Third quarter 2022

Interim report

About Vår Energi	About Vår Energi	2
	Key figures	3
Vår Energi is a leading independent upstream oil and gas Company on the Norwegian continental shelf
(NCS). The Company is founded on more than 50 years of NCS operations, a robust and diversified asset portfolio with ongoing development projects centred around hubs, and a strong exploration track record.	Highlights	4
In the first nine months of 2022, Vår Energi produced net 222 kboepd of oil and gas from 36 fields.	Key metrics and targets	5
The Company has a target to increase production to 350 kboepd by end-2025 while reducing production cost to USD 8 per boe from
approximately USD 13 in the first nine months of 2022 as new projects come on stream and effects from improvement measures	Operational review	6
are achieved. Material cash flow generation and an investment-grade balance sheet enable attractive and resilient dividend	Projects and developments	10
distributions. For 2022, Vår Energi guides for a dividend of 1 075 million. From 2023 and onwards, the Company plans to distribute	Exploration	12
20–30% of cash flow from operations after tax (CFFO).	HSSE	13
	Decarbonisation and environmental impact	14
On 16 February 2022, Vår Energi listed on Oslo Stock Exchange (OSE) under the ticker "VAR". The initial public offering (IPO) provides
access to Norwegian and international capital markets, a diversification of the Company's ownership structure and supports
employee participation.	Financial review	15
	Outlook	23
Vår Energi is committed to delivering a better future. The Company's ambition is to be the safest operator on the NCS, the partner of	Transactions with related parties	23
choice, an ESG leader and a net-zero producer (scope 1 and 2) by 2030.	Subsequent events	23
	Risks and risk management	23
To learn more, please visit: www.varenergi.no.	Alternative Performance Measures	24
	Financial statements	26
	Notes	33

Key figures third quarter

Second quarter 2022 in brackets

Vår Energi – Third quarter report 2022

Production kboepd

215 (210)

Petroleum revenues USD million

EBIT USD million

1 454 (1 674)

Profit before tax USD million

1 161 (1 214)

CFFO USD million

(573)

FCF USD million

(962)

NIBD / EBITDAX x 0.2 (0.4)

Third quarter 2022 highlights

Vår Energi reported USD 2 526 million in total income for the third quarter of 2022, EBIT was USD 1 454 million and cash flow from operations (CFFO) was USD 1 503 million in the quarter.

The Company expects to distribute 1 075 million in dividend for 2022 under current market conditions, paid on a quarterly basis. A dividend of USD 260 million (NOK 1.025 per share) for the second quarter was paid in August and USD 290 million (NOK 1.225 per share) for the third quarter will be distributed in November. The company further plans to distribute a dividend of USD 300 million (NOK ~1.27 per share) for the fourth quarter.

Safe operations, no serious incidents in the quarter
Production of 215 kboepd, an increase from 210 kboepd in the second quarter mainly due to reduced maintenance and turnaround activity on partner-operated fields
Full year 2022 production guidance revised to 220-225 kboepd
Average weighted realised price of USD 139 per boe in the quarter (oil USD 108 per boe, gas USD 204 per boe)
Production cost of USD 13.4 per boe, down from USD 14.7 per boe in the previous quarter on increased production and exchange rate effects
Revised Balder X schedule and investment estimate, other major development projects progressing according to schedule amid continued macro and supply chain uncertainties. Overall capex guidance for 2022 maintained
Net impairment of USD 573 million in the quarter, after-tax impact of USD 308 million reflected in net income
USD 5 099 million in available liquidity

Leverage ratio reduced to 0.2x at the end of September from 0.4x at the end of June due to strong cash flow from operations and increased cash position
The Board declared dividend of NOK 1.225 per share for the third quarter, totalling USD 290 million, to be distributed on 9 November

KPIs (USD million unless otherwise stated)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021
Actual serious injury frequency (x, 12 months rolling)	0.1	0.1	-	0.1	-	-
CO2 emissions intensity (operated licenses, kg/boe)	10.4	8.6	12.3	8.7	10.0	9.5
Production (kboepd)	215	210	247	222	242	246
Production cost (USD/boe)	13.4	14.7	11.6	13.3	11.5	12.0
Cash flow from operations before tax	2 027	1 864	1 331	6 275	2 892	4 415
Cash flow from operations (CFFO)	1 503	1 535	1 350	5 239	3 629	4 580
Free cash flow (FCF)	904	962	621	3 445	1 754	1 995
Dividends paid	260	225	213	485	688	950

"Macro complexity and the global security situation influence energy markets with wide-reaching effects, reaffirming the importance of the Norwegian Continental Shelf as a reliable supplier of oil and gas to Europe. Against this backdrop, our focus is on safe, efficient and secure operations, working in close collaboration with our partners and relevant authorities. At the same time, we progress the developments which are set to deliver our longer-term production growth, and while we revised the Balder X schedule and investment estimate in the quarter, we continue to deliver strong cash flow and shareholder distributions in 2022".

Torger Rød, CEO of Vår Energi.

Key metrics and targets

Production 1 (kboepd)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021

Crude oil	122.0	113.3	131.8	124.1	135.0	136.9
Gas	78.8	84.6	92.0	82.8	84.1	86.7
NGL	13.7	11.9	23.4	15.1	22.5	22.2
Total	214.5	209.8	247.2	222.0	241.6	245.8

Realised prices (USD/boe)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021
Crude oil	107.8	116.0	71.8	107.4	67.0	70.4

Gas	203.9	151.3	76.3	172.3	52.1	79.5
NGL	61.8	70.9	45.7	68.5	40.6	45.0
Average (volume weighted)	139.0	124.1	70.6	127.2	59.6	70.9

Financials
(USD million unless otherwise stated)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021
Total income	2 526	2 437	1 621	7 454	3 798	6 073
EBIT	1 454	1 674	824	4 846	1 762	3 012
Profit / (loss) before income taxes	1 161	1 214	640	4 071	1 461	2 600
Net earnings	(30)	56	156	450	432	644
Earnings per share (USD)	(0.01)	0.02	0.06	0.18	0.17	0.26
Dividend per share (USD)	0.10	0.09	0.09	0.19	0.28	0.38
NIBD / EBITDAX (including leasing)	0.2	0.4	1.0	0.2	1.0	0.8

Targets and outlook

2022 guidance (USD million unless otherwise stated)

Production	kboepd	220 – 225
Production cost	USD/boe	12.5 – 13.5
Development capex		2 300 – 2 600
Exploration and abandonment capex		200
Dividends for 2022, paid quarterly		1 075
Dividends for Q3 to be distributed in November		290
Dividend guidance for Q4 payable in Q1 2023		300
Q4 2022 cash tax payment estimate 1		~1 789
Other:
Final payment as part of the 2019 acquisition of ExxonMobil's non-operated assets on the NCS		~340

Long-term financial and operational targets
End-2025 production target	kboepd	> 350
Medium term production cost	USD/boe	8.0
Leverage through the cycle	NIBD/EBITDAX	1.3

¹ Assumed NOK/USD 9.5.

¹ Production numbers presented for 2021 are based on a gas conversion of 6.65, whereas production in 2022 are based on a factor of 6.29

Operational review

Total production	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021
Total production (mmboe)	19.7	19.1	22.7	60.6	65.9	89.7
Operated (kboepd)	34.7	41.5	36.6	41.5	42.9	44.9
Partner operated (kboepd)	179.8	168.3	210.6	180.5	198.7	201.0	20%
Total production (kboepd)	214.5	209.8	247.2	222.0	241.6	245.8
Operated (kboepd)	16%	20%	15%	19%	18%	18%
Partner operated (kboepd)	84%	80%	85%	81%	82%	82%
Production by type (kboepd)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021
Crude oil	122.0	113.3	131.8	124.1	135.0	136.9
Gas	78.8	84.6	92.0	82.8	84.1	86.7
NGL	13.7	11.9	23.4	15.1	22.5	22.2
Total	214.5	209.8	247.2	222.0	241.6	245.8

Production by type (percentage)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021	kboepd
Crude oil	57%	54%	53%	56%	56%	56%	Total production
Gas	37%	40%	37%	37%	35%	35%	247
NGL	6%	6%	9%	7%	9%	9%
Total	100%	100%	100%	100%	100%	100%

Volumes sold / lifted (mmboe)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021
Crude oil	10.1	10.7	13.1	33.3	36.7	49.0
Gas	6.6	6.9	7.4	20.6	20.0	28.0
NGL	1.4	1.9	2.3	4.5	6.4	8.2
Total	18.1	19.5	22.9	58.4	63.1	85.2

¹ Production numbers presented for 2021 are based on a gas conversion of 6.65, whereas production in 2022 are based on a factor of 6.29.

² Recalculated from 247 kboepd with adjusted gas conversion factor

Production split Q3 2022, percentage based on kboepd

Total production

kboepd

Production ¹

Vår Energi's production of oil, liquids and natural gas averaged 215 kboepd in the third quarter of 2022, an increase of 2% from the previous quarter mainly due to reduced maintenance and turnaround activity on partner-operated fields. Production in the third quarter was impacted by a planned turnaround on Balder/Ringhorne and operational issues at both partner-operated and operated fields.

Compared to the third quarter of 2021, production decreased by 11% from 242 2 kboepd mainly due to natural decline and operational issues at both partner-operated and operated fields.

Production from operated assets in the quarter was 35 kboepd (16%) whereas production from partneroperated assets was 180 kboepd (84%).

Production of crude oil and NGL (liquids) in the third quarter amounted to 63% (60% in the second quarter) of total production, whereas gas production was 37% (40% in the second quarter). During the quarter, the Company continued to reduce NGL recovery to increase gas volumes and gas sales due to favourable market conditions. This led to a net production decrease of 2 kboepd in the quarter.

Production in the first nine months of 2022 averaged 222 kboepd, a reduction of 20 kboepd (8%) when

compared to the same period last year. The lower production was mainly related to the Grane, Ekofisk, Statfjord fields and Snorre. Increased production from the Åsgard, Goliat and Tyrihans fields due to improved performance, reduced maintenance and turnaround activity, contributed to mitigate the decline in production.

Based on the year-to-date production and current projections for the fourth quarter, the Company has revised the full-year 2022 production guidance to 220 – 225 kboepd from the previously expected 230 – 245 kboepd communicated in the second quarter report.

Volumes lifted / sold

Total volumes produced in the third quarter were 19.7 mmboe whereas volumes sold in the quarter amounted to 18.1 mmboe. Total volumes produced in first nine months of 2022 were 60.6 mmboe and volumes sold 58.4 mmboe.

Production efficiency

Production efficiency (operated licenses) in the third quarter was 82%, in line with previous quarter. Production efficiency in the first nine months of 2022 was 84%. Production efficiency for Goliat was 88% in the quarter, whereas production efficiency for Balder/Ringhorne was 72% due to planned turnaround and maintenance activities successfully executed on time and budget.

Hubs

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 Vår Energi's portfolio.

The Company's four hubs delivered 73% of the total production in the first nine months of 2022.

Production – hubs (kboepd)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021

Åsgard Area	68.7	73.9	85.4	74.0	74.8	77.4
Tampen Area	38.7	38.3	45.2	38.8	40.9	41.9
Balder/Grane Area	29.4	25.4	30.1	29.4	36.4	36.0
Barents Sea Area	19.2	19.1	19.2	21.6	21.1	22.7
Other	58.6	53.1	67.4	58.2	68.2	67.8
Total	214.5	209.8	247.2	222.0	241.6	245.8


Production – hubs (percentage)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021

Åsgard area	32%	35%	35%	33%	31%	31%
Tampen area	18%	18%	18%	17%	17%	17%
Balder/Grane area	14%	12%	12%	13%	15%	15%
Barents sea area	9%	9%	8%	10%	9%	9%
Other
	27%	25%	27%	26%	28%	28%

Åsgard area

Third quarter production from the Åsgard area was 68.7 kboepd (32% of total production), down from 73.9 kboepd in the previous quarter. The lower production was mainly due to a planned upgrade of the gas dehydration system on Åsgard, which was successfully completed, combined with well cycling on Trestakk and Morvin to rebuild reservoir pressure.

Tampen area

Production from the Tampen area was 38.7 kboepd in the third quarter (17% of total production), in line with the previous quarter. Production was positively impacted by improved uptime following completion of a turnaround on Statfjord B during the second quarter. However, downtime on the Snorre water-alternating-gas injection system reduced production in the quarter. The system is now fully operational.

Balder/Grane area

Third quarter production from the Balder/Grane area was 29.4 kboepd (14% of total production), up from 25.4 kboepd in the previous quarter. Production increased in the quarter as the Grane field re-started production after a major turnaround in the second quarter. During the third quarter, Balder/Ringhorne completed a two-week turnaround according to plan and budget, which reduced production in the period.

