Annual report

2025

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Intro

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Corp. governance

Appendix

02

Aker BP annual report 2025

Contents

Letter from the CEO

FIT FOR THE FUTURE

A decade of shaping a culture built on improvement and growth has positioned Aker BP for increased value creation.

In 2025, we demonstrated that we are not only delivering strong results today, we are building momentum for tomorrow. Industry leading efficiency lifted production to the top end of our guided range, while we maintained low production costs and kept greenhouse gas emissions intensity from production among the lowest in the industry. Despite an exceptionally busy year, our develop- ment projects remained firmly on schedule. We also strengthened our resource base significantly, with three major discoveries adding around 100 million barrels net to Aker BP.

I am proud to lead a team whose competence, dedication and ambition consistently deliver high performance across multiple fronts, reinforcing Aker BP’s position as a leading operator on the Norwegian continental shelf (NCS).

The world around us

The state of international relations continues to have a decisive impact on global security, trade and energy markets. In this environment, my

foremost priorities are safeguarding our people and ensuring the security of our operations.

The oil and gas market is once again at the centre of the world’s attention as extreme volatility unfolds. After many years in this industry, I am well acquainted with large price swings. For me, the objective has always been clear: to build a company that does not soar with temporary price spikes, nor falter when markets turn. It is my belief that long-term success is built on resilience, the ability to perform consistently through cycles.

The robustness of Aker BP today allows us to steadily pursue our strategic path forward.

Volatility is not limited to prices. Forecasts for the future role of oil and gas in the global energy mix also fluctuate. While renewable energy is growing rapidly, global energy demand continues to rise. More than a transition, we are witnessing an addition. I see no credible near-term scenario in which demand for oil and gas declines substan- tially and sustainably.

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04

Aker BP annual report 2025

Intro

At the same time, awareness of the importance of energy security has been significantly reinforced in recent years. Energy security is an integral part of national and regional security. Norway’s increas- ingly important role as a stable and reliable energy supplier underpins my expectation of continued demand for Norwegian oil and gas and provides a solid foundation for Aker BP’s growth ambitions.

A decade of progress

As Aker BP marks its 10th anniversary in 2026, it is worth briefly reflecting on the remarkable period of growth.

First, we have demonstrated our ability to create value through mergers and acquisitions, including the integration of BP’s Norway business in 2016 and Lundin Norway in 2022.

Second, from our first development project at Ivar Aasen, brought on stream on Christmas Eve 2016, we have evolved into an operator capable of executing one of the largest project portfolios in the industry.

Third, we have a proven track record of maxim- ising value around existing hubs. Today’s producing fields are turned into tomorrow’s opportunities through infrastructure led exploration, lifetime extensions and strategic redevelopments.

I am convinced that these capabilities will continue to generate significant value across our portfolio in the decade ahead.

An army of problem solvers

The Norwegian continental shelf is a mature basin, and future discoveries are becoming smaller and more complex. Yet I see substantial remaining potential.

Turning marginal volumes and challenging reservoirs into profitable production is precisely what energises the Aker BP organisation, described by an external analyst as “an army of problem solvers”.

Over time, we have built a relentless improve- ment culture that enables us to unlock demanding resources.

Small subsea tiebacks are one example. This devel- opment concept will become increasingly impor- tant in the years ahead. By taking operatorship of Kjøttkake, a discovery made in 2025, we are applying fast track development methods to make smaller subsea tiebacks profitable. Our ambition is to reduce time from discovery to production to as little as three years, driven by productivity gains, supply chain integration and close collaboration with authorities, partners and alliances.

We apply the same mindset to so-called stranded assets, prospects previously deemed unprofitable or too complicated. The Omega Alfa discovery in 2025 was achieved through innovative exploration methods, unprecedented reservoir data acquisition and record breaking horizontal drilling. It emerged as one of Norway’s most significant finds in recent years, adding substantial new resources to Yggdrasil, Norway’s largest field development project. The achievement even reached the front page of The New York Times.

2025 numbers at a glance

Figures in parentheses refer to 2024

Safety:

Total recordable injury frequency (TRIF) was 2.0 (1.8)

Serious incident frequency (SIF) was 0.3 (0.4)

Financials:

Total income was USD 10.9 (12.4) billion

EBITDA for the year was USD 9.4 (11.1) billion

Production:

Output averaged 420 (439) mboepd

Production efficiency across all fields at 95 (94) percent

Cost efficiency:

Production cost remained low at USD 7.3 (6.2) per barrel

Emissions:

2.8 (2.6) kg CO 2 equivalents per barrel of oil equivalent produced (scope 1 and 2, equity share)

We remain an industry leader in terms of GHG emission intensity from production

The Aker BP stock (measured in USD):

Dividend increased five percent in 2025, set for another increase of five percent in 2026

Total shareholder return of 46 percent in 2025

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05

Aker BP annual report 2025

Intro

Our growing expertise in the most challenging conditions continues to shape our future portfolio. Fenris, a field development project in the Valhall area, represents the extreme end of high-pressure, high-temperature reservoirs. That is precisely why we pursued it. Through competence, collaboration and new technology, we delivered the wells safely and successfully. Next in line is Victoria, one of the largest undeveloped gas discoveries on the Norwegian continental shelf. Long considered too complex, this tight, high-pressure, high-temperature reservoir is now being matured with new compe- tence and experience.

Radically improved efficiency

I believe that future success in our industry will be defined by the ability to radically improve efficiency. At Aker BP, this is powered by a fundamental reshaping of how we operate. We are not discussing how to change; we are changing now.

A decade of investment in industrial data has given Aker BP what artificial intelligence needs most: structured, high quality, accessible data. We are now moving beyond digitalisation, with the ambition to embed artificial intelligence at the core of nearly every process in the company.

Future oil and gas fields will look and operate very differently from today. Yggdrasil exemplifies this shift, designed for low manning and periods of unmanned operation, supported by increased remote control and highly automated processes.

Aker BP cannot improve in isolation. To scale improvement, the entire value chain must evolve. We are therefore deepening integration with our alliance partners to create a unified ecosystem. This goes beyond collaboration; it is a true partnership.

The exploration and production company of the future

Competition on the Norwegian continental shelf is intensifying as all major players pursue growth. We have a clear strategy to attain and sustain production above 500,000 barrels per day beyond 2030, with ambitions to grow even further.

Success is not guaranteed for all companies, but Aker BP is in a strong financial position and well prepared for continued, profitable growth. I am confident that we are exceptionally well positioned to thrive in an increasingly complex environment.

Our vision is to be the exploration and production company of the future. As we approach our 10th anniversary, we can look back on achievements that build trust in our ability to deliver even more in the decade ahead.

Most importantly, Aker BP employees embrace the future. A future that will demand greater speed, higher efficiency, stronger competence and entirely new ways of working.

This is precisely what we have prepared for.

We are fit for the future.

We are building the exploration and production company of the future.

Karl Johnny Hersvik

Chief executive officer

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Appendix

06

Aker BP annual report 2025

Intro

Board of directors

(2/5)

Aker BP shares * :

None

Member of the BoD since:

2016

Independent of major shareholders:

Yes

Independent of the company ** :

Yes

Citizenship:

Norwegian

Residency:

Norway

Born:

1958

Trond Brandsrud

Shareholder-elected member and chair of the audit and risk committee

Experience, skills and education:

Brandsrud serves as a non-executive director and industry advisor. Brandsrud holds a master’s degree in finance from the Norwegian School of Economics (NHH).

From 2016 to 2019, he held several CEO and CFO roles in the financial services companies Lindorff, Intrum and Lowell. From 2010 to 2015, he served as the group CFO of Aker. In the period from 2007 to 2010, he served as the CFO of the Seadrill Group. Prior to these roles, Brandsrud had 23 years of experience from leading finance positions at Shell.

Key external appointments:

Brandsrud is a non-executive director and chair of the board of TGS ASA and Lowell Finans AS. He is also a board member of Lowell Group (Simon Midco Ltd.), Waterise BV and Aker Horizons ASA.

Aker BP shares * :

None

Member of the BoD since:

2016

Independent of major shareholders:

No

Independent of the company ** :

No

Citizenship:

British

Residency:

UK

Born:

1968

Kate Thomson

Shareholder-elected member and member of the audit and risk committee

Experience, skills and education:

Thomson is the CFO of BP p.l.c. Prior to joining BP p.l.c., Thomson qualified as a chartered accountant with Deloitte. She moved into international tax with Charter plc, where she became head of tax in 1998, before joining Ernst & Young in 2001 in M&A tax.

Key external appointments:

Thomson is a director of several BP p.l.c. Group companies and a member of the Institute of Chartered Accountants in England and Wales.

Aker BP shares * :

852,587

Member of the BoD since:

2022

Independent of major shareholders:

No

Independent of the company ** :

Yes

Citizenship:

British

Residency:

UK

Born:

1962

Charles Ashley Heppenstall

Shareholder-elected member

Experience, skills and education:

Heppenstall is the former president and CEO of Lundin Petroleum AB (2002–2015). He is a graduate of Durham University, where he obtained a Bachelor of Science in mathematics.

From 1984 until 1990, Heppenstall worked in the banking sector, where he was involved in project financing of oil and mining businesses. He has worked with public companies associated with the Lundin family since 1993.

Key external appointments:

Heppenstall is a board member of Lundin Mining and Lundin Gold, and the chair of the board in International Petroleum Corporation.

* Number of shares in Aker BP ASA as of 31 December 2025, including shares held by each member's close associates, as defined in the Norwegian Accounting Act.

** Based on guidance in the Norwegian Code of Practice for Corporate Governance

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Appendix

09

Aker BP annual report 2025

Intro

Board of directors

(3/5)

Aker BP shares * :

None

Member of the BoD since:

2022

Independent of major shareholders:

Yes

Independent of the company ** :

Yes

Citizenship:

Norwegian

Residency:

Norway

Born:

1960

Valborg Lundegaard

Shareholder-elected member and member of the audit and risk committee

Experience, skills and education:

Lundegaard has more than 30 years of experience in the energy industry, including serving as CEO of Aker Carbon Capture ASA, a pure play carbon capture company. After establishing a joint venture with SLB, she continued her involvement with the company as a board member.

Lundegaard began her career in Statoil (now Equinor). Her earlier career includes senior executive positions (EVP) at Aker Solutions, where she served as EVP for customer management (2016–2020) and EVP engineering (2011–2016). Lundegaard brings extensive international experience across board service, executive and project management, IPO, business development and sustainability. She holds a master’s degree in chemical engineering from the Norwegian University of Science and Technology (NTNU).

Key external appointments:

None

Aker BP shares * :

None

Member of the BoD since:

2024

Independent of major shareholders:

No

Independent of the company ** :

No

Citizenship:

Austrian and American

Residency:

UK

Born:

1970

Doris Reiter

Shareholder-elected member

Experience, skills and education:

Reiter is BP p.l.c.’s SVP UK North Sea. She is responsible for the company’s oil and gas portfolio on the UK continental shelf.

Reiter is a reservoir engineer by background and holds a PhD in petroleum engineering from Texas A&M University. She joined BP p.l.c. in 1998, and her career has taken her across the globe, from the Gulf of Mexico to Angola, working in multiple engineering and technical leadership roles.

Key external appointments:

Reiter is a director of several BP p.l.c. Group companies and chair of the Offshore Energies UK board.

Aker BP shares * :

706

Member of the BoD since:

2023

Independent of major shareholders:

Yes

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1971

Marit Hargemark

Employee-elected member and member of the organisational development and compensation committee

Experience, skills and education:

Hargemark serves as a full-time employee representative, while she previously worked as senior geologist. For more than ten years, the Johan Sverdrup field has been her primary focus. She has been following the field closely and has previously represented the company in the Johan Sverdrup licence partnership.

Hargemark holds a Master of Science in applied geophysics and has over 25 years of experience in the oil industry, both from oil compa- nies and software companies. Her technical experience ranges from seismic processing to reservoir modelling. She currently holds several leadership roles and responsibilities as union representative at Aker BP.

Key external appointments:

None

* Number of shares in Aker BP ASA as of 31 December 2025, including shares held by each member's close associates, as defined in the Norwegian Accounting Act.

** Based on guidance in the Norwegian Code of Practice for Corporate Governance

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Corp. governance

Appendix

10

Aker BP annual report 2025

Intro

Board of directors

(4/5)

Aker BP shares * :

2,172

Member of the BoD since:

2018

Independent of major shareholders:

Yes

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1962

Ingard Haugeberg

Employee-elected member

Experience, skills and education:

Haugeberg serves as a full-time employee representative. He is trained as an electromechanical repair technician at the Royal Norwegian Air Force Technical School at Kjevik, and holds a compa- ny-approved bachelor's degree in mechanics.

Prior to his current position, Haugeberg served as the HSSE site lead for the Ula field. Haugeberg has experience from the Royal Norwegian Air Force in Bodø, where he worked as a technical grenadier and later as department manager for Safelift A/S. He began his career in Amoco Norge as a mechanic on the Valhall field in 1991 and has held various positions in BP p.l.c. Norge since 1998.

Haugeberg has also held several directorships in BP p.l.c. Norge, Industrimaskiner A/S, Global Clean Energy, I/E Media and trippEl A/S.

Key external appointments:

None

Aker BP shares * :

2,404

Member of the BoD since:

2025

Independent of major shareholders:

Yes

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1985

Zeala Fortescue

Employee-elected member

Experience, skills and education:

Fortescue joined Aker BP in 2017 and works as a data analyst within exploration and reservoir development. She has held leadership responsibilities in the project department, as well as roles within analysis, digitalisation and artificial intelligence across business units. She has worked in the oil and gas industry since 2012, both in operator companies and in the rig sector, and has several years of experience with NATO.

Fortescue holds a master’s degree in economics from Radboud University in the Netherlands.

Key external appointments:

None

Aker BP shares * :

8,284

Member of the BoD since:

2021

Independent of major shareholders:

Yes

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1970

Tore Vik

Employee-elected member

Experience, skills and education:

Vik has been part of Aker BP since 2013, serving as a full-time employee representative. He holds a certification as an electrician from Bergen Maritime School. Prior to his current position, he worked as an electrician on the Ivar Aasen platform. With over 30 years of experience, Vik has expertise in both high-voltage and low-voltage systems. His professional background includes roles as an electrician and automation specialist on drilling rigs and vessels.

Key external appointments:

Vik is a member of the nomination committee at Kongsberg Automotive.

* Number of shares in Aker BP ASA as of 31 December 2025, including shares held by each member's close associates, as defined in the Norwegian Accounting Act.

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11

Aker BP annual report 2025

Intro

Board of directors

(5/5)

Aker BP shares * :

4,531

Member of the BoD since:

2025

Independent of major shareholders:

Yes

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1988

Stine Bjørnvold Bakken

Employee-elected member

Experience, skills and education:

Bakken joined Aker BP in 2018 and works as a lifecycle data service manager within operations. She has held leadership roles both offshore and onshore within operations, logistics and digitalisation, and has prior experience as a strategy consultant.

Bakken holds a Master of Science in industrial economics and technology management from the Norwegian University of Science and Technology (NTNU).

Key external appointments:

None

* Number of shares in Aker BP ASA as of 31 December 2025, including shares held by each member's close associates, as defined in the Norwegian Accounting Act.

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Aker BP annual report 2025

Intro

Executive management team

(2/6)

Aker BP shares * :

2,893

Family relations BoD/EMT:

No

Citizenship:

Irish

Residency:

Norway

Born:

1979

Paula Doyle

Chief digital officer

Employment, experience, skills and education:

Doyle has been the chief digital officer of Aker BP since joining the company in 2022. She came from the position of SVP sales and marketing at Cognite, where she was also part of the executive management team.

She has held a variety of roles within the oil and gas industry for companies such as ABB and Siemens in Norway and the Middle East. During her time in the Middle East, Doyle established and ran a non-profit industrial technology organisation.

Doyle has deep knowledge of industrial software space and digitalisation processes in heavy-asset industries, and holds a PhD in computer engineering from the University of Limerick.

Key external appointments:

None

Aker BP shares * :

8,657

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1962

Knut Sandvik

SVP projects execute

Employment, experience, skills and education:

Sandvik has been the SVP projects execute at Aker BP since 2019. He has more than 35 years’ experience in the oil and gas industry. Throughout his career, Sandvik has held various senior project and leadership positions across Aker companies, including four years as a member of the executive management teams.

Sandvik holds a degree in mechanical offshore engineering from Heriot-Watt University in Scotland.

Key external appointments:

None

Aker BP shares * :

6,447

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1972

Thomas D. Hoff-Hansen

Chief information officer

Employment, experience, skills and education:

Hoff-Hansen has been serving as chief information officer since 2024. Prior to this, he served as SVP Ula. Hoff-Hansen has worked for the company since 2009 and has broad experience from various technical roles, as well as management roles both offshore and onshore.

Before Hoff-Hansen started at Aker BP, he worked with automation and instrumentation at ExxonMobil.

Hoff-Hansen holds a Master of Science degree in cybernetics from the University of Stavanger.

Key external appointments:

None

* Number of shares in Aker BP ASA as of 31 December 2025, including shares held by each member's close associates, as defined in the Norwegian Accounting Act.

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Corp. governance

Appendix

14

Aker BP annual report 2025

Intro

Executive management team

(3/6)

Aker BP shares * :

2,381

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1970

Tommy Sigmundstad

SVP drilling and wells

Employment, experience, skills and education:

Sigmundstad has been the SVP drilling and wells at Aker BP since 2016. Prior to this, he was VP wells at BP Asia Pacific.

Sigmundstad has broad experience within the oil and gas industry from companies such as Baker Hughes and Philips, before joining BP in 2000. Within BP, Sigmundstad has held various operational, engineering and management positions in Norway, the United Kingdom, Azerbaijan and Indonesia.

Sigmundstad holds a master’s degree in petroleum engineering from the University of Stavanger.

Key external appointments:

Sigmundstad is a member of the board of directors at Fishbones.

Aker BP shares * :

None

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1968

Petter Sørhaug

SVP exploration and reservoir development

Employment, experience, skills and education:

Sørhaug was appointed SVP exploration and reservoir development in June 2025. He previously served as VP Yggdrasil subsurface and has held key leadership roles at Aker BP within subsurface analysis, reservoir excellence and geology.

With over 25 years of experience in Norway’s oil and gas sector, Sørhaug combines deep technical expertise with strong leadership and international field experience. He began his career at Statoil (now Equinor) and Hydro Oil & Energy.

Sørhaug holds a cand.scient. degree in structural geology from the University of Tromsø.

Key external appointments:

None

Aker BP shares * :

4,299

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1976

Marte Mogstad

SVP projects growth

Employment, experience, skills and education:

Mogstad assumed the role of SVP projects growth in May 2025 after serving as SVP Skarv since 2024. She joined the company from her position as executive vice president at Aker Solutions.

Mogstad brings over 20 years of experience from the oil and gas and renewable energy sectors. Throughout her career, Mogstad has held several leadership positions in operational management and business development, including three years as a member of the executive management team at Aker Solutions, responsible for engineering and, most recently, new energies.

Mogstad holds a master’s degree in mechanical engineering from the Norwegian University of Science and Technology (NTNU).

Key external appointments:

Mogstad is a member of the board of directors at Coremarine.

* Number of shares in Aker BP ASA as of 31 December 2025, including shares held by each member's close associates, as defined in the Norwegian Accounting Act.

BoD report

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Corp. governance

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15

Aker BP annual report 2025

Intro

Executive management team

(4/6)

Aker BP shares * :

5,746

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1968

Georg Vidnes

SVP Eiga

Employment, experience, skills and education:

Vidnes has been the SVP Eiga since 2024, after leading operations since 2020. He joined the company in 2019, where his first role was project manager for establishing the company’s operating model.

Vidnes has more than 25 years of experience from operator companies such as Statoil (now Equinor), Talisman and Repsol Sinopec, with an emphasis on drilling and wells, asset management, operations and major change projects. He has held positions as offshore installation manager (OIM), VP production, area director, and has led major organisational transition projects.

Vidnes holds a master’s degree in mechanical engineering from the Norwegian University of Science and Technology (NTNU).

Key external appointments:

None

Aker BP shares * :

3,489

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1978

Thomas Øvretveit

SVP operations

Employment, experience, skills and education:

Øvretveit has been the SVP operations since 2024, after serving as SVP Skarv since 2022.

Øvretveit has more than 25 years of experience from various positions at Statoil (now Equinor), including head of the process plant at Mongstad refinery, production manager on Troll and Oseberg, improvements manager, offshore installation manager (OIM), superintendent and O&M manager, as well as process engineer and process technician. He started out as an apprentice at Mongstad in 1996.

Øvretveit is a process engineer and skilled worker and has completed military officer training.

Key external appointments:

None

Aker BP shares * :

12,391

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1975

Marit Blaasmo

SVP people and safety

Employment, experience, skills and education:

Blaasmo has been the SVP people and safety since 2022. She previously served as SVP HSSEQ from 2019, and before that was responsible for the drilling and wells performance and improvement agenda. Blaasmo has been with the company since 2017.

She brings more than 18 years of experience from Statoil (now Equinor) and Baker Hughes INTEQ and has held multiple operational and management positions within drilling and wells disciplines.

Blaasmo holds a master’s degree in petroleum engineering from the Norwegian University of Science and Technology (NTNU).

Key external appointments:

None

* Number of shares in Aker BP ASA as of 31 December 2025, including shares held by each member's close associates, as defined in the Norwegian Accounting Act.

BoD report

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Corp. governance

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Aker BP annual report 2025

Intro

Executive management team

(5/6)

Aker BP shares * :

26,382

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1972

Ole Johan Molvig

SVP Valhall

Employment, experience, skills and education:

Molvig has been the SVP Valhall since 2020, after previously serving as SVP reservoir. He has worked for the company since 2009, joining Aker BP through Det Norske, where he held the position of VP subsurface.

Molvig has extensive and varied experience in the oil and gas industry, having worked for companies such as ExxonMobil, Statoil (now Equinor) and Marathon Oil.

Molvig holds a master’s degree in mechanical engineering from the Norwegian University of Science and Technology (NTNU).

Key external appointments:

None

Aker BP shares * :

13,785

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1967

Lars Høier

SVP Yggdrasil

Employment, experience, skills and education:

Høier has been the SVP Yggdrasil since 2020. He joined Aker BP in 2019 as VP concept development and technology.

Høier has more than 20 years of experience from Statoil (now Equinor), where he held positions such as SVP R&D and production director for several assets, including the Troll field.

Høier holds a Master of Science degree in physics from the University of Oslo and a PhD in petroleum technology from the Norwegian University of Science and Technology (NTNU).

Key external appointments:

None

Aker BP shares * :

10,095

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1975

Ine Dolve

SVP Alvheim

Employment, experience, skills and education:

Dolve has been the SVP Alvheim since 2022, following her role as SVP operations and asset development. She has worked for the company since 2010 and has been involved in various key projects to develop and improve both company and industry performance.

Before joining Aker BP, she worked in management consulting (PwC) within finance, change management and digitalisation for the oil and gas sector. She also has several years of national and international experience from the armed forces.

Dolve holds a master’s degree in finance and international manage- ment from the Norwegian School of Economics (NHH)/Esade, Barcelona. She is also educated at the Air Force Officer Candidate School and the Norwegian Naval Academy in Bergen.

Key external appointments:

None

* Number of shares in Aker BP ASA as of 31 December 2025, including shares held by each member's close associates, as defined in the Norwegian Accounting Act.

BoD report

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Corp. governance

Appendix

17

Aker BP annual report 2025

Intro

Executive management team

(6/6)

Aker BP shares * :

2,716

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1971

Torbjørg Opedal

SVP Skarv

Employment, experience, skills and education:

Opedal assumed the role of SVP Skarv in May 2025. Before this, she served as VP engineering and she has also served as VP subsea since joining Aker BP in 2021.

