Interim report
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BlueNord ASA Third Quarter Report 2026
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Third Quarter Report 2026 1 Highlights of the Quarter Compared to second quarter 2026 Total Revenue EBITDA $346m $220m 25% 50% Cash flow from operating activities before tax Total liquidity (cash and undrawn facilities) $142m $392m -44% -28% “Our shareholders approved the merger with Vår Energi in August, and BlueNord is now approaching the end of its journey as an independent company. We can look back on it with real satisfaction. Since we acquired our interest in the DUC in 2019, Tyra has been redeveloped and brought back into production, and we have returned substantial cash to our shareholders. Our success as a standalone company provides a strong foundation for BlueNord’s next chapter. As part of V år Energi, we believe our shareholders will benefit from greater scale and diversification while continuing our shared commitment to maximising operational performance and delivering long-term returns. The combination offers an opportunity to build on what both companies have achieved independently, and we are working through the remaining steps to completion. We expect the merger to close around the end of the year. This quarter Tyra delivered a step change in performance. Following the planned maintenance campaign in June we saw record production days close to 30 mboepd and gas export at maximum capacity. Until completion our focus is unchanged: running the business well and working to complete the transaction. Finally, I want to thank everyone at BlueNord for what they have delivered, and our shareholders for their support.” Euan Shirlaw, Chief Executive Officer
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Third Quarter Report 2026 2 Contents 01 Summary of the Quarter 4 Financial Review 5 Operational Review 8 02 Condensed Consolidated Statement of Comprehensive Income 12 Condensed Consolidated Statement of Financial Position 13 Condensed Consolidated Statement of Changes in Equity 14 Condensed Consolidated Statement of Cash Flows 15 03 Notes 16 Note 1: Accounting principles 17 Note 2: Income 18 Note 3: Production expenses 19 Note 4: Financial income and expenses 20 Note 5: Tax 21 Note 6: Earnings per share 24 Note 7: Intangible assets 25 Note 8: Property, plant and equipment 26 Note 9: Trade receivables and other current assets 27 Note 10: Inventories 27 Note 11: Restricted bank accounts, cash and cash equivalents 27 Note 12: Hybrid capital 28 Note 13: Borrowings 29 Note 14: Trade payables and other current liabilities 30 Note 15: Financial instruments 31 Note 16: Asset retirement obligations 34 Note 17: Subsequent events 34 04 Alternative performance measures 36 Appendix 38 Information about BlueNord 39
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Third Quarter Report 2026 3 Introduction 01
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Third Quarter Report 2026 4 Third Quarter 2026 Summary Transaction summary: • On 21 July, Vår Energi ASA and BlueNord ASA announced a proposed statutory merger of which Vår Energi’s 100% owned subsidiary is the surviving entity, making Vår Energi the largest independent producer of oil and gas in Europe. • On 24 August, shareholders approved the proposed transaction and merger plan at the Extraordinary General Meeting. • Closing of the transaction is still expected around the year end-2026, subject to several conditions’ precedent including regulatory and governmental approvals as outlined in the merger plan. • BlueNord shareholders will receive 9.7153 newly issued Vår Energi shares and NOK 76.83 in cash per share. • BlueNord may not declare and distribute any further dividends prior to the Effective Date. BlueNord shareholders will be compensated for Vår Energi dividends declared before merger completion, in accordance with the merger plan. Production in line with guidance as Tyra delivers step change performance • Total production of 43.6 mboepd net in the third quarter, in line with guidance. • The Tyra hub delivered a step change in stability and gas capacity following the planned June maintenance campaign, with record production days close to 30 mboepd net and gas export rates above 250 mmscfpd in line with maximum gas export capacity. Base assets remained within guidance despite temporary integrity -related issues at the Dan and Gorm hubs, supported by strong performance from the Halfdan and Gorm hubs. • The Operator continues to focus on sustaining the improved performance at the Tyra hub and delivering stable production from the base assets through well and reservoir optimisation activities. Strong financial position: • Total revenues of USD 346.0 million in the third quarter, up from USD 276.8 million in the previous quarter. Primarily driven by higher oil and gas sales volumes and increased effective commodity prices. • EBITDA of USD 219.6 million in the third quarter compared to USD 146.8 million in the previous quarter. • Overall loss year to date is driven by non-cash unrealised position on derivatives. • Cash flow from operating activities before tax was USD 141.5 million and net cash flow from operating activities was USD 69.7 million compared to USD 250.6 million and USD 249.2 million in the prior quarter. Decrease driven by working capital effects. Higher tax paid in the third quarter is a timing effect with a tax receivable to partly offset in the fourth quarter. • Available liquidity of USD 392.3 million with cash of USD 131.3 million and undrawn RBL capacity of USD 261.0 million. • Listing of BNOR18 on Oslo Stock Exchange. Financial and operational summary Unit Q3 2026 Q2 2026 Restated Q3 20252 YTD 2026 Restated YTD 20252 Total revenue USDm 346.0 276.8 251.4 940.5 760.1 EBITDA1 USDm 219.6 146.8 131.0 567.6 343.8 Adj. EBITDA1 USDm 221.2 148.4 137.4 572.5 375.7 Result before tax USDm (24.9) 62.2 22.1 35.4 27.6 Net result for the period USDm (19.7) 19.1 12.9 (10.0) 50.2 Cash flow from operating activities before tax1 USDm 141.5 250.6 128.8 548.9 269.9 Net Cash flow from operating activities1 USDm 69.7 249.2 127.8 459.8 252.2 Investments in oil and gas assets USDm 9.9 11.0 7.3 18.6 35.9 Net interest-bearing debt1 USDm 1,068.7 915.3 1,003.0 1,068.7 1,003.0 Oil production mboepd 22.7 21.1 22.5 22.7 21.3 Gas production mboepd 20.9 16.0 16.6 18.6 14.3 Total production3 mboepd 43.6 37.2 39.1 41.3 35.6 Realised Oil price USD/boe 96.8 101.3 70.9 94.3 71.7 +/- Effect of hedges USD/boe (15.4) (21.5) 3.1 (14.3) 1.8 Effective Oil price USD/boe 81.3 79.8 74.0 80.0 73.4 Realised Gas price EUR/MWh 61.8 43.8 30.7 49.0 37.1 +/- Effect of hedges and penalties EUR/MWh (18.8) (5.4) 4.6 (9.0) 2.0 Effective Gas price EUR/MWh 43.0 38.4 35.3 40.0 39.1 1) See the description of ‘Alternative performance measures’ at the end of this report for definitions. 2) Total revenue restated as penalties and gas purchases are moved to Production expenses, see note 2 in Q4 2025 report for more information. 3) Q2 production volumes reflect actuals, while financial reporting used estimated June 2026 volumes. The difference is immateri al.
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Financial review continued Third Quarter Report 2026 5 Financial Review Selected data from consolidated statement of comprehensive income USD million Q3 2026 Q2 2026 Restated Q3 20251 YTD 2026 Restated YTD 20251 Total revenue 346.0 276.8 251.4 940.5 760.1 EBITDA 219.6 146.8 131.0 567.6 343.8 EBIT 133.9 79.1 68.1 335.3 172.0 Result before tax (24.9) 62.2 22.1 35.4 27.6 Net result for the period (19.7) 19.1 12.9 (10.0) 50.2 Earnings per share (1.1) 0.4 0.2 (1.4) 1.6 1) Total revenue restated as penalties and gas purchases are moved to Production expenses, see note 2 in Q4 2025 report for more information. Total r evenues of USD 346.0 million in the third quarter , mainly from oil and gas sales from the Danish Underground Consortium (DUC) fields. Revenue increased from USD 276.8 million in the previous quarter, mainly reflecting higher oil and gas volumes following planned shutdowns in the prior quarter , as well as higher effective commodity prices. Oil liftings increased by 11.4% and gas sales volumes increased by 26.4% compared to prior quarter. Effective oil price increased by 2.0% and effective gas price increased by 12.6%. Production expenses directly attributable to the lifting and transport of the Company’s oil and gas production amounted to USD 92.1 million in the third quarter, equating to USD 22.9 per boe. This compares with USD 99.3 million, or USD 29.3 per boe, in the previous quarter. The reduction was primarily driven by lower maintenance work and higher production volumes following the planned shutdowns in the prior quarter. Lifting cost decreased to USD 16.0 per boe from USD 20.3 per boe in the previous quarter, reflecting the combined effect of lower maintenance costs and higher production volumes. Adjusted for gas purchases and fees, penalties, concept studies, insurance and changes in stock and oil inventory, total production expenses amounted to USD 107.9 million compared to USD 116.6 million in the previous quarter. Operating result before depreciation, amortisation and impairment (EBITDA) in the third quarter was a profit of USD 219.6 million, compared to USD 146.8 million in previous quarter. The increase was driven by higher revenues and lower production expenses. Net financial items amounted to an expense of USD 158.9 million for the third quarter, compared to an expense of USD 16.9 million in the previous quarter. The current quarter was mainly impacted by a USD 104.3 million non -cash unrealised loss on derivatives (primarily swaptions) whereas the second quarter included a USD 61.5 million non-cash unrealised gain on derivatives. Significant mark -to-market movements continue d during the quarter, reflecting ongoing volatility in commodity markets. Mark-to-market movements on derivatives that do not qualify for hedge accounting are recognised in net financial items. Income tax amounted to a net income of USD 5.2 million in the third quarter, compared to a net expense of USD 43.1 million in the previous quarter . The change is primarily due to the underlying operating result, offset by additional currency adjustment on the value of tax losses carried forward in DKK. The currency adjustment amounted to USD 9.5 million in the current quarter, compared to USD (1.2) million in previous quarter. In accordance with IFRS, tax loss carried forward are remeasured using the period -end exchange rate. Current income tax amounted to an expense of USD 4.4 million, while deferred tax movements resulted in an income of USD 9.6 million. This corresponds to a statutory tax rate of 64% on result before tax from hydrocarbon activities, adjusted for investment uplift, interest restriction and currency adjustment on tax losses carried forward in DKK. The effective tax rate was 0% on result before tax in Norway and UK and 22% tax on result before tax on ordinary income in Denmark. Net result for the third quarter was a loss of USD 19.7 million, compared to a profit of USD 19.1 million in the previous quarter.
