Quarterly Report • Oct 26, 2022
Quarterly Report
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In its first full quarter after the Lundin acquisition, Aker BP delivered operating profit of USD 3,959 million and net profit of USD 783 million.
"Third quarter 2022 was the first quarter of the enlarged Aker BP, following the completion of the Lundin transaction at the end of June. During the quarter we have successfully integrated the two organisations. At the same time, we maintained momentum in our operations and project development activities. Aker BP is well underway towards our goal of becoming an industry-leading low cost, low emissions company, positioned to deliver profitable growth into the next decade."
"Aker BP has a unique resource base, and over the last couple of years we have been working systematically to mature field development projects with combined resources of around 900 mmboe net to Aker BP. This work is now nearing completion, and we are currently aiming to submit PDOs for these projects by the end of 2022, and hence qualify for the temporary tax rules which were introduced in 2020."
"The world is characterised by geopolitical instability, inflation and increasing interest rates, supply chain constraints and high volatility in energy and commodity prices. In addition, the Norwegian government has proposed a tightening of the temporary tax rules. Aker BP will take all these factors into account before making final investment decisions."
Forward-looking statements in this report reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future and may not be within our control. All figures are presented in USD unless otherwise stated, and figures in brackets apply to the previous quarter.
| UNIT | Q3 2022 | Q2 2022 | Q3 2021 | |
|---|---|---|---|---|
| INCOME STATEMENT | ||||
| Total income | USD million | 4 866 | 2 026 | 1 563 |
| EBITDA | USD million | 4 536 | 1 749 | 1 250 |
| Net profit/loss | USD million | 783 | 188 | 206 |
| Earnings per share (EPS) | USD | 1.24 | 0.52 | 0.57 |
| OTHER FINANCIAL KEY FIGURES | ||||
| Net interest-bearing debt | USD million | 2 294 | 3 835 | 2 332 |
| Leverage ratio | 0.21* | 0.54* | 0.56 | |
| Dividend per share | USD | 0.53 | 0.48 | 0.31 |
| PRODUCTION AND SALES | ||||
| Net petroleum production | mboepd | 411.7 | 181.3 | 210.0 |
| Over/underlift | mboepd | (5.0) | (8.6) | 14.7 |
| Net sold volume | mboepd | 406.7 | 172.6 | 224.8 |
| - Liquids | mboepd | 342.2 | 127.5 | 183.6 |
| - Natural gas | mboepd | 64.5 | 45.1 | 41.2 |
| REALISED PRICES | ||||
| Liquids | USD/boe | 101.1 | 117.5 | 71.5 |
| Natural gas | USD/boe | 280.9 | 152.6 | 91.3 |
| AVERAGE EXCHANGE RATES | ||||
| USDNOK | 9.99 | 9.43 | 8.77 | |
| EURUSD | 1.02 | 1.06 | 1.18 |
*The ratio is calculated based on Aker BP group figures only, with no proforma adjustment for the Lundin transaction
| (USD MILLION) | Q3 2022 | Q2 2022 | Q3 2021 | 2022 YTD | 2021 YTD |
|---|---|---|---|---|---|
| Total income | 4 866 | 2 026 | 1 563 | 9 184 | 3 820 |
| EBITDA | 4 536 | 1 749 | 1 250 | 8 291 | 2 983 |
| EBIT | 3 959 | 1 128 | 849 | 6 862 | 2 054 |
| Pre-tax profit | 3 782 | 1 066 | 802 | 6 685 | 1 855 |
| Net profit/loss | 783 | 188 | 206 | 1 508 | 487 |
| EPS (USD) | 1.24 | 0.52 | 0.57 | 3.34 | 1.35 |
The income statement for the third quarter represents the first period which includes activity from the acquired Lundin assets as the transaction was completed on 30 June 2022. Thus, prior quarters are not directly comparable.
Total income in the third quarter amounted to USD 4,866 (2,026) million. The increase compared to the previous quarter was driven by production contributions from the Lundin transaction, coupled with higher average realised prices. The realised liquids price decreased by 14 percent to USD 101.1 (117.5) per barrel. The decrease in liquids price was however more than offset by average realised natural gas price of USD 280.9 (152.6) per boe. Sold volumes were 406.7 (172.6) mboepd in the quarter, following an underlift of 5.0 mboepd. Other income amounted to USD 15 (35) million.
Production cost for the oil and gas sold in the quarter amounted to USD 236 (190) million, with the increase quarter on quarter owing to increased production volumes. The average production cost per barrel produced was USD 7.3 (12.0), with the decrease caused by changes to the production mix following completion of the Lundin transaction, and higher production efficiency compared to the previous quarter. See note 4 for further details on production costs.
Exploration expenses amounted to USD 85 (67) million, of which dry well expenses totalling 53 (34) million related to the Barlindåsen, Lamba and Poseidon prospects were the main drivers. The increase was partly offset by lower seismic costs of USD 10 (19) million.
Depreciation amounted to USD 522 (199) million, corresponding to USD 13.8 (12.1) per barrel of oil equivalent. Impairments amounted to USD 55 (422) million and was related to the Ula area after further review of the cost and production profiles following the acceleration of the expected shut-down from 2032 to 2028. Other operating expenses amounted to USD 9 (20) million.
Operating profit was USD 3,959 (1,128) million for the third quarter. Net financial expenses amounted to USD 177 (62) million and was negatively impacted by currency effects (mainly the strengthening of USD against NOK). For more details, see note 9.
Profit before taxes amounted to USD 3,782 (1,066) million. Tax expense was USD 2,998 (878) million. The effective tax rate was 79 (82) percent.
This resulted in a net profit for the third quarter 2022 of USD 783 (188) 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 third quarter of USD 1,013 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 June and 30 September 2022. The company is in the process of merging the Lundin entities into Aker BP ASA and hence revert to USD as the single functional currency.
| (USD MILLION) | 30.09.2022 | 30.06.2022 | 31.12.2021 | 30.09.2021 |
|---|---|---|---|---|
| Goodwill | 13 193 | 14 246 | 1 647 | 1 647 |
| Property, plant and equipment (PP&E) | 14 865 | 15 988 | 7 976 | 7 667 |
| Other non-current assets | 3 057 | 3 181 | 1 863 | 1 993 |
| Cash and equivalent | 3 042 | 2 154 | 1 971 | 1 421 |
| Other current assets | 2 015 | 1 581 | 1 012 | 854 |
| Total assets | 36 172 | 37 149 | 14 470 | 13 582 |
| Equity | 11 483 | 12 061 | 2 342 | 2 128 |
| Bank and bond debt | 5 198 | 5 834 | 3 577 | 3 595 |
| Other long-term liabilities | 12 667 | 13 456 | 6 074 | 5 877 |
| Tax payable | 5 419 | 4 253 | 1 497 | 990 |
| Other current liabilities | 1 406 | 1 545 | 980 | 991 |
| Total equity and liabilities | 36 172 | 37 149 | 14 470 | 13 582 |
| Net interest-bearing debt | 2 294 | 3 835 | 1 742 | 2 332 |
| Leverage ratio | 0.21* | 0.54* | 0.33 | 0.56 |
*The ratio is calculated based on Aker BP group figures only, with no proforma adjustment for the Lundin transaction
At the end of the third quarter 2022, total assets amounted to USD 36.2 (37.1) billion, of which non-current assets were USD 31.1 (33.4) 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 strengthening of USD against NOK. This is the main reason for the decrease of goodwill and PP&E in the third quarter.
Equity amounted to USD 11.5 (12.0) billion at the end of the quarter, corresponding to an equity ratio of 32 (32) percent.
Bank and bond debt totalled USD 5,198 (5,834) million. This was entirely made up of bond debt as the company's bank
facilities were not drawn. Other long-term liabilities amounted to USD 12.7 (13.5) billion.
Tax payable increased by USD 1,166 million to 5,419 (4,253) million. The increase is caused by high profit before tax, and that only one tax instalment has been paid during the quarter.
At the end of the third quarter 2022, the company had total available liquidity of USD 6.4 (4.9) billion, comprising of USD 3.0 (2.2) billion in cash and cash equivalents, USD 3.4 (3.4) billion in undrawn credit facilities, while bank debt was zero (USD 0.6 billion).
| (USD MILLION) | Q3 2022 | Q2 2022 | Q3 2021 | 2022 YTD | 2021 YTD |
|---|---|---|---|---|---|
| Cash flow from operations | 2 361 | 1 187 | 1 063 | 4 923 | 3 071 |
| Cash flow from investments | -500 | -1 626 | -432 | -2 408 | -1 243 |
| Cash flow from financing | -1 041 | -210 | -184 | -1 499 | -943 |
| Net change in cash & cash equivalents | 820 | -649 | 447 | 1 016 | 885 |
| Cash and cash equivalents | 3 042 | 2 154 | 1 421 | 3 042 | 1 421 |
Net cash flow from operating activities was USD 2,361 (1,187) million in the quarter. Taxes paid amounted to USD 1,241 million. The cash flow from operations was negatively impacted by higher receivables and significant unrealized currency gains on NOK nominated payables, such as tax.
