Vår Energi in brief

Vår Energi is a leading independent upstream oil and gas company on the Norwegian continental shelf (NCS). To learn more, please visit varenergi.no.

Vår Energi is listed on the Oslo Stock Exchange (OSE) under the ticker "VAR".

About Vår Energi	2
Key figures	3

Highlights	4

Key metrics and targets	5

Operational review	6
Exploration	13
HSSE	14

Financial review	16
Key figures	16
Revenues and prices	18
Statement of financial position	19
Statement of cash flow	20
Outlook	21
Alternative Performance	22
Measures

Financial statements	23

Notes	29

Key figures third quarter 2025

Second quarter 2025 in brackets

Production kboepd

370

(288)

CFFO USD million

1 234

(766)

Petroleum revenues USD million

2 115

(1 828)

Capex USD million

726 (761)

EBIT USD million

1 071 (1 195)

FCF USD million

508 (4)

Profit before tax USD million

1 005

(1 234)

NIBD/EBITDAX

0.9

(0.9)

Third quarter 2025 highlights

Vår Energi reports strong third quarter results with transformational growth delivered ahead of schedule and a pipeline of new projects being progressed for long-term value creation

Production milestones met ahead of schedule

Average fourth quarter production expected ~430 kboepd
Jotun FPSO reached peak production in September
Adding ~180 kboepd at peak from new projects in 2025, 7 out of 9 projects on stream
Derisked outlook with key projects delivered

Solid financial performance

Significant cash flow from operations of USD 1.2 billion
Reduced net debt and USD 3.6 billion of available liquidity
Unit production cost expected around USD 10 per boe in the fourth quarter of 2025
18% of third quarter gas volumes sold at USD 90 per boe

Unlocking long-term future value creation

Expected to sanction ten projects in 2025
Increasing ownership in Ekofisk PPF project adding high value barrels

Delivering predictable and attractive dividends

Third quarter dividend of USD 300 million (NOK 1.211 per share) will be distributed 25 November¹
Full year dividend guidance for 2025 and 2026 of USD 1.2 billion

KPIs (USD million unless otherwise stated)	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024
Actual serious incident frequency (x, 12 months rolling)	-	-	0.1	-	0.1
CO2 emissions intensity (equity share, kg/boe)	9.4	10.5	10.0	9.9	10.0
Production (kboepd)	370	288	256	311	281
Production cost (USD/boe)	10.6	12.7	13.6	11.6	12.6
Cash flow from operations before tax	1 765	1 270	1 635	4 571	4 780
Cash flow from operations (CFFO)	1 234	766	1 310	3 322	3 030
Free cash flow (FCF)	508	4	592	1 240	846
Dividends paid	300	300	270	870	810

¹The dividend is subject to EGM approval 11 November

"We are pleased to see strong results for the quarter. Seven of the nine growth projects planned for start-up in 2025 are on stream, including Johan Castberg and the Jotun FPSO at the Balder field, with both producing at plateau. Our company is de-risked and has never been in a stronger position to continue to deliver high value and attractive shareholder returns.

With the strong ramp up of our new projects we expect to produce an average of approximately 430 thousand barrels of oil per day (kboepd) in the fourth quarter and we're on track to meet around the mid-point of the full year guidance range of 330 to 360 kboepd.

We are on target to sustain production at 350 to 400 kboepd towards 2030 and beyond. This will be delivered through our portfolio of around 30 early phase projects, backed by already discovered resources that are being moved towards development sanction at pace. We expect to sanction 10 projects in 2025, of which 4 are already moving forward, with average break evens below 35 USD/boe. Furthermore, the recent acquisition of TotalEnergies' interest in the Ekofisk Previously Produced Fields project adds high value barrels to our portfolio at an attractive price.

The Company demonstrates strong resilience, driven by solid financial results, reduced net debt and efficient operating cost of 10.6 USD/boe in the quarter.

On the back of this strong performance Vår Energi continues to provide attractive shareholder distributions. We confirm a dividend of USD 300 million for the third quarter and maintain our total dividend distribution guidance of USD 1.2 billion for the full year 2025 and 2026."

Nick Walker, the CEO of Vår Energi

Key metrics and targets

Income statement	Unit	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024
Total income	USD million	2 140	1 849	1 871	5 861	5 767
EBIT	USD million	1 071	1 195	740	3 238	2 786
Profit/(loss) before taxes	USD million	1 005	1 234	760	3 518	2 642
Net profit/(loss)	USD million	152	217	180	821	502
Earnings per share	USD	0.05	0.08	0.07	0.31	0.18
Other financial key figures
Production cost	USD/boe	10.6	12.7	13.6	11.6	12.6
Net interest-bearing debt (NIBD)	USD million	5 136	5 209	4 161	5 136	4 161
Leverage ratio (NIBD/EBITDAX)		0.9	0.9	0.7	0.9	0.7
Dividend per share	USD	0.12	0.12	0.11	0.35	0.32
Production
Total production	kboepd	370	288	256	311	281
- Oil	kboepd	255	180	154	199	162
- Gas	kboepd	98	92	86	95	100
- NGL	kboepd	18	16	16	17	19
Sales
Total sales	mmboe	31.1	26.0	24.0	80.8	74.9
- Crude oil	mmboe	20.8	17.1	14.2	52.9	43.9
- Gas1	mmboe	8.6	7.7	7.7	24.4	24.8
- NGL	mmboe	1.7	1.2	2.0	3.6	6.3
Realised prices
- Crude oil	USD/boe	68.6	68.5	80.6	70.6	83.3
- Gas1	USD/boe	72.4	78.8	76.2	79.1	70.8
- NGL	USD/boe	39.0	42.8	46.4	43.3	47.1
Average realised prices (volume weighted)		68.0	70.4	76.3	71.9	76.2

	1 Corrected with lifting on 30th September not included in trading update
--	---------------------------------------------------------------------------

Targets and outlook
2025 guidance (USD million unless otherwise	stated)
Full Year Production	kboepd	330-360
Q4 2025 production target	kboepd	~ 430
Production cost	USD/boe	11-12
Development capex		2 300- 2 500
Exploration capex		~ 400
Abandonment capex		~ 100
Dividend for Q3 2025 to be distributed in November		300
2025 Full year dividend guidance		1 200
4Q 2025 cash tax payment estimate1		~ 800

Long-term financial and operational targets
2026 production target	kboepd	~ 400
2027-2030 production target	kboepd	350-400
Q4 2025 and long-term production cost2	USD/boe	~ 10
2026-2030 development capex3		2 000 - 2 500
2026-2030 exploration capex3		200 - 300
2026-2030 abandonment capex3		~ 150
2026 Full year dividend guidance		1 200
Leverage through the cycle	NIBD/EBITDAX	< 1.3x

¹ Assumed NOK/USD at 10.5

In real 2025 and NOK/USD at 10.5

³ Per Annum

Operational review

Vår Energi's production of oil, liquids and natural gas averaged 370 kboepd in the third quarter of 2025. Production for the first nine months of the year averaged 311 kboepd. At the end of August the Company achieved the 400 kboepd production level milestone, ahead of schedule due to the Jotun FPSO at the Balder field ramping up faster than anticipated. The Company is also on track to produce around 430 kboepd in the fourth quarter this year, delivering on the strategy for transformational growth in 2025. The full year 2025 production is expected to be around the middle of the guided range of 330 to 360 kboepd.

Vår Energi's net production of oil, liquids and natural gas averaged 370 kboepd in the third quarter 2025, an increase of 29% from the previous quarter and at the top of the expected range. Production for the first nine months averaged 311 kboepd, which is in line with guided expectations, with the ramp-up of the Jotun FPSO ahead of plan mostly offsetting the impact of the later start-up and ramp-up of Johan Castberg compared to expectations. Strong operational performance continues on operated assets, with production efficiency better than target at 92% for the first nine months of 2025¹ . All main turnaround activities for 2025 have been completed by the end of the third quarter, with an impact of around 10 kboepd on full year production.

Vår Energy plans to start-up nine new projects during 2025, adding around 180 kboepd production at peak levels. Seven of these projects are on stream, which are currently contributing around 150 kboepd of new production to the portfolio, and the remaining two projects are targeted to start-up by end 2025. Halten East started up in March, on time and within budget, and is expected to start-up one further well before year end, bringing production close to plateau levels.

Production split third quarter

¹ Excluding Jotun FPSO ramp-up

The current production potential across the portfolio positions the Company to produce around 430 kboepd during fourth quarter.

Average production costs in third quarter was USD 10.6 per boe, and for the first nine months was USD 11.6 per boe. It is expected that full year production cost will be at the bottom end of the guidance range of USD 11-12 per boe. The Company expects that production costs will reduce to around USD 10 per boe in the fourth quarter of 2025 through the ramp up of lower cost barrels from the new projects and continuous cost improvements.

The Company's significant discovered resource base and comprehensive early phase project portfolio including the recent sanctions supports sustainable production of 350 to 400 kboepd towards 2030 and beyond. The Company is progressing around 30 early phase projects accounting for net 2C contingent resources of around 650 mmboe and expects to sanction 10 projects during 2025. Four projects have been sanctioned so far in 2025, amongst these, Balder Phase VI, a fast-track development operated by Vår Energi that will contribute with high value production through the Jotun FPSO already in late 2026 and Fram Sør, a subsea tie-back development to Troll C developing 116 mmboe gross¹ resources.

The Company has made five commercial exploration discoveries so far in 2025, with the two Equinor operated wells, F Sør and Smørbukk Midt, completed in the third quarter. The latter was drilled in August and put on production in September achieving initial production rates of around 30 kboepd gross² . The Goliat Ridge discoveries are being matured as a fast-track subsea development with flexibility to include potential future discoveries, and the first of two further appraisal wells is ongoing, with results expected before the end of 2025. The expected total exploration spend for 2025 is increased to around USD 400 million, following successful wells.

Since 2019 the Company has added around 300 mmboe in net contingent resources (2C) from the discoveries made, and more than 70% of these volumes are either under development planning, have taken project sanction or have started production.

With Vår Energi's major projects having been completed the Company has been de-risked. Looking forward a pipeline of smaller low-risk tie-back projects and a significant infill well programme across the portfolio will sustain production levels long term. These represent a series of smaller low risk decisions and, with around 65% of future capital spend uncommitted³ there is significant flexibility in the business to manage the capital spend programme through the commodity price cycles.

Production (kboepd)	Q3 2025	Q2 2025	Q3 2024		YTD 2025 YTD 2024
Balder Area	97	63	53	75	53
Barents Sea	90	36	32	51	31
North Sea	81	85	102	86	105
Norwegian Sea	103	104	70	99	91
Total Production	370	288	256	311	281

¹ Vår Energi working interest 40%

²Vår Energi working interest 22.65%

³ Average over period 2025-2030

As part of Vår Energi's hub strategy, the Company identifies strategic focus areas that provide a framework for evaluating exploration and development opportunities, maximising the use of existing infrastructure and optimising value creation throughout the asset portfolio.

Balder Area

Production (kboepd)	Q3 2025	Q2 2025	Q1 2025	Q4 2024	Q3 2024
Balder/Ringhorne	59	27	25	25	24
Grane/Svalin	11	10	12	11	10
Breidablikk	27	26	27	24	19
Total Balder Area	97	63	64	60	53

Performance from the Balder Area was strong with production of 97 kboepd in the third quarter, an increase of 54% compared to the second quarter, driven by the production start-up and the accelerated ramp-up at the Jotun FPSO at the Balder field, which has all fourteen subsea production wells started up unlocking gross proved plus probable (2P) reserves of around 150 mmboe1,2 . Due to the successful offshore completion of the project, the peak rate was achieved ahead of schedule in September. Average production from these wells is according to expectations, and work is ongoing to further optimise production levels going forward. In addition, the Company has also benefited from continued strong performance at the Breidablikk field. The Balder field production efficiency was 93% for the first nine months of the year³ , including a successfully conducted planned turnaround at Balder.

Average production year to date from the Balder Area was 75 kboepd, which is above expectations. In the fourth quarter it is expected that three Balder Phase V wells will be brought onstream and also new wells at Ringhorne, Breidablikk and Grane will achieve first oil.

¹ Balder Phase V and VI not included ² Vår Energi working interest 90%, ³ Excluding Jotun FPSO ramp-up

Projects

The Jotun FPSO project was fully completed by end September 2025 and, the project team has been demobilised.

The drilling of six new wells as part of Balder Phase V project is progressing as planned, with three wells expected to commence production during the fourth quarter 2025. Additionally, the Balder Phase VI project is in execution, ahead of original plan with anticipated first oil by end 2026, with strong economics at an internal rate of return (IRR) above 35% and breakeven price below USD 35 per boe. Together these projects will capture gross proved plus probable (2P) reserves in the range of 45-50 mmboe¹ .

Further early phase projects are also being progressed at pace to maximise the production capacity of the Jotun FPSO in the years to come. The Balder Next project is targeting to develop the next phase for the Balder field and unlock significant contingent resources. The project consists of taking the Balder Floating Production Unit (FPU) to shore for decommissioning, targeted in 2028. Selected wells producing through Balder FPU will be transferred to the Jotun FPSO. In addition, production will be accelerated as part of the Jotun FPSO debottlenecking project to increase production capacity on the FPSO, as well as developing new production wells. Combined this gives production from the Balder field area in the range 70-80 kboepd gross¹ towards 2030. The decommissioning of Balder FPU is expected to reduce operating costs by approximately USD 130 million gross¹per annum and to reduce CO2 emissions by around 80,000 tonnes gross¹per year. The above projects are steps to ensure high value barrels from the Balder area towards 2045 and beyond.

