Quarterly Report • Jul 14, 2020
Quarterly Report
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Aker BP delivered strong operational performance and record high production in the second quarter. The company's field developments progressed as planned, including a successful start-up of the first Ærfugl phase 2 well. Following the recently introduced temporary changes to the Norwegian petroleum tax system, the company has submitted the plan for development for Hod and entered into an agreement with Equinor on commercial terms for a coordinated NOAKA development.
Aker BP has implemented a wide range of measures to minimise the risk to people and operations from the COVID-19 pandemic, including reduced offshore manning, social distancing, travel restrictions and working from home. During the quarter, the company has implemented mandatory testing for all offshore personnel. The company has so far avoided any virus-related disruptions to its operations and will continue to enforce proper measures to minimise the risk level.
The company's net production in the second quarter was 209.8 (208.1) thousand barrels of oil equivalents per day (mboepd). Net sold volume was 232.0 (207.5) mboepd. Production efficiency remained high and was not significantly impacted by COVID-19. The production curtailments imposed by the Norwegian government have been mitigated by strong operational performance and increased capacity at Johan Sverdrup, hence the company maintains its full-year production estimate of 205-220 mboepd.
Total income for the second quarter amounted to USD 590 (872) million, negatively impacted by low oil prices following the COVID-19 pandemic. Average realised liquids price was USD 29.9 (44.7) per barrel, while the realised price for natural gas averaged USD 0.08 (0.14) per standard cubic metre (scm).
Production costs for the oil and gas sold in the quarter amounted to USD 196 (156) million. Production cost per produced barrel oil equivalents (boe) increased slightly to USD 9.1 (8.7), impacted by well maintenance costs which are expected to be reduced in the coming quarters. The company maintains its guidance of USD 7-8 per boe on average for the full year.
Exploration expenses amounted to USD 50 (50) million and included costs of the Sandia well which was dry. Total cash spend on exploration was USD 59 (53) million. The company's expected exploration spend is around USD 350 million for the full year, in line with previous guidance.
Depreciation was USD 286 (277) million, equivalent to USD 15.0 (14.6) per boe. The sharp drop in oil prices caused an impairment charge of USD 654 million in the first quarter. Due to recovering oil prices, reversal of prior period impairments amounted to USD 136 million in the second quarter.
Net financial expenses were USD 27 (149) million in the quarter. Profit before taxes amounted to USD 151 million, compared to a loss before taxes of USD 414 million in the first quarter. Tax credit was USD 19 (80) million due to a catch-up effect from the first quarter of the increased uplift introduced as part of the recently implemented temporary changes to the Petroleum Tax Law and by a positive currency effect on the value of the company's tax balances.
Overall, the company reported a net profit of USD 170 million for the quarter, compared to a net loss of USD 335 in the previous quarter.
Investments in fixed assets amounted to USD 360 (343) million in the second quarter. All field development projects progressed according to plan. Abandonment expenditures were USD 16 (22) million.
Certain temporary changes in the Petroleum Tax Law were enacted on 19 June 2020. These changes included a temporary ruling for depreciation and uplift, whereas all investments incurred for income years 2020 and 2021 including 24 percent uplift can be deducted from the basis for special tax in the year of investment. These changes also apply for all investments according to Plans for Development and Operation delivered by the end of 2022. In addition, the tax value of any losses incurred in 2020 and 2021 can be refunded from the state.
Following these changes Aker BP has submitted the Plan for Development and Operation for Hod. The Hod field will be developed as a copy of the Valhall Flank West development, with a normally unmanned installation remotely controlled from the Valhall field centre. Total investments for the development are estimated at around USD 600 million and the recoverable reserves are estimated at around 40 million barrels of oil equivalents. Work is already well underway at the yard at Kvaerner Verdal.
During the quarter, Aker BP and Equinor entered into an agreement in principle on commercial terms for a coordinated development of the NOAKA area. The companies have started preparations for submitting Plans for Development and Operation in 2022.
Maintaining a strong financial position is a key strategic priority for Aker BP. At the end of the second quarter Aker BP had USD 3.7 (4.0) billion in available liquidity. Net interest-bearing debt was USD 3.8 (3.5) billion, including 0.2 (0.3) billion in lease debt.
In May, the company disbursed dividends of USD 70.8 million, equivalent to USD 0.1967 per share. The Board has resolved to pay a quarterly dividend of USD 70.8 million (USD 0.1967 per share) in August 2020. It is the Board's ambition to maintain this level through the fourth quarter, implying total dividend payments of USD 425 million for the full year.
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 | Q2 2020 | Q1 2020 | Q2 2019 | 2020 YTD | 2019 YTD | |
|---|---|---|---|---|---|---|
| Total income | USDm | 590 | 872 | 785 | 1 462 | 1 621 |
| EBITDA | USDm | 329 | 666 | 522 | 994 | 1 061 |
| Net profit/loss | USDm | 170 | -335 | 62 | -165 | 73 |
| Earnings per share (EPS) | USD | 0.47 | -0.93 | 0.17 | -0.46 | 0.20 |
| Capex | USDm | 372 | 360 | 397 | 732 | 740 |
| Exploration spend | USDm | 59 | 53 | 119 | 112 | 278 |
| Abandonment spend | USDm | 16 | 22 | 41 | 39 | 62 |
| Production cost | USD/boe | 9.1 | 8.7 | 15.4 | 8.9 | 14.3 |
| Taxes paid | USDm | 81 | 48 | 208 | 129 | 314 |
| Net interest-bearing debt* | USDm | 3 806 | 3 548 | 2 907 | 3 806 | 2 907 |
| Leverage ratio | 1.5 | 1.2 | 0.9 | 1.5 | 0.9 |
*The definition of net interest-bearing debt includes Lease debt. See also the description of "Alternative performance measures" at the end of this report for definitions.
| UNIT | Q2 2020 | Q1 2020 | Q2 2019 | 2020 YTD | 2019 YTD | |
|---|---|---|---|---|---|---|
| Alvheim area | mboepd | 58.0 | 57.5 | 53.1 | 57.8 | 55.0 |
| Ivar Aasen | mboepd | 22.1 | 22.7 | 19.1 | 22.4 | 20.8 |
| Johan Sverdrup | mboepd | 51.0 | 43.9 | - | 47.5 | - |
| Skarv | mboepd | 20.6 | 19.8 | 22.7 | 20.2 | 22.6 |
| Ula area | mboepd | 10.4 | 12.8 | 6.2 | 11.6 | 7.2 |
| Valhall area | mboepd | 47.0 | 50.1 | 24.5 | 48.5 | 35.1 |
| Other | mboepd | 0.6 | 1.4 | 1.7 | 1.0 | 2.2 |
| Net production | mboepd | 209.8 | 208.1 | 127.3 | 208.9 | 142.9 |
| Over/underlift | mboepd | 22.2 | -0.6 | 13.4 | 10.8 | 8.4 |
| Net sold volume | mboepd | 232.0 | 207.5 | 140.7 | 219.7 | 151.3 |
| - liquids | mboepd | 198.2 | 174.3 | 112.8 | 186.2 | 120.8 |
| - natural gas | mboepd | 33.8 | 33.2 | 27.9 | 33.5 | 30.5 |
| Realised price liquids | USD/boe | 29.9 | 44.7 | 69.3 | 36.8 | 66.4 |
| Realised price natural gas | USD/scm | 0.08 | 0.14 | 0.16 | 0.11 | 0.20 |
| (USD MILLION) | Q2 2020 | Q1 2020 | Q2 2019 | 2020 YTD | 2019 YTD |
|---|---|---|---|---|---|
| Total income | 590 | 872 | 785 | 1 462 | 1 621 |
| EBITDA | 329 | 666 | 522 | 994 | 1 061 |
| EBIT | 178 | -266 | 354 | -87 | 641 |
| Pre-tax profit | 151 | -414 | 268 | -263 | 517 |
| Net profit | 170 | -335 | 62 | -165 | 73 |
| EPS (USD) | 0.47 | -0.93 | 0.17 | -0.46 | 0.20 |
Total income in the second quarter 2020 amounted to USD 590 (872) million. The decrease compared to the previous quarter is due to the sharp decrease in realised prices. Realised prices declined by 33 percent for liquids and 40 percent for natural gas. The price effect on total income was partly offset by a significant increase in sold volumes to 232.0 (207.5) mboepd, due to strong production and overlift.
The company is using oil put options in its hedging program to protect near-term cash flow against sharp drops in the oil price. In the second quarter, the company realised gains on these instruments of USD 56 million before tax (subject to ordinary corporate tax). This was however offset by a reversal of unrealised gains recognised in previous periods and the net effect on other income from the hedging program was therefore slightly negative for the quarter. Adjusted for the differences in taxation, the average realised liquids price including hedging was equivalent to USD 40.9 per barrel in the second quarter.
Production costs related to oil and gas sold in the quarter amounted to USD 196 (156) million. Production cost per produced unit in the quarter amounted to USD 9.1 (8.7) per boe, impacted by well maintenance costs which are expected to be reduced in the coming quarters.
Exploration expenses amounted to USD 50 (50) million and included purchase of seismic of USD 22 (2) million and costs for the Sandia well, which was drilled and concluded as dry.
Depreciation amounted to USD 286 (277) million. The depreciation per produced boe was stable at USD 15.0 (14.6). The sharp drop in oil prices caused an impairment charge of USD 654 million in the first quarter. Following the partial recovery in spot and forward oil prices observed in the second quarter the company has reversed certain impairments amounting to USD 136 million.
Operating profit was USD 178 million compared to an operating loss of USD 266 million in the previous quarter. Net financial expenses amounted to USD 27 (149) million. The decrease compared to the previous quarter mainly reflects the losses on currency positions and derivatives in the first quarter.
Profit before taxes amounted to USD 151 million, compared to a loss before taxes of USD 414 million in the first quarter. Tax credit was USD 19 million, mainly caused by a catch-up effect from the first quarter of the increased uplift introduced as part of the recently implemented temporary changes to the Petroleum Tax Law and by a positive currency effect on the value of the company's tax balances. This compares to a tax credit of USD 80 million in the previous quarter.
This resulted in a net profit for the second quarter 2020 of USD 170 million, compared to a net loss of USD 335 million in the previous quarter.
| (USD MILLION) | Q2 2020 | Q1 2020 | Q4 2019 | Q2 2019 |
|---|---|---|---|---|
| Total non-current assets | 11 050 | 10 913 | 11 508 | 10 889 |
| Total current assets | 839 | 814 | 719 | 603 |
| Total assets | 11 889 | 11 727 | 12 227 | 11 493 |
| Total equity | 1 912 | 1 813 | 2 368 | 2 664 |
| Bank and bond debt | 3 712 | 3 593 | 3 287 | 2 635 |
| Total abandonment provisions | 2 817 | 2 795 | 2 788 | 2 607 |
| Deferred taxes | 2 471 | 2 153 | 2 235 | 1 991 |
| Other liabilities | 976 | 1 372 | 1 549 | 1 596 |
| Total equity and liabilities | 11 889 | 11 727 | 12 227 | 11 493 |
| Net interest-bearing debt | 3 806 | 3 548 | 3 493 | 2 907 |
At the end of the second quarter 2020, total assets amounted to USD 11,889 (11,727) million, of which current assets were USD 839 (814) million.
Equity amounted to USD 1,912 (1,813) million at the end of the quarter, corresponding to an equity ratio of 16 (15) percent.
Deferred tax liabilities amounted to USD 2,471 (2,153) million. The main reason for the increase is the recently implemented temporary changes to the Petroleum Tax Law, which contributes to increase in deferred tax liabilities and decrease in tax payable. See note 9 to the financial statements for further details.
Bank and bond debt totalled USD 3,712 (3,593) million, of which bonds made up 90 percent.
At the end of the first quarter, the company had total available liquidity of USD 3.7 (4.0) billion, comprising USD 142 (323) million in cash and cash equivalents, and USD 3.6 (3.7) billion in undrawn credit facilities.
| (USD MILLION) | Q2 2020 | Q1 2020 | Q2 2019 | 2020 YTD | 2019 YTD |
|---|---|---|---|---|---|
| Cash flow from operations | 162 | 524 | 387 | 686 | 977 |
| Cash flow from investments | -339 | -395 | -541 | -734 | -1 052 |
| Cash flow from financing | -2 | 86 | 141 | 84 | 132 |
| Net change in cash & cash equivalents | -179 | 215 | -13 | 36 | 57 |
| Cash and cash equivalents | 142 | 323 | 102 | 142 | 102 |
Net cash flow from operating activities was USD 162 (524) million in the quarter. The main reason for the reduction was lower realised oil and gas prices. Taxes paid were USD 81 (48) million.
