Aker BP

Quarterly Report • Apr 28, 2022

QUARTERLY REPORT Q1 2022

FIRST QUARTER 2022 SUMMARY

Aker BP delivered record strong financial results for the first quarter 2022, driven by high oil and gas prices and by strong underlying performance. The company's field development projects progressed according to plan, and the Hod field started production early April. The company also initiated the blowdown phase for parts of the Skarv field to increase its natural gas exports to Europe. The proposed acquisition of Lundin Energy has received shareholder approvals and closing is scheduled for 30 June.

The company's net production in the first quarter was 208.2 (207.0) thousand barrels of oil equivalent per day (mboepd). The increase was mainly driven by higher production from Skarv and the Alvheim area, partly offset by lower production from the Ula area and Ivar Aasen compared to the previous quarter. Net sold volume was 216.2 (205.1) mboepd. The average realised liquids price increased to USD 100.9 (78.8) per barrel, while the average realised price for natural gas increased to USD 171.0 (169.5) per barrel of oil equivalent (boe).

Production costs for the oil and gas sold in the quarter amounted to USD 220 (202) million, and were impacted by the overlift and by high well intervention activity at Valhall, as well as by high power prices which are closely linked to the current high natural gas prices in Europe. The average production cost per produced unit was USD 11.6 (10.1) per boe. Exploration expenses amounted to USD 58 (83) million. Depreciation was USD 231 (219) million, equivalent to USD 12.3 (11.5) per boe.

This resulted in operating profit of USD 1,775 (1,260) million. After net financial income of USD 61 (-43) million, positively impacted by the sale of shares in Cognite AS, profit before taxes ended at USD 1,837 (1,218) million. Tax expenses amounted to USD 1,300 (854) million, and net profit was USD 537 (364) million for the quarter.

Capital expenditure amounted to USD 355 (442) million in the quarter, mainly related to development projects in the Alvheim and Valhall areas. The company continued progressing its portfolio of field development projects according to plan. During the first quarter, the PDOs for Kobra East & Gekko (KEG) in

the Alvheim area and Hanz at Ivar Aasen were approved by Norwegian authorities.

In late March, the company initiated the gas blowdown phase from two reservoir segments at Skarv. This will contribute to increased utilization of available gas processing and export capacity from the Skarv FPSO and Åsgard transport system, and thereby increase the natural gas volumes available for export to Europe.

The strong performance in the quarter resulted in a positive net cash flow of USD 845 million, further strengthening the company's financial position. At the end of the quarter, Aker BP had total available liquidity of USD 6.2 (5.4) billion. Net interest-bearing debt was USD 0.9 (1.7) billion, including USD 0.1 (0.1) billion in lease debt.

Dividend payments amounted to USD 171 million (USD 0.475 per share). The plan is to pay dividends of USD 0.475 per share each quarter this year, equivalent to USD 1.9 per share for the full year.

On 21 December 2021, the company announced a transaction agreement with Lundin Energy AB, pursuant to which Aker BP will acquire Lundin Energy's oil and gas related assets. The transaction has been approved by the shareholders of both companies. Closing of the transaction is expected to take place 30 June 2022.

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.

Financial summary

	UNIT	Q1 2022	Q4 2021	Q1 2021
Total income	USDm	2 291	1 849	1 133
EBITDA	USDm	2 007	1 559	878
Net profit/loss	USDm	537	364	127
Earnings per share (EPS)	USD	1.49	1.01	0.35
Capex	USDm	355	442	217
Exploration spend	USDm	67	95	86
Abandonment spend	USDm	16	16	98
Production cost	USD/boe	11.6	10.1	8.6
Taxes paid/refunded	USDm	388	160	(11)
Net interest-bearing debt	USDm	877	1 742	3 282
Leverage ratio		0.12	0.33	1.23
Dividend per share	USD	0.48	0.42	0.31
Average USDNOK exchange rate		8.85	8.72	8.51

