Quarterly Report • Feb 8, 2024
Quarterly Report
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Aker BP delivered strong operational performance in the fourth quarter of 2023, with low cost and high efficiency, although production volumes were impacted by an unplanned shutdown at Alvheim. All field development projects continued progressing as planned, and the company maintained its low emissions intensity at an industry-leading level.
"We ended the year on a strong note, successfully delivering on our targets despite experiencing some operational challenges in the second half.
I would like to take the opportunity to underscore the strong efforts of our team during the unplanned shutdown at Alvheim, which demonstrate the dedicated commitment and problem-solving capabilities that characterise this company.
Furthermore, I am pleased to confirm that our field development projects are on track. The cost estimates remain unchanged, and we are one year closer to first oil and generating another wave of value creation for Aker BP and our stakeholders.
Ultimately, we maintain our position as a leader in the E&P industry through high efficiency, low operational costs and low emissions."
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.
| UNIT | Q4 2023 | Q3 2023 | Q4 2022 | FY 2023 | FY 2022 | |
|---|---|---|---|---|---|---|
| INCOME STATEMENT | ||||||
| Total income | USD million | 3 556 | 3 513 | 3 826 | 13 670 | 13 010 |
| EBITDA | USD million | 3 174 | 3 174 | 3 491 | 12 286 | 11 782 |
| Net profit/loss | USD million | 164 | 588 | 112 | 1 336 | 1 603 |
| Earnings per share (EPS) | USD | 0.26 | 0.93 | 0.18 | 2.12 | 3.23 |
| OTHER FINANCIAL KEY FIGURES | ||||||
| Net interest-bearing debt | USD million | 3 114 | 2 833 | 2 658 | 3 114 | 2 658 |
| Leverage ratio | 0.19 | 0.19 | 0.21 | 0.19 | 0.21 | |
| Dividend per share | USD | 0.55 | 0.55 | 0.53 | 2.20 | 2.02 |
| PRODUCTION AND SALES | ||||||
| Net petroleum production | mboepd | 444.3 | 449.8 | 432.0 | 456.8 | 309.2 |
| Over/underlift | mboepd | 22.6 | 0.3 | (3.7) | 4.2 | (2.4) |
| Net sold volume | mboepd | 466.9 | 450.0 | 428.3 | 461.0 | 306.8 |
| - Liquids | mboepd | 408.4 | 389.6 | 362.2 | 397.8 | 251.6 |
| - Natural gas | mboepd | 58.5 | 60.5 | 66.0 | 63.2 | 55.2 |
| REALISED PRICES | ||||||
| Liquids | USD/boe | 83.6 | 87.6 | 86.6 | 81.6 | 97.9 |
| Natural gas | USD/boe | 73.9 | 60.5 | 150.4 | 74.3 | 193.4 |
| AVERAGE EXCHANGE RATES | ||||||
| USDNOK | 10.82 | 10.49 | 10.18 | 10.56 | 9.62 | |
| EURUSD | 1.08 | 1.09 | 1.02 | 1.08 | 1.05 |
| (USD MILLION) | Q4 2023 | Q3 2023 | Q4 2022 | FY 2023 | FY 2022 |
|---|---|---|---|---|---|
| Total income | 3 556 | 3 513 | 3 826 | 13 670 | 13 010 |
| EBITDA | 3 174 | 3 174 | 3 491 | 12 286 | 11 782 |
| EBIT | 2 154 | 2 618 | 2 214 | 8 989 | 8 964 |
| Pre-tax profit | 2 168 | 2 565 | 2 177 | 8 764 | 8 777 |
| Net profit/loss | 164 | 588 | 112 | 1 336 | 1 603 |
| EPS (USD) | 0.26 | 0.93 | 0.18 | 2.12 | 3.23 |
Total income in the fourth quarter amounted to USD 3,556 (3,513) million, as higher gas prices and increased volumes were partly offset by lower oil prices. Realised liquids prices decreased by five percent to USD 83.6 (87.6) per boe and realised natural gas price increased by 22 percent to USD 73.9 (60.5) per boe. Sold volumes increased by four percent to 466.9 (450.0) mboepd in the quarter.
Production expenses for the oil and gas sold in the quarter amounted to USD 298 (252) million, with change in over/ underlift as the main reason for the increase from last quarter. The average production cost per barrel produced was USD 6.2 (6.0). See note 2 for further details on production expenses. Exploration expenses amounted to USD 67 (74) million, with lower dry well expenses as the main reason for the decrease.
Depreciation amounted to USD 606 (557) million, equivalent to USD 14.8 (13.5) per boe. The change was mainly driven by increased abandonment provision for Ula. Since this field carries zero book value, any adjustments to such estimates are immediately reflected in the income statement as depreciation.
Impairments amounted to USD 415 (0) million, related to technical goodwill at Edvard Grieg & Ivar Aasen (USD 229 million) and Valhall (USD 183 million). For more information, see note 4.
Operating profit was USD 2,154 (2,618) million for the fourth quarter.
Net financial income amounted to USD 15 (-53) million. The change is mainly caused by the development in currency exchange rates and the related impact on currency loss and gains on currency derivatives. For more details, see note 7 and 13.
Profit before taxes amounted to USD 2,168 (2,565) million. Tax expense was USD 2,005 (1,977) million. The effective tax rate was 92 (77) percent, as the fourth quarter tax rate is impacted by impairment of technical goodwill with no effect on deferred tax.
This resulted in a net profit of USD 164 (588) million.
| (USD MILLION) | 31.12.2023 | 30.09.2023 | 31.12.2022 |
|---|---|---|---|
| Goodwill | 13 143 | 13 554 | 13 935 |
| Property, plant and equipment (PP&E) | 17 450 | 16 123 | 15 887 |
| Other non-current assets | 3 314 | 3 166 | 2 984 |
| Cash and equivalent | 3 388 | 3 375 | 2 756 |
| Other current assets | 1 751 | 1 909 | 2 000 |
| Total assets | 39 047 | 38 127 | 37 562 |
| Equity | 12 362 | 12 524 | 12 428 |
| Bank and bond debt | 5 798 | 5 754 | 5 279 |
| Other long-term liabilities | 15 453 | 14 271 | 13 607 |
| Tax payable | 3 600 | 4 070 | 5 084 |
| Other current liabilities | 1 833 | 1 509 | 1 164 |
| Total equity and liabilities | 39 047 | 38 127 | 37 562 |
| Net interest-bearing debt | 3 114 | 2 833 | 2 658 |
| Leverage ratio | 0.19 | 0.19 | 0.21 |
At the end of the fourth quarter, total assets amounted to USD 39.0 (38.1) billion, of which non-current assets were USD 33.9 (32.8) billion.
Equity amounted to USD 12.4 (12.5) billion at the end of the quarter, corresponding to an equity ratio of 32 (33) percent.
Bond debt totalled USD 5.8 (5.8) billion, and the company's bank facilities were not drawn. Other long-term liabilities amounted to USD 15.5 (14.3) billion, with the increase mainly caused by increased abandonment provision as described in note 14.
After paying two ordinary tax instalments and one additional voluntary instalment during the fourth quarter, tax payable decreased by USD 0.5 billion to 3.6 (4.1) billion.
At the end of the fourth quarter 2023, the company had total available liquidity of USD 6.8 (6.8) billion, comprising USD 3.4 (3.4) billion in cash and cash equivalents and USD 3.4 (3.4) billion in undrawn credit facilities.
| (USD MILLION) | Q4 2023 | Q3 2023 | Q4 2022 | FY 2023 | FY 2022 |
|---|---|---|---|---|---|
| Cash flow from operations | 1 503 | 2 101 | 807 | 5 407 | 5 729 |
| Cash flow from investments | (1 042) | (944) | (708) | (3 468) | (3 117) |
| Cash flow from financing | (433) | (488) | (329) | (1 309) | (1 828) |
| Net change in cash & cash equivalents | 28 | 669 | (231) | 631 | 785 |
| Cash and cash equivalents | 3 388 | 3 375 | 2 756 | 3 388 | 2 756 |
Net cash flow from operating activities was USD 1,503 (2,101) million in the quarter. Taxes paid increased by USD 1,345 million to USD 2,207 (862) million, with three tax instalments paid in the fourth quarter compared to only one ordinary tax instalment in the third quarter. Net cash used for investment activities was USD 1,042 (944) million, of which investments in fixed assets amounted to USD 1,054 (857) million.
Net cash outflow from financing activities was USD 433 (488) million. The main item in the fourth quarter was dividend disbursements of USD 348 (348) million.
The Annual General Meeting has 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 2023, the company paid a dividend of USD 0.55 per share. On 7 February 2024, the Board resolved to pay a quarterly dividend of USD 0.60 per share in the first quarter 2024, which will be disbursed on or about 21 February 2024. The ex-dividend date is 13 February 2024.
The company uses various types of economic hedging instruments. Commodity derivatives are used to mitigate the financial consequences of potential significant negative movements in oil and gas prices. Aker BP currently has limited exposure to fluctuations in interest rates, but generally manages such exposure by using interest rate derivatives. Foreign exchange derivatives are used to manage the company's exposure to currency risks, mainly costs in NOK, EUR, and GBP. Derivatives are marked to market with changes in market value recognized in the income statement.
The company had no material commodity derivatives exposure per 31 December 2023.
Aker BP engaged in one licence transaction during the fourth quarter, involving licence PL 1041 where the company purchased a 30 percent interest from Neptune Energy Norge AS, and simultaneously sold a 20 percent interest to Vår Energi ASA. After the transaction, Aker BP holds 80 percent interest in this licence, which is located just south of Bøyla in the Alvheim area. The transaction has already been approved by the authorities.