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Financial review continued Third Quarter Report 2026 6 Selected data from the consolidated statement of financial position USD million 30.09.2026 30.06.2026 31.12.2025 30.09.2025 Total non-current assets 3,136.7 2,935.7 2,955.4 2,813.7 Total current assets 375.5 371.7 398.9 415.0 Total assets 3,512.2 3,307.4 3,354.3 3,228.7 Total equity 97.9 467.2 767.9 784.4 Interest bearing debt 1,157.6 1,073.3 1,068.9 1,159.0 Asset retirement obligations (current and non-current) 1,385.9 1,374.3 1,349.3 1,167.5 Derivative Instruments, liabilities 669.1 154.4 2.0 4.7 Total current liabilities (excluding current asset retirement obligations) 651.3 329.6 166.5 114.4 Total non-current assets amounted to USD 3,136.7 million at the end of the third quarter, compared to USD 2,935.7 million in the previous quarter . The increase was primarily driven by a higher deferred tax asset mainly due to increase of losses carried forward at 64%. The loss is due to unrealised mark-to-market loss on oil and gas hedges. Partly offset by a decrease in fair value of derivative instruments reflecting unfavourable mark-to-market changes in oil and gas commodity hedges. Total non -current assets consist of property, plant and equipment USD 2.3 billio n, intangible assets USD 127.5 million, deferred tax asset USD 593.0 million, derivatives mainly related to oil and gas hedges and EUA swaptions USD 2.8 million and USD 67.3 million in restricted cash related to security for the Nini/Cecilie abandonment costs. Total current assets amounted to USD 375.5 million at the end of the third quarter, compared to USD 371.7 million at the end of the previous quarter. The increase primarily reflects increased trade receivables, partly offset by a lower cash balance and fair value of derivative instruments reflecting mark-to-market changes on oil and gas commodity hedges. Total current assets consist of USD 131.3 million cash, USD 64.2 million stock and oil inventory, USD 169.6 million trade receivables, mainly related to oil and gas revenue, USD 0.2 million derivatives related to oil and gas hedges, USD 9.4 million prepayments mainly related to insurance and USD 0.7 million other receivables. Total equity amounted to USD 97.9 million at the end of the third quarter, compared to USD 467.2 million at the end of the previous quarter . The decrease was mainly due to negative fair value adjustments on hedges recognised in other comprehensive income, a USD 174 million dividend payment, semi-annual preference dividends of USD 18 million to hybrid bond owners, in addition to a negative net result. Interest-bearing debt amounted to USD 1,157.6 million at the end of the third quarter, compared to USD 1,073.3 million at the end of the previous quarter. BlueNord’s USD 1.4 billion RBL facility was drawn at USD 800.0 million as of 30 September 2026, with a book value of USD 755.5 million, following a net drawdown of USD 75 million during the quarter. The USD 400 million senior unsecured bond loan BNOR18 had a book value of USD 402.1 million at the end of the period. Asset retirement obligations (current and non-current) amounted to USD 1,385.9 million at the end of the third quarter, compared to USD 1,374.3 million at the end of the previous quarter. The increase is primarily due to accretion expense for the period. Of the total liability, USD 1,314.2 million relates to the DUC assets. Total current liabilities (excluding current asset retirement obligation) amounted to USD 651.3 million at the end of third quarter, compared to USD 329.6 million in the previous quarter. The increase is mainly driven by higher derivatives reflecting changes in fair value during the quarter as well as higher other payables due to realised hedges payable to banks. This was partly offset by a decrease in taxes payable mainly due to expected payments made for prior years. Total current liabilities consist of USD 451.0 million current derivatives related to oil and gas price hedges, USD 54.9 million taxes payable, and USD 145.5 million trade payables and other current liabilities.
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Financial review continued Third Quarter Report 2026 7 Selected data from the consolidated statement of cash flows USD million Q3 2026 Q2 2026 Q3 2025 YTD 2026 YTD 2025 Cash flow from operating activities before tax 141.5 250.6 128.8 548.9 269.9 Net cash flow from operating activities 69.7 249.2 127.8 459.8 252.2 Cash flow used in investing activities (10.4) (11.4) (10.6) (19.9) 117.8 Cash flow from financing activities (137.7) (137.7) (368.5) (451.3) (423.6) Net change in cash and cash equivalents (78.3) 100.1 (251.3) (11.4) (53.6) Cash and cash equivalents 131.3 209.7 197.0 131.3 197.0 Net cash flow from operating activities amounted to USD 69.7 million for the third quarter, compared to USD 249.2 million for the previous quarter. Operating cash flow decreased, primarily driven by a working capital increase in trade receivables and the timing effect of cash receipts compared to earnings . Further the third quarter included tax payments of USD 71.8 million, where USD 69 million were made pertaining to the 2019- and 2020-income revisions. This will be partly offset by tax receivables due in a future quarter. Working capital movements had a negative impact of USD 70.8 million during the quarter, compared with a positive impact of USD 109.8 million in the previous quarter. This reflects higher trade receivables related to oil and gas sales. Partly offset by higher other current liabilities, over-lift and trade payables. Excluding changes in working capital, net cash flow from operating activities was a cash inflow of USD 140.5 million for the third quarter, compared to a cash inflow of USD 139.4 million in the previous quarter. Cash flow used in investing activities resulted in an outflow of USD 10.4 million for the quarter, compared to an outflow of USD 11.4 million for the previous quarter. The outflow in the current quarter was primarily due to capital expenditures of USD 2.2 million for the Gorm lifetime extension project, USD 3.2 million on minor projects on Tyra and USD 4.4 million to minor projects on Dan and Halfdan. Cash flow from financing activities amounted to an outflow of USD 137.7 million in the third quarter of 2026, compared to an outflow of USD 137.7 million in the previous quarter. Cash outflows comprised primarily USD 174.0 million cash dividends, semi-annual preference dividend of USD 18 million to hybrid bond holders and USD 20.5 million in interest and fees. In addition, a net USD 75 million drawdown was done under the RBL, resulting in a net increase in borrowings of USD 75 million. Net change in cash and cash equivalents amounted to negative USD 78.3 million at the end of the quarter compared to positive USD 100.1 million for the previous quarter. Cash and cash equivalents were in total USD 131.3 million at the end of third quarter 2026. Financial Risk Mitigation The Company actively seeks to reduce exposure to the risk of fluctuating commodity prices, in addition to interest rate and foreign exchange risk as required, through the establishment of hedging arrangements. To achieve this, BlueNord has executed a hedging policy in the market and entered into forward contracts. More details on BlueNord’s hedging policy can be found in note 1 9.4 and f urther detail on BlueNord’s financial risk management is outlined in note 2 to the financial statements in the 2025 Annual Report which is available at www.bluenord.com/reports-and-presentations/. The table below summarises the quantity of volume hedged and average hedged price at the end of the third quarter. Volume hedged oil (boe) Average hedged price ($/bbl)1 Volume hedged gas (MWh) Average hedged price (EUR/MWh)1 2026 2,070,000 80.6 3,285,000 47.1 2027 5,100,000 73.1 8,272,500 33.6 2028 3,300,000 73.2 2,955,000 30.3 1) Based on forward curve as at 30 September 2026.