Production for the first nine months of 2022 was below expectations due to drilling and well performance at Ringhorne, combined with technical challenges at Balder.

Barents Sea area

Production from the Barents Sea area (Goliat) was 19.2 kboepd in the third quarter (9% of total production), in line with the previous quarter. Goliat continued its strong operational performance in the quarter, driven by good progress on uptime improvement and cost reduction programs. Production was negatively impacted by integrity issues in wells, which were shut-in to ensure safe operations. The Company is working closely with partners to find a long-term solution.

Diverse and robust portfolio positioned for value-adding growth

Barents Sea Area Vår Energi operated: Goliat

Equinor operated: Johan Castberg

Other

Production from other assets, including Ekofisk, Ormen Lange, Fram and Sleipner, was 58.6 kboepd during the third quarter (27% of total production), up from 53.1 kboepd in the previous quarter. The increased production was mainly driven by improved uptime on the Ekofisk field following a turnaround in the second quarter of 2022. The compressor failure on Sleipner B continued to impact production in the quarter.

Production cost

Total production cost was USD 13.4 per boe in the third quarter of 2022 compared to USD 14.7 in the second quarter. The reduction is mainly due to less turnaround and maintenance activity and exchange rate effects. The decrease in transportation cost per boe is due to less gas volumes being transported, which has higher transport cost per boe compared to oil.

Production cost for the first nine months of 2022 was USD 13.3 per boe. Vår Energi maintains its fullyear 2022 guidance for production cost per barrel at USD 12.5 to 13.5.

For more information, see production cost detailed in the financial review section.

Production cost (USD/boe)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021
Production cost	10.6	11.6	8.9	10.5	8.7	9.3
Transportation cost	2.8	3.1	2.7	2.8	2.8	2.7
Total production cost	13.4	14.7	11.6	13.3	11.5	12.0

Projects and developments

Vår Energi is participating in several significant development projects on the NCS which support the Company's target of producing more than 350 kboepd by end-2025. While the Balder X project announced revised investment estimates and schedule in September, the Company's remaining project portfolio progressed according to plan in the third quarter, including developments such as Johan Castberg, Breidablikk and Fenja. Covid-19, supply chain disruptions and inflationary pressure continue to impact Vår Energi and the energy sector. However, time to market for the Company's value-adding growth projects and developments remains a key priority.

Balder X

The Balder X Project (90% working interest) consists of the refurbishment of the Jotun FPSO as the Balder area hub centre with new production wells. The project is expected to contribute with more than 63 kboepd per day (net to Vår Energi) at peak production in 2025.

As announced on 19 September, the project schedule and investment estimate have been revised following a comprehensive baseline project review. First oil is now expected in the third quarter of 2024. The project is progressing according to the revised plan. Key focus remains on ensuring progress and cost control for the remaining part of the project, while mitigating impact from external factors such as Covid-19, challenging weather for offshore and drilling activities and global supply chain disturbances.

Key deliverables and achievements in the quarter include:

Installation of the subsea systems is on track for completion in 2022 with the majority of the subsea systems already installed
Drilling is progressing per revised plan with three wells completed and drilling operations ongoing
Engineering on the Jotun FPSO is progressing. Construction ramp-up has started and a majority of the equipment has arrived at yard and is being installed

Johan Castberg

The Johan Castberg (30% working interest) development is progressing according to schedule, with a revised investment estimate as announced 6 October in the Norwegian National Budget for 2023. The FPSO hull and living quarter modules are currently at Stord (Norway) for topside integration. The adjusted investment estimate relates to increased scope of work transferred from the yard in Singapore to Stord. Planned start-up of the Johan Castberg field remains in the fourth quarter of 2024. Peak gross production is expected at approximately 190 kboepd, with an estimated production cost of approximately USD 3 per boe during the first year of full production. Vår Energi considers Johan Castberg a prosperous area with diverse prospects and significant upside potential as demonstrated with the three discoveries made in the area in 2021 and 2022.

Key deliverables and achievements in the quarter include:

Heavy lift campaign completed safely on schedule. All modules are installed and ready to be inter-connected and tested with completion expected in 2024
Subsea and marine campaign close to completion as per plan and below budget

Breidablikk

The Breidablikk field (34.4% working interest) is a significant field and includes two discoveries. The field is being developed with four subsea templates tied-back to the Grane platform. The Breidablikk PDO was delivered in September 2020 by the operator Equinor and approved in June 2021. The field is targeted to start production in the first quarter of 2024. Once in operation, the field is expected to generate a peak production of approximately 62 kboepd (gross). The project is progressing according to plan.

Key deliverables and achievements in the quarter include:

Drilling operations progressing ahead of plan with the Deepsea Aberdeen drilling rig
Subsea and marine campaign for 2022 completed as planned
The High Activity Period (HAP) on Grane topside has been extended, without impacting the overall schedule

Fenja

Fenja (45% working interest) will be developed as a subsea tie-back to Njord A, operated by Equinor. The Fenja development project is currently in the execution phase and development drilling commenced in 2021. Production start-up has previously been delayed (due to delays in the Njord Future project, in which Vår Energi has no working interest) and is planned for the first half of 2023.

Key deliverables and achievements in the quarter include:

Drilling operations, including four wells, successfully completed on plan
Njord A is on field with remaining scope to be finalised before start-up
Njord B relocated on field after completed work in Kristiansund and work is ongoing to prepare for start-up

Other projects

• Hywind Tampen is progressing with seven out of eleven floating wind turbines installed offshore. Expected start-up is now scheduled for the first quarter 2023, compared to previously in late 2022

Exploration

Vår Energi currently holds 145 licenses of which 46 are operated. The Company has a proven exploration track record founded on strong technical competencies and historical expertise on the entire NCS and maintains an active exploration strategy supported by a large inventory of potential exploration prospects across its NCS portfolio.

Four out of eight exploration wells have been executed to date in 2022 with a 50% rate of success and total maximum up to 60 million barrels of recoverable oil equivalent. The 2022 drilling campaign comprises of one high risk / high reward and seven wells located near the main hubs. Vår Energi is targeting around 200 – 250 mmboe in unrisked recoverable resources 1 by the end of 2022, with four remaining exploration wells yet to be drilled.

In the Barents Sea, the Company plans to start the drilling of two operated wells, Lupa and Countach, in the fourth quarter adjacent to the Vår Energioperated Goliat field. Drilling operations are expected to be completed in the fourth quarter of 2022 and first quarter of 2023, respectively.

¹ Reported numbers are 100% unrisked recoverable resources

Two additional partner-operated wells are scheduled to be drilled by year-end, both located close to key hubs in line with the Company's hub strategy.

During the third quarter, Vår Energi also participated to the 2022 Awards in Predefined Areas (APA), the annual licensing round for the best-known exploration areas on the Norwegian shelf. The application to the Ministry of Petroleum and Energy was submitted for eleven licenses, of which five as operator. The award of the new production licenses is planned for in the beginning of 2023.

Health, safety, security and the environment (HSSE)

Key HSSE indicators	Unit	Q3 2022	Q2 2022	Q1 2022	Q4 2021

Serious incident frequency (SIF Actual) 1 12M roll avg	Per mill. exp. hours	0.1	0.1	0.1	0.0
Serious incident frequency (SIF) 1 12M roll avg	Per mill. exp. hours	1.3	1.4	1.6	1.3
Total recordable injury frequency (TRIF) 2 12M roll avg	Per mill. exp. hours	3.7	2.7	2.5	3.2
Acute spill	Count	0 3	0	1	2
Process safety events Tier 1 and 2 4	Count	0	0	2	0
CO2 emissions intensity 5	Kg CO2/boe	10.4	8.6	7.6	8.1

Vår Energi fully recognises the changed security situation on the NCS following the war in Ukraine and the leakages in the Nord Stream gas pipelines from the end of September. Following the pipeline breaches, a heightened security level has been implemented across all assets on the NCS. The security measures also include onshore facilities and logistics bases, as well as increased awareness and attention in office facilities.

The Norwegian authorities have the main responsibility for the security of infrastructure and facilities. The Company is working in close collaboration with all relevant authorities and industry partners. The safety and security of employees is the top priority. In this special

situation, Vår Energi remains focused on safe and secure operations to maintain a reliable supply of oil and gas to Europe and the UK.

The Company maintains continuous focus on implementation of its safety initiatives, and the positive Serious Incidents Frequency (SIF) ¹ trend observed during the first half of 2022 continued in the third quarter. The 12-month rolling average SIF rate was 1.3, a decrease from 1.4 in the second quarter of 2022. No incidents in the quarter were classified with serious actual consequence.

The number of recordable injuries, all of which had low actual consequence, was stable in the quarter. None of the incidents had a higher potential consequence. The 12-month rolling average Total Recordable Injury Frequency (TRIF) ² was 3.7 in the third quarter, an increase compared to 2.7 in the second quarter 2022. The trend is primarily driven by incidents related to yard activities in the ongoing development projects. All incidents have been managed according to the Company's management system. Initiatives have been implemented and learnings are shared to turn the negative trend. Furthermore, Vår Energi focuses on major accident potential and continuously monitors key indicators through the Company's major accident risk indicator system (MARI).

To continuously strengthen the culture and improve safety, Vår Energi and its contractors continue to build on its key safety tools, such as the Always Safe Annual Wheel, the Life-Saving Rules and the Company's internal TIR tool (Take Time, Involve, Report).

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

² TRIF: 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, floatels, vessels, projects and modifications, and transportation of personnel, using a risk-based approach

³ The company conducted in Q3 2022 a precautionary oil spill response operation in response to an observation of an oil sheen on the surface in the Balder area. A production upset in conjunction with start-up of the Balder field after a technical turnaround caused an increased oil content in the produced water that may have triggered the observation. The event is being investigated ⁴ Classified according to IOGP RP 456

⁵ Direct Scope 1 emissions of CO2 (kg) from exploration and production (Operational control, equity share) divided by total equity share production (boe) from Marulk, Goliat, Balder and Ringhorne East

Decarbonisation and environmental impact

Vår Energi considers the decarbonisation of oil and gas production a prerequisite for ensuring a resilient business model and driving long-term value creation. The Company has committed to reduce its GHG emissions in support of the Paris Agreement and has started to implement and operationalise its decarbonisation plan. The company is committed to have net-zero Scope 1 GHG emissions ¹ in 2030 and net-zero Scope 2 GHG emissions and part of Scope 3 GHG emissions ² in 2025.

In addition to commitments to reduce Scope 1, 2 and 3 GHG emissions from the Company's current activities, the decarbonisation plan outlines ambitions and commitments for GHG emissions in projects and developments which is key for future growth towards a low carbon society.

In the third quarter, Vår Energi joined the global joint industry "Aiming for Zero Methane Emissions Initiative", headed by the Oil and Gas Climate Initiative (OGCI), whose members include companies such as ENI, BP, Chevron, Equinor, ExxonMobil, and Shell. By taking individual and collective actions, OGCI members will help accelerate the energy transition through deep reductions in greenhouse gases.

The CO2 emissions intensity for operated assets in the third quarter is estimated to 10.4 kg CO² per boe, versus 8.6 kg CO2 per boe in the second quarter. The increase reflects lower production volumes on the Balder and Ringhorne fields due to planned maintenance activities.

GO BACK

¹ Direct Scope 1 emissions of CO2 (kg) from exploration and production (Operational control, equity share) divided by total equity share production (boe) from Marulk, Goliat, Balder and Ringhorne East.

² Scope 3 categories include business travels, employee commuting, and upstream transportation and distribution (selected vessel categories)

EBIT

Financial review

Consolidated statements of income

USD million	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021
Total income	2 526	2 437	1 621	7 454	3 798	6 073
Production costs	(114)	(378)	(360)	(790)	(860)	(1 188)
Exploration expenses	(12)	(26)	(18)	(50)	(46)	(57)
Depreciation and Amortization	(346)	(329)	(395)	(1 116)	(1 235)	(1 705)
Impairment loss and reversals	(573)	-	-	(562)	177	(1)
Other operating expenses	(28)	(29)	(24)	(90)	(73)	(110)
Total operating cost	(1 073)	(763)	(796)	(2 608)	(2 037)	(3 061)
Operating profit / (loss) (EBIT)	1 454	1 674	824	4 846	1 762	3 012
Net financial income / (expenses)	(34)	(33)	(55)	(96)	(164)	(269)
Net exchange rate gain / (loss)	(258)	(426)	(129)	(679)	(137)	(142)
Profit / (loss) before income taxes	1 161	1 214	640	4 071	1 461	2 600
Income tax (expense) / income	(1 191)	(1 158)	(484)	(3 621)	(1 029)	(1 956)
Profit / (loss) for the period	(30)	56	156	450	432	644

Total income in the third quarter was USD 2 526 million (+4%) compared to USD 2 437 in the previous quarter, mainly driven by higher realised price for gas.

