Earnings Release • Jul 13, 2023
Earnings Release
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Aker BP delivered strong operational and financial performance in the second quarter 2023, with the highest production volume and lowest unit cost in the company's history.
(Numbers in brackets represent the previous quarter)
"It has been a very strong second quarter for Aker BP. We have produced more oil and gas, at a lower cost, and with lower emissions than ever before in our history. This excellent performance has led us to increase our expectations for the full year of 2023.
Beyond these strong results, I am also pleased that our field development projects are on track, and we have achieved important milestones throughout the quarter. This includes obtaining governmental approvals of all PDOs.
Furthermore, we have had exploration success in the quarter, contributing to the growth of our resource base and the value of our ongoing field development projects.
In summary, it has been a very active and productive quarter, and what I am most proud of is our dedicated team and a company culture for operational excellence and continuous improvement that really makes Aker BP 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 | Q2 2023 | Q1 2023 | Q2 2022 RESTATED |
H1 2023 | H1 2022 RESTATED |
|
|---|---|---|---|---|---|---|
| INCOME STATEMENT | ||||||
| Total income | USD million | 3 291 | 3 310 | 2 026 | 6 601 | 4 318 |
| EBITDA | USD million | 3 004 | 2 933 | 1 749 | 5 937 | 3 755 |
| Net profit/loss | USD million | 397 | 187 | 206 | 584 | 727 |
| Earnings per share (EPS) | USD | 0.63 | 0.30 | 0.57 | 0.92 | 2.02 |
| OTHER FINANCIAL KEY FIGURES | ||||||
| Net interest-bearing debt | USD million | 3 565 | 2 370 | 3 835 | 3 565 | 3 835 |
| Leverage ratio | 0.22 | 0.16 | 0.54 | 0.22 | 0.54 | |
| Dividend per share | USD | 0.55 | 0.55 | 0.48 | 1.10 | 0.95 |
| PRODUCTION AND SALES | ||||||
| Net petroleum production | mboepd | 480.7 | 452.7 | 181.3 | 466.8 | 194.7 |
| Over/underlift | mboepd | (3.3) | (3.1) | (8.6) | (3.2) | (0.4) |
| Net sold volume | mboepd | 477.4 | 449.6 | 172.6 | 463.6 | 194.3 |
| - Liquids | mboepd | 408.9 | 384.1 | 127.5 | 396.6 | 149.2 |
| - Natural gas | mboepd | 68.5 | 65.5 | 45.1 | 67.0 | 45.1 |
| REALISED PRICES | ||||||
| Liquids | USD/boe | 76.8 | 78.4 | 117.5 | 77.6 | 108.0 |
| Natural gas | USD/boe | 63.9 | 98.7 | 152.6 | 80.8 | 161.7 |
| AVERAGE EXCHANGE RATES | ||||||
| USDNOK | 10.71 | 10.24 | 9.43 | 10.48 | 9.14 | |
| EURUSD | 1.09 | 1.07 | 1.06 | 1.08 | 1.09 |
| (USD MILLION) | Q2 2023 | Q1 2023 | Q2 2022 RESTATED |
|---|---|---|---|
| Total income | 3 291 | 3 310 | 2 026 |
| EBITDA | 3 004 | 2 933 | 1 749 |
| EBIT | 2 257 | 1 961 | 1 157 |
| Pre-tax profit | 2 207 | 1 824 | 1 107 |
| Net profit/loss | 397 | 187 | 206 |
| EPS (USD) | 0.63 | 0.30 | 0.57 |
The company changed its accounting principle for abandonment provisions in the fourth quarter 2022. 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. In the fourth quarter 2022, the company 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.
Total income in the second quarter amounted to USD 3,291 (3,310) million. Compared to the first quarter, increase in sold volumes was offset by lower oil and gas prices. Realised liquids prices decreased by two percent to USD 76.8 (78.4) per boe and realised natural gas price decreased by 35 percent to USD 63.9 (98.7) per boe. Sold volumes increased by six percent to 477.4 (449.6) mboepd in the quarter.
Production expenses for the oil and gas sold in the quarter amounted to USD 247 (263) million, with lower well intervention at Valhall and strengthening of USD versus NOK as the main reasons for the reduction from last quarter. The average production cost per barrel produced decreased to USD 5.6 (7.2), with higher relative share of production from Johan Sverdrup as one of the contributors for the decrease. See note 3 for further details on production expenses. Exploration expenses amounted to USD 27 (98) million, with less dry well expenses as the main reason for the decrease.
Depreciation amounted to USD 645 (599) million, corresponding to USD 14.7 (14.7) per barrel of oil equivalent.
Impairments amounted to USD 102 (373) million, mainly related to technical goodwill on Edvard Grieg & Ivar Aasen CGU. In addition to technical goodwill not being depreciated, the main reason for the impairment was reduced short term forward prices. Further information is provided in note 5.
Operating profit was USD 2,257 (1,961) million for the second quarter.
Net financial expenses decreased to USD 50 (137) million, positively impacted by gain on repurchase of existing bonds in connection with a new US bond offering. For more details, see note 8 and 14.
Profit before taxes amounted to USD 2,207 (1,824) million. Tax expense was USD 1,811 (1,637) million. The effective tax rate was 82 (90) percent, impacted by the impairment of technical goodwill with no effect on deferred tax. This resulted in a net profit of USD 397 (187) million.
| (USD MILLION) | 30.06.2023 | 31.03.2023 | 30.06.2022 RESTATED |
|---|---|---|---|
| Goodwill | 13 554 | 13 636 | 14 246 |
| Property, plant and equipment (PP&E) | 16 218 | 16 220 | 16 620 |
| Other non-current assets | 3 248 | 3 122 | 3 181 |
| Cash and equivalent | 2 689 | 3 280 | 2 154 |
| Other current assets | 1 603 | 1 671 | 1 581 |
| Total assets | 37 312 | 37 928 | 37 781 |
| Equity | 12 316 | 12 267 | 11 919 |
| Bank and bond debt | 5 766 | 5 304 | 5 834 |
| Other long-term liabilities | 14 399 | 14 184 | 14 230 |
| Tax payable | 3 351 | 4 758 | 4 253 |
| Other current liabilities | 1 480 | 1 416 | 1 545 |
| Total equity and liabilities | 37 312 | 37 928 | 37 781 |
| Net interest-bearing debt | 3 565 | 2 370 | 3 835 |
| Leverage ratio | 0.22 | 0.16 | 0.54 |
At the end of the second quarter 2023, total assets amounted to USD 37.3 (37.9) billion, of which non-current assets were USD 33.0 (33.0) billion.
Equity amounted to USD 12.3 (12.3) billion at the end of the quarter, corresponding to an equity ratio of 33 (32) percent.
Bond debt totalled USD 5.8 (5.3) billion, and the company's bank facilities were not drawn. In June the company issued two new bonds; USD 500 million Senior Notes with a coupon of 5.6% due in 2028 and USD 1 billion Senior Notes with a coupon of 6.0% due in 2033. USD 1,000 million of
the proceeds from the new bonds were used to repurchase existing bonds, as further described in note 14. Other longterm liabilities amounted to USD 14.4 (14.2) billion.
After paying two tax instalments during the second quarter, tax payable decreased by USD 1,407 million to 3,351 (4,758) million.
At the end of the second quarter 2023, the company had total available liquidity of USD 6.1 (6.7) billion, comprising of USD 2.7 (3.3) billion in cash and cash equivalents and USD 3.4 (3.4) billion in undrawn credit facilities.
| (USD MILLION) | Q2 2023 | Q1 2023 | Q2 2022 |
|---|---|---|---|
| Cash flow from operations | 121 | 1 682 | 1 187 |
| Cash flow from investments | (776) | (705) | (1 626) |
| Cash flow from financing | 66 | (454) | (210) |
| Net change in cash & cash equivalents | (589) | 523 | (649) |
| Cash and cash equivalents | 2 689 | 3 280 | 2 154 |
Net cash flow from operating activities was USD 121 (1,682) million in the quarter. Taxes paid increased by USD 1,248 million to USD 2,817 (1,569) million, as there are two tax instalments due in the second quarter compared to only one instalment in the first quarter each year. Net cash used for investment activities was USD 776 (705) million, of which investments in fixed assets amounted to USD 664 (597) million for the quarter. Investments in capitalised exploration were USD 64 (79) million. Payments for decommissioning activities amounted to USD 48 (29) million.
Net cash inflow from financing activities was USD 66 million, compared to an outflow of 454 million in the previous quarter. The main items consisted of the issuance of new bonds amounting to USD 1.5 billion, repayment of bonds amounting to 1 billion and dividend disbursements of USD 348 (348) million.
The Annual General Meeting has authorised the Board to approve the distribution of dividends pursuant to section 8-2 (2) of the Norwegian Public Limited Companies Act.
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 second quarter 2023, the company paid a dividend of USD 0.55 per share. On 12 July 2023, the Board resolved to pay a quarterly dividend of USD 0.55 per share in the third quarter 2023, which will be disbursed on or about 26 July 2023. The ex-dividend date is 18 July 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 material commodity derivatives exposure per 30 June 2023.
| UNIT | H1 2023 | H1 2022 RESTATED |
|
|---|---|---|---|
| Net petroleum production | mboepd | 466.8 | 194.7 |
| Total income | USDm | 6 601 | 4 318 |
| Operating profit | USDm | 4 218 | 2 864 |
| Profit before taxes | USDm | 4 031 | 2 888 |
| Net profit/loss | USDm | 584 | 727 |
| Net interest-bearing debt | USDm | 3 565 | 3 835 |
The company changed its accounting principle for abandonment provisions in the fourth quarter 2022. 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. In the fourth quarter 2022, the company 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.
The Lundin transaction was completed on 30 June 2022 and almost doubled the group's production and revenue from 1 July 2022. Hence, the first half of 2022 represents the period prior to the Lundin transaction and is thus not directly comparable with the first half of 2023.
During the first six months of 2023, the company reported total income of USD 6,601 (4,318) million. The increase compared to the first half 2022 was mainly driven by production contributions from the Lundin transaction. Production in the period increased to 466.8 (194.7) thousand barrels of oil equivalent per day (mboepd). Average realised liquids prices decreased to USD 77.6 per barrel of oil equivalent (boe), compared to USD 108.0 in the first half 2022, while the average realised price for natural gas decreased to USD 80.8 (161.7) per boe.
Production costs for the oil and gas sold were USD 510 (411) million. Production costs were USD 6.3 (11.8) per produced boe.
Exploration expenses amounted to USD 125 (125) million. EBITDA amounted to USD 5,937 (3,755) million and operating profit was USD 4,218 (2,864) million. Net profit for the first half of 2023 was USD 584 million, compared to a net profit of USD 727 million for the first half of 2022.
Net cash flow from operating activities amounted to USD 1,803 (2,562) million, driven by increased tax payments. Net cash flow to investment activities amounted to USD 1,482 (1,908) million, with the decrease mainly caused by cash consideration paid for Lundin Energy in 2022. Net cash outflow from financing activities was USD 388 million, compared to an outflow of USD 458 million in the previous period.
