Q1 2026 report

Quarterly report Q1 2026

Highlights and key figures Financial review Operational review Financial statements Notes

Highlights and key figures

First quarter 2026

(Figures in brackets refer to previous quarter)

2 OKEA ASA Q1 2026

Highlights and key figures Financial review Operational review Financial statements Notes

Operational performance

Financial performance

Portfolio development

• Production of 34.9 (30.8) kboepd; increase mainly due to Talisker East on stream at Brage

• Production efficiency at 96 (91)%

• Drilling of Garn West South production well completed; commissioning challenges push back expected start-up to the third quarter of 2026

• TRIF decreased to 5.3 (6.0); no lost-time-injuries during the quarter

• Petroleum revenues of USD 264 (103) million; increase mainly due to higher realised prices as well as an overlift

• EBITDA of USD 129 (50) million

• Reversal of impairment of USD 154 (impairment of 62) million mainly due to increased forward prices; related post-tax income of USD 34 (expense of 17) million

• Net profit of USD 36 (loss of 18) million

• Total cash balance of USD 269 (234) million

• Recoverable resource estimates for Talisker West increased to 23-44 (16-33) mmboe; reducing expected break-even cost to less than 10 USD/boe

• Divested 20% WI in Mistral (PL1119) for a fixed consideration of USD 30 million; in addition, a contingent consideration ensures that OKEA retains an upside given a commercial Mistral Nord discovery

• Bestla and Power from Shore projects progressing according to plan

3 OKEA ASA Q1 2026

Highlights and key figures Financial review Operational review Financial statements Notes

Message from the CEO

I am pleased to report a strong start to 2026 with production in the first quarter of 34.9 kboepd. Sold volumes was as high as 39.1 kboepd during a period with increasing oil and gas prices. The high activity level is continuing and was managed without any serious incidents recorded in the quarter.

Following commencement of the Talisker East well in early January, production from Brage increased by 60% - a level not produced on Brage since 2012. In addition, through further subsurface maturation of the Talisker West Statfjord formation, recoverable resources (P50) have increased from 19 to 28 million barrels of oil equivalents (mmboe). The development concept remains unchanged and with the increase in volumes, expected break-even cost is reduced to less than 10 USD/boe.

At Draugen, the Garn West South production well was completed and rig released. Commissioning challenges has pushed back expected start-up to the third quarter of 2026.

We continue to optimise our exploration portfolio. In April, we entered into an agreement with Japex Norge AS to sell our 20% WI in Mistral (PL1119) for a fixed consideration of USD 30 million. The divestment strengthens OKEA's balance sheet and maintains focus on our core assets.

Our development projects are progressing to plan. At Bestla, pull-in of flow-lines to Brage is ongoing and construction of the onshore facilities for the Draugen Power from Shore project has been completed.

With an ongoing war in the Middle East, the global energy market has been highly volatile. We have delivered a strong quarter operationally and realised the highest prices since early last year. We keep our focus on the key tasks ahead and on what we can control to continue to create value for our shareholders.

Svein J. Liknes

Chief Executive Officer

Highlights and key figures Financial review Operational review Financial statements Notes

‌Financial review

Statement of comprehensive income

Amounts in USD million

Q1 2026 Q4 2025

Q1 2025

2025

Total operating income of USD 239 (107) million comprises:

• Revenues from sales of petroleum products of USD 264 (103) million. The increase was due to higher lifted crude volumes and increased market prices. Sold volumes amounted to 39,138 (20,419) boepd. Realised liquids prices comprises USD 79.5 (62.1) per boe for crude and USD

  46.4 (40.9) per boe for NGL. With NGLs constituting 16% (45%) of liquids volumes sold in the quarter, the average realised liquids price ended at USD 74.2 (52.4) per boe. Average realised price for natural gas amounted to USD 76.5 (57.4) per boe.

• Other operating income arrived at a net loss of USD 25 (income of 4) million, mainly driven by an unrealised hedging loss relating to collar hedges on crude, of USD 29 (gain of 1) million. The loss was driven by increased forward prices and was partly offset by tariff income at Gjøa and Statfjord of USD 6 (5) million.

  Total operating expenses of USD 15 (165) million comprises:

  Production expenses of USD 91 (87) million, corresponding to USD 26.7 (28.8) per boe. The increase in cost was driven by an intervention campaign at Draugen and preparations for maintenance campaigns scheduled for the second quarter on both Brage and Statfjord B. The reduction in cost per boe was a result of increased production.

  Changes in over-/underlift positions and production inventory resulting in an expense of USD 7 (income of 39) million as sold volumes exceeded produced volumes.

  Depreciation of oil and gas properties amounting to USD 59 (46) million. The increase was mainly due to higher production.

  Reversal of previous impairments at Statfjord amounted to USD 154 (impairment of 62) million. The reversal was driven by increased forward prices.

• Exploration and evaluation expenses of USD 8 (6) million.

• General and administrative expenses of USD 5 (3) million.

  Net profit of USD 36 (loss 18) million comprises:

• Profit from operating activities of USD 224 (loss of 58) million.

• Net financial income of USD 6 (expense of 2) million mainly driven by a net foreign exchange rate gain of USD 10 (loss of 1) million, partly offset by net accretion on asset retirement obligations and -rights.

• Tax expense of USD 193 (income of 42) million.

• Earnings per share amounted to USD 0.35 (loss of 0.17).

