Q3 Report

Highlights and key figures Financial review Operational review Financial statements Notes

Highlights and key figures

(Figures in brackets refer to previous quarter)

2 OKEA ASA Q3 2026

Highlights and key figures Financial review Operational review Financial statements Notes

Operational performance

Financial performance

Portfolio development

• Strong production despite Draugen maintenance

• Production of 29.1 (27.0) and production efficiency of 89% (83%)

• Garn West South at Draugen on stream and performing according to plan

• Preventive actions ongoing following two serious incidents

• Strong cash generation and strengthened financial position

• Petroleum revenues of USD 316 (313) million and EBITDA of USD 192 (207) million

• Impairment of USD 33 (94) million at Statfjord due to reduced volume estimates and increased capex

• Net profit of USD 29 (14) million

• Total cash balance of USD 476 (355) million

• Quarterly dividend to resume with a payment of NOK 2.00 per share in December 2026

• Continued portfolio delivery and near-term production growth

• Mistral divestment completed with a USD 28 million gain

• Bestla ahead of plan; first production expected before year-end

• Springmus East sanctioned; expected production in H2 2027

• Alpehumle classified as non-commercial

3 OKEA ASA Q3 2026

Highlights and key figures Financial review Operational review Financial statements Notes

I am very pleased with the strong operational execution during the third quarter. With Garn West South now on stream and the planned maintenance campaign at Draugen successfully completed, we are well positioned to deliver 2026 production towards the high end of our guidance range. We also expect Bestla to come on stream before year-end, ahead of schedule and at lower expected cost than previously estimated.

These achievements bring OKEA closer to an important inflection point. Investments made over the past years are translating into higher production, while our investment profile is reducing and becoming increasingly focused on flexible, shorter-cycle opportunities. As we enter 2027, this combination strengthens our cash flow outlook and increases our flexibility to balance shareholder distributions with value-accretive investments.

Reflecting this outlook and a strong current market, the company has decided to resume quarterly dividends with the first payment of NOK 2.00 per share already in December 2026. The intention is also to distribute at least NOK 1.00 per share quarterly in 2027, underlining our commitment to sustainable shareholder distributions.

At the same time, we are progressing the next phase of OKEA's growth. Springmus East at Draugen was sanctioned during the quarter and is expected on stream in the second half of 2027. Talisker West at Brage is also progressing towards drilling and production in 2027, while we continue to mature and high-grade our exploration portfolio, with an ambition to increase activity from up to four wells per year currently to up to six wells per year by 2030.

Our priorities remain clear: safe, reliable and cost efficient operations, disciplined capital allocation and a strong balance sheet, while delivering attractive shareholder returns and investing selectively in future growth. This remains at the core of OKEA's strategy.

Svein J. Liknes

Chief Executive Officer

Highlights and key figures Financial review Operational review Financial statements Notes

Total operating income of USD 332 (334) million comprises:

• Revenues from sales of petroleum products of USD 316 (313) million. The increase was due to higher realised gas and NGL prices, partly offset by lower volumes sold and lower realised crude prices. Sold volumes amounted to 33,449 (34,413) boepd. The realised liquids price was USD 94.6 (104.2) per boe, comprising USD 96.6 (116.9) per boe for crude and USD 58.4 (55.3) per boe for NGL. The average realised price for natural gas amounted to USD 121.3 (88.1) per boe.

• Other operating income of USD 16 (21) million was mainly due to a gain of USD 28 million relating to the sale of Mistral. This was partly offset by a hedging loss of USD 20 (gain of 15) million following an increase (reduction) in forward prices. Tariff income at Gjøa and Statfjord amounted to USD 7 (6) million.

  Total operating expenses of USD 228 (267) million comprises:

• Production expenses of USD 87 (89) million, corresponding to USD 29.5 (34.0) per boe. The decrease in cost per boe was due to less maintenance shutdowns compared to previous quarter. However, the cost remains higher than average due to the planned maintenance at Draugen.

• Changes in over-/underlift positions and production inventory resulting in an expense of USD 20 (28) million as sold volumes exceeded produced volumes.

• Depreciation of oil and gas properties amounting to USD 56 (47) million. The increase was mainly due to higher production.

• Impairments of USD 33 (94) million relate to a fixed asset impairment on Statfjord as a result of reduced volume estimates and increased capex, partly offset by increased forward prices. The related post-tax expense amounted to USD 7 ( 27) million.

• Exploration and evaluation expenses of USD 28 (5) million. The increase was due to expensing of previously capitalised cost on Alpehumle and Prince of USD 23 million.