Net cash used for investment activities was USD 339 (395) million, of which investments in fixed assets amounted to USD 360 (343) million for the quarter. Investments in capitalised exploration were USD 19 (31) million, and payments for decommissioning activities amounted to USD 15 (21) million in the quarter.
Net cash flow from financing activities was negative at USD 2 million, compared to a positive net cash flow from financing activities of USD 86 million in the previous quarter. Dividend disbursements of USD 71 (213) million and payments on lease debt of USD 30 (32) million was almost offset by a drawdown of USD 98 (-1,150) of the revolving credit facility.
The company seeks to reduce the risk related to foreign exchange, interest rates and commodity prices through hedging instruments. The company actively manages its exposures through a mix of forward contracts and options.
The following table shows the company's inventory of oil put options at the time of this report:
| OIL PUT OPTIONS | Q3 2020 | Q4 2020 |
|---|---|---|
| Share of oil prod. covered (after tax) | 85 % | 79 % |
| Average strike (USD/bbl) | 30 | 30 |
| Average premium (USD/bbl) | 1.9 | 1.9 |
At the Annual General Meeting in April 2020, the Board was authorised to approve the distribution of dividends based on the company's annual accounts for 2019 pursuant to section 8-2 (2) of the Norwegian Public Limited Companies Act.
In February, the company disbursed dividends of USD 212.5 million, corresponding to USD 0.5901 per share. In May, the company disbursed dividends of USD 70.8 million, equivalent to USD 0.1967 per share.
On 13 July 2020, the Board declared a dividend of USD 0.1967 per share, to be disbursed on or around 10 August. It is the Board's ambition to maintain this level through the fourth quarter, implying total dividend payments of USD 425 million for the full year.
Aker BP's net production was 19.1 (18.9) mmboe in the second quarter of 2020, corresponding to 209.8 (208.1) mboepd. Due to overlift, net sold volume represented 232.0 (207.5) mboepd. The average realised liquids price was USD 29.9 (44.7) per barrel, while the average realised gas price was USD 0.08 (0.14) per scm.
| Key figures | Aker BP interest | Q2 2020 | Q1 2020 | Q4 2019 | Q3 2019 | Q2 2019 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Alvheim | 65 % | 33 770 | 36 995 | 36 588 | 36 826 | 39 943 |
| Bøyla | 65 % | 6 568 | 7 631 | 7 534 | 4 490 | 2 364 |
| Skogul | 65 % | 7 899 | 1 622 | - | - | - |
| Vilje | 46.904 % | 3 259 | 3 472 | 3 279 | - | 2 300 |
| Volund | 65 % | 6 511 | 7 774 | 9 040 | 10 088 | 8 518 |
| Total production | 58 006 | 57 494 | 56 441 | 51 403 | 53 125 | |
| Production efficiency | 96 % | 98 % | 98 % | 96 % | 97 % |
Production from Skogul commenced in March and contributed to high and stable production at Alvheim in the second quarter. Optimal use of the gas handling facilities, deferred water breakthrough in several of the fields and continued high production efficiency also contributed to good operational results during the quarter and mitigated the effect of the production curtailments implemented by the Ministry of Petroleum and Energy (MPE) from June.
Drilling of the Kameleon Infill Mid well started in late March with the Semi-submersible rig Deepsea Nordkapp. Challenges in the overburden section of the well resulted in delays in getting down to the reservoir section. However, first oil is still expected during the fourth quarter.
Test production at Frosk continued through the Bøyla template. Development of the Frosk discovery has been further matured and the partners agreed to enter the concept phase during the quarter. The ambition is to select a concept by the end of 2020. The existing test production permit is valid until August 2020. The company will apply for an extended permit.
During the quarter a new subsea tie-back well has been matured as a new tri-lateral production well drilled from the Boa extension manifold to the southern Boa area. The planned spud for this well is in the fourth quarter with first oil during the second quarter next year. The well is a part of the strategy to arrest production decline in the Alvheim area.
| Key figures | Aker BP interest | Q2 2020 | Q1 2020 | Q4 2019 | Q3 2019 | Q2 2019 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Total production | 34.7862 % | 22 089 | 22 705 | 23 139 | 22 481 | 19 069 |
| Production efficiency | 98 % | 97 % | 97 % | 94 % | 87 % |
Ivar Aasen maintained high production efficiency during the quarter. The lower production in the second quarter compared to the first quarter mainly reflects reduced offtake in order to manage reservoir pressure. Ivar Aasen is targeting higher voidage replacement in 2020 which implies higher water injection than production. Production was also negatively impacted by the production curtailments implemented by the MPE. A maintenance shutdown originally planned for execution in June has been rescheduled to late August.
During the quarter a two-well IOR campaign has been matured for execution. The first well is scheduled to be spud by end of August. The campaign will be completed by the end of the year.
The licence partners in the Hanz development are currently considering a re-start of the work to mature the development. The work was put on hold earlier this year in response to the high market uncertainty.
From 2022 the Johan Sverdrup field will supply the fields on the Utsira high with power from shore. During the second quarter, the area's licence partners have formalised the area solution.
The Sørvesten exploration well will be drilled in the neighbouring PL 780 licence during the next quarter. Spirit Energy Norway is the operator and Aker BP has a 40 percent ownership interest.
| Key figures | Aker BP interest | Q2 2020 | Q1 2020 | Q4 2019 | Q3 2019 | Q2 2019 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Total production | 11.5733 % | 51 027 | 43 877 | 31 521 | - | - |
The ramp-up of production from Johan Sverdrup continued safely through the second quarter. Late April the oil production at the field reached the new phase 1 plateau of 470 thousand barrels of oil per day ("mbblpd"), after a successful debottlenecking of the process plant. However, production was negatively impacted by the production curtailments implemented by the MPE.
Phase 2 of the Johan Sverdrup development progressed according to plan, despite challenges caused by COVID-19 at several construction sites. The debottlenecking measures on the phase 1 process plant is also being implemented on the phase 2 process plant, increasing the total field oil process capacity from 660 mbblpd to 690 mbblpd.
During the quarter two new production wells were successfully drilled from the fixed rig drilling platform. Overall, 11 wells have now been put on stream.
| Key figures | Aker BP interest | Q2 2020 | Q1 2020 | Q4 2019 | Q3 2019 | Q2 2019 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Total production | 23.835 % | 20 599 | 19 788 | 22 119 | 21 717 | 22 657 |
| Production efficiency | 97 % | 99 % | 100 % | 98 % | 98 % |
Production efficiency remained high at Skarv during the second quarter. Production decline was arrested by the start-up of production from Ærfugl Phase 2 in April. The production start was characterised by quick turnaround from drilling to production. A successful clean-out was conducted to remove drilling and completion fluids from the well. However, oil wells at Skarv were shut-in during the final week of June in order to stay within the production permit following the production curtailments implemented by the MPE.
Phase 1 of the Ærfugl development project progressed well during the quarter. Installation and tie-in of static umbilicals and installation of subsea production jumpers were completed. The pipelay campaign is scheduled for the third quarter and the project remains on schedule for production to start in the fourth quarter 2020.
Phase 2 of the Ærfugl development project is progressing according to plan. A pre-lay rock installation campaign has been successfully completed. Production is expected to start for the two remaining wells in the fourth quarter next year.
| Key figures | Aker BP interest | Q2 2020 | Q1 2020 | Q4 2019 | Q3 2019 | Q2 2019 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Ula | 80 % | 4 250 | 5 512 | 4 339 | 4 751 | 2 811 |
| Tambar | 55 % | 2 932 | 3 642 | 3 054 | 2 531 | 1 455 |
| Oda | 15 % | 3 258 | 3 623 | 3 713 | 1 280 | 1 949 |
| Total production | 10 441 | 12 777 | 11 106 | 8 562 | 6 214 | |
| Production efficiency* | 80 % | 88 % | 78 % | 76 % | 46 % |
*Oda not included.
Production from the Ula and Tambar fields decreased in the second quarter due to the revised production permits following the production curtailments implemented by the MPE. In addition, a planned maintenance shut down and a temporary shut-in of a Tambar well led to a decrease in production. Production from the Oda field decreased due to corrective work on the chemical injection system.
Maersk Integrator finalised drilling at Ula during the second quarter. Four wells were successfully completed during the campaign, which started in July last year.
| Key figures | Aker BP interest | Q2 2020 | Q1 2020 | Q4 2019 | Q3 2019 | Q2 2019 |
|---|---|---|---|---|---|---|
| Production, boepd | ||||||
| Valhall | 90 % | 46 750 | 49 093 | 44 205 | 39 403 | 23 896 |
| Hod | 90 % | 225 | 982 | 1 176 | 880 | 618 |
| Total production | 46 975 | 50 075 | 45 381 | 40 283 | 24 514 | |
| Production efficiency | 78 % | 88 % | 90 % | 87 % | 53 % |
Second quarter production from Valhall decreased slightly from the previous quarter. This was mainly driven by a planned shutdown in June, thus Valhall production was not constrained by the production curtailments implemented by the MPE.
At Valhall Flank West two new wells were brought on stream during the quarter. Maersk Invincible has now concluded the nine well drilling campaign, but the rig will remain at Flank West to support stimulation operations. The rig will be moved to the field centre for plugging of wells at the old DP platform later this year.
A plan for development and operations (PDO) for the re-development of the Hod field was submitted to the authorities on 24 June. Hod is among the first projects to be realised under the temporary changes to the Norwegian petroleum tax system recently introduced.
The Hod field will be developed in collaboration with Aker BP's alliance partners with a normally unmanned installation remotely controlled from the Valhall field centre, with very low CO2 emissions due to power from shore. Total investments for the Hod development are estimated at around USD 600 million (gross). Production start is planned for first quarter 2022, and the recoverable reserves are estimated at around 40 million barrels of oil equivalents.
The NOAKA area 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 more than 500 million barrels of oil equivalents, with further exploration and appraisal potential.
During the quarter Aker BP and Equinor have entered into an agreement in principle on commercial terms for a coordinated development of the licences Krafla, Fulla and North of Alvheim (NOAKA) on the Norwegian Continental Shelf and have started preparations for submitting Plans for Development and Operation (PDO) in 2022.
The plans for the area consist of a processing platform in the South operated by Aker BP, an unmanned processing platform in the North operated by Equinor and several satellite platforms and tiebacks to cover the various discoveries. The concept will be further optimised prior to submitting the PDO.
Aker BP has established a project team to lead the company's activities in the early phase of the project until concept selection. The partners in the licences are Aker BP, Equinor and LOTOS.
Total exploration spend in the second quarter was USD 59 (53) million, while USD 50 (50) million was recognised as exploration expenses in the period, relating to dry well costs, seismic, area fees, field evaluation and G&G costs.
The company participated in one exploration well in the quarter, on the Sandia prospect in licence 719 in the Barents Sea. Aker BP has a 20 percent working interest in the licence. The well, which was operated by Spirit Energy Norge AS, was dry.
In February, Aker BP entered into an agreement with PGNiG Upstream Norway AS to swap its 3.3 percent interest in the non-operated Gina Krog field and an 11.9175 percent interest in licence 127C, in exchange for a 5 percent interest and operatorship in licence 838 and a cash consideration of up to USD 62 million.
Licence 838 is located near Skarv and contains the recent Shrek discovery as well as further exploration potential. Licence 127C contains the Alve Nord discovery and the Alve NE prospect, which is also located in the Skarv area. After the transaction, Aker BP holds 35 percent interest in licence 838 and 88.0825 percent interest in licence 127C, while it has fully divested its interest in the Gina Krog field.
The cash consideration consists of a firm payment of USD 51 million upon closing and an additional payment of USD 11 million contingent on progressing a development of the Alve Nord discovery. The transaction was completed on 30 April 2020, hence the second quarter cash flow from investment activities increased by USD 55 million (including working capital adjustments). A gain of USD 5 million has been recognised under "Other income" in the Income statement.
