Annual Report • Mar 15, 2022
Annual Report
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Aker BP's Sustainability report 2021 describes the company's management approach and performance to environment, social and governance.
The report can be found at
Aker BP is a pure play oil and gas company, conducting exploration, development and production activities on the Norwegian Continental Shelf (NCS). Measured in production, Aker BP is one of the largest independent oil companies in Europe.
Aker BP is the operator of Alvheim, Ivar Aasen, Skarv, Valhall, Hod, Ula and Tambar, a partner in the Johan Sverdrup field and holds a total of 124 licences, including non-operated licences. Towards the end of 2021, Aker BP ASA made an agreement to acquire Lundin Energy's oil and gas related activities on the NCS. The company's assets and activities are mainly based in Norway and within the Norwegian offshore tax regime.
Aker BP is headquartered at Fornebu outside Oslo and has offices in Stavanger, Trondheim, Harstad and Sandnessjøen. At the end of 2021, Aker BP had 1,839 employees.
In 2021 Aker BP purchased goods and services for about USD 3 billion, and engaged around 1,400 direct suppliers, mainly within the oil and gas service sector. Most Aker BP suppliers are based in Norway or in Europe and are generally contracted for high-technology services such as engineering, equipment and drilling and well services, or leasing of rigs and marine services.
Aker BP ASA is owned by Aker ASA (37,14%), BP p.l.c. (27,85%) and other shareholders (35,01%). The company is listed on the Oslo Børs (Stock Exhange) with ticker "AKRBP".
Information about Aker BP entities included in the consolidated financial statements is available to the public. Read more about Aker BP at
Strong performance by the Aker BP team successfully took us through yet another volatile year. We enter 2022 with a robust financial position and an investment portfolio that will secure growth and further value creation. However, as this letter is published in March, our deep concerns over the war in Ukraine and the suffering of the Ukrainian people overshadow everything. We are witnessing great uncertainty in the European energy supply. Our work to secure a stable low cost and low carbon oil and gas production is more important than ever.
At the heart of our achievements and ambitions is the fantastic Aker BP team - a team I am privileged and proud to lead. We intend to lead our industry on the most important parameters: low-cost, low-carbon, and substantial profitable growth. The serious situation in Europe in the start of 2022 has made our work and ambitions even more meaningful.
Mergers and acquisitions have created us and made our company one of the largest listed oil and gas companies in Europe. As a result, we are a diverse team comprising many different stories, backgrounds, expertise, and great knowledge. When all of this is merged into one team it gives us a strong competitive edge.
At Aker BP, programmers work with petroleum engineers, and robotics experts team up with maintenance crews. Together we challenge commonly held industry "truths." At the core of our identity is the drive to always do our best and relentlessly seek improvement. The result is a culture that fosters individual growth and advances our company and our industry.
in gross operated emissions through electrification, energy efficiency and portfolio
in gross operated emissions with all assets electrified
Evaluating decarbonisation strategy to achieve
Net zero by 2030
I believe a strong, improvement-driven attitude is a hallmark of future-fit oil and gas companies. It will prove critical in meeting the challenges facing our industry.
As the energy transition advances, the world will undoubtedly become less dependent on fossil fuels. However, in all relevant scenarios set forth in the Paris Agreement on Climate Change, oil and gas continue to meet a significant proportion of the world's energy demand. Oil and gas will coexist with renewable energy for decades to come.
Aker BP will continue as a pure-play oil and gas company. That is fundamental to our strategy. We are proud of who we are and what we do. We produce energy that the world will continue to depend on for years, as well as the raw materials for a wide range of products that people across the globe use in their daily lives. Our contribution to the energy transition is threefold.
In maximizing our value creation, our owners and the societies in which we operate will benefit. We contribute capital and
taxes — resources that can be redeployed in alternative energy projects and emerging industries.
In our climate strategy, we have committed to reducing our gross Scope 1 emissions by 50 percent by 2030 and 100 percent by 2050. Although cutting emissions is indisputably important from an environmental perspective, it will also directly impact Aker BP's financial performance as the cost of emitting CO2 rises.
We contribute to the growth of emerging industries by sharing our know-how and technology. In return, we gain access to forward-looking solutions and technological advancements. This exchange enables us to improve our profitability and further reduce our emissions.
The global energy transition will require massive financial funding. I am proud of Aker BP's contributions of capital to our owners and the substantial taxes we pay to the Norwegian government. However, we acknowledge that even the significant efforts outlined above will ultimately be insufficient. That is why we are ambitiously raising the bar and evaluating a decarbonisation strategy to bring us to net zero by the end of this decade.
In 2021 our revenues increased by 90 per cent compared to the year before and ended at a record-high USD 5.7 billion. The increase was mainly driven by a significant increase in oil and gas prices. Net profit was USD 851 million, or USD 2.37 per share.
I am convinced that the oil and gas companies with the lowest production costs and emissions will be the future winners in our industry. Aker BP's strong financial performance is attributable to safe, sustainable, and cost-effective operations and we work consistently across our assets to continually drive improvements.
In 2021, our net production was 209 thousand barrels of oil equivalent per day. Our production efficiency was 85 percent, and production costs for the full year amounted to USD 9.2 per barrel produced. We work every day to further reduce emissions from our operations. Our emissions intensity in 2021 was 4.8 kg CO2 per barrel of oil equivalent, a performance that places us firmly among the top-tier operators worldwide. Moreover, we continued our positive safety trend, with a reduction in our serious injury frequency rate and zero process safety incidents.
Our primary financial priorities in Aker BP are to maintain our strong financial capacity and secure a high degree of financial flexibility. These factors will prove decisive for our ability to invest in profitable growth and generate value for our stakeholders and society at large.
In 2021, we paid dividends totaling USD 487.5 million to our shareholders. For 2022, we plan to increase this to USD 684 million, or USD 1.9 per share, in total dividends to be paid in four quarterly installments in 2022.
Aker BP will pay taxes of around USD 1.5 billion for the fiscal year 2021, and we expect our tax payments to rise substantially over the coming decade. Taxes are not only important in maintaining the Norwegian welfare system. As I mentioned, our tax payments are also key contributions to a successful transition to the renewable energy society.
Aker BP enjoys a unique financial position. Our balance sheet has never been more robust. We have an ambitious investment program leading up to 2030, maturing over 700 million barrels net to Aker BP. We are developing a large hopper of projects all remain profitable even if oil prices drop to low levels.
The largest of our projects is the coordinated development of licences in the NOAKA area. Gross resources in the area are estimated at 600 barrels of oil equivalent, with additional exploration and upside potential. In 2021, a concept was selected for the Aker BP-operated NOA Fulla and the Equinoroperated Krafla. Both development projects are progressing according to plan, and final investment decisions are expected by year-end 2022.
Another major joint development following the same timeline is the New Central Platform (NCP) on Valhall and the tie-in of King Lear. These projects will secure continued high production and extended lifetime for the Valhall area and provide access to additional gross resources of more than 200 million barrels of oil equivalent.
Aker BP's unique alliance model is a prerequisite for these investments that has proven its worth over several years. In this model we work together with strategic partners as one team with shared goals and incentives, and I can truly say that our alliance partners have helped us pull through numerous challenges.
Our alliance model ensures that a large proportion of project contracts are awarded to Norwegian suppliers. This in turn contributes to the technological development of Norway's supplier industry and provides employment and job security at yards as the global energy transition progresses.
The NOAKA, NCP, and King Lear developments will be powered from shore. These large-scale projects will result in enormous value creation and positive ripple effects without giving rise to any significant increase in our greenhouse gas emissions. As such, they are fully in line with Aker BP's strategy.
Oil and gas output from the Norwegian Continental Shelf is facing natural decline. Thus, it is important to identify new opportunities. The most valuable and cleanest barrels are those that can be produced using infrastructure already in place, which is why Aker BP's exploration activities are mainly concentrated around existing fields.
In 2021, we drilled and participated in 10 exploration wells. In 2022, we are stepping up our exploration activities under an ambitious exploration program, which comprises a total of 13 wells targeting a net unrisked volume of more than 250 million barrels of oil equivalent.
In addition to finding and developing new fields, a key part of our growth strategy is to acquire additional quality assets. Our disciplined approach to mergers and acquisitions has proven successful.
On 21 December 2021, Aker BP announced a transaction agreement with Lundin Energy AB, under which Aker BP will acquire all of Lundin Energy's oil and gas-related business activities. The transaction is subject to approval by the shareholders of both companies at their respective general meetings as well as approval by relevant regulatory authorities. We expect the transaction to close around mid-2022.
We expect rapid and fundamental changes to our industry. The current uncertain situation in Europe has intensified this expectation. Our response is to create an even stronger pureplay oil and gas company. Our most resilient strategy remains to produce oil and gas at the lowest possible cost and with a minimal carbon footprint. I assure you that Aker BP will be an industry leader on both these parameters, and as such will continue to play an important part in the European energy supply.
Going forward, we will explore, find, develop, and produce more oil and gas. We will aggressively chase improvements through digitalization, our alliance model, and an effective and streamlined company structure. Moreover, we will continue to target attractive growth opportunities.
My goal is for Aker BP to set the benchmark on all aspects relevant to the oil and gas industry. I am convinced that with our strategy, financial robustness, project portfolio, growth ambitions, and the best team in the industry, Aker BP will prove impossible to beat.
We are creating an oil and gas company fit for the future, and we will pursue our objectives with an intensity never before seen in our industry.
KARL JOHNNY HERSVIK CEO, Aker BP ASA
P50 reserves development P50 reserves 2021
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Jan 2021 Apr 2021 Jul 2021 Oct 2021 Jan 2022
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| Key figures | Units | 2021 | 2020 | 2019 |
|---|---|---|---|---|
| Total income | USDm | 5 669 | 2 979 | 3 347 |
| EBITDA | USDm | 4 541 | 2 128 | 2 286 |
| Net profit/loss | USDm | 851 | 45 | 141 |
| Earnings per share (EPS) | USD | 2,37 | 0,12 | 0,39 |
| Capex | USDm | 1 427 | 1 306 | 1 667 |
| Exploration spend | USDm | 434 | 246 | 501 |
| Abandonment spend | USDm | 204 | 178 | 109 |
| Production cost | USD/boe | 9,2 | 8,3 | 12,4 |
| Taxes paid | USDm | 223 | -181 | 619 |
| Net interest-bearing debt | USDm | 1 742 | 3 647 | 3 493 |
| Leverage ratio | - | 0,33 | 1,5 | 1,2 |
| Key figures | Units | 2021 | 2020 | 2019 |
|---|---|---|---|---|
| Alvheim area | mboepd | 46,5 | 55,4 | 54,4 |
| Ivar Aasen | mboepd | 16,7 | 20,1 | 21,8 |
| Johan Sverdrup | mboepd | 63,0 | 51,9 | 7,9 |
| Skarv | mboepd | 29,0 | 21,0 | 22,3 |
| Ula area | mboepd | 7,8 | 11,0 | 8,5 |
| Valhall area | mboepd | 46,4 | 50,7 | 39,0 |
| Other | mboepd | 0,1 | 0,5 | 1,9 |
| SUM | mboepd | 209,4 | 210,7 | 155,9 |
| Liquids price | USD/boe | 69,2 | 40,0 | 64,8 |
| Gas price | USD/boe | 88,5 | 21,8 | 29,1 |
Elena-Michelle Erstad Dale presented the PDO to Secretary of State Tony Christian Tiller.
2021
Aker BP delivered oil and gas at low cost and with low emissions in 2021. Here are some of the most important highlights from the year.
Aker BP was awarded 10 new licences in the APA 2020.
Moody's Investor Service upgraded the long-term issuer rating of Aker BP from Ba1 to Baa3, with stable outlook.
Aker BP farmed in to new licence on the UK continental shelf in the greater Alvheim area.
A campaign to plug abandoned wells at Valhall was completed, six years ahead of plan, and five billion NOK below budget.
The Hod B platform was safely installed offshore.
Aker BP (operator) and licence partners ConocoPhillips and Lundin Energy Norway submitted a Plan for Development and Operations (PDO) for the Kobra East & Gekko project, which will extend the lifespan of the Alvheim FPSO to 2040.
The Gråsel field started production through the Skarv FPSO.
The Quarter Platform (QP) jacket was removed from the Valhall field centre, after 41 years in the North Sea. 98% of the steel was recycled at Aker Solutions' yard in Stord.
Aker BP awarded contracts worth NOK 1.8 billion for the facility scope of the KEG development..
The new Hod B platform was safely installed offshore, only 14 months after cutting the first steel.
The Aker Family launched an advertising campaign promoting the group's strategy and contribution to the energy transformation.
Former mayor of Stavanger, Kari Thu and Head of Automation at Ula, Roger Gabrielsen.
Aker BP awarded FEED contracts worth NOK 700 million to the field development of NOA Fulla.
Aker BP (operator) and licence partners Vår Energi and Lundin Energy Norway submitted a Plan for Development and Operations (PDO) for the Frosk field in the Alvheim area.
Aker BP celebrated 5 years.
October Ula celebrated 35 years.
Aker BP reported all time high incomes in the third quarter, due to stabile operations, high oil and gas prices.
The Ærfugl Phase 2 started production through the Skarv FPSO, ahead of schedule and on budget.
Aker BP made a concept select decision for King Lear and the New Central Platform at the Valhall field centre, and awarded FEED contracts worth NOK 400 million.
Øyvind Eriksen, Chairman of the board in Aker BP and Nick Walker, President and CEO of Lundin Energy.
Aker BP (operator) and licence partners Equinor and Spirit Energy affirmed the investment for the development of the Hanz discovery in the Ivar Aasen area.
Aker BP announced the acquisition of Lundin Energy's oil and gas activities. (Subject to AGM and regulatory approvals).
The debate surrounding the environmental impact of oil and gas production was a source of annoyance for Siril Rusten. So she got to work and made a video; a video that was ultimately viewed by hundreds of thousands of people.
Siril Rusten is a Process Technician at Valhall. During autumn 2021, she made a humoristic film clip about her work at Valhall. Rusten was inspired by the fierce debate surrounding exploration for and production of oil and gas during the campaign leading up to the Norwegian parliamentary election in September.
"I was annoyed by people arguing against our industry, while they had no idea how the oil industry actually operates, for example as regards emissions. This was the main reason I thought such a video was needed, and after seeing the response, it's obvious that many people had the same opinion as me," says Siril Rusten.
In the first part of the film, she parodies how oil workers are portrayed as not caring for the environment, while the last part of the film explains how they really work at Valhall to minimise emissions and environmental impact.
The film clip was first shown at an internal town hall at Aker BP and later published on social media. The reaction was overwhelming; more than 370,000 viewers on Facebook, and thousands more who watched the clip on other social media platforms channels. It's the most popular social media post ever for Aker BP.
"I got a vast number of reactions from friends, family, colleagues, acquaintances, as well as people I didn't know," says Rusten.
376,230 persons reached
51,778 persons engaged
Rusten was happy to receive a considerable amount of positive responses.
"Most of the feedback I got was people applauding me for making an honest and informative video which delivered its message in a fun way."
The video also made an impact on future oil workers.
"Schools thanked me because several students who wanted to work in the oil industry were about to change their choice due to what they were seeing on TV. They were worried that they wouldn't get a job. But students were so relieved after seeing my video that they dared to follow their dream anyway."
At year-end, Siril Rusten was nominated as a person to be proud of in Aker BP. The Petro Ladies club put her on the shortlist for Petroleum Lady of the Year, along with others such as the Norwegian minister of petroleum and energy, who eventually won the award.
"I think the video became so popular because it's funny. With all the likes, views, shares, and comments, the response ultimately shows that a lot of us are proud of our oil," she says.
The transformation of Valhall continues and will enable the field to operate up to around 2060 with minimal emissions and significant gas production.
Comprehensive modernisation of the area is underway, with the tie-in of new flank platforms, removal of the obsolete old drilling platform (DP) and processing platform (PCP), and permanent plugging of wells.
Fast and efficient plugging of wells on the drilling platform (DP) is - again - a significant achievement in 2021. Three infill wells were drilled on the North Flank, delivered without incident, under budget, and ahead of schedule. Valhall has a proven track record of delivering flank projects!
The Hod project was kept on schedule and installed during the summer. The drilling was conducted safely, securely – and fast. It will be remotely operated from Valhall when it goes on stream during the first half of 2022, expecting to produce 40 million barrels of oil equivalent.
There has been an enormous amount of activity on the field throughout 2021, despite significant challenges related to Covid-19 and introducing a new operating model. As an example, two rigs worked at the field simultaneously.
Both the rig activity and other major projects were conducted without serious incidents, but three minor medical treatment incidents were recorded, which shows room for improvement. No one shall be injured at Valhall.
Production in 2021 was 46.4 mboed, below the target of 49 mboed. During the spring, Valhall experienced significant challenges with multiple wells and shutdowns due to weaknesses in the control system.
However, the Valhall team managed to overcome the challenges, and achieved facility uptime of more than 98 per cent during autumn. All wells were repaired and put on stream. Production efficiency for the full year ended at 82 per cent, as compared with the target of 86 per cent.
Aker BP has decided to go forward with one of its most significant development projects: A new central platform (NCP) at Valhall and a tie-in of the King Lear field. A preferred concept has been selected, and Aker BP and its partners aim for a final investment decision in late 2022. The first oil and gas are planned for 2027.
King Lear is a gas condensate field, targeting customers in Poland as a replacement for coal. The Valhall complex will become a full-fledged hub, having the significant capacity needed to process gas and oil from the greater Valhall area.
The King Lear concept consists of a new process and wellhead platform (NCP), with a bridge connection to the Valhall field centre and a remote-controlled platform on the King Lear field around 50 km from the Valhall field centre. New infrastructure will be laid on the seabed to connect the two fields.
A total of 19 wells are planned, and the concept also includes considerable modification work on the Valhall field centre.
In 2022, Valhall will celebrate 40 years since its opening – a year that will truly symbolise the change in field life.
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The team at Ivar Aasen faced major challenges during 2021 but showed an incredible willingness to tackle the obstacles.
Excellent HSE performance has been delivered, with no significant injuries to personnel and zero process safety events.
Production has been below the target for 2021 at 16.7 mboed, as compared with the target of 18.1 mboed. This is related to a natural production decline and two notable events that impacted the production.
Two production wells started production (D-17 & D-12) early in 2021. The wells created substantial clean-up challenges, but the initial problems were solved after a great team effort.
The transformer at Edvard Grieg which provides power to Ivar Aasen failed in September and had to be shipped onshore for repair. After two months of reduced production, the transformer was re-installed, tested and started up again after an intense period and work effort.
Production efficiency for 2021 was 87 per cent, in contrast to the target of 92.5 per cent. This performance is related to the events described above.
The first subsea tie-back to the Ivar Aasen field, Hanz, was sanctioned in December 2021. The reservoir contains 20 million barrels (gross) of oil. It is a unique project that will use cross-flow injection for pressure support and re-use subsea equipment from the Jette field. This means that Hanz has a significantly smaller environmental footprint than comparable subsea developments.
Two significant activities will be at the centre of attention in 2022 —a turnaround (TAR) and start-up of power from shore. Currently, Ivar Aasen is supplied with electricity from gas turbines at the Edvard Grieg platform, but Phase 2 of Johan Sverdrup will provide power to Ivar Aasen starting from the fourth quarter of 2022. The gigantic field gets its electricity from the Norwegian mainland. Power from shore at Ivar Aasen will result in minimal CO2 emissions, more stable operation, and higher production efficiency.
Drilling activities planned at Ivar Aasen for 2022 include both an Improved Oil Recovery (IOR) campaign with two new production wells and one injection well, in addition to infrastructure-led exploration wells (ILX). The Lille Prinsen project, a candidate for tie-in to Ivar Aasen, will also be further matured in 2022.
*(test production from Ærfugl A-1H 2013)
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2021 marks a historically comprehensive plant upgrade at Skarv FPSO, highlighted by topside completion and the start of production from both Ærfugl Phase 2 and Gråsel.
Skarv is now the largest operated field in Aker BP's portfolio currently in production, from a gross perspective.
Full-year production ended at 29 mboed. The target was 30.5 mboed. About three-quarters of the output was gas. This is the highest level of processed gas through Skarv, and the FPSO is producing in line with the production record from 2013.
Gas prices continued to increase through 2021 and ended the year at very high levels. Skarv optimised its gas production through this period to adapt to the market situation.
Production start of the very profitable Gråsel field is an example of the value to be gained from creative early phase work, new well technology and efficient and safe execution.
During summer, the one-month planned turnaround increased the processing capacity to new levels and was conducted in a real 'one team' spirit, both in advance and during implementation. This led to starting production from the final phase of the Ærfugl project with two new high-producing wells.
Production efficiency for 2021 came in under the target of 90 per cent and ended at 82 per cent.
Well intervention operations were performed during the year to mitigate early water breakthrough experienced on some of the wells from the first phase of the Ærfugl project. This proved successful on one of the wells and will be further evaluated to reduce potential future water production.
2022 will be a year for stable production with minimum modifications to the facilities. Together with the partners, a drilling campaign including three operated and two partneroperated exploration wells will be underway during the summer of 2022.
High regularity and plan stability are priorities during 2022 to establish Skarv FPSO at a top-notch performance level and lay the foundation for future development through the Skarv Satellite Project (SSP).
The Skarv Satellite Project (SSP) is a more extensive portfolio of four tie-backs around Skarv. Aker BP is the operator, and the total volumes are estimated to be 120 million barrels. SSP will be one of the most significant subsea projects on the Norwegian Continental Shelf.
2021 marked the year when Ula transitioned into a late-life strategy, setting up the asset for safe, reliable and cost-effective operation in the years to come.
Experience transfer from other assets in the late-life phase has been conducted and adapted into the strategy process.
Ula experienced several injuries during 2021. In total, six injuries with medical treatment were recorded. The asset organisation has conducted a targeted health, safety and environment- (HSE) campaign highlighting risk assessments and safe execution of work.
Production Efficiency (PE) on Ula and Tambar finished lower than expected, where unplanned shutdowns and plant challenges related to produced water treatment had the greatest impact. The 2021 target for PE was set at 85.2 per cent, with actual performance of 76.2 per cent. The underperformance also affected production results, with an actual production of 6.4 mboed at year-end versus a target of 10.6 mboed.
Two infill wells were drilled during 2021, one on Tambar and one on Ula. Both were delivered ahead of schedule thanks to good cooperation between the operations and drilling teams. However, the outcome was in the lower end of the resource range.
A third gas turbine was installed and progressed to a Mechanical Complete stage during 2021. The remaining work is to conduct the commissioning and start-up phase before the final handover to operations by mid-2022. This is the last turbine to be installed, and Ula will now have a complete and upgraded power generation system. An important project to ensure barriers for overpressure protection was also completed.
The total scope of activity will be reduced in 2022, and the modification portfolio will be adjusted to a lower manning level. A turnaround (TAR) in 2022 will be significant to ensure the condition of the plant in the coming years. The well maintenance and intervention program will be a key part of the activity, ensuring well integrity and securing production.
One of the critical deliveries during 2021 has been to develop a technical lifetime plan for the offshore facilities. In addition to understanding the well intervention plan and reserve base, this work is the key component to build the short and long-term plan for the Ula lifetime. The licence period expires in 2028 and efforts will be required to ensure the necessary flexibility. This means that preparations to start licence and lifetime extension processes for Ula will be the next step in 2022. Safe and reliable operations with high plan attainment will be a critical success factor in the execution window.
THE ALVHEIM AREA
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There were no process safety events or serious injuries; however, there were two incidents requiring medical treatment on the Deepsea Nordkapp and Alvheim FPSO in 2021.
Alvheim has produced four per cent more than planned during 2021 and ended up with an average of 46.5 mboed net. Operational performance was strong throughout the year, with a production efficiency of 95 per cent. Once again, Alvheim continues to prove itself as a highly reliable organisation with a sustainable and robust record of accomplishments.
Field development activities in the Alvheim area in 2021 included completing the Boa Attic South infill well, which was put on stream in late March, and then drilling the Volund P5 Sidetrack well during the summer period. This well started production in November. A successful intervention job on the Frosk test producer was performed to regain integrity in the well, and production was re-started from one of two wellbores in November.
Furthermore, the dual-lateral well, Kameleon Infill West, was drilled in the fourth quarter of 2021, followed by tie-in operations at the start of 2022. Production from this well started mid-February 2022.
Other activities in the Alvheim area during 2021 included:
The Alvheim produced water capacity upgrade project continued its execution phase through 2021 with a completion plan during the first half of 2022. The installation is being done in conjunction with a gas debottlenecking project, which Aker BP expects will increase the gas capacity by approximately 15 per cent. Together, Aker BP anticipates these projects will improve the capacity for future tie-back projects at Alvheim.
The Asset's technical lifetime has been extended until 2040, which provides opportunities for future developments in the area.
Two plans for development and operation (PDO) were submitted to the authorities in 2021; the first was the Kobra East and Gekko (KEG) development. This project is a subsea development tied back to the Alvheim FPSO with four tri-lateral wells through the Kneler B manifold. Base case PDO reserves of 40 mmboe were increased to 50 mmboe due to the extended lifetime of the Alvheim Asset. The second PDO was the Frosk development, a subsea tieback to the Alvheim FPSO through the Bøyla template with two new production wells. A PDO for Trell & Trine is scheduled for submission in Q3 2022.
Drilling on Frosk is planned to start in mid-2022, followed by KEG and Trell & Trine. Drilling activities in the Alvheim area will continue for the next couple of years.
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Johan Sverdrup is and will continue to be an incredible oil field, Norway's 3rd largest, containing nearly three billion barrels of recoverable oil equivalent.
Johan Sverdrup has production properties never heard of before, anywhere in the world. The field will form the backbone of Norwegian oil production for the next 50 years.
The production wells each deliver close to 50,000 barrels of oil per day. A recovery factor of almost 70 per cent was assumed in the Plan for Development and Operation (PDO). After starting up, both ramp-up (commissioning of the pre-drilled oil production wells), the well capacity in each well, the processing capacity and the regularity have proven to be even better than expected.
In February 2021, Phase 1 of Johan Sverdrup was fully repaid, just 16 months after start-up and despite the oil price collapse in 2020.
Process capacity was increased from 380,000 barrels per day in the 2015 PDO to 530,000 barrels per day in 2021. At the same time, regularity remained high.
As of the end of 2021, more than 350 million barrels of oil has been produced from Johan Sverdrup (approx. 12 percent of the reserves). Aker BP's share has been nearly 45 million barrels, at a sales value of more than NOK 20 billion.
Depending on oil prices, Johan Sverdrup will contribute a staggering NOK 1400 billion in sales revenue over a life
expectancy of 50 years. NOK 900 billion of this goes to the Norwegian state and its people.
Aker BP's expected share of sales revenue from Johan Sverdrup over the lifetime is in the order of NOK 160 billion.
In 2021, production from Johan Sverdrup accounted for around one-third of the company's total production and sales revenue. The operating cost at Johan Sverdrup is only around USD two per barrel.
Development of Phase 2 is now in the final phase, ahead of schedule - and still has good HSE results, despite Covid-19.
New investments of just over NOK 40 billion will make it possible to extract oil from the fringe areas of the field, thanks to around 30 new wells – for which drilling started in January 2022. The plan calls for a new process platform - P2 - to be installed offshore in spring 2022 and this will increase process capacity by 35 per cent, from the current 535,000 barrels per day to 720,000 barrels per day.
Aker BP's share will increase from 66,000 to 89,000 barrels of oil equivalent per day. Production start is planned for Q4 2022.
Ongoing studies indicate that production at full field capacity can be increased to 755,000 barrels per day.
A formal concept was selected in the NOAKA area in 2021, and the resource base was upgraded to 600 million barrels of oil equivalent.
Aker BP currently estimates gross investments in the area at USD 10 billion, and the break-even oil price meets the company's hurdle of USD 30 per barrel.
NOAKA is located between Oseberg and Alvheim in the North Sea. The area holds several oil and gas discoveries, with further exploration and appraisal potential.
Together with the other partners in the licences, Equinor ASA and LOTOS Exploration & Production Norge AS, Aker BP is on track for a final investment decision before year-end.
Aker BP is operator of NOA Fulla in the southern part of the NOAKA area. A processing, drilling, and living quarters platform located at the Frigg Gamma Delta field, NOA PdQ, will function as an area hub. The Fulla, Langfjellet and Rind fields will be tied back to NOA PdQ. The Frøy field will be re-developed with a normally unmanned installation, a copy of the Hod B and Valhall Flank West platforms.
Equinor is operator of Krafla in the north. Aker BP holds a 50 per cent ownership interest in Krafla, and the investments in the Krafla development represent the company's largest non-operated investment ever.
Krafla will be developed with an unmanned production platform with five subsea templates and tied back to the NOA PdQ for oil and produced water processing.
Oil will be exported via the Oseberg transport system and gas will be exported through Statpipe.
Power from shore paves the way for minimal greenhouse gas emissions in the NOAKA area.
NOAKA will deliver substantial value for Aker BP, shareholders, partners and society at large. A significant number of the contracts are expected to be awarded to Norwegian suppliers. Consequently, the area development will contribute to developing the supplier industry and securing important activity at the yards, as they move into the energy transition.
Aker BP has mobilised alliance partners across the value chain to deliver the NOA Fulla project. Front-end engineering and design (FEED) contracts worth approximately USD 80 million were placed in September 2021. The FEED work is progressing as planned.
The ambition is for NOA Fulla to be the most digital offshore field development to date – both in the project execution and operations phases. A major digital project is ongoing together with strategic partners.
SHAREHOLDER-ELECTED CHAIR AND CHAIR OF THE COMPENSATION AND ORGANSATIONAL DEVELOPMENT COMMITTEE
Eriksen is the President and CEO of Aker ASA. He has worked for Aker since 2009. Eriksen has extensive experience as a corporate attorney from the Norwegian law firm BA-HR, where he started in 1990, became a partner in 1996 and a director/ chairman in 2003. He has worked with strategic and operational development, M&A and negotiations. Eriksen has held several board positions in various industries including shipping, finance, asset management, offshore drilling, fisheries, media, trade and industry. Eriksen holds a law degree from the University of Oslo.
Eriksen is chairman of the board in Aker BP ASA, Cognite AS, Aker Capital AS, Aker Holding AS, Aker Horizons ASA, Aker Property Group AS, C4IR Ocean, the VI Foundation, and REV Ocean AS. He is also a director of several companies, including Aker Solutions ASA, Aker BioMarine ASA, Aker Energy AS, Aker Carbon Capture ASA, Aker Clean Hydrogen AS, Aker Mainstream Renewables AS, The Resource Group TRG AS, TRG Holding AS and the Norwegian Cancer Society (Kreftforeningen). He is also a member of the World Economic Forum C4IR Global Network Advisory Boar.
| Aker BP shares*: | None*** |
|---|---|
| Member of the board since: | 2016 |
| Independent of major shareholders: | No |
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1964 |
** Family relations to other members of the Board or members of the Executive Management Team
*** Though exposure to the Aker BP share price through shareholding in Aker ASA
Kjell Inge Røkke
SHAREHOLDER-ELECTED MEMBER
Røkke has been a driving force in the development of Aker since the 1990s. Røkke launched his business career with the purchase of a 69-foot trawler in the United States in 1982, and gradually built a leading worldwide fisheries business. In 1996, the Røkke-controlled company RGI purchased enough Aker shares to become Aker's largest shareholder, and later merged RGI with Aker. Røkke owns 68.2 per cent of Aker ASA through The Resource Group TRG AS and subsidiaries.
Røkke is Aker ASA's primary owner and Chairman. He is currently a director in several companies, including Aker Solutions ASA, Aker BioMarine ASA and Aker Horizons ASA.
| Aker BP shares*: | None*** |
|---|---|
| Member of the board since: | 2013 |
| Independent of major shareholders: | No |
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1958 |
SHAREHOLDER-ELECTED DEPUTY CHAIR AND MEMBER OF THE AUDIT AND RISK COMMITTEE
Cannon has more than 40 years' experience in the oil and gas industry and investment banking and is an experienced director, holding executive and non-executive roles. She has served as the Deputy Chair of the board since 2013, and is a member of the Audit and Risk Committee and Organisational Development and Compensation Committee at Aker BP. Since 2019, she has been a Senior Advisor in the Strategic Advisory business at PJT Partners and from 2000, was a Senior Advisor at Morgan Stanley focusing on international upstream M&A. Prior to this, Cannon was an executive director on the boards of Hardy Oil & Gas and British Borneo, and earlier in her career was a director in investment banking at J Henry Schroder Wagg and held senior financial roles at Shell UK.
Cannon holds a Bachelor of Science (Honours) Degree from Glasgow University and is a Fellow of the Energy Institute.
Cannon is a non-executive director on the board of Aker Energy AS, STV Group plc and Harbour Energy plc.
| Aker BP shares*: | 12,078 |
|---|---|
| Member of the board since: | 2013 |
| Independent of major shareholders: | Yes |
| Family relations BoD/EMT**: | No |
| Citizenship: | British |
| Residency: | UK |
| Born: | 1957 |
SHAREHOLDER-ELECTED MEMBER AND CHAIR OF THE AUDIT AND RISK COMMITTEE
Brandsrud serves as a non-executive director and industry advisor. From 2016 to 2019, he held several CEO and CFO roles in the financial services companies Lindorff, Intrum and Lowell, and from 2010 to 2015, he served as the Group Chief Financial Officer of Aker. In the period from 2007 to 2010, he served as the CFO of the Seadrill Group. Prior to these roles, Brandsrud had 23 years of experience from leading finance positions in Shell.
Brandsrud holds a Master of Science degree from NHH Norwegian School of Economics.
Brandsrud is a non-executive director and board member of PGS ASA, the Lowell Group (Simon Midco Ltd) and Lowell Finans AS. He also has a part time executive assignment with Waterise AS.
SHAREHOLDER-ELECTED MEMBER
Doyle is Senior Vice President of Sales and Marketing at Cognite, where she also sits on the Executive Management Team. Doyle joined Cognite in 2018 and prior to that has held a variety of roles within the oil and gas industry for companies such as ABB and Siemens, in Norway and the Middle East. During her time in the Middle East, Doyle established and ran a non-profit industrial technology organisation. She has a deep knowledge of industrial software space and digitalisation processes in heavy-asset industries.
Doyle holds a PhD in Computer Engineering from the University of Limerick.
Key external appointments: None
SHAREHOLDER-ELECTED MEMBER AND MEMBER OF THE AUDIT AND RISK COMMITTEE
Thomson is the SVP Finance P&O for the BP p.l.c. Group, having previously held the positions of Group Treasurer and Group Head of Tax. In her current role she is responsible for commercial financial support, planning and performance for Production and Operations. Prior to joining BP p.l.c., Thomson qualified as a chartered accountant with Deloitte. She moved into international tax with Charter plc, where she became Head of Tax in 1998, before joining Ernst & Young in 2001 in M&A tax. Thomson is also a director of several BP p.l.c. Group companies and a member of the Institute of Chartered Accountants in England and Wales.
None
| Aker BP shares*: | None |
|---|---|
| Member of the board since: | 2018 |
| Independent of major shareholders: | Yes |
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1958 |
| None |
|---|
| 2021 |
| Yes |
| No |
| Irish |
| Norway |
| 1979 |
| Aker BP shares*: | None |
|---|---|
| Member of the board since: | 2018 |
| Independent of major shareholders: | No |
| Family relations BoD/EMT**: | No |
| Citizenship: | British |
| Residency: | UK |
| Born: | 1968 |
Murray Auchincloss
SHAREHOLDER-ELECTED MEMBER
Auchincloss joined Amoco Canada in 1992 and BP p.l.c. through the merger in 1999. He has built a career performing a range of commercial and leading roles across the company. Most recently he served as BP p.l.c.'s Upstream CFO (2015 to 2020).
Auchincloss holds a Bachelor of Finance degree from the University of Calgary. He also completed his Chartered Financial Analyst (CFA) certification in 1995.
Auchincloss is the Chief Financial Officer of BP p.l.c. He is a member of BP p.l.c.'s Executive Board and serves on the Main Board Audit Committee.
Terje Solheim
EMPLOYEE-ELECTED MEMBER AND MEMBER OF THE COMPENSATION AND ORGANSATIONAL DEVELOPMENT COMMITTEE
BP's Harstad office. He has been with Aker BP since 2013 and has held several positions with the company. Solheim was one of the founders of Norwegian Petro Services (NPS). He came to Aker BP from Det Norske Veritas (DNV).
Solheim has an extensive background from the Norwegian Armed Forces and is educated from the Norwegian Military Academy, Staff College Norwegian Armed Forces and Naval University of Monterey.
Key external appointments: None
EMPLOYEE-ELECTED MEMBER
Haugeberg serves as a full-time employee representative. Prior to this position, he was the HSSE Site Lead on the Ula field. Haugeberg has broad experience from the Royal Norwegian Air Force in Bodø as a technical grenadier and as department manager for Safelift A/S. He started in Amoco Norge as a mechanic on the Valhall field in 1991. He has held several positions in BP p.l.c. Norge since 1998. Haugeberg has also held a number of different directorships in BP p.l.c. Norge, Industrimaskiner A/S, Global Clean Energy, I/E Media and trippEl A/S.
