Interim report
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2 | DNO ASA Key figures Quarters First nine months Full-Year USD million Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 Key financials Revenues 1,023.0 760.5 546.8 2,410.8 992.4 1,474.0 EBITDAX 810.2 569.0 368.6 1,821.4 651.7 980.0 EBITDA 798.4 525.7 350.5 1,754.3 589.6 843.6 Operating profit/loss (-) 641.1 439.0 221.8 1,363.8 335.7 512.8 Net profit/loss (-) 101.1 83.4 19.9 235.2 8.9 -25.2 Free cash flow 326.5 289.5 101.0 761.7 -5.7 -36.6 Operational spend 386.8 437.4 425.7 1,166.1 870.5 1,282.8 Net cash/debt (-) -231.9 -552.9 -808.3 -231.9 -808.3 -885.9 Lifting costs (USD/boe) 8.5 15.7 10.7 10.8 9.7 9.6 Key operational data Net production (boepd) 142,768 88,430 115,396 120,997 97,521 110,667 Sales volume (boepd) 122,790 80,511 93,868 100,422 60,418 69,128 Gross operated production (boepd) 77,621 5,811 58,081 47,857 76,317 79,217 In 2025, Sval Energi was included in the Group accounts from 1 June. For more information about key figures, see the section on alternative performance measures. Q3 2026 highlights •Third quarter revenue of USD 1,023 million, up 35 percent quarter-on-quarter, driven by the resumption of Kurdistan region of Iraq production and higher prices across the portfolio •Operating profit increased 46 percent quarter-on-quarter to USD 641 million, while net profit increased 21 percent to USD 101 million •Net production across the portfolio averaged 142,768 barrels of oil equivalent per day (boepd), up 61 percent from the previous quarter following the resumption of Kurdistan production •On the back of strong operational performance, cash from operations increased to USD 660 million •Continued streamlining of portfolio across the Group through the completion of the Côte d’Ivoire divestment and the multi-asset swap with Vår Energi ASA on the Norwegian Continental Shelf •Board of Directors approved quarterly dividend of NOK 0.375 per share to be paid to shareholders in November, same level as last quarter Cover image: DNO raced ahead in the third quarter, setting new records for revenues and operating profit (AI generated illustration)
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Third Quarter 2026 Interim Results | 3 Operational review Net production during the third quarter stood at 142,768 barrels of oil equivalent per day (boepd), up from 88,430 boepd in the previous quarter. In the North Sea, net production averaged 85,364 boepd, up from 84,912 boepd in the previous quarter, Kurdistan averaged 54,914 boepd, up from 273 boepd in the previous quarter and the Group’s West Africa gas asset offshore Côte d’Ivoire averaged 2,488 boepd, down from 3,246 boepd in the previous quarter. In the North Sea, net production increased mainly due to continued ramp-up at Symra partly offset by planned maintenance at some fields during the quarter. In Kurdistan, the increase in net production reflects the resumption of production at the Tawke field on 28 June and the Peshkabir field on 11 July. The sale of the Group’s West Africa gas asset completed on 14 September. Reported production from this asset is included up to that date. Sales volume averaged 122,790 boepd during the third quarter, up from 80,511 boepd in the previous quarter. The increase was mainly driven by the resumption of production in Kurdistan and increased North Sea oil and gas liftings. The net underlift position decreased to 0.46 million barrels of oil equivalent (MMboe) as of end-Q3 (Q2 2026: underlift of 1.36 MMboe). Net entitlement (NE) production averaged 113,422 boepd during the third quarter, up from 84,912 boepd in the previous quarter due to increase from Kurdistan. Gross production from the Group’s operated licenses during the third quarter averaged 77,621 boepd, up from 5,811 boepd in the previous quarter. In the North Sea, gross operated production decreased to an average of 4,402 boepd, attributable to lower production from the Marulk (Norne area) and Trym fields. In Kurdistan, gross production increased from an average of 363 boepd in the previous quarter to an average of 73,219 boepd during the third quarter due to the resumption of production. Net production Quarters First nine months Full-Year boepd Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 North Sea 85,364 84,912 77,324 86,296 43,535 54,811 Kurdistan 54,914 273 34,929 31,652 50,756 52,569 West Africa 2,488 3,246 3,143 3,050 3,230 3,287 Total 142,768 88,430 115,396 120,997 97,521 110,667 Net production is based on DNO's percentage of ownership in the licenses. West Africa segment is equity accounted. Sales volume Quarters First nine months Full-Year boepd Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 North Sea 94,732 80,511 79,419 86,103 43,237 51,231 Kurdistan 28,058 - 14,449 14,319 17,181 17,896 Total 122,790 80,511 93,868 100,422 60,418 69,128 Sales volume reflects North Sea lifted volumes and NE production for Kurdistan. Net entitlement (NE) production Quarters First nine months Full-Year boepd Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 North Sea 85,364 84,912 77,324 86,296 43,535 54,811 Kurdistan 28,058 - 14,449 14,319 17,181 17,896 Total 113,422 84,912 91,772 100,615 60,716 72,707 NE production from the North Sea equals the segment’s net production. Gross operated production Quarters First nine months Full-Year boepd Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 North Sea 4,402 5,448 11,508 5,655 8,642 9,124 Kurdistan 73,219 363 46,572 42,202 67,674 70,092 Total 77,621 5,811 58,081 47,857 76,317 79,217 The table above shows gross operated production from the Group's operated licenses. Net production (Thousand boepd) Gross operated production (Thousand boepd)
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4 | DNO ASA Activity overview North Sea Net production averaged 85,364 boepd in the North Sea segment during the third quarter of 2026 (84,912 boepd in Q2 2026), of which 82,090 boepd was in Norway and 3,274 boepd in the United Kingdom (UK) (81,662 boepd and 3,250 boepd in Q2 2026, respectively). In the third quarter, oil accounted for 54 percent of production, gas for 40 percent and natural gas liquids (NGL) for 6 percent. In the previous quarter, the split was 53 percent oil, 41 percent gas and 6 percent NGL. During the third quarter, successful turnarounds were conducted at the Norne, Maria, Dvalin and Fenja fields, largely concluding DNO’s maintenance program for the year. DNO participated in one appraisal well and one pilot well on the Norwegian Continental Shelf (NCS) during the quarter. Completed in October, the Afrodite appraisal well in PL293 (10 percent interest) more than doubled the estimate of recoverable resources to 77-180 million barrels of oil equivalent (MMboe). In connection with production drilling at the Symra field (20 percent), a pilot well was drilled to appraise previous discoveries in the Heimdal Formation. With a post-drill estimate of 8-15 million barrels of oil equivalent from the new well, estimated recoverable Symra field volumes increased by up to 25 percent. On 30 September, DNO completed the previously announced multi-asset transaction with Vår Energi ASA, through which it acquired a five percent interest in the Gjøa field and Gjøa Nord discovery in exchange for interests in Nova and Ringhorne Nord. Including customary adjustments, DNO received net cash proceeds of USD 20.4 million at closing. The transaction streamlines the Company’s NCS portfolio and secures a strategic ownership in the offshore Gjøa hub. Overall, five new field developments have been delivered offshore Norway since 2025, another six are under execution and six additional projects are approaching investment decision, all planned onstream before 2030. Net production (boepd) per field in the North Sea: Quarters First nine months Full-Year boepd Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 Arran (UK) 2,770 2,693 2,538 2,895 3,303 3,366 Brage 3,099 2,312 3,542 3,100 2,757 2,675 Dvalin 2,234 2,905 2,718 2,634 1,365 1,829 Ekofisk area 7,867 7,466 9,260 7,678 3,242 4,775 Fenja 858 2,146 2,376 1,766 1,705 1,892 Gjøa area 16,944 15,707 12,122 16,801 5,806 8,644 Ivar Aasen area 6,742 4,032 2,596 4,594 1,280 1,607 Kvitebjørn 7,588 8,043 8,679 8,026 3,970 5,272 Maria 4,439 4,568 3,551 4,639 1,684 2,559 Martin Linge 9,118 8,668 8,069 9,098 3,636 4,736 Norne area 13,079 14,719 5,623 14,313 4,620 6,385 Trym 2,804 3,500 6,564 3,371 3,580 3,870 Ula area 7,536 7,845 8,991 7,105 5,900 6,505 Vilje - - 628 - 627 626 Other 285 308 65 275 61 71 Total 85,364 84,912 77,324 86,296 43,535 54,811 In the table, Ekofisk area comprises Ekofisk, Eldfisk, Embla and Tor fields, Gjøa area comprises Duva, Gjøa, Nova and Vega fields, Ivar Aasen area comprises Ivar Aasen, Hanz and Symra fields, Norne area comprises Alve (incl. Andvare), Marulk, Norne, Skuld, Urd and Verdande fields and Ula area comprises Blane (UK), Oda, Ula, Tambar and Tambar East fields. Kurdistan region of Iraq Gross production from the DNO-operated Tawke license, containing the Tawke and Peshkabir fields averaged 73,219 boepd during the third quarter of 2026 (363 boepd in Q2 2026). DNO resumed production at midyear after a four-month precautionary shutdown due to escalation of drone and missile attacks in the Middle East. The Tawke field contributed 34,671 boepd (363 boepd in Q2 2026) and the Peshkabir field contributed 38,548 boepd (0 boepd in Q2 2026) during the quarter. Net production is shown in the table below. In Kurdistan, drilling activity stepped up during the third quarter with a second third-party rig deployed to take part in the eight-well drilling program initiated shortly before yearend 2025. By far the most active operator in Kurdistan, DNO plans to increase drilling further in 2027 and is considering contracting a third large rig to drill beyond the existing production footprint on the license. The Company sold its oil at an average of USD 38.5 per barrel in the quarter, the highest level since local sales commenced in 2023. All payments for DNO’s oil were made to the Company’s international bank accounts in advance of oil deliveries. Prices for October oil sales in Kurdistan were raised to USD 45 per barrel, up nearly 50 percent from sales at the start of 2026. DNO holds a 75 percent operated interest in the Tawke license with partner Genel Energy International Limited holding the remaining 25 percent. At the Baeshiqa license (64 percent and operated), the Company works to minimize license running cost while determining its future work program. Net production (boepd) per field in Kurdistan: Quarters First nine months Full-Year boepd Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 Tawke 26,003 273 17,635 14,292 20,173 20,589 Peshkabir 28,911 - 17,294 17,359 30,582 31,981 Baeshiqa - - - - - - Total 54,914 273 34,929 31,652 50,756 52,569 West Africa The net production from the Company's equity accounted investment, Côte d'Ivoire (West Africa segment), averaged 2,488 boepd in the third quarter of 2026 (3,246 boepd in Q2 2026). On 14 September, DNO completed the sale of DNO CI LLC, the company through which DNO held its indirect interest in Block CI- 27 offshore Côte d’Ivoire, to Panoro Energy ASA, thereby exiting West Africa. Reported production from this asset is included up to that date. Quarters First nine months Full-Year boepd Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 Block CI-27 2,488 3,246 3,143 3,050 3,230 3,287 Total 2,488 3,246 3,143 3,050 3,230 3,287
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Third Quarter 2026 Interim Results | 5 Financial review Revenues, operating result and cash Revenues in the third quarter stood at USD 1,023.0 million, up 35 percent from the previous quarter (Q2 2026: USD 760.5 million). The increase was primarily driven by higher oil sales volumes and higher realized gas prices, partly offset by lower realized oil prices and net loss on commodity hedges. Revenues Quarters First nine months Full-Year USD million Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 North Sea 923.5 760.5 505.3 2,270.1 839.3 1,262.8 Kurdistan 99.5 - 41.5 140.7 153.0 211.2 Total 1,023.0 760.5 546.8 2,410.8 992.4 1,474.0 North Sea Realized price Quarters First nine months Full-Year USD/boe Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 Oil 99.6 115.1 72.0 100.2 71.6 69.1 Gas 122.9 89.5 63.8 97.6 70.4 66.3 NGL 62.1 69.0 40.5 56.5 43.3 41.0 Total 106.7 100.7 67.2 96.9 69.3 65.6 Kurdistan Realized price Quarters First nine months Full-Year USD/boe Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 Oil 38.5 - 31.2 36.0 32.6 32.3 Total 38.5 - 31.2 36.0 32.6 32.3 The Group reported an operating profit of USD 641.1 million in the third quarter, up from USD 439.0 million in the previous quarter, primarily due to higher revenues, lower lifting costs and exploration expenses partly offset by higher depreciation, impairment on Trym, administrative expenses and lower gain on transactions. Operating profit/loss Quarters First nine months Full-Year USD million Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 North Sea 594.8 465.6 217.4 1,353.2 331.9 505.2 Kurdistan 26.2 -26.3 -3.4 -5.1 6.0 6.3 Other 20.1 -0.3 7.9 15.7 -2.3 1.3 Total 641.1 439.0 221.8 1,363.8 335.7 512.8 Net financial expenses increased to USD 46.4 million (Q2 2026: USD 15.3 million) mainly reflecting a shift from a net currency gain the previous quarter to a net currency loss in the current quarter. The Group ended the quarter with a cash balance of USD 1,007.6 million (Q2 2026: USD 549.8 million). Cost of goods sold In the third quarter, the cost of goods sold amounted to USD 348.5 million, up from USD 297.9 million in the previous quarter. The increase is mainly due to higher depreciation in Kurdistan following the resumption of production and movement in underlift balance in the North Sea, partly offset by decrease in North Sea lifting costs. Lifting costs Lifting costs stood at USD 109.7 million in the third quarter, down from USD 121.4 million in the previous quarter. In the North Sea, the average lifting cost stood at USD 10.3 per barrel of oil equivalent (boe), down from USD 12.5 per boe in the previous quarter. The decrease mainly reflects lower costs on partner- operated assets, including the absence of restructuring costs recognized in the second quarter. In Kurdistan, the average lifting cost stood at USD 5.7 per boe. Quarters First nine months Full-Year USD million Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 North Sea 80.9 96.9 86.8 272.4 176.3 274.9 Kurdistan 28.8 24.7 24.2 77.4 73.2 102.1 Total 109.7 121.4 110.9 349.2 249.4 376.4 Quarters First nine months Full-Year USD/boe Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 North Sea 10.3 12.5 12.2 11.6 14.8 13.7 Kurdistan 5.7 - 7.5 9.0 5.3 5.3 Average 8.5 15.7 10.7 10.8 9.7 9.6 Depreciation, depletion and amortization (DD&A) DD&A related to the Group’s oil and gas production assets amounted to USD 150.9 million in the third quarter, up from USD 112.1 million in the previous quarter. The increase was mainly attributable to the resumption of production in Kurdistan. Quarters First nine months Full-Year USD million Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 North Sea 107.7 112.1 102.6 339.9 173.7 289.7 Kurdistan 43.2 - 20.3 65.4 71.7 99.9 Total 150.9 112.1 123.0 405.3 245.4 389.6 Quarters First nine months Full-Year USD/boe Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 North Sea 13.7 14.5 14.4 14.4 14.6 14.5 Kurdistan 16.7 - 15.3 16.7 15.3 15.3 Average 14.5 14.5 14.6 14.8 14.8 14.7 Exploration costs expensed Exploration costs expensed in the third quarter amounted to USD 11.8 million, down from USD 43.4 million in the previous quarter. The decrease was mainly due to no expensing of wells during the current quarter. Quarters First nine months Full-Year USD million Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 North Sea 11.8 43.4 18.1 67.1 62.1 136.5 Kurdistan - - - - - - Total 11.8 43.4 18.1 67.1 62.1 136.5 Capital expenditures Capital expenditures stood at USD 171.6 million in the third quarter, of which USD 153.0 million was incurred in the North Sea and USD 18.5 million in Kurdistan. Quarters First nine months Full-Year USD million Q3 2026 Q2 2026 Q3 2025 2026 2025 2025 North Sea 153.0 188.8 212.8 438.2 427.2 595.9 Kurdistan 18.5 13.6 4.1 43.0 15.2 21.9 Other - - 0.1 0.0 2.2 0.2 Total 171.6 202.4 217.0 481.3 444.5 618.0
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6 | DNO ASA Consolidated statements of comprehensive income Quarters First nine months Full-Year (unaudited, in USD million) Note Q3 2026 Q3 2025 2026 2025 2025 Revenues 2,3 1,023.0 546.8 2,410.8 992.4 1,474.0 Lifting costs -109.7 -110.9 -349.2 -249.4 -376.4 Tariff and transportation expenses -66.6 -69.4 -184.9 -115.5 -181.5 Movement in overlift/underlift -18.1 4.6 2.9 40.5 86.0 Depreciation, depletion and amortization 7 -154.1 -128.2 -415.7 -254.8 -403.4 Cost of goods sold -348.5 -303.9 -946.9 -579.2 -875.3 Gross profit 674.5 242.9 1,463.9 413.1 598.7 Share of profit/loss from Joint Venture -0.3 -3.2 5.2 0.6 7.7 Other operating income/expenses -1.4 18.1 -8.8 17.4 18.8 Administrative expenses -16.6 -17.5 -54.6 -34.3 -48.6 Impairment/reversal 7 -16.8 -0.4 -17.0 -0.4 56.4 Exploration expenses 4 -11.8 -18.1 -67.1 -62.1 -136.5 Gain/loss on transactions 8,16 13.6 - 42.2 1.3 16.2 Operating profit/loss 641.1 221.8 1,363.8 335.7 512.8 Financial income 5 8.0 11.4 14.0 32.4 37.7 Financial expenses 5 -54.4 -63.0 -102.9 -134.2 -153.1 Profit/loss before income tax 594.7 170.3 1,275.0 233.8 397.4 Tax income/expense 6 -493.6 -150.4 -1,039.8 -224.9 -422.6 Net profit/loss 101.1 19.9 235.2 8.9 -25.2 Currency translation differences 0.3 3.5 0.1 31.8 29.8 Other comprehensive income 0.3 3.5 0.1 31.8 29.8 Total comprehensive income, net of tax 101.4 23.4 235.2 40.7 4.6 Net profit/loss attributable to: Dividends paid on hybrid capital 11 10.8 10.8 32.3 10.8 21.5 Equity holders of the parent 90.3 9.1 202.9 -1.8 -46.7 Net profit/loss 101.1 19.9 235.2 8.9 -25.2 Total comprehensive income attributable to: Dividends paid on hybrid capital 11 10.8 10.8 32.3 10.8 21.5 Equity holders of the parent 90.6 12.6 203.0 30.0 -16.9 Total comprehensive income, net of tax 101.4 23.4 235.2 40.7 4.6 Weighted average number of shares outstanding (millions) 975.00 975.00 975.00 975.00 975.00 Earnings per share, basic (USD per share) 17 0.09 0.01 0.21 -0.00 -0.05 Earnings per share, diluted (USD per share) 17 0.09 0.01 0.21 -0.00 -0.05
