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BlueNord ASA
Quarterly Report • May 14, 2025
3692_rns_2025-05-14_899bfac5-7268-4d53-adfd-62f294c01c40.pdf
Quarterly Report
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BlueNord ASA
First Quarter Report 2025
Highlights of the Quarter
Compared to fourth quarter 2024
Revenue EBITDA
Cash flow from operating activities before tax
\$-52% 70m \$
\$80m -27%
Total liquidity (cash and undrawn facilities)
684m
First Quarter Report 2025 1
"BlueNord entered 2025 with strong operational momentum, having seen Tyra reach maximum technical capacity in the fourth quarter of 2024. While Dan, Halfdan, and Gorm have continued their track record of stable, predictable production in line with guidance, reaching plateau at Tyra has taken longer than expected. That said, we are now in a strong position with a positive outlook. In early May, Tyra production net to BlueNord peaked at over 26 mboe/d, with underlying reservoir performance continuing to exceed expectations. Together with the operator, our focus is on achieving stable operations and maximising operational efficiency at a hub that will support BlueNord's business through at least 2042. The transition of Tyra from development to delivery sets the stage for meaningful shareholder returns. For the first quarter of 2025, we are proposing a \$38 million distribution, representing 70% of net operating cashflow. With a resilient portfolio of gas-weighted growth, lowcost structure, and strengthened liquidity, BlueNord is well positioned to deliver sustainable cashflow, even amidst commodity market volatility. Our focus remains clear: to maximise operational value, maintain capital discipline, and deliver on our core commitment to shareholder returns."
31%
Euan Shirlaw, Chief Executive Officer
Contents
| Summary of the Quarter | 4 | |
|---|---|---|
| 01 | Financial Review | 5 |
| Operational Review | 9 | |
| Condensed Consolidated Statement of Comprehensive Income | 14 | |
| 02 | Condensed Consolidated Statement of Financial Position | 15 |
| Condensed Consolidated Statement of Changes in Equity | 16 | |
| Condensed Consolidated Statement of Cash Flows | 17 | |
| Notes | 18 | |
| 03 | Note 1: Accounting principles | 19 |
| Note 2: Revenue | 20 | |
| Note 3: Production expenses | 20 | |
| Note 4: Financial income and expenses | 21 | |
| Note 5: Tax | 22 | |
| Note 6: Earnings per share | 25 | |
| Note 7: Intangible assets | 26 | |
| Note 8: Property, plant and equipment | 27 | |
| Note 9: Trade receivables and other current assets | 28 | |
| Note 10: Inventories | 28 | |
| Note 11: Restricted cash, bank deposits, cash and cash equivalents | 28 | |
| Note 12: Borrowings | 29 | |
| Note 13: Trade payables and other current liabilities | 30 | |
| Note 14: Financial instruments | 31 | |
| Note 15: Asset retirement obligations | 34 | |
| Note 16: Subsequent events | 34 | |
| Alternative performance measures | 36 | |
| 04 | Appendix | 38 |
| Information about BlueNord | 39 | |
First Quarter 2025 Summary
Operational:
- Total production was 29.8 mboepd in the first quarter of which 8.9 mboepd was from the Tyra hub and 20.9 mboepd was from the base assets (Dan, Gorm and Halfdan hubs). This is within the BlueNord's quarterly guidance of 20.0-22.0 mboepd.
- Despite facing operational occurrences and adverse weather conditions during the final stage of the ramp-up to plateau production on Tyra II, significant progress was achieved this quarter. Continuation of ramp-up, and the long-term value and potential of Tyra remains strong.
- Net 2P (Proven and Probable) Reserves for the year end 2024 were 194 mmboe, with a 2P Reserves Replacement Ratio of 189 percent, adding a total of 17mmboe. The primary driver was the successful discovery of the Harald East Middle Jurassic accumulation, which is also expected to extend both the Tyra plateau period and the Harald hub's lifetime.
Financial and Corporate:
- Total revenues of USD 171.1 million in the first quarter compared to USD 192.9 million in the previous quarter.
- EBITDA of USD 79.5 million in the first quarter compared to USD 109.1 million in the previous quarter.
- Cash flow from operating activities before tax of USD 69.9 million in the first quarter and net cash flow from operating activities of USD 54.8 million in the first quarter compared to USD 145.7 million and USD 95.2 million respectively in the previous quarter.
- With Tyra II moving out of the construction phase, the Cash Call Security Agreement (CCSA) with TotalEnergies has been revised. Cash in escrow of USD 140 million plus interest accumulated of 18.4 million has been released and replaced by the issuance of a USD 100 million Letter of Credit (LC) under the RBL facility.
- Total liquidity of USD 684.1 million at the end of the period with cash on balance sheet of USD 414.1 million and undrawn RBL capacity of USD 270.0 million.
- Proposed distribution for the first quarter 2025 of USD 38 million is at 70% of Net cash flow from operating activities. Declaration and payment, in addition to the 2024 distribution of \$215 million, remains subject to the RBL completion test.
- Successfully added commodity hedges in the beginning of the quarter at attractive prices securing future cashflow primarily for 2025 and 2026.
| Financial and operational summary | Unit | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|---|
| Total revenue | USDm | 171.1 | 192.9 | 168.5 | 171.1 | 168.5 |
| EBITDA1) | USDm | 79.5 | 109.1 | 87.7 | 79.5 | 87.7 |
| Adj. EBITDA1) | USDm | 92.0 | 111.7 | 89.2 | 81.0 | 89.2 |
| Result before tax | USDm | (2.3) | (29.8) | 8.1 | (2.3) | 8.1 |
| Net result for the period | USDm | 18.6 | (75.9) | (4.6) | 18.6 | (4.6) |
| Cash flow from operating activities before tax1) | USDm | 69.9 | 145.7 | 88.4 | 69.9 | 88.4 |
| Net Cash flow from operating activities1) | USDm | 54.8 | 95.2 | 76.8 | 54.8 | 76.8 |
| Investments in oil and gas assets | USDm | 14.1 | 63.9 | 64.1 | 14.1 | 64.1 |
| Reserve-based lending facility, drawn | USDm | 880.0 | 880.0 | 850.0 | 880.0 | 850.0 |
| Net interest-bearing debt1) | USDm | 1,013.0 | 1,176.5 | 1,095.7 | 1,013.0 | 1,095.7 |
| Oil production | mboepd | 18.4 | 17.9 | 17.9 | 18.4 | 17.9 |
| Gas production | mboepd | 11.4 | 8.0 | 5.6 | 11.4 | 5.6 |
| Total production | mboepd | 29.8 | 25.9 | 23.5 | 29.8 | 23.5 |
| Over/(under)-lift | mboepd | (3.4) | 2.4 | (1.1) | (3.4) | (1.1) |
| Realised Oil price | USD/boe | 74.9 | 75.0 | 86.0 | 74.9 | 86.0 |
| +/- Effect of hedges | USD/boe | (0.9) | (0.5) | (13.0) | (0.9) | (13.0) |
| Effective Oil price | USD/boe | 74.0 | 74.5 | 73.0 | 74.0 | 73.0 |
| Realised Gas price | EUR/MWh | 40.2 | 39.8 | 25.0 | 40.2 | 25.0 |
| +/- Effect of hedges | EUR/MWh | (1.7) | (0.6) | 35.0 | (1.7) | 35.0 |
| Effective Gas price | EUR/MWh | 38.5 | 39.1 | 60.0 | 38.5 | 60.0 |
1) See the description of 'Alternative performance measures' at the end of this report for definitions.
Financial Review
Financial review continued
| USD million | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|
| Total revenue | 171.1 | 192.9 | 168.5 | 171.1 | 168.5 |
| EBITDA | 79.5 | 109.1 | 87.7 | 79.5 | 87.7 |
| EBIT | 35.3 | 68.9 | 58.5 | 35.3 | 58.5 |
| Result before tax | (2.3) | (29.8) | 8.1 | (2.3) | 8.1 |
| Net result for the period | 18.6 | (75.9) | (4.6) | 18.6 | (4.6) |
| Earnings per share | 0.7 | (2.9) | (0.2) | 0.7 | (0.2) |
Selected data from consolidated statement of comprehensive income
Revenues of USD 171.1 million in the first quarter of 2025 were mainly related to oil and gas sales from the Danish Underground Consortium (DUC) fields. This represents a decrease from the USD 192.9 million revenue in the previous quarter. The change compared to last quarter was mainly due to reduced oil volumes, which fell by 27.7 percent. This were due largely to lower oil production compared to the fourth quarter in addition to the overlift from the previous quarter unwinding. This was partially offset by an increase in gas volumes, which rose by 39.6 percent as a result of Tyra II continuing to ramp up.
Production expenses: In the current quarter USD 89.1 million was directly attributable to the lifting and transport of the Company's oil and gas production, equating to USD 33.2 per boe. This compares to USD 54.4 million in the previous quarter, equating to USD 22.8 per boe. Excluding the adjustment for 'Well & Reservoir Optimisation Management' (WROM) cost in fourth quarter this would have equated to USD 31.0 per boe. The remaining increase in cost per boe is primarily due to workover costs associated with the changed rig schedule as outlined in the operational review. There were no workovers in the previous quarter. The increase was partially offset by higher production volumes compared to last quarter. When adjusted for concept studies, insurance and changes in stock and oil inventory, total production expenses amounted to USD 78.5 million compared to USD 71.9 million in the previous quarter.
Operating result before depreciation, amortisation and impairment (EBITDA) in the first quarter of 2025 was a profit of USD 79.5 million, compared to USD 109.1 million in previous quarter. This decrease is due to the items outlined above.
Net Financial items amounted to an expense of USD 37.6 million for the first quarter of 2025, compared to an expense of USD 98.7 million in the previous quarter. The current quarter was positively influenced by the fair value adjustment of embedded derivatives on BNOR15, compared to a negative effect in the previous quarter. However, this was partly offset by a foreign exchange loss, whereas the previous quarter experienced a foreign exchange gain.