Haugeberg was trained as an electromechanical repair tech at the Royal Norwegian Air Force technical school at Kjevik and has a company-approved bachelor in mechanics.
Key external appointments: None
| Aker BP shares*: | 0 |
|---|---|
| Member of the board since: | 2020 |
| Independent of major shareholders: | Yes |
| Family relations BoD/EMT**: | No |
| Citizenship: | Canadian |
| Residency: | UK |
| Born: | 1970 |
| Aker BP shares*: | 637 |
|---|---|
| Member of the board since: | 2018 |
| Independent of major shareholders: | Yes |
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1962 |
| Aker BP shares*: Member of the board since: |
948 2018 |
|---|---|
| Independent of major shareholders: | Yes |
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1962 |
* Number of shares in Aker BP ASA as of 31 December 2021
** Family relations to other members of the Board or members of the Executive Management Team
Tore Vik
EMPLOYEE-ELECTED MEMBER
Tore has been employed by Aker BP since 2013 and is a full-time trustee. He has previously worked as an electrician on the Ivar Aasen platform.
Tore has over 30 years of experience as an electrician with both high-voltage and low-voltage papers. He has worked many years as an electrician / automator on drilling rigs and on ships.
EMPLOYEE-ELECTED MEMBER
Brevik has been employed by Aker BP since 2014. She is a process technician and works at Skarv FPSO. Brevik has worked offshore since 1998, for both Hydro and Statoil.
Brevik is the company's main trustee and has been a deputy employee representative to the Aker BP board since 2018.
Key external appointments: None
| Aker BP shares*: | 3,594 |
|---|---|
| Member of the board since: | 2021 |
| Independent of major shareholders: | Yes |
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1970 |
| Aker BP shares*: | 1,326 |
|---|---|
| Member of the board since: | 2021 |
| Independent of major shareholders: | Yes |
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1971 |
Karl Johnny Hersvik has been CEO of Aker BP since May 2014. Prior to joining Aker BP, he served as head of research for Statoil. Hersvik has held several specialist and executive positions with Norsk Hydro and StatoilHydro.
Hersvik holds a Cand. Scient. (second cycle) degree in Industrial Mathematics from the University of Bergen.
Hersvik is the chairman of the Board of Directors of Aker Energy AS, aiZe and Aker Clean Hydrogen. He is a member of the Board of Directors at Cognite and The Norwegian Oil and Gas Association.
Tønne has been the Chief Financial Officer of Aker BP ASA since January 2019 after advancing from the position of VP Corporate Controlling. Tønne has been with Aker BP since January 2017.
Prior to joining Aker BP, Tønne worked for the Boston Consulting Group where he co-led the Nordic Energy Practice Area supporting clients in O&G, Private Equity, Shipping and Industrial goods across a wide range of functional topics in Europe, North America and the Middle East.
Tønne holds a master's degree in finance from NHH Norwegian School of Economics.
Key external appointments: None
Dolve has been the SVP Operations and Asset Development since July 2020. She comes from the position of VP Operations & Asset development for Skarv in Aker BP. She has worked with the company since 2010 and been involved in various key projects to develop and improve both company and industry performance.
Prior to joining Aker BP, she worked in management consulting (PwC) within finance, management of change and digitalisation for O&G. She also has several years of experience from the Armed Forces, both nationally and internationally.
Dolve holds a master's degree in Finance and International Management from NHH Norwegian School of Economics / ESADE, Barcelona. She has also received education from the Air Force Officer Candidate School and the Norwegian Naval Academy in Bergen.
None
| Aker BP shares*: | 10,355 |
|---|---|
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1972 |
| Aker BP shares*: | 16,869 |
|---|---|
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1985 |
| Aker BP shares*: | 5,534 |
|---|---|
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1975 |
* Number of shares in Aker BP ASA as of 31 December 2021
** Family relations to other members of the Board or members of the Executive Management Team
Sandvik has been SVP Projects in Aker BP since July 2019. He has more than 30 years' experience from the oil & gas industry. Throughout his career, Sandvik has held various senior project and leadership positions across Aker companies, including four years as a member of the Aker Solutions Executive Management Team.
Sandvik holds a degree in Mechanical Offshore Engineering from Heriot-Watt University in Scotland.
None
Experience, skills and education: Kongelf is responsible for Aker BP's improvement program.
Prior to joining Aker BP, he served as head of Norwegian operations in Aker Solutions. He has more than 30 years of industrial experience from numerous technical and management positions in Aker Solutions.
Kongelf holds a master's degree from the Norwegian University of Science and Technology (NTNU).
Kongelf is a board member and Aker representative for Eureka Logistics AS, Eureka Pumps AS, FPE Sontum AS and Origo Solutions AS.
| Aker BP shares*: | 4,078 |
|---|---|
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1962 |
| Aker BP shares*: | 5,546 |
|---|---|
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1959 |
Blaasmo has been the SVP HSSEQ in Aker BP since May 2019. Prior to this, she was responsible for the Drilling & Wells performance and improvement agenda. Blaasmo has been with the company since August 2017.
She holds more than 18 years of experience from Equinor and Baker Hughes INTEQ and has held multiple operational and management positions within Drilling & Wells disciplines.
Blaasmo holds a master's degree in Petroleum Engineering from the Norwegian University of Science and Technology (NTNU).
Glørstad has been SVP Exploration since July 2018. She came from the position of Asset Development Manager for NOAKA. Glørstad has been with the company since 2011.
She has broad experience as a geologist in BP in Norway and the US and has held several managerial positions since joining the company.
Glørstad holds a Master of Science degree from the University of Bergen and a PhD in petroleum geology/sedimentology from the University of Oslo.
Key external appointments: None
Sigmundstad has been SVP Drilling & Wells in Aker BP since 2016. Prior to this, he was Vice President Wells in BP Asia Pacific.
Sigmundstad has broad experience within the oil and gas industry from companies such as Baker Hughes and Philips, before joining BP in 2000. Within BP, Sigmundstad has held various operational, engineering and management positions in Norway, the United Kingdom, Azerbaijan and Indonesia.
Sigmundstad holds a master's degree in petroleum engineering from the University of Stavanger.
Sigmundstad is a member of the board of directors in Fishbones.
| Aker BP shares*: | 4,688 |
|---|---|
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1975 |
| Aker BP shares*: | 9,423 |
|---|---|
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1975 |
| Aker BP shares*: | 10,038 |
|---|---|
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1970 |
* Number of shares in Aker BP ASA as of 31 December 2021
** Family relations to other members of the Board or members of the Executive Management Team
SVP STRATEGY & BUSINESS DEVELOPMENT
Experience, skills and education: Rosnes has worked at Aker BP as commercial advisor for strategy and business development since 2018.
He has more than 30 years of experience from leading positions in strategy, business development, commercial and projects from Petoro, Statoil and Shell, among others.
Rosnes holds a master's degree in petroleum technology from the University of Stavanger.
Key external appointments: None
Experience, skills and education: Høier has been SVP and Asset Manager for NOAKA since August 2020. He joined Aker BP in 2019 as VP for Concept Development and Technology.
Høier has more than 20 years of experience from Equinor, with positions as SVP for R&D, as well as production director for several assets, including the Troll field.
Høier holds a Master of Science degree in Physics from the University in Oslo and a PhD in Petroleum technology from the Norwegian University of Science and Technology (NTNU).
Key external appointments: None
| Aker BP shares*: | 408 |
|---|---|
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1965 |
| Aker BP shares*: | 6,671 |
|---|---|
| Family relations BoD/EMT**: | No |
| Citizenship: | Norwegian |
| Residency: | Norway |
| Born: | 1967 |
35
Aker BP reported excellent financial performance in 2021, driven by higher oil and gas prices, stable production, and good cost control. The company also delivered strong HSSEQ performance, with low emissions and a good safety record, and progressed its field development projects according to plan. At the end of 2021, the company has a significant resource base, a robust financial position, proven execution skills, and is well positioned for value creation in the years to come.
Aker BP is a pure play oil and gas company which has expanded to become one of the largest operators on the Norwegian Continental Shelf (NCS) through a combination of organic growth and M&A. The company's vision is to be the leading independent exploration and production (E&P) company producing its natural resources with low emissions and costs, while at the same time creating jobs and value for both shareholders and society at large.
On 21 December 2021, Aker BP announced an agreement with Lundin Energy AB to acquire Lundin Energy's oil and gas related activities to create the second largest oil and gas producer on the NCS. Following the transaction, Aker BP will operate six major production hubs on the NCS and be the second largest owner of the giant Johan Sverdrup oil field. With estimated pro forma production of above 400,000 barrels per day in 2022, industry-leading metrics on carbon emissions and operating costs, and a strong outlook for profitable growth, the combined entity will be well positioned for future value creation.
Environmental, Social and Governance (ESG) issues are of the highest importance to the Board of Directors of Aker BP. The Board recognises its responsibility for the safety of people and the environment and devotes appropriate time and resources to comply with all regulations and adhere to the highest standards in the oil and gas industry regarding Health, Safety, Security, Environment and Quality (HSSEQ).
Aker BP's overall HSSEQ performance improved in 2021 with a continued low number of injuries and serious incidents. The company had zero Process Safety Events in 2021. Three incidents with high potential were reported. These incidents, as well as all other incidents with low to moderate potential, have been thoroughly investigated, and the lessons learned have been shared across all operated assets. Overall, this HSSEQ performance is a strong achievement during a challenging year with regards to the Covid-19 pandemic. Maintaining and further improving the HSSEQ performance requires relentless efforts and continuous attention. Aker BP continues to further strengthen its safety culture based on a strong foundation of systematic learning from incidents and structured risk management.
It is the view of the Board that Aker BP can contribute positively to the energy transition along three axes. Firstly, by maximising its long-term value creation, the company also maximises its contribution to the society in the form of taxes, job creation and other ripple effects, as well as its capacity to distribute value to its shareholders. Secondly, the company is committed to minimising direct and indirect GHG emissions from its operations, and hence contribute to reducing the carbon footprint of the oil and gas industry. And thirdly, Aker BP is promoting a culture for industrial collaboration, innovation and data sharing to develop new technologies and ways of working to improve efficiency and reduce emissions.
Aker BP's CO2 intensity in 2021 was below 5 kg CO2 per barrel of oil equivalent (equity share), in line with the company's goal. This is less than half of the global industry average and significantly below the average for the NCS. In addition, Aker BP methane emissions remain low (0.02 percent methane of saleable gas in 2021).
In 2021, Aker BP implemented its new operating model. The purpose of this model is to improve safety and production efficiency and to reduce costs through standardisation within areas such as HSSEQ, maintenance, digital operations, procurement, and logistics. The new operating model provides a good framework for driving performance through transfer of best practice, utilisation of scale economics and continuous improvement.
The operational performance in 2021 was largely in line with the plan. Net production ended up at 209.4 (210.7) thousand barrels of oil equivalents per day (mboepd), slightly lower than the initial expectation of 210-220 mboepd. The fields Johan Sverdrup and Alvheim produced above expectations, while Ula and Valhall were below. Production cost ended at USD 9.2 (8.3), slightly higher than the expectation of USD 8.5-9.0, mainly driven by increased power costs towards the end of the year.
The company has over many years been working systematically to develop strategic alliances with its main suppliers. The alliance model is designed to align incentives, remove waste and drive continuous improvement with a One Team culture. These alliances now cover significant parts of the company's supply chain and provides Aker BP with significant project execution capabilities which will be essential in the years to come.
The field development activities in 2021 progressed according to plan, including phase 2 of the Ærfugl development, Johan Sverdrup phase 2 and Hod. First oil from Ærfugl phase 2 was achieved during 2021. Hod production is currently expected to start around mid-2022, a few months later than original plan due to late arrival of an installation vessel. Johan Sverdrup remains on track for first oil in fourth quarter 2022.
Aker BP has a large resource base, with 2P reserves of 802 (842) mmboe and 2C contingent resources of 1,022 (895) mmboe at the end of 2021. This represents a unique opportunity set for profitable growth. The company's ambition is to develop a large part of these resources over the coming years, and several major projects like NOAKA and Valhall NCP & King Lear are being matured for final investment decisions by the end of 2022.
Aker BP's capital allocation framework concentrates on three main priorities. The first is to maintain sufficient financial capacity through the cycle, safeguarding its investment grade credit profile. The second is to invest in profitable growth, with an established break-even oil price hurdle of USD 30 per barrel for sanctioning new projects using a 10 percent discount rate. The third is to return value creation to shareholders, including an ambition to grow dividends by a minimum of five percent per annum at oil prices above USD 40 per barrel.
At the end of 2021, the company's financial position was stronger than ever, with total available liquidity of USD 5.4 billion, a conservative leverage ratio of 0.3, no debt maturities before 2025, and investment grade credit ratings from the three leading rating agencies.
The Board is of the opinion that Aker BP is well positioned for further value accretive growth on the NCS. At the same time, the Board is conscious of the risks associated with project execution and the changing market conditions in which the
company operates. The Board is prioritizing capital discipline and mitigation of risk wherever possible throughout the organization.
The start of 2022 was marked by increased geopolitical tension and high macroeconomic uncertainty. The situation escalated with the Russian invasion of Ukraine on 24 February. This a serious setback for peace and democracy in the world and has left its mark on the international economy as well as on energy prices.
Aker BP's shares are listed on Oslo Børs with ticker symbol AKRBP and are freely negotiable. The total number of shares issued is 360.1 million, unchanged from the previous year.
The two major shareholders are Aker ASA with 37.14 percent and bp p.l.c. with 27.85 percent of the shares. The remaining 35 percent of the outstanding shares are held by a diversified group of more than 25,000 shareholders.
In 2021, the share price for Aker BP ended at NOK 271.6 per share, compared to NOK 216.2 per share at the end of 2020.
Aker BP is a Norwegian oil and gas company with exploration, development and production activities on the Norwegian Continental Shelf, ranking among the largest independent E&P companies in Europe measured by production. Its market capitalisation as of 31 December 2021 was USD 11.1 billion (NOK 97.8 billion). Headquartered in Bærum, Norway, with branch offices in Stavanger, Trondheim, Sandnessjøen and Harstad, Norway, Aker BP had 1,839 total employees, a portfolio of 124 licences, with 80 as operator and 44 as a field participant as of 31 December 2021.
Intro Assets BoD & EMT BoD's report Payments to governments Corporate governance Financials
Aker BP's oil and gas production in 2021 averaged 209.4 (210.7) mboepd. Of this, 82 percent was oil and liquids, while 18 percent was natural gas. The production comes predominantly from six fields or hubs: Alvheim, Ivar Aasen, Johan Sverdrup, Skarv, Ula, and Valhall.
The Johan Sverdrup field is operated by Equinor and came on stream in October 2019 after a successful construction and installation phase. Phase 1 of the project consisted of four large bridge-linked platforms (the field centre), Norway's largest oil export pipeline, a gas export pipeline, three subsea water injection templates, 20 pre-drilled production and water injection wells, and 100 megawatts power from shore.
The processing capacity for Johan Sverdrup Phase 1 at start-up was 440,000 barrels per day (bblpd). During 2020, it was established that the capacity exceeded the initial assumptions, and by the end of the year it had been increased to 500,000 bblpd. In 2021, by removing bottlenecks the processing capacity has been further increased to around 535,000 bblpd, with matching expanded water injection capacity.
Average daily production net to Aker BP in 2021 amounted to 63 mboepd including associated gas.
Powered with electricity from shore, the Johan Sverdrup field currently has carbon dioxide emissions of less than 1 kilogram per barrel. The break-even oil price is less than USD 15 per barrel and Aker BP expects the field will have operating costs below USD 2 per barrel at plateau.
The development of Phase 2 is now in the final phase, on schedule and still has good HSE results, despite Covid-19. Phase 2 includes development of a second processing platform, modifications of the riser platform at the field centre, five subsea templates in the periphery of the field, and an increase of the power from shore supply. The increased
power capacity will also serve several surrounding fields in the greater Utsira High area, including Ivar Aasen and Edward Grieg, operated by Aker BP and Lundin Energy, respectively, and will contribute to an annual reduction in total carbon dioxide emissions of nearly 1.2 million tonnes. Production is planned to start in the fourth quarter of 2022. Phase 2 is expected to increase the processing capacity to around 755,000 bblpd.
The Alvheim area consists of the fields Alvheim, Volund, Vilje, Bøyla and Skogul, which are all being produced through the Alvheim FPSO and operated by Aker BP. The oil is exported by shuttle tankers, and the produced gas is exported through the Scottish Area Gas Evacuation (SAGE) system. Aker BP's net production from the Alvheim area in 2021 averaged 46.5 mboepd. The operational performance was strong with a production efficiency of 95 percent.
The field development activities in the Alvheim area in 2021 included completion of the Boa Attic South infill well which was put on production late March and followed by drilling of a Volund side-track well during the summer period. This well started producing in November. A successful intervention job on the Frosk test producer was performed in November. Furthermore, the dual-lateral well, Kameleon Infill West was drilled in fourth quarter of 2021 and the tie-in operations were completed in February 2022.
During 2021, two PDO's were submitted to the authorities, the first one was for the Kobra East and Gekko development. This project is a subsea development tied back to the Alvheim FPSO with four tri-lateral wells through the Kneler B manifold. Base case PDO reserves of 40 mmboe, increased to 50 mmboe due to the later extended lifetime of the Alvheim FPSO. The second PDO was for the Frosk development project from the Bøyla licences. This development is a subsea tie-back to the Alvheim FPSO though the Bøyla template with two new production wells.
In addition to the development projects above, a term sheet was agreed between Alvheim and the Trell & Trine Unit and the project went through DG2 in December 2021. Current business case for the Trell & Trine project consists of three new development wells and subsea infrastructure tied into Alvheim's East Kameleon template. PDO submission is planned during the summer of 2022.
The project to upgrade Alvheim's capacity to handle produced water continued through 2021 with a plan of completion during first half of 2022. The installation is performed in conjunction with a gas debottlenecking project, which Aker BP expects will increase the gas capacity by approximately 15 percent. Together, these projects are expected to improve the capacity for future tie-back projects at Alvheim.
The Valhall area consists of the Valhall and Hod fields in the southern part of the Norwegian North Sea. Aker BP is the operator of both fields. The infrastructure in the area currently consists of the field centre with five separate bridgeconnected platforms. In addition, the field including Hod has five unmanned flank platforms. The produced oil is exported via pipeline to Ekofisk and further to Teesside, while the gas is exported via Norpipe to Emden in Germany.
Aker BP's net production from Valhall averaged 46.4 mboepd in 2021. Production efficiency was 83 percent.
In June 2020, Aker BP, together with its partner Pandion Energy, submitted a PDO for a new Hod B platform. This Normally Unmanned Installation (NUI) is developed utilizing the same concept, alliance partners and execution model as the Valhall Flank West project, which was successfully completed in 2019. Production from Hod B is expected to start during the first half of 2022.
Aker BP is working towards an investment decision and PDO submissions by end 2022 for the New Central Platform (NCP) and King Lear projects. The development concept was selected in fourth quarter 2021. The concept consists of a new process and wellhead platform which will have a bridge connection to the Valhall field centre, and an unmanned platform on King Lear, located approximately 50 km from the field centre. New infrastructure will be laid on the seabed to connect the two fields. A total of 19 wells are planned, and the concept also includes considerable modification work on the Valhall field centre to facilitate recovery of additional barrels. The project will be connected to the existing power from shore solution at Valhall, resulting in close to zero emissions from operations.
The project will add new slots for further development of the Valhall area and secure development of the King Lear field. The new facilities will also enable Valhall to become a hub for potential future gas discoveries in the area. Gross resources for the project are estimated to more than 200 mmboe, with a breakeven oil price of USD 25-30 per barrel of oil equivalent. First oil is scheduled for 2027.
The Skarv field is operated by Aker BP. Skarv is an oil and gas field in the northern part of the Norwegian Sea and is developed with an FPSO anchored to the seabed. The oil is offloaded to shuttle tankers, while the gas is transported to the Kårstø terminal in a pipeline connected to the Åsgard Transport System.
The Skarv Unit consist of several fields, including Skarv, Idun, Tilje, Ærfugl and Gråsel, which are all tied back to the Skarv FPSO. The Ærfugl field was developed in two phases, with three wells in the southern part as phase 1, and further three wells in the northern part of the field in phase 2. Ærfugl phase 1 and phase 2 started production in November 2020 and November 2021, respectively. During 2021, Gråsel, an oil field located between Ærfugl and Skarv was also developed and started production.
During 2021, Aker BP submitted an application for exemption for PDO for the development of Idun Tunge which will be developed by reusing an existing well slot on the Idun Template during 2022, with planned production start in 2023.
Several other discoveries in the Skarv area are being matured for development as subsea tiebacks to the Skarv FPSO. These fields include the Ørn, Shrek, Idun North and Alve North discoveries which are all operated by Aker BP. The plan is to submit PDOs for these fields in 2022, with estimated production start in 2025 and 2026.
Net production from Skarv, including Ærfugl, averaged 29.0 mboepd in 2021. The production efficiency in 2021 was 82 percent which is down from several years above 95 percent, due to a combination of planned maintenance and equipment failures which were subsequently repaired.
The Ivar Aasen field is operated by Aker BP. It is developed with a production, drilling and quarters (PDQ) platform with a steel jacket, and requires a separate jack-up rig for drilling and completion. First stage processing is carried out on the Ivar Aasen platform, and the partly processed fluids are transported to the Edvard Grieg field for final processing and export. Ivar Aasen is powered by electricity which is currently supplied from Edvard Grieg. In 2022, this will be replaced with power from shore.
Aker BP's net production from Ivar Aasen in 2021 averaged 16.7 mboepd. Production efficiency was 86.8 percent.
One new injection well was drilled and completed in 2021. Three more wells are planned to be drilled in 2022.
The Hanz project was sanctioned in December 2021. Hanz is the first subsea tie-back to the Ivar Aasen field. The reservoir contains an estimated 20 million barrels (gross) of oil. It is also a unique project that will use crossflow injection for pressure support and re-use subsea equipment from the Jette field. Consequently, the Hanz project has a significantly lower environmental footprint than comparable subsea developments. Production is planned to start in Q1 2024.
The Ula field is operated by Aker BP. The Ula area consists of the fields Ula, Tambar, Blane and Oda, which are all being produced through the Ula field centre. The oil is exported via Ekofisk to Teesside, while the gas is reinjected into the Ula reservoir to enhance oil recovery.
In recent years, Aker BP has been working to mature a re-development plan for Ula. In 2020, it was concluded that such re-development did not meet Aker BP's investment criteria. Consequently, a late-life strategy has now been adopted for Ula, and production is currently expected to end in the early 2030s.
Net production for Aker BP from the Ula area averaged 7.8 mboepd in 2021. The production efficiency was 76 percent.
The NOAKA area (North of Alvheim (NOA), Fulla and Krafla) is located between Oseberg and Alvheim in the Norwegian North Sea. The area holds several oil and gas discoveries with gross recoverable resources estimated at around 600 mmboe, with further exploration and appraisal potential. Aker BP is the operator for NOA and Fulla, while Equinor is the operator for Krafla.
The development 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, one satellite platform and 9 subsea templates to cover the various discoveries. Aker BP is working together with its strategic partners in cross-functional teams to further mature and improve the development concept for NOA and Fulla. Equinor, as operator for Krafla, is maturing the Krafla concept in close collaboration with Aker BP. A decision on continuation (DG2) for Fulla and North of Alvheim (NOA) was made in September 2021 and in November 2021 for Krafla. The ambition is to submit PDOs in the fourth quarter of 2022. Production start is targeted for 2027.
Aker BP is one of the most active exploration companies on the NCS, which is considered as a highly attractive basin with significant potential for new discoveries.
The company's exploration strategy is focused on two main goals. The first goal is to discover commercial resources near existing infrastructure. Such discoveries typically have short lead times, attractive economics, and contribute to better capacity utilization and lower unit cost at the host. The second goal is to discover resources that are big enough for new stand-alone field developments. The activity level within each category will fluctuate from year to year, but over time the company is aiming towards 80 percent of its exploration activity within the first category.
In 2021, Aker BP participated in a total of 10 exploration and appraisal wells. The well at Garantiana West resulted in a discovery of 8-23 mmboe which will be included in the resource base for the Garantiana field. The Lille Prinsen appraisal well confirmed the presence of hydrocarbons with an updated resource estimate of 12-60 mmboe, and this discovery is currently being evaluated for a potential development as a tie-back to Ivar Aasen or Edvard Grieg. The Gomez well near Valhall also proved hydrocarbons, however there is uncertainty whether the reservoir can be commercially produced. The Liatårnet appraisal well encountered only marginal volumes of hydrocarbons, and the discovery has subsequently been classified as non-commercial. The remaining six exploration wells were all classified as dry or non-commercial.
In January 2022, Aker BP was awarded 15 licences in the Awards in Predefined Areas licensing round (APA 2021), of which seven as operator. Of the 15 production licences awarded to Aker BP, 10 are in the North Sea (five as operator) and five are in the Norwegian Sea (two as operator). Most of these licenses are located close to the company's existing core areas.
The parent and group prepare its financial statements in accordance with International Financial Reporting Standards (IFRS) as adopted by EU and the Norwegian Accounting Act. There are no differences between parent and group figures except for a minor part related to Aker BP UK Limited, as described in note 2 to the Financial Statements.
The group's total income amounted to USD 5,669 (2,979) million. Total production volume was 76.4 (77.1) mmboe. The average realised liquids price was 69.2 (40.0) USD per barrel, while the realised price for natural gas averaged USD 88.5 (21.8) per barrel of oil equivalent (boe).
Production costs for the oil and gas sold in 2021 were USD 745 (628) million. Production costs per boe produced in 2021 amounted to USD 9.2 (8.3). Exploration expenses amounted to USD 353 (174) million and were mainly related to dry and non-commercial wells, seismic data, field evaluation and general exploration activities. Depreciation amounted to USD 964 (1,122) million.
Impairments amounted to USD 263 (573) million, mainly related to Ula/Tambar, partly offset by impairment reversal on Ivar Aasen. A breakdown of the impairment charges is included in note 13 to the financial statements.
Other operating expenses amounted to USD 29 (49) million.
The group reported an operating profit of USD 3,315 (433) million. The pre-tax profit amounted to USD 3,073 (164) million, and the tax expense amounted to USD 2,222 (119) million.
The tax rules and tax calculations are described in notes 1 and 10 to the financial statements.
The net profit was USD 851 (45) million.
Total assets at year-end amounted to USD 14.470 (12,420) million.
Equity amounted to USD 2,342 (1,987) million at the end of 2021, corresponding to an equity ratio of 16 (16) percent. Net interest-bearing debt, including leasing obligations, was USD 1,742 (3,647) million.
The company established its Euro Medium Term Note (EMTN) programme in April 2021 and issued EUR 750 million Senior Notes in May 2021, due in 2029.
At the end of the year, the company had total available liquidity of USD 5.4 (4.5) billion, comprising USD 1,971 (538) million in cash and cash equivalents and USD 3.4 (4.0) billion in undrawn credit facilities. For information about terms on the credit facilities, see note 18. Financial covenants for
the company's debt instruments were comfortably within applicable thresholds. The company has a robust balance sheet and ample financial flexibility.
Aker BP is currently rated by three rating agencies, S&P, Fitch, and Moody's. S&P Global Ratings has assigned a BBB- longterm corporate credit rating with positive outlook. Moody's has assigned a Baa3 long-term issuer rating with stable outlook and has placed the company under review for upgrade. Fitch has assigned a BBB-rating with positive outlook.
Net cash flow from operating activities amounted to USD 4,282 million, up from USD 2,011 million in 2020, positively impacted by higher oil and gas prices.
Net cash flow used in investment activities amounted to USD 1,727 (1,461) million. The main item was investments in fixed assets of USD 1,377 (1,239) million.
Net cash outflow from financing activities was USD 1,123 million, compared to an outflow of USD 119 million in 2020. The main items consisted of the issuance of a new bond amounting to USD 899 million, repayment of bonds amounting to USD 1,283 million and dividend disbursements of USD 488 (425) million.
The accounting principles used for the 2021 annual financial statements are consistent with the principles used in the 2020 annual financial statements, except for a change in presentation of payment of borrowing costs in the statement of cash flows. As from 2021, these cash flows are presented as financing activities, while they previously were presented as operational activities. Comparative figures have been restated accordingly. For more information see note 1.
Aker BP has initiated a process to prepare the reporting required under the EU Taxonomy Regulation, whilst awaiting final processing of the law in the EEA Joint Committee and the implementation of the regulation in Norwegian law. The preliminary analysis indicates that whilst most of the company's revenue and investments are outside the scope of the taxonomy in its current form, certain investments in low-carbon or zero emission solutions may qualify as sustainable investments.
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. No hedge accounting is applied.
At the time of this report, the company has purchased oil put options with strike prices of around USD 45 per barrel for approximately 62 percent of the expected oil production in 2022 (after tax).
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Pursuant to the Norwegian Accounting Act section 3-3a, the Board of Directors confirms that the requirements of the going concern assumption are met and that the annual accounts have been prepared on that basis. The Board considers the financial position and the liquidity of the company to be sound. Cash flow from operations, combined with the total available liquidity, is expected to be more than sufficient to finance the company's commitments in 2022.
In the Board of Directors' view, the annual accounts give a true and fair view of the company's assets and liabilities, financial position, and results. The Board of Directors is not aware of any factors that materially affect the assessment of the company's position as of 31 December 2021, or the result for 2021, other than those presented in the Board of Directors' Report or that otherwise follow from the financial statements.
Aker BP complies with guidelines from Oslo Stock Exchange and the Society of Petroleum Engineers' (SPE) classification system for quantification of petroleum reserves and contingent resources. Total net P90/1P reserves are estimated at 599 (641) mmboe, while net P50/2P reserves amounted to 802 (842) mmboe at year-end 2021. See note 30 for a more detailed review of the resource accounts. The reserves have been certified by an independent third party.
The Board of directors proposes that the profit for the year is transferred to retained earnings.
Health, Safety, Security, Environment and Quality (HSSEQ) 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 HSSEQ standards.
Aker BP's goal is to prevent any kind of harm and ensure a safe workplace. Everyone who works for the company – our employees, hired personnel and contractors – shall be able to perform their work in an environment where the emphasis is on safety. Our facilities shall be in good condition, and must be planned, designed, and maintained in a manner that ensures their technical integrity.
Combining risk insight with learnings from events and successes constitutes the foundation for further improvement to our HSSEQ performance and requires a continuous and systematic effort from the whole organization. The company's overall HSSEQ performance displays a positive trend. However, to meet our ambition of no harm to people and the environment we need to maintain our continuous effort to seek improvements in our HSSEQ performance.
In 2021 we had three incidents categorised with high consequence. A total of four people were seriously injured in these events. One of these cases was related to noise exposure where two people were affected, and the two other incidents involved a shoulder injury and a fractured bone. These incidents were investigated thoroughly in accordance with the company's established event management process. Aker BP had zero Process Safety Events (PSE) in 2021, continuing the strong trend since 2019. The Total Recordable Injuries Frequency (TRIF) for 2021 was 1.9 (1.2), which is higher than 2020 but still the second-best TRIF achievement over the past five years. The Serious Incident Frequency (SIF) improved from 0.7 in 2020 to 0.0 in 2021. The SIF has decreased significantly every year since 2017 when it was 2.5.
Throughout 2021, managing the risks associated with Covid-19 has been a top priority. The company's dedicated response team remained active for most of the year, operating the company's testing regime, ensuring compliance with regulatory requirements and providing support in case of outbreaks offshore. Aker BP did not experience any Covidrelated interruptions to its production in 2021. The company continues to monitor the situation and will adjust its level of response in accordance with regulations and advise from the Norwegian health authorities.
Aker BP develops quarterly learning campaigns focusing on preventing major accidents and dropped objects, avoiding injuries, and strengthening the health and working environment. This initiative is a collaboration between Equinor, Vår Energi, ConocoPhillips and Aker BP. The learning campaigns are designed to be used as a team exercise and are performed online by both offshore and onshore teams, and this also includes Aker BP's alliance partners. The teams watch online learning videos and perform practical tasks as well as give valuable feedback to the organization with regards to HSSEQ. From 2021 we also include the feedback from the organization in the development of new learning campaigns, which means that the staff and alliance partners can influence the safety focus based on their own identified needs within the area. The learning campaigns are performed both onshore and offshore, and within several target groups, such as premise providers, leaders, operative staff, and office personnel. This ensures that the learning material is specifically designed to the target group. This is repeated annually with updated case stories and tasks and is a strong contribution to the company's proactive HSE effort.
The Petroleum Safety Authority Norway (PSA) carried out 15 audits of Aker BP's operations and activities in 2021. Other authorities, such as the Norwegian Environment Agency, Norwegian Petroleum Directorate and three other petroleum authorities conducted six audits. Aker BP received two notices of order from the Petroleum Safety Authority in 2021. One notice was related to establishment and verification of a well barrier element on Hod B and the other was related to non-compliant visibility of flare boom during dark conditions on Valhall PH.
The purpose of security is to protect Aker BP's material and immaterial assets from malicious actors and unintentional security incidents. Through intelligence, value and threat assessments, as well as by raising awareness in the company, Aker BP works to ensure that neither the business nor the personnel are directly affected by threat agents.
Aker BP divides security into three main areas: personnel, physical and cyber security. The company works within these areas to protect the company's values in accordance with relevant legislation and company needs. This work is an integrated part of Aker BP's risk and barrier management and is followed up regularly by the Board.
In 2021 Aker BP's cyber resilience has improved through work in the Cyber Security Operations team, improved governance processes and training together with the emergency preparedness organization. The cyber security projects in the digitalization program have also introduced several cyber security improvements, further reducing cyber risk in Aker BP.
The company has continued to develop its threat intelligence capacity program to reduce uncertainty and enhance decision support to the Executive Management Team and specific business units.
The Business Management System (BMS) is the company's internal control system and hence the framework for creating value, controlling risk and secure safe operation. The BMS describes who we are and how we work and is intended to standardise our way of working and enable the organisation to perform activities the same way as one team. Through BMS, Aker BP ensures compliance with external and internal requirements and facilitates that we continuously improve to achieve common goals. In September 2021
Aker BP launched a new and more modern BMS platform and an updated governing hierarchy. The new platform and governing hierarchy are more user-friendly and gives the organisation a better understanding of Aker BP's governing elements and how they interrelate.
Risk-based assurance of conformity to the business management system requirements is governed by the company's Three Lines of Assurance model. Assurance is an activity to provide confidence that requirements will be fulfilled. Aker BP's three lines of assurance model is continually under improvement with regards to processes and tools to enhance execution and safeguard inherent and identified risk.
Sustainability is formally integrated and embedded into Aker BP's strategy and decision-making processes. Aker BP acknowledges the need for action in line with the Paris Agreement and the Norwegian Parliament's expectations and remains committed to continue contributing to the solution. It is a strategic priority for the company to be best-in-class in producing low-carbon oil and gas. The company's target is to achieve a 50 percent reduction in scope 1 CO2 emissions by 2030, and to have close to zero CO2 emissions by 2050. The company also has indirect emissions related to upstream scope 3 and is working in cooperation with suppliers to establish a greenhouse gas footprint for materials and set reduction targets for scope 3. In 2021, Aker BP strengthened its strategic priority to reduce scope 3 emissions. The goal is to minimise emissions from own activities on the NCS by choosing energy-efficient solutions and operations, as well as reducing emissions in the supply chain. In 2021, the company's CO2 intensity was 4.8 kg CO2 per boe (equity share), which is less than half the global average, and below the average for the NCS. The upstream methane intensity was 0.02 percent.
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The company is committed to maintain a working environment with equal opportunities for all based on qualifications, irrespective of gender, ethnicity, sexual orientation, or disability. Aker BP has a Diversity and Inclusion Policy expressing the principles to be followed, with clear targets and a plan for action. The company does not tolerate any form of discrimination, whether it be trade union affiliation, social background, political opinion, sensitive medical conditions and so forth.
There were no incidents of discrimination reported in 2021. However, in February 2021, the Norwegian Discrimination Tribunal concluded that the company had retaliated against an employee in 2018 after said employee had reported on alleged gender discrimination earlier the same year. The company investigated the case and ensured that necessary remediating measures were implemented.
At the end of 2021, women held 22.6 (21.5) percent of the positions in the company. The share of women on the Board of directors was 36 (36) percent. The share of women in the executive management team was 36 (40) percent and in the middle management it was 23 (24) percent.
Men and women with the same jobs, with equal professional experience who perform equally well, shall receive the same pay in Aker BP. The complexity of the job, discipline area and work experience affect the pay level of individual employees.
At the end of 2021, 9 (9) percent of the employees were of non-Norwegian origin.
Aker BP has a working environment committee as described in the Norwegian Working Environment Act. The committee plays an important role in monitoring and improving the working environment and in ensuring that the company complies with laws and regulations in this area.
Employees enjoy freedom of association, and the company is committed to maintaining an open and constructive dialogue with the employee representatives through meetings on a regular basis throughout the year. Five local trade unions are registered as being represented in the company: Tekna, Lederne, SAFE, Industri Energi and NITO.
