Aker BP

Quarterly Report • May 6, 2020

Q UA RT E R LY R E P O RT Q 1 2 0 2 0

FIRST QUARTER 2020 SUMMARY

The first quarter of 2020 was an extraordinary quarter. Aker BP delivered strong operational performance and set a new production record. This was however overshadowed by the COVID-19 pandemic and the sharp drop in global oil prices. The company's key priorities in this challenging situation are to safeguard its people, its production and its financial capacity.

Responding to COVID-19

Aker BP early on established a dedicated team to handle the company's operational response to the COVID-19 pandemic. In close cooperation with employees, suppliers and authorities, this team has implemented measures to minimize the risk of infection and business interruption both onshore and offshore. This includes a wide range of practical measures like reduced offshore manning, physical distancing, travel restrictions and working from home. Supported by these measures, the company has maintained its production at full capacity.

First quarter results

In the first quarter, Aker BP's net production was 208.1 (191.1) thousand barrels of oil equivalents per day (mboepd), and net sold volume was 207.5 (184.5) mboepd. These volumes represent a new all-time high for Aker BP, reflecting the continued ramp-up of production from the Johan Sverdrup field. Petroleum revenues did however decline by approximately 20 percent due to significantly lower realized oil and gas prices. This decline was partly mitigated by gains from the company's oil price hedging program. Total income for the first quarter amounted to USD 872 (1,003) million.

Production costs for the oil and gas sold in the quarter amounted to USD 156 (154) million. Per produced boe, production cost was reduced to USD 8.7 (9.1). Exploration expenses amounted to USD 50 (85) million and included costs of the Nidhogg well which was concluded as a non-commercial gas discovery. Depreciation

amounted to USD 277 (255) million, equivalent to USD 14.6 (14.5) per boe. Impairments amounted to USD 654 (0) million and were mainly caused by the sharp reduction in oil prices and the corresponding effect on investment plans and asset valuations.

Net financial expenses were USD 149 (67) million in the quarter, negatively impacted by the weaker NOK versus USD. Loss before taxes amounted to USD 414 million, compared to a profit of USD 424 million in the fourth quarter 2019. Tax income was USD 80 million, compared to a tax expense of USD 312 million in the previous quarter. The low effective tax rate for the first quarter mainly reflects the limited deductibility towards the special petroleum tax for financial items and impairments, as well as the currency-driven revaluation of the company's tax balances. Overall, the company reported a net loss of USD 335 million for the quarter, compared to a net profit of USD 112 million in the previous quarter.

Investments in fixed assets amounted to USD 343 (490) million in the quarter, driven by field development activities across the company's portfolio. First oil from Skogul was achieved during the quarter. Skogul is the subsea production well number 36 in the Alvheim area and has been delivered safely, efficiently and on schedule.

Updated investment program

In order to secure its financial optionality in response to the uncertainty caused by the COVID-19 situation and the sharp reduction in oil prices, Aker BP has made significant changes to its investment program which was presented at the company's Capital Markets Update in February 2020. All non-sanctioned field development projects are put on hold, and several exploration wells are postponed. For 2020, this represents a 20 percent reduction in capital spend compared to previous guidance, with potential for further reductions in coming years. Production costs are also expected to be reduced by around 20 percent from previous guidance, as all non-critical activities are being postponed and the weaker NOK favourably impacts the cost level. The production guidance for 2020 remains unchanged at 205-220 mboepd. The longer-term production outlook will obviously be impacted by the company's investment level.

Liquidity and financial position

Maintaining a strong financial position is a key strategic priority for Aker BP, and the company is continuously managing its capital structure and exposures to enhance flexibility and reduce cost and risk. During the first quarter, the company strengthened its liquidity by issuing USD 1.5 billion in new long-dated bonds at attractive terms. Furthermore, the maturity for USD 2 billion of the company's bank facility (RCF) was in April extended by one year from 2024 to 2025. The company's oil price hedging program has also been expanded. At the end of the first quarter Aker BP had USD 4.0 billion in available liquidity, with no significant debt maturities until 2022.

Dividends

Aker BP's ambition is to return a significant part of its value creation to shareholders through attractive cash dividends. However, given the weak oil market and the high uncertainty in the global economy, the Board has decided to retract the current dividend plan in order to retain financial flexibility and position the company for future value accretive organic and inorganic growth opportunities.

The Board has decided to pay USD 70.8 million (USD 0.1967 per share) in dividends in May 2020, representing one third of the previously guided amount. It is the Board's ambition to maintain this level for the remaining quarters of 2020, implying total dividend payments of USD 425 million for the full year. Each quarterly dividend decision will however be subject to a holistic assessment of all relevant factors, including oil prices, the COVID-19 situation and the company's financial position.

The company will revert with a new long-term dividend policy when market conditions allow.

Forward-looking statements in this report reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future and may not be within our control. All figures are presented in USD unless otherwise stated, and figures in brackets apply to the previous quarter.

Summary of financial results

	UNIT	Q1 2020	Q4 2019	Q1 2019
Total income	USDm	872	1 003	836
EBITDA	USDm	666	745	539
Net profit/loss	USDm	-335	112	10
Earnings per share (EPS)	USD	-0.93	0.31	0.03
Capex	USDm	360	506	343
Exploration spend	USDm	53	79	159
Abandonment spend	USDm	22	10	21
Production cost	USD/boe	8.7	9.1	13.4
Taxes paid	USDm	48	199	106
Net interest-bearing debt*	USDm	3 548	3 493	2 480
Leverage ratio		1.2	1.2	0.7

*The definition of net interest-bearing debt includes Lease debt. See also the description of "Alternative performance measures" at the end of this report for definitions.

Summary of production

	UNIT	Q1 2020	Q4 2019	Q1 2019
Alvheim area	mboepd	57.5	56.4	56.8
Ivar Aasen	mboepd	22.7	23.1	22.5
Johan Sverdrup	mboepd	43.9	31.5	-
Skarv	mboepd	19.8	22.1	22.6
Ula area	mboepd	12.8	11.1	8.2
Valhall area	mboepd	50.1	45.4	45.8
Other	mboepd	1.4	1.4	2.7
Net production	mboepd	208.1	191.1	158.7
Over/underlift	mboepd	-0.6	-6.6	3.3
Net sold volume	mboepd	207.5	184.5	162.0
- liquids	mboepd	174.3	151.4	128.8
- natural gas	mboepd	33.2	33.1	33.2
Realized price liquids	USD/boe	44.7	64.2	63.9
Realized price natural gas	USD/scm	0.14	0.17	0.24

FINANCIAL REVIEW

Income statement

(USD MILLION)	Q1 2020	Q4 2019	Q1 2019
Total income	872	1 003	836
EBITDA	666	745	539
EBIT	-266	491	287
Pre-tax profit	-414	424	249
Net profit/loss	-335	112	10
EPS (USD)	-0.93	0.31	0.03

Total income in the first quarter 2020 amounted to USD 872 (1,003) million. The decrease compared to the previous quarter is due to the sharp decrease in realized prices. Realized prices declined by 30 percent for liquids and 17 percent for natural gas. The price effect on total income was partly offset by a significant increase in sold volumes to 207.5 (184.5) mboepd, reflecting the continued ramp-up of production from the Johan Sverdrup field. Gains from the company's oil price hedging program amounted to USD 83 million and are recognized under other operating income.

Production costs related to oil and gas sold in the quarter amounted to USD 156 (154) million. Production cost per produced unit in the quarter amounted to USD 8.7 (9.1) per boe, reflecting the strong overall production numbers and positive contribution of low-cost barrels from Johan Sverdrup.

Exploration expenses amounted to USD 50 (85) million and included costs for the Nidhogg well, which was drilled and concluded as a non-commercial gas discovery during the quarter.

Depreciation amounted to USD 277 (255) million. The increase was driven by higher production volume, as the depreciation per produced boe was stable at USD 14.6 (14.5).

Impairments amounted to USD 654 (0) million and were mainly caused by the sharp reduction in oil prices and the corresponding effect on investment plans, production profiles and asset valuations. The impairments are related to both the producing fields Ula, Tambar and Ivar Aasen, as well as several exploration assets. Reference is made to note 5 and 6 in the financial statements for further details.

Operating loss was USD 266 million compared to an operating profit of USD 491 in the previous quarter.

Net financial expenses amounted to USD 149 (67) million. The increase from the previous quarter mainly reflects a net loss on currency positions and derivatives.

Loss before taxes amounted to USD 414 million, compared to a profit before taxes of USD 424 million in the fourth quarter. Tax income was USD 80 million, representing an effective tax rate of 19 percent. This compares to a tax expense of USD 312 million with the associated effective tax rate of 74 percent in the previous quarter. The low effective tax rate for the first quarter is mainly caused by currency changes with negative net tax impact, and the permanent differences relating to the impairment of goodwill and intangible assets.

This resulted in a net loss for the first quarter 2020 of USD 335 million, compared to a net profit of USD 112 million in the previous quarter.