Statement of financial position

NOK/USD exchange rate at the reporting date 9.75 10.08 10.55

Goodwill of USD 94 (91) million comprises USD 78 (75) million of technical goodwill and USD 17 (16) million of ordinary goodwill. The increase was due to foreign exchange rates at balance sheet date.

Oil and gas properties amounted to USD 886 (677) million. The increase was largely driven by the reversal of impairment at the Statfjord asset of USD 154 million. In addition, investments amounted to USD 84 (110) million, mainly relating to production drilling at Draugen and Statfjord as well as progress in the Bestla and Power from Shore development projects. These effects were partly offset by depreciation.

Other non-current assets of USD 499 (487) million mainly comprise asset retirement reimbursement rights of USD 445 (436) million relating to the obligation to Equinor, Shell and Harbour Energy to cover decommissioning costs for Statfjord, Draugen, Gjøa and Brage respectively. Capitalised exploration and evaluation assets amounted to USD 35 (33) million, while right-of-use assets amounted to USD 14 (13) million.

Cash and cash equivalents amounted to USD 210 (252) million.

Other current assets of USD 369 (309) million mainly comprise trade and other receivables of USD 202 (144) million, spare parts, equipment and inventory of USD 76 (79) million, placement of excess liquidity in money-market funds of USD 59 (57) million, and current portion of asset retirement reimbursement rights of USD 32 (29) million.

Interest bearing bond loans of USD 295 (295) million comprise the OKEA05 and OKEA06 bonds.

Other long-term liabilities of USD 1,254 (1,086) million mainly comprise asset retirement obligations of USD 994 (963) million which are partly offset by the asset retirement reimbursement rights outlined above. In addition, deferred tax liabilities amounted to USD 240

(104) million. The increase in deferred tax was driven by the reversal of asset impairments on Statfjord.

Income tax payable amounted to USD 70 (26) million.

Other current liabilities of USD 344 (352) million mainly comprise trade and other payables of USD 303 (308) million.

Statement of cash flows

Net cash flows from operating activities amounted to USD 70 (18) million. The increase in cashflow from operations was mainly due to the higher income in the quarter, partly offset by changes in working capital of USD 45 (22) million.

Net cash flows from investment activities of USD -118 (-126) million mainly relate to investments in oil and gas properties of USD 117 (108) million. The investments mainly relates to production drilling and the Bestla and Power from Shore development projects.

Net cash flows from financing activities of USD -1 (-15) million includes interest paid of USD 0.5 (14) million.

Cash and cash equivalents ended at USD 210 (252) million. Reference is made to note 18 for further details. In addition to the cash balance, USD 59 (57) million was placed in money-market funds classified as other current assets.

Financial risk management

OKEA addresses financial risk by use of derivatives and fixed price contracts to manage exposures to fluctuations in commodity prices and foreign exchange rates.

Financial hedging arrangements on foreign exchange exposure, CO2 quotas and oil and gas options are recognised at market value on each balance sheet date.

Hedging positions on crude oil and gas production as per the date of this report:

With an ongoing war in the Middle East, the global energy market has been highly volatile. At the reporting date, the company's collar based hedging portfolio carried a loss of USD 29 (gain of 1) million which was recognised in other income in the statement of comprehensive income. The loss was mainly driven by crude forwards trading above the upper bounds of the collars. The valuations reflect market conditions at the reporting date for all existing hedging positions.

The programme continues to provide downside protection for future revenues with certain limits on upsides.

Highlights and key figures Financial review Operational review Financial statements Notes

‌Operational review

Key operational figures

Produced volumes amounted to 34,888 (30,848) boepd. Production efficiency during the quarter was as high as 96 (91)%. The increase in production was mainly a result of start-up of the Talisker East well at Brage in January. In addition, Draugen and Statfjord both delivered increased production as a result of high production efficiency.

Production expenses amounted to USD 26.7 (28.8) per boe. The higher than average cost was driven by an intervention campaign on Draugen and preparations for maintenance campaigns to take place in the second quarter on both Brage and Statfjord B. These effects were somewhat offset by the increased production in the quarter.

Note, Production efficiency is calculated as actual production of main product divided by the total of actual production of main product, scheduled deferment and unscheduled deferment. Deferment is the reduction in production caused by a reduction in available production capacity.

QHSSE and ESG

Preventing harm to people's health and the environment is a key priority, and work to ensure safe working conditions is a continuous focus in OKEA.

With no serious incidents recorded in the quarter, SIF was reduced to 0.4 (0.5). There were no lost time injuries and one medical treatment incident which resulted in a reduction in TRIF to 5.3 (6.0).

There were no serious acute spills or hydrocarbon leakages from OKEA-operated assets during the quarter. GHG emissions intensity was 28 (31) kg CO2e per boe produced.

The share of females recruited was 38 (34)%.

2 Net compensation volumes from Duva and Nova received and sold (tie-in to Gjøa)

3 Definitions of alternative performance measures are available on page 42 of this report

OKEA operated assets

Draugen (operator, 44.56%)

The increase in production volumes reflects minimal downtime throughout the quarter with stable operations.

Drilling of the Garn West South production well was completed in the quarter. Commissioning challenges push back expected start-up to the third quarter of 2026.

The light-well intervention project on Draugen did not solve the scaling issues on the D2 well. Alternative solutions to get the well back in production are currently being assessed.

Brage (operator, 35.2%)

Production efficiency increased to 98% and Brage delivered ~60% increase in production volumes following start-up of the Talisker East production well in January combined with strong operational performance.

