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DNO ASA Earnings Release 2025
3580_rns_2026-02-05_1add3377-d4ba-461f-9779-28b814b56970.pdf
Earnings Release
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{1}------------------------------------------------
Key figures
| Quarters | Full-Year | ||||
|---|---|---|---|---|---|
| USD million | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 |
| Key financials | |||||
| Revenues | 481.6 | 546.8 | 176.6 | 1,474.0 | 666.8 |
| EBITDAX | 328.4 | 368.6 | 100.4 | 980.0 | 422.2 |
| EBITDA | 254.0 | 350.5 | 71.4 | 843.6 | 333.3 |
| Operating profit/loss (-) | 177.1 | 221.8 | -81.9 | 512.8 | 6.1 |
| Net profit/loss (-) | -34.1 | 19.9 | -98.4 | -25.2 | -27.1 |
| Free cash flow | -31.7 | 101.0 | -5.4 | -37.4 | 58.8 |
| Operational spend | 412.3 | 425.7 | 187.2 | 1,282.8 | 568.0 |
| Net cash/debt (-) | -885.9 | -808.3 | 99.0 | -885.9 | 99.0 |
| Lifting costs (USD/boe) | 9.4 | 10.7 | 7.9 | 9.6 | 6.5 |
| Key operational data | |||||
| Gross operated production (boepd) | 87,823 | 58,081 | 80,765 | 79,217 | 80,280 |
| Net production (boepd) | 149,678 | 115,396 | 77,646 | 110,667 | 77,269 |
| Sales volume (boepd) | 94,971 | 93,868 | 34,513 | 69,128 | 33,918 |
Sval Energi is included in the Group accounts from 1 June 2025. For more information about key figures, see the section on alternative performance measures.
2025 highlights
- Year-on-year doubling of revenues to USD 1,474 million in 2025, boosted by the June acquisition of Sval Energi Group AS in Norway
- Cash from operations reached USD 929 million, also more than doubled compared to previous year
- Operating profit increased to USD 513 million, while net profit stood at negative USD 25 million after deducting income tax and net financial expenses
-
Net production increased 43 percent year-on-year to 110,700 barrels of oil equivalent per day (boepd), of which North Sea 54,800 boepd, Kurdistan 52,600 boepd and West Africa 3,300 boepd
-
Production picked up in the fourth quarter with net production of 88,300 boepd in the North Sea and 58,000 boepd in Kurdistan
- Full production capacity in Kurdistan restored by yearend following midyear drone strikes
- A major milestone reached in late 2025 with 500 million barrels produced from Tawke license in Kurdistan (75 percent and operator)
- In 2025, USD 130 million was returned to shareholders through quarterly dividends
Cover photo: Marking the 500 million barrels milestone at the Tawke license recently, DNO Executive Chairman Bijan Mossavar-Rahmani cut the cake together with the chef. The cake featured an illustration of a key and the milestone slogan: DNO holds the key to Tawke.
{2}------------------------------------------------
Operational review
Gross operated production (Thousand boepd)
Net production (Thousand boepd)
Gross production from the Group's operated licenses during the fourth quarter averaged 87,823 barrels of oil equivalent per day (boepd), up from 58,081 boepd in the previous quarter. In Kurdistan, gross production increased to an average of 77,268 boepd during the fourth quarter, representing a 66 percent increase from the previous quarter (46,572 boepd). The increase is driven by recovery in production after the mid-July drone strikes, which resulted in temporary shutdown in the previous quarter. Operated production in the North Sea decreased to an average of 10,555 boepd, primarily attributable to lower production from the Trym field.
Net production during the fourth quarter stood at 149,678 boepd, up from 115,396 boepd in the previous quarter. In Kurdistan, net production averaged 57,951 boepd, up from 34,929 boepd in the previous quarter, the North Sea averaged 88,271 boepd, up from 77,324 boepd in the previous quarter and the Group's West Africa gas asset offshore Côte d'Ivoire averaged 3,456 boepd, up from 3,143 boepd in the previous quarter. The increase in net production compared to the previous quarter was mainly driven by the recovery in Kurdistan following the mid-July drone strikes. In the North Sea, additional contributions came from reduced turnaround activity, start-up of production at the Verdande and Andvare projects, and the ramp-up of production at the Maria Revit project.
Net entitlement (NE) production averaged 108,290 boepd during the fourth quarter, up from 91,772 boepd in the previous quarter.
Sales volume averaged 94,971 boepd during the fourth quarter, up from 93,868 boepd in the previous quarter. The increase in sales volume was mainly driven by increased sales volumes in Kurdistan partly offset by decreased sales volumes in the North Sea as the Company moved from an oil overlift position in the prior quarter to an underlift position in the current quarter. The net underlift position was 0.50 million barrels of oil equivalent (MMboe) as of end-Q4 (Q3 2025: overlift of 0.82 MMboe).
Gross operated production
| Quarters | Full-Year | ||||||
|---|---|---|---|---|---|---|---|
| boepd | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 | ||
| Kurdistan | 77,268 | 46,572 | 74,163 | 70,092 | 78,620 | ||
| North Sea | 10,555 | 11,508 | 6,602 | 9,124 | 1,659 | ||
| Total | 87,823 | 58,081 | 80,765 | 79,217 | 80,280 |
The table above shows gross operated production from the Group's operated licenses.
Net production
| Quarters | Full-Year | |||||
|---|---|---|---|---|---|---|
| boepd | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 | |
| Kurdistan | 57,951 | 34,929 | 55,620 | 52,569 | 58,965 | |
| North Sea | 88,271 | 77,324 | 19,031 | 54,811 | 15,201 | |
| West Africa | 3,456 | 3,143 | 2,994 | 3,287 | 3,103 | |
| Total | 149,678 | 115,396 | 77,646 | 110,667 | 77,269 |
Net production is based on DNO's percentage of ownership in the licenses. West Africa segment is equity accounted.
Net entitlement (NE) production
| Quarters | Full-Year | |||||
|---|---|---|---|---|---|---|
| boepd | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 | |
| Kurdistan | 20,019 | 14,449 | 17,424 | 17,896 | 18,172 | |
| North Sea | 88,271 | 77,324 | 19,031 | 54,811 | 15,201 | |
| Total | 108,290 | 91,772 | 36,456 | 72,707 | 33,373 |
NE production from the North Sea equals the segment's net production.
Sales volume
| Quarters | Full-Year | |||||
|---|---|---|---|---|---|---|
| boepd | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 | |
| Kurdistan | 20,019 | 14,449 | 17,424 | 17,896 | 18,172 | |
| North Sea | 74,952 | 79,419 | 17,088 | 51,231 | 15,746 | |
| Total | 94,971 | 93,868 | 34,513 | 69,128 | 33,918 |
Sales volume reflect North Sea lifted volumes and NE production for Kurdistan.
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Activity overview
Kurdistan region of Iraq
Gross production from the DNO-operated Tawke license, containing the Tawke and Peshkabir fields averaged 77,268 bopd during the fourth quarter of 2025 (46,572 bopd in Q3 2025). Output was up 66 percent from the previous quarter as the Company gradually restored production capacity following drone strikes in mid-2025. The Tawke field contributed 29,095 bopd (23,514 bopd in Q3 2025) and the Peshkabir field contributed 48,173 bopd (23,059 bopd in Q3 2025) during the quarter.
In mid-December 2025, DNO announced that it was revving up operations in Kurdistan as the Company passed the milestone marking 500 million barrels of oil produced from the Tawke license. The same month, drilling resumed after a two-and-ahalf-year spending hiatus with the spud of a new production well targeting the shallow Jeribe reservoir in the Tawke field. During the quarter, two rigs were mobilized to drill eight wells on the license through 2026. A third rig was signed up in January 2026 to drill additional wells in the flagship license, solidifying DNO's position as by far the most active international operator in the region.
Kurdistan oil is again flowing to international markets through the Iraq-Türkiye Pipeline. Exports resumed in late September 2025 after being halted since March 2023. To ensure predictable cash to support its ongoing spend, DNO continues to sell its oil on a cash-and-carry basis under existing contracts with local buyers at a price in the low USD 30s per barrel.
DNO holds a 75 percent operated interest in the Tawke license with partner Genel Energy International Limited holding the remaining 25 percent.
At the DNO-operated Baeshiqa license, the Company works to minimize license running cost while determining its future work program.
DNO holds a 64 percent operated interest in the Baeshiqa license (80 percent paying interest) with partners being Turkish Energy Company (TEC) with a 16 percent interest (20 percent paying interest) and the KRG with a 20 percent carried interest.
Net production (bopd) per field in Kurdistan:
| Quarters | Full-Year | |||||
|---|---|---|---|---|---|---|
| bopd | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 | |
| Tawke | 21,821 | 17,635 | 20,898 | 20,589 | 21,865 | |
| Peshkabir | 36,130 | 17,294 | 34,709 | 31,981 | 37,097 | |
| Baeshiqa | - | - | 13 | - | 3 | |
| Total | 57,951 | 34,929 | 55,620 | 52,569 | 58,965 |
North Sea
Net production averaged 88,271 boepd in the North Sea segment during the fourth quarter of 2025 (77,324 boepd in Q3 2025), of which 84,153 boepd was in Norway and 4,118 boepd in the United Kingdom (UK) (74,362 boepd and 2,962 boepd in Q3 2025, respectively). In the fourth quarter, oil accounted for 49 percent of production, gas for 44 percent and natural gas liquids (NGL) for 8 percent. In the previous quarter, the split was 50 percent oil, 43 percent gas and 7 percent NGL.