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Operational review continued Third Quarter Report 2026 8 Operational Review Production Key figures Unit Q3 2026 Q2 20261 Q3 2025 YTD 2026 YTD 2025 Dan hub mboepd 5.1 5.4 6.2 5.6 6.3 Gorm hub mboepd 4.1 3.1 3.4 3.8 3.6 Halfdan hub mboepd 8.4 9.4 10.6 9.1 10.8 Tyra hub mboepd 26.0 19.3 18.9 22.8 14.9 Total production mboepd 43.6 37.2 39.1 41.3 35.6 Over/(under)-lift mboepd 1.0 0.4 -2.3 0.9 -1.1 Net sales mboepd 44.6 37.6 36.8 42.2 34.5 Oil sales mboepd 23.7 21.5 20.6 23.6 20.2 Gas sales mboepd 20.9 16.0 16.1 18.6 14.3 Operational efficiency2 % 86.1 % 77.8 % 71.5 % 82.8 % 69.7 % Note: The subtotals and totals in the table may not equal the sum of the amounts shown due to rounding. 1) Production volumes are updated with actual volumes which do not correspond to the estimated volumes for June 2026 used in the financial reporting. There is no material difference for financial reporting purposes for the quarter. 2) Operational efficiency is calculated as: delivered production / (delivered production + planned shortfalls + unplanned shortfalls). Average production in Q3 2026 was 43.6 mboepd of which 26.0 mboepd was from the Tyra hub and 17.6 mboepd was from the base assets (Dan, Gorm and Halfdan hubs). At the Tyra hub, the quarter was characterised by significantly increased production levels and improved facility stability following the planned maintenance campaign successfully completed in June. Base assets production was characterised by strong performance from the Halfdan and Gorm hubs. Production was strong despite temporary integrity -related issues at the Dan and Gorm hubs. Production from the Halfdan hub was lower than in Q2 due to the planned maintenance shutdown of the Halfdan A platform during the quarter. Dan hub: production was impacted by the Kraka field being shut in for a period ending in August due to replacement of the production manifold following an external leak. During September, production was temporarily affected by integrity-related issues on the Dan an d Kraka fields, including leaks on production flowlines and connections. The required repairs were completed and production returned towards expected levels by the end of the quarter. Gorm hub production was affected during July by lift gas constraints associated with compressor maintenance activities. Following completion of the maintenance campaign, production returned to expected levels and remained stable for the rest of the quarter. Product ion from the Rolf field has been shut in since August due to a riser integrity issue, resulting in production losses of approximately 0.3 mboepd net. A repair plan is under evaluation, with Rolf production expected to be resumed before the end of 2026. On the Gorm field, the platform based WROM campaign is ongoing with successful completion of three out of six planned well interventions. Associated production gains are still to be confirmed. Halfdan hub production remained stable throughout the quarter with high operational efficiency. Planned maintenance of the Halfdan A platform was carried out between late July and late August, resulting in temporary production reductions. Production returned to full r ates following completion of the maintenance campaign and operational efficiency exceeded 95% during September. Tyra hub daily production levels and production stability increased significantly following the planned maintenance campaign completed in June. The improvement reflects technical measures implemented during the campaign, including replacement of the choke and rerouting of production from the HEMJ well at the Harald platform, which increased available production potential. The quarter also demonstrated a step change in gas production, with maximum gross gas export rates increasing from approximately 215 mmscfpd befor e the maintenance campaign to more than 250 mmscfpd following completion of the work, in line with the maximum export capacity of the IP compressor. During the quarter, Tyra achieved several record production days, reaching close to 30 mboepd net to BlueNord, and sustained production above 29 mboepd during extended periods. Production was periodically affected by operational activities and temporary production upsets,
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Operational review continued Third Quarter Report 2026 9 including the planned pigging of the Harald -Tyra pipeline in September, slugging, oil -in-water constraints and well -related issues. However, production recovered following each event and underlying production performance remained strong throughout the quarter. Health, Safety and the Environment BlueNord will conduct its business operation in full compliance with all applicable national legislation in the countries where it is operating. The Company is committed to carry out its activities in a responsible manner to protect people and the environment. Our fundamentals of HSEQ and safe business practice are an integral part of BlueNord’s operations and business performance. BlueNord puts emphasis on its employees performing company activities in line with the principles of business integrity and with respect for people and the environment. At BlueNord we work actively to reduce our carbon footprint while contributing to energy security. BlueNord is currently assessing further emissions reduction initiatives for its currently producing assets and for future activities. We monitor and validate environmental data, acting as an informed partner to the operator by providing robust oversight and constructive challenge. We are deepening our analysis to improve transparency on environmental performance and using these insights to embed environmental considerations more consistently into decision-making. CarbonCuts is a key element of our business. Under the EU’s Net -Zero Industry Act (NZIA), oil and gas producers are required to contribute to the EU -wide goal of achieving an annual CO₂ injection capacity of 50 Mt by 2030. Since 2024 CarbonCuts has been a wholly owned subsidiary of the BlueNord Group and currently the Ruby Project is the major focus of activities. In June 2024, CarbonCuts was awarded an exploration licence in Rødby. In early 2025 CarbonCuts conducted a 3D seismic survey covering 220 km2. Th is was followed by a re -entry in an old oil and gas exploration well from 1953. Activity remains ongoing for the exploration programme in 2026, including an exploration well in the process of drilling at the date of this report. Securing and sustaining public acceptance is of utmost importance and CarbonCuts continues to actively engage with stakeholders, including local communities, regulatory authorities and industry partners, seeking input and feedback to inform decisions and operations. For more information on the Company’s work, including the work of the ESG Committee, please see the Sustainability section page 26 - 49 and Audit Committee Report on page 61 in the 2025 Annual Report available on www.bluenord.com/reports-and-presentations/. Risks and uncertainties The material known risks and uncertainties faced by BlueNord are described in detail in the section headed ‘Risk Management Framework’ on page 16-23 of the 2025 Annual Report which is available at www.bluenord.com/reports-and- presentations/. These have not changed materially since publication. There are several risks and uncertainties that could have a material impact on BlueNord’s performance and financial position. Key headline risks relate to the following: • Oil and gas production and reserves • Market risks including, commodity prices, foreign currency exposure, interest rate risk, covenant compliance and available funding • Financial liabilities including future capital requirements and insurance risk • Cyber security • Third-party risk/non-operator • Politics, regulations and compliance • Climate risk Governance and organisation The number of employees was 5 7 (equivalent to 54.49 FTE’s) at the end of the third quarter , of which 22 employees are related to CarbonCuts.
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Operational review continued Third Quarter Report 2026 10 The governance of BlueNord ASA is described in detail in the section headed ‘Governance report’ on page 52 - 69 of the 2025 Annual Report which is available at www.bluenord.com/reports-and-presentations/. Outlook BlueNord enter ed 2026 with a significantly strengthened operational and financial platform. Price volatility has been considerable, prompting management to more regularly evaluate the market in order to manage fluctuations in commodity prices. The Company will continue to monitor global as well as local political and economic conditions that may affect future results. BlueNord remains well positioned going forward to navigate global events and potentially unforeseen challenges as well as any future oil- and gas price volatility through business and IT continuity plans, price hedging arrangements and pro- active steps taken by the operator of the DUC. Activity to progress value additive organic DUC investment projects also continues, and the company will seek to sanction projects when they are sufficiently matured. BlueNord ASA believes economic investments in these projects will help to replace produced reserves and provide strong financial returns benefitting the Company’s shareholders. Production The Operator continues to focus on maintaining stable and reliable production across the DUC assets. Following the planned maintenance campaign completed in June, the Tyra hub has demonstrated significantly improved production levels, higher facility stabi lity and increased gas handling capability at the Harald platform. A number of key focus areas have been identified for the remainder of 2026 and into 2027 to further enhance production performance and support sustained reliable operations. The operational experience gained during Q3 has demonstrated an improved ability to rapidly restore production following temporary interruptions. On the basis of steady state Tyra operations, the Company will no longer issue monthly production updates. Production from the base assets is expected to continue providing stable contributions. At the Gorm hub, platform -based well and reservoir optimisation management (WROM) activities are expected to continue throughout Q4, supporting production performance and recovery of additional reserves. The production guidance for the remainder of 2026 is shown below: Guidance 2026 Unit Base Tyra Total Q4 mboepd 18.0-20.0 24.0-29.0 42.0-49.0 Capital expenditure Capital expenditure for 2026 is expected to be in the range of USD 40-50 million. Looking ahead, for 2027 to 2030, capital expenditure is forecast to be in the range of USD 100-150 million per year, including maintenance and development capex.
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Third Quarter Report 2026 11 Financial Statements 02
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Third Quarter Report 2026 12 Condensed Consolidated Statement of Comprehensive Income USD million Note Q3 2026 Q2 2026 Restated Q3 20252 YTD 2026 Restated YTD 20252 Revenue 2 346.0 276.8 251.4 940.5 760.1 Total income 346.0 276.8 251.4 940.5 760.1 Production expenses 3 (107.9) (116.6) (108.5) (330.8) (379.8) Exploration and evaluation expenses (6.7) (3.8) (2.6) (13.3) (11.9) Personnel expenses (3.8) (4.1) (4.9) (10.7) (13.0) Other operating expenses (8.0) (5.6) (4.5) (17.9) (11.5) Total operating expenses (126.4) (130.1) (120.4) (372.8) (416.2) Operating result before depreciation, amortisation and impairment (EBITDA) 219.6 146.8 131.0 567.6 343.8 Depreciation/amortisation/impairment 7, 8 (85.7) (67.7) (62.9) (232.4) (171.8) Net operating result (EBIT) 133.9 79.1 68.1 335.3 172.0 Financial income 4 0.3 2.5 6.8 5.3 62.1 Financial expenses 4 (159.2) (19.4) (52.8) (305.1) (206.5) Net financial items (158.9) (16.9) (46.0) (299.8) (144.5) Result before tax (EBT) (24.9) 62.2 22.1 35.4 27.6 Income tax benefit/(expense) 5 5.2 (43.1) (9.1) (45.5) 22.6 Net result for the period1 (19.7) 19.1 12.9 (10.0) 50.2 Other comprehensive income: Items that are or may be subsequently reclassified to profit or loss: Realised cash flow hedge revenue 15 71.4 72.7 (11.2) 132.8 (16.9) Related tax - realised cash flow hedge 5, 15 (45.7) (46.5) 7.2 (85.0) 10.8 Changes in fair value cash flow hedge revenue 15 (506.3) 188.0 79.8 (782.0) 159.9 Changes in fair value cash flow hedge EUA 15 - - 1.7 - 1.8 Related tax - changes in fair value cash flow hedge 5, 15 324.1 (120.3) (52.1) 500.5 (103.5) Currency translation adjustment (1.2) 0.5 1.0 (2.0) 5.1 Total other comprehensive income/(loss) (157.8) 94.3 26.3 (235.8) 57.3 Total comprehensive income/(loss)1 (177.5) 113.4 39.2 (245.8) 107.4 Basic earnings/(loss) USD per share 1 6 (1.1) 0.4 0.2 (1.4) 1.6 Diluted earnings/(loss) USD per share 6 (1.1) 0.4 0.2 (1.4) 1.6 1) Each quarter in 2026, an amount of USD 9.0 million has been allocated to hybrid bond owners, reflecting the discretionary coupon for the period. In Q1 2026 nothing was allocated to hybrid bond owners, this was corrected in Q2 2026. Allocations to hybrid bondholders are determined on a period‑by‑period basis. For earnings per share purposes, the amount allocated to hybrid bondholders has been deducted from profit attributable to ordinary shareholders in accordance with IAS 33. See note 12 for further details. 2) Comparative total revenue and production expenses have been restated due to a reclassification of penalties and gas purchases, with no impact on net result. Further details are disclosed in Note 2 of the Group's Q4 2025 report.