The working environment in 2020 and 2021 was affected by extraordinary circumstances such as Covid-19 and organisational adjustments. The employee satisfaction survey registered a negative trend in 2020 and the beginning of 2021 but recovered substantially towards the end of 2021. Employee satisfaction is back to pre-Covid-19 levels and is overall good.
Working for Aker BP shall promote and not reduce the health of our employees and employee health is of major importance for us. Aker BP has several proactive and health promoting measures available for our employees. Several of these offers are available through our occupational health service and includes physical therapy, ergonomic guidance, crisis support line, workouts, travel medicine and vaccines, personal health, and occupational health.
In 2021, the total sickness absence in Aker BP was 3.9 (3.0) percent, which is significantly lower than the national average of 6.3 (6.0) percent in Norway. For onshore personnel the figure was 2.9 (2.3) percent. For offshore personnel, the figure was 6.7 (4.6) percent. Absence from work, due to sickness rose significantly towards the end of the year as omicron became the dominant variant in Norway. Aker BP is closely monitoring the development to address any risk to our employees or production. Reference is also made to the company's ESG report, which includes further details on Aker BP's working environment.
Aker BP's values are Enquiring (Søkende), Responsible (Ansvarlig), Predictable (Forutsigbar), Committed (Engasjert) and Respectful (Respektfull). The Norwegian words form the abbreviation SAFER. The values define the company culture and describe how we want to work in Aker BP. The values also guide our behaviour in the workplace and enable us to live by our Code of Conduct. Our goal is that every employee habitually acts according to our core values.
During 2021, Aker BP continued to strengthen its anticorruption compliance program with focus on training and awareness activities, introduction of new internal procedures, business partner integrity due diligence, and risk mapping of our supply chain. The company updated its Code of Conduct and approved a new human rights policy to address changes and developments in relevant regulatory frameworks, and to clarify expectations to employees, consultants, and business partners. The human rights policy describes Aker BP's commitments and how human rights impacts are managed in our supply chain and across our operations. Both policy documents are available at the company's website. Reference is also made to the company's Sustainability report, which includes further details on Aker BP's work in these areas.
Aker BP works to create value for all key stakeholders, including local communities where we operate, by integrating social responsibility into the way we do business. We partner with local, regional, and national businesses, organisations, and authorities to achieve mutual understanding of expectations, facilitate direct and indirect local benefits, and create opportunities for stakeholders.
Our stakeholders are the many individuals and organizations who are affected in some way by Aker BP's activities – whether it is in our role as an energy provider, an employer or as a business that helps boost local economies through jobs and revenue.
Open and proactive dialogue with stakeholders facilitates our ability to access the resources we require through the whole life cycle of our assets.
We work with governments, communities, and non-governmental organizations to implement social investment programs that can have a sustainable beneficial impact. We invest in community projects that align with local needs and our business activities.
When planning projects, we assess the potential impacts on communities. This helps to identify early on whether any activities could negatively affect stakeholders or the environment in nearby communities, and to find ways to prevent or mitigate those impacts. We consult with communities, so that we can understand their expectations and address concerns. Through this, we hope to resolve potential disagreements, avoiding negative impacts on others and disruption to our activities.
Aker BP is committed to stimulating local content by creating jobs and growing local businesses in the communities in which the company operates.
All five operated hubs (Alvheim, Valhall, Ula, Ivar Aasen and Skarv) have performed and secured acceptance for the impact assessment studies as part of the Government approval process.
According to the Government's Northern Area Policy, special focus should be given to the development and operation of fields located in Northern Norway to help stimulate local content and create value in the regions. The Skarv field, including the Ærfugl field development project, which was completed in 2021, are in this category.
Aker BP is a member of the Oil and Gas Cluster Helgeland, an organization located in Northern Norway with a key focus on how to involve local and regional business enterprises.
To stimulate the cooperation with schools and education, Aker BP is supporting activities and public offices that contribute to the growth and development of the local community by offering studies, competence-raising measures and innovation processes and projects such as Kunnskapsparken Helgeland, Tverrfaglig Opplæringskontor, Studiesenter Ytre Helgeland, and Sandnessjøen upper secondary school.
Aker BP is further developing the cooperation agreement with Nordland County focusing on local business development, schools, and education.
The aim of Aker BP's Research & Development (R&D) efforts is to support the company's journey to become the leading E&P company. Aker BP invests in R&D across the whole value chain and has a balanced portfolio of projects targeting knowledge and methods, physical technology development, and digital/software development.
During 2021, the R&D council with representatives from all business units has met regularly to monitor and manage that the R&D portfolio is aligned with the principles of the company's technology strategy. The portfolio has comprised around 100 projects with a total spend close to NOK 500 million. Projects in the portfolio have been prioritised and selected based on match with strategic technology themes, alignment with specific business needs, and line of sight to technology implementation and value outtake.
Some highlights from our R&D portfolio are:
Aker BP believes that good corporate governance with clearly defined roles and responsibilities between the owners, the Board and executive personnel is crucial for the company to deliver value to its shareholders.
The Board of Aker BP is responsible for maintaining the highest corporate governance standards. The Board carries out an annual review of the company's principles. The company complies with relevant rules and regulations for corporate governance, including the most recent version of the Norwegian Code of Conduct for Corporate Governance, published on 14 October 2021, unless otherwise specified.
An account of corporate governance is provided in a separate section of the annual report and on the company's website.
The company has emphasised the importance of providing accurate information in interim reports, capital market updates and through direct dialogue with relevant authorities.
Aker BP is reporting on payments to governments at country and project level, in accordance with the Norwegian Accounting Act § 3-3 d) and the Norwegian Securities Trading Act § 5-5a. The report is provided in a separate section of the annual report and on the company's website www.akerbp.com.
The directors and officers of Aker BP are covered under an Aker group Director & Officer's Liability Insurance (D&O). The insurance covers personal legal liabilities including defenceand legal costs. The officers and directors of the parent company and all subsidiaries globally (owned more than 50 percent) are covered by the insurance. The cover also includes employees in managerial positions or employees who become named in a claim or investigation.
Response and measures we use to manage or mitigate our risks are embedded in our governance and business management system complemented by our risk and barrier management framework. Risk management is fully integrated in all our activities and permeates and supports our decisionmaking at all levels. Communication of important risks arising across the value chain and assets is ensured by our enterprise risk process, which encompasses all business units.
The risk factors highlighted below could have a material adverse effect separately, or in combination, on our financial condition. Accordingly, investors should carefully consider these risks.
Aker BP's business depends significantly on the level of oil and gas prices, which are volatile, and are further subject to market expectations regarding such prices. If oil and gas prices decline, our results of operations, cash flows, financial condition and access to capital could be materially and adversely affected.
The company's profitability is determined in large part by the difference between the income received from the oil and gas produced and the operational costs, taxation costs relating to recovery (which are assessable irrespective of sales), as well as costs incurred in transporting and selling the oil and gas. Lower prices for oil and gas may thus reduce the amount of oil and gas that the company is able to produce economically. This may also reduce the economic viability of the production levels of specific wells or of projects planned or in development to the extent that production costs exceed anticipated revenue from such production.
The economics of producing from some wells and assets may also result in a reduction in the volumes of the company's reserves. Aker BP might also decide not to produce from certain wells at lower prices. These factors could result in a material decrease in net production revenue, causing a reduction in oil and gas acquisition and development activities. In addition, certain development projects could become unprofitable because of a decline in price and could result in the company having to postpone or cancel a planned project, or if it is not possible to cancel the project, carry out the project with negative economic impact.
In addition, a substantial material decline in prices from historical average prices could reduce the company's ability to refinance its outstanding credit facilities. Changes in the oil and gas prices may thus adversely affect the company's business, results of operations, cash flow, ability to pay dividends, financial condition, and prospects.
To mitigate commodity pricing risk, the company has a hedging program in place, through which it acquires put options on its oil price exposure 12 months forward (with flexibility to extend beyond 12 months at the CFO's
discretion, pending market conditions at any given point in time). Further, the company continuously screens additional hedging policies that further mitigate commodity price volatility, including strategies to mitigate price risk for gas.
Risks arising from the systems around our business may escalate and in combination shape systemic risk. Whole or parts of systems could be severely affected including those where the company conduct business. Financial systems, supply systems, resource system, even the human population system may solely or by combination be shocked because of e.g. infectious diseases spreading worldwide or by a global financial crisis. The different scenarios exhibit a large degree of uncertainty, lack of control, and undecisive impact from management actions. Under such circumstances psychological behaviour could be driven by fear and reactivity.
The company may face situations where there are extensive strain or full-scale shortage of resources (e.g. personnel, goods & services, finances) in the supply chain to perform our business activities as a result from systemic risk. Any such conditions could drain cash-flow, have material negative effect on our financial condition, force undesired change in strategic direction, and impact our ability to conduct business and deliver production.
While comprehensive mitigating measures against systemic risks are by nature impossible to put in place, the company monitors developments on a running basis, and the executive management team is proactive with respect to implementing measures to omit/avoid risks wherever possible.
Exploration, development, and production operations involve numerous safety and environmental risks and hazards that may result in material losses or additional expenditures.
Developing oil and gas resources and reserves into commercial production involves risk. Aker BP's exploration operations are subject to all the risks common in the oil
and gas industry. These risks include, but are not limited to, encountering unusual or unexpected subsurface features, rock formations or geological pressures, geological uncertainties, seismic shifts, blowouts, oil spills, uncontrollable flows of oil, natural gas or well fluids, explosions, fires, improper installation or operation of equipment and equipment damage or failure. Given the nature of offshore operations, Aker BP's exploration, operating and drilling facilities are also subject to the hazards inherent in marine operations, such as capsizing, sinking, grounding and damage from severe storms or other severe weather conditions, as well as loss of containment, fires, or explosions. Occurrence of any such significant events may result in material losses and adversely impact our cashflow and financial position.
The company has an extensive HSSEQ system in place which is continuously improving and ensures the proactive maintenance and early detection of potential threats. The company continuously work to improve the safety culture in all parts of its operations, onshore and offshore.
Climate changes could potentially have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. Aker BP's offshore operations and infrastructure could be at risk from such climatic events.
The company has completed a climate risk assessment and monitors exposure to physical climate risk on a running basis.
The oil and gas industry is highly competitive. Competition is particularly intense in the acquisition of (prospective) oil and gas licenses. Aker BP's competitive position depends on its geological, geophysical, and engineering expertise, financial resources, the ability to develop its assets and the ability to select, acquire, and develop proven reserves. Unsatisfactory ability to manoeuvre the competitive landscape may have a material effect on the company, its growth ambition, and ability to replace produced reserves.
The company's strategy to ensure that it remains competitive revolves around developing a portfolio with low cost, low carbon assets, which ensures that the business remains robust through the cycle.
On 24 February 2022, Russia launched a military invasion of Ukraine. Following the invasion, there has been ongoing battles on Ukrainian soil, creating significant uncertainties regarding global political and economic stability. Several countries have condemned the invasion by Russia, and severe sanctions have been imposed on banks, certain oligarchs, and the state itself. The war has caused significant business disruption, volatility in international debt and equity markets and disruption to the global economy in the short term. There is significant uncertainty around the breadth and duration of all disruptions related to the invasion, as well as its impact on the global economy. The extent to which the invasion impacts the company's results will depend on future developments, which are highly uncertain and difficult to predict, including new information which may emerge on an ongoing basis.
The energy markets are heavily impacted by the invasion and the following sanctions, and oil and gas prices have spiked from an already high level since the announcement on 24 February 2022. Russia is a key exporter of gas to Europe, and it is expected that volumes will decline both due to infrastructure breaches, sanctions making it cumbersome to trade, and potential unwillingness from Russia to export to the rest of the global community. There is significant uncertainty regarding how the invasion and the following sanctions will impact the access to energy, and the price of oil and gas and other commodities in the coming period, and the company's operations and results may be adversely impacted. The ongoing conflict in Ukraine could potentially lead to increased risk of cyber-attacks.
The company's business and results of operations could be adversely affected by climate change and the adoption of
new climate change laws, policies, and regulations. Growing concerns about climate change and greenhouse gas emissions have led to the adoption of various regulations and policies, including the Paris Agreement negotiated at the 2015 United Nations Conference on Climate Change (COP 21), which requires participating nations to reduce carbon emissions every five years beginning in 2023. Multiple plans have also been proposed in the Norwegian parliament to reduce carbon emissions from companies operating in certain sectors, including the oil and gas industry, and create a carbon trading system linked to the European Union's emissions trading scheme.
The emission reduction targets and other provisions of the recent Norwegian climate change law, the Paris Agreement, or similar legislative or regulatory initiatives enacted in the future, could adversely impact the company's business by imposing increased costs in the form of taxes or for the purchase of emission allowances, limiting the company's ability to develop new oil and gas reserves, decreasing the value of its assets, challenge asset lifetime extension, or reducing the demand for hydrocarbons and refined petroleum products.
By means of ensuring that the company holds a portfolio comprising of low carbon assets, Aker BP is well positioned to manage climate change-related, regulatory risks. Further, the company continuously monitors developments in the political landscape, including carbon credit prices, and is positioned to act promptly to changes.
Aker BP's production of oil and gas is delivered from a limited number of offshore fields. If mechanical or technical problems, abnormal weather or other events affect the production on one of these offshore fields or our partner operated assets, it may have direct and significant impact on a substantial portion of the company's production. Also, if the actual reserves associated with any one of these fields are less than the estimated reserves, the company's results from operations and financial condition could be materially adversely affected.
Unitization agreements relating to production licenses may include a redetermination clause, stating that the apportionment of the deposit between licenses can be adjusted within certain agreed time periods. Any such redetermination of interest in any of the company's licenses may have a negative effect on its interest in the unitised deposit, including its tract participation and cash flow from production. No assurance can be made that any such redetermination will be satisfactorily resolved or will be resolved within reasonable time and without incurring significant costs. Any redetermination negatively affecting the company's interest in a unit may have a material adverse effect on its business, results of operations, cash flow, financial conditions, and prospects.
Aker BP's ongoing development or decommissioning projects involve advanced engineering, extensive procurement activities and complex construction work to be carried out under various contract packages at different locations onshore. Furthermore, the company (together with its license partners), must carry out drilling operations, install, test and commission offshore installations and obtain governmental approval to take them into use prior to commencement of production. The complexity of such development projects makes them sensitive to circumstances that may affect the planned progress or sequence of the various activities.
Although Aker BP believes that the development or commissioning projects will be completed on schedule in accordance with all license requirements and within the estimated budgets, the current or future projected target dates for production or cessation may be delayed and cost overruns may incur.
Furthermore, estimated exploration costs are subject to many assumptions that may not prove to be correct. Any such inability to explore, appraise, develop, or decommission petroleum operations or incorrect assumptions regarding exploration costs may have an adverse effect on the company's growth ambitions, future business and revenue, operating results, financial condition, and cash flow.
Aker BP has established an alliance model comprising a total of six alliances covering various types of operations associated with developing projects and drilling & wells activities. This model ensures alignment of interests between alliance partners and the company, with risk sharing between the parties. It is the company's opinion that alliance model has resulted in higher efficiency and fewer cost overruns. Work to improve the alliance model and optimise the incentive structures are continuously ongoing.
Where the company is not the operator of a license, although it may have consultation rights or the right to withhold consent in relation to significant operational matters depending on
the level of its interest in such license (as most decisions by the management committee only require a majority vote), the company has limited control over management of the assets and mismanagement by the operator or disagreements with the operator as to the most appropriate course of action may result in significant delays, losses or increased costs to Aker BP. The company works in close collaboration with all licence partners to ensure that issues related to such risks are minimised through sharing a common understanding of goals and targets.
Market conditions may impair the liquidity situation of contractors and consequently their ability to meet its obligations towards the company. This may in turn impact both timeline and cost expectations to our projects and operations.
As previously mentioned, Aker BP has established an alliance model, which ensures alignment of interests between alliance partners and the company, with risk sharing between the parties. It is the company's opinion that has resulted in higher efficiency and fewer cost overruns. Work to improve the alliance model and optimise the incentive structures are continuously ongoing.
Aker BP performs a supplier risk mapping for all contracts that are deemed critical for the company's operations. This risk mapping includes both the supplier's financial health, ethical behaviour and other external factors that could impact the supplier's ability to deliver.
Aker BP's reserve evaluations are prepared in accordance with existing guidelines. These evaluations include many assumptions relating to factors such as initial production rates, recovery rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, future prices of oil and gas, operating costs, and royalties and other government levies that may be imposed over the producing life of the reserves and resources. Actual production and cash flows will vary from these evaluations, and such variations could be material. Although the company understands the life expectancy of each of its assets, the life of an asset may be shorter than anticipated. Among other things, evaluations are based, in part, on the assumed success of activities intended to be undertaken in future years. The reserves, resources and estimated cash flows contained in such evaluations will be reduced to the extent that such activities do not achieve the level of success assumed in the evaluations, and such reductions may have a material adverse effect on the company's business, results of operations, cash flow and financial condition.
The company allocates substantial resources to analysing and understanding its reservoirs and continuously monitors/ updates/stress tests its resource models. Further, the company applies a set of project decision criteria ensure that assets are as robust as possible before making investment decisions. These criteria include, but are not limited to, full-cycle NPV breakeven criteria and CO2 emissions intensity targets.
The Covid-19 pandemic has caused significant business disruption globally, significant volatility in international debt and equity markets and significant disruption to the economy. Under such pandemics, Aker BP's operations may experience delays or disruptions, such as the temporary suspension of operations at one or more of our operating facilities, with potentially negative impact on the company's financial results. Moreover, such events may also have a negative impact on the demand for oil and gas and hence lead to lower oil and gas prices and reduced revenues for Aker BP.
Since the onset of the Covid-19 pandemic, the company has had measures in place to protect personnel and to ensure uninterrupted production from all assets, including quarantine and testing schemes. These measures are described in the HSSEQ section of this report.
The company could be a target of cyber-attacks designed to penetrate the security of its network or internal systems, misappropriate proprietary information, commit financial fraud and/or cause interruptions to the company's activities, including a reduction or halt in production. Such attacks could, inter alia, include adversaries obtaining access to company systems, the introduction of malicious computer code or denial of service attacks. Such actual or perceived breaches of network security could adversely affect the company's business performance, and reputation, and may create exposure to the loss of information, litigation, and possible liability.
Aker BP's Board and management has cyber security high on its agenda, and all employees are required to take annual courses in cyber security. For more information about the company's approach to cyber security, see the Security chapter elsewhere in this report.
There is no assurance that future political conditions in Norway will not result in the government adopting different policies for petroleum taxation. In the event of changes to this tax regime, it could lead to new investments being less attractive and challenge further growth of the company.
Furthermore, the amounts of taxes could also change significantly because of new interpretations of the relevant tax laws and regulations or changes to such laws and regulations. In addition, tax authorities could review and question the company's tax returns leading to additional taxes and tax penalties which could be material.
The Norwegian Government has implemented a tax reform in Norway. The tax reform has, inter alia, led to a reduction in the general corporate tax rate, while the special petroleum tax rate has been increased. The overall effect of the rate changes for the petroleum sector is that the total marginal tax rate of 78 percent has remained unchanged. Further tax reform
may result in changes in the Norwegian tax system (which may include changes in the tax treatment of interest costs and to withholding tax on interest payments) that may affect our current and future tax positions, net income after tax and financial condition.
The company's future capital requirements depend on many factors, including the company's operational performance, project execution, oil and gas prices, and the level and timing of its investment program. The company has established a robust capital structure to ensure sufficient financial capacity for its planned field development projects. However, adverse developments in the company's operations or projects, as well as adverse developments in oil and gas prices, may lead to a need for additional capital, which could contribute to increase the company's debt levels above industry standards.
The company may also have to manage its business in a certain way to service its debt and other financial obligations. Should the financing of the company not be sufficient to meet its financing needs, the company may, among other things, be forced to reduce or delay capital expenditures or research and development expenditures or sell assets or businesses at unanticipated times and/or at unfavourable prices or other terms, or to seek additional equity capital or to restructure or refinance its debt. There can be no assurance that such measures would be successful or would be adequate to meet debt and other obligations as they come due or would not result in the company being placed in a less competitive position.
International and national policies, the general financial market conditions, stock exchange climate, interest level, the investors' interest in the company and their preferences regarding exposure to oil and gas production, the share price of the company, as well as several other factors beyond the company's control, may restrict the company's ability to raise necessary funds for future growth and/or investments. Thus, additional funding may not be available to the company or, if available, may not be available on acceptable terms. If the company is unable to raise additional funds as needed, the scope of its operations may be reduced and, as a result, the company may be unable to fulfil its long-term development program, or meet its obligations under its contracts, which may ultimately be withdrawn or terminated for non-compliance. The company may also have to forfeit or forego various opportunities, curtail its growth and/or reduce its assets. This could have a material adverse effect on the company's business, prospects, financial condition, results of operations and cash flows, and on the company's ability to fund the development of its business.
To mitigate these risks, the company works closely with financial advisers to identify threats and opportunities and ensure that the company maintains it financial strength. This includes, but is not limited to, monitoring options for optimising the company's balance sheet and lowering interest expenses.
The company's long-term debt is primarily based on fixed interest rates. The company has covenants related to its financial commitments. Failure to comply with financial covenants and other covenants may entail material adverse consequences, including the need to refinance, restructure, or dispose of certain parts of, the company's businesses to fulfil the company's financial obligations and there can be no assurances that the company in such event will be able to fulfil its financial obligations.
The company has a holistic approach to its financial planning and runs extensive financial stress tests on its planned activities to ensure that the company meets financial robustness criteria necessary to breach covenants and meets its financial commitments.
The company is exposed to market fluctuations in foreign exchange rates since the company reports profit and loss and the balance sheet in USD. Revenues are in USD for oil and in GBP and EUR for gas, while operational costs and investments are in several other currencies in addition to USD. Moreover, taxes are calculated and paid in NOK. The company actively manages its foreign currency exposure through a mix of forward contracts and options, however significant fluctuations in exchange rates between USD and NOK could adversely affect the liquidity position of the company. Volatility in exchange rates generally represents increased risk for the company.
The company's partners and counterparties consist of a diverse group of companies with no single material source of credit risk. However, a general downturn in financial
markets and economic activity may result in a higher volume of late payments and outstanding receivables, which may in turn adversely affect the company's business performance, operating results, cash flows and financial condition.
The company is vulnerable to adverse market perception as it must display a high level of integrity and maintain the trust and confidence of investors, license participants, public authorities, counterparties, employees, and the society. Any mismanagement, fraud, or failure to satisfy fiduciary or regulatory responsibilities, allegations of such activities, or negative publicity resulting from such other activities, or the association of any of the above with the company could materially adversely affect our reputation and the value of our brand, as well as our business, results of operations, cash flows and financial condition, and our ability to attract and retain talent.
To mitigate this risk, the company is regularly promoting the company's Code of Conduct amongst all employees, in addition to stakeholder management in general.
Technology and digitalization are important parts of the company's strategy, and we strongly believe those will contribute to Aker BP's growth and improved efficiency. Inefficient, or mis-judged implementation of such technologies and digitalization could have a negative effect on expected value realization and the company's strategy, reputation, cost profile, and safe operations. We also recognise that the development of new technologies and digitalisation may require additional funding and support beyond what is expected, and such consequences may adversely affect our reputation, cash flows, and potentially our financial condition.
Anti-bribery, anti-corruption, including tax-evasion and antimoney laundering laws, and other compliance requirements apply to the company, potential future joint ventures, and associates, in countries in which we do business. Any violation of such laws, regulations, and requirements could have a material adverse effect on our cash flows, financial condition, and reputation.
In addition to the promotion of the company's Code of Conduct, all employees are required to undertake annual refreshment courses on anti-bribery/anti-corruption. Moreover, the company has a compliance department to oversee the righteousness of all operations in the company.
The company operates in a competitive environment, and its future growth prospect depends upon its ability to access executive and senior management and key personnel.
Executive or senior personnel may terminate employment with the company rendering certain knowledge and skills in shortage. Large numbers of personnel leaving the company in a short timeframe could be a significant challenge to replace or find alternatives to recover. If we are unable to fill positions and retain executive and senior management and key personnel with needed skills and expertise, it could have a longer-term adverse effect on our business, financial position, and results of operations.
To attract and retain talent, Aker BP offers competitive salaries and other benefits, and strong career development opportunities to all employees. The company has an active internal job market, which allows for multi-skill competency development. Aker BP prioritises its employees' work-life balance, and constantly strives to maintain a supportive corporate culture to the benefit of its employees.
Although the company continuously strive for accurate, transparent, and comprehensive financial reporting, errors and omissions may penetrate our control mechanisms. Such errors and omissions, should they be significant, could drain senior management attention and require measures diverting efforts and prospects for growth. Inaccuracies could adversely affect our strategic decision making, productivity, slow growth and therefore may impact our cash flows and financial condition. The company's reputation and goodwill could also be adversely affected.
The company's Board has an Audit and Risk Committee (ARC), which is responsible for the oversight of the internal controls, risk management and audit process and making recommendations or proposals to improve the integrity of reporting. Details on the committee's work is available in the Corporate Governance section of the annual report.
The company's operations are subject to extensive HSSEQ regulatory requirements that may change and are likely to become more stringent over time. Government could require operators to adjust their future production plans, effecting production and costs related to development projects and our operations. We could incur additional costs in the future due to compliance with these requirements or because of violations of, or liabilities under, laws and regulations, such as fines, penalties, clean-up costs and third-party claims. Therefore, HSSEQ risks, should they materialise, may result in material negative effect to our financial condition.
The company could be subject to losses from risks related to insufficient insurance. The company's insurance policy is continually renewed and negotiated through agents and the market. The company could face a situation where the coverage either is not sufficient or the policy does not grant coverage, which may result in material negative effects to the company's financial condition. The company could also face a situation where changed practices in the insurance industry in response to the issue of climate change could reduce the company's ability to achieve full insurance coverage.
The company may face litigation arising from other risk factors. Litigation in a variety of jurisdictions could result in substantial costs (including civil or criminal penalties, or both, damages, or the imposition of import trade measures), require the company to devote substantial resources and divert management attention, which may result in a negative effect on the financial condition.
On 18 January 2022, Aker BP was offered 15 new licenses, including seven operatorships in the Awards in Predefined Areas (APA) 2021 licensing round.
On 2 February 2022, it was announced that Aker BP sold its 7.4 percent interest in Cognite AS to Saudi Aramco. The transaction was completed in February, and the company expects to recognise a gain of approximately USD 90 million in the first quarter of 2022.
On 14 February 2022, Aker BP and Lundin Energy entered a merger plan for the combination of Aker BP and Lundin Energy's oil and gas related assets.
On 23 February 2022, Aker BP disbursed USD 171 million in dividends to shareholders (USD 0.475 per share).
The Board of Directors and the CEO of Aker BP ASA Akerkvartalet, 8 March 2022
ØYVIND ERIKSEN Chairman of the Board
ANNE MARIE CANNON Deputy Chair
KJELL INGE RØKKE Board member
TROND BRANDSRUD Board member
PAULA DOYLE Board member
KATE THOMSON Board member
MURRAY AUCHINCLOSS Board member
TERJE SOLHEIM Board member
INGARD HAUGEBERG Board member
TORE VIK Board member
HILDE KRISTIN BREVIK Board member
KARL JOHNNY HERSVIK Chief Executive Officer
This report is prepared in accordance with the Norwegian Accounting Act Section § 3-3 d) and Securities Trading Act § 5-5 a). It states that companies engaged in activities within the extractive industries shall annually prepare and publish a report containing information about their payments to governments at country and project level. The Ministry of Finance has issued a regulation (F20.12.2013 nr 1682 – "the regulation") stipulating that the reporting obligation only apply to reporting entities above a certain size and to payments above certain threshold amounts. In addition, the regulation stipulates that the report shall include other information than payments to governments, and it provides more detailed rules applicable to definitions, publication and group reporting.
The management of Aker BP has applied judgment in the interpretation of the wording in the regulation with regard to the specific type of payment to be included in this report, and on what level it should be reported. When payments are required to be reported on a project-by-project basis, it is reported on a field-by-field basis. Only gross amounts on operated licences are reported, as all payments within the licence performed by non-operators will normally be cash calls transferred to the operator and will as such not be payments to the government.
All taxes and fees referred to in this report are fully paid to Norwegian governments.
The regulation's Section 2 no. 5 defines the different types of payments subject to reporting. In the following sections, only those applicable to Aker BP will be described.
The income tax is calculated and paid on corporate level and is therefore reported for the whole company rather than licence-by-licence. Net tax payments in 2021 of NOK 1 950 154 040 (including interest) are mainly related to tax refunds for the income year 2020 and tax payments for the income year 2021.
CO2 tax is to some extent included in the fuel price/rig rental paid to external rig companies. The CO2 tax paid on the Alvheim field includes the fields tied in to the Alvheim FPSO (Vilje, Volund, Bøyla and Skogul) as Alvheim performs the payment and charges the other fields via opex share.
| Name of field/license | CO2 tax paid in 2021 (NOK) |
|---|---|
| Alvheim | 99 032 168 |
| Hod | 306 196 |
| Ivar Aasen | 8 794 273 |
| Skarv | 156 086 164 |
| Tambar | 1 334 262 |
| Ula | 90 817 906 |
| Valhall | 7 069 148 |
| Total CO2 tax paid | 363 440 117 |
The company is a member of the NOx fund and all NOx payments are made to this fund rather than to the government.
The table below specifies the area fee paid by Aker BP on behalf of the various licences in 2021. Licenses of which the company has received net refund of area fee are not included in the figures.
| Name of field/license | Area fee paid in 2021 (NOK) |
|---|---|
| Alvheim | 12 240 000 |
| Bøyla | 4 590 000 |
| Hod | 2 450 000 |
| Ivar Aasen | 12 701 |
| Skarv | 20 043 000 |
| Skogul | 306 000 |
| Tambar | 456 773 |
| ULA | 5 867 000 |
| Valhall | 8 624 000 |
| Vilje | 931 000 |
| Volund | 765 000 |
| PL 026 | 1 470 000 |
| PL 102D | 5 049 000 |
| PL 102F | 3 978 000 |
| PL 127C | 4 896 000 |
| PL 146 | 14 452 770 |
| PL 159D | 1 071 000 |
| PL 212E | 2 142 000 |
| PL 242 | 2 448 000 |
| PL 261 | 7 497 000 |
| PL 442 | 12 067 145 |
| PL 685 | 45 603 370 |
| PL 784 | 3 892 866 |
| PL 858 | 18 236 668 |
| Total | 179 089 293 |
When companies are required to report payments as the above, it is also mandatory to report on investments, sales income, production volumes and purchases of goods and services in the country in which companies have activities within the extractive industries. As mentioned above, Aker BP operates on the Norwegian Continental Shelf only. This reporting requirement is therefore deemed to be met by the financial statements as specified below:
Aker BP ASA (Aker BP) aims to ensure the greatest possible value creation to shareholders and society over time in a safe and prudent manner. A good management and control model with a clear division of responsibility and roles between the owners, represented by the shareholders in the General Meeting, the Board of Directors and corporate management is crucial to achieve this.
The Board of Aker BP is responsible for actively adhering to sound corporate governance standards.
Aker BP is a Norwegian public limited liability company (ASA), listed on Oslo Børs and established under Norwegian laws. In accordance with the Norwegian Accounting Act, section 3-3b, Aker BP includes a description of principles for corporate governance as part of the Board of Directors' Report in the annual report or alternatively makes a reference to where this information can be found.
The Norwegian Corporate Governance Board (NCGB) has issued the Norwegian Code of Practice for Corporate Governance (the Code of Practice). The Code of Practice can be found on
Oslo Børs requires listed companies to publish an annual statement of their policy on corporate governance in accordance with the Code of Practice in force at the time. Issuer Rules for companies listed on Oslo Børs is available at www.euronext.com/en/markets/oslo.
Aker BP complies with the current edition of the Code of Practice, issued on 14 October 2021, unless otherwise specifically stated. The following statement on corporate governance is structured in the same way as the Code of Practice, thus following the 15 chapters included in the Code of Practice.
More detailed reporting on corporate governance issues can be found on our website www.akerbp.com, in this Annual report and in our Sustainability/ESG report.
Deviations to the code: None
According to Aker BP's Articles of Association article 3, its objective is "to carry out exploration for, and recovery of, petroleum and activities related thereto, and, by subscribing for shares or by other means, to participate in corresponding businesses or other business, alone or in cooperation with other enterprises and interests". Further information about the Articles of Association is available at the company's website.
Through an annual strategy process, the Board defines and evaluates the company's purpose and objectives, values and main strategies, and risk profiles for the company's business activities such that the company creates value for shareholders. Environmental, social and governance issues are an important part of the Board's annual strategy process. Together with the company's financial status, the objectives of the company are communicated to the market.
It is Aker BP's vision to create the leading independent exploration and production (E&P) company. To achieve this, the company will carry out exploration, development and production activities and be opportunistic in its approach to M&A, including buying and selling interests in companies, fields, and discoveries.
Throughout 2021, the COVID-19 pandemic continued to cause uncertainty and disruption to the global economy. Since the onset of the pandemic in the beginning of 2020, the Board's objective has been to make sure that Aker BP took all necessary measures to protect its people and operations from the virus, and to make sure the company is prepared to handle the potential operational and financial consequences of the situation.
The company maintains a Code of Conduct to ensure that employees, hired personnel, consultants and others acting on behalf of Aker BP, operate in a consistent manner with respect to ethics and good business practice. The Code of Conduct clarifies the company's fundamental ethical values and is a guideline for those making decisions on behalf of the company. Aker BP requires that all its employees and
consultants complete a mandatory annual Code of Conduct refresher course. In addition, Aker BP also maintains a Human rights policy to clarify its human rights commitments and describe how the company manages human rights impacts in the supply chain and across its operations. The Code of Conduct and the Human rights policy are both available on the company's website.
The company demonstrates responsibility through actions, the quality of its work, the projects, and products and all its activities. The company's ambition is that business activities shall integrate social, ethical, and environmental goals and measures. As a minimum, Aker BP will comply with laws, regulations, and conventions in the areas where the company operates, but the established set of ethical guidelines extends beyond such compliance. Established procurement procedures secure non-discrimination and transparency in the procurement processes, which also include environmental decision criteria. Aker BP has established an anti-corruption compliance program, and it is also stated in the Code of Conduct that no form of corruption is tolerated. Aker BP's Anti-Corruption Policy sets out in more detail the company's expectations regarding the actions of Aker BP Representatives and Business Partners and is available on the company's website.
In addition, the company has a sponsorship policy and program to promote the company and its activities. Guidelines for the use of sponsorships are included in the sponsorship policy and in the Code of Conduct. Aker BP supports measures that improve the company's brand and profile, and measures that can be for the benefit of the employees. Information about ongoing sponsorships is available on the company's website.
The company routinely conducts impact assessments as an integrated part of the sanctioning process of projects, for the purpose of accounting for the effects that a development or a facility and its operation could have on the environment,
including cultural monuments and cultural environment, natural resources, and society.
The company integrates considerations related to its stakeholders into its value creation and shall achieve its objectives in accordance with the Code of Conduct. In Aker BP's annual Sustainability Report, the company describes its business activities in terms of sustainability performance and development, its approach to environmental, social and governance (ESG) issues and presents a balanced picture of the opportunities and challenges it encounters in this area and how it works to address them. The report is available on the company's website.
Deviations to the code: None
The Board seeks to optimize the company's capital structure by balancing risk, return on equity against lenders' security and liquidity requirements. The company aims to have a good reputation in all debt and equity markets. The Board continuously evaluates the company's capital structure, ensuring a capital and debt structure that is appropriate to the company's objective, strategy, and risk profile. This involves monitoring available funding sources and related cost of capital. It is the company's goal that over time, Aker BP's shareholders shall receive a competitive return on their investment through increased share price and cash dividends. The Annual General Meeting (AGM) in April 2021 authorized the Board to approve the distribution of dividends based on the approved annual accounts for 2020. The background of this proposal was to facilitate the company's aim to distribute dividends quarterly.
In 2021, the company in total paid USD 487.5 million in dividends to shareholders, equivalent to USD 1.35 per share. During the fourth quarter 2021, the Board resolved to increase the dividend level to USD 1.9 per share for 2022.
The company's dividend policy is an integrated part of its overall capital allocation framework, together with and dependent on its financing and investment policies. The ambition is to provide a reliable dividend which grows in line with Aker BP's long-term value creation. Aker BP pays dividends in cash on a quarterly basis.
The company's financial liquidity is strong with cash and cash equivalents of USD 1,971 million and undrawn amounts on committed credit facilities of USD 3.4 billion as of 31 December 2021.
Aker BP is currently rated by three rating agencies, S&P, Fitch, and Moody's, all of which have assigned Investment Grade credit ratings to the company. S&P Global Ratings has assigned a BBBlong-term corporate credit rating with positive outlook. Fitch has also assigned a BBB- rating with positive outlook. Moody's has assigned a Baa3 rating and announced on 14 January 2022 that it had placed this rating on review for upgrade.
An integral priority of management and the Board is to make necessary adjustments in investment plans and shareholder distributions to protect liquidity and balance sheet robustness to retain its Investment Grade credit profile. Over the past couple of years, the company has demonstrated its ability to make such adjustments to investment plans, including adjustments to the original dividend and investment plans for 2020 with subsequent readjustments when the market conditions improved in 2021.