• General and administrative expenses of USD 4 (4) million.

  Net profit of USD 29 (14) million comprises:

• Profit from operating activities of USD 103 (67) million.

• Net financial income of USD 3 (loss of 2) million.

• Tax expense of USD 77 (51) million, which translates into an effective tax rate of 73% (78%). The effective tax rate was below the marginal tax rate mainly due to the gain on the Mistral sale which is not taxable.

Earnings per share amounted to USD 0.28 (0.14).

Goodwill of USD 88 (85) million comprises USD 71 (68) million of technical goodwill and USD 17 (16) million of ordinary goodwill.

Oil and gas properties amounted to USD 838 (812) million. The increase was largely driven by investments of USD 80 (81) million relating to production drilling at Draugen and Statfjord as well as progress on the Bestla and Power from Shore development projects. This was partly offset by impairment of the Statfjord asset of USD 33 (86) million and depreciation of USD 55 (47) million.

Other non-current assets of USD 523 (485) million mainly comprise asset retirement reimbursement rights of USD 428 (450) million relating to the obligation of Equinor, Shell and Harbour Energy to cover future decommissioning costs for Statfjord, Draugen, Gjøa and Brage respectively. Capitalised exploration and evaluation assets amounted to USD 12 (17) million, and right-of-use assets amounted to USD 78 (13) million. The increase in right-of-use assets was due to a new vessel lease replacing an expired contract.

Cash and cash equivalents amounted to USD 414 (296) million.

Other current assets of USD 357 (287) million mainly comprise trade and other receivables of USD 192 (136) million, spare parts, equipment and inventory of USD 67 (61) million, placements in money-market funds of USD 62 (59) million, and current portion of asset retirement reimbursement rights of USD 36 (31) million.

Interest bearing bond loans of USD 296 (296) million comprise the OKEA05 and OKEA06 bonds.

Other long-term liabilities of USD 1,223 (1,172) million mainly comprise asset retirement obligations of USD 974 (977) million which are partly offset by the asset retirement reimbursement rights outlined above. In addition, deferred tax liabilities amounted to USD 177

(175) million.

Income tax payable amounted to USD 179 (138) million.

Other current liabilities of USD 383 (256) million comprise trade and other payables of USD 324

(216) million and current asset retirement obligations of USD 38 (31) million.

Asset classified as held for sale of USD 0 (19) million and liabilities directly associated with assets classified as held for sale of USD 0 (15) million relate to the Mistral transaction which closed in September. Reference is made to note 29 for further details.

Net cash flows from operating activities amounted to USD 182 (179) million.

Net cash flows from investment activities amounted to USD -67 (-77) million. The decrease was mainly due to USD 32 (0) million in proceeds received from sale of the Mistral licence. This was partly offset by increased investments in oil and gas properties of USD 81 (74) million mainly comprising of production drilling at Draugen and Statfjord as well as progress in the Bestla and Power from Shore development projects.

Net cash flows from financing activities amounted to USD -2 (-15) million. The decrease was due to semi-annual interest on both outstanding bonds paid in the previous quarter.

Cash and cash equivalents ended at USD 414 (296) million. Reference is made to note 18 for further details. In addition to the cash balance, USD 62 (59) million was placed in money-market funds classified as other current assets.

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:

Crude oil

Price [USD/bbl] (ceilings) Price [USD/bbl] (floors) Hedged share (net p/tax)

Q4 2026

75 - 80

60

67%

Q1 2027

N/A N/A N/A

Q2 2027

N/A N/A N/A

Q3 2027

N/A N/A N/A

Q4 2027

N/A N/A N/A

Q1 2028

N/A N/A N/A

The current hedging programme provides downside protection for future revenues while limiting exposure to prices above the ceiling levels.

Global energy markets have been highly volatile in recent months. At the balance sheet date, the company's collar based hedging portfolio resulted in a loss of USD -20 (gain of 15) million, which was recognised in other income in the statement of comprehensive income. The loss reflects an increase (reduction) in crude oil forward prices during the quarter. There are currently no hedging positions for crude in place beyond Q4 2026.

2 Please see note 30 for more information.

Highlights and key figures Financial review Operational review Financial statements Notes

Produced volumes amounted to 29.1 (27.0) boepd. Production efficiency was 89 (83)%. The increase in volumes and production efficiency was mainly the result of strong performance despite the planned maintenance shutdown at Draugen in September

Production expenses amounted to USD 29.5 (34.0) per boe. The lower unit cost was mainly driven by the higher production in combination with reduced cost. The unit cost remain higher than average mainly due to the maintenance shutdown at Draugen.