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Third Quarter 2026 Interim Results | 7 Consolidated statements of financial position ASSETS At 30 Sep At 31 Dec (unaudited, in USD million) Note 2026 2025 2025 Non-current assets Deferred tax assets 6 17.1 13.6 8.7 Goodwill 7 1,365.3 1,415.9 1,360.6 Other intangible assets 7 178.3 348.0 296.9 Property, plant and equipment 7 3,264.3 2,813.3 3,029.1 Investment in Joint Venture 8 - 38.8 38.1 Other non-current receivables 10 140.7 109.0 120.0 Financial investments 8 21.7 - - Other assets 4.6 4.5 4.5 Total non-current assets 4,992.0 4,743.2 4,857.9 Current assets Inventories 9 99.1 105.3 105.7 Trade and other receivables 10 708.3 674.9 569.6 Derivatives 15 0.7 8.3 11.5 Cash and cash equivalents 18 1,007.6 531.5 453.7 Total current assets 1,815.7 1,319.9 1,140.4 TOTAL ASSETS 6,807.7 6,063.1 5,998.3 EQUITY AND LIABILITIES At 30 Sep At 31 Dec (unaudited, in USD million) Note 2026 2025 2025 Equity Equity 1,415.5 1,411.1 1,328.5 Total equity 1,415.5 1,411.1 1,328.5 Non-current liabilities Deferred tax liabilities 6 1,301.8 1,041.7 1,215.4 Interest-bearing liabilities 12 991.2 988.4 989.1 Provisions and other liabilities 13 1,309.8 1,239.0 1,234.9 Total non-current liabilities 3,602.8 3,269.1 3,439.4 Current liabilities Trade and other payables 14 515.2 557.0 462.1 Income taxes payable 6 938.0 429.7 320.3 Interest-bearing liabilities 12 239.4 339.7 339.4 Derivatives 15 15.0 8.0 5.6 Provisions and other liabilities 13 81.8 48.5 103.1 Total current liabilities 1,789.4 1,382.9 1,230.4 Total liabilities 5,392.2 4,651.9 4,669.8 TOTAL EQUITY AND LIABILITIES 6,807.7 6,063.1 5,998.3
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8 | DNO ASA Consolidated cash flow statement Quarters First nine months Full-Year (unaudited, USD million) Note Q3 2026 Q3 2025 2026 2025 2025 Operating activities Profit/loss before income tax 594.7 170.3 1,275.0 233.8 397.4 Adjustments to add/deduct non-cash items: Exploration cost previously capitalized carried to cost 4 -0.7 -0.8 16.7 14.5 62.8 Depreciation, depletion and amortization 7 154.1 128.2 415.7 254.8 403.4 Impairment/reversal 7 16.8 0.4 17.0 0.4 -56.4 ARO estimate change on fully impaired assets 0.0 0.6 16.1 1.1 4.0 Gain/loss on transactions 8,16 -13.6 - -42.2 -1.3 -16.2 Time value effects on trade receivables 5,10 - 7.2 8.9 6.9 14.8 Share of profit/loss from Joint Venture 0.3 3.2 -5.2 -0.6 -7.7 Amortization of borrowing issue costs 5,12 0.7 4.8 2.1 9.5 10.1 Accretion expense on ARO provisions 5 15.5 15.4 46.2 31.3 46.8 Interest expense 5 8.0 30.1 26.5 78.1 69.3 Interest income 5 -6.4 -9.5 -13.2 -29.6 -35.1 Change in unrealized gain/loss on derivatives 15 13.6 0.9 29.1 0.9 -4.7 Change in other balance sheet items, non-cash items and exchange effects 6.3 3.1 -10.9 9.1 -4.0 Change in working capital items and provisions: - Inventories 9 6.8 1.0 6.7 5.7 5.3 - Trade and other receivables 10 -80.3 36.9 -157.8 37.6 127.4 - Trade and other payables 14 -55.4 16.8 51.6 17.6 -77.5 - Provisions for other liabilities and charges 13 -0.1 -1.4 -0.4 -4.3 -9.8 Cash generated from operations 660.3 407.3 1,681.8 665.6 930.0 Net income taxes paid 6 -136.4 -52.9 -298.6 -167.2 -263.7 Interest received 5.4 6.5 10.2 24.3 30.0 Interest paid -25.7 -34.6 -73.7 -81.0 -105.8 Net cash from/used in operating activities 503.5 326.2 1,319.7 441.7 590.6 Investing activities Purchases of intangible assets 7 -17.3 -34.3 -50.1 -87.3 -130.3 Purchases of tangible assets 7 -154.3 -182.7 -431.1 -357.3 -487.7 Payments for decommissioning -26.4 -9.6 -100.4 -13.4 -33.2 Acquisition/Disposal (+) of subsidiary, net of cash acquired 8 48.0 - 48.0 -203.4 -203.4 Proceeds/Payments (-) license transactions 16 20.4 - 15.6 - 7.4 Equity contribution into Joint Venture -2.8 -6.3 -9.5 -9.2 -10.5 Dividends from Joint Venture 3.4 7.7 17.5 19.8 27.2 Net cash from/used in investing activities -129.1 -225.2 -509.9 -650.8 -830.6 Financing activities Proceeds from borrowings 12 314.1 335.7 573.1 1,265.7 1,383.1 Proceeds from hybrid bond 11 - - - 400.0 400.0 Repayment of borrowings 12 -177.1 -644.3 -670.9 -1,694.6 -1,812.7 Payment of debt and hybrid bond issue costs 11, 12 - - - -18.0 -18.0 Paid dividend -39.2 -36.2 -117.0 -93.9 -129.7 Paid dividend hybrid bond owners 11 -10.8 -10.8 -32.3 -10.8 -21.5 Payment of lease liabilities -2.5 -2.2 -7.9 -3.6 -3.5 Net cash from/used in financing activities 84.5 -357.8 -255.0 -155.2 -202.2 Net increase/decrease in cash and cash equivalents 459.0 -256.8 554.8 -364.3 -442.2 Cash and cash equivalents at beginning of the period 549.8 788.1 453.7 899.0 899.0 Exchange gains/losses on cash and cash equivalents -1.2 0.2 -0.9 -3.2 -3.1 Cash and cash equivalents at the end of the period 1,007.6 531.5 1,007.6 531.5 453.7 Of which restricted cash 20.4 18.1 20.4 18.1 17.5 Of which held in a restricted account in relation to the Capricorn offer 18 400.0 - 400.0 - -
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Third Quarter 2026 Interim Results | 9 Consolidated statement of changes in equity Other equity Currency Share Share Hybrid translation Retained Total (unaudited, in USD million) capital premium capital* differences earnings equity Total equity as of 31 December 2024 32.9 343.6 - -65.7 769.3 1,080.0 Currency translation differences for the period - - - 31.8 - 31.8 Other comprehensive income/loss - - - 31.8 - 31.8 Profit/loss for the period - - 10.8 - -1.8 8.9 Total comprehensive income - - 10.8 31.8 -1.8 40.7 Hybrid bond issue - - 393.5 - - 393.5 Payment of dividend - - -10.8 - -92.4 -103.1 Transactions with shareholders/hybrid capital owners - - 382.7 - -92.4 290.4 Total equity as of 30 September 2025 32.9 343.6 393.5 -33.9 675.1 1,411.1 Other equity Currency Share Share Hybrid translation Retained Total (unaudited, in USD million) capital premium capital* differences earnings equity Total equity as of 31 December 2025 32.9 343.6 393.5 -35.9 594.5 1,328.5 Reclassification of currency translation difference** - - - 45.8 -45.8 - Currency translation differences for the period - - - 0.1 - 0.1 Other comprehensive income/loss - - - 0.1 - 0.1 Profit/loss for the period - - 32.3 - 202.9 235.2 Total comprehensive income - - 32.3 0.1 202.9 235.2 Payment of dividend - - -32.3 - -116.0 -148.2 Transactions with shareholders/hybrid capital owners - - -32.3 - -116.0 -148.2 Total equity as of 30 September 2026 32.9 343.6 393.5 9.9 635.6 1,415.5 * See Note 11 for details ** Reclassification within equity following a change in the functional currency of subsidiary DNO Norge AS from NOK to USD
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10 | DNO ASA Notes to the consolidated interim financial statements Note 1 | Basis of preparation and accounting policies Principal activities and corporate information DNO ASA (the Company) and its subsidiaries (DNO or the Group) are engaged in international oil and gas exploration, development and production. Basis of preparation DNO ASA’s consolidated interim financial statements have been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting and IFRS standards issued and effective at the date of reporting as adopted by the EU. These interim financial statements have also been prepared in accordance with Oslo Stock Exchange regulations. The interim financial statements do not include all the information and disclosures required in the annual financial statements and should be read in conjunction with the DNO ASA Annual Report 2025. The interim financial information for 2026 and 2025 is unaudited. The interim financial statements have been prepared on a historical cost basis, with the following exceptions: liabilities related to share-based payments, derivative financial instruments, financial investments, equity instruments and business combinations are recognized at fair value. A detailed description of the accounting policies applied is included in the DNO ASA Annual Report 2025. The accounting policies adopted in the preparation of the interim financial statements are consistent with those followed in the preparation of the DNO ASA Annual Report 2025. Due to rounding adjustments, some row and column totals may not exactly match the sum of the amounts shown.