Income tax amounted to an income of USD 20.9 million for the first quarter of 2025 compared to a cost of USD 46.0 million for the previous quarter. The change in income tax is primarily due to currency adjustment on the value of tax losses carried forward in DKK. IFRS requires the tax loss balance to be revalued using the period end exchange rate. Current income tax YTD 2025 amounted to a cost of USD 1.0 million. Deferred tax movements in the quarter amounted to an income of USD 21.9 million. This corresponds to a statutory tax rate of 64 percent on result before tax on hydrocarbon income, adjusted for investment uplift and interest restriction as well as currency adjustment of tax losses carried forward in DKK. Effective 0 percent tax on result before tax in Norway and UK and effective 22 percent tax on result before tax on ordinary income in Denmark.
Net result for the first quarter of 2025 was a profit of USD 18.6 million, compared to USD 75.9 million loss in the previous quarter.
First Quarter Report 2025 5
Selected data from the consolidated statement of financial position
| USD million | 31.03.2025 | 31.12.2024 | 31.03.2024 |
|---|---|---|---|
| Total non-current assets | 2,906.5 | 2,947.5 | 3,080.7 |
| Total current assets | 584.3 | 514.3 | 324.3 |
| Total assets | 3,490.8 | 3,461.8 | 3,404.9 |
| Total equity | 738.8 | 695.6 | 780.7 |
| Interest bearing debt | 1,375.1 | 1,370.9 | 1,205.2 |
| Asset retirement obligations (current and non-current) | 1,137.5 | 1,122.1 | 1,050.3 |
| Derivative Instruments, liabilities | 116.6 | 172.5 | 132.7 |
| Total current liabilities (excluding current asset retirement obligations) | 473.8 | 482.1 | 617.9 |
Total non-current assets amounted to USD 2,906.5 million at the end of the first quarter of 2025, compared to USD 2,947.5 million in the previous quarter. The decrease was mainly due to higher depreciation than capital additions for the DUC investments in property, plant and equipment. Additionally, there was a reduction in deferred tax assets, primarily due to tax depreciation, partly offset by the currency adjustment of the tax losses carried forward in DKK. Offset partly by increased derivatives due to new gas hedges in place. Total non-current assets consist of property, plant and equipment of USD 2.5 billion, intangible assets of USD 143.0 million, deferred tax asset of USD 142.0 million, derivatives related to the oil and gas hedges of USD 9.0 million and USD 64.0 million in restricted cash related to cash pledged as security against Nini/Cecilie abandonment costs.
Total current assets amounted to USD 584.3 million at the end of the first quarter of 2025, compared to USD 514.3 million at the end of the previous quarter. This increase was due to higher trade receivables, tax receivables, prepayments, oil inventories and an increase in the value on derivative instruments mainly due to new gas hedges in place. Additionally, the revision to the CCSA released USD 158.4 million from restricted cash to cash on hand, significantly enhancing our liquidity position. Total current assets consist of USD 414.1 million of cash, USD 64.8 million of stock and oil inventory, USD 44.2 million in trade receivables, mainly related to oil and gas revenue, USD 24.8 million in derivatives related to oil and gas hedges, USD 18.7 million in prepayments mainly related to insurance, USD 16.1 million in tax receivables and USD 1.6 million in other receivables.
Total equity amounted to USD 738.8 million at the end of the first quarter of 2025, compared to USD 695.6 million at the end of the previous quarter. Increase mainly related to positive result and positive fair value adjustment of hedges.
Interest-bearing debt amounted to USD 1.4 billion at the end of the first quarter of 2025, consistent with the previous quarter. The convertible bond loan BNOR15 had a book value of USD 241.7 million at the end of the current quarter. BlueNord's USD 1.4 billion RBL facility, drawn at USD 880.0 million on 31 March 2025, had a book value of USD 836.6 million at the end of the first quarter. The senior unsecured bond loan BNOR16 had a book value of USD 296.9 million at the end of the period. For more information, see note 12.
Asset retirement obligations (current and non-current) amounted to USD 1,137.5 million at the end of the first quarter of 2025, compared to USD 1,122.1 million at the end of the previous quarter. The increase is primarily due to accretion expense for the period. Of the total, USD 1,070.0 million relates to the DUC assets, USD 64.0 million to Nini/Cecilie, USD 1.4 million to Lulita, and USD 2.2 million to the Tyra F-3 pipeline. The Nini/Cecilie obligation is secured through an escrow account of USD 64.0 million.
Total current liabilities (excluding current asset retirement obligation) amounted to USD 473.8 million at the end of first quarter of 2025 compared to USD 482.1 million last quarter. This was mainly related to lower derivatives liabilities as the current quarter was positively influenced by the fair value adjustment of embedded derivatives on BNOR15 and the weakening of gas prices during the quarter. Further, decreased VAT payable and reduced overlift of oil. Partly offset by increase in other current liabilities, trade payable and liabilities to operator. Total current liabilities consist of USD 241.7 million related to the convertible bond loan BNOR15, USD 110.0 million of current derivatives related to embedded derivatives on convertible bond BNOR15 and oil and gas price hedges, USD 36.3 million in liabilities to DUC operator, USD 18.4 million related to VAT payable, USD 46.4 million in accrued costs and USD 20.4 million related to trade payables.
| USD million | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|
| Cash flow from operating activities before tax | 69.9 | 145.7 | 88.4 | 69.9 | 88.4 |
| Net cash flow from operating activities | 54.8 | 95.2 | 76.8 | 54.8 | 76.8 |
| Cash flow used in investing activities | 143.9 | (62.9) | (73.5) | 143.9 | (73.5) |
| Cash flow from financing activities | (35.2) | (22.9) | (12.3) | (35.2) | (12.3) |
| Net change in cash and cash equivalents | 163.5 | 9.4 | (9.0) | 163.5 | (9.0) |
| Cash and cash equivalents | 414.1 | 250.6 | 157.7 | 414.1 | 157.7 |
Selected data from the consolidated statement of cash flows
Net Cash flow from operating activities amounted to USD 54.8 million for the first quarter of 2025, compared to USD 95.2 million for the previous quarter. The decline was due to lower sales of oil only partially offset by higher sales of gas, in addition to higher production costs attributable to workovers (this higher cost is more than offset by lower capex in investing activities below). In addition, net increase in working capital partially offset by lower tax paid. Excluding changes in working capital, net cash flow from operating activities amounted to a cash inflow of USD 66.1 million for the first quarter of 2025, compared to cash inflow of USD 59.2 million in the previous quarter.
Cash flow used in investing activities resulted in an inflow of USD 143.9 million for the quarter, compared to an outflow of USD 62.9 million for the previous quarter. This quarter's inflow includes the release of restricted bank deposits associated with the CCSA revision amounting to a USD 158.4 million inflow. The cash flow used in investing activities was mainly related to investments in the DUC asset, which is down by USD 49.7 million compared to the previous quarter. This includes USD 9.4 million for the Halfdan Gaslift project and WROM, USD 2.3 million for the Tyra reinstatement, USD 2.1 million for Gorm and Dan life time extension projects, and USD 0.3 million for other minor projects.
Cash flow from financing activities amounted to an outflow of USD 35.2 million for the first quarter of 2025, compared to USD 22.9 million for the previous quarter. The cash outflow in the current quarter was related to interest payments for the RBL facility and BNOR16, whereas the previous quarter included only interest for the RBL facility. BNOR16 interest is paid semi-annually.
Net change in cash and cash equivalents amounted to positive USD 163.5 million at the end of the quarter compared to positive USD 9.4 million for the previous quarter. Cash and cash equivalents were in total USD 414.1 million at the end of first quarter 2025.
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 14.4. Further detail on BlueNord's financial risk management is outlined in note 2 to the financial statements in the 2024 Annual Report which is available at www.bluenord.com/reports-and-presentations/.
The table below summarises the quantity of volume hedged and average price at the end of the first quarter.
| Volume hedged oil (boe) |
Average hedged price (\$/bbl) |
Volume hedged gas (MWh) |
Average hedged price (EUR/MWh) |
|
|---|---|---|---|---|
| 2025 | 3,539,001 | 73.5 | 6,434,997 | 42.2 |
| 2026 | 2,700,000 | 71.7 | 5,655,000 | 38.0 |
| 2027 | - | - | 1,095,000 | 36.2 |
Operational Review
Production
Operational review continued
| Key figures | Unit | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|---|
| Dan hub | mboepd | 6.4 | 6.7 | 7.8 | 6.4 | 7.8 |
| Gorm hub | mboepd | 3.1 | 4.8 | 4.0 | 3.1 | 4.0 |
| Halfdan hub | mboepd | 11.4 | 11.5 | 11.9 | 11.4 | 11.9 |
| Tyra hub | mboepd | 8.9 | 2.9 | (0.2) | 8.9 | (0.2) |
| Total production | mboepd | 29.8 | 25.9 | 23.5 | 29.8 | 23.5 |
| Over/(under)-lift | mboepd | (3.4) | 2.4 | (1.1) | (3.4) | (1.1) |
| Net sales | mboepd | 26.4 | 28.3 | 22.4 | 26.4 | 22.4 |
| Oil sales | mboepd | 15.0 | 20.3 | 16.8 | 15.0 | 16.8 |
| Gas sales | mboepd | 11.4 | 8.0 | 5.6 | 11.4 | 5.6 |
| Operational efficiency1) | % | 75.4 % | 88.6 % | 90.2 % | 75.4 % | 90.2 % |
1) Operational efficiency is calculated as: delivered production / (delivered production + planned shortfalls + unplanned shortfalls). Operational efficiency is for the base assets only.
Average production in Q1 2025 was 29.8 mboepd of which 8.9 was from the Tyra hub and 20.9 mboepd was from the base assets (Dan, Gorm and Halfdan hubs). This is within the Q1 guidance of the base assets of 20.0-22.0 mboepd.