Statement of financial position

(USD MILLION)	Q1 2020	Q4 2019	Q1 2019
Total non-current assets	10 913	11 508	10 498
Total current assets	814	719	619
Total assets	11 727	12 227	11 117
Total equity	1 813	2 368	2 799
Bank and bond debt	3 593	3 287	2 226
Total abandonment provisions	2 795	2 788	2 561
Deferred taxes	2 153	2 235	1 867
Other liabilities	1 372	1 549	1 664
Total equity and liabilities	11 727	12 227	11 117
Net interest-bearing debt	3 548	3 493	2 480

At the end of first quarter 2020, total assets amounted to USD 11,727 (12,227) million, of which current assets were USD 814 (719) million.

Equity amounted to USD 1,813 (2,368) million at the end of the quarter, corresponding to an equity ratio of 15 (19) percent.

Deferred tax liabilities amounted to USD 2,153 (2,235) million and are detailed in note 9 to the financial statements.

Bank and bond debt totalled USD 3,593 (3,287) million, of which bonds made up 92 percent.

At the end of the first quarter, the company had total available liquidity of USD 4.0 (2.7) billion, comprising USD 323 (107) million in cash and cash equivalents, and USD 3.7 (2.55) billion in undrawn credit facilities.

Cash flow

(USD MILLION)	Q1 2020	Q4 2019	Q1 2019
Cash flow from operations	524	525	591
Cash flow from investments	-395	-541	-511
Cash flow from financing	86	117	-9
Net change in cash & cash equivalents	215	101	71
Cash and cash equivalents	323	107	114

Net cash flow from operating activities was USD 524 (525) million in the quarter. Total income amounted to USD 872 million, down from USD 1,003 million in the fourth quarter mainly due to lower realized oil and gas prices. Taxes paid were USD 48 (199) million.

Net cash used for investment activities was USD 395 (541) million, of which investments in fixed assets amounted to USD 343 (490) million for the quarter. Investments in capitalized exploration were USD 31 (42) million, and payments for decommissioning activities amounted to USD 21 (9) million in the quarter.

Net cash flow from financing activities totalled USD 86 (117) million, of which USD 1,487 million came from the issue of new bonds. This was offset by a repayment of revolving credit facility of USD 1,150 million, dividend disbursements of USD 213 (188) million, payments related to lease debt of USD 32 (30) million and purchase of treasury shares of USD 7 (0) million for use in the company's share saving plan.

Risk management

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.

Since the previous quarterly report, Aker BP has added new put options for the second half of 2020. The following table shows the company's inventory of oil put options at the time of this report:

OIL PUT OPTIONS	Q2 2020	Q3 2020	Q4 2020
Share of oil prod. covered (after tax)	55 %	50 %	46 %
Average strike (USD/bbl)	54	26	26
Average premium (USD/bbl)	1.3	1.9	2.0

Dividends

On 24 February 2020, the company disbursed dividends of USD 212.5 million, equivalent to USD 0.5901 per share.

At the Annual General Meeting in April 2020, the Board was authorized to approve the distribution of dividends based on the company's annual accounts for 2019 pursuant to section 8-2 (2) of the Norwegian Public Limited Companies Act.

Aker BP's ambition is to return a significant part of its value creation to shareholders through attractive cash dividends. However, given the weak oil market and the high uncertainty in the global economy, the Board has decided to retract the current dividend plan in order to retain financial flexibility and position the company for future value accretive organic and inorganic growth opportunities.

The Board has decided to pay USD 70.8 million (USD 0.1967 per share) in dividends in May 2020, representing one third of the previously guided amount. The dividend will be disbursed on or around 22 May 2020. It is the Board's ambition to maintain this level for the remaining quarters of 2020, implying total dividend payments of USD 425 million for the full year. Each quarterly dividend decision will however be subject to a holistic assessment of all relevant factors, including oil prices, the COVID-19 situation and the company's financial position.

The company will revert with a new long-term dividend policy when market conditions allow.

OPER ATIONAL RE VIE W

Aker BP's net production was 18.9 (17.6) mmboe in the first quarter of 2020, corresponding to 208.1 (191.1) mboepd. This represents a new all-time high for Aker BP, driven by continued ramp-up at Johan Sverdrup and Valhall, as well as a record high production efficiency of 96 percent for the operated assets. Net sold volume was 207.5 (184.5) mboepd. The average realized liquids price was USD 44.7 (64.2) per barrel, while the average realized gas price was USD 0.14 (0.17) per scm.

Alvheim Area

Key figures	Aker BP interest	Q1 2020	Q4 2019	Q3 2019	Q2 2019	Q1 2019
Production, boepd
Alvheim	65 %	36 995	36 588	36 826	39 943	43 478
Bøyla	65 %	7 631	7 534	4 490	2 364	1 829
Skogul	65 %	1 622	-	-	-	-
Vilje	46.904 %	3 472	3 279	-	2 300	3 756
Volund	65 %	7 774	9 040	10 088	8 518	7 757
Total production		57 494	56 441	51 403	53 125	56 820
Production efficiency		98 %	98 %	96 %	97 %	97 %

First quarter production from the Alvheim area was 57.5 mboepd net to Aker BP, up two percent from the previous quarter. The high and stable production was enabled by optimal use of the gas handling facilities, deferred water breakthrough in several of the fields and continued high production efficiency at 98 percent.

Production from Skogul commenced in March. The Subsea alliance and the Semi drilling alliance have worked with Aker BP to deliver Skogul safely, efficiently and on schedule. Skogul is the subsea production well number 36 in the Alvheim area. The well is producing according to expectations.

Preparations for the drilling of Kameleon Infill Mid were completed during the quarter. Drilling started late in March with the Semi-submersible rig Deepsea Nordkapp, and first oil is expected during the fourth quarter.

Test production at Frosk continued through the Bøyla template. An application to prolong the test production period to August 2020 has been approved by the authorities.

Ivar Aasen

Key figures	Aker BP interest	Q1 2020	Q4 2019	Q3 2019	Q2 2019	Q1 2019
Production, boepd
Total production	34.7862 %	22 705	23 139	22 481	19 069	22 539
Production efficiency		97 %	97 %	94 %	87 %	98 %

First quarter production from Ivar Aasen was 22.7 mboepd net to Aker BP, down two percent from the previous quarter.

The production efficiency was high and continued at 97 percent, although it was negatively affected by a switch of the Ivar Aasen export pipelines and following a pigging operation. Production efficiency was also slightly negatively affected by gas export restrictions and unplanned shutdowns on Edvard Grieg due to loss of power.

Johan Sverdrup

Key figures	Aker BP interest	Q1 2020	Q4 2019	Q3 2019	Q2 2019	Q1 2019
Production, boepd
Total production	11.5733 %	43 877	31 521	-	-	-
Production efficiency		92 %	99 %	-	-	-

The production from Johan Sverdrup continued safely through the first quarter and increased gradually towards the original Phase 1 process plant design capacity of 440 mboepd gross. The average daily production net to Aker BP amounted to 43.9 mboepd in the quarter.

Based on the experience during the first half year of operations and through debottlenecking measures, the actual plant capacity for Phase 1 has been increased up to around 470 mboepd gross or 54 mboepd net to Aker BP.

Drilling of the first new production well from the fixed rig drilling platform (production well number nine) started early in January 2020 and was successfully completed and put on stream during the quarter. The tenth Johan Sverdrup well was completed during the quarter and came on stream in April. The field reached its new plateau production for the first phase in late April.

With low operating costs, below USD 2 per barrel, Johan Sverdrup provides important revenue and cashflow to the participating companies and the Norwegian society at large.

Phase 2 of the Johan Sverdrup development progresses according to plan.

Skarv Area

Key figures	Aker BP interest	Q1 2020	Q4 2019	Q3 2019	Q2 2019	Q1 2019
Production, boepd
Total production	23.835 %	19 788	22 119	21 717	22 657	22 558
Production efficiency		99 %	100 %	98 %	98 %	91 %

First quarter production from the Skarv area was 19.8 mboepd net to Aker BP, down 11 percent from the previous quarter. The reduction is mainly due to high gas export during the previous quarter following a reservoir behavior test. Skarv continues to show stable decline according to prognosis and the last quarter has been characterized by high production efficiency. A planned turnaround in April 2020 has been postponed to 2021 due to COVID-19.

Phase 1 of the Ærfugl development project maintained good progress during the quarter. All three production wells have been successfully completed. Fabrication of the electrical heat traced flowline and pipeline structures are on schedule for the start of the installation campaign. Due to COVID-19, some offshore activities have been rescheduled, and the risk of delayed deliveries has increased. Pipelaying is scheduled for late summer 2020, and production startup is planned for the fourth quarter 2020.

Phase 2 of the Ærfugl development project is progressing according to plan. The first well came on stream in April 2020, three years ahead of the original plan. For the two remaining satellite wells, production start is expected in the fourth quarter 2021.

Ula Area

Key figures	Aker BP interest	Q1 2020	Q4 2019	Q3 2019	Q2 2019	Q1 2019
Production, boepd
Ula	80 %	5 512	4 339	4 751	2 811	6 185
Tambar	55 %	3 642	3 054	2 531	1 455	1 916
Oda	15 %	3 623	3 713	1 280	1 949	102
Total production		12 777	11 106	8 562	6 214	8 203
Production efficiency*		88 %	78 %	76 %	46 %	75 %

*Oda not included.

