Vår Energi ASA

Interim / Quarterly Report • Jul 22, 2025

Interim report

Vår Energi - Internal I

Second quarter and first half 2025

Vår Energi in brief

Vår Energi is a leading independent upstream oil and gas company on the Norwegian continental shelf (NCS). We are committed to deliver a better future through responsible value driven growth based on over 50 years of NCS operations, a robust and diversified asset portfolio with ongoing development projects, and a strong exploration track record.

Safe and responsible operations are at the core of our strategy. Our ambition is to be the safest operator on the NCS, and to become carbon neutral in our net equity operational emissions by 2030.

Vår Energi has around 1400 employees and equity stakes in 42 producing fields. We have our headquarters outside Stavanger, Norway, with offices in Oslo, Hammerfest and Florø. 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	12
HSSE	13
Financial review	15
Key figures	15
Revenues and prices	17
Statement of financial position	18
Statement of cash flow	19
First half of 2025 review	20
Outlook	21
Alternative Performance	22
Measures
Financial statements	24
Notes	30

Key figures second quarter 2025

First quarter 2025 in brackets

Production kboepd

288 (272)

Petroleum revenues USD million

1 828 (1 833)

EBIT USD million

1 195 (972)

Profit before tax USD million

1 234 (1 279)

CFFO USD million

766 (1 322)

Capex USD million

761

(595)

USD million

4 (727)

FCF

NIBD/EBITDAX x

0.9 (0.8)

Second quarter 2025 highlights

Vår Energi reports strong results with key growth projects delivered as expected and a pipeline of quality new projects being moved forward to sustain long term resilience

Production on-track for the mid-point of full year guidance

• Jotun FPSO successfully on stream, peak production expected during September
• Johan Castberg producing at plateau
• Current production above 350 kboepd
• Major turnarounds completed by end of July

Strengthened financial position

• Unit production cost on track to meet approximately USD 10 per boe by the fourth quarter
• 25% of gas volumes locked in at USD 92 per boe
• Successful issuance of USD 1.5 billion senior notes
• Increased liquidity through refinancing of credit facilities
• Utilising flexibility to reduce spend by around USD 500 million in 2025/26

Demonstrating growth and unlocking future value

• Adding approximately 180 kboepd at peak from new fields in 2025
• Progressing project portfolio with four project sanctions year to date
• Exploration successes adding high value barrels

Delivering predictable and attractive dividends

• Second quarter dividend of USD 300 million (NOK 1.222 per share) will be distributed 26 August¹
• Full year dividend guidance for 2025 and 2026 of USD 1.2 billion

Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
-	-	0.1	-	0.1
10.7	9.8	10.1	10.3	10.1
288	272	287	280	293
12.7	11.6	12.4	12.2	12.2
1 270	1 535	1 669	2 805	3 146
766	1 322	711	2 088	1 720
4	727	(62)	731	253
300	270	270	570	540

¹The dividend is subject to EGM approval 12 August

"We are pleased to report strong results for the quarter. Our key growth projects have been delivered as expected, with four of the nine projects to come on stream this year already online. Johan Castberg is producing at full capacity, the Jotun FSPO at the Balder field and Halten East are ramping up and Ormen Lange Phase III has started ahead of plan. With current production above 350 thousand barrels of oil equivalent per day (kboepd), we expect to reach about 430 kboepd in the fourth quarter, delivering on our plans for transformative growth in 2025.

The Company is on track to sustain production at 350-400 kboepd towards 2030, which will be achieved by developing our portfolio of around 30 early phase projects. Over 10 of these projects are set to be sanctioned this year, with four already sanctioned in the first half, including the Balder Phase VI and Fram Sør subsea tie-backs. These projects are being moved forward at speed to deliver high value barrels with strong economics and average breakevens below USD 35 per barrel.

Our exploration program continues to deliver successful results, with three commercial discoveries so far this year, continuing the Company's leading exploration track record on the Norwegian Continental Shelf.

During the first half of 2025, the Company's financial position has been strengthened through the successful refinancing of credit facilities and issuance of senior notes, totalling USD 5.2 billion, reducing cost of debt and providing significant available liquidity.

To further improve the resilience and competitiveness of our business in a volatile market, measures are taken to reduce spend by USD 500 million for 2025 and 2026, while maintaining the long-term production outlook.

On the back of this strong performance, the Company continues to provide attractive and predictable shareholder distributions. We confirm a dividend of USD 300 million for the second quarter and guide a total dividend distribution of USD 1.2 billon for the full year 2025 and USD 1.2 billion for the full year 2026"

Nick Walker, the CEO of Vår Energi

Key metrics and targets

Income statement	Unit	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Total income	USD million	1 849	1 871	1 940	3 720	3 896
EBIT	USD million	1 195	972	992	2 167	2 046
Profit/(loss) before taxes	USD million	1 234	1 279	1 032	2 513	1 882
Net profit/(loss)	USD million	217	453	222	670	322
Earnings per share	USD	0.08	0.18	0.08	0.26	0.12
Other financial key figures
Production cost	USD/boe	12.7	11.6	12.4	12.2	12.2
Net interest-bearing debt (NIBD)	USD million	5 209	4 637	4 336	5 209	4 336
Leverage ratio (NIBD/EBITDAX)		0.9	0.8	0.8	0.9	0.8
Dividend per share	USD	0.12	0.11	0.11	0.23	0.22
Production
Total production	kboepd	288	272	287	280	293
- Oil	kboepd	180	160	162	170	166
- Gas	kboepd	92	96	103	94	107
- NGL	kboepd	16	16	22	16	20
Sales
Total sales	mmboe	26.0	23.8	25.1	49.8	51.0
- Crude oil	mmboe	17.1	15.0	15.1	32.1	29.6
- Gas	mmboe	7.7	8.0	7.9	15.8	17.1
- NGL	mmboe	1.2	0.7	2.1	1.9	4.3
Realised prices
- Crude oil	USD/boe	68.5	75.6	84.8	71.8	84.5
- Gas	USD/boe	78.8	86.7	70.4	82.9	68.4
- NGL	USD/boe	42.8	54.1	43.8	47.0	47.5
Average realised prices (volume weighted)		70.4	78.7	76.8	74.4	76.1

kboepd	330-360
kboepd	~ 430
USD/boe	11-12
	2 300- 2 500
	~ 380
	~ 100
	300
	1 200
	~ 1 200
kboepd	~ 400
kboepd	350-400
USD/boe	~ 10
	2 000 - 2 500
	200 - 300
	~ 150
	1 200
NIBD/EBITDAX	< 1.3x
	stated)

¹ Assumed NOK/USD at 10.5

2 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 288 kboepd in the second quarter of 2025. Production in the first half of the year averaged 280 kboepd, and with the main new project start-up's achieved the Company is on track to deliver full year 2025 production in the middle of the guided range of 330 to 360 kboepd. Fourth quarter 2025 production is expected to be around 430 kboepd.

Vår Energi's net production of oil, liquids and natural gas averaged 288 kboepd in the second quarter 2025, an increase of 6% from the previous quarter. First half 2025 production of 280 kboepd was around the bottom of the expected range, mainly due to the later start-up and slower ramp-up to plateau at Johan Castberg than initially planned. Strong operational performance continues on operated assets, with production efficiency better than target at 95% for the first half of 2025. The Company's main turnaround activities for 2025 were scheduled in the second quarter/early third quarter, with an impact of around 30 kboepd on second quarter 2025 production volumes.

Vår Energy plans to start-up nine new projects during 2025, adding around 180 kboepd production at peak levels. Four of these projects reached first production during the first half of 2025. Halten East started up in March, on time and within budget, and is expected to reach peak production of 20 kboepd net Vår Energi in the fourth quarter of 2025. Johan Castberg achieved first oil in March and ramped up to plateau production of 66 kboepd net Vår Energi in June. First production through the Jotun FPSO at the Balder field was achieved in June in line with guidance, peak production levels of 70 kboepd net Vår Energi are expected to be reached during September. Ormen Lange Phase III (subsea compression) started up in June ahead of schedule and below budget, when ramped up, the production contribution is around 5 kboepd net to Vår Energi. The remaining five projects are all on track to start-up before the end of 2025.

Production split first half of 2025

Current production potential is above 350 kboepd and fourth quarter 2025 production is now estimated to be around 430 kboepd, in line with the previous guidance of over 400 kboepd.

Production costs for the first half of 2025 were USD 12.2 per boe, with a guidance range of USD 11-12 per boe for the full year 2025. The first half of 2025 was impacted by start-up of new fields, and seasonal maintenance activities. 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 resource base and comprehensive early phase project portfolio including the recent sanctions supports sustainable production of 350-400 kboepd towards 2030. The Company is progressing around 30 early phase projects accounting for net 2C contingent resources of around 600 mmboe and expects to sanction over 10 projects during 2025. Four projects have been sanctioned year to date, 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. Fram Sør, a subsea tie-back development to Troll C took a final investment decision in the second quarter, developing 116 mmboe gross¹ resources.