Dan hub
In Q1 2025 shortfalls of ca. 0.5 mboepd were experienced on the Dan hub as generator issues caused the Kraka field to be closed in the period 18 January to 9 March. The issues have been resolved, and Kraka production has resumed. On the Dan field, a reactive work-over of the well MFA-14 was completed and the well was handed back to production in early March. The well has not been producing since September 2024 but now contributes to production by ca 0.2 mboepd (net BN). The Dan field has had stable production in Q1.
Gorm hub
After having had very stable production in January, the Gorm hub was shut down for planned maintenance for 10 days in February. As per plan, the hub was partially shut down in the following period, as the planned maintenance work was continued. However, on 12 March a leaking dry gas seal caused the platform to shut down. After changing out of the dry gas seal, production was resumed on 25 March. The Rolf field was closed in for ca. 30 days over January and February due to a generator trip caused by a power cut.
The planned WROM III campaign on Gorm includes 5 interventions and will be performed from the platform in H2 2025. The Noble Reacher rig was initially contracted back in 2022 to address a backlog of maintenance that had accumulated over some years of reduced activity. Over the past 2.5 years, a combination of maintenance and WROM initiatives have significantly reduced this backlog and improved production performance. Moving maintenance and well interventions to platform-based solutions will significantly reduce cost.
Halfdan hub
On Halfdan, the WROM campaign was completed in January 2025. During the campaign, which commenced in January 2024 a total of 21 interventions on 20 wells have been completed. A proactive work-over has been conducted on HDA-37 from the Shelf Drilling Winner rig in January, thereby safeguarding ca 0.25 mboepd (net BN). The Halfdan hub has had stable production in Q1 with OEFF of 90%. The Noble Reacher rig has now been moved to the HCA platform where the installation of HCA gas lift is ongoing.
Tyra hub
Production at the Tyra hub was halted in early January due to a mechanical seal failure on the IP compressor. After replacing the seal, production resumed on 16 January and continued to ramp up through January and February, reaching a to-date maximum export rate of 22.5 mboepd by the end of February. On the Tyra hub there was a breaker failure in the electrical high-voltage system on 4 March. This has caused the production from the Tyra hub to be restricted to the
Harald wells for the remainder of March and early April. The necessary replacement parts were successfully delivered offshore, and installation and testing completed, and Tyra resumed full operational capacity on 9 April. Continuation of production ramp-up is currently ongoing with two walk-to-work vessels for support.
Field Development
Infill drilling
The revised timing of the VUC infill well is a result of the success of the HEMJ well, which has extended the production plateau for Tyra by at least 10 months such that Tyra processing capacity will be fully utilised until at least Q2 2026. The Halfdan infill wells HDA-35 and HDA-31 are proposed to be drilled back-to-back in a campaign just before the VUC well. Drilling these infill wells consecutively will provide direct learning opportunities, optimize drilling operations and reduce time and cost. Further, several rig moves are required for reactive workovers until the drilling campaign kicks off in 2026, making it cost-ineffective to retain the rig during this period. The timeframe in which the drilling campaign is scheduled in 2026 indicates an open market where cost savings are expected to be realised. Based on this, it was decided to release the Shelf Drilling Winner rig. In the five months cancellation period until the rig is released, a Dan FF workover campaign with several high potential opportunities has been included in the work program to be completed by mid-August 2025.
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.
In January 2024 BlueNord acquired 100 percent of the shares in CarbonCuts, an early-stage CCS company in Denmark. BlueNord has been involved since 2022 by providing financial, technical and commercial support for an early-stage feasibility study for onshore CO2 storage. In January 2024 CarbonCuts submitted a licence application to the Danish Energy Agency to explore and store CO2 in the geological Rødby Structure on Lolland with 'Project Ruby'. In June 2024, CarbonCuts was successfully awarded the licence to explore the possibility of a future onshore CO₂ storage facility on the island of Lolland. CarbonCuts expects to begin storage in 2030 or earlier following a successful exploration plan. In March 2025 CarbonCuts applies for an exploration license in the tender for nearshore CO2 storage off the northern part of Jutland's west coast.
For more information on the Company's work, including the work of the ESG Committee, please see the Sustainability section page 38 - 63 and ESG Committee Report on page 77 in the 2024 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 24 of the 2024 Annual Report which is available at www.bluenord.com/reports-andpresentations/. 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
- Project delivery, including Tyra redevelopment project
- Decommissioning estimates
- Financial risks including, commodity prices, foreign currency exposure, access to capital and interest rate risk
- Cyber security
- Changes in environmental and tax legislation, including CO2 emissions costs
Governance and organisation
The number of employees was 50 (equivalent to 45.6 FTE's) at the end of the first quarter, of which 15 employees are related to CarbonCuts.
The governance of BlueNord ASA is described in detail in the section headed 'Governance report' on page 65 - 83 of the 2024 Annual Report which is available at www.bluenord.com/reports-and-presentations/.
Outlook
BlueNord has built a stable business that is underpinned by the Company's position in the DUC. 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.
As a response to the challenges in the European gas markets, BlueNord has together with its partners in the DUC identified several infill well opportunities. Final Investment Decision ('FID') has been taken on two infill wells in the Halfdan area with an expected capital investment of c. USD 13 per boe of reserves, however this will be further defined on sanction.
In a strategic move to optimise operations and reduce costs, the decision has been made to release the Shelf Drilling Winner rig and not extend the Noble Reacher rig. These decisions build on the success of recent initiatives and focus on achieving significant cost savings with minimal impact on our operations. We have updated our 2025 production guidance below for Base Assets to reflect this change. Furthermore, capital expenditure for 2025 is now expected to be around USD 50-60 million.
Tyra significantly enhances BlueNord's production, and the Company expects direct field operating expenditure to decrease below USD 13 per boe in the first full year of production.
With the start-up of Tyra, the Company is for 2025 providing separate production guidance on a quarterly basis for its Base Assets (Halfdan, Dan and Gorm) and Tyra. Plateau production is expected to be reached in May.
Based on the above the Company's Production Guidance is updated below for Q1 2025.
| Guidance 2025 | Unit | Base | Tyra | Total |
|---|---|---|---|---|
| Q1 | mboepd | 20-22 | 17-20 | 37-42 |
| Q2 | mboepd | 20-22 | 20-24 | 40-46 |
| Q3 | mboepd | 21-23 | 26-30 | 47-53 |
| Q4 | mboepd | 21-23 | 26-30 | 47-53 |
BlueNord's policy is to distribute 50-70 percentage of net cash flow from operating activities in shareholder returns for 2024-26. Our policy is to aim for maintaining a meaningful returns profile from 2027 onwards.
Condensed Consolidated Statement of Comprehensive Income
| USD million | Note | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|---|
| Total revenues | 2 | 171.1 | 192.9 | 168.5 | 171.1 | 168.5 |
| Production expenses | 3 | (78.5) | (71.9) | (72.3) | (78.5) | (72.3) |
| Exploration and evaluation expenses | (6.8) | (3.1) | (0.3) | (6.8) | (0.3) | |
| Personnel expenses | (2.9) | (5.5) | (4.3) | (2.9) | (4.3) | |
| Other operating expenses | (3.4) | (3.3) | (3.9) | (3.4) | (3.9) | |
| Total operating expenses | (91.6) | (83.8) | (80.8) | (91.6) | (80.8) | |
| Operating result before depreciation, amortisation and impairment (EBITDA) |
||||||
| Depreciation/amortisation/impairment | 7, 8 | 79.5 (44.2) |
109.1 (40.3) |
87.7 (29.2) |
79.5 (44.2) |
87.7 (29.2) |
| Net operating result (EBIT) | 35.3 | 68.9 | 58.5 | 35.3 | 58.5 | |
| Financial income | 4 | |||||
| Financial expenses | 4 | 20.3 | 9.7 | 7.4 | 20.3 | 7.4 |
| Net financial items | (57.9) (37.6) |
(108.4) (98.7) |
(57.7) (50.3) |
(57.9) (37.6) |
(57.7) (50.3) |
|
| Result before tax (EBT) | (2.3) | (29.8) | 8.1 | (2.3) | 8.1 | |
| Income tax benefit/(expense) | 5 | 20.9 | (46.0) | (12.7) | 20.9 | (12.7) |
| Net result for the period1) | 18.6 | (75.9) | (4.6) | 18.6 | (4.6) | |
| Other comprehensive income: Items that are or may be subsequently reclassified to profit or loss: |
||||||
| Realised cash flow hedge revenue | 14 | 5.8 | (1.4) | (14.8) | 5.8 | (14.8) |
| Realised cash flow hedge financial items | 14 | - | - | (10.2) | - | (10.2) |
| Related tax - realised cash flow hedge | 5, 14 | (3.7) | 0.9 | 11.7 | (3.7) | 11.7 |
| Changes in fair value cash flow hedge revenue | 14 | 56.3 | (72.7) | (42.4) | 56.3 | (42.4) |
| Changes in fair value cash flow hedge financial items | 14 | - | (1.2) | 0.6 | - | 0.6 |
| Related tax - changes in fair value cash flow hedge | 5, 14 | (36.0) | 46.8 | 27.0 | (36.0) | 27.0 |
| Currency translation adjustment | 1.6 | (3.5) | (1.1) | 1.6 | (1.1) | |
| Total other comprehensive income | 24.0 | (31.1) | (29.2) | 24.0 | (29.2) | |
| Total comprehensive income1) | 42.6 | (107.0) | (33.8) | 42.6 | (33.8) | |
| Basic earnings/(loss) USD per share | 6 | 0.7 | (2.9) | (0.2) | 0.7 | (0.2) |
| Diluted earnings/(loss) USD per share | 6 | 0.4 | (2.9) | (0.2) | 0.4 | (0.2) |
| Weighted average no. of shares outstanding, basic | 26,498,640 | 26,498,640 | 26,105,328 | 26,498,640 | 26,105,328 | |
| Weighted average no. of shares outstanding, diluted | 31,302,525 | 31,302,525 | 30,925,657 | 31,302,525 | 30,925,657 |
1) 100 percent attributable to equity holders of the parent company.