Barents Sea

Production (kboepd)	Q3 2025	Q2 2025	Q1 2025	Q4 2024	Q3 2024
Goliat	16	13	14	14	15
Johan Castberg	64	20	-	-	-
Snøhvit	9	4	13	16	17
Total Barents Sea	90	36	26	30	32

Average production in the Barents Sea was 90 kboepd in the third quarter, an increase of 150% from the second quarter due to the ramp-up of Johan Castberg.

The Goliat field had a production efficiency in the first nine months of 2025 of 96%, including planned maintenance activities in the second quarter. Year to date two new infill wells have been drilled at the Goliat field, with strong production above expectations. Acquisition of 4D seismic at Goliat and 3D seismic at the Goliat Ridge was concluded in the quarter, which will support the development of future drilling plans.

Johan Castberg reached plateau levels in June, with 66 kboepd net to Vår Energi. The field will be producing for more than 30 years, contributing to significant growth and value creation, with expected pay-back time of less than 2 years from start-up. The project has completed nineteen of the thirty planned development wells. The drilling program is scheduled to be completed by end of 2026.

Snøhvit has executed a planned turnaround in the second and third quarters, commencing in April and with production re-starting in August. In addition, the Askeladden West project started up in the quarter, an important contributor to maintain production plateau at the Snøhvit field and ensure full capacity utilisation at Hammerfest LNG¹ for years to come.

¹ Vår Energi working interest 90%

¹ Liquified Natural Gas

The project adds gross recoverable reserves of around 15 billion standard cubic metres of gas.

Average production from the Barents Sea for the first nine months of the year was 51 kboepd, and further production increase will come for the remainder of the year due to Johan Castberg production remaining at plateau levels and with stable Goliat and Snøhvit production.

Projects

The Johan Castberg area is highly prospective, and several new discoveries made in recent years are already being matured, including an extensive infill drilling program planned to be sanctioned in 2025. The Johan Castberg Cluster 1 development project consisting of two phases, Isflak and Snøfonn/Skavl with the Isflak development expected to be sanctioned by end fourth quarter 2025. In total, there are expected to be between 250 and 550 million barrels of new gross unrisked recoverable resources identified in the area, supporting continued high production at Johan Castberg towards 2030 and beyond.

Snøhvit is progressing the next plateau extension project, "Snøhvit Future", that entails both onshore compression and electrification of the Hammerfest LNG onshore facility. The start of onshore compression is planned for late 2028 and the plant will be electrified with power from the grid in 2029.

North Sea

Production (kboepd)	Q3 2025	Q2 2025	Q1 2025	Q4 2024	Q3 2024

Ekofisk Area	21	15	21	23	22
Snorre	16	17	16	17	18
Gjøa Area	11	15	15	18	17
Gudrun	4	7	6	6	5
Statfjord Area	10	10	12	12	14
Fram	11	12	13	15	15
Sleipner Area	2	3	3	4	5
Other	5	5	5	5	6
Total North Sea	81	85	92	100	102

Production from North Sea was 81 kboepd in the third quarter, an 8% reduction from previous quarter mainly due to planned turnarounds at Gjøa and Sleipner/Gudrun fields.

Vår Energi's operated assets have continued to perform strongly with the Gjøa area achieving 89% production efficiency in the first nine months of 2025, this includes the planned turnaround in the quarter. In addition, the Gjøa Low Pressure Project (LPP) started production in September, which increases gross production by around 6 kboepd, as well as increasing the recoverable volumes with approximately 25% from the Gjøa field.

North Sea average production for the first nine months of the year was 86 kboepd in line with expectations.

Restoration of Sleipner B production after the fire in 2024 is ongoing and full production is expected to be resumed in the first half of 2027. The after-tax cash impact is compensated by insurance coverage, which covers the lost production at a predefined price for up to twelve months.

Projects

The Fram Sør subsea tieback, Gudrun Low Pressure and Snorre Gas Export projects have been sanctioned in 2025.

Fram Sør will develop 116 mmboe gross proved plus probable (2P) reserves¹ and consists of several discoveries combined into one subsea development project that will export oil and gas via the Troll C platform. The development will bring highly valuable barrels on stream by connecting new infrastructure to existing facilities. Fram Sør has strong economics and fulfils Vår Energi's investment criteria for new developments. The Fram area continues to offer compelling potential for value creation. Building on recent discoveries, Mulder and Rhombi, the F-Sør discovery in the third quarter 2025 shows the potential of unlocking further resources¹ . Further exploration targets are set to be drilled in the years to come.

The Gjøa subsea projects are being matured towards final investment decision. The project consists of the Ofelia, Kyrre, Gjøa North and Cerisa discoveries, with up to 110 mmboe in estimated gross recoverable resources² . The current plan is to make a project concept selection by end 2025 and with the target to sanction the project in 2026.

In the Ekofisk area the Ekofisk PPF (Previously Produced Fields) project is being matured towards an investment decision within year end 2025. In October Vår Energi announced the acquisition of TotalEnergies' ownership interest in the Ekofisk PPF project increasing the Company's equity from 12.388% to 52.284%. The transaction will add estimated net proved plus probable reserves of 38 million barrels of oil equivalent (mmboe) with low operating costs per barrel and potential for further growth. The purchase price is USD 147 million and completion of the transaction is subject to Final Investment Decision for the project and customary regulatory approvals, including the carve-out of the PL018F licence from the PL018 licence. The transaction is expected to be completed by end 2025. In addition, final investment decision is targeted for the Eldfisk North project by end 2025.

¹ Vår Energi working interest 40%

² Vår Energi working interest 30% in Cerisa and Gjøa North, 40% in Ofeila and Kyrre

Norwegian Sea

Production (kboepd)	Q3 2025	Q2 2025	Q1 2025	Q4 2024	Q3 2024

Åsgard area	36	36	32	33	23
Mikkel	7	10	10	8	5
Tyrihans	11	13	13	11	8
Halten Øst	13	11	-	-	-
Ormen Lange	10	6	8	9	8
Fenja	7	11	12	15	13
Njord Area	10	9	6	5	4
Other	8	9	9	7	7
Total Norwegian Sea	103	104	90	88	70

In the Norwegian Sea production for the third quarter was 103 kboepd, in line with the previous quarter. Average production for the first nine months of 2025 was 99 kboepd, slightly above expectations.

During third quarter a commercial discovery was made in the Åsgard area with the successful drilling of Smørbukk Midt target. The discovery was made in August and production started early September with high initial rates of around 30 kboepd gross¹ . Åsgard subsea compression phase II project was also successfully brought onstream at the end of the quarter. The Åsgard Low Pressure Production 3 (LPP3) project is targeting startup by year end.

The increased production in 2025 is mainly due to the Halten East project coming on stream in March 2025, expecting to provide Vår Energi with net production of around 20 kboepd at peak levels expected in first half of 2026. The Company expects one additional Halten East well to come onstream before year end, further increasing production levels. The field holds gross reserves of around 100 mmboe² , and the area has additional unrisked gross recoverable resource potential of 100-200 mmboe for future development.

In addition, the Ormen Lange Phase III project started production at the end of second quarter this year, boosting production from the gas field with subsea compression. The project will increase recovery from 75% to 85% for the field and recover additional 30-50 billion cubic metres of gross gas reserves³ .

¹ Vår Energi 22.65% working interest

² Vår Energi 24.6% working interest

³ Vår Energi 6.3356% working interest

Exploration

The Company's exploration programme continues to deliver successful results, with five commercial discoveries so far in 2025 from the 15 exploration wells drilled, continuing the Company's leading exploration track record on the NCS. The five discoveries contain net recoverable resources in the range of 40 to 70 mmboe and all will be developed as subsea tie-back projects, adding high value barrels. A further 7 exploration wells are planned to be completed in 2025. The expected exploration spend for 2025 is increased to around USD 400 million, as a result of successful wells.

The Vår Energi operated Vidsyn exploration well in licence PL586, close to the Fenja field, in the Norwegian Sea is assessed as a commercial discovery in July. The discovery could open up new opportunities in neighbouring segments of the Vidsyn ridge, which will be further assessed with an appraisal campaign in 2026, targeting potential of up to 100 mmboe gross. The gross recoverable resources for the Vidsyn well are estimated in the range of 25 to 40 mmboe¹ .

The Equinor operated Drivis Tubåen exploration well in licence PL 532, close to Johan Castberg, in the Barents Sea was a commercial discovery. The gross recoverable resources are estimated in the range of 9 to 15 mmboe² . The exploration program close to Johan Castberg is key to unlock the prospective resources, ensuring the capacity of the newly started facility is utilised at full towards 2030 and beyond.

At Goliat, the Company has formally initiated an early phase project to progress the recent discoveries in the Goliat Ridge³, with the close proximity to Goliat FPSO providing the opportunity for a fast track, low emission, cost-efficient development adding high value barrels. The discoveries continue to demonstrate the potential of the Goliat ridge, with estimated gross discovered and prospective recoverable resources of above 200 mmboe. Two further appraisal wells will be completed before the end of 2025, with the first well ongoing. A new 3D seismic survey was acquired in the second quarter over the Goliat Ridge area to support development studies.

The Equinor operated F Sør exploration well in licence PL090, close to the Fram infrastructure in the North Sea, is considered a commercial discovery despite the limited estimated gross recoverable resources of around 4 mmboe⁴ further demonstrating the value of Infrastructure Led Exploration (ILX) in a highly prolific area with multiple commercial solutions. The discovery is being considered for

a tie-in to existing infrastructure or as part of a future new development in the area.

Another ILX example with successful results is Equinor operated Smørbukk Midt well in licence PL094, close to Smørbukk Sør and the Åsgard field. With estimated gross recoverable resources of around 13 mmboe⁵ , the well is already producing having been tied-in to the existing Smørbukk Sør infrastructure.

The Equinor operated Deimos exploration well in licence PL1238 and the Equinor operated Narvi well in licence PL554C were concluded in the third quarter, both were dry wells.

During the third quarter, Vår Energi submitted applications in the 2025 Awards in Predefined Areas (APA) annual licensing round, with awards expected in early 2026.

¹ Vår Energi working interest 75%

² Vår Energi working interest 30%

³ Vår Energi working interest 65%

⁴ Vår Energi working interest 40%

⁵ Vår Energi working interest 22.65%

Health, safety, security and the environment (HSSE)

Key HSSE indicators, operated activity	Unit	Q3 2025	Q2 2025	Q1 2025	Q4 2024	Q3 2024

Serious incident frequency (SIF Actual)1 12M rolling avg	Per mill. exp. Hours	0.0	0.0	0.0	0.1	0.1
Serious incident frequency (SIF)1 12M rolling avg	Per mill. exp. Hours	0.7	0.4	0.3	0.3	0.3
Total recordable injury frequency (TRIF)2 12M rolling avg	Per mill. exp. Hours	3.0	2.7	3.3	3.5	3.1
Significant spill to sea	Count	0	0	0	0	0
Process safety events Tier 1 and 23	Count	1	0	0	0	0
emissions intensity (equity share)4,5 CO2	kg CO2/boe	9.4	10.5	9.9	9.5	10.0

Vår Energi's commitment to safety remains strong with the ambition to be the safest operator on the NCS. The Company continues to enforce the safety tools and improvement initiatives proven to be effective, in close collaboration with our partners and contractors. During the third quarter the Company continued the positive performance with no actual serious incidents, however has experienced over the last quarter some

incidents with serious potential and one process safety event (tier 2). Vår Energi believes in the importance of learning from such events, and are currently addressing outcomes from the investigations. Recordable injuries in the third quarter are of lower potential. The Company extracts learnings from incidents to avoid similar events in the future.

¹SIF: Serious incident and near-misses per million worked hours. Includes actual and potential consequence. SIF Actual: incidents that have an actual serious consequence.

²TRIF: Personal injuries requiring medical treatment per million worked hours. Reporting boundaries SIF & TRIF: Health and safety incident data is reported for company sites as well as contracted drilling rigs, flotels, vessels, projects, and modifications, and transportation of personnel, using a risk-based approach.

³Classified according to IOGP RP 456.

⁴Direct Scope 1 emissions of CO2 (net equity share) of Company portfolio (operated and partner operated) kg of CO2 per produced barrel of oil equivalent.

⁵Emission numbers are preliminary until the EU ETS verification is completed by end of the first quarter 2025. Previous quarters are adjusted for errors in estimates.

ESG and decarbonisation

Vår Energi has industry leading ESG performance and is ranked amongst the top 15% in the global oil and gas industry by Sustainalytics and was with that once again awarded with the badge "2025 Sustainalytics ESG top rated Industry". The Company is also the only operator on the NCS with an ISO 50001:2018 energy management certification.

Vår Energi targets to reduce its net equity scope 1 GHG¹ emissions from three main levers, electrification with power from shore, portfolio optimisation and energy management. Following further assessment of the Halten and Snorre power from shore projects, these are proposed to be discontinued due to challenging economics. The Grane Balder Energy project will be further matured prior to potential concept select and final investment decision. The discontinuing of the two projects is expected to have limited impact on Vår Energi's overall emission reductions, with a path to reduce emissions with around 40% in the early 2030s.

In addition to emission reductions, Vår Energi is on the path to become carbon neutral in net equity operational emissions by 2030 through carbon removals in the voluntary carbon market. Carbon removals will be used for residual emissions and Vår Energi has entered into flexible

agreements to achieve this. Vår Energi has a target of zero scope 2 (market based) emissions² this is achieved through energy efficiencies and purchase of guarantees of origin from renewable sources for the residual scope 2 emissions. These purchases are done throughout the year.