Production summary

	UNIT	Q1 2022	Q4 2021	Q1 2021
Alvheim area	mboepd	45.3	43.4	50.1
Ivar Aasen	mboepd	14.0	15.2	20.2
Johan Sverdrup	mboepd	62.9	63.1	61.2
Skarv	mboepd	34.6	31.8	29.0
Ula area	mboepd	5.6	7.4	8.7
Valhall area	mboepd	45.5	46.1	53.0
Other	mboepd	0.2	0.1	0.0
Net production	mboepd	208.2	207.0	222.2
Over/underlift	mboepd	8.0	(1.9)	1.0
Net sold volume	mboepd	216.2	205.1	223.2
-Liquids	mboepd	171.1	165.4	183.0
-Natural gas	mboepd	45.0	39.7	40.2
Realised price liquids	USD/boe	100.9	78.8	60.1
Realised price natural gas	USD/boe	171.0	169.5	38.5

FINANCIAL REVIEW

Income statement

(USD MILLION)	Q1 2022	Q4 2021	Q1 2021
Total income	2 291	1 849	1 133
EBITDA	2 007	1 559	878
EBIT	1 775	1 260	591
Pre-tax profit	1 837	1 218	501
Net profit/loss	537	364	127
EPS (USD)	1.49	1.01	0.35

Total income in the first quarter 2022 amounted to USD 2,291 (1,849) million. The increase was mainly driven by higher oil prices and a higher share of gas production compared to the previous quarter. The average realised liquids price increased by 28 percent to USD 100.9 (78.8) per barrel, while the average realised gas price was stable quarter on quarter at USD 171.0 (169.5) per boe. Sold volumes were 216.2 (205.1) mboepd in the quarter, following an overlift of 8.0 mboepd compared to an underlift in the previous quarter of 1.9 mboepd. Other income amounted to USD 41 (28) million and was positively impacted by gains on commodity derivatives.

Production costs for the oil and gas sold in the quarter amounted to USD 220 (202) million and were impacted by the overlift and by high well intervention activity at Valhall, as well as by high power prices which are closely linked to the current high natural gas prices in Europe. The average production cost per produced unit was USD 11.6 (10.1) per boe. See note 3 for further details on production costs.

Exploration expenses amounted to USD 58 (83) million, of which dry well expenses were USD 39 (33) million, mainly related to the Grefsenkollen exploration well.

Depreciation amounted to USD 231 (219) million, corresponding to USD 12.3 (11.5) per barrel of oil equivalent. The change was mainly driven by changes in the relative share of production between the fields. Other operating expenses amounted to USD 7 (6) million.

Operating profit increased to USD 1,775 (1,260) million for the first quarter. Net financial income amounted to USD 61 (-43) million, with the increase compared to the previous quarter driven by the sale of shares in Cognite AS resulting in a gain of USD 99 million.

Profit before taxes amounted to USD 1,837 (1,218) million. Tax expense was USD 1,300 (854) million. The effective tax rate was 71 percent. See note 8 for further details on tax.

This resulted in a net profit for the first quarter 2022 of USD 537 (364) million.

Statement of financial position

(USD MILLION)	Q1 2022	Q4 2021	Q1 2021
Total non-current assets	11 781	11 487	11 155
Total current assets	4 045	2 983	1 086
Total assets	15 826	14 470	12 241
Total equity	2 708	2 342	1 989
Bank and bond debt	3 558	3 577	3 474
Total abandonment provisions	2 839	2 757	2 753
Deferred taxes	3 478	3 323	2 782
Other liabilities	3 244	2 471	1 243
Total equity and liabilities	15 826	14 470	12 241
Net interest-bearing debt	877	1 742	3 282

At the end of the first quarter 2022, total assets amounted to USD 15,826 (14,470) million, of which current assets were USD 4,045 (2,983) million.

Equity amounted to USD 2,708 (2,342) million at the end of the quarter, corresponding to an equity ratio of 17 (16) percent.

Deferred tax liabilities amounted to USD 3,478 (3,323) million and total abandonment provisions amounted to USD 2,839

(2,757) million. Bank and bond debt totalled USD 3,558 (3,577) million. This was entirely made up of bond debt as the company's bank facilities were not drawn.

At the end of the first quarter 2022, the company had total available liquidity of USD 6.2 (5.4) billion, comprising USD 2,817 (1,971) million in cash and cash equivalents, and USD 3.4 (3.4) billion in undrawn credit facilities.