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.

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.

An oil leak on Draugen was detected and has been preliminary categorised as a serious incident due to uncertainty related to volume. The source was located and the leak stopped. Investigation of the incident is ongoing and will include a final assessment of classification.

With two serious incidents recorded in the quarter, SIF increased to 0.9 (0.4). One incident was a potential for personnel injury and the other was the oil leak described above. In addition, two incidents with medical treatment resulted in an increase in TRIF to 7.8 (7.7). The increase is taken seriously and work to implement preventive measures across operations is ongoing.

GHG emissions intensity was 31 (33) kg CO2e per boe produced.

The share of females recruited over the last 12 months was 25 (42)%.

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

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

Production volumes and production efficiency were impacted by the planned three-week maintenance shutdown which was completed in September.

Production from the Garn West South well commenced in the third quarter and is expected to contribute ~5,000 boepd in the fourth quarter.

Higher production volumes and production efficiency reflect strong well performance and exceptional operational uptime.

The Bestla project is progressing well, with production start expected before year-end 2026. At plateau, Bestla is expected to produce 10 kboepd net to OKEA.

Production from the Talisker West discovery at Brage is expected in the second half of 2027. Total recoverable volume estimates from Statfjord, Brent and Cook formations are 23 - 44 mmboe.

Higher production volumes and production efficiency resulted from stable production and improved performance from the satellite fields.

Gas production remained stable in the quarter. To maintain liquids offtake, four new wells and two additional wells equipped with electric submersible pumps (ESPs) are planned for operation by end of 2027.

Based on recent production performance, it is expected that more water production is required to ensure gas release and to recover the reserves. Capex estimates have been increased to allow for drilling of additional water producers to recover the remaining reserves.

Production volumes and production efficiency remain strong. The Gjøa B-1 BH infill well is expected on stream in the fourth quarter and will increase production by ~500 boepd.

Peon has selected Gjøa as host platform. OKEA has no ownership in Peon, and a tie-in of Peon may improve the value of Gjøa & Nova through reduced unit cost and increased recoverable economical barrels.

Higher production volumes were a result of high production efficiency and good well performance.

Drilling operations under the IOR26 campaign has commenced with the first well expected in production around year-end.

During the turnaround at Draugen in September, the planned project scope was successfully completed and offshore construction activities continue at full capacity. Fiber-optic communication from shore to Draugen through the power cable has been put into operation. Testing of the onshore power transmission facilities has started and is expected finalised by year-end.

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 will also result in reduced production expenses and extend the economic life of the Draugen field. Project completion is expected in 2028.

The Bestla project is progressing ahead of plan, and is only left with commissioning and start-up preparations. Expected production-start is before year-end 2026.

The activity level at Brage has been high during the quarter, with focus shifting from construction to commissioning and start-up preparations. Subsea installations were completed in September.

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

Drilling of the PL 1153 Alpehumle prospect (20% WI) has been completed. The well was classified as a non-commercial gas discovery. The license will continue to process new data and evaluate potential remaining prospectivity.

The PL 1014 Arkenstone well (20% WI) is a high-impact opportunity located in the Northern Norwegian Sea and is operated by Equinor. Drilling of the well is expected in the first quarter of 2027.

The PL 1214 Kyllinglår prospect (28% WI) is scheduled for drilling in the fourth quarter of 2026. The well is operated by Equinor and is planned drilled with a semi-submersible rig from existing infrastructure in the Statfjord Nord field.

The PL 1102/1102 B Tverrdal prospect (35% WI) is an infrastructure led exploration well located 13km north of the Brage platform in the North Sea. Tverrdal is operated by OKEA and is scheduled for drilling the second half of 2027.

The PL 153 Trust prospect (12% WI), has been sanctioned in the license. The well is operated by Vår Energi and is planned drilled from existing infrastructure in the Gjøa field in the first half of 2027.

The sale the Mistral South discovery in PL 1119 (20% WI) to Japex Norge AS, was closed in September. The fixed consideration was USD 30 million. In addition, a contingent consideration assures upside given a commercial Mistral Nord discovery.

OKEA continues to focus on maturing and high-grading the exploration portfolio, and the ambition is to increase the activity level from the current up to 4 wells per year to up to 6 wells per year by 2030.

Applications for APA2026 (Awards in Pre-defined Area) was submitted in the third quarter. Acreage awards are expected announced in January 2027.