Net cash used for investment activities was USD 500 (1 626) million, of which investments in fixed assets amounted to USD 404 (271) million for the quarter. Investments in capitalised
Net cash outflow from financing activities was USD 1,041 million, compared to an outflow of USD 210 million in the previous quarter. The main items were dividend disbursements of USD 332 (171) million and USD 600 (0) million for repayment of a term loan transferred from Lundin.
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 company's exposure to
The following table shows the company's commodity derivatives exposure as of 30 September 2022:
| OIL PUT OPTIONS | Q4 2022 |
|---|---|
| Share of oil production covered (after tax) | 31 % |
| Average strike (USD/bbl) | 45 |
| Average premium (USD/bbl) | 1.6 |
| NATURAL GAS FUTURES | Q4 2022 |
|---|---|
| Share of gas production covered (after tax) | 6 % |
| Average price (EUR/MWh) | 180 |
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 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 will be merged into Aker BP ASA as soon as practically possible. The Dutch entities have been either liquidated or merged into Aker BP ASA, while the Swiss entity will be liquidated.
The integration of the two organisations was completed during the third quarter, and the new organisation, as well as certain changes to the executive management team, was implemented from 1 October 2022.
Aker BP's net production was 37.9 (16.5) mmboe in the third quarter 2022, corresponding to 411.7 (181.3) mboepd. Net sold volume was 406.7 (172.6) mboepd.
| KEY FIGURES | AKER BP INTEREST* | Q3 2022 | Q2 2022 | Q1 2022 | Q4 2021 | Q3 2021 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Alvheim | 80% (65%) | 38 087 | 35 295 | 34 688 | 31 721 | 36 061 |
| Bøyla (incl. Frosk) | 80% (65%) | 1 813 | 1 259 | 1 561 | 2 068 | 865 |
| Skogul | 65% | 1 910 | 2 488 | 2 407 | 1 817 | 4 449 |
| Vilje | 46.904% | 1 923 | 2 018 | 2 108 | 3 501 | 1 971 |
| Volund | 100% (65%) | 5 673 | 2 757 | 4 582 | 4 275 | 3 264 |
| Total production | 49 405 | 43 817 | 45 347 | 43 382 | 46 610 | |
| Production efficiency | 100 % | 97 % | 98 % | 94 % | 96 % |
*Production prior to the third quarter 2022 does not incorporate production related to Lundin Energy's ownership shares in the area
Production from the Alvheim area was slightly down in the third quarter compared to the previous quarter due to natural decline and completion of the summer maintenance programme. The production volumes for the third quarter reflect the increased ownership interest in Alvheim, Bøyla and Volund following the completion of the Lundin transaction. Production efficiency was 100 percent in the quarter.
The Plan for Development and Operations (PDO) for Frosk was approved by the Ministry of Petroleum and Energy (MPE) on 8 July 2022. The two-well drilling campaign is on schedule, and the first well was spudded on 1 October 2022. The drilling programme will be followed by a subsea tie-back campaign leading up to production start in the first half of 2023.
The Kobra East & Gekko (KEG) project is progressing according to plan. Installation of pipelines and static umbilical was completed in the third quarter, and engineering, fabrication and procurement activities and well planning are moving forward according to plan. The KEG drilling campaign is planned to commence in direct continuation of the Frosk programme. Production start for KEG is scheduled for 2024.
The PDO for Trell and Trine (T&T) was submitted to the MPE on 10 August 2022. Commitments have been made to secure vessel and materials for execution of the planned pipelay campaign in 2023, enabling drilling of the T&T wells directly after the KEG drilling campaign. First oil is scheduled for 2025.
| KEY FIGURES | AKER BP INTEREST* | Q3 2022 | Q2 2022 | Q1 2022 | Q4 2021 | Q3 2021 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Edvard Grieg Area | 65% (0%) | 84 798 | - | - | - | - |
| Ivar Aasen | 36.1712% (34.7862%) | 14 203 | 7 019 | 14 038 | 15 157 | 15 285 |
| Total production | 99 000 | 7 019 | 14 038 | 15 157 | 15 285 | |
| Production efficiency | 99% | 52 % | 87 % | 81 % | 86 % |
*Production prior to the third quarter 2022 does not incorporate production related to Lundin Energy's ownership shares in the area
Edvard Grieg was included in Aker BP's income statement for the first time in the third quarter, following the completion of the Lundin transaction 30 June 2022. Net production from the field was 84.8 mboepd in the quarter.
Ivar Aasen production increased compared to previous quarter, driven by the resolution of the technical issues on Edvard Grieg. Production efficiency increased from 52 percent in the second quarter to 99 percent in the third quarter.
The Edvard Grieg IOR campaign for 2023 is on schedule for a final investment decision in fourth quarter 2022. First oil from the first well is expected mid-2023.
The Ivar Aasen IOR campaign for 2022 is progressing well. The Maersk Invincible drilling rig arrived in September. First oil from the first of three wells is expected before year-end.
The Hanz project is progressing according to plan. First oil is expected in first quarter 2024.
During the third quarter, concept select decisions were made for the Utsira High projects, including Lille Prinsen, Rolvsnes full field, and Solveig phase 2. Long lead items have been committed and the final investment decision is expected before year-end.
The Edvard Grieg & Ivar Aasen area will be powered from shore as part of Johan Sverdrup Phase 2. Commissioning is ongoing towards planned start-up in December.
| KEY FIGURES | AKER BP INTEREST* | Q3 2022 | Q2 2022 | Q1 2022 | Q4 2021 | Q3 2021 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Total production | 31.5733% (11.5733%) | 161 971 | 57 924 | 62 908 | 63 112 | 63 424 |
*Production prior to the third quarter 2022 does not incorporate production related to Lundin Energy's ownership shares in Johan Sverdrup.
Johan Sverdrup produced at full process capacity with high regularity throughout the third quarter, except for the finalisation of the 17-day planned shutdown starting in late June for maintenance and preparation for start-up of Phase 2 production.
During the quarter, production wells number 17 and 18 were put on production.
Phase 2 of the Johan Sverdrup development progressed safely according to plan and cost. Offshore hook-up and commissioning of the newbuilt second processing platform (P2, platform number 5) continued. Phase 2 production well number 2 was completed in the third quarter and is ready for the planned production start in the fourth quarter.
| KEY FIGURES | AKER BP INTEREST | Q3 2022 | Q2 2022 | Q1 2022 | Q4 2021 | Q3 2021 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Total production | 23.835 % | 42 057 | 38 867 | 34 576 | 31 785 | 34 476 |
| Production efficiency | 97% | 90 % | 86 % | 88 % | 97 % |
Production from Skarv in third quarter increased to 42.1 mboepd compared to 38.9 mboepd in the second quarter, driven by high production efficiency of 97 percent.
The Skarv Satellites Project is progressing according to plan. The FEED studies were completed in the third quarter and the project is on track for final investment decision and PDO submission in late 2022.
The development projects in the area are progressing according to plan. Idun Tunge started production in the fourth quarter 2022.
| KEY FIGURES | AKER BP INTEREST | Q3 2022 | Q2 2022 | Q1 2022 | Q4 2021 | Q3 2021 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Ula | 80 % | 2 818 | 1 855 | 3 157 | 4 165 | 4 622 |
| Tambar | 55 % | 1 439 | 568 | 1 434 | 1 915 | 2 725 |
| Oda | 15 % | 4 401 | 1 247 | 1 014 | 1 297 | 1 192 |
| Total production | 8 658 | 3 670 | 5 605 | 7 376 | 8 539 | |
| Production efficiency | 62% | 36 % | 60 % | 77 % | 84 % |
Production from the Ula area was 8.7 mboepd, up from 3.7 mboepd in the previous quarter. The increase was mainly driven by completion of the planned turnaround activities in the second quarter, affecting all fields producing through Ula. Higher performance of the main Tambar well and a new sidetrack on Oda also contributed positively.
An impairment charge of USD 55 million related to Ula was recorded in the third quarter, after a further review of the cost and production profiles following the previously reported acceleration of the expected shut-down from 2032 to 2028.
| KEY FIGURES | AKER BP INTEREST | Q3 2022 | Q2 2022 | Q1 2022 | Q4 2021 | Q3 2021 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Valhall | 90% | 40 658 | 29 122 | 44 945 | 45 623 | 40 983 |
| Hod | 90% | 9 984 | 792 | 593 | 426 | 467 |
| Total production | 50 642 | 29 914 | 45 538 | 46 050 | 41 450 | |
| Production efficiency | 87% | 56 % | 89 % | 84 % | 76 % |
Third quarter production from Valhall was 50.6 mboepd, up from 29.9 mboepd in the previous quarter following the completion of planned maintenance in June and ramp-up of production from Hod. Production efficiency was 87 percent.
The Hod Field Development (HFD) project was completed according to plan. All six wells are stimulated and on production, and offshore modifications are finalised. HFD started up 22 months after the final investment decision was made and all wells were on production within five months of pipeline commissioning.
An additional infill well on Valhall Flank West was put on production in the third quarter. This was the final well drilled by Maersk Invincible on Valhall and marks the end of a successful
five-year programme comprising drilling and P&A operations at the field.