Condensed Consolidated Statement of Financial Position
| USD million | Note | 31.03.2025 | 31.12.2024 | 31.03.2024 |
|---|---|---|---|---|
| Non-current assets | ||||
| Intangible assets | 7 | 143.0 | 147.0 | 152.3 |
| Deferred tax assets | 5 | 142.0 | 159.8 | 245.1 |
| Property, plant and equipment | 8 | 2,547.2 | 2,573.0 | 2,464.5 |
| Right of Use asset | 1.3 | 1.5 | 1.3 | |
| Restricted bank deposits | 11, 14 | 64.0 | 61.5 | 214.4 |
| Derivative instruments | 14 | 9.0 | 4.8 | 3.1 |
| Total non-current assets | 2,906.5 | 2,947.5 | 3,080.7 | |
| Current assets | ||||
| Derivative instruments | 14 | 24.8 | 9.5 | 39.3 |
| Tax receivables | 5 | 16.1 | 2.2 | - |
| Trade receivables and other current assets | 9 | 64.4 | 39.0 | 64.3 |
| Inventories | 10 | 64.8 | 55.8 | 62.9 |
| Restricted cash and bank deposits | 11, 14 | 0.1 | 157.3 | 0.1 |
| Cash and cash equivalents | 11 | 414.1 | 250.6 | 157.7 |
| Total current assets | 584.3 | 514.3 | 324.3 | |
| Total assets | 3,490.8 | 3,461.8 | 3,404.9 | |
| Equity | ||||
| Share capital | 1.7 | 1.7 | 1.7 | |
| Other equity | 737.1 | 693.9 | 779.0 | |
| Total equity | 738.8 | 695.6 | 780.7 | |
| Non-current liabilities | ||||
| Asset retirement obligations | 15 | 1,126.4 | 1,110.6 | 1,043.9 |
| Bond loan | 12, 14 | 296.9 | 303.5 | 173.6 |
| Reserve-based lending facility | 12, 14 | 836.6 | 834.3 | 697.5 |
| Derivative instruments | 14 | 6.6 | 23.0 | 84.0 |
| Other non-current liabilities | 0.7 | 1.1 | 1.0 | |
| Total non-current liabilities | 2,267.1 | 2,272.7 | 2,000.0 | |
| Current liabilities | ||||
| Convertible bond loan | 12, 14 | 241.7 | 233.1 | 209.2 |
| Reserve-based lending facility | 12, 14 | - | - | 125.0 |
| Asset retirement obligations | 15 | 11.1 | 11.4 | 6.3 |
| Tax payable | 5 | - | 0.1 | 129.2 |
| Derivative instruments | 14 | 110.0 | 149.5 | 48.8 |
| Trade payables and other current liabilities | 13 | 122.1 | 99.4 | 105.8 |
| Total current liabilities | 484.9 | 493.5 | 624.2 | |
| Total liabilities | 2,752.0 | 2,766.1 | 2,624.2 | |
| Total equity and liabilities | 3,490.8 | 3,461.8 | 3,404.9 |
Condensed Consolidated Statement of Changes in Equity
| Share | Treasury | Currency | Cash flow | ||||
|---|---|---|---|---|---|---|---|
| Share | premium | share | translation | hedge | Other | Total | |
| USD million | capital | fund | reserve | reserve | reserve | equity | equity |
| 2024 | |||||||
| Equity as of 01.01.2024 | 1.7 | 782.9 | (0.1) | 2.0 | 24.9 | 2.2 | 813.6 |
| Net result for the period restated | (4.6) | (4.6) | |||||
| Other comprehensive income | |||||||
| Realised cash flow hedge revenue | - | - | - | - | (14.8) | - | (14.8) |
| Realised cash flow hedge financial items | - | - | - | - | (10.2) | - | (10.2) |
| Related tax - realised cash flow hedge | - | - | - | - | 11.7 | - | 11.7 |
| Changes in fair value cash flow hedge revenue | - | - | - | - | (42.4) | - | (42.4) |
| Changes in fair value cash flow hedge financial items | - | - | - | - | 0.6 | - | 0.6 |
| Related tax - changes in fair value cash flow hedge | - | - | - | - | 27.0 | - | 27.0 |
| Currency translation adjustments | - | - | - | (1.1) | - | - | (1.1) |
| Total other comprehensive income | - | - | - | (1.1) | (28.1) | - | (29.2) |
| Share-based incentive programme | - | - | - | - | - | 0.8 | 0.8 |
| Total transactions with owners for the period | - | - | - | - | - | 0.8 | 0.8 |
| Equity as of 31.03.2024 | 1.7 | 782.9 | (0.1) | 0.9 | (3.2) | (1.6) | 780.7 |
2025
| Equity as of 01.01.2025 | 1.7 | 787.2 | - | (1.0) | (26.3) | (65.9) | 695.6 |
|---|---|---|---|---|---|---|---|
| Net result for the period | 18.6 | 18.6 | |||||
| Realised cash flow hedge revenue | |||||||
| Realised cash flow hedge revenue | - | - | - | - | 5.8 | - | 5.8 |
| Related tax - realised cash flow hedge | - | - | - | - | (3.7) | - | (3.7) |
| Changes in fair value cash flow hedge revenue | - | - | - | - | 56.3 | - | 56.3 |
| Related tax - changes in fair value cash flow hedge | - | - | - | - | (36.0) | - | (36.0) |
| Currency translation adjustments | - | - | - | 1.6 | - | - | 1.6 |
| Total other comprehensive income | - | - | - | 1.6 | 22.4 | - | 24.0 |
| Share-based incentive programme | - | - | - | - | - | 0.6 | 0.6 |
| Total transactions with owners for the period | - | - | - | - | - | 0.6 | 0.6 |
| Equity as of 31.03.2025 | 1.7 | 787.2 | - | 0.6 | (4.0) | (46.7) | 738.8 |
Condensed Consolidated Statement of Cash Flows
| USD million | Note | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|---|
| Cash flows from operating activities | ||||||
| Net result for the period | 18.6 | (75.9) | (4.6) | 18.6 | (4.6) | |
| Adjustments for: | ||||||
| Income tax (benefit)/expense | 5 | (20.9) | 46.0 | 12.7 | (20.9) | 12.7 |
| Net financial items | 4 | 37.6 | 98.7 | 50.3 | 37.6 | 50.3 |
| Depreciation/impairment | 8 | 44.2 | 40.3 | 29.2 | 44.2 | 29.2 |
| Share-based payments expenses | 0.6 | (0.2) | 0.8 | 0.6 | 0.8 | |
| Interest received1) | 4 | 1.8 | 0.9 | 1.8 | 1.8 | 1.8 |
| Other financial items paid | (0.8) | (0.2) | 0.0 | (0.8) | 0.0 | |
| Changes in: | ||||||
| Trade receivable | 9 | (16.2) | (0.1) | 17.5 | (16.2) | 17.5 |
| Trade payables | 13 | 28.4 | 16.3 | (19.9) | 28.4 | (19.9) |
| Inventories and spare parts | 10 | (9.0) | 4.7 | (8.2) | (9.0) | (8.2) |
| Prepayments | 9 | (9.2) | 2.8 | 4.6 | (9.2) | 4.6 |
| Over/(under-lift) | 9 | (5.8) | 9.4 | 2.4 | (5.8) | 2.4 |
| Other current balance sheet items2) | 0.5 | 2.9 | 1.7 | 0.5 | 1.7 | |
| Cash flow from operating activities before tax | 69.9 | 145.7 | 88.4 | 69.9 | 88.4 | |
| Tax paid | (15.0) | (50.4) | (11.5) | (15.0) | (11.5) | |
| Net cash flow from operating activities | 54.8 | 95.2 | 76.8 | 54.8 | 76.8 | |
| Cash flows from investing activities | ||||||
| Acquisition of subsidiary, net of cash acquired | - | - | 1.5 | - | 1.5 | |
| Investment in oil and gas assets | 8 | (14.1) | (63.9) | (64.1) | (14.1) | (64.1) |
| Investment in exploration & evaluation assets | - | 0.4 | (0.0) | - | (0.0) | |
| Payments for decommissioning of oil and gas fields | (0.4) | 0.5 | (10.9) | (0.4) | (10.9) | |
| Changes in restricted cash accounts | 158.4 | - | - | 158.4 | - | |
| Net cash flow from investing activities | 143.9 | (62.9) | (73.5) | 143.9 | (73.5) | |
| Cash flows from financing activities | ||||||
| Lease payments | (0.1) | (0.1) | (0.1) | (0.1) | (0.1) | |
| Interests and fees external loan | (35.0) | (22.8) | (12.2) | (35.0) | (12.2) | |
| Net cash flow from financing activities | (35.2) | (22.9) | (12.3) | (35.2) | (12.3) | |
| Net change in cash and cash equivalents | 163.5 | 9.4 | (9.0) | 163.5 | (9.0) | |
| Cash and cash equivalents at the start of the period | 250.6 | 241.2 | 166.7 | 250.6 | 166.7 | |
| Cash and cash equivalents at end of the period | 414.1 | 250.6 | 157.7 | 414.1 | 157.7 |
1) Excluding interest received from cash call security account as these interests are added to the cash call security account, hence not available cash.
2) Mainly currency adjustments balance sheet items.
First Quarter Report 2025 17
First Quarter Report 2025 18
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 31 March 2025 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 financial 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 approved by the Board of Directors on 6 May 2025.
Going concern
The Board of Directors confirms that the interim financial statements have been prepared under the presumption of going concern, and that this is the basis for the preparation of these interim financial statements. 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 are prepared using the same accounting principles as the annual financial statements for 2024. In addition, due to the amendments to IAS 1 Presentation of Financial Statements, effective from 1.1.2024, the classification of the convertible bond loan has been reclassified/ assessed (el.) to short-term liabilities
For the full summary of significant accounting policies, reference is made to the annual financial statements for 2024.