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Highlights and key figures Financial review Operational review Financial statements Notes

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‌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 third 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 2 November 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 Breakdown of petroleum revenues

   Amounts in USD `000	Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025	2025
   Sale of liquids	204,373	241,335	165,183	633,407	493,400	546,950
   Sale of gas	111,361	71,799	53,237	259,241	187,526	236,734
   Total petroleum revenues	315,734	313,134	218,420	892,648	680,926	783,684
   Sale of liquids (boe)	2,159,519	2,316,634	2,527,899	7,004,260	7,325,615	8,346,651
   Sale of gas (boe)	917,815	814,906	809,898	2,727,014	2,529,156	3,386,709
   Total sale of petroleum in boe5	3,077,335	3,131,540	3,337,797	9,731,274	9,854,772	11,733,360

   Other operating income

   Amounts in USD `000	Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025	2025
   Gain / loss (-) from put/call options, oil	-13,900	10,027	-546	-31,386	-384	-209
   Gain / loss (-) from put/call options, gas	-6,206	3,285	-58	-5,047	1,748	2,210
   Gain / loss (-) from forward contracts, CO2 quotas	84	1,443	165	-591	30	478
   Change in fair value contingent consideration (see note 26)	0	-98	-991	-482	1,601	1,123
   Tariff income	6,848	5,575	5,133	18,396	14,988	19,929
   Sale of licences	27,810	0	464	27,810	546	846
   Income/expense from commercial agreements	0	44	0	-15	0	-2,017
   Joint utilisation of logistics resources	1,290	316	1,052	2,959	1,519	2,058
   Total other operating income/loss (-)	15,928	20,591	5,219	11,645	20,047	24,417

   5 Barrels of oil equivalents

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

   Amounts in USD `000	Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025	2025
   From licence billings - producing assets	75,300	79,157	64,138	232,648	176,827	254,043
   Other production expenses (insurance, transport)	10,543	8,790	12,030	30,965	31,907	40,484
   G&A expenses allocated to production expenses	1,351	1,373	1,284	4,196	4,090	5,535
   Total production expenses	87,194	89,320	77,451	267,809	212,824	300,062

   Changes in over-/underlift positions and production inventory

   Amounts in USD `000	Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025	2025
   Changes in over/underlift positions	-22,625	-13,197	-24,816	-35,446	-32,682	-2,550
   Changes in production inventory	2,224	-14,675	5,973	-19,602	-6,877	1,821
   Changes in over-/underlift positions and production inventory	-20,401	-27,872	-18,843	-55,049	-39,560	-729

8. Exploration and evaluation expenses

   Amounts in USD `000	Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025	2025
   Share of exploration and evaluation expenses from participation in licences excluding dry well impairment, from billing	2,954	3,150	3,675	7,962	9,400	13,220
   Share of exploration expenses from participation in licences, dry well write off, from billing	22,600	140	0	22,763	12,848	12,346
   Seismic and other exploration and evaluation expenses, outside billing	432	314	3,522	5,437	14,420	14,762
   G&A expenses allocated to exploration expenses	1,669	1,542	273	4,316	737	3,135
   Total exploration and evaluation expenses	27,656	5,146	7,471	40,478	37,404	43,464

9. Taxes Income taxes recognised in the income statement

   Amounts in USD `000	Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025	2025
   Change in deferred taxes current year	3,543	47,725	66,520	-77,417	34,038	23,247
   Taxes payable current year	-80,595	-98,009	-4,033	-243,503	-98,499	-45,349
   Tax payable adjustment previous year	0	-1,136	-108	3,584	1,435	1,475
   Change in deferred taxes previous year	0	801	-99	-3,766	-1,166	-1,166
   Total taxes (-) / tax income (+) recognised in the income statement	-77,052	-50,619	62,280	-321,102	-64,192	-21,793

   Reconciliation of income taxes

   Amounts in USD `000	Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025	2025
   Profit / loss (-) before income taxes	106,209	64,665	-99,607	400,696	27,204	-32,874
   Expected income tax at tax rate 78.004%	-82,847	-50,441	77,697	-312,558	-21,220	25,643
   Permanent differences, including impairment of goodwill	15,757	-5,160	-15,090	9,550	-50,160	-53,824
   Effect of uplift	879	1,445	1,445	3,523	4,283	5,491
   Financial and onshore items	-9,707	5,307	-1,566	-18,864	2,657	610
   Change valuation allowance	-1,135	-1,435	0	-2,570	-39	-39
   Adjustments previous year and other	0	-335	-207	-182	286	325
   Total income taxes recognised in the income statement	-77,052	-50,619	62,280	-321,101	-64,192	-21,793
   Effective income tax rate	73%	78%	63%	80%	236% -66%