First quarter production from the Ula area was 12.8 mboepd net to Aker BP, up 15 percent from the previous quarter. Production from the Ula and Tambar fields increased due to higher production efficiency and successful intervention activities at Tambar at the end of the fourth quarter and early in the first quarter. Production from Oda was stable compared to the previous quarter. However, the infill drilling program has recently been reduced from six to four wells. The rig will continue to drill at Ula until the third quarter 2020.

The company is continuing to mature the opportunity set in the Ula area, which is a complex process involving a broad set of technical and commercial disciplines.

The Maersk Integrator drilling rig has been in operation at Ula since mid-July 2019 and has now completed the second well.

Valhall Area

Key figures	Aker BP interest	Q1 2020	Q4 2019	Q3 2019	Q2 2019	Q1 2019
Production, boepd
Valhall	90 %	49 093	44 205	39 403	23 896	45 156
Hod	90 %	982	1 176	880	618	677
Total production		50 075	45 381	40 283	24 514	45 833
Production efficiency		88 %	90 %	87 %	53 %	94 %

First quarter production from the Valhall area was 50.1 mboepd net to Aker BP. This was 11 percent higher than the previous quarter driven by three additional wells brought on stream. At the end of March, Valhall noted a 500 consecutive-day streak of zero unplanned shutdowns.

At Flank West, drilling by the Maersk Invincible rig continued. At the end of the quarter seven wells were drilled and completed with a further two wells remaining in the Flank West campaign.

Drilling, slot recovery and well intervention work were performed at the field centre. Stimulation operations are ongoing, and wells are successively brought onstream as they are stimulated.

In response to COVID-19, extensive measures have been implemented at Valhall to ensure safe and reliable operations. This includes a significant reduction in non-critical activities in order to limit personnel travelling to the installations as well as reducing near-term spend. Valhall has significant flexibility in its project portfolio and numerous projects have been put on hold in order to protect near-team cash flows, including the Hod Field Development project.

North of Alvheim and Krafla-Askja (NOAKA)

The North of Alvheim and Krafla-Askja ("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.

Aker BP and the other partners have performed detailed studies of different development solutions for the NOAKA area. The premise has been that a development should capture all discovered resources in the area and facilitate future tie-ins of new discoveries. The partners in the NOAKA area are currently in constructive dialogue on how to develop the area.

E XPLOR ATION

Total exploration spend in the first quarter was USD 53 (79) million, while USD 50 million was recognized as exploration expenses in the period, relating to dry well costs, seismic, area fees, field evaluation and G&G costs.

Drilling of the Nidhogg prospect in the Skarv area started in January and was concluded as a non-commercial gas discovery during the quarter.

As announced on 23 March, the company has updated its investment program. This will also affect exploration spending, which is now estimated to be reduced by approximately 30 percent in 2020 compared to the original plan.

Aker BP's original exploration plan for 2020 consisted of 10 exploration wells. In cooperation with its partners, Aker BP has resolved to postpone four of these wells. Together with other cost reduction measures, the company now forecasts exploration spend of approximately USD 350 million for the year.

BUSINESS DEVELOPMENT

In February, Aker BP entered into an agreement with PGNiG Upstream Norway AS to swap its 3.3 percent interest in the non-operated Gina Krog field and an 11.9175 percent interest in license 127C, in exchange for a 5 percent interest and operatorship in license 838 and a cash consideration of up to USD 62 million.

License 838 is located near Skarv and contains the recent Shrek discovery as well as further exploration potential. License 127C contains the Alve Nord discovery and the Alve NE prospect, which is also located in the Skarv area. After the transaction, Aker BP holds 35 percent interest in license 838 and 88.0825 percent interest in license 127C, while it has fully divested its interest in the Gina Krog field.

The cash consideration consists of a firm payment of USD 51 million upon closing and an additional payment of USD 11 million contingent on a development of the Alve Nord discovery. The transaction was completed on 30 April 2020.

HE ALTH, SAFET Y, SECURIT Y AND THE 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.

KEY HSSE INDICATORS	UNIT	Q1 2020	Q4 2019	Q3 2019	Q2 2019	Q1 2019
Total recordable injury frequency (TRIF)	Per mill. exp. hours	0.4	2.0	2.7	4.0	3.1
Serious incident frequency (SIF)	Per mill. exp. hours	0	0.8	0.4	0.8	0.4
Loss of primary containment (LOPC)	Count	0	0	0	0	0
Process safety events Tier 1 and 2	Count	0	0	0	0	0
CO2 emissions intensity*	Kg CO2/boe	4.8	7.9	8.1	8.1	7.6

* From Q1 2020 Aker BP reports equity-based CO2-intensity. This includes equity share (financial ownership interest) of non-operated and operated assets based on scope 1 emissions. The figures for previous periods are not restated and only apply for operated assets (gross).

Both the serious incident frequency (SIF) and the total recordable injuries frequency (TRIF) were significantly improved in the first quarter 2020 compared to the fourth quarter 2019. In a period with challenges related to the COVID-19 outbreak, the importance of a robust and reliable HSSE performance is demonstrated. In January, the company established emergency response plans and mitigating measures to safeguard personnel and contribute to the social responsibility to curtail the spread of contagion and at the same time maintain our business activities with no impact on safety nor reliability.

The mitigating measures are continuously updated and strengthened by a COVID-19 project organization ensuring aligned and coordinated actions across the company, in accordance with the guidelines from the national health authorities in Norway.

OUTLOOK

The COVID-19 crisis and the sharp drop in oil prices have created an extremely challenging situation for the oil industry. Under these challenging circumstances, Aker BP's main financial priority is to secure the company's financial robustness, to protect its investment grade credit profile, and to secure future financial capacity to pursue value-accretive growth opportunities going forward.

The company has consequently decided to reduce its capital spending program for 2020, and the updated financial plan consists of the following main items*:

• Production of 205-220 mboepd (unchanged)
• Capex of USD ~1.2 billion (previously USD ~1.5 billion)
• Exploration spend of USD ~350 million (prev. USD ~500 million)
• Production cost of USD 7-8 per boe (prev. USD ~10 per boe)
• Abandonment spend of USD ~0.2 billion (unchanged)
• Dividends of USD 425 million (prev. USD 850 million)

Aker BP has also launched a process to adapt its organization to a reduced activity level. The first steps have already been taken, and the new organization will be implemented from fourth quarter 2020. In parallel, the company is maintaining momentum within its improvement program.

The Norwegian government on 29 April 2020 announced a decision to reduce the country's total oil production from June to December 2020, in order to contribute to a faster stabilization of the global oil market. At the time of this report, the field-specific reductions have not yet been decided, and it is therefore too early to conclude how this will affect Aker BP's production. Based on a preliminary assessment, the company still estimates its full-year production to be within the previously announced guidance range of 205-220 mboepd.

* The majority of the company's cost elements (both capex and production cost) are denominated in NOK. The estimated USD amounts are based on an USDNOK exchange rate of 10.0.

The Norwegian government on 30 April 2020 announced a proposal for a package of measures to support the oil and gas industry and the supply industry. The proposal includes temporary amendments to the Norwegian petroleum taxation which are intended to stimulate investments in the sector. The government will submit these proposals in the form of a bill to the Storting on 12 May.

Aker BP shares the view of the Norwegian Oil and Gas Association and finds it positive that the government is proposing measures to support the petroleum sector. However, the initial proposal has important weaknesses which are likely to limit the impact on future investment levels. For Aker BP, this proposal would only lead to marginal changes in the company's investment plans.

FINANCIAL STATEMENTS WITH NOTES

INCOME STATEMENT

	Group
		Q1	Q4	Q1	01.01.-31.03.
(USD 1 000)	Note	2020	2019	2019	2020	2019
Petroleum revenues		779 084	979 561	858 105	779 084	858 105
Other operating income		93 021	23 112	-21 843	93 021	-21 843
Total income	2	872 105	1 002 673	836 262	872 105	836 262
Production costs	3	156 043	154 272	200 462	156 043	200 462
Exploration expenses	4	50 336	84 683	90 359	50 336	90 359
Depreciation	6	277 412	255 015	183 102	277 412	183 102
Impairments	5, 6	653 697	-509	68 941	653 697	68 941
Other operating expenses		223	18 550	6 859	223	6 859
Total operating expenses		1 137 711	512 011	549 724	1 137 711	549 724
Operating profit		-265 606	490 661	286 538	-265 606	286 538
Interest income		1 369	338	6 064	1 369	6 064
Other financial income		108 709	51 341	9 719	108 709	9 719
Interest expenses		40 041	37 762	13 830	40 041	13 830
Other financial expenses		218 729	80 580	39 335	218 729	39 335
Net financial items	8	-148 691	-66 663	-37 381	-148 691	-37 381
Profit before taxes		-414 298	423 998	249 157	-414 298	249 157
Taxes (+)/tax income (-)	9	-79 564	312 448	238 731	-79 564	238 731
Net profit/loss		-334 734	111 550	10 425	-334 734	10 425
Weighted average no. of shares outstanding basic and diluted		359 984 388	360 113 509	360 113 509	359 984 388	360 113 509
Basic and diluted earnings/loss USD per share		-0.93	0.31	0.03	-0.93	0.03

