Aker BP

Annual Report • Mar 26, 2020

ANNUAL REPORT 2019

3 · Aker BP Annual Report 2019 –

Highlights 2019	4
Letter from the CEO	8
Key Figures 2019	11
A Focused Portfolio	13
Board of Directors	41
Executive Management Team	45
Board of Directors' Report	50
Reporting of Payments to Governments	71
The Board of Directors' Report on Corporate Governance	73
Financial statements	83

11
50
71

CONTENTS

HIGHLIGHTS 2019 I Q1 HIGHLIGHTS 2019 I Q2

the rst to be delivered under the wellhead platform alliance between Aker BP, Aker Solutions, Kværner and ABB.

7 APRIL – ULA DERRICK

14 JUNE – VALHALL QP

11 NOVEMBER - FULL SPEED AHEAD FOR ÆRFUGL PHASE 2

HIGHLIGHTS 2019 I Q3 HIGHLIGHTS 2019 I Q4

Energy Agency (IEA) Sustainable Development Scenario, oil and gas will continue to account for almost 50 percent of the energy mix in 2040. This is a scenario that is fully aligned with the Paris Agreement on Climate Change.

If providing funding for climate change policies is one of society's greatest challenges, the petroleum industry's greatest contribution must be to generate income that society can spend on effective climate measures. As an industry, the Norwegian oil and gas sector is already a unique contributor to society: For each NOK 100 in increased profitability, NOK 78 is returned to our community. It is in this way that our industry will provide a much-needed contribution to fund the energy transition.

Aker BP's most important contributions to the energy transition are three-fold: First, we are efficient producers, and so return greater value from oil and gas resources to our stakeholders. Second, we continuously improve energy efficiency throughout our operations, thus contributing to reduced emissions globally. And finally, we share our know-how, data, and technology with other industries.

A transitioning world will need the most carbon- and cost-effective barrels of oil that can be produced. To be cost-effective is also the best way to prepare for volatile markets and challenging circumstances. Here are some highlights from our achievements in 2019.

RESPONDING TO THE CORONAVIRUS SITUATION

Aker BP is closely monitoring the development in the spread of the coronavirus and has mobilized significant resources to manage the situation. The top priority is to protect the health and safety of our people, and to maintain safe and reliable operations across our activities.

Our initial response was to mobilize our emergency response organization to respond to the coronavirus situation. Subsequently a separate task force with significant resources has been mobilized to handle and normalize the situation. Instructions to all employees, intended to minimize the risk of the virus spreading among the company's employees and contractors have been developed and are continuously updated. In parallel we have established and are maintaining contingency plans to make sure we are prepared in case of an escalation of the situation.

In parallel to managing the operational side of the current situation, we are taking measures to protect the company's financial strength. This process involves a comprehensive evaluation of the company's business plan.

OUR CONTRIBUTION TO THE ENERGY TRANSITION

In 2019, the focus on climate change intensified. The world faces a two-pronged challenge: The global population is projected to grow by two billion by 2050, resulting in a rising demand for energy. Over the same period, however, CO2 emissions must be significantly reduced. According to the IPCC, over the next decade, global climate gas emissions must be halved if we are to succeed in halting global warming.

Undoubtedly, investments in the oil and gas sector will be a vital part of the energy transition. According to the International

STRONG OPERATIONAL PERFORMANCE

In 2019, Aker BP achieved outstanding operational results. Production efficiency was 92 percent. In the fourth quarter of 2019, net production was 191.1 mboepd. This figure, a new all-time high for Aker BP, reflects the successful startup of production from the Johan Sverdrup field. For the year 2019, the company's net production averaged 155.9 mboepd.

improve our safety performance compared to previous years. The serious-incident frequency, measured as incidents per million hours worked, was 0.6 in 2019.

Health, safety, security and environment issues are always the number one priority at Aker BP. In 2019, we continued to Aker BP's goal is to produce oil and gas as efficiently as possible to return greater value from our oil and gas resources to stakeholders. In 2019, Aker BP's CO2 intensity was below 7 kg CO2/boe (equity share), less than half the global industry average, and below the average for Norwegian continental shelf operators. From 2020 on, we aim to deliver an emission intensity below 5 kg CO2/boe.

When I originally wrote this letter, the purpose was to provide an update on Aker BP's achievements in 2019, and to demonstrate the value creation potential of the company. It is however impossible to ignore the dramatic events that have taken place in the beginning of 2020. The coronavirus outbreak represents a significant threat to public health as well as a severe disruption to the global economy, including the oil market and Aker BP's operations. Our top priority in this situation is to protect our people and our operations. RETURN VALUE

Produce efficiently to return high value from oil & gass resources to our stakeholders

Reduce emissions from our operations focusing on the total footprint

Aker BP had 2P reserves of 906 mmboe at the close of 2019, while our 2C contingent resources were 931 mmboe. We are thus positioned very favorably for further organic growth. Aker BP has a strong history of value-accretive mergers and acquisitions. However, over the past two years we have found it significantly more attractive to explore and develop our own resources.

Aker BP has emerged as a leading explorer, and in 2019, we were the top discoverer on the Norwegian continental shelf. We drilled 16 exploration wells and participated in 6 discoveries. Our net discovered volumes as of year-end 2019 amounted to approximately 170 mmboe. All in all, we have built a very strong resource base around our existing assets, providing the opportunity for robust profitable growth over the next five to ten years.

STRATEGIC VALUE CREATION

As of year-end 2019, Aker BP has established a total of eight alliances. We concluded 2019 with our first major alliance project producing its first oil. Through the development of Valhall Flank West, the wellhead platform alliance comprising Aker BP, Kvaerner, Aker Solutions, and ABB set a new standard for delivery of flank developments on the Norwegian continental shelf. We see significant potential for further improvement, efficiency, and value creation through applying our alliance model to future projects.

The Ærfugl field, which produces via the Skarv FPSO, is one of the most profitable development projects on the Norwegian continental shelf, with a break-even price of approximately USD 15 per barrel. Towards year-end 2019, Aker BP and our partners decided to proceed with Phase 2 of the Ærfugl project, three years ahead of the original schedule. The collaboration with our partners in the Subsea Alliance, Subsea 7 and Aker Solutions, allowed for this acceleration.

Perhaps of even greater importance in our improvement strategy is digitalization. In 18 months, we have established the Eureka digital lab, Aker BP's center of excellence for digital projects and host of unique digital competence. Our collaboration with Cognite and the industrial data platform "Cognite Data Fusion" is a proven success. Our next digitalization step will be to gather all Aker BP digital projects and initiatives under the Eureka umbrella, and accelerate roll-out of the resulting products to our operations.

CREATING VALUE FOR SHAREHOLDERS AND SOCIETY

The operational activities and continuous efforts to drive improvements in all aspects of our business — outlined above — generated considerable value in 2019. Profit before taxes amounted to USD 1,084 million in 2019. Tax expense was USD 943 million. Aker BP reported a net profit of USD 141 million for the full year 2019. Aker BP paid out USD 750 million in dividends in 2019. Total shareholder return on the Aker BP share was 42 percent.

We entered 2020 with a robust financial position. Our net production target for 2020 is 205-220 mboepd, and we aim for a production cost of USD ~10/boe.

INVEST IN THE SOLUTION

The world will continue to need oil and gas for the foreseeable future. The future will require more efficient oil and gas production. The winners in the oil and gas market of the future will be the companies that succeed in lowering emissions while reducing costs. This profile is a perfect fit for Aker BP's strategy. As a pure play oil and gas company, Aker BP aims to continue returning value through efficient production, reduced emissions, and sharing of data, know-how and technology with other industries.

I would like to thank the Aker BP team for their dedication, efforts and enthusiasm in 2019. In 2020 the challenges we face are quite different, but I am convinced that we have the right strategy, people and partners to navigate safely through the difficult times. And I am also convinced that when this is over, Aker BP will be an even stronger company, ready to deliver on our ambitious goals and to be a valuable contributor to the energy transition.

Karl Johnny Hersvik CEO, Aker BP ASA

KEY FIGURES 2019

SUMMARY OF FINANCIAL RESULTS

Key figures	Unit	2019	2018*	2017
Total income	USDm	3 347	3 752	2 563
EBITDA	USDm	2 286	2 745	1 786
Net profit/loss	USDm	141	476	275
Earnings per share (EPS)	USD	0.39	1.32	0.81
Capex	USDm	1 667	1 202	888
Exploration spend	USDm	501	359	262
Abandonment spend	USDm	109	243	86
Production cost	USD/boe	12.4	12.1	10.3
Taxes paid	USDm	619	606	101
Net interest-bearing debt**	USDm	3 493	1 973	3 156
Leverage ratio	-	1.2	0.6	1.4

SUMMARY OF PRODUCTION

Key figures	Unit	2019	2018	2017
Alvheim (65%)	boepd	39 183	40 724	53 849
Bøyla (65%)	boepd	4 071	2 913	4 357
Gina Krog (3.3%)	boepd	1 719	1 748	798
Hod (37.5%)	boepd	839	937	530
Ivar Aasen (34.8%)	boepd	21 810	23 523	18 100
Johan Sverdrup (11.6%)	boepd	7 945	-	-
Oda (15%)	boepd	1 770	-	-
Skarv (23.8%)	boepd	22 260	25 344	26 680
Tambar/Tambar East (55%/46.2%)	boepd	2 243	3 402	1 941
Ula (80%)	boepd	4 517	6 032	6 466
Valhall (36.0%)	boepd	38 166	35 041	13 357
Vilje (46.9%)	boepd	2 326	4 034	5 304
Volund (65%)	boepd	8 858	11 842	7 342
Other (Atla, Enoch)	boepd	145	118	103
SUM	boepd	155 852	155 658	138 825
Realized price liquids	USD/boe	64.8	70.8	55.1
Realized price natural gas	USD/scm	0.18	0.29	0.21

* Total income, EBITDA, EPS and net profit figures for 2018 are restated, see note 1 in Financial Statements.

** The definition of net interest-bearing debt includes Lease debt, which is recognized from Q1 2019 following the implementation of IFRS 16 Leases. The comparative figures for previous periods have not been restated. See also the description of "Alternative performance measures" at the end of the Financial Statements for definitions.

UNLOCKING THE POTENTIAL OF VALHALL

Removal of topsides, a technological world's first and Valhall Flank West on stream. It has been an eventful year, and the modernization of Valhall has only just begun.

2019 started off with tree simultaneous drilling operations on Valhall and Hod, which gave a good indication of the activity level for the year. Extensive planning and project management in the first half of the year culminated in the safe removal of QP, the original accommodation platform at Valhall. This was the first of the original structures at Valhall to be removed as part of the modernization of the Valhall field center.

Another major project this year was planning and execution of a turnaround. Inspections, upgrades and structural maintenance and modifications were carried out during the 34-day shutdown.

Full Wi-Fi coverage was installed at the Valhall field center in 2019 and handheld units are now used by operators to increase efficiency. New areas of use are constantly being discovered, and continuous development is done in the digitalization process.

VALHALL FLANK WEST ON STREAM

The Valhall Flank West jacket was installed on the field in May 2019 and the topsides followed the next month. The topside module was installed just 14 months after the first steel was cut at Kværner's yard in Verdal.

ALLIANCE STRATEGY DELIVERS RESULTS

Valhall Flank West is a benchmark for good project execution. Reorganization of the value chain through strategic partnerships and alliances is an important part of Aker BP's strategy. Four alliances contributed to the project and demonstrated a reduced number of engineering hours, reduced costs and reduced construction time compared with similar projects. And most importantly, the work was performed without any serious harm to people or the environment.

Production from Valhall Flank West started in December. The rest of the planned wells will be put on stream as they are completed, and work continues to further increase the value of the field.

INDUSTRY'S FIRST WITH STIMULATION METHOD

Valhall Flank West is a wellhead platform that will normally be unmanned. It receives power from shore via the Valhall field centre, in line with Aker BP's strategy of minimising its CO2 emissions from operations. Another method, Fishbones Stimulation Technology, was also successfully applied for the first time on Valhall. These new technologies are vital elements in the strategy to increase drainage from tight reservoirs in the Valhall area.

In November, Aker BP became the first company ever to successfully use a new well stimulation method offshore on the G10 well on Valhall. The Single-Trip Multi-Frac method had previously only been used onshore, and several challenges had to be solved to apply it in North Sea conditions.

While the traditional method takes two to three days to stimulate one zone of the reservoir, Aker BP can now do two zones in a day, making only one trip down into the reservoir with the coiled tubing. This method was also successfully applied on the first well on Valhall Flank West. Single-Trip Multi-Frac significantly reduces the cost of the well because less time is needed for use of vessels and equipment.

Bringing Valhall Flank West on stream is an important step towards achieving Aker BP's ambition of another billion barrels from Valhall. A transformation is underway, as we remove old platforms from the field center, invest in new wells, plug old wells and actively seek new business opportunities.

VALHALL AREA THE

«2019 was an important step into a new chapter of the Valhall story. We introduced new technology within well stimulation, further developed the field through Flank West and finally started the decommissioning of old facilities by removing the old quarters platform.»

Per Mikal Hauge

VP Valhall Operations and Asset Development

PRODUCTION 2019 PRODUCTION EFFICIENCY

HIGHLIGHTS FROM 2019

15 January Three simultaneous drilling operations on Valhall and Hod

7 May Valhall Flank West jacket installed

14 June Valhall QP topsides is safely removed, as part of the modernization of the Valhall Field Center

22 June The Valhall Flank West topsides is installed, just 14 months after the first steel was cut at Kværner's yard in Verdal

20 June Successful «Walk to work» campaign. The first stage of the hook-up phase on Valhall Flank West was carried out with a personnel gangway from a vessel to the unmanned platform

November World's first: Single-Trip Multi-Frac used to stimulate offshore well

16 December Valhall Flank West starts production

Valhall Hod

Net 2P Reserves: 322 mmboe

Valhall Area

Valhall SSPR NORPIPE Y

Hod – PL 033 Aker BP: 90 % Partner: Pandion 2P reserves: 35 mmboe (net)

Embla Flank

North

Flank West

Flank South

Eldfisk

Ekofisk

Edda

Vest ekofisk

Production history (mboepd gross)

Hod Deep West

Producing field Field development

UPDATED FOR AN EXTENDED LIFETIME

Ula acts as a third-party host for the subsea fields Oda and Blane. The Oda field, which is operated by Spirit Energy, started production in March 2019, three months ahead of plan. The field is processed at Ula and Aker BP holds a 15 percent share in the license. Extensive modifications have been made to the inlet facilities previously used for Oselvar in order to receive and treat the Oda wellstream.

Gas from the Oda reservoir is purchased by the Ula license and is injected into the Ula reservoir to increase oil recovery from the field, in line with Aker BP's strategy to maximize recovery.

Start-up of the Oda field and gas lift on Tambar resulted in a significant increase in production throughput over Ula, reaching 53,000 barrels of oil equivalents per day towards the end of the year. In addition, the Ula D platform has undergone major modifications to facilitate the ongoing drilling campaign from a heavy-duty jack-up rig. infill drilling campaign. After 33 years of service, the original drilling derrick and substructure were successfully removed by the Saipem 7000 heavy lift vessel. Drilling commenced in July and future drilling will be done by jack-up rigs. IMPROVING TECHNICAL CONDITION

GAS LIFT ON TAMBAR

Start-up of artificial gas lift on Tambar was another important milestone for the year. This increases oil recovery from the field and is expected to extend the production profile.

NEW DRILLING CAMPAIGN

Aker BP carried out extensive modifications to prepare for the arrival of the Maersk Integrator heavy duty jack-up rig for the

The strategy to improve the technical condition of the facilities and address obsolescence continues into 2020. One major modification project is the replacement of the entire power plant on Ula, using a piece small execution strategy. The first of three gas turbine power units has been completed.

The high activity on the field resulted in higher levels of manning than Ula has seen since the original installation in 1986, with over 300 people in the field. The Safe Scandinavia flotel, which had been providing additional temporary accommodation, was demobilized in May. has significant upside potential. Aker BP is working diligently to mature scenarios to maximize the value of the Ula area and for further development of the Ula hub facilities.

SAILING SMARTER

Aker BP has established a new shared logistics supply concept in the southern North Sea to support Ula, Tambar, Valhall, Gyda and exploration drilling in the vicinity.

As the activity surged in 2019, smarter use of the vessel fleet has been achieved, instead of increasing the number of vessels. This was accomplished through improved schedules and routes to provide flexibility and capacity, and thereby reduce unit costs.

MATURING OPPORTUNITIES

Aker BP will continue to mature the King Lear discovery located south of Ula and considers that the area around King Lear

«During 2019, we demonstrated Aker BP's commitment to revitalizing the Ula area. We started drilling again for the first time in many years, are making good progress on modernizing our obsolete power plant, and we have started work to understand what a future redevelopment of Ula might look like.»

Richard Miller

VP Operations and Asset Development Ula

PRODUCTION START: ULA 1986, TAMBAR 2001, TAMBAR EAST 2007, ODA 2019

PRODUCTION 2019 PRODUCTION EFFICIENCY

69 %

Aker BP considers the resource potential in the Ula area to be significant, from increased oil recovery, third party tie-ins, discoveries and exploration opportunities. The Oda field came on stream in 2019, which increased total production from the Ula area. The ambition is to further develop the Ula area and to extend the economic lifetime of the Ula hub.

ULA AREA THE

20 · Aker BP Annual Report 2019 – A Focused Portfolio

In 2019, Ivar Aasen became the first manned platform on the Norwegian shelf to be operated from an onshore control room. As the year progressed, the rewards could be harvested in terms of improved collaboration between onshore and offshore, as well as increased production.

IVAR AASEN

WORLD-CLASS PERFORMANCE

Aker BP sees a considerable potential for increased revenues after start-up of the onshore control room. The cooperation between the subsurface team and the onshore control room gives better understanding of reservoir complexity which is important to optimize and produce at maximum every day.

Production improvements have been important on Ivar Aasen this year, leading to efficient operations and increased production. Ivar Aasen continues to deliver world class performance of 92 percent production efficiency. This is expected to improve even more from 2022, when the platform will receive power from shore via the Johan Sverdrup field. of the year, Ivar Aasen had production from a total of nine oil producing wells supported by eight water injection wells. IMPROVEMENT AND DIGITALIZATION

During start-up of new wells or after shutdowns, the subsurface resources for the control room contributed to increased production and shared competence. In addition, the engineers are available for the control room just outside the door if assistance is required.

TWO NEW PRODUCTION WELLS

Operating the Ivar Aasen platform from shore has proved successful. In the event of lost communication from onshore control room, the offshore control room takes over the operation. The regularity for the first year in operation has been 100 percent. Ivar Aasen is Aker BP's digital pilot, where the company applies new technology to create the digital oil field of the future. Ivar Aasen has a "digital twin" based on live data from the Cognite platform. This can be described as a digital replica of the plant, process and automation systems that shows how they interact. The technology reduces costs over a facility's lifecycle through performance analytics and optimization in the virtual environment. It also enables campaign-based maintenance supported by predictive algorithms.

The first multilateral well on Ivar Aasen was successfully drilled in 2019, increasing production from the field. On a second used for the first time on Ivar Aasen.

well, the Fishbone Completion Technology was successfully The two wells provided additional drainage points in the reservoir and were drilled with excellent performance. At the end During 2019, Aker BP has worked persistently on maturing the Hanz discovery. Aker BP has also acquired a 40 percent interest in a nearby exploration license, PL 780, operated by Spirit Energy. Other near-field exploration campaigns are anticipated in the coming years, targeting possible tie-backs to Ivar Aasen.

All operators are equipped with personal digital devices, which enables easy communication and paperless access to technical documentation as well as live equipment data. The handheld devices make the work more efficient, more productive and safer.

The Ivar Aasen team continues to work for improved efficiency and reduced emissions. At the end of the year, a new measure was tested. By shutting down the compressor for periods without having a negative effect on the production, the power consumption is reduced. The test was successful, giving reduced CO2 emissions which had a positive impact on revenue and reduced operating costs.

FUTURE OPPORTUNITIES

«In January, we started to operate the Ivar Aasen platform from an onshore control room and that has been a success from day one. We have drilled two new production wells and continue to produce at plateau. The production goals for 2019 have been reached thanks to systematic work.»

Gudmund Evju

VP Operation and Asset Development Ivar Aasen

PRODUCTION 2019 PRODUCTION EFFICIENCY

24 · Aker BP Annual Report 2019 – A Focused Portfolio

HIGHLIGHTS FROM 2019

16 January Start operating Ivar Aasen from Aker BP's offices in Trondheim, as the first company on the shelf to operate a manned platform from an onshore control room.

20 June Start of production from first Ivar Aasen well with Fishbone Stimulation Technology.

6 September Acquired 40 percent ownership in nearby license PL 780 operated by Spirit Energy.

26 September Start of production from first multilateral well on Ivar Aasen.

Net 2P Reserves: 49 mmboe

Ivar Aasen Area

IVAR AASEN –Ivar Aasen unit

Aker BP: 34.8 % Partners: Equinor, Spirit, Wintershall, Neptune, Lundin, OKEA 2P reserves: 43 mmboe (net)

Production history (mboepd gross)

JK

Edvard Grieg

Johan Sverdrup

Producing field Field development Discovery Exploration prospect

SOLVING CHALLENGES AND KEEPING UP PRODUCTION

Aker BP mobilized a highly skilled team to solve the mid-water arch situation and get the systems up and running again. Repair and testing were performed through the third quarter, and normal production was reinstated in early October. The design weakness that was discovered on the mid-water arch has been rectified on all three arches to prevent similar incidents.

Alvheim delivered stable operations and a production of 54.4 million barrels per day in 2019, despite the fact that an incident with a mid-water arch led to a shutdown of production from the Vilje satellite and East Kameleon structure. In the meantime, the asset managed to maintain high production through optimized well management and gas lift utilization. The Froskelår exploration well provided interesting reservoir insight, and multiple concepts for developing the Frosk and Froskelår area are now being assessed and matured. CONTINUED FOCUS ON IOR

FROSK TEST PRODUCTION

The Frosk test well started producing in August and a pressure build-up test was later performed. The purpose was to gather valuable reservoir connectivity information which will help optimize overall development of the Frosk area.

Work on the mid-water arch necessitated drilling the production well on the Skogul field in two phases. The first phase of the operation started early in the third quarter, was temporarily suspended and then resumed in the fourth quarter. Skogul started production in the first quarter of 2020. During 2019, Aker BP has continued to mature both the Kobra East Gekko and the Trell and Trine developments. DEBOTTLENECKING FOR NEW OPPORTUNITIES

Aker BP continues the company's successful increased oil recovery track record on Alvheim. The Volund sidetrack well was drilled and completed in 23 days, which is 12 days faster than planned. The well was put on stream in May and is producing according to expectations.

Several new infill wells are planned in the coming years. The first one is Kameleon Infill Mid Well, with expected drilling start in the first half of 2020. A sidetrack target, Boa, has been matured and drilling is targeted for the fourth quarter of 2020.

The Frosk test production period was granted for six months, and an application to prolong this period has been approved by the authorities. Aker BP was awarded new licenses in the Alvheim area by the Norwegian authorities in January 2020 and is planning to explore new opportunities in the coming years.

Aker BP has identified opportunities for both increased gas processing and water treatment capacity on Alvheim. A gas capacity debottlenecking project was sanctioned in January 2020. A stronger focus on prolonged lifetime of the FPSO and its subsea facilities is important and will enable development of both proven resources and potential future exploration success.

«In 2019, we delivered safe, reliable and cost-effective operations throughout the year. New wells were put on stream and a lot of work has gone into maturing new projects and developing the project portfolio.»

Geir Westre Hjelmeland

VP Operations and Asset Development Alvheim

54.4

PRODUCTION 2019 PRODUCTION EFFICIENCY

97 %

Another year with exceptional uptime and production results has passed. Aker BP continues to mature new infill targets in the Alvheim area as well as removal of topside FPSO capacity bottlenecks. The award of new licenses in the area increases growth opportunities for the asset.

ALVHEIM AREA THE

mb o e p d

(net)

28 · Aker BP Annual Report 2019 – A Focused Portfolio

HIGHLIGHTS FROM 2019

March The Froskelår main exploration well proves oil and gas.

• May Volund sidetrack well starts production
• June Frosk exploration well and test producer is drilled
• June East Mid Water Arch incident discovered, leading to shut down from Vilje and East Kameleon
• June Subsea structures and umbilical installed on the Skogul field
• July Start drilling first phase of Skogul production well
• August Frosk test starts production
• August Rumpetroll well proves small gas discovery near the Bøyla field
• October Re-start of production from Vilje and East Kameleon
• November Continued drilling of production well on Skogul
• December Kameleon infill well sanctioned

Net 2P Reserves: 82 mmboe

Alvheim Area

ALVHEIM– PL 203

Aker BP: 65 % Partners: Lundin, ConocoPhillips 2P reserves: 59 mmboe (net)

VILJE– PL 036 D Aker BP: 46,9 % Partners: DNO, PGNiG 2P reserves: 6 mmboe (net)

VOLUND – PL 150 Aker BP: 65 %

Partner: Lundin 2P reserves: 7 mmboe (net)

Alvheim Vilje Volund Bøyla

TRELL

TRINE

CATERPILLAR

GEKKO

FROSKELÅR

Production history (mboepd gross)

RUMPETROLL

Producing field Test Production Discovery Exploration prospect

FROM DECLINE TOWARDS INCREASED PRODUCTION

The ambition for the Skarv area is to significantly increase the estimated production up until 2045.

TAKE-OFF FOR ÆRFUGL

Drilling of the first production well on Ærfugl Phase 1 marked the start of an active period for the asset. This was the first new production well on Skarv in six years. Three more production wells will be drilled during 2020. The increased production from Ærfugl will turn the curve from decline to increase towards plateau production.

The Ørn exploration well was drilled by operator Equinor in the third quarter of the year, with the exploration team from Aker BP as an active contributor. The well resulted in one of the largest gas discoveries on the Norwegian continental shelf this year. Just weeks later, the Shrek well was drilled by operator PGNiG and came in with volumes twice as high as the estimates. Reorganizing the value chain through strategic partnerships and alliances is an important part of Aker BP's strategy. The alliances in subsea, modifications and drilling and wells contributes to the Ærfugl project. SUCCESSFUL ENERGY EFFICIENCY PROJECTS Aker BP has set ambitious goals to reduce both operating

In November, the Ærfugl partners decided to proceed with

Skarv. Modification of the plant will contribute to an increased capacity of more than 15 percent.

Phase 2 of the project, three years ahead of the original plan. The Ærfugl field is one of the most profitable development projects on the Norwegian shelf with a break-even price of around USD 15 per barrel. In parallel with development of Ærfugl Phase 1, work has been proceeding to increase gas processing capacity on During 2019, Aker BP has worked intensively to develop the Gråsel discovery into a robust and profitable project. The Gråsel discovery was made in 1998. In this project we plan to re-use existing infrastructure in order to minimize development scope. This has been an enabler for a highly competitive project with a low break-even. Aker BP plans to start the development of Gråsel in 2020.

costs and CO2 emissions from Skarv by 30 percent compared with 2018 levels.

Throughout 2019, the onshore and offshore teams have been working on various energy efficiency initiatives. Reducing the export pressure and optimizing the power configuration Skarv has made it possible to reduce annual CO2 emissions by 22,000 tonnes and cost by NOK 19 million.

MATURING GRÅSEL

«It has been a fantastic year for Skarv with high uptime and two new discoveries. We have made good progress in maturing projects and reducing the operational CO2 footprint. At the same time, production efficiency has been record-high. With our license partners, we have developed a solid strategic foundation to bring Skarv into the future.»

Ine Dolve

VP Operations and Asset Development Skarv

PRODUCTION START: 2012

PRODUCTION 2019 PRODUCTION EFFICIENCY

96 %

Exploration success in the area in 2019 gave fresh perspectives on the geology around Skarv, generating new ideas on drilling prospects in the coming years. Several energy optimization projects resulted in reduced costs and lower CO2 emissions.

SKARV AREA THE

On 5 October 2019, the Johan Sverdrup field came on stream more than two months ahead of schedule and NOK 40 billion below budget. This giant oil field will be a major contributor to Aker BP's production and earnings growth in the years to come.

JOHAN SVERDRUP

«The development represents massive value creation for Aker BP and the other partners, as well as the Norwegian society. Both the operator, the partners and the contractors deserve praise for their excellent achievement. This is evidence that the Norwegian oil and gas industry is still one of the best in the world.»

Odd Ragnar Heum

VP Operations and Asset Development Johan Sverdrup

THE NORTH SEA GIANT IS ON STREAM

At peak, the Johan Sverdrup field will account for around one third of all oil production in Norway, delivering highly valuable barrels with record low emissions. The expected operating costs are below USD 2 per barrel.

Johan Sverdrup is expected to generate income from production of more than NOK 1,400 billion, of which NOK 900 billion will go to the Norwegian state and society. The operation phase is expected to last more than 50 years and will provide employment corresponding to more than 3,400 full-time equivalents on average every year.