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 2020 | Q1 2020 | Q4 2019 | Q3 2019 | Q2 2019 |
|---|---|---|---|---|---|---|
| Total recordable injury frequency (TRIF) | Per mill. exp. hours | 1.5 | 0.4 | 2.0 | 2.7 | 4.0 |
| Serious incident frequency (SIF) | Per mill. exp. hours | 0.5 | 0 | 0.8 | 0.4 | 0.8 |
| Loss of primary containment (LOPC) | Count | 0 | 0 | 0 | 0 | 0 |
| Process safety events Tier 1 and 2 | Count | 0 | 0 | 0 | 0 | 0 |
| CO2 emissions intensity* | Kg CO2/boe | 4.6 | 5.1 | 7.9 | 8.1 | 8.1 |
* From Q1 2020 Aker BP reports equity-based CO2-intensity. This includes equity share (financial ownership interest) of non-operated and operated assets based on scope 1 emissions. The figures for previous periods are not restated and only apply for operated assets (gross).
The COVID-19 barriers and preventative measures to protect personnel have been effective and will remain in place as long as necessary.
The company continues to work systematically to maintain safe and reliable operations as activity returns to more normal levels and this is being addressed through a safety summer campaign initiated in June at all operated assets.
| UNIT | PER 30 JUNE 2020 | PER 30 JUNE 2019 | |
|---|---|---|---|
| Oil and gas production | mboepd | 208.9 | 142.9 |
| Realised price liquids | USD/boe | 36.8 | 66.4 |
| Total income | USDm | 1 462 | 1 621 |
| EBITDA | USDm | 994 | 1 061 |
| Net profit | USDm | -165 | 73 |
| Net interest-bearing debt | USDm | 3 806 | 2 907 |
The first half of 2020 was extraordinary. Aker BP delivered strong operational performance and set new production records. This was however overshadowed by the COVID-19 pandemic and the sharp drop in global oil prices. The company's key priorities in this challenging situation have been, and continue to be, to safeguard its people, its production and its financial capacity.
In order to secure its financial strength in response to the uncertainty caused by the COVID-19 situation and the sharp reduction in oil prices, Aker BP made significant changes to its investment program presented at the company's Capital Markets Update in February 2020. All non-sanctioned field development projects were put on hold, and several exploration wells were postponed. The Board also decided to retract the original dividend plan in order to retain financial flexibility and position the company for future value accretive organic and inorganic growth opportunities.
In June 2020, the Norwegian parliament (Stortinget) approved a set of temporary changes to the petroleum tax system to stimulate investments in the Norwegian petroleum sector. Aker BP subsequently sanctioned the Hod field development. In addition, Aker BP and Equinor entered into an agreement in principle on commercial terms for a coordinated development of the NOAKA area. Aker BP and Equinor have started preparations for submitting Plans for Development and Operation in 2022.
During the first six months of 2020, the company reported consolidated revenues of USD 1,462 (1,621)* million. Production in the period was 208.9 (142.9) thousand barrels of oil equivalent per day (mboepd). Average realised liquids prices were USD 36.8 (66.4) per barrel of oil equivalents and USD 0.11 (0.20) per standard cubic metre of natural gas. The increase in production compared to first half last year was mainly due to the successful production start at Johan Sverdrup in the fourth quarter 2019.
Production costs for the oil and gas sold were USD 352 (399) million. Production costs were USD 8.9 (14.3) per produced boe. The decrease per boe was driven by higher production, weaker NOK and the postponements of non-critical activities in response to the COVID-19 pandemic.
Exploration expenses amounted to USD 100 (151) million. EBITDA amounted to USD 994 (1,061) million and EBIT was USD -87 (641) million. Net loss for the first half of 2020 was USD 165 million, compared to a net profit of USD 73 million for the first half of 2019.
Net cash flow to investment activities amounted to USD 734 (1,052) million, driven by field development activities across the company's portfolio.
The company further strengthened its liquidity by issuing USD 1.5 billion in new long-dated bonds at attractive terms in January. Furthermore, the maturity for USD 2 billion of the company's bank facility (RCF) was in April extended by one year from 2024 to 2025.
As of 30 June 2020, the company had net interest-bearing debt of USD 3,806 (2,907) million. Available liquidity was USD 3.7 (3.3) billion comprising of cash and cash equivalents of USD 142 (102) million and undrawn credit facilities of USD 3.6 (3.2) billion.
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 delivered strong HSSE performance during the first half of 2020, with a strong safety record, efficient management of the COVID-19 situation and record low CO2 emissions per unit produced.
* In the report for the first-half 2020 all figures in brackets apply to first-half 2019.
As an oil and gas company operating on the Norwegian Continental Shelf, exploration results, reserve and resource estimates and estimates for capital and operating expenditures are associated with uncertainty. The production performance of oil and gas fields may be variable over time.
The company is exposed to various forms of financial risks, including, but not limited to, fluctuation in oil prices, exchange rates, interest rates and capital requirements; these are described in the company's annual report and accounts, and in note 29 to the accounts for 2019. The company is also exposed to uncertainties relating to the international capital markets and access to capital and this may influence the speed with which development projects can be brought on stream.
The COVID-19 pandemic has created increased uncertainty and disruption to the global economy and potentially longer-term impact on demand for oil and gas. This represents a risk to the company's future price realisations, results from operations, cash flows, financial condition and access to capital. The pandemic also represents an additional risk of interruptions to the company's operations with potential negative effect on the company's results from operations and cash flows, as it could lead to temporary production shortfalls, increased costs and / or delays or cancellations to the company's investment program. Correspondingly, there is also a risk of future impairments of the book value of the company's assets.
The COVID-19 pandemic and the sharp drop in oil prices have created challenges for the oil industry. Under these extraordinary circumstances, Aker BP's main financial priorities are to secure the company's financial robustness, to protect its investment grade credit profile, and to maintain financial flexibility to pursue value-accretive growth opportunities going forward.
Four months into the COVID-19 situation, the financial position continues to be very robust, and the company remains well prepared for future value creation.
The recently introduced changes to Norwegian petroleum tax incentivise investment activity through improved liquidity and project economics. Subsequent to these changes, Aker BP launched the Hod development project, and continues to mature other projects.
Compared with the guiding provided in the report for the first quarter, the company's capex estimate has been increased to reflect the Hod development decision. The main items of the company's updated financial plan for 2020 are as follows*:
* The majority of the company's cost elements (both capex and production cost) are denominated in NOK. The estimated USD amounts are based on an USDNOK exchange rate of 10.0.
| Group | ||||||
|---|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | |||
| (USD 1 000) | Note | 2020 | 2020 | 2019 | 2020 | 2019 |
| Petroleum revenues | 584 170 | 779 084 | 780 071 | 1 363 254 | 1 638 176 | |
| Other income | 5 614 | 93 021 | 4 744 | 98 635 | -17 098 | |
| Total income | 2 | 589 784 | 872 105 | 784 816 | 1 461 889 | 1 621 077 |
| Production costs | 3 | 196 174 | 156 043 | 198 320 | 352 217 | 398 783 |
| Exploration expenses | 4 | 49 774 | 50 336 | 60 261 | 100 110 | 150 621 |
| Depreciation | 6 | 286 353 | 277 412 | 167 889 | 563 765 | 350 991 |
| Impairments | 5, 6 | -135 872 | 653 697 | - | 517 825 | 68 941 |
| Other operating expenses | 14 897 | 223 | 3 882 | 15 120 | 10 740 | |
| Total operating expenses | 411 326 | 1 137 711 | 430 352 | 1 549 038 | 980 076 | |
| Operating profit/loss | 178 458 | -265 606 | 354 464 | -87 148 | 641 002 | |
| Interest income | 1 224 | 1 369 | 6 735 | 2 593 | 12 799 | |
| Other financial income | 112 550 | 108 709 | 6 872 | 82 203 | 16 591 | |
| Interest expenses | 47 430 | 40 041 | 15 532 | 87 471 | 29 361 | |
| Other financial expenses | 93 762 | 218 729 | 84 307 | 173 435 | 123 642 | |
| Net financial items | 8 | -27 418 | -148 691 | -86 232 | -176 110 | -123 613 |
| Profit/loss before taxes | 151 040 | -414 298 | 268 232 | -263 258 | 517 388 | |
| Tax expense (+)/income (-) | 9 | -18 649 | -79 564 | 205 734 | -98 213 | 444 465 |
| Net profit/loss | 169 689 | -334 734 | 62 498 | -165 045 | 72 923 | |
| Weighted average no. of shares outstanding basic and diluted Basic and diluted earnings/loss USD per share |
359 613 509 0.47 |
359 984 388 -0.93 |
360 059 807 0.17 |
359 798 949 -0.46 |
360 086 510 0.20 |
| Group | |||||
|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | ||
| (USD 1 000) Note |
2020 | 2020 | 2019 | 2020 | 2019 |
| Profit/loss for the period | 169 689 | -334 734 | 62 498 | -165 045 | 72 923 |
| Total comprehensive income/loss in period | 169 689 | -334 734 | 62 498 | -165 045 | 72 923 |
| Group | |||||
|---|---|---|---|---|---|
| (USD 1 000) | Note | 30.06.2020 | 31.03.2020 | 31.12.2019 | 30.06.2019 |
| ASSETS | |||||
| Intangible assets | |||||
| Goodwill | 6 | 1 647 436 | 1 647 436 | 1 712 809 | 1 791 185 |
| Capitalized exploration expenditures | 6 | 487 027 | 478 761 | 621 315 | 554 293 |
| Other intangible assets | 6 | 1 566 521 | 1 522 389 | 1 915 968 | 1 967 332 |
| Tangible fixed assets | |||||
| Property, plant and equipment | 6 | 7 175 129 | 7 060 700 | 7 023 276 | 6 299 710 |
| Right-of-use assets | 6 | 137 296 | 170 834 | 194 328 | 238 879 |
| Financial assets | |||||
| Long-term receivables | 25 535 | 23 400 | 27 418 | 27 333 | |
| Other non-current assets | 10 709 | 9 869 | 10 364 | 10 416 | |
| Long-term derivatives | 12 | - | - | 2 706 | - |
| Total non-current assets | 11 049 653 | 10 913 389 | 11 508 183 | 10 889 148 | |
| Inventories | |||||
| Inventories | 99 324 | 97 337 | 87 539 | 99 205 | |
| Receivables | |||||
| Accounts receivable | 82 722 | 19 529 | 193 444 | 124 623 | |
| Tax receivables | 9 | 186 630 | - | - | 17 418 |
| Other short-term receivables | 10 | 327 922 | 307 635 | 330 516 | 259 518 |
| Short-term derivatives | 12 | - | 66 611 | - | 840 |
| Cash and cash equivalents | |||||
| Cash and cash equivalents | 11 | 142 333 | 322 789 | 107 104 | 101 828 |
| Total current assets | 838 931 | 813 902 | 718 603 | 603 432 | |
| TOTAL ASSETS | 11 888 584 | 11 727 291 | 12 226 786 | 11 492 580 |
| Group | ||||||
|---|---|---|---|---|---|---|
| (USD 1 000) | Note | 30.06.2020 | 31.03.2020 | 31.12.2019 | 30.06.2019 | |
| EQUITY AND LIABILITIES | ||||||
| Equity | ||||||
| Share capital | 57 056 | 57 056 | 57 056 | 57 056 | ||
| Share premium | 3 637 297 | 3 637 297 | 3 637 297 | 3 637 297 | ||
| Other equity | -1 782 268 | -1 881 123 | -1 326 767 | -1 030 555 | ||
| Total equity | 1 912 084 | 1 813 229 | 2 367 585 | 2 663 797 | ||
| Non-current liabilities | ||||||
| Deferred tax | 9 | 2 471 221 | 2 153 376 | 2 235 357 | 1 991 371 | |
| Long-term abandonment provision | 16 | 2 640 527 | 2 642 264 | 2 645 420 | 2 528 672 | |
| Long-term bonds | 14 | 3 121 781 | 3 120 062 | 1 630 936 | 1 858 665 | |
| Long-term derivatives | 12 | 14 951 | 56 982 | - | 30 173 | |
| Long-term lease debt | 7 | 156 396 | 179 501 | 202 592 | 252 467 | |
| Other interest-bearing debt | 15 | 380 708 | 280 784 | 1 429 132 | 775 920 | |
| Total non-current liabilities | 8 785 584 | 8 432 968 | 8 143 437 | 7 437 268 | ||
| Current liabilities | ||||||
| Trade creditors | 93 702 | 117 681 | 144 942 | 79 071 | ||
| Short-term bonds | 14 | 209 803 | 192 541 | 226 700 | - | |
| Accrued public charges and indirect taxes | 27 217 | 15 482 | 25 974 | 24 702 | ||
| Tax payable | 9 | - | 260 081 | 361 157 | 439 270 | |
| Short-term derivatives | 12 | 89 867 | 153 527 | 42 994 | 216 | |
| Short-term abandonment provision | 16 | 176 520 | 153 043 | 142 798 | 78 410 | |
| Short-term lease debt | 7 | 79 863 | 97 855 | 110 664 | 122 127 | |
| Other current liabilities | 13 | 513 945 | 490 884 | 660 535 | 647 720 | |
| Total current liabilities | 1 190 916 | 1 481 094 | 1 715 765 | 1 391 516 | ||
| Total liabilities | 9 976 500 | 9 914 063 | 9 859 201 | 8 828 783 | ||
| TOTAL EQUITY AND LIABILITIES | 11 888 584 | 11 727 291 | 12 226 786 | 11 492 580 |
| Other equity | ||||||||
|---|---|---|---|---|---|---|---|---|
| Other comprehensive income | ||||||||
| (USD 1 000) | Share capital | Share premium |
Other paid-in capital |
Actuarial gains/losses |
Foreign currency translation reserves1) |
Retained earnings |
Total other equity |
Total equity |
| Equity as of 31.12.2018 | 57 056 | 3 637 297 | 573 083 | -81 | -115 491 | -1 175 324 | -717 814 | 2 976 539 |
| Dividends distributed | - | - | - | - | - | -750 000 | -750 000 | -750 000 |
| Profit/loss for the period | - | - | - | - | - | 141 051 | 141 051 | 141 051 |
| Other comprehensive income for the period | - | - | - | -4 | - | - | -4 | -4 |
| Equity as of 31.12.2019 | 57 056 | 3 637 297 | 573 083 | -85 | -115 491 | -1 784 274 | -1 326 767 | 2 367 585 |
| Dividend distributed Profit/loss for the period Purchase of treasury shares2) |
- - - |
- - - |
- - - |
- - - |
- - - |
-212 500 -334 734 -7 122 |
-212 500 -334 734 -7 122 |
-212 500 -334 734 -7 122 |
| Equity as of 31.03.2020 | 57 056 | 3 637 297 | 573 083 | -85 | -115 491 | -2 338 630 | -1 881 123 | 1 813 229 |
| Dividend distributed Profit/loss for the period |
- - |
- - |
- - |
- - |
- - |
-70 833 169 689 |
-70 833 169 689 |
-70 833 169 689 |
| Equity as of 30.06.2020 | 57 056 | 3 637 297 | 573 083 | -85 | -115 491 | -2 239 774 | -1 782 268 | 1 912 084 |
1) The amount arose mainly as a result of the change in functional currency in 2014.