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

   Amounts in USD `000	30.09.2026	30.06.2026	31.12.2025	30.09.2025
   Tangible and intangible non-current assets	-652,460	-601,997	-499,711	-475,606
   Provisions (net ARO), lease liability, pensions and gain/loss account	511,550	446,002	441,348	423,996
   Interest bearing loans	-6,442	-4,149	-3,253	-3,967
   Current items (spareparts and inventory)	-29,978	-29,901	-42,322	-38,006
   Tax losses carried forward, onshore 22%	3,156	1,966	597	602
   Valuation allowance (uncapitalised deferred tax asset)	-3,156	-1,966	-597	-602
   Total deferred tax assets / liabilities (-) recognised	-177,331	-190,045	-103,939	-93,583
   Of this classified as held for sale, see note	0	15,026	0	0
   Total deferred tax assets / liabilities (-) recognised excl. classified as held for sale	-177,331	-175,020	-103,939	-93,583

   Specification of tax payable

   Amounts in USD `000	Total
   Tax payable at 1 January 2026	25,548
   Tax paid	-86,059
   Tax payable adjustment previous year	-3,584
   Tax payable current year recognised in the income statement	243,503
   Foreign currency translation effects	7
   Tax payable at 30 September 2026	179,415

   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	-77,417
   Change in deferred taxes previous year	-3,766
   Foreign currency translation effects	7,791
   Total deferred tax assets / liabilities (-) 30 September 2026	-177,331

10. Tangible assets and right-of-use assets

    Amounts in USD `000	Oil and gas properties Assets under Assets in development production		Furniture, 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	93,880	85,547	303	459	180,189
    Reclassification from inventory	0	-42	0	0	-42
    Removal and decommissioning asset	825	-19,155	0	0	-18,331
    Foreign currency translation effects	1,961	19,578	73	536	22,148
    Cost at 30.06.2026	456,713	1,487,128	6,176	36,584	1,986,601
    Accumulated depreciation and impairment at 1 January 2026	0	-1,084,470	-1,820	-22,211	-1,108,501
    Depreciation	0	-104,070	-421	-1,067	-105,558
    Impairment (-) and reversal of impairment	0	68,521	0	0	68,521
    Additional depr. of IFRS 16 ROU assets presented net in the income statement from leasing contracts entered into as licence operator	0	0	0	-59	-59
    Foreign currency translation effects	0	-11,786	-12	-297	-12,095
    Accumulated depreciation and impairment at 30.06.2026	0	-1,131,804	-2,254	-23,634	-1,157,691
    Carrying amount at 30.06.2026	456,713	355,325	3,922	12,951	828,910
    Cost at 1 July 2026	456,713	1,487,128	6,176	36,584	1,986,601
    Additions	34,228	52,877	230	65,906	153,241
    Reclassification from exploration	0	0	0	0	0
    Removal and decommissioning asset	5,052	-5,356	0	0	-304
    Foreign currency translation effects	15,112	50,028	207	680	66,027
    Cost at 30 September 2026	511,105	1,584,677	6,613	103,170	2,205,565
    Accumulated depreciation and impairment at 1 July 2026	0	-1,131,804	-2,254	-23,634	-1,157,691
    Depreciation	0	-54,954	-216	-653	-55,823
    Impairment (-) and reversal of impairment	0	-33,049	0	0	-33,049
    Additional depr. of IFRS 16 ROU assets presented net in the income statement from leasing contracts entered into as licence operator	0	0	0	0	0
    Foreign currency translation effects	0	-37,545	-74	-906	-38,525
    Accumulated depreciation and impairment at 30 September 2026	0	-1,257,352	-2,545	-25,192	-1,285,088
    Carrying amount at 30 September 2026	511,105	327,325	4,068	77,978	920,477

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	3,090	0	0	0
    Foreign currency translation effects	27	379	4,023	2,732	6,755
    Cost at 30 June 2026	1,786	35,981	266,057	180,704	446,761
    Accumulated depreciation and impairment at 1 January 2026	-54	0	-186,977	-161,778	-348,755
    Depreciation	-95	0	0	0	0
    Foreign currency translation effects	3	0	-2,437	-2,484	-4,921
    Accumulated Depreciation and impairment at 30 June 2026	-146	0	-197,756	-164,262	-362,018
    Carrying amount at 30 June 2026	1,641	35,981	68,301	16,442	84,743
    Cost at 1 July 2026	1,786	35,981	266,057	180,704	446,761
    Additions	0	17,325	0	0	0
    Disposals	0	-20,504	0	0	0
    Expensed exploration expenditures temporarily capitalised	0	-22,606	0	0	0
    Foreign currency translation effects	61	1,485	9,037	6,138	15,175
    Cost at 30 September 2026	1,847	11,682	275,094	186,842	461,936
    Accumulated depreciation at beginning of period	-146	0	0	0	0
    Accumulated impairment at beginning of period	0	0	-197,756	-164,262	-362,018
    Depreciation	-48	0	0	0	0
    Impairment	0	0	0	0	0
    Foreign currency translation effects	-4	0	-6,717	-5,579	-12,297
    Accumulated depreciation and impairment at 30 September 2026	-198	0	-204,473	-169,841	-374,315
    Carrying amount at 30 September 2026	1,649	11,682	70,621	17,001	87,622
    Of this classified as held for sale (see note 29)	0	0	0	0	0

