Fourth 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	Highlights	4
exploration track record. In 2022, Vår Energi produced net 220 kboepd of oil and gas from 36 fields.	Key metrics and targets	5
The Company has a target to increase production to above 350 kboepd by end-2025 while reducing production cost to
approximately USD 8 per boe from around USD 13.5 in 2022, as new projects come on stream and effects from improvement	Operational review	6
measures are achieved. Material cash flow generation and an investment-grade balance sheet enable attractive and resilient	Projects and developments	9
dividend distributions. For Q1 2023, Vår Energi guides for a dividend of USD 270 million, with the plan to distribute 20 – 30% of	Exploration	10
cash flow from operations after tax (CFFO) maintained.	HSSE	11
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	Decarbonisation and environmental impact	11
supports employee participation.	Financial review	12
	Outlook	20
Vår Energi is committed to delivering a better future. The Company's ambition is to be the safest operator, the partner of choice,	Transactions with related parties	20
an ESG leader and a net-zero producer (scope 1 and 2) by 2030.	Subsequent events	20
	Risks and uncertainty	20
To learn more, please visit: www.varenergi.no.	Alternative Performance Measures	21
	Financial statements	23
	Notes	30

Key figures fourth quarter 2022

Third quarter 2022 in brackets ¹

Production kboepd

Petroleum revenues USD million

EBIT USD million

1 531 (1 363)

-356

Profit before tax USD million

1 793 (1 071)

CFFO USD million

(1 503)

(599)

(904)

FCF

USD million

NIBD / EBITDAX x 0.3

(0.2)

¹ Restatement of third quarter due to changes in valuation of under/overlift

Fourth quarter 2022 highlights

Vår Energi reported USD 2 374 million in total income for the fourth quarter of 2022, bringing total income for the full year 2022 to USD 9 828 million, an increase of 62% from 2021 primarily due to higher oil and gas prices. Profit before taxes was USD 1 793 million in the quarter (+67% compared to last quarter) while USD 5 856 million for the full year compares to USD 2 647 million in 2021. Cash flow from operations (CFFO) was USD 443 million in the quarter and USD 5 682 million for the full year.

A dividend of USD 290 million (NOK 1.225 per share) for the third quarter was paid in November and USD 300 million (NOK 1.226 per share) for the fourth quarter will be distributed in March. The company further plans to distribute a dividend of USD 270 million for the first quarter 2023. For 2023, the dividend is planned to be approximately 30% of CFFO after tax.

Continued safe operations, no serious incidents in the quarter
Production of 214 kboepd in the fourth quarter, stable from the third quarter, full-year 2022 production of 220 kboepd within the revised guided range
Production guidance for 2023 of 210-230 kboepd
Average weighted realised price of USD 115 per boe in the quarter (oil USD 87 per boe, gas USD 182 per boe)
Fourth quarter and full-year production cost of USD 14.1 per boe and USD 13.5 per boe, respectively, within the guided range for the full year
Full-year 2023 production cost expected at USD 14.5 15.5
2022 exploration success rate of 57% 1, adding approximately 65 million boe (mmboe) of resources including operator of the largest NCS discovery for the year, being the Lupa discovery
Project portfolio progressing according to plan, including PDO for partner operated Verdande. The company's production target of above 350 kboepd by end-2025 maintained
Successful issue of USD 2 billion of five- and ten-year bonds in the US debt market in the fourth quarter
Continued strong balance sheet with leverage ratio at 0.3x at year-end 2022
The Board declared dividend of NOK 1.226 per share for the fourth quarter, totalling USD 300 million, to be distributed on 3 March, and hence a total distribution for 2022 of USD 1 075 million

KPIs (USD million unless otherwise stated)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021
Actual serious injury frequency (x, 12 months rolling)	0.1	0.1	-	0.1	-
CO2 emissions intensity (operated licenses, kg/boe)	10.5	10.4	8.1	9.2	9.5
Production (kboepd)	214	215	259	220	246
Production cost (USD/boe)	14.1	13.4	13.4	13.5	12.0
Cash flow from operations before tax	2 094	2 027	1 523	8 369	4 415
Cash flow from operations (CFFO)	443	1 503	951	5 682	4 580
Free cash flow (FCF)	(356)	904	241	3089	1 995
Dividends paid	290	260	262	775	950

"Today, Vår Energi celebrates one year as a listed company. In that brief period, we have delivered strong cash generation and attractive dividends. We have also progressed our development projects and are firmly on track for the end-2025 production and cost targets. Our exploration team yet again delivered world class results and we are proud to be the operator of the largest discovery on the NCS for the year. We expect a continued high activity level for 2023 as we work to realise our full potential and deliver more than 50% production growth towards end-2025 and lay the foundation for sustained high value creation beyond that."

Torger Rød, CEO of Vår Energi.

Key metrics and targets

Production 1 (kboepd)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021

Crude oil	122.4	122.0	142.6	123.7	136.9
Gas	78.3	78.8	94.6	81.7	86.7
NGL	13.5	13.7	21.3	14.7	22.2
Total	214.3	214.5	258.6	220.1	245.8

Realised prices (USD/boe)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021
Crude oil	86.6	107.8	80.4	101.7	70.4
Gas	181.6	203.9	148.3	174.5	79.5
NGL	54.7	61.8	60.6	65.4	45.0
Average (volume weighted)	115.1	139.0	103.4	124.1	70.9

Financials
(USD million unless otherwise stated)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021
Total income	2 374	2 526	2 274	9 828	6 073


EBIT Profit / (loss) before income taxes	1 531 1 793	1 363 1 071	1 249 1 137	6 369 5 856	3 059 2 647
Net earnings	488	(50)	212	936	654
Earnings per share (USD)	0.20	(0.02)	0.08	0.38	0.26
Dividend per share (USD)	0.12	0.10	0.10	0.31	0.38

Targets and outlook 2023 guidance (USD million unless otherwise stated)

Production	kboepd	210 – 230
Production cost	USD/boe	14.5 – 15.5
Development capex		2 400 – 2 700
Exploration capex		200
Abandonment capex		50
Dividends for Q4 2022 to be distributed in March		300
Dividend guidance for Q1 payable in Q2 2023		270
First half 2023 cash tax payment estimate 1		~1 800

Long-term financial and operational targets

End-2025 production target	kboepd	> 350
End-2025 production cost 2	USD/boe	~8.0
Leverage through the cycle	NIBD/EBITDAX	1.3x

¹ Assumed NOK/USD 9.5. ² Real 2021

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 1	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021
Total production (mmboe)	19.7	19.7	23.8	80.3	89.7	6%
Operated (kboepd)	38.2	34.7	50.8	40.7	44.9
Partner operated (kboepd)	176.1	179.8	207.7	179.4	201.0	20%
Total production (kboepd)	214.3	214.5	258.6	220.1	245.8
Percentage operated	18%	16%	20%	18%	18%
Percentage partner operated	82%	84%	80%	82%	82%
Production by type (kboepd)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021
Crude oil	122.4	122.0	142.6	123.7	136.9
Gas	78.3	78.8	94.6	81.7	86.7
NGL	13.5	13.7	21.3	14.7	22.2
Total	214.3	214.5	258.6	220.1	245.8

Production by type (percentage)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021	kboepd Total production
Crude oil	57%	57%	55%	56%	56%
Gas	37%	37%	37%	37%	35%	259
NGL	6%	6%	8%	7%	9%
Total	100%	100%	100%	100%	100%
Volumes sold / lifted (mmboe)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021

Crude oil	12.6	10.1	12.3	45.9	49.0
Gas	6.6	6.6	8.0	27.1	28.0
NGL	1.3	1.4	1.8	5.8	8.2
Total	20.5	18.1	22.1	78.8	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.

Production split

Q4 2022, percentage based on kboepd

Total production

kboepd

Production ¹

Vår Energi's net production of oil, liquids and natural gas averaged 214 kboepd in the fourth quarter of 2022, in line with third quarter, and a decrease of 18% compared to the fourth quarter of 2021. Fullyear 2022 production ended at 220 kboepd, within the revised guided range of 220-225 kboepd as communicated in the third quarter report.

During the quarter, the Company continued to reduce NGL recovery to increase gas volumes and gas sales due to favourable market conditions, representing a reduction of approximately 2 kboepd on an annual basis.

Based on current projections, the Company guides an average production for 2023 in the range of 210-230 kboepd. The guidance reflects a yearend production rate of approximately 220 kboepd and the expected net impact from; new projects coming on stream in 2023, various operational issues resolved in 2022, planned turnarounds and maintenance activities as well as the changed schedule for Balder X as communicated in the third quarter, and natural decline.

Total volumes produced in the fourth quarter were 19.7 mmboe whereas volumes sold in the quarter amounted to 20.5 mmboe.

Production efficiency

Production efficiency (operated licenses) in the fourth quarter was 87%, an increase from 82% in the previous quarter. For the full year, production efficiency equalled 85% compared to 87% in 2021. Production efficiency for Goliat was 96% in the quarter, whereas production efficiency for Balder/ Ringhorne was 73% due to maintenance activities.

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. Following the recent reorganisation of Vår Energi, the categorisation of the key strategic hub areas has been changed; Barents Sea, Norwegian Sea (including Åsgard), North Sea (including Tampen) and Balder area (including Grane). Fields previously reported as "Other" have been allocated to the above hub areas.

For the full year 2022, production decreased by approximately 10% compared to 2021, mainly due to various operational issues on operated and partner-operated fields, challenging well operations on operated fields and natural field decline.