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Note 2 | Segment information Third Quarter 2026 Interim Results | 11 The Group reports the following three operating segments: North Sea (which includes the Group’s oil and gas activities in Norway and the UK), Kurdistan and West Africa (which comprised the Group’s former equity accounted investment in Côte d’Ivoire). See Note 8 for information on the disposal of the asset in West Africa, which was completed during the third quarter. The segment assets/liabilities do not include internal receivables/liabilities. Total Un- Third quarter ending 30 September 2026 West reporting allocated/ Total USD million Note North Sea Kurdistan Africa Other segments eliminated Group Income statement information Revenues 3 923.5 99.5 - - 1,023.0 - 1,023.0 Lifting costs -80.9 -28.8 - - -109.8 0.1 -109.7 Tariff and transportation expenses -66.6 - - - -66.6 - -66.6 Movement in overlift/underlift -18.1 - - - -18.1 - -18.1 Depreciation, depletion and amortization -110.3 -43.3 - - -153.6 -0.5 -154.1 Cost of goods sold -275.9 -72.2 - - -348.1 -0.4 -348.5 Gross profit 647.6 27.3 - - 674.9 -0.4 674.5 Share of profit/loss from Joint Venture - - -0.3 - -0.3 - -0.3 Other operating income/expenses - -1.1 - -0.6 -1.7 0.3 -1.4 Administrative expenses -9.1 -0.1 - -0.7 -9.9 -6.8 -16.6 Impairment/reversal 7 -16.8 - - - -16.8 - -16.8 Exploration expenses 4 -11.8 - - - -11.8 - -11.8 Gain/loss on transactions 8, 16 -15.1 - - - -15.1 28.7 13.6 Operating profit/loss 594.8 26.2 -0.3 -1.3 619.3 21.8 641.1 Financial income/expenses (net) 5 -33.5 -0.9 1.8 0.4 -32.2 -14.2 -46.4 Tax income/expense 6 -493.6 - - - -493.6 - -493.6 Net profit/loss 67.7 25.3 1.5 -0.9 93.5 7.6 101.1
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Note 2 | Segment information 12 | DNO ASA Total Un- Third quarter ending 30 September 2025 West reporting allocated/ Total USD million Note North Sea Kurdistan Africa Other segments eliminated Group Income statement information Revenues 3 505.3 41.5 - - 546.8 - 546.8 Lifting costs -86.8 -24.2 - - -110.9 - -110.9 Tariff and transportation expenses -69.4 - - - -69.4 - -69.4 Movement in overlift/underlift 4.6 - - - 4.6 - 4.6 Depreciation, depletion and amortization -107.0 -20.5 - - -127.4 -0.8 -128.2 Cost of goods sold -258.5 -44.7 - - -303.1 -0.8 -303.9 Gross profit 246.9 -3.2 - - 243.7 -0.8 242.9 Share of profit/loss from Joint Venture - - -3.2 - -3.2 - -3.2 Other operating income/expenses - -0.2 - 18.2 18.1 - 18.1 Administrative expenses -11.0 -0.1 - -1.0 -12.1 -5.4 -17.5 Impairment/reversal 7 -0.4 - - - -0.4 - -0.4 Exploration expenses 4 -18.1 - - - -18.1 - -18.1 Operating profit/loss 217.4 -3.4 -3.2 17.2 228.0 -6.2 221.8 Financial income/expenses (net) 5 -40.0 -4.1 0.7 2.6 -40.8 -10.8 -51.6 Tax income/expense 6 -150.4 - - - -150.4 - -150.4 Net profit/loss 27.0 -7.5 -2.5 19.8 36.9 -17.0 19.9
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Note 2 | Segment information Third Quarter 2026 Interim Results | 13 Total Un- First nine months ending 30 September 2026 West reporting allocated/ Total USD million Note North Sea Kurdistan Africa Other segments eliminated Group Income statement information Revenues 3 2,270.1 140.7 - - 2,410.8 - 2,410.8 Lifting costs -272.4 -77.4 - - -349.8 0.6 -349.2 Tariff and transportation expenses -184.9 - - - -184.9 - -184.9 Movement in overlift/underlift 2.9 - - - 2.9 - 2.9 Depreciation, depletion and amortization 7 -348.2 -65.9 - - -414.0 -1.7 -415.7 Cost of goods sold -802.5 -143.2 - - -945.8 -1.1 -946.9 Gross profit 1,467.5 -2.5 - - 1,465.0 -1.1 1,463.9 Share of profit/loss from Joint Venture - - 5.2 - 5.2 - 5.2 Other operating income/expenses -6.3 -2.0 - -0.5 -8.8 0.0 -8.8 Administrative expenses -37.4 -0.5 -0.1 -0.5 -38.6 -16.0 -54.6 Impairment/reversal 7 -17.0 - - - -17.0 - -17.0 Exploration expenses 4 -67.1 - - - -67.1 - -67.1 Gain/loss on transactions 8, 16 13.5 - - - 13.5 28.7 42.2 Operating profit/loss 1,353.2 -5.1 5.1 -1.0 1,352.2 11.6 1,363.8 Financial income/expenses (net) 5 -53.6 -2.1 1.8 1.1 -52.8 -36.1 -88.8 Tax income/expense 6 -1,039.8 - - - -1,039.8 - -1,039.8 Net profit/loss 259.7 -7.1 6.9 0.1 259.7 -24.5 235.2 Financial position information Non-current assets 4,373.1 588.7 - - 4,961.7 30.3 4,992.0 Current assets 1,427.1 208.9 - 0.5 1,636.6 179.2 1,815.7 Total assets 5,800.2 797.6 - 0.5 6,598.3 209.5 6,807.7 Non-current liabilities 2,520.4 76.5 - - 2,596.8 1,006.0 3,602.8 Current liabilities 1,592.9 166.5 - 6.1 1,765.5 23.9 1,789.4 Total liabilities 4,113.3 242.9 - 6.1 4,362.3 1,029.9 5,392.2
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Note 2 | Segment information 14 | DNO ASA Total Un- First nine months ending 30 September 2025 West reporting allocated/ Total USD million Note North Sea Kurdistan Africa Other segments eliminated Group Income statement information Revenues 3 839.3 153.0 - - 992.4 - 992.4 Lifting costs -176.3 -73.2 - - -249.5 0.1 -249.4 Tariff and transportation expenses -115.5 - - - -115.5 - -115.5 Movement in overlift/underlift 40.5 - - - 40.5 - 40.5 Depreciation, depletion and amortization 7 -180.2 -72.2 - - -252.4 -2.5 -254.8 Cost of goods sold -431.5 -145.4 - - -576.9 -2.4 -579.2 Gross profit 407.9 7.6 - - 415.5 -2.4 413.1 Share of profit/loss from Joint Venture - - 0.6 - 0.6 - 0.6 Other operating income/expenses 0.2 -1.0 - 18.2 17.3 0.1 17.4 Administrative expenses -15.0 -0.6 - -1.4 -17.0 -17.3 -34.3 Impairment/reversal 7 -0.4 - - - -0.4 - -0.4 Exploration expenses 4 -62.1 - - - -62.1 - -62.1 Gain/loss on transactions 1.3 - - - 1.3 - 1.3 Operating profit/loss 331.9 6.0 0.6 16.8 355.3 -19.6 335.7 Financial income/expenses (net) 5 -63.4 -1.1 1.9 3.0 -59.7 -42.1 -101.8 Tax income/expense 6 -224.9 - - - -224.9 - -224.9 Net profit/loss 43.6 4.9 2.4 19.7 70.7 -61.8 8.9 Financial position information Non-current assets 4,085.1 609.4 38.8 - 4,733.2 9.9 4,743.2 Current assets 759.5 246.8 - 22.6 1,028.9 291.0 1,319.9 Total assets 4,844.6 856.2 38.8 22.6 5,762.1 301.0 6,063.1 Non-current liabilities 2,190.2 73.5 - - 2,263.7 1,005.4 3,269.1 Current liabilities 1,205.1 153.1 - 8.2 1,366.4 16.5 1,382.9 Total liabilities 3,395.3 226.6 - 8.2 3,630.1 1,021.8 4,651.9
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Note 3 | Revenues Third Quarter 2026 Interim Results | 15 Quarters First nine months Full-Year USD million Q3 2026 Q3 2025 2026 2025 2025 Sale of oil 628.7 326.2 1,425.2 578.4 801.9 Sale of gas 383.6 193.5 924.7 362.1 576.7 Sale of natural gas liquids (NGL) 17.3 12.9 68.5 30.9 60.0 Tariff income 8.3 5.2 20.9 10.9 18.6 Total revenues from contracts with customers 1,038.0 537.8 2,439.3 982.2 1,457.3 Gain/loss (-) on gas hedging instruments -15.0 9.0 -28.6 10.1 16.7 Total revenues 1,023.0 546.8 2,410.8 992.4 1,474.0 Sale of oil (bopd) 85,827 57,457 61,290 38,956 41,301 Sale of gas (boepd) 33,942 32,962 34,693 18,849 23,820 Sale of natural gas liquids (NGL) (boepd) 3,021 3,448 4,438 2,614 4,007 Total sales volume (boepd) 122,790 93,868 100,422 60,418 69,128 Note 4 | Exploration expenses Quarters First nine months Full-Year USD million Q3 2026 Q3 2025 2026 2025 2025 Exploration expenses (G&G and field surveys) -3.7 -7.4 -20.0 -17.8 -26.9 Seismic costs -3.2 -3.9 -11.9 -10.8 -19.0 Exploration cost capitalized in previous years carried to cost 0.7 - -16.7 -2.6 -2.6 Exploration costs capitalized this year carried to cost - 0.8 - -12.0 -60.2 Other exploration cost expensed -5.7 -7.6 -18.6 -18.9 -27.7 Total exploration expenses -11.8 -18.1 -67.1 -62.1 -136.5 Exploration expenses relate to the North Sea segment. Note 5 | Financial income and financial expenses Quarters First nine months Full-Year USD million Note Q3 2026 Q3 2025 2026 2025 2025 Interest income 6.4 9.5 13.2 29.6 35.1 Currency exchange gain (net) - - - - 1.7 Unrealized gain on foreign exchange derivatives 15 1.6 - 0.7 - - Other financial income 0.1 1.9 0.1 2.7 0.9 Financial income 8.0 11.4 14.0 32.4 37.7 Interest expense -25.3 -30.1 -76.4 -78.1 -104.9 Interest expense (IFRS 16) -0.8 -0.6 -2.5 -1.2 -1.8 Capitalized interest 17.4 3.2 49.9 4.0 35.6 Time value effect trade receivables 10 - -7.2 -8.9 -6.9 -14.8 Amortization of borrowing costs 12 -0.7 -4.8 -2.1 -9.5 -10.1 Accretion expense ARO -15.5 -15.4 -46.2 -31.3 -46.8 Currency exchange loss (net) -19.3 -7.2 -6.3 -1.4 - Unrealized loss on listed shares 8 -2.6 - -2.6 - - Other financial expenses -7.6 -0.9 -7.8 -9.8 -10.2 Financial expenses -54.4 -63.0 -102.9 -134.2 -153.1 Net financial income/expenses -46.4 -51.6 -88.8 -101.8 -115.4