As of 30 June 2023, the company had net interest-bearing debt of USD 3,565 (3,835) million. Available liquidity was USD 6.1 (5.6) billion comprising of cash and cash equivalents of USD 2,689 (2,154) million and undrawn credit facilities of USD 3.4 (3.4) billion.
Health, Safety, Security and Environment (HSSE) remains 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. The company continued to deliver strong HSSE performance during the first half of 2023, with a strong safety record including TRIF of 1.6 and CO2 emissions of 2.7 kg per boe.
Aker BP engaged in multiple license agreements and swaps during the second quarter:
The transactions are subject to government approvals.
Aker BP's net production was 43.7 (40.7) million barrels oil equivalent (mmboe) in the second quarter 2023, corresponding to 480.7 (452.7) mboepd. Net sold volume was 477.4 (449.6) mboepd.
| KEY FIGURES | AKER BP INTEREST* | Q2 2023 | Q1 2023 | Q4 2022 | Q3 2022 | Q2 2022 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Alvheim | 80% (65%) | 31.8 | 32.3 | 35.3 | 38.1 | 35.3 |
| Bøyla (incl. Frosk) | 80% (65%) | 7.1 | 4.6 | 3.3 | 1.8 | 1.3 |
| Skogul | 65% | 1.5 | 1.3 | 1.6 | 1.9 | 2.5 |
| Vilje | 46.904% | 1.7 | 1.8 | 2.2 | 1.9 | 2.0 |
| Volund | 100% (65%) | 2.9 | 2.8 | 3.5 | 5.7 | 2.8 |
| Total production | 45.0 | 42.8 | 45.8 | 49.4 | 43.8 | |
| Production efficiency | 100 % | 98 % | 99 % | 100 % | 97 % |
*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 45 mboepd net to Aker BP. This is an increase from the previous quarter as Frosk had its first full quarter of production following the production start in March. Production efficiency ended at 100 percent for 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 progressed its technical studies and scope maturation during the second quarter.
The Kobra East & Gekko (KEG) project is progressing on track. The 4-well drilling campaign began in January and has advanced ahead of schedule, with the first two wells already completed and the third currently underway. Initially, production from KEG was planned to commence in the first quarter of 2024. However, considering the strong progress in drilling, there is a possibility of accelerating production to 2023.
The Tyrving Plan for Development and Operations (PDO) was approved by the Ministry of Petroleum and Energy (MPE) 8 June 2023. Fabrication is still ongoing on several locations and the pipelay campaign has commenced during the second quarter. Drilling of the three Tyrving wells is scheduled to start in the first quarter of 2024 with production start in 2025.
| KEY FIGURES | AKER BP INTEREST* | Q2 2023 | Q1 2023 | Q4 2022 | Q3 2022 | Q2 2022 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Edvard Grieg Area | 65% (0%) | 74.9 | 71.8 | 86.1 | 84.8 | - |
| Ivar Aasen | 36.1712% (34.7862%) | 14.4 | 12.6 | 13.6 | 14.2 | 7.0 |
| Total production | 89.3 | 84.3 | 99.7 | 99.0 | 7.0 | |
| Production efficiency | 97 % | 87 % | 99 % | 99 % | 52 % |
*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.
Net production from Edvard Grieg & Ivar Aasen increased to 89.3 mboepd in the second quarter, driven by increased production efficiency following unplanned shut-downs in the previous quarter.
The Edvard Grieg IOR campaign for 2023 progressed as planned. Two of the three wells were brought on stream in the second quarter. The final well is to be put on stream in the third quarter.
The Hanz project is progressing according to plan. Pipelines to Ivar Aasen have been installed successfully and the project is ready for drilling of the production wells in the third quarter 2023. First oil is expected in first quarter 2024.
The Utsira High Project is progressing as planned with main contracts signed and detailed engineering and procurement ongoing. The project consists of two separate subsea tie-in projects. Symra (previously named Lille Prinsen) will be a tie-in to the Ivar Aasen platform, while Solveig phase 2 will be connected to the Edvard Grieg platform. Drilling will commence in third quarter 2025, while production start-up is scheduled for first quarter 2026 for Solveig and first quarter 2027 for Symra. Gross recoverable resources are estimated to 85 million barrels oil equivalent, and total investments are estimated to approximately NOK 16 billion in real terms. Aker BP is the operator for both developments.
| KEY FIGURES | AKER BP INTEREST* | Q2 2023 | Q1 2023 | Q4 2022 | Q3 2022 | Q2 2022 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Total production | 31.5733% (11.5733%) | 243.8 | 215.7 | 180.6 | 162.0 | 57.9 |
*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 safely and with high production efficiency in the second quarter.
Production was further ramped up to 755 mbblpd (gross) after successful testing of the Phase 2 facilities together with the existing field centre facilities.
Three new oil production wells were drilled, one from the field centre and two from the Phase 2 subsea templates. The new wells are expected to be put on production during the summer and will bring the total number of producing wells up to 26
| KEY FIGURES | AKER BP INTEREST | Q2 2023 | Q1 2023 | Q4 2022 | Q3 2022 | Q2 2022 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Total production | 23.835 % | 41.7 | 41.8 | 41.6 | 42.1 | 38.9 |
| Production efficiency | 98 % | 99 % | 97 % | 97 % | 90 % |
.
Skarv produced safely with stable rates at 41.7 mboepd. Production efficiency remained high at 98 percent.
Plan for Development and Operations (PDO) for three separate developments in the Skarv area was approved by the MPE in June. The developments, coordinated by the Skarv Satellite Project (SSP), consist of the gas and condensate discoveries Alve Nord, Idun Nord and Ørn. These projects
are estimated to bring approximately 120 million barrels of oil equivalent (gross) through Skarv FPSO from 2027. The SSP project has now entered the execution phase, with detailed engineering and procurement ongoing. Drilling is planned to commence in 2025.
| KEY FIGURES | AKER BP INTEREST | Q2 2023 | Q1 2023 | Q4 2022 | Q3 2022 | Q2 2022 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Ula | 80 % | 6.0 | 6.1 | 4.1 | 2.8 | 1.9 |
| Tambar | 55 % | 1.5 | 2.0 | 0.7 | 1.4 | 0.6 |
| Oda | 15 % | 1.0 | 2.5 | 4.0 | 4.4 | 1.2 |
| Total production | 8.6 | 10.6 | 8.8 | 8.7 | 3.7 | |
| Production efficiency | 72 % | 80 % | 56 % | 62 % | 36 % |
Production from the Ula area was 8.6 mboepd net to Aker BP in the second quarter. The reduction from the previous quarter was mainly driven by reduced production from the Oda field due to oil and water separation challenges and related maintenance on the main processing plant.
A project is underway to establish a late-life strategy for Ula, to facilitate safe and profitable operations until cease of production in 2028. In parallel, a field decommissioning study to prepare a work program for well plugging and platform removal is ongoing.
| KEY FIGURES | AKER BP INTEREST | Q2 2023 | Q1 2023 | Q4 2022 | Q3 2022 | Q2 2022 |
|---|---|---|---|---|---|---|
| Production, mboepd | ||||||
| Valhall | 90% | 41.5 | 42.9 | 42.4 | 40.7 | 29.1 |
| Hod | 90% | 10.8 | 14.5 | 13.1 | 10.0 | 0.8 |
| Total production | 52.2 | 57.4 | 55.5 | 50.6 | 29.9 | |
| Production efficiency | 89 % | 91 % | 89 % | 87 % | 56 % |
Production from the Valhall area was 52 mboepd net to Aker BP, with continued good well performance. The production efficiency was reduced to 89 percent due to a planned shutdown.
The Noble Integrator rig continued to support the stimulation and intervention activities at Valhall, aimed at bringing more wells up to their full production potential. During the second quarter the rig started 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 approved by the MPE in June 2023.
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 with 8 slots at Fenris tied back 50 kilometres to the PWP. The main ongoing activities are detailed engineering and procurement, which are progressing according to plan. In the second quarter fabrication was started at the Aker Solutions yard in Verdal.
Total recoverable resources for Valhall PWP-Fenris are estimated to be 230 mmboe gross, divided into 160 mmboe
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 the operator and will develop and operate the full area.
The final investment decision for the development of Yggdrasil was made by the partners in fourth quarter 2022, and in June 2023 the plans for development and operation were approved by the MPE. Gross investments in the area are estimated to NOK 115 billion in real terms. Production start is planned in 2027.
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. 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 in 2027.
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.
Munin will be developed with an unmanned production platform, which 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 a high degree of flexibility for potential tie-in of new discoveries.
The Yggdrasil area will be powered from shore to ensure minimal carbon footprint. In March, the MPE awarded Aker BP a licence to connect the platforms in the Yggdrasil area to the onshore power grid.
The Yggdrasil development is now in the execution phase, and the main priorities are currently detailed engineering and procurement. Construction across both Norwegian and international sites is planned to commence this autumn.
In May 2023, Aker BP made a significant oil discovery in the Yggdrasil area in the Øst Frigg Beta/Epsilon exploration well. The discovery is estimated at 53-90 million recoverable barrels of oil equivalent, and studies are underway with the aim to include this new discovery in the scope of the Yggdrasil development project.
Total exploration spend in the second quarter was USD 91 (119) million, while USD 27 (98) million was recognised as exploration expenses in the period, relating to dry well costs, seismic, area fees, field evaluation and G&G costs.
The Øst Frigg Beta/Epsilon exploration well in the Yggdrasil was drilled in the quarter. The well resulted in a discovery of 53-90 mmboe, twice as large as the original pre-drill
estimate. The discovery is located within production licences 873 and 442. Aker BP is the operator of both licences with an interest of 47.7 and 87.7 percent respectively.
Drilling of the Carmen well in licence 1148 started in the second quarter and was completed in July as a discovery. Aker BP has a 10 percent interest in the licence.
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 | Q2 2023 | Q1 2023 | Q4 2022 | Q3 2022 | Q2 2022 |
|---|---|---|---|---|---|---|
| Total recordable injury frequency (TRIF) L12M | Per mill. exp. hours |
1.6 | 1.1 | 1.1 | 1.3 | 1.6 |
| Serious incident frequency (SIF) L12M | Per mill. exp. hours |
0.2 | 0.3 | 0.4 | 0.2 | 0.2 |
| Acute spill | Count | 1 | 1 | 0 | 0 | 0 |
| Process safety events Tier 1 and 2 | Count | 0 | 0 | 0 | 0 | 0 |
| GHG emissions intensity*, equity share | Kg CO2e/boe | 2.6 | 2.9 | 3.2 | 3.8 | 5.3 |
*The definition of emissions intensity has been changed from previous quarterly reports, and now also includes emissions of methane and N2O, as well as CO2 emissions from exploration activities. Previous periods have been restated accordingly.