The Company has made three commercial exploration successes so far in 2025, with the recent Vår Energi operated Vidsyn well in the Fenja area and Equinor operated Drivis Tubåen well in the Johan Castberg area. The recent Goliat Ridge discoveries are being matured as a fast-track subsea development with flexibility to include potential future discoveries, and two appraisal wells are planned in the Goliat Ridge later this year, Goliat North and Zagato North.

The expected exploration spend for 2025 is increased to around USD 380 million, as a result of successful wells.

In light of the volitile markets, the Company has taken a proactive approach and has used the flexibility in the business, with around 65% of future capital spend uncommitted² , to reduce spend by around USD 500 million for the period 2025 – 2026. Vår Energi will utilise the volatility to make the Company even more efficient and competitive. These reductions will be achieved by utilising the flexibility the Company has in the early phase project portfolio, improvements and optimising the operational and exploration activities. The reduced spend levels will have no impact on the Company's plan to sustain production at 350 – 400 kboepd towards 2030.

¹Vår Energi working interest 40% ²Average over period 2025-2030

Production (kboepd)	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Balder Area	63	64	54	64	54
Barents Sea	36	26	29	31	30
North Sea	85	92	105	88	107
Norwegian Sea	104	90	99	97	102
Total Production	288	272	287	280	293

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)	Q2 2025	Q1 2025	Q4 2024	Q3 2024	Q2 2024
Balder/Ringhorne	27	25	25	24	26
Grane/Svalin	10	12	11	10	8
Breidablikk	26	27	24	19	19
Total Balder Area	63	64	60	53	54

Performance from the Balder Area was strong with production of 63 kboepd in the second quarter, a decrease of 2% compared to the first quarter, driven by planned turnaround activities at Balder and Ringhorne, which was offset by strong performance from the Breidablikk field and increased production from Ringhorne due to new wells coming on stream. The Balder field production efficiency was 91% in first half of 2025, including a successfully conducted planned turnaround.

Average production for the first half of 2025 was 64 kboepd, and further production increase is expected for the second half of the year due to Jotun FPSO ramping up to peak production. Five new wells are expected to be brought onstream from Breidablikk/Grane in the second half of the year, which will further increase the overall production from the hub.

Projects

The Balder X project has progressed its final commissioning in the quarter and successfully started production through the Jotun FSPO in June as planned. All 14 production wells have been completed and will be brought onstream during the ramp-up period and are expected to reach peak production during September.

The Jotun FPSO will deliver around 80 kboepd gross1,2 at peak, unlocking gross proved plus probable (2P) reserves of around 150 mmboe1,2 . In addition, the drilling of six new wells as part of Balder Phase V project progresses as planned, with the first well expected to commence production the fourth quarter 2025. Additionally, the Balder Phase VI project was sanctioned in the second quarter, ahead of original plan with anticipated first oil by end 2026, with 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 mmboe² .

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 a production from the Balder field area in the range 70-80 kboepd gross² towards 2030. The decommissioning of Balder FPU is expected to reduce operating costs by approximately USD 130 million gross² per annum and to reduce CO² emissions by around 80,000 tonnes gross² per year.

The above projects are steps to ensure high value barrels from the Balder area towards 2045 and beyond.

¹ Balder Phase V and VI not included ² Vår Energi working interest 90%

Barents Sea

Production (kboepd)	Q2 2025	Q1 2025	Q4 2024	Q3 2024	Q2 2024
Goliat	13	14	14	15	14
Johan Castberg	20	-	-	-	-
Snøhvit	4	13	16	17	16
Total Barents Sea	36	26	30	32	29

Average production in the Barents Sea was 36 kboepd in the second quarter, up 38% from the first quarter due to start-up of Johan Castberg. The Goliat field had a production efficiency in the first half of 2025 of 94%, impacted by planned maintenance activities in the second quarter. Two planned infill oil producers were successfully completed at the Goliat field in the quarter, with results in line with expectations. In addition, 4D seismic acquisition over the Goliat field is ongoing, which will support the development of future in-fill 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 in less than 2 years from start-up. The project has completed eighteen 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 second quarter, commenced in late April, and production is expected to started up in end of July.

Average production for the first six months of the year was 31 kboepd, and further production increase is expected for the second half of the year due to Johan Castberg production reaching plateau production levels and the Snøhvit planned turnaround.

North Sea

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, is targeting sanctioning of the first phase, Isflak, in the fourth quarter 2025. In total, there are between 250 and 550 million barrels of additional gross unrisked recoverable resources identified in the area.

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.

Production (kboepd)	Q2 2025	Q1 2025	Q4 2024	Q3 2024	Q2 2024
Ekofisk Area	15	21	23	22	19
Snorre	17	16	17	18	14
Gjøa Area	15	15	18	17	21
Gudrun	7	6	6	5	7
Statfjord Area	10	12	12	14	12
Fram	12	13	15	15	18
Sleipner Area	3	3	4	5	8
Other	5	5	5	6	5
Total North Sea	85	92	100	102	105

Production from North Sea was 85 kboepd in the second quarter, an 8% reduction from previous quarter mainly due to a planned turnaround in the Ekofisk area and lower well capacity from the Fram area.

Vår Energi's operated assets have continued to perform strongly with the Gjøa area achieving 97% production efficiency in the first half of 2025.

Average production for the first six months of the year was 88 kboepd in line with expectations.

Restoration of Sleipner B production after the fire in 2024 is ongoing and it is expected that the production will start up partly in September 2025 and full production 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

Fram Sør, Gudrun Low Pressure Project and Snorre Gas Export 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 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, a series of new exploration targets are set to be drilled in 2025 and 2026, unlocking potential further upside¹ .

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

In the Ekofisk area the Ekofisk PPF (Previously Produced Fields) project is being matured towards an investment decision within year end 2025. While the Eldfisk North project is planning a final investment decision during third quarter 2025.

¹ Vår Energi working interest 40%

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

Norwegian Sea

Production (kboepd)	Q2 2025	Q1 2025	Q4 2024	Q3 2024	Q2 2024
Åsgard area	36	32	33	23	37
Mikkel	10	10	8	5	9
Tyrihans	13	13	11	8	14
Halten Øst	11	1	-	-	-
Ormen Lange	6	8	9	8	8
Fenja	11	12	15	13	17
Njord Area	9	6	5	4	7
Other	9	8	7	7	9
Total Norwegian Sea	104	90	88	70	99

In the Norwegian Sea production for the second quarter was 104 kboepd, a 15% increase from the previous quarter. Average production for the first half of 2025 was 97 kboepd, in line with expectations.

The increased production in the quarter was mainly due to Halten East project coming on stream in March 2025, expecting to provide Vår Energi with net production of around 20 kboepd at peak expected in the fourth quarter of 2025. The field holds gross reserves of around 100 mmboe¹, and the area has additional unrisked gross recoverable resource potential of 100-200 mmboe for future development.

³ Vår Energi 24.6% working interest

Exploration

The Company's exploration program continues to deliver successful results, with three commercial discoveries so far in 2025 from the 11 exploration wells drilled, continuing the Company's leading exploration track record on the NCS. The three discoveries contain net recoverable resources in the range of 40 to 60 mmboe and all will be developed as subsea tie-back projects and will add high value barrels. A further 9 exploration wells are planned to be completed in 2025. The expected exploration spend for 2025 is increased to around USD 380 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, targeting up to a 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 assumed to be 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, the close proximity to Goliat FPSO provides 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. The drilling of two further appraisal wells is planned to start in the third quarter this year. A new 3D seismic survey was acquired in the second quarter over the Goliat Ridge area to support development studies.

The Aker BP operated Rondeslottet exploration well in licence PL1005, the Equinor operated Lit exploration well in licence PL169, the Equinor operated Garantiana NW well in licence PL 554 and the OMV operated Hoffmann exploration well in licence PL1194 were concluded in June/July 2025 , all

were dry wells. The Equinor operated Skred exploration well in licence PL 532 was classified as a non-commercial gas discovery.

¹ Vår Energi working interest 75% ² Vår Energi working interest 30% ³ Vår Energi working interest 65%

Health, safety, security and the environment (HSSE)

Key HSSE indicators, operated activity	Unit	Q2 2025	Q1 2025	Q4 2024	Q3 2024	Q2 2024
Serious incident frequency (SIF Actual)1 12M rolling avg	Per mill. exp. Hours	0.0	0.0	0.1	0.1	0.1
Serious incident frequency (SIF)1 12M rolling avg	Per mill. exp. Hours	0.4	0.3	0.3	0.3	0.3
Total recordable injury frequency (TRIF)2 12M rolling avg	Per mill. exp. Hours	2.7	3.3	3.5	3.1	2.8
Significant spill to sea	Count	0	0	0	0	0
Process safety events Tier 1 and 23	Count	0	0	0	0	1
emissions intensity (equity share)4,5 CO2	kg CO2/boe	10.7	9.8	9.5	10.0	10.1

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 second quarter the Company continued the positive performance with no actual serious incidents nor

incidents with a serious potential. Recordable injuries in the second quarter are of lower potential and have seen an improved level in over the last months versus the rolling 12 months average. 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.