Following DNO's acquisition of Sval Energi Group AS in June 2025, the legal merger of the Norwegian operating subsidiaries DNO Norge AS and Sval Energi AS was completed shortly before yearend.
With the recent startup of Andvare (32 percent) and Verdande (14.8 percent), DNO holds stakes in 30 producing North Sea fields across its 130 exploration and production licenses. DNO has another four ongoing North Sea developments (Dvalin North, 10 percent; Symra, 20 percent; Bestla, 39.3 percent and Berling, 30 percent) coming onstream between 2026 and 2029, underpinning the Company's continued growth on its home surf.
In the fourth quarter, the Company launched a fast-track project to develop its 2025 Kjøttkake discovery (40 percent) targeting first oil in early 2028. Kjøttkake is one of four DNO discoveries scheduled for final investment decisions by license partnerships in 2026.
DNO's active exploration program continued through the quarter with the drilling of Page (50 percent), Tyrihans Øst (30 percent) and Camilla Nord (5.5 percent). While Page was classified as dry with hydrocarbon shows, the two other wells discovered 1-8 MMboe and 2.2-4.7 MMboe, respectively, and are potential tieback candidates to existing infrastructure.
Following the end of the reporting period, DNO was in January 2026 awarded participation in 17 exploration licenses, of which four are operatorships, under Norway's Awards in Predefined Areas (APA) 2025 licensing round.
Net production (boepd) per field in the North Sea:
| Quarters | Full-Year | |||||
|---|---|---|---|---|---|---|
| boepd | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 | |
| Arran | 3,553 | 2,538 | 4,837 | 3,366 | 1,591 | |
| Brage | 2,431 | 3,542 | 2,511 | 2,675 | 2,697 | |
| Dvalin | 3,206 | 2,718 | - | 1,829 | - | |
| Ekofisk area | 9,326 | 9,260 | - | 4,775 | - | |
| Fenja | 2,447 | 2,376 | 1,150 | 1,892 | 1,422 | |
| Gjøa area | 17,066 | 12,122 | - | 8,644 | - | |
| Ivar Aasen area | 2,576 | 2,596 | - | 1,607 | - | |
| Kvitebjørn | 9,136 | 8,679 | - | 5,272 | - | |
| Maria | 5,155 | 3,551 | - | 2,559 | - | |
| Martin Linge | 7,999 | 8,069 | - | 4,736 | - | |
| Norne area | 10,457 | 5,623 | 5,571 | 6,091 | 4,924 | |
| Trym | 4,730 | 6,564 | 696 | 3,870 | 175 | |
| Ula area | 8,301 | 8,991 | 3,622 | 6,505 | 3,425 | |
| Verdande | 1,165 | - | - | 294 | - | |
| Vilje | 624 | 628 | 608 | 626 | 716 | |
| Other | 99 | 65 | 37 | 71 | 252 | |
| Total | 88,271 | 77,324 | 19,031 | 54,811 | 15,201 |
Ekofisk area comprises Ekofisk and SE Tor fields, Gjøa area comprises Nova, Duva and Vega fields, Ivar Aasen area comprises Ivar Aasen and Hanz fields, Norne area comprises Andvare, Alve, Marulk, Norne, Urd and Skuld fields, and Ula area comprises Ula, Tambar, Oda and Blane (UK) fields.
West Africa
The net production from the Company's equity accounted investment, Côte d'Ivoire (West Africa segment), averaged 3,456 boepd in the fourth quarter of 2025 (3,143 boepd in Q3 2025).
| Quarters | Full-Year | |||||
|---|---|---|---|---|---|---|
| boepd | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 | |
| Block CI-27 | 3,456 | 3,143 | 2,994 | 3,287 | 3,103 | |
| Total | 3,456 | 3,143 | 2,994 | 3,287 | 3,103 |
{4}------------------------------------------------
Financial review
Revenues, operating result and cash
Revenues in the fourth quarter stood at USD 481.6 million, down 12 percent compared to the previous quarter (Q3 2025: USD 546.8 million). The main driver of the revenue decrease was reduced sales volumes and realized prices in the North Sea partly offset by higher sales volumes in Kurdistan.
| Quarters | Full-Year | |||||
|---|---|---|---|---|---|---|
| USD million | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 | |
| Kurdistan | 58.2 | 41.5 | 54.9 | 211.2 | 230.8 | |
| North Sea | 423.4 | 505.3 | 121.8 | 1,262.8 | 436.0 | |
| Total | 481.6 | 546.8 | 176.6 | 1,474.0 | 666.8 |
| Kurdistan | |||||
|---|---|---|---|---|---|
| Realized price | Quarters | Full-Year | |||
| USD/boe | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 |
| Oil | 31.6 | 31.2 | 34.2 | 32.3 | 34.7 |
| Total | 31.6 | 31.2 | 34.2 | 32.3 | 34.7 |
| North Sea | |||||
|---|---|---|---|---|---|
| Realized price | Quarters Full-Year |
||||
| USD/boe | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 |
| Oil | 63.6 | 72.0 | 73.3 | 69.1 | 83.5 |
| Gas | 60.5 | 63.8 | 85.9 | 66.3 | 68.8 |
| NGL | 38.9 | 40.5 | 45.9 | 41.0 | 46.7 |
| Total | 59.3 | 67.2 | 75.6 | 65.6 | 74.7 |
The Group reported an operating profit of USD 177.1 million in the fourth quarter, down from an operating profit of USD 221.8 million in the previous quarter, primarily due to reduced revenue, higher lifting costs and increased exploration costs expensed in the North Sea partly offset by net impairment reversal and gain on license transactions.
Net financial expenses decreased to USD 13.6 million (Q3 2025: USD 51.6 million) mainly due to increase in capitalized interest of USD 32 million in relation to development projects in the North Sea.
The Group ended the quarter with a cash balance of USD 453.7 million (Q3 2025: USD 531.5 million).
Cost of goods sold
In the fourth quarter, the cost of goods sold amounted to USD 296.0 million, down from USD 303.9 million in the previous quarter. The decrease mainly reflects the shift from a net overlift to a net underlift position in the North Sea, partly offset by higher lifting costs and depreciation.
Lifting costs
Lifting costs stood at USD 127.0 million in the fourth quarter, up from USD 110.9 million in the previous quarter. In Kurdistan, the average lifting cost was USD 5.4 per barrel of oil equivalent (boe), down from USD 7.5 per boe in the previous quarter driven by higher production from stabilized operations after the drone strikes. In the North Sea, the average lifting cost stood at USD 12.1 per boe, down from USD 12.2 per boe in the previous quarter primarily due to increased production.
| Quarters | Full-Year | |||||
|---|---|---|---|---|---|---|
| USD million | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 | |
| Kurdistan | 28.9 | 24.2 | 26.2 | 102.1 | 83.0 | |
| North Sea | 98.6 | 86.8 | 28.3 | 274.9 | 93.2 | |
| Total | 127.0 | 110.9 | 54.5 | 376.4 | 175.5 |
| Quarters | Full-Year | ||||||
|---|---|---|---|---|---|---|---|
| (USD/boe) | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 | ||
| Kurdistan | 5.4 | 7.5 | 5.1 | 5.3 | 3.8 | ||
| North Sea | 12.1 | 12.2 | 16.2 | 13.7 | 16.7 | ||
| Average | 9.4 | 10.7 | 7.9 | 9.6 | 6.5 |
Depreciation, depletion and amortization (DD&A)
DD&A related to the Group's oil and gas production assets amounted to USD 144.2 million in the fourth quarter, up from USD 123.0 million in the previous quarter. The increase in DD&A was mainly driven by higher production in the North Sea and Kurdistan.
| Quarters | Full-Year | |||||
|---|---|---|---|---|---|---|
| USD million | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 | |
| Kurdistan | 28.2 | 20.3 | 28.0 | 99.9 | 116.1 | |
| North Sea | 116.0 | 102.6 | 19.4 | 289.7 | 62.2 | |
| Total | 144.2 | 123.0 | 47.3 | 389.6 | 178.2 |
| Quarters | Full-Year | |||||
|---|---|---|---|---|---|---|
| (USD/boe) | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 | |
| Kurdistan | 15.3 | 15.3 | 17.5 | 15.3 | 17.5 | |
| North Sea | 14.3 | 14.4 | 11.1 | 14.5 | 11.2 | |
| Average | 14.5 | 14.6 | 14.1 | 14.7 | 14.6 |
Exploration costs expensed
Exploration costs expensed in the fourth quarter amounted to USD 74.4 million, up from USD 18.1 million in the previous quarter. The increase in exploration costs expensed was mainly due to expensing of the Page dry well.
| USD million | Q4 2025 | Quarters Q3 2025 |
Q4 2024 | 2025 | Full-Year 2024 |
|---|---|---|---|---|---|
| Kurdistan | - | - | - | - | - |
| North Sea | 74.4 | 18.1 | 29.0 | 136.5 | 88.9 |
| Total | 74.4 | 18.1 | 29.0 | 136.5 | 88.9 |
Capital expenditures
Capital expenditures stood at USD 173.5 million in the fourth quarter, of which USD 6.6 million were in Kurdistan and USD 166.8 million in the North Sea.