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Note 6 | Income taxes 16 | DNO ASA Quarters First nine months Full-Year USD million Q3 2026 Q3 2025 2026 2025 2025 Tax income/expense Change in deferred taxes -124.4 -91.4 -134.0 -218.4 -404.8 Income tax receivable/payable -369.2 -59.0 -905.8 -6.5 -17.7 Total tax income/expense (-) -493.6 -150.4 -1,039.8 -224.9 -422.6 Quarters First nine months Full-Year USD million Q3 2026 Q3 2025 2026 2025 2025 Reconciliation of change in deferred tax assets/liabilities Deferred tax assets/liabilities at beginning of the period -1,174.0 -929.2 -1,206.8 -217.6 -217.6 Changes in deferred taxes in the income statement -124.4 -91.4 -134.0 -218.4 -404.8 Deferred taxes related to transactions 13.4 - 56.0 -546.6 -536.1 Currency and other movements on deferred tax asset/liability 0.3 -7.6 0.0 -45.7 -48.3 Deferred tax assets/liabilities (-) at end of the period -1,284.7 -1,028.2 -1,284.7 -1,028.2 -1,206.8 Recognized deferred tax assets (UK) 17.1 13.6 17.1 13.6 8.7 Recognized deferred tax liabilities (Norway) -1,301.8 -1,041.7 -1,301.8 -1,041.7 -1,215.4 Quarters First nine months Full-Year USD million Q3 2026 Q3 2025 2026 2025 2025 Reconciliation of change in tax receivable/payable Net tax receivable/payable at beginning of the period -688.6 -420.1 -320.3 27.5 27.5 Tax receivable/payable related to transactions - posted directly to balance sheet 0.2 - -2.3 -624.0 -606.7 Current period tax receivable/payable -369.2 -59.0 -905.8 -6.5 -17.7 Tax payments/refunds (-) 136.4 52.9 298.6 167.2 263.7 Change in estimate of uncertain tax positions - 2.9 - 2.9 - Currency and other movements on tax receivable/payable -16.8 -6.4 -8.2 3.2 12.9 Tax receivable/payable (-) at end of the period -938.0 -429.7 -938.0 -429.7 -320.3 Income taxes payable -799.4 -299.0 -799.4 -299.0 -189.3 Provision for uncertain tax positions -138.5 -130.7 -138.5 -130.7 -131.0 The tax balances relate to the activity on the Norwegian Continental Shelf and the UK Continental Shelf. Under the terms of the Production Sharing Contracts (PSC) in the Kurdistan region of Iraq, the Company’s subsidiary, DNO Iraq AS, is not required to pay any corporate income taxes. The share of profit oil of which the government is entitled to is deemed to include a portion representing the notional corporate income tax paid by the government on behalf of DNO. Current and deferred taxation arising from such notional corporate income tax is not calculated for Kurdistan as there is uncertainty related to the tax laws of the Kurdistan Regional Government (KRG) and there is currently no well-established tax regime for international oil companies. Profits/losses by Norwegian companies from upstream activities outside of Norway are not taxable/deductible in Norway in accordance with the General Tax Act, section 2-39. Under these rules, only certain financial income and expenses are taxable in Norway. Provision for uncertain tax positions mainly relates to tax exposures arising from acquisitions previously completed, for which the original sellers have provided tax indemnities. A tax indemnity receivable of USD 132.9 million is recognized under Trade and other receivables. The provision for uncertain tax positions is updated according to developments in the specific cases.
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Note 7 | Intangible assets/Property, plant and equipment (PP&E) Third Quarter 2026 Interim Results | 17 USD million Goodwill Other intangible assets Total intangibles Development assets Production assets Other PP&E RoU assets Total tangibles As of 1 January 2026 Acquisition costs 1,824.5 755.8 2,580.3 891.7 5,112.9 15.4 66.7 6,086.7 Accumulated impairments -463.9 -370.6 -834.5 -3.0 -461.8 - -2.7 -467.4 Accumulated depreciation - -88.3 -88.3 - -2,545.7 -13.1 -31.5 -2,590.2 Net book amount 1,360.6 296.9 1,657.5 888.8 2,105.4 2.3 32.5 3,029.1 Period ended 30 September 2026 Additions - 50.1 50.1 215.9 295.0 - 10.4 521.3 Additions through business combinations 64.6 - 64.6 70.0 25.0 - - 95.0 Capitalized interest - - - 49.9 - - - 49.9 Asset transfer - -10.1 -10.1 -290.1 300.2 - - 10.1 Disposals -42.8 -141.1 -183.9 - -26.1 - - -26.1 Exploration cost previously capitalized - -16.7 -16.7 - - - - - Impairments -16.8 - -16.8 - - -0.2 - -0.2 Depreciation - -1.0 -1.0 - -404.6 -0.7 -9.4 -414.7 Currency translation differences -0.2 0.1 -0.1 -3.2 3.1 0.0 1.2 1.1 Other - - - - - - -1.2 -1.2 Closing net book amount 1,365.3 178.3 1,543.6 931.3 2,298.0 1.5 33.5 3,264.3 As of 30 September 2026 Acquisition costs 1,846.2 638.1 2,484.3 936.9 5,747.0 15.8 77.3 6,777.0 Accumulated impairments -480.9 -370.6 -851.5 -5.6 -481.7 -0.2 -2.7 -490.2 Accumulated depreciation - -89.2 -89.2 - -2,967.2 -14.1 -41.1 -3,022.5 Net book amount 1,365.3 178.3 1,543.6 931.3 2,298.0 1.5 33.5 3,264.3 Additions to intangible assets relate to exploration and evaluation expenditures under the successful efforts method, acquisition of license interests and administrative software. Additions to tangible assets relate to oil and gas development and production assets, including changes in estimate of asset retirement obligation and other property, plant and equipment. DNO completed three license transactions during the period presented: a multi-asset swap with Equinor Energy AS, an acquisition from INPEX Idemitsu Norge AS settled in cash and a multi-asset swap with Vår Energi ASA. The interests acquired in each transaction are accounted for as business combinations and are presented as Additions through business combinations in the table above. The interests transferred in the Equinor and Vår Energi transactions are presented as Disposals. See Note 16 for further details. During the period presented, the Cuvette and Cerisa discoveries were transferred from Other intangible assets to Development assets as the projects progressed into the development stage. In addition, the Symra and Dvalin North projects were reclassified from Development assets to Production assets upon commencement of production.
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Note 7 | Intangible assets/Property, plant and equipment (PP&E) 18 | DNO ASA Impairment assessment At each reporting date, the Group assesses whether there is an indication that an asset may be impaired. An assessment of the recoverable amount is made when an impairment indicator exists. Goodwill is tested for impairment annually or more frequently when there are impairment indicators. Impairment is recognized when the carrying amount of an asset or a cash-generating unit (CGU), including associated goodwill, exceeds the recoverable amount. The recoverable amount is the higher of the asset’s fair value less cost to sell and the value in use. During the third quarter of 2026, an impairment of USD 16.8 million was recognized due to an increase in the asset retirement obligation for the Trym field. USD million Income statement: Balance sheet: CGU, Segment Recoverable amount (post-tax) Impairment -charge/ reversal (pre-tax) Tax income/ -expense Impairment -charge/ reversal (post-tax) Goodwill Property, plant and equipment Deferred tax asset/ -liability Currency effects Trym 21.4 -16.8 - -16.8 -16.8 - - - Total - -16.8 - -16.8 -16.8 - - - The table above shows the recoverable amounts and impairment charge for the CGUs which were impaired in the current quarter, and how it was recognized in the income statement and balance sheet. Impairment of goodwill does not give rise to any tax impact, and the impairment amounts are the same on a pre-tax and post-tax basis. Future Brent oil and gas prices are key assumptions in the impairment assessments and have a significant impact on the recoverable amounts of the Group’s assets. Short-term Brent oil price and gas assumptions applied in the impairment testing were based on forward curves and observable broker and analyst consensus, while long term assumptions reflect management’s view based on market data and expectations. The impairment test applied oil prices for 2026: USD 87.3, 2027: USD 74.1 and 2028: USD 76.8 per barrel, nominal terms. From 2029 onwards, the Brent oil price was based on the Group’s long-term price assumption of USD 75 per barrel in real terms (unchanged from yearend 2025). For gas the impairment test applied prices for 2026: USD 18.9, 2027: USD 13.5 and 2028: USD 12.1 per thousand standard cubic feet (mscf), nominal terms. From 2029 onwards, the gas price was based on the Group’s long-term price assumption of USD 10 per mscf in real terms (unchanged from yearend 2025). The relevant post-tax nominal discount rate (WACC) applied in the impairment test for Norwegian North Sea assets was 8.5 percent (yearend 2025: 8.0 percent).
