Vår Energi ASA

Report Publication Announcement • Mar 30, 2022

Annual statement of reserves 2021

Contents

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• 1. Introduction 3
• 1. Assumptions and methodology 4
• 1. Overview of Reserves 5

4.	Description of Reserves	10
4.1	Balder/Grane	10
4.1.1	Balder Area	10
4.1.2	Grane Area	10
4.2	Barents Sea	11
4.2.1	Goliat	11
4.2.2	Johan Castberg	11
4.3	Åsgard	11
4.3.1	Åsgard Area	11
4.3.2	Kristin Area	12
4.4	Tampen	12
4.4.1	Snorre Area	12
4.4.2	Statfjord Area	12
4.5	Other	13
4.5.1	Greater Ekofisk Area
	(including Tor and Tommeliten Alpha)	13
4.5.2	Ormen Lange	13
4.5.3	Fenja Area	13
4.5.4	Fram Area	14

• 1. Contingent Resources 15
• 1. Management Discussion and Analysis 16

1 Introduction

The report provides the status of hydrocarbon reserves and contingent resources for Vår Energi ASA as of 31 December 2021. The reserves and resources reported herein are those quantities represented as the internal estimates of Vår Energi ASA. International petroleum consultants DeGolyer and MacNaughton (D&M) have carried out an independent assessment of the reserves, and the results have been compared to the estimates of Vår Energi ASA in this report.

This Annual Statement of Reserves (ASR) has been prepared in accordance with Oslo Stock Exchange listing and disclosure requirements, Circular No. 1/2013 ("Circular 1/2013").

2 Assumptions and methodology

Estimates of reserves and contingent resources herein have been prepared in accordance with the Petroleum Resources Management System (PRMS) approved in March 2007 and revised in June 2018 by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists, the Society of Petroleum Evaluation Engineers, the Society of Exploration Geophysicists, the Society of Petrophysicists and Well Log Analysts, and the European Association of Geoscientists & Engineers.

Reserves are those quantities of petroleum anticipated to be commercially recoverable from known accumulations from a given date forward under defined conditions, including economic conditions, license terms, and other commercial elements. Reserves must be discovered, recoverable, commercial, and remaining as of the evaluation's effective date. Further, reserves are categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.

Contingent resources are those quantities of petroleum that are estimated, on a given date, to be potentially recoverable from known accumulations, but not currently considered to be commercially recoverable due to one or more contingencies.

SPE-PRMS 2018 - Resources Classification Framework

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3 Overview of Reserves

Vår Energi is one of the largest independent oil and gas producers in Norway, measured by production and reserves, and operates exclusively on the Norwegian Continental Shelf with a diverse mix of assets in the North Sea, Norwegian Sea and Barents Sea.

As of 31 December 2021, Vår Energi has a working interest in 45 fields containing reserves. Out of these fields, 36 are currently on production with developed reserves, one field has developed reserves but is temporarily shut-in, and eight fields contain undeveloped reserves. Several of the producing fields also have undeveloped reserves related to new drilling programs or projects.

Vår Energi's portfolio of operated and partner-operated assets are centered around four major hubs: the Balder/Grane Area, the Barents Sea Area, the Åsgard Area and the Tampen Area. The full list of the fields and Vår Energi's working interest is shown in Table 1.