| Quarters | Full-Year | |||||
|---|---|---|---|---|---|---|
| USD million | Q4 2025 | Q3 2025 | Q4 2024 | 2025 | 2024 | |
| Kurdistan | 6.6 | 4.1 | 5.8 | 21.9 | 46.8 | |
| North Sea | 166.8 | 212.8 | 90.9 | 595.9 | 239.3 | |
| Other | - | 0.1 | 0.1 | 0.2 | 0.9 | |
| Total | 173.5 | 217.0 | 96.8 | 618.0 | 287.0 |
{5}------------------------------------------------
Consolidated statements of comprehensive income
| Quarters | Full-Year | ||||
|---|---|---|---|---|---|
| (unaudited, in USD million) | Note | Q4 2025 | Q4 2024 | 2025 | 2024 |
| Revenues | 2,3 | 481.6 | 176.6 | 1,474.0 | 666.8 |
| Lifting costs | -127.0 | -54.5 | -376.4 | -175.5 | |
| Tariff and transportation expenses | -65.9 | -18.8 | -181.5 | -49.4 | |
| Movement in overlift/underlift | 45.5 | 3.6 | 86.0 | 2.1 | |
| Depreciation, depletion and amortization | 7 | -148.6 | -48.9 | -403.4 | -184.1 |
| Cost of goods sold | -296.0 | -118.6 | -875.3 | -406.9 | |
| Gross profit | 185.6 | 58.1 | 598.7 | 259.9 | |
| Share of profit/loss from Joint Venture | 7.1 | -0.3 | 7.7 | 3.3 | |
| Other operating income/expenses | 1.4 | -0.7 | 18.8 | -1.6 | |
| Administrative expenses | -14.4 | -5.5 | -48.6 | -23.5 | |
| Impairment/reversal oil and gas assets | 7 | 56.8 | -104.4 | 56.4 | -146.0 |
| Exploration expenses | 4 | -74.4 | -29.0 | -136.5 | -88.9 |
| Gain on license transactions | 15 | 14.9 | - | 16.2 | 3.0 |
| Operating profit/loss | 177.1 | -81.9 | 512.8 | 6.1 | |
| Financial income | 5 | 8.6 | 9.0 | 37.7 | 47.3 |
| Financial expenses | 5 | -22.2 | -19.8 | -153.1 | -66.7 |
| Profit/loss before income tax | 163.6 | -92.7 | 397.4 | -13.3 | |
| Tax income/expense | 6 | -197.7 | -5.7 | -422.6 | -13.8 |
| Net profit/loss | -34.1 | -98.4 | -25.2 | -27.1 | |
| Currency translation differences | -2.0 | -16.2 | 29.8 | -25.8 | |
| Other comprehensive income | -2.0 | -16.2 | 29.8 | -25.8 | |
| Total comprehensive income, net of tax | -36.1 | -114.5 | 4.6 | -52.9 | |
| Net profit/loss attributable to: | |||||
| Dividends paid on hybrid capital | 10 | 10.8 | - | 21.5 | - |
| Equity holders of the parent | -44.8 | -98.4 | -46.7 | -27.1 | |
| Net profit/loss | -34.1 | -98.4 | -25.2 | -27.1 | |
| Earnings per share, basic (USD per share) | 16 | -0.05 | -0.10 | -0.05 | -0.03 |
| Earnings per share, diluted (USD per share) | 16 | -0.05 | -0.10 | -0.05 | -0.03 |
| Weighted average number of shares outstanding (millions) | 975.00 | 975.00 | 975.00 | 975.00 |
{6}------------------------------------------------
Consolidated statements of financial position
| ASSETS | At 31 Dec | ||
|---|---|---|---|
| (unaudited, in USD million) | Note | 2025 | 2024 |
| Non-current assets | |||
| Deferred tax assets | 6 | 8.7 | 39.6 |
| Goodwill | 7 | 1,360.6 | 102.1 |
| Other intangible assets | 7 | 296.9 | 228.5 |
| Property, plant and equipment | 7 | 3,029.1 | 1,109.4 |
| Investment in Joint Venture | 38.1 | 48.8 | |
| Other non-current receivables | 9 | 120.0 | 98.2 |
| Other assets | 4.5 | - | |
| Total non-current assets | 4,857.9 | 1,626.6 | |
| Current assets | |||
| Inventories | 8 | 105.7 | 74.8 |
| Trade and other receivables | 9 | 569.6 | 338.1 |
| Derivatives | 14 | 11.5 | - |
| Tax receivables | 6 | - | 27.5 |
| Cash and cash equivalents | 453.7 | 899.0 | |
| Total current assets | 1,140.4 | 1,339.5 | |
| 2,966.1 | |||
| Note | 5,998.3 At 31 Dec 2025 |
2024 | |
| TOTAL ASSETS EQUITY AND LIABILITIES (unaudited, in USD million) |
|||
| Equity | |||
| 1,328.5 | |||
| 1,328.5 | |||
| Equity Total equity Non-current liabilities |
|||
| Deferred tax liabilities | 6 | 1,215.4 | |
| Interest-bearing liabilities | 11 | 989.1 | |
| 12 | 1,234.9 | ||
| 3,439.4 | |||
| 13 | 462.1 | ||
| 6 | 320.3 | ||
| 11 | 339.4 | ||
| Provisions and other liabilities Total non-current liabilities Current liabilities Trade and other payables Income taxes payable Interest-bearing liabilities Derivatives |
14 | 5.6 | |
| 12 | 103.1 | ||
| 1,230.4 | |||
| Provisions and other liabilities Total current liabilities |
|||
| Total liabilities | 4,669.8 | ||
| TOTAL EQUITY AND LIABILITIES | 5,998.3 | 1,080.0 1,080.0 257.2 790.5 484.5 1,532.2 323.7 - - - 30.2 353.9 1,886.1 2,966.1 |
{7}------------------------------------------------
Consolidated cash flow statement
| Quarters | Full-Year | |||
|---|---|---|---|---|
| (unaudited, USD million) Note |
Q4 2025 | Q4 2024 | 2025 | 2024 |
| Operating activities | ||||
| Profit/loss before income tax | 163.6 | -92.7 | 397.4 | -13.3 |
| Adjustments to add/deduct non-cash items: | ||||
| Exploration cost previously capitalized carried to cost 4 |
48.3 | 12.8 | 62.8 | 37.7 |
| Depreciation, depletion and amortization 7 |
148.6 | 48.9 | 403.4 | 184.1 |
| Impairment oil and gas assets 7 |
-56.8 | 104.4 | -56.4 | 146.0 |
| Loss/gain on PP&E | -14.9 | - | -16.2 | -3.0 |
| Time value effects on trade receivables 5, 9 |
7.9 | -0.4 | 14.8 | -11.4 |
| Share of profit/loss from Joint Venture | -7.1 | 0.3 | -7.7 | -3.3 |
| Amortization of borrowing issue costs 5, 11 |
0.7 | 0.9 | 10.1 | 3.8 |
| Accretion expense on ARO provisions 5 |
15.5 | 5.5 | 46.8 | 20.4 |
| Interest expense 5 |
-4.8 | 17.1 | 69.3 | 54.3 |
| Interest income 5 |
-5.5 | -11.9 | -35.1 | -38.1 |
| Other | -20.7 | 5.4 | -5.5 | -8.3 |
| Change in working capital items and provisions: | ||||
| - Inventories 8 |
-0.4 | 2.0 | 5.3 | 6.0 |
| - Trade and other receivables 9 |
89.8 | -44.8 | 127.4 | -46.1 |
| - Trade and other payables 13 |
-95.2 | 36.8 | -77.5 | 97.4 |
| - Provisions for other liabilities and charges 12 |
-5.5 | -2.3 | -9.8 | 6.9 |
| Cash generated from operations | 263.6 | 82.0 | 929.2 | 433.0 |
| Net income taxes paid/tax refund received | -96.5 | -0.8 | -263.7 | -0.8 |
| Interest received | 5.7 | 15.0 | 30.0 | 34.6 |
| Interest paid | -24.7 | -17.1 | -105.8 | -53.7 |
| Net cash from/used in operating activities | 148.1 | 79.0 | 589.8 | 413.0 |
| Investing activities Purchases of intangible assets |
-43.1 | -34.3 | -130.3 | -87.2 |
| Purchases of tangible assets | -130.4 | -62.5 | -487.7 | -199.8 |
| Payments for decommissioning | -19.8 | -0.9 | -33.2 | -4.9 |
| Acquisition of subsidiary, net of cash acquired 15 |
- | - | -203.4 | - |
| Proceeds/Payments (-) license transactions | 7.4 | -0.3 | 7.4 | -84.8 |
| Equity contribution into Joint Venture | -1.3 | -1.1 | -10.5 | -9.4 |
| Dividends from Joint Venture | 7.4 | 14.5 | 27.2 | 31.8 |
| Net cash from/used in investing activities | -179.8 | -84.5 | -830.6 | -354.2 |
| Financing activities | ||||
| Proceeds from borrowings 11 |
||||
| Proceeds from hybrid bond 10 |
7.5 | 15.0 | 1,273.1 | 365.0 |
| Repayment of borrowings 11 |
- | - | 400.0 | |
| Payment of debt issue costs 11 |
-7.2 | - | -1,701.9 | |
| Payment of hybrid bond issue costs 10 |
- | - | -11.6 | |
| Paid dividend | - | - | -6.4 | |
| Paid dividend hybrid bond owners 10 |
-35.8 | -27.4 | -129.7 | |
| Payment of lease liabilities | -10.8 | - | -21.5 | - -131.2 -5.6 - -102.5 - |
| Net cash from/used in financing activities | 0.1 -46.2 |
-0.7 -13.1 |
-3.5 -201.4 |
|
| Net increase/decrease in cash and cash equivalents | -77.9 | -18.5 | -442.2 | |
| Cash and cash equivalents at beginning of the period | 531.5 | 919.4 | 899.0 | |