LOW EMISSIONS. LOW COST. HIGH QUALITY.

It was a significant moment for the operator Equinor and for Aker BP and the other partners when the Johan Sverdrup field came on stream on 5 October. Johan Sverdrup is the third largest oil field on the Norwegian continental shelf, with estimated resources of between 2.2 to 3.2 billion barrels of oil equivalent and expected resources of 2.7 billion barrels of oil equivalent. 620,000 tonnes per year. The field emits 0.67 kg of CO2 per barrel, compared with a global average of around 18 kg. After 2022, Johan Sverdrup will also provide power from shore to other fields on the Utsira High, including Ivar Aasen, Edvard Grieg and Gina Krog, as well as the Sleipner field further south.

The Johan Sverdrup field is powered with electricity from shore, leading to CO2 emission reductions estimated at more than

There are a number of factors that make this field and the development project unique. At plateau, the field will produce 660,000 barrels of oil per day. Break-even price for the fullfield development is below USD 20 per barrel. Production is anticipated to reach plateau for the first phase during the summer of 2020, with a production of 440,000 barrels a day. the field center, five subsea templates, in addition to increased power-from-shore supply to the Utsira High. When the second processing platform commences operation in 2022, production capacity will increase from 440,000 to 660,000 barrels per day.

PHASE 2

The Johan Sverdrup field is being developed in two phases. The plan for development of Phase 2 was approved by the Norwegian authorities in May 2019. The second phase includes development of a new processing platform (P2), which will be the second of its kind at the field center. When this is installed, the field will be complete with five platforms.

Phase 2 also entails modifications of the riser platform and

PRODUCTION 2019 CO2 INTENSITY (KG/BOE)

0.67 mb

36 · Aker BP Annual Report 2019 – A Focused Portfolio

Net 2P Reserves: 307 mmboe

Johan Sverdrup

JK

Production history (mboepd gross)

Q4-19

Edvard Grieg

Petoro, Total 2P reserves: 307 mmboe (net)

Producing field Field development Discovery Exploration prospect

HIGHLIGHTS FROM 2019

March Record-breaking marine operation where the processing platform and the living quarters platform, a bridge and a flare stack were lifted into place in just three days. The processing platform lift was the heaviest lift ever executed offshore.

15 May Phase 2 plan approved by Norwegian authorities. Phase 2 includes a second processing platform and increased capacity for oil production up to 660,000 barrels a day.

5 October Johan Sverdrup on stream from the first of eight predrilled oil production wells

21 October First oil from Johan Sverdrup to Mongstad. The oil transported from the field in the North Sea to the plant, a distance of 283 kilometers. At the Mongstad complex, the oil is stored and prepared for shipping to markets all over the world.

10 November All eight pre-drilled oil production wells on stream and 12 pre-drilled water injection wells initiated.

3 December Reaches daily production of 350,000 barrels

7 January 2020 Official opening of the Johan Sverdrup field. Started drilling of the first new production well

Primeminister at Johan Sverdrup for opening.

All photos: Equinor

PRODUCTION Q4-19

Aker BP in social media 2019

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ØYVIND ERIKSEN

SHAREHOLDER-ELECTED CHAIR AND CHAIR OF THE COMPENSATION AND ORGANZA-TIONAL DEVELOPMENT COMMITTEE

Independent of major shareholders No
Aker BP shares *	None ***
Born	1964
Family relations BoD/EMT **	No
Citizenship	Norwegian
Residency	Norway

Experience, skills and education: Eriksen

has almost 20 years of experience in the legal industry, as he began his career at the law firm BAHR in 1990. During his time at BAHR, he became a partner in 1996 and a director/chairman in 2003. As a corporate attorney, he among other things worked with strategic and operational development, M&A and negotiations. Eriksen also worked closely with Aker. Eriksen has held several board positions in different industries, including shipping, finance, asset management, offshore drilling, fisheries, media, trade and industry. Eriksen holds a law degree from the University of Oslo.

Key external appointments: Eriksen is the President and CEO of Aker ASA, the chairman of the Board of Directors of Aker BP ASA, Aker Solutions ASA, Cognite AS, Aker Capital AS, Aker Kværner Holding AS and REV Ocean Inc. and director of several companies, including Aker Energy AS, Akastor ASA, The Resource Group TRG AS, TRG Holding AS and The Norwegian Cancer Society, among others. Eriksen is also a member of the World Economic Forum Center for the Fourth Industrial Revolution Advisory Board.

ANNE MARIE CANNON

SHAREHOLDER-ELECTED DEPUTY CHAIR AND MEMBER OF THE AUDIT AND RISK

COMMITTEE

Aker BP shares *	12,078
Born	1957
Family relations **	No
Citizenship	British
Residency	UK

Experience, skills and education: Cannon has more than 35 years' experience in the oil and gas sector in both industry and investment banking and is a Senior Advisor at PJT Partners. She has served as the Deputy Chairman of the board since 2013, and she is a member of the Audit and Risk Committee at Aker BP. Between 2000 and 2013 she served as a Senior Advisor to the Natural Resources Group at Morgan Stanley focusing on upstream M&A. Prior to this Cannon was an Executive Director on the boards of Hardy Oil & Gas and British Borneo and previously held senior financial roles at J Henry Schroder Wagg and Shell UK Exploration & Production. Cannon holds a Bachelor of Science (Honours) Degree from Glasgow University.

Key external appointments: Cannon is currently a non-executive director on the board of Aker Energy AS, Premier Oil and

STV Group.

-

GRO G. KIELLAND

SHAREHOLDER-ELECTED MEMBER AND MEM-BER OF THE COMPENSATION AND ORGANZA-TIONAL DEVELOPMENT COMMITTEE

Independent of major shareholders Yes
Aker BP shares *	1,750
Born	1959
Family relations **	No
Citizenship	Norwegian
Residency	Norway

Experience, skills and education: Kielland has had several leading positions in the oil and gas industry both in Norway and abroad, among others as CEO of BP Norge. Her professional experience includes work related to both operations and field development, as well as HSE. Kielland has a Master of Science degree and a Diploma of Education from the Norwegian University of Science and Technology.

Key external appointments: Kielland serves as an Operational Partner with HitecVision. In addition to her duties and responsibilities at the non-executive level for HitecVision, she also serves as a non-executive Chairman and Director for other companies.

* Number of shares in Aker BP ASA as of 31 December 2019

** 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

BOARD OF DIRECTORS

BERNARD LOONEY

SHAREHOLDER-ELECTED MEMBER

Independent of major shareholders No
Aker BP shares *	None
Born	1970
Family relations **	No
Citizenship	Irish
Residency	UK

Experience, skills and education: In Oc-

tober 2019 Bernard was announced as Group Chief Executive of BP, effective 5 February 2020. He came from a position as the Upstream Chief Executive for the BP Group, where he was responsible for exploration, development and production within the upstream segment. Looney joined BP plc in 1991 as a Drilling Engineer. He has extensive leadership experience in the oil and gas business, having worked in a variety of locations, including the North Sea, Vietnam, Gulf of Mexico and Alaska. He was appointed to the role of Chief Executive for BP's Upstream Segment in February 2016.

Key external appointments: Group Chief Executive of BP.

TERJE SOLHEIM

EMPLOYEE-ELECTED MEMBER AND MEMBER OF THE COMPENSATION AND ORGANZA-TIONAL DEVELOPMENT COMMITTEE

Independent of major shareholders Yes
Aker BP shares *	1,787
Born	1962
Family relations **	No
Citizenship	Norwegian
Residency	Norway

Family relations **	No
Citizenship	Norwegian
Residency	Norway
	Experience, skills and education: Solheim
	is the General Manager of Aker BP's
	Harstad office. Solheim has been with
	Aker BP since 2013 and has held several
	positions with the Company. He has an ex

Experience, skills and education: Solheim is the General Manager of Aker BP's Harstad office. Solheim has been with Aker BP since 2013 and has held several positions with the Company. He has an extensive background from the Norwegian Armed Forces and was one of the founders of Norwegian Petro Services (NPS). He came to Aker BP from Det Norske Veritas (DNV).

Key external appointments: None.

ANETTE HOEL HELGESEN

EMPLOYEE-ELECTED MEMBER

Independent of major shareholders Yes
Aker BP shares *	None
Born	1987
Family relations **	No
Citizenship	Norwegian
Residency	Norway

Experience, skills and education: Helgesen has been with Aker BP since 2011. As of February 2020, Helgesen will enter into a position as HSSEQ Manager Project & Concept Development. Prior to this she has held different positions in Aker BP and BP Norway, as Operations Engineering Manager for the Ula field, Process Engineer and onshore operations supervisor for the Valhall Field. Helgesen has a Master of Science degree in Chemical Engineering from the Norwegian University of Science and Technology in Trondheim.

Key external appointments: None.

KJELL INGE RØKKE

SHAREHOLDER-ELECTED MEMBER

Independent of major shareholders No
Aker BP shares *	None
Born	1958
Family relations **	No
Citizenship	Norwegian
Residency	Norway

Experience, skills and education: 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 % of Aker ASA through The Resource Group TRG AS and subsidiaries.

Key external appointments: Røkke is Aker ASA's primary owner and Chairman. He is currently director of several companies, including Kvaerner, Aker Energy, Aker BioMarine and Ocean Yield.

TROND BRANDSRUD

SHAREHOLDER-ELECTED MEMBER AND CHAIR OF THE AUDIT AND RISK COMMITTEE

Independent of major shareholders Yes
Aker BP shares *	None
Born	1958
Family relations **	No
Citizenship	Norwegian
Residency	Norway

Experience, skills and education: Brandsrud serves as a non-executive director and industry advisor. From 2016 to 2019 he had several CEO and CFO roles in the financial services companies Lindorff, Intrum and Lowell, and from 2010 to 2015 he acted 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 has 23 years of experience from leading finance positions in Royal Dutch Shell plc., both in Norway and internationally. Brandsrud holds a Master of Science degree from the Norwegian School of Economics and Business Administration.

Key external appointments: Brandsrud is non-executive director and board member of PGS ASA and the Lowell Group (Simon Midco Ltd).

KATHERINE ANNE THOMSON

SHAREHOLDER-ELECTED MEMBER AND MEM-BER OF THE AUDIT AND RISK COMMITTEE

Independent of major shareholders No
Aker BP shares *	None
Born	1968
Family relations **	No
Citizenship	British
Residency	UK

Experience, skills and education: Thomson is the Group Treasurer for the BP Group, having previously held the position of Group Head of Tax. In her current role, Thomson has responsibility for internal financing of the BP Group, providing liquidity to its businesses and optimizing value through the management of financial risks at the group level. Prior to joining BP, 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 Group companies.

Key external appointments: Cannon is currently a non-executive director on the board of Aker Energy AS, Premier Oil and STV Group.

* Number of shares in Aker BP ASA as of 31 December 2019

** Family relations to other members of the Board or members of the Executive Management Team

EXECUTIVE MANAGEMENT TEAM

KARL JOHNNY HERSVIK

CHIEF EXECUTIVE OFFICER

Aker BP shares *	6,081
Born	1972
Family relations **	No
Citizenship	Norwegian
Residency	Norway

Experience, skills and education: 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 a number of 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.

Key external appointments: Hersvik is the chairman of the Board of Directors of Aker Energy AS. He is a member of the Board of Directors at Cognite and Sjømannskirken - Norwegian Church Abroad.

DAVID TORVIK TØNNE

CHIEF FINANCIAL OFFICER

Experience, skills and education: 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. He holds a master's degree in finance from NHH Norwegian School of Economics. Prior to Aker BP, he worked for the Boston Consulting Group.

Key external appointments: None.

MARIT BLAASMO

SVP HSSEQ

Aker BP shares *	None
Born	1975
Family relations **	No
Citizenship	Norwegian
Residency	Norway

Experience, skills and education: Blaasmo was appointed SVP HSSEQ in Aker BP in May 2019. Prior to this, she held the position as responsible for the Drilling & Wells performance and improvement agenda. Blaasmo has been with the company since August 2017 and holds a master's degree in Petroleum Engineering from the Norwegian University of Science and Technology (NTNU). Prior to joining Aker BP, Blaasmo held multiple roles within Drilling & Wells at Baker Hughes INTEQ and Equinor.

Key external appointments: None.

INGARD HAUGEBERG

EMPLOYEE-ELECTED MEMBER

Independent of major shareholders Yes
Aker BP shares *	970
Born	1962
Family relations **	No
Citizenship	Norwegian
Residency	Norway

Experience, skills and education: 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. From 1998, he has held several positions in BP Norge. Haugeberg has also held a number of different directorships in BP Norge, Industrimaskiner A/S, Global Clean Energy, I/E Media and trippEl A/S. He was trained as an electro mechanical repair tech in the Royal Norwegian Air Force technical school centre at Kjevik and has a company-approved bachelor in mechanics.

Key external appointments: None.

ØRJAN HOLSTAD

EMPLOYEE-ELECTED MEMBER

Independent of major shareholders Yes
Aker BP shares *	2,656
Born	1989
Family relations **	No
Citizenship	Norwegian
Residency	Norway

Experience, skills and education: Holstad is a Senior HR Professional working with the offshore segment in Operations and Asset Development in Aker BP. He has a background as an Instrument Technician and has been an employee of BP Norge (now Aker BP) since 2010. Holstad has offshore experience and project experience from the Skarv FPSO. His experience in the oil and gas industry includes service as a full-time employee representative in BP Norge and member of the BP Norge AS Board of Directors from 2014 to 2016.

Key external appointments: None.

* Number of shares in Aker BP ASA as of 31 December 2019

** Family relations to other members of the Board or members of the Executive Management Team

* Number of shares in Aker BP ASA as of 31 December 2019

** Family relations to other members of the Board or members of the Executive Management Team

PER HARALD KONGELF

SVP IMPROVEMENT

Aker BP shares * None Born 1959 Family relations ** No Citizenship Norwegian Residency Norway

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. Kongelf holds an MSc degree from NTNU in Trondheim and has more than 30 years of industrial experience through numerous technical and management positions in Aker Solutions.

Key external appointments: Kongelf is member of the Board of Directors at DigitalNorway.

LENE LANDØY

SVP STRATEGY & BUSINESS DEVELOPMENT

Aker BP shares *	5,221
Born	1979
Family relations **	No
Citizenship	Norwegian
Residency	Norway

Experience, skills and education: Landøy was appointed SVP Strategy & Business Development in January 2019. She advanced from the position of VP Strategy, Portfolio and Analysis in Aker BP. Landøy has been with the company since January 2017. Landøy holds a master's degree in finance from NHH Norwegian School of Economics and the University of California Los Angeles (UCLA). She also holds a master's degree in international finance from the Skema Business School in France. Prior to joining Aker BP, Landøy led Equinor's business development unit on the Norwegian continental shelf.

Key external appointments: None.

OLE JOHAN MOLVIG

SVP RESERVOIR

Aker BP shares *	9,582
Born	1972
Family relations **	No
Citizenship	Norwegian
Residency	Norway

Experience, skills and education: Molvig has been with the company since 2009. Prior to the role as SVP Reservoir he held the position of VP Subsurface, Det norske. Molvik has extensive experience in the oil and gas industry, mainly from ExxonMobil, Statoil and Marathon Oil. Molvig holds a master's degree from NTNU in Trondheim.

Key external appointments: Molvig is member of the Board of Directors as a representative from Aker BP in the companies Fishbone and Resoptima.

ØYVIND BRATSBERG

SPECIAL ADVISOR

Aker BP shares *	54,802
Born	1959
Family relations **	No
Citizenship	Norwegian
Residency	Norway

Experience, skills and education: Bratsberg

joined Aker BP in 2008 as Chief Operating Officer. He has more than 30 years' experience from several companies in the areas of marketing, business development and operations. Before taking up his position with Det norske (Aker BP), he was responsible for early-phase field development on the Norwegian continental shelf for StatoilHydro. Bratsberg holds an MSc degree in Mechanical Engineering from NTH, now the Norwegian University of Science and Technology, NTNU.

Key external appointments: Bratsberg is a member of the Board for Standard Contracts on the Norwegian continental shelf.

KJETEL DIGRE

SVP OPERATIONS & ASSET DEVELOPMENT

Aker BP shares * 3,002 Born 1969 Family relations ** No Citizenship Norwegian Residency Norway

Experience, skills and education: Digre joined Aker BP in May 2019. Prior to joining Aker BP, he had 25 years of experience from Equinor where his last position was as SVP and Project Director for the Johan Sverdrup project development. Digre holds an MSc with distinction in Subsea and Petroleum Engineering from Heriot-Watt University in Edinburgh, Scotland.

Key external appointments: Digre is a member of the Board of Directors at AF-gruppen.

EVY GLØRSTAD

SVP EXPLORATION

Aker BP shares *	5,866
Born	1975
Family relations **	No
Citizenship	Norwegian
Residency	Norway

Experience, skills and education: 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 held several managerial positions since joining the company. Glørstad holds a PhD in Petroleum geology/sedimentology. She has broad experience as a geologist from BP in Norway and the US.

Key external appointments: None.

* Number of shares in Aker BP ASA as of 31 December 2019

** Family relations to other members of the Board or members of the Executive Management Team

* Number of shares in Aker BP ASA as of 31 December 2019

** Family relations to other members of the Board or members of the Executive Management Team

BOARD OF DIRECTORS' REPORT

KNUT SANDVIK

SVP PROJECTS

Aker BP shares *	None
Born	1962
Family relations **	No
Citizenship	Norwegian
Residency	Norway

Experience, skills and education: Sandvik joined Aker BP in July 2019. Prior to joining Aker BP, he has worked in the oil and gas industry for more than 30 years. Throughout his career, Sandvik has held various senior project and leadership positions across Aker Solutions, most recently as EVP Greenfield Projects. Sandvik holds a degree in Mechanical Offshore Engineering from Heriot-Watt University in Scotland.

Key external appointments: None.

TOMMY SIGMUNDSTAD

SVP DRILLING & WELLS

Aker BP shares * 1,538 *** Born 1970 Family relations ** No Citizenship Norwegian Residency Norway

Experience, skills and education: Sigmundstad has been SVP Drilling & Wells in Aker BP since 2016. Prior to this, he was Vice President Wells 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 different 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.

Key external appointments: Sigmundstad is member of the board of Directors in MHWirth.

* Number of shares in Aker BP ASA as of 31 December 2019

• ** Family relations to other members of the Board or members of the Executive Management Team
• *** Sigmundstad owns an additional 7,000 shares through the company Themi Management AS

BOARD OF DIRECTORS' REPORT

Aker BP delivered strong operational performance and reached several important milestones in 2019, with the production start at Johan Sverdrup and Valhall Flank West as two of the highlights. In the beginning of 2020 however, the spread of the COVID-19 virus has created increased uncertainty and disruption to the global economy. In this situation, the Board's objective is to make sure Aker BP is taking 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.

Aker BP carries out significant operations related to exploration and production of oil and gas on the Norwegian continental shelf (NCS). Environmental, Social and Governance (ESG) issues are of paramount importance to the Board of Directors of Aker BP. Accordingly, the Board recognizes its responsibility for the safety of people and the environment and devotes appropriate time and resources to comply with all regulations and strives to adhere to the highest standards in the oil and gas industry regarding Health, Safety, Security and Environment (HSSE).

To meet the challenges of an uncertain macro environment and to strengthen its long-term competitiveness, Aker BP has established a strong platform for value creation. The company leverages an effective business model built on lean principles, strong technological competence and industrial cooperation to ensure safe and efficient operations.

Aker BP has a comprehensive improvement agenda with four focus areas. The aim is to reduce cost and improve efficiency across all disciplines to enable sanctioning of new stand-alone projects at break-even prices below 35 USD/boe. The focus areas are:

• 1. reorganization of the value chain with strategic partnerships and alliances to remove waste and increase productivity;
• 1. digitalization of the Exploration & Production (E&P) business model;
• 1. changing the management systems and culture to build on «Lean» principles by prioritizing flow efficiency over resource efficiency and;
• 1. to bring these together inside one organization and one business model that withstands volatility and has the flexibility to sustain growth.

Aker BP's net production in 2019 was 155.9 thousand barrels of oil equivalents per day (mboepd). Total net production volume was 56.9 million barrels of oil equivalents (mmboe). About 93 percent of the production in 2019 came from the five operated production hubs; the Alvheim area, Ivar Aasen, the Valhall area, Skarv and the Ula area.

Aker BP continues to be an operator with low carbon emissions intensity. In 2019, Aker BP's CO2 intensity was below 7 kg CO2 per barrel of oil equivalents (equity share), which is less than half the global industry average and below the average for the NCS. From 2020 on, the company's goal is to deliver an emission intensity below 5 kg CO2/boe (equity share).

All major field development projects, including Johan Sverdrup, Valhall Flank West and Ærfugl, progressed according to plans. These projects are expected to contribute significantly to the company's production and profitability in the years to come. First oil from both Johan Sverdrup and Valhall Flank West was achieved during 2019.

The company participated in 16 exploration wells in 2019. The exploration activities resulted in net discovered volumes of 170 mmboe, consisting of the Froskelår Main, Froskelår NE, Liatårnet, Ørn, Shrek and Busta discoveries. In addition, the company expanded its license portfolio through the Awards in pre-defined Areas (APA) 2019. Aker BP was offered interests in 15 new production licenses on the NCS, of which 9 as operator.

Looking forward, the company has a large resource base, with 2P reserves of 906 (917) mmboe and contingent resources of 931 (946) mmboe. This resource base provides a basis for future organic growth.

The company has a robust and diversified capital structure with USD 2.7 billion in available liquidity as of 31 December 2019. In January 2020, the company further strengthened its liquidity by issuing USD 1.5 billion in new bonds. The company paid four dividends in 2019, totaling USD 750 million.

Even though the ongoing COVID-19 situation creates increased uncertainty in the short to medium term, the Board is of the opinion that Aker BP is well positioned for further value accretive growth on the NCS. 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.

SHARE PRICE PERFORMANCE AND OWNERSHIP STRUCTURE

than 14,000 shareholders. Aker BP is listed on the Oslo Stock Exchange under the ticker symbol «AKERBP».

RESPONDING TO THE COVID-19 SITUATION

Aker BP is closely monitoring the development in the spread of the COVID-19 virus and has mobilized significant resources to manage the situation. The top priority is to protect the health and safety of the company's employees and contractors, and to maintain safe and reliable operations.

In 2019, the share price for Aker BP ended at NOK 288 per share, compared to NOK 218 per share at the end of 2018. At the end of the year, 360.1 million shares were issued, which is the same as at the end of 2018. Aker ASA remains the largest owner with 40 percent, while BP P.L.C. owns 30 percent of the shares. The remaining 30 percent were split among more to be prepared in case of an escalation of the situation. In parallel to managing the operational side of the current situation, the company has also initiated a process aimed at protecting the company's financial strength. This process involves a comprehensive evaluation of the company's business plan.

The company's initial response was to mobilize its emergency response organization to respond to the COVID-19 situation. Subsequently a separate task force with significant resources has been mobilized to handle and normalize the situation. Instructions to all employees, intended to minimize the risk of the virus spreading among the company's employees and contractors have been developed and are continuously updated. In parallel, the company has established and is maintaining contingency plans

Two Boa wells and the startup of the Kameleon Infill South well in 2018 contributed positively to production from Alvheim in 2019. During an annual ROV inspection in June it was discovered that one of the tether frame connections on the eastern Mid Water Arch (MWA) had failed. This led to production being shut in from Vilje and East Kameleon. Production was protected by optimizing gaslift to other Alvheim wells. Repair and testing of the MWA systems were performed and production from Vilje and East Kameleon was reinstated in October 2019.

Net production from Alvheim, including Boa, averaged 39.2 mboepd in 2019. Production from the Alvheim field is estimated to end in 2033, with subsequent abandonment between 2033 and 2034. Year-end 2019 P50 reserves for Alvheim are estimated at 59 mmboe net to Aker BP.

The Volund field (65 %, operator) is located approximately eight km south of Alvheim and was the second field developed as a subsea tieback to Alvheim. The field started producing in 2009 with four production wells and one water injection well. Volund produces oil from Paleocene sandstone in the Hermod Formation.

During 2019 a structured Asset Development Plan was developed which emphasized the need for increased gas processing capacity and water treatment facilities. Such debottlenecking activity, together with increased focus on prolonged lifetime of the FPSO and its subsea facilities will enable development of both proven resources and potential future explorations successes. Through the year, both the Kobra East Gekko and the Trell and Trine developments have continued to be matured towards a concept selection. In the fourth quarter 2019 another Alvheim infill well, Kameleon Infill Mid, was sanctioned. The Bøyla field (65 %, operator) is located 28 km south of Alvheim at a water depth of 120 meters. The productive reservoir of the Bøyla field is within the Hermod sandstone member, which is a deep marine, channelized submarine fan system at a depth of approximately 2,100 meters. The field is tied back to the Alvheim FPSO. Production commenced in January 2015. The field is developed with two horizontal production wells and one water injection well. An oil discovery was made in the Frosk prospect near the

Net production at Volund averaged 8.9 mboepd in 2019. The Volund sidetrack well was put on production in May and produces according to expectations. Production from the Volund field is expected to last until 2033, with subsequent abandonment between 2033 and 2034. Year-end 2019 P50 reserves are estimated at 7 mmboe net to Aker BP. The development comprises a production, drilling and quarters (PDQ) platform with a steel jacket and a separate jack-up rig for drilling and completion. The platform has spare slots for possible additional wells. First stage processing is carried out on the Ivar Aasen field, and the partly processed fluids are transported to the Edvard Grieg field for final processing and export. Production started in December 2016. The platform is prepared for subsea tie-ins of nearby discoveries.

Bøyla field in 2018. In August 2019 a test producer was put on production. The well provides the company with valuable information about the reservoir and is producing according to expectations. The test production period was initially granted for six months. An application to prolong this period has been approved by the authorities.

The Vilje field (46.904 %, operator) is located northeast of Alvheim at a water depth of 120 meters. The productive reservoir of the Vilje field is the middle to late Palaeocene Heimdal Formation sandstone at a depth of approximately 2,100 meters. The field is tied back to the Alvheim FPSO. Production Average daily production net to Aker BP in 2019 amounted to 21.8 mboepd, and net reserves including Hanz are estimated at 49 mmboe.

Net production from Bøyla averaged 4.1 mboepd in 2019. Production from the Bøyla field is expected to cease in 2033, with subsequent abandonment scheduled to take place between 2033 to 2034. Year-end 2019 P50 reserves for Bøyla and the Frosk test producer are estimated at 5 mmboe net to Aker BP.

commenced in 2008. Net production from Vilje averaged 2.3 mboepd in 2019. Vilje was kept shut-in in the third quarter due to the failed MWA. Production from the Vilje field is expected to cease in 2033, with subsequent abandonment between 2033 to 2034. Yearend 2019 P50 reserves are estimated at 6 mmboe net to Aker BP. The Johan Sverdrup field (11.6 %, partner) is located 160 km west of Stavanger in the central part of the North Sea. Water depth is 110-120 meters. The main reservoir is of Upper Jurassic age consisting of coarse-grained sandstones of excellent production properties. Reservoir depth is approximately 1,900 meters. The operator Equinor estimates the field's recoverable volumes at 2.7 billion boe (between 2.2 and 3.2).

The Ivar Aasen field (34.8 %, operator) is located in the northern part of the North Sea, about 30 kilometers south of the Grane and Balder fields and consists of the discoveries Ivar Aasen and West Cable. The water depth is 110 meters. The Ivar Aasen reservoir is of Late Triassic to Middle Jurassic age, and contains oil at a depth of around 2,400 meters. Parts of the reservoir have an overlying gas cap. The reservoir in West Cable is in the Middle Jurassic Sleipner Formation, and contains oil at a depth of around 2,950 meters.

Business description

DESCRIPTION OF THE COMPANY

Aker BP is a fully-fledged E&P company with exploration, development and production activities on the NCS. Aker BP holds no oil or gas assets outside Norway. All activities are thus within the Norwegian offshore tax regime, and to the extent the company has overseas activities, these are related to construction and engineering of field developments.

Aker BP is active in all three main petroleum provinces on the NCS. The company remains convinced that the NCS offers attractive opportunities for oil and gas exploration and development. The company plans to continue to be an active industry player in the coming years.

The company's registered address is at Lysaker in Bærum municipality. The company also has offices in Harstad, Sandnessjøen, Stavanger and Trondheim. Karl Johnny Hersvik is Chief Executive Officer. At the end of 2019, the company had 1,742 (1,649) employees. The company has a total of 141 (138) licenses, including non-operated licenses.

PRODUCTION

As of 31 December 2019, Aker BP had production from 16 fields: Alvheim (65 % and operator), Atla (10 % and partner), Bøyla (65 %

and operator), Enoch (2 % and partner), Gina Krog (3.3 % and partner), Hod (90 % and operator), Ivar Aasen (34.786 % and operator), Johan Sverdrup (11.5733 % and partner), Oda (15 % and partner), Skarv (23.835 % and operator), Tambar/Tambar East (55/46.2 % and operator), Ula (80 % and operator), Valhall (90 % and operator), Vilje (46.904 % and operator) and Volund (65 % and operator).

