Earnings Release • Feb 10, 2023
Earnings Release
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Fourth quarter 2022 marked the end of a transformational year for Aker BP. Following the successful Lundin integration, the company has doubled its production, reduced its unit costs, and consolidated its position as a global leader within low carbon oil and gas production.
(Numbers in brackets represent the previous quarter)
"Fourth quarter marked the end of another remarkable year for Aker BP. Through the Lundin acquisition, we have doubled in size and created a stronger and more financially robust platform for future growth.
Our operations have been safer and more efficient than ever, and we are a global leader when it comes to low CO2 intensity in our industry.
And we have prepared and submitted PDOs for a large investment program which will contribute to new profitable growth and value creation both for Aker BP and its stakeholders.
In sum, I am very pleased with these achievements, and I believe we are well on our way to building the E&P company of the future."
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 restated.
| UNIT | Q4 2022 | Q3 2022 RESTATED |
Q4 2021 RESTATED |
|
|---|---|---|---|---|
| INCOME STATEMENT | ||||
| Total income | USD million | 3 826 | 4 866 | 1 849 |
| EBITDA | USD million | 3 491 | 4 536 | 1 559 |
| Net profit/loss | USD million | 112 | 763 | 355 |
| Earnings per share (EPS) | USD | 0.18 | 1.21 | 0.99 |
| OTHER FINANCIAL KEY FIGURES | ||||
| Net interest-bearing debt | USD million | 2 658 | 2 294 | 1 742 |
| Leverage ratio | 0.21* | 0.21* | 0.33 | |
| Dividend per share | USD | 0.53 | 0.53 | 0.42 |
| PRODUCTION AND SALES | ||||
| Net petroleum production | mboepd | 432.0 | 411.7 | 207.0 |
| Over/underlift | mboepd | (3.7) | (5.0) | (1.9) |
| Net sold volume | mboepd | 428.3 | 406.7 | 205.1 |
| - Liquids | mboepd | 362.2 | 342.2 | 165.4 |
| - Natural gas | mboepd | 66.0 | 64.5 | 39.7 |
| REALISED PRICES | ||||
| Liquids | USD/boe | 86.6 | 101.1 | 78.8 |
| Natural gas | USD/boe | 150.4 | 280.9 | 169.5 |
| AVERAGE EXCHANGE RATES | ||||
| USDNOK | 10.18 | 9.99 | 8.72 | |
| EURUSD | 1.02 | 1.01 | 1.14 |
*The ratio is calculated based on Aker BP group figures only, with no proforma adjustment for the Lundin transaction
| (USD MILLION) | Q4 2022 | Q3 2022 RESTATED |
Q4 2021 RESTATED |
FY 2022 RESTATED |
FY 2021 RESTATED |
|---|---|---|---|---|---|
| Total income | 3 826 | 4 866 | 1 849 | 13 010 | 5 669 |
| EBITDA | 3 491 | 4 536 | 1 559 | 11 782 | 4 541 |
| EBIT | 2 214 | 3 887 | 1 196 | 8 964 | 3 086 |
| Pre-tax profit | 2 177 | 3 713 | 1 165 | 8 777 | 2 896 |
| Net profit/loss | 112 | 763 | 355 | 1 603 | 828 |
| EPS (USD) | 0.18 | 1.21 | 0.99 | 3.23 | 2.30 |
The company has changed its accounting principle for abandonment provisions in the fourth quarter. The change is related to the discount rate applied in the calculation which will now consist of a risk-free rate only, while it historically has included a credit risk element. This contributes to an increase in the book value of the abandonment provisions and the corresponding assets and leads to higher depreciation. The company has also revised its accounting policy related to deferred tax on capitalised interests, increasing the applied deferred tax rate from 22 to 78 percent. Prior periods have been restated accordingly. Numbers in parenthesis in the sections below refers to restated Q3 2022 figures, where applicable.
Total income in the fourth quarter amounted to USD 3,826 (4,866) million. The main driver for the reduction was lower oil and gas prices. Realised liquids prices decreased by 14 percent to USD 86.6 (101.1) per barrel, and realised natural gas price decreased by 46 percent to USD 150.4 (280.9) per boe. Sold volumes increased by 5 percent to 428.3 (406.7) mboepd in the quarter.
Production cost for the oil and gas sold in the quarter amounted to USD 286 (236) million, mainly driven by increased sales volume compared to the previous quarter. The average production cost per barrel produced was stable at USD 7.2 (7.3). See note 4 for further details on production costs. Exploration expenses amounted to USD 32 (85) million, reflecting low activity in the quarter.
Depreciation amounted to USD 641 (594), corresponding to USD 16.1 (15.7) per barrel of oil equivalent, impacted by the change in accounting principle mentioned above.
Impairments amounted to USD 636 (55) million, of which USD 499 million was related to Wisting, where the planned investment decision has been postponed to 2026, with new cost and production profiles and where less favourable tax rules will apply. The remainder was related to technical goodwill at Edvard Grieg and was mainly caused by lower short term gas prices. See note 6 for further details.
Operating profit was USD 2,214 (3,887) million for the fourth quarter. Net financial expenses amounted to USD 37 (174) million. For more details, see note 9.
Profit before taxes amounted to USD 2,177 (3,713) million. Tax expense was USD 2,064 (2,949) million. The effective tax rate was 95 (79) percent, impacted by the impairment of technical goodwill with no effect on deferred tax. This resulted in a net profit for the fourth quarter 2022 of USD 112 (763) million.
The legal entities acquired in the Lundin transaction include companies with other functional currencies than USD (mainly NOK). The excess values in the purchase price allocation carried out as of 30 June 2022 were allocated to the underlying businesses acquired and denominated in the respective functional currencies of the entities that the excess values relate to. Translation from functional currency to the USD presentation currency upon consolidation gives rise to a currency translation element in the fourth quarter of USD 1,308 million, which is included in the statement of other comprehensive income. This mainly represents the net adjustment to the balance sheet due to the change in the USD/NOK exchange rate between 30 September and 31 December 2022 and is to a large extent a reversal of the corresponding negative amount of USD 1,013 million from the third quarter. At year end 2022 the legal entities acquired in the Lundin transaction were either liquidated or merged into Aker BP ASA. Hence, the mentioned impact on comprehensive income will cease from 1 January 2023.
| (USD MILLION) | 31.12.2022 | 30.09.2022 RESTATED |
31.12.2021 RESTATED |
|---|---|---|---|
| Goodwill | 13 935 | 13 193 | 1 647 |
| Property, plant and equipment (PP&E) | 15 887 | 15 307 | 10 214 |
| Other non-current assets | 2 984 | 3 057 | 1 863 |
| Cash and equivalent | 2 756 | 3 042 | 1 971 |
| Other current assets | 2 000 | 2 015 | 1 012 |
| Total assets | 37 562 | 36 613 | 16 708 |
| Equity | 12 428 | 11 320 | 2 197 |
| Bank and bond debt | 5 279 | 5 198 | 3 577 |
| Other long-term liabilities | 13 607 | 13 270 | 8 457 |
| Tax payable | 5 084 | 5 419 | 1 497 |
| Other current liabilities | 1 164 | 1 406 | 980 |
| Total equity and liabilities | 37 562 | 36 613 | 16 708 |
| Net interest-bearing debt | 2 658 | 2 294 | 1 742 |
| Leverage ratio | 0.21* | 0.21* | 0.33 |
*The ratio is calculated based on Aker BP group figures only, with no proforma adjustment for the Lundin transaction
At the end of the fourth quarter 2022, total assets amounted to USD 37.6 (36.6) billion, of which non-current assets were USD 32.8 (31.6) billion. As mentioned in the other comprehensive income section, parts of the balance sheet that arise from the Lundin transaction has been subject to currency adjustment, mainly caused by the weakening of USD against NOK during the quarter. This is the main reason for the increase of goodwill and property, plant and equipment in the fourth quarter.
Equity amounted to USD 12.4 (11.3) billion at the end of the quarter, corresponding to an equity ratio of 33 (31) percent, positively impacted by other comprehensive income.
Bond debt totalled USD 5,279 (5,198) million, and the company's bank facilities were not drawn. Other long-term liabilities amounted to USD 13.6 (13.3) billion.
Tax payable decreased by USD 334 million to 5,084 (5,419) million.
At the end of the fourth quarter 2022, the company had total available liquidity of USD 6.2 (6.4) billion, comprising of USD 2.8 (3.0) billion in cash and cash equivalents and USD 3.4 (3.4) billion in undrawn credit facilities.
| (USD MILLION) | Q4 2022 | Q3 2022 | Q4 2021 | FY 2022 | FY 2021 |
|---|---|---|---|---|---|
| Cash flow from operations | 807 | 2 361 | 1 211 | 5 729 | 4 282 |
| Cash flow from investments | -708 | -500 | -484 | -3 117 | -1 727 |
| Cash flow from financing | -329 | -1 041 | -180 | -1 828 | -1 123 |
| Net change in cash & cash equivalents | -231 | 820 | 547 | 785 | 1 433 |
| Cash and cash equivalents | 2 756 | 3 042 | 1 971 | 2 756 | 1 971 |
Net cash flow from operating activities was USD 807 (2,361) million in the quarter. Taxes paid amounted to USD 2,955 (1,241) million. The cash flow from operations was positively impacted by change in other balance sheet items mainly due to lower receivables and adjustments for significant currency losses on NOK nominated payables, such as tax, which are included in profit/loss before taxes. The amount largely represents a reversal of the corresponding negative impact in the third quarter.
Net cash used for investment activities was USD 708 (500) million, of which investments in fixed assets amounted to USD 570 (404) million for the quarter. Investments in capitalised exploration were USD 38 (89) million. Investments in financial assets amounted to USD 95 million, while the company received a settlement of USD 14 million related to the Lundin acquisition.
Net cash outflow from financing activities was USD 329 (1,041) million, of which the main item was dividend disbursements of USD 332 (332) million.
At the Annual General Meeting in April 2022, the Board was authorised to approve the distribution of dividends based on the company's annual accounts for 2021 pursuant to section 8-2 (2) of the Norwegian Public Limited Companies Act.
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
During the fourth quarter, the company paid a dividend of USD 0.525 per share. For the full year 2022, dividends amounted to USD 2.0 per share. On 9 February 2023, the Board resolved to pay a quarterly dividend of USD 0.55 per share in the first quarter 2023, which will be disbursed on or about 23 February 2023 (ex-dividend date 15 February 2023).
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 commodity derivatives exposure per 31 December 2022.
On 21 December 2021, Aker BP and Lundin Energy announced an agreement for Aker BP to acquire Lundin Energy's oil and gas business. As consideration, Lundin Energy's shareholders for each share in Lundin Energy received a cash consideration of USD 7.76 and 0.95098 shares in Aker BP, delivered in the form of Swedish Depository Receipts (SDRs). For more information about the SDR programme, please see https://akerbp.com/en/information-to-lundin-shareholders/.
The transaction was completed on 30 June 2022. In total, the consideration consisted of 271,908,701 newly issued shares and USD 2.22 billion in cash. After this, the total number of Aker BP shares issued is 632,022,210.
The acquired business was consolidated in the statement of financial position on a fair value basis per 30 June 2022 and is included in the income statement from 1 July 2022.
The acquisition included three Dutch legal entities and one Swiss legal entity, in addition to Lundin Energy Norway AS which was renamed to ABP Norway AS at completion of the transaction. ABP Norway AS was merged into Aker BP ASA on 31 December 2022. The Dutch and Swiss entities have been either liquidated or merged into Aker BP ASA, so that all NCS activities have been combined in one legal entity as from the beginning of 2023.