| Exchange gain/losses on cash and cash equivalents | 0.1 | -1.8 | -3.1 | |
| Cash and cash equivalents at the end of the period | 453.7 | 899.0 | 453.7 | -2.5 123.2 182.1 718.8 -1.9 899.0 |
{8}------------------------------------------------
Consolidated statement of changes in equity
| Other equity Currency |
||||||
|---|---|---|---|---|---|---|
| (unaudited, in USD million) | Share capital |
Share premium |
Hybrid capital |
translation differences |
Retained earnings |
Total equity |
| Total equity as of 31 December 2023 | 32.8 | 343.6 | - | -39.9 | 898.3 | 1,234.8 |
| Currency translation differences | - | - | - | -25.8 | - | -25.8 |
| Other comprehensive income/loss | - | - | - | -25.8 | - | -25.8 |
| Profit/loss for the period | - | - | - | - | -27.1 | -27.1 |
| Total comprehensive income | - | - | - | -25.8 | -27.1 | -52.9 |
| Payment of dividend | - | - | - | - | -101.9 | -101.9 |
| Transactions with shareholders | - | - | - | - | -101.9 | -101.9 |
| Total equity as of 31 December 2024 | 32.8 | 343.6 | - | -65.7 | 769.3 | 1,080.0 |
| Other equity | ||||||
|---|---|---|---|---|---|---|
| Share | Share | Hybrid | Currency translation |
Retained | Total | |
| (unaudited, in USD million) | capital | premium | capital | differences | earnings | equity |
| Total equity as of 31 December 2024 | 32.8 | 343.6 | - | -65.7 | 769.3 | 1,080.0 |
| Currency translation differences | - | - | - | 29.8 | - | 29.8 |
| Other comprehensive income/loss | - | - | - | 29.8 | - | 29.8 |
| Profit/loss for the period | - | - | 21.5 | - | -46.7 | -25.2 |
| Total comprehensive income | - | - | 21.5 | 29.8 | -46.7 | 4.6 |
| Hybrid bond issue, Note 10 | - | - | 393.5 | - | - | 393.5 |
| Payment of dividend | - | - | -21.5 | - | -128.2 | -149.7 |
| Transactions with shareholders/hybrid capital owners | - | - | 372.0 | - | -128.2 | 243.8 |
| Total equity as of 31 December 2025 | 32.8 | 343.6 | 393.5 | -35.9 | 594.5 | 1,328.5 |
{9}------------------------------------------------
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 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 and Accounts 2024.
The interim financial information for 2025 and 2024 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 and equity instruments are recognized at fair value. A detailed description of the accounting policies applied is included in the DNO ASA Annual Report and Accounts 2024.
The accounting policies adopted in the preparation of the interim financial statements are consistent with those followed in the preparation of DNO ASA Annual Report and Accounts 2024.
Following the acquisition of Sval Energi, the Group has harmonized accounting principles where necessary, and Sval Energi has been consolidated in the Group's interim financial statements from 1 June 2025.
Due to rounding adjustments, some row and column totals may not exactly match the sum of the amounts shown.
{10}------------------------------------------------
The Group reports the following three operating segments: Kurdistan, North Sea (which includes the Group's oil and gas activities in Norway and the UK) and West Africa (which represents the Group's equity accounted investment in Côte d'Ivoire). The segment assets/liabilities do not include internal receivables/liabilities.
| Total | Un | |||||||
|---|---|---|---|---|---|---|---|---|
| Fourth quarter ending 31 December 2025 USD million |
Note | Kurdistan | North Sea | West Africa |
Other | reporting | allocated/ segments eliminated |
Total Group |
| Income statement information Revenues |
3 | 58.2 | 423.4 | - | - | 481.6 | - | 481.6 |
| Lifting costs | -28.9 | -98.6 | - | - | -127.5 | 0.6 | -127.0 | |
| Tariff and transportation expenses | - | -65.9 | - | - | -65.9 | - | -65.9 | |
| Movement in overlift/underlift | - | 45.5 | - | - | 45.5 | - | 45.5 | |
| Depreciation, depletion and amortization | 7 | -28.3 | -119.6 | - | - | -147.9 | -0.7 | -148.6 |
| Cost of goods sold | -57.2 | -238.6 | - | - | -295.9 | -0.2 | -296.0 | |
| Gross profit | 1.0 | 184.8 | - | - | 185.8 | -0.2 | 185.6 | |
| Share of profit/loss from Joint Venture | - | - | 7.1 | - | 7.1 | - | 7.1 | |
| Other operating income/expenses | -0.0 | -0.0 | - | 1.4 | 1.4 | - | 1.4 | |
| Administrative expenses | -0.6 | -8.9 | - | -0.3 | -9.8 | -4.6 | -14.4 | |
| Impairment/reversal oil and gas assets | 7 | - | 56.8 | - | - | 56.8 | - | 56.8 |
| Exploration expenses | 4 | - | -74.4 | - | - | -74.4 | - | -74.4 |
| Gain on license transactions | - | 14.9 | - | - | 14.9 | - | 14.9 | |
| Operating profit/loss | 0.3 | 173.3 | 7.1 | 1.2 | 181.9 | -4.7 | 177.1 | |
| Financial income/expense (net) | 5 | -4.6 | 4.1 | -1.9 | -0.0 | -2.4 | -11.2 | -13.6 |
| Tax income/expense | 6 | - | -197.6 | - | - | -197.6 | -0.0 | -197.7 |
| Net profit/loss | -4.3 | -20.3 | 5.2 | 1.2 | -18.2 | -15.9 | -34.1 |
{11}------------------------------------------------
| Fourth quarter ending 31 December 2024 USD million |
Note | Kurdistan | North Sea | West Africa |
Other | Total reporting |
Un allocated/ segment eliminated |
Total Group |
|---|---|---|---|---|---|---|---|---|
| Income statement information | ||||||||
| Revenues | 3 | 54.9 | 121.8 | - | - | 176.6 | - | 176.6 |
| Lifting costs | -26.2 | -28.3 | - | - | -54.6 | 0.0 | -54.5 | |
| Tariff and transportation expenses | - | -18.8 | - | - | -18.8 | - | -18.8 | |
| Movement in overlift/underlift | - | 3.6 | - | - | 3.6 | - | 3.6 | |
| Depreciation, depletion and amortization | 7 | -28.1 | -19.9 | - | - | -48.0 | -0.9 | -48.9 |
| Cost of goods sold | -54.4 | -63.4 | - | - | -117.8 | -0.8 | -118.6 | |
| Gross profit | 0.5 | 58.4 | - | - | 58.9 | -0.8 | 58.1 | |
| Share of profit/loss from Joint Venture | - | - | -0.3 | - | -0.3 | - | -0.3 | |
| Other operating income/expenses | -0.7 | 0.0 | - | -0.1 | -0.8 | 0.0 | -0.7 | |
| Administrative expenses | -0.5 | -1.3 | - | -0.4 | -2.2 | -3.3 | -5.5 | |
| Impairment oil and gas assets | 7 | -89.0 | -15.4 | - | - | -104.4 | - | -104.4 |
| Exploration expenses | 4 | - | -29.0 | - | - | -29.0 | - | -29.0 |
| Operating profit/loss | -89.6 | 12.7 | -0.3 | -0.5 | -77.8 | -4.0 | -81.9 | |
| Financial income/expense (net) | 5 | 3.1 | -5.1 | 0.5 | 0.2 | -1.4 | -9.4 | -10.8 |
| Tax income/expense | 6 | - | -5.7 | - | - | -5.7 | - | -5.7 |
| Net profit/loss | -86.6 | 1.9 | 0.2 | -0.4 | -84.9 | -13.5 | -98.4 |
{12}------------------------------------------------
| Note | Kurdistan | North Sea | West Africa |
Other | Total reporting segment |
Un allocated/ eliminated |
Total Group |
|---|---|---|---|---|---|---|---|
| 3 | 211.2 | 1,262.8 | - | - | 1,474.0 | - | 1,474.0 |
| -376.4 | |||||||
| -181.5 | |||||||
| 86.0 | |||||||
| 7 | -100.5 | -299.7 | - | - | -400.2 | -3.2 | -403.4 |
| -202.6 | -670.1 | - | - | -872.7 | -2.6 | -875.3 | |
| 8.6 | 592.7 | - | - | 601.3 | -2.6 | 598.7 | |
| 7.7 | |||||||
| 18.8 | |||||||
| -48.6 | |||||||
| 56.4 | |||||||
| 4 | - | -136.5 | - | - | -136.5 | - | -136.5 |
| - | 16.2 | - | - | 16.2 | - | 16.2 | |
| 6.3 | 505.2 | 7.7 | 18.0 | 537.1 | -24.3 | 512.8 | |
| -115.4 | |||||||
| -422.6 | |||||||
| 0.7 | 23.3 | 7.7 | 20.9 | 52.5 | -77.7 | -25.2 | |
| 4,857.9 | |||||||
| 1,140.4 | |||||||
| 802.4 | 4,832.1 | 38.1 | 1.3 | 5,673.9 | 324.4 | 5,998.3 | |
| 3,439.4 | |||||||