    Carrying amount at 30 September 2026 excl. classified as held for sale 1,649 11,682 70,621 17,001 87,622
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 30 September 2026 stated in real terms:

    		Gas GBP/	Currency rates
    Year	Oil USD/BOE	therm	USD/NOK
    2026	96.7	1.38	9.6
    2027	85.4	1.40	9.6
    2028	74.8	0.90	9.6
    2029	76.8	0.79	9.9
    From 2030	77.3	0.75	10.0

    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.

    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

    Impairments of oil and gas assets of USD 33 (86) million on Statfjord were recorded in the quarter mainly due to reduced reserve estimates and increased planned Capex.

    Amounts in USD `000	Q3 2026 Technical goodwill	Oil & gas assets	Q2 2026 Technical goodwill	Oil & gas assets
    Statfjord	0	33,038	0	85,549
    Draugen	0	0	8,342	0
    Total impairment	0	33,038	8,342	85,549

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

    Sensitivities

    The table below shows how the recorded impairment in the quarter are impacted if the different assumptions are changed given that all other assumptions are constant. As there are impairments of both technical goodwill and asset impairments, both the pre-tax and post-tax impacts are shown.

    Change in impairment after

    Amounts in USD `000

    Increase in assumption

    Decrease in assumption

    Change Pre-tax Post-tax Pre-tax Post-tax

    Oil and gas price	+/- 10%	-131,718	-28,973	86,773	19,086
    Oil and gas price forward period	+/- 10%	-54,190	-11,920	54,190	11,920
    Currency rate USD/NOK	+/- 1.0 NOK	-69,164	-15,213	69,164	15,213
    Discount rate	+/- 1% point	3,812	838	-3,974	-874
    Environmental cost (CO2 and NOx)	+/- 20%	53,408	11,748	-53,408	-11,748

13. General and administrative expenses

    Amounts in USD `000	Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025	2025
    Salary and other employee benefits expenses	33,407	38,089	30,523	108,863	89,051	120,035
    Consultants and other operating expenses	17,363	16,038	15,705	50,138	48,614	65,606
    Allocated to operated licences	-43,659	-47,481	-41,552	-138,860	-118,885	-162,183
    Allocated to exploration and production expenses	-2,919	-2,457	-1,557	-7,177	-4,827	-6,732
    Total general and administrative expenses	4,191	4,189	3,118	12,965	13,953	16,726

14. Financial items

    Amounts in USD `000	Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025	2025
    Interest income	3,550	2,717	2,992	7,790	8,225	11,498
    Unwinding of discount asset retirement reimbursement right (indemnification asset)	6,483	6,716	5,474	19,363	15,743	21,365
    Gain on financial investments	777	754	-75	2,142	-21	-17
    Finance income	10,810	10,188	8,391	29,294	23,946	32,845
    Interest expense and fees from loans and borrowings	-7,248	-7,521	-7,287	-22,868	-20,657	-28,067
    Capitalised borrowing cost, development projects	7,235	7,198	6,644	21,643	13,778	20,711
    Other interest expense	-8	-334	-6	-407	-1,070	-1,087
    Unwinding of discount asset retirement obligations	-11,467	-11,544	-9,435	-33,744	-26,601	-36,148
    Loss on buy-back/early redemption bond loan	0	0	184	0	-5,405	-5,405
    Other financial expense	-568	-345	-370	-1,295	-1,205	-1,540
    Finance costs	-12,057	-12,547	-10,270	-36,672	-41,110	-51,536
    Exchange rate gain/loss (-), interest-bearing loans and borrowings	10,293	-5,645	3,268	15,048	33,254	30,419
    Net exchange rate gain/loss (-), other	-6,274	6,091	-3,421	-711	-12,208	-10,067
    Net exchange rate gain/loss (-)	4,019	447	-153	14,337	21,046	20,352
    Net financial items	2,773	-1,912	-2,032	6,959	3,882	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	130
    Effect of change in the discount rate	-15,526
    Asset retirement costs from billing, reimbursement from Shell and Harbour Energy	-2,604
    Asset retirement costs from billing, paid by Equinor	-25,057
    Unwinding of discount	19,363
    Foreign currency translation effects	23,220
    Asset retirement reimbursement right at 30 June 2026 (indemnification asset)	464,198
    Of this:
    Asset retirement reimbursement right, non-current	427,923
    Asset retirement reimbursement right, current	36,275
    Asset retirement reimbursement right at 30 June 2026 (indemnification asset)	464,198