Aker BP's net production was 39.7 (37.9) mmboe in the fourth quarter 2022, corresponding to 432.0 (411.7) mboepd. Net sold volume was 428.3 (406.7) mboepd.
| KEY FIGURES | AKER BP INTEREST* | Q4 2022 | Q3 2022 | Q2 2022 | Q1 2022 | Q4 2021 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Alvheim | 80% (65%) | 35 265 | 38 087 | 35 295 | 34 688 | 31 721 |
| Bøyla (incl. Frosk) | 80% (65%) | 3 259 | 1 813 | 1 259 | 1 561 | 2 068 |
| Skogul | 65% | 1 612 | 1 910 | 2 488 | 2 407 | 1 817 |
| Vilje | 46.904% | 2 154 | 1 923 | 2 018 | 2 108 | 3 501 |
| Volund | 100% (65%) | 3 482 | 5 673 | 2 757 | 4 582 | 4 275 |
| Total production | 45 771 | 49 405 | 43 817 | 45 347 | 43 382 | |
| Production efficiency | 99 % | 100 % | 97 % | 98 % | 94 % |
*Production prior to the third quarter 2022 does not incorporate production related to Lundin Energy's ownership shares in the area. Aker BP's interest prior to the third quarter 2022 is presented in brackets.
Production from the Alvheim area was slightly down in the fourth quarter compared to the previous quarter. Production efficiency continued to be strong at 99 percent in the quarter.
The lifetime extension project for the Alvheim FPSO is progressing as planned. The purpose is to prolong the lifetime to 2040. The project finished upgrading the living quarters and ballast control system in the fourth quarter.
The Frosk development project completed its two-well drilling campaign. The project is now mobilizing for the subsea tie-back campaign which is the final part of the field development phase. Expected production start is late in the first quarter of 2023.
The Kobra East & Gekko (KEG) project is progressing according to plan and the project has completed installation of pipelines and static umbilical. The KEG drilling campaign is planned to commence in direct continuation of the Frosk programme. Production start for KEG is scheduled for 2024.
The Tyrving project (previously called Trell and Trine) is progressing according to plan and commitments have been made to secure vessel and materials for execution of the planned pipelay campaign in 2023. Drilling of the Tyrving wells is expected to commence in the first half of 2024. First oil is scheduled for 2025.
| KEY FIGURES | AKER BP INTEREST* | Q4 2022 | Q3 2022 | Q2 2022 | Q1 2022 | Q4 2021 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Edvard Grieg Area | 65% (0%) | 86 139 | 84 798 | - | - | - |
| Ivar Aasen | 36.1712% (34.7862%) | 13 550 | 14 203 | 7 019 | 14 038 | 15 157 |
| Total production | 99 689 | 99 000 | 7 019 | 14 038 | 15 157 | |
| Production efficiency | 99% | 99% | 52 % | 87 % | 81 % |
*Production prior to the third quarter 2022 does not incorporate production related to Lundin Energy's ownership shares in the area. Aker BP's interest prior to the third quarter 2022 is presented in brackets.
Edvard Grieg & Ivar Aasen production remained stable at 99.7 mboepd with high production efficiency of 99 percent in the fourth quarter.
The Johan Sverdrup Phase 2 project, which was successfully completed in the fourth quarter, included a power from shore solution for the neighbouring fields, including Edvard Grieg & Ivar Aasen. This eliminates the need for offshore power generation and is expected to reduce the CO2 emissions from these fields by approximately 200,000 tonnes per year.
At Ivar Aasen, the 2022 IOR campaign, consisting of three new wells, was successfully completed and the first well was put on production in December. The remaining wells will start production during first quarter 2023.
The Edvard Grieg IOR campaign for 2023 was approved in the fourth quarter. The campaign consists of three wells and drilling is scheduled to begin in the second quarter 2023.
The Hanz project is progressing according to plan. First oil is expected in first quarter 2024.
On 16 December, Aker BP and its partners submitted the plan for the Utsira High Project to the Norwegian Ministry of Petroleum and Energy. The project consists of three separate subsea tie-in projects. Symra (previously named Lille Prinsen) will be a tie-in to the Ivar Aasen platform, while Solveig phase 2 and Troldhaugen (previously named Rolvsnes) will be connected to the Edvard Grieg platform. The execution of the Troldhaugen project will depend on the continued strong performance of the extended well test and will most likely be concluded in the third quarter 2023.
The Utsira High Project will develop gross recoverable resources of 124 million barrels oil equivalent. Drilling will commence in third quarter 2025, while production start-up is scheduled for first quarter 2026 for Solveig and Troldhaugen, and first quarter 2027 for Symra. The total investments are estimated to approximately NOK 21 billion in real terms. Aker BP is the operator for all three developments.
| KEY FIGURES | AKER BP INTEREST* | Q4 2022 | Q3 2022 | Q2 2022 | Q1 2022 | Q4 2021 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Total production | 31.5733% (11.5733%) | 180 610 | 161 971 | 57 924 | 62 908 | 63 112 |
*Production prior to the third quarter 2022 does not incorporate production related to Lundin Energy's ownership shares in Johan Sverdrup. Aker BP's interest prior to the third quarter 2022 is presented in brackets.
Johan Sverdrup produced from the P1 processing platform at full process capacity of 535 mbblpd with high regularity throughout the fourth quarter, except for a short planned shutdown executed in December in connection with the start-up of the Phase 2 production. During the quarter, production well number 19 was put on production.
Production from the Johan Sverdrup Phase 2 development started safely 15 December, according to plan and cost.
Production ramp up is ongoing to full field facilities design capacity 720 mbblpd. Thereafter further increase to 755 mbblpd will be tested. All the initially processed oil is produced by wells already drilled from the field centre drilling platform DP. The first Phase 2 production well from a subsea template was successfully put on production early January.
| KEY FIGURES | AKER BP INTEREST | Q4 2022 | Q3 2022 | Q2 2022 | Q1 2022 | Q4 2021 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Total production | 23.835 % | 41 563 | 42 057 | 38 867 | 34 576 | 31 785 |
| Production efficiency | 97% | 97% | 90 % | 86 % | 88 % |
Production from Skarv in the fourth quarter was stable at 41.6 mboepd in the fourth quarter, with continued high production efficiency of 97 percent. Production from the Idun Tunge development started according to plan in the quarter.
Plan for Development and Operations (PDO) for three separate developments in the Skarv area was submitted to the Norwegian Ministry of Petroleum and Energy in December. The developments, coordinated by the Skarv Satellite Project (SSP), consists of the gas and condensate discoveries Alve Nord, Idun Nord and Ørn. The projects are estimated to
bring approximately 120 million barrels of oil equivalents (gross) through Skarv FPSO from 2027. Commitments have been made to ensure timely engineering, fabrication, and installation for the execution phase.
The Skarv partnership has approved equipment commitments related to further infill wells in the area. An infill well on Ærfugl is currently being matured towards an investment decision in May 2023.
| KEY FIGURES | AKER BP INTEREST | Q4 2022 | Q3 2022 | Q2 2022 | Q1 2022 | Q4 2021 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Ula | 80 % | 4 091 | 2 818 | 1 855 | 3 157 | 4 165 |
| Tambar | 55 % | 669 | 1 439 | 568 | 1 434 | 1 915 |
| Oda | 15 % | 4 007 | 4 401 | 1 247 | 1 014 | 1 297 |
| Total production | 8 766 | 8 658 | 3 670 | 5 605 | 7 376 | |
| Production efficiency | 56% | 62% | 36 % | 60 % | 77 % |
Production from the Ula area remained stable at 8.8 mboepd. The reduction on Tambar due to equipment failure was offset by three producers coming back on stream on Ula. Oda production remained high.
The field is expected to shut down in 2028 and a field decommissioning study was commenced to prepare a work program for well plugging and platform removal.
| KEY FIGURES | AKER BP INTEREST | Q4 2022 | Q3 2022 | Q2 2022 | Q1 2022 | Q4 2021 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Valhall | 90% | 42 408 | 40 658 | 29 122 | 44 945 | 45 623 |
| Hod | 90% | 13 141 | 9 984 | 792 | 593 | 426 |
| Total production | 55 549 | 50 642 | 29 914 | 45 538 | 46 050 | |
| Production efficiency | 89% | 87% | 56 % | 89 % | 84 % |
Fourth quarter production from the Valhall area was 55.5 mboepd, up from 50.6 mboepd in the previous quarter due to continued ramp-up at Hod as well as improved regularity. One new infill well on Valhall Flank West was put on production in the quarter. Production efficiency was at 89 percent.
The Noble Integrator rig continues to support stimulation and intervention activities and bring more wells up to their full production potential at Valhall. Towards the end of the first quarter 2023, the rig will be relocated to Hod to embark on the first phase of a campaign to permanently plug and abandon eight wells at the old Hod A platform. The second phase of this campaign is planned to commence in the second half of 2023 with the rig Noble Invincible.
The Plan for Development and Operations (PDO) for the joint Valhall PWP & Fenris development project (previously named Valhall NCP & King Lear) was submitted to the authorities in December 2022. The joint development project comprises a new centrally located production and wellhead platform (PWP) bridge-linked to the Valhall central complex with 24 well slots, and an unmanned installation (UI) with 8 slots at Fenris (formerly King Lear) subsea tied back 50 kilometres to the PWP.
Total recoverable resources for Valhall PWP-Fenris are estimated to 230 mmboe gross, divided into 160 mmboe at Fenris and 70 mmboe at Valhall. The development plan includes a total of 19 wells, of which 15 at Valhall PWP and 4 at Fenris. Production start is planned for the second and third quarter 2027, respectively.
The project will also involve a modernisation of Valhall that ensures continued operation when parts of the current infrastructure are to be phased out in 2028, thus enabling production of the remaining Valhall reserves from 2029 onwards, which are estimated at 135-140 mmboe gross. In addition, the project will add gas capacity to Valhall and thus enable Valhall to serve as a hub for potential new gas discoveries in the future.
The development will leverage Valhall's existing power from shore system with minimal emissions, estimated at less than 1 kg CO2/boe.
The Yggdrasil area (formerly NOAKA) is located between Oseberg and Alvheim in the Norwegian North Sea. The area holds several oil and gas discoveries with gross recoverable resources estimated at around 650 million barrels of oil equivalents, with further exploration and appraisal potential.
Yggdrasil consist of the licence groups Hugin, Fulla and Munin. The partners in the licences are Aker BP ASA, Equinor ASA and LOTOS Exploration & Production Norge AS. Aker BP is operator and will develop and operate the full area.
In the fourth quarter final investment decision was made by all involved partners. On 16 December 2022, plans for development and operation were submitted to the Norwegian Ministry of Petroleum and Energy.
The Yggdrasil development concept includes a processing platform with well area and living quarters, Hugin A. It will function as an area hub. Hugin A is planned with low manning levels and is also being developed to be periodically unmanned after a few years of operation.
The Frøy field will be developed with a normally unmanned wellhead platform, Hugin B, that will be tied back to Hugin A.
Following the Lundin transaction, Aker BP holds 35 percent interest in the Equinor-operated Wisting discovery in licences PL537 and PL537B in the Barents Sea.
The partners have previously been planning for a final investment decision for Wisting by the end of 2022. However, due to cost pressure and potential capacity constraints in the supply industry, combined with changes in the temporary tax system, the partners in November decided to postpone
Total exploration spend in the fourth quarter was USD 60 (122) million, while USD 32 (85) 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 Lupa prospect, in production license 229 E in the Barents Sea was completed in the fourth quarter. The
Munin is an unmanned production platform. It will be tied back to Hugin A for oil and produced water processing.
Yggdrasil also represents an extensive subsea development with a total of nine templates, pipelines and umbilicals. 55 wells are planned in the area, of which 38 subsea wells and 17 platform wells. Additionally, the area concept has high flexibility for potential tie-in of new discoveries.
The oil will be exported via Grane Oil Pipe and the gas will be exported through Statpipe.
