 | 1815 | 944 |  | 9875 |
| Charges for provisions, net of write-back of unused <br>provisions, including change in discount rate<br>| 38 | 92 | 2602 | 231 |  | 2963 |
| **Segment assets** |  |  |  |  |  |  |
| Investments in joint ventures and associates<sup>a</sup> | 6111 | 10730 | 3183 | 8 |  | 20032 |
| Additions to non-current assets<sup>a c</sup> | 12098 | 7296 | 6700 | 1045 |  | 27139 |

---

aRestated for material items to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment.

bSee explanation of inventory holding gains and losses on page [185](#i52a2201c1e4d4ffd913f5ac1bb26a505_10392).

cIncludes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.

---

| | |
|:---|:---|
| 188 | bp Annual Report and Form 20-F 2025 |

---

**5. Segmental analysis – continued**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  | $ million |
|  |  |  |  |  |  | 2023 |
| By business  | gas & low <br>carbon energy<sup>a</sup><br>| oil production & <br>operations<br>| customers & <br>products<sup>a</sup><br>| other <br>businesses & <br>corporate<br>| Consolidation <br>adjustment and <br>eliminations<br>| Total <br>group<br>|
| **Segment revenues** |  |  |  |  |  |  |
| Sales and other operating revenues | 50297 | 24904 | 160215 | 2657 | (27943) | 210130 |
| Less: sales and other operating revenues between segments | (1808) | (23708) | (367) | (2060) | 27943 |  |
| Third party sales and other operating revenues | 48489 | 1196 | 159848 | 597 |  | 210130 |
| Earnings from joint ventures and associates – after interest <br>and tax<br>| (677) | 1164 | 427 | (16) |  | 898 |
| **Segment results** |  |  |  |  |  |  |
| Replacement cost profit (loss) before interest and taxation | 14080 | 11191 | 4230 | (903) | (14) | 28584 |
| Inventory holding gains (losses)<sup>b</sup> | 1 |  | (1237) |  |  | (1236) |
| **Profit (loss) before interest and taxation** | 14081 | 11191 | 2993 | (903) | (14) | 27348 |
| Finance costs |  |  |  |  |  | (3840) |
| Net finance income relating to pensions and other post-<br>employment benefits<br>|  |  |  |  |  | 241 |
| **Profit before taxation** |  |  |  |  |  | 23749 |
| **Other income statement items** |  |  |  |  |  |  |
| Depreciation, depletion and amortization |  |  |  |  |  |  |
| US | 96 | 3554 | 1883 | 85 |  | 5618 |
| Non-US | 5584 | 2138 | 1665 | 923 |  | 10310 |
| Charges for provisions, net of write-back of unused <br>provisions, including change in discount rate<br>| 139 | 35 | 2007 | 152 |  | 2333 |
| **Segment assets** |  |  |  |  |  |  |
| Investments in joint ventures and associates<sup>a</sup> | 5404 | 10721 | 4096 | 28 |  | 20249 |
| Additions to non-current assets<sup>a c</sup> | 5451 | 7384 | 8791 | 1075 |  | 22701 |

---

aRestated for material items to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment.

bSee explanation of inventory holding gains and losses on page [185](#i52a2201c1e4d4ffd913f5ac1bb26a505_10392).

cIncludes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  |  |  | **2025** |
| By geographical area | **US** | **Non-US** | **Total** |
| **Revenues** |  |  |  |
| Third party sales and other operating revenues<sup>a</sup> | **56703** | **132632** | **189335** |
| **Other income statement items** |  |  |  |
| Production and similar taxes | **175** | **1523** | **1698** |
| **Non-current assets** |  |  |  |
| Non-current assets<sup>b c</sup> | **61269** | **77194** | **138463** |

---

aNon-US region includes UK $28,714 million

bNon-US region includes UK $21,529 million

cIncludes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  |  |  | 2024 |
| By geographical area | US | Non-US | Total |
| **Revenues** |  |  |  |
| Third party sales and other operating revenues<sup>a</sup> | 58804 | 130381 | 189185 |
| **Other income statement items** |  |  |  |
| Production and similar taxes | 149 | 1650 | 1799 |
| **Non-current assets** |  |  |  |
| Non-current assets<sup>b c</sup> | 63415 | 81937 | 145352 |

---

aNon-US region includes UK $24,577 million.

bNon-US region includes UK $25,354 million.

cIncludes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 189 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**5. Segmental analysis – continued**

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  |  |  | 2023 |
| By geographical area | US | Non-US | Total |
| **Revenues** |  |  |  |
| Third party sales and other operating revenues<sup>a</sup> | 60577 | 149553 | 210130 |
| **Other income statement items** |  |  |  |
| Production and similar taxes | 136 | 1643 | 1779 |
| **Non-current assets** |  |  |  |
| Non-current assets<sup>b c</sup> | 64238 | 83816 | 148054 |

---

aNon-US region includes UK $39,975 million.

bNon-US region includes UK $23,949 million.

cIncludes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.

**6. Sales and other operating revenues** 

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| Crude oil | **2063** | 2219 | 2413 |
| Oil products | **114207** | 121019 | 128969 |
| Natural gas, LNG and NGLs | **27477** | 24464 | 29541 |
| Non-oil products and other revenues from contracts with customers | **15132** | 13362 | 10298 |
| **Revenue from contracts with customers** | **158879** | 161064 | 171221 |
| Other operating revenues<sup>a</sup> | **30456** | 28121 | 38909 |
| **Total sales and other operating revenues** | **189335** | 189185 | 210130 |

---

aPrincipally relates to commodity derivative transactions including sales of bp own production in trading books.

An analysis of third-party sales and other operating revenues by segment and region is provided in Note 5.

The group's sales to customers of crude oil and oil products were substantially all made by the customers & products segment. The group's sales

to customers of natural gas, LNG and NGLs were made by the gas & low carbon energy segment. A significant majority of the group's sales of non-

oil products and other revenues from contracts with customers were made by the customers & products segment.

**7. Income statement analysis** 

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| **Interest and other income** |  |  |  |
| Interest income from |  |  |  |
| Financial assets measured at amortized cost | **1203** | 1308 | 1034 |
| Financial assets measured at fair value through profit or loss | **129** | 181 | 215 |
| Other income<sup>a</sup> | **277** | 1284 | 386 |
|  | **1609** | 2773 | 1635 |
| Currency exchange losses charged to the income statement<sup>b</sup> | **(295)** | 541 | 74 |
| Expenditure on research and development | **274** | 301 | 298 |
| Costs relating to the Gulf of America oil spill (pre-interest and tax)<sup>c</sup> | **31** | 51 | 57 |
| **Finance costs** |  |  |  |
| Interest expense on lease liabilities | **704** | 468 | 363 |
| Interest expense on other liabilities measured at amortized cost<sup>d</sup> | **3419** | 3483 | 3115 |
| Capitalized at 4.69% (2024 4.94% and 2023 4.88%)<sup>e</sup> | **(142)** | (382) | (514) |
| Finance debt risk management activities<sup>f</sup> | **(22)** | 104 | (35) |
| Unwinding of discount on provisions | **675** | 617 | 504 |
| Unwinding of discount on other payables measured at amortized cost | **472** | 393 | 407 |
|  | **5106** | 4683 | 3840 |

---

a2024 includes a $427 million gain relating to the remeasurement of bp's previously held interests in bp Bunge Bioenergia and Lightsource bp and $498 million relating to the remeasurement of

certain US assets excluded from the Lightsource bp acquisition. See Note 3 for further information.

bExcludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss.

cIncluded within production and manufacturing expenses.

d2023 includes a loss of $49 million associated with the buyback of finance debt.

eTax relief on capitalized interest is approximately $36 million (2024 $53 million and 2023 $130 million).

fIncludes temporary valuation differences related to the group's interest rate and foreign currency exchange risk management associated with finance debt.

---

| | |
|:---|:---|
| 190 | bp Annual Report and Form 20-F 2025 |

---

**8. Exploration for and evaluation of oil and natural gas resources** 

The following financial information represents the amounts included within the group totals relating to activity associated with the exploration for

and evaluation of oil and natural gas resources. All such activity is recorded within the gas & low carbon energy and oil production & operations

segments.

For information on significant judgements made in relation to oil and natural gas accounting see Intangible assets in Note 1.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| Exploration and evaluation costs |  |  |  |
| Exploration expenditure written off | **343** | 767 | 746 |
| Other exploration costs | **227** | 207 | 251 |
| Exploration expense for the year | **570** | 974 | 997 |
| Impairment losses | **26** | 6 | 20 |
| Intangible assets – exploration and appraisal expenditure<sup>a</sup> | **3963** | 4438 | 4328 |
| Liabilities | **33** | 76 | 109 |
| Net assets | **3930** | 4362 | 4219 |
| Cash used in operating activities | **227** | 207 | 251 |
| Cash used in investing activities | **1169** | 1513 | 1039 |

---

aAmount capitalized at 31 December 2025, 2024 and 2023 relates to assets in various regions. This includes $536 million in the Brazil region (2024 $395 million, 2023 $418 million), $776 million in

the Middle East and North Africa region (2024 $1,289 million, 2023 $1,182 million) and $609 million in the Azerbaijan Georgia and Türkiye region (2024 $651 million, 2023 $631 million).

**9. Taxation** 

**Tax on profit**

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| **Current tax** |  |  |  |
| Charge for the year<sup>a</sup> | **6501** | 7187 | 9048 |
| Adjustment in respect of prior years | **(188)** | 234 | (373) |
|  | **6313** | 7421 | 8675 |
| **Deferred tax** |  |  |  |
| Origination and reversal of temporary differences in the current year<sup>b</sup> | **(537)** | (1851) | (238) |
| Adjustment in respect of prior years<sup>c</sup> | **675** | (17) | (568) |
|  | **138** | (1868) | (806) |
| **Tax charge on profit** | **6451** | 5553 | 7869 |

---

a2025 includes a charge of $55 million (2024 $4 million charge) in respect of Pillar Two income taxes.

b2025 includes a charge of $539 million in respect of the two-year extension of the UK Energy Profits Levy to 31 March 2030 and a charge of $235 million in respect of a change in the tax rate in

Germany. 2024 includes a charge of $96 million in respect of the 3% increase in the UK Energy Profits Levy from 1 November 2024. See Note 1 for further information.

cThe adjustment in respect of prior years reflects the reassessment of the deferred tax balances for prior periods in light of changes in facts and circumstances during the year, including changes

to price assumptions and profit forecasts (2025 $558 million charge, 2024 $190 million credit and 2023 $263 million credit). 2024 also includes a charge of $213 million (2023 $232 million credit) in

respect of a revision to the deferred tax impact of the UK Energy Profits Levy.

In 2025, the total tax credit recognized within other comprehensive income was $33 million (2024 $782 million credit and 2023 $735 million credit).

In 2025 and 2023 this primarily comprises the deferred tax impact of the remeasurements of the net pension and other post-employment benefit

liability or asset. In 2024 this primarily comprises a $658 million credit in respect of the reduction in the deferred tax liability on defined benefit

pension plan surpluses following the reduction in the rate of the authorized surplus payments tax charge in the UK from 35% to 25%. See Note 32

for further information.

The total tax credit recognized directly in equity was $33 million (2024 $167 million charge and 2023 $56 million charge). In 2025 this relates to

share-based payments. In 2024 this mainly relates to share-based payments and transactions involving non-controlling interests. In 2023 this

mainly relates to transactions involving non-controlling interests.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 191 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**9. Taxation – continued**

**Reconciliation of the effective tax rate**

The following table provides a reconciliation of the group weighted average statutory corporate income tax rate to the effective tax rate of the

group on profit or loss before taxation.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| **Profit (loss) before taxation** | **7746** | 6782 | 23749 |
| Tax charge (credit) on profit or loss | **6451** | 5553 | 7869 |
| Effective tax rate | **83%** | 82% | 33% |
|  |  |  | % |
| Tax rate computed at the weighted average statutory rate<sup>a</sup> | **55** | 66 | 34 |
| Increase (decrease) resulting from |  |  |  |
| Tax reported in equity-accounted entities | **(5)** | (7) | (2) |
| Adjustments in respect of prior years | **6** | 3 | (4) |
| Deferred tax not recognized | **5** | 5 | 2 |
| Disposal impacts | **—** | 5 |  |
| Foreign exchange | **(4)** | 5 |  |
| Items not deductible for tax purposes<sup>b</sup> | **11** | 5 | 2 |
| Tax rate change effect of UK Energy Profits Levy<sup>c</sup> | **7** | 1 |  |
| Impact of Germany tax rate change | **3** |  |  |
| Other<sup>d</sup> | **5** | (1) | 1 |
| **Effective tax rate** | **83** | 82 | 33 |

---

aCalculated based on the statutory corporate income tax rate applicable in the countries in which the group operates, weighted by the profits and losses before tax in the respective countries.

b2025 reflects the impact of limited tax relief on impairment charges.

c2025 comprises the deferred tax impact of the two-year extension of the UK Energy Profits Levy to 31 March 2030. 2024 comprises the deferred tax impact of a 3% increase in the UK Energy

Profits Levy on existing temporary differences.

dIncludes the impact of adjustments arising in countries where income tax is paid on our behalf by our government partners for which there is no deferred tax effect. 2024 includes the impact of

the non-taxable gain relating to the remeasurement of bp's pre-existing 49.97% interest in Lightsource bp and the remeasurement of certain US assets excluded from the Lightsource bp

acquisition.

**Deferred tax**

---

| | | |
|:---|:---|:---|
|  |  | $ million |
| Analysis of movements during the year in the net deferred tax liability | **2025** | 2024 |
| **At 1 January** | **3025** | 5349 |
| Exchange adjustments | **(63)** | 57 |
| Charge (credit) for the year in the income statement | **138** | (1868) |
| Charge (credit) for the year in other comprehensive income | **(33)** | (807) |
| Charge (credit) for the year in equity | **(33)** | 167 |
| Acquisitions and disposals | **283** | 127 |
| **At 31 December** | **3317** | 3025 |

---

---

| | |
|:---|:---|
| 192 | bp Annual Report and Form 20-F 2025 |

---

**9. Taxation – continued**

The following table provides an analysis of deferred tax in the income statement and the balance sheet by category of temporary difference:

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  | $ million |
|  |  | Income statement | Income statement | Balance sheet | Balance sheet |
|  | **2025** | 2024 | 2023 | **2025** | 2024 |
| **Deferred tax liability** |  |  |  |  |  |
| Depreciation | **(897)** | (1337) | (1552) | **15474** | 16333 |
| Pension plan surpluses | **(3)** | 62 | 133 | **1860** | 1789 |
| Derivative financial instruments | **37** | 40 | 12 | **106** | 58 |
| Other taxable temporary differences<sup>a</sup> | **37** | (352) | 10 | **824** | 663 |
|  | **(826)** | (1587) | (1397) | **18264** | 18843 |
| **Deferred tax asset** |  |  |  |  |  |
| Depreciation | **993** | (229) | (166) | **(1544)** | (2373) |
| Lease liabilities | **(395)** | (209) | (176) | **(2375)** | (1952) |
| Pension plan and other post-employment benefit plan deficits | **48** | 28 | (60) | **(552)** | (623) |
| Decommissioning, environmental and other provisions | **(314)** | 425 | 563 | **(5981)** | (5623) |
| Derivative financial instruments | **(48)** | (9) | (14) | **(277)** | (268) |
| Tax credits | **(111)** | (43) | (67) | **(1047)** | (937) |
| Loss carry forward | **580** | 194 | 296 | **(1852)** | (2285) |
| Other deductible temporary differences<sup>b</sup> | **211** | (438) | 215 | **(1319)** | (1757) |
|  | **964** | (281) | 591 | **(14947)** | (15818) |
| **Net deferred tax charge (credit) and net deferred tax liability** | **138** | (1868) | (806) | **3317** | 3025 |
| Of which – deferred tax liabilities |  |  |  | **7642** | 8428 |
| – deferred tax assets |  |  |  | **4325** | 5403 |

---

aThe 2025 and 2024 balance sheet amounts do not include any temporary differences that are individually significant.

bThe 2025 and 2024 balance sheet amounts include amounts relating to share based payments and other items.

Of the $4,325 million of deferred tax assets recognized on the group balance sheet at 31 December 2025 (2024 $5,403 million), $2,795 million (2024

$3,232 million) relates to entities that have suffered a loss in either the current or preceding period. For 2025, this mainly includes $1,613 million in

Germany, $473 million in Senegal and $388 million in Mauritania (2024 mainly included $1,680 million in Germany, $744 million in Mauritania and

$609 million in Senegal). For 2025, these amounts are supported by forecasts consistent with bp's future oil and gas price assumptions (see Note 1

for further information) and other assumptions used for impairment testing, and for Germany forecast profits associated with the customers &

products businesses that indicate sufficient future taxable profits will be available to utilize such assets within any applicable expiry period.

A summary of temporary differences, unused tax credits and unused tax losses for which deferred tax has not been recognized is shown in the

table below.

---

| | | |
|:---|:---|:---|
|  |  | $ billion |
| At 31 December | **2025** | 2024 |
| Unused US state tax losses<sup>a</sup> | **2.9** | 2.3 |
| Unused tax losses – other jurisdictions<sup>b</sup> | **9.4** | 7.3 |
| Unused tax credits | **36.7** | 33.3 |
| of which – arising in the UK<sup>c</sup> | **33.2** | 29.1 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; – arising in the US<sup>d</sup> | **3.5** | 4.2 |
| Deductible temporary differences<sup>e</sup> | **28.3** | 23.4 |
| Taxable temporary differences associated with investments in subsidiaries and equity-accounted entities | **0.7** | 0.7 |

---

aFor 2025 the majority of the unused tax losses have no fixed expiry date.

b2025 and 2024 mainly relate to Brazil, UK and Canada. The majority of the unused tax losses have no fixed expiry date.

cThe UK unused tax credits arise predominantly in overseas branches of UK entities based in jurisdictions with higher statutory corporate income tax rates than the UK. No deferred tax asset has

been recognized on these tax credits as they are unlikely to have value in the future; UK taxes on these overseas branches are largely mitigated by double tax relief in respect of overseas tax.

These tax credits have no fixed expiry date.

dThe US unused tax credits predominantly comprise foreign tax credits. No deferred tax asset has been recognized on these tax credits as they are unlikely to have value in the future. For 2025

these tax credits expire in the period 2026-2035.

e2025 and 2024 mainly comprise fixed asset temporary differences in overseas branches of UK entities. Substantially all of the temporary differences have no expiry date.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
| Impact of previously unrecognized deferred tax or write-down of deferred tax assets on tax charge | **2025** | 2024 | 2023 |
| Current tax benefit relating to the utilization of previously unrecognized deferred tax assets | **101** | 87 | 360 |
| Deferred tax benefit arising from the reversal of a previous write-down of deferred tax assets | **11** | 14 | 3 |
| Deferred tax benefit relating to the recognition of previously unrecognized deferred tax assets | **156** | 280 | 332 |
| Deferred tax expense arising from the write-down of a previously recognized deferred tax asset | **725** | 111 | 54 |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 193 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**10. Dividends** 

The quarterly dividend which is expected to be paid on 27 March 2026 in respect of the fourth quarter 2025 is 8.320 cents per ordinary share

($0.4992 per American Depositary Share (ADS)). The corresponding amount in sterling will be announced on 17 March 2026.

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | Pence per share | Pence per share | Pence per share | Cents per share | Cents per share | Cents per share |  |  | $ million |
|  | **2025** | 2024 | 2023 | **2025** | 2024 | 2023 | **2025** | 2024 | 2023 |
| Dividends announced and paid in cash |  |  |  |  |  |  |  |  |  |
| Preference shares |  |  |  |  |  |  | **1** | 1 | 1 |
| Ordinary shares |  |  |  |  |  |  |  |  |  |
| March | **6.1761** | 5.6922 | 5.5507 | **8.000** | 7.270 | 6.610 | **1257** | 1218 | 1183 |
| June | **5.8993** | 5.6825 | 5.3089 | **8.000** | 7.270 | 6.610 | **1237** | 1204 | 1152 |
| September | **6.1942** | 6.0498 | 5.7320 | **8.320** | 8.000 | 7.270 | **1288** | 1297 | 1249 |
| December | **6.2394** | 6.2959 | 5.7367 | **8.320** | 8.000 | 7.270 | **1276** | 1283 | 1224 |
|  | **24.5090** | 23.7204 | 22.3283 | **32.640** | 30.540 | 27.760 | **5059** | 5003 | 4809 |
| Dividend announced, paid in March 2026 |  |  |  | **8.320** |  |  | **1280** |  |  |

---

The amount of unclaimed dividends recognized as a liability in other payables at 31 December 2025 is $134 million (2024 $106 million).

The board decided not to offer a scrip dividend alternative in respect of any dividends announced since the third quarter 2019, including the fourth

quarter 2025 dividend expected to be paid on 27 March 2026.

The financial statements for the year ended 31 December 2025 do not reflect the dividend announced on 10 February 2026 and which is expected to

be paid on 27 March 2026; this will be treated as an appropriation of profit in the year ending 31 December 2026.

**11. Earnings per share** 

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | Cents per share |
| Per ordinary share | **2025** | 2024 | 2023 |
| Basic earnings per share | **0.35** | 2.38 | 87.78 |
| Diluted earnings per share | **0.34** | 2.32 | 85.85 |
|  |  | Dollars per share | Dollars per share |
| Per American Depositary Share (ADS)<sup>a</sup> | **2025** | 2024 | 2023 |
| Basic earnings per share | **0.02** | 0.14 | 5.27 |
| Diluted earnings per share | **0.02** | 0.14 | 5.15 |

---

aOne ADS is equivalent to six ordinary shares.

Basic earnings per ordinary share amounts are calculated by dividing the profit for the year attributable to bp ordinary shareholders by the

weighted average number of ordinary shares outstanding during the year.

The weighted average number of shares outstanding includes certain shares that will be issuable in the future under employee share-based

payment plans and excludes treasury shares, which includes shares held by the Employee Share Ownership Plan trusts (ESOPs).

For the diluted earnings per share calculation, the weighted average number of shares outstanding during the year is adjusted for the average

number of shares that are potentially issuable in connection with employee share-based payment plans. If the inclusion of potentially issuable

shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used

to calculate diluted earnings per share.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| Profit (loss) attributable to bp shareholders | **55** | 381 | 15239 |
| Less: dividend requirements on preference shares | **1** | 1 | 1 |
| Less: (gain) loss on redemption of perpetual hybrid bonds<sup>a</sup> | **—** | (10) |  |
| **Profit (loss) for the year attributable to bp ordinary shareholders** | **54** | 390 | 15238 |
|  |  |  | Shares thousand |
|  | **2025** | 2024 | 2023 |
| Basic weighted average number of ordinary shares<sup>b</sup> | **15586782** | 16385535 | 17360288 |
| Potential dilutive effect of ordinary shares issuable under employee share-based payment <br>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;plans<br>| **326218** | 431129 | 389790 |
| **Weighted average number of ordinary shares outstanding used to calculate diluted earnings** <br>**per share**<br>| **15913000** | 16816664 | 17750078 |
|  |  |  | Shares thousand |
|  | **2025** | 2024 | 2023 |
| Basic weighted average number of ordinary shares – ADS equivalent | **2597797** | 2730922 | 2893381 |
| Potential dilutive effect of ordinary shares (ADS equivalent) issuable under employee share-<br>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;based payment plans<br>| **54369** | 71855 | 64965 |
| **Weighted average number of ordinary shares (ADS equivalent) outstanding used to calculate** <br>**diluted earnings per share**<br>| **2652166** | 2802777 | 2958346 |

---

aSee Note 32 - *non-controlling interests* for further information.

bExcludes treasury shares. See Note 31 for further information.

---

| | |
|:---|:---|
| 194 | bp Annual Report and Form 20-F 2025 |

---

**11. Earnings per share – continued**

The number of ordinary shares outstanding at 31 December 2025, excluding treasury shares, and including certain shares that will be issuable in the

future under employee share-based payment plans was 15,377,210,044 (2024 15,851,028,983). Between 31 December 2025 and 13 February 2026, the

latest practicable date before the completion of these financial statements, there was a net decrease of 48,533,512 of ordinary shares primarily as a

result of share buy backs. For additional information on share buy backs see Note 31.

**Employee share-based payment plans**

The group operates share and share option plans for directors and certain employees to obtain ordinary shares and ADSs in the company.

The following table shows the number of shares potentially issuable under equity-settled employee share option plans, including the number of

options outstanding, the number of options exercisable at the end of each year, and the corresponding weighted average exercise prices. The

dilutive effect of these plans at 31 December is also shown.

---

| | | | | |
|:---|:---|:---|:---|:---|
| Share options |  | **2025** |  | 2024 |
|  | **Number of options**<sup>a b</sup><br>**thousand**<br>| **Weighted average**<br> **exercise price $**<br>| Number of options<sup>a b</sup><br>thousand<br>| Weighted average<br> exercise price $|
| Outstanding | **382873** | **4.21** | 533895 | 4.15 |
| Exercisable | **345112** | **4.23** | 2931 | 3.38 |
| Dilutive effect | **80562** | **n/a** | 140971 | n/a |

---

aNumbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).

bAt 31 December 2025 the quoted market price of one bp ordinary share was £4.33 (2024 £3.93).

In addition, the group operates a number of equity-settled employee share plans under which share units are granted to the group's senior leaders

and certain other employees. These plans typically have a three-year performance or restricted period during which the units accrue net notional

dividends which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into shares, but special

arrangements apply for participants that leave for qualifying reasons. The number of shares that are expected to vest each year under employee

share plans are shown in the table below. The dilutive effect of the employee share plans at 31 December is also shown.

---

| | | |
|:---|:---|:---|
| Share plans | **2025** | 2024 |
|  | **Number of shares**<sup>a</sup> | Number of shares<sup>a</sup> |
| Vesting | **thousand** | thousand |
| Within one year | **155555** | 271216 |
| 1 to 2 years | **116997** | 134342 |
| 2 to 3 years | **105074** | 102525 |
| 3 to 4 years | **366** | 956 |
| Over 4 years | **43** | 118 |
|  | **378035** | 509157 |
| **Dilutive effect** | **161105** | 269796 |

---

aNumbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).

There has been a net increase of 30,497,988 in the number of potential ordinary shares relating to employee share-based payment plans between

31 December 2025 and 13 February 2026.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 195 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**12. Property, plant and equipment (PP&E)**

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | $ million |
|  | **Land and land** <br>**improvements**<br>| **Buildings** | **Oil and gas** <br>**properties**<sup>a</sup><br>| **Plant,** <br>**machinery** <br>**and** <br>**equipment**<br>| **Fittings,** <br>**fixtures and** <br>**office** <br>**equipment**<br>| **Transportation** | **Oil depots,** <br>**storage tanks** <br>**and service** <br>**stations**<br>| **Total** |
| **Cost - owned PP&E** |  |  |  |  |  |  |  |  |
| At 1 January 2025 | **4060** | **1167** | **184304** | **48731** | **2315** | **2687** | **12417** | **255681** |
| Exchange adjustments | **299** | **47** | **—** | **1403** | **78** | **19** | **1011** | **2857** |
| Additions | **23** | **131** | **9896** | **2667** | **89** | **125** | **784** | **13715** |
| Acquisitions | **—** | **18** | **—** | **68** | **—** | **—** | **3** | **89** |
| Transfers from intangible assets | **—** | **—** | **3593** | **—** | **—** | **—** | **—** | **3593** |
| Reclassified as assets held for sale | **(72)** | **(69)** | **(923)** | **(1755)** | **(137)** | **(3)** | **(314)** | **(3273)** |
| Deletions and disposals | **(299)** | **(4)** | **(2074)** | **(1047)** | **(176)** | **(38)** | **(693)** | **(4331)** |
| **At 31 December 2025** | **4011** | **1290** | **194796** | **50067** | **2169** | **2790** | **13208** | **268331** |
| **Depreciation - owned PP&E** |  |  |  |  |  |  |  |  |
| At 1 January 2025 | **876** | **520** | **128091** | **26929** | **1716** | **1933** | **6561** | **166626** |
| Exchange adjustments | **60** | **17** | **—** | **961** | **50** | **8** | **629** | **1725** |
| Charge for the year | **47** | **60** | **11458** | **1741** | **138** | **102** | **771** | **14317** |
| Impairment losses | **11** | **5** | **568** | **1224** | **—** | **11** | **42** | **1861** |
| Impairment reversals | **(10)** | **—** | **(9)** | **(3)** | **—** | **(4)** | **(2)** | **(28)** |
| Transfers from intangible assets | **—** | **—** | **2285** | **—** | **—** | **—** | **—** | **2285** |
| Reclassified as assets held for sale | **(9)** | **(41)** | **(423)** | **(967)** | **(102)** | **(2)** | **(187)** | **(1731)** |
| Deletions and disposals | **(28)** | **(4)** | **(1843)** | **(795)** | **(167)** | **(36)** | **(472)** | **(3345)** |
| **At 31 December 2025** | **947** | **557** | **140127** | **29090** | **1635** | **2012** | **7342** | **181710** |
| Owned PP&E - net book amount at 31 December <br>2025<br>| **3064** | **733** | **54669** | **20977** | **534** | **778** | **5866** | **86621** |
| Right-of-use assets - net book amount at 31 <br>December 2025<sup>b</sup><br>| **—** | **1894** | **748** | **1863** | **—** | **2311** | **5196** | **12012** |
| **Total PP&E - net book amount at 31 December** <br>**2025**<br>| **3064** | **2627** | **55417** | **22840** | **534** | **3089** | **11062** | **98633** |
| **Cost - owned PP&E** |  |  |  |  |  |  |  |  |
| At 1 January 2024 | 3924 | 992 | 185346 | 47384 | 2290 | 2958 | 12224 | 255118 |
| Exchange adjustments | (213) | (35) |  | (864) | (43) | (23) | (637) | (1815) |
| Additions | 352 | 222 | 7899 | 3039 | 138 | 144 | 1042 | 12836 |
| Acquisitions | 60 | 148 |  | 1235 | 57 | 80 | 70 | 1650 |
| Transfers from intangible assets |  |  | 391 |  |  |  |  | 391 |
| Reclassified as assets held for sale | (25) | (41) | (3210) | (747) | (1) |  |  | (4024) |
| Deletions and disposals | (38) | (119) | (6122) | (1316) | (126) | (472) | (282) | (8475) |
| **At 31 December 2024** | 4060 | 1167 | 184304 | 48731 | 2315 | 2687 | 12417 | 255681 |
| **Depreciation - owned PP&E** |  |  |  |  |  |  |  |  |
| At 1 January 2024 | 838 | 553 | 123442 | 25671 | 1684 | 2292 | 6363 | 160843 |
| Exchange adjustments | (52) | (9) |  | (536) | (24) | (9) | (388) | (1018) |
| Charge for the year | 58 | 43 | 10626 | 1553 | 157 | 91 | 731 | 13259 |
| Impairment losses | 70 |  | 2418 | 1260 | 1 | 9 | 82 | 3840 |
| Impairment reversals |  |  | (420) | (4) |  | (3) |  | (427) |
| Reclassified as assets held for sale | (6) | (4) | (2168) | (367) | (1) |  |  | (2546) |
| Deletions and disposals | (32) | (63) | (5807) | (648) | (101) | (447) | (227) | (7325) |
| **At 31 December 2024** | 876 | 520 | 128091 | 26929 | 1716 | 1933 | 6561 | 166626 |
| Owned PP&E - net book amount at 31 December <br>2024<br>| 3184 | 647 | 56213 | 21802 | 599 | 754 | 5856 | 89055 |
| Right-of-use assets - net book amount at 31 <br>December 2024<sup>b</sup><br>|  | 1613 | 41 | 1431 | 10 | 2589 | 5499 | 11183 |
| **Total PP&E - net book amount at 31 December** <br>**2024**<br>| 3184 | 2260 | 56254 | 23233 | 609 | 3343 | 11355 | 100238 |
| Assets under construction included above |  |  |  |  |  |  |  |  |
| **At 31 December 2025** |  |  |  |  |  |  |  | **11653** |
| At 31 December 2024 |  |  |  |  |  |  |  | 10722 |
| Depreciation charge for the year on right-of-use assets |  |  |  |  |  |  |  |  |
| **2025** |  | **342** | **55** | **728** | **3** | **1026** | **874** | **3028** |
| 2024 |  | 215 | 30 | 640 | 3 | 1109 | 882 | 2878 |

---

aFor information on significant estimates and judgements made in relation to the estimation of oil and natural reserves see Property, plant and equipment within Note 1.

b$1,072 million (2024 $867 million) of drilling rig right-of-use assets and $2,119 million (2024 $2,455 million) of shipping vessel right-of-use assets are included in Plant, machinery and equipment

and Transportation respectively.

---

| | |
|:---|:---|
| 196 | bp Annual Report and Form 20-F 2025 |

---

**13. Capital commitments** 

Authorized future capital expenditure for property, plant and equipment (excluding right-of-use assets) by group companies for which contracts

had been signed at 31 December 2025 amounted to $14,639 million (2024 $13,642 million, 2023 $10,354 million). bp has contracted capital

commitments amounting to $2,238 million (2024 $3,392 million, 2023 $1,580 million) in relation to joint ventures and $89 million (2024 $59 million,

2023 $105 million) in relation to associates.

**14. Goodwill and impairment review of goodwill** 

---

| | | |
|:---|:---|:---|
|  |  | $ million |
|  | **2025** | 2024 |
| **Cost** |  |  |
| At 1 January | **15530** | 13176 |
| Exchange adjustments | **397** | (179) |
| Acquisitions and other additions | **(89)** | 2734 |
| Reclassified as assets held for sale | **(2756)** | (79) |
| Deletions and disposals | **(133)** | (122) |
| **At 31 December** | **12949** | 15530 |
| **Impairment losses** |  |  |
| At 1 January | **642** | 704 |
| Exchange adjustments | **30** | (2) |
| Impairment losses for the year | **2009** |  |
| Deletions and disposals | **(32)** | (60) |
| **At 31 December** | **2649** | 642 |
| **Net book amount at 31 December** | **10300** | 14888 |
| Net book amount at 1 January | **14888** | 12472 |

---

**Impairment review of goodwill**

---

| | | |
|:---|:---|:---|
|  |  | $ million |
| Goodwill at 31 December | **2025** | 2024 |
| gas & low carbon energy<sup>a</sup> | **3185** | 5166 |
| oil production & operations | **4870** | 4925 |
| customers & products<sup>a</sup> | **2245** | 4797 |
| other businesses & corporate | **—** |  |
|  | **10300** | 14888 |

---

a2024 restated to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment.

Goodwill acquired through business combinations has been allocated to groups of cash-generating units (CGUs) that are expected to benefit from

the synergies of the acquisition. For oil production & operations goodwill is allocated to CGUs in aggregate at the segment level, for gas & low

carbon energy, goodwill is allocated to the hydrocarbon CGUs ('upstream gas businesses') within the segment and to Lightsource bp (LSbp) and

Archaea Energy ('transition businesses'). For customers and products, goodwill has been allocated to Castrol, US Fuels, European Fuels and Other.

For information on significant estimates and judgements made in relation to impairments see Impairment of property, plant and equipment,

intangible assets and goodwill in Note 1.

gas & low carbon energy and oil production & operations

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  | $ million |  | $ million |
|  |  |  |  | **gas & low carbon energy** | | | **oil production & operations** | **oil production & operations** |
|  |  |  | **2025** |  |  | 2024 | **2025** | 2024 |
|  | **Upstream gas** <br>**businesses**<br>| **Transition** <br>**businesses**<br>| **Total** | Upstream <br>gas <br>businesses<br>| Transition <br>businesses<br>| Total<sup>a</sup> |  |  |
| Goodwill<sup>a</sup> | **2260** | **925** | **3185** | 2228 | 2938 | 5166 | **4870** | 4925 |
| Excess of recoverable amount over carrying <br>amount<br>| **2917** | **—** | **2917** | 2026 | n/a | 2026 | **13748** | 12432 |

---

aRestated to reflect the move of Archaea Energy from the customers & products segment to the gas & low carbon energy segment.

The table above shows the carrying amount of goodwill for the segments at the period end and the excess of the recoverable amount over the

carrying amount (headroom) at the date of the most recent test. The recoverable amounts for the upstream gas businesses and transition

businesses are based on value-in-use calculations. The increase in headroom for the goodwill impairment tests for the upstream gas businesses is

due to the passage of time and price impacts. For oil production & operations management have rolled-forward the most recent detailed

calculation as the criteria set out in IAS 36 for doing so were met.

During 2025 impairment charges of $2,009 million were recognized against the transition businesses goodwill balance. The impairment charges

arose as a result of changes in assumptions including future capital and operating expenditure and project development. No impairment of the

goodwill in the upstream gas businesses was recognized in 2025 or 2024. No impairment of the goodwill in oil production & operations was

recognized during 2025 or 2024.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 197 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**14. Goodwill and impairment review of goodwill – continued**

**Upstream gas businesses and oil production & operations**

The value in use for relevant CGUs in both the upstream gas businesses and oil production & operations is based on the cash flows expected to be

generated by the projected production profiles up to the expected dates of cessation of production of each field, based on appropriately risked

estimates of reserves and resources. Midstream and supply and trading activities and equity-accounted entities are generally not included in the

impairment reviews of goodwill, as they do not represent part of the grouping of CGUs to which the goodwill balances relate and which are used to

monitor the goodwill balances for internal management purposes. Where such activities form part of wider CGUs to which goodwill relates they are

reflected in the test. As the production profile and related cash flows can be estimated from bp's past experience, management believes that the

cash flows generated over the estimated life of field is the appropriate basis upon which to assess goodwill and individual assets for impairment in

both the upstream gas businesses and oil & production operations. The estimated date of cessation of production depends on the interaction of a

number of variables, such as the recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of the development

of the infrastructure necessary to recover the hydrocarbons, production costs, the contractual duration of the production concession and the

selling price of the hydrocarbons produced. As each field has specific reservoir characteristics and economic circumstances, the cash flows of

each field are computed using appropriate individual economic models and key assumptions agreed by bp management.

Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis, including operating and capital

expenditure, are derived from the business segment plans. The production profiles used are consistent with the reserve and resource volumes

approved as part of bp's centrally controlled process for the estimation of proved and probable reserves and total resources.

The average production for the purposes of goodwill impairment testing in the upstream gas businesses over the next 15 years is 146 mmboe per

year (2024 154 mmboe per year) and in the oil production and operations segment is 400 mmboe per year (2024 400 mmboe per year). Production

assumptions used for the goodwill impairment tests in both the upstream gas businesses and oil production & operations reflect management's

best estimate of future production of the existing portfolio at the time of the calculation.

The weighted-average pre-tax discount rate used in the review for the oil production & operations segment is 17%, and 11% for the gas businesses

(2024 17% for the oil production & operations segment and 11% for the gas businesses).

The most recent reviews for impairment for the oil production & operations and the upstream gas businesses were carried out in the fourth quarter.

The key assumptions used in the value-in-use calculations are oil and natural gas prices, production volumes and the discount rate. The value-in-

use calculations have been prepared for the purposes of determining whether the goodwill balances were impaired. For the upstream gas

businesses , estimated future cash flows were prepared on the basis of certain assumptions prevailing at the time of the tests. For the oil

production & operations segment, as permitted by IAS 36, the detailed calculations for recoverable amounts performed in 2024 were used as a

basis for the 2025 impairment tests. The recoverable amounts, key assumptions and sensitivity calculations for 2025 are prepared using the

remaining future cashflows from the 2024 detailed calculations. The headrooms for 2025 do not represent the headrooms that would result if a

test was run based on discounted future cashflows estimated using 2025 data and assumptions. The actual outcomes may differ from the

assumptions made. For example, reserves and resources estimates and production forecasts are subject to revision as further technical

information becomes available and economic conditions change. Due to economic developments, regulatory change and emissions reduction

activity arising from climate concern and other factors, future commodity prices and other assumptions may differ from the forecasts used in the

calculations.

Sensitivities to different variables have been estimated using certain simplifying assumptions. For example, lower oil and gas price or production

sensitivities do not fully reflect the specific impacts for each contractual arrangement and will not capture all favourable impacts that may arise

from cost deflation or savings. A detailed calculation at any given price or production profile may, therefore, produce a different result.

It is estimated that an 11% (2024 11%) reduction in revenue throughout each year of the remaining life of those assets, either as a result of adverse

price or production conditions or a combination of each, would cause the recoverable amount to be equal to the carrying amount of goodwill and

related net non-current assets of the oil production and operations segment. For the gas businesses a 9% (2024 6%) reduction would have the

same result.

It is estimated that no reasonably possible change in the discount rate would cause the recoverable amount to be equal to the carrying amount of

goodwill and related net non-current assets.

**Transition businesses**

The transition businesses goodwill relates to the acquisitions of Archaea Energy and Lightsource bp. Cash flows were derived from the approved

business plans.

For Archaea Energy, cash flows are derived from the approved business plan, which covers the period up to 2050. To determine the value in use,

approved business plan cash flows were discounted and aggregated with a terminal value.

For Lightsource bp, cash flows for a period of 10 years were discounted and aggregated with a terminal value. Management considers the use of 10

years of plan cash flows before adding a terminal value to be appropriate reflecting the maturity of the business with an early stage development

portfolio and other aspects of business model changes such that 10 years reflected an appropriate 'steady state' of development project sales and

other income from which terminal value cash flows could be determined.

The assumptions to which the impairment tests are most sensitive are for Lightsource bp, the solar project sell-down unit margin, terminal value

growth rate and the discount rate and for Archaea Energy renewable natural gas prices, and the level of capital expenditure and its consequential

impact on production volumes and discount rate. These assumptions are affected by market conditions. Discount rate assumptions are based on

the group's impairment discount rates as disclosed in Note 1. Other assumptions are based on management experience. The steady long-term

growth rate used in the Lightsource bp goodwill impairment test terminal value is a risk-adjusted rate reflecting assumptions about inflation and

project development growth.

It is estimated that a 1% decrease in the discount rates applied to the transition businesses would have resulted in a reduction to the goodwill

impairment charges of $1.7 billion. It is estimated that a 1% increase to the discount rates would have resulted in an increase to the goodwill

impairment charge of $0.9 billion.

These discount rate sensitivity analyses do not take into account any effect on the goodwill impairment test that would arise from first applying the

changes in assumptions to the underlying assets of the businesses.

---

| | |
|:---|:---|
| 198 | bp Annual Report and Form 20-F 2025 |

---

**14. Goodwill and impairment review of goodwill – continued**

Lightsource bp project development margins could change as a result of changes in sales prices achieved, development costs incurred or changes

in the number of projects sold. It is estimated that a 10% increase to project development unit margin would have resulted in a reduction to the

goodwill impairment charge of $0.4 billion. It is estimated that a 10% decrease in project development unit margin would have resulted in an

increase to the goodwill impairment charge of $0.5 billion. It is estimated that a 1% increase to the terminal value growth rate would have resulted

in a reduction to the goodwill impairment charge of $1.0 billion. It is estimated that a 1% decrease in the terminal value growth rate would have

resulted in an increase to the goodwill impairment charge of $0.6 billion.

These sensitivity analyses do not, however, represent management's best estimate of any impairment charges or reversals that might be

recognized as they do not fully incorporate consequential changes that may arise, such as changes in capital and operating costs, business plans

and phasing of development. The above sensitivity analyses therefore do not reflect a linear relationship between development margins or growth

rate and value that can be extrapolated. The interdependency of these inputs and factors limits the practicability of estimating the probability or

extent to which the overall recoverable amount is impacted by changes to the price assumptions or production volumes.

Given the impairment charges taken in the year, the recoverable amount of the transition businesses CGUs' goodwill is equal to its carrying

amount. Therefore, no disclosures regarding what changes in assumptions would cause headroom to be eroded have been provided. Also

reflecting that goodwill impairment reversals are not permitted by IFRS the sensitivities identified above are provided to give context to the

estimates taken at December 2025. No reversals to goodwill would arise should the estimates be changed favourably in the year ended December

2026. customers & products

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  |  | $ million |
|  |  |  |  | **2025** |  |  |  |  | 2024 |
|  | **US Fuels** | **European** <br>**Fuels**<br>| **Other** | **Total** | Castrol | US Fuels | European <br>Fuels<br>| Other | Total<sup>a</sup> |
| Goodwill<sup>a</sup> | **844** | **823** | **578** | **2245** | 2615 | 828 | 801 | 553 | 4797 |

---

aRestated to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment.

Cash flows for each group of CGUs are derived from the business segment plans, which cover a period of up to five years. To determine the value in

use for each of the groups of cash-generating units, cash flows for a period of 10 years, are discounted and aggregated with a terminal value. Pre-

tax discount rates ranging from 10-12% are applied. It is estimated that no reasonably possible change in the key assumptions used in the US Fuels

and European Fuels goodwill impairment assessments would cause the recoverable amount to be equal to the carrying amount of goodwill and

related net non-current assets.

No material impairment of the goodwill balances in customers & products was recognized during 2025.

**Castrol**

The goodwill associated with Castrol was reclassified to assets held for sale during the year.

**15. Intangible assets**

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | $ million |
|  |  |  |  | **2025** |  |  |  | 2024 |
|  | **Exploration** <br>**and appraisal** <br>**expenditure**<sup>a</sup><br>| **Biogas rights** <br>**agreements**<br>| **Other** <br>**intangibles**<br>| **Total** | Exploration <br>and appraisal <br>expenditure<sup>a</sup><br>| Biogas rights <br>agreements<br>| Other <br>intangibles<br>| Total |
| **Cost** |  |  |  |  |  |  |  |  |
| At 1 January | **13053** | **2990** | **7550** | **23593** | 13075 | 2989 | 7117 | 23181 |
| Exchange adjustments | **—** | **—** | **350** | **350** |  |  | (171) | (171) |
| Acquisitions<sup>b</sup> | **—** | **—** | **28** | **28** |  |  | 351 | 351 |
| Additions | **1213** | **1** | **544** | **1758** | 1539 | 193 | 904 | 2636 |
| Transfers to property, plant and equipment | **(3593)** | **—** | **—** | **(3593)** | (391) |  |  | (391) |
| Reclassified as assets held for sale | **—** | **—** | **(667)** | **(667)** | (1) |  | (385) | (386) |
| Deletions and disposals | **(3057)** | **(8)** | **(311)** | **(3376)** | (1169) | (192) | (266) | (1627) |
| **At 31 December** | **7616** | **2983** | **7494** | **18093** | 13053 | 2990 | 7550 | 23593 |
| **Amortization** |  |  |  |  |  |  |  |  |
| At 1 January | **8615** | **557** | **4775** | **13947** | 8747 | 105 | 4338 | 13190 |
| Exchange adjustments | **—** | **—** | **215** | **215** |  |  | (97) | (97) |
| Exploration expenditure written off | **343** | **—** | **—** | **343** | 767 |  |  | 767 |
| Charge for the year | **—** | **93** | **736** | **829** |  | 114 | 717 | 831 |
| Impairment losses | **26** | **710** | **41** | **777** | 6 | 344 | 108 | 458 |
| Impairment reversals | **—** | **(84)** | **—** | **(84)** | (2) |  |  | (2) |
| Transfers to property, plant and equipment | **(2285)** | **—** | **—** | **(2285)** |  |  |  |  |
| Reclassified as assets held for sale | **—** | **—** | **(502)** | **(502)** |  |  | (53) | (53) |
| Deletions and disposals | **(3046)** | **(7)** | **(291)** | **(3344)** | (903) | (6) | (238) | (1147) |
| **At 31 December** | **3653** | **1269** | **4974** | **9896** | 8615 | 557 | 4775 | 13947 |
| **Net book amount at 31 December** | **3963** | **1714** | **2520** | **8197** | 4438 | 2433 | 2775 | 9646 |
| Net book amount at 1 January | **4438** | **2433** | **2775** | **9646** | 4328 | 2884 | 2779 | 9991 |

---

aFor further information see Intangible assets within Note 1 and Note 8.

b2024 primarily relates to the acquisition of GETEC ENERGIE GmbH.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 199 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**16. Investments in joint ventures** 

The following table provides aggregated summarized financial information for the group's joint ventures as it relates to the amounts recognized in

the group income statement and on the group balance sheet.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  | $ million |
|  |  | Income statement | Income statement |  | Balance sheet |
|  |  | Earnings from joint ventures<br> - after interest and tax | Earnings from joint ventures<br> - after interest and tax |  | Investments in <br>joint ventures<br>|
|  | **2025** | 2024 | 2023 | **2025** | 2024 |
| Azule Energy | **406** | 504 | 700 | **5080** | 5109 |
| Other joint ventures | **(706)** | 405 | (633) | **8320** | 7182 |
|  | **(300)** | 909 | 67 | **13400** | 12291 |

---

The joint venture that is material to the group at 31 December 2025 is Azule Energy, which was formed during 2022 and in which bp owns a 50%

stake.

bp classifies its investment in Azule Energy Holdings Limited as a joint venture because, per the terms of the shareholders' agreements, bp has joint

control over Azule Energy. Azule Energy Holdings Limited is based in Angola and its functional currency is USD.

The following table provides summarized financial information relating to Azule Energy for 2025, 2024 and 2023. This information is presented on a

100% basis and reflects adjustments made by bp to Azule Energy's own results in applying the equity method of accounting. bp adjusts Azule

Energy Holdings Limited's results for the accounting required under IFRS relating to bp's purchase of its interests in Azule Energy Holdings Limited.

The operational and financial information is based on preliminary operational and financial results of Azule Energy Holdings Limited for 2025, 2024

and 2023. Actual results may differ from these amounts - immaterial adjustments to the 2023 numbers for Azule Energy Holdings Limited have

been included in the 2024 numbers.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  |  |  | Gross amount |
|  | **2025** | 2024 | 2023 |
| **Sales and other operating revenues** | **4426** | 5410 | 5164 |
| Profit (loss) before interest and taxation | **1266** | 1896 | 2146 |
| Finance costs | **304** | 512 | 400 |
| **Profit (loss) before taxation**<sup>a</sup> | **962** | 1384 | 1746 |
| Taxation | **150** | 376 | 346 |
| **Profit (loss) for the year** | **812** | 1008 | 1400 |
| Other comprehensive income | **—** |  |  |
| **Total comprehensive income** | **812** | 1008 | 1400 |
| Non-current assets | **22564** | 20584 |  |
| Current assets<sup>b</sup> | **4010** | 3384 |  |
| **Total assets** | **26574** | 23968 |  |
| Current liabilities<sup>c</sup> | **5056** | 3576 |  |
| Non-current liabilities<sup>d</sup> | **11358** | 10174 |  |
| **Total liabilities** | **16414** | 13750 |  |
| **Net assets** | **10160** | 10218 |  |
| Less: non-controlling interests | **—** |  |  |
|  | **10160** | 10218 |  |

---

aAzule Energy includes depreciation and amortisation of $2,729 million (2024 $2,844 million and 2023 $2,768 million), interest income of $nil (2024 $nil and 2023 $nil) and interest expense of $303

million (2024 $513 million and 2023 $407 million).

bAzule Energy includes cash and cash equivalents of $596 million (2024 $570 million).

cAzule Energy includes current financial liabilities of $4,635 million (2024 $3,417 million).

dAzule Energy includes non-current financial liabilities of $5,827 million (2024 $3,426 million).

The group received dividends of $437 million from Azule Energy Holdings Limited in 2025 (2024 $463 million and 2023 $708 million).

---

| | |
|:---|:---|
| 200 | bp Annual Report and Form 20-F 2025 |

---

**16. Investments in joint ventures – continued**

The following table provides aggregated summarized financial information relating to the group's share of joint ventures.

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  |  | $ million |
|  |  |  |  |  |  |  |  |  | bp share |
|  |  |  | **2025** |  |  | 2024 |  |  | 2023 |
|  | **Azule** <br>**Energy**<br>| **Other** | **Total** | Azule <br>Energy<br>| Other | Total | Azule <br>Energy<br>| Other | Total |
| **Sales and other operating revenues** | **2213** | **10030** | **12243** | 2705 | 12164 | 14869 | 2582 | 13705 | 16287 |
| Profit (loss) before interest and taxation | **633** | **(61)** | **572** | 948 | (74) | 874 | 1073 | 8 | 1081 |
| Finance costs | **152** | **398** | **550** | 256 | 249 | 505 | 200 | 421 | 621 |
| **Profit (loss) before taxation** | **481** | **(459)** | **22** | 692 | (323) | 369 | 873 | (413) | 460 |
| Taxation | **75** | **247** | **322** | 188 | (729) | (541) | 173 | 219 | 392 |
| Non-controlling interest | **—** | **—** | **—** |  | 1 | 1 |  | 1 | 1 |
| **Profit (loss) for the year** | **406** | **(706)** | **(300)** | 504 | 405 | 909 | 700 | (633) | 67 |
| Other comprehensive income | **—** | **—** | **—** |  | (3) | (3) |  | 45 | 45 |
| **Total comprehensive income** | **406** | **(706)** | **(300)** | 504 | 402 | 906 | 700 | (588) | 112 |
| Non-current assets | **11282** | **18162** | **29444** | 10292 | 13871 | 24163 |  |  |  |
| Current assets | **2005** | **3960** | **5965** | 1692 | 4363 | 6055 |  |  |  |
| **Total assets** | **13287** | **22122** | **35409** | 11984 | 18234 | 30218 |  |  |  |
| Current liabilities | **2528** | **3398** | **5926** | 1788 | 2914 | 4702 |  |  |  |
| Non-current liabilities | **5679** | **7244** | **12923** | 5087 | 5057 | 10144 |  |  |  |
| **Total liabilities** | **8207** | **10642** | **18849** | 6875 | 7971 | 14846 |  |  |  |
| **Net assets** | **5080** | **11480** | **16560** | 5109 | 10263 | 15372 |  |  |  |
| Less: non-controlling interests | **—** | **(90)** | **(90)** |  | (11) | (11) |  |  |  |
|  | **5080** | **11390** | **16470** | 5109 | 10252 | 15361 |  |  |  |
| **Group investment in joint ventures** |  |  |  |  |  |  |  |  |  |
| Group share of net assets (as above) | **5080** | **11390** | **16470** | 5109 | 10252 | 15361 |  |  |  |
| Cumulative impairment charge | **—** | **(3066)** | **(3066)** |  | (3066) | (3066) |  |  |  |
| Loans made by group companies to joint ventures | **—** | **(4)** | **(4)** |  | (4) | (4) |  |  |  |
|  | **5080** | **8320** | **13400** | 5109 | 7182 | 12291 |  |  |  |

---

Transactions between the group and its joint ventures are summarized below.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  | $ million |
| Sales to joint ventures |  | **2025** |  | 2024 |  | 2023 |
| Product | **Sales** | **Amount** <br>**receivable at** <br>**31 December**<br>| Sales | Amount <br>receivable at <br>31 December<br>| Sales | Amount <br>receivable at <br>31 December<br>|
| LNG, crude oil and oil products, natural gas | **2470** | **469** | 3653 | 507 | 3585 | 501 |
| Purchases from joint ventures |  | **2025** |  | 2024 |  | 2023 |
| Product | **Purchases** | **Amount** <br>**payable at** <br>**31 December**<br>| Purchases | Amount <br>payable at <br>31 December<br>| Purchases | Amount <br>payable at <br>31 December<br>|
| LNG, crude oil and oil products, natural gas, refinery operating <br>costs, plant processing fees<br>| **2230** | **426** | 2952 | 468 | 3328 | 427 |

---

In the normal course of business, bp enters into various arm's length transactions with joint ventures including fixed price commitments to sell and

to purchase commodities, forward sale and purchase contracts and agency agreements.

The terms of the outstanding balances receivable from joint ventures are typically 30 to 45 days. The balances are unsecured and will be settled in

cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income

statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above.

The majority of sales to joint ventures in 2025 relate to heating oil, gasoline, diesel and lubricant product transactions with Mobene and Ocwen

Energy. The majority of purchases from joint ventures in 2025 relate to crude oil and oil products transactions with Azule Energy.

bp's share of net impairment charges recognized by joint ventures in 2025 was $1,111 million (2024 $477 million and 2023 $1,285 million) of which

$1,082 million charge (2024 $nil and 2023 $1,152 million) was in the gas and low carbon energy segment and $29 million charge (2024 $477 million

charge and 2023 $133 million charge) was in the oil production & operations segment. The 2025 charges in the gas and low carbon energy segment

principally relate to Archaea Energy and offshore wind. The 2023 charges in the gas and low carbon energy segment principally related to the

group's US offshore wind investments.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 201 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**17. Investments in associates**

The following table provides aggregated summarized financial information for the group's associates as it relates to the amounts recognized in the

group income statement and on the group balance sheet. There were no individually material associates to the Group at 31 December 2025.

Summarized financial information for the group's share of associates is shown below.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  |  |  | bp share |
|  | **2025** | 2024 | 2023 |
| **Sales and other operating revenues** | **13374** | 12859 | 11396 |
| Profit before interest and taxation | **1940** | 2389 | 2279 |
| Finance costs | **32** | 41 | 41 |
| **Profit (loss) before taxation** | **1908** | 2348 | 2238 |
| Taxation | **990** | 1264 | 1407 |
| **Profit (loss) for the year** | **918** | 1084 | 831 |
| Other comprehensive income | **(4)** | (9) | (237) |
| **Total comprehensive income** | **914** | 1075 | 594 |
| Non-current assets | **12089** | 11395 |  |
| Current assets | **3915** | 4230 |  |
| **Total assets** | **16004** | 15625 |  |
| Current liabilities | **2997** | 3009 |  |
| Non-current liabilities | **5714** | 4886 |  |
| **Total liabilities** | **8711** | 7895 |  |
| **Net assets** | **7293** | 7730 |  |
| **Group investment in associates** |  |  |  |
| Group share of net assets (as above) | **7293** | 7730 |  |
| Loans made by group companies to associates | **32** | 11 |  |
|  | **7325** | 7741 |  |

---

Transactions between the group and its associates are summarized below.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  | $ million |
| Sales to associates |  | **2025** |  | 2024 |  | 2023 |
| Product | **Sales** | **Amount** <br>**receivable at** <br>**31 December**<br>| Sales | Amount <br>receivable at <br>31 December<br>| Sales | Amount <br>receivable at <br>31 December<br>|
| LNG, crude oil and oil products, natural gas | **1034** | **348** | 844 | 148 | 1009 | 368 |
|  |  |  |  |  |  | $ million |
| Purchases from associates |  | **2025** |  | 2024 |  | 2023 |
| Product | **Purchases** | **Amount** <br>**payable at** <br>**31 December**<br>| Purchases | Amount <br>payable at <br>31 December<br>| Purchases | Amount <br>payable at <br>31 December<br>|
| Crude oil and oil products, natural gas, transportation tariff | **6708** | **2052** | 7034 | 2223 | 5473 | 2607 |

---

In the normal course of business, bp enters into various arm's length transactions with associates including fixed price commitments to sell and to

purchase commodities, forward sale and purchase contracts and agency agreements.

The terms of the outstanding balances receivable from associates are typically 30 to 45 days. The balances are unsecured and will be settled in

cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income

statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above.

The majority of purchases from associates in 2025, 2024 and 2023 relate to crude oil and oil products transactions with Aker BP. Sales to associates

are related to various entities.

bp has commitments amounting to $6,993 million (2024 $7,921 million), primarily in relation to contracts with its associates for the purchase of

transportation capacity. For information on capital commitments in relation to associates see Note 13.

bp's share of impairment charges taken by associates in 2025 was $265 million (2024 $14 million).

---

| | |
|:---|:---|
| 202 | bp Annual Report and Form 20-F 2025 |

---

**18. Other investments**

---

| | | | | |
|:---|:---|:---|:---|:---|
|  |  |  |  | $ million |
|  |  | **2025** |  | 2024 |
|  | **Current**  | **Non-current** | Current  | Non-current |
| Equity investments<sup>a</sup> | **—** | **816** |  | 1095 |
| Contingent consideration | **60** | **25** | 55 | 136 |
| Other | **98** | **16** | 110 | 61 |
|  | **158** | **857** | 165 | 1292 |

---

aThe majority of equity investments are unlisted.

Unlisted equity investments are measured using observable recent market prices where available. The majority of investments are measured using

models with inputs that may include recent share price data, discounted future cash flows and other available active market pricing data using the

maximum available market information and bp's understanding of the associated company's performance and prospects. Contingent

consideration relates to amounts arising on disposals which are financial assets classified as measured at fair value through profit or loss.

**19. Inventories**

---

| | | |
|:---|:---|:---|
|  |  | $ million |
|  | **2025** | 2024 |
| Crude oil | **2789** | 3007 |
| Natural gas | **697** | 548 |
| Emissions allowances | **843** | 549 |
| Refined petroleum and petrochemical products | **5803** | 6627 |
|  | **10132** | 10731 |
| Trading inventories | **8665** | 8977 |
| Supplies | **2105** | 1946 |
| Biological assets | **112** | 178 |
| Solar projects | **1485** | 1400 |
|  | **22499** | 23232 |
| Cost of inventories expensed in the income statement | **110640** | 113941 |

---

The inventory valuation at 31 December 2025 is stated net of a provision of $475 million (2024 $388 million) to write down inventories to their net

realizable value, of which $277 million (2024 $199 million) relates to hydrocarbon inventories. The net charge to the income statement in the year in

respect of inventory net realizable value provisions was $137 million (2024 $77 million credit), of which $73 million charge (2024 $104 million credit)

related to hydrocarbon inventories.

Trading inventories are valued using quoted benchmark prices adjusted as appropriate for location and quality differentials. They are

predominantly categorized within level 2 of the fair value hierarchy.

**20. Trade and other receivables**

---

| | | | | |
|:---|:---|:---|:---|:---|
|  |  |  |  | $ million |
|  |  | **2025** |  | 2024 |
|  | **Current** | **Non-current** | Current | Non-current |
| **Financial assets** |  |  |  |  |
| Trade receivables | **21107** | **6** | 21659 | 502 |
| Amounts receivable from joint ventures and associates | **817** | **—** | 655 |  |
| Other receivables | **2882** | **1755** | 3524 | 808 |
|  | **24806** | **1761** | 25838 | 1310 |
| **Non-financial assets** |  |  |  |  |
| Sales taxes and production taxes | **1032** | **509** | 1165 | 356 |
| Other receivables | **176** | **106** | 124 | 149 |
|  | **1208** | **615** | 1289 | 505 |
|  | **26014** | **2376** | 27127 | 1815 |

---

In both 2025 and 2024 the group entered into non-recourse arrangements to discount certain receivables in support of supply and trading

activities and the management of credit risk.

Trade and other receivables are predominantly non-interest bearing.

See Note 29 for further information.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 203 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**21. Valuation and qualifying accounts**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  | $ million |
|  |  | **2025** |  | 2024 |  | 2023 |
|  | **Trade and** <br>**other** <br>**receivables**<br>| **Fixed asset**<br>**investments**<br>| Trade and <br>other <br>receivables<br>| Fixed asset<br>investments<br>| Trade and <br>other <br>receivables<br>| Fixed asset<br>investments<br>|
| **At 1 January** | **995** | **3298** | 1424 | 3183 | 636 | 3050 |
| Charged to costs and expenses | **23** | **179** | (90) | 140 | 866 | 176 |
| Charged to other accounts<sup>a</sup> | **10** | **—** | (7) |  | 1 | (1) |
| Deductions | **(90)** | **(62)** | (332) | (25) | (79) | (42) |
| **At 31 December** | **938** | **3415** | 995 | 3298 | 1424 | 3183 |

---

aPrincipally exchange adjustments.

Valuation and qualifying accounts relating to trade and other receivables comprise expected credit loss allowances. The expected credit loss

allowance comprises $811 million (2024 $858 million, 2023 $1,301 million) relating to receivables that were credit-impaired at the end of the year and

$127 million (2024 $137 million, 2023 $123 million) relating to receivables that were not credit-impaired at the end of the year.

Valuation and qualifying accounts relating to fixed asset investments comprise impairment provisions for investments in equity-accounted entities.

Valuation and qualifying accounts are deducted in the balance sheet from the assets to which they apply. For further information on the group's

credit risk management policies and how the group recognizes and measures expected losses see Note 29.

**22. Trade and other payables** 

---

| | | | | |
|:---|:---|:---|:---|:---|
|  |  |  |  | $ million |
|  |  | **2025** |  | 2024 |
|  | **Current** | **Non-current** | Current | Non-current |
| **Financial liabilities** |  |  |  |  |
| Trade payables | **37082** | **—** | 38636 |  |
| Amounts payable to joint ventures and associates | **2477** | **1** | 2690 | 1 |
| Payables for capital expenditure and acquisitions | **3054** | **85** | 3670 | 309 |
| Payables related to the Gulf of America oil spill | **1520** | **5735** | 1126 | 6830 |
| Other payables | **7771** | **457** | 7358 | 678 |
|  | **51904** | **6278** | 53480 | 7818 |
| **Non-financial liabilities** |  |  |  |  |
| Sales taxes, customs duties, production taxes and social security | **2001** | **55** | 2121 | 54 |
| Other payables | **2938** | **1642** | 2810 | 1537 |
|  | **4939** | **1697** | 4931 | 1591 |
|  | **56843** | **7975** | 58411 | 9409 |

---

Materially all of bp's trade payables have payment terms of less than 60 days and give rise to operating cash flows.

Trade and other payables, other than those relating to the Gulf of America oil spill, are predominantly interest free. See Note 29 (c) for further

information.

Payables related to the Gulf of America oil spill include amounts payable under the 2016 consent decree and settlement agreement with the United

States and five Gulf coast states, including amounts payable for natural resource damages, state claims and Clean Water Act penalties. On a

discounted basis the amounts included in payables related to the Gulf of America oil spill for these elements of the agreements are $3,207 million

payable over seven years, $1,748 million payable over eight years and $2,276 million payable over seven years respectively at 31 December 2025.

Reported within net cash provided by operating activities in the group cash flow statement is a net cash outflow of $1,169 million (2024 outflow of

$1,192 million, 2023 outflow of $1,280 million) related to the Gulf of America oil spill, which includes payments made in relation to these agreements.

For full details of these agreements, see bp Annual Report and Form 20-F 2015 - Legal Proceedings.

Payables related to the Gulf of America oil spill at 31 December 2025 also include amounts payable for settled economic loss and property damage

claims which are payable over a period of up to two years.

---

| | |
|:---|:---|
| 204 | bp Annual Report and Form 20-F 2025 |

---

**23. Provisions** 

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  | $ million |
|  | **Decommissioning** | **Environmental** | **Litigation and** <br>**claims**<br>| **Emissions** | **Other**<sup>c</sup> | **Total** |
| **At 1 January 2025** | **11758** | **1518** | **701** | **2330** | **1981** | **18288** |
| Exchange adjustments | **159** | **15** | **6** | **99** | **144** | **423** |
| Acquisitions | **—** | **—** | **26** | **—** | **3** | **29** |
| New and increase in existing provisions<sup>a</sup> | **528** | **325** | **362** | **3052** | **1329** | **5596** |
| Write-back of unused provisions<sup>a</sup> | **(2)** | **(73)** | **(20)** | **(83)** | **(707)** | **(885)** |
| Unwinding of discount<sup>b</sup> | **530** | **63** | **20** | **—** | **62** | **675** |
| Utilization | **(17)** | **(297)** | **(188)** | **(1834)** | **(522)** | **(2858)** |
| Reclassified to other payables | **(540)** | **(2)** | **(108)** | **—** | **(2)** | **(652)** |
| Reclassified as liabilities directly associated with <br>assets held for sale<br>| **(21)** | **(31)** | **(2)** | **—** | **(21)** | **(75)** |
| Deletions | **(142)** | **(18)** | **(1)** | **—** | **(1)** | **(162)** |
| **At 31 December 2025** | **12253** | **1500** | **796** | **3564** | **2266** | **20379** |
| Of which – current | **824** | **319** | **100** | **2709** | **757** | **4709** |
| – non-current | **11429** | **1181** | **696** | **855** | **1509** | **15670** |

---

aRecognized in the Group income statement, other than changes in decommissioning provisions related to owned assets.

bRecognized in the Group income statement

cOther includes provisions for onerous contracts and restructuring costs.

The decommissioning provision primarily comprises the future cost of decommissioning oil and natural gas wells, facilities and related pipelines.

The environmental provision includes provisions for costs related to the control, abatement, clean-up or elimination of environmental pollution

relating to soil, groundwater, surface water and sediment contamination. The litigation and claims category includes provisions for matters related

to, for example, commercial disputes, product liability, and allegations of exposures of third parties to toxic substances. Emissions provisions

primarily relate to obligations under the U.S. Environmental Protection Agency Renewable Fuel Standard Program and are driven by the amount of

the obligations outstanding and current price of the related credits. The provision will principally be settled through allowances already held as

inventory in the group balance sheet.

For information on significant estimates and judgements made in relation to provisions, see Provisions and contingencies within Note 1.

**Gulf of America oil spill**

The group has recognized certain assets, payables and provisions and incurs certain residual costs relating to the Gulf of America oil spill that

occurred in 2010. For further information see Notes 7, 22, 29 and 33. The litigation and claims provision presented in the table above includes the

latest estimate for the remaining costs associated with the Gulf of America oil spill. The amounts payable may differ from the amount provided and

the timing of payments is uncertain.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 205 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**24. Pensions and other post-employment benefits** 

Most group companies have pension plans, the forms and benefits of which vary with conditions and practices in the countries concerned. Pension

benefits may be provided through defined contribution plans (money purchase schemes) or defined benefit plans (final salary and other types of

schemes with committed pension benefit payments). For defined contribution plans, retirement benefits are determined by the value of funds

arising from contributions paid in respect of each employee. For defined benefit plans, retirement benefits are based on such factors as an

employee's pensionable salary and length of service. Defined benefit plans may be funded or unfunded. The assets of funded plans are generally

held in separately administered trusts.

For information on significant estimates and judgements made in relation to accounting for these plans see Pensions and other post-employment

benefits in Note 1.

The defined benefit pension obligation in the UK consists primarily of a closed funded final salary pension plan under which retired employees draw

the majority of their benefit as an annuity. This pension plan is governed by a corporate trustee whose board is composed of four member-

nominated directors, four company-nominated directors, one independent director and one independent chair nominated by the company. The

trustee board is required by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as

investment policies of the plan.

Employees in the UK are eligible for membership of defined contribution plans established with third-party providers.

In the US, all pension benefits now accrue under a cash balance formula. Benefits previously accrued under final salary formulas are legally

protected. Retiring US employees typically take their pension benefit in the form of a lump sum payment upon retirement. The plan is funded and

its assets are overseen by a fiduciary Investment Committee. At the end of 2025 the committee was composed of five bp employees appointed by

the president of bp Corporation North America Inc. (the appointing officer). The Investment Committee is required by law to act in the best

interests of the plan participants and is responsible for setting certain policies, such as the investment policies of the plan. US employees are also

eligible to participate in a defined contribution (401k) plan in which employee contributions are matched with company contributions.

In the US, group companies also provide post-employment healthcare to eligible retired employees and their dependents (and, in certain legacy

cases, life insurance coverage); the entitlement to these benefits is based on the date of hire, the employee remaining in service until a specified

age and completion of a minimum period of service.

In the Eurozone, there are defined benefit pension plans in Germany, France, the Netherlands and other countries. In Germany and France, the

majority of the pensions are unfunded. In Germany, the group's largest Eurozone plan, employees receive a pension and also have a choice to

supplement their core pension through salary sacrifice. For employees who joined since 2002, the core pension benefit is a career average plan

with retirement benefits based on such factors as an employee's pensionable salary and length of service. The returns on the notional contributions

made by both the company and employees are based on the interest rate which is set out in German tax law. Retired German employees take their

pension benefit typically in the form of an annuity. The German plans are governed by legal agreements between bp and the works council or

between bp and the trade union.

Following agreement with the works council, a proportion of the existing defined benefit plans covering approximately 60% of the total active

membership in Germany were closed to future accrual on 31 December 2025 resulting in a net past service cost of $6 million being recognized in

the income statement. Affected employees became eligible for new cash balance arrangements from 1 January 2026.

In the Netherlands, new legislation came into effect in 2023 for domestic pension plans requiring that new pension benefit accruals be exclusively

held in defined contribution plans from 1 January 2028 at the latest. In light of these requirements, and, following agreement with the Dutch retail

and refinery works councils, the existing defined benefit plans were closed to future accrual on 31 August 2025 resulting in a curtailment gain of

$40 million being recognized in the income statement. A new defined contribution plan for members of the defined benefits plans, as well as for

new members, came into effect on 1 September 2025.

The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they fall

due. During 2025 the aggregate level of contributions was $46 million (2024 $69 million and 2023 $42 million) along with $49 million of refunds

from closed plans (2024 $nil and 2023 $nil). The aggregate level of contributions in 2026 is expected to be approximately $100 million and includes

contributions in all countries that we expect to be required to make contributions by law or under contractual agreements, as well as an allowance

for discretionary funding.

For the primary UK defined benefit plan there is a funding agreement between the group and the trustee. On a three year cycle, a schedule of

contributions is agreed covering the next five years. The schedule of contributions is next scheduled to be updated after the 31 December 2026

formal actuarial valuation. No contractually committed funding was due at 31 December 2025.

The surplus relating to the primary UK defined benefit pension plan is recognized on the balance sheet on the basis that the company is entitled to

a refund of any remaining assets once all members have left the plan.

Minimum pension funding in the US is determined by legislation and is supplemented by discretionary contributions. No contributions were made

into the US pension plan in 2025 and no statutory funding requirement is expected in the next 12 months.

The surplus relating to the US pension fund is recognized on the balance sheet on the basis that economic benefit can be gained from the surplus

through a reduction in future contributions.

There was no minimum funding requirement for the US plan, and no significant minimum funding requirements in other countries at 31 December

2025. Following the closure of the Netherlands defined benefit plans to future accrual, the group's ability to access the surplus of $277 million at

31 December 2025 is now fully restricted as the company does not have a right to a refund and can no longer gain an economic benefit through a

reduction contributions. Consequently, the net defined benefit asset recognized on the balance sheet for these plans is now fully capped at zero.

The obligation and cost of providing pensions and other post-employment benefits is assessed annually using the projected unit credit method.

The date of the most recent actuarial review was 31 December 2025. The UK defined benefit plans are subject to a formal actuarial valuation every

three years; valuations are required more frequently in many other countries. The most recent formal actuarial valuation of the primary UK defined

benefit pension plan was as at 31 December 2023. A valuation of the US plan and largest Eurozone plans are carried out annually.

---

| | |
|:---|:---|
| 206 | bp Annual Report and Form 20-F 2025 |

---

**24. Pensions and other post-employment benefits – continued**

The material financial assumptions used to estimate the benefit obligations of the various plans are set out below. The assumptions are reviewed

by management at the end of each year and are used to evaluate the accrued benefit obligation at 31 December and pension expense for the

following year.

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  |  | % |
| Financial assumptions used to determine benefit obligation |  |  | UK |  |  | US |  |  | Eurozone |
| Financial assumptions used to determine benefit obligation | **2025** | 2024 | 2023 | **2025** | 2024 | 2023 | **2025** | 2024 | 2023 |
| Discount rate for plan liabilities | **5.6** | 5.5 | 4.8 | **5.4** | 5.6 | 5.0 | **4.2** | 3.5 | 3.6 |
| Rate of increase for pensions in payment | **2.7** | 2.9 | 2.8 | **—** |  |  | **1.8** | 1.8 | 2.1 |
| Rate of increase in deferred pensions | **2.7** | 2.9 | 2.8 | **—** |  |  | **0.6** | 0.6 | 0.7 |
| Inflation for plan liabilities | **2.9** | 3.1 | 3.0 | **2.0** | 2.0 | 2.0 | **2.0** | 2.0 | 2.4 |
|  |  |  |  |  |  |  |  |  | % |
| Financial assumptions used to determine benefit expense |  |  | UK |  |  | US |  |  | Eurozone |
| Financial assumptions used to determine benefit expense | **2025** | 2024 | 2023 | **2025** | 2024 | 2023 | **2025** | 2024 | 2023 |
| Discount rate for plan service cost<sup>a</sup> | **N/A** | N/A  | N/A | **5.7** | 5.0 | 5.2 | **3.7** | 3.7 | 4.3 |
| Discount rate for plan other finance expense | **5.5** | 4.8 | 5.0 | **5.6** | 5.0 | 5.2 | **3.5** | 3.6 | 4.2 |
| Inflation for plan service cost<sup>a</sup> | **N/A** | N/A | N/A | **2.0** | 2.0 | 2.0 | **2.0** | 2.4 | 2.1 |

---

aUK discount rate and inflation rate assumptions are not relevant in determining the benefit expense for the closed UK plan. Rates for the remaining small worldwide plan administered/reported

through the UK are 5.6% (2024 5.0% and 2023 5.0%) and 2.1% (2024 1.9% and 2023 1.9%) respectively.

The discount rate assumptions are based on third-party AA corporate bond indices and for our largest plans in the UK, US and the Eurozone we use

yields that reflect the maturity profile of the expected benefit payments. The inflation rate assumptions for our UK and US plans are based on the

difference between the yields on index-linked and fixed-interest long-term government bonds. In other countries, including the Eurozone, we use

this approach, or advice from the local actuary depending on the information available. The inflation assumptions are used to determine the rate of

increase for pensions in payment and the rate of increase in deferred pensions where there is such an increase.

In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best

practice in the countries in which we provide pensions and have been chosen with regard to applicable published tables adjusted where

appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. bp's most substantial

pension liabilities are in the UK, the US and the Eurozone where our mortality assumptions are as follows:

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  |  | Years |
| Mortality assumptions |  |  | UK |  |  | US |  |  | Eurozone |
|  | **2025** | 2024 | 2023 | **2025** | 2024 | 2023 | **2025** | 2024 | 2023 |
| Life expectancy at age 60 for a male currently <br>aged 60<br>| **27.1** | 27.0 | 27.4 | **25.2** | 25.1 | 25.0 | **26.4** | 26.2 | 26.1 |
| Life expectancy at age 60 for a male currently <br>aged 40<br>| **28.9** | 28.9 | 29.2 | **26.9** | 26.8 | 26.7 | **28.9** | 28.6 | 28.6 |
| Life expectancy at age 60 for a female <br>currently aged 60<br>| **28.9** | 29.0 | 29.2 | **28.2** | 28.1 | 28.1 | **29.5** | 29.5 | 29.3 |
| Life expectancy at age 60 for a female <br>currently aged 40<br>| **30.4** | 30.5 | 30.6 | **29.7** | 29.6 | 29.6 | **31.7** | 31.7 | 31.6 |

---

Pension plan assets are generally held in trusts, the primary objective of which is to accumulate assets sufficient to meet the obligations of the

plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio

management.

A proportion of the assets are held in equities, which are expected to generate a higher level of return over the long term, with an acceptable level

of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the

investment portfolios are highly diversified.

The trustee's long-term investment objective for the primary UK defined benefit plan is to invest the plan's assets in a responsible manner that

considers downside risk such that the assets are expected to be sufficient to pay benefits as and when they fall due. The UK plan uses a liability

driven investment (LDI) approach for part of the portfolio, investing primarily in government bonds to economically hedge against the effect of the

most significant plan liability assumptions of interest rate and inflation rate. This is partly funded by short-term sale and repurchase agreements,

whereby the plan borrows money using existing bonds as security and which will be bought back at a specified price at an agreed future date. The

funds raised are used to invest in further bonds to increase the proportion of assets which match the plan liabilities. The borrowings are shown

separately in the analysis of pension plan assets in the table below.

During 2025, the trustee extended its derisking strategy for the primary UK defined benefit plan by completing a bulk annuity buy-in transaction

with Legal & General Assurance Society Limited covering approximately 12% of the plan's liabilities. The buy-in was paid for by way of transfer of

$2,183 million of government issued bonds from the plan assets in exchange for a stream of cashflows to the plan replicating payments due to

relevant members.

The group was not legally relieved of the primary responsibility for the obligation and the benefits continue to be payable by the plan. The

difference of $148 million between the buy-in purchase price ($2,183 million) and the defined benefit liability covered by the policy ($2,035 million)

was accounted for in other comprehensive income.

For the primary UK defined benefit plan there is an agreement with the trustee to at least maintain the proportion of assets with liability matching

characteristics and review over time. There is a similar agreement in place for the primary US plan. During 2025, excluding qualifying insurance

policies in the UK, the asset allocation policies of the primary UK and US plans remained unchanged.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 207 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**24. Pensions and other post-employment benefits – continued**

The current asset allocation policy for the major plans at 31 December 2025 was as follows:

---

| | | |
|:---|:---|:---|
|  | **UK** | **US** |
| Asset category | **%** | **%** |
| Total equity (including private equity) | **8** | **19** |
| Bonds/cash (including LDI) | **85** | **81** |
| Property/real estate | **7** | **—** |

---

The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2025 were $3,702 million (2024 $4,970 million)

of government-issued nominal bonds and $10,805 million (2024 $11,105 million) of index-linked bonds.

Some of the group's pension plans in the Eurozone and other countries use derivative financial instruments as part of their asset mix to manage the

level of risk. The fair value of these instruments is included in other assets in the table below.

The group's main pension plans do not invest directly in either securities or property/real estate of the company or of any subsidiary.

The fair values of the various categories of assets held by the defined benefit plans at 31 December are presented in the table below, including the

effects of derivative financial instruments. Movements in the fair value of plan assets during the year are shown in detail in the table on page <u>[208](#i51f63c56799640a5b21b29a479dd097e_0-0-1-1-967146)</u>.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  | $ million |
|  | **UK**<sup>a</sup> | **US**<sup>b</sup> | **Eurozone** | **Other** | **Total** |
| Fair value of pension plan assets |  |  |  |  |  |
| At 31 December 2025 |  |  |  |  |  |
| Listed equities – developed markets | **725** | **137** | **84** | **181** | **1127** |
| – emerging markets | **29** | **17** | **10** | **70** | **126** |
| Private equity<sup>c</sup> | **1871** | **910** | **—** | **—** | **2781** |
| Government issued nominal bonds<sup>d</sup> | **3761** | **1369** | **901** | **214** | **6245** |
| Government issued index-linked bonds<sup>d</sup> | **10805** | **—** | **85** | **8** | **10898** |
| Corporate bonds<sup>d</sup> | **5383** | **2790** | **70** | **236** | **8479** |
| Property<sup>e</sup> | **2487** | **—** | **6** | **13** | **2506** |
| Cash | **574** | **83** | **912** | **106** | **1675** |
| Other<sup>f</sup> | **3232** | **46** | **(58)** | **11** | **3231** |
| Debt (repurchase agreements) used to fund liability driven investments | **(4278)** | **—** | **—** | **—** | **(4278)** |
|  | **24589** | **5352** | **2010** | **839** | **32790** |
| At 31 December 2024 |  |  |  |  |  |
| Listed equities – developed markets | 963 | 113 | 341 | 230 | 1647 |
| – emerging markets | 32 | 13 | 55 | 75 | 175 |
| Private equity<sup>c</sup> | 1916 | 950 |  | 2 | 2868 |
| Government issued nominal bonds<sup>d</sup> | 5027 | 1317 | 690 | 223 | 7257 |
| Government issued index-linked bonds<sup>d</sup> | 11105 |  | 78 | 7 | 11190 |
| Corporate bonds<sup>d</sup> | 6088 | 2763 | 605 | 261 | 9717 |
| Property<sup>e</sup> | 2344 |  | 84 | 19 | 2447 |
| Cash | 416 | 67 | 100 | 78 | 661 |
| Other<sup>f</sup> | 1039 | 36 | 54 | 14 | 1143 |
| Debt (repurchase agreements) used to fund liability driven investments | (5664) |  |  |  | (5664) |
|  | 23266 | 5259 | 2007 | 909 | 31441 |
| At 31 December 2023 |  |  |  |  |  |
| Listed equities – developed markets | 862 | 97 | 333 | 232 | 1524 |
| – emerging markets | 28 | 12 | 51 | 66 | 157 |
| Private equity<sup>c</sup> | 2022 | 1014 |  | 2 | 3038 |
| Government issued nominal bonds<sup>d</sup> | 6285 | 1457 | 746 | 285 | 8773 |
| Government issued index-linked bonds<sup>d</sup> | 13177 |  | 88 |  | 13265 |
| Corporate bonds<sup>d</sup> | 6144 | 2802 | 605 | 166 | 9717 |
| Property<sup>e</sup> | 2437 |  | 92 | 17 | 2546 |
| Cash | 453 | 59 | 82 | 85 | 679 |
| Other<sup>f</sup> | 1123 | 33 | 55 | 391 | 1602 |
| Debt (repurchase agreements) used to fund liability driven investments | (6485) |  |  |  | (6485) |
|  | 26046 | 5474 | 2052 | 1244 | 34816 |

---

aBonds held by the UK pension plans are denominated in sterling or hedged back to sterling to minimize foreign currency exposure. Property held by the UK pension plans is in the United

Kingdom.

bBonds held by the US pension plans are denominated in US dollars or hedged back to USD to minimize foreign currency exposure.

cPrivate equity is valued at fair value based on the most recent transaction price or third-party net asset, revenue or earnings based valuations that generally result in the use of significant

unobservable inputs.

dBonds held by pension plans are predominantly valued using observable market data based inputs other than quoted market prices in active markets.

eProperties are valued based on an analysis of recent market transactions supported by market knowledge derived from third-party professional valuers that generally result in the use of

significant unobservable inputs.

fOther includes qualifying insurance policies in the UK amounting to $2,159 million representing the asset associated with the buy in outlined on page [206](#i09b3d10405f84e42be69b92b4c5ef5c9_47507). The fair value of these insurance policies

is equal to the value of the defined benefit obligations to which these policies relate. Other included insurance policies arising from annuity buy-in in Canada amounting to $374 million in 2023.

Completion of a buy-out in 2024 reduced these amounts to $nil.

---

| | |
|:---|:---|
| 208 | bp Annual Report and Form 20-F 2025 |

---

**24. Pensions and other post-employment benefits – continued**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  | $ million |
|  |  |  |  |  | **2025** |
|  | **UK** | **US** | **Eurozone** | **Other** | **Total** |
| Analysis of the amount charged to profit or loss |  |  |  |  |  |
| Current service cost<sup>a</sup> | **47** | **157** | **56** | **25** | **285** |
| Past service cost<sup>b</sup> | **—** | **—** | **(39)** | **—** | **(39)** |
| Settlement<sup>b</sup> | **—** | **—** | **11** | **—** | **11** |
| **Operating charge (credit) relating to defined benefit plans** | **47** | **157** | **28** | **25** | **257** |
| Payments to defined contribution plans | **180** | **179** | **7** | **35** | **401** |
| **Total operating charge (credit)**  | **227** | **336** | **35** | **60** | **658** |
| Interest income on plan assets<sup>a</sup> | **(1322)** | **(286)** | **(78)** | **(38)** | **(1724)** |
| Interest on plan liabilities | **976** | **300** | **190** | **48** | **1514** |
| **Other finance (income) expense** | **(346)** | **14** | **112** | **10** | **(210)** |
| Analysis of the amount recognized in other comprehensive income |  |  |  |  |  |
| Actual asset return less interest income on plan assets | **(613)** | **120** | **(225)** | **(1)** | **(719)** |
| Change in financial assumptions underlying the present value of the plan liabilities | **453** | **(242)** | **436** | **8** | **655** |
| Change in demographic assumptions underlying the present value of the plan liabilities | **(26)** | **—** | **—** | **(1)** | **(27)** |
| Experience gains and losses arising on the plan liabilities | **15** | **(40)** | **(102)** | **(3)** | **(130)** |
| **Remeasurements recognized in other comprehensive income** | **(171)** | **(162)** | **109** | **3** | **(221)** |
| Movements in benefit obligation during the year |  |  |  |  |  |
| Benefit obligation at 1 January | **17324** | **5524** | **5002** | **1007** | **28857** |
| Exchange adjustments | **1301** | **—** | **646** | **50** | **1997** |
| Operating charge relating to defined benefit plans | **47** | **157** | **28** | **25** | **257** |
| Interest cost | **976** | **300** | **190** | **48** | **1514** |
| Contributions by plan participants | **8** | **—** | **2** | **5** | **15** |
| Benefit payments (funded plans)<sup>c</sup> | **(1160)** | **(313)** | **(95)** | **(64)** | **(1632)** |
| Benefit payments (unfunded plans)<sup>c</sup> | **(10)** | **(145)** | **(246)** | **(11)** | **(412)** |
| Reclassified as assets held for sale | **(24)** | **—** | **(161)** | **(77)** | **(262)** |
| Disposals | **—** | **—** | **(1)** | **—** | **(1)** |
| Remeasurements | **(442)** | **282** | **(334)** | **(4)** | **(498)** |
| **Benefit obligation at 31 December**<sup>a d e</sup> | **18020** | **5805** | **5031** | **979** | **29835** |
| Movements in fair value of plan assets during the year |  |  |  |  |  |
| Fair value of plan assets at 1 January | **23266** | **5259** | **2007** | **909** | **31441** |
| Exchange adjustments | **1757** | **—** | **257** | **43** | **2057** |
| Interest income on plan assets<sup>a e</sup> | **1322** | **286** | **78** | **38** | **1724** |
| Contributions by plan participants | **8** | **—** | **2** | **5** | **15** |
| Contributions by and refunds to employers (funded plans) | **9** | **—** | **16** | **(28)** | **(3)** |
| Benefit payments (funded plans)<sup>c</sup> | **(1160)** | **(313)** | **(95)** | **(64)** | **(1632)** |
| Reclassified as assets held for sale | **—** | **—** | **(30)** | **(63)** | **(93)** |
| Remeasurements<sup>f</sup> | **(613)** | **120** | **(225)** | **(1)** | **(719)** |
| Fair value of plan assets at 31 December<sup>g</sup> | **24589** | **5352** | **2010** | **839** | **32790** |
| **Surplus (deficit) at 31 December** | **6569** | **(453)** | **(3021)** | **(140)** | **2955** |
| Represented by |  |  |  |  |  |
| Asset recognized | **6697** | **921** | **93** | **60** | **7771** |
| Liability recognized | **(128)** | **(1374)** | **(3114)** | **(200)** | **(4816)** |
|  | **6569** | **(453)** | **(3021)** | **(140)** | **2955** |
| The surplus (deficit) may be analysed between funded and unfunded plans as follows |  |  |  |  |  |
| Funded | **6696** | **921** | **84** | **29** | **7730** |
| Unfunded | **(127)** | **(1374)** | **(3105)** | **(169)** | **(4775)** |
|  | **6569** | **(453)** | **(3021)** | **(140)** | **2955** |
| The defined benefit obligation may be analysed between funded and unfunded plans as <br>follows<br>|  |  |  |  |  |
| Funded | **(17893)** | **(4431)** | **(1926)** | **(810)** | **(25060)** |
| Unfunded | **(127)** | **(1374)** | **(3105)** | **(169)** | **(4775)** |
|  | **(18020)** | **(5805)** | **(5031)** | **(979)** | **(29835)** |

---

aThe costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of

administering other post-employment benefit plans are included in the benefit obligation. Following the closure of the primary UK pension plan, current service cost in the UK consists of

$36 million of costs of administering that plan and $11 million of current service cost from the remaining small worldwide plans administered and reported through the UK.

bPast service costs predominantly reflect curtailment impacts from the closure of plans in the Netherlands and Germany to future accrual. Settlements represent losses associated with

restructuring activity in Germany.

cThe benefit payments amount shown above comprises $1,975 million benefits and $12 million settlements, plus $57 million of plan expenses incurred in the administration of the benefit.

dThe benefit obligation for the US is made up of $4,602 million for pension liabilities and $1,203 million for other post-employment benefit liabilities (which are unfunded and are primarily retiree

medical liabilities). The benefit obligation for the Eurozone includes $2,976 million for pension liabilities in Germany which is largely unfunded.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 209 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**24. Pensions and other post-employment benefits – continued**

eIncludes $346 million (2024 $155 million) representing assets ceilings in plans in the Netherlands (see page [205](#i09b3d10405f84e42be69b92b4c5ef5c9_47518)), Switzerland and the UK. Movements in the asset ceiling during 2025 were interest

cost of $8 million and remeasurements of $183 million.

fThe actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.

gThe fair value of plan assets includes borrowings related to the LDI programme as described on page [207](#i09b3d10405f84e42be69b92b4c5ef5c9_47425).

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  | $ million |
|  |  |  |  |  | 2024 |
|  | UK | US | Eurozone | Other | Total |
| Analysis of the amount charged to profit or loss |  |  |  |  |  |
| Current service cost<sup>a</sup> | 48 | 160 | 62 | 23 | 293 |
| Past service cost<sup>b</sup> |  |  | (1) |  | (1) |
| Settlement<sup>b</sup> | (1) |  |  |  | (1) |
| **Operating charge (credit) relating to defined benefit plans** | 47 | 160 | 61 | 23 | 291 |
| Payments to defined contribution plans | 161 | 192 | 8 | 35 | 396 |
| **Total operating charge (credit)** | 208 | 352 | 69 | 58 | 687 |
| Interest income on plan assets<sup>a</sup> | (1218) | (267) | (70) | (49) | (1604) |
| Interest on plan liabilities | 909 | 283 | 184 | 60 | 1436 |
| **Other finance (income) expense** | (309) | 16 | 114 | 11 | (168) |
| Analysis of the amount recognized in other comprehensive income |  |  |  |  |  |
| Actual asset return less interest income on plan assets | (2388) | (239) | 65 | 83 | (2479) |
| Change in financial assumptions underlying the present value of the plan liabilities | 1496 | 403 | 103 | (48) | 1954 |
| Change in demographic assumptions underlying the present value of the plan liabilities | 194 | (8) | 1 | 2 | 189 |
| Experience gains and losses arising on the plan liabilities | 15 | (34) | 2 | (7) | (24) |
| **Remeasurements recognized in other comprehensive income** | (683) | 122 | 171 | 30 | (360) |
| Movements in benefit obligation during the year |  |  |  |  |  |
| Benefit obligation at 1 January | 19579 | 5837 | 5537 | 1371 | 32324 |
| Exchange adjustments | (352) |  | (355) | (66) | (773) |
| Operating charge relating to defined benefit plans | 47 | 160 | 61 | 23 | 291 |
| Interest cost | 909 | 283 | 184 | 60 | 1436 |
| Contributions by plan participants | 7 |  | 2 | 7 | 16 |
| Benefit payments (funded plans)<sup>c</sup> | (1153) | (243) | (89) | (427) | (1912) |
| Benefit payments (unfunded plans)<sup>c</sup> | (8) | (152) | (232) | (12) | (404) |
| Disposals |  |  |  | (2) | (2) |
| Remeasurements | (1705) | (361) | (106) | 53 | (2119) |
| **Benefit obligation at 31 December**<sup>a d</sup> | 17324 | 5524 | 5002 | 1007 | 28857 |
| Movements in fair value of plan assets during the year |  |  |  |  |  |
| Fair value of plan assets at 1 January | 26046 | 5474 | 2052 | 1244 | 34816 |
| Exchange adjustments | (473) |  | (139) | (61) | (673) |
| Interest income on plan assets<sup>a e</sup> | 1218 | 267 | 70 | 49 | 1604 |
| Contributions by plan participants | 7 |  | 2 | 7 | 16 |
| Contributions by employers (funded plans) | 9 |  | 46 | 14 | 69 |
| Benefit payments (funded plans)<sup>c</sup> | (1153) | (243) | (89) | (427) | (1912) |
| Remeasurements<sup>e</sup> | (2388) | (239) | 65 | 83 | (2479) |
| Fair value of plan assets at 31 December<sup>f</sup> | 23266 | 5259 | 2007 | 909 | 31441 |
| **Surplus (deficit) at 31 December** | 5942 | (265) | (2995) | (98) | 2584 |
| Represented by |  |  |  |  |  |
| Asset recognized | 6083 | 1009 | 273 | 92 | 7457 |
| Liability recognized | (141) | (1274) | (3268) | (190) | (4873) |
|  | 5942 | (265) | (2995) | (98) | 2584 |
| The surplus (deficit) may be analysed between funded and unfunded plans as follows |  |  |  |  |  |
| Funded | 6083 | 1009 | 261 | 48 | 7401 |
| Unfunded | (141) | (1274) | (3256) | (146) | (4817) |
|  | 5942 | (265) | (2995) | (98) | 2584 |
| The defined benefit obligation may be analysed between funded and unfunded plans as <br>follows<br>|  |  |  |  |  |
| Funded | (17183) | (4250) | (1746) | (861) | (24040) |
| Unfunded | (141) | (1274) | (3256) | (146) | (4817) |
|  | (17324) | (5524) | (5002) | (1007) | (28857) |

---

aThe costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of

administering other post-employment benefit plans are included in the benefit obligation. Following the closure of the primary UK pension plan, current service cost in the UK consists of $38

million of costs of administering that plan and $10 million of current service cost from the remaining small worldwide plans administered and reported through the UK.

bPast service costs predominantly reflect minor plan changes in France. Settlements represent changes in small worldwide plans administered and reported throughout the UK.

cThe benefit payments amount shown above comprises $1,907 million benefits and $352 million settlements relating to the buy-out in Canada, plus $57 million of plan expenses incurred in the

administration of the benefit.

---

| | |
|:---|:---|
| 210 | bp Annual Report and Form 20-F 2025 |

---

**24. Pensions and other post-employment benefits – continued**

dThe benefit obligation for the US is made up of $4,428 million for pension liabilities and $1,096 million for other post-employment benefit liabilities (which are unfunded and are primarily retiree

medical liabilities). The benefit obligation for the Eurozone includes $3,086 million for pension liabilities in Germany which is largely unfunded.

eThe actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.

fThe fair value of plan assets includes borrowings related to the LDI programme as described on page [207](#i09b3d10405f84e42be69b92b4c5ef5c9_47425).

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  | $ million |
|  |  |  |  |  | 2023 |
|  | UK | US | Eurozone | Other | Total |
| Analysis of the amount charged to profit or loss |  |  |  |  |  |
| Current service cost<sup>a</sup> | 44 | 156 | 47 | 21 | 268 |
| Past service cost<sup>b</sup> | 4 |  | 5 | (2) | 7 |
| Settlement<sup>b</sup> |  |  |  | 3 | 3 |
| **Operating charge (credit) relating to defined benefit plans** | 48 | 156 | 52 | 22 | 278 |
| Payments to defined contribution plans | 132 | 158 | 7 | 36 | 333 |
| **Total operating charge (credit)** | 180 | 314 | 59 | 58 | 611 |
| Interest income on plan assets<sup>a</sup> | (1259) | (274) | (78) | (56) | (1667) |
| Interest on plan liabilities | 869 | 297 | 194 | 66 | 1426 |
| **Other finance (income) expense** | (390) | 23 | 116 | 10 | (241) |
| Analysis of the amount recognized in other comprehensive income |  |  |  |  |  |
| Actual asset return less interest income on plan assets | (677) | 45 | 82 | 28 | (522) |
| Change in financial assumptions underlying the present value of the plan liabilities | (649) | 28 | (508) | (24) | (1153) |
| Change in demographic assumptions underlying the present value of the plan liabilities | (230) | (5) | 8 |  | (227) |
| Experience gains and losses arising on the plan liabilities | (320) | 45 | (84) | (1) | (360) |
| **Remeasurements recognized in other comprehensive income** | (1876) | 113 | (502) | 3 | (2262) |

---

aThe costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of

administering other post-employment benefit plans are included in the benefit obligation. Following the closure of the primary UK pension plan, current service cost in the UK consists of $34

million of costs of administering that plan and $10 million of current service cost from the remaining small worldwide plans administered and reported through the UK.

bPast service costs predominantly represent largely offsetting income and costs due to the removal of some benefits for members in Turkish plans and their replacement with new arrangements

administered and reported through the UK. There was also a $5 million past service cost in France relating to statutory retirement age changes. Settlements represent charges for special

termination benefits arising as a result of early retirements.

**Sensitivity analysis**

The discount rate, inflation and the mortality assumptions all have a significant effect on the amounts reported. A one-percentage point change, in

isolation, in certain assumptions as at 31 December 2025 for the group's pensions and other post-employment benefit expense would have had the

effects shown in the tables below. The effects shown for the expense in 2026 comprise the total of current service cost and net finance income or

expense.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  | $ million |
|  |  |  |  |  | **One percentage point** | **One percentage point** |
|  | **UK** | **UK** | **US** | **US** | **Eurozone** | **Eurozone** |
|  | **Increase** | **Decrease** | **Increase** | **Decrease** | **Increase** | **Decrease** |
| **Discount rate**<sup>a</sup> |  |  |  |  |  |  |
| Effect on expense in 2026 | **(186)** | **168** | **(44)** | **46** | **(2)** | **(5)** |
| Effect on obligation at 31 December 2025 | **(1803)** | **2185** | **(465)** | **614** | **(497)** | **604** |
| **Inflation rate**<sup>b</sup> |  |  |  |  |  |  |
| Effect on expense in 2026 | **90** | **(82)** | **8** | **(6)** | **22** | **(20)** |
| Effect on obligation at 31 December 2025 | **1613** | **(1464)** | **39** | **(33)** | **480** | **(414)** |

---

aThe amounts presented reflect that the discount rate is used to determine the asset interest income as well as the interest cost on the obligation.

bThe amounts presented reflect the total impact of an inflation rate change on the assumptions for rate of increase in salaries, pensions in payment and deferred pensions.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  |  | **One year increase** | **One year increase** |
|  | **UK** | **US** | **Eurozone** |
| **Longevity** |  |  |  |
| Effect on expense in 2026 | **33** | **4** | **9** |
| Effect on obligation at 31 December 2025 | **593** | **60** | **189** |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 211 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**24. Pensions and other post-employment benefits – continued**

**Estimated future benefit payments and the weighted average duration of defined benefit obligations**

The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, and the weighted average

duration of the defined benefit obligations at 31 December 2025 are as follows:

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  | $ million |
| Estimated future benefit payments | **UK** | **US** | **Eurozone** | **Other** | **Total** |
| 2026 | **1190** | **467** | **324** | **61** | **2042** |
| 2027 | **1212** | **463** | **325** | **55** | **2055** |
| 2028 | **1219** | **458** | **320** | **56** | **2053** |
| 2029 | **1233** | **467** | **319** | **55** | **2074** |
| 2030 | **1234** | **473** | **312** | **54** | **2073** |
| 2031 - 2035 | **6214** | **2383** | **1431** | **285** | **10313** |
|  |  |  |  |  | **Years** |
| Weighted average duration | **11.1** | **9.2** | **12.5** | **12.6** |  |

---

**25. Cash and cash equivalents** 

---

| | | |
|:---|:---|:---|
|  |  | $ million |
|  | **2025** | 2024 |
| Cash | **17158** | 16414 |
| Triparty repos and term bank deposits | **12691** | 14453 |
| Other cash equivalents | **6707** | 8337 |
|  | **36556** | 39204 |

---

Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; deposits and triparty repos of three months

or less with banks and similar institutions; money market funds and treasury bills. The carrying amounts of cash, triparty repos, term bank deposits

and treasury bills approximate their fair values. Substantially all of the other cash equivalents are categorized within level 1 of the fair value

hierarchy.

Cash and cash equivalents at 31 December 2025 includes $4,725 million (2024 $4,844 million) that is restricted. The restricted cash balances include

amounts required to cover initial margin on trading exchanges and certain cash balances which are subject to exchange controls.

The group holds $6,434 million (2024 $5,774 million) of cash and cash equivalents outside the UK and it is not expected that any significant tax will

arise on repatriation.

**26. Finance debt**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  | $ million |
|  |  |  | **2025** |  |  | 2024 |
|  | **Current** | **Non-current** | **Total** | Current | Non-current | Total |
| Borrowings | **3356** | **54602** | **57958** | 4474 | 55073 | 59547 |

---

The main elements of current borrowings are the current portion of long-term borrowings that is due to be repaid in the next 12 months of $3,003

million (2024 $3,793 million) and issued commercial paper of $200 million (2024 $500 million). Finance debt does not include accrued interest of

$552 million (2024 $585 million), which is reported within other payables. As part of actively managing its debt portfolio, during the year the group

bought back $2.0 billion (2024 $nil) of finance debt consisting entirely of US dollar bonds. These transactions have no significant impact on net debt

or gearing.

The following table shows the weighted-average interest rates achieved through a combination of borrowings and derivative financial instruments

entered into to manage interest rate and currency exposures.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  | **Fixed rate debt** | **Fixed rate debt** | **Floating rate debt** | **Floating rate debt** | **Total** |
|  | **Weighted**<br>**average**<br>**interest**<br>**rate%**<br>| **Weighted**<br>**average**<br>**time for**<br>**which rate**<br>**is fixed**<br>**Years**<br>| **Amount**<br>**$ million**<br>| **Weighted**<br>**average**<br>**interest**<br>**rate%**<br>| **Amount**<br>**$ million**<br>| **Amount**<br>**$ million**<br>|
|  |  |  |  |  |  | **2025** |
| US dollar | **5** | **8** | **41018** | **4** | **16486** | **57504** |
| Other currencies | **6** | **4** | **246** | **6** | **208** | **454** |
|  |  |  | **41264** |  | **16694** | **57958** |
|  |  |  |  |  |  | 2024 |
| US dollar | 4 | 8 | 41145 | 5 | 17847 | 58992 |
| Other currencies | 6 | 3 | 396 | 6 | 159 | 555 |
|  |  |  | 41541 |  | 18006 | 59547 |

---

---

| | |
|:---|:---|
| 212 | bp Annual Report and Form 20-F 2025 |

---

**26. Finance debt - continued**

**Fair values**

The estimated fair value of finance debt is shown in the table below together with the carrying amount as reflected in the balance sheet.

Long-term borrowings in the table below include the portion of debt that matures in the 12 months from 31 December 2025, whereas in the group

balance sheet the amount is reported within current finance debt.

The carrying amount of the group's short-term borrowings, comprising mainly of commercial paper, approximates their fair value. The fair values of

the significant majority of the group's long-term borrowings are determined using quoted prices in active markets, and so fall within level 1 of the

fair value hierarchy. Where quoted prices are not available, quoted prices for similar instruments in active markets are used and such

measurements are therefore categorized in level 2 of the fair value hierarchy.

---

| | | | | |
|:---|:---|:---|:---|:---|
|  |  |  |  | $ million |
|  |  | **2025** |  | 2024 |
|  | **Fair value** | **Carrying**<br>**amount**<br>| Fair value | Carrying<br>amount<br>|
| Short-term borrowings | **353** | **353** | 681 | 681 |
| Long-term borrowings | **54582** | **57605** | 54285 | 58866 |
| **Total finance debt** | **54935** | **57958** | 54966 | 59547 |

---

**27. Capital disclosures and net debt** 

The group defines capital as total equity plus net debt. Our financial framework seeks to support the pursuit of value growth for shareholders while

maintaining a secure financial base.

The group monitors capital on the basis of gearing, that is, the ratio of net debt to the total of net debt plus total equity. Net debt is calculated as

finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign

exchange and interest rate risks relating to finance debt for which hedge accounting is applied, less cash and cash equivalents. Net debt and

gearing are non-IFRS measures. bp believes these measures provide useful information to investors. Net debt enables investors to see the

economic effect of finance debt, related hedges and cash and cash equivalents in total. Gearing enables investors to see how significant net debt is

relative to total equity. The derivatives are reported on the balance sheet within the headings 'Derivative financial instruments'. All components of

equity are included in the denominator of the calculation.

At 31 December 2025, gearing was 23.1% (2024 22.7%).

---

| | | |
|:---|:---|:---|
|  |  | $ million |
| At 31 December | **2025** | 2024 |
| Finance debt | **57958** | 59547 |
| *Less: fair value asset (liability) of hedges related to finance debt*<sup>a</sup> | **(780)** | (2654) |
|  | **58738** | 62201 |
| Less: cash and cash equivalents | **36556** | 39204 |
| Net debt | **22182** | 22997 |
| Total equity | **74000** | 78318 |
| Gearing | **23.1%** | 22.7% |

---

aDerivative financial instruments entered into for the purpose of managing foreign currency exchange risk associated with net debt with a fair value liability position of $94 million (2024 liability of

$166 million) are not included in the calculation of net debt shown above as hedge accounting was not applied for these instruments.

Certain subsidiaries in the group have externally imposed capital requirements and have been in compliance with these requirements throughout

the year.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 213 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**27. Capital disclosures and net debt - continued**

An analysis of changes in liabilities arising from financing activities is provided below.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  | $ million |
|  | **Finance**<br>**debt**<br>| **Currency** <br>**swaps**<sup>a</sup><br>| **Lease liabilities** | **Partner payable** <br>**for leases** <br>**entered into on** <br>**behalf of joint** <br>**operations**<br>| **Total liabilities** <br>**arising from** <br>**financing** <br>**activities**<br>|
| At 1 January 2025 | **59547** | **4113** | **12000** | **37** | **75697** |
| Exchange adjustments | **127** | **—** | **399** | **2** | **528** |
| Net financing cash flow | **(3290)** | **(22)** | **(3091)** | **(2)** | **(6405)** |
| Fair value (gains) losses | **1664** | **(3044)** | **—** | **—** | **(1380)** |
| New and remeasured leases/joint operations payables | **—** | **—** | **5449** | **(4)** | **5445** |
| Other movements | **(90)** | **—** | **(186)** | **(2)** | **(278)** |
| **At 31 December 2025** | **57958** | **1047** | **14571** | **31** | **73607** |
| At 1 January 2024 | 51954 | 2978 | 11121 | 30 | 66083 |
| Exchange adjustments | (39) |  | (272) | (1) | (312) |
| Net financing cash flow | 4761 | (27) | (2833) | (14) | 1887 |
| Fair value (gains) losses | (840) | 1162 |  |  | 322 |
| New and remeasured leases/joint operations payables |  |  | 3441 | 24 | 3465 |
| Other movements<sup>b</sup> | 3711 |  | 543 | (2) | 4252 |
| **At 31 December 2024** | 59547 | 4113 | 12000 | 37 | 75697 |

---

aCurrency swaps include cross currency interest rate swaps.

bIncludes $3,726 million of finance debt and $585 million of lease liabilities acquired as part of the Lightsource bp and bp Bunge Bioenergia business combinations.

The finance debt and currency swap balances above do not include accrued interest, which is reported within other receivables and other payables

on the balance sheet and for which the associated cash flows are presented as operating cash flows in the group cash flow statement. The

currency swaps are reported on the balance sheet within the headings 'Derivative financial instruments' and are subsets of both derivatives held for

trading and derivatives designated in fair value hedge relationships as detailed in Note 30. When hedge accounting is applied to these derivatives

they are included in the calculation of net debt shown above.

In addition to the liabilities included in the table above the group has accrued $448 million (2024 $922 million) at the balance sheet date for shares

repurchased between the end of the reporting period and 10 February 2026 (2024 11 February 2025). $4,486 million (2024 $7,127 million) is included

in financing activities in the group cash flow statement for the cash used to repurchase shares during the year.

**28. Leases** 

The group leases a number of assets as part of its activities. This primarily includes drilling rigs in the oil production & operations and gas & low

carbon energy segments and retail service stations, oil depots and storage tanks in the customer & products segment as well as office

accommodation and vessel charters across the group. The weighted-average remaining lease term for the total lease portfolio is around nine years

(2024 eight years). Some leases have payments that vary with market interest or inflation rates. Certain leases contain residual value guarantees,

which may be triggered in certain circumstances such as if market values have significantly declined at the conclusion of the lease.

The table below shows the timing of the undiscounted cash outflows for the lease liabilities included on the balance sheet.

---

| | | |
|:---|:---|:---|
|  |  | $ million |
|  | **2025** | 2024 |
| **Undiscounted lease liability cash flows due:** |  |  |
| Within 1 year | **3596** | 3237 |
| 1 to 2 years | **2906** | 2418 |
| 2 to 3 years | **2222** | 1798 |
| 3 to 4 years | **1620** | 1394 |
| 4 to 5 years | **1481** | 1099 |
| 5 to 10 years | **4076** | 3039 |
| Over 10 years | **3435** | 1283 |
|  | **19336** | 14268 |
| Impact of discounting | **(4765)** | (2268) |
| **Lease liabilities at 31 December** | **14571** | 12000 |
| Of which – current | **2832** | 2660 |
| – non-current | **11739** | 9340 |

---

---

| | |
|:---|:---|
| 214 | bp Annual Report and Form 20-F 2025 |

---

**28. Leases - continued**

The group may enter into lease arrangements a number of years before taking control of the underlying asset due to construction lead times or to

secure future operational requirements. The total undiscounted amount for future commitments for leases not yet commenced as at 31 December

2025 is $2,953 million (2024 $5,311 million). The majority of this future commitment relates to pipelines that are under construction in the Gulf of

America from 2026.

---

| | | |
|:---|:---|:---|
|  |  | $ million |
|  | **2025** | 2024 |
| Total cash outflow for amounts included in lease liabilities | **3727** | 3283 |
| Expense for variable payments not included in the lease liability<sup>a</sup> | **61** | 45 |
| Short-term lease expense<sup>a</sup> | **286** | 499 |
| Additions to right-of-use assets in the period | **4349** | 3781 |
| Gain (loss) on sale and leaseback transactions | **1** |  |

---

aThe cash outflows for amounts not included in lease liabilities approximate the income statement expenses disclosed above.

An analysis of right-of-use assets and depreciation is provided in Note 12. An analysis of lease interest expense is provided in Note 7.

**29. Financial instruments and financial risk factors** 

The accounting classification of each category of financial instruments and their carrying amounts are set out below.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  | $ million |
| At 31 December 2025 | Note | **Measured at** <br>**amortized cost**<br>| **Mandatorily** <br>**measured at** <br>**fair value** <br>**through profit** <br>**or loss**<br>| **Derivative** <br>**hedging** <br>**instruments**<br>| **Total carrying**<br>**amount**<br>|
| **Financial assets** |  |  |  |  |  |
| Other investments | 18 | **—** | **1015** | **—** | **1015** |
| Loans |  | **1991** | **457** | **—** | **2448** |
| Trade and other receivables | 20 | **26567** | **—** | **—** | **26567** |
| Derivative financial instruments | 30 | **—** | **25892** | **245** | **26137** |
| Cash and cash equivalents | 25 | **31777** | **4779** | **—** | **36556** |
| **Financial liabilities** |  |  |  |  |  |
| Trade and other payables | 22 | **(58182)** | **—** | **—** | **(58182)** |
| Derivative financial instruments | 30 | **—** | **(23056)** | **(1024)** | **(24080)** |
| Accruals |  | **(7406)** | **—** | **—** | **(7406)** |
| Lease liabilities | 28 | **(14571)** | **—** | **—** | **(14571)** |
| Finance debt | 26 | **(57958)** | **—** | **—** | **(57958)** |
|  |  | **(77782)** | **9087** | **(779)** | **(69474)** |

---

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  | $ million |
| At 31 December 2024 | Note | Measured at <br>amortized cost<br>| Mandatorily <br>measured at <br>fair value <br>through profit <br>or loss<br>| Derivative <br>hedging <br>instruments<br>| Total carrying<br>amount<br>|
| **Financial assets** |  |  |  |  |  |
| Other investments | 18 | 26 | 1431 |  | 1457 |
| Loans |  | 1807 | 377 |  | 2184 |
| Trade and other receivables | 20 | 27148 |  |  | 27148 |
| Derivative financial instruments | 30 |  | 21226 |  | 21226 |
| Cash and cash equivalents | 25 | 32547 | 6657 |  | 39204 |
| **Financial liabilities** |  |  |  |  |  |
| Trade and other payables | 22 | (61298) |  |  | (61298) |
| Derivative financial instruments | 30 |  | (20224) | (2655) | (22879) |
| Accruals |  | (7397) |  |  | (7397) |
| Lease liabilities | 28 | (12000) |  |  | (12000) |
| Finance debt | 26 | (59547) |  |  | (59547) |
|  |  | (78714) | 9467 | (2655) | (71902) |

---

The fair value of finance debt is shown in Note 26. For all other financial instruments within the scope of IFRS 9, the carrying amount is either the fair

value, or approximates the fair value.

Information on gains and losses on derivative financial assets and financial liabilities classified as measured at fair value through profit or loss is

provided in the derivative gains and losses section of Note 30. Fair value gains and losses related to other assets and liabilities classified as

measured at fair value through profit or loss totalled a net loss of $354 million (2024 net gain of $1 million and 2023 net loss of $11 million). Dividend

income of $19 million (2024 $24 million and 2023 $18 million) from investments in equity instruments classified as measured at fair value through

profit or loss is presented within other income.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 215 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**29. Financial instruments and financial risk factors – continued** 

Interest income and expenses arising on financial instruments are disclosed in Note 7.

**Financial risk factors**

The group is exposed to a number of different financial risks arising from ordinary business exposures as well as its use of financial instruments

including market risks relating to commodity prices; foreign currency exchange rates and interest rates; credit risk; and liquidity risk.