| 1,230.4 | |||||||
| 7 5 6 |
-102.1 - - - -1.1 -1.2 - -5.7 - 598.5 203.9 73.7 150.8 |
-274.9 -181.5 86.0 - 0.2 -23.9 56.4 -59.3 -422.5 4,211.1 621.1 2,358.0 1,047.9 |
- - - 7.7 - - - 0.0 - 38.1 - - - |
- - - - 19.6 -1.7 - 2.9 - - 1.3 - 7.0 |
-377.0 -181.5 86.0 7.7 18.7 -26.8 56.4 -62.0 -422.6 4,847.7 826.2 2,431.7 1,205.7 |
0.6 - - - 0.1 -21.8 - -53.3 -0.0 10.2 314.2 1,007.6 24.7 |
{13}------------------------------------------------
| Full-Year ending 31 December 2024 USD million |
Note | Kurdistan | North Sea | West Africa |
Other | Total reporting |
Un allocated/ segment eliminated |
Total Group |
|---|---|---|---|---|---|---|---|---|
| Income statement information | ||||||||
| Revenues | 3 | 230.8 | 436.0 | - | - | 666.8 | - | 666.8 |
| Lifting costs | -83.0 | -93.2 | - | - | -176.1 | 0.7 | -175.5 | |
| Tariff and transportation expenses | - | -49.4 | - | - | -49.4 | - | -49.4 | |
| Movement in overlift/underlift | - | 2.1 | - | - | 2.1 | - | 2.1 | |
| Depreciation, depletion and amortization | 7 | -116.7 | -64.1 | - | - | -180.8 | -3.4 | -184.1 |
| Cost of goods sold | -199.7 | -204.5 | - | - | -404.2 | -2.7 | -406.9 | |
| Gross profit | 31.1 | 231.5 | - | - | 262.6 | -2.7 | 259.9 | |
| Share of profit/loss from Joint Venture | - | - | 3.3 | - | 3.3 | - | 3.3 | |
| Other operating income/expenses | -1.4 | 0.6 | - | -0.9 | -1.7 | 0.0 | -1.6 | |
| Administrative expenses | -0.5 | -10.6 | - | -1.5 | -12.7 | -10.8 | -23.5 | |
| Impairment oil and gas assets | 7 | -89.0 | -57.0 | - | - | -146.0 | - | -146.0 |
| Exploration expenses | 4 | - | -88.9 | - | - | -88.9 | - | -88.9 |
| Gain on license transactions | - | 3.0 | - | - | 3.0 | - | 3.0 | |
| Operating profit/loss | -59.8 | 78.4 | 3.3 | -2.4 | 19.5 | -13.5 | 6.1 | |
| Financial income/expense (net) | 5 | 11.6 | -10.3 | 1.5 | 1.2 | 4.0 | -23.4 | -19.4 |
| Tax income/expense | 6 | - | -13.8 | - | - | -13.8 | - | -13.8 |
| Net profit/loss | -48.2 | 54.3 | 4.8 | -1.2 | 9.7 | -36.8 | -27.1 | |
| Financial position information | ||||||||
| Non-current assets | 663.1 | 902.5 | 48.8 | - | 1,614.4 | 12.2 | 1,626.6 | |
| Current assets | 237.4 | 283.2 | - | 1.3 | 521.8 | 817.7 | 1,339.5 | |
| Total assets | 900.5 | 1,185.7 | 48.8 | 1.3 | 2,136.3 | 829.9 | 2,966.1 | |
| Non-current liabilities | 71.4 | 705.1 | - | - | 776.5 | 755.7 | 1,532.2 | |
| Current liabilities | 142.3 | 177.4 | - | 8.1 | 327.8 | 26.1 | 353.9 | |
| Total liabilities | 213.8 | 882.4 | - | 8.1 | 1,104.3 | 781.8 | 1,886.1 |
{14}------------------------------------------------
Note 3 | Revenues
| Quarters | Full-Year | |||
|---|---|---|---|---|
| USD million | Q4 2025 | Q4 2024 | 2025 | 2024 |
| Sale of oil | 223.5 | 99.5 | 801.9 | 496.0 |
| Sale of gas | 214.7 | 64.4 | 576.7 | 138.5 |
| Sale of natural gas liquids (NGL) | 29.1 | 9.8 | 60.0 | 26.9 |
| Tariff income | 7.7 | 3.0 | 18.6 | 5.4 |
| Total revenues from contracts with customers | 475.0 | 176.6 | 1,457.3 | 666.8 |
| Gain/loss on derivative oil hedging instruments | 6.6 | - | 16.7 | - |
| Total revenues | 481.6 | 176.6 | 1,474.0 | 666.8 |
| Sale of oil (bopd) | 48,260 | 24,044 | 41,301 | 26,852 |
| Sale of gas (boepd) | 38,572 | 8,142 | 23,820 | 5,496 |
| Sale of natural gas liquids (NGL) (boepd) | 8,139 | 2,327 | 4,007 | 1,571 |
| Total sales volume (boepd) | 94,971 | 34,513 | 69,128 | 33,918 |
Note 4 | Exploration expenses
| Quarters | Full-Year | ||||
|---|---|---|---|---|---|
| USD million | Q4 2025 | Q4 2024 | 2025 | 2024 | |
| Exploration expenses (G&G and field surveys) | -9.1 | -5.2 | -26.9 | -16.5 | |
| Seismic costs | -8.3 | -7.3 | -19.0 | -16.5 | |
| Exploration cost capitalized in previous years carried to cost | - | - | -2.6 | -0.8 | |
| Exploration costs capitalized this year carried to cost | -48.3 | -12.8 | -60.2 | -37.0 | |
| Other exploration cost expensed | -8.7 | -3.8 | -27.7 | -18.3 | |
| Total exploration expenses | -74.4 | -29.0 | -136.5 | -88.9 |
Exploration expenses relate to North Sea.
Note 5 | Financial income and financial expenses
| Quarters | Full-Year | |||
|---|---|---|---|---|
| USD million Note |
Q4 2025 | Q4 2024 | 2025 | 2024 |
| Interest income | 5.5 | 11.9 | 35.1 | 38.1 |
| Currency exchange gain (net) | 3.2 | -2.9 | 1.7 | 9.2 |
| Other financial income | - | - | 0.9 | - |
| Financial income | 8.6 | 9.0 | 37.7 | 47.3 |
| Interest expenses | -26.8 | -17.1 | -104.9 | -54.3 |
| Interest expenses (IFRS 16) | -0.6 | -0.3 | -1.8 | -1.2 |
| Capitalized interest | 31.6 | 4.1 | 35.6 | 4.1 |
| Time value effect trade debtors 9 |
-7.9 | 0.4 | -14.8 | 11.4 |
| Amortization of borrowing costs 11 |
-0.7 | -0.8 | -10.1 | -3.8 |
| Accretion expense ARO | -15.5 | -5.5 | -46.8 | -20.4 |
| Premium expense bonds | - | - | -8.3 | - |
| Other financial expenses | -2.2 | -0.7 | -1.9 | -2.5 |
| Financial expenses | -22.2 | -19.8 | -153.1 | -66.7 |
| Net financial income/expenses | -13.6 | -10.8 | -115.4 | -19.4 |
{15}------------------------------------------------
Note 6 | Income taxes
| Quarters | Full-Year | |||
|---|---|---|---|---|
| USD million | Q4 2025 | Q4 2024 | 2025 | 2024 |
| Tax income/expense | ||||
| Change in deferred taxes | -189.7 | -49.2 | -408.1 | -57.9 |
| Income tax receivable/payable | -7.9 | 43.5 | -14.5 | 44.1 |
| Total tax income/expense (-) | -197.7 | -5.7 | -422.6 | -13.8 |
| Quarters | Full-Year | |||
|---|---|---|---|---|
| USD million | Q4 2025 | Q4 2024 | 2025 | 2024 |
| Reconciliation of change in deferred tax assets/liabilities | ||||
| Deferred tax assets/liabilities at beginning of the period | -1,028.2 | -184.1 | -217.6 | -192.4 |
| Changes in deferred taxes in the income statement | -189.7 | -49.2 | -408.1 | -57.9 |
| Deferred taxes related to transactions | 10.5 | - | -536.1 | 9.9 |
| Currency and other movements on deferred tax asset/liability | 0.7 | 15.7 | -45.0 | 22.8 |
| Deferred tax assets/liabilities (-) at end of the period | -1,206.8 | -217.6 | -1,206.8 | -217.6 |
| Recognized deferred tax assets | 8.7 | 39.6 | 8.7 | 39.6 |
| Recognized deferred tax liabilities | -1,215.4 | -257.2 | -1,215.4 | -257.2 |
| Quarters | Full-Year | |||
|---|---|---|---|---|
| USD million | Q4 2025 | Q4 2024 | 2025 | 2024 |
| Reconciliation of change in tax receivable/payable | ||||
| Net tax receivable/payable at beginning of the period | -429.7 | -17.3 | 27.5 | -4.6 |
| Tax receivable/payable related to transactions - posted directly to balance sheet | 17.3 | -0.2 | -606.7 | -12.2 |
| Current period tax receivable/payable | -7.9 | 43.5 | -14.5 | 44.1 |
| Tax payment/refund | 96.5 | 0.8 | 263.7 | 0.8 |
| Currency and other movements on tax receivable/payable | 3.6 | 0.7 | 9.7 | -0.6 |
| Tax receivable/payable (-) at end of the period | -320.3 | 27.5 | -320.3 | 27.5 |
| Tax receivables | - | 27.5 | - | 27.5 |
| Income taxes payable | -189.3 | - | -189.3 | - |
| Provision for uncertain tax positions | -131.0 | - | -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, recognized during the second quarter, mainly relates to tax exposures arising from acquisitions previously completed by Sval Energi, for which the original sellers have provided tax indemnities. A corresponding tax indemnity receivable of USD 128.8 million is recognized under Trade and other receivables.