Production in 2019 averaged 155.9 mboepd.

Alvheim (65 %, operator) is an oil and gas field operated by Aker BP and is located in the North Sea at a water depth between 120 and 130 metres. The field consists of the Kneler, Boa, Kameleon, East Kameleon, Viper and Kobra structures as well as the Gekko discovery. The Boa reservoir straddles the Norway-UK median line, and is unitized with Verus Petroleum, who is the owner on the UK side. The productive reservoir of the Alvheim field is the middle to late Palaeocene/early Eocene Heimdal and Hermod Formation sandstones, which exist at a depth of approximately 2,100 meters.

Alvheim has been developed using a floating production, storage and offloading (FPSO) vessel, and production started in 2008. The development provides for the transport of oil by shuttle tanker and transportation of gas to the SAGE system. The Alvheim FPSO is also a production host for the satellite fields Volund, Vilje and Bøyla.

ties for production, drilling and accommodation, connected by bridges. The field started producing in 1986. The field's gas capacity was upgraded in 2008 with a new gas processing and injection module. The oil is exported via Ekofisk to Teeside and all gas is reinjected into the reservoir to enhance recovery.

Ula acts as a third-party host for the Oda and Blane fields via

The Ula field (80 %, operator) is located in the southern part of the North Sea. The water depth in the area is 70 meters. The main reservoir is at a depth of 3,345 meters in the Upper Jurassic Ula Formation. The development consists of three conventional steel facili-The field has been developed with a remotely controlled wellhead facility without processing equipment and started production in 2001. During 2019 the production has been improved by application of gas lift. Net production from Tambar averaged 2.2 mboepd in 2019. Year-end 2019 P50 reserves are estimated at 5 mmboe net to Aker BP.

Net production from Ula and Oda averaged 6.3 mboepd in 2019. The Ula concession period expires in 2028. The resource potential extends beyond the concession period, and it is common in the industry to achieve extensions to concessions, and the cessation of production will be subject to the technical life of the facilities and the economic cut-off. Year-end 2019 P50 reserves for Ula and Oda are estimated at 34 mmboe net to Aker BP.

subsea tiebacks. The Spirit Energy operated Oda field (15 %, partner) started production in March 2019. Oda is a subsea field which is tied back to Ula and re-uses existing Oselvar inlet facilities on Ula. Both the modification and back-log maintenance 2019 work scope has progressed as planned, and the temporary additional floating accommodation facilities at Ula were demobilized in May 2019. The original drilling derrick has been removed by heavy lift as part of the preparation for the infill drilling campaign. The Maersk Integrator was located at Ula from June 2019 and drilling operations started in July. The field was originally developed with three facilities for accommodation, drilling and processing, and started production in 1982. In June 2019 the original accommodation platform was successfully removed in a single-lift operation as a part of the modernization of the field center. The Valhall complex now consists of five separate steel platforms for drilling, wellheads, production, water injection, combined process- and hotel platform respectively. These platforms are bridge-connected. In addition, the field has three unmanned flank platforms, one in the west, one in the south and one in the north. Liquids are routed via pipeline to Ekofisk and further to Teesside in the UK. Gas is sent via Norpipe to Emden in Germany.

Aker BP considers the resource potential in the Ula area to be significant, both from increased oil recovery in the Ula and Tambar fields, from potential tiebacks of other discoveries including the King Lear discovery, and from exploration opportunities. To provide foundation for this upside potential, the strategy is to improve the technical condition of the facilities and address obsolescence. In parallel, the company is working diligently to mature the opportunity set, which is a complex process involving a broad set of technical and commercial disciplines. The ambition is that this leads to further development of the Ula area in the mid-2020s, although the value potential may be impacted by the longer term effects of the current COVID-19 situation. Net production from Valhall averaged 38.2 mboepd in 2019. The Valhall concession period currently expires in 2028. The resource potential extends beyond the concession period, and it is common in the industry to achieve extensions to concessions, and the cessation of production will be subject to the technical life of the facilities and the economic cut-off. The current design life for the new Production-Hotel platform (PH) is 2049, 2033 for the Injection Platform (IP) and the Flank North and South, and the Wellhead Platform (WP) has been granted life extension until 2028. Year-end 2019 P50 reserves are estimated at 287 mmboe net to Aker BP.

The Valhall field (90 %, operator) is located in the southern part of the Norwegian North Sea at water depth of 70 meters. The reservoir consists of chalk in the Upper Cretaceous Tor and Hod Formations. Reservoir depth is approximately 2,400 meters.

The Tambar and Tambar East field (55.0/46.2 %, operator) is located 16 kilometres southeast of the Ula field in the southern part of the North Sea. The water depth in the area is 68 meters. The reservoir consists of Upper Jurassic sandstones in the Ula Formation, deposited in a shallow marine environment. The reservoir lies at a depth of 4,100-4,200 meters. The original Hod development produced from 1990 to 2012 via a remotely operated wellhead platform tied back to Valhall. Hod currently produces from wells drilled from the Valhall Flank South platform. All wells on the Hod platform are currently shut in and awaiting plug and abandon operations.

The Hod field (90 %, operator) is located in the southern part of the North Sea. The field was discovered in 1974 and is located 13 kilometers south of Valhall. The water depth in the area is 72 meters. The reservoir lies in chalk in the lower Paleocene Ekofisk Formation, and the Upper Cretaceous Tor and Hod Formations. The reservoir depth is approximately 2,700 meters. Hod started producing in 1990.

Phase 1 of the field development came on stream in October 2019 after a very successful construction and installation phase, nine years after the discovery in 2010 and four and a half years after the Plan for Development and Operation (PDO) was approved in 2015. The mega project was delivered two months ahead of schedule, NOK 40 Billion below budget (more than 30 percent down from NOK 123 billion, nominal terms based on fixed currency) and with excellent HSE results. Phase 1 of the project consists of four large bridge-linked platforms (the field center), 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 MW power from shore.

After only five weeks of production, all the eight pre-drilled oil production wells were on stream and producing according to expectations at very high rates. In January 2020 drilling of the first new production well (well nine) started from the fixed rig drilling platform, which will drill continuously for the next 3-4 years. It is expected that the Phase 1 production capacity of 440 mboepd will be reached during the summer of 2020.

Powered with electricity from shore, the field has record-low CO2 emissions of well-below 1 kg per barrel. The break-even price is less than USD 20 per barrel and the field will have operating costs below USD 2 per barrel at plateau.

For more details about Phase 2 (the full field development), see separate chapter on "Development Projects" below.

Average daily production net to Aker BP in 2019 amounted to 7.9 mboepd (averaged over the full year, including associated gas), and year end net reserves are estimated at 307 mmboe, representing 34 percent of Aker BP's total P50 reserves.

The Skarv field (23.8 %, operator) is located about 200 kilometres west of Sandnessjøen in the northern part of the Norwegian Sea. The water depth in the area is 350-450 meters. The reservoirs in Skarv contain gas and condensate in Middle and Lower Jurassic sandstones in the Garn, Ile and Tilje Formations. There is also an underlying oil zone in the Skarv deposit in the Garn and Tilje Formations. The reservoirs lie at a depth of 3,300-3,700 meters.

Skarv is developed with an FPSO anchored to the seabed. The FPSO has a life expectancy of 25 years. Production started in 2012.

Net production from Skarv, including test production from Ærfugl, averaged 22.3 mboepd in 2019. The Skarv concession period currently expires in 2033 and the original Skarv FPSO design life is 2035. Year-end 2019 P50 reserves are estimated at 33 mmboe net to Aker BP.

tie-ins of new discoveries. The NOAKA area consists of the discoveries Frigg Gamma Delta, Langfjellet, Frøy, Fulla, Frigg, Rind and Krafla-Askja. Gross resources in the area are estimated to be more than 500 mmboe, with further upside potential from exploration and appraisal. The partners in the NOAKA area are currently in constructive dialogue on how to develop the area.

EXPLORATION Aker BP's ambition is to be the leading exploration company on the Norwegian continental shelf. The company has demonstrated excellent exploration results in 2019 and has exceeded its ambition of discovering 250 mmboe net to Aker BP in the period from 2016 to 2020. From 2016 through 2019, the company has discovered more than 300 mmboe net to Aker BP. Aker BP also conducted a successful drilling campaign around Skarv in 2019. Northwest of the Skarv FPSO, the Ørn exploration well was successfully completed as a gas discovery. Drilling of the Shrek prospect, also in the Skarv area, was concluded to be an oil and gas discovery. In February 2020, Aker BP entered into an agreement with PGNiG Upstream Norway AS to increase Aker BP's interest in the license and transfer the operatorship. The transfer of operatorship to Aker BP will enable an efficient development of this discovery as a

The company continues to seek additional prospect opportunities while improving the available data and technology to create a competitive edge. Aker BP's exploration activity is grouped in two categories; Exploration near own producing fields (Infrastructure led exploration – ILX) and exploration for growth opportunities (new hubs). Over time, the company is seeking a 60/40 balance between ILX and growth exploration targets. tie-back to the Skarv FPSO. In 2019, total investments in exploration amounted to USD 501 (359) million. Exploration expenses in the Income statement amounted to USD 306 (296) million, including expensed dry wells of USD 176 (66) million, while new capitalized exploration expenditures amounted to USD 370 (129) million.

Rumpetroll exploration well encounter gas and traces of petroleum but has been considered non-commercial. Extensive data acquisition and sampling have been conducted in order to increase the company's understanding of the injectite play in the area.

During 2019 Aker BP participated in 16 exploration wells and discovered around 170 mmboe net to Aker BP. The company's exploration drilling tested several new exploration growth options and ILX targets around Aker BP's producing assets. In January 2020, Aker BP was awarded 15 new licenses, including 9 operatorships, through Awards in Predefined Areas (APA 2019). Most of these licenses are located close to the company's existing core areas.

A significant oil discovery was made on Liatårnet in the NOA-KA area. Further data acquisition and analysis will be undertaken to determine the drainage strategy and recovery factor for the discovery. Aker BP's original exploration plan for 2020 consisted of participation in 10 exploration wells and total exploration investments of approximately USD 500 million. Due to the COVID-19 crisis and the sharp reduction in oil prices, the exploration activity level is likely to be reduced.

The company made several new discoveries in the Alvheim area in a drilling campaign launched on the back of the exploration success at Frosk in 2018. The Froskelår Main, as well as the Froskelår NE exploration well, proved oil and gas. The Furthermore, there is a risk that the uncertainty created by the COVID-19 situation could lead to future impairments of the book value of the company's exploration resources.

Net production from Hod averaged 0.8 mboepd in 2019. Year-end 2019 P50 reserves are estimated at 35 mmboe net to Aker BP.

The partner operated fields Atla (10 %), Enoch (2 %) and Gina Krog (3.3 %) produced an average of 1.9 mboepd net to Aker BP in 2019. Year-end 2019 P50 reserves net to Aker BP for these fields are estimated at 5 mmboe, all related to Gina Krog.

DEVELOPMENT PROJECTS

The field development activity in Aker BP was high in 2019, and the progress was good, with production start from both Johan Sverdrup, Valhall Flank West and Oda. In 2020, the planned activity level is slightly lower than 2019. There is also a risk of further reduction in activity level in 2020 and beyond, as the COVID-19 situation may lead to delays and cancellations in existing and new projects.

Johan Sverdrup Phase 2 (11.6 %, partner) (the full field development) is progressing well and according to plan. Phase 2 includes development of a second processing platform, modifications of the riser platform at the field center, five subsea templates in the periphery of the field, in addition to expanding the power-from-shore supply from 100 to 300 MW.

The total power capacity of 300 MW will also serve a number of surrounding fields in the greater Utsira High area (including the Edvard Grieg, Ivar Aasen, Gina Krog and Sleipner fields) by 2022 and saves in total close to 1.2 million tonnes of CO2 emissions, annually.

Contracts awarded so far in Phase 2 amount to more than NOK 20 billion. Phase 2 will increase the production capacity by 220 mboepd to a full field plateau capacity of 660 mboepd. Capital expenditures are estimated at NOK 41 billion (nominal terms based on fixed currency). Production start is planned for the fourth quarter 2022.

Ærfugl (23.8 %, operator) including the Snadd outer field (30.0 %, operator) is a nearly 60 km long and just 2-3 km wide gas condensate field, situated close to the Aker BP-operated Skarv FPSO.

The PDO, approved by Norwegian authorities in April 2018, covers the full-field development and includes the resources in both the Ærfugl and Snadd Outer fields, which are planned to be developed in two phases. The first phase includes three new production wells in the southern part of the field tied into the Skarv FPSO via a trace heated pipe-in-pipe flowline, in addition to the existing A-1 H well already producing.

The second phase of the development was approved and entered the execute phase according to plan in November 2019. The second phase of the project consist of 1 production well drilled through the existing Idun template, and two production

wells in the northern part of the field. Drilling of the first well through the Idun template is scheduled as part of the Ærfugl phase 1 drilling campaign, with production start planned in the summer of 2020. For the two remaining satellite wells, production start is planned in the fourth quarter 2021.

Remaining reserves for Ærfugl are estimated at 67 mmboe net to Aker BP.

Valhall Flank West (90 %, operator) is a project that continues the development of the Tor formation in Valhall on the western flank of the field. On 16 December 2019 the V-9 well was brought onstream thus marking successful first oil for the Flank West alliance project.

Valhall Flank West has been developed from a new Normally unmanned installation, tied back to the Valhall field center for processing and export. The PDO was approved in March 2018 with six production wells originally planned. Since the PDO the partnership has matured and sanctioned an additional three wells bringing the total Flank West well count to nine which will successively be drilled, completed and brought onstream as they are stimulated.

Remaining reserves for Valhall Flank West are now included in the Valhall year-end reserves estimate of 287 mmboe net to Aker BP.

Skogul (65 %, operator) is located 34 kilometres north of Alvheim at a water depth of 110 meters. The productive reservoir is within the Eocene Balder and Frigg formation deep marine deposited sandstone members at a depth of approximately 2,100 meters. The PDO was approved in March 2018, and the field is developed with a single multilateral production well tied back to the Vilje field, utilizing the existing pipeline from Vilje to the Alvheim FPSO.

The Skogul well drilling activity started in July 2019 but was suspended due to the issues with the eastern MWA at Alvheim. The rig returned to Skogul when the MWA had been repaired. Production commenced in the first quarter 2020. Aker BP has booked 6 mmboe as net reserves for Skogul.

Oda (15 %, partner) has been developed with a subsea template tied back to the Ula field center via the Oselvar infrastructure. The Oda field started production mid-March 2019. Natural gas from Oda supports the Ula development strategy by providing gas for the Water Alternating Gas (WAG) injection regime. Aker BP has booked 4 mmboe as net reserves for Oda.

In addition to the sanctioned projects, Aker BP and the other partners have performed detailed studies of different development solutions for the NOAKA area (North of Alvheim and Krafla-Askja). The premise has been that a development should capture all discovered resources in the area and facilitate future

Except for the changes mentioned above, the applied accounting principles are in all material respects the same as for the previous financial year.

HEDGING

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.

At year-end 2019, the company had purchased oil put options with strike prices of around USD 54 per barrel for approximately 60 percent of the expected oil production for the first half of 2020 (after tax).

THE GOING CONCERN ASSUMPTION

The world is currently in the middle of the COVID-19 crisis, and how it will unfold remains uncertain. Aker BP is taking measures to mitigate substantial negative impact for the company. However, in a worst-case scenario, the COVID-19 crisis may have devastating effects for the world economy, including Aker BP.

The COVID-19 crisis increases the risk regarding the going concern assumption for most companies, and this is also the case for Aker BP. Although the risk has increased, the assessment is that the company is able to continue as a going concern.

Therefore, 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. The company is continuously considering various sources of funding to facilitate the expected growth of the company. Cash flow from operations, combined with the total available liquidity, is expected to be more than sufficient to finance the company's commitments in 2020.

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 2019, or the result for 2019, other than those presented in the Board of Directors' Report or that otherwise follow from the financial statements.

RESOURCE ACCOUNTS

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 666 (683) mmboe, while net P50/2P reserves amounted to 906 (917) mmboe at year-end 2019. See note 31 for a more detailed review of the resource accounts. The reserves have been certified by an independent third party.

PROFIT FOR THE YEAR

The Board of directors proposes that the profit for the year is transferred to retained earnings.

The annual accounts

The group prepares its financial statements in accordance with International Financial Reporting Standards (IFRS) as adopted by EU and the Norwegian Accounting Act.

INCOME STATEMENT

The group's total income amounted to USD 3,347 (3,752) million. Total production volume was 56.9 (56.8) mmboe. The average realized liquids price was 64.8 (70.8) USD per barrel, while the realized price for natural gas averaged USD 0.18 (0.29) per standard cubic metre (scm).

Production costs for the oil and gas sold in 2019 were USD 720 (694) million. Production costs per boe produced in 2019 amounted to USD 12.4 (12.1). Exploration expenses amounted to USD 306 (296) million and were mainly related to dry and non-commercial wells, seismic data and general exploration activities. Depreciation amounted to USD 812 (752) million.

Impairments amounted to USD 147 (20) million related to technical goodwill on Ula/Tambar. A breakdown of the impairment charges is included in note 13 to the financial statements.

Other operating expenses amounted to USD 35 (17) million. The majority of other operating expenses are relating to preparation for operation, non-license related costs and IT costs.

The company reported an operating profit of USD 1,327 (1,972) million. The pre-tax profit amounted to USD 1,084 (1,802) million, and the tax expense amounted to USD 943 (1,326) million.

The tax rules and tax calculations are described in notes 1 and 10 to the financial statements.

The net profit was USD 141 (476) million.

STATEMENT OF FINANCIAL POSITION

Total assets at year-end amounted to USD 12,227 (10,709) million.

Equity amounted to USD 2,368 (2,977) million at the end of 2019, corresponding to an equity ratio of 19 (28) percent.

At 31 December 2019, gross bank and bond debt totaled USD 3,287 (2,018), of which bonds made up 57 percent.

The company successfully put in place a new capital structure in 2019. The previous USD 4 billion secured bank facility was replaced with a new USD 4 billion senior unsecured facility at lower cost and extended maturity. The company also issued a 5-year USD 750 million bond. In January 2020, the company issued a 5-year USD 500 million bond and a 10-year USD 1 billion bond.

Aker BP is currently rated by three rating agencies, S&P, Fitch and Moody's. During 2019, S&P and Fitch announced invest-

ment grade ratings (BBB-) on Aker BP, strengthening our credit profile. Rating from Moody's is one notch lower at Ba1. All ratings had stable outlook as of year end 2019. The risk of downgrades to the credit ratings has increased as a result of the COVID-19 situation and the recent drop in global oil prices.

At the end of the year, the company had total available liquidity of USD 2.7 (3.1) billion, comprising USD 107 (45) million in cash and cash equivalents, and USD 2.55 (3.1) billion in undrawn credit facilities. For information about terms on the credit facilities, see note 24.

CASH FLOW AND LIQUIDITY

Net cash flow from operating activities amounted to USD 1,885 million, down from 3,800 in 2018 that included tax refunds of USD 1.5 billion.

Net cash flow used in investment activities amounted to USD 2,178 (2,147) million. The main item was investments in fixed assets of USD 1,703 (1,313) million.

At the end of 2019, financial covenants for the company's debt instruments were comfortably within applicable thresholds. The company has a robust balance sheet and ample financial flexibility. The company's liquidity was further strengthened in January 2020 with the previously mentioned issuance of new bonds, which increased the available liquidity to approximately USD 4 billion.

In the start of 2020, due to the uncertainty related to both COVID-19 and the oil market weakness, the near-term cash flow outlook has deteriorated. In this situation, the company's main financial priority is to protect the liquidity and the robustness of its balance sheet, and to retain its investment grade (IG) credit profile. The company is prepared to make necessary adjustments in investment plans and shareholder distributions for this purpose.

CHANGES IN ACCOUNTING STANDARDS

As described in note 1, IFRS 16 Leases entered into force from 1 January 2019. The standard introduces a single on-balance sheet accounting model for all leases, which results in the recognition of a lease liability and a right-of-use asset in the balance sheet. The accounting principles applied are in line with the description provided in the group's annual financial statements for 2018. The impact on the balance sheet is presented on separate balance sheet items, and further details are provided in the notes, in particular note 12 and 26. The group has applied the modified retrospective approach with no restatement of comparative figures.

Prior to 2019, the group recognized revenue on the basis of the proportionate share of production during the period, regardless of actual sales (entitlement method). Due to recent development in IFRIC discussions, the group decided to change to the sales method from 1 January 2019. This means that 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. Comparative figures have been restated in line with IAS 8.

Security

Aker BP divides security into three main areas: personnel, object and information security. The company works within these areas to protect the company's values in accordance with relevant legislation and company needs. This work is also an integrated part of Aker BP's risk and barrier management.

Security differs from safety by focusing solely on unwanted events caused by intentional actions. Through intelligence, value and threat assessments, as well as by raising awareness in the company, we work to ensure that neither our business nor our personnel are directly affected by threat agents.

In 2019 Aker BP took action to increase mitigating actions in respect of cyber risk and to increase the overall maturity within cyber security. This resulted in a company-wide project to increase cyber resilience in existing digital infrastructure and a partnership with an external company to onboard new capacities for detecting cyber threats and managing incidents.

The company has enabled a more comprehensive security capability and developed a new threat intelligence capacity program to reduce uncertainty and enhance decision support to the Executive Management Team and relevant business units.

Furthermore, Aker BP has established valuable collaboration with the Aker ASA security group and exploited benefits and synergies with other Aker companies in a common effort to prevent and handle security matters. The company has continued its work on aligning a systematic and holistic approach to security risk management work and matured the company within the different security areas.

Climate strategy

BP's strategy and decision making. The Board of Directors has ownership of climate related objectives and expectations in Aker BP's climate strategy, and reviews and guides the major plans of action when it comes to investment decisions for climate initiatives.

In 2019, the company's CO2 intensity was below 7 kg CO2/boe (equity share), which is less than half the global average, and below the average for the NCS. From 2020 on, the company's goal is to deliver an emission intensity below 5 kg CO2/boe (equity share). The company has set a methane intensity target duction measures. Power from shore (hydro-electric power) is part of the active energy management within the company, and in 2019 we continued the feasibility studies for some of the existing fields in relation to life extension. Valhall already has power from shore and Ivar Aasen will receive power from shore in 2022 (receives power from nearby asset Edvard Grieg today).

Aker BP acknowledges the conclusions from the Intergovernmental Panel on Climate Change (IPCC) and is committed to take responsibility for the company's carbon footprint. Climate issues are formally integrated and embedded into Aker 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 number of years of work experience affect the pay level of individual employees.

In cases where new energy-intensive equipment is purchased, the equipment must be as energy-efficient as possible and be of low-emission technology. The company has also started to investigate how to develop data driven energy optimization through our digitalization program in collaboration with Cognite. This will be further pursued in 2020.

EMPLOYEES AND WORKING CONDITIONS

Status of employees and recruitment

• At year-end 2019, the company had 1,742 (1,649) employees. • Aker BP recruited 164 new employees and 11 apprentices
• in 2019. • Aker BP has a long-standing collaboration with graduate schools and universities to recruit talent as well as cooperation with regards to student internships.

Equal opportunities

of less than 0.20 percent. In 2019 the company's upstream methane intensity was 0.09 percent. Aker BP's improvement agenda includes energy management and the implementation of energy efficiency and emission re-The company is committed to maintaining an open and constructive dialogue with the employee representatives and has arranged meetings on a regular basis throughout the year. Four local trade unions are registered as being represented in the company; Tekna, Lederne, SAFE and Industri Energi.

The company endeavors to maintain a working environment with equal opportunities for all based on qualifications, irrespective of gender, ethnicity, sexual orientation or disability.

In December 2019, women held 21.6 percent of the positions in the company. The share of women on the Board of Directors was 36 percent. The share of women in the executive management team was 27 percent and in the middle management it was 19 percent.

At the end of 2019, 9.1 percent of the employees were of non-Norwegian origin.

The working environment

Aker BP has a working environment committee (AMU) 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.

HSSE and organization

Health, Safety, Security and Environment (HSSE) is always the number one priority in all of Aker BP's activities. The company strives to ensure that all its operations, drilling campaigns and projects are carried out under the highest HSSE standards.

HEALTH, SAFETY AND THE ENVIRONMENT IN AKER BP'S OPERATIONS

Aker BP shall be a safe workplace, where the goal is to prevent any kind of harm. 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.

The company's overall HSSE performance displays a positive trend. However, to meet our ambition of no harm to people we need to maintain our continuous effort to seek improvements in our HSSE culture and management practices.

During 2019, Aker BP experienced zero Process Safety Events (PSE), which is an encouraging result that provides a confirmation of our major risk management processes and tools. However, seven incidents with high potential were reported. Out of these, four events involved dropped objects with material damage or potential injury. One of the events involved work at height without the appropriate safety equipment as well as an instance of

work in a 690V cabinet without proper safety precautions. The most serious event with regards to potential consequences was an incident of confirmed gas detection on Ula resulting from an open flange on the flare system. These incidents were thoroughly investigated in accordance with the company's established event management processes. The learnings have been implemented both locally and, if relevant, across all operating assets. The Total Recordable Injuries Frequency (TRIF) increased slightly in 2019 to 3.1 compared to a TRIF of 2.98 in 2018. The Serious Incident Frequency (SIF) remains unchanged at 0.6.

Moving forward we will work systematically to understand our successes as a basis for further improving our HSSE performance. We believe that combining risk insight with learnings from events and knowledge on what we do when we succeed is the key to improving our HSSE performance further.

The Petroleum Safety Authority (PSA) carried out 26 audits of Aker BP operations and activities in 2019. Other authorities, such as the Norwegian Environmental Agency (NEA) and the Norwegian Radiation and Nuclear Safety Authority, conducted nine audits.

Aker BP received two notices of order in 2019; one from the PSA related to the audit «Logistics and management of health risk on Ula D and P» and one from the Norwegian Environment Agency related to the audit "Discharge to sea/air and non-conformance management" at Ivar Aasen. Aker BP complied with both orders in accordance with the set deadline.

RESEARCH AND DEVELOPMENT

• Increased understanding of subsurface and digitalization
• Direct link to our corporate strategy, either directly supporting our activities or creating intangible values (knowledge, methods and processes) that provide a competitive advantage
• Sizeable projects with momentum, dedicated people, with significant impact potential

The aim of Aker BP's Research & Development (R&D) efforts is to support our journey to become the leading independent offshore E&P company. We invest in R&D across our whole value chain, and we have a balanced portfolio of projects targeting knowledge and methods, physical technology development, and digital/software development. We led or participated in around 120 projects in 2019 with a total spend close to NOK 500 million. This is a significant increase in activity level from 2018, in line with our company's growth and ambition to deliver value accretive knowledge and technology to our assets. While we work on a broad range of topics, we have a set of strategic priorities to guide our investments: based on density CORPORATE GOVERNANCE Aker BP believes that good corporate governance with a clear distribution of roles and responsibility 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

With our current business plan, we see several areas where research and technology development will support resource growth and recovery, ensure safe operations, lower cost, and minimize the climate footprint. Some highlights from our R&D portfolio are:

• Continuing our development of a platform for acquisition, processing and storage of data from industrial sensors, meeting big data, robotics and machine learning challenges
• Enable remote control and automated lifting operations for the future crane solutions on unmanned installations
• "Digital oil field": Developing monitoring systems for real time production optimization, linked to modelling tools and enabling automatization of recommendations for production optimization

• Developing a downhole valve that separates water/gas

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 17 October 2018, unless otherwise specified.

An account of corporate governance is provided in a separate section of the annual report and on the company's website www.akerbp.com.

The company has emphasized the importance of providing accurate information in interim reports, capital market updates and through direct dialogue with relevant authorities.

REPORTING OF PAYMENTS TO GOVERNMENTS

Aker BP has prepared a report on government payments in accordance with the Norwegian Accounting Act § 3-3 d) and the Norwegian Securities Trading Act § 5-5a. 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 report is provided in a separate section of the annual report and on the company's website www.akerbp.com.

In the Board's view, the working environment in Aker BP during 2019 was good. This was confirmed through employee satisfaction surveys conducted during 2019, where the results showed good and consistent scores over time on questions related to working environment.

Sickness absence

In 2019, the total sickness absence in Aker BP was 2.4 percent, which is significantly lower than the national average of 5 percent in Norway. For onshore personnel the figure was 2.2 percent. For offshore personnel, the figure was 3.1 percent, which is comparable with other NCS operators.

Ethics and Integrity

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.

Aker BP's Code of Conduct sets out requirements for good business conduct and personal conduct for all employees of Aker BP and members of its governing bodies. The code also applies to directors, contract personnel, consultants and others who act on Aker BP's behalf. It has been developed in dialogue with the management group and is anchored with the Board of Directors. The Code of Conduct is available on our intranet and the company's website.

Social Responsibility

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, organizations and authorities to achieve mutual understanding of expectations, facilitate direct and indirect local benefits and create opportunities for stakeholders.