The group financial risk committee (GFRC) advises the chief financial officer (CFO) who oversees the management of these risks. The GFRC is

chaired by the CFO and consists of a group of senior managers including the SVPs tax and treasury, central financial planning & analysis, mergers &

acquisitions and business development, finance supply, trading and shipping, and the group controller. The purpose of the committee is to advise

on financial risks and the appropriate financial risk governance framework for the group. The committee provides assurance to the CFO and the

chief executive officer (CEO), and via the CEO to the board, that the group's financial risk-taking activity is governed by appropriate policies and

procedures and that financial risks are identified, measured and managed in accordance with group policies and group risk appetite.

The group's trading activities in the oil, natural gas, LNG and power markets are managed within the supply, trading and shipping business. Treasury

holds foreign exchange and interest-rate products in the financial markets to hedge group exposures related to debt and hybrid bond issuance; the

compliance, control and risk management processes for these activities are managed within the treasury business. All other foreign exchange and

interest rate activities within financial markets are performed within the supply, trading and shipping business and are also underpinned by the

compliance, control and risk management infrastructure common to the activities of bp's supply, trading and shipping business. All derivative

activity is carried out by specialist teams that have the appropriate skills, experience and supervision. These teams are subject to close financial and

management control.

The supply, trading and shipping business maintains formal governance processes that provide oversight of market risk, credit risk and operational

risk associated with trading activity. A policy and risk committee approves value-at-risk delegations, reviews incidents and validates risk-related

policies, methodologies and procedures. A commitments committee approves the trading of new products, instruments and strategies and

material commitments.

In addition, the supply, trading and shipping business undertakes derivative activity for risk management purposes under a control framework as

described more fully below.

(a) Market risk

Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The

primary commodity price risks that the group is exposed to include oil, natural gas and power prices that could adversely affect the value of the

group's financial assets, liabilities or expected future cash flows. The group has developed a control framework aimed at managing the volatility

inherent in certain of its ordinary business exposures. In accordance with the control framework the group enters into various transactions using

derivatives for risk management purposes.

The major components of market risk are commodity price risk, foreign currency exchange risk and interest rate risk, each of which is discussed

below.

**(i) Commodity price risk**

The group's supply, trading and shipping business is responsible for delivering value across the overall crude, oil products, gas, LNG and power

supply chains. As such, it routinely enters into spot and term physical commodity contracts in addition to optimising physical storage, pipeline and

transportation capacity. These activities expose the group to commodity price risk which is managed by entering into oil, natural gas and power

swaps, options and futures.

The group measures market risk exposure arising from its risk managed trading positions using value-at-risk techniques based on Monte Carlo

simulation models. These techniques make a statistical assessment of the market risk arising from possible future changes in market prices over a

one-day holding period within a 95% confidence level. Risk managed trading activity is subject to value-at-risk and other limits for each trading

activity and the aggregate of all trading activity. The calculation of potential changes in value within the risk managed period considers positions,

historical price movements and the correlation of these price movements. Models are regularly reviewed against actual fair value movements to

ensure integrity is maintained. The value-at-risk measure is supplemented by stress testing and scenario analysis through simulating the financial

impact of certain physical, economic and geo-political scenarios. The value-at-risk measure in respect of the aggregated risk managed trading

positions at 31 December 2025 was $34 million (2024 $42 million) whereas the average value-at-risk measure for the period was $49 million (2024

$35 million). This measure incorporates the effect of diversification reflecting the offsetting risks across the trading portfolio. Alternative measures

are used to monitor exposures which are not risk managed and for which value-at-risk techniques are not appropriate.

**(ii) Foreign currency exchange risk**

Since bp has global operations, fluctuations in foreign currency exchange rates can have a significant effect on the group's reported results and

future expenditure commitments. The effects of most exchange rate fluctuations are absorbed in business operating results through changing

cost competitiveness, lags in market adjustment to movements in rates and translation differences accounted for on specific transactions. For this

reason, the total effect of exchange rate fluctuations is not identifiable separately in the group's reported results. The main underlying economic

currency of the group's cash flows is the US dollar. This is because bp's major product, oil, is priced internationally in US dollars. bp's foreign

currency exchange management policy is to limit economic and material transactional exposures arising from currency movements against the US

dollar. The group co-ordinates the handling of foreign currency exchange risks centrally, by netting off naturally-occurring opposite exposures

wherever possible and then managing any material residual foreign currency exchange risks.

Most of the group's borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2025, the total foreign currency

borrowings not swapped into US dollars amounted to $454 million (2024 $555 million). The group also has in issue perpetual subordinated hybrid

bonds in euro, sterling and US dollars. Whilst the contractual terms of these instruments allow the group to defer coupon payments and the

repayment of principal indefinitely, the group has chosen to manage the foreign currency exposure relating to the non-US dollar hybrid bonds to

their respective first call periods.

The group manages the net residual foreign currency exposures by constantly reviewing the foreign currency economic value at risk and aims to

manage such risk to keep the 12-month foreign currency value at risk below $400 million. At no point over the past three years did the value at risk

exceed the maximum risk limit. A continuous assessment is made in respect of the group's foreign currency exposures to capture hedging

requirements.

---

| | |
|:---|:---|
| 216 | bp Annual Report and Form 20-F 2025 |

---

**29. Financial instruments and financial risk factors – continued** 

During the year, hedge accounting was applied to foreign currency exposure to highly probable forecast capital expenditure commitments. The

group fixes the US dollar cost of non-US dollar supplies by using currency forwards for the highly probable forecast capital expenditure. At

31 December 2025 the most significant open contracts in place were for USD equivalent amounts of $84 million Australian dollars (2024 $92 million

sterling).

Where the group enters into foreign currency exchange contracts for entrepreneurial trading purposes the activity is controlled using trading

value-at-risk techniques as explained in (i) commodity price risk above.

**(iii) Interest rate risk**

bp is also exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its financial

instruments, principally finance debt. While the group issues debt and hybrid bonds in a variety of currencies based on market opportunities, it uses

derivatives to swap the economic exposure to a floating rate basis, mainly to US dollar floating, but in certain defined circumstances maintains a US

dollar fixed rate exposure for a proportion of debt. The proportion of floating rate debt net of interest rate swaps at 31 December 2025 was 29% of

total finance debt outstanding (2024 30%). The weighted average interest rate on finance debt at 31 December 2025 was 5% (2024 5%) and the

weighted average maturity of fixed rate debt was eight years (2024 eight years).

The group's earnings are sensitive to changes in interest rates on the element of the group's finance debt that is contractually floating rate or has

been swapped to floating rates. If the interest rates applicable to these floating rate instruments of $16,694 million (2024 $18,006 million) (see Note

26) were to have changed by one percentage point on 1 January 2026, it is estimated that the group's finance costs for 2026 would change by

approximately $167 million (2024 $180 million).

(b) Credit risk

Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing financial loss

to the group and arises from cash and cash equivalents, derivative financial instruments and deposits with financial institutions and principally

from credit exposures to customers relating to outstanding receivables. Credit exposure also exists in relation to guarantees issued by group

companies under which the outstanding exposure incremental to that recognized on the balance sheet at 31 December 2025 was $708 million

(2024 $655 million) in respect of liabilities of joint ventures and associates and $659 million (2024 $585 million) in respect of liabilities of other third

parties. An amount of $170 million (2024 $146 million) is recorded as a liability at 31 December 2025 in relation to these guarantees. For all

guarantees, maturity dates vary, and the guarantees will terminate on payment and/or cancellation of the obligation. In general, a payment under

the guarantee contract would be triggered by failure of the guaranteed party to fulfil its obligation covered by the guarantee.

The group has a credit policy, approved by the CFO, that is designed to ensure that consistent processes are in place throughout the group to

measure and control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business

contract the extent to which the arrangement exposes the group to credit risk is considered. Key requirements of the policy include segregation of

credit approval authorities from any sales, marketing or trading teams authorized to incur credit risk; the establishment of credit systems and

processes to ensure that all counterparty exposure is rated and that all counterparty exposure and limits can be monitored and reported; and the

timely identification and reporting of any non-approved credit exposures and credit losses. While each segment is responsible for its own credit

risk management and reporting consistent with group policy, treasury holds group-wide credit risk authority and oversight responsibility for

exposure to banks and financial institutions.

For the purposes of financial reporting the group calculates expected loss allowances based on the maximum contractual period over which the

group is exposed to credit risk. Lifetime expected credit losses are recognized for trade receivables and the credit risk associated with the

significant majority of financial assets measured at amortized cost is considered to be low. Since the tenor of substantially all of the group's in-

scope financial assets is less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit

losses. Expected loss allowances for financial guarantee contracts are typically lower than their initial fair value less, where appropriate,

amortization. Financial assets are considered to be credit-impaired when there is reasonable and supportable evidence that one or more events

that have a detrimental impact on the estimated future cash flows of the financial asset have occurred. This includes observable data concerning

significant financial difficulty of the counterparty; a breach of contract; concession being granted to the counterparty for economic or contractual

reasons relating to the counterparty's financial difficulty, that would not otherwise be considered; it becoming probable that the counterparty will

enter bankruptcy or other financial re-organization or an active market for the financial asset disappearing because of financial difficulties. The

group also applies a rebuttable presumption that an asset is credit-impaired when contractual payments are more than 30 days past due. Where

the group has no reasonable expectation of recovering a financial asset in its entirety or a portion thereof, for example where all legal avenues for

collection of amounts due have been exhausted, the financial asset (or relevant portion) is written off.

The measurement of expected credit losses is a function of the probability of default, loss given default (i.e. the magnitude of the loss after

recovery if there is a default) and the exposure at default (i.e. the asset's carrying amount). The group allocates a credit risk rating to exposures

based on data that is determined to be predictive of the risk of loss, including but not limited to external ratings. Probabilities of default derived

from historical, current and future-looking market data are assigned by credit risk rating with a loss given default based on historical experience

and relevant market and academic research applied by exposure type. Experienced credit judgement is applied to ensure probabilities of default

are reflective of the credit risk associated with the group's exposures. Credit enhancements that would reduce the group's credit losses in the

event of default are reflected in the calculation when they are considered integral to the related asset.

The maximum credit exposure associated with financial assets is equal to the carrying amount. The group does not aim to remove credit risk

entirely but expects to experience a certain level of credit losses. As at 31 December 2025, the group had in place credit enhancements designed to

mitigate approximately $9.3 billion (2024 $8.2 billion) of credit risk related to assets in the scope of IFRS 9's impairment requirements. Credit

enhancements include standby and documentary letters of credit, bank guarantees, and insurance which are typically taken out with financial

institutions who have investment grade credit ratings. Reports are regularly prepared and presented to the GFRC that cover the group's overall

credit exposure and expected loss trends, exposure by segment, and overall quality of the portfolio.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 217 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**29. Financial instruments and financial risk factors – continued** 

Management information used to monitor credit risk, which reflects the impact of credit enhancements, indicates that the risk profile of financial

assets which are subject to review for impairment under IFRS 9 is as set out in the table below.

---

| | | |
|:---|:---|:---|
|  |  | % |
| As at 31 December | **2025** | 2024 |
| AAA to AA- | **14%** | 12% |
| A+ to A- | **52%** | 50% |
| BBB+ to BBB- | **13%** | 16% |
| BB+ to BB- | **11%** | 10% |
| B+ to B- | **6%** | 8% |
| CCC+ and below | **4%** | 4% |

---

Movements in the impairment provision for trade and other receivables are shown in Note 21.

**Financial instruments subject to offsetting, enforceable master netting arrangements and similar agreements**

The following table shows the amounts recognized for financial assets and liabilities which are subject to offsetting arrangements on a gross basis,

and the amounts offset in the balance sheet.

Amounts which cannot be offset under IFRS, but which could be settled net under the terms of master netting agreements if certain conditions

arise, and collateral received or pledged, are also presented in the table to show the total net exposure of the group.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  | $ million |
|  | **Gross** <br>**amounts of** <br>**recognized** <br>**financial** <br>**assets** <br>**(liabilities)** | **Amounts**<br>**set off** | **Net amounts**<br>**presented on**<br>**the balance**<br>**sheet** | **Related amounts not set off**<br>**in the balance sheet** | **Related amounts not set off**<br>**in the balance sheet** | **Net amount** |
| At 31 December 2025 | **Gross** <br>**amounts of** <br>**recognized** <br>**financial** <br>**assets** <br>**(liabilities)** | **Amounts**<br>**set off** | **Net amounts**<br>**presented on**<br>**the balance**<br>**sheet** | **Master**<br>**netting**<br>**arrangements**<br>| **Cash**<br>**collateral**<br>**(received)**<br>**pledged**<br>| **Net amount** |
| Derivative assets | **28414** | **(2277)** | **26137** | **(7491)** | **(544)** | **18102** |
| Derivative liabilities | **(26357)** | **2277** | **(24080)** | **7491** | **101** | **(16488)** |
| Trade and other receivables | **14055** | **(6385)** | **7670** | **(1555)** | **(170)** | **5945** |
| Trade and other payables | **(17308)** | **6385** | **(10923)** | **1555** | **8** | **(9360)** |
| At 31 December 2024 |  |  |  |  |  |  |
| Derivative assets | 23779 | (2553) | 21226 | (5624) | (362) | 15240 |
| Derivative liabilities | (25432) | 2553 | (22879) | 5624 | 294 | (16961) |
| Trade and other receivables | 17832 | (9445) | 8387 | (1532) | (206) | 6649 |
| Trade and other payables | (20289) | 9445 | (10844) | 1532 | 12 | (9300) |

---

(c) Liquidity risk

Liquidity risk is the risk that suitable sources of funding for the group's business activities may not be available. The group's liquidity is managed

centrally with operating units forecasting their cash and currency requirements to the central treasury function. Unless restricted by local

regulations, generally subsidiaries pool their cash surpluses to the treasury function, which will then arrange to fund other subsidiaries'

requirements, or invest any net surplus in the market or arrange for necessary external borrowings, while managing the group's overall net

currency positions. While there is the potential for concerns about the energy transition to impact banks' or debt investors' appetite to finance

hydrocarbon activity, we do not anticipate any material change to the group's funding or liquidity in the short to medium term as a result of such

concerns.

The group benefits from open credit provided by suppliers who generally sell on five to 60-day payment terms in accordance with industry norms.

bp utilizes various arrangements in order to manage its working capital and reduce volatility in cash flow. This includes discounting receivables and,

in the supply and trading businesses, managing inventory, collateral and supplier payment terms within a maximum of 60 days.

It is normal practice in the oil and gas supply and trading business for customers and suppliers to utilize letters of credit (LCs) facilities to mitigate

credit and non-performance risk. Consequently, LCs facilitate active trading in a global market where credit and performance risk can be

significant. In common with the industry, bp routinely provides LCs to some of its suppliers.

The group has committed LC facilities totalling $10,350 million (2024 $12,130 million), allowing LCs to be issued for a maximum 24-month duration.

The facilities are held with 17 international banks.

In certain circumstances, the supplier has the option to request accelerated payment from the LC provider in order to further reduce their

exposure. bp's payments are made to the provider of the LC rather than the supplier according to the original contractual payment terms. At 31

December 2025, a portion of the group's trade payables which were subject to the LC arrangements were payable to LC providers, with no material

exposure to any individual provider. If these facilities were not available, this could result in renegotiation of payment terms with suppliers such that

payment terms were shorter.

The group sometimes uses promissory notes to pay its suppliers and other counterparties. This is primarily done to facilitate the counterparty

accelerating its cash inflow without also accelerating the group's related cash outflow. For instance, if a supplier to the group's supply, trading and

shipping business would like prepayment or early-payment for a supply of goods, the group may issue a promissory note (payable at a future date)

in favour of that supplier on the supplier's desired cash inflow date, which that supplier can then convert to cash by selling it to a finance provider

on the same-day. The majority of promissory notes the group issues accrue interest on the principal amount of the note at a fixed rate stated on the

note from issuance to maturity. This is done to give the supplier or other counterparty certainty about the amount they will receive when they sell

the note. It also gives the group flexibility to select the maturity date of the note without that impacting the net present value of the note on its

issuance date. The maturity date the group selects for any promissory note that is for the purchase of goods by its supply and trading business will

be no more than 60 days after the group takes (or expects to take) title to those goods.

---

| | |
|:---|:---|
| 218 | bp Annual Report and Form 20-F 2025 |

---

**29. Financial instruments and financial risk factors – continued**

A portion of the group's trade payables form part of a reverse factoring arrangement with select suppliers.

Suppliers' participation in the reverse factoring arrangement is voluntary. Suppliers that participate have the option to receive early payment on

invoices from the group's external finance provider. If suppliers choose to receive early payment, they pay a fee to the finance provider. If they opt

not to receive early payment, they will pay no fee to the finance provider and will be paid the full invoice amount on the invoice due date. The group

provides data about invoices subject to the arrangement directly to the finance provider. This data includes the invoice due date and the maturity

date for each invoice. The invoice due date is the date the supplier would have been entitled to receive payment from the group had the invoice not

been made subject to the reverse factoring arrangement. The maturity date, which is the date the group will settle that invoice by paying the

finance provider, will, in some cases, be the same as the invoice due date. In other cases, it will be a date selected by the group that is no more than

60 days after the group has taken title to the goods to which the invoice relates. If the group selects a maturity date that is after the invoice due

date, the group pays the finance provider a fee.

Management does not consider the reverse factoring arrangement to result in excessive concentrations of liquidity risk, in part because the finance

provider has the option to (and does) sub-participate portions of the financings to other finance providers. The arrangements have been

established for a variety of reasons, including to ease the administrative burden of managing high volumes of invoices from some suppliers, to

facilitate some suppliers having the option to accelerate when they receive payment, often at a lower cost than that supplier's usual cost of

borrowing, and, in some cases, to manage the working capital and reduce volatility in cash flow of the group's supply and trading business. The

group has not derecognized the original trade payables relating to the arrangements because the original liability is not substantially modified on

entering into the arrangements.

Additional information about the group's trade payables that are subject to supplier finance arrangements is provided in the table below.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  |  | **2025** |  |  | 2024 |
|  | **Letters of** <br>**Credit** <br>| **Promissory** <br>**Notes**<br>| **Reverse** <br>**Factoring** <br>**Arrangements**<br>| Letters of <br>Credit<br>| Promissory <br>Notes<br>| Reverse <br>Factoring <br>Arrangements<br>|
| **Carrying amount of liabilities ($ million)** |  |  |  |  |  |  |
| Presented within trade and other payables | **5596** | **1356** | **1018** | 7431 | 1778 | 390 |
| of which suppliers have received payment from the <br>financial institution<br>| **5247** | **1356** | **1018** | 7016 | 1778 | 390 |
| **Range of payment due dates (days)** |  |  |  |  |  |  |
| Liabilities that are part of the arrangement | **6 to 60** | **30 to 60** | **30 to 60** | 8 to 57 | 30 to 60 | 30 to 60 |
| Trade payables that are not part of the arrangement | **8 to 60** | **6 to 60** | **7 to 60** | 6 to 60 | 6 to 60 | 6 to 60 |

---

The group does not provide any collateral to the external finance provider.

There were no material business combinations or foreign exchange differences that would affect the liabilities under the supplier finance

arrangement in either period.

There were no significant non-cash changes in the carrying amount of financial liabilities subject to the supplier finance arrangements. The

payments to the bank are included within operating cash flows because they continue to be part of the normal operating cycle of the group and

their principal nature remains operating – i.e., payment for the purchase of goods and services.

If these facilities were not available, this could result in renegotiation of payment terms with suppliers such that settlement periods were shorter.

Standard & Poor's Ratings long-term credit rating for bp is A- (stable) and Moody's Investors Service rating is A1 (stable) and the Fitch Ratings' long-

term credit rating is A+ (stable).

During 2025, $239 million (2024 $9 billion) of long-term taxable bonds were issued with terms of nine years. In addition the group issued perpetual

hybrid capital securities with a US dollar equivalent value of $500 million (2024 $4.3 billion). Commercial paper is issued at competitive rates to

meet short-term borrowing requirements as and when needed.

As a further liquidity measure, the group continues to maintain suitable levels of cash and cash equivalents, amounting to $36.6 billion at

31 December 2025 (2024 $39.2 billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate and

short notice. As at 31 December 2025, the group had substantial amounts of undrawn borrowing facilities available, consisting of a committed

$8.0 billion credit facility and $4.0 billion of standby facilities, available for five years. These facilities are held with 33 international banks and

borrowings via these facilities would be at pre-agreed rates.

The group manages liquidity risk associated with derivative contracts, other than derivative hedging instruments, based on the expected maturities

of both derivative assets and liabilities as indicated in Note 30. Management does not currently anticipate any cash flows, other than noted below,

that could be of a significantly different amount or could occur earlier than the expected maturity analysis provided.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 219 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**29. Financial instruments and financial risk factors – continued**

The table below shows the timing of undiscounted cash outflows relating to finance debt, trade and other payables and accruals. As part of actively

managing the group's debt portfolio it is possible that cash flows in relation to finance debt could be accelerated from the profile provided.

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | $ million |
|  |  |  |  | **2025** |  |  |  | 2024 |
|  | **Trade and**<br>**other**<br>**payables**<sup>a</sup><br>| **Accruals** | **Finance**<br>**debt**<sup>b</sup><br>| **Interest on** <br>**finance debt**<br>| Trade and<br>other<br>payables<sup>a</sup><br>| Accruals | Finance<br>debt<sup>b</sup><br>| Interest on <br>finance debt<br>|
| Within one year | **51907** | **5572** | **3312** | **2227** | 53663 | 6071 | 4402 | 2490 |
| 1 to 2 years | **1331** | **319** | **6628** | **1995** | 1670 | 260 | 4716 | 2217 |
| 2 to 3 years | **1203** | **181** | **6007** | **1717** | 1177 | 150 | 6449 | 1947 |
| 3 to 4 years | **1190** | **161** | **4235** | **1480** | 1139 | 130 | 5649 | 1678 |
| 4 to 5 years | **1186** | **172** | **3680** | **1312** | 1138 | 125 | 3928 | 1447 |
| 5 to 10 years | **2413** | **496** | **15775** | **4136** | 3889 | 375 | 17301 | 4877 |
| Over 10 years | **126** | **505** | **13292** | **5347** | 157 | 286 | 13947 | 6198 |
|  | **59356** | **7406** | **52929** | **18214** | 62833 | 7397 | 56392 | 20854 |

---

a2025 includes $8,367 million (2024 $9,520 million) in relation to the Gulf of America oil spill, of which $6,834 million (2024 $8,383 million) matures in greater than one year.

bNot included in the table above are amounts not expected to be paid in cash but for which a cash flow could occur in specific circumstances and for which the earliest repayment periods are

$758 million within 4-5 years, $4,070 million within 5-10 years and $719 million over 10 years. For 2024 the equivalent amounts were $528 million within 2-3 years and $3,283 million in 5-10 years.

The table below shows the timing of cash outflows for derivative financial instruments entered into for the purpose of managing interest rate and

foreign currency exchange risk, whether or not hedge accounting is applied, based upon contractual payment dates. As part of actively managing

the group's debt portfolio it is possible that cash flows in relation to associated derivatives could be accelerated from the profile provided. The

amounts reflect the gross settlement amount where the pay leg of a derivative will be settled separately from the receive leg, as in the case of

cross-currency swaps hedging non-US dollar finance debt or hybrid bonds. The swaps are with high investment-grade counterparties and

therefore the settlement-day risk exposure is considered to be negligible. Not shown in the table are the gross settlement amounts (inflows) for the

receive leg of derivatives that are settled separately from the pay leg, which amount to $25,612 million at 31 December 2025 (2024 $24,206 million)

to be received on the same day as the related cash outflows.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  | $ million |
|  |  |  | **2025** |  | 2024 |
| Cash outflows for derivative financial instruments at 31 December | **Derivative** <br>**assets**<br>| **Derivative** <br>**liabilities**<br>| **Total** | Derivative <br>liabilities<br>| Total |
| Within one year | **1812** | **3324** | **5136** | 1718 | 1718 |
| 1 to 2 years | **2009** | **1068** | **3077** | 5136 | 5136 |
| 2 to 3 years | **1085** | **658** | **1743** | 3077 | 3077 |
| 3 to 4 years | **—** | **3696** | **3696** | 1743 | 1743 |
| 4 to 5 years | **1330** | **225** | **1555** | 3696 | 3696 |
| 5 to 10 years | **3071** | **4443** | **7514** | 8307 | 8307 |
| Over 10 years | **498** | **1465** | **1963** | 2486 | 2486 |
|  | **9805** | **14879** | **24684** | 26163 | 26163 |

---

For further information on our derivative financial instruments, see Note 30.

**30. Derivative financial instruments** 

In the ordinary course of business the group enters into derivative financial instruments (derivatives) to manage its normal business exposures in

relation to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating rate and

fixed rate debt, consistent with its risk management policies and objectives. An outline of the group's financial risks and the objectives and policies

pursued in relation to those risks is set out in Note 29. Additionally, the group has a well-established entrepreneurial trading operation that is

undertaken in conjunction with these activities using a similar range of contracts.

For information on significant estimates and judgements made in relation to the valuation of derivatives see Derivative financial instruments within

Note 1.

The fair values of derivative financial instruments at 31 December are set out below.

Exchange traded derivatives are valued using closing prices provided by the exchange as at the balance sheet date. These derivatives are

categorized within level 1 of the fair value hierarchy. Exchange traded derivatives are typically considered settled through the (normally daily)

payment or receipt of variation margin.

Over-the-counter (OTC) financial swaps, forwards and physical commodity sale and purchase contracts are generally valued using readily available

information in the public markets and quotations provided by brokers and price index developers. These quotes are corroborated with market data

and are categorized within level 2 of the fair value hierarchy.

In certain less liquid markets, or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC financial swaps

and physical commodity sale and purchase contracts are valued using internally developed methodologies that consider historical relationships

between various commodities, and that result in management's best estimate of fair value. These contracts are categorized within level 3 of the fair

value hierarchy.

---

| | |
|:---|:---|
| 220 | bp Annual Report and Form 20-F 2025 |

---

**30. Derivative financial instruments – continued**

Financial OTC and physical commodity options are valued using industry standard models that consider various assumptions, including quoted

forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant

economic factors. The degree to which these inputs are observable in the forward markets determines whether the option is categorized within

level 2 or level 3 of the fair value hierarchy.

---

| | | | | |
|:---|:---|:---|:---|:---|
|  |  |  |  | $ million |
|  |  | **2025** |  | 2024 |
|  | **Fair value**<br>**asset**<br>| **Fair value**<br>**liability**<br>| Fair value<br>asset<br>| Fair value<br>liability<br>|
| **Derivatives held for trading** |  |  |  |  |
| Currency derivatives | **549** | **(720)** | 343 | (1738) |
| Oil price derivatives | **1509** | **(1315)** | 1350 | (1071) |
| Natural gas price derivatives | **14974** | **(13781)** | 11533 | (10506) |
| Power price derivatives | **8605** | **(7046)** | 7905 | (6893) |
| Other derivatives | **255** | **(194)** | 95 | (16) |
|  | **25892** | **(23056)** | 21226 | (20224) |
| **Cash flow hedges** |  |  |  |  |
| Currency forwards | **—** | **—** |  |  |
|  | **—** | **—** |  |  |
| **Fair value hedges** |  |  |  |  |
| Currency swaps | **245** | **(1022)** |  | (2651) |
| Interest rate swaps | **—** | **(2)** |  | (4) |
|  | **245** | **(1024)** |  | (2655) |
|  | **26137** | **(24080)** | 21226 | (22879) |
| Of which – current | **5180** | **(4413)** | 5112 | (4347) |
| – non-current | **20957** | **(19667)** | 16114 | (18532) |

---

**Derivatives held for trading**

The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to satisfy

supply requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original business

objective, and are recognized at fair value with changes in fair value recognized in the income statement. Trading activities are undertaken by using

a range of contract types in combination to create incremental gains by arbitraging prices between markets, locations and time periods. The net of

these exposures is monitored using market value-at-risk techniques as described in Note 29.

The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes.

Derivative assets held for trading have the following fair values and maturities.

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  | $ million |
|  |  |  |  |  |  |  | **2025** |
|  | **Less than**<br>**1 year**<br>| **1-2 years** | **2-3 years** | **3-4 years** | **4-5 years** | **Over**<br>**5 years**<br>| **Total** |
| Currency derivatives | **130** | **90** | **32** | **26** | **63** | **208** | **549** |
| Oil price derivatives | **1277** | **130** | **52** | **42** | **6** | **2** | **1509** |
| Natural gas price derivatives | **2116** | **1057** | **857** | **747** | **662** | **9535** | **14974** |
| Power price derivatives | **1653** | **1211** | **790** | **531** | **408** | **4012** | **8605** |
| Other derivatives | **1** | **2** | **226** | **1** | **—** | **25** | **255** |
|  | **5177** | **2490** | **1957** | **1347** | **1139** | **13782** | **25892** |
|  |  |  |  |  |  |  | $ million |
|  |  |  |  |  |  |  | 2024 |
|  | Less than<br>1 year<br>| 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over<br>5 years<br>| Total |
| Currency derivatives | 197 | 19 | 10 | 7 | 7 | 103 | 343 |
| Oil price derivatives | 1004 | 156 | 78 | 53 | 55 | 4 | 1350 |
| Natural gas price derivatives | 2337 | 923 | 628 | 556 | 503 | 6586 | 11533 |
| Power price derivatives | 1571 | 990 | 627 | 426 | 396 | 3895 | 7905 |
| Other derivatives | 4 | 4 |  | 85 |  | 2 | 95 |
|  | 5113 | 2092 | 1343 | 1127 | 961 | 10590 | 21226 |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 221 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**30. Derivative financial instruments – continued**

Derivative liabilities held for trading have the following fair values and maturities.

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  | $ million |
|  |  |  |  |  |  |  | **2025** |
|  | **Less than**<br>**1 year**<br>| **1-2 years** | **2-3 years** | **3-4 years** | **4-5 years** | **Over**<br>**5 years**<br>| **Total** |
| Currency derivatives | **(192)** | **(20)** | **(14)** | **(196)** | **(12)** | **(286)** | **(720)** |
| Oil price derivatives | **(1155)** | **(138)** | **(15)** | **(6)** | **(1)** | **—** | **(1315)** |
| Natural gas price derivatives | **(1748)** | **(917)** | **(705)** | **(605)** | **(545)** | **(9261)** | **(13781)** |
| Power price derivatives | **(1268)** | **(996)** | **(677)** | **(504)** | **(336)** | **(3265)** | **(7046)** |
| Other derivatives | **(18)** | **(7)** | **(169)** | **—** | **—** | **—** | **(194)** |
|  | **(4381)** | **(2078)** | **(1580)** | **(1311)** | **(894)** | **(12812)** | **(23056)** |
|  |  |  |  |  |  |  | $ million |
|  |  |  |  |  |  |  | 2024 |
|  | Less than<br>1 year<br>| 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over<br>5 years<br>| Total |
| Currency derivatives | (111) | (529) | (172) | (4) | (562) | (360) | (1738) |
| Oil price derivatives | (975) | (65) | (16) | (6) | (9) |  | (1071) |
| Natural gas price derivatives | (2075) | (836) | (515) | (409) | (363) | (6308) | (10506) |
| Power price derivatives | (1062) | (779) | (569) | (401) | (471) | (3611) | (6893) |
| Other derivatives | (6) | (1) |  | (9) |  |  | (16) |
|  | (4229) | (2210) | (1272) | (829) | (1405) | (10279) | (20224) |

---

The following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by

methodology of fair value estimation. This information is presented on a gross basis, that is, before netting by counterparty.

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  | $ million |
|  |  |  |  |  |  |  | **2025** |
|  | **Less than**<br>**1 year**<br>| **1-2 years** | **2-3 years** | **3-4 years** | **4-5 years** | **Over**<br>**5 years**<br>| **Total** |
| **Fair value of derivative assets** |  |  |  |  |  |  |  |
| Level 1 | **131** | **17** | **6** | **—** | **—** | **—** | **154** |
| Level 2 | **4813** | **1541** | **940** | **296** | **198** | **156** | **7944** |
| Level 3 | **1585** | **1339** | **1199** | **1105** | **983** | **13860** | **20071** |
|  | **6529** | **2897** | **2145** | **1401** | **1181** | **14016** | **28169** |
| Less: netting by counterparty | **(1352)** | **(407)** | **(188)** | **(54)** | **(42)** | **(234)** | **(2277)** |
|  | **5177** | **2490** | **1957** | **1347** | **1139** | **13782** | **25892** |
| **Fair value of derivative liabilities** |  |  |  |  |  |  |  |
| Level 1 | **(131)** | **(18)** | **(5)** | **(1)** | **(1)** | **—** | **(156)** |
| Level 2 | **(4337)** | **(1284)** | **(700)** | **(395)** | **(59)** | **(235)** | **(7010)** |
| Level 3 | **(1265)** | **(1183)** | **(1063)** | **(969)** | **(876)** | **(12811)** | **(18167)** |
|  | **(5733)** | **(2485)** | **(1768)** | **(1365)** | **(936)** | **(13046)** | **(25333)** |
| Less: netting by counterparty | **1352** | **407** | **188** | **54** | **42** | **234** | **2277** |
|  | **(4381)** | **(2078)** | **(1580)** | **(1311)** | **(894)** | **(12812)** | **(23056)** |
| **Net fair value** | **796** | **412** | **377** | **36** | **245** | **970** | **2836** |
|  |  |  |  |  |  |  | $ million |
|  |  |  |  |  |  |  | 2024 |
|  | Less than<br>1 year<br>| 1-2 years | 2-3 years | 3-4 years | 4-5 years | Over<br>5 years<br>| Total |
| **Fair value of derivative assets** |  |  |  |  |  |  |  |
| Level 1 | 157 | 35 | 7 | 2 |  |  | 201 |
| Level 2 | 5037 | 1457 | 551 | 330 | 134 | 107 | 7616 |
| Level 3 | 1516 | 1175 | 948 | 839 | 858 | 10626 | 15962 |
|  | 6710 | 2667 | 1506 | 1171 | 992 | 10733 | 23779 |
| Less: netting by counterparty | (1597) | (575) | (163) | (44) | (31) | (143) | (2553) |
|  | 5113 | 2092 | 1343 | 1127 | 961 | 10590 | 21226 |
| **Fair value of derivative liabilities** |  |  |  |  |  |  |  |
| Level 1 | (124) | (20) | (7) | (2) |  |  | (153) |
| Level 2 | (4491) | (1868) | (625) | (189) | (717) | (289) | (8179) |
| Level 3 | (1211) | (897) | (803) | (682) | (719) | (10133) | (14445) |
|  | (5826) | (2785) | (1435) | (873) | (1436) | (10422) | (22777) |
| Less: netting by counterparty | 1597 | 575 | 163 | 44 | 31 | 143 | 2553 |
|  | (4229) | (2210) | (1272) | (829) | (1405) | (10279) | (20224) |
| **Net fair value** | 884 | (118) | 71 | 298 | (444) | 311 | 1002 |

---

---

| | |
|:---|:---|
| 222 | bp Annual Report and Form 20-F 2025 |

---

**30. Derivative financial instruments – continued**

Level 3 derivatives

The following table shows the changes during the year in the net fair value of derivatives held for trading purposes within level 3 of the fair value

hierarchy.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  | $ million |
|  | **Oil**<br>**price**<br>| **Natural gas**<br>**price**<br>| **Power**<br>**price**<br>| **Currency** | **Other** | **Total** |
| Fair value contracts at 1 January 2025 | **30** | **394** | **(306)** | **12** | **2** | **132** |
| Gains (losses) recognized in the income statement | **85** | **62** | **466** | **115** | **23** | **751** |
| Sales | **—** | **—** | **84** | **—** | **—** | **84** |
| Settlements | **(50)** | **(113)** | **(113)** | **(18)** | **—** | **(294)** |
| Transfers out of level 3 | **(8)** | **(412)** | **(146)** | **—** | **1** | **(565)** |
| **Net fair value of contracts at 31 December 2025** | **57** | **(69)** | **(15)** | **109** | **26** | **108** |
| Deferred day-one gains (losses) |  |  |  |  |  | **1796** |
| **Derivative asset (liability)** |  |  |  |  |  | **1904** |
|  |  |  |  |  |  | $ million |
|  | Oil<br>price<br>| Natural gas<br>price<br>| Power<br>price<br>| Currency | Other | Total |
| Fair value contracts at 1 January 2024 | 107 | 599 | (120) | 219 | 2 | 807 |
| Gains (losses) recognized in the income statement | (26) | (90) | 129 | (193) |  | (180) |
| Purchases |  |  | 31 |  |  | 31 |
| Settlements | (38) | (100) | (377) | (14) |  | (529) |
| Transfers out of level 3 | (13) | (15) | 31 |  |  | 3 |
| Net fair value of contracts at 31 December 2024 | 30 | 394 | (306) | 12 | 2 | 132 |
| Deferred day-one gains (losses) |  |  |  |  |  | 1385 |
| Derivative asset (liability) |  |  |  |  |  | 1517 |

---

The amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at 31 December 2025 was a

$514 million gain (2024 $193 million loss related to derivatives still held at 31 December 2024).

Derivative gains and losses

The group enters into derivative contracts including futures, options, swaps and certain forward sales and forward purchases contracts, relating to

both currency and commodity trading activities. Gains or losses arise on contracts entered into for risk management purposes, optimization

activity and entrepreneurial trading. They also arise on certain contracts that are for normal procurement or sales activity for the group but that are

required to be fair valued under accounting standards. These gains and losses are included within sales and other operating revenues in the income

statement. Also included within this line item are gains and losses on inventory held for trading purposes. The total amount relating to all these

items was a net gain of $11,206 million (2024 $9,726 million net gain and 2023 $19,786 million net gain). This number does not include gains and

losses on the change in value of contracts which are not recognized under IFRS such as transportation and storage contracts, but does include the

associated financially settled contracts. The net amounts for actual gains and losses relating to these derivative contracts and all related items

therefore differ significantly from the amounts disclosed above.

As outlined in Note 1 - Significant estimate and judgement: derivative financial instruments, LNG contracts are only recognized in the financial

statements when associated cargoes are lifted. The embedded value in these contracts is not recognized and is subject to underlying commodity

price volatility. bp generally price risk manages the exposure to LNG cargoes due for delivery in the near term where there is a liquid market. It does

so on a portfolio basis using derivative instruments amongst other price risk management strategies. Under IFRS, these derivative instruments,

which are subject to similar price volatility, are recorded at fair value through profit and loss at each reporting period, which creates an accounting

mismatch in the financial statements between the accounting for LNG contracts and the derivatives used for risk management. For the years

ended 31 December 2025 and 31 December 2024, there were no material gains or losses recorded on the associated derivative positions. For the

year ended 31 December 2023, there were material gains recognized on the associated derivative positions due to the movement in the underlying

commodity prices.

The group also enters into derivative contracts relating to foreign currency risk management activities including contracts that the group has

entered into to manage the foreign currency exposure relating to the non-US dollar hybrid bonds to their respective first call periods. The change in

the unrealized value of these contracts was a net gain of $1,187 million (2024 $404 million net loss and 2023 $632 million net gain). Where the

derivative is economically hedging finance debt, gains and losses on such derivative contracts are included within finance costs. Where the

derivative is managing non-US hybrid bond exposure gains and loss are included within production and manufacturing expenses. Where these

gains and losses arise on derivatives hedging finance debt they are largely offset by opposing net foreign exchange differences on retranslation of

the associated non-US dollar debt. The net amounts for actual gains and losses relating to these derivative contracts and all related items therefore

differ significantly from the amounts disclosed above.

**Cash flow hedges**

(i) Foreign currency risk of highly probable forecast capital expenditure

At 31 December 2025, the group held currency forwards designated as hedging instruments in cash flow hedge relationships of highly probable

forecast non-US dollar capital expenditure. Note 29 outlines the group's approach to foreign currency exchange risk management. When the highly

probable forecast capital expenditure designated as a hedged item occurs, a non-financial asset is recognized and is presented within the fixed

asset section of the balance sheet.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 223 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**30. Derivative financial instruments – continued**

The group claims hedge accounting only for the spot value of the currency exposure in line with the strategy to fix the volatility in the spot

exchange rate element. The fair value on the instrument attributable to forward points and foreign currency basis spreads is taken immediately to

the income statement.

The group applies hedge accounting where there is an economic relationship between the hedged item and hedging instrument. The existence of

an economic relationship is determined at inception and prospectively by comparing the critical terms of the hedging instrument and those of the

hedged item. The group enters into hedging derivatives that match the currency and notional of the hedged items on a 1:1 hedge ratio basis. The

hedge ratio is determined by comparing the notional amount of the derivative with the notional designated on the forecast transaction. The group

determines the extent to which it hedges highly probable forecast capital expenditures on a project by project basis.

The group has identified the following sources of ineffectiveness, which are not expected to be material:

• counterparty's credit risk, the group mitigates counterparty credit risk by entering into derivative transactions with high credit quality

counterparties; and

• differences in settlement timing between the derivative and hedged items. The latter impacts the discount factor used in the calculation of the

hedge ineffectiveness. The group mitigates differences in timing between the derivatives and hedged items by applying a rolling strategy and

by hedging currency pairs from stable economies. The group's cash flow hedge designations are highly effective as the sources of

ineffectiveness identified are expected to result in minimal hedge ineffectiveness.

The group has not designated any net positions as hedged items in cash flow hedges of foreign currency risk.

(ii) Commodity price risk of highly probable forecast sales

During the period the group held Henry Hub NYMEX futures designated as hedging instruments in cash flow hedge relationships of certain highly

probable forecast future sales. Henry Hub NYMEX futures are subject to daily settlement, where their fair value at the end of each day is required to

be cash settled, such that the carrying amount of these hedging instruments within continuing hedge relationships is always zero at the end of

each day.

The group is exposed to the variability in the gas price, but only applied hedge accounting to the risk of Henry Hub price movements for a

percentage of future gas sales from its BPX Energy business.

The group applied hedge accounting in relation to these highly probable future sales where there was an economic relationship between the

hedged item and hedging instrument. The existence of an economic relationship was determined at inception and prospectively by comparing the

critical terms of the hedging instrument and those of the hedged item. The group entered into hedging derivatives that matched the notional

amounts of the hedged items on a 1:1 hedge ratio basis. The hedge ratio was determined by comparing the notional amount of the derivative with

the notional amount designated on the forecast transaction.

The hedge was highly effective due to the price index of the hedging instruments matching the price index of the hedged item. The group did not

designate any net positions as hedged items in cash flow hedges of commodity price risk.

The tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the

period.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **Change in fair** <br>**value of** <br>**hedging** <br>**instrument** <br>**used to** <br>**calculate** <br>**ineffectiveness**<br>| **Change in fair** <br>**value of hedged** <br>**item used to** <br>**calculate** <br>**ineffectiveness**<br>| **Hedge** <br>**ineffectiveness** <br>**recognized in** <br>**profit or (loss)**<br>|
| At 31 December 2025 |  |  |  |
| **Cash flow hedges** |  |  |  |
| Foreign exchange risk |  |  |  |
| Highly probable forecast capital expenditure | **—** | **—** | **—** |
| Commodity price risk |  |  |  |
| Highly probable forecast sales | **287** | **(287)** | **—** |
| At 31 December 2024 |  |  |  |
| **Cash flow hedges** |  |  |  |
| Foreign exchange risk |  |  |  |
| Highly probable forecast capital expenditure |  |  |  |
| Commodity price risk |  |  |  |
| Highly probable forecast sales | 155 | (155) |  |

---

---

| | |
|:---|:---|
| 224 | bp Annual Report and Form 20-F 2025 |

---

**30. Derivative financial instruments – continued**

The tables below summarize the carrying amount and nominal amount of the derivatives designated as hedging instruments in cash flow hedge

relationships.

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | **Carrying amount of hedging** <br>**instrument** | **Carrying amount of hedging** <br>**instrument** | **Nominal amounts of hedging** <br>**instruments** | **Nominal amounts of hedging** <br>**instruments** |
|  | **Assets** | **Liabilities** | **Nominal amounts of hedging** <br>**instruments** | **Nominal amounts of hedging** <br>**instruments** |
| At 31 December 2025 | **$ million** | **$ million** | **$ million** | **mmBtu** |
| **Cash flow hedges** |  |  |  |  |
| Foreign exchange risk |  |  |  |  |
| Highly probable forecast capital expenditure | **—** | **—** | **87** |  |
| Commodity price risk |  |  |  |  |
| Highly probable forecast sales | **—** | **—** |  | **(686)** |
| At 31 December 2024 |  |  |  |  |
| **Cash flow hedges** |  |  |  |  |
| Foreign exchange risk |  |  |  |  |
| Highly probable forecast capital expenditure |  |  | 95 |  |
| Commodity price risk |  |  |  |  |
| Highly probable forecast sales |  |  |  | (209) |

---

All hedging instruments are presented within derivative financial instruments on the group balance sheet.

Of the nominal amount of hedging instruments at 31 December 2025 relating to highly probable forecast capital expenditure, $67 million matures

within 12 months (2024 $95 million) and $20 million matures within one to two years of the balance sheet date (2024 $nil). Of the nominal amount of

hedging instruments at 31 December 2025 relating to highly probable forecast sales, 420 mmBtu matures within 12 months (2024 209 mmBtu) and

266 mmBtu matures within one to two years of the balance sheet date (2024 $nil).

The table below summarizes the weighted average exchange rates and the weighted average sales price in relation to the derivatives designated as

hedging instruments in cash flow hedge relationships at 31 December.

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | Weighted average price/rate | Weighted average price/rate | Weighted average price/rate | Weighted average price/rate |
|  | **2025** | **2025** | 2024 | 2024 |
| At 31 December | **Forecast capital** <br>**expenditure**<br>| **Forecast sales** | Forecast capital <br>expenditure<br>| Forecast sales |
| Sterling/US dollar | **1.35** |  | 1.25 |  |
| Euro/US dollar | **—** |  | 1.04 |  |
| Australian dollar/US dollar | **0.67** |  |  |  |
| Henry Hub $/mmBtu |  | **4.01** |  | 3.38 |

---

**Fair value hedges** 

At 31 December 2025, the group held interest rate and cross-currency interest rate swap contracts as fair value hedges of the interest rate risk and

foreign currency risk arising from group fixed rate debt issuances. Note 29 outlines the group's approach to interest rate and foreign currency

exchange risk management. The interest rate swaps are used to convert US dollar denominated fixed rate borrowings into floating rate debt. The

cross-currency interest rate swaps are used to convert sterling, euro, Australian dollar, Japanese yen, Swiss franc, Hong Kong dollar and Norwegian

krone denominated fixed rate borrowings into US dollar floating rate debt. The group manages all risks derived from debt issuance, such as credit

risk, however, the group applies hedge accounting only to certain components of interest rate and foreign currency risk in order to minimize hedge

ineffectiveness. The interest rate and foreign currency exposures are identified and hedged on an instrument-by-instrument basis.

For interest rate exposures, the group designates as a fair value hedge the benchmark interest rate component only. This is an observable and

reliably measurable component of interest rate risk. For foreign currency exposures, the group excludes from the designation the foreign currency

basis spread component implicit in the cross-currency interest rate swaps. This is separately calculated at hedge designation, is recognized in

other comprehensive income over the life of the hedge and amortized to the income statement on a straight-line basis, in accordance with the

group's policy on costs of hedging.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 225 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**30. Derivative financial instruments – continued**

The group applies hedge accounting where there is an economic relationship between the hedged item and the hedging instrument. The existence

of an economic relationship is determined initially by comparing the critical terms of the hedging instrument and those of the hedged item and it is

prospectively assessed using linear regression analysis. The group issues fixed rate debt and enters into interest rate and cross-currency interest

rate swaps with critical terms that match those of the debt and on a 1:1 hedge ratio basis. The hedge ratio is determined by comparing the notional

amount of the derivative with the notional amount of the debt. The hedge relationship is designated for the full term and notional value of the debt.

Both the hedging instrument and the hedged item are expected to be held to maturity.

The group has identified the following sources of ineffectiveness, which are not expected to be material:

• derivative counterparty's credit risk which is not offset by the hedged item. This risk is mitigated by entering into derivative transactions only

with high credit quality counterparties; and

• sensitivity to interest rate between the hedged item and the derivatives. This is driven by differences in payment frequencies between the

instrument and the bond.

The tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the

period. The signage convention for changes in fair value presented in this table is consistent with that presented in Note 27.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **Change in fair** <br>**value of hedging** <br>**instrument used** <br>**to calculate** <br>**ineffectiveness** | **Change in fair** <br>**value of hedged** <br>**item used to** <br>**calculate** <br>**ineffectiveness** | **Hedge** <br>**ineffectiveness** <br>**recognized in** <br>**profit or (loss)** |
| At 31 December 2025 | **Change in fair** <br>**value of hedging** <br>**instrument used** <br>**to calculate** <br>**ineffectiveness** | **Change in fair** <br>**value of hedged** <br>**item used to** <br>**calculate** <br>**ineffectiveness** | **Hedge** <br>**ineffectiveness** <br>**recognized in** <br>**profit or (loss)** |
| **Fair value hedges** |  |  |  |
| Interest rate risk on finance debt | **(2)** | **2** | **—** |
| Interest rate and foreign currency risk on finance debt | **(1850)** | **1797** | **53** |
| At 31 December 2024 |  |  |  |
| **Fair value hedges** |  |  |  |
| Interest rate risk on finance debt |  | 1 | (1) |
| Interest rate and foreign currency risk on finance debt | 927 | (772) | (155) |

---

The tables below summarize the carrying amount of the derivatives designated as hedging instruments in fair value hedge relationships at 31

December.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **Carrying amount of hedging** <br>**instrument** | **Carrying amount of hedging** <br>**instrument** | **Nominal amounts** <br>**of hedging** <br>**instruments** |
| At 31 December 2025 | **Assets** | **Liabilities** | **Nominal amounts** <br>**of hedging** <br>**instruments** |
| **Fair value hedges** |  |  |  |
| Interest rate risk on finance debt | **—** | **(2)** | **149** |
| Interest rate and foreign currency risk on finance debt | **245** | **(1022)** | **16304** |
| At 31 December 2024 |  |  |  |
| **Fair value hedges** |  |  |  |
| Interest rate risk on finance debt |  | (4) | 132 |
| Interest rate and foreign currency risk on finance debt |  | (2651) | 15887 |

---

All hedging instruments are presented within derivative financial instruments on the group balance sheet and are categorized within level 2 of the

fair value hierarchy. Ineffectiveness arising on fair value hedges is included within finance costs in the income statement.

The tables below summarize the profile by tenor of the nominal amount of the derivatives designated as hedging instruments in fair value hedge

relationships at 31 December.

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | $ million |
| At 31 December 2025 | **Less than 1** <br>**year**<br>| **1-2 years** | **2-3 years** | **3-4 years** | **4-5 years** | **5-10 years** | **Over 10 years** | **Total** |
| **Fair value hedges** |  |  |  |  |  |  |  |  |
| Interest rate risk on finance debt | **149** | **—** | **—** | **—** | **—** | **—** | **—** | **149** |
| Interest rate and foreign currency risk on <br>finance debt<br>| **2045** | **1525** | **1843** | **1166** | **1095** | **7099** | **1531** | **16304** |
| At 31 December 2024 |  |  |  |  |  |  |  |  |
| **Fair value hedges** |  |  |  |  |  |  |  |  |
| Interest rate risk on finance debt |  | 132 |  |  |  |  |  | 132 |
| Interest rate and foreign currency risk on <br>finance debt<br>| 1614 | 1819 | 1346 | 1627 | 1047 | 6521 | 1913 | 15887 |

---

---

| | |
|:---|:---|
| 226 | bp Annual Report and Form 20-F 2025 |

---

**30. Derivative financial instruments – continued**

The table below summarizes the weighted average floating interest rate and the weighted average exchange rates in relation to the derivatives

designated as hedging instruments in fair value hedge relationships at 31 December.

---

| | | | | |
|:---|:---|:---|:---|:---|
| At 31 December |  | **2025** |  | 2024 |
|  | **Interest rate** <br>**swaps**<br>| **Cross-currency** <br>**interest rate** <br>**swaps**<br>| Interest rate <br>swaps<br>| Cross-currency <br>interest rate <br>swaps<br>|
| Interest rate | **4.84%** | **5.64%** | 5.45% | 6.34% |
| Sterling/US dollar |  | **1.28** |  | 1.28 |
| Euro/US dollar |  | **1.13** |  | 1.13 |
| Hong Kong dollar/US dollar |  | **0.13** |  |  |
| Canadian dollar/US dollar |  | **—** |  | 0.78 |
| Australian dollar/ US dollar |  | **0.67** |  | 0.67 |
| Japanese Yen/ US dollar |  | **0.01** |  | 0.01 |
| Swiss Franc/US dollar |  | **1.18** |  | 1.18 |

---

The tables below summarize the carrying amount, and the accumulated fair value adjustments included within the carrying amount, of the hedged

items designated in fair value hedge relationships at 31 December.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  | $ million |
|  | **Carrying** <br>**amount of** <br>**hedged item**<br>|  | **Accumulated fair value adjustment included in the** <br>**carrying amount of hedged items** | **Accumulated fair value adjustment included in the** <br>**carrying amount of hedged items** | **Accumulated fair value adjustment included in the** <br>**carrying amount of hedged items** |
| At 31 December 2025 |  | **Liabilities** | **Assets** | **Liabilities** | **Discontinued** <br>**hedges**<br>|
| **Fair value hedges** |  |  |  |  |  |
| Interest rate risk on finance debt |  | **(149)** | **1** | **—** | **(85)** |
| Interest rate and foreign currency risk on finance debt |  | **(16281)** | **1201** | **(35)** | **134** |
| At 31 December 2024 |  |  |  |  |  |
| **Fair value hedges** |  |  |  |  |  |
| Interest rate risk on finance debt |  | (156) | 3 |  | (160) |
| Interest rate and foreign currency risk on finance debt |  | (16295) | 1017 |  | 143 |

---

The hedged item for all fair value hedges is presented within finance debt on the group balance sheet.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 227 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**30. Derivative financial instruments – continued**

**Movement in reserves related to hedge accounting**

The table below provides a reconciliation of the cash flow hedge and costs of hedging reserves on a pre-tax basis by risk category. The signage

convention of this table is consistent with that presented in Note 32.

---

| | | | | |
|:---|:---|:---|:---|:---|
|  |  |  |  | $ million |
|  | **Cash flow hedge reserve** | **Cash flow hedge reserve** |  |  |
|  | **Highly probable** <br>**forecast capital** <br>**expenditure**<br>| **Highly probable** <br>**forecast sales**<br>| **Interest rate** <br>**and foreign** <br>**currency risk on** <br>**finance debt**<br>| **Total** |
| At 1 January 2025 | **3** | **(2)** | **(186)** | **(185)** |
| Recognized in other comprehensive income |  |  |  |  |
| Cash flow hedges marked to market | **5** | **287** | **—** | **292** |
| Cash flow hedges reclassified to the income statement - hedged item affected profit <br>or loss<br>| **—** | **(127)** | **—** | **(127)** |
| Costs of hedging marked to market | **—** | **—** | **27** | **27** |
| Costs of hedging reclassified to the income statement | **—** | **—** | **34** | **34** |
|  | **5** | **160** | **61** | **226** |
| Cash flow hedges transferred to the balance sheet | **(6)** | **—** | **—** | **(6)** |
| **At 31 December 2025** | **2** | **158** | **(125)** | **35** |
|  |  |  |  | $ million |
|  | Cash flow hedge reserve | Cash flow hedge reserve |  |  |
|  | Highly probable <br>forecast capital <br>expenditure<br>| Highly probable <br>forecast sales<br>| Interest rate <br>and foreign <br>currency risk on <br>finance debt<br>| Total |
| At 1 January 2024 | 14 | 529 | (182) | 361 |
| Recognized in other comprehensive income |  |  |  |  |
| Cash flow hedges marked to market | (1) | 155 |  | 154 |
| Cash flow hedges reclassified to the income statement - hedged item affected profit <br>or loss<br>|  | (686) |  | (686) |
| Costs of hedging marked to market |  |  | (2) | (2) |
| Costs of hedging reclassified to the income statement |  |  | (2) | (2) |
|  | (1) | (531) | (4) | (536) |
| Cash flow hedges transferred to the balance sheet | (10) |  |  | (10) |
| **At 31 December 2024** | 3 | (2) | (186) | (185) |

---

All of the cash flow hedge reserve balances at 31 December 2025 and amounts reclassified from these cash flow hedge reserves into profit or loss

during the year relate to continuing hedge relationships. The amounts reclassified are presented in sales and other operating revenues in the

income statement.

Costs of hedging relates to the foreign currency basis spreads of hedging instruments used to hedge the group's interest rate and foreign currency

risk on debt which is a time-period related item.

---

| | |
|:---|:---|
| 228 | bp Annual Report and Form 20-F 2025 |

---

**31. Called-up share capital** 

The allotted, called up and fully paid share capital at 31 December was as follows:

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  | **2025** |  | 2024 |  | 2023 |
| Issued | **Shares**<br>**thousand**<br>| **$ million** | Shares<br>thousand<br>| $ million | Shares<br>thousand<br>| $ million |
| 8% cumulative first preference shares of £1 each<sup>a</sup> | **7233** | **12** | 7233 | 12 | 7233 | 12 |
| 9% cumulative second preference shares of £1 each<sup>a</sup> | **5473** | **9** | 5473 | 9 | 5473 | 9 |
|  |  | **21** |  | 21 |  | 21 |
| Ordinary shares of 25 cents each |  |  |  |  |  |  |
| At 1 January | **16662465** | **4165** | 17900800 | 4475 | 19097783 | 4774 |
| Issue of new shares for employee share-based payment plans | **—** | **—** |  |  | 66000 | 17 |
| Repurchase of ordinary share capital | **(835649)** | **(209)** | (1238335) | (310) | (1262983) | (316) |
| Repurchases transferred to treasury shares | **659497** | **165** |  |  |  |  |
| **At 31 December** | **16486313** | **4121** | 16662465 | 4165 | 17900800 | 4475 |
|  |  | **4142** |  | 4186 |  | 4496 |

---

aThe nominal amount of 8% cumulative first preference shares and 9% cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of

preference shares.

Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for

every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands vote on

other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each.

In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference

shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the

preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over

par value.

During 2025 the company repurchased 836 million (2024 1,238 million) ordinary shares for a total consideration of $4,486 million (2024 $7,127

million, including transaction costs of $24 million (2024 $38 million). 176 million shares repurchased were cancelled and 659 million shares were

held as treasury shares. The repurchased shares represented 5.1% of ordinary share capital. A further 74 million ordinary shares were repurchased

between the end of the reporting period and 13 February 2026, the latest practicable date before the completion of these financial statements, for

a total cost of $450 million of which $448 million has been accrued at 31 December 2025. The number of shares in issue is reduced when shares are

repurchased and cancelled, but is not reduced in respect of the repurchases transferred to treasury shares.

**Treasury shares**<sup>a</sup>

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  | **2025** |  | 2024 |  | 2023 |
|  | **Shares**<br>**thousand**<br>| **Nominal value**<br>**$ million**<br>| Shares<br>thousand<br>| Nominal value<br>$ million<br>| Shares<br>thousand<br>| Nominal value<br>$ million<br>|
| At 1 January | **812021** | **204** | 1077079 | 271 | 1124927 | 281 |
| Purchases for settlement of employee share plans | **660765** | **165** | 8302 | 2 | 24688 | 6 |
| Issue of new shares for employee share-based payment plans | **—** | **—** |  |  | 71039 | 19 |
| Shares re-issued for employee share-based payment plans | **(363198)** | **(92)** | (273360) | (69) | (143575) | (35) |
| **At 31 December** | **1109588** | **277** | 812021 | 204 | 1077079 | 271 |
| Of which – shares held in treasury by bp | **857433** | **214** | 481474 | 121 | 726339 | 183 |
| – shares held in ESOP trusts | **252118** | **63** | 330510 | 83 | 350704 | 88 |
| – shares held by bp's US share plan administrator<sup>b</sup> | **37** | **—** | 37 |  | 36 |  |

---

a See Note 32 for definition of treasury shares.

b Held in the form of ADSs to meet the requirements of employee share-based payment plans in the US.

For each year presented, the balance of shares held in treasury by bp at 1 January represents 2.9% (2024 4.1% and 2023 4.9%) of the called-up

ordinary share capital of the company.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 229 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY

---

| | |
|:---|:---|
| 230 | bp Annual Report and Form 20-F 2025 |

---

**32. Capital and reserves** 

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Share**<br>**capital** | **Share**<br>**premium**<br>**account** | **Capital**<br>**redemption**<br>**reserve** | **Merger**<br>**reserve** | **Total** <br>**share capital**<br>**and capital**<br>**reserves** |
| | **Share**<br>**capital** | **Share**<br>**premium**<br>**account** | **Capital**<br>**redemption**<br>**reserve** | **Merger**<br>**reserve** | **Total** <br>**share capital**<br>**and capital**<br>**reserves** |
| **At 1 January 2025** | **4186** | **14031** | **2806** | **27206** | **48229** |
| Profit (loss) for the year | **—** | **—** | **—** | **—** | **—** |
| **Items that may be reclassified subsequently to profit or loss** |  |  |  |  |  |
| Currency translation differences (including reclassifications) | **—** | **—** | **—** | **—** | **—** |
| Cash flow hedges and costs of hedging (including reclassifications) | **—** | **—** | **—** | **—** | **—** |
| Share of items relating to equity-accounted entities, net of tax | **—** | **—** | **—** | **—** | **—** |
| **Items that will not be reclassified to profit or loss** |  |  |  |  |  |
| Remeasurements of the net pension and other post-employment benefit liability or asset | **—** | **—** | **—** | **—** | **—** |
| Remeasurements of equity investments | **—** | **—** | **—** | **—** | **—** |
| Cash flow hedges that will subsequently be transferred to the balance sheet | **—** | **—** | **—** | **—** | **—** |
| **Total comprehensive income** | **—** | **—** | **—** | **—** | **—** |
| Dividends | **—** | **—** | **—** | **—** | **—** |
| Cash flow hedges transferred to the balance sheet, net of tax | **—** | **—** | **—** | **—** | **—** |
| Repurchases of ordinary share capital | **(44)** | **—** | **44** | **—** | **—** |
| Share-based payments, net of tax<sup>b</sup> | **—** | **35** | **—** | **—** | **35** |
| Share of equity-accounted entities' changes in equity, net of tax | **—** | **—** | **—** | **—** | **—** |
| Issue of perpetual hybrid bonds | **—** | **—** | **—** | **—** | **—** |
| Redemption of perpetual hybrid bonds, net of tax | **—** | **—** | **—** | **—** | **—** |
| Payments on perpetual hybrid bonds | **—** | **—** | **—** | **—** | **—** |
| Transactions involving non-controlling interests, net of tax | **—** | **—** | **—** | **—** | **—** |
| **At 31 December 2025** | **4142** | **14066** | **2850** | **27206** | **48264** |
| **At 1 January 2024** | 4496 | 13815 | 2496 | 27206 | 48013 |
| Profit (loss) for the year |  |  |  |  |  |
| **Items that may be reclassified subsequently to profit or loss** |  |  |  |  |  |
| Currency translation differences (including reclassifications)<sup>a</sup> |  |  |  |  |  |
| Cash flow hedges and costs of hedging (including reclassifications) |  |  |  |  |  |
| Share of items relating to equity-accounted entities, net of tax |  |  |  |  |  |
| Other |  |  |  |  |  |
| **Items that will not be reclassified to profit or loss** |  |  |  |  |  |
| Remeasurements of the net pension and other post-employment benefit liability or asset |  |  |  |  |  |
| Remeasurements of equity investments |  |  |  |  |  |
| Cash flow hedges that will subsequently be transferred to the balance sheet |  |  |  |  |  |
| **Total comprehensive income** |  |  |  |  |  |
| Dividends |  |  |  |  |  |
| Cash flow hedges transferred to the balance sheet, net of tax |  |  |  |  |  |
| Repurchases of ordinary share capital | (310) |  | 310 |  |  |
| Share-based payments, net of tax<sup>b</sup> |  | 216 |  |  | 216 |
| Issue of perpetual hybrid bonds |  |  |  |  |  |
| Redemption of perpetual hybrid bonds, net of tax |  |  |  |  |  |
| Payments on perpetual hybrid bonds |  |  |  |  |  |
| Transactions involving non-controlling interests, net of tax |  |  |  |  |  |
| **At 31 December 2024** | 4186 | 14031 | 2806 | 27206 | 48229 |

---

aIncludes $942 million recycling of cumulative foreign exchange losses from reserves relating to the sale of bp's Türkiye ground fuels business to Petrol Ofisi, offset by movements in Pound

Sterling against the US dollar.

bMovements in treasury shares relate to employee share-based payment plans.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 231 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**32. Capital and reserves – continued**

---

| | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  |  |  | $ million |
| **Treasury**<br>**shares** | **Foreign**<br>**currency**<br>**translation**<br>**reserve** | **Investments in** <br>**equity** <br>**instruments** | **Cash flow**<br>**hedges** | **Costs of** <br>**hedging** | **Total**<br>**fair value**<br>**reserves** | **Profit and**<br>**loss**<br>**account** | **bp**<br>**shareholders'**<br>**equity** | **Non-controlling interests** | **Non-controlling interests** | **Total equity** |
| **Treasury**<br>**shares** | **Foreign**<br>**currency**<br>**translation**<br>**reserve** | **Investments in** <br>**equity** <br>**instruments** | **Cash flow**<br>**hedges** | **Costs of** <br>**hedging** | **Total**<br>**fair value**<br>**reserves** | **Profit and**<br>**loss**<br>**account** | **bp**<br>**shareholders'**<br>**equity** | **Hybrid bonds** | **Other interest** | **Total equity** |
| **(9030)** | **(2196)** | **(3)** | **(98)** | **(187)** | **(288)** | **22531** | **59246** | **16649** | **2423** | **78318** |
| **—** | **—** | **—** | **—** | **—** | **—** | **55** | **55** | **799** | **441** | **1295** |
| **—** | **1804** | **1** | **—** | **—** | **1** | **—** | **1805** | **—** | **115** | **1920** |
| **—** | **—** | **—** | **122** | **61** | **183** | **—** | **183** | **—** | **—** | **183** |
| **—** | **—** | **—** | **—** | **—** | **—** | **(4)** | **(4)** | **—** | **—** | **(4)** |
| **—** | **—** | **—** | **—** | **—** | **—** | **(166)** | **(166)** | **—** | **—** | **(166)** |
| **—** | **—** | **(6)** | **—** | **—** | **(6)** | **—** | **(6)** | **—** | **—** | **(6)** |
| **—** | **—** | **—** | **5** | **—** | **5** | **—** | **5** | **—** | **—** | **5** |
| **—** | **1804** | **(5)** | **127** | **61** | **183** | **(115)** | **1872** | **799** | **556** | **3227** |
| **—** | **—** | **—** | **—** | **—** | **—** | **(5087)** | **(5087)** | **—** | **(524)** | **(5611)** |
| **—** | **—** | **—** | **(6)** | **—** | **(6)** | **—** | **(6)** | **—** | **—** | **(6)** |
| **(3558)** | **—** | **—** | **—** | **—** | **—** | **(454)** | **(4012)** | **—** | **—** | **(4012)** |
| **3917** | **—** | **—** | **—** | **—** | **—** | **(2840)** | **1112** | **—** | **—** | **1112** |
| **—** | **—** | **—** | **—** | **—** | **—** | **1** | **1** | **—** | **—** | **1** |
| **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **500** | **—** | **500** |
| **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **(1200)** | **—** | **(1200)** |
| **—** | **(9)** | **—** | **—** | **—** | **—** | **—** | **(9)** | **(793)** | **—** | **(802)** |
| **—** | **—** | **—** | **—** | **—** | **—** | **(65)** | **(65)** | **—** | **2538** | **2473** |
| **(8671)** | **(401)** | **(8)** | **23** | **(126)** | **(111)** | **13971** | **53052** | **15955** | **4993** | **74000** |
| (11323) | (1920) | 38 | 319 | (183) | 174 | 35339 | 70283 | 13566 | 1644 | 85493 |
|  |  |  |  |  |  | 381 | 381 | 641 | 207 | 1229 |
|  | (276) | (1) |  |  | (1) |  | (277) |  | (87) | (364) |
|  |  |  | (406) | (4) | (410) |  | (410) |  |  | (410) |
|  |  |  |  |  |  | (12) | (12) |  |  | (12) |
|  |  |  |  |  |  | (1) | (1) |  |  | (1) |
|  |  |  |  |  |  | 367 | 367 |  |  | 367 |
|  |  | (40) |  |  | (40) |  | (40) |  |  | (40) |
|  |  |  | (1) |  | (1) |  | (1) |  |  | (1) |
|  | (276) | (41) | (407) | (4) | (452) | 735 | 7 | 641 | 120 | 768 |
|  |  |  |  |  |  | (5018) | (5018) |  | (375) | (5393) |
|  |  |  | (10) |  | (10) |  | (10) |  |  | (10) |
|  |  |  |  |  |  | (7302) | (7302) |  |  | (7302) |
| 2293 |  |  |  |  |  | (1426) | 1083 |  |  | 1083 |
|  |  |  |  |  |  | (22) | (22) | 4352 |  | 4330 |
|  |  |  |  |  |  | 9 | 9 | (1300) |  | (1291) |
|  |  |  |  |  |  |  |  | (610) |  | (610) |
|  |  |  |  |  |  | 216 | 216 |  | 1034 | 1250 |
| (9030) | (2196) | (3) | (98) | (187) | (288) | 22531 | 59246 | 16649 | 2423 | 78318 |

---

---

| | |
|:---|:---|
| 232 | bp Annual Report and Form 20-F 2025 |

---

**32. Capital and reserves – continued**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Share<br>capital | Share<br>premium<br>account | Capital<br>redemption<br>reserve | Merger<br>reserve | Total <br>share capital<br>and capital<br>reserves |
| | Share<br>capital | Share<br>premium<br>account | Capital<br>redemption<br>reserve | Merger<br>reserve | Total <br>share capital<br>and capital<br>reserves |
| **At 1 January 2023** | 4795 | 13692 | 2180 | 27206 | 47873 |
| Profit (loss) for the year |  |  |  |  |  |
| **Items that may be reclassified subsequently to profit or loss** |  |  |  |  |  |
| Currency translation differences (including reclassifications) |  |  |  |  |  |
| Cash flow hedges and costs of hedging (including reclassifications) |  |  |  |  |  |
| Share of items relating to equity-accounted entities, net of tax |  |  |  |  |  |
| **Items that will not be reclassified to profit or loss** |  |  |  |  |  |
| Remeasurements of the net pension and other post-employment benefit liability or asset |  |  |  |  |  |
| Remeasurements of equity investments |  |  |  |  |  |
| Cash flow hedges that will subsequently be transferred to the balance sheet |  |  |  |  |  |
| **Total comprehensive income** |  |  |  |  |  |
| Dividends |  |  |  |  |  |
| Cash flow hedges transferred to the balance sheet, net of tax |  |  |  |  |  |
| Repurchases of ordinary share capital | (316) |  | 316 |  |  |
| Share-based payments, net of tax<sup>a</sup> | 17 | 123 |  |  | 140 |
| Share of equity-accounted entities' changes in equity, net of tax |  |  |  |  |  |
| Issue of perpetual hybrid bonds |  |  |  |  |  |
| Payments on perpetual hybrid bonds |  |  |  |  |  |
| Transactions involving non-controlling interests, net of tax |  |  |  |  |  |
| **At 31 December 2023** | 4496 | 13815 | 2496 | 27206 | 48013 |

---

aMovements in treasury shares relate to employee share-based payment plans.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 233 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**32. Capital and reserves – continued**

---

| | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  |  |  | $ million |
| Treasury<br>shares | Foreign<br>currency<br>translation<br>reserve | Investments in <br>equity <br>instruments | Cash flow<br>hedges | Costs of <br>hedging | Total<br>fair value<br>reserves | Profit and<br>loss<br>account | bp<br>shareholders'<br>equity | Non-controlling interests | Non-controlling interests | Total equity |
| Treasury<br>shares | Foreign<br>currency<br>translation<br>reserve | Investments in <br>equity <br>instruments | Cash flow<br>hedges | Costs of <br>hedging | Total<br>fair value<br>reserves | Profit and<br>loss<br>account | bp<br>shareholders'<br>equity | Hybrid bonds | Other interest | Total equity |
| (12153) | (2643) |  | (183) | (73) | (256) | 34732 | 67553 | 13390 | 2047 | 82990 |
|  |  |  |  |  |  | 15239 | 15239 | 586 | 55 | 15880 |
|  | 728 |  |  |  |  |  | 728 |  | 26 | 754 |
|  |  |  | 488 | (110) | 378 |  | 378 |  |  | 378 |
|  |  |  |  |  |  | (192) | (192) |  |  | (192) |
|  |  |  |  |  |  | (1504) | (1504) |  |  | (1504) |
|  |  | 38 |  |  | 38 |  | 38 |  |  | 38 |
|  |  |  | 15 |  | 15 |  | 15 |  |  | 15 |
|  | 728 | 38 | 503 | (110) | 431 | 13543 | 14702 | 586 | 81 | 15369 |
|  |  |  |  |  |  | (4831) | (4831) |  | (403) | (5234) |
|  |  |  | (1) |  | (1) |  | (1) |  |  | (1) |
|  |  |  |  |  |  | (8167) | (8167) |  |  | (8167) |
| 830 |  |  |  |  |  | (301) | 669 |  |  | 669 |
|  |  |  |  |  |  | 1 | 1 |  |  | 1 |
|  |  |  |  |  |  | (1) | (1) | 176 |  | 175 |
|  | (5) |  |  |  |  |  | (5) | (586) |  | (591) |
|  |  |  |  |  |  | 363 | 363 |  | (81) | 282 |
| (11323) | (1920) | 38 | 319 | (183) | 174 | 35339 | 70283 | 13566 | 1644 | 85493 |

---

---

| | |
|:---|:---|
| 234 | bp Annual Report and Form 20-F 2025 |

---

**32. Capital and reserves – continued**

**Share capital**

The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury

shares.

**Share premium account**

The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares.

**Capital redemption reserve**

The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled.

**Merger reserve**

The balance on the merger reserve represents the premium arising where the fair value of the consideration given is in excess of the nominal value

of the ordinary shares issued in an acquisition made by the issue of shares where merger relief under the Companies Act applies.

**Treasury shares**

Treasury shares represent bp shares repurchased and available for specific and limited purposes. For accounting purposes shares held in

Employee Share Ownership Plans (ESOPs) and bp's US share plan administrator to meet the future requirements of the employee share-based

payment plans are treated in the same manner as treasury shares and are, therefore, included in the financial statements as treasury shares. The

ESOPs are funded by the group and have waived their rights to dividends in respect of such shares held for future awards. Until such time as the

shares held by the ESOPs vest unconditionally to employees, the amount paid for those shares is shown as a reduction in shareholders' equity.

Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group.

**Investments in equity instruments**

This reserve records the change in fair value of investments in equity instruments for which the group has elected to recognize fair value gains and

losses in other comprehensive income.

**Foreign currency translation reserve**

The foreign currency translation reserve records exchange differences arising from the translation of the financial statements of foreign

operations. Upon disposal of foreign operations, the related accumulated exchange differences are reclassified to the income statement.

**Cash flow hedges**

This reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. For

further information on the accounting for cash flow hedges see Note 1 - Derivative financial instruments and hedging activities.

**Costs of hedging** 

This reserve records the change in fair value of the foreign currency basis spread of financial instruments to which cost of hedge accounting has

been applied. The accumulated amount relates to time-period related hedged items and is amortized to profit or loss over the term of the hedging

relationship. For further information on the accounting for costs of hedging see Note 1 - Derivative financial instruments and hedging activities.

**Profit and loss account**

The balance held on this reserve is the accumulated retained profits of the group.

**Non-controlling interests**

Non-controlling interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to bp shareholders. Included within non-

controlling interests are perpetual subordinated hybrid bonds, perpetual subordinated hybrid securities and certain equity instruments with

preferred distributions issued by group subsidiaries. The contractual terms of these instruments allow the group to defer coupon payments, equity

distributions and repayment of principal indefinitely. However, the terms and conditions of each instrument stipulate the circumstances in which

deferred payments and/or the principal amount of the instrument becomes payable. These circumstances, which include the announcement of a

bp p.l.c. ordinary share or parity equity dividend distribution, are within the group's control.

Perpetual subordinated hybrid bonds are issued by BP Capital Markets p.l.c., a group subsidiary, in euro, sterling and US dollars. During the year BP

Capital Markets p.l.c. redeemed $1.2 billion of the non-call 2025 4.375% US dollar hybrid bonds issued in 2020. As at 31 December 2025 the total

population of hybrid bonds include redemption options exercisable at the group's discretion from March 2026 to March 2035 (the first 'call date'),

on specified dates thereafter, or in the event of specific circumstances (such as a change in IFRS or tax regime) as set out in the individual terms of

each issue. Coupons are fixed for an initial period up to dates from June 2026 to June 2035 at rates of 3.25% to 6.45% and reset to rates determined

by the contractual terms of each instrument on certain dates thereafter. Whilst the contractual terms of these instruments allow the group to defer

coupon payments and the repayment of principal indefinitely, the group has chosen to swap the non-US dollar hybrid bonds to a USD floating

interest rate up to their respective first call periods. Payments made to and profit attributed to these hybrid bonds in the year totalled $644 million

(2024 $485 million) and $640 million (2024 $517 million) respectively. The amount of hybrid bonds included in non-controlling interests at the end of

the year was $13.5 billion (2024 $14.6 billion).

Perpetual subordinated hybrid securities issued by group subsidiaries include $1,000 million (2024 $500 million), specifically earmarked to fund BP

Alternative Energy Investments Ltd including the funding of Lightsource bp and $1,500 million (2024 $1500 million) specifically earmarked to fund a

floating, production, storage and offloading vessel (FPSO) used in one of the group's major projects. Payments made to and profit attributed to

perpetual hybrid securities in the year totalled $158 million (2024 $125 million) and $159 million (2024 $125 million) respectively. The amount of

perpetual subordinated hybrid securities included within non-controlling interests at the end of the year was $2.5 billion (2024 $2.0 billion).

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 235 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**32. Capital and reserves – continued**

Equity instruments with preferred distributions issued by group subsidiaries include $958 million of proceeds in 2025 from the sale of a 25% non-

controlling interest in the subsidiary that holds bp's 12% interest in the entity that owns Trans-Anatolian natural gas pipeline and proceeds of $1,500

million the sale of a 49% and 50%, respectively, in non-controlling interests in the group subsidiaries that hold interests in Permian and Eagle Ford

midstream assets. Proceeds in 2024 of $1,330 million comprise $500 million of proceeds from the sale of a 49% interest in a subsidiary that holds

certain Gulf of America midstream assets; and $830 million of proceeds from the sale of a 25% non-controlling interest in the subsidiary that holds

bp's 20% interest in the entity that holds the Trans Adriatic natural gas pipeline. In these transactions, the group retains control over the ability to

defer equity distributions which are not guaranteed, and investors have no right to redeem their shares other than in certain circumstances that are

within the group's control. The amount associated with equity instruments with preferred or other structured distributions included within non-

controlling interests at the end of the year was approximately $4.5 billion (2024 $1.6 billion).

The pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  |  |  | **2025** |
|  | **Pre-tax** | **Tax** | **Net of tax** |
| **Items that may be reclassified subsequently to profit or loss** |  |  |  |
| Currency translation differences (including reclassifications) | **1904** | **16** | **1920** |
| Cash flow hedges (including reclassifications) | **160** | **(38)** | **122** |
| Costs of hedging (including reclassifications) | **61** | **—** | **61** |
| Share of items relating to equity-accounted entities, net of tax | **(4)** | **—** | **(4)** |
| **Items that will not be reclassified to profit or loss** |  |  |  |
| Remeasurements of the net pension and other post-employment benefit liability or asset | **(221)** | **55** | **(166)** |
| Remeasurements of equity investments | **(6)** | **—** | **(6)** |
| Cash flow hedges that will subsequently be transferred to the balance sheet | **5** | **—** | **5** |
| **Other comprehensive income** | **1899** | **33** | **1932** |
|  |  |  | $ million |
|  |  |  | 2024 |
|  | Pre-tax | Tax | Net of tax |
| **Items that may be reclassified subsequently to profit or loss** |  |  |  |
| Currency translation differences (including reclassifications) | (288) | (76) | (364) |
| Cash flow hedges (including reclassifications) | (531) | 125 | (406) |
| Costs of hedging (including reclassifications) | (4) |  | (4) |
| Share of items relating to equity-accounted entities, net of tax | (12) |  | (12) |
| Other |  | (1) | (1) |
| **Items that will not be reclassified to profit or loss** |  |  |  |
| Remeasurements of the net pension and other post-employment benefit liability or asset<sup>a</sup> | (360) | 727 | 367 |
| Remeasurements of equity investments | (47) | 7 | (40) |
| Cash flow hedges that will subsequently be transferred to the balance sheet | (1) |  | (1) |
| **Other comprehensive income** | (1243) | 782 | (461) |
|  |  |  | $ million |
|  |  |  | 2023 |
|  | Pre-tax | Tax | Net of tax |
| **Items that may be reclassified subsequently to profit or loss** |  |  |  |
| Currency translation differences (including reclassifications) | 583 | 171 | 754 |
| Cash flow hedges (including reclassifications) | 637 | (149) | 488 |
| Costs of hedging (including reclassifications) | (78) | (32) | (110) |
| Share of items relating to equity-accounted entities, net of tax | (192) |  | (192) |
| **Items that will not be reclassified to profit or loss** |  |  |  |
| Remeasurements of the net pension and other post-employment benefit liability or asset | (2262) | 758 | (1504) |
| Remeasurements of equity investments | 51 | (13) | 38 |
| Cash flow hedges that will subsequently be transferred to the balance sheet | 15 |  | 15 |
| **Other comprehensive income** | (1246) | 735 | (511) |

---

a2024 includes a $658-million credit in respect of the reduction in the deferred tax liability on defined benefit pension plan surpluses following the reduction in the rate of the authorized surplus

payments tax charge in the UK from 35% to 25%.

---

| | |
|:---|:---|
| 236 | bp Annual Report and Form 20-F 2025 |

---

**33. Contingent liabilities and legal proceedings** 

**Contingent liabilities**

There were contingent liabilities at 31 December 2025 in respect of guarantees and indemnities entered into as part of the ordinary course of the

group's business. No material losses are likely to arise from such contingent liabilities. Further information on financial guarantees is included in

Note 29.

In the normal course of the group's business, bp group entities are subject to legal and regulatory proceedings arising out of current and past

operations, including matters related to commercial disputes, product liability, antitrust, commodities trading, premises-liability claims, consumer

protection, general health, safety, climate change and environmental claims and allegations of exposures of third parties to toxic substances, such

as lead pigment in paint, asbestos and other chemicals. The amounts claimed could be significant and could be material to the group's results of

operations, financial position or liquidity. While it is difficult to predict the ultimate outcome in some cases, bp expects that the impact of current

legal and regulatory proceedings on the group's results of operations, liquidity or financial position will not be material.

The group files tax returns in many jurisdictions across the world. Various tax authorities are currently examining these returns, which contain

matters that could be subject to differing interpretations of applicable tax laws and regulations. The resolution of tax positions through

negotiations with relevant tax authorities, or through litigation, can take several years to complete and the amounts could be significant and could,

in aggregate, be material to the group's results of operations, financial position or liquidity. While it is difficult to predict the ultimate outcome in

some cases, bp does not expect there to be any material impact upon the group's results of operations, financial position or liquidity.

The group is subject to numerous national and local health, safety and environmental laws and regulations concerning its products, operations and

other activities. These laws and regulations may require the group to take future action to remediate the effects on the environment of prior

disposal or release of chemicals or petroleum substances by the group or other parties. Such contingencies may exist for various sites including

refineries, chemical plants, oil fields, commodities extraction sites, service stations, terminals and waste disposal sites. In addition, the group may

have obligations relating to prior asset sales or closed facilities. The ultimate requirement for remediation and its costs are inherently difficult to

estimate. However, the estimated cost of environmental obligations has been provided in these accounts in accordance with the group's

accounting policies. While the amounts of future possible costs that are not provided for could be significant and material to the group's results of

operations in the period in which they are recognized, it is not possible to estimate the amounts involved. bp does not expect these costs to have a

material impact on the group's results of operations, financial position or liquidity.

If production and manufacturing facilities and pipelines are sold to third parties and the subsequent owner is unable to meet their

decommissioning obligations it is possible that, in certain circumstances, bp could be partially or wholly responsible for decommissioning. The

group estimates that for production facilities, approximately $17 billion (2024 $16 billion) of associated decommissioning obligations were

previously transferred to third parties. While the amounts associated with decommissioning provisions reverting to the group could be material, bp

is not currently aware of any such material cases that have a greater than remote chance of reverting to the group. Furthermore, as described in

Provisions and contingencies within Note 1, decommissioning provisions associated with customers & products facilities are not generally

recognized as the potential obligations cannot be measured given their indeterminate settlement dates.

By their nature, it is not practicable to estimate the potential financial impact or possible timing of the above contingencies as there are significant

uncertainties that are dependent on various factors that are not within the group's control.

**Contingent liabilities related to the Gulf of America oil spill**

For information on legal proceedings relating to the Deepwater Horizon oil spill, see Legal proceedings below. Any outstanding Deepwater Horizon

related claims are not expected to have a material impact on the group's financial performance.

**Legal proceedings**

Proceedings relating to the Deepwater Horizon oil spill

BP Exploration & Production Inc. (BPXP) was lease operator of Mississippi Canyon, Block 252 in the Gulf of America, where the semi-submersible rig

Deepwater Horizon was deployed at the time of the 20 April 2010 explosion and fire and resulting oil spill (the Incident). Lawsuits and claims arising

from the Incident were brought principally in US federal and state courts. The remaining proceedings arising from the Incident broadly seek

penalties, costs, damages and compensation for alleged environmental, personal injury, health and economic harm as a result of the Incident. bp

believes that impact of the remaining proceedings on the group's financial position or liquidity will not be material and in future reports will not

report on legal proceedings relating to the Incident absent any material developments.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 237 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**33. Contingent liabilities and legal proceedings – continued**

**Other legal proceedings**

Climate change

BP p.l.c., BP America Inc. and BP Products North America Inc. are co-defendants with other oil and gas companies in approximately 32 lawsuits

brought in various state and federal courts on behalf of various governmental and private parties. The lawsuits generally assert claims under a

variety of legal theories seeking to hold the defendant companies responsible for impacts allegedly caused by and/or relating to climate change.

Underlying many of the legal theories are allegations regarding deceptive communication and disinformation to the public. The lawsuits seek

remedies including payment of money and other forms of equitable relief. If such suits were successful, the cost of the remedies sought in the

various cases could be substantial. Defendants spent several years seeking to have the cases filed in state court removed to federal courts,

however Defendants' attempts were ultimately unsuccessful. Accordingly, nearly all the cases are proceeding in various state courts. As a group,

the lawsuits generally remain at relatively early stages in the litigation process. While it is not possible to predict the outcome of these legal actions,

bp believes that it has valid defences, and it intends to defend such actions vigorously.

Louisiana Coastal restoration

Six coastal parishes and the State of Louisiana have filed over 40 separate lawsuits in state courts in Louisiana against various oil and gas

companies seeking damages for coastal erosion. bp entities were named defendants in 17 of these cases. The lawsuits allege that the defendants'

historical operations in oil and gas fields within the Louisiana onshore coastal zone failed to comply with state permits and/or were conducted

without the required coastal use permits. The scope and scale of plaintiffs' damages demands are significant and unprecedented, including

substantial remediation costs, natural resource (ecological impact) damages and the claimed costs for restoring coastal wetlands allegedly

impacted by oil and gas field operations.

Defendants removed all of these lawsuits to federal court and the removals were contested by plaintiffs, eventually resulting in a decision from the

US Fifth Circuit Court of Appeals rejecting defendants' "federal officer" jurisdiction removal grounds in one of two lead cases – Plaquemines Parish

v. Riverwood, et al. At the time, the US Supreme Court declined to hear defendants' petition challenging the ruling. In 2024, the US Fifth Circuit

issued a further ruling rejecting "federal officer" jurisdiction in a subset of the removed cases contested on a related removal theory. Co-defendant

Chevron filed a renewed writ of certiorari petition with the US Supreme Court challenging the US Fifth Circuit's remand decision. On 16 June 2025,

the US Supreme Court granted Chevron's petition in Chevron USA Inc. v. Plaquemines Parish. Oral argument was held on January 12, 2026 and a

decision in the appeal is expected during the Court's current term which ends in June.

Following remand of the other lead removal case, Cameron Parish v. Auster, et. al., in which bp was the principal defendant, bp entered into a

settlement agreement and release with the plaintiffs in late 2023 in respect of all state and local governmental claims arising within Cameron

Parish. The terms of the settlement agreement and release are confidential and have not had and are not expected to have in the future, a

significant effect on the company's financial position or profitability.

Atlantic Richfield Company, a bp affiliate, was a named defendant along with Chevron in Plaquemines Parish v. Rozel, et al, another costal

restoration damages case set for trial in March 2025. A state trial court initially ruled in favour of Atlantic Richfield's motion for summary judgment

and dismissed it from the case, but following a motion by plaintiffs for reconsideration, the court reversed its summary judgment ruling and

reinstated Atlantic Richfield as a defendant. The plaintiffs' claims against Atlantic Richfield were severed from the March 2025 trial, and the case

proceeded to trial against Chevron alone. In April 2025 , following a three-week trial, the jury returned a verdict against Chevron awarding plaintiffs

$745 million. The court has yet to establish a new trial date for the plaintiffs' now separate claims against Atlantic Richfield. All other post-trial

activity in the case has been paused pending a decision from the US Supreme Court on Chevron's petition.

No bp entity is a named defendant in any of the other active Louisiana Coastal restoration docket cases with a trial date, all of which remain in the

early stages of litigation. In addition, four private landowners have filed separate claims in the state courts in Jefferson and Plaquemines Parishes

of Louisiana for restoration damages related to alleged impacts to their marshlands associated with historic oil field operations. bp entities are

defendants in two of these private landowner cases, having been previously dismissed from a third.

While it is not possible to predict the outcomes of these novel legal actions, bp believes that it has valid defences, and it intends to defend such

actions vigorously.

---

| | |
|:---|:---|
| 238 | bp Annual Report and Form 20-F 2025 |

---

**34. Remuneration of senior management and non-executive directors** 

**Remuneration of directors**

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| Total for all directors |  |  |  |
| Emoluments | **11** | 8 | 8 |
| Amounts received under incentive schemes<sup>a</sup> | **3** | 5 | 6 |
| **Total** | **14** | 13 | 14 |

---

<sup>a</sup>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.

**Remuneration of directors and senior management**

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| Total for all senior management and non-executive directors |  |  |  |
| Short-term employee benefits | **34** | 22 | 31 |
| Pensions and other post-employment benefits | **—** |  |  |
| Share-based payments<sup>a</sup> | **28** | 26 | 12 |
| Termination benefits | **—** | 3 |  |
| **Total** | **62** | 51 | 43 |

---

<sup>a</sup>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.

Short-term employee benefits

These amounts comprise fees and benefits paid to the non-executive chair and non-executive directors, as well as salary, benefits and cash

bonuses for senior management. Deferred annual bonus awards, to be settled in shares, are included in share-based payments.

Pensions and other post-employment benefits

The amounts represent the estimated cost to the group of providing pensions and other post-employment benefits to senior management in

respect of the current year of service measured in accordance with IAS 19 'Employee Benefits'.

Share-based payments

This is the cost to the group of senior management's participation in share-based payment plans, as measured by the fair value of options and

shares granted, accounted for in accordance with IFRS 2 'Share-based Payments'.

Termination benefits

Termination benefits include compensation to senior management for loss of office.

Related party transactions

Transactions between the group and its significant joint ventures and associates are summarized in Financial statements – Note 16 and Note 17. In

the ordinary course of its business, the group enters into transactions with various organizations with which some of its directors or executive

officers are associated. Except as described in this report, the group did not have any material transactions or transactions of an unusual nature

with, and did not make loans to, related parties in the period commencing 1 January 2025 to 13 February 2026.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 239 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**35. Employee costs and numbers** 

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
| Employee costs | **2025** | 2024 | 2023 |
| Wages and salaries<sup>a</sup> | **9295** | 8601 | 7835 |
| Social security costs | **1166** | 1032 | 943 |
| Share-based payments<sup>b</sup> | **847** | 1088 | 1131 |
| Pension and other post-employment benefit costs | **448** | 519 | 370 |
|  | **11756** | 11240 | 10279 |

---

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  | **2025** |  |  | 2024 |  |  | 2023 |
| Average number of employees<sup>c</sup> | **US** | **Non-US** | **Total** | US | Non-US | Total | US | Non-US | Total |
| gas & low carbon energy | **1000** | **5200** | **6200** | 900 | 4400 | 5300 | 900 | 3700 | 4600 |
| oil production & operations | **3300** | **6000** | **9300** | 3300 | 5700 | 9000 | 3100 | 5500 | 8600 |
| customers & products<sup>d e</sup> | **27100** | **43700** | **70800** | 27500 | 38000 | 65500 | 19500 | 36300 | 55800 |
| other businesses and corporate | **1200** | **10700** | **11900** | 1400 | 9800 | 11200 | 1400 | 9000 | 10400 |
|  | **32600** | **65600** | **98200** | 33100 | 57900 | 91000 | 24900 | 54500 | 79400 |

---

aIncludes termination costs of $467 million (2024 $336 million and 2023 $96 million).

bThe group provides certain employees with shares and share options as part of their remuneration packages. The majority of these share-based payment arrangements are equity-settled.

cReported to the nearest 100.

dIncludes 38,900 (2024 40,700 and 2023 33,800) service station staff.

eIncludes 9,100 (2024 1,700 and 2023 0) agricultural, operational and seasonal workers in Brazil.

**36. Auditor's remuneration** 

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
| Fees | **2025** | 2024 | 2023 |
| The audit of the company annual accounts<sup>a</sup> | **42** | 40 | 38 |
| The audit of accounts of subsidiaries of the company | **17** | 17 | 15 |
| Total audit | **59** | 57 | 53 |
| Audit-related assurance services<sup>b</sup> | **5** | 4 | 4 |
| Total audit and audit-related assurance services | **64** | 61 | 57 |
| Non-audit and other assurance services | **9** | 4 | 3 |
| Services relating to bp pension plans | **1** | 1 | 1 |
|  | **74** | 66 | 61 |

---

aFees in respect of the audit of the accounts of BP p.l.c. including the group's consolidated financial statements.

bIncludes interim reviews and audit of internal control over financial reporting and non-statutory audit services.

2025 includes $0.5 million of additional fees for 2024. 2024 includes $1.3 million of additional fees for 2023. 2023 includes $0.2 million of additional

fees for 2022. Auditor's remuneration is included in the income statement within distribution and administration expenses.

Tax services (in relation to income tax, indirect tax compliance, employee tax services and tax advisory services) were $nil in all periods presented.

The audit committee has established pre-approval policies and procedures for the engagement of Deloitte to render audit and certain assurance

and other services. The audit fees payable to Deloitte were considered as part of the audit tender process in 2016 and challenged by the audit

committee through comparison with the audit pricing proposals of the other bidding firms. Changes in audit fees subsequent to the audit tender,

including matters relevant to the 2025 audit, have been reviewed and challenged by the Audit Committee, before being approved. Deloitte

performed further assurance services that were not prohibited by regulatory or other professional requirements and were pre-approved by the

Committee. Deloitte is engaged for these services when its expertise and experience of bp are important. Most of this work is of an audit-related or

assurance nature. During 2025, no audit-related fees, tax fees or other non-audit fees were approved by the audit committee pursuant to the de

minimis exception to the pre-approval requirement provided by paragraph (c)(7)(i) (C) of Rule 2-01 of Regulation S-X.

Under SEC regulations, the remuneration of the auditor of $74 million (2024 $66 million and 2023 $61 million) is required to be presented as follows:

audit $59 million (2024 $57 million and 2023 $53 million); other audit-related $5 million (2024 $4 million and 2023 $4 million); tax $nil (2024 $nil and

2023 $nil); and all other fees $10 million (2024 $5 million and 2023 $4 million).

---

| | |
|:---|:---|
| 240 | bp Annual Report and Form 20-F 2025 |

---

**37. Subsidiaries, joint arrangements and associates**<sup>a</sup>

The more important subsidiaries, joint arrangements and associates of the group at 31 December 2025 and the group percentage of ordinary share

capital (to nearest whole number) are set out below. The group's share of the assets and liabilities of the more important unincorporated joint

arrangements are held by subsidiaries listed in the table below. Those subsidiaries held directly by the parent company are marked with an asterisk

(\*), the percentage owned being that of the group unless otherwise indicated. A complete list of undertakings of the group is included in Note 13 in

the parent company financial statements of BP p.l.c. which are filed with the Registrar of Companies in the UK, along with the group's annual report.

---

| | | | |
|:---|:---|:---|:---|
| **Subsidiaries** | **%** | **Country of**<br>**incorporation**<br>| **Principal activities** |
| International |  |  |  |
| BP Corporate Holdings Limited | 100 | England & Wales | Investment holding |
| BP Exploration Operating Company Limited | 100 | England & Wales | Exploration and production |
| \*BP Gamma Holdings Limited | 100 | England & Wales | Investment holding |
| \*BP Global Investments Limited | 100 | England & Wales | Investment holding |
| \*BP International Limited | 100 | England & Wales | Integrated oil operations  |
| BP Oil International Limited | 100 | England & Wales | Integrated oil operations |
| \*Castrol Group Holdings Limited | 100 | Scotland | Investment holding |
| Azerbaijan |  |  |  |
| BP Exploration (Caspian Sea) Limited | 100 | England & Wales | Exploration and production |
| BP Exploration (Azerbaijan) Limited | 100 | England & Wales | Exploration and production |
| Germany |  |  |  |
| BP Europa SE | 100 | Germany | Refining and marketing |
| Trinidad and Tobago |  |  |  |
| BP Trinidad and Tobago LLC | 70 | US | Exploration and production |
| UK |  |  |  |
| BP Capital Markets p.l.c. | 100 | England & Wales | Finance |
| Lightsource BP Renewable Energy Investments Limited | 100 | England & Wales | Onshore renewables |
| US |  |  |  |
| \*BP Holdings North America Limited | 100 | England & Wales | Investment holding |
| Atlantic Richfield Company | 100 | US | Exploration and production, refining and <br>marketing |
| BP America Inc. | 100 | US | Exploration and production, refining and <br>marketing |
| BP America Production Company | 100 | US | Exploration and production, refining and <br>marketing |
| BP Company North America Inc. | 100 | US | Exploration and production, refining and <br>marketing |
| BP Corporation North America Inc. | 100 | US | Exploration and production, refining and <br>marketing |
| BP Products North America Inc. | 100 | US | Exploration and production, refining and <br>marketing |
| The Standard Oil Company | 100 | US | Exploration and production, refining and <br>marketing |
| Archaea Energy Inc. | 100 | US | Bioenergy |
| BP Capital Markets America Inc. | 100 | US | Finance |
| **Joint arrangements** | **%** | **Country of**<br>**incorporation**<br>| **Principal activities** |
| Angola |  |  |  |
| Azule Energy Holdings Limited | 50 | England & Wales | Exploration and production |

---

aThere were no important associates in the group at 31 December 2025.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 241 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **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<sup>a</sup>), 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 <u>[340](#i0dd2ee81aac04f8c9c97c86197f0c6df_490)</u><u>-</u><u>[349](#i4306614df5024683a1d487f8c0e986db_261607)</u>.

aSee Note 1 - Investment in Rosneft.

---

| | |
|:---|:---|
| 242 | bp Annual Report and Form 20-F 2025 |

---

**Oil and natural gas exploration and production activities**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  |  | **$ million** |
|  |  |  |  |  |  |  |  |  | **2025** |
|  | **Europe** | **Europe** | **North** <br>**America** | **North** <br>**America** | **South** <br>**America**<br>| **Africa**<br>**Asia** |  | **Australasia** | **Total** |
|  | **UK** | **Rest of**<br>**Europe**<br>| **US** | **Rest of**<br>**North**<br>**America**<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **Capitalized costs at 31 December**<sup>a b</sup> | **Capitalized costs at 31 December**<sup>a b</sup> |  |  |  |  |  |  |  |  |
| Gross capitalized costs |  |  |  |  |  |  |  |  |  |
| Proved properties | **28834** | **—** | **79193** | **10** | **15476** | **19635** | **44989** | **6793** | **194930** |
| Unproved properties | **418** | **—** | **632** | **1981** | **1188** | **968** | **1633** | **796** | **7616** |
|  | **29252** | **—** | **79825** | **1991** | **16664** | **20603** | **46622** | **7589** | **202546** |
| Accumulated depreciation | **24342** | **—** | **48293** | **1604** | **13017** | **19949** | **30750** | **5945** | **143900** |
| **Net capitalized costs** | **4910** | **—** | **31532** | **387** | **3647** | **654** | **15872** | **1644** | **58646** |
| **Costs incurred for the year ended 31 December**<sup>a b</sup> | **Costs incurred for the year ended 31 December**<sup>a b</sup> | **Costs incurred for the year ended 31 December**<sup>a b</sup> |  |  |  |  |  |  |  |
| Acquisition of properties |  |  |  |  |  |  |  |  |  |
| Proved | **—** | **—** | **957** | **—** | **—** | **—** | **5** | **—** | **962** |
| Unproved | **—** | **—** | **13** | **—** | **1** | **—** | **4** | **—** | **18** |
|  | **—** | **—** | **970** | **—** | **1** | **—** | **9** | **—** | **980** |
| Exploration and appraisal costs<sup>c</sup> | **46** | **—** | **519** | **38** | **473** | **249** | **41** | **43** | **1409** |
| Development | **581** | **—** | **4461** | **—** | **686** | **226** | **2180** | **253** | **8387** |
| **Total costs** | **627** | **—** | **5950** | **38** | **1160** | **475** | **2230** | **296** | **10776** |
| **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> |  |  |  |  |  |  |  |
| Sales and other operating revenues<sup>d</sup> |  |  |  |  |  |  |  |  |  |
| Third parties | **107** | **—** | **1136** | **—** | **942** | **656** | **4282** | **1409** | **8532** |
| Sales between businesses | **2705** | **—** | **13187** | **—** | **790** | **139** | **6558** | **540** | **23919** |
|  | **2812** | **—** | **14323** | **—** | **1732** | **795** | **10840** | **1949** | **32451** |
| Exploration expenditure | **36** | **—** | **321** | **(6)** | **154** | **20** | **32** | **13** | **570** |
| Production costs | **547** | **—** | **2552** | **1** | **311** | **353** | **565** | **99** | **4428** |
| Production taxes | **(62)** | **—** | **175** | **—** | **318** | **—** | **1241** | **26** | **1698** |
| Other costs (income)<sup>e</sup> | **(95)** | **9** | **2571** | **23** | **28** | **(56)** | **39** | **90** | **2609** |
| Depreciation, depletion and amortization | **1454** | **—** | **4966** | **3** | **1178** | **530** | **3224** | **436** | **11791** |
| Net impairments and (gains) losses on sale of <br>businesses and fixed assets<br>| **249** | **4** | **(74)** | **—** | **(19)** | **121** | **11** | **(2)** | **290** |
|  | **2129** | **13** | **10511** | **21** | **1970** | **968** | **5112** | **662** | **21386** |
| Profit (loss) before taxation<sup>f</sup> | **683** | **(13)** | **3812** | **(21)** | **(238)** | **(173)** | **5728** | **1287** | **11065** |
| Allocable taxes | **703** | **—** | **882** | **(11)** | **18** | **678** | **4228** | **460** | **6958** |
| **Results of operations** | **(20)** | **(13)** | **2930** | **(10)** | **(256)** | **(851)** | **1500** | **827** | **4107** |

---

aThese tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes bp's share of oil and natural gas exploration and production

activities of joint operations. They do not include any costs relating to the Gulf of America oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG

liquefaction and transportation operations are excluded. In addition, bp's midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and Europe are

excluded. The most significant midstream pipeline interests include the South Caucasus Pipeline, the Baku-Tbilisi-Ceyhan pipeline, the Trans Adriatic Pipeline and the Trans Anatolian Pipeline.

Major LNG activities are located in Trinidad, Indonesia and Australia.

bCosts of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.

cIncludes exploration and appraisal drilling expenditures and pre development studies, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are

charged to income as incurred.

dPresented net of transportation costs, purchases and sales taxes.

eIncludes property taxes and other government take. The UK region includes a $275-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-

insurance programme.

fExcludes the unwinding of the discount on provisions and payables amounting to $480 million which is included in finance costs in the group income statement.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 243 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**Oil and natural gas exploration and production activities – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  |  | $ million |
|  |  |  |  |  |  |  |  |  | **2025** |
|  | **Europe** | **Europe** | **North** <br>**America** | **North** <br>**America** | **South** <br>**America**<br>| **Africa**<br>**Asia** |  | **Australasia** | **Total** |
|  | **UK** | **Rest of**<br>**Europe**<br>| **US** | **Rest of**<br>**North**<br>**America**<br>|  |  |  |  |  |
| **Equity-accounted entities (bp share)** | **Equity-accounted entities (bp share)** |  |  |  |  |  |  |  |  |
| **Capitalized costs at 31 December**<sup>a b</sup> | **Capitalized costs at 31 December**<sup>a b</sup> |  |  |  |  |  |  |  |  |
| Gross capitalized costs |  |  |  |  |  |  |  |  |  |
| Proved properties | **—** | **6480** | **—** | **—** | **13188** | **11832** | **11654** | **—** | **43154** |
| Unproved properties | **—** | **767** | **—** | **—** | **97** | **533** | **—** | **—** | **1397** |
|  | **—** | **7247** | **—** | **—** | **13285** | **12365** | **11654** | **—** | **44551** |
| Accumulated depreciation | **—** | **3805** | **—** | **—** | **7393** | **4251** | **3477** | **—** | **18926** |
| **Net capitalized costs** | **—** | **3442** | **—** | **—** | **5892** | **8114** | **8177** | **—** | **25625** |
| **Costs incurred for the year ended 31 December**<sup>a c d</sup> | **Costs incurred for the year ended 31 December**<sup>a c d</sup> | **Costs incurred for the year ended 31 December**<sup>a c d</sup> | **Costs incurred for the year ended 31 December**<sup>a c d</sup> |  |  |  |  |  |  |
| Acquisition of properties<sup>b</sup> |  |  |  |  |  |  |  |  |  |
| Proved | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** |
| Unproved | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** |
|  | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** |
| Exploration and appraisal costs<sup>c</sup> | **—** | **55** | **—** | **—** | **3** | **153** | **—** | **—** | **211** |
| Development | **—** | **1193** | **—** | **—** | **571** | **2379** | **806** | **—** | **4949** |
| **Total costs** | **—** | **1248** | **—** | **—** | **574** | **2532** | **806** | **—** | **5160** |
| **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> |  |  |  |  |  |  |
| Sales and other operating revenues<sup>e</sup> |  |  |  |  |  |  |  |  |  |
| Third parties | **—** | **1698** | **—** | **—** | **853** | **2700** | **1777** | **—** | **7028** |
| Sales between businesses | **—** | **—** | **—** | **—** | **955** | **—** | **—** | **—** | **955** |
|  | **—** | **1698** | **—** | **—** | **1808** | **2700** | **1777** | **—** | **7983** |
| Exploration expenditure | **—** | **55** | **—** | **—** | **—** | **18** | **—** | **—** | **73** |
| Production costs | **—** | **186** | **—** | **—** | **483** | **651** | **647** | **—** | **1967** |
| Production taxes | **—** | **—** | **—** | **—** | **267** | **27** | **—** | **—** | **294** |
| Other costs (income) | **—** | **2** | **—** | **—** | **116** | **(124)** | **24** | **—** | **18** |
| Depreciation, depletion and amortization | **—** | **481** | **—** | **—** | **451** | **1484** | **816** | **—** | **3232** |
| Net impairments and losses on sale of businesses and <br>fixed assets<br>| **—** | **321** | **—** | **—** | **—** | **129** | **—** | **—** | **450** |
|  | **—** | **1045** | **—** | **—** | **1317** | **2185** | **1487** | **—** | **6034** |
| Profit (loss) before taxation | **—** | **653** | **—** | **—** | **491** | **515** | **290** | **—** | **1949** |
| Allocable taxes | **—** | **651** | **—** | **—** | **76** | **343** | **121** | **—** | **1191** |
| **Results of operations** | **—** | **2** | **—** | **—** | **415** | **172** | **169** | **—** | **758** |

---

aThese tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude

oil and natural gas pipelines, LNG liquefaction, transportation operations as well as downstream and other activities are excluded.

bCosts of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.

cIncludes exploration and appraisal drilling expenditures and pre development studies, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are

charged to income as incurred.

dThe amounts shown reflect bp's share of equity-accounted entities' costs incurred, and not the costs incurred by bp in acquiring an interest in equity-accounted entities.

ePresented net of sales tax.

---

| | |
|:---|:---|
| 244 | bp Annual Report and Form 20-F 2025 |

---

**Oil and natural gas exploration and production activities – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  |  | $ million |
|  |  |  |  |  |  |  |  |  | 2024 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **Capitalized costs at 31 December**<sup>a b</sup> | **Capitalized costs at 31 December**<sup>a b</sup> |  |  |  |  |  |  |  |  |
| Gross capitalized costs |  |  |  |  |  |  |  |  |  |
| Proved properties | 29781 |  | 72248 | 8 | 14427 | 18756 | 42709 | 6504 | 184433 |
| Unproved properties | 411 |  | 3012 | 1936 | 2760 | 2471 | 1701 | 762 | 13053 |
|  | 30192 |  | 75260 | 1944 | 17187 | 21227 | 44410 | 7266 | 197486 |
| Accumulated depreciation | 24269 |  | 44067 | 1602 | 13450 | 20373 | 27528 | 5506 | 136795 |
| **Net capitalized costs** | 5923 |  | 31193 | 342 | 3737 | 854 | 16882 | 1760 | 60691 |
| **Costs incurred for the year ended 31 December**<sup>a b</sup> | **Costs incurred for the year ended 31 December**<sup>a b</sup> | **Costs incurred for the year ended 31 December**<sup>a b</sup> | **Costs incurred for the year ended 31 December**<sup>a b</sup> | **Costs incurred for the year ended 31 December**<sup>a b</sup> |  |  |  |  |  |
| Acquisition of properties |  |  |  |  |  |  |  |  |  |
| Proved |  |  | 52 |  |  |  |  |  | 52 |
| Unproved |  |  | 21 |  | 2 |  |  |  | 23 |
|  |  |  | 73 |  | 2 |  |  |  | 75 |
| Exploration and appraisal costs<sup>c</sup> | 57 |  | 655 | 102 | 294 | 508 | 82 | 59 | 1757 |
| Development | 629 |  | 3829 |  | 661 | 1334 | 1363 | 137 | 7953 |
| **Total costs** | 686 |  | 4557 | 102 | 957 | 1842 | 1445 | 196 | 9785 |
| **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> |  |  |  |  |  |
| Sales and other operating revenues<sup>d</sup> |  |  |  |  |  |  |  |  |  |
| Third parties | 182 |  | 1859 |  | 1090 | 2094 | 4515 | 1888 | 11628 |
| Sales between businesses | 2762 |  | 13035 |  | 163 |  | 7410 | 362 | 23732 |
|  | 2944 |  | 14894 |  | 1253 | 2094 | 11925 | 2250 | 35360 |
| Exploration expenditure | 1 |  | 463 | 97 | 137 | 188 | 55 | 33 | 974 |
| Production costs | 539 |  | 2645 | 1 | 399 | 230 | 617 | 106 | 4537 |
| Production taxes | (4) |  | 149 |  | 248 |  | 1366 | 40 | 1799 |
| Other costs (income)<sup>e</sup> | (221) | (8) | 2455 | 23 | 47 | 49 | (59) | 116 | 2402 |
| Depreciation, depletion and amortization | 1234 |  | 4394 | 3 | 1206 | 543 | 3116 | 477 | 10973 |
| Net impairments and (gains) losses on sale of <br>businesses and fixed assets<br>| 1058 | 14 | (471) | (19) | (259) | 2312 | (1) | (1) | 2633 |
|  | 2607 | 6 | 9635 | 105 | 1778 | 3322 | 5094 | 771 | 23318 |
| Profit (loss) before taxation<sup>f</sup> | 337 | (6) | 5259 | (105) | (525) | (1228) | 6831 | 1479 | 12042 |
| Allocable taxes | 195 | (1) | 1194 | (14) | (203) | 291 | 5003 | 557 | 7022 |
| **Results of operations** | 142 | (5) | 4065 | (91) | (322) | (1519) | 1828 | 922 | 5020 |

---

aThese tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes bp's share of oil and natural gas exploration and production

activities of joint operations. They do not include any costs relating to the Gulf of America oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG

liquefaction and transportation operations are excluded. In addition, bp's midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and Europe are

excluded. The most significant midstream pipeline interests include the South Caucasus Pipeline, the Baku-Tbilisi-Ceyhan pipeline, the Trans Adriatic Pipeline and the Trans Anatolian Pipeline.

Major LNG activities are located in Trinidad, Indonesia and Australia.

bCosts of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.

cIncludes exploration and appraisal drilling expenditures and pre development studies, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are

charged to income as incurred.

dPresented net of transportation costs, purchases and sales taxes.

eIncludes property taxes and other government take. The UK region includes a $313-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-

insurance programme.

fExcludes the unwinding of the discount on provisions and payables amounting to $460 million which is included in finance costs in the group income statement.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 245 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**Oil and natural gas exploration and production activities – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | | | | | | | | | $ million |
|  |  |  |  |  |  |  |  |  | 2024 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| **Equity-accounted entities (bp share)** | **Equity-accounted entities (bp share)** |  |  |  |  |  |  |  |  |
| **Capitalized costs at 31 December**<sup>a b</sup> | **Capitalized costs at 31 December**<sup>a b</sup> |  |  |  |  |  |  |  |  |
| Gross capitalized costs |  |  |  |  |  |  |  |  |  |
| Proved properties |  | 5211 |  |  | 12185 | 10181 | 10848 |  | 38425 |
| Unproved properties |  | 705 |  |  | 130 | 344 |  |  | 1179 |
|  |  | 5916 |  |  | 12315 | 10525 | 10848 |  | 39604 |
| Accumulated depreciation |  | 2968 |  |  | 7284 | 3209 | 2661 |  | 16122 |
| **Net capitalized costs** |  | 2948 |  |  | 5031 | 7316 | 8187 |  | 23482 |
| **Costs incurred for the year ended 31 December**<sup>a c d</sup> | **Costs incurred for the year ended 31 December**<sup>a c d</sup> | **Costs incurred for the year ended 31 December**<sup>a c d</sup> | **Costs incurred for the year ended 31 December**<sup>a c d</sup> | **Costs incurred for the year ended 31 December**<sup>a c d</sup> | **Costs incurred for the year ended 31 December**<sup>a c d</sup> |  |  |  |  |
| Acquisition of properties<sup>b</sup> |  |  |  |  |  |  |  |  |  |
| Proved |  |  |  |  |  |  |  |  |  |
| Unproved |  |  |  |  |  | 26 |  |  | 26 |
|  |  |  |  |  |  | 26 |  |  | 26 |
| Exploration and appraisal costs<sup>c</sup> |  | 58 |  |  | 5 | 54 |  |  | 117 |
| Development |  | 761 |  |  | 821 | 1105 | 901 |  | 3588 |
| **Total costs** |  | 819 |  |  | 826 | 1185 | 901 |  | 3731 |
| **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> |  |  |  |  |
| Sales and other operating revenues<sup>e</sup> |  |  |  |  |  |  |  |  |  |
| Third parties<sup>f</sup> |  | 1943 |  |  | 840 | 2692 | 1854 |  | 7329 |
| Sales between businesses<sup>f</sup> |  |  |  |  | 1127 |  |  |  | 1127 |
|  |  | 1943 |  |  | 1967 | 2692 | 1854 |  | 8456 |
| Exploration expenditure |  | 51 |  |  |  | 8 |  |  | 59 |
| Production costs |  | 145 |  |  | 812 | 560 | 574 |  | 2091 |
| Production taxes |  |  |  |  | 324 | 37 |  |  | 361 |
| Other costs (income)<sup>g</sup> |  | 26 |  |  | 134 | 142 | 25 |  | 327 |
| Depreciation, depletion and amortization |  | 453 |  |  | 477 | 1431 | 965 |  | 3326 |
| Net impairments and losses on sale of businesses and <br>fixed assets<br>|  | 65 |  |  | 849 |  |  |  | 914 |
|  |  | 740 |  |  | 2596 | 2178 | 1564 |  | 7078 |
| Profit (loss) before taxation |  | 1203 |  |  | (629) | 514 | 290 |  | 1378 |
| Allocable taxes<sup>g</sup> |  | 931 |  |  | (766) | 296 | 120 |  | 581 |
| **Results of operations** |  | 272 |  |  | 137 | 218 | 170 |  | 797 |

---

aThese tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude

oil and natural gas pipelines, LNG liquefaction, transportation operations as well as downstream and other activities are excluded.

bCosts of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.

cIncludes exploration and appraisal drilling expenditures and pre development studies, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are

charged to income as incurred.

dThe amounts shown reflect bp's share of equity-accounted entities' costs incurred, and not the costs incurred by bp in acquiring an interest in equity-accounted entities.

ePresented net of sales tax.

fSouth America third parties sales and sales between businesses split has been restated.

gAfrica other costs (income) have been restated and consequently the allocable taxes.