Opedal has over 20 years of experience in the oil and gas industry and has held various leadership roles at Statoil (now Equinor), both in Norway and internationally.

She holds an engineering degree from Bergen and Gjøvik University College of Engineering and has completed several continuing education programmes.

Key external appointments:

None

Aker BP shares * :

16,833

Family relations BoD/EMT:

No

Citizenship:

Norwegian

Residency:

Norway

Born:

1986

Talar Arif

SVP Ula

Employment, experience, skills and education:

Arif has been the SVP Ula since 2024. She previously served as HSSEQ manager for field operations, where she held responsibilities for HSSEQ, occupational health and environmental aspects related to Aker BP’s producing assets. She has been with the company since 2015 and brings extensive expertise in risk management, HSSEQ, performance and improvement.

Prior to joining Aker BP, Arif worked with HSSEQ at Shell. She also gained experience in supply chain management, maintenance and data management at BP Norge.

Arif holds a bachelor’s degree in computer engineering and a master’s degree in security and risk management from the University of Stavanger.

Key external appointments:

None

* Number of shares in Aker BP ASA as of 31 December 2025, including shares held by each member's close associates, as defined in the Norwegian Accounting Act.

BoD report

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Aker BP annual report 2025

Intro

Aker BP is a pure-play oil and gas company that has expanded to become the second-largest operator on the Norwegian continental shelf (NCS) through a combination of organic growth and mergers and acquisitions. The company’s vision is to be the exploration and production (E&P) company of the future, characterised by safe and efficient operations, low costs, low emissions and a leading role in the transformation of the industry.

Environmental, social and governance (ESG) issues are of the highest importance to Aker BP’s board of directors (BoD). The BoD recognises its respon- sibility for the safety of people and the environ- ment, devoting appropriate time and resources to comply with all regulations and adhering to the highest standards in the oil and gas industry in the areas of health, safety, security, environment and quality (HSSEQ).

Operations and projects

Aker BP delivered strong operational performance in 2025, marked by high production efficiency, low costs and low emissions. The production for the year ended at 420.1 (439.0) mboepd. All major

field development projects progressed according to plan, achieving key construction, drilling and installation milestones during the year.

Production efficiency averaged 95 (94) percent across the portfolio, supported by consistently strong performance and fewer planned mainte- nance activities compared with the previous year.

The strong operational performance was reflected in low production costs, which ended at USD 7.3 (6.2) per boe, while equity share scope 1 and 2 greenhouse gas (GHG) emission intensity remained low at 2.8 (2.6) kg CO 2 e per boe.

Additional information regarding exploration, development and operations can be found in the business description section below.

Financial priorities

Aker BP’s capital allocation framework is anchored around three priorities to support long-term value creation. The first priority is to preserve financial flexibility through the cycle by main- taining a robust balance sheet and protecting

the company's investment-grade credit profile. The second priority is to fund the investment programme, aimed at delivering profitable growth and maximising long-term value creation. The third priority is to return value to shareholders, primarily through a resilient and growing dividend.

In 2025, Aker BP retained its investment-grade credit ratings from the three leading rating agencies. During the year, the company issued USD 1,000 million of senior notes maturing in 2035 and entered into a new revolving credit facility of USD 3,225 million. Further details on bonds and bank facilities are provided in Note 20, page 169 and Note 22, page 171 to the financial statements. The company’s financial position remained strong, with total available liquidity of USD 5.9 (7.5) billion at year-end and a conservative leverage ratio of 0.63 (0.30).

The BoD remains focused on maximising long- term shareholder value and believes that Aker BP is well positioned for further value-accretive growth on the NCS. Over time, the value created will be distributed to shareholders primarily through dividends and, where appropriate,

supplemented by share buybacks. In 2025, Aker BP paid a total dividend of USD 2.52 per share.

Positioning the company for long-term growth

Aker BP is taking active steps to ensure that the company remains competitive, resilient and well positioned for value creation beyond the start-up of the major field developments currently under execution. In addition to delivering safe, efficient and low-emission operations, the company is advancing a broad set of initiatives to strengthen future performance, including efforts to increase organisational efficiency, enhance operational capabilities and accelerate the use of digital technologies and artificial intelligence across the value chain. These initiatives aim to improve recovery, reduce costs, enable more data-driven decision-making and support new ways of working. Combined with the company’s substantial resource base, strong exploration programme and continued focus on operational excellence, these efforts position Aker BP to sustain and grow its business on the NCS well beyond 2027.

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Johan Sverdrup

The Johan Sverdrup field, operated by Equinor, commenced production in October 2019. Phase 1 comprised four bridge-linked platforms, oil and gas export pipelines, three subsea water-injection templates and 20 pre-drilled wells. Phase 2 included the installation of a second processing platform, upgrades to the riser platform and the addition of five subsea templates.

In 2025, Aker BP's net production from Johan Sverdrup averaged 231.0 (238.6) mboepd, with production efficiency remaining high at 98 (95) percent.

In accordance with the unit agreement, the partners Aker BP and TotalEnergies initiated a redetermination process for the Johan Sverdrup unit in January 2025. The purpose of the process is to review and, where relevant, revise the equity interests of the unit owners based on new subsurface and production data acquired since the unit agreement was established in 2015. The redetermination process is expected to be concluded by the end of June 2026.

Johan Sverdrup Phase 3

Phase 3 of the Johan Sverdrup development comprises the installation of two new subsea templates and eight additional wells. The project was sanctioned in the second quarter of 2025 and is progressing according to plan, with fabrication

activities advancing at multiple sites. Drilling of the Phase 3 wells is expected to commence towards the end of 2026, with production start-up scheduled for the fourth quarter of 2027.

Alvheim area

The Alvheim area comprises the Alvheim, Volund, Vilje, Bøyla, Skogul and Tyrving fields. All fields are operated by Aker BP and produced through the Alvheim FPSO. Oil is exported by shuttle tankers, while produced gas is exported through the Scottish Area Gas Evacuation (SAGE) system.

In 2025, Aker BP's net production from the Alvheim area averaged 61.4 (57.5) mboepd, with production efficiency remaining high at 99 (95) percent.

The Frosk Attic infill well commenced production in the fourth quarter of 2025. Further infill targets and improved oil recovery (IOR) opportunities are being matured in the area.

Commissioning of the Carbon Optimiser project was completed during the year. Carbon Optimiser is an advanced system designed to automatically improve the energy efficiency of gas turbines and reduce GHG emissions.

Valhall area

The Valhall area, operated by Aker BP, comprises the Valhall and Hod fields in the southern

Norwegian North Sea. The infrastructure includes a field centre with three bridge-connected platforms and four unmanned wellhead platforms. Oil is exported via pipeline to Teesside, while gas is exported through the Norpipe system to Emden, Germany.

In 2025, Aker BP's net production from the Valhall area averaged 42.7 (47.4) mboepd, with produc- tion efficiency stable at 85 (85) percent.

The partnership continues to identify upside potential in the area.

Valhall PWP-Fenris

The Valhall PWP-Fenris project progressed according to plan during 2025, with fabrication and construction activities advancing at multiple sites. Modification work continued at the existing Valhall facilities, while key offshore campaigns at the Fenris field, including trenching and subsea rock installation, were completed. The develop- ment comprises a new production and wellhead platform (PWP) at the Valhall field centre and an unmanned installation at Fenris, tied back to the PWP.

Following a successful four-well drilling campaign at Fenris, planning of an additional well is underway. Drilling operations also progressed at Valhall PWP, where the first two wells were completed and work on the third well continued

through year end. In addition, four further wells have been included in the programme, enabled by available well slots on the new platform.

In total, the expanded drilling programme comprises five additional wells and is expected to increase recoverable volumes by approximately 30-35 million barrels of oil equivalent, bringing total gross recoverable resources to around 270 mmboe. Production start-up is expected in 2027.

The facilities will utilise the power-from-shore system, enabling a low scope 1 and 2 GHG emission intensity.

Skarv area

The Skarv area, located in the northern part of the Norwegian Sea, comprises the Skarv hub and a portfolio of associated fields and develop- ments, including Idun, Tilje, Ærfugl, Gråsel and Idun Tunge. All production is processed through the Skarv FPSO, which is operated by Aker BP. Oil is offloaded to shuttle tankers, while gas is transported to the Kårstø terminal via a pipeline connected to the Åsgard Transport System.

In 2025, net production from the Skarv area averaged 31.8 (33.6) mboepd, with production efficiency remaining high at 98 (89) percent.

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Skarv Satellites Project

The Skarv Satellites Project, which comprises the tie backs of Alve Nord, Idun Nord and Ørn to the Skarv FPSO, progressed well during 2025, with steady execution across drilling, subsea installation and topside modification activities.

Drilling of the Alve Nord and Ørn production wells is planned to continue throughout the first quarter of 2026. Preparations for the upcoming flotel period are also progressing as planned. The flotel is scheduled to arrive at Skarv in the latter part of the first quarter and will provide additional offshore accommodation and support during the intensive hook up and commissioning phase.

Reflecting solid progress across all workstreams, the expected start-up of the Skarv Satellites has been accelerated to the fourth quarter of 2026.

Eiga

The Eiga area is located in the North Sea and comprises the Edvard Grieg and Ivar Aasen hub, including associated developments such as Solveig and Hanz, all operated by Aker BP. At Ivar Aasen, initial processing takes place on the platform, with partially processed fluids transported to the Edvard Grieg platform for final processing and export. The fields are powered by electricity from shore.

In 2025, Aker BP’s net production from Eiga averaged 45.2 (55.9) mboepd. The reduction compared with 2024 primarily reflects natural

decline. Production efficiency remained high at 90 (95) percent.

Utsira High project

The Utsira High project comprises two subsea tie backs: Symra to the Ivar Aasen platform and Solveig Phase 2 to the Edvard Grieg platform.

Solveig Phase 2 commenced production on 30 January 2026, on schedule and within budget.

At Symra, the first two production wells have been completed, keeping the field on track for start-up in the third quarter of 2026. An appraisal well for Symra Phase 2 is planned following the ongoing drilling and completion activities.

Ula area

The Ula area comprises the Ula, Tambar, Tambar East and Oda fields. All fields are produced through the Ula field centre, which is operated by Aker BP. Oil is exported via Ekofisk to Teesside, while produced gas is reinjected into the Ula reservoir to enhance oil recovery.

In 2025, Aker BP’s net production from the Ula area averaged 8.0 (5.9) mboepd. Production efficiency was 77 (69) percent, impacted by planned well maintenance activities during the third quarter.

Production from the Ula area is expected to cease by 2028. The decommissioning project is progressing towards a concept select decision,

while efforts to optimise late life production continue in parallel.

Yggdrasil area

The Yggdrasil area, operated by Aker BP in part- nership with Equinor and Orlen Upstream Norway, is estimated to contain approximately 800 mmboe of recoverable resources. Through continued exploration and reservoir maturation, Aker BP aims to ultimately increase recoverable volumes to more than one billion barrels.

The development comprises a central processing platform (Hugin A), two unmanned platforms (Munin and Hugin B), extensive subsea infrastruc- ture and more than 55 planned wells. All facilities will be powered from shore, enabling a low scope 1 and 2 GHG emission intensity. First production is expected in 2027.

The Yggdrasil development project is advancing as planned, with significant milestones achieved throughout the year. The initial sections of the 255-kilometre subsea power cable were success- fully installed, and the Subsea Alliance prepared for a major offshore installation campaign in 2025, including pipeline laying in the Yggdrasil area. Construction and assembly of topside modules and jackets are on schedule at various locations in Norway and internationally. The Hugin A topside is taking shape at the Stord yard, while assembly of the Munin topside is progressing well in Haugesund. In addition, the Subsea Alliance completed installation of five manifolds, multiple

spool tie-ins and the 7.6-kilometre bundle in the Munin licence.

Two rigs successfully completed top-hole batching campaigns in the Hugin and Munin licences, and drilling of production wells commenced. All major modules from multiple fabrication sites arrived at Stord and were assembled onto the Hugin A topside, with stacking nearing completion. The Hugin B topside has been assembled and is undergoing multi-disciplinary outfitting, while its jacket is nearing completion. The Munin topside continues to advance through multi-disciplinary outfitting and has entered early commissioning activities. Installation and commissioning activities for the power-from-shore project also progressed during the period.

The Yggdrasil area continues to demonstrate strong exploration potential. In the third quarter of 2025, Aker BP made a significant oil discovery through the Omega Alfa exploration campaign, with estimated recoverable volumes of 96-134 mmboe. Together with the oil discovery at East Frigg in 2023, this supports the ambition to ulti- mately recover more than one billion barrels from the Yggdrasil area. Work to mature the Omega Alfa discovery has commenced, and follow-up exploration drilling in the neighbouring Frigg area is planned for 2027.

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Court of Appeal ruling on temporary injunction

The legal proceedings concerning the Ministry of Energy’s approvals of the plans for development and operation (PDOs) for the Breidablikk, Tyrving and Yggdrasil fields continued through the year. In November, the Borgarting Court of Appeal ruled that the Ministry’s 2024 decisions not to reopen the PDO approvals were invalid and ordered the Ministry to reassess the approvals within a defined deadline. However, the Court did not suspend the ongoing field activities, and Aker BP can continue executing the Yggdrasil development as planned.

Since then, both parties have appealed the ruling. The Government’s appeal has been admitted to the Norwegian Supreme Court. Conversely, the environmental organisations’ appeal regarding the injunction has not been admitted, which means that the requirement to halt ongoing activities will not be considered by the Supreme Court.

Exploration activities

Aker BP is among the most active exploration companies on the NCS, participating in approx- imately 10 to 15 exploration wells annually.

The NCS remains a highly attractive basin with substantial potential for new discoveries.

The company's exploration strategy is driven by two primary objectives. The first is to discover commercial resources close to existing infrastruc- ture. These types of discoveries typically offer short lead times, strong economics and enhanced capacity utilisation at host facilities, contributing to lower unit costs. The second objective is to identify resources large enough to support new stand-alone field developments. While the activity level within each category may vary from year to year, Aker BP aims to maintain around 80 percent of its explora- tion efforts within the first category over time.

In 2025, Aker BP participated in a total of 17 exploration and appraisal wells, of which five resulted in discoveries with commercial potential. Several of these were located in areas of existing infrastructure, such as the Omega Alfa campaign in the North Sea, which resulted in one of Norway’s largest oil discoveries in recent years, adding 96-134 mmboe to the Yggdrasil area.

Aker BP also participated in several other discoveries, including Kjøttkake and Lofn and Langemann.

In January 2026, Aker BP was offered interests in 22 new production licences offshore Norway, of which 12 to be operated by Aker BP, through the APA 2025 licensing round.

Research and development

Advanced technology plays an important role in Aker BP’s vision to be the E&P company of the future. To drive innovation and build expertise in next-generation technologies, Aker BP manages a corporate-level research and development (R&D) portfolio, overseen by an R&D council comprising members from various business units.

The company invests in R&D across the entire value chain, maintaining a balanced portfolio that spans knowledge and methodology devel- opment, physical technology advancements and digital/software innovations. In 2025, Aker BP spent approximately USD 42 million on its R&D portfolio.

In 2025, Aker BP continued to advance a broad technology agenda spanning the full value chain, with particular emphasis on seismic imaging and processing, robotics and autonomous systems,

digital subsurface workflows, and next generation drilling and well technologies. The R&D portfolio also reflected a strengthened push towards cost efficient plug and abandon (P&A) and decommis- sioning solutions, alongside major initiatives within carbon management, sensor technology, machine learning and enhanced reservoir understanding. Collectively, these efforts reinforced our long term ambition to apply data driven, automated and low emission technologies across both topside and subsea operations.

Projects sanctioned in 2025 were designed to unlock remaining resources, reduce operating costs and improve production efficiency through digitalisation and automation. Significant attention was directed towards subsea intervention tech- nologies, full waveform seismic imaging, advanced reservoir modelling and autonomous monitoring systems. At the same time, substantial investments were made in future subsea tie-back concepts, downhole processing technologies and autono- mous inspection platforms, positioning Aker BP to deploy next generation field architectures and implement innovative solutions with measurable operational and environmental impact.

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Statement of financial position

Total assets at year-end amounted to USD 44,806 (42,193) million.

Equity amounted to USD 11,226 (12,691) million at the end of 2025, corresponding to an equity ratio of 25 (30) percent. Net interest-bearing debt, including lease debt, was USD 7,094 (4,026) million.

The bond debt increased to USD 8.7 (7.5) billion. In 2025, the company issued one new bond totalling USD 1 billion. At the end of the year, the company had total available liquidity of USD 5.9 (7.5) billion, comprising USD 2.3 (4.1) billion in cash and cash equivalents, USD 0.3 (0.0) billion in financial investments, and USD 3.2 (3.4) billion in undrawn credit facilities. For information about terms on the credit facilities, see Note 20, page 169 in the financial statements. Financial covenants for the company’s debt instruments were comfortably within applicable thresholds.

The company has a robust balance sheet and ample financial flexibility.

Three credit rating agencies, S&P, Fitch, and Moody’s, currently rate Aker BP. All agencies have assigned a BBB/Baa2 credit rating with stable outlook.

Statement of cash flow

Net cash flow from operating activities amounted to USD 6,958 million, an increase from USD 6,423 million in 2024, positively impacted by decreased tax payments of USD 1,702 million and positive working capital movements, partly offset by lower petroleum revenues.

Net cash flow used in investment activities amounted to USD 7,506 (5,315) million. The main item was investments in fixed assets of USD 6,856 (4,774) million.

Net cash outflow used in financing activities was USD 1,353 million, compared to an outflow of USD 284 million in 2024. The main items consisted of the issuance of new bonds amounting to USD 988 (2,288) million and dividend disburse- ments of USD 1,593 (1,517) million.

Accounting standards

The accounting principles used for the 2025 annual financial statements are consistent with the principles used in the 2024 annual financial statements.

The going concern assumption

Pursuant to the Norwegian Accounting Act section 2.2 no.8, the BoD confirms that the requirements of the going concern assumption are met and that the annual accounts have been prepared on that basis. The BoD considers the financial position and the liquidity of the company to be sound. Cash

flow from operations, combined with the total available liquidity, is expected to be more than sufficient to finance the company’s commitments in 2026.

In the BoD’s view, the annual accounts give a true and fair view of the company’s assets and liabilities, financial position and results. The BoD is not aware of any factors that materially affect the assessment of the company’s position as of 31 December 2025, or the result for 2025, other than those presented in the BoD’s report or that otherwise follow from the financial statements.

Events after the reporting period

The company has not identified any event with significant accounting impacts that has occurred between the end of the reporting period and the date of this report that requires accounting recog- nition or disclosure in the financial statements.

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Business continuity risk

Business continuity risk reflects the possibility that Aker BP’s ability to maintain safe and stable operations may be disrupted by unplanned events affecting critical systems, people, infrastructure or supply chains. These events may arise from operational failures, technology outages, cyber incidents, extreme weather, industrial action, contractor insolvency or disruptions in logistics and service delivery. As operational environments and value chains become increasingly intercon- nected, the potential for cascading effects across assets, suppliers and partners has grown.

Ensuring continuity of mission-critical activities (those essential functions that enable the organisation to fulfil its core purpose, where any interruption could halt fundamental operations) and business-critical activities (important for effective delivery and performance, where disrup- tions may significantly reduce efficiency and have material operational or financial impact) is essential not only for maintaining production, but also for safeguarding people, protecting the environment and preserving the company’s licence to operate.

Impact

A disruption to mission- or business-critical activities may result in production losses, delays in project execution, impaired access to essential support services, and increased operational risk. Extended downtime may have financial consequences and affect the robustness of the company’s broader portfolio. In more severe scenarios, business continuity failures may reduce the company’s ability to respond effectively to emergencies, compromise its capacity to manage safety critical operations, and lead to reputational impacts that influence stakeholder confidence.

Mitigation in place

Aker BP maintains a structured and integrated business continuity framework designed to ensure resilience across operations, projects and support functions. Critical processes and systems are mapped and reviewed regularly to identify vulnerabilities, and contingency plans are devel- oped to ensure continuity of essential functions in the event of disruptions. The company conducts exercises and scenario-based testing to verify readiness and strengthen coordination across assets, partners and suppliers. Redundancy in critical systems, robust IT and OT recovery capa- bilities, and clear escalation and communication procedures further reinforce the organisation’s ability to sustain operations during unexpected events. Close collaboration with contractors and service providers helps secure alternative solutions when supply chain disruptions occur. Through these measures, Aker BP aims to maintain operational stability and protect value even under adverse conditions.

Financial risks

Financial risks relate to the company's financial performance and stability, including currency, interest rate and credit risks. Financial risks can have a significant impact on Aker BP's revenue and profitability, and the company must manage its financial exposure effectively.

Insurance risk

Insurance risk relates to the possibility that Aker BP’s insurance programmes may not fully cover losses arising from major incidents. Although the insurance market has improved during 2025, insurance capacity remains restricted, and for

high-value assets this may be a limiting factor in terms of coverage.

Impact

Insufficient or unavailable insurance coverage could leave the company exposed to significant financial loss following an accident, equipment damage, a pollution event or extended busi- ness interruption. Premium levels or capacity constraints in the market may increase operational costs and require a higher degree of self-retention, which in turn could affect liquidity and capital planning.

Mitigation in place

Aker BP maintains a comprehensive insurance portfolio aligned with industry practice and regu- latory requirements. Coverage levels and needs are reviewed regularly to ensure alignment with operational and financial exposures. The company engages proactively with insurers and brokers to secure stable capacity and favourable terms, supported by transparent communication of its strong safety and operational performance. Robust internal risk management practices, including barrier management, emergency preparedness and disciplined project execution, help reduce the like- lihood and severity of incidents. This strengthens the company’s risk profile in the insurance market and supports continued access to appropriate coverage.

Reporting risk

Reporting risk relates to the possibility that Aker BP’s internal or external reporting, particularly financial reporting, may be incomplete, inaccurate or delayed due to errors in underlying data, system limitations or weaknesses in processes and controls. As financial reporting relies on complex information flows across operations, joint ventures

and digital systems, disruptions or inaccuracies may reduce the reliability of financial results and affect transparency towards stakeholders.

Impact

Weaknesses in reporting can lead to misstate- ments in the company’s financial accounts, reduced confidence among investors and regulators, and, in severe cases, the need for restatements. Poor reporting quality may also hinder effective internal decision making and the monitoring of financial performance across the business. The company’s reputation and goodwill could also be adversely affected.

Mitigation in place

Aker BP operates a structured financial reporting framework with clear roles, defined controls and established accounting policies. Integrated financial systems, regular reconciliations and segregation of duties help reduce the risk of errors. Internal reviews, internal audit activities and external audits provide additional assurance. Ongoing competence development within finance and controlling functions ensures that reporting remains accurate, timely and aligned with evolving regulatory requirements.

The company’s audit and risk committee (ARC) is responsible for overseeing internal controls, risk management and the external audit process, and for making recommendations to improve the integrity of reporting. Details on the committee’s work are available in the BoD’s report on corpo- rate governance. The risk related to non-financial reporting is further described in the sustainability statement section 1.3.5 .

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Financial liabilities and financing of the company

Aker BP’s financial position is influenced by its cash position and portfolio of financial liabilities, including bond debt, lease obligations and other interest-bearing commitments. The size and struc- ture of net liabilities reflect the company’s invest- ment activity and long-term funding strategy. Adverse developments in operations, projects or oil and gas prices may require additional capital and could increase the company’s debt levels. The company is subject to financial covenants related to its credit facilities with banks, and failure to comply with these could lead to material adverse consequences.

Access to well-functioning capital markets is essential to secure competitive financing, maintain liquidity and support ongoing and planned field developments. Market conditions, interest rate levels, investor sentiment towards the energy sector and credit ratings may influence both the availability and cost of debt financing. Geopolitical developments, including tariffs, trade tensions and related regulatory measures, may further affect the company’s ability to access capital on favourable terms.