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Third Quarter Report 2026 13 Condensed Consolidated Statement of Financial Position USD million Note 30.09.2026 30.06.2026 31.12.2025 30.09.2025 Non-current assets Intangible assets 7 127.5 130.3 135.5 138.2 Deferred tax assets 5 593.0 303.2 166.4 141.3 Property, plant and equipment 8 2,345.5 2,418.3 2,550.9 2,448.8 Right of use assets 0.6 1.2 1.5 1.7 Restricted bank deposits 11, 15 67.3 68.7 69.7 69.4 Derivative instruments 15 2.8 14.0 31.4 14.3 Total non-current assets 3,136.7 2,935.7 2,955.4 2,813.7 Current assets Derivative instruments 15 0.2 13.6 81.0 62.1 Trade receivables and other current assets 9 179.8 81.9 107.3 96.3 Inventories 10 64.2 66.5 67.8 58.8 Restricted cash and bank deposits 11, 15 - - 0.1 0.8 Cash and cash equivalents 11 131.3 209.7 142.7 197.0 Total current assets 375.5 371.7 398.9 415.0 Total assets 3,512.2 3,307.4 3,354.3 3,228.7 Equity Share capital 1.6 1.6 1.6 1.7 Other equity 12 96.4 465.6 766.3 782.7 Total equity 97.9 467.2 767.9 784.4 Non-current liabilities Asset retirement obligations 16 1,359.5 1,355.0 1,344.0 1,158.4 Bond loan 13, 15 402.1 394.4 305.5 297.8 Reserve-based lending facility 13, 15 755.5 678.8 763.5 861.2 Derivative instruments 15 218.1 61.1 0.1 1.5 Other non-current liabilities 1.3 1.8 1.7 1.9 Total non-current liabilities 2,736.6 2,491.2 2,414.7 2,320.8 Current liabilities Asset retirement obligations 16 26.4 19.3 5.3 9.1 Tax payable 5 54.9 120.4 71.8 31.9 Derivative instruments 15 451.0 93.3 1.9 3.2 Trade payables and other current liabilities 14 145.5 115.9 92.7 79.3 Total current liabilities 677.7 349.0 171.7 123.5 Total liabilities 3,414.3 2,840.2 2,586.4 2,444.3 Total equity and liabilities 3,512.2 3,307.4 3,354.3 3,228.7
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Third Quarter Report 2026 14 Condensed Consolidated Statement of Changes in Equity USD million Share capital Share premium fund Treasury share reserve Hybrid capital Currency translation reserve Cash flow hedge reserve Other equity Total equity 2025 Equity as of 01.01.2025 1.7 787.2 - - (1.0) (26.3) (65.9) 695.6 Net result for the period - - - 8.0 - - 42.2 50.2 Other comprehensive income Realised cash flow hedge revenue - - - - - (16.9) - (16.9) Related tax - realised cash flow hedge - - - - - 10.8 - 10.8 Changes in fair value cash flow hedge revenue - - - - - 159.9 - 159.9 Changes in fair value cash flow hedge EUA - - - - - 1.8 - 1.8 Related tax - changes in fair value cash flow hedge - - - - - (103.5) - (103.5) Currency translation adjustments - - - - 5.1 - - 5.1 Total other comprehensive income - - - - 5.1 52.1 - 57.3 Hybrid bond issue - - - 285.9 - - - 285.9 Dividend paid - (252.0) - - - - - (252.0) Share buy-back - - (0.1) - - - (50.2) (50.3) Share-based incentive programme - - 0.0 - - - (2.3) (2.3) Total transactions with owners for the period - (252.0) (0.0) 285.9 - - (52.5) (18.7) Equity as of 30.09.2025 1.7 535.2 (0.0) 293.9 4.1 25.8 (76.3) 784.4 2026 Equity as of 01.01.2026 1.6 446.2 - 302.8 4.2 36.6 (23.4) 767.9 Net result for the period1 - - - 27.0 - - (37.0) (10.0) Other comprehensive income Realised cash flow hedge revenue - - - - - 132.8 - 132.8 Related tax - realised cash flow hedge - - - - - (85.0) - (85.0) Changes in fair value cash flow hedge revenue - - - - - (782.0) - (782.0) Related tax - changes in fair value cash flow hedge - - - - - 500.5 - 500.5 Currency translation adjustments - - - - (2.0) - - (2.0) Total other comprehensive loss - - - - (2.0) (233.7) - (235.8) Dividend paid - (389.0) - (36.0) - - - (425.0) Share-based incentive programme - - - - - - 0.8 0.8 Total transactions with owners for the period - (389.0) - (36.0) - - 0.8 (424.2) Equity as of 30.09.2026 1.6 57.2 - 293.8 2.1 (197.1) (59.6) 97.9 1) Each quarter in 2026, an amount of USD 9.0 million has been allocated to hybrid bond owners, reflecting the discretionary coupon for the period. In Q1 2026 nothing was allocated to hybrid bond owners, this was corrected in Q2 2026. Allocations to hybrid bondholders are determined on a period‑by‑period basis. For earnings per share purposes, the amount allocated to hybrid bondholders has been deducted from profit attributable to ordinary shareholders in accordance with IAS 33. See note 12 for further details.
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Third Quarter Report 2026 15 Condensed Consolidated Statement of Cash Flows USD million Note Q3 2026 Q2 2026 Q3 2025 YTD 2026 YTD 2025 Cash flows from operating activities Net result for the period (19.7) 19.1 12.9 (10.0) 50.2 Adjustments for: Income tax (benefit)/expense 5 (5.2) 43.1 9.1 45.5 (22.6) Net financial items 4 158.9 16.9 46.0 299.8 144.5 Depreciation/impairment 7, 8 85.7 67.7 62.9 232.4 171.8 Share-based payments expenses 0.3 0.3 0.1 0.8 0.7 Interest received1 4 1.2 1.1 2.8 2.9 6.9 Other financial items paid (8.8) (7.3) (0.9) (16.7) (2.3) Changes in: Trade receivable 9 (98.3) 83.9 10.1 (88.3) (50.6) Trade payables 14 25.9 19.2 (12.2) 65.3 (12.1) Inventories and spare parts 10 2.3 (1.0) 3.4 3.6 (3.0) Prepayments 9 0.4 5.0 1.5 9.7 (2.7) Over/(under)-lift 9 3.2 1.5 (5.8) 9.7 (10.4) Other current balance sheet items2 (4.4) 1.2 (1.1) (5.8) (0.4) Cash flow from operating activities before tax 141.5 250.6 128.8 548.9 269.9 Tax paid (71.8) (1.4) (1.1) (89.1) (17.7) Net cash flow from operating activities 69.7 249.2 127.8 459.8 252.2 Cash flows from investing activities Investment in oil and gas assets 8 (9.9) (11.0) (7.3) (18.6) (35.9) Investment in other assets (0.1) (0.0) (2.1) (0.1) (2.1) Payments for decommissioning of oil and gas fields (0.4) (0.4) (1.2) (1.2) (2.6) Changes in restricted cash accounts - - - - 158.4 Net cash flow from/(used in) investing activities (10.4) (11.4) (10.6) (19.9) 117.8 Cash flows from financing activities Net proceeds from hybrid capital issue 12 - - 285.9 - 285.9 Dividend paid (174.0) (100.0) (252.0) (389.0) (252.0) Dividend paid to hybrid bond holders (18.0) - - (36.0) - Share buy-back - - (50.3) - (50.3) Drawdown long-term liability 13 150.0 300.3 20.0 450.3 20.0 Repayment long-term liability 13 (75.0) (321.7) (331.4) (396.7) (331.4) Interests and fees external loan (20.5) (16.1) (40.5) (79.4) (95.4) Lease payments (0.2) (0.2) (0.1) (0.5) (0.4) Net cash flow from/(used in) financing activities (137.7) (137.7) (368.5) (451.3) (423.6) Net change in cash and cash equivalents (78.3) 100.1 (251.3) (11.4) (53.6) Cash and cash equivalents at the start of the period 209.7 109.6 448.3 142.7 250.6 Cash and cash equivalents at end of the period 131.3 209.7 197.0 131.3 197.0 1) Excluding interest received from cash call security account as these interests are added to the cash call security account, h ence not available cash. 2) Mainly currency adjustments balance sheet items.
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Third Quarter Report 2026 16 Notes 03
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Notes continued Third Quarter Report 2026 17 Notes 1 Accounting principles BlueNord ASA (‘BlueNord’, ‘the Company’ or ‘the Group’) is a public limited liability company registered in Norway, with headquarters in Oslo (Nedre Vollgate 3, 0158 Oslo). The Company has subsidiaries in Norway, Denmark, the Netherlands and the United Kingdom. The Company is listed on the Oslo Stock Exchange. Basis for preparation The interim condensed consolidated financial statements (the interim financial statements) as at, and for the period ended 30 September 2026 comprise of BlueNord ASA (BlueNord) and its subsidiaries. These interim financial statements have been prepared in accordance with IAS 34 Interim Financial Reporting as adopted by the EU. The interim financial statements do not include all the information and disclosures required to represent a complete set of financial statements, and these interim financial statements should be read in conjunction with the annual financia l statements. The interim financial statements are unaudited. The subtotals and totals in some of the tables may not equal the sum of the amounts shown due to rounding. These interim financial statements were authorised for issue by the Board of Directors on 27 October 2026. Going concern The Board of Directors confirms that the interim financial statements have been prepared on a going concern basis. The financial solidity and the Company's cash and working capital position are considered satisfactory in regards of the planned activity level for the next 12 months. Reference to summary of significant accounting policies These interim financial statements have been prepared using the same accounting principles as those applied in the annual financial statements for 2025. For the full summary of significant accounting policies, reference is made to the annual financial statements for 2025. Critical accounting estimates and judgements Estimates and judgements are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. The significant judgements made in applying the Group’s accounting policies and the key sources of estimation uncertainty were the same as those described in the last annual financial statements.
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Notes continued Third Quarter Report 2026 18 2 Income USD million Q3 2026 Q2 2026 Restated Q3 20251 YTD 2026 Restated YTD 20251 Sales of oil 177.6 156.3 140.5 516.0 404.3 Sales of gas and NGL 168.3 118.2 108.0 420.1 345.3 Tariff income 0.2 2.3 2.9 4.4 10.5 Total revenue 346.0 276.8 251.4 940.5 760.1 Other income - - - - - Total income 346.0 276.8 251.4 940.5 760.1 Sales volumes Production of oil (mmbbl) 2.1 1.9 2.1 6.2 5.8 Over/(under)-lift (mmbbl) 0.1 0.0 -0.2 0.2 -0.3 Sales of oil (mmbbl) 2.2 2.0 1.9 6.5 5.5 Production of gas (mmboe) 1.9 1.5 1.5 5.1 3.9 Purchase of gas (mmboe) 0.0 0.1 0.0 0.1 0.7 Sales of gas (mmboe) 2.0 1.6 1.5 5.2 4.6 Effective prices Effective oil price USD/bbl 81.3 79.8 74.0 80.0 73.4 Effective gas price USD/boe 85.6 76.0 70.8 80.1 74.3 Effective gas price EUR/MWh 43.0 38.4 35.3 40.0 39.1 1) Comparative figures restated as penalties and gas purchases previously deducted from revenue were reclassified to production expenses. No impact on net result. Further details are disclosed in Note 2 of the Group's Q4 2025 report. During the third quarter, all of BlueNord’s settlement of price hedges that were put in place with financial institutions in the market matched the physical sale of oil and gas and were recognised as revenue.