Cash flow

(USD MILLION)	Q1 2022	Q4 2021	Q1 2021
Cash flow from operations	1 375	1 211	900
Cash flow from investments	(282)	(484)	(322)
Cash flow from financing	(248)	(180)	(723)
Net change in cash & cash equivalents	845	547	(145)
Cash and cash equivalents	2 817	1 971	392

Net cash flow from operating activities was USD 1,375 (1,211) million in the quarter. Pre-tax profit increased in the quarter, driven by higher realised oil and gas prices and a higher relative share of gas production. This was partly offset by working capital changes and taxes paid.

Net cash used for investment activities was USD 282 (484) million, of which investments in fixed assets amounted to USD 335 (422) million for the quarter. Investments in capitalised exploration were USD 49 (46) million. Payments for

Risk management

The company uses various types of economic hedging instruments. Commodity derivatives are used to mitigate the financial consequences of potential significant negative movements in oil and gas prices. Aker BP currently has limited exposure to fluctuations in interest rates, but generally manages such exposure by using interest rate derivatives. Foreign exchange derivatives are used to manage the company's exposure to

decommissioning activities amounted to USD 16 (16) million. In addition, the company received USD 118 million in consideration for the sale of its shares in Cognite AS, which was completed in the quarter.

Net cash outflow from financing activities was USD 248 million, compared to an outflow of USD 180 million in the previous quarter. The main items were dividend disbursements of USD 171 (150) million and interest payments (including interest element of lease payment) of USD 55 (8) million.

currency risks, mainly costs in NOK, EUR, and GBP. These derivatives are marked to market with changes in market value recognized in the income statement.

The following table shows the company's inventory of oil put options and natural gas futures at the time of this report:

OIL PUT OPTIONS	Q2 2022	Q3 2022	Q4 2022
Share of oil production covered (after tax)	78 %	62 %	55 %
Average strike (USD/bbl)	45	45	45
Average premium (USD/bbl)	1.6	1.6	1.6

NATURAL GAS FUTURES	Q2 2022	Q3 2022	Q4 2022
Share of gas production covered (after tax)	13%	11%	10%
Average price (EUR/MWh)	173	173	173

Note: The share of production is calculated based on current Aker BP portfolio and does not include volumes from the Lundin Energy assets

Dividends

At the Annual General Meeting in April 2022, the Board was authorised to approve the distribution of dividends based on the company's annual accounts for 2021 pursuant to section 8-2 (2) of the Norwegian Public Limited Companies Act.

On 21 December 2021, the Board resolved to increase the annualised dividend to USD 1.90 per share, effective from first quarter 2022. The first quarterly dividend payment of USD 0.475 (NOK 4.1782) was paid on 23 February. The next dividend payment is expected to be disbursed on or about 11 May 2022.

OPERATIONAL REVIEW

Aker BP's net production was 18.7 (19.0) mmboe in the first quarter of 2022, corresponding to 208.2 (207.0) mboepd. Net sold volume was 216.2 (205.1) mboepd.

Alvheim Area

KEY FIGURES	AKER BP INTEREST	Q1 2022	Q4 2021	Q3 2021	Q2 2021	Q1 2021
Production, boepd
Alvheim	65%	34 688	31 721	36 061	34 799	35 176
Bøyla (incl. Frosk)	65%	1 561	2 068	865	1 191	2 921
Skogul	65%	2 407	1 817	4 449	4 542	4 450
Vilje	46.904%	2 108	3 501	1 971	1 789	2 707
Volund	65%	4 582	4 275	3 264	3 602	4 892
Total production		45 347	43 382	46 610	45 923	50 147
Production efficiency		98 %	94 %	96 %	91 %	99 %

First quarter production from the Alvheim area was 45.3 mboepd net to Aker BP. The increase compared to the previous quarter was driven by higher production efficiency of 98 (94) percent, partly offset by natural decline.

The Alvheim infill drilling program progressed well during the quarter. The Kameleon Infill West (KIW) well was completed and started production in early February.

All three development projects on Alvheim progressed according to plan during the quarter. The two-well drilling campaign on Frosk is scheduled to start in the third quarter, followed by a subsea tie-back campaign leading up to first oil in first quarter 2023. On Kobra East & Gekko (KEG), the Plan for Development and Operations (PDO) was approved by authorities in February. The offshore execution phase commenced in

January with a boulder removal campaign to prepare for installation of the new pipelines, planned in the third quarter. Well planning, engineering, fabrication and procurement activities are progressing according to plan. First oil is scheduled in first quarter 2024.