In the third quarter of 2025 scope 1 net equity CO² emissions intensity was 9.4 kg CO² per boe, versus 10.5 kg CO² per boe in the second quarter 2025. For the first nine months of 2025 scope 1 net equity CO2emissions intensity was around 9.9 kg CO² per boe. This level of emissions intensity is in line with the Company guidance for 2025 and is in the top quartile of world industry performance. For the third quarter the operated methane emission intensity for Vår Energi is 0.03%³ , well below the Near Zero levels⁴ .

Vår Energi has a value driven approach towards creating future optionality through CCS⁵ , and the Company is the operator of both the Iroko (40%) and Trudvang (40%) licences on the NCS. For the latter, operatorship was transferred to Vår Energi during first quarter 2025.

¹Greenhouse gas

²Vår Energi's share of operations where the Company is the operator

³Emitted CH⁴ vs exported gas

⁴Near zero below 0.2% as per OGCI definition

⁵ Carbon capture and storage

Financial review

Key figures

Key figures (USD million)	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024
Total income	2 140	1 849	1 871	5 861	5 767
Production costs	(298)	(395)	(305)	(998)	(1 033)
Other operating expenses	(44)	(43)	(36)	(130)	(68)
EBITDAX	1 799	1 411	1 530	4 733	4 665
Exploration expenses	(67)	(70)	(22)	(206)	(111)
EBITDA	1 732	1 341	1 508	4 528	4 554
Depreciation and amortisation	(863)	(587)	(454)	(1 908)	(1 455)
Impairment loss and reversals	202	441	(314)	619	(314)
Net financial income/(expenses)	(117)	(38)	(27)	(187)	(72)
Net exchange rate gain/(loss)	51	78	47	467	(73)
Profit/(loss) before taxes	1 005	1 234	759	3 518	2 641
Income tax (expense)/income	(854)	(1 018)	(580)	(2 697)	(2 139)
Profit/(loss) for the period	152	217	180	821	502

Total income in the third quarter amounted to USD 2 140 million, an increase of USD 291 million compared to the previous quarter due to higher sales offset by lower prices. Volumes sold increased by 17% to 31.1 mmboe in the quarter due to higher production. Realised crude price increased by 1% in the quarter to USD 69 per boe while realised gas price decreased by 8% in the quarter to USD 72 per boe.

Production cost in the third quarter amounted to USD 298 million, a decrease of USD 97 million compared to the previous quarter.

The average production cost per barrel produced decreased to USD 10.6 per boe in the quarter, compared to USD 12.7 per boe in the previous quarter. Third quarter 2025 decreased by USD 3 per boe, compared to third quarter of 2024.

Exploration expenses in the third quarter decreased to USD 67 million compared to USD 70 million in the previous quarter.

Depreciation and amortisation in the third quarter amounted to USD 863 million, an increase compared to the previous quarter due to higher production and higher depreciation rates as new fields are brought onstream.

Impairment loss and reversals in the quarter of USD 202 million was related to an impairment reversal of USD 232 million pre-tax on Balder and technical goodwill impairments of Njord, Gjøa and exploration potential of USD 26 million. Net impairment reversal in the quarter amounts to USD 25 million post-tax.

Net exchange rate gain in the third quarter amounted to USD 51 million, due to strengthened NOK versus USD and EUR.

Profit before taxes in the third quarter amounted to USD 1 005 million compared to USD 1 234 million in the previous quarter. Income tax expenses in the third quarter amounted to USD 854 million, a decrease of USD 164 million compared to the previous quarter.

The effective tax rate for the quarter was 85%, above the marginal tax rate of 78% due to impairment of technical goodwill and financial cost taxed at 22%.

Net result for the period amounted to USD 152 million, a decrease of USD 65 million compared to the previous period mainly due to higher depreciation and lower capitalised financial costs.

Revenues and prices

Total income (USD million)	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024
Revenue from crude oil sales	1 427	1 170	1 147	3 732	3 651
Revenue from gas sales	623	607	587	1 889	1 756
Revenue from NGL sales	65	51	94	155	296
Hedge	-	-	1	-	8
Total Petroleum Revenues	2 115	1 828	1 829	5 776	5 711

Other Operating Income	25	21	42	85	56
Total Income	2 140	1 849	1 871	5 861	5 767

Sales volumes (mmboe)
Sales of crude	20.8	17.1	14.2	52.9	43.9
Sales of gas	8.6	7.7	7.7	24.4	24.8
Sales of NGL	1.7	1.2	2.0	3.6	6.3
Total Sales Volumes	31.1	26.0	24.0	80.8	74.9

Realised prices (USD/boe)
Crude oil	69	68	81	71	83
Gas	72	79	76	79	71
NGL	39	43	46	43	47
Average realised prices	68	70	76	72	76

Vår Energi obtained an average realised price of USD 68 per boe in the quarter.

The realised gas price of USD 72 per boe in the third quarter was a result of the sales mix during the period, which included contracts with fixed prices and contracts linked to both short and long-term indexation. The fixed price contracts represented 18% of third quarter gas volumes sold at an average price of USD 90 per boe, substantially above the spot market reference price.

Vår Energi continues to execute fixed-price gas transactions. As of 30 September 2025, approximately 15% of the Company's gas production for the fourth quarter has been sold under fixed-price contracts, at an average price of around USD 78 per boe.

At the end of the third quarter, Vår Energi has hedged approximately 100% of the post-tax crude oil production until year end of 2025, with put options at a strike price of USD 50 per boe.

Consolidated statement of financial position

USD million	30 Sep 2025	30 Jun 2025	31 Dec 2024
Goodwill	3 333	3 323	2 988
Property, plant and equipment	20 178	19 951	16 737
Other non-current assets	1 017	985	876
Cash and cash equivalents	840	718	279
Other current assets	1 279	1 248	988
Total assets	26 647	26 224	21 868

Equity	833	972	833
Interest-bearing loans and borrowings	5 966	5 908	5 137
Deferred tax liabilities	12 618	12 362	10 501
Asset retirement obligations	3 948	3 920	3 389
Taxes payable	1 394	1 183	682
Other liabilities	1 889	1 878	1 327
Total equity and liabilities	26 647	26 224	21 868

Cash and cash equivalents	840	718	279
Revolving credit facilities	2 750	2 750	1 030
Total available liquidity	3 590	3 468	1 309

Net interest-bearing debt (NIBD)	5 136	5 209	4 870
EBITDAX 4 quarters rolling	5 971	5 702	5 902
Leverage ratio (NIBD/EBITDAX)	0.9	0.9	0.8

Total assets at the end of the third quarter amounted to USD 26 647 million, an increase from USD 26 224 million at the end of the previous quarter. Non-current assets were USD 24 528 million and current assets were USD 2 119 million at the end of the third quarter.

Total equity amounted to USD 833 million at the end of the third quarter, corresponding to an equity ratio of about 3%.

Net interest-bearing debt (NIBD) at the end of the third quarter was USD 5 136 million, a decrease of USD 73 million from the previous quarter.

As a result, total available liquidity amounted to USD 3 590 million at the end of the third quarter, compared to USD 3 468 million at the end of the previous quarter. Undrawn credit facilities at the end of the third quarter were USD 2 750 million and total cash and cash equivalents were USD 840 million. The Company maintains a strong financial position with a leverage ratio (NIBD/EBITDAX) of 0.9x at the end of the third quarter, well within the guided target of below 1.3x through the cycle.

Consolidated statement of cash flow

USD million	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024

Cash flow from operating activities	1 234	766	1 310	3 322	3 030
Cash flow used in investing activities	(740)	(781)	(699)	(2 148)	(3 521)
Cash flow from financing activities	(374)	56	(124)	(666)	583
Effect of exchange rate fluctuation	2	16	(11)	53	(36)
Change in cash and cash equivalents	120	41	487	508	92
Cash and cash equivalents, end of period	840	718	790	840	790

Net cash flows from operating activities	1 234	766	1 310	3 322	3 030
CAPEX	726	761	718	2 083	2 184
Free cash flow	508	4	592	1 240	846

Capex coverage (CFFO)/Capex)	1.7	1.0	1.8	1.6	1.4

Cash flow from operating activities (CFFO) post-tax was USD 1 234 million in the third quarter, an increase of USD 469 million from the previous quarter. This was mainly due to higher revenue.

Net cash used in investing activities was USD 740 million in the quarter, whereof USD 616 million was related to PP&E expenditures

Net cash outflow from financing activities amounted to USD 374 million in the quarter. Cash outflow in the quarter mainly consisted of interest paid of USD 41 million and dividends paid of USD 300 million.

Free cash flow (FCF) was USD 508 million in the quarter, compared to USD 4 million in the previous quarter. The increase is mainly driven by higher cash flow from operations and lower PP&E expenditures. The capex coverage was 1.7 in the third quarter, up from 1.0 in the previous quarter.

Outlook

Vår Energi has an ambition to deliver value-driven growth to support attractive and resilient long-term dividend distributions.

The Company's full year production guidance for 2025 is 330- 360 kboepd and for the fourth quarter 2025 is around 430 kboepd.

For 2025, the Company expects development capex between USD 2 300 and 2 500 million, around USD 400 million in exploration capex and around USD 100 million in abandonment capex. Production cost is expected to be at the bottom of the guidance range of USD 11 and 12 per boe for the full year 2025, reducing to around USD 10 per boe in the fourth quarter 2025.

In the current macro and operating environment Vår Energi's material cash flow generation and investment grade balance sheet support attractive dividend distributions. Vår Energi has a full year 2025 and 2026 dividend guidance of USD 1.2 billion¹ . Vår Energi's dividend policy is 25-30% of CFFO after tax over the cycle.

To ensure continuous access to capital at competitive cost, retaining investment grade credit ratings is a priority for Vår Energi. As such, the Company targets a NIBD/EBITDAX of below 1.3x through the cycle.

Transactions with related parties

For details on transactions with related parties, see note 24 in the Financial Statements.

Subsequent events

See note ##N_Events in the Financial Statements.

Risks and uncertainties

Vår Energi is exposed to a variety of risks associated with its oil and gas operations on the Norwegian Continental Shelf (NCS). Factors such as exploration, reserve and resource estimates, and projections for capital and operating costs are subject to inherent uncertainties. Additionally, the production performance of operated and partner operated oil and gas fields exhibit variability over time and is also affected by planned and unplanned maintenance and turnaround activities. A high activity level on the NCS create challenges for resource availability and may influence the planned progress and costs of Vår Energi's ongoing development projects, which encompass advanced engineering work, extensive procurement activities, and complex construction endeavors.

The Company is also exposed to a variety of risks typically associated with the oil and gas sector such as fluctuations in commodity prices, exchange rates, interest rates, and capital requirements.

Increasing geopolitical tensions have introduced an elevated level of uncertainty into the energy landscape, affecting supply chains and contributing to global economic volatility. Sudden geopolitical developments can influence energy markets, potentially impacting regulatory environments, trade agreements, and geopolitical stability in regions critical to Vår Energi's operations. These uncertainties may impact the predictability of market conditions, affecting both short-term decision-making and long-term strategic planning.

Tensions over trade tariffs increase and potential impacts on global demand and oil and gas supply dynamics introduced additional uncertainties and increased further the level of volatility in the financial market, affecting commodity prices, exchange rates and interest rates.

Climate change mitigation is impacting our operations and business with the introduction of new regulations and taxes on CO² emissions aiming to impact the demand for regular fossil fuels. Additionally, the cost of capital may increase as investors modify their behavior in response to these transformative trends. The company is managing the climate related transition risks by making its business strategies more resilient. The Company's operational, financial, strategic, compliance risks and the mitigation of these risks are described in the annual report for 2024, available on www.varenergi.no.

¹ Remaining 2025 dividend payments will be based on audited interim balance sheet

Alternative performance measures (APMs)

In this interim report, in order to enhance the understanding of the Group's performance and liquidity, Vår Energi presents certain alter-native performance measures ("APMs") as defined by the European Securities and Markets Authority ("ESMA") in the ESMA Guidelines on Alternative Performance Measures 2015/1057.

Vår Energi presents the APMs: Capex, Capex Coverage, EBITDAX, EBITDAX Margin, Free Cash Flow, NIBD and NIBD/EBITDAX Ratio.

The APMs are not measurements of performance under IFRS ("GAAP") and should not be considered to be an alternative to: (a) operating revenues or operating profit (as determined in accordance with GAAP), as a measure of Vår Energi's operating performance; or (b) any other measures of performance under GAAP. The APM presented herein may not be indicative of Vår Energi's historical operating results, nor is such measure meant to be predictive of the Group's future results.

Vår Energi believes that the APMs described herein are commonly reported by companies in the markets in which it competes and are widely used in comparing and analysing performance across companies within its industry.

The APMs used by Vår Energi are set out below (presented in alphabetical order):

"Capex" is defined by Vår Energi as expenditures on property, plant and equipment (PP&E) and expenditures on exploration and evaluation assets as presented in the cash flow statements within cash flow from investing activities.
"Capex Coverage" is defined by Vår Energi as cash flow from operating activities as presented in the cash flow statements ("CFFO"), as a ratio to Capex.
"EBITDAX" is defined by Vår Energi as profit/(loss) for the period before income tax (expense)/income, net financial items, net exchange rate gain/(loss),
depreciation and amortisation, impairments and exploration expenses.
"EBITDAX margin" is defined by Vår Energi as EBITDAX and EBITDA as a percentage of total income, respectively.
"EBITDAX 4 quarters rolling" EBITDAX of the last four quarters
"Free cash flow" ("FCF") is defined by Vår Energi as CFFO less CAPEX.
"Net interest-bearing debt" or "NIBD" is defined by Vår Energi as interest-bearing loans and borrowings including accrued interest ("Total interest-bearing debt" or "TIBD") less unrestricted cash and cash equivalents¹ .
"NIBD/EBITDAX" is defined by Vår Energi as NIBD as a ratio of EBITDAX.