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Notes continued Third Quarter Report 2026 19 3 Production expenses USD million Q3 2026 Q2 2026 Restated Q3 20251 YTD 2026 Restated YTD 20251 Direct field opex (63.0) (66.8) (74.5) (185.2) (212.2) Tariff and transportation expenses (21.8) (22.8) (20.5) (67.5) (62.7) Environmental costs (6.3) (7.7) (2.8) (20.6) (12.4) Production general and administrative (1.1) (1.9) (2.7) (5.6) (6.7) Field operating cost (92.1) (99.3) (100.5) (278.9) (293.8) Total produced volumes (mmboe) 4.0 3.4 3.6 11.3 9.7 Field operating cost per boe (22.9) (29.3) (28.0) (24.7) (30.2) Adjustments for: Gas purchases and fees1 (3.5) (10.3) (4.9) (18.8) (63.9) Penalties1 (1.6) (3.3) (0.5) (6.6) (18.8) Concept studies (0.0) 0.0 (0.1) 0.0 (0.3) Change in inventory position (0.9) 1.5 (2.2) (0.8) 5.0 Change in (over)/under-lift of oil and NGL (3.2) (1.5) 5.8 (9.7) 10.4 Insurance & other (4.6) (2.7) (5.7) (11.9) (16.9) Stock scrap (2.0) (1.0) (0.4) (4.1) (1.3) Production expenses (107.9) (116.6) (108.5) (330.8) (379.8) 1) Comparative figures restated as penalties and gas purchases previously deducted from revenue were reclassified to production expenses. No impact on net result. Further details are disclosed in Note 2 of the Group's Q4 2025 report. Field operating cost directly attributable to BlueNord’s oil and gas production amounted to USD 92.1 million in the third quarter, compared with USD 99.3 million in the previous quarter . The decrease was mainly driven by higher maintenance work associated with planned shutdowns in the second quarter. The field operating cost equates to USD 22.9 per boe produced during the third quarter, compared with USD 29.3 per boe in the previous quarter. Lifting cost per boe came to USD 16.0, lower than the prior quarter at USD 20.3. The decrease is due to the above mentioned decreased opex together with increased production from Tyra.
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Notes continued Third Quarter Report 2026 20 4 Financial income and expenses Financial income USD million Q3 2026 Q2 2026 Q3 2025 YTD 2026 YTD 2025 Total interest income 1.2 1.1 2.8 2.9 8.1 Change in fair value of embedded derivatives1 - - - - 39.6 Change in value adjustment amortised cost RBL - - - 2.8 - Foreign exchange gains (0.9) 1.4 4.0 (0.4) 14.3 Other financial income - - 0.0 0.0 0.0 Total other financial income (0.9) 1.4 4.0 2.4 54.0 Financial expenses USD million Q3 2026 Q2 2026 Q3 2025 YTD 2026 YTD 2025 Interest expenses current liabilities (0.2) (0.0) (0.3) (0.3) (0.5) Interest expense from bond loans (8.3) (8.3) (7.7) (24.3) (40.3) Interest expense from bank debt (22.1) (17.4) (26.0) (59.2) (69.4) Total interest expenses (30.7) (25.7) (33.9) (83.8) (110.2) Utilisation of derivatives (7.9) (6.6) - (14.5) - Unrealised gain/(loss) derivatives (104.3) 61.5 - (127.2) - Accretion expense related to asset retirement obligations (13.4) (13.4) (13.3) (40.3) (39.8) Extinguishment of bond loans - (33.8) (2.3) (33.8) (37.9) Foreign exchange losses (2.2) (0.6) (2.7) (3.5) (16.7) Other financial expenses (0.6) (0.7) (0.6) (2.0) (1.9) Total other financial expenses (128.5) 6.3 (18.8) (221.4) (96.3) Net financial items (158.9) (16.9) (46.0) (299.8) (144.5) 1) Fair value adjustment of embedded derivatives of BNOR15 convertible bonds. In June 2025 , the convertible bond BNOR15 was extinguished, including the derecognition of the associated embedded derivative. The bond was fully redeemed on 1 August 2025.
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Notes continued Third Quarter Report 2026 21 5 Tax Tax rates Producers of oil and gas on the Danish continental shelf are subject to the hydrocarbon tax regime governed by the Danish Hydrocarbon Tax Act (kulbrinteskatteloven) under which, income derived from the sale of oil and gas is taxed at an elevated 64%. Any i ncome deriving from other activities than first -time sales of hydrocarbons are taxed at the ordinary corporate income rate of currently 22%. The 64% effective tax rate is derived from the sum of a special corporate tax of 25% applicable to upstream oil and gas activities (Chapter 2) and a special hydrocarbon tax of 52% levied on pro fits from the exploration and extraction of oil and gas (Chapter 3A), in which the 25% tax is deductible in the hydrocarbon tax calculation. When calculating the 52% tax, the Company is allowed to deduct an uplift (i.e. increased depreciation basis for tax purposes) of 30% of the investments in property, plant and equipment over a period of six years. Through an agreement from 2017, licence holders on the Danish continental shelf have had the possibility of applying temporary new rules whereby the Company will have the possibility of increased uplift by 9% and accelerated depreciation during the period from 2017 to 2025. At the same time, an additional tax was introduced which will materialise from 2022 through 2037 if the average Brent oil price for the year exceeds USD 75.0 (2017 prices inflated by 2 pct. per year). The accumulated additional tax in the years 2022 through 2037 cannot exceed the benefit received in previous years related to the increased uplift and accelerated depreciation. The additional tax is accounted for in the year the oil price exceeds the thresholds Tax expense USD million Income tax in profit/loss (Danish corporate income tax and hydrocarbon tax) Q3 2026 Q2 2026 Q3 2025 YTD 2026 YTD 2025 Current tax (4.4) (2.9) (39.1) (9.6) (51.7) Current tax, prior year - (47.0) - (47.0) - Current tax (4.4) (49.9) (39.1) (56.6) (51.7) Deferred tax 9.6 (52.3) 29.9 (48.0) 74.2 Deferred tax, prior year - 59.2 - 59.2 - Deferred tax 9.6 6.8 29.9 11.1 74.2 Tax (expense)/ income 5.2 (43.1) (9.1) (45.5) 22.6 Income tax in profit/loss is solely derived from the Group's activities on the Danish continental shelf, of which the major part is subject to the elevated 64% hydrocarbon tax. Tax (expense)/income related to OCI Cash flow hedges 278.3 (166.8) (45.0) 415.5 (92.7) Tax (expense)/income related to OCI 278.3 (166.8) (45.0) 415.5 (92.7) The main driver of the movement in deferred tax in the current quarter is the revaluation of tax losses denominated in DKK. IFRS requires the balance to be revalued based on the period end exchange rate. Prior year adjustments on current and deferred tax relate to potential or actual adjustments of hydrocarbon tax returns for earlier years. Income tax on OCI is related to the derivatives designated in cash flow hedges. To the extent derivatives are associated with the sale of oil and gas, result from cash flow hedges is subject to 64% hydrocarbon tax.
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Notes continued Third Quarter Report 2026 22 Hydrocarbon tax 64% Corporate tax 22% Reconciliation of nominal to actual tax rate: Q3 2026 Q3 2026 In total Result before tax (32.8) 7.8 (24.9) Expected tax on profit before tax (21.0) 64% 1.7 22% (19.2) Tax effect of: Currency changes to tax losses carried forward in DKK1 9.5 -29% - 0% 9.5 Investment uplift on capex projects2 (6.7) 20% - 0% (6.7) Interest limitation 9.0 -27% - 0% 9.0 No recognition of tax assets in Norway and UK - 0% 2.3 29% 2.3 Tax expense (income) in profit/loss (9.2) 28% 4.0 51% (5.2) YTD 2026 YTD 2026 In total Result before tax 49.6 (14.2) 35.4 Expected tax on profit before tax 31.8 64% (3.1) 22% 28.6 Tax effect of: Prior year adjustment (20.5) -41% 8.3 -59% (12.2) Currency changes to tax losses carried forward in DKK1 15.3 31% - 0% 15.3 Investment uplift on capex projects2 (20.0) -40% - 0% (20.0) Interest limitation 24.1 49% - 0% 24.1 No recognition of tax assets in Norway and UK - 0% 9.6 -67% 9.6 Tax expense (income) in profit/loss 30.7 62% 14.8 -104% 45.5 Q3 2026 Q3 2026 In total OCI before tax (434.9) (1.2) (436.1) Expected tax on OCI before tax 278.3 64% 0.3 22% 278.6 Tax effect of: Non-taxable currency translation adjustment - (0.3) (0.3) Tax in OCI 278.3 64% - 22% 278.3 YTD 2026 YTD 2026 In total OCI before tax (649.2) (2.0) (651.3) Expected tax on OCI before tax 415.5 64% 0.4 22% 416.0 Tax effect of: Non-taxable currency translation adjustment - (0.4) (0.4) Tax in OCI 415.5 64% - 22% 415.5 1) Impact of changes in USD/DKK exchange rate on loss carried forward as the tax losses are carried forward in DKK. 2) The tax cost in the hydrocarbon tax regime is positively impacted by the 39% investment uplift on the Tyra Redevelopment project.