In January 2024, Aker BP was offered interests in 27 new production licences offshore Norway, of which 17 as operator, through the APA 2023 licensing round. Of the 27 production licences awarded to Aker BP, 15 are in the North Sea (12 as operator), 7 in the Norwegian Sea (3 as operator) and 5 in the Barents Sea (2 as operator).
In March 2023, Aker BP and OMV entered into a collaboration agreement for carbon capture and storage (CCS) and were awarded a licence in accordance with the CO2 Storage Regulations on the Norwegian Continental Shelf (NCS). The licence is situated in the Norwegian North Sea, approximately 100 km off the Norwegian coast, and it has been named Poseidon. Aker BP is the operator of the licence, with 50 percent interest.
Aker BP is evaluating Poseidon's potential as a business opportunity and as a potential means of reducing the company's net carbon footprint in the future.
A 3D seismic survey over the Poseidon licence area was successfully completed in the third quarter 2023. The partnership is currently preparing for a drill or drop decision.
Aker BP's net production was 40.9 (41.4) million barrels oil equivalent (mmboe) in the fourth quarter 2023, corresponding to 444.3 (449.8) mboepd. Net sold volume was 466.9 (450.0) mboepd.
| KEY FIGURES | AKER BP INTEREST | Q4 2023 | Q3 2023 | Q2 2023 | Q1 2023 | Q4 2022 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Alvheim | 80% | 24.3 | 22.9 | 31.8 | 32.3 | 35.3 |
| Bøyla (incl. Frosk) | 80% | 4.9 | 6.3 | 7.1 | 4.6 | 3.3 |
| Skogul | 65% | 1.4 | 0.3 | 1.5 | 1.3 | 1.6 |
| Vilje | 46.904% | 1.1 | 1.8 | 1.7 | 1.8 | 2.2 |
| Volund | 100% | 1.4 | 2.5 | 2.9 | 2.8 | 3.5 |
| Total production | 33.1 | 33.8 | 45.0 | 42.8 | 45.8 | |
| Production efficiency | 63 % | 81 % | 100 % | 98 % | 99 % |
Production from the Alvheim area was 33 mboepd net to Aker BP. The production efficiency was reduced to 63 percent due to unplanned downtime caused by a malfunction of the new equipment installed during the previous quarter's planned maintenance activities. This was partly offset by the start-up of production from Kobra East & Gekko (KEG).
KEG was completed approximately five months ahead of plan, mainly due to strong performance in the drilling campaign. The first well started production on 26 October 2023, and the remaining three wells are now also on stream.
The Plan for Development and Operations (PDO) for the Tyrving development received government approval in June 2023. The project is well into its execution phase, with fabrication ongoing at several locations. The rig completed the top-hole campaign in the quarter, preparing the three wells for the drilling campaign in the first half of 2024. Production start is planned in the first quarter 2025.
An infill well near Alvheim is progressing as planned. Drilling of the well is ongoing, with production start expected in the second quarter 2024. Another infill target is also being matured, with expected investment decision in the second half of 2024.
| KEY FIGURES | AKER BP INTEREST | Q4 2023 | Q3 2023 | Q2 2023 | Q1 2023 | Q4 2022 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Edvard Grieg Area | 65% | 61.8 | 70.8 | 74.9 | 71.8 | 86.1 |
| Ivar Aasen | 36.1712% | 12.1 | 11.2 | 14.4 | 12.6 | 13.6 |
| Total production | 74.0 | 82.0 | 89.3 | 84.3 | 99.7 | |
| Production efficiency | 99 % | 97 % | 97 % | 87 % | 99 % |
Net production from Edvard Grieg & Ivar Aasen decreased to 74.0 mboepd in the fourth quarter, primarily due to natural decline. Production efficiency remained high at 99 percent.
For the Hanz project, drilling of the production well has been completed while drilling of the water injection well is currently ongoing. Simultaneously, the final preparation of marine operations and topside commissioning are underway. First oil is currently expected in April 2024.
The Utsira High Project is progressing as planned. The main contracts have been signed, and detailed engineering and procurement are ongoing. The project consists of two separate subsea tie-in projects – Symra, which will be a tie-in to the Ivar Aasen platform, and Solveig phase 2, which will be connected to the Edvard Grieg platform. Drilling is set to commence in the third quarter of 2025, with production start-up planned in 2026.
| KEY FIGURES | AKER BP INTEREST | Q4 2023 | Q3 2023 | Q2 2023 | Q1 2023 | Q4 2022 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Total production | 31.5733% | 244.9 | 246.5 | 243.8 | 215.7 | 180.6 |
The Johan Sverdrup field continued to produce safely and efficiently at an elevated capacity level throughout the fourth quarter. Aker BP's share of the production amounted to 244.9 mboepd.
Drilling activities continued in the fourth quarter, both from the field centre and the subsea templates, increasing the total number of producing wells to 31. An additional eight oil production wells are planned to be put on production during 2024. The operator is also working to mature more infill and subsea wells.
In 2023, the oil production level at Johan Sverdrup was ramped up to 755 mbblpd (gross) after successful testing of the Phase 2 facilities in conjunction with the existing facilities. This represents a significant acceleration of production compared to the original design capacity of 660 mbblpd.
The operator currently expects to be able to maintain the current elevated production level until late 2024 or early 2025.
| KEY FIGURES | AKER BP INTEREST | Q4 2023 | Q3 2023 | Q2 2023 | Q1 2023 | Q4 2022 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Total production | 23.835 % | 36.5 | 37.6 | 41.7 | 41.8 | 41.6 |
| Production efficiency | 95 % | 91 % | 98 % | 99 % | 97 % |
Production from the Skarv area was 36.5 mboepd net to Aker BP in the fourth quarter. Production efficiency increased to 95% as the unplanned maintenance from the third quarter was completed in the first week of October.
To mitigate the natural decline in production, two new infill wells were approved in 2023. The drilling of these wells is planned in the second half of 2024, with production start expected around year-end.
The Skarv Satellite Project comprises the gas and condensate discoveries Alve Nord, Idun Nord, and Ørn, and is estimated to deliver approximately 120 mmboe gross through the Skarv FPSO from 2027. The project has entered the execution phase and is progressing as planned. Construction of subsea facilities through the Subsea Alliance has started in Sandnessjøen and Gdansk. In the fourth quarter, the subsea rock installation campaign was successfully completed, and installation of the flotel bridge landing on the Skarv FPSO started.
| KEY FIGURES | AKER BP INTEREST | Q4 2023 | Q3 2023 | Q2 2023 | Q1 2023 | Q4 2022 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Ula | 80 % | 4.7 | 5.0 | 6.0 | 6.1 | 4.1 |
| Tambar | 55 % | 1.2 | 1.4 | 1.5 | 2.0 | 0.7 |
| Oda | 15 % | 1.4 | 1.3 | 1.0 | 2.5 | 4.0 |
| Total production | 7.3 | 7.7 | 8.6 | 10.6 | 8.8 | |
| Production efficiency | 71 % | 73 % | 72 % | 80 % | 56 % |
Production from the Ula area was 7.3 mboepd net to Aker BP in the fourth quarter.
A side-track well is being matured on Tambar with final investment decision made in the fourth quarter 2023. Drilling of the well is scheduled for late 2024, with production expected to start in 2025.
A project is underway to establish a late-life strategy for Ula, to facilitate safe and profitable operations until cessation of production in 2028. In parallel, a field decommissioning study to prepare a work program for well plugging and platform removal is ongoing.
| KEY FIGURES | AKER BP INTEREST | Q4 2023 | Q3 2023 | Q2 2023 | Q1 2023 | Q4 2022 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Valhall | 90% | 37.7 | 32.5 | 41.5 | 42.9 | 42.4 |
| Hod | 90% | 10.8 | 9.6 | 10.8 | 14.5 | 13.1 |
| Total production | 48.5 | 42.1 | 52.2 | 57.4 | 55.5 | |
| Production efficiency | 84 % | 74 % | 89 % | 91 % | 89 % |
Production from the Valhall area increased to 48.5 mboepd in the fourth quarter as the field continued to ramp up production following the unplanned shutdown in the third quarter, and production efficiency improved to 84 percent.
The Noble Invincible rig finalised drilling of the infill well on Valhall Flank North in the quarter. Additionally, it completed workovers of two other wells in the area. The rig has now moved to Hod A to begin the second phase of the Hod A plugging and abandonment campaign. The objective is to permanently plug and abandon eight wells at the old Hod A platform.
The Valhall PWP & Fenris project progressed according to plan in the fourth quarter. The project consists of a new centrally located production and wellhead platform (PWP) at the Valhall central complex, along with an unmanned installation at Fenris tied back to the PWP.
Engineering and procurement activities are on schedule, and fabrication has started at several locations both in Norway and abroad. The PWP bridge, the Fenris jacket and subsea pipelines are some of the key components currently being manufactured.
The Yggdrasil development is in the execution phase and progressing according to plan. The construction work is engaging several thousand people across the world, and in the fourth quarter, fabrication commenced at several new major sites. Simultaneously, detailed engineering and procurement activities continued.
In May 2023, Aker BP made a significant oil discovery in the Øst Frigg Beta/Epsilon exploration well within the Yggdrasil area. The discovery, estimated at 53-90 mmboe, is currently under assessment for potential inclusion in the Yggdrasil development project.
Situated between Oseberg and Alvheim in the Norwegian North Sea, Yggdrasil encompasses several discoveries with total gross recoverable resources estimated at around 700 mmboe. Aker BP, in collaboration with the partners Equinor and PGNiG Upstream Norway, continues to actively explore in the area.
The Yggdrasil development concept includes a central processing platform (Hugin A), an unmanned gas production platform (Munin), a normally unmanned wellhead platforms (Hugin B), an extensive subsea infrastructure, and a total of 55 planned wells. The facilities will be powered from shore, ensuring stable operations and a minimal carbon footprint. The PDOs for Yggdrasil received government approval in June 2023, and production is scheduled to commence in 2027.