Planning of a three week maintenance shutdown to start in May is ongoing.

The Bestla project continues to progress according to plan, with first production at Brage expected from early 2027.

Partner operated assets

Statfjord area (partner, 28%)

The increase in production volumes was driven by higher uptime across all the Statfjord assets.

Drilling of the first oil hunter well has been completed. Due to low reservoir pressure, oil production from the well did not meet expectations. The oil hunter program will continue with two additional wells planned drilled, expected next year.

Planning of a maintenance shutdown at Statfjord B to take place in the second quarter is ongoing, expected to last about six weeks.

Gjøa G Nova (partner, 12% G 6%)

Production efficiency remains strong. The reduction in production volumes was a result of natural decline. Planning of the subsea tie-back, Gjøa Nord, and infill wells at Nova are ongoing.

Several tie-in candidates are being evaluated for connection to Gjøa as a potential host, including the Gjøa Nord discovery within the Gjøa license, which passed DG2 in December 2025.

Ivar Aasen (partner, 9.2385%)

Production efficiency remains high and production is stable.

The planned IOR26 campaign is scheduled to commence in the fourth quarter with drilling of four wells. Production from the first well is expected around year-end.

Development projects

Draugen - Power from Shore (operator, 44.56%)

The construction work for the onshore facility was completed and all large high-voltage components have arrived at site. Equipment installation and commissioning has commenced and is expected completed in 2026. Communication tests between Draugen and the Skardmyra onshore facility has been successfully completed. Offshore construction activities continue at full capacity.

The project will result in an average annual reduction of CO2 emissions of 200,000 tonnes from Draugen and 130,000 tonnes from Njord as well as an average annual reduction of NOx emissions of 1,250 tonnes from Draugen and 520 tonnes from Njord. The project is also expected to result in reduced production expenses, reduced amount of gas required for power generation, and will extend the economic life of the Draugen field. Project completion is expected in 2028.

Bestla (operator, 39.2788%)

The Bestla project is progressing according to plan with all key milestones on schedule. Drilling of the production wells were completed in the fourth quarter and marine subsea and topside installation activities have commenced.

All subsea deliverables remain on plan. In April the flow-lines pull-in to Brage was completed, with piping currently being deployed to connect flow-lines to Bestla. Preparations for the critical scope planned during the scheduled maintenance campaign at Brage in May, have also been completed.

The Bestla field is developed as a two-well tie-back to the Brage field and contains estimated gross recoverable reserves of 24 mmboe. Expected production is early 2027. Plateau production is expected within the first year of production with approximately 10 kboepd net to OKEA.

Exploration

Increased discovery estimate for Talisker West

The Talisker West discovery is located at the Brage field in the North Sea. Through further subsurface maturation of the Talisker Statfjord formation, recoverable resource estimates (P50) have increased from 19 to 28 million barrels of oil equivalents (mmboe). Total recoverable volume estimates from the Statfjord and Cook formations combined have increased to 23 - 44 mmboe, up from the previous estimate of 16 - 33 mmboe.

The development concept remains unchanged. With the increase in volumes, expected break-even cost has been reduced to less than 10 USD/boe. Production is expected in 2027.

Realising value from the Mistral discovery

In April, OKEA entered into a sale and purchase agreement with Japex Norge AS to sell its 20% WI in the Mistral (PL 1119) licence for a fixed consideration of USD 30 million. In addition, a contingent consideration ensures that OKEA retains an upside given a commercial Mistral Nord discovery. As a post-tax consideration, the positive net profit after tax impact of the transaction is estimated to USD 25 million. The gain will be recognized upon closing, which is expected by the end of the third quarter of 2026.

Update on key exploration projects:

OKEA farmed into the PL 1270 licence by entering into an agreement with DNO Norge AS for a 30% WI in the licence. Infrastructure is present in tie-back distance to Tyrihans. The transaction has been approved by the Ministry of Energy.

Effective 1 January 2026, OKEA swapped its 20% WI in PL 1260 containing the K2/Grieg prospect with 30% additional WI in PL 1255/1255B. OKEA aims to take over the operatorship, subject to partner and Ministry approval. Partners in the PL 1255/1255B licence include Equinor (30% WI), DNO Norge AS (20% WI) and OKEA ASA (50% WI post transaction). The transaction is subject to customary Ministry approvals.

The PL 1153 Alpehumle prospect (20% WI) is scheduled for spud in the second quarter of 2026. The well is operated by AkerBP.

The PL 1214 Kyllinglår prospect (28% WI) is scheduled for spud in the first quarter of 2027. The well is operated by Equinor and is planned drilled from existing infrastructure in the Statfjord Nord field.

The PL 1014 Arkenstone well (20% WI) is a high-risk/high-reward opportunity located in the Northern Norwegian Sea and operated by Equinor. The license partners continue to mature the exploration well design, and timing for drilling is being assessed.

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Highlights and key figures Financial review Operational review Financial statements Notes

‌Financial statements with notes Q1 2026

Statement of comprehensive income

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Statement of comprehensive income - continues

Statement of financial position

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Statement of changes in equity

Statement of cash flows

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Statement of cash flows - continues

‌Notes to the interim financial statement

1. General and corporate information

   These financial statements are the unaudited interim condensed financial statements of OKEA ASA for the first quarter of 2026.