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Notes continued Third Quarter Report 2026 23 Current income tax receivables/(payables) 30.09.2026 30.06.2026 31.12.2025 30.09.2025 Corporate tax 22% (Denmark) (16.6) (19.8) 0.2 (0.5) Hydrocarbon tax (Denmark) 0.5 (0.5) (50.9) (22.8) Hydrocarbon tax for prior years (Denmark) (38.8) (100.1) (21.1) (8.6) Tax receivables/(payables) (54.9) (120.4) (71.8) (31.9) Current income taxes for current and prior periods are measured at the amount that is expected to be paid to or be refunded from the tax authorities, as at the balance sheet date. Due to the complexity in the legislative framework and the limited amount of guidance from relevant case law, the measurement of taxable profits within the oil and gas industry is associated with some degree of uncertainty. Uncertain tax liabilities are recognised with the probable value if their probability is mor e likely than not. Tax payables of USD 54.9 million, which includes USD 16 million payable for 2025 and 2026, USD (21) million for prior years and 59.9 million in provision for uncertain tax positions. The decrease in current year payables compared to Q2 2026 is due to prepayments made for prior years and unrealised losses on oil and gas hedges. Deferred tax Deferred tax is measured at the amount that is expected to result in taxes due to temporary differences and the value of tax losses. The recognised deferred tax asset is allocated to the following balance sheet items, all pertaining to the Group’s activities on the Danish continental shelf: USD million Deferred tax and deferred tax asset 31.12.2025 Effect recognised in P&L Effect recognised in OCI 30.09.2026 Property, plant and equipment 992.0 (45.8) - 946.2 Intangible assets, licences 18.9 (21.7) - (2.8) Inventories and receivables 23.7 5.4 - 29.1 Asset retirement obligation (ARO) (805.1) (23.7) - (828.8) Other assets and liabilities (6.9) (0.2) - (7.1) Tax loss carryforward, chapter 2 tax (25%) (0.2) 14.3 (118.8) (104.6) Tax loss carryforward, chapter 3a tax (52%) (389.0) 60.6 (296.8) (625.1) Deferred tax asset, net (166.4) (11.1) (415.5) (593.0)
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Notes continued Third Quarter Report 2026 24 6 Earnings per share Earnings per share are calculated by dividing the profit attributable to ordinary shareholders of the parent company by the weighted average number of ordinary shares in issue during the period. USD million Q3 2026 Q2 2026 Q3 2025 YTD 2026 YTD 2025 Net result for the period (19.7) 19.1 12.9 (10.0) 50.2 Preference dividends on hybrid capital (9.0) (9.0) (8.0) (27.0) (8.0) Profit (loss) from operations attributable to ordinary shareholders (28.7) 10.1 4.9 (37.0) 42.2 Profit (loss) from operations basis for fully diluted shareholders (28.7) 10.1 4.9 (37.0) 42.2 Number of shares outstanding at the beginning of the period 25,567,202 25,567,202 26,498,640 25,567,202 26,498,640 Share buy-back - - (1,001,782) - (1,001,782) Treasury shares awarded - - 70,344 - 70,344 Number of shares outstanding at the end of the period 25,567,202 25,567,202 25,567,202 25,567,202 25,567,202 Weighted average number of shares (basic) 25,567,202 25,567,202 25,833,283 25,567,202 26,457,471 Adjustment for potential LTI shares 65,130 65,130 - 65,130 - Weighted average number of shares (diluted) 25,632,332 25,632,332 25,833,283 25,632,332 26,457,471 Earnings per share in USD (1.1) 0.4 0.2 (1.4) 1.6 Earnings per share in USD diluted (1.1) 0.4 0.2 (1.4) 1.6
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Notes continued Third Quarter Report 2026 25 7 Intangible assets USD million Capitalised exploration expenditures Licence Total Book value 31.12.25 1.9 133.5 135.5 Acquisition costs 31.12.25 1.9 186.0 187.9 Acquisition costs 30.06.26 1.9 186.0 187.9 Depreciation and write-downs 31.12.25 - (52.5) (52.5) Depreciation/write-down/amortisation - (5.1) (5.1) Depreciation and write-downs 30.06.26 - (57.6) (57.6) Book value 30.06.26 1.9 128.4 130.3 Acquisition costs 30.06.26 1.9 186.0 187.9 Acquisition costs 30.09.26 1.9 186.0 187.9 Depreciation and write-downs 30.06.26 - (57.6) (57.6) Depreciation/write-down/amortisation - (2.8) (2.8) Depreciation and write-downs 30.09.26 - (60.4) (60.4) Book value 30.09.26 1.9 125.6 127.5
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Notes continued Third Quarter Report 2026 26 8 Property, plant and equipment USD million Asset under construction Production facilities Other assets Total Book value 31.12.25 48.3 2,499.2 3.4 2,550.9 Acquisition costs 31.12.25 48.3 3,352.1 5.5 3,405.9 Reclassification from AUC to production facilities (1.3) 1.3 - - Additions 4.2 4.5 0.0 8.7 Currency translation adjustment - (0.0) (0.0) (0.1) Acquisition costs 30.06.26 51.2 3,357.8 5.5 3,414.5 Depreciation and write-downs 31.12.25 - (852.8) (2.1) (854.9) Depreciation - (130.8) (0.1) (130.9) Depreciation of capitalised borrowing cost - (10.4) - (10.4) Currency translation adjustment - 0.0 0.0 0.0 Depreciation and write-downs 30.06.26 - (994.0) (2.2) (996.2) Book value 30.06.26 51.2 2,363.8 3.3 2,418.3 Acquisition costs 30.06.26 51.2 3,357.8 5.5 3,414.5 Moved from AUC to production facilities (9.2) 9.2 - - Additions 2.8 7.2 0.1 10.0 Currency translation adjustment - (0.1) (0.1) (0.1) Acquisition costs 30.09.26 44.8 3,374.1 5.5 3,424.3 Depreciation and write-downs 30.06.26 - (994.0) (2.2) (996.2) Depreciation - (76.1) (0.1) (76.2) Depreciation of capitalised borrowing cost - (6.5) - (6.5) Currency translation adjustment - 0.0 0.0 0.0 Depreciation and write-downs 30.09.26 - (1,076.6) (2.2) (1,078.9) Book value 30.09.26 44.8 2,297.5 3.2 2,345.5 The Group identifies two cash-generating units (CGU), the DUC assets as a whole and the CarbonCuts business unit. The Group has not identified any impairment triggers in third quarter 2026 related to property, plant and equipment. See note 12 Impairments in the Annual Report 2025 for the accounting policies related to impairment of non-financial assets.
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Notes continued Third Quarter Report 2026 27 9 Trade receivables and other current assets USD million 30.09.2026 30.06.2026 31.12.2025 30.09.2025 Trade receivables 169.6 67.8 60.9 78.2 Under-lift of oil/NGL - - 6.1 4.1 Prepayments 9.4 9.9 19.1 12.2 Other receivables 0.7 4.2 21.2 1.9 Total trade receivables and other current receivables 179.8 81.9 107.3 96.3 10 Inventories USD million 30.09.2026 30.06.2026 31.12.2025 30.09.2025 Product inventory, oil 21.5 22.4 22.3 18.7 Other stock (spares & consumables) 42.7 44.1 45.5 40.1 Total inventories 64.2 66.5 67.8 58.8 9 11 Restricted bank accounts, cash and cash equivalents USD million 30.09.2026 30.06.2026 31.12.2025 30.09.2025 Non-current assets Restricted bank deposits pledged as security for abandonment obligation related to Nini/Cecilie 67.3 68.7 69.7 69.4 Total non-current restricted bank deposits 67.3 68.7 69.7 69.4 Current assets Unrestricted cash and cash equivalents 131.3 209.7 142.7 197.0 Restricted bank deposits1 - - 0.1 0.8 Total current cash and cash equivalents 131.3 209.7 142.8 197.8 Total bank deposits 198.6 278.4 212.5 267.2 1) Tax Withholding Account.
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Notes continued Third Quarter Report 2026 28 12 Hybrid capital In July 2025 the Company successfully issued a new USD 300 million subordinated callable hybrid bond with maturity in July 2085. The hybrid bond carries a fixed interest rate of 12.0% per annum, payable semi -annually. The BNOR17 will have the first call at 100% of its nominal value and a coupon step -up of 5 percentage points after 4.5 years, resulting in a new fixed rate of 17%. BlueNord has the right to defer coupon payments indefinitely, even after principal repayment, but must pay any deferred coupons before declaring ordinary dividends. Due to the long maturity and the right to defer coupon payments, the hybrid bond is classified as a compound financial instrument, with the equity component representing nearly the entire value. The liability component is calculated as the present value of the maturity payment in 2085, and because the debt component is immaterial, fees are allocated entirely to equity. Coupon payments, when made, will be recognised as a deduction from equity, similar to ordinary dividends, with the related income tax effect recognised as a reduction of income tax expense in profit or loss. The unwind of the discounting effect of the liability component will be expensed as interest (accretion). The hybrid bond replaced the convertible bond BNOR15, preserving the Group’s financial flexibility and eliminating the potential equity dilution associated with BNOR15’s mandatory conversion. Maturity 2085 Type Subordinated Financial classification Equity (99.7%) Notional amount USD 300 million Issued 10.07.2025 Maturing 10.07.2085 Quoting in Oslo First redemption at par 10.01.2030 Coupon 12% fixed rate Coupon step-up from 10.01.2030 5% fixed rate Deferral of interest payment Optional USD million Equity Debt Total Balance as of 31.12.25 302.8 1.0 303.8 Profit allocated to Hybrid owners 27.0 - 27.0 Accretion - 0.1 0.1 Interest paid classified as dividend (36.0) - (36.0) Balance as of 30.09.26 293.8 1.1 294.8 In 2025, USD 17.0 million was allocated to hybrid bond owners of the profit, reflecting the period from issuance on 10 July 2025 to 31 December 2025. A semi -annual hybrid coupon of USD 18.0 million was paid in January 2026. The difference between the amount allocated of the profit and the cash payment relates to the period from 1 to 10 January 2026 and has been recognised directly in equity. For each quarter in 2026, an amount of USD 9.0 million has been allocated to hybrid bond owners, reflecting the discretionary coupon for the period. In Q1 2026 nothing was allocated to hybrid bond owners, this was corrected in Q2 2026. Accordingly, the equity component of the hybrid capital changed only as a result of the coupon payment and the allocation made in the second and first quarter, while the liability component increased due to the accretion of the discount recognised as interest expense.