The Yggdrasil area will be powered from shore to ensure minimal carbon footprint.
The Yggdrasil development has moved into the execution phase and are well into detail engineering. In December 2022, Aker BP entered into Yggdrasil agreements amounting to approximately NOK 50 billion with alliance partners and suppliers.
the decision to 2026, which led to an impairment charge of USD 499 million (including technical goodwill) in the fourth quarter.
The partners are now planning for further exploration activity in the area, aiming to increase the resource base. In parallel, the development concept will be further matured to ensure an economically sound development and a robust project execution.
well resulted in a gas discovery with preliminary estimates of between 57-132 million barrels of oil equivalent. Aker BP has 50 percent interest in the licence which is operated by Vår Energi.
The Uer well in production licence 943 (20 percent interest) was drilled in the quarter and concluded as dry.
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 2022 | Q3 2022 | Q2 2022 | Q1 2022 | Q4 2021 |
|---|---|---|---|---|---|---|
| Total recordable injury frequency (TRIF) L12M | Per mill. exp. hours |
1.1 | 1.3 | 1.6 | 1.6 | 1.8 |
| Serious incident frequency (SIF) L12M | Per mill. exp. hours |
0.4 | 0.2 | 0.2 | 0.1 | 0 |
| Acute spill | Count | 0 | 0 | 0 | 3 | 0 |
| Process safety events Tier 1 and 2 | Count | 0 | 0 | 0 | 0 | 0 |
| CO2 emissions intensity, Equity share | Kg CO2/boe | 3.7 | 4.3 | 4.9 | 4.8 | 4.9 |
| CO2 emissions intensity L12M | Kg CO2/boe | 3.1 | 3.5 | 4.7 | 4.5 | 5.2 |
The positive trend in TRIF continued in the fourth quarter 2022. There were three serious incidents in the quarter, two of which involved falling objects. These incidents were investigated, and mitigating actions have been identified. No one was injured.
Aker BP's decarbonisation strategy consists of the following key ambitions:
Aker BP's CO2 emissions intensity was further reduced to 3.1 (3.5) kg CO2 per boe in the quarter, driven by improved energy efficiency and lower drilling activity, and by electrification of Edvard Grieg & Ivar Aasen which started receiving power from shore via the Johan Sverdrup Phase 2 power supply towards the end of the quarter. This will reduce annual emissions by more than 200,000 tonnes per year.
For 2022, Aker BP's ambition was to reduce CO2 emissions from the company's operated assets by at least 10,000 tonnes through energy efficiency improvements. The realised reduction amounted to approximately 73,000 tonnes. For 2023, the company's goal is to reduce its greenhouse gas emissions by 4 percent from its operated assets, equivalent to approximately 38,000 tonnes.
The company has applied for a licence area on the Norwegian continental shelf for CO2 storage and is working with partners to evaluate its potential as a business opportunity and as a means of reducing the company's net carbon footprint in the future.
The Board is of the opinion that, following the acquisition of Lundin Energy's oil and gas business, Aker BP is uniquely positioned for value creation. The key characteristics of the company are:
The company's financial plan for 2023 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 restated.
| Group | ||||||
|---|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | |||
| Restated | Restated | Restated | Restated | |||
| (USD 1 000) | Note | 2022 | 2022 | 2021 | 2022 | 2021 |
| Petroleum revenues | 3 803 738 | 4 850 956 | 1 820 879 | 12 896 182 | 5 639 990 | |
| Other income | 22 191 | 15 376 | 28 201 | 113 716 | 28 757 | |
| Total income | 3 | 3 825 929 | 4 866 332 | 1 849 080 | 13 009 898 | 5 668 747 |
| Production costs | 4 | 286 424 | 235 921 | 202 374 | 932 870 | 745 313 |
| Exploration expenses | 5 | 32 094 | 85 275 | 82 620 | 242 193 | 353 034 |
| Depreciation | 7 | 641 225 | 593 895 | 283 741 | 1 785 672 | 1 192 889 |
| Impairments | 6,7 | 636 213 | 55 128 | 79 016 | 1 032 154 | 262 554 |
| Other operating expenses | 16 026 | 9 412 | 5 536 | 52 577 | 29 261 | |
| Total operating expenses | 1 611 981 | 979 631 | 653 287 | 4 045 466 | 2 583 051 | |
| Operating profit/loss | 2 213 947 | 3 886 700 | 1 195 792 | 8 964 432 | 3 085 696 | |
| Interest income | 13 458 | 5 701 | 1 441 | 25 959 | 2 481 | |
| Other financial income | 590 702 | 291 481 | 31 041 | 774 287 | 116 171 | |
| Interest expenses | 35 764 | 25 121 | 26 072 | 107 718 | 139 533 | |
| Other financial expenses | 605 653 | 446 140 | 36 772 | 880 109 | 169 032 | |
| Net financial items | 9 | -37 257 | -174 080 | -30 362 | -187 581 | -189 913 |
| Profit/loss before taxes | 2 176 691 | 3 712 621 | 1 165 431 | 8 776 851 | 2 895 783 | |
| Tax expense (+)/income (-) | 10 | 2 064 333 | 2 949 388 | 810 264 | 7 173 910 | 2 067 855 |
| Net profit/loss | 112 357 | 763 233 | 355 166 | 1 602 940 | 827 928 | |
| Weighted average no. of shares outstanding basic and diluted | 631 585 639 | 631 431 886 | 359 787 854 | 496 764 969 | 359 642 622 | |
| Basic and diluted earnings/loss USD per share | 0.18 | 1.21 | 0.99 | 3.23 | 2.30 |
| Group | ||||||
|---|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | |||
| Restated | Restated | Restated | Restated | |||
| (USD 1 000) Note |
2022 | 2022 | 2021 | 2022 | 2021 | |
| Profit/loss for the period | 112 357 | 763 233 | 355 166 | 1 602 940 | 827 928 | |
| Items which may be reclassified over profit and loss (net of taxes) Foreign currency translation |
1 012 811 | -1 012 811 | - | - | - | |
| Items which will not be reclassified over profit and loss (net of taxes) Foreign currency translation Actuarial gain/loss pension plan |
295 325 3 |
- | - | 295 325 3 |
- | |
| Total comprehensive income/loss in period | 1 420 496 | -249 578 | 355 166 | 1 898 268 | 827 928 |
| Group | ||||
|---|---|---|---|---|
| Restated | Restated | |||
| (USD 1 000) | Note | 31.12.2022 | 30.09.2022 | 31.12.2021 |
| ASSETS | ||||
| Intangible assets | ||||
| Goodwill | 7 | 13 934 986 | 13 193 404 | 1 647 436 |
| Capitalized exploration expenditures | 7 | 251 736 | 222 587 | 256 535 |
| Other intangible assets | 7 | 2 344 354 | 2 527 042 | 1 407 551 |
| Tangible fixed assets | ||||
| Property, plant and equipment | 7 | 15 886 659 | 15 306 528 | 10 214 438 |
| Right-of-use assets | 7 | 111 336 | 119 104 | 94 177 |
| Financial assets | ||||
| Long-term receivables | 169 528 | 82 380 | 73 346 | |
| Other non-current assets | 104 480 | 105 409 | 30 304 | |
| Long-term derivatives | 13 | 2 907 | - | 1 375 |
| Total non-current assets | 32 805 987 | 31 556 454 | 13 725 162 | |
| Inventories | ||||
| Inventories | 209 506 | 173 816 | 126 442 | |
| Receivables | ||||
| Trade receivables | 950 942 | 791 851 | 366 785 | |
| Other short-term receivables | 11 | 686 237 | 1 047 222 | 500 154 |
| Short-term derivatives | 13 | 153 096 | 2 129 | 18 577 |
| Cash and cash equivalents | ||||
| Cash and cash equivalents | 12 | 2 756 012 | 3 041 997 | 1 970 906 |
| Total current assets | 4 755 793 | 5 057 014 | 2 982 863 | |
| TOTAL ASSETS | 37 561 780 | 36 613 468 | 16 708 025 |
| Group | ||||
|---|---|---|---|---|
| Restated | Restated | |||
| (USD 1 000) | Note | 31.12.2022 | 30.09.2022 | 31.12.2021 |
| EQUITY AND LIABILITIES | ||||
| Equity | ||||
| Share capital | 84 348 | 84 348 | 57 056 | |
| Share premium | 12 946 640 | 12 946 640 | 3 637 297 | |
| Other equity | -603 482 | -1 710 650 | -1 497 538 | |
| Total equity | 12 427 506 | 11 320 337 | 2 196 814 | |
| Non-current liabilities | ||||
| Deferred taxes | 10 | 9 359 146 | 8 971 538 | 3 291 287 |
| Long-term abandonment provision | 16 | 4 050 396 | 4 076 903 | 5 071 491 |
| Long-term bonds | 15 | 5 279 164 | 5 198 294 | 3 576 735 |
| Long-term derivatives | 13 | 16 981 | 43 948 | 2 370 |
| Long-term lease debt | 8 | 98 095 | 95 197 | 91 835 |
| Other non-current liabilities | 82 306 | 82 304 | - | |
| Total non-current liabilities | 18 886 088 | 18 468 185 | 12 033 718 | |
| Current liabilities | ||||
| Trade creditors | 133 875 | 93 836 | 147 366 | |
| Accrued public charges and indirect taxes | 36 632 | 33 792 | 28 147 | |
| Tax payable | 10 | 5 084 142 | 5 418 505 | 1 497 291 |
| Short-term derivatives | 13 | 34 924 | 429 861 | 35 082 |
| Short-term abandonment provision | 16 | 115 202 | 107 613 | 100 863 |
| Short-term lease debt | 8 | 36 298 | 42 310 | 44 378 |
| Other current liabilities | 14 | 807 113 | 699 029 | 624 366 |
| Total current liabilities | 6 248 186 | 6 824 946 | 2 477 493 | |
| Total liabilities | 25 134 274 | 25 293 131 | 14 511 211 | |
| TOTAL EQUITY AND LIABILITIES | 37 561 780 | 36 613 468 | 16 708 025 |
| Other equity | ||||||||
|---|---|---|---|---|---|---|---|---|
| Other comprehensive income | ||||||||
| Foreign currency | ||||||||
| Share | Other paid-in | Actuarial | translation | Accumulated | Total other | |||
| (USD 1 000) | Share capital | premium | capital | gains/losses | reserves | deficit | equity | Total equity |
| Equity at 01.01.2021 before restatement | 57 056 | 3 637 297 | 573 083 | -76 | -115 491 | -2 164 587 | -1 707 071 | 1 987 281 |
| Change in accounting principle1) | - | - | - | - | - | -122 300 | -122 300 | -122 300 |
| Restated equity as of 01.01.2021 | 57 056 | 3 637 297 | 573 083 | -76 | -115 491 | -2 286 886 | -1 829 371 | 1 864 982 |
| Dividend distributed | - | - | - | - | - | -337 500 | -337 500 | -337 500 |
| Restated profit/loss for the period | - | - | - | - | - | 472 762 | 472 762 | 472 762 |
| Net purchase of treasury shares | - | - | - | - | - | -8 595 | -8 595 | -8 595 |
| Restated equity as of 30.09.2021 | 57 056 | 3 637 297 | 573 083 | -76 | -115 491 | -2 160 220 | -1 702 704 | 1 991 648 |
| Dividends distributed | - | - | - | - | - | -150 000 | -150 000 | -150 000 |
| Restated profit/loss for the period | - | - | - | - | - | 355 166 | 355 166 | 355 166 |
| Other comprehensive income for the period | - | - | - | - | ||||
| Restated equity as of 31.12.2021 | 57 056 | 3 637 297 | 573 083 | -76 | -115 491 | -1 955 054 | -1 497 538 | 2 196 814 |
| Dividend distributed | - | - | - | - | - | -673 919 | -673 919 | -673 919 |
| Private placement | 27 292 | 9 309 343 | - | - | - | - | - | 9 336 636 |
| Restated profit/loss for the period | - | - | - | - | - | 1 490 583 | 1 490 583 | 1 490 583 |
| Purchase of treasury shares | - | - | - | - | - | -16 965 | -16 965 | -16 965 |
| Other comprehensive income for the period | - | - | - | -1 012 811 | - | -1 012 811 | -1 012 811 | |
| Restated equity as of 30.09.2022 | 84 348 | 12 946 640 | 573 083 | -76 | -1 128 303 | -1 155 355 | -1 710 650 | 11 320 337 |
| Dividend distributed | - | - | - | - | - | -331 812 | -331 812 | -331 812 |
| Profit/loss for the period | - | - | - | - | - | 112 357 | 112 357 | 112 357 |
| Sale of treasury shares2) | - | - | - | - | - | 18 489 | 18 489 | 18 489 |