   OKEA ASA ("OKEA" or the "company") is a public limited liability company incorporated and domiciled in Norway, with its main office located in Trondheim. The company's shares are listed on the Oslo Stock Exchange under the ticker "OKEA".

   OKEA is a leading mid- and late-life operator on the Norwegian continental shelf (NCS).

2. Basis of preparation

   The interim financial statements have been prepared in accordance with IAS 34 Interim Financial Reporting. The interim financial statements should be read in conjunction with the annual financial statements for 2025. The annual financial statements for 2025 were prepared in accordance with IFRS® Accounting Standards (IFRS) as adopted by the European Union (EU) and in accordance with the additional requirements following the Norwegian Accounting Act.

   All figures in the financial statements are presented in USD. OKEA's functional currency is NOK, however from Q1 2025 the company has presented its financial statements in USD.

   For presentation purposes, balance sheet items are translated from functional currency to presentation currency using spot rates at the balance sheet date. Items recognised in profit or loss and other comprehensive income are translated from functional currency to presentation currency using average exchange rates for the periods presented, or exchange rates at transaction dates where these differ significantly. Historical exchange rates are used for share capital and share premium.

   The interim financial statements were authorised for issue by the company's board of directors on 28 April 2026.

3. Accounting policies

   The accounting policies adopted in the preparation of the interim financial statements are consistent with those followed in the preparation of the annual financial statements for 2025. New standards, amendments and interpretations to existing standards effective from 1 January 2026 did not have significant impact on the financial statements.

4. Critical accounting estimates and judgements

   Preparation of the interim financial statements entails use of judgements, estimates and assumptions that affect the application of accounting policies and the amounts recognised as assets and liabilities, income and expenses. The estimates, and associated assumptions, are based on historical experience and other factors that are considered as reasonable under the circumstances. The actual results may deviate from these estimates. The material assessments underlying the application of the company's accounting policies, and the main sources of uncertainty, are the same for the interim financial statements as for the annual accounts for 2025.

5. Business segments

   The company's only business segment is development and production of oil and gas on the Norwegian continental shelf.

6. Income

   Breafidown of petroleum revenues

   Amounts in USD `000	Q1 2026	Q4 2025	Q1 2025	2025
   Sale of liquids	187,699	53,550	191,175	546,950
   Sale of gas	76,081	49,208	75,220	236,734
   Total petroleum revenues	263,779	102,758	266,395	783,684
   Sale of liquids (boe)	2,528,107	1,021,035	2,624,367	8,346,651
   Sale of gas (boe)	994,292	857,553	891,559	3,386,709
   Total sale of petroleum in boe4	3,522,399	1,878,588	3,515,925	11,733,360

   Other operating income

   Amounts in USD `000	Q1 2026	Q4 2025	Q1 2025	2025
   Gain / loss (-) from put/call options, oil	-27,513	175	-269	-209
   Gain / loss (-) from put/call options, gas	-2,126	461	992	2,210
   Gain / loss (-) from forward contracts, CO2 quotas	-2,119	448	-119	478
   Change in fair value contingent consideration (see note 26)	-383	-479	-207	1,123
   Tariff income	5,973	4,942	4,477	19,929
   Sale of licences	0	300	110	846
   Income/expense from commercial agreements	-59	-2,017	0	-2,017
   Joint utilisation of logistics resources	1,353	540	66	2,058
   Total other operating income/loss (-)	-24,873	4,371	5,051	24,417

   4 Barrels of oil equivalents

7. Production expenses G changes in over/underlift positions and production inventory

   Production expenses

   Amounts in USD `000	Q1 2026	Q4 2025	Q1 2025	2025
   From licence billings - producing assets	78,191	77,216	50,261	254,043
   Other production expenses (insurance, transport)	11,633	8,577	9,978	40,484
   G&A expenses allocated to production expenses	1,472	1,445	1,516	5,535
   Total production expenses	91,295	87,239	61,754	300,062

   Changes in over-/underlift positions and production inventory

   Amounts in USD `000	Q1 2026	Q4 2025	Q1 2025	2025
   Changes in over-/underlift positions	375	30,132	-2,020	-2,550
   Changes in production inventory	-7,152	8,699	-10,831	1,821
   Changes in over-/underlift positions and production inventory	-6,776	38,831	-12,851	-729

8. Exploration and evaluation expenses

   Amounts in USD `000	Q1 2026	Q4 2025	Q1 2025	2025
   Share of exploration and evaluation expenses from participation in licences excluding dry well impairment, from billing	1,858	3,820	2,861	13,220
   Share of exploration expenses from participation in licences, dry well write off, from billing	22	-501	5,169	12,346
   Seismic and other exploration and evaluation expenses, outside billing	4,690	343	1,164	14,762
   G&A expenses allocated to exploration expenses	1,105	2,398	199	3,135
   Total exploration and evaluation expenses	7,675	6,060	9,393	43,464

9. Taxes

   Income taxes recognised in the income statement

   Amounts in USD `000	Q1 2026	Q4 2025	Q1 2025	2025
   Change in deferred taxes current year	-128,685	-10,791	-21,114	23,247
   Taxes payable current year	-64,899	53,150	-79,598	-45,349
   Tax payable adjustment previous year	4,720	40	-111	1,475
   Change in deferred taxes previous year	-4,567	0	24	-1,166
   Total taxes (-) / tax income (+) recognised in the income statement	-193,431	42,399	-100,799	-21,793