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Note 7 | Intangible assets/Property, plant and equipment (PP&E) Third Quarter 2026 Interim Results | 19 USD million Goodwill Other intangible assets Total intangibles Development assets Production assets Other PP&E RoU assets Total tangibles As of 1 January 2025 Acquisition costs 466.5 597.5 1,064.0 399.2 3,344.2 15.1 32.0 3,790.6 Accumulated impairments -364.4 -283.1 -647.5 -127.6 -412.0 - - -539.5 Accumulated depreciation - -85.9 -85.9 - -2,109.0 -13.5 -19.2 -2,141.7 Net book amount 102.1 228.5 330.6 271.7 823.3 1.6 12.8 1,109.4 Period ended 30 September 2025 Additions - 87.3 87.3 215.5 149.9 0.5 5.9 371.7 Additions through business combinations 1,300.6 16.2 1,316.8 177.6 1,304.8 0.9 27.3 1,510.6 Capitalized interest - - - 4.0 - - - 4.0 Asset transfer - - - -36.5 36.5 - - - Disposals - - - - - - - 0.0 Exploration cost previously capitalized - -14.5 -14.5 - - - - - Impairments - - - - - - -0.4 -0.4 Depreciation - -1.8 -1.8 - -244.6 -1.1 -7.3 -253.0 Currency translation differences 13.3 32.4 45.7 43.6 34.8 0.1 0.2 78.7 Other - - - - - - -7.8 -7.8 Closing net book amount 1,415.9 348.0 1,763.9 675.9 2,104.7 2.0 30.7 2,813.3 As of 30 September 2025 Acquisition costs 1,825.3 754.7 2,580.1 815.2 4,962.1 17.1 58.4 5,852.8 Accumulated impairments -409.4 -319.0 -728.4 -139.3 -449.7 - -0.4 -589.4 Accumulated depreciation - -87.7 -87.7 - -2,407.6 -15.1 -27.3 -2,450.0 Net book amount 1,415.9 348.0 1,763.9 675.9 2,104.7 2.0 30.7 2,813.3
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Note 8 | Financial investments/Gain on disposal of Joint Venture 20 | DNO ASA Financial investments comprise equity instruments measured at fair value through profit or loss (FVTPL). Fair value is determined by reference to the quoted market price at the end of the reporting period. Changes in fair value are recognized in the consolidated statements of comprehensive income under Financial income or expenses. Quarters First nine months Full-Year USD million Q3 2026 Q3 2025 2026 2025 2025 Balance at beginning of the period - - - - - Additions 24.3 - 24.3 - - Fair value changes through profit or loss (FVTPL) -2.6 - -2.6 - - Disposal - - - - - Total financial investments at end of the period 21.7 - 21.7 - - Non-current portion 21.7 - 21.7 - - Current portion - - - - - Financial investments include the following: At 30 Sep At 31 Dec USD million 2026 2025 2025 Listed securities: Panoro Energy ASA 21.7 - - Total financial investments 21.7 - - On 19 August 2026, DNO ASA announced the sale of DNO CI LLC (formerly Mondoil Enterprises LLC), the company through which DNO held its indirect interest in Block CI-27 offshore Côte d’Ivoire, to Panoro Energy ASA. The announced consideration was USD 86.5 million with an effective date of 1 January 2025. The transaction was completed on 14 September 2026. After adjustment for cash generated in the divested company between the effective date and completion, consideration received amounted to USD 72.3 million, comprising USD 48.0 million in cash, including a USD 5.0 million deposit received earlier in the quarter, and 7 million shares in Panoro Energy ASA with a fair value of USD 24.3 million at completion. The shares received are recognized as Financial investments and represent 4.98 percent of the outstanding shares of Panoro Energy ASA. Panoro Energy ASA is listed on the Oslo Stock Exchange and the market price, classified as Level 1 in the fair-value hierarchy, is used for valuation of the shares at transaction date and at period end. The disposal of DNO CI LLC resulted in a gain, representing the difference between the fair value of the consideration received and the carrying amount of the investment derecognized. The gain is included in Gain/loss on transactions in the consolidated statements of comprehensive income. Cash consideration of USD 48.0 million is presented in investing activities in the consolidated cash flow statement. The shares received are a non-cash transaction. At 14 Sep USD million 2026 Fair value of consideration received 72.3 Carrying value of divested investment derecognized 43.1 Transaction cost 0.5 Gain 28.7
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Note 9 | Inventory Third Quarter 2026 Interim Results | 21 At 30 Sep At 31 Dec USD million 2026 2025 2025 Drilling equipment, spare parts and consumables 126.2 135.4 125.1 Provision for obsolete inventory -27.1 -30.2 -19.4 Total inventory 99.1 105.3 105.7 Book value of inventory as of the reporting date relates to the North Sea (USD 59.1 million) and to Kurdistan (USD 40.1 million). Note 10 | Other non-current receivables/Trade Receivables At 30 Sep At 31 Dec USD million 2026 2025 2025 Trade debtors (non-current portion) 140.7 109.0 120.0 Total other non-current receivables 140.7 109.0 120.0 Trade debtors 105.2 173.2 151.2 Tax indemnity receivable (Note 6) 132.9 128.6 128.8 Underlift 50.4 58.1 35.9 Other short-term receivables 419.8 315.0 253.6 Total trade and other receivables 708.3 674.9 569.6 As of 30 September 2026, the Company was owed a total of USD 286.3 million, excluding interest, by the KRG mainly related to sales of DNO’s entitlement share of oil to the KRG for the months October 2022 through March 2023 plus part of the amount invoiced for oil sold to the KRG in September 2022. These receivables are past due. During the third quarter of 2026, DNO recognized that USD 1.5 million of these arrears had been settled by way of offsetting against payables due to the KRG. The Company continues to engage with the KRG regarding collection of the arrears and expects that it will recover the full invoiced amount as has occurred in the past, but the timing of recovery is uncertain. Due to accounting requirements to incorporate the time value of money, the Company compared the book value of the KRG arrears with the present value of estimated future cash flows, resulting in a cumulative USD 56.1 million reduction of the book value, no change from the previous quarter. The underlift receivable as of the reporting date relates to North Sea underlifted volumes. Other short-term receivables mainly relate to items of working capital in licenses in the North Sea and Kurdistan and accrual for earned income not invoiced in the North Sea. Note 11 | Hybrid capital USD million Equity Liability Total Balance as of 31 December 2025 393.5 0.1 393.6 Profit/loss allocated to hybrid bond owners 32.3 - 32.3 Accretion - - - Interest payment classified as dividend -32.3 - -32.3 Balance as of 30 September 2026 393.5 0.1 393.6 On 17 June 2025, DNO ASA completed the placement of a USD 400 million hybrid bond with a coupon rate of 10.75 percent. The hybrid bond will have the first call date five and a half years after issuance, a five percent coupon step-up after six years and a final maturity date of 17 June 2085. DNO has the right to defer coupon payments and ultimately decide not to pay at maturity. Any deferred coupon payments become payable if DNO decides to exercise a repayment call option, pay dividends to shareholders or liquidation proceeds are formally opened. Due to features such as its long maturity, subordination attributes and the option to defer coupon payments and ultimately not pay these at maturity date, the hybrid bond has characteristics of equity. At initial recognition, the net present value of the principal is presented as debt in the consolidated statement of the financial position (balance sheet). The difference between the proceeds received and the discounted liability is recorded as equity. Coupon payments on the part classified as equity are not recognized on an accrual basis; instead, coupon paid is accounted for as a decrease in equity when the related contractual payment obligation arises on the coupon payment date, consistent with the accounting treatment of dividends. The terms of the hybrid bond do not include any financial covenants.
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Note 12 | Interest-bearing liabilities 22 | DNO ASA Interest-bearing liabilities Facility At 30 Sep At 31 Dec USD million Ticker currency Interest Maturity 2026 2025 2025 Non-current Bond loan (ISIN NO0013243766) DNO05 USD 9.250 % 04/06/29 400.0 400.0 400.0 Bond loan (ISIN NO0013511113) DNO06 USD 8.500 % 27/03/30 600.0 600.0 600.0 Hybrid bond (ISIN NO0013582627) liability portion (see Note 11) DNO07 USD 10.750 % 17/06/85 0.1 0.1 0.1 Capitalized borrowing issue costs -8.9 -11.7 -11.0 Total non-current interest-bearing liabilities 991.2 988.4 989.1 Current Prepayment facilities - Multiple See below See below 239.4 339.7 339.4 Total current interest-bearing liabilities 239.4 339.7 339.4 Total interest-bearing liabilities 1,230.6 1,328.1 1,328.5 Changes in liabilities arising from financing activities split between cash and non-cash changes At 1 Jan Cash Non-cash changes At 30 Sep USD million 2026 flows Amortization Acquisition Currency Reclassification 2026 Bond loans 1,000.1 - - - - - 1,000.1 Borrowing issue costs -11.0 - 2.1 - - - -8.9 Prepayment facilities 339.4 -97.8 - - -2.3 - 239.4 Total 1,328.5 -97.8 2.1 - -2.3 - 1,230.6 At 1 Jan Cash Non-cash changes At 30 Sep USD million 2025 flows Amortization Acquisition Currency Reclassification 2025 Bond loans 750.0 600.1 - - - -350.0 1,000.1 Bond loans (current) - -350.0 - - - 350.0 - Borrowing issue costs -9.5 -11.6 9.5 - -0.1 - -11.7 Reserve-based lending facility 50.0 -572.3 - 522.3 - - - Prepayment facilities - -106.7 - 446.0 0.3 - 339.7 Total 790.5 -440.4 9.5 968.3 0.2 - 1,328.1 The financial covenants of the DNO05 and DNO06 bonds require a minimum liquidity of USD 40 million and that the Group maintains either an equity ratio of 30 percent or total equity of at least USD 600 million. For details on the hybrid bond, see Note 11. The prepayment facilities comprise three agreements: one for DNO’s Norwegian gas production and two for its North Sea oil production, together providing offtake financing of up to USD 910 million. The gas offtake agreement and related financing facility of up to USD 500 million have a tenor of four years from 1 October 2025. Under the facility, DNO is paid by the bank the value of up to 270 days of scheduled gas production based on future gas sales receivables. The facility carries interest at a risk-free rate plus a margin and has no financial covenants. The oil offtake agreement with ExxonMobil Asia Pacific Pte. Ltd., covering around half of DNO's North Sea oil output, has a tenor of two years from 1 January 2026 and a related revolving credit facility of up to USD 185 million. The oil offtake agreement with Shell International Trading and Shipping Company Limited, covering the other half of the output, has an initial tenor of one year from 1 January 2026 and a related prepayment facility with a European bank of up to USD 225 million. These facilities are uncommitted. For additional information on the Group’s interest-bearing liabilities, refer to the DNO ASA Annual Report 2025.