¹The Company's definition of NIBD is changed to align with covenants in the revolving credit facilities agreement, accrued interests are included and lease liabilities and restricted cash are excluded.

Financial statements with note disclosures

	Unaudited consolidated statement of comprehensive income	24	Note 12	Impairment	38
	Unaudited consolidated balance sheet statement	25	Note 13	Trade receivables	40
	Unaudited consolidated statement of changes in equity	26	Note 14	Other current receivables and financial assets	40
	Unaudited consolidated statement of cash flows	27	Note 15	Financial instruments	40
Notes		29	Note 16	Cash and cash equivalents	42
Note 1	Summary of IFRS accounting principles	29	Note 17	Share capital and shareholders	42
Note 2	Business combination	29	Note 18	Hybrid capital	42
Note 3	Income	31	Note 19	Financial liabilities and borrowings	43
Note 4	Production costs	32	Note 20	Asset retirement obligations	44
Note 5	Other operating expenses	32	Note 21	Other current liabilities	44
Note 6	Exploration expenses	33	Note 22	Commitments, provisions and contingent consideration	45
Note 7	Financial items	33	Note 23	Lease agreements	45
Note 8	Income taxes	34	Note 24	Related party transactions	46
Note 9	Intangible assets	36	Note 25	Licence ownerships	47
Note 11	Right of use assets	38

Unaudited consolidated statement of comprehensive income

USD million, except earnings per share data	Note	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024
Petroleum revenues	3	2 115.1	1 827.6	1 828.9	5 775.7	5 711.0
Other operating income		25.3	21.4	42.1	84.9	55.7
Total income		2 140.4	1 849.0	1 871.0	5 860.7	5 766.8
Production costs	4	(297.6)	(395.3)	(305.3)	(997.6)	(1 033.5)
Exploration expenses	6 , 9	(66.6)	(69.7)	(21.8)	(205.6)	(110.9)
Depreciation and amortisation	10 , 11	(862.6)	(587.1)	(454.1)	(1 908.1)	(1 454.6)
Impairment losses and reversal	9 , 10 , 12	201.7	440.8	(313.6)	618.6	(313.6)
Other operating expenses	5	(44.1)	(43.1)	(36.0)	(130.0)	(68.3)
Total operating expenses		(1 069.2)	(654.4)	(1 130.9)	(2 622.6)	(2 980.8)
Operating profit/(loss)		1 071.1	1 194.6	740.1	3 238.1	2 785.9
Net financial income/(expenses)	7	(116.7)	(37.9)	(27.2)	(187.3)	(71.6)
Net exchange rate gain/(loss)	7	50.9	77.7	46.9	467.5	(72.6)
Profit/(loss) before taxes		1 005.4	1 234.4	759.8	3 518.3	2 641.7
Income tax (expense)/income	8	(853.7)	(1 017.7)	(579.5)	(2 697.1)	(2 139.5)
Profit/(loss) for the period		151.7	216.7	180.3	821.2	502.2
Attributable to:
Holders of ordinary shares		151.7	216.7	180.3	760.0	486.6
Dividends paid on hybrid capital	18	-	-	-	61.3	15.6
Profit / (loss) for the period		151.7	216.7	180.3	821.2	502.2
Other comprehensive income (items that may be reclassified subsequently to the income statement)
Currency translation differences		6.3	42.1	11.5	106.2	(73.5)
Actuarial adjustment pension		(0.0)	-	-	-	-
Net gain/(loss) on options used for hedging		0.9	4.0	7.5	3.2	(2.4)
Other comprehensive income for the period, net of tax		7.1	46.1	19.0	109.4	(75.9)
Total comprehensive income		158.8	262.9	199.4	930.6	426.3
Earnings per share
EPS basic and diluted	17	0.05	0.08	0.07	0.31	0.18

Unaudited consolidated balance sheet statement

USD million	Note	30 Sep 2025	30 Jun 2025	31 Dec 2024	30 Sep 2024

ASSETS
Non-current assets
Intangible assets
Goodwill	9	3 333.5	3 322.7	2 987.8	3 319.3
Capitalised exploration wells	9	543.2	482.1	404.9	422.1
Other intangible assets	9	153.2	154.9	241.9	265.7
Tangible fixed assets
Property, plant and equipment	10	20 177.9	19 950.7	16 737.1	17 487.2
Right of use assets	11	278.8	303.4	198.1	49.1
Financial assets
Investment in shares		1.1	1.1	0.7	0.8
Other non-current assets		40.6	43.4	30.8	35.4
Total non-current assets		24 528.2	24 258.3	20 601.3	21 579.7

Current assets
Inventories		330.7	280.5	241.4	246.4
Trade receivables	13 , 24	392.4	462.3	373.2	268.4
Other current receivables and financial assets	14	555.9	504.8	373.4	444.6
Cash and cash equivalents	16	840.3	717.6	278.9	790.4
Total current assets		2 119.2	1 965.3	1 266.8	1 749.8

TOTAL ASSETS		26 647.5	26 223.5	21 868.2	23 329.5

USD million	Note	30 Sep 2025	30 Jun 2025	31 Dec 2024	30 Sep 2024

EQUITY AND LIABILITIES
Equity
Share capital	17	46.0	46.0	46.0	46.0
Share premium		-	-	-	-
Hybrid capital	18	799.5	799.5	799.5	799.5
Other equity		(12.6)	126.8	(12.9)	520.9
Total equity		832.9	972.3	832.5	1 366.4
Non-current liabilities
Interest-bearing loans and borrowings	19	5 840.1	5 832.1	5 082.2	4 870.9
Deferred tax liabilities	8	12 617.7	12 362.2	10 500.9	10 756.1
Asset retirement obligations	20	3 822.3	3 796.9	3 283.7	3 630.2
Pension liabilities		11.9	11.1	15.5	23.8
Lease liabilities, non-current	23	150.6	175.1	141.5	45.5
Other non-current liabilities		425.6	440.1	115.0	122.2
Total non-current liabilities		22 868.2	22 617.5	19 138.8	19 448.6
Current liabilities
Asset retirement obligations, current	20	125.3	123.0	105.2	63.7
Accounts payables	24	488.4	442.6	356.1	327.1
Taxes payable	8	1 394.3	1 182.6	681.7	1 318.5
Interest-bearing loans, current	19	126.3	76.3	54.7	73.1
Lease liabilities, current	23	130.0	126.0	70.4	12.6
Other current liabilities	21	682.1	683.3	628.8	719.6
Total current liabilities		2 946.4	2 633.7	1 896.8	2 514.6

Total liabilities		25 814.6	25 251.2	21 035.7	21 963.1
TOTAL EQUITY AND LIABILITIES		26 647.5	26 223.5	21 868.2	23 329.5

Unaudited consolidated statement of changes in equity

					Other equity
USD million	Share capital	Share premium	Hybrid Capital	Other equity	Translation differences	Hedge reserve	Total equity
Balance as of 1 January 2024	46.0	758.2	799.5	622.6	(443.5)	(14.7)	1 768.1
Profit/(loss) for the period	-	-	15.6	486.6	-	-	502.2
Other comprehensive income/(loss)	-	-	-	-	(73.5)	(2.4)	(75.9)
Total comprehensive income/(loss)	-	-	-	486.6	(73.5)	(2.4)	426.3
Dividends paid	-	(758.2)	(15.6)	(51.8)	-	-	(825.6)
Share-based payment	-	-	-	(2.3)	-	-	(2.3)
Other	-	-	-	(11.2)	-	11.2	-
Balance as of 30 September 2024	46.0	-	799.5	1 043.8	(517.0)	(5.9)	1 366.4

Balance as of 1 October 2024	46.0	-	799.5	1 043.8	(517.0)	(5.9)	1 366.4
Profit/(loss) for the period	-	-	-	(175.1)	-	-	(175.1)
Other comprehensive income/(loss)	-	-	-	0.4	(86.1)	(5.8)	(91.5)
Total comprehensive income/(loss)	-	-	-	(174.7)	(86.1)	(5.8)	(266.6)
Dividends paid	-	-	-	(270.0)	-	-	(270.0)
Share-based payments	-	-	-	2.8	-	-	2.8
Other	-	-	-	(0.1)	-	0.1	-
Balance as of 31 December 2024	46.0	-	799.5	601.7	(603.1)	(11.6)	832.5
Balance as of 1 January 2025	46.0	-	799.5	601.7	(603.1)	(11.6)	832.5
Profit/(loss) for the period	-	-	61.3	760.0	-	-	821.2
Other comprehensive income/(loss)	-	-	-	-	106.2	3.2	109.4
Total comprehensive income/(loss)	-	-	61.3	760.0	106.2	3.2	930.6
Dividends paid	-	-	(61.3)	(870.0)	-	-	(931.3)
Share-based payments	-	-	-	1.0	-	-	1.0
Other	-	-	-	0.0	-	-	0.0
Balance as of 30 September 2025	46.0	-	799.5	492.7	(496.9)	(8.4)	832.8

Unaudited consolidated statement of cash flows

USD million	Notes	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024

Cash flow from operating activities
Profit / (loss) before income taxes		1 005.4	1 234.4	759.8	3 518.3	2 641.7
Adjustments to reconcile profit before tax to net cash flows:
- Depreciation and amortisation	10 , 11	862.7	587.2	454.1	1 908.1	1 454.6
- Impairment loss/(reversal)	9 , 10	(201.7)	(440.8)	313.6	(618.6)	313.7
- (Gain) / loss on sale and retirement of assets	5	(0.3)	1.1	(57.4)	6.1	(57.1)
- Expensed capitalised dry wells	6 , 9	48.7	57.1	1.9	157.6	56.1
- Accretion expenses (asset retirement obligation)	7 , 20	36.6	36.7	29.4	106.1	87.3
- Unrealised (gain) / loss on foreign currency transactions and balances	7	(59.3)	(51.4)	(68.1)	(462.5)	49.6
- Realised foreign exchange (gain) / loss related to financing activities		-	(32.6)	(6.5)	(53.4)	(3.1)
- Other non-cash items and reclassifications		77.6	(3.5)	42.6	81.9	(45.8)
Working capital adjustments:
- Changes in inventories, accounts payable and receivables		75.4	(178.9)	130.7	51.2	225.7
- Changes in other current balance sheet items	14 , 21	(79.5)	60.7	34.2	(124.1)	57.8
Income taxes paid	8	(531.2)	(504.3)	(324.7)	(1 248.5)	(1 750.7)
Net cash flow from operating activities		1 234.2	765.7	1 309.9	3 322.2	3 029.7

Cash flow from investing activities
Expenditures on exploration and evaluation assets	9	(109.5)	(71.1)	(82.3)	(253.2)	(217.8)
Expenditures on property, plant and equipment	10	(616.4)	(690.2)	(635.2)	(1 829.4)	(1 966.4)
Payment for decommissioning of oil and gas fields	20	(14.3)	(19.9)	(29.8)	(65.4)	(54.9)
Proceeds from sale of assets (sales price)		-	(0.1)	65.2	-	65.2
Net cash used on business combination	2	-	-	(16.5)	-	(1 347.2)
Net cash flow from investing activities		(740.3)	(781.3)	(698.7)	(2 148.0)	(3 521.1)

Unaudited consolidated statement of cash flows - continued

USD million	Note	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024

Cash flow from financing activities
Dividends paid		(300.0)	(300.0)	(270.0)	(870.0)	(810.0)
Dividends distributed to hybrid owners	18	-	-	-	(61.3)	(15.6)
Net proceeds from bond issue	15 , 19	-	1 500.0	-	2 588.6	-
Net proceeds/(payments) of revolving credit facilities	15 , 19	-	(995.0)	235.0	(1 984.1)	1 710.0
Payment of principal portion of lease liability	23	(32.8)	(32.1)	(17.1)	(91.5)	(66.2)
Interest paid		(40.9)	(116.6)	(72.3)	(247.9)	(234.8)
Net cash flow from financing activities		(373.6)	56.3	(124.4)	(666.2)	583.4

Net change in cash and cash equivalents		120.3	40.7	486.8	508.0	91.9

Cash and cash equivalents, beginning of period		717.6	661.2	314.8	278.9	734.9
Effect of exchange rate fluctuation on cash		2.4	15.8	(11.1)	53.4	(36.4)
Cash and cash equivalents, end of period		840.3	717.7	790.4	840.3	790.4

Notes

(All figures in USD million unless otherwise stated)

The unaudited interim condensed consolidated financial statements for the period ended 30 September 2025 have been prepared in accordance with IFRS® Accounting Standards and IAS 34 "Interim Financial Reporting". Thus, the interim financial statements do not include all information required by IFRS®'s and should be read in conjunction with the 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 not been subject to review or audit by independent auditors.

These interim financial statements were authorised for issue by the Company Board of Directors on 20 October 2025.