{16}------------------------------------------------
Note 7 | Intangible assets/ Property, plant and equipment (PP&E)
| Quarters | Full-Year | |||
|---|---|---|---|---|
| USD million | Q4 2025 | Q4 2024 | 2025 | 2024 |
| Additions of intangible assets | 43.1 | 34.3 | 130.3 | 87.2 |
| Additions of goodwill and intangible assets through business combinations | 57.9 | -2.5 | 1,374.7 | 113.8 |
| Disposal of goodwill and intangible assets | -42.4 | 0.1 | -42.4 | -1.1 |
| Transfers from intangible assets | -42.1 | - | -42.1 | - |
| Additions of tangible assets | 194.1 | 86.4 | 564.0 | 226.1 |
| Additions of tangible assets through business combination | 25.5 | -0.2 | 1,508.8 | 112.5 |
| Disposal of tangible assets | -56.4 | 2.5 | -56.4 | -30.9 |
| Transfers to tangible assets | 42.1 | - | 42.1 | - |
| Additions of right-of-use (RoU) assets | 1.0 | - | 6.8 | 0.3 |
| Additions of RoU assets through business combinations | - | - | 27.3 | - |
| Depreciation, depletion and amortization | -148.6 | -48.9 | -403.4 | -184.1 |
| Impairment oil and gas assets/goodwill/RoU assets | 56.8 | -104.4 | 56.4 | -146.0 |
| Exploration cost previously capitalized carried to cost (Note 4) | -48.3 | -12.8 | -62.8 | -37.7 |
Additions of intangible assets are related to exploration and evaluation expenditures (successful efforts method), license interests and administrative software. Additions of tangible assets are related to oil and gas development and production assets including changes in estimate of asset retirement, and other tangible assets. Transfers during the quarter relate to reclassifications of Kjøttkake and Ofelia discoveries from exploration assets (Other intangible assets) to development assets (Property, plant and equipment). Additions of right-of-use (RoU) assets are related to lease contracts under IFRS 16 Leases, see Note 12. During the quarter, DNO consolidated its Stavanger operations from two offices into one. The right-of-use asset for the vacated office was impaired during the quarter, totaling USD 2.3 million.
Additions through business combinations and disposals during the year are explained in Note 15.
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 fourth quarter of 2025, a net impairment reversal of USD 56.8 million was recognized on pre-tax basis. This was primarily driven by the reversal of previously recognized impairments on the Bestla field, part of the Brage area CGU, following an updated assessment reflecting the completion of significant development activities, partly offset by impairment charges in the Ekofisk area due to updated cost profiles, and in the Dvalin and Ivar Aasen area mainly due to revised production profiles. After tax, the Group reports a net impairment charge of USD 46.7 million, as the reversal on the Bestla field gives rise to a deferred tax liability. Impairment of goodwill does not give rise to any tax impact, and the impairment amounts are therefore the same on a pre-tax and post-tax basis.
| 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 |
| Ekofisk area | 200.0 | -55.0 | - | -55.0 | -55.0 | - | - | - |
| Dvalin | 73.0 | -14.0 | - | -14.0 | -14.0 | - | - | - |
| Ivar Aasen area | 213.0 | -7.0 | - | -7.0 | -7.0 | - | - | - |
| Brage area | 151.0 | 134.9 | -105.2 | 29.7 | - | 134.9 | -105.2 | - |
| Other, North Sea | - | -2.1 | 1.8 | -0.3 | 0.2 | -2.3 | 1.8 | - |
| Total | - | 56.8 | -103.5 | -46.7 | -75.8 | 132.6 | -103.5 | - |
The table above shows the recoverable amounts and impairment charge or reversal for the CGUs which were impaired in the current quarter, and how it was recognized in the income statement and balance sheet. 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 (2026: 60.9, 2027: USD 66.6, and 2028: USD 73.9 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 (yearend 2024: USD 65 per barrel). For gas (2026: 10.5, 2027: USD 10.0 and 2028: USD 10.4 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 (yearend 2024: USD 9 per mscf). The relevant post-tax nominal discount rate (WACC) applied in the impairment test for Norwegian North Sea assets was 8.0 percent (yearend 2024: 8.9 percent).
{17}------------------------------------------------
Note 8 | Inventory
| At 31 Dec | ||
|---|---|---|
| USD million | 2025 | 2024 |
| Drilling equipment, spare parts and consumables | 125.1 | 94.3 |
| Provision for obsolete inventory | -19.4 | -19.4 |
| Total inventory | 105.7 | 74.8 |
Book value of inventory as of the reporting date relates to Kurdistan (USD 54.3 million) and the North Sea (USD 51.4 million).
Note 9 | Other non-current receivables/ Trade Receivables
| At 31 Dec | ||
|---|---|---|
| USD million | 2025 | 2024 |
| Trade debtors (non-current portion) | 120.0 | 98.2 |
| Total other non-current receivables | 120.0 | 98.2 |
| Trade debtors | 151.2 | 185.0 |
| Tax indemnity receivable (Note 6) | 128.8 | - |
| Underlift | 35.9 | 7.1 |
| Other short-term receivables | 253.6 | 146.1 |
| Total trade and other receivables | 569.6 | 338.1 |
As of 31 December 2025, the Company was owed a total of USD 291.5 million, excluding any 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 fourth quarter of 2025, 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 47.2 million reduction of the book value, an increase of USD 7.9 million from previous quarter. Moreover, the classification of the receivables (current/non-current portion) was updated accordingly.
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 Kurdistan and the North Sea, accrual for earned income not invoiced in the North Sea and tax indemnity receivable (see Note 6).
{18}------------------------------------------------
Note 10 | Hybrid capital
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 DNO's right to defer coupon payments indefinitely, only the net present value of the principal is classified as debt in the statement of financial position. The difference between the proceeds and the recognized liability is classified as equity, resulting in the majority of the principal amount being classified as equity.
| USD million | Equity | Liability | Total |
|---|---|---|---|
| Balance as of 31 December 2024 | - | - | - |
| Hybrid bond issue (17 June 2025) | 399.9 | 0.1 | 400.0 |
| Issue costs | -6.4 | - | -6.4 |
| Profit/loss allocated to hybrid bond owners | -21.5 | - | -21.5 |
| Accretion | - | - | - |
| Interest payment classified as dividend | 21.5 | - | 21.5 |
| Balance as of 31 December 2025 | 393.5 | 0.1 | 393.6 |
Note 11 | Interest-bearing liabilities
Interest-bearing liabilities
| Facility | At 31 Dec | |||||
|---|---|---|---|---|---|---|
| USD million | Ticker | currency | Interest | Maturity | 2025 | 2024 |
| Non-current | ||||||
| Bond loan (ISIN NO0011088593) | DNO04 | USD | 7.875 % | 09/09/26 | - | 350.0 |
| Bond loan (ISIN NO0013243766) | DNO05 | USD | 9.250 % | 04/06/29 | 400.0 | 400.0 |
| Bond loan (ISIN NO0013511113) | DNO06 | USD | 8.500 % | 27/03/30 | 600.0 | - |
| Hybrid bond (ISIN NO0013582627) liability portion (see Note 10) | DNO07 | USD | 10.750 % | 17/06/85 | 0.1 | - |
| Capitalized borrowing issue costs | -11.0 | -9.5 | ||||
| Reserve-based lending facility | USD | See below | See below | - | 50.0 | |
| Total non-current interest-bearing liabilities | 989.1 | 790.5 | ||||
| Current | ||||||
| Prepayment facility | - | Multiple | See below | See below | 339.4 | - |
| Total current interest-bearing liabilities | 339.4 | - | ||||
| Total interest-bearing liabilities | 1,328.5 | 790.5 |
{19}------------------------------------------------
Note 11 | Interest-bearing liabilities
Changes in liabilities arising from financing activities split on cash and non-cash changes
| At 1 Jan | Cash | Non-cash changes | At 31 Dec | ||||
|---|---|---|---|---|---|---|---|
| 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 | 10.1 | - | -0.1 | - | -11.0 |
| Reserve-based lending facility | 50.0 | -572.3 | - | 522.3 | - | - | - |
| Bridge loan | - | - | - | - | - | - | - |
| Prepayment facilities | - | -106.4 | - | 446.0 | -0.1 | - | 339.4 |
| Total | 790.5 | -440.2 | 10.1 | 968.3 | -0.2 | - | 1,328.5 |
| At 1 Jan | Cash | Non-cash changes | At 31 Dec | ||||
|---|---|---|---|---|---|---|---|
| USD million | 2024 | flows Amortization | Acquisition | Currency | Reclassification | 2024 | |
| Bond loans | 400.0 | 350.0 | - | - | - | - | 750.0 |
| Bond loans (current) | 131.2 | -131.2 | - | - | - | - | - |
| Borrowing issue costs | -8.0 | -5.6 | 4.1 | - | - | - | -9.5 |
| Reserve-based lending facility | - | 15.0 | - | - | - | 35.0 | 50.0 |
| Reserve-based lending facility (current) | 35.0 | - | - | - | - | -35.0 | - |
| Total | 558.2 | 228.2 | 4.1 | - | - | - | 790.5 |
On 14 March 2025, DNO ASA completed the placement of a USD 600 million, five-year senior unsecured bond issued at 100 percent at par with a coupon rate of 8.50 percent. Subsequently, on 10 April 2025, the Company completed the full redemption of the DNO04 bond, redeeming USD 350 million at a price of 102.3625 percent at par plus accrued interest. The financial covenants of the DNO05 and DNO06 bonds require a minimum of USD 40 million of liquidity, and that the Group maintains either an equity ratio of 30 percent or a total equity of a minimum of USD 600 million.