Total income (USD million)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021
Petroleum revenues	2 520	2 423	1 615	7 426	3 761	6 043
Other operating income	7	13	6	28	37	29
Total income	2 526	2 437	1 621	7 454	3 798	6 073

4 846

Revenues from sale of petroleum products in the third quarter were USD 2 520 million, an increase of USD 96 million when compared to the USD 2 423 million reported for the second quarter of 2022. Higher product prices impacted petroleum revenues positively by USD 269 million whereas lower volumes sold impacted petroleum revenues negatively with USD 173 million.

Petroleum revenues from sale of liquids (USD 1 181 million) amounted to 47% of total petroleum revenues whereas revenue from sale of gas (USD 1 339 million) amounted to 53%. During the quarter, the Company continued to divert gas from injection and to minimise sale of methanol and ethane in order to maximise gas sales.

The average oil price realised in the third quarter was USD 107.8 per boe, down from USD 116.0 per boe in the previous quarter.

The average realised gas price in the third quarter was USD 203.9 per boe, an increase of USD 52.6 per boe from the second quarter 2022. In the third quarter, fixed price sales represented 28% of total sales at an average price of approximately 100 USD per boe. This included a oneyear gas sales agreement that ended in September 2022 and a fixed price contract at 138 USD per boe.

For the fourth quarter and 2023, Vår Energi has per 30 September 2022 executed fixed price transactions yielding ~150 USD per boe in Q4 2022, ~255 USD per boe in Q1 2023 and ~169 USD per boe in Q2/ Q3 2023. Main elements are (based on exchange rates per 7 October):

Approximately 19% of the gas production from October 2022 to September 2023 on a fixed price basis at an average price of ~169 USD per boe
10.5% of the gas production for the fourth quarter 2022 on a fixed price basis at an average price of ~131 USD per boe

Revenue split by petroleum type (USD million)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021

Revenue from crude oil sales	1 092	1 246	943	3 577	2 458	3 448
Revenue from gas sales	1 339	1 044	567	3 540	1 044	2 227
Revenue from NGL sales	88	133	105	309	260	368
Total petroleum revenues	2 520	2 423	1 615	7 426	3 761	6 043

Revenue split by petroleum type (percentage)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021

Revenue from crude oil sales	43%	51%	58%	48%	65%	57%
Revenue from gas sales	53%	43%	35%	48%	28%	37%
Revenue from NGL sales	4%	6%	6%	4%	7%	6%
Total	100%	100%	100%	100%	100%	100%

Realised prices (USD/boe)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021
Crude oil	107.8	116.0	71.8	107.4	67.0	70.4
Gas	203.9	151.3	76.3	172.3	52.1	79.5
NGL	61.8	70.9	45.7	68.5	40.6	45.0
Average (volume-weighted)	139.0	124.1	70.6	127.2	59.6	70.9

• 15% of the gas production for the first quarter 2023 on a fixed price basis at an average price of ~359 USD per boe

Production cost

Total production cost (produced volumes) in the third quarter amounted to USD 264 million, a reduction of 6% compared to the USD 281 million in the second quarter. The decrease in production cost when compared to the previous quarter was mainly due to less turnaround and maintenance activity. Production cost (sold volumes) was USD 114 million in the third quarter, a reduction of USD 264 million when compared to the previous quarter driven by significant effects from over-/underlift adjustments of USD 165 million. Overlift positions are priced at market product prices, while underlift positions are priced at unit production costs which give stronger effects in higher market prices.

USD million	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021

Cost of operations	167	182	171	512	473	688
Transportation and processing	55	58	62	171	185	243
Environmental taxes	30	28	19	92	68	102
Insurances	11	12	12	33	35	46
Production cost (produced volumes)	264	281	264	808	760	1 079
Back-up cost shuttle tankers	7	6	(1)	11	18	33
Adjustment of over/underlift (-)	(165)	82	80	(59)	39	15
Premium expense for crude put options	9	10	17	30	44	60
Production (sold volumes)	114	378	360	790	860	1 188
Total produced volumes (mmboe)	19.7	19.1	22.7	60.6	65.9	89.7
Production cost (USD/boe)	13.4	14.7	11.6	13.3	11.5	12.0

Exploration expenses

Exploration expenses in the third quarter amounted to USD 12 million. The decrease from the previous quarter is mainly related to lower dry well expenses in the quarter. Exploration expenses in first nine months of 2022 amounted to USD 50 million, up from USD 46 million when compared to the same period in 2021.

Depreciation, depletion, amortisation (DD&A)

DD&A in the third quarter was USD 346 million (+5%) compared to USD 329 million in the previous quarter. The increase was mainly due to the higher production. DD&A in first nine months of 2022 amounted to USD 1 116 million, down from USD 1 235 million when compared to the same period in 2021.

Impairment losses and reversals

Impairment loss in the third quarter was USD 573 million compared to no impairments or reversals in previous quarter. The impairment loss

in the quarter is related to the revised cost, schedule and production profile of the Balder X project. No other licenses have been impacted.

For more details on impairments and reversal of impairments, see note 11 in the consolidated financial statements.

Operating profit (EBIT)

EBIT for the third quarter was USD 1 454 million, down 13% from USD 1 674 million reported in the second quarter. EBIT in first nine months of 2022 was USD 4 846 million, up from USD 1 762 million in 2021.

Net finance

Net financial expenses in the third quarter were USD 34 million, in line with the previous quarter. Net exchange rate loss in the quarter amounted to USD 258 million, consisting of a realised gain of USD 29 million and USD 287 million of unrealised exchange rate losses related to the Company's interest-bearing loans. For more details, see note 6 in the consolidated financial statements.

Tax

The income tax expense in the third quarter was USD 1 191 million (+3%) compared to USD 1 158 million in the second quarter. The effective tax rate in the third quarter was 103%, up from 95% in the previous quarter. The increase was mainly due to impairment of goodwill which is not deductible for tax purposes. High unrealised exchange rate losses on external borrowing facilities further contributed to a high tax rate in the quarter.

Profit for the period

Loss in the third quarter was USD -30 million, down from a profit of USD 56 million in the previous quarter due to the impairment on Balder and net exchange rate loss described above. Profit in first nine months of 2022 was USD 450 million, up from USD 432 million in the same period previous year.

Condensed consolidated statements of financial position

NIBD / EBITDAX
----------------	--

NIBD/EBITDAX

Available liquidity	30 Sep 2022	30 Jun 2022	30 Sep 2021	31 Dec 2021
Cash and cash equivalents	1 499	892	264	224
RBL	-	-	795	-
RCF	3 600	3 600	600	3 260
Available liquidity	5 099	4 492	1 658	3 484

Available liquidity

USD million

Total assets at the end of the third quarter amounted to USD 17 665 million. The reduction from USD 18 621 million at the end of the second quarter is mainly due to a weaker NOK to USD when converting to reporting currency.

Tangible fixed assets including property, plant and equipment (PP&E) at the end of the period were USD 12 907 million and movements are detailed in note 9 in the consolidated financial statements.

Total equity amounted to USD 1 157 million, corresponding to an equity ratio of 7%.

Total cash and cash equivalents at the end of the third quarter were USD 1 499 million. At the end of the third quarter, the Company had USD 3 600 million in undrawn credit facilities bringing total available liquidity to USD 5 099 million.

USD million

Interest-bearing debt

Total interest-bearing debt (incl. leasing) at the end of the third quarter was USD 3 555 million, a decrease of USD 29 million from USD 3 584 million at the end of the previous quarter. For more details, see note 17 and 21 in the consolidated financial statements.

EBITDAX was USD 2 384 million in the quarter and free cash flow (FCF) was USD 904 million.

Due to the strong cash flow generated, the Company reduced its leverage ratio (NIBD including leasing/EBITDAX) to 0.2x at the end of the quarter, down from 0.4x at the end of the previous quarter.

Interest bearing debt excl. leasing (x)	30 Sep 2022	30 Jun 2022	30 Sep 2021	31 Dec 2021
Adjusted total interest bearing debt / EBITDAX	0.4	0.5	1.0	1.0
Adjusted net interest-bearing debt / EBITDAX	0.2	0.3	1.0	1.0

Interest bearing debt incl. leasing (USD million)	30 Sep 2022	30 Jun 2022	30 Sep 2021	31 Dec 2021

Interest-bearing loans and borrowings	2 977	2 977	4 712	4 493
Interest-bearing loans, current	348	343	-	333
Lease liabilities, non-current	130	160	95	216
Lease liabilities, current	99	103	37	109
Total interest bearing debt (TIBD)	3 555	3 584	4 845	5 152
Cash and cash equivalents	1 499	892	264	224
Net interest bearing debt (NIBD)	2 056	2 692	4 581	4 928
EBITDAX 4 quarters rolling	8 483	7 336	4 592	4 774
Total interest bearing debt / EBITDAX	0.4	0.5	1.1	1.1
Net interest-bearing debt / EBITDAX	0.2	0.4	1.0	1.0

Condensed consolidated statements of cash flow

Consolidated statements of cash flows (USD million)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021

Cash flow from operating activities (CFFO)	1 503	1 535	1 350	5 239	3 629	4 580
Cash flows used in investing activities	(603)	(596)	(739)	(1 849)	(1 911)	(2 633)
Cash flows from financing activities	(310)	(607)	(636)	(2 150)	(1 730)	(1 976)
Net change in cash and cash equivalents	591	332	(25)	1 240	(11)	(29)
Cash and cash equivalents, beginning of period	892	539	291	224	272	272
Effect of exchange rate fluctuation on cash held	16	22	(2)	35	3	(20)
Cash and cash equivalents, end of period	1 499	892	264	1 499	264	223

Cash flow from operating activities before tax USD million

Cash flow from operating activities (CFFO) was USD 1 503 million in the third quarter, in line with USD 1 535 million in the previous quarter.

Higher product prices contributed positively while working capital changes and higher taxes paid reduced the cash flow compared to the previous quarter.

Condensed consolidated statements of cash flow – continued

Cash flows used in investing activities (USD million)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021

Expenditures on exploration and evaluation assets	3	21	15	30	97	104
Expenditures on property, plant and equipment	596	552	714	1 763	1 778	2 480
Payment for decommissioning of oil and gas fields	4	23	10	56	57	70
Proceeds from sale of assets (sales price)	-	-	-	-	(21)	(24)
Expenditures on goodwill and other intangible assets	-	-	-	-	-	-
Total cash flows used in investing activities	603	596	739	1 849	1 911	2 633

Net cash flow used in investing activities in the third quarter was USD 603 million. Expenditures on property, plant and equipment (PP&E) were USD 596 million and expenditures in the Balder Area, Johan Castberg and Grane totalled 65% of total expenditures on PP&E.

Expenditures on PP&E (USD million, %)	Q3 2022	Q3 2022	Q2 2022	Q2 2022	Q3 2021	Q3 2021	FY 2021	FY 2021

Balder area	230	39%	215	43%	392	55%	1150	46%
Johan Castberg	79	13%	74	10%	77	11%	320	13%
Fenja	22	4%	20	3%	21	3%	103	4%
Grane	79	13%	62	11%	45	6%	159	6%
Snorre	30	5%	31	6%	45	6%	151	6%
Statfjord area	27	5%	35	6%	23	3%	83	3%
Sleipner area	1	-	2	-	3	-	31	1%
Ekofisk area	25	4%	22	4%	22	3%	89	4%
Goliat	26	4%	19	4%	32	4%	110	4%
Tommeliten	8	1%	9	2%	3	-	18	1%
Other	69	12%	64	12%	52	7%	265	11%
Total expenditures on PP&E	596	100%	552	100%	714	100%	2 480	100%

Expenditures on PP&E, third quarter 2022

Condensed consolidated statements of cash flow – continued

Capex coverage	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021
Expenditures on exploration
and evaluation assets	3	21	15	30	97	104
Expenditures on PP&E	596	552	714	1 763	1 778	2 480
Capex	599	573	729	1 794	1 875	2 585
CFFO	1 503	1 535	1 350	5 239	3 629	4 580
Capex coverage (x)	2.5	2.7	1.9	2.9	1.9	1.8

Capex coverage in the third quarter was 2.5x.

