Aker BP

Quarterly Report • Oct 22, 2025

QUARTERLY REPORT

Q3 2025

THIRD QUARTER 2025 RESULTS

Aker BP delivered another strong quarter in Q3 2025, demonstrating operational excellence, disciplined cost control, and continued progress on key growth projects. Production remained stable, supported by high uptime and safe execution across the portfolio. The company achieved a major milestone with the Omega Alfa oil discovery in the Yggdrasil area – one of the largest on the Norwegian Continental Shelf in the past decade. Aker BP's robust financial position and resilient cash flow underpin its commitment to shareholder returns while enabling continued investment in future growth.

Highlights

• • Stable production: Oil and gas production averaged 414 mboepd (415 mboepd in Q2), with high production efficiency and minimal unplanned downtime.
• • Cost discipline: Production cost was USD 7.6 per boe (USD 7.3 in Q2), impacted by planned maintenance.
• • Industry-leading low emissions: Greenhouse gas emission intensity at 2.9 kg CO2e per boe (Scope 1 & 2).
• • Project delivery: Major field developments including Yggdrasil, Valhall PWP-Fenris, Skarv Satellites, and Utsira High advanced on schedule, with all key construction and drilling milestones achieved.
• • Exploration breakthrough: The Omega Alfa campaign delivered a significant oil discovery in the Yggdrasil area, estimated at 96–134 mmboe recoverable.
• • Solid financials: Total income was USD 2.6 billion (USD 2.6 billion in Q2), with cash flow from operations of USD 2.0 billion (USD 1.2 billion in Q2).
• • Resilient dividends: A dividend of USD 0.63 per share was paid in the quarter, keeping Aker BP on track to deliver USD 2.52 per share for the year.

Comment from Karl Johnny Hersvik, CEO of Aker BP:

"In the third quarter, we continued to demonstrate stable and efficient operations across a diverse portfolio. Our growth projects progressed as planned, while our teams maintained high uptime, a strong safety record, and industry-leading low emissions."

"The Omega Alfa discovery was a clear highlight this quarter. As one of the largest oil finds on the Norwegian Continental Shelf in the past decade, it underscores the strength of our exploration strategy and our collaborative approach with partners. The discovery significantly expands the resource base for Yggdrasil and supports our ambition to grow production well into the next decade."

"Our financial position remains robust. Strong cash flow and disciplined capital allocation enable continued investment in future growth, advancement of major development projects, and delivery of attractive, resilient dividends to our shareholders."

Forward-looking statements in this report reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future and may not be within our control. All figures are presented in USD unless otherwise stated, and figures in brackets apply to the previous quarter.

Key figures

	UNIT	Q3 2025	Q2 2025	Q3 2024
INCOME STATEMENT
Total income	USD million	2 599	2 584	2 858
EBITDA	USD million	2 262	2 223	2 612
Net profit/loss	USD million	285	(324)	173
Earnings per share (EPS)	USD	0.45	(0.51)	0.27
CASH FLOW STATEMENT
Cash flow from operations	USD million	2 023	1 240	2 757
Cash flow from investments	USD million	(1 871)	(2 199)	(1 402)
Cash flow from financing	USD million	(547)	(645)	(491)
Net change in cash and cash equivalent	USD million	(395)	(1 603)	864
OTHER FINANCIAL KEY FIGURES
Net interest-bearing debt1	USD million	6 071	5 663	3 352
Leverage ratio1		0.49	0.43	0.22
Dividend per share	USD	0.63	0.63	0.60
PRODUCTION AND SALES
Net petroleum production	mboepd	414.0	415.0	414.7
Over/underlift	mboepd	(17.9)	(1.1)	(23.4)
Net sold volume	mboepd	396.1	413.8	391.3
- Liquids	mboepd	340.0	356.2	345.0
- Natural gas	mboepd	56.1	57.7	46.4
REALISED PRICES
Liquids	USD/boe	70.3	66.9	80.3
Natural gas	USD/boe	63.3	68.7	63.5
AVERAGE EXCHANGE RATES
USDNOK		10.10	10.30	10.71
EURUSD		1.17	1.13	1.10

¹From first quarter 2025, accrued interest on bonds is presented as short-term bond debt and thus included in the definition of Net interest-bearing debt. Comparative figures have been adjusted accordingly.

FINANCIAL REVIEW

Income statement

(USD MILLION)	Q3 2025	Q2 2025	Q3 2024
Total income	2 599	2 584	2 858
EBITDA	2 262	2 223	2 612
EBIT	1 475	915	1 695
Pre-tax profit	1 426	852	1 627
Net profit/loss	285	(324)	173
EPS (USD)	0.45	(0.51)	0.27

Total income for the third quarter amounted to USD 2,599 million (2,584 million in the previous quarter). Sold volumes fell by four percent to 396.1 thousand barrels of oil equivalent per day (mboepd). The average realised price for liquids rose by five percent to USD 70.3 (66.9) per barrel oil equivalent (boe), while the average price for natural gas declined by eight percent to USD 63.3 (68.7) per boe.

Production expenses for oil and gas sold amounted to USD 246 (285) million, mainly reflecting changes in over- and underlift. The average production cost per barrel produced was USD 7.6 (7.3). See note 2 for further details on production expenses. Exploration expenses totalled USD 72 (60) million.

Depreciation was USD 615 (591) million, or USD 16.1 (15.7) per boe. Impairments were USD 173 (717) million, relating to technical goodwill on Johan Sverdrup and the Valhall area. For further details, see note 7.

Operating profit for the quarter was USD 1,475 million (915 million).

Net financial expenses were USD 48 (63) million, primarily due to currency losses from a weaker dollar, partly offset by gains on currency derivatives. For more details, see note 4.

Profit before taxes was USD 1,426 (852) million. Tax expense was USD 1,141 (1,176) million, giving an effective tax rate of 80 (138) percent. For further details on tax, see note 5.

Net profit for the quarter was USD 285 million, compared to a net loss of USD 324 million in the previous quarter.

Balance sheet

(USD MILLION)	30.09.2025	30.06.2025	31.12.2024	30.09.2024
Goodwill	11 679	11 851	12 757	12 757
Property, plant and equipment (PP&E)	24 025	22 421	20 238	19 803
Other non-current assets	3 482	3 501	3 033	3 362
Cash and cash equivalents	2 344	2 745	4 147	4 147
Other current assets	2 647	2 358	2 018	1 625
Total assets	44 175	42 877	42 193	41 693
Equity	11 738	11 851	12 691	12 477
Bank and bond debt1	7 665	7 627	7 498	6 739
Other long-term liabilities	20 617	19 386	17 651	17 488
Tax payable	1 646	1 781	2 434	2 904
Other current liabilities1	2 508	2 232	1 920	2 085
Total equity and liabilities	44 175	42 877	42 193	41 693
Net interest-bearing debt2	6 071	5 663	4 026	3 352
Leverage ratio2	0.49	0.43	0.30	0.22

¹The company changed its presentation in the first quarter 2025. Accrued interest on bonds is now presented as short-term bond debt, whereas before 2025 it was classified under other current liabilities. Comparative figures have been adjusted accordingly.

At the end of the third quarter, total assets stood at USD 44.2 (42.9) billion, of which non-current assets were USD 39.2 (37.8) billion.

Equity was USD 11.7 (11.9) billion, corresponding to an equity ratio of 27 (28) percent.

Bond debt amounted to USD 7.7 (7.6) billion, while the company's bank facilities remained undrawn. Other long-term liabilities were USD 20.7 (19.4) billion.

Tax payable was USD 1.6 (1.8) billion.

At the end of the third quarter, the company's total available liquidity was USD 5.6 (6.0) billion, comprising USD 2.3 (2.7) billion in cash and cash equivalents, USD 0.3 (0.3) billion in financial investments, and USD 3.0 (3.0) billion in undrawn credit facilities.

²From first quarter 2025, accrued interest on bonds is presented as short-term bond debt and thus included in the definition of Net interest-bearing debt. Comparative figures have been adjusted accordingly.

Cash flow

(USD MILLION)	Q3 2025	Q2 2025	Q3 2024
Cash flow from operations	2 023	1 240	2 757
Cash flow from investments	(1 871)	(2 199)	(1 402)
Cash flow from financing	(547)	(645)	(491)
Net change in cash & cash equivalents	(395)	(1 603)	864
Cash and cash equivalents	2 344	2 745	4 147

Net cash flow from operating activities was USD 2,023 (1,240) million in the quarter, primarily reflecting lower tax payments. Net cash used for investment activities amounted to USD 1,871 (2,199) million, including USD 1,765 (1,799) million in investments in fixed assets.

Net cash outflow from financing activities was USD 547 (645) million, with dividend payments of USD 398 (398) million as the main item in the third quarter.

Dividends

The General Meeting has authorised the Board to approve the distribution of dividends pursuant to section 8-2 (2) of the Norwegian Public Limited Companies Act.

In the third quarter 2025, Aker BP paid a dividend of USD 0.63 per share. The Board has resolved to pay USD 0.63 per share in the fourth quarter, with disbursement scheduled for on or about 4 November 2025. The Aker BP shares will trade ex-dividend on 27 October 2025.

Hedging

Aker BP employs a range of hedging instruments to manage economic exposure:

• • Commodity hedging: Approximately 40 percent of the company's estimated oil price exposure for the fourth quarter of 2025 is hedged through put options with a strike price of USD 65 per barrel.
• • Currency hedging: The company's programme covers 75-90 percent of planned NOK expenditures over the next three years, at average USD/NOK rates between 10.5 and 11.0. Accrued tax liabilities are also hedged on a continuous basis.

All derivatives are marked to market, with changes in value recognised in the income statement.

OPERATIONAL REVIEW

Aker BP delivered strong operational performance across its portfolio in the third quarter of 2025. Net production averaged 414 mboepd, supported by high production efficiency and stable operations. Key assets such as Johan Sverdrup, Valhall, Alvheim, and Skarv maintained robust uptime. Notably, Ula achieved its highest production efficiency in recent years.

All major development projects progressed according to plan:

• Yggdrasil entered the drilling phase, with all key construction milestones achieved across multiple sites.
• Valhall PWP-Fenris completed its Fenris drilling campaign and advanced offshore modifications.
• Utsira High reached key subsea and platform modification milestones ahead of first oil in 2026.
• Skarv Satellites continued its high-activity phase with drilling and installation campaigns.