STATEMENT OF COMPREHENSIVE INCOME

		Group
	Q1	Q4	Q1	01.01.-31.03.
(USD 1 000) Note	2020	2019	2019	2020	2019
Profit/loss for the period	-334 734	111 550	10 425	-334 734	10 425
Items which will not be reclassified over profit and loss (net of taxes) Actuarial gain/loss pension plan	-	-4	-	-	-
Total comprehensive income in period	-334 734	111 546	10 425	-334 734	10 425

STATEMENT OF FINANCIAL POSITION

(USD 1 000)	Note	31.03.2020	31.03.2019	31.12.2019
ASSETS
Intangible assets
Goodwill	6	1 647 436	1 791 185	1 712 809
Capitalized exploration expenditures	6	478 761	496 094	621 315
Other intangible assets	6	1 522 389	1 986 986	1 915 968
Tangible fixed assets
Property, plant and equipment	6	7 060 700	5 953 972	7 023 276
Right-of-use assets	6	170 834	225 244	194 328
Financial assets
Long-term receivables		23 400	34 002	27 418
Other non-current assets		9 869	10 392	10 364
Long-term derivatives	12	-	-	2 706
Total non-current assets		10 913 389	10 497 874	11 508 183
Inventories Inventories		97 337	98 910	87 539
Receivables
Accounts receivable		19 529	45 271	193 444
Tax receivables	9	-	15 473	-
Other short-term receivables	10	307 635	345 374	330 516
Short-term derivatives	12	66 611	-	-
Cash and cash equivalents
Cash and cash equivalents	11	322 789	113 680	107 104
Total current assets		813 902	618 708	718 603
TOTAL ASSETS		11 727 291	11 116 582	12 226 786

STATEMENT OF FINANCIAL POSITION

(USD 1 000)	Note	31.03.2020	31.03.2019	31.12.2019
EQUITY AND LIABILITIES
Equity
Share capital		57 056	57 056	57 056
Share premium		3 637 297	3 637 297	3 637 297
Other equity		-1 881 123	-894 888	-1 326 767
Total equity		1 813 229	2 799 464	2 367 585
Non-current liabilities
Deferred taxes	9	2 153 376	1 867 333	2 235 357
Long-term abandonment provision	16	2 642 264	2 475 388	2 645 420
Long-term bonds	14	3 120 062	1 113 285	1 630 936
Long-term derivatives	12	56 982	27 945	-
Long-term lease debt	7	179 501	275 818	202 592
Other interest-bearing debt	15	280 784	1 112 304	1 429 132
Current liabilities
Trade creditors		117 681	112 033	144 942
Short-term bonds	14	192 541	-	226 700
Accrued public charges and indirect taxes		15 482	17 254	25 974
Tax payable	9	260 081	566 755	361 157
Short-term derivatives	12	153 527	10 354	42 994
Short-term abandonment provision	16	153 043	85 212	142 798
Short-term lease debt	7	97 855	92 735	110 664
Other current liabilities	13	490 884	560 700	660 535
Total liabilities		9 914 063	8 317 118	9 859 201
TOTAL EQUITY AND LIABILITIES		11 727 291	11 116 582	12 226 786

STATEMENT OF CHANGES IN EQUITY - GROUP

				Other equity
			Other comprehensive income
					Foreign currency
		Share	Other paid-in	Actuarial	translation	Retained	Total other
(USD 1 000)	Share capital	premium	capital	gains/(losses)	reserves1)	earnings	equity	Total equity
Equity as of 31.12.2018	57 056	3 637 297	573 083	-81	-115 491	-1 175 324	-717 814	2 976 539
Dividends distributed	-	-	-	-	-	-750 000	-750 000	-750 000
Profit/loss for the period	-	-	-	-	-	141 051	141 051	141 051
Other comprehensive income for the period	-	-	-	-4	-	-	-4	-4
Equity as of 31.12.2019	57 056	3 637 297	573 083	-85	-115 491	-1 784 274	-1 326 767	2 367 585
Dividend distributed	-	-	-	-	-	-212 500	-212 500	-212 500
Profit/loss for the period	-	-	-	-	-	-334 734	-334 734	-334 734
Purchase of treasury shares2)	-	-	-	-	-	-7 122	-7 122	-7 122
Equity as of 31.03.2020	57 056	3 637 297	573 083	-85	-115 491	-2 338 630	-1 881 123	1 813 229

1) The amount arose mainly as a result of the change in functional currency in Q4 2014.

2) The treasury shares are purchased for use in the company's share saving plan.

STATEMENT OF CASH FLOW

Group
		Q1	Q4	Q1		01.01.-31.03.
(USD 1 000)	Note	2020	2019	2019	2020	2019
CASH FLOW FROM OPERATING ACTIVITIES
Profit before taxes		-414 298	423 998	249 157	-414 298	249 157
Taxes paid	9	-48 150	-198 663	-105 930	-48 150	-105 930
Depreciation	6	277 412	255 015	183 102	277 412	183 102
Net impairment losses	5, 6	653 697	-509	68 941	653 697	68 941
Accretion expenses	8, 16	29 265	31 210	29 584	29 265	29 584
Interest expenses (including interest element of lease payments)	8	47 905	48 011	49 150	47 905	49 150
Interest paid (including interest element of lease payments)		-55 954	-41 908	-45 843	-55 954	-45 843
Changes in derivatives	2, 8	103 609	-46 474	20 495	103 609	20 495
Amortized loan costs	8	5 036	4 463	6 676	5 036	6 676
Expensed capitalized dry wells	4, 6	28 982	47 277	58 074	28 982	58 074
Changes in inventories, accounts payable and receivables		136 856	-51 019	118 262	136 856	118 262
Changes in other current balance sheet items		-240 662	54 061	-41 108	-240 662	-41 108
NET CASH FLOW FROM OPERATING ACTIVITIES		523 698	525 463	590 560	523 698	590 560
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields		-20 929	-9 295	-20 762	-20 929	-20 762
Disbursements on investments in fixed assets		-342 508	-490 457	-363 982	-342 508	-363 982
Disbursements on investments in capitalized exploration		-31 253	-41 597	-126 334	-31 253	-126 334
Disbursements on investments in licenses		-	-	-143	-	-143
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-394 691	-541 348	-511 222	-394 691	-511 222
CASH FLOW FROM FINANCING ACTIVITIES
Net drawdown/repayment of short-term debt		-	-15 000	-	-	-
Net drawdown/repayment of revolving credit facility		-1 150 000	350 000	-	-1 150 000	-
Net drawdown/repayment of reserve-based lending facility		-	-	200 000	-	200 000
Net proceeds from bond issue		1 487 406	-	-	1 487 406	-
Payments on lease debt related to investments in fixed assets		-26 606	-25 278	-16 283	-26 606	-16 283
Payments on other lease debt		-5 183	-5 156	-5 018	-5 183	-5 018
Paid dividend		-212 500	-187 500	-187 500	-212 500	-187 500
Net purchase/sale of treasury shares		-7 122	-	-	-7 122	-
NET CASH FLOW FROM FINANCING ACTIVITIES		85 995	117 065	-8 802	85 995	-8 802
Net change in cash and cash equivalents		215 002	101 180	70 537	215 002	70 537
Cash and cash equivalents at start of period		107 104	5 066	44 944	107 104	44 944
Effect of exchange rate fluctuation on cash held		682	859	-1 801	682	-1 801
CASH AND CASH EQUIVALENTS AT END OF PERIOD	11	322 789	107 104	113 680	322 789	113 680

NOTES

(All figures in USD 1 000 unless otherwise stated)

These condensed consolidated interim financial statements ("interim financial statements") have been prepared in accordance with the International Financial Reporting Standards as adopted by the EU ("IFRS") IAS 34 "Interim Financial Reporting", thus the interim financial statements do not include all information required by IFRS and should be read in conjunction with the group's annual financial statements as at 31 December 2019. The interim financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair statement of the financial position, results of operations and cash flows for the dates and interim periods presented. Interim period results are not necessarily indicative of results of operations or cash flows for an annual period. These interim financial statements have not been subject to review or audit by independent auditors.

These interim financial statements were authorised for issue by the company's Board of Directors on 5 May 2020.

Note 1 Accounting principles

The accounting principles used for this interim report are consistent with the principles used in the group's annual financial statements as at 31 December 2019.

In preparing these interim financial statements, management has made judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, income and expense. Actual results may differ from these estimates.

The significant judgements made by management in applying the group's accounting policies and the key sources of estimation uncertainty are in all material respect the same as those that applied to the annual financial statements as at 31 December 2019.