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.
2 Revenue
| USD million | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|
| Sales of oil | 100.1 | 139.4 | 111.4 | 100.1 | 111.4 |
| Sales of gas and NGL | 70.2 | 52.4 | 56.3 | 70.2 | 56.3 |
| Other income | 0.9 | 1.1 | 0.8 | 0.9 | 0.8 |
| Total revenue | 171.1 | 192.9 | 168.5 | 171.1 | 168.5 |
| Sales of oil (mmbbl) | 1.35 | 1.87 | 1.53 | 1.35 | 1.53 |
| Effective Oil price USD/bbl | 74.0 | 74.5 | 73.0 | 74.0 | 73.0 |
| Sales of gas (mmboe) | 1.02 | 0.73 | 0.51 | 1.02 | 0.51 |
| Effective gas price EUR/MWh | 38.5 | 39.1 | 60.0 | 38.5 | 60.0 |
| Effective gas price USD/boe | 68.5 | 71.4 | 110.3 | 68.5 | 110.3 |
During the first quarter, most of BlueNord's settlement of prices 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.
3 Production expenses
| USD million | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|
| Direct field opex | (63.3) | (37.3) | (52.2) | (63.3) | (52.2) |
| Tariff and transportation expenses | (19.1) | (13.7) | (9.8) | (19.1) | (9.8) |
| Environmental costs | (4.8) | (1.9) | (4.1) | (4.8) | (4.1) |
| Production general and administrative | (1.9) | (1.5) | (4.8) | (1.9) | (4.8) |
| Field operating cost | (89.1) | (54.4) | (70.9) | (89.1) | (70.9) |
| Total produced volumes (mmboe) | 2.7 | 2.4 | 2.1 | 2.7 | 2.1 |
| In USD per boe | (33.2) | (22.8) | (33.2) | (33.2) | (33.2) |
| Adjustments for: | |||||
| Concept studies | (0.2) | (1.3) | (0.3) | (0.2) | (0.3) |
| Change in inventory position | 10.7 | (0.9) | 6.8 | 10.7 | 6.8 |
| Change in (over)/under-lift of oil and NGL | 5.8 | (9.4) | (2.4) | 5.8 | (2.4) |
| Insurance & other | (5.5) | (5.0) | (5.4) | (5.5) | (5.4) |
| Stock scrap | (0.2) | (0.9) | (0.1) | (0.2) | (0.1) |
| Production expenses | (78.5) | (71.9) | (72.3) | (78.5) | (72.3) |
Production expenses for the first quarter, directly attributable to BlueNord's oil and gas production, totalled USD 89.1 million. This is an increase from USD 54.4 million in the previous quarter. Excluding the adjustment for 'Well & Reservoir Optimisation Management' (WROM) cost in fourth quarter 2024 this would have equated to USD 73.7 million. The remaining increase in field operating costs for the quarter relates to well workovers on the Dan and Halfdan fields (whereas the fourth quarter 2024 had no well workover costs), as well as increased transportation cost attributable to increased gas production at Tyra. Additionally, environmental costs are higher due to the fourth quarter 2024 including a full year true up and CO2 emission duties in Denmark effective from January 1, 2025, increasing costs marginally in first quarter.
The production cost equates to USD 33.2 per boe produced during the period compared to USD 22.8 per boe in Q4 2024. The increase in cost this quarter is primarily due to the aforementioned factors.
4 Financial income and expenses
Financial income
| USD million | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|
| Total interest income | 3.0 | 3.8 | 3.8 | 3.0 | 3.8 |
| Value adjustment embedded derivatives1) | 13.4 | - | - | 13.4 | - |
| Value adjustment foreign exchange contract | - | 0.6 | - | - | - |
| Realised gain interest swap RBL, ineffective part | - | - | 0.0 | - | 0.0 |
| Foreign exchange gains | 3.9 | 5.3 | 3.6 | 3.9 | 3.6 |
| Total other financial income | 17.3 | 5.9 | 3.6 | 17.3 | 3.6 |
Financial expenses
| USD million | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|
| Interest expenses current liabilities | (0.1) | (0.2) | (0.0) | (0.1) | (0.0) |
| Interest expense from bond loans | (16.2) | (15.8) | (11.9) | (16.2) | (11.9) |
| Interest expense from bank debt2) | (22.5) | (23.9) | (14.0) | (22.5) | (14.0) |
| Total interest expenses | (38.9) | (39.9) | (25.9) | (38.9) | (25.9) |
| Value adjustment embedded derivatives1) | - | (54.2) | (16.5) | - | (16.5) |
| Accretion expense related to asset retirement obligations | (13.3) | (13.7) | (13.5) | (13.3) | (13.5) |
| Foreign exchange losses | (5.1) | 0.1 | (1.1) | (5.1) | (1.1) |
| Other financial expenses | (0.6) | (0.7) | (0.6) | (0.6) | (0.6) |
| Total other financial expenses | (19.0) | (68.5) | (31.8) | (19.0) | (31.8) |
| Net financial items | (37.6) | (98.7) | (50.3) | (37.6) | (50.3) |
1) Fair value adjustment of the embedded derivatives of the BNOR15 convertible bonds.
2) Net of effective part of realised interest swap, related to RBL facility.
5 Tax
Tax rates
Producers of oil and gas on the Danish Continental Shelf are subject to the hydrocarbon tax regime under which, income derived from the sale of oil and gas is taxed at an elevated 64 percent. Any income deriving from other activities than firsttime sales of hydrocarbons is taxed at the ordinary corporate income rate of currently 22 percent. The 64 percent is calculated as the sum of the 'Chapter 2' tax of 25 percent plus a specific hydrocarbon tax (chapter 3A) of 52 percent, in which the 25 percent tax payable is deductible. Income generated in Norway and United Kingdom is subject to regular corporate tax at 22 percent.
Tax expense
USD million
| Income tax in profit/loss (Danish corporate income tax and hydrocarbon tax) |
Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|
| Current tax | (1.0) | 4.5 | (2.7) | (1.0) | (2.7) |
| Repayment of tax benefit related to chapter 3b | |||||
| Current tax, prior year | - | - (0.4) |
- | - | |
| Current tax | - (1.0) |
4.2 | - (2.7) |
- (1.0) |
- (2.7) |
| Deferred tax | 21.9 | (52.1) | (10.1) | 21.9 | (10.1) |
| Deferred tax, prior year | 1.8 | ||||
| Deferred tax | - 21.9 |
(50.2) | - (10.1) |
- 21.9 |
- (10.1) |
| Tax (expense)/ income | 20.9 | (46.0) | (12.7) | 20.9 | (12.7) |
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 percent hydrocarbon tax.
Tax (expense)/income related to OCI
| Cash flow hedges | (39.7) | 47.6 | 38.7 | (39.7) | 38.7 |
|---|---|---|---|---|---|
| Tax (expense)/income related to OCI | (39.7) | 47.6 | 38.7 | (39.7) | 38.7 |
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.
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 percent hydrocarbon tax.
| Hydrocarbon tax 64% | Corporate tax 22% | ||||
|---|---|---|---|---|---|
| Reconciliation of nominal to actual tax rate: | Q1 2025 | Q1 2025 | In total | ||
| Result before tax | (1.9) | (0.4) | (2.3) | ||
| Expected tax on profit before tax | (1.2) | 64% | (0.1) | 22% | (1.3) |
| Tax effect of: | |||||
| Currency changes to tax losses carried forward in DKK 2) | (16.6) | 880% | - | 0% | (16.6) |
| Investment uplift on capex projects 3) | (7.8) | 415% | - | 0% | (7.8) |
| Permanent differences 4) | - | 0% | (2.5) | 619% | (2.5) |
| Interest limitation | 5.9 | -311% | - | 0% | 5.9 |
| No recognition of tax assets in Norway and UK | - | 0% | 1.4 | -364% | 1.4 |
| Tax expense (income) in profit/loss | (19.8) | 1048% | (1.1) | 277% | (20.9) |
| YTD 2025 | YTD 2025 | In total | ||||
|---|---|---|---|---|---|---|
| Result before tax | (1.9) | (0.4) | (2.3) | |||
| Expected tax on profit before tax | (1.2) | 64% | (0.1) | 22% | (1.3) | |
| Tax effect of: | ||||||
| Currency changes to tax losses carried forward in DKK 2) | (16.6) | 880% | - | 0% | (16.6) | |
| Investment uplift on capex projects 3) | (7.8) | 415% | - | 0% | (7.8) | |
| Permanent differences 4) | - | 0% | (2.5) | 619% | (2.5) | |
| Interest limitation | 5.9 | -311% | - | 0% | 5.9 | |
| No recognition of tax assets in Norway and UK | - | 0% | 1.4 | -364% | 1.4 | |
| Tax expense (income) in profit/loss | (19.8) | 1048% | (1.1) | 277% | (20.9) | |
| Q1 2025 | Q1 2025 | In total | ||||
| OCI before tax | 62.1 | 1.6 | 63.8 | |||
| Expected tax on OCI before tax | (39.7) | 64% | (0.4) | 22% | (40.1) | |
| Tax effect of: | ||||||
| Non-taxable currency translation adjustment | - | 0.4 | 0.4 | |||
| Tax in OCI | (39.7) | 64% | (0.0) | 22% | (39.7) | |
| YTD 2025 | YTD 2025 | In total | ||||
| OCI before tax | 62.1 | 1.6 | 63.8 | |||
| Expected tax on OCI before tax | (39.7) | 64% | (0.4) | 22% | (40.1) | |
| Tax effect of: | ||||||
| Non-taxable currency translation adjustment | - | 0.4 | 0.4 | |||
| Tax in OCI | (39.7) | 64% | (0.0) | 22% | (39.7) |
2) Impact of changes in USD/DKK exchange rate on loss carried forward as the tax losses are carried forward in DKK.
