OKEA ASA

Regulatory Filings • Mar 31, 2025

Annual statement of reserves

2024

Contents

		Page
1	Introduction	2
2	Classification of reserves and contingent resources	3
3	Reserves	4
	3.1. Total reserves estimates 3.2 Development of reserves 3.3 Description of reserves	5 6 7
4	Contingent resources	18
	4.1 Total contingent resources estimate 4.2 Description of contingent resources	18 19
5	Management discussion and analysis	24

1 Introduction

The Annual statement of reserves and resources (ASR) is a full overview of the hydrocarbon volumes entitled to OKEA ASA ("OKEA") and has been prepared for both internal and external stakeholders. The reserves calculations and reporting are in line with the Listing and Disclosure Requirements for Oil and Natural Gas Companies as stated by Oslo Børs (Oslo Stock Exchange).

The overview in this document is the final version of the ASR 2024, with cut-off date 31 December 2024.

2 Classification of reserves and contingent resources

OKEA's reserves and contingent resources have been classified in accordance with the Petroleum Resources Management System (PRMS) of the Society of Petroleum Engineers (SPE). This classification system is consistent with Oslo Børs' requirements for disclosure of hydrocarbon reserves and contingent resources. The framework of the classification system is illustrated in Figure 2.1.

OKEA reports, in addition to 1P and 2P reserves, also 3P reserves, as well as contingent resources. All categories are reported in line with the PRMS.

Figure 2.1: PRMS including sub-classes based on maturity

3 Reserves

OKEA ASA has reserves distributed across ten fields, listed in Table 1. The project status category describes the maturity for each of the fields and projects according to the PRMS, c.f. Figure 2.1. Reserves categorised as "Approved for development" correspond to field developments for which the Plan for Development and Operations (PDO) is approved by the Ministry of Energy or an exemption from this has been given.

The reserves estimates are based on all technical data available including production data, logs, seismic data, cores, models, decline curve analysis etc.

Field/ Project	OKEA Working interest	Operator	Project Status Category	Comment
Draugen	44.56 %	OKEA ASA	On production	Includes Hasselmus
Bestla	39.2788 %	OKEA ASA	Approved for production	PDO approved November 2024
Brage	35.2 %	OKEA ASA	On production
Gjøa	12 %	Vår Energi ASA	On production
Ivar Aasen	9.2385 %	Aker BP ASA	On production
Nova	6 %	Harbour Energy Norge AS	On production
Statfjord	23.93123 %	Equinor Energy AS	On production
Statfjord Øst	14 %	Equinor Energy AS	On production
Statfjord Nord	28 %	Equinor Energy AS	On production
Sygna	15.4 %	Equinor Energy AS	On production
Yme	0 %	Repsol Norge AS	On production	Divested in November 2024

For economic evaluations, the long-term oil price assumption is 76 USD/bbl, with a long-term currency rate of USD/NOK 9.5. Gas price is set to 71 pence/therm (equivalent to 3.27 NOK/Sm³ ) NGL price is set to 545 USD/tonne. All prices are in real 2024 and a 2% annual inflation rate is used.

Gas reserves are reported as sales gas with an energy content of 40 MJ/Sm³ .

In addition, the following conversion factors are used:

Oil	1 Sm3 = 1 Sm3 oe = 6.29 bbl
Gas	1 000 Sm3 gas = 1 Sm3 oe
	1 Sm3 = 35.315 Scf
NGL	1 tonne NGL = 1.9 Sm3 oe

Table 1: OKEA asset portfolio with reserves as of 31 December 2024

3.1 Total reserves estimates

OKEA's net proven reserves (1P/P90) as of 31 December 2024 are estimated at 51.3 million barrels of oil equivalents. Total net proven plus probable reserves (2P/P50) are estimated at 75.6 million barrels of oil equivalents. The reserves figures account for the effects of production in 2024. The split between oil, NGL and gas, and between individual assets is given in Table 2.

The reserves numbers are verified through a third-party certification performed by AGR Petroleum Services AS. Please note that totals in tables above are arithmetic and not stochastic summations.

The corresponding 3P/P10 estimate of net OKEA reserves is 101.0 mmboe. For comparison, the corresponding Total Net 1P-, 2P- and 3P-reserves in ASR 2023 (31 December 2023) were 59.2, 83.2 and 106.0 mmboe, respectively, c.f. Table 3.

The reserves estimates are based on figures in the RNB2025 files reported by the operator of the individual assets with certain minor adjustments.

		1P/P90 (Low estimate)			2P/P50 (Base estimate)
Asset/Project	OKEA WI	Gross Oil	Gross NGL	Gross Gas	Net OE	Gross Oil	Gross NGL	Gross Gas	Net OE
Reserves – On Production
Brage	35.20 %	4.94	0.10	0.29	1.88	6.50	0.24	0.67	2.61
Draugen	44.56 %	44.18	3.92	6.42	24.30	48.82	5.29	8.65	27.97
Gjøa	12 %	0.77	5.93	11.52	2.19	1.04	7.46	14.47	2.76
Ivar Aasen	9.2385 %	10.48	0.70	2.14	1.23	31.17	2.34	7.19	3.76
Nova	6 %	14.70	3.45	6.11	1.46	29.43	4.89	8.59	2.57
Statfjord	23.93123 %	8.80	8.20	12.57	7.08	17.36	20.15	30.89	16.37
Statfjord Nord	28 %	5.56	0.20	0.31	1.70	12.77	0.46	0.70	3.90
Statfjord Øst	14 %	5.02	1.06	1.62	1.08	9.13	1.86	2.86	1.94
Sygna	15.40 %	0.87	0.00	0.00	0.13	1.76	0.00	0.00	0.27
Total Net					41.0				62.1
Reserves – Approved for Development
Bestla	39.28 %	10.75	1.71	4.82	6.78	13.73	1.96	5.53	8.34
Brage (Fensfjord5000; Bowmore; SE first producer)	35.20 %	1.67	0.16	0.44	0.80	3.64	0.42	1.14	1.83
Draugen (Power from Shore)	44.56 %	0.00	1.63	2.65	1.91	0.00	1.68	2.73	1.97
Gjøa (B1 LWI; LLP)	12.00 %	0.26	1.69	3.29	0.63	0.41	2.26	4.40	0.85
Statfjord (LPT pilot; SFC FFE)	23.93123 %	0.00	0.20	0.32	0.12	0.00	0.76	1.16	0.46
Total Net					10.2				13.4