Exploration activity was high, with total spend of USD 151 million. The Omega Alfa campaign resulted in one of Norway's largest oil discoveries in a decade, adding 96–134 mmboe to the Yggdrasil area.

Across all areas, Aker BP continued to deliver on its strategic priorities – safe operations, efficient execution, and value creation through growth and resource maturation.

Alvheim area

KEY FIGURES	AKER BP INTEREST	Q3 2025	Q2 2025	Q1 2025	Q4 2024	Q3 2024
Production, mboepd
Alvheim (incl. KEG)	80%	43.0	40.0	42.0	43.6	37.6
Bøyla (incl. Frosk)	80%	2.6	3.0	4.3	4.7	4.2
Skogul	65%	1.3	1.3	1.6	1.5	2.2
Tyrving	61.188%	9.4	14.9	17.6	12.9	3.2
Vilje	46.904%	1.0	1.0	1.0	1.0	1.2
Volund	100%	1.2	1.4	1.8	2.6	1.2
Total production		58.5	61.6	68.3	66.3	49.5
Production efficiency		99%	98%	99%	97%	90%

Production from the Alvheim area averaged 59 mboepd net to Aker BP in the third quarter, down from 62 mboepd in the previous quarter due to natural decline. Operational performance remained strong, with production efficiency improving to 98.9 percent.

The drilling of a new infill well was successfully completed. Tie-in activities are underway and first production is expected in October. Work is ongoing to mature additional IOR opportunities and infill targets.

Grieg Aasen area

KEY FIGURES	AKER BP INTEREST	Q3 2025	Q2 2025	Q1 2025	Q4 2024	Q3 2024
Production, mboepd
Edvard Grieg Area (incl. Solveig)	65%	29.1	35.9	35.5	36.6	39.4
Ivar Aasen (incl. Hanz)	36.1712%	7.4	10.3	12.1	13.5	10.8
Total production		36.5	46.2	47.6	50.1	50.1
Production efficiency		73%	96%	95%	95%	93%

Production from the Grieg Aasen area was 36 mboepd net to Aker BP in the third quarter, with production efficiency at 73.5 percent, down from 96.4 percent in the second quarter. The decline was primarily driven by the planned turnaround, along with reduced output due to tuning and finalisation of compressor upgrade activities.

At Hanz, production remains shut in to allow for placement of final pipeline covers over the Symra/Hanz pipelines.

The 2025 IOR campaign at Edvard Grieg has been completed. Well A-9 was brought online in August, and A-19 is scheduled to start production in October.

Planning for the 2026 IOR campaign at Ivar Aasen is progressing as expected, with rig arrival planned for summer 2026.

Utsira High project

The Utsira High project comprises two subsea tiebacks – Symra to the Ivar Aasen platform and Solveig Phase 2 to the Edvard Grieg platform – with first oil expected in 2026.

The project advanced according to plan during the quarter. Main subsea installation work at both Solveig and Symra has been completed, marking a key milestone.

During the three-week shutdown of the Edvard Grieg and Ivar Aasen platforms, modification work was executed as planned. The main modifications at Edvard Grieg for the Utsira High project are now complete.

Drilling operations at Symra are ongoing, with the first well successfully completed.

Johan Sverdrup

KEY FIGURES	AKER BP INTEREST	Q3 2025	Q2 2025	Q1 2025	Q4 2024	Q3 2024
Production, mboepd
Total production	31.5733%	232.9	237.8	236.3	239.3	237.2

The Johan Sverdrup field delivered strong performance in the third quarter, with continued high production efficiency, low operating costs, an excellent safety record, and minimal emissions. Aker BP's share of production averaged 233 mboepd for the period.

Drilling activities at the field centre continued, with one well completed alongside planned maintenance. The rig will proceed to drill two retrofit multilateral wells (RMLT), adding branches to existing production wells.

Johan Sverdrup Phase 3

Phase 3 of the Johan Sverdrup development, sanctioned in the second quarter, is progressing according to plan. The scope includes two new subsea templates and eight additional wells, with start-up scheduled for the fourth quarter of 2027.

Skarv area

KEY FIGURES	AKER BP INTEREST	Q3 2025	Q2 2025	Q1 2025	Q4 2024	Q3 2024
Production, mboepd
Total production	23.835%	29.5	31.9	34.8	35.2	23.8
Production efficiency		96%	99%	98%	96%	64%

Skarv delivered robust operational performance in the third quarter of 2025, supported by stable operations and the effective execution of planned activities. Net production averaged 29.5 mboepd, down from the previous quarter due to planned downtime and natural decline. Production efficiency was 96 percent, slightly lower than the prior quarter due to a planned annual emergency shutdown test.

Skarv Satellites Project

The Skarv Satellites Project, which includes the tie-back of the Alve Nord, Idun Nord, and Ørn discoveries to the Skarv FPSO, progressed according to plan. Activity levels remained high throughout the quarter, with multiple subsea facility and pipeline installation campaigns completed, and the production drilling campaign initiated. The first two wells at Idun Nord were successfully drilled during the period.

Preparations are underway for the upcoming flotel period in 2026. The flotel is scheduled to arrive at Skarv in the first quarter and will provide offshore accommodation and support for personnel during the intensive hook-up and commissioning phase.

Early-phase evaluations of additional tie-back projects and infill wells advanced during the quarter. The E-Prospect, Lunde, Storjo/Kaneljo, and Adriana/Sabina discoveries are all being considered as potential future tie-back candidates to the Skarv FPSO.

Ula area

KEY FIGURES	AKER BP INTEREST	Q3 2025	Q2 2025	Q1 2025	Q4 2024	Q3 2024
Production, mboepd
Ula	80%	5.1	2.6	3.7	4.3	3.4
Tambar	55%	4.6	4.0	1.8	1.2	0.7
Oda	15%	0.6	0.4	0.7	0.9	1.0
Total production		10.3	7.0	6.2	6.4	5.2
Production efficiency		91%	56%	81%	80%	60%

Net production from the Ula area averaged 10 mboepd in the third quarter of 2025, up from 7 mboepd in the previous quarter. The increase reflects strong performance from the production wells and high operational efficiency, which reached 91 percent.

Production from the Ula area is planned to cease by 2028. A decommissioning project is underway, progressing toward a concept select decision. This work is being carried out in parallel with ongoing efforts to optimise late-life production.

Valhall area

KEY FIGURES	AKER BP INTEREST	Q3 2025	Q2 2025	Q1 2025	Q4 2024	Q3 2024
Production, mboepd
Valhall	90%	37.2	25.4	39.2	42.8	40.2
Hod	90%	9.0	5.0	8.9	9.1	8.7
Total production		46.2	30.4	48.1	51.9	48.9
Production efficiency		92%	59%	92%	94%	90%

Net production from the Valhall area averaged 46 mboepd in the third quarter, up from 30 mboepd in the previous quarter. The increase was primarily due to the planned one-month shutdown in June for maintenance and project activities. Production efficiency reached 92 percent.

Valhall PWP-Fenris

The Valhall PWP-Fenris project continued to progress according to plan during the third quarter. Fabrication and construction activities are advancing on schedule, and offshore modifications to existing Valhall facilities are ongoing. The offshore hook-up scope for the bridge has commenced, and the final offshore subsea campaign for the season—covering spool metrology and umbilical preparations—was successfully completed.

Drilling of the fourth Fenris well was finalised during the quarter, concluding a successful campaign for the Fenris production wells. Strong geological results across all four wells have helped reduce volume uncertainty.

At Valhall PWP, drilling operations commenced during the quarter following the installation of the jacket and pre-drilling deck in June.

The PWP-Fenris development will modernise the Valhall hub and bring the Fenris gas discovery on stream, with first production expected in 2027.

Yggdrasil

The Yggdrasil area, operated by Aker BP in partnership with Equinor and Orlen Upstream Norway, is estimated to hold approximately 800 mmboe in recoverable resources. Through continued exploration and reservoir maturation, Aker BP aims to increase this to over one billion barrels.

The development includes:

• A central processing platform (Hugin A)
• Two unmanned platforms (Munin and Hugin B)
• Extensive subsea infrastructure
• More than 55 planned wells

All facilities will be powered from shore, enabling very low greenhouse gas emissions. First production is expected in 2027.

The project progressed according to plan in the third quarter:

• Both the Hugin A and the Munin jackets were successfully installed.
• The Subsea Alliance completed installation of the final five templates, additional pipelines, and the 7.7-kilometre south bundle in the Munin licence.

Construction and assembly activities are advancing across multiple sites:

• At Stord, the Hugin A topside is taking shape, with the wellbay module arriving from Dubai during the quarter.

• The Hugin A utility module was loaded out from Egersund, ready for transport to Stord.
• Assembly of the Hugin B topside and jacket commenced in Verdal.
• Outfitting of the Munin topside is progressing in Haugesund.
• Commissioning activities have started for the power-fromshore project.

The third quarter marked the start of long-term production drilling in the Yggdrasil area, with two rigs now operating in the Hugin and Munin licences.

The East Frigg Beta/Epsilon discovery, made in May 2023, has now been integrated into the Yggdrasil development and will be tied back to Hugin A via a subsea template, already installed on the seabed.

The area continues to demonstrate strong exploration potential. In the third quarter, Aker BP successfully completed the Omega Alfa exploration campaign in the North Sea, resulting in a significant oil discovery with estimated recoverable volumes of 96–134 mmboe. At the end of the quarter, drilling of the Natrudstilen prospect was ongoing.

Legal case regarding PDO approvals

In January 2024, Oslo District Court ruled that the Ministry of Energy's approvals of the PDOs for the Breidablikk, Tyrving, and Yggdrasil fields were invalid due to procedural errors specifically, the failure to assess end-user combustion emissions. A temporary injunction initially halted the issuance of new permits based on these PDOs.

The ruling and injunction were appealed by the Norwegian state to the Borgarting Court of Appeal, which in March 2024 decided to defer enforcement of the injunction, allowing permitting activities to continue. In October 2024, the Court of Appeal lifted the injunction. This decision was subsequently appealed by environmental organisations to the Supreme Court, which heard the case in March 2025 and issued its ruling in April. The Supreme Court returned the question of the temporary injunction to the Court of Appeal for renewed consideration.