Cash flows from financing activities (USD million)	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021
Dividends paid Net proceeds from bond issue	(260) -	(225) 497	(213) -	(485) 497	(688) -	(950) -
Net proceeds / (payments) of revolving credit facility	-	(840)	-	(2 021)	-	4 494
Net proceeds / (payments) of reserve based lending facility	-	-	(375)	-	(895)	(5 335)
Payment of principal portion of lease liability	(28)	(23)	(11)	(85)	(33)	(44)
Interest paid	(22)	(16)	(38)	(57)	(113)	(142)
Total cash flows used in investing activities	(310)	(607)	(636)	(2 150)	(1 730)	(1 976)

Net cash outflow from financing activities amounted to USD 310 million mainly related to dividends paid in the third quarter.

Outlook

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

The Company targets production of more than 350 kboepd by end 2025, corresponding to above 50% growth compared to the guided 2022 level. The end-2025 ambition is based on:

Material long-lived reserves and resources
Improved recovery, utilising leading reservoir technology and infill drilling to enhance and drive facilities and reservoir performance
Development of a robust pipeline of sanctioned projects centred around strategic hubs, including Balder X, Johan Castberg and Breidablikk

Growth levers beyond 2025 include maturing and developing unsanctioned projects, increased recovery and lifetime extension, continuing to leverage best-in-class NCS exploration capabilities to deliver new potential commercial discoveries, and executing on accretive M&A in hub areas to create value and synergies.

Based on the potential for improving operations in currently producing fields and the attractive cost profile in sanctioned developments, Vår Energi has an ambition to reduce production cost per boe to

USD 8 in the medium term from USD 13.3 year to date in 2022. This represents a reduction of around 40%.

For 2022, the Company maintains its guidance for USD 2 300–2 600 million in development capex and USD 200 million in exploration and abandonment capex.

Vår Energi's material cash flow generation and investment-grade balance sheet support attractive and resilient distributions. For 2022, the Company expects a dividend of USD 1 075 million to be paid quarterly. For the fourth quarter of 2022, Vår Energi has communicated a dividend of USD 300 million.

From 2023 and onwards, the Company plans to distribute 20–30% of cash flow from operations after tax in shareholder returns.

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 1.3x through the cycle.

Transactions with related parties

For details on transactions with related parties, see note 22 in the consolidated financial statements.

Subsequent events

See note 24 in the consolidated financial statements.

Risks and risk management

A detailed analysis of Vår Energi's operational, financial and external risks and mitigation of those risks through risk management is described in the prospectus published in February 2022 and the 2021 annual report, both available on www.varenergi.no.

Vår Energi is exposed to a variety of risks associated with oil and gas operations at the NCS, exploration, reserve and resource estimates and estimates for capital and operating cost expenditures are associated with uncertainty. The production performance of oil and gas fields may be variable over time.

The COVID-19 pandemic and war in Ukraine have caused significant business disruption globally. Although Vår Energi has no direct exposure towards Russia, Ukraine or Belarus, the Company is indirectly exposed through increased macro

and security uncertainties and supply chain disturbances. As previously mentioned, this has put pressure on the Company's growth projects and developments, but Vår Energi remains committed to mitigate project risk and progress towards targeted first oil. Development activity on the NCS is expected to increase going forward, which may put additional pressure on the supply chain and increase resource constraints.

Vår Energi is exposed to various forms of market and financial risks, non-exhaustive, commodity price fluctuations, exchange rates, interest rates and capital requirements. Vår Energi is also exposed to uncertainties relating to the capital markets and access to capital, this may influence the pace with which development projects can be brought on stream.

Risk management is an integral part of the Company's business activities, and the business areas consequently have the main responsibility for managing risks arising from its business activities.

Accounting policies and alternative performance measures (APMs)

Accounting policies

These financial statements are the unaudited Interim Consolidated Financial Statements of Vår Energi for the second quarter and first half of 2022. The Interim Financial Statements are prepared in accordance with the International Accounting Standard 34 (IAS 34) – Interim Financial Reporting.

These Interim Financial Statements should be read in conjunction with the Consolidated Financial Statements for 2021 as they provide an update of previously reported information.

The accounting policies used in the Interim Financial Statements are consistent with those used in the 2021 Consolidated IFRS Financial Statements.

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 alternative 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, Adjusted NIBD, NIBD/ EBITDAX Ratio, Adjusted NIBD/EBITDAX Ratio, TIBD/EBITDAX Ratio and Adjusted TIBD/EBITDAX Ratio.

The APMs are not measurement 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.
"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 and lease liabilities ("Total interest-bearing debt" or "TIBD") less cash and cash equivalents.
"Adjusted net interest-bearing debt" or "Adjusted NIBD" is defined by Vår Energi as TIBD excluding lease liabilities ("Adjusted total interest-bearing debt" or "Adjusted TIBD") less cash and cash equivalents.
"NIBD/EBITDAX" is defined by Vår Energi as NIBD as a ratio of EBITDAX.
"Adjusted NIBD/EBITDAX" is defined by Vår Energi as Adjusted NIBD as a ratio of EBITDAX.
"TIBD/EBITDAX" is defined by Vår Energi as interest-bearing loans and borrowings and lease liabilities as a ratio of EBITDAX.
"Adjusted TIBD/EBITDAX" is defined by Vår Energi as interestbearing loans and borrowings (but excluding lease liabilities) as a ratio of EBITDAX.

EBITDA and EBITDAX

EBITDA and EBITDAX in the third quarter of 2022 amounted to USD 2 372 million and USD 2 384 million, respectively.

USD million	Q3 2022	Q2 2022	Q3 2021	YTD Q3 2022	YTD Q3 2021	FY 2021

Profit / (loss) for the period	(30)	56	156	450	432	644
Income tax (expense)/income	(1 191)	(1 158)	(484)	(3 621)	(1 029)	(1 956)
Net financial income / (expenses)	(34)	(33)	(55)	(96)	(164)	(269)
Net exchange rate gain / (loss)	(258)	(426)	(129)	(679)	(137)	(142)
Depreciation and amortisation	(346)	(329)	(395)	(1 116)	(1 235)	(1 705)
Impairment loss and reversals	(573)	-	-	(562)	177	(1)
EBITDA	2 372	2 003	1 219	6 523	2 819	4 717
Exploration expenses	(12)	(26)	(18)	(50)	(46)	(57)
EBITDAX	2 384	2 029	1 237	6 573	2 865	4 774
Total income	2 526	2 437	1 621	7 454	3 798	6 073
EBITDA margin	94%	82%	75%	88%	74%	78%
EBITDAX margin	94%	83%	76%	88%	75%	79%

Financial statements with note disclosures

Unaudited consolidated financial statements

	Unaudited consolidated statement of comprehensive income	27	Note 10 Right of use assets	45
Unaudited consolidated balance sheet statement		28	Note 11 Impairment	46
Unaudited consolidated statement of changes in equity		30	Note 12 Trade receivables	48
			Note 13 Other current receivables and financial assets	48
	Unaudited consolidated statement of cash flows	31	Note 14 Financial instruments	49
Notes		33	Note 15 Cash and cash equivalents	50
Note 1	Summary of IFRS accounting principles and restatements	34	Note 16 Share capital and shareholders	50
Note 2	Income	37	Note 17 Financial liabilities and borrowings	51
Note 3	Production costs	38	Note 18 Asset retirement obligations	52
Note 4	Other operating expenses	39	Note 19 Other current liabilities	52
Note 5	Exploration expenses	39	Note 20 Commitments, provisions and contingent consideration	52
Note 6	Financial items	40	Note 21 Lease agreements	53
Note 7	Income taxes	41	Note 22 Related party transactions	54
Note 8	Intangible assets	43	Note 23 License ownerships	55
Note 9	Tangible assets	44	Note 24 Subsequent events	55

Unaudited consolidated statement of comprehensive income

USD 1000, except earnings per share data	Note	Q3 2022	Q2 2022	Restated Q3 2021	YTD 2022	Restated YTD 2021

Petroleum revenues	2	2 519 830	2 423 454	1 614 797	7 426 071	3 761 452
Other operating income	2	6 614	13 274	5 881	27 609	36 852
Total income		2 526 443	2 436 729	1 620 678	7 453 680	3 798 304
Production costs	1, 3	(114 480)	(378 442)	(359 810)	(789 913)	(860 426)
Exploration expenses	5, 8	(11 897)	(26 430)	(17 844)	(50 403)	(45 800)
Depreciation and amortisation	9, 10	(345 503)	(328 792)	(394 870)	(1 115 533)	(1 235 060)
Impairment loss and reversals	8, 9, 11	(572 531)	-	-	(561 667)	177 500
Other operating expenses	4	(28 459)	(29 113)	(23 887)	(90 485)	(72 969)
Total operating expenses		(1 072 870)	(762 776)	(796 412)	(2 608 001)	(2 036 755)
Operating profit / (loss)		1 453 573	1 673 952	824 266	4 845 679	1 761 549
Net financial income / (expenses)	6	(34 324)	(33 256)	(55 178)	(96 466)	(163 740)
Net exchange rate gain / (loss)	6	(258 099)	(426 279)	(128 962)	(678 500)	(136 748)
Profit/(loss) before taxes		1 161 151	1 214 418	640 126	4 070 713	1 461 061
Income tax (expense) / income	1, 7	(1 191 320)	(1 157 979)	(484 266)	(3 620 582)	(1 028 916)
Profit / (loss) for the period		(30 170)	56 439	155 859	450 131	432 144
Other comprehensive income:
Items that may be reclassified subsequently to the income statement:
Currency translation differences		(106 453)	(224 133)	(43 573)	(314 515)	(53 540)
Net gain / (loss) on put options used for hedging		(5 068)	9 929	3 518	2 491	(1 965)
Other comprehensive income for the period, net of tax		(111 521)	(214 204)	(40 054)	(312 024)	(55 505)
Total comprehensive income		(141 691)	(157 765)	115 805	138 108	376 639

Earnings per share
EPS Basic	1, 16	(0.01)	0.02	0.06	0.18	0.17
EPS Diluted	1, 16	(0.01)	0.02	0.06	0.18	0.17

Unaudited consolidated balance sheet statement

			Restated	Restated
				30 Sep 2021



8	1 835 231	2 241 297	2 531 897	2 706 638
8	166 028	180 484	199 981	191 773
8	84 901	92 524	104 520	104 710

9	12 725 525	13 927 344	15 188 917	15 050 992
10	181 183	222 066	298 432	105 855

	693	755	853	857
	729	1 064	1 809	2 012
	14 994 290	16 665 533	18 326 409	18 162 838


				294 559
				340 662
				197 825
				263 671
				1 096 717
	17 665 464	18 621 185	19 799 056	19 259 555
	Note 12, 22 1, 13 15	30 Sep 2022 273 522 677 804 220 842 1 499 006 2 671 174	30 Jun 2022 257 458 560 015 246 135 892 046 1 955 653	31 Dec 2021 301 329 745 921 201 809 223 588 1 472 647

Unaudited consolidated balance sheet statement – continued

USD 1000	Note	30 Sep 2022	30 Jun 2022	Restated 31 Dec 2021	Restated 30 Sep 2021		Sandnes, 24 October 2022 Signed Electronically
EQUITY AND LIABILITIES
Equity
Share capital	16	45 972	45 972	45 972	45 972	Thorhild Widvey	Liv Monica Bargem Stubholt
Share premium		2 158 181	2 418 181	2 643 181	2 905 181	Chair	Deputy Chair
Other equity	1	(1 046 918)	(905 446)	(1 186 278)	(1 397 629)
Total equity		1 157 234	1 558 706	1 502 874	1 553 523	Francesco Gattei	Guido Brusco
Non-current liabilities						Director	Director
Interest-bearing loans and borrowings	17	2 977 073	2 977 463	4 493 426	4 711 979
Deferred tax liabilities	7,1	6 939 035	7 444 464	7 907 749	7 851 674	Clara Andreoletti	Marica Calabrese
Asset retirement obligations	18	2 738 078	2 947 552	3 235 640	3 266 246	Director	Director
Lease liabilities, non-current	21	130 417	160 305	216 208	95 168
Other non-current liabilities		146 378	151 930	162 870	156 383
Total non-current liabilities		12 930 981	13 681 714	16 015 893	16 081 451	Fabio Romeo Director	Ove Gusevik Director
Current liabilities
Asset retirement obligations, current	18	13 390	18 016	61 536	58 917	Martha Skjæveland	Hege Susanne Blåsternes
Accounts payables	22	313 620	344 327	422 155	411 642	Director,	Director,
Taxes payable	7	2 378 317	2 033 759	801 432	549 890	employee representative	employee representative
Interest-bearing loans, current	17	348 276	343 202	333 149	-
Lease liabilities, current	21	98 974	103 301	108 880	37 395	Bjørn Nysted	Jan Inge Nesheim
Other current liabilities	1, 19	424 670	538 160	553 136	566 737	Director,	Director,
Total current liabilities		3 577 248	3 380 765	2 280 289	1 624 581	employee representative	employee representative
Total liabilities		16 508 229	17 062 479	18 296 182	17 706 032
							Torger Rød
TOTAL EQUITY AND LIABILITIES		17 665 464	18 621 185	19 799 056	19 259 555		Chief Executive Officer