Note 2 Income

	Group
	Q1	Q4	Q1	01.01.-31.03.
Breakdown of petroleum revenues (USD 1 000)	2020	2019	2019	2020	2019
Sales of liquids	708 927	894 926	740 780	708 927	740 780
Sales of gas	66 187	80 047	113 927	66 187	113 927
Tariff income	3 971	4 588	3 397	3 971	3 397
Total petroleum revenues	779 084	979 561	858 105	779 084	858 105
Sales of liquids (boe 1 000)	15 858	13 930	11 594	15 858	11 594
Sales of gas (boe 1 000)	3 026	3 046	2 988	3 026	2 988
Other income (USD 1 000)
Realized gain/loss (-) on oil derivatives	14 483	-2 215	-2 058	14 483	-2 058
Unrealized gain/loss (-) on oil derivatives	68 416	-2 533	-24 123	68 416	-24 123
Other income1)	10 122	27 860	4 338	10 122	4 338
Total other operating income	93 021	23 112	-21 843	93 021	-21 843

1) Includes partner coverage of RoU assets recognized on gross basis in the balance sheet and used in operated activity.

Note 3 Produced volumes and over/underlift adjustment

	Group
	Q1	Q4	Q1	01.01.-31.03.
(USD 1 000)	2020	2019	2019	2020	2019
Total produced volumes (boe 1 000)	18 938	17 578	14 280	18 938	14 280
Production cost per boe produced (USD/boe)	8.7	9.1	13.4	8.7	13.4
Production cost based on produced volumes	165 218	160 293	190 998	165 218	190 998
Adjustment for over/underlift (-)	-9 175	-6 021	9 464	-9 175	9 464
Production cost based on sold volumes	156 043	154 272	200 462	156 043	200 462

Note 4 Exploration expenses

	Group
	Q1	Q4	Q1	01.01.-31.03.
Breakdown of exploration expenses (USD 1 000)	2020	2020	2019	2020	2019
Seismic	2 402	12 644	532	2 402	532
Area fee	3 773	3 578	4 574	3 773	4 574
Field evaluation	6 531	9 723	15 925	6 531	15 925
Dry well expenses1)	28 982	47 277	58 074	28 982	58 074
Other exploration expenses	8 650	11 461	11 254	8 650	11 254
Total exploration expenses	50 336	84 683	90 359	50 336	90 359

1) Dry well expenses in Q1 2020 are mainly related to the Nidhogg well.

Note 5 Impairments

Impairment 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 Q1 2020, two categories of impairment tests have been performed:

• Impairment test of fixed assets and related intangible assets, including technical goodwill

• Impairment test of residual goodwill

Impairment is recognized when the book value of an asset or a cash-generating unit, including associated goodwill, exceeds the recoverable amount. The recoverable amount is the higher of the asset's fair value less cost to sell and value in use. The impairment testing for Q1 has been performed in accordance with the fair value method (level 3 in fair value hierarchy) and based on discounted cash flows. The expected future cash flow is discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money, and the specific risk related to the asset. The discount rate is derived from the weighted average cost of capital (WACC) for a market participant. Cash flows are projected for the estimated lifetime of the fields, which may exceed periods greater than five years.

For producing licenses and licenses in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Below is an overview of the key assumptions applied for impairment testing purposes as of 31 March 2020.

Prices

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 Q2 2020 to the end of Q1 2023. From Q2 2023, the oil and gas prices are based on the company's long-term price assumptions. Long-term oil price assumption is unchanged from year-end 2019.

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

Year	USD/BOE
2020	31.4
2021	39.7
2022	43.1
2023	62.9
From 2024 (in real terms)	65.0

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

Year	GBP/therm
2020	0.23
2021	0.32
2022	0.37
2023	0.53
From 2024 (in real terms)	0.53

Oil and gas reserves

Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable remaining reserves.

Future expenditure

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

Discount rate

The post tax nominal discount rate used is 7.8 percent, consistent with the rate applied at Q4 2019, with the reduction in risk free rate at Q1 2020 offset by increased market risk due to the high volatility in oil and gas prices. Cash flows used in impairment testing have been adjusted to reflect changes to planned future investments made in response to the current market conditions and the associated forecast production profiles.

Currency rates
Year	USD/NOK
2020	10.40
2021	10.40
2022	10.41
From 2023	8.00

The long-term NOK/USD currency rate has been changed from 7.5 in Q4 2019.

Inflation

The long-term inflation rate is assumed to be 2.0 percent.

Impairment testing of assets including technical goodwill

The technical goodwill recognized in previous business combinations is allocated to each CGU for the purpose of impairment testing. Hence, the impairment test of technical goodwill is included in the impairment testing of assets, and the technical goodwill is written down before the asset. The carrying value of the assets is the sum of tangible assets, intangible assets and technical goodwill as of the assessment date.

Below is an overview of the impairment charge and the carrying value per cash generating unit where impairment charges have been recognized in Q1 2020:

Cash-generating unit (USD 1 000)	Ula/Tambar	Ivar Aasen
Net carrying value	835 578	1 096 226
Recoverable amount	602 737	969 485
Impairment charge Q1	232 841	126 741
Allocated as follows:
Technical goodwill	54 202	11 170
Other intangible assets/license rights	178 638	37 111
Tangible fixed assets	-	78 459

In line with the methodology described in the annual report, deferred tax (from the date of acquisitions) reduces the net carrying value prior to the impairment charges. When deferred tax liabilities from the acquisitions decreases as a result of depreciation, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable. In Q1 the technical goodwill for Ula/Tambar and Ivar Aasen has been fully written down. The main reasons for the impairment are the decrease in the short-term oil and gas prices and the corresponding impact on cost and production profiles.

Sensitivity analysis

The table below shows how the impairment of assets and technical goodwill would be affected by changes in the various assumptions, given that the remaining assumptions are constant. The CGU's impacted are Ula/Tambar, Ivar Aasen and Alvheim.

	Change in impairment after
Assumption (USD 1 000)	Change	Increase in assumptions	Decrease in assumptions
Oil and gas price forward period	+/- 50 %	-276 477	453 439
Oil and gas price long-term	+/- 20 %	-338 837	450 943
Production profile (reserves)	+/- 5 %	-138 865	138 865
Discount rate	+/- 1 % point	73 518	-76 367
Currency rate USD/NOK	+/- 1.0 NOK	-126 939	157 551
Inflation	+/- 1 % point	-62 843	61 130

As the illustrative impairment sensitivity assumes no changes to other input factors, a price reduction of 20-50 percent 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.

Exploration assets

The current market situation has increased the uncertainty of the exploration portfolio. As a result, a total impairment charge of USD 294.1 million has been recognized in the quarter. The impairment charge has been allocated between other intangible assets and capitalized exploration expenditures with USD 149.3 million and USD 144.8 million respectively. The impairment charge mainly relates to Gohta and Filicudi, as well as parts of Trell & Trine and King Lear.

Residual goodwill

Residual goodwill is allocated across all CGUs for impairment testing. The combined recoverable amount exceeds the carrying amount by a substantial margin.

Summary of impairment/reversal of impairments

The following impairments/(reversals) have been recorded:

	Q1
(USD 1 000)	2020
Impairment of capitalized exploration expenditures	144 826
Impairment of other intangible assets/license rights	365 040
Impairment of tangible fixed assets	78 459
Impairment of goodwill	65 373
Total impairments	653 697

Note 6 Tangible fixed assets and intangible assets

TANGIBLE FIXED ASSETS - GROUP

Property, plant and equipment		Production	Fixtures and
(USD 1 000)	Assets under development	facilities including wells	fittings, office machinery	Total
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	135 062	8 505 026
Additions	1 528 536	362 334	30 633	1 921 503
Disposals	-	-	-	-
Reclassification	-2 561 772	2 617 326	4 718	60 271
Acquisition cost 31.12.2019	1 250 365	9 066 022	170 413	10 486 800
Accumulated depreciation and impairments 31.12.2018	-	2 701 357	57 394	2 758 751
Depreciation	-	677 217	28 065	705 282
Impairment	-	-509	-	-509
Retirement/transfer depreciations	-	-	-	-
Accumulated depreciation and impairments 31.12.2019	-	3 378 065	85 459	3 463 524
Book value 31.12.2019	1 250 365	5 687 957	84 954	7 023 276
Acquisition cost 31.12.2019	1 250 365	9 066 022	170 413	10 486 800
Additions	287 168	46 167	9 174	342 508
Disposals	-	-	-	-
Reclassification1)	-393 038	363 055	48 492	18 509
Acquisition cost 31.03.2020	1 144 495	9 475 244	228 078	10 847 817
Accumulated depreciation and impairments 31.12.2019	-	3 378 065	85 459	3 463 524
Depreciation	-	235 399	9 735	245 134
Impairment	-	78 459	-	78 459
Retirement/transfer depreciations	-	-	-	-
Accumulated depreciation and impairments 31.03.2020	-	3 691 923	95 194	3 787 117
Book value 31.03.2020	1 144 495	5 783 321	132 884	7 060 700

1) The reclassification is mainly relating to the Skogul development project within the Alvheim area, which entered into production phase during Q1 2020.

Production facilities, including wells, are depreciated in accordance with the unit-of-production method. Office machinery, fixtures and fittings etc. are depreciated using the straightline method over their useful life, i.e. 3 - 5 years. Removal and decommissioning costs are included as production facilities or fields under development.