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Notes continued Third Quarter Report 2026 29 13 Borrowings 30.09.2026 30.06.2026 31.12.2025 30.09.2025 USD million Principal amount Book value Principal amount Book value Principal amount Book value Principal amount Book value BNOR16 senior unsecured bond1 - - - - 300.0 305.5 300.0 297.8 BNOR18 senior unsecured bond2 400.0 402.1 400.0 394.4 - - - - Total non-current bonds 400.0 402.1 400.0 394.4 300.0 305.5 300.0 297.8 Reserve-based lending facility3 800.0 755.5 725.0 678.8 800.0 763.5 900.0 861.2 Total non-current debt 800.0 755.5 725.0 678.8 800.0 763.5 900.0 861.2 Total borrowings 1,200.0 1,157.6 1,125.0 1,073.3 1,100.0 1,068.9 1,200.0 1,159.0 Note: Book values reported on the basis of amortised cost for BNOR18, BNOR16 and the reserve-based lending facility. 1) The Company issued a senior unsecured bond of USD 300 million on 2 July 2024, with a maturity in July 2029. The bond carrie d an interest rate of 9.5% per annum, payable semi -annually. The BNOR16 bond was used to redeem the BNOR14 bond and for general corporate purposes. In May 2026, the Company exercised the call option to redeem all outstanding bonds in accordance with the Bond Terms. The BNOR16 bond was redeemed at the Make Whole Amount, corresponding to 108.69889% of the nominal amount plus accrued interest. The record date was 20 May 2026 and the settlement date was 22 May 2026. Upon redemption, the bond was derecognised in accordance with IFRS 9 Financial Instruments. The difference between the carrying amount of the financial liability at the redemption date and the consideration paid, including the make -whole premium and accru ed interest, was recognised in finance costs in the statement of profit or loss. The Company has no outstanding balance related to the BNOR16 bond as at the 30 September 2026. 2) In May 2026, the Company issued BNOR18, a 5 -year senior unsecured bond of USD 400 million, with maturity in May 2031. The bond carries an interest rate of 7.875% per annum, payable semi‑annually. The net proceeds from the bond issue were used to redeem the BNOR16 bond and to repay USD 75 million of the outstanding drawings under the reserve ‑based lending facility, with the remaining proceeds used for general corporate purposes. The bond is recognised at amortised cost using the effective interest method in accordance with IFRS 9. 3) The Company has a reserve‑based lending (“RBL”) facility with a total commitment of USD 1.4 billion, split into USD 1.15 billion by way of loan drawdowns (capped by the borrowing base amount availability, re -determined semi-annually) and USD 250 million for letters of credit issuance. Interest is accrued on the drawn loan amount at an interest rate equal to SOFR plus a margin component. In February 2026, the facility’s maturity was extended from December 2029 to December 2031. Amortisation will begin in December 2028, and there is an accordion option up to USD 400 million. The interest margin s remain unchanged. During the third quarter of 2026, the Company drew USD 150 million and subsequently repaid USD 75 million under the facility, resulting in a net increase in outstanding loan drawdowns of USD 75 million. As at 30 September 2026, outstanding loan drawdowns amounted to USD 800 million and outstanding letters of credit issues remains unchanged at USD 200 million.
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Notes continued Third Quarter Report 2026 30 Payment structure (USD million) at 30.09.2026 Year BNOR181 Reserve-based lending facility2 Total Interest rate 7.875% SOFR 2026 15.8 18.1 33.9 2027 31.5 71.9 103.4 2028 31.5 72.6 104.1 2029 31.5 210.4 241.9 2030 31.5 375.6 407.1 2031 415.8 350.0 765.8 Total 557.5 1,098.7 1,656.2 1) BNOR18 carries an interest rate of 7.875% per annum, payable semi-annually. 2) RBL interest payments include drawn, undrawn and letter of credit utilisation fees. There are no active interest rate hedges to date. 14 Trade payables and other current liabilities USD million 30.09.2026 30.06.2026 31.12.2025 30.09.2025 Trade payable 3.9 0.7 14.8 1.2 Liabilities to operator 42.7 42.3 19.9 37.2 Over-lift of oil/NGL 3.6 0.4 - - Accrued interest 0.5 0.2 0.5 1.0 Salary accruals 3.2 1.9 3.1 2.2 Public duties payable 14.1 17.0 18.7 17.8 Other current liabilities 77.5 53.5 35.7 19.9 Total trade payables and other current liabilities 145.5 115.9 92.7 79.3
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Notes continued Third Quarter Report 2026 31 15 Financial instruments 15.1 Fair value hierarchy The table below analyses financial instruments carried at fair value, by valuation method. The different levels have been defined as follows: Level 1 Quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 Inputs other than quoted prices included within level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 Inputs for the asset or liability that are not based on observable market data. On 30.09.2026 USD million Level 1 Level 2 Level 3 Total Assets Financial assets at fair value through profit or loss – Derivative instruments EUA - 2.8 - 2.8 Hedging instruments at fair value – Derivative instruments price hedge - 0.2 - 0.2 Total assets - 3.0 - 3.0 Liabilities Financial liabilities at fair value through profit or loss – Derivative instruments price hedge - 121.3 - 121.3 – Derivative instruments EUA - 0.1 - 0.1 Hedging instruments at fair value – Derivative instruments price hedge - 547.8 - 547.8 Total liabilities - 669.1 - 669.1 15.2 Financial instruments by category On 30.09.2026 USD million Financial instruments at amortised cost Financial instruments at fair value through profit or loss Hedging instruments at fair value Total Assets Derivative instruments EUA - 2.8 - 2.8 Derivative instruments price hedge - - 0.2 0.2 Trade receivables and other current assets 179.8 - - 179.8 Restricted bank deposits 67.3 - - 67.3 Cash and cash equivalents 131.3 - - 131.3 Total assets 378.4 2.8 0.2 381.4 Liabilities Derivative instruments EUA - 0.1 - 0.1 Derivative instruments price hedge - 121.3 547.8 669.1 Subordinated hybrid bond loan 1.1 - - 1.1 Senior unsecured bond loan 402.1 - - 402.1 Reserve-based lending facility 755.5 - - 755.5 Trade payables and other current liabilities 145.5 - - 145.5 Total liabilities 1,304.1 121.4 547.8 1,973.2
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Notes continued Third Quarter Report 2026 32 15.3 Financial instruments — fair values Set out below is a comparison of the carrying amounts and fair value of financial instruments on 30 Sep 2026: USD million Total amount outstanding1 Carrying Amount Fair Value Financial assets Derivative instruments EUA 2.8 2.8 Derivative instruments price hedge 0.2 0.2 Trade receivables and other current assets 179.8 179.8 Restricted bank deposits 67.3 67.3 Cash and cash equivalents 131.3 131.3 Total 381.4 381.4 Financial liabilities Derivative instruments EUA 0.1 0.1 Derivative instruments price hedge 669.1 669.1 Subordinated hybrid bond loan2 1.1 1.1 Senior unsecured bond loan 400.0 402.1 400.0 Reserve-based lending facility 800.0 755.5 800.0 Trade payables and other current liabilities 145.5 145.5 Total 1,200.0 1,973.2 2,015.6 1) Total amount outstanding on the bonds and under the RBL facility. 2) BNOR 17 is classified as a compound financial instrument with equity and debt components, please see note 12 Hybrid Capital for more information. The RBL facility is measured at amortised cost. Transaction costs are deducted from the amount initially recognised and are expensed over the period during which the debt is outstanding under the effective interest method. The capital outstanding is USD 800 million as per Q3 2026. 15.4 Hedging The Group actively seeks to reduce the market -related risks it is exposed to including, (i) commodity prices, (ii) market - linked floating interest rates and (iii) foreign exchange rates. The Company has a rolling hedge requirement under its RBL facility based on a minimum level of production corresponding to the RBL’s production forecast. The requirement is for the following volumes and time periods: (i) Oil: Year 1 at 50 % and Year 2 at 4 0%; (ii) Gas: Season 1 at 50 %, Season 2 at 50 %, Season 3 at 40 % and Season 4 at 20 % (seasons being the ensuing six-month seasons, with a season being October to March or April to September). Currently all the Company's commodity price hedging arrangements are a combination of fixed-price and option-based derivative instruments. No foreign exchange and interest hedges in place at the quarter end. The Company will continue to assess the need for these hedging considerations as part of its ongoing financial risk management strategy. As part of the Company’s compliance obligations under the EU Emissions Trading System (EU ETS), the Company is required to purchase EU Allowances (EUAs) to cover its carbon emissions. In line with its risk management policy, the Company has also entered into EUA-related derivative instruments, to hedge a portion of its expected future EUA purchase requirements. Hedge accounting is applied to the Company’s hedging arrangements when eligibility criteria are met. To the extent more than 100% of the market-related risk is hedged, the portion above 100% is considered ineffective, and the value adjustment is treated as a financial item in the Income Statement. In Q 3 2026, all of the Company’s arrangements in relation to
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Notes continued Third Quarter Report 2026 33 commodity prices were effective. Time value related to commodity hedging arrangements is considered insignificant and generally the valuation of the instruments does not take into consideration the time value. Maturity As of 30 September 2026 Less than 1 to 3 3 to 6 6 to 9 9 to 12 More than Total 1 month months months months months 12 months Commodity forward sales contracts oil: Notional quantity (in mbbl) 360.0 135.0 135.0 135.0 135.0 900.0 Notional amount (in USD million per bbl) 25.0 8.4 8.4 8.5 8.5 58.9 Average hedged sales price (in USD per bbl) 69.4 62.5 62.5 62.9 62.9 65.4 Commodity forward sales contracts gas: Notional quantity (in mMWh) 1,365.0 1,365.0 1,331.3 1,331.3 2,490.0 7,882.5 Notional amount (in EUR million per MWh) 47.2 47.2 39.3 39.3 71.6 244.6 Average hedged sales price (in EUR per MWh) 34.6 34.6 29.5 29.5 28.7 31.0 Commodity zero cost collar contracts oil: Notional quantity (in mbbl)1 1,110.0 1,185.0 1,185.0 1,095.0 4,395.0 8,970.0 Average hedged price - floor (in USD per bbl) 64.8 64.5 64.5 64.3 64.9 64.7 Average hedged price - ceiling (in USD per bbl) 74.9 74.9 74.9 73.9 73.7 74.2 Commodity collar contracts gas: Notional quantity (in mMWh) 1,020.0 1,020.0 645.0 645.0 2,400.0 5,730.0 Average hedged price - floor (in EUR per MWh) 31.1 31.1 27.9 27.9 25.8 28.2 Average hedged price - ceiling (in EUR per MWh) 44.2 44.2 34.8 34.8 33.2 37.5 Oil commodity put contracts: Notional quantity (in mbbl) 600.0 - - - - 600.0 Notional amount (in USD million per bbl) 45.0 - - - - 45.0 Average hedged sales price (in USD per bbl) 75.0 - - - - 75.0 Gas commodity put contracts: Notional quantity (in mMWh) 900.0 - - - - 900.0 Notional amount (in EUR million per MWh) 36.0 - - - - 36.0 Average hedged sales price (in EUR per MWh) 40.0 - - - - 40.0 1) Of which 1,050 mbbl oil and 900 mMWh for gas do not qualify for hedge accounting and are therefore measured at fair value through profit or loss. Swaptions and short puts are not included in the table.