In the Balder area, production from the operated Balder field increased by 4 kboepd following completion of turnaround in the third quarter and restoration of production from shut-in wells, while unplanned downtime at Grane impacted production negatively. On 10 February 2023, the production from the Balder area was temporarily reduced due to a potential riser integrity concern identified through the Company's monitoring systems. Ongoing inspection and analysis will determine when production can be resumed.
The operated Goliat asset in the Barents Sea delivered stable production from the previous quarter as contributions from infill drilling arrested natural field decline
In the North Sea, production increased 6 kboepd from the third quarter mainly driven by new wells at the Snorre field which started up in November, and a successful repair of the compressor at the Sleipner field which impacted production earlier in the year
In the Norwegian sea the production in the fourth quarter was negatively impacted by a fire at Åsgård B in November, which also reduced production from the subsea tie-back fields Mikkel, Kristin and Morvin. The incident coupled with capacity restrictions at the Kårstø terminal and natural decline, represented a decrease of

Diverse and robust portfolio positioned for value-adding growth

Production – hubs (kboepd)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021

Balder Area	29.8	29.4	34.6	29.5	36.0
Barents Sea	19.5	19.2	27.4	21.1	22.7
North Sea	82.9	76.9	88.0	78.0	86.1
Norwegian Sea	82.1	89.0	108.5	91.4	101.0
Total	214.3	214.5	258.6	220.1	245.8

Production – hubs (percentage)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021

Balder Area	14%	14%	13%	13%	15%
Barents Sea	9%	9%	11%	10%	9%
North Sea	39%	36%	34%	35%	35%
Norwegian Sea	38%	41%	42%	42%	41%
Total	100%	100%	100%	100%	100%


Production cost (USD/boe)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021

Production cost	12.0	10.6	11.0	10.9	9.3
Transportation cost	2.1	2.8	2.5	2.7	2.7
Total production cost	14.1	13.4	13.4	13.5	12.0

¹ Real 2021

Production cost

Total production cost was USD 14.1 per boe in the fourth quarter of 2022 compared to USD 13.4 in the third quarter. The increase is mainly due to phasing of maintenance activity.

For the full year, production cost per boe ended at 13.5, within the guided range of USD 12.5 – 13.5 per boe.

For 2023, Vår Energi guides at an average production cost per boe of USD 14.5 – 15.5. The increase from 2022 is mainly driven by higher expected CO2 taxes, increased well maintenance activities and general and commodity driven inflation.

The company expects production cost per boe to decrease towards its end-2025 target of approximately USD 8 1 per boe as new cost-effective developments come on stream and effects from improvement programs and strategic partnerships are realised.

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

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. The Company's project portfolio progressed according to plan in the fourth quarter, including developments such as Balder X, Johan Castberg and Breidablikk. Supply chain still imposes challenges to the industry. However, the procurement scope for all key projects in the Vår Energi portfolio has largely been completed with main equipment packages delivered, reducing risk of negative impacts.

Balder X

The project is progressing towards planned first oil in the third quarter of 2024. Project complexity remains a challenge. Several milestones were reached during the quarter and provide a de-risking of the project and confirmation of the revised plan announced in September.

Key deliverables and achievements in the quarter include:

Engineering scope is close to complete
Most equipment packages are delivered at the yard and commissioning progressed to plan.
Key heavy lifts safely completed during the quarter (torsion box, helideck and pedestal cranes)
Construction work has ramped up with increased efficiency and subsea equipment installed on seabed
Drilling operations are ongoing and progressing per plan with four wells completed at year-end. All producing wells are expected to be completed for first oil to support rapid production ramp-up

Johan Castberg

Planned start-up of the Johan Castberg field remains in the fourth quarter of 2024.

Key deliverables and achievements in the quarter include:

Ramp-up of integration activities at Stord according to plan
Subsea and marine campaign completed in November as planned

Breidablikk

The field is planned to start production in the first quarter of 2024.

Key deliverables and achievements in the quarter include:

Drilling operations progressing well ahead of plan
Subsea and marine campaign for 2022 completed on schedule, hardware delivery for 2023 installation campaign progressing on plan
The High Activity Period (HAP) on Grane topside ongoing

Bauge, Hyme and Fenja

The development projects are in the last stages of the execution phase and development drilling is finalised. Production start-up is planned during the first half of 2023.

Key deliverables and achievements in the quarter include:

Njord A platform started production at the end of 2022, prepared for the sequential tie-in of the oil fields
Electrification of the Njord Field to reduce emission decided by the partners in Njord and attached tie-in fields and revised PDO submitted

Exploration

Vår Energi currently holds 158 licenses of which 53 are operated. The Company has a proven exploration track record founded on strong technical competencies and historical expertise on the entire NCS and has an active exploration strategy supported by a large inventory of potential exploration prospects across the NCS portfolio.

During the fourth quarter, Vår Energi confirmed the discovery of gas in the operated Lupa well, adjacent to the Goliat field in the Barents Sea. Preliminary estimates for the size of the discovery are between 57-132 million barrels of recoverable oil equivalents ¹ (9-21 billion Sm³ recoverable gas resources), which makes it the largest discovery on the NCS in 2022.

Vår Energi also participated in the Calypso discovery in PL938 in the Norwegian Sea, operated by Neptune Energy. Preliminary estimates indicate 6-22 million barrels of recoverable oil equivalents. The Othello North well in the Norwegian Sea, operated by Equinor, was dry.

The exploration success rate for the full year was 57% 2 , and added approximately 65 million barrels of recoverable oil equivalents in contingent resources. This confirms Vår Energi's strong exploration capabilities. Three of the four successful wells were drilled in the Barents Sea, where the Company has a leading position and long-term strategic ambition to extend production though infrastructure-led developments.

The planned 2022 exploration drilling campaign also included spudding of the operated Countach well in the Barents Sea and partner-operated well Angulata in PL554. As announced 9 February, Vår Energi confirmed discovery of oil in the Countach well, nearby the Goliat field. A sidetrack is planned to be drilled to better define the size of the discovery. The Angulata well is expected to be concluded during the first quarter.

For 2023, Vår Energi plans to drill eight firm exploration wells and three contingent wells targeting a total of more than 50 mmboe of risked resources. Four of the firm wells are operated by Vår Energi.

The company was in January awarded 12 new production licenses, five of which as operator, in the 2022 Awards in the Predefined Areas (APA) covering mature areas. Most of the licenses are in areas close to existing infrastructure, supporting the company's hub strategy and strengthening the foundation for long-term value creation.

¹ Reported numbers are 100% unrisked recoverable resources ² Technical Success

Health, safety, security and the environment (HSSE)

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

Serious incident frequency (SIF Actual) 1	Per mill. exp. hours	0.1	0.1	0.1	0.1
Serious incident frequency (SIF) 1	Per mill. exp. hours	1.0	1.3	1.4	1.6
Total recordable injury frequency (TRIF) 2	Per mill. exp. hours	3.2	3.7	2.7	2.5
Acute spill	Count	0	0	0	1
Process safety events Tier 1 and 2 3	Count	1	0	0	2
CO2 emissions intensity 4	Kg CO2/boe	10.5	10.4	8.6	7.6

The Company maintains high focus on implementation of its safety initiatives, and the positive trend for the Serious Incidents Frequency (SIF) 1 continued in the fourth quarter. The 12-month rolling average SIF rate was 1.0, an improvement from 1.3 in the third quarter of 2022. None of the incidents in the quarter were classified with serious actual consequences.

The number of recordable injuries, all of which had low actual consequences, was stable in the quarter. The 12-month rolling average Total Recordable Injury Frequency (TRIF) 2 was 3.2 in the fourth quarter, an improvement compared to 3.7 in the third quarter 2022.

The trend is primarily driven by improved safety performance related to yard activities for 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 continue the positive trend. Furthermore, Vår Energi focuses on major accident potential and continuously monitors key indicators through the Company's major accident risk indicator system (MARI).

Vår Energi and its contractors continuously build on the 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).

Decarbonisation and environmental impact

Vår Energi considers the decarbonisation of oil and gas production a prerequisite for a resilient business model and long-term value creation. The Company has committed to reduce its GHG emissions in support of the Paris Agreement and the Konkraft agreement. Vår Energi is also a signatory to the OGCI Aiming for Zero Methane Emissions Initiative aiming to reach near zero methane emissions from operated oil and gas assets by 2030. The Company has started to implement and operationalise its decarbonisation plan, with the electrification of the Balder Area before 2030 as a priority. In parallel, the Company continuously seeks to reduce GHG emissions and has set specific target for 2023.

The CO2 emissions intensity for operated assets in the fourth quarter is estimated to 10.5 kg CO2 per boe, compared to 10.4 kg CO2 per boe in the third quarter. The slight increase is related to high exploration activity in the quarter.

¹ SIF: Serious incident and near-misses per million worked hours, 12 months rolling average. Includes actual and potential consequence. SIF Actual, 12 months rolling average: incidents that have an actual serious consequence.

² TRIF: Personal injuries requiring medical treatment per million worked hours, 12 months rolling average. 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 Classified according to IOGP RP 456.

⁴ 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.

Financial review

Statment of income

USD million	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021
Total income	2 374	2 526	2 274	9 828	6 073
Production costs 1	(345)	(205)	(329)	(1 143)	(1 141)
Exploration expenses	(22)	(12)	(11)	(72)	(57)
Depreciation and amortisation	(332)	(346)	(470)	(1 448)	(1 705)
Impairment loss and reversals	(96)	(573)	(178)	(658)	(1)
Other operating expenses	(47)	(28)	(38)	(138)	(110)
Total operating expenses	(843)	(1 163)	(1 026)	(3 459)	(3 014)
Operating profit / (loss) (EBIT)	1 531	1 363	1 249	6 369	3 059
Net financial income / (expenses)	(19)	(34)	(106)	(116)	(269)
Net exchange rate gain / (loss)	281	(258)	(6)	(397)	(142)
Profit / (loss) before income taxes	1 793	1 071	1 137	5 856	2 647
Income tax (expense) / income	(1 305)	(1 121)	(926)	(4 919)	(1 992)
Profit / (loss) for the period	488	(50)	212	936	654

¹ Production cost in previous periods changed due to restatement of over/underlift (note 1).

