AI Terminal
Aker BP
Earnings Release • Feb 12, 2025
3528_rns_2025-02-12_c5fb8c8d-bf42-457c-812b-4c50326b95c4.pdf
Earnings Release
Open in ViewerOpens in native device viewer
QUARTERLY REPORT Q4 2024
FOURTH QUARTER 2024 RESULTS
Aker BP delivered strong results in the fourth quarter and throughout 2024, driven by high production efficiency, low costs, and low emissions. With production at the upper end of guidance, a well-executed project portfolio, and robust cash flow generation, the company continued to create value and distribute attractive dividends to its shareholders.
Highlights
- • Excellent operational performance: Oil and gas production reached 449 (415) thousand barrels of oil equivalent per day (mboepd) during the quarter and 439 (457) for the full year 2024, close to the high end of the guided range of 430-440 mboepd.
- • Low cost: Production cost was USD 5.7 (6.6) per barrel. Ending the year at USD 6.2 (6.2) per barrel, below latest guidance of 6.5 dollars per barrel.
- • Low emissions: Greenhouse gas emission intensity was 2.5 (2.4) kg CO2e per boe (scope 1 & 2), ranking among the lowest in the global oil and gas sector.
- • Projects on track: Field development projects progressing according to plan, with overall capex estimates unchanged.
- • Strong financial results: Aker BP reported total income of USD 3.1 (2.9) billion, an EBITDA of USD 2.7 (2.6) billion and net profit of USD 562 (173) million for the quarter. On a full-year basis the company generated record-high cash flow from operations at USD 6.4 (5.4) billion.
- • Returning value: Dividends of USD 2.4 per share in 2024, to be increased by five percent in 2025.
Comment from Karl Johnny Hersvik, CEO of Aker BP:
"Over the past decade, Aker BP has undergone a transformation to build a future-fit E&P company. We have developed distinct capabilities that set us apart: a strong performance culture that drives execution excellence, a well-established alliance model that fosters collaboration across the value chain, and a leading position in digitalisation that is transforming the way we work. Combined with our world-class asset base, these strengths enable us to deliver industry-leading performance.
In the fourth quarter and throughout 2024, we delivered strong operational performance across all key metrics. Production reached the upper end of our guidance, with strong performance across the portfolio – led by Johan Sverdrup, which delivered a new annual production record. At the same time, we maintained industry-leading cost efficiency and emission intensity. I am also pleased that we remain on track to deliver our project portfolio and grow production into the next decade.
We have a clear pathway to sustain production above 500,000 barrels per day beyond 2030, with ambitions for further growth. With our capabilities, assets, resource base, and technology, we are ideally positioned to drive profitable growth on the Norwegian continental shelf.
With another year of strong value creation and cash flow behind us, we enter 2025 in our strongest financial position yet – providing the flexibility to advance our development projects while maintaining attractive dividends to our shareholders. In line with our ambition, we once again increase our dividends in 2025."
Forward-looking statements in this report reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future and may not be within our control. All figures are presented in USD unless otherwise stated, and figures in brackets apply to the previous quarter.
Key figures
| UNIT | Q4 2024 | Q3 2024 | Q4 2023 | FY 2024 | FY 2023 | |
|---|---|---|---|---|---|---|
| INCOME STATEMENT | ||||||
| Total income | USD million | 3 068 | 2 858 | 3 556 | 12 379 | 13 670 |
| EBITDA | USD million | 2 718 | 2 612 | 3 174 | 11 083 | 12 286 |
| Net profit/loss | USD million | 562 | 173 | 164 | 1 828 | 1 336 |
| Earnings per share (EPS) | USD | 0.89 | 0.27 | 0.26 | 2.90 | 2.12 |
| CASH FLOW STATEMENT | ||||||
| Cash flow from operations | USD million | 1 063 | 2 757 | 1 503 | 6 423 | 5 407 |
| Cash flow from investments | USD million | (1 366) | (1 402) | (1 042) | (5 315) | (3 468) |
| Cash flow from financing | USD million | 388 | (491) | (433) | (284) | (1 309) |
| Net change in cash and cash equivalent | USD million | 85 | 864 | 28 | 823 | 631 |
| OTHER FINANCIAL KEY FIGURES | ||||||
| Net interest-bearing debt | USD million | 3 929 | 3 286 | 3 114 | 3 929 | 3 114 |
| Leverage ratio | 0.29 | 0.21 | 0.19 | 0.29 | 0.19 | |
| Dividend per share | USD | 0.60 | 0.60 | 0.55 | 2.40 | 2.20 |
| PRODUCTION AND SALES | ||||||
| Net petroleum production | mboepd | 449.2 | 414.7 | 444.3 | 439.0 | 456.8 |
| Over/underlift | mboepd | (10.1) | (23.4) | 22.6 | (9.0) | 4.2 |
| Net sold volume | mboepd | 439.2 | 391.3 | 466.9 | 430.0 | 461.0 |
| - Liquids | mboepd | 373.5 | 345.0 | 408.4 | 370.2 | 397.8 |
| - Natural gas | mboepd | 65.7 | 46.4 | 58.5 | 59.8 | 63.2 |
| REALISED PRICES | ||||||
| Liquids | USD/boe | 74.1 | 80.3 | 83.6 | 80.1 | 81.6 |
| Natural gas | USD/boe | 79.0 | 63.5 | 73.9 | 62.9 | 74.3 |
| AVERAGE EXCHANGE RATES | ||||||
| USDNOK | 11.01 | 10.71 | 10.82 | 10.74 | 10.56 | |
| EURUSD | 1.07 | 1.10 | 1.08 | 1.08 | 1.08 |
FINANCIAL REVIEW
Income statement
| (USD MILLION) | Q4 2024 | Q3 2024 | Q4 2023 | FY 2024 | FY 2023 |
|---|---|---|---|---|---|
| Total income | 3 068 | 2 858 | 3 556 | 12 379 | 13 670 |
| EBITDA | 2 718 | 2 612 | 3 174 | 11 083 | 12 286 |
| EBIT | 2 079 | 1 695 | 2 154 | 8 264 | 8 989 |
| Pre-tax profit | 2 052 | 1 627 | 2 168 | 8 049 | 8 764 |
| Net profit/loss | 562 | 173 | 164 | 1 828 | 1 336 |
| EPS (USD) | 0.89 | 0.27 | 0.26 | 2.90 | 2.12 |
Total income for the fourth quarter amounted to USD 3,068 (2,858) million. The increase was driven by higher production. Sold volumes increased by 12 percent to 439.2 (391.3) mboepd. The average realised liquids price decreased by 8 percent to USD 74.1 (80.3) per boe, while the average price for natural gas rose by 24 percent to USD 79.0 (63.5) per boe.
Production expenses for oil and gas sold in the quarter amounted to USD 229 (186) million, with change in over/underlift being the main reason for the increase from the previous quarter. The average production cost per barrel produced was USD 5.7 (6.6). See note 2 for further details on production expenses. Exploration expenses amounted to USD 111 (40) million, with higher dry well expenses as the main reason for the increase from the previous quarter.
Depreciation amounted to USD 603 (614) million, or USD 14.6 (16.1) per boe. The decrease from the previous quarter was primarily driven by a reduction in the abandonment provision, which directly impacted depreciation on the Ula/ Tambar field. Impairments totalled USD 35 (304) million, all related to exploration assets. For further details, see note 7.
Operating profit for the fourth quarter was USD 2,079 (1,695) million.
Net financial expenses decreased to USD 27 (68) million, primarily due to developments in currency exchange rates and the related impact on currency gain and loss on currency derivatives. For more details, see note 4.
Profit before taxes totalled USD 2,052 (1,627) million. Tax expense was USD 1,490 (1,454) million, resulting in an effective tax rate of 73 (89) percent. The decrease in the tax rate was primarily due to the absence of goodwill impairment. For further details on tax, see note 5.
This resulted in a net profit of USD 562 (173) million for the quarter.
Balance sheet
| 31.12.2024 | 30.09.2024 | 31.12.2023 |
|---|---|---|
| 12 757 | 12 757 | 13 143 |
| 20 238 | 19 803 | 17 450 |
| 3 033 | 3 362 | 3 314 |
| 4 147 | 4 147 | 3 388 |
| 2 018 | 1 625 | 1 751 |
| 42 193 | 41 693 | 39 047 |
| 12 691 | 12 477 | 12 362 |
| 7 400 | 6 673 | 5 798 |
| 17 651 | 17 488 | 15 453 |
| 2 434 | 2 904 | 3 600 |
| 2 017 | 2 152 | 1 833 |
| 42 193 | 41 693 | 39 047 |
| 3 929 | 3 286 | 3 114 |
| 0.29 | 0.21 | 0.19 |
At the end of the fourth quarter, total assets amounted to USD 42.2 (41.7) billion, of which non-current assets were USD 36.0 (35.9) billion.
Equity amounted to USD 12.7 (12.5) billion at the end of the quarter, corresponding to an equity ratio of 30 (30) percent.
Bond debt increased to USD 7.4 (6.7) billion, while the company's bank facilities remained undrawn. In October, the company issued two new bonds: USD 750 million in Senior Notes with a coupon of 5.125%, due in 2034, and USD 750 million in Senior Notes with a coupon of 5.80%, due in 2054. USD 668 million of the proceeds from these issuances were used to repurchase existing bonds, as detailed in note 11. Other long-term liabilities amounted to USD 17.7 (17.5) billion.
Tax payable decreased by USD 0.5 billion to USD 2.4 (2.9) billion, following the payment of two tax instalments during the quarter.
At the end of the fourth quarter, the company had total available liquidity of USD 7.5 (7.5) billion, comprising USD 4.1 (4.1) billion in cash and cash equivalents and USD 3.4 (3.4) billion in undrawn credit facilities.
Cash flow
| (USD MILLION) | Q4 2024 | Q3 2024 | Q4 2023 | FY 2024 | FY 2023 |
|---|---|---|---|---|---|
| Cash flow from operations | 1 063 | 2 757 | 1 503 | 6 423 | 5 407 |
| Cash flow from investments | (1 366) | (1 402) | (1 042) | (5 315) | (3 468) |
| Cash flow from financing | 388 | (491) | (433) | (284) | (1 309) |
| Net change in cash & cash equivalents | 85 | 864 | 28 | 823 | 631 |
| Cash and cash equivalents | 4 147 | 4 147 | 3 388 | 4 147 | 3 388 |
Net cash flow from operating activities totalled USD 1,063 (2,757) million in the quarter. The reduction was primarily driven by higher tax payments and a net increase in working capital. Net cash used for investment activities amounted to USD 1,366 (1,402) million, including USD 1,272 (1,258) million in fixed asset investments.
Net cash inflow from financing activities was USD 388 million compared to a net cash outflow of 491 million the previous quarter. The main item in the fourth quarter was net proceeds from a bond issue of USD 1,481 (0) million, offset by bond repayments of USD 646 (0) million and dividend payments of USD 379 (379) million.
Dividends
The Annual General Meeting authorised the Board to approve the distribution of dividends pursuant to section 8-2 (2) of the Norwegian Public Limited Companies Act.
During the fourth quarter 2024, the company paid a dividend of USD 0.60 per share. The Board has resolved to pay a dividend of USD 0.63 per share in the first quarter, reflecting a five percent increase in the annual dividend per share. The dividend payment date will be on or about 25 February 2025. The Aker BP shares will trade ex-dividend on 17 February 2025.
Hedging
Aker BP uses a range of hedging instruments to manage economic exposure. Commodity options are employed to mitigate the financial impact of lower oil and gas prices. The company has limited exposure to interest rate fluctuations, as all bonds are issued at fixed-rate coupons. In the fourth quarter of 2024, USD 400 million was swapped from a fixed to a floating rate through an interest rate swap. Foreign exchange derivatives are used to manage currency risks, primarily related to costs in NOK, EUR, and GBP. All derivatives are marked to market, with changes in market value recognised in the income statement.
The company had no material commodity derivatives exposure as of 31 December 2024.