Table 1: Vår Energi's fields with reserves per 31 December 2021

Hub	Field/Project	Operator	Working interest	Field/Asset Status	Hub	Field/Project	Operator	Working interest	Field/Asset Status
Balder/Grane	Balder	Vår Energi ASA	90.0%	On production	Other	Bauge	Equinor Energy AS	17.5%	Development
Balder/Grane	Ringhorne Øst	Vår Energi ASA	70.0%	On production	Other	Hyme	Equinor Energy AS	17.5%	On production
Balder/Grane	Breidablikk	Equinor Energy AS	34.4%	Development	Other	Fenja	Neptune Energy AS	45.0%	Development
Balder/Grane	Grane	Equinor Energy AS	28.3%	On production	Other	Bøyla	Aker BP ASA	20.0%	On production
Balder/Grane	Svalin	Equinor Energy AS	13.0%	On production	Other	Frosk	Aker BP ASA	20.0%	On production
Barents Sea	Goliat	Vår Energi ASA	65.0%	On production	Other	Brage	Wintershall DEA Norge	12.3%	On production
Barents Sea	Johan Castberg	Equinor Energy AS	30.0%	Development	Other	Fram	Equinor Energy AS	25.0%	On production
Åsgard	Åsgard	Equinor Energy AS	22.1%	On production	Other	Ekofisk	ConocoPhillips AS	12.4%	On production
Åsgard	Mikkel	Equinor Energy AS	48.4%	On production	Other	Eldfisk	ConocoPhillips AS	12.4%	On production
Åsgard	Morvin	Equinor Energy AS	30.0%	On production	Other	Embla	ConocoPhillips AS	12.4%	On production
Åsgard	Trestakk	Equinor Energy AS	40.9%	On production	Other	Tommeliten Alpha	ConocoPhillips AS	9.1%	Development
Åsgard	Halten Øst	Equinor Energy AS	24.6%	Development	Other	Tor	ConocoPhillips AS	10.8%	On production
Åsgard	Kristin	Equinor Energy AS	16.7%	On production	Other	Alpha Horst	Equinor Energy AS	5.2%	Development
Åsgard	Lavrans	Equinor Energy AS	16.7%	Development	Other	Heidrun	Equinor Energy AS	5.2%	On production
Åsgard	Tyrihans	Equinor Energy AS	18.0%	On production	Other	Marulk	Vår Energi ASA	20.0%	On production
Tampen	Snorre	Equinor Energy AS	18.6%	On production	Other	Norne	Equinor Energy AS	6.9%	On production
Tampen	Vigdis	Equinor Energy AS	16.1%	On production	Other	Skuld	Equinor Energy AS	11.5%	On production
Tampen	Tordis	Equinor Energy AS	16.1%	On production	Other	Urd	Equinor Energy AS	11.5%	On production
Tampen	Statfjord	Equinor Energy AS	21.4%	On production	Other	Ormen Lange	A/S Norske Shell	6.3%	On production
Tampen	Statfjord Øst	Equinor Energy AS	20.6%	On production	Other	Gungne	Equinor Energy AS	13.0%	On production
Tampen	Statfjord Nord	Equinor Energy AS	25.0%	On production	Other	Sigyn	Equinor Energy AS	40.0%	On production
Tampen	Sygna	Equinor Energy AS	21.0%	On production	Other	Sleipner Øst	Equinor Energy AS	15.4%	On production
					Other	Sleipner Vest	Equinor Energy AS	17.2%	On production

As of 31 December 2021, Vår Energi's total net proved (1P) reserves were estimated to 714 million barrels of oil equivalents. Total net proved plus probable (2P) reserves were estimated to 1 133 mmboe. Further details of the reserves by asset groups and products are provided in Table 2.

The standard conversion factors published by the Norwegian Petroleum Directorate have been applied for estimates of reserves and resources in this report: (i) 6.29 barrels of oil to 1 Sm3 of oil, and (ii) 1000 Sm3 of gas to 1 Sm3 of oil equivalents (oe).

Table 2: Vår Energi's reserves as of 31 December 2021

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Total Reserves			1P (P90 / low estimate)			2P (P50 / best estimate)
Hub	Asset Group	Net Oil	Net NGL	Net Gas	Net Total	Net Oil	Net NGL	Net Gas	Net Total
		mmboe	mmboe	mmboe	mmboe	mmboe	mmboe	mmboe	mmboe
Balder/Grane	Balder Area	129	-	10	139	220	-	16	235
Balder/Grane	Grane Area	60	-	3	63	101	-	5	106
Barents Sea	Goliat	45	-	-	45	69	-	-	69
Barents Sea	Johan Castberg	117	-	6	123	168	-	7	175
Åsgard	Åsgard Area	14	14	41	68	24	26	72	122
Åsgard	Kristin Area	3	5	16	24	6	8	28	42
Tampen	Snorre Area	67	-	4	71	102	-	4	106
Tampen	Statfjord Area	9	4	9	22	13	5	11	29
Other	Greater Ekofisk Area	37	2	12	51	73	4	22	99
Other	Ormen Lange	1	-	34	36	1	-	42	43
Other	Fenja Area	21	3	6	30	27	4	7	38
Other	Fram Area	4	2	10	15	5	3	13	21
Other	Others	10	6	12	28	20	9	19	48
Total		517	34	163	714	830	57	246	1 133

The split between developed and undeveloped reserves per asset group and product are shown in Table 3 and Table 4.