Unaudited consolidated statement of changes in equity

	Share capital	Share premium	Other equity
Note			Other equity	Translation differences	Hedge reserve	Total equity
	45 972	3 593 181	(1 595 366)	(160 173)	(28 737)	1 854 877
1	-	-	8 409	487	-	8 897
	45 972	3 593 181	(1 586 957)	(159 685)	(28 737)	1 863 773
	-	-	432 144	-	-	432 144
	-	-	-	(53 540)	(1 965)	(55 505)
	-	-	432 144	(53 540)	(1 965)	376 639
	-	(688 000)	-	-	-	(688 000)
	-	-	1 111	-	-	1 111
	45 972	2 905 181	(1 153 702)	(213 226)	(30 702)	1 553 523
	-	-	211 895	-	-	211 895
	-	-	-	(9 428)	8 884	(544)
	-	-	211 895	(9 428)	8 884	211 352
	-	(262 000)	-	-	-	(262 000)
	-	-	-	-	-	-
	45 972	2 643 181	(941 806)	(222 654)	(21 818)	1 502 874
	-	-	450 131	-	-	450 131
	-	-	-	(314 515)	2 491	(312 024)
	-	-	450 131	(314 515)	2 491	138 108
	-	(485 000)	-	-	-	(485 000)
16	-	-	1 252	-	-	1 252
	45 972	2 158 181	(490 423)	(537 169)	(19 326)	1 157 234

Unaudited consolidated statement of cash flows

USD 1000	Note	Q3 2022	Q2 2022	Restated Q3 2021	YTD 2022	Restated YTD 2021

Profit / (loss) before income taxes	1	1 161 151	1 214 418	640 126	4 070 713	1 461 061
Adjustments to reconcile profit before tax to net cash flows
- Depreciation and amortisation	9, 10	345 503	328 792	394 870	1 115 533	1 235 060
- Impairment loss and reversals	8, 9	572 531	-	-	561 667	(177 500)
- (Gain) / loss on sale and retirement of assets	2	(300)	-	-	(300)	(19 103)
- Impairment of exploration wells	5, 8	2 276	18 032	3 239	25 406	8 146
- Accretion expenses (asset retirement obligation)	6, 18	23 519	22 076	25 833	69 877	68 593
- Unrealised (gain) / loss on foreign currency transactions and balances	6	286 807	382 048	152 434	640 818	219 470
- Other non-cash items and reclassifications		(75 831)	38 067	23 892	(3 922)	71 387
Working capital adjustments
- Changes in inventories, accounts payable and receivables		(221 106)	(132 805)	15 909	(122 269)	(33 557)
- Changes in other current balance sheet items		(67 183)	(6 816)	75 440	(82 497)	88 800
Contingent consideration paid related to prior business combination	19	-	-	-	-	(30 000)
Income tax received / (paid)	7	(524 208)	(328 896)	18 163	(1 036 413)	736 839
Net cash flows from operating activities		1 503 159	1 534 915	1 349 904	5 238 612	3 629 197

Cash flows from investing activities
Expenditures on exploration and evaluation assets	8	(2 734)	(21 114)	(14 983)	(30 081)	(97 388)
Expenditures on property, plant and equipment	9	(596 313)	(551 955)	(713 541)	(1 763 474)	(1 777 666)
Payment for decommissioning of oil and gas fields	18	(3 879)	(22 786)	(10 312)	(55 504)	(56 554)
Proceeds from sale of assets (sales price)		300	-	(101)	300	20 569
Net cash used in investing activities		(602 626)	(595 854)	(738 937)	(1 848 758)	(1 911 039)

Unaudited consolidated statement of cash flows – continued

USD 1000	Note	Q3 2022	Q2 2022	Restated Q3 2021	YTD 2022	Restated YTD 2021

Cash flows from financing activities
Dividends paid		(260 000)	(225 000)	(212 500)	(485 000)	(688 000)
Net proceeds from bond issue		-	496 906	-	496 906	-
Net proceeds/(payments) of revolving credit facilities	17	-	(840 000)	-	(2 020 500)	-
Net proceeds/(payments) of reserve based lending facility	17	-	-	(375 000)	-	(895 000)
Payment of principal portion of lease liability	21	(27 719)	(22 943)	(10 818)	(84 877)	(33 308)
Interest paid	1	(21 952)	(16 348)	(37 513)	(56 681)	(113 310)
Net cash from financing activities		(309 672)	(607 384)	(635 831)	(2 150 152)	(1 729 618)

Net change in cash and cash equivalents		590 862	331 676	(24 864)	1 239 701	(11 460)

Cash and cash equivalents, beginning of period		892 046	538 739	290 774	223 588	272 411
Effect of exchange rate fluctuation on cash held		16 098	21 630	(2 240)	35 717	2 720
Cash and cash equivalents, end of period		1 499 006	892 046	263 671	1 499 006	263 671

Notes

(All figures in USD 1000 unless otherwise stated)

The interim condensed consolidated financial statements for the period ended 30 September 2022 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 group's 2021 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's Board of Directors on 24 October 2022.

Note 1 Summary of IFRS accounting principles and restatements

The accounting principles adopted in the preparation of the interim condensed consolidated financial statements are consistent with those followed in the preparation of the Group's annual consolidated financial statements for the year ended 31 December 2021, except for a change in presentation of payment of borrowing costs in the statement of cash flows. The Group has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.

Restatement of interest paid in cash flow statement

During Q2 2022, the group decided to change its accounting principles related to presentation of interest payments in the cash flows statement. Interest payment are restated to be shown as financing activities in the statement of cash flows. In prior reporting periods, these cash flows were presented as operational activities. The reason behind the change is that interest payments are directly linked to the group's financing activities and are thus deemed more relevant to include under financing activities. Comparative figures have been restated accordingly and the impact on relevant previous periods is included in the table below.

USD 1000
Restating impact on Statement of Cash Flow	Q1 2021	Q2 2021	Q3 2021	Q4 2021	Q1 2022
Net cash flows from operating activities
Before restatement	930 347	1 273 934	1 310 447	922 484	2 182 157
Impact of restatement	39 466	36 332	37 513	28 221	18 381
After restatement	969 812	1 310 266	1 347 960	950 705	2 200 538
Net cash from financing activities
Before restatement	(578 434)	(439 556)	(598 318)	(218 378)	(1 214 715)
Impact of restatement	(39 466)	(36 332)	(37 513)	(28 221)	(18 381)
After restatement	(617 900)	(475 888)	(635 831)	(246 599)	(1 233 096)

Note 1 Summary of IFRS accounting principles and restatements – continued

Restatement of over/underlift of NGL lifted at the Kårstø terminal

Effective from the second quarter 2022, Vår Energi has corrected calculation of over/underlift of NGL lifted at the Kårstø terminal due to data quality issues in allocation of liftings at field level. Over/underlift of NGL from the fields that are lifted at the Kårstø terminal is recognised at the net position of the company's total portfolio. This was previously calculated at field level.

The impact of the restatement on the financial statement of previous quarters is summarized in the table below. The changes affect the relevant balance sheet line items; Other current receivables and financial assets, Other equity, Deferred tax liabilities and Other current liabilities. The line items Production costs and Income tax on the Statement of comprehensive income are affected.

Restating impact on Balance Sheet Statement Note Underlift before restatement Impact of restatement	01 Jan 2021	31 Mar 2021	30 Jun 2021	30 Sep 2021	31 Dec 2021	31 Mar 2022

	142 257	210 866	180 364	158 691	189 105	182 563
	(67 948)	(61 455)	(76 139)	(75 539)	(78 888)	(76 083)
Underlift after restatement 13	74 309	149 411	104 225	83 152	110 217	106 480
Overlift before restatement	166 175	168 011	192 336	296 345	317 605	392 087
Impact of restatement	(108 388)	(124 951)	(164 780)	(200 152)	(217 548)	(260 268)
Overlift after restatement 19	57 788	43 060	27 556	96 193	100 057	131 819
Equity before restatement	1 854 877	1 800 228	1 630 707	1 526 108	1 472 369	1 899 917
Impact of restatement	8 897	13 969	19 501	27 415	30 505	40 520
Equity after restatement	1 863 773	1 814 197	1 650 208	1 553 523	1 502 874	1 940 437
Deferred tax before restatement	7 342 952	7 579 941	7 776 683	7 754 476	7 799 594	7 934 656
Impact of restatement	31 543	49 527	69 140	97 198	108 155	143 665
Deferred tax after restatement 7	7 374 495	7 629 468	7 845 823	7 851 674	7 907 749	8 078 321

Note 1 Summary of IFRS accounting principles and restatements – continued

USD 1000
Restating impact on Statement of Comprehensive Income	Note	Q1 2021	Q2 2021	Q3 2021	Q4 2021	Q1 2022

Adjustment of (over)/under lift before restatement		61 139	(69 121)	(118 018)	9 053	(67 687)
Impact of restatement		23 048	25 974	38 266	14 781	43 946
Adjustment of (over)/under lift after restatement	3	84 187	(43 147)	(79 752)	23 834	(23 741)
Income tax (expense) / income before restatement		(337 045)	(169 368)	(454 419)	(915 311)	(1 237 005)
Impact of restatement		(17 977)	(20 260)	(29 847)	(11 529)	(34 278)
Income tax (expense) / income after restatement	7	(355 022)	(189 628)	(484 266)	(926 840)	(1 271 283)
Earnings per share before restatement		0.06	0.04	0.06	0.08	0.17
Impact of restatement		-	-	-	-	-
Earnings per share after restatement		0.07	0.04	0.06	0.08	0.17

Difference between impact in P&L vs. change in equity is related to translation effects.

Note 2 Income

Petroleum revenues (USD 1000)	Q3 2022	Q2 2022	Q3 2021	YTD 2022	YTD 2021

Revenue from crude oil sales	1 092 481	1 246 436	943 436	3 576 793	2 457 887
Revenue from gas sales	1 339 028	1 043 651	566 622	3 540 366	1 043 533
Revenue from NGL sales	88 321	133 367	104 738	308 912	260 032
Total petroleum revenues	2 519 830	2 423 454	1 614 797	7 426 071	3 761 452

Sales of crude (boe 1000)	10 133	10 743	13 134	33 309	36 691
Sales of gas (boe 1000)	6 567	6 896	7 431	20 550	20 027
Sales of NGL (boe 1000)	1 428	1 882	2 294	4 511	6 400

Other operating income (USD 1000)	Q3 2022	Q2 2022	Q3 2021	YTD 2022	YTD 2021

Gain/(loss) from sale of assets	300	-	-	300	19 103
Other operating income	6 314	13 274	5 881	27 309	17 749
Total other operating income	6 614	13 274	5 881	27 609	36 852

The majority of sales are to international customers in EU and the UK.

Other operating income mainly consist of partner's share of lease cost recovered by the Company in addition to a Q2 2022 insurance proceed of USD 4 million related to loss of production following the Balder subsea incident in the first quarter 2022.

Note 3 Production costs

USD 1000	Note	Q3 2022	Q2 2022	Restated Q3 2021	YTD 2022	Restated YTD 2021

Cost of operations		167 334	182 125	171 395	511 516	472 514
Transportation and processing		54 761	58 361	62 377	171 382	184 620
Environmental taxes		30 074	28 046	18 783	92 274	67 836
Insurance premium		11 443	12 170	11 590	32 914	34 666
Production cost based on produced volumes		263 613	280 702	264 145	808 087	759 636

Back-up cost shuttle tankers		6 650	5 799	(1 170)	11 285	17 858
Changes in over/(underlift)	1	(164 635)	81 705	79 752	(59 189)	38 712
Premium expense for crude put options	14	8 852	10 235	17 083	29 729	44 220
Production cost based on sold volumes		114 480	378 442	359 810	789 913	860 426

Total produced volumes (boe 1000)		19 737	19 089	22 744	60 601	65 944
Production cost per boe produced (USD/boe)		13.4	14.7	11.6	13.3	11.5

The changes in over/(underlift) are mainly due to allocation of liftings at field level and timing of liftings.