2) The treasury shares are purchased for use in the company's share saving plan.
| Group | ||||||
|---|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | |||
| (USD 1 000) | Note | 2020 | 2020 | 2019 | 2020 | 2019 |
| CASH FLOW FROM OPERATING ACTIVITIES | ||||||
| Profit/loss before taxes | 151 040 | -414 298 | 268 232 | -263 258 | 517 388 | |
| Taxes paid | 9 | -80 581 | -48 150 | -208 440 | -128 731 | -314 370 |
| Depreciation | 6 | 286 353 | 277 412 | 167 889 | 563 765 | 350 991 |
| Impairment | 5, 6 | -135 872 | 653 697 | 517 825 | 68 941 | |
| Accretion expenses | 8, 16 | 29 474 | 29 265 | 30 419 | 58 738 | 60 002 |
| Interest expenses (including interest element of lease payments) | 8 | 51 473 | 47 905 | 53 576 | 99 377 | 102 726 |
| Interest paid (including interest element of lease payments) | -22 653 | -55 954 | -53 580 | -78 607 | -99 423 | |
| Changes in derivatives | 2, 8 | -39 080 | 103 609 | -8 751 | 64 529 | 11 744 |
| Amortized loan costs | 8 | 4 930 | 5 036 | 6 112 | 9 966 | 12 788 |
| Expensed capitalized dry wells | 4, 6 | 9 866 | 28 982 | 29 163 | 38 847 | 87 237 |
| Changes in inventories, accounts payable and receivables | -89 159 | 136 856 | -112 609 | 47 697 | 5 654 | |
| Changes in other current balance sheet items | -3 708 | -240 662 | 214 626 | -244 370 | 173 518 | |
| NET CASH FLOW FROM OPERATING ACTIVITIES | 162 083 | 523 698 | 386 636 | 685 780 | 977 196 | |
| CASH FLOW FROM INVESTMENT ACTIVITIES | ||||||
| Payment for removal and decommissioning of oil fields | -15 007 | -20 929 | -39 554 | -35 936 | -60 316 | |
| Disbursements on investments in fixed assets | -359 514 | -342 508 | -414 194 | -702 022 | -778 176 | |
| Disbursements on investments in capitalized exploration | -19 413 | -31 253 | -87 155 | -50 666 | -213 489 | |
| Cash received from sale of licenses | 54 747 | - | - | 54 747 | - | |
| Disbursements on investments in licenses | - | - | - | - | -143 | |
| NET CASH FLOW FROM INVESTMENT ACTIVITIES | -339 186 | -394 691 | -540 903 | -733 877 | -1 052 125 | |
| CASH FLOW FROM FINANCING ACTIVITIES | ||||||
| Net drawdown/repayment of revolving credit facility | 98 450 | -1 150 000 | 775 314 | -1 051 550 | 775 314 | |
| Net drawdown/repayment of reserve-based lending facility | - | - | -1 150 000 | - | -950 000 | |
| Net proceeds from bond issue | - | 1 487 406 | 740 159 | 1 487 406 | 740 159 | |
| Payments on lease debt related to investments in fixed assets | -18 372 | -26 606 | -21 492 | -44 978 | -37 775 | |
| Payments on other lease debt | -11 609 | -5 183 | -4 758 | -16 792 | -9 777 | |
| Paid dividend | -70 833 | -212 500 | -187 500 | -283 333 | -375 000 | |
| Net purchase/sale of treasury shares | - | -7 122 | -10 665 | -7 122 | -10 665 | |
| NET CASH FLOW FROM FINANCING ACTIVITIES | -2 365 | 85 995 | 141 057 | 83 630 | 132 256 | |
| Net change in cash and cash equivalents | -179 469 | 215 002 | -13 209 | 35 533 | 57 327 | |
| Cash and cash equivalents at start of period | 322 789 | 107 104 | 113 680 | 107 104 | 44 944 | |
| Effect of exchange rate fluctuation on cash held | -987 | 682 | 1 358 | -305 | -443 | |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 11 | 142 333 | 322 789 | 101 828 | 142 333 | 101 828 |
(All figures in USD 1 000 unless otherwise stated)
These 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 annual financial statements as at 31 December 2019. 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 Intarnational Standard on Review Engagements 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity.
These interim financial statements were authorised for issue by the company's Board of Directors on 13 July 2020.
The accounting principles used for this interim report are consistent with the principles used in the group's annual financial statements as at 31 December 2019.
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 applied to the annual financial statements as at 31 December 2019.
The disruption to the global economy caused by COVID-19 resulted in a sharp decrease in oil prices and triggered a reduction in the company's investment program, though operational performance and production levels have been maintained. The fall in oil and gas prices has had a negative impact on operational results and cash flows in the period, and impairments of USD 654 million were recognized in Q1 2020.
In the second quarter, temporary changes to the Norwegian petroleum tax system have strengthened the company's investment capacity and are expected to provide additional liquidity (see note 9).
The recovery in shorter term oil prices as at Q2 2020 has been the main reason for a reversal of USD 135.9 million of the impairments of producing fields recognized in Q1 2020 (see note 5).
Actions have been taken to protect financial flexibility, including an updated and reduced investment program and cut in dividends. As of 30 June 2020 available liquidity on the Revolving Credit Facility is USD 3.6 billion and the related financial covenants meets the applicable thresholds by a substantial margin (see note 15).
The COVID-19 pandemic and associated uncertainties and disruption to the global economy may have negative effects on demand for oil and gas and / or result in interruptions to the company's operations. Such events may adversely impact the company's future results from operations and cash flows, and may lead to impairment of assets.
| Group | |||||||
|---|---|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | ||||
| Breakdown of petroleum revenues (USD 1 000) | 2020 | 2020 | 2019 | 2020 | 2019 | ||
| Sales of liquids | 539 643 | 708 927 | 710 913 | 1 248 570 | 1 451 693 | ||
| Sales of gas | 40 652 | 66 187 | 64 978 | 106 839 | 178 905 | ||
| Tariff income | 3 874 | 3 971 | 4 181 | 7 845 | 7 578 | ||
| Total petroleum revenues | 584 170 | 779 084 | 780 071 | 1 363 254 | 1 638 176 | ||
| Sales of liquids (boe 1 000) | 18 036 | 15 858 | 10 264 | 33 895 | 21 858 | ||
| Sales of gas (boe 1 000) | 3 073 | 3 026 | 2 541 | 6 099 | 5 528 | ||
| Other income (USD 1 000) | |||||||
| Realized gain/loss (-) on oil derivatives | 55 914 | 14 483 | -6 710 | 70 397 | -8 768 | ||
| Unrealized gain/loss (-) on oil derivatives | -70 764 | 68 416 | 6 654 | -2 348 | -17 469 | ||
| Gain on license transactions1) | 5 417 | - | - | 5 417 | - | ||
| Other income2) | 15 047 | 10 122 | 4 801 | 25 169 | 9 139 | ||
| Total other income | 5 614 | 93 021 | 4 744 | 98 635 | -17 098 |
1) Gain on sale of the 3.3 percent interest in the Gina Krog field, which was completed during Q2 2020.
2) Includes insurance settlement during Q2 2020, in addition to partner coverage of RoU assets recognized on gross basis in the balance sheet and used in operated activity.
| Group | |||||||
|---|---|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | ||||
| (USD 1 000) | 2020 | 2020 | 2019 | 2020 | 2019 | ||
| Total produced volumes (boe 1 000) | 19 090 | 18 938 | 11 585 | 38 028 | 25 866 | ||
| Production cost per boe produced (USD/boe) | 9.1 | 8.7 | 15.4 | 8.9 | 14.3 | ||
| Production cost based on produced volumes | 173 479 | 165 218 | 177 874 | 338 696 | 368 872 | ||
| Adjustment for over/underlift (-) | 22 695 | -9 175 | 20 446 | 13 521 | 29 910 | ||
| Production cost based on sold volumes | 196 174 | 156 043 | 198 320 | 352 217 | 398 783 |
| Group | |||||||
|---|---|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | ||||
| Breakdown of exploration expenses (USD 1 000) | 2020 | 2020 | 2019 | 2020 | 2019 | ||
| Seismic | 21 559 | 2 402 | 9 767 | 23 961 | 10 299 | ||
| Area fee | 4 371 | 3 773 | 4 717 | 8 143 | 9 291 | ||
| Field evaluation | 6 790 | 6 531 | 6 898 | 13 321 | 22 823 | ||
| Dry well expenses1) | 9 866 | 28 982 | 29 163 | 38 847 | 87 237 | ||
| Other exploration expenses | 7 188 | 8 650 | 9 716 | 15 838 | 20 971 | ||
| Total exploration expenses | 49 774 | 50 336 | 60 261 | 100 110 | 150 621 |
1) Dry well expenses in Q2 2020 are mainly related to the Sandia well.
Q1 2020 included impairments of the book value of assets other than associated goodwill. As such, prior period impairments may be subject to reversal if changes have occured in the estimates used for the calculation of the recoverable amount. 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 2020, two categories of impairment tests have been performed:
Impairment test of fixed assets and related intangible assets, including technical goodwill
Impairment test of residual goodwill
Impairment is recognized when the book value of an asset or a cash-generating unit, including associated goodwill, exceeds the recoverable amount. Correspondingly, a reversal of impairment is recognized when the recoverable amount exceeds the book value. Prior period impairment of goodwill is not subject to reversal. The recoverable amount is the higher of the asset's fair value less cost to sell and value in use. The impairment testing for 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 2020.
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 2020 to the end of Q2 2023. From Q3 2023, 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 2019.