The total recordable injuries frequency (TRIF) increased from last quarter due to an increase in the number of personal injuries (all classified with low or moderate severity) which require medical treatment. All injuries are being followed up and investigated in accordance with the company's governing system, and mitigating actions are implemented when necessary.
The serious incident frequency (SIF) went down from the previous quarter, as no serious incidents have been recorded in 2023.
The company had one chemical spill incident in the quarter, involving a leak of 2.5 m3 of hypochlorite from a pipe flange at Ula.
Aker BP's greenhouse gas (GHG) emissions intensity was further reduced to 2.6 (2.9) kg CO2e per boe in the quarter. The main driver for the reduction was an increased share of production from electrified fields, combined with continued focus on energy efficiency improvements.
The Board is of the opinion that Aker BP is uniquely positioned for value creation. The key characteristics of the company are:
The company's financial plan for 2023 has been updated to reflect the strong performance in the first half, and 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 | ||||||||
|---|---|---|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | |||||
| Restated | Restated | |||||||
| (USD 1 000) | Note | 2023 | 2023 | 2022 | 2023 | 2022 | ||
| Petroleum revenues | 3 259 914 | 3 298 239 | 1 991 666 | 6 558 153 | 4 241 488 | |||
| Other income | 30 706 | 12 115 | 34 683 | 42 821 | 76 149 | |||
| Total income | 2 | 3 290 620 | 3 310 354 | 2 026 349 | 6 600 974 | 4 317 637 | ||
| Production expenses | 3 | 246 953 | 263 338 | 190 394 | 510 291 | 410 525 | ||
| Exploration expenses | 4 | 27 278 | 97 692 | 67 301 | 124 970 | 124 824 | ||
| Depreciation | 6 | 645 066 | 598 952 | 251 116 | 1 244 018 | 550 552 | ||
| Impairments | 5,6 | 101 533 | 373 210 | 340 814 | 474 742 | 340 814 | ||
| Other operating expenses | 12 649 | 16 161 | 20 098 | 28 810 | 27 139 | |||
| Total operating expenses | 1 033 479 | 1 349 352 | 869 723 | 2 382 831 | 1 453 853 | |||
| Operating profit/loss | 2 257 141 | 1 961 002 | 1 156 626 | 4 218 143 | 2 863 784 | |||
| Interest income | 27 535 | 25 364 | 5 450 | 52 899 | 6 800 | |||
| Other financial income | 199 780 | 314 593 | 210 459 | 495 885 | 324 147 | |||
| Interest expenses | 41 111 | 43 617 | 27 101 | 84 728 | 46 833 | |||
| Other financial expenses | 236 032 | 433 693 | 238 093 | 651 237 | 260 358 | |||
| Net financial items | 8 | -49 828 | -137 353 | -49 285 | -187 181 | 23 756 | ||
| Profit/loss before taxes | 2 207 313 | 1 823 649 | 1 107 341 | 4 030 962 | 2 887 540 | |||
| Tax expense (+)/income (-) | 9 | 1 810 581 | 1 636 669 | 901 566 | 3 447 250 | 2 160 189 | ||
| Net profit/loss | 396 732 | 186 980 | 205 775 | 583 712 | 727 350 | |||
| Weighted average no. of shares outstanding basic and diluted | 631 793 145 | 631 793 145 | 359 787 854 | 631 793 145 | 359 787 854 | |||
| Basic and diluted earnings/loss USD per share | 0.63 | 0.30 | 0.57 | 0.92 | 2.02 |
| Group | |||||||
|---|---|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | ||||
| Restated | Restated | ||||||
| (USD 1 000) Note |
2023 | 2023 | 2022 | 2023 | 2022 | ||
| Profit/loss for the period | 396 732 | 186 980 | 205 775 | 583 712 | 727 350 | ||
| Total comprehensive income/loss in period | 396 732 | 186 980 | 205 775 | 583 712 | 727 350 |
| Group | ||||||
|---|---|---|---|---|---|---|
| Restated | ||||||
| (USD 1 000) | Note | 30.06.2023 | 31.03.2023 | 31.12.2022 | 30.06.2022 | |
| ASSETS | ||||||
| Intangible assets | ||||||
| Goodwill | 6 | 13 553 989 | 13 635 654 | 13 934 986 | 14 245 735 | |
| Capitalised exploration expenditures | 6 | 315 660 | 273 097 | 251 736 | 202 667 | |
| Other intangible assets | 6 | 2 203 358 | 2 254 664 | 2 344 354 | 2 658 270 | |
| Tangible fixed assets | ||||||
| Property, plant and equipment | 6 | 16 218 392 | 16 219 528 | 15 886 659 | 16 619 677 | |
| Right-of-use assets | 6 | 460 080 | 322 819 | 111 336 | 134 384 | |
| Financial assets | ||||||
| Long-term receivables | 165 242 | 166 368 | 169 528 | 78 639 | ||
| Other non-current assets | 101 403 | 103 420 | 104 480 | 106 804 | ||
| Long-term derivatives | 12 | 1 880 | 1 607 | 2 907 | - | |
| Total non-current assets | 33 020 005 | 32 977 157 | 32 805 987 | 34 046 175 | ||
| Inventories | ||||||
| Inventories | 173 964 | 193 178 | 209 506 | 160 347 | ||
| Financial assets | ||||||
| Trade receivables | 486 480 | 580 093 | 950 942 | 735 887 | ||
| Other short-term receivables | 10 | 932 369 | 894 160 | 686 237 | 676 452 | |
| Short-term derivatives | 12 | 10 243 | 3 165 | 153 096 | 8 374 | |
| Cash and cash equivalents | ||||||
| Cash and cash equivalents | 11 | 2 688 845 | 3 280 245 | 2 756 012 | 2 153 644 | |
| Total current assets | 4 291 901 | 4 950 842 | 4 755 793 | 3 734 705 | ||
| TOTAL ASSETS | 37 311 906 | 37 927 999 | 37 561 780 | 37 780 880 |
| Group | ||||||
|---|---|---|---|---|---|---|
| Restated | ||||||
| (USD 1 000) | Note | 30.06.2023 | 31.03.2023 | 31.12.2022 | 30.06.2022 | |
| EQUITY AND LIABILITIES | ||||||
| Equity | ||||||
| Share capital | 84 348 | 84 348 | 84 348 | 84 348 | ||
| Share premium | 12 946 640 | 12 946 640 | 12 946 640 | 12 946 640 | ||
| Other equity | -714 994 | -764 114 | -603 482 | -1 112 295 | ||
| Total equity | 12 315 993 | 12 266 874 | 12 427 506 | 11 918 692 | ||
| Non-current liabilities | ||||||
| Deferred taxes | 9 | 9 725 278 | 9 502 412 | 9 359 146 | 9 333 441 | |
| Long-term abandonment provision | 15 | 4 160 762 | 4 308 764 | 4 050 396 | 4 673 417 | |
| Long-term bonds | 14 | 5 765 847 | 5 304 158 | 5 279 164 | 5 234 200 | |
| Long-term derivatives | 12 | 58 553 | 45 807 | 16 981 | 34 889 | |
| Long-term lease debt | 7 | 372 075 | 244 428 | 98 095 | 105 742 | |
| Other interest-bearing debt | - | - | - | 600 000 | ||
| Other non-current liabilities | 82 340 | 82 366 | 82 306 | 82 385 | ||
| Total non-current liabilities | 20 164 853 | 19 487 935 | 18 886 088 | 20 064 073 | ||
| Current liabilities | ||||||
| Trade creditors | 158 179 | 69 813 | 133 875 | 130 711 | ||
| Accrued public charges and indirect taxes | 28 851 | 22 291 | 36 632 | 55 872 | ||
| Tax payable | 9 | 3 350 867 | 4 757 530 | 5 084 142 | 4 253 494 | |
| Short-term derivatives | 12 | 156 075 | 184 580 | 34 924 | 374 743 | |
| Short-term abandonment provision | 15 | 143 918 | 144 356 | 115 202 | 81 337 | |
| Short-term lease debt | 7 | 116 290 | 101 216 | 36 298 | 49 035 | |
| Other current liabilities | 13 | 876 880 | 893 405 | 807 113 | 852 923 | |
| Total current liabilities | 4 831 059 | 6 173 190 | 6 248 186 | 5 798 114 | ||
| Total liabilities | 24 995 912 | 25 661 125 | 25 134 274 | 25 862 188 | ||
| TOTAL EQUITY AND LIABILITIES | 37 311 906 | 37 927 999 | 37 561 780 | 37 780 880 |
| 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 |
| 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 | - | - | - | - | - | -171 054 | -171 054 | -171 054 |
| Restated profit/loss for the period | - | - | - | - | - | 521 575 | 521 575 | 521 575 |
| Restated equity as of 31.03.2022 | 57 056 | 3 637 297 | 573 083 | -76 | -115 491 | -1 604 533 | -1 147 017 | 2 547 335 |
| Dividend distributed | - | - | - | - | - | -171 054 | -171 054 | -171 054 |
| Private placement | 27 292 | 9 309 343 | - | - | - | - | - | 9 336 636 |
| Restated profit/loss for the period | - | - | - | - | - | 205 775 | 205 775 | 205 775 |
| Restated equity as of 30.06.2022 | 84 348 | 12 946 640 | 573 083 | -76 | -115 491 | -1 569 811 | -1 112 295 | 11 918 692 |
| Dividends distributed | - | - | - | - | - | -663 623 | -663 623 | -663 623 |
| Restated profit/loss for the period | - | - | - | - | - | 875 590 | 875 590 | 875 590 |
| Net sale of treasury shares | - | - | - | - | - | 1 524 | 1 524 | 1 524 |
| Other comprehensive income for the period | - | - | - | -3 | 295 325 | - | 295 323 | 295 323 |
| Equity as of 31.12.2022 | 84 348 | 12 946 640 | 573 083 | -78 | 179 834 | -1 356 320 | -603 482 | 12 427 506 |
| Dividend distributed | - | - | - | - | - | -347 612 | -347 612 | -347 612 |
| Profit/loss for the period | - | - | - | - | 186 980 | 186 980 | 186 980 | |
| Equity as of 31.03.2023 | 84 348 | 12 946 640 | 573 083 | -78 | 179 834 | -1 516 952 | -764 114 | 12 266 874 |
| Dividend distributed | - | - | - | - | - | -347 612 | -347 612 | -347 612 |
| Profit/loss for the period | - | - | - | - | - | 396 732 | 396 732 | 396 732 |
| Equity as of 30.06.2023 | 84 348 | 12 946 640 | 573 083 | -78 | 179 834 | -1 467 833 | -714 994 | 12 315 993 |
| Group | |||||||
|---|---|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | ||||
| Restated | Restated | ||||||
| (USD 1 000) | Note | 2023 | 2023 | 2022 | 2023 | 2022 | |
| CASH FLOW FROM OPERATING ACTIVITIES | |||||||
| Profit/loss before taxes | 2 207 313 | 1 823 649 | 1 107 341 | 4 030 962 | 2 887 540 | ||
| Taxes paid | 9 | -2 816 961 | -1 568 942 | -748 060 | -4 385 903 | -1 136 316 | |
| Depreciation | 6 | 645 066 | 598 952 | 251 116 | 1 244 018 | 550 552 | |
| Impairment | 5,6 | 101 533 | 373 210 | 340 814 | 474 742 | 340 814 | |
| Expensed capitalised dry wells | 4,6 | 5 043 | 63 771 | 33 676 | 68 814 | 73 118 | |
| Accretion expenses related to abandonment provision | 8,15 | 39 937 | 40 354 | 21 551 | 80 292 | 42 894 | |
| Total interest expenses | 8 | 41 111 | 43 617 | 27 101 | 84 728 | 46 833 | |
| Changes in unrealised gain/loss in derivatives | 2,8 | -23 110 | 329 713 | 211 778 | 306 603 | 180 114 | |
| Changes in inventories, trade creditors/receivables and accrued income | 207 165 | 133 760 | 200 652 | 340 925 | -81 087 | ||
| Changes in other balance sheet items | -285 759 | -156 069 | -259 399 | -441 829 | -342 597 | ||