---

| | |
|:---|:---|
| 246 | bp Annual Report and Form 20-F 2025 |

---

**Oil and natural gas exploration and production activities – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | | | | | | | | | $ million |
|  |  |  |  |  |  |  |  |  | 2023 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **Capitalized costs at 31 December**<sup>a b</sup> | **Capitalized costs at 31 December**<sup>a b</sup> |  |  |  |  |  |  |  |  |
| Gross capitalized costs |  |  |  |  |  |  |  |  |  |
| Proved properties | 29127 |  | 70404 | 6 | 17475 | 20763 | 41351 | 6331 | 185457 |
| Unproved properties | 369 |  | 3057 | 1917 | 2565 | 2739 | 1691 | 737 | 13075 |
|  | 29496 |  | 73461 | 1923 | 20040 | 23502 | 43042 | 7068 | 198532 |
| Accumulated depreciation | 22018 |  | 42364 | 1592 | 15712 | 21132 | 24431 | 4998 | 132247 |
| **Net capitalized costs** | 7478 |  | 31097 | 331 | 4328 | 2370 | 18611 | 2070 | 66285 |
| **Costs incurred for the year ended 31 December**<sup>a b</sup> | **Costs incurred for the year ended 31 December**<sup>a b</sup> | **Costs incurred for the year ended 31 December**<sup>a b</sup> | **Costs incurred for the year ended 31 December**<sup>a b</sup> |  |  |  |  |  |  |
| Acquisition of properties |  |  |  |  |  |  |  |  |  |
| Proved |  |  | 13 |  |  |  |  |  | 13 |
| Unproved |  |  | 51 |  | 2 | 6 |  |  | 59 |
|  |  |  | 64 |  | 2 | 6 |  |  | 72 |
| Exploration and appraisal costs<sup>c</sup> | 123 |  | 356 | 123 | 114 | 270 | 145 | 100 | 1231 |
| Development | 484 |  | 4690 |  | 713 | 863 | 1424 | 32 | 8206 |
| **Total costs** | 607 |  | 5110 | 123 | 829 | 1139 | 1569 | 132 | 9509 |
| **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> |  |  |  |  |
| Sales and other operating revenues<sup>d</sup> |  |  |  |  |  |  |  |  |  |
| Third parties | 206 |  | 665 |  | 1348 | 3227 | 4801 | 1765 | 12012 |
| Sales between businesses | 3483 |  | 12705 |  | 20 | 22 | 7731 | 412 | 24373 |
|  | 3689 |  | 13370 |  | 1368 | 3249 | 12532 | 2177 | 36385 |
| Exploration expenditure | 46 |  | 348 | 93 | 54 | 413 | 25 | 18 | 997 |
| Production costs | 477 |  | 2382 | 2 | 360 | 232 | 588 | 111 | 4152 |
| Production taxes | 13 |  | 136 |  | 229 |  | 1357 | 44 | 1779 |
| Other costs (income)<sup>e</sup> | (171) |  | 2144 | 13 | 115 | 304 | (35) | 145 | 2515 |
| Depreciation, depletion and amortization | 1063 |  | 3532 |  | 1351 | 1546 | 2844 | 412 | 10748 |
| Net impairments and (gains) losses on sale of <br>businesses and fixed assets<br>| 819 | (18) | 701 | (100) | 671 | 1430 | (1) | (4) | 3498 |
|  | 2247 | (18) | 9243 | 8 | 2780 | 3925 | 4778 | 726 | 23689 |
| Profit (loss) before taxation<sup>f</sup> | 1442 | 18 | 4127 | (8) | (1412) | (676) | 7754 | 1451 | 12696 |
| Allocable taxes | 365 | 19 | 889 | (3) | (565) | 439 | 5317 | 451 | 6912 |
| **Results of operations** | 1077 | (1) | 3238 | (5) | (847) | (1115) | 2437 | 1000 | 5784 |

---

aThese tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes bp's share of oil and natural gas exploration and production

activities of joint operations. They do not include any costs relating to the Gulf of America oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG

liquefaction and transportation operations are excluded. In addition, bp's midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and Europe are

excluded. The most significant midstream pipeline interests include the South Caucasus Pipeline, the Baku-Tbilisi-Ceyhan pipeline, the Trans Adriatic Pipeline and the Trans Anatolian Pipeline.

Major LNG activities are located in Trinidad, Indonesia and Australia.

bCosts of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.

cIncludes exploration and appraisal drilling expenditures and pre development studies, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are

charged to income as incurred.

dPresented net of transportation costs, purchases and sales taxes.

eIncludes property taxes and other government take. The UK region includes a $287-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-

insurance programme.

fExcludes the unwinding of the discount on provisions and payables amounting to $390 million which is included in finance costs in the group income statement.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 247 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**Oil and natural gas exploration and production activities – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | | | | | | | | | $ million |
|  |  |  |  |  |  |  |  |  | 2023 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| **Equity-accounted entities (bp share)** | **Equity-accounted entities (bp share)** |  |  |  |  |  |  |  |  |
| **Capitalized costs at 31 December**<sup>a b</sup> | **Capitalized costs at 31 December**<sup>a b</sup> |  |  |  |  |  |  |  |  |
| Gross capitalized costs |  |  |  |  |  |  |  |  |  |
| Proved properties |  | 4432 |  |  | 12530 | 8590 | 9947 |  | 35499 |
| Unproved properties |  | 652 |  |  | 125 | 372 |  |  | 1149 |
|  |  | 5084 |  |  | 12655 | 8962 | 9947 |  | 36648 |
| Accumulated depreciation |  | 2420 |  |  | 6807 | 1812 | 1696 |  | 12735 |
| **Net capitalized costs** |  | 2664 |  |  | 5848 | 7150 | 8251 |  | 23913 |
| **Costs incurred for the year ended 31 December**<sup>a c d</sup> | **Costs incurred for the year ended 31 December**<sup>a c d</sup> | **Costs incurred for the year ended 31 December**<sup>a c d</sup> | **Costs incurred for the year ended 31 December**<sup>a c d</sup> | **Costs incurred for the year ended 31 December**<sup>a c d</sup> |  |  |  |  |  |
| Acquisition of properties<sup>b</sup> |  |  |  |  |  |  |  |  |  |
| Proved |  |  |  |  |  |  |  |  |  |
| Unproved |  |  |  |  |  |  |  |  |  |
| Exploration and appraisal costs<sup>c</sup> |  | 42 |  |  | 7 | 44 |  |  | 93 |
| Development |  | 584 |  |  | 687 | 844 | 942 |  | 3057 |
| **Total costs** |  | 626 |  |  | 694 | 888 | 942 |  | 3150 |
| **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> | **Results of operations for the year ended 31 December**<sup>a</sup> |  |  |  |  |  |
| Sales and other operating revenues<sup>e</sup> |  |  |  |  |  |  |  |  |  |
| Third parties<sup>f</sup> |  | 2159 |  |  | 963 | 2550 | 1716 |  | 7388 |
| Sales between businesses<sup>f</sup> |  |  |  |  | 1107 |  |  |  | 1107 |
|  |  | 2159 |  |  | 2070 | 2550 | 1716 |  | 8495 |
| Exploration expenditure |  | 41 |  |  |  | 44 |  |  | 85 |
| Production costs |  | 169 |  |  | 715 | 427 | 374 |  | 1685 |
| Production taxes |  |  |  |  | 332 | 52 |  |  | 384 |
| Other costs (income)<sup>g</sup> |  | 21 |  |  | 257 | 42 | 8 |  | 328 |
| Depreciation, depletion and amortization |  | 455 |  |  | 451 | 1344 | 1144 |  | 3394 |
| Net impairments and losses on sale of businesses and <br>fixed assets<br>|  | 141 |  |  |  | 15 |  |  | 156 |
|  |  | 827 |  |  | 1755 | 1924 | 1526 |  | 6032 |
| Profit (loss) before taxation |  | 1332 |  |  | 315 | 626 | 190 |  | 2463 |
| Allocable taxes<sup>g</sup> |  | 1124 |  |  | 127 | 280 | 117 |  | 1648 |
| **Results of operations** |  | 208 |  |  | 188 | 346 | 73 |  | 815 |

---

aThese tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude

oil and natural gas pipelines, LNG liquefaction, transportation operations as well as downstream and other activities are excluded.

bCosts of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.

cIncludes exploration and appraisal drilling expenditures and pre development studies, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are

charged to income as incurred.

dThe amounts shown reflect bp's share of equity-accounted entities' costs incurred, and not the costs incurred by bp in acquiring an interest in equity-accounted entities.

ePresented net of sales tax.

fSouth America third parties sales and sales between businesses split has been restated.

gAfrica other costs (income) have been restated and consequently the allocable taxes.

---

| | |
|:---|:---|
| 248 | bp Annual Report and Form 20-F 2025 |

---

**Movements in estimated net proved reserves**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | million barrels | million barrels |
| **Crude oil**<sup>a b</sup> |  |  |  |  |  |  |  | **2025** | **2025** |
|  | **Europe** | **Europe** | **North** <br>**America** | **North** <br>**America** | **South** <br>**America**<br>| **Africa**<br>**Asia** |  | **Australasia** | **Total** |
|  | **UK** | **Rest of**<br>**Europe**<br>| **US**  | **Rest of**<br>**North**<br>**America**<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | **104** | **—** | **653** | **—** | **1** | **1** | **716** | **9** | **1483** |
| Undeveloped | **63** | **—** | **472** | **—** | **4** | **—** | **305** | **1** | **846** |
|  | **167** | **—** | **1125** | **—** | **5** | **1** | **1021** | **10** | **2329** |
| **Changes attributable to** |  |  |  |  |  |  |  |  |  |
| Revisions of previous estimates | **(40)** | **—** | **39** | **—** | **2** | **3** | **75** | **1** | **80** |
| Improved recovery | **—** | **—** | **13** | **—** | **—** | **—** | **—** | **—** | **13** |
| Purchases of reserves-in-place | **—** | **—** | **40** | **—** | **—** | **—** | **—** | **—** | **40** |
| Discoveries and extensions | **—** | **—** | **1** | **—** | **—** | **1** | **3** | **—** | **5** |
| Production | **(29)** | **—** | **(146)** | **—** | **(2)** | **(3)** | **(110)** | **(3)** | **(292)** |
| Sales of reserves-in-place | **(1)** | **—** | **(31)** | **—** | **—** | **—** | **—** | **—** | **(33)** |
|  | **(70)** | **—** | **(84)** | **—** | **—** | **1** | **(32)** | **(2)** | **(186)** |
| **At 31 December**<sup>c</sup> |  |  |  |  |  |  |  |  |  |
| Developed | **56** | **—** | **599** | **—** | **1** | **2** | **691** | **6** | **1354** |
| Undeveloped | **41** | **—** | **443** | **—** | **4** | **—** | **298** | **3** | **788** |
|  | **97** | **—** | **1042** | **—** | **6** | **2** | **989** | **8** | **2143** |
| **Equity-accounted entities (bp share)**<sup>d</sup> | **Equity-accounted entities (bp share)**<sup>d</sup> | **Equity-accounted entities (bp share)**<sup>d</sup> |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | **—** | **76** | **—** | **10** | **271** | **94** | **107** | **—** | **558** |
| Undeveloped | **—** | **42** | **—** | **—** | **217** | **77** | **3** | **—** | **339** |
|  | **—** | **118** | **—** | **10** | **488** | **170** | **110** | **—** | **896** |
| **Changes attributable to** |  |  |  |  |  |  |  |  |  |
| Revisions of previous estimates | **—** | **14** | **—** | **—** | **(40)** | **21** | **35** | **—** | **30** |
| Improved recovery | **—** | **1** | **—** | **—** | **3** | **—** | **—** | **—** | **4** |
| Purchases of reserves-in-place | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** |
| Discoveries and extensions | **—** | **4** | **—** | **—** | **29** | **1** | **—** | **—** | **34** |
| Production | **—** | **(20)** | **—** | **(1)** | **(19)** | **(29)** | **(29)** | **—** | **(98)** |
| Sales of reserves-in-place | **—** | **(1)** | **—** | **—** | **—** | **—** | **—** | **—** | **(1)** |
|  | **—** | **(3)** | **—** | **(1)** | **(26)** | **(7)** | **6** | **—** | **(31)** |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | **—** | **70** | **—** | **9** | **278** | **97** | **113** | **—** | **566** |
| Undeveloped | **—** | **45** | **—** | **—** | **184** | **67** | **4** | **—** | **299** |
|  | **—** | **115** | **—** | **9** | **461** | **163** | **117** | **—** | **865** |
| **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | **104** | **76** | **653** | **10** | **271** | **95** | **823** | **9** | **2041** |
| Undeveloped | **63** | **42** | **472** | **—** | **221** | **77** | **308** | **1** | **1184** |
|  | **167** | **118** | **1125** | **10** | **493** | **171** | **1131** | **10** | **3225** |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | **56** | **70** | **599** | **9** | **279** | **98** | **804** | **6** | **1920** |
| Undeveloped | **41** | **45** | **443** | **—** | **188** | **67** | **302** | **3** | **1088** |
|  | **97** | **115** | **1042** | **9** | **467** | **165** | **1105** | **8** | **3008** |

---

aCrude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying

production and the option and ability to make lifting and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cIncludes 1.7 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

dVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 249 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**Movements in estimated net proved reserves – continued**

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  | million barrels | million barrels |
| **Natural gas liquids**<sup>a b</sup> |  |  |  |  |  |  | **2025** | **2025** |
|  | **Europe** | **Europe** | **North** <br>**America** | **North** <br>**America** | **South** <br>**America**<br>| **Africa**<br>**Asia** | **Australasia** | **Total** |
|  | **UK** | **Rest of**<br>**Europe**<br>| **US** | **Rest of**<br>**North**<br>**America**<br>|  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |
| Developed | **2** | **—** | **202** | **—** | **1** | **—** | **1** | **206** |
| Undeveloped | **—** | **—** | **246** | **—** | **—** | **—** | **—** | **246** |
|  | **3** | **—** | **447** | **—** | **1** | **—** | **1** | **452** |
| **Changes attributable to** |  |  |  |  |  |  |  |  |
| Revisions of previous estimates | **1** | **—** | **(1)** | **—** | **2** | **—** | **—** | **1** |
| Improved recovery | **—** | **—** | **1** | **—** | **—** | **—** | **—** | **1** |
| Purchases of reserves-in-place | **—** | **—** | **25** | **—** | **—** | **—** | **—** | **25** |
| Discoveries and extensions | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** |
| Production<sup>c</sup> | **(1)** | **—** | **(41)** | **—** | **(2)** | **—** | **—** | **(45)** |
| Sales of reserves-in-place | **(1)** | **—** | **(16)** | **—** | **—** | **—** | **—** | **(17)** |
|  | **(1)** | **—** | **(32)** | **—** | **(1)** | **—** | **—** | **(35)** |
| **At 31 December** |  |  |  |  |  |  |  |  |
| Developed | **1** | **—** | **204** | **—** | **—** | **—** | **1** | **206** |
| Undeveloped | **—** | **—** | **212** | **—** | **—** | **—** | **—** | **212** |
|  | **1** | **—** | **415** | **—** | **—** | **—** | **1** | **417** |
| **Equity-accounted entities (bp share)**<sup>d</sup> | **Equity-accounted entities (bp share)**<sup>d</sup> | **Equity-accounted entities (bp share)**<sup>d</sup> |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |
| Developed | **—** | **3** | **—** | **—** | **3** | **10** | **—** | **16** |
| Undeveloped | **—** | **5** | **—** | **—** | **—** | **—** | **—** | **6** |
|  | **—** | **8** | **—** | **—** | **4** | **10** | **—** | **22** |
| **Changes attributable to** |  |  |  |  |  |  |  |  |
| Revisions of previous estimates | **—** | **—** | **—** | **—** | **1** | **2** | **—** | **3** |
| Improved recovery | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** |
| Purchases of reserves-in-place | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** |
| Discoveries and extensions | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** |
| Production | **—** | **(1)** | **—** | **—** | **—** | **(2)** | **—** | **(3)** |
| Sales of reserves-in-place | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** |
|  | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** |
| **At 31 December** |  |  |  |  |  |  |  |  |
| Developed | **—** | **3** | **—** | **—** | **4** | **10** | **—** | **17** |
| Undeveloped | **—** | **5** | **—** | **—** | **—** | **—** | **—** | **5** |
|  | **—** | **8** | **—** | **—** | **4** | **10** | **—** | **22** |
| **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |
| Developed | **2** | **3** | **202** | **—** | **4** | **10** | **1** | **222** |
| Undeveloped | **—** | **5** | **246** | **—** | **—** | **—** | **—** | **252** |
|  | **3** | **8** | **447** | **—** | **4** | **10** | **1** | **474** |
| **At 31 December** |  |  |  |  |  |  |  |  |
| Developed | **1** | **3** | **204** | **—** | **4** | **10** | **1** | **222** |
| Undeveloped | **—** | **5** | **212** | **—** | **—** | **—** | **—** | **217** |
|  | **1** | **8** | **415** | **—** | **4** | **10** | **1** | **439** |

---

aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.

dVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

---

| | |
|:---|:---|
| 250 | bp Annual Report and Form 20-F 2025 |

---

**Movements in estimated net proved reserves – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | million barrels | million barrels |
| **Total liquids**<sup>a b</sup> |  |  |  |  |  |  |  |  | **2025** |
|  | **Europe** | **Europe** | **North** <br>**America** | **North** <br>**America** | **South** <br>**America**<br>| **Africa**<br>**Asia** |  | **Australasia** | **Total** |
|  | **UK** | **Rest of**<br>**Europe**<br>| **US** | **Rest of**<br>**North**<br>**America**<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | **106** | **—** | **855** | **—** | **1** | **1** | **716** | **10** | **1689** |
| Undeveloped | **63** | **—** | **718** | **—** | **4** | **—** | **305** | **1** | **1092** |
|  | **169** | **—** | **1573** | **—** | **6** | **1** | **1021** | **11** | **2781** |
| **Changes attributable to** |  |  |  |  |  |  |  |  |  |
| Revisions of previous estimates | **(40)** | **—** | **37** | **—** | **4** | **3** | **75** | **1** | **81** |
| Improved recovery | **—** | **—** | **14** | **—** | **—** | **—** | **—** | **—** | **14** |
| Purchases of reserves-in-place | **—** | **—** | **65** | **—** | **—** | **—** | **—** | **—** | **65** |
| Discoveries and extensions | **—** | **—** | **2** | **—** | **—** | **1** | **3** | **—** | **6** |
| Production<sup>c</sup> | **(30)** | **—** | **(186)** | **—** | **(4)** | **(3)** | **(110)** | **(3)** | **(337)** |
| Sales of reserves-in-place | **(2)** | **—** | **(48)** | **—** | **—** | **—** | **—** | **—** | **(49)** |
|  | **(72)** | **—** | **(116)** | **—** | **—** | **—** | **(32)** | **(2)** | **(221)** |
| **At 31 December**<sup>d</sup> |  |  |  |  |  |  |  |  |  |
| Developed | **57** | **—** | **802** | **—** | **1** | **2** | **691** | **7** | **1560** |
| Undeveloped | **41** | **—** | **655** | **—** | **4** | **—** | **298** | **3** | **1000** |
|  | **98** | **—** | **1457** | **—** | **5** | **2** | **989** | **9** | **2560** |
| **Equity-accounted entities (bp share)**<sup>e</sup> | **Equity-accounted entities (bp share)**<sup>e</sup> | **Equity-accounted entities (bp share)**<sup>e</sup> |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | **—** | **78** | **—** | **10** | **274** | **103** | **107** | **—** | **573** |
| Undeveloped | **—** | **47** | **—** | **—** | **217** | **77** | **3** | **—** | **344** |
|  | **—** | **125** | **—** | **10** | **491** | **180** | **110** | **—** | **918** |
| **Changes attributable to** |  |  |  |  |  |  |  |  |  |
| Revisions of previous estimates | **—** | **14** | **—** | **—** | **(39)** | **22** | **35** | **—** | **33** |
| Improved recovery | **—** | **1** | **—** | **—** | **3** | **—** | **—** | **—** | **4** |
| Purchases of reserves-in-place | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** |
| Discoveries and extensions | **—** | **4** | **—** | **—** | **29** | **1** | **—** | **—** | **34** |
| Production | **—** | **(21)** | **—** | **(1)** | **(19)** | **(31)** | **(29)** | **—** | **(101)** |
| Sales of reserves-in-place | **—** | **(1)** | **—** | **—** | **—** | **—** | **—** | **—** | **(1)** |
|  | **—** | **(3)** | **—** | **(1)** | **(26)** | **(7)** | **6** | **—** | **(31)** |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | **—** | **73** | **—** | **9** | **282** | **106** | **113** | **—** | **582** |
| Undeveloped | **—** | **50** | **—** | **—** | **184** | **67** | **4** | **—** | **304** |
|  | **—** | **123** | **—** | **9** | **465** | **173** | **117** | **—** | **887** |
| **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | **106** | **78** | **855** | **10** | **275** | **105** | **823** | **10** | **2263** |
| Undeveloped | **63** | **47** | **718** | **—** | **222** | **77** | **308** | **1** | **1436** |
|  | **169** | **125** | **1573** | **10** | **497** | **182** | **1131** | **11** | **3699** |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | **57** | **73** | **802** | **9** | **283** | **108** | **804** | **7** | **2143** |
| Undeveloped | **41** | **50** | **655** | **—** | **188** | **67** | **302** | **3** | **1304** |
|  | **98** | **123** | **1457** | **9** | **471** | **175** | **1105** | **9** | **3447** |

---

aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.

dAlso includes 1.7 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

eVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 251 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**Movements in estimated net proved reserves – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | billion cubic feet | billion cubic feet |
| **Natural gas**<sup>a b</sup> |  |  |  |  |  |  |  | **2025** | **2025** |
|  | **Europe** | **Europe** | **North** <br>**America** | **North** <br>**America** | **South** <br>**America**<br>| **Africa**<br>**Asia** |  | **Australasia** | **Total** |
|  | **UK** | **Rest of**<br>**Europe**<br>| **US** | **Rest of**<br>**North**<br>**America**<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | **162** | **—** | **2600** | **—** | **379** | **161** | **3026** | **1254** | **7582** |
| Undeveloped | **29** | **—** | **2412** | **—** | **350** | **—** | **1320** | **431** | **4542** |
|  | **190** | **—** | **5012** | **—** | **730** | **161** | **4346** | **1685** | **12124** |
| **Changes attributable to** |  |  |  |  |  |  |  |  |  |
| Revisions of previous estimates | **24** | **—** | **2419** | **—** | **257** | **74** | **172** | **51** | **2996** |
| Improved recovery | **—** | **—** | **8** | **—** | **—** | **—** | **—** | **—** | **8** |
| Purchases of reserves-in-place | **—** | **—** | **208** | **—** | **—** | **—** | **—** | **—** | **208** |
| Discoveries and extensions | **—** | **—** | **1** | **—** | **170** | **65** | **111** | **2** | **349** |
| Production<sup>c</sup> | **(84)** | **—** | **(664)** | **—** | **(385)** | **(177)** | **(602)** | **(293)** | **(2205)** |
| Sales of reserves-in-place | **(42)** | **—** | **(93)** | **—** | **—** | **—** | **—** | **—** | **(135)** |
|  | **(102)** | **—** | **1878** | **—** | **41** | **(38)** | **(318)** | **(240)** | **1220** |
| **At 31 December**<sup>d</sup> |  |  |  |  |  |  |  |  |  |
| Developed | **76** | **—** | **3009** | **—** | **413** | **123** | **2660** | **947** | **7227** |
| Undeveloped | **12** | **—** | **3881** | **—** | **358** | **—** | **1368** | **498** | **6117** |
|  | **88** | **—** | **6890** | **—** | **771** | **123** | **4028** | **1445** | **13344** |
| **Equity-accounted entities (bp share)**<sup>e</sup> |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | **—** | **49** | **—** | **4** | **1053** | **536** | **43** | **—** | **1686** |
| Undeveloped | **—** | **111** | **—** | **—** | **651** | **215** | **—** | **—** | **976** |
|  | **—** | **160** | **—** | **4** | **1704** | **751** | **43** | **—** | **2662** |
| **Changes attributable to** |  |  |  |  |  |  |  |  |  |
| Revisions of previous estimates | **—** | **17** | **—** | **—** | **(36)** | **48** | **(1)** | **—** | **27** |
| Improved recovery | **—** | **1** | **—** | **—** | **1** | **—** | **—** | **—** | **2** |
| Purchases of reserves-in-place | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** |
| Discoveries and extensions | **—** | **2** | **—** | **—** | **141** | **2** | **—** | **—** | **145** |
| Production<sup>c</sup> | **—** | **(21)** | **—** | **—** | **(126)** | **(113)** | **(3)** | **—** | **(263)** |
| Sales of reserves-in-place | **—** | **(1)** | **—** | **—** | **—** | **—** | **—** | **—** | **(1)** |
|  | **—** | **(2)** | **—** | **(1)** | **(20)** | **(64)** | **(4)** | **—** | **(90)** |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | **—** | **51** | **—** | **4** | **1000** | **516** | **39** | **—** | **1610** |
| Undeveloped | **—** | **108** | **—** | **—** | **684** | **171** | **—** | **—** | **962** |
|  | **—** | **158** | **—** | **4** | **1684** | **687** | **39** | **—** | **2572** |
| **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | **162** | **49** | **2600** | **4** | **1433** | **697** | **3070** | **1254** | **9268** |
| Undeveloped | **29** | **111** | **2412** | **—** | **1001** | **215** | **1320** | **431** | **5518** |
|  | **190** | **160** | **5012** | **4** | **2434** | **911** | **4390** | **1685** | **14786** |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | **76** | **51** | **3009** | **4** | **1413** | **639** | **2699** | **947** | **8837** |
| Undeveloped | **12** | **108** | **3881** | **—** | **1042** | **171** | **1368** | **498** | **7079** |
|  | **88** | **158** | **6890** | **4** | **2455** | **810** | **4067** | **1445** | **15916** |

---

aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cIncludes 114 billion cubic feet of natural gas consumed in operations, 71 billion cubic feet in subsidiaries, 43 billion cubic feet in equity-accounted entities.

dIncludes 231 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

eVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

---

| | |
|:---|:---|
| 252 | bp Annual Report and Form 20-F 2025 |

---

**Movements in estimated net proved reserves – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | | | | | | | million barrels of oil equivalent<sup>c</sup> | million barrels of oil equivalent<sup>c</sup> | million barrels of oil equivalent<sup>c</sup> |
| **Total hydrocarbons**<sup>a b</sup> |  |  |  |  |  |  |  |  | **2025** |
|  | **Europe** | **Europe** | **North** <br>**America** | **North** <br>**America** | **South** <br>**America**<br>| **Africa**<br>**Asia** |  | **Australasia** | **Total** |
|  | **UK** | **Rest of**<br>**Europe**<br>| **US**  | **Rest of**<br>**North**<br>**America**<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | **134** | **—** | **1303** | **—** | **67** | **29** | **1237** | **226** | **2997** |
| Undeveloped | **68** | **—** | **1134** | **—** | **65** | **—** | **533** | **76** | **1875** |
|  | **202** | **—** | **2437** | **—** | **131** | **29** | **1770** | **302** | **4871** |
| **Changes attributable to** |  |  |  |  |  |  |  |  |  |
| Revisions of previous estimates | **(36)** | **—** | **454** | **—** | **48** | **15** | **105** | **10** | **597** |
| Improved recovery | **—** | **—** | **15** | **—** | **—** | **—** | **—** | **—** | **15** |
| Purchases of reserves-in-place | **—** | **—** | **101** | **—** | **—** | **—** | **—** | **—** | **101** |
| Discoveries and extensions | **—** | **—** | **2** | **—** | **29** | **12** | **22** | **—** | **66** |
| Production<sup>d e</sup> | **(44)** | **—** | **(301)** | **—** | **(71)** | **(34)** | **(214)** | **(54)** | **(717)** |
| Sales of reserves-in-place | **(9)** | **—** | **(64)** | **—** | **—** | **—** | **—** | **—** | **(73)** |
|  | **(89)** | **—** | **208** | **—** | **7** | **(6)** | **(87)** | **(43)** | **(10)** |
| **At 31 December**<sup>f</sup> |  |  |  |  |  |  |  |  |  |
| Developed | **70** | **—** | **1321** | **—** | **73** | **23** | **1150** | **170** | **2806** |
| Undeveloped | **43** | **—** | **1324** | **—** | **66** | **—** | **534** | **88** | **2055** |
|  | **113** | **—** | **2645** | **—** | **138** | **23** | **1683** | **258** | **4861** |
| **Equity-accounted entities (bp share)**<sup>g</sup> |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | **—** | **87** | **—** | **11** | **456** | **196** | **115** | **—** | **864** |
| Undeveloped | **—** | **66** | **—** | **—** | **330** | **114** | **3** | **—** | **513** |
|  | **—** | **153** | **—** | **11** | **785** | **310** | **118** | **—** | **1377** |
| **Changes attributable to** |  |  |  |  |  |  |  |  |  |
| Revisions of previous estimates | **—** | **17** | **—** | **—** | **(45)** | **31** | **35** | **—** | **37** |
| Improved recovery | **—** | **2** | **—** | **—** | **3** | **—** | **—** | **—** | **5** |
| Purchases of reserves-in-place | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** | **—** |
| Discoveries and extensions | **—** | **4** | **—** | **—** | **53** | **1** | **—** | **—** | **59** |
| Production<sup>e</sup> | **—** | **(25)** | **—** | **(1)** | **(41)** | **(50)** | **(29)** | **—** | **(146)** |
| Sales of reserves-in-place | **—** | **(1)** | **—** | **—** | **—** | **—** | **—** | **—** | **(1)** |
|  | **—** | **(3)** | **—** | **(1)** | **(29)** | **(18)** | **6** | **—** | **(47)** |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | **—** | **81** | **—** | **10** | **454** | **195** | **120** | **—** | **860** |
| Undeveloped | **—** | **68** | **—** | **—** | **302** | **96** | **4** | **—** | **470** |
|  | **—** | **150** | **—** | **10** | **756** | **292** | **123** | **—** | **1330** |
| **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | **134** | **87** | **1303** | **11** | **522** | **225** | **1352** | **226** | **3860** |
| Undeveloped | **68** | **66** | **1134** | **—** | **394** | **114** | **535** | **76** | **2387** |
|  | **202** | **153** | **2437** | **11** | **917** | **339** | **1888** | **302** | **6248** |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | **70** | **81** | **1321** | **10** | **527** | **218** | **1269** | **170** | **3666** |
| Undeveloped | **43** | **68** | **1324** | **—** | **367** | **96** | **537** | **88** | **2525** |
|  | **113** | **150** | **2645** | **10** | **894** | **315** | **1807** | **258** | **6191** |

---

aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

c5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.

dExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.

eIncludes 20 million barrels of oil equivalent of natural gas consumed in operations, 12 million barrels of oil equivalent in subsidiaries, 7 million barrels of oil equivalent in equity-accounted entities.

fIncludes 41 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

gVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 253 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**Movements in estimated net proved reserves – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | million barrels | million barrels |
| **Crude oil**<sup>a b</sup> |  |  |  |  |  |  |  | 2024 | 2024 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 129 |  | 713 |  | 3 | 5 | 729 | 11 | 1590 |
| Undeveloped | 74 |  | 352 |  | 5 |  | 323 | 1 | 755 |
|  | 203 |  | 1065 |  | 7 | 6 | 1052 | 12 | 2345 |
| **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**<sup>c</sup> |  |  |  |  |  |  |  |  |  |
| Developed | 104 |  | 653 |  | 1 | 1 | 716 | 9 | 1483 |
| Undeveloped | 63 |  | 472 |  | 4 |  | 305 | 1 | 846 |
|  | 167 |  | 1125 |  | 5 | 1 | 1021 | 10 | 2329 |
| **Equity-accounted entities (bp share)**<sup>d</sup> |  |  |  |  |  |  |  |  |  |
| **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)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 129 | 89 | 713 | 11 | 278 | 104 | 844 | 11 | 2179 |
| Undeveloped | 74 | 45 | 352 |  | 258 | 88 | 324 | 1 | 1142 |
|  | 203 | 133 | 1065 | 11 | 536 | 192 | 1168 | 12 | 3321 |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | 104 | 76 | 653 | 10 | 271 | 95 | 823 | 9 | 2041 |
| Undeveloped | 63 | 42 | 472 |  | 221 | 77 | 308 | 1 | 1184 |
|  | 167 | 118 | 1125 | 10 | 493 | 171 | 1131 | 10 | 3225 |

---

aCrude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying

production and the option and ability to make lifting and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cIncludes 1.5 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

dVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

---

| | |
|:---|:---|
| 254 | bp Annual Report and Form 20-F 2025 |

---

**Movements in estimated net proved reserves – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | million barrels | million barrels |
| **Natural gas liquids**<sup>a b</sup> |  |  |  |  |  |  |  | 2024 | 2024 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| **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<sup>c</sup> | (1) |  | (39) |  | (2) |  |  | (1) | (43) |
| Sales of reserves-in-place |  |  | (4) |  |  |  |  |  | (4) |
|  | (1) |  | 51 |  |  |  |  |  | 51 |
| **At 31 December**<sup>d</sup> |  |  |  |  |  |  |  |  |  |
| Developed | 2 |  | 202 |  | 1 |  |  | 1 | 206 |
| Undeveloped |  |  | 246 |  |  |  |  |  | 246 |
|  | 3 |  | 447 |  | 1 |  |  | 1 | 452 |
| **Equity-accounted entities (bp share)**<sup>e</sup> |  |  |  |  |  |  |  |  |  |
| **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)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 3 | 3 | 180 |  | 3 | 14 |  | 1 | 204 |
| Undeveloped |  | 5 | 217 |  | 1 |  |  |  | 223 |
|  | 3 | 8 | 397 |  | 4 | 14 |  | 1 | 427 |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | 2 | 3 | 202 |  | 4 | 10 |  | 1 | 222 |
| Undeveloped |  | 5 | 246 |  |  |  |  |  | 252 |
|  | 3 | 8 | 447 |  | 4 | 10 |  | 1 | 474 |

---

aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.

dIncludes 0.2 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

eVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 255 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**Movements in estimated net proved reserves – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | million barrels | million barrels | million barrels | million barrels | million barrels | million barrels | million barrels | million barrels | million barrels |
| **Total liquids**<sup>a b</sup> |  |  |  |  |  |  |  | 2024 | 2024 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 132 |  | 893 |  | 3 | 6 | 729 | 11 | 1775 |
| Undeveloped | 75 |  | 568 |  | 5 |  | 323 | 1 | 971 |
|  | 207 |  | 1462 |  | 7 | 6 | 1052 | 13 | 2746 |
| **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<sup>c</sup> | (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**<sup>d</sup> |  |  |  |  |  |  |  |  |  |
| Developed | 106 |  | 855 |  | 1 | 1 | 716 | 10 | 1689 |
| Undeveloped | 63 |  | 718 |  | 4 |  | 305 | 1 | 1092 |
|  | 169 |  | 1573 |  | 6 | 1 | 1021 | 11 | 2781 |
| **Equity-accounted entities (bp share)**<sup>e</sup> |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed |  | 92 |  | 11 | 278 | 113 | 115 |  | 608 |
| Undeveloped |  | 49 |  |  | 254 | 88 | 2 |  | 393 |
|  |  | 141 |  | 11 | 532 | 200 | 117 |  | 1001 |
| **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)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 132 | 92 | 893 | 11 | 281 | 118 | 844 | 11 | 2382 |
| Undeveloped | 75 | 49 | 568 |  | 259 | 88 | 324 | 1 | 1365 |
|  | 207 | 141 | 1462 | 11 | 540 | 206 | 1168 | 13 | 3747 |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | 106 | 78 | 855 | 10 | 275 | 105 | 823 | 10 | 2263 |
| Undeveloped | 63 | 47 | 718 |  | 222 | 77 | 308 | 1 | 1436 |
|  | 169 | 125 | 1573 | 10 | 497 | 182 | 1131 | 11 | 3699 |

---

aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.

dAlso includes 1.7 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

eVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

---

| | |
|:---|:---|
| 256 | bp Annual Report and Form 20-F 2025 |

---

**Movements in estimated net proved reserves – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | billion cubic feet | billion cubic feet |
| **Natural gas**<sup>a b</sup> |  |  |  |  |  |  |  | 2024 | 2024 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 221 |  | 2672 |  | 931 | 518 | 3051 | 1550 | 8942 |
| Undeveloped | 34 |  | 3229 |  | 503 | 207 | 1672 | 358 | 6003 |
|  | 255 |  | 5901 |  | 1434 | 724 | 4722 | 1907 | 14944 |
| **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<sup>c</sup> | (80) |  | (639) |  | (423) | (340) | (625) | (325) | (2432) |
| Sales of reserves-in-place |  |  | (76) |  | (115) | (402) |  |  | (594) |
|  | (65) |  | (889) |  | (704) | (564) | (376) | (222) | (2821) |
| **At 31 December**<sup>d</sup> |  |  |  |  |  |  |  |  |  |
| Developed | 162 |  | 2600 |  | 379 | 161 | 3026 | 1254 | 7582 |
| Undeveloped | 29 |  | 2412 |  | 350 |  | 1320 | 431 | 4542 |
|  | 190 |  | 5012 |  | 730 | 161 | 4346 | 1685 | 12124 |
| **Equity-accounted entities (bp share)**<sup>e</sup> |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed |  | 67 |  | 4 | 1027 | 463 | 46 |  | 1608 |
| Undeveloped |  | 110 |  |  | 621 | 188 |  |  | 919 |
|  |  | 177 |  | 4 | 1648 | 651 | 46 |  | 2527 |
| **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<sup>c</sup> |  | (20) |  |  | (129) | (46) | (2) |  | (199) |
| Sales of reserves-in-place |  |  |  |  | (4) |  |  |  | (5) |
|  |  | (18) |  |  | 56 | 100 | (2) |  | 135 |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed |  | 49 |  | 4 | 1053 | 536 | 43 |  | 1686 |
| Undeveloped |  | 111 |  |  | 651 | 215 |  |  | 976 |
|  |  | 160 |  | 4 | 1704 | 751 | 43 |  | 2662 |
| **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 221 | 67 | 2672 | 4 | 1958 | 981 | 3096 | 1550 | 10549 |
| Undeveloped | 34 | 110 | 3229 |  | 1125 | 394 | 1672 | 358 | 6922 |
|  | 255 | 177 | 5901 | 4 | 3082 | 1375 | 4768 | 1907 | 17471 |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | 162 | 49 | 2600 | 4 | 1433 | 697 | 3070 | 1254 | 9268 |
| Undeveloped | 29 | 111 | 2412 |  | 1001 | 215 | 1320 | 431 | 5518 |
|  | 190 | 160 | 5012 | 4 | 2434 | 911 | 4390 | 1685 | 14786 |

---

aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cIncludes 100 billion cubic feet of natural gas consumed in operations, 62 billion cubic feet in subsidiaries, 38 billion cubic feet in equity-accounted entities.

dIncludes 219 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

eVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 257 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**Movements in estimated net proved reserves – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  | million barrels of oil equivalent<sup>c</sup> | million barrels of oil equivalent<sup>c</sup> | million barrels of oil equivalent<sup>c</sup> |
| **Total hydrocarbons**<sup>a b</sup> |  |  |  |  |  |  |  | 2024 | 2024 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 170 |  | 1354 |  | 163 | 95 | 1255 | 279 | 3316 |
| Undeveloped | 81 |  | 1125 |  | 91 | 36 | 611 | 63 | 2006 |
|  | 251 |  | 2479 |  | 255 | 131 | 1866 | 341 | 5323 |
| **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<sup>d e</sup> | (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**<sup>f</sup> |  |  |  |  |  |  |  |  |  |
| Developed | 134 |  | 1303 |  | 67 | 29 | 1237 | 226 | 2997 |
| Undeveloped | 68 |  | 1134 |  | 65 |  | 533 | 76 | 1875 |
|  | 202 |  | 2437 |  | 131 | 29 | 1770 | 302 | 4871 |
| **Equity-accounted entities (bp share)**<sup>g</sup> |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed |  | 103 |  | 12 | 455 | 192 | 123 |  | 885 |
| Undeveloped |  | 68 |  |  | 361 | 120 | 2 |  | 552 |
|  |  | 172 |  | 12 | 816 | 313 | 124 |  | 1437 |
| **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<sup>e</sup> |  | (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 |  | 1377 |
| **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 170 | 103 | 1354 | 12 | 618 | 287 | 1378 | 279 | 4201 |
| Undeveloped | 81 | 68 | 1125 |  | 453 | 156 | 613 | 63 | 2558 |
|  | 251 | 172 | 2479 | 12 | 1071 | 444 | 1991 | 341 | 6759 |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | 134 | 87 | 1303 | 11 | 522 | 225 | 1352 | 226 | 3860 |
| Undeveloped | 68 | 66 | 1134 |  | 394 | 114 | 535 | 76 | 2387 |
|  | 202 | 153 | 2437 | 11 | 917 | 339 | 1888 | 302 | 6248 |

---

aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

c5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.

dExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.

eIncludes 17 million barrels of oil equivalent of natural gas consumed in operations, 11 million barrels of oil equivalent in subsidiaries, 6 million barrels of oil equivalent in equity-accounted entities.

fIncludes 41 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

gVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

---

| | |
|:---|:---|
| 258 | bp Annual Report and Form 20-F 2025 |

---

**Movements in estimated net proved reserves – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | million barrels | million barrels |
| **Crude oil**<sup>a b</sup> |  |  |  |  |  |  |  | 2023 | 2023 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 153 |  | 679 |  | 4 | 24 | 717 | 20 | 1596 |
| Undeveloped | 109 |  | 527 |  | 5 | 2 | 356 | 1 | 1000 |
|  | 261 |  | 1206 |  | 9 | 26 | 1073 | 21 | 2596 |
| **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**<sup>c</sup> |  |  |  |  |  |  |  |  |  |
| Developed | 129 |  | 713 |  | 3 | 5 | 729 | 11 | 1590 |
| Undeveloped | 74 |  | 352 |  | 5 |  | 323 | 1 | 755 |
|  | 203 |  | 1065 |  | 7 | 6 | 1052 | 12 | 2345 |
| **Equity-accounted entities (bp share)**<sup>d</sup> | **Equity-accounted entities (bp share)**<sup>d</sup> | **Equity-accounted entities (bp share)**<sup>d</sup> |  |  |  |  |  |  |  |
| **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)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 153 | 90 | 679 | 5 | 279 | 151 | 812 | 20 | 2188 |
| Undeveloped | 109 | 16 | 527 | 7 | 249 | 76 | 358 | 1 | 1343 |
|  | 261 | 106 | 1206 | 12 | 529 | 227 | 1169 | 21 | 3531 |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | 129 | 89 | 713 | 11 | 278 | 104 | 844 | 11 | 2179 |
| Undeveloped | 74 | 45 | 352 |  | 258 | 88 | 324 | 1 | 1142 |
|  | 203 | 133 | 1065 | 11 | 536 | 192 | 1168 | 12 | 3321 |

---

aCrude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying

production and the option and ability to make lifting and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cIncludes 2.2 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

dVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 259 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**Movements in estimated net proved reserves – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | million barrels | million barrels |
| **Natural gas liquids**<sup>a b</sup> |  |  |  |  |  |  |  | 2023 | 2023 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| **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<sup>c</sup> | (2) |  | (31) |  | (1) | (1) |  | (1) | (35) |
| Sales of reserves-in-place |  |  | (3) |  |  | (6) |  |  | (9) |
|  | (3) |  | (20) |  | (1) | (7) |  |  | (31) |
| **At 31 December**<sup>d</sup> |  |  |  |  |  |  |  |  |  |
| Developed | 3 |  | 180 |  |  |  |  | 1 | 184 |
| Undeveloped |  |  | 217 |  |  |  |  |  | 217 |
|  | 3 |  | 397 |  |  |  |  | 1 | 401 |
| **Equity-accounted entities (bp share)**<sup>e</sup> |  |  |  |  |  |  |  |  |  |
| **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)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 6 | 4 | 181 |  | 4 | 23 |  | 1 | 219 |
| Undeveloped |  |  | 236 |  | 1 | 10 |  |  | 247 |
|  | 6 | 4 | 417 |  | 5 | 33 |  | 1 | 466 |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | 3 | 3 | 180 |  | 3 | 14 |  | 1 | 204 |
| Undeveloped |  | 5 | 217 |  | 1 |  |  |  | 223 |
|  | 3 | 8 | 397 |  | 4 | 14 |  | 1 | 427 |

---

aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.

dIncludes 0 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

---

| | |
|:---|:---|
| 260 | bp Annual Report and Form 20-F 2025 |

---

**Movements in estimated net proved reserves – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | million barrels | million barrels |
| **Total liquids**<sup>a b</sup> |  |  |  |  |  |  |  |  | 2023 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 159 |  | 860 |  | 5 | 30 | 717 | 20 | 1791 |
| Undeveloped | 109 |  | 763 |  | 5 | 3 | 356 | 1 | 1237 |
|  | 267 |  | 1623 |  | 11 | 33 | 1073 | 22 | 3029 |
| **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<sup>c</sup> | (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**<sup>d</sup> |  |  |  |  |  |  |  |  |  |
| Developed | 132 |  | 893 |  | 3 | 6 | 729 | 11 | 1775 |
| Undeveloped | 75 |  | 568 |  | 5 |  | 323 | 1 | 971 |
|  | 207 |  | 1462 |  | 7 | 6 | 1052 | 13 | 2746 |
| **Equity-accounted entities (bp share)**<sup>e</sup> | **Equity-accounted entities (bp share)**<sup>e</sup> | **Equity-accounted entities (bp share)**<sup>e</sup> |  |  |  |  |  |  |  |
| **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 |  | 1001 |
| **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 159 | 94 | 860 | 5 | 283 | 174 | 812 | 20 | 2407 |
| Undeveloped | 109 | 16 | 763 | 7 | 250 | 86 | 358 | 1 | 1590 |
|  | 267 | 110 | 1623 | 12 | 534 | 260 | 1169 | 22 | 3997 |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | 132 | 92 | 893 | 11 | 281 | 118 | 844 | 11 | 2382 |
| Undeveloped | 75 | 49 | 568 |  | 259 | 88 | 324 | 1 | 1365 |
|  | 207 | 141 | 1462 | 11 | 540 | 206 | 1168 | 13 | 3747 |

---

aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.

dAlso includes 2.2 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

eVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 261 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**Movements in estimated net proved reserves – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | billion cubic feet | billion cubic feet |
| **Natural gas**<sup>a b</sup> |  |  |  |  |  |  |  | 2023 | 2023 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 360 |  | 2655 |  | 1077 | 1021 | 2594 | 1684 | 9392 |
| Undeveloped | 41 |  | 3154 |  | 748 | 221 | 2125 | 407 | 6696 |
|  | 401 |  | 5809 |  | 1825 | 1242 | 4719 | 2091 | 16087 |
| **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<sup>c</sup> | (100) |  | (560) |  | (439) | (462) | (594) | (284) | (2439) |
| Sales of reserves-in-place |  |  | (25) |  |  | (97) |  |  | (123) |
|  | (146) |  | 92 |  | (391) | (518) | 3 | (184) | (1143) |
| **At 31 December**<sup>d</sup> |  |  |  |  |  |  |  |  |  |
| Developed | 221 |  | 2672 |  | 931 | 518 | 3051 | 1550 | 8942 |
| Undeveloped | 34 |  | 3229 |  | 503 | 207 | 1672 | 358 | 6003 |
|  | 255 |  | 5901 |  | 1434 | 724 | 4722 | 1907 | 14944 |
| **Equity-accounted entities (bp share)**<sup>e</sup> |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed |  | 72 |  | 3 | 974 | 534 | 43 |  | 1627 |
| Undeveloped |  | 5 |  | 2 | 606 | 154 |  |  | 767 |
|  |  | 77 |  | 5 | 1580 | 689 | 43 |  | 2394 |
| **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<sup>c</sup> |  | (22) |  |  | (128) | (41) | (2) |  | (194) |
| Sales of reserves-in-place |  |  |  |  | (84) |  |  |  | (84) |
|  |  | 101 |  | (1) | 68 | (38) | 3 |  | 133 |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed |  | 67 |  | 4 | 1027 | 463 | 46 |  | 1608 |
| Undeveloped |  | 110 |  |  | 621 | 188 |  |  | 919 |
|  |  | 177 |  | 4 | 1648 | 651 | 46 |  | 2527 |
| **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 360 | 72 | 2655 | 3 | 2051 | 1556 | 2637 | 1684 | 11018 |
| Undeveloped | 41 | 5 | 3154 | 2 | 1355 | 375 | 2125 | 407 | 7463 |
|  | 401 | 77 | 5809 | 5 | 3405 | 1931 | 4762 | 2091 | 18481 |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | 221 | 67 | 2672 | 4 | 1958 | 981 | 3096 | 1550 | 10549 |
| Undeveloped | 34 | 110 | 3229 |  | 1125 | 394 | 1672 | 358 | 6922 |
|  | 255 | 177 | 5901 | 4 | 3082 | 1375 | 4768 | 1907 | 17471 |

---

aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cIncludes 99 billion cubic feet of natural gas consumed in operations, 62 billion cubic feet in subsidiaries, 36 billion cubic feet in equity-accounted entities.

dIncludes 430 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

eVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

---

| | |
|:---|:---|
| 262 | bp Annual Report and Form 20-F 2025 |

---

**Movements in estimated net proved reserves – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  | million barrels of oil equivalent<sup>c</sup> | million barrels of oil equivalent<sup>c</sup> | million barrels of oil equivalent<sup>c</sup> |
| **Total hydrocarbons**<sup>a b</sup> |  |  |  |  |  |  |  | 2023 | 2023 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 221 |  | 1318 |  | 191 | 206 | 1164 | 311 | 3411 |
| Undeveloped | 116 |  | 1306 |  | 134 | 41 | 723 | 72 | 2392 |
|  | 337 |  | 2624 |  | 325 | 247 | 1887 | 382 | 5802 |
| **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<sup>d e</sup> | (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**<sup>f</sup> |  |  |  |  |  |  |  |  |  |
| Developed | 170 |  | 1354 |  | 163 | 95 | 1255 | 279 | 3316 |
| Undeveloped | 81 |  | 1125 |  | 91 | 36 | 611 | 63 | 2006 |
|  | 251 |  | 2479 |  | 255 | 131 | 1866 | 341 | 5323 |
| **Equity-accounted entities (bp share)**<sup>g</sup> |  |  |  |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed |  | 106 |  | 6 | 446 | 236 | 102 |  | 896 |
| Undeveloped |  | 17 |  | 7 | 349 | 110 | 1 |  | 485 |
|  |  | 123 |  | 13 | 796 | 346 | 103 |  | 1381 |
| **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<sup>e</sup> |  | (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 |  | 1437 |
| **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** | **Total subsidiaries and equity-accounted entities (bp share)** |  |  |  |  |  |  |
| **At 1 January** |  |  |  |  |  |  |  |  |  |
| Developed | 221 | 106 | 1318 | 6 | 637 | 442 | 1266 | 311 | 4307 |
| Undeveloped | 116 | 17 | 1306 | 7 | 484 | 151 | 724 | 72 | 2877 |
|  | 337 | 123 | 2624 | 13 | 1121 | 593 | 1990 | 382 | 7183 |
| **At 31 December** |  |  |  |  |  |  |  |  |  |
| Developed | 170 | 103 | 1354 | 12 | 618 | 287 | 1378 | 279 | 4201 |
| Undeveloped | 81 | 68 | 1125 |  | 453 | 156 | 613 | 63 | 2558 |
|  | 251 | 172 | 2479 | 12 | 1071 | 444 | 1991 | 341 | 6759 |

---

aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

c5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.

dExcludes NGLs from processing plants in which an interest is held of 2 thousand barrels per day for equity-accounted entities.

eIncludes 17 million barrels of oil equivalent of natural gas consumed in operations, 11 million barrels of oil equivalent in subsidiaries, 6 million barrels of oil equivalent in equity-accounted entities.

fIncludes 41 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.

gVolumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 263 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas** 

**reserves**

The following tables set out the standardized measure of discounted future net cash flows, and changes therein, relating to crude oil and natural

gas production from the group's estimated proved reserves. This information is prepared in compliance with FASB Oil and Gas Disclosures

requirements.

Future net cash flows have been prepared on the basis of certain assumptions which may or may not be realized. These include the timing of future

production, the estimation of crude oil and natural gas reserves and the application of average crude oil and natural gas prices and exchange rates

from the previous 12 months. Furthermore, both proved reserves estimates and production forecasts are subject to revision as further technical

information becomes available and economic conditions change. bp cautions against relying on the information presented because of the highly

arbitrary nature of the assumptions on which it is based and its lack of comparability with the historical cost information presented in the financial

statements.

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  |  | $ million |
|  |  |  |  |  |  |  |  |  | **2025** |
|  | **Europe** | **Europe** | **North** <br>**America** | **North** <br>**America** | **South** <br>**America**<br>| **Africa**<br>**Asia** |  | **Australasia** | **Total** |
|  | **UK** | **Rest of**<br>**Europe**<br>| **US** | **Rest of**<br>**North**<br>**America**<br>|  |  |  |  |  |
| At 31 December |  |  |  |  |  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| Future cash inflows<sup>a</sup> | **7600** | **—** | **93300** | **—** | **5000** | **600** | **93300** | **11500** | **211300** |
| Future production cost<sup>b</sup> | **8500** | **—** | **39300** | **—** | **3300** | **200** | **34500** | **3600** | **89400** |
| Future development cost<sup>b</sup> | **800** | **—** | **15300** | **—** | **1200** | **100** | **13500** | **1600** | **32500** |
| Future taxation<sup>c</sup> | **(100)** | **—** | **6000** | **—** | **100** | **—** | **33100** | **1600** | **40700** |
| Future net cash flows | **(1600)** | **—** | **32700** | **—** | **400** | **300** | **12200** | **4700** | **48700** |
| 10% annual discount<sup>d</sup> | **(700)** | **—** | **12900** | **—** | **(500)** | **—** | **4300** | **1600** | **17600** |
| Standardized measure of discounted future net cash <br>flows<sup>e</sup><br>| **(900)** | **—** | **19800** | **—** | **900** | **300** | **7900** | **3100** | **31100** |
| **Equity-accounted entities (bp share)**<sup>f</sup> |  |  |  |  |  |  |  |  |  |
| Future cash inflows<sup>a</sup> | **—** | **10100** | **—** | **—** | **36800** | **12300** | **8100** | **—** | **67300** |
| Future production cost<sup>b</sup> | **—** | **4300** | **—** | **—** | **18500** | **4800** | **4100** | **—** | **31700** |
| Future development cost<sup>b</sup> | **—** | **1300** | **—** | **—** | **3900** | **1000** | **2800** | **—** | **9000** |
| Future taxation<sup>c</sup> | **—** | **3500** | **—** | **—** | **3700** | **1800** | **400** | **—** | **9400** |
| Future net cash flows | **—** | **1000** | **—** | **—** | **10700** | **4700** | **800** | **—** | **17200** |
| 10% annual discount<sup>d</sup> | **—** | **100** | **—** | **—** | **6300** | **1100** | **200** | **—** | **7700** |
| Standardized measure of discounted future net cash <br>flows<br>| **—** | **900** | **—** | **—** | **4400** | **3600** | **600** | **—** | **9500** |
| **Total subsidiaries and equity-accounted entities** | **Total subsidiaries and equity-accounted entities** | **Total subsidiaries and equity-accounted entities** | **Total subsidiaries and equity-accounted entities** | **Total subsidiaries and equity-accounted entities** | **Total subsidiaries and equity-accounted entities** | **Total subsidiaries and equity-accounted entities** | **Total subsidiaries and equity-accounted entities** | **Total subsidiaries and equity-accounted entities** | **Total subsidiaries and equity-accounted entities** |
| Standardized measure of discounted future net cash <br>flows<br>| **(900)** | **900** | **19800** | **—** | **5300** | **3900** | **8500** | **3100** | **40600** |

---

The following are the principal sources of change in the standardized measure of discounted future net cash flows:

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **Subsidiaries** | **Equity-accounted**<br>**entities (bp share)**<br>| **Total subsidiaries and**<br>**equity-accounted**<br>**entities**<br>|
| Sales and transfers of oil and gas produced, net of production costs | **(21400)** | **(5400)** | **(26800)** |
| Development costs for the current year as estimated in previous year | **6000** | **3200** | **9200** |
| Extensions, discoveries and improved recovery, less related costs | **1000** | **800** | **1800** |
| Net changes in prices and production cost | **(11100)** | **(3100)** | **(14200)** |
| Revisions of previous reserves estimates | **4200** | **600** | **4800** |
| Net change in taxation | **11300** | **1700** | **13000** |
| Future development costs | **(1100)** | **100** | **(1000)** |
| Net change in purchase and sales of reserves-in-place | **—** | **(100)** | **(100)** |
| Addition of 10% annual discount | **3800** | **1100** | **4900** |
| **Total change in the standardized measure during the year**<sup>g</sup> | **(7300)** | **(1100)** | **(8400)** |

---

aThe marker prices used were Brent $69.5/bbl, Henry Hub $3.4/mmBtu.

bProduction costs, which include production taxes and also fixed commitment costs associated with probable/contingent volumes, and development costs relating to future production of proved

reserves are based on the continuation of existing economic conditions. Future decommissioning costs are included.

cTaxation is computed with reference to appropriate year-end statutory corporate income tax rates.

dFuture net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.

eNon-controlling interests in BP Trinidad and Tobago LLC amounted to $271 million.

fThe standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments

of those entities.

gTotal change in the standardized measure during the year includes the effect of exchange rate movements.

---

| | |
|:---|:---|
| 264 | bp Annual Report and Form 20-F 2025 |

---

**Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas** 

**reserves – continued** 

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  |  | $ million |
|  |  |  |  |  |  |  |  |  | 2024 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| At 31 December |  |  |  |  |  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| Future cash inflows<sup>a</sup> | 15100 |  | 99300 |  | 3700 | 600 | 107300 | 15200 | 241200 |
| Future production cost<sup>b</sup> | 11800 |  | 39100 |  | 2900 | 100 | 37800 | 3900 | 95600 |
| Future development cost<sup>b</sup> | 1000 |  | 15300 |  | 500 | 100 | 11200 | 2100 | 30200 |
| Future taxation<sup>c</sup> | 2200 |  | 7100 |  | 100 | 100 | 42800 | 2400 | 54700 |
| Future net cash flows | 100 |  | 37800 |  | 200 | 300 | 15500 | 6800 | 60700 |
| 10% annual discount<sup>d</sup> | 100 |  | 15400 |  | (300) |  | 4900 | 2200 | 22300 |
| Standardized measure of discounted future net cash <br>flows<sup>e</sup><br>|  |  | 22400 |  | 500 | 300 | 10600 | 4600 | 38400 |
| **Equity-accounted entities (bp share)**<sup>f</sup> | **Equity-accounted entities (bp share)**<sup>f</sup> | **Equity-accounted entities (bp share)**<sup>f</sup> |  |  |  |  |  |  |  |
| Future cash inflows<sup>a</sup> |  | 11700 |  |  | 41600 | 15100 | 8400 |  | 76800 |
| Future production cost<sup>b</sup> |  | 4100 |  |  | 20900 | 5400 | 4200 |  | 34600 |
| Future development cost<sup>b</sup> |  | 2000 |  |  | 4100 | 2200 | 2900 |  | 11200 |
| Future taxation<sup>c</sup> |  | 4300 |  |  | 4600 | 2200 | 400 |  | 11500 |
| Future net cash flows |  | 1300 |  |  | 12000 | 5300 | 900 |  | 19500 |
| 10% annual discount<sup>d</sup> |  | 300 |  |  | 7000 | 1400 | 200 |  | 8900 |
| Standardized measure of discounted future net cash <br>flows<br>|  | 1000 |  |  | 5000 | 3900 | 700 |  | 10600 |
| **Total subsidiaries and equity-accounted entities** | **Total subsidiaries and equity-accounted entities** | **Total subsidiaries and equity-accounted entities** | **Total subsidiaries and equity-accounted entities** |  |  |  |  |  |  |
| Standardized measure of discounted future net cash <br>flows<br>|  | 1000 | 22400 |  | 5500 | 4200 | 11300 | 4600 | 49000 |

---

The following are the principal sources of change in the standardized measure of discounted future net cash flows:

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | Subsidiaries | Equity-accounted<br>entities (bp share)<br>| Total subsidiaries and <br>equity-accounted <br>entities<br>|
| Sales and transfers of oil and gas produced, net of production costs | (25700) | (5300) | (31000) |
| Development costs for the current year as estimated in previous year | 5100 | 2900 | 8000 |
| Extensions, discoveries and improved recovery, less related costs | 400 | 300 | 700 |
| Net changes in prices and production cost | (7300) | (1800) | (9100) |
| Revisions of previous reserves estimates | 2500 | 300 | 2800 |
| Net change in taxation | 11200 | 2100 | 13300 |
| Future development costs | (1400) | (600) | (2000) |
| Net change in purchase and sales of reserves-in-place | (1400) | 800 | (600) |
| Addition of 10% annual discount | 5000 | 1100 | 6100 |
| **Total change in the standardized measure during the year**<sup>g</sup> | (11600) | (200) | (11800) |

---

aThe marker prices used were Brent $81.17/bbl, Henry Hub $2.07/mmBtu.

bProduction costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future

decommissioning costs are included.

cTaxation is computed with reference to appropriate year-end statutory corporate income tax rates.

dFuture net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.

eNon-controlling interests in BP Trinidad and Tobago LLC amounted to $164 million.

fThe standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments

of those entities.

gTotal change in the standardized measure during the year includes the effect of exchange rate movements.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 265 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas** 

**reserves – continued**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  |  | $ million |
|  |  |  |  |  |  |  |  |  | 2023 |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total |
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| At 31 December |  |  |  |  |  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| Future cash inflows<sup>a</sup> | 19400 |  | 100200 |  | 6800 | 4400 | 118300 | 18000 | 267100 |
| Future production cost<sup>b</sup> | 11900 |  | 37500 |  | 4300 | 600 | 39600 | 4500 | 98400 |
| Future development cost<sup>b</sup> | 1200 |  | 12100 |  | 1000 | 500 | 8500 | 1400 | 24700 |
| Future taxation<sup>c</sup> | 4100 |  | 8400 |  | 500 | 1100 | 49900 | 3800 | 67800 |
| Future net cash flows | 2200 |  | 42200 |  | 1000 | 2200 | 20300 | 8300 | 76200 |
| 10% annual discount<sup>d</sup> | 900 |  | 16300 |  | (300) | 400 | 6300 | 2600 | 26200 |
| Standardized measure of discounted future net cash <br>flows<sup>e</sup><br>| 1300 |  | 25900 |  | 1300 | 1800 | 14000 | 5700 | 50000 |
| **Equity-accounted entities (bp share)**<sup>f</sup> | **Equity-accounted entities (bp share)**<sup>f</sup> | **Equity-accounted entities (bp share)**<sup>f</sup> |  |  |  |  |  |  |  |
| Future cash inflows<sup>a</sup> |  | 13700 |  |  | 44600 | 15200 | 9000 |  | 82500 |
| Future production cost<sup>b</sup> |  | 3700 |  |  | 20700 | 5500 | 4700 |  | 34600 |
| Future development cost<sup>b</sup> |  | 2100 |  |  | 5200 | 2300 | 3100 |  | 12700 |
| Future taxation<sup>c</sup> |  | 6000 |  |  | 5900 | 2100 | 400 |  | 14400 |
| Future net cash flows |  | 1900 |  |  | 12800 | 5300 | 800 |  | 20800 |
| 10% annual discount<sup>d</sup> |  | 500 |  |  | 7600 | 1700 | 200 |  | 10000 |
| Standardized measure of discounted future net cash <br>flows<br>|  | 1400 |  |  | 5200 | 3600 | 600 |  | 10800 |
| **Total subsidiaries and equity-accounted entities** | **Total subsidiaries and equity-accounted entities** | **Total subsidiaries and equity-accounted entities** | **Total subsidiaries and equity-accounted entities** |  |  |  |  |  |  |
| Standardized measure of discounted future net cash <br>flows<br>| 1300 | 1400 | 25900 |  | 6500 | 5400 | 14600 | 5700 | 60800 |

---

The following are the principal sources of change in the standardized measure of discounted future net cash flows:

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | Subsidiaries | Equity-accounted<br>entities (bp share)<br>| Total subsidiaries and<br>equity-accounted<br>entities<br>|
| Sales and transfers of oil and gas produced, net of production costs | (36500) | (6500) | (43000) |
| Development costs for the current year as estimated in previous year | 6000 | 2200 | 8200 |
| Extensions, discoveries and improved recovery, less related costs | 500 | 800 | 1300 |
| Net changes in prices and production cost | (50800) | (7100) | (57900) |
| Revisions of previous reserves estimates | 2500 | 1300 | 3800 |
| Net change in taxation | 30000 | 5100 | 35100 |
| Future development costs | (1000) | (300) | (1300) |
| Net change in purchase and sales of reserves-in-place | (800) |  | (800) |
| Addition of 10% annual discount | 9100 | 1400 | 10500 |
| **Total change in the standardized measure during the year**<sup>g</sup> | (41000) | (3100) | (44100) |

---

aThe marker prices used were Brent $83.27/bbl, Henry Hub $2.58/mmBtu.

bProduction costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future

decommissioning costs are included.

cTaxation is computed with reference to appropriate year-end statutory corporate income tax rates.

dFuture net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.

eNon-controlling interests in BP Trinidad and Tobago LLC amounted to $392 million.

fThe standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments

of those entities.

gTotal change in the standardized measure during the year includes the effect of exchange rate movements.

---

| | |
|:---|:---|
| 266 | bp Annual Report and Form 20-F 2025 |

---

**Operational and statistical information**

The following tables present operational and statistical information related to production, drilling, productive wells and acreage. Figures include

amounts attributable to assets held for sale.

**Crude oil and natural gas production**

The following table shows crude oil, natural gas liquids and natural gas production for the years ended 31 December 2025, 2024 and 2023.

Production for the year<sup>a b</sup>

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | **Europe** | **Europe** | **North** <br>**America** | **North** <br>**America** | **South** <br>**America**<br>| **Africa** | **Asia** | **Australasia** | **Total** |
|  | **UK** | **Rest of**<br>**Europe**<br>| **US** | **Rest of**<br>**North**<br>**America**<br>|  |  |  |  |  |
| Subsidiaries<sup>c</sup> |  |  |  |  |  |  |  |  |  |
| Crude oil<sup>d</sup> |  |  |  |  |  |  |  | thousand barrels per day | thousand barrels per day |
| **2025** | **78** | **—** | **399** | **—** | **5** | **8** | **302** | **8** | **800** |
| 2024 | 70 |  | 376 |  | 4 | 19 | 297 | 9 | 775 |
| 2023 | 74 |  | 335 |  | 4 | 29 | 293 | 10 | 745 |
| Natural gas liquids |  |  |  |  |  |  |  | thousand barrels per day | thousand barrels per day |
| **2025** | **4** | **—** | **111** | **—** | **6** | **—** | **—** | **1** | **123** |
| 2024 | 4 |  | 107 |  | 4 | 1 |  | 2 | 117 |
| 2023 | 5 |  | 88 |  | 4 | 2 |  | 2 | 100 |
| Natural gas<sup>e</sup> |  |  |  |  |  |  |  | million cubic feet per day | million cubic feet per day |
| **2025** | **203** | **—** | **1751** | **—** | **1045** | **453** | **1597** | **799** | **5847** |
| 2024 | 197 |  | 1690 |  | 1145 | 904 | 1655 | 882 | 6474 |
| 2023 | 247 |  | 1486 |  | 1191 | 1236 | 1578 | 774 | 6512 |
| Equity-accounted entities (bp share) |  |  |  |  |  |  |  |  |  |
| Crude oil<sup>d</sup> |  |  |  |  |  |  |  | thousand barrels per day | thousand barrels per day |
| **2025** | **—** | **55** | **—** | **—** | **56** | **78** | **79** | **—** | **268** |
| 2024 |  | 58 |  |  | 56 | 82 | 69 |  | 266 |
| 2023 |  | 60 |  |  | 57 | 82 | 62 |  | 261 |
| Natural gas liquids |  |  |  |  |  |  |  | thousand barrels per day | thousand barrels per day |
| **2025** | **—** | **2** | **—** | **—** | **1** | **5** | **—** | **—** | **8** |
| 2024 |  | 2 |  |  | 1 | 6 |  |  | 9 |
| 2023 |  | 3 |  |  | 1 | 6 |  |  | 9 |
| Natural gas<sup>e</sup> |  |  |  |  |  |  |  | million cubic feet per day | million cubic feet per day |
| **2025** | **—** | **54** | **—** | **—** | **284** | **264** | **—** | **—** | **603** |
| 2024 |  | 55 |  |  | 300 | 85 |  |  | 440 |
| 2023 |  | 58 |  |  | 299 | 74 |  |  | 432 |

---

aProduction excludes royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting

and sales arrangements independently.

bBecause of rounding, some totals may not exactly agree with the sum of their component parts.

cAll of the oil and liquid production from Canada is bitumen.

dCrude oil includes condensate.

eNatural gas production excludes gas consumed in operations.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 267 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

**Operational and statistical information – continued**

**Productive oil and gas wells and acreage**

The following tables show the number of gross and net productive oil and natural gas wells and total gross and net developed and undeveloped oil

and natural gas acreage in which the group and its equity-accounted entities had interests as at 31 December 2025. A 'gross' well or acre is one in

which a whole or fractional working interest is owned, while the number of 'net' wells or acres is the sum of the whole or fractional working

interests in gross wells or acres. Productive wells are producing wells and wells capable of production. Developed acreage is the acreage within the

boundary of a field, on which development wells have been drilled, which could produce the reserves; while undeveloped acres are those on which

wells have not been drilled or completed to a point that would permit the production of commercial quantities, whether or not such acres contain

proved reserves.

---

| | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  | **Europe** | **Europe** | **North** <br>**America** | **North** <br>**America** | **South** <br>**America**<br>| **Africa**<br>**Asia** |  | **Australasia** | **Total**<sup>a</sup> |
|  |  | **UK** | **Rest of**<br>**Europe**<br>| **US** | **Rest of**<br>**North**<br>**America**<br>|  |  |  |  |  |
| **Number of productive wells at 31 December 2025** | **Number of productive wells at 31 December 2025** | **Number of productive wells at 31 December 2025** | **Number of productive wells at 31 December 2025** | **Number of productive wells at 31 December 2025** |  |  |  |  |  |  |
| Oil wells<sup>b</sup> | – gross | **120** | **126** | **973** | **8** | **4927** | **807** | **3004** | **—** | **9965** |
|  | – net | **69** | **20** | **631** | **2** | **2417** | **77** | **667** | **—** | **3883** |
| Gas wells<sup>c</sup> | – gross | **31** | **9** | **3819** | **—** | **1233** | **92** | **197** | **91** | **5472** |
|  | – net | **7** | **1** | **2163** | **—** | **402** | **41** | **74** | **22** | **2710** |
| **Oil and natural gas acreage at 31 December 2025** | **Oil and natural gas acreage at 31 December 2025** | **Oil and natural gas acreage at 31 December 2025** | **Oil and natural gas acreage at 31 December 2025** | **Oil and natural gas acreage at 31 December 2025** |  |  |  |  | thousands of acres | thousands of acres |
| Developed | – gross | **72** | **83** | **1504** | **8** | **1242** | **626** | **1355** | **838** | **5727** |
|  | – net | **44** | **13** | **972** | **2** | **370** | **125** | **286** | **157** | **1969** |
| Undeveloped<sup>d</sup> | – gross | **434** | **2257** | **3771** | **9237** | **9950** | **21019** | **10641** | **7998** | **65308** |
|  | – net | **339** | **358** | **3253** | **6193** | **4801** | **8408** | **5805** | **3364** | **32521** |

---

aBecause of rounding, some totals may not exactly agree with the sum of their component parts.

bIncludes approximately 169 gross (32 net) multiple completion wells (more than one formation producing into the same well bore).

cIncludes approximately 11 gross (5 net) multiple completion wells. If one of the multiple completions in a well is an oil completion, the well is classified as an oil well.

dUndeveloped acreage includes leases and concessions.

**Net oil and gas wells completed or abandoned**

The following table shows the number of net productive and dry exploratory and development oil and natural gas wells completed or abandoned in

the years indicated by the group and its equity-accounted entities. Productive wells include wells in which hydrocarbons were encountered and the

drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well is one found

to be incapable of producing hydrocarbons in sufficient quantities to justify completion.

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | **Europe** | **Europe** | **North** <br>**America** | **North** <br>**America** | **South** <br>**America**<br>| **Africa** | **Asia** | **Australasia** | **Total**<sup>a</sup> |
|  | **UK** | **Rest of**<br>**Europe**<br>| **US** | **Rest of**<br>**North**<br>**America**<br>|  |  |  |  |  |
| **2025** |  |  |  |  |  |  |  |  |  |
| **Exploratory** |  |  |  |  |  |  |  |  |  |
| Productive | **—** | **0.3** | **0.6** | **—** | **2.9** | **2.7** | **0.4** | **—** | **6.9** |
| Dry | **—** | **0.6** | **0.3** | **—** | **1.0** | **—** | **0.6** | **—** | **2.6** |
| **Development** |  |  |  |  |  |  |  |  |  |
| Productive | **4.4** | **0.3** | **172.2** | **—** | **68.5** | **6.1** | **51.4** | **0.2** | **303.0** |
| Dry | **—** | **—** | **4.9** | **—** | **0.6** | **0.4** | **1.2** | **—** | **7.1** |
| 2024 |  |  |  |  |  |  |  |  |  |
| Exploratory |  |  |  |  |  |  |  |  |  |
| Productive |  |  | 0.7 |  | 0.5 | 0.4 | 0.7 |  | 2.3 |
| Dry |  |  | 1.0 | 0.8 | 0.5 |  | 0.5 |  | 2.8 |
| Development |  |  |  |  |  |  |  |  |  |
| Productive | 1.5 | 0.5 | 149.0 |  | 69.3 | 2.5 | 55.1 |  | 277.8 |
| Dry |  |  | 15.0 |  |  | 1.1 | 0.5 |  | 16.6 |
| 2023 |  |  |  |  |  |  |  |  |  |
| Exploratory |  |  |  |  |  |  |  |  |  |
| Productive |  |  | 2.0 |  |  |  | 0.8 | 0.4 | 3.2 |
| Dry | 0.5 |  | 0.8 | 0.5 |  |  | 0.2 |  | 2.0 |
| Development |  |  |  |  |  |  |  |  |  |
| Productive<sup>b</sup> | 2.6 | 0.6 | 141.9 | 0.1 | 85.2 | 4.2 | 39.7 | 0.4 | 274.7 |
| Dry |  |  |  |  |  |  | 0.4 |  | 0.4 |

---

aBecause of rounding, some totals may not exactly agree with the sum of their component parts.

bIncludes correction of 2023 productive wells

---

| | |
|:---|:---|
| 268 | bp Annual Report and Form 20-F 2025 |

---

**Operational and statistical information – continued**

**Drilling and production activities in progress**

The following table shows the number of exploratory and development oil and natural gas wells in the process of being drilled by the group and its

equity-accounted entities as of 31 December 2025. Suspended development wells and long-term suspended exploratory wells are also included in

the table.

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | **Europe** | **Europe** | **North** <br>**America** | **North** <br>**America** | **South** <br>**America**<br>| **Africa**<br>**Asia** |  | **Australasia** | **Total**<sup>a</sup> |
|  | **UK** | **Rest of**<br>**Europe**<br>| **US** | **Rest of**<br>**North**<br>**America**<br>|  |  |  |  |  |
| **At 31 December 2025** |  |  |  |  |  |  |  |  |  |
| **Exploratory** |  |  |  |  |  |  |  |  |  |
| Gross | **—** | **—** | **—** | **—** | **2.0** | **1.0** | **1.0** | **—** | **4.0** |
| Net | **—** | **—** | **—** | **—** | **0.8** | **0.5** | **0.1** | **—** | **1.4** |
| **Development** |  |  |  |  |  |  |  |  |  |
| Gross | **3.0** | **9.5** | **49.0** | **—** | **29.0** | **14.0** | **63.0** | **—** | **167.5** |
| Net | **1.8** | **1.5** | **36.4** | **—** | **11.3** | **1.8** | **21.3** | **—** | **74.1** |

---

aBecause of rounding, some totals may not exactly agree with the sum of their component parts.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 269 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Financial statements** |

---

Pages 269-333 have been removed as they do not form part of bp's Annual Report on Form 20-F as filed with the SEC.

---

| | | |
|:---|:---|:---|
| 334 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

---

| | |
|:---|:---|
| **Additional disclosures** |  |
| Additional information | **[335](#i0dd2ee81aac04f8c9c97c86197f0c6df_478)** |
| Liquidity and capital resources | **[338](#i0dd2ee81aac04f8c9c97c86197f0c6df_484)** |
| Oil and gas disclosures for the group | **[340](#i0dd2ee81aac04f8c9c97c86197f0c6df_490)** |
| Additional information for customers & <br>products | **[350](#i0dd2ee81aac04f8c9c97c86197f0c6df_493)** |
| Environmental expenditure | **[352](#i0dd2ee81aac04f8c9c97c86197f0c6df_499)** |
| Regulation of the group's business | **[352](#i0dd2ee81aac04f8c9c97c86197f0c6df_502)** |
| International trade sanctions | **[358](#i0dd2ee81aac04f8c9c97c86197f0c6df_508)** |
| Material contracts | **[358](#i0dd2ee81aac04f8c9c97c86197f0c6df_511)** |
| Property, plant and equipment | **[359](#i0dd2ee81aac04f8c9c97c86197f0c6df_514)** |
| Related party transactions | **[359](#i0dd2ee81aac04f8c9c97c86197f0c6df_517)** |
| Corporate governance practices | **[359](#i0dd2ee81aac04f8c9c97c86197f0c6df_520)** |
| Code of ethics | **[360](#i0dd2ee81aac04f8c9c97c86197f0c6df_523)** |
| Controls and procedures | **[360](#i0dd2ee81aac04f8c9c97c86197f0c6df_526)** |
| Cyber security | **[360](#i0dd2ee81aac04f8c9c97c86197f0c6df_529)** |
| Principal accountant's fees and services | **[361](#i0dd2ee81aac04f8c9c97c86197f0c6df_532)** |
| Additional Directors' report disclosures | **[361](#i0dd2ee81aac04f8c9c97c86197f0c6df_535)** |
| Disclosures required under Listing Rule 6.6.1R | **[362](#i0dd2ee81aac04f8c9c97c86197f0c6df_538)** |
| Cautionary statement | **[362](#i0dd2ee81aac04f8c9c97c86197f0c6df_541)** |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 335 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Additional disclosures** |

---

Additional information

**Capital expenditure**★

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| Capital expenditure |  |  |  |
| Organic capital expenditure★ | **13613** | 16135 | 14998 |
| Inorganic capital expenditure<sup>ab</sup>★ | **920** | 102 | 1255 |
|  | **14533** | 16237 | 16253 |
| Capital expenditure by segment |  |  |  |
| gas & low carbon energy<sup>ac</sup> | **3410** | 5842 | 4773 |
| oil production & operations | **6760** | 6198 | 6278 |
| customers & products<sup>abc</sup> | **4071** | 3789 | 4761 |
| other businesses & corporate | **292** | 408 | 441 |
|  | **14533** | 16237 | 16253 |
| Capital expenditure by geographical area |  |  |  |
| US | **6129** | 6566 | 8105 |
| Non-US | **8404** | 9671 | 8148 |
|  | **14533** | 16237 | 16253 |

---

a2025 includes the final payment for the bp Bunge Bioenergia acquisition. 2024 includes the cash acquired net of acquisition payments on completion of the bp Bunge Bioenergia and Lightsource

bp acquisitions.

b2023 includes $1.1 billion in respect of the TravelCenters of America acquisition.

c2024 and 2023 have been restated to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment.

---

| | | |
|:---|:---|:---|
| 336 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Adjusting items**

Adjusting items are items that bp discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are

items that management considers to be important to period-on-period analysis of the group's results and are disclosed in order to enable investors

to better understand and evaluate the group's reported financial performance. An analysis of adjusting items is shown in the table below.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| gas & low carbon energy |  |  |  |
| Gain on sale of businesses and fixed assets<sup>a</sup> | **258** | 297 | 19 |
| Net impairment and losses on sale of businesses and fixed assets<sup>ab</sup> | **(4448)** | (3521) | (2221) |
| Environmental and related provisions | **—** |  |  |
| Restructuring, integration and rationalization costs<sup>c</sup> | **(2)** | (25) |  |
| Fair value accounting effects<sup>de</sup>★ | **1270** | (1550) | 8859 |
| Other<sup>f</sup> | **(1115)** | 1048 | (1299) |
|  | **(4037)** | (3751) | 5358 |
| oil production & operations |  |  |  |
| Gain on sale of businesses and fixed assets<sup>a</sup> | **407** | 144 | 297 |
| Net impairment and losses on sale of businesses and fixed assets<sup>a</sup> | **(552)** | (790) | (1819) |
| Environmental and related provisions | **(268)** | 5 | 54 |
| Restructuring, integration and rationalization costs<sup>c</sup> | **(67)** | (15) | (1) |
| Fair value accounting effects | **—** |  |  |
| Other<sup>g</sup> | **(376)** | (492) | (121) |
|  | **(856)** | (1148) | (1590) |
| customers & products |  |  |  |
| Gain on sale of businesses and fixed assets<sup>a</sup> | **317** | 190 | 44 |
| Net impairment and losses on sale of businesses and fixed assets<sup>abh</sup> | **(1030)** | (2600) | (1757) |
| Environmental and related provisions | **(68)** | (99) | (97) |
| Restructuring, integration and rationalization costs<sup>c</sup> | **(241)** | (123) |  |
| Fair value accounting effects<sup>e</sup> | **(207)** | (81) | (86) |
| Other<sup>i</sup> | **57** | (847) | (287) |
|  | **(1172)** | (3560) | (2183) |
| other businesses & corporate |  |  |  |
| Gain on sale of businesses and fixed assets<sup>a</sup> | **5** | 39 | 1 |
| Net impairment and losses on sale of businesses and fixed assets<sup>a</sup> | **(5)** | (19) | (41) |
| Environmental and related provisions<sup>j</sup> | **(320)** | (87) | (604) |
| Restructuring, integration and rationalization costs<sup>c</sup> | **(210)** | (59) | 38 |
| Fair value accounting effects<sup>e</sup> | **1157** | (221) | 630 |
| Gulf of America oil spill | **(31)** | (51) | (57) |
| Other | **12** | 18 | (4) |
|  | **608** | (380) | (37) |
| Total before interest and taxation | **(5457)** | (8839) | 1548 |
| Finance costs<sup>k</sup> | **(428)** | (505) | (405) |
| Total before taxation | **(5885)** | (9344) | 1143 |
| Taxation on adjusting items<sup>lm</sup> | **246** | 1495 | 972 |
| Taxation – tax rate change effect<sup>n</sup> | **(774)** | (316) | 232 |
| Total after taxation<sup>o</sup> | **(6413)** | (8165) | 2347 |

---

aSee Financial statements – Note 4 for further information.

b2024 has been restated for material items to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment.

cRestructuring charges are classified as adjusting items where they relate to an announced major group restructuring. A major group restructuring is a restructuring programme affecting more

than one of the group's operating segments that is expected to result in charges of more than $1 billion over a defined period. 2024 includes charges for provisions arising from the groups

transformation project that was announced on 16 January 2024.

dUnder IFRS bp marks-to-market the value of the hedges used to risk-manage LNG contracts, but not the contracts themselves, resulting in a mismatch in accounting treatment. The fair value

accounting effect includes the change in value of LNG contracts that are being risk-managed, and the underlying result reflects how bp risk-manages its LNG contracts.

eFor further information, including the nature of fair value accounting effects reported in each segment, see page [379](#ic1bd6a858b574c36a4546a99df7ac8f6_70132).

f2025 includes $1,082 million of impairment charges recognized through equity-accounted earnings primarily relating to the Archaea Energy and offshore wind businesses. 2024 includes a $508

million gain relating to the remeasurement of bp's pre-existing 49.97% interest in Lightsource bp, and $498 million relating to the remeasurement of certain US assets excluded from the

Lightsource bp acquisition (see Note 3 for further information). 2023 includes $1,140 million of impairment charges recognized through equity-accounted earnings relating to our US offshore wind

projects.

g2024 includes $429 million of impairment charges recognized through equity-accounted earnings relating to our interest in Pan American Energy Group.

hFor 2024, see Financial statements – Note 2 for further information.

i2024 includes recognition of onerous contract provisions related to the Gelsenkirchen refinery. The unwind of these provisions will be reported as an adjusting item as the contractual obligations

are settled.

j2023 primarily relates to charges related to the control, abatement, clean-up or elimination of environmental pollution and legal settlements.

kAll periods presented include the unwinding of discounting effects relating to Gulf of America oil spill payables and the income statement impact of temporary valuation differences related to

the group's interest rate and foreign currency exchange risk management associated with finance debt. 2025 and 2024 include the unwinding of discounting effects relating to certain onerous

contract provisions. 2023 includes the income statement impact associated with the buyback of finance debt.

lAll periods include certain foreign exchange effects on tax as adjusting items. These amounts represent the impact of: (i) foreign exchange on deferred tax balances arising from the conversion of

local currency tax base amounts into functional currency; and (ii) taxable gains and losses from the retranslation of US dollar-denominated intra-group loans to local currency.

m2025 includes limited tax relief on impairment charges and the impact of the reassessment of the recognition of deferred tax assets.

nAll periods include revisions to the deferred tax impact of the introduction of the UK Energy Profits Levy (EPL) on temporary differences existing at the opening balance sheet date. The EPL

increases the headline rate of tax on taxable profits from bp's North Sea business to 78%. In 2025 a two-year extension of the EPL to 31 March 2030 was substantively enacted. 2025 also includes

the deferred tax impact of a change in the tax rate in Germany. See Note 1 for further information.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 337 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Additional disclosures** |

---

o2023 includes a $146-million charge for the EU Solidarity Contribution.

**Non-IFRS information on fair value accounting effects**

The impacts of fair value accounting effects, relative to management's internal measure of performance, are set out below. Further information on

fair value accounting effects is provided on page <u>[379](#ic1bd6a858b574c36a4546a99df7ac8f6_70132)</u>.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| gas & low carbon energy |  |  |  |
| Unrecognized (gains) losses brought forward from previous period | **(2674)** | (1125) | (9960) |
| Favourable (adverse) impact relative to management's measure of performance | **1270** | (1550) | 8859 |
| Exchange translation gains (losses) on fair value accounting effects | **(5)** | 1 | (24) |
| Unrecognized (gains) losses carried forward | **(1409)** | (2674) | (1125) |
| customers & products |  |  |  |
| Unrecognized (gains) losses brought forward from previous period | **(96)** | (17) | 79 |
| Favourable (adverse) impact relative to management's measure of performance | **(207)** | (81) | (86) |
| Exchange translation gains (losses) on fair value accounting effects | **—** | 2 | (10) |
| Unrecognized (gains) losses carried forward | **(303)** | (96) | (17) |
| other businesses & corporate |  |  |  |
| Unrecognized (gains) losses brought forward from previous period | **(1146)** | (925) | (1555) |
| Favourable (adverse) impact relative to management's measure of performance<sup>a</sup> | **1157** | (221) | 630 |
| Unrecognized (gains) losses carried forward | **11** | (1146) | (925) |
| Group |  |  |  |
| Unrecognized (gains) losses brought forward from previous period | **(3916)** | (2067) | (11436) |
| Favourable (adverse) impact relative to management's measure of performance | **2220** | (1852) | 9403 |
| Exchange translation gains (losses) on fair value accounting effects | **(5)** | 3 | (34) |
| Unrecognized (gains) losses carried forward | **(1701)** | (3916) | (2067) |
| Favourable (adverse) impact relative to management's measure of performance – by region |  |  |  |
| gas & low carbon energy |  |  |  |
| US | **376** | (582) | 900 |
| Non-US | **894** | (968) | 7959 |
|  | **1270** | (1550) | 8859 |
| customers & products |  |  |  |
| US | **(58)** | (214) | (18) |
| Non-US | **(149)** | 133 | (68) |
|  | **(207)** | (81) | (86) |
| other businesses & corporate |  |  |  |
| US | **—** |  |  |
| Non-US | **1157** | (221) | 630 |
|  | **1157** | (221) | 630 |
|  | **2220** | (1852) | 9403 |
| Taxation credit (charge) | **(206)** | 325 | (915) |
|  | **2014** | (1527) | 8488 |

---

aIncludes changes in the fair value of derivatives entered into by the group to manage currency exposure and interest rate risks relating to hybrid bonds to their respective first call periods. For

further information see page [379](#ic1bd6a858b574c36a4546a99df7ac8f6_70132).

**Net debt including leases**

Net debt including leases★ is shown in the table below.

---

| | | |
|:---|:---|:---|
|  |  | $ million |
| At 31 December | **2025** | 2024 |
| Net debt<sup>a</sup>★ | **22182** | 22997 |
| Lease liabilities | **14571** | 12000 |
| Net partner (receivable) payable for leases entered into on behalf of joint operations★ | **(1067)** | (88) |
| Net debt including leases | **35686** | 34909 |
| Total equity | **74000** | 78318 |
| Gearing including leases★ | **32.5%** | 30.8% |

---

aSee Financial statements – Note 27 for a reconciliation of net debt to finance debt, which is the nearest equivalent measure to net debt on an IFRS basis.

---

| | | |
|:---|:---|:---|
| 338 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

Liquidity and capital resources

**Financial framework** 

The financial framework sets out how we allocate the cash we generate

to deliver dividends to shareholders, strengthen our balance sheet and

invest with discipline to grow the value of bp.

A resilient dividend is our first capital allocation priority. Based on our

current forecasts and subject to the board's discretion each quarter, the

dividend is expected to increase by at least 4% per ordinary share a

year.

Net debt★ at 31 December 2025 was $22.2 billion<sup>a</sup> and is expected to

reduce over time to a targeted range of $14-18 billion by the end of 2027,

reflecting the full allocation of excess cash★ to the balance sheet, in

service of optimizing financing costs and to accelerate strengthening of

the balance sheet. bp is committed to strengthening the balance sheet

and we continue to target improving our credit metrics within an 'A'

grade credit range.

When considering our capital structure; we also look at other

instruments including hybrid bonds and securities or obligations such

as leases and Gulf of America settlement liabilities. At year-end 2025,

the total net debt, hybrid bonds and securities, leases and Gulf of

America settlement liabilities was $57.8 billion.

Capital expenditure in 2025 was $14.5 billion, including $0.9 billion of

inorganic capital expenditure★. We expect capital expenditure of

around $13.0-13.5 billion in 2026 including inorganic expenditure. We

believe this level of capital expenditure supports progressively growing

earnings per ordinary share in the long term. Within this frame we are

allocating capital to our highest returning opportunities across the

portfolio.

In 2025 the return on average capital employed★ was 13.9%<sup>b</sup> at an

average of $69 per barrel. The return on average capital employed is

targeted to be over 16%<sup>c</sup> in 2027 at $70 per barrel in 2024 real terms,

and assuming bp planning assumptions, as we execute our reset

strategy. This is supported by a target compound annual growth rate in

adjusted free cash flow★ of over 20%<sup>c</sup> from 2024 to 2027 and subject to

the same price and planning assumptions.

aThe nearest equivalent IFRS measure is finance debt at the end of 2025 of $58.0 billion.

bThe nearest equivalent IFRS measures of numerator and denominator are profit for the year

attributable to bp shareholders for 2025 of $0.1 billion and total equity at the end of 2025 of

$74.0 billion respectively. Profit for attributable to bp shareholders divided by total equity at

31 December 2025 was 0.1%.

cThis is on a price adjusted basis and is assuming a hypothetical price environment of $70/bbl

Brent, $4/mmBtu Henry Hub, and $10.3/bbl refining indicator margin (all 2024 real) and

assumptions about the impact of these marker prices on underlying replacement cost profit

before tax.

**Distributions to shareholders**

The dividend is determined in US dollars, the economic currency of bp,

and the dividend level is reviewed by the board each quarter. The

quarterly dividend was increased from 8.000 to 8.320 cents per

ordinary share per quarter in the second quarter of 2025.

The total dividend distributed to bp shareholders in 2025 was $5.1 billion

(2024 $5.0 billion). This dividend was all paid in cash to shareholders.

Based on our current forecasts and subject to the board's discretion

each quarter, the dividend is expected to increase by at least 4% per

ordinary share a year.

At the fourth quarter 2025 results in February 2026, the board decided

to suspend share buybacks; excess cash is now fully allocated to the

balance sheet, in service of optimizing financing costs and

strengthening the balance sheet.

In 2025 bp executed $4.5 billion of share buybacks (2024 $7.1 billion),

including fees and stamp duty. Since 1 January 2026 an additional

$450 million shares have been repurchased up to 13 February 2026,

including fees and stamp duty.

**Financing the group's activities**

The group's principal commodities, oil and gas, are priced

internationally in US dollars. Group policy has generally been to

minimize economic exposure to currency movements by financing

operations with US dollar debt. Where debt and hybrid bonds are issued

in other currencies, they are generally swapped back to US dollars using

derivative contracts, or else hedged by maintaining offsetting cash

positions in the same currency. Cash balances of the group are mainly

held in US dollars or swapped to US dollars, and holdings are well

diversified to reduce concentration risk. The group is not, therefore,

exposed to significant currency risk regarding its cash or borrowings.

Also see Risk factors on page <u>[67](#i0dd2ee81aac04f8c9c97c86197f0c6df_109)</u> for further information on risks

associated with prices and markets, and Financial statements – Note 29.

The group's finance debt at 31 December 2025 amounted to $58.0

billion (2024 $59.5 billion). Of the total finance debt, $3.4 billion is

classified as short term at the end of 2025 (2024 $4.5 billion). See

Financial statements – Note 26 for more information on the short-term

balance. Net debt was $22.2 billion at the end of 2025, a decrease of

$0.8 billion from the 2024 year-end position of $23.0 billion. BP p.l.c.

fully and unconditionally guarantees securities issued by BP Capital

Markets p.l.c. and BP Capital Markets America Inc., which are 100%-

owned finance subsidiaries of BP p.l.c.

At 31 December 2025 the group held a balance of $16.0 billion (2024

$16.6 billion) issued perpetual subordinated hybrid instruments

consisting of $13.5 billion (2024 $14.6 billion) hybrid bonds and $2.5

billion (2024 $2.0 billion) hybrid securities. Proceeds from hybrid

securities are typically earmarked to fund specific project or investment

activities. As the group has the unconditional right to avoid transfer of

cash or another financial asset in relation to these hybrid instruments,

which were issued by group subsidiaries, they are classified as equity

instruments and reported within non-controlling interest.

The ratio of finance debt to finance debt plus total equity at

31 December 2025 was 43.9% (2024 43.2%). Gearing was 23.1% at the

end of 2025 (2024 22.7%). See Financial statements – Note 27 for finance

debt, which is the nearest equivalent measure on an IFRS basis, and for

further information on net debt.

Cash and cash equivalents of $36.6 billion at 31 December 2025 (2024

$39.2 billion) are included in net debt. We manage our cash position so

that the group has adequate cover to respond to potential short-term

market liquidity, short-term price environment volatility, and expect to

maintain a robust cash position.

The group also has an undrawn committed $8 billion credit facility and

undrawn committed standby facilities of $4 billion (see Financial

statements – Note 29 for more information).

We believe that the group's resilient balance sheet and strong

investment grade credit rating will allow the group to meet its known

contractual and other obligations in both the short and long term with

the group having sufficient working capital, taking into account the

amounts of undrawn borrowing facilities, access to capital markets,

levels of cash and cash equivalents and its ongoing ability to generate

cash through operations. This belief is subject to a degree of

uncertainty that can be expected to increase looking out over time and,

accordingly, that future outcomes cannot be guaranteed or predicted

with certainty.

bp utilizes various arrangements in order to manage its working capital

including discounting of receivables and, in the supply and trading

business, the active management of supplier payment terms, inventory

and collateral.

Standard & Poor's Ratings' long-term credit rating for BP p.l.c. is A-

(stable), the Moody's Investors Service rating is A1 (stable) and the Fitch

Ratings' long-term credit rating is A+ (stable).

The group's sources of funding, its access to capital markets and

maintaining a strong cash position are described in Financial

statements – Note 25 and Note 29. Further information on the

management of liquidity risk and credit risk, and the maturity profile

and fixed/floating rate characteristics of the group's debt are also

provided in Financial statements – Note 26 and Note 29.

**The information above contains forward-looking statements, which by** 

**their nature involve risk and uncertainty because they relate to events** 

**and depend on circumstances that will or may occur in the future and** 

**are outside the control of bp. You are urged to read the Cautionary** 

**statement on page <u>[362](#i0dd2ee81aac04f8c9c97c86197f0c6df_541)</u> and Risk factors on page <u>[67](#i0dd2ee81aac04f8c9c97c86197f0c6df_109)</u>, which describe the** 

---

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| bp Annual Report and Form 20-F 2025 | 339 |

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| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Additional disclosures** |

---

**risks and uncertainties that may cause actual results and** 

**developments to differ materially from those expressed or implied by** 

**these forward-looking statements.**

**Off-balance sheet arrangements**

At 31 December 2025, the group's share of third-party finance debt and

lease liabilities of equity-accounted entities was $10.8 billion (2024 $8.0

billion). These amounts are not reflected in the group's debt on the

balance sheet. The group has issued third-party guarantees under

which amounts outstanding, incremental to amounts recognized on the

balance sheet at 31 December 2025, were $708 million (2024 $655

million) in respect of liabilities of joint ventures★ and associates★ and

$659 million (2024 $585 million) in respect of liabilities of other third

parties. Of these amounts, $708 million (2024 $655 million) of the joint

ventures and associates guarantees relate to borrowings and, for other

third-party guarantees, $408 million (2024 $430 million) relate to

guarantees of borrowings.

**Contractual obligations**

The following table summarizes the group's capital expenditure

commitments for property, plant and equipment at 31 December 2025

and the proportion of that expenditure for which contracts have been

placed.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  |  | Payments due by period | Payments due by period |
| Capital expenditure | Less than 1 <br>year<br>| More than 1 <br>year<br>| Total |
| Committed | 13049 | 16724 | 29773 |
| of which is contracted | 7517 | 7122 | 14639 |

---

Capital expenditure is considered to be committed when the project

has received the appropriate level of internal management approval.

For joint operations★, the net bp share is included in the amounts

above.

In addition, at 31 December 2025 the group had committed to capital

expenditure relating to investments in equity-accounted entities

amounting to $2,896 million. Contracts were in place for $2,327 million

of this total.

The following table summarizes the group's principal contractual

obligations at 31 December 2025, distinguishing between those for

which a liability is recognized on the balance sheet and those for which

no liability is recognized. See Financial framework above for bp's

approach to capital allocation and Financing the group's activities

above for bp's plan and ability to generate and obtain cash in the short

and long term. Also see Financial statements – Note 23 for more

information on provisions, Note 24 on pensions and other post-

employment benefits, Note 26 on borrowings, Note 28 on leases, Note

29 and Note 30 on derivatives and financial instruments.

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  |  | Payments due by period | Payments due by period |
| Expected payments by period under <br>contractual obligations<br>| Less than 1 <br>year<br>| More than 1 <br>year<br>| Total |
| Balance sheet obligations |  |  |  |
| Borrowings<sup>a</sup> | 5539 | 65604 | 71143 |
| Lease liabilities<sup>b</sup> | 3596 | 15740 | 19336 |
| Decommissioning liabilities<sup>c</sup> | 812 | 23759 | 24571 |
| Environmental liabilities<sup>c</sup> | 318 | 1611 | 1929 |
| Gulf of America oil spill <br>liabilities<sup>d</sup><br>| 1533 | 6834 | 8367 |
| Pensions and other post-<br>employment benefits<sup>e</sup><br>| 490 | 11864 | 12354 |
|  | 12288 | 125412 | 137700 |
| Off-balance sheet obligations |  |  |  |
| Unconditional purchase <br>obligations<sup>f</sup><br>|  |  |  |
| Crude oil and oil products | 48271 | 2689 | 50960 |
| Natural gas and LNG | 16685 | 50880 | 67565 |
| Chemicals and other refinery <br>feedstocks<br>| 1290 | 1695 | 2985 |
| Power | 6693 | 13802 | 20495 |
| Utilities | 56 | 324 | 380 |
| Transportation | 1993 | 14118 | 16111 |
| Use of facilities and services | 3124 | 16762 | 19886 |
|  | 78112 | 100270 | 178382 |
| Total | 90400 | 225682 | 316082 |

---

aExpected payments include interest totalling $18,214 million (less than 1 year $2,227 million,

more than 1 year $15,987 million).

bExpected payments include interest totalling $4,765 million (less than 1 year $728 million,

more than 1 year $4,037 million).

cThe amounts presented are undiscounted.

dThe amounts presented are undiscounted. Gulf of America oil spill liabilities are included in

the group balance sheet, on a discounted basis, within other payables. See Financial

statements – Note 22 for further information.

eRepresents the expected future contributions to funded pension plans and payments by the

group for unfunded pension plans, and the expected future payments for other post-

employment benefits.

fRepresents any agreement to purchase goods or services that is enforceable and legally

binding and that specifies all significant terms (such as fixed or minimum purchase volumes,

timing of purchase and pricing provisions). Agreements that do not specify all significant

terms, or that are not enforceable, are excluded. The amounts shown include arrangements

to secure long-term access to supplies of crude oil, natural gas, feedstocks and pipeline

systems. In addition, the amounts shown for 2026 include purchase commitments existing at

31 December 2025 entered into principally to meet the group's short-term manufacturing and

marketing requirements. The price risk associated with these crude oil, natural gas and power

contracts is discussed in Financial statements – Note 29.

**Commitments for the delivery of oil and gas**

We sell crude oil, natural gas and liquefied natural gas under a variety of

contractual obligations. Some of these contracts specify the delivery of

fixed and determinable quantities. For the period from 2026 to 2028

worldwide, we are contractually committed to deliver approximately

288 million barrels of oil, 6,288 billion cubic feet of natural gas, and

70Mt of liquefied natural gas. The commitments principally relate to

group subsidiaries★ based in Azerbaijan, Oman, Trinidad and Tobago,

the UK and the US. We expect to fulfil these delivery commitments with

production from our proved developed reserves and supplies from

existing contracts, supplemented by market purchases as necessary.

---

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|:---|:---|:---|
| 340 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

Oil and gas disclosures for the group

**Analysis by region**

Our oil and gas operations are set out below by geographical area, with

associated significant events for 2025. bp's percentage working

interest in oil and gas assets is shown in brackets. Working interest is

the cost-bearing ownership share of an oil or gas lease. Consequently,

the percentages disclosed for certain agreements do not necessarily

reflect the percentage interests in proved reserves, production or

revenue.

In addition to exploration, development and production activities, our oil

production & operations (OP&O) and gas businesses also include

certain midstream and liquefied natural gas (LNG) supply activities.

Midstream activities involve the management of crude oil and natural

gas pipelines, processing facilities and export terminals, LNG

processing facilities and transportation, and our natural gas liquids

(NGLs) processing business.

Our upstream LNG production activities are located in Abu Dhabi,

Angola, Australia, Indonesia, Mauritania and Senegal and Trinidad and

Tobago. In 2025 our production was 12 million tonnes (Mt) of LNG from

these assets, of which 5.2Mt were optimized and delivered through

supply, trading and shipping (ST&S), which supplements equity

production with merchant third-party volumes leading to a global long-

term strategic LNG portfolio of 26.8Mtpa. In addition to the long-term

equity and merchant supply portfolio, bp delivered 14.7Mtpa in 2025 of

incremental merchant volumes through short and mid-term cargoes

managed through the ST&S LNG business. These supplement the long-

term portfolio and allow generation of short-term value when

opportunities exist.

The LNG is marketed through contractual rights to access import

terminal capacity in the liquid markets of Europe and UK, and

relationships to market directly to end-user customers or trading

entities. LNG is supplied to all major LNG demand centres for example

Argentina, Bangladesh, Brazil, Caribbean, China, Croatia, Iberia and

North West Europe, India, Japan, Mediterranean, Philippines, Singapore,

South Korea, Taiwan, Thailand, Türkiye and the UK.

**Europe**

bp has interest in offshore oil and gas activities in the UK and Norway. In

2025 bp's UK production came from two key areas: the Shetland area

comprising the Clair and Schiehallion fields; and the central area

comprising the Andrew area, Culzean, Vorlich and ETAP fields. In

Norway, production was through our equity-accounted 15.9% interest in

Aker BP.

• Aker BP achieved its strongest exploration year since 2010,

highlighted by three major 2025 discoveries: the Lofn and

Langemann gas and condensate find near Sleipner, the large Omega

Alfa oil discovery in the Yggdrasil area and the Kjøttkake oil and gas

discovery in the Northern North Sea.

• In October bp agreed to sell its 32% non-operated working interest

in the Culzean development in the central North Sea to Serica

Energy. The sale was subject to a pre-emption period of 30 days,

with each of the Culzean field partners (TotalEnergies, 49.99%, and

NEO NEXT, 18.01%) having the option to acquire bp's stake on the

same terms as those agreed by Serica. In November NEO NEXT

exercised its preemption rights and acquired bp's working interest

on the conditions agreed with Serica. The deal completed in

December.

• In October bp announced it had safely started up production from

the Murlach field in the UK North Sea. The two-well subsea tieback is

expected to add a peak net production of around 15,000 barrels of

oil equivalent per day.

**North America**

Our oil and gas activities in North America are located in four areas:

deepwater Gulf of America, the Lower 48 states, Canada and Mexico.

bp has around 300 lease blocks in the Gulf of America and operates five

production hubs.

• In April bp announced an oil discovery at the Far South prospect in

the deepwater US Gulf of America. Both the initial well and a

subsequent sidetrack encountered oil in high-quality Miocene

reservoirs. Preliminary data supports a potentially commercial

volume of hydrocarbons.

• In August bp announced the start-up of the Argos Southwest

Extension project in the Gulf of America. The project consists of

three wells and a new drill centre tied back to the Argos platform and

is expected to add 20,000 barrels of oil equivalent per day of gross

peak annualized average production. bp is operator of Argos with

60.5% working interest, with co-owners Woodside Energy (23.9%)

and Union Oil Company of California, an affiliate of Chevron U.S.A.

Inc. (15.6%).

• In September bp announced it had reached a final investment

decision (FID) on the Tiber-Guadalupe project in the Gulf of America.

The 100% bp-owned Tiber-Guadalupe will be bp's seventh operated

oil and gas production hub in the Gulf of America, featuring a new

floating production platform with the capacity to produce 80,000

barrels of crude oil per day. The project includes six wells in the Tiber

field and a two-well tieback from the Guadalupe field. Production is

expected to start in 2030.

• In December bp was the apparent highest bidder on 51 lease blocks

in the US Gulf of America Federal Lease Sale BBG1, which included

219 leases.

• In December bp successfully delivered first oil from the Atlantis Drill

Center 1 expansion in the US Gulf of America. The two-well subsea

tieback to the existing Atlantis platform is expected to add

15,000boe/d gross peak annualized average production.

bpx energy, bp's onshore oil and gas business in the Lower 48 states,

has significant operated and non-operated activities across Louisiana

and Texas producing natural gas, oil, NGLs and condensate, with

primary focus on developing unconventional resources. It had a 1.8

billion boe proved reserve base at 31 December 2025, predominantly in

unconventional reservoirs (tight gas, shale gas and shale oil). bpx

energy's core assets span over 0.8 million net developed acres with

over 2,400 operated gross wells at 31 December 2025. Daily net

production averaged 466mboe/d in 2025.

bpx energy continues to operate as a separate business while

remaining part of the OP&O segment. With its own governance,

systems, and processes, it is structured to increase competitive

performance through swift decision making and innovation, while

maintaining bp's commitment to safe, reliable and compliant

operations.

• In June bpx energy started up the Crossroads facility in the Permian

Basin, bpx's fourth and final central delivery facility to be built,

following the earlier Grand Slam, Checkmate and Bingo facilities.

• In July bpx energy took over operations from Devon Energy of

certain assets in the Eagle Ford Shale following the April dissolution

of their joint venture in the Blackhawk field.

• In November and December bp completed a two-phase divestment

of non-controlling interests in Permian and Eagle Ford midstream

assets to investor Sixth Street for a total of $1.5 billion.

bp's onshore US crude oil and product pipelines and related

transportation assets were included in the customers & products

segment.

In Canada, bp is focused on pursuing offshore exploration and

development opportunities and conducts trading and marketing

activities across various energy commodities. We hold exploration and

significant discovery licenses in offshore Newfoundland and Labrador,

including an interest in the Equinor-operated Bay du Nord project. bp

also holds offshore exploration licenses in the Arctic, where the

moratorium has been extended until 31 December 2028.

In Mexico, bp holds interests in an exploration block in the Salina Basin

with Equinor and Total, Block 1 (bp 33% operator) and an exploration

block in the Sureste Basin, Block 34 (bp 42.5% operator), with Total, QPI

Mexico and Hokchi Energy. Hokchi Energy is a subsidiary of Pan

American Energy Group (PAEG, see below). bp holds 50% of PAEG and

PAEG holds 55% of Hokchi Energy. Separate to the above holdings in

Mexico, Hokchi Energy also holds an interest in two other blocks.

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| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 341 |

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| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Additional disclosures** |

---

Formal relinquishment of Block 1 and Block 34 licences is still pending

regulatory approval.

**South America**

bp has oil and gas activities in Brazil and Trinidad and Tobago and,

through PAEG, in Argentina and Bolivia.

In Brazil bp has interests in six exploration areas across three basins:

• Petrobras as the operator of Alto de Cabo Frio Central block (bp

50%) drilled an appraisal well completed in July, as part of the

appraisal plan (PAD) filed in 2023, with indication of hydrocarbon

shows. The block strategy is under development and will be finalized

following completion of post-well analyses, expected by end 2026.

• In June GNA II started commercial operation, a 1.7 gigawatts capacity

gas fired power plant, the largest in Brazil. bp is the exclusive LNG

supplier for GNA II and holds a 33.5% stake in the project alongside

Siemens Energy (33.5%) and SPIC Brazil (33%).

• In August bp announced an exploration discovery at the

Bumerangue prospect in the deepwater offshore Brazil. bp drilled

exploration well 1-BP-13-SPS at the Bumerangue block, located in the

Santos Basin, 404 kilometres (218 nautical miles) off the coast of

Brazil, in a water depth of 2,372 metres. bp holds a 100% participation

in the block with Pré-Sal Petróleo S.A. as the Production Sharing

Contract manager. bp secured the block in December 2022 during

the first cycle of the Open Acreage of Production Sharing of the

Brazilian national petroleum agency (ANP). bp is now putting plans in

place for an appraisal programme which is expected to start around

the end of the year. This will provide data from locations across the

reservoir, to enable us to describe the fluid characteristics and

resource potential.

PAEG, a joint venture that is owned by bp (50%) and BC E&P Uruguay

S.A. (50%), has activities mainly in Argentina and as noted above, Mexico,

and is also present in Bolivia.

In Trinidad and Tobago bp holds interests in exploration and production

licences and production-sharing contracts (PSCs)★ covering 2.1 million

acres offshore the east and north-east coast. Facilities include 12

offshore platforms, 3 subsea tiebacks and 2 onshore processing

facilities. Production comprises gas and associated liquids.

bp also holds interests in the Atlantic LNG facility. The total gross

capacity of the LNG facility is approximately 12Mtpa, with three trains in

operation. bp's shareholding averages 43% across the companies which

own the LNG trains comprising the LNG facility. Upon expiration of the

Train 4 contract on 1 May 2027, and completion of full restructuring bp's

shareholding will increase to 45%.

• In March FID was taken on the Ginger project which will become

bpTT's fourth subsea project and will include four subsea wells and

subsea trees tied back to bpTT's existing Mahogany B platform. First

gas from the project is expected in 2027.

• In May bp announced first gas from the Mento project. Mento is a

50:50 joint venture between EOG Resources Trinidad Ltd (EOG) and

bpTT, with EOG as the operator. The development features a 12-slot

attended facility that is located in acreage jointly licensed by bpTT

and EOG off Trinidad's south-east coast.

• In November bp announced that it had safely completed the Cypre

seven-well drilling programme in Trinidad, the second phase of the

Cypre project, following delivery of first gas in April 2025. Cypre is

bpTT's third subsea development. It comprises seven wells tied back

into bpTT's existing Juniper platform.

• bpTT and EOG are also currently working on the Coconut gas

development under a similar joint venture arrangement.

Construction is in progress with start-up expected in 2027.

• The seismic processing activity over the joint Manakin-Cocuina field

was successfully completed in September 2024. bp is operator of

the Manakin block which was discovered in 2000. bp and NGC also

hold an exploration and production licence for the development of

the Cocuina gas discovery, which is the Venezuelan portion of the

cross-border Manakin-Cocuina gas field. Activity ceased in April

2025 with the revocation of its specific OFAC license. In February

2026 General Licences 48, 49 and 50 were issued by OFAC which

authorized contractors and certain companies including bp plc and

its subsidiaries to progress with oil and gas projects in Venezuela. bp

is therefore authorized to progress with the development of the

Manakin-Cocuina project subject to the conditions contained in the

General Licences.

Seismic processing activity was completed and interpretation of results

underway on deepwater blocks Blocks 25a, 25b and 27 in Trinidad and

Tobago. These blocks are a 50:50 joint venture between bp and Shell,

with bp operating Blocks 25a and 25b, and Shell operating Block 27.

**Africa**

bp's oil and gas activities in Africa are located in Angola, Namibia, Egypt,

Libya, Mauritania and Senegal.

In Angola, bp and Eni each own a 50% interest in the Azule Energy

(Azule) joint venture. Azule is Angola's largest independent equity

producer of oil and gas, holding stakes in 18 licences, as well as an

interest in the Angola LNG plant.

• In July Azule, operator of Block 15/06 in Angola, together with its

partners, announced the successful start-up of the Agogo Integrated

West Hub Project, which aims to fully develop the Agogo and

Ndungu fields in Block 15/06.

• In July Azule, operator of Block 1/14, and its partners announced a

gas discovery at the Gajajeira-01 exploration well, located offshore in

the Lower Congo Basin, Angola. Initial assessments suggest gas

volumes in place could exceed 1 trillion cubic feet, with up to 100

million barrels of associated condensate.

• In October Rhino Resources, operator of the Petroleum Exploration

Licence 85 in the Orange Basin offshore Namibia, partnering with

Azule, announced a discovery at the Volans 1-X well. The well found

26 metres of net pay in rich-gas condensate bearing reservoirs with

excellent quality petrophysical properties and a high condensate to

gas ratio. This discovery builds on the announcement in April of a

discovery in the Capricornus 1-X exploration well in the same license

block.

• In December Azule announced the signing of a Sale and Purchase

Agreement (SPA) with a consortium of Etablissements Maurel &

Prom S.A. (M&P) and BW Energy (BWE) for the sale of Azule's

participating interest in offshore Blocks 14 and 14K located in the

Lower Congo Basin. Azule holds a 20% interest in Block 14 and a 10%

interest in Block 14K. The offshore blocks have been producing since

1999. Net working interest production to Azule from both the blocks

combined was 9600 barrels of oil per day in 2024. Completion of the

transaction is expected to occur mid-2026 and is subject to

customary adjustments and approvals by the partners and Angolan

authorities.

In Egypt, bp holds an investment in Nile Delta. Through its joint ventures

with Egyptian Natural Gas Holding Company (EGAS), Egyptian General

Petroleum Corporation (EGPC), International Egyptian Oil Company

(IEOC), Eni, the Pharaonic Petroleum Company (PhPC), ADNOC, and

through collaboration with Belayim Petroleum Company (Petrobel), bp

and its partners now produce more than 60% of Egypt's total gas

supply. In addition, bp owns interest in other exploration projects.