Right-of-use assets
	Vessels and
(USD 1 000)	Drilling Rigs	Boats	Office	Other	Total
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 01.01.2019	-	-	-	-	-
Depreciation	5 369	3 166	7 820	177	16 531
Impairment	-	-	-	-	-
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 31.12.2019	5 369	3 166	7 820	177	16 531
Book value 31.12.2019	101 487	68 941	21 774	2 127	194 328
Acquisition cost 31.12.2019	106 856	72 106	29 593	2 303	210 859
Additions	-	-	-	-	-
Abandonment activity1)	974	273	-	-	1 247
Reclassification2)	-17 529	-979	-	-	-18 509
Acquisition cost 31.03.2020	88 354	70 854	29 593	2 303	191 104
Accumulated depreciation and impairments 31.12.2019	5 369	3 166	7 820	177	16 531
Depreciation	1 071	668	1 955	44	3 738
Impairment	-	-	-	-	-
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 31.03.2020	6 440	3 834	9 775	221	20 270
Book value 31.03.2020	81 913	67 019	19 819	2 082	170 834

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

2) Reclassified to tangible fixed assets in line with the activity of the right-of-use asset.

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

INTANGIBLE ASSETS - GROUP (USD 1 000) Licenses etc. Software Total Goodwill 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 Retirement/transfer depreciations - - - - - 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 Acquisition cost 31.12.2019 2 396 433 7 501 2 403 934 621 315 2 738 973 Additions - - - 31 253 - Disposals/expensed dry wells - - - 28 982 - Reclassification - - - - - Acquisition cost 31.03.2020 2 396 433 7 501 2 403 934 623 587 2 738 973 Accumulated depreciation and impairments 31.12.2019 480 465 7 501 487 966 - 1 026 165 Depreciation 28 540 - 28 540 - - Impairment 365 040 - 365 040 144 826 65 373 Retirement/transfer depreciations - - - - - Accumulated depreciation and impairments 31.03.2020 874 044 7 501 881 546 144 826 1 091 537 Book value 31.03.2020 1 522 389 - 1 522 389 478 761 1 647 436 Other intangible assets Capitalized exploration expenditures

Licenses include both planned and producing projects on various fields. The producing projects are depreciated in line with the unit-of-production method for the applicable field.

	Group
Depreciation in the income statement (USD 1 000)	Q1	Q4	Q1	01.01.-31.03.
	2020	2019	2019	2020	2019
Depreciation of tangible fixed assets	245 134	223 279	159 527	245 134	159 527
Depreciation of right-of-use assets	3 738	3 807	4 533	3 738	4 533
Depreciation of other intangible assets	28 540	27 930	19 043	28 540	19 043
Total depreciation in the income statement	277 412	255 015	183 102	277 412	183 102

Impairment in the income statement (USD 1 000)

Impairment/reversal of tangible fixed assets	78 459	-509	-	78 459	-
Impairment/reversal of other intangible assets	365 040	-	-	365 040	-
Impairment/reversal of capitalized exploration expenditures	144 826	-	-	144 826	-
Impairment of goodwill	65 373	-	68 941	65 373	68 941
Total impairment in the income statement	653 697	-509	68 941	653 697	68 941

Note 7 Leasing

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
(USD 1 000)	31.03.2020	31.03.2019	31.12.2019
Lease debt as of 1 January	313 256	389 833	389 833
New lease debt recognized in the period	-	-	34 385
Payments of lease debt1)	-36 699	-27 760	-134 253
Interest expense on lease debt	4 911	6 459	23 897
Currency exchange differences	-4 111	22	-606
Total lease debt	277 356	368 553	313 256
Break down of the lease debt to short-term and long-term liabilities
Short-term	97 855	92 735	110 664
Long-term	179 501	275 818	202 592
Total lease debt	277 356	368 553	313 256
1) Payments of lease debt split by activities (USD 1 000):
Investments in fixed assets	30 716	21 220	108 587
Abandonment activity	1 521	1 466	4 444
Operating expenditures	3 116	3 734	15 278
Exploration expenditures	221	791	1 384
Other income	1 126	549	4 561
Total	36 699	27 760	134 253
Nominal lease debt maturity breakdown (USD 1 000):
Within one year	113 045	115 473	127 747
Two to five years	153 037	248 016	175 947
After five years	57 693	72 625	61 518
Total	323 775	436 113	365 212

The identified leases have no significant impact on the group`s financing, loan covenants or dividend policy. The group does not have any residual value guarantees. Extension options are included in the lease liability when, based on management's judgement, it is reasonably certain that an extension will be exercised.

Note 8 Financial items

	Group
(USD 1 000)	Q1	Q4	Q1	01.01.-31.03.
	2020	2019	2019	2020	2019
Interest income	1 369	338	6 064	1 369	6 064
Realized gains on derivatives	3 739	2 334	4 420	3 739	4 420
Change in fair value of derivatives	-	49 007	5 299	-	5 299
Net currency gains	104 970	-	-	104 970	-
Total other financial income	108 709	51 341	9 719	108 709	9 719
Interest expenses	42 994	42 552	42 691	42 994	42 691
Interest on lease debt	4 911	5 458	6 459	4 911	6 459
Capitalized interest cost, development projects	-12 900	-14 712	-41 997	-12 900	-41 997
Amortized loan costs	5 036	4 463	6 676	5 036	6 676
Total interest expenses	40 041	37 762	13 830	40 041	13 830
Net currency loss	-	24 592	605	-	605
Realized loss on derivatives	11 036	23 860	6 694	11 036	6 694
Change in fair value of derivatives	172 025	-	1 671	172 025	1 671
Accretion expenses	29 265	31 210	29 584	29 265	29 584
Other financial expenses	6 403	919	782	6 403	782
Total other financial expenses	218 729	80 580	39 335	218 729	39 335
Net financial items	-148 691	-66 663	-37 381	-148 691	-37 381

Note 9 Tax

	Group
	Q1	Q4	Q1	01.01.-31.03.
Tax for the period (USD 1 000)	2020	2019	2019	2020	2019
Current year tax payable	-5 348	346 791	129 282	-5 348	129 282
Change in current year deferred tax	-78 385	-44 863	110 686	-78 385	110 686
Prior period adjustments	4 169	10 521	-1 237	4 169	-1 237
Total tax (+)/tax income (-)	-79 564	312 448	238 731	-79 564	238 731

	Group
Calculated tax receivable (+)/tax payable (-) (USD 1 000)	31.03.2020	31.03.2019	31.12.2019
Tax receivable/payable at 01.01.	-361 157	-540 860	-540 860
Current year tax (-)/tax receivable (+)	5 348	-129 282	-461 984
Taxes receivable/payable related to acquisitions/sales	-	520	520
Net tax payment (+)/tax refund (-)	48 150	105 930	618 593
Prior period adjustments and change in estimate of uncertain tax positions	-7 764	13 278	16 955
Currency movements of tax receivable/payable	55 343	-868	5 619
Total net tax receivable (+)/tax payable (-)	-260 081	-551 282	-361 157
Tax receivable included as current assets (+)	-	15 473	-
Tax payable included as current liabilities (-)	-260 081	-566 755	-361 157

		Group
Deferred tax (-)/deferred tax asset (+) (USD 1 000)	31.03.2020	31.03.2019	31.12.2019
Deferred tax/deferred tax asset 01.01.	-2 235 357	-1 752 757	-1 752 757
Change in deferred tax in the income statement	78 385	-110 686	-463 106
Prior period adjustment	3 595	-3 891	-19 509
Deferred tax charged to OCI and equity	-	-	15
Net deferred tax (-)/deferred tax asset (+)	-2 153 376	-1 867 333	-2 235 357

	Group
	Q1	Q4	Q1	01.01.-31.03.
Reconciliation of tax expense (USD 1 000)	2020	2019	2019	2020	2019
78 % tax rate on profit before tax	-323 152	330 719	194 342	-323 152	194 342
Tax effect of uplift	-35 291	-33 642	-31 063	-35 291	-31 063
Permanent difference on impairment	170 786	-	53 774	170 786	53 774
Foreign currency translation of NOK monetary items	-78 670	18 487	472	-78 670	472
Foreign currency translation of USD monetary items	-411 206	88 763	1 138	-411 206	1 138
Tax effect of financial and other 22 % items	242 250	-25 576	17 519	242 250	17 519
Currency movements of tax balances1)	351 367	-76 648	-323	351 367	-323
Other permanent differences, prior period adjustments and change in estimate of uncertain tax positions	4 351	10 347	2 873	4 351	2 873
Total tax (+)/tax income (-)	-79 564	312 448	238 731	-79 564	238 731

1) Tax balances are in NOK and converted to USD using the period end currency rate. When NOK weakens against USD, the tax rate increases as there is less remaining tax depreciation measured in USD (and vice versa).

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.