| NET CASH FLOW FROM OPERATING ACTIVITIES | 121 338 | 1 682 014 | 1 186 570 | 1 803 352 | 2 561 865 | ||
| CASH FLOW FROM INVESTMENT ACTIVITIES | |||||||
| Payment for removal and decommissioning of oil fields | 15 | -48 445 | -28 564 | -36 204 | -77 008 | -52 245 | |
| Disbursements on investments in fixed assets (excluding capitalised interest) | 6 | -663 488 | -597 442 | -270 769 | -1 260 931 | -606 076 | |
| Disbursements on investments in capitalised exploration | 6 | -64 166 | -79 409 | -76 257 | -143 576 | -124 813 | |
| 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 | -776 100 | -705 415 | -1 626 013 | -1 481 515 | -1 907 912 | ||
| CASH FLOW FROM FINANCING ACTIVITIES | |||||||
| Net drawdown/repayment/fees related to revolving credit facility | -975 | - | -1 050 | -975 | -1 050 | ||
| Repayment of bonds | -1 000 000 | - | - | -1 000 000 | - | ||
| Net proceeds from bond issue | 1 488 410 | - | - | 1 488 410 | - | ||
| Interest paid (including interest element of lease payments) | -38 340 | -77 979 | -17 712 | -116 319 | -73 106 | ||
| Payments on lease debt related to investments in fixed assets | -18 520 | -14 797 | -10 704 | -33 317 | -28 834 | ||
| Payments on other lease debt | -17 028 | -13 524 | -9 170 | -30 552 | -12 804 | ||
| Paid dividend | -347 612 | -347 612 | -171 054 | -695 224 | -342 108 | ||
| NET CASH FLOW FROM FINANCING ACTIVITIES | 65 935 | -453 913 | -209 689 | -387 978 | -457 902 | ||
| Net change in cash and cash equivalents | -588 827 | 522 686 | -649 132 | -66 141 | 196 051 | ||
| Cash and cash equivalents at start of period | 3 280 245 | 2 756 012 | 2 816 731 | 2 756 012 | 1 970 906 | ||
| Effect of exchange rate fluctuation on cash held | -2 573 | 1 547 | -13 955 | -1 026 | -13 312 | ||
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 11 | 2 688 845 | 3 280 245 | 2 153 644 | 2 688 845 | 2 153 644 |
(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 2022 annual financial statements. The interim financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair statement of the financial position, results of operations and cash flows for the dates and interim periods presented. Interim period results are not necessarily indicative of results of operations or cash flows for an annual period. These interim financial statements have been subject to a review in accordance with the International Standard on Review Engagements 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity.
The acquisition of the Lundin Energy's oil and gas business ("Lundin Energy") was completed on 30 June 2022, and the transaction was thus reflected in the statement of financial position in the second quarter 2022 report. Hence, Q2 2023 is not directly comparable to Q2 2022 since the latter does not include any activity from Lundin Energy. At 31 December 2022, the merger processes with the legacy Lundin Energy entities were completed. These entities had other functional currency than USD which gave rise to significant currency translation elements in the group consolidation. From 1 January 2023 the activity in the legacy Lundin entities are carried out in the legal entity Aker BP ASA and the mentioned impact on comprehensive income is thus no longer present.
These interim financial statements were authorised for issue by the company's Board of Directors on 12 July 2023.
The accounting principles used for this interim report are consistent with the principles used in the group's 2022 annual financial statements. This includes two changes in accounting principles as described below. The comparison periods Q2 2022 and 1 January to 30 June 2022 have been restated accordingly in this report.
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 changed the discount rate in Q4 2022 so that this no longer includes a credit element. Comparative figures from 1 January 2021 was restated accordingly. The table below shows the restatement impact for the comparison period Q2 2022, 1 January to 30 June 2022 and 1 January to 31 December 2021.
| Q2 | 01.01.-30.06. | 01.01.-31.12. | |
|---|---|---|---|
| Breakdown of restatement impact on the income statement (USD 1 000) | 2022 | 2022 | 2021 |
| Depreciation - prior to restatement | 198 875 | 430 000 | 964 083 |
| Depreciation - after restatement | 251 116 | 550 552 | 1 192 889 |
| Change | 52 241 | 120 552 | 228 807 |
| Impairment - prior to restatement | 422 034 | 422 034 | 262 554 |
| Impairment - after restatement | 340 814 | 340 814 | 262 554 |
| Change | -81 220 | -81 220 | - |
| Net financial items - prior to restatement | -61 778 | -315 | -241 718 |
| Net financial items - after restatement | -49 285 | 23 756 | -189 913 |
| Change | 12 493 | 24 071 | 51 804 |
| Tax expense/income - prior to restatement | 878 370 | 2 178 389 | 2 222 080 |
| Tax expense/income - after restatement | 910 719 | 2 166 485 | 2 084 012 |
| Change | 32 349 | -11 904 | -138 069 |
| Net profit/loss - prior to restatement | 187 500 | 724 411 | 850 704 |
| Net profit/loss - after restatement | 196 622 | 721 055 | 811 771 |
| Change | 9 122 | -3 357 | -38 933 |
| Breakdown of restatement impact on the statement of financial position (USD 1 000) | 30.06.2022 | 31.12.2021 |
|---|---|---|
| Property, plant and equipment - prior to restatement | 15 987 869 | 7 976 308 |
| Property, plant and equipment - after restatement | 16 619 677 | 10 214 438 |
| Change | 631 808 | 2 238 131 |
| Long-term abandonment provision - prior to restatement | 3 849 345 | 2 656 358 |
| Long-term abandonment provision - after restatement | 4 673 417 | 5 071 491 |
| Change | 824 072 | 2 415 133 |
| Deferred tax - prior to restatement | 9 383 567 | 3 323 213 |
| Deferred tax - after restatement | 9 233 594 | 3 185 144 |
| Change | -149 973 | -138 069 |
| Equity - prior to restatement | 12 060 830 | 2 341 891 |
| Equity - after restatement | 12 018 539 | 2 302 957 |
| Change | -42 290 | -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.
| Q2 | 01.01.-30.06. | 01.01.-31.12. | |
|---|---|---|---|
| Breakdown of restating impact on the income statement (USD 1 000) | 2022 | 2022 | 2021 |
| Tax expense/income - prior to restating | 910 719 | 2 166 485 | 2 084 012 |
| Tax expense/income - after restating | 901 566 | 2 160 189 | 2 067 855 |
| Change | -9 153 | -6 296 | -16 157 |
| Net profit/loss - prior to restatement | 196 622 | 721 055 | 811 771 |
| Net profit/loss - after restatement | 205 775 | 727 350 | 827 928 |
| Change | 9 153 | 6 296 | 16 157 |
| Breakdown of restating impact on the statement of financial position (USD 1 000) | 30.06.2022 | 31.12.2021 | |
| Deferred tax - prior to restating | 9 233 594 | 3 185 144 | |
| Deferred tax - after restating | 9 333 441 | 3 291 287 | |
| Change | 99 847 | 106 143 | |
| Equity - prior to restating | 12 018 539 | 2 302 957 | |
| Equity - after restating | 11 918 692 | 2 196 814 | |
| Change | -99 847 | -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 2022 annual financial statements.
| Group | |||||
|---|---|---|---|---|---|
| Q2 | Q1 Q2 |
01.01.-30.06. | |||
| Breakdown of petroleum revenues (USD 1 000) | 2023 | 2023 | 2022 | 2023 | 2022 |
| Sales of liquids | 2 857 525 | 2 711 519 | 1 363 769 | 5 569 044 | 2 917 697 |
| Sales of gas | 398 503 | 581 865 | 626 316 | 980 368 | 1 319 450 |
| Tariff income | 3 886 | 4 854 | 1 581 | 8 740 | 4 341 |
| Total petroleum revenues | 3 259 914 | 3 298 239 | 1 991 666 | 6 558 153 | 4 241 488 |
| Sales of liquids (boe 1 000) | 37 212 | 34 567 | 11 604 | 71 779 | 27 006 |
| Sales of gas (boe 1 000) | 6 233 | 5 896 | 4 105 | 12 129 | 8 158 |
| Other income (USD 1 000) | |||||
| Realised gain (+)/loss (-) on commodity derivatives | - | -34 | 28 657 | -34 | 26 339 |
| Unrealised gain (+)/loss (-) on commodity derivatives | -541 | -1 083 | -28 706 | -1 624 | 9 742 |
| Gain on license transactions | - | - | 11 000 | - | 11 000 |
| Other income1) | 31 246 | 13 232 | 23 733 | 44 479 | 29 067 |
| Total other income | 30 706 | 12 115 | 34 683 | 42 821 | 76 149 |
1) The figure includes insurance settlements on Ivar Aasen and Skarv
| Group | |||||||
|---|---|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | ||||
| Breakdown of production expenses (USD 1 000) | 2023 | 2023 | 2022 | 2023 | 2022 | ||
| Cost of operations | 152 994 | 200 937 | 147 398 | 353 930 | 297 419 | ||
| Shipping and handling | 73 962 | 74 432 | 39 382 | 148 394 | 89 070 | ||
| Environmental taxes | 16 753 | 16 478 | 10 986 | 33 231 | 29 211 | ||
| Production expenses based on produced volumes | 243 709 | 291 847 | 197 766 | 535 556 | 415 701 | ||
| Adjustment for over (+)/underlift (-) | 3 244 | -28 509 | -7 372 | -25 265 | -5 176 | ||
| Production expenses based on sold volumes | 246 953 | 263 338 | 190 394 | 510 291 | 410 525 | ||
| Total produced volumes (boe 1 000) | 43 742 | 40 742 | 16 494 | 84 484 | 35 232 | ||
| Production expenses per boe produced (USD/boe) | 5.6 | 7.2 | 12.0 | 6.3 | 11.8 |
| Group | ||||||
|---|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | |||
| Breakdown of exploration expenses (USD 1 000) | 2023 | 2023 | 2022 | 2023 | 2022 | |
| Seismic | 1 817 | 12 339 | 19 103 | 14 156 | 20 549 | |
| Area fee | 4 156 | 5 062 | 3 026 | 9 218 | 7 381 | |
| Field evaluation | 2 247 | 1 836 | 1 797 | 4 084 | 6 108 | |
| Dry well expenses | 5 043 | 63 771 | 33 676 | 68 814 | 73 118 | |
| G&G and other exploration expenses | 14 014 | 14 684 | 9 699 | 28 698 | 17 667 | |
| Total exploration expenses | 27 278 | 97 692 | 67 301 | 124 970 | 124 824 |
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 Q2 2023, impairment test has been performed for fixed assets and related intangible assets, including technical goodwill.