Total income (USD million)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021
Petroleum revenues	2 354	2 520	2 282	9 781	6 043
Other operating income	19	7	(7)	47	29
Total income	2 374	2 526	2 274	9 828	6 073

Revenues from sale of petroleum products in the fourth quarter were USD 2 354 million, a decrease of USD 166 million when compared to third quarter of 2022. Lower product prices impacted petroleum revenues negatively by USD 490 million whereas higher volumes sold impacted petroleum revenues positively with USD 324 million.

During the quarter, the Company continued to divert gas from injection and to minimise sale of methanol and ethane to maximise gas sales.

In the fourth quarter, fixed price sales represented 29% of total sales with an average price of 163 USD per boe.

Similarly, Vår Energi has also for the three first quarters of 2023executed fixed price transactions. As per 27 January 2023, the Company has entered into the following transactions (based on the average exchange rates during January 2023):

~33% of the gas production for the first quarter 2023 has been sold on a fixed price basis at an average price of ~285 USD per boe
~22% of the gas production for the second quarter 2023 on a fixed price basis at an average price of ~190 USD per boe
~20% of the gas production for the third quarter 2023 on a fixed price basis at an average price of ~190 USD per boe

Revenue split by petroleum type (USD million)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021

Revenue from crude oil sales	1 092	1 092	990	4 669	3 448
Revenue from gas sales	1 192	1 339	1 184	4 732	2 227
Revenue from NGL sales	70	88	108	379	368
Total petroleum revenues	2 354	2 520	2 282	9 781	6 043

Revenue split by petroleum type (percentage)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021
Revenue from crude oil sales	46%	43%	43%	48%	57%
Revenue from gas sales	51%	53%	52%	48%	37%
Revenue from NGL sales	3%	4%	5%	4%	6%
Total petroleum revenues	100%	100%	100%	100%	100%

Realised prices (USD/boe)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021
Crude oil price	86.6	107.8	80.4	101.7	70.4
Gas price	181.6	203.9	148.3	174.5	79.5
NGL price	54.7	61.8	60.6	65.4	45.0
Average (volume-weighted)	115.1	139.0	103.4	124.1	70.9

USD million	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021

Cost of operations	190	167	216	701	688
Transportation and processing	42	55	59	214	243
Environmental taxes	31	30	34	140	102
Insurance premium	16	11	12	49	46
Production cost based on produced volumes	279	264	320	1 087	1 079
Back-up cost shuttle tankers	8	7	15	19	33
Adjustment of over/(underlift)	49	(74)	(22)	(2)	(32)
Premium expense for crude put options	10	9	16	40	60
Production cost based on sold volumes	345	205	329	1 143	1 141
Total produced volumes (mmboe) (unaudited)	19.7	19.7	23.8	80.3	89.7
Production cost USD/boe produced volumes (unaudited)	14.1	13.4	13.4	13.5	12.0

Production cost

The increase in production cost based on produced volumes compared to the previous quarter was mainly due to more maintenance activities.

Production cost, based on sold volumes, increased by USD 140 million when compared to the previous quarter, mainly due to higher liftings.

Exploration expenses

Exploration cost in fourth quarter was USD 22 million. The increase from the previous quarter is due to higher exploration activity in combination with the expense of dry wells. Exploration expenses in 2022 amounted to USD 72 million, up from USD 57 million when compared to 2021.

Depreciation, depletion, amortisation (DD&A)

DD&A in fourth quarter was USD 332 million (-4%) compared to USD 346 million in previous quarter. DD&A in 2022 amounted to USD 1 448 million, down from USD 1 705 million when compared to the same period in 2021 mainly due to lower production.

Impairment losses and reversals

The impairment loss of USD 96 million in the quarter is related Balder, Brage and Morvin. For more details, see note 11 in the financial statements.

Net finance

Net exchange rate gain amounted to USD 281 million in the quarter, consisting of a realised loss of USD 278 million and USD 559 million of unrealised exchange rate gains related to the Company's interest-bearing loans. For more details, see note 6 in the financial statements.

Tax

The income tax in the fourth quarter was USD 1 305 million, an increase of USD 184 million from third quarter. Tax rate for full year 2022 increased to 84% compared to 75% in 2021 due to changes in tax legislation giving less tax uplift.

Profit for the period

Net income of USD 488 million in the period was positively impacted by an exchange rate gain due to strengthening of the NOK in the period.

Condensed statement of financial position

Financial position (USD million)	31 Dec 2022	30 Sep 2022	31 Dec 2021

Intangible assets	2 338	2 086	2 836
Tangible fixed assets	14 738	12 907	15 487
Financial assets	1	1	3
Current assets	1 720	2 671	1 473
Total assets	18 797	17 665	19 799
Total equity	1 482	1 166	1 516
Non-current liabilities	14 007	12 961	16 062
Current liabilities	3 309	3 539	2 221
Total liabilities	17 316	16 500	18 283
Total Equity and Liabilities	18 797	17 665	19 799

Available liquidity	31 Dec 2022	30 Sep 2022	31 Dec 2021
Cash and cash equivalents	445	1 499	224
RCF	3 600	3 600	2 080
Available liquidity	4 045	5 099	2 304

Total assets at the end of the fourth quarter amounted to USD 18 797 million, an increase from USD 17 665 million at the end of the third quarter due to high capex spend and a stronger NOK to USD when converting to reporting currency.

Tangible fixed assets including property, plant and equipment (PP&E) were USD 14 738 million and movements are detailed in note 9 in the financial statement.

Total equity amounted to USD 1 482 million, corresponding to an equity ratio of ~8%.

Total cash and cash equivalents at the end of the fourth quarter were USD 445 million. The Company had USD 3 600 million in undrawn credit facilities bringing total available liquidity to USD 4 045 million, at the end of the period.

Available liquidity

USD million

NIBD/EBITDAX

Interest-bearing debt

Total interest-bearing debt (incl. leasing) at end of fourth quarter was USD 3 165 million, a decrease of USD 390 million compared to previous period.

EBITDAX was USD 1 981 million in the quarter and free cash flow (FCF) was negative USD 356 million.

Due to a negative cash flow generated the Company increased its leverage ratio (NIBD including leasing/EBITDAX) to 0.3x at the end of the quarter, up from 0.2x at the end of the previous quarter.

Interest bearing debt excl. leasing (x)	31 Dec 2022	30 Sep 2022	31 Dec 2021

Adjusted total interest bearing debt / EBITDAX	0.3	0.4	1.0
Net interest-bearing debt / EBITDAX	0.3	0.2	1.0

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

Interest-bearing loans and borrowings	2 453	2 977	4 493
Interest-bearing loans, current	500	348	333
Lease liabilities, non-current	113	130	216
Lease liabilities, current	99	99	109
Adjusted total interest bearing debt	3 165	3 555	5 152
Cash and cash equivalents	445	1 499	224
Adjusted NIBD	2 721	2 056	4 928
EBITDAX 4 quarters rolling	8 547	8 473	4 821
Adjusted total interest-bearing debt / EBITDAX	0.4	0.4	1.1
Net interest-bearing debt / EBITDAX	0.3	0.2	1.0

Total interest-bearing debt (TIBD)

Condensed statement of cash flow

Cash flow from operating activities before tax USD million

Statements of cash flows (USD million)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021

Cash flow from operating activities (CFFO)	443	1 503	951	5 682	4 580
Cash flows used in investing activities	(814)	(603)	(722)	(2 663)	(2 633)
Cash flows from financing activities	(753)	(310)	(246)	(2 903)	(1 976)
Net change in cash and cash equivalents	(1 124)	591	(17)	115	(29)
Cash and cash equivalents, beginning of period	1 499	892	264	224	272
Effect of exchange rate fluctuation on cash held	70	16	(24)	106	(20)
Cash and cash equivalents, end of period	445	1 499	223	445	223

Higher taxes paid, the payment to Exxon and increased capital expenditures reduced the cash flow compared to the previous quarter.

8 369

Condensed statement of cash flow – continued

Cash flows used in investing activities (USD million)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021

Expenditures on exploration and evaluation assets	47	3	7	77	104
Expenditures on property, plant and equipment	753	596	703	2 516	2 480
Payment for decommissioning of oil and gas fields	15	4	14	70	70
Proceeds from sale of assets (sales price)	-	(0)	(4)	(0)	(24)
Expenditures on goodwill and other intangible assets	-	-	0	-	0
Net cash used on business combination	-	-	2	-	2
Total cash flows used in investing activities	814	603	722	2 663	2 633

Expenditures in the Balder Area, Johan Castberg and Grane totalled 65% of total expenditures on PP&E.

Expenditures on PP&E (USD million, %)	Q4 2022	Q4 2022	Q3 2022	Q3 2022	Q4 2021	Q4 2021	FY 2022	FY 2022

Balder area	333	44%	230	39%	341	49%	1 078	43%
Johan Castberg	79	11%	79	13%	91	13%	324	13%
Fenja	10	1%	22	4%	45	6%	81	3%
Grane	75	10%	79	13%	37	5%	261	10%
Snorre	35	5%	30	5%	26	4%	120	5%
Statfjord area	29	4%	27	5%	23	3%	119	5%
Sleipner area	2	-	1	-	20	3%	8	0%
Ekofisk area	25	3%	25	4%	20	3%	97	4%
Goliat	10	1%	26	4%	15	2%	62	2%
Tommeliten	11	1%	8	1%	13	2%	35	1%
Other	145	19%	69	12%	72	10%	333	13%
Total expenditures on PP&E	753	100%	596	100%	703	100%	2 516	100%

Condensed statement of cash flow – continued

Capex coverage	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021
Expenditures on exploration and evaluation assets	47	3	7	77	104
Expenditures on PP&E	753	596	703	2 516	2 480
Capex 1	800	599	710	2 593	2 585
CFFO	443	1 503	951	5 682	4 580
Capex coverage (x)	0.6	2.5	1.3	2.2	1.8

Cash flows from financing activities
(USD million)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021

Dividends paid	(290)	(260)	(262)	(775)	(950)
Net proceeds from bond issue	1 967	-	-	2 464	-
Net proceeds / (payments) of revolving credit facility	(2 000)	-	4 494	(4 021)	4 494
Net proceeds / (payments) of reserve based lending facility	-	-	(4 440)	-	(5 335)
Payment of other loans and borrowings	(300)	-	-	(300)	-
Payment of principal portion of lease liability	(26)	(28)	(10)	(110)	(44)
Interest paid	(104)	(22)	(27)	(161)	(141)
Total cash flows used in investing activities	(753)	(310)	(246)	(2 903)	(1 976)

Net cash outflow from financing activities amounted to USD 753 million mainly related to dividends paid and final payment to Exxon in the quarter.