   Reconciliation of income taxes

   Amounts in USD `000	Q1 2026	Q4 2025	Q1 2025	2025
   Profit / loss (-) before income taxes	229,822	-60,078	122,127	-32,874
   Expected income tax at tax rate 78.004%	-179,270	46,863	-95,264	25,643
   Permanent differences, including impairment of goodwill	-1,047	-3,665	-12,369	-53,824
   Effect of uplift	1,198	1,207	1,351	5,491
   Financial and onshore items	-14,465	-2,046	5,280	610
   Change valuation allowance	0	0	517	-39
   Adjustments previous year and other	153	40	-314	325
   Total income taxes recognised in the income statement	-193,431	42,399	-100,799	-21,793
   Effective income tax rate	84%	71% 83% (66%)

   Specification of tax effects on temporary differences, tax losses and uplift carried forward

   Amounts in USD `000	31.03.2026	31.12.2025	31.03.2025
   Tangible and intangible non-current assets	-663,378	-499,711	-497,687
   Provisions (net ARO), lease liability, pensions and gain/loss account	463,214	441,348	392,890
   Interest bearing loans	-5,494	-3,253	-1,763
   Current items (spareparts and inventory)	-34,626	-42,322	-33,418
   Tax losses carried forward, onshore 22%	617	597	28
   Valuation allowance (uncapitalised deferred tax asset)	-617	-597	-28
   Total deferred tax assets / liabilities (-) recognised	-240,285	-103,939	-139,977

   Specification of tax payable

   Amounts in USD `000	Total
   Tax payable at 1 January 2026	25,548
   Tax paid	-16,718
   Tax payable adjustment previous year	-4,720
   Tax payable current year recognised in the income statement	64,899
   Foreign currency translation effects	729
   Tax payable at 31 March 2026	69,737

   Total deferred tax assets / liabilities (-)

   Amounts in USD `000	Total
   Deferred tax assets / liabilities (-) at 1 January 2026	-103,939
   Deferred tax current year recognised in the income statement	-128,685
   Change in deferred taxes previous year	-4,567
   Foreign currency translation effects	-3,095
   Total deferred tax assets / liabilities (-) 31 March 2026	-240,285

10. Tangible assets and right-of-use assets

    	Oil and gas properties		Furniture,
    Amounts in USD `000	Assets under development	Assets in production	fixtures and office machines	Right of use assets	Total
    Cost at 1 January 2026	360,047	1,401,201	5,799	35,589	1,802,636
    Additions	43,570	47,630	-18	459	91,641
    Reclassification from exploration	0	-207	0	0	-207
    Removal and decommissioning asset	839	-515	0	0	324
    Disposals	0	0	0	0	0
    Foreign currency translation effects	11,956	46,905	195	1,193	60,249
    Cost at 31 March 2026	416,412	1,495,014	5,976	37,241	1,954,644
    Accumulated depreciation and impairment at 1 January 2026	0	-1,084,470	-1,820	-22,211	-1,108,501
    Depreciation	0	-58,150	-202	-525	-58,876
    Impairment (-) and reversal of impairment	0	154,071	0	0	154,071
    Additional depr. of IFRS 16 ROU assets presented net in the income statement from leasing contracts entered into as licence operator	0	0	0	58	58
    Foreign currency translation effects	0	-36,694	-61	-744	-37,499
    Accumulated depreciation and impairment at 31 March 2026	0	-1,025,242	-2,082	-23,422	-1,050,747
    Carrying amount at 31 March 2026	416,412	469,772	3,894	13,819	903,897

11. Goodwill, exploration and evaluation assets and other intangible assets

    Amounts in USD `000	Other intangible assets	Exploration and evaluation assets	Technical goodwill	Ordinary goodwill	Total goodwill
    Cost at 1 January 2026	1,759	32,512	262,034	177,972	440,006
    Additions	0	1,276	0	0	0
    Disposals	0	0	0	0	0
    Expensed exploration expenditures temporarily capitalised	0	0	0	0	0
    Foreign currency translation effects	59	1,088	8,797	5,975	14,773
    Cost at 31 March 2026	1,819	34,876	270,832	183,947	454,779
    Accumulated depreciation at beginning of period	-54	0	0	0	0
    Accumulated impairment at beginning of period	0	0	-186,977	-161,778	-348,755
    Depreciation	-46	0	0	0	0
    Impairment	0	0	0	0	0
    Foreign currency translation effects	-2	0	-6,277	-5,431	-11,709
    Accumulated depreciation and impairment at 31 March 2026	-102	0	-193,254	-167,210	-360,464
    Carrying amount at 31 March 2026	1,716	34,876	77,577	16,737	94,315

12. Impairment / reversal of impairment

    Tangible and intangible assets are tested for impairment / reversal of impairment whenever indicators are identified and at least on an annual basis. Impairment is recognised when the book value of an asset or cash generating unit exceeds the estimated recoverable amount. The recoverable amount is the higher of the asset's fair value less costs to sell and value in use and is estimated based on discounted future cash flows. The discount rate applied represents the weighted average cost of capital (WACC).

    Technical goodwill arises as an offsetting account to the deferred tax recognised in business combinations and is allocated to each Cash Generating Unit (CGU). Technical goodwill will be impaired during the life-time of the CGU and is a non-cash expense. As reserves are produced, depreciation of the oil and gas properties (CGU) reduces deferred tax and exposes technical goodwill for impairment.

    Fair value assessments of the company's right-of-use (ROU) asset-portfolio are included in the impairment test.