The Borgarting Court of Appeal is scheduled to hear the case in the first week of September 2025, with a ruling expected in October.

On 2 June 2025, Greenpeace filed a new petition for a temporary injunction with the Oslo District Court. The petition was dismissed, as the court deemed it to be a repetition of the claim already pending before the Court of Appeal.

This latest ruling has no impact on the validity of Aker BP's PDO approvals. The company is not a party to the case. Tyrving commenced production in September 2024, and the Yggdrasil project continues to progress according to plan.

EXPLORATION

Total exploration spend in the third quarter amounted to USD 151 million (USD 110 million in Q2 2025), with USD 72 million (USD 60 million) recognised as exploration expenses. These figures include costs related to dry wells, seismic data, area fees, field evaluation, and geological and geophysical work.

The Omega Alfa campaign in the North Sea resulted in one of Norway's largest oil discoveries in a decade, adding 96-134 mmboe to the Yggdrasil area. Five targets were drilled via a multilateral well in licences PL873, PL873B, and PL1249, operated by Aker BP with ownership shares of 38–48 percent.

Other exploration activities in the quarter included:

• Skrustikke dry well in PL554, operated by Equinor, Aker BP share: 30 percent
• Narvi dry well in PL554E, operated by Equinor, Aker BP share: 30 percent
• Lofn/Langemann ongoing wells in PL1140, operated by Equinor, Aker BP share: 40 percent
• Page ongoing well in PL1086, operated by DNO, Aker BP share: 20 percent
• Avbitertang ongoing well in PL554, operated by Equinor, Aker BP share: 30 percent
• Natrudstilen ongoing well in PL873, operated by Aker BP, Aker BP share: 48 percent

Licence swap agreement with Japex

In July, Aker BP entered into an agreement with Japex Norge AS to strengthen its North Sea portfolio. The transaction includes a swap of a 10 percent interest in the Alve Nord development (PL127C) and a 3.5 percent interest in the Verdande development (PL127/PL127DS) in exchange for Japex's Northern North Sea assets and a cash consideration of USD 14 million. Aker BP will acquire a 15 percent interest in the Kjøttkake discovery (PL1182S), increasing its total share to 45 percent, a 10 percent interest in the Kveikje discovery (PL293B/PL293CS), and a 20 percent interest in PL1212S. The effective date is 1 January 2025. The transaction was completed in October and is thus not included in the Q3 figures.

HEALTH, SAFETY, SECURITY AND ENVIRONMENT

HSSE is always the number one priority in all of Aker BP's activities. The company strives to ensure that all its operations, drilling campaigns and projects are carried out under the highest HSSE standards.

KEY HSSE INDICATORS	UNIT	Q3 2025	Q2 2025	Q1 2025	Q4 2024	Q3 2024
Total recordable injury frequency (TRIF) L12M	Per mill. working hours	1.7	2.3	1.9	1.8	2.0
Serious incident frequency (SIF) L12M	Per mill. working hours	0.2	0.1	0.2	0.4	0.7
Acute spill	Count	1	0	1	1	0
Process safety events Tier 1 and 2	Count	0	0	0	0	0
GHG emissions intensity, equity share (scope 1&2)	Kg CO2e/boe	2.9	2.8	2.8	2.5	2.4

Health & Safety

The twelve-month rolling average for Total Recordable Injury Frequency (TRIF) declined to 1.7 following four reported incidents in the second quarter. Of these, three were classified as lost-time injuries and one required medical treatment without resulting in employee absence.

The Serious Incident Frequency (SIF) increased to 0.2 as there were two incidents during the third quarter. A fall, which also counted as a TRIF case, with potential fatality, and a dropped-object incident with similar potential but no actual harm.

All incidents are routinely investigated to identify root causes and improve safety standards.

Environment

Aker BP recorded one minor spill in the quarter. The spill occurred during installation of a subsea template and was caused by a leaking bleed-off valve, resulting in water-based hydraulic control fluid being spilled to sea.

No process safety events were reported in the third quarter.

Aker BP's greenhouse gas (GHG) emissions intensity for the third quarter was 2.9 (2.8) kg CO2e per boe.

OUTLOOK

The Board believes Aker BP is uniquely positioned for long-term value creation, leveraging several core strengths:

• Aker BP is a pure-play oil and gas company, producing from a portfolio of world-class assets with high operational efficiency, low costs, and a strong safety record. This generates substantial cash flow and provides a solid foundation for further value creation through increased recovery and near-field exploration.
• The company is also an industry leader in emissions efficiency, with one of the lowest greenhouse gas emission intensities in the oil and gas sector and a well-defined pathway towards GHG neutrality for scope 1 and 2 emissions.
• Aker BP is driving industrial transformation through a comprehensive improvement agenda, leveraging strategic alliances and digitalisation to enhance operational excellence and sustainable growth. These initiatives strengthen competitiveness and productivity across the entire value chain.
• With a substantial resource base, extensive exploration acreage, and a portfolio of high-return field development projects, Aker BP is well positioned for continued profitable growth. Executed under a capital-efficient tax framework, these projects remain on track to deliver a significant production increase from 2027.
• Aker BP has established a resilient financial framework with clear capital allocation priorities. Maintaining a robust balance sheet with financial flexibility and an investment grade credit rating remains the top financial priority. This approach ensures the funding of high-return, low break-even projects, maximising long-term value creation. Over time, this value will be returned to shareholders through dividends.

While the broader geopolitical and macroeconomic environment remains uncertain, Aker BP is well positioned to navigate volatility. With a robust balance sheet, substantial liquidity, industry-leading low costs, and a portfolio of resilient, low break-even, high-return investments, the company continues to deliver strong performance.

The Board is confident that Aker BP is well equipped to manage the current environment while remaining firmly focused on longterm value creation for its shareholders.

Guidance for 2025

Aker BP has updated its financial guidance for 2025 as follows (previous guidance in brackets):

• Production: 410–425 mboepd (400–420 mboepd)

• Production cost: USD ~7 per boe (unchanged)

• Capex: USD ~6.5 billion (unchanged)

• Exploration spend: USD ~500 million (USD ~450 million) • Abandonment spend: USD ~100 million (unchanged)

• Dividend: USD 0.63 per share per quarter, annualised at USD 2.52 per share (unchanged)

Disclaimer

Forward-looking statements in this report reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future and may not be within our control. All figures are presented in USD unless otherwise stated, and figures in brackets apply to the previous quarter.

FINANCIAL STATEMENTS WITH NOTES

INCOME STATEMENT (UNAUDITED)

				Group
		Q3	Q2	Q3		01.0130.09.
(USD million)	Note	2025	2025	2024	2025	2024
Petroleum revenues		2,528.7	2,533.4	2,822.4	8,212.1	9,217.1
Other income		69.9	50.7	35.2	171.3	94.6
Total income	1	2,598.5	2,584.1	2,857.6	8,383.4	9,311.7
Production expenses	2	246.2	285.1	186.1	809.7	687.3
Exploration expenses	3	71.9	59.8	40.0	239.0	215.8
Depreciation	6	614.7	591.4	613.9	1,897.1	1,794.3
Impairments	6,7	172.5	716.7	303.5	1,077.8	386.2
Other operating expenses		18.3	15.8	19.2	48.5	43.4
Total operating expenses		1,123.6	1,668.8	1,162.8	4,072.1	3,127.0
Operating profit/loss		1,474.9	915.3	1,694.9	4,311.3	6,184.7
Interest income		28.5	35.3	42.8	106.4	115.2
Other financial income		51.4	155.2	68.1	510.3	153.4
Interest expenses		16.2	18.3	24.2	46.2	79.8
Other financial expenses		112.2	235.2	154.4	668.3	376.8
Net financial items	4	-48.5	-63.0	-67.8	-97.9	-188.0
Profit/loss before taxes		1,426.4	852.3	1,627.1	4,213.4	5,996.7
Tax expense (+)/income (-)	5	1,140.9	1,176.3	1,453.7	3,935.8	4,730.8
Net profit/loss		285.5	-324.0	173.4	277.6	1,265.9
Weighted average no. of shares outstanding basic and diluted		630,465,201	631,458,608	630,786,689	631,290,842	631,077,878
Basic and diluted earnings/loss USD per share		0.45	-0.51	0.27	0.44	2.01

STATEMENT OF COMPREHENSIVE INCOME (UNAUDITED)

	Group
		Q3	Q2	Q3	01.0130.09.
(USD million)	Note	2025	2025	2024	2025	2024
Profit/loss for the period		285.5	-324.0	173.4	277.6	1,265.9
Total comprehensive income/loss in period		285.5	-324.0	173.4	277.6	1,265.9

STATEMENT OF FINANCIAL POSITION (UNAUDITED)

				Group
(USD million)	Note	30.09.2025	30.06.2025	31.12.2024	30.09.2024
ASSETS
Intangible assets
Goodwill	6	11,678.8	11,851.3	12,756.6	12,756.6
Capitalised exploration expenditures	6	580.1	502.1	420.4	486.1
Other intangible assets	6	1,791.7	1,840.5	1,937.6	1,990.8
Tangible fixed assets
Property, plant and equipment	6	24,024.6	22,421.3	20,238.4	19,802.6
Right-of-use assets	6	935.7	969.0	578.8	673.4
Financial assets
Long-term receivables		81.4	79.5	69.0	80.7
Other non-current assets		24.1	24.6	22.6	104.7
Long-term derivatives	13	68.9	85.7	5.0	26.1
Total non-current assets		39,185.3	37,774.0	36,028.4	35,921.0
Inventories
Inventories		476.6	425.8	305.9	255.3
Financial assets
Trade receivables		755.3	645.3	914.9	676.4
Other short-term receivables	8	1,020.0	869.4	796.4	668.6
Financial investments	9	300.0	300.0	-	-
Short-term derivatives	13	94.6	117.4	0.3	24.5
Cash and cash equivalents
Cash and cash equivalents	10	2,343.6	2,745.5	4,146.9	4,147.4
Total current assets		4,990.1	5,103.3	6,164.5	5,772.0
TOTAL ASSETS		44,175.4	42,877.3	42,192.9	41,693.0

STATEMENT OF FINANCIAL POSITION (UNAUDITED)