Impact

If available financing becomes constrained and/ or cost of capital increases, the company may face reduced financial flexibility and challenges

in funding planned investments. Higher interest rates, limited access to capital markets or unfavourable refinancing conditions could impact long-term cash flows, investment pace and the company’s ability to execute its strategy. In more severe scenarios, insufficient financing capacity could force reductions or delays in capital expendi- tures, divestments under unfavourable conditions, or the need to seek additional equity or undertake debt restructuring. Such developments could adversely affect the company’s business, financial condition, operational results and ability to fully realise the potential of its investment portfolio.

Mitigation in place

Aker BP maintains a strong balance sheet, diversified funding sources and a well-structured debt portfolio with long-term maturities. Liquidity reserves, such as cash and cash equivalents, committed credit facilities and prudent risk management practices, support resilience under varying market conditions. The company monitors financial markets closely, adjusts its financing strategy when necessary, and maintains an active and transparent dialogue with investors, lenders and rating agencies to safeguard continued access to competitive capital and ensure compliance with financial covenants.

Financial risk described in the financial statements.

The company is exposed to several financial risks as described in the financial statements, including market risk, credit risk and liquidity risk. Note 29, page 176 to the financial statements provides further information about the company’s exposure and risks in relation to commodity price risk, currency risk, interest rate risk, liquidity risk and credit risk. Reference is also made to Note 14, page 165 to the financial statements for sensitivity testing of potential impairment based on future development in commodity prices.

Strategic risks

Strategic risks are risks that either directly impair the company’s ability to realise its strategy or arise as a result of long-term plans and posi- tioning, affecting valuation and performance in the medium- to long-term. The energy sector is undergoing significant changes, with a shift towards renewable energy sources. Aker BP must ensure that it is well positioned to adapt to these changes to remain competitive and sustain long- term growth.

Concentration of operations

Aker BP’s activities are concentrated on the Norwegian continental shelf, which exposes the company to risks associated with operating in

a single geographic region. This concentration means that unforeseen events, such as regu- latory changes, shifts in national policy, labour disruptions, regional supply chain constraints, or major incidents affecting offshore infrastructure, may have a more pronounced impact on the company than if operations were geographically diversified. The company’s financial performance, project progress and long-term value creation are therefore closely linked to conditions in this specific operating environment.

Impact

A regional incident or regulatory shift may affect multiple assets simultaneously, leading to operational interruptions, delays in project execution or reduced production. Dependence on one jurisdiction also heightens exposure to local political decisions, environmental expectations and market conditions.

Mitigation in place

Aker BP mitigates concentration risk through a robust asset portfolio within the region, diversified across fields, basins and development phases. Strong relationships with authorities, partners and suppliers, combined with high operational stand- ards, disciplined risk management and emergency preparedness, support resilience. Continuous optimisation of operations and strategic planning ensure that the company can adapt effectively to changing conditions on the NCS.

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Human capital and organisational capability risk

Aker BP’s future performance depends on its ability to attract, develop and retain highly skilled personnel across technical and operational disci- plines. Increased activity levels and competition for critical competencies place growing demands on the organisation. At the same time, the tran- sition towards more digital and automated work processes requires new skillsets and continuous capability development.

Impact

Insufficient organisational capacity or capability gaps may reduce execution quality, increase operational risk and slow the adoption of new technologies. A shortage of key skills may also lead to delays or inefficiencies across the value chain.

Mitigation in place

Aker BP invests in structured recruitment, training and development programmes and fosters a strong One Team culture that encourages collaboration, learning and shared responsibility. Workforce planning ensures that critical capabil- ities are developed and maintained. Leadership development and targeted talent initiatives support retention and prepare the organisation for future needs.

It is a strategic priority for the company to be an attractive employer. To attract and retain talent, Aker BP offers competitive salaries and other

benefits, as well as strong career development opportunities for all employees.

Evaluation of reserves and resources

The evaluation of Aker BP’s reserves and resources is based on geological data, well results, reservoir modelling, production history and engineering assessments. Although the company follows established industry standards and uses recognised methodologies, estimates remain subject to uncertainty due to the inherent variability of subsurface conditions and the limitations of available data. Changes in reservoir performance, drilling outcomes, commodity prices, operating costs or technological assumptions may result in revisions to previously reported volumes.

Impact

Revisions to reserves or resources can influence long term production forecasts, asset valuations and the economic basis for investment decisions. Significant negative revisions may affect future cash flow expectations, project prioritisation and financial performance.

Mitigation in place

Aker BP applies robust processes, peer reviews and independent assessments to strengthen the reliability of reserve and resource estimates. The company allocates substantial resources to analysing and understanding its reservoirs and conducts regular reservoir surveillance. Reservoir models are updated and stress-tested to ensure that new information is incorporated promptly.

The company adheres to recognised reporting frameworks and engages qualified external expertise when required, helping to ensure that estimates remain transparent, up to date and aligned with industry practice. Furthermore, the company applies a set of decision criteria to ensure that projects are economically robust before making investment decisions. These criteria include, but are not limited to, full-cycle NPV break-even criteria and scope 1 and 2 GHG emission intensity targets

Maturation of hydrocarbon resources base

Maturation of the hydrocarbon resources base refers to the uncertainty linked to identifying, evaluating and progressing new opportunities from early concepts to sanctioned projects. The quality of subsurface data, the complexity of reservoirs, and changing economic or regulatory conditions may influence the company’s ability to convert resources into reserves. As opportunities move through the maturation funnel, updated technical assessments, cost estimates and market assumptions may lead to reprioritisation, delays or downgrades.

Impact

Lower than expected maturation of new resources can reduce long-term production potential and narrow the future project pipeline. This may affect the company’s ability to maintain stable output over time, limit growth options and influence long- term value creation. Significant changes in project

assumptions may also lead to revisions of earlier resource estimates.

The inability to replace produced volumes with new discoveries and development could erode the company's market position and shareholder value. These factors may result in a diminished investment appeal and competitiveness in the oil and gas industry.

Mitigations in place

Aker BP applies structured evaluation processes and multidisciplinary reviews to ensure that new opportunities are assessed using the best available data and methods. Regular reservoir surveillance, updated geological models and improved seismic imaging strengthen technical certainty. The company maintains a diverse portfolio of oppor- tunities across basins and development phases to reduce dependency on individual prospects. Close collaboration between the subsurface, project and commercial teams helps ensure that resource maturation remains robust, competitive and aligned with strategic priorities. Technology and digitalisation, including advanced seismic imaging, increased oil recovery methods and systematic monitoring of field performance, further support the identification and maturation of brownfield and greenfield opportunities.

Climate-related risks

The climate-related risks are described in section 2 Climate change of the sustainability statement.

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Market and commodity price risk

Market and commodity price risk arises from fluctuations in global oil and gas prices, which remain inherently volatile. Prices are affected by underlying macroeconomic developments, global supply–demand conditions, policy shifts, energy transition trends and geopolitical events. Prolonged periods of reduced prices may lower revenue and cash flow, influence project economics, and affect the company’s capacity to invest and return value to shareholders.

Impact

Fluctuating prices can reduce operating income, erode margins, and may ultimately result in delays or reprioritisation of investment decisions. In weakened markets, economic assumptions underpinning ongoing or planned developments may need revision, potentially affecting long-term value creation.

Mitigation in place

Aker BP maintains a low break-even portfolio that remains resilient across a wide range of commodity price scenarios. Rigorous capital disci- pline ensures that activity levels can be adjusted if market conditions deteriorate. Operational effi- ciency programmes and cost reduction initiatives help sustain competitiveness, while continuous monitoring of global energy markets supports well informed strategic decisions. The company also has a hedging policy in place, through which it may secure downside price exposure on oil and gas.

Regulatory and political risk

The company is subject to extensive regulatory requirements, including taxation, emissions management, environmental standards and safety performance. Regulatory and political develop- ments, both national and international, may affect operational conditions, cost levels and access to licences or acreage. Shifts in rules or expectations can introduce uncertainty and affect the pace of project maturation as well as ongoing operations.

Impact

Changes in regulatory frameworks may increase compliance costs, lead to delays in approvals or licensing processes, and influence project profitability. In some cases, major policy shifts may require modifications to strategic plans or project concepts.

General instability and increased threats related to the geopolitical situation impact many of the other risk factors and various aspects of the business, from oil and gas prices to capacity in the supply chain and the increased complexity of cyberattacks.

Mitigation in place

Aker BP maintains proactive and transparent dialogue with regulators, policymakers and industry associations to anticipate and understand upcoming changes. The company actively partici- pates through representation on relevant consulta- tive committees and industry forums to contribute to, and stay informed on, regulatory development. Regulatory developments are included early in project planning and long-term strategy processes,

supported by scenario planning and impact assess- ments to evaluate potential outcomes. Compliance systems and internal controls are continuously strengthened to ensure consistent application of requirements.

To address geopolitical risk affecting the company’s operations and business environ- ment, specific mitigating actions have been implemented. These actions are detailed in their respective sections. For example, for impact on the supply chain see Supply chain and contractor risk, page 29 . For cyber security, see Cyber security and digital resilience risk, page 29 . Robustness and resilience towards potential geopolitical events are evaluated and put in place where deemed necessary. Response plans are established and implemented rapidly when specific situations occur.

Brand risk and stakeholder relationship risk

Brand and stakeholder relationship risk relates to the possibility that negative perceptions among key stakeholders, including authorities, partners, investors, employees, suppliers, local communities and the public, may affect Aker BP’s licence to operate, strategic flexibility or long-term value creation. As an offshore operator with high public visibility and dependency on regulatory trust, the company’s reputation is closely tied to its safety performance, environmental footprint, trans- parency, and ability to deliver on commitments. Operational incidents, delays in major projects, insufficient communication, or misalignment with stakeholder expectations on topics such

as climate, emissions, or responsible business conduct may weaken confidence in the company.

Impact

A deterioration in stakeholder trust can impact access to acreage, regulatory support, partner- ship opportunities and talent attraction. It may also increase scrutiny from authorities, prolong decision processes, affect contract negotiations and influence investor sentiment. More broadly, reputational damage may affect the compa- ny’s long-term competitiveness and strategic opportunities.

While reliance on joint arrangements and contrac- tors is a key aspect of the company's business model, such arrangements also introduce risk, as contractor non-compliance or failure can result in legal liabilities and have a cascading effect on the company’s reputation and business outcomes.

Mitigation in place

Aker BP prioritises open, consistent and transparent dialogue with stakeholders across all levels of the business. The company places strong emphasis on safe and reliable operations, responsible environmental performance, and clear communication of targets, results and expectations.

Communication, support, oversight of contractors and the ability to withstand adverse events are all governed by processes in the business manage- ment system to ensure that the company is acting in accordance with core values and requirements at all times.

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Ethics and compliance

Ethics and compliance risk relates to the poten- tial negative consequences that arise when a company, its employees, or its partners fail to act in accordance with laws, regulations, internal poli- cies, or expected ethical standards. This includes risks linked to breaches of legal requirements, improper business conduct, bribery and corrup- tion, conflicts of interest, misuse of confidential information, and behaviour that undermines trust or integrity. Such risks can expose the company to legal sanctions, financial penalties, reputational damage, and operational disruption, and may erode confidence among regulators, partners, employees, and other stakeholders.

Business ethics and compliance

Business ethics and compliance risk relates to the possibility that employees, contractors or partners may act in ways that are inconsistent with laws, internal standards or expectations for responsible conduct set forth by the company or society at large. As Aker BP operates in a highly regulated environment with strict requirements for integrity, transparency and responsible behaviour, any deviation from accepted ethical standards, including conflicts of interest, corruption, improper facilitation, or breaches of internal procedures, could undermine trust and expose the company to regulatory scrutiny. Ensuring that all personnel understand and adhere to ethical expectations is essential for maintaining Aker BP’s licence to operate.

Impact

Breaches of business ethics or failure to satisfy fiduciary or regulatory responsibilities, allegations of such activities, or negative publicity resulting from such other activities, or the association of any of the above with the company could materi- ally adversely affect our reputation and the value of our brand. They could also impact our business, results of operations, cash flows and financial condition, and our ability to attract and retain talent. Incidents involving unethical behaviour can also affect organisational culture, weaken rela- tionships with authorities and partners, and impair the company’s ability to secure new licences or collaborate with other parties.

Mitigation in place

Aker BP maintains a comprehensive ethics and compliance framework that includes a formal Code of Conduct, tailored training programmes, due diligence processes and a robust anti-corrup- tion programme to prevent, detect and mitigate risk of bribery and corruption. The dedicated compliance department conducts regular risk assessments of integrity risks to align the anti-corruption programme with the current risk profile. Employees and contractors have access to reporting channels for concerns, including anony- mous whistleblowing. Our integrity channel is also open to external parties. Aker BP maintains a strict non-retaliation policy. The company conducts regular risk assessments, monitors compliance with policies and evaluates third party integrity. Strong governance structures and leadership focus reinforce a culture of integrity throughout the organisation.

Laws and regulations

Risk related to laws and regulations arises from the possibility that Aker BP may unintentionally fail to comply with applicable legal requirements or that new or amended legislation may affect operations, project development or strategic priorities. The regulatory landscape for oil and gas companies is continuously evolving, particularly within areas such as environment, emissions, safety, trans- parency and corporate governance. Adapting to new legislative obligations requires operational adjustments and robust internal processes to ensure ongoing compliance.

Impact

Non compliance with laws or regulations may result in fines, enforcement actions, increased scrutiny from authorities, operational delays or restrictions on activities. Changes in legislation may also influence the economic viability of projects, increase reporting obligations or require modifications to operational practices. Persistent compliance issues could weaken trust among regulators and other stakeholders. Changes to the tax regime could lead to new investments being less attractive and challenge further growth of the company.

Mitigation in place

The company continuously monitors develop- ments in the political landscape and is positioned to act promptly to changes. Compliance reviews, audits and internal controls support consistent application of legal requirements across the organisation.

Legal risk

Legal risk arises from contractual disputes, claims, litigation, or disagreements with partners, suppliers or other stakeholders. Lawsuit risk is related to the legal and reputational challenges that the company may face due to an increasing trend to take legal action against governments and oil and gas stakeholders. The outcome of such cases could have implications for the company's current project portfolio and future operations as well as its public image and stakeholder relations.

Impact

Legal disputes may lead to financial losses, delays in project execution, constraints on operational flexibility or reputational impacts. Litigation or major contractual disagreements can divert management attention, increase the administrative burden and influence stakeholder relationships, including increased pressure from investors and other stakeholders. In some cases, adverse legal outcomes may require changes to business prac- tices or contract structures. The impact of climate lawsuit risks could be significant, depending on the ruling and the subsequent actions of the government and the parliament.

Mitigation in place

The company strives to always operate within the bounds of applicable laws, regulations and permits. The company continuously monitors developments in the regulatory framework and engages with relevant stakeholders. The company maintains clear internal processes for contract management and dispute handling, supported by experienced legal and commercial teams.

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Our long-term horizon reflects the achievement of our climate-related targets towards 2050, described in section 2.4 in the climate change chapter, in a market still dependent on oil and gas. Supply of electrical power from shore to offshore installations and other technologies allowing operations with low GHG emission intensity are long-term strategies for our business. The portfolio in 2050 will be different from today, with Eiga, Skarv and Alvheim expected to be decom- missioned by then.

Climate-related impacts are identified and assessed continuously through monitoring of scope 1 GHG emissions and energy use for all assets in our portfolio. The combination of regular monitoring of GHG emissions and the annual reporting of scope 1, 2 and 3 emissions give a comprehensive understanding of the impact of our total GHG emissions and energy use. Through our DMA, we have evaluated both direct and indirect sources of GHG emissions and their potential impact on climate change.

IROs are identified both as a result of our internal activity set, as well as from various sources such as regulators, industry initiatives, NGOs, public perception and investors. Climate-related risks and opportunities follow the risk management process described in section 1.4 .

The legal proceedings concerning the Ministry of Energy’s approvals of the PDOs for the Breidablikk, Tyrving and Yggdrasil fields continued through 2025. The status of the case is described in the business description section of the BoD report.

Climate-related hazards were identified as part of our climate risk analysis but were deemed immaterial in relation to the impact these hazards are predicted to have on our assets.

To assess and manage climate-related risks, we use scenario analysis, sensitivity testing and an internal carbon price, in addition to reducing our own emissions. We base these scenario analyses on our internal scope 1 emission forecasts towards 2050. Aker BP considers its strategy, emission reduction pathway and portfolio to be resilient to the projected oil and gas prices, as well as carbon prices under the various IEA scenarios. For information regarding how Aker BP assesses climate-related risks using scenario analysis, please see section 2.6 in the climate change chapter.

E2 – Pollution

As all Aker BP’s own operations are located on the Norwegian continental shelf (NCS), all activities leading to actual or potential pollution by emissions to air and discharges to sea, are strictly regulated by Norwegian law and discharge permits.

Aker BP’s enterprise risk management system supports resilience and adaptation to changing circumstances and uncertainty. Our risk-based approach to prevention, reduction and remedi- ation of pollution is triggered by our activities, regulatory requirements, as well as stakeholder expectations.

Thorough planning and execution of our oper- ational, project and drilling activities include identification and management of environmental

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Environment

Social

Governance

General

ESRS topic

IRO name

Sub-topic

Category

Up- stream

Own ops.

Down- stream

Short term

Medium term

Long term

Resource use and circular economy

Waste generation

Waste

Negative actual impact

●

●

●

●

Use of virgin/raw materials

Resources inflows, including resource use

Negative actual impact

●

●

●

Waste from decommissioning

Waste

Negative actual impact

●

●

●

●

Social

Own workforce

Working conditions

Working conditions

Negative potential impact

●

●

●

●

Working time offshore

Working conditions

Negative actual impact

●

●

●

●

Discrimination, inequality and harassment

Equal treatment and opportunities for all

Negative potential impact

●

●

●

●

Major accidents

Health and safety

Negative potential impact

●

●

●

●

Work-related injuries and illness

Health and safety

Negative actual impact

●

●

●

●

Loss of value creation due to adverse health and safety impacts

Health and safety

Financial risk

●

●

●

●

Workers in the value chain

Working conditions

Working conditions

Negative actual impact

●

●

●

●

Health and safety impacts

Working conditions

Negative actual impact

●

●

●

●

Forced labour and inadequate framework for young workers

Other work-related rights

Negative potential impact

●

●

●

●

Harassment

Equal treatment and opportunities for all

Negative potential impact

●

●

●

●

Affected communities

Impacts on affected communities

Communities' economic, social and cultural rights

Negative potential impact

●

●

●

●

●

Governance

Business conduct

Ethical business conduct

Corporate culture, Corruption and bribery

Negative potential impact

●

●

●

●

Protection of whistleblowers

Protection of whistleblowers

Negative potential impact

●

●

●

●

●

●

Responsible supplier management

Management of relationships with suppliers

Positive potential impact

●

●

●

●

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Other EU legislation

The table below provides an overview of all the datapoints that derive from other EU legislation, and whether these datapoints have been deemed material/not material. Where a datapoint is material, see the table above for reference to where information on the datapoint can be found.

Sustainable Finance Disclosure Regulations (SFDR) Pillar 3 (P3)

Datapoints in Appendix B

EU legislation

Materiality

Location

ESRS 2 GOV-1 Board's gender diversity paragraph 21 (d)

SFDR, BR

Material

ESRS 2 GOV-1 Percentage of board members who are independent paragraph 21 (e)

BR

Material

ESRS 2 GOV-4 Statement on due diligence paragraph 30

SFDR

Material

ESRS 2 SBM-1 Involvement in activities related to fossil fuel activities paragraph 40 (d) i

SFDR, P3, BR

Material

ESRS 2 SBM-1 Involvement in activities related to chemical production paragraph 40 (d) ii

SFDR, BR

Not material

NA

ESRS 2 SBM-1 Involvement in activities related to controversial weapons paragraph 40 (d) iii

SFDR, BR

Not material

NA

ESRS 2 SBM-1 Involvement in activities related to cultivation and production of tobacco paragraph 40 (d) iv

BR

Not material

NA

ESRS E1-1 Transition plan to reach climate neutrality by 2050 paragraph 14

EUCL

Material

NA

ESRS E1-1 Undertakings excluded from Paris-aligned Benchmarks paragraph 16 (g)

P3, BR

Material

NA

ESRS E1-4 GHG emission reduction targets paragraph 34

SFDR, P3, BR

Material

ESRS E1-5 Energy consumption from fossil sources disaggregated by sources (only high climate impact sectors) paragraph 38

SFDR

Material

ESRS E1-5 Energy consumption and mix paragraph 37

SFDR

Material

ESRS E1-5 Energy intensity associated with activities in high climate impact sectors paragraphs 40 to 43

SFDR

Material

ESRS E1-6 Gross Scope 1, 2, 3 and Total GHG emissions paragraph 44

SFDR, P3, BR

Material

ESRS E1-6 Gross GHG emissions intensity para- graphs 53 to 55

SFDR, P3, BR

Material

Datapoints in Appendix B

EU legislation

Materiality

Location

ESRS E1-7 GHG removals and carbon credits paragraph 56

EUCL

Material

ESRS E1-9 Exposure of the benchmark portfolio to climate-related physical risks paragraph 66

BR

Material

NA

ESRS E1-9 Disaggregation of monetary amounts by acute and chronic physical risk paragraph 66 (a)

ESRS E1-9 Location of significant assets at material physical risk paragraph 66 (c)

P3

Not material

NA

ESRS E1-9 Breakdown of the carrying value of its real estate assets by energy-efficiency classes paragraph 67 (c).