The nominal oil prices applied in the impairment test are as follows:
| Year | USD/BOE |
|---|---|
| 2020 | 41.4 |
| 2021 | 43.1 |
| 2022 | 45.1 |
| 2023 | 57.7 |
| From 2024 (in real terms) | 65.0 |
| Year | GBP/therm |
|---|---|
| 2020 | 0.23 |
| 2021 | 0.34 |
| 2022 | 0.39 |
| 2023 | 0.49 |
| From 2024 (in real terms) | 0.53 |
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 7.8 percent, consistent with the rate applied at Q4 2019, with the reduction in risk free rate at Q2 2020 offset by increased market risk due to the high volatility in oil and gas prices. Cash flows used in impairment testing have been adjusted to reflect changes to planned future investments made in response to the current market conditions and the associated forecasted production profiles.
| Currency rates | |
|---|---|
| Year | USD/NOK |
| 2020 | 9.63 |
| 2021 | 9.62 |
| 2022 | 9.63 |
| 2023 | 8.82 |
| From 2024 | 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 reversal of impairment charge and the carrying value per cash generating unit where impairment reversals have been recognized in Q2 2020:
| Cash-generating unit (USD 1 000) | Ula/Tambar | Ivar Aasen |
|---|---|---|
| Net carrying value | 613 462 | 933 214 |
| Recoverable amount | 677 803 | 1 004 745 |
| Impairment/reversal (-) | -64 340 | -71 532 |
| Allocated as follows: | ||
| Technical goodwill | - | - |
| Other intangible assets/license rights | -64 340 | -2 565 |
| Tangible fixed assets | - | -68 967 |
The main reasons for the reversal of impairment are the increase in the short-term oil and gas prices and updated cost and production profiles.
For an overview of the impairment/reversal allocation, see note 6.
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 CGU's impacted are Ula/Tambar, Ivar Aasen and Alvheim.
| Change in impairment after | |||||
|---|---|---|---|---|---|
| Assumption (USD 1 000) | Change | Increase in assumptions | Decrease in assumptions | ||
| Oil and gas price forward period | +/- 50 % | -88 719 | 489 705 | ||
| Oil and gas price long-term | +/- 20 % | -89 821 | 401 537 | ||
| Production profile (reserves) | +/- 5 % | -53 387 | 137 774 | ||
| Discount rate | +/- 1 % point | 52 264 | -46 343 | ||
| Currency rate USD/NOK | +/- 2.0 NOK | -85 837 | 351 580 | ||
| Inflation | +/- 1 % point | -44 221 | 75 512 |
Residual goodwill is allocated across all CGUs for impairment testing. The combined recoverable amount exceeds the carrying amount by a substantial margin.
| Property, plant and equipment | Production | Fixtures and | ||
|---|---|---|---|---|
| Assets under | facilities | fittings, office | ||
| (USD 1 000) | development | including wells | machinery | Total |
| Book value 31.12.2019 | 1 250 365 | 5 687 957 | 84 954 | 7 023 276 |
| Acquisition cost 31.12.2019 | 1 250 365 | 9 066 022 | 170 413 | 10 486 800 |
| Additions | 287 168 | 46 167 | 9 174 | 342 508 |
| Disposals/retirement | - | - | - | - |
| Reclassification | -393 038 | 363 055 | 48 492 | 18 509 |
| Acquisition cost 31.03.2020 | 1 144 495 | 9 475 244 | 228 078 | 10 847 817 |
| Accumulated depreciation and impairments 31.12.2019 | - | 3 378 065 | 85 459 | 3 463 524 |
| Depreciation | - | 235 399 | 9 735 | 245 134 |
| Impairment/reversal (-) | - | 78 459 | - | 78 459 |
| Disposals/retirement depreciation | - | - | - | - |
| Accumulated depreciation and impairments 31.03.2020 | - | 3 691 923 | 95 194 | 3 787 117 |
| Book value 31.03.2020 | 1 144 495 | 5 783 321 | 132 884 | 7 060 700 |
| Acquisition cost 31.03.2020 | 1 144 495 | 9 475 244 | 228 078 | 10 847 817 |
| Additions | 129 169 | 247 441 | 4 135 | 380 745 |
| Disposals/retirement1) | - | 675 733 | -69 | 675 664 |
| Reclassification | -192 438 | 201 898 | - | 9 460 |
| Acquisition cost 30.06.2020 | 1 081 226 | 9 248 849 | 232 283 | 10 562 358 |
| Accumulated depreciation and impairments 31.03.2020 | - | 3 691 923 | 95 194 | 3 787 117 |
| Depreciation | - | 243 217 | 10 085 | 253 302 |
| Impairment/reversal (-) | - | -68 967 | - | -68 967 |
| Disposals/retirement depreciation1) | - | -584 292 | 69 | -584 223 |
| Accumulated depreciation and impairments 30.06.2020 | - | 3 281 881 | 105 348 | 3 387 229 |
| Book value 30.06.2020 | 1 081 226 | 5 966 968 | 126 935 | 7 175 129 |
1) The disposal is mainly related to sale of the Gina Krog field and relinquishment of the Jette license.
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 31.12.2019 | 101 487 | 68 941 | 21 774 | 2 127 | 194 328 |
| Acquisition cost 31.12.2019 | 106 856 | 72 106 | 29 593 | 2 303 | 210 859 |
| Additions | - | - | - | - | - |
| Abandonment activity | -974 | -273 | - | - | -1 247 |
| Disposals/retirement | - | - | - | - | - |
| Reclassification | -17 529 | -979 | - | - | -18 509 |
| Acquisition cost 31.03.2020 | 88 354 | 70 854 | 29 593 | 2 303 | 191 104 |
| Accumulated depreciation and impairments 31.12.2019 | 5 369 | 3 166 | 7 820 | 177 | 16 531 |
| Depreciation | 1 071 | 668 | 1 955 | 44 | 3 738 |
| Impairment/reversal (-) | - | - | - | - | - |
| Disposals/retirement depreciation | - | - | - | - | - |
| Accumulated depreciation and impairments 31.03.2020 | 6 440 | 3 834 | 9 775 | 221 | 20 270 |
| Book value 31.03.2020 | 81 913 | 67 019 | 19 819 | 2 082 | 170 834 |
| Acquisition cost 31.03.2020 | 88 354 | 70 854 | 29 593 | 2 303 | 191 104 |
| Additions | - | - | - | - | - |
| Abandonment activity1) | -610 | -226 | - | - | -836 |
| Disposals/retirement2) | 16 197 | 5 920 | - | - | 22 117 |
| Reclassification3) | -8 808 | -652 | - | - | -9 460 |
| Acquisition cost 30.06.2020 | 62 739 | 64 056 | 29 593 | 2 303 | 158 691 |
| Accumulated depreciation and impairments 31.03.2020 | 6 440 | 3 834 | 9 775 | 221 | 20 270 |
| Depreciation | 8 194 | 871 | 1 923 | 44 | 11 032 |
| Impairment/reversal (-) | - | - | - | - | - |
| Disposals/retirement depreciation2) | |||||
| -8 535 | -1 373 | - | - | -9 907 | |
| Accumulated depreciation and impairments 30.06.2020 | 6 099 | 3 333 | 11 698 | 265 | 21 395 |
| Book value 30.06.2020 | 56 640 | 60 723 | 17 895 | 2 038 | 137 296 |
1) This represents the share of right-of-use assets used in abandonment activity, and thus booked against the abandonment provision.
2) The disposal is related to termination of the Maersk Reacher rig and sale of the Gina Krog field during Q2 2020.
3) Reclassified 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.
| Other intangible assets | Capitalized exploration |
||||
|---|---|---|---|---|---|
| (USD 1 000) | Licenses etc. | Software | Total | expenditures | Goodwill |
| Book value 31.12.2019 | 1 915 968 | - | 1 915 968 | 621 315 | 1 712 809 |
| Acquisition cost 31.12.2019 | 2 396 433 | 7 501 | 2 403 934 | 621 315 | 2 738 973 |
| Additions | - | 31 253 | - | ||
| Disposals/retirement/expensed dry wells | - | - | - | 28 982 | - |
| Reclassification | - | - | - | - | - |
| Acquisition cost 31.03.2020 | 2 396 433 | 7 501 | 2 403 934 | 623 587 | 2 738 973 |
| Accumulated depreciation and impairments 31.12.2019 | 480 465 | 7 501 | 487 966 | - | 1 026 165 |
| Depreciation | 28 540 | - | 28 540 | - | - |
| Impairment/reversal (-) | 365 040 | - | 365 040 | 144 826 | 65 373 |
| Disposals/retirement depreciation | - | - | - | - | - |
| Accumulated depreciation and impairments 31.03.2020 | 874 044 | 7 501 | 881 546 | 144 826 | 1 091 537 |
| Book value 31.03.2020 | 1 522 389 | - | 1 522 389 | 478 761 | 1 647 436 |
| Acquisition cost 31.03.2020 | 2 396 433 | 7 501 | 2 403 934 | 623 587 | 2 738 973 |
| Additions | - | - | - | 19 413 | - |
| Disposals/retirement/expensed dry wells | 27 448 | - | 27 448 | 9 866 | 12 391 |
| Reclassification | - | - | - | - | - |
| Acquisition cost 30.06.2020 | 2 368 985 | 7 501 | 2 376 486 | 633 134 | 2 726 583 |
| Accumulated depreciation and impairments 31.03.2020 | 874 044 | 7 501 | 881 546 | 144 826 | 1 091 537 |
| Depreciation | 22 018 | - | 22 018 | - | - |
| Impairment/reversal (-) | -68 186 | - | -68 186 | 1 281 | - |
| Disposals/retirement depreciation | -25 413 | - | -25 413 | - | -12 391 |
| Accumulated depreciation and impairments 30.06.2020 | 802 463 | 7 501 | 809 964 | 146 107 | 1 079 146 |
| Book value 30.06.2020 | 1 566 521 | - | 1 566 521 | 487 027 | 1 647 436 |
Licenses 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 |
||||
| Depreciation in the income statement (USD 1 000) | 2020 | 2020 | 2019 | 2020 | 2019 |
| Depreciation of tangible fixed assets | 253 302 | 245 134 | 144 399 | 498 436 | 303 926 |
| Depreciation of right-of-use assets | 11 032 | 3 738 | 3 836 | 14 771 | 8 369 |
| Depreciation of other intangible assets | 22 018 | 28 540 | 19 654 | 50 558 | 38 696 |
| Total depreciation in the income statement | 286 353 | 277 412 | 167 889 | 563 765 | 350 991 |
| Impairment in the income statement (USD 1 000) | |||||
| Impairment/reversal of tangible fixed assets | -68 967 | 78 459 | - | 9 492 | - |
| Impairment/reversal of other intangible assets | -68 186 | 365 040 | - | 296 854 | - |
| Impairment/reversal of capitalized exploration expenditures | 1 281 | 144 826 | - | 146 107 | - |
| Impairment of goodwill | - | 65 373 | - | 65 373 | 68 941 |
| Total impairment in the income statement | -135 872 | 653 697 | - | 517 825 | 68 941 |
The incremental borrowing rate applied in discounting of the nominal lease debt is between 4.16 percent and 6.67 percent, dependent on the duration of the lease and when it was intially recognized.
| Group | |||
|---|---|---|---|
| 2020 | 2019 | ||
| (USD 1 000) | Q2 | 01.01.-31.03. | 01.01.-31.12. |
| Lease debt as of beginning of period | 277 356 | 313 256 | 389 833 |
| New lease debt recognized in the period | - | - | 34 385 |
| Payments of lease debt1) | -34 314 | -36 699 | -134 253 |
| Lease debt derecognized in the period2) | -12 767 | - | - |
| Interest expense on lease debt | 4 333 | 4 911 | 23 897 |
| Currency exchange differences | 1 652 | -4 111 | -606 |
| Total lease debt | 236 259 | 277 356 | 313 256 |
| Short-term | 79 863 | 97 855 | 110 664 |
| Long-term | 156 396 | 179 501 | 202 592 |
| Investments in fixed assets | 21 027 | 30 716 | 108 587 |
|---|---|---|---|
| Abandonment activity | 1 077 | 1 521 | 4 444 |
| Operating expenditures | 11 010 | 3 116 | 15 278 |
| Exploration expenditures | 123 | 221 | 1 384 |
| Other income | 1 077 | 1 126 | 4 561 |
| Total | 34 314 | 36 699 | 134 253 |
2) The derecognition is related to termination of the Maersk Reacher rig and sale of the Gina Krog field during Q2 2020.