Note 4 Other operating expenses

USD 1000	Q3 2022	Q2 2022	Q3 2021	YTD 2022	YTD 2021

R&D expenses	9 485	10 182	6 160	35 497	21 384
Pre-production costs	5 206	5 806	4 061	17 203	14 585
Guarantee fee decommissioning obligation	6 863	6 765	5 649	18 504	16 662
Administration expenses	6 906	6 361	4 983	19 280	15 766
Other expenses	-	-	3 035	-	4 572
Total other operating expenses	28 459	29 113	23 887	90 485	72 969

Note 5 Exploration expenses

USD 1000	Note	Q3 2022	Q2 2022	Q3 2021	YTD 2022	YTD 2021

Seismic		1 366	316	1 473	1 985	2 472
Area Fee		2 069	2 114	2 358	6 083	7 267
Dry well expenses	8	2 276	18 032	3 239	25 406	8 146
Other exploration expenses		6 186	5 967	10 775	16 929	27 915
Total exploration expenses		11 897	26 430	17 844	50 403	45 800

Dry well expenses are mainly related to the wells PL901 7122/6-3 S Rødhette, PL209 6305/5-C-3 H Ormen Lange Deep and the 34/4-18 S Statfjord Kile Well.

Note 6 Financial items

Q3 2022 2 929 (35 378) (1 992) 27 865 (2 513) (23 519)	Q2 2022 492 (23 033) (1 930) 19 597 (4 174) (22 076)	Q3 2021 1 551 (37 513) (1 610) 16 887 (5 053) (25 048)	YTD 2022 3 771 (78 394) (7 149) 68 933 (9 477) (69 877)	YTD 2021 9 089 (113 310) (5 173) 39 535 (15 079) (68 593)







(1 716)	(2 131)	(4 392)	(4 272)	(10 209)
(34 324)	(33 256)	(55 178)	(96 466)	(163 740)
(286 807)	(382 048)	(152 434)	(640 818)	(219 470)
28 709	(44 231)	23 471	(37 683)	82 723
(258 099)	(426 279)	(128 962)	(678 500)	(136 748)
				(300 488)
		(292 423) (459 535)	(184 140)	(774 966)

Vår Energi's functional currency is NOK, whilst interest bearing loans are in USD. Due to weakening of NOK vs. USD, significant unrealised foreign exchange losses were recognised in 2022. Of the USD 640 818 thousand reported YTD September 2022, USD 640 282 thousand is unrealised foreign exchange loss directly linked the loans in USD.

Note 7 Income taxes

			Restated		Restated
USD 1000	Q3 2022	Q2 2022	Q3 2021	YTD 2022	YTD 2021

Current year tax payable / (receivable)	1 063 507	774 004	287 714	3 001 311	328 352
Prior period adjustments to current tax	238	5 647	(25)	7 937	1 297
Current tax expense / (income)	1 063 745	779 651	287 690	3 009 248	329 649

Deferred tax expense / (income)	127 575	378 327	196 577	611 334	699 268
Tax expense / (income) in profit and loss	1 191 320	1 157 979	484 266	3 620 582	1 028 916
Effective tax rate in %	103%	95%	76%	89%	70%
Tax expense / (income) in put option used for hedging	529	863	977	724	(569)
Tax expense / (income) in other comprehensive income	1 191 849	1 158 842	485 244	3 621 305	1 028 347

The tax calculation in the second and third quarter is based on the new cash flow based petroleum tax legislation, enacted by the Norwegian Parliament in June 2022 with effect from 01 January 2022. The main feature of the new legislation is that investments from 1 January 2022 can be expensed when incurred for special petroleum tax purposes, replacing the 6 years depreciation. The uplift deduction will be discontinued for investment not covered by the temporary 2020 tax regime. Impact of the new tax regime in the second quarter on first quarter figures was a reduction of payable taxed of USD 198 million, more than offset by an increase of USD 229 million in deferred taxes.

				Restated		Restated
Reconciliation of tax expense	Tax rate	Q3 2022	Q2 2022	Q3 2021	YTD 2022	YTD 2021

Corporate (78%) tax rate on profit / loss before tax 1	78%	905 744	947 294	499 298	3 175 319	1 139 627
Tax effect of uplift	71.8%	(49 478)	(48 331)	(100 731)	(148 011)	(270 541)
Tax effects of new legislation on uplift 1		-	10 476	-	-	-
Impairment of goodwill	78%	182 528	-	-	182 528	28 709
Tax effects of items taxed at other than corporate (78%) tax rate 2	56%	146 591	219 539	86 202	373 695	142 680
Tax effects of new legislation on other items 1		-	20 550	-	20 482	-
Other permanent differences, prior period adjustments and change in estimates of uncertain tax positions	78%	5 935	8 450	(503)	16 569	(11 559)
Tax expense / (Income)		1 191 320	1 157 979	484 266	3 620 582	1 028 916

¹ Tax effects in the second quarter of the new legislation is USD 20.5 million related to valuation allowance for lack of statutory tax deduction at effective rate 6.204% related to abandonment of the last field, and USD 10.5 million

in reduced uplift deduction recognised in the first quarter. Effective tax rate has changed from 78% in the old tax regime to 78.004% in the new tax regime.

² The effects of items taxed at other than corporate (78%) tax rate in second and third quarter 2022 is mainly impacted by fluctuation in USD/NOK exchange rate on the company's external borrowings.

Note 7 Income taxes – continued

			Restated		Restated
Deferred tax asset / (liability)	Q3 2022	Q2 2022	Q3 2021	YTD 2022	YTD 2021
Deferred tax asset / (liability) at beginning of period	(7 444 464)	(8 078 321)	(7 845 823)	(7 907 749)	(7 374 495)
Current year deferred tax income / (expense)	(127 575)	(378 327)	(196 577)	(611 334)	(699 268)
Deferred taxes recognised directly in OCI or equity	(529)	(863)	(977)	(724)	569
Currency translation effects	633 533	1 013 048	191 703	1 580 772	221 519
Net deferred tax asset / (liability) as of closing balance	(6 939 035)	(7 444 464)	(7 851 674)	(6 939 035)	(7 851 674)

Calculated tax (payable) / receivable	Q3 2022	Q2 2022	Q3 2021	YTD 2022	YTD 2021
Tax (payable) / receivable at beginning of period	(2 033 759)	(1 802 687)	(250 569)	(801 432)	506 349
Current year payable taxes	(1 063 507)	(774 004)	(287 714)	(3 001 311)	(328 352)
Net tax payment / (tax refund)	524 208	328 896	(18 162)	1 036 413	(736 839)
Prior period adjustments and change in estimate of uncertain tax positions	(238)	(5 647)	25	(7 937)	(1 297)
Currency translation effects	194 979	219 684	6 531	395 950	10 250
Net tax (payable) / receivable as of closing balance	(2 378 317)	(2 033 759)	(549 890)	(2 378 317)	(549 890)

A tax payment of USD 924 million related to 2022 net income was made 3 October 2022.

Note 8 Intangible assets

USD 1000	Goodwill	Other intan gible assets	Capitalised exploration wells	Total	USD 1000	Note	Goodwill	Other intangible assets	Capitalised exploration wells	Total
Cost as at 1 January 2022	5 009 390	104 520	199 981	5 313 891	Cost as at 1 July 2022		4 434 433	92 524	180 484	4 707 440
Additions	-	-	27 347	27 347	Additions		-	-	2 734	2 734
Disposals / expensed exploration wells	-	-	(23 130)	(23 130)	Disposals / expensed exploration wells	5	-	-	(2 276)	(2 276)
Currency translation effects	(574 957)	(11 996)	(23 714)	(610 667)	Currency translation effects		(365 336)	(7 623)	(14 914)	(387 873)
Cost as at 30 June 2022	4 434 433	92 524	180 484	4 707 440	Cost as at 30 September 2022		4 069 097	84 901	166 028	4 320 026
Depreciation and impairment as at 1 January 2022	(2 477 492)	-	-	(2 477 492)	Depreciation and impairment as 1 July 2022		(2 193 136)	-	-	(2 193 136)
Currency translation effects	284 356	-	-	284 356	Impairment loss	11	(233 998)	-	-	(233 998)
Depreciation and impairment as at 30 June 2022	(2 193 136)	-	-	(2 193 136)	Currency translation effects		193 268	-	-	193 268
					Depreciation and impairment as at 30 September 2022		(2 233 866)	-	-	(2 233 866)
Net book value as at 30 June 2022	2 241 297	92 524	180 484	2 514 304
					Net book value as at 30 September 2022		1 835 231	84 901	166 028	2 086 160

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

Note 9 Tangible assets

		Wells and	Facilities	Other property,
USD 1000	Note	production facilities	under con struction	plant and equipment	Total
Cost as at 1 January 2022		14 617 577	5 113 429	39 350	19 770 356
Additions		266 882	893 019	7 260	1 167 161
Estimate change asset retirement cost	18	78 038	-	-	78 038
Reclassification		65 912	(29 551)	-	36 361
Currency translation effects		(1 732 799)	(657 355)	(5 104)	(2 395 257)
Cost as at 30 June 2022		13 295 611	5 319 542	41 506	18 656 659

Depreciation and impairment as at 1 January 2022		(4 567 768)	-	(13 671)	(4 581 439)
Depreciation		(748 379)	-	(3 282)	(751 662)
Impairment reversal / (loss)		10 865	-	-	10 865
Currency translation effects		591 038	-	1 884	592 922
Depreciation and impairment as at 30 June 2022		(4 714 245)	-	(15 070)	(4 729 314)

Net book value as at 30 June 2022		8 581 366	5 319 542	26 437	13 927 344

Capitalised interests for facilities under construction were USD 19 882 thousand in the second quarter and USD 28 172 thousand in the third quarter 2022.

Rate used for capitalisation of interests was 1.9% in the second quarter 2022 and 2.4% in the third quarter.

Effective from 1 January 2022, Vår Energi has changed reserves classification system from U.S. Securities and Exchange Commission (SEC) to SPE-PRMS (Petroleum Resources Management System). The impact inUOP-depreciation rates are limited with increased total proved reserves of 0.7%.

		Wells and	Facilities	Other property,
USD 1000	Note	production facilities	under construction	plant and equipment	Total
Cost as at 1 July 2022		13 295 611	5 319 542	41 506	18 656 659
Additions		150 748	441 297	4 268	596 313
Estimate change asset retirement cost	18	12 839	-	-	12 839
Reclassification		12 515	5 976	-	18 491
Currency translation effects		(1 109 458)	(473 330)	(3 735)	(1 586 523)
Cost as at 30 September 2022		12 362 256	5 293 484	42 040	17 697 779

Depreciation and impairment as at 1 July 2022		(4 714 245)	-	(15 070)	(4 729 314)
Depreciation		(336 941)	-	(2 503)	(339 444)
Impairment reversal / (loss)	11	(338 533)	-	-	(338 533)
Currency translation effects		433 600	-	1 437	435 038
Depreciation and impairment as at 30 September 2022		(4 956 118)	-	(16 136)	(4 972 254)

Net book value as at 30 September 2022		7 406 137	5 293 484	25 904	12 725 525

Note 10 Right of use assets

		Rigs,
USD 1000	Offices	helicopters and supply vessels	Warehouse	Total
Cost as at 1 January 2022	75 830	304 182	13 546	393 558
Additions	4 081	2 596	-	6 677
Reclassification	-	(36 361)	-	(36 361)
Currency translation effects	(13 615)	(30 643)	1 399	(42 859)
Cost as at 30 June 2022	66 296	239 774	14 945	321 015

Depreciation and impairment as at 1 January 2022	(15 707)	(72 924)	(6 496)	(95 126)
Depreciation	(1 597)	(15 784)	(987)	(18 368)
Currency translation effects	1 703	12 002	841	14 545
Depreciation and impairment as at 30 June 2022	(15 600)	(76 706)	(6 642)	(98 950)

Net book value as at 30 June 2022	50 696	163 068	8 303	222 066

		Rigs, helicopters and
USD 1000	Offices	supply vessels	Warehouse	Total
Cost as at 1 July 2022	66 296	239 774	14 945	321 015
Reclassification	-	(18 491)	-	(18 491)
Currency translation effects	(5 192)	(18 731)	(1 068)	(24 991)
Cost as at 30 September 2022	61 104	202 552	13 877	277 533
Depreciation and impairment as at 1 July 2022	(15 600)	(76 706)	(6 642)	(98 950)
Depreciation	(1 260)	(4 541)	(259)	(6 059)
Currency translation effects	1 799	6 489	370	8 658
Depreciation and impairment as at 30 September 2022	(15 061)	(74 758)	(6 531)	(96 351)
Net book value as at 30 September 2022	46 043	127 794	7 346	181 183

Note 11 Impairment

Impairment testing

Impairment tests of individual cash-generating units (CGUs) are performed when impairment triggers are identified. Impairment tests were initiated in Q3 2022 due to updated cost and schedule for the Balder X project and the significant goodwill on the balance sheet.