• In February bp successfully completed the drilling activity at the El

King-2 exploration well in the North King Mariout Offshore

Concession as part of its West Nile Delta (WND) drilling campaign

• Also in February bp announced the Raven Infills project in the West

Nile Delta (WND) had started production ahead of schedule. bp, the

operator, holds an 82.75% stake in the project, while Harbour Energy

owns the remaining 17.25%.

• In March bp announced successful completion of the El Fayoum-5

gas discovery well in the North Alexandria Offshore Concession. It is

planned to be tied-back to bp's operated WND Gas Development.

• In September bp announced the signing of a memorandum of

understanding (MoU) to evaluate opportunities for a five-well

programme at water depths ranging from 300 to 1,500 metres in the

Mediterranean Sea, offshore Egypt. Drilling operations are expected

to start in 2026.

• In January 2026 bp was awarded two offshore exploration

concessions in Egypt: North-East El Alamein Offshore and West El

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| 342 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

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Hammad Offshore, advancing our exploration portfolio and long-

term growth ambitions. The North-East El Alamein Offshore

Concession (bp 100% equity) covers 3,336km² near bp's West Nile

Delta assets. The West El Hammad Offshore Concession (Eni 75%

operator, bp 25%) covers 1,894km² in the East Nile Delta, also near

existing infrastructure.

In Libya, bp partners with the Libyan Investment Authority (LIA) and Eni

(operator) in an exploration and production-sharing agreement (EPSA)

to explore acreage in the onshore Ghadames and offshore Sirt basins

(bp 42.5%).

Exploration operations under the EPSA resumed in 2023, following the

period of force majeure between 2012 and 2022.

In Mauritania and Senegal, bp retains the exploitation licences in the

respective C8 and Saint Louis Offshore Profond blocks pertinent to the

Greater Tortue Ahmeyim (GTA) Unit cross-border development (bp

56.3%).

• In April bp announced that it had safely loaded the first cargo of LNG

for export from GTA.

**Asia**

bp has activities in Abu Dhabi, Azerbaijan, China, India, Indonesia, Iraq,

Kuwait and Oman.

In China, we have a 30% equity stake in the Guangdong LNG

regasification terminal and trunkline project (GDLNG) with a total

storage capacity of 640,000 cubic metres. bp also has 0.6Mtpa of

regasification capacity at GDLNG for up to 12 years starting from the

beginning of 2021. bp imports LNG from our global portfolio and

delivers regasified natural gas via the terminal to power plant and city

gas customers in Guangdong province under long-term sales contracts.

In May bp announced it had entered into a long-term LNG sale and

purchase agreement with Zhejiang Energy. Under the agreement, bp

will provide Zhejiang Energy with up to 1 million tonnes per annum of

LNG for over 10 years on a delivered ex-ship (DES) basis from bp's

diverse portfolio of LNG sources.

In Azerbaijan, bp operates two production-sharing agreements (PSAs)★,

Azeri-Chirag-Gunashli (ACG) (bp 30.37%) and Shah Deniz (SD) (bp

29.99%) and also holds a number of other exploration and development

licenses.

• In March bp announced it has agreed for Apollo-managed funds to

purchase a 25% non-controlling stake in BP Pipelines (TANAP)

Limited, the bp subsidiary that holds a 12% share in the Trans

Anatolian Natural Gas Pipeline (TANAP) that carries natural gas from

Azerbaijan across Türkiye, for consideration of approximately $1.0

billion. bp remains the controlling shareholder of BP Pipelines

(TANAP) Limited. A similar deal on purchase by Apollo of a 20% non-

controlling interest in BP Pipelines TAP Limited was completed in

2024. •In June bp and its partners, announced the FID for the new Shah

Deniz Compression project, the next stage of development of the

giant Shah Deniz gas field in the Azerbaijan sector of the Caspian

Sea.

• In June bp, State Oil Company of the Azerbaijan Republic (SOCAR)

and TPAO signed agreements enabling TPAO to join the PSA for the

Shafag-Asiman offshore block in the Azerbaijan sector of the

Caspian Sea. Following completion, bp and SOCAR each holds 35%,

while TPAO will hold 30% participating interest in the PSA.

• In June bp announced it had signed fully termed agreements with

SOCAR to acquire 35% participating interests and become the

operator of each of the Karabagh development block and the

Ashrafi-Dan Ulduzu-Aypara (ADUA) exploration area in the Azerbaijan

sector of the Caspian Sea.

• In December the development programme for the Karabagh field in

the Caspian Sea, offshore Azerbaijan, was approved by the

management committee (joint venture) and subsequently by SOCAR

as the State representative. Seismic acquisition commenced

thereafter.

Naftiran Intertrade Co Ltd (NICO), a subsidiary of the National Iranian Oil

Company, and LUKOIL Overseas Shah Deniz Limited, a subsidiary of

PJSC LUKOIL, hold a 10% and 19.99% participating interest respectively

in the Shah Deniz PSA. For information on the compliance of this project

with the EU, UK and US trade sanctions, see International trade

sanctions on page <u>[358](#i0dd2ee81aac04f8c9c97c86197f0c6df_508)</u>.

bp holds a 30.1% interest in and operates the Baku-Tbilisi-Ceyhan (BTC)

oil pipeline. The 1,768-kilometre pipeline transports oil from the ACG

oilfield and condensate from the Shah Deniz gas and condensate field in

the Caspian Sea, along with other third-party oil, to the eastern

Mediterranean port of Ceyhan. The pipeline has a capacity of

1mmboe/d, with an average throughput in 2025 of 565mboe/d.

bp as operator of Azerbaijan International Operating Company and the

Georgian Pipeline Company for the Georgian section also operates the

Western Route Export Pipeline (WREP) that transports ACG oil to Supsa

on the Black Sea coast of Georgia. Exports through the pipeline have

been suspended since May 2022 (with occasional short-term exports

driven by operational needs) due to lack of nominations from the

shipper group. In current market conditions WREP serves as a

contingency export route for ACG crude oil.

bp holds a 29.99% interest in and operates certain parts of the 693-

kilometre South Caucasus Pipeline (SCP). The pipeline takes gas from

the Shah Deniz field in Azerbaijan through Georgia to the Turkish border

and has a capacity of 440mboe/d (including expansion), with average

throughput in 2025 of 392mboe/d.

bp also holds a 12% interest in the Trans Anatolian Natural Gas Pipeline

(TANAP). The pipeline takes Shah Deniz gas from the Turkish border and

transports it to Eskisehir in Türkiye and to the Greek border where it

connects with the Trans Adriatic Pipeline (TAP). The current capacity of

TANAP is 275mboe/d and the average throughput in 2025 was

260mboe/d.

bp has a 20% interest in Trans Adriatic Pipeline (TAP), which takes gas

through Greece and Albania into Italy. The current capacity of TAP is

167mboe/d and the total average throughput in 2025 was 173mboe/d.

In Oman, bp operates Block 61 in which bp holds 40% interest. bp also

has a 50% interest in Block 77 operated by Eni.

In Abu Dhabi, bp holds a 10% interest in the ADNOC Onshore

concession and 10% shareholding in the shipping company NGSCO and

10% in Ruwais LNG. ADNOC LNG supplied approximately 5Mt of LNG

(0.7bcfe/d regasified) in 2025. bp's interest in the ADNOC Onshore

concession expires at the end of 2054.

• In June bp acquired a 10% interest in ADNOC's planned LNG project

in Al Ruwais Industrial City, Abu Dhabi, joining ADNOC Gas (60%

stake), Mitsu & Co, Shell and TotalEnergies (also 10% each). Ruwais

LNG is planned to have two liquefaction trains with a total annual

capacity of 9.6Mt per annum.

In February 2026 bp and the Kuwait Oil Company signed a two-year

extension of the enhanced technical service agreement to support

production optimization of the Burgan oil field.

In Iraq, bp holds a 49% participating interest in Basra Energy Company

Limited (BECL). BECL is an incorporated joint venture (IJV) company

owned by bp (49%) and PetroChina (51%) and acts as Rumaila lead

contractor since 2022.

In March bp received final government ratification for its contract to

invest in the redevelopment of several giant oil fields in Kirkuk, in the

north of Iraq. The contract between North Oil Company, North Gas

Company (NGC) and bp includes the rehabilitation and redevelopment

of the fields, spanning oil, gas, power and water with potential for

investment in exploration. In October this contract became effective,

after agreeing an initial baseline production rate.

In India, bp holds a participating interest in two oil and gas PSAs, KG D6

33.33% and NEC25 33.33%, operated by Reliance Industries Limited

(RIL), and three oil and gas blocks under revenue-sharing contracts, 40%

in KG-UDWHP-2018/1 and 40% in KG-UDWHP-2022/1, operated by RIL;

and 30% in GS-OSHP-2022/2 operated by Oil and Natural Gas

Corporation Limited (ONGC). bp also holds a 50% stake in India Gas

Solutions Private Limited, a joint venture with RIL, for the sourcing and

marketing of gas in India.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 343 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Additional disclosures** |

---

• In May bp made the FID to invest in an infill wells programme at the

KG D6 block located offshore India

In February bp and ONGC signed agreement under which bp will serve

as the technical services provider for ONGC's Mumbai High field.

In April bp, RIL and ONGC were awarded a shallow water block GS-

OSHP-2022/2 (ONGC operator 40%, RIL 30%, bp 30%) in Gujarat-

Saurashtra basin, in India's Open Acreage Licensing Policy Bid Round IX.

In the Asian part of Indonesia, bp holds an interest in the Andaman II

PSC exploration block (operated by Harbour Energy), located offshore

North Sumatra, and in Agung I and Agung II exploration blocks offshore

Indonesia. Agung I covers over 6,000km<sup>2</sup> off the coast of Bali and East

Java and Agung II spans almost 8,000km<sup>2</sup> offshore South Sulawesi,

West Nusa Tenggara and East Java.

**Australasia**

bp has activities in Australia and Eastern Indonesia.

In Australia bp is one of six participants in the North West Shelf (NWS)

venture, which has been producing LNG, pipeline gas, condensate, LPG

and oil since the 1980s. Five partners hold interest in the gas

infrastructure (bp 16.67%) and six partners hold interest in the gas and

condensate reserves (bp 15.78%). The NWS venture is one of the largest

LNG export projects in the region, with four LNG trains currently in

operation following retirement of one LNG train in late 2024, and also

supplies domestic gas into the Western Australia market. bp's net share

of the capacity of NWS LNG trains is 2.26Mt (15.78% of 14.3Mtpa gross) of

LNG per year.

• In November the Greater Western Flank 4 project in the North West

Shelf, offshore Australia (bp 16.67%, operator Woodside) reached FID.

The project involves five subsea tieback wells with start-up targeted

for 2028.

bp is one of four participants in Browse LNG Joint Venture, operated by

Woodside (bp 44.33%). The project is aimed at developing natural gas

resources located in the offshore Browse basin.

bp has a 50% interest in the WA-541-P exploration title in Western

Australia's offshore Northern Carnarvon basin. The joint venture,

operated by Santos, is working towards the drilling of two commitment

wells.

bp also has a 100% interest in the WA-551-P exploration title adjacent to

WA-541-P and is currently carrying out prospect maturation activities.

In Papua Barat, Eastern Indonesia, bp operates the Tangguh LNG plant

(bp 40.22%). The plant consists of three trains with total production

capacity of 11.4Mtpa. The Tangguh asset comprises 30 production wells,

four offshore platforms, three LNG processing trains, and two LNG

loading facilities. Tangguh supplies LNG to customers in Indonesia,

Mexico, China, South Korea, Taiwan and Japan through a combination of

long, medium and spot contracts.

• In August a consortium of bp (16.09%), its Tangguh partners (23.91%),

operator EnQuest (40%), and Agra (20%) secured the right to explore

the Gaea and Gaea II cover onshore and offshore gas blocks near our

Tangguh LNG facility with the signing of government-backed

contracts

**Oil and natural gas**

**Resource progression**

bp manages its hydrocarbon resources in three major categories:

prospect inventory, contingent resources and reserves. When a

discovery is made, volumes usually transfer from the prospect

inventory to the contingent resources category. The contingent

resources move through various sub-categories as their technical and

commercial maturity increases through appraisal activity.

At the point of final investment decision, most proved reserves will be

categorized as proved undeveloped (PUD). Volumes will subsequently

be recategorized from PUD to proved developed (PD) as a consequence

of development activity. When part of a well's proved reserves depends

on a later phase of activity, only that portion of proved reserves

associated with existing, available facilities and infrastructure moves to

PD. The first PD bookings will typically occur at the point of first oil or

gas production. Major development projects typically take one to five

years from the time of initial booking of PUD to the start of production.

Changes to proved reserves bookings may be made due to analysis of

new or existing data concerning production, reservoir performance,

commercial factors and additional reservoir development activity.

Volumes can also be added or removed from our portfolio through

acquisition or divestment of properties and projects. When we dispose

of an interest in a property or project, the volumes associated with our

adopted plan of development for which we have a final investment

decision will be removed from our proved reserves upon completion of

the transaction. When we acquire an interest in a property or project,

the volumes associated with the existing development and any

committed projects will be added to our proved reserves if bp has

made a final investment decision and they satisfy the SEC's criteria for

attribution of proved status. Following the acquisition, additional

volumes may be progressed to proved reserves from non-proved

reserves or contingent resources.

Non-proved reserves and contingent resources in a field will only be

recategorized as proved reserves when all the criteria for attribution of

proved status have been met and the volumes are included in the

business plan and scheduled for development, typically within five

years. bp will only book proved reserves where development is

scheduled to commence after more than five years if these proved

reserves satisfy the SEC's criteria for attribution of proved status and

bp management has reasonable certainty that these proved reserves

will be produced.

At the end of 2025 bp had no proved undeveloped reserves held for

more than five years in our onshore US developments.

Over the past five years, bp has annually progressed a five-year average

of 20% (19% for 2024 five-year average) of our group proved

undeveloped reserves (including the impact of disposals and price

acceleration effects in PSAs) to proved developed reserves. This

equates to a turnover time of five years.

Proved reserves as estimated at the end of 2025 meet bp's criteria for

project sanctioning and SEC tests for proved reserves. We have not

halted or changed our commitment to proceed with any material

project to which proved undeveloped reserves have been attributed.

In 2025 we progressed 481mmboe of proved undeveloped reserves

(412mmboe for our subsidiaries★ alone) to proved developed reserves

through ongoing investment in our subsidiaries' and equity-accounted

entities' development activities. Total development expenditure,

excluding midstream activities, was $13,336 million in 2025 ($8,387

million for subsidiaries and $4,949 million for equity-accounted entities).

Of the $8,387 million of total development expenditure for our

subsidiaries, approximately $4,900 million was used for development

activity to progress proved undeveloped reserves to proved developed.

Of the $4,949 million development expenditure for our equity-

accounted entities, approximately $1,800 million was used for

development activity to progress proved undeveloped reserves to

proved developed. The major areas with progressed volumes in 2025

were the US, Azerbaijan, Trinidad and Tobago, Southern Cone and

Middle East.

---

| | | |
|:---|:---|:---|
| 344 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

Revisions of previous estimates for proved undeveloped reserves are

due to changes relating to field performance, well results, revisions to

future activity plans (including alignment with our investment criteria

and changes to the macroeconomic climate) or changes in commercial

conditions including price impacts. The net revisions to previous

estimates across both our subsidiaries and our equity-accounted

entities include net positive revisions driven by revisions to activity

plans, revisions due to well results and revisions driven by price, and net

negative revisions driven by field performance. The net revisions to

previous estimates across only our subsidiaries include net positive

revisions driven by revisions to activity plans, revisions due to well

results and revisions driven by price, and net negative revisions driven

by field performance. In each case, none of these factors resulted in

revisions that were material to the group as a whole. The following

tables describe the changes to our proved undeveloped reserves

position through the year for our subsidiaries and equity-accounted

entities, and for our subsidiaries alone.

---

| | |
|:---|:---|
|  | volumes in mmboe<sup>a</sup> |
| Subsidiaries and equity-accounted entities | Group |
| Proved undeveloped reserves at 1 January 2025 | **2387** |
| Revisions of previous estimates | **380** |
| Price | **78** |
| Revision of future activity plans | **409** |
| Field performance | **(119)** |
| Well results | **12** |
| Improved recovery | **20** |
| Discoveries and extensions | **125** |
| Purchases | **59** |
| Sales | **(42)** |
| Total in year proved undeveloped reserves changes | **542** |
| Proved developed reserves reclassified as <br>undeveloped<br>| **77** |
| Progressed to proved developed reserves by <br>development activities (e.g. drilling/completion)<br>| **(481)** |
| **Proved undeveloped reserves at 31 December 2025** | **2525** |

---

---

| | |
|:---|:---|
| Subsidiaries only | volumes in mmboe<sup>a</sup> |
| Proved undeveloped reserves at 1 January 2025 | **1875** |
| Revisions of previous estimates | **418** |
| Price | **88** |
| Revision of future activity plans | **416** |
| Field performance | **(107)** |
| Well results | **22** |
| Improved recovery | **15** |
| Discoveries and extensions | **66** |
| Purchases | **59** |
| Sales | **(41)** |
| Total in year proved undeveloped reserves changes | **518** |
| Proved developed reserves reclassified as <br>undeveloped<br>| **75** |
| Progressed to proved developed reserves by <br>development activities (e.g. drilling/completion)<br>| **(412)** |
| **Proved undeveloped reserves at 31 December 2025** | **2055** |

---

aBecause of rounding, some totals may not agree exactly with the sum of their component

parts.

bp bases its proved reserves estimates on the requirement of

reasonable certainty, with rigorous technical and commercial

assessments based on conventional industry practice and regulatory

requirements. bp only applies technologies that have been field-tested

and have been demonstrated to provide reasonably certain results with

consistency and repeatability in the formation being evaluated or in an

analogous formation. bp applies high-resolution seismic data for the

identification of reservoir extent and fluid contacts only where there is

an overwhelming track record of success in its local application. In

certain cases bp uses numerical simulation as part of a holistic

assessment of recovery factor for its fields, where these simulations

have been field-tested and have been demonstrated to provide

reasonably certain results with consistency and repeatability in the

formation being evaluated or in an analogous formation. In certain

deepwater fields bp has booked proved reserves before production

flow tests are conducted, in part because of the significant safety, cost

and environmental implications of conducting these tests. The industry

has made substantial technological improvements in understanding,

measuring and delineating reservoir properties without the need for

flow tests. To determine reasonable certainty of commercial recovery,

bp employs a general method of reserves assessment that relies on the

integration of three types of data:

• Well data used to assess the local characteristics and conditions of

reservoirs and fluids.

• Field-scale seismic data to allow the interpolation and extrapolation

of these characteristics outside the immediate area of the local well

control.

• Data from relevant analogous fields.

Well data includes appraisal wells or sidetrack holes, full logging suites,

core data and fluid samples. bp considers the integration of this data in

certain cases to be superior to a flow test in providing understanding of

overall reservoir performance. The collection of data from logs, cores,

wireline formation testers, pressures and fluid samples calibrated to

each other and to the seismic data can allow reservoir properties to be

determined over a greater volume than the localized volume of

investigation associated with a short-term flow test. There is a strong

track record of proved reserves recorded using these methods,

validated by actual production levels.

**Governance**

bp's centrally controlled process for proved reserves estimation

approval forms part of a holistic and integrated system of internal

control. It consists of the following elements:

• Accountabilities of certain officers of the group to ensure that there

is review and approval of proved reserves bookings independent of

the operating business, and that there are effective controls in the

approval process and verification that the proved reserves estimates

and the related financial impacts are reported in a timely manner.

• Capital allocation processes, whereby delegated authority is

exercised to commit to capital projects that are consistent with the

delivery of the group's business plan. A formal review process exists

to ensure that both technical and commercial criteria are met prior

to the commitment of capital to projects.

• Internal audit, whose role is to consider whether the group's system

of internal control is adequately designed and operating effectively

to respond appropriately to the risks that are significant to bp.

• Approval hierarchy, whereby proved reserves changes above certain

threshold volumes require immediate review and all proved reserves

require annual central authorization and have scheduled periodic

reviews. The frequency of periodic reviews ensures that 100% of the

bp proved reserves base undergoes central review every three years.

bp's vice president of reserves is the individual primarily responsible for

overseeing the preparation of the reserves estimate. He has more than

30 years of diversified industry experience in reserves estimation with

the past five years managing the governance and compliance. He is a

past chairman of the Society of Petroleum Engineers (Russia & Caspian).

No specific portion of compensation bonuses for senior management is

directly related to proved reserves targets. Additions to proved reserves

is one of several indicators by which the performance of the gas & low

carbon energy and oil production & operations segments is assessed by

the remuneration committee for the purposes of determining

compensation bonuses for the executive directors. Other indicators

include a number of financial and operational measures.

bp's variable pay programme for the other senior managers in the gas &

low carbon energy and oil production & operations segments is based

on individual performance contracts. Individual performance contracts

are based on agreed items from the business performance plan, one of

which, if chosen, could relate to proved reserves.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 345 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Additional disclosures** |

---

**Compliance**

International Financial Reporting Standards (IFRS) do not provide

specific guidance on reserves disclosures. bp estimates proved

reserves in accordance with SEC Rule 4-10 (a) of Regulation S-X and

relevant Compliance and Disclosure Interpretations (C&DI) and Staff

Accounting Bulletins as issued by the SEC staff.

By their nature, there is always risk involved in the ultimate

development and production of proved reserves including, but not

limited to: final regulatory approval; the installation of new or additional

infrastructure, as well as changes in oil and gas prices; changes in

operating and development costs; and the continued availability of

additional development capital. All the group's proved reserves held in

subsidiaries and equity-accounted entities are estimated by the group's

petroleum engineers, or by independent petroleum engineering

consulting firms and then assured by the group's petroleum engineers.

Netherland, Sewell & Associates (NSAI), an independent petroleum

engineering consulting firm, has estimated the net proved crude oil,

condensate, natural gas liquids (NGLs) and natural gas reserves, as of

31 December 2025, of certain properties owned by bp in the US Lower

48. The properties evaluated by NSAI account for 100% of bp's net

proved reserves in the US Lower 48 as of 31 December 2025. The net

proved reserves estimates prepared by NSAI were prepared in

accordance with the reserves definitions of Rule 4-10(a)(1)-(32) of

Regulation S-X. All reserves estimates involve some degree of

uncertainty. bp has filed NSAI's independent report on its reserves

estimates as an exhibit to this *Annual Report and Form 20-F 2025* filed

with the SEC.

Our proved reserves are associated with both concessions (tax and

royalty arrangements) and agreements where the group is exposed to

the upstream risks and rewards of ownership, but where our

entitlement to the hydrocarbons is calculated using a more complex

formula, such as with PSAs. In a concession, the consortium of which we

are a part is entitled to the proved reserves that can be produced over

the licence period, which may be the life of the field. In a PSA, we are

entitled to recover volumes that equate to costs incurred to develop

and produce the proved reserves, and an agreed share of the remaining

volumes or the economic equivalent. As part of our entitlement is driven

by the monetary amount of costs to be recovered, price fluctuations will

have an impact on both production volumes and reserves.

We disclose our share of proved reserves held in equity-accounted

entities (joint ventures★ and associates★), although we do not control

these entities or the assets held by such entities.

**bp's estimated net proved reserves and proved reserves** 

**replacement**

94% of our total proved reserves of subsidiaries at 31 December 2025

were held through joint operations★ (94% in 2024), and 22% of the

proved reserves were held through such joint operations where we

were not the operator (23% in 2024).

Estimated net proved reserves of crude oil at 31 December

2025<sup>abc</sup>

---

| | | | |
|:---|:---|:---|:---|
|  |  | million barrels | million barrels |
|  | Developed | Undeveloped | Total |
| UK | **56** | **41** | **97** |
| US | **599** | **443** | **1042** |
| Rest of North America | **—** | **—** | **—** |
| South America<sup>d</sup> | **1** | **4** | **6** |
| Africa | **2** | **—** | **2** |
| Rest of Asia | **691** | **298** | **989** |
| Australasia | **6** | **3** | **8** |
| Subsidiaries | **1354** | **788** | **2143** |
| Equity-accounted entities | **566** | **299** | **865** |
| **Total** | **1920** | **1088** | **3008** |

---

Estimated net proved reserves of natural gas liquids at

31 December 2025<sup>ab</sup>

---

| | | | |
|:---|:---|:---|:---|
|  |  | million barrels | million barrels |
|  | Developed | Undeveloped | Total |
| UK | **1** | **—** | **1** |
| US | **204** | **212** | **415** |
| Rest of North America | **—** | **—** | **—** |
| South America | **—** | **—** | **—** |
| Africa | **—** | **—** | **—** |
| Rest of Asia | **—** | **—** | **—** |
| Australasia | **1** | **—** | **1** |
| Subsidiaries | **206** | **212** | **417** |
| Equity-accounted entities | **17** | **5** | **22** |
| **Total** | **222** | **217** | **439** |

---

Estimated net proved reserves of liquids<sup>d</sup>★

---

| | | | |
|:---|:---|:---|:---|
|  |  | million barrels | million barrels |
|  | Developed | Undeveloped | Total |
| Subsidiaries | **1560** | **1000** | **2560** |
| Equity-accounted entities | **582** | **304** | **887** |
| **Total** | **2143** | **1304** | **3447** |

---

Estimated net proved reserves of natural gas at 31 December

2025<sup>ab</sup>

---

| | | | |
|:---|:---|:---|:---|
|  | billion cubic feet | billion cubic feet | billion cubic feet |
|  | Developed | Undeveloped | Total |
| UK | **76** | **12** | **88** |
| US | **3009** | **3881** | **6890** |
| Rest of North America | **—** | **—** | **—** |
| South America<sup>e</sup> | **413** | **358** | **771** |
| Africa | **123** | **—** | **123** |
| Rest of Asia | **2660** | **1368** | **4028** |
| Australasia | **947** | **498** | **1445** |
| Subsidiaries | **7227** | **6117** | **13344** |
| Equity-accounted entities | **1610** | **962** | **2572** |
| **Total** | **8837** | **7079** | **15916** |

---

Estimated net proved reserves on an oil equivalent basis

---

| | | | |
|:---|:---|:---|:---|
|  | million barrels of oil equivalent | million barrels of oil equivalent | million barrels of oil equivalent |
|  | Developed | Undeveloped | Total |
| Subsidiaries | **2806** | **2055** | **4861** |
| Equity-accounted entities | **860** | **470** | **1330** |
| **Total** | **3666** | **2525** | **6191** |

---

aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the

royalty owner has a direct interest in the underlying production and the option and ability to

make lifting and sales arrangements independently, and include non-controlling interests in

consolidated operations. We disclose our share of reserves held in joint ventures and

associates that are accounted for by the equity method, although we do not control these

entities or the assets held by such entities.

bThe 2025 marker prices used were Brent $69.512/bbl (2024 $81.171/bbl and 2023 $83.27/bbl)

and Henry Hub $3.409/mmBtu (2024 $2.065/mmBtu and 2023 $2.58/mmBtu).

cIncludes condensate.

dIncludes 1.7 million barrels of liquids in respect of the 30% non-controlling interest in BP

Trinidad and Tobago LLC.

eIncludes 231 billion cubic feet of natural gas in respect of the 30% non-controlling interest in

BP Trinidad and Tobago LLC.

Because of rounding, some totals may not agree exactly with the sum of their

component parts.

**Proved reserves replacement**

Total hydrocarbon proved reserves at 31 December 2025, on an oil

equivalent basis including equity-accounted entities, decreased by 1%

compared with 31 December 2024 (0.2% decrease for subsidiaries and

3% decrease for equity-accounted entities). Natural gas increased by

8% (10% increase for subsidiaries and 3% decrease for equity-

accounted entities).

There was a net increase from acquisitions and disposals of 27mmboe

within our US and North Sea subsidiaries.

---

| | | |
|:---|:---|:---|
| 346 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

The proved reserves replacement ratio★ is the extent to which

production is replaced by proved reserves additions. This ratio is

expressed in oil equivalent terms and includes changes resulting from

revisions to previous estimates, improved recovery, and extensions and

discoveries. For 2025, the proved reserves replacement ratio excluding

acquisitions and disposals was 90% (50% in 2024 and 47% in 2023) for

subsidiaries and equity-accounted entities, 95% for subsidiaries alone

and 69% for equity-accounted entities alone. There was a net increase

(126mmboe) of reserves due to higher gas prices, primarily in our US

subsidiaries, partly offset by a decrease in reserves in some of our PSAs

in Angola.

In 2025 net additions to the group's proved reserves (excluding

production, sales and purchases of reserves-in-place) amounted to

780mmboe (679mmboe for subsidiaries and 101mmboe for equity-

accounted entities), through revisions to previous estimates including

price, improved recovery from, and extensions to, existing fields, and

discoveries of new fields. The majority of subsidiary additions were

through revisions to previous estimates and extensions to existing

fields and discoveries of new fields, where they represented a mixture

of proved developed and proved undeveloped reserves. The principal

proved reserves additions in our subsidiaries by region were in the US,

Trinidad and the Middle East. The principal reserves additions in our

equity-accounted entities were in Iraq, Angola and Norway.

In January 2024 it was reported that the Oslo District Court had

determined that certain development permits granted by the

Norwegian government during 2023 were invalid. This includes

development permits for two fields in which Aker bp has an interest. The

court's decision is not final and could be appealed. If bp's equity-

accounted share of the reserves attributable to these two fields is

removed from the calculation of bp's 2025 proved reserves ratio, that

ratio would remain the same. Removal of the same reserves from bp's

2025 reporting would impact proved hydrocarbon reserves for the

group, proved undeveloped reserves and estimated net proved

reserves on an oil equivalent basis, amongst other reported measures,

both for equity-accounted entities and group.

24% of our proved reserves are associated with PSAs. The countries in

which we produced under PSAs in 2025 were Angola, Azerbaijan, Egypt,

India, Indonesia, Mexico and Oman, and includes the technical service

contract (TSC)★ governing our investment in the Rumaila field in Iraq

that functions as a PSA.

The group holds no licences in our PSAs or TSCs due to expire within the

next three years that would have a significant impact on bp's reserves

or production, including undeveloped acreage.

For further information on our reserves see page <u>[248](#i0dd2ee81aac04f8c9c97c86197f0c6df_403)</u>.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 347 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Additional disclosures** |

---

**bp's net production by country – crude oil**<sup>a</sup> **and natural gas liquids**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  | thousand barrels per day | thousand barrels per day | thousand barrels per day |
|  |  |  |  | bp net share of production<sup>b</sup> | bp net share of production<sup>b</sup> | bp net share of production<sup>b</sup> |
|  |  |  | Crude oil |  |  | Natural gas <br>liquids<br>|
|  | **2025** | 2024 | 2023 | **2025** | 2024 | 2023 |
| **Subsidiaries** |  |  |  |  |  |  |
| UK | **78** | 70 | 74 | **4** | 4 | 5 |
| Total Europe | **78** | 70 | 74 | **4** | 4 | 5 |
| Lower 48 onshore<sup>c</sup> | **108** | 86 | 69 | **87** | 84 | 66 |
| Gulf of America deepwater | **291** | 290 | 266 | **24** | 23 | 22 |
| Total US | **399** | 376 | 335 | **111** | 107 | 88 |
| Total North America | **399** | 376 | 335 | **111** | 107 | 88 |
| Trinidad and Tobago | **5** | 4 | 4 | **6** | 4 | 4 |
| Total South America | **5** | 4 | 4 | **6** | 4 | 4 |
| Egypt<sup>d</sup> | **7** | 19 | 28 | **—** | 1 | 1 |
| Algeria<sup>c</sup> | **—** |  | 1 | **—** |  | 1 |
| Mauritania | **1** |  |  | **—** |  |  |
| Total Africa | **8** | 19 | 29 | **—** | 1 | 2 |
| Abu Dhabi | **208** | 202 | 197 | **—** |  |  |
| Azerbaijan | **66** | 66 | 70 | **—** |  |  |
| India | **6** | 6 | 4 | **—** |  |  |
| Oman | **22** | 23 | 22 | **—** |  |  |
| Total Rest of Asia | **302** | 297 | 293 | **—** |  |  |
| Total Asia | **302** | 297 | 293 | **—** |  |  |
| Australia | **6** | 7 | 8 | **1** | 2 | 2 |
| Eastern Indonesia | **2** | 2 | 2 | **—** |  |  |
| Total Australasia | **8** | 9 | 10 | **1** | 2 | 2 |
| Total subsidiaries | **800** | 775 | 745 | **123** | 117 | 100 |
| **Equity-accounted entities (bp share)** |  |  |  |  |  |  |
| Argentina | **51** | 52 | 51 | **1** | 1 | 1 |
| Mexico | **4** | 3 | 5 | **—** |  |  |
| Bolivia | **1** | 1 | 1 | **—** |  |  |
| Egypt<sup>d</sup> | **3** |  |  | **2** | 2 | 2 |
| Norway | **55** | 58 | 60 | **2** | 2 | 3 |
| Iraq | **79** | 69 | 62 | **—** |  |  |
| Angola | **75** | 82 | 82 | **3** | 4 | 4 |
| Total equity-accounted entities | **268** | 266 | 261 | **8** | 9 | 9 |
| Total subsidiaries and equity-accounted entities<sup>e</sup> | **1069** | 1041 | 1006 | **131** | 126 | 109 |

---

aIncludes condensate.

bProduction excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting

and sales arrangements independently.

cIn 2024 bp disposed of certain Lower 48 onshore interests in the US. In 2023 bp disposed of its interests in Algeria.

dIn 2024 bp disposed of certain interests in Egypt to form Arcius Energy.

eIncludes 2 net mboe/d of NGLs from processing plants in which bp has an interest (2024 2mboe/d and 2023 2mboe/d).

Because of rounding, some totals may not agree exactly with the sum of their component parts.

---

| | | |
|:---|:---|:---|
| 348 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**bp's net production by country – natural gas**

---

| | | | |
|:---|:---|:---|:---|
|  | million cubic feet per day | million cubic feet per day | million cubic feet per day |
|  | bp net share of production<sup>a</sup> | bp net share of production<sup>a</sup> | bp net share of production<sup>a</sup> |
|  | **2025** | 2024 | 2023 |
| **Subsidiaries** |  |  |  |
| UK | **203** | 197 | 247 |
| Total Europe | **203** | 197 | 247 |
| Lower 48 onshore<sup>b</sup> | **1573** | 1530 | 1338 |
| Gulf of America deepwater | **177** | 160 | 149 |
| Total US | **1751** | 1690 | 1486 |
| Total North America | **1751** | 1690 | 1486 |
| Trinidad and Tobago<sup>b</sup> | **1045** | 1145 | 1191 |
| Total South America | **1045** | 1145 | 1191 |
| Egypt<sup>c</sup> | **353** | 904 | 1220 |
| Mauritania<sup>d</sup> | **53** |  |  |
| Senegal<sup>d</sup> | **48** |  |  |
| Algeria<sup>b</sup> | **—** |  | 16 |
| Total Africa | **453** | 904 | 1236 |
| Azerbaijan | **731** | 748 | 714 |
| India | **275** | 303 | 283 |
| Oman | **590** | 604 | 582 |
| Total Rest of Asia | **1597** | 1655 | 1578 |
| Total Asia | **1597** | 1655 | 1578 |
| Australia | **227** | 276 | 301 |
| Eastern Indonesia | **572** | 606 | 473 |
| Total Australasia | **799** | 882 | 774 |
| Total subsidiaries<sup>e</sup> | **5847** | 6474 | 6512 |
| **Equity-accounted entities (bp share)** |  |  |  |
| Argentina | **246** | 267 | 247 |
| Bolivia | **37** | 33 | 50 |
| Mexico | **1** | 1 | 2 |
| Egypt<sup>c</sup> | **165** | 9 |  |
| Norway | **54** | 55 | 58 |
| Angola | **99** | 76 | 74 |
| Total equity-accounted entities<sup>e</sup> | **603** | 440 | 432 |
| Total subsidiaries and equity-accounted entities | **6450** | 6914 | 6944 |

---

aProduction excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting

and sales arrangements independently.

bIn 2024 bp disposed of certain interests in Trinidad and Tobago. In 2023 bp disposed of its interests in Algeria and certain Lower 48 onshore interests in the US.

cIn 2024 bp disposed of certain interests in Egypt to form Arcius Energy.

dIn 2025 the Greater Tortue Ahmeyim LNG project in Mauritania and Senegal has begun flowing gas.

eNatural gas production volumes exclude gas consumed in operations within the lease boundaries of the producing field, but the related reserves are included in the group's reserves.

Because of rounding, some totals may not agree exactly with the sum of their component parts.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 349 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Additional disclosures** |

---

The following tables provide additional data and disclosures in relation to our oil and gas operations.

**Average sales price per unit of production (realizations**★**)**<sup>a</sup>

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | $ per unit of production | $ per unit of production |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total<br>group<br>average<br>|
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  |  |  |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **2025** |  |  |  |  |  |  |  |  |  |
| **Crude oil**<sup>b</sup> | **69.20** | **—** | **63.79** | **—** | **70.05** | **64.50** | **70.53** | **63.87** | **66.92** |
| **Natural gas liquids** | **38.80** | **—** | **20.74** | **—** | **36.08** | **—** | **—** | **48.71** | **22.35** |
| **Gas** | **12.76** | **—** | **2.63** | **—** | **5.20** | **4.14** | **7.01** | **9.36** | **5.61** |
| 2024 |  |  |  |  |  |  |  |  |  |
| Crude oil<sup>b</sup> | 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<sup>b</sup> | 82.99 |  | 75.28 |  | 84.36 | 76.30 | 83.86 | 68.27 | 79.37 |
| Natural gas liquids | 46.52 |  | 19.26 |  | 30.76 | 44.41 |  | 33.47 | 23.79 |
| Gas | 16.71 |  | 2.08 |  | 3.58 | 4.82 | 7.72 | 8.89 | 5.60 |
| **Equity-accounted entities**<sup>c</sup> |  |  |  |  |  |  |  |  |  |
| **2025** |  |  |  |  |  |  |  |  |  |
| **Crude oil**<sup>b</sup> | **—** | **68.90** | **—** | **—** | **62.47** | **67.07** | **61.82** | **—** | **64.90** |
| **Natural gas liquids** | **—** | **—** | **—** | **—** | **25.50** | **49.02** | **—** | **—** | **36.90** |
| **Gas** | **—** | **11.99** | **—** | **—** | **3.69** | **—** | **—** | **—** | **4.98** |
| 2024 |  |  |  |  |  |  |  |  |  |
| Crude oil<sup>b</sup> |  | 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<sup>b</sup> |  | 81.61 |  |  | 75.49 | 80.21 | 75.21 |  | 78.33 |
| Natural gas liquids |  |  |  |  | 30.95 | 42.89 |  |  | 36.70 |
| Gas |  | 12.80 |  |  | 3.66 |  |  |  | 5.15 |

---

**Average production cost per unit of production**<sup>d</sup>

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  |  |  |  |  |  |  |  | $ per unit of production | $ per unit of production |
|  | Europe | Europe | North <br>America | North <br>America | South <br>America<br>| Africa | Asia | Australasia | Total<br>group<br>average<br>|
|  | UK | Rest of<br>Europe<br>| US | Rest of<br>North<br>America<br>|  |  |  | | |
| **Subsidiaries** |  |  |  |  |  |  |  |  |  |
| **2025** | **12.82** | **—** | **8.61** | **—** | **4.45** | **11.19** | **2.68** | **1.85** | **6.28** |
| 2024 | 13.74 |  | 9.33 |  | 5.27 | 3.57 | 2.89 | 1.78 | 6.17 |
| 2023 | 10.69 |  | 9.61 |  | 4.53 | 2.52 | 2.81 | 2.09 | 5.78 |
| **Equity-accounted entities** |  |  |  |  |  |  |  |  |  |
| **2025** | **—** | **7.31** | **—** | **—** | **20.07** | **18.42** | **22.51** | **—** | **17.64** |
| 2024 |  | 6.16 |  |  | 20.40 | 18.30 | 22.88 |  | 17.37 |
| 2023 |  | 6.22 |  |  | 17.87 | 15.46 | 16.41 |  | 14.38 |

---

aUnits of production are barrels for liquids and thousands of cubic feet for gas. Realizations include transfers between businesses.

bIncludes condensate.

cIn certain countries it is common for equity-accounted entities' agreements to include pricing clauses that require selling a significant portion of the entitled production to local governments or

markets at discounted prices.

dUnits of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes.

---

| | | |
|:---|:---|:---|
| 350 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

Additional information for customers & products

**Reconciliation of customers & products RC profit before** 

**interest and tax to underlying RC profit before interest** 

**and tax to adjusted EBITDA**★ **by business**

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| RC profit (loss) before interest and <br>tax for customers & products<sup>a</sup><br>| **4100** | (1043) | 4230 |
| Less: Adjusting items gains <br>(charges)<sup>a</sup><br>| **(1172)** | (3560) | (2183) |
| Underlying RC profit before interest <br>and tax for customers & products<br>| **5272** | 2517 | 6413 |
| By business: |  |  |  |
| customers – convenience & <br>mobility<br>| **3764** | 2584 | 2644 |
| *Castrol – included in customers* | ***971*** | *831* | *730* |
| products – refining & trading | **1508** | (67) | 3769 |
| Add back: Depreciation, depletion <br>and amortization<br>| **4145** | 3957 | 3548 |
| By business: |  |  |  |
| customers – convenience & <br>mobility<br>| **2443** | 2135 | 1736 |
| *Castrol – included in customers* | ***179*** | *176* | *167* |
| products – refining & trading | **1702** | 1822 | 1812 |
| Adjusted EBITDA for customers & <br>products<br>| **9417** | 6474 | 9961 |
| By business: |  |  |  |
| customers – convenience & <br>mobility<br>| **6207** | 4719 | 4380 |
| *Castrol – included in customers* | ***1150*** | *1007* | *897* |
| products – refining & trading | **3210** | 1755 | 5581 |

---

a2024 has been restated for material items to reflect the move of our Archaea Energy business

from the customers & products segment to the gas & low carbon energy segment.

**Sales volume**

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | thousand <br>barrels per <br>day<br>|
|  | **2025** | 2024 | 2023 |
| Marketing sales<sup>a</sup> | **2696** | 2714 | 2718 |
| Trading/supply sales<sup>b</sup> | **494** | 373 | 358 |
| Total refined product sales | **3190** | 3087 | 3076 |
| Crude oil<sup>c</sup> | **72** | 86 | 102 |
| Total | **3262** | 3173 | 3178 |

---

aMarketing sales include branded and unbranded sales of refined fuel products and lubricants

to business-to-business and business-to-consumer customers, including service station

dealers, jobbers, airlines, small and large resellers such as hypermarkets, and the military.

bTrading/supply sales are fuel sales to large unbranded resellers and other oil companies.

cCrude oil sales relate to third-party transactions executed primarily by supply, trading and

shipping. In addition, reported crude oil sales in 2025 includes 37 thousand barrels per day

(2024 52 thousand barrels per day and 2023 68 thousand barrels per day) relating to volumes

sold directly by the gas & low carbon energy and oil production & operations segments.

In the table above, volumes of crude oil and refined product trading/

supply sales are presented on a basis consistent with income statement

presentation. These figures do not correspond to actual volumes of

physically traded energy products and are not intended for use in

assessing emissions volumes or carbon intensity. Marketing volumes

shown represent physically delivered transactions regardless of income

statement presentation of such transactions.

**Retail sites**<sup>a</sup>

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | Number of <br>bp-branded <br>retail sites<br>|
|  | **2025** | 2024 | 2023 |
| US | **8750** | 8500 | 8200 |
| Europe | **7150** | 7750 | 8050 |
| Rest of world | **5150** | 4950 | 4850 |
| Total | **21050** | 21200 | 21100 |

---

aReported to the nearest 50. Includes sites operated by dealers, jobbers, franchisees or brand

licensees or joint venture (JV) partners, under the bp brand. These may move to and from the

bp brand as their fuel supply agreement or brand licence agreement expires and is

renegotiated in the normal course of business. Retail sites are primarily branded bp, *ARCO*,

*Amoco*, *Aral*, *Thorntons* and *TravelCenters of America,* and also include sites in India through

our Jio-bp JV.

**Refinery throughputs**<sup>abc</sup><sup>de</sup>

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | thousand <br>barrels per <br>day<br>|
|  | **2025** | 2024 | 2023 |
| US | **635** | 612 | 662 |
| Europe | **805** | 782 | 749 |
| Total | **1440** | 1394 | 1411 |
|  |  |  | % |
| Refining availability★ | **96.3** | 94.3 | 96.1 |

---

aThis does not include bp's interest in Pan American Energy Group.

bRefinery throughputs reflect crude oil and other feedstock volumes.

cOn 28 February 2023, bp completed the sale of its 50% interest in the bp-Husky Toledo

refinery in Ohio, US to Cenovus Energy, its partner in the facility.

dOn 1 December 2024, bp completed the sale of its 50% ownership in the SAPREF refinery to

the South African state-owned entity Central Energy Fund SOC Ltd.

eOn 6 February 2025 bp announced its intention to market its Ruhr Oel GmbH – BP

Gelsenkirchen operation in Germany for potential sale, including its refinery in Gelsenkirchen

and DHC Solvent Chemie GmbH in Mülheim an der Ruhr.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 351 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Additional disclosures** |

---

**Refinery capacity**

The following table<sup>a</sup> summarizes bp's average daily crude distillation capacities as at 31 December 2025.

---

| | | | | |
|:---|:---|:---|:---|:---|
|  |  |  | Crude distillation <br>capacities<sup>b</sup><br>|  |
|  | Country | Refinery |  | thousand barrels<br>per day<br>|
| **US** |  |  |  |  |
| US North West | US | Cherry Point |  | **251** |
| US Mid West |  | Whiting |  | **440** |
|  |  |  |  | **691** |
| **Europe** |  |  |  |  |
| North West Europe | Germany | Gelsenkirchen<sup>c</sup> |  | **265** |
|  |  | Lingen |  | **97** |
|  | Netherlands | Rotterdam |  | **394** |
| Mediterranean | Spain | Castellón |  | **110** |
|  |  |  |  | **866** |
| Total capacity at 31 December 2025 |  |  |  | **1557** |

---

aThis does not include bp's interest in Pan American Energy Group.

bCrude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period under normal operational conditions.

cOn 6 February 2025 bp announced its intention to market its Ruhr Oel GmbH – BP Gelsenkirchen operation in Germany for potential sale, including its refinery in Gelsenkirchen and DHC Solvent

Chemie GmbH in Mülheim an der Ruhr.

---

| | | |
|:---|:---|:---|
| 352 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

Environmental expenditure

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| Operating expenditure | **435** | 575 | 524 |
| Capital expenditure | **443** | 393 | 329 |
| Clean-ups | **16** | 20 | 23 |
| Additions to environmental <br>remediation provision<br>| **325** | 254 | 228 |
| Increase (decrease) in <br>decommissioning provision<br>| **528** | 942 | 920 |

---

Operating and capital expenditure on the prevention, control, treatment

or elimination of air and water emissions and solid waste is often not

incurred as a separately identifiable transaction. Instead, it forms part of

a larger transaction that includes, for example, normal operations and

maintenance expenditure. The figures for environmental operating and

capital expenditure in the table are therefore estimates, based on the

definitions and guidelines of the American Petroleum Institute.

Environmental operating expenditure of $435 million in 2025 (2024 $575

million) showed an overall decrease of 24%, largely due to decreased

expenditure in BP Products North America.

Environmental capital expenditure of $443 million in 2025 (2024 $393

million) showed an overall increase of 13%, largely due to increased

expenditure for BP Products North America.

Clean-up costs were $16 million in 2025 (2024 $20 million), representing

oil spill clean-up costs and other associated remediation and disposal

costs.

In addition to operating and capital expenditure, we also establish

provisions for future environmental remediation work. Expenditure

against such provisions normally occurs in subsequent periods and is

not included in environmental operating expenditure reported for such

periods.

Provisions for environmental remediation are made when a clean-up is

probable and the amount of the obligation can be reliably estimated.

Generally, this coincides with the commitment to a formal plan of action

or, if earlier, on divestment or on closure of inactive sites.

The extent and cost of future environmental restoration, remediation

and abatement programmes are inherently difficult to estimate. They

often depend on the extent of contamination, and the associated

impact and timing of the corrective actions required, technological

feasibility and bp's share of liability. Though the costs of future

programmes could be significant and may be material to the results of

operations in the period in which they are recognized, it is not expected

that such costs will be material to the group's overall results of

operations or financial position. For further information, see Note 1 –

Significant judgements and estimates: provisions.

Additions to our environmental remediation provision reflect new

liabilities and scope/cost reassessments of the remediation plans of a

number of our sites, primarily in the US. The charge for environmental

remediation provisions in 2025 arising from new and acquired sites was

$4 million (2024 $24 million and 2023 $37 million).

In addition, we make provisions on installation of our oil and gas

producing assets and related pipelines to meet the cost of eventual

decommissioning. On installation of an oil or natural gas production

facility, a provision is established that represents the discounted value

of the expected future cost of decommissioning the asset.

In 2025 the net increase in the decommissioning provision was primarily

due to recognition of additional provisions from new infrastructure and

changes in cost estimate assumptions. .

We undertake periodic reviews of existing provisions. These reviews

take account of revised cost assumptions, changes in decommissioning

requirements and any technological developments.

Provisions for environmental remediation and decommissioning are

usually established on a discounted basis, as required by IAS 37

'Provisions, Contingent Liabilities and Contingent Assets'.

Further details of decommissioning and environmental provisions

appear in Financial statements – Note 23.

Regulation of the group's business

Our businesses and operations are subject to the laws and regulations

applicable in each country, state or other regional or local area in which

they occur. These cover virtually all aspects of bp's activities and

include matters such as the acquisition of rights to develop and operate

projects, production rates, royalties, environmental, health and safety

protection, fuel specifications and transportation, trading, pricing, anti-

trust, export, taxes, and foreign exchange.

**Oil and gas contractual and regulatory framework**

The terms and conditions of the leases, licences and contracts under

which our upstream oil and gas interests are held vary from country to

country. These leases, licences and contracts are generally granted by

or entered into with a government entity or state-owned or controlled

company and are sometimes entered into with private property owners.

Arrangements with governmental or state entities usually take the form

of licences or production-sharing agreements (PSAs)★, although

arrangements with private entities and US government entities are

usually by lease.

Licences (or concessions) give the holder the right to explore for,

develop and produce a commercial discovery. Under a licence, the

holder bears the risk of exploration, development and production

activities and provides the financing for these operations. In principle,

the licence holder is entitled to all production, minus any royalties that

are payable in kind. A licence holder is generally required to pay

production taxes or royalties, which may be in cash or in kind.

In certain countries, separate licences are required for exploration and

production activities, and in some cases production licences are limited

to only a portion of the area covered by the original exploration licence.

PSAs entered into with a government entity or state-owned or state-

controlled company generally require bp (alone or with other

contracting companies) to provide all the financing and bear the risk of

exploration and production activities in exchange for a share of the

production remaining after royalties, if any. Less typically, bp may

explore for, develop and produce hydrocarbons under a service

agreement with the host entity in exchange for reimbursement of costs

and/or a fee paid in cash rather than production.

bp frequently conducts its exploration and production activities in joint

arrangements or co-ownership arrangements with other international

oil companies, state-owned or -controlled companies and/or private

companies. Conventionally, all costs, benefits, rights, obligations,

liabilities and risks incurred in carrying out joint arrangement or co-

ownership operations under a lease, licence or PSA are shared among

the joint arrangement or co-owning parties according to agreed

ownership interests which are set out in a joint operating agreement. To

the extent that any liabilities arise, whether to governments or third

parties, or between the joint arrangement parties or co-owners

themselves, each joint arrangement party or co-owner will generally be

liable under the terms of a joint operating agreement to meet these in

proportion to its ownership interest. Any agreed allocation of liability

amongst the joint arrangement parties is, however, often different to

the position under the relevant licence, lease or PSA, which may provide

for joint and several liability of the joint arrangement parties including

for decommissioning obligations. In many upstream operations, a party

(known as the operator) will be appointed (pursuant to a joint operating

agreement) to carry out day-to-day operations on behalf of the joint

arrangement or co-ownership. The operator is typically one of the joint

arrangement parties or a co-owner and will carry out its duties either

through its own staff, or by contracting out various elements to third-

party contractors or service providers. bp acts as operator on behalf of

joint arrangements and co-ownerships in a number of countries.

Frequently, work (including drilling and related activities) will be

contracted out to third-party service providers. The relevant contract

will specify the work, the remuneration, and typically the risk allocation

between the parties. Depending on the service to be provided, the

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contract may also contain provisions allocating risks and liabilities

associated with pollution and environmental damage, damage to a well

or hydrocarbon reservoirs and for claims from third parties or other

losses. The allocation of those risks varies among contracts and is

determined through negotiation between the parties.

In general, bp incurs income tax on income generated from production

activities (whether under a licence or PSA). In addition, depending on the

area, bp's production activities may be subject to a range of other taxes,

levies and assessments, including special petroleum taxes and revenue

taxes. The taxes imposed on oil and gas production profits and activities

may be substantially higher than those imposed on other activities, for

example in Egypt, the UK, the US and the United Arab Emirates.

**Low carbon energy – renewables contractual and** 

**regulatory framework**

The majority of our renewable assets are held indirectly through

interests in incorporated joint ventures or special purpose entities (in

either case, a Project Company). The renewables contractual and

regulatory framework and the rights granted in relation to a renewable

asset significantly vary from country to country. In some countries, the

regulatory framework is still under development or subject to

significant change as the renewables industry evolves.

In general terms the rights to a renewable asset are usually held by a

Project Company through a package of assets that together form the

renewable project owned by such Project Company, including:

• one or more leases, easements or licences over land or seabed

granted by a public or private individual or entity that grant the

Project Company rights to develop, build and operate the renewable

asset in such areas of land or seabed;

• one or more generation licences that grant the Project Company the

right to produce and sell the electricity to the market;

• an interconnection agreement that grants the Project Company the

right to connect the power project into the grid;

• an offtake agreement which, depending on the country's electricity

market, is entered into with a utility company, a corporate buyer or a

public entity; and

• potentially, a subsidy mechanism in the form of a feed in tariff,

contract for difference, hedging mechanism or renewable energy

certificate to support the development of the project.

The risk allocation between the developer/generator and the host

government or private entity has not been standardized in the industry.

However, in general terms the Project Company bears the risk of the

development, construction and operation of the renewable energy

project and secures the financing for these operations and receives any

profit from the revenue generated through the offtake agreement and/

or subsidy mechanism (if available).

**Greenhouse gas regulation**

In December 2015, nearly 200 nations at the United Nations climate

change conference in Paris (COP21) agreed to the Paris Agreement

which aims to hold the increase in the global average temperature to

well below 2°C above pre-industrial levels and to pursue efforts to limit

the temperature increase to 1.5°C above pre-industrial levels.

Signatories aim to reach global peaking of greenhouse gas (GHG)

emissions as soon as possible and to undertake rapid reductions

thereafter, so as to achieve a balance between human caused

emissions and removals by sinks of GHGs in the second half of this

century. The Paris Agreement commits all signatories to submit

Nationally Determined Contributions (NDCs) (i.e. pledges or plans of

climate action) and pursue domestic measures aimed at achieving the

objectives of their NDCs. Signatories are required to submit revised

NDCs every five years, and the revised NDCs are expected to be more

ambitious with each revision. The first global stocktake of progress was

published by the United Nations in September 2023 and further

assessments will occur every five years. The UAE conference (COP28) in

Dubai, which took place in November and December 2023, marked the

conclusion and outcome of this first stocktake and reached a

consensus which includes calls for an acceleration of efforts towards

the phase-down of unabated coal power and to transition away from

fossil fuels in energy systems. The 2024 Baku conference (COP 29)

included agreements in relation to finance and carbon markets. The

2025 Belém conference (COP30) included agreement to triple

adaptation finance by 2035, and emphasized accelerating the shift to

renewable energy sources, and ensuring a just transition.

More stringent national and regional measures relating to the transition

to a lower carbon economy, such as the UK's 2050 net zero carbon

emissions commitment, can be expected in the future. These measures

could increase bp's production costs for certain products, increase

compliance and litigation costs, increase demand for competing energy

alternatives or products with lower-carbon intensity, and affect the

sales and specifications of many of bp's products. Further, such

measures could lead to constraints on production and supply and

access to new reserves, particularly due to the long-term nature of

many of bp's projects.

Certain current and announced GHG measures and developments

potentially affecting bp's businesses in various markets in which bp

operates are summarized below. For information on steps that bp is

taking in relation to climate change issues and for details of bp's GHG

reporting, see page <u>[37](#i0dd2ee81aac04f8c9c97c86197f0c6df_79)</u>.

**United States**

In the US, bp's operations are affected by the regulation of GHGs in a

number of ways. The federal Clean Air Act (CAA) and its various

amendments regulate air emissions, permitting, fuel specifications and

other aspects of our production, refining, distribution and marketing

activities.

GHG Reporting Rule

The federal GHG Mandatory Reporting Rule requires operators of

certain facilities and producers and importers/exporters of petroleum

products to file annual GHG emissions reports with EPA quantifying

direct GHG emissions from affected facilities, as well as the GHG

emissions that would result from the release or combustion of the

petroleum products imported, exported or produced. In addition,

several states have their own GHG reporting rules.

Our US businesses are subject to GHG and other environmental

requirements and regulatory uncertainty, including that the current or

any future US administration could revise or revoke current or prior

administration programmes, as well as the possibility of increased

expenditures in having to comply with numerous diverse and non-

uniform regulatory initiatives at the state and local levels. In September

2025, the United States Environmental Protection Agency (US EPA)

proposed regulations that would revoke or suspend GHG reporting

requirements for the oil and gas sector for 10 years.

US Inflation Reduction Act

The 2022 US Inflation Reduction Act (IRA) included a significant package

of largely supply-side measures supporting low carbon energy sources

and decarbonization technologies in the US. In 2023, bp applied for

various DOE and FAA grants related to certain of bp's low carbon

energy and decarbonization projects. In 2024 DOE and FAA notified bp

of its grant awards and bp and its co-applicants executed award

agreements with the DOE. On 20 January 2025, the Trump

Administration issued an Executive Order directing agencies to pause

the disbursement of IRA funding for review. This Order is subject to

legal challenges that have resulted in the effective suspension of

implementation pending judicial resolution.

Methane

In 2024 the EPA promulgated the "Standards of Performance for New,

Reconstructed, and Modified Sources and Emissions Guidelines for

Existing Sources: Oil and Natural Gas Sector Climate Review." These

regulations focused on methane and volatile organic compound

emissions from oil and gas production at new and existing facilities and

include significant requirements in the areas of fugitive emissions

monitoring and repair, flaring, emission event reporting, process

controller and pump emissions, and storage vessels. In March 2025, the

EPA announced reconsideration of the 2024 regulations, and, in

December 2025, finalized the Interim Final Rule extending many of the

original compliance deadlines in the 2024 regulations.

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Separate from the above, the IRA required EPA to collect an annual

Waste Emissions Charge (WEC) on methane emissions from oil and

natural gas facilities that exceed specific levels of emissions and

methane intensity. In November 2024, EPA promulgated regulations to

implement the WEC provisions of the IRA, but those regulations were

disapproved by the US Congress in March 2025 and are no longer in

place.

Climate Resilience Funds

Several US states, including New York and Vermont, have enacted laws

seeking recovery from historical GHG emitters to create climate

resilience funds to address climate change impacts by financing

infrastructure upgrades, disaster preparation, and other resilience

projects. Other states, including New Jersey, California, Maryland and

Massachusetts, are considering similar legislation. The extent and cost

of such future environmental climate fund programmes are difficult to

estimate at this time.

Electricity

Other EPA GHG and environmental regulations affect electricity

generation practices and prices and have an impact on the market for

fuels used to generate electricity and on renewable energy installations.

These regulations are in flux due to changes in approach between

presidential administrations, as well as lawsuits challenging those

regulations.

The 2022 Supreme Court decision in West Virginia v. EPA limited EPA's

regulatory authority to require electricity 'generation shifting' (e.g. from

coal to natural gas or renewable sources). In response to the West

Virginia v. EPA decision, in April 2024 EPA promulgated new carbon

pollution standards for coal and gas-fired power plants. The regulations

significantly tighten emissions limits for those plants and will require

some plants to install carbon capture technology. In 2025 EPA

proposed repealing those regulations.

Renewable Fuel Standard

EPA's Renewable Fuel Standard (RFS) regulations require transportation

fuel sold in the US to contain a minimum volume of renewable fuels. In

2023, EPA announced a final rule establishing biofuel volume

requirements and associated percentage standards (renewable volume

obligations or RVOs) for cellulosic biofuel, biomass-based diesel,

advanced biofuel, and total renewable fuel for 2023-2025, which was

remanded to EPA and the wildlife agencies for further explanation. EPA

is delayed in promulgating RVOs for 2026, but in a deadline lawsuit

challenging the agency's delay, EPA stated its intention to finalize the

regulations in the first quarter of 2026.

State Low Carbon Fuel Standards

A number of states, municipalities and regional organizations continue

to advance climate initiatives that affect our US operations. For

example, California, Oregon, and Washington impose carbon-intensity

reduction requirements on transportation fuels sold in those states. In

November 2024, California updated its Low Carbon Fuel Standard

(LCFS) to achieve a 30% reduction in carbon intensity by 2030 and a

90% reduction in carbon intensity by 2045. In 2024 New Mexico became

the latest US state to enact LCFS legislation, with regulations likely to

take effect in 2026.

Mobile Source Emissions

US fuel markets are affected by EPA and National Highway Traffic

Safety Administration (NHTSA) regulation of light, medium and heavy-

duty vehicle emissions (both fuel economy and tailpipe standards) as

well as for non-road engines and vehicles and certain large GHG

stationary emission sources. In August 2025, EPA issued a proposed

recission of all federal GHG emission standards and the Endangerment

Finding that provides the legal justification for such GHG standards for

light-, medium- and heavy-duty vehicles. EPA has not yet finalized the

proposed recissions and legal challenges to rescinding the 2009

Endangerment Finding are expected. In December 2025, NHTSA

proposed to reduce the stringency of fuel economy standards for light-

duty vehicles. Relatedly, in July 2025, the US Congress eliminated civil

penalties for non-compliance with corporate average fuel economy

standards.

Light-duty and Medium Duty Vehicles

In March 2024, EPA promulgated a final rule entitled "Multi-Pollutant

Emissions Standards for Model Year 2027 and Later Light-Duty and

Medium-Duty Vehicles," which significantly tightens emissions

standards for light- and medium-duty vehicles for model year (MY) 2027

and beyond and imposes new warranty, durability, and certification

requirements, including for electric vehicles. The regulations are

intended to spur emissions reductions technology on hydrocarbon-

powered vehicles and to encourage the transition to electric vehicles.

The regulations will phase in over MY 2027-2032. In March 2025, EPA

announced that it would reconsider the regulations.

Heavy-Duty Vehicles

In 2022, EPA promulgated a final rule entitled "Control of Air Pollution

from New Motor Vehicles: Heavy Duty Engine and Vehicle Standards,"

which established new emission standards for oxides of nitrogen (NOx)

and other pollutants for highway heavy-duty engines. In March 2025,

EPA announced that it would re-evaluate that final rule.

California Mobile Sources

The CAA authorizes the state of California to set its own separate

vehicle emissions regulations, stricter than those at the federal level.

Under CAA Section 209, California can apply to EPA for a waiver of

federal pre-emption, and EPA is to grant this waiver absent certain

disqualifying conditions. Under CAA Section 177, other states can adopt

California standards or follow federal standards but cannot set their

own. In May 2025, the US Congress passed resolutions under the

Congressional Review Act (CRA) rescinding EPA waivers covering

California's Advanced Clean Cars (ACC) II, Advanced Clean Trucks (ACT),

and Heavy-Duty Low NOx Omnibus (Omnibus) regulations, which set

emissions standards and sales mandates for zero-emission vehicles

(ZEVs) in the state. California and other states have sued to challenge

these CRA recissions, and California has offered manufacturers

alternative paths for certification of new vehicles in the state – including

continued compliance with the regulations subject to CRA disapproval,

compliance with superseded California standards, or compliance with

EPA standards and certification requirements. Meanwhile, EPA and

other parties have contested whether California can fall back on pre-

existing standards or else require certification within the state for

current and future model years.

In October 2025, a federal district court issued a preliminary injunction

barring California from attempting to enforce the Clean Truck

Partnership – a 2023 agreement between California and the heavy-duty

vehicle and engine manufacturers under which the manufacturers

agreed to comply with California regulations in exchange for more lead

time and other measures. Claims challenging California's continued

enforcement of ACC II, ACT and Omnibus remain pending in the case.

California Advanced Clean Cars Program

California's ACC regulations were originally enacted in 2012 for MY 2015

to 2025. The ACC program is a package of state regulations that set

emissions standards for criteria pollutants, GHG emission standards for

light-duty vehicles, and a ZEV sales mandate. In 2019, EPA and NHTSA

jointly promulgated the "Safer Affordable Fuel-Efficient Vehicles Rule

Part One: One National Program (SAFE-1)," which effectively disallowed

the ACC program. In 2021, EPA revoked SAFE-1, and the ACC program

went back into force. In response to a legal challenge, the US Court of

Appeals for the DC Circuit upheld EPA's decision to restore the

California waiver. That decision was appealed to the Supreme Court,

which did not review the waiver itself but held that fuel producers had

standing to challenge the waiver. That litigation is now stayed as EPA

again reconsiders the waiver decision. In 2022, California finalized the

next generation of its GHG and ZEV standards ACC II sets annual ZEV

and plug-in hybrid vehicle (PHEV) sales requirements from MY 2026 to

2035 and increasingly more stringent emission standards to ensure

automakers gradually phase out new sales of internal combustion

engine vehicles.

In 2023 California filed a CAA Section 209 waiver of federal pre-emption

application with EPA. In December 2024, EPA granted California's

waiver under ACC II that requires that by MY 2035, all new light-duty

vehicles sold in California must be ZEVs or PHEVs. As noted above, in

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May 2025, Congress passed the CRA resolution rescinding the ACC II waiver,

which California and other states have challenged.

California Advanced Clean Trucks Program

In 2023, EPA granted California's request for a waiver of federal

preemption covering, in part, ACT regulations, which mandate

increasing quantities of ZEV sales for medium- and heavy-duty vehicles

in the state. As noted above, in May 2025, the US Congress passed a

resolution under the CRA that purports to void that waiver. Legal

challenges to the CRA resolution, as well as legal challenges to

continuing efforts to enforce the ACT Program, have been filed and are

pending.

EPA Proposal to Rescind Endangerment Finding

In 2025 EPA proposed to rescind the 2009 Endangerment Finding,

which forms the statutory basis for GHG emissions regulations for

motor vehicles and engines under the Clean Air Act, including the Biden

Administration electric vehicle mandates. If finalized, the proposal

would remove all GHG standards for light-, medium- and heavy-duty

vehicles and heavy-duty engines. EPA indicated it will solicit public

comment on the proposal.

These and other initiatives regarding GHG emissions create significant

regulatory uncertainty and may have a significant effect on the

production, sale and profitability of many of bp's products in the US.

**European Union** 

The EU has adopted a goal of achieving climate neutrality by 2050 as

part of the European Green Deal and, subsequently, a 55% GHG

reduction target by 2030 and a 90% target by 2040, both compared to

1990 levels. To achieve the 2030 target, EU member states and

Parliament adopted most measures proposed as part of the so-called

'Fit for 55' package. These include: revisions of the EU Emissions Trading

Scheme (EU ETS) and a newly created Carbon Border Adjustment

Mechanism (CBAM); the Renewable Energy Directive (RED) – including

an obligation on transport fuel suppliers to increase the share of

renewables of their fuel supply; a sustainable aviation fuel (SAF)

blending mandate from 2025; and CO2 targets for the sales of new

vehicles which are expected to accelerate the decarbonization of the

transport sector and impact fuel demand despite certain flexibilities for

vehicle manufacturers currently under discussion. We expect changes

to some of these laws as part of planned reviews and to bring them in

line with the recently agreed 2040 GHG reduction target.

Pending full implementation and ongoing and future revisions of these

laws, this would inter alia lead to higher shares of renewables across all

sectors (including transport), higher cost to supply fuels due to a cap-

and-trade system for the road transport and buildings sector starting in

2028, a continuously reduced number of GHG emission allowances and

associated free allocation under the EU ETS, and a continued decline of

fuel demand from new cars and trucks linked to CO2 targets for vehicle

manufacturers. The EU also adopted measures that may impact the

ability to import certain crude oils and natural gas into the region.

Some EU member states have adopted national targets above and

beyond current EU climate goals, such as Germany, with a climate

neutrality target by 2045.

**United Kingdom**

In November 2024, the UK government announced a nationally

determined contribution target to reduce all greenhouse gas emissions

by at least 81% by 2035 compared to 1990 levels.

The UK Emissions Trading System (UK ETS) launched on 1 January 2021

following the end of the Brexit transition period and the UK's

participation in the EU ETS. It seeks to provide a carbon pricing

mechanism as a tool for helping achieve the UK's net zero target and

covers the same GHGs and sectors as the EU ETS. bp's North Sea

operations are subject to the UK ETS.

In July 2023, the UK government published a response to a 2022

consultation on proposed changes to the UK ETS rules. That response

included decisions to expand the scope of the scheme to include

domestic maritime transport from 2026, waste incineration and energy

from waste from 2028 and process emissions from carbon dioxide

venting from the upstream oil and gas sector from 2025.

In November 2025, the UK government and the UK ETS Authority

published their combined response to the December 2023 Free

Allocation Review and the December 2024 Carbon Leakage

consultations. In relation to data and benchmarking, the UK ETS

Authority decided that operators can choose to have their activity data

for either 2020 only, or 2020 and 2021, excluded from determining their

historical activity level for the 2027-30 allocation period. Current

benchmarks for 2027 are retained, with the intention of adopting

updated EU benchmark values from 2028-30. In relation to carbon

leakage, the UK ETS Authority decided that: (i) The current list of sectors

subject to carbon leakage is retained; (ii) It will not introduce the tiering

of free allocations of UK ETS allowances for sectors at risk of carbon

leakage based on the carbon leakage exposure factor or cross-sectoral

correction factor; (iii) It will not bring forward the phase out of free

allocations for sectors not at risk of carbon leakage; (iv) No additional

benchmarking methodologies will be introduced in 2027, which would

have introduced conditions on the provision of free allocation to

installations with exceptional access to decarbonisation technologies.

Their introduction may be reconsidered for future allocation periods;

and (v) It will gradually phase out free allocations for sectors covered by

the UK Carbon Border Adjustment Mechanism (UK CBAM) beginning in

2027, with an indicative phase out trajectory of nine years.

In December 2025, the UK ETS published the response to its December

2023 Future Markets Policy consultation. The response indicates that

the UK ETS Authority will retain and inflation-proof the auction reserve

price to maintain its real value, implementing an inflation-based

increase since its introduction in 2026, and increasing the value yearly

by inflation from 2027. It will retain the existing design and operation of

the cost containment mechanism and retain its discretion. It will also

discount the implementation of a quantity-triggered supply adjustment

mechanism for a standalone UK ETS.

In December 2025, UK government also published a response to the UK

ETS Authority's consultation to extend the UK ETS beyond 2030. The

response confirmed it will be extended into a Phase II from 2031, which

will run for 10 years from 1 January 2031 to 31 December 2040, and

banking of allowances will be permitted between Phase I and Phase II.

**Other countries and regions**

China is operating emissions trading pilot programmes in a number of

cities and provinces. One of bp's subsidiaries in China is participating in

these programmes. In February 2021 China introduced a national

emissions trading market (National ETS). The National ETS is intended to

be an essential tool for China to fulfil its commitment to reach peak

emissions by 2030 and carbon neutrality by 2060. On 9 September

2024, the Ministry for Ecology and Environment of China (the MEE)

released a draft work plan to expand the sectoral coverage of the

National ETS. Currently covering only the power sector, the plan

proposes to extend the National ETS to include the cement, steel, and

aluminium industries. In March 2025, the MEE officially expanded the

sectoral coverage of the National ETS to include the cement, steel, and

aluminium industries. The expansion would bring an additional

approximately 1,500 companies into the National ETS. For now, the

National ETS participants are limited to the key emission entities

identified by each provincial-level government authority based on the

standard set out by the MEE. bp is not participating in the National ETS.

In October 2021, as part of its '1+N' climate policy framework, China

issued working guidance setting out specific targets and measures for

achieving peak carbon emissions and carbon neutrality, and an action

plan which sets out the main objectives for the next decade to achieve

peak carbon emissions by 2030. The working guidance is the '1' (i.e. a

long-term approach to combating climate change), while 'N' are various

policies starting with the action plan. In June 2022, 17 government

authorities jointly released the National Climate Change Adaptation

Strategy 2035 making overall plans to prepare the country to adapt to

climate change from the present to 2035.

China's domestic voluntary carbon mechanism called the China

Certified Emission Reduction (CCER) programme has been suspended

since 2017. In 2023, significant progress towards relaunching the CCER

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has been made by relevant authorities, including the promulgation of a

regulation on CCER trading for trial implementation and the publication

of methodologies that will be used to quantify net emission reductions

or removals for four types of projects (forestation, solar thermal power,

offshore wind power generation and mangrove revegetation). CCER

programme was relaunched on 22 January 2024 and the first CCER

project after the relaunch was registered on 3 December 2024. On 3

January 2025, two new CCER methodologies were released – for

issuing carbon credits to projects utilizing coal mine gas and energy

efficient highway tunnel lighting. First batch of new CCERs was issued

in March 2025 and more CCER methodologies were released in 2025.

On 5 January 2024, China's State Council approved an interim

regulation for the national emissions trading scheme. The final version

was issued on 4 February 2024 which has provisions on defining the

scale of the national carbon market, determining allocation of

emissions allowances and data quality supervision.

**Other environmental regulation**

In addition to the GHG regulations referred to above, climate change

programmes and regulation of unconventional oil and gas extraction

under a number of environmental laws may have a significant effect on

the production, sale and profitability of many of bp's products.

Environmental laws also require bp to remediate and restore areas

affected by the release of hazardous substances or hydrocarbons

associated with our operations or properties. These laws may apply to

sites that bp currently owns or operates, sites that it previously owned

or operated, or sites used for the disposal of its and other parties'

waste. See Financial statements – Note 23 for information on provisions

for environmental restoration and remediation.

A number of pending or anticipated governmental proceedings against

certain bp group companies under environmental laws could result in

monetary or other sanctions. Group companies are also subject to

environmental claims for personal injury and property damage alleging

the release of, or exposure to, hazardous substances. The costs

associated with future environmental remediation obligations,

governmental proceedings and claims could be significant and may be

material to the results of operations in the period in which they are

recognized. We cannot accurately predict the effects of future

developments, such as stricter environmental laws and regulations or

enforcement policies, or future events at our facilities on the group, and

there can be no assurance that material liabilities and costs will not be

incurred in the future. For a discussion of the group's environmental

expenditure, see page <u>[352](#i0dd2ee81aac04f8c9c97c86197f0c6df_499)</u> and for a discussion of legal proceedings,

see page <u>[236](#i0dd2ee81aac04f8c9c97c86197f0c6df_379)</u>.

Significant health, safety and environmental legislation and regulation

affecting our businesses and profitability, in addition to those referred

to above, include the following:

**United States**

• The Clean Water Act regulates wastewater and other effluent

discharges from bp's facilities, and bp is required to obtain

discharge permits, install control equipment and implement

operational controls and preventative measures.

• The Resource Conservation and Recovery Act (RCRA) regulates the

generation, storage, transportation and disposal of wastes

associated with our operations and can require corrective action at

locations where such wastes have been disposed of or released. bp

has incurred, or is likely to incur, liability under RCRA or similar state

laws in connection with sites bp operates or previously operated.

• The Comprehensive Environmental Response, Compensation, and

Liability Act (CERCLA) can, in certain circumstances, impose the

entire cost of investigation and remediation on a party who owned or

operated a site contaminated with a hazardous substance, or who

arranged for disposal of a hazardous substance at a site. bp has

incurred, or is likely to incur, liability under CERCLA or similar state

laws, including costs attributed to insolvent or unidentified parties.

bp is also subject to claims for remediation costs and natural

resource damages under CERCLA and other federal and state laws.

CERCLA also requires reporting on the releases of certain quantities

of listed hazardous substances to designated government agencies.

In April 2024, EPA listed PFOA and PFOS (types of perfluoroalkyl

substances (PFAS) used in fire-fighting foam and many consumer

products) as hazardous substances under CERCLA. This listing may

impact remediation costs and result in additional reporting and

other environmental obligations. Several states have passed

legislation limiting the use of PFAS in fire-fighting foam, and other

states may do so in the future.

• The Emergency Planning and Community Right-to-Know Act

requires reporting on the storage, use and releases of certain

quantities of listed extremely hazardous substances to designated

government agencies.

• The Toxic Substances Control Act regulates bp's manufacture,

import, export, sale and use of chemical substances and products. In

addition, EPA has revised processes and procedures for prioritization

of existing chemicals for risk evaluation, assessment and

management. Agency actions and announcements are monitored

regularly to identify developments with potential impacts on

chemical substances important to bp products and operations.

• The Occupational Safety and Health Act imposes workplace safety

and health requirements on bp operations along with significant

process safety management obligations, requiring continuous

evaluation and improvement of operational practices to enhance

safety and reduce workplace emissions at gas processing, refining

and other regulated facilities.

• The Oil Pollution Act 1990 imposes operational requirements, liability

standards and other obligations governing the transportation of

petroleum products in US waters. States may impose additional

obligations. Alaska, West Coast and certain East Coast states impose

additional requirements and stricter liability standards.

• The Outer Continental Continental Shelf Land Act, the Mineral

Leasing Act and other statutes give the Department of Interior (DOI)

and the Bureau of Land Management authority to regulate

operations and air emissions, including equipment and testing, at

offshore and onshore operations on federal lands subject to DOI

authority.

• The Endangered Species Act (ESA) and Marine Mammal Protection

Act protect certain species' habitats from adverse human impacts

by restricting operations or development at certain times and in

certain places. In 2020, the US Fish and Wildlife Service (FWS)

published regulatory definitions impacting habitat designations

under the ESA, but in 2022 the Biden administration rescinded those

definitions. The Biden administration rescission of those definitions

could expand the geographic areas subject to habitat protections. In

November 2025, the FWS proposed to reinstate the 2020 version of

the habitat designation regulations.

**European Union**

• The Industrial Emissions Directive (IED) 2010 provides the framework

for granting permits for major industrial sites. Revised IED entered

into force in August 2024, strengthening the application of Best

Available Techniques (BATs) and introducing stricter emission limit

values and binding environmental performance levels, among other

changes. It will impact bp refineries across Europe.

• The EU Registration, Evaluation Authorization and Restriction of

Chemicals (REACH) Regulation 2006 requires registration of

chemical substances manufactured in or imported into the EU,

together with the submission of relevant hazard and risk data.

REACH affects our manufacturing or trading/import operations in

the EU. bp maintains compliance by checking whether imports are

covered by the registrations of non-EU suppliers' representatives,

preparing and submitting registration dossiers to cover new

manufactured and imported substances, and updating previously

submitted registrations as required.

• The Water Framework Directive (WFD) published in 2000 aims to

protect the quantity and quality of ground and surface waters of the

EU member states. The transposition into national laws is still

ongoing and planned to be finalized by 2027. Future proceedings on

the determination of pollutants/priority substances as well as

environmental quality standards in line with the WFD may require

additional compliance efforts and increased costs for managing

freshwater withdrawals and discharges from bp's EU operations.

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| bp Annual Report and Form 20-F 2025 | 357 |

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| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Additional disclosures** |

---

• The Corporate Sustainability Reporting Directive (CSRD) entered into

force on 5 January 2023 introducing new requirements for certain

EU and non-EU companies, to include disclosures related to climate,

the environment and wider sustainability issues. The CSRD also

expands to in-scope entities the requirements introduced by the EU

Taxonomy Regulation, to identify environmentally sustainable

activities and then disclose metrics related to capital and operating

expenditure and turnover associated with those activities. Under the

2025 Omnibus simplification package, the application of CSRD

reporting requirements has been delayed by two years for many in-

scope companies, with reporting expected to begin in 2027 for

FY2026.

• The Corporate Sustainability Due Diligence Directive (CSDDD)

entered into force in July 2024 but has undergone targeted

amendments as part of the Omnibus package. It still requires certain

EU and non-EU companies to conduct due diligence on human rights

and environmental risks but no longer includes the obligation to

adopt a climate transition plan. In-scope companies are expected to

comply in July 2029 for FY2028.

**United Kingdom**

• Following the UK's exit from the European Union, operative EU laws

were retained in UK law by the European Union (Withdrawal) Act 2018

(EUWA). In June 2023, the Retained EU Law (Revocation and Reform)

Act 2023 received Royal Assent. From 1 January 2024, retained EU

law is now termed "assimilated law," and the Act removed the

principle of EU law supremacy and direct effect. The Act allows for

significant changes to the status, operation and content of retained

EU law, including through amendments to the EUWA. This may mean

that over time there will be amendments to and deviations from

retained EU law including in respect of environmental matters.

• Since the end of the transition period on 31 December 2020, there

has been a parallel UK REACH regime which applies in Great Britain

only, with EU REACH continuing to apply in Northern Ireland. UK

REACH contains equivalent requirements to EU REACH, although

future developments and potential divergences are uncertain.

• The Environment Act 2021 comprises various key parts including

governance, waste and resource efficiency, air quality and

environmental recall, water, nature and biodiversity and

conservation covenants. The governance parts include a

comprehensive framework for legally binding environmental

improvement targets; to establish a framework for future policy

statements on environmental principles to protect the environment

by making environmental considerations a key part of policy

development process across government; and to establish the

Office for Environmental Protection, an independent public body to

have oversight of environmental matters. The UK government's first

suite of environmental targets became law in January 2023, but

these have not had a material impact on bp.

**Other countries and regions**

Regulations governing the discharge of treated water have also been

developed in countries outside the US and EU, including in Trinidad and

Tobago where bp commissioned a new wastewater treatment plant in

2020 to meet consent levels agreed with the regulators to apply

relevant water discharge rules.

The Abidjan Convention, together with its Additional Protocols, sets

environmental quality standards for the discharge of chemicals to the

marine environment. Mauritania and Senegal are both signatories to the

Abidjan Convention. bp's offshore facilities have implemented water

management systems which are designed to meet the environmental

quality standards for their gas operations in Mauritania and Senegal.

The Convention for the Protection of the Marine Environment of the

North-East Atlantic (OSPAR) aims to protect the marine environment of

the North-East Atlantic. The OSPAR 2012 recommendation and guideline

for the implementation of a risk-based approach to the management of

produced water discharges from offshore installations in the North Sea

supports a key goal of working towards eliminating harmful discharges.

In 2020 the International Association of Oil and Gas Producers issued a

report 'Oil And Gas Risk Based Assessment of Offshore Produced Water

Discharges' which presents industry good practice and aims to broaden

the understanding and acceptance of Risk Based Assessment (RBA)

techniques internationally and improve consistency in the application of

assumptions, levels of conservatism, and selection of risk endpoints.

At OSPAR's Offshore Industry Committee (OIC) meeting in March 2024,

the Committee agreed changes to OSPAR's List of Substances/

Preparations Used and Discharged Offshore which are Considered to

Pose Little or No Risk to the Environment (PLONOR). This includes two

inorganic substances, calcium bromide and sodium bromide which are

used in Completion fluid formulations. Further work is progressing on

the harmonisation of OSPAR's approach to offshore chemicals and the

REACH Regulation, now focused on the potential impact of adjustments

to the current Harmonised Mandatory Control System (HCMS) for

regulators and industry. OIC also agreed the report on the

implementation of OSPAR Recommendation 2006/3 on Environmental

Goals for the Discharge by the Offshore Industry of Chemicals that Are,

or Which Contain Substances Identified as Candidates for Substitution –

Technical and Safety Obstacles.

**Environmental maritime regulations**

bp's shipping operations are subject to extensive national and

international regulations governing operations, training, pollution

prevention, liability, and insurance. These include:

• Liability and spill prevention and planning requirements governing,

among others, tankers, barges, and offshore facilities are imposed

by OPA in US waters. OPA also mandates a levy on imported and

domestically produced oil to fund oil spill responses. Some states,

including Alaska, Washington, Oregon and California, impose

additional liability for oil spills. Outside US territorial waters, bp

shipping tankers are subject to international pollution prevention,

liability, spill response and preparedness regulations developed

through the UN's International Maritime Organization (IMO),

including the International Convention on Civil Liability for Oil

Pollution Damage, the International Convention for the Prevention of

Pollution from Ships (MARPOL), the International Convention on Oil

Pollution, Preparedness, Response and Co-operation, and the

International Convention on Civil Liability for Bunker Oil Pollution

Damage. In April 2010, a Protocol was adopted to address issues that

have inhibited ratification of the International Convention on Liability

and Compensation for Damage in Connection with the Carriage of

Hazardous and Noxious Substances by Sea 1996 (HNS Convention).

As at 31 December 2025, the HNS Convention had not entered into

force.

• A global sulphur cap of 0.5% applies to marine fuel under MARPOL

with a stricter 0.1% cap in environmentally sensitive areas. In order to

comply, ships either need to consume low sulphur marine fuels,

operate on alternative low sulphur fuels such as LNG or implement

approved abatement technology to enable them to meet the low

sulphur emissions requirements while continuing to use higher

sulphur fuel. Certain regional and local authorities also enforce

sulphur caps outside of the MARPOL framework.

• From 2023 all vessels over 400 gross tonnage became subject to

IMO requirements as to energy efficiency design (EEXI) and the

carbon intensity of operations (CII).

• Under EU legislation, maritime transport has been brought into the

scope of the EU ETS from 2024, applicable to all vessels of 5,000

gross tonnage and above calling at EU ports regardless of a vessel's

flag.

• Under the Fuel EU Maritime Regulation, from 2025 ship owners are

required to reduce the GHG intensity of their fuel use gradually over

time, initially by 2%, increasing to 6% by 2030 and 80% by 2050.

• From 2025 tankers calling at California's major ports must comply

with emission reduction and reporting requirements set by the

California Air Resources Board (CARB), aimed at limiting emission of

pollutants including oxides of nitrogen (Nox) and diesel particulate

matter.

To meet its financial responsibility requirements, bp shipping maintains

marine oil pollution liability insurance in respect of its operated ships to

a maximum limit of $1 billion for each occurrence through mutual

insurance associations (P&I Clubs), although there can be no assurance

that a spill would necessarily be adequately covered by insurance or

that liabilities would not exceed insurance recoveries.

---

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| 358 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

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International trade sanctions

During the period covered by this report, non-US subsidiaries, or other

non-US entities of bp, conducted limited activities in, or with persons

from, certain countries identified by the US Department of State as

State Sponsors of Terrorism or otherwise subject to US, EU and UK

sanctions (Sanctioned Countries). In 2025 sanctions restrictions were

insignificant to the group's financial condition and results of operations.

bp monitors its activities with Sanctioned Countries, persons from

Sanctioned Countries and individuals and companies subject to US, EU

and UK sanctions and seeks to comply with applicable sanctions laws

and regulations.

bp has a 29.99% interest in and operates the Shah Deniz field in

Azerbaijan (Shah Deniz), has a 29.99% interest in and performs some

operations for a related gas pipeline entity, South Caucasus Pipeline

Company Limited (SCPC), and has a 23.99% non-operating interest in a

related gas marketing entity, Azerbaijan Gas Supply Company Limited

(AGSC). Naftiran Intertrade Co. Limited and NICO SPV Limited

(collectively, NICO) have a 10% non-operating interest in each of Shah

Deniz and SCPC and an 8% non-operating interest in AGSC. LUKOIL

Overseas Shah Deniz Limited and LUKOIL Overseas Shah Deniz

Midstream Limited (collectively, LUKOIL Shah Deniz) have a 19.99% non-

operating interest in each of Shah Deniz and SCPC and a 15.99% non-

operating interest in AGSC.

Shah Deniz, SCPC and AGSC continue in operation as they were

excluded from the application of US Iran sanctions as they fall within the

exception for certain natural gas projects under Section 603 of the Iran

Threat Reduction and Syria Human Rights Act of 2012 (ITRA). Shah Deniz

was excluded from the main operative provisions of the EU sanctions

regulations following the snap-back of the EU Iran sanctions in

September 2025. In September and October 2025, the UK issued two

general licences permitting UK persons to conduct activities relating to

Shah Deniz, SCPC and AGSC that would otherwise be prohibited by UK

Iran and Russia sanctions respectively.

On 3 December 2018 bp entered into an agreement with, among others,

SOCAR and NICO pursuant to which SOCAR pays to BP Exploration

(Shah Deniz) Limited (BPXSD), as the Shah Deniz operator, compensation

for NICO's waiver of its right to lift its share of Shah Deniz condensate.

Such amounts are used to cover cash calls to NICO in respect of

operating costs due from NICO to BPXSD. On 20 November 2025, a

similar arrangement was entered into among bp, SOCAR and LUKOIL

Shah Deniz. In November 2025, OFAC issued a licence in relation to

these arrangements which is subject to further renewal before its expiry

in April 2026.

In 2025 international sanctions against Syria were significantly lifted. bp

terminated all sales of crude oil and petroleum products into Syria

following the imposition in 2011 of further US and EU sanctions against

Syria at the time, though bp continues to supply aviation fuel to non-

governmental Syrian resellers outside of Syria.

bp has a joint arrangement in Cuba which imports, manufactures,

markets and sells lubricants.

Since 2014, the US and the EU have imposed sanctions on certain

sectors of the Russian economy (energy, finance and defence/military)

and on certain individuals and entities, including Rosneft. These sectoral

sanctions include restrictions on certain oil and gas activities in Russia

including the provision of financial assistance, technical assistance,

goods and services.

In response to Russia's military action in Ukraine in 2022, the US, EU, UK

and many other countries have imposed broad economic and trade

sanctions. The scope of these sanctions includes restrictions on dealing

with designated individuals and entities (including Rosneft and Lukoil as

of 2025); restrictions on the Russian financial sector; blocking economic

activity in certain areas of Ukraine not controlled by the Ukrainian

government; prohibitions in relation to investment in Russia;

prohibitions and restrictions relating to Russian origin oil and oil

products; prohibitions and restrictions relating to Russian origin iron

and steel products, prohibitions and restrictions relating to Russian

origin metals, prohibitions and restrictions on the provision of certain

legal advisory services, prohibitions and restrictions in relation to

transportation, including shipping and aircraft; trade controls limiting

the purchase and import of a wide range of goods from Russia, and

export controls limiting the export of a wide range of goods and

technical assistance to Russia.

In response, Russia has implemented counter-sanctions including

restrictions on the divestment from Russian assets by foreign investors

and restrictions on the payments of dividends to certain foreign

shareholders, including those based in the UK, requiring such dividends

to be paid in roubles into restricted bank accounts and a requirement

for approval of the Russian government for transfers from any such

bank accounts out of Russia.

The bp group does not source any materials directly from Russia. In

2022 bp discontinued sales of our products to customers in Russia.

Such sales were not material to the bp group. As a result, outside of our

shareholding in Rosneft and related businesses in Russia, direct

impacts due to exposure to Russia have not been material and are not

expected to be material in the future. bp continues to monitor Russia

related sanctions and other international restrictions for any impacts on

our businesses and the exit of our shareholding in Rosneft.

bp maintains bank accounts and has registered and paid required fees

to maintain registrations of patents and trademarks in certain

Sanctioned Countries.

bp has equity interests in non-operated joint arrangements with air fuel

sellers, resellers, and fuel delivery services around the world. From time

to time, the joint arrangement operator or other partners may sell or

deliver fuel to airlines from Sanctioned Countries or flights to

Sanctioned Countries, without bp's involvement.

bp has no control over the activities non-controlled associates may

undertake in Sanctioned Countries or with persons from Sanctioned

Countries.

**Disclosure pursuant to ITRA Section 219**

To our knowledge, none of bp's activities, transactions or dealings are

required to be disclosed pursuant to ITRA Section 219, with the following

possible exceptions.

In 2025 payments in relation to tax with an aggregate US dollar

equivalent value of approximately $3,000 were made from a bp trust

account held with Tadvin Co. to Iranian public entities on behalf of BP

Iran. No gross revenues or net profits are attributable to BP Iran's

activities.

During 2025 the International Bank of Yemen (IBY) was sanctioned by

the US. bp holds two bank accounts at IBY which were used to support

historical operations in Yemen. Both accounts were dormant prior to

the time IBY was sanctioned, became blocked accounts from that time

and remain blocked as at the date of this report. Together, the accounts

hold around $60,000. In 2025, bp did not operate in Yemen and no

gross revenues or net profits are attributable to any bp activities in

Yemen.

Material contracts

On 4 April 2016 the district court approved the Consent Decree among

BP Exploration & Production Inc., BP Corporation North America Inc., BP

p.l.c., the United States and the states of Alabama, Florida, Louisiana,

Mississippi and Texas (the Gulf states) which fully and finally resolved

any and all natural resource damages (NRD) claims of the United States,

the Gulf states, and their respective natural resource trustees and all

Clean Water Act (CWA) penalty claims, and certain other claims of the

United States and the Gulf states.

Concurrently, the definitive Settlement Agreement that bp entered into

with the Gulf states (Settlement Agreement) with respect to State

claims for economic, property and other losses became effective.

bp has filed the Consent Decree and the Settlement Agreement as

exhibits to its *Annual Report and Form 20-F 2020* filed with the SEC. For

further details of the Consent Decree and the Settlement Agreement,

see Legal proceedings in *bp Annual Report and Form 20-F 2015*.

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| bp Annual Report and Form 20-F 2025 | 359 |

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|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Additional disclosures** |

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Property, plant and equipment

bp has freehold and leasehold interests in real estate and other tangible

assets in numerous countries, but no individual property is significant to

the group as a whole. For more on the significant subsidiaries★ of the

group at 31 December 2025 and the group percentage of ordinary share

capital see Financial statements – Note 37. For information on

significant joint ventures★ and associates★ of the group see Financial

statements – Note 16 and 17.

Related party transactions

Transactions between the group and its significant joint ventures and

associates are summarized in Financial statements – Note 16 and 17. In

the ordinary course of its business, the group enters into transactions

with various organizations with which some of its directors or executive

officers are associated. Except as described in this report, the group did

not have any material transactions or transactions of an unusual nature

with, and did not make loans to, related parties in the period

commencing 1 January 2025 to 13 February 2026.

Corporate governance practices

In the US, bp ADSs are listed on the New York Stock Exchange (NYSE).

The significant differences between bp's corporate governance

practices as a UK company and those required by NYSE listing

standards for US companies are listed as follows:

**Independence**

As set out on page <u>[77](#i0dd2ee81aac04f8c9c97c86197f0c6df_136)</u>, bp has adopted separate terms of reference for

the board and each of its committees as part of its corporate

governance framework. The terms of reference for the board and each

of its committees are reviewed periodically. The board and audit

committee terms of reference were last updated with effect from 1

January 2025, while the other three principal committees were last

updated with effect from 25 July 2024. The terms of reference reflect

the UK Corporate Governance Code approach to corporate governance.

As such, the way in which bp makes determinations of directors'

independence differs from the NYSE approach.

bp's corporate governance framework requires that all non-executive

directors (NEDs) be determined by the board to be 'independent in

character and judgement and free from any business or other

relationship which could materially interfere with the exercise of their

judgement'. The bp board has determined that, in its judgement, all of

the NEDs are independent. In doing so, however, the board did not

explicitly take into consideration the independence requirements

outlined in the NYSE's listing standards.

**Committees**

bp has a number of board committees that are broadly comparable in

purpose and composition to those required by NYSE rules for domestic

US companies. For instance, bp has a remuneration (rather than a

compensation) committee. bp also has an audit committee, which NYSE

rules require for both US companies and foreign private issuers. These

committees are composed solely of NEDs whom the board has

determined to be independent, in the manner described above.

Each committee operates under its own terms of reference together

with a set of terms applicable to all the committees (see the board

committee reports on pages <u>[82](#i0dd2ee81aac04f8c9c97c86197f0c6df_160)</u><u>-</u><u>[125](#ice7ed01c803e4808b3b636ee225997b7_8758)</u> and <u>bp.com/governance</u>.

Under US securities law and the listing standards of the NYSE, bp is

required to have an audit committee that satisfies the requirements of

Rule 10A-3 under the Exchange Act and Section 303A.06 of the NYSE

Listed Company Manual. bp's audit committee complies with these

requirements. The bp audit committee does not have direct

responsibility for the appointment, reappointment or removal of the

independent auditors. Instead, it follows the UK Companies Act 2006

and the UK Corporate Governance Code by making recommendations

to the board on these matters for it to put forward for shareholder

approval at the AGM.

One of the NYSE's additional requirements for the audit committee

states that at least one member of the audit committee is to have

'accounting or related financial management expertise'. The board

determined that Tushar Morzaria possesses such expertise and also

possesses the financial and audit committee experience set forth in

both the UK Corporate Governance Code and the SEC rules (see audit

committee report on page <u>[84](#i0dd2ee81aac04f8c9c97c86197f0c6df_166)</u>). Mr Morzaria is the audit committee

financial expert as defined in Item 16A of Form 20-F.

**Summary of terms of reference for audit committee and** 

**remuneration committee**

The audit committee's full terms of reference are available on our

website at <u>bp.com/governance</u>. 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 <u>bp.com/governance</u>. 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.

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| 360 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

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**Shareholder approval of equity compensation plans**

The NYSE rules for US companies require that shareholders must be

given the opportunity to vote on all equity-compensation plans and

material revisions to those plans. bp complies with UK requirements

that are similar to the NYSE rules. The board, however, does not

explicitly take into consideration the NYSE's detailed definition of what

are considered 'material revisions'.

**Item 16J insider trading policy**

The board has approved a share dealing policy governing the

acquisition, sale and other dispositions of the company's securities by

employees, contractors, officers and members of the board of the

company.

The bp share dealing policy is included in this Form 20-F as Exhibit 11.2.

Code of ethics

The company has adopted a code of ethics for its chief executive

officer, chief financial officer, group controller, and SVP internal audit

whose roles are equivalent to the SEC roles as required by the

provisions of Section 406 of the Sarbanes-Oxley Act of 2002 and the

rules issued by the SEC. There have been no waivers from the code of

ethics relating to any officers. A copy of the code of ethics can be found

at <u>bp.com/codeofethics</u>.

The NYSE rules require that US companies adopt and disclose a code of

business conduct and ethics for directors, officers and employees. bp

has adopted a code of conduct, which applies to all employees, officers

and members of the board. This was updated and published in January

2023, with certain elements further updated and published in October

2025. In addition, bp has adopted a code of ethics as described above

for the chief executive officer, chief financial officer, group controller,

and SVP internal audit as required by the SEC. bp considers that these

codes and policies address the matters specified in the NYSE rules for

US companies. During 2021 the board adopted a diversity, equity and

inclusion policy, which requires it to encourage a diverse and inclusive

working environment in the boardroom. The policy was most recently

reviewed by the board in 2024, and amendments were made to reflect

regulatory changes and market practice. The updated policy was then

approved with effect from 1 January 2025.

Controls and procedures

**Evaluation of disclosure controls and procedures**

The company maintains 'disclosure controls and procedures', as such

term is defined in Exchange Act Rule 13a-15(e), that are designed to

ensure that information required to be disclosed in reports the

company files or submits under the Exchange Act is recorded,

processed, summarized and reported within the time periods specified

in the Securities and Exchange Commission rules and forms, and that

such information is accumulated and communicated to management,

including the company's group chief executive and chief financial

officer, as appropriate, to allow timely decisions regarding required

disclosure.

In designing and evaluating our disclosure controls and procedures, our

management, including the group chief executive and chief financial

officer, recognize that any controls and procedures, no matter how well

designed and operated, can provide only reasonable, not absolute,

assurance that the objectives of the disclosure controls and procedures

are met. Because of the inherent limitations in all control systems, no

evaluation of controls can provide absolute assurance that all control

issues and instances of fraud within the company, if any, have been

detected. Further, in the design and evaluation of our disclosure

controls and procedures our management necessarily was required to

apply its judgement in evaluating the costs and benefits of possible

control and procedure design options. Also, we have investments in

unconsolidated entities. As we do not control these entities, our

disclosure controls and procedures with respect to such entities are

necessarily substantially more limited than those we maintain with

respect to our consolidated subsidiaries★. Because of the inherent

limitations in a cost-effective control system, misstatements due to

error or fraud may occur and not be detected. The company's

disclosure controls and procedures have been designed to meet, and

management believes that they meet, reasonable assurance standards.

The company's management, with the participation of the company's

interim group chief executive and chief financial officer, has evaluated

the effectiveness of the company's disclosure controls and procedures

pursuant to Exchange Act Rule 13a-15(b) as of the end of the period

covered by this annual report. Based on that evaluation, the interim

group chief executive and chief financial officer have concluded that

the company's disclosure controls and procedures were effective at a

reasonable assurance level.

**Management's report on internal control over financial** 

**reporting**

Management of bp is responsible for establishing and maintaining

adequate internal control over financial reporting. bp's internal control

over financial reporting is a process designed under the supervision of

the principal executive and financial officers to provide reasonable

assurance regarding the reliability of financial reporting and the

preparation of bp's financial statements for external reporting purposes

in accordance with IFRS.

As of the end of the 2025 fiscal year, management conducted an

assessment of the effectiveness of internal control over financial

reporting in accordance with the criteria in the Internal Control

Integrated Framework issued in 2013 by the Committee of Sponsoring

Organizations of the Treadway Commission (COSO). Based on this

assessment, management has determined that bp's internal control

over financial reporting as of 31 December 2025 was effective.

The company's internal control over financial reporting includes policies

and procedures that pertain to the maintenance of records that, in

reasonable detail, accurately and fairly reflect transactions and

dispositions of assets; provide reasonable assurances that transactions

are recorded as necessary to permit preparation of financial statements

in accordance with IFRS and that receipts and expenditures are being

made only in accordance with authorizations of management and the

directors of bp; and provide reasonable assurance regarding prevention

or timely detection of unauthorized acquisition, use or disposition of

bp's assets that could have a material effect on our financial

statements. bp's internal control over financial reporting as of

31 December 2025 has been audited by Deloitte LLP, an independent

registered public accounting firm, as stated in their report appearing on

page <u>[154](#ief7b657c95eb449abf4ca6590a827970_29161)</u> of *bp Annual Report and Form 20-F 2025*.

**Changes in internal control over financial reporting**

There were no changes in the group's internal control over financial

reporting that occurred during the period covered by the Form 20-F

that have materially affected or are reasonably likely to materially affect

our internal control over financial reporting.

Cyber security

**Governance**

The board oversees bp's internal control and risk management

framework. The board is supported by the safety and sustainability

committee which oversees cyber security risk and received reports

from bp's chief information security officer (CISO) on cyber security

incidents at every committee meeting in 2025, including information on

bp's response to incidents. This allows an ongoing assessment by the

committee of the effectiveness of bp's overall cyber security

programme. A session is held once a year to review bp's roadmap and

progress for addressing cyber security risk. Read more in the safety and

sustainability committee report on page <u>[82](#i0dd2ee81aac04f8c9c97c86197f0c6df_160)</u>.

At management level, assessment and management of material risks

from cyber security threats is led by bp's executive vice president of

technology, a member of bp's leadership team with deep experience in

bp's engineering and operations functions, with support from bp's

CISO, who has over 20 years of experience in the information

technology industry. bp's digital safety operational risk committee

brings together additional senior members of bp's digital leadership

team to assist in ensuring that cyber security risks across bp are

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 361 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Additional disclosures** |

---

identified, understood, accurately quantified and are managed in

accordance with bp's internal controls framework.

**Risk management and strategy**

bp has implemented a threat-focused strategy to assess cyber security

risks and protect against, detect, respond to, and recover from cyber

attacks. bp maintains internal teams focused on cyber security

intelligence and emergency response to monitor the external threat

landscape and the threats to bp's IT and operational technology

infrastructure. bp partners with third-party specialists to augment its in-

house capabilities as necessary. bp has a defined protocol for cyber

incident notification based on severity and bp's internal cyber security

teams brief the CISO, technology EVP, other senior leadership and

relevant board and management committees about incidents on an as

needed basis.

Cyber security risk management is integrated into bp's overall risk

management process. bp's entities are required to identify, assess and

report key risks, including cyber security risks, to relevant members of

senior leadership. bp maintains additional procedures to manage cyber

security risks related to third-party service providers, including

conducting information security assessments for certain providers,

providing relevant trainings for bp employees, and maintaining

information security requirements for suppliers.

Our business strategy, results of operations and financial condition

have not been materially affected by risks from cyber security threats,

including as a result of previously identified cyber security incidents. For

more information on our cyber security related risks, see Risk Factors

on page <u>[67](#i0dd2ee81aac04f8c9c97c86197f0c6df_109)</u>.

Principal accountant's fees and services

The audit committee has established policies and procedures for the

engagement of the independent registered public accounting firm,

Deloitte LLP, to render audit and certain assurance services. The policy

provides for pre-approval by the audit committee of specifically defined

audit, audit-related, non-audit and other services that are not prohibited

by regulatory or other professional requirements. Deloitte is engaged

for these services when its expertise and experience of bp are

important. Most of this work is of an audit nature.The audit committee,

CFO and group controller monitor overall compliance with bp's policy

on audit-related and non-audit services, including whether the

necessary pre-approvals have been obtained. The committee regularly

reviews the policy, including in 2025, when it was updated to include

clarification regarding bp's employment of current and former

employees or partners of the auditor.

Under the policy, pre-approval is given for specific services within the

following categories: i) audit-related services, such as those required by

law or where the auditor is best placed to undertake such work on

similar terms, ii) non-audit services required by law, such as reporting

required by a regulatory authority, and iii) other services, such as

additional assurance or updates on applicable law and accounting

standards. bp operates a two-tier system for audit and non-audit

services. For audit-related services, the audit committee has a pre-

approved aggregate level, within which specific work may be approved

by management. Non-audit services are pre-approved for management

to authorize per individual engagement, but above a defined level must

be approved by the chair of the audit committee or the full committee.

The audit committee has delegated to the chair of the audit committee

authority to approve permitted services provided that any decisions are

reported to the committee at its next scheduled meeting. Any proposed

service not included in the approved service list must be approved in

advance of commencing the engagement by the audit committee chair

or the full audit committee, depending on the level of fee payable.

The audit committee evaluates the performance of the auditor each

year. The audit fees payable to Deloitte are reviewed by the committee

in the context of other global companies for cost-effectiveness. The

committee keeps under review the scope and results of audit work and

the independence and objectivity of the auditor. External regulation and

bp policy requires the auditor to rotate its lead audit partner every five

years. See Financial statements – Note 36 and the audit committee

report on page <u>[84](#i0dd2ee81aac04f8c9c97c86197f0c6df_166)</u> for details of fees for services provided by the

auditor.

Additional Directors' report disclosures

This section of *bp Annual Report and Form 20-F 2025* forms part of the

Directors' report. Certain information has been included in the Strategic

report that would otherwise be required to be disclosed in the Directors'

report, as noted below.

**Indemnity provisions**

In accordance with bp's Articles of Association, on appointment each

director is granted an indemnity from the company in respect of

liabilities incurred as a result of their office, to the extent permitted by

law. These indemnities were in force throughout the financial year and

at the date of this report. In respect of those liabilities for which

directors may not be indemnified, the company maintained a directors'

and officers' liability insurance policy throughout 2025. During the year,

a review of the terms and scope of the policy was undertaken as part of

the annual renewal. Although a director's defence costs may be met,

neither the company's indemnity nor insurance provides cover in the

event that the director is proved to have acted fraudulently or

dishonestly. One of the group's subsidiaries★ is a trustee of the UK

pension scheme. Each director of that subsidiary is granted an

indemnity from the company in respect of liabilities incurred as a result

of such a subsidiary's activities as a trustee of the pension scheme, to

the extent permitted by law. These indemnities were in force

throughout the financial year and as at the date of this report.

**Financial risk management objectives and policies**

The disclosures in relation to financial risk management objectives and

policies, including the policy for hedging, are included in How we

manage risk on page <u>[67](#i0dd2ee81aac04f8c9c97c86197f0c6df_109)</u>, Liquidity and capital resources on page <u>[338](#i0dd2ee81aac04f8c9c97c86197f0c6df_484)</u> 

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 <u>[12](#i9811d5a2482a48558bac7855094e4f43_3-1-7-2-837181)</u> and <u>[189](#i0dd2ee81aac04f8c9c97c86197f0c6df_292)</u> for our expenditure on research and

development.

**Branches**

As a global group our interests and activities are held or operated

through subsidiaries, branches, joint arrangements★ or associates★

established in – and subject to the laws and regulations of – many

different jurisdictions.

**Employees**

Disclosures in respect of how the directors have engaged with

employees and had regard to their interests are included in Our

stakeholders and Key decisions on pages <u>[79](#ib69cd64a5c90459290d844e1919861cd_2-1-2-1-882904)</u><u>,</u> <u>[80](#i0dd2ee81aac04f8c9c97c86197f0c6df_142)</u> and <u>[81](#i0dd2ee81aac04f8c9c97c86197f0c6df_151)</u>.

The disclosures concerning policies in relation to the employment of

disabled persons and employee involvement are included in

Sustainability – our people on page <u>[57](#i87f52fc5efef4a16865a4af06e1e7987_26442)</u>.

---

| | | |
|:---|:---|:---|
| 362 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Employee share schemes**

Certain shares held as a result of participation in some employee share

plans carry voting rights. Voting rights in respect of such shares are

exercisable via a nominee. Dividend waivers are in place in respect of

unallocated shares held in employee share plan trusts.

**Suppliers, customers and others**

Disclosures in respect of how the directors have engaged with

suppliers, customers and others in business relationships with the

company are included in Our stakeholders on pages <u>[80](#i0dd2ee81aac04f8c9c97c86197f0c6df_142)</u><u>-</u><u>[81](#i0dd2ee81aac04f8c9c97c86197f0c6df_151)</u>.

**Change of control provisions**

On 5 October 2015, the United States lodged with the district court in

MDL 2179 a proposed Consent Decree between the United States, the

Gulf states, BP Exploration & Production Inc., BP Corporation North

America Inc. and BP p.l.c., to fully and finally resolve any and all natural

resource damages claims of the United States, the Gulf states and their

respective natural resource trustees and all Clean Water Act penalty

claims, and certain other claims of the United States and the Gulf states.

Concurrently, bp entered into a definitive Settlement Agreement with

the five Gulf states (Settlement Agreement) with respect to state claims

for economic, property and other losses. On 4 April 2016, the district

court approved the Consent Decree, at which time the Consent Decree

and Settlement Agreement became effective. The federal government

and the Gulf states may jointly elect to accelerate the payments under

the Consent Decree in the event of a change of control or insolvency of

BP p.l.c., and the Gulf states individually have similar acceleration rights

under the Settlement Agreement. For further details of the Consent

Decree and the Settlement Agreement, see Legal proceedings in bp

Annual Report and Form 20-F 2015.

**Political donations, expenditure and contributions**

Disclosures in relation to political donations, expenditure and

contributions are included on page <u>[58](#i87f52fc5efef4a16865a4af06e1e7987_114161)</u>.

**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 <u>[39](#i0dd2ee81aac04f8c9c97c86197f0c6df_85)</u><u>-</u><u>[40](#i6579caf4201e4bca9f275366f590fa49_17810)</u>.

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 | <u>[189](#i0dd2ee81aac04f8c9c97c86197f0c6df_292)</u> |
| (2), (3) | Not applicable |
| (4), (5) Waiver of director emoluments | Not applicable |
| (6) – (10) | Not applicable |
| (11), (12) Dividend waivers | <u>[362](#ib8a911d3090649649441bf4d4c2fa023_10588)</u> |
| (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 <u>[4](#i0dd2ee81aac04f8c9c97c86197f0c6df_19)</u>), Interim chief executive officer's letter (page <u>[5](#i0dd2ee81aac04f8c9c97c86197f0c6df_22)</u>),the

Strategic report (inside front cover and pages <u>[1](#i0dd2ee81aac04f8c9c97c86197f0c6df_7)</u><u>-</u><u>[71](#if6cc4a1e1b354006ac4c1604da81c9a3_3683)</u>), Additional

disclosures (pages <u>[334](#i0dd2ee81aac04f8c9c97c86197f0c6df_475)</u><u>-</u><u>[363](#iff3518df5cc644e3bf43f43df37650db_23483)</u>) and Shareholder information (pages

<u>[364](#i0dd2ee81aac04f8c9c97c86197f0c6df_547)</u><u>-</u><u>[374](#i325b097f870d49278bb6bef47378fe6b_11-1-1-1-963066)</u>), including but not limited to statements under the headings

'Energy Outlook', 'Our strategy', 'Consistency with the Paris goals', 'Our

business model', 'Our financial frame', '2026 guidance' 'Outlook for

2026', 'Our investment process' and '2026 shareholder calendar' and

including but not limited to statements regarding: plans and

expectations relating to business, financial performance, results of

operations, cash flow and allocation of capital expenditure; plans and

expectations regarding bp's financial frame (including annual dividend

increases, net debt, credit rating, capital expenditures and distribution

of operating cash flow as dividends and share buybacks), balance sheet,

working capital, operating cash flow, return on average capital

employed (ROACE), liquidity, capital discipline, cost base, future

shareholder distributions, amount, timing or use of payments related to

divestments and other proceeds (including expectations and plans

relating to the Castrol divestment and allocation of the expected

proceeds), future dividend payments and progress towards our cost

saving targets; plans and expectations regarding share buybacks,

allocation and use of excess cash; plans and expectations regarding

bp's 2026 guidance (including with respect to reported and underlying

upstream production, growth of bp's customers businesses, products

refining margins and refinery turnaround activity); plans and

expectations regarding total capital expenditure, depreciation,

depletion and amortization, divestments and other proceeds, Gulf of

America oil spill payments, other businesses & corporate underlying

annual charge, and the effective tax rate and the underlying effective

tax rate; plans and expectations regarding bp's engagement plans and

programs and their impact on bp's results of operations and financial

position; plans and expectations regarding bp's four primary targets

(including adjusted free cash flow growth, net debt, structural cost

reduction and ROACE) and reporting of bp's progress towards those

targets; assumptions regarding interest rates and broader

macroeconomic conditions; plans and expectations relating to bp's

investor proposition including those to grow shareholder value and

simplify and strengthen bp; plans and expectations relating to bp's

investment process, strategy and capital investment, including future

capital investment allocation, expected IRR, access to capital and the

restructuring of certain investments; plans and expectations relating to

bp's intra-group funding and liquidity arrangements; plans and

expectations relating to bp's ability to meet contractual obligations;

expectations regarding inflation, price volatility, refining margins and

price assumptions; plans and expectations relating to risk, including risk

management processes and climate-related risks; plans, expectations

and projections regarding bp's oil and gas business, including related

investment plans and their impact on production and cash flow, oil and

gas prices, operational emissions, oil and gas production targets, and

future divestments; plans and expectations regarding bp's customers

and products business, including investment plans and growth in

aviation, biofuels and refineries; plans and expectations regarding bp's

low carbon energy business, including the growth and decarbonization

of the offshore wind and hydrogen and CCS businesses; plans and

expectations regarding bp's ST&S business, including relating to

electrification of the energy systems and decarbonization of electricity;

plans and expectations related to the energy transition (including

scenario analysis), investments in transition businesses, reduction of

operational carbon intensity, climate change, sustainability (including

bp's sustainability aims), greenhouse gas emissions, management,

decarbonization, net zero ambition and aims, and related laws and

regulations; plans and expectations regarding bp's focus on biodiversity

and water use, including bp's freshwater use, bp's freshwater

management approach, bp's ability to address water-related business

risk and bp's freshwater withdrawal in stressed catchments; plans and

expectations regarding projects, joint ventures, partnerships,

agreements and memoranda of understanding with governments,

commercial entities and other third party partners (including, but not

limited to, the Gelsenkirchen refinery, the Green Canyon Block 584, the

Tiber-Guadalupe project, the Atlantis Drill Center 1 expansion project,

the NZT and NEP projects, the Ginger project, the KGD6 infills wells

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 363 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Additional disclosures** |

---

project, the Shah Deniz Compression, the Atlantis Major Facility

Expansion, the Kirkuk redevelopment project, the Juniper Wells, the

Greater Western Flank 4 project, the Argos Southwest Extension

project, the Murlach project, the Etlas joint venture, Lightsource bp., the

Alto de Cabo Frio Central block, the Bumerangue project, the Atlantic

LNG facility, the Agogo Integrated West Hub Project, offshore Blocks

1/14, 14 and 14K in the Lower Congo Basin, the five-well programme in

the Mediterranean Sea, the agreement between State Oil Company of

the Azerbaijan Republic and bp and subsequently approved

development plans in regard to the Karabagh field, the agreement

between bp and ONGC in relation to Mumbai High field and the Browse

LNG Joint Venture); expectations regarding contingent liabilities, legal

and trial proceedings, court decisions, potential investigations and civil

actions by regulators, government entities and/or other entities or

parties, and the timing and potential impact of such proceedings,

settlement agreements relating to such proceedings and bp's

intentions in respect thereof; plans and expectations regarding

relationships with governments, customers, partners, suppliers,

communities and key stakeholders; plans and expectations regarding

upstream production and downstream performance and returns; plans

and expectations regarding bp's external audit tender process; plans

and expectations regarding the appointment and succession plans of

bp's directors; plans and expectations regarding bp's long-term

viability, including ability to continue in operation and meet liabilities;

expectations regarding bp's refining assets, including their useful

economic lives and depreciation; expectations regarding the impact of

emissions costs on bp's oil and gas CGU carrying values; expectations

regarding the impact of the energy transition on the recoverable

amount of property, plant and equipment and goodwill in the oil and

gas industry; expectations regarding the timing of production of bp's

reserves and resources; expectations regarding the impact of the

German tax legislation on bp's tax obligations; plans and expectations

regarding the adoption and impact of the amendments to IFRS and

related elections; plans and expectations regarding employee share

plans, funded defined benefit plans and other post-employment

benefits; expectations regarding impact of international trade

sanctions; plans and expectations regarding operations and safety;

expectations regarding the structure of energy demand; plans and

expectations regarding the competitiveness and value of bp's

refineries; plans and expectations relating to bp's research and

development spend and outcomes; expectations related to changes

laws, regulations and policies; and plans and expectations regarding

bp's shareholder calendar.