| Other comprehensive income for the period | - | - | -3 | 1 308 137 | - | 1 308 134 | 1 308 134 | |
| Equity as of 31.12.2022 | 84 348 | 12 946 640 | 573 083 | -78 | 179 834 | -1 356 320 | -603 482 | 12 427 506 |
1) Relates to changes in accounting principle for deferred tax on capitalised interest, as described in note 1
2) The treasury shares are purchased/sold for use in the group's share saving plan
| Group | |||||||
|---|---|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | ||||
| Restated | Restated | Restated | Restated | ||||
| (USD 1 000) | Note | 2022 | 2022 | 2021 | 2022 | 2021 | |
| CASH FLOW FROM OPERATING ACTIVITIES | |||||||
| Profit/loss before taxes | 2 176 691 | 3 712 621 | 1 165 431 | 8 776 851 | 2 895 783 | ||
| Taxes paid | 10 | -2 955 009 | -1 240 800 | -198 475 | -5 332 125 | -296 155 | |
| Taxes refunded | 10 | - | - | 38 350 | - | 72 989 | |
| Depreciation | 7 | 641 225 | 593 895 | 283 741 | 1 785 672 | 1 192 889 | |
| Impairment | 6,7 | 636 213 | 55 128 | 79 016 | 1 032 154 | 262 554 | |
| Accretion expenses | 9,16 | 40 286 | 36 716 | 16 494 | 119 895 | 61 944 | |
| Total interest expenses (excluding amortized loan costs) | 9 | 22 677 | 12 034 | 23 034 | 75 903 | 117 073 | |
| Changes in unrealized gain/loss in derivatives | 3,9 | -575 779 | 70 422 | 1 444 | -325 242 | 50 015 | |
| Amortized loan costs | 9 | 13 087 | 13 087 | 3 038 | 31 815 | 22 460 | |
| Expensed capitalized dry wells | 5,7 | 9 745 | 52 936 | 33 243 | 135 800 | 98 827 | |
| Changes in inventories, trade creditors and receivables | -154 742 | -106 308 | 23 164 | -268 657 | -48 794 | ||
| Changes in other balance sheet items | 952 458 | -838 974 | -257 771 | -302 594 | -147 428 | ||
| NET CASH FLOW FROM OPERATING ACTIVITIES | 806 850 | 2 360 757 | 1 210 710 | 5 729 472 | 4 282 157 | ||
| CASH FLOW FROM INVESTMENT ACTIVITIES | |||||||
| Payment for removal and decommissioning of oil fields | -19 296 | -7 329 | -16 123 | -78 870 | -172 512 | ||
| Disbursements on investments in fixed assets (excluding capitalized interest) | -570 227 | -403 742 | -421 862 | -1 580 045 | -1 376 879 | ||
| Disbursements on investments in capitalized exploration | -37 788 | -89 163 | -45 656 | -251 764 | -177 464 | ||
| Investments in financial asset | -95 000 | - | - | -95 000 | - | ||
| Consideration paid in Lundin Energy transaction net of cash acquired | 13 862 | - | - | -1 228 922 | - | ||
| Cash received from sale of financial asset | - | - | - | 118 005 | - | ||
| NET CASH FLOW FROM INVESTMENT ACTIVITIES | -708 449 | -500 234 | -483 642 | -3 116 596 | -1 726 855 | ||
| CASH FLOW FROM FINANCING ACTIVITIES | |||||||
| Net drawdown/repayment/fees related to revolving credit facility | - | -600 000 | - | -601 050 | -7 675 | ||
| Repayment of bonds | - | - | - | - | -1 282 503 | ||
| Net proceeds from bond issue | - | - | - | - | 899 334 | ||
| Interest paid (including interest element of lease payments) | -3 531 | -79 828 | -8 444 | -156 465 | -151 085 | ||
| Payments on lease debt related to investments in fixed assets | -6 976 | -6 641 | -18 125 | -42 452 | -44 805 | ||
| Payments on other lease debt | -5 662 | -5 655 | -3 071 | -24 121 | -39 810 | ||
| Paid dividend | -331 812 | -331 812 | -150 000 | -1 005 731 | -487 500 | ||
| Net purchase/sale of treasury shares | 18 489 | -16 965 | - | 1 524 | -8 595 | ||
| NET CASH FLOW FROM FINANCING ACTIVITIES | -329 492 | -1 040 900 | -179 640 | -1 828 294 | -1 122 640 | ||
| Net change in cash and cash equivalents | -231 091 | 819 622 | 547 429 | 784 582 | 1 432 662 | ||
| Cash and cash equivalents at start of period | 3 041 997 | 2 153 644 | 1 420 783 | 1 970 906 | 537 801 | ||
| Effect of exchange rate fluctuation on cash held | -54 894 | 68 730 | 2 694 | 525 | 443 | ||
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 12 | 2 756 012 | 3 041 997 | 1 970 906 | 2 756 012 | 1 970 906 |
(All figures in USD 1 000 unless otherwise stated)
These unaudited condensed consolidated interim financial statements ("interim financial statements") have been prepared in accordance with the International Financial Reporting Standards as adopted by the EU ("IFRS") 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 2021 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 report. The activity of Lundin Energy has been fully reflected in the financial statements from 30 June 2022, including effects from the fair value adjustment of Lundin Energy in line with IFRS 3, as described in note 2 to the second quarter financial statements. In all material respects, the activity of Lundin Energy has been conducted in the legal entity ABP Norway AS (previously Lundin Energy Norway AS), which had NOK as its functional currency. In line with accounting guidance, the related purchase price allocation (PPA) has been fixed in NOK accordingly, and thus given rise to a significant foreign currency translation in the group accounts recognized in the statement of comprehensive income during subsequent quarters. Due to the development of currency rates during Q3 and Q4 2022, the main part of the currency translation recognized in Q3 has been reversed in Q4. At 31 December 2022, ABP Norway AS merged with Aker BP ASA, meaning that the mentioned impact on comprehensive impact will cease from 1 January 2023.
These interim financial statements were authorised for issue by the company's Board of Directors on 9 February 2023.
The accounting principles used for this interim report are consistent with the principles used in the group's 2021 annual financial statements except for the impact of changes in accounting principle reflected in these interim financial statements as described below.
In preparing these interim financial statements, management has made judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, income and expense. Actual results may differ from these estimates.
As described in the accounting principles in the 2021 Annual Financial Statements, the discount rate for calculating abandonment provisions has historically included a credit element in addition to a risk free rate. In line with the development in industry practice with regards to the interpretation of the relevant guidelines in IAS 37, the company has changed the discount rate so that this no longer includes a credit element. Comparative figures from 1 January 2021 have been restated accordingly. Based on the complexity in the calculations, it has been deemed impracticable to measure the impact on equity at 1 January 2021. As a result, the company has recorded the difference between the remeasured abandonment provision and the historical abandonment provision at 1 January 2021 as an adjustment to Property, plant and equipment.
| Q3 | Q4 | 01.01.-31.12. | ||
|---|---|---|---|---|
| Breakdown of restatement impact on the income statement (USD 1 000) | 2022 | 2021 | 2022 | 2021 |
| Depreciation - prior to restatement | 521 590 | 219 312 | 1 592 815 | 964 083 |
| Depreciation - after restatement | 593 895 | 283 741 | 1 785 672 | 1 192 889 |
| Change | 72 306 | 64 429 | 192 857 | 228 807 |
| Impairment - prior to restatement | 55 128 | 79 016 | 1 113 374 | 262 554 |
| Impairment - after restatement | 55 128 | 79 016 | 1 032 154 | 262 554 |
| Change | - | - | -81 220 | - |
| Net financial items - prior to restatement | -177 262 | -42 683 | -214 834 | -241 718 |
| Net financial items - after restatement | -174 080 | -30 362 | -187 581 | -189 913 |
| Change | 3 182 | 12 321 | 27 253 | 51 804 |
| Tax expense/income - prior to restatement | 2 998 412 | 853 509 | 7 241 135 | 2 222 080 |
| Tax expense/income - after restatement | 2 944 493 | 812 862 | 7 175 311 | 2 084 012 |
| Change | -53 919 | -40 647 | -65 824 | -138 069 |
| Net profit/loss - prior to restatement | 783 332 | 364 030 | 1 620 101 | 850 704 |
| Net profit/loss - after restatement | 768 128 | 352 568 | 1 601 540 | 811 771 |
| Change | -15 204 | -11 462 | -18 561 | -38 933 |
| Breakdown of restatement impact on the statement of financial position (USD 1 000) | 30.09.2022 | 31.12.2021 |
|---|---|---|
| Property, plant and equipment - prior to restatement | 14 865 385 | 7 976 308 |
| Property, plant and equipment - after restatement | 15 306 528 | 10 214 438 |
| Change | 441 143 | 2 238 131 |
| Long-term abandonment provision - prior to restatement | 3 374 373 | 2 656 358 |
| Long-term abandonment provision - after restatement | 4 076 903 | 5 071 491 |
| Change | 702 530 | 2 415 133 |
| Deferred tax - prior to restatement | 9 070 689 | 3 323 213 |
| Deferred tax - after restatement | 8 866 797 | 3 185 144 |
| Change | -203 893 | -138 069 |
| Equity - prior to restatement | 11 482 574 | 2 341 891 |
| Equity - after restatement | 11 425 079 | 2 302 957 |
| Change | -57 495 | -38 933 |
The tax regime for oil and gas companies in Norway limits the tax deduction on parts of the company's interest expenses to 22 percent, while the general tax rate in the industry is 78 percent. Parts of these interest expenses have been capitalised as Property, plant and equipment, and deferred tax has been calculated at 22 percent in line with the tax deduction outside the special tax regime, in line with industry peers. The company has revised its accounting policy, and concluded to change the applied deferred tax rate from 22 to 78 percent for interest capitalised as Property, plant and equipment, to better reflect the tax consequences that would follow from the manner in which the company expects to recover the carrying amount of Property, plant and equipment. Prior periods have been restated accordingly. The figures below include the restatements related to abandonment provisions in the table above, to the extent applicable.
| Q3 | Q4 | 01.01.-31.12. | ||
|---|---|---|---|---|
| Breakdown of restating impact on the income statement (USD 1 000) | 2022 | 2021 | 2022 | 2021 |
| Tax expense/income - prior to restating | 2 944 493 | 812 862 | 7 175 311 | 2 084 012 |
| Tax expense/income - after restating | 2 949 388 | 810 264 | 7 173 910 | 2 067 855 |
| Change | 4 895 | -2 598 | -1 401 | -16 157 |
| Breakdown of restating impact on the statement of financial position (USD 1 000) | 30.09.2022 | 31.12.2021 |
|---|---|---|
| Deferred tax - prior to restating | 8 866 797 | 3 185 144 |
| Deferred tax - after restating | 8 971 538 | 3 291 287 |
| Change | 104 742 | 106 143 |
| Equity - prior to restating | 11 425 079 | 2 302 957 |
| Equity - after restating | 11 320 337 | 2 196 814 |
| Change | -104 742 | -106 143 |
The significant judgements made by management in applying the group's accounting policies and the key sources of estimation uncertainty are in all material respects the same as those that were applied in the group's 2021 annual financial statements except for the changes described above.