Note 1 Summary of IFRS accounting principles

The accounting principles adopted in the preparation of the interim condensed financial statements are consistent with those followed in the preparation of the annual financial statements for the year ended 31 December 2024. , except for certain changes in estimates. For determining the depreciation rate based on the Unit of Production method, management has revised the estimation technique to apply 2P reserves (proved + probable) for facilities and 2PD reserves (proved + probable developed) for wells for Balder/Ringhorne and Johan Castberg. This has been done to better align depreciation with the actual consumption of economic benefits. This change results in a more even depreciation profile over time and a more stable relationship between expected earnings and associated costs.

Other material estimates and judgements made by management in applying the IFRS Accounting Standards are the same as those applied in the 2024 annual financial statements..

None of the amendments to IFRS Accounting Standards effective from 1 January 2025 has had a significant impact on the condensed interim financial statements. Vår Energi has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.

Note 2 Business combination

On 31 January 2024, Vår Energi completed the acquisition of Neptune Energy Norway AS (renamed Vår Energi Norge AS at completion of the transaction). The transaction was announced on 23 June 2023.

Vår Energi paid a cash consideration of USD 2.1 billion, and the transaction was financed through available liquidity and credit facilities. The acquired assets, all located on the NCS, are complementary to Vår Energi's current portfolio and highly cash generative with low production cost and limited near-term investments. The transaction also strengthens Vår Energi's position in all existing hub areas and combine two strong organisations with extensive NCS experience.

The acquisition date for accounting purposes is 1 January 2024. The acquisition is regarded as a business combination and has been accounted for in accordance with IFRS 3. A purchase price allocation (PPA) has been performed as of 1. January 2024 to allocate the consideration to fair value of the assets and liabilities in Neptune Energy Norway AS.

USD million 31 Jan 2024 Value of cash consideration 2 106.8

Each identifiable asset and liability are measured at fair value on the acquisition date based on guidance in IFRS 13. The standard defines fair value as the price that would be received when selling an asset or paid transfer a liability in an orderly transaction between market participants at the measurement date. This definition emphasises that fair value is a market-based measurement and not an entity-specific measurement. When measuring fair value Vår Energi has applied the assumptions that market participants would use under current market conditions (including assumptions regarding risk) when valuing the specific asset or liability.

Acquired property, plant and equipment has been valued using the income approach. Trade receivables have been recognised at full contractual amounts due as they relate to large and credit-worthy customers, and there have been no significant uncollectible amounts in Neptune Energy Norway AS historically.

Note 2 Business combination - continued

For accounting purposes, the recognised amounts of assets and liabilities assumed as at the date of the acquisition were as follows:

USD million	01 Jan 2024
Goodwill	1 529.9
Other intangible assets	192.5
Property, plant and equipment	1 976.3
Right of use assets	10.5
Other non-current assets	8.2
Inventories	19.5
Trade receivables	174.2
Other current receivables and financial assets	191.4
Cash and cash equivalents	776.1
Total assets	4 878.6
Deferred tax liabilities	1 120.9
Asset retirement obligation	368.3
Pension liabilities	23.6
Lease liabilities, non-current	7.0
Other non-current liabilities	284.8
Accounts payable	81.7
Taxes payable	705.9
Lease liabilities, current	3.5
Other current liabilities	176.2
Total liabilities	2 771.9
Net assets and liabilities recognised	2 106.8
Fair value of consideration paid on acquisition	2 106.8

The goodwill of USD 1 530 million arises principally because of the following factors:

1. 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 ("residual goodwill").
1. The requirement to recognise deferred tax assets and liabilities for the difference between the assigned fair values and the tax bases of assets acquired and liabilities assumed in a business combination. Licences under development and licences in production can only be sold in a market after tax, based on a decision made by the Norwegian Ministry of Finance pursuant to the Petroleum Taxation Act Section 10. The assessment of fair value of such licences is therefore based on cash flows after tax. Nevertheless, in accordance with IAS 12 para 15 and 19, a provision is made for deferred tax corresponding to the tax rate multiplied by the difference between the acquisition cost and the tax base. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax ("technical goodwill").

None of the goodwill recognised will be deductible for tax purposes.

USD million	01 Jan 2024
Goodwill related to synergies - residual goodwill	218.9
Goodwill as a result of deferred tax - technical goodwill	1 310.9
Net goodwill from the acquisition of Neptune Norway	1 529.9

In first quarter 2025 a reallocation of the PPA value has been performed due to new information available. The PP&E has been decreased by USD 24 million, Goodwill has been increased by USD 66 million, Other non-current liabilities has been increased by USD 252 million and Deferred tax has been decreased by USD 210 million compared to fourth quarter of 2024.

The purchase price allocations above are final and based on currently available information about fair values as of the acquisition date, in accordance with guidance in IFRS 3.

Note 3 Income

Petroleum revenues (USD million)	Note	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024

Revenue from crude oil sales		1 426.6	1 169.6	1 147.3	3 731.8	3 651.0
Revenue from gas sales		623.1	606.7	586.6	1 888.6	1 756.1
Revenue from NGL sales		65.3	51.4	94.4	155.4	296.1
Gains from hedging	14	-	-	0.6	-	7.8
Total petroleum revenues		2 115.1	1 827.7	1 828.9	5 775.8	5 711.0

Sales of crude (boe million)		20.8	17.1	14.2	52.9	43.9
Sales of gas (boe million)		8.6	7.7	7.7	24.4	24.8
Sales of NGL (boe million)		1.7	1.2	2.0	3.6	6.3

Other operating income (USD million)		Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024

Gain/(loss) from sale of assets		-	0.0	33.8	0.0	36.8
Partner share of lease cost		13.3	11.0	2.5	35.3	8.9
Other operating income		12.0	10.4	5.8	49.6	10.0
Total other operating income		25.3	21.4	42.1	84.9	55.7

Vår Energi has elected to sell part of its gas on a fixed price/forward basis. Per 30 September 2025 Vår Energi has sold approximately 15% of the gas production for the fourth quarter in 2025 at around USD 78 pr boe.

Note 4 Production Costs

USD million	Note	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024

Cost of operations		227.4	222.5	215.8	625.9	636.7
Transportation and processing		73.8	56.7	54.1	183.7	181.8
Environmental taxes		45.2	39.7	34.2	126.2	104.4
Insurance premium		15.4	14.8	16.2	44.2	47.7
Production cost based on produced volumes		361.8	333.7	320.3	980.1	970.5

Back-up cost shuttle tankers		(2.8)	16.0	7.8	8.6	13.0
Changes in over/(underlift)		(68.4)	40.0	(30.1)	(11.3)	23.9
Premium expense for crude put options	15	7.0	5.5	7.3	20.3	26.2
Production cost based on sold volumes		297.6	395.3	305.3	997.6	1 033.5

Total produced volumes (boe million)		34.1	26.2	23.6	84.8	76.9
Production cost per boe produced (USD/boe)		10.6	12.7	13.6	11.6	12.6

Note 5 Other operating expenses

USD million	Note	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024

R&D expenses		9.9	8.8	6.7	26.2	24.9
Pre-production costs		12.2	14.0	16.1	44.1	40.6
Guarantee fee decommissioning obligation		4.2	4.1	4.1	12.6	13.5
Administration expenses		8.6	8.5	5.5	28.0	23.9
Legal provisions		(0.7)	4.6	-	3.9	-
Integration cost		-	-	3.2	-	17.4
Value adjustment contingent considerations	22	-	-	(3.4)	-	(62.3)
Other expenses		9.9	3.1	3.8	15.1	10.2
Total other operating expenses		44.1	43.1	36.0	130.0	68.3

Note 6 Exploration expenses

USD million	Note	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024
Seismic		(6.4)	2.5	8.6	1.2	27.9
Area fee		5.1	4.4	8.0	13.5	12.9
Dry well expenses	9	48.3	57.1	1.9	157.2	56.1
Other exploration expenses		19.6	5.7	3.4	33.6	13.9
Total exploration expenses		66.6	69.7	21.8	205.6	110.9

Dry well expenses in the third quarter of 2025 are associated with exploration wells in PL 1238 (Deimos), PL 554C (Narvi) and PL 532 (Skred).

Note 7 Financial items

USD million	Note	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024
Interest income		5.1	7.3	4.6	17.0	19.5
Interests on debts and borrowings	19	(90.3)	(87.1)	(90.9)	(259.3)	(255.9)
Interest on lease debt		(3.8)	(3.9)	(1.0)	(11.6)	(3.4)
Capitalised interest cost, development projects		23.3	92.2	92.2	201.5	261.9
Amortisation of fees and expenses		(9.6)	(3.5)	(2.2)	(15.4)	(6.6)
Accretion expenses (asset retirement obligation)	20	(36.6)	(36.7)	(29.4)	(106.1)	(87.3)
Other financial expenses		(4.8)	(2.9)	(1.9)	(10.0)	(4.1)
Change in fair value of hedges (ineffectiveness)	15	(0.1)	(3.2)	1.4	(3.4)	4.3
Net financial income/(expenses)		(116.7)	(37.9)	(27.2)	(187.3)	(71.6)
Unrealised exchange rate gain/(loss)		59.3	51.4	68.1	462.5	(49.6)
Realised exchange rate gain/(loss)		(8.4)	26.3	(21.1)	5.0	(23.0)
Net exchange rate gain/(loss)		50.9	77.7	46.9	467.5	(72.6)
Net financial items		(65.8)	39.8	19.7	280.2	(144.2)

Vår Energi's functional currency is NOK, whilst interest bearing loans and bonds are in USD and EUR. The strengthening of NOK during the third quarter of 2025 resulted in net exchange gain of USD 50.9 million.

Note 8 Income taxes

USD million	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024

Current period tax payable/(receivable)	727.5	422.5	452.2	1 793.9	1 457.5
Prior period adjustment to current tax	5.4	32.3	0.0	30.4	0.6
Current tax expense/(income)	732.9	454.8	452.3	1 824.4	1 458.1
Change in current year deferred tax	120.8	594.9	127.2	904.8	681.4
Prior period adjustments to deferred tax	-	(32.1)	-	(32.1)	-
Deferred tax expense/(income)	120.8	562.9	127.2	872.7	681.4
Tax expense/(income) in profit and loss	853.7	1 017.7	579.5	2 697.1	2 139.5
Effective tax rate in %	85%	82%	76%	77%	81%
Tax expense/(income) in put option used for hedging and pension	0.3	1.2	2.5	1.3	(0.5)
Tax expense/(income) in other comprehensive income	854.0	1 018.8	582.0	2 698.3	2 138.9

Reconciliation of tax expense	Tax rate	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024

Marginal (78%) tax rate on profit/loss before tax	78%	784.2	962.9	592.7	2 744.4	2 060.6
Tax effect of uplift	71,8%	(4.5)	(3.9)	(9.1)	(12.8)	(21.5)
Impairment of goodwill	78%	20.2	55.1	18.3	95.7	18.3
Tax effects of items taxed at other than marginal (78%) tax rate1	56%	50.7	3.2	24.5	(109.7)	187.5
Tax effects of acquisition, sale and swap of licences2		-	-	(43.1)	-	(43.1)
Other permanent differences, prior period adjustments and change in estimates of uncertain tax positions	78%	3.1	0.4	(3.7)	(20.5)	(62.4)
Tax expense/(income)		853.7	1 017.7	579.5	2 697.1	2 139.5

¹ The items taxed at other than marginal (78%) tax rate are mainly interests and fluctuations in currency exchange rate on the company's external borrowings.

²Tax effects related to sale of Norne area in 2024.

Note 8 Income taxes - continued

Deferred tax asset/(liability)	Note	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024

Deferred tax asset/(liability) at beginning of period		(12 362.2)	(11 286.1)	(10 342.9)	(10 500.9)	(8 943.0)
Change in current year deferred tax		(120.8)	(594.9)	(127.2)	(904.8)	(681.4)
Prior period adjustments		-	32.1	-	32.1	-
Deferred taxes on business combinations2	2	-	-	(103.1)	209.6	(1 407.3)
Deferred taxes related to acquisition, sale and swap of licences		-	-	(3.4)	-	(3.4)
Deferred taxes recognised directly in OCI or equity		(0.3)	(1.2)	(2.5)	(1.3)	0.5
Currency translation effects		(134.4)	(512.1)	(177.1)	(1 452.4)	278.4
Net deferred tax asset/(liability) as of closing balance		(12 617.7)	(12 362.2)	(10 756.1)	(12 617.7)	(10 756.1)

Tax payable	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024

Tax payable at beginning of period	(1 182.6)	(1 178.3)	(1 175.6)	(681.7)	(964.4)
Current period payable taxes	(727.5)	(422.5)	(452.2)	(1 793.9)	(1 457.5)
Payable taxes related to business combinations 2	-	-	(1.6)	-	(707.5)
Net tax payments	531.2	504.3	324.7	1 248.5	1 750.7
Prior period adjustments and change in estimate of uncertain tax positions	(5.4)	(32.3)	(0.0)	(30.4)	(0.6)
Currency translation effects	(10.0)	(53.8)	(13.7)	(136.7)	60.9
Net tax payable as of closing balance	(1 394.3)	(1 182.6)	(1 318.5)	(1 394.3)	(1 318.5)

²Acquisition of Neptune Energy Norge in Q1 2024 and acquisition of Ringhorne East share in Q3 2024.