OPERATIONAL REVIEW
Aker BP delivered strong operational performance in the fourth quarter of 2024, marked by high production efficiency, low costs, and low emissions. Production levels rebounded following maintenance in the previous quarter, driven by strong contributions from Johan Sverdrup and the ramp-up of Tyrving in the Alvheim area. Our field development projects progressed as planned, with capital expenditures in line with guidance.
Aker BP's net production was 41.3 mmboe, up from 38.2 in the previous quarter. This corresponds to a daily average of 449.2 mboepd, compared to 414.7 mboepd last quarter.
The net sold volume reached 439.2 mboepd, up from 391.3 mboepd in the previous quarter. Of this, 85 percent was liquids and 15 percent was gas. The sales were impacted by an underlift of 10.1 mboepd, compared to an underlift of 23.4 mboepd in the previous quarter.
Average production efficiency across the portfolio increased to 95 percent from 88 percent last quarter, as the capacity utilisation rebounded following seasonal maintenance in the previous quarter.
The strong operational performance was reflected in low production cost and greenhouse gas emission intensity, which stood at USD 5.7 per boe and 2.5 kg CO2e per boe, respectively.
The portfolio of field development projects progressed as planned and within budget in the fourth quarter. Onshore, the primary focus is on construction activities and assembling topsides and jackets at the yards. Offshore, subsea installation activities are underway, and drilling campaigns are being planned and executed.
For the year 2024, the company delivered strongly across all guidance parameters. Production was at the higher end of the guided range, operational costs below expectations and all investments in line with the estimates provided at the beginning of the year.
Alvheim Area
| KEY FIGURES | AKER BP INTEREST | Q4 2024 | Q3 2024 | Q2 2024 | Q1 2024 | Q4 2023 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Alvheim | 80% | 43.6 | 37.6 | 46.3 | 46.9 | 24.3 |
| Bøyla (incl. Frosk) | 80% | 4.7 | 4.2 | 5.2 | 5.6 | 4.9 |
| Skogul | 65% | 1.5 | 2.2 | 2.1 | 2.4 | 1.4 |
| Tyrving | 61.26% | 12.9 | 3.2 | - | - | - |
| Vilje | 46.904% | 1.0 | 1.2 | 1.2 | 1.3 | 1.1 |
| Volund | 100% | 2.6 | 1.2 | 2.1 | 0.8 | 1.4 |
| Total production | 66.3 | 49.5 | 57.0 | 57.1 | 33.1 | |
| Production efficiency | 97% | 90% | 97% | 96% | 63% |
Production from the Alvheim area averaged 66 mboepd net to Aker BP in the fourth quarter. The increase from the previous quarter was driven by the Tyrving field reaching full production capacity in October. Furthermore, production efficiency improved due to less planned maintenance impacting production compared to the previous quarter.
The Tyrving development project started production in September, five months ahead of plan. All three wells are now in production, with only a few close-out activities remaining for 2025. This marks the end of a successful string of projects in the recent history of the Alvheim area, with both Frosk and Kobra East Gekko coming on stream in 2023, and now Tyrving in 2024.
In parallel to the tie-in projects, the partnership is continuously evaluating measures to increase oil and gas recovery. In the fourth quarter an infill target passed final investment decision, with first oil planned for fourth quarter 2025.
Grieg Aasen Area
| KEY FIGURES | AKER BP INTEREST | Q4 2024 | Q3 2024 | Q2 2024 | Q1 2024 | Q4 2023 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Edvard Grieg Area | 65% | 36.6 | 39.4 | 46.1 | 54.7 | 61.8 |
| Ivar Aasen | 36.1712% | 13.5 | 10.8 | 11.7 | 11.1 | 12.1 |
| Total production | 50.1 | 50.1 | 57.8 | 65.8 | 74.0 | |
| Production efficiency | 95% | 93% | 94% | 99% | 99% |
Aker BP's net production from the Grieg Aasen area averaged 50 mboepd in the fourth quarter, with a production efficiency of 95 percent.
The Utsira High project is well into the execution phase. Currently, testing of subsea equipment is progressing well, alongside preparations for the subsea installation and the 2025 drilling program. The project features two subsea tiebacks: Symra, which will connect to the Ivar Aasen platform, and Solveig Phase 2, which will tie into the Edvard Grieg platform. Production from both fields is anticipated to start in 2026.
A new infill drilling program on the Edvard Grieg field is set to begin, with final preparations underway ahead of the rig's arrival. The two-well drilling campaign is scheduled to commence in the first quarter of 2025.
Johan Sverdrup
| KEY FIGURES | AKER BP INTEREST | Q4 2024 | Q3 2024 | Q2 2024 | Q1 2024 | Q4 2023 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Total production | 31.5733% | 239.3 | 237.2 | 241.0 | 236.9 | 244.9 |
The Johan Sverdrup field delivered strong performance in the fourth quarter, maintaining high production efficiency, a very good safety record, and low costs and emissions. Aker BP's share of the production averaged 239 mboepd during the quarter.
Drilling activities continued during the quarter but were delayed due to rig maintenance and challenging weather conditions. As a result, two wells from the original drilling plan remain to be completed. These are scheduled for the first quarter of 2025, which will bring the total number of producing wells to 41. Additionally, drilling from the field centre is expected to continue throughout 2025, with plans to add four new lateral branches to existing production wells.
The Johan Sverdrup Phase 3 project passed final concept selection in December. The project aims to add two new subsea templates, comprising a total of 8 wells tied back to existing infrastructure. Final investment decision is scheduled for the second quarter 2025.
In accordance with the unit agreement, the partners Aker BP and Total in January 2025 called for a redetermination process in the Johan Sverdrup Unit. The purpose is to review and, if relevant, revise and re-allocate each unit owner's equity share in the Johan Sverdrup Unit based on the new knowledge acquired through drilling and oil production since the unit agreement was established in 2015.
Skarv Area
| KEY FIGURES | AKER BP INTEREST | Q4 2024 | Q3 2024 | Q2 2024 | Q1 2024 | Q4 2023 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Total production | 23.835% | 35.2 | 23.8 | 37.2 | 38.3 | 36.5 |
| Production efficiency | 96% | 64% | 98% | 98% | 95% |
Production from the Skarv area averaged 35 mboepd net to Aker BP in the fourth quarter, reflecting an increase driven by the successful ramp-up of operations following the planned maintenance shutdown in the prior quarter.
The first of two new infill wells was completed and successfully put on stream during the quarter. The second infill well suffered damage to the wellbore during drilling and has been temporarily plugged.
The Skarv Satellite project made strong progress during the quarter and is now preparing for the 2025 subsea installation and drilling campaigns. The project encompasses three separate developments in the Skarv area – Alve Nord, Idun Nord, and Ørn – which will be tied back to the Skarv FPSO, with production expected to begin in 2027.
Ula Area
| KEY FIGURES | AKER BP INTEREST | Q4 2024 | Q3 2024 | Q2 2024 | Q1 2024 | Q4 2023 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Ula | 80% | 4.3 | 3.4 | 4.0 | 4.1 | 4.7 |
| Tambar | 55% | 1.2 | 0.7 | 1.4 | 0.6 | 1.2 |
| Oda | 15% | 0.9 | 1.0 | 1.1 | 1.0 | 1.4 |
| Total production | 6.4 | 5.2 | 6.5 | 5.7 | 7.3 | |
| Production efficiency | 80% | 60% | 76% | 62% | 71% |
Production from the Ula area averaged 6 mboepd net to Aker BP in the fourth quarter. The increase was due to successful ramp-up of production on the Ula field following the planned maintenance in the previous quarter.
Production in the Ula area is expected to cease by 2028. A decommissioning project has been initiated and is progressing towards a concept select decision in the second half of 2025.
A sidetrack well in the Tambar area is nearing completion, with first oil expected towards the end of the first quarter 2025.
Valhall Area
| KEY FIGURES | AKER BP INTEREST | Q4 2024 | Q3 2024 | Q2 2024 | Q1 2024 | Q4 2023 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Valhall | 90% | 42.8 | 40.2 | 36.9 | 36.5 | 37.7 |
| Hod | 90% | 9.1 | 8.7 | 7.9 | 7.7 | 10.8 |
| Total production | 51.9 | 48.9 | 44.8 | 44.1 | 48.5 | |
| Production efficiency | 94% | 90% | 80% | 77% | 84% |
Aker BP's net production from the Valhall area increased to 52 mboepd in the fourth quarter. Production efficiency increased to 94 percent, the highest in over five years, driven by high uptime and improved well performance.
The partnership continues to identify upside potential in the area, and two new infill targets are being matured towards an investment decision in the first quarter 2025.
Valhall PWP-Fenris
The Valhall PWP-Fenris project progressed as planned, with fabrication and construction activities advancing at multiple sites. Modification work is ongoing at the existing Valhall facilities, while key offshore campaigns for the Fenris field, including trenching and subsea rock installation, were successfully completed during the quarter. Furthermore, the first well on the Fenris field has been finalized, and drilling operations for the second well began in the fourth quarter.
Yggdrasil
The Yggdrasil area, which is being developed by Aker BP and its partners, is currently estimated to hold approximately 700 million barrels of oil equivalent (mmboe) in recoverable resources. The development includes a central processing platform (Hugin A), two unmanned platforms (Munin and Hugin B), extensive subsea infrastructure, and more than 50 planned wells. The facilities will be powered with renewable power from shore, which will lead to minimal GHG emissions. Production is scheduled to begin in 2027.
The Yggdrasil development is two years into project execution and is progressing according to plan. Construction and assembly of topside modules and jackets are now the key focus for the project teams. Most notably, the assembly of the Hugin A topside commenced in the fourth quarter at the yard in Stord, and in Haugesund the assembly of the Munin topside continues apace. Meanwhile, engineering, procurement and fabrication activities are ongoing as planned.
In recent years, extensive new data from OBN seismic surveys and exploration wells have been gathered in the Yggdrasil area. This has greatly improved the subsurface team's understanding of the reservoir, enhancing models, reducing risks, and enabling the optimal placement of wells. Detailed well planning and the operationalisation of drilling plans are currently in progress. After the summer 2025, the first two rigs will begin drilling production wells in the Yggdrasil area.
Work is advancing on the 2023 oil discovery at Øst Frigg Beta/Epsilon, which is planned to be included in the Yggdrasil development project. The development concept has been selected, and the project is moving towards a final investment decision in the second quarter 2025.
Court of Appeal Ruling on Temporary Injunction
In January 2024, Oslo District Court ruled that the Ministry of Energy's approvals of the PDOs for the Breidablikk, Tyrving, and Yggdrasil fields were invalid due to procedural errors, specifically the failure to assess end-user combustion emissions. A temporary injunction initially halted the issuance of new permits based on these PDOs. However, the injunction was lifted by Borgarting Court of Appeal, allowing permitting to continue. This decision has been appealed to the Supreme Court, with proceedings scheduled in March. The main case, including an advisory opinion from the EFTA Court, is anticipated to be heard in 2025.
Aker BP, operator of Yggdrasil and Tyrving, is not involved in the court case. The PDO approvals remain valid for the company, which continues both projects as planned. Tyrving began production in September 2024, and Yggdrasil is progressing on schedule.
EXPLORATION
Total exploration spend in the fourth quarter was USD 123 (127) million, while USD 111 (40) million was recognised as exploration expenses in the period, relating to dry well costs, seismic, area fees, field evaluation, and G&G costs.
An appraisal well in production licence 211 CS in the Norwegian Sea was completed in the quarter. The well successfully confirmed the discoveries in the Sabina and Adriana targets. Total estimated recoverable resources for both targets combined corresponds to around 45-82 million barrels of oil equivalent. The discoveries are being evaluated for potential tie-back to existing infrastructure in the area. Aker BP holds a 15 percent interest in the licence, which is operated by Harbour Energy.