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". Since March 2024, the Company has been included in the Oslo Stock Exchange ESG index as the only oil and gas company. The Company is also the only operator on the NCS with an ISO 50001:2018 energy management certification.

Vår Energi has a clear path to more than 50% GHG¹ emissions reduction for its scope 1 emissions by 2030² from three main levers, electrification with power from shore, portfolio optimisation and energy management. In addition to emission reductions, Vår Energi is also on the path to become carbon neutral in net equity operational emissions by 2030 through carbon removals in the voluntary carbon market for residual emissions and have entered into flexible agreements to achieve this. Vår Energi has zero scope 2 (market based) emissions³ in first half of 2025, this is achieved through energy efficiencies and purchase of

guarantees of origin from renewable sources for the residual scope 2 emissions

In the second quarter of 2025 scope 1 net equity CO2 emissions intensity was 10.7 kg CO2 per boe, versus 9.8 kg CO2 per boe in the first quarter 2025. For the first half of 2025 scope 1 net equity CO2 emissions intensity was around 10.3 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 second quarter and first half of 2025 the operated methane emission intensity for Vår Energi is 0.02%⁴ , well below the Near Zero levels⁵ .

Vår Energi has a value driven approach towards creating future optionality through CCS⁶ , 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

²Baseline year 2005

³Vår Energi's share of operations where the Company is the operator ⁴Emitted CH⁴ vs exported gas ⁵Near zero below 0.2% as per OGCI definition

6 Carbon capture and storage (CCS)

Financial review

Key figures

Key figures (USD million)	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Total income	1 849	1 871	1 940	3 720	3 896
Production costs	(395)	(305)	(346)	(700)	(728)
Other operating expenses	(43)	(43)	(48)	(86)	(32)
EBITDAX	1 411	1 524	1 546	2 934	3 135
Exploration expenses	(70)	(69)	(56)	(139)	(89)
EBITDA	1 341	1 455	1 490	2 795	3 046
Depreciation and amortisation	(587)	(458)	(498)	(1 045)	(1 000)
Impairment loss and reversals	441	(24)	-	417	-
Net financial income/(expenses)	(38)	(33)	(26)	(71)	(44)
Net exchange rate gain/(loss)	78	339	65	417	(120)
Profit/(loss) before taxes	1 234	1 279	1 032	2 513	1 882
Income tax (expense)/income	(1 018)	(826)	(810)	(1 843)	(1 560)
Profit/(loss) for the period	217	453	222	670	322

Total income in the second quarter amounted to USD 1 849 million, a decrease of USD 22 million compared to the previous quarter due to lower prices being offset by higher sales. Volumes sold increased by 9% to 26.0 mmboe in the quarter due to higher production. Realised crude price decreased by 9% in the quarter to USD 68 per boe while realised gas price decreased by 9% in the quarter to USD 79 per boe.

Production cost in the second quarter amounted to USD 395 million, an increase of USD 90 million compared to the previous quarter.

The average production cost per barrel produced increased to USD 12.7 per boe in the quarter, compared to USD 11.6 per boe in the previous quarter mainly driven by start-up of new fields and seasonal planned maintenance activities. Second quarter 2025 increased by USD 0.3 per boe, compared to second quarter of 2024.

Exploration expenses in the second quarter increased to USD 70 million compared to USD 69 million in the previous quarter mainly due to increased dry well cost.

Depreciation and amortisation in the second quarter amounted to USD 587 million, an increase compared to the previous quarter due to higher depreciation rates driven by Halten East and Johan Castberg coming on stream.

Impairment loss and reversals in the quarter of USD 441 million was related to an impairment reversal of USD 510 million pre-tax on Balder due to changes in reserves and technical goodwill impairments on Njord, Gjøa and Snøhvit. Net impairment reversal in the quarter amounts to USD 42 million post-tax.

Net exchange rate gain in the second quarter amounted to USD 78 million, due to strengthened NOK versus USD offset by the weakening of NOK towards the EUR.

Profit before taxes in the second quarter amounted to USD 1 234 million compared to USD 1 279 million in the previous quarter. Income tax expense in the second quarter amounted to USD 1 018 million, an increase of USD 192 million compared to the previous quarter.

The effective tax rate for the quarter was 82%, above the marginal tax rate of 78% due to impairment of technical goodwill partly offset by exchange rate gain taxed at 22%.

Net result for the period amounted to USD 217 million, a decrease of USD 236 million compared to the previous period mainly due to higher tax expense in the quarter.

Revenues and prices

Total income (USD million)	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Revenue from crude oil sales	1 170	1 136	1 282	2 305	2 504
Revenue from gas sales	607	659	558	1 265	1 170
Revenue from NGL sales	51	39	91	90	202
Hedge	-	-	2	-	7
Total Petroleum Revenues	1 828	1 833	1 933	3 661	3 882
Other Operating Income	21	38	7	60	14
Total Income	1 849	1 871	1 940	3 720	3 896
Sales volumes (mmboe)
Sales of crude	17.1	15.0	15.1	32.1	29.6
Sales of gas	7.7	8.0	7.9	15.8	17.1
Sales of NGL	1.2	0.7	2.1	1.9	4.3
Total Sales Volumes	26.0	23.8	25.1	49.8	51.0
Realised prices (USD/boe)
Crude oil	68	76	85	72	85
Gas	79	87	70	83	68
NGL	43	54	44	47	47
Average realised prices	70	79	77	74	76

Vår Energi obtained an average realised price of USD 70 per boe in the quarter.

The realised gas price of USD 79 per boe in the second 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 25% of second quarter gas volumes sold at an average price of USD 92 per boe, substantially above the spot market reference price.

Vår Energi continues to execute fixed price transactions. As of 30 June 2025, the Company has entered into a transactions of approximately 18% of the gas production for the third quarter of 2025 has been sold on a fixed price basis at an average price around USD 90 per boe.

At the end of the second 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 Jun 2025	31 Mar 2025	31 Dec 2024
Goodwill	3 323	3 247	2 988
Property, plant and equipment	19 951	18 144	16 737
Other non-current assets	985	1 047	876
Cash and cash equivalents	718	661	279
Other current assets	1 248	1 051	988
Total assets	26 224	24 149	21 868
Equity	972	1 009	833
Interest-bearing loans and borrowings	5 908	5 270	5 137
Deferred tax liabilities	12 362	11 286	10 501
Asset retirement obligations	3 920	3 617	3 389
Taxes payable	1 183	1 178	682
Other liabilities	1 878	1 788	1 327
Total equity and liabilities	26 224	24 149	21 868
Cash and cash equivalents	718	661	279
Revolving credit facilities	2 750	2 005	1 030
Total available liquidity	3 468	2 666	1 309
Net interest-bearing debt (NIBD)	5 209	4 637	4 870
EBITDAX 4 quarters rolling	5 702	5 837	5 902
Leverage ratio (NIBD/EBITDAX)	0.9	0.8	0.8

Total assets at the end of the second quarter amounted to USD 26 224 million, an increase from USD 24 149 million at the end of the previous quarter. Non-current assets were USD 24 258 million and current assets were USD 1 965 million at the end of the second quarter.

Total equity amounted to USD 972 million at the end of the second quarter, corresponding to an equity ratio of about 4%.

Net interest-bearing debt (NIBD¹ ) at the end of the second quarter was USD 5 209 million, an increase of USD 572 million from the previous quarter.

As a result, total available liquidity amounted to USD 3 468 million at the end of the second quarter, compared to USD 2 666 million at the end of the previous quarter. Undrawn credit facilities at the end of the second quarter were USD 2 750 million and total cash and cash equivalents were USD 718 million. The Company maintains a strong financial position with a leverage ratio (NIBD/EBITDAX) of 0.9x at the end of the second quarter, well within the guided target of below 1.3x through the cycle.

¹NIBD has been changed to include accrued interest and exclude lease liability and restricted cash to align with covenants in the revolving credit facilities agreement. Please see the Alternative performance measures (APMs) section of the report for detailed descriptions of the Company's APMs.

Consolidated statement of cash flow

USD million	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Cash flow from operating activities	766	1 322	711	2 088	1 720
Cash flow used in investing activities	(781)	(626)	(784)	(1 408)	(2 822)
Cash flow from financing activities	56	(349)	(327)	(293)	708
Effect of exchange rate fluctuation	16	35	(7)	51	(25)
Change in cash and cash equivalents	41	347	(400)	388	(395)
Cash and cash equivalents, end of period	718	661	315	718	315
Net cash flows from operating activities	766	1 322	711	2 088	1 720
CAPEX	761	595	773	1 357	1 467
Free cash flow	4	727	(62)	731	253
Capex coverage (CFFO)/Capex)	1.0	2.2	0.9	1.5	1.2

Cash flow from operating activities (CFFO) post-tax was USD 766 million in the second quarter, a decrease of USD 557 million from the previous quarter. This was mainly due to two tax instalments paid in the quarter and negative working capital movements. The negative working capital movements are related to higher receivables at end of the second quarter compared to the first quarter.