Note 9 Intangible assets

			Other intangible	Capitalised exploration
USD million	Note	Goodwill	assets	wells	Total

Cost as of 1 January 2025		5 249.5	242.8	404.9	5 897.1
Additions		-	-	143.7	143.7
Additions through business combination	2	66.4	-	-	66.4
Reclassification		-	(113.5)	(12.1)	(125.5)
Expensed exploration wells	6	-	-	(109.0)	(109.0)
Disposals		(2.2)	(3.5)	-	(5.8)
Currency translation effects		647.6	30.3	54.7	732.7
Cost as of 30 June 2025		5 961.2	156.1	482.1	6 599.4

Depreciation and impairment as of 1 January 2025		(2 261.6)	(0.9)	-	(2 262.5)
Depreciation		-	(0.1)	-	(0.1)
Impairment reversal/(loss)		(94.5)	-	-	(94.5)
Currency translation effects		(282.4)	(0.2)	-	(282.6)
Depreciation and impairment as of 30 June 2025		(2 638.5)	(1.2)	-	(2 639.7)

Net book value as of 30 June 2025		3 322.7	154.9	482.1	3 959.7

Net book value as of 30 September 2025		3 333.5	153.2	543.2	4 029.9

Depreciation and impairment as of 30 September 2025		(2 693.4)	(1.0)	-	(2 694.4)
Currency translation effects		(28.9)	0.2	-	(28.8)
Impairment reversal/(loss)	12	(25.9)	-	-	(25.9)
Depreciation		-	-	-	-
Depreciation and impairment as of 1 July 2025		(2 638.5)	(1.2)	-	(2 639.7)
Cost as of 30 September 2025		6 026.9	154.2	543.2	6 724.3
Currency translation effects		65.7	1.8	7.3	74.8
Disposals		-	0.7	-	0.7
Expensed exploration wells	6	-	-	(48.7)	(48.7)
Reclassification		-	(4.4)	(7.1)	(11.4)
Additions through business combination	2	-	-	-	-
Additions		-	-	109.5	109.5
Cost as of 1 July 2025		5 961.2	156.1	482.1	6 599.4
USD million	Note	Goodwill	Other intangible assets	Capitalised exploration wells	Total

Other intangible assets include exploration potentials acquired through business combinations and measured according to the successful efforts method.

Note 10 Tangible assets

USD million	Note	Wells and production facilities	Facilities under construction	Other property, plant and equipment	Total
Cost as of 1 January 2025		17 101.3	7 445.6	114.1	24 661.0
Additions		495.8	880.5	14.9	1 391.1
Estimate change asset retirement cost	20	91.2	-	-	91.2
Additions through business combinations	2	(39.0)	-	-	(39.0)
Reclassification		6 597.2	(6 433.2)	-	164.0
Disposals		-	-	(0.6)	(0.6)
Currency translation effects		2 290.1	847.7	15.0	3 152.7
Cost as of 30 June 2025		26 536.5	2 740.5	143.3	29 420.4

Depreciation and impairment as of 1 January 2025		(7 828.7)	(38.9)	(56.2)	(7 923.9)
Depreciation		(1 003.1)	-	(13.6)	(1 016.7)
Impairment reversal / (loss)	12	467.5	44.0	-	511.5
Currency translation effects		(1 027.9)	(5.0)	(7.7)	(1 040.7)
Depreciation and impairment as of 30 June 2025		(9 392.3)	0.0	(77.5)	(9 469.8)

Net book value as of 30 June 2025		17 144.3	2 740.6	65.8	19 950.7

USD million	Note	Wells and production facilities	Facilities under construction	Other property, plant and equipment	Total

Cost as of 1 July 2025		26 536.5	2 740.5	143.3	29 420.4
Additions		556.5	78.4	4.4	639.3
Estimate change asset retirement cost	20	(38.2)	-	-	(38.2)
Additions through business combinations	2	15.5	-	-	15.5
Reclassification		1 788.3	(1 757.7)	0.2	30.7
Disposals		(0.0)	-	(3.8)	(3.8)
Currency translation effects		290.3	23.7	1.6	315.7
Cost as of 30 September 2025		29 149.0	1 085.0	145.7	30 379.7
Depreciation and impairment as of 1 July 2025		(9 392.3)	0.0	(77.5)	(9 469.8)
Depreciation		(835.5)	-	(11.3)	(846.7)
Impairment reversal / (loss)	12	227.6	-	-	227.6
Currency translation effects		(115.3)	-	(0.9)	(116.3)
Depreciation and impairment as of 30 Sep 2025		(10 115.5)	0.0	(86.3)	(10 201.8)

Net book value as of 30 September 2025		19 033.5	1 085.0	59.4	20 177.9

Capitalised interests for facilities under construction were USD 23 million in the third quarter 2025 compared to USD 92 million in the second quarter 2025.

Rate used for capitalisation of interests was 6.45% in the third quarter 2025, same as in the second quarter 2025.

Note 11 Right of use assets

_USD million		Rigs, nelicopters and supply vessels	Warehouse	Total
Cost as at 1 January 2025	73.5	247.4	18.7	339.6
Additions	2.1	135.9	-	138.0
Reclassification	-	(38.4)	-	(38.4)
Currency translation effects	9.6	40.6	3.0	53.2
Cost as at 30 June 2025	85.2	385.6	21.7	492.5
Depreciation and impairment as at 1 January 2025	(26.0)	(102.8)	(12.7)	(141.5)
Depreciation	(3.5)	(24.1)	(0.9)	(28.5)
Currency translation effects	(3.8)	(13.0)	(2.3)	(19.1)
Depreciation and impairment as at 30 June 2025	(33.4)	(139.8)	(15.9)	(189.1)
Net book value as at 30 June 2025	51.9	245.7	5.8	303.4
Cost as at 1 July 2025	85.2	385.6	21.7	492.5
Additions		7.9		7.9
Reclassification		(19.3)	-	(19.3)
Currency translation effects	0.8	4.2	0.2	5.2
Cost as at 30 September 2025	86.1	378.3	21.8	486.3
Depreciation and impairment as at 1 July 2025	(33.4)	(139.8)	(15.9)	(189.1)
Depreciation	(1.9)	(13.8)	(0.5)	(16.2)
Currency translation effects	(0.3)	(1.8)	(0.2)	(2.3)
Depreciation and impairment as at 30 September 2025	(35.6)	(155.4)	(16.5)	(207.5)
Net book value as at 30 September 2025	50.5	222.9	5.3	278.8

Note 12 Impairments

Impairment testing

Impairment tests of individual cash-generating units (CGUs) are performed annually and quarterly when impairment triggers are identified. Impairment testing of fixed assets and related intangible assets was performed as of 30 September 2025.

Key assumptions applied for impairment testing purposes as of 30 September 2025 are based on Vår Energi's macroeconomic assumptions. Below is an overview of the key assumptions applied:

Prices

The oil and gas prices are based on the forward curve for the next three-year period and from the fourth year the oil and gas prices are based on the company's long-term price assumptions. Vår Energi's long term oil price assumption is 75 USD/bbl (real 2024) and long-term gas price assumption is €29/MWh (real 2024), unchanged compared to the assumed prices per 30 June 2025.

The nominal oil prices (USD/bbl) applied in the impairment tests are as follows:

Year	31 Dec 2024	30 Jun 2025	30 Sep 2025

2025	74.0	66.8	66.7
2026	74.5	68.9	67.8
2027	78.5	75.1	73.8

The nominal gas prices (USD/boe) applied in the impairment tests are as follows:

Year	31 Dec 2024	30 Jun 2025	30 Sep 2025
2025	83.1	67.9	65.0
2026	65.6	65.0	62.7
2027	59.1	58.8	59.4

Note 12 Impairments - continued

Oil and gas reserves

Future cash flows are calculated based on expected production profiles and estimated proven, probable and risked possible reserves.

Year mmboe	31 Dec 2024	30 Jun 2025	30 Sep 2025
2025 - 2029	611	565	530
2030 - 2034	311	323	325
2035 - 2039	160	166	166
2040 - 2060	132	135	135

Future expenditure

Future capex, opex and abex are calculated based on expected production profiles and the best estimate of related cost.

Discount rate

The post tax nominal discount rate used is 8.0 percent, unchanged vs. 30 June 2025.

Currency rates	2025	2026	2027	2028 onwards
NOK/USD	10.0	10.0	10.0	10.0
NOK/Euro	11.7	11.6	11.3	11.0

The long-term currency rates are unchanged vs. previous quarter.

Inflation

Inflation is assumed to be 3% in 2025, 2.5% in 2026 and then 2% in future years. The inflation rate assumption for 2026 is updated from 2% per 30 June 2025.

Impairments charge/reversal

The impairment testing as of 30 September 2025 identified an impairment reversal for Balder CGU of USD 227.6 million, largely attributed to transportation price updates. Goodwill impairment for Njord and Gjøa, was recorded at USD 20.5 million, mainly resulting from lower short-term commodity prices. Additionally, exploration disposals included an associated impairment of technical goodwill valued at USD 5.4 million.

				Impairment allocated
Cash generating unit (USD million)	Net carrying calue	Recoverable amount	Impairment / reversal (-)	Goodwill	PP&E	Deferred tax impact
Balder area	1 691.5	1 748.4	(227.6)	-	(227.6)	177.5
Njord area	607.1	600.4	6.7	6.7	-	-
Gjøa area	162.0	148.2	13.8	13.8	-	-
Other	-	-	5.4	5.4	-	-
Total			(201.7)	25.9	(227.6)	177.5

Sensitivity analysis

The table below shows how the impairment or reversal of impairment of assets and technical goodwill would be affected by changes in the various assumptions, given that the remaining assumptions are constant.

The sensitivities are created for illustration purposes, based on a simplified method and assumes no changes in other input factors. Significant reductions in oil and gas prices or production profiles are likely to result in changes to business plans, field cut-off as well as other factors used when estimating an asset's recoverable amount. Changes in such input factors may reduce the actual impairment amount compared to the illustrative sensitivity below.

	Change in impairment after
Assumption USD million	Change	Increase in assumptions	Decrease in assumptions
Short and long term prices of oil and gas	+/-25%	(21)	3 179
Production profile	+/- 5%	(17)	444
Discount rate	+/- 1% point	207	(6)

Climate related risks

The climate related risk assessment is generally described in the company's annual report. Impairment testing includes a step up of CO² tax/fees from current levels to approximately NOK 2 371 per ton in 2030 (real 2025).

Note 13 Trade receivables

USD million	Note	30 Sep 2025	30 Jun 2025	31 Dec 2024	30 Sep 2024

Trade receivables - related parties	24	658.2	508.4	448.9	402.6
Trade receivables - external parties		151.7	180.9	181.7	123.2
Sale of trade receivables		(417.5)	(227.0)	(257.4)	(257.4)
Total trade receivables		392.4	462.3	373.2	268.4

Vår Energi has Credit Discount Agreements with several banks. Under the arrangements the ownership, including credit risk, of invoices for oil and gas sales are transferred to the respective banks, and the receivables to which the payments relate are derecognised from Vår Energi's balance sheet. Payments to the banks are made when Vår Energi receives payments from the customers.

Trade receivables are presented net of payments received from the banks for the sold invoices, as Vår Energi has retained the right to receive payments from the customers and obligation to pay these cash flows to the banks without material delay, but only to the extent Vår Energi collects the payments from the customers.

Note 14 Other current receivables and financial assets

USD million	Note	30 Sep 2025	30 Jun 2025	31 Dec 2024	30 Sep 2024

Net underlift of hydrocarbons		345.9	247.9	223.1	240.7
Net receivables from joint operations		148.3	170.2	121.1	127.3
Prepaid expenses		54.0	78.6	16.8	49.2
Commodity derivatives - financial assets	15	0.8	6.7	17.2	19.1
Other receivables		6.9	1.5	(4.8)	8.2
Total other current receivables and financial assets		555.9	504.8	373.4	444.6

Note 15 Financial instruments

Derivative financial instruments

Vår Energi uses derivative financial instruments to manage exposures in fluctuations in interest rates and commodity prices.

In May 2023 interest rate swaps were entered into for the same amount as the EUR 600 million Senior Note. Under the swaps, the Company receives a fixed amount equal to the coupon payment for the EUR senior notes and pays a floating rate to the swap providers. The interest rate swaps are accounted for as a fair value hedge. Interest swaps are reflected at fair value with fair value changes to be accounted for as other financial income/expenses. Bond debt is initially recognised at nominal value. The carrying value is adjusted to reflect changes in interest level with fair value changes accounted for as other financial income/expenses. Inefficiencies in hedging are measured and booked against fair value of bond debt and accounted for as other financial income/expenses (note 7).

As of 30 September 2025, Vår Energi had the following volumes of commodity derivatives in place with the following strike prices:

Hedging instruments	Volume (no of options outstanding at balance sheet date) in million (bbl)	Exercise price (USD per bbl)
Brent crude oil put options 30.09.2025, exercisable in 2025	6.8	50

	Volume (no of options outstanding at	Excercise price
Hedging instruments Gas TTF long put options 30.09.2025, exercisable in 2025	balance sheet date) in million (MWH) 0.1	(EUR per MWH) 25

Brent crude put options – financial assets

USD million Note	Q3 2025	Q1-Q2 2025	2024

The beginning of the period	6.7	17.2	11.0
Additions through business combinations	-	-	25.2
New derivatives	-	-	31.9
3 Realised hedges exercised	-	-	(9.2)
Change in fair value realised	(7.8)	(2.7)	(21.5)
hedges Change in fair value unrealised hedges	1.9	(7.7)	(20.2)
The end of the period	0.8	6.7	17.2

Note 15 Financial instruments - continued

As of 30 September 2025, the fair value of outstanding commodity derivatives assets is USD 0.8 million.

Unrealised gains and losses are recognised in OCI. Note that the cost price (time value agreed at the inception of the contracts) for the options is paid at the time of realisation (time of exercise or expiration) and that this deferred payment is presented as current liabilities in the balance sheet, see below table.