			Group
(USD million)	Note	30.09.2025	30.06.2025	31.12.2024	30.09.2024
EQUITY AND LIABILITIES
Equity
Share capital		84.3	84.3	84.3	84.3
Share premium		12,946.6	12,946.6	12,946.6	12,946.6
Other equity		-1,292.7	-1,180.2	-339.9	-554.2
Total equity		11,738.3	11,850.8	12,691.1	12,476.8
Non-current liabilities
Deferred taxes	5	15,445.4	14,446.9	12,990.0	12,363.2
Long-term abandonment provision	12	4,476.6	4,199.0	4,147.7	4,584.6
Long-term bonds	11	7,362.7	7,455.5	7,336.8	6,577.7
Long-term derivatives	13	-	0.1	55.3	1.2
Long-term lease debt	15	695.1	739.8	458.0	538.1
Other non-current liabilities		-	-	-	1.0
Total non-current liabilities		27,979.9	26,841.3	24,987.8	24,065.7
Current liabilities
Trade creditors		459.2	254.1	329.1	355.3
Short-term bonds	11	302.6	171.9	160.8	161.4
Accrued public charges and indirect taxes		45.9	36.7	40.8	37.1
Tax payable	5	1,646.4	1,781.0	2,433.6	2,903.8
Short-term derivatives	13	2.1	1.6	151.7	28.0
Short-term abandonment provision	12	94.9	92.8	131.7	125.4
Short-term lease debt	15	353.8	340.8	217.7	222.1
Other current liabilities	14	1,552.3	1,506.4	1,048.5	1,317.5
Total current liabilities		4,457.2	4,185.3	4,514.0	5,150.5
Total liabilities		32,437.1	31,026.6	29,501.7	29,216.2
TOTAL EQUITY AND LIABILITIES		44,175.4	42,877.3	42,192.9	41,693.0

STATEMENT OF CHANGES IN EQUITY - GROUP (UNAUDITED)

					Other equity
					Other comprehensive income
		Share	Other paid-in	Actuarial	Foreign currency translation	Accumulated	Total other
(USD million)	Share capital	premium	capital	gains/losses	reserves	deficit	equity	Total equity
Equity as of 31.12.2023	84.3	12,946.6	573.1	-0.2	179.8	-1,421.6	-668.8	12,362.2
Dividend distributed	-	-	-	-	-	-758.4	-758.4	-758.4
Profit/loss for the period	-	-	-	-	-	1,092.6	1,092.6	1,092.6
Purchase of treasury shares	-	-	-	-	-	-12.2	-12.2	-12.2
Share-based payments	-	-	-	-	-	0.4	0.4	0.4
Equity as of 30.06.2024	84.3	12,946.6	573.1	-0.2	179.8	-1,099.2	-346.4	12,684.5
Dividend distributed	-	-	-	-	-	-379.2	-379.2	-379.2
Profit/loss for the period	-	-	-	-	-	173.4	173.4	173.4
Purchase of treasury shares	-	-	-	-	-	-2.2	-2.2	-2.2
Share-based payments	-	-	-	-	-	0.3	0.3	0.3
Equity as of 30.09.2024	84.3	12,946.6	573.1	-0.2	179.8	-1,307.0	-554.2	12,476.8
Dividend distributed	-	-	-	-	-	-379.2	-379.2	-379.2
Profit/loss for the period	-	-	-	-	-	561.8	561.8	561.8
Sale of treasury shares	-	-	-	-	-	31.4	31.4	31.4
Share-based payments	-	-	-	-	-	0.3	0.3	0.3
Other comprehensive income for the period	-	-	-	0.1	-	-	0.1	0.1
Equity as of 31.12.2024	84.3	12,946.6	573.1	-0.1	179.8	-1,092.7	-339.9	12,691.1
Dividend distributed	-	-	-	-	-	-796.3	-796.3	-796.3
Profit/loss for the period	-	-	-	-	-	-7.8	-7.8	-7.8
Purchase of treasury shares	-	-	-	-	-	-36.8	-36.8	-36.8
Share-based payments	-	-	-	-	-	0.7	0.7	0.7
Equity as of 30.06.2025	84.3	12,946.6	573.1	-0.1	179.8	-1,933.1	-1,180.2	11,850.8
Dividend distributed	-	-	-	-	-	-398.2	-398.2	-398.2
Profit/loss for the period	-	-	-	-	-	285.5	285.5	285.5
Share-based payments	-	-	-	-	-	0.3	0.3	0.3
Equity as of 30.09.2025	84.3	12,946.6	573.1	-0.1	179.8	-2,045.5	-1,292.7	11,738.3

STATEMENT OF CASH FLOWS (UNAUDITED)

				Group
		Q3	Q2	Q3	01.0130.09.
(USD million)	Note	2025	2025	2024	2025	2024
CASH FLOW FROM OPERATING ACTIVITIES
Profit/loss before taxes		1,426.4	852.3	1,627.1	4,213.4	5,996.7
Taxes paid	5	-295.3	-1,571.2	-458.2	-2,584.3	-3,597.9
Taxes refunded	5	-	0.2	34.3	0.2	34.3
Depreciation	6	614.7	591.4	613.9	1,897.1	1,794.3
Impairment	6,7	172.5	716.7	303.5	1,077.8	386.2
Expensed capitalised dry wells	3,6	24.2	28.2	3.8	127.5	114.8
Accretion expenses related to abandonment provision	4,12	47.9	47.1	46.0	141.1	139.5
Total interest expenses	4	16.2	18.3	24.2	46.2	79.8
Changes in unrealised gain/loss in derivatives	1,4	46.7	-88.3	-59.9	-356.4	131.5
Foreign currency exchange on bonds, tax payable and cash and
cash equivalents		28.8	173.2	56.8	423.4	-87.6
Changes in inventories and trade creditors/receivables		44.3	128.8	585.9	119.0	210.7
Changes in other working capital items		-95.5	351.6	-15.2	285.3	166.4
Changes in other balance sheet items, and other non-cash items		-8.3	-8.0	-5.6	-18.2	-8.8
NET CASH FLOW FROM OPERATING ACTIVITIES		2,022.6	1,240.1	2,756.5	5,372.1	5,360.0
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields	12	-9.7	-32.1	-66.5	-64.7	-191.8
Disbursements on investments in fixed assets (excluding capitalised interest)	6	-1,764.9	-1,799.5	-1,257.5	-4,868.4	-3,501.6
Disbursements on investments in capitalised exploration expenditures	6	-96.0	-66.9	-77.5	-260.1	-255.4
Investments in financial assets	9	-	-300.0	-	-300.0	-
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-1,870.5	-2,198.5	-1,401.6	-5,493.3	-3,948.8
CASH FLOW FROM FINANCING ACTIVITIES
Net drawdown/repayment/fees related to revolving credit facility		-	-	-1.5	-	-1.5
Repayment of bonds		-	-	-	-63.6	-
Net proceeds from bond issue		-	-	-	-	806.6
Interest paid (including interest element of lease payments)		-67.8	-150.8	-66.9	-285.7	-207.0
Payments on lease debt related to investments in fixed assets		-31.0	-23.6	-11.1	-68.3	-41.7
Payments on other lease debt		-49.7	-35.4	-30.5	-129.6	-76.8
Paid dividend Net purchase/sale of treasury shares		-398.2 -	-398.2 -36.8	-379.2 -2.2	-1,194.5 -36.8	-1,137.6 -14.4
NET CASH FLOW FROM FINANCING ACTIVITIES		-546.7	-644.8	-491.4	-1,778.5	-672.4
Net change in cash and cash equivalents		-394.6	-1,603.3	863.5	-1,899.7	738.9
Cash and cash equivalents at start of period		2,745.5	4,282.9	3,233.3	4,146.9	3,388.4
Effect of exchange rate fluctuation on cash and cash equivalents		-7.3	65.9	50.5	96.3	20.1
CASH AND CASH EQUIVALENTS AT END OF PERIOD	10	2,343.6	2,745.5	4,147.4	2,343.6	4,147.4
SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD
Bank deposits, cash and cash equivalents		2,313.1	2,716.6	4,125.1	2,313.1	4,125.1
Restricted bank deposits		30.5	28.9	22.3	30.5	22.3
CASH AND CASH EQUIVALENTS AT END OF PERIOD	10	2,343.6	2,745.5	4,147.4	2,343.6	4,147.4

NOTES (unaudited)

(All figures in USD million unless otherwise stated)

These unaudited condensed consolidated interim financial statements ('interim financial statement') have been prepared in accordance with the IFRS® Accounting Standards as adopted by the EU IAS 34 'Interim Financial Reporting', thus the interim financial statements do not include all information required by IFRS and should be read in conjunction with the group's 2024 annual financial statements. The interim financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair statement of the financial position, results of operations and cash flows for the dates and interim periods presented. Interim period results are not necessarily indicative of results of operations or cash flows for an annual period. These interim financial statements have been subject to a review in accordance with the International Standard on Review Engagements 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity.

These interim financial statements were authorised for issue by the company's board of directors on 21 October 2025.

The accounting principles used for this interim report are consistent with those used in the company's 2024 annual financial statements, except for certain changes in presentation. Accrued interest on bonds is now presented as short-term bond debt, whereas before 2025 it was classified under other current liabilities. Additionally, the last line item in the cash flow statement, previously (before 2025) referred to as 'changes in other balance sheet items', has been divided into three new line items to provide more detailed information regarding cash flow. Comparative figures have been adjusted accordingly.

In preparing these interim financial statements, management has made judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, income and expense. Actual results may differ from these estimates.

The significant judgements made by management in applying the group's accounting policies and the key sources of estimation uncertainty are in all material respects the same as those that were applied in the group's 2024 annual financial statements.