3) The tax cost in the hydrocarbon tax regime is positively impacted by the 39 percent investment uplift on the Tyra Redevelopment project. 4) Mainly related to fair value adjustment of embedded derivatives.
| Current income tax receivables/(payables) | 31.12.2024 | 31.03.2025 |
|---|---|---|
| Corporate tax 22% (Denmark) | (0.8) | (1.9) |
| Hydrocarbon tax (Denmark) | 11.5 | 26.5 |
| Hydrocarbon tax for prior years (Denmark) | (8.6) | (8.6) |
| Tax receivables/(payables) | 2.2 | 16.1 |
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 more likely than not. Tax receivables of USD 16.1 million, which includes USD 11.5 million actual cash receivables to be refunded in 2025, USD 14.0 in prepayment of tax for income year 2025 and USD 9.4 million in provision for uncertain tax positions.
A Danish subsidiary in the group is involved in a tax case raised by the Danish Tax Authorities (Skattestyrelsen) regarding the transfer price of assets between group entities in the financial year 2019. The outcome of this case is currently not known and there are multiple scenarios that could lead to different tax treatments that affect the years from 2019 onwards as temporary differences. In accordance with the Group's accounting policies, no provision has been recognised to date.
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 | Effect recognised |
Effect recognised |
||
|---|---|---|---|---|
| Deferred tax and deferred tax asset | 31.12.2024 | in P&L | in OCI | 31.03.2025 |
| Property, plant and equipment | 1,061.2 | (1.4) | 1,059.8 | |
| Intangible assets, licences | 14.7 | (2.1) | - | 12.6 |
| Inventories and receivables | 32.5 | 4.3 | - | 36.8 |
| Asset retirement obligation (ARO) | (671.1) | (7.1) | - | (678.1) |
| Other assets and liabilities | (5.6) | (9.6) | - | (15.2) |
| Tax loss carryforward, corporate tax (22%) | 6.5 | - | 6.5 | |
| Tax loss carryforward, chapter 2 tax (25%) | - (31.3) |
19.1 | - | (12.1) |
| Tax loss carryforward, chapter 3a tax (52%) | (560.2) | (31.8) | - 39.7 |
(552.2) |
| Deferred tax asset, net | (159.8) | (21.9) | 39.7 | (142.0) |
9
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 | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|
| Profit (loss) from operations attributable to ordinary shareholders |
18.6 | (75.9) | (4.6) | 18.6 | (4.6) |
| Adjustment amortisation of convertible bond loan | 8.6 | 8.2 | 7.4 | 8.6 | 7.4 |
| Adjustment fair value of embedded derivatives | (13.4) | 54.2 | 16.5 | (13.4) | 16.5 |
| Profit (loss) from operations basis for fully diluted shareholders |
13.8 | (13.5) | 19.3 | 13.8 | 19.3 |
| Number of shares outstanding at the beginning of the period |
26,498,640 | 26,498,640 | 26,105,328 | 26,498,640 | 26,105,328 |
| Number of shares outstanding at the end of the period |
26,498,640 | 26,498,640 | 26,105,328 | 26,498,640 | 26,105,328 |
| Weighted average number of shares (basic) | 26,498,640 | 26,498,640 | 26,105,328 | 26,498,640 | 26,105,328 |
| Adjustment convertible bond loan 1) | 4,803,885 | 4,803,885 | 4,441,461 | 4,803,885 | 4,441,461 |
| Adjustment option schemes | - | - | 378,868 | - | 378,868 |
| Weighted average number of shares (diluted) | 31,302,525 | 31,302,525 | 30,925,657 | 31,302,525 | 30,925,657 |
| Earnings per share in USD | 0.7 | (2.9) | (0.2) | 0.7 | (0.2) |
| Earnings per share in USD diluted | 0.4 | (2.9) | (0.2) | 0.4 | (0.2) |
1) The BNOR15 convertible bond loan is converted to number of shares by dividing the principal amount at period end (USD 247.1 million, current quarter) with the strike price (51.43 USD/ share, current quarter) as this is less favourable compared to the conversion price (61.37 USD/share). The conversion price is 99 percent of the volume-weighted average price (VWAP) for the last 20 days (654.1 NOK/share) converted to USD by using the closing rate at period end (10.55 NOK/USD).
7 Intangible assets
| Capitalised exploration |
||||
|---|---|---|---|---|
| USD million | expenditures | Licence | Goodwill | Total |
| Book value 31.12.23 | 1.9 | 149.7 | - | 151.6 |
| Acquisition costs 31.12.23 | 1.9 | 186.0 | - | 187.9 |
| Additions | - | - | 2.2 | 2.2 |
| Currency translation adjustment | - | - | (0.1) | (0.1) |
| Acquisition costs 31.12.2024 | 1.9 | 186.0 | 2.1 | 190.0 |
| Depreciation and write-downs 31.12.23 | - | (36.3) | - | (36.3) |
| Depreciation/amortisation | - | (6.7) | - | (6.7) |
| Depreciation and write-downs 31.12.2024 | - | (43.0) | - | (43.0) |
| Book value 31.12.2024 | 1.9 | 143.0 | 2.1 | 147.0 |
| Acquisition costs 31.12.2024 | 1.9 | 186.0 | 2.1 | 190.0 |
| Additions | - | - | - | - |
| Currency translation adjustment | - | - | 0.1 | 0.1 |
| Acquisition costs 31.03.2025 | 1.9 | 186.0 | 2.2 | 190.1 |
| Depreciation and write-downs 31.12.2024 | - | (43.0) | - | (43.0) |
| Depreciation/write-down/amortisation | - | (1.9) | (2.2) | (4.1) |
| Depreciation and write-downs 31.03.2025 | - | (44.9) | (2.2) | (47.1) |
| Book value 31.03.2025 | 1.9 | 141.1 | - | 143.0 |
On the CarbonCuts cash-generating unit (CGU), the Group recognized a goodwill of USD 2.2 million in Q1 2024 from the acquisition of CarbonCuts. As of March 31, 2025, the entire goodwill arising from the acquisition has been impaired. This decision is driven by uncertainty surrounding the future business prospects and early-stage nature of the project as well as market conditions for CO2 storage that are still to mature.
8 Property, plant and equipment
| USD million | Asset under construction |
Production facilities |
Other assets |
Total |
|---|---|---|---|---|
| Book value 31.12.23 | 1,422.8 | 1,003.7 | 1.4 | 2,427.9 |
| Acquisition costs 31.12.23 | 1,422.8 | 1,491.5 | 3.1 | 2,917.4 |
| Reclassification from AUC to production facilities | (1,401.5) | 1,401.5 | - | - |
| Additions | 31.3 | 185.5 | 0.1 | 216.9 |
| Reclassifications from opex to capex | - | 19.4 | - | 19.4 |
| Revaluation abandonment assets | - | 37.1 | - | 37.1 |
| Acquisition of subsidiary | - | - | 0.0 | 0.0 |
| Sale of assets | - | - | (0.0) | (0.0) |
| Disposals | - | - | (0.0) | (0.0) |
| Currency translation adjustment | - | (0.1) | (0.1) | (0.2) |
| Acquisition costs 31.12.24 | 52.6 | 3,135.0 | 3.1 | 3,190.7 |
| Depreciation and write-downs 31.12.23 | - | (487.9) | (1.7) | (489.5) |
| Depreciation | - | (127.0) | (0.2) | (127.2) |
| Depreciation of capitalized borrowing cost | - | (1.1) | - | (1.1) |
| Acquisition of subsidiary | - | - | (0.0) | (0.0) |
| Sale of asset, reversal depreciation | - | - | 0.0 | 0.0 |
| Disposals | - | - | 0.0 | 0.0 |
| Currency translation adjustment | - | 0.0 | 0.0 | 0.1 |
| Depreciation and write-downs 31.12.24 | - | (615.9) | (1.9) | (617.7) |
| Book value 31.12.24 | 52.6 | 2,519.1 | 1.3 | 2,573.0 |
| Acquisition costs 31.12.24 | 52.6 | 3,135.0 | 3.1 | 3,190.7 |
| Additions | 4.0 | 10.1 | 0.1 | 14.1 |
| Revaluation abandonment assets | - | 0.1 | - | 0.1 |
| Currency translation adjustment | - | 0.1 | 0.0 | 0.1 |
| Acquisition costs 31.03.25 | 56.6 | 3,145.2 | 3.2 | 3,205.1 |
| Depreciation and write-downs 31.12.24 | - | (615.9) | (1.9) | (617.7) |
| Depreciation | - | (38.0) | (0.1) | (38.0) |
| Depreciation of capitalized borrowing cost | - | (2.1) | - | (2.1) |
| Currency translation adjustment | - | (0.0) | (0.0) | (0.0) |
| Depreciation and write-downs 31.03.25 | - | (655.9) | (1.9) | (657.9) |
| Book value 31.03.25 | 56.6 | 2,489.3 | 1.3 | 2,547.2 |
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 first quarter 2025 related to property, plant and equipment. See note 1.7 in the Annual Report 2024 for the accounting policies related to impairment of non-financial assets.