Brent crude put options – deferred premiums

USD million	Note	Q3 2025	Q1-Q2 2025	2024
The beginning of the period		(18.6)	(31.9)	(29.8)
Additions through business combinations		-	-	(2.6)
Settlement	4	7.0	13.3	32.5
New Brent crude put options		-	-	(31.9)
FX-effect		-	0.1	(0.1)
The end of the period		(11.6)	(18.6)	(31.9)

The full intrinsic value ("in the money value") of the options at the time of expiry, if any, is presented in petroleum revenues. The premiums paid for the put options are accounted for as cost of hedging and recycled from OCI to the income statement in the period in which the hedged revenues are realised and presented as production costs.

Commodity Derivatives - financial liabilities

USD million	Note	Q3 2025	Q1-Q2 2025	2024
The beginning of the period		0.0	(0.1)	-
Additions through business combinations		-	-	(8.0)
Realised hedges exercised	3	-	-	1.4
Change in fair value realised		0.1	-	3.6
hedges Change in fair value unrealised hedges		(0.1)	0.1	2.9
The end of the period		0.0	0.0	(0.1)

As of 30 September 2025, the fair value of outstanding commodity derivatives liabilities are USD (0.0) million. Unrealised gains and losses are recognised in OCI.

Change in Hedge Reserve

USD million	Note	Q3 2025	Q1-Q2 2025	2024
The beginning of the period		11.8	14.8	18.8
Additions through business combinations		-	-	(14.6)
Realised hedges exercised	3	-	-	7.8
Realised cost of hedge expired options		0.7	(10.7)	(14.5)
Hedge ineffectiveness in net financial income/expense	7	-	-	-
Change in fair value unrealised hedges		(1.8)	7.7	17.3
The end of the period		10.7	11.8	14.8

After tax balance as of 30 September 2025 is USD 8.4 million.

Reconciliation of liabilities arising 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.

			Non-cash changes
USD million	31 Dec 2024	Cash flows	Amortisation / Accretion/ Accruals	Currency	Fair Value Adj.	30 Sep 2025

Long-term interest-bearing debt	1 970.0	(1 984.1)	-	14.1	-	-
Bond USD Senior Notes	2 500.0	1 500.0	-	-	-	4 000.0
Bond EUR Senior Notes	640.7	1 088.6	-	167.5	-	1 896.8
Subord. EUR Fixed Rate	808.5	-	0.6	1.2	-	810.3
Prepaid loan expenses	(37.5)	(43.4)	15.1	(1.6)	-	(67.5)
Accrued interests	54.7	(54.7)	126.4	-	-	126.3
Totals including hybrid	5 936.4	506.3	142.1	181.2	-	6 765.8

Note 16 Cash and cash equivalents

USD million	30 Sep 2025	30 Jun 2025	31 Dec 2024	30 Sep 2024

Bank deposits, unrestricted	830.2	699.8	266.6	782.9
Bank deposit, restricted, employee taxes	10.1	17.8	12.3	7.5
Total bank deposits	840.3	717.6	278.9	790.4

Note 17 Share capital and shareholders

As of 30 September 2025, the total share capital of the company is USD 46 million or NOK 399 million. The share capital is divided into 2 496 406 246 ordinary shares and 4 Class B shares. Each share has a nominal value of NOK 0.16. The ordinary shares represent NOK 399 424 999.36 of the total share capital, while the Class B shares represent NOK 0.64 of the total share capital.

All shares rank pari passu and have equal rights in all respects, including voting rights, dividends and other distributions, except for the class B shares with respect to board appointments. Four members to the board, will be elected by the general meeting with a simple majority among the votes cast for Class B shares. Such number to be reduced if the holder of the Class B shares holds less shares of the Company.

Vår Energi ASA's share saving program gives employees the opportunity to buy shares in Vår Energi ASA through monthly salary deductions. If the shares are retained for two full calendar years with continuous employment after the end of the saving year, the employees will be awarded a bonus share for each share they have purchased. This will be settled by Vår Energi ASA buying shares in the market. The award is treated as equity settled. The dilutive effect of equity settled shares under the share saving program is immaterial to the EPS calculation.

USD million	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024
Profit (loss) attributable to ordinary equity holders	151.7	216.7	180.3	821.2	502.2
EPS adj. for calc. interest/dividend on hybrid capital	(17.1)	(16.7)	(16.3)	(49.1)	(45.9)
Number of shares (in millions)	2 496	2 496	2 496	2 496	2 496
Earnings per share in USD basic and diluted	0.05	0.08	0.07	0.31	0.18

Note 18 Hybrid capital

Vår Energi ASA has issued EUR 750 million of subordinated fixed rate reset securities due on the 15th of November 2083. This is broadening the Company's funding sources and investor base and is reinforcing the balance sheet with a new layer of capital. Vår Energi has the right to defer coupon payments and ultimately decide not to pay at maturity. Deferred coupon payments become payable, however, if the Company decides to pay dividends to the shareholders.

Maturity	2083
Type	Subordinated
Financial classification	Equity (99 %)
Carrying Amount	EUR 744 million
Notional Amount	EUR 750 million
Issued	15 Nov 2023
Maturing	15 Nov 2083
Quoted in	Luxembourg
First redemption at par	15 Nov 2028
Coupon until first reset date	7.862% fixed rate until 15 Feb 2029
Margin Step-ups	+0.25% points from 15 Feb 2034 and
	+0.75% points after 15 Feb 2049
Deferral of interest payment	Optional

USD million	Equity	Debt	Total
Balance as of 31 December 2024	799.5	9.0	808.5
Profit/loss allocated to Hybrid owners	61.3	-	61.3
Non-cash changes	-	1.8	1.8
Interest classified as dividend	(61.3)	-	(61.3)
Balance as of 30 September 2025	799.5	10.8	810.3

Interest-bearing loans and borrowings

USD million	Coupon/int. Rate	Maturity	30 Sep 2025	30 Jun 2025	31 Dec 2024	30 Sep 2024

Bond USD Senior Notes (22/27)	5.00%	05-2027	500.0	500.0	500.0	500.0
Bond USD Senior Notes (22/28)	7.50%	01-2028	1 000.0	1 000.0	1 000.0	1 000.0
Bond USD Senior Notes (22/32)	8.00%	11-2032	1 000.0	1 000.0	1 000.0	1 000.0
Bond USD Senior Notes (25/30)	5.875 %	05-2030	750.0	750.0	-	-
Bond USD Senior Notes (25/35)	6.50%	05-2035	750.0	750.0	-	-
Bond EUR Senior Notes (23/29)	5.50%	05-2029	722.7	725.6	640.7	691.8
Bond EUR Senior Notes (25/31)	3.875 %	03-2031	1 174.1	1 172.0	-	-
Subord.EUR Fixed Rate Sec(23/83)	7.862 %	11-2083	10.8	10.6	9.0	9.6
RCF Working capital facility	1.08%+SOFR+CAS	05-2025	-	-	1 475.0	1 475.0
RCF Liquidity facility	1.13%+SOFR+CAS	05-2025	-	-	495.0	235.0
RCF Working capital facility	1.00%+SOFR +CAS	05-2028	-	-	-	-
RCF Liquidity facility	0.95%+SOFR +CAS	05-2030	-	-	-	-
Prepaid loan expenses			(67.5)	(76.1)	(37.5)	(40.5)
Accrued interests			126.3	76.3	54.7	73.1
Total interest-bearing loans and borrowings			5 966.5	5 908.4	5 136.9	4 944.0


Of which current and non-current:
Interest-bearing loans, current			126.3	76.3	54.7	73.1
Interest-bearing loans and borrowings non-current			5 840.1	5 832.1	5 082.2	4 870.9
Bond EUR Senior Notes (23/29):
Fair value of hedge related to EUR			16.9	21.2	19.1	21.9
senior notes Hedge inefficiency related to EUR			1.4	1.3	(1.8)	(1.9)
senior notes Bond EUR Senior Notes net including FV hedge			704.5	703.2	623.3	671.8

Credit facilities - Utilised and unused amount
USD million			30 Sep 2025	30 Jun 2025	31 Dec 2024	30 Sep 2024

Drawn amount credit facility Undrawn amount credit facilities			- 2 750.0	- 2 750.0	1 970.0 1 030.0	1 710.0 1 290.0

Vår Energi ASA has five senior USD notes and two senior EUR notes outstanding. The senior notes are registered on the Luxembourg Stock Exchange ("LuxSE") and coupon payments are made semi-annually for the USD notes and annually for the EUR notes. The senior notes have no financial covenants. The fair value of the bonds as of 30 September was USD 6 252 million.

In March 2025, Vår Energi ASA issued EUR 1000 million Senior Notes maturing in 2031. In May 2025, the Company issued two tranches of USD Senior Notes of 750 million each, maturing in 2030 and 2035 respectively.

The liability of Vår Energi ASA's EUR 750 million Subordinated Fixed Rate Reset Securities due in 2083 is reflected as interest bearing debt. For more details on the EUR Fixed Rate Reset Security, see note 18.

In May 2025, the Company refinanced its' unsecured revolving credit facilities by signing a new agreement totaling USD 2.75 billion, split over a USD 1000 million working capital facility and a USD 1750 million liquidity facility maturing in 2028 and 2030 respectively with the option to extend for additional two years at the lenders' discretion.

The facilities have covenants covering leverage (net interest-bearing debt to 12 months rolling EBITDAX not to exceed 3.5) and interest coverage (EBITDA to 12 months rolling interest expenses shall exceed 5) which will be tested at the end of each calendar quarter. The interest rate payable for each of the facilities is determined by timing and the company's credit rating taking the aggregate of the Secured Overnight Financing Rate (SOFR) and the Credit Adjustment Spread (CAS) and adding the applicable margin for the present period as shown in the table.

Note 20 Asset retirement obligations

USD million	Note	Q3 2025	Q1-Q2 2025	2024

Beginning of period		3 919.8	3 388.9	3 295.1
Additions through business combinations	2	-	-	371.5
Change in estimate	10	68.4	69.0	373.2
Change in discount rate	10	(106.4)	22.7	(204.2)
Accretion discount	7	36.6	69.4	115.7
Payment for decommissioning of oil and gas fields		(14.3)	(51.1)	(66.8)
Disposals		-	-	(103.8)
Currency translation effects		43.5	420.9	(391.7)
Total asset retirement obligations		3 947.6	3 919.8	3 388.9
Short-term		125.3	123.0	105.2
Long-term		3 822.3	3 796.9	3 283.7

Breakdown by decommissioning period		30 Sep 2025	30 Jun 2025	31 Dec 2024

2024-2030		239.5	235.1	216.5
2031-2040		2 226.7	2 230.1	1 949.2
2041-2061		1 481.4	1 454.7	1 223.3

The estimate is based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The calculations assume an inflation rate of 3% in 2025, 2.5% in 2026 and 2% in future years and discount rates between 3.8% - 4.0% per 30 September 2025. The assumptions for inflation rates were changed from 2% to 2.5% for 2026 while the discount rates were increased from 3.5% - 3.8% per 30 June 2025. The discount rates are based on risk-free interest without addition of credit margin.

Third quarter 2025 payment for decommissioning of oil and gas fields (abex) is mainly related to Statfjord, Ekofisk and Balder area.

Vår Energi has a retirement obligation as a shipper in Gassled booked to other non-current liabilities in the balance sheet statement. Vår Energi has accrued USD 94.7 million for this purpose per 30 September 2025, compared to USD 92.4 million per 30 June 2025..

Note 21 Other current liabilities

USD million	Note	30 Sep 2025	30 Jun 2025	31 Dec 2024	30 Sep 2024

Net overlift from hydrocarbons		276.0	216.2	162.5	148.8
Net payables to joint operations		365.2	408.4	365.5	475.4
Employee payables and accrued public charges		9.7	21.7	47.5	39.0
Contingent Consideration, current		-	-	-	18.8
Commodity derivaties	15	11.6	18.6	31.9	26.9
Other payables		19.7	18.4	21.4	10.7
Total other current liabilities		682.1	683.3	628.8	719.6

The liability for oil put options relates to cost of oil put options that under the purchase agreement is due for payment at the time of settlement of the option (exercise/expiry) and is not a measure of fair value.

Note 22 Commitments, provisions and contingent consideration

The company has significant contractual commitments for capital and operating expenditures from its participation in operated and partner operated exploration, development and production projects.

During the normal course of its business, the company will be involved in disputes, including tax disputes. The company makes accruals for probable liabilities related to litigation and claims based on management's best judgment and in line with IAS37 and IAS12.

After disagreement between the participants in the Breidablikk Unit, the Ministry Energy decided on the apportionment of the Breidablikk field on 29 June 2021, the decision was confirmed by the King in Counsel on 8 October 2021. Based on this tract participation Vår Energi's equity in the Breidablikk field was 34.4%. Vår Energi claimed that the Company had received approximately 5% less than the Company was entitled to. Sør-Rogaland District Court rejected Vår Energi's claim on 30 January 2024. Gulating Appeal Court rejected the appeal in decision 6 June 2025. Vår Energi has submitted an appeal to the Supreme Court.

Oslo District Court on 18 January 2024 delivered a decision in a case where Greenpeace and Natur og Ungdom had sued the Norwegian State represented by the Ministry of Energy. The Court concluded that the government's approvals of the respective Plan for Development and Operation ("PDO") for the three fields; Breidablikk, Tyrving and Yggdrasil are invalid due to insufficient impact assessments of climate effects of CO2 emissions related to the use of produced petroleum by the end user. The Court further granted a temporary injunction prohibiting the State from granting these fields any further approvals that require a valid PDO approval until the matter is resolved. Vår Energi is not a party to this dispute, but the outcome may have implications for Vår Energi as a licensee holding 34.4% interests in the Breidablikk field. The Ministry appealed to Court of Appeal, and a decision is expected mid October 2025.