Outlook

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

The Company's production guidance for 2023 is in the range of 210-230 kboepd.

For 2023, the Company expects development capex between USD 2 400–2 700 million and USD 200 million in exploration capex and USD 50 million in abandonement capex.

Vår Energi's material cash flow generation and investment-grade balance sheet support attractive and resilient distributions. For the first quarter

of 2023, Vår Energi plans to pay a dividend of USD 270 million.

Vår Energi plans to distribute 20-30% of CFFO after tax over the cycle in shareholder returns. For 2023, the dividend is planned to be approximately 30% of CFFO after tax.

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 Financial Statement.

Subsequent events

See note 24 in the Financial Statement.

Risks and uncertainty

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

The ripple effects of Russia's invasion of Ukraine, European energy crisis, US and EU monetary tightening causing economic slowdown and global inflation impacts market and financial risk, including, but 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.

The company's operational, financial, strategic and compliance risks and the mitigation of these risks are described in the prospectus published in February 2022 and the 2021 annual report, both available on www.varenergi.no

Alternative performance measures (APMs)

In this interim report, in order to enhance the understanding of the company'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 company'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

USD million	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021
Profit / (loss) for the period	488	(50)	212	936	654
Income tax (expense) / income	(1 305)	(1 121)	(926)	(4 919)	(1 992)
Net financial income / (expenses)	(19)	(34)	(106)	(116)	(269)
Net exchange rate gain / (loss)	281	(258)	(6)	(397)	(142)
Depreciation and amortisation	(332)	(346)	(470)	(1 448)	(1 705)
Impairment loss and reversals	(96)	(573)	(178)	(658)	(1)
EBITDA	1 960	2 281	1 897	8 475	4 764
Exploration expenses	(22)	(12)	(11)	(72)	(57)
EBITDAX	1 981	2 293	1 908	8 547	4 821
Total income	2 374	2 526	2 274	9 828	6 073
EBITDA margin	83%	90%	83%	86%	78%
EBITDAX margin	83%	91%	84%	87%	79%

Financial statements with note disclosures

Unaudited financial statements

Unaudited statement of comprehensive income		24	Note 10 Right of use assets	41
Unaudited balance sheet statement		25	Note 11 Impairment	42
	Unaudited statement of changes in equity	27	Note 12 Trade receivables	45
			Note 13 Other current receivables and financial assets	45
	Unaudited statement of cash flows	28	Note 14 Financial instruments	46
Notes		30	Note 15 Cash and cash equivalents	47
Note 1	Summary of IFRS accounting principles and restatements	31	Note 16 Share capital and shareholders	47
Note 2	Income	33	Note 17 Financial liabilities and borrowings	48
Note 3	Production costs	34	Note 18 Asset retirement obligations	49
Note 4	Other operating expenses	35	Note 19 Other current liabilities	49
Note 5	Exploration expenses	35	Note 20 Commitments, provisions and contingent consideration	49
Note 6	Financial items	36	Note 21 Lease agreements	50
Note 7	Income taxes	37	Note 22 Related party transactions	51
Note 8	Intangible assets	39	Note 23 License ownerships	52
Note 9	Tangible assets	40	Note 24 Subsequent events	53

Unaudited statement of comprehensive income

USD 1000, except earnings per share data	Note	Q4 2022	Restated Q3 2022	Restated Q4 2021	FY 2022	Restated FY 2021

Petroleum revenues	2	2 354 471	2 519 830	2 281 923	9 780 543	6 043 375
Other operating income	2	19 479	6 614	(7 495)	47 088	29 357
Total income		2 373 951	2 526 443	2 274 428	9 827 630	6 072 732
Production costs	1, 3	(345 223)	(204 896)	(329 027)	(1 143 139)	(1 141 021)
Exploration expenses	5, 8	(21 660)	(11 897)	(11 338)	(72 063)	(57 138)
Depreciation and amortisation	9, 10	(332 433)	(345 503)	(469 501)	(1 447 966)	(1 704 561)
Impairment loss and reversals	8, 9, 11	(96 255)	(572 531)	(178 482)	(657 922)	(982)
Other operating expenses	4	(47 236)	(28 459)	(37 514)	(137 721)	(110 483)
Total operating expenses		(842 807)	(1 163 286)	(1 025 863)	(3 458 811)	(3 014 186)
Operating profit / (loss)		1 531 144	1 363 157	1 248 566	6 368 820	3 058 546
Net financial income / (expenses)	6	(19 424)	(34 324)	(105 749)	(115 889)	(269 489)
Net exchange rate gain / (loss)	6	281 461	(258 099)	(5 623)	(397 039)	(142 371)
Profit/(loss) before taxes		1 793 181	1 070 734	1 137 194	5 855 891	2 646 687
Income tax (expense) / income	1, 7	(1 305 149)	(1 120 796)	(925 638)	(4 919 489)	(1 992 331)
Profit / (loss) for the period		488 032	(50 061)	211 556	936 402	654 356
Other comprehensive income:
Items that may be reclassified subsequently to the income statement:
Currency translation differences		120 587	(107 350)	(9 486)	(196 722)	(63 113)
Net gain / (loss) on put options used for hedging		(3 830)	(5 068)	8 884	(1 338)	6 919
Other comprehensive income for the period, net of tax		116 757	(112 418)	(602)	(198 060)	(56 194)
Total comprehensive income		604 789	(162 479)	210 955	738 342	598 162
Earnings per share
EPS Basic	1, 16	0.20	(0.02)	0.08	0.38	0.26
EPS Diluted	1, 16	0.20	(0.02)	0.08	0.38	0.26

Unaudited balance sheet statement

			Restated	Restated
USD 1000	Note	31 Dec 2022	30 Sep 2022	31 Dec 2021
ASSETS
Non-current assets
Intangible assets
Goodwill	8	2 019 512	1 835 231	2 531 897
Capitalised exploration wells	8	225 287	166 028	199 981
Other intangible assets	8	93 515	84 901	104 520
Tangible fixed assets
Property, plant and equipment	9	14 562 237	12 725 525	15 188 917
Right of use assets	10	175 423	181 183	298 432
Financial assets
Investment in shares		763	693	853
Other non-current assets		532	729	1 809
Total non-current assets		17 077 268	14 994 290	18 326 409

Current assets
Inventories		265 811	273 522	301 329
Trade receivables	12, 22	796 317	677 804	745 921
Other current receivables and financial assets	1, 13	213 286	220 842	201 809
Cash and cash equivalents	15	444 607	1 499 006	223 588
Total current assets		1 720 020	2 671 174	1 472 647

TOTAL ASSETS		18 797 288	17 665 464	19 799 056

Unaudited balance sheet statement – continued

USD 1000	Note	31 Dec 2022	Restated 30 Sep 2022	Restated 31 Dec 2021		Sandnes, 15 February 2023 Signed Electronically
EQUITY AND LIABILITIES
Equity
Share capital	16	45 972	45 972	45 972	Thorhild Widvey	Liv Monica Bargem Stubholt
Share premium		1 868 181	2 158 181	2 643 181	Chair	Deputy Chair
Other equity	1	(432 582)	(1 038 519)	(1 173 324)
Total equity		1 481 571	1 165 633	1 515 828	Francesco Gattei	Guido Brusco
					Director	Director
Non-current liabilities
Interest-bearing loans and borrowings	17	2 452 589	2 977 073	4 493 426
Deferred tax liabilities	7, 1	8 127 971	6 968 812	7 953 676	Clara Andreoletti	Marica Calabrese
Asset retirement obligations	18	3 156 126	2 738 078	3 235 640	Director	Director
Lease liabilities, non-current	21	113 334	130 417	216 208
Other non-current liabilities		156 544	146 378	162 870	Fabio Romeo	Ove Gusevik
Total non-current liabilities		14 006 564	12 960 759	16 061 820	Director	Director
Current liabilities
Asset retirement obligations, current	18	60 012	13 390	61 536	Martha Skjæveland	Hege Susanne Blåsternes
Accounts payables	22	368 589	313 620	422 155	Director,	Director,
Taxes payable	7	1 778 222	2 378 317	801 432	employee representative	employee representative
Interest-bearing loans, current	17	500 000	348 276	333 149
Lease liabilities, current	21	99 312	98 974	108 880	Bjørn Nysted	Jan Inge Nesheim
Other current liabilities	1, 19	503 019	386 493	494 256	Director,	Director,
Total current liabilities		3 309 154	3 539 072	2 221 408	employee representative	employee representative
Total liabilities		17 315 718	16 499 831	18 283 228
						Torger Rød
TOTAL EQUITY AND LIABILITIES		18 797 288	17 665 464	19 799 056		Chief Executive Officer