Impairment is recognised when the book value of an asset or a cash-generating unit, including associated goodwill, exceeds the recoverable amount. Correspondingly, a reversal of impairment is recognised when the recoverable amount exceeds the book value. Prior period impairment of goodwill is not subject to reversal. The recoverable amount is the higher of the asset's fair value less cost to sell and value in use. The impairment testing for Q2 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 30 June 2023.
Future price level is a key assumption and has significant impact on the net present value. Forecasted oil and gas prices are based on management's estimates and available market data. Information about market prices in the near future can be derived from the futures contract market. The information about future prices is less reliable on a long-term basis, as there are fewer observable market transactions going forward. In the impairment test, the oil and gas prices are therefore based on the forward curve from the beginning of Q3 2023 to the end of Q2 2026. From Q3 2026, the oil and gas prices are based on the company's long-term price assumptions. Long-term gas price assumption is unchanged from previous quarter. Long-term oil price assumption for the period 2027 to 2035 is updated from 65.0 USD/BOE applied in 2022 and Q1 2023.
The nominal oil prices applied in the impairment test are as follows:
| Year | USD/BOE |
|---|---|
| 2023 | 75.1 |
| 2024 | 73.4 |
| 2025 | 71.0 |
| 2026 | 71.9 |
| From 2027 to 2035 (in real 2023 terms) | 70.0 |
| From 2036 (in real 2023 terms) | 65.0 |
The nominal gas prices applied in the impairment test are as follows:
| Year | GBP/therm |
|---|---|
| 2023 | 1.08 |
| 2024 | 1.35 |
| 2025 | 1.14 |
| 2026 | 0.84 |
| From 2027 (in real 2023 terms) | 0.67 |
Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable reserves including potentially additional risked volumes.
Future capex, opex and abandonment cost are calculated based on the expected production profiles and the best estimate of the related cost. The cost profiles include an estimated impact of the currently high cost escalation in the industry.
The post tax nominal discount rate used is 8.7 percent, consistent with the rate applied at Q1 2023.
| Currency rates | |
|---|---|
| Year | USD/NOK |
| 2023 | 10.74 |
| 2024 | 10.64 |
| 2025 | 10.64 |
| 2026 | 9.58 |
| From 2027 | 8.50 |
The long-term currency rate is updated from 8.00 applied in previous quarters.
The long-term inflation rate is assumed to be 2.0 percent. The currently high cost escalation in the industry is reflected in the cash flows rather than in the inflation rate.
The technical goodwill recognised in previous business combinations is allocated to each CGU for the purpose of impairment testing. Hence, the impairment test of technical goodwill is included in the impairment testing of assets, and the technical goodwill is written down before the asset. The carrying value of the assets is the sum of tangible assets, intangible assets and technical goodwill as of the assessment date. In line with the methodology described in the annual report, deferred tax (from the date of acquisitions) reduces the net carrying value prior to the impairment charges. When deferred tax liabilities from the acquisitions decreases as a result of depreciation, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable.
Below is an overview of the impairment charge and the carrying value per cash generating unit where impairment has been recognised in Q2 2023:
| Cash-generating unit (USD 1 000) | Edvard Grieg & Ivar Aasen CGU |
|---|---|
| Net carrying value | 4 067 413 |
| Recoverable amount | 3 985 748 |
| Impairment/reversal (-) | 81 665 |
| Allocated as follows: | |
| Technical goodwill | 81 665 |
| Other intangible assets/license rights | - |
| Tangible fixed assets | - |
The reason for the Edvard Grieg & Ivar Aasen CGU impairment is mainly related to decrease in short-term oil and gas prices and the decrease of deferred tax liabilities as described above, partly offset by the increase in long-term oil price.
During the quarter, an impairment charge of USD 19.9 million has been recognized related to the exploration well named Ve.
The table below shows how the impairment or reversal of impairment of assets and technical goodwill would be affected by changes in the various assumptions, given that the remaining assumptions are constant. The figures in the table below are in all material respect related to goodwill impairment, which would have no impact on deferred tax.
| Change in impairment after | ||||||
|---|---|---|---|---|---|---|
| Assumption (USD 1 000) | Change | Increase in assumptions | Decrease in assumptions | |||
| Oil and gas price forward period | +/- 50 % | - | 2 165 605 | |||
| Oil and gas price long-term | +/- 20 % | - | 627 918 | |||
| Production profile (reserves) | +/- 5 % | - | 117 651 | |||
| Discount rate | +/- 1 % point | 35 478 | - | |||
| Currency rate USD/NOK | +/- 2.0 NOK | - | 393 192 | |||
| Inflation | +/- 1 % point | - | 72 123 |
In the annual report 2022, a sensitivity analysis towards prices from various IEA scenarios was provided, showing a significant need for impairment in the net zero scenario. The increase in long term oil price assumption increases the gap between the accounting assumptions and the prices in the net zero scenario, and would increase the need for impairment in that scenario accordingly.
| Property, plant and equipment | Production | Fixtures and | ||
|---|---|---|---|---|
| (USD 1 000) | Assets under development |
facilities including wells |
fittings, office machinery |
Total |
| Book value 31.12.2022 | 1 614 177 | 14 196 407 | 76 075 | 15 886 659 |
| Acquisition cost 31.12.2022 | 1 614 177 | 21 301 017 | 268 306 | 23 183 501 |
| Additions | 497 027 | 389 789 | 2 562 | 889 379 |
| Disposals/retirement | - | - | - | - |
| Reclassification | -215 487 | 227 718 | 3 207 | 15 438 |
| Acquisition cost 31.03.2023 | 1 895 718 | 21 918 525 | 274 075 | 24 088 318 |
| Accumulated depreciation and impairments 31.12.2022 | - | 7 104 610 | 192 232 | 7 296 841 |
| Depreciation | - | 532 191 | 8 820 | 541 011 |
| Impairment/reversal (-) | 30 938 | - | - | 30 938 |
| Disposals/retirement depreciation | - | - | - | - |
| Accumulated depreciation and impairments 31.03.2023 | 30 938 | 7 636 801 | 201 052 | 7 868 790 |
| Book value 31.03.2023 | 1 864 780 | 14 281 724 | 73 024 | 16 219 528 |
| Acquisition cost 31.03.2023 | 1 895 718 | 21 918 525 | 274 075 | 24 088 318 |
| Additions | 519 968 | 34 127 | 2 725 | 556 820 |
| Disposals/retirement | - | - | - | - |
| Reclassification | 3 897 | 18 987 | - | 22 885 |
| Acquisition cost 30.06.2023 | 2 419 583 | 21 971 639 | 276 800 | 24 668 023 |
| Accumulated depreciation and impairments 31.03.2023 | 30 938 | 7 636 801 | 201 052 | 7 868 790 |
| Depreciation | - | 571 811 | 9 029 | 580 841 |
| Impairment/reversal (-) | - | - | - | - |
| Disposals/retirement depreciation | - | - | - | - |
| Accumulated depreciation and impairments 30.06.2023 | 30 938 | 8 208 612 | 210 081 | 8 449 631 |
| Book value 30.06.2023 | 2 388 646 | 13 763 027 | 66 719 | 16 218 392 |
Production facilities, including wells, are depreciated in accordance with the unit-of-production method. Office machinery, fixtures and fittings etc. are depreciated using the straightline method over their useful life, i.e. 3 - 5 years. Estimated future Removal and decommissining costs are included as part of cost of production facilities or fields under developement
| Right-of-use assets | |||||
|---|---|---|---|---|---|
| Vessels and | |||||
| (USD 1 000) | Drilling Rigs | Boats | Office | Other | Total |
| Book value 31.12.2022 | 15 075 | 44 089 | 50 576 | 1 597 | 111 336 |
| Acquisition cost 31.12.2022 | 17 850 | 54 723 | 77 290 | 2 303 | 152 166 |
| Additions | 242 573 | - | - | - | 242 573 |
| Allocated to abandonment activity | -1 117 | -194 | - | - | -1 312 |
| Disposals/retirement | - | - | - | - | - |
| Reclassification | -20 764 | -397 | - | - | -21 161 |
| Acquisition cost 31.03.2023 | 238 543 | 54 131 | 77 290 | 2 303 | 372 267 |
| Accumulated depreciation and impairments 31.12.2022 | 2 776 | 10 634 | 26 714 | 706 | 40 829 |
| Depreciation | 3 970 | 1 072 | 3 532 | 44 | 8 618 |
| Impairment/reversal (-) | - | - | - | - | - |
| Disposals/retirement depreciation | - | - | - | - | - |
| Accumulated depreciation and impairments 31.03.2023 | 6 746 | 11 706 | 30 246 | 750 | 49 448 |
| Book value 31.03.2023 | 231 797 | 42 425 | 47 044 | 1 553 | 322 819 |
| Acquisition cost 31.03.2023 | 238 543 | 54 131 | 77 290 | 2 303 | 372 267 |
| Additions1) | 179 225 | - | 380 | - | 179 605 |
| Allocated to abandonment activity | -2 758 | -475 | - | - | -3 233 |
| Disposals/retirement | - | - | - | - | - |
| Reclassification2) | -25 987 | -205 | - | - | -26 192 |
| Acquisition cost 30.06.2023 | 389 022 | 53 452 | 77 670 | 2 303 | 522 447 |
| Accumulated depreciation and impairments 31.03.2023 | 6 746 | 11 706 | 30 246 | 750 | 49 448 |
| Depreciation | 8 359 | 984 | 3 532 | 44 | 12 919 |
| Impairment/reversal (-) | - | - | - | - | - |
| Disposals/retirement depreciation | - | - | - | - | - |
| Accumulated depreciation and impairments 30.06.2023 | 15 105 | 12 690 | 33 777 | 794 | 62 367 |
| Book value 30.06.2023 | 373 918 | 40 761 | 43 893 | 1 509 | 460 080 |
1) The additions are mainly related to the rig Noble Invincible.
2) Reclassified mainly to tangible fixed assets in line with the activity of the right-of-use asset.