By their nature, forward-looking statements involve risk and uncertainty

because they relate to events and depend on circumstances that will or

may occur in the future and are outside the control of bp.

Actual results or outcomes may differ materially from those expressed

in such statements, depending on a variety of factors, including: the

extent and duration of the impact of current market conditions

including the volatility of oil prices, the effects of bp's plan to exit its

shareholding in Rosneft and other investments in Russia, overall global

economic and business conditions impacting bp's business and

demand for bp's products as well as the specific factors identified in the

discussions accompanying such forward-looking statements; changes

in consumer preferences and societal expectations; the pace of

development and adoption of alternative energy solutions;

developments in policy, law, regulation, technology and markets,

including societal and investor sentiment related to the issue of climate

change; the receipt of relevant third party and/or regulatory approvals

including ongoing approvals required for the continued developments

of approved projects; the timing and level of maintenance and/or

turnaround activity; the timing and volume of refinery additions and

outages; the timing of bringing new fields onstream; the timing,

quantum and nature of certain acquisitions and divestments; future

levels of industry product supply, demand and pricing, including supply

growth in North America and continued base oil and additive supply

shortages; OPEC+ quota restrictions; PSA and TSC effects; operational

and safety problems; potential lapses in product quality; economic and

financial market conditions generally or in various countries and

regions; political stability and economic growth in relevant areas of the

world; changes in laws and governmental regulations and policies,

including related to climate change; changes in social attitudes and

customer preferences; regulatory or legal actions including the types of

enforcement action pursued and the nature of remedies sought or

imposed; the actions of prosecutors, regulatory authorities and courts;

delays in the processes for resolving claims; amounts ultimately

payable and timing of payments relating to the Gulf of America oil spill;

exchange rate fluctuations; development and use of new technology;

recruitment and retention of a skilled workforce; the success or

otherwise of partnering; the actions of competitors, trading partners,

contractors, subcontractors, creditors, rating agencies and others; bp's

access to future credit resources; business disruption and crisis

management; the impact on bp's reputation of ethical misconduct and

non-compliance with regulatory obligations; trading losses; major

uninsured losses; the possibility that international sanctions or other

steps taken by governmental or any other relevant persons may impact

bp's ability to sell its interests in Rosneft, or the price for which bp could

sell such interests; the actions of contractors; natural disasters and

adverse weather conditions; changes in public expectations and other

changes to business conditions; wars and acts of terrorism; cyber-

attacks or sabotage; and those factors discussed elsewhere in this

report including under Risk factors (page <u>[62](#i0dd2ee81aac04f8c9c97c86197f0c6df_6396)</u>). In addition to factors set

forth elsewhere in this report, those set out above are important

factors, although not exhaustive, that may cause actual results and

developments to differ materially from those expressed or implied by

these forward-looking statements.

Statements regarding competitive

position

Statements referring to bp's competitive position are based on the

company's belief and, in some cases, rely on a range of sources,

including investment analysts' reports, independent market studies and

bp's internal assessments of the relevant market based on publicly

available information about the financial results and performance of

market participants.

---

| | | |
|:---|:---|:---|
| 364 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

---

| | |
|:---|:---|
| **Shareholder information** |  |
| Share prices and listings | **[365](#i0dd2ee81aac04f8c9c97c86197f0c6df_550)** |
| Dividends | **[365](#i0dd2ee81aac04f8c9c97c86197f0c6df_553)** |
| Shareholder taxation information | **[365](#i0dd2ee81aac04f8c9c97c86197f0c6df_556)** |
| Major shareholders | **[367](#i0dd2ee81aac04f8c9c97c86197f0c6df_559)** |
| Annual general meeting | **[368](#i0dd2ee81aac04f8c9c97c86197f0c6df_562)** |
| Memorandum and Articles of Association | **[368](#i0dd2ee81aac04f8c9c97c86197f0c6df_565)** |
| Purchases of equity securities by the issuer and <br>affiliated purchasers | **[372](#i0dd2ee81aac04f8c9c97c86197f0c6df_568)** |
| Fees and charges payable by ADS holders | **[373](#i0dd2ee81aac04f8c9c97c86197f0c6df_571)** |
| Fees and payments made by the Depositary to <br>the issuer | **[373](#i0dd2ee81aac04f8c9c97c86197f0c6df_574)** |
| Documents on display | **[373](#i0dd2ee81aac04f8c9c97c86197f0c6df_577)** |
| Shareholding administration | **[374](#i0dd2ee81aac04f8c9c97c86197f0c6df_580)** |
| 2026 shareholder calendar | **[374](#i0dd2ee81aac04f8c9c97c86197f0c6df_583)** |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 365 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Shareholder information** |

---

Share prices and listings

**Markets and market prices**

The primary market for the company's ordinary shares (trading symbol

'BP'), 8% cumulative first preference shares (trading symbol 'BP.A') and

9% cumulative second preference shares (trading symbol 'BP.B') is the

London Stock Exchange (LSE). The company's ordinary shares are a

constituent element of the Financial Times Stock Exchange 100 Index.

In the US, the company's securities are listed and traded on the New

York Stock Exchange (NYSE) in the form of American Depositary Shares

(ADSs) (trading symbol 'BP'), for which JPMorgan Chase Bank, N.A. is the

depositary (the Depositary) and transfer agent. The Depositary's

principal office is 270 Park Avenue, Floor 8, New York, NY, 10017, US.

Each ADS represents six ordinary shares. ADSs are evidenced by

American depositary receipts (ADRs), which may be issued in either

certificated or book entry form.

The company delisted from the Frankfurt Stock Exchange on

23 April 2025.

On 13 February 2026, 697,484,895 ADSs (equivalent to approximately

4,184,909,371 ordinary shares or some 26.65% of the total issued share

capital, excluding shares held in treasury) were outstanding and were

held by approximately 55,047 ADS holders. Of these, about 54,410 had

registered addresses in the US at that date. One of the registered

holders of ADSs represents approximately 1,278,868 underlying holders.

On 13 February 2026, there were approximately 186,939 ordinary

shareholders. Of these shareholders, around 1,449 had registered

addresses in the US and held a total of some 3,534,557 ordinary shares.

On 13 February 2026, there were approximately 1,029 preference

shareholders. Of these shareholders, around 14 had registered

addresses in the US and held a total of some 2,773 preference shares.

Since a number of the ordinary shares and ADSs were held by brokers

and other nominees, the number of holders in the US may not be

representative of the number of beneficial holders or their respective

country of residence.

Dividends

The company's current policy is to pay interim dividends on a quarterly

basis on its ordinary shares.

Our policy is also to announce dividends for ordinary shares in US

dollars and state an equivalent sterling dividend. Dividends on the

company's ordinary shares will be paid in sterling and on the company's

ADSs in US dollars. The rate of exchange used to determine the sterling

amount equivalent is the average of the market exchange rates in

London over three business days in advance of the sterling equivalent

announcement date. The directors may choose to declare dividends in

any currency provided that a sterling equivalent is announced. It is not

the company's intention to change its current policy of announcing

dividends on ordinary shares in US dollars.

Information regarding dividends announced and paid by the company

on ordinary shares and preference shares is provided in the

consolidated Financial statements – Note 10.

A Scrip Dividend Programme (Scrip Programme) was approved by

shareholders in 2010 and was renewed for a further three years at the

2024 AGM. It enabled the company's ordinary shareholders and ADS

holders to elect to receive dividends by way of new fully paid ordinary

shares (or ADSs in the case of ADS holders) instead of cash. The

operation of the Scrip Programme is always subject to the directors'

decision to make the Scrip Programme offer available in respect of any

particular dividend.

The company announced on 29 October 2019 and as part of all

subsequent quarterly results announcements made since, that the

board had suspended the Scrip Programme in respect of those

quarterly dividends. The company does not expect to offer a scrip

election for the foreseeable future. Ordinary shareholders and ADS

holders (subject to certain exceptions) may be able to participate in

dividend reinvestment plans. Any decisions with respect to future

dividends will be made by the board of BP p.l.c. following the end of

each quarter.

Future dividends will be dependent on future earnings, the financial

condition of the group, the Risk factors set out on page <u>[67](#i0dd2ee81aac04f8c9c97c86197f0c6df_109)</u> and other

matters that may affect the business of the group set out in Our

strategy on page <u>[8](#i0dd2ee81aac04f8c9c97c86197f0c6df_31)</u> and in Liquidity and capital resources on page <u>[338](#i0dd2ee81aac04f8c9c97c86197f0c6df_484)</u>.

The quarterly dividend which is expected to be paid on 27 March 2026 in

respect of the fourth quarter 2025 is 8.320 cents per ordinary share

($0.49920 per American Depositary Share (ADS)). The corresponding

amount in sterling will be announced on 17 March 2026.

The following table shows dividends announced and paid by the

company per ADS for the past five years.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| Dividends per ADS<sup>a</sup> | Dividends per ADS<sup>a</sup> | March | June | September | December | Total |
| 2021 | UK pence | 22.61 | 22.27 | 23.72 | 24.63 | 92.23 |
|  | US cents | 31.50 | 31.50 | 32.76 | 32.76 | 128.52 |
| 2022 | UK pence | 24.96 | 26.13 | 31.01 | 29.64 | 111.74 |
| 2022 | US cents | 32.76 | 32.76 | 36.04 | 36.04 | 137.60 |
| 2023 | UK pence | 33.30 | 31.85 | 34.39 | 34.42 | 133.97 |
| 2023 | US cents | 39.66 | 39.66 | 43.62 | 43.62 | 166.56 |
| **2024** | **UK pence** | **34.15** | **34.10** | **36.30** | **37.78** | **142.33** |
| **2024** | **US cents** | **43.62** | **43.62** | **48.00** | **48.00** | **183.24** |
| **2025** | **UK pence** | **37.06** | **35.40** | **37.17** | **37.44** | **147.07** |
|  | **US cents** | **48.00** | **48.00** | **49.92** | **49.92** | **195.84** |

---

aDividends announced and paid by the company on ordinary and preference shares are

provided in the consolidated Financial statements – Note 10.

There are no UK foreign exchange controls or other restrictions on the

import or export of capital by, or on the payment of dividends to, non-

resident holders of BP p.l.c. shares, or that materially affect the conduct

of BP p.l.c's operations, other than restrictions applicable to certain

countries and persons subject to UN, US, UK, or EU economic sanctions,

to the extent these restrictions can be complied with in law.

Shareholder taxation information

This section describes the material US federal income tax and UK

taxation consequences of owning ordinary shares or ADSs to a US

holder who holds the ordinary shares or ADSs as capital assets for tax

purposes. This section does not discuss tax consequences arising under

the Medicare contribution tax on net investment income or the

alternative minimum tax. It also does not apply inter alia to members of

special classes of holders some of which may be subject to other rules,

including: tax-exempt entities, life insurance companies, dealers in

securities, traders in securities that elect a mark-to-market method of

accounting for securities holdings, holders that, actually or

constructively, hold 10% or more of the company's shares (as measured

by voting power or value), holders that hold the shares or ADSs as part

of a straddle or a hedging or conversion transaction, holders that

purchase or sell the shares or ADSs as part of a wash sale for US federal

income tax purposes, or holders whose functional currency is not the

US dollar. In addition, if a partnership holds the shares or ADSs, the US

federal income tax treatment of a partner will generally depend on the

status of the partner and the tax treatment of the partnership and may

not be described fully below.

A US holder is any beneficial owner of ordinary shares or ADSs that is for

US federal income tax purposes (1) a citizen or resident of the US, (2) a

US domestic corporation, (3) an estate whose income is subject to US

federal income taxation regardless of its source, or (4) a trust if a US

court can exercise primary supervision over the trust's administration

and one or more US persons are authorized to control all substantial

decisions of the trust.

This section is based on the tax laws of the United States, including the

Internal Revenue Code of 1986, as amended, its legislative history,

existing and proposed US Treasury regulations thereunder, published

rulings and court decisions, and the taxation laws of the UK, all as

currently in effect, as well as the income tax convention between the US

and the UK that entered into force on 31 March 2003 (the Treaty). These

laws are subject to change, possibly on a retroactive basis. This section

further assumes that each obligation under the terms of the deposit

---

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|:---|:---|:---|
| 366 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

agreement relating to bp ADSs and any related agreement will be

performed in accordance with its terms.

For purposes of the Treaty and the estate and gift tax convention

between the US and the UK that entered into force on 11 November 1979

(the Estate Tax Convention) and for US federal income tax and UK

taxation purposes, a holder of ADRs evidencing ADSs will be treated as

the owner of the company's ordinary shares represented by those

ADRs. Exchanges of ordinary shares for ADRs and ADRs for ordinary

shares generally will not be subject to US federal income tax or to UK

taxation other than stamp duty or stamp duty reserve tax, as described

below.

Investors should consult their own tax advisor regarding the US federal,

state and local, UK and other tax consequences of owning and

disposing of ordinary shares and ADSs in their particular circumstances,

and in particular whether they are eligible for the benefits of the Treaty

in respect of their investment in the shares or ADSs.

**Taxation of dividends**

**UK taxation**

Under current UK taxation law, no withholding tax will be deducted from

dividends paid by the company, including dividends paid to US holders.

A US holder that is a company resident for tax purposes in the UK or

trading in the UK through a permanent establishment generally will not

be taxable in the UK on a dividend it receives from the company. A US

holder who is an individual resident for tax purposes in the UK is subject

to UK tax on dividends received from the company, including dividends

paid but reinvested under any dividend reinvestment plan for ordinary

shareholders, that are in excess of the annual dividend allowance.

However, if the shareholder's dividend income is covered by their

personal allowance of £12,570 (for 2025/26) after taking into account

other sources of income, no UK tax will be payable on their dividend

income.

For 2025/26 the dividend allowance is £500 which means there is no UK

tax due on the first £500 of dividends received. Dividends above this

level are subject to tax at 8.75% for basic tax payers, 33.75% for higher

rate tax payers and 39.35% for additional rate tax payers.

Although the first £500 of dividend income is not subject to UK income

tax, it does not reduce the total income for tax purposes. Dividends

within the dividend allowance still count towards basic or higher rate

bands, and may therefore affect the rate of tax paid on dividends

received in excess of the £500 allowance. For instance, if an individual

has an annual gross salary of £55,000 and also receives a dividend of

£12,000 they will be subject to the following scenario. The individual's

personal allowance and the basic rate tax band will be used up by the

gross salary. The remaining part of the salary and the whole of the

dividend will be subject to tax at the higher rate, although the dividend

allowance will reduce the amount of dividend subject to tax. The

dividend of £12,000 will be reduced by the dividend allowance of £500

leaving taxable dividend income of £11,500. The dividend will be taxed at

33.75% so that the total tax payable on the dividends is £3,881.

An individual US holder should inform HM Revenue & Customs each

year for which that US holder receives dividends chargeable to UK tax. If

a US holder needs to report to HMRC and already files a self-

assessment tax return in the UK, the US holder should include the

dividend income in that return and submit it by the deadline. If the US

holder does not file a self-assessment return, the US holder should

inform HM Revenue & Customs by 5 October. How the income is

reported and taxed will depend on the size of the dividend income for

that tax year. If the US holder received dividend income up to £10,000,

the US holder can inform HM Revenue & Customs by either asking to

update his or her tax code or contacting the helpline. If the US holder's

dividend income is over £10,000, he or she will need to fill out a self-

assessment tax return. For this, the US holder will need to register for

self-assessment by 5 October. A US holder will not need to report his or

her dividend income to HM Revenue & Customs if the amount is within

his or her dividend allowance for that tax year.

**US federal income taxation**

A US holder is subject to US federal income taxation on the gross

amount of any dividend paid by the company (including dividends paid

but reinvested under the Global Invest Direct (GID) Dividend

Reinvestment Plan for ADS holders) out of its current or accumulated

earnings and profits (as determined for US federal income tax

purposes). Dividends paid to a non-corporate US holder that constitute

qualified dividend income will be taxable to the holder at a preferential

rate, provided that the holder has a holding period in the ordinary

shares or ADSs of more than 60 days during the 121-day period

beginning 60 days before the ex-dividend date and meets other holding

period requirements. Dividends paid by the company with respect to

the ordinary shares or ADSs will generally be qualified dividend income.

For US federal income tax purposes, a dividend must be included in

income when the US holder, in the case of ordinary shares, or the

Depositary, in the case of ADSs, actually or constructively receives the

dividend and will not be eligible for the dividends-received deduction

generally allowed to US corporations in respect of dividends received

from other US corporations. US ADS holders should consult their own

tax advisor regarding the US tax treatment of the dividend fee in

respect of dividends. Dividends will generally be income from sources

outside the US and generally will be 'passive category income' for

purposes of computing a US holder's foreign tax credit limitation.

As noted above in UK taxation, a US holder will not be subject to UK

withholding tax. Accordingly, the receipt of a dividend will not entitle the

US holder to a foreign tax credit.

The amount of the dividend distribution on the ordinary shares that is

paid in pounds sterling will be the US dollar value of the pounds sterling

payments made, determined at the spot pounds sterling/US dollar rate

on the date the dividend is distributed, regardless of whether the

payment is, in fact, converted into US dollars. Generally, any gain or loss

resulting from currency exchange fluctuations during the period from

the date the pounds sterling dividend payment is distributed to the date

the payment is converted into US dollars will be treated as ordinary

income or loss and will not be eligible for the preferential tax rate on

qualified dividend income. The gain or loss generally will be income or

loss from sources within the US for foreign tax credit limitation

purposes.

Distributions in excess of the company's earnings and profits, as

determined for US federal income tax purposes, will be treated as a

return of capital to the extent of the US holder's basis in the ordinary

shares or ADSs and thereafter as capital gain, subject to taxation as

described in 'Taxation of capital gains – US federal income taxation'

section below.

In addition, the taxation of dividends may be subject to the rules for

passive foreign investment companies (PFIC), described below under

'Taxation of capital gains – US federal income taxation'. Distributions

made by a PFIC do not constitute qualified dividend income and are not

eligible for the preferential tax rate applicable to such income.

**Taxation of capital gains**

**UK taxation**

A US holder may be liable for both UK and US tax in respect of a gain on

the disposal of ordinary shares or ADSs if the US holder is (1) resident for

tax purposes in the UK at the date of disposal, (2) person who (a) has left

the UK; (b) was resident in the UK for four out of the seven years before

the year of departure; (c) acquired the shares before leaving the UK; (d)

sold the shares while not resident in the UK; and (e) returns to the UK

within a period not exceeding five complete tax years after departure,

(3) a US domestic corporation resident in the UK by reason of its

business being managed or controlled in the UK, or (4) a citizen of the

US that carries on a trade or profession or vocation in the UK through a

branch or agency or a corporation that carries on a trade, profession or

vocation in the UK, through a permanent establishment, and that has

used, held, or acquired the ordinary shares or ADSs for the purposes of

such trade, profession or vocation of such branch, agency or permanent

establishment.

Under the Treaty, capital gains on dispositions of ordinary shares or

ADSs generally will be subject to tax only in the jurisdiction of residence

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 367 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Shareholder information** |

---

of the relevant holder as determined under both the laws of the UK and

the US and as required by the terms of the Treaty.

Under the Treaty, individuals who are residents of either the UK or the

US and who have been residents of the other jurisdiction (the US or the

UK, as the case may be) at any time during the six years immediately

preceding the relevant disposal of ordinary shares or ADSs may be

subject to tax with respect to capital gains arising from a disposition of

ordinary shares or ADSs of the company not only in the jurisdiction of

which the holder is resident at the time of the disposition but also in the

other jurisdiction.

The UK Capital Gains Tax rate is dependent on the level of an individual's

taxable income. For 2025/26, where total taxable income and gains

after all allowable deductions are less than the upper limit of the basic

rate income tax band of £37,700 (for 2025/26), the rate of Capital Gains

Tax will be 18%. For gains (and any parts of gains) above that limit the

rate will be 24%.

An individual may be entitled to a capital gains tax free allowance,

depending on that individual's circumstances (in particular, election for

the remittance basis of taxation). For individuals who are entitled to the

allowance for 2025/26, this has been set at £3,000. Corporation tax on

chargeable gains is levied at 25% for companies from 1 April 2023.

**US federal income taxation**

A US holder who sells or otherwise disposes of ordinary shares or ADSs

will recognize a capital gain or loss for US federal income tax purposes

equal to the difference between the US dollar value of the amount

realized on the disposition and the US holder's tax basis, determined in

US dollars, in the ordinary shares or ADSs. Any such capital gain or loss

generally will be long-term gain or loss, subject to tax at a preferential

rate for a non-corporate US holder, if the US holder's holding period for

such ordinary shares or ADSs exceeds one year. The tax basis of shares

acquired through reinvested dividends under the GID Dividend

Reinvestment Plan for ADS holders is equal to the fair market value of

the stock on the investment date. The holding period for shares

acquired under the plan begins the day after the applicable investment

date.

Gain or loss from the sale or other disposition of ordinary shares or

ADSs will generally be income or loss from sources within the US for

foreign tax credit limitation purposes. The deductibility of capital losses

is subject to limitations.

We do not believe that ordinary shares or ADSs will be treated as stock

of a passive foreign investment company (PFIC) for US federal income

tax purposes, but this conclusion is a factual determination that is made

annually and thus is subject to change. If we are treated as a PFIC,

unless a US holder elects to be taxed annually on a mark-to-market

basis with respect to ordinary shares or ADSs, any gain realized on the

sale or other disposition of ordinary shares or ADSs would in general not

be treated as capital gain. Instead, a US holder would be treated as if he

or she had realized such gain rateably over the holding period for

ordinary shares or ADSs and would be taxed at the highest tax rate in

effect for each such year to which the gain was allocated, in addition to

which an interest charge in respect of the tax attributable to each such

year would apply. Certain 'excess distributions' would be similarly

treated if we were treated as a PFIC.

**Additional tax considerations**

**Scrip Programme**

Until the publication of the 2019 third quarter results, the company had

an optional Scrip Programme, wherein holders of bp ordinary shares or

ADSs could elect to receive any dividends in the form of new fully paid

ordinary shares or ADSs of the company instead of cash. Please consult

your tax advisor for the consequences to you.

**UK inheritance tax**

The Estate Tax Convention applies to UK inheritance tax. ADSs held by

an individual who is domiciled for the purposes of the Estate Tax

Convention in the US and is for the purposes of the Estate Tax

Convention a national of the US and not a national of the UK will not be

subject to UK inheritance tax on the individual's death or on transfer

during the individual's lifetime unless, among other things, the ADSs are

part of the business property of a permanent establishment situated in

the UK or a fixed base used for the performance of independent

personal services. In the exceptional case where ADSs are subject to

both inheritance tax and US federal gift or estate tax, the Estate Tax

Convention generally provides for tax payable in the US to be credited

against tax payable in the UK or for tax paid in the UK to be credited

against tax payable in the US, based on priority rules set forth in the

Estate Tax Convention.

**UK stamp duty and stamp duty reserve tax**

The statements below relate to what is understood to be the current

practice of HM Revenue & Customs in the UK under existing law.

Provided that any instrument of transfer is not executed in the UK and

remains at all times outside the UK and the transfer does not relate to

any matter or thing done or to be done in the UK, no UK stamp duty is

payable on the acquisition or transfer of ADSs. Neither will an

agreement to transfer ADSs in the form of ADRs give rise to a liability to

stamp duty reserve tax.

Purchases of ordinary shares, as opposed to ADSs, through the CREST

system of paperless share transfers will be subject to stamp duty

reserve tax at 0.5%. The charge will arise as soon as there is an

agreement for the transfer of the shares (or, in the case of a conditional

agreement, when the condition is fulfilled). The stamp duty reserve tax

will apply to agreements to transfer ordinary shares even if the

agreement is made outside the UK between two non-residents.

Purchases of ordinary shares outside the CREST system are subject

either to stamp duty at a rate of £5 per £1,000 (or part, unless the stamp

duty is less than £5, when no stamp duty is charged), or stamp duty

reserve tax at 0.5%. Stamp duty and stamp duty reserve tax are

generally the liability of the purchaser.

A subsequent transfer of ordinary shares to the Depositary's nominee

will give rise to further stamp duty at the rate of £1.50 per £100 (or part)

or stamp duty reserve tax at the rate of 1.5% of the value of the ordinary

shares at the time of the transfer. For ADR holders electing to receive

ADSs instead of cash, after the 2012 first quarter dividend payment, HM

Revenue & Customs no longer seeks to impose 1.5% stamp duty reserve

tax on issues of UK shares and securities to non-EU clearance services

and depositary receipt systems.

Major shareholders

The disclosure of certain major and significant shareholdings in the share

capital of the company is governed by the Companies Act 2006, the UK

Financial Conduct Authority's Disclosure Guidance and Transparency Rules

(DTR) and the US Securities Exchange Act of 1934.

Register of members holding bp ordinary shares as at

31 December 2025

---

| | | | |
|:---|:---|:---|:---|
| Range of holdings | Number of <br>ordinary<br>shareholders<br>| Percentage of <br>total<br>ordinary <br>shareholders<br>| Percentage of <br>total ordinary <br>share capital<br>excluding shares<br>held in treasury<br>|
| 1-200 | 50785 | 27.06 | 0.02 |
| 201-1000 | 60165 | 32.05 | 0.21 |
| 1001-10000 | 67106 | 35.75 | 1.35 |
| 10001-100000 | 8482 | 4.52 | 1.13 |
| 100001-1000000 | 648 | 0.35 | 1.54 |
| Over 1,000,000<sup>a</sup> | 522 | 0.28 | 95.76 |
| Totals | 187708 | 100 | 100 |

---

aIncludes JPMorgan Chase Bank, N.A. holding 26.40% of the total ordinary issued share capital

(excluding shares held in treasury) as the approved depositary for ADSs, a breakdown of

which is shown in the table below.

---

| | | |
|:---|:---|:---|
| 368 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

Register of holders of American depositary shares (ADSs) as at

31 December 2025<sup>a</sup>

---

| | | | |
|:---|:---|:---|:---|
| Range of holdings | Number of<br>ADS holders<br>| Percentage of<br> total ADS holders<br>| Percentage of <br>total ADSs<br>|
| 1-200 | 33191 | 58.98 | 0.26 |
| 201-1000 | 15026 | 26.70 | 1.04 |
| 1001-10000 | 7774 | 13.81 | 2.86 |
| 10001-100000 | 277 | 0.49 | 0.66 |
| 100001-1000000 | 3 | 0.01 | 0.08 |
| Over 1,000,000<sup>b</sup> | 2 | 0.00 | 95.10 |
| Totals | 56273 | 100 | 100 |

---

aOne ADS represents six 25 cent ordinary shares.

bOne holder of ADSs represents 1,278,163 approx. underlying shareholders.

As at 31 December 2025 there were also 1,038 preference shareholders.

Preference shareholders represented 0.54% and ordinary shareholders

represented 99.46% of the total issued nominal share capital of the

company (excluding shares held in treasury) as at that date.

As at 13 February 2026, the 8% preference shares and 9% preference

shares in issue comprised only 0.31% and 0.23% respectively of the

company's total issued nominal share capital (excluding shares held in

treasury) the rest being ordinary shares.

**Substantial shareholders**

The following table shows holdings of 3% or more voting rights in

ordinary shares of 25 cents in BP p.l.c. as per the most recent

notification of each respective holder to bp under DTR 5. The

percentage of voting rights detailed below was calculated as at the

date of the relevant disclosures.

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | As at 31 December 2025 | As at 31 December 2025 | As at 13 February 2026 | As at 13 February 2026 |
|  | Number of voting <br>rights<br>| Percentage <br>of capital<br>| Number of voting <br>rights<br>| Percentage <br>of capital<br>|
| BlackRock, Inc. | 1504412502 | 7.37 | 1504412502 | 7.37 |
| Elliott <br>Investment <br>Management, <br>L.P.<br>| 806743232 | 5.00 | 806743232 | 5.00 |
| Norges Bank<sup>a</sup> | 641036583 | 3.99 | 641036583 | 3.99 |

---

aIn the last three financial years and up to the date of this report, BP p.l.c. received six

notifications from Norges Bank relating to changes in its voting rights holdings, as follows: (1)

the percentage of voting rights exceeding 3% on 9 February 2023; (2) exceeding 4% on 12

September 2024; (3) falling below 4% on 20 September 2024; (4) exceeding 4% again on 23

September 2024; (5) falling below 4% on 11 April 2025; and (6) falling below 3% on 2 January

2026. There are no current disclosable interests in holdings of 3% or more

voting rights in 8% cumulative first preference shares of £1 each and 9%

cumulative second preference shares of £1 each.

**Largest registered shareholders**

Under the US Securities Exchange Act of 1934 bp is aware of the

following interests as at 13 February 2026.

Ordinary shares of $0.25 in BP p.l.c.:

---

| | | |
|:---|:---|:---|
| Holder | Holding of<br>ordinary shares<br>| Percentage of <br>ordinary share capital <br>excluding shares held <br>in treasury<br>|
| JPMorgan Chase Bank N.A., <br>depositary for ADSs, through its <br>nominee Guaranty Nominees <br>Limited<br>| 4184909371 | 26.65 |
| BlackRock, Inc. | 1429585141 | 9.11 |
| Vanguard Group Holdings | 840449006 | 5.35 |
| Norges Bank Investment <br>Management (NBIM)<br>| 460072521 | 2.93 |

---

8% cumulative first preference shares of £1 each in BP p.l.c.:

---

| | | |
|:---|:---|:---|
| Holder | Holding of 8%<br>cumulative first<br>preference <br>shares<br>| Percentage<br>of class<br>|
| Hargreaves Lansdown Asset <br>Management Limited<br>| 1384537 | 19.14 |
| Interactive Investor Share Dealing <br>Services<br>| 1114005 | 15.40 |
| Halifax Share Dealing Services | 625928 | 8.65 |
| Barclays, Plc. | 547371 | 7.57 |
| Canaccord Genuity Group Inc. | 532260 | 7.36 |
| AJ Bell Securities, Ltd. | 482911 | 6.68 |
| Ameriprise Financials, Inc. | 287500 | 3.97 |
| HSBC Holdings Plc | 247915 | 3.43 |

---

9% cumulative second preference shares of £1 each in BP p.l.c.:

---

| | | |
|:---|:---|:---|
| Holder | Holding of 9%<br>cumulative second <br>preference shares<br>| Percentage<br>of class<br>|
| Hargreaves Lansdown Asset Management <br>Limited<br>| 941599 | 17.20 |
| Interactive Investor Share Dealing <br>Services<br>| 695214 | 12.70 |
| AJ Bell Securities, Ltd | 640890 | 11.71 |
| Canaccord Genuity Group Inc. | 359000 | 6.56 |
| J. Safra Sarasin Group | 345500 | 6.31 |
| Halifax Share Dealing Services | 337325 | 6.16 |
| Ameriprise Financial, Inc. | 250000 | 4.57 |
| Barclays, PLC. | 188886 | 3.45 |
| HSBC Holdings Plc | 172325 | 3.15 |
| Charles Stanley Group Plc | 165697 | 3.03 |

---

The company's major shareholders' voting rights may differ to their

total interest and can be found under the 'Substantial shareholders'

heading above where voting rights are over 3%.

Annual general meeting (AGM)

The 2026 AGM is scheduled to be held on Thursday 23 April 2026 at

11:00am BST. A separate notice convening the meeting is distributed to

shareholders, which includes an explanation of the items of business to

be considered at the meeting.

All resolutions for which notice has been given will be decided on a poll.

Deloitte LLP have expressed their willingness to continue in office as

auditors and a resolution for their reappointment is included in the

*Notice of bp Annual General Meeting 2026.*

Memorandum and Articles of

Association

The following summarizes certain provisions of the company's

Memorandum and Articles of Association and applicable English law.

This summary is qualified in its entirety by reference to the UK

Companies Act 2006 (the Act) and the company's Memorandum and

Articles of Association. The Memorandum and Articles of Association

are available online at <u>bp.com/usefuldocs</u>.

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.

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|:---|:---|
| bp Annual Report and Form 20-F 2025 | 369 |

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| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Shareholder information** |

---

**Objects and purposes**

BP p.l.c. is a public company limited by shares and registered in England

and Wales with the registered number 102498. The provisions

regulating the operations of the company, known as its 'objects', were

historically stated in a company's memorandum. The Act abolished the

need to have object provisions and so at the AGM held on 15 April 2010

shareholders approved the removal of its objects clause together with

all other provisions of its Memorandum that, by virtue of the Act, are

treated as forming part of the company's Articles of Association.

**Directors and secretary**

The business and affairs of the company shall be managed by the

directors. The company's Articles of Association provide that any

person may be appointed by the existing directors or by the

shareholders in a general meeting either as a replacement for another

director or as an additional director. Any person appointed by the

directors will hold office only until the next general meeting, notice of

which is first given after their appointment and will then be eligible for

re-election by the shareholders. A director may be removed by the

company as provided for by applicable law and shall vacate office in

certain circumstances as set out in the Articles of Association. In

addition, the company may, by special resolution, remove a director

before the expiration of his/her period of office and, subject to the

Articles of Association, may by ordinary resolution appoint another

person to be a director instead. There is no requirement for a director to

retire on reaching any age.

The Articles of Association place a general prohibition on a director

voting in respect of any contract or arrangement in which the director

has a material interest other than by virtue of such director's interest in

shares in the company. However, in the absence of some other material

interest not indicated below, a director is entitled to vote and to be

counted in a quorum for the purpose of any vote relating to a resolution

concerning the following matters:

• The giving of security or indemnity with respect to any money lent or

obligation taken by the director at the request or benefit of the

company or any of its subsidiary undertakings.

• The giving of security or indemnity to a third party with respect to

any debt or obligation of the company or any of its subsidiary

undertakings for which the director has assumed responsibility.

• Any proposal in which the director is interested, concerning the

underwriting of company securities or debentures or the giving of

any security to a third party for a debt or obligation of the company

or any of its subsidiary undertakings.

• Any proposal concerning any other company in which the director is

interested, directly or indirectly (whether as an officer or shareholder

or otherwise), provided that the director and persons connected with

such director are not the holder or holders of 1% or more of the

voting interest in the shares of such company.

• Any proposal concerning the purchase or maintenance of any

insurance policy under which the director may benefit.

• Any proposal concerning the giving to the director of any other

indemnity which is on substantially the same terms as indemnities

given or to be given to all of the other directors or to the funding by

the company of his expenditure on defending proceedings or the

doing by the company of anything to enable the director to avoid

incurring such expenditure where all other directors have been given

or are to be given substantially the same arrangements.

• Any proposal concerning an arrangement for the benefit of the

employees and directors or former employees and former directors

of the company or any of its subsidiary undertakings, including but

without being limited to a retirement benefits scheme and an

employees' share scheme, which does not accord to any director any

privilege or advantage not generally accorded to the employees or

former employees to whom the arrangement relates.

The Act requires a director of a company who is in any way interested in

a contract or proposed contract with the company to declare the nature

of the director's interest at a meeting of the directors of the company.

The definition of 'interest' includes the interests of spouses, children,

companies and trusts. The Act also requires that a director must avoid a

situation where a director has, or could have, a direct or indirect interest

that conflicts, or possibly may conflict, with the company's interests.

The Act allows directors of public companies to authorize such conflicts

where appropriate, if a company's Articles of Association so permit. The

company's Articles of Association permit the authorization of such

conflicts. The directors may exercise all the powers of the company to

borrow money, except that the amount remaining undischarged of all

moneys borrowed by the company shall not, without approval of the

shareholders, exceed two times the amount paid up on the share capital

plus the aggregate of the amount of the capital and revenue reserves of

the company and its subsidiary undertakings incorporated in the UK.

Variation of the borrowing power of the board may only be affected by

amending the Articles of Association.

Remuneration of non-executive directors shall be determined in the

aggregate by resolution of the shareholders. Remuneration of executive

directors is determined by the remuneration committee. This

committee is made up of non-executive directors only. There is no

requirement of share ownership for a director's qualification.

The Articles of Association provide entitlement to the directors'

pensions and death and disability benefits to the directors' relations

and dependants respectively.

The circumstances in which a director's office will automatically

terminate include, among others: when a director ceases to hold an

executive office of the company and the directors resolve that they

should cease to be a director; if a medical practitioner provides an

opinion that a director has become incapable of acting as a director and

may remain so incapable for more than a further three months and the

directors resolve that they should cease to be a director; and if all of the

other directors vote in favour of a resolution stating that the person

should cease to be a director.

The company secretary has express powers to delegate any of the

powers or discretions conferred on him or her.

**Dividend rights; other rights to share in company profits;** 

**capital calls**

Shareholders of the company may, by resolution, declare dividends but

no such dividend may be declared in excess of the amount

recommended by the directors. The directors may also pay interim

dividends without obtaining shareholder approval. No dividend may be

paid other than out of profits available for distribution, as determined

under IFRS and the Act. Dividends on ordinary shares are payable only

after payment of dividends on bp preference shares. Any dividend

unclaimed after a period of 10 years from the date of declaration of

such dividend shall be forfeited and reverts to bp. If the company

exercises its right to forfeit shares and sells shares belonging to an

untraced shareholder, then any entitlement to claim dividends or other

monies unclaimed in respect of those shares will be for a period of 12

months after the sale. The company may take such steps as the

directors decide are appropriate in the circumstances to trace the

member entitled and the sale may be made at such time and on such

terms as the directors may decide.

The directors have the power to declare and pay dividends in any

currency provided that a sterling equivalent is announced. It is not the

company's intention to change its current policy of paying dividends in

US dollars. At the company's AGM held on 15 April 2010, shareholders

approved the introduction of a Scrip Dividend Programme (Scrip

Programme) and to include provisions in the Articles of Association to

enable the company to operate the Scrip Programme. The Scrip

Programme was renewed at the company's AGM held on 25 April 2024

for a further three years. The Scrip Programme enables ordinary

shareholders and bp ADS holders to elect to receive new fully paid

ordinary shares (or bp ADSs in the case of bp ADS holders) instead of

cash. The operation of the Scrip Programme is always subject to the

directors' decision to make the scrip offer available in respect of any

particular dividend. Should the directors decide not to offer the scrip in

respect of any particular dividend, cash will automatically be paid

instead. The directors may determine in relation to any scrip dividend

plan or programme how the costs of the programme will be met, the

minimum number of ordinary shares required in order to be able to

---

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|:---|:---|:---|
| 370 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

participate in the programme and any arrangements to deal with legal

and practical difficulties in any particular territory.

Apart from shareholders' rights to share in bp's profits by dividend (if

any is declared or announced), the Articles of Association provide that

the directors may set aside:

• A special reserve fund out of the balance of profits each year to

make up any deficit of cumulative dividend on the bp preference

shares.

• A general reserve out of the balance of profits each year, which shall

be applicable for any purpose to which the profits of the company

may properly be applied. This may include capitalization of such sum,

pursuant to an ordinary shareholders' resolution, and distribution to

shareholders as if it were distributed by way of a dividend on the

ordinary shares or in paying up in full unissued ordinary shares for

allotment and distribution as bonus shares.

Any such sums so deposited may be distributed in accordance with the

manner of distribution of dividends as described above.

Holders of shares are not subject to calls on capital by the company,

provided that the amounts required to be paid on issue have been paid

off. All shares are fully paid.

**Share transfers and share certificates**

The directors may permit transfers to be effected other than by an

instrument in writing. Share certificates will not be required to be issued

by the company if they are not required by law.

The company may charge an administrative fee in the event that a

shareholder wishes to replace two or more certificates representing

shares with a single certificate or wishes to surrender a single

certificate and replace it with two or more certificates. All certificates

are sent at the member's risk.

**Voting rights**

The Articles of Association of the company provide that voting on

resolutions at a shareholders' meeting will be decided on a poll other

than resolutions of a procedural nature, which may be decided on a

show of hands. If voting is on a poll, every shareholder who is present in

person or by proxy has one vote for every ordinary share held and two

votes for every £5 in nominal amount of bp preference shares held. If

voting is on a show of hands, each shareholder who is present at the

meeting in person or whose duly appointed proxy is present in person

will have one vote, regardless of the number of shares held, unless a

poll is requested.

Shareholders do not have cumulative voting rights.

For the purposes of determining which persons are entitled to attend or

vote at a shareholders' meeting and how many votes such persons may

cast, the company may specify in the notice of the meeting a time, not

more than 48 hours before the time of the meeting, by which a person

who holds shares in registered form must be entered on the company's

register of members in order to have the right to attend or vote at the

meeting or to appoint a proxy to do so.

Holders on record of ordinary shares may appoint a proxy, including a

beneficial owner of those shares, to attend, speak and vote on their

behalf at any shareholders' meeting, provided that a duly completed

proxy form is received not less than 48 hours (or such shorter time as

the directors may determine) before the time of the meeting or

adjourned meeting or, where the poll is to be taken after the date of the

meeting, not less than 24 hours (or such shorter time as the directors

may determine) before the time of the poll.

Record holders of bp ADSs are also entitled to attend, speak and vote at

any shareholders' meeting of the company by the appointment by the

approved depositary, JPMorgan Chase Bank N.A., of them as proxies in

respect of the ordinary shares represented by their ADSs. Each such

proxy may also appoint a proxy. Alternatively, holders of bp ADSs are

entitled to vote by supplying their voting instructions to the Depositary,

who will vote the ordinary shares represented by their ADSs in

accordance with their instructions.

Proxies may be delivered electronically.

Corporations who are members of the company may appoint one or

more persons to act as their representative or representatives at any

shareholders' meeting provided that the company may require a

corporate representative to produce a certified copy of the resolution

appointing them before they are permitted to exercise their powers.

Matters are transacted at shareholders' meetings by the proposing and

passing of resolutions, of which there are two types: ordinary or special.

An ordinary resolution requires the affirmative vote of a majority of the

votes cast at a meeting at which there is a quorum. A special resolution

requires the affirmative vote of not less than three quarters of the votes

cast at a meeting at which there is a quorum. Any AGM requires 21 clear

days' notice. The notice period for any other general meeting is 14 clear

days subject to the company obtaining annual shareholder approval,

failing which, a 21 clear day notice period will apply.

**Liquidation rights; redemption provisions**

In the event of a liquidation of bp, after payment of all liabilities and

applicable deductions under UK laws and subject to the payment of

secured creditors, the holders of bp preference shares would be

entitled to the sum of (1) the capital paid up on such shares plus,

(2) accrued and unpaid dividends and (3) a premium equal to the higher

of (a) 10% of the capital paid up on the bp preference shares and (b) the

excess of the average market price over par value of such shares on the

London Stock Exchange during the previous six months. The remaining

assets (if any) would be divided pro rata among the holders of ordinary

shares.

Without prejudice to any special rights previously conferred on the

holders of any class of shares, bp may issue any share with such

preferred, deferred or other special rights, or subject to such

restrictions as the shareholders by resolution determine (or, in the

absence of any such resolutions, by determination of the directors), and

may issue shares that are to be or may be redeemed.

**Variation of rights**

The rights attached to any class of shares may be varied with the

consent in writing of holders of 75% of the shares of that class or on the

adoption of a special resolution passed at a separate meeting of the

holders of the shares of that class. At every such separate meeting, all

of the provisions of the Articles of Association relating to proceedings

at a general meeting apply, except that the quorum with respect to a

meeting to change the rights attached to the preference shares is 10%

or more of the shares of that class, and the quorum to change the rights

attached to the ordinary shares is one third or more of the shares of

that class.

**Shareholders' meetings and notices**

Shareholders must provide bp with a postal or electronic address in the

UK to be entitled to receive notice of shareholders' meetings. Holders of

bp ADSs are entitled to receive notices under the terms of the deposit

agreement relating to bp ADSs. The substance and timing of notices are

described above under the heading 'Voting rights'.

Under the Act, the AGM of shareholders must be held once every year,

within each six-month period beginning with the day following the

company's accounting reference date. All general meetings shall be

held at a time and place determined by the directors. If any

shareholders' meeting is adjourned for lack of quorum, notice of the

time and place of the adjourned meeting may be given in any lawful

manner, including electronically. Powers exist for action to be taken

either before or at the meeting by authorized officers to ensure its

orderly conduct and safety of those attending.

The directors have power to convene a general meeting which is a

hybrid meeting, that is to provide facilities for shareholders to attend a

meeting which is being held at a physical place by electronic means as

well (but not to convene a purely electronic meeting).

The provisions of the Articles of Association in relation to satellite

meetings permit facilities being provided by electronic means to allow

those persons at each place to participate in the meeting.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 371 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Shareholder information** |

---

**Limitations on voting and shareholding**

There are no limitations, either under the laws of the UK or under the

company's Articles of Association, restricting the right of non-resident

or foreign owners to hold or vote bp ordinary or preference shares in

the company other than limitations that would generally apply to all of

the shareholders and limitations applicable to certain countries and

persons subject to EU economic sanctions or those sanctions adopted

by the UK government which implement resolutions of the Security

Council of the United Nations.

**Disclosure of interests in shares**

The Act permits a public company to give notice to any person whom

the company believes to be or, at any time during the three years prior

to the issue of the notice, to have been interested in its voting shares

requiring them to disclose certain information with respect to those

interests. Failure to supply the information required may lead to

disenfranchisement of the relevant shares and a prohibition on their

transfer and receipt of dividends and other payments in respect of

those shares and any new shares in the company issued in respect of

those shares. In this context the term 'interest' is widely defined and will

generally include an interest of any kind whatsoever in voting shares,

including any interest of a holder of bp ADSs.

**Called-up share capital**

Details of the allotted, called-up and fully-paid share capital at

31 December 2025 are set out in Financial statements – Note 31. In

accordance with institutional investor guidelines, the company deems it

appropriate to grant authority to the directors to allot shares and other

securities and to disapply pre-emption rights by way of shareholders'

resolutions at each AGM in place of authority granted by virtue of the

company's Articles of Association. At the AGM on 17 April 2025,

authorization was given to the directors to allot shares in the company

and to grant rights to subscribe for, or to convert any security into,

shares in the company up to an aggregate nominal amount as set out in

the *Notice of Annual General Meeting 2025*. These authorities were

given for the period until the next AGM in 2026 or 17 July 2026,

whichever is the earlier. These authorities are renewed annually at

the AGM.

**Company records and service of notice**

In relation to notices not covered by the Act, the reference to notice by

advertisement in a national newspaper also includes advertisements via

other means such as a public announcement.

---

| | | |
|:---|:---|:---|
| 372 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

Purchases of equity securities by the issuer and affiliated purchasers

During the 2025 financial year the company repurchased 835,648,878 ordinary shares with a nominal value of $0.25 each for a total consideration

of $4,479,471,803 (including transaction costs), for the purpose of returning capital to shareholders and to offset the expected dilution from the

vesting of awards under employee share schemes. The shares repurchased in 2025 represented 5.35% of the company's issued share capital,

excluding shares held in treasury, on 31 December 2025. Of the shares repurchased in 2025, shares purchased under the 2024 AGM authority

represented 3.27%, and shares purchased under the 2025 AGM authority represented 2.07% of bp's issued share capital, excluding shares held in

treasury, on 31 December 2025. A further 74,395,880 ordinary shares were repurchased between the end of the financial year and 13 February 2026

at a cost of $450,225,900 (including transaction costs) representing 0.48% of the company's issued share capital, excluding shares held in treasury,

on 31 December 2025. Of the ordinary shares repurchased in 2025 and in 2026 up to 13 February under the share buyback programme, 176,152,257

were cancelled and 733,892,501 were transferred into treasury.

Authorization for the company to make market purchases (as defined in section 693(4) of the Companies Act 2006) of ordinary shares with a

nominal value of $0.25 each in the company was renewed at the company's 2025 AGM covering the period until the date of the company's 2026

AGM or 17 July 2026, whichever is earlier. The maximum number of ordinary shares to be purchased under this authority will not exceed

1,600,606,341 ordinary shares. The shares purchased may be cancelled or held in treasury.

The following table provides details of ordinary share purchases made (1) under the share buyback programmes and (2) by the Employee Share

Ownership Plans (ESOPs) and other purchases of ordinary shares and ADSs made to satisfy the requirements of certain employee share-based

payment plans.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  | **Total number of** <br>**shares** <br>**purchased**<sup>a</sup><br>| **Average price**<br>**paid per share**<br>**$**<br>| Number of <br>shares <br>purchased by <br>ESOPs or for <br>certain <br>employee <br>share-based <br>plans<sup>b</sup><br>| Number of <br>shares <br>purchased under <br>buyback <br>programmes<sup>c</sup><br>| Maximum <br>approximate <br>dollar value of <br>shares yet to <br>be purchased <br>under the <br>programmes <br>$ million<br>|
| **2025** |  |  |  |  |  |
| January 7 - January 31 | **132132317** | **5.25** | 1200000 | 130932317 | N/A |
| February 3 - February 11 | **45219940** | **5.30** |  | 45219940 | N/A |
| March 6 - March 31 | **165553368** | **5.56** | 68000 | 165485368 | N/A |
| April 1 - April 29 | **170261000** | **4.88** |  | 170261000 | N/A |
| May 21 - May 30 | **11533500** | **4.88** |  | 11533500 | N/A |
| June 2 - June 30 | **33297000** | **5.08** |  | 33297000 | N/A |
| July 1 - July 31 | **88997107** | **5.32** |  | 88997107 | N/A |
| August 1 - August 29 | **25601600** | **5.60** |  | 25601600 | N/A |
| September 1 - September 30 | **22955250** | **5.80** |  | 22955250 | N/A |
| October 1 - October 31 | **86032971** | **5.73** |  | 86032971 | N/A |
| November 3 - November 28 | **30171877** | **6.03** |  | 30171877 | N/A |
| December 1 - December 22 | **25160948** | **5.98** |  | 25160948 | N/A |
| **2026** |  |  |  |  |  |
| January 7 - January 30 | **54782912** | **5.92** |  | 54782912 | N/A |
| February 2 - February 13 | **37278988** | **6.31** | 17666020 | 19612968 | N/A |

---

aAll share purchases were of ordinary shares of $0.25 each and/or ADSs (each representing six ordinary shares) and were on/open market transactions.

bTransactions represent the purchases of ordinary shares and ADSs made to satisfy requirements of certain employee share-based payment plans.

cShare repurchases from 1 January to 7 February 2025 were made under a share buyback programme announced on 29 October 2024 for a period up to and including 7 February 2025. On 3 March

2025 the company announced a programme covering a period up to and including 25 April 2025. On 29 April 2025 the company announced a programme covering a period up to and including 1

August 2025. On 5 August 2025 the company announced a programme covering a period up to and including 31 October 2025. On 4 November 2025 the company announced a programme

covering a period up to and including 6 February 2026.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 373 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **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 <br>underlying shares<br>| Issuance of ADSs against the deposit of shares, <br>including deposits and issuances in respect of:<br>•Share distributions, stock splits, rights, merger.<br>•Exchange of securities or other transactions or <br>event or other distribution affecting the ADSs or <br>deposited securities.<br>| $5.00 per 100 ADSs (or portion thereof) <br>evidenced by the new ADSs delivered.<br>|
| Selling or exercising rights | Distribution or sale of securities, the fee being an <br>amount equal to the fee for the execution and delivery <br>of ADSs that would have been charged as a result of <br>the deposit of such securities.<br>| $5.00 per 100 ADSs (or portion thereof). |
| Withdrawing an underlying share | Acceptance of ADSs surrendered for withdrawal of <br>deposited securities.<br>| $5.00 for each 100 ADSs (or portion thereof) <br>evidenced by the ADSs surrendered.<br>|
| Expenses of the Depositary | Expenses incurred on behalf of holders in connection <br>with:<br>•Stock transfer or other taxes and governmental <br>charges.<br>•Delivery by cable, telex, electronic and facsimile <br>transmission.<br>•Transfer or registration fees, if applicable, for the <br>registration of transfers of underlying shares.<br>•Expenses of the Depositary in connection with the <br>conversion of foreign currency into US dollars <br>(which are paid out of such foreign currency).<br>| Expenses payable are subject to agreement <br>between the company and the Depositary by <br>billing holders or by deducting charges from <br>one or more cash dividends or other cash <br>distributions.<br>|
| Dividend fees | ADS holders who receive a cash dividend are charged a <br>fee which bp uses to offset the costs associated with <br>administering the ADS programme.<br>| The Deposit Agreement provides that a fee of <br>$0.05 or less per ADS can be charged. The <br>current fee is $0.02 per bp ADS per calendar <br>year (equivalent to $0.005 per bp ADS per <br>quarter per cash distribution).<br>|
| Global Invest Direct (GID) Plan | New investors and existing ADS holders can buy, sell or <br>reinvest dividends into further bp ADSs by enrolling in <br>bp's GID Plan, sponsored and administered by the <br>Depositary.<br>| Cost per transaction is $2.00 for recurring, <br>$2.00 for one-time automatic investments, and <br>$5.00 for investment made by check. Dividend <br>reinvestment is 5% of the dividend amount up <br>to a maximum of $5.00. Purchase trading <br>commission is $0.12 per share. <br>|

---

Fees and payments made by the

Depositary to the issuer

The Depositary has agreed to reimburse certain company expenses

related to the company's ADS programme and incurred by the company

in connection with the ADS programme arising during the year ended 31

December 2025. The Depositary reimbursed to the company, or paid

amounts on the company's behalf to third parties, or waived its fees and

expenses, of $15,033,009.99 for the year ended 31 December 2025.

The table below sets out the types of expenses that the Depositary has

agreed to reimburse and the fees it has agreed to waive for standard

costs associated with the administration of the ADS programme

relating to the year ended 31 December 2025.

---

| | |
|:---|:---|
| Category of expense reimbursed,<br>waived or paid directly to third parties<br>| Amount reimbursed, waived or <br>paid directly to third parties for <br>the year ended 31 December 2025<br>$|
| Fees for delivery and surrender of bp <br>ADSs<br>| 1788953.72 |
| Dividend fees<sup>a</sup> | 13244056.27 |
| Waived fees |  |
| Total | 15033009.99 |

---

aDividend fees are charged to ADS holders who receive a cash distribution, which bp uses to

offset the costs associated with administering the ADS programme.

Under certain circumstances, including removal of the Depositary or

termination of the ADS programme by the company, the company is

required to repay the Depositary certain amounts reimbursed and/or

expenses paid to or on behalf of the company during the 12-month

period prior to notice of removal or termination.

Documents on display

The *bp Annual Report and Form 20-F 2025* is available online at

<u>bp.com/annualreport</u>. To obtain a hard copy of bp's complete audited

financial statements, free of charge, UK-based shareholders should

contact bp Distribution Services by calling +44 (0) 800 037 2172 or by

emailing bpdistributionservices@bp.com. If based in the US or Canada,

shareholders should contact Equiniti by calling 1 888 301 2505 or by

emailing bpreports@equiniti.com

The company is subject to the information requirements of the US

Securities Exchange Act of 1934 applicable to foreign private issuers. In

accordance with these requirements, the company files its *Annual* 

*Report and Form 20-F* and other related documents with the SEC. The

SEC maintains an internet site at sec.gov that contains reports and

other information regarding issuers, including bp, that file electronically

with the SEC. bp's SEC filings are also available at <u>bp.com/sec</u>. bp

discloses in this report (see Corporate governance practices (Form 20-F

Item 16G) on page <u>[359](#i0dd2ee81aac04f8c9c97c86197f0c6df_520)</u> significant ways (if any) in which its corporate

governance practices differ from those mandated for US companies

under NYSE listing standards.

---

| | | |
|:---|:---|:---|
| 374 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

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 <u>mybpshares.com</u>

**ADS holders**

Computershare Trust Company, N.A.

PO Box 43304, Providence, RI 02940-3304

Toll-free in the US +1 877 638 5672

From outside the US +1 651 306 4383

2026 shareholder calendar<sup>a</sup>

---

| | |
|:---|:---|
| 27 Mar 2026 | Fourth quarter interim dividend payment for 2025 |
| 23 Apr 2026 | Annual general meeting  |
| 28 April 2026 | First quarter results announced  |
| 15 May 2026 | Record date (to be eligible for the first quarter interim <br>dividend)<br>|
| 26 June 2026 | First quarter interim dividend payment for 2025 and 8% <br>and 9% preference shares record date<br>|
| 31 Jul 2026 | 8% and 9% preference shares dividend payment |
| 04 Aug 2026 | Second quarter results announced |
| 14 Aug 2026 | Record date (to be eligible for the second quarter <br>interim dividend)<br>|
| 18 Sep 2026 | Second quarter interim dividend payment for 2025 |
| 27 Oct 2026 | Third quarter results announced |
| 6 Nov 2026 | Record date (to be eligible for the third quarter interim <br>dividend)<br>|
| 18 Dec 2026 | Third quarter interim dividend payment for 2025 |

---

aAll future dates are provisional and may be subject to change. For the full calendar see

bp.com/financialcalendar.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 375 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Glossary** |

---

**Glossary**

Abbreviations

**ADR**

American depositary receipt.

**ADS**

American depositary share. 1 ADS = 6 ordinary shares.

**Barrel (bbl)**

159 litres, 42 US gallons.

**bcf**

Billion cubic feet.

**bcfe**

Billion cubic feet equivalent.

**boe**

Barrels of oil equivalent.

**CAGR**

Compound annual growth rate.

**EJ/yr**

Exajoules per year.

**EVP**

Executive vice president.

**FPSO**

Floating production, storage and offloading.

**GAAP**

Generally accepted accounting practice.

**Gas**

Natural gas.

**gCO2e/MJ**

Grams of carbon dioxide equivalent per megajoule of energy.

**GHG**

Greenhouse gas.

**GRI**

Global Reporting Initiative.

**GtCO2**

Gigatonnes of carbon dioxide.

**GW**

Gigawatt.

**GWh**

Gigawatt hour.

**HSSE**

Health, safety, security and environment.

**IFRS**

International Financial Reporting Standards.

**kb/d**

Thousand barrels per day.

**KPIs**

Key performance indicators.

**kt**

Thousand tonnes.

**LNG**

Liquefied natural gas.

**LPG**

Liquefied petroleum gas.

**mb/d**

Thousand barrels per day.

**Mbbl**

Million barrels.

**mboe/d**

Thousand barrels of oil equivalent per day.

**mmb/d**

Million barrels per day.

**mmboe/d**

Million barrels of oil equivalent per day.

**mmBtu**

Million British thermal units.

**mmcf/d**

Million cubic feet per day.

**Mt**

Million tonnes.

**MtCO2e**

Million tonnes of CO2 equivalent.

**Mtpa**

Million tonnes per annum.

**MW**

Megawatt.

**MWe**

Megawatt electrical.

**MWp**

Megawatt peak.

**NGLs**

Natural gas liquids.

**PSA**

Production-sharing agreement.

**PTA**

Purified terephthalic acid.

**RC**

Replacement cost.

**SEC**

The United States Securities and Exchange Commission.

**TWh**

Terawatt hour.

**SVP**

Senior vice president.

**scfm**

Standard cubic feet per minute.

---

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---

Definitions

Unless the context indicates otherwise, the definitions for the following

glossary terms are given below.

Non-IFRS measures are sometimes referred to as alternative

performance measures.

**CA100+ resolution glossary**

**CA100+ resolution** 

The CA100+ resolution means the special resolution requisitioned by

Climate Action 100+ and passed at bp's 2019 Annual General Meeting,

the text of which is set out below.

Special resolution: Climate Action 100+ shareholder resolution on

climate change disclosures.

That in order to promote the long-term success of the company, given

the recognized risks and opportunities associated with climate change,

we as shareholders direct the company to include in its strategic report

and/or other corporate reports, as appropriate, for the year ending 2019

onwards, a description of its strategy which the board considers, in

good faith, to be consistent with the goals of Articles 2.1(a)(1) and 4.1(2) of

the Paris Agreement (3) (the Paris goals), as well as:

(1) Capital expenditure: how the company evaluates the consistency of

each new material capex investment, including in the exploration,

acquisition or development of oil and gas resources and reserves and

other energy sources and technologies, with (a) the Paris goals and

separately (b) a range of other outcomes relevant to its strategy.

(2) Metrics and targets: the company's principal metrics and relevant

targets or goals over the short, medium and/or long term, consistent

with the Paris goals, together with disclosure of:

aThe anticipated levels of investment in (i) oil and gas resources and

reserves; and (ii) other energy sources and technologies.

bThe company's targets to promote reductions in its operational

greenhouse gas emissions, to be reviewed in line with changing

protocols and other relevant factors.

cThe estimated carbon intensity of the company's energy products and

progress on carbon intensity over time.

dAny linkage between the above targets and executive remuneration.

(3) Progress reporting: an annual review of progress against (1) and (2)

above.

Such disclosure and reporting to include the criteria and summaries of

the methodology and core assumptions used, and to omit commercially

confidential or competitively sensitive information and be prepared at

reasonable cost; and provided that nothing in this resolution shall limit

the company's powers to set and vary its strategy, or associated targets

or metrics, or to take any action which it believes in good faith, would

best promote the long-term success of the company.

The Paris goals

(1)Article 2.1(a) of the Paris Agreement states the goal of 'Holding the

increase in the global average temperature to well-below-2°C above

pre-industrial levels and pursuing efforts to limit the temperature

increase to 1.5°C above pre-industrial levels, recognizing that this

would significantly reduce the risks and impacts of climate change'.

(2)Article 4.1 of the Paris Agreement: In order to achieve the long-term

temperature goal set out in Article 2, parties aim to reach global

peaking of greenhouse gas emissions as soon as possible,

recognizing that peaking will take longer for developing country

parties, and to undertake rapid reductions thereafter in accordance

with best available science, so as to achieve a balance between

anthropogenic emissions by sources and removals by sinks of

greenhouse gases in the second half of this century, on the basis of

equity, and in the context of sustainable development and efforts to

eradicate poverty.

(3)U.N. Framework Convention on Climate Change Conference of

Parties, Twenty-First Session, Adoption of the Paris Agreement, U.N.

Doc. FCCC/CP/2015/L.9/Rev.1 (Dec. 12, 2015).

**New material capex investment**

For the purposes of the 2024 evaluation discussed on pages <u>[20](#i0dd2ee81aac04f8c9c97c86197f0c6df_52)</u><u>-</u><u>[23](#i2249540127db4d059a13c9b841c3712c_11132)</u><u>,</u> 'new

material capex investment' means a decision taken by the resource

commitment meeting (RCM) in 2024 to incur inorganic or organic

investments greater than $250 million that relate to a new project or

asset, extending an existing project or asset, or acquiring or increasing a

share in a project, asset or entity.

For the purposes of evaluating material capex investments for

consistency with the Paris goals, two quantitative tests were applied,

see page <u>[22](#i2249540127db4d059a13c9b841c3712c_11131)</u>.

**Operational carbon intensity (CI)**

The annual average operational GHG emissions (TeCO2e/unit), divided

by the relevant unit of output:

Per thousand barrels of oil equivalent in upstream.

• Per utilized equivalent distillation capacity in refining.

• per thousand tonnes of petrochemicals production.

**Net zero aims and ambition glossary**

**Average carbon intensity of sold energy products**

The rate of GHG emissions per unit of energy delivered (in grams CO2e/

MJ) estimated in respect of sold energy products★. GHG emissions are

estimated on a lifecycle basis covering use, production, and distribution

of sold energy products.

**Energy products**

For the purposes of our 2025 disclosures relating to net zero sales★ we

consider an energy product to be one that is emissive or provides

energy in its end use case. For further information on products included

in bp's 2025 net zero sales aim reporting see the *bp Basis of Reporting* 

*2025*, <u>bp.com/basisofreporting</u>.

**Methane intensity** 

Methane intensity refers to the amount of methane emissions from bp's

operated upstream oil and gas assets as a percentage of the total gas

that goes to market from those operations. Our methodology is aligned

with the Oil and Gas Climate Initiative (OGCI) methodology.

**Net zero**

References to global net zero in the phrase, 'to help the world get to net

zero', means achieving '...a balance between anthropogenic emissions

by sources and removals by sinks of greenhouse gases...on the basis of

equity, and in the context of sustainable development and efforts to

eradicate poverty', as set out in Article 4(1) of the Paris Agreement.

References to net zero for bp in the context of our ambition and net

zero operations and net zero sales aims mean achieving a balance

between (a) the relevant Scope 1 and 2 emissions (for net zero

operations) and product lifecycle emissions (for net zero sales) and (b)

the aggregate of applicable deductions from qualifying activities such

as sinks under our methodology at the applicable time.

**Net zero**★ **operations**

bp's aim to reach net zero operational greenhouse gas (CO2 and

methane) emissions by 2050 or sooner, on a gross operational control

basis, in accordance with bp's net zero operations aim, which relates to

our reported Scope 1 and 2 emissions. Any interim target or aim in

respect of bp's net zero operations aim is defined in terms of absolute

reductions relative to the baseline year of 2019.

**Net zero sales**

bp's aim to reach net zero for the carbon intensity of sold energy

products★. Any interim target or aim in respect of bp's net zero sales

aim is defined in terms of reductions in the carbon intensity of the

energy products we sell (in grams CO2e/MJ) relative to the baseline

year of 2019.

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|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Glossary** |

---

**Sold energy products**

For the purposes of bp's net zero sales aim, sold energy products

represent sales by a bp group subsidiary, joint operation or bp equity

accounted entity (EAE). For further information see the bp Basis of

Reporting 2025 <u>bp.com/basisofreporting</u>.

**Adjusted EBIDA** 

Adjusted EBIDA is a non-IFRS measure. This metric, as applicable to the

directors' remuneration performance measure, requires a calculation of

profit or loss for the period, adjusting for finance costs and net finance

(income) or expense relating to pensions and other post-employment

benefits and taxation, inventory holding gains or losses before tax, net

adjusting items★ before interest and tax, and taxation on an underlying

RC basis, and adding back depreciation, depletion and amortization

(pre-tax) and exploration expenditure written-off (net of adjusting items,

pre-tax). The nearest equivalent measure on an IFRS basis is profit or

loss for the period.

**Adjusted EBIDA per share compound annual growth rate** 

**(CAGR)**

Adjusted EBIDA per share is a non-IFRS measure. This metric, as

applicable to the directors' remuneration performance measure, is

calculated based on the shares in issue at period end.

**Adjusted EBITDA** 

Adjusted EBITDA is a non-IFRS measure presented for bp's operating

segments and the group. Adjusted EBITDA for bp's operating segments

is defined as replacement cost (RC) profit before interest and tax,

excluding net adjusting items before interest and tax, and adding back

depreciation, depletion and amortization and exploration write-offs (net

of adjusting items). Adjusted EBITDA by business is a further analysis of

adjusted EBITDA for the customers & products businesses. bp believes

it is helpful to disclose adjusted EBITDA by operating segment and by

business because it reflects how the segments measure underlying

business delivery. The nearest equivalent measure on an IFRS basis for

the segment is RC profit or loss before interest and tax, which is bp's

measure of profit or loss that is required to be disclosed for each

operating segment under IFRS. A reconciliation to IFRS information is

provided on pages **<u>[350](#i07755ba02df142ddbe272479a28d7a7a_5878)</u> and <u>[388](#i8d8183dbb7704a419cda8a463c63183a_7145)</u>**.

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 **<u>[387](#i8d8183dbb7704a419cda8a463c63183a_7142)</u>**.

**Adjusted free cash flow**

Non-IFRS measure. It is defined as adjusted operating cash flow★ (see

below) less total cash capital expenditure★.

bp believes the measure provides useful information to investors.

Adjusted free cash flow enables investors to measure our progress on

delivering growth and improving our performance. The nearest IFRS

measures are net cash provided by (used in) operating activities and

total cash capital expenditure.

We are unable to present reconciliations of forward-looking information

for adjusted free cash flow to net cash provided by operating activities,

because without unreasonable efforts, we are unable to forecast

accurately certain adjusting items required to present a meaningful

comparable IFRS forward-looking financial measure. These items

include inventory holding gains or losses, fair value accounting effects

and other adjusting items, that are difficult to predict in advance in

order to include in an IFRS estimate.

**Adjusted free cash flow compound annual growth rate (CAGR)** 

Non-IFRS measure. Adjusted free cash flow compound annual growth is

the annualized growth rate of adjusted free cash flow (defined above).

bp believes adjusted free cash flow CAGR is useful information to

investors to compare with adjusted free cash flow on a price adjusted

basis CAGR. The nearest IFRS measures to calculate adjusted free cash

flow CAGR are net cash provided by (used in) operating activities and

total cash capital expenditure.

**Adjusted free cash flow compound annual growth rate (CAGR)** 

**(primary target)**

Non-IFRS measure. Our primary target adjusted free cash flow CAGR is

on a price adjusted basis and is the annualized growth rate of adjusted

free cash flow (defined above), assuming a hypothetical price

environment of $70/bbl Brent, $4/mmBtu Henry Hub, and $10.3/bbl

refining indicator margin (all 2024 real) and assumptions about the

impact of these marker prices on underlying replacement cost profit

before tax.

bp believes adjusted free cash flow on a price adjusted basis compound

annual growth rate helps investors to measure our progress on

delivering growth and improving our performance on a normalized price

environment basis. The nearest IFRS measures to calculate adjusted

free cash flow CAGR are net cash provided by (used in) operating

activities and total capital expenditure.

We are unable to present reconciliations of forward-looking information

for adjusted free cash flow to net cash provided by operating activities,

because without unreasonable efforts, we are unable to forecast

accurately certain adjusting items required to present a meaningful

comparable IFRS forward-looking financial measure. These items

include inventory holding gains or losses, fair value accounting effects

and other adjusting items, that are difficult to predict in advance in

order to include in an IFRS estimate.

**Adjusted operating cash flow**

Non-IFRS measure. It is defined as net cash provided by (used in)

operating activities as presented in the group cash flow statement,

excluding movements in inventories and other current and non-current

assets and liabilities as presented in the group cash flow statement,

adjusted for inventory holding gains/losses, fair value accounting

effects (FVAEs) relating to subsidiaries and other adjusting items

relating to the non-cash movement of US emissions obligations carried

as a provision that will be settled by allowances held as inventory. When

used in the context of a segment or subset of businesses rather than

the group, the terms refer to the segment or business' estimated share

thereof.

bp believes the measure provides useful information to investors.

Adjusted operating cash flow enables investors to measure our

progress on delivering growth and improving our performance. The

nearest IFRS measure is net cash provided by (used in) operating

activities.

We are unable to present reconciliations of forward-looking information

for adjusted operating cash flow to net cash provided by operating

activities, because without unreasonable efforts, we are unable to

forecast accurately certain adjusting items required to present a

meaningful comparable IFRS forward-looking financial measure. These

items include inventory holding gains or losses, FVAEs and other

adjusting items, that are difficult to predict in advance in order to

include in an IFRS estimate.

**Adjusted operating expenditure**

Non IFRS measure and a subset of production and manufacturing

expenses plus distribution and administration expenses. It represents

the majority of the remaining expenses in these line items but excludes

certain costs that are variable, primarily with volumes (such as freight

costs). Other variable costs are included in purchases in the income

statement. Management believes that adjusted operating expenditure

is a performance measure that provides investors with useful

information regarding the company's financial performance because it

considers these expenses to be the principal operating and overhead

expenses that are most directly under their control although they also

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---

include certain adjusting items★, foreign exchange and commodity

price effects. The nearest IFRS measures are production and

manufacturing expenses and distributions and administration

expenses. A reconciliation of production and manufacturing expense

plus distribution and administration expenses to adjusted operating

expenditure is provided on page **<u>[386](#i8d8183dbb7704a419cda8a463c63183a_7146)</u>**.

**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 **<u>[336](#i70cb1abed366405bb4de86a8f38af0b7_5994)</u>**.

**Associate**

An entity over which the group has significant influence and that is

neither a subsidiary nor a joint arrangement of the group. Significant

influence is the power to participate in the financial and operating

policy decisions of the investee but is not control or joint control over

those policies.

**Blue hydrogen**

Hydrogen made from natural gas or coal in combination with carbon

capture and storage (CCS).

**Capital employed** 

Non-IFRS measure. It is defined as total equity plus finance debt.

**Capital expenditure**

Total cash capital expenditure as stated in the group cash flow

statement. Capital expenditure for the operating segments, gas & low

carbon energy businesses and customers & products businesses is

presented on the same basis.

**Commodity trading contracts**

bp participates in regional and global commodity trading markets in

order to manage, transact and hedge the crude oil, refined products

and natural gas that the group either produces or consumes in its

manufacturing operations. The range of contracts the group enters into

in its commodity trading operations is described below. Using these

contracts, in combination with rights to access storage and

transportation capacity, allows the group to access advantageous

pricing differences between locations, time periods and grades.

**Exchange-traded commodity derivatives**

Contracts that are typically in the form of futures and options traded on

a recognized exchange, such as Nymex and ICE. Such contracts are

traded in standard specifications for the main marker crude oils, such

as Brent and West Texas Intermediate; the main product grades, such

as gasoline and gasoil; and for natural gas and power. Gains and losses,

otherwise referred to as variation margin, are generally settled on a

daily basis with the relevant exchange. These contracts are used for the

trading and risk management of crude oil, refined products, and natural

gas and power. Realized and unrealized gains and losses on exchange-

traded commodity derivatives are included in sales and other operating

revenues for accounting purposes.

**Over-the-counter (OTC) contracts** 

Contracts that are typically in the form of forwards, swaps and options.

Some of these contracts are traded bilaterally between counterparties

or through brokers, others may be cleared by a central clearing

counterparty. These contracts can be used both for trading and risk

management activities. Realized and unrealized gains and losses on

OTC contracts are included in sales and other operating revenues for

accounting purposes. Many grades of crude oil bought and sold use

standard contracts including US domestic light sweet crude oil,

commonly referred to as West Texas Intermediate, and a standard

North Sea crude blend – Brent, Forties, Oseberg and Ekofisk (BFOE).

Forward contracts are used in connection with the purchase of crude oil

supplies for refineries and for marketing and sales of the group's oil

production and refined products. The contracts typically contain

standard delivery and settlement terms. These transactions call for

physical delivery of oil with consequent operational and price risk.

However, various means exist and are used from time to time, to settle

obligations under the contracts in cash rather than through physical

delivery. Physically settled BFOE contracts delivered by cargo

additionally specify a standard volume and tolerance.

Gas and power OTC markets are highly developed in North America and

the UK, where commodities can be bought and sold for delivery in

future periods. These contracts are negotiated between two parties to

purchase and sell gas and power at a specified price, with delivery and

settlement at a future date. Typically, the contracts specify delivery

terms for the underlying commodity. Some of these transactions are

not settled physically as they can be net settled by transacting

offsetting sale or purchase contracts for the same location and delivery

period. The contracts contain standard terms such as delivery point,

pricing mechanism, settlement terms and specification of the

commodity. Typically, volume, price and term (e.g. daily, monthly and

balance of month) are the main variable contract terms.

Swaps are typically contractual obligations to exchange cash flows

between two parties. A typical swap transaction usually references a

floating price and a fixed price with the net difference of the cash flows

being settled. Options give the holder the right, but not the obligation,

to buy or sell crude, oil products, natural gas or power at a specified

price on or before a specific future date. Amounts under these

derivative financial instruments are settled at expiry. Typically, netting

agreements are used to limit credit exposure and support liquidity.

**Spot and term contracts** 

Spot contracts are contracts to purchase or sell a commodity at the

market price prevailing on or around the delivery date when title to the

inventory is taken. Term contracts are contracts to purchase or sell a

commodity at regular intervals over an agreed term. Though spot and

term contracts may have a standard form, there is no offsetting

mechanism in place. As such, these transactions result in physical

delivery with operational and price risk. Spot and term contracts

typically relate to purchases of crude for a refinery, products for

marketing, or third-party natural gas, or sales of the group's oil

production, oil products or gas production to third parties. For

accounting purposes, spot and term sales are included in sales and

other operating revenues when title passes. Similarly, spot and term

purchases are included in purchases for accounting purposes.

**Consolidation adjustment – UPII**

Unrealized profit in inventory arising on inter-segment transactions.

**Convenience gross margin**

Non-IFRS measure. Convenience gross margin is calculated as RC profit

before interest and tax for the customers & products segment,

excluding RC profit before interest and tax for the refining & trading

business (a non-IFRS measure), and adjusting items★ (as defined above)

for the convenience & mobility business to derive underlying RC profit

before interest and tax for the convenience & mobility business;

subtracting underlying RC profit before interest and tax for the *Castrol* 

business; adding back depreciation, depletion and amortization,

production and manufacturing, distribution and administration

expenses for convenience & mobility (excluding *Castrol*); subtracting

earnings from equity-accounted entities in the convenience & mobility

business (excluding *Castrol*) and gross margin for the retail fuels, EV

charging, aviation, B2B and midstream businesses. bp believes it is

helpful because this measure may help investors to understand and

evaluate, in the same way as management, our progress against our

strategic objectives of convenience growth. The nearest IFRS measure

is RC profit before interest and tax for the customers & products

segment.

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|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Glossary** |

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**Convenience gross margin growth (%)**

Non-IFRS measure. See convenience gross margin definition.

Convenience gross margin growth at constant foreign exchange is a

non-IFRS measure. This metric, as applicable to the directors'

remuneration performance measure, requires a calculation of the

comparative convenience margin ($ million) at current period foreign

exchange rates (constant foreign exchange) and compares the current

period value with the restated comparative period value, which results

in the growth % at constant foreign exchange rates. The nearest IFRS

measure to convenience gross margin is RC profit before interest and

tax for the customer & products segment.

**Developed renewables to final investment decision (FID)**

Total generating capacity for assets developed to FID by all entities

where bp has an equity share (proportionate to equity share). If asset is

subsequently sold bp will continue to record capacity as developed to

FID. If bp equity share increases developed capacity to FID will increase

proportionately to share increase for any assets where bp held equity at

the point of FID.

**Divestment proceeds**

Disposal proceeds as per the group cash flow statement.

**Dividend yield**

Sum of the four quarterly dividends announced in respect of the year as

a percentage of the year-end share price.

**Downstream**

Downstream is the customers & products segment. It comprises our

customer-focused businesses, which include convenience and retail

fuels, EV charging, as well as *Castrol*, aviation, B2B, midstream and bp

bioenergy. It also comprises our products businesses which include

refining and oil trading.

**Dutch Title Transfer Facility**

The TTF (Title Transfer Facility) is the virtual trading point for natural gas

in the Netherlands. It is commonly used as a benchmark hub for gas

prices in Europe.

**Electric vehicle charge points / EV charge points** 

Defined as the number of connectors on a charging device, operated by

either bp or a bp joint venture, as adjusted to be reflective of bp's

accounting share of joint arrangements.

**Excess cash** 

Non-IFRS measure. It refers to the net of sources and uses of cash.

Sources of cash include net cash provided by operating activities, cash

provided from investing activities and cash receipts relating to

transactions involving non-controlling interests. Uses of cash include

lease liability payments, payments on perpetual hybrid bonds, dividends

paid, cash capital expenditure, the cash cost of share buybacks to offset

the dilution from vesting of awards under employee share schemes,

cash payments relating to transactions involving non-controlling

interests and currency translation differences relating to cash and cash

equivalents as presented on the condensed group cash flow statement.

**Fair value accounting effects** 

Non-IFRS adjustments to our IFRS profit (loss).They reflect the

difference between the way bp manages the economic exposure and

internally measures performance of certain activities and the way those

activities are measured under IFRS. Fair value accounting effects are

included within adjusting items. They relate to certain of the group's

commodity, interest rate and currency risk exposures as detailed below.

Other than as noted below, the fair value accounting effects described

are reported in both the gas & low carbon energy and customer &

products segments.

bp uses derivative instruments to manage the economic exposure

relating to inventories above normal operating requirements of crude

oil, natural gas and petroleum products. Under IFRS, these inventories

are recorded at historical cost. The related derivative instruments,

however, are required to be recorded at fair value with gains and losses

recognized in the income statement. This is because hedge accounting

is either not permitted or not followed, principally due to the

impracticality of effectiveness-testing requirements. Therefore,

measurement differences in relation to recognition of gains and losses

occur. Gains and losses on these inventories, other than net realizable

value provisions, are not recognized until the commodity is sold in a

subsequent accounting period. Gains and losses on the related

derivative commodity contracts are recognized in the income

statement, from the time the derivative commodity contract is entered

into, on a fair value basis using forward prices consistent with the

contract maturity.

bp enters into physical commodity contracts to meet certain business

requirements, such as the purchase of crude for a refinery or the sale of

bp's gas production. Under IFRS these physical contracts are treated as

derivatives and are required to be fair valued when they are managed as

part of a larger portfolio of similar transactions. Gains and losses arising

are recognized in the income statement from the time the derivative

commodity contract is entered into.

IFRS require that inventory held for trading is recorded at its fair value

using period-end spot prices, whereas any related derivative

commodity instruments are required to be recorded at values based on

forward prices consistent with the contract maturity. Depending on

market conditions, these forward prices can be either higher or lower

than spot prices, resulting in measurement differences.

bp enters into contracts for pipelines and other transportation, storage

capacity, oil and gas processing, liquefied natural gas (LNG) and certain

gas and power contracts that, under IFRS, are recorded on an accruals

basis. These contracts are risk-managed using a variety of derivative

instruments that are fair valued under IFRS. This results in measurement

differences in relation to recognition of gains and losses.

The way that bp manages the economic exposures described above,

and measures performance internally, differs from the way these

activities are measured under IFRS. bp calculates this difference for

consolidated entities by comparing the IFRS result with management's

internal measure of performance. We believe that disclosing

management's estimate of this difference provides useful information

for investors because it enables investors to see the economic effect of

these activities as a whole.

These include:

• Under management's internal measure of performance the

inventory, transportation and capacity contracts in question are

valued based on fair value using relevant forward prices prevailing at

the end of the period.

• Fair value accounting effects also include changes in the fair value of

the near-term portions of LNG contracts that fall within bp's risk

management framework. LNG contracts are not considered

derivatives, because there is insufficient market liquidity, and they

are therefore accrual accounted under IFRS. However, oil and natural

gas derivative financial instruments used to risk manage the near-

term portions of the LNG contracts are fair valued under IFRS. The

fair value accounting effect, which is reported in the gas and low

carbon energy segment, represents the change in value of LNG

contracts that are being risk managed and which is reflected in the

underlying result, but not in reported earnings. Management

believes that this gives a better representation of performance in

each period.

Furthermore, the fair values of derivative instruments used to risk

manage certain other oil, gas, power and other contracts, are deferred

to match with the underlying exposure. The commodity contracts for

business requirements are accounted for on an accruals basis.

In addition, fair value accounting effects include changes in the fair

value of derivatives entered into by the group to manage currency

exposure and interest rate risks relating to hybrid bonds to their

respective first call periods. The hybrid bonds which are classified as

equity instruments and were recorded in the balance sheet at their

issuance date at their USD equivalent issued value. Under IFRS these

equity instruments are not remeasured from period to period, and do

not qualify for application of hedge accounting. The derivative

instruments relating to the hybrid bonds, however, are required to be

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---

recorded at fair value with mark to market gains and losses recognized

in the income statement. Therefore, measurement differences in

relation to the recognition of gains and losses occur. The fair value

accounting effect, which is reported in the other businesses &

corporate segment, eliminates the fair value gains and losses of these

derivative financial instruments that are recognized in the income

statement. We believe that this gives a better representation of

performance, by more appropriately reflecting the economic effect of

these risk management activities, in each period.

**Finance debt ratio**

Finance debt ratio is defined as the ratio of finance debt to the total of

finance debt plus total equity.

**Gearing**

See net debt and gearing below.

**Gearing including leases**

See net debt including leases and gearing including leases below.

**Green hydrogen**

Hydrogen produced by electrolysis of water using renewable power.

**Hydrocarbons**

Liquids and natural gas. Natural gas is converted to oil equivalent at

5.8 billion cubic feet = 1 million barrels.

**Inorganic capital expenditure**

A subset of capital expenditure on a cash basis and a non-IFRS measure.

Inorganic capital expenditure comprises consideration in business

combinations and certain other significant investments made by the

group. It is reported on a cash basis. bp believes that this measure

provides useful information as it allows investors to understand how

bp's management invests funds in projects which expand the group's

activities through acquisition. The nearest equivalent measure on an

IFRS basis is capital expenditure on a cash basis. Further information

and a reconciliation to IFRS information is provided on page **<u>[335](#i70cb1abed366405bb4de86a8f38af0b7_5993)</u>**.

**Inventory holding gains and losses**

Inventory holding gains and losses are non-IFRS adjustments to our

IFRS profit (loss) and represent:

• The difference between the cost of sales calculated using the

replacement cost of inventory and the cost of sales calculated on

the first-in first-out (FIFO) method after adjusting for any changes in

provisions where the net realizable value of the inventory is lower

than its cost. Under the FIFO method, which we use for IFRS

reporting of inventories other than for trading inventories, the cost

of inventory charged to the income statement is based on its

historical cost of purchase or manufacture, rather than its

replacement cost. In volatile energy markets, this can have a

significant distorting effect on reported income. The amounts

disclosed as inventory holding gains and losses represent the

difference between the charge to the income statement for

inventory on a FIFO basis (after adjusting for any related movements

in net realizable value provisions) and the charge that would have

arisen based on the replacement cost of inventory. For this purpose,

the replacement cost of inventory is calculated using data from each

operation's production and manufacturing system, either on a

monthly basis, or separately for each transaction where the system

allows this approach.

• An adjustment relating to certain trading inventories that are not

price risk managed which relate to a minimum inventory volume that

is required to be held to maintain underlying business activities. This

adjustment represents the movement in fair value of the inventories

due to prices, on a grade-by-grade basis, during the period. This is

calculated from each operation's inventory management system on

a monthly basis using the discrete monthly movement in market

prices for these inventories.

The amounts disclosed are not separately reflected in the financial

statements as a gain or loss. No adjustment is made in respect of the

cost of inventories held as part of a trading position and certain other

temporary inventory positions that are price risk-managed. See

Replacement cost (RC) profit or loss definition below.

**Joint arrangement**

An arrangement in which two or more parties have joint control.

**Joint control**

Contractually agreed sharing of control over an arrangement, which

exists only when decisions about the relevant activities require the

unanimous consent of the parties sharing control.

**Joint operation**

A joint arrangement whereby the parties that have joint control of the

arrangement have rights to the assets, and obligations for the liabilities,

relating to the arrangement.

**Joint venture**

A joint arrangement whereby the parties that have joint control of the

arrangement have rights to the net assets of the arrangement.

**Liquids**

Comprises crude oil, condensate and natural gas liquids. For the oil

production & operations segment, it also includes bitumen.

**LNG portfolio**

LNG portfolio refers to bp group's LNG equity production plus

additional long-term merchant LNG volumes.

**LNG train**

An LNG train is a processing facility used to liquefy and purify natural

gas in the formation of LNG.

**Major projects**

Have a bp net investment of at least $250 million, or are considered to

be of strategic importance to bp or of a high degree of complexity.

**Modified free cash flow** 

A non-IFRS measure. It is defined as operating cash flow less: (1) net

cash used in investing activities as presented in the group cash flow

statement; and (2) lease liability payments included in financing

activities and adjusting for receipts relating to transactions involving

non-controlling interests reported within financing activities in the

group cash flow statement and movements in lease creditor.

**Net debt and gearing**

Non-IFRS measures. Net debt is calculated as finance debt, as shown in

the balance sheet, plus the fair value of associated derivative financial

instruments that are used to hedge foreign currency exchange and

interest rate risks relating to finance debt, for which hedge accounting

is applied, less cash and cash equivalents. Net debt does not include

accrued interest, which is reported within other receivables and other

payables on the balance sheet and for which the associated cash flows

are presented as operating cash flows in the group cash flow

statement. Gearing is defined as the ratio of net debt to the total of net

debt plus total equity. bp believes these measures provide useful

information to investors. Net debt enables investors to see the

economic effect of finance debt, related hedges and cash and cash

equivalents in total. Gearing enables investors to see how significant

net debt is relative to total equity. The derivatives are reported on the

balance sheet within the headings 'Derivative financial instruments'. See

Financial statements – Note 27 for information on finance debt, which is

the nearest equivalent measure to net debt on an IFRS basis. The

nearest equivalent IFRS measure to gearing on an IFRS basis is finance

debt ratio.

We are unable to present reconciliations of forward-looking information

for net debt or gearing to finance debt and total equity, because

without unreasonable efforts, we are unable to forecast accurately

certain adjusting items required to present a meaningful comparable

IFRS forward-looking financial measure. These items include fair value

asset (liability) of hedges related to finance debt and cash and cash

equivalents, that are difficult to predict in advance in order to include in

an IFRS estimate.

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| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Glossary** |

---

**Net debt including leases and gearing including leases**

Non-IFRS measures. Net debt including leases is calculated as net debt

plus lease liabilities, less the net amount of partner receivables and

payables relating to leases entered into on behalf of joint operations.

Gearing including leases is defined as the ratio of net debt including

leases to the total of net debt including leases plus total equity. bp

believes these measures provide useful information to investors as they

enable investors to understand the impact of the group's lease portfolio

on net debt and gearing. See Financial statements – Note 27 for

information on finance debt, which is the nearest equivalent measure to

net debt including leases on an IFRS basis. The nearest equivalent IFRS

measure to gearing including leases on an IFRS basis is finance debt

ratio. A reconciliation to IFRS information is provided on page **<u>[337](#i70cb1abed366405bb4de86a8f38af0b7_21551)</u>**.

**Operating cash flow**

Net cash provided by (used in) operating activities as stated in the

group cash flow statement. When used in the context of a segment

rather than the group, the terms refer to the segment's share thereof.

**Operating management system (OMS)**

bp's OMS helps us manage risks in our operating activities by setting

out bp's principles for good operating practice. It brings together bp

requirements on health, safety, security, the environment, social

responsibility and operational reliability, as well as related issues, such

as maintenance, contractor relations and organizational learning, into a

common management system.

**Organic capital expenditure**

Non-IFRS measure. Organic capital expenditure comprises capital

expenditure on a cash basis less inorganic capital expenditure. bp

believes that this measure provides useful information as it allows

investors to understand how bp's management invests funds in

developing and maintaining the group's assets. The nearest equivalent

measure on an IFRS basis is capital expenditure on a cash basis. An

analysis of organic capital expenditure by segment and region, and a

reconciliation to IFRS information is provided on page **<u>[335](#i70cb1abed366405bb4de86a8f38af0b7_5993)</u>**.

We are unable to present reconciliations of forward-looking information

for organic capital expenditure to total cash capital expenditure,

because without unreasonable efforts, we are unable to forecast

accurately the adjusting item, inorganic capital expenditure, that is

difficult to predict in advance in order to derive the nearest IFRS

estimate.

**Plant reliability**

This metric, as applicable to the directors' remuneration performance

measure, see Upstream / hydrocarbon plant reliability.

**Production-sharing agreement/contract (PSA/PSC)** 

An arrangement through which an oil and gas company bears the risks

and costs of exploration, development and production. In return, if

exploration is successful, the oil company receives entitlement to

variable physical volumes of hydrocarbons, representing recovery of

the costs incurred and a stipulated share of the production remaining

after such cost recovery.

**Proved reserves replacement ratio**

The extent to which the year's production has been replaced by proved

reserves added to our reserve base. The ratio is expressed in oil-

equivalent terms and includes changes resulting from discoveries,

improved recovery and extensions and revisions to previous estimates,

but excludes changes resulting from acquisitions and disposals.

**Realizations**

Realizations are the result of dividing revenue generated from

hydrocarbon sales, excluding revenue generated from purchases made

for resale and royalty volumes, by revenue generating hydrocarbon

production volumes. Revenue generating hydrocarbon production

reflects the bp share of production as adjusted for any production

which does not generate revenue. Adjustments may include losses due

to shrinkage, amounts consumed during processing, and contractual or

regulatory host committed volumes such as royalties. For the gas & low

carbon energy and oil production & operations segments, realizations

include transfers between businesses.

**Refining availability**

Represents Solomon Associates' operational availability for bp-

operated refineries, which is defined as the percentage of the year that

a unit is available for processing after subtracting the annualized time

lost due to turnaround activity and all mechanical, process and

regulatory downtime.

**Refining indicator margin (RIM)**

A simple indicator of the weighted average of bp's crude slate and

product yield as deemed representative for each refinery. Actual

margins realized by bp may vary due to a variety of factors, including

the actual mix of a crude and product for a given quarter.

**Refining marker margin (RMM)**

The average of regional indicator margins weighted for bp's crude

refining capacity in each region. Each regional marker margin is based

on product yields and a marker crude oil deemed appropriate for the

region. The regional indicator margins may not be representative of the

margins achieved by bp in any period because of bp's particular refinery

configurations and crude and product slate.

**Renewable natural gas (RNG)**

RNG is a pipeline-quality, lower carbon fuel that is interchangeable with

traditional natural gas. It is a form of biogas and a product of

decomposing organic material at sites including landfills, farms and

wastewater treatment facilities.

**Renewables pipeline**

Renewable projects satisfying the criteria below until the point they can

be considered developed to FID:

Site-based projects that have obtained land exclusivity rights, or for

power purchase agreement based projects an offer has been made to

the counterparty, or for auction projects pre-qualification criteria have

been met, or for acquisition projects post a binding offer has been

accepted.

**Replacement cost (RC) profit or loss/RC profit or loss** 

**attributable to bp shareholders** 

Reflects the replacement cost of inventories sold in the period and is

calculated as profit or loss attributable to bp shareholders, adjusting for

inventory holding gains and losses (net of tax). RC profit or loss for the

group is not a recognized IFRS measure. bp believes this measure is

useful to illustrate to investors the fact that crude oil and product prices

can vary significantly from period to period and that the impact on our

reported result under IFRS can be significant. Inventory holding gains

and losses vary from period to period due to changes in prices as well

as changes in underlying inventory levels. In order for investors to

understand the operating performance of the group excluding the

impact of price changes on the replacement of inventories, and to make

comparisons of operating performance between reporting periods, bp's

management believes it is helpful to disclose this measure. The nearest

equivalent measure on an IFRS basis is profit or loss attributable to bp

shareholders. See Financial statements – Note 5. A reconciliation to IFRS

information is provided on page **<u>[24](#i8e6e3a69d0f94d719097c18a300de66c_0-0-1-5-965654)</u>**.

**Reported recordable injury frequency**

Reported recordable injury frequency measures the number of

reported work-related employee and contractor incidents that result in

a fatality or injury per 200,000 hours worked. This represents reported

incidents occurring within bp's operational HSSE reporting boundary.

That boundary includes bp's own operated facilities and certain other

locations or situations.

**Retail fuel volumes** 

Retail fuel volumes are fuel volumes sold from bp branded retail sites

and includes gasoline, diesel, LPG sales and other fuel sales (e.g. ad blue

sold at the pump). Does not include fuels volume for equity accounted

entities.

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---

**Retail sites**

Retail sites include sites operated by dealers, jobbers, franchisees or

brand licensees or joint venture (JV) partners, under the bp brand. These

may move to and from the bp brand as their fuel supply agreement or

brand licence agreement expires and are renegotiated in the normal

course of business.

Retail sites are primarily branded *BP*, Arco, *Amoco*, *Aral*, *Thorntons*, and

TravelCenters of America and also includes sites in India through our

Jio-bp JV.

**Return on average capital employed (ROACE)**

Non-IFRS measure. ROACE is defined as underlying replacement cost

profit, which is defined as profit or loss attributable to bp shareholders

adjusted for inventory holding gains and losses, adjusting items and

related taxation on inventory holding gains and losses and adjusting

items total taxation, after adding back non-controlling interest and

interest expense net of tax, divided by the average of the beginning and

ending balances of total equity plus finance debt, excluding cash and

cash equivalents and goodwill as presented on the group balance sheet

over the periods presented. Interest expense before tax is finance costs

as presented on the group income statement, excluding lease interest,

the unwinding of the discount on provisions and other payables and

other adjusting items reported in finance costs. bp believes it is helpful

to disclose the ROACE because this measure gives an indication of the

company's capital efficiency. The nearest IFRS measures of the

numerator and denominator are profit or loss for the period attributable

to bp shareholders and total equity respectively. The reconciliation of

the numerator and denominator is provided on page **<u>[385](#i8d8183dbb7704a419cda8a463c63183a_7088)</u>**.

We are unable to present forward-looking information of the nearest

IFRS measures of the numerator and denominator for ROACE, because

without unreasonable efforts, we are unable to forecast accurately

certain adjusting items required to calculate a meaningful comparable

IFRS forward-looking financial measure. These items include inventory

holding gains or losses and interest net of tax, that are difficult to

predict in advance in order to include in an IFRS estimate.

**Return on average capital employed (ROACE) on a price** 

**adjusted basis**

Non-IFRS measure. ROACE on a price adjusted basis is adjusted ROACE

(defined above), calculated assuming a hypothetical price environment

of $70/bbl Brent, $4/mmBtu Henry Hub, and a $10.3/bbl refining

indicator margin (all 2024 real) and assumptions about the impact of

these marker prices on underlying replacement cost profit before tax.

bp believes ROACE on a price adjusted basis helps investors to assess

the company's capital efficiency and underlying performance on a

normalized price environment basis. The nearest IFRS measures of the

numerator and denominator are profit or loss for the period attributable

to bp shareholders and total equity respectively.

**Strategic convenience sites**

Strategic convenience sites are retail sites, within the bp portfolio,

which sell bp-supplied vehicle energy (e.g. *BP*, *Aral*, Arco, *Amoco*,

*Thorntons*, *bp pulse*, TravelCenters of America and *PETRO*) and either

carry one of the strategic convenience brands (e.g. M&S, Rewe to Go) or

a differentiated bp-controlled convenience offer. To be considered a

strategic convenience site, the convenience offer should have a

demonstrable level of differentiation in the market in which it operates.

Strategic convenience site count includes sites under a pilot phase.

**Structural cost reduction**

Non-IFRS measure. It is calculated as decreases in underlying operating

expenditure★ (as defined below) as a result of operational efficiencies,

divestments, workforce reductions and other cost saving measures that

are expected to be sustainable compared with 2023 levels. The total

change between periods in underlying operating expenditure will

reflect both structural cost reductions and other changes in spend,

including market factors, such as inflation and foreign exchange

impacts, as well as changes in activity levels and costs associated with

new operations. Estimates of cumulative annual structural cost

reduction may be revised depending on whether cost reductions

realized in prior periods are determined to be sustainable compared

with 2023 levels. Structural cost reductions are stewarded internally to

support management's oversight of spending over time.

bp believes this performance measure is useful in demonstrating how

management drives cost discipline across the entire organization,

simplifying our processes and portfolio and streamlining the way we

work. The nearest IFRS measures are production and manufacturing

expenses and distributions and administration expenses. A

reconciliation of production and manufacturing expenses plus

distribution and administration expenses to underlying operating

expenditure is provided on page **<u>[386](#i8d8183dbb7704a419cda8a463c63183a_7146)</u>**.

We are unable to present forward-looking information of the nearest

IFRS measures, because without unreasonable efforts, we are unable to

forecast accurately certain adjusting items required to calculate a

meaningful comparable IFRS forward-looking financial measure.

**Subsidiary**

An entity that is controlled by the bp group. Control of an investee

exists when an investor is exposed, or has rights, to variable returns

from its involvement with the investee and has the ability to affect

those returns through its power over the investee.

**Technical service contract (TSC)** 

Technical service contract is an arrangement through which an oil and

gas company bears the risks and costs of exploration, development and

production. In return, the oil and gas company receives entitlement to

variable physical volumes of hydrocarbons, representing recovery of

the costs incurred and a profit margin which reflects incremental

production added to the oilfield.

**Tier 1 and tier 2 process safety events**

Tier 1 events are losses of primary containment from a process of

greatest consequence – such as causing harm to a member of the

workforce, damage to equipment from a fire or explosion, a community

impact or exceeding defined quantities. Tier 2 events are those of lesser

consequence. These represent reported incidents occurring within bp's

operational HSSE reporting boundary. That boundary includes bp's own

operated facilities and certain other locations or situations.

**Tight oil and gas**

Natural oil and gas reservoirs locked in hard sandstone rocks with low

permeability, making the underground formation extremely tight.

**Transition businesses**

Business activities (including development, production/manufacture/

generation and marketing, distribution and trading) associated with

products and services that support energy transition, including in the

areas of biogas, biofuels, EV charging, renewable power generation,

hydrogen and carbon capture.

**Transition Scenario Catalogue**

A catalogue of third-party transition scenarios, compiled by bp to

support TCFD transition resilience analysis and to help inform

impairment sensitivity analysis. This catalogue takes as its start point

data from the most recent (at the time of preparation) World Business

Council for Sustainable Development (WBCSD) Energy Climate Scenario

Catalogue Version 3.0, published May 2024, which we have updated for

amended IEA, NGFS and UN PRI IPR data where these source providers

have since published updated scenarios for key transition variables or

have 'retired' older scenarios. For further details see page <u>[53](#i37f5f0f2ee4e45afa2448273fb7b6bb9_1-0-1-6-781302)</u>.

**UK National Balancing Point**

A virtual trading location for sale, purchase and exchange of UK natural

gas. It is the pricing and delivery point for the Intercontinental Exchange

natural gas futures contract.

**Ultra-fast charging** 

Electric vehicle charging of greater than or equal to 150kW.

**Unconventionals**

Resources found in geographic accumulations over a large area, that

usually present additional challenges to development such as low

permeability or high viscosity. Examples include shale gas and oil,

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|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Glossary** |

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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 **<u>[384](#i8d8183dbb7704a419cda8a463c63183a_7148)</u>**.

**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 **<u>[386](#i8d8183dbb7704a419cda8a463c63183a_7146)</u>**.

**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 <u>[336](#i70cb1abed366405bb4de86a8f38af0b7_5994)</u> 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 <u>[24](#i0dd2ee81aac04f8c9c97c86197f0c6df_61)</u> for the group and pages <u>[28](#i6da98af5df9a465582ca9b70b3e52802_95700)</u><u>-</u><u>[36](#i7f5a22ab96474e61ab4a1c459f7c7c41_5723)</u> 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 **<u>[384](#i8d8183dbb7704a419cda8a463c63183a_7149)</u>**.

**Upstream**

Upstream includes oil and natural gas field development and

production within the gas & low carbon energy and oil production &

operations segments. References to upstream exclude Rosneft.

**Upstream / hydrocarbon plant reliability**

bp-operated upstream plant reliability is calculated taking 100% less the

ratio of total unplanned plant deferrals divided by installed production

capacity, excluding non-operated assets and bpx energy. Unplanned

plant deferrals are associated with the topside plant and where

applicable the subsea equipment (excluding wells and reservoirs).

Unplanned plant deferrals include breakdowns, which does not include

Gulf of America weather-related downtime.

**Upstream unit production costs**

Upstream unit production costs are calculated as production costs

divided by units of production. Production costs do not include ad

valorem and severance taxes. Units of production are barrels for liquids

and thousands of cubic feet for gas. Amounts disclosed are for bp

subsidiaries only and do not include bp's share of equity-accounted

entities.

**West Texas Intermediate (WTI)** 

A light sweet crude oil, priced at Cushing, Oklahoma, which serves as a

benchmark price for purchases of oil in the US.

**Working capital** 

Movements in inventories and other current and non-current assets and

liabilities as stated in the group cash flow statement.

**Trade marks**

Trade marks of the bp group appear throughout this report. They

include:

*Amoco, Aral, Aral pulse, BP, bp pulse, Castrol, Gigahub, PETRO, TA,* 

*Thorntons, epic goods and earnify*

Trade marks:

REWE to Go – a registered trade mark of REWE

---

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|:---|:---|:---|
| 384 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

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**Non-IFRS measures reconciliations**

**Reconciliation of basic earnings per ordinary share to underlying RC profit**★ **per ordinary share**★

---

| | | | |
|:---|:---|:---|:---|
|  | Per ordinary share – cents | Per ordinary share – cents | Per ordinary share – cents |
|  | **2025** | 2024 | 2023 |
| Profit (loss) for the year attributable to bp shareholders | **0.35** | 2.38 | 87.78 |
| Inventory holding (gains) losses★, before tax | **8.67** | 2.98 | 7.12 |
| Taxation charge (credit) on inventory holding gains and losses | **(2.15)** | (0.73) | (1.69) |
|  | **6.87** | 4.63 | 93.21 |
| Net (favourable) adverse impact of adjusting items★, before tax | **37.76** | 56.95 | (6.58) |
| Taxation charge (credit) on adjusting items | **3.39** | (7.18) | (6.94) |
| Underlying RC profit for the year | **48.02** | 54.40 | 79.69 |

---

**Reconciliation of basic earnings per ADS to underlying RC profit per ADS**★

---

| | | | |
|:---|:---|:---|:---|
|  | Per ADS – dollars | Per ADS – dollars | Per ADS – dollars |
|  | **2025** | 2024 | 2023 |
| Profit (loss) for the year attributable to bp shareholders | **0.02** | 0.14 | 5.27 |
| Inventory holding (gains) losses, before tax | **0.52** | 0.18 | 0.43 |
| Taxation charge (credit) on inventory holding gains and losses | **(0.13)** | (0.04) | (0.11) |
|  | **0.41** | 0.28 | 5.59 |
| Net (favourable) adverse impact of adjusting items, before tax | **2.27** | 3.42 | (0.40) |
| Taxation charge (credit) on adjusting items | **0.20** | (0.44) | (0.41) |
| Underlying RC profit for the year | **2.88** | 3.26 | 4.78 |

---

**Reconciliation of effective tax rate (ETR) to underlying ETR**★

**Taxation (charge) credit**

---

| | | | |
|:---|:---|:---|:---|
|  | $ million | $ million | $ million |
|  | **2025** | 2024 | 2023 |
| Taxation on profit or loss before taxation for the year | **(6451)** | (5553) | (7869) |
| Adjusted for taxation on inventory holding gains and losses | **334** | 119 | 292 |
| Adjusted for adjusting items total taxation | **(528)** | 1179 | 1204 |
| Taxation on an underlying RC basis | **(6257)** | (6851) | (9365) |

---

**Effective tax rate**

---

| | | | |
|:---|:---|:---|:---|
|  | % | % | % |
|  | **2025** | 2024 | 2023 |
| ETR on profit or loss before taxation for the year | **83** | 82 | 33 |
| Adjusted for inventory holding gains and losses | **(8)** | (4) |  |
| Adjusted for adjusting items total taxation | **(33)** | (37) | 6 |
| Underlying ETR | **42** | 41 | 39 |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 385 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Non-IFRS measures reconciliations** |

---

**Return on average capital employed (ROACE)**★

---

| | | |
|:---|:---|:---|
|  |  | $ million |
|  | **2025** | 2024 |
| Profit for the year attributable to bp shareholders | **55** | 381 |
| Inventory holding (gains) losses, before tax | **1351** | 488 |
| Taxation charge (credit) on inventory holding gains and losses | **(334)** | (119) |
| Adjusting items, before tax | **5885** | 9344 |
| Taxation charge (credit) on adjusting items | **528** | (1179) |
| Underlying RC profit | **7485** | 8915 |
| Interest expense<sup>a</sup> | **3339** | 3113 |
| Taxation on interest expense | **(539)** | (404) |
| Non-controlling interests (NCI) | **1240** | 848 |
|  | **11525** | 12472 |
| Total equity | **74000** | 78318 |
| Finance debt | **57958** | 59547 |
| Capital employed | **131958** | 137865 |
| Less: Goodwill<sup>b</sup> | **13056** | 14888 |
| Cash and cash equivalents | **36556** | 39204 |
|  | **82346** | 83773 |
| Average capital employed excluding goodwill and cash and cash equivalents | **83059** | 87859 |
| Profit for the year attributable to bp shareholders divided by total equity | **0.1%** | 0.5% |
| ROACE | **13.9%** | 14.2% |

---

aFinance costs, as reported in the Group income statement, were $5,106 million (2024 $4,683 million). Interest expense is finance costs excluding lease interest of $672 million (2024 $441 million),

unwinding of discount on provisions and other payables of $1,147 million (2024 $1,013 million) and other adjusting items related to finance costs $52 million gain (2024 $116 million expense).

b2025 includes the amount of goodwill classified as held for sale at 31 December 2025.

---

| | | |
|:---|:---|:---|
| 386 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Underlying operating expenditure**★ **reconciliation** 

---

| | | | |
|:---|:---|:---|:---|
|  |  | $ million | $ million |
|  | **2025** | 2024 | 2023 |
| **From group income statement** |  |  |  |
| Production and manufacturing expenses | **25646** | 26584 | 25044 |
| Distribution and administration expenses | **17494** | 16417 | 16772 |
|  | **43140** | 43001 | 41816 |
| **Less certain variable costs:** |  |  |  |
| Transportation and shipping costs<sup>a</sup> | **10456** | 10516 | 9650 |
| Environmental costs<sup>a</sup> | **5713** | 3987 | 4271 |
| Marketing and distribution costs | **1692** | 1882 | 2430 |
| Commission, storage and handling costs | **1594** | 1519 | 1633 |
| Other variable costs and non-cash costs | **1819** | 1495 | 743 |
| Certain variable costs | **21274** | 19399 | 18727 |
| **Adjusted operating expenditure**★ | **21866** | 23602 | 23089 |
| **Less certain adjusting items**★**:** |  |  |  |
| Gulf of America oil spill | **31** | 51 | 57 |
| Environmental and related provisions | **656** | 181 | 647 |
| Restructuring, integration and rationalization costs | **520** | 222 | (37) |
| Fair value accounting effects – derivative instruments relating to the hybrid bonds | **(1157)** | 221 | (630) |
| Other certain adjusting items | **(71)** | 601 | 419 |
| Certain adjusting items | **(21)** | 1276 | 456 |
| **Underlying operating expenditure** | **21887** | 22326 | 22633 |
| **Underlying operating expenditure reduction relative to 2023** | **(439)** | (307) |  |
| Increase/(decrease) in underlying operating expenditure due to inflation, exchange, portfolio changes <br>and organic growth<br>| **1572** | 443 |  |
| Structural cost reduction★ | **(2011)** | (750) |  |

---

aComparative periods have been restated for a reclassification in costs from transportation and shipping to environmental.

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 387 |

---

---

| |
|:---|
| ![NavigtionTabCornerV1.jpg](bp-20251231_g5.jpg) |
| **Non-IFRS measures reconciliations** |

---

**Adjusted EBITDA**★

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| Profit (loss) for the period | **1295** | 1229 | 15880 |
| Finance costs | **5106** | 4683 | 3840 |
| Net finance (income) expense relating to pensions and other post-employment benefits | **(210)** | (168) | (241) |
| Taxation | **6451** | 5553 | 7869 |
| Profit before interest and tax | **12642** | 11297 | 27348 |
| Inventory holding (gains) losses, before tax | **1351** | 488 | 1236 |
|  | **13993** | 11785 | 28584 |
| Net (favourable) adverse impact of adjusting items, before interest and tax | **5457** | 8839 | (1548) |
|  | **19450** | 20624 | 27036 |
| Add back: Depreciation, depletion and amortization | **17822** | 16622 | 15928 |
| Exploration expenditure written off | **343** | 766 | 746 |
| Adjusted EBITDA | **37615** | 38012 | 43710 |

---

---

| | | |
|:---|:---|:---|
| 388 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Reconciliation of RC profit before interest and tax for gas & low carbon energy and oil production & operations to** 

**adjusted EBITDA**

---

| | | | |
|:---|:---|:---|:---|
|  |  |  | $ million |
|  | **2025** | 2024 | 2023 |
| **gas & low carbon energy** |  |  |  |
| RC profit before interest and tax<sup>a</sup> | **1330** | 3052 | 14080 |
| Less: Net favourable (adverse) impact of adjusting items<sup>a</sup> | **(4037)** | (3751) | 5358 |
| Underlying RC profit before interest and tax | **5367** | 6803 | 8722 |
| Add back: Depreciation, depletion and amortization | **4969** | 4835 | 5680 |
| Exploration expenditure written off | **30** | 222 | 362 |
| Adjusted EBITDA | **10366** | 11860 | 14764 |
| **oil production & operations** |  |  |  |
| RC profit before interest and tax | **8558** | 10789 | 11191 |
| Less: Net favourable (adverse) impact of adjusting items | **(856)** | (1148) | (1590) |
| Underlying RC profit before interest and tax | **9414** | 11937 | 12781 |
| Add back: Depreciation, depletion and amortization | **7719** | 6797 | 5692 |
| Exploration expenditure written off | **313** | 544 | 384 |
| Adjusted EBITDA | **17446** | 19278 | 18857 |

---

a2024 has been restated for material items to reflect the move of our Archaea Energy business from the customers & products segment to the gas & low carbon energy segment.

The Directors' report on pages <u>[72](#i0dd2ee81aac04f8c9c97c86197f0c6df_121)</u><u>-</u><u>[90](#i372e476394b943ee83d7eb667cf64e6f_331852)</u>, <u>[91](#i0dd2ee81aac04f8c9c97c86197f0c6df_187)</u> (in respect of the remuneration committee), <u>[126](#i0dd2ee81aac04f8c9c97c86197f0c6df_217)</u>, <u>[241](#i0dd2ee81aac04f8c9c97c86197f0c6df_397)</u><u>-</u><u>[268](#i289f9d686a3c4f4a9ddd036104bd90d5_3926)</u> and <u>[334](#i0dd2ee81aac04f8c9c97c86197f0c6df_475)</u><u>-</u><u>[388](#i8d8183dbb7704a419cda8a463c63183a_11278)</u> was approved by the board and

signed on its behalf by Ben J. S. Mathews, company secretary on 6 March 2026.

BP p.l.c.

Registered in England and Wales No. 102498

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 389 |

---

**Signatures**

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the

undersigned to sign this annual report on its behalf.

BP p.l.c.