On 30 June 2022, Aker BP finalized the acquisition of Lundin Energy. The transaction was announced on 21 December 2021, and Aker BP issued 271.91 million new shares to the owners of Lundin Energy as compensation. In addition, the group paid a cash consideration of USD 2.22 billion. The purpose of the transaction is to create the E&P company of the future which will offer low CO2 emmisions, low cost and an attractive growth pipeline in the industry. The acquisition includes three Dutch and one Swiss legal entity, in addition to Lundin Energy Norway AS (renamed to ABP Norway AS at completion of the transaction). All oil and gas assets included in the transaction are located on the Norwegian Continental Shelf.
The acquisition date for accounting purposes corresponds to the finalization of the transaction on 30 June 2022. The acquisition is regarded as a business combination and has been accounted for using the acquisition method of accounting in accordance with IFRS 3. A purchase price allocation (PPA) has been performed to allocate the consideration to fair value of assets and liabilities in Lundin Energy. The PPA is performed as of the acquisition date, 30 June 2022. The 30 June closing share price at Oslo Stock Exchange (NOK 342.1) and the closing currency exchange rate (USD/NOK 9.9629) were used as a basis for measuring the value of the shares consideration, as set forth below. The value of the cash consideration is adjusted for certain settlement arrangements and currency impacts as the cash was transferred in Swedish Kronor.
| (USD 1 000) | 30.06.2022 |
|---|---|
| Value of cash consideration | 2 235 667 |
| Value of share consideration | 9 336 636 |
| Total value of consideration | 11 572 302 |
In the fourth quarter, the group received a settlement of USD 13.9 million from the seller, meaning that total value of consideration was reduced to USD 11 558 million.
Each identifiable asset and liability is measured at its acquisition date fair value based on guidance in IFRS 13. The standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. This definition emphasizes that fair value is a marketbased measurement, not an entity-specific measurement. When measuring fair value, the group uses the assumptions that market participants would use when pricing the asset or liability under current market conditions, including assumptions about risk. Acquired property, plant and equipment have been valued using the cost approach (replacement cost), while intangible assets (value of licenses) have been valued using the income approach.
Accounts receivable are recognized at gross contractual amounts due, as they relate to large and credit-worthy customers. Historically, there has been no significant uncollectible accounts receivable in Lundin Energy.
The recognized amounts of assets and liabilities assumed as at the date of the acquisition were as follows:
| (USD 1 000) | 30.06.2022 |
|---|---|
| Goodwill1) | 12 598 299 |
| Other intangible assets2) | 1 282 230 |
| Property, plant and equipment3) | 7 508 731 |
| Right-of-use assets | 34 757 |
| Long-term receivables | 12 550 |
| Other non-current assets | 241 |
| Inventories | 40 156 |
| Trade receivables | 389 758 |
| Other short-term receivables | 217 474 |
| Intercompany | 57 048 |
| Cash and cash equivalents | 937 619 |
| Total assets | 23 078 862 |
| Deferred taxes1) | 5 844 226 |
| Long-term abandonment provision3) | 569 751 |
| Long-term bonds | 1 725 965 |
| Long-term derivatives | 4 277 |
| Long-term lease debt | 20 251 |
| Other interest-bearing debt | 600 000 |
| Trade creditors | 17 858 |
| Accrued public charges and indirect taxes | 33 109 |
| Tax payable | 2 181 017 |
| Short-term derivatives | 199 367 |
| Short-term abandonment provision | 21 580 |
| Short-term lease debt | 14 506 |
| Other current liabilities | 274 655 |
| Total liabilities | 11 506 560 |
| Net assets and liabilities recognized | 11 572 302 |
| Fair value of consideration paid on acquisition4) | 11 572 302 |
1) During Q4, a remeasurement adjustment was made to the deferred tax liability resulting in a reduction of the deferred tax liability by USD 42 million. This has been adjusted in Q4 with goodwill as the offsetting entry.
2) Mainly related to undeveloped oil and gas assets
3) As described in note 1, the accounting principle for abandonment provision has been changed in Q4, increasing the total abandonment provision to USD 745 million with an offsetting entry on Property, plant and equipment.
4) In the fourth quarter, the group received a settlement of USD 13.9 million from the seller, meaning that total value of consideration was reduced to USD 11 558 million.
The goodwill of USD 12.6 billion arises principally because of the following factors:
The ability to capture synergies that can be realized from managing a larger portfolio of both acquired and existing fields on the Norwegian Continental Shelf, including workforce ("residual goodwill").
The requirement to recognize deferred tax assets and liabilities for the difference between the assigned fair values and the tax bases of assets acquired and liabilities assumed in a business combination. Licences under development and licences in production can only be sold in a market after tax, based on a decision made by the Norwegian Ministry of Finance pursuant to the Petroleum Taxation Act Section 10. The assessment of fair value of such licences is therefore based on cash flows after tax. Nevertheless, in accordance with IAS 12 Sections 15 and 19, a provision is made for deferred tax corresponding to the tax rate multiplied by the difference between the acquisition cost and the tax base. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax ("technical goodwill").
None of the goodwill recognized will be deductable for tax purposes.
| Reconciliation of goodwill from the acquisition of Lundin Energy (USD 1 000) | 30.06.2022 |
|---|---|
| Goodwill related to synergies - residual goodwill1) | 6 347 119 |
| Goodwill as a result of deferred tax - technical goodwill | 6 251 180 |
| Net goodwill from the acquisition of Lundin Energy | 12 598 299 |
1) As mentioned above, the goodwill has been subsequently adjusted.
The purchase price allocation above is preliminary and based on currently available information about fair values as of the acquisition date. If new information becomes available within 12 months from the acquisition date, the group may change the fair value assessment in the PPA, in accordance with guidance in IFRS 3.
| Group | ||||||
|---|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | |||
| Breakdown of petroleum revenues (USD 1 000) | 2022 | 2022 | 2021 | 2022 | 2021 | |
| Sales of liquids | 2 886 641 | 3 182 066 | 1 199 242 | 8 986 404 | 4 392 625 | |
| Sales of gas | 913 536 | 1 665 909 | 618 441 | 3 898 895 | 1 233 314 | |
| Tariff income | 3 561 | 2 981 | 3 195 | 10 883 | 14 051 | |
| Total petroleum revenues | 3 803 738 | 4 850 956 | 1 820 879 | 12 896 182 | 5 639 990 | |
| Sales of liquids (boe 1 000) | 33 326 | 31 484 | 15 216 | 91 816 | 63 447 | |
| Sales of gas (boe 1 000) | 6 074 | 5 931 | 3 649 | 20 164 | 13 935 | |
| Other income (USD 1 000) | ||||||
| Realized gain/loss (-) on commodity derivatives | 5 744 | -5 080 | -6 638 | 27 003 | -19 362 | |
| Unrealized gain/loss (-) on commodity derivatives | 4 402 | -5 156 | 3 432 | 8 989 | -5 449 | |
| Gain on license transactions | - | - | - | 11 000 | - | |
| Other income | 12 046 | 25 612 | 31 407 | 66 725 | 53 568 | |
| Total other income | 22 191 | 15 376 | 28 201 | 113 716 | 28 757 |
| Group | |||||||
|---|---|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | ||||
| Breakdown of production cost (USD 1 000) | 2022 | 2022 | 2021 | 2022 | 2021 | ||
| Cost of operations | 192 948 | 192 314 | 139 544 | 682 681 | 472 791 | ||
| Shipping and handling | 73 763 | 68 679 | 41 874 | 231 513 | 179 579 | ||
| Environmental taxes | 21 083 | 13 650 | 10 428 | 63 944 | 47 637 | ||
| Production cost based on produced volumes | 287 794 | 274 644 | 191 845 | 978 139 | 700 007 | ||
| Adjustment for over/underlift (-) | -1 370 | -38 723 | 10 529 | -45 269 | 45 306 | ||
| Production cost based on sold volumes | 286 424 | 235 921 | 202 374 | 932 870 | 745 313 | ||
| Total produced volumes (boe 1 000) | 39 741 | 37 879 | 19 042 | 112 853 | 76 439 | ||
| Production cost per boe produced (USD/boe) | 7.2 | 7.3 | 10.1 | 8.7 | 9.2 |
| Group | |||||
|---|---|---|---|---|---|
| Q4 | Q3 | Q4 | 01.01.-31.12. | ||
| Breakdown of exploration expenses (USD 1 000) | 2022 | 2022 | 2021 | 2022 | 2021 |
| Seismic | 3 561 | 10 313 | 3 079 | 34 424 | 23 138 |
| Area fee | 3 758 | 1 186 | 7 067 | 12 324 | 18 891 |
| Field evaluation | 830 | 3 812 | 31 218 | 10 749 | 176 969 |
| Dry well expenses | 9 745 | 52 936 | 33 243 | 135 800 | 98 827 |
| Other exploration expenses | 14 201 | 17 028 | 8 012 | 48 896 | 35 208 |
| Total exploration expenses | 32 094 | 85 275 | 82 620 | 242 193 | 353 034 |
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 2022, 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 recognized 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 recognized 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 licenses and licenses 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 2022.
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 2023 to the end of Q4 2025. From Q1 2026, the oil and gas prices are based on the company's long-term price assumptions. Long-term oil and gas price assumptions are unchanged from previous quarter.
The nominal oil prices applied in the impairment test are as follows:
| Year | USD/BOE |
|---|---|
| 2023 | 83.9 |
| 2024 | 79.0 |
| 2025 | 75.0 |
| From 2026 (in real 2022 terms) | 65.0 |
The nominal gas prices applied in the impairment test are as follows:
| Year | GBP/therm |
|---|---|
| 2023 | 2.05 |
| 2024 | 1.97 |
| 2025 | 1.59 |
| From 2026 (in real 2022 terms) | 0.67 |
Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable remaining reserves.
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 8.7 percent. This represents a change from 8.2 percent applied in the previous quarter, and a change from 7.6 percent applied at yearend 2021.
| Currency rates | |
|---|---|
| Year | USD/NOK |
| 2023 | 9.64 |
| 2024 | 9.54 |
| 2025 | 9.49 |
| From 2026 | 8.00 |
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 recognized 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 impairments have been recognized in Q4 2022:
| Edvard Grieg & | |
|---|---|
| Cash-generating unit (USD 1 000) Wisting |
Ivar Aasen |
| Net carrying value 625 793 |
4 673 989 |
| Recoverable amount 109 885 |
4 532 497 |
| Foreign currency translation 17 011 |
4 665 |
| Impairment/reversal (-) 498 897 |
136 826 |
| Allocated as follows: | |
| Technical goodwill 240 572 |
136 826 |
| Other intangible assets/license rights 258 325 |
- |
| Tangible fixed assets - |
- |
The main reason for the Wisting impairment is related to the postponed planned investment decision, with new profiles and where less favorable tax rules will apply. The Edvard Grieg & Ivar Aasen CGU impairment is mainly related to decrease in short-term gas prices and currency translation effects of PPA balances in functional currency other than USD.