Net cash used in investing activities was USD 781 million in the quarter, whereof USD 692 million was related to PP&E expenditures. Investments in the Balder Area and at Johan Castberg represented around 56% of these expenditures.

Net cash outflow from financing activities amounted to USD 56 million in the quarter. Cash outflow in the quarter consisted of interest paid of USD 117 million, dividends paid of USD 300 million, partly offset by net inflow of bond issue and payment of RCF of USD 505 million.

Free cash flow (FCF) was USD 4 million in the quarter, compared to USD 727 million in the previous quarter. The decrease is mainly driven by lower cash flow from operations, due to higher tax payment and negative working capital impact in the second quarter combined with higher PP&E expenditures. The capex coverage was 1.0 in the second quarter, down from 2.2 in the previous quarter.

Report for the first half 2025

	Unit	1H 2025	1H 2024
Net petroleum production	kboepd	280	293
Total Income	USD million	3 720	3 896
Operating profit	USD million	2 167	2 046
Profit before taxes	USD million	2 513	1 882
Net profit	USD million	670	322
Net interest-bearing debt	USD million	5 209	4 336
Net cash flow from operating activities	USD million	2 088	1 720
Net cash used in investing activities	USD million	(1 408)	(2 822)
Net cash from financing activities	USD million	(293)	708

During the first six months of 2025, Vår Energi reported total income of USD 3 720 million, compared to USD 3 896 million in the first six months of 2024. The decrease was mainly driven by lower sales due to lower production and lower realised crude prices partly offset by higher realised gas prices.

Production in the first half of 2025 was 280 kboepd compared to 293 kboepd in the first half of 2024. The decrease was mainly due to reduced production in the North Sea and Norwegian sea areas.

Average realised crude prices decreased to USD 71.8 per boe, compared to USD 84.5 per boe in the first half of 2024, while the average realised gas price increased to USD 82.9 per boe, compared to USD 68.4 per boe in the first half of 2024.

Production cost in the first half of 2025 was USD 12.2 per boe stable compared to USD 12.2 per boe in the first half of 2024.

Operating profit for the first half of 2025 was USD 2 167 million, an increase from USD 2 046 million in the first half of 2024. The increase was mainly due to reversal of impairment of 417 in 2025. Net profit in the first half of 2025 was USD 670 million compared to USD 322 million in the first half of 2024.

Net interest-bearing debt at the end of the first half of 2025 was USD 5 208 million compared to USD 4 336 million in the first half of 2024.

Net cash flow from operating activities in the first half of 2025 was USD 2 088 million compared to USD 1 720 million in the first half 2024.

Net cash used in investing activities was USD 1 408 million in the first half of 2025 compared to USD 2 822 million in the first half of 2024, the decrease was mainly due to the Neptune Energy acquisition in 2024.

Net cash outflow from financing activities was USD 293 million in the first half of 2025 compared to a cash inflow of USD 708 million in the first half of 2024.

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 380 million in exploration capex and around USD 100 million in abandonment capex. Production cost is expected to be between USD 11 and 12 per boe in 2025, reducing to around USD 10 per boe in the fourth quarter 2025.

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 26 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.

Recent tensions over trade tariffs increase and potential impacts on global demand 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.

Responsibility Statement

The Board of Directors and the CEO confirm that to the best of our knowledge the interim financial statement for the first half of 2025 have been prepared in accordance with IFRS, as adopted by the EU, IAS 34 Interim financial reporting, and requirements in accordance with the Norwegian Accounting Act, and gives a true and fair view of the Company's assets, liabilities, financial positions, and results for the period.

The Board of Directors and the CEO certify that the financial report for the first six months ended 30 June 2025 gives a true and fair view of the Company's business performance, major related party transactions, and describes the principal risks and uncertainties that the Company faces.

Sandnes, 21 July 2025 Signed electronically

Thorhild Widvey Chair

Liv Monica Bargem Stubholt Deputy Chair

Francesco Gattei Director

Guido Brusco Director

Francesca Rinaldi Director

Claudia Almadori Director

Ole Johan Gillebo Director

Fabio Ignazio Romeo Director

Martha Skjæveland

Lilli Sahlman Fagerdal Director, employee elected

representative

Director, employee elected representative

Carl Anders Olof Kjörling Director, employee elected representative

Jan Inge Nesheim Director, employee elected representative

Nicholas John Robert Walker Chief Executive Officer

Financial statements with note disclosures

	Unaudited consolidated statement of comprehensive income	25	Note 12	Impairment	39
	Unaudited consolidated balance sheet statement	26	Note 13	Trade receivables	41
	Unaudited consolidated statement of changes in equity	27	Note 14	Other current receivables and financial assets	41
	Unaudited consolidated statement of cash flows	28	Note 15	Financial instruments	41
Notes		30	Note 16	Cash and cash equivalents	43
Note 1	Summary of IFRS accounting principles	30	Note 17	Share capital and shareholders	43
Note 2	Business combination	30	Note 18	Hybrid capital	43
Note 3	Income	32	Note 19	Financial liabilities and borrowings	44
Note 4	Production costs	33	Note 20	Asset retirement obligations	45
Note 5	Other operating expenses	33	Note 21	Other current liabilities	45
Note 6	Exploration expenses	34	Note 22	Commitments, provisions and contingent consideration	46
Note 7	Financial items	34	Note 23	Lease agreements	46
Note 8	Income taxes	35	Note 24	Related party transactions	47
Note 9	Intangible assets	37	Note 25	Licence ownerships	48
Note 10	Tangible assets	38	Note 26	Subsequent events	48
Note 11	Right of use assets	39

Unaudited consolidated statement of comprehensive income

USD million, except earnings per share data	Note	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Petroleum revenues	3	1 827.6	1 833.1	1 933.3	3 660.7	3 882.1
Other operating income		21.4	38.2	6.8	59.6	13.6
Total income		1 849.0	1 871.3	1 940.1	3 720.3	3 895.8
Production costs	4	(395.3)	(304.7)	(346.4)	(700.0)	(728.2)
Exploration expenses	6 , 9	(69.7)	(69.3)	(55.8)	(139.0)	(89.0)
Depreciation and amortisation	10 , 11	(587.1)	(458.3)	(497.8)	(1 045.4)	(1 000.4)
Impairment losses and reversal	9 , 10 , 12	440.8	(23.9)	(0.0)	416.9	(0.0)
Other operating expenses	5	(43.1)	(42.9)	(48.0)	(85.9)	(32.3)
Total operating expenses		(654.4)	(899.0)	(948.0)	(1 553.4)	(1 849.9)
Operating profit/(loss)		1 194.6	972.4	992.2	2 166.9	2 045.8
Net financial income/(expenses)	7	(37.9)	(32.7)	(25.7)	(70.6)	(44.4)
Net exchange rate gain/(loss)	7	77.7	338.9	65.4	416.6	(119.5)
Profit/(loss) before taxes		1 234.4	1 278.6	1 031.9	2 513.0	1 881.9
Income tax (expense)/income	8	(1 017.7)	(825.7)	(810.0)	(1 843.4)	(1 559.9)
Profit/(loss) for the period		216.7	452.9	221.8	669.6	321.9
Attributable to:
Holders of ordinary shares		216.7	391.6	221.8	608.3	306.3
Dividends paid on hybrid capital	18	-	61.3	-	61.3	15.6
Profit / (loss) for the period		216.7	452.9	221.8	669.6	321.9
Other comprehensive income (items that may be reclassified subsequently to the income statement)
Currency translation differences		42.1	57.8	13.0	99.9	(85.1)
Net gain/(loss) on options used for hedging		4.0	(1.6)	(5.3)	2.3	(10.0)
Other comprehensive income for the period, net of tax		46.1	56.2	7.7	102.3	(95.0)
Total comprehensive income		262.9	509.0	229.5	771.8	226.9
Earnings per share
EPS basic and diluted	17	0.08	0.18	0.08	0.26	0.12

Unaudited consolidated balance sheet statement

USD million	Note	30 Jun 2025	31 Mar 2025	31 Dec 2024	30 Jun 2024
ASSETS
Non-current assets
Intangible assets
Goodwill	9	3 322.7	3 246.7	2 987.8	3 328.2
Capitalised exploration wells	9	482.1	457.2	404.9	345.6
Other intangible assets	9	154.9	255.4	241.9	262.7
Tangible fixed assets
Property, plant and equipment	10	19 950.7	18 143.5	16 737.1	16 876.7
Right of use assets	11	303.4	295.5	198.1	32.5
Financial assets
Investment in shares		1.1	0.7	0.7	0.8
Other non-current assets		43.4	38.2	30.8	12.1
Total non-current assets		24 258.3	22 437.0	20 601.3	20 858.5
Current assets
Inventories		280.5	272.3	241.4	240.8
Trade receivables	13 , 24	462.3	242.1	373.2	443.4
Other current receivables and financial assets	14	504.8	536.4	373.4	385.2
Cash and cash equivalents	16	717.6	661.2	278.9	314.8
Total current assets		1 965.3	1 711.9	1 266.8	1 384.2
TOTAL ASSETS		26 223.5	24 149.0	21 868.2	22 242.7