Note 10 Other short-term receivables

		Group
(USD 1 000)	31.03.2020	31.03.2019	31.12.2019
Prepayments	80 134	66 662	65 813
VAT receivable	6 796	7 082	8 904
Underlift of petroleum	49 152	39 170	46 515
Accrued income from sale of petroleum products	78 019	136 882	80 514
Other receivables, mainly balances with license partners	93 534	95 578	128 770
Total other short-term receivables	307 635	345 374	330 516

Note 11 Cash and cash equivalents

The item 'Cash and cash equivalents' consists of bank accounts and short-term investments that constitute parts of the group's transaction liquidity.

		Group
Breakdown of cash and cash equivalents (USD 1 000)	31.03.2020	31.03.2019	31.12.2019
Bank deposits	322 789	113 680	107 104
Cash and cash equivalents	322 789	113 680	107 104
Unused RCF/RBL facility (see note 15)	3 700 000	2 850 000	2 550 000

Note 12 Derivatives

		Group
(USD 1 000)	31.03.2020	31.03.2019	31.12.2019
Unrealized gain currency contracts	-	-	2 706
Long-term derivatives included in assets	-	-	2 706
Unrealized gain on commodity derivatives	66 611	-	-
Short-term derivatives included in assets	66 611	-	-
Total derivatives included in assets	66 611	-	2 706
Unrealized losses interest rate swaps	-	27 945	-
Unrealized losses currency contracts	56 982	-	-
Long-term derivatives included in liabilities	56 982	27 945	-
Unrealized losses commodity derivatives	-	6 870	1 805
Unrealized losses interest rate swaps	73 727	-	37 017
Unrealized losses currency contracts	79 800	3 484	4 172
Short-term derivatives included in liabilities	153 527	10 354	42 994
Total derivatives included in liabilities	210 509	38 300	42 994

The group has various types of economic hedging instruments. Commodity derivatives are used to hedge the risk of oil price reduction. The group manages its interest rate exposure using interest rate derivatives, including interest rate swap and a cross currency interest rate swap. Foreign currency exchange derivatives are used to manage the company's exposure to currency risks, mainly costs in NOK, EUR and GBP. These derivatives are mark to market with changes in market value recognized in the income statement. The nature of the instruments and the valuation method is consistent with the disclosed information in the annual financial statements as at 31 December 2019.

Note 13 Other current liabilities

		Group
Breakdown of other current liabilities (USD 1 000)	31.03.2020	31.03.2019	31.12.2019
Balances with license partners	47 198	25 723	67 199
Share of other current liabilities in licenses	269 887	357 645	379 787
Overlift of petroleum	9 123	3 766	15 660
Unpaid wages and vacation pay, accrued interest and other provisions	164 676	173 566	197 889
Total other current liabilities	490 884	560 700	660 535

Note 14 Bonds

			Group
Senior unsecured bonds (USD 1 000)	Interest	Maturity	31.03.2020	31.03.2019	31.12.2019
DETNOR02 Senior unsecured bond1)		Jul 2020	-	225 843	-
AKERBP – Senior Notes (17/22)2)	6.000%	Jul 2022	395 537	393 763	395 046
AKERBP – Senior Notes (18/25)2)	5.875%	Mar 2025	494 733	493 680	494 470
AKERBP – Senior Notes (19/24)2)	4.750%	Jun 2024	741 900	-	741 421
AKERBP – Senior Notes (20/30)2)	3.750%	Jan 2030	992 180	-	-
AKERBP – Senior Notes (20/25)2)	3.000%	Jan 2025	495 712	-	-
Long-term bonds			3 120 062	1 113 285	1 630 936
DETNOR02 Senior unsecured bond1)		Jul 2020	192 541	-	226 700
Short-term bonds			192 541	-	226 700

1) The bond is denominated in NOK and carries an interest rate of 3 month Nibor + 6.5 percent. The interest is paid on a quarterly basis. The bond has been swapped into USD using a cross currency interest rate swap whereby the group pays Libor + 6.81 percent quarterly. The financial covenants for this bond are consistent with the RCF as described in note 15.

2) Interests are paid on a semi annual basis. None of the long-term bonds have financial covenants.

Note 15 Other interest-bearing debt

	Group
(USD 1 000)	31.03.2020	31.03.2019	31.12.2019
Reserve-based lending facility	-	1 112 304	-
Revolving credit facility	280 784	-	1 429 132
Long-term interest-bearing debt	280 784	1 112 304	1 429 132

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, of which the first was exercised in April 2020. The interest rate is LIBOR plus a margin of 1.08 percent for the Liquidity Facility and 1.33 percent for the Working Capital Facility. In addition, a utilization fee is applicable for the Liquidity Facility. A commitment fee of 35 percent of applicable margin is paid on the undrawn facility. The financial covenants are as follows:

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

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

The financial covenants 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 16 Provision for abandonment liabilities

		Group
(USD 1 000)	31.03.2020	31.03.2019	31.12.2019
Provisions as of 1 January	2 788 218	2 552 592	2 552 592
Incurred cost removal	-22 176	-21 575	-108 332
Accretion expense - present value calculation	29 265	29 584	121 723
Changed net present value from changed discount rate	-	-	238 053
Change in estimates and incurred liabilities on new drilling and installations	-	-	-15 818
Total provision for abandonment liabilities	2 795 306	2 560 601	2 788 218
Break down of the provision to short-term and long-term liabilities
Short-term	153 043	85 212	142 798
Long-term	2 642 264	2 475 388	2 645 420
Total provision for abandonment liabilities	2 795 306	2 560 601	2 788 218

The estimate is based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The calculations assume an inflation rate of 2.0 percent and a nominal discount rate before tax of between 3.77 percent and 4.59 percent. The credit margin included in the discount rate is 2.20 percent.

Note 17 Contingent liabilities and assets

During the normal course of its business, the group will be involved in disputes, including tax disputes. The group has made accruals for probable liabilities related to litigation and claims based on management's best judgment and in line with IAS 37 and IAS 12.

Note 18 Subsequent events

In January 2020 Aker BP entered into an agreement with PGNiG Upstream Norway AS to swap its 3.3 percent interest in the non-operated Gina Krog field and a 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. The transaction was closed on 30 April 2020 and had no material impact on the financial statement.

Note 19 Investments in joint operations

Fields operated:	31.03.2020	31.12.2019
Alvheim	65.000%	65.000 %
Bøyla	65.000%	65.000 %
Hod	90.000%	90.000 %
Ivar Aasen Unit	34.786%	34.786 %
Jette Unit1)	0.000%	70.000 %
Valhall	90.000%	90.000 %
Vilje	46.904%	46.904 %
Volund	65.000%	65.000 %
Tambar	55.000%	55.000 %
Skogul	65.000%	65.000 %
Tambar Øst	46.200%	46.200 %
Ula	80.000%	80.000 %
Skarv	23.835%	23.835 %

1) Relinquished license or Aker BP has withdrawn from the license

Production licenses in which Aker BP is the operator:
License:	31.03.2020	31.12.2019 License:	31.03.2020	31.12.2019
PL 001B	35.000%	35.000 % PL 777C	40.000%	40.000 %
PL 006B	90.000%	90.000 % PL 777D	40.000%	40.000 %
PL 019	80.000%	80.000 % PL 784	40.000%	40.000 %
PL 019C	80.000%	80.000 % PL 814	40.000%	40.000 %
PL 019E	80.000%	80.000 % PL 818	40.000%	40.000 %
PL 019F2)	55.000%	0.000 % PL 818B	40.000%	40.000 %
PL 019H3)	0.000%	80.000 % PL 822S	60.000%	60.000 %
PL 026	92.130%	92.130 % PL 8393)	0.000%	23.835 %
PL 026B	90.260%	90.260 % PL 8433)	0.000%	40.000 %
PL 028B	35.000%	35.000 % PL 858	40.000%	40.000 %
PL 033	90.000%	90.000 % PL 867	40.000%	40.000 %
PL 033B	90.000%	90.000 % PL 867B1)	40.000%	0.000 %
PL 036C	65.000%	65.000 % PL 868	60.000%	60.000 %
PL 036D	46.904%	46.904 % PL 869	60.000%	60.000 %
PL 036E	64.000%	64.000 % PL 873	40.000%	40.000 %
PL 036F1)	64.000%	0.000 % PL 874	90.260%	90.260 %
PL 065	55.000%	55.000 % PL 8933)	0.000%	60.000 %
PL 065B	55.000%	55.000 % PL 906	60.000%	60.000 %
PL 088BS	65.000%	65.000 % PL 907	60.000%	60.000 %
PL 102D	50.000%	50.000 % PL 914S	34.786%	34.786 %
PL 102F	50.000%	50.000 % PL 915	35.000%	35.000 %
PL 102G	50.000%	50.000 % PL 9163)	0.000%	40.000 %
PL 102H	50.000%	50.000 % PL 919	65.000%	65.000 %
PL 127C	100.000%	100.000 % PL 932	60.000%	60.000 %
PL 146	77.800%	77.800 % PL 941	50.000%	50.000 %
PL 150	65.000%	65.000 % PL 9483)	0.000%	40.000 %
PL 159D	23.835%	23.835 % PL 951	40.000%	40.000 %
PL 203	65.000%	65.000 % PL 963	70.000%	70.000 %
PL 212	30.000%	30.000 % PL 964	40.000%	40.000 %
PL 212B	30.000%	30.000 % PL 977	60.000%	60.000 %
PL 212E	30.000%	30.000 % PL 978	60.000%	60.000 %
	35.000%		60.000%
PL 242	50.000%	35.000 % PL 979	30.000%	60.000 %
PL 261	30.000%	50.000 % PL 986	60.000%	30.000 %
PL 262	55.000%	30.000 % PL 1005	60.000%	60.000 %
PL 300	77.800%	55.000 % PL 1008	40.000%	60.000 %
PL 333	65.000%	77.800 % PL 1022	40.000%	40.000 %
PL 340	65.000%	65.000 % PL 1026	50.000%	40.000 %
PL 340BS	90.260%	65.000 % PL 1028	50.000%	50.000 %
PL 364		90.260 % PL 1030		50.000 %
PL 442	90.260%	90.260 % PL 10411)	40.000%	0.000 %
PL 442B	90.260%	90.260 % PL 10421)	40.000%	0.000 %
PL 442C1)	90.260%	0.000 % PL 10451)	65.000%	0.000 %
PL 460	65.000%	65.000 % PL 10471)	40.000%	0.000 %
PL 685	40.000%	40.000 % PL 10661)	50.000%	0.000 %
PL 762	20.000%	20.000 % PL 10811)	60.000%	0.000 %
PL 777	40.000%	40.000 %
PL 777B	40.000%	40.000 %
Number of licenses in which Aker BP is the operator			86	82