At the end of 2021, the company's book equity was USD 2.3 billion, which represents 16 percent of the balance sheet total of USD 14.5 billion. The market value of the company's equity was USD 11.1 billion (NOK 97.8 billion) on 31 December 2021.
In April 2021, the AGM authorized the Board to increase the share capital by a maximum of NOK 18,005,675, representing up to five percent of the total share capital at the time of such meeting. The authorization can be utilized for share capital increases to strengthen the company's equity, convert debt into equity and fund business opportunities. At the time of this report, this mandate has not been used.
The AGM in April 2021 also provided the Board with a mandate to acquire treasury shares representing up to five percent of the total share capital at the time of such meeting. The purpose for this mandate was i) utilization as transaction currency in connection with acquisitions, mergers, demergers or other transactions, ii) of investment or for subsequent sale or cancellation of such shares and iii) in connection with the share savings plan for employees. The mandate is valid until the AGM in 2022. As per 31 December 2021, the mandate had only been used in part and in connection with the share savings plan for employees. The company's employees subscribed for a total of 669,447 shares (0.19 percent of total shares outstanding). After delivery of these shares, Aker BP held 325,655 treasury shares at the end of 2021.
Deviations to the code: None
The company has one class of shares and all shares carry the same rights.
When the company considers it to be in the best interest of shareholders to issue new equity there is a clear objective to limit the level of dilution. Aker BP will carefully consider alternative financing options, its overall capital structure, the purpose and need for new equity, the timing of such an offering, the offer share price, the financial market conditions, and the need for compensating existing shareholders if pre-emption rights are waived. Arguments for waiving pre-emption rights will be clearly stated.
If the Board decides to use its current authorization to re-purchase company shares, the transactions will be carried out through the stock exchange or at prevailing stock exchange prices if carried out in any other way.
As per 31 December 2021, Aker ASA (Aker) owned 37.14 percent and bp p.l.c. (bp) owned 27.85 percent of Aker BP. Aker and bp both account for Aker BP in accordance with the equity method.
Aker BP is committed to equal treatment of all shareholders. The Board is of the view that it is positive for Aker BP that Aker and bp assume the role of active owners and are actively involved in matters of major importance to Aker BP and to all shareholders. The cooperation with Aker and bp offers Aker BP access to expertise and resources within upstream business activities, HSSEQ, technology, strategy, transactions, and funding. It may be necessary to offer Aker and bp special access to commercial information in connection with such cooperation. Any information disclosed to Aker's and bp's representatives in such a context will be disclosed in compliance with the laws and regulations governing the stock exchange and the securities market.
Applicable accounting standards and regulations require Aker and bp to prepare their consolidated financial statements to include accounting information of Aker BP. Aker BP is considered an associate of Aker and bp under the applicable accounting standard. To comply with these accounting standards, Aker and BP have in the past received, and will going forward receive, unpublished accounting information from Aker BP. Such distribution of unpublished accounting information from Aker BP to Aker and bp is executed under strict confidentiality and in accordance with applicable regulations on the handling of inside information.
The Board recognizes Aker's and bp's contribution as active shareholders. Investor communication seeks to ensure that any shareholders can contribute, and management will actively meet with and seek the views of shareholders.
Aker BP has no related parties, as defined in the Public Limited Liability Company Act (Allmennaksjeloven). The company has nevertheless established a policy for transactions with such parties and extended these to include Aker. This policy requires that any material business acquisitions or agreements with Aker (or its related parties) which are not part of Aker BP's ordinary course of business are subject to an independent valuation. The Board of Directors and executive management are very conscious that all relations with Aker and bp, their subsidiaries and other companies in which Aker or bp have ownership interests or entities they have significant control over, shall be premised on commercial terms and are entered into on an arm's length basis. Transactions with Aker and bp controlled companies are described in the financial statements' disclosure about transactions with related parties.
Aker BP's shares are freely negotiable securities and the company's Articles of Association do not impose any form of restriction on their negotiability.
The company's shares are listed on Oslo Børs and the company works actively to attract the interest of new Norwegian and foreign shareholders. Strong liquidity in the company's shares is essential if the company is to be viewed as an attractive investment and thus achieve a competitive cost of capital.
Deviations to the code: None
The General Meeting of shareholders is the company's highest authority and nominates the Board of Directors as the highest governing body. The Board strives to ensure that the General Meeting is an effective forum for communication between the shareholders and the Board and encourages shareholders to participate in the meetings.
The Board can convene an extraordinary General Meeting at any time. A shareholder or a group holding at least five percent of the company's shares can request an extraordinary General Meeting. The Board is then obliged to hold the meeting within one month of receiving the request.
The AGM is normally held before the end of April each year, and no later than the end of June, which is the latest date permitted by the Public Limited Liability Companies Act. The date of the next AGM is normally included in the company's financial calendar, which is available at the company's website.
The notice of a General Meeting is sent to shareholders and published on the company's website and the stock exchange, no later than 21 days prior to the meeting.
Article 7 of the company's Articles of Association, about the General Meeting, stipulates that documents concerning matters to be considered by the General Meeting will be made available to the shareholders on the company's website. This also applies to documents that are required by law to be included in or enclosed with the notice of the General Meeting.
The supporting documentation provides the necessary information for shareholders to form a view on the matters to be considered.
The AGM is normally held before the end of April each year, and no later than the end of June, which is the latest date permitted by the Public Limited Liability Companies Act. The date of the next AGM is normally included in the company's financial calendar, which is available at the company's website. The notice of a General Meeting is sent to shareholders and published on the company's website and the stock exchange, no later than 21 days prior to the meeting.
Article 7 of the company's Articles of Association, about the General Meeting, stipulates that documents concerning matters to be considered by the General Meeting will be made available to the shareholders on the company's website. This also applies to documents that are required by law to be included in or enclosed with the notice of the General Meeting.
The supporting documentation provides the necessary information for shareholders to form a view on the matters to be considered.
The Board proposes the agenda for the AGM. The main agenda items are determined by the requirements of the Public Limited Liability Companies Act and Article 7 in the company's Articles of Association.
Before the AGM, the Board will nominate a person who can vote on behalf of shareholders as their authorized representative. Shareholders may cast their votes in writing, including by means of electronic communication, in a period prior to the General Meeting. Appropriate arrangements are made for shareholders to be able to vote on each individual matter.
The chair of Aker BP's General Meetings is elected by the General Meeting itself.
The Code of Practice states that it is appropriate that all members of the Board should attend General Meetings. Representatives from the Board, the nomination committee, the auditor, and the executive management will attend the AGM.
Minutes of General Meetings are published on the company's website and through a stock exchange announcement.
Deviations from the code: The Code of Practice recommends that all members of the Board are present at the General Meeting and that the chairman of the Nomination Committee should attend the AGM. Due to the nature of discussions at General Meetings, Aker BP has not deemed it necessary to require all Board members and the chairman of the Nomination Committee to be present.
Article 8 in the company's Articles of Association stipulates the composition of and states the main duties of the Nomination Committee.
The company's Nomination Committee shall consist of three members elected by the General Meeting. The Nomination Committee should be composed in such a way that it represents a wide range of shareholders' interests, and if possible, both genders should be represented. More than half of the members shall be independent of the Board and the executive management, and the members shall be elected for a period of two years at a time.
The Nomination Committee shall propose candidates for - and remuneration to - the Board of Directors and the Nomination Committee and justify its recommendation for each candidate separately. The Nomination Committee's recommendations shall be well-grounded. When reporting its recommendations to the General Meeting, the Nomination Committee provides an account of how it has carried out its work.
The Nomination Committee ensures that the shareholder's views are taken into consideration when candidates are proposed. The committee also ensures that the proposed composition of the Board covers all relevant fields of competence, and that the requirement of at least 40 percent of each gender on the Board is met.
Shareholders have an opportunity to submit proposals to the committee. The electronic mailbox for submitting proposals to the committee, with deadlines for submitting proposals where such apply, is accessible through the company's website at www.akerbp.com/proposecandidate.
At the AGM in April 2020, Svein Oskar Stoknes was elected as the Chair of the Nomination Committee for two years. Ingebret Hisdal and Donna Riley were elected as members of the Nomination Committee for two years. No members of the committee are members of executive management or the Board of Aker BP.
Deviations from the code: None
The Board of Aker BP consisted of eleven members as of 31 December2021. The company's Articles of Associations Article 5 stipulates that the Board shall consist of up to eleven members. As required for all Norwegian public limited liability companies, each gender shall be represented by at least 40 percent of the Board members (not applicable to employee representatives).
The general meeting elects the Board members and Chairman of the Board. The term of office for members of the Board is two years at a time.
Among the shareholder-elected Board members, two (Kjell Inge Røkke and Øyvind Eriksen) are affiliated with the company's largest shareholder Aker, and two (Murray Auchincloss and Kate Thomson) are affiliated with the company's second largest shareholder bp. All other Board members are considered independent, defined as individuals who don't have a material or pecuniary relationship with the company either directly or through one of the company's partners, main shareholders, or management members. All Board members are considered independent of the company's executive personnel.
In 2021, the Board conducted a total of 10 Board meetings. Participation was 90 percent.
The Board composition ensures alignment of interests with all shareholders and members of the Board are encouraged to own shares in the company. It is the Board's view that the Board collectively meets the need for expertise, capacity, and diversity. Aker BP's Board members have extensive industrial and managerial experience, both from the oil and gas industry, banking and finance, and from the IT sector.
The average tenure of the current Board members is six years.
An overview of the expertise of the Board members is available on the website: www.akerbp.com/en/ board-of-directors.
Deviations from the code: None
The Board has authority over and is responsible for decisionmaking on, and supervision of, the company's business operations and management, including strategies and targets related to sustainable development, and has adopted a yearly plan for its activities. The Board handles matters of major importance, or of an extraordinary nature and may in addition require management to refer any matter to it. The objectives of the Board's work are to create value for the company's shareholders in both the short and long term and to ensure that Aker BP fulfils its obligations. An important task for the Board is to appoint the CEO and while the CEO is responsible for the day-to-day management of the company's business activities, carried out by the Executive Management Team (EMT), the Board acknowledges its responsibility for the overall management of the company. The Board is responsible for:
The Board recognizes the significant risks associated with operations. Consequently, the Board has dedicated significant resources and time to understand and discuss not only general risks facing an E&P company, but also inherent risks connected to organization, culture, and leadership. For a company like Aker BP, the Board views the risks in taking on an operated development project and meeting the required financing for its entire portfolio as well as taking on operated assets, to be among the most significant risks. Accordingly, this is where the mitigating efforts are concentrated.
In addition to the above-mentioned responsibilities, the Board also develops, approves, monitors, and updates the company's sustainability strategies, policies, and goals. The Board's work in this regard includes, but is not limited to, approval of business plans in which emissions are an important decision criterion, and of initiatives to lower emissions from own operations as well as in the supply chain. For 2021, the ambition was to reduce CO2 emissions from the company's operated assets by at least 10,000 tonnes, while the realised reduction amounted to approximately 23,000 tonnes of CO2. For 2022, the company is targeting a reduction of at least 10,000 tonnes of CO2 emissions from its operated assets.
The work of the Board is based on the rules of procedure describing the Board's responsibility including the division of roles between the Board and the CEO. There are specific instructions to guide the work of the CEO. The CEO, CFO and the company secretary attend all Board meetings. Other members of the company's executive management attend the Board meetings by invitation and as necessary due to specific matters. If the Chair of the Board has been personally involved in matters of a material character, the Deputy Chair takes over the tasks of the chair directing the Board's work in the specific matter.
Considering the size of the company and the scope of its activities, the Board finds it appropriate to keep all Board members informed about all Board matters, except for cases where Board members may have conflicting interests with the company.
The Board regularly carries out self-evaluations of its own performance, including evaluations of the Board's competence and potential areas for strengthening this competence. The head of the Audit and Risk Committee conducts one-on-one discussions with all board members as part of these selfevaluations. The latest self-evaluation was carried out by the Board at the turn of the year, and the results of the selfevaluations are communicated to and used by the Nomination Committee in its work.
The Board members and executive personnel are responsible for making the company aware of any material interests that they may have in items to be considered by the Board of directors. The company's Code of Conduct requires all Aker BP representatives to act impartially in all business matters and provides clear guidelines on how to act in situations where there is a risk of conflicts of interest and partiality.
The Board of Directors has two sub-committees: The Audit and Risk Committee (ARC) and the Compensation and Organisational Development Committee.
The Board has established an Audit and Risk Committee (ARC) consisting of the following Board members:
All members are independent of the company's executive management. Anne Marie Cannon sits on the Board of Directors in Aker Energy AS, which is 50 percent owned by Aker. Kate Thomson is SVP Finance Production & Operations at bp.
The Chair of the Audit and Risk Committee is considered to have experience and formal background qualifying as "financial expert" according to the requirement stated in the Public Limited Liability Company Act. In the period 2016- 2017 Trond Brandsrud was Chief Financial Officer at Lindorff. From 2010 to 2015, he was the Chief Financial Officer of Aker ASA. He has also been Chief Financial Officer in Seadrill, and he has held several leading financial positions in Shell for 20 years, both in Norway and globally.
The Audit and Risk Committee assists the Board's responsibilities within integrity of financial reporting and the financial reporting process. The committee holds regular meetings and reviews the quality of all interim and annual reports before they are reviewed by the Board of Directors and then published. The Audit and Risk Committee also reviews the Sustainability report. In 2021, the committee held seven meetings.
The company's auditor works closely with the Audit and Risk Committee and attended all meetings during the year. The committee also oversees the company's financial risk management and monitors and reviews the company's business risk. The Audit and Risk Committee oversees Aker BP's anti-corruption compliance program and handling of reports submitted via the company's whistleblowing channel.
The management and the Audit and Risk Committee evaluate the risk management on financial reporting and the effectiveness of established internal controls. Identified risks and effects of financial reporting are discussed on a quarterly basis.
It is the view of the committee that cooperation between the auditor and executive management is good. The Audit and Risk Committee has worked together with executive management and the auditor to improve the internal control environment according to the principles of the COSO (Committee of Sponsoring Organizations of the Treadway Commission) framework over the last 5 years.
The Board has a Compensation and Organizational Development Committee consisting of the following three Board members:
The Compensation and Organizational Development Committee is established to ensure that remuneration arrangements support the strategy of the business and enable the recruitment, succession planning and leadership development, and motivation and retention of senior executives. It needs to comply with the requirements of regulatory and governance bodies, satisfy the expectations of shareholders and remain consistent with the expectations of the wider employee population. Further, the committee shall ensure that the overall organizational structure is set up to deliver on the company's strategy going forward. In 2021, the committee held three meetings.
In addition to the above-mentioned committees, the Board may appoint various ad hoc sub-committees when required, with a limited timeframe and scope. The authority of a sub-committee is limited to preparing items and making recommendations to the Board.
The oversight of health, safety, security, and environmental matters (HSSE) is retained directly by the Board. HSSE issues, including cyber security, is at the top of the agenda in every single Board meeting.
In addition, the Board has established a Safety and Environmental Assurance Committee (SEAC) to strengthen the administration work on health, safety, cyber security, and environmental matters. The committee reports to the Board on a quarterly basis and has in 2021 consisted of the following members:
Marit Blaasmo, SVP HSSEQ, Aker BP
Ine Dolve, SVP Operations & Asset Development, Aker BP
SEAC assures that the HSSE work is adequately and properly organized and addressed throughout the entire company and that the HSSE policy and governing processes are embedded in all operations. In addition, SEAC shall:
In 2021, the committee held five meetings.
Deviations from the code: None
Appropriate internal control and risk management contributes to transparency and quality reporting for the benefit of the company, stakeholders, shareholders' long-term interests and operational excellence as an operator on the Norwegian Continental Shelf.
The company continuously and systematically operates a robust and transparent risk management process throughout the organization. The purpose of the process is to enable the company to maximize opportunities, minimize threats and optimize achievements of business objectives.
As of 2021, the company's operational activities are limited to Norway and are subject to Norwegian regulations. All activities taking place in a production license are subject to supervision and audits from governmental bodies like the Petroleum Safety Authority Norway, the Norwegian Environment Agency, and from license partners.
Intro Assets BoD & EMT BoD's report Payments to governments Financials
The Board considers risk in the context of growing a sustainable business while meeting governance, safety and accountability expected by stakeholders. The Board and the Audit and Risk Committee regularly review major risks identified and communicated through the company Enterprise Risk Management process.
The Business Management System (BMS) is the company's framework for creating and sustaining value, trust, and predictability. BMS describes how Aker BP works, controls risk and improves. The BMS describes approximately 300 business processes supplemented by governing documents, requirements, and descriptions. During 2021, the BMS content has been migrated to a new and modern management system software platform. The new BMS system platform has been implemented across all business units.
Risk-based assurance of conformity to the business management system requirements is governed by the company's "Three lines of assurance" model. An improved framework for Aker BP's "Three lines of assurance" was introduced in 2020 and is continually under improvement with regards to processes and tools to enhance execution. First- and second-line assurance-activities are performed by management. First and second line roles are responsible for delivery and assurance of core activities, by establishing and maintaining appropriate structures and processes for the management of operations and risk, including internal controls to ensure conformity with regulatory and ethical requirements and expectations.
Internal audit is established as the third line of assurance, providing independent and objective assurance and advice on the adequacy and effectiveness of governance and risk management. This is achieved through the application of systematic and risk-based audits. To ensure the independence of the internal audit function, the chief audit officer reports administratively to CEO, and functionally to the board of directors.
Aker BP has established a framework for Internal Control for Financial Reporting based on the principles of the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and is operationalized as follows:
The established framework is an integrated part of the company's management system. The company's internal control environment is characterized by clearly defined responsibilities and roles between the Board of Directors, Audit and Risk committee and management. The implemented procedure for financial reporting is integrated with the company's management system, including ethical guidelines that describe how the representatives of the company must act. Aker BP's Anti-Corruption Policy and Speak-up policy provide additional control mechanisms to address and detect deviations.
The company has established processes, procedures, and controls for financial reporting, which are appropriate for an exploration and production company. The company's documented procedures are designed to provide:
A risk assessment related to financial reporting is performed and documented by management and reviewed by the Audit and Risk Committee, which also performs a quarterly risk review of business risks. The Committee reports any findings or deviations to the Board of Directors. In 2021, the following main risk areas were identified related to financial reporting:
The company seeks to communicate transparently on its activities and its financial reporting based on significant interaction between financial reporting management and management responsible for exploration, development, production, and decommissioning activities in the business.
Key events that may affect the financial reporting are identified and monitored continuously. Judgmental items regarding the financial reporting and tax consideration are presented to the Audit and Risk Committee at least on a quarterly basis.
The Finance Department monitors the compliance with established procedures and reports any material deviations to the Audit and Risk Committee. It also identifies actions to improve procedures and conducts a self-assessment of its performance against objectives, which are then presented and discussed with the Audit and Risk Committee.
Deviations from the code: None
The remuneration of the Board members is not performancebased but based on a fixed annual fee. None of the shareholder-elected Board members have pension schemes or termination payment agreements with the company. The company does not grant share options to members of the Board. Information about all remuneration paid to individual Board members is provided in Note 7 to the annual accounts.
The General Meeting decides the remuneration of the Board and the sub-committees. The Nomination Committee proposes the remuneration of the Board to the General Meeting and ensures that it reflects the responsibility of its members and the time spent on Board work. The Board must approve any Board member's consultancy work for the company and remuneration for such work. No such work was carried out during 2021.
Deviations from the code: None
The Board makes guidelines for executive remuneration, including the CEO's remuneration and other terms and conditions of employment. These guidelines set out the main principles applied in determining the salary and other remuneration of executive personnel and are addressed as a separate item at the General Meeting.
The total remuneration consists of a base salary, a pension contribution, an annual bonus based on company performance, and a long-term share-based incentive (LTIP). Members of EMT are covered under the same budget, guidelines, and limitations as other onshore personnel in the company.
Information about all remuneration paid to the CEO and the EMT members is provided in Note 7 to the annual accounts.
Base salary levels are determined considering the nature of the individual role, individual considerations, the market positioning, and remuneration conditions at Aker BP. The base salary is reviewed annually to ensure that it is set at the right level and potential annual percentage increases are aligned with those of employees in general, except in specific circumstances. The CEO base salary is determined by the Board. Adjustment of the base salaries for other senior executives is decided by the CEO within the wage settlement framework adopted by the Board.
Pension is based on a defined contribution plan and is capped at twelve times the National Insurance scheme basic amount (12G) for all employees including the executive management.
The company's bonus system is designed to promote performance in line with the company's strategy. The bonus for all employees, including the CEO and EMT, is determined by the company's performance on a pre-defined set of key performance indicators (KPIs) and Company Priorities, which are important improvement initiatives or activities with clear deliverables that are critical for the company's future success.
The KPIs and Company Priorities are each weighted 50 percent when estimating the bonus outcome. The final bonus outcome, following the formulaic assessment of performance relative to targets is specifically reserved as a matter for the CEO and the Compensation & Organisational Development Committee. Accordingly, the committee may exercise its discretion to adjust the outcome upwards or downwards. The CEO has maximum bonus potential corresponding to 100 percent of base salary. For other members of EMT, the maximum potential is 60 percent. The maximum bonus for employees outside the EMT varies from 10 percent to 30 percent depending on position level.
The KPIs and Company Priorities for 2021 are specified below. The targets and the stretch targets are labelled 'execute' and 'improve' respectively.
| Key Performance Indicators for Aker BP 2021 |
Execute | Improve | Actual |
|---|---|---|---|
| Safety (SIF per million hours) | 0.45 | 0.4 | 0 |
| Production (mboepd) | 215 | 220 | 209.4 |
| Production cost (USD/boe) | 8.5 | 8 | 9.2 |
| Net reserve additions (mmboe) | 44 | 75 | 36 |
| Relative Shareholder Return1) | 5% | 10% | -1.8% |
| CO2 intensity – Equity based (kg/boe) | 5 | 4.5 | 4.8 |
| Value creation (change in risked NPV) | 11% | 13% | 6.3% |
1) Versus Index defined as average of Oslo Energy Index and Stoxx Europe 600 Oil & Gas
Certain members of the EMT participate in a five-year incentive program started in January 2019, through December 2023, linked to the relative performance of the Aker BP share price versus a benchmark index consisting of the average of the Oslo Energy Index and the Stoxx 600 Europe Oil & Gas index (each weighted 50 percent). The incentive program payment is calculated as a linear function of market outperformance, where an outperformance of 30 percent or more will result in a payment of the maximum cap. The maximum total payment
is capped at 200 percent of the executive's annual base salary. The CEO incentive program has the same mechanics and start/ end date and is capped at NOK 30 million.
The CEO and members of the EMT have 6 months mutual notice period. For all other employees, the notice period is 3 months.
Executives receive non-monetary benefits such as phones etc. aligned with local practice. In addition, executives may participate in customary employee benefit programmes, e.g., employee share programmes.
Deviations from the code: None
Aker BP maintains a proactive dialogue with analysts, investors, and other stakeholders of the company. The company strives to continuously publish relevant information to the market in a timely, effective, and non-discriminatory manner, and has a clear goal to attract both Norwegian and foreign investors and to promote higher stock liquidity. The company complies with the Oslo Børs Code of Practice for IR of 1 July 2019.
All stock exchange announcements are made available on the Oslo Børs' website,
Aker BP publishes its preliminary annual accounts by the end of February, as part of its fourth quarter report. The complete annual report, including approved and audited accounts and the Board of Directors' Report, is available no later than three weeks before the AGM. Information sent to shareholders is published on the website simultaneously.
The company's financial calendar for the coming year is published as a stock exchange announcement and made available on the company's website no later than 31 December each year, in accordance with the continuing obligations for companies listed on Oslo Børs.
Aker BP's presentations of quarterly results and its annual Capital Markets Update are webcasted live through the company's web page and are also made available for replay. At the presentations, executive management review and comment on the published results, market conditions and the company's future activities, and answer questions from the audience.
The company's management gives high priority to communication with the investor market. Individual meetings are organized for a wide range of existing and potential new investors and analysts. The company also attends relevant industry and investor conferences.
Aker BP will reduce its contacts with analysts, investors, and journalists in the final 30 days before publication of its results. During this period, the company will give no comments to the media or other parties about the company's results and outlook. This is to ensure that all interested parties in the market are treated equally.
With respect to communicating critical concerns to the Board, the company has multiple reporting channels through which concerns may be raised, all of which are highlighted in employee's annual refresher Code of Conduct course. Regardless of the channel used to raise concerns, they are normally first lifted to the Audit and risk committtee (ARC) for initial assessment, following which they are lifted to the Board if necessary. The compliance department reports regularly to the ARC and informs the committee about the cases that it receives through the company's integrity channel which is also available for external stakeholders. If the ARC considers it critical, the concern would be then lifted to the Board. The number of cases received through the whistleblowing channel is available in the ESG report under the compliance chapter.
Deviations from the code: None
The Board has established a separate set of guidelines for how it will act in the event of a takeover bid, as recommended by the Code of Practice. The overriding principle for review of a takeover bid is equal treatment of shareholders. The principles are based on the Board of Directors and management having an independent responsibility for fair and equal treatment of shareholders in a takeover process, and that the day-to-day operations of the company are not unnecessarily disturbed. It is management's responsibility to ensure that the Board of Directors is made aware of any potential takeover bid, while the Board of Directors is responsible for ensuring that shareholders are kept informed and are given reasonable time to consider the offer.
Unless the Board of Directors has a particular reason, it will not take steps to prevent or obstruct a takeover bid for the company's shares, nor hinder the progress of the bid without approval from shareholders.
If an offer is made for Aker BP's shares, the Board of Directors should make a statement to the shareholders that contains an assessment of the bid, the Board of Directors' recommendations and the reason for the recommendation. If the Board of Directors is unable to make a recommendation to shareholders, the Board of Directors shall explain its reasoning for this.
Transactions that have the effect of a sale of the company or a major part of it must be decided on by shareholders at a shareholders' meeting.
Deviations from the code: None
The AGM elects the auditor and approves the auditor's fee. The Board of Directors will meet with the auditor annually without representatives of company management being present, to review internal control procedures and discuss any weaknesses and proposals for improvement. The auditor is invited to and participates in the Board meetings to discuss the annual accounts. In these meetings, the auditor reports on any material changes in the company's accounting principles and key aspects of the audit, including matters on which there has been disagreement between the auditor and the executive management of the company.
The auditor participates in all meetings with the Audit and Risk Committee and meets the Audit and Risk Committee without the company's management being present. The Board ensures that the auditor submits the main features of the plan for the annual audit of the company to the Audit and Risk Committee annually. The auditor's independence in relation to the company is evaluated annually. The auditor may carry out certain audit related or non-audit services for the company, providing these are not in conflict with its duties as auditor. The company has established an audit and non-audit service policy.
In the annual financial statements, the auditor's remuneration is split between the audit fee and fees for other services. In the presentation to the AGM, the chair presents a breakdown between the audit fee and fees for other services.
Deviations from the code: None
Income statement Statement of comprehensive income Statement of financial position Statement of changes in equity Statement of cash flow Notes to the accounts Note 1 Summary of IFRS accounting principles Note 2 Overview of subsidiaries Note 3 Segment information Note 4 Income Note 5 Production costs Note 6 Exploration expenses Note 7 Payroll expenses and remuneration Note 8 Auditors fee Note 9 Financial items Note 10 Taxes Note 11 Earnings per share Note 12 Tangible fixed assets and intangible assets Note 13 Impairments Note 14 Accounts receivable Note 15 Other short-term receivables Note 16 Inventories Note 17 Other non-current assets Note 18 Cash and cash equivalents Note 19 Share capital and shareholders Note 20 Bonds Note 21 Provision for abandonment liabilities Note 22 Derivatives Note 23 Other current liabilities Note 24 Lease agreements Note 25 Commitments Note 26 Transactions with related parties Note 27 Financial instruments Note 28 Investments in joint operations Note 29 Events after the balance sheet date Note 30 Classification of reserves and contingent resources (unaudited) Statement by the Board of Directors and Chief Executive Officer Alternative performance measures Independent Auditor's Report
INCOME STATEMENT
| Group & Parent | |||
|---|---|---|---|
| (USD 1 000) | Note | 2021 | 2020 |
| Petroleum revenues | 4 | 5 639 990 | 2 868 153 |
| Other operating income | 4 | 28 757 | 111 110 |
| Total income | 5 668 747 | 2 979 263 | |
| Production costs | 5 | 745 313 | 627 975 |
| Exploration expenses | 6 | 353 034 | 174 099 |
| Depreciation | 12 | 964 083 | 1 121 818 |
| Impairments | 12,13 | 262 554 | 573 128 |
| Other operating expenses | 7,8 | 29 261 | 49 457 |
| Total operating expenses | 2 354 245 | 2 546 477 | |
| Operating profit | 3 314 502 | 432 786 | |
| Interest income | 2 481 | 3 763 | |
| Other financial income | 116 171 | 170 865 | |
| Interest expenses | 139 533 | 181 677 | |
| Other financial expenses | 220 836 | 262 052 | |
| Net financial items | 9 | -241 718 | -269 101 |
| Profit before taxes | 3 072 785 | 163 685 | |
| Taxes (+)/tax income (-) | 10 | 2 222 080 | 118 970 |
| Net profit | 850 704 | 44 715 | |
| Weighted average no. of shares outstanding basic and diluted | 11 | 359 642 622 | 359 808 121 |
| Basic and diluted earnings USD per share | 11 | 2.37 | 0.12 |
| Group & Parent | ||||
|---|---|---|---|---|
| (USD 1 000) Note |
2021 | 2020 | ||
| Profit for the period | 850 704 | 44 715 | ||
| Items which will not be reclassified over profit and loss (net of taxes) | ||||
| Actuarial gain/loss pension plan | - | 9 | ||
| Total comprehensive income in period | 850 704 | 44 724 |
Intro Assets BoD & EMT BoD's report Payments to governments Corporate governance
| Group & Parent | ||||
|---|---|---|---|---|
| (USD 1 000) | Note | 31.12.2021 | 31.12.2020 | |
| ASSETS | ||||
| Intangible assets | ||||
| Goodwill | 12 | 1 647 436 | 1 647 436 | |
| Capitalized exploration expenditures | 12 | 256 535 | 521 922 | |
| Other intangible assets | 12 | 1 407 551 | 1 521 311 | |
| Tangible fixed assets | ||||
| Property, plant and equipment | 12 | 7 976 308 | 7 266 137 | |
| Right-of-use assets | 12 | 94 177 | 132 735 | |
| Financial assets | ||||
| Long-term receivables | 73 346 | 29 086 | ||
| Other non-current assets | 17 | 30 304 | 30 210 | |
| Long-term derivatives | 22 | 1 375 | 12 841 | |
| Total non-current assets | 11 487 032 | 11 161 678 | ||
| Inventories Inventories |
16 | 126 442 | 112 704 | |
| Receivables | ||||
| Accounts receivable | 14 | 366 785 | 297 880 | |
| Other short-term receivables | 15 | 500 154 | 286 817 | |
| Short-term derivatives | 22 | 18 577 | 23 212 | |
| Cash and cash equivalents | ||||
| Cash and cash equivalents | 18 | 1 970 906 | 537 801 | |
| Total current assets | 2 982 863 | 1 258 414 | ||
| TOTAL ASSETS | 14 469 895 | 12 420 091 |
| Group & Parent | ||||
|---|---|---|---|---|
| (USD 1 000) | Note | 31.12.2021 | 31.12.2020 | |
| EQUITY AND LIABILITIES | ||||
| Equity | ||||
| Share capital | 19 | 57 056 | 57 056 | |
| Share premium | 3 637 297 | 3 637 297 | ||
| Other equity | -1 352 462 | -1 707 071 | ||
| Total equity | 2 341 891 | 1 987 281 | ||
| Non-current liabilities Deferred taxes |
10 | 3 323 213 | 2 642 461 | |
| Long-term abandonment provision | 21 | 2 656 358 | 2 650 263 | |
| Long-term bonds | 20 | 3 576 735 | 3 968 566 | |
| Long-term derivatives | 22 | 2 370 | - | |
| Long-term lease debt | 24 | 91 835 | 131 856 | |
| Total non-current liabilities | 9 650 511 | 9 393 146 | ||
| Current liabilities | ||||
| Trade creditors | 147 366 | 113 517 | ||
| Accrued public charges and indirect taxes | 28 147 | 25 761 | ||
| Tax payable | 10 | 1 497 291 | 163 352 | |
| Short-term derivatives | 22 | 35 082 | 3 539 | |
| Short-term abandonment provision | 21 | 100 863 | 155 244 | |
| Short-term lease debt | 24 | 44 378 | 83 904 | |
| Other current liabilities | 23 | 624 366 | 494 346 | |
| Total current liabilities | 2 477 493 | 1 039 664 | ||
| Total liabilities | 12 128 004 | 10 432 810 | ||
| TOTAL EQUITY AND LIABILITIES | 14 469 895 | 12 420 091 |
Akerkvartalet, 8 March 2022 The Board of Directors and the CEO of Aker BP ASA, Akerkvartalet, 8 March 2022
Øyvind Eriksen, Chairman of the Board Kjell Inge Røkke, Board member
ØYVIND ERIKSEN Chairman of the Board
Paula Doyle, Board member Terje Solheim, Board member
PAULA DOYLE Board member
INGARD HAUGEBERG Board member
ANNE MARIE CANNON Deputy Chair
KATE THOMSON Board member
TORE VIK Board member
Anne Marie Cannon, Deputy Chair Trond Brandsrud, Board member
Kate Thomson, Board member Murray Auchincloss, Board member KJELL INGE RØKKE Board member
MURRAY AUCHINCLOSS Board member
HILDE KRISTIN BREVIK Board member
TROND BRANDSRUD Board member
TERJE SOLHEIM Board member
KARL JOHNNY HERSVIK Chief Executive Officer
| Other equity | ||||||||
|---|---|---|---|---|---|---|---|---|
| Other comprehensive income | ||||||||
| Foreign | ||||||||
| currency | ||||||||
| Other paid-in | Actuarial | translation | Accumulated | Total other | ||||
| (USD 1 000) | Share capital | Share premium | capital | gains/(losses) | reserves1) | deficit | equity | Total equity |
| 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 |
| Dividends distributed | - | - | - | - | - | -425 000 | -425 000 | -425 000 |
| Profit for the period | - | - | - | - | - | 44 715 | 44 715 | 44 715 |
| Purchase/sale of treasury shares2) | - | - | - | - | - | -28 | -28 | -28 |
| Other comprehensive income for the period | - | - | - | 9 | - | - | 9 | 9 |
| Equity as of 31.12.2020 | 57 056 | 3 637 297 | 573 083 | -76 | -115 491 | -2 164 587 | -1 707 071 | 1 987 281 |
| Dividends distributed | - | - | - | - | - | -487 500 | -487 500 | -487 500 |
| Profit for the period | - | - | - | - | - | 850 704 | 850 704 | 850 704 |
| Purchase/sale of treasury shares2) | - | - | - | - | - | -8 595 | -8 595 | -8 595 |
| Other comprehensive income for the period | - | - | - | - | - | - | - | - |
| Equity as of 31.12.2021 (Group and Parent) | 57 056 | 3 637 297 | 573 083 | -76 | -115 491 | -1 809 977 | -1 352 462 | 2 341 891 |
1) The amount arose mainly as a result of the change in functional currency in 2014.
2) The treasury shares are purchased/sold for use in the company's share saving plan.
| Group & Parent | ||||
|---|---|---|---|---|
| Restated | ||||
| (USD 1 000) | Note | 2021 | 2020 | |
| CASH FLOW FROM OPERATING ACTIVITIES | ||||
| Profit/loss before taxes | 3 072 785 | 163 685 | ||
| Taxes paid | -296 155 | -145 286 | ||
| Taxes refunded | 72 989 | 326 208 | ||
| Depreciation | 12 | 964 083 | 1 121 818 | |
| Impairment | 12,13 | 262 554 | 573 128 | |
| Accretion expenses | 9,21 | 113 748 | 116 947 | |
| Total interest expenses (excluding amortized loan costs) | 9 | 117 073 | 161 863 | |
| Changes in derivatives | 4,9 | 50 015 | -15 999 | |
| Amortized loan costs | 9 | 22 460 | 19 813 | |
| Expensed capitalized dry wells | 6,12 | 98 827 | 56 626 | |
| Changes in inventories, trade creditors and receivables | -48 794 | -161 027 | ||
| Changes in other current balance sheet items | -147 428 | -206 423 | ||
| NET CASH FLOW FROM OPERATING ACTIVITIES | 4 282 157 | 2 011 353 | ||
| CASH FLOW FROM INVESTMENT ACTIVITIES | ||||
| Payment for removal and decommissioning of oil fields | 21 | -172 512 | -150 306 | |
| Disbursements on investments in fixed assets (excluding capitalized interest) | 12 | -1 376 879 | -1 238 601 | |
| Disbursements on investments in capitalized exploration expenditures | 12 | -177 464 | -127 283 | |
| Cash received from sale of licenses | - | 54 747 | ||
| NET CASH FLOW USED IN INVESTMENT ACTIVITIES | -1 726 855 | -1 461 443 | ||
| CASH FLOW FROM FINANCING ACTIVITIES | ||||
| Net drawdown/repayment/fees related to revolving credit facility | -7 675 | -1 451 550 | ||
| Repayment of bonds | -1 282 503 | -618 553 | ||
| Net proceeds from bond issue | 899 334 | 2 718 248 | ||
| Receipt/payment upon settlement of derivatives related to financing | - | -56 804 | ||
| Interest paid (including interest element of lease payments) | -151 085 | -184 068 | ||
| Payments on lease debt related to investments in fixed assets | -44 805 | -57 885 | ||
| Payments on other lease debt | -39 810 | -43 709 | ||
| Paid dividend | -487 500 | -425 000 | ||
| Net purchase/sale of treasury shares | -8 595 | -28 | ||
| NET CASH FLOW FROM FINANCING ACTIVITIES | 27 | -1 122 640 | -119 348 | |
| Net change in cash and cash equivalents | 1 432 662 | 430 562 | ||
| Cash and cash equivalents at start of period | 537 801 | 107 104 | ||
| Effect of exchange rate fluctuation on cash held | 443 | 134 | ||
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 18 | 1 970 906 | 537 801 |
Aker BP ASA ("Aker BP" or "the company") is an oil company involved in exploration, development and production of oil and gas on the Norwegian Continental Shelf (NCS).