Table 3: Vår Energi's developed reserves as of 31 December 2021

Total Reserves			1P (P90 / low estimate)			2P (P50 / best estimate)
Hub	Asset Group	Net Oil	Net NGL	Net Gas	Net Total	Net Oil	Net NGL	Net Gas	Net Total
		mmboe	mmboe	mmboe	mmboe	mmboe	mmboe	mmboe	mmboe
Balder/Grane	Balder Area	37	-	1	37	41	-	1	42
Balder/Grane	Grane Area	21	-	3	24	30	-	3	33
Barents Sea	Goliat	44	-	-	44	62	-	-	62
Barents Sea	Johan Castberg	-	-	-	-	-	-	-	-
Åsgard	Åsgard Area	12	11	34	57	16	14	42	72
Åsgard	Kristin Area	2	4	15	21	4	6	22	32
Tampen	Snorre Area	56	-	4	60	78	-	4	82
Tampen	Statfjord Area	6	3	8	17	8	4	10	22
Other	Greater Ekofisk Area	31	1	6	38	41	2	9	53
Other	Ormen Lange	1	-	22	23	1	-	24	25
Other	Fenja Area	1	-	-	1	1	-	1	2
Other	Fram Area	4	2	10	15	5	3	13	21
Other	Others	8	4	11	23	11	6	16	33
Total Developed		221	26	113	361	300	34	145	480

Table 4: Vår Energi's undeveloped reserves as of 31 December 2021

Total Reserves			1P (P90 / low estimate)		2P (P50 / best estimate)
Hub	Asset Group	Net Oil	Net NGL	Net Gas	Net Total	Net Oil	Net NGL	Net Gas	Net Total
		mmboe	mmboe	mmboe	mmboe	mmboe	mmboe	mmboe	mmboe
Balder/Grane	Balder Area	92	-	9	102	178	-	15	193
Balder/Grane	Grane Area	39	-	-	39	71	-	2	73
Barents Sea	Goliat	1	-	-	1	7	-	-	7
Barents Sea	Johan Castberg	117	-	6	123	168	-	7	175
Åsgard	Åsgard Area	2	2	7	11	8	12	30	50
Åsgard	Kristin Area	1	-	1	2	2	2	5	10
Tampen	Snorre Area	11	-	-	11	24	-	-	24
Tampen	Statfjord Area	4	1	1	5	5	1	1	7
Other	Greater Ekofisk Area	6	-	6	13	32	2	13	46
Other	Ormen Lange	-	-	12	12	-	-	17	18
Other	Fenja Area	20	3	6	29	26	3	7	35
Other	Fram Area	-	-	-	-	-	-	-	-
Other	Others	2	2	2	5	9	3	3	15
Total Undeveloped		295	8	50	353	530	23	101	654

2022 is first year of Vår Energi ASA being listed on Oslo Børs and preparing an Annual Statement of Reserves in accordance with the PRMS classification system. Consequently, a reconciliation of reserves development in 2021 is not available this reporting cycle.

4 Description of Reserves

This section includes a brief description of the fields within the asset groups presented in Tables 2-4 in the previous section. A brief description of the field development is provided together with a description of the status of ongoing or planned project or drilling activities. The field descriptions are to a large extent extractions from www.norskpetroleum.no, a website run in cooperation by the Ministry of Petroleum and Energy and the Norwegian Petroleum Directorate.

4.1 Balder/Grane

4.1.1 Balder Area

The Balder Area consists of the Balder/Ringhorne and Ringhorne East fields.

Balder is a field in the central part of the North Sea, just west of the Grane field. The water depth is 125 metres. Balder was discovered in 1967, and the initial plan for development and operation (PDO) was approved in 1996. Production started in 1999. The field has been developed with subsea wells tied-back to the Balder production, storage and offloading vessel (FPSO). The Ringhorne deposit, located nine kilometres north of the Balder FPSO, is included in the Balder complex. Ringhorne is developed with a combined accommodation, drilling and pre-processing facility with a steel jacket, tied back to the Balder FPSO for final processing, crude oil storage and gas export.