On 18 January 2024, the Oslo District Court ruled that the Ministry of Energy's approvals for the plans for development and operation (PDO) for the Breidablikk, Tyrving, and Yggdrasil fields were invalid due to procedural errors. The court concluded that the state had failed to consider the effects of combustion emissions as part of the final PDO. In addition, the court issued a temporary injunction, preventing the state from making decisions that assume valid PDO approval for the projects.
Currently, the ruling is non-binding concerning procedural errors. The Norwegian state has appealed both the main ruling and the temporary injunction to the Borgarting Court of Appeal.
Aker BP, which has participating interests and operates the Yggdrasil and Tyrving development projects, is not a party to the court case. The PDO approvals granted for Yggdrasil and Tyrving remain valid in relation to Aker BP.
Aker BP continues executing the Yggdrasil and Tyrving projects in accordance with the permissions granted. In response to the current situation, a dedicated task force has been established to identify potential risks and coordinate the company's activities and risk-mitigating actions.
Total exploration spend in the third quarter was USD 81 (72) million, while USD 67 (74) million was recognised as exploration expenses in the period, relating to dry well costs, seismic, area fees, field evaluation and G&G costs.
Drilling of the Ofelia prospect, in production licence 929 in the North Sea was completed in the fourth quarter. The well confirmed already proven volumes in the main reservoir and made an additional gas discovery in a side-track well. Combined preliminary volume estimates are between 27-52 million barrels of oil equivalent. Aker BP has 10 percent interest in the licence which is operated by Neptune Energy.
The Surtsey prospect in production licence 272 B (50 percent interest) was drilled in the quarter. The well proved a small oil discovery, which is currently concluded as non-commercial.
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 2023 | Q3 2023 | Q2 2023 | Q1 2023 | Q4 2022 |
|---|---|---|---|---|---|---|
| Total recordable injury frequency (TRIF) L12M* | Per mill. exp. hours |
2.4 | 2.8 | 2.7 | 1.7 | 1.7 |
| Serious incident frequency (SIF) L12M* | Per mill. exp. hours |
0.3 | 0.3 | 0.4 | 0.5 | 0.7 |
| Acute spill | Count | 1 | 0 | 1 | 1 | 0 |
| Process safety events Tier 1 and 2 | Count | 1 | 0 | 0 | 0 | 0 |
| GHG emissions intensity, equity share | Kg CO2e/boe | 2.8 | 2.8 | 2.6 | 2.9 | 3.2 |
*TRIF and SIF figures from prior periods have been restated to incorporate a new and more accurate methodology for measuring exposure hours. The updated approach is based on actual timewriting rather than estimated hours, resulting in a decrease in exposure hours and, consequently, an increase in TRIF and SIF.
The twelve months rolling average for the Total Recordable Injury Frequency (TRIF) decreased, while the Serious Incident Frequency (SIF) remained stable from the previous quarter. Three SIF incidents were recorded in the fourth quarter. Two of these involved falling objects, while one was categorised as a near-miss incident. None of these incidents resulted in personnel injuries or significant damage to equipment. Four TRIF injuries were recorded, all of which were classified as having moderate severity. All such incidents are routinely investigated to identify root causes and improve safety standards.
During the restart of Alvheim following the unplanned downtime in the quarter, approximately 64 cubic metres of oil leaked into the sea. The authorities were notified, and proper oil spill response measures were successfully implemented. There are no indications that the spill resulted in any environmental damage. The incident has been classified as a Tier 1 process safety event, due to a loss of primary containment (LOPC) of crude oil.
Aker BP's greenhouse gas (GHG) emissions intensity was stable at 2.8 (2.8) kg CO2e per boe in the quarter, and in line with the average for the full year.
The Board is of the opinion that Aker BP is uniquely positioned for value creation. The key characteristics of the company are:
The company's financial plan for 2024 consists of the following key parameters
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.
| Group | ||||||
|---|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | |||
| (USD million) | Note | 2023 | 2023 | 2022 | 2023 | 2022 |
| Petroleum revenues | 3 541.8 | 3 480.1 | 3 803.7 | 13 580.0 | 12 896.2 | |
| Other income | 14.3 | 32.8 | 22.2 | 89.9 | 113.7 | |
| Total income | 1 | 3 556.1 | 3 512.9 | 3 825.9 | 13 669.9 | 13 009.9 |
| Production expenses | 2 | 298.0 | 251.8 | 286.4 | 1 060.1 | 932.9 |
| Exploration expenses | 3 | 67.0 | 74.3 | 32.1 | 266.3 | 242.2 |
| Depreciation | 5 | 605.8 | 556.9 | 641.2 | 2 406.8 | 1 785.7 |
| Impairments | 4,5 | 414.8 | - | 636.2 | 889.5 | 1 032.2 |
| Other operating expenses | 16.8 | 12.3 | 16.0 | 57.8 | 52.6 | |
| Total operating expenses | 1 402.3 | 895.4 | 1 612.0 | 4 680.5 | 4 045.5 | |
| Operating profit/loss | 2 153.8 | 2 617.5 | 2 213.9 | 8 989.4 | 8 964.4 | |
| Interest income | 42.0 | 38.5 | 13.5 | 133.4 | 26.0 | |
| Other financial income | 275.4 | 106.3 | 590.7 | 321.2 | 774.3 | |
| Interest expenses | 36.0 | 41.1 | 35.8 | 161.8 | 107.7 | |
| Other financial expenses | 266.8 | 156.5 | 605.7 | 518.2 | 880.1 | |
| Net financial items | 7 | 14.6 | -52.8 | -37.3 | -225.4 | -187.6 |
| Profit/loss before taxes | 2 168.3 | 2 564.7 | 2 176.7 | 8 764.0 | 8 776.9 | |
| Tax expense (+)/income (-) | 8 | 2 004.6 | 1 976.5 | 2 064.3 | 7 428.3 | 7 173.9 |
| Net profit/loss | 163.8 | 588.2 | 112.4 | 1 335.7 | 1 602.9 | |
| Weighted average no. of shares outstanding basic and diluted Basic and diluted earnings/loss USD per share |
631 153 169 0.26 |
630 520 302 0.93 |
631 585 639 0.18 |
631 311 010 2.12 |
496 764 969 3.23 |
| Group | ||||||
|---|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | |||
| (USD million) | Note 2023 |
2023 | 2022 | 2023 | 2022 | |
| Profit/loss for the period | 163.8 | 588.2 | 112.4 | 1 335.7 | 1 602.9 | |
| Items which may be reclassified over profit and loss (net of taxes) | ||||||
| Foreign currency translation | - | - | 1 012.8 | - | - | |
| Items which will not be reclassified over profit and loss (net of taxes) | ||||||
| Foreign currency translation | - | - | 295.3 | - | 295.3 | |
| Actuarial gain/loss pension plan | 0.1 | - | 0.0 | 0.1 | 0.0 | |
| Total comprehensive income/loss in period | 163.8 | 588.2 | 1 420.5 | 1 335.8 | 1 898.3 |
| (USD million) | Note | 31.12.2023 | 30.09.2023 | 31.12.2022 |
|---|---|---|---|---|
| ASSETS | ||||
| Intangible assets | ||||
| Goodwill | 5 | 13 142.8 | 13 554.0 | 13 935.0 |
| Capitalised exploration expenditures | 5 | 325.4 | 312.9 | 251.7 |
| Other intangible assets | 5 | 2 123.4 | 2 163.7 | 2 344.4 |
| Tangible fixed assets | ||||
| Property, plant and equipment | 5 | 17 449.8 | 16 123.5 | 15 886.7 |
| Right-of-use assets | 5 | 655.3 | 420.8 | 111.3 |
| Financial assets | ||||
| Long-term receivables | 69.1 | 166.6 | 169.5 | |
| Other non-current assets | 102.9 | 98.2 | 104.5 | |
| Long-term derivatives | 11 | 38.1 | 3.3 | 2.9 |
| Total non-current assets | 33 906.8 | 32 843.0 | 32 806.0 | |
| Inventories | ||||
| Inventories | 202.3 | 180.4 | 209.5 | |
| Financial assets | ||||
| Trade receivables | 658.8 | 770.2 | 950.9 | |
| Other short-term receivables | 9 | 742.2 | 944.0 | 686.2 |
| Short-term derivatives | 11 | 148.1 | 14.5 | 153.1 |
| Cash and cash equivalents | ||||
| Cash and cash equivalents | 10 | 3 388.4 | 3 375.2 | 2 756.0 |
| Total current assets | 5 139.7 | 5 284.2 | 4 755.8 | |
| TOTAL ASSETS | 39 046.5 | 38 127.2 | 37 561.8 |
| Group | ||||
|---|---|---|---|---|
| (USD million) | Note | 31.12.2023 | 30.09.2023 | 31.12.2022 |
| EQUITY AND LIABILITIES | ||||
| Equity | ||||
| Share capital | 84.3 | 84.3 | 84.3 | |
| Share premium | 12 946.6 | 12 946.6 | 12 946.6 | |
| Other equity | -668.8 | -507.4 | -603.5 | |
| Total equity | 12 362.2 | 12 523.6 | 12 427.5 | |
| Non-current liabilities | ||||
| Deferred taxes | 8 | 10 592.3 | 10 181.6 | 9 359.1 |
| Long-term abandonment provision | 14 | 4 304.1 | 3 618.5 | 4 050.4 |
| Long-term bonds | 13 | 5 798.2 | 5 753.6 | 5 279.2 |
| Long-term derivatives | 11 | 0.5 | 36.4 | 17.0 |
| Long-term lease debt | 6 | 555.5 | 352.2 | 98.1 |
| Other non-current liabilities | 1.0 | 82.4 | 82.3 | |