Impairment testing of fixed assets and related intangible assets, including technical goodwill were performed as of September 30 2022. There were no impairment indicators for ordinary goodwill as of September 30 2022.

Impairment is recognised when the book value of an asset or a cash-generating unit exceeds the recoverable amount. The recoverable amount is the higher of the asset's fair value less cost of disposal and its value in use. The fair value less cost of disposal estimates are level 3 fair value estimates in the fair value hierarchy. Impairments are correspondingly reversed if the conditions for the impairment are no longer present. Upper limit of reversal is the historical impairments less estimated depreciation as if the impairment had not taken place. Impairments of goodwill are not reversed.

The impairment testing is performed based on discounted cash flows. The expected future cash flow is discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money, and the specific risk related to the asset. The discount rate is derived from the weighted average cost of capital (WACC) for a market participant. Cash flows are projected for the estimated lifetime of the fields.

Key assumptions applied for impairment testing purposes as of 30 September 2022 are based on Vår Energi's macroeconomic assumptions. Below is an overview of the key assumptions applied:

Prices

Future price level is a key assumption and has significant impact on the net present value. 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 increased from 65 USD/BBL to 70 USD/BBL (real 2022) and long-term gas price increased from 33.6 USD/BOE to 56.2 USD/BOE (real 2022) in Q3 2022 mainly due to structural changes in the European energy market impacted by the phase out of Russian oil and gas.

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

Year	31 Dec 2021	30 Jun 2022	30 Sep 2022

2022	74.1	105.1	87.3
2023	68.9	85.9	77.4
2024	68.1	73.9	73.6

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

Year	31 Dec 2021	30 Jun 2022	30 Sep 2022

2022	121.8	222.4	300.1
2023	61.5	137.4	278.0
2024	40.6	65.4	139.2

Oil and gas reserves

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

Production (mboe) per period as applied in the impairment test:

Year	MBOE

2022 – 2026	452
2027 – 2031	333
2032 – 2036	157
2037 – 2041	83
2042 – 2054	62

Note 11 Impairment – continued

Future expenditure

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

Discount rate

The post tax nominal discount rate used is 8.0 percent, unchanged vs. Q2 2022.

Currency rates

The currency rates used are 9.50 NOK/USD for 2023 and 9.00 NOK/USD from 2024 onwards. Euro currency rate of 9.90 NOK/EUR used for both short and long term. The NOK/USD rate for 2023 is up from 9.00 NOK/USD as applied per 30 June 2022.

Inflation

Inflation for 2023 is assumed to be 4%. The long-term inflation rate beyond 2023 is assumed to be 2.0%. Impairment testing per 30 June 2022 assumed yearly inflation rate of 2% from 2022.

Impairment testing of goodwill

The technical goodwill recognised in previous business combinations is allocated to each CGU for the purpose of impairment testing. Hence, technical goodwill is included in the impairment testing of the CGU, and the technical goodwill is written down before the asset. The carrying value of the CGU is the sum of tangible assets, intangible assets and technical goodwill as of the assessment date. In the impairment test performed, carrying value is adjusted by the remaining part of deferred tax from which the technical goodwill arose, to avoid an immediate impairment of all technical goodwill. When deferred tax liabilities from the acquisitions decreases as a result of depreciation, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable.

Impairment charge/reversal

The impairment testing per 30 September 2022 identified impairment to the Balder CGU of USD 572 531 thousand due to updated cost, schedule and production profile related to the Balder X project. Historical impairments, excluding goodwill, were fully reversed per 31 March 2022.

				Impairment allocated
Cash generating unit (USD 1000)	Net carrying value	Recoverable amount	Impairment / reversal (-)	Goodwill	PP&E	Deferred tax impact
Balder Area	1 281 283	972 808	572 531	233 998	338 533	(264 056)

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.

	Change in impairment after
Assumption USD 1000	Change	Increase in assumption	Decrease in assumption
Oil and gas prices	+/-25%	(573 000)	2 339 000
Production profile	+/- 5%	(363 000)	451 000
Discount rate	+/- 1% point	210 000	(223 000)

The sensitivities are created for illustration purposes, based on a simplified method and assumes no changes in other input factors. Significant reductions are likely to result in changes in business plans, cut-offs as well as other factors used when estimating an asset's recoverable amount. Changes in such input factors would likely significantly reduce the actual impairment amount compared to the illustrative sensitivity above. The impact of the sensitivities is mainly related to the Balder Area.

Climate related risks

The climate related risk assessment is generally described in the company's sustainability reporting. Financial reporting and impairment testing includes a step up of CO2 tax/fees from current levels to approximately NOK 2 000 per ton in 2030.

Note 12 Trade receivables

USD 1000	Note	30 Sep 2022	30 Jun 2022	31 Dec 2021	30 Sep 2021

Trade receivables - related parties	22	221 086	361 750	424 834	320 649
Trade receivables - external parties		456 718	364 548	412 627	296 625
Sale of trade receivables		-	(166 283)	(91 540)	(276 612)
Total trade receivables		677 804	560 015	745 921	340 662

As part of the Group's working capital optimisation and finance cost minimisation procedures, Vår Energi has entered into Credit Discount Agreements with several banks. Under the arrangements the ownership, including credit risk, of invoices for oil cargos sold 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, an 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.

As per 30 September 2022, no active agreements are in place.

Note 13 Other current receivables and financial assets

USD 1000	Note	30 Sep 2022	30 Jun 2022	Restated 31 Dec 2021	Restated 30 Sep 2021
Net underlift of hydrocarbons	1	121 555	131 475	110 217	83 152
Prepaid expenses		37 944	27 394	8 305	27 670
Brent crude put options - financial assets	14	20 001	18 046	17 407	11 985
Other		41 342	69 219	65 880	75 018
Total other current receivables and financial assets		220 842	246 135	201 809	197 825

Note 14 Financial instruments

Derivative financial instruments

The Group uses derivative financial instruments, such as Brent crude put options to hedge its commodity price risks.

As of 30 September 2021 and 30 September 2022, the Group had the following volumes of Brent crude oil put options in place and with the following strike prices:

Hedging instruments	Volume (no of put options outstanding at balance sheet date) in thousands (BBL)	Excercise price (USD per BBL)
Brent crude oil put options 30 Sep 2021, exercisable in 2021	4 220	40
Brent crude oil put options 30 Sep 2021, exercisable in 2022	11 051	47
Brent crude oil put options 30 Sep 2022, exercisable in 2022	3 298	47
Brent crude oil put options 30 Sep 2022, exercisable in 2023	9 388	50

Brent crude put options – financial assets

USD 1000	Note	Q3 2022	2021	Q3 2021

The beginning of the period		18 046	26 354	16 927
Cost of hedge	3	(8 852)	(60 492)	(17 083)
Effective portion recognised in OCI		3 659	9 976	5 306
New Brent crude put options		7 000	39 339	4 970
FX-effect		148	2 230	1 865
The end of the period		20 001	17 407	11 985

As of 30 September 2022, the fair value of outstanding Brent Crude oil put options amounted to USD 20 001 thousand. 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 1000	Note	Q3 2022	2021	Q3 2021

The beginning of the period		(36 327)	(58 263)	(55 780)
Cost of hedge	3	8 852	60 492	17 083
New Brent crude put options		(7 000)	(39 339)	(4 970)
FX-effect		(148)	(2 229)	(1 865)
The end of the period		(34 623)	(39 339)	(45 532)

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. -

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 1000	31 Dec 2021		Cash flows Amortisation	Currency	Other	30 Sep 2022

Bond USD Senior Notes (22/27)	-	500 000	-	-	-	500 000
Long-term interest-bearing debt (RCF)	4 520 500	(2 020 500)	-	-	-	2 500 000
Deferred payment ExxonMobil 1	333 149	-	15 127	-	-	348 276
Prepaid loan expenses	(27 074)	(6 325)	9 477	644	351	(22 927)
Totals	4 826 575	(1 526 825)	24 604	644	351	3 325 349

¹ Deferred payment to ExxonMobil is due 30 December 2022 and is classified as current liability as of December 2021. It includes accrued interest.

Note 15 Cash and cash equivalents

USD 1000	30 Sep 2022	30 Jun 2022	31 Dec 2021	30 Sep 2021
Bank deposits, unrestricted	1 494 595	885 366	214 133	257 296
Bank deposit, restricted, employee taxes	4 411	6 679	9 454	6 375
Total bank deposits	1 499 006	892 046	223 588	263 671

Note 16 Share capital and shareholders

Vår Energi ASA was listed on the Oslo Stock Exchange 16 February 2022, and as a consequence of this, company bylaws, voting rights and composition of the board was changed.

In 2021, the share capital was 399 425 shares at par value NOK 1 000. Every share had equal voting rights, 1 share corresponded to 1 vote.

As of 30 September 2022, the total share capital of the company is USD 45 972 thousand or NOK 399 425 thousand. 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 respect, including with respect to voting rights and dividends and other distributions, except from the class B shares. 4 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.

Earnings per share are calculated by dividing the net result attributable to shareholders of the Parent Company by the number of shares after the listing on Oslo Stock Exchange. The calculation for all periods presented have been adjusted retrospectively to the new number of shares.

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, hence it will not affect earnings per share.

Note 17 Financial liabilities and borrowings

Interest-bearing loans and borrowings

USD 1000	Coupon/ Int. Rate	Maturity	30 Sep 2022	30 Jun 2022	31 Dec 2021	30 Sep 2021

Bond USD Senior Notes (22/27)	5%		500 000	500 000	-	-
RBL credit facility			-	-	-	4 440 000
Bridge facility	0.80%+SOFR +CAS		Nov 2023 2 500 000	2 500 000	3 000 000	-
Working capital facility	1.08%+SOFR +CAS	Nov 2024	-	-	1 420 500	-
Liquidity facility	1.13%+SOFR +CAS	Nov 2026	-	-	-	-
Credit facility	1.13%+SOFR +CAS	Mar 2023	-	-	100 000	-
Deferred payment ExxonMobil			348 276	343 202	333 149	329 301
Prepaid loan expenses			(22 927)	(22 537)	(27 074)	(57 322)
Total interest-bearing loans and borrowings			3 325 349	3 320 665	4 826 575	4 711 979

Of which current and non-current
Interest-bearing loans, current			348 276	343 202	333 149	-
Interest-bearing loans and borrowings			2 977 073	2 977 463	4 493 426	4 711 979

Credit facilities – utilised and unused amount

USD 1000	30 Sep 2022	30 Jun 2022	31 Dec 2021	30 Sep 2021
Drawn amount RCF credit facility	2 500 000	2 500 000	4 520 500	4 440 000
Undrawn amount credit facilities 1	3 600 000	3 600 000	2 079 500	1 394 500

¹ Where current share is 600 mUSD in Q3 2022

On 1 November 2021, Vår Energi signed a senior unsecured multicurrency facilities agreement for USD 6.0 billion with a group of 12 international banks, refinancing the reserve based lending ('RBL') facility.

On 18 May 2022 Vår Energi ASA issued USD 500 million of 5% Senior Notes due in 2027 at a price equal to 99.961% on the Luxembourg Stock Exchange ("LuxSE"). The coupon is payable semi-annually on 18 May and 18 November. The funds were used for partial repayment of the Bridge Facility.

Per 30 September the facilities agreement contains of 3 separate facilities amounting to USD 5.5 billion; (1) bridge to bond facility of USD 2.5 billion which including extension options at the borrower's discretion has a final maturity 1 November 2023, (2) working capital revolving credit facility of USD 1.5 billion maturing 1 November 2024 and (3) liquidity facility of USD 1.5 billion maturing 1 Nov 2026. The facilities have no amortisation structure and all amounts outstanding fall due at maturity. 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 above.

On 24 March 2020, Vår Energi signed two unsecured revolving credit facility agreements (RCF) for a total amount of USD 600 million with a tenor of 3 years. The agreements were amended and restated 18 November 2021 to align with the Corporate Facilities with no changes to tenor or total commitment.

Deferred payment to ExxonMobil is part of the consideration for the 2019 acquisition of ExxonMobil's ownership interests in Partner-Operated fields and licenses on the Norwegian Continental Shelf.