USD million	Note	30 Jun 2025	31 Mar 2025	31 Dec 2024	30 Jun 2024
EQUITY AND LIABILITIES
Equity
Share capital	17	46.0	46.0	46.0	46.0
Share premium		-	-	-	218.2
Hybrid capital	18	799.5	799.5	799.5	799.5
Other equity		126.8	163.4	(12.9)	372.3
Total equity		972.3	1 008.8	832.5	1 435.9
Non-current liabilities
Interest-bearing loans and borrowings	19	5 832.1	5 198.7	5 082.2	4 588.8
Deferred tax liabilities	8	12 362.2	11 286.1	10 500.9	10 342.9
Asset retirement obligations	20	3 796.9	3 512.7	3 283.7	3 332.4
Pension liabilities		11.1	21.0	15.5	23.8
Lease liabilities, non-current	23	175.1	174.7	141.5	53.1
Other non-current liabilities		440.1	405.0	115.0	119.0
Total non-current liabilities		22 617.5	20 598.2	19 138.8	18 460.0
Current liabilities
Asset retirement obligations, current	20	123.0	104.7	105.2	80.6
Accounts payables	24	442.6	392.9	356.1	370.3
Taxes payable	8	1 182.6	1 178.3	681.7	1 175.6
Interest-bearing loans, current	19	76.3	71.7	54.7	53.9
Lease liabilities, current	23	126.0	124.7	70.4	21.3
Other current liabilities	21	683.3	669.7	628.8	645.1
Total current liabilities		2 633.7	2 542.0	1 896.8	2 346.8
Total liabilities		25 251.2	23 140.2	21 035.7	20 806.8
TOTAL EQUITY AND LIABILITIES		26 223.5	24 149.0	21 868.2	22 242.7

Unaudited consolidated statement of changes in equity

				Other equity
					Translation
USD million	Share capital	Share premium	Hybrid Capital	Other equity	differences	Hedge reserve	Total equity
Balance as of 1 January 2024	46.0	758.2	799.5	622.6	(443.5)	(14.7)	1 768.0
Profit/(loss) for the period	-	-	15.6	306.3	-	-	321.9
Other comprehensive income/(loss)	-	-	-	-	(85.1)	(10.0)	(95.0)
Total comprehensive income/(loss)	-	-	-	306.3	(85.1)	(10.0)	226.9
Dividends paid	-	(540.0)	(15.6)	-	-	-	(555.6)
Share-based payment	-	-	-	(3.4)	-	-	(3.4)
Other	-	-	-	(10.9)	-	10.9	-
Balance as of 30 June 2024	46.0	218.2	799.5	914.7	(528.5)	(13.8)	1 435.9
Balance as of 1 July 2024	46.0	218.2	799.5	914.7	(528.5)	(13.8)	1 435.9
Profit/(loss) for the period	-	-	-	5.2	-	-	5.2
Other comprehensive income/(loss)	-	-	-	0.4	(74.6)	1.7	(72.4)
Total comprehensive income/(loss)	-	-	-	5.6	(74.6)	1.7	(67.2)
Dividends paid	-	(218.2)	-	(321.8)	-	-	(540.0)
Share-based payments	-	-	-	3.8	-	-	3.8
Other	-	-	-	(0.5)	-	0.5	-
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	608.3	-	-	669.6
Other comprehensive income/(loss)	-	-	-	-	99.9	2.3	102.2
Total comprehensive income/(loss)	-	-	61.3	608.3	99.9	2.3	771.8
Dividends paid	-	-	(61.3)	(570.0)	-	-	(631.3)
Share-based payments	-	-	-	(0.8)	-	-	(0.8)
Other	-	-	-	0.0	-	-	0.0
Balance as of 30 June 2025	46.0	-	799.5	639.3	(503.2)	(9.2)	972.3

Unaudited consolidated statement of cash flows

USD million	Notes	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Cash flow from operating activities
Profit / (loss) before income taxes		1 234.4	1 278.6	1 031.9	2 513.0	1 881.9
Adjustments to reconcile profit before tax to net cash flows:
- Depreciation and amortisation	10 , 11	587.2	458.3	497.9	1 045.4	1 000.4
- Impairment loss/(reversal)	9 , 10	(440.8)	23.9	-	(416.9)	-
- (Gain) / loss on sale and retirement of assets	5	1.1	5.3	0.1	6.4	0.2
- Expensed capitalised dry wells	6 , 9	57.1	51.9	35.8	108.9	54.2
- Accretion expenses (asset retirement obligation)	7 , 20	36.7	32.8	29.5	69.5	57.8
- Unrealised (gain) / loss on foreign currency transactions and balances	7	(51.4)	(351.8)	(68.5)	(403.2)	117.7
- Realised foreign exchange (gain) / loss related to financing activities		(32.6)	(20.7)	1.8	(53.4)	3.3
- Other non-cash items and reclassifications		(3.5)	7.7	29.2	4.3	(88.4)
Working capital adjustments:
- Changes in inventories, accounts payable and receivables		(178.9)	154.7	46.8	(24.2)	95.0
- Changes in other current balance sheet items	14 , 21	60.6	(105.2)	64.1	(44.6)	23.6
Income taxes paid	8	(504.3)	(213.0)	(957.9)	(717.3)	(1 425.9)
Net cash flow from operating activities		765.7	1 322.4	710.7	2 087.9	1 719.8
Cash flow from investing activities
Expenditures on exploration and evaluation assets	9	(71.1)	(72.5)	(85.1)	(143.7)	(135.4)
Expenditures on property, plant and equipment	10	(690.2)	(522.7)	(687.5)	(1 212.9)	(1 331.2)
Payment for decommissioning of oil and gas fields	20	(19.9)	(31.2)	(11.3)	(51.1)	(25.1)
Proceeds from sale of assets (sales price)		-	0.0	-	-	-
Net cash used on business combination	2	-	-	0.0	-	(1 330.7)
Net cash flow from investing activities		(781.3)	(626.4)	(783.9)	(1 407.7)	(2 822.4)

Unaudited consolidated statement of cash flows - continued

USD million	Note	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Cash flow from financing activities
Dividends paid		(300.0)	(270.0)	(270.0)	(570.0)	(540.0)
Dividends distributed to hybrid owners	18	-	(61.3)	-	(61.3)	(15.6)
Net proceeds from bond issue	15 , 19	1 500.0	1 088.6	-	2 588.6	-
Net proceeds/(payments) of revolving credit facilities	15 , 19	(995.0)	(989.1)	75.0	(1 984.1)	1 475.0
Payment of principal portion of lease liability	23	(32.1)	(26.7)	(24.6)	(58.7)	(49.1)
Interest paid		(116.6)	(90.4)	(106.9)	(207.0)	(162.5)
Net cash flow from financing activities		56.3	(348.9)	(326.5)	(292.5)	707.8
Net change in cash and cash equivalents		40.7	347.1	(399.8)	387.7	(394.8)
Cash and cash equivalents, beginning of period		661.2	278.9	721.6	278.9	734.9
Effect of exchange rate fluctuation on cash		15.8	35.2	(7.1)	51.0	(25.3)
Cash and cash equivalents, end of period		717.7	661.2	314.8	717.6	314.8

Notes

(All figures in USD million unless otherwise stated)

The unaudited interim condensed consolidated financial statements for the period ended 30 June 2025 have been prepared in accordance with IAS 34 Interim Financial Reporting. Thus, the interim financial statements do not include all information required by IFRSs 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 21 July 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. 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").