| Nominal lease debt maturity breakdown (USD 1 000): | |||
|---|---|---|---|
| Within one year | 93 231 | 113 045 | 127 747 |
| Two to five years | 129 902 | 153 037 | 175 947 |
| After five years | 54 562 | 57 693 | 61 518 |
| Total | 277 695 | 323 775 | 365 212 |
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. | |||
| (USD 1 000) | 2020 | 2020 | 2019 | 2020 | 2019 | |
| Interest income | 1 224 | 1 369 | 6 735 | 2 593 | 12 799 | |
| Realized gains on derivatives | 2 706 | 3 739 | 2 547 | 6 445 | 6 967 | |
| Change in fair value of derivatives | 109 844 | - | 4 324 | - | 9 623 | |
| Net currency gains | - | 104 970 | - | 75 758 | - | |
| Total other financial income | 112 550 | 108 709 | 6 872 | 82 203 | 16 591 | |
| Interest expenses | 47 140 | 42 994 | 47 360 | 90 134 | 90 052 | |
| Interest on lease debt | 4 333 | 4 911 | 6 216 | 9 243 | 12 674 | |
| Capitalized interest cost, development projects | -8 972 | -12 900 | -44 156 | -21 873 | -86 152 | |
| Amortized loan costs | 4 930 | 5 036 | 6 112 | 9 966 | 12 788 | |
| Total interest expenses | 47 430 | 40 041 | 15 532 | 87 471 | 29 361 | |
| Net currency loss | 29 211 | - | 9 011 | - | 9 616 | |
| Realized loss on derivatives | 35 071 | 11 036 | 6 578 | 46 107 | 13 272 | |
| Change in fair value of derivatives | 172 025 | 2 227 | 62 181 | 3 898 | ||
| Accretion expenses | 29 474 | 29 265 | 30 419 | 58 738 | 60 002 | |
| Other financial expenses | 6 | 6 403 | 36 072 | 6 408 | 36 854 | |
| Total other financial expenses | 93 762 | 218 729 | 84 307 | 173 435 | 123 642 | |
| Net financial items | -27 418 | -148 691 | -86 232 | -176 110 | -123 613 | |
| Group | |||||
|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | ||
| Tax for the period (USD 1 000) | 2020 | 2020 | 2019 | 2020 | 2019 |
| Current year tax payable/receivable | -370 512 | -5 348 | 77 657 | -375 860 | 206 939 |
| Change in current year deferred tax | 355 571 | -78 385 | 122 856 | 277 186 | 233 542 |
| Prior period adjustments | -3 708 | 4 169 | 5 221 | 461 | 3 984 |
| Tax expense (+)/income (-) | -18 649 | -79 564 | 205 734 | -98 213 | 444 465 |
| Group | ||||
|---|---|---|---|---|
| 2020 | 2019 | |||
| Calculated tax payable (-)/tax receivable (+) (USD 1 000) | Q2 | 01.01.-31.03. | 01.01.-31.12. | |
| Tax payable/receivable at beginning of period | -260 081 | -361 157 | -540 860 | |
| Current year tax payable/receivable | 370 512 | 5 348 | -461 984 | |
| Tax payable/receivable related to acquisitions/sales1) | -3 548 | - | 520 | |
| Net tax payment/refund | 80 581 | 48 150 | 618 593 | |
| Prior period adjustments and change in estimate of uncertain tax positions | 3 708 | -7 764 | 16 955 | |
| Currency movements of tax payable/receivable | -4 543 | 55 343 | 5 619 | |
| Net tax payable (-)/receivable (+) | 186 630 | -260 081 | -361 157 | |
| Tax receivable included as current assets (+) | 186 630 | - | - | |
| Tax payable included as current liabilities (-) | - | -260 081 | -361 157 |
| Group | |||
|---|---|---|---|
| 2020 | 2019 | ||
| Deferred tax liability (-)/asset (+) (USD 1 000) | Q2 | 01.01.-31.03. | 01.01.-31.12. |
| Deferred tax liability/asset at beginning of period | -2 153 376 | -2 235 357 | -1 752 757 |
| Change in current year deferred tax | -355 571 | 78 385 | -463 106 |
| Deferred tax related to acquisitions/sales1) | 37 727 | - | - |
| Prior period adjustments | - | 3 595 | -19 509 |
| Deferred tax charged to OCI and equity | - | - | 15 |
| Net deferred tax liability (-)/asset (+) | -2 471 221 | -2 153 376 | -2 235 357 |
1) Related to sale of the Gina Krog field during Q2 2020.
| Group | |||||
|---|---|---|---|---|---|
| Q2 | Q1 | Q2 | 01.01.-30.06. | ||
| Reconciliation of tax expense (USD 1 000) | 2020 | 2020 | 2019 | 2020 | 2019 |
| 78 % tax rate on profit/loss before tax | 117 811 | -323 152 | 209 221 | -205 341 | 403 563 |
| Tax effect of uplift | -109 217 | -35 291 | -33 012 | -144 508 | -64 076 |
| Permanent difference on impairment | -2 613 | 170 786 | - | 168 174 | 53 774 |
| Foreign currency translation of NOK monetary items | 21 497 | -78 670 | 6 706 | -57 173 | 7 177 |
| Foreign currency translation of USD monetary items | 219 217 | -411 206 | 25 541 | -191 989 | 26 679 |
| Tax effect of financial and other 22 % items | -98 302 | 242 250 | 11 486 | 143 949 | 29 005 |
| Currency movements of tax balances2) | -162 338 | 351 367 | -23 757 | 189 029 | -24 080 |
| Other permanent differences, prior period adjustments and change in estimate of uncertain tax positions |
-4 705 | 4 351 | 9 550 | -353 | 12 423 |
| Tax expense (+)/income (-) | -18 649 | -79 564 | 205 734 | -98 213 | 444 465 |
2) 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).
Certain temporary changes in the Petroleum Tax Law were enacted on 19 June 2020. The changes in tax law included a temporary rule for depreciation and uplift, whereby all investments incurred for income year 2020 and 2021 including 24% uplift can be deducted for special tax (56%) in the year of investment. The temporary changes will also be applicable for investments up to and including year of production start in accordance with new PDOs delivered within 31 December 2022 and approved within 31 December 2023. In addition, the value of tax losses incurred in 2020 and 2021 will be refunded from the state. The tax effect for 2020 of the temporary changes are included as of Q2.
In accordance with statutory requirements, the calculation of current tax is required to be based on NOK functional currency. This may impact the effective tax rate as the company's functional currency is USD.
| Group | ||||
|---|---|---|---|---|
| (USD 1 000) | 30.06.2020 | 31.03.2020 | 31.12.2019 | 30.06.2019 |
| Prepayments | 67 247 | 80 134 | 65 813 | 64 682 |
| VAT receivable | 14 638 | 6 796 | 8 904 | 6 086 |
| Underlift of petroleum | 33 695 | 49 152 | 46 515 | 26 409 |
| Accrued income from sale of petroleum products | 110 866 | 78 019 | 80 514 | 60 066 |
| Other receivables, mainly balances with license partners | 101 476 | 93 534 | 128 770 | 102 275 |
| Total other short-term receivables | 327 922 | 307 635 | 330 516 | 259 518 |
The item 'Cash and cash equivalents' consists of bank accounts and short-term investments that constitute parts of the group's transaction liquidity.
| Group | ||||
|---|---|---|---|---|
| Breakdown of cash and cash equivalents (USD 1 000) | 30.06.2020 | 31.03.2020 | 31.12.2019 | 30.06.2019 |
| Bank deposits | 142 333 | 322 789 | 107 104 | 101 828 |
| Cash and cash equivalents | 142 333 | 322 789 | 107 104 | 101 828 |
| Unused RCF facility (see note 15) | 3 600 000 | 3 700 000 | 2 550 000 | 3 200 000 |
| Group | |||||
|---|---|---|---|---|---|
| (USD 1 000) | 30.06.2020 | 31.03.2020 | 31.12.2019 | 30.06.2019 | |
| Unrealized gain currency contracts | - | - | 2 706 | - | |
| Long-term derivatives included in assets | - | - | 2 706 | - | |
| Unrealized gain on commodity derivatives | - | 66 611 | - | - | |
| Unrealized gain currency contracts | - | - | - | 840 | |
| Short-term derivatives included in assets | - | 66 611 | - | 840 | |
| Total derivatives included in assets | - | 66 611 | 2 706 | 840 | |
| Unrealized losses interest rate swaps | - | - | - | 30 173 | |
| Unrealized losses currency contracts | 14 951 | 56 982 | - | - | |
| Long-term derivatives included in liabilities | 14 951 | 56 982 | - | 30 173 | |
| Unrealized losses commodity derivatives | 4 153 | - | 1 805 | 216 | |
| Unrealized losses interest rate swaps1) | 57 246 | 73 727 | 37 017 | - | |
| Unrealized losses currency contracts | 28 468 | 79 800 | 4 172 | - | |
| Short-term derivatives included in liabilities | 89 867 | 153 527 | 42 994 | 216 | |
| Total derivatives included in liabilities | 104 818 | 210 509 | 42 994 | 30 389 |
1) The unrealized loss is related to DETNOR02 (see note 14) and realized on 2 July 2020, in connection with the repayment of the bond.
The group has various types of economic hedging instruments. Commodity derivatives are used to hedge the risk of oil price reduction. The group manages its interest rate exposure using interest rate derivatives, including interest rate swap and a cross currency interest rate swap. Foreign currency exchange derivatives are used to manage the company's exposure to currency risks, mainly costs in NOK, EUR and GBP. These derivatives are mark to market with changes in market value recognized in the income statement. The nature of the instruments and the valuation method is consistent with the disclosed information in the annual financial statements as at 31 December 2019.
| Group | ||||
|---|---|---|---|---|
| Breakdown of other current liabilities (USD 1 000) | 30.06.2020 | 31.03.2020 | 31.12.2019 | 30.06.2019 |
| Balances with license partners | 39 482 | 47 198 | 67 199 | 49 242 |
| Share of other current liabilities in licenses | 299 451 | 269 887 | 379 787 | 412 322 |
| Overlift of petroleum | 17 145 | 9 123 | 15 660 | 11 450 |
| Unpaid wages and vacation pay, accrued interest and other provisions | 157 866 | 164 676 | 197 889 | 174 706 |
| Total other current liabilities | 513 945 | 490 884 | 660 535 | 647 720 |
| Group | ||||||
|---|---|---|---|---|---|---|
| Senior unsecured bonds (USD 1 000) | Maturity | 30.06.2020 | 31.03.2020 | 31.12.2019 | 30.06.2019 | |
| DETNOR02 Senior unsecured bond1) | Jul 2020 | - | - | - | 230 296 | |
| AKERBP – Senior Notes 6.000% (17/22)2) | Jul 2022 | 396 027 | 395 537 | 395 046 | 394 225 | |
| AKERBP – Senior Notes 5.875% (18/25)2) | Mar 2025 | 494 996 | 494 733 | 494 470 | 493 943 | |
| AKERBP – Senior Notes 4.750% (19/24)2) | Jun 2024 | 742 376 | 741 900 | 741 421 | 740 201 | |
| AKERBP – Senior Notes 3.750% (20/30)2) | Jan 2030 | 992 405 | 992 180 | - | - | |
| AKERBP – Senior Notes 3.000% (20/25)2) | Jan 2025 | 495 976 | 495 712 | - | - | |
| Long-term bonds - book value | 3 121 781 | 3 120 062 | 1 630 936 | 1 858 665 | ||
| Long-term bonds - fair value | 3 089 480 | 2 568 155 | 1 727 205 | 1 963 965 | ||
| DETNOR02 Senior unsecured bond1) | Jul 2020 | 209 803 | 192 541 | 226 700 | - | |
| Short-term bonds - book value | 209 803 | 192 541 | 226 700 | - | ||
| Short-term bonds - fair value | 211 229 | 198 847 | 238 744 | - |
1) The bond is denominated in NOK and carries an interest rate of 3 month Nibor + 6.5 percent. The interest is paid on a quarterly basis. The bond has been swapped into USD using a cross currency interest rate swap whereby the group pays Libor + 6.81 percent quarterly. The financial covenants for this bond are consistent with the RCF as described in note 15. The bond was repaid 2 July 2020 by drawing on the Revolving Credit Facility.
2) Interest is paid on a semi annual basis. None of the long-term bonds have financial covenants.
| Group | |||||
|---|---|---|---|---|---|
| (USD 1 000) | 30.06.2020 | 31.03.2020 | 31.12.2019 | 30.06.2019 | |
| Revolving credit facility1) | 380 708 | 280 784 | 1 429 132 | 775 920 | |
| Other interest-bearing debt | 380 708 | 280 784 | 1 429 132 | 775 920 |
1) Utilization is made under the Working Caital facility.