The company is a public limited liability company registered and domiciled in Norway. Aker BP's shares are listed on Oslo Stock Exchange (Oslo Børs) under the ticker AKRBP. The company's registered business address is Oksenøyveien 10, 1366 Lysaker, Norway.
The Aker BP group comprise the parent company Aker BP ASA and the three subsidiaries Det norske oljeselskap AS (including its subsidiary Aker BP UK Limited), Alvheim AS and Sandvika Fjellstue AS. Det norske oljeselskap AS, Alvheim AS and Sandvika Fjellstue AS are not consolidated in the group financial statements as they are immaterial. For more information regarding subsidiaries, see note 2.
On 21 December 2021, Aker BP announced a transaction agreement with Lundin Energy AB, pursuant to which Aker BP will acquire all of Lundin Energy's oil and gas related assets. The transaction is subject to approval by the shareholders of both companies at their respective general meetings, and approval by relevant authorities. Closing of the transaction is targeted in the second quarter 2022.
The financial statements were approved by the Board of Directors on 8 March 2022 and will be presented for approval at the Annual General Meeting on 5 April 2022.
The group consolidated and the company's financial statements have been prepared in accordance with the Norwegian Accounting Act and International Financial Reporting Standards as adopted by the EU ("IFRS"). In these financial statements, reference to the company is applicable to the group and the parent entity unless otherwise stated.
The financial statements have been prepared on a historical cost basis with the exception of the following accounting items which are measured on an alternative basis at each reporting date:
All amounts have been rounded to the nearest thousand unless otherwise stated. As a result of rounding adjustments, the figures in one or more rows or columns included in the
financial statements and notes may not add up to the total of that row or column.
The functional currency of Aker BP ASA and the presentation currency of the group is United States Dollars ("USD").
The preparation of financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that have an effect on the application of accounting principles and the reported assets, liabilities, income and expenses.
The significant judgments management has made regarding the application of accounting principles are as follows:
For the purpose of impairment testing, goodwill is allocated to a cash-generating unit (CGU), or groups of CGUs that are expected to benefit from the synergies of the business combination from which it arose. The allocation of goodwill requires judgment and may significantly impact any subsequent impairment charge. Although not an IFRS term, "technical goodwill" is used by Aker BP to describe the category of goodwill arising as an offsetting account to deferred tax liabilities recognised in business combinations, as described in section 1.8 below. There are no specific IFRS guidelines pertaining to the allocation of technical goodwill, and management has therefore applied the general guidelines for allocating goodwill. In general, technical goodwill is allocated at the CGU level for impairment testing purposes, while residual goodwill may be allocated across all CGUs based on the facts and circumstances of the business combination.
When performing the impairment test for technical goodwill, deferred tax liabilities recognized in relation to the acquired licenses reduce the net carrying value prior to any impairment charges. This methodology avoids an immediate impairment of all technical goodwill. When deferred tax liabilities from the initial recognition decreases, additional technical goodwill is 'exposed' to impairment. Subsequent to the initial purchase price allocation, depreciation of book values will result in decreasing deferred tax liabilities.
Accounting estimates are used to determine reported amounts, including the depreciation of assets, the cost and timing of decommissioning activities, impairment testing of goodwill and the recognition and measurement of tax liabilities. Whilst these estimates are based on management's best judgment and assessments of previous and current events and actions, the actual results may deviate from the
original estimates. Changes to accounting estimates are recognized in the period when they arise. The main sources of uncertainty when making estimates and judgments relate to the following:
Oil and gas reserves are estimated by the company's experts in accordance with industry standards. The estimates are based on Aker BP's own assessment of internal information and information received from operators. In addition, proven and probable reserves are certified by an external party. Proven and probable oil and gas reserves consist of the estimated quantities of crude oil, natural gas and condensates shown by geological and technical data to be recoverable with reasonable certainty from known reservoirs under existing economic and operational conditions, i.e. on the date that the estimates are prepared. Current market prices are used in the estimates.
Proven and probable reserves and production volumes are used to calculate the depreciation of oil and gas fields by applying the unit-of-production method. Reserve estimates are also used as basis for impairment testing of licenserelated assets and goodwill. Changes in petroleum prices and cost estimates may change reserve estimates and accordingly economic cut-off, which may impact the timing of assumed decommissioning and removal activities. Changes to reserve estimates can also result from updated production and reservoir information. Future changes to proven and probable oil and gas reserves can have a material effect on depreciation, life of field, impairment of license-related assets and goodwill, and operating results.
Expenses relating to the drilling of exploration wells are temporarily recognized in the Statement of financial position as capitalized exploration expenditures, pending an evaluation of potential oil and gas discoveries. If resources are not discovered, or if recovery of the resources is considered technically or commercially unviable, the costs of exploration wells are expensed. Judgments as to whether this expenditure should remain capitalized or be expensed at the reporting date may materially affect the operating result for the period.
The fair values of non-financial assets and liabilities are required to be determined, for example in a business combination, to determine the allocation of purchase price in an asset deal or when the recoverable amount of an asset or CGU is based on fair value less cost to sell. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability.
A fair value measurement of a non-financial asset takes into account a market participant's ability to generate economic
benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use. The group uses valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. The fair value of oil fields in production and development phase is normally based on discounted cash flow models, where the determination of inputs to the model may require significant judgment, as described in the section below regarding impairment.
Changes in the expected future value/cash flows of CGUs results in impairment if the estimated recoverable value is lower than the book value (including any allocated goodwill) or the reversal of previously recognized impairment if the recoverable value is higher than the book value (though impairment of goodwill is not reversed). Estimates of recoverable value involve the application of judgment and assumptions, including in relation to the modelling of future cash flows to estimate the CGUs value in use or fair value.
The evaluation of impairment requires long-term assumptions concerning a number of often volatile economic factors, including future oil prices, oil production, currency exchange rates and discount rates. Such assumptions require the estimation of relevant factors such long-term prices, the levels of capex and opex, production estimates and decomissioning costs. These evaluations are also necessary to determine a CGU's fair value unless information can be obtained from an actual observable market transaction. See note 12 ' Tangible fixed assets and intangible assets' and note 13 'Impairments' for details of impairments.
The company has obligations to decommission and remove offshore installations at the end of their production period. Obligations associated with decommissioning and removal of long-term assets are recognized at present value of future expenditures at the date they are expected to be incurred. At the initial recognition of an obligation, the estimated cost is capitalized as production plant and depreciated over the useful life of the asset (typically by application of the unit-ofproduction method). There is significant future uncertainty in the estimate of costs for decommissioning and removal, as these estimates are based on currently applicable laws and regulations, and existing technologies. Many decommissioning and removal activities will take place many decades in the future, and the technology and related costs are expected to evolve in this time. The estimates include costs based on expected removal concepts using existing technology and estimated costs of maritime operations, hiring of single-lift and heavy-lift barges and drilling rigs. As as result, there may be significant adjustments to the estimates of decomissioning liabilities and associated assets that can affect future financial results. See note 21 'Provision for abandonment liabilities' for further details about decommissioning and removal obligations.
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Income tax expense, tax payables or receivables, and deferred taxes are based on management's interpretation of applicable laws and regulations, and on relevant court decisions where relevant. These estimates are dependent on management's ability to interpret and apply the requirements of tax and other relevant legislation, and requires judgment in respect of the recognition and measurement of any uncertain tax positions. See note 10 'Taxes' for further details.
Transactions and balances
Transactions denominated in foreign currencies are translated using the exchange rate on the transaction date. Monetary items denominated in foreign currencies in the Statement of Financial Position are translated using the exchange rates at the reporting date. Foreign exchange gains and losses are recognized as incurred. Non-monetary items that are measured at historical costs in a foreign currency are translated using the exchange rates on the date of the initial transaction. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rate on the date when the fair value is determined.
Revenue from the sale of liquids or gas is recognised at the point in time when the company's contractual performance obligations has been fulfilled and control is transferred to the customer, which will ordinarily be at the point of delivery when title passes (sales method).
There is no significant judgement applying IFRS 15 'Revenue from contracts with customers' to the company's revenue generating contracts.
Changes in over/underlift balances are valued at production cost including depreciation and presented as an adjustment to cost. See note 5 for further details.
Gains or losses on asset disposals as described in section 1.9 are included in other operating income.
Tariff revenue from processing of oil and gas is recognized as earned in line with underlying agreements.
IFRS defines a joint arrangement as an arrangement over which two or more parties have joint control. Joint control is the contractually agreed sharing of control which exists only when decisions about the relevant activities (being those that significantly affect the returns of the arrangement) require unanimous consent of the parties sharing control.
The company has interests in licenses on the Norwegian Continental Shelf. Under IFRS 11 Joint Arrangements, a joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets and obligations for the liabilities, relating to the arrangement.
The company recognizes investments in joint operations (oil and gas production licenses) by reporting its share of related revenues, expenses, assets, liabilities and cash flows under the respective items in the company's financial statements.
For those licenses that are not deemed to be joint arrangements pursuant to the definition in IFRS 11 as there is no joint control, the company recognizes its share of related expenses, assets, liabilities and cash flows on a line-by-line basis in the financial statements in accordance with applicable IFRSs.
Current assets and current liabilities include items that fall due for payment less than a year from the end of the reporting period and items relating to the ordinary business cycle. The following year's instalments on long-term liabilities are classified as current liabilities. Financial investments in shares are classified as current assets, while strategic investments are classified as non-current assets.
In order to consider an acquisition as a business combination, the acquired asset or groups of assets must constitute a business (an integrated set of operations and assets conducted and managed for the purpose of providing a return to the investors). The combination consists of inputs and substantive processes applied to these inputs that have the ability to create outputs. Amendments to IFRS 3 effective in January 2020 introduce a new optional 'concentration test' which may result in a business combination being accounted for as an asset acquisition if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group or similar identifiable assets.
Acquired businesses are included in the financial statements from the transaction date. The transaction date is defined as the date on which the company obtains control over the financial and operating assets. This date may differ from the actual date on which the assets are transferred.
For accounting purposes, the acquisition method is applied to the purchase of businesses. Acquisition cost equals the fair value of consideration, including contingent consideration, equity instruments issued and liabilities assumed in connection with the transfer of control. Acquisition cost is measured against the fair value of the acquired assets and liabilities. Identifiable intangible assets are included in connection with acquisitions if they can be separated from other assets or meet the legal contractual criteria. If the acquisition cost at the time of the acquisition exceeds the fair value of the acquired net assets (when the acquiring entity achieves control of the transferring entity), goodwill arises.
In a business combination, if the fair value of the net identifiable assets acquired exceeds the acquisition cost on the acquisition date, the excess amount is taken to the Income statement immediately.
In a business combination, goodwill is allocated to the CGUs or groups of CGUs that are expected to benefit from synergies of the acquisition. The allocation of goodwill may vary depending on the basis for its initial recognition.
The majority of the company's goodwill is related to the requirement to recognize deferred tax for the difference between the assigned fair values and the related tax base ("technical goodwill"). The fair value of of the company's licenses, all of which are located on the Norwegian Continental Shelf, are based on cash flows after tax. This is because these licenses are only sold in an after-tax market based on the tax carry-over principles pursuant to the Petroleum Taxation Act section 10. The purchaser is therefore not entitled to a tax deduction for the consideration paid over and above the seller's tax values. In accordance with IAS 12 paragraphs 15 and 24, a provision is made for deferred tax corresponding to the difference between the acquisition cost and the transferred tax depreciation basis. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax. Technical goodwill is tested for impairment separately for each CGU which give rise to the technical goodwill. A CGU may be individual oil fields, or a group of oil fields that are connected to the same infrastructure/production facilities.
The estimation of fair value and goodwill may be adjusted up to 12 months after the acquisition if new information has emerged about facts and circumstances that existed at the time of the acquisition and which, had they been known, would have affected the calculation of the amounts recognized.
Acquisition-related costs, except costs to issue related debt or equity securities, are expensed as incurred.
On acquisition of a license that involves the right to explore for and produce petroleum resources, it is considered in each case whether the acquisition should be treated as a business combination (see Item 1.8) or an asset purchase. Generally, purchases of licenses in a development or production phase will be regarded as a business combination. Other license purchases regarded as asset purchases are described below.
For licenses in the development phase, the acquisition cost is allocated between capitalized exploration expenses, license rights and production plant.
When entering into agreements regarding the purchase/ swap of assets, the parties agree on an effective date for the takeover of the net cash flow (usually 1 January in the calendar year which would also normally be the effective date for tax purposes). In the period between the effective date and the completion date, the seller will include its sold share of the license in the financial statements. In accordance with the purchase agreement, there is a settlement with
the seller of the net cash flow from the asset in the period from the effective date to the completion date (pro & contra settlement). The pro & contra settlement will be adjusted to the seller's losses/gains and to the assets for the purchaser, in that the settlement (after a tax reduction) is deemed to be part of the consideration in the transaction. Revenues and expenses from the relevant license are included in the purchaser's Income statement from the acquisition date, as defined in 1.8 above.
For tax purposes, the purchaser will include the net cash flow (pro & contra) and any other income and costs as from the effective date.
When acquiring licenses that are defined as asset acquisitions, no provision is made for deferred tax.
Farm-in agreements are usually entered into in the exploration phase and are characterised by the transferor waiving future financial benefits in the form of reserves, in exchange for reduced future financing obligations. For example, a license interest is taken over in return for a share of the transferor's expenses relating to the drilling of a well. In the exploration phase, the company normally accounts for farm-in agreements on a historical cost basis, as the fair value cannot be reliably determined.
Swaps of assets are calculated at the fair value of the asset being surrendered, unless the transaction lacks commercial substance, or neither the fair value of the asset received, nor the fair value of the asset surrendered, can be effectively measured. In the exploration phase, the company normally recognizes swaps based on historical cost, as the fair value cannot be reliably measured.
According to Norwegian law, a unitization is required if a petroleum deposit extends over several production licenses and these production licenses have different ownership interests. Consensus must be achieved with regard to the most beneficial coordination of the joint development and ownership distribution of the petroleum deposit. A unitization agreement shall be approved by the Ministry of Petroleum and Energy.
The company normally recognizes unitizations in the exploration phase based on historical cost, as the fair value cannot be reliably measured. For unitizations involving licenses outside the exploration phase, it has to be considered whether the transaction has commercial substance. If so, the unitization is recognized at fair value.
Tangible fixed assets are recognized on a historical cost basis.
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The book value of tangible fixed assets consists of acquisition cost net of accumulated depreciation and impairment losses.
Ordinary repair and maintenance costs relating to day-to-day operations are charged to the Income statement in the period in which they are incurred.
Gains and losses relating to the disposal of assets are determined by comparing the selling price with the book value, and are included in other operating income/expenses on a post tax basis. Assets held for sale are measured at the lower of the book value and the fair value less cost to sell.
Capitalized exploration expenditures are classified as intangible assets and reclassified to tangible assets at the start of development. For accounting purposes, the field is considered to enter the development phase when the technical feasibility and commercial viability of extracting hydrocarbons from the field are demonstrable, normally at the time of concept selection. All costs relating to the development of commercial oil and/or gas fields are recognized as tangible assets. Pre-operational costs are expensed as they are incurred.
The company employs the 'successful efforts' method to account for exploration and development costs. All exploration costs (including seismic shooting, seismic studies and 'own time'), with the exception of acquisition costs of licenses and drilling costs for exploration wells, are expensed as incurred. When exploration drilling is ongoing in a period after the reporting date and the result of the drilling is subsequently not successful, the capitalized exploration cost as of the reporting date is expensed if the evaluation of the well is completed before the date when the financial statements are authorized for issue.
Drilling cost for exploration wells are temporarily capitalized pending the evaluation of potential discoveries of oil and gas resources. Such costs can remain capitalized for more than one year. The main criteria is that there must be plans for future activity in the license area or that a development decision is expected in the near future. If no resources are discovered, or if recovery of the resources is considered technically or commercially unviable, expenses relating to the drilling of exploration wells are charged to expense.
Acquired license rights are recognized as intangible assets at the time of acquisition. Acquired license rights related to fields in the exploration phase remain as intangible assets also when the related fields enter the development or production phase.
Capitalized exploration and evaluation expenditures, development expenditures from construction, installation or completion of infrastructure facilities such as platforms, pipelines and production wells, and field-dedicated transport systems for oil and gas are capitalized as production facilities and are depreciated using the unit-of-production method based on proven and probable developed reserves expected to be recovered from the area during the concession or contract period. Acquired assets used for the recovery and production of petroleum deposits, including license rights, are also depreciated using the unit-of-production method based on proven and probable reserves. The reserve basis used for depreciation purposes is updated at least annually. Any changes in the reserves affecting unit-of-production calculations are reflected prospectively.
Depreciation of assets other than oil and gas fields, including right of use assets, is calculated using the straight-line method over estimated useful lives and adjusted for any impairment or change in residual value, if applicable.
Tangible fixed assets and intangible assets
Tangible fixed assets and intangible assets (including license rights, exclusive of goodwill) with a finite useful life will be assessed for potential impairment when events or changes in circumstances indicate that the book value of the assets is higher than the recoverable amount.
The unit of account for assessment of impairment is based on the lowest level at which it is possible to identify cash inflows that are independent of cash inflows from other groups of fixed assets. For oil and gas assets, this is typically the field or license level. Impairment is recognized when the book value of the CGU (including any allocated goodwill) exceeds the recoverable amount. The recoverable amount is the higher of the asset's fair value less cost of disposal and value in use. When estimating value in use and fair value less cost of disposal, expected future cash flows are 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).
The lifetime of the field for the purpose of impairment testing is normally determined by the point in time when the operating cash flow from the field becomes negative.
For exploration licenses, impairment is based on an assessment of whether plans for further activities have been established or, if applicable, an evaluation of whether development will be decided on in the near future as described in section 1.11.
A previously recognized impairment can only be reversed if changes have occurred in the estimates used for the calculation of the recoverable amount. However, the reversal cannot be to an amount that is higher than it would have been if the impairment had not previously been recognized. Such reversals are recognized in the Income statement. After a reversal, the depreciation amount is adjusted in future periods
in order to distribute the asset's revised book value, minus any residual value, on a systematic basis over the asset's expected remaining life.
Goodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that the value may be impaired.
Impairment is recognized if the recoverable amount of the CGU (or group of CGUs) to which the goodwill is related is less than the book value, including associated goodwill and deferred tax as described in section 1.8. Losses relating to impairment of goodwill cannot be reversed in future periods.
The company has classified the financial instruments into the following categories of financial assets and liabilities:
Financial assets with fixed or determinable cash flows that are not quoted in an active market are classified as loans and receivables.
Financial liabilities that do not form part of the "held for trading purposes" category and which have not been designated as being at fair value with changes in value through profit or loss are classified as other financial liabilities.
Further details on fair values of financial instruments are provided in note 28 'Financial instruments'.
Financial assets that are held at amortized cost are impaired when, based on objective evidence, it is likely that the instrument's cash flows have been negatively affected by one or more events that have occurred after initial recognition. In addition, the loss event must have an impact on estimated future cash flows that can be reliably estimated. The impairment is recognized in the Income statement.
Research consists of original, planned studies carried out with a view to achieving new scientific or technical knowledge or understanding, and the associated costs are expensed as incurred. Development consists of the application of information gained through research, or of other knowledge, to a plan or design for the production of new or significantly improved materials, facilities, products, processes, systems or services before commercial production or use commences. Development costs are capitalized when the underlying project is technically feasible.
The company presents its payroll and administration costs based on the functions in development, operational and exploration activities respectively, based on allocation of registered hours worked, net of amounts recharged to operated licenses.
At the inception of a contract, the company assesses whether the contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.
The lease liability is recognized at the commencement date and measured at the present value of the remaining lease payments, discounted using the company's incremental borrowing rate at the commencement date. The borrowing rate is derived from the terms of the company's existing credit facilities. RoU assets are depreciated over the lease term as this is ordinarily shorter than the useful life of the assets. The lease term represents the non-cancellable period of the lease, together with periods covered by an option either to extend or to terminate the lease when the company is reasonably certain to exercise this option.
The company applies the exemption for short term leases (12 months or less) and low value leases. As such, related lease payments are not recognized in the balance sheet, but expensed or capitalized in line with the accounting treatment for other non-lease expenses. The inclusion of non-lease components may vary across different lease categories, but for the most material class of assets (rigs), the company has excluded the non-lease components when measuring the lease liability.
The company may enter into lease contracts as an operator on behalf of a license, and has for such leases only recognized its net share of the related lease liability. Whether a contract is entered into on behalf of the license is subject to a contract specific assessment, but the general principle is that there needs to be a direct link between the lease contract and the license or field on which the RoU asset shall be used. Other lease contracts, such as offices and supply vessels not linked to specific fields, are recognized on a gross basis although the related cashflows are charged to the license partners, typically via cost pools. For such contracts, the partner's share of the cost recovered by the company are presented as other income.
The company may enter into lease contracts in its own name at the initial signing, and subsequently allocate the related RoU asset to operated licenses. In such cases, the license allocation will normally be the basis for determining both the commencement and the duration of the lease (and application of the short-term lease exemption).
Trade debtors are recognized in the Statement of Financial Position at nominal value after a deduction for the provision for credit losses. Historically there have been no significant credit losses.
Borrowing costs that can be directly ascribed to procurement, processing or production of a qualifying asset are capitalized as part of the asset's acquisition cost. Borrowing cost is only capitalized during the development phase. Other borrowing costs are expensed in the period in which they are incurred.
A qualifying asset is one that necessarily takes a substantial period of time to be made ready for its intended use or sale. Qualifying assets are generally those that are subject to major development or construction projects.
Inventories mainly consists of equipment for the drilling of exploration and production wells and are valued at the lower of cost price (based on weighted average cost) and net realizable value.
Cash and cash equivalents include cash, bank deposits, and other short-term highly liquid investments with an original due date of three months or less. Bank overdrafts are included in the Statement of Financial Position as short-term loans.
All borrowings are initially recognized at transaction price, which equals the fair value of the amount received net of costs directly related to the establishment of the loan or issuance of debt.
Subsequently, interest-bearing borrowings are valued at amortized cost using the effective interest method; the difference between the transaction price (after transaction costs) and the face value is recognized in the Income statement in the period until the loan falls due. Amortized costs are calculated by considering all issue costs on the settlement date, except for any discount or premium expensed immediately.
Tax consists of tax payable and changes in deferred tax. Deferred tax/tax benefits are calculated on the basis of the differences between book value and tax basis values of assets and liabilities, with the exception of temporary differences on acquisition of licenses that are defined as asset purchases.
Deferred tax is measured using the expected tax rate when the tax benefit is realised or the tax liability is met, based on tax rates and tax regulations that have been enacted or substantively enacted at the reporting date.
Tax payable and deferred tax is recognized directly against equity or other comprehensive income insofar as the tax items are related to equity transactions or items of other comprehensive income.
Deferred tax and tax benefits are presented net, where netting is legally permitted and the deferred tax benefit and liability are related to the same tax subject and are payable to the same tax authorities.
The company's functional currency is USD, while it is a statutory requirement to calculate the current tax based on NOK functional currency. This may impact the effective tax rate when the exchange rate between NOK and USD fluctuates. The revaluation of tax receivable and payable is presented as foreign exchange gain/loss, while the impact on deferred tax from revaluation of tax balances is presented as tax expense / income.
As a production company, Aker BP is subject to the special provisions of the Petroleum Taxation Act. Taxable profits from activities on the Norwegian Continental Shelf are liable to ordinary company tax and special tax. The tax rate for general corporate tax was 22 percent in 2020, and was unchanged in 2021. The rate for special tax was 56% for both years.
Pipelines and production facilities can be depreciated by up to 16 2/3 percent annually, i.e., using the straight-line method over six years. Tax depreciation commences when the expenses are incurred. When a field stops producing, any remaining tax values (except for future uplift) may be deducted in that year.
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.
Uplift is a special income deduction in the basis for calculation of special tax. Uplift is calculated on the basis of investments in pipelines and production facilities, and can be regarded as an extra depreciation deduction in the special tax regime. The uplift rate was 5.2 percent in 2019 over a period of four years, totalling 20.8 percent from 2019. Uplift is recognized in the year it is deducted in the companies' tax returns, and this has a similar effect on the tax for the period as a permanent difference. Under the temporary tax rule enacted in 2020, the uplift is 24% for income year 2020 and 2021 and can be deducted for special tax (56%) in the year of investment.
Interest on debt with associated currency losses/gains (net financial expenses on interest-bearing debt) is distributed between the offshore and onshore tax regimes. Offshore interest deduction is calculated as the net financial costs of interest-bearing debt multiplied by 50 percent of the ratio between net asset value for tax purposes allocated to the offshore tax regime as of 31 December in the income year and the average interest-bearing debt through the income year.
Remaining financial expenses, currency losses and all interest income as well as currency gains are allocated to the onshore jurisdiction.
Uncovered losses in the onshore tax jurisdictions resulting from the distribution of net financial items can be allocated to the offshore tax jurisdictions and deducted from regular income.
Only 50 percent of other losses in the onshore tax jurisdictions are permitted to be reallocated to the offshore tax jurisdictions as deductions in regular income.
Companies subject to special tax may, without time limitations, carry forward losses with the addition of interest. A corresponding rule also applies to unused uplift. The tax position can be transferred on realisation of the company or merger. Alternatively, disbursement of the tax value can be claimed from the State if the company ceases petroleum activities. The tax loss will thus be reclassified from deferred tax to current tax at the time the petroleum activity ceases, or is transferred to another company. Under the temporary tax rule encated in 2020, the value of tax losses incurred in 2020 and 2021 will be refunded from the state.
The company complies with the requirement to have an occupational pension scheme in accordance with the Norwegian law on required occupational pension ("lov om obligatorisk tjenestepensjon").
The company makes contributions to the pension plan for fulltime employees equal to 7 percent for salary up to 7.1 G and 25.1 percent between 7.1 and 12 G. The pension premiums are charged to expenses as they are incurred.
An early retirement scheme (AFP) has been introduced for all employees. The scheme is a multi-employer defined benefit plan, but is accounted for as a defined contribution pension, and premiums are expensed as incurred.
A provision is recognized when the company incurs a commitment (legal or constructive) as a result of a past event, it is probable that financial settlement will take place as a
result of this commitment, and the amount can be reliably calculated. Provisions are evaluated at each period end and are adjusted to reflect the best estimate.
An onerous contract is a contract in which the unavoidable costs of meeting the obligations under the contract exceed the economic benefits expected to be received under it. A provision for onerous contracts is measured at the present value of the lower of the expected cost of terminating the contract and the expected net cost of continuing with the contract.If the discounting effect is significant, provisions are discounted using a discount rate before tax that reflects the market's pricing of the time value and risk specifically associated with the commitment. As discounting unwinds, the book value of the provisions is increased in each period to reflect the change in time relative to the due date of the commitment. The effect of this increase is expensed as an accretion expense.
In accordance with the license terms and conditions for the licenses in which the company participates, the Norwegian State can require license owners to remove the installation in whole or in part when production ceases or the license period expires.
In the initial recognition of the decommissioning and removal obligations, the company provides for the net present value of future costs related to decommissioning and removal. A corresponding asset is capitalized as a tangible fixed asset and depreciated using the unit-of-production method. Changes in the time value (net present value) of the obligation related to decommissioning and removal accretion are charged to income as financial expenses and increase the balance-sheet liability related to future decommissioning and removal expenses. Changes in the best estimate for expenses related to decommissioning and removal are recognized in the Statement of financial position, except where it relates to licenses with no future production. The discount rate used in the calculation of the fair value of the decommissioning and removal obligation is the risk-free rate with the addition of a credit risk element.
Since its formation, the company has conducted its entire business in one consistent segment, defined as exploration for and production of petroleum in Norway. The company conducts its activities on the Norwegian Continental Shelf, and management monitors the company at this level. The financial information relating to geographical distribution and large customers is presented in note 3.
Earnings per share are calculated by dividing the net profit/ loss attributable to ordinary equity holders of the parent entity by the weighted average number of the total outstanding shares. Shares issued during the year are weighted in relation to the period in which they have been outstanding.
Except for in the event of a business combination, neither contingent liabilities nor contingent assets are recognized.
A contingent liability is a possible obligation that arises from past events and whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the entity; or a present obligation that arises from past events but is not recognized because it is not probable that an outflow of resources embodying economic benefits will be required to settle the obligation or the amount of the obligation cannot be measured with sufficient reliability.
Contingent liabilities are disclosed with the exception of contingent liabilities where the probability of the liability having to be settled is remote.
Contingent assets are possible asset that arises from past events and whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the entity. Information about such contingent assets is provided if inflow of economic benefits is probable.
The group has applied the following standards and amendment for the first time for their annual reporting period commencing 1 January 2021:
Interest Rate Benchmark Reform Phase 2 – amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16
As further described in note 27, the amendment listed above did not have any impact on the amounts recognized in prior periods and are not expected to significantly affect the current or future periods.
Certain new accounting standards and interpretations are issued, but not yet effective as of 31 December 2021. These standards are not expected to have a material impact on the group in the current or future reporting periods.
From 2021, the group presents cash flows related to payment of borrowing costs in the statement of cash flows as financing activities, while they prior to 2021 were presented as operational and investment activities. The reason behind the change is that borrowing costs are directly linked to the group's financing activities, and are thus deemed more relevant to include under financing activities. Comparative figures have been restated accordingly in line with IAS 8.
The following table shows the effects of the change in accounting policy:
| BREAKDOWN OF RESTATING IMPACT ON STATEMENT OF CASH FLOW (USD 1000) |
01.01–31.12 2020 |
|---|---|
| Net cash flow from operating activities | |
| Prior to restating | 1 857 053 |
| After restating | 2 011 353 |
| Change | 154 300 |
| Net cash flow from investment activities | |
| Prior to restating | -1 500 710 |
| After restating | -1 461 443 |
| Change | 39 267 |
| Net cash flow from financing activities | |
| Prior to restating | -74 219 |
| After restating | -119 348 |
| Change | -193 568 |
Impact on net change in cash and cash equivalents 0
Aker BP UK Limited was established as a subsidiary of Det norske oljeselskap AS during 2020. There were no activities in 2020. In Q1 2021, the company entered into an agreement with Eni UK to acquire a 50 percent non-operated interest in license P2511 on the UK continental shelf. During 2021 the main activity has been to acquire and interpret seismic in the area. License P2511 is located to the borderline of the Norwegian continental shelf. The key objective for the partnership between Eni UK and Aker BP UK is to explore the resource potential, based on the knowledge obtained in the Alvheim area.
The spending in 2021 in Aker BP UK Limited relates to exploration activity of USD 4.5 million, and note 6 provides a split on exploration activity for the parent company Aker BP ASA and Aker BP UK Limited. As this is the only difference between the parent and group figures, separate columns for parent and group has not been provided for other parts of the financial statements.
Aker BP ASA has three other subsidiaries which are not consolidated in the group accounts in 2021 due to materiality considerations:
Det norske oljeselskap AS, previously Marathon Oil Norge AS, was acquired by Aker BP in October 2014. All activity was transferred to Aker BP on 31 October 2014. During 2020, Aker BP UK Limited (see above) was established as a subsidiary of Det norske oljeselskap AS. Except for the subsidiary, the only asset in this company is cash equivalents reflecting the share capital amounting to USD 1.0 million.
The sole purpose of Alvheim AS is to act as legal owner of MST Alvheim, the floating production facility which is used to produce oil and gas from the Alvheim fields. The costs of and benefits from operating the MST Alvheim will be carried by the partners in the Alvheim field. Hence, Alvheim AS only has the formal ownership rather than the actual value of the production facilities. Aker BP has a 65 percent share in Alvheim AS, which corresponds to the ownership in the Alvheim field. There were no activities in 2021.
Sandvika Fjellstue AS owns a conference centre used by Aker BP, located in Sandvika in Verdal.
The group's business is entirely related to exploration for and production of petroleum on, or to the borderline of, the Norwegian continental shelf. The group's activities are considered to have a homogeneous risk and return profile before tax, and the business is located in the geographical area Norway, except for one exploration license in UK. The group operates within a single operating segment which matches the internal reporting to the company's executive management. In 2021 the group had sales transactions with 2 customers, which represented more than 10% of total sales, and accounted for USD 4 281 million (BP Oil International Limited) and USD 1 056 (BP Gas Marketing Limited). In 2020 the company had sales transactions with 1 customer, BP Oil International Ltd, which represented more than 10% of total sales, and accounted for USD 2 547 million
| Group & Parent | |||||
|---|---|---|---|---|---|
| Breakdown of petroleum revenues (USD 1 000) | 2021 | 2020 | |||
| Sales of liquids | 4 392 625 | 2 581 776 | |||
| Sales of gas | 1 233 314 | 270 404 | |||
| Tariff income | 14 051 | 15 973 | |||
| Total petroleum sales | 5 639 990 | 2 868 153 | |||
| Sales of liquids (boe 1 000) (unaudited) | 63 447 | 64 549 | |||
| Sales of gas (boe 1 000) (unaudited) | 13 935 | 12 384 | |||
| Other income (USD 1 000) | |||||
| Realized gain/loss (-) on oil derivatives | -19 362 | 55 328 | |||
| Unrealized gain/loss (-) on oil derivatives | -5 449 | -1 734 | |||
| Gain on license transactions | - | 5 417 | |||
| Other income1) | 53 568 | 52 099 | |||
| Total other operating income | 28 757 | 111 110 |
1) The amounts include insurance settlements, in addition to partner coverage of RoU assets recognized on gross basis in the balance sheet and used in operated activity.
Refer to note 22 and 27 for further details regarding commodity derivatives.
| Group & Parent | ||
|---|---|---|
| Production costs (USD 1 000) | 2021 | 2020 |
| Cost of operations | 472 791 | 435 366 |
| Shipping and handling | 179 579 | 168 824 |
| Environmental taxes | 47 637 | 35 922 |
| Production cost based on produced volumes | 700 007 | 640 111 |
| Adjustment for over/underlift (-) | 45 306 | -12 137 |
| Production cost based on sold volumes | 745 313 | 627 975 |
| Total produced volumes (boe 1 000) | 76 439 | 77 101 |
| Production cost per boe produced (USD/boe) | 9.2 | 8.3 |
| Group & Parent | ||
|---|---|---|
| Breakdown of exploration expenses (USD 1 000) | 2021 | 2020 |
| Seismic1) | 23 138 | 25 522 |
| Area fees | 18 891 | 15 272 |
| Field evaluation | 176 969 | 44 718 |
| Dry well expenses | 98 827 | 56 626 |
| Other exploration expenses2) | 35 208 | 31 961 |
| Total exploration expenses | 353 034 | 174 099 |
1) USD 3.7 million related to Aker BP UK Limited
2) USD 0.8 million related to Aker BP UK Limited
| Group & Parent | |||
|---|---|---|---|
| Breakdown of payroll expenses (USD 1 000) | 2021 | 2020 | |
| Payroll expenses | 328 324 | 265 874 | |
| Pension | 31 197 | 26 748 | |
| Social security tax | 51 090 | 41 505 | |
| Other personnel costs | 7 039 | 5 348 | |
| Total payroll expenses | 417 649 | 339 475 |
The figures above are based on taxable income for the employees. The increase between the years is mainly caused by employee bonuses relating to 1.5 years (2020 and half of 2021) was paid in 2021, while 2020 figures only include 0.5 year of bonus payment (half of 2019).