Reserves – Total

Table 2: OKEA reserves as of 31 December 2024 in mmboe

3.2 Development of reserves

OKEA's reserves and resources are regularly updated through field development work, improvement of technical subsurface models, acquisitions/disposals, and production. Table 3 illustrates how the volumes have changed since ASR 2023 (31 December 2023).

Asset	EoY 2023		Production		Acquisitions / Disposals		Revisions of previous estimates		Projects matured		EoY 2024
	1P/ P90	2P/ P50	1P/ P90	2P/ P50	1P/ P90	2P/ P50	1P/ P90	2P/ P50	1P/ P90	2P/ P50	1P/ P90	2P/ P50
Bestla	0.00	0.00	0.00	0.00	0.00	0.00	0.00	0.00	6.78	8.34	6.78	8.34
Brage	1.25	2.94	-2.37	-2.37	0.00	0.00	3.01	2.04	0.79	1.83	2.68	4.44
Draugen	27.66	31.12	-3.35	-3.35	0.00	0.00	1.90	2.16	0.00	0.00	26.21	29.93
Gjøa	3.32	4.58	-1.62	-1.62	0.00	0.00	1.09	0.56	0.04	0.09	2.82	3.60
Ivar Aasen	3.76	4.74	-0.81	-0.81	0.00	0.00	-1.72	-0.17	0.00	0.00	1.23	3.76
Nova	2.85	4.20	-0.61	-0.61	0.00	0.00	-0.80	-1.28	0.02	0.26	1.46	2.57
Statfjord	11.78	20.90	-2.81	-2.81	0.00	0.00	-6.13	-7.49	4.36	6.23	7.20	16.83
Statfjord Nord	3.69	7.12	-0.86	-0.86	0.00	0.00	-1.13	-2.36	0.00	0.00	1.71	3.90
Statfjord Øst	2.29	3.85	-0.62	-0.62	0.00	0.00	-0.59	-1.28	0.00	0.00	1.08	1.94
Sygna	0.21	0.36	-0.08	-0.08	0.00	0.00	0.00	-0.01	0.00	0.00	0.13	0.27
Yme	2.42	3.44	0.00	0.00	-2.42	-3.44	0.00	0.00	0.00	0.00	0.00	0.00
Total	59.2	83.3	-13.1	-13.1	-2.4	-3.4	-4.4	-7.8	12.0	16.8	51.3	75.6

The "disposal" of Yme relates to the divestment of OKEA's 15% working interests to Lime Petroleum AS with effective date 1 January 2024.

Maturation of Bestla is a result of the PDO approval from November 2024. Maturation at Brage is linked to approval of three well projects (A-28 DT2, A-23 H, and A-34 E).

Maturation at Gjøa is linked to approval of the B-1 production well intervention. Maturation at Statfjord is related to the SFC FFE project and approval of wells to be drilled in 2025 and 2026.

Revisions of previous estimates on Draugen are mainly a result of production experiences more positive than expected related to Hasselmus and the associated restart of gas export.

The revisions on Statfjord and satellites are primarily the result of reduced economic lifetime for this asset resulting from increased operational expenses in the RNB2025. The accelerated economic cut-off results in lower reserves than technically recoverable resources. OKEA expects these revisions to be recovered by continued IOR (see section 4.2.11) and/or cost reduction measures.

The revision on Brage relates to an increased economic lifetime as result of the Bestla PDO approval. The revision of Nova estimates is a result of challenges regarding water injection.

3.3 Description of reserves

The following section describes fields on production and fields approved/justified for development where OKEA holds a working interest.

3.3.1 Draugen (PL093)

The Draugen field is in the Norwegian Sea, approximately 140 km Northwest of Kristiansund, in 250 meters water depth, c.f. Figure 3.2.

OKEA's working interest on Draugen is 44.56%. The other licensees are Petoro AS (47.88%) and M Vest Energy AS (7.56%).

Discovery

The field was discovered by well 6407/9-1 in 1984, proving oil in the Rogn formation. This was the first discovery in Rogn on the Haltenbanken terrace.

Reservoir

The oil is in the Garn and Rogn formations, of which the latter holds more than 90% of the reserves. The reservoir quality is excellent, with average permeability of more than 2 Darcy. The best well, A-4 A, has the offshore world record oil production rate reaching a peak of 77 000 bbl per day.

Development

The field is developed with a concrete gravity-based structure (GBS), with full oil stabilisation and storage capabilities. Oil is exported by shuttle tankers. Gas is exported through the gas pipeline connected to the Åsgard Transport System (ÅTS).