On 17 June 2025, DNO ASA completed the placement of USD 400 million of subordinated hybrid bonds with a coupon rate of 10.75 percent. Due to the instrument's long maturity and the issuer's option to defer interest payments and ultimately decide not to pay at maturity, the proceeds are mainly classified as equity. For more details, see Note 10.
During the second quarter of 2025, the Group fully repaid the outstanding amounts under its reserve-based lending (RBL) facilities related to its Norwegian and UK production licenses, including the RBL facility assumed through the acquisition of Sval Energi, totaling USD 602.3 million. At the same time, all letters of credit related to the Group's Norwegian and UK oil and gas operations were replaced by surety bonds.
On 25 June 2025, the Group entered into a USD 300 million one-year bridge loan with an interest rate of SOFR plus a margin of 4.00 percent. There were no amounts outstanding under the facility as of yearend 2025.
On 2 July 2025, DNO announced that the Norwegian operating subsidiaries entered into an offtake agreement with ENGIE SA for DNO's Norwegian gas production and secured a related offtake financing facility with a major U.S. bank for up to USD 500 million. The offtake agreement has a tenor of four years as 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 risk-free rate plus a margin and has no financial covenants.
On 18 December 2025, DNO announced that the Norwegian operating subsidiaries entered into two offtake agreements for DNO's North Sea oil production and secured related offtake financing facilities for up to USD 410 million. The agreement with ExxonMobil Asia Pacific Pte. Ltd., covering around half of DNO's North Sea oil output, has a tenor of two years and a related revolving credit facility of up to USD 185 million. The agreement with Shell International Trading and Shipping Company Limited, covering the other half of the output, has an initial tenor of one year and a related prepayment facility with a European bank of up to USD 225 million.
For additional information about the Group's interest-bearing liabilities, refer to the DNO ASA Annual Report and Accounts 2024.
{20}------------------------------------------------
Note 12 | Provisions and other liabilities
| At 31 Dec | ||
|---|---|---|
| USD million | 2025 | 2024 |
| Non-current | ||
| Asset retirement obligations (ARO) | 1,169.0 | 467.9 |
| Other long-term provisions and charges | 44.4 | 6.9 |
| Lease liabilities | 21.5 | 9.7 |
| Total non-current provisions and other liabilities | 1,234.9 | 484.5 |
| Current | ||
| Asset retirement obligations (ARO) | 77.0 | 12.9 |
| 10.1 | 14.2 | |
| Other provisions and charges | ||
| Current lease liabilities | 15.9 | 3.1 |
| Total current provisions and other liabilities | 103.1 | 30.2 |
Asset retirement obligations
The provisions for ARO are based on the present value of estimated future cost of decommissioning oil and gas assets in Kurdistan and the North Sea. 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, an FSO vessel and a rig lease linked to the non-operated Martin Linge oil and gas field. The FSO and rig leases were assumed as part of the Sval Energi acquisition and 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 the management's judgement, 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 31 Dec | ||
|---|---|---|
| USD million | 2025 | 2024 |
| Within one year | 15.8 | 4.0 |
| Two to five years | 14.5 | 8.7 |
| After five years | 3.4 | 3.2 |
| Total undiscounted lease liabilities end of the period | 33.7 | 15.9 |
The table above summarizes the Group's maturity profile of the lease liabilities based on contractual undiscounted payments.
{21}------------------------------------------------
Note 13 | Trade and other payables
| At 31 Dec | ||
|---|---|---|
| USD million | 2025 | 2024 |
| Trade payables | 61.0 | 84.5 |
| Public duties payable | 2.8 | 4.0 |
| Prepayments from customers | 4.8 | 4.7 |
| Overlift and other adjustments | 112.1 | 103.7 |
| Other accrued expenses | 281.4 | 126.8 |
| Total trade and other payables | 462.1 | 323.7 |
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 Kurdistan and the North Sea, 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 14 | Derivatives
| At 31 Dec | ||
|---|---|---|
| USD million | 2025 | 2024 |
| Commodity derivatives (current assets) | 11.5 | - |
| Commodity derivatives (current liabilities) | 5.6 | - |
| Net derivatives | 5.9 | - |
Through the acquisition of Sval Energi, DNO assumed a portfolio of commodity derivatives which are used to hedge the Group's exposure to gas price fluctuations. The derivative portfolio is revalued on a mark to market basis, with changes in value recognized in the income statement. All derivatives are measured at fair value on a recurring basis (level 2 in the fair value hierarchy).
As of 31 December 2025, the Group had hedged approximately 40 percent of the post-tax gas price exposure in the North Sea structure for 2026. The hedging strategy involves the use of collar structures. The weighted average strike prices are USD 61 per boe for the purchased puts and USD 124 for the calls sold. The current commodity derivative liability is related to deferred hedging premiums.
{22}------------------------------------------------
Note 15 | Business combination
Sval Energi acquisition
On 7 March 2025, DNO ASA entered into an agreement to acquire 100 percent of the shares of Sval Energi Group AS (Sval Energi) from HitecVision funds for a cash consideration of USD 450.0 million, based on an enterprise value of USD 1.6 billion. The effective date of the transaction was 1 January 2025, and the transaction was completed in June 2025. The Company has designated 31 May 2025 as the acquisition date for accounting purposes.
The transaction is regarded as a business combination and is accounted for using the acquisition method in accordance with IFRS 3. A purchase price allocation (PPA) has been performed to allocate the consideration to the fair value of assets acquired and liabilities assumed.
The announced cash consideration of USD 450.0 million was adjusted in accordance with the share purchase agreement at completion, resulting in a final cash consideration of USD 462.4 million. The amount shown under investing activities in the consolidated cash flow statement is net of a deposit of USD 22.5 million paid during the first quarter of 2025 and USD 259.0 million of cash that Sval Energi brought into the Group at the accounting acquisition date. No contingent consideration is payable.
The goodwill recognized relates to:
- Technical goodwill, which arises from the requirement to recognize deferred tax on the difference between the assigned fair value and the tax base of assets acquired and liabilities assumed. In Norway, licenses under development and licenses in production can only be sold on an after-tax basis, in line with requirements from the Norwegian Ministry of Finance pursuant to the Petroleum Taxation Act. As a result, the fair value of such licenses is determined based on after-tax cash flows. Nevertheless, in accordance with IAS 12, a deferred tax liability is recognized for the difference between the fair value and the tax base, measured using the applicable tax rate. The corresponding offsetting entry is recognized as goodwill.
- Residual goodwill, which is the portion of the consideration that cannot be allocated to identifiable assets or liabilities. It reflects the value of expected synergies that can be realized from managing a larger portfolio on the Norwegian Continental Shelf, including benefits from scale and the existing workforce.
None of the goodwill recognized will be deductible for tax purposes. Transaction costs of USD 6.7 million were incurred and expensed as administrative expenses in the consolidated statement of comprehensive income.
Since the acquisition date, DNO has included in its consolidated statement of comprehensive income a revenue of USD 733.0 million and a net loss of USD 20.9 million. If the acquisition had completed on 1 January 2025, DNO's consolidated statement of comprehensive income would have included USD 722.3 million in additional revenue and USD 19.1 million of additional net profit.
| Fair value at | |
|---|---|
| USD million | acquisition-date |
| Goodwill | 1,335.3 |
| Other intangible assets | 16.2 |
| Property, plant & equipment | 1,510.6 |
| Other non-current receivables | 8.2 |
| Other non-current assets | 4.5 |
| Inventories | 36.1 |
| Trade and other receivables | 380.9 |
| Derivatives | 14.5 |
| Cash and cash equivalents | 259.0 |
| Total assets | 3,565.4 |
| Deferred tax liabilities | 546.6 |
| Interest-bearing liabilities | 968.3 |
| Non-current provisions and other liabilities | 697.3 |
| Trade and other payables | 143.1 |
| Income taxes payable | 624.0 |
| Derivatives | 13.3 |
| Current provisions and other liabilities | 110.5 |
| Total liabilities | 3,103.0 |
| Net assets and liabilities recognized | 462.4 |
| Fair value of consideration paid on acquisition | 462.4 |
The above PPA is preliminary and reflects the information currently available regarding the fair values as of the acquisition date. In accordance with IFRS 3, the Company may revise the fair value assessments within twelve months of the acquisition date should new information emerge that affects the initial estimates. The PPA reported in the previous quarters has been updated to reflect new information that existed as of the acquisition date related to decommission security payments. As a result, other non-current liabilities and goodwill increased by USD 34.7 million.