(Registrant)

/s/ Ben J. S. Mathews

Company secretary

6 March 2026

---

| | | |
|:---|:---|:---|
| 390 | bp Annual Report and Form 20-F 2025 | ★ See glossary on **page <u>[375](#i0dd2ee81aac04f8c9c97c86197f0c6df_586)</u>** |

---

**Cross reference to Form 20-F** 

---

| | | | |
|:---|:---|:---|:---|
| Item 1. |  | Identity of Directors, Senior Management and Advisers | n/a |
| Item 2. |  | Offer Statistics and Expected Timetable | n/a |
| Item 3. |  | Key Information |  |
|  | A. | [Reserved] | n/a |
|  | B. | Capitalization and indebtedness | n/a |
|  | C. | Reasons for the offer and use of proceeds | n/a |
|  | D. | Risk factors | 62-66 |
| Item 4. |  | Information on the Company |  |
|  | A. | History and development of the company | 23-27, 182-184, 190, 196, 199-202, 340-346, 350-351, 368-369, 373, 391 |
|  | B. | Business overview | 6-7, 12-13, 18-35, 185-189, 340-358, 363 |
|  | C. | Organizational structure | 240, 391 |
|  | D. | Property, plants and equipment | 14-15, 28-35, 160-161, 175, 266-268, 339-352, 359 |
| Item 4A. |  | Unresolved Staff Comments |  |
| Item 5. |  | Operating and Financial Review and Prospects |  |
|  | A. | Operating results | 6-9, 12-13, 18-27, 62-66, 201, 211-212, 214-228, 338-345, 350-358 |
|  | B. | Liquidity and capital resources | 159, 196, 211-219, 338-339 |
|  | C. | Research and development, patent and licenses, etc. | 12, 189 |
|  | D. | Trend information | 6-9, 12-13, 18-27, 340-351 |
|  | E. | Critical Accounting Estimates | n/a |
| Item 6. |  | Directors, Senior Management and Employees |  |
|  | A. | Directors and senior management | 73-76 |
|  | B. | Compensation | 91-125, 205-211, 238-239 |
|  | C. | Board practices | 73-75, 84-88 |
|  | D. | Employees | 56-58, 239 |
|  | E. | Share ownership | 56-58, 91-125, 205-211, 238 |
|  | F. | Disclosure of a registrant's action to recover erroneously awarded <br>compensation<br>| n/a |
| Item 7. |  | Major Shareholders and Related Party Transactions |  |
|  | A. | Major shareholders | 367-368 |
|  | B. | Related party transactions | 199-202, 359 |
|  | C. | Interests of experts and counsel | n/a |
| Item 8. |  | Financial Information |  |
|  | A. | Consolidated Statements and Other Financial Information | 155-240, 338, 365 |
|  | B. | Significant Changes | n/a |
| Item 9. |  | The Offer and Listing |  |
|  | A. | Offer and listing details | 365  |
|  | B. | Plan of distribution | n/a |
|  | C. | Markets | 365 |
|  | D. | Selling shareholders | n/a |
|  | E. | Dilution | n/a |
|  | F. | Expenses of the issue | n/a |
| Item 10. |  | Additional Information |  |
|  | A. | Share capital | n/a |
|  | B. | Memorandum and articles of association | 368-371 |
|  | C. | Material contracts | 358 |
|  | D. | Exchange controls | 365 |
|  | E. | Taxation | 365-367 |
|  | F. | Dividends and paying agents | n/a |
|  | G. | Statements by experts | n/a |
|  | H. | Documents on display | 373 |
|  | I. | Subsidiary information | n/a |
|  | J. | Annual Report to Security Holders | n/a |
| Item 11. |  | Quantitative and Qualitative Disclosures About Market Risk | 214-219 |
| Item 12. |  | Description of Securities Other than Equity Securities |  |
|  | A. | Debt Securities | n/a |
|  | B. | Warrants and Rights | n/a |
|  | C. | Other Securities | n/a |
|  | D. | American Depositary Shares | 373 |
| Item 13. |  | Defaults, Dividend Arrearages and Delinquencies |  |
| Item 14. |  | Material Modifications to the Rights of Security Holders and Use of Proceeds |  |
| Item 15. |  | Controls and Procedures | 154, 360 |
| Item 16. |  | [Reserved] | n/a |
| Item 16A. |  | Audit committee financial expert | 84, 359 |
| Item 16B. |  | Code of Ethics | 360 |
| Item 16C. |  | Principal Accountant Fees and Services | 239, 361 |
| Item 16D. |  | Exemptions from the Listing Standards for Audit Committees | n/a |
| Item 16E. |  | Purchases of Equity Securities by the Issuer and Affiliated Purchasers | 372 |
| Item 16F. |  | Change in Registrant's Certifying Accountant | n/a |
| Item 16G. |  | Corporate Governance | 359-360 |
| Item 16H. |  | Mine Safety Disclosure | n/a |
| Item 16I. |  | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | n/a |
| Item 16J. |  | Insider Trading Policies. | 360 |
| Item 16K. |  | Cyber security | 55-56, 64, 68, 360-361 |
| Item 17. |  | Financial Statements | n/a |
| Item 18. |  | Financial Statements | 155-159 |
| Item 19. |  | Exhibits | 391 |

---

---

| | |
|:---|:---|
| bp Annual Report and Form 20-F 2025 | 391 |

---

**Information about this report**

This document constitutes the Annual Report and Accounts in

accordance with UK requirements and the Annual Report on Form 20-F

in accordance with the US Securities Exchange Act of 1934, for BP p.l.c.

for the year ended 31 December 2025. A cross reference to Form 20-F

requirements is included on page <u>[390](#i0dd2ee81aac04f8c9c97c86197f0c6df_595)</u>.

This document contains the Strategic report on the inside front cover

and pages <u>[1](#i0dd2ee81aac04f8c9c97c86197f0c6df_7)</u><u>-</u><u>[71](#if6cc4a1e1b354006ac4c1604da81c9a3_3683)</u> and the Directors' report on pages <u>[72](#i0dd2ee81aac04f8c9c97c86197f0c6df_121)</u><u>-</u><u>[90](#i372e476394b943ee83d7eb667cf64e6f_331852)</u>, <u>[91](#i0dd2ee81aac04f8c9c97c86197f0c6df_187)</u> (in part only),

<u>[126](#i0dd2ee81aac04f8c9c97c86197f0c6df_217)</u>, <u>[241](#i0dd2ee81aac04f8c9c97c86197f0c6df_397)</u><u>-</u><u>[268](#i289f9d686a3c4f4a9ddd036104bd90d5_3926)</u> and <u>[334](#i0dd2ee81aac04f8c9c97c86197f0c6df_475)</u><u>-</u><u>[388](#i8d8183dbb7704a419cda8a463c63183a_7145)</u>. 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 <u>[91](#i0dd2ee81aac04f8c9c97c86197f0c6df_187)</u><u>-</u><u>[125](#ice7ed01c803e4808b3b636ee225997b7_8758)</u>. The

consolidated financial statements of the group are on pages <u>[129](#i0dd2ee81aac04f8c9c97c86197f0c6df_232)</u><u>-</u><u>[240](#i0dd2ee81aac04f8c9c97c86197f0c6df_391)</u> 

and the corresponding reports of the auditor are on pages <u>149-</u><u>[154](#ief7b657c95eb449abf4ca6590a827970_29161)</u>.

*bp Annual Report and Form 20-F 2025* may be downloaded from

<u>bp.com/annualreport</u>. No material on the bp website, other than the

items identified as *bp Annual Report and Form 20-F 2025*, forms any

part of this document. References in this document to other documents

on the bp website, such as *bp Energy Outlook 2025*, and *bp* 

*Sustainability Report* are included as an aid to their location and are not

incorporated by reference into this document.

BP p.l.c. is the parent company of the bp group of companies. The

company was incorporated in 1909 in England and Wales and changed

its name to BP p.l.c. in 2001. Where we refer to the company, we mean

BP p.l.c. The company and each of its subsidiaries★ are separate legal

entities. Unless otherwise stated or the context otherwise requires, the

term "BP" or "bp" and terms such as "we", "us" and "our" are used in this

report for convenience to refer to one or more of the members of the

bp group instead of identifying a particular entity or entities.

Information in this document reflects 100% of the assets and operations

of the company and its subsidiaries that were consolidated at the date

or for the periods indicated, including non-controlling interests.

The company's primary share listing is the London Stock Exchange. In

the US, the company's securities are traded on the New York Stock

Exchange (NYSE) in the form of ADSs (see page <u>[365](#i0dd2ee81aac04f8c9c97c86197f0c6df_550)</u> for more details).

The term 'shareholder' in this report means, unless the context

otherwise requires, investors in the equity capital of BP p.l.c., both direct

and indirect. As the company's shares, in the form of ADSs, are listed on

the NYSE, an Annual Report on Form 20-F is filed with the SEC. Ordinary

shares are ordinary fully paid shares in BP p.l.c. of 25 cents each.

Preference shares are cumulative first preference shares and

cumulative second preference shares in BP p.l.c. of £1 each.

---

| | |
|:---|:---|
| **Registered office and** <br>**our worldwide headquarters:**<br>**BP p.l.c.**<br>1 St James's Square<br>London SW1Y 4PD<br>UK<br>Tel +44 (0)20 7496 4000<br>| **Our agent in the US:**<br>**BP America Inc.**<br>501 Westlake Park Boulevard<br>Houston, Texas 77079<br>US<br>Tel +1 281 366 2000<br>|
| **Registered in England and Wales No. 102498.**<br>**London Stock Exchange symbol 'BP.'** | **Registered in England and Wales No. 102498.**<br>**London Stock Exchange symbol 'BP.'** |

---

**Exhibits**

The following documents are filed in the Securities and Exchange

Commission (SEC) EDGAR system, as part of this Annual Report on

Form 20-F, and can be viewed on the SEC's website.

---

| | |
|:---|:---|
| [Exhibit 1](https://www.sec.gov/Archives/edgar/data/313807/000031380725000007/a31122024bpex1_bpxmemora.htm) | Memorandum and Articles of Association of <br>BP p.l.c.\*\*\*\*†<br>|
| [Exhibit 2](a31122025bpxex2descripti.htm) | Description of rights of each class of <br>securities registered under Section 12 of the <br>Securities Exchange Act of 1934†<br>|
| [Exhibit 4.1](a31122025bpex41executive.htm) | The BP Executive Directors' Incentive <br>Plan\*\*\*\*†<br>|
| [Exhibit 4.4](https://www.sec.gov/Archives/edgar/data/313807/000031380724000008/a31122023bpex44ktservice.htm) | Director's Service Agreement for K <br>Thomson\*\*\*†<br>|
| [Exhibit 4.8](a31122025bpex48_carolhow.htm) | Director's Service Agreement for C Howle† |
| [Exhibit 4.10](a31122025bpex410_rulesxs.htm) | The BP Share Award Plan 2025† |
| [Exhibit 8](#i0dd2ee81aac04f8c9c97c86197f0c6df_391) | Subsidiaries (included as Note 37 to the <br>Financial Statements)<br>|
| [Exhibit 11.1](https://www.sec.gov/Archives/edgar/data/313807/000095012310021364/u08439exv11.htm) | Code of Ethics\*† |
| [Exhibit 11.2](a31122025bpex112_bpshare.htm) | Insider trading policy and procedure\*\*\*\*† |
| [Exhibit 12](a31122025bp20-fexhibit12.htm) | Rule 13a – 14(a) Certifications† |
| [Exhibit 13](a31122025bp20-fexhibit13.htm) | Rule 13a – 14(b) Certifications#† |
| [Exhibit 15.](a31122025bp20-fexhibit151.htm)1 | Consent of Netherland, Sewell & Associates† |
| [Exhibit 15.2](a31122025bpex152_nsaiye2.htm) | Report of Netherland, Sewell & Associates† |
| [Exhibit 15.3](https://www.sec.gov/Archives/edgar/data/313807/000119312516492156/d80942dex154.htm) | Consent Decree\*\*† |
| [Exhibit 15.4](https://www.sec.gov/Archives/edgar/data/313807/000119312516492156/d80942dex155.htm) | Gulf states Settlement Agreement\*\*† |
| [Exhibit 15.5](a31122025bp20-fexhibit155.htm) | Consent of Deloitte LLP† |
| [Exhibit 17](a31122025bpex17guaranteeds.htm) | Guaranteed Securities† |
| [Exhibit 97](a31122025bpex97clawbackp.htm) | Executive Compensation Clawback <br>Policy\*\*\*\*†<br>|
| Exhibit 101 | Inline XBRL data files |
| Exhibit 104 | Cover page interactive data file (formatted as <br>Inline XBRL and contained in Exhibit 101) <br>|

---

---

| | |
|:---|:---|
| \* | Incorporated by reference to the company's Annual Report on Form 20-F <br>for the year ended 31 December 2009.<br>|
| \*\* | Incorporated by reference to the company's Annual Report on Form 20-F <br>for the year ended 31 December 2015.<br>|
| \*\*\* | Incorporated by reference to the company's Annual Report on Form 20-F <br>for the year ended 31 December 2023.<br>|
| \*\*\*\* | Incorporated by reference to the company's Annual Report on Form 20-F <br>for the year ended 31 December 2024.<br>|
| # | Furnished only. |
| † | Included only in the annual report filed in the Securities and Exchange <br>Commission EDGAR system.<br>|

---

The total amount of long-term securities of BP p.l.c. and its subsidiaries

under any one instrument does not exceed 10% of their total assets on a

consolidated basis.

The company agrees to furnish copies of any or all such instruments to

the SEC on request.

---

| | |
|:---|:---|
| 392 | bp Annual Report and Form 20-F 2025 |

---

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®, ISO 14001 and FSC® certified.

![FSC_C022913_MIX_Paper_Landscape_BlackOnWhite_r_2crHAV.jpg](bp-20251231_g202.jpg)

![BackCoverV2.jpg](bp-20251231_g203.jpg)

bp's corporate reporting

suite includes information

about our financial and

operating performance,

sustainability performance

and global energy trends

and projections.

---

| | |
|:---|:---|
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | <u>bp.com</u> |

---

**bp Annual Report and Form 20-F 2025**

Details of our financial and operating

performance in print and online.

---

| | |
|:---|:---|
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | <u>bp.com/annualreport</u> |

---

**bp Sustainability Report 2025**

Details of our sustainability

performance with additional

information online.

---

| | |
|:---|:---|
| ![ReadMoreOnlineBPGreen.gif](bp-20251231_g6.gif) | <u>bp.com/sustainability</u> |

---

**bp Energy Outlook 2025**

Provides our projections of future

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affect them out to 2040.

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**Group databook 2021-2025**

Five-year financial and operating data

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© BP p.l.c. 2025

## Ex-2

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Confidential DESCRIPTION OF SECURITIES REGISTERED UNDER SECTION 12 OF THE EXCHANGE ACT As of 31 December 2025 BP p.l.c. ("BP," the "Company," "we," "us," and "our") had the following series of securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934: Title of each class Name of each exchange on which registered American Depositary Shares New York Stock Exchange Ordinary Shares of 25c each New York Stock Exchange(\*) 3.017% Guaranteed Notes due 2027 New York Stock Exchange 3.279% Guaranteed Notes due 2027 New York Stock Exchange 3.543% Guaranteed Notes due 2027 New York Stock Exchange 3.588% Guaranteed Notes due 2027 New York Stock Exchange 5.017% Guaranteed Notes due 2027 New York Stock Exchange 3.723% Guaranteed Notes due 2028 New York Stock Exchange 3.937% Guaranteed Notes due 2028 New York Stock Exchange 4.234% Guaranteed Notes due 2028 New York Stock Exchange 4.699% Guaranteed Notes due 2029 New York Stock Exchange 4.868% Guaranteed Notes due 2029 New York Stock Exchange 4.970% Guaranteed Notes due 2029 New York Stock Exchange 1.749% Guaranteed Notes due 2030 New York Stock Exchange 3.633% Guaranteed Notes due 2030 New York Stock Exchange 2.721% Guaranteed Notes due 2032 New York Stock Exchange 4.812% Guaranteed Notes due 2033 New York Stock Exchange 4.893% Guaranteed Notes due 2033 New York Stock Exchange 4.989% Guaranteed Notes due 2034 New York Stock Exchange 5.227% Guaranteed Notes due 2034 New York Stock Exchange 3.060% Guaranteed Notes due 2041 New York Stock Exchange 2.772% Guaranteed Notes due 2050 New York Stock Exchange 3.000% Guaranteed Notes due 2050 New York Stock Exchange 3.067% Guaranteed Notes due 2050 New York Stock Exchange 2.939% Guaranteed Notes due 2051 New York Stock Exchange 3.001% Guaranteed Notes due 2052 New York Stock Exchange 3.379% Guaranteed Notes due 2061 New York Stock Exchange 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes New York Stock Exchange 6.125% Perpetual Subordinated Fixed Rate Reset Notes New York Stock Exchange 6.450% Perpetual Subordinated Fixed Rate Reset Notes New York Stock Exchange (\*) Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.

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2 Capitalized terms used but not defined herein have the meanings given to them in BP's Annual Report and Form 20-F 2025.

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3 I. ORDINARY SHARES The following description of our ordinary shares of US$0.25 each is a summary and does not purport to be complete. It is subject to and qualified in its entirety by BP's Articles of Association and by the Companies Act 2006 (the "Act") and any other applicable English law concerning companies, as amended from time to time. A copy of BP's Articles of Association is filed as Exhibit 1 to BP's Annual Report and Form 20-F 2025. A. General The number of ordinary shares outstanding at 31 December 2025, excluding treasury shares, and including certain shares that will be issuable in the future under employee share-based payment plans was 15,377,210,044. The primary market for the company's ordinary shares (trading symbol 'BP') 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, Hamburg and Dusseldorf Stock Exchanges. All of the existing issued BP ordinary shares are fully paid. BP ordinary shares are represented in certificated registered form and also in uncertificated form under "CREST". CREST is an electronic settlement system in the U.K. which enables BP ordinary shares to be evidenced and transferred electronically without use of a physical certificate. B. Dividend rights If recommended by the directors of BP, shareholders of BP 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 twelve 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 (the "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

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4 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. BP announced on 29 October 2019 and as part of all subsequent quarterly results announcements made since, that the board of directors had decided not to offer a scrip dividend alternative in respect of those quarterly dividends. 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), BP's 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. C. Voting rights BP's Articles of Association provide that voting on resolutions at a shareholders' meeting will be decided on a poll other than resolutions of a procedural nature, which may be decided on a show of hands. If voting is on a poll, every shareholder who is present in person or by proxy has one vote for every ordinary share held and two votes for every £5 in nominal amount of BP preference shares held. If voting is on a show of hands, each shareholder who is present at the meeting in person or whose duly appointed proxy is present in person will have one vote, regardless of the number of shares held, unless a poll is requested. Shareholders do not have cumulative voting rights. For the purposes of determining which persons are entitled to attend or vote at a shareholders' meeting and how many votes such persons may cast, the company may specify in the notice of the meeting a time, not more than 48 hours before the time of the meeting, by which a person who holds shares in registered form must be entered on the company's register of members in order to have the right to attend or vote at the meeting or to appoint a proxy to do so. Holders on record of ordinary shares may appoint a proxy, including a beneficial owner of those shares, to attend, speak and vote on their behalf at any shareholders' meeting, provided that a duly completed proxy form is received not less than 48 hours (or such shorter time as the directors may determine) before the time of the meeting or adjourned meeting or, where the poll is to be taken after the date of the meeting, not less than 24 hours (or such shorter time as the directors may determine) before the time of the poll. Proxies may be delivered electronically.

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5 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 of those persons voting at a meeting at which there is a quorum. A special resolution requires the affirmative vote of not less than three quarters of the persons voting 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. D. Liquidation rights; redemption provisions In the event of a liquidation of BP, any assets remaining after payment of all liabilities (including in respect of the guarantees on certain of the Notes), applicable deductions under UK law, amounts payable to the holders of BP's preference shares and amounts payable to pursuant to guarantees on hybrid securities (including the 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes, 6.125% Perpetual Subordinated Fixed Rate Reset Notes and 6.450% Perpetual Subordinated Fixed Rate Reset Notes) 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. Subject to authorization by shareholder resolution, BP may purchase its own shares in accordance with the Act. E. Pre-emption rights and new issues of shares Under Section 549 of the Act, the directors are, with certain exceptions, unable to allot equity securities without the authority of the shareholders in a general meeting. The term "equity securities" as defined in the Act includes BP ordinary shares or securities convertible into BP ordinary shares. In addition, Section 561 of the Act imposes further restrictions on the issue of equity securities (as defined in the Act, which would include BP ordinary shares or securities convertible into BP ordinary shares) which are, or are to be, paid up wholly in cash and not first offered to existing shareholders in proportion to their existing shareholdings. Holders of BP ADSs would, acting through the Depositary, be entitled to participate in any such preemptive offer. BP's Articles of Association authorize the directors to issue equity securities subject to the provisions of the Act and any resolution passed by shareholders in general meeting (such authority is sought on an annual basis). In accordance with institutional investor guidelines, the company deems it appropriate to grant authority to the directors to allot shares and other securities and to disapply pre-emption rights by way of shareholders resolutions at each AGM in place of authority granted by virtue of the company's Articles of Association. At the AGM on 17 April 2025, authorization was given to the directors to allot shares in the company and to grant rights to subscribe for, or to convert any security into, shares in the company up to an aggregate nominal amount as if section 561(1) of the Act (providing for pre-emption rights for the shareholders of a

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6 company in respect of allotments by such company of its equity securities) did not apply. The resolutions dis-applying pre-emption rights comply with institutional shareholder guidance and in particular the Statement of Principles on Disapplying Pre-Emption Rights most recently published by the Pre-Emption Group. These authorities were given for the period until the next AGM in 2026 or 17 July 2026, whichever is the earlier. These authorities are renewed annually at the AGM. F. 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. G. 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. H. 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 UK economic sanctions or those sanctions adopted by the UK government which implement resolutions of the Security Council of the United Nations. I. Transfer of Shares Except as described in this paragraph, the Articles of Association do not restrict the transferability of BP ordinary shares. BP ordinary shares may be transferred by an instrument in any usual form or in any other form acceptable to the directors. The directors may refuse to register a transfer:

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7 • if it is of shares which are not fully paid; or • if it is in favor of more than four persons jointly BP may not refuse to register transfers of BP ordinary shares if it would prevent dealings in the shares on the London Stock Exchange from taking place on an open and proper basis. J. 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. There are no provisions in BP's Articles of Association whereby persons acquiring, holding or disposing of a certain percentage of BP's shares are required to make disclosure of their ownership percentage, although there are such requirements under Part 6 of the Financial Services and Markets Act 2000 and Rule 5 of the Disclosure Guidance and Transparency Rules made by the Financial Conduct Authority (successor to the UK Financial Services Authority). These requirements impose a statutory obligation on a person to notify BP and the Financial Conduct Authority of the percentage of the voting rights in BP such person directly or indirectly holds or controls, or has rights over, through his direct or indirect holding of certain financial instruments, if the percentage of those voting rights: • reaches, exceeds or falls below 3% and/or any subsequent whole percentage figure as a result of an acquisition or disposal of shares or financial instruments; or • reaches, exceeds or falls below any such threshold as a result of any change in the breakdown or number of voting rights attached to shares in BP. The Disclosure Guidance and Transparency Rules set out in detail the circumstances in which an obligation of disclosure will arise, as well as certain exemptions from those obligations for specified persons. Under section 793 of the Act, BP may, by notice in writing, require a person that BP knows or has reasonable cause to believe is or was during the three years preceding the date of notice interested in BP's shares to indicate whether or not that is the case and, if that person does or did hold an interest in BP's shares, to provide certain information as set out in that Act. Article 19 of the EU Market Abuse Regulation (2014/596) as it forms part of domestic UK law by virtue of the European Union (Withdrawal) Act 2018 further requires persons discharging managerial responsibilities within BP (and their persons closely associated) to notify BP of transactions conducted on their own account in BP shares or derivatives or certain financial instruments relating to BP shares. The City Code on Takeovers and Mergers also imposes strict disclosure requirements with regard to dealings in the securities of an offeror or offeree company on all parties to a takeover and also on their respective associates during the course of an offer period. K. Company records and service of notice

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8 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.

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9 II. AMERICAN DEPOSITARY SHARES A. General The ordinary shares of BP may be issued in the form of American Depositary Shares (ADSs). Each ADS represents six ordinary shares. ADSs are listed on the NYSE. ADSs are evidenced by American depositary receipts (ADRs), which may be issued in either certificated or book entry form. JPMorgan Chase Bank, N.A. is the depositary (the "Depositary") and transfer agent. Each ADS represents an ownership interest in six ordinary shares deposited with the custodian, as agent of the depositary, under the Second Amended and Restated Deposit Agreement, dated 6 December 2013, as amended (the Deposit Agreement). The Depositary's principal office is presently located at 383 Madison Avenue, Floor 11, New York, NY, 10179, US. You may hold ADSs either directly or indirectly through your broker or other financial institution. If you hold ADSs directly, by having an ADS registered in your name on the books of the depositary, you are an ADR holder. If you hold the ADSs through your broker or financial institution nominee, you must rely on the procedures of such broker or financial institution to assert the rights of an ADR holder described in this section. You should consult with your broker or financial institution to find out what those procedures are. The following is a summary of the material terms of the Deposit Agreement. Because it is a summary, it does not contain all the information that may be important to you. For more complete information, you should read the entire form of Deposit Agreement and the form of ADR, which contain the terms of the ADSs. Please refer to Exhibit 99.(A) filed on a post-effective amendment to Form F-6 (File No. 333- 144817) with the SEC on 12 June 2013, Exhibit 99.(a)(2) filed on a post-effective amendment to Form F- 6 (File No. 333-144817) with the SEC on 9 February 2017 and Exhibit 99.(a)(3) filed on a post-effective amendment to Form F-6 (File No. 333-144817) with the SEC on 27 March 2020. Copies of the Deposit Agreement are also available for inspection at the offices of the Depositary. B. Voting Procedure Record holders of BP ADSs are also entitled to attend, speak and vote at any shareholders' meeting of BP by the appointment by the Depositary 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. If ADSs are held indirectly through a brokerage account or otherwise in street name, the holder must rely on the procedures established by his or her broker or financial institution to assert the rights of ADS holders described in this section. In the event a situation arises where the aggregate number of votes to be cast by or on behalf of the Depositary at a BP shareholder meeting exceeds the total number of ordinary shares registered in the name of the Depositary or its custodian as of the record date for ordinary shares, the BP Articles of Association provide an adjustment mechanism intended to ensure that the Depositary may only vote those shares which are registered in its name at the record date for ordinary shares. The adjustment may be made on a pro rata basis or may be made with respect to specific votes. In any circumstance where the Depositary is unable to make an adjustment, the chairman may make any adjustment of the votes to be cast by or on behalf of the Depositary on a pro rata basis or in such other manner as may have been prescribed by regulations or procedures established by the directors.

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10 Except in respect of an adjustment of votes as described in the preceding paragraph, if any question arises as to whether an ADS holder, as proxy for the Depositary, or the proxy of an ADS holder, has been validly appointed to vote (or exercise any other right), according to BP's Articles of Association the question shall be determined: • by the chairman of the meeting or in accordance with procedures established by the board of directors, if such question arises at or in relation to a general shareholders meeting; or • by the board of directors at their discretion, if such question arises in any other circumstances. The Depositary or BP will notify direct ADS holders of the upcoming meeting and arrange to distribute certain materials to such holders. The materials will: • contain such information as is contained in the meeting's notice or in the solicitation materials; and • explain how ADS holders may instruct the Depositary to vote the ordinary shares or other deposited securities (if any) underlying ADSs if the ADS holder appoints the Depositary as proxy, or how an ADS holder may appoint a proxy other than the Depositary. ADS holders may also vote directly as an ordinary shareholder by withdrawing from the Depositary at least six of the BP ordinary shares underlying one of their ADSs. C. Share Dividends and Other Distributions The Depositary will pay to ADS holders the cash dividends or other distributions it or the custodian receives on ordinary shares or any other deposited securities, after deducting any applicable fees and expenses. The Depositary may also, pursuant to BP's Articles of Association, request BP to pay to the ADS holder directly the cash dividends or other distributions, if the ADSs are held directly. ADS holders will receive those distributions in proportion to the number or of ordinary shares represented by their ADSs. ADS holders will generally receive cash dividends payable on ordinary shares or any other deposited securities in U.S. dollars. To the extent that BP pays any cash dividend other than in U.S. dollars, the Depositary will convert such dividend into U.S. dollars and distribute the amount received in U.S. dollars except where the Depositary determines that in its judgment any foreign currency received by it cannot be converted on a reasonable basis into U.S. dollars transferable in the U.S. or if any governmental approval for payment in U.S. dollars is required and cannot be obtained with a reasonable cost or within a reasonable time period. In that circumstance the Deposit Agreement allows the Depositary to distribute, subject to applicable laws and regulations, foreign currency only to those ADS holders who are entitled to receive payment in foreign currency. It will hold the foreign currency it cannot convert for the account of ADS holders who have not been paid. It will not invest the foreign currency and it will not be liable for any interest. Before making a distribution the Depositary deducts any withholding taxes. The Depositary will distribute only whole U.S. dollars and cents. Fractional cents will be withheld without liability and dealt with by the Depositary in accordance with its then current practices. If the exchange rates fluctuate during a time when the Depositary cannot convert the foreign currency, holders may lose some or all of the value of the distribution depending on the extent of such currency fluctuation. The Depositary may distribute new ADSs representing any shares BP distributes as a dividend or free distribution, if BP requests it to make this distribution. The Depositary may issue fractional ADSs only in connection with such share distributions. Fractional ADSs may only be issued through the direct registration

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11 system maintained by the Depositary. If the Depositary does not distribute additional ADSs, each ADS will also represent the proportion of the new shares allocable to such ADS. If BP offers holders of its securities any rights to subscribe for additional shares or any other rights, BP may make these rights available to holders of ADSs by means of warrants or otherwise, if lawful and feasible. If it is not lawful and not feasible and it is practical to sell the rights, the Depositary may in its discretion sell the rights and distribute the proceeds to ADS holders in the same way as it does with cash. The Depositary may allow rights that are not distributed or sold to lapse. In that case, holders of ADSs will receive no value for them. The Deposit Agreement provides that in respect of any other distributions the Depositary will make distributions to ADS holders by any means the Depositary thinks is equitable and practical, including the sale of what BP distributed and distribute the net proceeds, in the same way as it does with cash, or it may adopt such other methods it deems equitable and practical. The Depositary is not responsible if it decides that it is unlawful or impractical to make a distribution available to any ADS holders. BP has no obligation to register ADSs, shares, rights or other securities under the Securities Act of 1933. It also has no obligation to take any other action to permit the distribution of ADSs, shares, rights or anything else to ADS holders. This means that ADS holders may not receive the distributions BP makes on its shares or any value for them if it is unlawful or impractical for them to be made available to ADS holders. D. Deposit, Withdrawal and Cancellation ADS holders who hold or acquire ordinary shares may deposit them with the Depositary or custodian for the Depositary and hold ADSs instead. Where ordinary shares are deposited with the custodian they will be held by the custodian for the account and to the order of the Depositary. To the extent that an ADS holder is requested to do so by the custodian for the Depositary, an ADS holder must deliver to it the following: • certificates or other instruments of title for the ordinary shares to be deposited, properly endorsed and in a form satisfactory to the custodian; • a written order directing the Depositary to issue to an ADS holder, or upon the written order of an ADS holder, ADRs evidencing the number of ADSs which will represent the number of ordinary shares deposited; • any required payments; • an instrument which provides for the prompt transfer to the custodian of any dividend, right to subscribe for additional ordinary shares or right to receive other property--or, in lieu of such a transfer instrument, an agreement of indemnity; and • any other required documents. The custodian will then as soon as practicable present the ordinary shares for registration of the transfer into the name of the custodian, or its nominee, and notify the Depositary that the registration occurred. The deposit of the ordinary shares will be done at the ADS holder's cost and expense. Once the Depositary receives notice of the deposit, it shall issue to an ADS holder American Depositary receipts evidencing the number of ADSs to which that holder is entitled. ADSs will be issued in book-entry form, unless an ADS holder specifically requests them in certificated form.

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12 ADS holders may deposit ordinary shares directly with the Depositary for the purpose of having them forwarded to the custodian, but a charge will apply and delivery will be at the holder's risk. Where an ADS holder wishes to hold ordinary shares instead of ADSs, the holder must submit a written order to the Depositary to withdraw ordinary shares from deposit and surrender the ADSs at the Depositary's office. Upon payment of its fees and expenses and of any taxes or charges, the Depositary will deliver the underlying shares at the office of the custodian. At the holder's request, risk and expense, the Depositary may also deliver the deposited securities at office or any other place specified by the holder. Fractional shares are not deliverable on the cancellation of ADSs and, to the extent the cancellation of ADSs would give rise to the delivery of a fractional share, the Depositary will promptly advise the holder and will either deliver a new ADR in book entry form evidencing such fractional ADS or arrange to sell the fractional share and deliver the net proceeds from such sale net of the costs and expenses of such sale to the holder entitled thereto. E. Amendment and Termination BP may agree with the Depositary to amend the Deposit Agreement and the ADRs without the consent of ADR holders, and for any reason. If the amendment adds or increases fees or charges, except for taxes and governmental charges, or prejudices an important right of ADR holders, it will only become effective 30 days after the Depositary notifies ADR holders of the amendment. At the time an amendment becomes effective, ADR holders are considered to agree to the amendment and to be bound by the Deposit Agreement as amended. However, no amendment will impair the right of an ADS holder to receive the deposited securities in exchange for ADRs, except in order to comply with mandatory provisions of applicable law. The Depositary will terminate the Deposit Agreement if BP asks it to do so, in which case it must notify ADR holders at least 30 days before termination. The Depositary may also terminate the Deposit Agreement after notifying ADR holders. If the Depositary informs BP that it would like to resign and BP does not appoint a new depositary within 60 days, the Depositary is subject to certain obligations with respect to distributions and deposited securities which are set forth in the Deposit Agreement. F. Reports and Other Communications The Depositary will make available for inspection by holders at its office and at any other designated transfer offices any reports and other communications received from BP which are made generally available to the holders of ordinary shares by BP and will arrange for the transmittal or, when requested by BP, otherwise make available to holders copies of such reports and communications, as provided in the Deposit Agreement. The Depositary will also make available at its offices a register for the transfer of ADRs, which at all reasonable times will be open for the inspection of holders. G. Reclassifications, Recapitalizations and Mergers If BP: • changes the par value of, splits, cancels, consolidates or otherwise reclassifies any of the BP ordinary shares; or • recapitalizes, reorganizes, merges, consolidates, sells its assets, or takes any similar action, then: (1) The cash, ordinary shares or other securities received by the Depositary automatically will become new deposited securities under the Deposit Agreement, and each ADR will

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13 represent its equal share of the new deposited securities unless additional ADRs are delivered as in the case of a stock dividend; and (2) The Depositary will, if BP asks it to, issue new ADSs or ask the ADR holder to surrender outstanding ADRs in exchange for new ADRs identifying the new deposited securities. H. Limitations on Obligations and Liability to ADR Holders The Deposit Agreement expressly limits the obligations of BP and the Depositary. It also limits their liability. Pursuant to the Deposit Agreement, BP and the Depositary: • are obliged only to take the actions specifically set forth in the Deposit Agreement without negligence or bad faith; • are not liable if either of them is prevented or delayed by law, any provision of the BP Articles of Association or circumstances beyond their control from performing their obligations under the Deposit Agreement; • are not liable if either of them exercises, or fails to exercise, any discretion permitted under the agreement; • have no obligation to become involved in a lawsuit or proceeding related to the ADRs or the Deposit Agreement on an ADR holder's behalf or on behalf of any other party unless they are indemnified to their satisfaction; • may rely upon any advice of or information from any legal counsel, accountants, any person depositing ordinary shares, any ADR holder or any other person whom they believe in good faith is competent to give them that advice or information; • may rely and shall be protected in acting upon any written notice or other document believed by them to be genuine; and • shall not be responsible for any failure to carry out any instructions to vote any of the ordinary shares. In the Deposit Agreement, BP and the Depositary agree to indemnify each other under specified circumstances.

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14 III. DEBT SECURITIES Each series of notes listed on the New York Stock Exchange and set forth on the cover page to BP's Annual Report and Form 20-F 2025 has been issued by BP Capital Markets plc. ("BP Capital UK") or BP Capital Markets America Inc. ("BP Capital America" and, together with BP Capital UK, the "BP Debt Issuers") and guaranteed by BP. Each of these series of notes and related guarantees was issued pursuant to an effective registration statement and a related prospectus and prospectus supplement (if applicable) setting forth the terms of the relevant series of notes and related guarantees (collectively, the "Notes"). The following description of our Notes is a summary and does not purport to be complete and is qualified in its entirety by the full terms of the Notes. The following table sets forth the aggregate principal amount outstanding, issuer, file numbers of the registration statements and dates of issuance for each relevant series of Notes. Certain of the Notes issued by BP Capital UK (the "Old Exchange Notes") were exchanged for new Notes issued by BP Capital America on 14 December 2018 (the "New Exchange Notes") pursuant to a registration statement filed on Form F-4 (Registration Nos. 333-228369 and 333-228369-01). The New Exchange Notes have substantially identical terms to the Old Exchange Notes for which they were exchanged. Series Aggregate Principal Amount Outstanding Date(s) of Issuance Issuer(s) Registration Statement File No. 3.017% Guaranteed Notes due 2027 $876,418,000 12 December 2018 BP Capital America 333-228369 and 333-228369-01 3.279% Guaranteed Notes due 2027 $1,500,000,000 19 September 2017 BP Capital U.K. 333-208478 and 333-208478-01 3.543% Guaranteed Notes due 2027 $500,000,000 6 April 2020 BP Capital America 333-226485 and 333-226485-02 3.588% Guaranteed Notes due 2027 — — — — Old Exchange Notes $236,291,000 14 February 2017 BP Capital U.K. 333-208478 and 333-208478-01 New Exchange Notes $613,653,000 12 December 2018 BP Capital America 333-228369 and 333-228369-01 5.017% Guaranteed Notes due 2027 $1,150,000,000 17 May 20241 and 25 November 2024 BP Capital America 333-277842 and 333-277842-02 3.723% Guaranteed Notes due 2028 $800,000,000 28 November 2016 BP Capital U.K. 333-208478 and 333-208478-01 3.937% Guaranteed Notes due 2028 $1,000,000,000 21 September 2018 BP Capital America 333-226485 and 333-226485-02 4.234% Guaranteed Notes due 2028 $2,000,000,000 6 November 20182 and 11 February 2019 BP Capital America 333-226485 and 333-226485-02 4.699% Guaranteed Notes due 2029 $1,250,000,000 10 January 2024 BP Capital America 333-254751 and 333-254751-02 1 17 May 2024 (with respect to $750,000,000 aggregate principal amount of notes) and 25 November 2024 (with respect to $400,000,000 aggregate principal amount of notes). 2 6 November 2018 (with respect to $1,000,000,000 aggregate principal amount of notes) and 11 February 2019 (with respect to $1,000,000,000 aggregate principal amount of notes).

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15 Series Aggregate Principal Amount Outstanding Date(s) of Issuance Issuer(s) Registration Statement File No. 4.868% Guaranteed Notes due 2029 $650,000,000 25 November 2024 BP Capital America 333-277842 and 333-277842-02 4.970% Guaranteed Notes due 2029 $750,000,000 17 May 2024 BP Capital America 333-277842 and 333-277842-02 1.749% Guaranteed Notes due 2030 $1,000,000,000 10 August 2020 BP Capital America 333-226485 and 333-226485-02 3.633% Guaranteed Notes due 2030 $1,250,000,000 6 April 2020 BP Capital America 333-226485 and 333-226485-02 2.721% Guaranteed Notes due 2032 $2,000,000,000 12 January 2022 BP Capital America 333-254751 and 333-254751-02 4.812% Guaranteed Notes due 2033 $2,250,000,000 13 February 2023 BP Capital America 333-254751 and 333-254751-02 4.893% Guaranteed Notes due 2033 $1,500,000,000 11 May 2023 BP Capital America 333-254751 and 333-254751-02 4.989% Guaranteed Notes due 2034 $1,000,000,000 10 January 2024 BP Capital America 333-254751 and 333-254751-02 5.227% Guaranteed Notes due 2034 $1,950,000,000 17 May 20243 and 25 November 2024 BP Capital America 333-277842 and 333-277842-02 3.060% Guaranteed Notes due 2041 $1,450,000,000 17 June 2021 BP Capital America 333-254751 and 333-254751-02 2.772% Guaranteed Notes due 2050 $1,500,000,000 10 August 2020 BP Capital America 333-226485 and 333-226485-02 3.000% Guaranteed Notes due 2050 $2,000,000,000 24 February 20204 and 9 March 2020 BP Capital America 333-226485 and 333-226485-02 3.067% Guaranteed Notes due 2050 $1,426,000 13 December 2019 BP Capital America 333-226485 and 333-226485-02 2.939% Guaranteed Notes due 2051 $2,250,000,000 4 December 20205 and 8 February 2021 BP Capital America 333-226485 and 333-226485-02 3.001% Guaranteed Notes due 2052 $1,250,000,000 17 September 2021 BP Capital America 333-254751 and 333-254751-02 3.379% Guaranteed Notes due 2061 $2,050,000,000 8 February 20216, 17 June 2021 and 17 September 2021 BP Capital America 333-226485 3 17 May 2024 (with respect to $1,000,000,000 aggregate principal amount of notes) and 25 November 2024 (with respect to $950,000,000 aggregate principal amount of notes). 4 24 February 2020 (with respect to $1,250,000,000 aggregate principal amount of notes) and 9 March 2020 (with respect to $750,000,000 aggregate principal amount of notes). 5 4 December 2020 (with respect to $1,500,000,000 aggregate principal amount of notes) and 8 February 2021 (with respect to $750,000,000 aggregate principal amount of notes). 6 8 February 2021 (with respect to $1,250,000,000 aggregate principal amount of notes), 17 June 2021 (with respect to $550,000,000 aggregate principal amount of notes) and 17 September 2021 (with respect to $250,000,000 aggregate principal amount of notes).

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16 Series Aggregate Principal Amount Outstanding Date(s) of Issuance Issuer(s) Registration Statement File No. and 333-226485-02, 333-254751 and 333-254751-027 4.875% Perpetual Subordinated Non-call 10 Fixed Rate Reset Notes $2,500,000,000 22 June 2020 BP Capital U.K. 333-226485 and 333-226485-01 6.125% Perpetual Subordinated Fixed Rate Reset Notes $1,250,000,000 18 November 2024 BP Capital U.K. 333-277842 and 333-277842-01 6.450% Perpetual Subordinated Fixed Rate Reset Notes $1,300,000,000 1 March 2024 BP Capital U.K. 333-254751 and 333-254751-01 A. Descriptions of Notes Description of 3.017% Guaranteed Notes due 2027 The following terms are applicable to the 3.017% Guaranteed Notes due 2027. • Issuer: BP Capital America • Title: 3.017% Guaranteed Notes due 2027 • Total principal amount outstanding: $876,418,000 • Issuance date: 12 December 2018 • Maturity date: 16 January 2027 • Interest rate: 3.017% per annum • Date interest starts accruing: 16 September 2018 • Interest payment dates: Each 16 January and 16 July, subject to the day count convention. • First interest payment date: 16 January 2019 • Optional redemption: Prior to 16 October 2026 (the date that is three months prior to the scheduled maturity date for the 2027 fixed rate notes), the issuer has the right to redeem the 2027 fixed rate notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2027 fixed rate notes to be redeemed and (ii) the 7 Registration Statement Nos. 333-226485 and 333-226485-02 (with respect to $1,250,000,000 aggregate principal amount of notes issued 8 February 2021), Registration Statement Nos. 333-254751 and 333- 254751-02 (with respect to $800,000,000 aggregate principal amount of notes issued 17 June 2021 and 17 September 2021).

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17 sum of the present values of the remaining scheduled payments of principal and interest on the 2027 fixed rate notes to be redeemed that would be due if such notes matured on 16 October 2026 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. On or after 16 October 2026 (the date that is three months prior to the scheduled maturity date for the 2027 fixed rate notes), the issuer has the right to redeem the 2027 fixed rate notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2027 fixed rate notes to be redeemed , plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2027 fixed rate notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by the issuer "Reference treasury dealer" means Barclays Capital Inc., BNP Paribas Securities Corp., HSBC Securities (USA) Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Mizuho Securities USA Inc. and Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.279% Guaranteed Notes due 2027 The following terms are applicable to the 3.279% Guaranteed Notes due 2027. • Issuer: BP Capital U.K. • Title: 3.279% Guaranteed Notes due 2027 • Total principal amount outstanding: $1,500,000,000 • Issuance date: 19 September 2017 • Maturity date: 19 September 2027 • Interest rate: 3.279% per annum • Date interest starts accruing: 19 September 2017

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18 • Interest payment dates: Each 19 March and 19 September, subject to the day count convention. • First interest payment date: 19 March 2018 • Optional redemption: Prior to 19 June 2027 (the date that is three months prior to the scheduled maturity date for the 2027 fixed rate notes), the issuer has the right to redeem the 2027 fixed rate notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2027 fixed rate notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2027 fixed rate notes to be redeemed that would be due if such notes matured on 19 June 2027 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. On or after 19 June 2027 (the date that is three months prior to the scheduled maturity date for the 2027 fixed rate notes), the issuer has the right to redeem the 2027 fixed rate notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2027 fixed rate notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2027 fixed rate notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by the issuer "Reference treasury dealer" means Credit Suisse Securities (USA) LLC, Goldman Sachs & Co. LLC, HSBC Securities (USA) Inc., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and UBS Securities LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.543% Guaranteed Notes due 2027 The following terms are applicable to the 3.543% Guaranteed Notes due 2027. • Issuer: BP Capital America • Title: 3.543% Guaranteed Notes due 2027 • Total principal amount outstanding: $500,000,000

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19 • Issuance date: 6 April 2020 • Maturity date: 6 April 2027 • Interest rate: 3.543% per annum • Date interest starts accruing: 6 April 2020 • Interest payment dates: Each 6 April and 6 October, subject to the day count convention. • First interest payment date: 6 October 2020 • Optional redemption: Prior to 6 February 2027 (the date that is two months prior to the scheduled maturity date for the 2027 notes), BP Capital America has the right to redeem the 2027 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2027 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2027 notes to be redeemed that would be due if such 2027 notes matured on 6 February 2027 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 45 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 6 February 2027 (the date that is two months prior to the scheduled maturity date for the 2027 notes), BP Capital America has the right to redeem the 2027 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2027 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2027 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such 2027 notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by BP Capital America. "Reference treasury dealer" means BNP Paribas Securities Corp., BofA Securities, Inc., Citigroup Global Markets Inc., HSBC Securities (USA) Inc., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.588% Guaranteed Notes due 2027

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20 The following terms are applicable to the 3.588% Guaranteed Notes due 2027. • Issuer: BP Capital U.K. (Old Exchange Notes) and BP Capital America (New Exchange Notes) • Title: 3.588% Guaranteed Notes due 2027 • Total principal amount outstanding: $236,291,000 (Old Exchange Notes) and $613,653,000 (New Exchange Notes) • Issuance date: 14 February 2017 (Old Exchange Notes) and 12 December 2018 (New Exchange Notes) • Maturity date: 14 April 2027 • Interest rate: 3.588% per annum • Date interest starts accruing: 14 February 2017 (Old Exchange Notes) and 14 October 2018 (New Exchange Notes) • Interest payment dates: Each 14 April and 14 October, subject to the day count convention. • First interest payment date: 14 October 2017 (Old Exchange Notes) and 14 April 2019 (New Exchange Notes) • Optional redemption: Prior to 14 January 2027 (the date that is three months prior to the scheduled maturity date for the 2027 notes), the issuer has the right to redeem the 2027 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2027 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2027 notes to be redeemed that would be due if such notes matured on 14 January 2027 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in each case accrued and unpaid interest to the date of redemption. On or after 14 January 2027 (the date that is three months prior to the scheduled maturity date for the 2027 notes), the issuer has the right to redeem the 2027 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2027 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2027 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by the issuer "Reference treasury dealer" means Barclays Capital Inc., BNP Paribas Securities Corp., Deutsche Bank Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, MUFG Securities

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21 Americas Inc., and RBS Securities Inc. (marketing name "NatWest Markets") or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefore another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 5.017% Guaranteed Notes due 2027 The following terms are applicable to the 5.017% Guaranteed Notes due 2027. • Issuer: BP Capital America • Title: 5.017% Guaranteed Notes due 2027 • Total principal amount outstanding: $1,150,000,000 • Issuance date: 17 May 2024 (with respect to $750,000,000 aggregate principal amount of notes) and 25 November 2024 (with respect to $400,000,000 aggregate principal amount of notes) • Maturity date: 17 November 2027 • Interest rate: 5.017% per annum • Date interest starts accruing: 17 May 2024 • Interest payment dates: Each 17 May and 17 November, subject to the day count convention. • First interest payment date: 17 November 2024 • Optional redemption: Prior to 17 October 2027 (the date that is one month prior to the scheduled maturity date for the 2027 notes), BP Capital America has the right to redeem the 2027 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2027 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2027 notes to be redeemed that would be due if such notes matured on 17 October 2027 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 10 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 17 October 2027 (the date that is one month prior to the scheduled maturity date for the 2027 notes), BP Capital America has the right to redeem the 2027 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2027 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following are applicable.

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22 "Treasury Rate" means, with respect to any redemption date, the yield determined by BP Capital America in accordance with the following two paragraphs. (1) The Treasury Rate shall be determined by BP Capital America after 4:15 p.m., New York City time (or after such time as yields on U.S. government securities are posted daily by the Board of Governors of the Federal Reserve System), on the third business day preceding the redemption date based upon the yield or yields for the most recent day that appear after such time on such day in the most recent statistical release published by the Board of Governors of the Federal Reserve System designated as "Selected Interest Rates (Daily) - H.15" (or any successor designation or publication) ("H.15") under the caption "U.S. government securities–Treasury constant maturities–Nominal" (or any successor caption or heading). In determining the Treasury Rate, BP Capital America shall select, as applicable: (1) the yield for the Treasury constant maturity on H.15 exactly equal to the period from the redemption date to the Par Call Date (the "Remaining Life"); or (2) if there is no such Treasury constant maturity on H.15 exactly equal to the Remaining Life, the two yields – one yield corresponding to the Treasury constant maturity on H.15 immediately shorter than and one yield corresponding to the Treasury constant maturity on H.15 immediately longer than the Remaining Life – and shall interpolate to the Par Call Date on a straight-line basis (using the actual number of days) using such yields and rounding the result to three decimal places; or (3) if there is no such Treasury constant maturity on H.15 shorter than or longer than the Remaining Life, the yield for the single Treasury constant maturity on H.15 closest to the Remaining Life. For purposes of this paragraph, the applicable Treasury constant maturity or maturities on H.15 shall be deemed to have a maturity date equal to the relevant number of months or years, as applicable, of such Treasury constant maturity from the redemption date. (2) If on the third business day preceding the redemption date H.15 or any successor designation or publication is no longer published, BP Capital America shall calculate the Treasury Rate based on the rate per annum equal to the semi-annual equivalent yield to maturity at 11:00 a.m., New York City time, on the second business day preceding such redemption date of the United States Treasury security maturing on, or with a maturity that is closest to, the Par Call Date, as applicable. If there is no United States Treasury security maturing on the Par Call Date but there are two or more United States Treasury securities with a maturity date equally distant from the Par Call Date, one with a maturity date preceding the Par Call Date and one with a maturity date following the Par Call Date, BP Capital America shall select the United States Treasury security with a maturity date preceding the Par Call Date. If there are two or more United States Treasury securities maturing on the Par Call Date or two or more United States Treasury securities meeting the criteria of the preceding sentence, BP Capital America shall select from among these two or more United States Treasury securities the United States Treasury security that is trading closest to par based upon the average of the bid and asked prices for such United States Treasury securities at 11:00 a.m., New York City time. In determining the Treasury Rate in accordance with the terms of this paragraph, the semi-annual yield to maturity of the applicable United States Treasury security shall be based upon the average of the bid and asked prices (expressed as a percentage of principal amount) at 11:00 a.m., New York City time, of such United States Treasury security, and rounded to three decimal places. Notice of any redemption will be mailed or electronically delivered (or otherwise transmitted in accordance with the depositary's procedures) at least 10 days but not more than 60 days before the redemption date to each holder of 2027 notes to be redeemed.

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23 If less than all of the 2027 notes are to be redeemed, the 2027 notes to be redeemed shall be selected by the trustee in accordance with its policies and procedures. For so long as the 2027 notes are held by DTC, Euroclear or Clearstream (or another depositary), the redemption of the 2027 notes shall be done in accordance with the policies and procedures of the depositary. Unless BP Capital America defaults in payment of the redemption price, on and after the redemption date interest will cease to accrue on the 2027 notes or portions thereof called for redemption. Neither the trustee nor the paying agent shall be responsible for calculating the redemption price. BP Capital America's actions and determinations in determining the redemption price shall be conclusive and binding for all purposes, absent manifest error. Once notice of redemption is sent, the 2027 notes called for redemption will become due and payable on the redemption date and at the applicable redemption price, plus accrued and unpaid interest to the redemption date, subject to any conditions precedent specified in such notice. Description of 3.723% Guaranteed Notes due 2028 The following terms are applicable to the 3.723% Guaranteed Notes due 2028. • Issuer: BP Capital U.K. • Title: 3.723% Guaranteed Notes due 2028 • Total principal amount outstanding: $800,000,000 • Issuance date: 28 November 2016 • Maturity date: 28 November 2028 • Interest rate: 3.723% per annum • Date interest starts accruing: 28 November 2016 • Interest payment dates: Each 28 May and 28 November, subject to the day count convention. • First interest payment date: 28 May 2017 • Optional redemption: Prior to 28 August 2028 (the date that is three months prior to the scheduled maturity date for the 2028 notes), the issuer has the right to redeem the 2028 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2028 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2028 notes to be redeemed that would be due if such notes matured on 28 August 2028 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 25 basis points, plus in each case accrued and unpaid interest to the date of redemption. On or after 28 August 2028 (the date that is three months prior to the scheduled maturity date for the 2028 notes), the issuer has the right to redeem the 2028 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2028 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum

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24 equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2028 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by the issuer "Reference treasury dealer" means BNP Paribas Securities Corp., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated and MUFG Securities Americas Inc. or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by the issuer, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, the issuer shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.937% Guaranteed Notes due 2028 The following terms are applicable to the 3.937% Guaranteed Notes due 2028. • Issuer: BP Capital America • Title: 3.937% Guaranteed Notes due 2028 • Total principal amount outstanding: $1,000,000,000 • Issuance date: 21 September 2018 • Maturity date: 21 September 2028 • Interest rate: 3.937% per annum • Date interest starts accruing: 21 September 2018 • Interest payment dates: Each 21 March and 21 September, subject to the day count convention. • First interest payment date: 21 March 2019 • Optional redemption: Prior to 21 June 2028 (the date that is three months prior to the scheduled maturity date for the 2028 notes), BP Capital America has the right to redeem the 2028 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2028 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2028 notes to be redeemed that would be due if such notes matured on 21 June 2028 (not including any portion of

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25 payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 15 basis points, plus in each case accrued and unpaid interest to the date of redemption. On or after 21 June 2028 (the date that is three months prior to the scheduled maturity date for the 2028 notes), BP Capital America has the right to redeem the 2028 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2028 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2028 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by BP Capital America. "Reference treasury dealer" means Citigroup Global Markets Inc., Goldman Sachs & Co. LLC, HSBC Securities (USA) Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Mizuho Securities USA LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 4.234% Guaranteed Notes due 2028 The following terms are applicable to the 4.234% Guaranteed Notes due 2028. • Issuer: BP Capital America • Title: 4.234% Guaranteed Notes due 2028 • Total principal amount outstanding: $2,000,000,000 • Issuance date: 6 November 2018 (with respect to $1,000,000,000 aggregate principal amount of notes) and 11 February 2019 (with respect to $1,000,000,000 aggregate principal amount of notes) • Maturity date: 6 November 2028 • Interest rate: 4.234% per annum • Date interest starts accruing: 6 November 2018

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26 • Interest payment dates: Each 6 May and 6 November, subject to the day count convention. • First interest payment date: 6 May 2019 • Optional redemption: Prior to 6 August 2028 (the date that is three months prior to the scheduled maturity date for the 2028 notes), BP Capital America has the right to redeem the 2028 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2028 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2028 notes to be redeemed that would be due if such notes matured on 6 August 2028 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 6 August 2028 (the date that is three months prior to the scheduled maturity date for the 2028 notes), BP Capital America has the right to redeem the 2028 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2028 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2028 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by BP Capital America. "Reference treasury dealer" means Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC, NatWest Markets Securities Inc., SG Americas Securities, LLC and UBS Securities LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 4.699% Guaranteed Notes due 2029 The following terms are applicable to the 4.699% Guaranteed Notes due 2029. • Issuer: BP Capital America • Title: 4.699% Guaranteed Notes due 2029 • Total principal amount outstanding: $1,250,000,000

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27 • Issuance date: 10 January 2024 • Maturity date: 10 April 2029 • Interest rate: 4.699% per annum • Date interest starts accruing: 10 January 2024 • Interest payment dates: Each 10 April and 10 October, subject to the day count convention. • First interest payment date: 10 October 2024 • Optional redemption: Prior to 10 March 2029 (the date that is one month prior to the scheduled maturity date for the 2029 notes), BP Capital America has the right to redeem the 2029 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2029 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2029 notes to be redeemed that would be due if such notes matured on 10 March 2029 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 12.5 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 10 March 2029 (the date that is one month prior to the scheduled maturity date for the 2029 notes), BP Capital America has the right to redeem the 2029 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2029 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following are applicable. "Treasury Rate" means, with respect to any redemption date, the yield determined by BP Capital America in accordance with the following two paragraphs. (1) The Treasury Rate shall be determined by BP Capital America after 4:15 p.m., New York City time (or after such time as yields on U.S. government securities are posted daily by the Board of Governors of the Federal Reserve System), on the third business day preceding the redemption date based upon the yield or yields for the most recent day that appear after such time on such day in the most recent statistical release published by the Board of Governors of the Federal Reserve System designated as "Selected Interest Rates (Daily) - H.15" (or any successor designation or publication) ("H.15") under the caption "U.S. government securities–Treasury constant maturities–Nominal" (or any successor caption or heading). In determining the Treasury Rate, BP Capital America shall select, as applicable: (1) the yield for the Treasury constant maturity on H.15 exactly equal to the period from the redemption date to the Par Call Date (the "Remaining Life"); or (2) if there is no such Treasury constant maturity on H.15 exactly equal to the Remaining Life, the two yields – one yield corresponding to the Treasury constant maturity on H.15 immediately shorter than and one yield corresponding to the Treasury constant maturity on H.15 immediately longer than the Remaining Life – and shall interpolate to the Par Call Date on a straight-line basis (using the actual number of days) using such yields and rounding the result to three decimal places; or (3) if there is no such Treasury constant maturity on H.15 shorter than or longer than the Remaining Life, the yield for the single Treasury constant maturity on H.15 closest to the Remaining Life. For purposes of this paragraph, the applicable Treasury constant maturity or maturities on H.15 shall be deemed to have a

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![](a31122025bpxex2descripti028.jpg)

28 maturity date equal to the relevant number of months or years, as applicable, of such Treasury constant maturity from the redemption date. (2) If on the third business day preceding the redemption date H.15 or any successor designation or publication is no longer published, BP Capital America shall calculate the Treasury Rate based on the rate per annum equal to the semi-annual equivalent yield to maturity at 11:00 a.m., New York City time, on the second business day preceding such redemption date of the United States Treasury security maturing on, or with a maturity that is closest to, the Par Call Date, as applicable. If there is no United States Treasury security maturing on the Par Call Date but there are two or more United States Treasury securities with a maturity date equally distant from the Par Call Date, one with a maturity date preceding the Par Call Date and one with a maturity date following the Par Call Date, BP Capital America shall select the United States Treasury security with a maturity date preceding the Par Call Date. If there are two or more United States Treasury securities maturing on the Par Call Date or two or more United States Treasury securities meeting the criteria of the preceding sentence, BP Capital America shall select from among these two or more United States Treasury securities the United States Treasury security that is trading closest to par based upon the average of the bid and asked prices for such United States Treasury securities at 11:00 a.m., New York City time. In determining the Treasury Rate in accordance with the terms of this paragraph, the semi-annual yield to maturity of the applicable United States Treasury security shall be based upon the average of the bid and asked prices (expressed as a percentage of principal amount) at 11:00 a.m., New York City time, of such United States Treasury security, and rounded to three decimal places. Notice of any redemption will be mailed or electronically delivered (or otherwise transmitted in accordance with the depositary's procedures) at least 10 days but not more than 60 days before the redemption date to each holder of 2029 notes to be redeemed. If less than all of the 2029 notes are to be redeemed, the 2029 notes to be redeemed shall be selected by the trustee in accordance with its policies and procedures. For so long as the 2029 notes are held by DTC, Euroclear or Clearstream (or another depositary), the redemption of the 2029 notes shall be done in accordance with the policies and procedures of the depositary. Unless BP Capital America defaults in payment of the redemption price, on and after the redemption date interest will cease to accrue on the 2029 notes or portions thereof called for redemption. Neither the trustee nor the paying agent shall be responsible for calculating the redemption price. BP Capital America's actions and determinations in determining the redemption price shall be conclusive and binding for all purposes, absent manifest error. Once notice of redemption is sent, the 2029 notes called for redemption will become due and payable on the redemption date and at the applicable redemption price, plus accrued and unpaid interest to the redemption date, subject to any conditions precedent specified in such notice. Description of 4.868% Guaranteed Notes due 2029 The following terms are applicable to the 4.868% Guaranteed Notes due 2029. • Issuer: BP Capital America • Title: 4.868% Guaranteed Notes due 2029 • Total principal amount outstanding: $650,000,000

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29 • Issuance date: 25 November 2024 • Maturity date: 25 November 2029 • Interest rate: 4.868% per annum • Date interest starts accruing: 25 November 2024 • Interest payment dates: Each 25 May and 25 November, subject to the day count convention. • First interest payment date: 25 May 2025 • Optional redemption: Prior to 25 October 2029 (the date that is one month prior to the scheduled maturity date for the 2029 notes), BP Capital America has the right to redeem the 2029 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2029 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2029 notes to be redeemed that would be due if such notes matured on 25 October 2029 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 10 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 25 October 2029 (the date that is one month prior to the scheduled maturity date for the 2029 notes), BP Capital America has the right to redeem the 2029 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2029 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following are applicable. "Treasury Rate" means, with respect to any redemption date, the yield determined by BP Capital America in accordance with the following two paragraphs. (1) The Treasury Rate shall be determined by BP Capital America after 4:15 p.m., New York City time (or after such time as yields on U.S. government securities are posted daily by the Board of Governors of the Federal Reserve System), on the third business day preceding the redemption date based upon the yield or yields for the most recent day that appear after such time on such day in the most recent statistical release published by the Board of Governors of the Federal Reserve System designated as "Selected Interest Rates (Daily) - H.15" (or any successor designation or publication) ("H.15") under the caption "U.S. government securities–Treasury constant maturities–Nominal" (or any successor caption or heading). In determining the Treasury Rate, BP Capital America shall select, as applicable: (1) the yield for the Treasury constant maturity on H.15 exactly equal to the period from the redemption date to the Par Call Date (the "Remaining Life"); or (2) if there is no such Treasury constant maturity on H.15 exactly equal to the Remaining Life, the two yields – one yield corresponding to the Treasury constant maturity on H.15 immediately shorter than and one yield corresponding to the Treasury constant maturity on H.15 immediately longer than the Remaining Life – and shall interpolate to the Par Call Date on a straight-line basis (using the actual number of days) using such yields and rounding the result to three decimal places; or (3) if there is no such Treasury constant maturity on H.15 shorter than or longer than the Remaining Life, the yield for the single Treasury constant maturity on H.15 closest to the Remaining Life. For purposes of this paragraph, the applicable Treasury constant maturity or maturities on H.15 shall be deemed to have a

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30 maturity date equal to the relevant number of months or years, as applicable, of such Treasury constant maturity from the redemption date. (2) If on the third business day preceding the redemption date H.15 or any successor designation or publication is no longer published, BP Capital America shall calculate the Treasury Rate based on the rate per annum equal to the semi-annual equivalent yield to maturity at 11:00 a.m., New York City time, on the second business day preceding such redemption date of the United States Treasury security maturing on, or with a maturity that is closest to, the Par Call Date, as applicable. If there is no United States Treasury security maturing on the Par Call Date but there are two or more United States Treasury securities with a maturity date equally distant from the Par Call Date, one with a maturity date preceding the Par Call Date and one with a maturity date following the Par Call Date, BP Capital America shall select the United States Treasury security with a maturity date preceding the Par Call Date. If there are two or more United States Treasury securities maturing on the Par Call Date or two or more United States Treasury securities meeting the criteria of the preceding sentence, BP Capital America shall select from among these two or more United States Treasury securities the United States Treasury security that is trading closest to par based upon the average of the bid and asked prices for such United States Treasury securities at 11:00 a.m., New York City time. In determining the Treasury Rate in accordance with the terms of this paragraph, the semi-annual yield to maturity of the applicable United States Treasury security shall be based upon the average of the bid and asked prices (expressed as a percentage of principal amount) at 11:00 a.m., New York City time, of such United States Treasury security, and rounded to three decimal places. Notice of any redemption will be mailed or electronically delivered (or otherwise transmitted in accordance with the depositary's procedures) at least 10 days but not more than 60 days before the redemption date to each holder of 2029 notes to be redeemed. If less than all of the 2029 notes are to be redeemed, the 2029 notes to be redeemed shall be selected by the trustee in accordance with its policies and procedures. For so long as the 2029 notes are held by DTC, Euroclear or Clearstream (or another depositary), the redemption of the 2029 notes shall be done in accordance with the policies and procedures of the depositary. Unless BP Capital America defaults in payment of the redemption price, on and after the redemption date interest will cease to accrue on the 2029 notes or portions thereof called for redemption. Neither the trustee nor the paying agent shall be responsible for calculating the redemption price. BP Capital America's actions and determinations in determining the redemption price shall be conclusive and binding for all purposes, absent manifest error. Once notice of redemption is sent, the 2029 notes called for redemption will become due and payable on the redemption date and at the applicable redemption price, plus accrued and unpaid interest to the redemption date, subject to any conditions precedent specified in such notice. Description of 4.970% Guaranteed Notes due 2029 The following terms are applicable to the 4.970% Guaranteed Notes due 2029. • Issuer: BP Capital America • Title: 4.970% Guaranteed Notes due 2029 • Total principal amount outstanding: $750,000,000

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31 • Issuance date: 17 May 2024 • Maturity date: 17 October 2029 • Interest rate: 4.970% per annum • Date interest starts accruing: 17 May 2024 • Interest payment dates: Each 17 April and 17 October, subject to the day count convention. • First interest payment date: 17 October 2024 • Optional redemption: Prior to 17 September 2029 (the date that is one month prior to the scheduled maturity date for the 2029 notes), BP Capital America has the right to redeem the 2029 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2029 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2029 notes to be redeemed that would be due if such notes matured on 17 September 2029 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 10 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 17 September 2029 (the date that is one month prior to the scheduled maturity date for the 2029 notes), BP Capital America has the right to redeem the 2029 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2029 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following are applicable. "Treasury Rate" means, with respect to any redemption date, the yield determined by BP Capital America in accordance with the following two paragraphs. (1) The Treasury Rate shall be determined by BP Capital America after 4:15 p.m., New York City time (or after such time as yields on U.S. government securities are posted daily by the Board of Governors of the Federal Reserve System), on the third business day preceding the redemption date based upon the yield or yields for the most recent day that appear after such time on such day in the most recent statistical release published by the Board of Governors of the Federal Reserve System designated as "Selected Interest Rates (Daily) - H.15" (or any successor designation or publication) ("H.15") under the caption "U.S. government securities–Treasury constant maturities–Nominal" (or any successor caption or heading). In determining the Treasury Rate, BP Capital America shall select, as applicable: (1) the yield for the Treasury constant maturity on H.15 exactly equal to the period from the redemption date to the Par Call Date (the "Remaining Life"); or (2) if there is no such Treasury constant maturity on H.15 exactly equal to the Remaining Life, the two yields – one yield corresponding to the Treasury constant maturity on H.15 immediately shorter than and one yield corresponding to the Treasury constant maturity on H.15 immediately longer than the Remaining Life – and shall interpolate to the Par Call Date on a straight-line basis (using the actual number of days) using such yields and rounding the result to three decimal places; or (3) if there is no such Treasury constant maturity on H.15 shorter than or longer than the Remaining Life, the yield for the single Treasury constant maturity on H.15 closest to the Remaining Life. For purposes of this paragraph, the applicable Treasury constant maturity or maturities on H.15 shall be deemed to have a

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32 maturity date equal to the relevant number of months or years, as applicable, of such Treasury constant maturity from the redemption date. (2) If on the third business day preceding the redemption date H.15 or any successor designation or publication is no longer published, BP Capital America shall calculate the Treasury Rate based on the rate per annum equal to the semi-annual equivalent yield to maturity at 11:00 a.m., New York City time, on the second business day preceding such redemption date of the United States Treasury security maturing on, or with a maturity that is closest to, the Par Call Date, as applicable. If there is no United States Treasury security maturing on the Par Call Date but there are two or more United States Treasury securities with a maturity date equally distant from the Par Call Date, one with a maturity date preceding the Par Call Date and one with a maturity date following the Par Call Date, BP Capital America shall select the United States Treasury security with a maturity date preceding the Par Call Date. If there are two or more United States Treasury securities maturing on the Par Call Date or two or more United States Treasury securities meeting the criteria of the preceding sentence, BP Capital America shall select from among these two or more United States Treasury securities the United States Treasury security that is trading closest to par based upon the average of the bid and asked prices for such United States Treasury securities at 11:00 a.m., New York City time. In determining the Treasury Rate in accordance with the terms of this paragraph, the semi-annual yield to maturity of the applicable United States Treasury security shall be based upon the average of the bid and asked prices (expressed as a percentage of principal amount) at 11:00 a.m., New York City time, of such United States Treasury security, and rounded to three decimal places. Notice of any redemption will be mailed or electronically delivered (or otherwise transmitted in accordance with the depositary's procedures) at least 10 days but not more than 60 days before the redemption date to each holder of 2029 notes to be redeemed. If less than all of the 2029 notes are to be redeemed, the 2029 notes to be redeemed shall be selected by the trustee in accordance with its policies and procedures. For so long as the 2029 notes are held by DTC, Euroclear or Clearstream (or another depositary), the redemption of the 2029 notes shall be done in accordance with the policies and procedures of the depositary. Unless BP Capital America defaults in payment of the redemption price, on and after the redemption date interest will cease to accrue on the 2029 notes or portions thereof called for redemption. Neither the trustee nor the paying agent shall be responsible for calculating the redemption price. BP Capital America's actions and determinations in determining the redemption price shall be conclusive and binding for all purposes, absent manifest error. Once notice of redemption is sent, the 2029 notes called for redemption will become due and payable on the redemption date and at the applicable redemption price, plus accrued and unpaid interest to the redemption date, subject to any conditions precedent specified in such notice. Description of 1.749% Guaranteed Notes due 2030 The following terms are applicable to the 1.749% Guaranteed Notes due 2030. • Issuer: BP Capital America • Title: 1.749% Guaranteed Notes due 2030 • Total principal amount outstanding: $1,000,000,000

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33 • Issuance date: 10 August 2020 • Maturity date: 10 August 2030 • Interest rate: 1.749% per annum • Date interest starts accruing: 10 August 2020 • Interest payment dates: Each 10 February and 10 August, subject to the day count convention. • First interest payment date: 10 February 2021 • Optional redemption: Prior to 10 May 2030 (the date that is three months prior to the scheduled maturity date for the 2030 notes), BP Capital America has the right to redeem the 2030 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2030 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2030 notes to be redeemed that would be due if such 2030 notes matured on 10 May 2030 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 10 May 2030 (the date that is three months prior to the scheduled maturity date for the 2030 notes), BP Capital America has the right to redeem the 2030 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2030 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2030 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such 2030 notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by BP Capital America. "Reference treasury dealer" means Citigroup Global Markets Inc., HSBC Securities (USA) Inc., J.P. Morgan Securities LLC, Mizuho Securities USA LLC and Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.633% Guaranteed Notes due 2030

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34 The following terms are applicable to the 3.633% Guaranteed Notes due 2030. • Issuer: BP Capital America • Title: 3.633% Guaranteed Notes due 2030 • Total principal amount outstanding: $1,250,000,000 • Issuance date: 6 April 2020 • Maturity date: 6 April 2030 • Interest rate: 3.633% per annum • Date interest starts accruing: 6 April 2020 • Interest payment dates: Each 6 April and 6 October, subject to the day count convention. • First interest payment date: 6 October 2020 • Optional redemption: Prior to 6 January 2030 (the date that is three months prior to the scheduled maturity date for the 2030 notes), BP Capital America has the right to redeem the 2030 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2030 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2030 notes to be redeemed that would be due if such 2030 notes matured on 6 January 2030 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 45 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 6 January 2030 (the date that is three months prior to the scheduled maturity date for the 2030 notes), BP Capital America has the right to redeem the 2030 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2030 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2030 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such 2030 notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by BP Capital America. "Reference treasury dealer" means BNP Paribas Securities Corp., BofA Securities, Inc., Citigroup Global Markets Inc., HSBC Securities (USA) Inc., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary

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35 treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 2.721% Guaranteed Notes due 2032 The following terms are applicable to the 2.721% Guaranteed Notes due 2032. • Issuer: BP Capital America • Title: 2.721% Guaranteed Notes due 2032 • Total principal amount outstanding: $2,000,000,000 • Issuance date: 12 January 2022 • Maturity date: 12 January 2032 • Interest rate: 2.721% per annum • Date interest starts accruing: 12 January 2022 • Interest payment dates: Each 12 January and 12 July, subject to the day count convention. • First interest payment date: 12 July 2022 • Optional redemption: Prior to 12 October 2031 (the date that is three months prior to the scheduled maturity date for the 2032 notes), BP Capital America has the right to redeem the 2032 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2032 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2032 notes to be redeemed that would be due if such notes matured on 12 October 2031 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 15 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 12 October 2031 (the date that is three months prior to the scheduled maturity date for the 2032 notes), BP Capital America has the right to redeem the 2032 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2032 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2032 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues

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36 of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by BP Capital America. "Reference treasury dealer" means one of BNP Paribas Securities Corp., Citigroup Global Markets Inc., Credit Agricole Securities (USA) Inc., Credit Suisse Securities (USA) LLC, Goldman Sachs & Co. LLC and Wells Fargo Securities, LLC or one of their affiliates, which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 4.812% Guaranteed Notes due 2033 The following terms are applicable to the 4.812% Guaranteed Notes due 2033. • Issuer: BP Capital America • Title: 4.812% Guaranteed Notes due 2033 • Total principal amount outstanding: $2,250,000,000 • Issuance date: 13 February 2023 • Maturity date: 13 February 2033 • Interest rate: 4.812% per annum • Date interest starts accruing: 13 February 2023 • Interest payment dates: Each 13 February and 13 August, subject to the day count convention. • First interest payment date: 13 August 2023 • Optional redemption: Prior to 13 November 2032 (the date that is three months prior to the scheduled maturity date for the 2033 notes), BP Capital America has the right to redeem the 2033 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2033 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2033 notes to be redeemed that would be due if such notes matured on 13 November 2032 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 13 November 2032 (the date that is three months prior to the scheduled maturity date for the 2033 notes), BP Capital America has the right to redeem the 2033 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100%

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37 of the principal amount of the 2033 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following are applicable. "Treasury Rate" means, with respect to any redemption date, the yield determined by BP Capital America in accordance with the following two paragraphs. (1) The Treasury Rate shall be determined by BP Capital America after 4:15 p.m., New York City time (or after such time as yields on U.S. government securities are posted daily by the Board of Governors of the Federal Reserve System), on the third business day preceding the redemption date based upon the yield or yields for the most recent day that appear after such time on such day in the most recent statistical release published by the Board of Governors of the Federal Reserve System designated as "Selected Interest Rates (Daily) - H.15" (or any successor designation or publication) ("H.15") under the caption "U.S. government securities–Treasury constant maturities–Nominal" (or any successor caption or heading). In determining the Treasury Rate, BP Capital America shall select, as applicable: (1) the yield for the Treasury constant maturity on H.15 exactly equal to the period from the redemption date to the Par Call Date (the "Remaining Life"); or (2) if there is no such Treasury constant maturity on H.15 exactly equal to the Remaining Life, the two yields – one yield corresponding to the Treasury constant maturity on H.15 immediately shorter than and one yield corresponding to the Treasury constant maturity on H.15 immediately longer than the Remaining Life – and shall interpolate to the Par Call Date on a straight-line basis (using the actual number of days) using such yields and rounding the result to three decimal places; or (3) if there is no such Treasury constant maturity on H.15 shorter than or longer than the Remaining Life, the yield for the single Treasury constant maturity on H.15 closest to the Remaining Life. For purposes of this paragraph, the applicable Treasury constant maturity or maturities on H.15 shall be deemed to have a maturity date equal to the relevant number of months or years, as applicable, of such Treasury constant maturity from the redemption date. (2) If on the third business day preceding the redemption date H.15 or any successor designation or publication is no longer published, BP Capital America shall calculate the Treasury Rate based on the rate per annum equal to the semi-annual equivalent yield to maturity at 11:00 a.m., New York City time, on the second business day preceding such redemption date of the United States Treasury security maturing on, or with a maturity that is closest to, the Par Call Date, as applicable. If there is no United States Treasury security maturing on the Par Call Date but there are two or more United States Treasury securities with a maturity date equally distant from the Par Call Date, one with a maturity date preceding the Par Call Date and one with a maturity date following the Par Call Date, BP Capital America shall select the United States Treasury security with a maturity date preceding the Par Call Date. If there are two or more United States Treasury securities maturing on the Par Call Date or two or more United States Treasury securities meeting the criteria of the preceding sentence, BP Capital America shall select from among these two or more United States Treasury securities the United States Treasury security that is trading closest to par based upon the average of the bid and asked prices for such United States Treasury securities at 11:00 a.m., New York City time. In determining the Treasury Rate in accordance with the terms of this paragraph, the semi-annual yield to maturity of the applicable United States Treasury security shall be based upon the average of the bid and asked prices (expressed as a percentage of principal amount) at 11:00 a.m., New York City time, of such United States Treasury security, and rounded to three decimal places.

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38 Notice of any redemption will be mailed or electronically delivered (or otherwise transmitted in accordance with the depositary's procedures) at least 10 days but not more than 60 days before the redemption date to each holder of 2033 notes to be redeemed. If less than all of the 2033 notes are to be redeemed, the 2033 notes to be redeemed shall be selected by the trustee by such method as the trustee deems to be fair and appropriate. For so long as the 2033 notes are held by DTC, Euroclear or Clearstream (or another depositary), the redemption of the 2033 notes shall be done in accordance with the policies and procedures of the depositary. Unless BP Capital America defaults in payment of the redemption price, on and after the redemption date interest will cease to accrue on the 2033 notes or portions thereof called for redemption. Neither the trustee nor the paying agent shall be responsible for calculating the redemption price. BP Capital America's actions and determinations in determining the redemption price shall be conclusive and binding for all purposes, absent manifest error. Once notice of redemption is sent, the 2033 notes called for redemption will become due and payable on the redemption date and at the applicable redemption price, plus accrued and unpaid interest to the redemption date, subject to any conditions precedent specified in such notice. Description of 4.893% Guaranteed Notes due 2033 The following terms are applicable to 4.893% Guaranteed Notes due 2033. • Issuer: BP Capital America • Title: 4.893% Guaranteed Notes due 2033 • Total principal amount outstanding: $1,500,000,000 • Issuance date: 11 May 2023 • Maturity date: 11 September 2033 • Interest rate: 4.893% per annum • Date interest starts accruing: 11 May 2023 • Interest payment dates: Each 11 March and 11 September, subject to the day count convention. • First interest payment date: 11 September 2023 • Optional redemption: Prior to 11 June 2033 (the date that is three months prior to the scheduled maturity date for the 2033 notes), BP Capital America has the right to redeem the 2033 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2033 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2033 notes to be redeemed that would be due if such notes matured on 11 June 2033 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 25 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 11 June 2033 (the date that is three months prior to the scheduled maturity

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39 date for the 2033 notes), BP Capital America has the right to redeem the 2033 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2033 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following are applicable. "Treasury Rate" means, with respect to any redemption date, the yield determined by BP Capital America in accordance with the following two paragraphs. (1) The Treasury Rate shall be determined by BP Capital America after 4:15 p.m., New York City time (or after such time as yields on U.S. government securities are posted daily by the Board of Governors of the Federal Reserve System), on the third business day preceding the redemption date based upon the yield or yields for the most recent day that appear after such time on such day in the most recent statistical release published by the Board of Governors of the Federal Reserve System designated as "Selected Interest Rates (Daily) - H.15" (or any successor designation or publication) ("H.15") under the caption "U.S. government securities–Treasury constant maturities–Nominal" (or any successor caption or heading). In determining the Treasury Rate, BP Capital America shall select, as applicable: (1) the yield for the Treasury constant maturity on H.15 exactly equal to the period from the redemption date to the Par Call Date (the "Remaining Life"); or (2) if there is no such Treasury constant maturity on H.15 exactly equal to the Remaining Life, the two yields – one yield corresponding to the Treasury constant maturity on H.15 immediately shorter than and one yield corresponding to the Treasury constant maturity on H.15 immediately longer than the Remaining Life – and shall interpolate to the Par Call Date on a straight-line basis (using the actual number of days) using such yields and rounding the result to three decimal places; or (3) if there is no such Treasury constant maturity on H.15 shorter than or longer than the Remaining Life, the yield for the single Treasury constant maturity on H.15 closest to the Remaining Life. For purposes of this paragraph, the applicable Treasury constant maturity or maturities on H.15 shall be deemed to have a maturity date equal to the relevant number of months or years, as applicable, of such Treasury constant maturity from the redemption date (2) If on the third business day preceding the redemption date H.15 or any successor designation or publication is no longer published, BP Capital America shall calculate the Treasury Rate based on the rate per annum equal to the semi-annual equivalent yield to maturity at 11:00 a.m., New York City time, on the second business day preceding such redemption date of the United States Treasury security maturing on, or with a maturity that is closest to, the Par Call Date, as applicable. If there is no United States Treasury security maturing on the Par Call Date but there are two or more United States Treasury securities with a maturity date equally distant from the Par Call Date, one with a maturity date preceding the Par Call Date and one with a maturity date following the Par Call Date, BP Capital America shall select the United States Treasury security with a maturity date preceding the Par Call Date. If there are two or more United States Treasury securities maturing on the Par Call Date or two or more United States Treasury securities meeting the criteria of the preceding sentence, BP Capital America shall select from among these two or more United States Treasury securities the United States Treasury security that is trading closest to par based upon the average of the bid and asked prices for such United States Treasury securities at 11:00 a.m., New York City time. In determining the Treasury Rate in accordance with the terms of this paragraph, the semi-annual yield to maturity of the applicable United States Treasury security shall be based upon the average of the bid

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40 and asked prices (expressed as a percentage of principal amount) at 11:00 a.m., New York City time, of such United States Treasury security, and rounded to three decimal places. Notice of any redemption will be mailed or electronically delivered (or otherwise transmitted in accordance with the depositary's procedures) at least 10 days but not more than 60 days before the redemption date to each holder of 2033 notes to be redeemed. If less than all of the 2033 notes are to be redeemed, the 2033 notes to be redeemed shall be selected by the trustee by such method as the trustee deems to be fair and appropriate. For so long as the 2033 notes are held by DTC, Euroclear or Clearstream (or another depositary), the redemption of the 2033 notes shall be done in accordance with the policies and procedures of the depositary. Unless BP Capital America defaults in payment of the redemption price, on and after the redemption date interest will cease to accrue on the 2033 notes or portions thereof called for redemption. Neither the trustee nor the paying agent shall be responsible for calculating the redemption price. BP Capital America's actions and determinations in determining the redemption price shall be conclusive and binding for all purposes, absent manifest error. Once notice of redemption is sent, the 2033 notes called for redemption will become due and payable on the redemption date and at the applicable redemption price, plus accrued and unpaid interest to the redemption date, subject to any conditions precedent specified in such notice. Description of 4.989% Guaranteed Notes due 2034 The following terms are applicable to the 4.989% Guaranteed Notes due 2034. • Issuer: BP Capital America • Title: 4.989% Guaranteed Notes due 2034 • Total principal amount outstanding: $1,000,000,000 • Issuance date: 10 January 2024 • Maturity date: 10 April 2034 • Interest rate: 4.989% per annum • Date interest starts accruing: 10 January 2024 • Interest payment dates: Each 10 April and 10 October, subject to the day count convention. • First interest payment date: 10 October 2024 • Optional redemption: Prior to 10 January 2034 (the date that is three months prior to the scheduled maturity date for the 2034 notes), BP Capital America has the right to redeem the 2034 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2034 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2034 notes to be redeemed that would be due if such notes matured on 10 January 2034 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption

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41 date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 15 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 10 January 2034 (the date that is three months prior to the scheduled maturity date for the 2034 notes), BP Capital America has the right to redeem the 2034 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2034 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following are applicable. "Treasury Rate" means, with respect to any redemption date, the yield determined by BP Capital America in accordance with the following two paragraphs. (1) The Treasury Rate shall be determined by BP Capital America after 4:15 p.m., New York City time (or after such time as yields on U.S. government securities are posted daily by the Board of Governors of the Federal Reserve System), on the third business day preceding the redemption date based upon the yield or yields for the most recent day that appear after such time on such day in the most recent statistical release published by the Board of Governors of the Federal Reserve System designated as "Selected Interest Rates (Daily) - H.15" (or any successor designation or publication) ("H.15") under the caption "U.S. government securities–Treasury constant maturities–Nominal" (or any successor caption or heading). In determining the Treasury Rate, BP Capital America shall select, as applicable: (1) the yield for the Treasury constant maturity on H.15 exactly equal to the period from the redemption date to the Par Call Date (the "Remaining Life"); or (2) if there is no such Treasury constant maturity on H.15 exactly equal to the Remaining Life, the two yields – one yield corresponding to the Treasury constant maturity on H.15 immediately shorter than and one yield corresponding to the Treasury constant maturity on H.15 immediately longer than the Remaining Life – and shall interpolate to the Par Call Date on a straight-line basis (using the actual number of days) using such yields and rounding the result to three decimal places; or (3) if there is no such Treasury constant maturity on H.15 shorter than or longer than the Remaining Life, the yield for the single Treasury constant maturity on H.15 closest to the Remaining Life. For purposes of this paragraph, the applicable Treasury constant maturity or maturities on H.15 shall be deemed to have a maturity date equal to the relevant number of months or years, as applicable, of such Treasury constant maturity from the redemption date. (2) If on the third business day preceding the redemption date H.15 or any successor designation or publication is no longer published, BP Capital America shall calculate the Treasury Rate based on the rate per annum equal to the semi-annual equivalent yield to maturity at 11:00 a.m., New York City time, on the second business day preceding such redemption date of the United States Treasury security maturing on, or with a maturity that is closest to, the Par Call Date, as applicable. If there is no United States Treasury security maturing on the Par Call Date but there are two or more United States Treasury securities with a maturity date equally distant from the Par Call Date, one with a maturity date preceding the Par Call Date and one with a maturity date following the Par Call Date, BP Capital America shall select the United States Treasury security with a maturity date preceding the Par Call Date. If there are two or more United States Treasury securities maturing on the Par Call Date or two or more United States Treasury securities meeting the criteria of the preceding sentence, BP Capital America shall select from among these two or more United States Treasury securities the United States Treasury security that is trading closest to par based upon the average of the bid and asked prices for such United States Treasury securities at 11:00 a.m., New York City time. In determining the Treasury

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42 Rate in accordance with the terms of this paragraph, the semi-annual yield to maturity of the applicable United States Treasury security shall be based upon the average of the bid and asked prices (expressed as a percentage of principal amount) at 11:00 a.m., New York City time, of such United States Treasury security, and rounded to three decimal places. Notice of any redemption will be mailed or electronically delivered (or otherwise transmitted in accordance with the depositary's procedures) at least 10 days but not more than 60 days before the redemption date to each holder of 2034 notes to be redeemed. If less than all of the 2034 notes are to be redeemed, the 2034 notes to be redeemed shall be selected by the trustee in accordance with its policies and procedures. For so long as the 2034 notes are held by DTC, Euroclear or Clearstream (or another depositary), the redemption of the 2034 notes shall be done in accordance with the policies and procedures of the depositary. Unless BP Capital America defaults in payment of the redemption price, on and after the redemption date interest will cease to accrue on the 2034 notes or portions thereof called for redemption. Neither the trustee nor the paying agent shall be responsible for calculating the redemption price. BP Capital America's actions and determinations in determining the redemption price shall be conclusive and binding for all purposes, absent manifest error. Once notice of redemption is sent, the 2034 notes called for redemption will become due and payable on the redemption date and at the applicable redemption price, plus accrued and unpaid interest to the redemption date, subject to any conditions precedent specified in such notice. Description of 5.227% Guaranteed Notes due 2034 The following terms are applicable to the 5.227% Guaranteed Notes due 2034. • Issuer: BP Capital America • Title: 5.227% Guaranteed Notes due 2034 • Total principal amount outstanding: $1,950,000,000 • Issuance date: 17 May 2024 (with respect to $1,000,000,000 aggregate principal amount of notes) and 25 November 2024 (with respect to $950,000,000 aggregate principal amount of notes) • Maturity date: 17 November 2034 • Interest rate: 5.227% per annum • Date interest starts accruing: 17 November 2024 • Interest payment dates: Each 17 May and 17 November, subject to the day count convention. • First interest payment date: 17 May 2025 • Optional redemption: Prior to 17 August 2034 (the date that is three months prior to the scheduled maturity date for the 2034 notes), BP Capital America has the right to redeem the 2034 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2034 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2034 notes to be

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43 redeemed that would be due if such notes matured on 17 August 2034 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 15 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 17 August 2034 (the date that is three months prior to the scheduled maturity date for the 2034 notes), BP Capital America has the right to redeem the 2034 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2034 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following are applicable. "Treasury Rate" means, with respect to any redemption date, the yield determined by BP Capital America in accordance with the following two paragraphs. (1) The Treasury Rate shall be determined by BP Capital America after 4:15 p.m., New York City time (or after such time as yields on U.S. government securities are posted daily by the Board of Governors of the Federal Reserve System), on the third business day preceding the redemption date based upon the yield or yields for the most recent day that appear after such time on such day in the most recent statistical release published by the Board of Governors of the Federal Reserve System designated as "Selected Interest Rates (Daily) - H.15" (or any successor designation or publication) ("H.15") under the caption "U.S. government securities–Treasury constant maturities–Nominal" (or any successor caption or heading). In determining the Treasury Rate, BP Capital America shall select, as applicable: (1) the yield for the Treasury constant maturity on H.15 exactly equal to the period from the redemption date to the Par Call Date (the "Remaining Life"); or (2) if there is no such Treasury constant maturity on H.15 exactly equal to the Remaining Life, the two yields – one yield corresponding to the Treasury constant maturity on H.15 immediately shorter than and one yield corresponding to the Treasury constant maturity on H.15 immediately longer than the Remaining Life – and shall interpolate to the Par Call Date on a straight-line basis (using the actual number of days) using such yields and rounding the result to three decimal places; or (3) if there is no such Treasury constant maturity on H.15 shorter than or longer than the Remaining Life, the yield for the single Treasury constant maturity on H.15 closest to the Remaining Life. For purposes of this paragraph, the applicable Treasury constant maturity or maturities on H.15 shall be deemed to have a maturity date equal to the relevant number of months or years, as applicable, of such Treasury constant maturity from the redemption date. (2) If on the third business day preceding the redemption date H.15 or any successor designation or publication is no longer published, BP Capital America shall calculate the Treasury Rate based on the rate per annum equal to the semi-annual equivalent yield to maturity at 11:00 a.m., New York City time, on the second business day preceding such redemption date of the United States Treasury security maturing on, or with a maturity that is closest to, the Par Call Date, as applicable. If there is no United States Treasury security maturing on the Par Call Date but there are two or more United States Treasury securities with a maturity date equally distant from the Par Call Date, one with a maturity date preceding the Par Call Date and one with a maturity date following the Par Call Date, BP Capital America shall select the United States Treasury security with a maturity date preceding the Par Call Date. If there are two or more United States Treasury securities maturing on the Par Call Date or two or more United States Treasury securities meeting the criteria of the preceding sentence, BP Capital America shall select from among these two or more United States Treasury securities the United States Treasury security that is

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![](a31122025bpxex2descripti044.jpg)

44 trading closest to par based upon the average of the bid and asked prices for such United States Treasury securities at 11:00 a.m., New York City time. In determining the Treasury Rate in accordance with the terms of this paragraph, the semi-annual yield to maturity of the applicable United States Treasury security shall be based upon the average of the bid and asked prices (expressed as a percentage of principal amount) at 11:00 a.m., New York City time, of such United States Treasury security, and rounded to three decimal places. Notice of any redemption will be mailed or electronically delivered (or otherwise transmitted in accordance with the depositary's procedures) at least 10 days but not more than 60 days before the redemption date to each holder of 2034 notes to be redeemed. If less than all of the 2034 notes are to be redeemed, the 2034 notes to be redeemed shall be selected by the trustee in accordance with its policies and procedures. For so long as the 2034 notes are held by DTC, Euroclear or Clearstream (or another depositary), the redemption of the 2034 notes shall be done in accordance with the policies and procedures of the depositary. Unless BP Capital America defaults in payment of the redemption price, on and after the redemption date interest will cease to accrue on the 2034 notes or portions thereof called for redemption. Neither the trustee nor the paying agent shall be responsible for calculating the redemption price. BP Capital America's actions and determinations in determining the redemption price shall be conclusive and binding for all purposes, absent manifest error. Once notice of redemption is sent, the 2034 notes called for redemption will become due and payable on the redemption date and at the applicable redemption price, plus accrued and unpaid interest to the redemption date, subject to any conditions precedent specified in such notice. Description of 3.060% Guaranteed Notes due 2041 The following terms are applicable to the 3.060% Guaranteed Notes due 2041. • Issuer: BP Capital America • Title: 3.060% Guaranteed Notes due 2041 • Total principal amount outstanding: $1,450,000,000 • Issuance date: 17 June 2021 • Maturity date: 17 June 2041 • Interest rate: 3.060% per annum • Date interest starts accruing: 17 June 2021 • Interest payment dates: Each 17 June and 17 December, subject to the day count convention. • First interest payment date: 17 December 2021 • Optional redemption: Prior to 17 December 2040 (the date that is six months prior to the scheduled maturity date for the 2041 notes), BP Capital America has the right to redeem the 2041 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2041 notes to be redeemed and (ii) the sum of

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45 the present values of the remaining scheduled payments of principal and interest on the 2041 notes to be redeemed that would be due if such notes matured on 17 December 2040 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 15 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 17 December 2040 (the date that is six months prior to the scheduled maturity date for the 2041 notes), BP Capital America has the right to redeem the 2041 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2041 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2041 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by BP Capital America. "Reference treasury dealer" means one of BofA Securities, Inc., Citigroup Global Markets Inc., Mizuho Securities USA LLC, Morgan Stanley & Co. LLC, SG Americas Securities, LLC or Wells Fargo Securities, LLC or one of their affiliates, which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 2.772% Guaranteed Notes due 2050 The following terms are applicable to the 2.772% Guaranteed Notes due 2050. • Issuer: BP Capital America • Title: 2.772% Guaranteed Notes due 2050 • Total principal amount outstanding: $1,500,000,000 • Issuance date: 10 August 2020 • Maturity date: 10 November 2050 • Interest rate: 2.772% per annum • Date interest starts accruing: 10 August 2020

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46 • Interest payment dates: Each 10 May and 10 November, subject to the day count convention. • First interest payment date: 10 May 2021 • Optional redemption: Prior to 10 May 2050 (the date that is six months prior to the scheduled maturity date for the 2050 notes), BP Capital America has the right to redeem the 2050 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2050 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2050 notes to be redeemed that would be due if such 2050 notes matured on 10 May 2050 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 25 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 10 May 2050 (the date that is six months prior to the scheduled maturity date for the 2050 notes), BP Capital America has the right to redeem the 2050 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2050 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2050 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such 2050 notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by BP Capital America. "Reference treasury dealer" means Citigroup Global Markets Inc., HSBC Securities (USA) Inc., J.P. Morgan Securities LLC, Mizuho Securities USA LLC and Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.000% Guaranteed Notes due 2050 The following terms are applicable to the 3.000% Guaranteed Notes due 2050. • Issuer: BP Capital America • Title: 3.000% Guaranteed Notes due 2050 • Total principal amount outstanding: $2,000,000,000

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47 • Issuance date: 24 February 2020 (with respect to $1,250,000,000 aggregate principal amount of notes) and 9 March 2020 (with respect to $750,000,000 aggregate principal amount of notes) • Maturity date: 24 February 2050 • Interest rate: 3.000% per annum • Date interest starts accruing: 24 February 2020 • Interest payment dates: Each 24 February and 24 August, subject to the day count convention. • First interest payment date: 24 August 2020 • Optional redemption: Prior to 24 August 2049 (the date that is six months prior to the scheduled maturity date for the notes), BP Capital America has the right to redeem the notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of 100% of the principal amount of the notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed that would be due if such notes matured on 24 August 2049 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 24 August 2049 (the date that is six months prior to the scheduled maturity date for the notes), BP Capital America has the right to redeem the notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by BP Capital America. "Reference treasury dealer" means Barclays Capital Inc., BofA Securities, Inc., Goldman Sachs & Co. LLC and Morgan Stanley & Co. LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.067% Guaranteed Notes due 2050

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48 • Issuer: BP Capital America • Title: 3.067% Guaranteed Notes due 2050 • Total principal amount outstanding: $1,426,000 • Issuance date: 13 December 2019 • Maturity date: 30 March 2050 • Interest rate: 3.067% per annum • Date interest starts accruing: 13 December 2019 • Interest payment dates: 30 March and 30 September of each year, subject to the day count convention. • First interest payment date: 30 March 2020 (short first coupon) • Redemption at the option of BP Capital America: On or after 31 March 2025 and prior to 30 September 2049 (the date that is six months prior to the scheduled maturity date for the notes), BP Capital America has the right to redeem the notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed that would be due if such notes matured on 30 September 2049 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 15 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 30 September 2049 (the date that is six months prior to the scheduled maturity date for the notes), BP Capital America has the right to redeem the notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semiannual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by BP Capital America "Reference treasury dealer" means Citigroup Global Markets Inc. or one of its affiliates, which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and its successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the

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49 bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. • Redemption at the option of the holder: Holders of the notes have the right to elect to have BP Capital America redeem the notes in whole or in part in increments of $1,000 on 30 March 2025 at a price equal to 94.022% of the principal amount of the notes to be redeemed together with accrued interest to such date. If the notes are held in book-entry form through DTC, then in order to exercise the option to redeem the notes, a beneficial holder of the notes must (i) instruct its direct or indirect participant through which it holds an interest in the notes to notify the trustee of its election to exercise its repayment option in accordance with the then-applicable operating procedures of DTC and (ii) provide an email notice of such holder's intention to exercise its option to redeem the notes to gtreasuryp54@bp.com. In order for the exercise of the option to be effective and the note to be repaid, such notice must be delivered to the trustee through DTC during the period from and including 30 January 2025 to and including the close of business on 28 February 2025 (or, if 28 February 2025 is not a business day, the next succeeding business day). DTC must receive any such notice from its participants in time to exercise such repayment option request in accordance with their applicable operating procedures and the terms of the notes. Different firms have different deadlines for accepting instructions from their customers. The beneficial holder should consult the direct or indirect participant through which it holds an interest in the notes to ascertain the deadline for ensuring that timely notice will be delivered to DTC. If the notes are not held in book-entry form, then in order for the exercise of the option to be effective and a note to be repaid, BP Capital America must receive, at the office of the trustee located at The Bank of New York Mellon Trust Company, N.A., 2 North LaSalle Street, Suite 700, Chicago, Illinois 60602 Attention: Corporate Trust Administration, with a copy (which shall not constitute notice) sent to gtreasuryp54@bp.com, during the period from and including 30 January 2025 to and including the close of business on 28 February 2025 (or, if 28 February 2025 is not a business day, the next succeeding business day), such note, together with the form entitled "Option to Elect Repayment" attached to such note duly completed. Exercise of the repayment option by the holder of a note shall be irrevocable. No transfer or of any note (or, in the event that any note is to be repaid in part, such portion of the note to be repaid) will be permitted after exercise of the repayment option. Description of 2.939% Guaranteed Notes due 2051 The following terms are applicable to the 2.939% Guaranteed Notes due 2051. • Issuer: BP Capital America • Title: 2.939% Guaranteed Notes due 2051 • Total principal amount outstanding: $2,250,000,000 • Issuance date: 4 December 2020 (with respect to $1,500,000,000 aggregate principal amount of notes) and 8 February 2021 (with respect to $750,000,000 aggregate principal amount of notes) • Maturity date: 4 June 2051 • Interest rate: 2.939% per annum • Date interest starts accruing: 4 December 2020

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50 • Interest payment dates: Each 4 June and 4 December, subject to the day count convention. • First interest payment date: 4 June 2021 • Optional redemption: Prior to 4 December 2050 (the date that is six months prior to the scheduled maturity date for the notes), BP Capital America has the right to redeem the notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed that would be due if such notes matured on 4 December 2050 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 4 December 2050 (the date that is six months prior to the scheduled maturity date for the notes), BP Capital America has the right to redeem the notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by BP Capital America. "Reference treasury dealer" means Barclays Capital Inc., BofA Securities, Inc., Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC or their affiliates, each of which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.001% Guaranteed Notes due 2052 The following terms are applicable to the 3.001% Guaranteed Notes due 2052. • Issuer: BP Capital America • Title: 3.001% Guaranteed Notes due 2052 • Total principal amount outstanding: $1,250,000,000 • Issuance date: 17 September 2021

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51 • Maturity date: 17 March 2052 • Interest rate: 3.001% per annum • Date interest starts accruing: 17 September 2021 • Interest payment dates: Each 17 March and 17 September, subject to the day count convention. • First interest payment date: 17 March 2022 • Optional redemption: Prior to 17 September 2051 (the date that is six months prior to the scheduled maturity date for the 2052 notes), BP Capital America has the right to redeem the 2052 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2052 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2052 notes to be redeemed that would be due if such notes matured on 17 September 2051 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 20 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 17 September 2051 (the date that is six months prior to the scheduled maturity date for the 2052 notes), BP Capital America has the right to redeem the 2052 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2052 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2052 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by BP Capital America. "Reference treasury dealer" means one of Barclays Capital Inc., Goldman Sachs & Co. LLC, HSBC Securities (USA) Inc., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC. and TD Securities (USA) LLC or one of their affiliates, which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 3.379% Guaranteed Notes due 2061 The following terms are applicable to the 3.379% Guaranteed Notes due 2061.

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52 • Issuer: BP Capital America • Title: 3.379% Guaranteed Notes due 2061 • Total principal amount outstanding: $2,050,000,000 • Issuance date: 8 February 2021 (with respect to $1,250,000,000 aggregate principal amount of notes), 17 June 2021 (with respect to $550,000,000 aggregate principal amount of notes) and 17 September 2021 (with respect to $250,000,000 aggregate principal amount of notes) • Maturity date: 8 February 2061 • Interest rate: 3.379% per annum • Date interest starts accruing: 8 February 2021 (with respect to $1,800,000,000 aggregate principal amount of notes issued on 8 February 2021 and 17 June 2021) and 8 August 2021 (with respect to $250,000,000 aggregate principal amount of notes issued on 8 August 2021) • Interest payment dates: Each 8 February and 8 August, subject to the day count convention. • First interest payment date: 8 August 2021. • Optional redemption: Prior to 8 August 2060 (the date that is six months prior to the scheduled maturity date for the 2061 notes), BP Capital America has the right to redeem the 2061 notes, in whole or in part, at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2061 notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2061 notes to be redeemed that would be due if such notes matured on 8 August 2060 (not including any portion of payments of interest accrued and unpaid to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the treasury rate plus 25 basis points, plus in either case accrued and unpaid interest to the date of redemption. On or after 8 August 2060 (the date that is six months prior to the scheduled maturity date for the 2061 notes), BP Capital America has the right to redeem the 2061 notes, in whole or in part, at any time and from time to time at a redemption price equal to 100% of the principal amount of the 2061 notes to be redeemed, plus accrued and unpaid interest, if any, thereon to, but excluding, the date of redemption. For purposes of determining the optional redemption price, the following definitions are applicable. "Treasury rate" means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity or interpolated (on a day count basis) of the comparable treasury issue, assuming a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date. "Comparable treasury issue" means the U.S. Treasury security or securities selected by the quotation agent as having an actual or interpolated maturity comparable to the remaining term of the 2061 notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes. "Comparable treasury

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53 price" means, with respect to any redemption date, the average of the reference treasury dealer quotations for such redemption date. "Quotation agent" means one of the reference treasury dealers appointed by BP Capital America. "Reference treasury dealer" means one of Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Goldman Sachs & Co. LLC., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC or NatWest Markets Securities Inc. or one of their affiliates, which is a primary U.S. government securities dealer in the United States (a "primary treasury dealer"), and their respective successors, and two other primary treasury dealers selected by BP Capital America, provided, however, that if any of the foregoing shall cease to be a primary treasury dealer, BP Capital America shall substitute therefor another primary treasury dealer. "Reference treasury dealer quotations" means with respect to each reference treasury dealer and any redemption date, the average, as determined by the quotation agent, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the quotation agent by such reference treasury dealer at 5:00 p.m. New York time on the third business day preceding such redemption date. Description of 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes The following terms are applicable to the 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes. • Issuer: BP Capital U.K. • Title: 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes • Total principal amount outstanding: $2,500,000,000 • Issuance date: 22 June 2020 • Maturity date: The notes are perpetual securities in respect of which there is no fixed redemption date. BP Capital U.K. shall only have the right to redeem, purchase or substitute or vary the notes in accordance with "—Optional Redemption on Interest Payment Date", "—Optional Redemption for Certain Events", "—Optional Tax Redemption", "—Substitution or Variation" as described in the applicable Prospectus Supplement or otherwise in accordance with the terms of the notes. • Ranking of the Notes: The notes are unconditional, unsecured and subordinated obligations of BP Capital U.K. and will rank pari passu without any preference among themselves and pari passu with any Parity Obligations of BP Capital U.K. but junior to any Senior Obligations of BP Capital U.K. and senior to the Ordinary Shares of BP Capital U.K. • To give effect to the intended ranking described above, if at any time a Winding-Up of BP Capital U.K. occurs (otherwise than for the purposes of a Solvent Reorganization of BP Capital U.K.), the amount payable by BP Capital U.K. to a Noteholder under or in relation to such noteholder's notes (in lieu of any other payment by BP Capital U.K. to such noteholder under or in relation to the notes, including pursuant to the terms of the notes or the Indenture) shall be the amount that would have been payable to such noteholder if, immediately prior to and throughout such Winding-Up, such noteholder was the holder of Notional Preference Shares in BP Capital U.K. For the purposes only of that calculation, in respect of each note and accrued but unpaid interest (including any outstanding Arrears of Interest in respect of such interest) a noteholder will be deemed to hold a Notional

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54 Preference Share in BP Capital U.K. entitling the holder thereof to receive in respect of such Notional Preference Share an amount in the Winding-Up of BP Capital U.K. that is equal to the principal amount of the relevant note and any accrued but unpaid interest and any outstanding Arrears of Interest in respect of such interest (without double counting) (and, in the case of an administration, on the same assumption that shareholders were entitled to claim and recover in respect of their shares to the same degree as in a Winding- Up). Amounts payable to the noteholders of the notes pursuant to this provision will only be paid after the debts owing to the holders of the Senior Obligations of BP Capital U.K. have been paid in full. The subordination provisions applicable to the notes will be governed by English law. • "Winding-Up" means an order being made, or an effective resolution being passed, for the winding-up of BP Capital U.K. or BP, as the case may be, or an administrator of BP Capital U.K. or BP, as the case may be, being appointed and such administrator giving notice that it intends to declare and distribute a dividend. • Ranking of the Guarantee: The payment of the principal of and interest on the notes is fully guaranteed by BP. The obligations of BP under the Guarantee are unconditional, unsecured and subordinated and the rights and claims of noteholders will rank pari passu without any preference among themselves and pari passu with any Parity Obligations of BP but junior to any Senior Obligations of BP and senior to the Ordinary Shares of BP. • To give effect to the intended ranking described above, if at any time a Winding-Up of BP occurs (otherwise than for the purposes of a Solvent Reorganization of BP), the amount payable by BP to a noteholder under or in relation to the Guarantee (in lieu of any other payment by BP to such noteholder under or in relation to the Guarantee), shall be the amount that would have been payable to such noteholder if, immediately prior to and throughout such Winding-Up, such noteholder was the holder of Notional Preference Shares in BP. For the purposes only of that calculation, in respect of each note and accrued but unpaid interest (including any outstanding Arrears of Interest in respect of such interest payment) a noteholder will be deemed to hold a Notional Preference Share in BP entitling the holder thereof to receive in respect of such Notional Preference Share an amount in the Winding-Up of BP that is equal to the principal amount of the relevant note and any accrued but unpaid interest and any outstanding Arrears of Interest in respect of such interest (without double counting) (and, in the case of an administration, on the assumption that the shareholders were entitled to claim and recover in respect of their shares to the same degree as in a Winding-Up). For the purpose of construing the provisions of the Guarantee and BP's payment obligations in respect thereof, the latter amounts shall be treated as due and payable by the Issuer on the date such Winding-Up order of BP Capital U.K. is made or such resolution is passed or notice is given, as the case may be and, consequently, a claim under the Guarantee in respect of such amount may be made on, or at any time after, such date. Amounts payable to the noteholder upon Winding-Up will only be paid after the debts owing to the holders of the Senior Obligations of BP have been paid in full. The subordination provisions applicable to the Guarantee will be governed by English law. • Deferral of Interest: BP Capital U.K. may elect, in its sole discretion, to defer payment of the amount of interest (in whole or in part) (a "Deferred Interest Payment") due on any Interest Payment Date in respect of the notes. Such Deferred Interest Payments will accrue additional interest at the relevant interest rate prevailing from time to time (which will also be added to any Deferred Interest Payments on each subsequent Interest Payment Date and accrue interest in the same manner). Any such deferred payments and any additional interest thereon are referred to as "Arrears of Interest".