Figure 3.2: Draugen field location and adjacent area (Norwegian Sea)

The drainage strategy is based on centrally located production wells, supported by down-flank water injectors. The field was initially developed with 6 platform wells and 1 subsea well and has later been supplemented by several subsea wells. The platform wells have gas lift, while the subsea wells are produced via a subsea booster pump to lower the tubing head pressure.

Status

Gross production in 2024 amounted to 7.52 mmboe, equivalent to 3.35 mmboe net to OKEA. Approximately 69% of the production stems from oil export. A large fraction of the produced water is reinjected into the reservoir, for pressure support. The rest is discharged to sea. Gas and NGL are exported through the Åsgard Transport System (ÅTS).

Currently, 5 out of 6 platform wells and 9 out of 10 subsea wells are producing, in addition to 2 subsea water injectors. One subsea well (G-3 H) - injecting condensate until 1 October 2023 – is currently shut in. D-1 AH is shut in due to high water cut. Subsea wells G-1 H, G-2 H, G-5 H and all Ewells produce on reduced choke setting to maintain reservoir pressure. Production is continuously monitored and optimised by a production management team.

The reserves estimates are based on the RNB2025 submission by OKEA, assuming production until end of economic field lifetime at end of 2040. Note that the lifetime of the field has been extended through the Power from shore project, see below.

Some of the projects that contribute to the Draugen reserves are discussed below. Contingent resources related to the Draugen field are described in Section 4 and 5, respectively.

Hasselmus

Hasselmus is a gas accumulation above a 5.5 meters oil leg, 7 km northwest of the Draugen field, c.f. Figure 3.2. The structure was discovered by well 6407/9-9 in 1999 and is now part of the Draugen field.

The reservoir is a sand-prone interval of tidally influenced shallow marine deposits, interpreted to be laterally continuous with high Net to Gross ratio, close to 100% in the gas zone. Seismic interpretation indicates that the reservoir is not affected by any major internal faults.

Hasselmus is drained by a single vertical gas producer well, placed close to the crest of the structure. Gas expansion will be the main driving mechanism, possibly assisted by limited aquifer support. The oil leg will not be recovered.

Hasselmus is tied back to the Draugen platform via a subsea pipeline. To cater for future tie-ins from third party licences, a pipeline end manifold (PLEM) has been included in the design. Topside modification includes a re-bundling of the main export compressor, as well as heater and scrubber for the Hasselmus gas.

Hasselmus started production 1 October 2023. Production performance have been well above PDO-expectations and gas off-take rate is increased from 700,000 to 900,000 Sm³ /d by late October 2024. The associated export volumes are reported as reserves.

Restart of gas export

The Hasselmus development provides sufficient gas to meet Draugen's fuel consumption requirement and thereby allowed for restart of gas export from Draugen in 2023. Accordingly, expected NGL volumes produced from the Draugen field that are evacuated through the Åsgard transport system after Hasselmus start-up are reported as reserves.

Power from shore

The Draugen-Njord electrification shall provide electric power from shore (PfS) to both the Draugen field and the Njord field. The project was sanctioned (DG3) by the Draugen license and the Njord unit in 2022. Authority approval was obtained in December 2023. This measure will not only reduce emissions from the two platforms drastically, but also result in reduced OPEX and allow higher gas export from Draugen.

Lifetime to 2040

As a direct consequence of the PfS-project being sanctioned and approved, the economic lifetime of the field is extended to end of year 2040, yielding increased reserves.

3.3.2 Brage (PL055)

The Brage field is located in the North Sea, 125 km west of Bergen and between the Troll and Oseberg field at a water depth of 140 meters, c.f. Figure 3.3.

OKEA's working interest on Brage is 35.2%. The other licensees are Lime Petroleum AS (33.8434%), DNO Norge AS (14.2567%), Petrolia NOCO AS (12.2575%) and M Vest Energy AS (4.4424%).

Discovery

The Brage field was discovered with well 31/4-3 in 1980, proving oil and gas in Jurassic sandstones.

Reservoir

Brage produces oil from sandstones of Lower Jurassic age in the Statfjord Group and Cook Formation, and sandstones of Middle Jurassic age in the Brent Group and the Fensfjord Formation. There is also oil and gas in Upper Jurassic sandstones in the Sognefjord Formation. The reservoirs lie at a depth of 2,000-2,300 meters. The reservoir quality varies from poor to excellent.

Development

The plan for development and operation (PDO) was approved in 1990. The field has been developed with an integrated processing, drilling and accommodation facility with a steel jacket. Production started in 1993.

The Brage field is currently producing from five different reservoirs with different characteristics and recovery methods; the Statfjord, Cook, Fensfjord, Sognefjord formations, and the Brent group.

Due to the limited natural pressure support, water injection is required to maintain reservoir pressure.

Oil is transported by pipeline to the Oseberg field and further through the Oseberg Transport System (OTS) pipeline to the Sture terminal. A gas pipeline is tied-back to Statpipe transporting gas to Kårstø for processing and further export.

Figure 3.3: Location of the Brage Unit, the Bestla field, and adjacent area (North Sea)

Status

Gross production in 2024 amounted to 6.74 mmboe, equivalent to 2.37 mmboe net to OKEA. More than 72% of the production stems from oil export.

Approximately half of produced water is reinjected to the reservoir, whereas the rest is discharged to sea. In addition, water from Utsira is injected into the reservoir; this water is withdrawn from the Utsira formation using two water producers. Currently, Brage is producing from 23 producers and injecting water in 4 injectors.