{23}------------------------------------------------
Note 15 | Business combination
Multi-asset swap with Aker BP
On 5 November 2025, DNO ASA announced that it had entered into an agreement to execute a multi-asset swap with Aker BP ASA. As a result, DNO's stake in the Verdande field increased from 10.5 to 14 percent. In exchange, the Company transferred its entire stake in the Vilje field (28.9 percent) and a 9 percent interest in the Kveikje discovery, as well as reducing its interests in PL1171 Sunndal (from 50 to 34 percent), PL1175 Reka (from 30 to 20 percent), and PL1204 Abel (from 60 to 40 percent). The transaction was completed on 29 December 2025, which was also the acquisition date for accounting purposes. 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 | 12.9 |
| Deferred tax assets | 0.6 |
| Producing asset | 20.6 |
| Tax receivable | 11.2 |
| Other current assets | 3.5 |
| Total assets | 48.8 |
| Deferred tax liability | 15.1 |
| Asset retirement obligation | 1.7 |
| Other current liabilities | 1.9 |
| Total liabilities | 18.6 |
| Net assets and liabilities recognized | 30.2 |
| Fair value of consideration paid on acquisition | 30.2 |
| The gain on the disposal, representing the difference between the proceeds and the carrying amount, has been recognized in the profit/loss statement. | |
| Net asset derecognized | -1.2 |
| Consideration received | 9.8 |
| Gain | 11.0 |
{24}------------------------------------------------
Note 15 | Business combination
Transactions with Orlen
On 18 November 2025, DNO ASA announced the divestment of its 7.604 percent stake in the Ekofisk Previously Produced Fields (PPF) project in license PL018B and PL018F on the Norwegian Continental Shelf to Orlen Upstream Norway AS. DNO also announced the acquisition from Orlen of a 20 percent interest in license PL1135, which contains the Cassio prospect, as well as a 0.8272 percent interest in the Verdande field. DNO retained its 7.604 percent in PL018 containing the producing fields Ekofisk, Eldfisk and Embla as well as a share in the Tor Unit. The transaction was completed on 19 December 2025, which was also the acquisition date for accounting purposes, and was settled in cash. The recognized goodwill relates primarily to technical goodwill. No contingent consideration is payable or receivable, and transaction costs were negligible.
| USD million Goodwill Deferred tax assets Producing asset Exploration asset Tax receivable |
Fair value at acquisition-date 6.3 0.3 4.9 |
|---|---|
| 4.0 | |
| 2.7 | |
| Other current assets | 0.4 |
| Total assets | 18.6 |
| Deferred tax liability | 6.7 |
| Asset retirement obligation | 0.4 |
| Other current liabilities | 0.6 |
| Total liabilities | 7.7 |
| Net assets and liabilities recognized | 10.9 |
| Fair value of consideration paid on acquisition | 10.9 |
{25}------------------------------------------------
Note 16 | Earnings per share
| Quarters | Full-Year | |||
|---|---|---|---|---|
| Q4 2025 | Q4 2024 | 2025 | 2024 | |
| Net profit/loss attributable to equity holders of the parent (USD million) | -34.1 | -98.4 | -25.2 | -27.1 |
| EPS adjustment for calculated interest/dividend on hybrid capital (USD million) | -10.8 | - | -23.1 | - |
| Number of shares (millions) | 975.00 | 975.00 | 975.00 | 975.00 |
| Earnings per share, basic and diluted (USD) | -0.05 | -0.10 | -0.05 | -0.03 |
Note 17 | Subsequent events after the reporting date
DNO receives 17 awards in Norway's APA licensing round
On 13 January 2026, the Company announced that its wholly-owned subsidiary DNO Norge AS has been awarded participation in 17 exploration licenses of which four are operatorships, under Norway's APA 2025 licensing round. Of the 17 new licenses, 15 are in the North Sea and two in the Norwegian Sea.
{26}------------------------------------------------
Alternative performance measures
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 Full-Year |
||||
|---|---|---|---|---|
| USD million | Q4 2025 | Q4 2024 | 2025 | 2024 |
| Revenues | 481.6 | 176.6 | 1,474.0 | 666.8 |
| Lifting costs | -127.0 | -54.5 | -376.4 | -175.5 |
| Tariff and transportation | -65.9 | -18.8 | -181.5 | -49.4 |
| Movement in overlift/underlift | 45.5 | 3.6 | 86.0 | 2.1 |
| Share of profit/loss from Joint Venture | 7.1 | -0.3 | 7.7 | 3.3 |
| Exploration expenses | -74.4 | -29.0 | -136.5 | -88.9 |
| Administrative expenses | -14.4 | -5.5 | -48.6 | -23.5 |
| Other operating income/expenses | 1.4 | -0.7 | 18.8 | -1.6 |
| EBITDA | 254.0 | 71.4 | 843.6 | 333.3 |
| EBITDAX | ||||
| USD million | Q4 2025 | Q4 2024 | 2025 | 2024 |
| EBITDA | 254.0 | 71.4 | 843.6 | 333.3 |
| Exploration expenses | 74.4 | 29.0 | 136.5 | 88.9 |
| EBITDAX | 328.4 | 100.4 | 980.0 | 422.2 |
| Lifting costs | Q4 2025 | Q4 2024 | 2025 | 2024 |
| Lifting costs (USD million) | -127.0 | -54.5 | -376.4 | -175.5 |
| Net production (MMboe)* | 13.5 | 6.9 | 39.2 | 27.1 |
| Lifting costs (USD/boe) | 9.4 | 7.9 | 9.6 | 6.5 |
| * For accounting purposes, the net production from equity accounted investments is excluded. | ||||
| Capital expenditures | Q4 2025 | Q4 2024 | 2025 | 2024 |
| Purchases of intangible assets | -43.1 | -34.3 | -130.3 | -87.2 |
| Purchases of tangible assets* | -130.4 | -62.5 | -487.7 | -199.8 |
| Capital expenditures | -173.5 | -96.8 | -618.0 | -287.0 |
* Excludes estimate changes on asset retirement obligations.
{27}------------------------------------------------
Alternative performance measures
Operational spend
| Quarters | Full-Year | ||||
|---|---|---|---|---|---|
| USD million | Q4 2025 | Q4 2024 | 2025 | 2024 | |
| Lifting costs | -127.0 | -54.5 | -376.4 | -175.5 | |
| Tariff and transportation expenses | -65.9 | -18.8 | -181.5 | -49.4 | |
| Exploration expenses | -74.4 | -29.0 | -136.5 | -88.9 | |
| Exploration cost previously capitalized carried to cost (Note 4) | 48.3 | 12.8 | 62.8 | 37.7 | |
| Purchases of intangible assets | -43.1 | -34.3 | -130.3 | -87.2 | |
| Purchases of tangible assets | -130.4 | -62.5 | -487.7 | -199.8 | |
| Payments for decommissioning | -19.8 | -0.9 | -33.2 | -4.9 | |
| Operational spend | -412.3 | -187.2 | -1,282.8 | -568.0 | |
| Free cash flow | |||||
| USD million | Q4 2025 | Q4 2024 | 2025 | 2024 | |
| Net cash from/used in operating activities | 148.1 | 79.0 | 589.8 | 413.0 | |
| Capital expenditures | -173.5 | -96.8 | -618.0 | -287.0 | |
| Payments from license transactions | 7.4 | -0.3 | 7.4 | -84.8 | |
| Payments for decommissioning | -19.8 | -0.9 | -33.2 | -4.9 | |
| Equity contribution into Joint Venture | -1.3 | -1.1 | -10.5 | -9.4 | |
| Dividends from Joint Venture | 7.4 | 14.5 | 27.2 | 31.8 | |
| Free cash flow | -31.7 | -5.4 | -37.4 | 58.8 | |
| Equity | |||||
| USD | 2025 | 2024 | |||
| Equity | 1,328.5 | 1,080.0 | |||
| Total assets | 5,998.3 | 2,966.1 | |||
| Equity ratio | 22.1% | 36.4% | |||
| Net debt | |||||
| USD million | 2025 | 2024 | |||
| Cash and cash equivalents (including restricted cash) | 453.7 | 899.0 | |||
| Interest-bearing liabilities (Note 11) | 1,339.5 | 800.0 | |||
| Net cash/debt | -885.9 | 99.0 |
{28}------------------------------------------------
Alternative performance measures
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 and impairment of oil and gas assets 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 of 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. It does not include expenditures related to the acquisition of subsidiaries. Management believes that this measure is useful because it provides an overview of capital investments used in the relevant period.
Operational spend
Operational spend is comprised of lifting costs, tariff and transportation expenses, exploration expenses, capital expenditures and payments for decommissioning. It does not include expenditures related to the acquisition of subsidiaries. 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
The equity ratio is calculated by dividing total equity by the total assets. Management uses total equity and equity ratio to monitor capital and financial covenants.
Free cash flow
Free cash flow comprises net cash from/used in operating activities less capital expenditures, payments from license transactions, payments for decommissioning and net cash received/paid from equity accounted investments. It does not include expenditures related to the acquisition of subsidiaries. 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 facility. Management believes that net cash/debt is a useful measure because it provides indication of the minimum necessary debt financing (if the figure is negative) to which the Group is subject at the reporting date.
{29}------------------------------------------------
NOTES
{30}------------------------------------------------
{31}------------------------------------------------