Planning of the joint Valhall PWP & Fenris development project (previously named Valhall NCP & King Lear) progressed well during the third quarter. The selected development concept consists of a new process and wellhead platform (PWP) which will provide Valhall with significant gas processing capacity, and an unmanned platform on the Fenris gas field. The project will be connected to the existing power from shore solution at Valhall, resulting in close to zero emissions from operations. The project remains on track for PDO submission in the fourth quarter 2022. Production start is scheduled for 2027.
The NOAKA area is located between Oseberg and Alvheim in the Norwegian North Sea and consists of several oil and gas discoveries with gross resources estimated to around 600 million barrels of oil equivalent. The partners (Aker BP ASA, Equinor ASA and LOTOS Exploration & Production Norge AS) are planning for a coordinated development of the area, with Aker BP as the operator.
The NOA Fulla development concept includes a fixed platform at the Frigg Gamma Delta field. The fixed platform, NOA PdQ, will function as an area hub, with processing, drilling, and living quarters. Further, the Frøy field will be re-developed with a normally unmanned installation, as a copy of the Valhall Flank West and the Hod B platforms. The development concept also includes robust and flexible subsea production systems with dual drilling layout for the Fulla, Langfjellet and Rind fields, all tied back to the NOA PdQ. Krafla will be developed with an
unmanned production platform and five subsea templates. The Krafla development will be tied back to the NOA PdQ for oil and produced water processing. The NOAKA area will be powered from shore to ensure minimal carbon footprint.
During the third quarter 2022, the FEED reports were completed, and the public hearings of the impact assessments were concluded. The NOAKA project remains on schedule for submission of PDO in the fourth quarter 2022.
The environmental impact assessments for NOA Fulla and Krafla were published during second quarter, and the partners are preparing for a final investment decision in fourth quarter 2022.
Following the Lundin transaction, Aker BP holds 35 percent interest in the Equinor-operated Wisting field development which is located in licence PL537 and PL537B in the Barents Sea.
Total exploration spend in the third quarter was USD 122 (116) million, while USD 85 (67) 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 two prospects, Barlindåsen and Newt, in production license 941 in the Skarv area were completed in the quarter. The Newt well resulted in an oil and gas discovery with preliminary estimates of between 11-36 million barrels of oil equivalent. The licensees will consider producing the discovery via the Skarv FPSO. Aker BP is operator and has an ownership share of 80 percent in the licence. The Barlindåsen well was dry.
The contemplated development concept for Wisting includes a subsea solution where the oil is processed and stored on an FPSO. The production facility will be powered from shore and export of gas is planned to Snøhvit. An investment decision is planned during fourth quarter 2022.
The Ophelia prospect in production license 929 (10 percent interest) was also drilled during the quarter and resulted in a discovery. Preliminary estimates place the size of the discovery between 16 and 39 million barrels of recoverable oil equivalent. The licensees will assess the discovery along with other discoveries/prospects in the vicinity, and is considering a possible development utilising existing infrastructure on the Gjøa field.
The Lamba well in production licence 782S (20 percent interest) and the Poseidon well in production license 1104 (40 percent interest) were both concluded as dry. After the end of the quarter, the Uer well in production licence 943 (20 percent interest) has been 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 | Q3 2022 | Q2 2022 | Q1 2022 | Q4 2021 | Q3 2021 |
|---|---|---|---|---|---|---|
| Total recordable injury frequency (TRIF) L12M | Per mill. exp. hours |
1.3 | 1.6 | 1.8 | 1.9 | 1.6 |
| Serious incident frequency (SIF) L12M | Per mill. exp. hours |
0.1 | 0.1 | 0 | 0 | 0 |
| Acute spill | Count | 3 | 0 | 3 | 0 | 0 |
| Process safety events Tier 1 and 2 | Count | 0 | 0 | 0 | 0 | 0 |
| CO2 emissions intensity, Equity share | Kg CO2/boe | 3.4 | 4.8 | 4.5 | 5.3 | 4.9 |
| CO2 emissions intensity L12M | Kg CO2/boe | 4.3 | 4.9 | 4.8 | 4.8 | 4.4 |
The positive trend in TRIF continued in the third quarter 2022. Three TRIF incidents were recorded during the quarter. The incidents have been followed up and investigated in accordance with the company's governing system. Mitigating actions are currently being implemented.
Aker BP's CO2 emission intensity dropped to 3.4 kg CO2 per boe, down from an average of 4.9 kg for the previous 12 months primarily due to the increased ownership in lowemission fields following the Lundin transaction. Aker BP's CO2 emissions intensity is among the lowest across the oil and gas industry.
The company's decarbonisation strategy consists of the following key ambitions:
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 the second half of 2022 consists of the following key parameters:
In its proposal for the National budget for 2023, the Norwegian government has proposed a change to the temporary tax rules for the petroleum sector. The proposal is that the uplift for capital expenditures is reduced from 17.69 percent to 12.4 percent. This would have a negative impact on the after-tax cash flow and valuation for investment projects that are covered by the temporary tax rules.
Forward-looking statements in this report reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future and may not be within our control. All figures are presented in USD unless otherwise stated, and figures in brackets apply to the previous quarter.
| Group | ||||||
|---|---|---|---|---|---|---|
| Q3 | Q2 | Q3 | 01.01.-30.09. | |||
| (USD 1 000) | Note | 2022 | 2022 | 2021 | 2022 | 2021 |
| Petroleum revenues | 4 850 956 | 1 991 666 | 1 558 228 | 9 092 444 | 3 819 112 | |
| Other income | 15 376 | 34 683 | 4 447 | 91 525 | 556 | |
| Total income | 3 | 4 866 332 | 2 026 349 | 1 562 675 | 9 183 969 | 3 819 667 |
| Production costs | 4 | 235 921 | 190 394 | 208 798 | 646 446 | 542 939 |
| Exploration expenses | 5 | 85 275 | 67 301 | 97 477 | 210 099 | 270 414 |
| Depreciation | 7 | 521 590 | 198 875 | 246 846 | 951 590 | 744 771 |
| Impairments | 6,7 | 55 128 | 422 034 | 153 881 | 477 161 | 183 538 |
| Other operating expenses | 9 412 | 20 098 | 6 534 | 36 551 | 23 725 | |
| Total operating expenses | 907 326 | 898 701 | 713 537 | 2 321 847 | 1 765 387 | |
| Operating profit/loss | 3 959 006 | 1 127 648 | 849 138 | 6 862 122 | 2 054 281 | |
| Interest income | 5 701 | 5 450 | 342 | 12 501 | 1 040 | |
| Other financial income | 291 481 | 210 459 | 33 449 | 615 628 | 85 129 | |
| Interest expenses | 25 121 | 27 101 | 27 018 | 71 954 | 113 461 | |
| Other financial expenses | 449 322 | 250 586 | 54 218 | 733 752 | 171 743 | |
| Net financial items | 9 | -177 262 | -61 778 | -47 444 | -177 577 | -199 035 |
| Profit/loss before taxes | 3 781 744 | 1 065 870 | 801 694 | 6 684 545 | 1 855 246 | |
| Tax expense (+)/income (-) | 10 | 2 998 412 | 878 370 | 595 860 | 5 176 802 | 1 368 571 |
| Net profit/loss | 783 332 | 187 500 | 205 834 | 1 507 744 | 486 674 | |
| Weighted average no. of shares outstanding basic and diluted | 631 431 886 | 359 787 854 | 359 336 759 | 451 330 898 | 359 593 679 | |
| Basic and diluted earnings/loss USD per share | 1.24 | 0.52 | 0.57 | 3.34 | 1.35 |
| Group | ||||||
|---|---|---|---|---|---|---|
| Q3 | Q2 | Q3 | 01.01.-30.09. | |||
| (USD 1 000) | Note | 2022 | 2022 | 2021 | 2022 | 2021 |
| Profit/loss for the period | 783 332 | 187 500 | 205 834 | 1 507 744 | 486 674 | |
| Items which may be reclassified over profit and loss (net of taxes) Foreign currency translation |
-1 012 811 | - | - | -1 012 811 | - | |
| Total comprehensive income/loss in period | -229 479 | 187 500 | 205 834 | 494 932 | 486 674 |
| Group | ||||||
|---|---|---|---|---|---|---|
| (USD 1 000) | Note | 30.09.2022 | 30.06.2022 | 31.12.2021 | 30.09.2021 | |
| ASSETS | ||||||
| Intangible assets | ||||||
| Goodwill | 7 | 13 193 404 | 14 245 735 | 1 647 436 | 1 647 436 | |
| Capitalized exploration expenditures | 7 | 222 587 | 202 667 | 256 535 | 404 515 | |