1) Interest awarded in the APA Licensing round

2) Aker BP has acquired a 55% share in PL019F

3) Relinquished license or Aker BP has withdrawn from the license

Fields non-operated:	31.03.2020	31.12.2019
Atla	10.000%	10.000 %
Enoch	2.000%	2.000 %
Gina Krog	3.300%	3.300 %
Johan Sverdrup	11.573%	11.573 %
Oda	15.000%	15.000 %

Production licenses in which Aker BP is a partner:
License:	31.03.2020	31.12.2019 License:	31.03.2020	31.12.2019
PL 006C	15.000%	15.000 % PL 8111)	0.000%	20.000 %
PL 006E	15.000%	15.000 % PL 838	30.000%	30.000 %
PL 006F	15.000%	15.000 % PL 838B	30.000%	30.000 %
PL 029B	20.000%	20.000 % PL 8441)	0.000%	20.000 %
PL 035	50.000%	50.000 % PL 852	40.000%	40.000 %
PL 035C	50.000%	50.000 % PL 852B	40.000%	40.000 %
PL 048D	10.000%	10.000 % PL 852C	40.000%	40.000 %
PL 102C	10.000%	10.000 % PL 857	20.000%	20.000 %
PL 127	50.000%	50.000 % PL 862	50.000%	50.000 %
PL 127B	50.000%	50.000 % PL 8631)	0.000%	40.000 %
PL 220	15.000%	15.000 % PL 863B1)	0.000%	40.000 %
PL 265	20.000%	20.000 % PL 864	20.000%	20.000 %
PL 272	50.000%	50.000 % PL 892	30.000%	30.000 %
PL 272B	50.000%	50.000 % PL 902	30.000%	30.000 %
PL 405	15.000%	15.000 % PL 902B	30.000%	30.000 %
PL 457BS	40.000%	40.000 % PL 942	30.000%	30.000 %
PL 492	60.000%	60.000 % PL 954	20.000%	20.000 %
PL 502	22.222%	22.222 % PL 955	30.000%	30.000 %
PL 533	35.000%	35.000 % PL 961	30.000%	30.000 %
PL 533B	35.000%	35.000 % PL 962	20.000%	20.000 %
PL 554	30.000%	30.000 % PL 966	30.000%	30.000 %
PL 554B	30.000%	30.000 % PL 968	20.000%	20.000 %
PL 554C	30.000%	30.000 % PL 981	40.000%	40.000 %
PL 554D	30.000%	30.000 % PL 982	40.000%	40.000 %
PL 615	4.000%	4.000 % PL 985	20.000%	20.000 %
PL 615B	4.000%	4.000 % PL 1031	20.000%	20.000 %
PL 719	20.000%	20.000 % PL 10402)	30.000%	0.000 %
PL 722	20.000%	20.000 % PL 10512)	20.000%	0.000 %
PL 780	40.000%	40.000 % PL 10522)	20.000%	0.000 %
PL 782S	20.000%	20.000 % PL 10542)	30.000%	0.000 %
PL 782SB	20.000%	20.000 % PL 10642)	30.000%	0.000 %
PL 782SC	20.000%	20.000 % PL 10692)	50.000%	0.000 %
PL 782SD	20.000%	20.000 %
Number of licenses in which Aker BP is the partner			61	59

1) Relinquished license or Aker BP has withdrawn from the license

2) Interest awarded in the APA Licensing round

Note 20 Results from previous interim reports

	2020	2019
(USD 1 000)	Q1	Q4	Q3	Q2	Q1
Total income	872 105	1 002 673	723 338	784 816	836 262
Production costs	156 043	154 272	167 267	198 320	200 462
Exploration expenses	50 336	84 683	70 213	60 261	90 359
Depreciation	277 412	255 015	205 867	167 889	183 102
Impairments	653 697	-509	78 376	-	68 941
Other operating expenses	223	18 550	6 038	3 882	6 859
Total operating expenses	1 137 711	512 011	527 760	430 352	549 724
Operating profit	-265 606	490 661	195 578	354 464	286 538
Net financial items	-148 691	-66 663	-52 710	-86 232	-37 381
Profit before taxes	-414 298	423 998	142 868	268 232	249 157
Taxes (+)/tax income (-)	-79 564	312 448	186 291	205 734	238 731
Net profit/loss	-334 734	111 550	-43 423	62 498	10 425

	2020		2019
(boe 1 000)	Q1	Q4	Q3	Q2	Q1
Sold volumes
Liquids Gas	15 858 3 026	13 930 3 046	10 437 2 743	10 264 2 541	11 594 2 988

	2020	2019
(USD 1 000)	Q1	Q4	Q3	Q2	Q1
Assets
Goodwill	1 647 436	1 712 809	1 712 809	1 791 185	1 791 185
Other intangible assets	2 001 150	2 537 283	2 570 893	2 521 625	2 483 080
Property, plant and equipment	7 060 700	7 023 276	6 613 597	6 299 710	5 953 972
Right-of-use asset	170 834	194 328	215 328	238 879	225 244
Receivables and other assets	524 382	651 986	609 112	521 934	533 949
Calculated tax receivables (short)	-	-	-	17 418	15 473
Cash and cash equivalents	322 789	107 104	5 066	101 828	113 680
Total assets	11 727 291	12 226 786	11 726 805	11 492 580	11 116 582
Equity and liabilities
Equity	1 813 229	2 367 585	2 443 539	2 663 797	2 799 464
Other provisions for liabilities incl. P&A (long)	2 699 246	2 645 420	2 542 083	2 558 845	2 503 334
Deferred tax	2 153 376	2 235 357	2 279 415	1 991 371	1 867 333
Bonds and bank debt	3 593 387	3 286 768	2 939 545	2 634 585	2 225 589
Lease debt	277 356	313 256	341 071	374 595	368 553
Other current liabilities incl. P&A	930 616	1 017 244	986 162	830 119	785 554
Tax payable	260 081	361 157	194 991	439 270	566 755
Total equity and liabilities	11 727 291	12 226 786	11 726 805	11 492 580	11 116 582

Alternative performance measures

Aker BP may disclose alternative performance measures as part of its financial reporting as a supplement to the financial statements prepared in accordance with IFRS. Aker BP believes that the alternative performance measures provide useful supplemental information to management, investors, security analysts and other stakeholders and are meant to provide an enhanced insight into the financial development of Aker BP's business operations and to improve comparability between periods.

Abandonment spend (abex) is payment for removal and decommissioning of oil fields1)

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

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

Capex is disbursements on investments in fixed assets deducted by capitalized interest cost1)

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

EBITDA is short for earnings before interest and other financial items, taxes, depreciation and amortisation and impairments

EBITDAX is short for earnings before interest and other financial items, taxes, depreciation and amortisation, impairments and exploration expenses

Equity ratio is total equity divided by total assets

Exploration spend (expex) is exploration expenses plus additions to capitalized exploration wells less dry well expenses1)

Leverage ratio is calculated as Net interest-bearing debt divided by twelve months rolling EBITDAX, excluding impacts from IFRS 162)

Net interest-bearing debt is book value of current and non-current interest-bearing debt less cash and cash equivalents3)

Production cost per boe is production cost basd on produced volumes (see note 3), divided by number of barrels of oil equivalents produced in the corresponding period

1) Includes payments of lease debt as disclosed in note 7.

2) 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.

3) Includes leasing debt.

AKER BP ASA

Fornebuporten, Building B Oksenøyveien 10 1366 Lysaker

Postal address: P.O. Box 65 1324 Lysaker, Norway

Telephone: +47 51 35 30 00 E-mail: post@akerbp.com

www.akerbp.com