The reserves estimates are based on the RNB2025 submission by OKEA. During 2024, three projects were matured to reserves: Brage Bowmore (A-28 DT2), Sognefjord East first producer (A-23H), and Fensfjord5000 (A-34 E). Contingent resources related to the Brage field are described in Chapter 4.2.5.

3.3.3 Bestla (PL740)

The Bestla field (formerly known as the Brasse discovery) is located in the PL740 license, in Block 31/7, approximately 13 km south of Brage and 13 km east of the Oseberg field, c.f. Figure 3.3.

OKEA's working interest in the Bestla field is 39.2788%. The other licensees are DNO Norge AS (39.2788%), Lime Petroleum AS (17%), and M Vest Energy AS (4.4424%).

Discovery

Discovered in June 2016 by well 31/7-1, the field consists of a low relief, three-way dip-closed structure with a stratigraphic pinch-out component to the north. The structure has been penetrated by six wellbores in total.

Reservoir

The main reservoir interval in the discovery is represented by the Sognefjord Formation (Upper Jurassic) with a gross hydrocarbon column of approximately 45 m, consisting of approximately 22 m of oil (36 °API) with a gas cap. The oil-water contact in the central and southern areas of the field is located at approximately 2,172.5 mTVDSS, with the gas-oil contact varying between 2148 mTVDSS (observed in well 31/7-1) and 2155 mTVDSS (observed in well 31/7-2 A). Well 31/7-3 A, drilled in the northern area of the field, encountered three oil-filled intervals, where the two deepest intervals had different oils (34°API) compared to the main area in the south. The two deeper sand intervals have been interpreted as smaller local closures separated from the main area.

Development

The field will be developed by two horizontal wells which will be tied back to the Brage platform.

Status

OKEA became partner and operator of the license in 2023. A PDO was submitted in march 2024, and approved in November 2024. Production is planned to start in 2027.

3.3.4 Gjøa (PL153)

The Gjøa field is in the northern part of the North Sea, 50 kilometres northeast of the Troll field, in the PL153 license, c.f. Figure 3.4. Water depth in the area is 360 meters.

OKEA's working interest on Gjøa is 12%. The other licensees are Vår Energi ASA (Operator, 30%), Petoro AS (30%), and Harbour Energy Norge AS (28%).

Discovery

The field was discovered by exploration well 35/9-1 / 35/9-1 R in 1989, confirming gas in the Viking Group and Brent Group, and oil in the Dunlin Group.

Reservoir

The Gjøa reservoir comprises the Upper Jurassic Viking Group, and the middle Jurassic Brent and Dunlin Groups. The oil column of 30-45 m and the gas column of approximately 200 m both have local variations. The reservoir is compartmentalised in seven segments, with heterogenous properties caused by alternating layers of good and poor reservoir sands, silts and shales. As a result, the porosity ranges from 10% to 27% and the permeability from hundreds of millidarcy to several darcy.

Development

The drainage strategy is managed pressure depletion with concurrent oil rim production. The field is developed with thirteen subsea wells (of which seven currently are shut in), connected to five templates and directed back to a semi-submersible unit with full oil stabilisation capacities. Advanced well technology with branches and zonal control is implemented, and all wells have multiphase meters and permanent downhole gauges. Oil is exported through the Troll oil pipeline to the Mongstad terminal, and gas is exported though the FLAGS pipeline to the St. Fergus terminal. In 2017, the production plant on Gjøa was upgraded to handle low pressure production to boost the reserves on Gjøa. The Gjøa platform was also the first floating platform with power from shore, reducing CO² emissions by 200 000 tonnes per year. Gjøa is host for the Vega, Duva and Nova fields.

Figure 3.4: Gjøa field location and adjacent area (North Sea)

Status

Gross production in 2024 amounted to 13.52 mmboe, equivalent to 1.62 mmboe net to OKEA. Approximately 90% of the production stems from export of gas and associated NGL.

The reserves estimate for Gjøa is based on the RNB2025 submitted by the operator, and includes reserves from the main field, the P1 redevelopment project, the B1 LWI project and the low low pressure (LLP) project.

Contingent resources related to the Gjøa field are discussed in Chapter 4.2.7.

3.3.5 Ivar Aasen Unit (PL338 BS)

The Ivar Aasen field is located in the North Sea, 8 km north of the Edvard Grieg field and around 30 km south of Grane and Balder, c.f. Figure 3.5. The water depth is 110 meters.

OKEA holds a 9.2385% working interest in the unit. The other licensees are Aker BP ASA (Operator, 36.1712%), Equinor Energy AS (41.473%), Sval Energi AS (12.3173%) and M Vest Energy AS (0.8%).

Discovery

Ivar Aasen was discovered with well 16/1-9 in 2008, proving oil and gas in Jurassic and Triassic sandstones. The Ivar Aasen field includes two accumulations: Ivar Aasen and West Cable. The accumulations cover several licences and have been unitised into the Ivar Aasen Unit.

Reservoir

The two accumulations are located on the Gudrun Terrace between the Southern Viking Graben and the Utsira High. The reservoir consists of shallow marine sandstones in the Hugin Formation and fluvial sandstones in the Sleipner and Skagerrak Formations and is of Jurassic and Triassic age. The reservoir depth is approximately 2 400 meters. The Ivar Aasen reservoir has a small overlying gas cap. The West Cable reservoir is in Sleipner fluvial sandstone of Middle Jurassic age and is located at 2 950 meters depth.