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55 BP Capital U.K. must pay Arrears of Interest in respect of the relevant notes upon the date for redemption of all the relevant notes or in certain other limited circumstances. • Interest rate: (a) 4.875% per annum, for the period from (and including) the Issue Date to (but excluding) the relevant First Reset Date and (b) from (and including) the relevant First Reset Date, at an Interest Rate per annum equal to the relevant Reset Interest Rate, in each case on the outstanding principal amount of the Notes. • Reset Date: The Reset Dates will be (a) the relevant First Reset Date and (b) each date that falls five, or a multiple of five, years following the relevant First Reset Date. • First Reset Date: The First Reset Date will be 22 June 2030. • Reset Determination Date: The Reset Determination Date will be the day falling two Business Days prior to the relevant Reset Date. • Reset Interest Rate: The Reset Interest Rate, in relation to any Reset Period, is the sum of the relevant Five-Year Treasury Rate, calculated as provided for in the relevant Prospectus Supplement, in relation to that Reset Period plus the Margin applicable to that Reset Period. • Reset Period: The period from (and including) the relevant First Reset Date to (but excluding) the next relevant Reset Date, and each successive period from (and including) a Reset Date to (but excluding) the next succeeding Reset Date. • Date interest starts accruing: 22 June 2020 • Interest payment dates: Each 22 June and 22 December, subject to the day count convention and the Optional Interest Deferral described in the relevant Prospectus Supplement. • Interest Periods: The period beginning on (and including) the Issue Date and ending on (but excluding) the first Interest Payment Date and each successive period beginning on (and including) an Interest Payment Date and ending on (but excluding) the next succeeding Interest Payment Date. • First interest payment date: 22 December 2020 • Interest Amount: Subject to Optional Interest Deferral, the amount of interest payable in respect of the Calculation Amount on each Interest Payment Date to (and including) the relevant First Reset Date shall be, with respect to the Non-Call 10 Notes, $24.38. Subject to Optional Interest Deferral, the amount of interest payable in respect of the Calculation Amount for any other period for which interest is to be calculated shall be calculated by: • applying the applicable Interest Rate to the Calculation Amount; • multiplying the product thereof by the Day Count Fraction; and • rounding the resulting figure to the nearest cent (half a cent being rounded upwards). • The relevant amount of interest payable in respect of the notes for any period shall be the product of: (i) the relevant amount of interest per Calculation Amount determined as

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56 described above; and (ii) the number by which the Calculation Amount is required to be multiplied to equal the principal amount of the notes. • "Calculation Amount" means $1,000. • "Day Count Fraction" means 30/360. Where it is necessary to calculate an amount of interest in respect of any Note for a period which is less than or equal to a complete Interest Period, such interest shall be calculated on the basis of a 360-day year consisting of 12 months of 30 days each and, in the case of an incomplete month, the number of days elapsed. • Optional redemption: Subject to applicable laws, BP Capital U.K. may, by giving not less than 10 nor more than 60 days' notice to the Trustee and the relevant Noteholders in accordance with the notice provisions set forth in the Indenture (which notice shall be irrevocable), redeem the relevant notes (in whole but not in part) on the First Call Date, which shall be 22 March 2030, and on any day thereafter to (and including) the First Reset Date, which shall be 22 June 2030, or on any Interest Payment Date thereafter, at their outstanding principal amount plus any accrued but unpaid interest up to (but excluding) the relevant Redemption Date and any outstanding Arrears of Interest (without double counting). • Outstanding Liabilities: As of 31 December 2020 the total finance debt and lease liabilities of the BP group, all of which would rank senior to the notes and the related guarantee upon liquidation, equaled approximately $81,926,000,000 in aggregate principal amount. This does not include obligations of the subsidiaries of BP (other than BP Capital Markets U.K.), to which the obligations of BP under the Guarantee are structurally subordinated. As of 31 December 2020, BP had outstanding 5,473,414 cumulative second preference shares of £1 each, which will rank as Parity Obligations to the Guarantee as of the Issue Date. As of 31 December 2020, BP also had outstanding 7,232,838 cumulative first preference shares of £1 each, which will rank as Senior Obligations to the Guarantee as of the Issue Date. • Limitations on the Issuance of Additional Senior Indebtedness: None of the notes, the guarantee or the indenture under which the notes were issued restrict BP Capital U.K. or BP from issuing additional securities (including preference shares or other equity securities) which will be deemed Parity Obligations or Senior Obligations of the notes and Guarantee, as applicable. • Substitution or Variation: If a Rating Agency Event, an Accounting Event, a Tax Deduction Event or an event that permits an Optional Tax Redemption to occur (a "Substitution or Variation Event") has occurred and is continuing, then BP Capital U.K. or BP may, as an alternative to redemption, subject to the conditions set forth under "—Conditions to Special Event Redemption and Substitution or Variation" in the applicable Prospectus Supplement (without any requirement for the consent or approval of the Noteholders) and subject to the Trustee, immediately prior to the giving of any notice referred to herein, having received an officers' certificate and an opinion of counsel (each as defined in the Indenture), each stating to the effect that the provisions of this section have been complied with, and having given not less than 10 nor more than 60 days' notice to the Trustee, the Calculation Agent and the relevant Noteholders (which notice shall be irrevocable), at any time either (i) substitute all, but not less than all, of the relevant notes for, or (ii) vary the terms of the relevant notes with the effect that they remain or become (as the case may be), Qualifying Securities, and the Noteholders shall be bound by such substitution or variation. Upon expiry of such notice, BP Capital U.K. or BP will either vary the terms of or, as the case may be, substitute the relevant notes in accordance with this section. In connection with the substitution of Qualifying Securities for the relevant notes or the variation of the terms of the relevant notes,

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57 each Noteholder by the purchase of the relevant notes authorizes the Trustee to, and the Trustee shall, authenticate such new notes in accordance with Section 303 of the Indenture. In connection with any substitution or variation in accordance with this section, BP Capital U.K. will comply with the rules of any stock exchange on which the relevant notes are for the time being listed or admitted to trading. Any such substitution or variation in accordance with the foregoing provisions following a Substitution or Variation Event shall only be permitted if it does not give rise to any other Substitution or Variation Event with respect to the Qualifying Securities. Any such substitution or variation in accordance with the foregoing provisions following a Substitution or Variation Event shall only be permitted if it does not result in the Qualifying Securities no longer being eligible for the same, or a higher amount of, "equity credit" (or such other nomenclature that the Rating Agency may then use to describe the degree to which an instrument exhibits the characteristics of an ordinary share) as is attributed to the relevant notes on the date notice is given to Noteholders of the substitution or variation. In no event shall the Trustee have any responsibility whatsoever to determine whether any such substitution or variation results in the Qualifying Securities. Any such substitution or variance could have unexpected commercial consequences depending on the circumstances of an individual Noteholder, and we will consider the impact on the class of Noteholders taken as a whole and are not required to take into account the individual circumstances of each Noteholder. "Qualifying Securities" means securities that contain terms not materially less favorable to the class of Noteholders of the Non-Call 5.25 Notes or Non-Call 10 Notes, as the case may be, and in each case taken as a whole, than the terms of the respective notes (as reasonably determined by BP Capital U.K. (in consultation with an independent investment bank or counsel of international standing)) and provided that an officers' certificate to such effect (and confirming that the conditions set out in (a) to (j) below have been satisfied) shall have been delivered to the Trustee prior to the substitution or variation of the relevant notes upon which certificate the Trustee shall rely absolutely). Such Qualifying Securities: a) shall be issued by (x) BP Capital U.K. (or any successor thereto as issuer of the relevant notes) with a guarantee of BP (or any successor thereto as guarantor of the relevant notes), (y) BP or (z) a wholly owned direct or indirect finance subsidiary of BP with a guarantee of BP (or any successor thereto as guarantor of the relevant notes); and b) (and/or, as appropriate, the guarantee as aforesaid) shall rank pari passu on a Winding-Up of BP Capital U.K. (or any successor thereto as issuer of the relevant notes) with the relevant notes or on a Winding-Up of BP (or any successor thereto as guarantor of the relevant notes) with the Guarantee; and c) shall contain terms which provide for the same or a more favorable Interest Rate from time to time applying to the relevant notes and preserve the same Interest Payment Dates; and d) shall preserve the obligations (including the obligations arising from the exercise of any right) of BP Capital U.K. (or any successor thereto as issuer of the relevant notes) as to redemption of the relevant notes, including (without limitation) as to timing of, and amounts payable upon, such redemption; and e) shall preserve any existing rights under the terms of the relevant notes to any accrued interest, any Deferred Interest Payments, any Arrears of Interest and any other amounts payable under the relevant notes which, in each case, has accrued to Noteholders and not been paid; and

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58 f) shall not contain terms providing for loss absorption through principal write-down or conversion to ordinary shares; and g) shall otherwise contain substantially identical terms (as reasonably determined by BP Capital U.K. (or any successor thereto as issuer of the relevant notes)) to the relevant notes, save where (without prejudice to the requirement that the terms are not materially less favorable to the class of relevant Noteholders taken as a whole than the terms of the relevant notes as described above) any modifications to such terms are required to be made to avoid the occurrence or effect of a Rating Agency Event, an Accounting Event, a Tax Deduction Event or an event that permits an Optional Tax Redemption to occur; and h) shall, immediately after such substitution or variation, be assigned at least the same credit rating(s) by the same Rating Agencies as may have been assigned to the relevant notes at the invitation of or with the consent of BP Capital U.K. (or any successor thereto as issuer of the relevant notes) immediately prior to such substitution or variation; and i) shall not provide for the mandatory deferral or cancellation of payments of interest and/or principal; and j) shall be (x) listed on the Official List and admitted to trading on the London Stock Exchange plc's Main Market or (y) listed on such other stock exchange as is a Recognised Stock Exchange at that time or admitted to trading on a Multilateral Trading Facility as selected by BP Capital U.K (or any successor thereto as issuer of the relevant notes). For the purposes of the definition of Qualifying Securities: "Multilateral Trading Facility" means a multilateral trading facility described in section 987(1)(b) of the Income Tax Act 2007 of the United Kingdom, as the same may be amended from time to time and any provision, statute or statutory instrument replacing the same from time to time; "Official List" means the Official List of the Financial Conduct Authority in its capacity as competent authority under the Financial Services and Markets Act 2000 of the United Kingdom (as the same may be amended from time to time and any provision, statute or statutory instrument replacing the same from time to time); and "Recognised Stock Exchange" means a recognised stock exchange as defined in section 1005 of the Income Tax Act 2007 of the United Kingdom as the same may be amended from time to time and any provision, statute or statutory instrument replacing the same from time to time. • Events of Default Provisions • An Event of Default under the relevant notes occurs only in the event of a Winding-Up of BP Capital U.K. or BP other than for the purposes of a Solvent Reorganization of BP Capital U.K. or BP. If, for a period of 30 days or more, BP Capital U.K. or BP are in default in the payment of any principal or interest (including any Arrears of Interest) in respect of the relevant notes which is due and payable (a "Payment Default"), then BP Capital U.K. and/or BP, as the case may be, will be deemed to be in default under the Indenture and the relevant notes, and the Trustee may, and if instructed by the holders as described in "—

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59 Entitlement of the Trustee" below shall, take such actions as set forth under "— Proceedings" or "—Enforcement" below to institute actions, steps or proceedings for the Winding-Up of BP Capital U.K. and/or BP. For the avoidance of doubt, a Payment Default is not an Event of Default and shall not result in any right of Acceleration pursuant to Section 502 of the Indenture. • Proceedings: If a Payment Default occurs and is continuing, then BP Capital U.K. or BP, as the case may be, shall, without notice from the Trustee, be deemed to be in default under the Indenture and the relevant notes and (subject to the provisions set forth below) the Trustee may, and if instructed by the holders as described in "—Entitlement of the Trustee" below shall, institute actions, steps or proceedings for the Winding-Up of BP Capital U.K. and/or BP and/or prove in the Winding-Up of BP Capital U.K. and/or BP and/or claim in the liquidation or administration of BP Capital U.K. and/or BP, such claim being subordinated, and for the amount, as provided in "—Subordination and Waiver of Set-off Provisions". • Enforcement: Without prejudice to "—Proceedings" and subject to the provisions set forth below, the Trustee may, and if instructed by the holders as described in "—Entitlement of the Trustee" below shall, at any time and without further notice, institute such proceedings or take such steps or actions against BP Capital U.K. and/or BP as it may think fit to enforce any term or condition binding on BP Capital U.K. and/or BP under the Indenture or the relevant notes, but in no event shall BP Capital U.K. and/or BP, by virtue of the institution of any such proceedings, steps or actions, be obliged to pay any sum or sums in cash or otherwise, sooner than the same would otherwise have been payable by it under the Indenture or the relevant notes. • Entitlement of Trustee: The Trustee shall not be bound to take any of the actions referred to in the provisions set forth under "— Proceedings" or "—Enforcement" above against BP Capital U.K. and/or BP to enforce the terms of the Indenture or the relevant notes at the request of the Noteholders or take any other action or step under or pursuant to the terms of the relevant notes or the Indenture unless (i) it shall have been so requested in writing by the Noteholders of at least 25% in principal amount of the relevant notes then outstanding and (ii) it shall have been indemnified and/or secured and/or prefunded by the relevant Noteholders to its satisfaction. However, if a Payment Default or an Event of Default has occurred and is continuing, the Trustee shall exercise such of the rights and powers vested in it by the Indenture, and use the same degree of care and skill in their exercise, as a prudent person would exercise or use under the circumstances in the conduct of his or her own affairs. The Trustee shall not be liable with respect to any action taken or omitted to be taken by it in good faith in accordance with the request of the Noteholders of at least 25% in principal amount of the relevant notes then outstanding. • Right of Noteholders: No Noteholder shall be entitled to proceed directly against BP Capital U.K. or BP or to institute proceedings for the Winding-Up or claim in the liquidation of BP Capital U.K. or BP or to prove in such Winding-Up unless the Trustee, having become so bound to proceed, institute, prove or claim, fails to do so within a 60 day period and such failure shall be continuing, in which case the Noteholder shall have only such rights against BP Capital U.K. or BP as those which the Trustee is entitled to exercise as set out in this section. • Extent of Noteholders' Remedy: No remedy against BP Capital U.K. or BP, other than as referred to in the relevant prospectus supplement, shall be available to the Trustee or the

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60 Noteholders, whether for the recovery of amounts owing in respect of the relevant notes or under the Indenture or in respect of any breach by BP Capital U.K. or BP of any of their other obligations under or in respect of the relevant notes or under the Indenture. For the avoidance of doubt, nothing in the foregoing shall (i) prevent the Trustee from proving in any Winding-Up (otherwise than for the purposes of a Solvent Reorganization of BP Capital U.K. or BP, as the case may be) or administration of BP Capital U.K. or BP and/or claiming in any liquidation of BP Capital U.K. or BP (even if not instituted by the Trustee), or (ii) impair the right of any Noteholder to receive payment of principal, premium or interest (including Arrears of Interest) on such noteholder's notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such noteholder's notes. • Defined Terms: The following definitions shall apply to subordination of the notes and subordination of the guarantee provisions: • "Notional Preference Shares" means, with respect to BP Capital U.K. or BP, as the case may be, a notional class of preference shares in the capital of BP Capital U.K. or BP, as the case may be: (i) ranking junior to the claims of all holders of Senior Obligations of BP Capital U.K. or BP, as the case may be; (ii) having an equal right to return of assets in the Winding-Up of BP Capital U.K. or BP, as the case may be, and so ranking pari passu with any Parity Obligations of BP Capital U.K. or BP, as the case may be; and (iii) having a right to return of capital ahead of, and so ranking ahead of, the claims of holders of the Ordinary Shares of BP Capital U.K. or BP, as the case may be. • "Parity Obligations" means, with respect to BP Capital U.K. or BP, as the case may be: (a) the most junior class of preference share capital of BP Capital U.K. or BP, as the case may be; and (b) any other security, guarantee or other instrument issued by, or any other obligation of BP Capital U.K. or BP, as the case may be, which ranks or is expressed to rank pari passu with BP Capital U.K.'s obligations under the Notes or BP's obligations under the Guarantee, including the Other Hybrid Capital Notes. • "Ordinary Shares" means (i) any ordinary shares in the capital of BP Capital U.K. or BP, as the case may be, or (ii) any present or future shares of any other class of shares of BP Capital U.K. or BP, as the case may be, ranking pari passu with the ordinary shares of BP Capital U.K. or BP, as the case may be or, in either case, any depository or other receipts or certificates, including American depositary receipts representing such shares. • "Senior Obligations" means all obligations of BP Capital U.K. or BP, as the case may be, but excluding any Parity Obligations and any Ordinary Shares of BP Capital U.K. or BP, as the case may be. Description of 6.125% Perpetual Subordinated Fixed Rate Reset Notes The following terms are applicable to the 6.125% Perpetual Subordinated Fixed Rate Reset Notes. • Issuer: BP Capital U.K. • Title: 6.125% Perpetual Subordinated Fixed Rate Reset Notes • Total principal amount outstanding: $1,250,000,000

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61 • Issuance date: 18 November 2024 • Maturity date: The notes are perpetual securities in respect of which there is no fixed redemption date. BP Capital U.K. shall only have the right to redeem, purchase or substitute or vary the notes in accordance with "—Optional Redemption on Interest Payment Date", "—Optional Redemption for Certain Events", "—Optional Tax Redemption", "—Optional Clean-Up Redemption", "— Substitution or Variation" as described in the applicable Prospectus Supplement or otherwise in accordance with the terms of the notes. • Ranking of the Notes: The notes are unconditional, unsecured and subordinated obligations of BP Capital U.K. and will rank pari passu without any preference among themselves and pari passu with any Parity Obligations of BP Capital U.K. but junior to any Senior Obligations of BP Capital U.K. and senior to the Ordinary Shares of BP Capital U.K. • To give effect to the intended ranking described above, if at any time a Winding-Up of BP Capital U.K. occurs (otherwise than for the purposes of a Solvent Reorganization of BP Capital U.K.), the amount payable by BP Capital U.K. to a noteholder under or in relation to such noteholder's notes (in lieu of any other payment by BP Capital U.K. to such noteholder under or in relation to the notes, including pursuant to the terms of the notes or the Indenture) shall be the amount that would have been payable to such noteholder if, immediately prior to and throughout such Winding-Up, such noteholder was the holder of Notional Preference Shares in BP Capital U.K. For the purposes only of that calculation, in respect of each Note and accrued but unpaid interest (including any outstanding Arrears of Interest in respect of such interest) a noteholder will be deemed to hold a Notional Preference Share in BP Capital U.K. entitling the holder thereof to receive in respect of such Notional Preference Share an amount in the Winding-Up of BP Capital U.K. that is equal to the principal amount of the relevant note and any accrued but unpaid interest and any outstanding Arrears of Interest in respect of such interest (without double counting) (and, in the case of an administration, on the same assumption that shareholders were entitled to claim and recover in respect of their shares to the same degree as in a Winding- Up). Amounts payable to the noteholders of the notes pursuant to this provision will only be paid after the debts owing to the holders of the Senior Obligations of BP Capital U.K. have been paid in full. The subordination provisions applicable to the notes will be governed by English law. • "Winding-Up" means an order being made, or an effective resolution being passed, for the winding-up of BP Capital U.K. or BP, as the case may be, or an administrator of BP Capital U.K. or BP, as the case may be, being appointed and such administrator giving notice that it intends to declare and distribute a dividend. • Ranking of the Guarantee: The payment of the principal of and interest on the notes is fully guaranteed by BP. The obligations of BP under the Guarantee are unconditional, unsecured and subordinated and the rights and claims of noteholders will rank pari passu without any preference among themselves and pari passu with any Parity Obligations of BP but junior to any Senior Obligations of BP and senior to the Ordinary Shares of BP. • To give effect to the intended ranking described above, if at any time a Winding-Up of BP occurs (otherwise than for the purposes of a Solvent Reorganization of BP), the amount payable by BP to a noteholder under or in relation to the Guarantee (in lieu of any other payment by BP to such noteholder under or in relation to the Guarantee), shall be the amount that would have been payable to such noteholder if, immediately prior to and

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62 throughout such Winding-Up, such noteholder was the holder of Notional Preference Shares in BP. For the purposes only of that calculation, in respect of each note and accrued but unpaid interest (including any outstanding Arrears of Interest in respect of such interest payment) a noteholder will be deemed to hold a Notional Preference Share in BP entitling the holder thereof to receive in respect of such Notional Preference Share an amount in the Winding-Up of BP that is equal to the principal amount of the relevant note and any accrued but unpaid interest and any outstanding Arrears of Interest in respect of such interest (without double counting) (and, in the case of an administration, on the assumption that the shareholders were entitled to claim and recover in respect of their shares to the same degree as in a Winding-Up). For the purpose of construing the provisions of the Guarantee and BP's payment obligations in respect thereof, the latter amounts shall be treated as due and payable by the Issuer on the date such Winding-Up order of BP Capital U.K. is made or such resolution is passed or notice is given, as the case may be and, consequently, a claim under the Guarantee in respect of such amount may be made on, or at any time after, such date. Amounts payable to the noteholder upon Winding-Up will only be paid after the debts owing to the holders of the Senior Obligations of BP have been paid in full. The subordination provisions applicable to the Guarantee will be governed by English law. • Deferral of Interest: BP Capital U.K. may elect, in its sole discretion, to defer payment of the amount of interest (in whole or in part) (a "Deferred Interest Payment") due on any Interest Payment Date in respect of the notes. Such Deferred Interest Payments (as defined herein) will accrue additional interest at the relevant interest rate prevailing from time to time (which will also be added to any Deferred Interest Payments on each subsequent Interest Payment Date and accrue interest in the same manner). Any such deferred payments and any additional interest thereon are referred to as "Arrears of Interest". BP Capital U.K. must pay Arrears of Interest in respect of the relevant notes upon the date for redemption of all the relevant notes or in certain other limited circumstances. • Interest rate: (a) 6.125% per annum, for the period from (and including) the Issue Date to (but excluding) the relevant First Reset Date and (b) from (and including) the relevant First Reset Date, at an Interest Rate per annum equal to the relevant Reset Interest Rate, in each case on the outstanding principal amount of the notes. • Reset Date: The Reset Dates will be (a) the relevant First Reset Date and (b) each date that falls five, or a multiple of five, years following the relevant First Reset Date. • First Reset Date: The First Reset Date will be 18 June 2035. • Reset Determination Date: The Reset Determination Date will be the day falling two Business Days prior to the relevant Reset Date. • Reset Interest Rate: The Reset Interest Rate, in relation to any Reset Period, is the sum of the relevant Five-Year Treasury Rate, calculated as provided for in the relevant Prospectus Supplement, in relation to that Reset Period plus the Margin applicable to that Reset Period. • Reset Period: The period from (and including) the relevant First Reset Date to (but excluding) the next relevant Reset Date, and each successive period from (and including) a Reset Date to (but excluding) the next succeeding Reset Date. • Date interest starts accruing: 18 November 2024

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63 • Interest payment dates: Each 18 June and 18 December, subject to the day count convention and the Optional Interest Deferral described in the relevant Prospectus Supplement. • Interest Periods: The period beginning on (and including) the Issue Date and ending on (but excluding) the first Interest Payment Date and each successive period beginning on (and including) an Interest Payment Date and ending on (but excluding) the next succeeding Interest Payment Date. • First interest payment date: 18 June 2025 (and thus a long first interest period) • Interest Amount: Subject to Optional Interest Deferral, the amount of interest payable in respect of the Calculation Amount (a) on the First Interest Payment Date shall be $35.73 and (b) on each Interest Payment Date to (and including) the First Reset Date shall be $30.63. Subject to Optional Interest Deferral, the amount of interest payable in respect of the Calculation Amount for any other period for which interest is to be calculated shall be calculated by: • applying the applicable Interest Rate to the Calculation Amount; • multiplying the product thereof by the Day Count Fraction; and • rounding the resulting figure to the nearest cent (half a cent being rounded upwards). • The relevant amount of interest payable in respect of the notes for any period shall be the product of: (i) the relevant amount of interest per Calculation Amount determined as described above; and (ii) the number by which the Calculation Amount is required to be multiplied to equal the principal amount of the notes. • "Calculation Amount" means $1,000. • "Day Count Fraction" means 30/360. Where it is necessary to calculate an amount of interest in respect of any Note for a period which is less than or equal to a complete Interest Period, such interest shall be calculated on the basis of a 360-day year consisting of 12 months of 30 days each and, in the case of an incomplete month, the number of days elapsed. • Optional redemption: Subject to applicable laws, BP Capital U.K. may, by giving not less than 10 nor more than 60 days' notice to the Trustee and the relevant noteholders in accordance with the notice provisions set forth in the Indenture (which notice shall be irrevocable), redeem the relevant notes (in whole but not in part) on the First Call Date and on any day thereafter to (and including) the First Reset Date, or on any Interest Payment Date thereafter, at their outstanding principal amount plus any accrued but unpaid interest up to (but excluding) the relevant Redemption Date and any outstanding Arrears of Interest (without double counting). • Optional Clean-Up Redemption: On the giving of not less than 10 nor more than 60 days' notice to the Trustee and the relevant holders in accordance with the notice provisions set forth in the indenture (which notice shall be irrevocable), the notes may be redeemed or purchased and cancelled at the option of BP Capital U.K. (in whole but not in part) at a redemption amount equal to 100% of the principal amount of the notes plus accrued and unpaid interest up to (but excluding) the relevant Redemption Date and any outstanding Arrears of Interest (without double counting) if 75% or more in initial aggregate principal amount of the notes (which for these purposes, shall

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64 include any additional notes issued pursuant to "Further Issuances") have previously been redeemed or purchased and cancelled. • Outstanding Liabilities: As of 30 September 2024, BP had outstanding 5,473,414 cumulative second preference shares of £1 each, which will rank as Parity Obligations to the Guarantee as of the Issue Date. As of 30 September 2024, BP also had outstanding 7,232,838 cumulative first preference shares of £1 each, which will rank as Senior Obligations to the Guarantee as of the Issue Date. • Limitations on the Issuance of Additional Senior Indebtedness: None of the notes, the guarantee or the indenture under which the notes were issued restrict BP Capital U.K. or BP from issuing additional securities (including preference shares or other equity securities) which will be deemed Parity Obligations or Senior Obligations of the notes and Guarantee, as applicable. • Substitution or Variation: If a Rating Agency Event, an Accounting Event, a Tax Deduction Event or an event that permits an Optional Tax Redemption to occur (a "Substitution or Variation Event") has occurred and is continuing, then BP Capital U.K. or BP may, as an alternative to redemption, subject to the conditions set forth under "—Conditions to Special Event Redemption and Substitution or Variation" in the applicable Prospectus Supplement (without any requirement for the consent or approval of the noteholders) and subject to the Trustee, immediately prior to the giving of any notice referred to herein, having received an officers' certificate and an opinion of counsel (each as defined in the Indenture), each stating to the effect that the provisions of this section have been complied with, and having given not less than 10 nor more than 60 days' notice to the Trustee, the Calculation Agent and the relevant noteholders (which notice shall be irrevocable), at any time either (i) substitute all, but not less than all, of the notes for, or (ii) vary the terms of the notes with the effect that they remain or become (as the case may be), Qualifying Securities, and the noteholders shall be bound by such substitution or variation. Upon expiry of such notice, BP Capital U.K. or BP will either vary the terms of or, as the case may be, substitute the notes in accordance with this section. In connection with the substitution of Qualifying Securities for the notes or the variation of the terms of the notes, each noteholder by the purchase of the notes authorizes the Trustee to, and the Trustee shall, authenticate such new notes in accordance with Section 303 of the Indenture. In connection with any substitution or variation in accordance with this section, BP Capital U.K. will comply with the rules of any stock exchange on which the notes are for the time being listed or admitted to trading. Any such substitution or variation in accordance with the foregoing provisions following a Substitution or Variation Event shall only be permitted if it does not give rise to any other Substitution or Variation Event with respect to the Qualifying Securities. Any such substitution or variation in accordance with the foregoing provisions following a Substitution or Variation Event shall only be permitted if it does not result in the Qualifying Securities not being or no longer being (as the case may be) eligible for the same, or a higher amount of, "equity credit" (or such other nomenclature that the Rating Agency may then use to describe the degree to which an instrument exhibits the characteristics of an ordinary share) as is attributed to the notes on the date notice is given to noteholders of the substitution or variation. In no event shall the Trustee have any responsibility whatsoever to determine whether any such substitution or variation results in the Qualifying Securities. Any such substitution or variation could have unexpected commercial consequences depending on the circumstances of an individual noteholder, and we will consider the impact on the class of noteholders taken as a whole and are not required to take into account the individual circumstances of each noteholder. "Qualifying Securities" means securities that contain terms not materially less favorable to the class of noteholders of the notes, as the case may be, and in each case taken as a whole, than the terms

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65 of the respective notes (as reasonably determined by BP Capital U.K. (in consultation with an independent investment bank or counsel of international standing)) and provided that an officers' certificate to such effect (and confirming that the conditions set out in (a) to (j) below have been satisfied) shall have been delivered to the Trustee prior to the substitution or variation of the notes upon which certificate the Trustee shall rely absolutely). Such Qualifying Securities: a) shall be issued by (x) BP Capital U.K. (or any successor thereto as issuer of the notes) with a guarantee of BP (or any successor thereto as guarantor of the notes), (y) BP or (z) a wholly owned direct or indirect finance subsidiary of BP with a guarantee of BP (or any successor thereto as guarantor of the notes); and b) (and/or, as appropriate, the guarantee as aforesaid) shall rank pari passu on a Winding-Up of BP Capital U.K. (or any successor thereto as issuer of the notes) with the notes or on a Winding- Up of BP (or any successor thereto as guarantor of the notes) with the Guarantee; and c) shall contain terms which provide for the same or a more favorable Interest Rate from time to time applying to the notes and preserve the same Interest Payment Dates; and d) shall preserve the obligations (including the obligations arising from the exercise of any right) of BP Capital U.K. (or any successor thereto as issuer of the notes) as to redemption of the notes, including (without limitation) as to timing of, and amounts payable upon, such redemption; and e) shall preserve any existing rights under the terms of the notes to any accrued interest, any Deferred Interest Payments, any Arrears of Interest and any other amounts payable under the notes which, in each case, has accrued to noteholders and not been paid; and f) shall not contain terms providing for loss absorption through principal write-down or conversion to ordinary shares; and g) shall otherwise contain substantially identical terms (as reasonably determined by BP Capital U.K. (or any successor thereto as issuer of the notes)) to the notes, save where (without prejudice to the requirement that the terms are not materially less favourable to the class of relevant noteholders taken as a whole than the terms of the notes as described above) any modifications to such terms are required to be made to avoid the occurrence or effect of a Rating Agency Event, an Accounting Event, a Tax Deduction Event or an event that permits an Optional Tax Redemption to occur; and h) shall, immediately after such substitution or variation, be assigned at least the same credit rating(s) by the same Rating Agencies as may have been assigned to the notes at the invitation of or with the consent of BP Capital U.K. (or any successor thereto as issuer of the notes) immediately prior to such substitution or variation; and i) shall not provide for the mandatory deferral or cancellation of payments of interest and/or principal; and j) shall be (x) listed on the Official List and admitted to trading on the London Stock Exchange plc's Main Market or (y) listed on such other stock exchange as is a Recognised Stock Exchange at that time or admitted to trading on a Multilateral Trading Facility as selected by BP Capital U.K (or any successor thereto as issuer of the notes).

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66 For the purposes of the definition of Qualifying Securities: "Multilateral Trading Facility" means a multilateral trading facility described in section 987(1)(b) of the Income Tax Act 2007 of the United Kingdom, as the same may be amended from time to time and any provision, statute or statutory instrument replacing the same from time to time; "Official List" means the Official List of the Financial Conduct Authority in its capacity as competent authority under the Financial Services and Markets Act 2000 of the United Kingdom (as the same may be amended from time to time and any provision, statute or statutory instrument replacing the same from time to time); and "Recognised Stock Exchange" means a recognised stock exchange as defined in section 1005 of the Income Tax Act 2007 of the United Kingdom as the same may be amended from time to time and any provision, statute or statutory instrument replacing the same from time to time. • Events of Default Provisions • An Event of Default under the relevant notes occurs only in the event of a Winding-Up of BP Capital U.K. or BP other than for the purposes of a Solvent Reorganization of BP Capital U.K. or BP. If, for a period of 30 days or more, BP Capital U.K. or BP are in default in the payment of any principal or interest (including any Arrears of Interest (without double counting)) in respect of the notes which is due and payable (a "Payment Default"), then BP Capital U.K. and/or BP, as the case may be, will be deemed to be in default under the Indenture and the notes, and the Trustee may, and if instructed by the holders as described in "—Entitlement of the Trustee" below shall, take such actions as set forth under "—Proceedings" or "—Enforcement" below to institute actions, steps or proceedings for the Winding-Up of BP Capital U.K. and/or BP. For the avoidance of doubt, a Payment Default is not an Event of Default and shall not result in any right of Acceleration pursuant to Section 502 of the Indenture. • Proceedings: If a Payment Default occurs and is continuing, then BP Capital U.K. or BP, as the case may be, shall, without notice from the Trustee, be deemed to be in default under the Indenture and the notes and (subject to the provisions set forth below) the Trustee may, and if instructed by the holders as described in "—Entitlement of the Trustee" below shall, institute actions, steps or proceedings for the Winding-Up of BP Capital U.K. and/or BP and/or prove in the Winding-Up of BP Capital U.K. and/or BP and/or claim in the liquidation or administration of BP Capital U.K. and/or BP, such claim being subordinated, and for the amount, as provided in "—Subordination and Waiver of Set-off Provisions". • Enforcement: Without prejudice to "—Proceedings" and subject to the provisions set forth below, the Trustee may, and if instructed by the holders as described in "—Entitlement of the Trustee" below shall, at any time and without further notice, institute such proceedings or take such steps or actions against BP Capital U.K. and/or BP as it may think fit to enforce any term or condition binding on BP Capital U.K. and/or BP under the Indenture or the notes, but in no event shall BP Capital U.K. and/or BP, by virtue of the institution of any such proceedings, steps or actions, be obliged to pay any sum or sums in cash or otherwise, sooner than the same would otherwise have been payable by it under the Indenture or the notes.

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67 • Entitlement of Trustee: The Trustee shall not be bound to take any of the actions referred to in the provisions set forth under "—Proceedings" or "—Enforcement" above against BP Capital U.K. and/or BP to enforce the terms of the Indenture or the notes at the request of the noteholders or take any other action or step under or pursuant to the terms of the notes or the Indenture unless (i) it shall have been so requested in writing by the noteholders of at least 25% in principal amount of the notes then outstanding and (ii) it shall have been indemnified and/or secured and/or prefunded by the relevant noteholders to its satisfaction. However, if a Payment Default or an Event of Default has occurred and is continuing, the Trustee shall exercise such of the rights and powers vested in it by the Indenture, and use the same degree of care and skill in their exercise, as a prudent person would exercise or use under the circumstances in the conduct of his or her own affairs. The Trustee shall not be liable with respect to any action taken or omitted to be taken by it in good faith in accordance with the request of the noteholders of at least 25% in principal amount of the notes then outstanding. • Right of Noteholders: No noteholder shall be entitled to proceed directly against BP Capital U.K. or BP or to institute proceedings for the Winding-Up or claim in the liquidation of BP Capital U.K. or BP or to prove in such Winding-Up unless the Trustee, having become so bound to proceed, institute, prove or claim, fails to do so within a 60 day period and such failure shall be continuing, in which case the noteholder shall have only such rights against BP Capital U.K. or BP as those which the Trustee is entitled to exercise as set out in this section. • Extent of Noteholders' Remedy: No remedy against BP Capital U.K. or BP, other than as referred to in this section, shall be available to the Trustee or the noteholders, whether for the recovery of amounts owing in respect of the notes or under the Indenture or in respect of any breach by BP Capital U.K. or BP of any of their other obligations under or in respect of the notes or under the Indenture. For the avoidance of doubt, nothing in the foregoing shall (i) prevent the Trustee from proving in any Winding-Up (otherwise than for the purposes of a Solvent Reorganization of BP Capital U.K. or BP, as the case may be) or administration of BP Capital U.K. or BP and/or claiming in any liquidation of BP Capital U.K. or BP (even if not instituted by the Trustee), or (ii) impair the right of any noteholder to receive payment of principal, premium or interest (including Arrears of Interest) on such noteholder's notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such noteholder's notes. • Defined Terms: The following definitions shall apply to subordination of the notes and subordination of the guarantee provisions: • "Notional Preference Shares" means, with respect to BP Capital U.K. or BP, as the case may be, a notional class of preference shares in the capital of BP Capital U.K. or BP, as the case may be: (i) ranking junior to the claims of all holders of Senior Obligations of BP Capital U.K. or BP, as the case may be; (ii) having an equal right to return of assets in the Winding-Up of BP Capital U.K. or BP, as the case may be, and so ranking pari passu with any Parity Obligations of BP Capital U.K. or BP, as the case may be; and (iii) having a right to return of capital ahead of, and so ranking ahead of, the claims of holders of the Ordinary Shares of BP Capital U.K. or BP, as the case may be. • "Parity Obligations" means, with respect to BP Capital U.K. or BP, as the case may be: (a) the most junior class of preference share capital of BP Capital U.K. or BP, as the case may be; and (b) any other security, guarantee or other instrument issued by, or any other

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68 obligation of BP Capital U.K. or BP, as the case may be, which ranks or is expressed to rank pari passu with BP Capital U.K.'s obligations under the notes or BP's obligations under the Guarantee, including the Other Hybrid Capital Notes. • "Ordinary Shares" means (i) any ordinary shares in the capital of BP Capital U.K. or BP, as the case may be, or (ii) any present or future shares of any other class of shares of BP Capital U.K. or BP, as the case may be, ranking pari passu with the ordinary shares of BP Capital U.K. or BP, as the case may be or, in either case, any depository or other receipts or certificates, including American depositary receipts representing such shares. • "Senior Obligations" means all obligations of BP Capital U.K. or BP, as the case may be, but excluding any Parity Obligations and any Ordinary Shares of BP Capital U.K. or BP, as the case may be. • "Solvent Reorganization" means, in any such case, a solvent Winding-Up for the purposes of a reorganization, reconstruction, amalgamation or the substitution in place of BP Capital U.K. or BP, as the case may be, of a Successor in Business, the terms of which reorganization, reconstruction, amalgamation or substitution (x) have previously been approved by way of a supplemental indenture to the Indenture which has been approved by the holders of the notes in accordance with the terms of the Indenture and (y) do not provide that the notes shall thereby become redeemable or repayable. Description of 6.450% Perpetual Subordinated Fixed Rate Reset Notes The following terms are applicable to the 6.450% Perpetual Subordinated Fixed Rate Reset Notes. • Issuer: BP Capital U.K. • Title: 6.450% Perpetual Subordinated Fixed Rate Reset Notes • Total principal amount outstanding: $1,300,000,000 • Issuance date: 1 March 2024 • Maturity date: The notes are perpetual securities in respect of which there is no fixed redemption date. BP Capital U.K. shall only have the right to redeem, purchase or substitute or vary the notes in accordance with "—Optional Redemption on Interest Payment Date", "—Optional Redemption for Certain Events", "—Optional Tax Redemption", "—Optional Clean-Up Redemption", "— Substitution or Variation" as described in the applicable Prospectus Supplement or otherwise in accordance with the terms of the notes. • Ranking of the Notes: The notes are unconditional, unsecured and subordinated obligations of BP Capital U.K. and will rank pari passu without any preference among themselves and pari passu with any Parity Obligations of BP Capital U.K. but junior to any Senior Obligations of BP Capital U.K. and senior to the Ordinary Shares of BP Capital U.K. • To give effect to the intended ranking described above, if at any time a Winding-Up of BP Capital U.K. occurs (otherwise than for the purposes of a Solvent Reorganization of BP Capital U.K.), the amount payable by BP Capital U.K. to a noteholder under or in relation to such noteholder's notes (in lieu of any other payment by BP Capital U.K. to such noteholder under or in relation to the notes, including pursuant to the terms of the notes or

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69 the Indenture) shall be the amount that would have been payable to such noteholder if, immediately prior to and throughout such Winding-Up, such noteholder was the holder of Notional Preference Shares in BP Capital U.K. For the purposes only of that calculation, in respect of each Note and accrued but unpaid interest (including any outstanding Arrears of Interest in respect of such interest) a noteholder will be deemed to hold a Notional Preference Share in BP Capital U.K. entitling the holder thereof to receive in respect of such Notional Preference Share an amount in the Winding-Up of BP Capital U.K. that is equal to the principal amount of the relevant note and any accrued but unpaid interest and any outstanding Arrears of Interest in respect of such interest (without double counting) (and, in the case of an administration, on the same assumption that shareholders were entitled to claim and recover in respect of their shares to the same degree as in a Winding- Up). Amounts payable to the noteholders of the notes pursuant to this provision will only be paid after the debts owing to the holders of the Senior Obligations of BP Capital U.K. have been paid in full. The subordination provisions applicable to the notes will be governed by English law. • "Winding-Up" means an order being made, or an effective resolution being passed, for the winding-up of BP Capital U.K. or BP, as the case may be, or an administrator of BP Capital U.K. or BP, as the case may be, being appointed and such administrator giving notice that it intends to declare and distribute a dividend. • Ranking of the Guarantee: The payment of the principal of and interest on the notes is fully guaranteed by BP. The obligations of BP under the Guarantee are unconditional, unsecured and subordinated and the rights and claims of noteholders will rank pari passu without any preference among themselves and pari passu with any Parity Obligations of BP but junior to any Senior Obligations of BP and senior to the Ordinary Shares of BP. • To give effect to the intended ranking described above, if at any time a Winding-Up of BP occurs (otherwise than for the purposes of a Solvent Reorganization of BP), the amount payable by BP to a noteholder under or in relation to the Guarantee (in lieu of any other payment by BP to such noteholder under or in relation to the Guarantee), shall be the amount that would have been payable to such noteholder if, immediately prior to and throughout such Winding-Up, such noteholder was the holder of Notional Preference Shares in BP. For the purposes only of that calculation, in respect of each note and accrued but unpaid interest (including any outstanding Arrears of Interest in respect of such interest payment) a noteholder will be deemed to hold a Notional Preference Share in BP entitling the holder thereof to receive in respect of such Notional Preference Share an amount in the Winding-Up of BP that is equal to the principal amount of the relevant note and any accrued but unpaid interest and any outstanding Arrears of Interest in respect of such interest (without double counting) (and, in the case of an administration, on the assumption that the shareholders were entitled to claim and recover in respect of their shares to the same degree as in a Winding-Up). For the purpose of construing the provisions of the Guarantee and BP's payment obligations in respect thereof, the latter amounts shall be treated as due and payable by the Issuer on the date such Winding-Up order of BP Capital U.K. is made or such resolution is passed or notice is given, as the case may be and, consequently, a claim under the Guarantee in respect of such amount may be made on, or at any time after, such date. Amounts payable to the noteholder upon Winding-Up will only be paid after the debts owing to the holders of the Senior Obligations of BP have been paid in full. The subordination provisions applicable to the Guarantee will be governed by English law.

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70 • Deferral of Interest: BP Capital U.K. may elect, in its sole discretion, to defer payment of the amount of interest (in whole or in part) (a "Deferred Interest Payment") due on any Interest Payment Date in respect of the notes. Such Deferred Interest Payments (as defined herein) will accrue additional interest at the relevant interest rate prevailing from time to time (which will also be added to any Deferred Interest Payments on each subsequent Interest Payment Date and accrue interest in the same manner). Any such deferred payments and any additional interest thereon are referred to as "Arrears of Interest". BP Capital U.K. must pay Arrears of Interest in respect of the relevant notes upon the date for redemption of all the relevant notes or in certain other limited circumstances. • Interest rate: (a) 6.450% per annum, for the period from (and including) the Issue Date to (but excluding) the relevant First Reset Date and (b) from (and including) the relevant First Reset Date, at an Interest Rate per annum equal to the relevant Reset Interest Rate, in each case on the outstanding principal amount of the notes. • Reset Date: The Reset Dates will be (a) the relevant First Reset Date and (b) each date that falls five, or a multiple of five, years following the relevant First Reset Date. • First Reset Date: The First Reset Date will be 1 March 2034. • Reset Determination Date: The Reset Determination Date will be the day falling two Business Days prior to the relevant Reset Date. • Reset Interest Rate: The Reset Interest Rate, in relation to any Reset Period, is the sum of the relevant Five-Year Treasury Rate, calculated as provided for in the relevant Prospectus Supplement, in relation to that Reset Period plus the Margin applicable to that Reset Period. • Reset Period: The period from (and including) the relevant First Reset Date to (but excluding) the next relevant Reset Date, and each successive period from (and including) a Reset Date to (but excluding) the next succeeding Reset Date. • Date interest starts accruing: 1 March 2024 • Interest payment dates: Each 1 March and 1 September, subject to the day count convention and the Optional Interest Deferral described in the relevant Prospectus Supplement. • Interest Periods: The period beginning on (and including) the Issue Date and ending on (but excluding) the first Interest Payment Date and each successive period beginning on (and including) an Interest Payment Date and ending on (but excluding) the next succeeding Interest Payment Date. • First interest payment date: 1 September 2024 • Interest Amount: Subject to Optional Interest Deferral, the amount of interest payable in respect of the Calculation Amount (a) on the First Interest Payment Date shall be $35.73 and (b) on each Interest Payment Date to (and including) the First Reset Date shall be $30.63. Subject to Optional Interest Deferral, the amount of interest payable in respect of the Calculation Amount for any other period for which interest is to be calculated shall be calculated by: • applying the applicable Interest Rate to the Calculation Amount; • multiplying the product thereof by the Day Count Fraction; and

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71 • rounding the resulting figure to the nearest cent (half a cent being rounded upwards). • The relevant amount of interest payable in respect of the notes for any period shall be the product of: (i) the relevant amount of interest per Calculation Amount determined as described above; and (ii) the number by which the Calculation Amount is required to be multiplied to equal the principal amount of the notes. • "Calculation Amount" means $1,000. • "Day Count Fraction" means 30/360. Where it is necessary to calculate an amount of interest in respect of any Note for a period which is less than or equal to a complete Interest Period, such interest shall be calculated on the basis of a 360-day year consisting of 12 months of 30 days each and, in the case of an incomplete month, the number of days elapsed. • Optional redemption: Subject to applicable laws, BP Capital U.K. may, by giving not less than 10 nor more than 60 days' notice to the Trustee and the relevant noteholders in accordance with the notice provisions set forth in the Indenture (which notice shall be irrevocable), redeem the relevant notes (in whole but not in part) on the First Call Date and on any day thereafter to (and including) the First Reset Date, or on any Interest Payment Date thereafter, at their outstanding principal amount plus any accrued but unpaid interest up to (but excluding) the relevant Redemption Date and any outstanding Arrears of Interest (without double counting). • Optional Clean-Up Redemption: On the giving of not less than 10 nor more than 60 days' notice to the Trustee and the relevant holders in accordance with the notice provisions set forth in the indenture (which notice shall be irrevocable), the notes may be redeemed or purchased and cancelled at the option of BP Capital U.K. (in whole but not in part) at a redemption amount equal to 100% of the principal amount of the notes plus accrued and unpaid interest up to (but excluding) the relevant Redemption Date and any outstanding Arrears of Interest (without double counting) if 75% or more in initial aggregate principal amount of the notes (which for these purposes, shall include any additional notes issued pursuant to "Further Issuances") have previously been redeemed or purchased and cancelled. • Outstanding Liabilities: As of 31 December 2023, BP had outstanding 5,473,414 cumulative second preference shares of £1 each, which will rank as Parity Obligations to the Guarantee as of the Issue Date. As of 31 December 2023, BP also had outstanding 7,232,838 cumulative first preference shares of £1 each, which will rank as Senior Obligations to the Guarantee as of the Issue Date. • Limitations on the Issuance of Additional Senior Indebtedness: None of the notes, the guarantee or the indenture under which the notes were issued restrict BP Capital U.K. or BP from issuing additional securities (including preference shares or other equity securities) which will be deemed Parity Obligations or Senior Obligations of the notes and Guarantee, as applicable. • Substitution or Variation: If a Rating Agency Event, an Accounting Event, a Tax Deduction Event or an event that permits an Optional Tax Redemption to occur (a "Substitution or Variation Event") has occurred and is continuing, then BP Capital U.K. or BP may, as an alternative to redemption, subject to the conditions set forth under "—Conditions to Special Event Redemption and Substitution or Variation" in the applicable Prospectus Supplement (without any requirement for the consent or approval of the noteholders) and subject to the Trustee, immediately prior to the

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72 giving of any notice referred to herein, having received an officers' certificate and an opinion of counsel (each as defined in the Indenture), each stating to the effect that the provisions of this section have been complied with, and having given not less than 10 nor more than 60 days' notice to the Trustee, the Calculation Agent and the relevant noteholders (which notice shall be irrevocable), at any time either (i) substitute all, but not less than all, of the notes for, or (ii) vary the terms of the notes with the effect that they remain or become (as the case may be), Qualifying Securities, and the noteholders shall be bound by such substitution or variation. Upon expiry of such notice, BP Capital U.K. or BP will either vary the terms of or, as the case may be, substitute the notes in accordance with this section. In connection with the substitution of Qualifying Securities for the notes or the variation of the terms of the notes, each noteholder by the purchase of the notes authorizes the Trustee to, and the Trustee shall, authenticate such new notes in accordance with Section 303 of the Indenture. In connection with any substitution or variation in accordance with this section, BP Capital U.K. will comply with the rules of any stock exchange on which the notes are for the time being listed or admitted to trading. Any such substitution or variation in accordance with the foregoing provisions following a Substitution or Variation Event shall only be permitted if it does not give rise to any other Substitution or Variation Event with respect to the Qualifying Securities. Any such substitution or variation in accordance with the foregoing provisions following a Substitution or Variation Event shall only be permitted if it does not result in the Qualifying Securities not being or no longer being (as the case may be) eligible for the same, or a higher amount of, "equity credit" (or such other nomenclature that the Rating Agency may then use to describe the degree to which an instrument exhibits the characteristics of an ordinary share) as is attributed to the notes on the date notice is given to noteholders of the substitution or variation. In no event shall the Trustee have any responsibility whatsoever to determine whether any such substitution or variation results in the Qualifying Securities. Any such substitution or variation could have unexpected commercial consequences depending on the circumstances of an individual noteholder, and we will consider the impact on the class of noteholders taken as a whole and are not required to take into account the individual circumstances of each noteholder. "Qualifying Securities" means securities that contain terms not materially less favorable to the class of noteholders of the notes, as the case may be, and in each case taken as a whole, than the terms of the respective notes (as reasonably determined by BP Capital U.K. (in consultation with an independent investment bank or counsel of international standing)) and provided that an officers' certificate to such effect (and confirming that the conditions set out in (a) to (j) below have been satisfied) shall have been delivered to the Trustee prior to the substitution or variation of the notes upon which certificate the Trustee shall rely absolutely). Such Qualifying Securities: a) shall be issued by (x) BP Capital U.K. (or any successor thereto as issuer of the notes) with a guarantee of BP (or any successor thereto as guarantor of the notes), (y) BP or (z) a wholly owned direct or indirect finance subsidiary of BP with a guarantee of BP (or any successor thereto as guarantor of the notes); and b) (and/or, as appropriate, the guarantee as aforesaid) shall rank pari passu on a Winding-Up of BP Capital U.K. (or any successor thereto as issuer of the notes) with the notes or on a Winding- Up of BP (or any successor thereto as guarantor of the notes) with the Guarantee; and c) shall contain terms which provide for the same or a more favorable Interest Rate from time to time applying to the notes and preserve the same Interest Payment Dates; and d) shall preserve the obligations (including the obligations arising from the exercise of any right) of BP Capital U.K. (or any successor thereto as issuer of the notes) as to redemption of the

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73 notes, including (without limitation) as to timing of, and amounts payable upon, such redemption; and e) shall preserve any existing rights under the terms of the notes to any accrued interest, any Deferred Interest Payments, any Arrears of Interest and any other amounts payable under the notes which, in each case, has accrued to noteholders and not been paid; and f) shall not contain terms providing for loss absorption through principal write-down or conversion to ordinary shares; and g) shall otherwise contain substantially identical terms (as reasonably determined by BP Capital U.K. (or any successor thereto as issuer of the notes)) to the notes, save where (without prejudice to the requirement that the terms are not materially less favourable to the class of relevant noteholders taken as a whole than the terms of the notes as described above) any modifications to such terms are required to be made to avoid the occurrence or effect of a Rating Agency Event, an Accounting Event, a Tax Deduction Event or an event that permits an Optional Tax Redemption to occur; and h) shall, immediately after such substitution or variation, be assigned at least the same credit rating(s) by the same Rating Agencies as may have been assigned to the notes at the invitation of or with the consent of BP Capital U.K. (or any successor thereto as issuer of the notes) immediately prior to such substitution or variation; and i) shall not provide for the mandatory deferral or cancellation of payments of interest and/or principal; and j) shall be (x) listed on the Official List and admitted to trading on the London Stock Exchange plc's Main Market or (y) listed on such other stock exchange as is a Recognised Stock Exchange at that time or admitted to trading on a Multilateral Trading Facility as selected by BP Capital U.K (or any successor thereto as issuer of the notes). For the purposes of the definition of Qualifying Securities: "Multilateral Trading Facility" means a multilateral trading facility described in section 987(1)(b) of the Income Tax Act 2007 of the United Kingdom, as the same may be amended from time to time and any provision, statute or statutory instrument replacing the same from time to time; "Official List" means the Official List of the Financial Conduct Authority in its capacity as competent authority under the Financial Services and Markets Act 2000 of the United Kingdom (as the same may be amended from time to time and any provision, statute or statutory instrument replacing the same from time to time); and "Recognised Stock Exchange" means a recognised stock exchange as defined in section 1005 of the Income Tax Act 2007 of the United Kingdom as the same may be amended from time to time and any provision, statute or statutory instrument replacing the same from time to time. • Events of Default Provisions

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74 • An Event of Default under the relevant notes occurs only in the event of a Winding-Up of BP Capital U.K. or BP other than for the purposes of a Solvent Reorganization of BP Capital U.K. or BP. If, for a period of 30 days or more, BP Capital U.K. or BP are in default in the payment of any principal or interest (including any Arrears of Interest (without double counting)) in respect of the notes which is due and payable (a "Payment Default"), then BP Capital U.K. and/or BP, as the case may be, will be deemed to be in default under the Indenture and the notes, and the Trustee may, and if instructed by the holders as described in "—Entitlement of the Trustee" below shall, take such actions as set forth under "—Proceedings" or "—Enforcement" below to institute actions, steps or proceedings for the Winding-Up of BP Capital U.K. and/or BP. For the avoidance of doubt, a Payment Default is not an Event of Default and shall not result in any right of Acceleration pursuant to Section 502 of the Indenture. • Proceedings: If a Payment Default occurs and is continuing, then BP Capital U.K. or BP, as the case may be, shall, without notice from the Trustee, be deemed to be in default under the Indenture and the notes and (subject to the provisions set forth below) the Trustee may, and if instructed by the holders as described in "—Entitlement of the Trustee" below shall, institute actions, steps or proceedings for the Winding-Up of BP Capital U.K. and/or BP and/or prove in the Winding-Up of BP Capital U.K. and/or BP and/or claim in the liquidation or administration of BP Capital U.K. and/or BP, such claim being subordinated, and for the amount, as provided in "—Subordination and Waiver of Set-off Provisions". • Enforcement: Without prejudice to "—Proceedings" and subject to the provisions set forth below, the Trustee may, and if instructed by the holders as described in "—Entitlement of the Trustee" below shall, at any time and without further notice, institute such proceedings or take such steps or actions against BP Capital U.K. and/or BP as it may think fit to enforce any term or condition binding on BP Capital U.K. and/or BP under the Indenture or the notes, but in no event shall BP Capital U.K. and/or BP, by virtue of the institution of any such proceedings, steps or actions, be obliged to pay any sum or sums in cash or otherwise, sooner than the same would otherwise have been payable by it under the Indenture or the notes. • Entitlement of Trustee: The Trustee shall not be bound to take any of the actions referred to in the provisions set forth under "—Proceedings" or "—Enforcement" above against BP Capital U.K. and/or BP to enforce the terms of the Indenture or the notes at the request of the noteholders or take any other action or step under or pursuant to the terms of the notes or the Indenture unless (i) it shall have been so requested in writing by the noteholders of at least 25% in principal amount of the notes then outstanding and (ii) it shall have been indemnified and/or secured and/or prefunded by the relevant noteholders to its satisfaction. However, if a Payment Default or an Event of Default has occurred and is continuing, the Trustee shall exercise such of the rights and powers vested in it by the Indenture, and use the same degree of care and skill in their exercise, as a prudent person would exercise or use under the circumstances in the conduct of his or her own affairs. The Trustee shall not be liable with respect to any action taken or omitted to be taken by it in good faith in accordance with the request of the noteholders of at least 25% in principal amount of the notes then outstanding. • Right of Noteholders: No noteholder shall be entitled to proceed directly against BP Capital U.K. or BP or to institute proceedings for the Winding-Up or claim in the liquidation of BP Capital U.K. or BP or to prove in such Winding-Up unless the Trustee, having become so bound to proceed, institute, prove or claim, fails to do so within a 60 day period and

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75 such failure shall be continuing, in which case the noteholder shall have only such rights against BP Capital U.K. or BP as those which the Trustee is entitled to exercise as set out in this section. • Extent of Noteholders' Remedy: No remedy against BP Capital U.K. or BP, other than as referred to in this section, shall be available to the Trustee or the noteholders, whether for the recovery of amounts owing in respect of the notes or under the Indenture or in respect of any breach by BP Capital U.K. or BP of any of their other obligations under or in respect of the notes or under the Indenture. For the avoidance of doubt, nothing in the foregoing shall (i) prevent the Trustee from proving in any Winding-Up (otherwise than for the purposes of a Solvent Reorganization of BP Capital U.K. or BP, as the case may be) or administration of BP Capital U.K. or BP and/or claiming in any liquidation of BP Capital U.K. or BP (even if not instituted by the Trustee), or (ii) impair the right of any noteholder to receive payment of principal, premium or interest (including Arrears of Interest) on such noteholder's notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such noteholder's notes. • Defined Terms: The following definitions shall apply to subordination of the notes and subordination of the guarantee provisions: • "Notional Preference Shares" means, with respect to BP Capital U.K. or BP, as the case may be, a notional class of preference shares in the capital of BP Capital U.K. or BP, as the case may be: (i) ranking junior to the claims of all holders of Senior Obligations of BP Capital U.K. or BP, as the case may be; (ii) having an equal right to return of assets in the Winding-Up of BP Capital U.K. or BP, as the case may be, and so ranking pari passu with any Parity Obligations of BP Capital U.K. or BP, as the case may be; and (iii) having a right to return of capital ahead of, and so ranking ahead of, the claims of holders of the Ordinary Shares of BP Capital U.K. or BP, as the case may be. • "Parity Obligations" means, with respect to BP Capital U.K. or BP, as the case may be: (a) the most junior class of preference share capital of BP Capital U.K. or BP, as the case may be; and (b) any other security, guarantee or other instrument issued by, or any other obligation of BP Capital U.K. or BP, as the case may be, which ranks or is expressed to rank pari passu with BP Capital U.K.'s obligations under the notes or BP's obligations under the Guarantee, including the Other Hybrid Capital Notes. • "Ordinary Shares" means (i) any ordinary shares in the capital of BP Capital U.K. or BP, as the case may be, or (ii) any present or future shares of any other class of shares of BP Capital U.K. or BP, as the case may be, ranking pari passu with the ordinary shares of BP Capital U.K. or BP, as the case may be or, in either case, any depository or other receipts or certificates, including American depositary receipts representing such shares. • "Senior Obligations" means all obligations of BP Capital U.K. or BP, as the case may be, but excluding any Parity Obligations and any Ordinary Shares of BP Capital U.K. or BP, as the case may be. • "Solvent Reorganization" means, in any such case, a solvent Winding-Up for the purposes of a reorganization, reconstruction, amalgamation or the substitution in place of BP Capital U.K. or BP, as the case may be, of a Successor in Business, the terms of which reorganization, reconstruction, amalgamation or substitution (x) have previously been approved by way of a supplemental indenture to the Indenture which has been approved

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76 by the holders of the notes in accordance with the terms of the Indenture and (y) do not provide that the notes shall thereby become redeemable or repayable. B. Other Terms Applicable to All Notes The following terms are applicable to all Notes, except where otherwise noted. Guarantee: Payment of the principal of and interest on the notes is fully guaranteed by BP. Denomination: The notes will be issued in denominations of $1,000 and integral multiples of $1,000. Regular record dates for interest: The 15th calendar day preceding each interest payment date, whether or not such day is a business day. Business day: If any payment is due in respect of the notes on a day that is not a business day, it will be made on the next following business day, provided that no interest will accrue on the payment so deferred. A "business day" for these purposes is any week day on which banking or trust institutions in neither New York nor London are authorized generally or obligated by law, regulation or executive order to close. Ranking: The notes are unsecured and unsubordinated and will rank equally with all of the issuer's other unsecured and unsubordinated indebtedness, except for the 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes, which rank as specified in Section A herein. Further issuances: The issuer of the Notes may, at its sole option, at any time and without the consent of the then existing note holders issue additional notes in one or more transactions subsequent to the date of the applicable prospectus supplement with terms (other than the issuance date, issue price and, possibly, the first call date, first reset date, the first interest payment date and/or the date interest starts accruing) identical to the notes issued under such prospectus supplement. These additional notes will be deemed part of the same series as the notes issued under such prospectus supplement and will provide the holders of these additional notes the right to vote together with holders of the notes issued under such prospectus supplement, provided that such additional notes will be issued with no more than de minimis original issue discount or will be part of a "qualified reopening" for U.S. federal income tax purposes, except that in the case of the 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes, additional notes of such series will be only issued if they are fungible with the original notes for U.S. federal income tax purposes. Day Count: • For Notes which are floating rate notes – Actual / 360 • For Notes which are fixed rate notes – 30/360 Day count convention: • For Notes which are floating rate notes – Modified following. If any interest payment date falls on a day that is not a business day, that interest payment date will be postponed to the next succeeding business day unless that business day is in the next succeeding calendar month, in which case the interest payment date will be the immediately preceding business day. • For Notes which are fixed rate notes – Following Unadjusted

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77 Trading through DTC, Clearstream, Luxembourg and Euroclear: Initial settlement for the notes has been made in immediately available funds. Secondary market trading between DTC participants will occur in the ordinary way in accordance with DTC's rules and will be settled in immediately available funds using DTC's Same-Day Funds Settlement System. Secondary market trading between Clearstream Banking, société anonyme, in Luxembourg ("Clearstream, Luxembourg"), customers and/or Euroclear Bank S.A./N.V. ("Euroclear") participants will occur in the ordinary way in accordance with the applicable rules and operating procedures of Clearstream, Luxembourg and Euroclear and will be settled using the procedures applicable to conventional Eurobonds in immediately available funds. Name of depositary: The Depository Trust Company, commonly referred to as "DTC". Sinking Fund: There is no sinking fund. Trustee: • If the issuer is BP Capital U.K., the notes have been issued under an indenture with The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee, dated as of 8 March 2002, as supplemented by a supplemental indenture with respect to the notes entered into on the issuance date. • If the issuer is BP Capital America, the notes have been issued under an indenture with The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank), as trustee, dated as of 4 June 2003, as supplemented by a supplemental indenture with respect to the notes entered into on the issuance date. Use of proceeds: The net proceeds from the sale of the notes will be used for general corporate purposes, including working capital for BP or other companies in the BP Group and the repayment of existing borrowings of BP and its subsidiaries. Governing law and jurisdiction: The indenture, the notes and the guarantee are governed by New York law, except for the subordination provisions and waiver of set-off provisions in respect of the 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes, which will be governed by English law. Any legal proceeding arising out of or based upon the indenture, the notes or the guarantee may be instituted in any state or federal court in the Borough of Manhattan in New York City, New York. BP Capital U.K.'s principal executive offices are located at Chertsey Road, Sunbury on Thames, Middlesex TW16 7BP, England. BP Capital America's principal executive offices are located at 501 Westlake Park Boulevard, Houston, Texas 77079. C. Description of Debt Securities and Guarantees The following terms are applicable to all Notes, except where otherwise specified. In the following description, "you" means direct holders of the Notes (and not street name or other indirect holders of securities).

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78 DESCRIPTION OF DEBT SECURITIES AND GUARANTEES Each of the BP Debt Issuers may issue guaranteed debt securities using the prospectus dated 12 March 2024. As required by U.S. federal law for all bonds and notes of companies that are publicly offered, the debt securities are governed by a document called the indenture. BP Capital America has entered into an Indenture, dated 4 June 2003, between BP Capital America., BP p.l.c. and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A.) as trustee. BP Capital U.K. has entered into an Indenture, dated 8 March 2002, between BP Capital U.K., BP p.l.c. and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A.) as trustee. The trustee under each of the indentures has two main roles: • first, it can enforce your rights against us if we default. There are some limitations on the extent to which the trustee acts on your behalf, described under "Default and Related Matters—Events of Default—Remedies If an Event of Default Occurs" below; and • second, the trustee performs administrative duties for us, such as sending you interest payments, transferring your debt securities to a new buyer if you sell and sending you notices. BP acts as the guarantor of the guaranteed debt securities issued under the BP Debt Issuers' indentures. The guarantees are described under "—Guarantees" below. The indentures and their associated documents contain the full legal text governing the matters described in this section. The indentures, the debt securities and the guarantees are governed by New York law. The indentures are exhibits to our registration statement. This section contains what we believe is a materially complete and accurate summary of the material provisions of the indentures, which are substantially identical to each other, the debt securities and the guarantees. However, because it is a summary, it does not describe every aspect of the indentures, the debt securities or the guarantees. This summary is subject to and qualified in its entirety by reference to all the provisions of the indentures, including some of the terms used in the indentures. We describe the meaning for only the more important terms. We also include references in parentheses to some sections of the indentures. Whenever we refer to particular sections or defined terms of the indentures in this prospectus or in the prospectus supplement, those sections or defined terms are incorporated by reference here or in the prospectus supplement. This summary also is subject to and qualified by reference to the description of the particular terms of your series described above. The BP Debt Issuers may each issue as many distinct series of debt securities under its respective indenture as it wishes. This section summarizes all material terms of the debt securities that are common to all series, unless otherwise described above. We may issue the debt securities as original issue discount securities, which are debt securities that are offered and sold at a substantial discount to their stated principal amount. (Section 101) Special U.S. federal income tax, accounting and other considerations may apply to original issue discount securities. The applicable U.S. federal income tax considerations for original issue discount securities are described under "Original Issue Discount" below. The debt securities may also be issued as indexed securities or securities denominated in foreign currencies or currency units, as described in more detail above. Accordingly, this summary also is subject to and qualified by reference to the description of the terms of the series described above.

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79 Unless otherwise described above, the debt securities will be issued only in fully registered form without interest coupons. Guarantees BP will fully and unconditionally guarantee the payment of the principal of, premium, if any, and interest on the guaranteed debt securities, including certain additional amounts which may be payable under the guarantees, as described under "Special Situations—Payment of Additional Amounts". BP guarantees the payment of such amounts when such amounts become due and payable, whether at the stated maturity of the debt securities, by declaration of acceleration, call for redemption or otherwise. Overview of Remainder of This Description The remainder of this description summarizes: • Additional mechanics relevant to the debt securities under normal circumstances, such as how you transfer ownership and where we make payments. • Your rights under several special situations, such as if we merge with another company or if we want to change a term of the debt securities. • Your rights to receive payment of additional amounts due to changes in U.K. tax withholding or deduction requirements. • Your rights if we default or experience other financial difficulties. • Our relationship with the trustee. Additional Mechanics Exchange and Transfer You may have your debt securities broken into more debt securities of smaller denominations or combined into fewer debt securities of larger denominations, as long as the total principal amount is not changed. (Section 305) This is called an exchange. You may exchange or transfer registered debt securities at the office of the trustee. The trustee acts as our agent for registering debt securities in the names of holders and transferring registered debt securities. We may change this appointment to another entity or perform the service ourselves. The entity performing the role of maintaining the list of registered holders is called the security registrar. It will also register transfers of the registered debt securities. (Section 305) You will not be required to pay a service charge to transfer or exchange debt securities, but you may be required to pay for any tax or other governmental charge associated with the exchange or transfer. The transfer or exchange of a registered debt security will only be made if the security registrar is satisfied with your proof of ownership. If we have designated additional transfer agents, they are described above. We may cancel the designation of any particular transfer agent. We may also approve a change in the office through which any transfer agent acts. (Section 1002)

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80 If the debt securities are redeemable and we redeem less than all of the debt securities of a particular series, we may block the transfer or exchange of debt securities during a specified period of time in order to freeze the list of holders to prepare the mailing. The period begins 15 days before the day we mail the notice of redemption and ends on the day of that mailing. We may also refuse to register transfers or exchanges of debt securities selected for redemption. However, we will continue to permit transfers and exchanges of the unredeemed portion of any security being partially redeemed. (Section 305) Payment and Paying Agents We will pay interest to you if you are a direct holder listed in the trustee's records at the close of business on a particular day in advance of each due date for interest, even if you no longer own the security on the interest due date. That particular day, usually about two weeks in advance of the interest due date, is called the regular record date and is as described above. (Section 307) We will pay interest, principal and any other money due on the registered debt securities at the corporate trust office of the trustee in Chicago, Illinois. That office is currently located at The Bank of New York Mellon Trust Company, N.A., 2 North LaSalle Street, Suite 700, Chicago, Illinois 60602. You must make arrangements to have your payments picked up at or wired from that office. We may also choose to pay interest by mailing checks. Interest on global securities will be paid to the holder thereof by wire transfer of sameday funds. Holders buying and selling debt securities must work out between them how to compensate for the fact that we will pay all the interest for an interest period to the one who is the registered holder on the regular record date. The most common manner is to adjust the sales price of the debt securities to pro rate interest fairly between buyer and seller. This prorated interest amount is called accrued interest. We may also arrange for additional payment offices, and may cancel or change these offices, including our use of the trustee's corporate trust office. These offices are called paying agents. We may also choose to act as our own paying agent. We must notify you through the trustee of changes in the paying agents for any particular series of debt securities. (Section 1002) Notices We and the trustee will send notices only to direct holders, using their addresses as listed in the trustee's records. (Section 106) Regardless of who acts as paying agent, all money that we pay to a paying agent that remains unclaimed at the end of two years after the amount is due to direct holders will be repaid to us. After that twoyear period, you may look only to us for payment and not to the trustee, any other paying agent or anyone else. (Section 1006) Special Situations Mergers and Similar Events We are generally permitted to consolidate or merge with another company or firm. We are also permitted to sell or lease substantially all of our assets to another corporation or other entity or to buy or lease substantially all of the assets of another corporation or other entity. No vote by holders of debt securities approving any of these actions is required, unless as part of the transaction we make changes to the indenture requiring your approval, as described below under "—Modification and Waiver". We may take these

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81 actions as part of a transaction involving outside third parties or as part of an internal corporate reorganization. We may take these actions even if they result in: • a lower credit rating being assigned to the debt securities; or • additional amounts becoming payable in respect of U.K. withholding tax, and the debt securities thus being subject to redemption at our option, as described below under "—Optional Tax Redemption". We have no obligation under the indenture to seek to avoid these results, or any other legal or financial effects that are disadvantageous to you, in connection with a merger, consolidation or sale or lease of assets that is permitted under the indenture. However, we may not take any of these actions unless all the following conditions are met: • Where a BP Debt Issuer or BP, as applicable, merges out of existence or sells or leases substantially all of its assets, the other entity must assume its obligations on the debt securities or the guarantees. Such other entity must be organized under the laws of such BP entity's jurisdiction or a political subdivision thereof. • The merger, sale or lease of assets or other transaction must not cause a default on the debt securities, and we must not already be in default. For purposes of this nodefault test, a default would include an event of default that has occurred and not been cured, as described below under "Default and Related Matters—Events of Default—What Is an Event of Default?" A default for this purpose would also include any event that would be an event of default if the requirements for giving us default notice or our default having to exist for a specific period of time were disregarded. • It is possible that the merger, sale or lease of assets or other transaction would cause some of our property to become subject to a mortgage, security interest, lien or other legal mechanism giving lenders preferential rights in that property over other lenders or over our general creditors if we fail to pay them back. • It is possible that the U.S. Internal Revenue Service may deem a merger or other similar transaction to cause an exchange for U.S. federal income tax purposes of debt securities for new securities by the holders of the debt securities. This could result in the recognition of taxable gain or loss for U.S. federal income tax purposes and possible other adverse tax consequences. Modification and Waiver There are three types of changes we can make to the indenture and the debt securities. Changes Requiring Your Approval • First, there are changes that cannot be made to your debt securities without your specific approval. We must obtain your specified approval in order to: • change the stated maturity of the principal or interest on a debt security; • reduce any amounts due on a debt security;

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82 • reduce the amount of principal payable upon acceleration of the maturity of a debt security following a default; • change the place or currency of payment on a debt security; • impair your right to sue for payment; • reduce the percentage of holders of debt securities whose consent is needed to modify or amend the indenture; • reduce the percentage of holders of debt securities whose consent is needed to waive compliance with various provisions of the indenture or to waive various defaults; • modify any other aspect of the provisions dealing with modification and waiver of the indenture; and • change the obligations of BP to pay any principal, premium or interest under the guarantees. (Section 902) Changes Requiring a Majority Vote • The second type of change to the indenture and the debt securities is the kind that requires a vote in favor by holders of debt securities owning a majority of the principal amount of the particular series affected. Most changes fall into this category, except for clarifying changes and other changes that would not adversely affect holders of the debt securities in any material respect. The same vote would be required for us to obtain a waiver of all or part of the covenants described in this summary or a waiver of a past default. However, we cannot obtain a waiver of a payment default or any other aspect of the indenture or the debt securities listed in the first category described above under "Changes Requiring Your Approval" unless we obtain your individual consent to the waiver. (Section 513) Changes Not Requiring Approval The third type of change does not require any vote by holders of debt securities. This type is limited to clarifications and other changes that would not adversely affect holders of the debt securities in any material respect. (Section 901) Further Details Concerning Voting When taking a vote, we will use the following rules to decide how much principal amount to attribute to a security: • For original issue discount securities, we will use the principal amount that would be due and payable on the voting date if the maturity of the debt securities were accelerated to that date because of a default. • For debt securities whose principal amount is not known (for example, because it is based on an index), we will use a special rule for that security, as described above. • For debt securities denominated in one or more foreign currencies or currency units, we will use the U.S. dollar equivalent as of the date of original issuance.

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83 • Debt securities will not be considered outstanding, and therefore not eligible to vote, if we have deposited or set aside in trust for you money for their payment or redemption. Debt securities will also not be eligible to vote if they have been fully defeased as described below under "—Defeasance and Discharge". (Section 101) • We will generally be entitled to set any day as a record date for the purpose of determining the holders of outstanding debt securities that are entitled to vote or take other action under the indenture. If we set a record date for a vote or other action to be taken by holders of a particular series, that vote or action may be taken only by persons who are holders of outstanding debt securities of that series on the record date and must be taken within 90 days following the record date or another period that we may specify (or as the trustee may specify, if it set the record date). We may shorten or lengthen (but not beyond 90 days) this period from time to time. (Sections 501, 502, 512, 513 and 902) Redemption and Repayment Unless otherwise described above, your debt security will not be entitled to the benefit of any sinking fund—that is, we will not deposit money on a regular basis into any separate custodial account to repay your debt securities. In addition, we will not be entitled to redeem your debt security before its stated maturity unless a redemption commencement date is specified above. You will not be entitled to require us to buy your debt security from you, before its stated maturity, unless one or more repayment dates is specified above. If a redemption commencement date or a repayment date is specified above, one or more redemption prices or repayment prices may be specified, which may be expressed as a percentage of the principal amount of your debt security or by reference to one or more formulae used to determine the redemption price(s). It may also specify one or more redemption periods during which the redemption prices relating to a redemption of debt securities during those periods will apply. If a redemption commencement date is specified above, we may redeem your debt security at our option at any time on or after that date. If we redeem your debt security, we will do so at the specified redemption price, together with interest accrued to the redemption date. If different prices are specified for different redemption periods, the price we pay will be the price that applies to the redemption period during which your debt security is redeemed. If a repayment date is specified above, your debt security will be repayable by us at your option on the specified repayment date(s) at the specified repayment price(s), together with interest accrued to the repayment date. In the event that we exercise an option to redeem any debt security, we will give written notice of the principal amount of the debt security to be redeemed to the trustee at least 45 days before the applicable redemption date and to the holder not less than 30 days nor more than 60 days before the applicable redemption date. We will give the notice in the manner described above under "Additional Mechanics— Notices". If a debt security represented by a global security is subject to repayment at the holder's option, the depositary or its nominee, as the holder, will be the only person that can exercise the right to repayment. Any indirect holders who own beneficial interests in the global security and wish to exercise a repayment right must give proper and timely instructions to their banks or brokers through which they hold their interests, requesting that they notify the depositary to exercise the repayment right on their behalf. Different firms have different deadlines for accepting instructions from their customers; we urge you to take care to

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84 act promptly enough to ensure that your request is given effect by the depositary before the applicable deadline for exercise. We or our affiliates may purchase debt securities from investors who are willing to sell from time to time, either in the open market at prevailing prices or in private transactions at negotiated prices. Debt securities that we or they purchase may, in our discretion, be held, resold or canceled. Payment of Additional Amounts The government of any jurisdiction where BP or BP Capital U.K. is incorporated may require BP or BP Capital U.K. to withhold or deduct amounts from payments on the principal or interest on a debt security or any amounts to be paid under the guarantees for or on account of taxes or any other governmental charges. If the jurisdiction requires a withholding or deduction of this type, BP or BP Capital U.K., as the case may be, may be required to pay you an additional amount so that the net amount you receive will be the amount specified in the debt security to which you are entitled. However, in order for you to be entitled to receive the additional amount, you must not be resident in the jurisdiction that requires the withholding or deduction. BP or BP Capital U.K., as the case may be, will not have to pay additional amounts under any of the following circumstances: • The U.S. government or any political subdivision of the U.S. government is the entity that is imposing the tax or governmental charge. • The tax or governmental charge is imposed due to the presentation of a debt security, if presentation is required, for payment on a date more than 30 days after the security became due or after the payment was provided for. • The tax or governmental charge is on account of an estate, inheritance, gift, sale, transfer, personal property or similar tax or other governmental charge. The tax or governmental charge is for a tax or governmental charge that is payable in a manner that does not involve withholdings. • The tax or governmental charge is imposed or withheld because the holder or beneficial owner failed: • to provide information about the nationality, residence or identity of the holder or beneficial owner, or • to make a declaration or satisfy any information requirements, that the statutes, treaties, regulations or administrative practices of the taxing jurisdiction require as a precondition to exemption from all or part of such tax or governmental charge. • The withholding or deduction is imposed pursuant to European Council Directive 2003/48/EC or European Council Directive 2014/48/EC, regarding taxation of, and information exchange among member states of the European Union with respect to, interest income, or any other Directive implementing the conclusions of the ECOFIN Council meeting of 2627 November 2000, or any law implementing or complying with, or introduced in order to conform to, such Directives.

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85 • The withholding or deduction is imposed on a holder or beneficial owner who could have avoided such withholding or deduction by presenting its debt securities to another paying agent. • The tax or governmental charge is withheld or imposed due to a combination of the items listed above (other than the first bulleted item listed above). • The holder is a fiduciary or partnership or an entity that is not the sole beneficial owner of the payment of the principal of, or any interest on, any security, and the laws of the jurisdiction require the payment to be included in the income of a beneficiary or settlor for tax purposes with respect to such fiduciary or a member of such partnership or a beneficial owner who would not have been entitled to such additional amounts had it been the holder of such security. These provisions will also apply to any taxes or governmental charges imposed by any jurisdiction in which a successor to BP or BP Capital U.K., as the case may be, is organized. Additional circumstances in which BP would not be required to pay additional amounts, if any, are described above and in the prospectus supplement relating to the debt securities. (Section 1010) Optional Tax Redemption We may also have the option to redeem the debt securities of a given series if, as a result of any change in United Kingdom tax treatment, BP or BP Capital U.K. would be required to pay additional amounts as described in the previous subsection under "—Payment of Additional Amounts". This option applies only in the case of changes in United Kingdom tax treatment that occur on or after the date specified above for the applicable series of debt securities. The redemption price for the debt securities, other than original issue discount debt securities, will be equal to the principal amount of the debt securities being redeemed plus accrued interest. The redemption price for original issue discount debt securities will be specified above for such securities. (Section 1108) Event Risk Provisions The debt securities do not contain event risk provisions designed to require BP or the BP Debt Issuers to redeem or repurchase the debt securities, reset the interest rate or take other actions in response to highly leveraged transactions, changes in credit ratings or similar occurrences. Defeasance and Discharge The following discussion of full defeasance and discharge will be applicable to your series of debt securities only if we choose to have them apply to that series. If we do so choose, it will be stated in the above description of your debt securities. (Section 403) We can legally release ourselves from any payment or other obligations on the debt securities, except for various obligations described below, if we, in addition to other actions, put in place the following arrangements for you to be repaid: • We must deposit in trust for your benefit and the benefit of all other direct holders of the debt securities a combination of money and U.S. government or U.S. government agency notes or bonds that will generate enough cash to make interest, principal and any other payments on the debt securities on their various due dates. In addition, on the date of such deposit, we must not be in default. For purposes of this nodefault test, a default would include an event of default that has occurred and not been cured, as described below under "Default and Related Matters— Events of Default—What Is an Event of Default?" A default for this purpose would also include

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86 any event that would be an event of default if the requirements for giving us default notice or our default having to exist for a specific period of time were disregarded. • We must deliver to the trustee a legal opinion of our counsel confirming that under current U.S. federal income tax law we may make the above deposit without causing you to be taxed on the debt securities any differently than if we did not make the deposit and just repaid the debt securities ourselves. In the case of debt securities being discharged, we must deliver along with this opinion a private letter ruling from U.S. Internal Revenue Service to this effect or a revenue ruling pertaining to a comparable form of transaction to that effect published by the U.S. Internal Revenue Service. • If the debt securities are listed on the New York Stock Exchange, we must deliver to the trustee a legal opinion of our counsel confirming that the deposit, defeasance and discharge will not cause the debt securities to be delisted. However, even if we take these actions, a number of our obligations relating to the debt securities will remain. These include the following obligations: • to register the transfer and exchange of debt securities; • to replace mutilated, destroyed, lost or stolen debt securities; • to maintain paying agencies; and • to hold money for payment in trust. Default and Related Matters Ranking • The debt securities are not secured by any of our property or assets. Accordingly, your ownership of debt securities means you are one of our unsecured creditors. The debt securities are not subordinated to any of our other debt obligations and therefore they rank equally with all our other unsecured and unsubordinated indebtedness. Events of Default You will have special rights if an event of default occurs and is not cured, as described later in this subsection. What Is an Event of Default? The term "event of default" means, with respect to a debt security other than the 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes, any of the following: • We do not pay the principal or any premium on the debt security at maturity. • We do not pay interest on the debt security within 30 days of its due date. • We do not deposit any sinking fund payment for the debt security on its due date.

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87 • We remain in breach of a covenant or any other term of the applicable indenture for 90 days after we receive a notice of default stating we are in breach. The notice must be sent by either the trustee or holders of 25% of the principal amount of debt securities of the affected series. • We file for bankruptcy or certain other events if bankruptcy, insolvency or reorganization occur. • Any other event of default described above occurs. (Section 501) An "event of default" under the 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes occurs only in the event of a Winding-Up of BP Capital U.K. or BP other than for the purposes of a Solvent Reorganization of BP Capital U.K. or BP. If, for a period of 30 days or more, BP Capital U.K. or BP are in default in the payment of any principal or interest (including any Arrears of Interest) in respect of such subordinated notes which is due and payable (a "Payment Default"), then BP Capital U.K. and/or BP, as the case may be, will be deemed to be in default under the Indenture and the relevant Notes, and the Trustee may, and if instructed by the holders as described in "—Entitlement of the Trustee" in the relevant prospectus supplement shall, take such actions as set forth under "—Proceedings" or "—Enforcement" in the relevant prospectus supplement, to institute actions, steps or proceedings for the Winding-Up of BP Capital U.K. and/or BP. For the avoidance of doubt, a Payment Default is not an Event of Default and shall not result in any right of Acceleration pursuant to Section 502 of the Indenture. Remedies If an Event of Default Occurs. If an event of default has occurred and has not been cured, the trustee or the holders of 25% in principal amount of the debt securities of the affected series may declare the entire principal amount of all the debt securities of that series to be due and immediately payable. This is called a declaration of acceleration of maturity. A declaration of acceleration of maturity may be canceled by the holders of at least a majority in principal amount of the debt securities of the affected series if: • all amounts due (as interest, principal and otherwise) are paid or deposited with the trustee; and • all events of default, other than the nonpayment of the principal of the debt securities which have become due solely by such declaration of acceleration, have been cured or waived. (Section 502) Except in cases of default, where the trustee has some special duties, the trustee is not required to take any action under the indenture at the request of any holders unless the holders offer the trustee reasonable protection from expenses and liability. This protection is called an indemnity. (Section 603) If reasonable indemnity is provided, the holders of a majority in principal amount of the outstanding debt securities of the relevant series may direct the time, method and place of conducting any lawsuit or other formal legal action seeking any remedy available to the trustee. These majority holders may also direct the trustee in performing any other action under the indenture. (Section 512) Before you bypass the trustee and bring your own lawsuit or other formal legal action or take other steps to enforce your rights or protect your interests relating to the debt securities, the following must occur, provided that the provisions of this paragraph do not apply to the 4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes: • You must give the trustee written notice that an event of default has occurred and remains uncured. • The holders of 25% in principal amount of all outstanding debt securities of the relevant series must make a written request that the trustee take action because of the default, and must

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88 offer reasonable indemnity to the trustee against the cost and other liabilities of taking that action. • The trustee must have not taken action for 60 days after receipt of the above notice, request and offer of indemnity. (Section 507) We will furnish to the trustee every year a written statement of certain of our officers certifying that, to their knowledge, we are in compliance with the indenture and the debt securities, or else specifying any default. (Section 1008) Regarding the Trustee BP and several of its subsidiaries maintain banking relations with the trustee group of companies in the ordinary course of their business. The Bank of New York Mellon Trust Company, N.A. acts as trustee under other indentures under which BP acts as guarantor. If an event of default occurs, or an event occurs that would be an event of default if the requirements for giving us default notice or our default having to exist for a specific period of time were disregarded, the trustee may in certain circumstances prescribed by the Trust Indenture Act of 1939 be considered to have a conflicting interest with respect to the debt securities or the applicable indenture. In that case, the trustee may be required to resign as trustee under the applicable indenture and we would be required to appoint a successor trustee.

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## Exhibit 4.1

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RULES APPLICABLE TO AWARDS GRANTED ON OR AFTER 26 JULY 2023 THE BP EXECUTIVE DIRECTORS' INCENTIVE PLAN (Adopted by shareholders at the Annual General Meeting on 13th April 2000) (Renewed by shareholders at the Annual General Meeting on 14th April 2005) (Renewed by shareholders at the Annual General Meeting on 15th April 2010) (Renewed by shareholders at the Annual General Meeting on 10th April 2014) (Amended by the Remuneration Committee on 18th May 2017) (Renewed by shareholders at the Annual General Meeting on 27th May 2020) (Amended by the Remuneration Committee on 26th July 2023)

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RULES APPLICABLE TO AWARDS GRANTED ON OR AFTER 26 JULY 2023 CONTENTS PART PAGE THE BP EXECUTIVE DIRECTORS' INCENTIVE PLAN ........................................ 1 DEFINITIONS ............................................................................................................. 2 EDIP PERFORMANCE SHARE ELEMENT .............................................................. 7 EDIP DEFERRED BONUS ELEMENT ..................................................................... 22

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RULES APPLICABLE TO AWARDS GRANTED ON OR AFTER 26 JULY 2023 134 THE BP EXECUTIVE DIRECTORS' INCENTIVE PLAN This document sets out the rules of the EDIP as they will apply for Awards granted following 26 July 2023. A separate version of the rules sets out the rules of the EDIP as they applied for Awards granted before 26 July 2023. PREAMBLE The EDIP has two elements which comprise the tools available to the Committee to construct Executive Directors' long-term incentive arrangements: 1. The Performance Share Element (Part 1) This element permits performance share awards to be granted which may result in Shares vesting (without payment) to the extent that a performance condition imposed by the Committee is met. 2. The Deferred Bonus Element (Part 2) This element permits a proportion of the annual bonus for any financial year to be deferred into a share award that will vest subject to continued employment only. The Performance Share Element and the Deferred Bonus Element are each standalone elements of the EDIP under which distinct awards are granted, but together comprise the EDIP. The key objectives of the EDIP are to ensure that the remuneration packages for the Executive Directors support the Company's goal of maximizing sustainable long-term shareholder value, and to provide a just system of fixed and variable pay for Executive Directors, taking into account the success of the Company and the competitive global marketplace in which the Company operates. The Committee will keep these objectives, and the manner in which it operates the EDIP, under regular review, and will be proactive in obtaining an understanding of shareholder preferences.

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234 DEFINITIONS 1.1 In this EDIP, unless the context otherwise requires, the following words and expressions shall have the following meanings, namely: Approval Date means the date of approval of the EDIP by the Company in general meeting; Award means an award granted under rule 1 in the form of an Option, a Conditional Award or a Phantom Award as the Committee may determine, which is for the time being subsisting; Award Certificate means the notification to a Participant setting out the specific conditions of an Award in such form as the Committee may determine from time to time; Board means the board of directors of the Company or a duly authorised committee of it which may include the Committee; Capital Reorganisation means any variation in the share capital or reserves of the Company (including, without limitation, by way of capitalisation issue, rights issue, open offer, sub-division, consolidation or reduction); Cause means material breach by a Participant of his/her contract of employment; Cash Amount means, in relation to an Award which has Vested, an amount which, in the opinion of the Committee, is equal to the Market Value on the Vesting Date of the Vested Shares less any amount which the Participant is required to pay under these rules in order to realise the Award; Committee means the remuneration committee of the Board or such other appropriately constituted committee; Company means BP p.l.c. registered in England and Wales under number 00102498; Company's Remuneration Policy means at any time the directors' remuneration policy most recently approved by shareholders of the Company in accordance with section 439A Companies Act 2006; Conditional Award means an Award which takes the form of a conditional right to acquire or receive Shares at no or nominal cost or a conditional allocation of Shares; Control has the meaning given to that word by section 995 of the Income Tax Act 2007; Date of Grant means the date on which the Committee grants an Award; Dealing Day means any day on which the London Stock Exchange is open for the transaction of business; Dealing Restriction means a restriction imposed by any law, order, regulation or directive, the Listing rules, the Market Abuse Regulation, the Share Dealing Code, the City Code on Takeovers and Mergers, the rules applying to any Listing of the Company and/or any other code adopted by the Company regulating dealings in Shares; Deferral Period means the period(s) specified by the Committee pursuant to rule 1.5 of the Deferred Bonus Element;

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334 Deferred Bonus Element means the BP EDIP Deferred Bonus Element; Dividend Equivalent means additional Shares awarded to a Participant in respect of his/her Vested Shares; the EDIP means this Executive Directors Incentive Plan, comprising the Performance Share Element and the Deferred Bonus Element, as amended from time to time; Employees' Share Scheme has the meaning given by section 1166 of the Companies Act 2006; Executive means a person who, at the Date of Grant is an employee (including an executive director of the Company) of any member of the Group; Financial Year means a financial year of the Company within the meaning of section 390 of the Companies Act 2006; Grant Period means the period of 42 days commencing on any of the following: (a) 26 July 2023 (being the date the EDIP in its current form was approved by shareholders of the Company or the Committee); (b) the day on which the Company makes an announcement of its results for any period; (c) any day on which the Committee resolves that exceptional circumstances exist which justify the grant of Awards; or (d) the day following the lifting of any Dealing Restrictions which prevented the grant of the Award during the periods referred to in (a) to (c) above. Group means the Company and the Subsidiaries from time to time and the expressions member of the Group and Group Company shall be construed accordingly; Listed means admitted to trading on the London Stock Exchange or other recognised stock exchange, and Listing will be construed accordingly; Listing Rules means the UK Listing Rules published by the Financial Conduct Authority (as amended from time to time); the London Stock Exchange means London Stock Exchange Group plc or any successor body thereto; Malus and Clawback Policy means the Company's malus and clawback policy, as amended from time to time; Market Abuse Regulation means Regulation (EU) No 596/2014 of the European Parliament and of the Council of 16 April 2014 on market abuse (or any equivalent or successor legislation); Market Value means, in relation to a Share on any day: (a) if and for so long as the Shares are admitted to trading on the London Stock Exchange: (i) the closing middle-market quotation for a Share on that day (as derived from the daily official list of the London Stock Exchange); or

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434 (ii) the average of the closing middle-market quotations during such period as the Committee may determine but not exceeding 30 Dealing Days ending on that day and provided such Dealing Day(s) fall within a Grant Period; or (b) if the Shares are ADRs, the Committee has the discretion to calculate the value of ADRs by reference to the closing middle-market quotation for an ADR as valued on the New York Stock Exchange on that day; or (c) if the Shares are not admitted to trading on the London Stock Exchange, the market value of a Share on that day as determined in accordance with Part VIII of the UK Taxation of Chargeable Gains Act 1992; Misconduct means: (a) material misconduct; (b) conduct in which the Executive has participated or was responsible for which has resulted or could result in material financial loss or reputational harm; (c) failure to meet appropriate standards of fitness and propriety; and (d) any other misconduct as determined by the Committee in its discretion; Notional Amount has the meaning given in rule 1.3 of the Deferred Bonus Element; Notional Share means a notional share equal in value to a Share, but having no legal rights attributable to a Share; Official List means the Official List of the UK Financial Conduct Authority; Option means an Award which takes the form of an option to acquire Shares at no or nominal cost following Vesting; Participant means an individual who holds a subsisting Award (including, where the context permits, the legal personal representatives of a deceased Participant); Performance Conditions means the performance conditions applicable to an Award as determined by the Committee at the Date of Grant; Performance Period means, unless the Committee determines otherwise at the Date of Grant, in relation to an Award, the period of three Financial Years commencing with the Financial Year in which the Date of Grant falls; Performance Share Element means the BP EDIP Performance Share Element; and Phantom Award means an Award which takes the form of a right to receive a cash payment calculated by reference to the Market Value of a Notional Share; Plan means the BP Executive Directors' Incentive Plan comprising the Performance Share Element and the Deferred Bonus Element as amended from time to time in accordance with the rules; Registered Holder means any person or persons nominated by the Company to hold Retained Shares on behalf of a Participant; Relevant Date has the meaning set out below, with references to sub-rules for the Performance Share Element being to sub-rules of rule 12 and for the Deferred Bonus Element being to sub-rules of rule 7:

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534 (a) if the Relevant Event falls within sub-rule (a) the date on which Control is obtained and any conditions to which the offer is made subject are satisfied; (b) if the Relevant Event falls within sub-rule (b), either the date on which the scheme of arrangement is approved at the shareholders' meeting or is sanctioned by the Court (as determined by the Committee in its absolute discretion); (c) if the Relevant Event falls within sub-rule (c), the date on which the person first becomes so bound or entitled; or (d) if the Relevant Event falls within sub-rule (d), the date on which notice of the resolution for winding up is given; Retained Shares means a Participant's Vested Shares and the Dividend Equivalents attributable thereto which shall be held by the Registered Holder pursuant to rule 6 of the Performance Share Element; Retention Period means a period of three years ending with the sixth anniversary of the date of commencement of the Performance Period; Share Dealing Code means the Company's code on share dealing as in force from time to time; Shares means fully paid ordinary shares in the capital of the Company or ADRs representing those shares or shares or ADRs representing those shares following any Capital Reorganisation and references to Shares shall include Notional Shares where required; Subsidiary means any company which is a subsidiary of the Company within the meaning of section 1159 of and Schedule 6 to the Companies Act 2006; Tax and/or Tax Liability means all liability to income tax (or overseas equivalent) which any member of the Group is liable to account for on behalf of the Participant directly to any taxation authority (including, but without limitation, through the PAYE system) and all liability to social security (or overseas equivalent) which any member of the Group is liable to account for on behalf of the Participant to any taxation authority (including, but without limitation, primary Class 1 (employee's) National Insurance contributions) which arises in connection with an Award or Shares; Termination Date means the date on which a Participant ceases to be employed by the Group; Transfer Date means the date on which Shares may be released from the Retention Period in accordance with the rules of this Plan; Treasury Shares means treasury shares held by the Company in accordance with sections 724 to 732 of the Companies Act 2006; Trustees means the trustees or trustee for the time being of any employee benefit trust established by the Company or any member of the Group from time to time for the benefit of employees of the Group; Vesting Date means in respect of an Award (a) the later of: (i) the third anniversary of the Date of Grant; (ii) the date on which the Committee has determined the Performance Conditions (if applicable) have been satisfied; (iii) the date on which the

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634 Deferral Period ends; or (b) such other date as an Award may vest in accordance with these rules, provided that if the Vesting Date would otherwise fall in a Closed Period or on a date when the Company and/or the Participant would otherwise be subject to any Dealing Restrictions, it shall be at such later date as when those Dealing Restrictions lift; Vesting Period means in relation to an Award, the period beginning on the Date of Grant of such Award and ending on the Vesting Date; and Vested Shares means Shares or notional Shares the subject of Awards in respect of which the Vesting Date has passed, and Vest and Vesting shall be construed accordingly. 1.2 Interpretation. In the EDIP, unless the context otherwise requires: (a) references to a person include any individual, firm, body corporate (wherever incorporated), government, state or agency of a state or any joint venture, association, partnership, works council or employee representative body (whether or not having separate legal personality); (b) headings do not affect the interpretation of the EDIP; the singular shall include the plural and vice versa; and references to one gender include all genders; and (c) references to "realise", "realised" or "realisable" in the case of a Conditional Award and a Phantom Award shall, in the case of an Option, be construed as "call for", "called for" or "may be called for" respectively. 1.3 Enactments. Except as otherwise expressly provided in the EDIP, any express reference to an enactment includes references to: (i) that enactment as amended, consolidated or re-enacted by or under any other enactment before or after the Adoption Date; (ii) any enactment which that enactment re-enacts (with or without modification); and (iii) any subordinate legislation (including regulations) made (before or after the Adoption Date) under that enactment, as amended, consolidated or re-enacted as described at (i) or (ii) above.

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734 PART 1 EDIP Performance Share Element

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834 CONTENTS RULE PAGE 1. GRANT OF AWARDS ..................................................................................... 9 2. PERFORMANCE CONDITIONS ..................................................................... 9 3. INDIVIDUAL LIMITS ON AWARDS .......................................................... 10 4. VESTING OF AWARDS ................................................................................ 10 5. ENTITLEMENT TO DIVIDEND EQUIVALENTS ...................................... 11 6. RIGHTS OF PARTICIPANTS DURING THE RETENTION PERIOD ........ 11 7. TRANSFER OF RETAINED SHARES .......................................................... 12 8. LEAVERS ........................................................................................................ 13 9. ISSUE, TRANSFER OR LISTING OF SHARES .......................................... 14 10. DEALING RESTRICTIONS ........................................................................... 14 11. LAPSE OF AWARDS ..................................................................................... 14 12. CORPORATE EVENTS ................................................................................. 15 13. ROLLOVER OF AWARDS ............................................................................ 16 14. ADJUSTMENTS OF AWARDS ..................................................................... 17 15. MALUS AND CLAWBACK .......................................................................... 18 16. TAXATION ..................................................................................................... 18 17. PLAN LIMITS ................................................................................................. 18 18. AMENDMENT AND ADMINISTRATION .................................................. 19 19. GENERAL ....................................................................................................... 20 20. GOVERNING LAW ....................................................................................... 21

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RULES APPLICABLE TO AWARDS GRANTED ON OR AFTER 26 JULY 2023 934 1. GRANT OF AWARDS 1.1 The Committee shall, in its absolute discretion, determine which Executives (if any) will be selected for the grant of an Award. Awards may then be granted to selected Executives during a Grant Period. 1.2 An Executive may be granted any form of Award or any combination of Awards. The Committee shall determine whether any Award will take the form of an Option, a Conditional Award or a Phantom Award. Each Award shall be evidenced by an Award Certificate issued by the Company or such other documentation as the Committee may determine in its absolute discretion. 1.3 Prior to the granting of any Awards, the Committee may, in its absolute discretion, enter into a deed poll recording its intention to grant Awards and agreeing to be bound by the Award Certificates issued pursuant to rule 1.2 above. 1.4 No payment shall be required for the grant of an Award. 1.5 No Award shall be granted under the Plan more than ten years after the Approval Date. 1.6 Every Award granted under this Plan shall be personal to the Participant to whom it is granted and, except to the extent necessary to enable a personal representative to realise the Award following the death of a Participant, neither the Award nor the benefit of that Award may be transferred, assigned, charged or otherwise alienated. An Award will lapse immediately if the Participant to whom it was made purports to transfer, charge or otherwise alienate that Award otherwise than as permitted by this rule 1.6. 1.7 The grant of any Award under the Plan shall be subject to any applicable Dealing Restrictions. 2. PERFORMANCE CONDITIONS 2.1 The Vesting of all Awards will be dependent upon the satisfaction of Performance Conditions that are considered by the Committee to be appropriate to the strategic objectives of the Group. The Committee can set different Performance Conditions for Awards granted in different years (in terms of the type of condition, the weighting given to that condition and the targets applicable to each condition) provided that, in the reasonable opinion of the Committee, the Performance Conditions are not materially less challenging from any one Award to the next. 2.2 An Award will Vest as to the percentage of Shares (or, in the case of an Award which is granted in the form of a Phantom Award, notional Shares) determined in accordance with the Performance Conditions. 2.3 The Committee may determine that an Award should be subject to multiple Performance Conditions or that an Award should be sub-divided and that each part be subject to a different condition. 2.4 The Committee may vary the Performance Conditions applying to existing Awards if an event occurs or there are circumstances (for example, an acquisition or disposal of a business or a significant part of a business) such that the conditions are no longer a fair measure of performance provided that, in the reasonable opinion of the Committee, the new conditions are not materially less challenging than the original conditions

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1034 would have been but for the event or circumstances in question. In exercising any power to vary the Performance Conditions, the Committee will have regard to ensuring fairness between Participants and shareholders. 2.5 The Committee shall, as soon as reasonably practicable, notify a Participant of any determination made under rule 2.4. 2.6 An Award shall lapse to the extent the Performance Conditions are not met at the relevant Vesting Date. 3. INDIVIDUAL LIMITS ON AWARDS 3.1 The maximum aggregate value of Awards which an Executive may be granted in respect of any Financial Year shall be determined by reference to the maximum grant permitted for the Chief Executive Officer in accordance with the Company's Remuneration Policy, as amended from time to time. The Committee shall have absolute discretion as to how the maximum 'aggregate value' of an Award is determined taking account of the need to balance the interests of shareholders, the Company and Executives, including but not limited to using the total Market Value averaged over the last quarter of the Financial Year immediately preceding the Date of Grant and the total Market Value averaged over a number of Dealing Days immediately preceding the Date of Grant. 3.2 If the grant of any Award would result in the breaching of the limit in rule 3.1, that Award shall be treated as taking effect over the maximum number of Shares over which it could have been granted without breaching such limit. 4. VESTING OF AWARDS 4.1 Save as otherwise permitted in these rules, and subject to any applicable Retention Period, an Award shall Vest: (a) on the Vesting Date; (b) to the extent that the Performance Conditions which apply to that Award have been met; and (c) provided that the Participant has remained an Executive during the relevant Performance Period and until the Vesting Date. 4.2 Subject to any Dealing Restrictions, Shares comprised in a Vested Conditional Award will be issued or transferred to the Participants subject to any arrangements to give effect to the Retention Period in accordance with rules 6 and 7, as soon as reasonably practicable following the Vesting Date. A Participant need take no action to realise a Conditional Award other than pay the Company any amount specified at the Date of Grant to realise the Award. 4.3 Subject to any Dealing Restrictions, Vested Options are exercisable by written notice to the Company in the form required by the Company and payment of any amount specified at the Date of Grant to realise the Award at any time during the period of 6 months following the Vesting Date. A notice of exercise will take effect on the date it is accepted as valid by the Company or, if there are any Dealing Restrictions in place on that date, such later date when all Dealing Restrictions have lifted. Subject to any

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1134 Dealing Restrictions and any arrangements to give effect to the Retention Period in accordance with rules 6 and 7, the Shares comprised in a Vested Option will be issued or transferred to the Participant as soon as reasonably practicable following the date the notice of exercise takes effect. 4.4 Vested Phantom Awards shall be satisfied in the next available payroll following the Vesting Date by a payment equal to the Market Value of the Vested notional Shares under the Phantom Award on the Vesting Date. 4.5 Save as otherwise provided in these rules, an Award shall lapse automatically on the Participant ceasing to be an Executive at any time before the Vesting Date applicable to the Award. 4.6 Notwithstanding the above, a Participant's Award shall not Vest if they are suspended from their employment by reason of suspected Misconduct at the Vesting Date or if the Committee has reason to believe that there are circumstances that could give rise to the application of rule 15 and shall only Vest on such date as the Participant is found not to have committed such Misconduct or the Committee has determined that there are no circumstances that would justify the application of rule 15. 5. ENTITLEMENT TO DIVIDEND EQUIVALENTS 5.1 The Committee may in its discretion grant an Award on the basis that it carries Dividend Equivalents. 5.2 If an Award has been granted on the basis that it carries Dividend Equivalents, the Participant will, subject to rule 5.4, be entitled to additional Shares, equal in value to the dividends which would have been paid on the Shares which have Vested during the Vesting Period, such Dividend Equivalent to accrue on the relevant record date for an interim or final dividend in respect of Shares and to be paid on or around the date an Award is satisfied by the Company. 5.3 The additional Shares to which the Participant becomes entitled under rule 5.2 will be calculated in such manner as the Committee in its absolute discretion determines including whether it will be calculated by reference only to ordinary dividends and without regard to special dividends or distributions, super dividends or dividends-in- specie. In making any determination the Committee shall have regard to the effect of the dividend on the value of an Award and whether the Award is otherwise being adjusted in connection with payment of the dividend. 5.4 Instead of issuing or transferring additional Shares, the Committee may in its absolute discretion satisfy any entitlement to Dividend Equivalents arising in accordance with rule 5.2 by giving a cash payment with an equivalent value as determined at the time of Vesting. 5.5 For the avoidance of doubt, any payment referred to in this rule 5 does not represent an entitlement to actual dividends on the underlying Shares, by reason of the Participant not being the beneficial owner of the Shares at that time. 6. RIGHTS OF PARTICIPANTS DURING THE RETENTION PERIOD 6.1 Following the Vesting Date, a sufficient number of Vested Shares and Dividend Equivalents may be sold on the Participant's behalf in order to discharge any tax and

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1234 social security liabilities that arise on vesting of the Award. Any shares not sold shall become Retained Shares for the purposes of this rule 6. 6.2 The Committee shall procure that the Retained Shares shall be held by the Registered Holder on behalf of the Participant under the terms of this Plan until the Transfer Date. 6.3 Subject to the retention obligation under rule 6.2 above, the Participant shall be beneficial owner of the Retained Shares with effect from the Vesting Date. The Participant shall enjoy all rights attaching to the Retained Shares (including dividend and voting rights in respect of such Shares) except rights attaching to Shares by reference to a record date preceding the Vesting Date. 6.4 Shares or other securities issued to the Registered Holder in respect of Retained Shares shall be retained by the Registered Holder as if they were the Retained Shares from which they derive. In the event of a rights issue, the Registered Holder may, if the Participant requests, transfer to the Participant any Shares or other securities acquired with funds provided by the Participant. 7. TRANSFER OF RETAINED SHARES 7.1 Save as otherwise provided in these rules the Transfer Date shall be the date on which the Retention Period expires. 7.2 If on the date the Retention Period would otherwise expire, the Participant is suspended from their employment by reason of suspected Misconduct, the Retention Period shall only expire on such date as there is a final finding by the Company in respect of that suspected Misconduct. 7.3 Where a Participant ceases to be an employee of a member of the Group due to a reason stated in rules 8.1 and 8.2, the Transfer Date shall be: (a) where the Termination Date occurs during the Retention Period, 12 months after the Termination Date unless the Committee decides otherwise at its absolute discretion pursuant to rule 7.5; and (b) where the Termination Date occurs during the Performance Period, 12 months after the Vesting Date unless the Committee in its absolute discretion determines otherwise. 7.4 As soon as practicable after the Transfer Date, the Company shall procure the transfer to each Participant of the full legal and beneficial ownership of the Retained Shares held on his behalf free from any liens, charges or encumbrances. 7.5 At the request of a Participant, the Committee may at its absolute discretion agree to the transfer to the Participant of some or all of the Retained Shares held on his behalf before the Transfer Date in the following circumstances: (a) the Participant dies and the Company has received satisfactory evidence of the grant of probate in respect of the deceased Participant's estate; (b) the occurrence of any of the corporate transactions set out in rule 12 of the Plan; or

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1334 (c) the Committee resolves in its absolute discretion that Retained Shares should be released to the Participant. 8. LEAVERS 8.1 Death. If a Participant dies, Awards granted to him/her will Vest on the Termination Date in accordance with rule 8.4. 8.2 Other Leavers. Where a Participant ceases to be an Eligible Employee at any time before the Vesting Date applicable to his Award by reason of: (a) redundancy; (b) injury, disability or ill-health (evidenced to the satisfaction of the Committee); (c) his/her employing company ceasing to be under the Control of the Company; (d) the business (or part of a business) in which he is employed being transferred to a person who is not a member of the Group; or (e) any other reason at the discretion of the Committee, his/her Award shall continue, and will Vest on the original Vesting Date in accordance with rule 8.3, save that the Committee may determine that an Award shall instead Vest on the Termination Date in accordance with rule 8.4. Where an Award is subject to more than one Performance Condition, the Committee may treat each discrete part of the Award that is subject to a particular Performance Condition as a separate Award with the result that the Committee may determine that part of an Award shall continue and Vest on the original Vesting Date in accordance with rule 8.3 and that part of an Award shall Vest on the Termination Date. 8.3 Delayed Vesting. Where, by reason of rule 8.2, an Award Vests in accordance with this rule 8.3, the number of Vested Shares shall be determined by the Committee by reference to: (a) the application of the Performance Condition at the original Vesting Date; and (b) multiplying the resulting number of Shares or Notional Shares by the fraction A/B (where A is the number of complete months from the Date of Grant to the Termination Date and which shall not be greater than the total number of months in the Vesting Period and B is 36 or such other number as is equal to the number of months in the Vesting Period), save that the Committee may, in its absolute discretion, disapply in whole or in part the application of the time pro-rating fraction. 8.4 Immediate Vesting. Where, by reason of rule 8.1 or rule 8.2, an Award Vests in accordance with this rule 8.4 the number of Vested Shares shall be determined by the Committee by reference to: (a) the application of the Performance Condition at the Termination Date, or at such other date (whether later or earlier) within a reasonable period of the Termination Date on which data is available in the ordinary course to allow the testing of Performance Conditions; and

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1434 (b) multiplying the resulting number of Shares or Notional Shares by the fraction A/B (where A is the number of complete months from the Date of Grant until the Termination Date and which shall not be greater than the total number of months in the Vesting Period and B is 36 or equal to such other number of months in the original Vesting Period), save that in any particular case, the Committee may, in its absolute discretion, disapply in whole or in part the application of the time pro-rating fraction. 8.5 If a Participant ceases employment in any circumstances other than those described at rules 8.1 or 8.2, his unvested Awards shall lapse automatically on the Termination Date. 8.6 For the avoidance of doubt, where a Participant ceases employment and has Shares that are subject to a Retention Period, that Retention Period shall continue irrespective of the reason for cessation of employment with Shares being transferred on the Transfer Date in accordance with rule 7. 8.7 Meaning of ceasing employment. For the purposes of this rule 8, a Participant shall not be treated as ceasing to be an Executive until he or she ceases to be employed by or hold office with the Company or any member of the Group. The reason for the termination of employment of a Participant shall be determined by reference to rule 8.1 and 8.2 regardless of whether such termination was lawful or unlawful (and howsoever caused). 9. ISSUE, TRANSFER OR LISTING OF SHARES 9.1 The Committee shall issue or procure the transfer of Shares to be allotted or transferred pursuant to: (i) the realisation of a Conditional Award within 30 days following the Vesting Date of the Award; and (ii) pursuant to the exercise of an Option, within 30 days of receipt of the notice of exercise by the Company. 9.2 Shares to be issued or transferred pursuant to the Plan will rank pari passu in all respects with the Shares then in issue, except that they will not rank for any rights attaching to Shares by reference to a record date preceding the Vesting Date. 9.3 For so long as the Shares are admitted to Listing, application will be made for any newly issued ordinary shares to be admitted to such listing and admitted to trading on the relevant stock exchange. 10. DEALING RESTRICTIONS 10.1 Notwithstanding any other rule of this Plan, no Award shall be granted, Vest, exercised, adjusted or satisfied (as applicable) if (i) it would be prohibited by any Dealing Restriction or (ii) the sale of any Shares to meet any Tax liability as a consequence of such grant, Vesting, exercise, adjustment or satisfaction (as applicable) would be prohibited by any Dealing Restriction. 11. LAPSE OF AWARDS 11.1 Awards shall lapse upon the occurrence of the earliest of the following events: (a) to the extent that it is determined by the Committee that the Performance Conditions applicable to an Award have not been met following the expiry of the relevant Performance Period, the expiry of that Performance Period;

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1534 (b) the Participant ceasing to be an Executive other than in the circumstances specified in rules 8.1 or 8.2; (c) in relation to an Award which is granted in the form of an Option, 6 months following the Vesting Date; (d) the expiry of any relevant period specified in rule 12; (e) unless the Committee determines otherwise, the Participant being deprived of the legal or beneficial ownership of the Award by operation of law, or doing or omitting to do anything which causes them to be so deprived including becoming or being declared bankrupt; (f) any purported transfer of an Award otherwise than as permitted by rule 1.6; or (g) to the extent that the Participant fails to realise the Award under rule 8. 12. CORPORATE EVENTS Takeover and Liquidation 12.1 This rule 12 applies if: (a) any person (either alone or together with any person acting in concert with him) obtains Control of the Company as a result of making: (i) a general offer to acquire the whole of the issued ordinary share capital of the Company which is made on a condition such that if it is satisfied, the person making the offer will have Control of the Company; or (ii) a general offer to acquire all of the Shares; (b) any person proposes to obtain Control of the Company in pursuance of a compromise or arrangement sanctioned by the Court under Part 26 of the Companies Act 2006 or its equivalent under applicable law; (c) any person becomes bound or entitled to acquire Shares in the Company under sections 974 to 991 inclusive of the Companies Act 2006 or its equivalent under applicable law; or (d) notice is given of a resolution for the voluntary or compulsory winding-up of the Company, (each a Relevant Event). 12.2 Where this rule 12 applies and subject to rules 12.3, 12.4 and 13.1 below, all outstanding Awards will automatically Vest and, in the case of an Award granted in the form of an Option shall be automatically exercised on the Relevant Date provided that any exercise price payable by the Participant on exercise is equal to or less than the relevant offer price or consideration (as determined by the Committee). Where this rule 12 applies, and subject to rules 12.3, 12.4 and 13.1 below, any outstanding Awards granted in the form of Options that are not exercised on the Relevant Date shall lapse automatically. Proportion of Award that Vests

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1634 12.3 The number of Shares in respect of which the Award Vests shall be determined by the Committee by reference to: (a) the application of the Performance Condition at the Relevant Date; and (b) multiplying the resulting number of Shares or Notional Shares by the fraction A/B (where A is the number of complete months from the Date of Grant until the Relevant Date and which shall not be greater than the total number of months in the Vesting Period and B is 36 or equal to such other number of months in the original Vesting Period), save that in any particular case, the Committee may, in its absolute discretion, disapply, in whole or in part, the application of the time pro-rating fraction. 12.4 Without prejudice to the operation of rule 13, Awards shall not Vest or be exercised without the consent of the Committee under the foregoing provisions of this rule 12 if the purpose and effect of the Relevant Event, together with any associated transactions, is to create a new holding company for the Company, such company having substantially the same shareholders and proportionate shareholdings as those of the Company immediately prior to the Relevant Event. Unless the Committee determines otherwise in its absolute discretion, an Award will in such circumstances be exchanged for an equivalent award in accordance with rule 13 below and notice of a replacement award shall be issued to each affected Participant accordingly. Demerger 12.5 If the Committee becomes aware that the Company is or is expected to be affected by any demerger, dividend in specie, super-dividend or other transaction which, in the opinion of the Committee, would affect the current or future value of any Awards, the Committee, acting fairly, reasonably and objectively, may in its absolute discretion allow some or all Awards to be realised in accordance with rule 12.3. The Committee shall specify the period in which such Awards shall be realisable and whether such Awards shall lapse at the end of the specified period. 12.6 Where a Participant ceases to be employed by a member of the Group at any time before the Vesting Date applicable to an Award by reason of the demerger by the Company of the business or division in which they are employed, the Committee may determine for some or all Participants leaving the Group as a result of the demerger that part or all of the Award shall vest and/or that Awards held by such Participants should be rolled over into equivalent awards over shares in the demerged company (or such terms as the Committee shall agree with that company). This is without prejudice to the operation of the provisions in rule 12.5 or 8.2 in the event of a demerger. 13. ROLLOVER OF AWARDS 13.1 If any other business entity (the acquiring company): (a) obtains Control of the Company as a result of making: (i) a general offer to acquire the whole of the issued ordinary share capital of the Company which is made on a condition such that if it is satisfied the acquiring company will have Control of the Company; or (ii) a general offer to acquire all the Shares; or

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1734 (b) proposes to obtain Control of the Company in pursuance of a compromise or arrangement sanctioned by the Court under Part 26 of the Companies Act 2006 or its equivalent under applicable law; or (c) becomes bound or entitled to acquire shares in the Company under sections 974 to 991 inclusive of the Companies Act 2006 or their equivalent under applicable law, and the acquiring company notifies Participants of an offer of a replacement Award, then, on the Relevant Date, for any Award which has not lapsed (the old award) a Participant may elect to release and accept in consideration of that release an award (the new award) which (in the opinion of the Committee) is equivalent to the old award but relates to shares in a different company (whether the acquiring company itself or another company) (the new grantor). 13.2 The provisions of the Plan shall be construed as if: (a) the new award were an award granted under the Plan at the same time as the old award; (b) references to the Company in the rules were references to the new grantor; (c) references to the Committee in the rules were references to the board of directors of the new grantor or any duly authorised committee thereof; (d) references to Shares were references to shares in the new grantor; and (e) the Vesting Date in relation to the new award was the same as that in relation to the old award. 13.3 The Committee may make such adjustments to the Performance Condition applicable to the new award as it, in its absolute discretion, considers appropriate. 13.4 Subject to rule 12.4, if notice is given by an acquiring company under rule 13.1 and a Participant does not elect to release an old award and accept in consideration for that release a new award, the old award will vest and be exercised in accordance with rule 12.2. 14. ADJUSTMENTS OF AWARDS 14.1 In the event of any Capital Reorganisation (or the implementation by the Company of a demerger or payment of a super dividend which would otherwise materially affect the value of an Award) the Committee may adjust the number of Shares subject to Awards (including, for the avoidance of doubt, Vested Shares in respect of which any Award has been realised but Shares have not yet been transferred to the Participant) to such extent and in such manner as it thinks fit. 14.2 Any adjustments to Awards made pursuant to rule 14.1 shall be notified to the relevant Participants as soon as is reasonably practicable and the Committee may call in, cancel, endorse, issue or re-issue any Award certificate as a result of that adjustment.

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1834 15. MALUS AND CLAWBACK 15.1 Notwithstanding any provision in these rules or in any Award Certificate, Awards are subject to the Malus and Clawback Policy and by accepting an Award, a Participant agrees to be bound by the terms of that policy. 16. TAXATION 16.1 Any liability of a Participant to Tax or social security contributions in respect of an Award (including, for the avoidance of doubt, any cash amount paid under these rules) shall be for the account of the relevant Participant, and the release of any Shares the subject of a Conditional Award or the exercise of any Option shall be conditional on the Participant complying with any arrangements specified by the Company or the Trustees for the payment of taxation and any social security contributions (including, without limitation, the sale of sufficient Shares to enable the Company or the Trustees or any employing company in the Group to satisfy its obligations in respect of deduction of taxation and employee's social security contributions at source). 16.2 The Company or, where the Committee so directs, any member of the Group, will pay the appropriate stamp duty on behalf of Participants in respect of any transfer of Shares on the Vesting of a Share Award or exercise of an Option under the Plan. 17. PLAN LIMITS 17.1 No Award shall be granted under the Plan to the extent that the result of that grant would be that the aggregate number of Shares that could be issued on the realisation of that Award and any other Award granted at the same time, when added to the number of Shares that: (a) could be issued on the realisation of any subsisting awards or options granted during the preceding ten years under the Plan or any other Employees' Share Scheme established by the Company; and (b) have been issued on the realisation of any awards or options granted during the preceding ten years under the Plan or any other Employees' Share Scheme established by the Company, would exceed 10 per cent of the ordinary share capital of the Company for the time being in issue. 17.2 No Award shall be granted under the Plan to the extent that the result of that grant would be that the aggregate number of Shares that could be issued on the realisation of that Award and any other Award granted at the same time, when added to the number of Shares that: (a) could be issued on the realisation of any subsisting awards or options granted during the preceding ten years under the Plan or any other discretionary share plans adopted by the Company; and (b) have been issued on the realisation of any awards or options granted during the preceding ten years under the Plan or any other discretionary share plans adopted by the Company,

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1934 would exceed 5 per cent of the ordinary share capital of the Company for the time being in issue. 17.3 Reference in this rule 17 to the issue of Shares shall, for the avoidance of doubt, mean the issue and allotment but not the transfer of Shares. Transfers of Treasury Shares shall also count towards the percentage limits set out in rules 17.1 and 17.2 above for so long as UK institutional shareholder guidelines recommend this. 17.4 In determining the above limits no account shall be taken of any Shares attributable to an Award which was released, lapsed, forfeited or otherwise became incapable of realisation. 18. AMENDMENT AND ADMINISTRATION 18.1 The decision of the Committee shall be final and binding in all matters relating to the Plan and it may at any time discontinue the grant of further Awards. 18.2 The Committee may amend any of the provisions of the Plan in any way it thinks fit, PROVIDED THAT: (a) the Committee shall not make any amendment that would materially prejudice the interests of existing Participants except with the prior consent or sanction of Participants who, if they realised their Awards in full, would thereby become entitled to not less than three-quarters of all the Shares which would fall to be allotted or transferred upon realisation in full of all outstanding Awards; and (b) no amendment which, in the reasonable opinion of the Committee, is to the advantage of Executives or Participants may be made to: (i) the definition of Executive; (ii) the limitations on the number of Shares subject to the Plan; (iii) the maximum entitlement of an Executive under the Plan; (iv) the basis for determining a Participant's entitlement to Shares under the Plan; (v) the terms of Shares to be provided under the Plan; and (vi) the adjustment provisions of the Plan, without the prior approval of the Company in general meeting except: (aa) in the case of minor amendments to benefit the administration of the Plan, to take account of a change in legislation or to obtain or maintain favourable tax, exchange control or regulatory treatment for Participants or for any member of the Group; or (bb) as otherwise permitted under these rules. 18.3 Notwithstanding any other provision of the Plan, the Committee may establish appendices to the Plan for the purpose of granting Awards to Executives who are or may become primarily liable to tax outside the United Kingdom on their remuneration, subject to such modifications as may be necessary or desirable to take account of overseas tax, exchange control, securities laws or other applicable laws provided that

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2034 any Shares made available under such appendices shall count towards the limits set out in rule 17. 19. GENERAL 19.1 Any member of the Group may provide money to the Trustee or any other person to enable them or him/her to acquire Shares to be held for the purposes of the Plan, or enter into any guarantee or indemnity for the purposes, to the extent permitted by any applicable law. 19.2 The Plan shall terminate on 27 May 2030 or at any earlier time by the passing of a resolution by the Committee or an ordinary resolution of the Company in general meeting. Termination of the Plan shall be without prejudice to the subsisting rights of Participants. 19.3 An Award will not constitute a contract of employment. The rights and obligations of any individual under the terms of their office or employment with the Group shall not be affected by their participation in the Plan or any right they may have to participate in the Plan. An individual who participates in the Plan waives all and any rights to compensation or damages in consequence of the termination of their office or employment with any company for any reason whatsoever (whether lawfully or unlawfully), insofar as those rights arise or may arise from their ceasing to have rights under the Plan as a result of such termination, or from the loss or diminution in value of such rights or entitlements. In the event of any conflict between the terms of this rule 19.3 and the Participant's terms of employment, this rule will take precedence. 19.4 The existence of any Award shall not affect in any way the right or power of the Company or its shareholders to make or authorise any or all adjustments, recapitalisations, reorganisations or other changes in the Company's capital structure, or any merger or consolidation of the Company, or any issue of Company shares, bonds, debentures, preferred or prior preference stocks ahead of, or convertible into, or otherwise affecting the Shares or the rights thereof, or the dissolution or liquidation of the Company or any sale or transfer of all or any part of its assets or business, or any other corporate act or proceeding, whether of a similar character or otherwise. 19.5 Any notice or other document which has to be given to a Participant under or in connection with the Plan may be (i) delivered or sent by post to him at his home address according to the records of his employing company, (ii) sent by email to any email address according to the records of his employing company or, in either case, such other address as may appear to the Company to be appropriate, or (iii) provided electronically through a website hosted by the Company or an agent of the Company, provided that the Participant is notified by email or post that such notice or document has been or will be provided in this manner. 19.6 Notices sent by post to a Participant will be deemed to have been given on the day after the date of posting. Notices sent by email, in the absence of evidence to the contrary, will be deemed to have been received on the day after sending. 19.7 Notices provided through a website will be deemed to have been received on the day they are posted on the website or, if later, the day the Participant is deemed in accordance with rule 19.6 to have received the notification that the notice has been provided there.