| Total non-current liabilities | 21 251.5 | 20 024.7 | 18 886.1 | |
| Current liabilities | ||||
| Trade creditors | 291.0 | 139.9 | 133.9 | |
| Accrued public charges and indirect taxes | 38.8 | 34.8 | 36.6 | |
| Tax payable | 8 | 3 599.9 | 4 069.8 | 5 084.1 |
| Short-term derivatives | 11 | 32.8 | 89.2 | 34.9 |
| Short-term abandonment provision | 14 | 250.6 | 167.8 | 115.2 |
| Short-term lease debt | 6 | 148.7 | 102.0 | 36.3 |
| Other current liabilities | 12 | 1 071.0 | 975.4 | 807.1 |
| Total current liabilities | 5 432.9 | 5 578.9 | 6 248.2 | |
| Total liabilities | 26 684.3 | 25 603.7 | 25 134.3 | |
| TOTAL EQUITY AND LIABILITIES | 39 046.5 | 38 127.2 | 37 561.8 |
| 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 |
| Restated equity as of 31.12.2021 | 57.1 | 3 637.3 | 573.1 | -0.1 | -115.5 | -1 955.1 | -1 497.5 | 2 196.8 |
| Dividend distributed | - | - | - | - | - | -673.9 | -673.9 | -673.9 |
| Private placement | 27.3 | 9 309.3 | - | - | - | - | - | 9 336.6 |
| Restated profit/loss for the period | - | - | - | - | - | 1 490.6 | 1 490.6 | 1 490.6 |
| Purchase of treasury shares | -17.0 | -17.0 | -17.0 | |||||
| Other comprehensive income for the period | -1 012.8 | -1 012.8 | -1 012.8 | |||||
| Restated equity as of 30.09.2022 | 84.3 | 12 946.6 | 573.1 | -0.1 | -1 128.3 | -1 155.4 | -1 710.7 | 11 320.3 |
| Dividends distributed | - | - | - | - | - | -331.8 | -331.8 | -331.8 |
| Profit/loss for the period | - | - | - | - | - | 112.4 | 112.4 | 112.4 |
| Net sale of treasury shares | - | - | - | - | - | 18.5 | 18.5 | 18.5 |
| Other comprehensive income for the period | - | - | - | -0.0 | 1 308.1 | - | 1 308.1 | 1 308.1 |
| 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 |
| Dividend 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 |
| Group | ||||||
|---|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | |||
| (USD million) | Note | 2023 | 2023 | 2022 | 2023 | 2022 |
| CASH FLOW FROM OPERATING ACTIVITIES | ||||||
| Profit/loss before taxes | 2 168.3 | 2 564.7 | 2 176.7 | 8 764.0 | 8 776.9 | |
| Taxes paid | 8 | -2 207.2 | -862.0 | -2 955.0 | -7 455.2 | -5 332.1 |
| Depreciation | 5 | 605.8 | 556.9 | 641.2 | 2 406.8 | 1 785.7 |
| Impairment | 4,5 | 414.8 | - | 636.2 | 889.5 | 1 032.2 |
| Expensed capitalised dry wells | 3,5 | 38.5 | 46.6 | 9.7 | 153.9 | 135.8 |
| Accretion expenses related to abandonment provision | 7,14 | 44.1 | 41.9 | 40.3 | 166.3 | 119.9 |
| Total interest expenses | 7 | 36.0 | 41.1 | 35.8 | 161.8 | 107.7 |
| Changes in unrealised gain/loss in derivatives | 1,7 | -260.8 | -94.6 | -575.8 | -48.8 | -325.2 |
| Changes in inventories, trade creditors/receivables and accrued income | 505.8 | -271.7 | 269.3 | 575.0 | -313.9 | |
| Changes in other balance sheet items | 157.3 | 78.2 | 528.4 | -206.3 | -257.3 | |
| NET CASH FLOW FROM OPERATING ACTIVITIES | 1 502.6 | 2 101.1 | 806.8 | 5 407.1 | 5 729.5 | |
| CASH FLOW FROM INVESTMENT ACTIVITIES | ||||||
| Payment for removal and decommissioning of oil fields | 14 | -31.1 | -44.5 | -19.3 | -152.7 | -78.9 |
| Disbursements on investments in fixed assets (excluding capitalised interest) | 5 | -1 053.8 | -856.9 | -570.2 | -3 171.6 | -1 580.0 |
| Disbursements on investments in capitalised exploration expenditures | 5 | -52.0 | -43.1 | -37.8 | -238.6 | -251.8 |
| Investments in financial asset | 95.0 | - | -95.0 | 95.0 | -95.0 | |
| Consideration paid in Lundin Energy transaction net of cash acquired | - | - | 13.9 | - | -1 228.9 | |
| Cash received from sale of financial asset | - | - | - | - | 118.0 | |
| NET CASH FLOW FROM INVESTMENT ACTIVITIES | -1 041.9 | -944.5 | -708.4 | -3 467.9 | -3 116.6 | |
| CASH FLOW FROM FINANCING ACTIVITIES | ||||||
| Net drawdown/repayment/fees related to revolving credit facility | -7.3 | - | - | -8.3 | -601.1 | |
| Repayment of bonds | - | - | - | -1 000.0 | - | |
| Net proceeds from bond issue | -0.0 | -2.3 | - | 1 486.1 | - | |
| Interest paid (including interest element of lease payments) | -65.5 | -70.0 | -3.5 | -251.8 | -156.5 | |
| Payments on lease debt related to investments in fixed assets | -23.0 | -23.2 | -7.0 | -79.5 | -42.5 | |
| Payments on other lease debt | -11.9 | -11.6 | -5.7 | -54.0 | -24.1 | |
| Paid dividend | -347.6 | -347.6 | -331.8 | -1 390.4 | -1 005.7 | |
| Net purchase/sale of treasury shares | 22.5 | -33.1 | 18.5 | -10.5 | 1.5 | |
| NET CASH FLOW FROM FINANCING ACTIVITIES | -432.8 | -487.8 | -329.5 | -1 308.5 | -1 828.3 | |
| Net change in cash and cash equivalents | 27.9 | 668.9 | -231.1 | 630.7 | 784.6 | |
| Cash and cash equivalents at start of period | 3 375.2 | 2 688.8 | 3 042.0 | 2 756.0 | 1 970.9 | |
| Effect of exchange rate fluctuation on cash held | -14.7 | 17.4 | -54.9 | 1.7 | 0.5 | |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 10 | 3 388.4 | 3 375.2 | 2 756.0 | 3 388.4 | 2 756.0 |
| SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD | ||||||
| Bank deposits and cash | 3 366.9 | 3 354.0 | 2 756.0 | 3 366.9 | 2 756.0 | |
| Restricted bank deposits | 21.5 | 21.2 | - | 21.5 | - | |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 10 | 3 388.4 | 3 375.2 | 2 756.0 | 3 388.4 | 2 756.0 |
(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 2022 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.
The acquisition of the Lundin Energy's oil and gas business ("Lundin Energy") was completed on 30 June 2022, and the transaction was thus reflected in the statement of financial position in the second quarter 2022 report. At 31 December 2022, the merger processes with the legacy Lundin Energy entities were completed. These entities had other functional currency than USD which gave rise to significant currency translation elements in the group consolidation. From 1 January 2023 the activity in the legacy Lundin entities are carried out in the legal entity Aker BP ASA and the mentioned impact on comprehensive income is thus no longer present.
These interim financial statements were authorised for issue by the company's Board of Directors on 7 February 2024.
| Group | |||||||
|---|---|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | ||||
| Breakdown of petroleum revenues (USD million) | 2023 | 2023 | 2022 | 2023 | 2022 | ||
| Sales of liquids | 3 140.2 | 3 140.5 | 2 886.6 | 11 849.8 | 8 986.4 | ||
| Sales of gas | 397.9 | 336.3 | 913.5 | 1 714.5 | 3 898.9 | ||
| Tariff income | 3.7 | 3.3 | 3.6 | 15.7 | 10.9 | ||
| Total petroleum revenues | 3 541.8 | 3 480.1 | 3 803.7 | 13 580.0 | 12 896.2 | ||
| Sales of liquids (boe million) | 37.6 | 35.8 | 33.3 | 145.2 | 91.8 | ||
| Sales of gas (boe million) | 5.4 | 5.6 | 6.1 | 23.1 | 20.2 | ||
| Other income (USD million) | |||||||
| Realised gain (+)/loss (-) on commodity derivatives | - | - | 5.7 | -0.0 | 27.0 | ||
| Unrealised gain (+)/loss (-) on commodity derivatives | -0.8 | 2.6 | 4.4 | 0.2 | 9.0 | ||
| Gain on licence transactions | 0.0 | - | - | 0.0 | 11.0 | ||
| Other income1) | 15.1 | 30.2 | 12.0 | 89.7 | 66.7 | ||
| Total other income | 14.3 | 32.8 | 22.2 | 89.9 | 113.7 |
1) The figure includes partner coverage of RoU assets recognised on gross basis in the balance sheet and used in operated activity.
| Group | |||||
|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | ||
| Breakdown of production expenses (USD million) | 2023 | 2023 | 2022 | 2023 | 2022 |
| Cost of operations | 179.8 | 173.9 | 192.9 | 707.6 | 682.7 |
| Shipping and handling | 58.2 | 59.2 | 73.8 | 265.7 | 231.5 |
| Environmental taxes | 16.2 | 13.5 | 21.1 | 62.9 | 63.9 |
| Production expenses based on produced volumes | 254.2 | 246.6 | 287.8 | 1 036.3 | 978.1 |
| Adjustment for over (+)/underlift (-) | 43.8 | 5.3 | -1.4 | 23.8 | -45.3 |
| Production expenses based on sold volumes | 298.0 | 251.8 | 286.4 | 1 060.1 | 932.9 |
| Total produced volumes (boe million) | 40.9 | 41.4 | 39.7 | 166.7 | 112.9 |
| Production expenses per boe produced (USD/boe) | 6.2 | 6.0 | 7.2 | 6.2 | 8.7 |
| Group | |||||
|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | ||
| Breakdown of exploration expenses (USD million) | 2023 | 2023 | 2022 | 2023 | 2022 |
| Seismic | 5.1 | 7.9 | 3.6 | 27.2 | 34.4 |
| Area fee | 1.1 | 4.0 | 3.8 | 14.4 | 12.3 |
| Field evaluation | 6.0 | 3.3 | 0.8 | 13.5 | 10.7 |
| Dry well expenses1) | 38.5 | 46.6 | 9.7 | 153.9 | 135.8 |
| G&G and other exploration expenses | 16.2 | 12.6 | 14.2 | 57.5 | 48.9 |
| Total exploration expenses | 67.0 | 74.3 | 32.1 | 266.3 | 242.2 |
1) Dry well expenses in Q4 2023 are mainly related to the wells Surtsey/Jolnir and Magellan.