Drilling of the Othello/Falstaff prospect in production licence 1086 in the southern North Sea was completed in the quarter. A discovery was made with preliminary estimates of 25-57 million barrels of oil equivalent. The discovery will, along with other discoveries and prospects in the vicinity, be assessed with a view to potential future development. Aker BP holds a 20 percent interest in the licence, which is operated by DNO.
The Equinor-operated Kvernbit well in licence 1185 (20% interest), and the Aker BP-operated wells Kaldafjell in licence 932 (40% interest) and Rumpetroll South in licence 869 (80% interest) were concluded as dry in the quarter.
Aker BP conducted the following licence transactions in the fourth quarter:
- Acquisition of a 40 percent interest and operatorship in production license 1147 from Sval.
- Swap agreement with Equinor, where Aker BP received a 10 percent interest in production license 1014/1014B in exchange for 10 percent in PL1090.
- Transfer of operatorship of the Oda field in production licence 405 in the Ula area from Sval to Aker BP, completed in first quarter 2025.
HEALTH, SAFETY, SECURITY AND ENVIRONMENT
HSSE is always the number one priority in all of Aker BP's activities. The company strives to ensure that all its operations, drilling campaigns and projects are carried out under the highest HSSE standards.
| KEY HSSE INDICATORS | UNIT | Q4 2024 | Q3 2024 | Q2 2024 | Q1 2024 | Q4 2023 |
|---|---|---|---|---|---|---|
| Total recordable injury frequency (TRIF) L12M | Per mill. working hours |
1.9 | 2.0 | 1.6 | 2.5 | 2.4 |
| Serious incident frequency (SIF) L12M | Per mill. working hours |
0.4 | 0.7 | 0.6 | 0.5 | 0.3 |
| Acute spill | Count | 1 | 0 | 0 | 0 | 1 |
| Process safety events Tier 1 and 2 | Count | 0 | 0 | 0 | 2 | 1 |
| GHG emissions intensity, equity share (scope 1&2) | Kg CO2e/boe | 2.5 | 2.4 | 2.6 | 3.0 | 2.8 |
Health & Safety
The injury frequency trended down in the fourth quarter. The twelve months rolling average for the Total Recordable Injury Frequency (TRIF) decreased to 1.9, while the Serious Incident Frequency (SIF) decreased to 0.4.
During the quarter, there were four reported injuries affecting TRIF, none of which classified as serious.
Environment
A minor spill occurred during the quarter, involving 2.1 m3 of oil-based mud discharged into the sea from a drilling rig in the Skarv Area. The incident was classified as a Tier 3 acute spill with low severity and is being routinely investigated.
No process safety events were reported in the fourth quarter.
Aker BP's greenhouse gas (GHG) emissions intensity for the fourth quarter was 2.5 (2.4) kg CO2e per boe. The increase in emission intensity compared to the previous quarter was primarily due to the resumption of regular activity levels on the Skarv FPSO, following the production halt during planned maintenance in the prior quarter.
OUTLOOK
The Board believes Aker BP is uniquely positioned for long-term value creation, leveraging several core strengths.
Aker BP produces oil and gas from a portfolio of world-class assets with high operational efficiency, low costs, and a strong safety record. This generates substantial cash flow and provides a solid foundation for further value creation through increased recovery and near-field exploration.
The company is also an industry leader in emissions efficiency, with one of the lowest greenhouse gas emission intensities in the oil and gas sector and a well-defined pathway towards GHG neutrality for scope 1 and 2 emissions.
Aker BP is driving industrial transformation through a comprehensive improvement agenda, leveraging strategic alliances and digitalisation to enhance operational excellence and sustainable growth. These initiatives strengthen competitiveness and productivity across the entire value chain.
With a substantial resource base, extensive exploration acreage, and a portfolio of high-return field development projects, Aker BP is well positioned for continued profitable growth. Executed under a capital-efficient tax framework, these projects remain on track to deliver a significant production increase from 2027.
Aker BP has established a resilient financial framework with clear capital allocation priorities. Maintaining a robust balance sheet with financial flexibility and an investment grade credit rating remains the top financial priority. This approach ensures the funding of high-return, low break-even projects, maximising long-term value creation. Over time, this value will be returned to shareholders through dividends.
These strengths collectively position Aker BP to deliver significant long-term value.
Guidance for 2025
- Production of 390-420 mboepd
- Production cost of USD ~7 per boe
- Capex of USD ~5.5-6 billion
- Exploration spend of USD ~450 million
- Abandonment spend of USD ~150 million
- Quarterly dividend of USD 0.63 per share, annualised at USD 2.52 per share up 5% from 2024
Disclaimer
Forward-looking statements in this report reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future and may not be within our control. All figures are presented in USD unless otherwise stated, and figures in brackets apply to the previous quarter.
FINANCIAL STATEMENTS WITH NOTES
15 · Aker BP Quarterly Report · Q4 2024
INCOME STATEMENT (UNAUDITED)
| Group | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | |||||||
| (USD million) | Note | 2024 | 2024 | 2023 | 2024 | 2023 | ||||
| Petroleum revenues | 3 025.6 | 2 822.4 | 3 541.8 | 12 242.7 | 13 580.0 | |||||
| Other income | 42.1 | 35.2 | 14.3 | 136.7 | 89.9 | |||||
| Total income | 1 | 3 067.7 | 2 857.6 | 3 556.1 | 12 379.4 | 13 669.9 | ||||
| Production expenses | 2 | 229.1 | 186.1 | 298.0 | 916.4 | 1 060.1 | ||||
| Exploration expenses | 3 | 110.7 | 40.0 | 67.0 | 326.5 | 266.3 | ||||
| Depreciation | 6 | 603.5 | 613.9 | 605.8 | 2 397.8 | 2 406.8 | ||||
| Impairments | 6,7 | 35.4 | 303.5 | 414.8 | 421.6 | 889.5 | ||||
| Other operating expenses | 10.2 | 19.2 | 16.8 | 53.5 | 57.8 | |||||
| Total operating expenses | 988.8 | 1 162.8 | 1 402.3 | 4 115.8 | 4 680.5 | |||||
| Operating profit/loss | 2 078.9 | 1 694.9 | 2 153.8 | 8 263.6 | 8 989.4 | |||||
| Interest income | 47.7 | 42.8 | 42.0 | 162.9 | 133.4 | |||||
| Other financial income | 238.3 | 68.1 | 275.4 | 391.7 | 321.2 | |||||
| Interest expenses | 15.7 | 24.2 | 36.0 | 95.5 | 161.8 | |||||
| Other financial expenses | 297.2 | 154.4 | 266.8 | 674.0 | 518.2 | |||||
| Net financial items | 4 | -26.9 | -67.8 | 14.6 | -214.9 | -225.4 | ||||
| Profit/loss before taxes | 2 052.0 | 1 627.1 | 2 168.3 | 8 048.7 | 8 764.0 | |||||
| Tax expense (+)/income (-) | 5 | 1 490.2 | 1 453.7 | 2 004.6 | 6 221.0 | 7 428.3 | ||||
| Net profit/loss | 561.8 | 173.4 | 163.8 | 1 827.7 | 1 335.7 | |||||
| Weighted average no. of shares outstanding basic and diluted | 631 661 159 | 630 786 689 | 631 153 169 | 631 224 495 | 631 311 010 | |||||
| Basic and diluted earnings/loss USD per share | 0.89 | 0.27 | 0.26 | 2.90 | 2.12 |
STATEMENT OF COMPREHENSIVE INCOME (UNAUDITED)
| Group | ||||||
|---|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | |||
| (USD million) | Note | 2024 | 2024 | 2023 | 2024 | 2023 |
| Profit/loss for the period | 561.8 | 173.4 | 163.8 | 1 827.7 | 1 335.7 | |
| Items which may be reclassified over profit and loss (net of taxes) Foreign currency translation |
- | - | - | - | - | |
| Items which will not be reclassified over profit and loss (net of taxes) Actuarial gain/loss pension plan |
0.1 | - | 0.1 | 0.1 | 0.1 | |
| Total comprehensive income/loss in period | 561.9 | 173.4 | 163.8 | 1 827.8 | 1 335.8 |
STATEMENT OF FINANCIAL POSITION (UNAUDITED)
| Group | |||||
|---|---|---|---|---|---|
| (USD million) | Note | 31.12.2024 | 30.09.2024 | 31.12.2023 | |
| ASSETS | |||||
| Intangible assets | |||||
| Goodwill | 6 | 12 756.6 | 12 756.6 | 13 142.8 | |
| Capitalised exploration expenditures | 6 | 420.4 | 486.1 | 325.4 | |
| Other intangible assets | 6 | 1 937.6 | 1 990.8 | 2 123.4 | |
| Tangible fixed assets | |||||
| Property, plant and equipment | 6 | 20 238.4 | 19 802.6 | 17 449.8 | |
| Right-of-use assets | 6 | 578.8 | 673.4 | 655.3 | |
| Financial assets | |||||
| Long-term receivables | 69.0 | 80.7 | 69.1 | ||
| Other non-current assets | 22.6 | 104.7 | 102.9 | ||
| Long-term derivatives | 13 | 5.0 | 26.1 | 38.1 | |
| Total non-current assets | 36 028.4 | 35 921.0 | 33 906.8 | ||
| Inventories | |||||
| Inventories | 305.9 | 255.3 | 202.3 | ||
| Financial assets | |||||
| Trade receivables | 914.9 | 676.4 | 875.7 | ||
| Other short-term receivables | 8 | 796.4 | 668.6 | 525.3 | |
| Short-term derivatives | 13 | 0.3 | 24.5 | 148.1 | |
| Cash and cash equivalents | |||||
| Cash and cash equivalents | 10 | 4 146.9 | 4 147.4 | 3 388.4 | |
| Total current assets | 6 164.5 | 5 772.0 | 5 139.7 | ||
| TOTAL ASSETS | 42 192.9 | 41 693.0 | 39 046.5 |
STATEMENT OF FINANCIAL POSITION (UNAUDITED)
| Group | ||||
|---|---|---|---|---|
| (USD million) | Note | 31.12.2024 | 30.09.2024 | 31.12.2023 |
| EQUITY AND LIABILITIES | ||||
| Equity | ||||
| Share capital | 84.3 | 84.3 | 84.3 | |
| Share premium Other equity |
12 946.6 -339.9 |
12 946.6 -554.2 |
12 946.6 -668.8 |
|
| Total equity | 12 691.1 | 12 476.8 | 12 362.2 | |
| Non-current liabilities | ||||
| Deferred taxes | 5 | 12 990.0 | 12 363.2 | 10 592.3 |
| Long-term abandonment provision | 12 | 4 147.7 | 4 584.6 | 4 304.1 |
| Long-term bonds | 11 | 7 336.8 | 6 577.7 | 5 798.2 |
| Long-term derivatives | 13 | 55.3 | 1.2 | 0.5 |
| Long-term lease debt | 9 | 458.0 | 538.1 | 555.5 |
| Other non-current liabilities | - | 1.0 | 1.0 | |
| Total non-current liabilities | 24 987.8 | 24 065.7 | 21 251.5 | |
| Current liabilities | ||||