Note 1 Income

			Group
	Q3	Q2	Q3		01.0130.09.
Breakdown of petroleum revenues (USD million)	2025	2025	2024	2025	2024
Sales of liquids	2,199.2	2,169.7	2,548.0	7,028.3	8,307.7
Sales of gas	326.7	360.5	271.0	1,174.3	898.7
Tariff income	2.7	3.2	3.3	9.5	10.7
Total petroleum revenues	2,528.7	2,533.4	2,822.4	8,212.1	9,217.1
Sales of liquids (boe million)	31.3	32.4	31.7	99.2	101.1
Sales of gas (boe million)	5.2	5.2	4.3	16.1	15.8
Other income (USD million)
Realised gain (+)/loss (-) on commodity derivatives	-3.8	-2.4	-0.0	-7.3	0.3
Unrealised gain (+)/loss (-) on commodity derivatives	-2.9	3.9	-0.8	-0.5	-1.0
Other income1)	76.6	49.3	36.0	179.1	95.3
Total other income	69.9	50.7	35.2	171.3	94.6

¹⁾ The figure includes partner coverage of assets recognised on gross basis in the balance sheet and used in operated activity.

Note 2 Production expenses

		Group
	Q3	Q2	Q3		01.0130.09.
Breakdown of production expenses (USD million)	2025	2025	2024	2025	2024
Cost of operations	201.1	195.4	185.9	575.2	533.8
Shipping and handling	72.9	62.6	53.5	200.3	185.6
Environmental taxes	16.9	16.2	10.8	47.3	35.4
Production expenses based on produced volumes	290.9	274.2	250.3	822.8	754.8
Adjustment for over (+)/underlift (-)	-44.7	10.9	-64.1	-13.1	-67.4
Production expenses based on sold volumes	246.2	285.1	186.1	809.7	687.3
Total produced volumes (boe million)	38.1	37.8	38.2	115.6	119.3
Production expenses per boe produced (USD/boe)	7.6	7.3	6.6	7.1	6.3

Note 3 Exploration expenses

		Group
	Q3	Q2	Q3		01.0130.09.
Breakdown of exploration expenses (USD million)	2025	2025	2024	2025	2024
Seismic	15.6	2.4	8.9	26.2	21.7
Area fee	3.2	4.8	4.3	12.3	10.2
Field evaluation	10.3	9.4	10.3	25.2	28.3
Dry well expenses1)	24.2	28.2	3.8	127.5	114.8
G&G and other exploration expenses	18.6	15.0	12.7	47.9	40.8
Total exploration expenses	71.9	59.8	40.0	239.0	215.8

¹⁾ Dry well expenses in Q3 2025 are mainly related to Skrustikke and Narvi.

Note 4 Financial items

			Group
	Q3	Q2	Q3	01.0130.09.
(USD million)	2025	2025	2024	2025	2024
Interest income	28.5	35.3	42.8	106.4	115.2
Realised gains on derivatives	49.7	77.7	7.0	153.1	51.9
Change in fair value of derivatives	1.7	77.5	61.0	356.9	4.8
Net currency gains	-	-	-	-	96.1
Other financial income	-	0.0	0.0	0.4	0.5
Total other financial income	51.4	155.2	68.1	510.3	153.4
Interest expenses	84.8	93.5	68.3	267.0	183.6
Interest on lease debt	13.7	12.4	9.5	35.1	28.6
Amortised loan costs1)	7.3	7.7	11.7	22.9	34.8
Capitalised borrowing costs, development projects	-89.7	-95.2	-65.4	-278.9	-167.2
Total interest expenses	16.2	18.3	24.2	46.2	79.8
Net currency loss	25.6	188.2	60.5	452.9	-
Realised loss on derivatives	0.2	0.0	47.3	74.1	100.3
Change in fair value of derivatives	38.5	-	0.4	-	135.4
Accretion expenses related to abandonment provision	47.9	47.1	46.0	141.1	139.5
Other financial expenses	-0.0	-0.0	0.2	0.2	1.6
Total other financial expenses	112.2	235.2	154.4	668.3	376.8
Net financial items	-48.5	-63.0	-67.8	-97.9	-188.0

¹⁾ The figure mainly consists of the amortisation of the difference between fair value and nominal value on the bonds acquired in the Lundin transaction in 2022.

Note 5 Tax

			Group
	Q3	Q2	Q3		01.0130.09.
Tax for the period (USD million)	2025	2025	2024	2025	2024
Current year tax payable/receivable	141.8	200.4	781.3	1,503.3	3,024.2
Change in current year deferred tax	998.6	975.9	671.8	2,432.0	1,771.5
Prior period adjustments	0.5	-0.0	0.7	0.5	-64.9
Tax expense (+)/income (-)	1,140.9	1,176.3	1,453.7	3,935.8	4,730.8
				Group
			2025	2025	2024
Calculated tax payable (-)/tax receivable (+) (USD million)			Q3	01.0130.06.	01.0131.12.
Tax payable/receivable at beginning of period			-1,781.0	-2,433.6	-3,599.9
Current year tax payable/receivable			-141.8	-1,361.5	-3,883.1
Net tax payment/refund			295.3	2,288.8	4,727.5
Prior period adjustments and change in estimate of uncertain tax positions			-0.6	23.9	50.4
Currency movements of tax payable/receivable			-18.3	-298.6	271.4
Net tax payable (-)/receivable (+)			-1,646.4	-1,781.0	-2,433.6
				Group
			2025	2025	2024
Deferred tax liability (-)/asset (+) (USD million)			Q3	01.0130.06.	01.0131.12.
Deferred tax liability/asset at beginning of period			-14,446.9	-12,990.0	-10,592.3
Change in current year deferred tax			-998.6	-1,433.4	-2,398.3
Prior period adjustments			0.1	-23.4	0.5

	Group
	Q3	Q2	Q3	01.0130.09.
Reconciliation of tax expense (USD million)	2025	2025	2024	2025	2024
78% tax rate on profit/loss before tax	1,112.6	664.8	1,269.2	3,286.6	4,677.7
Tax effect of uplift	-143.3	-136.7	-98.2	-378.0	-267.3
Permanent difference on impairment	134.6	559.1	236.8	840.7	301.2
Foreign currency translation of monetary items other than USD	18.4	143.3	46.9	342.7	-73.4
Foreign currency translation of monetary items other than NOK	9.2	17.3	5.1	67.3	-16.7
Tax effect of financial and other 22% items	39.6	-29.7	24.3	-82.9	152.8
Currency movements of tax balances	-14.7	-49.2	-20.9	-135.0	27.9
Other permanent differences, prior period adjustments and change in	-15.6	7.4	-9.4	-5.7	-71.4
estimate of uncertain tax positions
Tax expense (+)/income (-)	1,140.9	1,176.3	1,453.7	3,935.8	4,730.8

Deferred tax charged to other comprehensive income - - 0.0 Net deferred tax liability (-)/asset (+) -15,445.4 -14,446.9 -12,990.0

The financial statements of the company are presented in USD, its functional currency. However, as per statutory regulations, current taxes are calculated as if NOK was the functional currency. Consequently, when determining taxable income, currency gains and losses from the financial statements are replaced with the translation effect of monetary items other than NOK. Tax balances are maintained in NOK and converted to USD using the period-end exchange rate. These adjustments can influence the effective tax rate, due to fluctuations in the exchange rate between NOK and USD.

Note 6 Tangible fixed assets and intangible assets

TANGIBLE FIXED ASSETS - GROUP

Property, plant and equipment	Assets under	Production facilities	Fixtures and fittings, office
(USD million)	development	including wells	machinery	Total
Book value 31.12.2024	7,530.7	12,654.9	52.9	20,238.4
Acquisition cost 31.12.2024	7,564.7	23,436.6	307.9	31,309.1
Additions	3,158.8	95.7	13.8	3,268.3
Disposals/retirement	-	-	-	-
Reclassification	21.2	-0.3	13.5	34.4
Acquisition cost 30.06.2025	10,744.7	23,532.1	335.1	34,611.9
Accumulated depreciation and impairments 31.12.2024	34.0	10,781.7	255.0	11,070.7
Depreciation	-	1,108.7	11.1	1,119.9
Impairment/reversal (-)	-	-	-	-
Disposals/retirement depreciation	-	-	-	-
Accumulated depreciation and impairments 30.06.2025	34.0	11,890.4	266.1	12,190.6
Book value 30.06.2025	10,710.7	11,641.6	69.0	22,421.3
Acquisition cost 30.06.2025	10,744.7	23,532.1	335.1	34,611.9
Additions	1,867.5	190.1	37.5	2,095.1
Disposals/retirement	-	-	-	-
Reclassification	8.0	0.1	19.7	27.7
Acquisition cost 30.09.2025	12,620.2	23,722.2	392.3	36,734.7
Accumulated depreciation and impairments 30.06.2025	34.0	11,890.4	266.1	12,190.6
Depreciation	-	512.2	7.3	519.5
Impairment/reversal (-)	-	-	-	-
Disposals/retirement depreciation	-	-	-	-
Accumulated depreciation and impairments 30.09.2025	34.0	12,402.6	273.5	12,710.1
Book value 30.09.2025	12,586.2	11,319.6	118.8	24,024.6

Production facilities, including wells, are depreciated in accordance with the unit-of-production method. Office machinery, fixtures and fittings etc. are depreciated using the straight-line method over their useful life, i.e. 3-5 years. Estimated future removal and decommissioning costs are included as part of cost of production facilities or fields under development.

Right-of-use assets

(USD million)	Drilling Rigs	Boats	Office	Other	Total
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	439.6	=	70.3	0.7	510.7
Allocated to abandonment activity	-1.8	=	-	-	-1.8
Disposals/retirement	=	-	-	-	-
Reclassification	-55.3	-	-	-	-55.3
Acquisition cost 30.06.2025	1,001.1	51.2	145.1	3.0	1,200.4
Accumulated depreciation and impairments 31.12.2024	97.5	20.4	49.0	1.1	168.0
Depreciation	51.9	3.3	8.2	0.1	63.5
Impairment/reversal (-)	=	=	=	-	-
Disposals/retirement depreciation	=	-	-	-	-
Accumulated depreciation and impairments 30.06.2025	149.4	23.8	57.2	1.1	231.5
Book value 30.06.2025	851.7	27.5	87.9	1.9	969.0
Acquisition cost 30.06.2025	1,001.1	51.2	145.1	3.0	1,200.4
Additions 1)	=	=	47.0	-	47.0
Allocated to abandonment activity	-	-	=	-	-
Disposals/retirement	-	-	-	-	-
Reclassification 2)	-34.1	=	=	-	-34.1
Acquisition cost 30.09.2025	967.0	51.2	192.1	3.0	1,213.4
Accumulated depreciation and impairments 30.06.2025	149.4	23.8	57.2	1.1	231.5
Depreciation	39.5	1.7	5.0	0.0	46.2
Impairment/reversal (-)	-	-	-	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 30.09.2025	188.9	25.4	62.1	1.2	277.7
Book value 30.09.2025	778.1	25.8	130.0	1.8	935.7

^<sup>1) Mainly related to new Stavanger office.