Unaudited statement of changes in equity

				Other equity
					Translation
USD 1000	Note	Share capital	Share premium	Other equity	differences	Hedge reserve	Total equity
Balance at 1 January 2021 before restatement		45 972	3 593 181	(1 595 366)	(160 173)	(28 737)	1 854 877
Impact of restatement	1	-	-	11 040	639	-	11 679
Balance at 1 January 2021 after restatement		45 972	3 593 181	(1 584 326)	(159 534)	(28 737)	1 866 556
Profit / (loss) for the period		-	-	654 356	-	-	654 356
Other comprehensive income / (loss)		-	-	-	(63 113)	6 919	(56 194)
Total comprehensive income / (loss)		-	-	654 356	(63 113)	6 919	598 162
Dividends paid		-	(950 000)	-	-	-	(950 000)
Other		-	-	1 111	-	-	1 111
Balance at 31 December 2021		45 972	2 643 181	(928 860)	(222 647)	(21 818)	1 515 828
Profit / (loss) for the period		-	-	448 371	-	-	448 371
Other comprehensive income / (loss)		-	-	-	(317 309)	2 491	(314 818)
Total comprehensive income / (loss)		-	-	448 371	(317 309)	2 491	133 553
Dividends paid		-	(485 000)	-	-	-	(485 000)
Share-based payments		-	-	1 252	-	-	1 252
Balance at 30 September 2022		45 972	2 158 181	(479 237)	(539 956)	(19 326)	1 165 633
Profit / (loss) for the period		-	-	488 032	-	-	488 032
Other comprehensive income / (loss)		-	-	-	120 587	(3 830)	116 757
Total comprehensive income / (loss)		-	-	488 032	120 587	(3 830)	604 789
Dividends paid		-	(290 000)	-	-	-	(290 000)
Share-based payments	16	-	-	1 148	-	-	1 148
Balance at 31 December 2022		45 972	1 868 181	9 943	(419 369)	(23 156)	1 481 571

Unaudited statement of cash flows

USD 1000	Note	Q4 2022	Restated Q3 2022	Restated Q4 2021	FY 2022	Restated FY 2021
Profit / (loss) before income taxes	1	1 793 181	1 070 734	1 137 137	5 855 891	2 646 687
Adjustments to reconcile profit before tax to net cash flows:
- Depreciation and amortisation	9, 10	332 433	345 503	469 501	1 447 966	1 704 561
- Impairment loss and reversals	8, 9	96 255	572 531	178 482	657 922	982
- (Gain) / loss on sale and retirement of assets	2	32 021	(300)	16 871	31 721	(2 232)
- Impairment of exploration wells	5, 8	5 194	2 276	(2 260)	30 600	5 887
- Accretion expenses (asset retirement obligation)	6, 18	24 366	23 519	26 140	94 243	94 733
- Unrealised (gain) / loss on foreign currency transactions and balances	6	(559 643)	286 807	339 470	81 175	558 940
- Other non-cash items and reclassifications		303 067	(75 477)	(251 824)	299 499	(161 069)
Working capital adjustments:		-		-		-
- Changes in inventories, accounts payable and receivables		(33 076)	(221 106)	(384 836)	(155 346)	(437 761)
- Changes in other current balance sheet items	13, 19	99 907	22 880	(5 576)	25 059	34 734
Contingent consideration paid related to prior business combination	19	-	-	-	-	(30 000)
Income tax received / (paid)	7	(1 650 439)	(524 208)	(572 400)	(2 686 852)	164 439
Net cash flows from operating activities		443 265	1 503 160	950 705	5 681 877	4 579 902
Cash flows from investing activities
Expenditures on exploration and evaluation assets	8	(46 969)	(2 734)	(6 930)	(77 050)	(104 318)
Expenditures on property, plant and equipment	9	(752 623)	(596 313)	(702 632)	(2 516 097)	(2 480 298)
Payment for decommissioning of oil and gas fields	18	(14 814)	(3 879)	(13 865)	(70 318)	(70 418)
Proceeds from sale of assets (sales price)		-	300	3 829	300	24 398
Expenditures on goodwill and other intangible assets		-	-	(295)	-	(295)
Net cash used on business combination		-	-	(2 208)	-	(2 208)
Net cash used in investing activities		(814 407)	(602 626)	(722 101)	(2 663 165)	(2 633 140)

Unaudited statement of cash flows – continued

USD 1000	Note	Q4 2022	Restated Q3 2022	Restated Q4 2021	FY 2022	Restated FY 2021
Cash flows from financing activities
Dividends paid		(290 000)	(260 000)	(262 000)	(775 000)	(950 000)
Net proceeds from bond issue		1 966 617	-	-	2 463 523	-
Net proceeds/(payments) of revolving credit facilities	17	(2 000 000)	-	4 494 104	(4 020 500)	4 494 104
Net proceeds/(payments) of reserve based lending facility	17	-	-	(4 440 000)	-	(5 335 000)
Payment of other loans and borrowings	17	(300 000)	-	-	(300 000)	-
Payment of principal portion of lease liability	21	(25 570)	(27 719)	(10 482)	(110 447)	(43 790)
Interest paid	1	(104 122)	(21 952)	(28 221)	(160 803)	(141 532)
Net cash from financing activities		(753 075)	(309 672)	(246 599)	(2 903 227)	(1 976 218)
Net change in cash and cash equivalents		(1 124 217)	590 862	(17 995)	115 485	(29 456)
Cash and cash equivalents, beginning of period		1 499 006	- 892 046	263 671	223 588	272 411
Effect of exchange rate fluctuation on cash held		69 818	16 098	(22 088)	105 534	(19 367)
Cash and cash equivalents, end of period		444 607	1 499 006	223 588	444 607	223 588

Notes

(All figures in USD 1000 unless otherwise stated)

The interim condensed financial statements for the period ended 31 December 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 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.

Restructuring of subsidiaries directly or indirectly owned by Vår Energi ASA took place during 4Q 2022. Dividends were paid to Vår Energi ASA which reduced investments in subsidiaries to zero. There are no business activities in the two remaining subsidiaries as of 31 December 2022. The balance sheets of the subsidiaries holds tax positions of USD 31 225 thousand which are offset by receivables towards Vår Energi ASA.

Based on the materiality of the subsidiaries, the financial statements for 4Q 2022 are Vår Energi ASA with no restatement of the comparative periods.

The following table shows the group structure per 31 December 22.

Shares in subsidiaries

Name	Business location	Voting/ownership
Vår Energi Marine AS	Sandnes, Norway	100%
PR Jotun DA	Sandnes, Norway	5%

Shares in subsidiaries indirectly owned

Name	Business location	Voting/ownership
PR Jotun DA	Sandnes, Norway	95%

These interim financial statements were authorised for issue by the company's Board of Directors on 15 February 2023.

Note 1 Summary of IFRS accounting principles and restatements

The accounting principles adopted in the preparation of the interim condensed financial statements are consistent with those followed in the preparation of the annual financial statements for the year ended 31 December 2021, except for a change in presentation of payment of borrowing costs in the statement of cash flows as reported in the Q2 2022 Financial Statement and change in accounting principles for over/underlift from Q4 2022. Vår Energi 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, Vår Energi 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 Vår Energi'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 comparison periods is included in the following table.

USD 1000
Restating impact on Statement of Cash Flow	Q4 2021	FY 2021
Net cash flows from operating activities
Before restatement	922 484	4 438 371
Impact of restatement	28 221	141 532
After restatement	950 705	4 579 902

Net cash from financing activities
Before restatement	(218 378)	(1 834 686)
Impact of restatement	(28 221)	(141 532)
After restatement	(246 599)	(1 976 218)

Note 1 Summary of IFRS accounting principles and restatements – continued

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

Effective from 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.

Restatement of over/underlift due to change in accounting principles

Effecting from fourth quarter 2022, Vår Energi has elected to change its accounting policy for measurement of overlift to measure both over/underlift at cost as we believe this will provide more relevant information about financial performance and financial position of the Company. In addition, this change will also make Vår Energi more comparable to peer companies on the NCS. In prior reporting periods, the overlift was recognised for the fair value / sale price while the underlift was valued at the lower of production cost and sale price.

USD 1000 Restating impact on Balance Sheet Statement	Note	01 Jan 2021	31 Dec 2021	30 Sep 2022
Underlift before restatement		142 257	189 105
Impact of restatement		(67 948)	(78 888)
Underlift after restatement	13	74 309	110 217
Overlift before restatement		166 175	317 606	60 661
Impact of restatement 1		(121 033)	(276 429)	(38 176)
Overlift after restatement	19	45 142	41 177	22 485
Equity before restatement		1 854 877	1 472 369	1 157 234
Impact of restatement 1		11 679	43 459
Equity after restatement		1 866 556	1 515 828	1 165 633
Deferred tax before restatement		7 342 952	7 799 594	6 939 035
Impact of restatement 1		41 407	154 082	29 778
Deferred tax after restatement	7	7 384 359	7 953 676	6 968 812

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

Adjustment of (over)/under lift before restatement		164 635	9 053	(116 947)
Impact of restatement 1		(90 417)	13 240	148 960
Adjustment of (over)/under lift after restatement	3	74 219	22 293	32 013

Income tax (expense) / income before restatement		(1 191 320)	(915 311)	(1 876 143)
Impact of restatement 1		70 525	(10 327)	(116 188)
Income tax (expense) / income after restatement	7	(1 120 796)	(925 638)	(1 992 331)

¹ Impact of restatement include both NGL correction and change in accounting policy for measurement of overlift.

Note 2 Income

Petroleum revenues (USD 1000)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021
Revenue from crude oil sales	1 092 302	1 092 481	990 270	4 669 095	3 448 157
Revenue from gas sales	1 191 916	1 339 028	1 183 799	4 732 282	2 227 332
Revenue from NGL sales	70 254	88 321	107 853	379 166	367 885
Total petroleum revenues	2 354 471	2 519 830	2 281 923	9 780 543	6 043 375

Sales of crude (boe 1000)	12 614	10 133	12 315	45 923	49 006
Sales of gas (boe 1000)	6 565	6 567	7 984	27 115	28 011
Sales of NGL (boe 1000)	1 285	1 428	1 780	5 796	8 180

Other operating income (USD 1000)	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021

Gain/(loss) from sale of assets	-	300	(16 871)	300	2 232
Other operating income	19 479	6 314	9 376	46 788	27 125
Total other operating income	19 479	6 614	(7 495)	47 088	29 357

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

Increase of other operating income in Q4 2022 mainly reflect final settlement with ExxonMobil related to the 2019 business combination.