| Other intangible assets | 7 | 2 527 042 | 2 658 270 | 1 407 551 | 1 374 238 | |
| Tangible fixed assets | ||||||
| Property, plant and equipment | 7 | 14 865 385 | 15 987 869 | 7 976 308 | 7 666 727 | |
| Right-of-use assets | 7 | 119 104 | 134 384 | 94 177 | 105 248 | |
| Financial assets | ||||||
| Long-term receivables | 82 380 | 78 639 | 73 346 | 73 975 | ||
| Other non-current assets | 105 409 | 106 804 | 30 304 | 32 553 | ||
| Long-term derivatives | 13 | - | - | 1 375 | 2 765 | |
| Total non-current assets | 31 115 311 | 33 414 367 | 11 487 032 | 11 307 457 | ||
| Inventories | ||||||
| Inventories | 173 816 | 160 347 | 126 442 | 123 430 | ||
| Receivables | ||||||
| Trade receivables | 791 851 | 735 887 | 366 785 | 412 195 | ||
| Other short-term receivables | 11 | 1 047 222 | 676 452 | 500 154 | 307 293 | |
| Short-term derivatives | 13 | 2 129 | 8 374 | 18 577 | 10 860 | |
| Cash and cash equivalents | ||||||
| Cash and cash equivalents | 12 | 3 041 997 | 2 153 644 | 1 970 906 | 1 420 783 | |
| Total current assets | 5 057 014 | 3 734 705 | 2 982 863 | 2 274 561 | ||
| TOTAL ASSETS | 36 172 326 | 37 149 071 | 14 469 895 | 13 582 017 |
| (USD 1 000) | Note | 30.09.2022 | 30.06.2022 | 31.12.2021 | 30.09.2021 |
|---|---|---|---|---|---|
| EQUITY AND LIABILITIES | |||||
| Equity | |||||
| Share capital | 84 348 | 84 348 | 57 056 | 57 056 | |
| Share premium | 12 946 640 | 12 946 640 | 3 637 297 | 3 637 297 | |
| Other equity | -1 548 414 | -970 158 | -1 352 462 | -1 566 492 | |
| Total equity | 11 482 574 | 12 060 830 | 2 341 891 | 2 127 860 | |
| Non-current liabilities | |||||
| Deferred taxes | 10 | 9 070 689 | 9 383 567 | 3 323 213 | 3 142 033 |
| Long-term abandonment provision | 16 | 3 374 373 | 3 849 345 | 2 656 358 | 2 637 470 |
| Long-term bonds | 15 | 5 198 294 | 5 234 200 | 3 576 735 | 3 594 939 |
| Long-term derivatives | 13 | 43 948 | 34 889 | 2 370 | 2 006 |
| Long-term lease debt | 8 | 95 197 | 105 742 | 91 835 | 95 772 |
| Other interest-bearing debt | 12 | - | 600 000 | - | - |
| Other non-current liabilities | 82 304 | 82 385 | - | - | |
| Total non-current liabilities | 17 864 806 | 19 290 127 | 9 650 511 | 9 472 221 | |
| Current liabilities | |||||
| Trade creditors | 93 836 | 130 711 | 147 366 | 166 599 | |
| Accrued public charges and indirect taxes | 33 792 | 55 872 | 28 147 | 25 203 | |
| Tax payable | 10 | 5 418 505 | 4 253 494 | 1 497 291 | 990 482 |
| Short-term derivatives | 13 | 429 861 | 374 743 | 35 082 | 27 675 |
| Short-term abandonment provision | 16 | 107 613 | 81 337 | 100 863 | 78 750 |
| Short-term lease debt | 8 | 42 310 | 49 035 | 44 378 | 61 869 |
| Other current liabilities | 14 | 699 029 | 852 923 | 624 366 | 631 358 |
| Total current liabilities | 6 824 946 | 5 798 114 | 2 477 493 | 1 981 937 | |
| Total liabilities | 24 689 752 | 25 088 242 | 12 128 004 | 11 454 157 | |
| TOTAL EQUITY AND LIABILITIES | 36 172 326 | 37 149 071 | 14 469 895 | 13 582 017 |
| 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 as of 31.12.2020 | 57 056 | 3 637 297 | 573 083 | -76 | -115 491 | -2 164 587 | -1 707 071 | 1 987 281 |
| Dividend distributed | - | - | - | - | - | -225 000 | -225 000 | -225 000 |
| Profit/loss for the period | - | - | - | - | - | 280 841 | 280 841 | 280 841 |
| Purchase of treasury shares | - | - | - | - | - | -12 818 | -12 818 | -12 818 |
| Equity as of 30.06.2021 | 57 056 | 3 637 297 | 573 083 | -76 | -115 491 | -2 121 564 | -1 664 048 | 2 030 304 |
| Dividend distributed | - | - | - | - | - | -112 500 | -112 500 | -112 500 |
| Profit/loss for the period | - | - | - | - | - | 205 834 | 205 834 | 205 834 |
| Net sale of treasury shares | - | - | - | - | - | 4 223 | 4 223 | 4 223 |
| Equity as of 30.09.2021 | 57 056 | 3 637 297 | 573 083 | -76 | -115 491 | -2 024 008 | -1 566 492 | 2 127 860 |
| Dividends distributed | - | - | - | - | - | -150 000 | -150 000 | -150 000 |
| Profit/loss for the period | - | - | - | - | - | 364 030 | 364 030 | 364 030 |
| Other comprehensive income for the period | - | - | - | - | - | |||
| Equity as of 31.12.2021 | 57 056 | 3 637 297 | 573 083 | -76 | -115 491 | -1 809 977 | -1 352 462 | 2 341 891 |
| Dividend distributed | - | - | - | - | - | -342 108 | -342 108 | -342 108 |
| Private placement | 27 292 | 9 309 343 | - | - | - | - | - | 9 336 636 |
| Profit/loss for the period | - | - | - | - | - | 724 411 | 724 411 | 724 411 |
| Equity as of 30.06.2022 | 84 348 | 12 946 640 | 573 083 | -76 | -115 491 | -1 427 674 | -970 158 | 12 060 830 |
| Dividend distributed | - | - | - | - | - | -331 812 | -331 812 | -331 812 |
| Profit/loss for the period | - | - | - | - | - | 783 332 | 783 332 | 783 332 |
| Purchase of treasury shares1) | - | - | - | - | - | -16 965 | -16 965 | -16 965 |
| Other comprehensive income for the period | - | - | - | - | -1 012 811 | - | -1 012 811 | -1 012 811 |
| Equity as of 30.09.2022 | 84 348 | 12 946 640 | 573 083 | -76 | -1 128 303 | -993 118 | -1 548 414 | 11 482 574 |
1) The treasury shares are purchased for use in the group's share saving plan
| Group | ||||||
|---|---|---|---|---|---|---|
| Q3 | Q2 | Q3 | 01.01.-30.09. | |||
| (USD 1 000) | Note | 2022 | 2022 | 2021 | 2022 | 2021 |
| CASH FLOW FROM OPERATING ACTIVITIES | ||||||
| Profit/loss before taxes | 3 781 744 | 1 065 870 | 801 694 | 6 684 545 | 1 855 246 | |
| Taxes paid | 10 | -1 240 800 | -748 060 | -97 680 | -2 377 116 | -97 680 |
| Taxes refunded | 10 | - | - | - | - | 34 640 |
| Depreciation | 7 | 521 590 | 198 875 | 246 846 | 951 590 | 744 771 |
| Impairment | 6,7 | 55 128 | 422 034 | 153 881 | 477 161 | 183 538 |
| Accretion expenses | 9,16 | 39 897 | 34 044 | 28 624 | 106 862 | 84 933 |
| Total interest expenses (excluding amortized loan costs) | 9 | 12 034 | 24 500 | 23 975 | 53 226 | 94 039 |
| Changes in unrealized gain/loss in derivatives | 3,9 | 70 422 | 211 778 | 13 295 | 250 537 | 48 570 |
| Amortized loan costs | 9 | 13 087 | 2 601 | 3 043 | 18 728 | 19 422 |
| Expensed capitalized dry wells | 5,7 | 52 936 | 33 676 | 37 603 | 126 055 | 65 584 |
| Changes in inventories, trade creditors and receivables | -106 308 | 67 511 | -27 388 | -113 914 | -71 958 | |
| Changes in other balance sheet items | -838 974 | -126 258 | -121 030 | -1 255 052 | 110 343 | |
| NET CASH FLOW FROM OPERATING ACTIVITIES | 2 360 757 | 1 186 570 | 1 062 862 | 4 922 622 | 3 071 447 | |
| CASH FLOW FROM INVESTMENT ACTIVITIES | ||||||
| Payment for removal and decommissioning of oil fields | -7 329 | -36 204 | -23 241 | -59 574 | -156 389 | |
| Disbursements on investments in fixed assets (excluding capitalized interest) | -403 742 | -270 769 | -359 969 | -1 009 818 | -955 017 | |
| Disbursements on investments in capitalized exploration | -89 163 | -76 257 | -48 562 | -213 977 | -131 808 | |
| Consideration paid in Lundin Energy transaction net of cash acquired | - | -1 242 784 | - | -1 242 784 | - | |
| Cash received from sale of financial asset | - | - | - | 118 005 | - | |
| NET CASH FLOW FROM INVESTMENT ACTIVITIES | -500 234 | -1 626 013 | -431 772 | -2 408 147 | -1 243 214 | |
| CASH FLOW FROM FINANCING ACTIVITIES | ||||||
| Net drawdown/repayment/fees related to revolving credit facility | -600 000 | -1 050 | - | -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) | -79 828 | -17 712 | -54 766 | -152 933 | -142 642 | |
| Payments on lease debt related to investments in fixed assets | -6 641 | -10 704 | -15 580 | -35 476 | -26 680 | |
| Payments on other lease debt | -5 655 | -9 170 | -5 850 | -18 458 | -36 739 | |
| Paid dividend | -331 812 | -171 054 | -112 500 | -673 919 | -337 500 | |
| Net purchase/sale of treasury shares | -16 965 | - | 4 223 | -16 965 | -8 595 | |
| NET CASH FLOW FROM FINANCING ACTIVITIES | -1 040 900 | -209 689 | -184 473 | -1 498 802 | -943 000 | |
| Net change in cash and cash equivalents | 819 622 | -649 132 | 446 617 | 1 015 673 | 885 233 | |
| Cash and cash equivalents at start of period | 2 153 644 | 2 816 731 | 975 360 | 1 970 906 | 537 801 | |
| Effect of exchange rate fluctuation on cash held | 68 730 | -13 955 | -1 195 | 55 418 | -2 251 | |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 12 | 3 041 997 | 2 153 644 | 1 420 783 | 3 041 997 | 1 420 783 |
(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 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. In this 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 is conducted in the legal entity ABP Norway AS (previously Lundin Energy Norway AS), which has 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 Q3 2022.