Stakeholder engagement

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 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.

Local business and community benefits

Aker BP is committed to 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 company's Ærfugl development field, located offshore west of Helgeland, is in this category.

Aker BP has continued the contract strategy from Skarv to the Ærfugl development project, where the company keep focus on four elements to stimulate local engagement and value creation;

• 1. Maximizing the local impacts
• 1. Decentralized contracts
• 1. Local procurement function and active supplier development
• 1. Close contact and cooperation with Nordland County, local municipalities in Helgeland, business, schools and educational institutions.

Supplier/vendor seminars and one-to-one meetings have been conducted, focusing on how local businesses can position themselves to win contracts. Splitting up contracts in sizes manageable for local businesses and their capacity, has given them the opportunity to compete in tendering processes.

Aker BP is a member of the Oil and Gas Cluster Helgeland and Petro Arctic, both organizations located in Northern Norway with 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 Tverrfaglig Opplæringskontor», «Studiesenter Ytre Helgeland», «Kunnskapsutvikling 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.

company conduct business. Financial systems, supply systems, resource system, even the human population system may solely or by combination be shocked as a result 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 behavior could be driven by fear and reactivity.

The company may face situations where there is extensive strain or full-scale shortage or resources (e.g. personnel, goods & services, finances) to perform our business activities as a result from systemic risk. Any such conditions could drain cashflow, have material negative effect on our financial condition, force undesired change in strategic direction, and impact our ability to conduct business.

• Exploration, development and production operations involve numerous safety and environmental risks and hazards that may result in material losses or additional expenditures

• The market in which the company operates is highly competitive

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 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 cash-flow and financial position. 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 could be at risk from such climatic events. • The company'a current production and expected future production is concentrated in a few fields Aker BP's production of oil and gas comes 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, 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.

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, or reducing the demand for hydrocarbons and refined petroleum products.

The oil and gas industry is very 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 maneuver the competitive landscape may have a material effect on the company and its growth ambition. • Climate change regulation could have negative effect on the company The company's business and results of operations could be adversely affected by climate change and the adoption of 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 unitized 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 condition and prospects.

• There are risks related to redetermination of unitized petroleum deposits

Risk factors

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.

Response and measures we use to manage or mitigate our risks are embedded in our governance and management system complemented by our risk management framework.

Risk-based assurance of the business management system requirements is governed by the company's three lines of defence model. Assurance is an activity to provide confidence that quality requirements will be fulfilled. Aker BP's three lines of defence model is continually under improvement with regards to processes and tools to enhance execution.

• Aker BP's business, results of operations, cash flow and financial condition depend significantly on the level of oil and gas prices and market expectations of these, and may be adversely affected by volatile oil and gas prices and by the general global economic and financial market situation

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.

• The company is exposed to systemic risks

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

The company's future capital requirements depend on many factors, including whether the company's cash flow from operations is sufficient to fund the company's business plans. The company may need additional funds in the longer term in order to further develop exploration and development programs or to acquire assets or shares of other companies. In particular, the development projects require significant capital expenditures in the years to come. Even though the company has taken measures to ensure a solid financial basis for the development projects, the company cannot assure that it will be able to generate or obtain sufficient funds to finance the projects. In particular, given the extensive scope of the projects, any unforeseen circumstances or actions to be dealt with that are not accounted for, may result in a substantial gap between estimated and actual costs. Thus, the actual costs necessary to carry out the projects may be considerably higher than currently estimated. These investments, along with the company's ongoing operations, may be financed partially or wholly with debt, which may increase the company's debt levels above industry standards. The general financial market conditions, stock exchange climate, interest level, the investors' interest in the company, the share price of the company, as well as a number of 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.

and other obligations as they come due, or would not result in the company being placed in a less competitive position.

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 unfavorable 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 in underlying interest rates 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 in order 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 is exposed to interest rate and liquidity risk associated with its borrowing portfolio and fluctuations

• Development projects are associated with risks relating to delays and costs

Aker BP's ongoing development 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, as this may result in delays or cost increases.

Although Aker BP believes that the development 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 may be delayed and cost overruns may incur.

Furthermore, estimated exploration costs are subject to a number of assumptions that may not prove to be correct. Any such inability to explore, appraise or develop 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.

• The company is subject to third-party risk in terms of operators and partners

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 is subject to third-party risk in terms of contractors

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 development project timelines and cost.

• Oil and gas production could vary significantly from reported reserves and resources

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. Hence, 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 exploration 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 exploration 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 may become a target of cyber-attacks

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 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 or reputation, and may create exposure to the loss of information, litigation and possible liability.

• Changes in taxation and regulations for the petroleum industry

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 as a result 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 % 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.

• Changes in foreign exchange rates may affect the company's results of operations and financial position

The company is exposed to market fluctuations in foreign exchange rates due to the fact that 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. The COVID-19 crisis has so far resulted in a strengthened USD against NOK, which generally has positive impact on the company's financial measures as most revenue is in USD while much of the expenditure is in NOK. However, volatility in exchange rates generally represents increased risk for the company.

• The company is exposed to risk of counterparties being unable to fulfil their financial obligations

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, operating results, cash flows and financial condition.

• The company is vulnerable to adverse market perceptions

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 and counterparties. 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 flow and financial condition.

• The company is dependent on realization of new technologies and digitizing the value chain

Technology and digitalization is an important part of the company's strategy and we strongly believe those will contribute to Aker BP's growth and improved efficiency. Inefficient implementation of such technologies and digitalization could have a negative effect on the company's strategy and reputation. We also recognize that the development of new technologies and digitalization may require additional funding and support beyond what is expected, and such consequences may adversely affect our reputation, cash-flow, and potentially financial condition.

• Violation of anti-bribery or anti-corruption laws risk

Anti-bribery, anti-corruption, including tax-evasion and anti-money laundering laws apply to the company, potential future joint ventures and associates in countries in which we do business. Any violation of such laws and regulations could have a material adverse effect on our cash flows and financial condition.

• The company is dependent on Senior management and discontinuity may pose a risk

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 finding 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.

• Company financial reporting routines – errors and omissions risk

• The company may be exposed to more stringent HSSE laws and regulations

• The company may be subject to insufficient insurance coverage

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.

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-flow and financial condition. The company's reputation and goodwill could also be adversely affected. by signals of increased production volumes from several major oil producing countries and has caused a significant decline in global oil prices. The long-term impact from these events on the global economy and the oil market is difficult to predict. From an accounting perspective, this could have a significant impact on recoverable amounts of Aker BP's assets. On 8 January 2020, the company issued USD 500 million

• The company may be engaged in litigation arising from other risk factors

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.

The company's operations are subject to extensive HSSE 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. We could incur additional costs in the future due to compliance with these requirements or as a result of violations of, or liabilities under, laws and regulations, such as fines, penalties, clean-up costs and third-party claims. Therefore, HSSE risks, should they materialise, may result in material negative effect to our financial condition. including 9 operatorships in the Awards in Predefined Areas (APA) 2019 licensing round. On 11 February 2020, Aker BP announced that the company had entered into an agreement with PGNiG Upstream Norway AS to swap its 3.3 percent interest in the non-operated Gina Krog field and an 11.9175 percent interest in license 127C, in exchange for a 5 percent interest and operatorship in license 838 and a cash consideration. The transaction is subject to approval by the Norwegian authorities.

During first quarter 2020, the spread of the COVID-19 virus (corona) has caused global disruption with negative consequences both for human health and economic activity. Aker BP has implemented measures to minimize the spread of the virus and minimize the risk of disruptions to its operations.

The corona situation has created significant uncertainty in the global oil market. This uncertainty has been further amplified

3.00 percent Senior Notes due 2025 and USD 1 billion 3.75 percent Senior Notes due 2030.

On 15 January 2020, Aker BP was offered 15 new licenses,

On 24 February 2020, Aker BP disbursed USD 212.5 million in dividends to shareholders.

REPORTING OF PAYMENTS TO GOVERNMENTS

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 licenses are reported, as all payments within the license performed by non-operators will normally be cash calls transferred to the operator and will as such not be payments to the government.

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 income tax is calculated and paid on corporate level and is therefore reported for the whole company rather than license-by-license. The tax payments in 2019 of NOK 5,410 506,720 (including interest) are mainly related to tax instalments for the income year 2018 and income year 2019. CO2 tax 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 and Bøyla) as Alvheim performs the payment and charges the other fields via opex share.

REPORTING OF PAYMENTS

Income tax

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 company is member of the NOx fund and all NOx payments are made to this fund rather than to the government.

Name of field/license	CO2 tax paid in 2019 (NOK)
Alvheim	97 108 741
Ivar Aasen	9 444 645
Hod	499 255
Valhall	12 759 856
Ula	76 835 053
Skarv	176 400 910
Total CO2 paid	373 048 460

NOx

BOARD OF DIRECTORS' – signature page

The Board of Directors of Aker BP ASA Akerkvartalet, 19 March 2020

ØYVIND ERIKSEN Chairman

KJELL INGE RØKKE Board member

ANNE MARIE CANNON

Deputy chair

BERNARD LOONEY Board member

TROND BRANDSRUD Board member

GRO KIELLAND Board member

INGARD HAUGEBERG Board member

KATE THOMSON Board member

ANETTE HOEL HELGESEN Board member

ØRJAN HOLSTAD Board member

TERJE SOLHEIM

Board member

KARL JOHNNY HERSVIK Chief Executive Officer

Area fee

The table below specifies the area fee paid by Aker BP on behalf of the different licenses in 2019. 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 2019 (NOK)
Alvheim	9 249 369
Hod	2 695 000
Skarv	15 606 000
Tambar	5 851 500
Ula	5 790 000
Valhall	8 624 000
Vilje	931 000
Volund	765 000
PL 019C	1 519 000
PL 026	1 470 000
PL 027D	1 377 000
PL 036E	441 000
PL 102D	16 524 000
PL 102F	3 978 000
PL 127C	4 896 000
PL 146	13 311 000
PL 159D	1 071 000
PL 169C	1 377 000
PL 212E	2 142 000
PL 242	2 448 000
PL 261	10 404 000
PL 442	12 986 000
PL 504	1 071 000
PL 685	13 817 984
PL 858	30 330 230
	168 675 083

OTHER INFORMATION REQUIRED TO BE REPORTED

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:

• Total net investments amounted to USD 2,178,431 thousand, as specified in the cash flow analysis in the financial statements
• Sales income (Petroleum revenues) in 2019 amounted to USD 3,338,667 thousand, as specified in Note 4 to the financial statements
• Total production in 2019 was 56,886,136 barrels of oil equivalents, see Note 5 to the financial statements
• For information about purchases of goods and services, reference is made to the Income Statement and the related notes

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.

1. Implementation and reporting on corporate governance

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). The Code can be found on www.nues. no. Adherence to the Code is based on the "comply or explain" principle, which means that a company must comply with all the recommendations of the Code or explain why it has chosen an alternative approach to specific recommendations.

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 the Oslo Stock Exchange and established under Norwegian laws. In accordance with the Norwegian Accounting 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: http://www.akerbp.com/ en/investor/corporate-governance/articles-of-association/.

The Oslo Stock Exchange requires listed companies to publish an annual statement of their policy on corporate governance in accordance with the Code in force at the time. Continuing obligations for companies listed on the Oslo Stock Exchange is available at www.oslobors.no.

Aker BP complies with the current edition of the Code, issued on 17 October 2018, unless otherwise specifically stated. The following statement on corporate governance is structured in the same way as the Code, thus following the 15 chapters included in the Code.

Deviations to the code: None

2. Business

Through an annual strategy process, the Board defines and evaluates the company's objectives, main strategies and risk profiles for the company's business activities such that the company creates value for shareholders. Together with the company's financial status, these objectives are communicated to the market.

It is Aker BP's vision to create the leading independent offshore exploration and production (E&P) company. In order 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.

In the beginning of 2020, the spread of the COVID-19 virus has created increased uncertainty and disruption to the global economy. The situation will affect the company's business activities, and it is the Board's objective to make sure Aker BP is taking 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. Any updates to the company's business plan and/or objectives resulting from this situation will be communicated to the market following Aker BP's procedures for information and communications (cf. chapter 13 of this report).

THE BOARD OF DIRECTORS' REPORT ON CORPORATE GOVERNANCE

The company has adopted 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 including corporate social responsibility and is a guideline for those making decisions on behalf of the company. The Code of Conduct is available on the website http://www.akerbp. com/en/about-us/code-of-conduct/.

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. It is also stated in the Code of Conduct that any form of corruption is not tolerated. Aker BP's Anti-Corruption Policy sets out in more detail the company's expectations with regard to the actions of Aker BP Representatives and Business Partners and is available on the website: https://www.akerbp.com/en/about-us/codeof-conduct/aker-bp-anti-corruption-policy/.

In addition, the company has a sponsorship program to promote the company and its activities. Guidelines for the use of sponsorships are included in the Code of Conduct. Aker BP supports measures that are directly related to the company's business as an oil company, measures that improve the company's profile and measures that can be for the benefit of the employees. Examples of the company's ongoing sponsorships is described in Aker BP's Sustainability Report.

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, including information on matters that relate to human rights, employee rights and social matters, the external environment, the prevention of corruption, the working environment, equal treatment, discrimination and environmental impact. The report is available on the website: https://www. akerbp.com/en/investor/reports/sustainability-report/.

Deviations to the code: None

3. Equity and dividends

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 2019 authorized the Board to approve the distribution of dividends based on the approved annual accounts for 2018. The background of this proposal was to facilitate the company's aim to distribute dividends quarterly. In 2019, the company paid USD 750 million (USD 2.20828 per share) in dividends to shareholders.

The company's financial liquidity is considered to be good, although the near-term cash flow outlook has deteriorated due to the recent drop in global oil prices. At 31 December 2019, the company's cash and cash equivalents were USD 107 million. In addition, available undrawn amounts on committed credit facilities were USD 2.55 billion. Aker BP is currently rated by three rating agencies, S&P, Fitch and Moody's. During 2019, S&P and Fitch announced investment grade ratings (BBB-) on Aker BP, strengthening our credit profile. Rating from Moody's is one notch lower at Ba1. All ratings had stable outlook as of year end 2019. The risk of downgrades to the credit ratings has increased as a result of the COVID-19 situation and the recent drop in global oil prices.

At year-end 2019, the company's book equity was USD 2.37 billion, which represents 19 percent of the balance sheet total of USD 12.27 billion. The market value of the company's equity was USD 11.81 billion (NOK 103.71 billion) on 31 December 2019. As per mid-March 2020, the market value of the company's equity has fallen sharply.

The company is prepared to make necessary adjustments in investment plans and shareholder distributions in order to protect the liquidity and the robustness of its balance sheet, and to retain its investment grade (IG) credit profile.

In April 2019, 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 in order to strengthen the company's equity, convert debt into equity and fund business opportunities. At 31 December 2019, the mandate had not been used.

and transactions with close

The AGM in April 2019 also provided the Board with a mandate to acquire company shares equivalent to 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 2020. At 31 December 2019, 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 521,815 shares (0.14 percent of total shares outstanding). After delivery of these shares, Aker BP held zero treasury shares. 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 ASA and BP P.L.C. 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 ASA and BP P.L.C. offers Aker BP access to expertise and resources within upstream business activities, technology, strategy, transactions and funding. It may be necessary to offer Aker ASA and BP P.L.C. special access to commercial information in connection with such cooperation. Any information disclosed to Aker ASA's and BP P.L.C.'s representatives in such a context will be disclosed in compliance with the laws and regulations governing the stock exchange and the securities market.

BP P.L.C. owned 30 percent of Aker BP. Aker Capital AS is a wholly-owned subsidiary of Aker ASA. Aker ASA and BP P.L.C. accounts for Aker BP in accordance with the equity method.

Deviations to the code: None 4. Equal treatment of shareholders associates The company has one class of shares and all shares carry the same rights. Applicable accounting standards and regulations require Aker ASA and BP P.L.C. to prepare their consolidated financial statements to include accounting information of Aker BP. Aker BP is considered an associate of Aker ASA and BP P.L.C. under the applicable accounting standard. In order to comply with these accounting standards, Aker ASA and BP P.L.C. 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 ASA and BP P.L.C. is executed under strict confidentiality and in accordance with applicable regulations on the handling of inside information.

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 in the event that pre-emption rights are waived. Arguments for waiving pre-emption rights will be clearly stated. The Board recognizes Aker ASA's and BP P.L.C.'s contribution as active shareholders. Investor communication seeks to ensure that any shareholders are able to contribute, and management will actively meet with and seek the views of shareholders.

In the event that 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. At 31 December 2019, Aker Capital AS owned 40 percent and Aker BP has no related parties, as defined in the Public Limited Liability Company Act ("Almennaksjeloven"). The company has nevertheless established procedures for transactions with such parties and also extended these to include Aker ASA. The Board of Directors and executive management are very conscious that all relations with Aker ASA and BP P.L.C., its subsidiaries and other companies in which Aker ASA or BP P.L.C. 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.

Deviations to the code: None

5. Shares and negotiability

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 the Oslo Stock Exchange 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 low cost of capital.

Deviations to the code: None

6. General meetings

The General Meeting of shareholders is the company's highest authority. 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.

Preparation for General Meetings

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 https://www.akerbp. com/en/investor/financial-calendar/.

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.

Participation in a General Meeting

The Board ensures that the company's shareholders can participate in the general meeting. According to Article 7 in the Articles of Association, the right to attend and vote at the General Meeting can only be exercised when the share transaction is recorded in the shareholder register no later than the fifth business day prior to the General Meeting (registration date).

Shareholders who are unable to attend a General Meeting are encouraged to vote by proxy. A form for the appointment of a proxy, which allows separate voting instructions to be given for each matter to be considered by the meeting, is included with the notice. The deadline for registration is set as close as possible to the date of the meeting, normally the day before.

Conduct of a General Meeting and agenda for AGM

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 given period prior to the General Meeting. Appropriate arrangements are made for shareholders to vote separately on candidates nominated for election to the company's corporate bodies.

Aker BP's General Meetings are chaired by the person elected by the General Meeting.

The Code 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.

Deviations from the code: The code 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.

7. Nomination committee

Minutes of General Meetings are published on the company's website and through a stock exchange announcement. pany's largest shareholder Aker ASA. Among the shareholder-elected Board members, two (Bernard Looney and Kate Thomson) are affiliated with the company's second largest shareholder BP P.L.C.. All other Board members are considered independent of the company's two main shareholders, as well as of the company's material business contacts. All Board members are considered independent of the company's executive personnel.

The Nomination Committee should be composed in such a way that it represents a wide range of shareholders' interests. If possible, both genders should be represented in the committee. The Nomination Committee's duties are also stated in Article 8 in the Articles of Association. The committee shall propose candidates for - and remuneration to - the Board of Directors and the Nomination Committee and justify its recommendation for each candidate separately.

Article 8 in the company's Articles of Association stipulates that the Nomination Committee shall consist of three members elected by the General Meeting. It also stipulates that the majority of the members shall be independent of the Board and the executive management and that the members shall be elected for a period of two years at a time. The committee's remuneration is determined by the General Meeting. 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. Board members possess strong experience from banking and finance, oil and gas sector in general, and reservoir engineering, exploration and field development in particular.

8. Board of Directors: Composition and independence

The Board of Aker BP consisted of eleven members at 31 December 2019. The company's Articles of Associations Article 5 stipulates that the Board shall consist of up to eleven members.

At the AGM in April 2019, Arild Støren Frick was re-elected as the Chair of the Nomination Committee for two years. Finn Haugan and Hilde Myrberg were re-elected as members of the Nomination Committee for two years in 2018. No members of the committee are members of executive management or the Board of Aker BP. An overview of the expertise of the Board members is available on the website: http://www.akerbp.com/en/about-us/ board-of-directors/. Deviations from the code: None

In 2019, the Board conducted a total of 10 Board meetings. Participation was 92 percent.

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 http://www.akerbp.com/proposecandidate/. Deviations from the code: None The Board has authority over and is responsible for supervising the company's business operations and management 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 at all times. 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, the Board acknowledges its responsibility for the overall management of the company. The Board is responsible for:

The general meeting elects the Chairman of the Board. The term of office for members of the Board is two years at a time. C. Ensuring that shareholders have access to timely and correct information about financial circumstances and important business-related events in accordance with relevant legislation, and

9. The work of the board of directors

Among the shareholder-elected Board members, two (Kjell Inge Røkke and Øyvind Eriksen) are affiliated with the com-D. Ensuring the establishment and securing the integrity of the company's internal control and management systems.

A. Drawing up strategic plans and supervising these through regular reporting and reviewing,

B. Identifying significant risks to Aker BP's activities and establishing appropriate systems to monitor and manage such risks,

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.

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 carried out a self-evaluation of its own performance for 2019 which included an evaluation of the Board's competence and potential areas for strengthening this competence.

The Board ensures that members of the Board of Directors and executive personnel make 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 provides clear guidelines as to how employees and representatives of the company's governing bodies should act in situations where there is a risk of conflicts of interest and partiality.

Audit and Risk Committee

The Board has established an Audit and Risk Committee consisting of the following Board members:

• Trond Brandsrud, Chair
• Anne Marie Cannon
• Kate Thomson

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 ASA (the largest shareholder in Aker BP). Kate Thomson is Group Treasurer for BP P.L.C.

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 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. In 2019, the committee held eight 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 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 four years.

Oversight of HSSE and operational risks

Oversight of HSSE and operational risks is retained directly by the Board. In addition, the Board has established a committee to strengthen the administration work on health, safety, cyber security and environmental matters. The committee reports to the Board on a quarterly basis and consist of the following eight members:

• Fawas Bitar, Head of Chief Executive Upstream's Office, BP – Chair of the committee
• Karl Johnny Hersvik, CEO, Aker BP
• Marit Blaasmo, SVP HSSEQ, Aker BP
• Kjetel Digre, SVP Operations & Asset Development, Aker BP
• Knut Sandvik, SVP Projects, Aker BP
• Ariel Flores, Head of North Sea, BP
• Tony Brock, Head of Safety and Operational Risk, BP

The committee reviews risks related to operating activities. The committee shares experiences and practices in the HSSE area, learnings from incidents and aligns leadership experiences on common areas of focus in relation to management of safety and operational risks. In 2019, the committee held four meetings.

Compensation and Organizational Development Committee

The Board has a Compensation and Organizational Development Committee consisting of the following three Board members:

• Øyvind Eriksen, Chair
• Gro Kielland
• Terje Solheim

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 2019, the committee held three meetings.

In addition to the Audit and Risk Committee and Compensation and Organizational Development Committee, 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.

Deviations from the code: None

10. Risk management and internal control

Risk Management

Appropriate internal control and risk management contributes to transparency and quality reporting for the benefit of the company, stakeholders, shareholders' long-term interests and the operational challenges as an operator on the Norwegian continental shelf.

The company continuously and systematically operates a robust and transparent risk management process vertically and horizontally throughout the organization.

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 (e.g. the Petroleum Safety Authority Norway (Norwegian PSA) and the Norwegian Environment Agency), and license partners.

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 reported through the company Enterprise Risk Management process.

The Business Management System (BMS) is formed by a cultural framework and a structural framework and encompasses the company's guidelines for how it integrates considerations related to stakeholders into its creation of value (Code of Conduct). The structural framework consists of twelve common governing models, the asset value chain and a set of technical support and business support process areas. The purpose of the process is to enable the company to maximize opportunities, minimize threats and optimize achievements of business objectives. Risk is addressed and managed throughout the asset value chain. One common way of working supported by a common infrastructure enables holistic risk management at all levels. The company's risk response includes monitoring of enduring and emerging risks through continuous analysis and engagement with operational management. Mitigating processes and plans are developed for all significant risks. The company may consult external advisors to find the most appropriate and balanced risk response.

Internal control for financial reporting

Aker BP has established a framework for Internal Control for Financial Reporting based on the principles of the COSO (Committee of Sponsoring Organizations of the Treadway Commission) and is operationalized as follows:

• Internal Control Environment
• Risk Assessment
• Risk Response and Control Activities
• Information and communication
• Monitoring

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.

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:

• Effective and appropriate identification and mitigation of financial reporting risks
• Measurement of compliance against procedures
• Appropriate segregation of duties
• Provision of relevant, timely and reliable financial reporting that provides a fair view of Aker BP's business
• Safeguard against fraudulent manipulation of reported figures
• Compliance with all relevant requirements of IFRS

A risk assessment related to financial reporting is performed and documented by management. Risk assessments are monitored by the Audit and Risk Committee on a quarterly basis as part of the quarterly reporting process. The Board of Directors approves the overall risk assessment related to financial reporting on an annual basis. In 2019, the following main risk areas were identified related to financial reporting:

• Impairment of goodwill, tangible and intangible assets There is a risk that reductions in recoverable values below book values are not identified and recorded in an appropriate manner
• Tax Complexity in tax regulations and calculation entail risk of error in financial reporting
• Asset retirement obligation There is a risk of errors in the estimates and calculations during the ARO process

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. An "Issue list" is established to summarize accounting and tax effects and judgment arising from events and activities. Both the auditor and the Audit and Risk Committee review and discuss the "Issue list" 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.

In 2020, Aker BP will continue to focus on improvements of internal controls and further develop the ERP system that was implemented in 2018. The internal control environment has been evaluated and will be continuously improved as part of the new SAP solution for Aker BP.

Deviations from the code: None

11. Remuneration of the board of directors

The remuneration of the Board members is not performance-based 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 2019.

Deviations from the code: None

12. Remuneration of executive personnel

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. Note 7 to the annual accounts contains details about the remuneration of the Board and Executive Management Team (EMT), including payroll, bonus payments and pension expenses.

Members of EMT are covered under the same budget, guidelines and limitations as onshore Aker BP employees in the annual salary review. The CEO base salary is determined by the Board.

The bonus for all employees, including the EMT, is determined by the performance on a set of company-wide performance indicators (KPIs) and the delivery on a set of carefully selected company priorities. These KPIs and company priorities are

weighted equally. KPI's include measures on safety, production, production cost, reserve additions, value creation and shareholder return. Company priorities are either important improvement initiatives or activities with clear deliverables that are critical for the company's future success.

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. 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.

basic amount (12G) for all employees including the executive management.

Deviations from the code: None

13. Information and communications

In addition, certain members of the EMT participate in a fiveyear 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 Stock Exchange Energy Index and the Stoxx 600 Europe Oil & Gas index (both weighing 50 percent each). 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 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 continued to be a defined contribution plan capped at twelve times the National Insurance scheme 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 the Oslo Stock Exchange. Aker BP holds open presentations or conference calls in connection with the publication of the company's quarterly results in addition to an annual capital markets update. The presentations are webcasted for the benefit of investors who are prevented from attending or do not wish to attend the presentations. At the presentations, executive management review and comment on the published results, market conditions and the company's future activities.

All stock exchange announcements are made available on the Oslo Stock Exchange website, www.newsweb.no, as well as the company's website (www.akerbp.com) at the same time. The announcements are also distributed to news agencies and other online services.

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 Stock Exchange Code of Practice for IR of 1 July 2019. Aker BP will reduce its contacts with analysts, investors and journalists in the final two weeks 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 future outlook. This is to ensure that all interested parties in the market are treated equally. Deviations from the code: None

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.