Note 3 Production costs

USD 1000	Note	Q4 2022	Restated Q3 2022	Restated Q4 2021	FY 2022	Restated FY 2021

Cost of operations		189 924	167 334	215 606	701 441	688 120
Transportation and processing		42 169	54 761	58 530	213 551	243 150
Environmental taxes		30 714	30 074	33 822	122 988	101 658
Insurance premium		15 872	11 443	11 800	48 786	46 466
Production cost based on produced volumes		278 679	263 613	319 758	1 086 766	1 079 394

Back-up cost shuttle tankers		7 959	6 650	15 290	19 245	33 148
Changes in over/(underlift)	1	48 774	(74 219)	(22 293)	(2 411)	(32 013)
Premium expense for crude put options	14	9 810	8 852	16 272	39 540	60 492
Production cost based on sold volumes		345 223	204 896	329 027	1 143 139	1 141 021

Total produced volumes (boe 1000)		19 718	19 737	23 788	80 319	89 732
Production cost per boe produced (USD/boe)		14.1	13.4	13.4	13.5	12.0

The changes in over/(underlift) are due to timing of liftings vs. production.

Note 4 Other operating expenses

USD 1000	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021

R&D expenses	(3 963)	9 485	10 799	31 535	32 183
Pre-production costs	7 558	5 206	6 027	24 761	20 612
Guarantee fee decommissioning obligation	3 686	6 863	5 476	22 190	22 138
Administration expenses	7 051	6 906	10 733	26 331	26 499
Other expenses	32 905	-	4 479	32 905	9 051
Total other operating expenses	47 236	28 459	37 514	137 721	110 483

Other expenses include disposal of the Brasse licences in Q4 2022. R&D expenses in Q4 2022 include an adjustment related to prior 2022 quarters.

Note 5 Exploration expenses

USD 1000	Note	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021
Seismic		2 756	1 366	517	4 741	2 989
Area Fee		1 778	2 069	2 495	7 861	9 762
Dry well expenses	8	5 194	2 276	(2 260)	30 600	5 887
Other exploration expenses		11 932	6 185	10 586	28 861	38 501
Total exploration expenses		21 660	11 897	11 338	72 063	57 138

Dry well expenses in 2022 are mainly related to the wells PL901 7122/6-3 S Rødhette, PL209 6305/5-C-3 H Ormen Lange Deep, the 34/4-18 S Statfjord Kile Well and the PL124 6507/8-11 Othello North.

Note 6 Financial items

USD 1000	Note	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021
Other financial income		6 240	2 929	4 954	10 011	14 043
Interests on debts and borrowings	17	(51 387)	(35 378)	(30 151)	(129 782)	(143 462)
Interest on lease debt		(2 162)	(1 992)	(2 646)	(9 312)	(7 819)
Capitalised interest cost, development projects		62 041	27 865	9 498	130 974	49 034
Amortisation of fees and expenses		(8 324)	(2 513)	(58 416)	(17 801)	(73 495)
Accretion expenses (asset retirement obligation)	18	(24 366)	(23 519)	(26 140)	(94 243)	(94 733)
Other financial expenses		(1 465)	(1 716)	(2 847)	(5 737)	(13 056)
Net financial income / (expenses)		(19 424)	(34 324)	(105 749)	(115 889)	(269 489)
Unrealised exchange rate gain / (loss)		559 643	(286 807)	(339 470)	(81 175)	(558 940)
Realised exchange rate gain / (loss)		(278 181)	28 709	333 847	(315 864)	416 570
Net exchange rate gain / (loss)		281 461	(258 099)	(5 623)	(397 039)	(142 371)
Net financial items		262 038	(292 423)	(111 372)	(512 929)	(411 859)

Increase of capitalised interest cost in Q4 2022 is mainly due to increased interest rate after refinancing in November 2022 with USD 2 000 million in bond financing.

Vår Energi's functional currency is NOK, whilst interest bearing loans and bonds are in USD. A down payment of USD 2 000 million on the bridge facility was completed in Q4 2022 causing a realised exchange rate loss of USD 232 million. Due to strengthening of NOK vs. USD exchange rate during 4Q 2022, significant unrealised foreign exchange gains were recognised in the period, mainly related to the loans and bonds in USD.

Note 7 Income taxes

USD 1000	Q4 2022	Restated Q3 2022	Restated Q4 2021	FY 2022	Restated FY 2021
Current period tax payable / (receivable)	849 850	1 063 507	818 767	3 851 161	1 147 119
Prior period adjustments to current tax	12 891	238	14 620	20 828	15 917
Current tax expense / (income)	862 741	1 063 745	833 387	3 871 989	1 163 036

Deferred tax expense / (income)	442 408	57 050	92 251	1 047 499	829 295
Tax expense / (income) in profit and loss	1 305 149	1 120 796	925 638	4 919 489	1 992 331
Effective tax rate in %	73%	105%	81%	84%	75%
Tax expense / (income) in put option used for hedging	(1 065)	529	2 535	(341)	1 965
Tax expense / (income) in other comprehensive income	1 304 085	1 121 324	928 172	4 919 148	1 994 296

Reconciliation of tax expense	Tax rate	Q4 2022	Restated Q3 2022	Restated Q4 2021	FY 2022	Restated FY 2021
Marginal (78%) tax rate on profit / loss before tax	78%	1 398 753	835 215	887 011	4 567 829	2 064 416
Tax effect of uplift	71.8%	(63 676)	(49 478)	(106 926)	(211 687)	(377 467)
Impairment of goodwill	78%	1 494	182 528	129 679	184 022	158 388
Tax effects of items taxed at other than marginal (78%) tax rate 1	56%	(59 302)	146 591	(5 888)	314 393	136 792
Tax effects of new legislation on other items 2		30 404	-	-	50 885	-
Other permanent differences, prior period adjustments and change in estimates of uncertain tax positions	78%	(2 523)	5 939	21 761	14 047	10 202
Tax expense / (Income)		1 305 149	1 120 796	925 638	4 919 489	1 992 331

¹ The effects of items taxed at other than marginal (78%) tax rate are mainly impacted by fluctuation in currency exchange rate on the company's external borrowings and working capital.

² Tax effects in the fourth quarter of USD 30.4 million related to an updated valuation allowance for lack of statutory tax deduction at effective rate 6.204% related to abandonment without anticipated tax shield.

Note 7 Income taxes – continued

Deferred tax asset / (liability)	Q4 2022	Restated Q3 2022	Restated Q4 2021	FY 2022	Restated FY 2021

Deferred tax asset / (liability) at beginning of period	(6 968 812)	(7 547 947)	(7 899 008)	(7 953 676)	(7 384 359)
Current period deferred tax income / (expense)	(442 408)	(57 050)	(92 251)	(1 047 499)	(829 295)
Deferred taxes recognised directly in OCI or equity	1 065	(529)	(2 535)	341	(1 965)
Currency translation effects	(717 815)	636 714	40 117	872 864	261 944
Net deferred tax asset / (liability) as of closing balance	(8 127 971)	(6 968 812)	(7 953 676)	(8 127 971)	(7 953 676)

Calculated tax (payable) / receivable	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021

Tax (payable) / receivable at beginning of period	(2 378 317)	(2 033 759)	(549 890)	(801 432)	506 349
Current period payable taxes	(849 850)	(1 063 507)	(818 767)	(3 851 161)	(1 147 119)
Payable taxes related to business combinations	-	-	969	-	969
Net tax payment / (tax refund)	1 650 439	524 208	572 400	2 686 852	(164 439)
Prior period adjustments and change in estimate of uncertain tax positions	(12 891)	(238)	(14 620)	(20 828)	(15 917)
Currency translation effects	(187 602)	194 979	8 476	208 347	18 726
Net tax (payable) / receivable as of closing balance	(1 778 222)	(2 378 317)	(801 432)	(1 778 222)	(801 432)

Note 8 Intangible assets

USD 1000	Goodwill	Other intangible 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 October 2022		4 069 097	84 901	166 028	4 320 026
Additions	-	-	30 081	30 081	Additions		-	-	46 969	46 969
Disposals / expensed exploration wells	-	-	(25 406)	(25 406)	Disposals / expensed exploration wells	5	-	-	(5 194)	(5 194)
Currency translation effects	(940 293)	(19 619)	(38 627)	(998 539)	Currency translation effects		412 842	8 614	17 483	438 938
Cost as at 30 September 2022	4 069 097	84 901	166 028	4 320 026	Cost as at 31 December 2022		4 481 939	93 515	225 287	4 800 740

Depreciation and impairment as at 1 January 2022	(2 477 492)	-	-	(2 477 492)	Depreciation and impairment as 1 October 2022		(2 233 866)	-	-	(2 233 866)
Provision for impairment reversal / (loss)	(233 998)	-	-	(233 998)	Impairment loss	11	(1 916)	-	-	(1 916)
Currency translation effects	477 625	-	-	477 625	Currency translation effects		(226 645)	-	-	(226 645)
Depreciation and impairment as at 30 September 2022	(2 233 866)	-	-	(2 233 866)	Depreciation and impairment as at 31 December 2022		(2 462 426)	-	-	(2 462 426)
Net book value as at 30 September 2022	1 835 231	84 901	166 028	2 086 160	Net book value as at 31 December 2022		2 019 512	93 515	225 287	2 338 314

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

Note 9 Tangible assets

		Wells and production	Facilities under con	Other property, plant and
USD 1000	Note	facilities	struction	equipment	Total
Cost as at 1 January 2022		14 617 577	5 113 429	39 350	19 770 356
Additions		417 630	1 334 316	11 528	1 763 474
Estimate change asset retirement cost	18	90 878	-	-	90 878
Reclassification		78 428	(23 576)	-	54 852
Currency translation effects		(2 842 257)	(1 130 685)	(8 838)	(3 981 780)
Cost as at 30 September 2022		12 362 256	5 293 484	42 040	17 697 779

Depreciation and impairment as at 1 January 2022		(4 567 768)	-	(13 671)	(4 581 439)
Depreciation		(1 085 320)	-	(5 786)	(1 091 106)
Impairment reversal / (loss)		(327 669)	-	-	(327 669)
Currency translation effects		1 024 639	-	3 321	1 027 960
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

Capitalised interests for facilities under construction were USD 28 172 thousand in third quarter and USD 60 606 thousand in fourth quarter 2022.