Development

The Ivar Aasen and West Cable discoveries are developed with a steel jacket platform, with living quarters and processing facilities. Drilling and completion operations are performed from a mobile jack-up rig adjacent to the Ivar Aasen platform. Water is removed from the well stream on the platform and oil and gas rates are measured before transportation through multiphase pipelines to the Edvard Grieg installation for stabilisation and export.

The drainage strategy for Ivar Aasen assumes water injection for pressure maintenance. West Cable was produced through natural pressure support where the major driving force was natural water influx and formation of a secondary gas cap.

The Ivar Aasen unit development plan (Ivar Aasen and West Cable discoveries) also includes production of the reserves from the Hanz (PL028B) discovery. The approved PDO sets out that Ivar

Figure 3.5: Ivar Aasen Unit and adjacent area (North Sea)

Aasen and West Cable (Ivar Aasen Unit) will be developed in the first phase and Hanz in the second phase. OKEA has no working interest in the Hanz field. Ivar Aasen started production in 2016.

Status

Gross production in 2024 amounted to 8.81 mmboe, equivalent to 0.81 mmboe net to OKEA. Approximately 73% of the production stems from oil export.

The reserves estimate for Ivar Aasen is based on the RNB2025 submitted by the operator. The drainage pattern in the east segment - particularly in the Skagerrak Formation - is still the main uncertainty in the reservoir.

Figure 3.5: Ivar Aasen field location and adjacent area (North Sea)

3.3.6 Yme (PL316)

OKEA divested its 15% working interest in Yme to Lime Petroleum AS in November 2024. Accordingly, the working interest, net reserves and net contingent resources from Yme at end of year 2024 are zero, c.f. table 1, table 2, and table 4. Since effective date of this transition was 1 January 2024, production from Yme has been excluded in table 3.

3.3.7 Nova (PL418)

Nova lies in Block 35, license PL 418, in the northern North Sea, 17 km southwest of Gjøa, c.f. figure 3.4. Water depth is 370 m. The field was discovered in 2012, with the well 35/9-7. The PDO was approved in 2018.

OKEA's working interest in Nova is 6%. The other licensees are Harbour Energy Norge AS (operator, 39%), Sval Energi AS (45%) and Pandion Energy AS (10%).

Reservoir

Intra Heather sands constitute the reservoir at Nova. These late Jurassic sands have been deposited in a turbiditic system and are eroded towards the southwest. The trap is stratigraphic with a structural component. The field can be split in three main areas: Main, Southeast and East, the first one being the most important one. The Intra Heather 2 Lower and Upper units constitute the main part of the reservoir. They are separated by a shale but are in communication through the faults. The Lower Unit has a 95% NTG, good connectivity and is of excellent quality. The upper Unit has a 60% NTG with a complex facies composition.

Development

The field is developed with two subsea templates: one four slot production template and one four slot template for water injection. The field is drained through pressure maintenance by water injection and gas lift. The producers are slanted to horizontal, completed with sand screens and gas lift. The production is tied back to Gjøa. The oil is exported through the Troll pipeline to the Mongstad terminal. The gas is exported though the FLAGS pipeline to the St. Fergus terminal.

Status

Production started in 2022. Initial problems with pressure support by water injection have been mitigated through drilling of a new injector W-1 AH and through additional perforations in W-2 H. However, lower-than-expected pressure support is still a limiting factor for production since the reservoir pressure needs to be kept above bubble point pressure to avoid the loss of reserves.

Gross production in 2024 amounted to 10.14 mmboe, equivalent to 0.61 mmboe net to OKEA. Approximately 73% of the production stems from oil export.

3.3.8 Statfjord (PL037)

Statfjord is one of the oldest producing fields on the NCS and located in the North Sea in the Tampen area on the border between the Norwegian and the UK sector, c.f. Figure 3.6. The field was discovered in 1974 and the PDO was approved in 1976. Production from the first platform, Statfjord A, commenced in 1979. Approximately 15% of the field is located in the UK sector.

OKEA's working interest on Statfjord is 23.93123%. The other licensees are Equinor Energy AS (operator, 40.17029%), Vår Energi ASA (21.36717%), and Equinor UK Limited (14.53131%). OKEA's working interest with respect to the Norwegian part of the Statfjord field is thus 28%.

Reservoir

The main producing intervals on the Statfjord field are the Brent (Middle Jurassic) and Statfjord (Late Triassic-Early Jurassic) Groups, with additional production from the Cook Formation in the Dunlin Group. The reservoirs of the Brent and Statfjord Groups are generally characterised by shallow marine to alluvial plain deposits of excellent quality. The Statfjord Group demonstrates more heterogeneity than the Brent Group and a higher degree of baffling.

Observed permeabilities are highly variable laterally and vertically, ranging from 0.001 to 1 millidarcy. The Statfjord Field has a very active aquifer giving natural pressure support.

Development

The Statfjord field is developed with three fully integrated concrete platforms; Statfjord A placed centrally on the field, Statfjord B in the southern part of the field with production start-up in 1982 and Statfjord C in the northern part of the field with production start-up in 1985.

In 2005 the Statfjord Late Life (SFLL) project was sanctioned. This introduced partial depressurisation of the Statfjord Field through accelerated liquid offtake to liberate gas from remaining oil, and to produce it together with the previously injected gas.

In Cook Formation and in some isolated reservoir segments in the eastern part of the field water and/or gas are injected to maximize oil recovery and support producers.

In 2019 the FLX (Field Lifetime eXtension) project was launched with further acceleration of the depressurisation and the gas liberation by an extensive drilling program targeting the main field.