The nearby field Ringhorne Øst is also tied-back to Balder via the Ringhorne platform. Ringhorne Øst was discovered in 2003, and the plan for development and operation (PDO) was approved in 2005. The field is developed with four production wells drilled from the Ringhorne platform. Production started in 2006.

A revised PDO for Balder and Ringhorne was approved in 2020. The development plan includes lifetime extension and relocation of the Jotun FPSO, and drilling of new subsea wells. The Jotun FPSO is currently at a shipyard undergoing maintenance and upgrades. It is scheduled to be on location in the Balder field in 2023. Ringhorne Øst will also benefit from an amended PDO for Balder and Ringhorne approved in 2020. Field lifetime will be prolonged, and production can benefit from increased capacity in the area.

4.1.2 Grane Area

The Grane Area consists of the Grane, Svalin and Breidablikk fields.

Grane is a field in the central part of the North Sea, just east of the Balder field. The water depth is 130 metres. Grane was discovered in 1991, and the plan for development and operation (PDO) was approved in 2000. The field has been developed with an integrated

accommodation, drilling and processing facility with a steel jacket. The facility has 40 well slots. Production started in 2003. The Svalin field is tied-back to the Grane platform.

Svalin is a field in the central part of the North Sea, six kilometres southwest of the Grane field. The water depth is 120 metres. Svalin was discovered in 1992, and the plan for development and operation (PDO) was approved in 2012. The Svalin C structure is developed with a subsea template tied-in to the Grane facility, and Svalin M is developed with a multilateral well drilled from Grane. Production started in 2014.

Breidablikk is a field in the central part of the North Sea, ten kilometers northeast of the Grane field. The water depth is 130 metres. Breidablikk includes two discoveries, D-structure and F-structure, discovered in 1992 and 2013, respectively. The plan for development and operation (PDO) was approved in June 2021. The field is being developed with four subsea templates tied-back to the Grane platform.

4.2Barents Sea

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4.2.1 Goliat

Goliat is a field in the Barents Sea, 50 kilometres southeast of the Snøhvit field. The water depth is 360-420 metres. Goliat was discovered in 2000, and the plan for development and operation (PDO) was approved in 2009. The field is developed with a cylindrical floating production, storage and offloading facility (Sevan 1000 FPSO). Eight subsea templates with a total of 32 well slots are tied-back to the FPSO. Production started in 2016. Goliat was granted a PDO exemption for the Snadd reservoir in 2017 and the Goliat Vest reservoir in 2020. Production from these reservoirs started in 2017 and 2021 respectively.

Several infill wells have been drilled in 2021. Also in 2021, the Rødhette discovery (7122/6-3 S) was made in the area north of the Goliat field.

4.2.2Johan Castberg

Johan Castberg is a field in the Barents Sea, 100 kilometres northwest of the Snøhvit field. The water depth is 370 metres. Johan Castberg consists of the three discoveries Skrugard, Havis and Drivis, proven between 2011 and 2013. The discoveries will be developed together, and the plan for development and operation (PDO) was approved in June 2018. The development concept is a production, storage and offloading vessel (FPSO) with additional subsea solutions including 18 horizontal production wells and 12 injection wells. The field is currently under development, and production is scheduled to start in 2024.

4.3Åsgard 4.3.1 Åsgard Area

The Åsgard Area consists of the Åsgard, Mikkel, Trestakk, Morvin and Halten Øst fields.

Åsgard is a field in the central part of the Norwegian Sea. The water depth is 240-300 metres. Åsgard was discovered in 1981, and the plan for development and operation (PDO) was approved in 1996. The Åsgard field includes the deposits Smørbukk, Smørbukk Sør, Midgard and the undeveloped Smørbukk Nord. The field has been developed with subsea wells tied-back to a production, storage and offloading vessel (FPSO), Åsgard A. The development also includes Åsgard B, a floating, semi-submersible facility for gas and condensate processing. The gas centre is connected to a floating storage and offloading vessel for condensate, Åsgard C. Production started in 1999 and gas export started in 2000. The Åsgard facilities are an important part of the Norwegian Sea infrastructure. The Mikkel and Morvin fields are tied to Åsgard B for processing, and gas from

Åsgard B is sent to the Tyrihans field for gas lift. The PDO for a subsea gas compression facility at Midgard was approved in 2012 and started operations in 2015.