9 Trade receivables and other current assets
| USD million | 31.03.2025 | 31.12.2024 | 31.03.2024 |
|---|---|---|---|
| Trade receivables | 44.2 | 27.9 | 42.4 |
| Under-lift of oil/NGL | - | - | 0.2 |
| Prepayments | 18.7 | 9.5 | 20.3 |
| Other receivables | 1.6 | 1.6 | 1.5 |
| Total trade receivables and other current receivables | 64.4 | 39.0 | 64.3 |
10 Inventories
9
| USD million | 31.03.2025 | 31.12.2024 | 31.03.2024 |
|---|---|---|---|
| Product inventory, oil | 24.4 | 13.7 | 21.8 |
| Other stock (spares & consumables) | 40.4 | 42.1 | 41.1 |
| Total inventories | 64.8 | 55.8 | 62.9 |
11 Restricted bank accounts, cash and cash equivalents
| USD million | 31.03.2025 | 31.12.2024 | 31.03.2024 |
|---|---|---|---|
| Non-current assets | |||
| Restricted bank deposits pledged as security for abandonment obligation related to Nini/Cecilie |
64.0 | 61.5 | 62.9 |
| Restricted bank deposits pledged as security for cash call obligations towards TotalEnergies1) |
- | - | 151.5 |
| Total non-current restricted bank deposits | 64.0 | 61.5 | 214.4 |
| Current assets | |||
| Unrestricted cash and cash equivalents | 414.1 | 250.6 | 157.7 |
| Restricted bank deposits pledged as security for cash call obligations towards TotalEnergies1) |
- | 157.2 | - |
| Restricted bank deposits2) | 0.1 | 0.1 | 0.1 |
| Total current cash and cash equivalents | 414.2 | 407.9 | 157.8 |
| Total bank deposits | 478.1 | 469.4 | 372.2 |
1) BlueNord made a USD 140 million bank deposit into a security account to secure future requests for anticipated payments related to capital and operating expenditures in accordance with the security agreement with TotalEnergies E&P Denmark A/S as operator of the DUC. As of the first quarter of 2025, the Cash Call Security Agreement (CCSA) has been terminated. The termination process involved the release of the Cash Call Security Account and the issuance of a \$100 million Letter of Credit (LC).
2) Tax Withholding Account.
12 Borrowings
| 31.03.2025 | 31.12.2024 | 31.03.2024 | ||||
|---|---|---|---|---|---|---|
| USD million | Principal amount |
Book value |
Principal amount |
Book value |
Principal amount |
Book value |
| BNOR16 senior unsecured bond 1) | 300.0 | 296.9 | 300.0 | 303.5 | - | - |
| BNOR14 senior unsecured bond 2) | - | - | - | - | 175.0 | 173.6 |
| Total non-current bonds | 300.0 | 296.9 | 300.0 | 303.5 | 175.0 | 173.6 |
| Reserve-based lending facility 3) | 880.0 | 836.6 | 880.0 | 834.3 | 725.0 | 697.5 |
| Total non-current debt | 880.0 | 836.6 | 880.0 | 834.3 | 725.0 | 697.5 |
| BNOR15 convertible bond 4) | 247.1 | 241.7 | 247.1 | 233.1 | 228.4 | 209.2 |
| Reserve-based lending facility 3) | - | - | - | - | 125.0 | 125.0 |
| Total current debt | 247.1 | 241.7 | 247.1 | 233.1 | 353.4 | 334.2 |
| Total borrowings | 1,427.1 | 1,375.1 | 1,427.1 | 1,370.9 | 1,253.4 | 1,205.2 |
Note: Book values reported on the basis of amortised cost for BNOR16 (BNOR14 called upon in June 2024), the reserve-based lending facility and the convertible bond loan element of BNOR15.
- 1) The Company issued a senior unsecured bond of USD 300 million 2 July 2024, with a maturity in July 2029. The bond carries an interest of 9.5 per cent p.a., payable semi-annually. The BNOR16 bond has been used to redeem the BNOR14 bond and for other general corporate purposes.
- 2) As at 14 June 2024, the Company exercised the call option to redeem all of BNOR14 at 110.00131 percentage (plus accrued unpaid interests on the redeemed amount) on 02 July 2024.
- 3) The Company completed the amendment and restatement of its USD 1.1 billion reserve-based lending facility and entered into an amended and increased reserve-based lending Facility in Q2 2024. The facility has a five and a half-year tenor with a maximum limit of USD 1.4 billion (an increase of USD 300 million), with a maximum of USD 1.15 billion available for cash drawdown by the Company. Interest is accrued on the drawn amount with an interest rate comprising the aggregate of SOFR and 4.0 percent per annum margin. The current capital outstanding is USD 880 million at Q1 2025.
- 4) The Company issued a convertible bond loan of USD 207.6 million in December 2022, with a five-year tenor and a mandatory conversion to equity or cash settlement after three years (31 December 2025). BNOR15 is made up of a transfer from BNOR13 of USD 151.4 million plus additional compensation bonds of USD 56.2 million. The lender was granted a right to convert the loan into new shares in the Company by way of set-off against the claim on the Company. The loan carries an interest of 8 percent p.a. on a PIK basis, with an alternative option for the Company to pay cash interest at 6 percent p.a., payable semi-annually. Conversion price of USD 51.4307 per share. In 2023 USD 0.1 million was converted into equity. No capital movements were recorded in 2024 or 2025. For more information on the bond terms see www.bluenord.com/debt.
Payment structure (USD million) at 31.03.2025
| Year | BNOR161) | Reserve-based lending facility3) |
Total |
|---|---|---|---|
| Interest rate 2) | 9,5% | SOFR | |
| 2025 | 14.3 | 63.9 | 78.2 |
| 2026 | 28.5 | 85.3 | 113.8 |
| 2027 | 28.5 | 302.8 | 331.3 |
| 2028 | 28.5 | 382.2 | 410.7 |
| 2029 | 328.5 | 352.6 | 681.1 |
| Total | 428.3 | 1,186.8 | 1,615.1 |
1) BNOR16 carries as interest rate of 9.50 percent per annum, payable semi-annually.
2) BNOR15 carries an interest charge of: (i) 6 percent per annum in cash, payable semi-annually, or; (ii) 8 percent per annum payment in kind ('PIK') cumulative interest, rolled up semi-annually, to add to BNOR15 capital on conversion at expiry of the bond. Currently the Company has elected the PIK interest of 8 percent and is therefore forecasting no cash interest payments on BNOR15 in the above table.
3) RBL interest payments include drawn, undrawn and letter of credit utilisation fees. There are no active interest rate hedges to date.
13 Trade payables and other current liabilities
| USD million | 31.03.2025 | 31.12.2024 | 31.03.2024 |
|---|---|---|---|
| Trade payable | 20.4 | 4.4 | 1.0 |
| Liabilities to operator | 36.3 | 31.1 | 70.0 |
| Over-lift of oil/NGL | 0.5 | 6.3 | - |
| Accrued interest | 2.9 | 3.4 | 1.4 |
| Salary accruals | 3.2 | 2.3 | 2.8 |
| Public duties payable | 18.4 | 33.7 | 13.3 |
| Other current liabilities | 40.3 | 18.2 | 17.4 |
| Total trade payables and other current liabilities | 122.1 | 99.4 | 105.8 |
14 Financial instruments
14.1 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 31.03.2025
| 33.8 |
|---|
| 33.8 |
| 71.8 |
| 44.9 |
| 116.6 |
1) For more information see section 14.3
14.2 Financial instruments by category
| Financial | ||||
|---|---|---|---|---|
| instruments | ||||
| Financial | at fair value | Hedging | ||
| On 31.03.2025 | instruments at | through | instruments at | |
| USD million | amortised cost | profit or loss | fair value | Total |
| Assets | ||||
| Derivative instruments price hedge | - | - | 33.8 | 33.8 |
| Trade receivables and other current assets | 64.4 | - | - | 64.4 |
| Restricted bank deposits | 64.0 | - | - | 64.0 |
| Cash and cash equivalents | 414.1 | - | - | 414.1 |
| Total assets | 542.6 | - | 33.8 | 576.4 |
| Liabilities | ||||
| Derivative instruments price hedge | - | - | 44.9 | 44.9 |
| Embedded derivatives convertible bond BNOR15 | - | 71.8 | - | 71.8 |
| Convertible bond loan | 241.7 | - | - | 241.7 |
| Senior unsecured bond loan | 296.9 | - | - | 296.9 |
| Reserve-based lending facility | 836.6 | - | - | 836.6 |
| Trade payables and other current liabilities | 122.1 | - | - | 122.1 |
| Total liabilities | 1,497.2 | 71.8 | 44.9 | 1,613.8 |
14.3 Financial instruments — fair values
Set out below is a comparison of the carrying amounts and fair value of financial instruments on 31 Mar 2025:
| Total amount | Carrying | Fair | |
|---|---|---|---|
| USD million | outstanding* | Amount | Value |
| Financial assets | |||
| Derivative instruments price hedge | 33.8 | 33.8 | |
| Trade receivables and other current assets | 64.4 | 64.4 | |
| Restricted bank deposits | 64.0 | 64.0 | |
| Cash and cash equivalents | 414.1 | 414.1 | |
| Total | 576.4 | 576.4 | |
| Financial liabilities | |||
| Derivative instruments price hedge | 44.9 | 44.9 | |
| Embedded derivative convertible bond BNOR15 | 71.8 | 71.8 | |
| Convertible bond loans | 247.1 | 241.7 | 175.3 |
| Senior unsecured bond loan | 300.0 | 296.9 | 300.0 |
| Reserve-based lending facility | 880.0 | 836.6 | 880.0 |
| Trade payables and other current liabilities | 122.1 | 122.1 | |
| Total | 1,427.1 | 1,613.8 | 1,594.0 |
* Total amount outstanding on the bonds and under the RBL facility
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 880 million in Q1 2025.
The senior unsecured bond loan is measured at amortised cost, in addition a total of USD 11.5 million in transaction costs are deducted from the amount initially recognised.