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Notes continued Third Quarter Report 2026 34 16 Asset retirement obligations 2026 2026 2025 USD million Q3 01.01.-30.06 01.01.-31.12. Provisions as of beginning of period 1,374.3 1,349.3 1,122.1 Provisions and change of estimates (1.4) (1.0) 178.3 Accretion expense 13.4 26.9 53.0 Incurred removal cost (0.4) (0.8) (4.5) Currency translation adjustment (0.1) (0.0) 0.3 Total provisions made for asset retirement obligations 1,385.9 1,374.3 1,349.3 Breakdown of short-term and long-term asset retirement obligations Short-term 26.4 19.3 5.3 Long-term 1,359.5 1,355.0 1,344.0 Total provisions for asset retirement obligations 1,385.9 1,374.3 1,349.3 The balance as per 30 September 2026 is USD 1,314.2 million for DUC, USD 67.3 million for Nini/Cecilie, USD 1.7 million for Lulita (non-DUC share) and USD 2.8 million for Tyra F-3 pipeline. Provisions for asset retirement obligations represent the future expected costs to decommission and remove equipment and production facilities. These estimates are calculated in compliance with the Petroleum Activities Act and applicable international regulations and guidelines. The calculations incorporate an assumed inflation rate of 2.0% and a nominal pre -tax risk-free discount rate of 4.2%. The abandonment estimates are based on the annual decommissioning cost forecast and budget under the DUC partnership. These projections remain subject to uncertainties, including fluctuations in commodity prices, developments in CO₂ emissions costs, and assessments of field recovery potential. 17 Subsequent events The Company has not identified any events with significant accounting impacts that have occurred between the end of the reporting period and the date of this report.
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Third Quarter Report 2026 35 Information 0 4
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Alternative Performance Measures Third Quarter Report 2026 36 BlueNord chooses to disclose Alternative Performance Measures as part of its financial reporting as a supplement to the financial statements prepared in accordance with International Financial Reporting Standards. This information is provided as useful supplemental information to investors, security analysts and other stakeholders to provide an enhanced insight into the financial development of BlueNord’s business operations and to improve comparability between periods. EBITDA Earnings before interest, taxes, depreciation, depletion, amortisation and impairments. EBITDA assists in comparing performance on a consistent basis without regard to depreciation and amortisation, which can vary significantly depending on accounting methods or non-operating factors and provides a more complete and comprehensive analysis of our operating performance relative to other companies. Adjusted EBITDA (Adj. EBITDA) is EBITDA modified to exclude non-recurring events and transactions not directly related to the operational results for the period. This includes, but is not limited to, restructuring costs, fair value adjustments related to the share-options programme, and non-payment insurance costs associated with the DUC acquisition. USD million Q3 2026 Q2 2026 Q3 2025 YTD 2026 YTD 2025 EBITDA 219.6 146.8 131.0 567.6 343.8 Extraordinary gas penalties1 - - 4.9 - 24.3 Non-payment insurance 1.6 1.6 1.6 4.8 4.5 Share-option programme2 - - 0.0 - 1.4 Restructuring cost3 - - - - 1.6 Adj. EBITDA 221.2 148.4 137.4 572.5 375.7 1) Upstream and downstream gas penalties related to Tyra start-up. From 2026 this is not included as extraordinary cost. 2) Dividend cash compensation and social security taxes related to retention shares. 3) Restructuring cost related to reorganisation. Cash flow from operating activities before tax is defined as Net Cash flow from operating activities excluding tax payments. USD million Q3 2026 Q2 2026 Q3 2025 YTD 2026 YTD 2025 Cash flow from operating activities before tax 141.5 250.6 128.8 548.9 269.9 Tax (paid)/received (71.8) (1.4) (1.1) (89.1) (17.7) Net cash flow from operating activities 69.7 249.2 127.8 459.8 252.2 Interest-bearing debt defined as the book value of the current and non-current interest-bearing debt. USD million 30.09.2026 30.06.2026 31.12.2025 30.09.2025 Senior unsecured bond loan (402.1) (394.4) (305.5) (297.8) Reserve-based lending facility (755.5) (678.8) (763.5) (861.2) Interest-bearing debt (1,157.6) (1,073.3) (1,068.9) (1,159.0)
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Alternative Performance Measures Third Quarter Report 2026 37 Net interest -bearing debt is defined by BlueNord as cash and cash equivalents reduced by current and non -current interest-bearing debt. The RBL facility and bond loans are included in the calculation with the total amount outstanding and not the amortised cost including transaction cost. Net interest-bearing debt as per debt covenant is defined by BlueNord as net interest-bearing debt adjusted for convertible bond loans and letters of credit issued. USD million 30.09.2026 30.06.2026 31.12.2025 30.09.2025 Cash and cash equivalents 131.3 209.7 142.7 197.0 Senior unsecured bond loan (400.0) (400.0) (300.0) (300.0) Reserve-based lending facility (800.0) (725.0) (800.0) (900.0) Net interest-bearing debt (1,068.7) (915.3) (957.3) (1,003.0) Include issued letters of credit (200.0) (200.0) (200.0) (200.0) Net interest-bearing debt as per debt covenant (1,268.7) (1,115.3) (1,157.3) (1,203.0)
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Third Quarter Report 2026 38 Appendix Dan hub Key figures Unit Q3 2026 Q2 20261 Q3 2025 YTD 2026 YTD 2025 Dan mboepd 5.0 5.4 5.5 5.3 5.6 Kraka mboepd 0.1 0.0 0.7 0.3 0.6 Operational efficiency2 % 83.5 % 81.0 % 85.9 % 84.1 % 81.6 % Gorm hub Key figures Unit Q3 2026 Q2 20261 Q3 2025 YTD 2026 YTD 2025 Gorm mboepd 1.3 0.9 0.6 1.1 0.5 Rolf mboepd 0.1 0.1 0.1 0.1 0.1 Skjold mboepd 2.8 2.0 2.7 2.6 3.0 Operational efficiency2 % 84.0 % 67.2 % 61.3 % 79.6 % 65.7 % Halfdan hub Key figures Unit Q3 2026 Q2 20261 Q3 2025 YTD 2026 YTD 2025 Halfdan mboepd 8.4 9.4 10.6 9.1 10.8 Operational efficiency2 % 86.4 % 91.9 % 94.1 % 90.7 % 91.6 % Tyra hub Key figures Unit Q3 2026 Q2 20261 Q3 2025 YTD 2026 YTD 2025 Tyra mboepd 10.6 9.0 6.4 9.8 4.7 Harald mboepd 9.6 5.5 6.8 7.4 6.1 Roar mboepd 1.8 1.2 1.7 1.4 1.2 Valdemar mboepd 4.0 3.6 4.0 4.1 3.0 Operational efficiency2 % 86.8 % 73.4 % 61.6 % 80.3 % 57.1 % 1) Production volumes are updated with actual volumes which do not correspond to the estimated volumes for June 2026 used in the financial reporting. There is no material difference for financial reporting purposes for the quarter. 2) Operational efficiency is calculated as: delivered production / (delivered production + planned shortfalls + unplanned shortfalls).
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Information about BlueNord Third Quarter Report 2026 39 Head Office BlueNord Headquarter Nedre Vollgate 3, 0158 Oslo, Norway Telephone +47 22 33 60 00 Internet www.bluenord.com Organisation number NO 987 989 297 MVA Financial Calendar 17 February 2027 Q4 2026 Report 22 April 2027 Annual Report 2026 Board of Directors Glen Ole Rødland Chair of the Board Peter Coleman Kristin Færøvik Elisabeth Proust Jann Brown Christian Bækken Management Euan Shirlaw Chief Executive Officer Jacqueline Lindmark Boye Chief Financial Officer Miriam Jager Lykke Chief Operating Officer Cathrine Torgersen Chief Corporate Affairs Officer Investor Relations Phone +47 22 33 60 00 E-mail cathrine.torgersen@bluenord.com Annual Reports Annual reports for BlueNord are available on www.bluenord.com Quarterly publications Quarterly reports and supplementary information for investors and analysts are available on www.bluenord.com. The publications can be ordered by e-mailing cathrine.torgersen@bluenord.com. News Releases In order to receive news releases from BlueNord, please register on www.bluenord.com or e-mail cathrine.torgersen@bluenord.com.