The senior unsecured Revolving Credit Facility (RCF) was established in May 2019 and comprise a 3-year USD 2.0 billion Working Capital Facility and a USD 2.0 billion 5-year Liquidity Facility. The Liquidity Facility includes two 12-month extension options, of which the first was exercised in April 2020. The interest rate is LIBOR plus a margin of 1.08 percent for the Liquidity Facility and 1.33 percent for the Working Capital Facility. In addition, a utilization fee is applicable for the Liquidity Facility. A commitment fee of 35 percent of applicable margin is paid on the undrawn 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 June 2020 the Leverage Ratio is 1.46 and Interest Coverage Ratio is 11.6 (see APM section for further details), which are well within the thresholds mentioned above. Applying the forward curve at end of Q2 2020, the company's estimates show that the financial covenants will continue to be within the thresholds 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 | ||||
|---|---|---|---|---|
| 2020 | ||||
| (USD 1 000) | Q2 | 01.01.-31.03. | 01.01.-31.12. | |
| Provisions as of beginning of period | 2 795 306 | 2 788 218 | 2 552 592 | |
| Change in abandonment liability due to asset sales1) | -13 122 | - | - | |
| Incurred cost removal | -15 843 | -22 176 | -108 332 | |
| Accretion expense - present value calculation | 29 474 | 29 265 | 121 723 | |
| Changed net present value from changed discount rate | - | - | 238 053 | |
| Change in estimates and incurred liabilities on new drilling and installations | 21 231 | - | -15 818 | |
| Total provision for abandonment liabilities | 2 817 047 | 2 795 306 | 2 788 218 | |
| Short-term | 176 520 | 153 043 | 142 798 | |
| Long-term | 2 640 527 | 2 642 264 | 2 645 420 |
1) Related to sale of the Gina Krog field during Q2 2020.
The estimate is 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 3.77 percent and 4.59 percent. The discount rate is unchanged from Q4 2019 with the reduction in risk free rate in 2020 offset by increased credit margin.
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 company has not identified any events with significant accounting impacts that have occured between the end of the reporting period and the date of this report.
| Fields operated: | 30.06.2020 | 31.03.2020 |
|---|---|---|
| Alvheim | 65.000% | 65.000 % |
| Bøyla | 65.000% | 65.000 % |
| Hod | 90.000% | 90.000 % |
| Ivar Aasen Unit | 34.786% | 34.786 % |
| Valhall | 90.000% | 90.000 % |
| Vilje | 46.904% | 46.904 % |
| Volund | 65.000% | 65.000 % |
| Tambar | 55.000% | 55.000 % |
| Skogul | 65.000% | 65.000 % |
| Tambar Øst | 46.200% | 46.200 % |
| Ula | 80.000% | 80.000 % |
| Skarv | 23.835% | 23.835 % |
| Production licenses in which Aker BP is the operator: | ||||
|---|---|---|---|---|
| License: | 30.06.2020 | 31.03.2020 License: | 30.06.2020 | 31.03.2020 |
| PL 001B | 35.000% | 35.000 % PL 777D | 40.000% | 40.000 % |
| PL 006B | 90.000% | 90.000 % PL 784 | 40.000% | 40.000 % |
| PL 019 | 80.000% | 80.000 % PL 814 | 40.000% | 40.000 % |
| PL 019C | 80.000% | 80.000 % PL 818 | 40.000% | 40.000 % |
| PL 019E | 80.000% | 80.000 % PL 818B | 40.000% | 40.000 % |
| PL 019F | 55.000% | 55.000 % PL 822S | 60.000% | 60.000 % |
| PL 026 | 92.130% | 92.130 % PL8382) | 35.000% | 30.000 % |
| PL 026B | 90.260% | 90.260 % PL 858 | 40.000% | 40.000 % |
| PL 028B | 35.000% | 35.000 % PL 867 | 40.000% | 40.000 % |
| PL 033 | 90.000% | 90.000 % PL 867B | 40.000% | 40.000 % |
| PL 033B | 90.000% | 90.000 % PL 868 | 60.000% | 60.000 % |
| PL 036C | 65.000% | 65.000 % PL 869 | 60.000% | 60.000 % |
| PL 036D | 46.904% | 46.904 % PL 873 | 40.000% | 40.000 % |
| PL 036E | 64.000% | 64.000 % PL 874 | 90.260% | 90.260 % |
| PL 036F | 64.000% | 64.000 % PL 906 | 60.000% | 60.000 % |
| PL 065 | 55.000% | 55.000 % PL 907 | 60.000% | 60.000 % |
| PL 065B | 55.000% | 55.000 % PL 914S | 34.786% | 34.786 % |
| PL 088BS | 65.000% | 65.000 % PL 915 | 35.000% | 35.000 % |
| 50.000% | 65.000% | |||
| PL 102D | 50.000% | 50.000 % PL 919 | 60.000% | 65.000 % |
| PL 102F | 50.000% | 50.000 % PL 932 | 50.000% | 60.000 % |
| PL 102G | 50.000 % PL 941 | 50.000 % | ||
| PL 102H | 50.000% | 50.000 % PL 951 | 40.000% | 40.000 % |
| PL 127C1) | 88.083% | 100.000 % PL 9633) | 0.000% | 70.000 % |
| PL 146 | 77.800% | 77.800 % PL 964 | 40.000% | 40.000 % |
| PL 150 | 65.000% | 65.000 % PL 977 | 60.000% | 60.000 % |
| PL 159D | 23.835% | 23.835 % PL 978 | 60.000% | 60.000 % |
| PL 203 | 65.000% | 65.000 % PL 979 | 60.000% | 60.000 % |
| PL 212 | 30.000% | 30.000 % PL 986 | 30.000% | 30.000 % |
| PL 212B | 30.000% | 30.000 % PL 1005 | 60.000% | 60.000 % |
| PL 212E | 30.000% | 30.000 % PL 1008 | 60.000% | 60.000 % |
| PL 242 | 35.000% | 35.000 % PL 1022 | 40.000% | 40.000 % |
| PL 261 | 50.000% | 50.000 % PL 1026 | 40.000% | 40.000 % |
| PL 262 | 30.000% | 30.000 % PL 1028 | 50.000% | 50.000 % |
| PL 300 | 55.000% | 55.000 % PL 1030 | 50.000% | 50.000 % |
| PL 333 | 77.800% | 77.800 % PL 1041 | 40.000% | 40.000 % |
| PL 340 | 65.000% | 65.000 % PL 1042 | 40.000% | 40.000 % |
| PL 340BS | 65.000% | 65.000 % PL 1045 | 65.000% | 65.000 % |
| PL 364 | 90.260% | 90.260 % PL 1047 | 40.000% | 40.000 % |
| PL 442 | 90.260% | 90.260 % PL 1066 | 50.000% | 50.000 % |
| PL 442B | 90.260% | 90.260 % PL 1081 | 60.000% | 60.000 % |
| PL 442C | 90.260% | 90.260 % | ||
| PL 460 | 65.000% | 65.000 % | ||
| PL 685 | 40.000% | 40.000 % | ||
| PL 762 | 20.000% | 20.000 % | ||
| PL 777 | 40.000% | 40.000 % | ||
| PL 777B | 40.000% | 40.000 % | ||
| PL 777C | 40.000% | 40.000 % | ||
| Number of licenses in which Aker BP is the operator | 86 | 87 |
1) Decreased ownership as a result of the PGNiG transaction
2) Aker BP became the operator as a result of the PGNiG transaction
3) Relinquished license
| Fields non-operated: | 30.06.2020 | 31.03.2020 |
|---|---|---|
| Atla | 10.000% | 10.000 % |
| Enoch | 2.000% | 2.000 % |
| Gina Krog1) | 0.000% | 3.300 % |
| Johan Sverdrup | 11.573% | 11.573 % |
| Oda | 15.000% | 15.000 % |
1) Share sold to PGNiG
| Production licenses in which Aker BP is a partner: | ||||
|---|---|---|---|---|
| License: | 30.06.2020 | 31.03.2020 License: | 30.06.2020 | 31.03.2020 |
| PL 006C | 15.000% | 15.000 % PL 838B | 30.000% | 30.000 % |
| PL 006E | 15.000% | 15.000 % PL 852 | 40.000% | 40.000 % |
| PL 006F | 15.000% | 15.000 % PL 852B | 40.000% | 40.000 % |
| PL 029B1) | 0.000% | 20.000 % PL 852C | 40.000% | 40.000 % |
| PL 035 | 50.000% | 50.000 % PL 8572) | 0.000% | 20.000 % |
| PL 035C | 50.000% | 50.000 % PL 862 | 50.000% | 50.000 % |
| PL 048D | 10.000% | 10.000 % PL 8642) | 0.000% | 20.000 % |
| PL 102C | 10.000% | 10.000 % PL 892 | 30.000% | 30.000 % |
| PL 127 | 50.000% | 50.000 % PL 902 | 30.000% | 30.000 % |
| PL 127B | 50.000% | 50.000 % PL 902B | 30.000% | 30.000 % |
| PL 220 | 15.000% | 15.000 % PL 942 | 30.000% | 30.000 % |
| PL 265 | 20.000% | 20.000 % PL 954 | 20.000% | 20.000 % |
| PL 272 | 50.000% | 50.000 % PL 955 | 30.000% | 30.000 % |
| PL 272B | 50.000% | 50.000 % PL 961 | 30.000% | 30.000 % |
| PL 405 | 15.000% | 15.000 % PL 962 | 20.000% | 20.000 % |
| PL 457BS | 40.000% | 40.000 % PL 966 | 30.000% | 30.000 % |
| PL 492 | 60.000% | 60.000 % PL 968 | 20.000% | 20.000 % |
| PL 502 | 22.222% | 22.222 % PL 981 | 40.000% | 40.000 % |
| PL 533 | 35.000% | 35.000 % PL 982 | 40.000% | 40.000 % |
| PL 533B | 35.000% | 35.000 % PL 985 | 20.000% | 20.000 % |
| PL 554 | 30.000% | 30.000 % PL 1031 | 20.000% | 20.000 % |
| PL 554B | 30.000% | 30.000 % PL 1040 | 30.000% | 30.000 % |
| PL 554C | 30.000% | 30.000 % PL 1051 | 20.000% | 20.000 % |
| PL 554D | 30.000% | 30.000 % PL 1052 | 20.000% | 20.000 % |
| PL 6152) | 0.000% | 4.000 % PL 1054 | 30.000% | 30.000 % |
| PL 615B2) | 0.000% | 4.000 % PL 1064 | 30.000% | 30.000 % |
| PL 719 | 20.000% | 20.000 % PL 1069 | 50.000% | 50.000 % |
| PL 722 | 20.000% | 20.000 % | ||
| PL 780 | 40.000% | 40.000 % | ||
| PL 782S | 20.000% | 20.000 % | ||
| PL 782SB | 20.000% | 20.000 % | ||
| PL 782SC | 20.000% | 20.000 % | ||
| PL 782SD | 20.000% | 20.000 % | ||
| Number of licenses in which Aker BP is the partner | 55 | 60 |
1) Share sold to PGNiG
2) Relinquished license
| 2020 | |||||
|---|---|---|---|---|---|
| (USD 1 000) | Q2 | Q1 | Q4 | Q3 | Q2 |
| Total income | 589 784 | 872 105 | 1 002 673 | 723 338 | 784 816 |
| Production costs | 196 174 | 156 043 | 154 272 | 167 267 | 198 320 |
| Exploration expenses | 49 774 | 50 336 | 84 683 | 70 213 | 60 261 |
| Depreciation | 286 353 | 277 412 | 255 015 | 205 867 | 167 889 |
| Impairments | -135 872 | 653 697 | -509 | 78 376 | - |
| Other operating expenses | 14 897 | 223 | 18 550 | 6 038 | 3 882 |
| Total operating expenses | 411 326 | 1 137 711 | 512 011 | 527 760 | 430 352 |
| Operating profit/loss | 178 458 | -265 606 | 490 661 | 195 578 | 354 464 |
| Net financial items | -27 418 | -148 691 | -66 663 | -52 710 | -86 232 |
| Profit/loss before taxes | 151 040 | -414 298 | 423 998 | 142 868 | 268 232 |
| Tax expense (+)/income (-) | -18 649 | -79 564 | 312 448 | 186 291 | 205 734 |
| Net profit/loss | 169 689 | -334 734 | 111 550 | -43 423 | 62 498 |
| 2020 | 2019 | |||||
|---|---|---|---|---|---|---|
| (boe 1 000) | Q2 | Q1 | Q4 | Q3 | Q2 | |
| Sold volumes | ||||||
| Liquids Gas |
18 036 3 073 |
15 858 3 026 |
13 930 3 046 |
10 437 2 743 |
10 264 2 541 |
| 2020 | 2019 | |||||
|---|---|---|---|---|---|---|
| (USD 1 000) | Q2 | Q1 | Q4 | Q3 | Q2 | |
| Assets | ||||||
| Goodwill | 1 647 436 | 1 647 436 | 1 712 809 | 1 712 809 | 1 791 185 | |
| Other intangible assets | 2 053 548 | 2 001 150 | 2 537 283 | 2 570 893 | 2 521 625 | |
| Property, plant and equipment | 7 175 129 | 7 060 700 | 7 023 276 | 6 613 597 | 6 299 710 | |
| Right-of-use asset | 137 296 | 170 834 | 194 328 | 215 328 | 238 879 | |
| Receivables and other assets | 546 212 | 524 382 | 651 986 | 609 112 | 521 934 | |
| Calculated tax receivables (short) | 186 630 | - | - | - | 17 418 | |
| Cash and cash equivalents | 142 333 | 322 789 | 107 104 | 5 066 | 101 828 | |
| Total assets | 11 888 584 | 11 727 291 | 12 226 786 | 11 726 805 | 11 492 580 | |
| Equity and liabilities | ||||||
| Equity | 1 912 084 | 1 813 229 | 2 367 585 | 2 443 539 | 2 663 797 | |
| Other provisions for liabilities incl. P&A (long) | 2 655 478 | 2 699 246 | 2 645 420 | 2 542 083 | 2 558 845 | |
| Deferred tax | 2 471 221 | 2 153 376 | 2 235 357 | 2 279 415 | 1 991 371 | |
| Bonds and bank debt | 3 712 292 | 3 593 387 | 3 286 768 | 2 939 545 | 2 634 585 | |
| Lease debt | 236 259 | 277 356 | 313 256 | 341 071 | 374 595 | |
| Other current liabilities incl. P&A | 901 251 | 930 616 | 1 017 244 | 986 162 | 830 119 | |
| Tax payable | - | 260 081 | 361 157 | 194 991 | 439 270 | |
| Total equity and liabilities | 11 888 584 | 11 727 291 | 12 226 786 | 11 726 805 | 11 492 580 |
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)
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
Capex is disbursements on investments in fixed assets deducted by capitalized interest cost1)
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)
Leverage ratio is calculated as Net interest-bearing debt divided by twelve months rolling EBITDAX, excluding any impacts from IFRS 16
Interest coverage ratio is calculated as twelve months rolling EBITDA, divided by interest expenses, 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 3)
1) Includes payments of lease debt as disclosed in note 7.