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

$^{^{2)}}$ Reclassified to tangible and intangible assets in line with the activity of the right-of-use asset.

INTANGIBLE ASSETS - GROUP

		Capitalised
		exploration		Other intangible assets
(USD million)	Goodwill	expenditures	Depreciated	Not depreciated	Total
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	-	164.1	-	2.0	2.0
Disposals/retirement/expensed dry wells	-	-103.3	-	-	-
Reclassification	-	20.9	-	-	-
Acquisition cost 30.06.2025	15,014.1	756.4	2,568.5	827.4	3,395.9
Accumulated depreciation and impairments 31.12.2024	2,257.5	254.4	1,320.8	135.5	1,456.3
Depreciation	-	-	99.1	-	99.1
Impairment/reversal (-)	905.2	-	-	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 30.06.2025	3,162.8	254.4	1,419.9	135.5	1,555.4
Book value 30.06.2025	11,851.3	502.1	1,148.6	691.9	1,840.5
Acquisition cost 30.06.2025	15,014.1	756.4	2,568.5	827.4	3,395.9
Additions	-	96.0	-	0.2	0.2
Disposals/retirement/expensed dry wells	-	-24.2	-	-	-
Reclassification	-	6.3	-	-	-
Acquisition cost 30.09.2025	15,014.1	834.5	2,568.5	827.5	3,396.1
Accumulated depreciation and impairments 30.06.2025	3,162.8	254.4	1,419.9	135.5	1,555.4
Depreciation	-	-	48.9	-	48.9
Impairment/reversal (-)	172.5	-	-	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 30.09.2025	3,335.3	254.4	1,468.8	135.5	1,604.3
Book value 30.09.2025	11,678.8	580.1	1,099.7	692.1	1,791.7

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.

			Group
	Q3	Q2	Q3		01.0130.09.
Depreciation in the income statement (USD million)	2025	2025	2024	2025	2024
Depreciation of tangible fixed assets	519.5	514.4	545.7	1,639.4	1,596.0
Depreciation of right-of-use assets	46.2	30.2	21.9	109.7	60.2
Depreciation of other intangible assets	48.9	46.8	46.3	148.0	138.2
Total depreciation in the income statement	614.7	591.4	613.9	1,897.1	1,794.3
Impairment in the income statement (USD million)
Impairment/reversal of tangible fixed assets	-	-	-	-	-
Impairment/reversal of other intangible assets	-	-	-	-	-
Impairment/reversal of capitalised exploration expenditures	-	-	-	-	-
Impairment of goodwill	172.5	716.7	303.5	1,077.8	386.2
Total impairment in the income statement	172.5	716.7	303.5	1,077.8	386.2

Note 7 Impairments

Impairment testing

Impairment tests of individual cash-generating units are performed when impairment/reversal triggers are identified, and goodwill is tested for impairment at least annually. In Q3 2025, impairment tests have been performed for fixed assets and related intangible assets, including technical goodwill.

Impairment is recognised when the book value of an asset or a cash-generating unit, including associated goodwill, exceeds the recoverable amount. Correspondingly, a reversal of impairment is recognised when the recoverable amount exceeds the book value. Prior period impairment of goodwill is not subject to reversal. The recoverable amount is the higher of the asset's fair value less cost to sell and value in use. The impairment testing for Q3 has been performed in accordance with the fair value method (level 3 in the fair value hierarchy) and based on discounted cash flows. The expected future cash flow is 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) for a market participant. Cash flows are projected for the estimated lifetime of the fields, which may extend beyond five years.

For producing licences and licences in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Below is an overview of the key assumptions applied for impairment testing purposes as of 30 September 2025.

Prices

Future price level is a key assumption and has significant impact on the net present value. Forecasted oil and gas prices are based on management's estimates and available market data. Information about market prices in the near future can be derived from the futures contract market. The information about future prices is less reliable on a long-term basis, as there are fewer observable market transactions going forward. In the impairment test, the oil and gas prices are therefore based on the forward curve from the beginning of Q4 2025 to the end of Q3 2028. From Q4 2028, the oil and gas prices are based on the company's long-term price assumptions. Long-term oil and gas price assumptions are unchanged from previous quarter.

The nominal oil prices applied in the impairment test are as follows:

	2025	2025
Nominal oil prices (USD/boe)	Q3	Q2
2025	66.8	66.5
2026	65.0	64.8
2027	65.0	65.2
2028	69.4	72.7
From 2029 (in real 2025 terms)	75.0	75.0

The nominal gas prices applied in the impairment test are as follows:

	2025	2025
Nominal gas prices (GBP/therm)	Q3	Q2
2025	0.81	0.84
2026	0.80	0.85
2027	0.77	0.78
2028	0.74	0.77
From 2029 (in real 2025 terms)	0.76	0.76

Oil and gas reserves

Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable reserves including potentially additional risked volumes.

Future expenditure

Future capex, opex and abandonment cost are calculated based on the expected production profiles and the best estimate of the related cost. The cost profiles include an estimated impact of the currently high cost escalation in the industry.

Discount rate

The post-tax nominal discount rate applied is 8.8 percent, consistent with the rate used in Q2 2025.

Currency rates

	2025	2025
USD/NOK	Q3	Q2
2025	10.00	10.07
2026	10.02	10.06
2027	10.07	10.07
2028	10.08	10.03
From 2029	10.00	10.00

The long-term currency rate is unchanged from previous quarter.

Inflation

The long-term inflation rate is assumed to be 2.0 percent. 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. In line with the methodology described in the annual report, deferred tax (from the date of acquisitions) reduces the net carrying value prior to the impairment charges. 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 Q3 2025:

		Johan Sverdrup
Cash-generating unit (USD million)	Valhall CGU	CGU
Net carrying value	7,890.6	8,755.9
Recoverable amount	7,816.7	8,657.3
Impairment/reversal (-)	73.9	98.6
Allocated as follows:
Technical goodwill	73.9	98.6
Other intangible assets/licence rights	-	-
Tangible fixed assets	-	-

The impairment in Q3 is mainly related to decrease of deferred tax liabilities as described above, in addition to updated cost and production profiles.

Sensitivity analysis

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

			Change in impairment after
		Increase in	Decrease in
Assumption (USD million)	Change	assumptions	assumptions
Oil and gas price forward period	+/- 50%	-172.5	2,842.6
Oil and gas price long-term	+/- 20%	-172.5	2,442.9
Production profile (reserves)	+/- 5%	-172.5	484.0
Discount rate	+/- 1% point	193.4	-172.5
Currency rate USD/NOK	+/- 2.0 NOK	-172.5	1,242.6
Inflation	+/- 1% point	-172.5	416.0

Note 8 Other short-term receivables

	Group
(USD million)	30.09.2025	30.06.2025	31.12.2024	30.09.2024
Prepayments	553.0	502.7	390.8	344.2
VAT receivable	14.9	31.6	45.6	18.3
Underlift of petroleum	116.0	56.7	97.9	111.6
Other receivables, mainly balances with licence partners	336.1	278.4	262.1	194.5
Total other short-term receivables	1,020.0	869.4	796.4	668.6

Note 9 Financial investments

		Group
(USD million)	30.09.2025	30.06.2025	31.12.2024	30.09.2024
Notes	300.0	300.0	-	-
Financial investments	300.0	300.0	-	-

In the second quarter of 2025, the company invested USD 300 million in liquid Notes. This investment will enhance returns on surplus cash while maintaining liquidity. The Notes have a maturity period of three years, with an option for the company to redeem them by providing three months' notice. The interest rate is based on SOFR plus a 0.55 percent margin. The Notes are rated A+ and are considered to have low credit risk.

Note 10 Cash and cash equivalents

	Group
Breakdown of cash and cash equivalents (USD million)	30.09.2025	30.06.2025	31.12.2024	30.09.2024
Bank deposits	2,213.1	2,716.6	4,125.8	4,125.1
Restricted bank deposits1)	30.5	28.9	21.2	22.3
Cash equivalents2)	100.0	-	-	-
Cash and cash equivalents	2,343.6	2,745.5	4,146.9	4,147.4
Undrawn RCF facility	2,950.0	2,950.0	3,400.0	3,400.0

¹⁾ Mainly related to tax deduction account.

The RCF is undrawn as at 30 September 2025 and the remaining unamortised fees of USD 9.9 million related to the facility are therefore included in other noncurrent assets.

The senior unsecured Revolving Credit Facility (RCF) was established in May 2019 and currently consists of two tranches:

(1) Working Capital Facility with a committed amount of USD 1.3 billion until May 2026 (USD 1.4 billion until May 2025) and,

(2) Liquidity Facility with a committed amount of USD 1.65 billion until May 2026 (USD 2.0 billion until May 2025).

The interest rate for the Working Capital Facility is Term SOFR plus a margin of 1.00 percent and for the Liquidity Facility Term SOFR plus a margin of 0.75 percent.

In 2023, Aker BP signed a new USD 1.8 billion RCF. The new facility will have a forward date (availability date) at the same time as the existing RCF expires in 2026 and has a maturity in 2029. The facility includes one extension option with potential final maturity in 2030. The interest rate for the new facility is Term SOFR plus a margin of 0.85 percent.

Drawing under the Liquidity Facility and the new RCF will add a utilisation fee. A commitment fee of 35 percent of applicable margin is paid on the undrawn part of the Working Capital Facility and Liquidity Facility. For the new RCF, the commitment fee will not apply until the availability date in 2026.

The financial covenants are as follows:

• Leverage Ratio: Net interest-bearing debt divided by twelve months rolling EBITDAX (excluding any impacts from IFRS 16) shall not exceed 3.5
• Interest Coverage Ratio: Twelve months rolling EBITDA divided by Interest expenses (excluding any impacts from IFRS 16) shall be a minimum of 3.5

The financial covenants in the group's current debt facilities exclude the effects from IFRS 16, and therefore cannot be directly derived from the group's financial statements. See reconciliations of Alternative Performance Measures for detailed information.