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 2023, two categories of impairment tests have been performed:
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 2023.
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 2024 to the end of Q4 2026. From Q1 2027, the oil and gas prices are based on the company's long-term price assumptions. Long-term oil and gas price assumption is unchanged from previous quarter.
The nominal oil prices applied in the impairment test are as follows:
| Year | USD/BOE |
|---|---|
| 2024 | 76.3 |
| 2025 | 73.3 |
| 2026 | 70.8 |
| From 2027 to 2035 (in real 2023 terms) | 70.0 |
| From 2036 (in real 2023 terms) | 65.0 |
The nominal gas prices applied in the impairment test are as follows:
| Year | GBP/therm |
|---|---|
| 2024 | 0.85 |
| 2025 | 0.91 |
| 2026 | 0.82 |
| From 2027 (in real 2023 terms) | 0.67 |
Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable reserves including potentially additional risked volumes.
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.
The post tax nominal discount rate used is 8.9 percent, updated from 8.7 percent applied in the previous quarter.
| Currency rates | |
|---|---|
| Year | USD/NOK |
| 2024 | 10.11 |
| 2025 | 10.07 |
| 2026 | 10.03 |
| From 2027 | 8.50 |
The long-term currency rate is unchanged from previous quarters.
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.
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.
Below is an overview of the impairment charge and the carrying value per cash generating unit where impairment has been recognised in Q4 2023:
| Edvard Grieg & | |||
|---|---|---|---|
| Cash-generating unit (USD million) | Other | Valhall CGU | Ivar Aasen CGU |
| Net carrying value | 3.1 | 5 944.7 | 3 889.4 |
| Recoverable amount | 5 762.0 | 3 660.8 | |
| Impairment/reversal (-) | 3.1 | 182.7 | 228.6 |
| Allocated as follows: | |||
| Technical goodwill | 182.7 | 228.6 | |
| Other intangible assets/licence rights | - | ||
| Tangible fixed assets | 3.1 | - |
The impairment is mainly related to decrease in short-term oil and gas prices, updated cost and production profiles and decrease of deferred tax liabilities as described above.
During the quarter, an impairment charge of in total USD 0.5 million has been recognised related to the former exploration wells.
For the twelve months period ended 31 December 2023 a total impairment charge of USD 889.5 million has been recognised. The impairment is allocated to the Edvard Grieg & Ivar Aasen CGU (USD 576.1 million), Valhall CGU (USD 182.5 million) and Troldhaugen (110.5 million) mainly related to technical goodwill, and exploration assets (20.4 million). Also see note 5.
The table below shows how the impairment or reversal of impairment of assets and technical goodwill 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 goodwill impairment, 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 % | -204.7 | 2 513.4 | |||
| Oil and gas price long-term | +/- 20 % | -5.0 | 1 126.2 | |||
| Production profile (reserves) | +/- 5 % | -6.2 | 283.4 | |||
| Discount rate | +/- 1 % point | 128.0 | -0.0 | |||
| Currency rate USD/NOK | +/- 2.0 NOK | -137.3 | 593.0 | |||
| Inflation | +/- 1 % point | -0.0 | 427.9 |
The residual goodwill is tested for impairment on corporate level. The starting point for the impairment test is the difference between market value and book value of equity. At year end 2023 the market value exceeds the carrying amount of equity by a substantial margin.
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 2 260 per tonn (2023 real) 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 2022 real terms. For the sensitivity calculation, a linear development between the average price for 2023 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) | Net Zero | Pledges | Stated Policies | ||
| Valhall/Hod | 2 969 | ||||
| Skarv | |||||
| Ula | -57 | -93 | |||
| Alvheim | 132 | ||||
| Johan Sverdrup | 706 | ||||
| Grieg/Aasen | 390 | ||||
| Yggdrasil | 52 | ||||
| Total | 4 250 | -57 | -93 |
| Oil USD/bbl | Gas USD/mmbtu | |||
|---|---|---|---|---|
| Scenario price ranges | 2030 | 2050 | 2030 | 2050 |
| Net Zero | 42 | 25 | 4.3 | 4.1 |
| Announced Pledges | 74 | 60 | 6.5 | 5.4 |
| Stated Policies | 85 | 83 | 6.9 | 7.1 |
| Property, plant and equipment | Production | Fixtures and | ||
|---|---|---|---|---|
| Assets under | facilities | fittings, office | ||
| (USD million) | development | including wells | machinery | Total |
| Book value 31.12.2022 | 1 614.2 | 14 196.4 | 76.1 | 15 886.7 |
| Acquisition cost 31.12.2022 | 1 614.2 | 21 301.0 | 268.3 | 23 183.5 |
| Additions | 1 750.4 | 71.0 | 7.0 | 1 828.4 |
| Disposals/retirement | - | - | - | - |
| Reclassification | -233.6 | 294.2 | 3.2 | 63.8 |
| Acquisition cost 30.09.2023 | 3 131.0 | 21 666.2 | 278.5 | 25 075.7 |
| Accumulated depreciation and impairments 31.12.2022 | - | 7 104.6 | 192.2 | 7 296.8 |
| Depreciation | - | 1 597.7 | 26.8 | 1 624.5 |
| Impairment/reversal (-) | 30.9 | - | - | 30.9 |
| Disposals/retirement depreciation | - | - | - | - |
| Accumulated depreciation and impairments 30.09.2023 | 30.9 | 8 702.3 | 219.0 | 8 952.3 |
| Book value 30.09.2023 | 3 100.1 | 12 963.9 | 59.5 | 16 123.5 |
| Acquisition cost 30.09.2023 | 3 131.0 | 21 666.2 | 278.5 | 25 075.7 |
| Additions | 921.2 | 919.5 | 3.8 | 1 844.6 |
| Disposals/retirement | - | - | - | - |
| Reclassification1) | -495.3 | 526.2 | - | 30.9 |
| Acquisition cost 31.12.2023 | 3 556.9 | 23 111.9 | 282.3 | 26 951.2 |
| Accumulated depreciation and impairments 30.09.2023 | 30.9 | 8 702.3 | 219.0 | 8 952.3 |
| Depreciation | - | 537.3 | 8.8 | 546.1 |
| Impairment/reversal (-) | 3.1 | - | - | 3.1 |
| Disposals/retirement depreciation | - | - | - | - |
| Accumulated depreciation and impairments 31.12.2023 | 34.0 | 9 239.6 | 227.8 | 9 501.4 |
| Book value 31.12.2023 | 3 522.9 | 13 872.3 | 54.5 | 17 449.8 |
1) The reclassification is mainly related to the Kobra East & Gekko project, which entered into production phase during Q4 2023.
Production facilities, including wells, are depreciated in accordance with the unit-of-production method. Office machinery, fixtures and fittings etc. are depreciated using the straight-line 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 increased abandonment provision as a result of updated discount rate, as described in note 14.
| Right-of-use assets | |||||
|---|---|---|---|---|---|
| Vessels and | |||||
| (USD million) | Drilling Rigs | Boats | Office | Other | Total |
| Book value 31.12.2022 | 15.1 | 44.1 | 50.6 | 1.6 | 111.3 |
| Acquisition cost 31.12.2022 | 17.9 | 54.7 | 77.3 | 2.3 | 152.2 |
| Additions | 421.8 | - | 0.4 | - | 422.2 |
| Allocated to abandonment activity | -4.3 | -0.9 | - | - | -5.2 |
| Disposals/retirement | - | - | - | - | - |
| Reclassification | -72.1 | -1.4 | - | - | -73.6 |
| Acquisition cost 30.09.2023 | 363.3 | 52.4 | 77.7 | 2.3 | 495.6 |
| Accumulated depreciation and impairments 31.12.2022 | 2.8 | 10.6 | 26.7 | 0.7 | 40.8 |
| Depreciation | 20.8 | 2.6 | 10.3 | 0.1 | 33.9 |
| Impairment/reversal (-) | - | - | - | - | - |
| Disposals/retirement depreciation | - | - | - | - | - |
| Accumulated depreciation and impairments 30.09.2023 | 23.6 | 13.3 | 37.0 | 0.8 | 74.8 |
| Book value 30.09.2023 | 339.6 | 39.1 | 40.6 | 1.5 | 420.8 |
| Acquisition cost 30.09.2023 | 363.3 | 52.4 | 77.7 | 2.3 | 495.6 |
| Additions1) | 263.5 | - | 18.9 | - | 282.3 |
| Allocated to abandonment activity | -2.2 | -0.2 | - | - | -2.3 |
| Disposals/retirement | 4.2 | - | - | - | 4.2 |
| Reclassification2) | -29.4 | -1.0 | - | - | -30.3 |
| Acquisition cost 31.12.2023 | 591.0 | 51.2 | 96.5 | 2.3 | 741.1 |
| Accumulated depreciation and impairments 30.09.2023 | 23.6 | 13.3 | 37.0 | 0.8 | 74.8 |
| Depreciation | 10.2 | 0.5 | 4.4 | 0.0 | 15.1 |
| Impairment/reversal (-) | - | - | - | - | - |
| Disposals/retirement depreciation | -4.2 | - | - | - | -4.2 |
| Accumulated depreciation and impairments 31.12.2023 | 29.7 | 13.8 | 41.4 | 0.9 | 85.7 |
| Book value 31.12.2023 | 561.4 | 37.4 | 55.1 | 1.4 | 655.3 |
1) The additions are mainly related to the rig Deepsea Nordkapp.