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.
| Change in impairment after | ||||||
|---|---|---|---|---|---|---|
| Assumption (USD 1 000) | Change | Increase in assumptions | Decrease in assumptions | |||
| Oil and gas price forward period | +/- 50 % | - | 2 093 950 | |||
| Oil and gas price long-term | +/- 20 % | -109 526 | 859 349 | |||
| Production profile (reserves) | +/- 5 % | -27 382 | 297 482 | |||
| Discount rate | +/- 1 % point | 104 438 | -29 544 | |||
| Currency rate USD/NOK1) | +/- 2.0 NOK | -85 150 | 790 605 | |||
| Inflation | +/- 1 % point | -37 435 | 355 663 |
1) The sensitivity does not include the currency impact on recoverable amount as a result of consolidation of entities with functional currency other than USD
Residual goodwill is allocated across all CGUs for impairment testing. The combined recoverable amount exceeds the carrying amount 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 2 160 per tonn (2022 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 2021 real terms. For the sensitivity calculation, a linear development between spot price at year end 2022 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 | 2 223 | - | - | ||
| Skarv | - | - | - | ||
| Ula | - | - | - | ||
| Alvheim | 45 | - | - | ||
| Johan Sverdrup | 75 | - | - | ||
| Edvard Grieg & Ivar Aasen | 601 | - | - | ||
| Yggdrasil | 682 | - | - | ||
| Wisting | 110 | 12 | -189 | ||
| Total | 3 735 | 12 | -189 |
| Oil USD/bbl | Gas USD/mmbtu | |||
|---|---|---|---|---|
| Scenario price ranges | 2030 | 2050 | 2030 | 2050 |
| Net Zero | 35 | 24 | 4.6 | 3.8 |
| Announced Pledges | 64 | 60 | 7.9 | 6.3 |
| Stated Policies | 82 | 95 | 8.5 | 9.2 |
| Property, plant and equipment | Production | Fixtures and | ||
|---|---|---|---|---|
| Assets under | facilities | fittings, office | ||
| (USD 1 000) | development | including wells | machinery | Total |
| Restated book value 31.12.2021 | 1 795 436 | 8 332 297 | 86 705 | 10 214 438 |
| Restated acquisition cost 31.12.2021 | 1 795 436 | 13 403 026 | 256 449 | 15 454 911 |
| Additions | 658 700 | 529 177 | 8 111 | 1 195 988 |
| Impact of change in accounting principle | - | -1 839 919 | - | -1 839 919 |
| Acquisition of Lundin Energy | 933 182 | 6 726 306 | 3 811 | 7 663 300 |
| Disposals/retirement | - | - | - | - |
| Reclassification | -524 217 | 651 761 | 7 273 | 134 816 |
| Foreign currency translation | -84 037 | -538 647 | -322 | -623 006 |
| Acquisition cost 30.09.2022 | 2 779 065 | 18 931 704 | 275 320 | 21 986 090 |
| Restated accumulated depreciation and impairments 31.12.2021 | - | 5 070 729 | 169 744 | 5 240 473 |
| Depreciation | - | 1 043 873 | 30 531 | 1 074 404 |
| Impairment/reversal (-) | - | 385 073 | - | 385 073 |
| Disposals/retirement depreciation | - | - | - | - |
| Foreign currency translation | - | -20 342 | -45 | -20 387 |
| Accumulated depreciation and impairments 30.09.2022 | - | 6 479 333 | 200 230 | 6 679 563 |
| Book value 30.09.2022 | 2 779 065 | 12 452 371 | 75 091 | 15 306 528 |
| Acquisition cost 30.09.2022 | 2 779 065 | 18 931 704 | 275 320 | 21 986 090 |
| Additions | 377 327 | 107 642 | 10 104 | 495 073 |
| Disposals/retirement | - | - | 17 483 | 17 483 |
| Reclassification1) | -1 608 378 | 1 614 878 | - | 6 500 |
| Foreign currency translation | 66 163 | 646 793 | 365 | 713 320 |
| Acquisition cost 31.12.2022 | 1 614 177 | 21 301 017 | 268 306 | 23 183 501 |
| Accumulated depreciation and impairments 30.09.2022 | - | 6 479 333 | 200 230 | 6 679 563 |
| Depreciation | - | 591 428 | 9 413 | 600 841 |
| Impairment/reversal (-) | - | 489 | - | 489 |
| Disposals/retirement depreciation | - | - | -17 483 | -17 483 |
| Foreign currency translation Accumulated depreciation and impairments 31.12.2022 |
- - |
33 359 7 104 610 |
72 192 232 |
33 431 7 296 841 |
| Book value 31.12.2022 | 1 614 177 | 14 196 407 | 76 075 | 15 886 659 |
1) The reclassification is mainly related to the Johans Sverdrup phase 2 development project, which entered into production phase during Q4 2022
See note 1 for a description of change in accounting principle related to abandonment provisions.
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. Removal and decommissioning costs are included as production facilities or fields under development.
| Vessels and Drilling Rigs Boats Office Other (USD 1 000) Total Book value 31.12.2021 12 313 50 740 29 350 1 774 94 177 Acquisition cost 31.12.2021 18 412 57 436 52 416 2 303 130 567 Additions 22 542 - 7 046 - 29 588 Acquisition of Lundin Energy 11 069 - 23 688 - 34 757 Allocated to abandonment activity - -358 - - -358 Disposals/retirement - - - - - Reclassification -22 289 -1 769 - - -24 058 Foreign currency translation -710 - -1 952 - -2 661 Acquisition cost 30.09.2022 29 024 55 309 81 198 2 303 167 834 Accumulated depreciation and impairments 31.12.2021 6 099 6 696 23 066 530 36 390 Depreciation 1 231 2 860 8 209 132 12 432 Impairment/reversal (-) - - - - - Disposals/retirement depreciation - - - - - Foreign currency translation - - -92 - -92 Accumulated depreciation and impairments 30.09.2022 7 330 9 556 31 182 662 48 730 Book value 30.09.2022 21 694 45 753 50 016 1 641 119 104 Acquisition cost 30.09.2022 29 024 55 309 81 198 2 303 167 834 Additions - - 4 177 - 4 177 Allocated to abandonment activity - -8 - - -8 Disposals/retirement 6 099 10 8 086 - 14 194 Reclassification1) -5 783 -568 - - -6 351 Foreign currency translation 707 - - - 707 Acquisition cost 31.12.2022 17 850 54 723 77 290 2 303 152 166 Accumulated depreciation and impairments 30.09.2022 7 330 9 556 31 182 662 48 730 Depreciation 1 544 1 078 3 617 44 6 284 Impairment/reversal (-) - - - - - Disposals/retirement depreciation -6 099 - -8 086 - -14 185 Foreign currency translation - - - - - Accumulated depreciation and impairments 31.12.2022 2 776 10 634 26 714 706 40 829 Book value 31.12.2022 15 075 44 089 50 576 1 597 111 336 |
Right-of-use assets | |||
|---|---|---|---|---|
1) 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.
| Capitalized | |||||
|---|---|---|---|---|---|
| exploration | Other intangible assets | ||||
| (USD 1 000) | Goodwill | expenditures | Depreciated | Not depreciated | Total |
| Book value 31.12.2021 | 1 647 436 | 256 535 | 641 967 | 765 584 | 1 407 551 |
| Acquisition cost 31.12.2021 | 2 726 583 | 444 232 | 1 480 063 | 888 922 | 2 368 985 |
| Additions | -14 405 | 213 977 | - | - | - |
| Acquisition of Lundin Energy | 12 598 299 | - | 25 653 | 1 256 577 | 1 282 230 |
| Disposals/retirement/expensed dry wells | - | 126 055 | - | - | - |
| Reclassification | - | -110 758 | 122 661 | -122 661 | - |
| Foreign currency translation | -1 037 926 | -243 | -2 113 | -103 523 | -105 636 |
| Acquisition cost 30.09.2022 | 14 272 550 | 421 152 | 1 626 264 | 1 919 315 | 3 545 579 |
| Accumulated depreciation and impairments 31.12.2021 | 1 079 146 | 187 696 | 838 096 | 123 338 | 961 434 |
| Depreciation | - | - | 57 611 | - | 57 611 |
| Impairment/reversal (-) | - | 10 869 | - | - | - |
| Disposals/retirement depreciation | - | - | - | - | - |
| Foreign currency translation | - | - | -508 | - | -508 |
| Accumulated depreciation and impairments 30.09.2022 | 1 079 146 | 198 565 | 895 199 | 123 338 | 1 018 537 |
| Book value 30.09.2022 | 13 193 404 | 222 587 | 731 065 | 1 795 977 | 2 527 042 |
| Acquisition cost 30.09.2022 | 14 272 550 | 421 152 | 1 626 264 | 1 919 315 | 3 545 579 |
| Additions1) | -41 042 | 37 788 | 743 | - | 743 |
| Disposals/retirement/expensed dry wells | - | 9 745 | - | - | - |
| Reclassification2) | - | -149 | 732 361 | -732 361 | - |
| Foreign currency translation | 1 172 890 | 1 255 | 2 388 | 115 862 | 118 250 |
| Acquisition cost 31.12.2022 | 15 404 399 | 450 301 | 2 361 756 | 1 302 816 | 3 664 572 |
| Accumulated depreciation and impairments 30.09.2022 | 1 079 146 | 198 565 | 895 199 | 123 338 | 1 018 537 |
| Depreciation | - | - | 34 100 | - | 34 100 |
| Impairment/reversal (-) | 377 398 | - | - | 258 325 | 258 325 |
| Disposals/retirement depreciation | - | - | - | - | - |
| Foreign currency translation | 12 868 | - | 448 | 8 808 | 9 256 |
| Accumulated depreciation and impairments 31.12.2022 | 1 469 413 | 198 565 | 929 747 | 390 471 | 1 320 218 |
| Book value 31.12.2022 | 13 934 986 | 251 736 | 1 432 009 | 912 345 | 2 344 354 |
1) The negative additions in the fourth quarter is mainly related to change in deferred tax in the purchase price allocation as described in note 2
2) The reclassification is mainly related to the Johans Sverdrup phase 2 development project, which entered into production phase during Q4 2022
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. | ||
| Restated | Restated | Restated | Restated | ||
| Depreciation in the income statement (USD 1 000) | 2022 | 2022 | 2021 | 2022 | 2021 |
| Depreciation of tangible fixed assets | 600 841 | 561 878 | 263 773 | 1 675 245 | 1 105 014 |
| Depreciation of right-of-use assets | 6 284 | 5 917 | 2 540 | 18 716 | 10 416 |
| Depreciation of other intangible assets | 34 100 | 26 100 | 17 428 | 91 711 | 77 459 |
| Total depreciation in the income statement | 641 225 | 593 895 | 283 741 | 1 785 672 | 1 192 889 |
| Impairment in the income statement (USD 1 000) | |||||
| Impairment/reversal of tangible fixed assets | 489 | 55 128 | 88 168 | 385 562 | 184 664 |
| Impairment/reversal of other intangible assets | 258 325 | - | -50 741 | 258 325 | 36 301 |
| Impairment/reversal of capitalized exploration expenditures | - | - | 41 589 | 10 869 | 41 589 |
| Impairment of goodwill | 377 398 | - | - | 377 398 | - |
| Total impairment in the income statement | 636 213 | 55 128 | 79 016 | 1 032 154 | 262 554 |
The incremental borrowing rate applied in discounting of the nominal lease debt is between 1.8 percent and 6.9 percent, dependent on the duration of the lease and when it was intially recognized.