    Asset retirement reimbursement right consists of a receivable from the seller A/S Norske Shell ("Shell") from OKEA's acquisition of Draugen and Gjøa assets in 2018, a receivable from the seller Harbour Energy Norge AS ("Harbour", previously Wintershall Dea Norge AS) from OKEA's acquisition of the Brage asset in 2022, and a receivable from the seller Equinor Energy AS ("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 89 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 52 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 5.7% (year end 2025: 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 188 million (2026 value) subject to index regulation.

    The net present value of the receivable is calculated using a discount rate of 5.4% (year end 2025: 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 5.0% (year end 2025: 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 30 September 2026	103,910,350
    Nominal value NOK per share at 30 September 2026	0.10
    Share capital NOK at 30 September 2026	10,391,035
    Nominal value USD per share at 30 September 2026	0.01
    Share capital USD at 30 September 2026	1,229,272

17. Trade and other receivables

    Amounts in USD `000	30.09.2026	30.06.2026	31.12.2025	30.09.2025
    Accounts receivable and receivables from operated licences	36,778	23,316	20,987	22,234
    Accrued revenue	82,853	56,329	18,903	48,892
    Prepayments	7,034	8,258	7,916	10,915
    Working capital and overcall, joint operations/licences	58,619	36,593	69,153	57,317
    Underlift of petroleum products	2,557	7,000	23,274	11,778
    VAT	1,296	257	1,733	1,248
    Accrued interest income	2,513	2,210	0	5,489
    Other receivables	24	24	361	336
    Fair value put/call options, gas	0	1,250	630	553
    Fair value put/call options, oil	0	0	337	0
    Fair value forward contracts, foreign exchange	130	86	21	360
    Fair value forward contracts, CO2 quotas	325	233	926	481
    Total trade and other receivables	192,130	135,556	144,243	159,603

    No provisions have been recognised for bad debt on receivables.

18. Cash and cash equivalents

    Amounts in USD `000	30.09.2026	30.06.2026	31.12.2025	30.09.2025
    Bank deposits, unrestricted	300,798	226,675	161,624	266,754
    Bank deposit, time deposit	100,000	56,695	73,053	95,670
    Bank deposit, restricted, net proceeds from bond issue OKEA06 on escrow account	127	125	124	123
    Bank deposit, restricted, employee taxes	0	0	5,554	2,831
    Bank deposit, restricted, deposit office leases	3,154	3,051	2,074	2,066
    Bank deposit, restricted, other	9,825	9,309	9,081	9,075
    Total cash and cash equivalents	413,904	295,855	251,509	376,519

    In addition to the cash and cash equivalents, USD 61.8 (59.1) 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	6,509
    Effects of change in the discount rate	-38,466
    Asset retirement costs from billing	-31,607
    Unwinding of discount	33,744
    Foreign currency translation effects	49,351
    Asset retirement obligations at 30 September 2026	1,011,143
    Of this:
    Asset retirement obligations, non-current	973,532
    Asset retirement obligations, current	37,611
    Asset retirement obligations at 30 September 2026	1,011,143

    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	30.09.2026	30.06.2026	31.12.2025	30.09.2025
    Inventory of petroleum products	15,107	12,481	32,893	24,396
    Spare parts and equipment	51,818	48,738	45,814	51,315
    Total spare parts, equipment and inventory	66,924	61,218	78,707	75,712

21. Trade and other payables

    Amounts in USD `000	30.09.2026	30.06.2026	31.12.2025	30.09.2025
    Trade creditors	46,235	4,182	35,014	42,658
    Accrued holiday pay and other employee benefits	20,303	17,869	22,767	21,015
    Working capital, joint operations/licences	160,781	146,214	163,914	194,915
    Overlift of petroleum products	28,150	10,088	14,356	33,252
    Accrued interest bond loans	8,567	1,708	1,724	8,567
    Other provisions, current (see note 26)	0	0	9,252	8,853
    Prepayments from customers	3,312	2	28,788	16,484
    Fair value put/call options, gas	3,833	0	0	0
    Fair value put/call options, oil	8,668	4,080	0	54
    Fair value forward contracts, CO2 quotas	0	0	0	0
    Other accrued expenses	36,934	31,515	32,004	26,298
    Total trade and other payables	323,740	215,658	307,819	352,097

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	606	529	1,135
    Foreign exchange movement	-8,791	-6,647	-15,438
    Foreign currency translation effects	8,635	6,558	15,193
    Interest bearing bond loans at 30 September 2026	172,399	123,715	296,114

    All the effects above represents non-cash canges.