    Valuation of oil and gas properties and goodwill are inherently uncertain due to the judgemental nature of the underlying estimates.

    Key assumptions applied in the impairment test at 31 March 2026 stated in real terms:

    Year	Oil USD/BOE	Gas GBP/ therm	Currency rates USD/NOK
    2026	91.8	1.22	9.8
    2027	73.8	1.02	9.8
    2028	71.9	0.76	9.9
    2029	77.2	0.75	10.0

    10.0	Change	Increase in assumption	Decrease in assumption	Increase in assumption	Decrease in assumption
    	Oil and gas price +/- 10%	-187,468	-1,472	-33,398	152,599
    	Oil and gas price forward period +/- 10%	-187,468	-97,523	-33,398	56,547
    	Currency rate USD/NOK +/- 1.0 NOK	-187,468	-78,950	-33,398	75,121
    	Discount rate +/- 1% point	-150,400	-142,574	3,671	11,497
    	Environmental cost (CO2 and NOx) +/- 20%	-101,884	-187,468	52,187	-33,398

    From 2030 77.3 0.75

    Future capex, opex and abandonment cost are calculated based on expected production profiles and the best estimate of related cost. The nominal discount rate applied for estimating fair values is 10% post tax. The long-term inflation rate is assumed to be 2%.

    Total cost for CO2 comprises Norwegian CO2 tax and cost of the EU Emission Trading System and is estimated to gradually increase from NOK 1,806 per tonne in 2025 towards a long term price of NOK 2,400 (real 2025) per tonne from 2030 and NOK 3,400 (real 2025) from 2035 in line with price estimates presented by the Norwegian authorities in 2025. NOx prices are estimated to increase from approximately NOK 18 per kg in 2025 to a level of approximately 27 NOK per kg from 2030.

    Impairment testing of technical goodwill, ordinary goodwill, fixed assets and ROU assets

    A reversal of impairments of oil and gas assets of USD 154 (impairment of 57) million on Statfjord were recorded in the quarter due to increased forward prices.

    Amounts in USD `000	Q1 2026		Q4 2025
    	Technical goodwill	Oil & gas assets	Technical goodwill	Oil & gas assets
    Statfjord	0	-154,070	0	56,814
    Draugen	0	0	1,569	0
    Gjøa/Nova	0	0	3,135	0
    Total impairment	0	-154,070	4,704	56,814

    No impairments on ordinary goodwill were required in the First quarter 2026.

    Sensitivities

    Alternative calculations of pre- Increase / decrease (-) of pre-

    Amounts in USD `000

    tax impairment/reversal (-)

    tax impairment

    Other assumptions

    For oil and gas reserves, future cash flows are calculated on the basis of expected production profiles and estimated proven and probable remaining reserves limited by economic cut-off.

13. General and administrative expenses

    Amounts in USD `000	Q1 2026	Q4 2025	Q1 2025	2025
    Salary and other employee benefits expenses	37,368	30,984	27,059	120,035
    Consultants and other operating expenses	16,737	16,992	14,480	65,606
    Allocated to operated licences	-46,944	-41,359	-35,235	-162,183
    Allocated to exploration and production expenses	-2,577	-3,843	-1,714	-6,732
    Total general and administrative expenses	4,585	2,773	4,589	16,726

14. Financial items

    Amounts in USD `000	Q1 2026	Q4 2025	Q1 2025	2025
    Interest income	1,522	3,273	2,179	11,498
    Unwinding of discount asset retirement reimbursement right (indemnification asset)	6,163	5,622	4,922	21,365
    Gain on financial investments	611	5	54	-17
    Finance income	8,296	8,899	7,155	32,845
    Interest expense and fees from loans and borrowings	-8,099	-7,411	-5,655	-28,067
    Capitalised borrowing cost, development projects	7,210	6,934	2,956	20,711
    Other interest expense	-66	-16	-1	-1,087
    Unwinding of discount asset retirement obligations	-10,733	-9,597	-7,897	-36,148
    Loss on buy-back/early redemption bond loan	0	0	0	-5,405
    Other financial expense	-381	-335	-324	-1,540
    Finance costs	-12,068	-10,426	-10,921	-51,536
    Exchange rate gain / loss (-), interest-bearing loans and borrowings	10,400	-2,835	18,080	30,419
    Net exchange rate gain / loss (-)	-528	2,141	-5,842	-10,067
    Net exchange rate gain / loss (-)	9,871	-694	12,239	20,352
    Net financial items	6,099	-2,220	8,472	1,661

15. Asset retirement reimbursement right

    Amounts in USD `000	Total
    Asset retirement reimbursement right at 1 January 2026 (indemnification asset)	464,673
    Changes in estimates	12,665
    Effect of change in the discount rate	-13,957
    Asset retirement costs from billing, reimbursement from Shell and Harbour Energy	-40
    Asset retirement costs from billing, paid by Equinor	-8,070
    Unwinding of discount	6,163
    Foreign currency translation effects	15,607
    Asset retirement reimbursement right at 31 March 2026 (indemnification asset)	477,041
    Of this:
    Asset retirement reimbursement right, non-current	444,761
    Asset retirement reimbursement right, current	32,280
    Asset retirement reimbursement right at 31 March 2026 (indemnification asset)	477,041

    Asset retirement reimbursement right consists of a receivable from the seller Shell from OKEA's acquisition of Draugen and Gjøa assets in 2018, a receivable from the seller Harbour Energy (previously Wintershall Dea) from OKEA's acquisition of the Brage asset in 2022, and a receivable from the seller Equinor from OKEA's acquisition of the Statfjord asset in 2023.