Work is ongoing to increase the recovery from the Åsgard field, while third party tie-ins to Åsgard will prolong the lifetime of the facilities. Smørbukk Nord FID is expected in 2022.

The Mikkel field is located in the eastern part of the Norwegian Sea. It was discovered in 1987, and the plan for development and operation (PDO) was approved in 2001. The field is developed with two subsea templates tied-back to the Åsgard B facility. Production started in 2003.

Trestakk is a field in the central part of the Norwegian Sea, 20 kilometres south of the Åsgard field. Trestakk was proven in 1986 and the PDO was approved in 2017. The development concept consists of one subsea template with four well slots and an additional satellite well. The subsea installation is tied-back to the Åsgard A facility for processing and gas injection. Production started in 2019.

Morvin is located 15 kilometres west of the Åsgard field. Morvin was discovered in 2001, and the plan for development and production (PDO) was approved in 2008. The field is developed with two 4-slot subsea templates, tied to the Åsgard B facility. Production started in 2010.

Halten Øst includes six discoveries (Flyndretind, Gamma, Harepus, Nona, Natalia and Sigrid) located in the Norwegian Sea east of the Åsgard field. The water depth is 240-300 metres. The gas-condensate discoveries will be tied-back to Åsgard B facility via the Midgard subsea system. The plan for development and operation (PDO) is planned to be submitted within Q2 2022.

4.3.2Kristin Area

The Kristin Area consists of the Kristin, Tyrihans and Lavrans fields.

Kristin is a field in the Norwegian Sea, a few kilometres southwest of the Åsgard field. The water depth is 370 metres. Kristin was discovered in 1997, and the plan for development and operation (PDO) was approved in 2001. The field is developed with four 4-slot subsea templates tied-back to a semi-submersible facility for processing. Production started in 2005. An amended PDO was approved in 2007. The Tyrihans and Maria fields are tied back to the Kristin facility.

The Tyrihans field was discovered in 1983 and the PDO was approved in 2005. The field is developed with five subsea templates tied-back to the Kristin platform, four templates for production and gas injection and one template for seawater injection. Gas for injection and gas lift is supplied from the Åsgard B platform. Production started in 2009.

A PDO for Kristin South including development of Kristin-Q area and Lavrans was delivered to the authorities in July 2021. Kristin South will be tied back to Kristin facility for processing and export.

4.4Tampen

4.4.1 Snorre Area

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The Snorre Area consists of the Snorre, Vigdis and Tordis fields.

Snorre is a field in the Tampen area in the northern part of the North Sea. The water depth is 300-350 metres. Snorre was discovered in 1979, and the plan for development and operation (PDO) was approved in 1988. The field is developed with the facilities Snorre A, located in the southern part of the field, and Snorre B in the northern part. Snorre A is a floating tension-leg platform for accommodation, drilling and

processing, and Snorre B is a semi-submersible integrated drilling, processing and accommodation facility.

In 2018, an amended PDO for the Snorre Expansion Project was approved. It includes six subsea templates, each with four wells tiedback to Snorre A. Production started in 2020. Snorre Expansion Project is progressing according to plan. Several measures to increase oil recovery from Snorre are being considered. Possible third party tie-ins may lead to further development of the field.

In 2020, an amended PDO for the development of the Hywind Tampen wind farm was approved. The wind farm will consist of 11 floating turbines which will supply part of the electricity needed for the Snorre and Gullfaks fields. These will be the first platforms in the world to receive power from a floating wind farm. The Hywind Tampen wind farm is scheduled for start-up at the end of 2022.

Vigdis is a field in the Tampen area in the northern part of the North Sea, between the Snorre, Statfjord and Gullfaks fields. The water depth is 280 metres. Vigdis was discovered in 1986, and the plan for development and operation (PDO) was approved in 1994. The field has been developed with seven subsea templates and two satellite wells connected to the Snorre A facility. Production started in 1997. Oil from Vigdis is processed in a dedicated processing module on Snorre A.