14. Take-overs

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. 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 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

15. Auditor

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 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

			Group		Parent
OVERVIEW OF THE FINANCIAL STATEMENTS AND NOTES				Restated		Restated
Income statement	(USD 1 000)	Note	2019	2018	2019	2018
Statement of comprehensive income
	Petroleum revenues	4	3 338 667	3 713 022	3 338 667	3 713 022
Statement of financial position	Other operating income	4	8 421	38 600	8 421	38 600
Statement of changes in equity - group and parent
Statement of cash flow	Total income		3 347 088	3 751 622	3 347 088	3 751 622
Notes to the accounts
Note 1 Summary of IFRS accounting principles
Note 2 Overview of subsidiaries	Production costs	5	720 321	693 585	720 321	693 585
Note 3 Segment information	Exploration expenses	6	305 516	295 908	305 516	295 908
Note 4 Income	Depreciation	12	811 874	752 437	811 874	752 437
Note 5 Produced volumes and over/underlift adjustment	Impairments	12, 13	146 808	20 172	146 808	20 172
Note 6 Exploration expenses	Other operating expenses	7,8	35 328	17 037	35 328	17 037
Note 7 Payroll expenses and remuneration
Note 8 Auditors fee	Total operating expenses		2 019 848	1 779 140	2 019 848	1 779 140
Note 9 Financial items
Note 10 Taxes
Note 11 Earnings per share	Operating profit		1 327 241	1 972 481	1 327 241	1 972 481
Note 12 Tangible fixed assets and intangible assets
Note 13 Impairments	Interest income		16 490	25 976	16 490	19 114
Note 14 Accounts receivable	Other financial income		35 255	141 823	35 255	185 415
Note 15 Other short-term receivables	Interest expenses		76 587	120 033	76 587	120 033
Note 16 Inventories	Other financial expenses		218 145	218 272	218 145	281 689
Note 17 Other non-current assets
Note 18 Cash and cash equivalents
Note 19 Share capital and shareholders	Net financial items	9	-242 986	-170 505	-242 986	-197 192
Note 20 Bonds
Note 21 Provision for abandonment liabilities
Note 22 Derivatives	Profit before taxes		1 084 254	1 801 976	1 084 254	1 775 289
Note 23 Provisions for other liabilities
Note 24 Other interest-bearing debt	Taxes (+)/tax income (-)	10	943 204	1 326 198	943 204	1 324 619
Note 25 Other current liabilities
Note 26 Lease agreements	Net profit		141 051	475 778	141 051	450 670
Note 27 Commitments
Note 28 Transactions with related parties
Note 29 Financial instruments	Weighted average no. of shares outstanding basic and diluted	11	360 014 176	360 113 509	360 014 176	360 113 509
	Basic and diluted earnings USD per share	11	0.39	1.32	0.39	1.25

STATEMENT OF COMPREHENSIVE INCOME

SD 1 000)	Note
ofit for the period

		Group		Parent
		Restated			Restated
(USD 1 000)	Note	2019	2018	2019	2018
Profit for the period		141 051	475 778	141 051	450 670
Items which will not be reclassified over profit and loss (net of taxes)
Actuarial gain/loss pension plan		-4	8	-4	8
Items which may be reclassified over profit and loss (net of taxes)
Currency translation adjustment		-	-72 612	-	-
Reclassification to profit and loss		-	47 504	-	-
Total comprehensive income in period		141 046	450 678	141 046	450 678

Income statement Statement of comprehensive income Statement of financial position Statement of changes in equity - group and parent 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 Produced volumes and over/underlift adjustment 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 Provisions for other liabilities Note 24 Other interest-bearing debt Note 25 Other current liabilities Note 26 Lease agreements Note 27 Commitments Note 28 Transactions with related parties Note 29 Financial instruments Note 30 Investments in joint operations Note 31 Events after the balance sheet date Note 32 Classification of reserves and contingent resources (unaudited) Statement by the Board of Directors and Chief Executive Officer Alternative performance measures Independent Auditor's Report

FINANCIAL STATEMENTS WITH NOTES

STATEMENT OF FINANCIAL POSITION

		Group		Parent
			Restated		Restated
(USD 1 000)	Note	31.12.2019	31.12.2018	31.12.2019	31.12.2018
EQUITY AND LIABILITIES
Equity
Share capital	19	57 056	57 056	57 056	57 056
Share premium		3 637 297	3 637 297	3 637 297	3 637 297
Other equity		-1 326 767	-717 814	-1 326 767	-717 814
Total equity		2 367 585	2 976 539	2 367 585	2 976 539
Non-current liabilities
Deferred taxes	10	2 235 357	1 752 757	2 235 357	1 752 757
Long-term abandonment provision	21	2 645 420	2 447 558	2 645 420	2 447 558
Provisions for other liabilities	23	403	107 519	403	107 519
Long-term bonds	20	1 630 936	1 110 488	1 630 936	1 110 488
Long-term derivatives	22	-	26 275	-	26 275
Long-term lease debt	26	202 592	-	202 592	-
Other interest-bearing debt	24	1 429 132	907 954	1 429 132	907 954
Current liabilities
Trade creditors		144 942	105 567	144 942	105 567
Short-term bonds	20	226 700	-	226 700	-
Accrued public charges and indirect taxes		25 974	25 061	25 974	25 061
Tax payable	10	361 157	551 942	361 157	551 942
Short-term derivatives	22	42 994	8 783	42 994	8 783
Short-term abandonment provision	21	142 798	105 035	142 798	105 035
Short-term lease debt	26	110 664	-	110 664	-
Other current liabilities	25	660 132	583 894	660 132	583 894
Total liabilities		9 859 201	7 732 833	9 859 201	7 732 833
TOTAL EQUITY AND LIABILITIES		12 226 786	10 709 371	12 226 786	10 709 371

Kate Thomson, Board member Bernard Looney, Board member

Gro Kielland, Board member Terje Solheim, Board member

Ingard Haugeberg, Board member Anette Hoel Helgesen, Board member

The Board of Directors and the CEO of Aker BP ASA Akerkvartalet, 19 March 2020

STATEMENT OF FINANCIAL POSITION

Øyvind Eriksen, Chairman of the Board Kjell Inge Røkke, Board member Anne Marie Cannon, Deputy Chair Trond Brandsrud, Board member ØYVIND ERIKSEN

Karl Johnny Hersvik, Chief Executive Officer Ørjan Holstad, Board member INGARD HAUGEBERG

		Group		Parent
(USD 1 000)			Restated		Restated
	Note	31.12.2019	31.12.2018	31.12.2019	31.12.2018
ASSETS
Intangible assets
Goodwill	12	1 712 809	1 860 126	1 712 809	1 860 126
Capitalized exploration expenditures	12	621 315	427 439	621 315	427 439
Other intangible assets	12	1 915 968	2 005 885	1 915 968	2 005 885
Tangible fixed assets
Property, plant and equipment	12	7 023 276	5 746 275	7 023 276	5 746 275
Right-of-use assets	12	194 328	-	194 328	-
Financial assets
Long-term receivables		27 418	37 597	27 418	37 597
Other non-current assets	17	10 364	10 388	10 364	10 388
Long-term derivatives	22	2 706	-	2 706	-
Total non-current assets		11 508 183	10 087 710	11 508 183	10 087 710
Inventories
Inventories	16	87 539	93 179	87 539	93 179
Receivables
Accounts receivable	14	193 444	162 798	193 444	162 798
Tax receivables	10	-	11 082	-	11 082
Other short-term receivables	15	330 516	292 405	330 516	292 405
Short-term derivatives	22	-	17 253	-	17 253
Cash and cash equivalents
Cash and cash equivalents	18	107 104	44 944	107 104	44 944
Total current assets		718 603	621 661	718 603	621 661
TOTAL ASSETS		12 226 786	10 709 371	12 226 786	10 709 371

Chairman

KJELL INGE RØKKE Board member

ANNE MARIE CANNON Deputy chair

BERNARD LOONEY

Board member

TROND BRANDSRUD Board member

GRO KIELLAND Board member

Board member

KATE THOMSON Board member

ANETTE HOEL HELGESEN Board member

ØRJAN HOLSTAD Board member

TERJE SOLHEIM Board member

KARL JOHNNY HERSVIK Chief Executive Officer

STATEMENT OF CASH FLOW

		Group			Parent
			Restated		Restated 2018
(USD 1 000)	Note	2019	2018	2019
CASH FLOW FROM OPERATING ACTIVITIES
Profit before taxes		1 084 254	1 801 976	1 084 254	1 775 289
Taxes paid		-618 593	-606 082	-618 593	-606 082
Taxes refunded		-	1 513 394	-	1 513 394
Depreciation	12	811 874	752 437	811 874	752 437
Net impairment losses	12, 13	146 808	20 172	146 808	20 172
Accretion expenses	9, 21	121 723	128 737	121 723	128 737
Interest expenses (including interest element of lease payments)	9	199 569	200 524	199 569	200 524
Interest paid (including interest element of lease payments)	9	-194 033	-195 659	-194 033	-195 659
Changes in derivatives	4, 9	22 484	11 558	22 484	11 558
Amortized loan costs	9	21 705	29 722	21 705	29 722
Amortization of fair value of contracts		-	56 775	-	56 775
Expensed capitalized dry wells	6, 12	176 419	65 852	176 419	65 852
Changes in inventories, accounts payable and receivables		14 369	-7 800	14 369	-7 800
Changes in other current balance sheet items		98 567	27 964	98 567	54 651
NET CASH FLOW FROM OPERATING ACTIVITIES		1 885 146	3 799 570	1 885 146	3 799 570
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields	21	-104 890	-242 545	-104 890	-242 545
Disbursements on investments in fixed assets	12	-1 703 213	-1 312 697	-1 703 213	-1 312 697
Disbursements on investments in capitalized exploration	12	-370 185	-128 795	-370 185	-128 795
Disbursements on investments in licenses	12	-143	-463 049	-143	-463 049
NET CASH FLOW USED IN INVESTMENT ACTIVITIES		-2 178 431	-2 147 085	-2 178 431	-2 147 085
CASH FLOW FROM FINANCING ACTIVITIES
Net drawdown/repayment of short-term debt	24	-	-1 500 000	-	-1 500 000
Net drawdown/repayment of revolving credit facility	24	1 425 222	-	1 425 222	-
Net drawdown/repayment of reserve-based lending facility	24	-950 000	-380 252	-950 000	-380 252
Net proceeds from bond issue	9, 20	740 159	492 423	740 159	492 423
Payments on lease debt related to investments in fixed assets	26	-88 718	-	-88 718	-
Payments on other lease debt	26	-20 880	-	-20 880	-
Paid dividends		-750 000	-450 000	-750 000	-450 000
NET CASH FLOW FROM FINANCING ACTIVITIES	29	355 782	-1 837 829	355 782	-1 837 829
Net change in cash and cash equivalents		62 498	-185 344	62 498	-185 344
Cash and cash equivalents at start of period		44 944	232 504	44 944	232 504
Effect of exchange rate fluctuation on cash held		-338	-2 216	-338	-2 216
CASH AND CASH EQUIVALENTS AT END OF PERIOD	18	107 104	44 944	107 104	44 944

STATEMENT OF CHANGES IN EQUITY - GROUP AND PARENT

			Other equity
				Other comprehensive income
(USD 1 000)		Share capital Share premium	Other paid-in capital	Actuarial gains/(losses)	Foreign currency translation reserves*	Retained earnings	Total other equity	Total equity
Equity as of 31.12.2017	57 056	3 637 297	573 083	-89	-90 383	-1 188 366	-705 756	2 988 596
Change of accounting principle**	-	-	-	-	-	-12 736	-12 736	-12 736
Restated equity as of 01.01.2018	57 056	3 637 297	573 083	-89	-90 383	-1 201 102	-718 492	2 975 860
Dividends distributed	-	-	-	-	-	-450 000	-450 000	-450 000
Restated profit for the period	-	-	-	-	-	475 778	475 778	475 778
Other comprehensive income for the period	-	-	-	8	-25 108	-	-25 100	-25 100
Restated equity as of 31.12.2018	57 056	3 637 297	573 083	-81	-115 491	-1 175 324	-717 814	2 976 539
Dividends distributed	-	-	-	-	-	-750 000	-750 000	-750 000
Profit for the period	-	-	-	-	-	141 051	141 051	141 051
Other comprehensive income for the period	-	-	-	-4	-	-	-4	-4
Equity as of 31.12.2019 (Group and Parent)	57 056	3 637 297	573 083	-85	-115 491	-1 784 274	-1 326 767	2 367 585

* The main part of the foreign currency translation reserve arose as a result of the change in functional currency in Q4 2014

** Relates to change in accounting principle for revenue recognition, as described in note 1.

GENERAL INFORMATION

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 AKERBP. The company's registered business address is Oksenøyveien 10, 1366 Lysaker, Norway.

Aker BP's group consolidated financial statements comprise the parent company Aker BP ASA and the subsidiary Aker BP AS (previously Hess Norge AS) which was liquidated during 2018. For more information regarding subsidiaries, see note 2.

The financial statements were approved by the Board of Directors on 19 March 2020 and will be presented for approval at the Annual General Meeting on 16 April 2020.

Note 1

Summary of IFRS accounting principles

1.1 BASIS OF PREPARATION

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").

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:

• Financial instruments at fair value through profit or loss.
• Loans, receivables and other financial liabilities, which are recognized at amortized cost.

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.

1.2 FUNCTIONAL CURRENCY AND PRESENTATION CURRENCY

The functional currency of Aker BP ASA and the presentation currency of the group is United States Dollars ("USD").

1.3 IMPORTANT ACCOUNTING JUDGMENTS, ESTIMATES AND ASSUMPTIONS

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:

Goodwill allocation and methodology for impairment testing

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:

Proven and probable oil and gas reserves

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 independent third 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 license-related 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. 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. Decommissioning and removal obligations

is measured using the assumptions that market participants would use when pricing the asset or liability.

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.

Impairment/reversal of impairment

Successful Effort Method - exploration 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. Fair value measurement 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 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-of-production 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 sigle-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.

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). 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.

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 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 disputed tax positions. See note 10 'Taxes' for further details.

Income tax

NOTES TO THE ACCOUNTS

1.4 FOREIGN CURRENCY TRANSACTIONS

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.

1.5 REVENUE RECOGNITION

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.

Prior to 2019, the group recognized revenue on the basis of the proportionate share of production during the period, regardless of actual sales (entitlement method). Following development in IFRIC discussions relating to the interpretation of the entitlement method under IFRS 15, the company changed its revenue recognition policy to the sales method effective 1 January 2019. As a result, 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. Comparative figures have been restated.

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.

1.6 INTERESTS IN JOINT ARRANGEMENTS

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.

1.7 CLASSIFICATION IN STATEMENT OF FINANCIAL POSITION

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.

1.8 BUSINESS COMBINATIONS AND GOODWILL

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 processes applied to these inputs that have the ability to create outputs.

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.

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.

Goodwill is allocated to the CGUs or groups of CGUs that are expected to benefit from synergy effects 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

1.9 ACQUISITIONS, SALES AND LICENSE SWAPS

Oil and gas production licenses

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. 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.

license are included in the purchaser's Income statement from the acquisition date, as defined in 1.8 above.

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. 1.10 UNITIZATIONS 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.

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

For licenses in the development phase, the acquisition cost is allocated between capitalized exploration expenses, license rights and production plant. 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.

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.

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 1.11 TANGIBLE FIXED ASSETS AND INTANGIBLE ASSETS General Tangible fixed assets are recognized on a historical cost basis. 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.

Swaps

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.

OPERATING ASSETS RELATED TO PETROLEUM ACTIVITIES

Exploration and development costs relating to oil and gas fields

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.

Depreciation of oil and gas fields

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.

1.12 IMPAIRMENT

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

Goodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that the value may be impaired.

-

• Financial liabilities measured at amortized costs

loss are classified as other financial liabilities.

Further details on fair values of financial instruments are provided in note 29 'Financial instruments'.

1.14 IMPAIRMENT OF FINANCIAL ASSETS

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. 1.17 LEASES 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.

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.

1.15 RESEARCH AND DEVELOPMENT

1.13 FINANCIAL INSTRUMENTS The company has classified the financial instruments into the following categories of financial assets and liabilities: • Financial assets at fair value designated as such upon initial recognition • Cash and receivables • Financial liabilities at fair value designated as such upon initial recognition 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.

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.

1.16 PRESENTATION OF PAYROLL AND ADMINISTRATION COSTS

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 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 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 amountsrecharged to operated licenses. 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.

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).

1.18 TRADE DEBTORS

Trade debtors are recognized in the Statement of Financial Position at nominal value after a deduction for the provision for credit losses.

1.19 BORROWING COSTS

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.

1.20 INVENTORIES

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.

1.21 CASH AND CASH EQUIVALENTS

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.

1.22 INTEREST-BEARING DEBT

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.

1.23 TAX

General

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.

Functional currency

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.

Petroleum taxation

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 23 percent in 2018, and was changed to 22 percent in 2019. The rate for special tax was 55% and 56% correspondingly.

Tax depreciation

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.

Uplift

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 5.3 percent in 2018 and 5.2 percent from 2019 over a period of four years, totalling 21.2 percent from 2018 and 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.

Financial items

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.

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.

1.25 PROVISIONS

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.

Tax loss 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. 1.24 EMPLOYEE BENEFITS Pension schemes 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.

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. present obligation that arises from past events but is not recwith sufficient reliability. Contingent liabilities are disclosed with the exception of contingent liabilities where the probability of the liability having to be settled is remote.

1.26 SEGMENT

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.

Decommissioning and removal costs: 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. 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.

1.27 EARNINGS PER SHARE

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.

1.28 CONTINGENT LIABILITIES AND ASSETS

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 ognized 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

1.29 CHANGES TO ACCOUNTING STANDARDS AND INTERPRETATIONS THAT:

HAVE ENTERED INTO FORCE:

IFRS 16 Leases

IFRS 16 Leases was issued in January 2016 and replaced the current lease accounting standard, IAS 17 Leases, including related interpretations. The new standard introduces a single on-balance sheet accounting model for all leases, which results in the recognition of a lease liability and a right of use asset ("RoU asset) in the balance sheet. The standard was effective from 1 January 2019.

The company has applied the modified retrospective approach with no restatement of comparative figures. The lease liability at the date of the initial application is measured at the present value of the remaining lease payments, discounted using the company's incremental borrowing rate of approximately 6.7 percent. 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 company has applied the exemption for short term leases (12 months or less) and low value leases. This means that 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).

The lease liability and corresponding RoU asset was USD 390 million at initial recognition on 1 January 2019. Existing onerous lease contract values (recognized based on IFRS 3 in previous years business combinations) of approximately USD 150 million, reduced the value of the corresponding RoU asset. The transition has no impact on equity.

The IFRS 16 impact on the income statement is immaterial in 2019, as the majority of the RoU assets have mainly been used in activity not charged to the income statement, such as field development (including production drilling) and plugging and abandonment. The main impact on the statement of cash flows is that lease payments are generally presented under financing activities whilst they have been presented as operating or investing activities under IAS17.

The impact on the balance sheet is presented on separate balance sheet items, and further details are provided in the notes, in particular note 12 and 26.

Change in accounting principles for revenue recognition

Prior to 2019, the group recognized revenue on the basis of the proportionate share of production during the period, regardless of actual sales (entitlement method). Due to recent development in IFRIC discussions, the group decided to change to the sales method from 1 January 2019. This means that 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. Comparative figures have been restated in line with IAS 8.

The following table shows the effects of the change in accounting policy:

IFRIC 23 Uncertainty over Income Tax Treatments

• Whether an entity considers uncertain tax treatments separately or together
• The assumptions an entity makes about the examination of tax treatments by taxation authorities
• How an entity determines taxable profit (tax loss), tax bases, unused tax losses, unused tax credits and tax rates (how to reflect uncertainty in these positions)
• How an entity considers changes in facts and circumstances

The interpretation clarifies how to consider uncertain tax treatment within the scope of IAS 12 Income Taxes. Uncertainty over income tax treatments arises when it is unclear how the applicable tax regulations should be understood for a specific transaction or event, and when it is uncertain whether taxation authorities will approve an entity's tax treatment. The interpretation specifically addresses the following: A number of standards and interpretations are issued, but not yet effective as of 31 December 2019. Those that may have a material impact on the group are disclosed below. Amendments to IFRS 3 Definition of a Business The amendments provide updated guidance on whether an acquisition is of a business or a group of assets.

The interpretation is effective for annual reporting periods beginning on or after 1 January 2019, but certain transition

HAVE BEEN ISSUED BUT HAVE NOT ENTERED INTO FORCE:

reliefs are available. The interpretation had no significant impact on the company's financial statement. It is not expected that the amendments will have an immediate impact. However, it may have an impact on the assessment of whether a group of assets constitutes a business with regard to future acquisitions.

The amended definition emphasises that the output of a business is to provide goods and services to customers, whereas the previous definition focused on returns in the form of dividends, lower costs or other economic benefits to investors and others. In addition to amending the wording of the definition, the Board has provided supplementary guidance.

The amendments must be applied to transactions for which the acquisition date is on or after the first the beginning of the first annual reporting period beginning on or after 1 January 2020. Early application is permitted.

(USD 1 000)	2018	Group restated 2018	Change
Petroleum revenues	3 711 472	3 713 022	1 550
Production costs	689 102	693 585	4 483
Taxes (+)/tax income (-)	1 328 486	1 326 198	-2 288
Net profit	476 423	475 778	-645
Other short-term recievables	360 194	292 405	-67 789
Other equity	-704 432	-717 814	-13 381
Deferred taxes	1 800 199	1 752 757	-47 442
Other current liabilities	590 860	583 894	-6 966

Note 5 Produced volumes and over/underlift adjustment

Note 6 Exploration expenses

	Group	Parent
		Restated		Restated
(USD 1 000)	2019	2018	2019	2018
Total produced volumes (boe 1 000) (unaudited)	56 886	56 815	56 886	56 815
Production cost based on produced volumes	706 308	689 102	706 308	689 102
Adjustment for over/underlift (-)	14 014	4 483	14 014	4 483
Production cost based on sold volumes	720 321	693 585	720 321	693 585

		Group	Parent
Breakdown of payroll expenses (USD 1 000)	2019 2018		2019	2018
Payroll expenses	293 363	275 220	293 363	275 220
Pension	26 988	27 460	26 988	27 460
Social security tax	45 368	42 945	45 368	42 945
Other personnel costs	4 984	4 950	4 984	4 950
Total payroll expenses	370 704	350 575	370 704	350 575

Employee share program

	Group		Parent
Breakdown of exploration expenses (USD 1 000)	2019	2018	2019	2018
Seismic	28 875	95 458	28 875	95 458
Area fees	15 537	13 822	15 537	13 822
Field evaluation	42 532	79 323	42 532	79 323
Dry well expenses	176 419	65 852	176 419	65 852
Other exploration expenses	42 153	41 453	42 153	41 453
Total exploration expenses	305 516	295 908	305 516	295 908

Number of full time equivalents employed during the year	2019 2018		2019	2018
Europe	1 703	1 493	1 703	1 493
Total	1 703	1 493	1 703	1 493

The company has an annual share purchase program for all employees, including senior executives. The shares in the program are offered at a 20 percent discount 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 11.5 million in 2019, compared to USD 13.2 million in 2018.

Note 7 Payroll expenses and remuneration

Group Parent

Note 2 Overview of subsidiaries

Det norske oljeselskap AS (100 percent)

Alvheim AS (65 percent)

Sandvika Fjellstue AS (100 percent)

Note 3 Segment information

Note 4 Income

Total other operating income 8 421 38 600 8 421 38 600

The company's business is entirely related to exploration for and production of petroleum in Norway. The company's activities are considered to have a homogeneous risk and return profile before tax, and the business is located in the geographical area Norway. The company operates within a single operating segment which matches the internal reporting to the company's executive management. In 2019 the company had sales transactions with one customer, BP Oil International Ltd, which represented more than 10% of total sales, and accounted for USD 2 883 million. In 2018 the company had sales transactions with two customers, BP Oil International Ltd and BP Gas Marketing Ltd, which represented more than 10% of the total sales, and accounted for USD 3 297 million and USD 380 million.

		Group		Parent
		Restated		Restated
Breakdown of petroleum revenues (USD 1 000)	2019	2018	2019	2018
Sales of liquids	2 993 456	3 139 350	2 993 456	3 139 350
Sales of gas	328 816	554 248	328 816	554 248
Tariff income	16 395	19 423	16 395	19 423
Total petroleum sales	3 338 667	3 713 022	3 338 667	3 713 022
Sales of liquids (boe 1 000) (unaudited)	46 224	44 331	46 224	44 331
Sales of gas (boe 1 000) (unaudited)	11 317	12 083	11 317	12 083
Other income (USD 1 000)
Realized gain/loss (-) on oil derivatives	-12 824	-16 242	-12 824	-16 242
Unrealized gain/loss (-) on oil derivatives	-19 058	24 944	-19 058	24 944
Other income*	40 303	29 898	40 303	29 898

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. As of year-end 2019, the only remaining asset in this company is cash equivalents reflecting the share capital amounting to USD 1.0 million.

Aker BP ASA has three subsidiaries which are not consolidated in the group accounts in 2019 due to materiality considerations:

Sandvika Fjellstue AS owns a conference centre used by Aker BP, located in Sandvika in Verdal.

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.

* For 2019 the amount includes insurance settlement during Q4 2019 relating to prior years, in addition to partner coverage of RoU assets recognized on gross basis in the balance sheet and used in operated activity. For 2018 the amount mainly related to a non-recurring tariff compensation.

Refer to note 22 and 29 for further details regarding commodity derivatives.

Fees in 2019*
Name	Comments	Fee (USD 1 000)	Total number of shares	Owning interest
Øyvind Eriksen	Chairman of the Board from 11.03.2016. Chair of the Organizational Development and Compensation committee.	102	-	-
Anne Marie Cannon	Deputy Chair from 17.04.2013. Member of the Audit & Risk committee.	65	12 078	0.0 %
Bernard Looney	Board member from 30.09.2016.	-	-	-
Kjell Inge Røkke	Board member from 17.04.2013.	45	-	-
Trond Brandsrud	Board member from 11.03.2016. Chairman of the Audit & Risk committee from 28.04.2016.	68	-	-
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.	50	1750	0.0 %
Terje Solheim	Employee rep. from 20.03.2014. Member of the Organizational Development and Compensation committee.	26	1787	0.0 %
Ørjan Holstad	Employee representative from 01.11.2017.	22	2656	0.0 %
Murray Auchincloss	Deputy board member from 01.04.2017.	-	-	-
Nina Aas	Deputy employee representative from 30.08.2018.	4	2800	0.0 %
Oddbjørn Aune	Deputy employee representative from 30.08.2018.	4	4068	0.0 %
Hilde K.Brevik	Deputy employee representative from 30.08.2018.	4	350	0.0 %
Arild Støren Frick	Chairman of the Nomination committee.	4	-	-
Finn Haugan	Member of the Nomination committee.	4	-	-
Hilde Myrberg	Member of the Nomination committee.	4	-	-
Ingar Haugeberg	Employee representative from 30.08.2018.	22	970	0.0 %
Anette Hoel Helgesen	Employee representative from 30.08.2018.	22	-	-
Member until 30.04.2019
Lone Margrethe Olstad	Employee representative from 11.03.2016 to 30.04.2019.	1	-	-
Total		445	12 428	0.0 %

Fees in 2019*
		Fee (USD 1 000)	Total number	Owning
Name	Comments		of shares	interest
Øyvind Eriksen	Chairman of the Board from 11.03.2016. Chair of the Organizational Development and Compensation committee.	102	-	-
Anne Marie Cannon	Deputy Chair from 17.04.2013. Member of the Audit & Risk committee.	65	12 078	0.0 %
Bernard Looney	Board member from 30.09.2016.	-	-	-
Kjell Inge Røkke	Board member from 17.04.2013.	45	-	-
Trond Brandsrud	Board member from 11.03.2016. Chairman of the Audit & Risk committee from 28.04.2016.	68	-	-
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.	50	1750	0.0 %
Terje Solheim	Employee rep. from 20.03.2014. Member of the Organizational Development and Compensation committee.	26	1787	0.0 %
Ørjan Holstad	Employee representative from 01.11.2017.	22	2656	0.0 %
Murray Auchincloss	Deputy board member from 01.04.2017.	-	-	-
Nina Aas	Deputy employee representative from 30.08.2018.	4	2800	0.0 %
Oddbjørn Aune	Deputy employee representative from 30.08.2018.	4	4068	0.0 %
Hilde K.Brevik	Deputy employee representative from 30.08.2018.	4	350	0.0 %
Arild Støren Frick	Chairman of the Nomination committee.	4	-	-
Finn Haugan	Member of the Nomination committee.	4	-	-
Hilde Myrberg	Member of the Nomination committee.	4	-	-
Ingar Haugeberg	Employee representative from 30.08.2018.	22	970	0.0 %
Anette Hoel Helgesen	Employee representative from 30.08.2018.	22	-	-
Member until 30.04.2019
Lone Margrethe Olstad	Employee representative from 11.03.2016 to 30.04.2019.	1	-	-
Total		445	12 428	0.0 %

* Fee to board members are paid in NOK and converted to USD using a yearly average USD/NOK-rate of 8.8037.

The tables below include regular fees to the Board and fees for participation in the Board's subcommittees, including the nomination committee. Fees to Board members employed by the Aker ASA is paid to the company, not to the Board member in person. The table also includes the number of shares and owning interest in Aker BP ASA held directly or indirectly through related parties. Indirect ownership through other companies is included as a whole where the ownership interest is 50 percent or more.