The Court of Appeal dismissed the motion for a temporary injunction for the three fields, and this decision was appealed to the Supreme Court. On 11 April 2025 the Supreme Court ruled that the Court of Appeal had not applied a correct understanding of the law in its reasoning and referred the matter concerning the temporary injunction back to the Court of Appeal. Until the Court of Appeal decides otherwise, the temporary injunction established by the Court in the first instance is suspended. There are no effects on the Financial Statements related to this court case.

In October Vår Energi entered into an agreement with Total Energie to acquire their 39.896% ownership in the Ekofisk PPF project. The purchase price is USD 147 million and completion of the transaction is subject to Final Investment Decision for the project and customary regulatory approvals, including the carve-out of the PL018F licence from the PL018 licence. The transaction is expected to be completed by end 2025

Note 23 Lease agreements

USD million	Note	Q3 2025	Q1-Q2 2025	2024

Opening Balance lease debt		301.1	211.9	116.9
New lease debt in period		7.9	138.0	178.3
Additions through business combinations	2	-		10.5
Payments of lease debt		(32.8)	(58.7)	(83.3)
Lease debt derecognised in the period				1.0
Interest expense on lease debt		3.8	7.8	5.4
Currency exchange differences		0.7	2.1	(17.0)
Total lease debt		280.7	301.1	211.9

Breakdown		30 Sep 2025	30 Jun 2025	31 Dec 2024

Short-term		130.0	126.0	70.4
Long-term		150.6	175.1	141.5
Total lease debt		280.7	301.1	211.9

Lease debt split by activities		30 Sep 2025	30 Jun 2025	31 Dec 2024

Offices		60.2	61.3	55.7
Rigs, helicopters and supply vessels		214.8	233.6	149.9
Warehouse		5.7	6.1	6.3
Total		280.7	301.0	211.9

Vår Energi has entered into lease agreements for drilling rigs, supply vessels, and warehouses supporting operation at Balder, Gjøa and Goliat, where the most significant lease is the rig COSL Prospector operating in the Barents Sea. The group also has leases for offices in Sandnes, Florø, Oslo and Hammerfest, with the most significant contract being the main office building in Vestre Svanholmen 1, Sandnes.

During third quarter 2025 one lease related to rental of vessel on Balder has been included in lease debt. See note 11 for the Right of use assets.

Note 24 Related party transactions

Vår Energi has a number of transactions with other wholly owned or controlled companies by the shareholders. The related party transactions reported are with entities owned or controlled by the majority ultimate shareholder of Vår Energi, Eni SpA.. Revenues are mainly related to sale of oil, gas and NGL while the expenditures are mainly related to technical services, seconded personnel, insurance, guarantees and rental cost.

Current assets
USD million	30 Sep 2025	30 Jun 2025	31 Dec 2024	30 Sep 2024

Trade receivables
Eni Trade & Biofuels SpA	599.7	485.7	376.6	369.6
Eni SpA	57.8	22.0	71.7	22.7
Eni Global Energy Markets	0.1	-	-	8.6
Other	0.6	0.8	0.6	1.7
Total trade receivables	658.2	508.4	448.9	402.6

Current liabilities
USD million	30 Sep 2025	30 Jun 2025	31 Dec 2024	30 Sep 2024

Account payables
Eni Trade & Biofuels SpA	12.0	20.7	21.3	12.2
Eni SpA	0.3	1.2	10.4	11.3
Eni International BV	13.2	8.8	17.1	12.8
Other	-	0.4	0.8	0.6
Total account payables	25.5	31.1	49.6	36.9

All receivables are due within 1 year.

USD million	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024
Eni Trade & Biofuels SpA Eni SpA	1 495.2 194.4	1 139.4 197.8	1 217.7 163.6	3 804.1 628.1	3 742.3 554.9
Eni Global Energy Markets	0.4	0.3	23.8	0.6	60.7
Other Total	- 1 690.0	- 1 337.5	- 1 405.1	- 4 432.8	- 4 357.9

Operating and capital expenditures

USD million	Q3 2025	Q2 2025	Q3 2024	YTD 2025	YTD 2024

Eni Trade & Biofuels SpA	(2.7)	16.3	8.6	10.1	18.9
Eni SpA	0.4	1.7	4.8	0.7	12.7
Eni International BV	4.2	4.1	4.1	12.6	13.5
Other	(0.2)	0.1	(1.2)	0.2	1.2
Total	1.7	22.2	16.3	23.6	46.3

Note 25 Licence ownerships

Vår Energi has the following changes in the license portfolio since 31 December 2024.

Licences	WI%	Operator
044 D	13.1 %	ConocoPhillips
229 I	65%	Vår Energi
554 F	30%	Equinor Energy
636 D	30%	Vår Energi
1194 C	30%	OMV Norge
1218 B	20%	Aker BP
1246	17.2 %	Equinor Energy
1254	40%	Vår Energi
1260	45%	Vår Energi
1262	20%	Wellesley Petroleum
1263	20%	INPEX Idemitsu Norge
1265	40%	Equinor Energy
1268	30%	Aker BP
1269	30%	Equinor Energy
1274	20%	OMV Norge
1275	50%	Vår Energi

Licences/Fields	WI%	Operator
Licence transactions
107 B	22.5 %	Equinor Energy
107 D	22.5 %	Equinor Energy
820 S	44%	Vår Energi
820 SB	44%	Vår Energi
956	65%	Vår Energi
EXL007	40%	Vår Energi CCS

Industry terms

Term	Definition/description	Term	Definition/description
boepd	Barrels of oil equivalent per day	NGL	Natural gas liquids
boe	Barrels of oil equivalent	NOD	Norwegian Offshore Directorate
bbl	Barrels	OSE	Oslo Stock Exchange
CFFO	Cash flow from operations	PDO	Plan for Development and Operation
E&P	Exploration and Production	PIO	Plan for Installation and Operations
FID	Final investment decision	PRM	Permanent reservoir monitoring
FPSO	Floating, production, storage and offloading vessel	PRMS	Petroleum Resources Management System
HAP	High activity period	scf	Standard cubic feet
HSEQ	Health, Safety, Environment and Quality	sm3	Standard cubic meters
HSSE	Health, Safety, Security and Environment	SPT	Special petroleum tax
IG	Investment grade	SPS	Subsea production system
kboepd	Thousands of barrels of oil equivalent per day	SURF	Subsea umbilicals, riser and flowlines
mmbls	Millions of barrels	1P reserves	The quantities of petroleum which can be estimated with reasonable certainty to be
mmboe	Millions of barrels of oil equivalents		commercially recoverable, also referred to as "proved reserves".
mmscf	Millions of standard cubic feet	2C resources	The quantities of petroleum estimated to be potentially recoverable from known accumulations, also referred to as "contingent resources".
MoF	Ministry of Finance	2P reserves	Proved plus probable reserves consisting of 1P reserves plus those
MoE	Ministry of Energy		additional reserves, which are less likely to be recovered than 1P reserves.
NCS	Norwegian Continental Shelf

Disclaimer

"The Materials speak only as of their date, and the views expressed are subject to change based on a number of factors, including, without limitation, macroeconomic and market conditions, investor attitude and demand, the business prospects of the Group and other issues. The Materials and the conclusions contained herein are necessarily based on economic, market and other conditions as in effect on, and the information available to the Company as of, their date. The Materials comprise a general summary of certain matters in connection with the Group. The Materials do not purport to contain all information required to evaluate the Company, the Group and/or their respective financial position. The Materials should among other be reviewed together with the Company's previously issued periodic financial reports and other public disclosures by the Company. The Materials contain certain financial information, including financial figures for and as of 30 September 2025 that is preliminary and unaudited, and that has been rounded according to established commercial standards. Further, certain financial data included in the Materials consists of financial measures which may not be defined under IFRS or Norwegian GAAP. These financial measures may not be comparable to similarly titled measures presented by other companies, nor should they be construed as an alternative to other financial measures determined in accordance with IFRS or Norwegian GAAP.

The Company urges each reader and recipient of the Materials to seek its own independent advice in relation to any financial, legal, tax, accounting or other specialist advice. No such advice is given by the Materials and nothing herein shall be taken as constituting the giving of investment advice and the Materials are not intended to provide, and must not be taken as, the exclusive basis of any investment decision or other valuation and should not be considered as a recommendation by the Company (or any of its affiliates) that any reader enters into any transaction. Any investment or other transaction decision should be

taken solely by the relevant recipient, after having ensured that it fully understands such investment or transaction and has made an independent assessment of the appropriateness thereof in the light of its own objectives and circumstances, including applicable risks.

The Materials may constitute or include forward-looking statements. Forwardlooking statements are statements that are not historical facts and may be identified by words such as "plans", "targets", "aims", "believes", "expects", "ambitions", "projects", "anticipates", "intends", "estimates", "will", "may", "continues", "should" and similar expressions. Any statement, estimate or projections included in the Materials (or upon which any of the conclusion contained herein are based) with respect to anticipated future performance (including, without limitation, any statement, estimate or projection with respect to the condition (financial or otherwise), prospects, business strategy, plans or objectives of the Group and/or any of its affiliates) reflect, at the time made, the Company's beliefs, intentions and current targets/aims and may prove not to be correct. Although the Company believes that these assumptions were reasonable when made, these assumptions are inherently subject to significant known and unknown risks, uncertainties, contingencies and other important factors which are difficult or impossible to predict and are beyond its control. The Company does not intend or assume any obligation to update these forward-looking statements.

To the extent available, industry, market and competitive position data contained in the Materials come from official or third-party sources. Third-party industry publications, studies and surveys generally state that the data contained therein have been obtained from sources believed to be reliable, but that there is no guarantee of the accuracy or completeness of such data. While

the Company believes that each of these publications, studies and surveys has been prepared by a reputable source, none of the Company, its affiliates or any of its or their respective representatives has independently verified the data contained therein. In addition, certain of the industry, market and competitive position data contained in the Materials may come from the Company's own internal research and estimates based on the knowledge and experience of the Company in the markets in which it has knowledge and experience. While the Company believes that such research and estimates are reasonable, they, and their underlying methodology and assumptions, have not been verified by any independent source for accuracy or completeness and are subject to change and correction without notice. Accordingly, reliance should not be placed on any of the industry, market or competitive position data contained in the Materials.

The Materials are not directed to, or intended for distribution to or use by, any person or entity that is a citizen or resident or located in any locality, state, country or other jurisdiction where such distribution, publication, availability or use would be contrary to law or regulation of such jurisdiction or which would require any registration or licensing within such jurisdiction. Any failure to comply with these restrictions may constitute a violation of the laws of any such jurisdiction. The Company's securities have not been registered and the Company does not intend to register any securities referred to herein under the U.S. Securities Act of 1933 (as amended) or the laws of any state of the United States. This document is also not for publication, release or distribution in any other jurisdiction where to do so would constitute a violation of the relevant laws of such jurisdiction nor should it be taken or transmitted into such jurisdiction and persons into whose possession this document comes should inform themselves about and observe any such restrictions.'

AI Terminal

Vår Energi ASA

3780_rns_2025-10-21_1f19f01b-39ca-4174-9a0c-8ce3b87de178.pdf

Vår Energi in brief

Key figures third quarter 2025

Third quarter 2025 highlights

Production milestones met ahead of schedule

Solid financial performance

Unlocking long-term future value creation

Delivering predictable and attractive dividends

Key metrics and targets

Operational review

Production split third quarter

Balder Area

Projects

Barents Sea

Projects

North Sea

Projects

Norwegian Sea

Exploration

Health, safety, security and the environment (HSSE)

ESG and decarbonisation

Financial review

Key figures

Revenues and prices

Consolidated statement of financial position

Consolidated statement of cash flow

Outlook

Transactions with related parties

Subsequent events

Risks and uncertainties

Alternative performance measures (APMs)

Financial statements with note disclosures

Unaudited consolidated statement of comprehensive income

Unaudited consolidated balance sheet statement

Unaudited consolidated statement of changes in equity

Unaudited consolidated statement of cash flows

Unaudited consolidated statement of cash flows - continued

Notes

Note 1 Summary of IFRS accounting principles

Note 2 Business combination

Note 2 Business combination - continued

Note 3 Income

Note 4 Production Costs

Note 5 Other operating expenses

Note 6 Exploration expenses

Note 7 Financial items

Note 8 Income taxes

Note 8 Income taxes - continued

Note 9 Intangible assets

Note 10 Tangible assets

Note 11 Right of use assets

Note 12 Impairments

Impairment testing

Prices

Note 12 Impairments - continued

Oil and gas reserves

Future expenditure

Discount rate

Inflation

Impairments charge/reversal

Sensitivity analysis

Climate related risks

Note 13 Trade receivables

Note 14 Other current receivables and financial assets

Note 15 Financial instruments

Derivative financial instruments

Brent crude put options – financial assets

Note 15 Financial instruments - continued

Brent crude put options – deferred premiums

Commodity Derivatives - financial liabilities

Change in Hedge Reserve

Reconciliation of liabilities arising from financing activities

Note 16 Cash and cash equivalents

Note 17 Share capital and shareholders

Note 18 Hybrid capital

Interest-bearing loans and borrowings

Note 20 Asset retirement obligations

Note 21 Other current liabilities