Rate used for capitalisation of interests was 2.4% in third quarter 2022 and 3.8% in the fourth 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 in UOP-depreciation rates are limited with increased total proved reserves of 0.7%.

Capital spares of USD 41 652 thousand were in 4Q 2022 reclassified from inventory to PP&E due to change in accounting policy.

USD 1000	Note	Wells and production facilities	Facilities under construction	Other property, plant and equipment	Total

Cost as at 1 October 2022		12 362 256	5 293 484	42 040	17 697 779
Additions		247 386	498 275	6 962	752 623
Estimate change asset retirement cost	18	175 503	-	-	175 503
Reclassification		65 272	(5 467)	-	59 805
Disposals		-	(32 021)	-	(32 021)
Currency translation effects		1 259 882	553 237	4 585	1 817 703
Cost as at 31 December 2022		14 110 298	6 307 507	53 587	20 471 393

Depreciation and impairment as at 1 October 2022		(4 956 118)	-	(16 136)	(4 972 254)
Depreciation		(323 543)	(74)	(3 394)	(327 011)
Impairment reversal / (loss)	11	(94 339)	-	-	(94 339)
Currency translation effects		(513 814)	1	(1 738)	(515 551)
Depreciation and impairment as at 31 December 2022		(5 887 814)	(73)	(21 268)	(5 909 156)

Net book value as at 31 December 2022		8 222 484	6 307 434	32 319	14 562 237

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	-	(54 852)	-	(54 852)
Currency translation effects	(18 807)	(49 374)	331	(67 850)
Cost as at 30 September 2022	61 104	202 552	13 877	277 533

Depreciation and impairment as at 1 January 2022	(15 707)	(72 924)	(6 496)	(95 126)
Depreciation	(2 857)	(20 325)	(1 246)	(24 428)
Currency translation effects	3 502	18 491	1 211	23 203
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

		Rigs, helicopters and
USD 1000	Offices	supply vessels	Warehouse	Total
Cost as at 1 October 2022	61 104	202 552	13 877	277 533
Additions	-	-	-	-
Reclassification	-	(18 153)	-	(18 153)
Currency translation effects	5 628	20 901	1 278	27 808
Cost as at 31 December 2022	66 733	205 300	15 156	287 188

Depreciation and impairment as at 1 October 2022	(15 061)	(74 758)	(6 531)	(96 351)
Depreciation	(1 234)	(3 424)	(764)	(5 422)
Currency translation effects	(1 387)	(8 003)	(602)	(9 993)
Depreciation and impairment as at 31 December 2022	(17 683)	(86 185)	(7 896)	(111 765)

Net book value as at 31 December 2022	49 049	119 115	7 259	175 423

Note 11 Impairment

Impairment testing

Impairment tests of individual cash-generating units (CGUs) are performed quarterly when impairment triggers are identified, and full impairment testing is performed annually. Impairment testing of fixed assets and related intangible assets, including technical and ordinary goodwill were performed as of December 31 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 31 December 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 is 70 USD/BBL (real 2022) and long-term gas price is 56.2 USD/BOE (real 2022).

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

Year	31 Dec 2021	30 Sep 2022	31 Dec 2022

2022	68.9	77.4	80.1
2023	68.1	73.6	75.5
2024	69.4	75.2	77.3

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

Year	31 Dec 2021	30 Sep 2022	31 Dec 2022

2022	61.6	278.0	132.4
2023	40.6	139.2	106.0
2024	38.1	73.8	91.9

Note 11 Impairment – continued

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 tests:

Year / MBOE	31 Dec 2021	30 Sep 2022	31 Dec 2022

2023 – 2026	451	430	435
2027 – 2031	325	333	353
2032 – 2036	156	157	163
2037 – 2041	83	83	83
2042 – 2054	59	62	62

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. Q3 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. Unchanged vs. Q3 2022.

Inflation

Inflation for 2023 is assumed to be 4%. The long-term inflation rate beyond 2023 is assumed to be 2.0%. Unchanged vs. Q3 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.

The ordinary goodwill is tested for impairment on an operating segment level. If the net recoverable amount calculated as total of NPV less Net book value (NBV) for the offshore asset portfolio exceeds the carrying value of ordinary goodwill, no impairment is recorded.

Note 11 Impairment – continued

Impairment charge/reversal

The impairment testing per 31 December 2022 identified impairment to three CGUs; Balder Area (USD 68 million), Brage (USD 27 million) and Morvin (USD 2 million). The Balder impairment is mainly related to high cash flows in Q4 from production relative to limited depreciation of the carrying value. There are no material changes to the reserves, production profile or project economics for Balder.

No impairment triggers for ordinary goodwill.

				Impairment allocated
Cash generating unit (USD 1000)	Net carrying value	Recoverable amount	Impairment / reversal (-)	Goodwill	PP&E	Deferred tax impact

Balder Area	1 066 936	1 052 038	67 717		67 717	(52 819)
Brage	6 465	608	26 622		26 622	(20 766)
Morvin	13 209	11 293	1 916	1 916
Total			96 255	1 916	94 339	(73 585)

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%	(420 000)	3 407 000
Production profile	+/- 5%	(64 000)	919 000
Discount rate	+/- 1% point	224 000	(190 000)

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	31 Dec 2022	30 Sep 2022	31 Dec 2021
Trade receivables – related parties	22	478 714	221 086	424 834
Trade receivables – external parties		382 405	456 718	412 627
Sale of trade receivables		(64 802)	-	(91 540)
Total trade receivables		796 317	677 804	745 921

Vår Energi has 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 and obligation to pay these cash flows to the banks without material delay, but only to the extent Vår Energi collects the payments from the customers.

Note 13 Other current receivables and financial assets

USD 1000	Note	31 Dec 2022	Restated 30 Sep 2022	Restated 31 Dec 2021
Net underlift of hydrocarbons	1	101 889	121 555	110 217
Prepaid expenses		30 672	37 944	8 305
Brent crude put options – financial assets	14	14 805	20 001	17 407
Other		65 920	41 342	65 880
Total other current receivables and financial assets		213 286	220 842	201 809

Note 14 Financial instruments

Derivative financial instruments

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

As of 31 December 2021 and 31 December 2022, Vår Energi 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 31 Dec 2021, exercisable in 2022	14 349	47
Brent crude oil put options 31 Dec 2022, exercisable in 2023	14 038	50

Brent crude put options – financial assets

USD 1000	Note	Q4 2022	2021	Q4 2021

The beginning of the period		20 001	26 354	11 985
Cost of hedge	3	(9 810)	(60 492)	(16 272)
Effective portion recognised in OCI		(6 717)	9 976	11 601
New Brent crude put options		11 451	39 339	9 969
FX-effect		(120)	2 230	124
The end of the period		14 805	17 407	17 407

As of 31 December 2022, the fair value of outstanding Brent Crude oil put options amounted to USD 14.805 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	Q4 2022	2021	Q4 2021

The beginning of the period		(34 623)	(58 263)	(45 532)
Cost of hedge	3	9 810	60 492	16 272
New Brent crude put options		(11 451)	(39 339)	(9 969)
FX-effect		120	(2 229)	(110)
The end of the period		(36 143)	(39 339)	(39 339)

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/ Accretion	Currency	Other	31 Dec 2022

Bond USD Senior Notes	-	2 500 000	-	-	-	2 500 000
Long-term interest-bearing debt (RCF)	4 520 500	(4 020 500)	-	-	(500 000)	-
Short-term interest-bearing debt (RCF)	-	-	-	-	500 000	500 000
Deferred payment ExxonMobil 1	333 149	(352 335)	18 091	1 095	-	0
Prepaid loan expenses	(27 074)	(39 809)	17 801	1 320	351	(47 411)
Totals	4 826 575	(1 912 644)	35 892	2 415	351	2 952 589

¹ USD 352.335 thousand was paid to ExxonMobi 30 December 2022 (USD 300.000 thousand plus interest).

Note 15 Cash and cash equivalents

USD 1000	31 Dec 2022	30 Sep 2022	31 Dec 2021
Bank deposits, unrestricted	434 693	1 494 595	214 133
Bank deposit, restricted, employee taxes	9 914	4 411	9 454
Total bank deposits	444 607	1 499 006	223 588

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 31 December 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 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	31 Dec 2022	30 Sep 2022	31 Dec 2021

Bond USD Senior Notes (22/27)	5.00%		500 000	500 000	-
Bond USD Senior Notes (22/28)	7.50%		1 000 000		-
Bond USD Senior Notes (22/32)	8.00%		1 000 000		-
RCF Bridge facility	1.00%+SOFR +CAS	Nov 2023	500 000	2 500 000	3 000 000
RCF Working capital facility	1.08%+SOFR +CAS	Nov 2024	-	-	1 420 500
RCF Liquidity facility	1.13%+SOFR +CAS	Nov 2026	-	-	-
RCF Credit facility	1.13%+SOFR +CAS	Mar 2023	-	-	100 000
Deferred payment ExxonMobil			-	348 276	333 149
Prepaid loan expenses			(47 411)	(22 927)	(27 074)
Total interest-bearing loans and borrowings		2 952 589	3 325 349	4 826 575

Of which current and non-current
Interest-bearing loans, current			500 000	348 276	333 149
Interest-bearing loans and borrowings		2 452 589	2 977 073	4 493 426

Credit facilities – utilised and unused amount

USD 1000	31 Dec 2022	30 Sep 2022	31 Dec 2021

Drawn amount RCF credit facility	500 000	2 500 000	4 520 500
Undrawn amount credit facilities 1	3 600 000	3 600 000	2 079 500

¹ Where current share is USD 600 million as of 31 December 2022

In 2022, Vår Energi ASA made three issuances of senior notes in the US debt capital markets. The inaugural issue of USD 500 million of 5% Senior Notes due in May 2027 was made on 18 May 2022. On 15 November 2022 Vår Energi ASA issued USD 1000 million of 7.5% Senior Notes due in January 2028 and USD 1000 million of 8.0% Senior Notes due in November 2032. The senior notes are registered on the Luxembourg Stock Exchange ("LuxSE") and coupon payments are made semi-annually. The proceeds have been used for partial repayment of the bridge facility. The senior notes have no financial covenants.