Status

During 2024, five new producers have come on stream whilst 9 wells were on the drilling schedule at the beginning of the year.

Gross production in 2024 amounted to 10.04 mmboe, equivalent to 2.81 mmboe net to OKEA. More than 45% of the production stems from oil export.

3.3.9 Statfjord Nord (PL037)

Statfjord Nord (SFN) is located north of Statfjord, in the Tampen area, c.f. figure 3.6. Statfjord Nord was discovered in 1977 and the PDO was approved in 1990. Production started in 1995.

OKEA's working interest on Statfjord Nord is 28%. The other licensees are Equinor Energy AS (operator, 17%), Petoro AS (30%), and Vår Energi ASA (25%).

Reservoir

Production on Statfjord Nord is from reservoirs of the Upper Jurassic Munin Formation (turbidites) and the shoreface sands of the Etive and Rannoch Formations (Brent Group), both of which exhibit excellent reservoir quality.

Development

Statfjord Nord is a subsea development with two 4-slot production templates (E and F) with a total of 8 production wells and a single 4-slot injection template (D) with three injection wells to Statfjord Nord and one injection well to Sygna. The well stream is transferred through pipelines to the Statfjord C platform for processing, metering, and onward transportation.

Status

Gross production in 2024 amounted to 3.06 mmboe, equivalent to 0.86 mmboe net to OKEA. Approximately 90% of the production stems from oil export.

A new Etive producer was drilled from the F-4 well slot using the COSL Promoter drilling rig in Q2 2024. After an LWI operation, E-2 was put back in production in Q4.

Figure 3.6: Statfjord area map (North Sea)

3.3.10 Statfjord Øst (PL037)

The Statfjord Øst field is located in the Tampen area and northeast of the Statfjord field, c.f. Figure 3.6. Statfjord Øst was discovered in 1976. The PDO was approved in 1990 and the field started production in 1994.

OKEA's working interest on Statfjord Øst is 14%. The other licensees are Equinor Energy AS (operator, 29.25%), Petoro AS (30%), Vår Energi ASA (20.55%), JAPEX Norge AS (4.8%), and Wintershall Dea Norge AS (1.4%).

Reservoir

Production on Statfjord Øst is from high quality shoreface sands of the Upper to Lower Brent Group (Rannoch, Etive, Ness and Tarbert Formations).

Development

The Statfjord Øst field was originally developed with two production subsea templates (L and M) and one injection subsea template (K). The field is in pressure communication with the Statfjord field and has been on depletion since the cessation of water injection in 2008.

A revised PDO was approved in 2021 to provide gas lift to the two templates and redrill 2 wells on the L-template and 3 wells on the M-template. These wells were drilled between March 2023 and February 2024. The first well started production in August 2023.

Status

Gross production in 2024 amounted to 4.45 mmboe, equivalent to 0.62 mmboe net to OKEA. Approximately 62% of the production stems from oil export.

The main activities for Statfjord Øst in 2024 have been related to installation of xmas trees and starting up the new gas lift wells.

3.3.11 Sygna (PL037)

Sygna is located in the Tampen area and northeast of the Statfjord Nord field, c.f. Figure 3.6. Sygna was discovered in 1996. The PDO was approved in 1999 and production started the year after.

OKEA's working interest on Sygna is 15.4%. The other licensees are Equinor Energy AS (operator, 28.025%), Petoro AS (30%), Vår Energi ASA (20.995%), JAPEX Norge AS (4.32%), and Wintershall Dea Norge AS (1.26%).

Reservoir

Production on Sygna is from high quality shoreface sands of the Etive and Rannoch Formations (Brent Group).

Development

Sygna is a subsea development with a 4-slot subsea production template with 3 producers (N-1 H, N-2 AH, and N-3 H). The well stream is transferred through pipelines to the Statfjord C platform for processing, metering and onward transportation. The production strategy for Sygna is full voidage replacement maintaining the reservoir pressure around 330 bar.

The production wells on Sygna are placed high on the structure, whereas the water injector is located low on the structure in the western part of the field.

Status

Gross production in 2024 amounted to 0.52 mmboe, equivalent to 0.08 mmboe net to OKEA. All production stems from oil export.

4 Contingent resources

Contingent resources are proven oil and gas for which a production decision has not yet been made. Petroleum volumes in potential improved recovery projects are included in this category.

4.1 Total contingent resources estimates

OKEA holds contingent resources in several licenses, as shown in table 4. The contingent resources are verified by a third-party certification performed by AGR Petroleum Services.

Table 4: OKEA contingent resources as of 31 December 2024

Field or Discovery	OKEA WI		Gross Oil equivalents (mmboe)		Net Oil equivalents (mmboe)
		1C/P90	2C/ P50	3C/ P10	1C/ P90	2C/ P.50	P10
Aurora	65 %	10.16	12.98	19.27	6.60	8.44	12.53
Brage	35.2 %	22.12	43.83	67.95	7.79	15.43	23.92
Bestla	39.2788 %	1.33	2.93	4.88	0.52	1.15	1.92
Calypso	30 %	13.02	17.79	24.18	3.91	5.34	7.25
Draugen	44.56 %	26.94	32.60	38.58	12.00	14.53	17.19
Galtvort	44.56%	7.33	13.76	21.38	3.27	6.13	9.53
Gjøa	12 %	1.17	2.34	3.51	0.14	0.28	0.42
Hamlet	12 %	5.55	11.99	15.19	0.67	1.44	1.82
Ivar Aasen	9.2385 %	9.65	19.26	30.56	0.89	1.78	2.82
Nova	6 %	12.06	24.23	37.89	0.72	1.45	2.27
Statfjord	23.93123 %	26.59	37.99	49.38	6.36	9.09	11.82
Statfjord Nord	28 %	0.93	1.33	1.73	0.26	0.37	0.48
Statfjord Øst	14 %	3.56	4.92	6.29	0.50	0.69	0.88
Sygna	15.4 %	0.00	0.00	0.00	0.00	0.00	0.00
Total Contingent Volumes					43.6	66.1	92.9

Please note that totals in the table above are arithmetic and not stochastic summations. The aggregate Low (1C) may be a very conservative estimate and aggregate High (3C) may be a very optimistic one. Aggregates of Base (2C) results typically have less portfolio effect.