Right-of-use assets are depreciated linearly over the lifetime of the related lease contract.
| Capitalised | |||||
|---|---|---|---|---|---|
| (USD 1 000) | Goodwill | exploration expenditures |
Depreciated | Other intangible assets Not depreciated |
Total |
| Book value 31.12.2022 | 13 934 986 | 251 736 | 1 432 009 | 912 345 | 2 344 354 |
| Acquisition cost 31.12.2022 | 15 404 399 | 450 301 | 2 361 756 | 1 302 816 | 3 664 572 |
| Additions | - | 79 409 | 2 573 | - | 2 573 |
| Disposals/retirement/expensed dry wells | - | 63 771 | - | - | - |
| Reclassification | - | 5 723 | 6 946 | -6 946 | |
| Acquisition cost 31.03.2023 | 15 404 399 | 471 662 | 2 371 275 | 1 295 870 | 3 667 145 |
| Accumulated depreciation and impairments 31.12.2022 | 1 469 413 | 198 565 | 929 747 | 390 471 | 1 320 218 |
| Depreciation | - | - | 49 323 | - | 49 323 |
| Impairment/reversal (-) | 299 332 | - | - | 42 940 | 42 940 |
| Disposals/retirement depreciation | - | - | - | - | - |
| Accumulated depreciation and impairments 31.03.2023 | 1 768 745 | 198 565 | 979 070 | 433 411 | 1 412 481 |
| Book value 31.03.2023 | 13 635 654 | 273 097 | 1 392 205 | 862 459 | 2 254 664 |
| Acquisition cost 31.03.2023 | 15 404 399 | 471 662 | 2 371 275 | 1 295 870 | 3 667 145 |
| Additions | - | 64 166 | - | - | - |
| Disposals/retirement/expensed dry wells | - | 5 043 | - | - | - |
| Reclassification | - | 3 307 | - | - | - |
| Acquisition cost 30.06.2023 | 15 404 399 | 534 092 | 2 371 275 | 1 295 870 | 3 667 145 |
| Accumulated depreciation and impairments 31.03.2023 | 1 768 745 | 198 565 | 979 070 | 433 411 | 1 412 481 |
| Depreciation | - | - | 51 307 | - | 51 307 |
| Impairment/reversal (-) | 81 665 | 19 868 | - | - | - |
| Disposals/retirement depreciation | - | - | - | - | - |
| Accumulated depreciation and impairments 30.06.2023 | 1 850 410 | 218 433 | 1 030 377 | 433 411 | 1 463 787 |
| Book value 30.06.2023 | 13 553 989 | 315 660 | 1 340 899 | 862 459 | 2 203 358 |
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 | |||||
|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | ||
| Restated | Restated | ||||
| Depreciation in the income statement (USD 1 000) | 2023 | 2023 | 2022 | 2023 | 2022 |
| Depreciation of tangible fixed assets | 580 841 | 541 011 | 233 329 | 1 121 851 | 512 526 |
| Depreciation of right-of-use assets | 12 919 | 8 618 | 3 496 | 21 537 | 6 515 |
| Depreciation of other intangible assets | 51 307 | 49 323 | 14 291 | 100 629 | 31 511 |
| Total depreciation in the income statement | 645 066 | 598 952 | 251 116 | 1 244 018 | 550 552 |
| Impairment in the income statement (USD 1 000) | |||||
| Impairment/reversal of tangible fixed assets | - | 30 938 | 329 945 | 30 938 | 329 945 |
| Impairment/reversal of other intangible assets | - | 42 940 | - | 42 940 | - |
| Impairment/reversal of capitalised exploration expenditures | 19 868 | - | 10 869 | 19 868 | 10 869 |
| Impairment of goodwill | 81 665 | 299 332 | - | 380 997 | - |
| Total impairment in the income statement | 101 533 | 373 210 | 340 814 | 474 742 | 340 814 |
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 recognised.
| Group | |||
|---|---|---|---|
| 2023 | 2023 | 2022 | |
| (USD 1 000) | Q2 | 01.01.-31.03. | 01.01.-31.12. |
| Lease debt as of beginning of period | 345 644 | 134 393 | 136 213 |
| New lease debt recognised in the period2) | 179 605 | 242 573 | 33 765 |
| Payments of lease debt1) | -42 031 | -33 100 | -74 068 |
| Interest expense on lease debt | 6 483 | 4 779 | 7 496 |
| Lease debt from acquisition of Lundin Energy | - | - | 34 757 |
| Currency exchange differences | -1 337 | -3 001 | -3 769 |
| Total lease debt | 488 364 | 345 644 | 134 393 |
| Short-term | 116 290 | 101 216 | 36 298 |
| Long-term | 372 075 | 244 428 | 98 095 |
| 1) Payments of lease debt split by activities (USD 1 000): | |||
| Investments in fixed assets | 21 897 | 17 294 | 46 942 |
| Abandonment activity | 3 612 | 1 518 | 751 |
| Operating expenditures | 2 664 | 4 500 | 13 878 |
| Exploration expenditures | 4 528 | 5 927 | 6 222 |
| Other income | 9 329 | 3 862 | 6 275 |
| Total | 42 031 | 33 100 | 74 068 |
| Nominal lease debt maturity breakdown (USD 1 000): | |||
| Within one year | 146 237 | 114 676 | 42 646 |
| Two to five years | 374 586 | 245 341 | 87 179 |
| After five years | 18 740 | 22 463 | 26 403 |
| Total | 539 563 | 382 480 | 156 227 |
2) The new lease debt recognised in Q2 2023 is mainly related to the rig Noble Invincible.
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 | |||||
|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | ||
| Restated | Restated | ||||
| (USD 1 000) | 2023 | 2023 | 2022 | 2023 | 2022 |
| Interest income | 27 535 | 25 364 | 5 450 | 52 899 | 6 800 |
| Realised gains on derivatives | 507 | 55 202 | 4 124 | 55 708 | 11 577 |
| Change in fair value of derivatives | 23 650 | - | - | 5 163 | 1 425 |
| Net currency gains | 131 905 | 259 066 | 206 334 | 390 970 | 212 419 |
| Other financial income1) | 43 719 | 325 | - | 44 044 | 98 725 |
| Total other financial income | 199 780 | 314 593 | 210 459 | 495 885 | 324 147 |
| Interest expenses | 49 391 | 46 046 | 32 373 | 95 437 | 62 962 |
| Interest on lease debt | 6 483 | 4 779 | 1 755 | 11 262 | 3 805 |
| Capitalised interest cost, development projects | -27 924 | -20 294 | -9 627 | -48 219 | -25 575 |
| Amortised loan costs2) | 13 162 | 13 087 | 2 601 | 26 248 | 5 642 |
| Total interest expenses | 41 111 | 43 617 | 27 101 | 84 728 | 46 833 |
| Realised loss on derivatives | 191 536 | 64 345 | 29 862 | 255 881 | 37 563 |
| Change in fair value of derivatives | - | 328 630 | 183 072 | 310 143 | 173 862 |
| Accretion expenses related to abandonment provision | 39 937 | 40 354 | 21 551 | 80 292 | 42 894 |
| Other financial expenses | 4 559 | 364 | 3 608 | 4 923 | 6 040 |
| Total other financial expenses | 236 032 | 433 693 | 238 093 | 651 237 | 260 358 |
| Net financial items | -49 828 | -137 353 | -49 285 | -187 181 | 23 756 |
1) Mainly related to the net gain from repurchase of bonds, as described in note 14
2) The figure includes amortisation of the difference between fair value and nominal value on the bonds acquired in the Lundin transaction in Q2 2022
| Group | ||||||
|---|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | |||
| Restated | Restated | |||||
| Tax for the period (USD 1 000) | 2023 | 2023 | 2022 | 2023 | 2022 | |
| Current year tax payable/receivable | 1 526 272 | 1 535 967 | 993 178 | 3 062 240 | 2 161 467 | |
| Change in current year deferred tax | 222 905 | 110 878 | -104 075 | 333 783 | -16 818 | |
| Current and deferred tax related to change in tax system | - | - | 13 052 | - | 13 052 | |
| Prior period adjustments | 61 404 | -10 176 | -590 | 51 228 | 2 488 | |
| Tax expense (+)/income (-) | 1 810 581 | 1 636 669 | 901 566 | 3 447 250 | 2 160 189 |
| Group | |||
|---|---|---|---|
| 2023 | 2023 | 2022 | |
| Calculated tax payable (-)/tax receivable (+) (USD 1 000) | Q2 | 01.01.-31.03. | 01.01.-31.12. |
| Tax payable/receivable at beginning of period | -4 757 530 | -5 084 142 | -1 497 291 |
| Current year tax payable/receivable | -1 526 272 | -1 535 967 | -7 162 988 |
| Current year tax payable/receivable related to change in tax system | - | - | 176 391 |
| Net tax payment/refund | 2 816 961 | 1 568 942 | 5 332 125 |
| Net tax payable related to acquisition of Lundin Energy | - | - | -2 181 017 |
| Prior period adjustments and change in estimate of uncertain tax positions | -61 443 | 42 564 | 29 847 |
| Currency movements of tax payable/receivable | 177 416 | 251 074 | 245 846 |
| Current tax charged to other comprehensive income (foreign currency translation) | - | - | -27 055 |
| Net tax payable (-)/receivable (+) | -3 350 867 | -4 757 530 | -5 084 142 |
| Group | |||
|---|---|---|---|
| 2023 | 2023 | 2022 | |
| Deferred tax liability (-)/asset (+) (USD 1 000) | Q2 | 01.01.-31.03. | 01.01.-31.12. |
| Deferred tax liability/asset at beginning of period | -9 502 412 | -9 359 146 | -3 291 287 |
| Change in current year deferred tax | -222 905 | -110 878 | 12 294 |
| Change in current year deferred tax related to change in tax system | - | - | -189 444 |
| Deferred tax related to acquisition of Lundin Energy | - | - | -5 801 917 |
| Prior period adjustments | 39 | -32 388 | -27 925 |
| Deferred tax charged to other comprehensive income (mainly foreign currency translation) | - | - | -60 868 |
| Net deferred tax liability (-)/asset (+) | -9 725 278 | -9 502 412 | -9 359 146 |
| Group | |||||
|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | ||
| Restated | Restated | ||||
| Reconciliation of tax expense (USD 1 000) | 2023 | 2023 | 2022 | 2023 | 2022 |
| 78 % tax rate on profit/loss before tax | 1 721 792 | 1 422 519 | 863 844 | 3 144 311 | 2 252 396 |
| Tax effect of uplift | -42 893 | -41 011 | -26 955 | -83 904 | -71 735 |
| Permanent difference on impairment | 63 702 | 233 491 | - | 297 193 | - |
| Foreign currency translation of monetary items other than USD | -95 734 | -206 660 | -157 597 | -302 394 | -162 458 |
| Foreign currency translation of monetary items other than NOK | -7 348 | -92 944 | -61 660 | -100 292 | -55 438 |
| Tax effect of financial and other 22 % items | 64 237 | 252 867 | 140 487 | 317 103 | 73 560 |
| Currency movements of tax balances1) | 37 761 | 76 897 | 150 268 | 114 658 | 147 766 |
| Other permanent differences, prior period adjustments and change in estimate of uncertain tax positions |
69 064 | -8 491 | -6 821 | 60 574 | -23 903 |
| Tax expense (+)/income (-) | 1 810 581 | 1 636 669 | 901 566 | 3 447 250 | 2 160 189 |
1) Tax balances are in NOK and converted to USD using the period end currency rate. When NOK weakens against USD, the tax rate increases as there is less remaining tax depreciation measured in USD (and vice versa).