2. 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	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Revenue from crude oil sales		1 169.6	1 135.7	1 281.8	2 305.2	2 503.7
Revenue from gas sales		606.7	658.8	558.0	1 265.4	1 169.5
Revenue from NGL sales		51.4	38.7	91.4	90.1	201.8
Gains from hedging	14	-	-	2.1	-	7.2
Total petroleum revenues		1 827.7	1 833.1	1 933.3	3 660.7	3 882.1
Sales of crude (boe million)		17.1	15.0	15.1	32.1	29.6
Sales of gas (boe million)		7.7	8.0	7.9	15.8	17.1
Sales of NGL (boe million)		1.2	0.7	2.1	1.9	4.3
Other operating income (USD million)		Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Gain/(loss) from sale of assets		0.0	0.0	1.3	0.0	3.0
Partner share of lease cost		11.0	11.0	3.2	22.0	6.4
Other operating income		10.4	27.3	2.3	37.6	4.2
Total other operating income		21.4	38.2	6.8	59.6	13.6

Note 4 Production Costs

USD million	Note	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Cost of operations		222.5	176.0	214.9	398.5	420.9
Transportation and processing		56.7	53.3	61.2	110.0	127.7
Environmental taxes		39.7	41.3	32.6	81.0	70.2
Insurance premium		14.8	14.0	16.0	28.8	31.5
Production cost based on produced volumes		333.7	284.5	324.7	618.3	650.2
Back-up cost shuttle tankers		16.0	(4.6)	4.2	11.4	5.1
Changes in over/(underlift)		40.0	17.0	8.9	57.0	54.0
Premium expense for crude put options	15	5.5	7.8	8.6	13.3	18.9
Production cost based on sold volumes		395.3	304.7	346.4	700.0	728.2
Total produced volumes (boe million)		26.2	24.5	26.1	50.7	53.3
Production cost per boe produced (USD/boe)		12.7	11.6	12.4	12.2	12.2

Note 5 Other operating expenses

USD million	Note	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
R&D expenses		8.8	7.5	11.0	16.2	18.2
Pre-production costs		14.0	18.0	12.6	32.0	24.4
Guarantee fee decommissioning obligation		4.1	4.3	4.2	8.4	9.5
Administration expenses		8.5	10.9	8.0	19.5	18.4
Legal provisions		4.6	-	-	4.6	-
Integration cost		-	-	6.0	-	14.3
Value adjustment contingent considerations	22	-	-	-	-	(59.0)
Other expenses		3.1	2.1	6.3	5.2	6.4
Total other operating expenses		43.1	42.9	48.0	85.9	32.3

Note 6 Exploration expenses

USD million	Note	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Seismic		2.5	5.2	12.7	7.6	19.3
Area fee		4.4	3.9	2.0	8.4	5.0
Dry well expenses	9	57.1	51.9	35.8	108.9	54.2
Other exploration expenses		5.7	8.3	5.3	14.0	10.6
Total exploration expenses		69.7	69.3	55.8	139.0	89.0

Dry well expenses in the second quarter of 2025 are associated with exploration wells in PL 1005 (Rondeslottet), PL 169 (Lit and Svalin M Sør), PL 532 (Skred), PL 554 (Garantiana NW) and PL 1194 (Hoffmann).

Note 7 Financial items

USD million	Note	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Interest income		7.3	4.6	4.2	11.9	14.9
Interests on debts and borrowings	19	(87.1)	(81.9)	(87.5)	(169.0)	(165.0)
Interest on lease debt		(3.9)	(3.9)	(1.1)	(7.8)	(2.4)
Capitalised interest cost, development projects		92.2	86.0	89.8	178.2	169.7
Amortisation of fees and expenses		(3.5)	(2.4)	(2.2)	(5.9)	(4.4)
Accretion expenses (asset retirement obligation)	20	(36.7)	(32.8)	(29.5)	(69.5)	(57.8)
Other financial expenses		(2.9)	(2.3)	(1.5)	(5.2)	(2.1)
Change in fair value of hedges (ineffectiveness)	15	(3.2)	(0.0)	2.1	(3.3)	2.9
Net financial income/(expenses)		(37.9)	(32.7)	(25.7)	(70.6)	(44.4)
Unrealised exchange rate gain/(loss)		51.4	351.8	68.5	403.2	(117.7)
Realised exchange rate gain/(loss)		26.3	(12.9)	(3.0)	13.4	(1.9)
Net exchange rate gain/(loss)		77.7	338.9	65.4	416.6	(119.5)
Net financial items		39.8	306.2	39.7	346.0	(164.0)

Vår Energi's functional currency is NOK, whilst interest bearing loans and bonds are in USD and EUR. The strengthening of NOK during the second quarter of 2025 resulted in net exchange gain of USD 78 million.

Note 8 Income taxes

USD million	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Current period tax payable/(receivable)	422.5	644.0	502.6	1 066.5	1 005.3
Prior period adjustment to current tax	32.3	(7.3)	0.6	25.0	0.5
Current tax expense/(income)	454.8	636.7	503.2	1 091.5	1 005.8
Change in current year deferred tax	594.9	189.0	306.9	784.0	554.1
Prior period adjustments to deferred tax	(32.1)	-	-	(32.1)	-
Deferred tax expense/(income)	562.9	189.0	306.9	751.9	554.1
Tax expense/(income) in profit and loss	1 017.7	825.7	810.0	1 843.4	1 559.9
Effective tax rate in %	82%	65%	79%	73%	83%
Tax expense/(income) in put option used for hedging and pension	1.2	(0.2)	(1.7)	1.0	(3.0)
Tax expense/(income) in other comprehensive income	1 018.8	825.5	808.4	1 844.4	1 557.0

Reconciliation of tax expense	Tax rate	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Marginal (78%) tax rate on profit/loss before tax	78%	962.9	997.3	804.9	1 960.2	1 467.9
Tax effect of uplift	71,8%	(3.9)	(4.4)	(6.9)	(8.3)	(12.4)
Impairment of goodwill	78%	55.1	20.4	-	75.5	-
Tax effects of items taxed at other than marginal (78%) tax rate1	56%	3.2	(163.7)	19.4	(160.5)	163.1
Other permanent differences, prior period adjustments and change in estimates of uncertain tax positions	78%	0.4	(23.9)	(7.3)	(23.5)	(58.7)
Tax expense/(income)		1 017.7	825.7	810.0	1 843.4	1 559.9

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.

Note 8 Income taxes - continued

Deferred tax asset/(liability)	Note	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Deferred tax asset/(liability) at beginning of period		(11 286.1)	(10 500.9)	(9 890.5)	(10 500.9)	(8 943.0)
Change in current year deferred tax		(594.9)	(189.0)	(306.9)	(784.0)	(554.1)
Prior period adjustments		32.1	-	-	32.1	-
Deferred taxes on business combinations2	2	-	209.6	-	209.6	(1 304.2)
Deferred taxes recognised directly in OCI or equity		(1.2)	0.2	1.7	(1.0)	3.0
Currency translation effects		(512.1)	(805.9)	(147.2)	(1 318.0)	455.5
Net deferred tax asset/(liability) as of closing balance		(12 362.2)	(11 286.1)	(10 342.9)	(12 362.2)	(10 342.9)

Tax payable	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Tax payable at beginning of period	(1 178.3)	(681.7)	(1 606.5)	(681.7)	(964.4)
Current period payable taxes	(422.5)	(644.0)	(502.6)	(1 066.5)	(1 005.3)
Payable taxes related to business combinations 2	-	-	-	-	(705.9)
Net tax payments	504.3	213.0	957.9	717.3	1 425.9
Prior period adjustments and change in estimate of uncertain tax positions	(32.3)	7.3	(0.6)	(25.0)	(0.5)
Currency translation effects	(53.8)	(73.0)	(23.8)	(126.7)	74.6
Net tax payable as of closing balance	(1 182.6)	(1 178.3)	(1 175.6)	(1 182.6)	(1 175.6)

2Acquisition of Neptune Energy Norge in Q1 2024.

Note 9 Intangible assets

USD million	Note	Goodwill	Other intangible assets	Capitalised exploration wells	Total	USD million	Note	Goodwill	Other intangible assets	Capitalised exploration wells	Total
Cost as of 1 January 2025		5 249.5	242.8	404.9	5 897.1	Cost as of 1 April 2025		5 704.1	256.5	457.2	6 417.7
Additions		-	-	72.5	72.5	Additions		-	-	71.1	71.1
Additions through business combination	2	66.4	-	-	66.4	Additions through business combination	2	-	-	-	-
Reclassification		-	(1.6)	(1.8)	(3.4)	Reclassification		-	(111.8)	(10.3)	(122.1)
Expensed exploration wells	6	-	-	(51.9)	(51.9)	Expensed exploration wells	6	-	-	(57.1)	(57.1)
Disposals		(2.2)	(3.0)	-	(5.3)	Disposals		-	(0.5)	-	(0.5)
Currency translation effects		390.5	18.4	33.5	442.3	Currency translation effects		257.1	12.0	21.2	290.3
Cost as of 31 March 2025		5 704.1	256.5	457.2	6 417.7	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 and impairment as of 1 April 2025		(2 457.4)	(1.1)	-	(2 458.5)
Depreciation		-	(0.1)	-	(0.1)	Depreciation		-	-	-	-
Impairment reversal/(loss)		(23.9)	-	-	(23.9)	Impairment reversal/(loss)	12	(70.7)	-	-	(70.7)
Currency translation effects		(171.9)	(0.1)	-	(171.9)	Currency translation effects		(110.5)	(0.1)	-	(110.5)
Depreciation and impairment as of 31 March 2025		(2 457.4)	(1.1)	-	(2 458.5)	Depreciation and impairment as of 30 June 2025		(2 638.5)	(1.2)	-	(2 639.7)
Net book value as of 31 March 2025		3 246.7	255.4	457.2	3 959.2	Net book value as of 30 June 2025		3 322.7	154.9	482.1	3 959.7