Note 18 Asset retirement obligations

USD 1000	Q3 2022	Q1 – Q2 2022	2021
Beginning of period	2 965 568	3 297 176	4 286 451
Change in estimate	12 840	78 038	(922 730)
Accretion discount	23 519	46 358	94 733
Payment for decommissioning of oil and gas fields	(3 879)	(51 625)	(70 418)
Currency translation effects	(246 580)	(404 379)	(90 860)
Total asset retirement obligations	2 751 468	2 965 568	3 297 176
Short-term	13 390	18 016	61 536
Long-term	2 738 078	2 947 552	3 235 640

Breakdown by decommissioning period	30 Sep 2022	30 Jun 2022	31 Dec 2021
2022 – 2030	214 090	215 008	269 534
2031 – 2040	1 647 302	1 790 513	1 989 456
2041 – 2057	890 076	960 047	1 038 186

Change in estimate include updated discount rates and revised cost estimates for Balder and Goliat.

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 inflation rates of 5.7% in 2022, 4.0% in 2023 and 2.0% from 2024 onwards and discount rates between 3.2% – 3.4% per 30 September 2022. For year end 2021 the inflation rates were 1.8% – 2.3% and the discount rates between 1.15% – 3.0%. The discount rates are based on risk-free interest without addition of credit margin.

Third quarter 2022 payment for decommissioning of oil and gas fields (abex) is mainly related to Ekofisk/Tor.

Vår Energi has a retirement obligation as a shipper in Gassled booked to other non-current liabilities in the balance sheet statement. The Group has accrued USD 61 359 thousand for this purpose per 30 September 2022.

Note 19 Other current liabilities

USD 1000	Note	30 Sep 2022	30 Jun 2022	Restated 31 Dec 2021	Restated 30 Sep 2021

Net overlift of hydrocarbons	1	60 661	198 143	100 057	96 193
Net payables to joint operations		303 291	291 782	408 426	410 962
Employees, accrued public charges and other payables		26 095	11 909	5 314	14 050
Deferred payment for option premiums - oil puts	14	34 623	36 327	39 339	45 532
Total other current liabilities		424 670	538 160	553 136	566 737

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 20 Commitments, provisions and contingent consideration

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

The company has significant contractual commitments for capital and operating expenditures from its participation in operated and partner operated exploration, development and production projects. The current main development projects are Johan Castberg, Balder Future, Breidablikk and Fenja.

Note 21 Lease agreements

Vår Energi has entered into lease agreements for drilling rigs, helicopter, storage vessel and other vessels to secure planned activities.

The Group has lease agreements for offices in Sandnes, Oslo and Hammerfest. The most significant office contract is the lease of the main office building in Vestre Svanholmen 1, Sandnes.

Vår Energi also has leases for supply vessels and warehouses supporting operation at Balder and Goliat, where the most significant are for the supply vessels operating at Goliat.

Two new lease agreements commenced in Q1 2022 for helicopter services at Sola and storage unit in Sandnes. There are no new lease agreements in Q3 2022.

USD 1000	Q3 2022	Q1 – Q2 2022	2021
Opening Balance lease debt	263 606	325 088	164 482
New lease debt in period	-	6 472	208 819
Payments of lease debt	(29 383)	(61 147)	(48 401)
Interest expense on lease debt	2 178	5 144	7 819
Currency exchange differences	(7010)	(11 952)	(7 631)
Total lease debt	229 391	263 606	325 088

Breakdown of the lease debt to short-term and long-term liabilities	30 Sep 2022	30 Jun 2022	2021
Short-term	98 974	103 301	108 880
Long-term	130 417	160 305	216 208
Total lease debt	229 391	263 606	325 088
Lease debt split by activities	30 Sep 2022	30 Jun 2022	2021
Offices	51 689	57 301	66 525
Rigs, helicopters and supply vessels	170 133	197 301	250 811
Warehouse	7 569	9 003	7 752
Total	229 391	263 606	325 088

Note 22 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 is 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 1000	30 Sep 2022	30 Jun 2022	31 Dec 2021	30 Sep 2021
Trade receivables
Eni Trade & Biofuels SpA	33 781	110 883	160 533	193 700
Eni SpA	137 657	199 327	123 884	85 960
Eni Global Energy Markets	47 576	49 436	138 342	38 581
Other	2 072	2 104	2 075	2 409
Total trade receivables	221 086	361 750	424 834	320 649

All receivables are due within 1 year.

Current liabilities

USD 1000	30 Sep 2022	30 Jun 2022	31 Dec 2021	30 Sep 2021

Account Payables
Eni International BV	16 304	10 868	21 336	16 076
Eni Global Energy Markets	12 704	11 152	24 547	9 694
Eni SpA	10 407	6 763	19 387	16 963
Other	644	1 099	915	93
Total account payables	40 058	29 882	66 185	42 826

Sales revenue
USD 1000	Q3 2022	Q2 2022	Q3 2021	YTD 2022	YTD 2021

Eni Trade & Biofuels SpA	647 634	646 220	463 080	2 001 682	1 298 625
Eni SpA	459 540	327 112	196 694	786 653	361 073
Eni Global Energy Markets	134 159	133 186	77 059	428 853	150 378
Total sales revenue	1 241 334	1 106 518	736 834	3 217 188	1 810 075

Operating and capital expenditures

USD 1000	Q3 2022	Q2 2022	Q3 2021	YTD 2022	YTD 2021

Eni Trade & Biofuels SpA	12 353	13 705	12 682	43 839	23 541
Eni International BV	6 877	6 737	5 369	18 481	16 518
Eni SpA	6 527	9 200	15 925	18 276	32 700
Eni Global Energy Markets	(3 343)	373	(8 773)	(15 299)	6 844
Eni International Resources Ltd.	145	1 077	(12)	1 644	845
Other	2 244	276	(5 671)	2 672	(15 923)
Total operating and capital expenditures	24 803	31 367	19 520	69 612	64 523

Note 23 License ownerships

Vår Energi has the following new licenses since year end 2021.

Fields	WI %	Operator

PL091F	41%	Vår Energi
PL209 BS	10%	Equinor
PL586B	45%	Neptune
PL1025SB	30%	Vår Energi
PL1043B	40%	Vår Energi
PL1139	20%	Lundin
PL1154	40%	Vår Energi
PL1163	20%	ConocoPhillips
PL1168	50%	Vår Energi
PL1169	30%	Equinor
PL229H	50%	Vår Energi

Fields	WI %	Operator	Changes
Additions
PL393	30%	Vår Energi	Working interest and operator
PL917	20%	Vår Energi	Working interest and operator
PL917B	20%	Vår Energi	Working interest and operator
Disposals
PL027HS	10%	Vår Energi	Working interest
PL956	20%	Vår Energi	Working interest
PL985	10%	Vår Energi	Working interest
Other changes
PL947/PL947B		Vår Energi	Operator

The asset transactions are in licenses in the exploration phase.

Note 24 Subsequent events

Asset transactions/Other changes

Vår Energi has elected to sell part of its gas on a fixed price/forward basis. For the fourth quarter 2022, Vår Energi has sold 10.5% of the estimated gas production on a fixed price basis at an average price of 130.8 USD/boe. Vår Energi has also chosen to forward sell 15% of its estimated gas production in the first quarter 2023 at an average sales price of 359.3 USD/ boe. The current market situation is very much impacted by the war in Ukraine and the resulting reduced flow of gas from Russia into the European market.

Vår Energi operates only on the Norwegian Continental Shelf and market its petroleum products to customers in Norway, EU and UK. While not directly exposed to Russia's invasion of Ukraine, there is significant uncertainty regarding the potential impact on safe and reliable energy supply, as well as to the market prices of oil, gas and other commodities which may impact future operations and results.

Industry terms

Term	Definition/description

Boepd	Barrels of oil equivalent per day
Bscf	Billions of standard cubic feet
CFFO	Cash flow from operations
E&P	Exploration and Production
FID	Final investment decision
FPSO	Floating, production, storage and offloading vessel
HAP	High activity period
HSEQ	Health, Safety, Environment and Quality
HSSE	Health, Safety, Security and Environment
IG	Investment grade
Kboepd	Thousands of barrels of oil equivalent per day
Mmbls	Standard millions of barrels
Mmboe	Millions of barrels of oil equivalents
Mmscf	Millions of standard cubic feet
MoF	Ministry of Finance
MPE	Ministry of Petroleum and Energy
NCS	Norwegian Continental Shelf
NGL	Natural gas liquids
NPD	Norwegian Petroleum Directorate
OSE	Oslo Stock Exchange
PDO	Plan for Development and Operation
PIO	Plan for Installation and Operations
PRM	Permanent reservoir monitoring

Term	Definition/description
PRMS	Petroleum Resources Management System
Scf	Standard cubic feet
Sm3	Standard cubic meters
SPT	Special petroleum tax
SPS	Subsea production system
SURF	Subsea umbilicals, riser and flowlines
1P reserves	The quantities of petroleum which can be estimated with reasonable certainty to be commercially recoverable, also referred to as "proved reserves".
2C resources	The quantities of petroleum estimated to be potentially recoverable from known accumulations, also referred to as "contingent resources".
2P reserves	Proved plus probable reserves consisting of 1P reserves plus those additional reserves, which are less likely to be recovered than 1P reserves.

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 equity market conditions, investor attitude and demand, the business prospects of the Group and other specific 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 do not purport to contain all information required to evaluate the Company, the Group and/or their respective financial position. The Materials should be reviewed together with the Company's Annual Report 2021. The Materials contain certain financial information, including financial figures for and as of 30 September, 2022 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 strongly suggests that each Recipient seeks its own independent advice in relation to any financial, legal, tax, accounting or other specialist advice; no such advice is given by the Materials. 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 Recipient enters into any transaction. The Materials comprise a general summary of certain matters in connection with the Group. The Materials do not purport to contain all the information that any Recipient may require to make a decision with regards to any transaction. Any decision as to whether to enter into any

transaction should be taken solely by the relevant Recipient. Before entering into such transaction, each Recipient should take steps to ensure that it fully understands such transaction and has made an independent assessment of the appropriateness of such transaction in the light of its own objectives and circumstances, including the possible risks and benefits of entering into such transaction.

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Vår Energi ASA

3780_rns_2022-10-25_9fdba0c5-dab6-46ef-b75f-3dd8d8d5dd7f.pdf

Third quarter 2022

Key figures third quarter

Third quarter 2022 highlights

Torger Rød, CEO of Vår Energi.

Key metrics and targets

Targets and outlook

Operational review

Production split Q3 2022, percentage based on kboepd

Production 1

Volumes lifted / sold

Production efficiency

Hubs

Åsgard area

Tampen area

Balder/Grane area

Barents Sea area

Diverse and robust portfolio positioned for value-adding growth

Barents Sea Area Vår Energi operated: Goliat

Other

Production cost

Projects and developments

Balder X

Johan Castberg

Breidablikk

Fenja

Other projects

Exploration

Health, safety, security and the environment (HSSE)

Decarbonisation and environmental impact

Financial review

Consolidated statements of income

Production cost

Exploration expenses

Depreciation, depletion, amortisation (DD&A)

Impairment losses and reversals

Operating profit (EBIT)

Net finance

Tax

Profit for the period

Condensed consolidated statements of financial position

Interest-bearing debt

Condensed consolidated statements of cash flow

Condensed consolidated statements of cash flow – continued

Net cash flow used in investing activities in the third quarter was USD 603 million. Expenditures on property, plant and equipment (PP&E) were USD 596 million and expenditures in the Balder Area, Johan Castberg and Grane totalled 65% of total expenditures on PP&E.

Expenditures on PP&E, third quarter 2022

Condensed consolidated statements of cash flow – continued

Outlook

Transactions with related parties

Subsequent events

Risks and risk management

Accounting policies and alternative performance measures (APMs)

Accounting policies

Alternative performance measures ("APMs")

EBITDA and EBITDAX

Financial statements with note disclosures

Unaudited consolidated financial statements

Unaudited consolidated statement of comprehensive income

Unaudited consolidated balance sheet statement

Unaudited consolidated balance sheet statement – continued

Unaudited consolidated statement of changes in equity

Unaudited consolidated statement of cash flows

Unaudited consolidated statement of cash flows – continued

Notes

(All figures in USD 1000 unless otherwise stated)

Note 1 Summary of IFRS accounting principles and restatements

Restatement of interest paid in cash flow statement

Note 1 Summary of IFRS accounting principles and restatements – continued

Restatement of over/underlift of NGL lifted at the Kårstø terminal

Note 1 Summary of IFRS accounting principles and restatements – continued

Note 2 Income

Note 3 Production costs

Note 4 Other operating expenses

Note 5 Exploration expenses

Note 6 Financial items

Note 7 Income taxes

Note 7 Income taxes – continued

Note 8 Intangible assets

Production ¹