| Trade creditors | 329.1 | 355.3 | 291.0 | |
| Short-term bonds | 11 | 63.5 | 95.2 | - |
| Accrued public charges and indirect taxes | 40.8 | 37.1 | 38.8 | |
| Tax payable | 5 | 2 433.6 | 2 903.8 | 3 599.9 |
| Short-term derivatives | 13 | 151.7 | 28.0 | 32.8 |
| Short-term abandonment provision | 12 | 131.7 | 125.4 | 250.6 |
| Short-term lease debt | 9 | 217.7 | 222.1 | 148.7 |
| Other current liabilities | 14 | 1 145.8 | 1 383.7 | 1 071.0 |
| Total current liabilities | 4 514.0 | 5 150.5 | 5 432.9 | |
| Total liabilities | 29 501.7 | 29 216.2 | 26 684.3 | |
| TOTAL EQUITY AND LIABILITIES | 42 192.9 | 41 693.0 | 39 046.5 |
STATEMENT OF CHANGES IN EQUITY - GROUP (UNAUDITED)
| Other equity | ||||||||
|---|---|---|---|---|---|---|---|---|
| Other comprehensive income | ||||||||
| Foreign currency | ||||||||
| Share | Other paid-in | Actuarial | translation | Accumulated | Total other | |||
| (USD million) | Share capital | premium | capital | gains/losses | reserves | deficit | equity | Total equity |
| Equity as of 31.12.2022 | 84.3 | 12 946.6 | 573.1 | -0.1 | 179.8 | -1 356.3 | -603.5 | 12 427.5 |
| Dividend distributed | - | - | - | - | - | -1 042.8 | -1 042.8 | -1 042.8 |
| Profit/loss for the period | - | - | - | - | - | 1 171.9 | 1 171.9 | 1 171.9 |
| Purchase of treasury shares | - | - | - | - | - | -33.1 | -33.1 | -33.1 |
| Equity as of 30.09.2023 | 84.3 | 12 946.6 | 573.1 | -0.1 | 179.8 | -1 260.3 | -507.4 | 12 523.6 |
| Dividends distributed | - | - | - | - | - | -347.6 | -347.6 | -347.6 |
| Profit/loss for the period | - | - | - | - | - | 163.8 | 163.8 | 163.8 |
| Sale of treasury shares | - | - | - | - | - | 22.5 | 22.5 | 22.5 |
| Other comprehensive income for the period | - | - | - | -0.1 | - | - | -0.1 | -0.1 |
| Equity as of 31.12.2023 | 84.3 | 12 946.6 | 573.1 | -0.2 | 179.8 | -1 421.6 | -668.8 | 12 362.2 |
| Dividend distributed | - | - | - | - | - | -1 137.6 | -1 137.6 | -1 137.6 |
| Profit/loss for the period | - | - | - | - | - | 1 265.9 | 1 265.9 | 1 265.9 |
| Purchase of treasury shares | - | - | - | - | - | -14.4 | -14.4 | -14.4 |
| Share-based payments | - | - | - | - | - | 0.7 | 0.7 | 0.7 |
| Equity as of 30.09.2024 | 84.3 | 12 946.6 | 573.1 | -0.2 | 179.8 | -1 307.0 | -554.2 | 12 476.8 |
| Dividend distributed | - | - | - | - | - | -379.2 | -379.2 | -379.2 |
| Profit/loss for the period | - | - | - | - | - | 561.8 | 561.8 | 561.8 |
| Sale of treasury shares | - | - | - | - | - | 31.4 | 31.4 | 31.4 |
| Share-based payments | - | - | - | - | - | 0.3 | 0.3 | 0.3 |
| Other comprehensive income for the period | - | - | - | 0.1 | - | - | 0.1 | 0.1 |
| Equity as of 31.12.2024 | 84.3 | 12 946.6 | 573.1 | -0.1 | 179.8 | -1 092.7 | -339.9 | 12 691.1 |
STATEMENT OF CASH FLOWS (UNAUDITED)
| Group | ||||||
|---|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | |||
| (USD million) | Note | 2024 | 2024 | 2023 | 2024 | 2023 |
| CASH FLOW FROM OPERATING ACTIVITIES | ||||||
| Profit/loss before taxes | 2 052.0 | 1 627.1 | 2 168.3 | 8 048.7 | 8 764.0 | |
| Taxes paid | 5 | -1 165.9 | -458.2 | -2 207.2 | -4 763.8 | -7 455.2 |
| Taxes refunded | 5 | 1.9 | 34.3 | - | 36.2 | - |
| Depreciation | 6 | 603.5 | 613.9 | 605.8 | 2 397.8 | 2 406.8 |
| Impairment | 6,7 | 35.4 | 303.5 | 414.8 | 421.6 | 889.5 |
| Expensed capitalised dry wells | 3,6 | 79.3 | 3.8 | 38.5 | 194.1 | 153.9 |
| Accretion expenses related to abandonment provision | 4,12 | 44.6 | 46.0 | 44.1 | 184.1 | 166.3 |
| Total interest expenses | 4 | 15.7 | 24.2 | 36.0 | 95.5 | 161.8 |
| Changes in unrealised gain/loss in derivatives | 1,4 | 223.1 | -59.9 | -260.8 | 354.6 | -48.8 |
| Changes in inventories and trade creditors/receivables | -315.4 | 585.9 | 505.8 | -104.7 | 575.0 | |
| Changes in other balance sheet items | -511.7 | 36.0 | 157.3 | -441.7 | -206.3 | |
| NET CASH FLOW FROM OPERATING ACTIVITIES | 1 062.5 | 2 756.5 | 1 502.6 | 6 422.6 | 5 407.1 | |
| CASH FLOW FROM INVESTMENT ACTIVITIES | ||||||
| Payment for removal and decommissioning of oil fields | 12 | -10.7 | -66.5 | -31.1 | -202.5 | -152.7 |
| Disbursements on investments in fixed assets (excluding capitalised interest) | 6 | -1 272.1 | -1 257.5 | -1 053.8 | -4 773.7 | -3 171.6 |
| Disbursements on investments in capitalised exploration expenditures | 6 | -83.4 | -77.5 | -52.0 | -338.7 | -238.6 |
| Investments in financial asset | - | - | 95.0 | - | 95.0 | |
| NET CASH FLOW FROM INVESTMENT ACTIVITIES | -1 366.2 | -1 401.6 | -1 041.9 | -5 315.0 | -3 467.9 | |
| CASH FLOW FROM FINANCING ACTIVITIES | ||||||
| Net drawdown/repayment/fees related to revolving credit facility | - | -1.5 | -7.3 | -1.5 | -8.3 | |
| Repayment of bonds | -645.5 | - | - | -645.5 | -1 000.0 | |
| Net proceeds from bond issue | 1 481.2 | - | -0.0 | 2 287.7 | 1 486.1 | |
| Interest paid (including interest element of lease payments) | -58.9 | -66.9 | -65.5 | -266.0 | -251.8 | |
| Payments on lease debt related to investments in fixed assets | -11.0 | -11.1 | -23.0 | -52.6 | -79.5 | |
| Payments on other lease debt | -29.7 | -30.5 | -11.9 | -106.5 | -54.0 | |
| Paid dividend | -379.2 | -379.2 | -347.6 | -1 516.9 | -1 390.4 | |
| Net purchase/sale of treasury shares | 31.4 | -2.2 | 22.5 | 17.0 | -10.5 | |
| NET CASH FLOW FROM FINANCING ACTIVITIES | 388.2 | -491.4 | -432.8 | -284.2 | -1 308.5 | |
| Net change in cash and cash equivalents | 84.5 | 863.5 | 27.9 | 823.4 | 630.7 | |
| Cash and cash equivalents at start of period | 4 147.4 | 3 233.3 | 3 375.2 | 3 388.4 | 2 756.0 | |
| Effect of exchange rate fluctuation on cash and cash equivalents | -84.9 | 50.5 | -14.7 | -64.8 | 1.7 | |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 10 | 4 146.9 | 4 147.4 | 3 388.4 | 4 146.9 | 3 388.4 |
| SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD | ||||||
| Bank deposits and cash | 4 125.8 | 4 125.1 | 3 366.9 | 4 125.8 | 3 366.9 | |
| Restricted bank deposits | 21.2 | 22.3 | 21.5 | 21.2 | 21.5 | |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 10 | 4 146.9 | 4 147.4 | 3 388.4 | 4 146.9 | 3 388.4 |
NOTES (unaudited)
(All figures in USD million unless otherwise stated)
These unaudited condensed consolidated interim financial statements ("interim financial statements") have been prepared in accordance with the IFRS® Accounting Standards as adopted by the EU IAS 34 "Interim Financial Reporting", thus the interim financial statements do not include all information required by IFRS and should be read in conjunction with the group's 2023 annual financial statements. The interim financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair statement of the financial position, results of operations and cash flows for the dates and interim periods presented. Interim period results are not necessarily indicative of results of operations or cash flows for an annual period. These interim financial statements have not been subject to a review in accordance with the International Standard on Review Engagements 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity.
These interim financial statements were authorised for issue by the company's Board of Directors on 11 February 2025.
Note 1 Income
| Group | ||||||||
|---|---|---|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | |||||
| Breakdown of petroleum revenues (USD million) | 2024 | 2024 | 2023 | 2024 | 2023 | |||
| Sales of liquids | 2 545.5 | 2 548.0 | 3 140.2 | 10 853.2 | 11 849.8 | |||
| Sales of gas | 477.0 | 271.0 | 397.9 | 1 375.7 | 1 714.5 | |||
| Tariff income | 3.1 | 3.3 | 3.7 | 13.8 | 15.7 | |||
| Total petroleum revenues | 3 025.6 | 2 822.4 | 3 541.8 | 12 242.7 | 13 580.0 | |||
| Sales of liquids (boe million) | 34.4 | 31.7 | 37.6 | 135.5 | 145.2 | |||
| Sales of gas (boe million) | 6.0 | 4.3 | 5.4 | 21.9 | 23.1 | |||
| Other income (USD million) | ||||||||
| Realised gain (+)/loss (-) on commodity derivatives | 0.0 | -0.0 | - | 0.3 | -0.0 | |||
| Unrealised gain (+)/loss (-) on commodity derivatives | 0.2 | -0.8 | -0.8 | -0.8 | 0.2 | |||
| Gain on licence transactions | - | - | 0.0 | - | 0.0 | |||
| Other income1) | 41.9 | 36.0 | 15.1 | 137.3 | 89.7 | |||
| Total other income | 42.1 | 35.2 | 14.3 | 136.7 | 89.9 |
1) The figure includes partner coverage of assets recognised on gross basis in the balance sheet and used in operated activity.
Note 2 Production expenses
| Group | |||||
|---|---|---|---|---|---|
| Breakdown of production expenses (USD million) | Q4 | Q3 | Q4 | 01.01.-31.12. | |
| 2024 | 2024 | 2023 | 2024 | 2023 | |
| Cost of operations | 168.3 | 185.9 | 179.8 | 702.1 | 707.6 |
| Shipping and handling | 56.8 | 53.5 | 58.2 | 242.4 | 265.7 |
| Environmental taxes | 10.8 | 10.8 | 16.2 | 46.2 | 62.9 |
| Production expenses based on produced volumes | 235.9 | 250.3 | 254.2 | 990.7 | 1 036.3 |
| Adjustment for over (+)/underlift (-) | -6.8 | -64.1 | 43.8 | -74.3 | 23.8 |
| Production expenses based on sold volumes | 229.1 | 186.1 | 298.0 | 916.4 | 1 060.1 |
| Total produced volumes (boe million) | 41.3 | 38.2 | 40.9 | 160.7 | 166.7 |
| Production expenses per boe produced (USD/boe) | 5.7 | 6.6 | 6.2 | 6.2 | 6.2 |
Note 3 Exploration expenses
| Group | ||||||
|---|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | |||
| Breakdown of exploration expenses (USD million) | 2024 | 2024 | 2023 | 2024 | 2023 | |
| Seismic | 6.1 | 8.9 | 5.1 | 27.8 | 27.2 | |
| Area fee | 0.4 | 4.3 | 1.1 | 10.6 | 14.4 | |
| Field evaluation | 10.7 | 10.3 | 6.0 | 39.0 | 13.5 | |
| Dry well expenses1) | 79.3 | 3.8 | 38.5 | 194.1 | 153.9 | |
| G&G and other exploration expenses | 14.2 | 12.7 | 16.2 | 55.0 | 57.5 | |
| Total exploration expenses | 110.7 | 40.0 | 67.0 | 326.5 | 266.3 |
1) Dry well expenses in Q4 2024 are mainly related to Kaldafjell, Rumpetroll South and Kvernbit.