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Note 13 | Provisions and other liabilities Third Quarter 2026 Interim Results | 23 At 30 Sep At 31 Dec USD million 2026 2025 2025 Non-current Asset retirement obligations (ARO) 1,240.6 1,213.3 1,169.0 Other long-term provisions and charges 44.9 9.3 44.4 Lease liabilities 24.4 16.3 21.5 Total non-current provisions and other liabilities 1,309.8 1,239.0 1,234.9 Current Asset retirement obligations (ARO) 50.7 21.2 77.0 Other provisions and charges 17.0 10.4 10.1 Current lease liabilities 14.1 16.9 15.9 Total current provisions and other liabilities 81.8 48.5 103.1 Total provisions and other liabilities 1,391.6 1,287.5 1,337.9 Asset retirement obligations The provisions for ARO are based on the present value of estimated future costs of decommissioning oil and gas assets in the North Sea and Kurdistan. The discount rates before tax applied were between 4.60 percent and 5.60 percent. Non-cancellable lease commitments The lease liabilities recognized in the balance sheet mainly relate to office rent, a Floating Storage and Offloading (FSO) vessel and a rig lease linked to the non- operated Martin Linge oil and gas field, where the lease liability recognized represents DNO’s share only. The identified lease liabilities have no significant impact on the Group’s financing, loan covenants or dividend policy. The Group does not have any residual value guarantees. Extension options are included in the lease liability when, based on management’s judgment, it is reasonably certain that an extension will be exercised. Non-lease components are not included as part of the lease liabilities. Undiscounted lease liabilities and maturity of cash outflows (non-cancellable): At 30 Sep At 31 Dec USD million 2026 2025 2025 Within one year 14.9 18.5 17.5 Two to five years 29.0 15.9 21.5 After five years 1.0 4.3 3.6 Total undiscounted lease liabilities end of the period 44.9 38.7 42.7 The table above summarizes the Group’s maturity profile of the lease liabilities based on contractual undiscounted payments.
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Note 14 | Trade and other payables 24 | DNO ASA At 30 Sep At 31 Dec USD million 2026 2025 2025 Trade payables 90.4 86.5 61.0 Public duties payable 30.9 4.4 2.8 Prepayments from customers 34.6 19.3 4.8 Overlift and other adjustments 126.6 181.9 112.1 Other accrued expenses 232.6 264.8 281.4 Total trade and other payables 515.2 557.0 462.1 Trade payables are non-interest bearing and normally settled within 30 days. Trade payables and other accrued expenses include items of working capital related to participation in oil and gas licenses in the North Sea and Kurdistan, and prepayments from customers related to oil and gas sales in the North Sea. The overlift and other adjustments relate to North Sea overlifted volumes, valued at production cost including depreciation and other lifting related adjustments in Kurdistan. Note 15 | Derivatives At 30 Sep At 31 Dec USD million 2026 2025 2025 Derivatives (current assets) 0.7 8.3 11.5 Derivatives (current liabilities) 15.0 8.0 5.6 Net derivatives -14.3 0.3 5.9 The Group uses derivative financial instruments to manage its exposure to foreign currency and commodity price risks. Derivatives are measured at fair value on a recurring basis (Level 2 in the fair value hierarchy), with changes in fair value recognized in the income statement. Foreign exchange derivatives are primarily used to hedge the Group's exposure to NOK, mainly related to Norwegian tax payments. As of 30 September 2026, the Group had hedged 30 percent of the remaining tax installments for 2026 at a weighted average USD/NOK exchange rate of 9.58 and 2 percent of estimated tax installments for the first half of 2027 at a weighted average USD/NOK exchange rate equivalent to 9.59. Changes in fair value are recognized in Financial income/expenses, see Note 5. Commodity derivatives are used to hedge a portion of the Group's exposure to gas price fluctuations in the North Sea. As of 30 September 2026, approximately 29 percent of the Group's post-tax gas price exposure for the remainder of 2026 was hedged through collar structures. The weighted average strike prices were USD 57.4 per boe for the purchased put options and USD 108.5 per boe for the written call options. Changes in fair value are recognized in Revenues, see Note 3.
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Note 16 | Business combinations Third Quarter 2026 Interim Results | 25 Multi-asset swap with Equinor (completed during the second quarter) On 16 March 2026, DNO ASA announced a non-cash swap of Norwegian Continental Shelf assets with Equinor Energy AS. Under the agreement, DNO acquired a 19 percent interest in Atlantis and a 10 percent interest in Afrodite, two gas condensate discoveries near the Kvitebjørn field. In exchange, the Company transferred its interests in the Røver, Mistral, Tyrihans East and Bergknapp discoveries, as well as the Sjørøver exploration license. The transaction was completed on 29 May 2026, which was also the acquisition date for accounting purposes. The acquisition of the interest in the Atlantis and the Afrodite discoveries has been considered as a business combination and is accounted for using the acquisition method in accordance with IFRS 3. The recognized goodwill relates primarily to technical goodwill. No contingent consideration is payable or receivable, and transaction costs were negligible. Fair value at USD million acquisition date Goodwill 55.7 Property, plant and equipment (Development assets) 70.0 Tax receivable 2.0 Other current assets 0.7 Total assets 128.4 Deferred tax liability 54.6 Other current liabilities 0.6 Total liabilities 55.2 Net assets and liabilities recognized 73.2 Consideration for the acquired assets 73.2 The difference between the fair value of the consideration received and the carrying amount of the divested interests is recognized as a gain in Gain/loss on transactions in the consolidated statements of comprehensive income. Carrying value of divested assets derecognized 44.3 Consideration for the acquired assets 73.2 Gain 28.8 Transaction with INPEX Idemitsu (completed during the second quarter) On 7 May 2026, DNO ASA announced an agreement with INPEX Idemitsu Norge AS to acquire a 3.3 percent interest in the producing Vega Unit and 15 percent in PL090C, which is tied back to Gjøa and part of the Gjøa area cash generating unit. The acquisition increased DNO’s interest in Vega Unit to 8.8 percent. The transaction was completed on 30 June 2026, which was also the acquisition date for accounting purposes and was settled in cash. The transaction has been considered as a business combination and is accounted for using the acquisition method in accordance with IFRS 3. The recognized goodwill relates primarily to technical goodwill. No contingent consideration is payable or receivable, and transaction costs were negligible. Fair value at USD million acquisition date Goodwill 3.8 Deferred tax assets 3.8 Property, plant and equipment (Production assets) 9.8 Other non-current assets 3.2 Other current assets 0.8 Total assets 21.4 Deferred tax liability 7.5 Asset retirement obligation 4.9 Tax payable 1.8 Other current liabilities 2.4 Total liabilities 16.6 Net assets and liabilities recognized 4.8 Consideration paid on completion 4.8
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Note 16 | Business combinations 26 | DNO ASA Multi-asset swap with Vår Energi (completed during the third quarter) On 18 June 2026, DNO ASA announced a multi-asset transaction of NCS assets with Vår Energi ASA. DNO acquired a five percent interest in the Vår Energi- operated Gjøa field and the Gjøa Nord discovery in the Northern North Sea in exchange for a five percent interest in Nova, a subsea field tied back to the Gjøa platform. This reduced DNO’s interest in Nova from 45 percent to 40 percent. DNO also exited the Ringhorne Nord discovery in the Central North Sea by divesting its 15 percent interest in PL956 to Vår Energi. As further consideration, DNO received a balancing cash payment of USD 17.5 million. Including settlement of adjustments between the effective date and completion, net cash received on completion was USD 20.4 million. The transaction was completed on 30 September 2026, which was also the acquisition date for accounting purposes. The acquisition of the Gjøa and Gjøa Nord interests is accounted for as a business combination under IFRS 3. The recognized goodwill relates primarily to technical goodwill. No contingent consideration is payable or receivable, and transaction costs were negligible. Fair value at USD million acquisition date Goodwill 5.1 Property, plant and equipment (Production assets) 15.2 Other current assets 3.4 Cash and cash equivalents 31.9 Total assets 55.6 Deferred tax liability 5.4 Asset retirement obligation 9.0 Tax payable 23.3 Other current liabilities 4.6 Total liabilities 42.4 Net assets and liabilities recognized 13.2 Consideration received on completion 13.2 The difference between the fair value of the consideration received and the carrying amount of the divested interests is recognized as a loss in Gain/loss on transactions in the consolidated statements of comprehensive income. Net asset derecognized 28.3 Consideration received 13.2 Loss -15.1 Note 17 | Earnings per share Quarters First nine months Full-Year Q3 2026 Q3 2025 2026 2025 2025 Net profit/loss 101.1 19.9 235.2 8.9 -25.2 EPS adjustment for calculated interest/dividend on hybrid capital (USD million) -10.8 -10.8 -32.4 -12.3 -23.1 Weighted average number of ordinary shares (million) 975.00 975.00 975.00 975.00 975.00 Earnings per share, basic and diluted (USD) 0.09 0.01 0.21 -0.00 -0.05
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Note 18 | Capricorn offer/Restricted cash Third Quarter 2026 Interim Results | 27 On 1 September 2026, DNO ASA announced an offer, through its wholly owned subsidiary DNO Bidco AS, to acquire the entire issued and to be issued share capital of Capricorn Energy plc, subject to certain conditions. Capricorn's Board of Directors confirmed that they intended to recommend the offer to Capricorn shareholders. On 17 September 2026, DNO Bidco’s offer was revised to an all-cash consideration of USD 5.214 per share. Following an increased competing offer from Genel Energy plc, DNO Bidco announced on 28 September 2026 that the financial terms of its revised offer were final and would not be increased. Capricorn's Board recommended Genel’s increased offer and withdrew its recommendation of DNO Bidco's offer. On 16 October 2026, the shareholder meetings required to approve DNO Bidco's offer were adjourned indefinitely. DNO Bidco's offer had not lapsed as of the date of this report. Among other things, DNO Bidco’s offer is conditional upon the shareholder meetings to approve the offer being held by no later than 7 November 2026, being the 22nd day after the expected date of such meetings as set out in the scheme document in relation to the offer, or such later date as (i) may be agreed between DNO Bidco and Capricorn or (ii) (in a competitive situation) may be specified by DNO Bidco with the consent of the UK Takeover Panel, and in each case that (if so required) the Court of Session in Edinburgh may allow. DNO Bidco will make an announcement by 8.00 a.m. on the UK business day following such date confirming whether it has invoked the condition, waived the deadline, or agreed to extend the deadline. Under the UK Takeover Code, cash offers require the bidder’s financial adviser to confirm that sufficient resources are available to the bidder to satisfy full acceptance of the offer. In connection with the offer and this confirmation, DNO made a USD 400 million cash deposit which is held under the terms of an escrow arrangement with Lambert Energy Advisory Limited, as DNO Bidco’s financial adviser in relation to the offer, and DNB Bank ASA, as escrow agent. The deposit is included in Cash and cash equivalents and is restricted until: (i) if DNO Bidco’s offer becomes effective, the date on which it has satisfied its payment obligations in full; or (ii) the date on which DNO Bidco’s offer lapses, terminates or (with the consent of the UK Takeover Panel) is withdrawn. Note 19 | Subsequent events after the reporting date Kjøttkake development approved On 29 October 2026, DNO announced that the license partners have approved the development of the Kjøttkake discovery, in which DNO holds a 40 percent interest. The three-well subsea project will be tied back to the Gjøa platform. Kjøttkake holds an estimated 37 MMboe of recoverable resources and is expected to start production in the first half of 2028. The field will deliver gross production of some 20,000 boepd at plateau. Afrodite resource estimate updated after appraisal well On 29 October 2026, DNO announced that an appraisal well on the Afrodite gas condensate discovery in license PL293 in the Norwegian North Sea has more than doubled the estimate of recoverable resources to 77-180 MMboe. DNO holds a 10 percent interest in Afrodite.