From 1 January 2023 the temporary tax regime uplift rate was reduced from from 17.69 to 12.4 percent.
In accordance with statutory requirements, the calculation of current tax is required to be based on each company's local currency. This may impact the effective tax rate as the group's presentation currency is USD and the operating entities in the group can have different functional currency than USD.
| Group | |||||
|---|---|---|---|---|---|
| (USD 1 000) | 30.06.2023 | 31.03.2023 | 31.12.2022 | 30.06.2022 | |
| Prepayments | 168 072 | 111 384 | 123 980 | 79 295 | |
| VAT receivable | 14 272 | 14 276 | 12 406 | 15 405 | |
| Underlift of petroleum | 68 446 | 75 353 | 53 630 | 95 921 | |
| Accrued income from sale of petroleum products | 518 889 | 524 861 | 335 505 | 363 735 | |
| Other receivables, mainly balances with license partners | 162 690 | 168 287 | 160 715 | 122 096 | |
| Total other short-term receivables | 932 369 | 894 160 | 686 237 | 676 452 |
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) | 30.06.2023 | 31.03.2023 | 31.12.2022 | 30.06.2022 | ||
| Bank deposits | 2 688 845 | 3 280 245 | 2 756 012 | 2 153 644 | ||
| Cash and cash equivalents | 2 688 845 | 3 280 245 | 2 756 012 | 2 153 644 | ||
| Unused RCF facility | 3 400 000 | 3 400 000 | 3 400 000 | 3 400 000 |
The RCF is undrawn as at 30 June 2023 and the remaining unamortised fees of USD 9.9 million related to the facility are therefore included in other non-current assets.
The senior unsecured Revolving Credit Facility (RCF) of USD 3.4 billion was established in May 2019 and consist of two tranches:
(1) Working Capital Facility with a committed amount of USD 1.4 billion until 2025 and USD 1.3 billion until 2026, and
(2) Liquidity Facility with a committed amount of USD 2.0 billion until 2025 and USD 1.65 billion until 2026.
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 utilisation 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 in the group's current debt facilities exclude the effects from IFRS 16, and therefore cannot be directly derived from the group's financial statements. See reconciliations of Alternative Performance Measures for detailed information.
As at 30 June 2023 the Leverage Ratio is 0.22 and Interest Coverage Ratio is 83.5 (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 Q2 2023, the group's estimates show that the financial covenants will continue to comply with the covenants by a substantial margin.
| Group | ||||
|---|---|---|---|---|
| (USD 1 000) | 30.06.2023 | 31.03.2023 | 31.12.2022 | 30.06.2022 |
| Unrealised gain currency contracts | 1 880 | 1 607 | 2 907 | - |
| Long-term derivatives included in assets | 1 880 | 1 607 | 2 907 | - |
| Unrealised gain commodity derivatives | - | - | - | 8 080 |
| Unrealised gain currency contracts | 10 243 | 3 165 | 153 096 | 294 |
| Short-term derivatives included in assets | 10 243 | 3 165 | 153 096 | 8 374 |
| Total derivatives included in assets | 12 123 | 4 772 | 156 003 | 8 374 |
| Fair value of option related to sale of Cognite | 10 832 | 15 995 | 15 995 | 15 995 |
| Unrealised losses currency contracts | 47 720 | 29 812 | 986 | 18 894 |
| Long-term derivatives included in liabilities | 58 553 | 45 807 | 16 981 | 34 889 |
| Unrealised losses commodity derivatives | 1 624 | 1 083 | - | 7 326 |
| Unrealised losses currency contracts | 154 452 | 183 497 | 34 924 | 367 416 |
| Short-term derivatives included in liabilities | 156 075 | 184 580 | 34 924 | 374 743 |
| Total derivatives included in liabilities | 214 628 | 230 387 | 51 905 | 409 632 |
The group uses various types of financial hedging instruments. Commodity derivatives are used to hedge the price risk of oil and gas and foreign exchange derivatives are used to hedge the group's currency exposure, mainly in NOK, EUR and GBP.
The derivative portfolio is revalued on a mark to market basis, with changes in value recognised in the income statement. The nature of the derivative instruments and the valuation method are consistent with the disclosed information in the annual financial statements as of 31 December 2022. All derivatives are measured at fair value on a recurring basis (level 2 in the fair value hierarchy, except for Cognite put option which is considered level 3).
As of 30 June 2023, the company has foreign exchange contracts to secure USD and EUR value of NOK cashflows for future tax payments and capital expenditure.
| Group | ||||
|---|---|---|---|---|
| Breakdown of other current liabilities (USD 1 000) | 30.06.2023 | 31.03.2023 | 31.12.2022 | 30.06.2022 |
| Balances with license partners | 47 793 | 94 231 | 43 132 | 73 620 |
| Share of other current liabilities in licenses | 514 932 | 502 967 | 460 783 | 409 480 |
| Overlift of petroleum | 20 474 | 24 136 | 30 922 | 113 433 |
| Payroll liabilities, accrued interest and other provisions | 293 681 | 272 071 | 272 276 | 256 390 |
| Total other current liabilities | 876 880 | 893 405 | 807 113 | 852 923 |
| Outstanding | Group | ||||
|---|---|---|---|---|---|
| Senior unsecured bonds (USD 1 000) | amount | 30.06.2023 | 31.03.2023 | 31.12.2022 | 30.06.2022 |
| Senior Notes 3.000% (Jan 20/Jan 25)2) | USD 95.5 mill | 94 079 | 498 391 | 498 172 | 497 733 |
| Senior Notes 2.875% (Sep 20/Jan 26)2) | USD 129.7 mill | 127 900 | 497 990 | 497 813 | 497 458 |
| Senior Notes 2.000% (Jul 21/Jul 26)2)3) | USD 707.1 mill | 651 390 | 913 848 | 907 387 | 894 464 |
| Senior Notes 5.600% (Jun 23/Jun 28)1) | USD 500 mill | 497 185 | - | - | |
| Senior Notes 1.125% (May 21/May 29) | EUR 750 mill | 810 666 | 808 460 | 795 304 | 774 017 |
| Senior Notes 3.750% (Jan 20/Jan 30) | USD 1,000 mill | 994 805 | 994 608 | 994 411 | 994 016 |
| Senior Notes 4.000% (Sep 20/Jan 31) | USD 750 mill | 745 592 | 745 447 | 745 302 | 745 011 |
| Senior Notes 3.100% (Jul 21/Jul 31)3) | USD 1,000 mill | 850 051 | 845 413 | 840 776 | 831 500 |
| Senior Notes 6.000% (Jun 23/Jun 33)1) | USD 1,000 mill | 994 178 | - | - | - |
| Long-term bonds - book value | 5 765 847 | 5 304 158 | 5 279 164 | 5 234 200 | |
| Long-term bonds - fair value | 5 403 561 | 4 972 331 | 4 829 678 | 4 915 338 |
1) In June 2023 the company issued two new US bonds:
USD 500 million aggregate principal amount of 5.6 percent Senior Notes due 2028
USD 1,000 million aggregate principal amount of 6.0 percent Senior Notes due 2033
2) Parts of the proceeds from the new bonds were used to tender for our outstanding bonds maturing in 2025 and 2026. In total we repurchased the following volumes split per bond (principal amount):
USD 404.5 million on USD Senior Notes 3.000% (Jan 2025)
USD 370.3 million on USD Senior Notes 2.875% (Jan 2026)
USD 292.9 million on USD Senior Notes 2.000% (Jul 2026)
The fair value of these bonds were lower than the book value at the time of repurchase. This resulted in a net gain of USD 43.7 million presented as other financial income in Q2.
3) Prior to the repurchase mentioned above, these bonds had a nominal value of USD 1 billion and were recognised at fair value in connection with the Lundin Energy transaction at 30 June 2022. The difference between fair value and nominal value is linearly amortised over the lifetime of the bonds (see note 8).
Interest is paid on a semi annual basis, except for the EUR Senior Notes which is paid on an annual basis. None of the bonds have financial covenants.
| Group | |||
|---|---|---|---|
| 2023 | 2023 | 2022 | |
| (USD 1 000) | Q2 | 01.01.-31.03. | 01.01.-31.12. |
| Provisions as of beginning of period | 4 453 120 | 4 165 598 | 5 172 354 |
| Incurred removal cost | -51 678 | -29 875 | -79 236 |
| Accretion expense | 39 937 | 40 354 | 119 895 |
| Abandonment liabilities from acquisition of Lundin Energy | - | - | 745 900 |
| Foreign currency translation | - | - | 6 692 |
| Impact of changes to discount rate | -211 768 | 273 999 | -1 876 918 |
| Change in estimates and provisions relating to new drilling and installations | 75 068 | 3 044 | 76 911 |
| Total provision for abandonment liabilities | 4 304 680 | 4 453 120 | 4 165 598 |
| Short-term | 143 918 | 144 356 | 115 202 |
| Long-term | 4 160 762 | 4 308 764 | 4 050 396 |
Reference is made to note 1 for a description of change in the accounting principle for abandonment provision from Q4 2022. Following the change in accounting principle, the nominal pre-tax discount rate (risk-free) at end of Q2 is between 3.8 percent and 5.4 percent, depending on the timing of the expected cashflows.The corresponding range at end of Q1 was 3.5 to 4.6 percent. The calculations assume an inflation rate of 2.0 percent.
During the normal course of its business, the group will be involved in disputes, including tax disputes. The group has made accruals for probable liabilities related to litigation and claims based on management's best judgment and in line with IAS 37 and IAS 12.
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 | 30.06.2023 | 31.03.2023 |
|---|---|---|
| Aker BP as operator | 120 | 126 |
| Aker BP as partner | 64 | 68 |
| Changes in production licenses in which Aker BP is the operator: | Changes in production licenses in which Aker BP is a partner: | |||||
|---|---|---|---|---|---|---|
| License: | 30.06.2023 | 31.03.2023 License: | 30.06.2023 | 31.03.2023 | ||
| PL 8302) | 0.000% | 40.000 % PL 782SD2) | 0.000% | 20.000 % | ||
| PL 8861) | 80.000% | 60.000 % PL 917B2) | 0.000% | 40.000 % | ||
| PL 886B1) | 80.000% | 60.000 % PL 10642) | 0.000% | 20.000 % | ||
| PL 9062) | 0.000% | 50.000 % PL 11222) | 0.000% | 20.000 % | ||
| PL 10822) | 0.000% | 50.000 % | ||||
| PL 10952) | 0.000% | 50.000 % | ||||
| PL 11242) | 0.000% | 23.835 % | ||||
| PL 11572) | 0.000% | 60.000 % | ||||
| Total | 2 | 8 Total | - | 4 |
1) License transaction with Sval Energi
2) Relinquished license or Aker BP has withdrawn from the license
End of financial statement
Aker BP may disclose alternative performance measures as part of its financial reporting as a supplement to the financial statements prepared in accordance with IFRS. Aker BP believes that the alternative performance measures provide useful supplemental information to management, investors, security analysts and other stakeholders and are meant to provide an enhanced insight into the financial development of Aker BP's business operations and to improve comparability between periods.