Note 4 Financial items
| Group | |||||
|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | ||
| (USD million) | 2024 | 2024 | 2023 | 2024 | 2023 |
| Interest income | 47.7 | 42.8 | 42.0 | 162.9 | 133.4 |
| Realised gains on derivatives | 10.9 | 7.0 | 13.3 | 62.8 | 83.4 |
| Change in fair value of derivatives | - | 61.0 | 261.7 | 4.8 | 48.6 |
| Net currency gains | 227.4 | - | - | 323.5 | 144.8 |
| Other financial income | 0.0 | 0.0 | 0.5 | 0.5 | 44.5 |
| Total other financial income | 238.3 | 68.1 | 275.4 | 391.7 | 321.2 |
| Interest expenses | 81.5 | 68.3 | 56.6 | 265.1 | 212.7 |
| Interest on lease debt | 9.5 | 9.5 | 9.6 | 38.1 | 26.9 |
| Amortised loan costs1) | 8.1 | 11.7 | 11.5 | 42.9 | 49.3 |
| Capitalised borrowing costs, development projects | -83.4 | -65.4 | -41.7 | -250.6 | -127.1 |
| Total interest expenses | 15.7 | 24.2 | 36.0 | 95.5 | 161.8 |
| Net currency loss | - | 60.5 | 194.8 | - | - |
| Realised loss on derivatives | 23.2 | 47.3 | 27.7 | 123.5 | 345.2 |
| Change in fair value of derivatives | 223.3 | 0.4 | - | 358.7 | - |
| Accretion expenses related to abandonment provision | 44.6 | 46.0 | 44.1 | 184.1 | 166.3 |
| Other financial expenses | 6.2 | 0.2 | 0.2 | 7.7 | 6.7 |
| Total other financial expenses | 297.2 | 154.4 | 266.8 | 674.0 | 518.2 |
| Net financial items | -26.9 | -67.8 | 14.6 | -214.9 | -225.4 |
1) The figure mainly consists of the amortisation of the difference between fair value and nominal value on the bonds acquired in the Lundin transaction in 2022.
Note 5 Tax
| Group | |||||
|---|---|---|---|---|---|
| Q4 Q3 Q4 01.01.-31.12. |
|||||
| Tax for the period (USD million) | 2024 | 2024 | 2023 | 2024 | 2023 |
| Current year tax payable/receivable | 858.9 | 781.3 | 1 554.1 | 3 883.1 | 6 136.4 |
| Change in current year deferred tax | 626.8 | 671.8 | 409.6 | 2 398.3 | 1 200.5 |
| Prior period adjustments | 4.5 | 0.7 | 40.9 | -60.4 | 91.4 |
| Tax expense (+)/income (-) | 1 490.2 | 1 453.7 | 2 004.6 | 6 221.0 | 7 428.3 |
| Group | |||
|---|---|---|---|
| 2024 | 2024 | 2023 | |
| Calculated tax payable (-)/tax receivable (+) (USD million) | Q4 | 01.01.-30.09. | 01.01.-31.12. |
| Tax payable/receivable at beginning of period | -2 903.8 | -3 599.9 | -5 084.1 |
| Current year tax payable/receivable | -858.9 | -3 024.2 | -6 136.4 |
| Net tax payment/refund | 1 163.9 | 3 563.6 | 7 455.2 |
| Prior period adjustments and change in estimate of uncertain tax positions | -4.4 | 54.8 | -58.4 |
| Currency movements of tax payable/receivable | 169.5 | 102.0 | 223.9 |
| Net tax payable (-)/receivable (+) | -2 433.6 | -2 903.8 | -3 599.9 |
| Group | |||
| 2024 | 2024 | 2023 | |
| Deferred tax liability (-)/asset (+) (USD million) | Q4 | 01.01.-30.09. | 01.01.-31.12. |
| Deferred tax liability/asset at beginning of period | -12 363.2 | -10 592.3 | -9 359.1 |
|---|---|---|---|
| Change in current year deferred tax | -626.8 | -1 771.5 | -1 200.5 |
| Prior period adjustments | -0.1 | 0.6 | -32.7 |
| Deferred tax charged to other comprehensive income (mainly foreign currency translation) | 0.0 | - | -0.0 |
| Net deferred tax liability (-)/asset (+) | -12 990.0 | -12 363.2 | -10 592.3 |
| Group | |||||
|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | ||
| Reconciliation of tax expense (USD million) | 2024 | 2024 | 2023 | 2024 | 2023 |
| 78 % tax rate on profit/loss before tax | 1 600.6 | 1 269.2 | 1 691.4 | 6 278.3 | 6 836.3 |
| Tax effect of uplift | -100.5 | -98.2 | -69.6 | -367.8 | -209.9 |
| Permanent difference on impairment | - | 236.8 | 320.8 | 301.2 | 618.0 |
| Foreign currency translation of monetary items other than USD | -175.7 | 46.9 | 150.6 | -249.1 | -112.0 |
| Foreign currency translation of monetary items other than NOK1) | -37.7 | 5.1 | 21.4 | -54.4 | -10.1 |
| Tax effect of financial and other 22 % items1) | 110.0 | 24.3 | -87.5 | 262.8 | 172.6 |
| Currency movements of tax balances | 81.1 | -20.9 | -64.2 | 109.0 | 29.1 |
| Other permanent differences, prior period adjustments and change in estimate of uncertain tax positions |
12.5 | -9.4 | 41.6 | -59.0 | 104.4 |
| Tax expense (+)/income (-) | 1 490.2 | 1 453.7 | 2 004.6 | 6 221.0 | 7 428.3 |
1) Prior to Q1 2024, the foreign currency translation of monetary items other than NOK was calculated based on 78 % tax rate, while parts of this adjustment had a contra entry under Tax effect of financial and other 22% items due to limited tax deduction on currency items. From Q1 2024 the applicable tax rate has been applied to avoid the grossing effect in these two lines. Prior periods have been adjusted accordingly.
The financial statements of the company are presented in USD, its functional currency. However, as per statutory regulations, current taxes are calculated as if NOK was the functional currency. Consequently, when determining taxable income, currency gains and losses from the financial statements are replaced with the translation effect of monetary items other than NOK. Tax balances are maintained in NOK and converted to USD using the period-end exchange rate. These adjustments can influence the effective tax rate, due to fluctuations in the exchange rate between NOK and USD.
Note 6 Tangible fixed assets and intangible assets
TANGIBLE FIXED ASSETS - GROUP
| Property, plant and equipment | Production | Fixtures and | ||
|---|---|---|---|---|
| Assets under | facilities | fittings, office | ||
| (USD million) | development | including wells | machinery | Total |
| Book value 31.12.2023 | 3 522.9 | 13 872.3 | 54.5 | 17 449.8 |
| Acquisition cost 31.12.2023 | 3 556.9 | 22 565.8 | 281.2 | 26 404.0 |
| Additions | 3 218.3 | 654.2 | 22.2 | 3 894.8 |
| Disposals/retirement | - | - | - | - |
| Reclassification | -552.8 | 606.9 | -0.0 | 54.0 |
| Acquisition cost 30.09.2024 | 6 222.4 | 23 826.9 | 303.4 | 30 352.7 |
| Accumulated depreciation and impairments 31.12.2023 | 34.0 | 8 693.5 | 226.6 | 8 954.2 |
| Depreciation | - | 1 575.4 | 20.6 | 1 596.0 |
| Impairment/reversal (-) | - | - | - | - |
| Disposals/retirement depreciation | - | - | - | - |
| Accumulated depreciation and impairments 30.09.2024 | 34.0 | 10 268.9 | 247.2 | 10 550.2 |
| Book value 30.09.2024 | 6 188.4 | 13 558.0 | 56.2 | 19 802.6 |
| Acquisition cost 30.09.2024 | 6 222.4 | 23 826.9 | 303.4 | 30 352.7 |
| Additions | 1 292.4 | -398.2 | 4.5 | 898.6 |
| Disposals/retirement | - | - | - | - |
| Reclassification | 49.9 | 7.8 | - | 57.7 |
| Acquisition cost 31.12.2024 | 7 564.7 | 23 436.6 | 307.9 | 31 309.1 |
| Accumulated depreciation and impairments 30.09.2024 | 34.0 | 10 268.9 | 247.2 | 10 550.2 |
| Depreciation | - | 512.8 | 7.8 | 520.6 |
| Impairment/reversal (-) | -0.0 | - | - | -0.0 |
| Disposals/retirement depreciation | - | - | - | - |
| Accumulated depreciation and impairments 31.12.2024 | 34.0 | 10 781.7 | 255.0 | 11 070.7 |
| Book value 31.12.2024 | 7 530.7 | 12 654.9 | 52.9 | 20 238.4 |
Production facilities, including wells, are depreciated in accordance with the unit-of-production method. Office machinery, fixtures and fittings etc. are depreciated using the straightline method over their useful life, i.e. 3 - 5 years. Estimated future Removal and decommissioning costs are included as part of cost of production facilities or fields under developement. The additions in Q4 is impacted by decreased abandonment provision as a result of updated discount rate, as described in note 12.
Right-of-use assets
| Vessels and | |||||
|---|---|---|---|---|---|
| (USD million) | Drilling Rigs | Boats | Office | Other | Total |
| Book value 31.12.2023 | 561.4 | 37.4 | 55.1 | 1.4 | 655.3 |
| Acquisition cost 31.12.2023 | 591.0 | 51.2 | 95.5 | 2.3 | 740.0 |
| Additions | 191.7 | - | - | - | 191.7 |
| Allocated to abandonment activity | -24.9 | - | - | - | -24.9 |
| Disposals/retirement | - | - | 20.7 | - | 20.7 |
| Reclassification | -74.2 | - | - | - | -74.2 |
| Acquisition cost 30.09.2024 | 683.7 | 51.2 | 74.8 | 2.3 | 812.0 |
| Accumulated depreciation and impairments 31.12.2023 | 29.7 | 13.8 | 40.4 | 0.9 | 84.7 |
| Depreciation | 43.4 | 5.0 | 11.6 | 0.1 | 60.2 |
| Impairment/reversal (-) | - | - | - | - | - |
| Disposals/retirement depreciation | - | - | -6.3 | - | -6.3 |
| Accumulated depreciation and impairments 30.09.2024 | 73.1 | 18.8 | 45.7 | 1.0 | 138.5 |
| Book value 30.09.2024 | 610.6 | 32.4 | 29.1 | 1.3 | 673.4 |
| Acquisition cost 30.09.2024 | 683.7 | 51.2 | 74.8 | 2.3 | 812.0 |
| Additions1) | -41.8 | - | - | - | -41.8 |
| Allocated to abandonment activity | - | - | - | - | - |
| Disposals/retirement | - | - | - | - | - |
| Reclassification2) | -23.4 | - | - | - | -23.4 |
| Acquisition cost 31.12.2024 | 618.5 | 51.2 | 74.8 | 2.3 | 746.8 |
| Accumulated depreciation and impairments 30.09.2024 | 73.1 | 18.8 | 45.7 | 1.0 | 138.5 |
| Depreciation | 24.4 | 1.7 | 3.4 | 0.0 | 29.4 |
| Impairment/reversal (-) | - | - | - | - | - |
| Disposals/retirement depreciation | - | - | - | - | - |
| Accumulated depreciation and impairments 31.12.2024 | 97.5 | 20.4 | 49.0 | 1.1 | 168.0 |
| Book value 31.12.2024 | 521.0 | 30.8 | 25.8 | 1.2 | 578.8 |
1) Impacted by change in lease period and update of future rig rate assumptions.
2) Reclassified to tangible and intangible assets in line with the activity of the right-of-use asset.
Right-of-use assets are depreciated linearly over the lifetime of the related lease contract.