P3

Not material

NA

ESRS E1-9 Degree of exposure of the portfolio to climate- related opportunities paragraph 69

BR

Not material

NA

ESRS E2-4 Amount of each pollutant listed in Annex II of the E-PRTR Regulation (European Pollutant Release and Transfer Register) emitted to air, water and soil, paragraph 28

SFDR

Material

ESRS E3-1 Water and marine resources paragraph 9

SFDR

Material

ESRS E3-1 Dedicated policy paragraph 13

SFDR

Not material

NA

ESRS E3-1 Sustainable oceans and seas paragraph 14

SFDR

Not material

NA

ESRS E3-4 Total water recycled and reused paragraph 28 (c)

SFDR

Not material

NA

ESRS E3-4 Total water consumption in m 3 per net revenue on own operations paragraph 29

SFDR

Not material

NA

ESRS 2 - SBM 3 - E4 paragraph 16 (a) i

SFDR

Material

ESRS 2 - SBM 3 - E4 paragraph 16 (b)

SFDR

Material

ESRS 2 - SBM 3 - E4 paragraph 16 (c)

SFDR

Material

ESRS E4-2 Sustainable land / agriculture practices or policies paragraph 24 (b)

SFDR

Material

NA

ESRS E4-2 Sustainable oceans / seas practices or policies paragraph 24 (c)

SFDR

Material

Benchmarks Regulation (BR) EU Climate Law (EUCL)

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Datapoints in Appendix B

EU legislation

Materiality

Location

ESRS E4-2 Policies to address deforestation paragraph 24 (d)

SFDR

Material

NA

ESRS E5-5 Non-recycled waste paragraph 37 (d)

SFDR

Material

ESRS E5-5 Hazardous waste and radioactive waste paragraph 39

SFDR

Material

ESRS 2- SBM3 - S1 Risk of incidents of forced labour paragraph 14 (f)

SFDR

Material

NA

ESRS 2- SBM3 - S1 Risk of incidents of child labour para- graph 14 (g)

SFDR

Material

NA

ESRS S1-1 Human rights policy commitments paragraph 20

SFDR

Material

ESRS S1-1 Due diligence policies on issues addressed by the fundamental International Labour Organisation Conventions 1 to 8, paragraph 21

BR

Material

ESRS S1-1 Processes and measures for preventing trafficking in human beings paragraph 22

SFDR

Material

NA

ESRS S1-1 Workplace accident prevention policy or management system paragraph 23

SFDR

Material

ESRS S1-3 Grievance/complaints handling mechanisms paragraph 32 (c)

SFDR

Material

ESRS S1-14 Number of fatalities and number and rate of work-related accidents paragraph 88 (b) and (c)

SFDR, BR

Material

ESRS S1-14 Number of days lost to injuries, accidents, fatalities or illness paragraph 88 (e)

SFDR

Material

ESRS S1-16 Unadjusted gender pay gap paragraph 97 (a)

SFDR, BR

Material

ESRS S1-16 Excessive CEO pay ratio paragraph 97 (b)

SFDR

Material

ESRS S1-17 Incidents of discrimination paragraph 103 (a)

SFDR

Material

ESRS S1-17 Non-respect of UNGPs on Business and Human Rights and OECD Guidelines paragraph 104 (a)

SFDR, BR

ESRS 2 - SBM3 – S2 Significant risk of child labour or forced labour in the value chain paragraph 11 (b)

SFDR

Material

Datapoints in Appendix B

EU legislation

Materiality

Location

ESRS S2-1 Human rights policy commitments paragraph 17

SFDR

Material

ESRS S2-1 Policies related to value chain workers paragraph 18

SFDR

Material

ESRS S2-1 Non-respect of UNGPs on Business and Human Rights principles and OECD guidelines paragraph 19

SFDR, BR

Material

ESRS S2-1 Due diligence policies on issues addressed by the fundamental International Labor Organisation Conventions 1 to 8, paragraph 19

BR

Material

ESRS S2-4 Human rights issues and incidents connected to its upstream and downstream value chain paragraph 36

SFDR

Material

ESRS S3-1 Human rights policy commitments paragraph 16

SFDR

Material

ESRS S3-1 Non-respect of UNGPs on Business and Human Rights, ILO principles or OECD guidelines paragraph 17

SFDR, BR

Material

ESRS S3-4 Human rights issues and incidents paragraph 36

SFDR

Material

ESRS S4-1 Policies related to consumers and end-users paragraph 16

SFDR

Not material

NA

ESRS S4-1 Non-respect of UNGPs on Business and Human Rights and OECD guidelines paragraph 17

SFDR, BR

Not material

NA

ESRS S4-4 Human rights issues and incidents paragraph 35

SFDR

Not material

NA

ESRS G1-1 United Nations Convention against Corruption paragraph 10 (b)

SFDR

Material

NA

ESRS G1-1 Protection of whistle- blowers paragraph 10 (d)

SFDR

Material

NA

ESRS G1-4 Fines for violation of anti-corruption and anti-bribery laws paragraph 24 (a)

SFDR, BR

Material

ESRS G1-4 Standards of anti- corruption and antibribery paragraph 24 (b)

SFDR

Material

NA

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Environmental management and compliance

Environmental compliance and safeguarding the environment are key priorities for Aker BP. Aker BP’s environmental management system is an integral part of the company’s sustainability framework and management system. The system covers all our own operations at all locations. Our environmental management system follows the guiding principles in ISO 14001 and is regularly audited to promote compliance with the standard. Aker BP’s external environment policy describes our commitment to safeguarding and avoiding harm to the environment.

We perform environmental aspect and risk assess- ments and evaluate appropriate actions when planning exploration and development drilling. Also, we update environmental risk analyses for assets where changes in activity levels could affect environmental performance. We identify actual and potential environmental impacts and risks, and we involve relevant stakeholders and experts in the evaluation process. Annual HSSEQ programmes are in place for both exploration and production drilling, as well as for production activities. Each programme defines clear HSSEQ objectives, planned activities and designated focus areas for the respective year.

We continuously review and assess the degree to which environmental expectations are met. Environmental metrics are reported and followed up through our environmental accounting system, NEMS, which follows the guiding principles in ISO 14001.

Aker BP uses the annual submission of reports to authorities, audits performed by regulatory agencies and self-assessments to ensure environmental compliance. The compliance checks in the self-assessment process consider both environmental aspects and regulatory require- ments. The audits verify the effectiveness of our environmental management system and are part of our continuous improvement efforts to ensure compliance. Over time, these audits cover all our own operations at all locations.

Discharges to sea from our own operations and exploration activities are governed by our discharge permits issued by the Norwegian Environment Agency. We report on the compli- ance status for our discharges and emissions to the authorities, for both operating fields and exploration drilling, on an annual basis. Annual reports, along with feedback on these annual reports from the Norwegian Environment Agency, also provide input for continuous improvement of our environmental performance.

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General

Social

Governance

Environment

IRO name and description

Sub-topic

Category

Up- stream

Own ops.

Down- stream

Short term

Medium term

Long term

Lower oil and gas prices due to decreased demand and an accelerated energy transition

Demand for oil and gas could decline significantly faster than supply can adjust, for instance due to the energy transition and electrification progressing faster than anticipated. This imbalance could lead to lower oil and gas prices.

Mitigation actions

Strict financial framework for investment decisions; sanctioning projects with low break-even oil prices

Scenario analysis and stress-testing on both portfolio and project levels and internal carbon price exceeding IEA’s Net Zero Emissions by 2050 scenario

Climate change mitigation

Financial risk

●

●

●

Increased cost of capital due to negative perceptions from society and stakeholders

Availability and cost of capital could be negatively impacted by a change in the capital market's perception of the oil and gas industry, or as a result of any shortcomings in our decarbonisation plan and sustainability commitments.

Mitigation actions

Efforts in place to secure financial flexibility and maintain investment grade credit rating

Maintaining Aker BP brand value

Climate change mitigation

Financial risk

●

●

●

Financial benefits and improved reputation from investments in CCS

CCS could represent a potential new revenue stream for Aker BP, and support our customers in decarbonising.

Actions to realise opportunities

Assess current acreage for CCS development. Aker BP is already the operator on two CCS licences and partner on a third

Further develop business model and technology related to CCS

Assess possible new acreage suitable for CCS

Climate change mitigation

Financial opportunity

●

●

Financial benefits from industry-leading scope 1 and 2 GHG emission intensity

Aker BP’s industry-leading 1) scope 1 and 2 GHG emission intensity, low production costs and high ESG performance could provide a competitive advantage and better opportunities to obtain capital in the future.

Actions to realise opportunities

Cost reduction initiatives

Energy management and other emission reduction initiatives

Continuous evaluation of electrification using power from shore or from offshore wind, where feasible

Continued investment in digitalisation and business transformation

Climate change mitigation

Financial opportunity

●

●

●

●

Data from Wood Mackenzie placed Aker BP among the top five percent of the world’s 250 largest oil and gas companies in terms of lowest GHG emission intensity from production in 2025.

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Social

Governance

Environment

Operational control GHG emissions across the value chain (1,000 t CO 2 e)

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Social

Governance

Environment

Actions planned to be undertaken before 2030

Action description

Timeline

Emission change (1,000 t CO 2 e)

Retirement of assets

Decommissioning of Ula, one of our three remaining gas-powered assets, is planned for 2028

2028

-171

Energy efficiency

Projected emission reductions from energy management initiatives in 2030

2030

-27

Actions planned to be undertaken between 2030 and 2050

Action description

Timeline

Emission change (1,000 t CO 2 e)

Retirement of assets

Based on our current portfolio, our two remaining gas-powered assets at this point, Skarv and Alvheim, as well as the Eiga area is planned to be decommissioned by 2050

2030–2050

-423

Energy efficiency

Projected emission reductions from energy management initiatives in 2050

2050

-26

Actions to achieve 50 percent reduction in operational control scope 1 and 2 GHG emissions by 2030

Aker BP will continue to seek cost-effective emission reduction measures to reduce GHG emissions from our operated assets. Investments in electrification constitute the most important lever for reducing scope 1 emissions under our ‘avoid’ and ‘reduce’ pillars. In 2028, we plan to retire our Ula asset, as well as bring new electrified production on stream mainly through our Yggdrasil and Valhall PWP-Fenris projects. Based on current projections, around 85 percent of Aker BP’s equity share production is estimated to be electrified by 2030, enabling us to maintain a portfolio with an industry-leading 1) low equity share scope 1 and 2 GHG emission intensity.

Actions to achieve 90 percent reduction in scope 1 and 2 GHG emissions by 2050

By the 2040s, we estimate that our scope 1 and 2 GHG emissions will be significantly reduced due to the decommissioning of Alvheim and Skarv, our two remaining non-electrified assets at this point. Based on our current projected portfolio, 100 percent of Aker BP’s operated production is expected to be electrified with power from shore by the 2040s. We aim to continue our work on energy efficiency towards 2050, which will help us reach our target of 90 percent reduction in operational control and equity share scope 1 and 2 GHG emissions by 2050.

Actions related to methane emissions

Minimising methane emissions is a key part of Aker BP’s climate efforts and is covered by our climate and energy policy, as described in section 2.1 . One of Aker BP’s climate-related targets, presented in section 2.4 , is to minimise methane emissions and maintain an operational control scope 1 methane emission intensity below 0.05 percent 2) .

To reach our target and enhance our under- standing and control of all methane emission sources, Aker BP is a member of the Oil and Gas Methane Partnership 2.0 (OGMP 2.0). Through this partnership, we are committed to reporting in accordance with the OGMP 2.0 standard from 2025 onwards, providing a more detailed and action-oriented foundation for identifying, moni- toring and reducing methane emissions across our operations.

Going forward, we will continue to develop site-specific monitoring survey plans for our operated assets. In addition, we are working to implement improved leak detection and repair (LDAR) surveying techniques for surface and subsea assets, in line with forthcoming methane regulations. The site-specific monitoring will support our source-specific emission estimates, enabling our emissions to be kept at a minimum and remain well within our long-term methane emission intensity target.

Data from Wood Mackenzie placed Aker BP among the top five percent of the world’s 250 largest oil and gas companies in terms of lowest GHG emission intensity from production in 2025.

Calculated as volume of operational control scope 1 methane emissions from operated assets and drilling activities, expressed as a percentage of the total volume of saleable gas.

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Governance

Environment

Actions related to upstream scope 3 emissions

Aker BP’s climate and energy policy, as described in section 2.1 , outlines our ambition to work in cooperation with suppliers and contractors to establish a GHG emission footprint and implement appropriate measures to reduce upstream scope 3 emissions. As of 2025, Aker BP does not have any targets related to upstream scope 3 emissions.

During 2025, we have strengthened our part- nerships with selected suppliers with a goal of identifying product-specific emission factors and suitable emission reduction initiatives.

We may consider setting upstream scope 3 emission reduction targets in the future if we identify a performance indicator suitable for our business model.

Other climate-related actions

Carbon capture and storage

Aker BP believes that CCS will play an important role in the transition to a low-carbon energy future and has identified a material opportunity related to financial benefits and improved reputation from investments in CCS. As of now, we do not have any policies, targets or metrics related to CCS, primarily because our CCS activities are still at an early stage and the regulatory and fiscal frame- works are not yet sufficiently matured. However, in the future, we may introduce relevant policies, targets and performance indicators to guide and evaluate our efforts.

In 2023, Aker BP was awarded its first CO 2 storage licence on the NCS, Poseidon (EXL005), together with OMV (Norge) AS. This licence,

operated by Aker BP, is located in the Southern Norwegian sector of the North Sea. In September 2024, Aker BP received its second CO 2 storage licence, Atlas (EXL011). Orlen Upstream Norge AS has since joined as a licence partner. EXL011 is located east of the Aker BP-operated Yggdrasil development in the Central North Sea. In February 2025, the Ministry of Energy awarded Aker BP a third licence, Forsete (EXL013), located west of Yggdrasil. Forsete is operated by Equinor Low Carbon Solution AS.

Aker BP has a strategic partnership with Höegh Evi to develop a comprehensive CO 2 transport and storage solution for industrial CO 2 emitters in Europe. This collaboration combines the compa- nies’ respective strengths, expertise and technol- ogies to enable collection, conditioning, transport and secure injection of CO 2 for permanent storage in subsea reservoirs on the NCS.

Aker BP’s CCS activities currently have three focus areas. Firstly, we are capturing high-quality subsurface opportunities and assessing their suitability for carbon storage through detailed subsurface studies. Secondly, we are evaluating field development concepts to mature projects towards development decisions. Thirdly, we are establishing strategic partnerships across the CCS value chain to develop a viable business model, while collaborating with the industry and authorities to establish a regulatory and fiscal framework for CCS.

The Atlas project is in the feasibility phase and has the potential to become a key enabler for large- scale carbon capture and storage in Europe.

Research and development (R&D) related to climate and external environment

One of the stated ambitions in our climate and energy policy is to contribute to the development and sharing of technology to enable new indus- tries. Aker BP continuously invests and participates in R&D activities. Our prioritised areas of R&D include digitalisation and technology development

within emission and discharge control, health, safety, security, environment and quality (HSSEQ) and other operational disciplines.

Our total R&D spend in 2025 was USD 38.6 million, while our allocated spending to climate and external environment was USD 4.0 million. As of now, we do not have any targets related to R&D.

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Aker BP equity share scope 1 and 2 GHG emission intensity compared to global average

Aker BP operational control scope 1 methane emission intensity

Target 3

We aim to minimise GHG emissions and maintain an equity share scope 1 and 2 GHG emission intensity below 4 kg CO 2 e/boe. According to IOGP, this is less than one quarter of the global average in 2024 1) .

Our equity share scope 1 and 2 GHG emission intensity in 2025 was 2.8 (2.6) kg CO 2 e/boe, well below our target of below 4 kg CO 2 e/boe. This is in line with our expectations. The equity share scope 1 and 2 GHG emission intensity is expected to increase in the next two years due to increased drilling and commissioning activities. Beyond 2027, we expect the intensity to fall back to levels consistent with previous years.

This is a continuous target and thus has no baseline value or applicability period.

The share of scope 1 and scope 2 emissions varies from year to year. Historically, scope 2 emissions have constituted less than five percent of total scope 1 and 2 GHG emissions but this is expected to increase going forward. Location-based method is used for calculating scope 2 emissions.

The decarbonisation levers described in section 2.3 along with continued high production from our assets in our own operations will help us reach this target.

Target 4

We aim to minimise methane emissions and maintain an operational control scope 1 methane emission intensity 2) below 0.05 percent.

Our operational control scope 1 methane emission intensity in 2025 was 0.017 (0.018) percent CH 4 of saleable gas. This is in line with our expecta- tions and is at a similar level to previous years. Continued focus on methane emission reduction initiatives and production optimisation is key to achieving this long-term target.

Our 2025 operational control scope 1 methane emission intensity was also lower than the 0.12 percent as reported by Oil and Gas Climate Initiative (OGCI). Most of our methane emissions originate from releases of non-combusted gas, through cold venting, fugitive emissions and from offloading on our FPSOs (floating production storage and offloading vessels).

This is a continuous target and thus has no baseline value or applicability period.

The global average upstream GHG emission intensity in 2024 was 17.8 kg CO 2 e/boe according to the International Association of Oil & Gas Producers (IOGP) (IOGP Environmental performance indicators - 2024 data).

Calculated as volume of operational control scope 1 methane emissions from operated assets and drilling activities, expressed as a percentage of the total volume of saleable gas.

IOGP Environmental performance indicators - 2024 data

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Total GHG emissions by source

Emission source/category 1) 2) 3)

Unit

Operational control

Equity share

Base year (2017)

2025

2024

2030 target

2050 target

Reduction from baseline

Base year (2017)

2025

2024

2030 target

2050 target

Reduction from baseline

Scope 1 GHG emissions

Gross scope 1 GHG emissions

1,000 t CO 2 e

881

838

417

405

CO 2 (carbon dioxide)

1,000 t CO 2 e

850

806

395

383

CH 4 (methane)

1,000 t CO 2 e

28

29

20

21

N 2 O (nitrous oxide)

1,000 t CO 2 e

4

3

2

2

Percentage of scope 1 GHG emissions from regulated

emission trading schemes

%

92%

93%

93%

94%

Scope 2 GHG emissions

Gross location-based scope 2 GHG emissions 4)

1,000 t CO 2 e

10

11

12

12

Gross market-based scope 2 GHG emissions 4)

1,000 t CO 2 e

463

514

525

562

Total scope 1 and 2 GHG emissions

1,000 t CO 2 e

1,250

892

850

625

125

29%

666

429

418

GHG neutrality

90%

36%

Scope 3 GHG emissions

Total Gross indirect (Scope 3) GHG emissions

1,000 t CO 2 e

68,685

71,458

68,508

71,330

Purchased goods and services

1,000 t CO 2 e

94

95

89

82

Capital goods

1,000 t CO 2 e

354

90

242

57

Fuel- and Energy-Related activities (not included in Scope 1 or Scope 2)

1,000 t CO 2 e

27

26

19

18

Upstream transportation and distribution

1,000 t CO 2 e

237

202

185

129

Waste generated in operations

1,000 t CO 2 e

1

1

1

1

Business travel

1,000 t CO 2 e

12

12

12

12

Downstream transportation and distribution

1,000 t CO 2 e

193

191

193

191

Processing of sold products

1,000 t CO 2 e

4,677

4,668

4,677

4,668

Use of sold products

1,000 t CO 2 e

63,089

66,172

63,089

66,172

Total GHG emissions (location-based)

1,000 t CO 2 e

69,576

72,308

68,936

71,748

Total GHG emissions (market-based)

1,000 t CO 2 e

70,029

72,810

69,449

72,298

Methodologies, significant assumptions and emission factors for calculation of scope 1, 2 and 3 emissions are presented in the respective sections. section 2.5.1 , section 2.5.2 and section 2.5.3 .

Aker BP has zero scope 1, 2 or 3 emissions from biogenic sources.

All Global Warming Potential (GWP) factors used are from IPCC AR6.

2024-values are restated due to emission factors for 2024 not being available at the time Aker BP published its 2024 annual report.

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The underpinning anti-corruption procedure establishes a framework for preventing all forms of corruption and guidance for our employees and business partners on how to apply these principles in their work. As stated in our anti-corruption procedure, Aker BP prohibits all forms of corruption, including bribery. All allegations or incidents of corruption and bribery shall be reported in accordance with the established processes for reporting of concerns and handled in line with the internal procedure for handling whistleblowing reports, applicable laws and regulations. More information on raising concerns is provided in section 10.2 . Aker BP’s compliance department oversees the risk of corruption and bribery and reports on a quarterly basis to the executive management team and the audit and risk committee. The investigation team operates sepa- rately from the management involved in the matter.

The code of conduct and anti-corruption proce- dure, which are owned by the CEO and approved by the BoD, apply to all employees and those acting for or on behalf of Aker BP. Employees are encouraged to report any suspected violation of Aker BP’s code of conduct, anti-corruption procedure or applicable rules. Aker BP regularly communicates the content of its policies through internal channels, external websites and meetings with suppliers and business partners. Our contractual provisions set expectations for our business partners to align their business conduct with Aker BP’s standards.

Each year, Aker BP conducts a compliance risk assessment, led by the compliance department in collaboration with key company functions (such as legal, finance, supply chain and projects). The compliance risk assessment aims to identify areas with the highest risk of non-compliance, including corruption and bribery. The result of the

assessment is used to improve our compliance programme by enabling us to implement more targeted actions to effectively mitigate the identified risks.

Actions

Everyone working for or on behalf of Aker BP shall follow the policies and procedures outlined above to prevent unethical and non-transparent behaviour.

In 2025, our code of conduct and anti-corruption procedure were updated in accordance with the two-year review cycle. The updates to the code of conduct included reinforcing our zero tolerance for all forms of corruption and clarifying guidelines related to conflicts of interest, confidentiality and data privacy, cyber security, responsible use of AI, and diversity, equality and inclusion. A new chapter was introduced outlining expectations for Aker BP employees serving in board posi- tions on behalf of Aker BP. The updates to the anti-corruption procedure reflect the evolving regulatory landscape and are designed to provide clear guidance on anti-corruption for Aker BP’s representatives.

The revision process was coordinated with internal stakeholders, including representatives from legal, people and organisation (P&O), digital, security, climate and external environment, and the EMT, to ensure comprehensive input and alignment across the organisation.

In addition, the compliance department updated internal guidelines on gifts and hospitality and conflicts of interest to clarify expectations and responsibilities related to these topics. A new compliance app was launched to simplify the registration and approval processes for gifts and hospitality and conflicts of interest situations.

The compliance risk assessment conducted in 2025 indicated that the key areas with potential exposure to the risk of bribery and corruption relate to project activities and interactions with third parties. Based on the compliance risk assessment, we have developed a compliance training plan tailored for all levels within the organisation. The objective of this

plan is to ensure that all employees understand the potential impact of unethical and non-transparent behaviour on markets, society and governmental bodies. Since certain positions are at higher risk, this customised plan ensures that all employees, including those in functions-at-risk, receive training to help them manage the risks they encounter.

Compliance programme

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Signatures – Board of Directors and chief executive officer

The board of directors and the chief executive officer of Aker BP ASA Fornebu, 24 March 2026

Øyvind Eriksen

Chair of the board

Trond Brandsrud

Board member

Doris Reiter

Board member

Kjell Inge Røkke

Board member

Kate Thomson

Board member

Ingard Haugeberg

Board member

Anne Marie Cannon

Deputy chair

Charles Ashley Heppenstall

Board member

Zeala Fortescue

Board member

Tore Vik

Board member

Karl Johnny Hersvik

Chief executive officer

Stine Bjørnvold Bakken

Board member

Marit Hargemark

Board member

Valborg Lundegaard

Board member

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Independent auditor's statement

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Risk assessment

In 2025, Aker BP performed its annual compliance risk assessment where risks of adverse impact on human rights and decent working conditions were part of the assessment. Together with the supply chain management department, we have mapped out suppliers and production sites that we consider to have a higher exposure to risks of adverse impact on human rights and decent working conditions. The following potential risk areas were mapped as particularly relevant:

Human rights (forced labour and inadequate framework for young workers)

Working conditions (insecure employment, inadequate remuneration, limited social dialogue, work-life imbalance and long working hours)

Health and safety

Harassment

In 2025, we continued to strengthen our supplier risk and due diligence process. This involved reviewing and updating our screening risk model, streamlining requirements, and revising the due diligence process and risk classification. These enhancements were aimed at reducing third-party risk exposure and creating a more efficient process with fewer manual steps and improved throughput time.

Due diligence

Aker BP performs human rights due diligence to identify, prevent, mitigate and account for potential and actual adverse human rights

impacts. We have processes in place to enable remediation where we may cause or contribute to adverse human rights impacts. Our approach is based on the OECD Due Diligence Guidance for Responsible Business Conduct and is integrated into relevant business processes across the company.

Stakeholder engagement and industry cooperation

Meaningful stakeholder engagement and dialogue are key elements in managing human rights risks. We collaborate regularly with relevant stakeholders and rightsholders to inform them about our ongoing work to ensure respect for human rights and to incorporate feedback into our work to reduce actual and potential adverse impacts on human rights. Our stakeholders include employees, authorities, local communities, non-governmental organisations (NGOs), business partners, suppliers, contractors, investors and other counterparties.

Aker BP participates in a cross-industry initiative led by Offshore Qualific, a collaboration between companies and suppliers in the offshore and energy industry. Through this initiative, we gain access to shared supplier data and human rights audits results.

In 2025, Aker BP participated in quarterly meetings where the members of Offshore Qualific group shared their experiences related to human rights management and common expectations to supplier qualification on the basis of human rights.

Since 2024, Aker BP has been a member of Ipieca, a global oil and gas association. Ipieca brings together members and stakeholders to lead in integrating sustainability by advancing climate action, environmental responsibility and social performance across oil, gas and renewables activities.

Engaging in Ipieca's working groups, including the human rights working group, enables Aker BP to collaborate with other industry leaders, sharing best practices and exploring innovative solutions.