2) Reclassified mainly to tangible fixed 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.
| Capitalised | |||||
|---|---|---|---|---|---|
| (USD million) | Goodwill | exploration expenditures |
Depreciated | Other intangible assets Not depreciated |
Total |
| Book value 31.12.2022 | 13 935.0 | 251.7 | 1 431.3 | 913.1 | 2 344.4 |
| Acquisition cost 31.12.2022 | 15 404.4 | 450.3 | 2 361.0 | 1 303.6 | 3 664.6 |
| Additions | - | 186.7 | - | 4.8 | 4.8 |
| Disposals/retirement/expensed dry wells | - | 115.4 | - | - | - |
| Reclassification | - | 9.7 | 6.9 | -6.9 | 0.0 |
| Acquisition cost 30.09.2023 | 15 404.4 | 531.3 | 2 368.0 | 1 301.5 | 3 669.4 |
| Accumulated depreciation and impairments 31.12.2022 | 1 469.4 | 198.6 | 929.7 | 390.5 | 1 320.2 |
| Depreciation | - | - | 142.5 | - | 142.5 |
| Impairment/reversal (-) | 381.0 | 19.9 | - | 42.9 | 42.9 |
| Disposals/retirement depreciation | - | - | - | - | - |
| Accumulated depreciation and impairments 30.09.2023 | 1 850.4 | 218.4 | 1 072.3 | 433.4 | 1 505.7 |
| Book value 30.09.2023 | 13 554.0 | 312.9 | 1 295.7 | 868.0 | 2 163.7 |
| Acquisition cost 30.09.2023 | 15 404.4 | 531.3 | 2 368.0 | 1 301.5 | 3 669.4 |
| Additions | - | 52.0 | - | 4.3 | 4.3 |
| Disposals/retirement/expensed dry wells | - | 38.5 | - | - | - |
| Reclassification | - | -0.5 | 90.9 | -90.9 | - |
| Acquisition cost 31.12.2023 | 15 404.4 | 544.3 | 2 458.9 | 1 214.8 | 3 673.7 |
| Accumulated depreciation and impairments 30.09.2023 | 1 850.4 | 218.4 | 1 072.3 | 433.4 | 1 505.7 |
| Depreciation | - | - | 44.6 | - | 44.6 |
| Impairment/reversal (-) | 411.2 | 0.5 | - | - | - |
| Disposals/retirement depreciation | - | - | - | - | - |
| Accumulated depreciation and impairments 31.12.2023 | 2 261.6 | 218.9 | 1 116.9 | 433.4 | 1 550.3 |
| Book value 31.12.2023 | 13 142.8 | 325.4 | 1 342.0 | 781.4 | 2 123.4 |
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) | 2023 | 2023 | 2022 | 2023 | 2022 |
| Depreciation of tangible fixed assets | 546.1 | 502.6 | 600.8 | 2 170.6 | 1 675.2 |
| Depreciation of right-of-use assets | 15.1 | 12.4 | 6.3 | 49.1 | 18.7 |
| Depreciation of other intangible assets | 44.6 | 41.9 | 34.1 | 187.1 | 91.7 |
| Total depreciation in the income statement | 605.8 | 556.9 | 641.2 | 2 406.8 | 1 785.7 |
| Impairment in the income statement (USD million) | |||||
| Impairment/reversal of tangible fixed assets | 3.1 | - | 0.5 | 34.0 | 385.6 |
| Impairment/reversal of other intangible assets | - | - | 258.3 | 42.9 | 258.3 |
| Impairment/reversal of capitalised exploration expenditures | 0.5 | - | - | 20.4 | 10.9 |
| Impairment of goodwill | 411.2 | - | 377.4 | 792.2 | 377.4 |
| Total impairment in the income statement | 414.8 | - | 636.2 | 889.5 | 1 032.2 |
The incremental borrowing rate applied in discounting of the nominal lease debt is between 2.4 percent and 6.9 percent, dependent on the duration of the lease and when it was initially recognised.
| Group | |||
|---|---|---|---|
| 2023 | 2023 | 2022 | |
| (USD million) | Q4 | 01.01.-30.09. | 01.01.-31.12. |
| Lease debt as of beginning of period | 454.2 | 134.4 | 136.2 |
| New lease debt recognised in the period2) | 282.3 | 422.2 | 33.8 |
| Payments of lease debt1) | -44.4 | -116.0 | -74.1 |
| Interest expense on lease debt | 9.6 | 17.3 | 7.5 |
| Lease debt from acquisition of Lundin Energy | - | - | 34.8 |
| Currency exchange differences | 2.5 | -3.7 | -3.8 |
| Total lease debt | 704.2 | 454.2 | 134.4 |
| Short-term | 148.7 | 102.0 | 36.3 |
| Long-term | 555.5 | 352.2 | 98.1 |
| 1) Payments of lease debt split by activities (USD million): | |||
| Investments in fixed assets | 29.3 | 66.4 | 46.9 |
| Abandonment activity | 2.3 | 6.0 | 0.8 |
| Operating expenditures | 2.2 | 9.1 | 13.9 |
| Exploration expenditures | 0.2 | 11.7 | 6.2 |
| Other income | 10.4 | 22.7 | 6.3 |
| Total | 44.4 | 116.0 | 74.1 |
| Nominal lease debt maturity breakdown (USD million): | |||
| Within one year | 220.2 | 133.3 | 42.6 |
| Two to five years | 528.4 | 350.6 | 87.2 |
| After five years | 11.8 | 15.2 | 26.4 |
| Total | 760.4 | 499.1 | 156.2 |
2) The new lease debt recognised in Q4 2023 is mainly related to the rig Deepsea Nordkapp.
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.
| Group | |||||
|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | ||
| (USD million) | 2023 | 2023 | 2022 | 2023 | 2022 |
| Interest income | 42.0 | 38.5 | 13.5 | 133.4 | 26.0 |
| Realised gains on derivatives | 13.3 | 14.4 | 19.3 | 83.4 | 33.5 |
| Change in fair value of derivatives | 261.7 | 91.9 | 571.4 | 48.6 | 333.7 |
| Net currency gains | - | - | - | 144.8 | 308.4 |
| Other financial income | 0.5 | - | 0.0 | 44.5 | 98.8 |
| Total other financial income | 275.4 | 106.3 | 590.7 | 321.2 | 774.3 |
| Interest expenses | 56.6 | 60.7 | 48.1 | 212.7 | 154.0 |
| Interest on lease debt | 9.6 | 6.1 | 1.8 | 26.9 | 7.5 |
| Capitalised interest cost, development projects | -41.7 | -37.2 | -27.2 | -127.1 | -85.6 |
| Amortised loan costs1) | 11.5 | 11.5 | 13.1 | 49.3 | 31.8 |
| Total interest expenses | 36.0 | 41.1 | 35.8 | 161.8 | 107.7 |
| Net currency loss | 194.8 | 51.5 | 337.5 | - | 269.4 |
| Realised loss on derivatives | 27.7 | 61.6 | 225.2 | 345.2 | 480.9 |
| Change in fair value of derivatives | - | - | - | - | - |
| Accretion expenses related to abandonment provision | 44.1 | 41.9 | 40.3 | 166.3 | 119.9 |
| Other financial expenses | 0.2 | 1.6 | 2.7 | 6.7 | 9.8 |
| Total other financial expenses | 266.8 | 156.5 | 605.7 | 518.2 | 880.1 |
| Net financial items | 14.6 | -52.8 | -37.3 | -225.4 | -187.6 |
1) The figure includes amortisation of the difference between fair value and nominal value on the bonds acquired in the Lundin transaction in Q2 2022.