As at 30 September 2025, the Leverage Ratio is 0.49 and Interest Coverage Ratio is 43.7 (see APM section for further details).

In October 2025, Aker BP reached an agreement with a syndicate of banks to refinance its existing credit facilities into a new Revolving Credit Facility. The new facility will consist of two tranches. The first is a USD 2 billion Liquidity tranche maturing in 2030, including two extension options that could potentially extend the final maturity to 2032. The second tranche is a Working Capital tranche of minimum USD 1 billion, set to expire in 2028, with an extension option that may extend the maturity to 2029. The interest rates for both tranches are Term SOFR plus a margin of 0.85 percent. The transaction is expected to be signed by the end of October.

²⁾ In the third quarter of 2025, the company invested USD 100 million in a financial instrument with Bank of America as the counterparty, which locks in a price differential that generates an implied return corresponding to Term SOFR plus a 0.30% margin. The contracts are rated A+, considered to carry low credit risk, and can be cancelled at any time without mark-to-market exposure and at no cost.

Note 11 Bonds

	Outstanding		Group
Senior unsecured bonds (USD million)	amount	30.09.2025	30.06.2025	31.12.2024	30.09.2024
Senior Notes 2.875% (Sep 20/Jan 26)2)	USD 95.5 mill	-	-	95.0	128.8
Senior Notes 2.000% (Jul 21/Jul 26)2)	USD 104.8 mill	-	101.9	100.5	674.0
Senior Notes 5.600% (Jun 23/Jun 28)	USD 500 mill	498.0	497.8	497.5	497.3
Senior Notes 1.125% (May 21/May 29)	EUR 750 mill	877.9	876.2	776.0	836.3
Senior Notes 3.750% (Jan 20/Jan 30)	USD 1,000 mill	996.6	996.4	996.0	995.8
Senior Notes 4.000% (Sep 20/Jan 31)	USD 750 mill	746.9	746.8	746.5	746.3
Senior Notes 3.100% (Jul 21/Jul 31)	USD 1,000 mill	891.8	887.2	877.9	873.2
Senior Notes 4.000% (May 24/May 32)	EUR 750 mill	874.2	872.4	772.0	832.5
Senior Notes 6.000% (Jun 23/Jun 33)	USD 1,000 mill	994.3	994.1	993.7	993.5
Senior Notes 5.125% (Oct 24/Oct 34)1)	USD 750 mill	742.9	742.7	742.0	-
Senior Notes 5.800% (Oct 24/Oct 54)1)	USD 750 mill	740.2	740.1	739.7	-
Long-term bonds - book value		7,362.7	7,455.5	7,336.8	6,577.7
Long-term bonds - fair value		7,326.1	7,315.3	7,080.0	6,555.7
Senior Notes 3.000% (Jan 20/Jan 25)2) 3)	USD 63.6 mill	-	-	63.5	95.2
Senior Notes 2.875% (Sep 20/Jan 26)2)	USD 95.5 mill	95.4	95.2	-	-
Senior Notes 2.000% (Jul 21/Jul 26)2)	USD 104.8 mill	102.6	-	-	-
Accrued interest bonds4)		104.7	76.7	97.3	66.2
Short-term bonds - book value		302.6	171.9	160.8	161.4
Short-term bonds - fair value		302.5	171.3	160.8	161.0

¹⁾ In October 2024 the company issued two new US bonds:

The fair values of these bonds were lower than the principal value at the time of repurchase. Adjusted for expensed amortised cost, this resulted in a net loss of USD 5.7 million presented as other financial expense in Q4 2024.

Interest is paid on a semi-annual basis, except for the EUR Senior Notes which are paid on an annual basis. None of the bonds have financial covenants.

^- USD 750 million aggregate principal amount of 5.125% Senior Notes due 2034

^- USD 750 million aggregate principal amount of 5.800% Senior Notes due 2054

²⁾ Parts of the proceeds from the new bonds were used to repurchase the following principal amounts:

^- USD 31.9 million on USD Senior Notes 3.000% (Jan 2025)

^- USD 34.2 million on USD Senior Notes 2.875% (Jan 2026)

^- USD 602.3 million on USD Senior Notes 2.000% Senior Notes (Jul 2026)

³⁾ The bond was redeemed in January 2025.

⁴⁾ Prior to 2025 accrued interest on bonds was presented as other current liabilities, but is presented as short-term bonds from Q1 2025. Previous periods have been adjusted accordingly.

Note 12 Provision for abandonment liabilities

	Group
	2025	2025	2024
(USD million)	Q3	01.0130.06.	01.0131.12.
Provisions as of beginning of period	4,291.9	4,279.4	4,554.7
Incurred removal cost	-9.7	-56.8	-227.3
Accretion expense	47.9	93.2	184.1
Impact of changes to discount rate	136.9	-114.9	-358.0
Change in estimates and new provisions	104.6	91.0	126.0
Total provision for abandonment liabilities	4,571.6	4,291.9	4,279.4
Short-term	94.9	92.8	131.7
Long-term	4,476.6	4,199.0	4,147.7

The nominal pre-tax discount rate (risk-free) at end of Q3 is between 3.6 percent and 4.7 percent, depending on the timing of the expected cashflows.The corresponding range at end of Q2 2025 was 3.8 percent to 4.9 percent. The calculations assume an inflation rate of 2.0 percent.

Note 13 Derivatives

				Group
(USD million)	30.09.2025		30.06.2025	31.12.2024	30.09.2024
Unrealised gain on interest rate swaps		5.1	3.5	-	-
Unrealised gain currency contracts	63.8		82.2	5.0	26.1
Long-term derivatives included in assets	68.9		85.7	5.0	26.1
Unrealised gain commodity derivatives		6.8	10.1	-	-
Unrealised gain currency contracts	87.8		107.2	0.3	24.5
Short-term derivatives included in assets	94.6		117.4	0.3	24.5
Total derivatives included in assets	163.4		203.1	5.2	50.6
Unrealised losses interest rate swaps		-	-	7.1	-
Unrealised losses currency contracts		-	0.1	48.1	1.2
Long-term derivatives included in liabilities		-	0.1	55.3	1.2
Unrealised losses commodity derivatives		1.2	1.3	0.6	0.8
Unrealised losses currency contracts		0.9	0.3	151.1	27.2
Short-term derivatives included in liabilities		2.1	1.6	151.7	28.0
Total derivatives included in liabilities		2.1	1.7	207.0	29.2

The group uses various types of financial hedging instruments. Commodity derivatives may be used to hedge the price risk of oil and gas and foreign exchange derivatives are used to hedge the group's currency exposure, mainly in NOK, EUR and GBP.

The derivative portfolio is revalued on a mark to market basis, with changes in value recognised in the income statement. The nature of the derivative instruments and the valuation method are consistent with the disclosed information in the annual financial statements as of 31 December 2024. All derivatives are measured at fair value on a recurring basis (level 2 in the fair value hierarchy).

As of 30 September 2025, the company has hedged approximately 40 percent of its estimated post-tax oil price exposure for the fourth quarter of 2025 through the purchase of put options with a strike price of USD 65 per barrel. With regard to FX, the company's hedging programme currently covers 75-90 percent of planned NOK expenditures until end of 2027, at average USD/NOK rates between 10.5 and 11.0. In addition, accrued tax liabilities are hedged on a continuous basis.

Note 14 Other current liabilities

	Group
Breakdown of other current liabilities (USD million)	30.09.2025	30.06.2025	31.12.2024	30.09.2024
Balances with licence partners	171.2	106.9	61.0	117.2
Share of other current liabilities in licences	1,110.4	1,165.6	771.3	882.9
Overlift of petroleum	29.7	15.0	24.7	45.2
Accrued interest1)	34.7	32.1	25.7	24.7
Payroll liabilities and other provisions	206.2	186.9	165.8	247.5
Total other current liabilities	1,552.3	1,506.4	1,048.5	1,317.5

¹⁾ Prior to 2025 accrued interest on bonds was presented as other current liabilities, but is presented as short-term bonds from Q1 2025. Previous periods have been adjusted accordingly.

Note 15 Leasing

The incremental borrowing rate applied in discounting of the nominal lease debt is between 2.5 percent and 6.9 percent, dependent on the duration of the lease and when it was initially recognised.

		Group
	2025	2025	2024
(USD million)	Q3	01.0130.06.	01.0131.12.
Lease debt as of beginning of period	1,080.7	675.6	704.2
New leases and remeasurements2)	47.0	510.7	149.9
Payments of lease debt1)	-94.4	-138.6	-197.2
Lease debt derecognised	-	-	-14.5
Interest expense on lease debt	13.7	21.4	38.1
Currency exchange differences	1.9	11.6	-4.8
Total lease debt	1,048.8	1,080.7	675.6
Short-term	353.8	340.8	217.7
Long-term	695.1	739.8	458.0
1) Payments of lease debt split by activities (USD million):
Investments in fixed assets	36.3	44.3	65.4
Abandonment activity	0.0	2.3	26.2
Operating expenditures	2.7	4.7	7.6
Exploration expenditures	7.5	24.3	31.6
Other income	47.8	63.0	66.5
Total	94.4	138.6	197.2

²⁾ New leases and remeasurements in Q3 2025 are mainly related to new Stavanger office.

	Group
	2025	2025	2024
Nominal lease debt maturity breakdown (USD million):	Q3	01.0130.06.	01.0131.12.
Within one year	396.0	385.5	247.5
Two to five years	652.9	733.7	480.7
After five years	161.3	106.9	1.9
Total	1,210.2	1,226.1	730.1

The identified leases have no significant impact on the group's financing, loan covenants or dividend policy. The group does not have any residual value guarantees. Extension options are included in the lease liability when, based on management's judgement, it is reasonably certain that an extension will be exercised.

Note 16 Contingent liabilities and assets

During the normal course of its business, the group will be involved in disputes, including tax disputes. The group has made accruals for probable liabilities related to litigation and claims based on management's best judgment and in line with IAS 37 and IAS 12.

Note 17 Subsequent events

The group has not identified any events with significant accounting impacts that have occurred between the end of the reporting period and the date of this report that require accounting recognition or disclosure in these interim financial statements.