The company has an annual share purchase program for all employees, including senior executives. The shares in the program are offered at a 25 percent discount (20 percent in 2020) and are subject to a three-year lock-up during which employees are not allowed to sell the shares. In connection with the share purchase program, all employees are also offered an interest free loan of 60 percent of the basic amount in the National Insurance scheme ("G"), to be repaid within one year. In total, employees subscribed for USD 12.6 million in 2021, compared to USD 11.9 million in 2020.
| Group & Parent | ||||
|---|---|---|---|---|
| Number of full time equivalents employed during the year | 2021 | 2020 | ||
| Europe | 1 773 | 1 745 | ||
| Total | 1 773 | 1 745 |
| Remuneration of senior executives in 2021* | Payments in | Total number | Owning | |||||
|---|---|---|---|---|---|---|---|---|
| (USD 1 000) | Salary | Bonus** | kind | Other | Total remuneration | Pension costs | of shares*** | interest |
| Karl Johnny Hersvik (Chief Executive Officer) | 929 | 651 | 121 | 19 | 1 719 | 24 | 10 355 | 0.0 % |
| Øyvind Bratsberg (Special Advisor)1) | 344 | 91 | 1 | 780 | 1 216 | 12 | N/A | N/A |
| Per Harald Kongelf (SVP Improvement) | 423 | 171 | 3 | - | 598 | 24 | 5 546 | 0.0 % |
| Tommy Sigmundstad (SVP D&W) | 380 | 154 | 12 | 7 | 553 | 24 | 10 038 | 0.0 % |
| Evy Glørstad (SVP Exploration & Reservoir Development) | 392 | 160 | 7 | - | 559 | 25 | 9 423 | 0.0 % |
| Lene Landøy (SVP Strategy and Business Development)2) | 340 | 451 | 5 | 6 | 802 | 16 | N/A | N/A |
| David Torvik Tønne (Chief Financial Officer) | 384 | 154 | 6 | 3 | 547 | 23 | 16 869 | 0.0 % |
| Marit Blaasmo (SVP HSSEQ) | 287 | 111 | 3 | - | 401 | 24 | 4 688 | 0.0 % |
| Knut Arne Kristian Sandvik (SVP projects) | 377 | 224 | 7 | - | 608 | 25 | 4 078 | 0.0 % |
| Ine Dolve (SVP Operations & Asset Development) | 369 | 130 | 5 | 6 | 510 | 25 | 5 534 | 0.0 % |
| Lars Høier (SVP Operations & Asset Development - NOAKA | 359 | 138 | 4 | 1 | 503 | 24 | 6 671 | 0.0 % |
| Jan Rosnes (SVP Strategy and Business Development)3) | 209 | 49 | 4 | - | 263 | 24 | 408 | 0.0 % |
| Total remuneration of senior executives in 2021 | 4 793 | 2 487 | 177 | 822 | 8 279 | 269 | 73 610 | 0.0 % |
1) Special Advisor until 30.06.2021. Other includes payments arising from a mutual agreement relating to Bratsberg leaving the company.
2) SVP Strategy and Business Development until 31.08.2021. Bonus includes accrued LTIP payment earned from 2019 to 2021 relating to Landøy leaving the company.
3) SVP Strategy and Business Development since 01.09.2021
* All remuneration to senior executives is paid in NOK and converted to USD using a yearly average USD/NOK-rate of 8.5991. For executives who been in the Executive Management Team only parts of the year, the figures include payroll for the full year.
** Numbers represent actual ordinary bonus earned in 2021, excluding LTIP (see description below).
*** These shares have been purchased by the individuals and are not part of the remuneration. The numbers include shares held in companies where the senior executives have controlling interest.
| Remuneration of senior executives in 2020* | Payments in | Total number | Owning | |||||
|---|---|---|---|---|---|---|---|---|
| (USD 1 000) | Salary | Bonus** | kind | Other | Total remuneration | Pension costs | of shares*** | interest |
| Karl Johnny Hersvik (Chief Executive Officer)1) | 830 | 521 | 133 | 227 | 1 712 | 19 | 10 355 | 0.0 % |
| Øyvind Bratsberg (Special Advisor) | 406 | 156 | 2 | 3 | 567 | 19 | 54 802 | 0.0 % |
| Per Harald Kongelf (SVP Improvement) | 401 | 155 | 2 | 1 | 559 | 20 | 5 546 | 0.0 % |
| Tommy Sigmundstad (SVP D&W) | 356 | 139 | 4 | 20 | 519 | 19 | 9 418 | 0.0 % |
| Ole Johan Molvig (SVP Reservoir Development)2) | 356 | 139 | 1 | - | 496 | 19 | 14 874 | 0.0 % |
| Evy Glørstad (SVP Exploration & Reservoir Development)3) | 347 | 143 | 3 | 4 | 497 | 20 | 5 866 | 0.0 % |
| Lene Landøy (SVP Strategy and Business Development) | 327 | 130 | 6 | - | 462 | 19 | 10 122 | 0.0 % |
| David Torvik Tønne (Chief Financial Officer) | 346 | 139 | 5 | - | 489 | 19 | 13 900 | 0.0 % |
| Marit Blaasmo (SVP HSSEQ) | 254 | 103 | 2 | - | 359 | 20 | 2 153 | 0.0 % |
| Kjetel Rokseth Digre (Chief Operating Officer) 4) | 308 | 93 | 1 | - | 403 | 13 | 3 002 | 0.0 % |
| Knut Arne Kristian Sandvik (SVP projects) | 305 | 205 | 7 | 6 | 523 | 20 | 2 577 | 0.0 % |
| Ine Dolve (SVP Operations & Asset Development) 5) | 284 | 91 | 5 | 10 | 390 | 20 | 4 033 | 0.0 % |
| Lars Høier (SVP Operations & Asset Development - NOAKA)6) | 278 | 89 | 1 | 5 | 373 | 19 | 5 675 | 0.0 % |
| Total remuneration of senior executives in 2020 | 4 798 | 2 101 | 173 | 277 | 7 349 | 246 | 142 323 | 0.0 % |
1) Other includes final settlement of previous LTIP scheme
2) SVP Reservoir Development until 31.08.2020
3) SVP Exploration until 31.08.2020
4) Chief Operating Officer until 31.07.2020
5) SVP Operations & Asset Development since 01.08.2020
6) SVP Operations & Asset Development - NOAKA since 01.09.2020
* All remuneration to senior executives is paid in NOK and converted to USD using a yearly average USD/NOK-rate of 9.4004. For executives who have been in the Executive Management Team only parts of the year, the figures include payroll for the full year.
** Numbers represent actual ordinary bonus earned in 2020, excluding LTIP (see description below).
*** These shares have been purchased by the individuals and are not part of the remuneration. The numbers include shares held in companies where the senior executives have controlling interest.
| Fees in 2021* | ||||
|---|---|---|---|---|
| Fee | Total number | Owning | ||
| Name | Comments | (USD 1 000) | of shares | interest |
| Øyvind Eriksen | Chairman of the Board from 11.03.2016. Chair of the Organizational Development and Compensation committee. | 104 | - | - |
| Anne Marie Cannon | Deputy Chair from 17.04.2013. Member of the Audit & Risk committee and Organizational Development and Compensation committee. | 71 | 12 078 | 0.0 % |
| Kjell Inge Røkke | Board member from 17.04.2013. | 46 | - | - |
| Murray Auchincloss | Board member from 16.04.2020 | - | - | - |
| Trond Brandsrud | Board member from 11.03.2016. Chairman of the Audit & Risk committee from 28.04.2016. | 69 | - | - |
| Kate Thomson | Board member from 30.09.2016. Member of the Audit & Risk committee from 04.10.2016. | - | - | - |
| Paula Doyle | Board member from 15.04.2021. | 34 | - | - |
| Terje Solheim | Employee rep. from 20.03.2014. Member of the Organizational Development and Compensation committee. | 26 | 637 | 0.0 % |
| Ingard Haugeberg | Employee representative from 30.08.2018. | 23 | 948 | 0.0 % |
| Hilde K.Brevik | Deputy employee representative from 30.08.2018. | 13 | 1 201 | 0.0 % |
| Tore Vik | Employee representative from 14.07.2021. | 11 | 3 594 | 0.0 % |
| Sarah Alexandra Berg Deputy employee representative from 07.07.2021. | 2 | 1 949 | 0.0 % | |
| Rune K. Fauskanger | Deputy employee representative from 07.07.2021. | 2 | 6 649 | 0.0 % |
| Thomas Husvæg | Deputy employee representative from 07.07.2021. | 2 | 132 | 0.0 % |
| Ørjan K.Brakstad | Deputy employee representative from 07.07.2021. | 2 | 423 | 0.0 % |
| Svein Oskar Stoknes Chair of the Nomination committee from 16.04.2020. | - | - | - | |
| Ingebret Hisdal | Member of the Nomination committee from 16.04.2020. | 7 | - | - |
| Donna Riley | Member of the Nomination committee from 16.04.2020. | - | - | - |
| Member until | ||||
| Gro Kielland | Board member from 20.03.2014 to 15.04.2021. | 19 | N/A | N/A |
| Ørjan Holstad | Employee representative from 01.11.2017 to 07.07.2021. | 13 | N/A | N/A |
| Anette Hoel Helgesen Employee representative from 30.08.2018 to 07.07.2021. | 13 | N/A | N/A | |
| Nina Aas | Deputy employee representative from 30.08.2018 to 07.07.2021. | 2 | N/A | N/A |
| Oddbjørn Aune | Deputy employee representative from 30.08.2018 to 07.07.2021. | 2 | N/A | N/A |
| Total | 463 | 27 611 | 0.0 % |
* Fee to board members are paid in NOK and converted to USD using a yearly average USD/NOK-rate of 8.5991.
| Fee | Total number | Owning | ||
|---|---|---|---|---|
| Name | Comments | (USD 1 000) | of shares | interest |
| Øyvind Eriksen | Chairman of the Board from 11.03.2016. Chair of the Organizational Development and Compensation committee. | 96 | - | - |
| Anne Marie Cannon | Deputy Chair from 17.04.2013. Member of the Audit & Risk committee. | 59 | 12 078 | 0.0 % |
| Kjell Inge Røkke | Board member from 17.04.2013. | 44 | - | - |
| Murray Auchincloss | Board member from 16.04.2020 | - | - | - |
| Trond Brandsrud | Board member from 11.03.2016. Chairman of the Audit & Risk committee from 28.04.2016. | 62 | - | - |
| Kate Thomson | Board member from 30.09.2016. Member of the Audit & Risk committee from 04.10.2016. | - | - | - |
| Gro Kielland | Board member from 20.03.2014. Member of the Organizational Development and Compensation committee. | 53 | 1 750 | 0.0 % |
| Terje Solheim | Employee rep. from 20.03.2014. Member of the Organizational Development and Compensation committee. | 24 | 1 987 | 0.0 % |
| Ørjan Holstad | Employee representative from 01.11.2017. | 21 | 4 384 | 0.0 % |
| Ingard Haugeberg | Employee representative from 30.08.2018. | 21 | 1 510 | 0.0 % |
| Anette Hoel Helgesen Employee representative from 30.08.2018. | 21 | 1 134 | 0.0 % | |
| Nina Aas | Deputy employee representative from 30.08.2018. | 3 | 3 892 | 0.0 % |
| Oddbjørn Aune | Deputy employee representative from 30.08.2018. | 3 | 5 796 | 0.0 % |
| Hilde K.Brevik | Deputy employee representative from 30.08.2018. | 3 | 721 | 0.0 % |
| Svein Oskar Stoknes Chair of the Nomination committee from 16.04.2020. | 4 | - | - | |
| Ingebret Hisdal | Member of the Nomination committee from 16.04.2020. | 4 | - | - |
| Donna Riley | Member of the Nomination committee from 16.04.2020. | - | - | - |
| Member until 16.04.2020 | ||||
| Bernard Looney | Board member from 30.09.2016. to 16.04.2020 | - | - | - |
| Hilde Myberg | Member of the Nomination committee from 2012 to 16.04.2020 | 4 | - | - |
| Arild Støren Frick | Chairman of the Nomination committee from 16.04.2015 to 16.04.2020 | 4 | ||
| Total | 424 | 33 252 | 0.0 % |
* Fee to board members are paid in NOK and converted to USD using a yearly average USD/NOK-rate of 9.4004.
In 2021, the companys remuneration policy has been in accordance with the guidelines described in the Board of Directors Report for 2020 and submitted to the annual general meeting for an advisory vote in April 2021.
The Board makes guidelines for executive remuneration, including the CEO's remuneration and other terms and conditions of employment. These guidelines set out the main principles applied in determining the salary and other remuneration of executive personnel and are addressed as a separate item at the General Meeting.
Senior executives receive a basic salary, adjusted annually. The company's senior executives participate in the general arrangements applicable to all the company's employees as regards bonus programme (see below), pension plans and other payments in kind such as free internet connection at home and subsidized fitness centre fees. In special cases, the company may offer other benefits in order to recruit personnel, including to compensate for bonus rights earned in previous employment.
The bonus for all employees, including the CEO and EMT, is determined by the company's performance on a pre-defined set of key performance indicators (KPIs) and Company Priorities, which are important improvement initiatives or activities with clear deliverables that are critical for the company's future success. For 2021, the KPIs were as follows:
| KPI (unaudited) | Execute | Improve | Actual |
|---|---|---|---|
| Safety (SIF/1 mill hrs) | 0.45 | 0.40 | - |
| Production (mboepd) | 215.0 | 220.0 | 209.4 |
| Production Cost (USD/boe) | 8.5 | 8.0 | 9.2 |
| Net reserve additions (mmboe) | 44 | 75 | 36 |
| Value creation (change in Risked NPV) | 11% | 13% | 6.3 % |
| Relatively Shareholder Return | 5% | 10% | -1.8% |
| CO2 Intensity (kg CO2/boe) - operated fields | <5 | <4.5 | 4.8 |
Company Priorities are either important improvement initiatives or activities with clear deliverables that are critical for the company's future success. Below is a list of the priorities for 2021:
• Deliver Ærfugl Ph. II first gas in December 2021 at planned quality and cost
• Complete installation of Hod NUI by Aug 26th and ensure readiness to start drilling by Oct 17th at planned quality and cost
• Develop and execute portfolio procurement strategy aimed at securing fit for purpose capacity in a potentially tight NCS supplier market
• Scale learnings from 2020 HSSEQ incident trends on Ula and Valhall to all assets
• Complete proposed foundation for dimensioning of Offshore Org. by 31.03.2021, and completed implementation of offshore standardized organization by 30.06.2021
• Maximize value of major improvement initiatives aimed at D&W costs and processes
• Move 100 offshore vendor days related to crane inspections and work on the process control system (PCS) onshore by implementing remote assistance/access/work
• Build and operationalize a subsurface data factory delivering quality subsurface data products by end June 2021
• Deliver valuable energy efficiency projects to reduce environmental footprint by 10 000 tonnes CO2 per annum
• Define strategic, timely and efficient governance mechanisms and tool for strategic workforce planning
These KPIs and company priorities are each weighted 50 percent when estimating the bonus outcome. The final bonus outcome, following the formulaic assessment of performance relative to targets is specifically reserved as a matter for the CEO and the Compensation & Organisational Committee. Accordingly, the committee may exercise its discretion to adjust the outcome upwards or downwards. The CEO has maximum bonus potential corresponding to 100 percent of his base salary. For other members of EMT, the limit is 60 percent. The maximum bonus for employees outside the EMT varies from 10 percent to 30 percent based on internal job grade.
For 2021, bonus for the first half was paid in September 2021, while the bonus for the second half of the year will be paid in February 2022. The bonus was set to 70% of maximum potential based on approximately 35% performance on the KPI's, 95% performance on the priorities and a discretionary adjustment.
Certain members of the EMT participate in a five-year incentive program (LTIP) started in January 2019, through December 2023, linked to the relative performance of the Aker BP share price versus a benchmark index consisting of the average of the Oslo Energy Index and the Stoxx 600 Europe Oil & Gas index (each weighted 50 percent). The incentive program payment is calculated as a linear function of market outperformance, where an outperformance of 30 percent or more will result in a payment of the maximum cap. The market outperformance as of year end 2021 was 33%. The maximum total payment is capped at 200 percent of the executive manager's annual base salary. The CEO incentive program has the same mechanics and start/end date and is capped at NOK 30 million.
The pension scheme continues to be a defined contribution plan capped at twelve times the National Insurance scheme basic amount (12G) for all employees including the executive management. The CEO and members of the EMT have 6 months mutual notice period. For all other employees, the notice period is 3 months.
Adjustment of the CEO's base salary is decided by the Board. Adjustment of the base salaries for other senior executives is decided by the CEO within the wage settlement framework adopted by the Board.
| Group & Parent | ||||
|---|---|---|---|---|
| (USD 1 000) | 2021 | 2020 | ||
| Fees for statutory audit services - KPMG (excluding VAT) | 432 | 452 | ||
| Fees for other attestations - KPMG (excluding VAT) | 124 | 217 | ||
| Total auditor's fees | 555 | 669 |
| Group & Parent | |||
|---|---|---|---|
| (USD 1 000) | 2021 | 2020 | |
| Total interest income | 2 481 | 3 763 | |
| Realized gains on derivatives | 27 392 | 16 821 | |
| Change in fair value of derivatives | 74 537 | ||
| Net currency gains | 88 779 | 79 507 | |
| Total other financial income | 116 171 | 170 865 | |
| Interest expenses | 145 651 | 184 501 | |
| Interest on lease debt | 11 558 | 16 629 | |
| Capitalized interest cost, development projects | -40 136 | -39 267 | |
| Amortized loan costs | 22 460 | 19 813 | |
| Total interest expenses | 139 533 | 181 677 | |
| Realised loss on derivatives | 23 249 | 125 791 | |
| Change in fair value of derivatives | 44 565 | - | |
| Accretion expenses | 113 748 | 116 947 | |
| Other financial expenses | 39 274 | 19 314 | |
| Total other financial expenses | 220 836 | 262 052 | |
| Net financial items | -241 718 | -269 101 |
The rate (weighted average interest rate) used to determine the amount of borrowing cost eligible for capitalisation in 2021 is 4.46 percent. The corresponding rate for 2020 was 5.30 percent.
| Group & Parent | ||
|---|---|---|
| Tax for the period (USD 1 000) | 2021 | 2020 |
| Current year tax payable/receivable | 1 526 236 | -333 104 |
| Prior period adjustments to current tax | 15 093 | 7 275 |
| Current tax expense (+)/income (-) | 1 541 329 | -325 829 |
| Change in current year deferred tax | 684 723 | 448 393 |
| Prior period adjustments to deferred tax | -3 971 | -3 595 |
| Deferred tax expense (+)/ income (-) | 680 752 | 444 799 |
| Tax expense (+)/income (-) | 2 222 080 | 118 970 |
| Effective tax rate in % | 72% | 73 % |
| Group & Parent | |||
|---|---|---|---|
| Reconciliation of tax expense (USD 1 000) | Tax rate | 2021 | 2020 |
| 78% tax rate on profit/loss before tax | 78% | 2 396 772 | 127 674 |
| Tax effect of uplift | 56% | -270 454 | -268 564 |
| Permanent differences on impairment | 78% | -36 862 | 169 670 |
| Foreign currency translation of monetary items other than USD | 78% | -68 575 | -62 040 |
| Foreign currency translation of monetary items other than NOK | 78% | 16 508 | 129 042 |
| Tax effect of financial and other 22% items | 56% | 114 038 | 37 761 |
| Currency movements of tax balances1) | 78% | 43 332 | -30 321 |
| Other permanent differences, prior period adjustments and change in estimate | 78% | 27 321 | 15 748 |
| of uncertain tax positions | |||
| Tax expense (+)/income (-) | 2 222 080 | 118 970 |
1) Tax balances are in NOK and converted to USD using the period end currency rate. When the NOK weakens against USD, the tax rate increases as there is less remaining tax depreciation measured in USD.
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.
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 & Parent | |||
|---|---|---|---|
| Breakdown of tax effect of temporary differences (USD 1 000) | 2021 | 2020 | |
| Tangible fixed assets | -4 622 963 | -3 686 831 | |
| Capitalized exploration cost | -200 098 | -407 099 | |
| Other intangible assets | -735 936 | -856 493 | |
| Abandonment provision | 2 150 633 | 2 186 518 | |
| Lease debt | 106 246 | 168 293 | |
| Financial instruments | 3 850 | -7 153 | |
| Other provisions | -24 945 | -39 696 | |
| Net deferred tax liability (-)/deferred tax asset (+) | -3 323 213 | -2 642 461 |
| Group & Parent | ||||
|---|---|---|---|---|
| Deferred tax liability (-)/asset (+) (USD 1 000) | 2021 | 2020 | ||
| Deferred tax liability/asset at beginning of period | -2 642 461 | -2 235 357 | ||
| Change in current year deferred tax | -684 723 | -448 393 | ||
| Deferred tax related to acquisitions/sales | - | 37 727 | ||
| Prior period adjustments | 3 971 | 3 595 | ||
| Deferred tax charged to OCI and equity | - | -33 | ||
| Net deferred tax liability (-)/deferred tax asset (+) | -3 323 213 | -2 642 461 |
| Group & Parent | ||
|---|---|---|
| Calculated tax payable (-)/ tax receivable (+) (USD 1 000) | 2021 | 2020 |
| Tax payable/receivable at beginning of period | -163 352 | -361 157 |
| Current year tax payable/receivable | -1 526 236 | 333 104 |
| Tax payable/receivable related to acquisitions/sales | - | -3 855 |
| Net tax payment/tax refund | 223 166 | -180 922 |
| Prior period adjustments and change in estimate of uncertain tax positions | -57 165 | -10 425 |
| Currency movements of tax payable/receivable | 26 297 | 59 903 |
| Net tax payable (-)/receivable (+) | -1 497 291 | -163 352 |
Earnings per share is calculated by dividing the year's profit attributable to ordinary equity holders of the parent entity, which was USD 851 million (USD 45 million in 2020) by the year's weighted average number of outstanding ordinary shares, which was 359.6 million (359.8 million in 2020). There are no option schemes or convertible bonds in the company, meaning there is no difference between the ordinary and diluted earnings per share.
| Group & Parent | ||||
|---|---|---|---|---|
| (USD 1 000) | 2021 | 2020 | ||
| Profit for the year attributable to ordinary equity holders of the parent entity | 850 704 | 44 715 | ||
| The year's average number of ordinary shares (in thousands) | 359 643 | 359 808 | ||
| Earnings per share in USD | 2.37 | 0.12 |
| Property, plant and equipment | Production | Fixtures and | ||
|---|---|---|---|---|
| Assets under | facilities including | fittings, office | ||
| (USD 1 000) | development | 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 | 586 301 | 739 166 | 21 954 | 1 347 421 |
| Disposals/retirement | - | 675 733 | -69 | 675 664 |
| Reclassification | -747 913 | 757 420 | 48 867 | 58 375 |
| Acquisition cost 31.12.2020 | 1 088 754 | 9 886 875 | 241 304 | 11 216 932 |
| Accumulated depreciation and impairments 31.12.2019 | - | 3 378 065 | 85 459 | 3 463 524 |
| Depreciation | - | 963 619 | 40 776 | 1 004 395 |
| Impairment/reversal (-) | - | 67 099 | - | 67 099 |
| Disposals/retirement depreciation | - | -584 292 | 69 | -584 223 |
| Accumulated depreciation and impairments 31.12.2020 | - | 3 824 491 | 126 305 | 3 950 795 |
| Book value 31.12.2020 | 1 088 754 | 6 062 384 | 114 999 | 7 266 137 |
| Acquisition cost 31.12.2020 | 1 088 754 | 9 886 875 | 241 304 | 11 216 932 |
| Additions | 814 409 | 620 779 | 12 750 | 1 447 938 |
| Disposals/retirement | - | - | - | - |
| Reclassification | -107 727 | 428 436 | 2 395 | 323 103 |
| Acquisition cost 31.12.2021 | 1 795 436 | 10 936 089 | 256 449 | 12 987 974 |
| Accumulated depreciation and impairments 31.12.2020 | - | 3 824 491 | 126 305 | 3 950 795 |
| Depreciation | - | 832 768 | 43 440 | 876 207 |
| Impairment/reversal (-) | - | 184 664 | - | 184 664 |
| Disposals/retirement depreciation | - | - | - | - |
| Accumulated depreciation and impairments 31.12.2021 | - | 4 841 922 | 169 744 | 5 011 666 |
| Book value 31.12.2021 | 1 795 436 | 6 094 167 | 86 705 | 7 976 308 |
Capitalized exploration expenditures are reclassified to "Assets under development" when the field enters into the development phase. If development plans are subsequently reevaluated, the associated costs remain in assets under development and are not reclassified back to exploration assets. Assets under development are reclassified to "Production facilities" from the start of production. Production facilities, including wells, are depreciated in accordance with the unit-of-production method. Office machinery, fixtures and fittings etc. are depreciated using the straight-line method over their useful life, i.e. 3 - 5 years. Removal and decommissioning costs are included as production facilities or assets under development.
See note 13 for information regarding impairment charges.
| (USD 1 000) | Drilling Rigs | Vessels and 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 | - | - | 16 834 | - | 16 834 |
| Allocated to abandonment activity | -11 236 | -1 199 | - | - | -12 435 |
| Disposals/retirement | -16 197 | -5 920 | - | - | -22 117 |
| Reclassification | -31 461 | -2 972 | - | - | -34 432 |
| Acquisition cost 31.12.2020 | 47 963 | 62 016 | 46 427 | 2 303 | 158 709 |
| Accumulated depreciation and impairments 31.12.2019 | 5 369 | 3 166 | 7 820 | 177 | 16 531 |
| Depreciation | 9 265 | 2 827 | 7 082 | 177 | 19 350 |
| Impairment/reversal (-) | - | - | - | - | - |
| Disposals/retirement depreciation | -8 535 | -1 373 | - | - | -9 907 |
| Accumulated depreciation and impairments 31.12.2020 | 6 099 | 4 620 | 14 902 | 353 | 25 974 |
| Book value 31.12.2020 | 41 864 | 57 395 | 31 525 | 1 950 | 132 735 |
| Acquisition cost 31.12.2020 | 47 963 | 62 016 | 46 427 | 2 303 | 158 709 |
| Additions | - | - | 5 989 | - | 5 989 |
| Allocated to abandonment activity1) | -11 518 | -1 943 | - | - | -13 461 |
| Disposals/retirement | - | - | - | - | - |
| Reclassification2) | -18 034 | -2 636 | - | - | -20 669 |
| Acquisition cost 31.12.2021 | 18 412 | 57 436 | 52 416 | 2 303 | 130 567 |
| Accumulated depreciation and impairments 31.12.2020 | 6 099 | 4 620 | 14 902 | 353 | 25 974 |
| Depreciation | - | 2 076 | 8 164 | 177 | 10 416 |
| Impairment/reversal (-) | - | - | - | - | - |
| Disposals/retirement depreciation | - | - | - | - | - |
| Accumulated depreciation and impairments 31.12.2021 | 6 099 | 6 696 | 23 066 | 530 | 36 390 |
| Book value 31.12.2021 | 12 313 | 50 740 | 29 350 | 1 774 | 94 177 |
1) This represents the share of right-of-use assets used in abandonment activity, and thus booked against the abandonment provision.
2) 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 | - | - | - | 127 283 | - | |
| Disposals/expensed dry wells | 27 448 | - | 27 448 | 56 626 | 12 391 | |
| Reclassification | - | - | - | -23 942 | - | |
| Acquisition cost 31.12.2020 | 2 368 985 | 7 501 | 2 376 486 | 668 029 | 2 726 583 | |
| Accumulated depreciation and impairments 31.12.2019 | 480 465 | 7 501 | 487 966 | - | 1 026 165 | |
| Depreciation | 98 073 | - | 98 073 | - | - | |
| Impairment | 294 549 | - | 294 549 | 146 107 | 65 373 | |
| Retirement/transfer depreciations | -25 413 | - | -25 413 | - | -12 391 | |
| Accumulated depreciation and impairments 31.12.2020 | 847 674 | 7 501 | 855 175 | 146 107 | 1 079 146 | |
| Book value 31.12.2020 | 1 521 311 | - | 1 521 311 | 521 922 | 1 647 436 | |
| Acquisition cost 31.12.2020 | 2 368 985 | 7 501 | 2 376 486 | 668 029 | 2 726 583 | |
| Additions | - | 177 464 | - | |||
| Disposals/expensed dry wells | - | 7 501 | 7 501 | 98 827 | - | |
| Reclassification | - | - | - | -302 434 | - | |
| Acquisition cost 31.12.2021 | 2 368 985 | - | 2 368 985 | 444 232 | 2 726 583 | |
| Accumulated depreciation and impairments 31.12.2020 | 847 674 | 7 501 | 855 175 | 146 107 | 1 079 146 | |
| Depreciation | 77 459 | - | 77 459 | - | - | |
| Impairment/reversal (-) | 36 301 | - | 36 301 | 41 589 | - | |
| Disposals/retirement depreciation | - | -7 501 | -7 501 | - | - | |
| Accumulated depreciation and impairments 31.12.2021 | 961 434 | - | 961 434 | 187 696 | 1 079 146 | |
| Book value 31.12.2021 | 1 407 551 | - | 1 407 551 | 256 535 | 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 & Parent | ||
|---|---|---|
| Depreciation in the Income statement (USD 1 000) | 2021 | 2020 |
| Depreciation of tangible fixed assets | 876 207 | 1 004 395 |
| Depreciation of right-of-use assets | 10 416 | 19 350 |
| Depreciation of intangible assets | 77 459 | 98 073 |
| Total depreciation in the Income statement | 964 083 | 1 121 818 |
| Impairment in the Income statement (USD 1 000) | ||
| Impairment/reversal of tangible fixed assets | 184 664 | 67 099 |
| Impairment/reversal of other intangible assets | 36 301 | 294 549 |
| Impairment/reversal of capitalized exploration expenditures | 41 589 | 146 107 |
| Impairment of goodwill | - | 65 373 |
| Total impairment in the Income statement | 262 554 | 573 128 |
See note 13 for information regarding impairment charges.
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 2021, 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 2021 has been performed in accordance with the fair value method (level 3 in fair value hierarchy) and based on discounted cash flows. The expected future cash flow is discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money, and the specific risk related to the asset. The discount rate is derived from the weighted average cost of capital (WACC) for a market participant. Cash flows are projected for the estimated lifetime of the fields, which may exceed periods greater than five years.
For producing licenses and licenses in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Below is an overview of the key assumptions applied for impairment testing purposes as of 31 December 2021.
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 2022 to the end of 2024. From 2025, the oil and gas prices are based on the company's long-term price assumptions. Long-term oil price assumption is unchanged from year-end 2020.
The nominal oil prices applied in the impairment test are as follows:
| Year | USD/BOE |
|---|---|
| 2022 | 75.8 |
| 2023 | 71.0 |
| 2024 | 67.9 |
| From 2025 (in real 2021 terms) | 65.0 |
The nominal gas prices applied in impairment test are as follows:
| Year | GBP/therm |
|---|---|
| 2022 | 1.64 |
| 2023 | 1.03 |
| 2024 | 0.66 |
| From 2025 (in real 2021 terms) | 0.48 |
Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable remaining reserves. For more information about the determination of the reserves, reference is made to note 1, section 1.3, and to note 30.
Future capex, opex and abandonment cost are calculated based on the expected production profiles and the best estimate of the related cost.
The discount rate is derived from the company's weighted average cost of capital ("WACC"). The capital structure considered in the WACC calculation is derived from the capital structures of an identified peer group and market participants with consideration given to optimal structures. The cost of equity is derived from the expected return on investment by the company's investors. The cost of debt is based on the interest-bearing borrowings on debt specific to the assets acquired. The beta factors are evaluated annually based on publicly available market data about the identified peer group.
The post tax nominal discount rate used in Q4 is 7.6 percent. This represents a change from 8.1 percent applied in previous quarters in 2021 and year end 2020.
| Year USD/NOK |
|
|---|---|
| 2022 | 8.87 |
| 2023 | 8.92 |
| 2024 | 8.95 |
| From 2025 | 8.00 |
Long term currency rate is unchanged from year end 2020.
The long-term inflation rate is assumed to be 2.0 percent, which is the same as applied at year-end 2020.
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 the impairment test performed, carrying value is adjusted by the remaining part of deferred tax from which the technical goodwill arose, to avoid an immediate impairment of all technical goodwill. When deferred tax liabilities from the acquisitions decreases as a result of depreciation, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable.
Below is an overview of the impairment charge and the carrying value per cash generating unit where impairment has been recognized in 2021:
| Cash-generating unit (USD 1 000) | Ula/Tambar | Ivar Aasen1) |
|---|---|---|
| Net carrying value | 761 641 | 840 894 |
| Recoverable amount | 398 753 | 1 034 840 |
| Impairment/reversal (-) | 362 888 | -90 928 |
| Allocated as follows: | ||
| Technical goodwill | - | - |
| Other intangible assets/license rights | 89 695 | -2 652 |
| Tangible fixed assets | 273 193 | -88 275 |
1) Reversal of impairment on Ivar Aasen is capped at maximun available reversal amount adjusted for depreciation.
The main reasons for the Ula impairment charge are the effect of updated cost and production profiles offset by the increase in short-term oil and gas prices. The main reason for the Ivar Aasen impairment reversal is the increase in short-term oil and gas prices.
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 Valhall.
| Change in impairment after | |||
|---|---|---|---|
| Assumption (USD 1 000) | Change | Increase in assumption | Decrease in assumption |
| Oil and gas price forward period | +/- 50 % | -231 316 | 613 846 |
| Oil and gas price long-term | +/- 20 % | -124 607 | 145 421 |
| Production profile (reserves) | +/- 5 % | -55 798 | 55 798 |
| Discount rate | +/- 1 % point | -4 342 | 7 048 |
| Currency rate USD/NOK | +/- 2.0 NOK | -183 672 | 304 906 |
| Inflation | +/- 1 % point | -35 937 | 32 739 |
Although illustrative impairment sensitivity assumes no changes to other input factors, a price reduction of 20% is likely to result in changes in business plans as well as other factors used when estimating an asset's recoverable amount. Changes in such input factors would likely significantly reduce the actual impairment amount compared to the illustrative sensitivity above.
During 2021, a net impairment reversal of USD 9.2 million has been recognized, mainly related to an impairment of Liatårnet of USD 47.6 million, and an impairment reversal of USD 60.0 million related to Trell & Trine. The reversal was triggered by an updated impairment assessment in relation to the project being included in the Alvheim CGU after concept selection was made towards the end of the fouth quarter. The impairment charge and reversal of prior period impairment have been allocated between other intangible assets and capitalized exploration expenditures with USD -50.7 million (net reversal) and USD 41.6 million (net impairment) respectively.
Residual goodwill is allocated across all CGUs for impairment testing. The combined recoverable amount exceeds the carrying amount by a substantial margin.
The climate related risk assessment is generally described in the company's sustainability reporting. For financial reporting, the transition risk (market, regulatory, reputation, technical and operational) is deemed as the most important, and this has been integrated in the economic assumptions used for impairment testing. This includes a step up of CO2 tax/fees from current levels to approximately NOK 2 100 per tonn (2021 real) in 2030.
In addition, various scenarios from International Energy Agency have been included in a separate sensitivity test which includes the six producing CGU's in the company. The price assumptions in those senarios have been provided by IEA at 2030 and 2050 in 2020 real terms, and for the sensitivity calculation a linear development between average actual 2021 and to 2030, as well as between 2030 and 2050 have been applied. The table below summarizes how the impairment charge would increase (+) or decrease (-) using the oil and gas price assumptions in the following scenarios (2030 and 2050 prices in brackets):
| Change in impairment | ||||||
|---|---|---|---|---|---|---|
| IEA Scenario (USD 1 000 000) | Valhall/Hod | Ula/Tambar | Alvheim | Ivar Aasen | Total | |
| Net Zero | (Oil 36 - 24 USD/bbl, Gas 3.9 - 3.6 USD/mmbtu) | 1 047 | 210 | 15 | 118 | 1 390 |
| Sustainable Development | (Oil 56 - 50 USD/bbl, Gas 4.2 - 4.5 USD/mmbtu) | - | 47 | - | - | 47 |
| Announced Pledges | (Oil 67 - 64 USD/bbl, Gas 6.5 - 6.5 USD/mmbtu) | - | -43 | - | - | -43 |
| Stated Policies | (Oil 77 - 88 USD/bbl, Gas 7.7 - 8.3 USD/mmbtu) | - | -125 | - | - | -125 |
The estimated impairment charge on the CGU's Johan Sverdrup and Skarv would not be impacted by any of the scenarios above. Ula/Tambar is the only CGU where there is previous impairment charge that could be reversed going forward. The estimated headroom in the impairment test on all six CGU's would increase by approximately USD 1.5 billion in the Stated Policies scenario, compared to the oil and gas prices applied in the impairment testing.
In 2020, the impairment charge was mainly related to two CGU's and allocated to technical goodwill, other intagible assets from acquisitions and tangible fixed assets, in addition to an impairment of exploration wells. The methodology for impairment testing was the same as in 2021 as described in this note.