These interim financial statements were authorised for issue by the company's Board of Directors on 25 October 2022.
The accounting principles used for this interim report are consistent with the principles used in the group's 2021 annual financial statements.
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.
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.
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 third quarter, the group has recognized USD 14.4 million as estimated receivable as part of a settlement arrangement with the seller, meaning that total value of consideration has been 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 |
|---|---|
| Goodwill | 12 598 299 |
| Other intangible assets1) | 1 282 230 |
| Property, plant and equipment | 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 taxes | 5 844 226 |
| Long-term abandonment provision | 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 acquisition2) | 11 572 302 |
1) Mainly related to undeveloped oil and gas assets
2) In the third quarter, the group has recognized USD 14.4 million as estimated receivable as part of a settlement arrangement with the seller, meaning that total value of consideration has been 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 a result of the estimated decrese in total consideration, the value of the residual goodwill has been reduced accordingly, by USD 14.4 million in the third quarter.
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 | ||||||
|---|---|---|---|---|---|---|
| Q3 | Q2 | Q3 | 01.01.-30.09. | |||
| Breakdown of petroleum revenues (USD 1 000) | 2022 | 2022 | 2021 | 2022 | 2021 | |
| Sales of liquids | 3 182 066 | 1 363 769 | 1 208 591 | 6 099 762 | 3 193 383 | |
| Sales of gas | 1 665 909 | 626 316 | 345 849 | 2 985 359 | 614 873 | |
| Tariff income | 2 981 | 1 581 | 3 788 | 7 322 | 10 856 | |
| Total petroleum revenues | 4 850 956 | 1 991 666 | 1 558 228 | 9 092 444 | 3 819 112 | |
| Sales of liquids (boe 1 000) | 31 484 | 11 604 | 16 892 | 58 490 | 48 231 | |
| Sales of gas (boe 1 000) | 5 931 | 4 105 | 3 787 | 14 089 | 10 286 | |
| Other income (USD 1 000) | ||||||
| Realized gain/loss (-) on commodity derivatives | -5 080 | 28 657 | -6 638 | 21 259 | -12 725 | |
| Unrealized gain/loss (-) on commodity derivatives | -5 156 | -28 706 | 4 094 | 4 587 | -8 881 | |
| Gain on license transactions | - | 11 000 | - | 11 000 | - | |
| Other income | 25 612 | 23 733 | 6 991 | 54 680 | 22 161 | |
| Total other income | 15 376 | 34 683 | 4 447 | 91 525 | 556 |
| Group | |||||
|---|---|---|---|---|---|
| Q3 | Q2 | Q3 | 01.01.-30.09. | ||
| Breakdown of production cost (USD 1 000) | 2022 | 2022 | 2021 | 2022 | 2021 |
| Cost of operations | 192 314 | 147 398 | 114 051 | 489 734 | 333 248 |
| Shipping and handling | 68 679 | 39 382 | 46 173 | 157 749 | 137 705 |
| Environmental taxes | 13 650 | 10 986 | 14 199 | 42 861 | 37 209 |
| Production cost based on produced volumes | 274 644 | 197 766 | 174 422 | 690 345 | 508 162 |
| Adjustment for over/underlift (-) | -38 723 | -7 372 | 34 376 | -43 899 | 34 777 |
| Production cost based on sold volumes | 235 921 | 190 394 | 208 798 | 646 446 | 542 939 |
| Total produced volumes (boe 1 000) | 37 879 | 16 494 | 19 322 | 73 112 | 57 396 |
| Production cost per boe produced (USD/boe) | 7.3 | 12.0 | 9.0 | 9.4 | 8.9 |
| Group | ||||||
|---|---|---|---|---|---|---|
| Q3 | Q2 | Q3 | 01.01.-30.09. | |||
| Breakdown of exploration expenses (USD 1 000) | 2022 | 2022 | 2021 | 2022 | 2021 | |
| Seismic | 10 313 | 19 103 | 3 953 | 30 862 | 20 059 | |
| Area fee | 1 186 | 3 026 | 3 926 | 8 567 | 11 824 | |
| Field evaluation | 3 812 | 1 797 | 43 423 | 9 920 | 145 751 | |
| Dry well expenses1) | 52 936 | 33 676 | 37 603 | 126 055 | 65 584 | |
| Other exploration expenses | 17 028 | 9 699 | 8 571 | 34 695 | 27 196 | |
| Total exploration expenses | 85 275 | 67 301 | 97 477 | 210 099 | 270 414 |
1) Dry well expenses in Q3 2022 are mainly related to the wells Barlindåsen, Lamba and Poseidon.
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 Q3 2022, impairment test has been performed for fixed assets and related intangible assets, including technical 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 Q3 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. The effects of the proposed 2023 Fiscal Budget (see note 18) is included in the calculations. Below is an overview of the key assumptions applied for impairment testing purposes as of 30 September 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 Q4 2022 to the end of Q3 2025. From Q4 2025, the oil and gas prices are based on the company's long-term price assumptions. Long-term oil price assumption is unchanged from year-end 2021. Long-term gas price assumption is updated from 0.48 GBP/therm applied in previous quarters in 2022.
The nominal oil prices applied in the impairment test are as follows:
| Year | USD/BOE |
|---|---|
| 2022 | 87.5 |
| 2023 | 78.2 |
| 2024 | 72.4 |
| 2025 | 69.5 |
| From 2026 (in real 2022 terms) | 65.0 |
The nominal gas prices applied in the impairment test are as follows:
| Year | GBP/therm |
|---|---|
| 2022 | 4.01 |
| 2023 | 4.55 |
| 2024 | 3.13 |
| 2025 | 1.94 |
| From 2026 (in real 2022 terms) | 0.72 |
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 post tax nominal discount rate used is 8.2 percent, consistent with the rate applied at Q2 2022.
| Currency rates | |
|---|---|
| Year | USD/NOK |
| 2022 | 10.89 |
| 2023 | 10.77 |
| 2024 | 10.67 |
| 2025 | 9.99 |
| From 2026 | 8.00 |
The long-term inflation rate is assumed to be 2.0 percent.
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 impairment has been recognized in Q3 2022:
| Cash-generating unit (USD 1 000) | Ula/Tambar |
|---|---|
| Net carrying value | 55 232 |
| Recoverable amount | - |
| Impairment/reversal (-) | 55 232 |
| Allocated as follows: | |
| Technical goodwill | - |
| Other intangible assets/license rights | - |
| Tangible fixed assets | 55 232 |
The main reason for the Ula impairment is updates on cost and production profiles from the matured acceleration of the expected shut-down from 2032 to 2028, and the decrease in short-term oil prices compared to the previous quarter.
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 % | -12 355 | 514 385 |
| Oil and gas price long-term | +/- 20 % | - | 107 615 |
| Production profile (reserves) | +/- 5 % | - | - |
| Discount rate | +/- 1 % point | - | - |
| Currency rate USD/NOK1) | +/- 2.0 NOK | - | - |
| Inflation | +/- 1 % point | - | - |
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
| Property, plant and equipment | Production | Fixtures and | ||
|---|---|---|---|---|
| (USD 1 000) | Assets under development |
facilities including wells |
fittings, office machinery |
Total |
| Book value 31.12.2021 | 1 795 436 | 6 094 167 | 86 705 | 7 976 308 |
| Acquisition cost 31.12.2021 | 1 795 436 | 10 936 089 | 256 449 | 12 987 974 |
| Additions | 456 539 | 732 486 | 4 980 | 1 194 004 |
| Acquisition of Lundin Energy | 933 182 | 6 571 737 | 3 811 | 7 508 731 |
| Disposals/retirement | - | - | - | - |
| Reclassification | -483 424 | 588 116 | 7 273 | 111 965 |
| Acquisition cost 30.06.2022 | 2 701 733 | 18 828 429 | 272 512 | 21 802 674 |
| Accumulated depreciation and impairments 31.12.2021 | - | 4 841 922 | 169 744 | 5 011 666 |
| Depreciation | - | 371 904 | 20 070 | 391 974 |
| Impairment/reversal (-) | - | 411 165 | - | 411 165 |
| Disposals/retirement depreciation | - | - | - | - |
| Accumulated depreciation and impairments 30.06.2022 | - | 5 624 991 | 189 814 | 5 814 805 |
| Book value 30.06.2022 | 2 701 733 | 13 203 437 | 82 698 | 15 987 869 |
| Acquisition cost 30.06.2022 | 2 701 733 | 18 828 429 | 272 512 | 21 802 674 |
| Additions1) | ||||
| 202 161 | -203 309 | 3 131 | 1 983 | |
| Disposals/retirement Reclassification |
- -40 793 |
- 63 644 |
- - |
- 22 851 |
| Foreign currency translation | -84 037 | -538 647 | -322 | -623 006 |
| Acquisition cost 30.09.2022 | 2 779 065 | 18 150 117 | 275 320 | 21 204 503 |
| Accumulated depreciation and impairments 30.06.2022 | - | 5 624 991 | 189 814 | 5 814 805 |
| Depreciation | - | 479 112 | 10 461 | 489 573 |
| Impairment/reversal (-) | - | 55 128 | - | 55 128 |
| Disposals/retirement depreciation | - | - | - | - |
| Foreign currency translation | - | -20 342 | -45 | -20 387 |
| Accumulated depreciation and impairments 30.09.2022 | - | 6 138 889 | 200 230 | 6 339 119 |
| Book value 30.09.2022 | 2 779 065 | 12 011 228 | 75 091 | 14 865 385 |
1) The negative net additions related to production facilities is caused by the decrease in estmiated abandonment liabilities (see note 16)
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.