| Q2 | Q1 | 01.01.-30.06. | Q2 | 01.01.-31.12. | ||
|---|---|---|---|---|---|---|
| (USD 1 000) | Note | 2020 | 2020 | 2020 | 2019 | 2019 |
| Abandonment spend | ||||||
| Payment for removal and decommissioning of oil fields | 15 007 | 20 929 | 35 936 | 39 554 | 104 890 | |
| Payments of lease debt (abandonment activity) | 7 | 1 077 | 1 521 | 2 598 | 497 | 4 444 |
| Abandonment spend | 16 084 | 22 450 | 38 534 | 40 052 | 109 334 | |
| Depreciation per boe | ||||||
| Depreciation | 6 | 286 353 | 277 412 | 563 765 | 167 889 | 811 874 |
| Total produced volumes (boe 1 000) | 3 | 19 090 | 18 938 | 38 028 | 11 585 | 56 886 |
| Depreciation per boe | 15.0 | 14.6 | 14.8 | 14.5 | 14.3 | |
| Dividend per share | ||||||
| Paid dividend | 70 833 | 212 500 | 283 333 | 187 500 | 750 000 | |
| Number of shares outstanding | 359 614 | 359 984 | 359 799 | 360 060 | 360 014 | |
| Dividend per share | 0.20 | 0.59 | 0.79 | 0.52 | 2.08 | |
| Capex | ||||||
| Disbursements on investments in fixed assets | 359 514 | 342 508 | 702 022 | 414 194 | 1 703 213 | |
| Payments of lease debt (investments in fixed assets) | 7 | 21 027 | 30 716 | 51 743 | 26 581 | 108 587 |
| Capitalized interest | 8 | -8 972 | -12 900 | -21 873 | -44 156 | -144 686 |
| CAPEX | 371 568 | 360 324 | 731 892 | 396 619 | 1 667 113 | |
| EBITDA | ||||||
| Total income | 2 | 589 784 | 872 105 | 1 461 889 | 784 816 | 3 347 088 |
| Production costs | 3 | -196 174 | -156 043 | -352 217 | -198 320 | -720 321 |
| Exploration expenses | 4 | -49 774 | -50 336 | -100 110 | -60 261 | -305 516 |
| Other operating expenses | -14 897 | -223 | -15 120 | -3 882 | -35 328 | |
| EBITDA | 328 939 | 665 503 | 994 442 | 522 353 | 2 285 922 | |
| EBITDAX | ||||||
| Total income | 2 | 589 784 | 872 105 | 1 461 889 | 784 816 | 3 347 088 |
| Production costs | 3 | -196 174 | -156 043 | -352 217 | -198 320 | -720 321 |
| Other operating expenses | -14 897 | -223 | -15 120 | -3 882 | -35 328 | |
| EBITDAX | 378 713 | 715 839 | 1 094 552 | 582 614 | 2 591 439 | |
| Equity ratio | ||||||
| Total equity | 1 912 084 | 1 813 229 | 1 912 084 | 2 663 797 | 2 367 585 | |
| Total assets | 11 888 584 | 11 727 291 | 11 888 584 | 11 492 580 | 12 226 786 | |
| Equity ratio | 16% | 15% | 16% | 23% | 19% | |
| Exploration spend | ||||||
| Disbursements on investments in capitalized exploration expenditures | 19 413 | 31 253 | 50 666 | 87 155 | 370 185 | |
| Exploration expenses | 4 | 49 774 | 50 336 | 100 110 | 60 261 | 305 516 |
| Dry well | 4 | -9 866 | -28 982 | -38 847 | -29 163 | -176 419 |
| Payments of lease debt (exploration expenditures) | 7 | 123 | 221 | 343 | 468 | 1 384 |
| Exploration spend | 59 443 | 52 829 | 112 272 | 118 721 | 500 666 |
| Q2 | Q1 | 01.01.-30.06. | Q2 | 01.01.-31.12. | ||
|---|---|---|---|---|---|---|
| (USD 1 000) | Note | 2020 | 2020 | 2020 | 2019 | 2019 |
| Interest coverage ratio | ||||||
| Twelve months rolling EBITDA | 20 | 2 219 431 | 2 412 844 | 2 219 431 | 2 417 110 | 2 285 922 |
| Twelve months rolling EBITDA, impacts from IFRS 16 | 7 | -27 485 | -20 638 | -27 485 | -9 823 | -20 636 |
| Twelve months rolling EBITDA, excluding impacts from IFRS 16 | 2 191 945 | 2 392 206 | 2 191 945 | 2 407 287 | 2 265 287 | |
| Twelve months rolling interest expenses | 8 | 175 754 | 175 975 | 175 754 | 197 069 | 175 672 |
| Twelve months rolling amortized loan cost | 8 | 18 883 | 20 065 | 18 883 | 26 791 | 21 705 |
| Twelve months rolling interest income | 8 | 6 284 | 11 795 | 6 284 | 27 870 | 16 490 |
| Net interest expenses | 188 354 | 184 244 | 188 354 | 195 990 | 180 886 | |
| Interest coverage ratio | 11.6 | 13.0 | 11.6 | 12.3 | 12.5 | |
| Leverage ratio | ||||||
| Long-term bonds | 14 | 3 121 781 | 3 120 062 | 3 121 781 | 1 858 665 | 1 630 936 |
| Other interest-bearing debt | 15 | 380 708 | 280 784 | 380 708 | 775 920 | 1 429 132 |
| Short-term bonds | 14 | 209 803 | 192 541 | 209 803 | - | 226 700 |
| Cash and cash equivalents | 11 | 142 333 | 322 789 | 142 333 | 101 828 | 107 104 |
| Net interest-bearing debt excluding lease debt | 3 569 959 | 3 270 598 | 3 569 959 | 2 532 757 | 3 179 664 | |
| Twelve months rolling EBITDAX | 20 | 2 474 436 | 2 678 337 | 2 474 436 | 2 733 708 | 2 591 439 |
| Twelve months rolling EBITDAX, impacts from IFRS 16 | 7 | -26 965 | -19 797 | -26 965 | -9 202 | -19 839 |
| Twelve months rolling EBITDAX, excluding impacts from IFRS 16 | 2 447 471 | 2 658 540 | 2 447 471 | 2 724 505 | 2 571 600 | |
| Leverage ratio | 1.46 | 1.23 | 1.46 | 0.93 | 1.24 | |
| Net interest-bearing debt | ||||||
| Long-term bonds | 14 | 3 121 781 | 3 120 062 | 3 121 781 | 1 858 665 | 1 630 936 |
| Long-term lease debt | 7 | 156 396 | 179 501 | 156 396 | 252 467 | 202 592 |
| Other interest-bearing debt | 15 | 380 708 | 280 784 | 380 708 | 775 920 | 1 429 132 |
| Short-term bonds | 14 | 209 803 | 192 541 | 209 803 | - | 226 700 |
| Short-term lease debt | 7 | 79 863 | 97 855 | 79 863 | 122 127 | 110 664 |
| Cash and cash equivalents | 11 | 142 333 | 322 789 | 142 333 | 101 828 | 107 104 |
| Net interest-bearing debt | 3 806 218 | 3 547 954 | 3 806 218 | 2 907 352 | 3 492 920 |
Operating profit/loss see Income Statement
Production cost per boe see note 3
Pursuant to the Norwegian Securities Trading Act section § 5-5 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 2020 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, 13 July 2020 |
Øyvind Eriksen, Chair of the Board Kjell Inge Røkke, Board member Anne Marie Cannon, Deputy Chair Trond Brandsrud, Board member Gro Kielland, Board member Murray Auchincloss, Board member Ingard Haugeberg, Board member Terje Solheim, Board member Anette Hoel Helgesen, Board member Kate Thomson, Board member
Karl Johnny Hersvik, Chief Executive Officer Ørjan Holstad, Board member
KPMG AS Sørkedalsveien 6 Postboks 7000 Majorstuen 0306 Oslo
Telephone +47 04063 Fax +47 22 60 96 01 Internet www.kpmg.no Enterprise 935 174 627 MVA
To the Board of Directors of Aker BP ASA
We have reviewed the accompanying condensed consolidated statements of financial position of Aker BP ASA as at 30 June 2020, 30 June 2019 and 31 March 2020, and the related condensed consolidated income statements and statements of comprehensive income and cash flows for the sixmonth periods ended 30 June 2020 and 2019, and the three-month periods ended 30 June 2020, 30 June 2019 and 31 March 2020, and the related condensed consolidated statement of changes in equity for the three-month periods ended 30 June 2020 and 31 March 2020, and notes to the condensed consolidated interim financial information (the "condensed consolidated interim financial information"). Management is responsible for the preparation and presentation of this condensed consolidated interim financial information in accordance with International Accounting Standard 34, Interim Financial Reporting as adopted by the EU. Our responsibility is to express a conclusion on this condensed consolidated interim financial information based on our review.
We conducted our review in accordance with the 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, 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 condensed consolidated interim financial information, is not prepared, in all material respects, in accordance with International Accounting Standard 34, Interim Financial Reporting as adopted by the EU.
Our report does not extend to the summary financial information for interim periods included in note 20 which is not a required disclosure under International Accounting Standard 34 Interim Financial Reporting.
Oslo, 13 July 2020
KPMG AS
Mona Irene Larsen State Authorised Public Accountant (Norway)
| KPMG AS, a Norwegian limited liability company and member firm of the KPMG network of independent member firms affiliated | |
|---|---|
| with KPMG International Cooperative ("KPMG International"), a Swiss entity. |
| Oslo | Elverum | Mo i Rana | Stord |
|---|---|---|---|
| Alta | Finnsnes | Molde | Straume |
| Arendal | Hamar | Skien | Tromsø |
| Bergen | Haugesund | Sandefjord | Trondheim |
| Boda | Knarvik | Sandnessiøen | Tynset |
| Department | Keintignoond | $O_{\text{intraator}}$ | امور بمملأ |
Fornebuporten, Building B Oksenøyveien 10 1366 Lysaker
Postal address: P.O. Box 65 1324 Lysaker, Norway
Telephone: +47 51 35 30 00 E-mail: [email protected]
www.akerbp.com
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