INTANGIBLE ASSETS - GROUP
| Capitalised | |||||
|---|---|---|---|---|---|
| (USD million) | Goodwill | exploration expenditures |
Other intangible assets Depreciated Not depreciated Total |
||
| Book value 31.12.2023 | 13 142.8 | 325.4 | 1 342.0 | 781.4 | 2 123.4 |
| Acquisition cost 31.12.2023 | 15 014.1 | 544.3 | 2 440.4 | 947.6 | 3 388.1 |
| Additions | - | 255.4 | - | 5.6 | 5.6 |
| Disposals/retirement/expensed dry wells | - | 114.8 | - | - | - |
| Reclassification | - | 20.1 | 128.1 | -128.1 | - |
| Acquisition cost 30.09.2024 | 15 014.1 | 705.0 | 2 568.5 | 825.2 | 3 393.7 |
| Accumulated depreciation and impairments 31.12.2023 | 1 871.4 | 218.9 | 1 098.4 | 166.3 | 1 264.7 |
| Depreciation | - | - | 138.2 | - | 138.2 |
| Impairment/reversal (-) | 386.2 | - | - | - | - |
| Disposals/retirement depreciation | - | - | 30.8 | -30.8 | - |
| Accumulated depreciation and impairments 30.09.2024 | 2 257.5 | 218.9 | 1 267.4 | 135.5 | 1 402.9 |
| Book value 30.09.2024 | 12 756.6 | 486.1 | 1 301.1 | 689.7 | 1 990.8 |
| Acquisition cost 30.09.2024 | 15 014.1 | 705.0 | 2 568.5 | 825.2 | 3 393.7 |
| Additions | - | 83.4 | - | 0.3 | 0.3 |
| Disposals/retirement/expensed dry wells | - | 79.3 | - | - | - |
| Reclassification | - | -34.3 | - | - | - |
| Acquisition cost 31.12.2024 | 15 014.1 | 674.7 | 2 568.5 | 825.4 | 3 393.9 |
| Accumulated depreciation and impairments 30.09.2024 | 2 257.5 | 218.9 | 1 267.4 | 135.5 | 1 402.9 |
| Depreciation | - | - | 53.4 | - | 53.4 |
| Impairment/reversal (-) | - | 35.4 | - | - | - |
| Disposals/retirement depreciation | - | - | - | - | - |
| Accumulated depreciation and impairments 31.12.2024 | 2 257.5 | 254.4 | 1 320.8 | 135.5 | 1 456.3 |
| Book value 31.12.2024 | 12 756.6 | 420.4 | 1 247.7 | 689.9 | 1 937.6 |
Other intangible assets include both planned and producing projects on various fields. The producing projects are depreciated in line with the unit-of-production method for the applicable field.
| Group | |||||
|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | ||
| Depreciation in the income statement (USD million) | 2024 | 2024 | 2023 | 2024 | 2023 |
| Depreciation of tangible fixed assets | 520.6 | 545.7 | 546.1 | 2 116.5 | 2 170.6 |
| Depreciation of right-of-use assets | 29.4 | 21.9 | 15.1 | 89.6 | 49.1 |
| Depreciation of other intangible assets | 53.4 | 46.3 | 44.6 | 191.7 | 187.1 |
| Total depreciation in the income statement | 603.5 | 613.9 | 605.8 | 2 397.8 | 2 406.8 |
| Impairment in the income statement (USD million) | |||||
| Impairment/reversal of tangible fixed assets | -0.0 | - | 3.1 | -0.0 | 34.0 |
| Impairment/reversal of other intangible assets | - | - | - | - | 42.9 |
| Impairment/reversal of capitalised exploration expenditures | 35.4 | - | 0.5 | 35.4 | 20.4 |
| Impairment of goodwill | - | 303.5 | 411.2 | 386.2 | 792.2 |
| Total impairment in the income statement | 35.4 | 303.5 | 414.8 | 421.6 | 889.5 |
Note 7 Impairments
Impairment testing
Impairment tests of individual cash-generating units are performed when impairment/reversal triggers are identified, and goodwill is tested for impairment at least annually. In Q4 2024, two categories of impairment tests have been performed:
- Impairment test of fixed assets and related intangible assets, including technical goodwill
- Impairment test of residual goodwill
Impairment is recognised when the book value of an asset or a cash-generating unit, including associated goodwill, exceeds the recoverable amount. Correspondingly, a reversal of impairment is recognised when the recoverable amount exceeds the book value. Prior period impairment of goodwill is not subject to reversal. The recoverable amount is the higher of the asset's fair value less cost to sell and value in use. The impairment testing for Q4 has been performed in accordance with the fair value method (level 3 in fair value hierarchy) and based on discounted cash flows. The expected future cash flow is discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money, and the specific risk related to the asset. The discount rate is derived from the weighted average cost of capital (WACC) for a market participant. Cash flows are projected for the estimated lifetime of the fields, which may exceed periods greater than five years.
For producing licences and licences in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Below is an overview of the key assumptions applied for impairment testing purposes as of 31 December 2024.
Prices
Future price level is a key assumption and has significant impact on the net present value. Forecasted oil and gas prices are based on management's estimates and available market data. Information about market prices in the near future can be derived from the futures contract market. The information about future prices is less reliable on a long-term basis, as there are fewer observable market transactions going forward. In the impairment test, the oil and gas prices are therefore based on the forward curve from the beginning of Q1 2025 to the end of Q4 2027. From Q1 2028, the oil and gas prices are based on the company's long-term price assumptions. Long-term oil price assumption is updated from 71.4 USD/BOE for the period 2028-2035 and from 66.3 USD/BOE for the period from 2036 to 73.5 USD/BOE for the period 2028 and thereafter. Long-term gas price assumption is updated from 0.70 GBP/therm to 0.74 GBP/therm.
The nominal oil prices applied in the impairment test are as follows:
| 2024 | 2024 | |
|---|---|---|
| Nominal oil prices (USD/BOE) | Q4 | Q3 |
| 2025 | 73.3 | 71.0 |
| 2026 | 70.6 | 70.4 |
| 2027 | 69.2 | 71.7 |
| From 2028 to 2035 (in real 2024 terms) | 73.5 | 71.4 |
| From 2036 (in real 2024 terms) | 73.5 | 66.3 |
The nominal gas prices applied in the impairment test are as follows:
| 2024 | 2024 | |
|---|---|---|
| Nominal gas prices (GBP/therm) | Q4 | Q3 |
| 2025 | 1.17 | 0.95 |
| 2026 | 0.98 | 0.85 |
| 2027 | 0.82 | 0.74 |
| From 2028 (in real 2024 terms) | 0.74 | 0.70 |
Oil and gas reserves
Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable reserves including potentially additional risked volumes.
Future expenditure
Future capex, opex and abandonment cost are calculated based on the expected production profiles and the best estimate of the related cost. The cost profiles include an estimated impact of the currently high cost escalation in the industry.
Discount rate
The post tax nominal discount rate used is 8.8 percent, updated from 8.9 percent applied in previous quarters.
Currency rates
| 2024 | 2024 | |
|---|---|---|
| USD/NOK | Q4 | Q3 |
| 2025 | 11.38 | 10.56 |
| 2026 | 11.35 | 10.55 |
| 2027 | 11.32 | 10.03 |
| From 2028 | 10.00 | 8.50 |
The long-term currency rate is updated to 10.00 from 8.50 applied in previous quarters.
Inflation
The long-term inflation rate is assumed to be 2.0 percent. The currently high cost escalation in the industry is reflected in the cash flows rather than in the inflation rate.
Impairment testing of assets including technical goodwill
The technical goodwill recognised in previous business combinations is allocated to each CGU for the purpose of impairment testing. Hence, the impairment test of technical goodwill is included in the impairment testing of assets, and the technical goodwill is written down before the asset. The carrying value of the assets is the sum of tangible assets, intangible assets and technical goodwill as of the assessment date. In line with the methodology described in the annual report, deferred tax (from the date of acquisitions) reduces the net carrying value prior to the impairment charges. When deferred tax liabilities from the acquisitions decreases as a result of depreciation, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable.
No impairment is recognised for fixed assets including technical goodwill as of 31 December 2024, mainly due to the increase in long-term oil and gas prices and USD/NOK currency rate compared to previous quarter.
Exploration assets
During the quarter, an impairment charge of in total USD 35.4 million has been recognised mainly related to the former exploration wells Ferdinand, Hassel and Muskovitt.
Year to date impairment charge
For the twelve months period ended 31 December 2024 a total impairment charge of USD 421.6 million has been recognised. The impairment is allocated to the Grieg Aasen CGU (USD 218.8 million), Valhall CGU (USD 53.1 million), Johan Sverdrup CGU (114.4 million) and is related to technical goodwill, in addition to exploration assets (35.4 million). Reference is also made to note 6.
Sensitivity analysis
The table below shows how the recorded impairment or reversal of impairment for the current period would be affected by changes in the various assumptions, given that the remaining assumptions are constant. The figures in the table below are in all material respect related to impairment of technical goodwill, which would have no impact on deferred tax.
| Change in impairment after | ||||
|---|---|---|---|---|
| Assumption (USD million) | Change | Increase in assumptions |
Decrease in assumptions |
|
| Oil and gas price forward period | +/- 50 % | - | 2 366.5 | |
| Oil and gas price long-term | +/- 20 % | - | 1 187.9 | |
| Production profile (reserves) | +/- 5 % | - | 311.5 | |
| Discount rate | +/- 1 % point | 40.2 | - | |
| Currency rate USD/NOK | +/- 2.0 NOK | - | 321.9 | |
| Inflation | +/- 1 % point | - | 482.9 |
Residual goodwill
Residual goodwill is assessed for impairment at the corporate level, and is based on a comparison between fair value and book value of equity. The fair value is calculated using the share price as of the balance sheet date, converted to USD based on the USD/NOK exchange rate at the end of the period, and adjusted for a control premium (classified as level 3 in the fair value hierarchy). As of year-end 2024, the fair value exceeds the book value of equity, and no impairment is thus recognised.
Climate related risks
The climate related risk assessment is generally described in the company's sustainability reporting. For financial reporting, the transition risk (market, regulatory, reputation, technical and operational) is deemed as the most important, and this has been integrated in the economic assumptions used for impairment testing. This includes a step up of CO2 tax/fees from current levels to approximately NOK 2 500 per tonn (in real 2024 terms) in 2030.
In addition, various scenarios from International Energy Agency have been included in a separate sensitivity test as presented below. The price assumptions in those senarios have been provided by IEA at 2030 and 2050 in 2023 real terms. For the sensitivity calculation, a linear development between the average price for 2024 and IEA price in 2030, as well as between 2030 and 2050 have been applied. The table below summarizes how the impairment charge would increase (+) or decrease (-) using the oil and gas price assumptions in the following scenarios:
| Change in impairment | |||
|---|---|---|---|
| Announced | |||
| IEA Scenario (USD million) | Stated Policies | Pledges | Net Zero |
| Valhall CGU | - | 118.2 | 3 491.1 |
| Skarv CGU | - | - | - |
| Ula CGU | - | - | - |
| Alvheim CGU | - | - | 306.3 |
| Johan Sverdrup CGU | - | - | 1 284.5 |
| Grieg Aasen CGU | - | - | 473.2 |
| Yggdrasil CGU | - | - | 368.1 |
| Verdande CGU | - | - | - |
| Total | - | 118.2 | 5 923.3 |
| Oil USD/bbl | Gas USD/mmbtu | |||
|---|---|---|---|---|
| Scenario price ranges | 2030 | 2050 | 2030 | 2050 |
| Stated Policies | 79 | 75 | 6.5 | 7.7 |
| Announced Pledges | 72 | 58 | 6.0 | 5.2 |
| Net Zero | 42 | 25 | 4.4 | 4.0 |
Note 8 Other short-term receivables
| Group | |||
|---|---|---|---|
| (USD million) | 31.12.2024 | 30.09.2024 | 31.12.2023 |
| Prepayments | 390.8 | 344.2 | 279.7 |
| VAT receivable | 45.6 | 18.3 | 18.8 |
| Underlift of petroleum | 97.9 | 111.6 | 41.7 |
| Other receivables, mainly balances with licence partners | 262.1 | 194.5 | 185.1 |
| Total other short-term receivables | 796.4 | 668.6 | 525.3 |
Prior to Q1 2024, accrued income from sale of petroleum products was included in other short-term receivables. From Q1 2024, these receivables have been presented as part of trade receivables. Previous periods have been adjusted accordingly.