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Alternative performance measures 28 | DNO ASA DNO discloses alternative performance measures (APMs) as a supplement to the Group’s financial statements prepared based on issued guidelines from the European Securities and Markets Authority (ESMA). The Company believes that the APMs provide useful supplemental information to management, investors, securities analysts and other stakeholders and are meant to provide an enhanced insight into the financial development of DNO’s business operations, financing and future prospects and to improve comparability between periods. Reconciliations of relevant APMs, definitions and explanations of the APMs are provided below. EBITDA Quarters First nine months Full-Year USD million Q3 2026 Q3 2025 2026 2025 2025 Revenues 1,023.0 546.8 2,410.8 992.4 1,474.0 Lifting costs -109.7 -110.9 -349.2 -249.4 -376.4 Tariff and transportation expenses -66.6 -69.4 -184.9 -115.5 -181.5 Movement in overlift/underlift -18.1 4.6 2.9 40.5 86.0 Share of profit/loss from Joint Venture -0.3 -3.2 5.2 0.6 7.7 Exploration expenses -11.8 -18.1 -67.1 -62.1 -136.5 Administrative expenses -16.6 -17.5 -54.6 -34.3 -48.6 Other operating income/expenses -1.4 18.1 -8.8 17.4 18.8 EBITDA 798.4 350.5 1,754.3 589.6 843.6 EBITDAX USD million Q3 2026 Q3 2025 2026 2025 2025 EBITDA 798.4 350.5 1,754.3 589.6 843.6 Exploration expenses 11.8 18.1 67.1 62.1 136.5 EBITDAX 810.2 368.6 1,821.4 651.7 980.0 Lifting costs Q3 2026 Q3 2025 2026 2025 2025 Lifting costs (USD million) -109.7 -110.9 -349.2 -249.4 -376.4 Net production (MMboe)* 12.9 10.3 32.2 25.7 39.2 Lifting costs (USD/boe) 8.5 10.7 10.8 9.7 9.6 * For accounting purposes, the net production from equity accounted investments is excluded Capital expenditures Q3 2026 Q3 2025 2026 2025 2025 Purchases of intangible assets -17.3 -34.3 -50.1 -87.3 -130.3 Purchases of tangible assets* -154.3 -182.7 -431.1 -357.3 -487.7 Capital expenditures -171.6 -217.0 -481.3 -444.5 -618.0 * Excludes estimate changes on asset retirement obligations and capitalized interest
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Alternative performance measures Third Quarter 2026 Interim Results | 29 Operational spend Quarters First nine months Full-Year USD million Q3 2026 Q3 2025 2026 2025 2025 Lifting costs -109.7 -110.9 -349.2 -249.4 -376.4 Tariff and transportation expenses -66.6 -69.4 -184.9 -115.5 -181.5 Exploration expenses -11.8 -18.1 -67.1 -62.1 -136.5 Exploration cost previously capitalized carried to cost (Note 4) -0.7 -0.8 16.7 14.5 62.8 Purchases of intangible assets -17.3 -34.3 -50.1 -87.3 -130.3 Purchases of tangible assets -154.3 -182.7 -431.1 -357.3 -487.7 Payments for decommissioning -26.4 -9.6 -100.4 -13.4 -33.2 Operational spend -386.8 -425.7 -1,166.1 -870.5 -1,282.8 Free cash flow USD million Q3 2026 Q3 2025 2026 2025 2025 Net cash from/used in operating activities 503.5 326.2 1,319.7 441.7 590.6 Capital expenditures -171.6 -217.0 -481.3 -444.5 -618.0 Payments from license transactions 20.4 - 15.6 - 7.4 Payments for decommissioning -26.4 -9.6 -100.4 -13.4 -33.2 Equity contribution into Joint Venture -2.8 -6.3 -9.5 -9.2 -10.5 Dividends from Joint Venture 3.4 7.7 17.5 19.8 27.2 Free cash flow 326.5 101.0 761.7 -5.7 -36.6 Equity USD million Q3 2026 Q3 2025 2026 2025 2025 Equity 1,415.5 1,411.1 1,415.5 1,411.1 1,328.5 Total assets 6,807.7 6,063.1 6,807.7 6,063.1 5,998.3 Equity ratio 20.8% 23.3% 20.8% 23.3% 22.1% Net debt USD million Q3 2026 Q3 2025 2026 2025 2025 Cash and cash equivalents (including restricted cash) 1,007.6 531.5 1,007.6 531.5 453.7 Interest-bearing liabilities (Note 12) 1,239.5 1,339.7 1,239.5 1,339.7 1,339.5 Net cash/debt -231.9 -808.3 -231.9 -808.3 -885.9
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Alternative performance measures 30 | DNO ASA Definitions and explanations of APMs The Company has defined and explained the purpose of the following APMs: EBITDA (Earnings before interest, tax, depreciation and amortization) EBITDA, as reconciled above, can be found by excluding the DD&A, impairment of oil and gas assets and gain/loss on transactions from the profit/loss from operating activities. Management believes that this measure provides useful information regarding the Group’s ability to fund its capital investments and provides a helpful measure for comparing its operating performance with those of other companies. EBITDAX (Earnings before interest, tax, depreciation, amortization and exploration expenses) EBITDAX, as reconciled above, can be found by excluding the exploration expenses from the EBITDA. Management believes that this measure provides useful information regarding the Group’s profitability and ability to fund its exploration activities and provides a helpful measure for comparing its performance with those of other companies. Lifting costs (USD/boe) Lifting costs comprise expenses related to the production of oil and gas, including operation and maintenance of installations, well intervention activities and insurances. DNO’s lifting costs per boe are calculated by dividing DNO’s share of lifting costs across producing assets by net production for the relevant period. Management believes that the lifting cost per boe is a useful measure because it provides an indication of the Group’s level of operational cost effectiveness between time periods and with those of other companies. Capital expenditures Capital expenditures comprise the purchase of intangible and tangible assets irrespective of whether paid in the period. Management believes that this measure is useful because it provides an overview of capital investments used in the relevant period. Operational spend Operational spend comprises lifting costs, tariff and transportation expenses, exploration expenses, capital expenditures and payments for decommissioning. Exploration expenses are adjusted to exclude the write-off of exploration costs previously capitalized. Management believes that this measure is useful because it provides a complete overview of the Group’s total operational costs, capital investments and payments for decommissioning used in the relevant period. Equity Management uses total equity and equity ratio to monitor capital and financial covenants. The equity ratio is calculated by dividing total equity by the total assets. Free cash flow Free cash flow comprises net cash from/used in operating activities less capital expenditures and payments for decommissioning, adjusted for net payments/proceeds from license transactions and net cash received/paid from equity accounted investments. Management believes that this measure is useful because it provides an indication of the profitability of the Group’s operating activities excluding the non-cash items of the income statement and includes operational spend. This measure also provides a helpful measure for comparing with that of other companies. Net cash/debt Net cash/debt comprises cash and cash equivalents less bond loans, reserve-based lending facility and offtake financing facilities. Substantially all of the hybrid bond is classified as equity under IFRS and is therefore not included in net cash/debt. Management believes that net debt is a useful measure because it provides an indication of the minimum necessary debt financing (if the figure is negative) to which the Group is subject at the balance sheet date.
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Third Quarter 2026 Interim Results | 31 NOTES
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DNO ASA Dokkveien 1 N-0250 Oslo Norway Phone: (+47) 23 23 84 80 dno.no