| Group | |||||
|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | ||
| Tax for the period (USD million) | 2023 | 2023 | 2022 | 2023 | 2022 |
| Current year tax payable/receivable | 1 554.1 | 1 520.1 | 2 169.8 | 6 136.4 | 7 163.0 |
| Change in current year deferred tax | 409.6 | 457.1 | -111.9 | 1 200.5 | -12.3 |
| Current and deferred tax related to change in tax system | - | - | - | - | 13.1 |
| Prior period adjustments | 40.9 | -0.7 | 6.4 | 91.4 | 10.2 |
| Tax expense (+)/income (-) | 2 004.6 | 1 976.5 | 2 064.3 | 7 428.3 | 7 173.9 |
| Group | |||
|---|---|---|---|
| 2023 | 2023 | 2022 | |
| Calculated tax payable (-)/tax receivable (+) (USD million) | Q4 | 01.01.-30.09. | 01.01.-31.12. |
| Tax payable/receivable at beginning of period | -4 069.8 | -5 084.1 | -1 497.3 |
| Current year tax payable/receivable | -1 554.1 | -4 582.4 | -7 163.0 |
| Current year tax payable/receivable related to change in tax system | - | - | 176.4 |
| Net tax payment/refund | 2 207.2 | 5 247.9 | 5 332.1 |
| Net tax payable related to acquisition of Lundin Energy | - | - | -2 181.0 |
| Prior period adjustments and change in estimate of uncertain tax positions | -39.5 | -18.9 | 29.8 |
| Currency movements of tax payable/receivable | -143.8 | 367.7 | 245.8 |
| Current tax charged to other comprehensive income (foreign currency translation) | - | - | -27.1 |
| Net tax payable (-)/receivable (+) | -3 599.9 | -4 069.8 | -5 084.1 |
| 2023 | 2023 | 2022 | |
|---|---|---|---|
| Deferred tax liability (-)/asset (+) (USD million) | Q4 | 01.01.-30.09. | 01.01.-31.12. |
| Deferred tax liability/asset at beginning of period | -10 181.6 | -9 359.1 | -3 291.3 |
| Change in current year deferred tax | -409.6 | -790.9 | 12.3 |
| Change in current year deferred tax related to change in tax system | - | - | -189.4 |
| Deferred tax related to acquisition of Lundin Energy | - | - | -5 801.9 |
| Prior period adjustments | -1.1 | -31.6 | -27.9 |
| Deferred tax charged to other comprehensive income (mainly foreign currency translation) | -0.0 | - | -60.9 |
| Net deferred tax liability (-)/asset (+) | -10 592.3 | -10 181.6 | -9 359.1 |
| Group | |||||
|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | ||
| Reconciliation of tax expense (USD million) | 2023 | 2023 | 2022 | 2023 | 2022 |
| 78 % tax rate on profit/loss before tax | 1 691.4 | 2 000.6 | 1 697.9 | 6 836.3 | 6 846.3 |
| Tax effect of uplift | -69.6 | -56.5 | -42.6 | -209.9 | -161.7 |
| Permanent difference on impairment | 320.8 | 0.0 | 294.4 | 618.0 | 294.4 |
| Foreign currency translation of monetary items other than USD | 150.6 | 39.7 | 125.4 | -112.0 | -170.6 |
| Foreign currency translation of monetary items other than NOK | 50.7 | 31.8 | 304.0 | -17.8 | 129.6 |
| Tax effect of financial and other 22 % items | -116.8 | -20.0 | -247.3 | 180.3 | 60.1 |
| Currency movements of tax balances1) | -64.2 | -21.4 | -90.3 | 29.1 | 138.9 |
| Other permanent differences, prior period adjustments and change in estimate of | 41.6 | 2.3 | 22.8 | 104.4 | 36.9 |
| uncertain tax positions | |||||
| Tax expense (+)/income (-) | 2 004.6 | 1 976.5 | 2 064.3 | 7 428.3 | 7 173.9 |
1) Tax balances are in NOK and converted to USD using the period end currency rate. When NOK weakens against USD, the tax rate increases as there is less remaining tax depreciation measured in USD (and vice versa).
From 1 January 2023 the temporary tax regime uplift rate was reduced from from 17.69 to 12.4 percent.
In accordance with statutory requirements, the calculation of current tax is required to be based on each company's local currency. This may impact the effective tax rate as the group's presentation currency is USD and the operating entities in the group can have different functional currency than USD.
| Group | |||
|---|---|---|---|
| (USD million) | 31.12.2023 | 30.09.2023 | 31.12.2022 |
| Prepayments | 279.7 | 227.0 | 124.0 |
| VAT receivable | 18.8 | 9.6 | 12.4 |
| Underlift of petroleum | 41.7 | 78.3 | 53.6 |
| Accrued income from sale of petroleum products | 216.9 | 482.2 | 335.5 |
| Other receivables, mainly balances with licence partners | 185.1 | 146.9 | 160.7 |
| Total other short-term receivables | 742.2 | 944.0 | 686.2 |
The item 'Cash and cash equivalents' consists of bank accounts and short-term investments that constitute parts of the group's available liquidity.
| Group | ||
|---|---|---|
| 31.12.2023 | 30.09.2023 | 31.12.2022 |
| 3 366.9 | 3 354.0 | 2 756.0 |
| 21.5 | 21.2 | - |
| 3 388.4 | 3 375.2 | 2 756.0 |
| 3 400.0 | 3 400.0 | 3 400.0 |
1) Tax deduction account
The RCF is undrawn as at 31 December 2023 and the remaining unamortised fees of USD 15.0 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 consist 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.
(3) 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 2028. The facility includes two extension options 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 facilities. 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 times
Interest Coverage Ratio: Twelve months rolling EBITDA divided by Interest expenses (excluding any impacts from IFRS 16) shall be a minimum of 3.5 times
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 2023 the Leverage Ratio is 0.19 and Interest Coverage Ratio is 95.2 (see APM section for further details). Based on the group's current business plans and applying oil and gas price forward curves at end of Q4 2023, the group's estimates show that the financial covenants will continue to comply with the covenants by a substantial margin.
| Group | ||||
|---|---|---|---|---|
| (USD million) | 31.12.2023 | 30.09.2023 | 31.12.2022 | |
| Unrealised gain currency contracts | 38.1 | 3.3 | 2.9 | |
| Long-term derivatives included in assets | 38.1 | 3.3 | 2.9 | |
| Unrealised gain commodity derivatives | 0.2 | 1.0 | - | |
| Unrealised gain currency contracts | 147.9 | 13.4 | 153.1 | |
| Short-term derivatives included in assets | 148.1 | 14.5 | 153.1 | |
| Total derivatives included in assets | 186.2 | 17.7 | 156.0 | |
| Fair value of option related to sale of Cognite | - | 8.1 | 16.0 | |
| Unrealised losses currency contracts | 0.5 | 28.3 | 1.0 | |
| Long-term derivatives included in liabilities | 0.5 | 36.4 | 17.0 | |
| Fair value of option related to sale of Cognite | 4.8 | - | - | |
| Unrealised losses currency contracts | 28.0 | 89.2 | 34.9 | |
| Short-term derivatives included in liabilities | 32.8 | 89.2 | 34.9 | |
| Total derivatives included in liabilities | 33.3 | 125.6 | 51.9 |
The group uses various types of financial hedging instruments. Commodity derivatives are 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 2022. 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 2023, the company has entered into foreign exchange contracts to secure USD and EUR value of NOK cashflows for future tax payments and capital expenditure.
| Group | |||
|---|---|---|---|
| Breakdown of other current liabilities (USD million) | 31.12.2023 | 30.09.2023 | 31.12.2022 |
| Balances with licence partners | 30.9 | 36.1 | 43.1 |
| Share of other current liabilities in licences | 692.5 | 597.3 | 460.8 |
| Overlift of petroleum | 42.8 | 35.6 | 30.9 |
| Accrued interest | 85.8 | 84.5 | 95.8 |
| Payroll liabilities and other provisions | 219.2 | 221.9 | 176.5 |
| Total other current liabilities | 1 071.0 | 975.4 | 807.1 |
| Outstanding | Group | ||||
|---|---|---|---|---|---|
| Senior unsecured bonds (USD million) | amount | 31.12.2023 | 30.09.2023 | 31.12.2022 | |
| Senior Notes 3.000% (Jan 20/Jan 25)2) | USD 95.5 mill | 94.5 | 94.3 | 498.2 | |
| Senior Notes 2.875% (Sep 20/Jan 26)2) | USD 129.7 mill | 128.3 | 128.1 | 497.8 | |
| Senior Notes 2.000% (Jul 21/Jul 26)2)3) | USD 707.1 mill | 660.4 | 655.9 | 907.4 | |
| Senior Notes 5.600% (Jun 23/Jun 28)1) | USD 500 mill | 496.8 | 496.6 | - | |
| Senior Notes 1.125% (May 21/May 29) | EUR 750 mill | 824.8 | 790.4 | 795.3 | |
| Senior Notes 3.750% (Jan 20/Jan 30) | USD 1,000 mill | 995.2 | 995.0 | 994.4 | |
| Senior Notes 4.000% (Sep 20/Jan 31) | USD 750 mill | 745.9 | 745.7 | 745.3 | |
| Senior Notes 3.100% (Jul 21/Jul 31)3) | USD 1,000 mill | 859.3 | 854.7 | 840.8 | |
| Senior Notes 6.000% (Jun 23/Jun 33)1) | USD 1,000 mill | 993.0 | 992.8 | - | |
| Long-term bonds - book value | 5 798.2 | 5 753.6 | 5 279.2 | ||
| Long-term bonds - fair value | 5 629.4 | 5 268.2 | 4 829.7 |
1) In June 2023 the company issued two new USD bonds:
USD 500 million Senior Notes 5.600% (Jun 2028)
USD 1,000 million Senior Notes 6.000% (Jun 2033)
2) Parts of the proceeds from the new bonds were used to tender for our outstanding bonds maturing in 2025 and 2026. In total we repurchased the following volumes split per bond (principal amount):
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.
3) Prior to the repurchase 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 at 30 June 2022. The difference between fair value and nominal value is linearly amortised over the lifetime of the bonds (see note 7).
Interest is paid on a semi annual basis, except for the EUR Senior Notes which is paid on an annual basis. None of the bonds have financial covenants.
| Group | |||
|---|---|---|---|
| 2023 | 2023 | 2022 | |
| (USD million) | Q4 | 01.01.-30.09. | 01.01.-31.12. |
| Provisions as of beginning of period | 3 786.3 | 4 165.6 | 5 172.4 |
| Incurred removal cost | -33.5 | -126.7 | -79.2 |
| Accretion expense | 44.1 | 122.2 | 119.9 |
| Abandonment liabilities from acquisition of Lundin Energy | - | - | 745.9 |
| Foreign currency translation | - | - | 6.7 |
| Impact of changes to discount rate | 425.7 | -526.9 | -1 876.9 |
| Change in estimates and provisions relating to new drilling and installations | 332.0 | 152.2 | 76.9 |
| Total provision for abandonment liabilities | 4 554.7 | 3 786.3 | 4 165.6 |
| Short-term | 250.6 | 167.8 | 115.2 |
| Long-term | 4 304.1 | 3 618.5 | 4 050.4 |
The nominal pre-tax discount rate (risk-free) at end of Q4 is between 4.0 percent and 4.9 percent, depending on the timing of the expected cashflows.The corresponding range at end of Q3 was 4.6 to 5.5 percent. The calculations assume an inflation rate of 2.0 percent.