The BNOR15 instrument has been determined to contain embedded derivatives which are accounted for separately as derivatives at fair value through profit or loss, while the loan element subsequent to initial recognition is measured at amortised cost, transaction costs are included in the amortised cost. The embedded derivative is valued on an option valuation basis, the carrying value as on 31 March 2025 was USD 71.8 million. The assumptions in establishing the option value as on 31 March 2025 are shown below. The following table lists the inputs to the model used to calculate the fair value of the embedded derivatives:
| BNOR15 | ||
|---|---|---|
| Valuation date | (date) | 31 Mar 25 |
| Agreement execution date | (date) | 30 Dec 22 |
| Par value of bonds | (USD) | 247,067,145 |
| Reference share price at time of agreement | (NOK) | 413 |
| Fair value at grant date | (USD) | 38,928,552 |
| PIK interest rate | (%) | 8.00% |
| Expected life | (years) | 0.8 |
| Number of options | (#) | 4,803,885 |
| Conversion price | (NOK) | 537 |
| Fixed FX rate of agreement | (USD:NOK) | 10.440 |
| Risk-free rate (based on government bonds) | (%) | 3.78% |
| Expected volatility | (%) | 42.21% |
| Model used | Black - Scholes - Merton |
14.4 Hedging
The Group actively seeks to reduce the market-related risks it is exposed to including, (i) commodity prices, (ii) marketlinked floating interest rates and (iii) foreign exchange rates.
The Company has a rolling hedge requirement under its newly refinanced 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 percentage and Year 2 at 40 percentage; (ii) Gas: Season 1 at 50 percentage, Season 2 at 50 percentage, Season 3 at 40 percentage and Season 4 at 20 percentage (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 mixture of forward contracts and options.
No foreign exchange and interest hedge in place to date. The Company will continue to assess the need for these hedging considerations as part of its ongoing financial risk management strategy.
Hedge accounting is applied to all the Company's hedging arrangements. To the extent more than 100 percent of the market-related risk is hedged, the portion above 100 percent is considered ineffective, and the value adjustment is treated as a financial item in the Income Statement. In Q1 2025, most of the Company's arrangements in relation to commodity prices were effective, the part that exceeded the physical sale of oil was recognised as a financial cost. Time value related to commodity hedging arrangements is considered insignificant and generally the valuation of the instruments do not take into consideration the time value.
| Maturity | |||||||
|---|---|---|---|---|---|---|---|
| Less than 1 month |
1 to 3 months |
3 to 6 months |
6 to 9 months |
9 to 12 months |
More than 12 months |
Total | |
| As of 31 March 2025 | |||||||
| Commodity forward sales contracts oil: | |||||||
| Notional quantity (in mbbl) | - | 779.0 | 915.0 | 840.0 | 525.0 | 975.0 | 4,034.0 |
| Notional amount (in USD million per bbl) | - | 56.4 | 67.5 | 61.9 | 39.1 | 71.1 | 296.0 |
| Average hedged sales price (in USD per bbl) | - | 72.4 | 73.8 | 73.7 | 74.5 | 72.9 | 73.4 |
| Commodity forward sales contracts gas: | |||||||
| Notional quantity (in mMWh) | - | 1,425.0 | 1,590.0 | 1,140.0 | 1,140.0 | 1,860.0 | 7,155.0 |
| Notional amount (in EUR million per MWh) | - | 53.9 | 60.5 | 42.3 | 42.3 | 61.4 | 260.4 |
| Average hedged sales price (in EUR per MWh) | - | 37.8 | 38.0 | 37.1 | 37.1 | 9.7 | 22.5 |
| Commodity zero cost collar contracts oil: | |||||||
| Notional quantity (in mbbl) | - | 435.0 | 210.0 | 360.0 | 300.0 | 900.0 | 2,205.0 |
| Average hedged price - floor (in USD per bbl) | - | 70.3 | 72.5 | 71.4 | 65.0 | 65.0 | 67.8 |
| Average hedged price - ceiling (in USD per bbl) | - | 82.4 | 78.9 | 78.1 | 77.8 | 77.3 | 78.7 |
| Commodity zero cost collar contracts gas: | |||||||
| Notional quantity gas (in mMWh) | - | 720.0 | 720.0 | 840.0 | 840.0 | 2,910.0 | 6,030.0 |
| Average hedged price - floor (in EUR per MWh) | - | 42.5 | 42.5 | 40.3 | 40.3 | 32.4 | 37.0 |
| Average hedged price - ceiling (in EUR per MWh) | - | 57.6 | 57.6 | 56.1 | 56.1 | 45.4 | 51.3 |
15 Asset retirement obligations
| 2025 | 2024 | |
|---|---|---|
| USD million | Q4 | 01.01.-31.12. |
| Provisions as of beginning of period | 1,122.1 | 1,049.0 |
| Provisions and change of estimates | 2.5 | 34.5 |
| Accretion expense | 13.3 | 54.2 |
| Incurred removal cost | (0.4) | (15.5) |
| Currency translation adjustment | 0.1 | (0.1) |
| Total provisions made for asset retirement obligations | 1,137.5 | 1,122.1 |
| Break down of short-term and long-term asset retirement obligations | ||
| Short-term | 11.1 | 11.4 |
| Long-term | 1,126.4 | 1,110.6 |
| Total provisions for asset retirement obligations | 1,137.5 | 1,122.1 |
The balance as per 31 March 2025 is USD 1,070.0 million for DUC, USD 64.0 million for Nini/Cecilie, USD 1.4 million for Lulita (non-DUC share) and USD 2.2 million for Tyra F-3 pipeline.
Estimates are based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The calculations assume an inflation rate of 2.0 percent and a nominal discount rate before tax of 5.0 percent. The credit margin included in the discount rate is 2.1 percent. The abandonment estimates are further guided by the annual Decommissioning Programme and Budget, approved under the DUC partnership. These are contingent on commodity prices development, CO2 emissions cost development and field recovery assessments.
16 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.
Alternative Performance Measures
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 a 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 | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|
| EBITDA | 79.5 | 109.1 | 87.7 | 79.5 | 87.7 |
| Extraordinary gas penalties1) | 11.0 | - | - | - | - |
| Non-payment insurance | 1.5 | 0.8 | 1.5 | 1.5 | 1.5 |
| Restructuring cost2) | - | 1.8 | - | - | - |
| Adj. EBITDA | 92.0 | 111.7 | 89.2 | 81.0 | 89.2 |
1) Related to Tyra start-up.
2) 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 | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|
| Cash flow from operating activities before tax | 69.9 | 145.7 | 88.4 | 69.9 | 88.4 |
| Tax (paid)/received | (15.0) | (50.4) | (11.5) | (15.0) | (11.5) |
| Net cash flow from operating activities | 54.8 | 95.2 | 76.8 | 54.8 | 76.8 |
Interest-bearing debt defined as the book value of the current and non-current interest-bearing debt.
| USD million | 31.03.2025 | 31.12.2024 | 31.03.2024 |
|---|---|---|---|
| Convertible bond loans | (241.7) | (233.1) | (209.2) |
| Senior unsecured bond loan | (296.9) | (303.5) | (173.6) |
| Reserve-based lending facility | (836.6) | (834.3) | (822.5) |
| Interest-bearing debt | (1,375.1) | (1,370.9) | (1,205.2) |
Alternative Performance Measures
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 | 31.03.2025 | 31.12.2024 | 31.03.2024 |
|---|---|---|---|
| Cash and cash equivalents | 414.1 | 250.6 | 157.7 |
| Convertible bond loans | (247.1) | (247.1) | (228.4) |
| Senior unsecured bond loan | (300.0) | (300.0) | (175.0) |
| Reserve-based lending facility | (880.0) | (880.0) | (850.0) |
| Net interest-bearing debt | (1,013.0) | (1,176.5) | (1,095.7) |
| Adjustment for convertible bond loans | 247.1 | 247.1 | 228.4 |
| Include issued letters of credit | (100.0) | (100.0) | (100.0) |
| Net interest-bearing debt as per debt covenant | (865.9) | (1,029.4) | (967.3) |
Appendix
Dan hub
| Key figures | Unit | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|---|
| Dan | mboepd | 6.1 | 5.9 | 7.0 | 6.1 | 7.0 |
| Kraka | mboepd | 0.3 | 0.7 | 0.8 | 0.3 | 0.8 |
| Operational efficiency1) | % | 81.5 % | 82.7 % | 89.7 % | 81.5 % | 89.7 % |
Gorm hub
| Key figures | Unit | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|---|
| Gorm | mboepd | 0.4 | 0.7 | 1.0 | 0.4 | 1.0 |
| Rolf | mboepd | 0.1 | 0.3 | 0.3 | 0.1 | 0.3 |
| Skjold | mboepd | 2.7 | 4.0 | 2.7 | 2.7 | 2.7 |
| Operational efficiency1) | % | 57.2 % | 87.3 % | 84.2 % | 57.2 % | 84.2 % |
Halfdan hub
| Key figures | Unit | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|---|
| Halfdan | mboepd | 11.4 | 11.4 | 11.9 | 11.4 | 11.9 |
| Operational efficiency1) | % | 89.7 % | 90.3 % | 92.8 % | 89.7 % | 92.8 % |
Tyra hub
| Key figures | Unit | Q1 2025 | Q4 2024 | Q1 2024 | YTD 2025 | YTD 2024 |
|---|---|---|---|---|---|---|
| Tyra | mboepd | 2.3 | 0.7 | (0.2) | 2.3 | (0.2) |
| Harald | mboepd | 4.5 | 2.2 | - | 4.5 | - |
| Lulita | mboepd | - | - | - | - | - |
| Roar | mboepd | 0.7 | - | - | 0.7 | - |
| Svend | mboepd | - | - | - | - | - |
| Valdemar | mboepd | 1.5 | - | - | 1.5 | - |
| Operational efficiency1) | % | NA | NA | NA | NA | NA |
1) Operational efficiency is calculated as: delivered production / (delivered production + planned shortfalls + unplanned shortfalls).
Information about BlueNord
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 2025
| 10 April | Annual Report 2024 |
|---|---|
| 14 May | Annual General Meeting |
| 07 May | Q1 2025 Report |
| 10 July | Q2 and Half-year 2025 Report |
| 29 October | Q3 2025 Report |
Board of Directors
Glen Ole Rødland Chair Marianne Lie Tone Kristin Omsted Robert J McGuire Peter Coleman Kristin Færøvik João Saraiva e Silva
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 |
|---|---|
| [email protected] |
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 [email protected].
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