Training and awareness

We provide regular training to our own workforce on human rights. In 2025, training on whistle- blowing and grievance mechanisms was included as a separate module in the code of conduct refresher course. We also delivered targeted awareness training on work-related crime to offshore installation managers and HSSEQ site representatives.

We regularly communicate the content of our human rights and related policies to our suppliers, business partners and external stakeholders through our external website, as well as through ongoing dialogue and meetings.

Requirements for our suppliers

We work closely with our suppliers to ensure they operate in line with Aker BP’s standards in HSSEQ, ethics and corporate social responsibility. These requirements are stated in our supplier declaration, which must be signed by the supplier

prior to conducting business with Aker BP, with the exception of suppliers of goods and services that have low inherent and material risk to Aker BP. Signing our supplier declaration demonstrates a commitment to conduct business in a manner consistent with our principles, and to setting similar standards for their own suppliers.

As part of our supplier audits, we assess the supplier’s capability to communicate the expectations outlined in our supplier declaration throughout their supply chain and to ensure these standards are upheld.

To further reduce risk, Aker BP includes appro- priate compliance clauses in the contracts based on the level of risk identified.

Grievance mechanisms and remediation

Where we have identified any negative actual or potential human rights impacts, we aim to have measures in place to reduce or mitigate these impacts. We encourage employees and external parties to raise concerns and report suspected violations of applicable laws and regulations via our integrity channel. Reports can be sent anonymously through Aker BP’s integrity channel, which is managed by an external third party. Aker BP has a strict non-retaliation policy.

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Transparency

Specific instance process before the OECD contact point for responsible business conduct

Aker BP has been party to a specific Instance procedure before the Norwegian OECD Contact Point for Responsible Business Conduct (the NCP) following a complaint filed by eight civil society organisations on 31 May 2022 against Aker BP and Aker ASA. The complaint alleged that the companies had not complied with the OECD Guidelines for Multinational Enterprises in connec- tion with Aker BP’s acquisition of Lundin Energy AB ('Lundin')’s oil and gas business, that was announced in December 2021 and completed in June 2022. Lundin is accused of having contrib- uted to gross human rights abuses and war crimes in Sudan during its operations there in 1999-2003 and the matter is subject to criminal proceedings before Stockholm City Court. The complainants claimed that the transaction left Lundin (later renamed Orrön Energy AB) financially incapable of providing remedy to victims. The NCP admitted parts of the complaint, delimited to Aker BP’s (and Aker ASA’s) human rights due diligence at the time of the transaction, and issued its Final Statement on 18 June 2025.

The issue under consideration was whether Aker BP had carried out due diligence in line with the OECD Guidelines at the time of the transaction with respect to a potential adverse impact on the victims’ right to an effective remedy from Lundin, should responsibility be established. The company acquired by Aker BP was Lundin Energy Norway AS and the NCP did not question our assessment that there is no connection between this company and the alleged human rights impact. However, the NCP found that Aker BP’s due diligence had not adequately addressed the risk that Lundin Energy/Orrön Energy would not be financially capable of meeting its potential responsibility for providing remedy under the OECD Guidelines.

Aker BP has reviewed its role as a party to the negotiations and agreement with Lundin and the steps taken in the due diligence in light of the expectations of the OECD Guidelines. The conclu- sion remains that Aker BP did not contribute to a potential adverse impact on the right to remedy. Aker BP’s business relationship with Lundin/Orrön Energy ended in 2022.

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Signatures – Board of Directors and chief executive officer

The board of directors and the chief executive officer of Aker BP ASA Fornebu, 24 March 2026

Øyvind Eriksen

Chair of the board

Trond Brandsrud

Board member

Doris Reiter

Board member

Kjell Inge Røkke

Board member

Kate Thomson

Board member

Ingard Haugeberg

Board member

Anne Marie Cannon

Deputy chair

Charles Ashley Heppenstall

Board member

Zeala Fortescue

Board member

Tore Vik

Board member

Karl Johnny Hersvik

Chief executive officer

Stine Bjørnvold Bakken

Board member

Marit Hargemark

Board member

Valborg Lundegaard

Board member

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Financial statements

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Statement of financial position

(USD million)

Note

Group

Parent

31.12.2025

31.12.2024

31.12.2025

31.12.2024

Equity and liabilities

Equity

Share capital

Note 21

84.3

84.3

84.3

84.3

Share premium

12,946.6

12,946.6

12,946.6

12,946.6

Other equity

-1,804.7

-339.9

-1,804.7

-339.8

Total equity

11,226.2

12,691.1

11,226.3

12,691.2

Non-current liabilities

Deferred taxes

Note 11

16,001.2

12,990.0

16,001.2

12,990.0

Long-term abandonment provision

Note 23

4,576.0

4,147.7

4,576.0

4,147.7

Long-term bonds

Note 22

8,358.6

7,336.8

8,358.6

7,336.8

Long-term derivatives

Note 24

0.6

55.3

0.6

55.3

Long-term lease debt

Note 26

712.7

458.0

712.7

458.0

Total non-current liabilities

29,649.0

24,987.8

29,649.0

24,987.8

Current liabilities

Trade creditors

692.6

329.1

692.6

329.1

Short-term bonds

Note 22

307.2

160.8

307.2

160.8

Accrued public charges and indirect taxes

46.3

40.8

46.3

40.8

Tax payable

Note 11

1,052.8

2,433.6

1,052.8

2,433.6

Short-term derivatives

Note 24

3.4

151.7

3.4

151.7

Short-term abandonment provision

Note 23

93.4

131.7

93.4

131.7

Short-term lease debt

Note 26

359.4

217.7

359.4

217.7

Other current liabilities

Note 25

1,375.7

1,048.5

1,375.6

1,048.4

Total current liabilities

3,930.7

4,514.0

3,930.6

4,513.9

Total liabilities

33,579.8

29,501.7

33,579.7

29,501.7

Total equity and liabilities

44,806.0

42,192.9

44,806.0

42,192.8

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Signatures – Board of Directors and chief executive officer

The board of directors and the chief executive officer of Aker BP ASA Fornebu, 24 March 2026

Øyvind Eriksen

Chair of the board

Trond Brandsrud

Board member

Doris Reiter

Board member

Kjell Inge Røkke

Board member

Kate Thomson

Board member

Ingard Haugeberg

Board member

Anne Marie Cannon

Deputy chair

Charles Ashley Heppenstall

Board member

Zeala Fortescue

Board member

Tore Vik

Board member

Karl Johnny Hersvik

Chief executive officer

Stine Bjørnvold Bakken

Board member

Marit Hargemark

Board member

Valborg Lundegaard

Board member

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Statement of cash flows

(USD million)

Note

Group

Parent

2025

2024

2025

2024

Cash flow from financing activities

Net drawdown/repayment/fees related to revolving credit facility

-6.0

-1.5

-6.0

-1.5

Repayment of bonds

-63.6

-645.5

-63.6

-645.5

Net proceeds from bond issue

988.4

2,287.7

988.4

2,287.7

Interest paid (including interest element of lease payments)

-394.8

-266.0

-394.8

-266.0

Payments on lease debt related to investments in fixed assets

-114.2

-52.6

-114.2

-52.6

Payments on other lease debt

-164.4

-106.5

-164.4

-106.5

Paid dividend

-1,592.7

-1,516.9

-1,592.7

-1,516.9

Net purchase/sale of treasury shares

-5.6

17.0

-5.6

17.0

Net cash flow from financing activities

Note 29

-1,352.9

-284.2

-1,352.9

-284.2

Net change in cash and cash equivalents

-1,900.7

823.4

-1,900.7

823.3

Cash and cash equivalents at start of period

4,146.9

3,388.4

4,146.9

3,388.4

Effect of exchange rate fluctuation on cash and cash equivalents

97.9

-64.8

97.9

-64.8

Cash and cash equivalents at end of period

Note 20

2,344.1

4,146.9

2,344.1

4,146.9

Specification of cash equivalents at end of period

Bank deposits, cash and cash equivalents

2,314.1

4,125.8

2,314.1

4,125.7

Restricted bank deposits

30.1

21.2

30.1

21.2

Cash and cash equivalents at end of period

Note 20

2,344.1

4,146.9

2,344.1

4,146.9

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Goodwill allocation and methodology for impairment testing

For the purpose of impairment testing, goodwill is allocated to a cash-generating unit (CGU), or groups of CGUs that are expected to benefit from the synergies of the business combination from which it arose. A CGU is typically a producing field or a group of producing licences for which a separate offtake facility exists that can generate separate cash flows. The allocation of goodwill requires judgement and may significantly impact any subsequent impairment charge. Although not an IFRS term, 'technical goodwill' is used by Aker BP to describe the category of goodwill arising as an offsetting account to deferred tax liabilities recognised in business combinations, as described in section 1.6 below. There are no specific IFRS guidelines pertaining to the allocation of technical goodwill, and management has therefore applied the general guidelines for allocating goodwill. In general, technical goodwill is allocated at the CGU level for impairment testing purposes, while residual goodwill may be allocated across all CGUs based on the facts and circumstances of the business combination.

When performing the impairment test for technical goodwill, deferred tax liabilities recognised in relation to the acquired licences reduce the net carrying value prior to any impairment charges. This methodology avoids an immediate impairment of all technical goodwill. When deferred tax liabilities from the initial recognition decreases, additional technical goodwill is ‘exposed’ to impairment. Subsequent to the initial purchase price allocation, depreciation of book values will result in decreasing deferred tax liabilities. When applicable, technical goodwill is impaired before the asset.

Since Aker BP operates in a single segment, impairment testing for residual goodwill is conducted at the company level based on its corporate valuation. As a starting point, if the fair value of the company’s equity exceeds its book value, no impairment is recorded.

Proven and probable oil and gas reserves

Oil and gas reserves are estimated by the company’s reservoir experts in accordance with industry standards. The estimates are based on Aker BP’s own assessment of internal information and information received from operators. In addition, proven and probable reserves are certified by an external party. Proven and probable oil and gas reserves consist of the estimated quantities of crude oil, natural gas and condensates shown by geological and technical data to be recoverable with reasonable certainty from known reservoirs under existing economic and operational conditions, i.e., on the date that the estimates are prepared. Current market prices are used in the estimates.

Changes in petroleum prices and cost estimates may affect reserve estimates and accordingly the economic cut-off, which may impact the timing of assumed decommissioning and removal activities. Changes to reserve estimates can also result from updated production and reservoir information. Future changes to proven and probable oil and gas reserves can have a material effect on life of field, depreciation, impairment of licence-related assets and goodwill, decommissioning and removal obligation, and operating profit/loss.

Accounting for exploration costs – application of the successful effort method

Expenses relating to the drilling of exploration wells are temporarily recognised in the statement of financial position as capitalised exploration expenditures, pending an evaluation of potential oil and gas discoveries. If resources are not discovered, or if recovery of the resources is considered technically or commercially unviable, the costs of exploration wells are expensed. Judgements as to whether this expenditure should remain capitalised or be expensed at the reporting date may materially affect the operating result for the period.

Fair value measurement

The fair values of non-financial assets and liabilities are required to be determined, for example in a business combination, to determine the allocation of purchase price in an asset transaction or when the recoverable amount of an asset or CGU is based on fair value less cost to sell. 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 at the measurement date. The fair value of an asset or a liability is measured using the assump-tions that market participants would use when pricing the asset or liability.

A fair value measurement of a non-financial asset takes into account a market participant's ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use. The group uses valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value, maximising the use of relevant observable inputs and minimising the use of unobservable inputs. The fair value of oil fields in production and development phase is normally based on discounted cash flow models, where the determination of inputs to the model may require significant judgement, as described in the section below regarding impairment.

Impairment/reversal of impairment

The evaluation of impairment requires long-term assumptions concerning a number of often volatile economic factors, including future oil and gas prices, oil and gas production, currency exchange rates and discount rates. Such assumptions require the estimation of relevant factors such as long-term prices, production estimates, the levels of capital expenditures (capex) and operating expenditures (opex), and decommissioning and removal costs (abex). These evaluations are also necessary to determine a CGU’s fair value unless information can be obtained from an actual observable market transaction. See Note 13, page 162and Note 14, page 165.

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Decommissioning and removal obligations

The company has obligations to decommission and remove offshore installations at the end of their production period. The estimates include costs based on expected removal concepts using existing technology and estimated costs of maritime operations, hiring of single-lift and heavy-lift barges and drilling rigs. There is significant future uncertainty in the estimate of costs for decommissioning and removal, as these estimates are based on currently applicable laws and regulations, and existing technologies. Many decommissioning and removal activities will take place many decades in the future, and the technology and related costs are expected to evolve in this time. As a result, there may be significant adjustments to the estimates of decommissioning liabilities and associated assets that can affect future financial results. See Note 23, page 171for further details about decommissioning and removal obligations.

Income tax

Income tax expense, tax payables or receivables, and deferred taxes are based on management’s interpre-tation of applicable laws and regulations, and on relevant court decisions where relevant. These estimates are dependent on management’s ability to interpret and apply the requirements of tax and other relevant legislation, and requires judgement in respect of the recognition and measurement of any uncertain tax positions. See Note 11, page 160for further details.

1.4 Revenue recognition

Revenue from the sale of liquids or gas is recognised at the point in time when the company’s contractual performance obligations have been fulfilled and control is transferred to the customer, which will ordinarily be at the point of delivery when title passes (sales method). This is normally at the time of loading oil or NGL on vessels used for transport, or at agreed point of delivery for dry gas.

There is no significant judgement applying IFRS 15 ‘Revenue from contracts with customers’ to the company’s revenue generating contracts.

Changes in over/underlift balances are valued at production cost including depreciation and presented as an adjustment to cost. See Note 6, page 156for further details.

Gains or losses on asset disposals as described in section 1.7 are included in other operating income.

Tariff revenue from processing of oil and gas is recognised as earned in line with underlying agreements.

1.5 Interests in licences and partnerships

The company has interests in licences on the Norwegian continental shelf. Under IFRS 11 Joint Arrangements, a joint operation is 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. The company recognises investments in joint operations (oil and gas production licences) by reporting its share of related revenues, expenses, assets, liabilities and cash flows under the respective items in the company's financial statements.

IFRS defines a joint arrangement as an arrangement over which two or more parties have joint control. Joint control is the contractually agreed sharing of control which exists only when decisions about the relevant activities (being those that significantly affect the returns of the arrangement) require unanimous consent of the parties sharing control.

For those licences that are not deemed to be joint arrangements pursuant to the definition in IFRS 11 as there is no joint control, the company recognises its share of related expenses, assets, liabilities and cash flows on a line-by-line basis in the financial statements by analogy to IFRS 11 and in accordance with applicable IFRSs.

1.6 Business combinations and goodwill

In a business combination, goodwill is allocated to the CGUs or groups of CGUs that are expected to benefit from synergies of the acquisition. The allocation of goodwill may vary depending on the basis for its initial recognition. Goodwill resulting from business combinations is separated in two classes of goodwill.

If the acquisition cost at the time of the acquisition exceeds the fair value of the acquired net assets, residual goodwill arises. Residual goodwill represents the ability to capture synergies that can be realised from managing a larger portfolio of both acquired and existing fields on the Norwegian continental shelf, including workforce. The residual goodwill is tested for impairment on an operating segment level at least annually. Aker BP operates in one single operating segment and residual goodwill is thus tested for impairment on company level based on a corporate valuation of the company. As a starting point, if the fair value of the company’s equity, exceeds the book value of equity, no impairment is recorded.

The other class of goodwill is related to the requirement to recognise deferred tax for the difference between the assigned fair values and the related tax base ('technical goodwill'). The fair value of the compa-ny’s licences, all of which are located on the Norwegian continental shelf, are based on cash flows after tax. This is because these licences are only sold in an after-tax market based on the tax carry-over principles pursuant to the Petroleum Taxation Act section 10. The purchaser is therefore not entitled to a tax deduc-tion for the consideration paid over and above the seller’s tax values. In accordance with IAS 12 paragraphs 15 and 24, a provision is made for deferred tax corresponding to the difference between the acquisition cost and the transferred tax depreciation basis. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax. Technical goodwill is tested for impairment separately for each CGU which give rise to the technical goodwill. A CGU may be individual oil fields, or a group of oil fields that are connected to the same infrastructure/production facilities.

1.7 Acquisitions, sales and licence swaps

On acquisition of a licence that involves the right to explore for and produce petroleum resources, it is considered in each case whether the acquisition should be treated as a business combination (see section 1.6) or an asset purchase. Generally, purchases of licences in a development or production phase will be regarded as a business combination. Other licence purchases regarded as asset purchases are described below.

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Oil and gas production licences

For licences in the development phase, the acquisition cost is allocated between capitalised exploration expenses, licence rights (other intangible assets) and production plant (tangible fixed assets).

When entering into agreements regarding the purchase/swap of assets, the parties agree on an effective date for the takeover of the net cash flow (usually 1 January in the calendar year which would also normally be the effective date for tax purposes). In the period between the effective date and the completion date, the seller will include its sold share of the licence in the financial statements. In accordance with the purchase agreement, there is a settlement with the seller of the net cash flow from the asset in the period from the effective date to the completion date (pro & contra settlement). The pro & contra settlement will be adjusted to the seller’s losses/gains and to the assets for the purchaser, in that the settlement (after a tax reduction) is deemed to be part of the consideration in the transaction. Revenues and expenses from the relevant licence are included in the purchaser’s income statement from the acquisition date.

For tax purposes, the purchaser will include the net cash flow (pro & contra) and any other income and costs as from the effective date.

Deferred tax is not recognised when acquiring licences that are defined as asset acquisitions.

1.8 Tangible fixed assets and intangible assets

General

Tangible fixed assets are recognised on a historical cost basis.

Gains and losses relating to the disposal of assets are determined by comparing the selling price with the book value, and are included in other operating income/expenses on a post-tax basis, to the extent the selling price is on a post-tax basis.

Operating assets related to petroleum activities

Exploration and development costs relating to oil and gas fields

Capitalised exploration expenditures are classified as intangible assets and reclassified to tangible assets at the start of development. For accounting purposes, the field is considered to enter the development phase when the technical feasibility and commercial viability of extracting hydrocarbons from the field are demon-strable, normally at the time of concept selection. All costs relating to the development of commercial oil and/or gas fields are recognised as tangible assets. Pre-operational costs are expensed as they are incurred.

The company employs the ’successful efforts’ method to account for exploration and development costs. All exploration costs (including seismic shooting, seismic studies and 'own time’), with the exception of acquisition costs of licences and drilling costs for exploration wells, are expensed as incurred. When explo-ration drilling is ongoing in a period after the reporting date and the result of the drilling is subsequently not successful, the capitalised exploration cost as of the reporting date is expensed if the evaluation of the well is completed before the date when the financial statements are authorised for issue.

Drilling cost for exploration wells are temporarily capitalised pending the evaluation of potential discoveries of oil and gas resources. Such costs can remain capitalised for more than one year. The main criteria is that there must be plans for future activity in the licence area or that a development decision is expected in the near future. If no resources are discovered, or if recovery of the resources is considered technically or commercially unviable, expenses relating to the drilling of exploration wells are charged to expense.

Other intangible assets

Acquired licence rights are recognised as intangible assets at the time of acquisition. Acquired licence rights related to fields in the exploration phase remain as intangible assets also when the related fields enter the development or production phase.

Depreciation of oil and gas fields

Capitalised exploration and evaluation expenditures, development expenditures from construction, installation or completion of infrastructure facilities such as platforms, pipelines and production wells, and field-dedicated transport systems for oil and gas are capitalised as production facilities and are depreciated using the unit-of-production method based on proven and probable developed reserves expected to be recovered from the area during the concession or contract period. Acquired assets used for the recovery and production of petroleum deposits, including licence rights, are also depreciated using the unit-of-pro-duction method based on proven and probable reserves. The reserve basis used for depreciation purposes is updated at least annually. Any changes in the reserves affecting unit-of-production calculations are reflected prospectively.

Depreciation of assets other than oil and gas fields, including right of use assets, is calculated using the straight-line method over estimated useful lives and adjusted for any impairment or change in residual value, if applicable.

1.9 Impairment

Tangible fixed assets and intangible assets

The unit of account for assessment of impairment is based on the lowest level at which it is possible to identify cash inflows that are independent of cash inflows from other groups of fixed assets. For oil and gas assets, this is typically the field or licence level. Impairment is recognised when the book value of the CGU (including any allocated goodwill) exceeds the recoverable amount. When estimating value in use and fair value less cost to sell, expected future cash flows are discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money and the specific risk related to the asset. The discount rate is derived from the Weighted Average Cost of Capital (WACC).

The lifetime of the field for the purpose of impairment testing is normally determined by the point in time when the operating cash flow from the field becomes negative.

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For exploration licences, impairment is based on an assessment of whether plans for further activities have been established or, if applicable, an evaluation of whether development will be decided on in the near future as described in section 1.8.

A previously recognised impairment can only be reversed if changes have occurred in the estimates used for the calculation of the recoverable amount.

Goodwill

Goodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that the value may be impaired.

Impairment is recognised if the recoverable amount of the CGU (or group of CGUs) to which the technical goodwill is related is less than the book value, including associated goodwill and deferred tax as described in section 1.6, which also includes information about residual goodwill. Losses relating to impairment of goodwill cannot be reversed in future periods.

1.10 Financial instruments

The group’s financial assets and liabilities comprise non-listed equity instruments, derivative financial instruments (assets and liabilities), receivables, financial investments, cash and cash equivalents, payables, other current liabilities and non-current liabilities. The classification of financial assets and liabilities at initial recognition depends on the financial instrument’s contractual cash flow characteristics and the group’s business model for managing them. The company has classified the financial instruments into the following categories of financial assets and liabilities:

Financial assets at fair value through profit or loss

Financial assets measured at amortised cost

Financial liabilities at fair value through profit or loss

Financial liabilities measured at amortised cost

The group’s financial instruments at amortised cost includes trade receivables with the objective hold to collect and other short-term deposits, trade payables and other current and non-current liabilities. Receivables are initially recognised at fair value less impairment losses.

All borrowings are initially recognised at transaction price, which equals the fair value of the amount received net of costs directly related to the establishment of the loan or issuance of debt.

Subsequently, interest-bearing borrowings are valued at amortised cost using the effective interest method; the difference between the transaction price (after transaction costs) and the face value is recognised in the income statement in the period until the loan falls due. Amortised cost is calculated by considering all issue costs on the settlement date.

Financial liabilities that do not form part of the 'held for trading purposes' category and which have not been designated as being at fair value with changes in value through profit or loss are classified as other financial liabilities.

Further details on fair values of financial instruments are provided in Note 29, page 176.

1.11 Presentation of payroll and administration costs

The company presents its payroll and administration costs based on the functions in development, operational and exploration activities respectively, based on allocation of registered hours worked, net of amounts recharged to partners on operated licences.

1.12 Leases

The lease liability is recognised at the commencement date and measured at the present value of the remaining lease payments, discounted using the company's incremental borrowing rate at the commence-ment date. The borrowing rate is derived from the terms of the company's existing credit facilities.

Right-of-use (RoU) assets are depreciated over the lease term as this is ordinarily shorter than the useful life of the assets.

The company applies the exemption for short-term leases (12 months or less) and low value leases. As such, related lease payments are not recognised in the balance sheet, but expensed or capitalised in line with the accounting treatment for other non-lease expenses. The inclusion of non-lease components may vary across different lease categories, but for the most material class of assets (rigs), the company has excluded the non-lease components when measuring the lease liability.

Lease agreements that are planned to be applied on several operated licences, are generally recognised on a gross basis as Aker BP is deemed to be the primary obligator. The company may enter into lease contracts as an operator on behalf of a licence, and may for such leases only recognise its net share of the related lease liability. Whether a contract is entered into on behalf of the licence is subject to a contract specific assessment. For lease contracts recognised on a gross basis, the partner's share of the cost recovered by the company are presented as other income.