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

Note 10 Tangible assets

Net book value as of 31 March 2025		12 313.0	5 765.6	65.0	18 143.5
Depreciation and impairment as of 31 Dec 2024		(8 881.2)	(41.9)	(67.0)	(8 990.1)
Currency translation effects		(615.1)	(3.0)	(4.6)	(622.6)
Impairment reversal / (loss)	12	-	-	-	-
Depreciation		(437.4)	-	(6.3)	(443.6)
Depreciation and impairment as of 1 January 2025		(7 828.7)	(38.9)	(56.2)	(7 923.9)
Cost as of 31 March 2025		21 194.2	5 807.5	132.0	27 133.6
Currency translation effects		1 352.1	551.6	9.0	1 912.7
Disposals		-	-	-	-
Reclassification		2 662.6	(2 641.5)	-	21.1
Additions through business combinations	2	(39.0)	-	-	(39.0)
Estimate change asset retirement cost	20	(30.9)	-	-	(30.9)
Additions		148.1	451.7	8.9	608.7
Cost as of 1 January 2025		17 101.3	7 445.6	114.1	24 661.0
USD million	Note	Wells and production facilities	Facilities under construction	Other property, plant and equipment	Total

				Other
		Wells and production	Facilities under	property, plant and
USD million	Note	facilities	construction	equipment	Total
Cost as of 1 April 2025		21 194.2	5 807.5	132.0	27 133.6
Additions		347.7	428.7	6.0	782.4
Estimate change asset retirement cost	20	122.1	-	-	122.1
Additions through business combinations	2	-	-	-	-
Reclassification		3 934.6	(3 791.7)	-	142.9
Disposals		-	-	(0.6)	(0.6)
Currency translation effects		937.9	296.1	6.0	1 240.0
Cost as of 30 June 2025		26 536.5	2 740.5	143.3	29 420.4
Depreciation and impairment as of 1 April 2025		(8 881.2)	(41.9)	(67.0)	(8 990.1)
Depreciation		(565.8)	-	(7.3)	(573.1)
Impairment reversal / (loss)	12	467.5	44.0	-	511.5
Currency translation effects		(412.8)	(2.1)	(3.2)	(418.1)
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

Capitalised interests for facilities under construction were USD 92 million in the second quarter 2025 compared to USD 86 million in the first quarter 2025.

Rate used for capitalisation of interests was 6.45% in the second quarter 2025, compared to 6.39% in the first quarter 2025.

Note 11 Right of use assets

		Rigs, helicopters
		and supply
USD million	Offices	vessels	Warehouse	Total
Cost as at 1 January 2025	73.5	247.4	18.7	339.6
Additions	-	107.9	0.0	107.9
Reclassification	-	(17.7)	(0.0)	(17.7)
Currency translation effects	5.9	25.2	2.0	33.1
Cost as at 31 March 2025	79.4	362.9	20.7	463.0
Depreciation and impairment as at 1 January 2025	(26.0)	(102.8)	(12.7)	(141.5)
Depreciation	(1.7)	(12.4)	(0.4)	(14.5)
Currency translation effects	(2.4)	(7.5)	(1.6)	(11.5)
Depreciation and impairment as at 31 March 2025	(30.1)	(122.7)	(14.7)	(167.5)
Net book value as at 31 March 2025	49.3	240.2	6.0	295.5
Cost as at 1 April 2025	79.4	362.9	20.7	463.0
Additions	2.1	28.0		30.1
Reclassification		(20.7)	- -	(20.7)
Currency translation effects	- 3.7	15.4	1.0	20.1
Cost as at 30 June 2025	85.2	385.6	21.7	492.5
Depreciation and impairment as at 1 April 2025	(30.1)	(122.7)	(14.7)	(167.5)
Depreciation	(1.9)	(11.7)	(0.5)	(14.1)
Currency translation effects	(1.4)	(5.4)	(0.7)	(7.5)
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

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 June 2025.

Key assumptions applied for impairment testing purposes as of 30 June 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 31 March 2025.

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

Year	31 Dec 2024	31 Mar 2025	30 Jun 2025
2025	74.0	72.7	66.8
2026	74.5	72.9	68.9
2027	78.5	77.3	75.1

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

Year	31 Dec 2024	31 Mar 2025	30 Jun 2025
2025	83.1	75.2	67.9
2026	65.6	61.7	65.0
2027	59.1	55.7	58.8

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	31 Mar 2025	30 Jun 2025
2025 - 2029	611	585	565
2030 - 2034	311	316	323
2035 - 2039	160	162	166
2040 - 2060	132	134	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. 31 March 2025.

Currency rates	2025	2026	2027	2028 onwards
NOK/USD	10.1	10.0	10.0	10.0
NOK/Euro	11.8	11.6	11.2	10.7

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

Inflation

Inflation for 2025 is assumed to be 3% and then 2% in future years. Unchanged vs. assumptions per 31 March 2025.

Impairments charge/reversal

The impairment testing as of 30 June 2025 identified an impairment reversal for Balder CGU of USD 511.4 million, largely attributed to additional reserves from new planned infill wells and updated profiles. Goodwill impairment for Njord, Gjøa, and Snøhvit was recorded at USD 70.6 million, mainly resulting from lower shortterm commodity prices.

Cash generating unit (USD million)	Net carrying calue	Recoverable amount	Impairment / reversal (-)	Goodwill	PP&E	Deferred tax impact
Balder area	1 561.4	1 673.9	(511.4)	-	(511.4)	399.0
Njord area	660.7	621.3	39.4	39.4	-	-
Gjøa area	184.6	164.6	20.0	20.0	-	-
Snøhvit	652.7	641.5	11.2	11.2	-	-
Total			(440.8)	70.6	(511.4)	399.0

Impairment allocated

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%	(311)	4 096
Production profile	+/- 5%	(302)	661
Discount rate	+/- 1% point	372	(86)

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 Jun 2025	31 Mar 2025	31 Dec 2024	30 Jun 2024
Trade receivables - related parties	24	508.4	422.3	448.9	508.9
Trade receivables - external parties		180.9	153.2	181.7	184.9
Sale of trade receivables		(227.0)	(333.4)	(257.4)	(250.4)
Total trade receivables		462.3	242.1	373.2	443.4

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 Jun 2025	31 Mar 2025	31 Dec 2024	30 Jun 2024
Net underlift of hydrocarbons		247.9	278.6	223.1	186.7
Net receivables from joint operations		170.2	158.6	121.1	108.9
Prepaid expenses		78.6	93.4	16.8	71.7
Commodity derivatives - financial assets	15	6.7	7.2	17.2	16.3
Other receivables		1.5	(1.5)	(4.8)	1.7
Total other current receivables and financial assets		504.8	536.4	373.4	385.2

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 June 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 30.06.2025, exercisable in 2025	12.9	50
Hedging instruments	Volume (no of options outstanding at balance sheet date) in million (MWH)	Excercise price (EUR per MWH)
Gas TTF long put options 30.06.2025, exercisable in 2025	0.1	25
Gas TTF short call options 30.06.2025, exercisable in 2025	-0.1	100

Brent crude put options – financial assets

.

USD million	Note	Q2 2025	Q1 2025	2024
The beginning of the period		7.2	17.2	11.0
Additions through business combinations		-	-	25.2
New derivatives		-	-	31.9
Realised hedges exercised	3	-	-	(9.2)
Change in fair value realised		(2.4)	(0.4)	(21.5)
hedges Change in fair value unrealised hedges		1.9	(9.6)	(20.2)
The end of the period		6.7	7.2	17.2

Note 15 Financial instruments - continued

As of 30 June 2025, the fair value of outstanding commodity derivatives assets is USD 6.7 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	Q2 2025	Q1 2025	2024
The beginning of the period		(24.1)	(31.9)	(29.8)
Additions through business combinations		-	-	(2.6)
Settlement	4	5.5	7.8	32.5
New Brent crude put options		-	-	(31.9)
FX-effect		0.0	0.0	(0.1)
The end of the period		(18.6)	(24.1)	(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	Q2 2025	Q1 2025	2024
The beginning of the period		(0.0)	(0.1)	-
Additions through business combinations Realised hedges exercised	3	- -	- -	(8.0) 1.4
Change in fair value realised		0.0	0.0	3.6
hedges Change in fair value unrealised hedges		(0.0)	0.1	2.9
The end of the period		(0.0)	(0.0)	(0.1)

As of 30 June 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

Note	Q2 2025	Q1 2025	2024
	16.9	14.8	18.8
	-	-	(14.6)
3	-	-	7.8
	(3.2)	(7.4)	(14.5)
7	-	-	(0.0)
	(1.9)	9.5	17.3
	11.8	16.9	14.8

After tax balance as of 30 June 2025 is USD 9.3 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 Jun 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	-	- 163.3	- 5.1	1 897.6
Subord. EUR Fixed Rate	808.5	-	0.4	1.2		810.1
Prepaid loan expenses	(37.5)	(43.3)	5.8	(1.1)	-	(76.1)
Accrued interests	54.7	(44.0)	65.6		-	76.3
Totals including hybrid	5 936.4	517.1	71.8	- 177.5	- 5.1	6 707.8

Note 16 Cash and cash equivalents

USD million	30 Jun 2025	31 Mar 2025	31 Dec 2024	30 Jun 2024
Bank deposits, unrestricted	699.7	633.3	266.6	306.4
Bank deposit, restricted, employee taxes	17.8	27.9	12.3	8.4
Total bank deposits	717.6	661.2	278.9	314.8