As of 31 December 2022, Vår Energi's senior unsecured facilities agreement entered into with a group of 12 international banks contains of 3 separate facilities amounting to USD 3.5 billion; (1) bridge to bond facility of USD 500 million 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.

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 and was fully repaid in 2022 in accordance with the sales and purchase agreement.

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Note 18 Asset retirement obligations

USD 1000	Q4 2022	Q1 – Q3 2022	2021
Beginning of period	2 751 468	3 297 176	4 286 451
Change in estimate	175 503	90 878	(922 730)
Accretion discount	24 366	69 877	94 733
Payment for decommissioning of oil and gas fields	(14 814)	(55 504)	(70 418)
Currency translation effects	279 615	(650 959)	(90 860)
Total asset retirement obligations	3 216 138	2 751 468	3 297 176
Short-term	60 012	13 390	61 536
Long-term	3 156 126	2 738 078	3 235 640

Breakdown by decommissioning period	31 Dec 2022	30 Sep 2022	31 Dec 2021
2022-2030	339 511	214 090	269 534

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

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 4.0% in 2023 and 2.0% from 2024 onwards and discount rates between 3.1% – 3.2% per 31 December 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.

2031-2040 1 721 737 1 647 302 1 989 456 2041-2057 1 154 890 890 076 1 038 186

Forth quarter 2022 payment for decommissioning of oil and gas fields (abex) is mainly related to Åsgard.

Vår Energi has a retirement obligation as a shipper in Gassled booked to other non-current liabilities in the balance sheet statement. Vår Energi has accrued USD 70 336 thousand for this purpose per 31 December 2022.

Note 19 Other current liabilities

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

Net overlift of hydrocarbons	1	37 961	22 485	41 177
Net payables to joint operations		378 167	303 291	408 426
Employees, accrued public charges and other payables		50 748	26 095	5 314
Deferred payment for option premiums - oil puts	14	36 143	34 623	39 339
Total other current liabilities		503 019	386 493	494 256

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 company 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.

There are no new lease agreements in 4Q 2022.

USD 1000	Q4 2022	Q1 – Q3 2022	2021
Opening Balance lease debt	229 391	325 088	164 482
New lease debt in period	-	6 275	208 819
Payments of lease debt	(26 647)	(90 458)	(48 401)
Interest expense on lease debt	1 974	7 298	7 819
Currency exchange differences	7 928	(18 812)	(7 631)
Total lease debt	212 646	229 391	325 088

Breakdown of the lease debt to short-term and long-term liabilities	31 Dec 2022	30 Sep 2022	2021
Short-term	99 312	98 974	108 880
Long-term	113 334	130 417	216 208
Total lease debt	212 646	229 391	325 088
Lease debt split by activities	31 Dec 2022	30 Sep 2022	2021
Offices	55 941	51 689	66 525
Rigs, helicopters and supply vessels	149 140	170 133	250 811
Warehouse	7 566	7 569	7 752
Total	212 646	229 391	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.

Sales revenue

Current assets
USD 1000	31 Dec 2022	30 Sep 2022	31 Dec 2021
Trade receivables
Eni Trade & Biofuels SpA	251 129	33 781	160 533
Eni SpA	129 270	137 657	123 884
Eni Global Energy Markets	97 768	47 576	138 342
Other	546	2 072	2 075
Total trade receivables	478 714	221 086	424 834

USD 1000	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021

Eni Trade & Biofuels SpA	705 181	647 634	612 258	2 706 863	1 910 883
Eni SpA	345 095	459 540	342 355	1 472 251	703 428
Eni Global Energy Markets	200 912	134 159	322 994	629 765	473 372
Total sales revenue	1 251 188	1 241 334	1 277 608	4 808 879	3 087 683

All receivables are due within 1 year.

Current liabilities

USD 1000	31 Dec 2022	30 Sep 2022	31 Dec 2021

Account Payables
Eni International BV	21 740	16 304	21 336
Eni Global Energy Markets	22 063	12 704	24 547
Eni SpA	11 751	10 407	19 387
Other	1 340	644	915
Total account payables	56 894	40 058	66 185

Operating and capital expenditures

USD 1000	Q4 2022	Q3 2022	Q4 2021	FY 2022	FY 2021

Eni Trade & Biofuels SpA	5 001	12 353	5 479	48 841	29 020
Eni International BV	3 658	6 877	5 387	22 138	21 904
Eni SpA	3 186	6 527	13 594	21 462	46 294
Eni Global Energy Markets	10 144	(3 343)	14 746	(5 155)	21 590
Eni International Resources Ltd.	382	145	1 174	2 026	2 019
Other	(2 215)	2 244	17 540	455	1 616
Total operating and capital expenditures	20 156	24 803	57 920	89 768	122 443

Asset transactions/Other changes

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
PL820S/BS	30%	Vår Energi
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
PL820S/BS	30%	Vår Energi	Working interest and operator
PL095	0.18%	Equinor	Working interest

Disposals
PL027HS	10%	Vår Energi	Working interest
PL956	20%	Vår Energi	Working interest
PL985	10%	Vår Energi	Working interest
PL822S	40%	Aker BP	Working interest
PL124	4.82%	Equinor	Working interest
PL740	50%	DNO	Relinquished
PL946	40%	Equinor	Relinquished
PL1035	30%	Suncor	Relinquished
PL1070	30%	Total	Relinquished
PL1065	40%	Vår Energi	Relinquished
Other changes
PL947/PL947B		Vår Energi	Operator

The asset transactions are in licenses in the exploration phase.

Note 24 Subsequent events

In January 2023, Vår Energi was awarded 12 licenses in the APA 2022 licensing round, of which five as operator. Vår Energi is offered licenses in both the North Sea, the Norwegian Sea and the Barents Sea – most of them in areas close to existing infrastructure.

Vår Energi has decided to withdraw from the Barents Blue project as the cooperation agreement expired on 31 January 2023. This decision will not impact Vår Energi's position in the Barents Sea, and the work to find a comprehensive gas export solution continues.

Vår Energi has elected to sell part of its gas on a fixed price/forward basis. For the first quarter of 2023, Vår Energi has sold ~33% of the estimated gas production on a fixed price basis at an average price of ~285 USD/boe. Vår Energi has also chosen to forward sell ~20% of its estimated gas production in the second and third quarter of 2023 at an average sales price of ~190 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 company 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 company 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 31 December, 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 company. 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.

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

To the extent available, the industry, market and competitive position data contained in the Materials come from official or third-party sources. Thirdparty industry publications, studies and surveys generally state that the data contained therein have been obtained from sources believed to be reliable, but that there is no guarantee of the accuracy or completeness of such data. While the Company believes that each of these publications, studies and surveys has been prepared by a reputable source, none of the Company, its affiliates or any of its or their respective representatives has independently verified the data contained therein. In addition, certain of the industry, market and competitive position data contained in the Materials come from the Company's own internal research and estimates based on the knowledge and experience of the Company in the markets in which it has knowledge and experience. While the Company believes that such research and estimates are reasonable, they, and their underlying methodology and assumptions, have not been verified by any independent source for accuracy or completeness and are subject to change and correction without notice. Accordingly, reliance should not be placed on any of the industry, market or competitive position data contained in the Materials.

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

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Vår Energi ASA

3780_rns_2023-02-16_309ec91f-b44c-4358-9467-1335a130c0f3.pdf

Fourth quarter 2022

Key figures fourth quarter 2022

Fourth quarter 2022 highlights

Key metrics and targets

Targets and outlook 2023 guidance (USD million unless otherwise stated)

Long-term financial and operational targets

Operational review

Production split

Production 1

Production efficiency

Hubs

Diverse and robust portfolio positioned for value-adding growth

Production cost

Projects and developments

Balder X

Johan Castberg

Breidablikk

Bauge, Hyme and Fenja

Exploration

Health, safety, security and the environment (HSSE)

Decarbonisation and environmental impact

Financial review

Statment of income

Production cost

Exploration expenses

Depreciation, depletion, amortisation (DD&A)

Impairment losses and reversals

Net finance

Tax

Profit for the period

Condensed statement of financial position

Available liquidity

Interest-bearing debt

Total interest-bearing debt (TIBD)

Condensed statement of cash flow

Cash flow from operating activities before tax USD million

Condensed statement of cash flow – continued

Condensed statement of cash flow – continued

Outlook

Transactions with related parties

Subsequent events

Risks and uncertainty

Alternative performance measures (APMs)

EBITDA and EBITDAX

Financial statements with note disclosures

Unaudited financial statements

Unaudited statement of comprehensive income

Unaudited balance sheet statement

Unaudited balance sheet statement – continued

Unaudited statement of changes in equity

Unaudited statement of cash flows

Unaudited statement of cash flows – continued

Notes

(All figures in USD 1000 unless otherwise stated)

Shares in subsidiaries

Shares in subsidiaries indirectly owned

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

Restatement of over/underlift due to change in accounting principles

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

Note 9 Tangible assets

Note 10 Right of use assets

Note 11 Impairment

Impairment testing

Prices

Note 11 Impairment – continued

Oil and gas reserves

Future expenditure

Production ¹