| Right-of-use assets | |||||
|---|---|---|---|---|---|
| Vessels and | |||||
| (USD 1 000) | Drilling Rigs | Boats | Office | Other | 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 | - | -353 | - | - | -353 |
| Disposals/retirement | - | - | - | - | - |
| Reclassification | -15 909 | -1 361 | - | - | -17 270 |
| Acquisition cost 30.06.2022 | 36 114 | 55 722 | 83 150 | 2 303 | 177 289 |
| Accumulated depreciation and impairments 31.12.2021 | 6 099 | 6 696 | 23 066 | 530 | 36 390 |
| Depreciation | 119 | 1 610 | 4 698 | 88 | 6 515 |
| Impairment/reversal (-) | - | - | - | - | - |
| Disposals/retirement depreciation | - | - | - | - | - |
| Accumulated depreciation and impairments 30.06.2022 | 6 218 | 8 306 | 27 764 | 618 | 42 906 |
| Book value 30.06.2022 | 29 896 | 47 416 | 55 386 | 1 685 | 134 384 |
| Acquisition cost 30.06.2022 | 36 114 | 55 722 | 83 150 | 2 303 | 177 289 |
| Additions | - | - | - | - | - |
| Allocated to abandonment activity | - | -5 | - | - | -5 |
| Disposals/retirement | - | - | - | - | - |
| Reclassification1) | -6 380 | -408 | - | - | -6 788 |
| 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 30.06.2022 | 6 218 | 8 306 | 27 764 | 618 | 42 906 |
| Depreciation | 1 112 | 1 251 | 3 510 | 44 | 5 917 |
| 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 |
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 | Depreciated | Other intangible assets Not depreciated |
Total | ||
| (USD 1 000) | Goodwill | expenditures | |||
| 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 | - | 124 813 | - | - | - |
| Acquisition of Lundin Energy | 12 598 299 | - | 25 653 | 1 256 577 | 1 282 230 |
| Disposals/retirement/expensed dry wells | - | 73 118 | - | - | - |
| Reclassification | - | -94 695 | 122 661 | -122 661 | - |
| Acquisition cost 30.06.2022 | 15 324 882 | 401 232 | 1 628 377 | 2 022 838 | 3 651 215 |
| Accumulated depreciation and impairments 31.12.2021 | 1 079 146 | 187 696 | 838 096 | 123 338 | 961 434 |
| Depreciation | - | - | 31 511 | - | 31 511 |
| Impairment/reversal (-) | - | 10 869 | - | - | - |
| Disposals/retirement depreciation | - | - | - | - | - |
| Accumulated depreciation and impairments 30.06.2022 | 1 079 146 | 198 565 | 869 607 | 123 338 | 992 945 |
| Book value 30.06.2022 | 14 245 735 | 202 667 | 758 770 | 1 899 500 | 2 658 270 |
| Acquisition cost 30.06.2022 | 15 324 882 | 401 232 | 1 628 377 | 2 022 838 | 3 651 215 |
| Additions1) | -14 405 | 89 163 | - | - | - |
| Disposals/retirement/expensed dry wells | - | 52 936 | - | - | - |
| Reclassification | - | -16 063 | - | - | - |
| 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 30.06.2022 | 1 079 146 | 198 565 | 869 607 | 123 338 | 992 945 |
| Depreciation | - | - | 26 100 | - | 26 100 |
| Impairment/reversal (-) | - | - | - | - | - |
| 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 |
1) The negative addition in the third quarter is related to estimated final settlement on the Lundin transaction
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 | |||||
|---|---|---|---|---|---|
| Q3 | Q2 | Q3 | 01.01.-30.09. | ||
| Depreciation in the income statement (USD 1 000) | 2022 | 2022 | 2021 | 2022 | 2021 |
| Depreciation of tangible fixed assets | 489 573 | 181 088 | 225 148 | 881 547 | 676 864 |
| Depreciation of right-of-use assets | 5 917 | 3 496 | 2 444 | 12 432 | 7 877 |
| Depreciation of other intangible assets | 26 100 | 14 291 | 19 255 | 57 611 | 60 031 |
| Total depreciation in the income statement | 521 590 | 198 875 | 246 846 | 951 590 | 744 771 |
| Impairment in the income statement (USD 1 000) | |||||
| Impairment/reversal of tangible fixed assets | 55 128 | 411 165 | 149 630 | 466 293 | 96 495 |
| Impairment/reversal of other intangible assets | - | - | 4 251 | - | 87 042 |
| Impairment/reversal of capitalized exploration expenditures Impairment of goodwill |
- - |
10 869 - |
- - |
10 869 - |
- - |
| Total impairment in the income statement | 55 128 | 422 034 | 153 881 | 477 161 | 183 538 |
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) | Q3 | 01.01.-30.06. | 01.01.-31.12. | |
| Lease debt as of beginning of period | 154 777 | 136 213 | 215 760 | |
| New lease debt recognized in the period | - | 29 588 | 5 989 | |
| Payments of lease debt1) | -14 198 | -45 443 | -96 173 | |
| Interest expense on lease debt | 1 902 | 3 805 | 11 558 | |
| Lease debt from acquisition of Lundin Energy | - | 34 757 | - | |
| Currency exchange differences | -4 973 | -4 143 | -921 | |
| Total lease debt | 137 507 | 154 777 | 136 213 | |
| Short-term | 42 310 | 49 035 | 44 378 | |
| Long-term | 95 197 | 105 742 | 91 835 | |
| 1) Payments of lease debt split by activities (USD 1 000): | ||||
| Investments in fixed assets | 7 623 | 31 487 | 50 423 | |
| Abandonment activity | 35 | 660 | 31 715 | |
| Operating expenditures | 4 130 | 5 208 | 7 499 | |
| Exploration expenditures | 114 | 5 931 | 1 858 | |
| Other income | 2 297 | 2 157 | 4 678 | |
| Total | 14 198 | 45 443 | 96 173 | |
| Nominal lease debt maturity breakdown (USD 1 000): | ||||
| Within one year | 48 613 | 55 939 | 51 010 | |
| Two to five years | 82 714 | 89 447 | 68 602 | |
| After five years | 29 556 | 34 387 | 42 837 | |
| Total | 160 883 | 179 773 | 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 | |||||
|---|---|---|---|---|---|
| Q3 | Q2 | Q3 | 01.01.-30.09. | ||
| (USD 1 000) | 2022 | 2022 | 2021 | 2022 | 2021 |
| Interest income | 5 701 | 5 450 | 342 | 12 501 | 1 040 |
| Realized gains on derivatives | 2 564 | 4 124 | 3 640 | 14 141 | 21 868 |
| Change in fair value of derivatives | - | - | - | 1 425 | - |
| Net currency gains | 288 868 | 206 334 | 29 810 | 501 288 | 63 262 |
| Other financial income | 49 | - | - | 98 774 | - |
| Total other financial income | 291 481 | 210 459 | 33 449 | 615 628 | 85 129 |
| Interest expenses | 42 964 | 32 373 | 30 611 | 105 926 | 112 431 |
| Interest on lease debt | 1 902 | 1 755 | 2 708 | 5 706 | 9 190 |
| Capitalized interest cost, development projects | -32 831 | -9 627 | -9 344 | -58 407 | -27 582 |
| Amortized loan costs1) | 13 087 | 2 601 | 3 043 | 18 728 | 19 422 |
| Total interest expenses | 25 121 | 27 101 | 27 018 | 71 954 | 113 461 |
| Net currency loss | 124 840 | - | - | 124 840 | - |
| Realized loss on derivatives | 218 175 | 29 862 | 8 205 | 255 738 | 8 239 |
| Change in fair value of derivatives | 65 267 | 183 072 | 17 389 | 239 129 | 39 689 |
| Accretion expenses | 39 897 | 34 044 | 28 624 | 106 862 | 84 933 |
| Other financial expenses | 1 142 | 3 608 | 1 | 7 182 | 38 882 |
| Total other financial expenses | 449 322 | 250 586 | 54 218 | 733 752 | 171 743 |
| Net financial items | -177 262 | -61 778 | -47 444 | -177 577 | -199 035 |
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 | |||||
|---|---|---|---|---|---|
| Q3 | Q2 | Q3 | 01.01.-30.09. | ||
| Tax for the period (USD 1 000) | 2022 | 2022 | 2021 | 2022 | 2021 |
| Current year tax payable/receivable | 2 831 715 | 993 178 | 500 466 | 4 993 182 | 858 627 |
| Change in current year deferred tax | 165 441 | -127 271 | 94 625 | 166 823 | 503 543 |
| Current and deferred tax related to change in tax system | - | 13 052 | - | 13 052 | - |
| Prior period adjustments | 1 257 | -590 | 769 | 3 744 | 6 402 |
| Tax expense (+)/income (-) | 2 998 412 | 878 370 | 595 860 | 5 176 802 | 1 368 571 |
| 2022 | 2022 | 2021 | |
|---|---|---|---|
| Calculated tax payable (-)/tax receivable (+) (USD 1 000) | Q3 | 01.01.-30.06. | 01.01.-31.12. |
| Tax payable/receivable at beginning of period | -4 253 494 | -1 497 291 | -163 352 |