Abandonment spend (abex) is payment for removal and decommissioning of oil fields1)
Capex is disbursements on investments in fixed assets1)
Depreciation per boe is depreciation divided by number of barrels of oil equivalents produced in the corresponding period
Dividend per share (DPS) is dividend paid in the quarter divided by number of shares outstanding
EBITDA is short for earnings before interest and other financial items, taxes, depreciation and amortisation and impairments
EBITDAX is short for earnings before interest and other financial items, taxes, depreciation and amortisation, impairments and exploration expenses
Equity ratio is total equity divided by total assets
Exploration spend (expex) is exploration expenses plus additions to capitalised exploration wells less dry well expenses1)
Free cash flow (FCF) is net cash flow from operating activities less net cash flow from investment activities
Interest coverage ratio is calculated as twelve months rolling EBITDA, divided by interest expenses, excluding any impacts from IFRS 16.
Leverage ratio is calculated as Net interest-bearing debt divided by twelve months rolling EBITDAX, excluding any impacts from IFRS 16
Net interest-bearing debt is book value of current and non-current interest-bearing debt less cash and cash equivalents
Operating profit/loss is short for earnings/loss before interest and other financial items and taxes
Production cost per boe is production expenses based on produced volumes, divided by number of barrels of oil equivalents produced in the corresponding period (see note 3)
1) Includes payments of lease debt as disclosed in note 7.
| Q2 | Q1 | Q2 | 01.01.-30.06. | 01.01.-31.12. | ||
|---|---|---|---|---|---|---|
| Restated | ||||||
| (USD 1 000) | Note | 2023 | 2023 | 2022 | 2023 | 2022 |
| Abandonment spend | ||||||
| Payment for removal and decommissioning of oil fields | 48 445 | 28 564 | 36 204 | 77 008 | 78 870 | |
| Payments of lease debt (abandonment activity) | 7 | 3 612 | 1 518 | 414 | 5 131 | 751 |
| Abandonment spend | 52 057 | 30 082 | 36 618 | 82 139 | 79 621 | |
| Depreciation per boe | ||||||
| Depreciation | 6 | 645 066 | 598 952 | 251 116 | 1 244 018 | 1 785 672 |
| Total produced volumes (boe 1 000) | 3 | 43 742 | 40 742 | 16 494 | 84 484 | 112 853 |
| Depreciation per boe | 14.7 | 14.7 | 15.2 | 14.7 | 15.8 | |
| Dividend per share | ||||||
| Paid dividend | 347 612 | 347 612 | 171 054 | 695 224 | 1 005 731 | |
| Number of shares outstanding | 631 793 | 631 793 | 359 788 | 631 793 | 496 765 | |
| Dividend per share | 0.55 | 0.55 | 0.48 | 1.10 | 2.02 | |
| Capex | ||||||
| Disbursements on investments in fixed assets (excluding capitalised interest) | 663 488 | 597 442 | 270 769 | 1 260 931 | 1 580 045 | |
| Payments of lease debt (investments in fixed assets) CAPEX |
7 | 21 897 685 386 |
17 294 614 737 |
11 649 282 418 |
39 192 1 300 123 |
46 942 1 626 987 |
| EBITDA | ||||||
| Total income | 2 | 3 290 620 | 3 310 354 | 2 026 349 | 6 600 974 | 13 009 898 |
| Production expenses | 3 | -246 953 | -263 338 | -190 394 | -510 291 | -932 870 |
| Exploration expenses | 4 | -27 278 | -97 692 | -67 301 | -124 970 | -242 193 |
| Other operating expenses | -12 649 | -16 161 | -20 098 | -28 810 | -52 577 | |
| EBITDA | 3 003 740 | 2 933 163 | 1 748 556 | 5 936 903 | 11 782 258 | |
| EBITDAX | ||||||
| Total income | 2 | 3 290 620 | 3 310 354 | 2 026 349 | 6 600 974 | 13 009 898 |
| Production expenses | 3 | -246 953 | -263 338 | -190 394 | -510 291 | -932 870 |
| Other operating expenses | -12 649 | -16 161 | -20 098 | -28 810 | -52 577 | |
| EBITDAX | 3 031 018 | 3 030 856 | 1 815 857 | 6 061 873 | 12 024 451 | |
| Equity ratio | ||||||
| Total equity | 12 315 993 | 12 266 874 | 12 427 506 | 12 315 993 | 12 427 506 | |
| Total assets | 37 311 906 | 37 927 999 | 37 561 780 | 37 311 906 | 37 561 780 | |
| Equity ratio | 33% | 32% | 33% | 33% | 33% | |
| Exploration spend | ||||||
| Disbursements on investments in capitalised exploration expenditures | 64 166 | 79 409 | 76 257 | 143 576 | 251 764 | |
| Exploration expenses | 4 | 27 278 | 97 692 | 67 301 | 124 970 | 242 193 |
| Dry well | 4 | -5 043 | -63 771 | -33 676 | -68 814 | -135 800 |
| Payments of lease debt (exploration expenditures) | 7 | 4 528 | 5 927 | 5 725 | 10 455 | 6 222 |
| Exploration spend | 90 930 | 119 257 | 115 607 | 210 187 | 364 380 |
| Q2 | Q1 | Q2 | 01.01.-30.06. | 01.01.-31.12. | ||
|---|---|---|---|---|---|---|
| (USD 1 000) | Note | 2023 | 2023 | 2022 | 2023 | 2022 |
| Interest coverage ratio | ||||||
| Twelve months rolling EBITDA | 13 964 011 | 12 708 828 | 6 563 565 | 13 964 011 | 11 782 258 | |
| Twelve months rolling EBITDA, impacts from IFRS 16 | 7 | -33 829 | -25 672 | -14 200 | -33 829 | -20 835 |
| Twelve months rolling EBITDA, excluding impacts from IFRS 16 | 13 930 182 | 12 683 156 | 6 549 366 | 13 930 182 | 11 761 424 | |
| Twelve months rolling interest expenses | 8 | 186 494 | 169 476 | 126 794 | 186 494 | 154 019 |
| Twelve months rolling amortised loan cost | 8 | 52 421 | 41 861 | 11 723 | 52 421 | 31 815 |
| Twelve months rolling interest income | 8 | 72 058 | 49 973 | 8 583 | 72 058 | 25 959 |
| Net interest expenses | 166 858 | 161 364 | 129 933 | 166 858 | 159 876 | |
| Interest coverage ratio1) | 83.5 | 78.6 | 50.4 | 83.5 | 73.6 | |
| Leverage ratio | ||||||
| Long-term bonds | 14 | 5 765 847 | 5 304 158 | 5 234 200 | 5 765 847 | 5 279 164 |
| Other interest-bearing debt | - | - | 600 000 | - | - | |
| Cash and cash equivalents | 11 | 2 688 845 | 3 280 245 | 2 153 644 | 2 688 845 | 2 756 012 |
| Net interest-bearing debt excluding lease debt | 3 077 002 | 2 023 913 | 3 680 556 | 3 077 002 | 2 523 151 | |
| Twelve months rolling EBITDAX | 14 206 351 | 12 991 190 | 6 868 486 | 14 206 351 | 12 024 451 | |
| Twelve months rolling EBITDAX, impacts from IFRS 16 | 7 | -33 141 | -24 988 | -13 004 | -33 141 | -20 153 |
| Twelve months rolling EBITDAX, excluding impacts from IFRS 16 | 14 173 209 | 12 966 202 | 6 855 482 | 14 173 209 | 12 004 299 | |
| Leverage ratio1) | 0.22 | 0.16 | 0.54 | 0.22 | 0.21 | |
| Net interest-bearing debt | ||||||
| Long-term bonds | 14 | 5 765 847 | 5 304 158 | 5 234 200 | 5 765 847 | 5 279 164 |
| Other interest-bearing debt | - | - | 600 000 | - | - | |
| Long-term lease debt | 7 | 372 075 | 244 428 | 105 742 | 372 075 | 98 095 |
| Short-term lease debt | 7 | 116 290 | 101 216 | 49 035 | 116 290 | 36 298 |
| Cash and cash equivalents | 11 | 2 688 845 | 3 280 245 | 2 153 644 | 2 688 845 | 2 756 012 |
| Net interest-bearing debt | 3 565 366 | 2 369 557 | 3 835 332 | 3 565 366 | 2 657 545 | |
| Free cash flow | ||||||
| Net cash flow from operating activities | 121 338 | 1 682 014 | 1 186 570 | 1 803 352 | 5 729 472 | |
| Net cash flow from investment activities | -776 100 | -705 415 | -1 626 013 | -1 481 515 | -3 116 596 | |
| Free cash flow | -654 762 | 976 599 | -439 443 | 321 837 | 2 612 876 |
1) These ratios are calculated based on Aker BP group figures only, with no proforma adjustments for the Lundin Energy transaction.
Operating profit/loss see Income Statement
Production cost per boe see note 3
Pursuant to the Norwegian Securities Trading Act section § 5-6 with pertaining regulations, we hereby confirm that, to the best of our knowledge, the company's interim financial statements for the period 1 January to 30 June 2023 have been prepared in accordance with IAS 34, as endorsed by the EU, and in accordance with the requirements for additional information provided for by the Norwegian Accounting Act. The information presented in the financial statements gives a true and fair picture of the company's liabilities, financial position and results overall.
To the best of our knowledge, the Board of Directors' half-yearly report together with the yearly report, gives a true and fair picture of the development, performance and financial position of the company, and includes a description of the principal risk and uncertainty factors facing the company.
| The Board of Directors and the CEO of Aker BP ASA | ||
|---|---|---|
| Akerkvartalet, 12 July 2023 |
| Øyvind Eriksen, Chair of the Board | Kjell Inge Røkke, Board member |
|---|---|
| Anne Marie Cannon, Deputy Chair | Trond Brandsrud, Board member |
| Valborg Lundegaard, Board member | Murray Auchincloss, Board member |
| Ingard Haugeberg, Board member | Terje Solheim, Board member |
| Tore Vik, Board member | Kate Thomson, Board member |
| Charles Heppenstall, Board member | Hilde Kristin Brevik, Board member |
Karl Johnny Hersvik, Chief Executive Officer
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 June 2023, and the related condensed consolidated income statement, the statement of comprehensive income, the statement of changes in equity and the cash flow statement for the three-month and six-month periods 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, 12 July 2023 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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