Tordis is a field in the Tampen area in the northern part of the North Sea, between the Statfjord and Gullfaks fields. The water depth is 150-220 metres. Tordis was discovered in 1987, and the plan for development and operation (PDO) was approved in 1991. The field has been developed with a central subsea manifold tied-back to the Gullfaks C facility, which also supplies water for injection. Seven single-well

satellites and two 4-slots subsea templates are tied-back to the manifold. Production started in 1994.

4.4.2Statfjord Area

The Statfjord Area consists of the Statfjord Unit, Statfjord Nord, Statfjord Øst and Sygna fields.

Statfjord is a field in the Tampen area in the northern part of the North Sea, on the border between the Norwegian and UK sectors. The Norwegian share of the field is 85.47 per cent. The water depth is 150 metres. Statfjord was discovered in 1974, and the plan for development and operation (PDO) was approved in 1976. The field has been developed with three fully integrated concrete facilities: Statfjord A, Statfjord B and Statfjord C. Statfjord A, centrally located on the field, came on stream in 1979. Statfjord B, in the southern part of the field, in 1982, and Statfjord C, in the northern part, in 1985. The satellite fields Statfjord Øst, Statfjord Nord and Sygna have a dedicated inlet separator on Statfjord C. A PDO for Statfjord Late Life was approved in 2005.

Statfjord Nord is located 17 kilometres north of the Statfjord field. The water depth is 250-290 metres. Statfjord Nord was discovered in 1977, and the plan for development and operation (PDO) was approved in 1990. The field has been developed with two production templates and one water injection template tied-back to the Statfjord C facility. Production started in 1995.

Statfjord Øst is located seven kilometres northeast of the Statfjord field. The water depth is 150-190 metres. Statfjord Øst was discovered in 1976, and the plan for development and operation (PDO) was approved in 1990. The field has been developed with two subsea production templates and one water injection template, tied-back to the

Statfjord C platform. In addition, two production wells have been drilled from Statfjord C. Production started in 1994. A PDO amendment was approved in 2021; four new wells will be drilled from the existing subsea templates in 2023-2024. The project also includes modifications on Statfjord C and a new pipeline for gas lift.

Sygna is a field northeast of the Statfjord Nord field. The water depth is 300 metres. Sygna was discovered in 1996, and the plan for development and operation (PDO) was approved in 1999. The field has been developed with three subsea wells tied-back to the Statfjord C facility, and one long-reach water injection well drilled from the Statfjord Nord template. Production started in 2000.

Work is ongoing to extend the lifetime of the Statfjord field and tiebacks, including drilling of several new wells in the years to come. Satellite fields tied-back to Statfjord as well as nearby discoveries will benefit from the lifetime extension.

4.5Other

4.5.1 Greater Ekofisk Area (including Tor and Tommeliten Alpha)

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The Greater Ekofisk Area consists of the Ekofisk, Eldfisk and Embla fields, while the adjacent Tor and Tommeliten Alpha fields are also included in this asset group.

Ekofisk and Eldfisk are oil fields in the southern part of the Norwegian sector in the North Sea. The water depth is approximately 70 metres. Ekofisk was discovered in 1969, and the initial plan for development and operation (PDO) was approved in 1972. Eldfisk was discovered in 1970, and the plan for development and operation (PDO) was approved in 1975. The Embla field is located just south of the Eldfisk field. Embla

was discovered in 1988, and the plan for development and operation (PDO) was approved in 1990. The field has been developed with an unmanned wellhead facility, which is remotely controlled from Eldfisk. Production started in 1993.

Production from Ekofisk and Eldfisk is maintained at a high level through continuous water injection, drilling of production and injection wells, and well interventions. Infill drilling is expected to continue throughout the lifetime of the fields. A further development of the northern part of Eldfisk is being evaluated.

As part of the Eldfisk II development project, Embla was tied to the Eldfisk S facility, extending the lifetime for Embla. Currently, there are four producers.

Tor is a field in the southern part of the Norwegian sector in the North Sea, 13 kilometres northeast of the Ekofisk field. The water depth is 70 metres. Tor was discovered in 1970, and the plan for development and operation (PDO) was approved in 1973. The field was shut down in 2015. A new PDO for the redevelopment of Tor was approved in 2019. The development includes two subsea templates with eight horizontal production wells, tied-back to the Ekofisk Centre. Production started again in 2020.