| Group | |||
|---|---|---|---|
| 2022 | 2022 | 2021 | |
| (USD 1 000) | Q4 | 01.01.-30.09. | 01.01.-31.12. |
| Lease debt as of beginning of period | 137 507 | 136 213 | 215 760 |
| New lease debt recognized in the period | 4 177 | 29 588 | 5 989 |
| Payments of lease debt1) | -14 427 | -59 641 | -96 173 |
| Interest expense on lease debt | 1 789 | 5 706 | 11 558 |
| Lease debt from acquisition of Lundin Energy | - | 34 757 | - |
| Currency exchange differences | 5 347 | -9 116 | -921 |
| Total lease debt | 134 393 | 137 507 | 136 213 |
| Short-term | 36 298 | 42 310 | 44 378 |
| Long-term | 98 095 | 95 197 | 91 835 |
| 1) Payments of lease debt split by activities (USD 1 000): | |||
| Investments in fixed assets | 7 832 | 39 110 | 50 423 |
| Abandonment activity | 57 | 694 | 31 715 |
| Operating expenditures | 4 540 | 9 337 | 7 499 |
| Exploration expenditures | 178 | 6 044 | 1 858 |
| Other income | 1 820 | 4 454 | 4 678 |
| Total | 14 427 | 59 641 | 96 173 |
| Nominal lease debt maturity breakdown (USD 1 000): | |||
| Within one year | 42 646 | 48 613 | 51 010 |
| Two to five years | 87 179 | 82 714 | 68 602 |
| After five years | 26 403 | 29 556 | 42 837 |
| Total | 156 227 | 160 883 | 162 448 |
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. | ||
| Restated | Restated | Restated | Restated | ||
| (USD 1 000) | 2022 | 2022 | 2021 | 2022 | 2021 |
| Interest income | 13 458 | 5 701 | 1 441 | 25 959 | 2 481 |
| Realized gains on derivatives | 19 325 | 2 564 | 5 524 | 33 466 | 27 392 |
| Change in fair value of derivatives | 571 377 | - | - | 333 674 | - |
| Net currency gains | - | 288 868 | 25 517 | 308 373 | 88 779 |
| Other financial income | 49 | - | 98 774 | - | |
| Total other financial income | 590 702 | 291 481 | 31 041 | 774 287 | 116 171 |
| Interest expenses | 48 093 | 42 964 | 33 221 | 154 019 | 145 651 |
| Interest on lease debt | 1 789 | 1 902 | 2 368 | 7 496 | 11 558 |
| Capitalized interest cost, development projects | -27 206 | -32 831 | -12 555 | -85 612 | -40 136 |
| Amortized loan costs1) | 13 087 | 13 087 | 3 038 | 31 815 | 22 460 |
| Total interest expenses | 35 764 | 25 121 | 26 072 | 107 718 | 139 533 |
| Net currency loss | 337 509 | 124 840 | - | 269 434 | - |
| Realized loss on derivatives | 225 207 | 218 175 | 15 010 | 480 945 | 23 249 |
| Change in fair value of derivatives | - | 65 267 | 4 876 | - | 44 565 |
| Accretion expenses | 40 286 | 36 716 | 16 494 | 119 895 | 61 944 |
| Other financial expenses | 2 651 | 1 142 | 392 | 9 834 | 39 274 |
| Total other financial expenses | 605 653 | 446 140 | 36 772 | 880 109 | 169 032 |
| Net financial items | -37 257 | -174 080 | -30 362 | -187 581 | -189 913 |
1) The figure includes amortization 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. | ||
| Restated | Restated | Restated | Restated | ||
| Tax for the period (USD 1 000) | 2022 | 2022 | 2021 | 2022 | 2021 |
| Current year tax payable/receivable | 2 169 807 | 2 831 715 | 667 609 | 7 162 988 | 1 526 236 |
| Change in current year deferred tax | -111 893 | 116 416 | 137 935 | -12 294 | 530 497 |
| Current and deferred tax related to change in tax system | - | - | - | 13 052 | - |
| Prior period adjustments | 6 420 | 1 257 | 4 720 | 10 164 | 11 122 |
| Tax expense (+)/income (-) | 2 064 333 | 2 949 388 | 810 264 | 7 173 910 | 2 067 855 |
| 2022 | 2022 | 2021 | |
|---|---|---|---|
| Calculated tax payable (-)/tax receivable (+) (USD 1 000) | Q4 | 01.01.-30.09. | 01.01.-31.12. |
| Tax payable/receivable at beginning of period | -5 418 505 | -1 497 291 | -163 352 |
| Current year tax payable/receivable | -2 169 807 | -4 993 182 | -1 526 236 |
| Current year tax payable/receivable related to change in tax system | - | 176 391 | - |
| Net tax payment/refund | 2 955 009 | 2 377 116 | 223 166 |
| Net tax payable related to acquisition of Lundin Energy | - | -2 181 017 | - |
| Prior period adjustments and change in estimate of uncertain tax positions | 6 773 | 23 073 | -57 165 |
| Currency movements of tax payable/receivable | -225 233 | 471 079 | 26 297 |
| Current tax charged to other comprehensive income (foreign currency translation) | -232 380 | 205 326 | - |
| Net tax payable (-)/receivable (+) | -5 084 142 | -5 418 505 | -1 497 291 |
| Group | |||
|---|---|---|---|
| 2022 | 2022 | 2021 | |
| Restated | Restated | ||
| Deferred tax liability (-)/asset (+) (USD 1 000) | Q4 | 01.01.-30.09. | 01.01.-31.12. |
| Deferred tax liability/asset at beginning of period | -8 971 538 | -3 291 287 | -2 764 761 |
| Change in current year deferred tax | 111 893 | -99 598 | -530 497 |
| Change in current year deferred tax related to change in tax system | - | -189 444 | - |
| Deferred tax related to acquisition of Lundin Energy | 42 309 | -5 844 226 | - |
| Prior period adjustments | -340 | -27 585 | 3 971 |
| Deferred tax charged to other comprehensive income (mainly foreign currency translation) | -541 470 | 480 602 | - |
| Net deferred tax liability (-)/asset (+) | -9 359 146 | -8 971 538 | -3 291 287 |
| Group | ||||||
|---|---|---|---|---|---|---|
| Q4 | Q3 Q4 |
01.01.-31.12. | ||||
| Restated | Restated | Restated | Restated | |||
| Reconciliation of tax expense (USD 1 000) | 2022 | 2022 | 2021 | 2022 | 2021 | |
| 78 % tax rate on profit/loss before tax | 1 697 906 | 2 895 993 | 909 034 | 6 846 295 | 2 258 703 | |
| Tax effect of uplift | -42 638 | -47 335 | -79 880 | -161 708 | -270 454 | |
| Permanent difference on impairment | 294 386 | - | -39 691 | 294 386 | -36 862 | |
| Foreign currency translation of monetary items other than USD | 125 443 | -133 549 | -19 768 | -170 564 | -68 575 | |
| Foreign currency translation of monetary items other than NOK | 303 967 | -118 966 | 14 950 | 129 563 | 16 508 | |
| Tax effect of financial and other 22 % items | -247 255 | 233 821 | 6 373 | 60 126 | 97 881 | |
| Currency movements of tax balances1) | -90 300 | 81 463 | 8 441 | 138 929 | 43 332 | |
| Other permanent differences, prior period adjustments and change in estimate of uncertain tax positions |
22 826 | 37 960 | 10 805 | 36 883 | 27 321 | |
| Tax expense (+)/income (-) | 2 064 333 | 2 949 388 | 810 264 | 7 173 910 | 2 067 855 |
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).
See note 1 for a description of change in accounting principles impacting deferred tax.
Changes to the Petroleum Tax Act were enacted in June 2022 with effect from 1 January 2022. The combined tax rate of 78% is maintained, but according to the new rules the special petroleum tax (56%) is converted into a cash based tax. When calculating the special petroleum tax for 2022 and onwards, companies can make immediate deductions for expenses incurred, but with no right for uplift. In addition the corporate tax (22%) is deductible in the special tax base (56%). In order to maintain the overall tax rate of 78%, the special tax rate is increased to 71.8% [56% / (1-22%)]. During the fourth quarter, the National Budget 2023 was approved. This includes a change in the temporary tax regime uplift from 17.69 to 12.4 percent. Such change will increase the tax charge for the group from 2023 and onwards.
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 1 000) | 31.12.2022 | 30.09.2022 | 31.12.2021 | |
| Prepayments | 123 980 | 66 437 | 45 429 | |
| VAT receivable | 12 406 | 9 391 | 13 354 | |
| Underlift of petroleum | 53 630 | 47 923 | 36 944 | |
| Accrued income from sale of petroleum products | 335 505 | 759 569 | 290 254 | |
| Other receivables, mainly balances with license partners | 160 715 | 163 902 | 114 172 | |
| Total other short-term receivables | 686 237 | 1 047 222 | 500 154 |
The item 'Cash and cash equivalents' consists of bank accounts and short-term investments that constitute parts of the group's available liquidity.
| Group | ||||
|---|---|---|---|---|
| Breakdown of cash and cash equivalents (USD 1 000) | 31.12.2022 | 30.09.2022 | 31.12.2021 | |
| Bank deposits | 2 756 012 | 3 041 997 | 1 970 906 | |
| Cash and cash equivalents | 2 756 012 | 3 041 997 | 1 970 906 | |
| Unused RCF facility | 3 400 000 | 3 400 000 | 3 400 000 |
The RCF is undrawn as at 31 December 2022 and the remaining unamortized fees of USD 11.0 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 with an extension option for one year until 2026, and (2) Liquidity Facility with a committed amount of USD 2.0 billion until 2025 and USD 1.65 billion until 2026.
The interest rate for USD is Term SOFR plus a margin of 1.00 percent for the Working Capital Facility and 0.75 percent for the Liquidity Facility. Drawing under the Liquidity Facility will add a utilization fee. A commitment fee of 35 percent of applicable margin is paid on the undrawn part of the total facility. The financial covenants are as follows:
The financial covenants are calculated on a 12 months rolling basis. As at 31 December 2022 the Leverage Ratio is 0.21 and Interest Coverage Ratio is 73.6 (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 2022, the group's estimates show that the financial covenants will continue to comply with the covenants by a substantial margin.
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.
| Group | |||
|---|---|---|---|
| (USD 1 000) | 31.12.2022 | 30.09.2022 | 31.12.2021 |
| Unrealized gain currency contracts | 2 907 | - | 1 375 |
| Long-term derivatives included in assets | 2 907 | - | 1 375 |
| Unrealized gain commodity derivatives | - | 618 | - |
| Unrealized gain currency contracts | 153 096 | 1 511 | 18 577 |
| Short-term derivatives included in assets | 153 096 | 2 129 | 18 577 |
| Total derivatives included in assets | 156 003 | 2 129 | 19 952 |
| Fair value of option related to sale of Cognite | 15 995 | 15 995 | - |
| Unrealized losses currency contracts | 986 | 27 953 | 2 370 |
| Long-term derivatives included in liabilities | 16 981 | 43 948 | 2 370 |
| Unrealized losses commodity derivatives | - | 5 019 | 8 989 |
| Unrealized losses currency contracts | 34 924 | 424 842 | 26 094 |
| Short-term derivatives included in liabilities | 34 924 | 429 861 | 35 082 |
| Total derivatives included in liabilities | 51 905 | 473 809 | 37 452 |
The group uses various types of financial hedging instruments. Commodity derivatives are used to hedge the price risk of oil and gas, foreign exchange derivatives to hedge the group's currency exposure, mainly in NOK, EUR and GBP, and interest rate derivatives to hedge volatility in interest rates.