Note 9 Leasing
The incremental borrowing rate applied in discounting of the nominal lease debt is between 2.5 percent and 6.9 percent, dependent on the duration of the lease and when it was initially recognised.
| Group | ||||
|---|---|---|---|---|
| 2024 | 2024 | 2023 | ||
| (USD million) | Q4 | 01.01.-30.09. | 01.01.-31.12. | |
| Lease debt as of beginning of period | 760.2 | 704.2 | 134.4 | |
| New leases and remeasurements2) | -41.8 | 191.7 | 704.5 | |
| Payments of lease debt1) | -50.1 | -147.1 | -160.4 | |
| Lease debt derecognised | - | -14.5 | - | |
| Interest expense on lease debt | 9.5 | 28.6 | 26.9 | |
| Currency exchange differences | -2.1 | -2.7 | -1.2 | |
| Total lease debt | 675.6 | 760.2 | 704.2 | |
| Short-term | 217.7 | 222.1 | 148.7 | |
| Long-term | 458.0 | 538.1 | 555.5 | |
| 1) Payments of lease debt split by activities (USD million): | ||||
| Investments in fixed assets | 16.1 | 49.3 | 95.7 | |
| Abandonment activity | 0.2 | 26.0 | 8.3 | |
| Operating expenditures | 2.3 | 5.3 | 11.3 | |
| Exploration expenditures | 8.6 | 22.9 | 12.0 | |
| Other income | 22.9 | 43.6 | 33.1 | |
| Total | 50.1 | 147.1 | 160.4 |
2) New leases and remeasurements in Q4 2024 are mainly related to change in lease period and update of future rig rate assumptions.
| Group | ||||
|---|---|---|---|---|
| 2024 | 2024 | 2023 | ||
| Nominal lease debt maturity breakdown (USD million): | Q4 | 01.01.-30.09. | 01.01.-31.12. | |
| Within one year | 247.5 | 256.1 | 220.2 | |
| Two to five years | 480.7 | 571.5 | 528.4 | |
| After five years | 1.9 | 2.0 | 11.8 | |
| Total | 730.1 | 829.5 | 760.4 |
The identified leases have no significant impact on the group`s financing, loan covenants or dividend policy. The group does not have any residual value guarantees. Extension options are included in the lease liability when, based on management's judgement, it is reasonably certain that an extension will be exercised.
Note 10 Cash and cash equivalents
The item 'Cash and cash equivalents' consists of bank accounts and time deposits that constitute parts of the group's available liquidity.
| Group | |||
|---|---|---|---|
| Breakdown of cash and cash equivalents (USD million) | 31.12.2024 | 30.09.2024 | 31.12.2023 |
| Bank deposits | 4 125.8 | 4 125.1 | 3 366.9 |
| Restricted bank deposits1) | 21.2 | 22.3 | 21.5 |
| Cash and cash equivalents | 4 146.9 | 4 147.4 | 3 388.4 |
| Undrawn RCF facility | 3 400.0 | 3 400.0 | 3 400.0 |
1) Tax deduction account
The RCF is undrawn as at 31 December 2024 and the remaining unamortised fees of USD 12.3 million related to the facility are therefore included in other non-current assets.
The senior unsecured Revolving Credit Facility (RCF) of USD 3.4 billion was established in May 2019 and consists of two tranches: (1) Working Capital Facility with a committed amount of USD 1.4 billion until 2025 and USD 1.3 billion until 2026, and (2) Liquidity Facility with a committed amount of USD 2.0 billion until 2025 and USD 1.65 billion until 2026.
In November 2023, Aker BP signed a new USD 1.8 billion RCF with 9 banks. The new facility will have a forward date (availability date) at the same time as the existing RCF expires in 2026 and has a maturity in 2029. The facility includes one extension option with potential final maturity in 2030.
The interest rate for the Working Capital Facility is Term SOFR plus a margin of 1.00 percent and for the Liquidity Facility Term SOFR plus a margin of 0.75 percent. The new RCF with forward start in 2026 will have an interest rate of Term SOFR plus a margin of 0.85 percent.
Drawing under the Liquidity Facility and new RCF will add a utilisation fee. A commitment fee of 35 percent of applicable margin is paid on the undrawn part of the Working Capital Facility and Liquidity Facility. Commitment fee will not be relevant for the new RCF before available in 2026. The financial covenants are as follows:
-
Leverage Ratio: Net interest-bearing debt divided by twelve months rolling EBITDAX (excluding any impacts from IFRS 16) shall not exceed 3.5
-
Interest Coverage Ratio: Twelve months rolling EBITDA divided by Interest expenses (excluding any impacts from IFRS 16) shall be a minimum of 3.5
The financial covenants in the group's current debt facilities exclude the effects from IFRS 16, and therefore cannot be directly derived from the group's financial statements. See reconciliations of Alternative Performance Measures for detailed information.
As at 31 December 2024 the Leverage Ratio is 0.29 and Interest Coverage Ratio is 75.9 (see APM section for further details).
Note 11 Bonds
| Outstanding | Group | |||
|---|---|---|---|---|
| Senior unsecured bonds (USD million) | amount | 31.12.2024 | 30.09.2024 | 31.12.2023 |
| Senior Notes 3.000% (Jan 20/Jan 25)2) 3) | USD 63.6 mill | - | - | 94.5 |
| Senior Notes 2.875% (Sep 20/Jan 26)2) 3) | USD 95.5 mill | 95.0 | 128.8 | 128.3 |
| Senior Notes 2.000% (Jul 21/Jul 26)2) 3) 4) | USD 104.8 mill | 100.5 | 674.0 | 660.4 |
| Senior Notes 5.600% (Jun 23/Jun 28) | USD 500 mill | 497.5 | 497.3 | 496.8 |
| Senior Notes 1.125% (May 21/May 29) | EUR 750 mill | 776.0 | 836.3 | 824.8 |
| Senior Notes 3.750% (Jan 20/Jan 30) | USD 1,000 mill | 996.0 | 995.8 | 995.2 |
| Senior Notes 4.000% (Sep 20/Jan 31) | USD 750 mill | 746.5 | 746.3 | 745.9 |
| Senior Notes 3.100% (Jul 21/Jul 31)4) | USD 1,000 mill | 877.9 | 873.2 | 859.3 |
| Senior Notes 4.000% (May 24/May 32) | EUR 750 mill | 772.0 | 832.5 | - |
| Senior Notes 6.000% (Jun 23/Jun 33) | USD 1,000 mill | 993.7 | 993.5 | 993.0 |
| Senior Notes 5.125% (Oct 24/Oct 34)1) | USD 750 mill | 742.0 | - | - |
| Senior Notes 5.800% (Oct 24/Oct 54)1) | USD 750 mill | 739.7 | - | - |
| Long-term bonds - book value | 7 336.8 | 6 577.7 | 5 798.2 | |
| Long-term bonds - fair value | 7 080.0 | 6 555.7 | 5 629.4 | |
| Senior Notes 3.000% (Jan 20/Jan 25)2) 3) | USD 63.6 mill | 63.5 | 95.2 | - |
| Short-term bonds - book value | 63.5 | 95.2 | - | |
| Short-term bonds - fair value | 63.5 | 94.8 | - |
1) In October 2024 the company issued two new US bonds:
-
USD 750 million aggregate principal amount of 5.125 % Senior Notes due 2034
-
USD 750 million aggregate principal amount of 5.800 % Senior Notes due 2054
2) Parts of the proceeds from the new bonds were used to repurchase the following principal amounts:
-
USD 31.9 million on USD Senior Notes 3.000% (Jan 2025)
-
USD 34.2 million on USD Senior Notes 2.875% (Jan 2026)
-
USD 602.3 million on USD Senior Notes 2.000% Senior Notes (Jul 2026)
The fair value of these bonds were lower than the book value at the time of repurchase. Adjusted for expensed amortised cost, this resulted in a net loss of USD 5.7 million presented as other financial expense in Q4 2024.
3) The following principal amounts were repurchased in Q2 2023:
-
USD 404.5 million on USD Senior Notes 3.000% (Jan 2025)
-
USD 370.3 million on USD Senior Notes 2.875% (Jan 2026)
-
USD 292.9 million on USD Senior Notes 2.000% (Jul 2026)
The fair value of these bonds were lower than the book value at the time of repurchase. This resulted in a net gain of USD 43.7 million presented as other financial income in Q2 2023.
4) Prior to the repurchases mentioned above, these bonds had a nominal value of USD 1 billion and were recognised at fair value in connection with the Lundin Energy transaction in 2022. The difference between fair value and nominal value is linearly amortised over the lifetime of the bonds (see note 4).
Interest is paid on a semi annual basis, except for the EUR Senior Notes which are paid on an annual basis. None of the bonds have financial covenants.
Note 12 Provision for abandonment liabilities
| Group | ||||
|---|---|---|---|---|
| 2024 | 2024 | 2023 | ||
| (USD million) | Q4 | 01.01.-30.09. | 01.01.-31.12. | |
| Provisions as of beginning of period | 4 709.9 | 4 554.7 | 4 165.6 | |
| Incurred removal cost | -10.7 | -216.6 | -160.2 | |
| Accretion expense | 44.6 | 139.5 | 166.3 | |
| Impact of changes to discount rate | -493.4 | 135.4 | -101.2 | |
| Change in estimates and new provisions | 29.0 | 97.0 | 484.1 | |
| Total provision for abandonment liabilities | 4 279.4 | 4 709.9 | 4 554.7 | |
| Short-term | 131.7 | 125.4 | 250.6 | |
| Long-term | 4 147.7 | 4 584.6 | 4 304.1 |
The nominal pre-tax discount rate (risk-free) at end of Q4 is between 4.2 percent and 4.6 percent, depending on the timing of the expected cashflows.The corresponding range at end of Q3 was 3.5 to 4.1 percent. The calculations assume an inflation rate of 2.0 percent.
Note 13 Derivatives
| Group | |||
|---|---|---|---|
| (USD million) | 31.12.2024 | 30.09.2024 | 31.12.2023 |
| Unrealised gain currency contracts | 5.0 | 26.1 | 38.1 |
| Long-term derivatives included in assets | 5.0 | 26.1 | 38.1 |
| Unrealised gain commodity derivatives | - | - | 0.2 |
| Unrealised gain currency contracts | 0.3 | 24.5 | 147.9 |
| Short-term derivatives included in assets | 0.3 | 24.5 | 148.1 |
| Total derivatives included in assets | 5.2 | 50.6 | 186.2 |
| Unrealised losses interest rate swaps1) | 7.1 | - | - |
| Unrealised losses currency contracts | 48.1 | 1.2 | 0.5 |
| Long-term derivatives included in liabilities | 55.3 | 1.2 | 0.5 |
| Fair value of option related to sale of Cognite | - | - | 4.8 |
| Unrealised losses commodity derivatives | 0.6 | 0.8 | - |
| Unrealised losses currency contracts | 151.1 | 27.2 | 28.0 |
| Short-term derivatives included in liabilities | 151.7 | 28.0 | 32.8 |
| Total derivatives included in liabilities | 207.0 | 29.2 | 33.3 |
1) USD 400 million of the Senior Notes 5.125% due 2034 has been swapped from a fixed rate to a floating rate using an interest rate swap. Starting from October 2026 until maturity in 2034, the group will pay SOFR plus a fixed spread and receive 5.125% semi-annually.
The group uses various types of financial hedging instruments. Commodity derivatives may be used to hedge the price risk of oil and gas and foreign exchange derivatives are used to hedge the group's currency exposure, mainly in NOK, EUR and GBP.
The derivative portfolio is revalued on a mark to market basis, with changes in value recognised in the income statement. The nature of the derivative instruments and the valuation method are consistent with the disclosed information in the annual financial statements as of 31 December 2023. All derivatives are measured at fair value on a recurring basis (level 2 in the fair value hierarchy, except for Cognite put option which is considered level 3).