The Tommeliten Alpha development concept includes ten horizontal producers, two 6-slot Subsea Production Station templates, a direct electric heated flowline back to the Ekofisk Complex and an umbilical. Tie-in and de-bottlenecking modifications will be performed at the Ekofisk Complex including a new processing module. The field will produce by pressure depletion. The field is under development with PDO submitted in 2021 and the production is planned to start in 2024.

4.5.2Ormen Lange

Ormen Lange is a field in the southern part of the Norwegian Sea, 120 kilometres west-northwest of the Nyhamna processing plant. The water depth varies from 800 to more than 1 100 metres. Ormen Lange was discovered in 1997, and the plan for development and operation (PDO) was approved in 2004. The field has been developed in several phases. The development comprises four 8-slot subsea templates with a total of 24 production wells. Production started in 2007 from two subsea templates in the central part of the field tied back to Nyhamna. In 2009 and 2011, two additional templates were installed in the southern and northern parts of the field, respectively.

Onshore gas compression at the Nyhamna terminal started operation in 2017, and a PDO for subsea gas compression was submitted to the authorities in 2021. Work is ongoing to increase recovery from the field, and two new infill wells are planned drilled in 2022.

4.5.3Fenja Area

The Fenja Area consists of the Fenja, Bauge and Hyme fields.

The Fenja field is located in the Norwegian Sea, 35 kilometres southwest of the Njord field. The water depth is 325 metres. The field also includes the discovery 6406/12-3 A (Bue). Fenja was discovered in 2014, and the plan for development and operation (PDO) was approved in 2018. The field is being developed with two subsea templates with up to six wells, tied-back to the third-party Njord A facility. Production from Fenja is planned to start in early 2023.

Bauge is located 15 kilometres east of the Njord field. The water depth is 280 metres. Bauge was discovered in 2013, and the plan for development and operation (PDO) was approved in June 2017. The field will be

14 CONTENTS | INTRODUCTION ASSUMPTIONS AND METHODOLOGY OVERVIEW OF RESERVES DESCRIPTION OF RESERVES CONTINGENT RESOURCES MANAGEMENT DISCUSSION AND ANALYSIS

developed with two production wells tied-back to the Njord A facility. A future water injection well is planned drilled from the existing subsea template on the Hyme field. The field is under development and the production is planned to start in late 2022.

Hyme is located 19 kilometres northeast of the Njord field. The water depth is 250 metres. Hyme was discovered in 2009, and the plan for development and operation (PDO) was approved in 2011. The field is developed with a subsea template including one production well and one water injection well. Hyme is connected to the Njord A facility. Production started in 2013, however, was temporarily stopped in 2016 when the Njord A facility was shut down and towed to land for reinforcement and modifications. Hyme is expected to resume production late 2022, when the Njord facility is in place again.

4.5.4Fram Area

Fram is a field in the northern part of the North Sea, 20 kilometres north of the Troll field. The water depth is 350 metres. Fram was discovered in 1990 and comprises two main structures, Fram Vest and Fram Øst, with several deposits. The plan for development and operation (PDO) for Fram Vest was approved in 2001, and production started in 2003. The PDO for Fram Øst was approved in 2005, and production

started in 2006. Both structures are developed with two subsea templates each, tied-back to the Troll C platform. A PDO exemption for Fram C-Øst was approved in 2016; the development included a long oil producer drilled from the B2-template on Fram Øst. Another PDO exemption was granted in 2018 for two wells in the Fram-Øst Brent reservoir, drilled from one of the existing templates on Fram Øst.

An extra gas module dedicated to Fram on the Troll C platform started operation in 2020. Two successful exploration wells in the Fram area have recently been drilled and a development plan is being matured.

5 Contingent Resources

Approximately 60 per cent of Vår Energi ASA's contingent resources as of 31 December 2021 are associated with new development projects at existing fields. The main projects being matured towards an investment decision are King & Prince (Balder Area) as well as additional infill drilling in the Balder Area, the development of Goliat gas resources, and the development of discoveries and drilling in the Fram area. The remaining volume of the contingent resources is linked to new discoveries. The main contributors in this category are the Alke, Garantiana, Brasse fields and several discoveries in the Barents Sea near the Johan Castberg field.