The derivative portfolio is revalued on a mark to market basis, with changes in value recognized in the income statement. In Q1 2022 the company entered into certain natural gas futures contracts to hedge its gas price exposure. The company granted a put option in relation to the sale of shares in Cognite in Q1 2022. Except for these new elements, 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 2021. 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 2022, the company has foreign exchange contracts to secure USD value of NOK cashflows for future tax payments and capital expenditure.
| Group | ||||
|---|---|---|---|---|
| Breakdown of other current liabilities (USD 1 000) | 31.12.2022 | 30.09.2022 | 31.12.2021 | |
| Balances with license partners | 43 132 | 43 497 | 48 456 | |
| Share of other current liabilities in licenses | 460 783 | 447 578 | 311 694 | |
| Overlift of petroleum | 30 922 | 26 421 | 40 044 | |
| Payroll liabilities, accrued interest and other provisions | 272 276 | 181 533 | 224 173 | |
| Total other current liabilities | 807 113 | 699 029 | 624 366 |
| Group | ||||
|---|---|---|---|---|
| Senior unsecured bonds (USD 1 000) | Maturity | 31.12.2022 | 30.09.2022 | 31.12.2021 |
| AKERBP – USD Senior Notes 3.000% (20/25) | Jan 2025 | 498 172 | 497 953 | 497 295 |
| AKERBP – USD Senior Notes 2.875% (20/26) | Jan 2026 | 497 813 | 497 635 | 497 103 |
| AKERBP - USD Senior Notes 2.000% (21/26)1) | July 2026 | 907 387 | 900 926 | - |
| AKERBP – EUR Senior Notes 1.125% (21/29) | May 2029 | 795 304 | 726 273 | 843 995 |
| AKERBP – USD Senior Notes 3.750% (20/30) | Jan 2030 | 994 411 | 994 213 | 993 622 |
| AKERBP – USD Senior Notes 4.000% (20/31) | Jan 2031 | 745 302 | 745 156 | 744 720 |
| AKERBP - USD Senior Notes 3.100% (21/31)1) | July 2031 | 840 776 | 836 138 | - |
| Long-term bonds - book value | 5 279 164 | 5 198 294 | 3 576 735 | |
| Long-term bonds - fair value | 4 829 678 | 4 643 293 | 3 752 778 |
1) These bonds have a nominal value of USD 1 billion and were recognized at fair value in connection with the Lundin Energy transaction at 30 June 2022. The difference between fair value and nominal value is linearly amortized over the lifetime of the bonds (see note 9).
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 | |||
|---|---|---|---|
| 2022 | 2022 | 2021 | |
| Restated | Restated | ||
| (USD 1 000) | Q4 | 01.01.-30.09. | 01.01.-31.12. |
| Provisions as of beginning of period | 4 184 516 | 5 172 354 | 4 897 275 |
| Incurred removal cost | -19 304 | -59 932 | -185 973 |
| Accretion expense | 40 286 | 79 609 | 61 944 |
| Abandonment liabilities from acquisition of Lundin Energy | 745 900 | - | |
| Foreign currency translation | 49 788 | -43 096 | - |
| Impact of changes to discount rate | -140 915 | -1 736 003 | -382 458 |
| Change in estimates and provisions relating to new drilling and installations | 51 227 | 25 684 | 781 566 |
| Total provision for abandonment liabilities | 4 165 598 | 4 184 516 | 5 172 354 |
| Short-term | 115 202 | 107 613 | 100 863 |
| Long-term | 4 050 396 | 4 076 903 | 5 071 491 |
Reference is made to note 1 for a description of change in the accounting principle for abandonment provision. Following the change in accounting principle, the nominal pre tax discount rate (risk free) at end of Q4 is between 3.9 percent and 4.7 percent, depending on the timing of the expected cashflows.The corresponding range at end of Q3 was 3.8 to 4.3 percent. while it was between 0.4 and 1.9 at year end 2021. The calculations assume an inflation rate of 2.0 percent for all applicable periods.
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.
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.
| Total number of licenses | 31.12.2022 | 30.09.2022 |
|---|---|---|
| Aker BP as operator | 121 | 121 |
| Aker BP as partner | 93 | 94 |
| Changes in production licenses in which Aker BP is the operator: | Changes in production licenses in which Aker BP is a partner: | ||||||
|---|---|---|---|---|---|---|---|
| License: | 31.12.2022 | 30.09.2022 License: | 31.12.2022 | 30.09.2022 | |||
| PL 127C2) | 68.083% | 88.083 % PL 006F1) | 0.000% | 15.000 % | |||
| PL 127DS3) | 88.083% | 0.000 % PL 211CS2) | 15.000% | 0.000 % | |||
| PL 822S4) | 87.700% | 60.000 % PL 5331) | 0.000% | 35.000 % | |||
| PL 9324) | 60.000% | 100.000 % PL 9434) | 20.000% | 10.000 % | |||
| PL 9412) | 70.000% | 80.000 % | |||||
| PL 941B2) | 70.000% | 80.000 % | |||||
| PL 5331) | 0.000% | 40.000 % | |||||
| Total | 6 | 6 Total | 2 | 3 |
1) Relinquished license or Aker BP has withdrawn from the license
2) Transaction with Winthershall Dea
3) Carve-out of PL 127C
4) License transaction Q4
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 capitalized exploration wells less dry well expenses1)
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 cost basd on produced volumes, divided by number of barrels of oil equivalents produced in the corresponding period (see note 4)
1) Includes payments of lease debt as disclosed in note 8.
| Q4 | Q3 | Q4 | 01.01.-31.12. | 01.01.-31.12. | ||
|---|---|---|---|---|---|---|
| Restated | Restated | Restated | Restated | |||
| (USD 1 000) | Note | 2022 | 2022 | 2021 | 2022 | 2021 |
| Abandonment spend | ||||||
| Payment for removal and decommissioning of oil fields | 19 296 | 7 329 | 16 123 | 78 870 | 172 512 | |
| Payments of lease debt (abandonment activity) | 8 | 57 | 35 | 203 | 751 | 31 715 |
| Abandonment spend | 19 353 | 7 364 | 16 326 | 79 621 | 204 227 | |
| Depreciation per boe | ||||||
| Depreciation | 7 | 641 225 | 593 895 | 283 741 | 1 785 672 | 1 192 889 |
| Total produced volumes (boe 1 000) | 4 | 39 741 | 37 879 | 19 042 | 112 853 | 76 439 |
| Depreciation per boe | 16.1 | 15.7 | 14.9 | 15.8 | 15.6 | |
| Dividend per share | ||||||
| Paid dividend | 331 812 | 331 812 | 150 000 | 1 005 731 | 487 500 | |
| Number of shares outstanding | 631 586 | 631 432 | 359 788 | 496 765 | 359 643 | |
| Dividend per share | 0.53 | 0.53 | 0.42 | 2.02 | 1.36 | |
| Capex | ||||||
| Disbursements on investments in fixed assets (excluding capitalized interest) | 570 227 | 403 742 | 421 862 | 1 580 045 | 1 376 879 | |
| Payments of lease debt (investments in fixed assets) | 8 | 7 832 | 7 623 | 20 150 | 46 942 | 50 423 |
| CAPEX | 578 059 | 411 365 | 442 012 | 1 626 987 | 1 427 302 | |
| EBITDA | ||||||
| Total income | 3 | 3 825 929 | 4 866 332 | 1 849 080 | 13 009 898 | 5 668 747 |
| Production costs | 4 | -286 424 | -235 921 | -202 374 | -932 870 | -745 313 |
| Exploration expenses | 5 | -32 094 | -85 275 | -82 620 | -242 193 | -353 034 |
| Other operating expenses | -16 026 | -9 412 | -5 536 | -52 577 | -29 261 | |
| EBITDA | 3 491 385 | 4 535 723 | 1 558 550 | 11 782 258 | 4 541 139 | |
| EBITDAX | ||||||
| Total income | 3 | 3 825 929 | 4 866 332 | 1 849 080 | 13 009 898 | 5 668 747 |
| Production costs | 4 | -286 424 | -235 921 | -202 374 | -932 870 | -745 313 |
| Other operating expenses | -16 026 | -9 412 | -5 536 | -52 577 | -29 261 | |
| EBITDAX | 3 523 479 | 4 620 998 | 1 641 170 | 12 024 451 | 4 894 173 | |
| Equity ratio | ||||||
| Total equity | 12 427 506 | 11 320 337 | 2 196 814 | 12 427 506 | 2 196 814 | |
| Total assets | 37 561 780 | 36 613 468 | 16 708 025 | 37 561 780 | 16 708 025 | |
| Equity ratio | 33% | 31% | 13% | 33% | 13% | |
| Exploration spend | ||||||
| Disbursements on investments in capitalized exploration expenditures | 37 788 | 89 163 | 45 656 | 251 764 | 177 464 | |
| Exploration expenses | 5 | 32 094 | 85 275 | 82 620 | 242 193 | 353 034 |
| Dry well | 5 | -9 745 | -52 936 | -33 243 | -135 800 | -98 827 |
| Payments of lease debt (exploration expenditures) | 8 | 178 | 114 | 227 | 6 222 | 1 858 |
| Exploration spend | 60 315 | 121 616 | 95 260 | 364 380 | 433 529 |
| Q4 | Q3 | Q4 | 01.01.-31.12. | 01.01.-31.12. | ||
|---|---|---|---|---|---|---|
| (USD 1 000) | Note | 2022 | 2022 | 2021 | 2022 | 2021 |
| Interest coverage ratio | ||||||
| Twelve months rolling EBITDA | 11 782 258 | 9 849 423 | 4 541 139 | 11 782 258 | 4 541 139 | |
| Twelve months rolling EBITDA, impacts from IFRS 16 | 8 | -20 835 | -17 508 | -14 035 | -20 835 | -14 035 |
| Twelve months rolling EBITDA, excluding impacts from IFRS 16 | 11 761 424 | 9 831 915 | 4 527 104 | 11 761 424 | 4 527 104 | |
| Twelve months rolling interest expenses | 9 | 154 019 | 139 147 | 145 651 | 154 019 | 145 651 |
| Twelve months rolling amortized loan cost | 9 | 31 815 | 21 766 | 22 460 | 31 815 | 22 460 |
| Twelve months rolling interest income | 9 | 25 959 | 13 942 | 2 481 | 25 959 | 2 481 |
| Net interest expenses | 159 876 | 146 971 | 165 630 | 159 876 | 165 630 | |
| Interest coverage ratio1) | 73.6 | 66.9 | 27.3 | 73.6 | 27.3 | |
| Leverage ratio | ||||||
| Long-term bonds | 15 | 5 279 164 | 5 198 294 | 3 576 735 | 5 279 164 | 3 576 735 |
| Cash and cash equivalents | 12 | 2 756 012 | 3 041 997 | 1 970 906 | 2 756 012 | 1 970 906 |
| Net interest-bearing debt excluding lease debt | 2 523 151 | 2 156 298 | 1 605 829 | 2 523 151 | 1 605 829 | |
| Twelve months rolling EBITDAX | 12 024 451 | 10 142 142 | 4 894 173 | 12 024 451 | 4 894 173 | |
| Twelve months rolling EBITDAX, impacts from IFRS 16 | 8 | -20 153 | -16 776 | -12 177 | -20 153 | -12 177 |
| Twelve months rolling EBITDAX, excluding impacts from IFRS 16 | 12 004 299 | 10 125 366 | 4 881 996 | 12 004 299 | 4 881 996 | |
| Leverage ratio1) | 0.21 | 0.21 | 0.33 | 0.21 | 0.33 | |
| Net interest-bearing debt | ||||||
| Long-term bonds | 15 | 5 279 164 | 5 198 294 | 3 576 735 | 5 279 164 | 3 576 735 |
| Long-term lease debt | 8 | 98 095 | 95 197 | 91 835 | 98 095 | 91 835 |
| Short-term lease debt | 8 | 36 298 | 42 310 | 44 378 | 36 298 | 44 378 |
| Cash and cash equivalents | 12 | 2 756 012 | 3 041 997 | 1 970 906 | 2 756 012 | 1 970 906 |
| Net interest-bearing debt | 2 657 545 | 2 293 805 | 1 742 042 | 2 657 545 | 1 742 042 |
1) These ratios are calculated based on Aker BP group figures only, with no proforma adjustments for the Lundin Energy transaction. Based on estimates of historical financial metrics of Lundin Energy, combined interest coverage ratio and leverage ratio are estimated to 80 and 0.2 respectively.
Operating profit/loss see Income Statement
Production cost per boe see note 4
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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