    Receivable from the seller Shell from OKEA's acquisition of Draugen and Gjøa assets:

    The parties have agreed that the seller Shell will cover 80% of OKEA's share of total decommissioning costs for the Draugen and Gjøa fields up to a predefined post-tax cap amount of USD 87 million (2026 value) subject to Consumer Price Index (CPI) adjustment. The present value of the expected payments is recognised as a pre-tax receivable from the seller.

    In addition, the seller has agreed to pay OKEA a fixed amount of USD 51 million (2026 value) subject to a CPI adjustment according to a schedule based on the percentage of completion of the decommissioning of the Draugen and Gjøa fields.

    The net present value of the receivable is calculated using a discount rate of 5.5% (5.3%).

    Receivable from the seller Harbour Energy from OKEA's acquisition of the Brage asset:

    The parties have agreed that Harbour Energy will retain responsibility for 80% of OKEA's share of total decommissioning costs related to the Brage Unit, limited to an agreed pre-tax cap of USD 184 (2026 value) million subject to index regulation.

    The netpresent value of the receivable is calculated using a discount rate of 5.7% (5.3%).

    Receivable from the seller Equinor from OKEA's acquisition of the Statfjord assets:

    The parties have agreed that Equinor will retain responsibility for 100% of OKEA's share of total decommissioning costs related to Statfjord A.

    The net present value of the receivable is calculated using a discount rate of 5.1% (4.8%).

16. Share capital

    Ordinary shares
    Outstanding shares at 1 January 2026 New shares issued during 2026	103,910,350 0
    Number of outstanding shares at 31 March 2026	103,910,350
    Nominal value NOK per share at 31 March 2026	0.10
    Share capital NOK at 31 March 2026	10,391,035
    Nominal value USD per share at 31 March 2026	0.01
    Share capital USD at 31 March 2026	1,229,272

17. Trade and other receivables

    Amounts in USD `000	31.03.2026	31.12.2025	31.03.2025
    Accounts receivable and receivables from operated licences	28,317	20,987	16,120
    Accrued revenue	90,385	18,903	59,990
    Prepayments	13,442	7,916	8,500
    Working capital and overcall, joint operations/licences	44,341	69,153	58,069
    Underlift of petroleum products	23,154	23,274	16,754
    VAT	495	1,733	1,380
    Accrued interest income	788	0	1,716
    Other receivables	372	361	318
    Fair value put/call options, gas	0	630	650
    Fair value put/call options, oil	0	337	0
    Fair value forward contracts, foreign exchange	377	21	2,215
    Fair value forward contracts, CO2 quotas	0	926	313
    Total trade and other receivables	201,671	144,243	166,026

    No provisions have been recognised for bad debt on receivables.

18. Cash and cash equivalents

    Amounts in USD `000	31.03.2026	31.12.2025	31.03.2025
    Bank deposits, unrestricted	164,784	161,624	263,380
    Bank deposit, time deposit	32,264	73,053	66,856
    Bank deposit, restricted, net proceeds from bond issue OKEA06 on escrow account	125	124	0
    Bank deposit, restricted, employee taxes	11	5,554	2,462
    Bank deposit, restricted, deposit office leases	3,105	2,074	1,632
    Bank deposit, restricted, other	9,476	9,081	8,222
    Total cash and cash equivalents	209,765	251,509	342,553

    In addition to the cash and cash equivalents, USD 59.4 (56.9) million was placed in money-market funds. Reference is made to note 27.

19. Asset retirement obligations

    Amounts in USD `000	Total
    Provisions at 1 January 2026	991,612
    Changes in estimates	19,490
    Effects of change in the discount rate	-18,685
    Asset retirement costs from billing	-10,511
    Unwinding of discount	10,733
    Foreign currency translation effects	33,291
    Asset retirement obligations at 31 March 2026	1,025,930
    Of this:
    Asset retirement obligations, non-current	993,568
    Asset retirement obligations, current	32,362
    Asset retirement obligations at 31 March 2026	1,025,930

    Provisions for asset retirement obligations represent the future expected costs for close-down and removal of oil equipment and production facilities. The provision is based on the company's best estimate. The net present value of the estimated obligation is calculated using a discount rate of 4.4% (year end 2025: 4.2%). The assumptions are based on the economic environment at balance sheet date. Actual asset retirement costs will ultimately depend upon future market prices for the necessary works which will reflect market conditions at the relevant time. Furthermore, the timing of the close-down is likely to depend on when the field ceases to produce at economically viable rates. This in turn will depend upon future oil and gas prices, which are inherently uncertain.

    For recovery of costs of decommissioning related to assets acquired from Shell, Harbour Energy (previously Wintershall Dea) and Equinor, reference is made to note 15.