4.2 Description of contingent resources

The following section describes fields/discoveries with contingent resources where OKEA holds a working interest.

4.2.1 Aurora (PL195)

The Aurora discovery is situated in licenses PL195 and PL195 B, approximately 20 km west of Gjøa, c.f. figure 3.4. The water depth in the area is about 373 m.

OKEA became operator of the two licenses in October 2020 and holds a 65% working interest in each. The other partner is Petoro AS (35%).

Discovery

Aurora was discovered in 1988 through well 35/8-3. The well proved hydrocarbons in the Intra-Heather Formation sandstones. No gas-water contact was apparent, indicating gas down to 3,511 m TVDSS.

The discovery was appraised by well 35/8-4, which encountered no hydrocarbons, indicating water up to 3 611 m TVDSS. Seismic data suggests a major fault east of the discovery well. Consequently, any hydrocarbons east of this fault are considered prospective volumes.

Reservoir

Log analyses of the Heather sands indicated a probable gross gas column of 70 m with a net pay of 31.9 m. Average porosity in the net sand was 15.6% with an estimated average water saturation of 22%. Reservoir temperature is about 90 degree Celsius, and pressure is around 400 bar. No fluid samples were taken.

Development

OKEA has initiated a project regarding development of the Aurora discovery as a tie-in to Gjøa. Currently, the discovery is envisioned to be produced by means of a single gas producer well, possibly deviated, using pressure depletion as major driving mechanism. Tie-back to Gjøa can be accomplished by utilizing existing infrastructure in the area, related to the Vega, Nova and/or Gjøa developments.

Status

The development project was initiated in September 2020 and is currently working towards a decision to drill an appraisal well in 2026. First gas from Aurora could then be produced in 2030, given a positive outcome of the appraisal well and available capacity at Gjøa.

4.2.2 Calypso (PL938)

The Calypso gas and oil discovery is located in license PL938, approximately 12 km northwest of the Draugen Field, c.f. figure 3.2.

Neptune Energy Norge AS is the operator with a 30% interest. Partners are OKEA (30%), Pandion (20%) and Vår Energi (20%).

Discovery

Calypso was discovered in November 2022 with the 6407/8-8 S exploration well. The well encountered an estimated 8 meter thick gas column and a 33 m thick oil column in a 132 m thick Garn Formation.

Reservoir

The reservoir is of good to very good quality, with average permeability ranging from 100-1000 millidarcy and porosity averaging around 21%. The OWC is interpreted from pressure points and a total column from the oil-water contact to the crest of the structure is 41 m. The pressure is close to hydrostatic.

Development

The discovery is likely to be developed with one multilateral well with potentially one water injector as drive mechanism. Aquifer strength is currently being evaluated to better understand the need for water injection. A tie-back to Draugen may be achieved with pressure depletion as the main driving mechanism (depending on aquifer study outcome). The operator also considers Njord (via Hyme) as an alternative host.

Status

The development project was initiated in August 2023 and is currently working towards a DG1.

4.2.3 Galtvort (PL1223)

The Galtvort gas discovery is located in license PL1223, approximately 5 km northwest of the Hasselmus, c.f. fFigure 3.2.

OKEA ASA is the operator with Petoro and M Vest ENERGY AS as partners. The license interests are the same as for the Draugen field

Discovery

Galtvort was discovered in 2008 with wells 6407/8-4 S and –4 A. The wells encountered a gas column in the Garn and Tilje Formations.

Reservoir

The reservoir is of good to very good quality, with average permeability ranging from 100-1000 millidarcy and porosity averaging around 21%. The GWC is interpreted from pressure points at 2160 mTVD MSL close to hydrostatic pressure.

Development

The discovery is likely to be developed with one production well tied back to Draugen via the Hasselmus infra-structure.

Status

The development project was initiated in 2024 and is currently working towards a DG1 decision in 2025

4.2.4 Draugen IOR

The Draugen asset is described in section 3.3.1. During 2020 and 2021, the infill well target Garn West Sør close to the existing producer well D-2 H was identified. During summer 2023, two observation wells were drilled to this target, and the nearby Springmus target. Both wells proved oil at these locations. Detailed re-modelling of the two accumulations is ongoing.

The potential for increased injection by restoring PWRI to the Northern water injection template (NWIT) was investigated by injection at a high rate in the NWIT wells B-2 and B-5 the winter 2022-2023. The test revealed a significant potential for IOR, which additionally would provide for increased re-injection of produced water. The onset of injection is depending on an electrification of the Draugen platform facilities.

There are also more immature IOR targets, e.g., East Flank and Dansemus, that will be further scrutinized in the upcoming year. Similarly, a potential further extension of Draugen lifetime beyond 2040 is being evaluated.