1) SVP Strategy and Business Development since 01.02.2019

2) Chief Financial Officer since 01.02.2019

3) SVP HSSEQ since 01.05.2019

4) Chief Operating Officer since 01.05.2019. Other includes signing on fee

5) SVP Projects since 01.07.2019

6) Chief Financial Officer until 31.01.2019

7) SVP Projects until 31.03.2019

8) SVP HSSEQ until 30.04.2019

9) Acting SVP Operations and Asset Development until 30.04.2019

Remuneration of senior executives in 2019*
			Payments in		Total		Total number	Owning
(USD 1 000)	Salary	Bonus**	kind	Other	remuneration	Pension costs	of shares***	interest
Karl Johnny Hersvik (Chief Executive Officer)	826	517	1	6	1 350	20	6 081	0.0 %
Øyvind Bratsberg (Special Advisor)	425	155	1	4	584	21	54 802	0.0 %
Per Harald Kongelf (SVP Improvement)	416	153	1	-	571	21	-	-
Tommy Sigmundstad (SVP D&W)	369	137	3	-	510	20	8 538	0.0 %
Ole Johan Molvig (SVP Reservoir Development)	369	137	1	-	508	20	9 582	0.0 %
Evy Glørstad (SVP Exploration)	338	133	1	2	475	21	5 866	0.0 %
Lene Landøy (SVP Strategy and Business Development) 1)	316	128	2	-	447	20	5 221	0.0 %
David Torvik Tønne (Chief Financial Officer) 2)	348	137	2	-	487	20	5 778	0.0 %
Marit Blaasmo (SVP HSSEQ) 3)	253	82	1	1	337	21	-	-
Kjetel Rokseth Digre (Chief Operating Officer) 4)	285	174	1	796	1 256	14	3 002	0.0 %
Knut Arne Kristian Sandvik (SVP projects) 5)	145	77	1	-	223	11	-	-
Alexander Krane (Chief Financial Officer) 6)	190	-	1	-	191	5	17 021	0.0 %
Olav Henriksen (SVP Projects) 7)	294	53	-	1	348	11	-	-
Jorunn Kvåle (SVP HSSE) 8)	270	67	1	17	356	21	-	-
Svein Jakob Liknes (SVP Operations) 9)	209	38	2	-	249	10	-	-
Total remuneration of senior executives in 2019	5 054	1 989	23	828	7 893	256	115 891	0.0 %

1) Bonus includes accrued LTI commitments

Remuneration of senior executives in 2018*
			Payments in		Total		Total number	Owning
(USD 1 000)	Salary	Bonus**	kind	Other	remuneration	Pension costs of shares***		interest
Karl Johnny Hersvik (Chief Executive Officer) 1)	783	1 187	2	1	1 973	21	3 577	0.0 %
Øyvind Bratsberg (Special Advisor)	453	177	2	4	635	22	54 290	0.0 %
Alexander Krane (Chief Financial Officer)	438	172	9	-	619	21	17 021	0.0 %
Gro G. Haatvedt (SVP Exploration) 2)	476	-	1	5	483	77	10 832	0.0 %
Olav Henriksen (SVP Projects)	481	291	2	-	774	102	-	-
Per Harald Kongelf (SVP Improvement)	413	171	2	-	586	23	-	-
Tommy Sigmundstad (SVP D&W)	370	155	4	12	541	21	7 528	0.0 %
Ole Johan Molvig (SVP Reservoir Development)	376	155	2	-	533	21	6 485	0.0 %
Jorunn Kvåle (SVP HSSE)	284	116	2	18	420	23	-	-
Eldar Larsen (SVP Operations) 3)	388	158	2	24	572	22	1 858	0.0 %
Evy Glørstad-Clark (SVP Exploration) 4)	300	103	2	2	406	22	5 866	0.0 %
Svein Jakob Liknes (SVP Operations) 5)	353	105	6	-	464	21	-	-
Total remuneration of senior executives in 2018	5 116	2 789	34	65	8 004	396	107 457	0.0 %

2) SVP Exploration until 31.07.2018

3) SVP Operations until 06.05.2018

4) SVP Exploration since 01.08.2018

5) Acting SVP Operations since 07.05.2018

* All remuneration to senior executives is paid in NOK and converted to USD using a yearly average USD/NOK-rate of 8.1338.

** Numbers represent actual bonus earned in 2018. From the total amount in this column, USD 671 thousand relates to LTI program.

*** 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.

* All remuneration to senior executives is paid in NOK and converted to USD using a yearly average USD/NOK-rate of 8.8037.

*** 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.

** Numbers represent actual bonus earned in 2019. No LTIP accrual has been included in the table above, as Aker BP share price does not outperform the benchmark index as at the date of this report (see description below).

Note 8 Auditors fee

	Group		Parent
(USD 1 000)	2019	2018	2019	2018
Fees for statutory audit services - KPMG (excluding VAT)	546	429	546	429
Fees for other attestations - KPMG (excluding VAT)	139	132	139	132
Total auditor's fees	685	561	685	561
Note 9 Financial items
	Group		Parent
(USD 1 000)	2019	2018	2019	2018
Total interest income	16 490	25 976	16 490	19 114
Realized gains on derivatives	11 261	141 823	11 261	141 823
Change in fair value of derivatives	7 316	-	7 316	-
Net currency gains	16 677	-	16 677	43 592
Total other financial income	35 255	141 823	35 255	185 415
Interest expenses	175 672	200 524	175 672	200 524
Interest on lease debt	23 897	-	23 897	-
Capitalized interest cost, development projects	-144 686	-110 213	-144 686	-110 213
Amortized loan costs	21 705	29 722	21 705	29 722
Total interest expenses	76 587	120 033	76 587	120 033
Net currency loss/gain (-) before reclassification from OCI	-	-43 592	-	-
Reclassification from OCI*	-	47 504	-	-
Realised loss on derivatives	46 751	45 993	46 751	45 993
Change in fair value of derivatives	10 742	36 503	10 742	36 503
Accretion expenses	121 723	128 737	121 723	128 737
Other financial expenses**	38 929	3 128	38 929	70 456
Total other financial expenses	218 145	218 272	218 145	281 689
Net financial items	-242 986	-170 505	-242 986	-197 192

The rate (weighted average interest rate) used to determine the amount of borrowing cost eligible for capitalisation in 2019 is 6.57 percent. The corresponding rate for 2018 was 6.52 percent.

* The reclassification from OCI in 2018 related to the refund of tax losses in Aker BP AS (previously Hess Norge AS), and the subsequent liquidation of Aker BP AS. The reclassification reflected the USD/NOK currency movement from the acquisition of Hess Norge AS at 22 December 2017 to the tax refund and liquidation of Aker BP AS on 28 November 2018.

** The parent company number in 2018 includes a group continuity adjustment, as well as other adjustments to the value of shares in subsidiaries.

Guidelines and adherence to the quidelines of 2019

In 2019, the companys remuneration policy has been in accordance with the guidelines described in the Board of Directors Report for 2018 and submitted to the annual general meeting for an advisory vote in April 2019.

Guidelines for 2020

It is up to the Board to decide whether to pay bonuses, based on the previous year's performance. For 2019, the bonus will be disbursed in Q1 2020.

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.

Fees in 2018*
Name	Comments	Fee (USD 1 000)	Total number of shares	Owning interest
Øyvind Eriksen	Chairman of the Board from 11.03.2016. Chairman of the Compensation committee.	108	-	-
Anne Marie Cannon	Deputy Chair from 17.04.2013. Member of the Audit & Risk committee.	68	6 309	0.0 %
Bernard Looney	Board member from 30.09.2016.	-	-	-
Kjell Inge Røkke	Board member from 17.04.2013.	47	-	-
Trond Brandsrud	Board member from 11.03.2016. Chairman of the Audit & Risk committee from 28.04.2016.	71	-	-
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 Compensation committee.	61	-	-
Terje Solheim	Employee representative from 20.03.2014. Member of the Compensation committee from 28.04.2016.	28	1 150	0.0 %
Lone Margrethe Olstad	Employee representative from 11.03.2016.	19	-	-
Ørjan Holstad	Employee representative from 01.11.2017.	28	1 789	0.0 %
Murray Auchincloss	Deputy board member from 01.04.2017.	-	-	-
Nina Aas	Deputy employee representative from 30.08.2018.	1	2 288	0.0 %
Oddbjørn Aune	Deputy employee representative from 30.08.2018.	1	4 068	0.0 %
Hilde K.Brevik	Deputy employee representative from 30.08.2018.	1	156	0.0 %
Arild Støren Frick	Chairman of the Nomination committee from 13.04.2015.	4	-	-
Finn Haugan	Member of the Nomination committee.	4	-	-
Hilde Myrberg	Member of the Nomination committee.	4	-	-
Ingar Haugeberg	Employee representative from 30.08.2018.	8	970	0.0 %
Anette Hoel Helgesen	Employee representative from 30.08.2018.	8	-	-
Members until 30.08.2018
Bjørn Thore Ribesen	Employee representative from 11.03.2016 to 30.08.2018.	18	24 462	0.0 %
	Kristin Gjertsen (2.deputy) Deputy employee representative from 11.03.2016 to 30.08.2018.	3	-	-
Ifor Roberts (3.deputy)	Deputy employee representative from 11.03.2016 to 30.08.2018.	3	12 345	0.0 %
	Martine Midtsand Hovland Deputy employee representative from November 2017 to 30.08.2018.	3	-	-
Total		492	53 537	0.0 %

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 bonuses for all employees, including the EMT, are determined by the performance on a set of company-wide performance indicators (KPIs) and the delivery on a set of carefully selected company priorities. These KPIs and company priorities are weighted equally. KPI's include measures on safety, production, production cost, reserve additions, value creation and shareholder return. Company priorities are either important improvement initiatives or activities with clear deliverables that are critical for the company's future success.

* Fee to board members are paid in NOK and converted to USD using a yearly average USD/NOK-rate of 8.1338.

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 Board has established guidelines for 2020 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 will be communicated to the company's annual general meeting in April 2020.

Members of EMT have individual maximum bonus potential varying from 60 percent to 100 percent of their base salary. The maximum bonus for employees outside the EMT varies from 10 percent to 30 percent based on internal job grade. In addition, 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 Stock Exchange Energy Index and the Stoxx 600 Europe Oil & Gas index (both weighting 50 percent each). 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 manager's annual base salary. The CEO incentive program has the same mechanics and start/end date and is capped at NOK 30 million.

	Group		Parent
		Restated		Restated
Reconciliation of change in deferred tax (-)/deferred tax asset (+) (USD 1 000)	2019	2018	2019	2018
Deferred tax/deferred tax asset 31.12.	-1 752 757	-1 307 148	-1 752 757	-1 307 148
Effect of change in accounting principle***	-	45 155	-	45 155
Deferred tax/deferred tax asset 01.01.	-1 752 757	-1 261 993	-1 752 757	-1 261 993
Change in deferred tax in the income statement	-463 106	-524 645	-463 106	-524 645
Prior period adjustment	-19 509	33 912	-19 509	33 912
Deferred tax charged to OCI and equity	15	-30	15	-30
Total deferred tax liability (-)/deferred tax asset (+)	-2 235 357	-1 752 757	-2 235 357	-1 752 757

Note 11 Earnings per share

	Group		Parent
Reconciliation of change in tax receivable (+)/tax payable (-) (USD 1 000)	2019	2018	2019	2018
Tax receivable (+)/tax payable (-) at 1.1	-540 860	1 234 850	-540 860	-351 156
Current year tax in Income statement	-461 984	-803 396	-461 984	-801 818
Tax receivable (+)/tax payable (-) related to acquisitions/sales	520	4 387	520	2 809
Tax payment (+)/tax refund (-)	618 593	-907 312	618 593	606 082
Prior period adjustments and change in estimate of uncertain tax positions	16 955	-30 269	16 955	-30 269
Revaluation of tax payable	5 619	-39 119	5 619	33 492
Tax receivable (+)/tax payable (-)	-361 157	-540 860	-361 157	-540 860
Tax receivable	-	11 082	-	11 082
Tax payable	-361 157	-551 942	-361 157	-551 942

	Group
		Restated
(USD 1 000)	2019	2018
Profit for the year attributable to ordinary equity holders of the parent entity	141 051	475 778
The year's average number of ordinary shares (in thousands)	360 014	360 114
Earnings per share in USD	0.39	1.32

Earnings per share is calculated by dividing the year's profit attributable to ordinary equity holders of the parent entity, which was USD 141 million (USD 476 million in 2018) by the year's weighted average number of outstanding ordinary shares, which was 360.0 million (360.1 million in 2018). There are no option schemes or convertible bonds in the company, meaning there is no difference between the ordinary and diluted earnings per share.

Reconciliation of change in deferred tax (-)/deferred tax asset (+) (USD 1 000)

Deferred tax/deferred tax asset 31.12.
Effect of change in accounting principle ***
Deferred tax/deferred tax asset 01.01.

*** Relates to change in deferred tax as a result of the change in accounting principle for revenue recognition as described in note 1.

Note 10 Taxes

	Group		Parent
		Restated		Restated
Breakdown of the current year's tax income (-)/tax expense (+) (USD 1 000)	2019	2018	2019	2018
Current year tax payable	461 984	803 396	461 984	801 818
Prior periods' adjustments to current tax	-1 396	32 069	-1 396	32 069
Current tax income (-)/expense (+)	460 588	835 465	460 588	833 886
Current year deferred tax	463 106	524 645	463 106	524 645
Prior periods' adjustments to deferred tax	19 509	-33 912	19 509	-33 912
Deferred tax income (-)/expense (+)	482 615	490 733	482 615	490 733
Net tax income (-)/tax expense (+)	943 204	1 326 198	943 204	1 324 619
Effective tax rate in %	87%	74 %	87%	75 %

Breakdown of tax effect of temporary differences and	Group	Parent
		Restated
tax losses carry forward (USD 1 000)	2019	2018	2019	2018
Tangible fixed assets	-3 134 183	-2 401 716	-3 134 183	-2 401 716
Capitalized exploration cost	-484 626	-333 402	-484 626	-333 402
Other intangible assets	-1 037 789	-1 100 480	-1 037 789	-1 100 480
Abandonment provision	2 170 198	1 986 262	2 170 198	1 986 262
Lease debt	244 340	-	244 340	-
Financial instruments	8 863	4 095	8 863	4 095
Other provisions	-2 160	92 484	-2 160	92 484
Total deferred tax liability (-)/deferred tax asset (+)	-2 235 357	-1 752 757	-2 235 357	-1 752 757

		Group		Parent
			Restated		Restated
Reconciliation of tax expense (+)/tax income (-) (USD 1 000)	Tax rate	2019	2018	2019	2018
78% tax rate on profit before tax	78%	845 718	1 405 541	845 718	1 384 726
Tax effect on uplift	56%	-129 619	-130 767	-129 619	-130 767
Change in tax rates		-	-2 047	-	-2 047
Permanent difference on impairment	78%	114 907	-	114 907	-
Tax effect on OCI reclassification*	78%	-	37 053	-	-
Foreign currency translation of NOK monetary items	78%	-12 535	-34 002	-12 535	-34 002
Foreign currency translation of USD monetary items	78%	-16 006	-111 806	-16 006	-111 806
Tax effect of financial and other 22 %/23 % items	56%	81 593	50 578	81 593	50 578
Currency movements of tax balances**	78%	34 297	113 147	34 297	113 147
Other permanent differences, prior period adjustments and change in estimate of uncertain tax positions	78%	24 848	-1 498	24 848	54 792
Total taxes (+)/tax income (-)		943 204	1 326 198	943 204	1 324 619

* Refer to note 9. The amount in 2018 was not tax deductible, and so represents a permanent difference in the effective tax rate reconciliation.

** 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.

The tax rate for general corporation tax changed from 23 to 22 percent from 1 January 2019. The rate for special tax changed from the same date from 55 to 56 percent.

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.

	Other intangible assets
(USD 1 000)	Licenses etc.	Software	Total	Exploration wells	Goodwill
Book value 31.12.2017	1 617 005	34	1 617 039	365 417	1 860 126
Acquisition cost 31.12.2017	1 933 241	7 501	1 940 742	365 417	2 738 973
Additions	463 049	-	463 049	128 795	-
Disposals/expensed dry wells	-	-	-	65 852	-
Reclassification	-	-	-	-921	-
Acquisition cost 31.12.2018	2 396 290	7 501	2 403 791	427 439	2 738 973
Accumulated depreciation and impairments 31.12.2017	316 236	7 467	323 703	-	878 847
Depreciation	73 653	34	73 686	-	-
Impairment	516	-	516	-	-
Accumulated depreciation and impairments 31.12.2018	390 404	7 501	397 906	-	878 847
Book value 31.12.2018	2 005 885	-	2 005 885	427 439	1 860 126
Acquisition cost 31.12.2018	2 396 290	7 501	2 403 791	427 439	2 738 973
Additions	143	-	143	370 185	-
Disposals/expensed dry wells	-	-	-	176 916	-
Reclassification	-	-	-	608	-
Acquisition cost 31.12.2019	2 396 433	7 501	2 403 934	621 315	2 738 973
Accumulated depreciation and impairments 31.12.2018	390 404	7 501	397 906	-	878 847
Depreciation	90 060	-	90 060	-	-
Impairment	-	-	-	-	147 317
Accumulated depreciation and impairments 31.12.2019	480 465	7 501	487 966	-	1 026 165
Book value 31.12.2019	1 915 968	-	1 915 968	621 315	1 712 809

	Group		Parent
Depreciation in the Income statement (USD 1 000)	2019	2018	2019	2018
Depreciation of tangible fixed assets	705 282	678 751	705 282	678 751
Depreciation of right-of-use assets	16 531	-	16 531	-
Depreciation of intangible assets	90 060	73 686	90 060	73 686
Total depreciation in the Income statement	811 874	752 437	811 874	752 437

Impairment in the Income statement (USD 1 000)

Total impairment in the Income statement	146 808	20 172	146 808	20 172
Impairment of goodwill	147 317	-	147 317	-
Impairment/reversal of intangible assets	-	516	-	516
Impairment/reversal of tangible fixed assets	-509	19 657	-509	19 657

See note 13 for information regarding impairment charges.

Note 12 Tangible fixed assets and intangible assets

TANGIBLE FIXED ASSETS - GROUP AND PARENT

Property, plant and equipment
			Fixtures and
(USD 1 000)	Assets under development	Production facilities including wells	fittings, office machinery	Total
Book value 31.12.2017	1 480 689	4 032 797	69 007	5 582 493
Acquisition cost 31.12.2017	1 480 689	6 057 801	104 346	7 642 835
Additions	1 011 222	-172 615	22 662	861 269
Reclassification	-208 309	201 176	8 053	921
Acquisition cost 31.12.2018	2 283 602	6 086 362	135 061	8 505 025
Accumulated depreciation and impairments 31.12.2017	-	2 025 004	35 338	2 060 342
Depreciation	-	656 697	22 054	678 751
Impairment	-	19 657	-	19 657
Accumulated depreciation and impairments 31.12.2018	-	2 701 357	57 392	2 758 750
Book value 31.12.2018	2 283 602	3 385 005	77 669	5 746 275
Acquisition cost 31.12.2018	2 283 602	6 086 362	135 061	8 505 025
Additions	1 528 536	362 334	30 633	1 921 503
Reclassification*	-2 561 772	2 617 326	4 718	60 271
Acquisition cost 31.12.2019	1 250 365	9 066 022	170 411	10 486 798
Accumulated depreciation and impairments 31.12.2018	-	2 701 357	57 392	2 758 750
Depreciation	-	677 217	28 065	705 282
Impairment	-	-509	-	-509
Accumulated depreciation and impairments 31.12.2019	-	3 378 065	85 458	3 463 522
Book value 31.12.2019	1 250 365	5 687 957	84 954	7 023 276

* This represents the share of right-of-use assets used in abandonment activity, and thus booked against the abandonment provision.

** Of which 60 271 reclassified to tangible fixed assets and 608 reclassified to capitalized exploration in line with the activity of the right-of-use asset.

Right-of-use assets
(USD 1 000)	Drilling Rigs	Vessels and Boats	Office	Other	Total
Right-of-use assets at initial recognition 01.01.2019	132 270	76 628	29 593	2 303	240 795
Additions	34 385	-	-	-	34 385
Abandonment activity*	2 706	737	-	-	3 442
Reclassification**	-57 093	-3 785	-	-	-60 878
Acquisition cost 31.12.2019	106 856	72 106	29 593	2 303	210 859
Accumulated depreciation and impairments 31.12.2018	-	-	-	-	-
Depreciation	5 369	3 166	7 820	177	16 531
Impairment	-	-	-	-	-
Accumulated depreciation and impairments 31.12.2019	5 369	3 166	7 820	177	16 531
Book value 31.12.2018	101 487	68 941	21 774	2 127	194 328

Right-of-use assets are depreciated linearly over the lifetime of the related lease contract.

* The reclassification is mainly relating to the Johan Sverdrup field and Valhall Flank West, which entered into production phase during Q4 2019, in addition to reclassfication from right-of-use asset.

Capitalized exploration expenditures are reclassified to "Assets under development" when the field enters into the development phase. If development plans are subsequently re-evaluated, 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.

Currency rates

Year	USD/NOK
2020	8.79
2021	8.80
2022	8.82
From 2023	7.50

Inflation

Impairment testing of assets other than goodwill

Impairment testing of technical goodwill

Sensitivity analysis

Assumption (USD 1 000)	Change in goodwill impairment after
	Change	Increase in assumption	Decrease in assumption
Oil and gas price	+/- 20%	-	130 888
Production profile (reserves)	+/- 5%	-	-
Discount rate	+/- 1% point	-	-
Currency rate USD/NOK	+/- 1.0 NOK	-	32 730
Inflation	+/- 1% point	-	-

The table below shows how the impairment of 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 and Alvheim.

The main reasons for the impairment are reduced deferred tax, together with updated cost and production profiles and decrease in the near-term oil and gas prices.

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.

Long-term currency rate is unchanged from year-end 2018.

The reversal of impairment of USD 0.5 million in 2019 relates to changes in ARO liability on CGUs with no carrying value.

	Impairment charged/reversal			Amount as of 31.12.2019
Cash generating unit (USD 1 000)	Intangible	Tangible	Recoverable amount Carrying value
Ula/Tambar	147 317	-	550 187	527 483
Total	147 317	-	550 187	527 483

The carrying value of the CGUs consists of the carrying values of the oilfield assets plus associated technical goodwill. 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.

For the Alvheim, Valhall/Hod and Skarv/Ærfugl CGUs no impairment has been recognized during 2019. For the Ula/Tambar CGU, an impairment charge was recognized in Q1 2019 and Q3 2019.

Technical goodwill has been allocated to individual CGUs for the purpose of impairment testing. The residual goodwill is allocated to group of CGUs including all fields acquired together with all existing Aker BP's fields, as this mainly relates to tax and workforce synergies and the ability to capture synergies from managing a portfolio of both acquired and existing fields on the NCS.

The long-term inflation rate is assumed to be 2.0 percent, which is the same as applied at year-end 2018.

Below is an overview of the impairment charge and the carrying value per cash generating unit where impairment has been recognized in 2019:

The impairment test of assets other than goodwill has been performed prior to the quarterly goodwill impairment test. If these assets are found to be impaired, their carrying value will be written down before the impairment test of goodwill. The carrying value of the assets is the sum of tangible assets and intangible assets as of the assessment date.

Impairment testing

Oil and gas prices

Year	USD/BOE
2020	64.2
2021	59.4
2022	57.3
From 2023 (in real terms)	65.0

Year	GBP/therm
2020	0.32
2021	0.42
2022	0.44
2023	0.52
From 2024 (in real terms)	0.53

Oil and gas reserves

Future expenditure

Discount rate

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 2019.

The nominal gas prices applied in impairment test are as follows:

Impairment is recognized when the book value of an asset or a cash-generating unit, including associated goodwill, exceeds the recoverable amount. The recoverable amount is the higher of the asset's fair value less cost to sell and value in use. For assets and goodwil related to the CGUs Ivar Aasen, Johan Sverdrup and Gina Krogh, the impairment testing has been based on value in use. For assets and goodwill related to the CGUs Ula/Tambar, Alvheim, Valhall/Hod and Skarv/Ærfug, the impairment testing has been based on fair value (level 3 in fair value hierarchy). For both value in use and fair value, the impairment testing is performed 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. If not specifically stated otherwise, the same assumptions have been applied for value in use and fair value testing.

• Impairment test of fixed assets and related intangible assets, other than goodwill - Impairment test of goodwill

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 2020 to the end of 2022. From 2023, the oil and gas prices are based on the company's long-term price assumptions. Long-term oil price assumption is unchanged from year-end 2018.

Future capex, opex and abandonment cost are calculated based on the expected production profiles and the best estimate of the related cost.

For both value in use and fair value testing the post tax nominal discount rate used is 7.8 percent. This represents a change from 7.9 percent applied in previous quarters in 2019 and year-end 2018 for value in use testing, and a change from 10.0 percent applied in previous quarters in 2019 and year-end 2018 for fair value testing.

Impairment tests of individual cash-generating units are performed when impairment triggers are identified, and for goodwill impairment is tested at least annually. In 2019, two categories of impairment tests have been performed:

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 32.

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 nominal oil prices applied in the impairment test are as follows:

Note 16 Inventories

The inventory mainly consists of equipment for the drilling of exploration and production wells.

	tory value (USD 1 000)
--	------------------------

Note 17 Other non-current assets

Note 18 Cash and cash equivalents

	Group		Parent
Inventory value (USD 1 000)	2019	2018	2019	2018
Inventories - measured at cost	116 595	111 896	116 595	111 896
Provision for obsolete equipment	29 057	18 716	29 057	18 716
Book value of inventories	87 539	93 179	87 539	93 179

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
(USD 1 000)	31.12.2019	31.12.2018	31.12.2019	31.12.2018
Shares in Alvheim AS	10	10	10	10
Shares in Det norske oljeselskap AS	1 021	1 021	1 021	1 021
Shares in Sandvika Fjellstue AS	1 814	1 814	1 814	1 814
Investment in subsidiaries	2 845	2 845	2 845	2 845
Tenancy deposit	1 914	1 934	1 914	1 934
Other non-current assets	5 606	5 609	5 606	5 609
Total other non-current assets	10 364	10 388	10 364	10 388

Note 19 Share capital and shareholders

	Group		Parent
Breakdown of cash and cash equivalents (USD 1 000)	31.12.2019	31.12.2018	31.12.2019	31.12.2018
Bank deposits	107 104	44 944	107 104	44 944
Cash and cash equivalents	107 104	44 944	107 104	44 944
Unused Reserve-based lending facility/Revolving credit facility (see note 24)	2 550 000	3 050 000	2 550 000	3 050 000

	Parent
(USD 1 000)	31.12.2019	31.12.2018
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.

Alvheim AS, Det norske oljeselskap AS (previously Marathon Oil Norge AS) and Sandvika Fjellstue AS have been deemed immaterial for consolidation purposes. For more information regarding shares in subsidiaries, see note 2.

Impairment testing of residual goodwill

Impairment testing in 2018

Summary of impairment/reversal of impairments

The following impairments/(reversals) have been recorded:

Note 14 Accounts receivable

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
2019	193 444	191 960	464	445	576
2018	162 798	162 798	-	-	-

Note 15 Other short-term receivables

	Group		Parent
(USD 1 000)	31.12.2019	31.12.2018	31.12.2019	31.12.2018
Receivables related to the sale of petroleum	193 444	162 798	193 444	162 798
Total accounts receivable	193 444	162 798	193 444	162 798

* Comparable figure has been restated to reflect the valuation of underlift to production cost, in line with the sales method as described in note 1.

		Group	Parent
(USD 1 000)	2019	2018	2019	2018
Impairment of other intangible assets/license rights	-	516	-	516
Impairment of tangible fixed assets	-509	19 657	-509	19 657
Impairment of technical goodwill	147 317	-	147 317	-
Total impairments	146 808	20 172	146 808	20 172

• discount rate of 7.9 percent nominal after tax (value in use) and 10.0 percent nominal after tax (fair value)

The following assumptions were applied for the impairment testing at year-end 2018:

As mentioned above, residual goodwill is allocated across all CGUs for impairment testing. The combined recoverable amount exceeds the carrying amount by a substantial margin. Based on this, no impairment of residual goodwill has been recognized.

		Group		Parent
		Restated		Restated
(USD 1 000)	31.12.2019	31.12.2018	31.12.2019	31.12.2018
Prepayments	65 813	64 004	65 813	64 004
VAT receivable	8 904	8 871	8 904	8 871
Underlift of petroleum*	46 515	54 924	46 515	54 924
Accrued income from sale of petroleum products	80 514	52 825	80 514	52 825
Other receivables, mainly balances with license partners	128 770	111 781	128 770	111 781
Total other short-term receivables	330 516	292 405	330 516	292 405

The company's customers are mainly large, financially sound oil companies. Accounts receivable consist of receivables related to the sale of oil and gas.

As described in note 31, the spread of COVID-19 virus during the first quarter 2020, combined with the significant drop in oil prices, may have a significant impact on recoverable amounts of Aker BP's assets going forward.

In 2018, the impairment charge was in all material respect related to technical goodwill from acquisitions and impairment of tangible fixed assets. The methodology for impairment testing was the same as in 2019 as described in this note.