| Current year tax payable/receivable | -2 831 715 | -2 161 467 | -1 526 236 |
| Current year tax payable/receivable related to change in tax system | - | 176 391 | - |
| Net tax payment/refund | 1 240 800 | 1 136 316 | 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 | 1 027 | 22 046 | -57 165 |
| Currency movements of tax payable/receivable | 219 563 | 251 527 | 26 297 |
| Current tax charged to OCI and equity (mainly relating to foreign currency translation) | 205 314 | - | - |
| Net tax payable (-)/receivable (+) | -5 418 505 | -4 253 494 | -1 497 291 |
| Group | ||||
|---|---|---|---|---|
| 2022 | 2022 | 2021 | ||
| Deferred tax liability (-)/asset (+) (USD 1 000) | Q3 | 01.01.-30.06. | 01.01.-31.12. | |
| Deferred tax liability/asset at beginning of period | -9 383 567 | -3 323 213 | -2 642 461 | |
| Change in current year deferred tax | -165 441 | -1 382 | -684 723 | |
| Change in current year deferred tax related to change in tax system | - | -189 444 | - | |
| Deferred tax related to acquisition of Lundin Energy | - | -5 844 226 | - | |
| Prior period adjustments | -2 273 | -25 302 | 3 971 | |
| Deferred tax charged to OCI and equity (mainly relating to foreign currency translation) | 480 592 | - | - | |
| Net deferred tax liability (-)/asset (+) | -9 070 689 | -9 383 567 | -3 323 213 |
| Group | |||||
|---|---|---|---|---|---|
| Q3 | Q2 | Q3 | 01.01.-30.09. | ||
| Reconciliation of tax expense (USD 1 000) | 2022 | 2022 | 2021 | 2022 | 2021 |
| 78 % tax rate on profit/loss before tax | 2 949 912 | 831 495 | 625 321 | 5 214 213 | 1 447 092 |
| Tax effect of uplift | -47 335 | -26 955 | -69 449 | -119 069 | -190 574 |
| Permanent difference on impairment | - | - | 4 149 | - | 2 829 |
| Foreign currency translation of monetary items other than USD | -133 549 | -157 597 | -22 772 | -296 007 | -48 807 |
| Foreign currency translation of monetary items other than NOK | -118 966 | -61 660 | -18 432 | -174 404 | 1 558 |
| Tax effect of financial and other 22 % items | 228 927 | 149 641 | 44 088 | 308 782 | 105 067 |
| Currency movements of tax balances1) | 81 463 | 150 268 | 27 840 | 229 229 | 34 891 |
| Other permanent differences, prior period adjustments and change in estimate of | 37 960 | -6 821 | 5 115 | 14 057 | 16 516 |
| uncertain tax positions | |||||
| Tax expense (+)/income (-) | 2 998 412 | 878 370 | 595 860 | 5 176 802 | 1 368 571 |
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).
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%)]. See note 18 for proposed changes to the tax regime after period end.
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) | 30.09.2022 | 30.06.2022 | 31.12.2021 | 30.09.2021 |
| Prepayments | 66 437 | 79 295 | 45 429 | 41 535 |
| VAT receivable | 9 391 | 15 405 | 13 354 | 7 683 |
| Underlift of petroleum | 47 923 | 95 921 | 36 944 | 21 741 |
| Accrued income from sale of petroleum products | 759 569 | 363 735 | 290 254 | 145 465 |
| Other receivables, mainly balances with license partners | 163 902 | 122 096 | 114 172 | 90 869 |
| Total other short-term receivables | 1 047 222 | 676 452 | 500 154 | 307 293 |
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) | 30.09.2022 | 30.06.2022 | 31.12.2021 | 30.09.2021 | |
| Bank deposits | 3 041 997 | 2 153 644 | 1 970 906 | 1 420 783 | |
| Cash and cash equivalents | 3 041 997 | 2 153 644 | 1 970 906 | 1 420 783 | |
| Unused RCF facility | 3 400 000 | 3 400 000 | 3 400 000 | 3 400 000 |
The RCF is undrawn as at 30 September 2022 and the remaining unamortized fees of USD 12.0 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:
Leverage Ratio: Total net debt divided by EBITDAX shall not exceed 3.5 times
Interest Coverage Ratio: EBITDA divided by Interest expenses shall be a minimum of 3.5 times
The financial covenants are calculated on a 12 months rolling basis. As at 30 September 2022 the Leverage Ratio is 0.21 and Interest Coverage Ratio is 66.9 (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 Q3 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) | 30.09.2022 | 30.06.2022 | 31.12.2021 | 30.09.2021 |
| Unrealized gain currency contracts | - | - | 1 375 | 2 765 |
| Long-term derivatives included in assets | - | - | 1 375 | 2 765 |
| Unrealized gain commodity derivatives | 618 | 8 080 | - | - |
| Unrealized gain currency contracts | 1 511 | 294 | 18 577 | 10 860 |
| Short-term derivatives included in assets | 2 129 | 8 374 | 18 577 | 10 860 |
| Total derivatives included in assets | 2 129 | 8 374 | 19 952 | 13 625 |
| Fair value of option related to sale of Cognite | 15 995 | 15 995 | - | - |
| Unrealized losses currency contracts | 27 953 | 18 894 | 2 370 | 2 006 |
| Long-term derivatives included in liabilities | 43 948 | 34 889 | 2 370 | 2 006 |
| Unrealized losses commodity derivatives | 5 019 | 7 326 | 8 989 | 12 420 |
| Unrealized losses currency contracts | 424 842 | 367 416 | 26 094 | 15 255 |
| Short-term derivatives included in liabilities | 429 861 | 374 743 | 35 082 | 27 675 |
| Total derivatives included in liabilities | 473 809 | 409 632 | 37 452 | 29 681 |
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 30 September 2022, the company has commodity contracts to protect downside price risk of oil and gas for the remaining part of 2022 and 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) | 30.09.2022 | 30.06.2022 | 31.12.2021 | 30.09.2021 |
| Balances with license partners | 43 497 | 73 620 | 48 456 | 77 026 |
| Share of other current liabilities in licenses | 447 578 | 409 480 | 311 694 | 357 849 |
| Overlift of petroleum | 26 421 | 113 433 | 40 044 | 14 312 |
| Payroll liabilities, accrued interest and other provisions | 181 533 | 256 390 | 224 173 | 182 171 |
| Total other current liabilities | 699 029 | 852 923 | 624 366 | 631 358 |
| Group | |||||
|---|---|---|---|---|---|
| Senior unsecured bonds (USD 1 000) | Maturity | 30.09.2022 | 30.06.2022 | 31.12.2021 | 30.09.2021 |
| AKERBP – USD Senior Notes 3.000% (20/25) | Jan 2025 | 497 953 | 497 733 | 497 295 | 497 075 |
| AKERBP – USD Senior Notes 2.875% (20/26) | Jan 2026 | 497 635 | 497 458 | 497 103 | 496 926 |
| AKERBP - USD Senior Notes 2.000% (21/26)1) | July 2026 | 900 926 | 894 464 | - | - |
| AKERBP – EUR Senior Notes 1.125% (21/29) | May 2029 | 726 273 | 774 017 | 843 995 | 862 939 |
| AKERBP – USD Senior Notes 3.750% (20/30) | Jan 2030 | 994 213 | 994 016 | 993 622 | 993 424 |
| AKERBP – USD Senior Notes 4.000% (20/31) | Jan 2031 | 745 156 | 745 011 | 744 720 | 744 575 |
| AKERBP - USD Senior Notes 3.100% (21/31)1) | July 2031 | 836 138 | 831 500 | - | - |
| Long-term bonds - book value | 5 198 294 | 5 234 200 | 3 576 735 | 3 594 939 | |
| Long-term bonds - fair value | 4 643 293 | 4 915 338 | 3 752 778 | 3 823 194 |
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 |
| Q3 | 01.01.-30.06. | 01.01.-31.12. |
| 3 930 682 | 2 757 221 | 2 805 507 |
| -7 334 | -52 599 | -185 973 |
| 39 897 | 66 965 | 113 748 |
| - | 591 331 | - |
| -43 096 | - | - |
| -445 606 | 496 928 | -340 973 |
| 7 443 | 70 836 | 364 912 |
| 3 481 986 | 3 930 682 | 2 757 221 |
| 107 613 | 81 337 | 100 863 |
| 3 374 373 | 3 849 345 | 2 656 358 |
Estimates are based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The calculations assume an inflation rate of 2.0 percent and a nominal discount rate before tax of between 4.8 percent and 5.3 percent. This represents a change from the second quarter, when the discount rate was between 3.7 percent and 4.2 percent. The credit margin included in the discount rate is 1.0 percent both in the second and third quarter.