As of 31 December 2024, the company has entered into foreign exchange contracts to secure USD value of NOK cashflows for future tax payments and capital expenditure.
Note 14 Other current liabilities
| Group | ||||
|---|---|---|---|---|
| Breakdown of other current liabilities (USD million) | 31.12.2024 | 30.09.2024 | 31.12.2023 | |
| Balances with licence partners | 61.0 | 117.2 | 30.9 | |
| Share of other current liabilities in licences | 771.3 | 882.9 | 692.5 | |
| Overlift of petroleum | 24.7 | 45.2 | 42.8 | |
| Accrued interest | 123.0 | 90.9 | 85.8 | |
| Payroll liabilities and other provisions | 165.8 | 247.5 | 219.2 | |
| Total other current liabilities | 1 145.8 | 1 383.7 | 1 071.0 |
Note 15 Contingent liabilities and assets
During the normal course of its business, the group will be involved in disputes, including tax disputes. The group has made accruals for probable liabilities related to litigation and claims based on management's best judgment and in line with IAS 37 and IAS 12.
Note 16 Subsequent events
The Group 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 that require accounting recognition or diclosure in these interim financial statements.
Note 17 Investments in joint operations
| Total number of licences | 31.12.2024 | 30.09.2024 |
|---|---|---|
| Aker BP as operator | 130 | 130 |
| Aker BP as partner | 62 | 61 |
| Changes in production licences in which Aker BP is the operator: | Changes in production licences in which Aker BP is a partner: | ||||
|---|---|---|---|---|---|
| Licence: | 31.12.2024 | 30.09.2024 Licence: | 31.12.2024 | 30.09.2024 | |
| PL 10662) | 0.000% | 50.000% | PL 102C2) | 0.000% | 10.000% |
| PL 1066B2) | 0.000% | 50.000% | PL 1014¹) | 10.000% | 0.000% |
| PL 1139¹) | 60.000% | 0.000% | PL 1014B¹) | 10.000% | 0.000% |
| PL 1147¹) | 60.000% | 0.000% | PL 1086¹) | 20.000% | 0.000% |
| PL 1090¹) | 20.000% | 30.000% | |||
| PL 1109¹) | 20.000% | 0.000% | |||
| PL 11291) | 0.000% | 30.000% | |||
| PL 11471) | 0.000% | 20.000% | |||
| Total | 2 | 2 Total | 5 | 4 |
1) Part of asset transactions
2) Relinquisher or Aker BP have withdrawn from the licence
End of financial statement
Alternative Performance Measures
Aker BP may disclose alternative performance measures as part of its financial reporting as a supplement to the financial statements prepared in accordance with IFRS. Aker BP believes that the alternative performance measures provide useful supplemental information to management, investors, security analysts and other stakeholders and are meant to provide an enhanced insight into the financial development of Aker BP's business operations and to improve comparability between periods.
Abandonment spend (abex) is payment for removal and decommissioning of oil fields1)
Capex is disbursements on investments in fixed assets1)
Depreciation per boe is depreciation divided by number of barrels of oil equivalents produced in the corresponding period
Dividend per share (DPS) is dividend paid in the quarter divided by number of shares outstanding
EBITDA is short for earnings before interest and other financial items, taxes, depreciation and amortisation and impairments
EBITDAX is short for earnings before interest and other financial items, taxes, depreciation and amortisation, impairments and exploration expenses
Equity ratio is total equity divided by total assets
Exploration spend (expex) is exploration expenses plus additions to capitalised exploration wells less dry well expenses1)
Free cash flow (FCF) is net cash flow from operating activities less net cash flow from investment activities
Interest coverage ratio is calculated as twelve months rolling EBITDA, divided by interest expenses, excluding any impacts from IFRS 16.
Leverage ratio is calculated as Net interest-bearing debt divided by twelve months rolling EBITDAX, excluding any impacts from IFRS 16
Net interest-bearing debt is book value of current and non-current interest-bearing debt less cash and cash equivalents
Operating profit/loss is short for earnings/loss before interest and other financial items and taxes
Production cost per boe is production expenses based on produced volumes, divided by number of barrels of oil equivalents produced in the corresponding period (see note 2)
1) Includes payments of lease debt as disclosed in note 9.
| Q4 | Q3 | Q4 | 01.01.-31.12. | 01.01.-31.12. | ||
|---|---|---|---|---|---|---|
| (USD million) | Note | 2024 | 2024 | 2023 | 2024 | 2023 |
| Abandonment spend | ||||||
| Payment for removal and decommissioning of oil fields | 10.7 | 66.5 | 31.1 | 202.5 | 152.7 | |
| Payments of lease debt (abandonment activity) | 9 | 0.2 | 8.0 | 2.3 | 26.2 | 8.3 |
| Abandonment spend | 10.9 | 74.5 | 33.4 | 228.7 | 161.0 | |
| Depreciation per boe | ||||||
| Depreciation | 6 | 603.5 | 613.9 | 605.8 | 2 397.8 | 2 406.8 |
| Total produced volumes (boe million) | 2 | 41.3 | 38.2 | 40.9 | 160.7 | 166.7 |
| Depreciation per boe | 14.6 | 16.1 | 14.8 | 14.9 | 14.4 | |
| Dividend per share | ||||||
| Paid dividend | 379.2 | 379.2 | 347.6 | 1 516.9 | 1 390.4 | |
| Number of shares outstanding | 631.7 | 630.8 | 631.2 | 631.2 | 631.3 | |
| Dividend per share | 0.60 | 0.60 | 0.55 | 2.40 | 2.20 | |
| Capex | ||||||
| Disbursements on investments in fixed assets (excluding capitalised interest) | 1 272.1 | 1 257.5 | 1 053.8 | 4 773.7 | 3 171.6 | |
| Payments of lease debt (investments in fixed assets) | 9 | 16.1 | 11.1 | 29.3 | 65.4 | 95.7 |
| CAPEX | 1 288.2 | 1 268.6 | 1 083.1 | 4 839.1 | 3 267.3 | |
| EBITDA | ||||||
| Total income | 1 | 3 067.7 | 2 857.6 | 3 556.1 | 12 379.4 | 13 669.9 |
| Production expenses | 2 | -229.1 | -186.1 | -298.0 | -916.4 | -1 060.1 |
| Exploration expenses | 3 | -110.7 | -40.0 | -67.0 | -326.5 | -266.3 |
| Other operating expenses | -10.2 | -19.2 | -16.8 | -53.5 | -57.8 | |
| EBITDA | 2 717.7 | 2 612.2 | 3 174.4 | 11 083.0 | 12 285.7 | |
| EBITDAX | ||||||
| Total income | 1 | 3 067.7 | 2 857.6 | 3 556.1 | 12 379.4 | 13 669.9 |
| Production expenses | 2 | -229.1 | -186.1 | -298.0 | -916.4 | -1 060.1 |
| Other operating expenses | -10.2 | -19.2 | -16.8 | -53.5 | -57.8 | |
| EBITDAX | 2 828.5 | 2 652.2 | 3 241.4 | 11 409.5 | 12 552.0 | |
| Equity ratio | ||||||
| Total equity | 12 691.1 | 12 476.8 | 12 362.2 | 12 691.1 | 12 362.2 | |
| Total assets | 42 192.9 | 41 693.0 | 39 046.5 | 42 192.9 | 39 046.5 | |
| Equity ratio | 30% | 30% | 32% | 30% | 32% | |
| Exploration spend | ||||||
| Disbursements on investments in capitalised exploration expenditures | 83.4 | 77.5 | 52.0 | 338.7 | 238.6 | |
| Exploration expenses | 3 | 110.7 | 40.0 | 67.0 | 326.5 | 266.3 |
| Dry well | 3 | -79.3 | -3.8 | -38.5 | -194.1 | -153.9 |
| Payments of lease debt (exploration expenditures) | 9 | 8.6 | 13.5 | 0.2 | 31.6 | 12.0 |
| Exploration spend | 123.4 | 127.3 | 80.7 | 502.7 | 363.0 |
| Q4 | Q3 | Q4 | 01.01.-31.12. | 01.01.-31.12. | |
|---|---|---|---|---|---|
| Note (USD million) |
2024 | 2024 | 2023 | 2024 | 2023 |
| Interest coverage ratio | |||||
| Twelve months rolling EBITDA | 11 083.0 | 11 539.6 | 12 285.7 | 11 083.0 | 12 285.7 |
| Twelve months rolling EBITDA, impacts from IFRS 16 9 |
-74.8 | -62.3 | -45.2 | -74.8 | -45.2 |
| Twelve months rolling EBITDA, excluding impacts from IFRS 16 | 11 008.2 | 11 477.3 | 12 240.5 | 11 008.2 | 12 240.5 |
| Twelve months rolling interest expenses 4 |
265.1 | 240.1 | 212.7 | 265.1 | 212.7 |
| Twelve months rolling amortised loan cost 4 |
42.9 | 46.3 | 49.3 | 42.9 | 49.3 |
| Twelve months rolling interest income 4 |
162.9 | 157.2 | 133.4 | 162.9 | 133.4 |
| Net interest expenses | 145.1 | 129.3 | 128.5 | 145.1 | 128.5 |
| Interest coverage ratio | 75.9 | 88.8 | 95.2 | 75.9 | 95.2 |
| Leverage ratio | |||||
| Long-term bonds 11 |
7 336.8 | 6 577.7 | 5 798.2 | 7 336.8 | 5 798.2 |
| Short-term bonds 11 |
63.5 | 95.2 | - | 63.5 | - |
| Other interest-bearing debt | - | - | - | - | - |
| Cash and cash equivalents 10 |
4 146.9 | 4 147.4 | 3 388.4 | 4 146.9 | 3 388.4 |
| Net interest-bearing debt excluding lease debt | 3 253.4 | 2 525.5 | 2 409.8 | 3 253.4 | 2 409.8 |
| Twelve months rolling EBITDAX | 11 409.5 | 11 822.4 | 12 552.0 | 11 409.5 | 12 552.0 |
| Twelve months rolling EBITDAX, impacts from IFRS 16 9 |
-74.1 | -61.5 | -44.4 | -74.1 | -44.4 |
| Twelve months rolling EBITDAX, excluding impacts from IFRS 16 | 11 335.4 | 11 760.9 | 12 507.6 | 11 335.4 | 12 507.6 |
| Leverage ratio | 0.29 | 0.21 | 0.19 | 0.29 | 0.19 |
| Net interest-bearing debt | |||||
| Long-term bonds 11 |
7 336.8 | 6 577.7 | 5 798.2 | 7 336.8 | 5 798.2 |
| Other interest-bearing debt | - | - | - | - | - |
| Long-term lease debt 9 |
458.0 | 538.1 | 555.5 | 458.0 | 555.5 |
| Short-term bonds 11 |
63.5 | 95.2 | - | 63.5 | - |
| Short-term lease debt 9 |
217.7 | 222.1 | 148.7 | 217.7 | 148.7 |
| Cash and cash equivalents 10 |
4 146.9 | 4 147.4 | 3 388.4 | 4 146.9 | 3 388.4 |
| Net interest-bearing debt | 3 929.0 | 3 285.7 | 3 114.0 | 3 929.0 | 3 114.0 |
| Free cash flow | |||||
| Net cash flow from operating activities | 1 062.5 | 2 756.5 | 1 502.6 | 6 422.6 | 5 407.1 |
| Net cash flow from investment activities | -1 366.2 | -1 401.6 | -1 041.9 | -5 315.0 | -3 467.9 |
| Free cash flow | -303.7 | 1 355.0 | 460.7 | 1 107.6 | 1 939.2 |
Operating profit/loss see Income Statement
Production cost per boe see note 2
Aker BP ASA
Fornebuporten, Building B Oksenøyveien 10 1366 Lysaker
www.akerbp.com
CONTACT
Postal address: P.O. Box 65 1324 Lysaker, Norway
Telephone: +47 51 35 30 00 E-mail: [email protected]