20. Spare parts, equipment and inventory

    Amounts in USD `000	31.03.2026	31.12.2025	31.03.2025
    Inventory of petroleum products	26,866	32,893	19,344
    Spare parts and equipment	49,035	45,814	43,773
    Total spare parts, equipment and inventory	75,902	78,707	63,117

21. Trade and other payables

    Amounts in USD `000	31.03.2026	31.12.2025	31.03.2025
    Trade creditors	31,327	35,014	32,053
    Accrued holiday pay and other employee benefits	14,937	22,767	17,037
    Working capital, joint operations/licences	133,109	163,914	134,762
    Overlift of petroleum products	13,563	14,356	7,626
    Accrued interest bond loans	8,567	1,724	4,816
    Other provisions, current (see note 26)	9,945	9,252	7,370
    Prepayments from customers	29,396	28,788	8,578
    Fair value put/call options, gas	1,530	0	0
    Fair value put/call options, oil	24,433	0	176
    Fair value forward contracts, CO2 quotas	1,155	0	0
    Accrued consideration from acquisitions of interests in licences	0	0	70
    Other accrued expenses	34,919	32,004	32,065
    Total trade and other payables	302,882	307,819	244,552

22. Interest bearing bond loans

    In June 2025, the company issued a USD 175 million secured bond loan (OKEA06). Maturity date for OKEA06 is June 2029, and the interest rate is fixed at 9.125% p.a. with semi-annual interest payments. OKEA 06 was issued at par value.

    In May 2024, the company issued a USD 125 million secured bond loan (OKEA05). Maturity date for OKEA05 is May 2028, and the interest rate is fixed at 9.125% p.a. with semi-annual interest payments. OKEA05 was issued at par value.

    During 2026, the company has been in full compliance with the covenants under the bond agreements. The financial covenants of OKEA05 and OKEA06 comprise:

    • Leverage Ratio (Total Debt - Liquid Assets) / 12-mth rolling EBITDA of max 1.75x

    • Minimum Liquidity of USD 45 million

23. Other credit facilities

    To enhance the financial flexibility, OKEA has a Revolving Credit Facility (RCF) which is available for working capital purposes. The RCF has a limit of USD 45 million until November 2027, and thereafter reduces to USD 26.25 million until final maturity in December 2028. No draw downs have been made on the RCF.

    Amounts in USD `000	Bond loan OKEA06	Bond loan OKEA05	Total
    Interest bearing bond loans at 1 January 2026	171,949	123,275	295,224
    Amortisation of transaction costs	195	170	365
    Foreign exchange movement	-5,922	-4,478	-10,400
    Foreign currency translation effects	5,819	4,419	10,238
    Interest bearing bond loans at 31 March 2026	172,041	123,386	295,427
    Interest bearing bond loans at 1 January 2026	171,949	123,275	295,224
    Non-cash changes:
    Amortisation of transaction costs	195	170	365
    Foreign exchange movement	-5,922	-4,478	-10,400
    Foreign currency translation effects	5,819	4,419	10,238
    Interest bearing bond loans at 31 March 2026	172,041	123,386	295,427

24. Leasing

    Amounts in USD `000	Total
    Lease liability at 1 January 2026	16,208
    Additions lease contracts	669
    Accretion lease liability	308
    Payments of lease debt and interest	-999
    Foreign currency translation effects	544
    Total lease debt at 31 March 2026	16,731
    Break down of lease liability
    Short-term (within 1 year)	3,982
    Long-term	12,748
    Total lease liability	16,731
    Undiscounted lease liabilities and maturity of cash outflows
    Within 1 year	3,982
    1 to 5 years	13,145
    After 5 years	8,804
    Total	25,931

    The company has entered into operating leases for office facilities. In addition, as operator of the Draugen field, the company has on behalf of the licence entered into operating leases for logistic resources such as supply vessel with associated remote operated vehicle (ROV), base and warehouse for spare parts and hence these lease debts are recognised on a gross basis.

    Lease payments related to leasing contracts entered into as an operator of the Draugen field are presented on a gross basis.

25. Commodity contracts

    Amounts in USD `000	31.03.2026	31.12.2025	31.03.2025
    Accumulated unrealised gain/loss (-) commodity contracts included in other operating income / loss(-)	-24,214	968	473
    Short-term net derivatives included in assets/liabilities (-)	-24,214	968	473

    OKEA uses derivative financial instruments to manage its exposure to fluctuations in commodity prices related to future petroleum production. The commodity derivatives consists of option-based structures, including collars, where a sold call option is combined with a purchased put option to reduce the net hedging premium.

    Commodity derivative contracts are recognised at fair value on the balance sheet. Changes in fair value are recognised in profit or loss and presented as other operating income/loss. The valuation reflects prevailing market conditions at the reporting date

    As at 31 March 2026, commodity derivatives had a net accumulated unrealised loss of USD 24 million (31 December 2025: unrealised gain of USD 1 million), recognised in other operating income/loss. The commodity derivatives are presented as short-term net derivatives included in assets/(liabilities).

    Amounts in USD `000	Total
    Provision at 1 January 2026	9,252
    Settlements/payments to Equinor	0
    Changes in fair value	383
    Foreign currency translation effects	-309
    Other provisions at 31 March 2026	9,945
    Specification of other provisions:
    Other provisions, non-current	0
    Other provisions, current (classified within trade and other payables)	9,945
    Other provisions at 31 March 2026	9,945

26. Other provisions

Other provisions consists of provisions for additional contingent consideration from OKEA's acquisition of the Statfjord asset in 2023. The provisions for contingent consideration is measured at fair value with changes in fair value recognised in the income statement. The fair value is estimated using an option pricing methodology, where the expected option payoff is calculated at each future payment date and discounted back to the balance date.

OKEA shall pay to Equinor an additional contingent consideration with contingent payment terms applicable for 2023-2025 for certain thresholds of realised oil and gas prices.