1.13 Borrowing costs

Borrowing costs that can be directly ascribed to procurement, processing or production of a qualifying asset are capitalised as part of the asset’s acquisition cost. Borrowing cost is only capitalised during the development phase. Other borrowing costs are expensed in the period in which they are incurred.

In principle, borrowing costs include interest expenses calculated using the effective interest method in accordance with IFRS 9 and exchange differences arising from foreign currency borrowings to the extent that they are regarded as an adjustment to interest costs.

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The calculated capitalisation rate should at any time be based on the weighted average interest rate for the last twelve months. This calculated interest rate is used to the extent that capitalised interest does not exceed borrowing cost incurred within one quarter.

A qualifying asset is one that necessarily takes a substantial period of time (minimum 12 months) to be made ready for its intended use or sale. Qualifying assets are generally those that are subject to major development or construction projects.

1.14 Inventories

Inventories mainly consist of equipment for the drilling of exploration and production wells and are valued at the lower of cost price (based on weighted average cost) and net realisable value.

1.15 Cash and cash equivalents

Cash and cash equivalents include cash, bank deposits, and other short-term highly liquid investments with an original due date of three months or less. Bank overdrafts are included in the statement of financial position as short-term loans.

1.16 Tax

General

Tax consists of tax payable and changes in deferred tax. Deferred tax/tax benefits are calculated on the basis of the differences between book value and tax basis values of assets and liabilities, with the exception of temporary differences on acquisition of licences that are defined as asset purchases.

Deferred tax is measured using the expected tax rate when the tax benefit is realised or the tax liability is met, based on tax rates and tax regulations that have been enacted or substantively enacted at the reporting date.

Tax payable and deferred tax is recognised directly against equity or other comprehensive income insofar as the tax items are related to equity transactions or items of other comprehensive income.

Deferred tax and tax benefits are presented net, where netting is legally permitted and the deferred tax benefit and liability are related to the same tax subject and are payable to the same tax authorities.

Functional currency

The company’s functional currency is USD, while it is a statutory requirement to calculate the current tax based on NOK functional currency. This may impact the effective tax rate when the exchange rate between NOK and USD fluctuates. The revaluation of tax receivable and payable is presented as foreign exchange gain/loss, while the impact on deferred tax from revaluation of tax balances is presented as tax expense/income.

Petroleum taxation

As an oil and gas company in Norway, Aker BP is subject to the special provisions of the Petroleum Taxation Act. Taxable profits from activities on the Norwegian continental shelf are liable to ordinary company tax and special tax. The overall tax rate for activities according to the Petroleum Taxation Act is 78 percent.

The ordinary company tax is 22 percent. In addition, the company is subject to a special petroleum tax of 71.8 percent. The special petroleum tax is a cash-based tax and companies can make immediate deduc-tions for expenses incurred. In addition, the corporate tax (22 percent) is deductible in the special tax base (71.8 percent) in order to maintain the overall tax rate of 78 percent.

Tax depreciation and uplift

Investments in pipelines and production facilities can be depreciated by up to 16 2/3 percent annually, i.e., using the straight-line method over six years. Tax depreciation commences when the expenses are incurred. When a field stops producing, any remaining tax values may be deducted in that year. Changes to the Petroleum Taxation Act were enacted in June 2022 with effect from 1 January 2022. Under the new rules, investments are immediately deducted in the special tax base, while the ordinary depreciation rules still apply to the corporate tax base.

Uplift is a special income deduction in the basis for calculation of special tax. Uplift is calculated on the basis of investments in pipelines and production facilities and can be regarded as an extra depreciation deduction in the special tax regime. The uplift rate is 12.4 percent and from 2023 uplift is only applicable for investments covered by the temporary changes enacted to the Petroleum Tax Act in 2020. The temporary changes are applicable for investments up to and including year of production start in accordance with new PDOs delivered within 31 December 2022 and approved within 31 December 2023.

Financial items

Interest on debt with associated currency losses/gains is distributed between the offshore and onshore tax regimes. Offshore interest deduction is calculated as the net financial costs of interest-bearing debt multiplied by 50 percent of the ratio between net asset value for tax purposes allocated to the offshore tax regime as of 31 December in the income year and the average interest-bearing debt through the income year.

Remaining financial expenses, currency losses and all interest income as well as currency gains are allocated to the onshore jurisdiction.

Uncovered losses in the onshore tax jurisdictions resulting from the distribution of net financial items can be allocated to the offshore tax jurisdictions and deducted from regular income.

Only 50 percent of other losses in the onshore tax jurisdictions are permitted to be reallocated to the offshore tax jurisdictions as deductions in regular income.

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Tax loss

Corporate tax losses are carried forward without time limitations for companies subject to special tax. Special petroleum tax losses are reimbursed by the state in the following year as part of the ordinary tax assessment. The tax position can be transferred on realisation of the company or merger.

1.17 Provisions

Decommissioning and removal costs

In accordance with the licence terms and conditions for the licences in which the company participates, the Norwegian State can require licence owners to remove the installation in whole or in part when production ceases or the licence period expires.

In the initial recognition of the decommissioning and removal obligations, the company provides for the net present value of future costs related to decommissioning and removal based on its working interest in the respective fields. A corresponding asset is capitalised as a tangible fixed asset and depreciated using the unit-of-production method. Changes in the time value (net present value) of the obligation related to decommissioning and removal accretion are charged to the income statement as financial expenses and increase the balance-sheet liability related to future decommissioning and removal expenses. Changes in the best estimate for expenses related to decommissioning and removal are recognised in the statement of financial position (property, plant and equipment), except where it relates to licences with no future production or where the company will be charged a portion of the liability as a user, i.e., based on shipped volumes. The discount rate used in the calculation of the fair value of the decommissioning and removal obligation is the risk-free rate.

1.18 Segment

Since its formation, the company has conducted its entire business in one consistent segment, defined as exploration for and production of petroleum in Norway. The company conducts its activities on the Norwegian continental shelf, and management monitors the company at this level. The financial informa-tion relating to geographical distribution and large customers is presented in Note 4, page 155.

1.19 Changes to accounting standards and interpretations that:

Have entered into force:

The group has applied the following standards and amendment for the first time for their annual reporting period commencing 1 January 2025:

Amendments to IAS 21 – Lack of Exchangeability

The application of the amendment did not have a material impact on the financial statements in 2025.

Have been issued but have not entered into force:

Certain new accounting standards and interpretations have been issued, but are not yet effective as of 31 December 2025. The group has not early adopted these standards. Except as noted below, these standards are not expected to have a material impact on the group in the current or future reporting periods.

IFRS 18 – Presentation and Disclosure in Financial Statements

In April 2024, the International Accounting Standards Board (IASB) issued IFRS 18 Presentation and Disclosure in Financial Statements, replacing IAS 1. IFRS 18 is effective for annual reporting periods beginning on or after 1 January 2027, with early adoption permitted.

IFRS 18 introduces significant changes to the structure and content of the primary financial statements, with a particular focus on the statement of profit or loss. Key requirements include:

New mandatory subtotals, including

Operating profit

Profit before financing and income taxes

Disclosure of management defined performance measures (MPMs), requiring entities to present, reconcile, and explain these subtotals when used in public communications.

Revised principles for aggregation and disaggregation, enhancing clarity and comparability of financial information.

A shift of some presentation related guidance from IAS 1 to IAS 8 and IFRS 7 as part of consequential amendments.

The group is currently assessing the potential impacts of IFRS 18. Although IFRS 18 may change the presentation of the group’s primary statements — particularly subtotals in the statement of profit or loss — the standard does not change recognition or measurement requirements. Based on the current assessment, IFRS 18 is not expected to have a material impact on the group’s net profit or equity, but will require re-presentation of comparative information and updates to note disclosures upon adoption.

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Employee share programme

The company has an annual share purchase programme for all employees, including senior executives. The shares in the programme are offered at a 20 percent discount to market value and are subject to a three-year lock-up during which employees are not allowed to sell the shares. In connection with the share purchase programme, all employees are also offered an interest-free loan of 60 percent of the basic amount in the National Insurance Scheme ('G'), to be repaid within one year. In total, employees subscribed for USD 24.6 million in 2025, compared to USD 22.4 million in 2024.

Remuneration for the executive management team (EMT)

Information about remuneration to the EMT is provided in the remuneration report in the annual report.

Accounting information regarding the share-based long-term incentive plan (LTIP)

The LTIP for members of the EMT is described in the remuneration report, while certain required accounting information is included below.

The fair value of the grants issued in the LTIP has been measured using a Monte Carlo simulation. Service conditions were not taken into account when measuring fair value. The post-vesting lock-in condition has been incorporated into the grant date fair value by applying a discount to the valuation by estimating the probability that the employees will not comply with this condition. The LTIP agreement includes a clawback clause.

The inputs used in the measurement of the 1 July 2025 grant date fair values were as follows:

Fair value at grant date

NOK 269.17

Aker BP share price at grant date

NOK 257.73

Expected volatility:

Aker BP

31%

Oslo Energy Index

27%

STOXX Europe 600 Oil & Gas Index

21%

S&P Commodity Producers Oil & Gas Exploration & Production Index

27%

Expected life

3 years

Risk free interest rate (based on government bonds)

3.5%

Expected volatility has been based on an evaluation of the historical volatility of the company’s share price, particularly over the historical period commensurate with the expected term. The expected term of the grants has been based on a three-year vesting period.

Total number of shares owned by members of EMT

Name

Total number of shares 20251)

Karl Johnny Hersvik (chief executive officer)

25,894

David Tønne (chief financial officer)

28,603

Per Harald Kongelf (chief operating officer)

6,148

Paula Doyle (chief digital officer)

2,893

Thomas D. Hoff-Hansen (chief information officer)

6,447

Knut Sandvik (SVP projects execute)

8,657

Marte Mogstad (SVP projects growth)

4,299

Tommy Sigmundstad (SVP drilling and wells)

2,381

Marit Blaasmo (SVP people and safety)

12,391

Thomas Øvretveit (SVP operations)

3,489

Georg Vidnes (SVP Eiga)

5,746

Ine Dolve (SVP Alvheim)

10,095

Lars Høier (SVP Yggdrasil)

13,785

Ole Johan Molvig (SVP Valhall)

26,382

Talar Arif (SVP Ula)

16,833

Torbjørg Opedal (SVP Skarv)

2,716

Total

176,759

The numbers include shares held by each member’s close associates, as defined by the Norwegian Accounting Act.

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Remuneration and shares owned by the BoD

The table below includes regular fees to the BoD and fees for participation in the BoD's subcommittees. Fees to board members are paid in NOK and converted to USD using a yearly average USD/NOK-rate of 10.3912 for 2025. Corresponding rate for 2024 was 10.7433. The total number of shares includes shares held by each member’s close associates, as defined by the Norwegian Accounting Act.

Name

Comments

2025

2024

Fee (USD 1,000)

Total number of shares

Fee (USD 1,000)

Total number of shares

Øyvind Eriksen1)

Chair of the BoD and chair of the organisational development and compensation committee

102

-

95

-

Anne Marie Cannon

Deputy chair of the BoD, member of the audit and risk committee and member of the organisational development and compensation committee

71

12,078

62

12,078

Kjell Inge Røkke2)

Board member

46

-

28

1,200

Trond Brandsrud

Board member and chair of the audit and risk committee

69

-

62

-

Kate Thomson3)

Board member and member of the audit and risk committee

-

-

-

-

Charles Ashley Heppenstall

Board member

46

852,587

41

852,587

Valborg Lundegaard1)

Board member and member of the audit and risk committee

59

-

42

-

Doris Reiter3)

Board member

-

-

-

-

Marit Hargemark

Employee-elected member and member of the organisational development and compensation committee

27

706

23

706

Ingard Haugeberg

Employee-elected member

23

2,172

20

1,663

Tore Vik

Employee-elected member

23

8,284

20

6,954

Zeala Fortescue4)

Employee-elected member

7

2,404

N/A

N/A

Stine Bjørnvold Bakken4)

Employee-elected member

7

4,531

N/A

N/A

Sarah Alexandra Berg

Deputy employee-elected member

3

3,881

3

3,118

Rune Karstein Fauskanger

Deputy employee-elected member

3

12,589

3

11,571

Ani Isabel Chiang5)

Deputy employee-elected member

20

1,976

20

1,671

Ole Martin Teien6)

Deputy employee-elected member

0

1,769

N/A

N/A

Charlotte Bårdsen Torvestad6)

Deputy employee-elected member

0

8,268

N/A

N/A

Member until 31.10.20257)

Thomas Husvæg

Employee-elected member

26

N/A

44

847

Hilde K. Brevik

Deputy employee-elected member

2

N/A

3

2,022

Geir Smaaskjær

Deputy employee-elected member

2

N/A

3

2,805

Terje Solheim

Deputy employee-elected member

2

N/A

2

637

Total

541

911,245

471

897,859

Fees to board members employed in the Aker ASA group will be paid to the company, not to the board member in person.

Kjell Inge Røkke owns and controls TRG Holding AS, which controls 68 percent of Aker ASA, which through a subsidiary owns 21 percent of Aker BP.

Board members employed by BP plc groups have forfeited their board fees.

Employee-elected member from 01.11.2025.

Employee-elected member until 31.10.2025. Deputy employee-elected member from 01.11.2025.

Deputy employee-elected member from 01.11.2025.

The number of shares is not provided for board members who have left the board during 2025.

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Tangible fixed assets – Right-of-use assets

(USD million)

Group and parent

Drilling rigs

Vessels and boats

Office

Other

Total

Book value 31.12.2023

561.4

37.4

55.1

1.4

655.3

Acquisition cost 31.12.2023

591.0

51.2

95.5

2.3

740.0

Additions

149.9

-

-

-

149.9

Allocated to abandonment activity

-24.9

-

-

-

-24.9

Disposals/retirement

-

-

-20.7

-

-20.7

Reclassification1)

-97.6

-

-

-

-97.6

Acquisition cost 31.12.2024

618.5

51.2

74.8

2.3

746.8

Accumulated depreciation and impairment 31.12.2023

29.7

13.8

40.4

0.9

84.7

Depreciation

67.8

6.7

15.0

0.2

89.6

Impairment/reversal (-)

-

-

-

-

-

Disposals/retirement depreciation

-

-

-6.3

-

-6.3

Accumulated depreciation and impairment 31.12.2024

97.5

20.4

49.0

1.1

168.0

Book value 31.12.2024

521.0

30.8

25.8

1.2

578.8

Acquisition cost 31.12.2024

618.5

51.2

74.8

2.3

746.8

Additions

544.8

-

117.3

0.7

662.9

Allocated to abandonment activity

-1.8

-

-

-

-1.8

Disposals/retirement

-

-

-36.6

-0.3

-36.9

Reclassification1)

-136.0

-

-

-

-136.0

Acquisition cost 31.12.2025

1,025.6

51.2

155.5

2.7

1,235.0

Accumulated depreciation and impairment 31.12.2024

97.5

20.4

49.0

1.1

168.0

Depreciation

119.0

6.7

16.6

0.2

142.5

Impairment/reversal (-)

-

-

-

-

-

Disposals/retirement depreciation

-

-

-36.6

-0.3

-36.9

Accumulated depreciation and impairment 31.12.2025

216.5

27.1

29.1

0.9

273.5

Book value 31.12.2025

809.1

24.1

126.4

1.8

961.5

Reclassified to tangible and intangible fixed assets in line with the activity of the right-of-use asset.

See Note 26, page 173for information regarding leases.

Right-of-use assets are depreciated linearly over the lifetime of the related lease contract.

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Intangible assets

(USD million)

Group and parent

Goodwill

Capitalised exploration expenditures

Other intangible assets

Depreciated

Not depreciated

Total

Book value 31.12.2023

13,142.8

325.4

1,342.0

781.4

2,123.4

Acquisition cost 31.12.2023

15,014.1

544.3

2,440.4

947.6

3,388.1

Additions

-

338.7

-

5.9

5.9

Expensed dry wells

-

-194.1

-

-

-

Disposals/retirement

-

-

-

-

-

Reclassification1)

-

-14.2

128.1

-128.1

-

Acquisition cost 31.12.2024

15,014.1

674.7

2,568.5

825.4

3,393.9

Accumulated depreciation and impairment 31.12.2023

1,871.4

218.9

1,098.4

166.3

1,264.7

Depreciation

-

-

191.7

-

191.7

Impairment/reversal (-)

386.2

35.4

-

-

-

Disposals/retirement depreciation

-

-

30.8

-30.8

-

Accumulated depreciation and impairment 31.12.2024

2,257.5

254.4

1,320.8

135.5

1,456.3

Book value 31.12.2024

12,756.6

420.4

1,247.7

689.9

1,937.6

Acquisition cost 31.12.2024

15,014.1

674.7

2,568.5

825.4

3,393.9

Additions

-

319.8

52.0

2.1

54.1

Expensed dry wells

-

-193.7

-

-

-

Disposals/retirement

-

-24.7

-

-9.6

-9.6

Reclassification

-

21.2

-

-

-

Acquisition cost 31.12.2025

15,014.1

797.4

2,620.5

818.0

3,438.4

Accumulated depreciation and impairment 31.12.2024

2,257.5

254.4

1,320.8

135.5

1,456.3

Depreciation

-

-

192.3

-

192.3

Impairment/reversal (-)

1,489.0

0.0

461.3

71.2

532.4

Disposals/retirement depreciation

-

-24.7

-

-0.9

-0.9

Accumulated depreciation and impairment 31.12.2025

3,746.5

229.6

1,974.4

205.8

2,180.2

Book value 31.12.20252)

11,267.6

567.8

646.1

612.2

1,258.3

The reclassification of other intangible assets is mainly related to the Tyrving development project, which entered into production phase during 2024.

As of 31 December 2025, goodwill consists of USD 6,863.3 million in residual goodwill and USD 4,404.3 million in technical goodwill.

Other intangible assets include both planned and producing projects on various fields. The producing projects are depreciated in line with the unit-of-production method for the applicable field.

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Discount rate

The discount rate is derived from the company's weighted average cost of capital (WACC). The capital structure considered in the WACC calculation is derived from the capital structures of an identified peer group and market participants with consideration given to optimal structures. The cost of equity is derived from the expected return on investment by the company's investors. The cost of debt is based on the interest-bearing borrowings on debt specific to the assets acquired. The beta factors are evaluated annually based on publicly available market data about the identified peer group.

The post-tax nominal discount rate used at year end is 8.4 percent. This represents a change from 8.8 percent applied at year end 2024.

Currency rates

Year

USD/NOK

2026

10.12

2027

10.17

2028

10.19

From 2029

10.00

The long-term currency rate is unchanged from year end 2024.

Inflation

The long-term inflation rate is assumed to be 2.0 percent, which is the same as applied at year end 2024. The currently high cost escalation in the industry is reflected in the cash flows rather than in the inflation rate.

Impairment testing of assets including technical goodwill

The technical goodwill recognised in previous business combinations is allocated to each CGU for the purpose of impairment testing. Hence, the impairment test of technical goodwill is included in the impairment testing of assets, and the technical goodwill is written down before the asset. The carrying value of the assets is the sum of tangible assets, intangible assets and technical goodwill as of the assessment date. Deferred tax is incorporated into the post-tax estimate of the fair value, ensuring comparability with the pre-tax carrying amount. When deferred tax liabilities from the acquisitions decreases as a result of depreciation, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable.

Below is an overview of the impairment charge and the carrying value per cash-generating unit where impairment has been recognised in 2025:

Cash-generating unit

Group & parent

(USD million)

Alvheim CGU

Eiga CGU1)

Johan Sverdrup CGU

Valhall CGU

Net carrying value

2,199.6

3,299.8

9,100.3

8,741.3

Recoverable amount

2,091.8

3,156.1

8,170.5

7,901.2

Impairment (+)/reversal (-)

107.8

143.7

929.8

840.2

Allocated as follows:

Technical goodwill

107.8

143.7

929.8

307.7

Other intangible assets2)

-

-

-

532.4

Tangible fixed assets

-

-

-

-

The figures represent the recoverable amount at the end of Q2, as there were no impairments recorded in Q3 or Q4.

USD 71.2 million relates to acquisitions from previous years recognised on a post-tax basis.

The main reason for the impairment is related to decrease in future oil and gas prices and decrease of deferred tax liabilities as described above, in addition to updated cost and production profiles.

Sensitivity analysis

The table below shows how the impairment or reversal of impairment for the fourth quarter would be affected by changes in the various assumptions, given that the remaining assumptions are constant. The figures in the table below are mainly related to impairment of technical goodwill, which would have no impact on deferred tax.

Assumptions

Change

Change in impairment after

(USD million)

Increase in assumption

Decrease in assumption

Oil and gas price forward period

+/- 50%

-943.6

3,115.0

Oil and gas price long-term

+/- 20%

-943.6

2,911.4

Production profile (reserves)

+/- 5%

-860.3

905.8

Discount rate

+/- 1% point

313.9

-316.8

Currency rate USD/NOK

+/- 2.0 NOK

-762.1

1,714.9

Inflation

+/- 1% point

-943.6

1,127.3

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Residual goodwill

Residual goodwill is assessed for impairment at the corporate level, and is based on a comparison between fair value and book value of equity. The fair value is calculated using the share price as of the balance sheet date, converted to USD based on the USD/NOK exchange rate at the end of the period, and adjusted for a control premium (classified as level 3 in the fair value hierarchy). As of year end 2025, the fair value exceeds the book value of equity, and no impairment is thus recognised.

Climate related risks

As mentioned in the future expenditures section, the cash flows applied in the impairment testing include a step up of CO2tax/fees from current levels to approximately NOK 2,500 per tonne (2025 real) in 2030.

Further, as described in Note 3, page 154, a sensitivity analysis has been performed based on various scenarios provided by the International Energy Agency. The results are included in a separate sensitivity test presented below. The price assumptions in those scenarios have been provided by IEA for 2035 and 2050 in real 2024 terms. For the sensitivity calculation, a linear development between the average price for 2024 and IEA price in 2035, as well as between 2035 and 2050 has been applied. The table below summarises how the impairment charge would increase (+) or decrease (-) using the oil and gas price assumptions in the following scenarios:

IEA scenarios

Change in impairment

(USD million)

Stated Policies

Current Policies

Net Zero Emissions by 2050

Valhall CGU

-567.3

-567.3

4,248.8

Skarv CGU

-

-

-

Ula CGU

-

-

-

Alvheim CGU

-72.6

-72.6

277.8

Johan Sverdrup CGU

-303.8

-303.8

984.5

Eiga CGU

-

-

363.7

Yggdrasil CGU

-

-

132.5

Total

-943.7

-943.7

6,007.3

Scenario price ranges

Oil USD/bbl

Gas USD/mmbtu

2035

2050

2035

2050

Stated Policies

80.0

76.0

6.5

8.4

Current Policies

89.0

106.0

9.1

10.6

Net Zero Emissions by 2050

33.0

25.0

4.2

4.0

In addition, capitalised exploration and other related balances have been reviewed as of year end 2025, in order to assess the exposure and dependency of future government approvals of plan for development and operations (PDO). An amount of USD 782 million would have been impaired in a situation where no new project developments would be approved.

Impairment testing in 2024

In 2024, the impairment charge was mainly related to three CGU's and allocated to technical goodwill, in addition to an impairment of exploration assets. The methodology for impairment testing was the same as in 2025 as described in this note.