• a long-term inflation of 2.0 percent

• a long-term exchange rate of NOK/USD 7.5 (forward curve first three years)

• a long-term oil price assumption of 65 USD/barrel, using forward curve first three years

Note 21 Provision for abandonment liabilities

Note 22 Derivatives

		Group		Parent
(USD 1 000)	31.12.2019	31.12.2018	31.12.2019	31.12.2018
Provisions as of 1 January	2 552 592	3 043 884	2 552 592	3 043 884
Incurred cost removal	-108 332	-201 227	-108 332	-201 227
Accretion expense - present value calculation	121 723	128 737	121 723	128 737
Changed net present value from changed discount rate	238 053	-277 081	238 053	-277 081
Change in estimates and incurred liabilities on new drilling and installations	-15 818	-141 721	-15 818	-141 721
Total provision for abandonment liabilities	2 788 218	2 552 592	2 788 218	2 552 592
Breakdown of the provision to short-term and long-term liabilities
Short-term	142 798	105 035	142 798	105 035
Long-term	2 645 420	2 447 558	2 645 420	2 447 558
Total provision for abandonment liabilities	2 788 218	2 552 592	2 788 218	2 552 592

Note 23 Provisions for other liabilities

	Group		Parent
(USD 1 000)	31.12.2019	31.12.2018	31.12.2019	31.12.2018
Unrealized gain currency contracts	2 706	-	2 706	-
Long-term derivatives included in assets	2 706	-	2 706	-
Unrealized gain commodity derivatives	-	17 253	-	17 253
Short-term derivatives included in assets	-	17 253	-	17 253
Total derivatives included in assets	2 706	17 253	2 706	17 253
Unrealized losses interest rate swaps	-	26 275	-	26 275
Long-term derivatives included in liabilities	-	26 275	-	26 275
Unrealized losses commodity derivatives	1 805	-	1 805	-
Unrealized losses interest rate swaps	37 017	-	37 017	-
Unrealized losses currency contracts	4 172	8 783	4 172	8 783
Short-term derivatives included in liabilities	42 994	8 783	42 994	8 783
Total derivatives included in liabilities	42 994	35 058	42 994	35 058

The estimate is based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The calculations assume an inflation rate of 2.0 percent and a nominal discount rate before tax of between 3.77 percent and 4.59 percent. For previous quarters in 2019 and year-end 2018 the inflation rate was 2.0 percent and the discount rate was between 4.46 percent and 5.01 percent. The credit margin included in the discount rate is 2.20 percent. For previous quarters in 2019 and year-end 2018 the credit margin was 2.00 percent.

	Group		Parent
Breakdown of provisions for other liabilities (USD 1 000)	31.12.2019	31.12.2018	31.12.2019	31.12.2018
Fair value of contracts assumed in acquisitions*	-	106 040	-	106 040
Other long term liabilities	403	1 480	403	1 480
Total provisions for other liabilities	403	107 519	403	107 519

The group has different types of economic hedging instruments. The commodity derivatives are used to hedge the risk of oil price reduction. The group manages its interest rate exposure using interest rate derivatives, including a cross currency interest rate swap. Foreign currency exchange derivatives are used to manage the company's exposure to currency risks, mainly 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.

* The negative contract values are mainly related to rig contracts entered into by companies acquired by Aker BP, which differed from current market terms at the time of the acquisitions. The fair value is based on the difference between market price and contract price at the time of the acquisitions. Upon the implementation of IFRS 16 on 1 January 2019, the amount was netted against the right-of-use asset as described in note 1.

* Nominee accounts

Note 20 Bonds

	Group		Parent
(USD 1 000)	31.12.2019	31.12.2018	31.12.2019	31.12.2018
DETNOR02 Senior unsecured bond*	-	223 839	-	223 839
AKERBP – Senior Notes (17/22)**	395 046	393 301	395 046	393 301
AKERBP – Senior Notes (18/25)***	494 470	493 349	494 470	493 349
AKERBP – Senior Notes (19/24)****	741 421	-	741 421	-
Long-term bonds	1 630 936	1 110 488	1 630 936	1 110 488
DETNOR02 Senior unsecured bond*	226 700	-	226 700	-
Short-term bonds	226 700	-	226 700	-

	No. of shares	Owning
Overview of the 20 largest shareholders registered as of 31 December 2019	(in 1 000)	interest
AKER CAPITAL AS	144 049	40.00%
BP Exploration Operating Company Ltd	108 021	30.00%
FOLKETRYGDFONDET	12 651	3.51%
State Street Bank and Trust Comp*	4 195	1.16%
VERDIPAPIRFONDET DNB NORGE	2 697	0.75%
HSBC Bank Plc*	2 680	0.74%
CLEARSTREAM BANKING S.A.*	2 676	0.74%
JPMorgan Chase Bank, N.A., London*	1 797	0.50%
RBC INVESTOR SERVICES BANK S.A.*	1 362	0.38%
State Street Bank and Trust Comp*	1 256	0.35%
State Street Bank and Trust Comp*	1 234	0.34%
DANSKE INVEST NORSKE INSTIT. II.	1 184	0.33%
VERDIPAPIRFONDET KLP AKSJENORGE	1 117	0.31%
Santander Securities Services, S.A*	1 089	0.30%
KLP AKSJENORGE INDEKS	1 056	0.29%
TVENGE	1 000	0.28%
VERDIPAPIRFONDET NORDEA KAPITAL	953	0.26%
ARCTIC FUNDS PLC	917	0.25%
JPMorgan Chase Bank, N.A., London*	889	0.25%
State Street Bank and Trust Comp*	886	0.25%
OTHER	68 403	18.99%
Total	360 114	100.00%

**** The bond was established in June 2019 and carries an interest of 4.75 percent. The principal falls due in June 2024 and interest is paid on a semi annual basis. The bond is senior unsecured and has no financial covenants.

* The bond is denominated in NOK and runs from July 2013 to July 2020 and carries an interest rate of 3 month Nibor + 6.5 percent. The principal falls due on July 2020 and interest is paid on a quarterly basis. The bond is unsecured. The bond has been swapped into USD using a cross currency interest rate swap whereby the group pays Libor + 6.81 percent quarterly. The financial covenants for this bond are consistent with the Revolving credit facility as described in note 24.

** The bond was established in July 2017 and carries an interest of 6.0 percent. The principal falls due in July 2022 and interest is paid on a semi annual basis. The bond is senior unsecured and has no financial covenants.

*** The bond was established in March 2018 and carries an interest of 5.875 percent. The principal falls due in March 2025 and interest is paid on a semi annual basis. The bond is senior unsecured and has no financial covenants.

	Group	Parent
(USD 1 000)	2019	2019
Operating lease obligation 31.12.2018	1 100 753	1 100 753
Short-term and low value leases	-403 720	-403 720
Non-lease components excluded	-223 551	-223 551
Other	-8 574	-8 574
Nominal lease debt 01.01.2019	464 907	464 907
Discounting	-75 075	-75 075
Lease debt 01.01.2019	389 833	389 833
New lease debt recognized in the period	34 385	34 385
Payments of lease debt*	-134 253	-134 253
Interest expense on lease debt	23 897	23 897
Currency exchange differences	-606	-606
Total lease debt 31.12.2019	313 256	313 256
Break down of the lease debt to short-term and long-term liabilities

Total lease debt
------------------	--

Investments in fixed assets
Abandonment activity
Operating expenditures
Exploration expenditures
Other income

Short-term	110 664	110 664
Long-term	202 592	202 592
Total lease debt	313 256	313 256
* Payments of lease debt split by activities (USD 1 000):	2019	2019
Investments in fixed assets	108 587	108 587
Abandonment activity	4 444	4 444
Operating expenditures	15 278	15 278
Exploration expenditures	1 384	1 384
Other income	4 561	4 561
Total	134 253	134 253

Nominal lease debt maturity breakdown (USD 1 000):

Within one year	127 747	127 747
Two to five years	175 947	175 947
After five years	61 518	61 518
Total	365 212	365 212

Note 27 Commitments

Capital commitments and other contractual obligations

Guarantees

The company has a bank guarantee related to withheld payroll tax of NOK 300 million.

The total expenditure relating to short-term leases which are not recognized as part of lease liabilities was USD 126 million in 2019.

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 transportation cost in the coming two years. This guarantee amounts to NOK 980 million as of year-end 2019 (NOK 900 million in 2018).

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 2019. No sublease of right-of-use assets has occured.

	Group		Parent
(USD 1 000)	31.12.2019	31.12.2018	31.12.2019	31.12.2018
Within one year	355 386	291 693	355 386	291 693
One to five years	520 204	482 445	520 204	482 445
After five years	102 951	183 743	102 951	183 743
Total	978 541	957 881	978 541	957 881

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 2019. The ability to allocate future rig lease to partners may be significantly impacted by the COVID – 19 crisis, as described in note 31. 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 26 in relation to right-of-use assets.

Note 24 Other interest-bearing debt

Note 25 Other current liabilities

Note 26 Lease agreements

Significant lease agreements

The group has applied the modified retrospective approach with no restatement of comparative figures. Refer to the accounting principles in the 2018 financial statements for description of impact and changes in accounting. The difference between the operating lease commitments, as disclosed in note 25 in the 2018 financial statements and the lease debt recognized at initial application is reconciled in the table below. The incremental borrowing rate applied in discounting of the nominal lease debt is between 4.16 percent and 6.67 percent, dependent on the duration of the lease and when it was intially recognized.

		Group		Parent
		Restated		Restated
Breakdown of other current liabilities (USD 1 000)	31.12.2019	31.12.2018	31.12.2019	31.12.2018
Balances with license partners	67 199	22 779	67 199	22 779
Share of other current liabilities in licenses	379 787	309 260	379 787	309 260
Overlift of petroleum*	15 660	10 055	15 660	10 055
Fair value of contracts assumed in acquisitions**	-	42 998	-	42 998
Unpaid wages and vacation pay, accrued interest and other provisions.	197 486	198 801	197 486	198 801
Total other current liabilities	660 132	583 894	660 132	583 894

We also have two rig commitment contracts with Odfjell Drilling: the Deepsea Stavanger and the Deepsea Nordkapp. The Deepsea Stavanger is on contract until the end of the Ærfugl Phase 1 campaign (which is estimated to be March 2020), and the Deepsea Nordkapp is on a two year contract from May 2019 until June 2021. In December 2019, the first option period for the Deepsea Nordkapp was signed, and extended the contract until June 2022. In addition we had a rig commitment contract for Scarabeo 8 until June 2019. 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 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.

Non-lease components such as the service element of rig commitments are not included as part of the lease debt. As at 31 December 2019 this amounts to USD 123 million.

	Group		Parent
(USD 1 000)	31.12.2019	31.12.2018	31.12.2019	31.12.2018
Reserve-based lending facility	-	907 954	-	907 954
Revolving credit facility	1 429 132	-	1 429 132	-
Long-term interest-bearing debt	1 429 132	907 954	1 429 132	907 954

• Interest Coverage Ratio: EBITDA divided by Interest expenses shall be a minimum of 3.5 times

• Leverage Ratio: Total net debt divided by EBITDAX shall not exceed 3.5 times

In May 2019, the group refinanced the Reserve-based lending facility (RBL) with a USD 4.0 billion senior unsecured Revolving credit facility (RCF). The RCF comprise a 3-year USD 2.0 billion Working Capital Facility and a USD 2.0 billion 5-year Liquidity Facility. The Liquidity Facility includes two 12-month extension options. The interest rate is LIBOR plus a margin of 1.08 percent for the Liquidity Facility and 1.33 percent for the Working Capital Facility. In addition, a utilization fee is applicable for the Working Capital Facility. A commitment fee of 35 percent of applicable margin is paid on the undrawn facility. The financial covenants are as follows:

For 2019, the group had seven rig commitment contracts in place. This included four jack-up rigs from Maersk Drilling: Maersk Invincible, Maersk Integrator, Maersk Reacher and Maersk Interceptor. The Maersk Invincible is contracted on the Valhall license until May 2022. The Maersk Integrator is contracted for approximately 14 months to the Ula area, which commenced in June 2019. In addition, the Maersk Reacher is on hire for accommodation purposes on Valhall until October 2020. All of these three are included as leases in the table below. In addition, the Maersk Interceptor was contracted on the Ivar Aasen license until the end of 2019 and fall under the short-term exemption.

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.

* Comparable figure has been restated to reflect the valuation of overlift to production cost, in line with the sales method as described in note 1.

** As described in note 23, the fair value of contracts was in 2019 netted against the right-of-use assets as at 1 January 2019.

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.

Note 29 Financial instruments

Capital structure and equity

Categories of financial assets and liabilities

Categories of financial assets and financial liabilities - Group and Parent

31.12.2018	Financial assets at fair value designated as such upon initial recognition	Cash and receivables	Financial liabilities at fair value designated as such upon initial recognition	Financial liabilities measured at amortized cost	Total
Assets
Accounts receivable	-	162 798	-	-	162 798
Tax receivable	-	11 082	-	-	11 082
Other short-term receivables*	-	296 188	-	-	296 188
Cash and cash equivalents	-	44 944	-	-	44 944
Derivatives	17 253	-	-	-	17 253
Total financial assets	17 253	515 012	-	-	532 265
Liabilities
Derivatives	-	-	35 058	-	35 058
Trade creditors	-	-	-	105 567	105 567
Bonds	-	-	-	1 110 488	1 110 488
Other interest bearing debt	-	-	-	907 954	907 954
Other short-term liabilities	-	-	-	590 860	590 860
Total financial liabilities	-	-	35 058	2 714 870	2 749 928

* Prepayments are not included in other short-term receivables, as they do not meet the definition of financial instruments.

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.

31.12.2019	Financial assets at fair value designated as such upon initial recognition	Cash and receivables	Financial liabilities at fair value designated as such upon initial recognition	Financial liabilities measured at amortized cost	Total
Assets
Accounts receivable	-	193 444	-	-	193 444
Tax receivable	-	-	-	-	-
Other short-term receivables*	-	264 702	-	-	264 702
Cash and cash equivalents	-	107 104	-	-	107 104
Derivatives	2 706	-	-	-	2 706
Total financial assets	2 706	565 251	-	-	567 957
Liabilities
Derivatives	-	-	42 994	-	42 994
Trade creditors	-	-	-	144 942	144 942
Bonds	-	-	-	1 857 636	1 857 636
Other interest bearing debt	-	-	-	1 429 132	1 429 132
Other short-term liabilities	-	-	-	660 132	660 132
Total financial liabilities	-	-	42 994	4 091 842	4 134 837

The company is rated by S&P Global, Fitch and Moody's. The investment grade rating assigned by both S&P Global and Fitch in 2019 has increased access to a very liquid capital market, inluding bank and bond financing, at attractive terms. The company's financial position and resource and reserve levels are important parameters in relation to the assigned rating and access to the capital markets. The company seeks 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.

Contingent liabilities

Note 28 Transactions with related parties

Transactions with related parties

		Group		Parent
Related party (USD 1 000)	Receivables (+) / liabilities (-)	31.12.2019	31.12.2018	31.12.2019	31.12.2018
Aker Solutions ASA	Trade creditors	-1 221	-6 759	-1 221	-6 759
Cognite AS	Trade creditors	-	-1 244	-	-1 244
Kværner AS	Trade creditors	-	-1 051	-	-1 051
Other Aker Group Companies	Trade creditors	-1 916	-706	-1 916	-706
Other BP Group Companies	Trade creditors	-1	-7	-1	-7
Aker Energy Ghana	Trade debtors	-	564	-	564
BP Oil International Ltd.	Trade debtors	126 224	205 750	126 224	205 750
BP Global Investments Ltd.	Trade debtors	-	2 840	-	2 840
Other BP Group Companies	Trade debtors	858	349	858	349
Other Aker Group Companies	Trade debtors	145	-	145	-

		Group		Parent
Related party (USD 1 000)	Revenues (-) / expenses (+)	2019	2018	2019	2018
Akastor Real Estate AS	Office rental	2 948	1 289	2 948	1 289
Aker ASA	Board remuneration etc	553	258	553	258
Aker Energy AS	Recharge of consultants and shared services	-2 280	-	-2 280	-
Aker Energy Ghana	Recharge of consultants and shared services	-	-12 149	-	-12 149
Aker Solutions ASA	Development costs	220 523	206 081	220 523	206 081
Cognite AS	Other operating expenses	11 053	11 425	11 053	11 425
First Geo AS	Exploration expenses	5 533	5 446	5 533	5 446
Kværner AS	Other operating expenses	37 623	68 616	37 623	68 616
OCY Alexandra	Platform supply vessel leases	-	10 689	-	10 689
OCY Frayja Limited	Platform supply vessel leases	4 251	801	4 251	801
OCY Orla Limited	Platform supply vessel leases	4 251	801	4 251	801
Other Aker companies	Operating expenses	1 091	1 237	1 091	1 237
BP Exploration Operating Co	Purchases of consultant and shared services and merger cost	2 844	1 870	2 844	1 870
BP Gas Marketing Ltd	Sales of Gas	-279 191	-380 389	-279 191	-380 389
BP International Ltd	Purchases of consultant and shared services	-	1 182	-	1 182
BP Oil International Ltd	Sales of Oil and NGL	-2 880 261	-3 297 563	-2 880 261	-3 297 563
Other BP Group Companies	Other operating expenses	854	-1 532	854	-1 532

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.

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.

At year-end 2019, Aker (Aker Capital AS) and BP Exploration Operating Company Ltd are the two major shareholders in Aker BP, with a total ownership interest of 40.00 and 30.00 percent. 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.

(iii) Interest rate risk

Change in interest rate level in basis points (USD 1 000)		31.12.2019	31.12.2018
Effect on pre-tax profit/loss:	+ 100 points	-11 435	-112
	- 100 points	11 882	1 276

In order to calculate sensitivity of interest rate changes, floating interest rates have been changed by + / - 100 basis points.

(iv) Liquidity risk/liquidity management

The company's liquidity risk is the risk that it will not be able to meet its financial obligations as they fall due.

The company's objective for the placement and management of excess capital is to maintain a low risk profile and good liquidity.

The company is exposed to interest rate risk to borrowings and cash deposits. Floating-interest loans involve risk exposure for the company's future cash flows. As of 31 December 2019, the company's total debt liabilities exposed to interest risk amounted to approximately USD 1.7 billion, distributed between short-term bonds and the revolving credit facility. The corresponding debt liabilities as of 31 December 2018 amounted to approximately USD 1.1 billion.

The terms of the company's debt instruments are described in notes 20 and 24. The interest rate risk relating to cash and cash equivalents is relatively limited. The following table shows the company's sensitivity to potential changes in interest rates which is reasonably possible:

The table presents the annual effect on profit and loss for the financial instruments exposed to interest risk at the balance sheet date. Any changes in interest rates will impact the fair value of interest rate swaps, as the floating rate interest received on the interest rate swaps is associated with a corresponding floating rate interest payment on a bond or a loan. A change in fair value on the interest rate swaps has reduced the exposure to interest rate risk by USD 5.2 million in the sensitivity presented.

In July 2017 the UK's Financial Conduct Authority announced that from 1 January 2022 it would no longer compel panel banks to submit the rates required to calculate LIBOR and the transition away from IBOR to alternative reference rates moves at various speed in different markets. However, new benchmark regulation demands that an alternative fallback rate must be in place in the event that the current IBOR rate should be discontinued. The various countries are at different stages in deciding and implementing this new rate and determining the fallback mechanism.

This will require Aker BP to replace the references to the relevant IBOR rates in financial agreements, with new benchmark rates or insert fallback language to cater for a discontinuation of IBOR rates, at the earliest by the end of 2021. The new proposed benchmark rates are not fully adopted by regulations and capital markets, however we expect no material impact as the alternative reference rate is expected to be similar to the current IBOR rate. Aker BP will continue to follow the development and consultations closely.

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 liquid assets as of 31 December 2019 are deposited in bank accounts. As of 31 December 2019, the company had cash reserves of USD 107 million (2018: USD 45 million). Revenues and expenses are carefully managed on a day-to-day basis for liquidity risk management purposes.

Financial risk

(i) Commodity price risk

(USD 1 000)	Increase/decrease in oil price	31.12.2019	31.12.2018
Effect on pre-tax profit/loss:	+ 30%	-4 263	-27 141
	- 30%	31 977	72 889

(ii) Currency risk

The table below shows the company's exposure in NOK as of 31 December:

Exposure relating to (USD 1 000)	31.12.2019	31.12.2018
Tax receivables, cash and cash equivalents, other short-term receivables and deposits	136 056	191 599
Trade creditors, tax payable, leasing liability and other short-term liabilities	-960 920	-1 050 045
Bonds	-230 392	-218 878
Net exposure to NOK	-1 055 256	-1 077 324

(USD 1 000)	Change in exchange rate	31.12.2019	31.12.2018
Effect on pre-tax profit/loss:	+ 10%	14 900	16 040
	- 10%	-21 470	-12 779

The sensitivity above includes the impact from currency derivatives.

In 2019 the company had put options in place with a strike of 50, 55, 60 and 65 USD/bbl. for approximately 20 percent of the 2019 oil production, corresponding to approximately 69 percent of the after tax value.

The following table summarizes the sensitivity of the commodity derivatives to a reasonably possible change in the forward oil price as of 31 December 2019, with all other variables held constant. As the company has not hedged production after 2020, the calculation is based on 2020 forward curve only. The impact presented below is on the fair value of the commodity derivatives only, and does not include other Income statement effects from changes in oil prices.

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 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 USD/NOK exchange rate. Other currencies are not included as the exposure is deemed immaterial.

The company is also exposed to change in other exchange rates such as GBP/USD and EUR/USD, but the amounts are deemed immaterial.

The company has financed its activities with Revolving credit facility (see note 24) and bonds (see note 20 and note 31). In addition, the company has financial instruments such as accounts receivable, trade creditors 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 against lower oil prices. Foreign currency exchange contracts and options are used in order to reduce currency risk related to cash flows. The company manages a portion of its interest rate exposure with a cross currency interest rate swap and 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 interest 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. In 2019 the company entered into new commodity hedges for 2020. These are put options with an average strike price 54 USD/bbl, for approximately 8 percent of estimated 2020 oil production, corresponding to approximately 27 percent of the after tax value.

Fair value hierarchy

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.

31.12.2019

31.12.2018

31.12.2019
Financial instruments recognized at fair value (USD 1 000)	Level 1	Level 2	Level 3
Financial assets or liabilities measured at fair value with changes in value recognized through profit or loss
Derivatives	- -40 289		-
31.12.2018
Financial instruments recognized at fair value (USD 1 000)	Level 1	Level 2	Level 3
Financial assets or liabilities measured at fair value with changes in value recognized through profit or loss
Derivatives	-	-17 805	-

In the course of the reporting period, there were no changes in the fair value measurements that involved any transfers between levels.

Reconciliation of liabilities arising from financing activities

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).

			Non-cash changes
	31.12.2017	Cash flows	Amortization	Currency	Other fin exp	31.12.2018
Long-term interest-bearing debt (RBL)	1 270 556	-380 000	17 398	-	-	907 954
Short-term interest-bearing debt	1 496 374	-1 500 000	3 626	-	-	-
Bonds	622 039	492 266	8 694	-12 511	-	1 110 488
Paid dividends	-	-450 000	-	-	-	-
Totals	3 388 969	-1 837 734	29 718	-12 511	-	2 018 443

			Non-cash changes
	31.12.2018	Cash flows	Amortization	Currency	Other fin exp*	31.12.2019
Long-term interest-bearing debt (RBL)	907 954	-950 000	7 249	-	34 796	-
Long-term interest-bearing debt (RCF)	-	1 425 222	3 909	-	-	1 429 132
Short-term interest-bearing debt	-	-	-	-	-	-
Bonds	1 110 488	740 159	10 546	-3 654	97	1 857 636
Paid dividends	-	-750 000	-	-	-	-
Totals	2 018 443	465 381	21 705	-3 654	34 893	2 536 768

* Other financial expenses mainly represents the remaining unamortized fees in relation to the refinancing of the RBL facility

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:

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.

The table below shows the payment structure for the company's financial commitments, based on undiscounted contractual payments:

(v) Credit risk

Determination of fair value

31.12.2019	Book value	Less than 1 year	1-2 years	2-5 years	over 5 years	Total
Non-derivative financial liabilities:
Bonds	1 857 636	329 761	89 000	1 339 188	507 344	2 265 293
Other interest-bearing debt	1 429 132	56 150	56 150	1 607 426	-	1 719 726
Trade creditors and other liabilities	805 074	805 074	-	-	-	805 074
Derivative financial liabilities
Derivatives	40 289	42 994	-2 706	-	-	40 289
Total as of 31.12.2019	4 132 131	1 233 980	142 444	2 946 614	507 344	4 830 382

	31.12.2019			31.12.2018
Fair value of financial instruments (USD 1 000)	Book value	Fair value	Book value	Fair value
Financial liabilities measured at amortized cost:
Bonds	1 857 636	1 966 037	1 110 488	1 148 533
Other interest-bearing debt	1 429 132	1 429 132	907 954	907 954
Total financial liabilities	3 286 768	3 395 169	2 018 443	2 056 488

		Contract related cash flow
31.12.2018	Book value	Less than 1 year	1-2 years	2-5 years	over 5 years	Total
Non-derivative financial liabilities:
Bonds	1 110 488	70 333	287 106	517 474	539 811	1 414 723
Other interest-bearing debt	907 954	34 108	927 851	-	-	961 959
Trade creditors and other liabilities	696 427	696 427	-	-	-	696 427
Derivative financial liabilities
Derivatives	35 058	8 783	26 275	-	-	35 058
Total as of 31.12.2018	2 749 928	809 651	1 241 231	517 474	539 811	3 108 167

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).

The bond issued September 2013 is listed on Oslo Børs, and the fair value for disclosure purposes is determined using the quoted value as of 31 December 2019. The USD 6%, 5.875% and 4.75% Senior Notes are all listed on The International Stock Exchange, and the fair values for disclosure purposes are determined using the quoted value as of 31 December 2019. For the RCF facility, the fair value is assessed to equal the book value.

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 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.

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 accounts receivable and other short-term receivables, see notes 14 and 15.

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.