The following assumptions were applied for the impairment testing at year-end 2020:
discount rate of 8.1 percent nominal after tax for both value in use and fair value testing
a long-term inflation of 2.0 percent
a long-term exchange rate of NOK/USD 8.0 (forward curve first three years)
The following impairments/(reversals) have been recorded:
| Group & Parent | |||
|---|---|---|---|
| (USD 1 000) | 2021 | 2020 | |
| Impairment/reversal of tangible fixed assets | 184 664 | 67 099 | |
| Impairment/reversal of other intangible assets | 36 301 | 294 549 | |
| Impairment/reversal of capitalized exploration expenditures | 41 589 | 146 107 | |
| Impairment of goodwill | - | 65 373 | |
| Total impairments | 262 554 | 573 128 |
The company's customers are mainly large, financially sound oil companies. Accounts receivable consist of receivables related to the sale of oil and gas.
| Group & Parent | ||
|---|---|---|
| (USD 1 000) | 31.12.2021 | 31.12.2020 |
| Receivables related to the sale of petroleum | 366 785 | 297 880 |
| Total accounts receivable | 366 785 | 297 880 |
Age distribution of accounts receivable as of 31 December for the group was as follows:
| Year (USD 1 000) | Total | Not due | <30d | 30-90d | >90d |
|---|---|---|---|---|---|
| 2021 | 366 785 | 363 662 | 2 208 | 542 | 373 |
| 2020 | 297 880 | 295 710 | 226 | 6 | 1 938 |
| Group & Parent | ||
|---|---|---|
| (USD 1 000) | 31.12.2021 | 31.12.2020 |
| Prepayments | 45 429 | 59 635 |
| VAT receivable | 13 354 | 6 770 |
| Underlift of petroleum | 36 944 | 53 537 |
| Accrued income from sale of petroleum products | 290 254 | 49 441 |
| Other receivables, mainly balances with license partners | 114 172 | 117 433 |
| Total other short-term receivables | 500 154 | 286 817 |
The inventory mainly consists of equipment for the drilling of exploration and production wells.
| Group & Parent | ||
|---|---|---|
| Inventory value (USD 1 000) | 2021 | 2020 |
| Inventories - measured at cost | 144 457 | 142 291 |
| Provision for obsolete equipment | 18 016 | 29 586 |
| Book value of inventories | 126 442 | 112 704 |
| Group & Parent | ||
|---|---|---|
| (USD 1 000) | 31.12.2021 | 31.12.2020 |
| Shares in Alvheim AS | 10 | 10 |
| Shares in Det norske oljeselskap AS | 1 021 | 1 021 |
| Shares in Sandvika Fjellstue AS | 1 814 | 1 814 |
| Investment in subsidiaries | 2 845 | 2 845 |
| Tenancy deposit | 1 810 | 1 969 |
| Unamortized fees - RCF1) | 15 860 | 16 020 |
| Other non-current assets | 9 789 | 9 376 |
| Total other non-current assets | 30 304 | 30 210 |
1) Remaining unamortized fees related to the Revolving Credit Facility (RCF). These have been reclassified from other interest-bearing debt as the RCF was undrawn as at 31 December 2020 and 31 December 2021.
Alvheim AS, Det norske oljeselskap AS and Sandvika Fjellstue AS have been deemed immaterial for consolidation purposes. For more information regarding shares in subsidiaries, see note 2.
The item 'Cash and cash equivalents' consists of bank accounts and short-term investments that constitute parts of the group's transaction liquidity.
| Group & Parent | ||||
|---|---|---|---|---|
| Breakdown of cash and cash equivalents (USD 1 000) | 31.12.2021 | 31.12.2020 | ||
| Bank deposits | 1 970 906 | 537 801 | ||
| Cash and cash equivalents | 1 970 906 | 537 801 | ||
| Unused Revolving Credit Facility | 3 400 000 | 4 000 000 |
The RCF is undrawn as at 31 December 2021 and the remaining unamortized fees of USD 15.9 million related to the facility are therefore included in other non-current assets.
The senior unsecured Revolving Credit Facility (RCF) was established in May 2019, with the Working Capital facility amended and extended in April 2021. The Working Capital Facility has a committed amount of USD 1.4 billion and is due in 2024, with options for up to two years extension. The Liquidity facility is due in 2026, and has a committed amount of USD 2.0 billion until 2025 and then reduces to USD 1.65 billion for the final year. The interest rate is LIBOR plus a margin of 1.25 percent for the Working Capital Facility and 1.00 percent for the Liquidity Facility (see note 27 for impact of the IBOR reform). 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 31 December 2021 the Leverage Ratio is 0.33 and Interest Coverage Ratio is 27.3 (see APM section for further details), which are well within the thresholds mentioned above. Based on the group's current business plans and applying oil and gas price forward curves at end of Q4 2021, the group'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.
| Parent | ||
|---|---|---|
| (USD 1 000) | 31.12.2021 | 31.12.2020 |
| Share capital | 57 056 | 57 056 |
| Total number of shares (in 1 000) | 360 114 | 360 114 |
| Nominal value per share in NOK | 1.00 | 1.00 |
There is only one single class of shares in the company and all shares carry a single voting right.
| No. of shares | Owning | |
|---|---|---|
| Overview of the 20 largest shareholders registered as of 31 December 2021 | (in 1 000) | interest |
| AKER CAPITAL AS | 133 758 | 37.14% |
| BP Exploration Op Co Ltd | 100 303 | 27.85% |
| FOLKETRYGDFONDET | 12 386 | 3.44% |
| State Street Bank and Trust Comp1) | 5 933 | 1.65% |
| Euroclear Bank S.A./N.V.1) | 2 917 | 0.81% |
| JPMorgan Chase Bank, N.A., London1) | 2 334 | 0.65% |
| State Street Bank and Trust Comp1) | 2 055 | 0.57% |
| State Street Bank and Trust Comp1) | 1 807 | 0.50% |
| State Street Bank and Trust Comp1) | 1 492 | 0.41% |
| VERDIPAPIRFONDET DNB NORGE | 1 484 | 0.41% |
| State Street Bank and Trust Comp1) | 1 473 | 0.41% |
| VERDIPAPIRFOND ODIN NORGE | 1 413 | 0.39% |
| CACEIS Bank Spain SA1) | 1 396 | 0.39% |
| VERDIPAPIRFONDET ALFRED BERG GAMBA | 1 301 | 0.36% |
| The Bank of New York Mellon SA/NV1) | 1 297 | 0.36% |
| RBC Investor services bank S.A.1) | 1 229 | 0.34% |
| CLEARSTREAM BANKING S.A.1) | 1 223 | 0.34% |
| VERDIPAPIRFONDET KLP AKSJENORGE IN | 1 128 | 0.31% |
| JPMorgan Chase Bank, N.A., London1) | 1 062 | 0.29% |
| State Street Bank and Trust Comp1) | 1 060 | 0.29% |
| OTHER | 83 065 | 23.07% |
| Total | 360 114 | 100.00% |
1) Nominee accounts
| Group & Parent | |||
|---|---|---|---|
| (USD 1 000) | Maturity | 31.12.2021 | 31.12.2020 |
| AKERBP – USD Senior Notes 4.750% (19/24) | Jun 2024 | - | 743 329 |
| AKERBP – USD Senior Notes 3.000% (20/25) | Jan 2025 | 497 295 | 496 417 |
| AKERBP – USD Senior Notes 5.875% (18/25) | Mar 2025 | - | 495 523 |
| AKERBP – USD Senior Notes 2.875% (20/26) | Jan 2026 | 497 103 | 496 394 |
| AKERBP – EUR Senior Notes 1.125% (21/29) | May 2029 | 843 995 | - |
| AKERBP – USD Senior Notes 3.750% (20/30) | Jan 2030 | 993 622 | 992 764 |
| AKERBP – USD Senior Notes 4.000% (20/31) | Jan 2031 | 744 720 | 744 139 |
| Long-term bonds - book value | 3 576 735 | 3 968 566 | |
| Long-term bonds - fair value | 3 752 778 | 4 191 375 |
Interest is paid on a semi annual basis, except for the EUR Senior Notes which is paid on an annual basis. None of the bonds have financial covenants.
The fair value on bonds are based on the listed prices in the active markets (level 1 in fair value hierarchy).
| Group & Parent | |||
|---|---|---|---|
| (USD 1 000) | 31.12.2021 | 31.12.2020 | |
| Provisions as of beginning of period | 2 805 507 | 2 788 218 | |
| Change in abandonment liability due to asset sales | - | -13 122 | |
| Incurred removal cost | -185 973 | -162 741 | |
| Accretion expense | 113 748 | 116 947 | |
| Impact of changes to discount rate | -340 973 | 20 554 | |
| Change in estimates and provisions relating to new drilling and installations | 364 912 | 55 650 | |
| Total provision for abandonment liabilities | 2 757 221 | 2 805 507 | |
| Breakdown of the provision to short-term and long-term liabilities | |||
| Short-term | 100 863 | 155 244 | |
| Long-term | 2 656 358 | 2 650 263 | |
| Total provision for abandonment liabilities | 2 757 221 | 2 805 507 |
Estimates are based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The calculations assume an inflation rate of 2.0 percent and a nominal discount rate before tax of between 3.7 percent and 5.2 percent. For previous quarters in 2021 and year end 2020 the inflation rate was 2.0 percent and the discount rate was between 3.1 percent and 4.6 percent. The credit margin included in the discount rate is 3.3 percent. For previous quarters in 2021 and year end 2020 the credit margin was 3.0 percent.
| Group & Parent | ||
|---|---|---|
| (USD 1 000) | 31.12.2021 | 31.12.2020 |
| Unrealized gain currency contracts | 1 375 | 12 841 |
| Long-term derivatives included in assets | 1 375 | 12 841 |
| Unrealized gain currency contracts | 18 577 | 23 212 |
| Short-term derivatives included in assets | 18 577 | 23 212 |
| Total derivatives included in assets | 19 952 | 36 053 |
| Unrealized losses currency contracts | 2 370 | - |
| Long-term derivatives included in liabilities | 2 370 | - |
| Unrealized losses commodity derivatives | 8 989 | 3 539 |
| Unrealized losses currency contracts | 26 094 | - |
| Short-term derivatives included in liabilities | 35 082 | 3 539 |
| Total derivatives included in liabilities | 37 452 | 3 539 |
The company has various types of economic hedging instruments, but no hedge accounting is applied. Commodity derivatives are used to hedge the risk of oil price reduction. The company currently has limited exposure towards fluctuations in interest rate, but generally manages such exposure by using interest rate derivatives. 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. In the income statement, impacts from commodity derivatives are presented as other income, while impacts from other derivatives are presented as financial items.
| Group & Parent | |||
|---|---|---|---|
| Breakdown of other current liabilities (USD 1 000) | 31.12.2021 | 31.12.2020 | |
| Balances with license partners | 48 456 | 20 915 | |
| Share of other current liabilities in licenses | 311 694 | 245 158 | |
| Overlift of petroleum | 40 044 | 11 331 | |
| Payroll liabilities, accrued interest and other provisions | 224 173 | 216 942 | |
| Total other current liabilities | 624 366 | 494 346 |
The company has entered into leases for rig contracts, other license related commitments and office premises. The leases do not contain any restrictions on the company's dividend policy or financing. To the extent the lease has been approved and committed by the partners in the relevant Aker BP operated licenses, the committments disclosed represent Aker BP share only.
During 2021, the group had five rig commitments in place. This included three jack-up rigs from Maersk Drilling: the Maersk Invincible, Maersk Integrator and Maersk Reacher. The Maersk Invincible is contracted by the Valhall license until May 2022 and is included as lease in the table below. The Maersk Integrator was committed by different licenses under separate well contracts in 2021, where the last contract ended in November 2021. During the summer the Maersk Reacher was contracted by the Valhall license on a 9 months contract to do stimulation and intervention activities on Valhall. The short-term exemption under IFRS 16 was applied for both these contracts and the related rigs were thus not recognised as a right of use asset. In January 2022, Maersk Drilling and Aker BP entered into a rig swap agreement where Maersk Reacher is to be replaced by the Maersk Integrator. The swap will take place in Q1 2022. The Maersk Reacher work scope will be transferred on to the Maersk Integrator with an added scope estimated to eight months, which means that Maersk Integrator will be employed until January 2023.
In December 2021, Maersk Drilling and Aker BP agreed to renew the frame agreement with five-year commitment for Maersk Integrator and Maersk Invincible. This will allow Aker BP to assign the two rigs to multiple operations with multi-purpose use of the rigs during the frame agreement period. Different rate structures will apply during the period reflecting different operating modes, agreed incentive schemes, and market developments. Over the frame agreement renewal period, the five-year commitment for the two rigs is expected to have a combined total contract value of approximately USD 1 billion. There will be different work scopes, with varying durations in the period from 2023 to 2027, including options to return the rigs for multiple parts of the period as deemed appropriate by the company.
Aker BP also had two semi-submersible rig commitment contracts with Odfjell Drilling: The Deepsea Stavanger and the Deepsea Nordkapp. The Deepsea Stavanger was on contract until July 2021 and then returned to execute the Lyderhorn campaign in November 2021. The Deepsea Nordkapp was committed until June 2023 after a one-year extension option was exercised in 2021. In addition, there was a scope based option to extend the contract to include completion of the KEG project scope, which is expected to last to end of Q1 2024. This option was exercised in February 2022. These rig leases have been entered into in the company's name at the initial signing, and subsequently partly allocated to licenses. According to the planned use of the related leased assets, the duration for each license indicates that the short-term exemption will be applied. It is thus not expected that these commitments at any point in time will be recognized as a lease liability.
Non-lease components such as the service element of rig commitments are not included as part of the lease debt. As at 31 December 2021 this amounts to USD 16 million.
The incremental borrowing rate applied in discounting of the nominal lease debt is between 2.71 percent and 6.71 percent, dependent on the duration of the lease and when it was intially recognized.
| Group & Parent | ||
|---|---|---|
| (USD 1 000) | 2021 | 2020 |
| Lease debt as of beginning of period | 215 760 | 313 256 |
| New lease debt recognized in the period | 5 989 | 16 834 |
| Payments of lease debt1) | -96 173 | -118 224 |
| Lease debt derecognized in the period | - | -12 767 |
| Interest expense on lease debt | 11 558 | 16 629 |
| Currency exchange differences | -921 | 32 |
| Total lease debt | 136 213 | 215 760 |
| Short-term | 44 378 | 83 904 |
|---|---|---|
| Long-term | 91 835 | 131 856 |
| Total lease debt | 136 213 | 215 760 |
| 1) Payments of lease debt split by activities (USD 1 000): | 2021 | 2020 |
| Investments in fixed assets | 50 423 | 67 125 |
| Abandonment activity | 31 715 | 27 660 |
| Operating expenditures | 7 499 | 18 075 |
| Exploration expenditures | 1 858 | 874 |
| Other income | 4 678 | 4 489 |
| Total | 96 173 | 118 224 |
| Within one year | 51 010 | 95 124 |
|---|---|---|
| Two to five years | 68 602 | 99 809 |
| After five years | 42 837 | 57 464 |
| Total | 162 448 | 252 397 |
The group does not have any residual value guarantees or variable lease payments. Extension options are included in the lease liability when, based on management's judgement, it is reasonably certain that an extension will be exercised. No such extension options are recognized as at 31 December 2021. No sublease of right-of-use assets has occured.
The total expenditure relating to short-term leases which are not recognized as part of lease liabilities was USD 66 million in 2021 (USD 70 million in 2020).
Aker BP`s net share of capital commitments and other contractual obligations in the table below are mainly related to rig commitments not recognized as lease liabilities, rig leases not yet commenced and booked future gas transportation capacity. Parts of the rig leases have been entered into in the company's name at the initial signing, and subsequently partly allocated to licenses. The figures have been calculated based on the assumed net share for the company based on the planned use of the related leased assets as at 31 December 2021. The planned duration for each license indicate that the short-term exemption will be applied. It is thus not expected that these commitments at any point in time will be recognized as a lease liability. The numbers below exclude any liabilities disclosed in note 24 in relation to right-of-use assets.
| Group & Parent | ||
|---|---|---|
| (USD 1 000) | 31.12.2021 | 31.12.2020 |
| Within one year | 387 894 | 603 269 |
| One to five years | 263 283 | 321 994 |
| After five years | 61 288 | 92 285 |
| Total | 712 465 | 1 017 548 |
In connection with the booking of capacity in the infrastructure on the Norwegian Continental Shelf, the operator of the infrastructure (Gassco) requires a guarantee covering the expected transportation cost in the coming two years. This guarantee amounts to NOK 830 million as of year-end 2021 (NOK 1,060 million in 2020).
The company has a bank guarantee related to withheld payroll tax of NOK 300 million.
During the normal course of its business, the company will be involved in disputes, including tax disputes. Potential tax claims related to previous taxable income of acquired companies can to some extent be reimbursed from the sellers. The company 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.
As for other licenses on the NCS, the company has unlimited liability for damage, including pollution damage. The company has insured its pro rata liability on the NCS on a par with other oil companies. Installations and liability are covered by an operational liability insurance policy.
At year-end 2021, Aker (Aker Capital AS) and BP Exploration Operating Company Ltd are the two major shareholders in Aker BP, with a total ownership interest of 37.1 and 27.9 percent (2020: 40.0 and 30.0 respectively). An overview of the 20 largest shareholders is provided in note 19. Entities controlled either by the Aker Group or the BP Group are considered to be related parties under IFRS.
Transactions with related parties are carried out on the basis of the "arm's length" principle.
| Group & Parent | |||
|---|---|---|---|
| Related party (USD 1 000) | Receivables (+) / liabilities (-) | 31.12.2021 | 31.12.2020 |
| aiZe AS | Other receivables | - 2 704 |
|
| Cognite AS | Trade creditors | -1 991 | 1 021 |
| Other Aker Group Companies | Trade creditors | -149 | -244 |
| Other BP Group Companies | Trade creditors | -58 | -2 |
| BP Oil International Ltd. | Trade debtors | 360 600 | 294 742 |
| Other BP Group Companies | Trade debtors | -356 | -368 |
| Other Aker Group Companies | Trade debtors | - 74 |
| Group & Parent | ||||
|---|---|---|---|---|
| Related party (USD 1 000) | Revenues (-) / expenses (+) | 2021 | 2020 | |
| AGR Consultancy Services AS1) | Purchases of consultant services | - | 7 718 | |
| AGR Petroleum Service AS1) | Exploration expenses | - | 3 087 | |
| aiZe AS | Purchases of consultant and technology services | 880 | - | |
| Aker ASA | Board remuneration etc | 632 | 286 | |
| Akastor Real Estate AS1) | Office rental | - | 1 556 | |
| Aker Offshore Wind Operating Company | Purchases of consultant and engineering services | - | ||
| Aker Solutions ASA1) | Development costs | - | 159 409 | |
| Cognite AS | Purchases of consultant and IT services | 15 273 | 12 548 | |
| Kværner AS1) | Development costs | - | 62 407 | |
| OCY Frayja Limited | Platform supply vessel leases | 3 853 | 4 210 | |
| OCY Orla Limited | Platform supply vessel leases | 3 853 | 4 210 | |
| Other Aker Group companies | Operating expenses | 581 | 1 312 | |
| BP Oil International Ltd. | Sales of Oil and NGL | -4 280 791 | -2 613 806 | |
| BP Gas Marketing Ltd. | Sales of Gas | -1 055 588 | -171 917 | |
| Other BP Group Companies | Other operating expenses | -404 |
1) These entities are not deemed related parties to Aker BP ASA from 22 December 2020, due to reduced ownership interest and the reclassification of Aker's interests in these entities to associates in the Aker Group.
The main objective of the company's management of the capital structure is to maximize return to the owners by ensuring competitive conditions for both the company's own capital and borrowed capital.
The company is rated by S&P Global, Fitch and Moody's. The investment grade rating assigned by all three companies continue to provide access to capital markets, including bank and bond financing, at attractive terms. The company's production level, financial position and resource and reserve levels are important parameters in relation to the assigned rating. The company continues to optimize its capital structure by balancing the return on equity against liquidity requirements.
The company monitors changes in financing needs, risk, assets and cash flows, and evaluates the capital structure continuously. To maintain the desired capital structure, the company considers various types of capital transactions, including refinancing of its debt, purchase or issue new shares or debt instruments, sell assets or pay back capital to the owners.
Unless specified otherwise, the numbers below apply both to the group and the parent.
The company has the following financial assets and liabilities: financial assets and liabilities recognized at fair value through profit or loss, cash and receivables, and other liabilities. The latter two are recognized in the accounts at amortized cost, while the first item is recognized at fair value.
| Financial assets at fair value | Cash, cash | Financial liabilities at fair value | Financial liabilities | ||
|---|---|---|---|---|---|
| designated as such upon initial | equivalents and | designated as such upon initial | measured at | ||
| 31.12.2021 | recognition | receivables | recognition | amortized cost | Total |
| Assets | |||||
| Accounts receivable | - | 366 785 | - | - | 366 785 |
| Other short-term receivables1) | - | 454 724 | - | - | 454 724 |
| Cash and cash equivalents | - | 1 970 906 | - | - | 1 970 906 |
| Derivatives | 19 952 | - | - | - | 19 952 |
| Total financial assets | 19 952 | 2 792 415 | - | - | 2 812 367 |
| Liabilities | |||||
| Derivatives | - | - | 37 452 | - | 37 452 |
| Trade creditors | - | - | - | 147 366 | 147 366 |
| Bonds | - | - | - | 3 576 735 | 3 576 735 |
| Other short-term liabilities | - | - | - | 624 366 | 624 366 |
| Total financial liabilities | - | - | 37 452 | 4 348 467 | 4 385 920 |
| Financial assets at fair value | Cash, cash | Financial liabilities at fair value | Financial liabilities | ||
|---|---|---|---|---|---|
| designated as such upon initial | equivalents and | designated as such upon initial | measured at | ||
| 31.12.2020 | recognition | receivables | recognition | amortized cost | Total |
| Assets | |||||
| Accounts receivable | - | 297 880 | - | - | 297 880 |
| Other short-term receivables1) | - | 227 182 | - | - | 227 182 |
| Cash and cash equivalents | - | 537 801 | - | - | 537 801 |
| Derivatives | 36 053 | - | - | - | 36 053 |
| Total financial assets | 36 053 | 1 062 862 | - | - | 1 098 915 |
| Liabilities | |||||
| Derivatives | - | - | 3 539 | - | 3 539 |
| Trade creditors | - | - | - | 113 517 | 113 517 |
| Bonds | - | - | - | 3 968 566 | 3 968 566 |
| Other short-term liabilities | - | - | - | 494 346 | 494 346 |
| Total financial liabilities | - | - | 3 539 | 4 576 429 | 4 579 968 |
1) Prepayments are not included in other short-term receivables, as they do not meet the definition of financial instruments.
The company has financed its activities with bonds (see note 20) and has an undrawn revolving credit facility with a syndication of banks (see note 18). In addition, the company has financial instruments such as accounts receivable, trade creditors, cash balances etc., directly related to its day-to-day operations. For hedging purposes, the company has different types of economic hedging instruments, but no hedge accounting is applied. Commodity derivatives are used to hedge the risk for lower oil prices. Foreign currency exchange derivatives are used in order to reduce currency risk related to cash flows. For the year 2021 all outstanding debt hold fixed rate coupons. The group currently has limited exposure towards fluctuations in interest rate, but generally manages such exposure by using interest rate derivatives.
The most important financial risks which the company is exposed to relate to lower oil and gas prices, change in foreign exchange rates and access to cost efficient funding.
The company's risk management, including financial risk management, is designed to ensure identification, analysis and systematic and cost-efficient handling of risk. Established management procedures provide a sound basis for reporting and monitoring of the company's financial risk exposure.
Aker BP's revenues are derived from the sale of petroleum products, and the revenue flow is therefore exposed to oil and gas price fluctuations. The company is continuously evaluating and assessing opportunities for hedging as part of a prudent financial risk management process. At year end 2021, the company had hedges in place for 13 percent of estimated 2022 oil production, corresponding to approximately 47 percent of the after tax value, and with an average strike of 45 USD/bbl (see note 22). Hedges in place at year end 2021:
| Oil put options | Q1 2022 | Q2 2022 | Q3 2022 | Q4 2022 |
|---|---|---|---|---|
| Production covered (mmboe) | 2.6 | 2.6 | 1.5 | 1.5 |
| Average premium (USD/bbl) | 1.9 | 1.9 | 1.9 | 1.9 |
| Average strike (USD/bbl) | 45 | 45 | 45 | 45 |
In 2021 the company had put options in place with a strike of 35, 40, 45 and 50 USD/bbl. for approximately 16 percent of the 2021 oil production, corresponding to approximately 58 percent of the undiscounted after-tax value.
Revenues from sale of petroleum and gas are mainly in USD, EUR and GBP, while expenditures are mainly in NOK, USD, EUR and GBP. Sales and expenses in the same currency contribute to mitigating some of the currency risk. Currency derivatives may be used to further reduce this risk.
The table below shows the company's exposure in NOK as of 31 December:
| Exposure relating to (USD 1 000) | 31.12.2021 | 31.12.2020 |
|---|---|---|
| Tax receivables, cash and cash equivalents and other short-term receivables | 192 622 | 153 700 |
| Trade creditors, tax payable, leasing liability and other short-term liabilities | -2 038 762 | -643 834 |
| Net exposure to NOK | -1 846 140 | -490 134 |
The amounts above does not include tax balances in NOK, as they are not deemed to be financial instruments.The company's management of currency risk takes into account the USD values of non-USD assets, liabilities, opex and investments over time, including those exposures arising from the requirement to perform the tax calculation in NOK while the company's functional currency is USD.
The table below shows the impact on profit/loss from changes in NOK/USD exchange rate.
| (USD 1 000) | Change in exchange rate | 31.12.2021 | 31.12.2020 |
|---|---|---|---|
| Effect on pre-tax profit/loss: | + 10% | 25 423 | -3 609 |
| - 10% | -31 072 | 4 411 |
The sensitivity above includes the impact from currency derivatives.
In 2021 the company had EUR/USD exposure related to bond, cash and receivables from gas sales. The company established its Euro Medium Term Note ('EMTN') programme in April 2021 and issued EUR 750 million Senior Notes in May 2021. As these Senior Notes bonds are EUR denominated there are currency risks associated with the translation to the company's USD functional currency and the cash payments of interest and principle amounts, though EUR denominated gas sales mitigate the risks associated with payments. The company has not entered any foreign currency exchange derivatives related to the EUR Senior Notes.
The table below shows the company's related EUR exposure as of 31 December:
| Exposure relating to (USD 1 000) | 31.12.2021 | 31.12.20201) |
|---|---|---|
| Cash and cash equivalents and other short-term receivables | 332 143 | - |
| Bonds | -849 375 | - |
| Net exposure to EUR | -517 232 | - |
The table below shows the impact on profit/loss from changes in EUR/USD exchange rate for the EUR bond, cash and cash equivalents and other short-term receivables. Other EUR balances are not included as the exposure is deemed immaterial.
| (USD 1 000) | Change in exchange rate | 31.12.2021 | 31.12.20201) |
|---|---|---|---|
| Effect on pre-tax profit/loss: | + 10% | 47 019 | - |
| - 10% | -57 473 | - |
The company is also exposed to change in other exchange rates such as GBP/USD, but the amounts are deemed immaterial.
In 2021, the company had no oustanding debt liabilities exposed to floating interest rate risk. The corresponding debt liabilities as of 31 December 2020 amounted to zero. The company is relatively limited exposed to interest-rate risk related to cash and cash equivalents.
The terms of the company's debt instruments are described in notes 20.
On 5 March 2021, the United Kingdom's Financial Conduct Authority (FCA) confirmed that all LIBOR settings will either cease to be provided by any administrator or no longer be representative after 31 December 2021, in the case of all sterling, euro, Swiss franc and Japanese yen settings, and the 1-week and 2-month US dollar settings; and after 30 June 2023, in the case of the remaining US dollar settings.
It has been announced that USD LIBOR will remain published and representative for overnight, 1-month, 3-month, 6-month and 12-month US dollar LIBOR settings until end-June 2023, when transition to appropriate alternative rates will occur. Aker BP will follow guidance on USD LIBOR exposures, including SOFR principles.
For all the relevant material financial agreements, Aker BP has in place new benchmark rates or a fallback clause to cater for the discontinuation of IBOR rates. The IBOR reform did not have any current impact on Aker BP and is not expected to significantly affect future periods. All our bonds are at fixed interest rate, and the RCF is currently undrawn. Further, the fallback to SOFR rates adjusted for applicable credit adjustment spread after June 2023 is not expected to materially differ from the IBOR rate.
The company's liquidity risk is the risk that it will not be able to meet its financial obligations as they fall due.
Short-term (12 months) and long-term (five years) forecasts are prepared on a regular basis to plan the company's liquidity requirements. These plans are updated regularly for various scenarios and form part of the decision basis for the company's management and Board of Directors.
Excess liquidity is defined as the sum of bank account balances, short-term bank deposits and unused credit facilities. For excess liquidity, the requirement for low liquidity risk (i.e. the risk of realization on short notice) is generally more important than maximizing the return.
The company's objective for the placement and management of excess capital is to maintain a low risk profile and good liquidity.
The company's liquid assets as of 31 December 2021 are deposited in bank accounts and on short term time deposits with banks. As of 31 December 2021, the company had cash reserves of USD 1 971 million (2020: USD 538 million). Revenues and expenses are carefully managed on a day-to-day basis for liquidity risk management purposes.
The table below shows the payment structure for the company's financial commitments, based on undiscounted contractual payments:
| Contract related cash flow | |||||||
|---|---|---|---|---|---|---|---|
| 31.12.2021 | Book value | Less than 1 year | 1-2 years | 2-5 years | over 5 years | SUM | |
| Non-derivative financial liabilities: | |||||||
| Bonds | 3 576 735 | 106 563 | 106 563 | 1 290 002 | 2 894 690 | 4 397 818 | |
| Trade creditors and other liabilities | 771 732 | 771 732 | - | - | - | 771 732 | |
| Derivative financial liabilities | |||||||
| Derivatives | 37 452 | 35 082 | 2 370 | - | - | 37 452 | |
| Total as of 31.12.2021 | 4 385 920 | 913 378 | 108 933 | 1 290 002 | 2 894 690 | 5 207 003 |
| 31.12.2020 | Book value | Less than 1 year | 1-2 years | 2-5 years | over 5 years | SUM |
|---|---|---|---|---|---|---|
| Non-derivative financial liabilities: | ||||||
| Bonds | 3 968 566 | 152 630 | 161 875 | 2 160 000 | 2 590 938 | 5 065 443 |
| Trade creditors and other liabilities | 607 862 | 607 862 | - | - | - | 607 862 |
| Derivative financial liabilities | ||||||
| Derivatives | 3 539 | 3 539 | - | - | - | 3 539 |
| Total as of 31.12.2020 | 4 579 968 | 764 032 | 161 875 | 2 160 000 | 2 590 938 | 5 676 844 |
The risk of counterparties being financially incapable of fulfilling their obligations is regarded as minor as there have not historically been any losses on accounts receivable. The company's customers and license partners are generally large and credit worthy oil companies, and it has thus not been necessary to make any provision for credit losses.
In the management of the company's liquid assets, low credit risk is prioritized. Liquid assets are generally placed in bank deposits that represent a low credit risk. All investments are subject to internal policy that requires a rating equivalent to A-2 from S&P and limits investment with a single counterparty.
The maximum credit risk exposure corresponds to the book value of financial assets. The company deems its maximum risk exposure to correspond with the book value of cash and cash equivalents, accounts receivable and other short-term receivables, see notes 14, 15 and 18.
The fair value of forward exchange contracts is determined using the forward exchange rate at the end of the reporting period. The fair value of commodity derivatives is determined using the forward Brent blend curve at the end of the reporting period. The fair value of interest rate swaps and cross currency interest rate swaps is determined by using the expected floating interest rates at the end of the period and is confirmed by external market sources. See note 22 for detailed information about the derivatives. The following of the company's financial instruments have not been valued at fair value: trade debtors, other short-term receivables, other long-term receivables, short-term loans and other short-term liabilities, bonds and other interest bearing liabilities.
The carrying amount of cash and cash equivalents is approximately equal to fair value, since these instruments have a short term to maturity. Similarly, the carrying amount of accounts receivable, other receivables, trade creditors and other short-term liabilities is materially the same as their fair value as they are entered into on ordinary terms and conditions.
The USD 4,00%, 3,75%, 3,00% and 2,875% Senior Notes and the EUR 1.125% Senior Notes are all listed on The Luxembourg Stock Exchange. The fair values for disclosure purposes are determined using the quoted value as of 31 December 2021.
The following is a comparison between the book value and fair value of the company's financial instruments, except those where the carrying amount is a reasonable approximation of fair value (such as short-term trade receivables and payables in addition to instruments measured to fair value).
| 31.12.2021 | 31.12.2020 | |||
|---|---|---|---|---|
| Fair value of financial instruments (USD 1 000) | Book value | Fair value | Book value | Fair value |
| Financial liabilities measured at amortized cost: | ||||
| Bonds | 3 576 735 | 3 752 778 | 3 968 566 | 4 191 375 |
| Total financial liabilities | 3 576 735 | 3 752 778 | 3 968 566 | 4 191 375 |
The company classifies fair value measurements by employing a value hierarchy that reflects the significance of the input used in preparing the measurements. The fair value hierarchy consists of the following levels:
Level 1 - input in the form of listed (unadjusted) prices in active markets for identical assets or liabilities.
Level 2 - input other than listed prices of assets and liabilities included in Level 1 that is observable for assets or liabilities, either directly (i.e. as prices) or indirectly (i.e. derived from prices).
Level 3 - input for assets or liabilities for which there is no observable market data (non-observable input).
The company has no assets or liabilities in Level 3.
| Level 1 | Level 2 | Level 3 |
|---|---|---|
| - | -17 501 | - |
| Level 1 | Level 2 | Level 3 |
| - | ||
| - | 32 514 |
In the course of the reporting period, there were no changes in the fair value measurements that involved any transfers between levels.
The table below shows a reconciliation between the opening and the closing balances in the statement of financial position for liabilities arising from financing activities.
| Non-cash changes | ||||||
|---|---|---|---|---|---|---|
| 31.12.2020 | Cash flows | Amortization | Currency | Other fin exp1) | 31.12.2021 | |
| Bonds | 3 968 566 | -383 169 | 14 658 | -61 725 | 38 405 | 3 576 735 |
| Paid dividends | - | -487 500 | - | - | - | - |
| Totals | 3 968 566 | -870 669 | 14 658 | -61 725 | 38 405 | 3 576 735 |
| Restated | Non-cash changes | |||||
|---|---|---|---|---|---|---|
| 31.12.2019 | Cash flows | Amortization | Currency | Other fin exp2) | 31.12.2020 | |
| Other interest-bearing debt (RCF) | 1 429 132 | -1 451 550 | 6 348 | - | 16 070 | - |
| Bonds | 1 857 636 | 2 099 695 | 13 465 | -17 839 | 15 609 | 3 968 566 |
| Paid dividends | - | -425 000 | - | - | - | - |
| Totals | 3 286 768 | 223 145 | 19 813 | -17 839 | 31 679 | 3 968 566 |
1) Other financial expenses in 2021 repesents early redemption fee of bond and discount on new bond.
2) Reclass of remaining unamortized fees of USD 16.0 million related to the RCF facility, included in other non-current assets at 31 December 2020, and early redemption fee of bond and discount on new bonds in 2020.