24. Leasing

The company has entered into operating leases for office facilities. In addition, as operator at the NCS, 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. In Q3 the company has entered into a new 5-year lease for the the vessel North Cruys.

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

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 in 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 30 September 2026, the company's crude oil hedging programme covered approximately 67% of expected Q4 2026 production, net of petroleum tax, through collar contracts. The company had no crude oil hedging positions in place beyond 2026.

The company's gas hedging programme covered approximately 47% of expected Q4 2026 production, net of petroleum tax, gradually decreasing to approximately 20% by Q1 2028, primarily through collar contracts.

As at 30 September 2026, commodity derivatives had a net accumulated unrealised loss of USD 13 million (30 June 2026: unrealised loss of USD 3 million) which has been reflected in the financial statements.

1. Other provisions

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

   Under the agreement, OKEA was required to pay Equinor additional contingent consideration with payment terms linked to realised oil and gas prices for the period 2023-2025. The final settlement was completed in the second quarter of 2026.

2. Financial investments

   Amounts in USD `000	30.09.2026	30.06.2026	31.12.2025	30.09.2025
   Investments in money-market funds	61,843	59,068	56,881	41,709
   Total financial investments	61,843	59,068	56,881	41,709

3. Fair value of financial instruments

   The carrying amounts of financial assets and liabilities, except for interest bearing bond loans, are approximately equal to their respective fair values.

   For the interest bearing bond loans OKEA05 and OKEA06, with a total issue amount of USD 300 million, total fair value is estimated to USD 315 million at 30 September 2026. OKEA05 and OKEA06 are listed on the Oslo Stock Exchange. The fair value is based on the latest quoted market prices (level 2 in the fair value hierarchy according to IFRS 13) as per balance sheet date.

   Put/call options oil, put/call options gas, forward contracts CO2 quotas and forward contracts foreign exchange are carried in the statement of financial position at fair value. The fair values are based on quoted market prices at the balance sheet date (level 2 in the fair value hierarchy).

4. Sale of Mistral licence

   In April OKEA entered into a SPA with Japex Norge AS, where OKEA is selling the 20% WI in Mistral (PL1119) for USD 30 million in fixed consideration. In addition, a contingent consideration ensures that OKEA retains an upside given a commercial Mistral Nord discovery. A gain from the sale of USD 28 million was recognised as other operating income in Q3 2026.

   Amounts in USD '000	30.09.2026	30.06.2026
   Assets classified as held for sale: Exploration and evaluation assets	0	19,264
   Total assets classified as held for sale	0	19,264
   Liabilities directly associated with assets classified as held for sale: Deferred tax liabilities	0	15,026
   Total liabilities directly associated with assets classified as held for sale	0	15,026

   Assets and liabilities classified as held for sale at 30 September 2026

5. Change in presentation Statement of cash flows

   Trade and other payables Inv Before					estments in oil and gas assets Before
   Amounts in USD `000	Restated	restatement	Change	Restated	restatement	Change
   Q1 2025	-37,904	-40,009	2,105	-70,871	-68,766	-2,105
   Q2 2025	-13,833	-6,585	-7,248	-76,071	-83,319	7,248
   Q3 2025	76,374	93,023	-16,649	-83,376	-100,025	16,649

   The company re-assessed the allocation and presentation of working capital movements from Investment in oil and gas assets and Trade and other payables in the Statement of cash flows in the fourth quarter 2025. Due to high investment activity and timing differences between incurring the expenses and payment, the effect on the presentation in the Statement of cash flows are considered material.

   As a result, restatement of comparative periods for the Investment in oil and gas assets and Change in trade and other payables lines in the Statement of cash flows have been made in accordance with the table below. The effect on cash position is zero.

6. Events after the balance sheet date

On 3 November, OKEA announced a dividend payment of NOK 207.8 million (NOK 2.00 per share) to be paid on or about 15 December 2026. The distribution is to be made as repayment of paid-in capital.