Note 30 Investments in joint operations

Fields operated:	31.12.2019	31.12.2018
Alvheim	65.000 %	65.000 %
Bøyla	65.000 %	65.000 %
Hod	90.000 %	90.000 %
Ivar Aasen Unit	34.786 %	34.786 %
Jette Unit	70.000 %	70.000 %
Valhall	90.000 %	90.000 %
Vilje	46.904 %	46.904 %
Volund	65.000 %	65.000 %
Tambar	55.000 %	55.000 %
Tambar Øst	46.200 %	46.200 %
Ula	80.000 %	80.000 %
Skarv	23.835 %	23.835 %

Production licenses in which Aker BP is the operator: License: 31.12.2019 31.12.2018 License: 31.12.2019 31.12.2018 PL 001B 35.000 % 35.000 % PL 748* 0.000 % 50.000 % PL 006B 90.000 % 90.000 % PL 748B* 0.000 % 50.000 % PL 019 80.000 % 80.000 % PL 762 20.000 % 20.000 % PL 019C 80.000 % 80.000 % PL 777 40.000 % 40.000 % PL 019E 80.000 % 80.000 % PL 777B 40.000 % 40.000 % PL 019H** 80.000 % 0.000 % PL 777C 40.000 % 40.000 % PL 026 92.130 % 92.130 % PL 777D 40.000 % 40.000 % PL 026B 90.260 % 90.260 % PL 784 40.000 % 40.000 % PL 027D* 0.000 % 100.000 % PL 790 0.000 % 30.000 % PL 028B 35.000 % 35.000 % PL 814 40.000 % 40.000 % PL 033 90.000 % 90.000 % PL 818 40.000 % 40.000 % PL 033B 90.000 % 90.000 % PL 818B 40.000 % 40.000 % PL 036C 65.000 % 65.000 % PL 822S 60.000 % 60.000 % PL 036D 46.904 % 46.904 % PL 839 23.835 % 23.835 % PL 036E 64.000 % 64.000 % PL 843 40.000 % 40.000 % PL 065 55.000 % 55.000 % PL 858 40.000 % 40.000 %

PL 065B	55.000 %	55.000 %	PL 861*	0.000 %	50.000 %
PL 088BS	65.000 %	65.000 %	PL 867	40.000 %	40.000 %
PL 102D	50.000 %	50.000 %	PL 868	60.000 %	60.000 %
PL 102F	50.000 %	50.000 %	PL 869	60.000 %	60.000 %
PL 102G	50.000 %	50.000 %	PL 872*	0.000 %	40.000 %
PL 102H	50.000 %	50.000 %	PL 873	40.000 %	40.000 %
PL 127C	100.000 %	100.000 %	PL 874	90.260 %	90.260 %
PL 146	77.800 %	77.800 %	PL 893	60.000 %	60.000 %
PL 150	65.000 %	65.000 %	PL 895*	0.000 %	60.000 %
PL 159D	23.835 %	23.835 %	PL 906	60.000 %	60.000 %
PL 169C*	0.000 %	50.000 %	PL 907	60.000 %	60.000 %
PL 203	65.000 %	65.000 %	PL 914S	34.786 %	34.786 %
PL 203B*	0.000 %	65.000 %	PL 915	35.000 %	35.000 %
PL 212	30.000 %	30.000 %	PL 916	40.000 %	40.000 %
PL 212B	30.000 %	30.000 %	PL 919	65.000 %	65.000 %
PL 212E	30.000 %	30.000 %	PL 932	60.000 %	60.000 %
PL 242	35.000 %	35.000 %	PL 941	50.000 %	50.000 %
PL 261	50.000 %	50.000 %	PL 948	40.000 %	40.000 %
PL 262	30.000 %	30.000 %	PL 951	40.000 %	40.000 %
PL 300	55.000 %	55.000 %	PL 963	70.000 %	70.000 %
PL 333	77.800 %	77.800 %	PL 964	40.000 %	40.000 %
PL 340	65.000 %	65.000 %	PL 977**	60.000 %	0.000 %
PL 340BS	65.000 %	65.000 %	PL 978**	60.000 %	0.000 %
PL 364	90.260 %	90.260 %	PL 979**	60.000 %	0.000 %
PL 442	90.260 %	90.260 %	PL 986**	30.000 %	0.000 %
PL 442B	90.260 %	90.260 %	PL 1005**	60.000 %	0.000 %
PL 460	65.000 %	65.000 %	PL 1008**	60.000 %	0.000 %
PL 504*	0.000 %	47.593 %	PL 1022**	40.000 %	0.000 %
PL 626*	0.000 %	60.000 %	PL 1026**	40.000 %	0.000 %
PL 659*	0.000 %	50.000 %	PL 1028**	50.000 %	0.000 %

PL 685 40.000 % 40.000 % PL 1030** 50.000 % 0.000 %

Number of licenses in which Aker BP is the operator 82 8 3

* Relinquished license or Aker BP has withdrawn from the license

** Interest awarded in the APA Licensing round

Fields non-operated:	31.12.2019	31.12.2018
Atla	10.000 %	10.000 %
Enoch	2.000 %	2.000 %
Gina Krog	3.300 %	3.300 %
Johan Sverdrup	11.573 %	11.5733 %
Oda	15.000 %	15.000 %

License:	31.12.2019	31.12.2018	License:	31.12.2019	31.12.2018
PL 006C	15.000 %	15.000 %	PL 782SC	20.000 %	20.000 %
PL 006E	15.000 %	15.000 %	PL 782SD***	20.000 %	0.000 %
PL 006F***	15.000 %	0.000 %	PL 810**	0.000 %	30.000 %
PL018DS**	0.000 %	13.338 %	PL810B**	0.000 %	30.000 %
PL 029B	20.000 %	20.000 %	PL 811	20.000 %	20.000 %
PL 035	50.000 %	50.000 %	PL 813**	0.000 %	3.300 %
PL 035C	50.000 %	50.000 %	PL 838	30.000 %	30.000 %
PL 048D	10.000 %	10.000 %	PL 838B***	30.000 %	0.000 %
PL 102C	10.000 %	10.000 %	PL 842**	0.000 %	30.000 %
PL 127	50.000 %	50.000 %	PL 844	20.000 %	20.000 %
PL 127B	50.000 %	50.000 %	PL 852	40.000 %	40.000 %
PL 220	15.000 %	15.000 %	PL 852B	40.000 %	40.000 %
PL 265	20.000 %	20.000 %	PL 852C	40.000 %	40.000 %
PL 272	50.000 %	50.000 %	PL 857	20.000 %	20.000 %
PL 272B	50.000 %	0.000 %	PL 862	50.000 %	50.000 %
PL 405	15.000 %	15.000 %	PL 863	40.000 %	40.000 %
PL 457BS	40.000 %	40.000 %	PL 863B	40.000 %	40.000 %
PL 492	60.000 %	60.000 %	PL 864	20.000 %	20.000 %
PL 502	22.222 %	22.222 %	PL 891**	0.000 %	30.000 %
PL 533	35.000 %	35.000 %	PL 892	30.000 %	30.000 %
PL 533B	35.000 %	35.000 %	PL 902	30.000 %	30.000 %
PL 554	30.000 %	30.000 %	PL 902B***	30.000 %	0.000 %
PL 554B	30.000 %	30.000 %	PL 942	30.000 %	30.000 %
PL 554C	30.000 %	30.000 %	PL 954	20.000 %	20.000 %
PL 554D	30.000 %	30.000 %	PL 955	30.000 %	30.000 %
PL 615	4.000 %	4.000 %	PL 961	30.000 %	30.000 %
PL 615B	4.000 %	4.000 %	PL 962	20.000 %	20.000 %
PL 719	20.000 %	20.000 %	PL 966	30.000 %	30.000 %
PL 721**	0.000 %	40.000 %	PL 968***	20.000 %	0.000 %
PL 722	20.000 %	20.000 %	PL 981***	40.000 %	0.000 %
PL 780*	40.000 %	0.000 %	PL 982***	40.000 %	0.000 %
PL 782S	20.000 %	20.000 %	PL 985***	20.000 %	0.000 %
PL 782SB	20.000 %	20.000 %	PL 1031***	20.000 %	0.000 %
Number of licenses in which Aker BP is a partner				59	5 5

* Aker BP has aquired a 40% share of PL 780

*** Interest awarded in the APA Licensing round ** Relinquished license or Aker BP has withdrawn from the license

	Field/project
	Alvheim (Norwegian part, including Kameleon, Kneler and Viper/Kobra)
Boa
Bøyla
	Frosk Test Production
Vilje
Volund
Ula
Tambar
	Tambar East
Vahall
Hod
Skarv
	Ærfugl A-1H
	Ivar Aasen
	Johan Sverdup Phase 1
	Gina Krog
Oda
Atla
Enoch

Table 2 - Aker BP fields - Undeveloped reserves

Total net proven reserves (1P/P90) as of 31 December 2019 to Aker BP ASA are estimated at 666 million barrels of oil equivalents. Total net proven plus probable reserves (2P/P50) are estimated at 906 million barrels of oil equivalents. The split between liquid and gas and between the different subcategories are given in tables 3 and 4.

Field/project	Investment share	Operator	Resource class
Johan Sverdup Phase 2	11.57 %	Equinor	Approved for Development
Hanz	35.00 %	Aker BP	Approved for Development
Alvheim Kameleon Gas Cap Blow Down	65.00 %	Aker BP	Approved for Development
Kameleon Infill Mid	65.00 %	Aker BP	Approved for Development
Skogul	65.00 %	Aker BP	Approved for Development
Valhall Flank North Water Injection	90.00 %	Aker BP	Approved for Development
Valhall Flank South West Infill Drilling	90.00 %	Aker BP	Approved for Development
Valhall Flank West Project	90.00 %	Aker BP	Approved for Development
Valhall Flank West V-12 Infill	90.00 %	Aker BP	Approved for Development
Valhall Flank West V-4 Infill	90.00 %	Aker BP	Approved for Development
Valhall IP drilling programme	90.00 %	Aker BP	Approved for Development
Valhall Tor Fm Infill PSCN	90.00 %	Aker BP	Approved for Development
Valhall WP Production recovery	90.00 %	Aker BP	Approved for Development
Ula Drilling phase 1	80.00 %	Aker BP	Approved for Development
Tambar K2 Sidetrack	55.00 %	Aker BP	Approved for Development
Snadd Outer	30.00 %	Aker BP	Approved for Development
Ærfugl Phase 1	23.84 %	Aker BP	Approved for Development
Ærfugl Phase 2	23.84 %	Aker BP	Approved for Development
Frosk Test Production unsanctioned	65.00 %	Aker BP	Justified for Development
Boa Sidetrack South	57.62 %	Aker BP	Justified for Development
Ivar Aasen OP-E-SK2	34.79 %	Aker BP	Justified for Development
Ivar Aasen OP-W	34.79 %	Aker BP	Justified for Development
Hod Field Development Project	90.00 %	Aker BP	Justified for Development

Investment share	Operator	Resource class
65.00 %	Aker BP	On Production
57.62 %	Aker BP	On Production
65.00 %	Aker BP	On Production
65.00 %	Aker BP	On Production
46.90 %	Aker BP	On Production
65.00 %	Aker BP	On Production
80.00 %	Aker BP	On Production
55.00 %	Aker BP	On Production
46.20 %	Aker BP	On Production
90.00 %	Aker BP	On Production
90.00 %	Aker BP	On Production
23.84 %	Aker BP	On Production
23.84 %	Aker BP	On Production
34.79 %	Aker BP	On Production
11.57 %	Equinor	On Production
3.30 %	Equinor	On Production
15.00 %	Spirit Energy	On Production
10.00 %	Total	On Production
2.00 %	Repsol Sinopec	On Production

Aker BP ASA has a working interest in 42 fields/projects containing reserves, see Table 1 and 2. Out of these fields/projects, 19 are in the sub-class "On Production"/Developed, 18 are in the sub-class "Approved for Development"/Undeveloped and five are in the sub-class "Justified for Development"/Undeveloped. Note that several fields have reserves in more than one reserve sub-class.

Note 31 Events after the balance sheet date

Classification of reserves and contingent resources

Figure 1 - SPE's classification system used by Aker BP ASA

Reserves, developed and non-developed

During first quarter 2020, the spread of the COVID-19 virus ("corona") caused global disruption with negative consequences both for human health and economic activity. Aker BP has implemented measures to minimize the spread of the virus and minimize the risk of disruptions to its operations. The corona situation has created significant uncertainty in the global oil market. This uncertainty has been further amplified by signals of increased production volumes from several major oil producing countries, and has caused a significant decline in global oil prices.

The long-term impact from these events on the global economy and the oil market is difficult to predict. From an accounting perspective, this may have a significant impact on recoverable amounts of Aker BP's assets.

On 15 January 2020, Aker BP was offered 15 new licenses, including 9 operatorships in the Awards in Predefined Areas (APA) 2019 licensing round.

On 24 February 2020, Aker BP disbursed USD 212.5 million in dividend to shareholders.

Note 32 Classification of reserves and contingent resources (unaudited)

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.

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 approximately 0.003 percent of total 2P reserves.

On 15 January 2020, Aker BP closed a bond offering for USD 500 million 3 percent Senior Notes due 2025 and USD 1 billion 3.75 percent Senior Notes due 2030. Interest will be payable semi-annually. The bonds are senior unsecured and have no financial covenants. The gross proceeds from the issue were mainly used to repay outstanding amounts under the Revolving credit facility.

On 11 February 2020, Aker BP announced that the company had entered into an agreement with PGNiG Upstream Norway AS to swap its 3.3 percent interest in the non-operated Gina Krog field and an 11.9175 percent interest in license 127C, in exchange for a 5 percent interest and operatorship in license 838 and a cash consideration. The transaction will provide Aker BP with a total cash consideration of up to USD 62 million, consisting of a firm payment of USD 51 million upon closing and an additional payment of USD 11 million contingent on a development of the Alve Nord discovery.

			PRODUCTION	Project Maturity sub-classes
				On Production
		COMMERCIAL	RESERVES	Approved for Development
				Justified for Development
TOTAL PETROLEUM INITIALLY-IN-PLACE (PIIP) DISCOVERED PIIP				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

	Interest	1P / P90 (low estimate)				2P / P50 (best estimate)
Approved for development		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.
31.12.2019	%	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)
Johan Sverdup Phase 2	11.6 %	400	1	1	402	46	587	4	5	595	69
Hanz	35.0 %	12	1	2	15	5	15	1	3	19	7
Alvheim Kameleon Gas Cap Blow Down 65.0 %		-	-	10	10	7	-	-	17	17	11
Kameleon Infill Mid	65.0 %	3	-	0	3	2	4	-	0	5	3
Skogul	65.0 %	5	-	1	6	4	9	-	1	10	6
Valhall Flank North Water Injection	90.0 %	6	0	0	6	6	7	0	0	8	7
Valhall Flank South West Infill Drilling	90.0 %	2	0	0	2	2	4	0	1	5	4
Valhall Flank West Project	90.0 %	32	2	7	41	37	43	2	9	55	49
Valhall Flank West V-12 Infill	90.0 %	2	0	1	3	3	3	0	1	5	4
Valhall Flank West V-4 Infill	90.0 %	2	0	1	3	3	3	0	1	4	4
Valhall IP drilling programme	90.0 %	8	0	1	10	9	10	0	2	13	11
Valhall Tor Fm Infill PSCN	90.0 %	2	0	1	3	3	3	0	1	4	4
Valhall WP Production recovery	90.0 %	12	1	3	16	14	19	1	5	26	23
Ula Drilling phase 1	80.0 %	15	0	-	15	12	28	1	-	29	23
Tambar K2 Sidetrack	55.0 %	1	0	0	1	0	3	0	1	4	2
Snadd Outer	30.0 %	2	5	23	30	9	3	6	29	38	11
Ærfugl Phase 1	23.8 %	13	14	64	91	22	20	20	96	136	32
Ærfugl Phase 2	23.8 %	4	6	27	37	9	6	10	46	62	15
Total		522	30	142	694	192	769	47	218	1 034	288

Total reserves 31.12.2019	666	906
Total reserves 31.12.2018	683	917

	Interest		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.
31.12.2019	%	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)
Frosk Test Production unsanctioned	65.0 %	1	-	0	1	1	3	-	0	3	2
Boa Sidetrack South	57.6 %	2	-	1	3	2	3	-	1	5	3
Ivar Aasen OP-E-SK2	34.8 %	1	0	0	1	1	3	0	0	3	1
Ivar Aasen OP-W	34.8 %	1	0	0	2	1	3	0	0	3	1
Hod Field Development Project	90.0 %	20	1	3	24	21	30	1	4	35	31
Total		26	1	4	31	25	41	1	6	49	38

Table 5 - Aggregated reserves, production, developments, and adjustments
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 31.12.2018	254	343	410	543	18	31	683	917
Production	-56	-56	-	-	-	-	-56	-56
Transfer	243	299	-226	-271	-17	-28	0	0
Revisions	8	-7	-5	-4	-0	-0	4	-10
IOR	-	-	2	3	3	5	5	8
Discovery and extensions	-	-	10	16	21	31	31	48
Acquisition and sale	-	-	-	-	-	-	-	-
Balance as of 31.12.2019	449	580	192	288	25	38	666	906
Delta	194	236	-218	-255	7	8	-17	-11
Note that some rounding errors may occur.

Changes from the 2018 reserve report are summarized in Table 5. During 2019, Aker BP 2P reserves were reduced by 11 mmboe from 917 to 906 mmboe. Production was 56 mmboe. Thus, net reserves increases were 45 mmboe. The main reasons for increases are the continued development of the Valhall area (especially the Hod field development project with 31.4 mmboe and new wells on the Valhall flanke West) and new developments and wells in the Alvheim- and Ivar Aasen-areas.

An oil price of 70 USD/bbl (2020) and 65 USD/bbl (following years) has been used for reserves estimation. Low- and high case sensitivities with oil prices of 35 and 90 USD/bbl, respectively, have been performed by AGR. This had only moderate effect on the reserve estimates. The low price resulted in a reduction in total net proven (1P/P90) reserves of 14.4% and net proven plus probable (2P/P50) reserves of 7.6%. The high oil price resulted in an increase of 0.6% and 0% for proven (1P/P90) and proven plus probable (2P/P50), respectively.

Note also that production numbers are preliminary pr November 2019, leaving numbers for the last two months of 2019 as estimates. These final numbers may be slightly different.

Table 3 - Reserves by field, area and reserve class

			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.
31.12.2019	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)
Alvheim (incl Boa)	44	-	14	58	37	65	-	28	93	59
Volund	5	-	1	6	4	8	-	3	11	7
Vilje	7	-	-	7	3	12	-	-	12	6
Bøyla	2	-	0	2	1	3	-	0	3	2
Frosk Test Production	2	-	0	2	1	4	-	0	4	3
Skogul	5	-	1	6	4	9	-	1	10	6
Alvheim Area	65	-	16	81	51	100	-	33	133	82
Ula	21	1	-	21	17	36	1	-	38	30
Tambar	3	0	1	4	2	8	0	2	10	5
Tambar East	-	-	-	-	-	0	0	0	0	0
Ula Area	24	1	1	26	19	44	2	2	48	36
Valhall	195	9	34	238	215	260	12	47	319	287
Hod	23	1	3	27	24	33	1	5	39	35
Valhall Area	218	10	38	265	239	293	13	51	357	322
Ivar Aasen	60	3	10	73	25	102	5	16	123	43
Hanz	12	1	2	15	5	15	1	3	19	7
Ivar Aasen Area	72	4	12	88	31	117	6	18	142	49
Ærfugl	23	29	138	190	47	33	42	197	272	67
Skarv	15	17	77	109	26	27	19	90	137	33
Skarv Area	38	46	216	300	73	60	61	288	409	100
Johan Sverdrup	2 040	42	51	2 134	247	2 533	53	64	2 650	307
Atla	-	-	-	-	-	-	-	-	-	-
Enoch	-	-	-	-	-	1	-	0	1	0
Gina Krog	49	22	62	133	4	58	26	78	162	5
Oda	15	-	-	15	2	28	-	1	29	4
Other (Atla, Enoch, Gina Krog and Oda)	64	22	62	148	7	87	26	79	193	10
Total	2 521	125	396	3 042	666	3 235	161	535	3 932	906

Table 4 - Reserves by project and reserve class

	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.
31.12.2019	%	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)	(mmboe)
Alvheim	65.0 %	30	-	2	32	21	44	-	7	51	33
Boa	57.6 %	8	-	1	9	5	13	-	3	15	9
Bøyla	65.0 %	2	-	0	2	1	3	-	0	3	2
Frosk Test Production	65.0 %	0	-	0	0	0	1	-	0	1	0
Vilje	46.9 %	7	-	-	7	3	12	-	-	12	6
Volund	65.0 %	5	-	1	6	4	8	-	3	11	7
Ula	80.0 %	6	0	-	6	5	8	0	-	8	7
Tambar	55.0 %	3	0	1	4	2	4	0	1	6	3
Tambar East	46.2 %	-	-	-	-	-	0	0	0	0	0
Vahall	90.0 %	129	5	20	154	139	167	7	26	200	180
Hod	90.0 %	3	0	0	3	3	3	0	0	4	3
Skarv Base	23.8 %	15	17	77	109	26	27	19	90	137	33
Ærfugl A-1H	23.8 %	3	5	24	33	8	4	6	27	36	9
Ivar Aasen	34.8 %	57	3	10	70	24	97	5	15	117	41
Johan Sverdup Phase 1	11.6 %	1 640	42	50	1 732	200	1 946	49	59	2 055	238
Gina Krog	3.3 %	49	22	62	133	4	58	26	78	162	5
Oda	15.0 %	15	-	-	15	2	28	-	1	29	4
Atla	10.0 %	-	-	-	-	-	-	-	-	-	-
Enoch	2.0 %	-	-	-	-	-	1	-	0	1	0
Total		1 973	94	250	2 317	449	2 425	113	311	2 848	580

Alternative performance measures

* The definition of Leverage ratio has been adjusted to comply with the financial covenants in the group's current debt facilities. Both leasing debt and IFRS 16 impacts on EBITDAX are thus excluded when calculating this ratio.

** Includes leasing debt from 2019

*** Definition was changed in 2019 as production cost in the income statement includes adjustment for over/underlift, while this APM still applies to produced volumes.

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 fields

Depreciation per boe is depreciation divided by number of barrels of oil equivalents produced in the corresponding period

Dividend per share (DPS) is dividend paid in the quarter divided by number of shares outstanding

Capex is disbursements on investments in fixed assets deducted by capitalized interest cost

Operating profit is short for earnings before interest and other financial items and taxes

Production cost per boe is production cost basd on produced volumes (see note 5), divided by number of barrels of oil equivalents produced in the corresponding period***

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 expenses

Leverage ratio is calculated as Net interest-bearing debt divided by twelve months rolling EBITDAX, excluding impacts from IFRS 16*

Net interest-bearing debt is book value of current and non-current interest-bearing debt less cash and cash equivalents**

STATEMENT BY THE BOARD OF DIRECTORS AND CHIEF EXECUTIVE OFFICER

Øyvind Eriksen, Chairman of the Board Kjell Inge Røkke, Board member

Anne Marie Cannon, Deputy Chair Trond Brandsrud, Board member

Karl Johnny Hersvik, Chief Executive Officer Ørjan Holstad, Board member

The Board of Directors of Aker BP ASA

Akerkvartalet, 19 March 2020

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 2019 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.

Kate Thomson, Board member Bernard Looney, Board member GRO KIELLAND Board member

Gro Kielland, Board member Terje Solheim, Board member INGARD HAUGEBERG

Ingard Haugeberg, Board member Anette Hoel Helgesen, Board member ØRJAN HOLSTAD

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.

ØYVIND ERIKSEN Chairman

ANNE MARIE CANNON Deputy chair

BERNARD LOONEY

Board member

TROND BRANDSRUD Board member

Board member

KATE THOMSON Board member

ANETTE HOEL HELGESEN Board member

Board member

TERJE SOLHEIM Board member

KARL JOHNNY HERSVIK Chief Executive Officer

Impairment of licence assets and associated goodwill 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 licence assets and the associated goodwill are sensitive to changes in assumptions, in particular oil and gas prices, discount rate and forecast operational performance including the volumes of oil and gas to be produced and licence related expenditures. Any negative developments in these assumptions and forecasts may be an impairment trigger, even if other factors have moved favourably.

In addition, the goodwill balances allocated to licence cash generating units will be subject to impairment charges over time as the related oil and gas reserves are produced.

Management's determination of the recoverable amounts of licence assets requires a number of estimates and assumptions relating to operational and market factors, some of which involve a high degree of judgment. In addition, the calculation of recoverable amounts requires complex financial modelling of the cash flows of each cash generating unit.

Significant auditor judgment is required when evaluating whether the recoverable amounts, and the assumptions which drive the underlying cash flow estimates, are reasonable and supportable.

For each cash generating unit where a material risk of impairment was identified, we critically assessed the key elements of the cash flow forecasts, including:

• production profiles with reference to reserves estimates prepared by the Company's reservoir engineers and third party reserves certification reports;
• three year oil and gas prices with reference to forward curve data and the Company's long term oil price assumptions against benchmark data from third party analysts;
• opex and capex expenditures with reference to historical forecasts, approved licence budgets and management forecasts; and
• abandonment expenditures with reference to our audit work on the abandonment provision (refer Abandonment provisions Key Audit Matter).

In addition, KPMG valuation specialists assessed the mathematical and methodological integrity of management's impairment models, including the modelling of tax related cash flows, and assessed the reasonableness of the discount rate applied with reference to market data.

We also considered whether the disclosures regarding key assumptions and sensitivities adequately reflected the underlying impairment assessments.

Abandonment provisions

Refer to financial statement Note 1.3 (Important accounting judgments, estimates and assumptions), Note 1.25 (Provisions) and Note 20 (Provision for abandonment liabilities).

The key audit matter How the matter was addressed in our audit

Management's estimate of abandonment provisions requires significant judgment due to:

As a result of these uncertainties, there are typically a wide range of possible abandonment provision estimates for each license. Significant auditor judgment is therefore required when

• the technically challenging nature of the decommissioning work which may be performed over several years;
• applying experiences and data from actual decommissioning projects (e.g. number of days required to plug wells) to estimates of future decommissioning activities;
• uncertainties over current market costs for decommissioning work (e.g. rig rates) and future cost escalation; and
• the relatively limited number of analogous decommissioning projects completed by the Company and the wider industry which can act as benchmarks. • plug and abandonment costs for drilled wells, including rig costs, with reference to contractual terms where available and / or the Company's benchmark data;

For each licence with a potentially significant abandonment liability, we critically assessed management's estimate of the decommissioning costs, including:

• well count and relevant technical details of facilities and infrastructure with reference to publicly available information and licence reporting;
• assumptions for the number of days required for plugging and abandonment activities, with reference to the Company's internal benchmark data where available;
• facilities removal and decommissioning costs with reference to contractual terms where available and / or the Company's internal benchmark data and third-party reports where available; and

KPMG AS Sørkedalsveien 6 Postboks 7000 Majorstuen 0306 Oslo

Telephone +47 04063 Fax +47 22 60 96 01 Internet www.kpmg.no Enterprise 935 174 627 MVA

To the General Meeting of Aker BP ASA

Independent Auditor's Report

Report on the Audit of the Financial Statements

Opinion

We have audited the financial statements of Aker BP ASA. The financial statements comprise:

• The financial statements of the parent company Aker BP ASA (the Company), which comprise the statement of financial position as at 31 December 2019, and income statement, statement of comprehensive income, statement of changes in equity, statement of cash flow for the year then ended, and notes to the financial statements, including a summary of significant accounting policies, and
• The consolidated financial statements of Aker BP ASA and its subsidiaries (the Group), which comprise the statement of financial position as at 31 December 2019, and income statement, statement of comprehensive income, statement of changes in equity, statement of cash flow for the year then ended, and notes to the financial statements, including a summary of significant accounting policies.

In our opinion:

• The financial statements are prepared in accordance with the law and regulations.
• The accompanying financial statements give a true and fair view of the financial position of the Company as at 31 December 2019, and its financial performance and its cash flows for the year then ended in accordance with International Financial Reporting Standards as adopted by the EU.
• The accompanying consolidated financial statements give a true and fair view of the financial position of the Group as at 31 December 2019, and its financial performance and its cash flows for the year then ended in accordance with International Financial Reporting Standards as adopted by the EU.

Basis for Opinion

We conducted our audit in accordance with laws, regulations, and auditing standards and practices generally accepted in Norway, including 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 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.

Key Audit Matters

Key audit matters are those matters that, in our professional judgment, were of most significance in our audit of the financial statements for 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.

	Ullices In:
KPMG AS, a Norwegian limited liability company and member firm of the KPMG network of independent member firms affiliated	Alta	Elverum	Mo i Rana
with KPMG International Cooperative ("KPMG International"), a Swiss entity.		Finnsnes	Molde
Statsautoriserte revisorer - medlemmer av Den norske Revisorforening	Arendal	Hamar	Skien
	Bergen	Haugesund	Sandefjord
	Bodø	Knarvik	Sandnessjøe

Auditor's Responsibilities for the Audit of the Financial Statements

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 laws, regulations, and auditing standards and practices generally accepted in Norway, including 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 laws, regulations, and auditing standards and practices generally accepted in Norway, including ISAs, we exercise professional judgment and maintain professional skepticism throughout the audit. We also:

fraud or error. We design and perform audit procedures responsive to those risks, and obtain audit detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of

• obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the

• identify and assess the risks of material misstatement of the financial statements, whether due to evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not internal control.
• effectiveness of the Company's or the Group's internal control.
• evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management.
• conclude on the appropriateness of management's use of the going concern basis of accounting up to the date of our auditor's report. However, future events or conditions may cause the Company or the Group to cease to continue as a going concern.
• evaluate the overall presentation, structure and content of the financial statements, including the in a manner that achieves fair presentation.
• obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Group to express an opinion on the consolidated financial We remain solely responsible for our audit opinion.

and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Company's or the Group's ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor's report to the related disclosures in the financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained

disclosures, and whether the financial statements represent the underlying transactions and events

statements. We are responsible for the direction, supervision and performance of the group audit.

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 Board of Directors 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.

evaluating the abandonment provisions, and to determine whether there is sufficient evidence available to support the estimates and judgments made.	• foreign currency, inflation and cost escalation assumptions with reference to market and industry data. For non-operated licences where the Company uses the operator company estimates, we assessed the amounts against reports from the operator company.
	In addition, we assessed the assumed economic cut-off date with reference to licence forecasts, including an assessment of the consistency with the forecasts and assumptions used in impairment testing and other audit work.
	We assessed the mathematical accuracy of management's discounting model to confirm the year-end present values of decommissioning cost estimates and accretion recognised during the year, and the discount rate applied with reference to industry practice along with market and Company data.

Other information

Management is responsible for the other information. The other information comprises information included 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 other information and we do not express any form of assurance conclusion thereon.

In connection with our audit of the financial statements, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the financial statements or our knowledge obtained in the audit or otherwise appears to be materially misstated.

If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard.

Responsibilities of the Board of Directors and the Chief Executive Officer for the Financial Statements

The Board of Directors and the Chief Executive Officer (Management) are responsible for the preparation and fair presentation of the financial statements 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. The financial statements of the Company use the going concern basis of accounting insofar as it is not likely that the enterprise will cease operations. The financial statements of the Group use 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.

Report on Other Legal and Regulatory Requirements

Opinion on the Board of Directors' report

Based on our audit of the financial statements as described above, it is our opinion that the information presented in the Board of Directors' report including the statements on Corporate Governance and Corporate Social Responsibility concerning the financial statements, the going concern assumption, and the proposal for the allocation of the profit is consistent with the financial statements and complies with the law and regulations.

Opinion on Registration and Documentation

Based on our audit of the financial statements as described above, and control procedures we have considered necessary in accordance with the International Standard on Assurance Engagements (ISAE) 3000, Assurance Engagements Other than Audits or Reviews of Historical Financial Information, it is our opinion that management has fulfilled its duty to produce a proper and clearly set out registration and documentation of the Company's accounting information in accordance with the law and bookkeeping standards and practices generally accepted in Norway.

Oslo, 19 March 2020 KPMG AS

Mona Irene Larsen State Authorised Public Accountant

CONTACT

Please contact VP Communications, Tore Langballe if you have any questions.

tore.langballe@akerbp.com Tel: +47 907 77 841

Photo credits per page:

Anne Lise Norheim: 1, 3, 4, 14, 22, 25, 30, 33, 52, 54, 59, 60, 63, 64, 67, 69, 70, 73, 74, 76, 77, 79, 80

Elisabeth Tønnesen: 4, 8, 45, 46, 47, 48

Woldcam: 5, 7, 15, 17, 18, 19, 21, 25, 26, 27, 29, 31, 33, 43, 44, 51, 57, 68

Equinor: 7, 34, 37

Stuart Conway: 21

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