Note 18 Investments in joint operations

Total number of licences	30.09.2025	30.06.2025
Aker BP as operator	135	138
Aker BP as partner	56	53

Changes in production licences in which Aker BP is the operator:			Changes in production licences in which Aker BP is a partner:
Licence:	30.09.2025	30.06.2025 Licence:		30.09.2025	30.06.2025
PL 10421)	0.000%	40.000%	PL 9352)	0.000%	20.000%
PL 11021)	0.000%	55.000%	PL 10421)	40.000%	0.000%
PL 1102B1)	0.000%	55.000%	PL 11021)	20.000%	0.000%
			PL 1102B1)	20.000%	0.000%
			PL 1102C1)	20.000%	0.000%
Total	-		3 Total	4	1

¹⁾ Part of asset transactions

End of financial statement

²⁾ Relinquished or Aker BP has withdrawn from the licence

Alternative Performance Measures

Aker BP may disclose alternative performance measures as part of its financial reporting as a supplement to the financial statements prepared in accordance with IFRS. Aker BP believes that the alternative performance measures provide useful supplemental information to management, investors, security analysts and other stakeholders and are meant to provide an enhanced insight into the financial development of Aker BP's business operations and to improve comparability between periods.

In the second quarter of 2025 leverage ratio was revised so that financial investments are deducted when calculating net interest-bearing debt. This approach aligns with the leverage ratio definition used for the financial covenants in the company's Revolving Credit Facility. The definition of free cash flow was also adjusted to reflect the financial investment.

Abandonment spend (abex) is payment for removal and decommissioning of oil fields1)

Available liquidity is the sum of cash and cash equivalents, financial investments and undrawn RCF facility

Capex is disbursements on investments in fixed assets1)

Depreciation per boe is depreciation divided by number of barrels of oil equivalents produced in the corresponding period

Dividend per share (DPS) is dividend paid in the quarter divided by number of shares outstanding

EBITDA is short for earnings before interest and other financial items, taxes, depreciation and amortisation and impairments

EBITDAX is short for earnings before interest and other financial items, taxes, depreciation and amortisation, impairments and exploration expenses

Equity ratio is total equity divided by total assets

Exploration spend (expex) is exploration expenses plus additions to capitalised exploration wells less dry well expenses1)

Free cash flow (FCF) is net cash flow from operating activities less net cash flow from investment activities, adjusted for investments in financial assets

Interest coverage ratio is calculated as twelve months rolling EBITDA, divided by interest expenses, excluding any impacts from IFRS 16

Leverage ratio is calculated as net interest-bearing debt divided by twelve months rolling EBITDAX, excluding any impacts from IFRS 16

Net interest-bearing debt is book value of current and non-current interest-bearing debt less financial investments and cash and cash equivalents

Operating profit/loss is short for earnings/loss before interest and other financial items and taxes

Production cost per boe is production expenses based on produced volumes, divided by number of barrels of oil equivalents produced in the corresponding period (see note 2)

¹⁾ Includes payments of lease debt as disclosed in note 15.

		Q3	Q2	Q3	01.0130.09.	01.0130.09.
(USD million)	Note	2025	2025	2024	2025	2024
Abandonment spend
Payment for removal and decommissioning of oil fields		9.7	32.1	66.5	64.7	191.8
Payments of lease debt (abandonment activity)	15	0.0	0.4	8.0	2.4	26.0
Abandonment spend		9.7	32.5	74.5	67.1	217.8
Depreciation per boe
Depreciation	6	614.7	591.4	613.9	1,897.1	1,794.3
Total produced volumes (boe million)	2	38.1	37.8	38.2	115.6	119.3
Depreciation per boe		16.1	15.7	16.1	16.4	15.0
Dividend per share
Paid dividend		398.2	398.2	379.2	1,194.5	1,137.6
Number of shares outstanding		630.5	631.5	630.8	631.3	631.1
Dividend per share		0.63	0.63	0.60	1.89	1.80
Capex Disbursements on investments in fixed assets (excluding capitalised interest)		1,764.9	1,799.5	1,257.5	4,868.4	3,501.6
Payments of lease debt (investments in fixed assets)	15	36.3	28.5	11.1	80.6	49.3
CAPEX		1,801.2	1,828.0	1,268.6	4,949.1	3,550.8
EBITDA
Total income	1	2,598.5	2,584.1	2,857.6	8,383.4	9,311.7
Production expenses	2	-246.2	-285.1	-186.1	-809.7	-687.3
Exploration expenses	3	-71.9	-59.8	-40.0	-239.0	-215.8
Other operating expenses		-18.3	-15.8	-19.2	-48.5	-43.4
EBITDA		2,262.1	2,223.4	2,612.2	7,286.2	8,365.3
EBITDAX
Total income	1	2,598.5	2,584.1	2,857.6	8,383.4	9,311.7
Production expenses Other operating expenses	2	-246.2 -18.3	-285.1 -15.8	-186.1 -19.2	-809.7 -48.5	-687.3 -43.4
EBITDAX		2,334.0	2,283.2	2,652.2	7,525.2	8,581.0
Equity ratio
Total equity		11,738.3	11,850.8	12,476.8	11,738.3	12,476.8
Total assets		44,175.4	42,877.3	41,693.0	44,175.4	41,693.0
Equity ratio		27%	28%	30%	27%	30%
Exploration spend
Disbursements on investments in capitalised exploration expenditures		96.0	66.9	77.5	260.1	255.4
Exploration expenses	3	71.9	59.8	40.0	239.0	215.8
Dry well	3	-24.2	-28.2	-3.8	-127.5	-114.8
Payments of lease debt (exploration expenditures)	15	7.5	11.6	13.5	31.8	22.9
Exploration spend		151.2	110.1	127.3	403.4	379.3

		Q3	Q2	Q3	01.0130.09.	01.0130.09.
(USD million)	Note	2025	2025	2024	2025	2024
Interest coverage ratio
Twelve months rolling EBITDA		10,003.9	10,354.1	11,539.6	10,003.9	11,539.6
Twelve months rolling EBITDA, impacts from IFRS 16	15	-144.2	-112.3	-62.3	-144.2	-62.3
Twelve months rolling EBITDA, excluding impacts from IFRS 16		9,859.7	10,241.7	11,477.3	9,859.7	11,477.3
Twelve months rolling interest expenses	4	348.5	332.1	240.1	348.5	240.1
Twelve months rolling amortised loan cost	4	31.0	35.4	46.3	31.0	46.3
Twelve months rolling interest income	4	154.1	168.3	157.2	154.1	157.2
Net interest expenses		225.5	199.2	129.3	225.5	129.3
Interest coverage ratio		43.7	51.4	88.8	43.7	88.8
Leverage ratio
Long-term bonds	11	7,362.7	7,455.5	6,577.7	7,362.7	6,577.7
Short-term bonds	11	302.6	171.9	161.4	302.6	161.4
Other interest-bearing debt		-	-	-	-	-
Cash and cash equivalents	10	2,343.6	2,745.5	4,147.4	2,343.6	4,147.4
Financial investments	9	300.0	300.0	-	300.0	-
Net interest-bearing debt excluding lease debt		5,021.8	4,581.8	2,591.8	5,021.8	2,591.8
Twelve months rolling EBITDAX		10,353.7	10,671.9	11,822.4	10,353.7	11,822.4
Twelve months rolling EBITDAX, impacts from IFRS 16	15	-143.4	-111.3	-61.5	-143.4	-61.5
Twelve months rolling EBITDAX, excluding impacts from IFRS 16		10,210.3	10,560.6	11,760.9	10,210.3	11,760.9
Leverage ratio1)		0.49	0.43	0.22	0.49	0.22
Net interest-bearing debt
Long-term bonds	11	7,362.7	7,455.5	6,577.7	7,362.7	6,577.7
Short-term bonds	11	302.6	171.9	161.4	302.6	161.4
Other interest-bearing debt		-	-	-	-	-
Long-term lease debt	15	695.1	739.8	538.1	695.1	538.1
Short-term lease debt	15	353.8	340.8	222.1	353.8	222.1
Cash and cash equivalents	10	2,343.6	2,745.5	4,147.4	2,343.6	4,147.4
Financial investments	9	300.0	300.0	-	300.0	-
Net interest-bearing debt1)		6,070.6	5,662.5	3,352.0	6,070.6	3,352.0
Available liquidity
Cash and cash equivalents	10	2,343.6	2,745.5	4,147.4	2,343.6	4,147.4
Financial investments	9	300.0	300.0	-	300.0	-
Undrawn RCF facility	10	2,950.0	2,950.0	3,400.0	2,950.0	3,400.0
Available liquidity		5,593.6	5,995.5	7,547.4	5,593.6	7,547.4
Free cash flow
Net cash flow from operating activities		2,022.6	1,240.1	2,756.5	5,372.1	5,360.0
Net cash flow from investment activities		-1,870.5	-2,198.5	-1,401.6	-5,493.3	-3,948.8
Investments in financial assets		-	300.0	-	300.0	-
Free cash flow		152.0	-658.4	1,355.0	178.8	1,411.3

¹⁾ Prior to 2025 accrued interest on bonds was presented as other current liabilities, but is presented as short-term bonds from Q1 2025. Previous periods have been adjusted accordingly.

Operating profit/loss see Income Statement

Production cost per boe see note 2

To the Shareholders of Aker BP ASA

Report on Review of Interim Financial Information

Introduction

We have reviewed the accompanying condensed consolidated statement of financial position of Aker BP ASA as at 30 September 2025, and the related condensed consolidated income statement, the statement of comprehensive income, the statement of changes in equity and the statement of cash flows for the three-month and nine-month period then ended, and a summary of significant accounting policies and other explanatory notes. Management is responsible for the preparation of this interim financial information in accordance with IAS 34 Interim Financial Reporting. Our responsibility is to express a conclusion on this interim financial information based on our review.

Scope of Review

We conducted our review in accordance with International Standard on Review Engagements 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity. A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (ISAs), and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the accompanying consolidated interim financial information is not prepared, in all material respects, in accordance with IAS 34 Interim Financial Reporting.

Stavanger, 21 October 2025 PricewaterhouseCoopers AS

Gunnar Slettebø

State Authorised Public Accountant

Aker BP ASA

Fornebuporten, Building B

www.akerbp.com

CONTACT

Postal address: P.O. Box 65

Telephone: +47 51 35 30 00