The following assumptions were applied for the impairment testing at year end 2024:

Discount rate of 8.8 percent nominal after tax for both value in use and fair value testing

Long-term inflation of 2.0 percent

Long-term exchange rate of NOK/USD 10.0 (forward curve first three years)

Long-term oil price assumption (real 2025) of 75.0 USD/boe (forward curve first three years)

Long-term gas price assumption (real 2025) of 0.76 GBP/therm (forward curve first three years)

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Categories of financial assets and financial liabilities - group and parent

Financial assets at fair value through profit and loss

Financial assets measured at amortised cost

Financial liabilities at fair value through profit and loss

Financial liabilities measured at amortised cost

Total

31.12.2024

Assets

Trade receivables

-

914.9

-

-

914.9

Other short-term receivables1)

3.3

402.4

-

-

405.7

Cash and cash equivalents

-

4,146.9

-

-

4,146.9

Long-term receivables

-

69.0

-

-

69.0

Derivatives

5.2

-

-

-

5.2

Total financial assets

8.5

5,533.3

-

-

5,541.8

Liabilities

Derivatives

-

-

207.0

-

207.0

Trade creditors

-

-

-

329.1

329.1

Bonds

-

-

-

7,497.6

7,497.6

Other short-term liabilities

-

-

-

1,048.5

1,048.5

Total financial liabilities

-

-

207.0

8,875.2

9,082.2

Prepayments are not included in other short-term receivables, as they do not meet the definition of financial instruments.

Financial risk

The company has financed its activities with bonds (see Note 22, page 171) and maintains an undrawn revolving credit facility with a syndication of banks (see Note 20, page 169). In addition, the company has financial instruments such as trade receivable, trade creditors, cash balances etc., directly related to its day-to-day operations. For hedging purposes, the company has different types of economic hedging instruments, but no hedge accounting is applied.

Commodity derivatives may be used to mitigate the risk of lower oil and gas prices, while foreign currency exchange derivatives help reduce currency risk.

In 2025, all outstanding notes carries fixed-rate coupons. However, the group has swapped USD 400 million of the senior notes 5.125% 2034 bond from a fixed rate to a floating rate using an interest rate swap starting from October 2026 (see Note 24, page 172).

The most important financial risks which the company is exposed to relate to lower oil and gas prices, change in foreign exchange rates and access to cost efficient funding.

The company's risk management, including financial risk management, is designed to ensure identification, analysis and systematic and cost-efficient handling of risk. Established management procedures provide a sound basis for reporting and monitoring of the company's financial risk exposure.

(i) Commodity price risk

Aker BP's revenues are derived from the sale of petroleum products, and the revenue flow is therefore exposed to oil and gas price fluctuations. The company is continuously evaluating and assessing opportu-nities for hedging as part of a prudent financial risk management process. The company had no material commodity derivatives exposure per 31 December 2025.

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(ii) Currency risk

Revenues from sale of petroleum products are mainly in USD, EUR and GBP, while expenditures are mainly in NOK, USD, EUR and GBP. Sales and expenses in the same currency contribute to mitigating some of the currency risk. Currency derivatives are used to further reduce this risk.

The table below shows the company's exposure in NOK as of 31 December:

Exposure relating to

(USD million)

31.12.2025

31.12.2024

Cash and cash equivalents and receivables

336.9

330.1

Trade creditors, tax payable, leasing liability and other short-term liabilities

-2,397.3

-3,129.6

Net exposure to NOK

-2,060.3

-2,799.6

The amounts above does not include tax balances in NOK, as they are not deemed to be financial instruments. The company's management of currency risk takes into account the USD values of non-USD assets, liabilities, opex and investments over time, including those exposures arising from the requirement to perform the tax calculation in NOK while the company's functional currency is USD.

The table below shows the impact on profit/loss from changes in NOK/USD exchange rate, including the impact from currency derivatives. For further information about currency derivatives, see Note 24, page 172.

(USD million)

Change in exchange rate

31.12.2025

31.12.2024

Effect on pre-tax profit/loss:

+ 10% (stronger USD)

-44.3

-100.6

- 10% (weaker USD)

47.1

108.5

In 2025 the company had EUR/USD exposure related to bonds, cash and cash equivalents and receivables from gas sales. As the company has two senior notes bonds denominated in EUR, there is currency risk associated with the translation into the company’s USD functional currency and the cash payments of interest and principal amounts, though EUR denominated gas sales and EUR time deposit mitigate the risks associated with payments.

The table below shows the company's exposure in EUR as of 31 December:

Exposure relating to

(USD million)

31.12.2025

31.12.2024

Cash and cash equivalents and receivables

403.5

1,186.3

Bonds, trade creditors and other short-term liabilities

-1,927.1

-1,779.0

Net exposure to EUR

-1,523.6

-592.7

The table below shows the impact on profit/loss from changes in EUR/USD exchange rate for the EUR bond, cash and cash equivalents and receivables.

(USD million)

Change in exchange rate

31.12.2025

31.12.2024

Effect on pre-tax profit/loss:

+ 10% (stronger USD)

139.1

53.6

- 10% (weaker USD)

-168.6

-66.2

In 2025 the company had GBP/USD exposure related cash and cash equivalents and receivables from gas sales.

The table below shows the company's exposure in GBP as of 31 December:

Exposure relating to

(USD million)

31.12.2025

31.12.2024

Cash and cash equivalents and receivables

94.5

227.2

Trade creditors and other short-term liabilities

-48.6

-34.6

Net exposure to GBP

45.9

192.5

The table below shows the impact on profit/loss from changes in GBP/USD exchange rate for cash and cash equivalents and receivables.

(USD million)

Change in exchange rate

31.12.2025

31.12.2024

Effect on pre-tax profit/loss:

+ 10% (stronger USD)

-4.1

-17.4

- 10% (weaker USD)

5.2

21.6

The company is also exposed to changes in other exchange rates, but the amounts are deemed immaterial.

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(iii) Interest-rate risk

In 2025, the company had no outstanding debt liabilities exposed to floating interest rate risk. However, the company has swapped USD 400 million of the senior notes 5.125% 2034 bond from a fixed rate to a floating rate using an interest rate swap starting from October 2026. Additionally, the company is exposed to interest-rate risk related to cash and cash equivalents.

The following table shows the company's sensitivity to potential changes in interest rates on cash balances, partly offset by interest rate swap. For further information about interest rate swap, see Note 24, page 172.

Change in interest rate level in basis points

(USD million)

31.12.2025

31.12.2024

Effect on pre-tax profit/loss:

+ 100 points

-2.7

18.3

- 100 points

4.2

-14.6

The terms of the company's debt instruments are described in Note 20, page 169and Note 22, page 171.

(iv) Liquidity risk/liquidity management

The company's liquidity risk is the risk that it will not be able to meet its financial obligations as they fall due.

Short-term (12 months) and long-term (five years) forecasts are prepared on a regular basis to plan the company's liquidity requirements. These plans are updated regularly for various scenarios and form part of the decision basis for the company's management and board of directors.

Available liquidity is defined as the sum of cash and cash equivalents, financial investments and undrawn revolving credit facility. For available liquidity, the requirement for low liquidity risk (i.e. the risk of realisa-tion on short notice) is generally more important than maximising the return. As of 31 December 2025, the company’s available liquidity amounted to USD 5,869 million (USD 7,547 million in 2024). Revenues and expenses are managed on a day-to-day basis for liquidity risk management purposes.

The company deems its maximum liquidity risk exposure to correspond with the book value of cash and cash equivalents, financial investment, trade receivables and other short-term receivables, see Note 15, page 168, Note 16, page 168, Note 19, page 169and Note 20, page 169.

The company's objective for the placement and management of excess capital is to maintain a low risk profile and financial flexibility.

The table below shows the payment structure for the company's financial commitments, based on undis-counted contractual payments. For corresponding information on lease debt and capital commitments and other contractual obligations, reference is made to Note 26, page 173and Note 27, page 174.

Book value

Contract related cash flow

Less than 1 year

1-2 years

2-5 years

over 5 years

Total

31.12.2025

Non-derivative financial liabilities:

Bonds

8,665.8

569.7

365.9

3,376.7

7,827.8

12,140.1

Trade creditors and other liabilities

2,068.3

2,068.3

-

-

-

2,068.3

Derivative financial liabilities

Derivatives

4.0

3.4

0.6

-

-

4.0

Total as of 31.12.2025

10,738.0

2,641.4

366.5

3,376.7

7,827.8

14,212.4

31.12.2024

Non-derivative financial liabilities:

Bonds

7,497.6

336.5

512.3

2,174.3

7,749.7

10,772.7

Trade creditors and other liabilities

1,377.6

1,377.6

-

-

-

1,377.6

Derivative financial liabilities

Derivatives

207.0

151.7

37.9

16.0

1.4

207.0

Total as of 31.12.2024

9,082.2

1,865.8

550.1

2,190.3

7,751.2

12,357.3

(v) Credit risk

The risk of counterparties being financially incapable of fulfilling their obligations is regarded as minor as there have not historically been any losses on trade receivable. The company's customers and licence partners are generally large and credit worthy oil companies. Consequently, no provision for credit losses has been required.

In the management of the company's liquid assets, low credit risk is prioritised. Liquid assets are generally placed in bank deposits that represent a low credit risk. All investments are subject to internal policy that requires a rating equivalent to A-2 from S&P and limits investment with a single counterparty.

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The maximum credit risk exposure corresponds to the book value of financial assets. The company deems its maximum risk exposure to correspond with the book value of cash and cash equivalents, trade receiva-bles, financial investments, derivatives and other short-term receivables, see Note 15, page 168, Note 16, page 168, Note 19, page 169, Note 20, page 169and Note 24, page 172.

Determination of fair value

The fair value of forward exchange contracts is determined using the forward exchange rate at the end of the reporting period. The fair value of commodity derivatives is determined using the forward Brent blend curve at the end of the reporting period. The fair value of interest rate swaps and cross currency interest rate swaps is determined by using the expected floating interest rates at the end of the period and is confirmed by external market sources. See Note 24, page 172for detailed information about the derivatives.

The carrying amount of cash and cash equivalents is approximately equal to fair value, since these instru-ments have short time to maturity. Similarly, the carrying amount of trade receivable, other receivables, trade creditors and other short-term liabilities is materially the same as their fair value as they are entered into on ordinary terms and conditions.

The senior notes are all listed on The Luxembourg Stock Exchange. The fair values for disclosure purposes are determined using the quoted value as of 31 December 2025.

The following is a comparison between the book value and fair value of the company's financial instru-ments, except those where the carrying amount is a reasonable approximation of fair value (such as current trade receivables and payables in addition to instruments measured at fair value).

Fair value of financial instruments

(USD million)

31.12.2025

31.12.2024

Book value

Fair value

Book value

Fair value

Financial liabilities measured at amortised cost:

Bonds

8,665.8

8,593.2

7,497.6

7,240.8

Total financial liabilities

8,665.8

8,593.2

7,497.6

7,240.8

Fair value hierarchy

The company classifies fair value measurements by employing a value hierarchy that reflects the signifi-cance of the input used in preparing the measurements. The fair value hierarchy consists of the following levels:

Level 1 - input in the form of listed (unadjusted) prices in active markets for identical assets or liabilitiesLevel 2 - input other than listed prices of assets and liabilities included in level 1 that is observable for assets or liabilities, either directly (i.e. as prices) or indirectly (i.e. derived from prices)Level 3 - input for assets or liabilities for which there is no observable market data (non-observable input)

Financial instruments recognised at fair value

(USD million)

Level 1

Level 2

Level 3

31.12.2025

Financial assets or liabilities measured at fair value with changes in value recognised through profit or loss:

Other short-term receivables

-

-

-

Long-term receivables

-

-

-

Derivatives

-

110.2

-

31.12.2024

Financial assets or liabilities measured at fair value with changes in value recognised through profit or loss:

Other short-term receivables1)

-

-

3.3

Long-term receivables

-

-

-

Derivatives

-

-201.7

-

The sale of 2.6 percent of Johan Sverdrup during 2019 (made by Lundin) included a contingent consideration based on future reserve reclassifications and was due in 2026. The valuation is considered level 3 in the fair value hierarchy. In Q4 2025, it became evident that the conditions for payment had not been met, and the amount was therefore derecognised.

In the course of the reporting period, there were no changes in the fair value measurements that involved any transfers between levels.

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Reconciliation of cash flows from financing activities

The table below shows a reconciliation between the opening and the closing balances in the statement of financial position for liabilities arising from financing activities.

(USD million)

31.12.2024

Cash flows

Non-cash changes

31.12.2025

Interest expense

Amortisation

Currency

Other1)

Bonds (excluding accrued interest classified as bonds)

7,400.3

924.8

-

27.6

204.2

0.4

8,557.3

Other interest-bearing debt (RCF)

-

-6.0

-

-

-

6.0

-

Accrued interest, classified as bonds and other current liabilities

123.0

-394.8

406.3

-

-

-

134.5

Lease debt

675.6

-278.6

-

-

12.2

662.9

1,072.0

Paid dividends

-

-1,592.7

-

-

-

-

-

Treasury shares

-1.4

-5.6

-

-

-

-

-7.0

Totals

8,197.5

-1,352.9

406.3

27.6

216.3

669.3

9,756.8

(USD million)

31.12.2023

Cash flows

Non-cash changes

31.12.2024

Interest expense

Amortisation

Currency

Other1)

Bonds (excluding accrued interest classified as bonds)

5,798.2

1,642.2

-

38.6

-86.6

7.9

7,400.3

Other interest-bearing debt (RCF)

-

-1.5

-

-

-

1.5

-

Accrued interest, classified as bonds and other current liabilities

85.8

-266.0

303.2

-

-

-

123.0

Lease debt

704.2

-159.1

-

-

-4.8

135.4

675.6

Paid dividends

-

-1,516.9

-

-

-

-

-

Treasury shares

-18.4

17.0

-

-

-

-

-1.4

Totals

6,569.8

-284.2

303.2

38.6

-91.4

144.7

8,197.5

Other includes gain related to repurchase of bonds in 2024, accruals for cost related to bond issue and new leases and remeasurements/lease debt derecognised, as described in Note 26, page 173.

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181

Aker BP annual report 2025

Financials

Licence:

31.12.2025

31.12.2024

PL 359

65.000%

65.000%

PL 364

87.700%

87.700%

PL 405

15.000%

0.000%

PL 442

87.700%

87.700%

PL 442B

87.700%

87.700%

PL 442C

87.700%

87.700%

PL 442D

87.700%

0.000%

PL 457BS

40.000%

40.000%

PL 460

65.000%

65.000%

PL 492

100.000%

100.000%

PL 501

37.384%

37.384%

PL 501B

37.384%

37.384%

PL 609

55.000%

55.000%

PL 609B

55.000%

55.000%

PL 609D

55.000%

55.000%

PL 782SB

0.000%

60.000%

PL 782SC

0.000%

60.000%

PL 822S

87.700%

87.700%

PL 838

35.000%

35.000%

PL 869

80.000%

80.000%

PL 869B

80.000%

80.000%

PL 873

47.700%

47.700%

PL 873B

47.700%

47.700%

PL 873C

47.700%

47.700%

PL 874

87.700%

87.700%

PL 886

0.000%

60.000%

PL 886B

0.000%

60.000%

PL 919

80.000%

80.000%

PL 932

40.000%

40.000%

PL 932B

40.000%

40.000%

PL 941

70.000%

70.000%

PL 942

30.000%

30.000%

PL 942BS

30.000%

0.000%

PL 979

60.000%

60.000%

PL 979B

60.000%

60.000%

PL 1005

0.000%

40.000%

PL 1008

71.918%

71.918%

PL 1041

0.000%

80.000%

PL 1042

0.000%

40.000%

PL 1045

80.000%

80.000%

PL 1045B

80.000%

80.000%

PL 1084

0.000%

60.000%

PL 1085

55.000%

55.000%

PL 1088

77.800%

77.800%

Licence:

31.12.2025

31.12.2024

PL 1088B

77.800%

77.800%

PL 1092

0.000%

50.000%

PL 1097

70.000%

70.000%

PL 1097B

70.000%

0.000%

PL 1102

0.000%

55.000%

PL 1102B

0.000%

55.000%

PL 1110

55.000%

55.000%

PL 1133

0.000%

35.000%

PL 1134

0.000%

35.000%

PL 1139

60.000%

60.000%

PL 1142

82.060%

82.060%

PL 1143

82.060%

82.060%

PL 1144

40.000%

40.000%

PL 1147

60.000%

60.000%

PL 1153

40.000%

40.000%

PL 1158

40.000%

40.000%

PL 1162

0.000%

50.000%

PL 1170

0.000%

35.000%

PL 1171

66.000%

50.000%

PL 1172

40.000%

40.000%

PL 1175

60.000%

50.000%

PL 1175B

60.000%

0.000%

PL 1176

0.000%

60.000%

PL 1198

40.000%

40.000%

PL 1198B

40.000%

0.000%

PL 1199

50.000%

50.000%

PL 1206S

87.700%

87.700%

PL 1207

80.000%

80.000%

PL 1215

40.000%

40.000%

PL 1218

40.000%

40.000%

PL 1218B

40.000%

0.000%

PL 1230

40.000%

40.000%

PL 1242

40.000%

40.000%

PL 1243

40.000%

40.000%

PL 1245

50.000%

0.000%

PL 1247

60.000%

0.000%

PL 1249

38.160%

0.000%

PL 1250S

38.160%

0.000%

PL 1268

50.000%

0.000%

PL 1271S

50.000%

0.000%

PL 1272

35.000%

0.000%

EXL005

50.000%

50.000%

EXL011

80.000%

100.000%

Number of production licences in which Aker BP is the operator

131

132

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Aker BP annual report 2025

Financials

Fields non-operated:

31.12.2025

31.12.2024

Atla

0.000%

10.000%

Enoch

2.000%

2.000%

Johan Sverdrup

31.573%

31.573%

Oda

0.000%

15.000%

Production licences in which Aker BP is a partner:

Licence:

31.12.2025

31.12.2024

PL 006C

35.000%

35.000%

PL 048D

10.000%

10.000%

PL 127

0.000%

50.000%

PL 211CS

15.000%

15.000%

PL 211DS

15.000%

15.000%

PL 220

15.000%

15.000%

PL 229E

50.000%

50.000%

PL 229G

50.000%

50.000%

PL 265

27.384%

27.384%

PL 405

0.000%

15.000%

PL 293

19.000%

0.000%

PL 293CS

19.000%

0.000%

PL 502

22.222%

22.222%

PL 537

35.000%

35.000%

PL 537B

35.000%

35.000%

PL 554

30.000%

30.000%

PL 554B

30.000%

30.000%

PL 554C

30.000%

30.000%

PL 554D

30.000%

30.000%

PL 554E

30.000%

30.000%

PL 554F

30.000%

0.000%

PL 782S

40.000%

40.000%

PL 820S

26.000%

26.000%

PL 820SB

26.000%

26.000%

PL 894

0.000%

10.000%

PL 917

40.000%

40.000%

PL 929

10.000%

10.000%

PL 935

0.000%

20.000%

PL 956

20.000%

20.000%

PL 984

10.000%

10.000%

PL 984BS

0.000%

10.000%

PL 985

0.000%

30.000%

PL 1014

10.000%

10.000%

PL 1014B

10.000%

10.000%

Licence:

31.12.2025

31.12.2024

PL 1040

30.000%

30.000%

PL 1042

40.000%

0.000%

PL 1086

20.000%

20.000%

PL 1090

20.000%

20.000%

PL 1102

20.000%

0.000%

PL 1102B

20.000%

0.000%

PL 1102C

20.000%

0.000%

PL 1109

20.000%

20.000%

PL 1123

0.000%

20.000%

PL 1126

30.000%

30.000%

PL 1126B

30.000%

30.000%

PL 1131

20.000%

20.000%

PL 1138

0.000%

30.000%

PL 1140

40.000%

40.000%

PL 1145

0.000%

40.000%

PL 1148

10.000%

10.000%

PL 1148B

10.000%

10.000%

PL 1148CS

10.000%

10.000%

PL 1149

0.000%

30.000%

PL 1149B

0.000%

30.000%

PL 1151

20.000%

20.000%

PL 1151B

20.000%

0.000%

PL 1152

0.000%

50.000%

PL 1154

30.000%

30.000%

PL 1163

0.000%

20.000%

PL 1165

0.000%

40.000%

PL 1182S

45.000%

30.000%

PL 1185

20.000%

20.000%

PL 1191

0.000%

30.000%

PL 1202S

0.000%

30.000%

PL 1204

20.000%

0.000%

PL 1204BS

20.000%

0.000%

PL 1208

40.000%

40.000%

PL 1212S

20.000%

0.000%

PL 1217

20.000%

20.000%

PL 1222

30.000%

30.000%

PL 1237

20.000%

20.000%

PL 1238

0.000%

20.000%

PL 1240

30.000%

30.000%

PL 1244

40.000%

0.000%

P.2511

0.000%

50.000%

P.2543

50.000%

50.000%

EXL013

50.000%

0.000%

Number of production licences in which Aker BP is a partner

59

64

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Aker BP annual report 2025

Financials

Aggregated reserves, production, developments and adjustments

Net attributed million barrels of oil equivalent

(mmboe)

On production

Approved for development

Justified for development

Total

1P/P90

2P/P50

1P/P90

2P/P50

1P/P90

2P/P50

1P/P90

2P/P50

Balance as of 31.12.2024

675

855

392

708

3

6

1,071

1,568

Production

-153

-153

-

-

-

-

-153

-153

Transfers

7

13

-4

-7

-3

-6

-

-

Revisions

53

33

14

-2

-

-

67

31

Improved oil recovery

-

-

11

18

10

14

21

33

Discoveries and extensions

-

-

35

52

-

-

35

52

Acquisitions and sales

1

2

-6

-7

-

-

-5

-6

Balance as of 31.12.2025

583

750

442

762

10

14

1,035

1,526

Net reduction (-) /increase (+)

-92

-105

50

54

6

9

-35

-42

Climate-related risk:

As described in Note 3, page 154on climate-related risk, a sensitivity analysis has been performed to show the impact on reserves as at 31 December 2025, if all production would cease from 2050 onwards. Such acceleration of cease of production would result in a decrease in the reserves of approximately 13 million boe.

For further information, see the annual statement of reserves published on www.akerbp.com.