Production licenses in which Aker BP is the operator:
| Fields operated: | 31.12.2021 | 31.12.2020 | Fields operated: | 31.12.2021 | 31.12.2020 |
|---|---|---|---|---|---|
| Alvheim | 65.000 % | 65.000 % | Tambar | 55.000 % | 55.000 % |
| Bøyla | 65.000 % | 65.000 % | Tambar Øst | 46.200 % | 46.200 % |
| Hod | 90.000 % | 90.000 % | Ula | 80.000 % | 80.000 % |
| Ivar Aasen Unit | 34.786 % | 34.786 % | Valhall | 90.000 % | 90.000 % |
| Skogul | 65.000 % | 65.000 % | Vilje | 46.904 % | 46.904 % |
| Skarv | 23.835 % | 23.835 % | Volund | 65.000 % | 65.000 % |
| License: | 31.12.2021 | 31.12.2020 | License: | 31.12.2021 | 31.12.2020 |
|---|---|---|---|---|---|
| PL 001B | 35.000 % | 35.000 % | PL 784 | 40.000 % | 40.000 % |
| PL 006B | 90.000 % | 90.000 % | PL 814 | 0.000 % | 40.000 % |
| PL 019 | 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 | 87.700 % | 92.130 % | PL 838 | 35.000 % | 35.000 % |
| PL 026B | 87.700 % | 90.260 % | PL 858 | 40.000 % | 40.000 % |
| PL 028B | 35.000 % | 35.000 % | PL 867 | 80.000 % | 40.000 % |
| PL 033 | 90.000 % | 90.000 % | PL 867B | 80.000 % | 40.000 % |
| PL 033B | 90.000 % | 90.000 % | PL 868 | 0.000 % | 60.000 % |
| PL 036C | 65.000 % | 65.000 % | PL 869 | 65.000 % | 60.000 % |
| PL 036D | 46.904 % | 46.904 % | PL 873 | 47.700 % | 40.000 % |
| PL 036E | 48.420 % | 64.000 % | PL 874 | 87.700 % | 90.260 % |
| PL 036F | 48.420 % | 64.000 % | PL 906 | 50.000 % | 60.000 % |
| PL 065 | 55.000 % | 55.000 % | PL 907 | 0.000 % | 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 % |
| PL 102D | 44.000 % | 50.000 % | PL 919 | 65.000 % | 65.000 % |
| PL 102F | 48.420 % | 50.000 % | PL 932 | 60.000 % | 60.000 % |
| PL 102G | 48.420 % | 50.000 % | PL 941 | 50.000 % | 50.000 % |
| PL 102H | 44.000 % | 50.000 % | PL 942 | 30.000 % | 30.000 % |
| PL 127C | 88.083 % | 88.083 % | PL 964 | 0.000 % | 40.000 % |
| PL 146 | 77.800 % | 77.800 % | PL 977 | 0.000 % | 60.000 % |
| PL 146B | 77.800 % | 0.000 % | PL 978 | 0.000 % | 60.000 % |
| PL 150 | 65.000 % | 65.000 % | PL 979 | 60.000 % | 60.000 % |
| PL 159D | 23.835 % | 23.835 % | PL 986 | 50.000 % | 50.000 % |
| PL 203 | 65.000 % | 65.000 % | PL 1005 | 40.000 % | 40.000 % |
| PL 212 | 30.000 % | 30.000 % | PL 1008 | 90.000 % | 60.000 % |
| PL 212B | 30.000 % | 30.000 % | PL 1022 | 0.000 % | 40.000 % |
| PL 212E | 30.000 % | 30.000 % | PL 1026 | 40.000 % | 40.000 % |
| PL 242 | 35.000 % | 35.000 % | PL 1028 | 50.000 % | 50.000 % |
| PL 261 | 60.000 % | 50.000 % | PL 1030 | 0.000 % | 50.000 % |
| PL 261C | 23.835 % | 0.000 % | PL 1041 | 55.000 % | 40.000 % |
| PL 262 | 30.000 % | 30.000 % | PL 1042 | 40.000 % | 40.000 % |
| PL 300 | 55.000 % | 55.000 % | PL 1045 | 65.000 % | 65.000 % |
| PL 333 | 77.800 % | 77.800 % | PL 1045B | 65.000 % | 0.000 % |
| PL 340 | 65.000 % | 65.000 % | PL 1047 | 40.000 % | 40.000 % |
| PL 340BS | 65.000 % | 65.000 % | PL 1066 | 50.000 % | 50.000 % |
| PL 364 | 87.700 % | 90.260 % | PL 1085 | 55.000 % | 0.000 % |
| PL 442 | 87.700 % | 90.260 % | PL 1088 | 77.800 % | 0.000 % |
| PL 442B | 87.700 % | 90.260 % | PL 1097 | 40.000 % | 0.000 % |
| PL 442C | 87.700 % | 90.260 % | PL 1099 | 40.000 % | 0.000 % |
| PL 460 | 65.000 % | 65.000 % | PL 1110 | 40.000 % | 0.000 % |
| PL 685 | 40.000 % | 40.000 % | PL 1124 | 23.835 % | 0.000 % |
| Number of licenses in which Aker BP is the operator | 80 | 79 |
| Fields non-operated: | 31.12.2021 | 31.12.2020 |
|---|---|---|
| Atla | 10.000 % | 10.000 % |
| Enoch | 2.000 % | 2.000 % |
| Johan Sverdrup | 11.573 % | 11.573 % |
| Oda | 15.000 % | 15.000 % |
| License: | 31.12.2021 | 31.12.2020 | License: | 31.12.2021 | 31.12.2020 |
|---|---|---|---|---|---|
| PL 006C | 35.000 % | 15.000 % | PL 782SC | 20.000 % | 20.000 % |
| PL 006E | 15.000 % | 15.000 % | PL 782SD | 20.000 % | 20.000 % |
| PL 006F | 15.000 % | 15.000 % | PL 838B | 30.000 % | 30.000 % |
| PL 035 | 50.000 % | 50.000 % | PL 852 | 0.000 % | 40.000 % |
| PL 035C | 50.000 % | 50.000 % | PL 852B | 0.000 % | 40.000 % |
| PL 048D | 10.000 % | 10.000 % | PL 852C | 0.000 % | 40.000 % |
| PL 102C | 10.000 % | 10.000 % | PL 862 | 0.000 % | 50.000 % |
| PL 127 | 50.000 % | 50.000 % | PL 892 | 30.000 % | 30.000 % |
| PL 127B | 50.000 % | 50.000 % | PL 902 | 0.000 % | 30.000 % |
| PL 167 | 10.000 % | 0.000 % | PL 902B | 0.000 % | 30.000 % |
| PL 167B | 10.000 % | 0.000 % | PL 943 | 10.000 % | 0.000 % |
| PL 167C | 10.000 % | 0.000 % | PL 954 | 0.000 % | 20.000 % |
| PL 220 | 15.000 % | 15.000 % | PL 955 | 0.000 % | 30.000 % |
| PL 265 | 20.000 % | 20.000 % | PL 961 | 0.000 % | 30.000 % |
| PL 272 | 50.000 % | 50.000 % | PL 962 | 0.000 % | 20.000 % |
| PL 272B | 50.000 % | 50.000 % | PL 966 | 0.000 % | 30.000 % |
| PL 405 | 15.000 % | 15.000 % | PL 968 | 20.000 % | 20.000 % |
| PL 457BS | 40.000 % | 40.000 % | PL 981 | 40.000 % | 40.000 % |
| PL 492 | 60.000 % | 60.000 % | PL 982 | 0.000 % | 40.000 % |
| PL 502 | 22.222 % | 22.222 % | PL 985 | 20.000 % | 20.000 % |
| PL 533 | 35.000 % | 35.000 % | PL 1031 | 0.000 % | 20.000 % |
| PL 533B | 0.000 % | 35.000 % | PL 1040 | 30.000 % | 30.000 % |
| PL 554 | 30.000 % | 30.000 % | PL 1051 | 20.000 % | 20.000 % |
| PL 554B | 30.000 % | 30.000 % | PL 1052 | 20.000 % | 20.000 % |
| PL 554C | 30.000 % | 30.000 % | PL 1054 | 30.000 % | 30.000 % |
| PL 554D | 30.000 % | 30.000 % | PL 1056 | 0.000 % | 10.000 % |
| PL 719 | 0.000 % | 20.000 % | PL 1064 | 20.000 % | 30.000 % |
| PL 722 | 20.000 % | 20.000 % | PL 1069 | 50.000 % | 50.000 % |
| PL 780 | 0.000 % | 40.000 % | PL 1122 | 20.000 % | 0.000 % |
| PL 782S | 20.000 % | 20.000 % | PL 1123 | 30.000 % | 0.000 % |
| PL 782SB | 20.000 % | 20.000 % | |||
| Number of licenses in which Aker BP is a partner | 44 | 55 |
On 2 February 2022, it was announced that Aker BP sold its 7.4 percent interest in Cognite AS to Saudi Aramco. The transaction was completed in February, and the company expects to recognise a gain of approximately USD 90 million in the first quarter of 2022.
On 23 February 2022, Aker BP disbursed USD 171.1 million in dividend to shareholders.
On 21 December 2021, Aker BP announced a transaction agreement with Lundin Energy AB, pursuant to which Aker BP will acquire Lundin Energy's oil and gas related assets. The merger plan was approved by Boards on 14 February 2022. The transaction is subject to approval by the shareholders of both companies at their respective general meetings, and approval by relevant authorities. The annual general meetings are scheduled for 31 March 2022 for Lundin Energy and 5 April 2022 for Aker BP.
Aker BP ASA's reserve and contingent resource volumes have been classified in accordance with the Society of Petroleum Engineer's (SPE's) "Petroleum Resources Management System". This classification system is consistent with Oslo Børs requirements for the disclosure of hydrocarbon reserves and contingent resources. The framework of the classification system is illustrated in Figure 1.
| PRODUCTION | Project Maturity sub-classes |
||
|---|---|---|---|
| On Production | |||
| TOTAL PETROLEUM INITIALLY-IN-PLACE (PIIP) DISCOVERED PIIP |
COMMERCIAL | RESERVES | Approved for Development |
| Increasing Chance of Commerciality Justified for Development |
|||
| Development Pending | |||
| CONTINGENT | Development Unclarified or On Hold | ||
| SUB-COMMERCIAL | RESOURCES | Development Not Viable | |
| UNRECOVERABLE | |||
| Prospect | |||
| PROSPECTIVE | Lead | ||
| RESOURCES | Play | ||
| UNRECOVERED PIIP |
UNRECOVERABLE | Not to scale | |
| Range of uncertainty |
All reserve estimates are based on all available data including seismic, well logs, core data, drill stem tests and production history. Industry standards are used to establish 1P and 2P. This includes decline analysis for mature fields in which reliable trends are established. For undeveloped fields and less mature producing fields reservoir simulation models or simulations models in combination with decline analysis have been used for profiles generation.
Note that an independent third party, AGR Petroleum Services AS, has certified 1P and 2P reserves for all Aker BP assets except for the minor assets Atla and Enoch, representing 0.003 percent of total 2P reserves.
Aker BP ASA has a working interest in 36 fields/projects containing reserves, see Table 1 and 2. Out of these fields/projects, 25 are in the sub-class "On Production"/Developed, 10 are in the sub-class "Approved for Development"/Undeveloped and one is in the sub-class "Justified for Development"/Undeveloped. Note that several fields have reserves in more than one reserve sub-class.
| Field/project | Investment share | Operator | Resource class |
|---|---|---|---|
| Alvheim (Norwegian part, including Kameleon, Kneler and Viper/Kobra) | 65.00 % | Aker BP | On Production |
| Boa | 57.62 % | Aker BP | On Production |
| Bøyla | 65.00 % | Aker BP | On Production |
| Frosk Test Production | 65.00 % | Aker BP | On Production |
| Skogul | 65.00 % | Aker BP | On Production |
| Vilje | 46.90 % | Aker BP | On Production |
| Volund | 65.00 % | Aker BP | On Production |
| Volund P5 Sidetrack | 65.00 % | Aker BP | On Production |
| Ivar Aasen | 34.79 % | Aker BP | On Production |
| Johan Sverdup Phase 1 | 11.57 % | Equinor | On Production |
| Oda | 15.00 % | Spirit Energy | On Production |
| Skarv | 23.84 % | Aker BP | On Production |
| Skarv Gråsel | 23.84 % | Aker BP | On Production |
| Ærfugl A-1H | 23.84 % | Aker BP | On Production |
| Ærfugl Phase 1 | 23.84 % | Aker BP | On Production |
| Ærfugl Phase 2 | 23.84 % | Aker BP | On Production |
| Ærfugl Nord | 30.00 % | Aker BP | On Production |
| Tambar | 55.00 % | Aker BP | On Production |
| Tambar East | 46.20 % | Aker BP | On Production |
| Ula | 80.00 % | Aker BP | On Production |
| Ula A-10 Recompletion | 80.00 % | Aker BP | On Production |
| Hod | 90.00 % | Aker BP | On Production |
| Valhall | 90.00 % | Aker BP | On Production |
| Atla | 10.00 % | Total | On Production |
| Enoch | 2.00 % | Repsol Sinopec | On Production |
| Field/project | Investment share | Operator | Resource class |
|---|---|---|---|
| Alvheim Kameleon Gas Cap Blow Down | 65.00 % | Aker BP | Approved for Development |
| Kameleon Infill West | 65.00 % | Aker BP | Approved for Development |
| Kobra East/Gekko | 65.00 % | Aker BP | Approved for Development |
| Hanz | 35.00 % | Aker BP | Approved for Development |
| Johan Sverdup Phase 2 (incl WAG) | 11.57 % | Equinor | Approved for Development |
| Skarv LPP | 23.84 % | Aker BP | Approved for Development |
| Ærfugl LPP | 23.84 % | Aker BP | Approved for Development |
| Hod Field Development | 90.00 % | Aker BP | Approved for Development |
| Valhall Flank West V-11 Infill | 90.00 % | Aker BP | Approved for Development |
| Valhall New Central Platform | 90.00 % | Aker BP | Approved for Development |
| Frosk | 65.00 % | Aker BP | Justified for Development |
Total net proven reserves (1P/P90) as of 31 December 2021 to Aker BP ASA are estimated at 599 million barrels of oil equivalents. Total net proven plus probable reserves (2P/P50) are estimated at 802 million barrels of oil equivalents. The split between liquid and gas and between the different subcategories are given in tables 3 and 4.
| 1P / P90 (low estimate) | 2P / P50 (best estimate) | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Gross oil | Gross NGL | Gross gas Gross oil equiv Net oil equiv.Gross oil/cond Gross NGL | Gross gas Gross oil equiv Net oil equiv. | |||||||||
| 31.12.2021 | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | ||
| Alvheim (incl Boa) | 60 | - | 35 | 95 | 61 | 77 | - | 52 | 129 | 83 | ||
| Bøyla | 2 | - | -0 | 2 | 1 | 2 | - | 0 | 2 | 2 | ||
| Frosk | 6 | - | 0 | 6 | 4 | 16 | - | 1 | 17 | 11 | ||
| Skogul | 3 | - | 0 | 3 | 2 | 4 | - | 0 | 5 | 3 | ||
| Vilje | 9 | - | - | 9 | 4 | 13 | - | - | 13 | 6 | ||
| Volund | 4 | - | 0 | 4 | 3 | 7 | - | 1 | 8 | 5 | ||
| Alvheim Area | 83 | - | 36 | 119 | 75 | 120 | - | 54 | 174 | 110 | ||
| Ivar Aasen | 45 | 3 | 10 | 58 | 20 | 59 | 4 | 12 | 75 | 26 | ||
| Hanz | 9 | 1 | 2 | 12 | 4 | 15 | 1 | 3 | 20 | 7 | ||
| Ivar Aasen Area | 54 | 4 | 12 | 70 | 24 | 74 | 5 | 15 | 94 | 33 | ||
| Skarv | 12 | 16 | 73 | 102 | 24 | 15 | 19 | 91 | 125 | 30 | ||
| Gråsel | 6 | 0 | 2 | 8 | 2 | 8 | 1 | 4 | 12 | 3 | ||
| Ærfugl | 12 | 15 | 72 | 100 | 24 | 19 | 24 | 110 | 153 | 36 | ||
| Ærfugl Nord | 1 | 1 | 7 | 9 | 3 | 1 | 3 | 14 | 18 | 5 | ||
| Skarv Area | 31 | 33 | 154 | 218 | 53 | 43 | 47 | 219 | 308 | 75 | ||
| Tambar | 3 | 0 | 1 | 4 | 2 | 5 | 0 | 1 | 7 | 4 | ||
| Tambar East | - | - | - | - | - | 0 | 0 | 0 | 0 | 0 | ||
| Ula | 13 | 1 | - | 15 | 12 | 25 | 2 | - | 26 | 21 | ||
| Ula Area | 17 | 1 | 1 | 19 | 14 | 30 | 2 | 1 | 34 | 25 | ||
| Hod | 26 | 1 | 4 | 31 | 28 | 34 | 2 | 6 | 42 | 38 | ||
| Valhall | 176 | 9 | 32 | 216 | 195 | 228 | 11 | 42 | 281 | 253 | ||
| Valhall Area | 202 | 10 | 36 | 248 | 223 | 262 | 13 | 48 | 323 | 291 | ||
| Johan Sverdup | 1 726 | 32 | 41 | 1 799 | 208 | 2 207 | 48 | 51 | 2 305 | 267 | ||
| Oda | 8 | 0 | 1 | 9 | 1 | 12 | 0 | 1 | 14 | 2 | ||
| Atla Base | - | - | - | - | - | 0 | - | - | 0 | 0 | ||
| Enoch Base | - | - | - | - | - | 0 | - | - | 0 | 0 | ||
| Other (Atla, Enoch and Oda) | 8 | 0 | 1 | 9 | 1 | 13 | 0 | 1 | 14 | 2 | ||
| Total | 2 123 | 80 | 280 | 2 483 | 599 | 2 749 | 115 | 389 | 3 253 | 802 |
| Interest | 1P / P90 (low estimate) | 2P / P50 (best estimate) | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| On production | Gross oil/cond. Gross NGL | Gross gas Gross oil equiv Net oil equiv. | Gross oil | Gross NGL | Gross gas Gross oil equiv Net oil equiv. | ||||||
| 31.12.2021 | % | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) |
| Alvheim | 65.0 % | 34 | - | 5 | 39 | 26 | 41 | - | 8 | 49 | 32 |
| Boa | 57.6 % | 7 | - | 1 | 8 | 5 | 11 | - | 2 | 12 | 7 |
| Bøyla | 65.0 % | 2 | - | -0 | 2 | 1 | 2 | - | 0 | 2 | 2 |
| Frosk Test Production | 65.0 % | - | - | - | - | - | 7 | - | 0 | 7 | 5 |
| Skogul | 65.0 % | 3 | - | 0 | 3 | 2 | 4 | - | 0 | 5 | 3 |
| Vilje | 46.9 % | 9 | - | - | 9 | 4 | 13 | - | - | 13 | 6 |
| Volund | 65.0 % | 3 | - | 0 | 4 | 2 | 6 | - | 1 | 7 | 4 |
| Volund P5 Sidetrack | 65.0 % | 1 | - | 0 | 1 | 0 | 1 | - | 0 | 1 | 1 |
| Ivar Aasen | 34.8 % | 45 | 3 | 10 | 58 | 20 | 59 | 4 | 12 | 75 | 26 |
| Johan Sverdup Phase 1 | 11.6 % | 1 349 | 32 | 40 | 1 421 | 164 | 1 607 | 43 | 46 | 1 696 | 196 |
| Oda | 15.0 % | 8 | 0 | 1 | 9 | 1 | 12 | 0 | 1 | 14 | 2 |
| Skarv | 23.8 % | 12 | 15 | 68 | 95 | 23 | 13 | 17 | 81 | 111 | 27 |
| Skarv Gråsel | 23.8 % | 6 | 0 | 2 | 8 | 2 | 8 | 1 | 4 | 12 | 3 |
| Ærfugl A-1H | 23.8 % | 3 | 5 | 23 | 31 | 7 | 6 | 7 | 35 | 48 | 11 |
| Ærfugl Phase 1 | 23.8 % | 8 | 9 | 42 | 58 | 14 | 12 | 13 | 60 | 84 | 20 |
| Ærfugl Phase 2 | 23.8 % | 1 | 1 | 6 | 8 | 2 | 1 | 2 | 10 | 14 | 3 |
| Ærfugl Nord | 30.0 % | 1 | 1 | 7 | 9 | 3 | 1 | 3 | 14 | 18 | 5 |
| Tambar | 55.0 % | 3 | 0 | 1 | 4 | 2 | 5 | 0 | 1 | 7 | 4 |
| Tambar East | 46.2 % | - | - | - | - | - | 0 | 0 | 0 | 0 | 0 |
| Ula | 80.0 % | 12 | 1 | - | 13 | 10 | 21 | 2 | - | 22 | 18 |
| Ula A-10 Recompletion | 80.0 % | 2 | 0 | - | 2 | 2 | 4 | 0 | - | 4 | 3 |
| Hod | 90.0 % | 2 | 0 | 0 | 2 | 2 | 2 | 0 | 0 | 3 | 3 |
| Valhall | 90.0 % | 158 | 7 | 28 | 194 | 174 | 200 | 9 | 35 | 245 | 221 |
| Atla | 10.0 % | - | - | - | - | - | 0 | - | - | 0 | 0 |
| Enoch | 2.0 % | - | - | - | - | - | 0 | - | - | 0 | 0 |
| Total | 1 669 | 75 | 232 | 1 977 | 467 | 2 037 | 103 | 310 | 2 450 | 601 |
| Interest | 1P / P90 (low estimate) | 2P / P50 (best estimate) | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Justified for development | Gross oil/cond. Gross NGL | Gross gas Gross oil equiv Net oil equiv.Gross oil/cond Gross NGL | Gross gas Gross oil equiv Net oil equiv. | ||||||||
| 31.12.2021 | % | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) | (mmboe) |
| Frosk | 23.8 % | 6 | - | 0 | 6 | 4 | 9 | - | 1 | 10 | 6 |
| Total | 6 | - | 0 | 6 | 4 | 9 | - | 1 | 10 | 6 |
| Total reserves 31.12.2021 | 599 | 802 |
|---|---|---|
| Total reserves 31.12.2020 | 641 | 842 |
Changes from the 2020 reserve report are summarized in Table 5. During 2021, Aker BP 2P reserves were reduced by 40 mmboe from 842 to 802 mmboe. The production was 76 mmboe. Thus, net reserves increases were 36 mmboe. The main reasons for increased net reserve estimate (i.e. disregarding the produced volumes) are the KEG- and Froskdevelopements, drilling of more wells in Valhall and initiatives to increase recovery from existing or already decided projects, primarily in the Alvheim-area. On the negative side, reserves were reduced in both Ærfugl and Ivar Aasen due to poorer than expected reservoir performance.
An oil price of 67 USD/bbl (2022), 65 USD/bbl (2022) and 65 USD/bbl (following years) has been used for reserves estimation. Low- and high case sensitivities with oil prices of 35 USD/bbl and 90 USD/bbl, respectively, have been performed by AGR. This had a moderate effect on the reserves estimates. The low price resulted in a reduction in total net proven (1P/P90) reserves of 25 % and net proven plus probable (2P/P50) reserves of 17 %. The high oil price scenario resulted in a marginal increase in reserves of less than 2% to the proven (1P/P90)- or proven plus probable (2P/P50)-estimates.
| Net attributed million barrels of oil equivalent | On production | Approved for devlop. | Justified for devlop. | Total | ||||
|---|---|---|---|---|---|---|---|---|
| (mmboe) | 1P/P90 | 2P/P50 | 1P/P90 | 2P/P50 | 1P/P90 | 2P/P50 | 1P/P90 | 2P/P50 |
| Balance as of 31.12.2020 | 511 | 647 | 128 | 192 | 2 | 3 | 641 | 842 |
| Production | -76 | -76 | - | - | - | - | -76 | -76 |
| Transfer | 30 | 43 | -28 | -40 | -2 | -3 | 0 | 0 |
| Revisions | 1 | -14 | -4 | -2 | - | - | -3 | -15 |
| IOR | 0 | 1 | 6 | 10 | - | - | 6 | 11 |
| Discovery and extensions | - | - | 26 | 33 | 4 | 6 | 30 | 40 |
| Acquisition and sale | - | - | - | - | - | - | - | - |
| Balance as of 31.12.2021 | 466 | 601 | 128 | 194 | 4 | 6 | 599 | 802 |
| Delta | -44 | -45 | -0 | 2 | 2 | 3 | -42 | -40 |
Note also that production numbers are preliminary pr October 2021, leaving numbers for the last two months of 2021 as estimates. The final numbers may be slightly different.
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 and the group's financial statements for 2021 have been prepared in accordance with IFRS, as adopted by the EU, and requirements in accordance with the Norwegian Accounting Act. The information presented in the financial statements gives a true and fair view of the company's liabilities, financial position and results overall.
To the best of our knowledge, the Board of Directors' Report gives a true and fair view of the development, performance and financial position of the company, and includes a description of the principal risk and uncertainty factors facing the company and the group. Additionally, we confirm to the best of our knowledge that the report 'Payment to governments' as provided in a separate section in this annual report has been prepared in accordance with the requirements in the Norwegian Securities Trading Act Section 5-5a with pertaining regulations.
Akerkvartalet, 8 March 2022 The Board of Directors and the CEO of Aker BP ASA, Akerkvartalet, 8 March 2022
ØYVIND ERIKSEN Chairman of the Board
Kate Thomson, Board member Murray Auchincloss, Board member PAULA DOYLE Board member
Paula Doyle, Board member Terje Solheim, Board member
INGARD HAUGEBERG Board member
Øyvind Eriksen, Chairman of the Board Kjell Inge Røkke, Board member
ANNE MARIE CANNON Deputy Chair
KATE THOMSON Board member
TORE VIK Board member
KJELL INGE RØKKE Board member
MURRAY AUCHINCLOSS Board member
HILDE KRISTIN BREVIK Board member
TROND BRANDSRUD Board member
TERJE SOLHEIM Board member
KARL JOHNNY HERSVIK Chief Executive Officer
Aker BP may disclose alternative performance measures as part of its financial reporting as a supplement to the financial statements prepared in accordance with IFRS. Aker BP believes that the alternative performance measures provide useful supplemental information to management, investors, security analysts and other stakeholders and are meant to provide an enhanced insight into the financial development of Aker BP's business operations and to improve comparability between periods.
Abandonment spend (abex) is payment for removal and decommissioning of oil fields1)
Capex is disbursements on investments in fixed assets1)
Depreciation per boe is depreciation divided by number of barrels of oil equivalents produced in the corresponding period
Dividend per share (DPS) is dividend paid during the year divided by number of shares outstanding
EBITDA is short for earnings before interest and other financial items, taxes, depreciation and amortisation and impairments
EBITDAX is short for earnings before interest and other financial items, taxes, depreciation and amortisation, impairments and exploration expenses
Equity ratio is total equity divided by total assets
Exploration spend (expex) is exploration expenses plus additions to capitalized exploration wells less dry well expenses1)
Interest coverage ratio is calculated as twelve months rolling EBITDA, divided by interest expenses, excluding any impacts from IFRS 16.
Leverage ratio is calculated as Net interest-bearing debt divided by twelve months rolling EBITDAX, excluding any impacts from IFRS 16
Net interest-bearing debt is book value of current and non-current interest-bearing debt less cash and cash equivalents
Operating profit/loss is short for earnings/loss before interest and other financial items and taxes
Production cost per boe is production cost basd on produced volumes, divided by number of barrels of oil equivalents produced in the corresponding period (see note 5)
1) Includes payments of lease debt as disclosed in note 24.
| Intro | Assets | BoD & EMT | BoD's report | Payments to governments | Corporate governance |
|---|---|---|---|---|---|
| (USD 1 000) | Note | 2021 | 2020 |
|---|---|---|---|
| Abandonment spend | |||
| Payment for removal and decommissioning of oil fields | 172 512 | 150 306 | |
| Payments of lease debt (abandonment activity) | 24 | 31 715 | 27 660 |
| Abandonment spend | 204 227 | 177 966 | |
| Depreciation per boe | |||
| Depreciation | 12 | 964 083 | 1 121 818 |
| Total produced volumes (boe 1 000) | 5 | 76 439 | 77 101 |
| Depreciation per boe | 12.6 | 14.6 | |
| Dividend per share | |||
| Paid dividend | 487 500 | 425 000 | |
| Number of shares outstanding | 359 643 | 359 808 | |
| Dividend per share | 1.36 | 1.18 | |
| Capex | |||
| Disbursements on investments in fixed assets (excluding capitalized interest) | 1 376 879 | 1 238 601 | |
| Payments of lease debt (investments in fixed assets) | 24 | 50 423 | 67 125 |
| CAPEX | 1 427 302 | 1 305 727 | |
| EBITDA | |||
| Total income | 4 | 5 668 747 | 2 979 263 |
| Production costs | 5 | -745 313 | -627 975 |
| Exploration expenses | 6 | -353 034 | -174 099 |
| Other operating expenses | -29 261 | -49 457 | |
| EBITDA | 4 541 139 | 2 127 731 | |
| EBITDAX | |||
| Total income | 4 | 5 668 747 | 2 979 263 |
| Production costs | 5 | -745 313 | -627 975 |
| Other operating expenses | -29 261 | -49 457 | |
| EBITDAX | 4 894 173 | 2 301 830 | |
| Equity ratio | |||
| Total equity | 2 341 891 | 1 987 281 | |
| Total assets | 14 469 895 | 12 420 091 | |
| Equity ratio | 16% | 16% | |
| Exploration spend | |||
| Disbursements on investments in capitalized exploration expenditures | 177 464 | 127 283 | |
| Exploration expenses | 6 | 353 034 | 174 099 |
| Dry well | 6 | -98 827 | -56 626 |
| Payments of lease debt (exploration expenditures) | 24 | 1 858 | 874 |
| Exploration spend | 433 529 | 245 629 |
| (USD 1 000) | Note | 2021 | 2020 |
|---|---|---|---|
| Interest coverage ratio | |||
| Twelve months rolling EBITDA | 4 541 139 | 2 127 731 | |
| Twelve months rolling EBITDA, impacts from IFRS 16 | 24 | -14 035 | -23 438 |
| Twelve months rolling EBITDA, excluding impacts from IFRS 16 | 4 527 104 | 2 104 293 | |
| Twelve months rolling interest expenses | 9 | 145 651 | 184 501 |
| Twelve months rolling amortized loan cost | 9 | 22 460 | 19 813 |
| Twelve months rolling interest income | 9 | 2 481 | 3 763 |
| Net interest expenses | 165 630 | 200 552 | |
| Interest coverage ratio | 27.3 | 10.5 | |
| Leverage ratio | |||
| Long-term bonds | 20 | 3 576 735 | 3 968 566 |
| Cash and cash equivalents | 18 | 1 970 906 | 537 801 |
| Net interest-bearing debt excluding lease debt | 1 605 829 | 3 430 766 | |
| Twelve months rolling EBITDAX | 4 894 173 | 2 301 830 | |
| Twelve months rolling EBITDAX, impacts from IFRS 16 | 24 | -12 177 | -22 564 |
| Twelve months rolling EBITDAX, excluding impacts from IFRS 16 | 4 881 996 | 2 279 266 | |
| Leverage ratio | 0.33 | 1.51 | |
| Net interest-bearing debt | |||
| Long-term bonds | 20 | 3 576 735 | 3 968 566 |
| Long-term lease debt | 24 | 91 835 | 131 856 |
| Short-term lease debt | 24 | 44 378 | 83 904 |
| Cash and cash equivalents | 18 | 1 970 906 | 537 801 |
| Net interest-bearing debt | 1 742 042 | 3 646 526 |
Production cost per boe see note 5
KPMG AS Sørkedalsveien 6 Postboks 7000 Majorstuen 0306 Oslo
Telephone +47 45 40 40 63 Fax Internet www.kpmg.no Enterprise 935 174 627 MVA
To the General Meeting of Aker BP ASA
We have audited the financial statements of Aker BP ASA (the "Company"), together with its subsidiaries (the "Group"). The financial statements comprise:
• The financial statements of the Company and Group, which comprise the statement of financial position as at 31 December 2021, the income statement, statement of comprehensive income, statement of changes in equity and statement of cash flows for the year then ended, and notes to the financial statements, including a summary of significant accounting policies.
Our opinion is consistent with our additional report to the Audit Committee.
We conducted our audit in accordance with International Standards on Auditing (ISAs). Our responsibilities under those standards are further described in the Auditor's Responsibilities for the Audit of the Financial Statements section of our report. We are independent of the Company and the Group as required by laws and regulations and the International Ethics Standards Board for Accountants' International Code of Ethics for Professional Accountants (including International Independence Standards) (IESBA Code), and we have fulfilled our other ethical responsibilities in accordance with these requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.
To the best of our knowledge and belief, no prohibited non-audit services referred to in the Audit Regulation (537/2014) Article 5.1 have been provided.
We have been the auditor of the Company for 7 years from the election by the general meeting of the shareholders on 7 April 2014 for the accounting year 2014.
Key audit matters are those matters that, in our professional judgment, were of most significance in our audit of the financial statements of the current period. These matters were addressed in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters.
| uinuss in. | |||||
|---|---|---|---|---|---|
| KPMG AS, a Norwegian limited liability company and member firm of the KPMG network of independent member firms affiliated | olaC | Elverum | Mo i Rana | Stord | |
| with KPMG International Cooperative ("KPMG International"), a Swiss entity. | Alta | Finnsnes | Molde | Straume | |
| Arendal | Hamar | Skien | Tromsø | ||
| Statsautoriserte revisorer - medlemmer av Den norske Revisorforening | Bergen | Haugesund | Sandefiord | Trondheim | |
| Bodø | Knarvik | Sandnessjøen | Tynset | ||
| Drammen | Kristiansand | Stavanger | Alesund |
Refer to Board of Directors' report and financial statement Note 1.3 (Important accounting judgments, estimates and assumptions), Note 1.12 (Impairment accounting policy) and Note 13 (Impairments).
| The key audit matter | How the matter was addressed in our audit |
|---|---|
| The recoverable amounts of producing licence | For each producing licence cash generating unit |
| assets and the associated goodwill are sensitive | where a material risk of impairment or reversal |
| to changes in assumptions, in particular oil and | was identified, we critically assessed the key |
| gas prices, discount rate and forecast | elements of the cash flow forecasts, including: |
| operational performance including the volumes | • |
| of oil and gas to be produced and licence | production profiles with reference to |
| related expenditures. Any negative | reserves estimates prepared by the |
| developments in these assumptions and | Company's reservoir engineers and third |
| forecasts may be an impairment trigger, even if | party reserves certification reports; |
| other factors have moved favourably. Similarly, | • |
| positive developments in such assumptions and | three-year oil and gas prices with reference |
| forecasts may be a trigger to reverse previously | to forward curve data and the Company's |
| recognised impairments. | long term oil price assumptions against |
| In addition, the goodwill balances allocated to | benchmark data from third party analysts; |
| producing licence cash generating units will be | • |
| subject to impairment charges over time as the | opex and capex expenditures with reference |
| related oil and gas reserves are produced. | to historical forecasts, approved licence |
| Impairment of goodwill is not reversed. | budgets and management forecasts; and |
| Management's determination of the recoverable | • |
| amounts of producing licence assets requires a | abandonment expenditures with reference |
| number of estimates and assumptions relating to | to our audit work on the abandonment |
| operational and market factors, some of which | provision. |
| involve a high degree of judgment. In addition, | In addition, KPMG valuation specialists |
| the calculation of recoverable amounts requires | assessed the mathematical and methodological |
| complex financial modelling of the cash flows of | integrity of management's impairment models, |
| each cash generating unit. | including the modelling of tax related cash flows. |
| Significant auditor judgment is required when | We also considered whether the disclosures |
| evaluating whether the recoverable amounts, | regarding key assumptions and sensitivities |
| and the assumptions which drive the underlying | adequately reflected the underlying impairment |
| cash flow estimates, are reasonable and | assessments and reasonably possible changes |
| supportable. | in assumptions. |
The Board of Directors and the Managing Director (management) are responsible for the information in the Board of Directors' report and the other information accompanying the financial statements. The other information comprises information in the annual report, but does not include the financial statements and our auditor's report thereon. Our opinion on the financial statements does not cover the information in the Board of Directors' report nor the other information accompanying the financial statements.
In connection with our audit of the financial statements, our responsibility is to read the Board of Directors' report and the other information accompanying the financial statements. The purpose is to consider if there is material inconsistency between the Board of Directors' report and the other information accompanying the financial statements and the financial statements or our knowledge obtained in the audit, or whether the Board of Directors' report and the other accompanying information otherwise appears to be materially misstated. We are required to report if there is a material misstatement in the Board of Directors' report or the other information accompanying the financial statements. We have nothing to report in this regard.
Independent Auditor's Report - Aker BP ASA
Based on our knowledge obtained in the audit, it is our opinion that the Board of Directors' report
Our opinion on the Board of Director's report applies correspondingly to the statements on Corporate Governance and Corporate Social Responsibility, and to the report on payments to governments.
Management is responsible for the preparation of financial statements that give a true and fair view in accordance with International Financial Reporting Standards as adopted by the EU, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.
In preparing the financial statements, management is responsible for assessing the Company's and the Group's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Group or to cease operations, or has no realistic alternative but to do so.
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with ISAs will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these financial statements.
As part of an audit in accordance with ISAs, we exercise professional judgment and maintain professional scepticism throughout the audit. We also:
We communicate with the Board of Directors regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.
We also provide the Audit Committee with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards.
From the matters communicated with the Board of Directors, we determine those matters that were of most significance in the audit of the financial statements of the current period and are therefore the key audit matters. We describe these matters in our auditor's report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication.
We have performed an assurance engagement to obtain reasonable assurance that the financial statements with file name 549300NFTY73920OYK69-2021-12-31-en have been prepared in accordance with Section 5-5 of the Norwegian Securities Trading Act (Verdipapirhandelloven) and the accompanying Regulation on European Single Electronic Format (ESEF).
In our opinion, the financial statements have been prepared, in all material respects, in accordance with the requirements of ESEF.
Management is responsible for preparing, tagging and publishing the financial statements in the single electronic reporting format required in ESEF. This responsibility comprises an adequate process and the internal control procedures which management determines is necessary for the preparation, tagging and publication of the financial statements.
Our responsibility is to express an opinion on whether the financial statements have been prepared in accordance with ESEF. We conducted our work in accordance with the International Standard for Assurance Engagements (ISAE) 3000 – "Assurance engagements other than audits or reviews of historical financial information". The standard requires us to plan and perform procedures to obtain reasonable assurance that the financial statements have been prepared in accordance with the European Single Electronic Format.
As part of our work, we performed procedures to obtain an understanding of the company's processes for preparing its financial statements in the European Single Electronic Format. We evaluated the completeness and accuracy of the iXBRL tagging and assessed management's use of judgement. Our work comprised reconciliation of the financial statements tagged under the European Single Electronic Format with the audited financial statements in human-readable format. We believe that the evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.
Oslo, 8 March 2022 KPMG AS
Roland Fredriksen State Authorised Public Accountant
4
Please contact Senior Vice President HSSEQ, Marit Blaasmo, if you have any questions.
[email protected] Tel: +47 416 87 486
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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