Note 17 Share capital and shareholders

As of 30 June 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	Q2 2025	Q1 2025	Q2 2024	YTD 2025	YTD 2024
Profit (loss) attributable to ordinary equity holders	216.7	452.9	221.8	669.6	321.9
EPS adj. for calc. interest/dividend on hybrid capital *	(16.7)	(15.3)	(13.7)	(32.0)	(29.6)
Number of shares (in millions)	2 496	2 496	2 496	2 496	2 496
Earnings per share in USD basic and diluted	0.08	0.18	0.08	0.26	0.12

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 Dec 2024	799.5	9.0	808.5
Profit/loss allocated to Hybrid owners	61.3	-	61.3
Non-cash changes	-	1.6	1.6
Interest classified as dividend	(61.3)	-	(61.3)
Balance as of 30 Jun 2025	799.5	10.6	810.1

Note 19 Financial liabilities and borrowings

Interest-bearing loans and borrowings

USD million	Coupon/int. Rate	Maturity	30 Jun 2025	31 Mar 2025	31 Dec 2024	30 Jun 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	-	-	-
Bond USD Senior Notes (25/35)	6.50%	05-2035	750.0	-	-	-
Bond EUR Senior Notes (23/29)	5.50%	05-2029	725.6	664.4	640.7	645.1
Bond EUR Senior Notes (25/31)	3.875 %	03-2031	1 172.0	1 081.5	-	-
Subord.EUR Fixed Rate Sec(23/83)	7.862 %	11-2083	10.6	9.6	9.0	9.0
RCF Working capital facility	1.08%+SOFR+CAS	05-2025	-	975.0	1 475.0	1 475.0
RCF Liquidity facility	1.13%+SOFR+CAS	05-2025	-	20.0	495.0	-
RCF Working capital facility	1.00%+SOFR +CAS	05-2028	-	-	-	-
RCF Liquidity facility	0.95%+SOFR +CAS	05-2030	-	-	-	-
Prepaid loan expenses			(76.1)	(51.9)	(37.5)	(40.3)
Accrued interests			76.3	71.7	54.7	53.9
Total interest-bearing loans and borrowings			5 908.4	5 270.4	5 136.9	4 642.7
Of which current and non-current:
Interest-bearing loans, current			76.3	71.7	54.7	53.9
Interest-bearing loans and borrowings non-current			5 832.1	5 198.7	5 082.2	4 588.8
Bond EUR Senior Notes (23/29): Fair value of hedge related to EUR
senior notes Hedge inefficiency related to EUR			21.2	17.4	19.1	3.3
senior notes			1.3	(1.9)	(1.8)	(0.4)
Bond EUR Senior Notes net including FV hedge			703.2	648.9	623.3	642.3
Credit facilities - Utilised and unused amount
USD million			30 Jun 2025	31 Mar 2025	31 Dec 2024	30 Jun 2024
Drawn amount credit facility			-	995.0	1 970.0	1 475.0

Undrawn amount credit facilities 2 750.0 2 005.0 1 030.0 1 525.0

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 June was USD 6 176 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	Q2 2025	Q1 2025	2024
Beginning of period		3 617.4	3 388.9	3 295.1
Additions through business combinations	2	-	-	371.5
Change in estimate	10	11.1	57.9	373.2
Change in discount rate	10	111.4	(88.7)	(204.2)
Accretion discount	7	36.7	32.8	115.7
Payment for decommissioning of oil and gas fields		(19.9)	(31.2)	(66.8)
Disposals		-	-	(103.8)
Currency translation effects		163.2	257.8	(391.7)
Total asset retirement obligations		3 919.9	3 617.4	3 388.9
Short-term		123.0	104.7	105.2
Long-term		3 796.9	3 512.7	3 283.7
Breakdown by decommissioning period		30 Jun 2025	30 Mar 2025	31 Dec 2024
2024-2030		235.1	209.1	216.5
2031-2040		2 230.1	2 083.9	1 949.2
2041-2061		1 454.7	1 324.4	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 and 2% in future years and discount rates between 3.5% - 3.8% per 30 June 2025. The assumptions for inflation rates were unchanged while the discount rates were decreased from 3.8% - 4.1% per 31 March 2025. The discount rates are based on risk-free interest without addition of credit margin.

Second quarter 2025 payment for decommissioning of oil and gas fields (abex) is mainly related to Statfjord, Ekofisk, Goliat 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 92.4 million for this purpose per 30 June 2025, compared to USD 86.5 million per 31 March 2025..

Note 21 Other current liabilities

USD million	Note	30 Jun 2025	31 Mar 2025	31 Dec 2024	30 Jun 2024
Net overlift from hydrocarbons		216.2	230.4	162.5	136.7
Net payables to joint operations		408.4	327.5	365.5	425.1
Employee payables and accrued public charges		21.7	68.3	47.5	20.5
Contingent Consideration, current		-	-	-	22.2
Commodity derivaties	15	18.6	24.1	31.9	33.9
Other payables		18.4	19.5	21.4	6.7
Total other current liabilities		683.3	669.7	628.8	645.1

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. The deadline for an appeal to the Supreme Court is 21 August 2025.

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 has appealed to the Borgarting Court of Appeal. The appeal will be heard in September 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.

Note 23 Lease agreements

USD million	Note	Q2 2025	Q1 2025	2024
Opening Balance lease debt		299.4	211.9	116.9
New lease debt in period		30.1	107.9	178.3
Additions through business combinations	2	-	-	10.5
Payments of lease debt		(32.1)	(26.7)	(83.3)
Lease debt derecognised in the period			-	1.0
Interest expense on lease debt		- 3.9	3.9	5.4
Currency exchange differences		(0.2)	2.3	(17.0)
Total lease debt		301.1	299.4	211.9
Breakdown		30 Jun 2025	31 Mar 2025	31 Dec 2024
Short-term		126.0	124.7	70.4
Long-term		175.1	174.7	141.5
Total lease debt		301.1	299.4	211.9
Lease debt split by activities		30 Jun 2025	31 Mar 2025	31 Dec 2024
Offices		61.3	58.3	55.7
Rigs, helicopters and supply vessels		233.7	234.7	149.9
Warehouse		6.1	6.3	6.3
Total		301.1	299.4	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 second quarter 2025 one new lease of parking spaces has been included in lease debt. In addition, the rig COSL Prospector has been updated to include 6 additional months of the optional period. 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 Jun 2025	31 Mar 2025	31 Dec 2024	30 Jun 2024
Trade receivables
Eni Trade & Biofuels SpA	485.7	341.9	376.6	430.8
Eni SpA	22.0	79.8	71.7	69.5
Eni Global Energy Markets	-	-	-	6.9
Other	0.8	0.6	0.6	1.8
Total trade receivables	508.4	422.3	448.9	508.9

Current liabilities
USD million	30 Jun 2025	31 Mar 2025	31 Dec 2024	30 Jun 2024
Account payables
Eni Trade & Biofuels SpA	20.7	13.9	21.3	7.7
Eni SpA	1.2	2.6	10.4	7.8
Eni International BV	8.8	4.4	17.1	8.5
Other	0.4	0.9	0.8	0.5
Total account payables	31.1	21.8	49.6	24.6

All receivables are due within 1 year.

Sales revenue USD million Q2 2025 Q1 2025 Q2 2024 1H 2025 1H 2024 Eni Trade & Biofuels SpA 1 139.4 1 169.4 1 351.1 2 308.8 2 524.6 Eni SpA 197.8 235.9 196.9 433.7 391.3 Eni Global Energy Markets 0.3 - 14.7 0.3 36.9 Other - - - - - Total 1 337.5 1 405.4 1 562.7 2 742.8 2 952.8

Operating and capital expenditures
USD million	Q2 2025	Q1 2025	Q2 2024	1H 2025	1H 2024
Eni Trade & Biofuels SpA	16.3	(3.5)	4.8	12.7	10.3
Eni SpA	1.7	(1.4)	1.8	0.3	7.9
Eni International BV	4.1	4.3	4.2	8.4	9.5
Other	0.1	0.5	2.0	0.6	2.5
Total	22.2	(0.2)	12.8	22.0	30.1

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

Note 26 Subsequent events

Vår Energi has elected to sell part of its gas on a fixed price/forward basis. Per 30 June 2025 Vår Energi has sold approximately 18% of the gas production for the third quarter in 2025 at around USD 90 pr boe.

The exploration wells Skred (PL532), Garantiana NW(PL554) and Hoffmann (PL1194) have been finalized and concluded dry in July 2025. In the financial statement per 30 June 2025 USD 25.7 million related to these wells has been expensed.

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 June 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.'

Vår Energi – Second quarter report 2025 ABOUT VÅR ENERGI HIGHLIGHTS KEY METRICS AND TARGETS OPERATIONAL REVIEW FINANCIAL REVIEW FINANCIAL STATEMENTS NOTES