End of financial statement

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Financials

(USD million)

Note

Group

Parent

2025

2024

2025

2024

Abandonment spend

Payment for removal and decommissioning of oil fields

83.0

202.5

83.0

202.5

Payments of lease debt (abandonment activity)

2.5

26.2

2.5

26.2

Abandonment spend

85.6

228.7

85.6

228.7

Depreciation per boe

Depreciation

2,574.0

2,397.8

2,574.0

2,397.8

Total produced volumes (boe million)

153.4

160.7

153.4

160.7

Depreciation per boe

16.8

14.9

16.8

14.9

Dividend per share

Paid dividend

1,592.7

1,516.9

1,592.7

1,516.9

Number of shares outstanding (million)

631.3

631.2

631.3

631.2

Dividend per share

2.52

2.40

2.52

2.40

Capex

Disbursements on investments in fixed assets (excluding capitalised interest)

6,855.6

4,773.7

6,855.6

4,773.7

Payments of lease debt (investments in fixed assets)

133.5

65.4

133.5

65.4

CAPEX

6,989.1

4,839.1

6,989.1

4,839.1

EBITDA

Total income

10,943.1

12,379.4

10,943.1

12,379.4

Production expenses

-1,174.9

-916.4

-1,174.9

-916.4

Exploration expenses

-343.6

-326.5

-343.3

-326.0

Other operating expenses

-69.3

-53.5

-69.1

-53.5

EBITDA

9,355.3

11,083.0

9,355.8

11,083.5

EBITDAX

Total income

10,943.1

12,379.4

10,943.1

12,379.4

Production expenses

-1,174.9

-916.4

-1,174.9

-916.4

Other operating expenses

-69.3

-53.5

-69.1

-53.5

EBITDAX

9,698.9

11,409.5

9,699.1

11,409.5

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Aker BP annual report 2025

Financials

(USD million)

Note

Group

Parent

2025

2024

2025

2024

Equity ratio

Total equity

11,226.2

12,691.1

11,226.3

12,691.2

Total assets

44,806.0

42,192.9

44,806.0

42,192.8

Equity ratio

25%

30%

25%

30%

Exploration spend

Disbursements on investments in capitalised exploration expenditures

319.8

338.7

319.8

338.7

Exploration expenses

343.6

326.5

343.3

326.0

Dry well

-193.7

-194.1

-193.7

-194.1

Payments of lease debt (exploration expenditures)

36.7

31.6

36.7

31.6

Exploration spend

506.4

502.7

506.1

502.2

Interest coverage ratio

Twelve months rolling EBITDA

9,355.3

11,083.0

9,355.8

11,083.5

Twelve months rolling EBITDA, impacts from IFRS 16

-154.3

-74.8

-154.3

-74.8

Twelve months rolling EBITDA, excluding impacts from IFRS 16

9,201.1

11,008.2

9,201.5

11,008.7

Twelve months rolling interest expenses

358.9

265.1

358.9

265.1

Twelve months rolling amortised loan cost

40.2

42.9

40.2

42.9

Twelve months rolling interest income

135.6

162.9

135.6

162.9

Net interest expenses

263.5

145.1

263.5

145.1

Interest coverage ratio 1)

34.9

75.9

34.9

75.9

Leverage ratio

Long-term bonds

8,358.6

7,336.8

8,358.6

7,336.8

Short-term bonds

307.2

160.8

307.2

160.8

Cash and cash equivalents

2,344.1

4,146.9

2,344.1

4,146.9

Financial investments

300.0

-

300.0

-

Net interest-bearing debt, excluding lease debt

6,021.7

3,350.7

6,021.7

3,350.7

Twelve months rolling EBITDAX

9,698.9

11,409.5

9,699.1

11,409.5

Twelve months rolling EBITDAX, impacts from IFRS 16

-153.3

-74.8

-153.3

-74.8

Twelve months rolling EBITDAX, excluding impacts from IFRS 16

9,545.6

11,334.7

9,545.7

11,334.7

Leverage ratio 1)

0.63

0.30

0.63

0.30

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Aker BP annual report 2025

Financials

(USD million)

Note

Group

Parent

2025

2024

2025

2024

Net interest-bearing debt

Long-term bonds

8,358.6

7,336.8

8,358.6

7,336.8

Short-term bonds

307.2

160.8

307.2

160.8

Long-term lease debt

712.7

458.0

712.7

458.0

Short-term lease debt

359.4

217.7

359.4

217.7

Cash and cash equivalents

2,344.1

4,146.9

2,344.1

4,146.9

Financial investments

300.0

-

300.0

-

Net interest-bearing debt

7,093.7

4,026.3

7,093.7

4,026.3

Available liquidity

Cash and cash equivalents

2,344.1

4,146.9

2,344.1

4,146.9

Financial investments

300.0

-

300.0

-

Undrawn RCF facility

3,225.0

3,400.0

3,225.0

3,400.0

Available liquidity

5,869.1

7,546.9

5,869.1

7,546.9

Free cash flow

Net cash flow from operating activities

6,958.2

6,422.6

6,958.2

6,422.5

Net cash flow from investment activities

-7,506.0

-5,315.0

-7,506.0

-5,315.0

Investments in financial assets

300.0

-

300.0

-

Free cash flow

-247.8

1,107.6

-247.8

1,107.6

Prior to 2025 accrued interest on bonds was presented as other current liabilities, but is presented as short-term bonds from 2025. Previous periods have been adjusted accordingly.

Operating profit/loss: see Income statement, page 137

Production cost per boe: see Note 6, page 156

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Aker BP annual report 2025

Financials

Independent auditor's statement

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Gov. payments

Corp. governance

Appendix

193

Aker BP annual report 2025

Financials

Independent auditor's statement

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Appendix

194

Aker BP annual report 2025

Financials

Variable pay – Bonus

The company’s bonus system is designed to promote performance in line with the company’s strategy. For 2025, the bonus for all employees, including the CEO and EMT, was determined by the company’s performance on a predefined set of key performance indicators (KPIs), company priorities and project execution targets agreed with the BoD, with each component accounting for 30 percent of the overall bonus outcome. The combined score for these three components was

scaled to arrive at the mathematical bonus score, which could then be adjusted at the ODCC’s discretion (the remaining 10 percent) in collabora- tion with the CEO.

The maximum bonus potential for the CEO and EMT is 60 percent of base salary, while the maximum bonus for employees outside the EMT ranges from 10 percent to 30 percent, depending on position level.

Company priorities

Company priorities consist of important improvement initiatives and activities with clear deliverables that are vital for the company’s future success. Below is a list of the priorities for 2025:

Mature technical and commercial solutions for unlocking marginal development opportunities

Achieve 100 percent delivery of applicable digital initiatives, as defined in the ‘ready for 2027’ operations plan

Subsea tie-backs: Progress next generation solutions through pilot projects

Conclude the tender process within mainte- nance, modifications and operations (MMO), and set transformational targets with a commercial model for future alliance partners

Deliver, test and scale use of functionality in the agile asset management programme for early-phase projects to mature understanding of how to change the way we work

Deliver business value potential and risk assessments from data and workflows across the business units projects, drilling and wells, and exploration and reservoir development

Deliver implementation of the new operations strategy

Deliver defined milestones within the digital alliance, according to plan and cost at expected level of quality

Project execution

From 2025, the project execution KPI comprises the following two metrics that track progress on Yggdrasil, Valhall PWP-Fenris, Utsira High and the Skarv Satellite Project (SSP).

Achievement of key milestones (75% weight)

Development of capex level (25% weight)

Overall result 2025 bonus

The bonus for the first half of 2025 was paid in September, while the bonus for the second half was paid in February 2026. The bonus for all employees (including EMT) was set at 85 percent of the maximum potential, based on 114 percent performance on KPI targets, 85 percent perfor- mance on company initiatives and 57 percent performance on project execution.

Variable pay – Long-term share-based incentive plan (LTIP)

The long-term share-based incentive plan is strategically designed to incentivise executive directors to achieve the company’s long-term business objectives and maximising alignment with shareholder value creation. This plan functions as an equity-settled share-based payment scheme with a three-year vesting period.

Grants are made under the programme on an annual basis for all members of the EMT, normally on 1 July each year. In 2025, 54,259 grants were awarded with vesting in July 2028 (repre- senting the base number of awards before any performance adjustments, as described below). The number of awards made corresponds to 20 percent of the EMT member’s base salary, divided by the Aker BP share price on the award date. In addition, 10,587 grants were awarded with vesting in 2026 and 2027, as they represent an adjustment to the awards made in 2023 and 2024 to reflect subsequent dividend.

Key performance indicators for Aker BP 2025

Key performance indicator

Actual

Safety (serious incidents/1 mill. work hours)

0.3

Net production from operated assets (mboepd)

189

Adjusted production cost (USD/boe) 1)

7.5

Net reserve additions (mmboe)

116

Value creation (change in risked NPV)

+2.2%

Relative shareholder return

20.7%

Equity share scope 1 GHG intensity (kg CO 2 e/boe)

2.8

CO 2 equivalent emission reduction (thousand tonnes)

43

Adjusted to reflect planning assumptions for FX and power prices

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Remuneration

Information regarding the reported financial year

The main conditions of the LTIP plan

Opening balance

During the year

Closing balance

Name, position

Specification of plan

Performance period

Award date

Vesting date

End of holding period

Grants awarded at the beginning of the year

Grants awarded

Performance adjusted grants

Grants vested

Grants awarded and unvested at year end

Shares subject to lock-in

Per Øyvind Seljebotn, SVP exploration and reservoir development 1)

2022-2025 LTIP

2022-2025

01/07/2022

30/06/2025

30/06/2026

1,673

98

-1,771

-

-

-

2023-2026 LTIP

2023-2026

01/07/2023

30/06/2026

30/06/2027

3,035

178

-3,213

-

-

-

2024-2027 LTIP

2024-2027

01/07/2024

30/06/2027

30/06/2028

2,685

158

-2,843

-

-

-

Marit Blaasmo, SVP people and safety

2022-2025 LTIP

2022-2025

01/07/2022

30/06/2025

30/06/2026

1,822

204

-1,611

-415

-

415

2023-2026 LTIP

2023-2026

01/07/2023

30/06/2026

30/06/2027

2,762

311

-

-

3,073

-

2024-2027 LTIP

2024-2027

01/07/2024

30/06/2027

30/06/2028

2,491

280

-

-

2,771

-

2025-2028 LTIP

2025-2028

01/07/2025

30/06/2028

30/06/2029

-

2,729

-

-

2,729

-

Thomas Øvretveit, SVP operations

2022-2025 LTIP

2022-2025

01/07/2022

30/06/2025

30/06/2026

1,583

176

-1,398

-361

-

361

2023-2026 LTIP

2023-2026

01/07/2023

30/06/2026

30/06/2027

2,448

276

-

-

2,724

-

2024-2027 LTIP

2024-2027

01/07/2024

30/06/2027

30/06/2028

2,353

265

-

-

2,618

-

2025-2028 LTIP

2025-2028

01/07/2025

30/06/2028

30/06/2029

-

2,468

-

-

2,468

-

Georg Vidnes, SVP Eiga

2022-2025 LTIP

2022-2025

01/07/2022

30/06/2025

30/06/2026

1,735

195

-1,534

-396

-

396

2023-2026 LTIP

2023-2026

01/07/2023

30/06/2026

30/06/2027

2,861

322

-

-

3,183

-

2024-2027 LTIP

2024-2027

01/07/2024

30/06/2027

30/06/2028

2,520

284

-

-

2,804

-

2025-2028 LTIP

2025-2028

01/07/2025

30/06/2028

30/06/2029

-

2,712

-

-

2,712

-

Ine Dolve, SVP Alvheim

2022-2025 LTIP

2022-2025

01/07/2022

30/06/2025

30/06/2026

2,285

257

-2,021

-521

-

521

2023-2026 LTIP

2023-2026

01/07/2023

30/06/2026

30/06/2027

2,955

334

-

-

3,289

-

2024-2027 LTIP

2024-2027

01/07/2024

30/06/2027

30/06/2028

2,312

261

-

-

2,573

-

2025-2028 LTIP

2025-2028

01/07/2025

30/06/2028

30/06/2029

-

2,545

-

-

2,545

-

Lars Høier, SVP Yggdrasil

2022-2025 LTIP

2022-2025

01/07/2022

30/06/2025

30/06/2026

2,297

258

-2,031

-524

-

524

2023-2026 LTIP

2023-2026

01/07/2023

30/06/2026

30/06/2027

3,158

356

-

-

3,514

-

2024-2027 LTIP

2024-2027

01/07/2024

30/06/2027

30/06/2028

2,807

318

-

-

3,125

-

2025-2028 LTIP

2025-2028

01/07/2025

30/06/2028

30/06/2029

-

3,046

-

-

3,046

-

Ole Johan Molvig, SVP Valhall

2022-2025 LTIP

2022-2025

01/07/2022

30/06/2025

30/06/2026

2,343

264

-2,072

-535

-

535

2023-2026 LTIP

2023-2026

01/07/2023

30/06/2026

30/06/2027

3,181

360

-

-

3,541

-

2024-2027 LTIP

2024-2027

01/07/2024

30/06/2027

30/06/2028

2,815

318

-

-

3,133

-

2025-2028 LTIP

2025-2028

01/07/2025

30/06/2028

30/06/2029

-

3,025

-

-

3,025

-

Talar Arif, SVP Ula

2024-2027 LTIP

2024-2027

01/07/2024

30/06/2027

30/06/2028

1,636

184

-

-

1,820

-

2025-2028 LTIP

2025-2028

01/07/2025

30/06/2028

30/06/2029

-

1,779

-

-

1,779

-

Torbjørg Opedal, SVP Skarv

2025-2028 LTIP

2025-2028

01/07/2025

30/06/2028

30/06/2029

-

2,373

-

-

2,373

-

For this individual, the figure reflects terminated grants rather than performance adjusted grants.

Intro

BoD report

Sustainability

Financials

Transparency

Gov. payments

Corp. governance

Appendix

200

Aker BP annual report 2025

Remuneration

USD (1,000)

Fixed remuneration

Variable remuneration

Pension expense

Total remuneration

Proportion of fixed remuneration

Proportion of variable remuneration

Number of grants awarded 3)

Total number of outstanding grants

Total number of shares 4)

Name

Position

Year

Salary

Payments in kind

Bonus 2)

Share based payment 3)

Petter Sørhaug 6)

SVP exploration and reservoir development

2025

301

24

121

11

24

482

73%

27%

2,688

2,688

-

Per Øyvind Seljebotn 7)

SVP exploration and reservoir development

2025

353

14

-

-42

25

350

112%

-12%

434

-

N/A

2024

338

9

128

54

23

552

67%

33%

3,132

7,393

1,712

Marit Blaasmo

SVP people and safety

2025

332

8

164

68

26

599

61%

39%

3,524

8,573

12,391

2024

309

7

119

52

24

511

66%

34%

2,925

7,075

10,958

Thomas Øvretveit

SVP operations

2025

321

60

149

62

24

616

66%

34%

3,185

7,810

3,489

2024

286

48

109

47

22

511

70%

30%

2,734

6,384

2,110

Georg Vidnes

SVP Eiga

2025

339

56

163

69

25

652

64%

36%

3,513

8,699

5,746

2024

311

29

120

52

23

536

68%

32%

2,955

7,116

3,925

Ine Dolve

SVP Alvheim

2025

329

14

153

70

27

593

62%

38%

3,397

8,407

10,095

2024

304

9

110

58

24

505

67%

33%

2,809

7,552

9,065

Lars Høier

SVP Yggdrasil

2025

375

36

184

78

25

698

62%

38%

3,978

9,685

13,785

2024

346

33

134

62

23

598

67%

33%

3,326

8,262

12,701

Ole Johan Molvig

SVP Valhall

2025

372

3

182

79

25

661

61%

39%

3,967

9,699

26,382

2024

347

3

134

62

23

569

65%

35%

3,340

8,339

22,065

Talar Arif

SVP Ula

2025

214

11

107

24

24

380

65%

35%

1,963

3,599

16,833

2024

192

5

74

8

22

301

73%

27%

1,636

1,636

5,883

Torbjørg Opedal 8)

SVP Skarv

2025

258

9

114

10

26

417

70%

30%

2,373

2,373

2,716

SVP exploration and reservoir development from 26.06.2025.

SVP exploration and reservoir development until 26.06.2025.

SVP Skarv from 05.05.2025.

Intro

BoD report

Sustainability

Financials

Transparency

Gov. payments

Corp. governance

Appendix

202

Aker BP annual report 2025

Remuneration

Signatures – Board of Directors and chief executive officer

The board of directors and the chief executive officer of Aker BP ASA Fornebu, 24 March 2026

Øyvind Eriksen

Chair of the board

Trond Brandsrud

Board member

Doris Reiter

Board member

Kjell Inge Røkke

Board member

Kate Thomson

Board member

Ingard Haugeberg

Board member

Anne Marie Cannon

Deputy chair

Charles Ashley Heppenstall

Board member

Zeala Fortescue

Board member

Tore Vik

Board member

Karl Johnny Hersvik

Chief executive officer

Stine Bjørnvold Bakken

Board member

Marit Hargemark

Board member

Valborg Lundegaard

Board member

Intro

BoD report

Sustainability

Financials

Transparency

Gov. payments

Corp. governance

Appendix

204

Aker BP annual report 2025

Remuneration

The ARC supports the BoD’s responsibilities in ensuring the integrity of financial and sustainability reporting and the related reporting processes. In recent years, the committee has intensified its focus on monitoring non-financial reporting to adequately address its formal responsibilities related to the Corporate Sustainability Reporting Directive, which was incorporated in Norwegian Law with effect for the 2024 reporting year. The committee conducts regular meetings to review the quality of all interim and annual reports before they undergo the BoD's scrutiny and subsequent publication. Additionally, the ARC reviews the sustainability statement included in the BoD's report, which is an integral part of the commit- tee’s responsibility for sustainability reporting as mentioned above. In 2025, the committee held seven meetings.

The company’s auditor PwC, works closely with the ARC and attended all meetings during the year. The committee informs the BoD of the result of the audit, including how the audit contributed to the integrity of the financial reporting. The committee also oversees the company’s financial risk management, internal audit, and monitors and reviews the company’s business risks. The ARC oversees Aker BP’s anti-corruption compliance programme and handling of reports submitted via the company’s integrity channel.

The management and the ARC evaluate the risk management on financial reporting and the effectiveness of established internal controls. Identified risks and effects of financial reporting are discussed on a quarterly basis.

It is the view of the committee that cooperation between the auditor and executive management is good. The ARC works together with EMT and the auditor to improve the internal control environ- ment according to the principles of the Committee of Sponsoring Organizations of the Treadway Commission (COSO) framework.

The ARC has oversight over the assurance activity in the company, and the head of internal audit is reporting to the ARC. This is securing that internal audit has independence from the management of Aker BP.

Organisational development and compensation committee

The BoD has an organisation development and compensation committee (ODCC) consisting of the following three board members:

Øyvind Eriksen, chair

Anne Marie Cannon

Marit Hargemark

The ODCC is established to ensure that remuner- ation arrangements support the strategy of the business and enable the recruitment, succession planning and leadership development, and moti- vation and retention of senior executives. It needs to comply with the requirements of regulatory and governance bodies, satisfy the expectations of shareholders and remain consistent with the expectations of the wider employee population. Further, the committee shall ensure that the overall organisational structure is set up to deliver

on the company’s strategy going forward. In 2025, the committee held four meetings.

Safety and environmental assurance committee

The oversight of health, safety, security and environmental matters (HSSE) is retained directly by the BoD. HSSE issues, including cyber security, are at the top of the agenda in every single BoD meeting.

In addition, the BoD has established a Safety and Environmental Assurance Committee (SEAC) to strengthen the administration work on health, safety, cyber security, and environmental matters. The committee reports to the BoD on a quarterly basis and has in 2025 consisted of the following members:

Fawaz Bitar, SVP HSE & Carbon, bp – chair of the committee

Karl Johnny Hersvik, CEO, Aker BP

Marit Blaasmo, SVP people and safety, Aker BP

Knut Sandvik, SVP projects execute, Aker BP

Anchala Klein, VP Safety & operational risk, Wells, bp

Doris Reiter, SVP North Sea, bp

Tommy Sigmundstad, SVP drilling and wells, Aker BP

Arthur Alexander, Business Advisor, HSE & Carbon, bp

Henry Barda, VP Shareholder team, bp

Georg Vidnes, SVP Eiga, Aker BP

John Nugent, Strategy & risk Senior Manager, bp

SEAC assures that the HSSE work is adequately and properly organised and addressed throughout the entire company and that the HSSE policy and governing processes are embedded in all operations. In addition, SEAC shall:

Review all risks related to operating activities, including operational integrity and technical and mechanical integrity of wells

Review all risks related to cyber security

Share learnings from incidents by in-depth analysis in the relevant areas of mutual interest or incident follow-up

Align leadership experiences on common areas of focus in relation to management of safety and operational risk

Share experiences and practices in the HSSE area

Review and give advice to management regarding the company’s HSSE work

The committee may conduct visits to all relevant sites, including offshore installations, to ensure that the company’s governing processes and proper practices are adhered to

In 2025, the committee held four meetings.

In addition to the above-mentioned committees, the BoD may appoint various ad hoc subcommit- tees when required, with a limited timeframe and scope. The authority of a subcommittee is limited to preparing items and making recommendations to the BoD.

Deviations from the code: None

Intro

BoD report

Sustainability

Financials

Transparency

Remuneration

Gov. payments

Appendix

212

Aker BP annual report 2025

Corp. governance

Term

Definition

Medical treatment injury

A personal injury that is not severe enough to be reported as a lost time injury but is more severe than requiring a simple first aid treatment, for example if prescription medicine is given, sutures are needed, etc.

Methane emission intensity

Volume of operational control scope 1 methane emissions from operated assets and drilling activities, expressed as a percentage of the total volume of saleable gas

N 2 O

Dinitrogen oxide

NCS

Norwegian continental shelf

NGO

Non-governmental organisation

nmVOC

Non-methane volatile organic compounds

Non-emloyees

People under an agency-type arrangement that meets the following criteria:

The position requires that the person acts in an Aker BP role or capacity

The work will mainly be carried out at Aker BP’s offices or installations, and by use of Aker BP’s equipment

The duration of the engagement is at least three months

NORM

Naturally occurring radioactive material

NORSOK

The NORSOK standards are developed by the Norwegian petroleum industry to ensure adequate safety, value adding and cost effectiveness for petroleum industry developments and operations

NO x

Collective term for nitrogen monoxide (NO) and nitrogen dioxide (NO 2 )

NPV

Net present value

P&A

Plug and abandon

OECD

The Organisation for Economic Co-operation and Development

OECD Guidelines

The OECD Guidelines for Multinational Enterprises

Operational control

Aker BP has the ability to direct the operational activities and relationship of the entity, site, operation or asset. In practice, this means accounting for 100 percent of the emissions from our operated activities

Own operations

Aker BP’s working interest in both operated and non-operated assets

P&O

People and organisation

PDO

Plan for development and operation

Produced water

Produced water is a by-product in the oil and gas well-stream, containing oil residues and other organic compounds

Protected areas

Protected areas are defined where no industrial activity, or only limited activity, is permitted

R&D

Research and development

Scope 1

Direct emissions from owned or controlled sources

Term

Definition

Scope 2

Indirect emissions from the generation of purchased energy. Calculated either as location-based or market-based, see separate definitions

Scope 3

Indirect emissions (not included in scope 2) that occur in the value chain of the company, including both upstream and downstream emissions

SEAC

Safety and environmental assurance committee. An initiative from the BoD, whose purpose is to support and strengthen management’s work on issues related to security, cybersecurity and the environment

Serious incident

Serious incidents with actual and/or potential consequence in category A, and actual serious injuries leading to defined medical disability, ref. the Directorate of Labour and Welfare’s disability tables, excluding events with quality (production loss, economical loss), reputation or security consequences per million work hours

Serious incident frequency (SIF)

Number of serious incidents per million working hours

SO x

Sulphur oxides

SVO

SVOs (in Norwegian, 'Særlig verdifulle og sårbare områder') are particularly valuable and vulnerable areas for biodiversity that have been identified and managed under the Norwegian Management Plan for marine areas

TCFD

Task Force on Climate-related Financial Disclosures

The Norwegian Transparency Act

Norwegian Act relating to enterprises' transparency and work on fundamental human rights and decent working conditions (Lov om virksomheters åpenhet og arbeid med grunnleggende menneskerettigheter og anstendige arbeidsforhold - Åpenhetsloven (LOV-2021-06-18-99))

Tier 1 and 2 process safety events

A process safety event is an unplanned loss of containment from a process. Tier 1 and tier 2 events are classified according to ANSI/API RP 754, where tier 1 represents the most severe cases and tier 2 the less severe

Tier 1 supplier

Direct supplier to Aker BP

Total recordable injury frequency (TRIF)

Number of work-related injuries per million working hours

UN Global Compact

The United Nations Global Compact is a non-binding United Nations pact to get businesses and firms worldwide to adopt sustainable and socially responsible policies, and to report on their implementation

Upstream value chain

Actors upstream in Aker BP’s value chain that provide products or services that are used in the production of our products

Work-related fatalities

Fatalities taking place while working for Aker BP

Work-related illness

Illnesses related to work performed for Aker BP

Work-related injuries

Injuries such as medical treatments and above (excluding first aid injuries) taking place while working for Aker BP

Intro

BoD report

Sustainability

Financials

Transparency

Remuneration

Gov. payments

Corp. governance

223

Aker BP annual report 2025

Appendix

Photos: Anne Lise Norheim

Design: Headspin

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