4.2.5 Brage IOR

The Brage asset is described in section 3.3.2. The main method for increased recovery on the Brage Field is through infill drilling. Infill drilling for increasing the recovery is the main strategy for the future too, but also other methods for increased recovery are being evaluated.

One new project is added to the category "Development Unclarified" (RC 7A) during 2024, namely "Brage unit IOR upside" which includes several immature targets at Brage. In addition, some producers and exploration pilots are currently being matured compared to last year audit, mainly in Sognefjord East area. For 2025, it is planned to drill one producer in Talisker East Brent Upper Oseberg. Drilling of the first producer to Sognefjord East (A-23 H) will include two exploration pilot holes into Prince North and into Prince South.

In addition to the infill/development wells described above, a test production of Shetland Fm. will be performed through an intervention in well A-31 T2. Based on the results from this test production, the potential in Shetland will be evaluated. The RNB2025 contains also contingent volumes related to a possible lifetime extension.

4.2.6 Bestla IOR

The Bestla asset is described in section 3.3.3. The RNB2025 contains contingent volumes related to a possible lifetime extension.

4.2.7 Gjøa IOR

The Gjøa asset is described in section 3.3.4. The operator reports in RNB2025 contingent volumes related to gas cap blowdown in the P4 segment.

4.2.8 Hamlet

The Hamlet discovery was proven in spring 2022 by Neptune and is located in the licenses PL153 (Gjøa) and PL153 C. It is now referred to as Gjøa Nord.

Reservoir

The Hamlet discovery is composed of stacked turbiditic sands from the Agat Fm. Three main sands are identified from seismic and well observations with permeabilities between 10 and 400 millidarcy.

Development

The drainage strategy is pressure depletion with at least one producer well. The well flow would be brought back to Gjøa via the G template (P1 segment). An investment decision was attempted ("Gjøa Nord project"), but not obtained in December 2022. The license is now evaluating the possibility to develop Hamlet together with the Ofelia discovery, made in 2022 in the neighbouring license, north of Hamlet.

4.2.9 Ivar Aasen IOR

The Ivar Aasen asset is described in section 3.3.5. Several infill drilling opportunities have been identified on Ivar Aasen and are currently in various stages of maturation. During 2024, the IOR2026 campaign passed DG0. The base case is drilling 4 out of 7 identified targets in 2026.

The process of building a new reservoir model is ongoing. The gas blowdown on Ivar Aasen has been identified as a late life opportunity, and maturation will continue late 2025.

4.2.10 Nova IOR

The Nova asset is described in section 3.3.7. The operator reports in RNB2025 contingent resources related to well interventions and infill drilling. These projects are included in the ASR.

4.2.11 Statfjord IOR

The Statfjord asset is described in section 3.3.8. The operator reports in RNB2025 contingent resources related to several IOR measures, including infill drilling, recompletions and modifications. These projects are included in the ASR.

4.2.12 Statfjord Nord IOR

The Statfjord Nord asset is described in section 3.3.9. The operator reports in RNB2025 contingent resources related to infill drilling and interventions. These projects are included in the ASR.

4.2.12 Statfjord Øst IOR

The Statfjord Øst asset is described in section 3.3.10. The operator reports in RNB2025 contingent resources related to infill drilling. These projects are included in the ASR.

5 Management discussion and analysis

The reported 2P/P50 reserves include volumes which are believed to be recoverable based on reasonable assumptions about future economical, fiscal and financial conditions. Discounted future cash flows after tax are calculated for the various fields on the basis of expected production profiles and estimated proven and probable reserves. Cut-off time for the reserves is set at zero cash flow. The company has used a long-term inflation assumption of 2%, a long-term exchange rate of USD/NOK 9.5, and a long-term oil price of 76 USD/bbl (real 2024 terms).

The calculations of recoverable volumes are however associated with significant uncertainties. The 2P/P50 estimate represents our best estimate of reserves/resources while the 1P/P90 figures reflect our high confidence estimates. The methods used for subsurface mapping do not fully clarify all essential parameters for either the actual hydrocarbons in place or the recoverability of the hydrocarbons. Thus, there is a risk that actual results may be lower than the 1P/P90. A significant change in oil prices may also impact the economical reserves. Low oil prices may force the licensees to shut down producing fields early and lead to lower production. Similarly, betterthan-expected reservoir performance or higher oil prices may extend the lifetime of the fields beyond what is currently premised.

During 2024, net reserve reduced from 83 to 76 mmboe. The positive contribution from the Bestla development, was largely offset by volumes produced during the year, the divestment of Yme, and accelerated economic cut-off on Statfjord. A key focus for OKEA in the coming year, will be to work with the operator at Statfjord by focusing on IOR and cost reduction measures to improve this outlook. In addition, OKEA will continue develop volumes by infill and production drilling at Brage and other assets and look for inorganic growth opportunities. The company is also building a portfolio of prospects in the Norwegian Sea and North Sea basins and expects the results of four exploration wells in 2025.

Svein Jakob Liknes

CEO

Contact OKEA: okea@okea.no +47 73 52 52 22

IR contacts: Birte Norheim, CFO

birte.norheim@okea.no +47 952 93 321

Stig Hognestad, VP Investor Relations

stig.hognestad@okea.no +47 902 59 040

Trondheim Oslo Stavanger Kristiansund Bergen Kongens gate 8 Tordenskioldsgate 8-10 Kongsgårdbakken 1-3 Råket 2 Espehaugen 32 7011 Trondheim 0160 Oslo 4005 Stavanger 6516 Kristiansund 5258 Bergen