During the normal course of its business, the group will be involved in disputes, including tax disputes. The group has made accruals for probable liabilities related to litigation and claims based on management's best judgment and in line with IAS 37 and IAS 12.
On 6 October 2022 the Government presented the proposed 2023 National Budget, including 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, and has been taken into consideration when performing impairment calculation as of 30 September 2022. The group is currently assessing the related impact on future cashflows and income statements.
| Total number of licenses | 30.09.2022 | 30.06.2022 Total number of licenses | 30.09.2022 | 30.06.2022 | ||
|---|---|---|---|---|---|---|
| Aker BP as operator | 79 | 81 ABP Norway as operator | 41 | 42 | ||
| Aker BP as partner | 44 | 44 ABP Norway as partner | 49 | 49 | ||
| Changes in production licenses in which Aker BP is the operator: | Changes in production licenses in which Aker BP is a partner: | |||||
| License: | 30.09.2022 | 30.06.2022 License: | 30.09.2022 | 30.06.2022 | ||
| PL 6851) | 0.000% | 35.000 % | ||||
| PL 9151) | 0.000% | 60.000 % | ||||
| Total | - | 2 Total | - | - | ||
| Changes in production licenses in which ABP Norway is the operator: Changes in production licenses in which ABP Norway is a partner: License: 30.09.2022 30.06.2022 License: 30.09.2022 30.06.2022 |
||||||
| PL 10271) | 0.000% | 40.000 % | ||||
| Total | - | 1 Total | - | - |
1) Relinquished license
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.
| Note 2022 2022 2021 2022 2021 (USD 1 000) Abandonment spend Payment for removal and decommissioning of oil fields 7 329 36 204 23 241 59 574 172 512 Payments of lease debt (abandonment activity) 8 35 414 3 357 694 31 715 Abandonment spend 7 364 36 618 26 598 60 268 204 227 Depreciation per boe Depreciation 7 521 590 198 875 246 846 951 590 964 083 Total produced volumes (boe 1 000) 4 37 879 16 494 19 322 73 112 76 439 Depreciation per boe 13.8 12.1 12.8 13.0 12.6 Dividend per share Paid dividend 331 812 171 054 112 500 673 919 487 500 Number of shares outstanding 631 432 359 788 359 337 451 331 359 643 Dividend per share 0.53 0.48 0.31 1.49 1.36 Capex Disbursements on investments in fixed assets (excluding capitalized interest) 403 742 270 769 359 969 1 009 818 1 376 879 Payments of lease debt (investments in fixed assets) 8 7 623 11 649 17 549 39 110 50 423 CAPEX 411 365 282 418 377 518 1 048 928 1 427 302 EBITDA Total income 3 4 866 332 2 026 349 1 562 675 9 183 969 5 668 747 Production costs 4 -235 921 -190 394 -208 798 -646 446 -745 313 Exploration expenses 5 -85 275 -67 301 -97 477 -210 099 -353 034 Other operating expenses -9 412 -20 098 -6 534 -36 551 -29 261 EBITDA 4 535 723 1 748 556 1 249 865 8 290 873 4 541 139 EBITDAX Total income 3 4 866 332 2 026 349 1 562 675 9 183 969 5 668 747 Production costs 4 -235 921 -190 394 -208 798 -646 446 -745 313 Other operating expenses -9 412 -20 098 -6 534 -36 551 -29 261 EBITDAX 4 620 998 1 815 857 1 347 342 8 500 972 4 894 173 Equity ratio Total equity 11 482 574 12 060 830 2 127 860 11 482 574 2 341 891 Total assets 36 172 326 37 149 071 13 582 017 36 172 326 14 469 895 Equity ratio 32% 32% 16% 32% 16% Exploration spend Disbursements on investments in capitalized exploration expenditures 89 163 76 257 48 562 213 977 177 464 Exploration expenses 5 85 275 67 301 97 477 210 099 353 034 Dry well 5 -52 936 -33 676 -37 603 -126 055 -98 827 Payments of lease debt (exploration expenditures) 8 114 5 725 578 6 044 1 858 |
Q3 | Q2 | Q3 | 01.01.-30.09. | 01.01.-31.12. | |
|---|---|---|---|---|---|---|
| Exploration spend | 121 616 | 115 607 | 109 013 | 304 065 | 433 529 |
| Q3 | Q2 | Q3 | 01.01.-30.09. | 01.01.-31.12. | ||
|---|---|---|---|---|---|---|
| (USD 1 000) | Note | 2022 | 2022 | 2021 | 2022 | 2021 |
| Interest coverage ratio | ||||||
| Twelve months rolling EBITDA | 9 849 423 | 6 563 565 | 3 605 280 | 9 849 423 | 4 541 139 | |
| Twelve months rolling EBITDA, impacts from IFRS 16 | 8 | -17 508 | -14 200 | -14 052 | -17 508 | -14 035 |
| Twelve months rolling EBITDA, excluding impacts from IFRS 16 | 9 831 915 | 6 549 366 | 3 591 228 | 9 831 915 | 4 527 104 | |
| Twelve months rolling interest expenses | 9 | 139 147 | 126 794 | 162 300 | 139 147 | 145 651 |
| Twelve months rolling amortized loan cost | 9 | 21 766 | 11 723 | 22 502 | 21 766 | 22 460 |
| Twelve months rolling interest income | 9 | 13 942 | 8 583 | 1 128 | 13 942 | 2 481 |
| Net interest expenses | 146 971 | 129 933 | 183 674 | 146 971 | 165 630 | |
| Interest coverage ratio1) | 66.9 | 50.4 | 19.6 | 66.9 | 27.3 | |
| Leverage ratio | ||||||
| Long-term bonds | 15 | 5 198 294 | 5 234 200 | 3 594 939 | 5 198 294 | 3 576 735 |
| Other interest-bearing debt | 12 | - | 600 000 | - | - | - |
| Cash and cash equivalents | 12 | 3 041 997 | 2 153 644 | 1 420 783 | 3 041 997 | 1 970 906 |
| Net interest-bearing debt excluding lease debt | 2 156 298 | 3 680 556 | 2 174 157 | 2 156 298 | 1 605 829 | |
| Twelve months rolling EBITDAX | 10 142 142 | 6 868 486 | 3 917 416 | 10 142 142 | 4 894 173 | |
| Twelve months rolling EBITDAX, impacts from IFRS 16 | 8 | -16 776 | -13 004 | -12 111 | -16 776 | -12 177 |
| Twelve months rolling EBITDAX, excluding impacts from IFRS 16 | 10 125 366 | 6 855 482 | 3 905 305 | 10 125 366 | 4 881 996 | |
| Leverage ratio1) | 0.21 | 0.54 | 0.56 | 0.21 | 0.33 | |
| Net interest-bearing debt | ||||||
| Long-term bonds | 15 | 5 198 294 | 5 234 200 | 3 594 939 | 5 198 294 | 3 576 735 |
| Other interest-bearing debt | 12 | - | 600 000 | - | - | - |
| Long-term lease debt Short-term lease debt |
8 8 |
95 197 42 310 |
105 742 49 035 |
95 772 61 869 |
95 197 42 310 |
91 835 44 378 |
| Cash and cash equivalents | 12 | 3 041 997 | 2 153 644 | 1 420 783 | 3 041 997 | 1 970 906 |
| Net interest-bearing debt | 2 293 805 | 3 835 332 | 2 331 798 | 2 293 805 | 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 70 and 0.1 respectively.
Operating profit/loss see Income Statement
Production cost per boe see note 4
To the shareholders of Aker BP ASA
We have reviewed the accompanying condensed consolidated statement of financial position of Aker BP ASA as at 30 September 2022, and the related condensed consolidated income statement, the statement of comprehensive income, the statement of changes in equity and the statement of cash flow for the nine-month period then ended, and a summary of significant accounting policies and other explanatory notes. Management is responsible for the preparation of this interim financial information in accordance with IAS 34 Interim Financial Reporting. Our responsibility is to express a conclusion on this interim financial information based on our review.
We conducted our review in accordance with International Standard on Review Engagements 2410, Review of Interim Financial Information Performed by the Independent Auditor of the Entity. A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (ISAs), and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.
Based on our review, nothing has come to our attention that causes us to believe that the accompanying consolidated interim financial information is not prepared, in all material respects, in accordance with IAS 34 Interim Financial Reporting.
Stavanger, 25 October 2022 PricewaterhouseCoopers AS
Gunnar Slettebø State Authorised Public Accountant
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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