This section includes a brief description of the main contingent resources within the Vår Energi's portfolio.

Balder Area (including King & Prince)

There are significant remaining resources to be targeted in the Balder and Ringhorne fields through future infill drilling programs. In addition, the 2021 exploration campaign delivered a significant resource addition through the King & Prince discoveries. The development concept for King & Prince is currently being evaluated.

Goliat

Contingent resources in Goliat are associated with the development of the gas resources in the field. Solutions for gas export are being evaluated.

Alke

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The Alke gas discovery is operated by Vår Energi in PL489 in the Hammerfest Basin, about 54 kilometers south of the Snohvit field in a water depth of 160 meters. The planning of a possible development of the Alke field is ongoing. Decision Gate 1 (DG1) was passed Q2 2019.

Johan Castberg Area

Contingent resources are related to nearby discoveries within tie-in range to the Johan Castberg FPSO, i.e. Isflak, Iskrystall, Kayak, Kramsnø, Nunatak, Skavl and Skruis. The planned gas blowdown at the end of the field life is also included in contingent resources.

Åsgard

Åsgard field contingent resources include new infill drilling and new projects that are being matured together with the project of extending Åsgard field life until 2040.

Mikkel

Contingent resources are related to the Ultra Low Pressure Project (subsea boosting).

Statfjord Area

Contingent resources consist of the new activities aimed to increase the reserves from the field and that are part of the Statfjord Life Extension Project.

Garantiana

Garantiana (34/6-2 S) is a discovery in the northern North Sea, 15 kilometres north of the Visund field. The water depth is 380 metres. The discovery was proven in 2012 and delineated in 2014. In 2021, a new discovery was made in a separate structure just west of Garantiana. An exploration well to another separate structure south of Garantiana is planned drilled during 2022.

Fram Area

Contingent resources are related to future well drilling in Fram and also for Echino South and Blasto discoveries.

Brasse

Brasse is a discovery in the northern North Sea, 13 kilometres south of the Brage field and 13 kilometres southeast of the Oseberg Field Center. The water depth is 120 metres. The discovery was proven in 2016 and delineated by four wells in the period from 2017 to 2019. The reservoir contains oil with a gas cap in the Upper Jurassic Sognefjord Formation. Development concept with subsea tie-back to the Oseberg facilities is being evaluated.

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6 Management Discussion and Analysis

Vår Energi ASA's reserves and resources estimates are based on standard industry practices and methodologies. The evaluations and assessments have been performed by experienced professionals in Vår Energi ASA with extensive industry experience, and the methodology and results have been quality controlled as part of the company's internal reserves estimation procedures.

A third-party independent assessment has been performed by international petroleum consultants DeGolyer and MacNaughton (D&M) on all Vår Energi ASA's fields that have remaining hydrocarbon volumes classified as reserves. The assessment was based on input data provided by Vår Energi ASA, as well as publicly available data about the fields. The results of the independent assessment indicate, when compared on an aggregate basis, no material difference compared to the reserves presented herein.

The 2P reserves estimates represents the expected outcome for the fields based on the performance observed to date, planned activities in the licenses and reasonable assumptions about future economic and fiscal conditions. The Company has applied a long-term oil price assumption of 65 USD/bbl (real 2021 terms), long-term inflation assumption of 1.9 per cent and a long-term exchange rate assumption of 8.5 USD/NOK in the economic evaluation of its reserves. The estimation of recoverable volumes is associated with geological and economic uncertainties. The 1P

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reserves reflect the Company's estimate of volumes with reasonable certainty to be recovered, however there is remaining risk that actual results may be lower than the 1P estimates. Lower and higher oil prices may also shorten or extend the economic life of fields, resulting in lower or higher recoverable volumes than what is assumed.

The report, including this Management's Discussion and Analysis (MD&A), contains and was prepared on the basis of forward-looking information and statements. Such information and statements are based on management's current assumptions, expectations, estimates and projections and are therefore subject to risks and uncertainties that could cause actual results, performance or events to differ materially. Vår Energi ASA can give no assurance that those assumptions, expectations, estimates and projections will occur or be realized and readers should not place undue reliance on forward-looking statements.

Torger Rød CEO, Vår Energi ASA

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