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2134 19.8 Any notice or other document required to be given to the Company under or in connection with the Plan may be delivered or sent by post to it at its registered office (or such other place or places as the Committee may from time to time determine and notify to Participants) or sent by email to any email address notified to the sender. 19.9 All Share certificates, Award certificates and other communications relating to the Plan will be sent at the Participant's risk. 19.10 Benefits under the Plan shall not be pensionable. 19.11 Any Shares acquired under the Plan will be subject to the Articles of Association of the Company as amended from time to time. 19.12 The invalidity or non-enforceability of one or more provisions of the Plan will not affect the validity or enforceability of the other provisions of the Plan, which will remain in full force and effect. 19.13 Nothing in this Plan confers any benefit, right or expectation on a person who is not an Executive. No third party has any rights under the Contracts (Rights of Third Parties) Act 1999 to enforce any term of this Plan. This does not affect any other right or remedy of a third party which may exist. 19.14 The decision of the Committee in any dispute or question concerning the interpretation, construction or effect of the Plan or any other questions arising in connection with the Plan shall be final and conclusive. 19.15 By participating in the Plan, the Participant's attention is drawn to the data privacy information of the Company, which sets out how the Participant's personal data will be used and shared by the Company and other Group Companies. The data privacy information does not form part of these rules and may be updated from time to time. Any such updates shall be notified to the Participant. 20. GOVERNING LAW 20.1 These rules and any non-contractual obligations arising out of or in connection with these rules shall be governed by, and interpreted in accordance with, English law. 20.2 The English courts shall have exclusive jurisdiction in relation to all disputes (including claims for set-off and counterclaims) arising out of or in connection with these rules including, without limitation, disputes arising out of or in connection with: (i) the creation, validity, effect, interpretation, performance or non-performance of, or the legal relationships established by, these rules; and (ii) any non-contractual obligations arising out of or in connection with these rules. For such purposes each party irrevocably submits to the jurisdiction of the English courts and waives any objection to the exercise of such jurisdiction.

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RULES APPLICABLE TO AWARDS GRANTED ON OR AFTER 26 JULY 2023 2234 PART 2 EDIP Deferred Bonus Element

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CONTENTS CLAUSE PAGE 2334 1. GRANT OF AWARDS ................................................................................... 24 2. VESTING OF AWARDS ................................................................................ 25 3. ENTITLEMENT TO DIVIDEND EQUIVALENTS ...................................... 25 4. LEAVERS ........................................................................................................ 26 5. ISSUE, TRANSFER OR LISTING OF SHARES .......................................... 27 6. DEALING RESTRICTIONS ........................................................................... 27 7. CORPORATE EVENTS ................................................................................. 27 8. ROLLOVER OF AWARDS ............................................................................ 29 9. ADJUSTMENTS OF AWARDS ..................................................................... 30 10. MALUS AND CLAWBACK .......................................................................... 30 11. TAXATION ..................................................................................................... 30 12. PLAN LIMITS ................................................................................................. 30 13. AMENDMENT AND ADMINISTRATION .................................................. 31 14. GENERAL ....................................................................................................... 32 15. GOVERNING LAW ....................................................................................... 34

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&nbsp;&nbsp;&nbsp;&nbsp;2434 1. GRANT OF AWARDS 1.1 Subject to this rule 1, the Committee may, during a Grant Period, grant an Award to any Executive who at any time during the Financial Year immediately preceding the proposed Date of Grant (the Bonus Year) was a participant in any annual bonus plan operated by the Company or any Group Company. 1.2 An Executive may be granted any form of Award or any combination of Awards. The Committee shall determine whether any Award will take the form of an Option, a Conditional Award or a Phantom Award. Each Award shall be evidenced by an Award Certificate issued by the Company or such other documentation as the Committee may determine in its absolute discretion. 1.3 The Committee shall determine in respect of each Executive a notional amount comprising the value of any annual bonus that is to be satisfied as Shares under an Award (the Notional Amount). For the avoidance of doubt, the determination of the Notional Amount shall not represent an entitlement of an Executive to a bonus. 1.4 The number of Shares or Notional Shares subject to the Award will be set by dividing the Notional Amount, expressed on a pre-tax basis, by the Market Value of a Share averaged over such Dealing Days as the Committee may determine taking account of the need to balance the interests of shareholders, the Company and Executives, including but not limited to the three business days following the announcement of the Company's results for the previous Financial Year. 1.5 The Committee shall on or prior to the Date of Grant determine: a) the number of Shares or Notional Shares subject to the Award, in accordance with rule 1.4; b) the period for which the Award must be held before it Vests (the Deferral Period), which shall be the period of three years from 1 January of the Financial Year following that to which an Executive's annual bonus relates or such other period or periods as the Committee considers is appropriate; c) whether the Award will accrue Dividend Equivalents and the basis on which it shall do so pursuant to rule 3; and d) any other restrictions or requirements that the Committee determines are appropriate. 1.6 Prior to the granting of any Awards, the Committee may, in its absolute discretion, enter into a deed poll recording its intention to grant Awards and agreeing to be bound by the Award Certificates issued pursuant to rule 1.2 above. 1.7 No payment shall be required for the grant of an Award. 1.8 No Award shall be granted under the Plan more than ten years after the Approval Date. 1.9 Every Award granted under this Plan shall be personal to the Participant to whom it is granted and, except to the extent necessary to enable a personal representative to realise the Award following the death of a Participant, neither the Award nor the benefit of

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&nbsp;&nbsp;&nbsp;&nbsp;2534 that Award may be transferred, assigned, charged or otherwise alienated. An Award will lapse immediately if the Participant to whom it was made purports to transfer, charge or otherwise alienate that Award otherwise than as permitted by this rule 1.6. 1.10 The grant of any Award under the Plan shall be subject to any applicable Dealing Restrictions. 2. VESTING OF AWARDS 2.1 Save as otherwise permitted in these rules, an Award shall Vest: a) on the Vesting Date; and b) provided that the Participant has remained an Executive during the period to the Vesting Date. 2.2 Subject to any Dealing Restrictions, Shares comprised in a Vested Conditional Award will be issued or transferred to the Participant as soon as reasonably practicable following the Vesting Date. A Participant need take no action to realise a Conditional Award other than pay the Company any amount specified at the Date of Grant to realise the Award. 2.3 Subject to any Dealing Restrictions, Vested Options are exercisable by written notice to the Company in the form required by the Company and payment of any amount specified at the Date of Grant to realise the Award at any time during the period of 6 months following the Vesting Date. A notice of exercise will take effect on the date it is accepted as valid by the Company or, if there are any Dealing Restrictions in place on that date, such later date when all Dealing Restrictions have lifted. Subject to any Dealing Restrictions in accordance with rule 6 below, the Shares comprised in a Vested Option will be issued or transferred to the Participant as soon as reasonably practicable following the date the notice of exercise takes effect. 2.4 Vested Phantom Awards shall be satisfied in the next available payroll following the Vesting Date by a payment equal to the Market Value of the Vested notional Shares under the Phantom Award on the Vesting Date. 2.5 Notwithstanding the above, a Participant's Award shall not Vest if they are suspended from their employment by reason of suspected Misconduct or the Committee has reason to believe that there are circumstances that could give rise to the application of rule 10 and shall only Vest on such date as the Participant is found not to have committed such Misconduct or the Committee has determined that there are no circumstances that would justify the application of rule 10. 3. ENTITLEMENT TO DIVIDEND EQUIVALENTS 3.1 The Committee may in its discretion grant an Award on the basis that it carries Dividend Equivalents. 3.2 If an Award has been granted on the basis that it carries Dividend Equivalents, the Participant will, subject to rule 3.4, be entitled to additional Shares, equal in value to the dividends which would have been paid on the Shares which have Vested during the

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&nbsp;&nbsp;&nbsp;&nbsp;2634 Deferral Period, such Dividend Equivalent to accrue on the relevant record date for an interim or final dividend in respect of Shares and to be paid on or around the date an Award is satisfied by the Company. 3.3 The additional Shares to which the Participant becomes entitled under rule 3.2 will be calculated in such manner as the Committee in its absolute discretion determines including whether it will be calculated by reference only to ordinary dividends and without regard to special dividends or distributions, super dividends or dividends-in- specie. In making any determination the Committee shall have regard to the effect of the dividend on the value of an Award and whether the Award is otherwise being adjusted in connection with payment of the dividend. 3.4 Instead of issuing or transferring additional Shares, the Committee may in its absolute discretion satisfy any entitlement to Dividend Equivalents arising in accordance with rule 3.2 by giving a cash payment with an equivalent value as determined at the time of Vesting. 3.5 For the avoidance of doubt, any payment referred to in this rule 3 does not represent an entitlement to actual dividends on the underlying Shares, by reason of the Participant not being the beneficial owner of the Shares at that time. 4. LEAVERS 4.1 If a Participant ceases to be an employee of a member of the Group for any reason prior to the end of the Deferral Period or, at the Date of Grant has already ceased to be an employee of a member of the Group, the Participant's Award shall be preserved and shall vest at the end of such Deferral Period (provided that, in the event that a Participant is dismissed for Cause, the Shares comprised in his/her Award shall lapse on termination of employment). 4.2 Notwithstanding rule 4.1 above, if a Participant ceases to be an employee of a member of the Group for any reason before the end of the Deferral Period, the Committee has the discretion to determine that his/her Award shall Vest on the Termination Date and: (a) apply a pro rata reduction to the number of Vested Shares based on the period of time after the Date of Grant and ending on the Termination Date relative to the period of three years; or (b) decide, acting fairly and reasonably, that the reduction in the number of Vested Shares under rule 4.2(a) is inappropriate in any particular case when it shall increase the number of Vested Shares to such higher number as it decided provided that number does not exceed the number of Shares determined under rule 1.4. 4.3 A Participant will not cease to be an Executive for the purposes of this rule 4 if they cease to be employed by a member of the Group but continue to be or are immediately afterwards employed by another member of the Group. 4.4 Where a Participant ceases to be employed by a member of the Group at any time before the Vesting Date applicable to an Award by reason of the demerger by the Company

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&nbsp;&nbsp;&nbsp;&nbsp;2734 of the business or division in which they are employed, the Committee may determine for some or all Participants leaving the Group as a result of the demerger that part or all of the Award shall vest and/or that Awards held by such Participants should be rolled over into equivalent awards over shares in the demerged company (or such terms as the Committee shall agree with that company). 5. ISSUE, TRANSFER OR LISTING OF SHARES 5.1 The Committee shall issue or procure the transfer of Shares to be allotted or transferred pursuant to: (i) the realisation of a Conditional Award within 30 days following the Vesting Date of the Award; and (ii) pursuant to the exercise of an Option, within 30 days of receipt of the notice of exercise by the Company. 5.2 Shares to be issued or transferred pursuant to the Plan will rank pari passu in all respects with the Shares then in issue, except that they will not rank for any rights attaching to Shares by reference to a record date preceding the Vesting Date. 5.3 For so long as the Shares are admitted to Listing, application will be made for any newly issued ordinary shares to be admitted to such listing and admitted to trading on the relevant stock exchange. 6. DEALING RESTRICTIONS 6.1 Notwithstanding any other rule of this Plan, no Award shall be granted, Vest, be exercised, adjusted or satisfied (as applicable) if (i) it would be prohibited by any Dealing Restriction or (ii) the sale of any Shares to meet any Tax liability as a consequence of such grant, Vesting, exercise, adjustment or satisfaction (as applicable) would be prohibited by any Dealing Restriction. 7. CORPORATE EVENTS Takeover and Liquidation 7.1 This rule 7 applies if: (a) any person (either alone or together with any person acting in concert with him) obtains Control of the Company as a result of making: (i) a general offer to acquire the whole of the issued ordinary share capital of the Company which is made on a condition such that if it is satisfied, the person making the offer will have Control of the Company; or (ii) a general offer to acquire all of the Shares; (b) any person proposes to obtain Control of the Company in pursuance of a compromise or arrangement sanctioned by the Court under Part 26 of the Companies Act 2006 or its equivalent under applicable law; (c) any person becomes bound or entitled to acquire Shares in the Company under sections 974 to 991 inclusive of the Companies Act 2006 or its equivalent under applicable law; or

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&nbsp;&nbsp;&nbsp;&nbsp;2834 (d) notice is given of a resolution for the voluntary or compulsory winding-up of the Company, (each a Relevant Event). 7.2 Where this rule 7 applies and subject to rules 7.3, 7.4 and 8.1 below, all outstanding Awards will automatically Vest and, in the case of an Award granted in the form of an Option shall be automatically exercised on the Relevant Date provided that any exercise price payable by the Participant on exercise is equal to or less than the relevant offer price or consideration (as determined by the Committee). Where this rule 7 applies, and subject to rules 7.3, 7.4 and 8.1 below, any outstanding Awards granted in the form of Options that are not exercised on the Relevant Date shall lapse automatically. Proportion of Award that Vests 7.3 The number of Shares in respect of which the Award Vests shall be determined by the Committee by reference to multiplying the resulting number of Shares or Notional Shares by the fraction A/B (where A is the number of complete months from the Date of Grant until the Relevant Date and which shall not be greater than the total number of months in the Deferral Period and B is 36 or equal to such other number of months in the original Deferral Period), save that in any particular case, the Committee may, in its absolute discretion, disapply, in whole or in part, the application of the time pro- rating fraction. 7.4 Without prejudice to the operation of rule 8, Awards shall not Vest or be exercised without the consent of the Committee under the foregoing provisions of this rule 7 if the purpose and effect of the Relevant Event, together with any associated transactions, is to create a new holding company for the Company, such company having substantially the same shareholders and proportionate shareholdings as those of the Company immediately prior to the Relevant Event. Unless the Committee determines otherwise in its absolute discretion, an Award will in such circumstances be exchanged for an equivalent award in accordance with rule 8 below and notice of a replacement award shall be issued to each affected Participant accordingly. Demerger 7.5 If the Committee becomes aware that the Company is or is expected to be affected by any demerger, dividend in specie, super-dividend or other transaction which, in the opinion of the Committee, would affect the current or future value of any Awards, the Committee, acting fairly, reasonably and objectively, may in its absolute discretion allow some or all Awards to be realised in accordance with rule 7.3. The Committee shall specify the period in which such Awards shall be realisable and whether such Awards shall lapse at the end of the specified period. 7.6 Where a Participant ceases to be employed by a member of the Group at any time before the Vesting Date applicable to an Award by reason of the demerger by the Company of the business or division in which they are employed, the Committee may determine for some or all Participants leaving the Group as a result of the demerger that part or all of the Award shall vest and/or that Awards held by such Participants should be rolled over into equivalent awards over shares in the demerged company (or such terms as the

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&nbsp;&nbsp;&nbsp;&nbsp;2934 Committee shall agree with that company). This is without prejudice to the operation of the provisions in rule 7.5 in the event of a demerger. 8. ROLLOVER OF AWARDS 8.1 If any other business entity (the acquiring company): (a) obtains Control of the Company as a result of making: (i) a general offer to acquire the whole of the issued ordinary share capital of the Company which is made on a condition such that if it is satisfied the acquiring company will have Control of the Company; or (ii) a general offer to acquire all the Shares; or (b) proposes to obtain Control of the Company in pursuance of a compromise or arrangement sanctioned by the Court under Part 26 of the Companies Act 2006 or its equivalent under applicable law; or (c) becomes bound or entitled to acquire shares in the Company under sections 974 to 991 inclusive of the Companies Act 2006 or their equivalent under applicable law, and the acquiring company notifies Participants of an offer of a replacement Award, then, on the Relevant Date, for any Award which has not lapsed (the old award) a Participant may elect to release and accept in consideration of that release an award (the new award) which (in the opinion of the Committee) is equivalent to the old award but relates to shares in a different company (whether the acquiring company itself or another company) (the new grantor). 8.2 The provisions of the Plan shall be construed as if: (a) the new award were an award granted under the Plan at the same time as the old award; (b) references to the Company in the rules were references to the new grantor; (c) references to the Committee in the rules were references to the board of directors of the new grantor or any duly authorised committee thereof; (d) references to Shares were references to shares in the new grantor; and (e) the Vesting Date in relation to the new award was the same as that in relation to the old award. 8.3 The Committee may make such adjustments to the Performance Condition applicable to the new award as it, in its absolute discretion, considers appropriate. 8.4 Subject to rule 7.4, if notice is given by an acquiring company under rule 8.1 and a Participant does not elect to release an old award and accept in consideration for that release a new award, the old award will vest and be exercised in accordance with rule 7.2.

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&nbsp;&nbsp;&nbsp;&nbsp;3034 9. ADJUSTMENTS OF AWARDS 9.1 In the event of any Capital Reorganisation (or the implementation by the Company of a demerger or payment of a super dividend which would otherwise materially affect the value of an Award) the Committee may adjust the number of Shares subject to Awards (including, for the avoidance of doubt, Vested Shares in respect of which any Award has been realised but Shares have not yet been transferred to the Participant) to such extent and in such manner as it thinks fit. 9.2 Any adjustments to Awards made pursuant to rule 9.1 shall be notified to the relevant Participants as soon as is reasonably practicable and the Committee may call in, cancel, endorse, issue or re-issue any Award certificate as a result of that adjustment. 10. MALUS AND CLAWBACK 10.1 Notwithstanding any provision in these rules or in any Award Certificate, Awards are subject to the Malus and Clawback Policy and by accepting an Award, a Participant agrees to be bound by the terms of that policy. 11. TAXATION 11.1 Any liability of a Participant to Tax or social security contributions in respect of an Award (including, for the avoidance of doubt, any cash amount paid under these rules) shall be for the account of the relevant Participant, and the release of any Shares the subject of a Conditional Award or the exercise of any Option shall be conditional on the Participant complying with any arrangements specified by the Company or the Trustees for the payment of taxation and any social security contributions (including, without limitation, the sale of sufficient Shares to enable the Company or the Trustees or any employing company in the Group to satisfy its obligations in respect of deduction of taxation and employee's social security contributions at source). 11.2 The Company or, where the Committee so directs, any member of the Group, will pay the appropriate stamp duty on behalf of Participants in respect of any transfer of Shares on the Vesting of a Share Award or exercise of an Option under the Plan. 12. PLAN LIMITS 12.1 No Award shall be granted under the Plan to the extent that the result of that grant would be that the aggregate number of Shares that could be issued on the realisation of that Award and any other Award granted at the same time, when added to the number of Shares that: (a) could be issued on the realisation of any subsisting awards or options granted during the preceding ten years under the Plan or any other Employees' Share Scheme established by the Company; and (b) have been issued on the realisation of any awards or options granted during the preceding ten years under the Plan or any other Employees' Share Scheme established by the Company,

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&nbsp;&nbsp;&nbsp;&nbsp;3134 would exceed 10 per cent of the ordinary share capital of the Company for the time being in issue. 12.2 No Award shall be granted under the Plan to the extent that the result of that grant would be that the aggregate number of Shares that could be issued on the realisation of that Award and any other Award granted at the same time, when added to the number of Shares that: (a) could be issued on the realisation of any subsisting awards or options granted during the preceding ten years under the Plan or any other discretionary share plans adopted by the Company; and (b) have been issued on the realisation of any awards or options granted during the preceding ten years under the Plan or any other discretionary share plans adopted by the Company, would exceed 5 per cent of the ordinary share capital of the Company for the time being in issue. 12.3 Reference in this rule 12 to the issue of Shares shall, for the avoidance of doubt, mean the issue and allotment but not the transfer of Shares. Transfers of Treasury Shares shall also count towards the percentage limits set out in rules 12.1 and 12.2 above for so long as UK institutional shareholder guidelines recommend this. 12.4 In determining the above limits no account shall be taken of any Shares attributable to an Award which was released, lapsed, forfeited or otherwise became incapable of realisation. 13. AMENDMENT AND ADMINISTRATION 13.1 The decision of the Committee shall be final and binding in all matters relating to the Plan and it may at any time discontinue the grant of further Awards. 13.2 The Committee may amend any of the provisions of the Plan in any way it thinks fit, PROVIDED THAT: (a) the Committee shall not make any amendment that would materially prejudice the interests of existing Participants except with the prior consent or sanction of Participants who, if they realised their Awards in full, would thereby become entitled to not less than three-quarters of all the Shares which would fall to be allotted or transferred upon realisation in full of all outstanding Awards; and (b) no amendment which, in the reasonable opinion of the Committee, is to the advantage of Executives or Participants may be made to: (i) the definition of Executive; (ii) the limitations on the number of Shares subject to the Plan; (iii) the maximum entitlement of an Executive under the Plan;

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&nbsp;&nbsp;&nbsp;&nbsp;3234 (iv) the basis for determining a Participant's entitlement to Shares under the Plan; (v) the terms of Shares to be provided under the Plan; and (vi) the adjustment provisions of the Plan, without the prior approval of the Company in general meeting except: (aa) in the case of minor amendments to benefit the administration of the Plan, to take account of a change in legislation or to obtain or maintain favourable tax, exchange control or regulatory treatment for Participants or for any member of the Group; or (bb) as otherwise permitted under these rules. 13.3 Notwithstanding any other provision of the Plan, the Committee may establish appendices to the Plan for the purpose of granting Awards to Executives who are or may become primarily liable to tax outside the United Kingdom on their remuneration, subject to such modifications as may be necessary or desirable to take account of overseas tax, exchange control, securities laws or other applicable laws provided that any Shares made available under such appendices shall count towards the limits set out in rule 17. 14. GENERAL 14.1 Any member of the Group may provide money to the Trustee or any other person to enable them or him/her to acquire Shares to be held for the purposes of the Plan, or enter into any guarantee or indemnity for the purposes, to the extent permitted by any applicable law. 14.2 The Plan shall terminate on 27 May 2030 or at any earlier time by the passing of a resolution by the Committee or an ordinary resolution of the Company in general meeting. Termination of the Plan shall be without prejudice to the subsisting rights of Participants. 14.3 An Award will not constitute a contract of employment. The rights and obligations of any individual under the terms of their office or employment with the Group shall not be affected by their participation in the Plan or any right they may have to participate in the Plan. An individual who participates in the Plan waives all and any rights to compensation or damages in consequence of the termination of their office or employment with any company for any reason whatsoever (whether lawfully or unlawfully), insofar as those rights arise or may arise from their ceasing to have rights under the Plan as a result of such termination, or from the loss or diminution in value of such rights or entitlements. In the event of any conflict between the terms of this rule 14.3 and the Participant's terms of employment, this rule will take precedence. 14.4 The existence of any Award shall not affect in any way the right or power of the Company or its shareholders to make or authorise any or all adjustments, recapitalisations, reorganisations or other changes in the Company's capital structure, or any merger or consolidation of the Company, or any issue of Company shares, bonds, debentures, preferred or prior preference stocks ahead of, or convertible into, or otherwise affecting the Shares or the rights thereof, or the dissolution or liquidation of

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&nbsp;&nbsp;&nbsp;&nbsp;3334 the Company or any sale or transfer of all or any part of its assets or business, or any other corporate act or proceeding, whether of a similar character or otherwise. 14.5 Any notice or other document which has to be given to a Participant under or in connection with the Plan may be (i) delivered or sent by post to him at his home address according to the records of his employing company, (ii) sent by email to any email address according to the records of his employing company or, in either case, such other address as may appear to the Company to be appropriate, or (iii) provided electronically through a website hosted by the Company or an agent of the Company, provided that the Participant is notified by email or post that such notice or document has been or will be provided in this manner. 14.6 Notices sent by post to a Participant will be deemed to have been given on the day after the date of posting. Notices sent by email, in the absence of evidence to the contrary, will be deemed to have been received on the day after sending. 14.7 Notices provided through a website will be deemed to have been received on the day they are posted on the website or, if later, the day the Participant is deemed in accordance with rule 14.6 to have received the notification that the notice has been provided there. 14.8 Any notice or other document required to be given to the Company under or in connection with the Plan may be delivered or sent by post to it at its registered office (or such other place or places as the Committee may from time to time determine and notify to Participants) or sent by email to any email address notified to the sender. 14.9 All Share certificates, Award certificates and other communications relating to the Plan will be sent at the Participant's risk. 14.10 Benefits under the Plan shall not be pensionable. 14.11 Any Shares acquired under the Plan will be subject to the Articles of Association of the Company as amended from time to time. 14.12 The invalidity or non-enforceability of one or more provisions of the Plan will not affect the validity or enforceability of the other provisions of the Plan, which will remain in full force and effect. 14.13 Nothing in this Plan confers any benefit, right or expectation on a person who is not an Executive. No third party has any rights under the Contracts (Rights of Third Parties) Act 1999 to enforce any term of this Plan. This does not affect any other right or remedy of a third party which may exist. 14.14 The decision of the Committee in any dispute or question concerning the interpretation, construction or effect of the Plan or any other questions arising in connection with the Plan shall be final and conclusive. 14.15 By participating in the Plan, the Participant's attention is drawn to the data privacy information of the Company, which sets out how the Participant's personal data will be used and shared by the Company and other Group Companies. The data privacy

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&nbsp;&nbsp;&nbsp;&nbsp;3434 information does not form part of these rules and may be updated from time to time. Any such updates shall be notified to the Participant. 15. GOVERNING LAW 15.1 These rules and any non-contractual obligations arising out of or in connection with these rules shall be governed by, and interpreted in accordance with, English law. 15.2 The English courts shall have exclusive jurisdiction in relation to all disputes (including claims for set-off and counterclaims) arising out of or in connection with these rules including, without limitation, disputes arising out of or in connection with: (i) the creation, validity, effect, interpretation, performance or non-performance of, or the legal relationships established by, these rules; and (ii) any non-contractual obligations arising out of or in connection with these rules. For such purposes each party irrevocably submits to the jurisdiction of the English courts and waives any objection to the exercise of such jurisdiction.

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## Exhibit 4.8

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## Exhibit 4.10

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 BP p.l.c. RULES OF THE BP SHARE AWARD PLAN 2025 Shareholders' Approval: 17 April 2025 Designated Corporate Officer's Adoption on behalf of the Company: 22 April 2025 Expiry Date: 17 April 2035 Linklaters LLP One Silk Street London EC2Y 8HQ Telephone (+44) 20 7456 2000 Ref 01/140

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 i **Table of Contents** Contents Page 1 Definitions ............................................................................................................................ 1 2 Sub-Plans ............................................................................................................................. 3 3 Terms to be included in Sub-Plans ................................................................................... 4 4 Documentation of Awards .................................................................................................. 6 5 Limits .................................................................................................................................... 7 6 Terms applicable to all Awards .......................................................................................... 8 7 Vesting .................................................................................................................................. 9 8 Retention Period ............................................................................................................... 12 9 Leaving employment ........................................................................................................ 15 10 Malus and clawback .......................................................................................................... 18 11 Corporate events ............................................................................................................... 20 12 Changing the Plan and termination ................................................................................ 23 13 General ............................................................................................................................... 24

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 1 1 Definitions In these rules: "Acquiring Company" means a person who has or obtains control (within the meaning of Section 995 of the Income Tax Act 2007) of the Company; "ADS" means an American depositary share representing ordinary shares of the Company; "Award" means a conditional right to receive Shares, each of which can take the form of a Conditional Award, Restricted Shares, or an Option, and includes an Award which has continued during a Retention Period; "Award Date" means the date on which an Award is granted; "Bonus Deferral Award" means an Award which is granted to a Participant in lieu of any bonus which they might otherwise have been paid in cash, and which is or has been designated as such by the Designated Corporate Officer under rule 3.3.3; "Business Day" means a day on which the London Stock Exchange (or, if relevant and if the Designated Corporate Officer determines, any stock exchange nominated by the Designated Corporate Officer on which the Shares are traded) is open for the transaction of business; "Buy-out Award" means any Award made to compensate for awards forfeited on or due to be forfeited as a result of recruitment; "Change of Control" means: (i) a person (or group of persons acting in concert) obtaining control (within the meaning of Section 995 of the Income Tax Act 2007) of the Company as the result of a general offer to acquire Shares becoming or being declared wholly unconditional; or (ii) a court sanctioning a compromise or arrangement in connection with the acquisition of Shares under Section 895 of the Companies Act 2006 or equivalent procedure under local legislation pursuant to which a person (or group of persons) obtains control (within the meaning of Section 995 of the Income Tax Act 2007) of the Company; or (iii) if the Designated Corporate Officer, in their discretion so decides, a person (or a group of persons acting in concert) obtaining control (within the meaning of Section 995 of the Income Tax Act 2007) of the Company in any other way; "Clawback Period" means the period during which the Designated Corporate Officer can decide under rule 10.4 (Clawback) that clawback will apply to the Award, being the period as set out in the applicable malus and clawback terms, or if no such period is specified, the period from the date on which the Award Vests until the sixth anniversary of the Award Date; "Company" means BP p.l.c.; "Condition" means any condition to which an Award is subject; "Conditional Award" means a conditional right to receive Shares for free granted under the Plan (which may be referred to as a "Restricted Share Unit", where appropriate); "Dealing Restrictions" means any restriction on dealing in securities imposed by regulation, statute, order, directive or any code adopted by the Company, as varied from time to time;

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 2 "Designated Corporate Officer" means the Chief Executive Officer of the Company or such other senior level leader (or their delegate(s)) authorised from time to time under the Company's delegation of authority (or in each case any duly authorised delegate(s) of such person(s)); "Dividend Equivalent" means an amount linked to dividends on the number of Shares in respect of which an Award Vests or is exercised as determined under rule 7.6 (Dividend Equivalent); "Employee" means (other than in respect of rule 13.1 (Terms of employment)) any employee of a member of the Group excluding an executive director of the Company; "Final Lapse Date" means the latest date on which an Option will lapse set by the Designated Corporate Officer under rule 3.3.7 which will not be later than the 10th anniversary of the Award Date, or if no such date is specified, the first anniversary of Vesting; "Grantor" means the Company or any other entity which agrees to satisfy an Award under the Plan; "Group" means: (i) the Company; (ii) its Subsidiaries from time to time; or (iii) any other company which is associated with the Company and is so designated by the Designated Corporate Officer and, for the avoidance of doubt, a company may be treated as an associated company for some purposes or in relation to some Participants but not in relation to others; "Investment Association" means the trade association for UK investment managers, known as the Investment Association, with registration number 4343737; "London Stock Exchange" means the London Stock Exchange plc; "Market Value" means, on any date, the market value determined by the Designated Corporate Officer in such manner as they consider reasonable (which, without limitation, may use an average price over a period ending on that date and which may be different for different purposes under the Plan); "New Issue Share" means Shares to be allotted by the Company; "Normal Vesting Date" means the date set for Vesting of an Award under rule 3.2.3; "Option" means a right to acquire Shares on exercise granted under the Plan; "Option Price" means the amount (which may be zero) payable on the exercise of an Option set by the Designated Corporate Officer under rule 3.2.5; "Participant" means a person holding (or who previously held) an Award or their personal representatives; "Plan" means these rules known as "The BP Share Award Plan 2025", as changed from time to time; "Remuneration Rules" means, in relation to any Employee or Participant, the remuneration codes, regulations, guidance and/or regulatory expectations which apply to the Employee or Participant from time to time;

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 3 "Restricted Share Agreement" means the agreement or documents governing how Restricted Shares are held as referred to in rule 4.2 (Restricted Shares); "Restricted Shares" means Shares held in the name of or for the benefit of a Participant subject to the Restricted Share Agreement; "Retention Period" means any period during which any restrictions apply to an Award or the Shares subject to an Award following Vesting as referred to in rule 3.3.5; "Retention Shares" means the Shares which are subject to a Retention Period; "Shares" means fully paid ordinary shares in the capital of the Company and includes ADSs where appropriate; "Sub-Plan" means any plan, agreement or other arrangement created or designated by the Designated Corporate Officer in accordance with rule 2 (Sub-Plans); "Subsidiary" means a company which is a subsidiary of the Company within the meaning of Section 1159 of the Companies Act 2006; and "Vesting" means, subject to the rules and the terms set at grant and any Retention Period: (i) in relation to an Option, an Option becoming exercisable; (ii) in relation to a Conditional Award, a Participant becoming entitled to have the Shares issued or transferred to them; and (iii) in relation to Restricted Shares, the restrictions set out in the Restricted Share Agreement ceasing to have effect as described in rule 7.5.3, and "Vesting" shall include the terms "Vest" and "Vested". 2 Sub-Plans 2.1 Requirement for a Sub-Plan An Award may only be granted under a Sub-Plan. 2.2 Creation and designation of Sub-Plans Subject to these rules, the Designated Corporate Officer may, at any time: 2.2.1 create and determine the terms of any new Sub-Plan; 2.2.2 designate any existing plan, agreement or other arrangement as a Sub-Plan whether it was adopted or operated before or after the date of approval of this Plan; and/or 2.2.3 decide that a Sub-Plan is no longer a Sub-Plan. The rules of a Sub-Plan may be different to those of the Plan but must not be such as would require the approval of the Company in general meeting if the Plan were amended to include them under rule 12.2 (Shareholder approval). 2.3 Content of Sub-Plans 2.3.1 Subject to rule 2.2 (Creation and designation of Sub-Plans), the rules of a Sub-Plan can:

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 4 (i) set out how any discretion or power given under these rules will be exercised in relation to any or all awards under the Sub-Plan; (ii) disapply any of the rules or apply additional rules; and/or (iii) set out circumstances in which rule 9.2 (Exceptions) will apply in relation to the Award which are not listed in that rule or specify circumstances which are listed in that rule but which will not apply. 2.3.2 Except as provided below, the terms of each Sub-Plan and any Award will be consistent with these rules. 2.3.3 A Sub-Plan or the terms of an Award can be inconsistent with these rules to the extent only that these rules could be amended to include that inconsistency without the approval of the Company in general meeting under rule 12 (Changing the Plan and termination). 2.3.4 If a Sub-Plan or the terms of any Award are inconsistent with these rules in a manner which is not permitted by rule 2.3.3, the Sub-Plan or Award will be read in a manner which is so consistent, as determined by the Designated Corporate Officer. 2.3.5 For the avoidance of doubt, where the rules of the Sub-Plan are more restrictive than this Plan then the terms of that Sub-Plan shall to the exclusion of the Plan apply to the Awards made under it. 2.3.6 Awards under a Sub-Plan will be treated as Awards for the purposes of the limit in rule 5 (Limits). 2.3.7 If there is a conflict between the rules of the Plan and the Sub-Plan, the Sub-Plan will prevail except to the extent that it would not comply with rule 2.2 (Creation and designation of Sub-Plans). Where there is a conflict between the Plan and the Sub- Plan in respect of Awards granted before the date of shareholder approval of the Plan then the Sub-Plan will apply even though it may not comply with rule 2.2 (Creation and designation of Sub-Plans). 2.3.8 Amendments to the Sub-Plan will be subject to rule 12.2 (Shareholder approval). 3 Terms to be included in Sub-Plans 3.1 Types of Awards The Sub-Plan will set out: 3.1.1 whether Awards may be granted over Shares; and 3.1.2 whether Awards will take the form of: (i) Conditional Awards; (ii) Options; or (iii) Restricted Shares, or a combination of these. 3.2 Terms which must be included in Sub-Plans The Sub-Plan or the terms of each Award will set out:

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 5 3.2.1 the number of Shares subject to the Award or how that will be determined; 3.2.2 whether the Award is over Shares or ADSs; 3.2.3 the date or dates on which and/or conditions on which Awards will Vest or lapse (being the Normal Vesting Date), including the terms of any Condition or any other condition to which the Award is subject; 3.2.4 the treatment of the Award if the Participant ceases to be employed by any member of the Group, which may include the Award lapsing, continuing in effect, Vesting early or being exchanged for an equivalent award relating to the new employer (in each case, wholly or in part); and 3.2.5 in the case of an Option, the Option Price (if any). 3.3 Terms which may be included in Sub-Plans Without limiting the Designated Corporate Officer's discretion under rule 2.2.1, the Sub-Plan or the terms of an Award may also: 3.3.1 provide restrictions that apply to the Award and/or the Shares subject to the Award during a period following the Vesting of the Award, and if so the terms of such restrictions; 3.3.2 provide for Awards to carry a Dividend Equivalent, determined on such basis as is set out in the Sub-Plan; 3.3.3 provide for Awards to be granted as Bonus Deferral Awards and/or as Buy-out Awards; 3.3.4 provide that Awards may be cash settled, on such basis as is set out in the Sub- Plan; 3.3.5 provide that Awards may be subject to a Retention Period on such basis as is set out in the Sub-Plan; 3.3.6 include malus and/or clawback provisions; and 3.3.7 specify the Final Lapse Date of an Option. 3.4 Conditions 3.4.1 The Designated Corporate Officer may decide that Vesting of an Award will be conditional on the satisfaction of one or more conditions set by the Designated Corporate Officer on grant. The Conditions may be linked to the performance of the Company, the Participant and/or any member of the Group or any other matter and may provide that the Award will lapse to the extent that they are not satisfied. 3.4.2 Where an Award is subject to Conditions, the Designated Corporate Officer may change a Condition if anything happens which causes the Designated Corporate Officer to consider it appropriate to do so. 3.5 Dividend Equivalents 3.5.1 If an Award carries a Dividend Equivalent, the amount of the Dividend Equivalent will be the number of Shares in respect of which the Award Vests multiplied by the per- Share amount of the dividends with a payment and record date between the Award Date and the date of Vesting ("relevant dividends").

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 6 3.5.2 However, the Designated Corporate Officer may determine on grant that: (i) the amount will be determined as if each relevant dividend were re-invested in further Shares at the Market Value of a Share on the payment date; or (ii) the amount will be determined as if interest were payable on each relevant dividend from the payment date until the date of Vesting (or exercise, if applicable) at a rate determined by the Designated Corporate Officer; and/or (iii) in the case of an Option, the Dividend Equivalent will be: (a) payable on exercise, not Vesting; and/or (b) calculated as if relevant dividends were the dividends on a Share the payment and record date for which falls between the Award Date and the date of exercise (rather than the date of Vesting); and/or (iv) a different calculation approach will apply. 3.5.3 The Designated Corporate Officer may at any time decide to exclude all or part of a special dividend or dividend in specie which may otherwise be included within Dividend Equivalent calculations and entitlements. 3.6 No payment for Awards A Participant is not required to pay for the grant of an Award. 3.7 Regulatory override Nothing in these rules or the terms of any Award will oblige any Group company or any other person to make any payment which would be inconsistent with the Remuneration Rules. If the Designated Corporate Officer determines that payment of any part of an Award would be so inconsistent, they may: 3.7.1 amend the Plan or the terms of the Award under rule 12 (Changing the Plan and termination); 3.7.2 adjust (including to nil and/or retrospectively) the number of Shares or method for valuing Shares or amount of cash payable under the Award; and/or 3.7.3 delay, and/or impose additional conditions on the Vesting or payment/settlement of an Award and/or the ending of a Retention Period. 4 Documentation of Awards 4.1 Awards other than Restricted Shares An Award (other than an Award of Restricted Shares) will be documented in such manner as the Designated Corporate Officer may decide and the Participant will be notified of the grant of the Award and the terms set for the Award in writing. 4.2 Restricted Shares 4.2.1 Where an Award takes the form of Restricted Shares, the Participant must (if required by the Designated Corporate Officer) enter into: (i) an agreement with the Grantor, that to the extent that the Award lapses under the Plan, the Shares are forfeited and they will immediately transfer their

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 7 interest in them, for no consideration or nominal consideration, to any person (which may include the Company, where permitted) specified by the Grantor; (ii) any tax elections required by the Designated Corporate Officer; and (iii) any other documentation which the Designated Corporate Officer considers necessary or desirable to give effect to the terms of the Award, including a power of attorney or blank share transfer form. 4.2.2 If the Participant does not do so within a period specified by the Designated Corporate Officer, the Award will lapse at the end of that period. 4.2.3 On or after the grant of an Award of Restricted Shares, the Grantor will procure that the relevant number of Shares is issued or transferred to the Participant or to another person to be held for the benefit of the Participant under the terms of the Plan. Where applicable, the share certificates or other documents of title relating to any Restricted Shares may be retained by the Grantor. 5 Limits 5.1 Plan limits An Award that may be settled in New Issue Shares may only be granted if the number of Shares committed to be issued under that Award would not exceed 10 per cent (or such higher percentage set from time to time by the Investment Association) of the ordinary share capital (adjusted for share issuance and cancellation) of the Company in issue immediately before the date of grant, when aggregated with outstanding Awards granted under any Sub- Plan, or under any other employee share plan operated by the Company, in the previous 10 years (or such longer period as set from time to time by the Investment Association). 5.2 Scope of Plan limits 5.2.1 When calculating the limits in rule 5.1 (Plan limits), Shares will be ignored: (i) where the right to acquire them is released, declined, forfeited or lapses; or (ii) which are committed to be issued under any Dividend Equivalent. 5.2.2 As long as so required by the Investment Association, Shares transferred from treasury to satisfy Awards are counted as a part of the ordinary share capital of the Company, and as New Issue Shares. 5.2.3 The precise method for calculating the limits in this rule 5 shall, subject to these rules, be determined by the Designated Corporate Officer from time to time in their discretion. 5.3 Awards in breach of limits If the Grantor tries to grant an Award which is inconsistent with this rule 5, the Award will be limited and will take effect from the Award Date on a basis consistent with this rule 5. 5.4 Listing Rules No Shares will be issued under the Plan if it would cause UK Listing Rule 6.2.22 (Shares in public hands) to be breached.

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 8 6 Terms applicable to all Awards 6.1 Eligibility Awards may only be granted to Employees or, if provided for under the applicable Sub-Plan, former Employees. 6.2 Timing of Awards 6.2.1 Subject to the rest of this rule, Awards may be granted at any time. 6.2.2 No Awards may be granted when grants are prevented by Dealing Restrictions. 6.2.3 No Awards may be granted after 17 April 2035 or such earlier date as the Designated Corporate Officer may specify. 6.3 Voting and dividends 6.3.1 A Participant is not entitled to vote, to receive dividends or to have any other rights of a shareholder in respect of Shares subject to an Option or a Conditional Award until the Shares are issued or transferred to the Participant. 6.3.2 Except to the extent specified in the Restricted Share Agreement, a Participant will have all rights of a shareholder in respect of Restricted Shares until the Award lapses. 6.4 No transfer or hedging Unless agreed by the Designated Corporate Officer, a Participant may not sell, transfer, assign, hedge, charge or otherwise dispose of an Award or any rights in respect of an Award and must not enter into any transaction which transfers the risk of price movements with regard to the Shares subject to an Award. If they do, whether voluntarily or involuntarily, then that Award will immediately lapse unless determined otherwise by the Designated Corporate Officer. This rule 6.4 does not apply: 6.4.1 to the transmission of an Award on the death of a Participant to their personal representatives; or 6.4.2 to the assignment of an Award, with the prior consent of the Designated Corporate Officer, subject to any terms and conditions the Designated Corporate Officer may impose. 6.5 Adjustment of Awards 6.5.1 If there is: (i) a variation in the equity share capital of the Company, including a capitalisation or rights issue, sub-division, consolidation or reduction of share capital; (ii) a demerger (in whatever form) or exempt distribution by virtue of Section 1075 of the Corporation Tax Act 2010; (iii) a special dividend or distribution; or (iv) any other corporate event which might affect the current or future value of any Award,

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 9 the Designated Corporate Officer may adjust the number or class of Shares or securities subject to the Award and, in the case of an Option, the Option Price. 6.5.2 Subject to the Restricted Share Agreement, a Participant will have the same rights as any other shareholders in respect of Restricted Shares where rule 6.5.1 applies. Any shares, securities or rights allotted to a Participant as a result of such an event will be: (i) treated as if they were awarded to the Participant under the Sub-Plan in the same way and at the same time as the Restricted Shares in respect of which the rights were conferred; and (ii) subject to the rules of the Sub-Plan and the terms of the Restricted Share Agreement, provided that this will not apply to any Shares which a Participant acquires on a rights issue or similar transaction to the extent that they exceed the number the Participant would have acquired on a sale of sufficient rights issued nil-paid to take up the balance of the rights. 7 Vesting 7.1 Timing and extent of Vesting Subject to the rest of these rules, an Award will Vest on the later of the following: 7.1.1 the Normal Vesting Date; or 7.1.2 the date on which the Designated Corporate Officer determines the extent to which any Condition or any other conditions are satisfied (which they will do as soon as reasonably practicable after the end of the period over which they are tested), or on any other date on which the Award Vests under these rules. For the avoidance of doubt, where there is more than one Normal Vesting Date in respect of an Award, then the Award will only be capable of Vesting on each Normal Vesting Date to the extent stated on grant. 7.2 Delayed Vesting Without limiting rule 10.3 (Malus), Vesting may, at the Designated Corporate Officer's discretion, be delayed in respect of a Participant's Award, or any part of it, if any of the following circumstances apply on the anticipated date of Vesting: 7.2.1 the Participant is subject to any Investigation; 7.2.2 the Participant's employment has terminated or is about to terminate in circumstances where it is not clear whether the Award should lapse under rule 10 (Malus and clawback); 7.2.3 a matter which may otherwise involve or affect that Participant has been referred to the Designated Corporate Officer for review under rule 10 (Malus and clawback); or 7.2.4 the Designated Corporate Officer considers that it is necessary or appropriate to defer Vesting. In these cases, Vesting will not occur unless and until the Designated Corporate Officer determines that the Award should Vest.

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 10 "Investigation" means, for the purpose of this rule 7.2, any enquiry or investigation by any member of the Group into the conduct, capability or performance of a Participant that may potentially lead to disciplinary action being taken against that Participant, and/or any disciplinary procedure (whether in accordance with any relevant contractual obligation, policy or otherwise) that has been commenced by any member of the Group against a Participant. 7.3 Dealing Restrictions If Vesting or the issue or transfer of Shares in satisfaction of an Award is prevented by any Dealing Restriction, the period for Vesting, issue or transfer will be delayed for that Award until the Dealing Restriction no longer applies. 7.4 Issuing Shares or transferring Shares from treasury Any Award (granted under any Sub-Plan) may be satisfied: 7.4.1 by issuing New Issue Shares to or to the order of the Participant if the Award was or could have been granted on the basis it would be satisfied with New Issue Shares under rule 5.1 (Plan limits); or 7.4.2 by transferring Shares from treasury to or to the order of the Participant; or 7.4.3 in any other manner permitted by the Sub-Plan or the terms of the Award. 7.5 Consequences of Vesting 7.5.1 If an Award takes the form of a Conditional Award, as soon as reasonably practicable after Vesting, the Grantor will arrange (subject to the rest of this rule 7 and rules 8 (Retention Period), 10 (Malus and clawback) and 13 (General)) for the issue or transfer to, or to the order of, the Participant, of the number of Shares in respect of which the Award has Vested. 7.5.2 A Participant can only exercise an Option to the extent it has Vested. To exercise it, the Participant must give notice in any prescribed form to the Grantor and pay any Option Price or make arrangements satisfactory to the Grantor for its payment. Subject to the rest of this rule 7 and rules 8 (Retention Period), 10 (Malus and clawback) and 13 (General), the Grantor will arrange for Shares to be issued or transferred to the Participant as soon as practicable following the date on which the Option is exercised. Notwithstanding anything else in these rules, an Option will always lapse on the Final Lapse Date if it does not lapse earlier under these rules. If an Option lapses under more than one provision of the rules of the Plan, the provision resulting in the shortest exercise period or earliest lapse date will prevail. 7.5.3 To the extent an Award of Restricted Shares Vests, the restrictions referred to in rule 4 (Documentation of Awards) and contained in the Restricted Share Agreement will cease to apply. 7.6 Dividend Equivalent Subject to any determinations under rule 3.5 (Dividend Equivalents), if the Award carries a Dividend Equivalent, it will be paid in cash or additional Shares at the time the Award is satisfied.

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 11 7.7 Cash and share alternative 7.7.1 The Grantor may, subject to the approval of the Designated Corporate Officer, satisfy an Option or Conditional Award by paying the Participant an amount in cash equal to the Market Value of the number of Shares in respect of which the Award Vests or is exercised. For Options, the cash amount must be equal to the amount by which the Market Value of all of the Shares in respect of which the Option is exercised exceeds the total Option Price and the Participant need not pay the Option Price. 7.7.2 An Award may be granted on the basis that it will always be satisfied in this way. 7.7.3 Where a Participant becomes entitled to a cash payment under these rules, subject to the approval of the Designated Corporate Officer, the Grantor can satisfy that entitlement by issuing or transferring a number of Shares (subject to rule 13.2 (Tax)) which have a Market Value on the date of Vesting for Awards and exercise for Options equal to the cash payment entitlement. 7.8 Automatic exercise of Options following death 7.8.1 To the extent that: (i) a deceased Participant's Option is exercisable but has not been exercised by the close of the Business Day before the last day of the exercise period determined under rule 9.4.3 but for this rule 7.8.1; and (ii) it is in the money on that day, the Company will, unless the Designated Corporate Officer decides otherwise, treat it as having been exercised on that day. 7.8.2 The Company will, subject to any decision made under rule 7.8.4, arrange for sufficient of the Shares resulting from the exercise to be sold on behalf of the Participant to raise an amount (after costs of sale) equal to the Option Price and any tax or social security required to be withheld under rule 13.2 (Tax). The remaining Shares subject to the Option will be issued or transferred as set out in rule 7.5.2 (subject always to rule 9.4.4). 7.8.3 An Option is "in the money" on any day, if the Designated Corporate Officer estimates that, if all the Shares resulting from exercise were sold on that day, the sale proceeds (after making a reasonable allowance for any costs of sale) would be more than the Option Price. 7.8.4 The personal representatives of a deceased Participant may give notice at any time before the day referred to in rule 7.8.1 requesting that this rule 7.8 not apply to the Option. 7.8.5 No member of the Group will be liable for any loss incurred by the Participant or their estate as a result of the application of or failure to apply this rule 7.8. 7.9 Issuing Shares for less than nominal value This rule applies where: 7.9.1 an Option is exercised and the Option Price is nil or less than the nominal value of a Share at the time; or 7.9.2 a Conditional Award Vests.

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 12 If the Award is to be satisfied by the issue of New Issue Shares, the Designated Corporate Officer is authorised to capitalise the reserves of the Company. The amount to be capitalised will be the nominal value of a Share less the Option Price (if any) multiplied by the number of Shares to be issued. 8 Retention Period This rule 8 applies if the Designated Corporate Officer determines that an Award is subject to a Retention Period. 8.1 How the Retention Period will apply to an Award 8.1.1 Before the Award Vests, the Designated Corporate Officer will determine whether: (i) the Award will continue in respect of the Retention Shares through the Retention Period (subject to this rule 8) ("Deferral of Vesting"); or (ii) the Retention Shares will be issued or transferred into the beneficial ownership of the Participant and held in accordance with this rule 8 ("Owned Shares"). 8.1.2 Deferral of Vesting: Where the Designated Corporate Officer determines that the Award will continue through the Retention Period, they shall calculate the number of Shares which Vest in accordance with rule 7.1 (Timing and extent of Vesting) but the Retention Shares will only be issued or transferred or cash paid under rule 7.5 (Consequences of Vesting) at the end of the Retention Period and subject to this rule 8. 8.1.3 Owned Shares: Where the Designated Corporate Officer has determined that Owned Shares will be issued or transferred to the Participant, they will calculate the number of Shares which Vest in accordance with rule 7.1 (Timing and extent of Vesting) and will issue or transfer the beneficial ownership of the Retention Shares (if not already held in respect of an Award of Restricted Shares), for no consideration, to any person specified by the Designated Corporate Officer to be held during the Retention Period under this rule 8. 8.1.4 Where the Award is an Option and the Designated Corporate Officer has determined that it will continue during the Retention Period, the Option will become exercisable as described in rule 7.5 (Consequences of Vesting) and any Retention Shares acquired on the exercise of the Option during the Retention Period (less any tax paid) will continue to be held as Owned Shares. 8.1.5 If required to do so by the Designated Corporate Officer, the Participant must enter into an agreement setting out the basis on which the Retention Shares will be held under this rule 8. If the Participant does not do so in the manner and within the timeframe specified by the Designated Corporate Officer, the Award will lapse and the Retention Shares will not be issued or transferred (or will be forfeited if already issued or transferred). 8.1.6 If the Retention Shares have already been transferred to the Participant or to another person to be held for the benefit of the Participant, the Participant will immediately transfer their interest in the Retention Shares, for no consideration or nominal consideration, to any person (which may include the Company, where permitted) specified by the Designated Corporate Officer.

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 13 8.2 Tax 8.2.1 Where tax is payable before the end of the Retention Period then rule 13.2 (Tax) will apply and Shares may be sold or the number of Shares under Award reduced under that rule. To the extent they are sold and/or reduced, the Retention Period will apply in respect of the remainder of the Shares. 8.2.2 The Participant must enter into any elections in relation to Retention Shares required by the Designated Corporate Officer, including tax elections. If the Participant does not do so in the manner and within the timeframe specified by the Designated Corporate Officer, the Award will lapse at the end of that period and the Retention Shares will not be issued or transferred (or they will be forfeited if already issued or transferred). 8.3 Rights during the Retention Period 8.3.1 Owned Shares The following additional provisions will apply to Owned Shares during the Retention Period: (i) The Participant will be entitled to vote (or to give instructions as to voting) and to receive dividends and have all other rights of a shareholder in respect of the Owned Shares from the date on which the Participant becomes the beneficial owner. (ii) The Participant may not transfer, assign or otherwise dispose of the Owned Shares or any interest in them (or instruct anyone to do so) except in the case of: (a) the sale of sufficient entitlements nil-paid in relation to an Owned Share to take up the balance of the entitlements under a rights issue or similar transaction; or (b) to fund any tax in accordance with rule 8.2 (Tax); or (c) Shares becoming subject to (or the Participant agreeing to approve or vote in favour of) a Change of Control or a transaction contemplated by rule 11.1.2; or (d) in any other circumstances if the Designated Corporate Officer so allows. (iii) Any securities which the Participant receives in respect of Owned Shares as a result of an event described in rule 6.5 (Adjustment of Awards) during the Retention Period will, unless the Designated Corporate Officer decides otherwise, be subject to the same restrictions as the corresponding Owned Shares. This will not apply to any Shares which a Participant acquires on a rights issue or similar transaction to the extent that they exceed the number they would have acquired on a sale of sufficient rights under the rights issued nil-paid to take up the balance of the rights. (iv) For the avoidance of doubt, clawback (under rule 10.4 (Clawback)) will apply to the Owned Shares during the Retention Period.

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 14 8.3.2 Deferral of Vesting The following provisions will apply during the Retention Period where an Award continues through the Retention Period: (i) Except as required under rule 8.2 (Tax), the Participant will have no rights in respect of the Retention Shares until the Shares are acquired at the end of the Retention Period. (ii) The Participant may not transfer, assign or otherwise dispose of the Retention Shares subject to any Award or any interest in them. (iii) If the Award carries a Dividend Equivalent, rule 7.6 (Dividend Equivalent) may apply from the Award Date until the end of the Retention Period. (iv) For the avoidance of doubt, malus under rule 10.3 (Malus) will continue to apply throughout the Retention Period. 8.4 Leaving employment and the Retention Period 8.4.1 Subject to rule 9.5 (Retention Period on death and leaving), if the Participant leaves employment during the Retention Period, rule 9 (Leaving employment) will not apply and the Retention Period will continue to apply after the Participant has left employment, unless the Designated Corporate Officer decides otherwise. 8.4.2 If a Participant leaves employment before the start of the Retention Period and the Award does not lapse, the Designated Corporate Officer may decide that the Retention Period will not apply. 8.4.3 If the Participant leaves employment during the Retention Period in circumstances in which their employment could have been terminated without notice or otherwise due to the Participant's misconduct, the Award will lapse. 8.5 Forfeiture of Owned Shares To the extent that Owned Shares are forfeited under rule 8.4.3 (Leaving employment and the Retention Period) or rule 10 (Malus and clawback), the Participant will, or is deemed to consent to, the immediate transfer of their beneficial ownership of the Owned Shares, for no consideration or nominal consideration, to any person (which may include the Company, where permitted) specified by the Designated Corporate Officer. 8.6 End of the Retention Period 8.6.1 The Retention Period will end on the earliest of the following: (i) the date on which the Retention Period will normally end, as set by the Designated Corporate Officer in relation to the Award; (ii) the date on which the Designated Corporate Officer decides that the number of Retention Shares is sufficiently small that the continuation of the Retention Period is not warranted; (iii) the date on which the Participant dies; and (iv) the date of a Change of Control or other transaction described in rule 11.1.2, unless the Award is exchanged.

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 15 8.6.2 Owned Shares: At the end of a Retention Period, the restrictions relating to Owned Shares in rule 8.3.1 (Owned Shares) will cease to apply and the Shares will be transferred to the Participant or as they may direct. 8.6.3 Deferral of Vesting: At the end of a Retention Period, the Award will Vest under rule 7 (Vesting) to the extent determined under rule 8.1.2 (How the Retention Period will apply to an Award). 9 Leaving employment 9.1 General rule Subject to rule 9.2 (Exceptions), rule 9.4 (Death) or rule 9.7 (Bonus Deferral Awards and Buy-out Awards), an Award will lapse if the Participant leaves employment before the Award Vests. 9.2 Exceptions 9.2.1 Subject to rules 9.6 (Early Vesting), 9.10 (Transfer), 9.11 (Career Breaks) and the rest of this rule 9.2, if a Participant leaves employment before the Award Vests due to: (i) ill-health, injury or disability, as established to the satisfaction of the Company; (ii) retirement with the agreement of the Participant's employer; (iii) the Participant's employing company ceasing to be a member of the Group; (iv) a transfer of the undertaking, or the part of the undertaking, in which the Participant works to a person who is not a member of the Group; (v) redundancy; or (vi) any other reason if the Designated Corporate Officer so decides in a particular case, an Award will not lapse but will continue in effect and the rules will continue to apply. 9.2.2 The Designated Corporate Officer must exercise any discretion provided for in rule 9.2.1(vi) within 80 days after he/she becomes aware of the cessation of the relevant Participant's employment or office and where the discretion is not exercised in favour of the Participant the Awards will be treated as having lapsed on the date of cessation. 9.2.3 Vesting or exercise of the Award on or after leaving employment will be subject to any applicable Condition and any such additional conditions or requirements as the Designated Corporate Officer may impose. 9.2.4 Unless the Designated Corporate Officer decides otherwise, the number of Shares in respect of which the Award Vests will be reduced to reflect the proportion of the period up to the Normal Vesting Date which had elapsed by the date the on which the Participant left employment or to such greater extent as they may determine (assessed on such basis as the Designated Corporate Officer decides).

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 16 9.3 Exchange of awards on a sale of employer If the Designated Corporate Officer, with the agreement of any relevant purchaser, so decides before the event referred to in rule 9.2.1(iii) or 9.2.1(iv) takes effect, Awards will not Vest, but will instead be exchanged, and rules 11.3 (Lapse of Options) to 11.7 (Exchange terms) will apply. In applying rules 11.4 (Exchange of Awards) to 11.7 (Exchange terms), the "Acquiring Company" will mean the relevant purchaser or any company nominated by the relevant purchaser and approved by the Designated Corporate Officer. 9.4 Death 9.4.1 If a Participant dies, their Award will Vest subject to rule 9.4.2, on the date of death and where relevant will lapse as to the balance. 9.4.2 If the Award is subject to a Condition, rule 9.6.2 will apply or the Designated Corporate Officer may decide to waive the Condition. 9.4.3 If the Award is an Option, it will be exercisable for 12 months from the date of death (or such longer period as the Designated Corporate Officer may specify), after which, unless exercised under rule 7.8 (Automatic exercise of Options following death), it will lapse. 9.4.4 The Grantor will only arrange for Shares to be issued or transferred, or cash paid to the personal representatives of a deceased Participant, if they have produced such evidence as the Designated Corporate Officer may require of their status as such. The receipt by any person who has produced such evidence will discharge the Grantor from any obligation to the Participant or their estate. 9.5 Retention Period on death and leaving 9.5.1 If a Participant leaves employment because of ill-health, injury or disability, as established to the satisfaction of the Company, the Designated Corporate Officer may decide that: (i) the Retention Period will not apply to any Award which Vests as a result; and/or (ii) any Retention Period which started before the Participant left employment will come to an end. 9.5.2 If a Participant dies, no Retention Period will apply to any Awards which Vest, and any Retention Period which has already started will come to an end. 9.5.3 On leaving in other circumstances, see rule 8.4 (Leaving employment and the Retention Period). 9.6 Early Vesting 9.6.1 If rule 9.2 (Exceptions) applies, the Designated Corporate Officer may decide that the Participant's Award will Vest, to the extent described in that rule, on the date of leaving employment or a later date determined by the Designated Corporate Officer. 9.6.2 In this circumstance, if the Award is subject to any condition (including a Condition), the Designated Corporate Officer will determine the extent to which it is satisfied on the date of Vesting in accordance with its terms or, if not specified in those terms,

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 17 they will estimate the extent to which it would be satisfied in such manner as they consider reasonable. 9.6.3 The Award will lapse to the extent it does not Vest. 9.7 Bonus Deferral Awards and Buy-out Awards The Designated Corporate Officer may decide that rule 9.1 (General rule) will not apply to Bonus Deferral Awards or Buy-out Awards or that rule 9.1 (General rule) will apply subject to such modifications as may be determined at grant. 9.8 Period for exercise of Options After the Participant has left employment, an Option will, unless a different exercise period and lapse date is determined by the Designated Corporate Officer (provided always that at the latest, an Option will lapse on the Final Lapse Date), lapse 12 months after the later of leaving employment and Vesting. 9.9 Meaning of "leaving employment" 9.9.1 Subject to rule 9.9.2, a Participant will only be treated as "leaving employment" when they are no longer an Employee of any member of the Group, as determined by the Designated Corporate Officer, and may not be treated as leaving employment if they commence employment with a member of the Group within one month (or such longer period as the Designated Corporate Officer may allow) of leaving. 9.9.2 The Designated Corporate Officer may decide that a Participant will be treated as leaving employment on the date they give or are given notice terminating their office or employment. 9.9.3 The Designated Corporate Officer may exercise any discretion under this rule 9 differently in relation to different Awards held by the same Participant. 9.10 Transfer If a Participant remains an Employee but is transferred to work in another country or changes tax resident status and, as a result, they would: 9.10.1 suffer a tax disadvantage in relation to their Award (this being shown to the satisfaction of the Designated Corporate Officer); or 9.10.2 become subject to restrictions on their ability to hold or deal in the Shares or the proceeds of the sale of the Shares acquired on Vesting or exercise because of the securities laws or exchange control laws of the country to which the Participant is transferred, then the Designated Corporate Officer may decide that the Award will Vest on a date they choose before or after the transfer takes effect. The Award will Vest to the extent the Designated Corporate Officer permits and will lapse as to the balance. 9.11 Career Breaks 9.11.1 If a Participant is on a career break on the date that their Awards would ordinarily Vest under the Plan, then unless the Designated Corporate Officer determines otherwise in any particular case, the Awards will Vest in accordance with these rules (but subject to any Retention Period) as soon as practicable after it has been

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 18 determined that the Participant has returned to normal employment at the end of the career break and has continued to be in their normal employment for a period of three months from the date of return, and in that period has not given or received notice of termination of employment. For the purposes of this rule, career break means an extended period of unpaid leave from normal work, without ceasing to be an Employee of any member of the Group, with the agreement of the Company, which is designated by the Designated Corporate Officer as a career break for the purposes of these rules. 9.11.2 Unless any of the reasons set out in rule 9.2 (Exceptions), 9.4 (Death) or 11 (Corporate events) apply, if the Participant ceases to be an Employee before having returned to normal employment at the end of the career break or during the three- month period referred to in rule 9.11.1, then the Awards will lapse on cessation of employment. If any of the reasons set out in rule 9.2 (Exceptions) or 9.4 (Death) do apply, the Awards will Vest in accordance with these rules (but subject to any Retention Period) as soon as practicable after cessation of employment. If any of the reasons set out in rule 11 (Corporate events) apply, Awards will Vest in accordance with that rule. 10 Malus and clawback 10.1 Application of malus and clawback An Award and a Participant shall be subject to: 10.1.1 any malus and/or clawback terms as set out at rule 10.2 (Minimum malus and clawback circumstances) below; 10.1.2 any malus and/or clawback terms of the Sub-Plan and/or the Award; 10.1.3 any policy that provides for malus or clawback as operated by any business unit and/or member of the Group from time to time; and 10.1.4 any contractual terms between the Participant and any member of the Group which provide for malus or clawback, and, in the case of clawback, clawback may be applied during the Clawback Period. 10.2 Minimum malus and clawback circumstances The minimum malus and clawback circumstances are: 10.2.1 The Participant has engaged in conduct (including, but not limited to, a violation of the Company's code of conduct (as amended from time to time)) which the Designated Corporate Officer considers was contrary to the legitimate expectations of the Company for an Employee in the Participant's position (or the position occupied by the Participant before they left the Group). 10.2.2 The performance of the Participant or the team, business area, member of the Group or profit centre in which the Participant works has fallen materially below the level expected at the time of grant of the Award. 10.2.3 Results announced for any period have been restated or subsequently appeared materially financially inaccurate or misleading as determined by the Designated Corporate Officer.

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 19 10.2.4 A business unit or profit centre in which the Participant works or has worked has made a material financial loss as a result of circumstances that could reasonably have been risk-managed, and which leads to or is likely to create reputational damage to the Group. 10.2.5 Any team, business area, member of the Group or profit centre in which the Participant works or has worked has been the subject of any regulatory investigation or has been in breach of any laws, rules or codes of conduct applicable to it or the standards reasonably expected of it. 10.2.6 The Designated Corporate Officer determines that material reputational damage has been caused to the Group or any member of the Group for which the Participant is responsible or accountable and which could have been reasonably avoided or mitigated. 10.2.7 The Designated Corporate Officer determines that, as a result of any miscalculation or use of incorrect information by the Company or any member of the Group (or any of their directors, employees or agents), the benefit received or receivable by the individual on Vesting of an Award (or exercise of an Option) would be, is or was incorrect. 10.2.8 The Designated Corporate Officer determines there has been a significant environmental / health & safety failure or other material risk management failure within the Group for which the Participant is responsible or accountable. 10.2.9 There has been a significant deterioration in the financial health of the Group or any member of the Group. 10.2.10 The Participant owes (for any reason, including as a debt) money to the Company or any member of the Group. 10.2.11 The Participant has ceased to be an Employee but has retained all or any portion of their Award for any reason, and the Participant either joins a Competitor Organisation of any member of the Group, and/or solicits Employees of any member of the Group to exit their Group employment, within 12 months of ceasing to be an Employee. The Designated Corporate Officer will have the sole discretion to determine the definition of "Competitor Organisation". 10.2.12 Any other event as a result of which the Designated Corporate Officer considers that the application of this rule is appropriate. 10.3 Malus Where the Designated Corporate Officer decides that malus will apply to a Participant: 10.3.1 the Award will lapse or, in the case of Owned Shares, will be forfeited, wholly or in part as they may determine; and/or 10.3.2 the restricted period or any Retention Period for any Award will be extended by such period as they may determine; and/or 10.3.3 if the Award has already Vested but Shares have not yet been released (because of, for example, any Dealing Restrictions), a reduced number of Shares as determined by the Designated Corporate Officer (including nil) will be released to the Participant.

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 20 10.4 Clawback Where, during the Clawback Period, the Designated Corporate Officer decides that clawback will apply to a Participant, then the Participant must transfer to, or to the order of, the Company, for no consideration, a number of Shares equal to the gross number of Shares which they acquired pursuant to any Award (or such lesser number as the Designated Corporate Officer may determine), or pay to, or to the order, of the Company an amount equal to the Market Value of such Shares (as at such date as the Designated Corporate Officer may determine) or the gross amount of cash (or such lesser amount as the Designated Corporate Officer may determine) which was paid pursuant to the Award (which shall be a debt immediately due and payable) and for which purpose the Designated Corporate Officer may decide that: 10.4.1 any Award, bonus or other benefit which might have been granted, Vested or paid to the Participant under this or any other arrangement will be reduced, be treated as never having been awarded or will not Vest; and/or 10.4.2 to the extent permitted by law, any amount payable in respect of the clawback may be deducted from any amount that is otherwise payable to the Participant by any member of the Group, including salary or bonus. 10.5 General 10.5.1 For the avoidance of doubt, circumstances described in rule 10.1 (Application of malus and clawback) can arise even if the Participant was not responsible for the event in question or if it happened before or after the Vesting or grant of the Award. 10.5.2 Malus and/or clawback may be applied differently for different Participants or for different Awards held by the same Participant in relation to the same event. 10.5.3 The Designated Corporate Officer will notify the Participant of any application of malus or clawback. 10.5.4 Without limiting rule 13.1 (Terms of employment), the Participant will not be entitled to any compensation in respect of any application of malus or clawback. 11 Corporate events 11.1 Time of Vesting 11.1.1 If there is a Change of Control an Award Vests subject to rules 11.2 (Extent of Vesting), 11.3 (Lapse of Options) and 11.4 (Exchange of Awards). 11.1.2 If the Company is or may be affected by: (i) any demerger, delisting, distribution (other than an ordinary dividend) or other transaction which, in the opinion of the Designated Corporate Officer, might affect the current or future value of any Award; or (ii) any reverse takeover (not within rule 11.1.1 above), merger by way of a dual- listed company or other significant corporate event, as determined by the Designated Corporate Officer, the Designated Corporate Officer may allow an Award to Vest to the extent specified in rule 11.2 (Extent of Vesting). The Designated Corporate Officer may impose other conditions on Vesting.

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 21 11.1.3 This rule 11.1.3 applies if an Option Vests as a result of, or has Vested before, a court sanctioning a compromise or arrangement in connection with the acquisition of Shares. The Designated Corporate Officer may decide at any time before court sanction that the Option will be deemed exercised (to the extent specified under rule 11.2 (Extent of Vesting) or otherwise) with effect from court sanction, if they consider that the value of consideration receivable for the resulting Shares under the compromise or arrangement would be more than the total Option Price. The Option Price will be deducted from the consideration receivable for the resulting Shares. The Company will notify each affected Participant of this decision and may give the Participant a reasonable opportunity to direct the Company that the Option should not be deemed exercised. 11.2 Extent of Vesting Where an Award Vests under rule 11.1 (Time of Vesting): 11.2.1 an Award will Vest to the extent that any Condition has been met to the date of Vesting and subject to any such additional conditions as the Designated Corporate Officer may impose; and 11.2.2 unless the Designated Corporate Officer decides otherwise, the number of Shares in respect of which the Award Vests will be reduced to reflect the proportion of the period up to the Normal Vesting Date which had elapsed by the date of Vesting or to such greater extent as they may determine. To the extent that the Award does not Vest as a result of this rule 11.2, the Designated Corporate Officer may decide that it will be exchanged (wholly or partly) under rule 11.4 (Exchange of Awards). 11.3 Lapse of Options An Option will be exercisable: 11.3.1 following a Change of Control, for six months after the Change of Control or, if earlier, for six weeks after the date on which a notice to acquire Shares under Section 979 of the Companies Act 2006 is first served; or 11.3.2 following an event described in rule 11.1.1, for such period (not exceeding one year) as the Designated Corporate Officer may set at the time of the event, and will lapse at the end of that period to the extent it has not been exercised or exchanged. 11.4 Exchange of Awards An Award will not Vest (or, in the case of an Option, be exercisable) following a Change of Control or an event described in rule 11.1.2 but will be exchanged pursuant to rule 11.7 (Exchange terms) where: 11.4.1 an offer to exchange the Award is made and accepted by a Participant; or 11.4.2 the Designated Corporate Officer, with the consent of the Acquiring Company, decides before the Change of Control that the Award will be automatically exchanged; or

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 22 11.4.3 the Participant's variable remuneration is subject to regulatory deferral requirements in accordance with applicable Remuneration Rules, unless the Designated Corporate Officer decides otherwise. 11.5 Designated Corporate Officer In this rule 11, "Designated Corporate Officer" means the person or persons identified by the Company as such immediately before the Change of Control. 11.6 Timing of exchange Where an Award is to be exchanged under rule 11.4 (Exchange of Awards) the exchange is effective immediately following the relevant event. 11.7 Exchange terms Where a Participant is granted a new award in exchange for an existing Award, the new Award: 11.7.1 must confer a right to acquire shares in the Acquiring Company or another body corporate determined by the Acquiring Company unless the Designated Corporate Officer decides that the new Award may instead confer a right to receive cash calculated by reference to the value of the existing Award at the date of exchange under rule 11.6 (Timing of exchange); 11.7.2 must be equivalent to the existing Award, subject to rule 11.7.4; 11.7.3 is treated as having been acquired at the same time as the existing Award and, subject to rule 11.7.4, will Vest in the same manner and at the same time and be subject to the same Retention Period; 11.7.4 must: (i) be subject to a Condition which is, so far as possible, equivalent to any Condition applying to the existing Award; or (ii) not be subject to any Condition but be in respect of the number of shares which is equivalent to the number of Shares comprised in the existing Award which would have Vested under rule 11.2 (Extent of Vesting) and Vest at the original Normal Vesting Date set by the Designated Corporate Officer on the grant of the Award; and/or (iii) be subject to such other terms as the Designated Corporate Officer considers appropriate in all the circumstances; and (iv) is governed by the Plan, excluding rule 12.2 (Shareholder approval), as if references to Shares were references to the shares over which the new award is granted and references to the Company were references to the Acquiring Company or the body corporate determined under rule 11.7.1 above.

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 23 12 Changing the Plan and termination 12.1 Designated Corporate Officer's powers Subject to rule 12.2 (Shareholder approval), the Designated Corporate Officer may at any time change the Plan in any way, including changes to the terms of any Sub-Plan and/or any existing Award already granted which are: 12.1.1 to the disadvantage of the Participant; or 12.1.2 to the advantage of the Participant but only if the Plan would permit a new Award to be granted on those changed terms. 12.2 Shareholder approval 12.2.1 Except as described in rules 12.1.1 and 12.2.2, the Company in a general meeting must approve in advance by ordinary resolution any proposed change to the Plan to the advantage of present or future Participants, which relates to: (i) the Participants; (ii) the limits on the number of Shares, cash or other benefits subject to the Plan; (iii) the basis for determining a Participant's entitlement to, and the terms of, securities, cash or other benefits to be provided and for the adjustment thereof (if any) if there is a capitalisation issue, rights issue or open offer, sub-division or consolidation of shares or reduction of capital or any other variation of capital; or (iv) the terms of this rule 12.2.1. 12.2.2 The Designated Corporate Officer can change the Plan (or the terms of any Sub- Plan and/or any existing Award already granted) and need not obtain the approval of the Company in general meeting for any changes to a Condition in accordance with rule 3.4 (Conditions) or for any minor changes: (i) to benefit the administration of the Plan; (ii) to comply with or take account of the provisions of any proposed or existing legislation or regulation; (iii) to take account of any changes to legislation or regulation; or (iv) to obtain or maintain favourable tax, exchange control or regulatory treatment of the Company, any Subsidiary or any present or future Participant. 12.2.3 The Company in general meeting must approve in advance by ordinary resolution any proposed change to rule 5.1 (Plan limits). 12.3 Employees' share scheme No amendment or operation of the Plan will be effective to the extent that the Plan would cease to be an "employees' share scheme" as defined in Section 1166 of the Companies Act 2006.

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 24 12.4 Notice The Designated Corporate Officer is not required to give Participants notice of any changes. 12.5 Termination The Plan will terminate on the 10th anniversary of shareholder approval of the Plan unless the shareholders provide a further approval by ordinary resolution for the Plan to continue but the Designated Corporate Officer may terminate the Plan at any time before that date. The termination of the Plan will not affect existing Awards but no further Awards may be granted under any Sub-Plan. 13 General 13.1 Terms of employment 13.1.1 For the purposes of this rule 13, "Employee" means any person who is or will be eligible to be a Participant, or any other person. 13.1.2 This rule applies: (i) whether the Company, the Designated Corporate Officer, the administrator, or any member of the Group, has full discretion in the operation of the Plan, or whether such person could be regarded as being subject to any obligations in the operation of the Plan; (ii) during an Employee's employment or employment relationship with any member of the Group; and (iii) after the termination of an Employee's employment or employment relationship, whether the termination is lawful or unlawful. 13.1.3 Nothing in the rules or the operation of the Plan forms part of the contract of employment or employment relationship of an Employee. The rights and obligations arising from the employment relationship between the Employee and the Company or any member of the Group are separate from, and are not affected by, the Plan. Participation in the Plan does not create any right to, or expectation of, continued employment or a continued employment relationship. 13.1.4 The grant of Awards on a particular basis in any year does not create any right to or expectation of the grant of Awards on the same basis, or at all, in any future year. 13.1.5 The benefit to an Employee of participating in the Plan shall not form any contractual right and shall not be pensionable or benefit bearing. 13.1.6 No Employee has a right to participate in the Plan, or be considered for participation in it, at a particular level or at all. Participation in one operation of the Plan does not imply any right to participate, or to be considered for participation in any later operation of the Plan. 13.1.7 Without prejudice to an Employee's right in respect of Awards, including their Vesting, subject to and in accordance with the express terms of the Plan, no Employee has any rights in respect of the exercise or omission to exercise any discretion, or the making or omission to make any decision, relating to the Awards or their Vesting. Any and all discretions, decisions or omissions relating to the Awards or their Vesting may operate to the disadvantage of the Employee, even if this could

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 25 be regarded as capricious or unreasonable, or could be regarded as in breach of any implied term between the Employee and their employer, including any implied duty of trust and confidence. Any such implied term is excluded and overridden by this rule. 13.1.8 No Employee has any right to compensation for any loss in relation to the Plan, including: (i) any loss or reduction of any rights or expectations under the Plan in any circumstances or for any reason (including lawful or unlawful termination of employment or the employment relationship); (ii) any exercise of a discretion or a decision taken in relation to Awards or to the Plan, or any failure to exercise a discretion or take a decision; and (iii) the operation, suspension, termination or amendment of the Plan, or any grant of Awards or their Vesting or release. 13.1.9 Participation in the Plan is permitted only on the basis that the Participant accepts all the provisions of its rules, including in particular this rule. By participating in the Plan, an Employee waives all rights under the Plan, other than the right to acquire Shares subject to and in accordance with the express terms of the Plan and any applicable conditions (or Conditions), in consideration for, and as a condition of, the grant of Awards under the Plan. 13.1.10 Each of the provisions of this rule is entirely separate and independent from each of the other provisions. If any provision is found to be invalid then it will be deemed never to have been part of these rules and to the extent that it is possible to do so, this will not affect the validity or enforceability of any of the remaining provisions. 13.2 Tax 13.2.1 The Participant will be responsible for all taxes, social security contributions and other liabilities applicable to them arising out of or in connection with an Award or the acquisition, holding or disposal of Shares or any interest in them or any changes in the rights or restrictions attached to them. 13.2.2 If the Grantor, any member of the Group or the trustee of any employee benefit trust has any liability to pay or account for any such tax, contribution, levy or charge, it will normally meet the liability by selling Shares to which the Participant becomes entitled on their behalf and using the proceeds to meet the liability. However, the Designated Corporate Officer may decide that the liability will, instead, be met by: (i) deducting the amount of the liability from any cash payment due under the Plan; (ii) reducing the number of Shares to which the Participant would otherwise be entitled; and/or (iii) deducting the amount from any payment of salary, bonus or other payment due to the Participant. 13.2.3 The Participant will enter into any elections required by the Designated Corporate Officer, including tax elections and/or elections to transfer any liability, or agreements to pay social security contributions.

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 26 13.2.4 Notwithstanding anything else in these rules, the Vesting of an Award or the issue or transfer of Shares or any payment of cash may be delayed until the Participant has done all things reasonably required by the Designated Corporate Officer to give effect to this rule 13.2. 13.3 Designated Corporate Officer's decision final and binding The decision of the Designated Corporate Officer, on the interpretation of the Plan (including any Sub-Plan) and/or the terms of any Award, or in any dispute relating to an Award granted or matter relating to the Plan, will be final and conclusive. 13.4 Third party rights Nothing in this Plan confers any benefit, right or expectation on a person who is not a Participant and no third party has any rights under the Contracts (Rights of Third Parties) Act 1999 or any equivalent local legislation to enforce any term of this Plan, provided that any member of the Group may rely on and enforce all of the terms of the Plan. This does not affect any other right or remedy of a third party which may exist. 13.5 Documents provided to shareholders Prior to the Participant becoming a shareholder of the Company, the Company is not required to provide to Participants copies of any documents or notices normally sent to the holders of its Shares. 13.6 Costs The Company will pay the costs of introducing and administering the Plan. The Company may ask a Participant's employer or any other member of the Group to bear the costs in respect of an Award to that Participant. 13.7 Employee trust Any member of the Group may provide money to the trustee of any trust or any other person to enable them or him to acquire Shares to be held for the purposes of the Plan, or enter into any guarantee or indemnity for those purposes, to the extent permitted by Section 682 of the Companies Act 2006. 13.8 Data protection 13.8.1 Subject to rule 13.8.3, by participating in the Plan and accepting an Award, the Participant consents to the holding and processing of personal information provided by the Participant to any member of the Group, trustee or third party service provider, for all purposes relating to the operation of the Plan. These include, but are not limited to: (i) administering and maintaining Participant records; (ii) providing information to members of the Group, trustees of any employee benefit trust, registrars, brokers or third party administrators of the Plan; (iii) providing information to future purchasers or merger partners of the Company, the Participant's employing company, or the business in which the Participant works; and

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 27 (iv) transferring information about the Participant to a country or territory that may not provide the same statutory protection for the information as the Participant's home country. 13.8.2 The Participant is entitled to a copy of the personal information held about them (subject to payment of any fee set by the Designated Corporate Officer where charging such a fee would be lawful). If anything is inaccurate, the Participant has the right to have it corrected. 13.8.3 The basis for any processing of personal information about the Participant under the EU's General Data Protection Regulation (2016/679) ("GDPR") (or any successor laws, including its incorporation into UK law as the UK GDPR) is set out in the Company's Fair Processing Notice on people@bp as well as the privacy notices held by the share plan administrators. The Fair Processing Notice and privacy notices also contain details about how the Participant's personal information is processed and the Participant's rights in relation to that information. The Participant has a right to review the Fair Processing Notice and the privacy notices. 13.9 Consents All allotments, issues and transfers of Shares will be subject to any necessary consents under any relevant enactments or regulations for the time being in force in any relevant country. The Participant is responsible for complying with any requirements they need to fulfil in order to obtain or avoid the necessity for any such consent. 13.10 Share rights Shares issued to satisfy Awards under the Plan will rank equally in all respects with the Shares in issue on the date of allotment. They will not rank for any rights attaching to Shares by reference to a record date preceding the date of allotment. Where Shares are transferred to a Participant, including a transfer out of treasury, the Participant will be entitled to all rights attaching to the Shares by reference to a record date on or after the transfer date. The Participant will not be entitled to rights before that date. 13.11 Listing If and so long as the Shares are listed and traded on a public market, the Company will apply for listing of any Shares issued under the Plan as soon as practicable. 13.12 Separate provisions 13.12.1 Each of the provisions of these rules is entirely separate and independent from each of the other provisions. If any provision of any rule is found to be invalid, illegal or unenforceable, in whole or in part, in relation to an Award or a Participant, the provision shall apply to that Award or Participant with whatever deletion or modification is necessary so that the provision is legal, valid and enforceable and gives effect to the commercial intention of the parties. 13.12.2 To the extent it is not possible to delete or modify the provision, in whole or in part, then such provision or part of it will be deemed, to the extent that it is illegal, invalid or unenforceable, never to have been part of these rules in relation to that Award or that Participant and to the extent that it is possible to do so, this will not affect the validity or enforceability of any of the remaining provisions of that or any other rule.

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&nbsp;&nbsp;&nbsp;&nbsp;3036746900/84/22 Apr 2025 28 13.13 Notices 13.13.1 Any information or notice to a person who is or will be eligible to be a Participant under or in connection with the Plan may be posted, or sent by electronic means, in such manner to such address as the Company considers appropriate, including publication on any website. 13.13.2 Any information or notice to the Company or other duly appointed agent under or in connection with the Plan may be sent by post or by electronic means to it at its registered office or such other place, and by such other means, as the Designated Corporate Officer or duly appointed agent may decide and notify to Participants. 13.13.3 Notices sent by post will be deemed to have been given on the second day after the date of posting. However, notices sent by or to a Participant who is working overseas will be deemed to have been given on the seventh day after the date of posting. Notices sent by electronic means, in the absence of evidence to the contrary, will be deemed to have been received on the day after sending. 13.14 Governing law and jurisdiction Except as may be stated elsewhere herein or in any Sub-Plan, English law governs the Plan and all Awards and their construction. The English courts have exclusive jurisdiction in respect of disputes arising under or in connection with the Plan or any Award.

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## Exhibit 11.2

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;bp share dealing policy The bp share dealing policy (Policy) forms a set of requirements as defined in the Code of Conduct of BP p.l.c. (Company) and seeks to prevent individuals from misusing, or placing themselves under suspicion of misusing, information about bp to which they have access and which is not available to other investors or potential investors. The Policy covers all securities of the Company including, but not limited to, the Company's shares. The Policy applies to all bp employees, contractors, officers and members of the board of the Company. Additional share dealing requirements relating only to members of the board of the Company, being persons discharging managerial responsibility as defined under the UK Market Abuse Regulation (PDMRs), are included in the Policy. Failure to comply with the Policy may result in internal disciplinary procedures being applied. It is a criminal offence to use inside information for illegal purposes, including dealing in securities based on inside information or recommending, encouraging or inducing others to do the same. Summary practical guidance is set out in the appendix. If you are not sure whether you can deal in securities of the Company, please first of all get in touch with the Company Secretary's Office. Confidential vs inside information 1. You must not at any time disclose to anyone (including but not limited to your family, friends and business acquaintances) any confidential or sensitive information about bp. In addition, if any information you have access to is inside information\* you must not: (i) deal\* in any securities\* of the Company or any instruments linked to them; (ii) recommend, encourage or induce somebody else to do the same; and/or (iii) disclose the inside information except where you have had confirmation from the Company Secretary's Office that you may do so and are required to do so as a part of your employment or duties. These actions – 1(i-iii) above are considered 'insider dealing' and 'unlawful disclosure of inside information'. The prohibition on insider dealing applies even if you will not profit from the dealing. 2. From time to time, as a part of your employment or duties, you may come across information which is not inside information in relation to bp, but which is inside information in relation to a different company (for example, a company that is a customer of, or supplier to, bp). You must not undertake any of the actions identified in 1(i-iii) above in relation to that company or its securities when you have inside information in relation to that company. \*See appendix

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;PDMRs 3. Members of the board of the Company are identified as PDMRs of the Company. Individuals identified as PDMRs will be notified that they are PDMRs. 4. All PDMRs are categorised as permanent restricted persons, meaning you and the persons closely associated with you (PCAs – see below) must always seek and receive clearance from the Company Secretary's Office prior to dealing in the Company's securities and the securities of any bp Group company. 5. Every transaction in the Company's securities conducted on your own account, or on the account of any of your PCAs, must be promptly notified to: (i) the Company Secretary's Office no later than one business day after the relevant transaction; and (ii) the UK Financial Conduct Authority no later than three working days after the relevant transaction (when notified, the Company Secretary's Office will complete this on behalf of you and your PCAs). 6. Your 'PCAs' are: (i) your spouse or civil partner; (ii) your dependent children, meaning children or stepchildren under the age of 18 years who are unmarried and do not have a civil partner; (iii) a relative who has shared the same household as you for at least one year on the date of dealing; and (iv) a legal person, trust or partnership, the managerial responsibilities of which are discharged by you or by one of the persons in paragraphs (i- iii), which is directly or indirectly controlled by such a person, which is set up for the benefit of such a person, or the economic interests of which are substantially equivalent to those of such a person. 7. You must notify: (i) your PCAs in writing of their obligations under the Policy and keep a copy of that notification (the Company Secretary's Office will provide you with a template that you can use to do this); and (ii) the Company Secretary's Office of the identity of your PCAs (including any changes to that list). Restricted persons 8. There are two categories of restricted persons: 'permanent' and 'designated' restricted persons. 9. PDMRs, members of the bp leadership team and the company secretary as well as those with access to the email inboxes of these individuals are permanent restricted persons. Individuals will be notified that they are permanent restricted persons.

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;10. Certain individuals may from time to time be designated restricted persons where their role or function requires them to have access to confidential and potentially sensitive information. You will be notified if you are identified as a designated restricted person and will also be notified when you are no longer identified as a designated restricted person. 11. By way of example, you may become a designated restricted person by virtue of having access to the Company's unpublished financial results during closed periods. Closed periods take place during the longer of (i) the period from the end of the relevant quarterly financial period up to the date of publication of the Company's financial results; or (ii) the period of 30 calendar days before the date of such publication. If you are a designated restricted person by virtue of your access to the Company's unpublished financial results, you will be notified when a closed period starts and when it is due to end. Insiders 12. Certain individuals may from time to time be insiders where they are deemed to be in possession of inside information about the Company. You will be notified if you are identified as an insider and that your personal details are being added to a list maintained for this purpose. You will also be notified when the insider list has closed. If you are notified that you are an insider you must not deal in the securities of the Company, even if you had received prior clearance to deal. 13. If you have been identified as an insider, the restrictions on dealing in bp securities are applicable to you and your connected persons\*/PCAs. It is your responsibility to notify your connected persons/PCAs of any relevant restrictions. 14. If you believe you are in possession of inside information but have not been notified that you are an insider, neither you nor your connected persons/PCAs should deal in the Company's securities and you must notify the Company Secretary's Office immediately. Clearance to deal 15. If and for so long as you are a restricted person, whether permanent (including PDMRs) or designated, you should not deal in the Company's securities without requesting and receiving clearance to deal. 16. If you are a permanent restricted person (including PDMRs), neither you nor your connected persons/PCAs should deal in the securities of any bp Group company without requesting and receiving clearance to deal. 17. If and for so long as you are an insider, you and your connected persons must not deal in the securities of the Company. 18. Clearance to deal must be sought and received in advance of dealing, from the Company Secretary's Office. The chair of the board is required to seek and receive clearance to deal from the senior independent director in consultation with the company secretary. Any other director of the Company and any member of the bp leadership team is required to seek and receive clearance from the company

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;secretary. The company secretary is required to seek and receive clearance from the chair of the board. 19. In seeking clearance to deal, submission of the request requires you to confirm details about your proposed dealing and that you are not in possession of inside information about the Company. 20. Once you have received clearance to deal, you should deal as soon as possible and in any event within two business days of receiving clearance. If for any reason, the approved dealing has not taken place within two business days, clearance to deal should be sought again.

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Appendix Summary practical guidance on key terms referenced in the Policy are provided below: Inside information – information which: • relates directly or indirectly to the Company or its securities; • is precise in nature; • has not been made public; and • would be likely to have a significant effect on the price of the Company's securities if it were made public. Dealing – covers a very wide range of transactions in a company's securities, including but not limited to: • buying or selling bp securities; • transferring securities to other accounts, including those of spouses and including gifts; • exercising bp share awards or joining bp share schemes; • providing instructions in relation to any bp shares held through a retirement account (401(k), personal account, or other account; • using the Company's shares as security for a loan; and • entering into any derivative contract which relates to the Company's securities. If you have entered into a commitment to deal at a time when you were not restricted, any consequential dealing while under restrictions may be permissible – please get in touch with the Company Secretary's Office for further guidance. Securities – covers any securities including, for example, shares, bonds, notes and depositary receipts and any financial instruments linked to them, such as derivatives. Connected persons – covers the same definition as 'PCAs' under provision 6 of the Policy. The notification obligations set out under provision 7 of the Policy relating to PCAs do not apply to connected persons.

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## Ex-12

**EXHIBIT 12**

**Rule 13a—14(a) Certificates**

I, Carol Howle, certify that:

1. I have reviewed this annual report on Form 20-F of BP p.l.c.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4. The company's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the company's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the company's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company's internal control over financial reporting; and

5. The company's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company's auditors and the audit committee of the company's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company's internal control over financial reporting.

---

| | |
|:---|:---|
| &nbsp;&nbsp;&nbsp;Date: 6 March 2026 | /s/ Carol Howle |
| | Carol Howle |
| | Interim Chief Executive Officer |

---

------

I, Kate Thomson, certify that:

1. I have reviewed this annual report on Form 20-F of BP p.l.c.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4. The company's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the company's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the company's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company's internal control over financial reporting; and

5. The company's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company's auditors and the audit committee of the company's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company's internal control over financial reporting.

---

| | |
|:---|:---|
| &nbsp;&nbsp;&nbsp;Date: 6 March 2026 | /s/ Kate Thomson |
| | Kate Thomson |
| | Chief Financial Officer |

---

## Ex-13

**Exhibit 13**

**Rule 13a — 14(b) Certificates**

**Certification**

**Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**

**(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)**

&nbsp;&nbsp;&nbsp;&nbsp;Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code), the undersigned officer of BP p.l.c., a company incorporated under the laws of England and Wales (the "<u>company</u>"), hereby certifies, to such officer's knowledge, that:

&nbsp;&nbsp;&nbsp;&nbsp;The Annual Report on Form 20-F for the year ended December 31, 2025 (the "<u>Report</u>") of the company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the company.

---

| | |
|:---|:---|
| Date: 6 March 2026 | /s/ Carol Howle |
| | Carol Howle |
| | Interim Chief Executive Officer |

---

&nbsp;&nbsp;&nbsp;&nbsp;The foregoing certification is being furnished solely pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.

&nbsp;&nbsp;&nbsp;&nbsp;A signed original of this written statement required by Section 906 has been provided to the company and will be retained by the company and furnished to the Securities and Exchange Commission or its staff upon request.

**Certification**

**Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**

**(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)**

&nbsp;&nbsp;&nbsp;&nbsp;Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code), the undersigned officer of BP p.l.c., a company incorporated under the laws of England and Wales (the "<u>company</u>"), hereby certifies, to such officer's knowledge, that:

&nbsp;&nbsp;&nbsp;&nbsp;The Annual Report on Form 20-F for the year ended December 31, 2025 (the "<u>Report</u>") of the company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the company.

---

| | |
|:---|:---|
| Date: 6 March 2026 | /s/ Kate Thomson |
| | Kate Thomson |
| | Chief Financial Officer |

---

&nbsp;&nbsp;&nbsp;&nbsp;The foregoing certification is being furnished solely pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.

&nbsp;&nbsp;&nbsp;&nbsp;A signed original of this written statement required by Section 906 has been provided to the company and will be retained by the company and furnished to the Securities and Exchange Commission or its staff upon request.

## Exhibit 15.1

![image_2.jpg](image_2.jpg)

**EXHIBIT 15.1**

<u>CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS</u>

We hereby consent to (i) the reference to Netherland, Sewell & Associates, Inc. contained in the section entitled "Oil and gas disclosures for the group" of the Annual Report and Form 20-F for the year ended December 31, 2025, of BP p.l.c. (the Form 20-F), as set forth under the heading "Compliance" on page 345 and (ii) the inclusion of our third-party letter report dated January 23, 2026, concerning our estimates of the proved reserves and future revenue, as of December 31, 2025, to the BPX Production Company interest in certain oil and gas properties located in Louisiana and Texas (the Third-Party Report), which is included as Exhibit 15.2 to the Form 20-F, and to the incorporation by reference of the reference to Netherland, Sewell & Associates, Inc. in the Form 20-F and of the Third-Party Report in the following Registration Statements:

The Registration Statement on Form F-3 (File Nos. 333-277842, 333-277842-01 and 333-277842-02) of BP p.l.c., BP Capital Markets p.l.c., and BP Capital Markets America Inc., and the Registration Statements on Form S-8 (File Nos. 333-67206, 333-79399, 333-102583, 333-103923, 333-103924, 333-119934, 333-123482, 333-123483, 333-131583, 333-131584, 333-132619, 333-146868, 333-146870, 333-146873, 333-149778, 333-173136, 333-177423, 333-179406, 333-186462, 333-186463, 333-199015, 333-200794, 333-200795, 333-200796, 333-207188, 333-207189, 333-210316, 333-210318, 333-253287, 333-254578, 333-270440, 333-273587 and 333-280100) of BP p.l.c.

**&nbsp;&nbsp;&nbsp;&nbsp;NETHERLAND, SEWELL & ASSOCIATES, INC.**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;

&nbsp;&nbsp;&nbsp;&nbsp;By:&nbsp;&nbsp;&nbsp;&nbsp;<u>/s/ Richard B. Talley, Jr.</u>&nbsp;&nbsp;&nbsp;&nbsp;

&nbsp;&nbsp;&nbsp;&nbsp;Richard B. Talley, Jr., P.E.

&nbsp;&nbsp;&nbsp;&nbsp;Chairman and Chief Executive Officer

Houston, Texas

March 6, 2026

## Exhibit 15.2

![](a31122025bpex152_nsaiye2001.jpg)

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;January 23, 2026 Mr. Kyle Koontz BPX Production Company 1700 Platte Street, Suite 150 Denver, Colorado 80202 Dear Mr. Koontz: In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2025, to the BPX Production Company (BPX) interest in certain oil and gas properties located in Louisiana and Texas. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves within BPX's U.S. Lower 48 business unit and that the proved reserves within BPX's U.S. Lower 48 business unit represent 30 percent of the BP p.I.c. subsidiaries' proved reserves. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. We estimate the net reserves and future net revenue to the BPX interest in these properties, as of December 31, 2025, to be: Net Reserves Future Net Revenue (M$) Oil NGL (1)Gas(1) Present Worth Category (MBBL) (MBBL) (MMCF) Total at 10% Proved Developed Producing 151,477.6 179,213.8 2,768,451.8 10,824,961.3 07,127,915.3 Proved Undeveloped 170,175.2 202,969.4 3,790,164.2 07,654,687.4 03,007,087.6 Total Proved 321,652.8 382,183.2 6,558,616.0 18,479,648.7 10,135,002.9 (1) Gas reserves are inclusive of fuel gas volumes expected to be consumed in field operations. The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. Oil equivalent volumes shown in this report are expressed in thousands of barrels of oil equivalent (MBOE), determined using the ratio of 5.8 MCF of gas to 1 barrel of oil. The table following the definitions sets forth our estimates of net reserves, by reserves category, to the BPX interest for each Discovered Resources Management (DRM) field. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Our study indicates that as of December 31, 2025, there are no proved developed non-producing reserves for these properties. No study was made to determine whether probable or possible reserves might be established for these properties. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Gross revenue is BPX's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for BPX's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties. Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month trade date price for each month in the period January through December 2025. For oil and NGL volumes, the average West Texas Intermediate spot price of $65.343 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $3.409 per MMBTU is adjusted for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $64.681 per barrel of oil, $24.053 per barrel of NGL, and $2.645 per MCF of gas. Operating costs used in this report are based on operating expense records of BPX. These costs include the per- well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into per-well costs and per-unit-of- production costs. Headquarters general and administrative overhead expenses of BPX are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation. Capital costs used in this report were provided by BPX and are based on authorizations for expenditure, budget estimates, and actual costs from recent activity. Capital costs are included as required for new development wells and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are BPX's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation. For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the BPX interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on BPX receiving its net revenue interest share of estimated future gross production. Additionally, although we are aware of firm transportation contracts that are in place for these properties, the associated costs are considered by BPX to be corporate-level expenses; no adjustments have been made to our estimates of future revenue to account for such contracts. The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by BPX, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report. For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment. The data used in our estimates were obtained from BPX, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis. Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699 By: Richard B. Talley, Jr., P.E. Chairman and Chief Executive Officer By: By: C. Ashley Smith, P.E. 100560 Edward C. Roy III, P.G. 2364 Vice President Vice President Date Signed: January 23, 2026 Date Signed: January 23, 2026 CAS:MSS

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DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 1 of 6 The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations. (1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties. (2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) Same environment of deposition; (iii) Similar geological structure; and (iv) Same drive mechanism. Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest. (3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons. (4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature. (5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. (6) 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. Supplemental definitions from the 2018 Petroleum Resources Management System: Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation. Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. (7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. (ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

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DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 2 of 6 (iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. (iv) Provide improved recovery systems. (8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. (9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. (10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section. (11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date. (12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory- type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs. (ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. (iii) Dry hole contributions and bottom hole contributions. (iv) Costs of drilling and equipping exploratory wells. (v) Costs of drilling exploratory-type stratigraphic test wells. (13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section. (14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir. (15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. (16) Oil and gas producing activities. (i) Oil and gas producing activities include: (A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations; (B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; (C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: (1) Lifting the oil and gas to the surface; and (2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

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DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 3 of 6 (D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as: a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered. (ii) Oil and gas producing activities do not include: (A) Transporting, refining, or marketing oil and gas; (B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; (C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or (D) Production of geothermal steam. (17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. (18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

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DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 4 of 6 (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. (19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence. (20) Production costs. (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: (A) Costs of labor to operate the wells and related equipment and facilities. (B) Repairs and maintenance. (C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. (D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. (E) Severance taxes. (ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. (21) Proved area. The part of a property to which proved reserves have been specifically attributed. (22) 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 (LKH) 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 (HKO) 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 favorable than in the reservoir as a whole, the operation of an installed program 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 program was based; and

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DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 5 of 6 (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. (23) Proved properties. Properties with proved reserves. (24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. (25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. (26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas: 932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year: a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. 932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B: a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves. d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

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DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) Definitions - Page 6 of 6 e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. (27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. (28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations. (29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion. (30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area. (31) 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. From the SEC's Compliance and Disclosure Interpretations (October 26, 2009): Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule. Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:  The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);  The company's historical record at completing development of comparable long-term projects;  The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;  The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and  The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority). (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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. (32) Unproved properties. Properties with no proved reserves.

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SUMMARY OF NET RESERVES BPX PRODUCTION COMPANY INTEREST AS OF DECEMBER 31, 2025 Oil NGL (1)Gas(1) Oil Equivalent (MBBL) (MBBL) (MMCF) (MBOE) 9573-East Texas Gas Proved Developed Producing 254.3 0.1 169,481.3 29,475.4 Proved Undeveloped 0.0 0.0 67,230.9 11,591.5 Total Proved 254.3 0.1 236,712.1 41,066.9 9659-Hawkville Proved Developed Producing 631.0 11,169.5 470,247.0 92,877.6 Proved Undeveloped 367.6 8,612.2 249,237.8 51,951.9 Total Proved 998.6 19,781.8 719,484.7 144,829.5 Haynesville Proved Developed Producing 424.4 0.0 894,262.1 154,607.6 Proved Undeveloped 0.0 0.0 2,044,962.7 352,579.7 Total Proved 424.4 0.0 2,939,224.8 507,187.3 North_EF Proved Developed Producing 46,588.4 24,357.3 170,766.3 100,388.1 Proved Undeveloped 53,465.6 31,343.4 227,758.3 124,077.8 Total Proved 100,053.9 55,700.7 398,524.5 224,465.9 Permian Proved Developed Producing 92,009.7 106,821.0 654,708.1 311,711.3 Proved Undeveloped 99,565.9 116,012.0 693,905.4 335,216.5 Total Proved 191,575.6 222,833.0 1,348,613.5 646,927.8 South_EF Proved Developed Producing 11,570.0 36,865.8 408,987.1 118,950.8 Proved Undeveloped 16,776.1 47,001.8 507,069.2 151,203.6 Total Proved 28,346.1 83,867.6 916,056.3 270,154.4 All Properties Proved Developed Producing 151,477.6 179,213.8 2,768,451.8 808,010.8 Proved Undeveloped 170,175.2 202,969.4 3,790,164.2 1,026,621.0 Total Proved 321,652.8 382,183.2 6,558,616.0 1,834,631.8 Note: (1) Gas reserves are inclusive of fuel gas volumes expected to be consumed in field operations. Net Reserves DRM Field/Reserves Category Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves included herein have not been adjusted for risk. Totals may not add because of rounding. All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.

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## Exhibit 15.5

**Exhibit 15.5**

**Consent of Independent Registered Public Accounting Firm** 

We consent to the incorporation by reference of our reports dated 6 March 2026 relating to the consolidated financial statements of BP p.l.c. (the "Company") and the effectiveness of the Company's internal control over financial reporting, appearing in this Annual Report on Form 20-F of the Company for the year ended 31 December 2025, in the following Registration Statements:

Registration Statements on Form F-3 (File Nos. 333-277842, 333-277842-01 and 333-277842-02) of the Company, BP Capital Markets p.l.c., and BP Capital Markets America Inc., and the Registration Statements on Form S-8 (File Nos. 333-67206, 333-79399, 333-102583, 333-103923, 333-103924, 333-119934, 333-123482, 333-123483, 333-131583, 333-131584, 333-132619, 333-146868, 333-146870, 333-146873, 333-149778, 333-173136, 333-177423, 333-179406, 333-186462, 333-186463, 333-199015, 333-200794, 333-200795, 333-200796, 333-207188, 333-207189, 333-210316, 333-210318, 333-253287, 333-254578, 333-270440, 333-273587 and 333-280100) of the Company.

/s/ Deloitte LLP

London, United Kingdom

6 March 2026

## Ex-17

**Exhibit 17** 

**List of Subsidiary Issuers of Guaranteed Securities** 

Each of the following subsidiaries of BP p.l.c. (the "Guarantor") is issuer of the following outstanding securities, which are fully and unconditionally guaranteed by the Guarantor:

<u>BP Capital Markets America Inc</u> 

3.017% Guaranteed Notes due 2027

3.543% Guaranteed Notes due 2027

3.588% Guaranteed Notes due 2027

5.017% Guaranteed Notes due 2027

3.937% Guaranteed Notes due 2028

4.234% Guaranteed Notes due 2028

4.699% Guaranteed Notes due 2029

4.868% Guaranteed Notes due 2029

4.970% Guaranteed Notes due 2029

1.749% Guaranteed Notes due 2030

3.633% Guaranteed Notes due 2030

2.721% Guaranteed Notes due 2032

4.812% Guaranteed Notes due 2033

4.893% Guaranteed Notes due 2033

4.989% Guaranteed Notes due 2034

5.227% Guaranteed Notes due 2034

3.060% Guaranteed Notes due 2041

2.772% Guaranteed Notes due 2050

3.000% Guaranteed Notes due 2050

3.067% Guaranteed Notes due 2050

2.939% Guaranteed Notes due 2051

3.001% Guaranteed Notes due 2052

3.379% Guaranteed Notes due 2061

<u>BP Capital Markets p.l.c.</u> 

3.279% Guaranteed Notes due 2027

3.588% Guaranteed Notes due 2027

3.723% Guaranteed Notes due 2028

4.875% Perpetual Subordinated Non-Call 10 Fixed Rate Reset Notes

6.125% Perpetual Subordinated Fixed Rate Reset Notes

6.450% Perpetual Subordinated Fixed Rate Reset Notes

## Ex-97

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;BP p.l.c. Malus and Clawback Policy 1. Introduction 1.1 BP p.l.c. (the Company) has adopted this policy (the Policy) to provide for the adjustment, recovery or "clawback" of variable compensation awards (including, but not limited to, annual bonus, deferred share awards and performance share awards) (awards) from certain executive directors and leadership team members as further set forth herein. The Remuneration Committee of the Company's Board of Directors (the Remuneration Committee) is empowered to reduce, cancel, or impose additional conditions on unpaid or unvested awards (malus) and/or recover any paid or vested awards (clawback) under the Company's incentive plans. 1.2 The Policy has two parts: • Part A of the Policy (the Discretionary Policy) aims to maintain the integrity of the Company's incentive plans in the eyes of participants and shareholders; ensure fairness to individuals (both in terms of procedure for determining malus and clawback and outcomes); drive consistency of decision making; ensure that decisions can be robustly defended from challenge; and maintain the Company's ability to attract and retain the highest calibre staff. It has been developed in relation to the exercise of malus and clawback to drive consistency and fairness of application. • Part B of the Policy (the Mandatory Policy) is adopted pursuant to the requirements of Section 303A.14 of the New York Stock Exchange (NYSE) Listed Company Manual. 1.3 The Policy will be administered independently by the Remuneration Committee, whose determinations will be final, binding and conclusive. If the Remuneration Committee determines clawback is mandatory under the Mandatory Policy, the Committee may nevertheless in its discretion impose further penalties under the Discretionary Policy, but may not exercise any discretion to reduce the amount of mandatory clawback under the Mandatory Policy. \*\*\*

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-2- Part B Mandatory Clawback Policy 1. Statement of Policy 1.1 The Company shall recover reasonably promptly the amount of erroneously awarded Incentive-Based Compensation (as defined below) in the event that the Company is required to prepare an accounting restatement due to the material noncompliance of the Company with any financial reporting requirement under applicable securities laws, including any required accounting restatement to correct an error in previously issued financial statements that is material to the previously issued financial statements, or that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period (a Restatement). 1.2 The Company shall recover erroneously awarded Incentive-Based Compensation in compliance with this Mandatory Policy except to the extent provided under the section entitled "4. Exceptions" herein. 2. Scope of Policy 2.1 Covered Persons and Recovery Period. This Mandatory Policy applies to all Incentive-Based Compensation received by a person: • after beginning service as an Executive Officer, • who served as an Executive Officer at any time during the performance period for that Incentive-Based Compensation, • while the Company has a class of securities listed on NYSE, and • during the three completed fiscal years immediately preceding the date that the Company is required to prepare a Restatement (the Recovery Period). Notwithstanding this look-back requirement, the Company is only required to apply this Mandatory Policy to Incentive-Based Compensation received on or after 2 October 2023. For purposes of this Mandatory Policy, Incentive-Based Compensation shall be deemed "received" in the Company's fiscal period during which the Financial Reporting Measure(s) (as defined herein) specified in the Incentive- Based Compensation award is attained, even if the payment or grant of the Incentive-Based Compensation occurs after the end of that period.

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-3- 2.2 Transition Period. In addition to the Recovery Period, this Mandatory Policy applies to any transition period (that results from a change in the Company's fiscal year) within or immediately following the Recovery Period (a Transition Period), provided that a Transition Period between the last day of the Company's previous fiscal year end and the first day of the Company's new fiscal year that comprises a period of nine to 12 months will be deemed a completed fiscal year. For clarity, the Company's obligation to recover erroneously awarded Incentive-Based Compensation under this Mandatory Policy is not dependent on if or when a Restatement is filed. 2.3 Determining Recovery Period. For purposes of determining the relevant Recovery Period, the date that the Company is required to prepare the Restatement is the earlier to occur of: • the date the board of directors of the Company (the Board), a committee of the Board, or the officer or officers of the Company authorized to take such action if Board action is not required, concludes, or reasonably should have concluded, that the Company is required to prepare a Restatement, and • the date a court, regulator, or other legally authorized body directs the Company to prepare a Restatement. 3. Amount Subject To Recovery 3.1 Recoverable Amount. The amount of Incentive-Based Compensation subject to recovery under this Mandatory Policy is the amount of Incentive-Based Compensation received that exceeds the amount of Incentive-Based Compensation that otherwise would have been received had it been determined based on the restated amounts, computed without regard to any taxes paid. 3.2 Covered Compensation Based on the Company's Common Share Price or TSR. For Incentive-Based Compensation based on the price of the Company's common shares or total shareholder return (TSR), where the amount of erroneously awarded Incentive-Based Compensation is not subject to mathematical recalculation directly from the information in a Restatement, the recoverable amount shall be based on a reasonable estimate of the effect of the Restatement on the share price or TSR upon which the Incentive-Based Compensation was received. In such event, the Company shall maintain documentation of the determination of that reasonable estimate and provide such documentation to the NYSE. 4. Exceptions

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-4- 4.1 The Company shall recover erroneously awarded Incentive-Based Compensation in compliance with this Mandatory Policy except to the extent that the conditions set out below are met and the Committee has made a determination that recovery would be impracticable: 4.2 Direct Expense Exceeds Recoverable Amount. The direct expense paid to a third party to assist in enforcing this Mandatory Policy would exceed the amount to be recovered; provided, however, that before concluding it would be impracticable to recover any amount of erroneously awarded Incentive- Based Compensation based on the anticipated expense of enforcement, the Company shall make a reasonable attempt to recover such erroneously awarded Incentive-Based Compensation, document such reasonable attempt(s) to recover, and provide that documentation to the NYSE. 4.3 Violation of Home Country Law. Recovery would violate applicable English law where that law was adopted prior to November 28, 2022; provided, however, that before concluding it would be impracticable to recover any amount of erroneously awarded Incentive-Based Compensation based on violation of English law, the Company shall obtain an opinion of English counsel, acceptable to the NYSE, that recovery would result in such a violation, and shall provide such opinion to NYSE. 4.4 Recovery from Certain Tax-Qualified Retirement Plans. Recovery would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to employees of the Company, to fail to meet the requirements of 26 U.S.C. 401(a)(13) or 26 U.S.C. 411(a) and regulations thereunder. 5. Prohibition Against Indemnification 5.1 The Company shall not indemnify any Executive Officer or former Executive Officer against the loss of erroneously awarded Incentive-Based Compensation. 6. Disclosure 6.1 The Company shall file all disclosures with respect to recoveries under this Mandatory Policy in accordance with the requirements of all the U.S. federal securities laws, including the disclosure required to be included in applicable Securities and Exchange Commission (SEC) filings. 7. Definitions 7.1 Unless the context otherwise requires, the following definitions apply for purposes of this Mandatory Policy:

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-5- 7.2 Executive Officer means the Company's president, principal financial officer, principal accounting officer (which may be the same individual as principal financial officer, but if there is no such accounting officer, the controller), any vice-president of the Company in charge of a principal business unit, division, or function (such as sales, administration, or finance), any other officer who performs a policy-making function, or any other person who performs similar policymaking functions for the Company. Executive officers of the Company's subsidiaries are deemed Executive Officers of the Company if they perform such policy making functions for the Company. Policy-making function is not intended to include policymaking functions that are not significant. Identification of an Executive Officer for purposes of this Mandatory Policy will include at a minimum executive officers identified pursuant to 17 CFR 229.401(b). The Executive Officers shall comprise the "senior management" identified as such in the Company's annual report on Form 20-F. 7.3 Financial Reporting Measures means any of the following: (i) measures that are determined and presented in accordance with the accounting principles used in preparing the Company's financial statements, and any measures that are derived wholly or in part from such measures, (ii) stock price and (iii) TSR. A Financial Reporting Measure need not be presented within the Company's financial statements or included in a filing with the SEC. 7.4 Incentive-Based Compensation means any compensation that is granted, earned, or vested based wholly or in part upon the attainment of a Financial Reporting Measure. 8. Amendment; Termination. 8.1 The Committee may amend this Mandatory Policy from time to time and may terminate this Mandatory Policy at any time, in each case in its sole discretion. 9. Effectiveness; Other Recoupment Rights 9.1 This Mandatory Policy shall be effective as of 1 December 2023. Any right of recoupment under this Mandatory Policy is in addition to, and not in lieu of, any other remedies or rights of recoupment that may be available to the Company and its subsidiaries and affiliates under applicable law or pursuant to the terms of any similar policy or similar provision in any employment agreement, equity award agreement or similar agreement.

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