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.
On 18 January 2024, the Oslo District Court ruled that the Ministry of Energy's approvals for the plans for development and operation (PDO) for the Breidablikk, Tyrving, and Yggdrasil fields were invalid due to procedural errors. The court concluded that the state had failed to consider the effects of combustion emissions as part of the final PDO.
In addition, the court issued a temporary injunction, preventing the state from making decisions that assume valid PDO approval for the projects.
Currently, the ruling is non-binding in relation to the procedural errors. The state has filed an appeal against both the main ruling and the temporary injunction to the Borgarting Court of Appeal.
Aker BP, which has participating interests and operates the Yggdrasil and Tyrving development projects, is not a party to the court case. The PDO approvals granted for Yggdrasil and Tyrving remain valid in relation to Aker BP.
Aker BP continues executing the Yggdrasil and Tyrving projects in accordance with the permissions granted. In response to the current situation, a dedicated task force has been established to identify potential risks and coordinate the company's activities and risk-mitigating actions.
The court case is deemed to have no material impact on the Q4 interim financial statements.
| Total number of licences | 31.12.2023 | 30.09.2023 |
|---|---|---|
| Aker BP as operator | 118 | 120 |
| Aker BP as partner | 61 | 62 |
| Changes in production licences in which Aker BP is the operator: | Changes in production licences in which Aker BP is a partner: | ||||
|---|---|---|---|---|---|
| Licence: | 31.12.2023 | 30.09.2023 Licence: | 31.12.2023 | 30.09.2023 | |
| PL 976¹) | 70.000% | 40.000 % PL 9432) | 0.000% | 20.000 % | |
| PL 1041¹) | 80.000% | 70.000 % | |||
| PL 1048²) | 0.000% | 50.000 % | |||
| PL 1099²) | 0.000% | 40.000 % | |||
| PL 1110¹) | 55.000% | 40.000 % | |||
| Total | 3 | 5 Total | - | 1 |
1) Licence transactions
2) Relinquished licence or Aker BP has withdrawn from the licence
End of financial statement
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 3)
1) Includes payments of lease debt as disclosed in note 7.
| Q4 | Q3 | Q4 | 01.01.-31.12. | 01.01.-31.12. | ||
|---|---|---|---|---|---|---|
| (USD million) | Note | 2023 | 2023 | 2022 | 2023 | 2022 |
| Abandonment spend | ||||||
| Payment for removal and decommissioning of oil fields | 31.1 | 44.5 | 19.3 | 152.7 | 78.9 | |
| Payments of lease debt (abandonment activity) | 6 | 2.3 | 0.9 | 0.1 | 8.3 | 0.8 |
| Abandonment spend | 33.4 | 45.4 | 19.4 | 161.0 | 79.6 | |
| Depreciation per boe | ||||||
| Depreciation | 5 | 605.8 | 556.9 | 641.2 | 2 406.8 | 1 785.7 |
| Total produced volumes (boe million) | 2 | 40.9 | 41.4 | 39.7 | 166.7 | 112.9 |
| Depreciation per boe | 14.8 | 13.5 | 16.1 | 14.4 | 15.8 | |
| Dividend per share | ||||||
| Paid dividend | 347.6 | 347.6 | 331.8 | 1 390.4 | 1 005.7 | |
| Number of shares outstanding | 631.2 | 630.5 | 631.6 | 631.3 | 496.8 | |
| Dividend per share | 0.55 | 0.55 | 0.53 | 2.20 | 2.02 | |
| Capex | ||||||
| Disbursements on investments in fixed assets (excluding capitalised interest) | 1 053.8 | 856.9 | 570.2 | 3 171.6 | 1 580.0 | |
| Payments of lease debt (investments in fixed assets) | 6 | 29.3 | 27.2 | 7.8 | 95.7 | 46.9 |
| CAPEX | 1 083.1 | 884.1 | 578.1 | 3 267.3 | 1 627.0 | |
| EBITDA | ||||||
| Total income | 1 | 3 556.1 | 3 512.9 | 3 825.9 | 13 669.9 | 13 009.9 |
| Production expenses | 2 | -298.0 | -251.8 | -286.4 | -1 060.1 | -932.9 |
| Exploration expenses | 3 | -67.0 | -74.3 | -32.1 | -266.3 | -242.2 |
| Other operating expenses | -16.8 | -12.3 | -16.0 | -57.8 | -52.6 | |
| EBITDA | 3 174.4 | 3 174.4 | 3 491.4 | 12 285.7 | 11 782.3 | |
| EBITDAX | ||||||
| Total income | 1 | 3 556.1 | 3 512.9 | 3 825.9 | 13 669.9 | 13 009.9 |
| Production expenses | 2 | -298.0 | -251.8 | -286.4 | -1 060.1 | -932.9 |
| Other operating expenses | -16.8 | -12.3 | -16.0 | -57.8 | -52.6 | |
| EBITDAX | 3 241.4 | 3 248.8 | 3 523.5 | 12 552.0 | 12 024.5 | |
| Equity ratio | ||||||
| Total equity | 12 362.2 | 12 523.6 | 12 427.5 | 12 362.2 | 12 427.5 | |
| Total assets | 39 046.5 | 38 127.2 | 37 561.8 | 39 046.5 | 37 561.8 | |
| Equity ratio | 32% | 33% | 33% | 32% | 33% | |
| Exploration spend | ||||||
| Disbursements on investments in capitalised exploration expenditures | 52.0 | 43.1 | 37.8 | 238.6 | 251.8 | |
| Exploration expenses | 3 | 67.0 | 74.3 | 32.1 | 266.3 | 242.2 |
| Dry well | 3 | -38.5 | -46.6 | -9.7 | -153.9 | -135.8 |
| Payments of lease debt (exploration expenditures) | 6 | 0.2 | 1.3 | 0.2 | 12.0 | 6.2 |
| Exploration spend | 80.7 | 72.2 | 60.3 | 363.0 | 364.4 |
| Q4 | Q3 | Q4 | 01.01.-31.12. | 01.01.-31.12. | ||
|---|---|---|---|---|---|---|
| (USD million) | Note | 2023 | 2023 | 2022 | 2023 | 2022 |
| Interest coverage ratio | ||||||
| Twelve months rolling EBITDA | 12 285.7 | 12 602.7 | 11 782.3 | 12 285.7 | 11 782.3 | |
| Twelve months rolling EBITDA, impacts from IFRS 16 | 6 | -45.2 | -39.0 | -20.8 | -45.2 | -20.8 |
| Twelve months rolling EBITDA, excluding impacts from IFRS 16 | 12 240.5 | 12 563.8 | 11 761.4 | 12 240.5 | 11 761.4 | |
| Twelve months rolling interest expenses | 7 | 212.7 | 204.2 | 154.0 | 212.7 | 154.0 |
| Twelve months rolling amortised loan cost | 7 | 49.3 | 50.8 | 31.8 | 49.3 | 31.8 |
| Twelve months rolling interest income | 7 | 133.4 | 104.9 | 26.0 | 133.4 | 26.0 |
| Net interest expenses | 128.5 | 150.2 | 159.9 | 128.5 | 159.9 | |
| Interest coverage ratio1) | 95.2 | 83.6 | 73.6 | 95.2 | 73.6 | |
| Leverage ratio | ||||||
| Long-term bonds | 13 | 5 798.2 | 5 753.6 | 5 279.2 | 5 798.2 | 5 279.2 |
| Other interest-bearing debt | - | - | - | - | - | |
| Cash and cash equivalents | 10 | 3 388.4 | 3 375.2 | 2 756.0 | 3 388.4 | 2 756.0 |
| Net interest-bearing debt excluding lease debt | 2 409.8 | 2 378.4 | 2 523.2 | 2 409.8 | 2 523.2 | |
| Twelve months rolling EBITDAX | 12 552.0 | 12 834.1 | 12 024.5 | 12 552.0 | 12 024.5 | |
| Twelve months rolling EBITDAX, impacts from IFRS 16 | 6 | -44.4 | -38.2 | -20.2 | -44.4 | -25.0 |
| Twelve months rolling EBITDAX, excluding impacts from IFRS 16 | 12 507.6 | 12 795.9 | 12 004.3 | 12 507.6 | 11 999.5 | |
| Leverage ratio1) | 0.19 | 0.19 | 0.21 | 0.19 | 0.21 | |
| Net interest-bearing debt | ||||||
| Long-term bonds | 13 | 5 798.2 | 5 753.6 | 5 279.2 | 5 798.2 | 5 279.2 |
| Other interest-bearing debt | - | - | - | - | - | |
| Long-term lease debt | 6 | 555.5 | 352.2 | 98.1 | 555.5 | 98.1 |
| Short-term lease debt | 6 | 148.7 | 102.0 | 36.3 | 148.7 | 36.3 |
| Cash and cash equivalents | 10 | 3 388.4 | 3 375.2 | 2 756.0 | 3 388.4 | 2 756.0 |
| Net interest-bearing debt | 3 114.0 | 2 832.6 | 2 657.5 | 3 114.0 | 2 657.5 | |
| Free cash flow | ||||||
| Net cash flow from operating activities | 1 502.6 | 2 101.1 | 806.8 | 5 407.1 | 5 729.5 | |
| Net cash flow from investment activities | -1 041.9 | -944.5 | -708.4 | -3 467.9 | -3 116.6 | |
| Free cash flow | 460.7 | 1 156.6 | 98.4 | 1 939.2 | 2 612.9 |
1) These ratios are calculated based on Aker BP group figures only, with no proforma adjustments for the Lundin Energy transaction.
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
Postal address: P.O. Box 65 1324 Lysaker, Norway
Telephone: +47 51 35 30 00 E-mail: [email protected]
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