On the Trell & Trine (T&T) project, the concept select decision (DG2) was passed in fourth quarter 2021, and the pre-investment program was approved by authorities during first quarter 2022. The project is on track to submit a PDO in third quarter 2022. Commitments have been placed to secure a vessel and materials for execution of the planned pipelay campaign in 2023, enabling drilling of the Trell & Trine wells in direct continuation of the KEG drilling campaign. First oil is scheduled for first quarter 2025.

Ivar Aasen

KEY FIGURES	AKER BP INTEREST	Q1 2022	Q4 2021	Q3 2021	Q2 2021	Q1 2021
Production, boepd
Total production	34.7862%	14 038	15 157	15 285	16 129	20 206
Production efficiency		87 %	81 %	86 %	89 %	90 %

First quarter production from Ivar Aasen was 14.0 mboepd net to Aker BP, down seven percent compared to the previous quarter. Higher production efficiency of 87 (81) percent was more than offset by technical issues on Edvard Grieg towards the end of the quarter, resulting in an unplanned shutdown of Ivar Aasen. Production has since restarted at reduced rates, and it is expected that production will ramp up to full speed once remediation works have been completed towards the middle of May. To minimise the impact of the shutdown, the planned turnaround activities at Ivar Aasen have been accelerated from May to April.

Planning of the 2022 IOR drilling campaign progressed well during the quarter, and the campaign was approved by the license partners in April.

The Hanz development project received approval from the authorities on 11 March and the project is now in the execution phase. First oil is expected in first quarter 2024.

During the quarter, the licence partners at Lille Prinsen approved Ivar Aasen as the tie-back host. Work continues towards a concept select decision during the second quarter. The plan is to sanction the project by the end of 2022.

Johan Sverdrup

KEY FIGURES	AKER BP INTEREST	Q1 2022	Q4 2021	Q3 2021	Q2 2021	Q1 2021
Production, boepd
Total production	11.5733%	62 908	63 112	63 424	64 262	61 178

Johan Sverdrup produced at process capacity of 535 mboepd with high regularity through the first quarter of 2022. A planned four-day shutdown was executed in January to upgrade the Safety and Automation System in preparation for start-up of the second processing platform (P2). Production well number 15 was put on production in late March.

Phase 2 of the Johan Sverdrup development progressed safely according to plan and cost. Hook-up and commissioning of the P2 platform at Aibel's construction site in Haugesund was completed late February and the platform was installed offshore on schedule on 8 March by the heavy lift vessel Pioneering Spirit, which also installed a bridge connecting P2 to the field centre. Offshore hook-up and commissioning started immediately thereafter. The installation of infield pipelines and a power cable from shore was completed. Drilling of Phase 2 wells started ahead of schedule in January. After a two-month break, drilling is expected to continue from April. Phase 2 production start is planned for fourth quarter 2022.

Skarv Area

KEY FIGURES	AKER BP INTEREST	Q1 2022	Q4 2021	Q3 2021	Q2 2021	Q1 2021
Production, boepd
Total production	23.835 %	34 576	31 785	34 476	20 581	28 973
Production efficiency		86 %	88 %	97 %	58 %	84 %

Production from the Skarv area in the first quarter of 2022 was 34.6 mboepd net to Aker BP, an increase of nine percent compared to the previous quarter. The increase was mainly driven by the first full quarter of production from the last Ærfugl wells, partly offset by temporarily reduced production capacity due to technical problems with the seawater lifting pumps. The relevant pumps were replaced during the quarter, and production was back at full capacity in March. Production efficiency in the quarter was 86 (88) percent.

In late March, a gas blowdown was initiated from two reservoir segments following nine years of gas injection to produce the oil reserves in the segments. Blowdown is part of the approved drainage strategy in the Skarv PDO and is now occurring two

years later than stipulated in the plan approved by the authorities. The blowdown will contribute to increased utilization of available gas processing and export capacity from the Skarv FPSO and Åsgard transport system, and thereby increase gas volumes available for export to Europe.

The development projects on Skarv made good progress during the first quarter. On the Idun Tunge project, drilling is scheduled to start in the second half of 2022. Preparations for the Skarv Satellites project (Ørn, Shrek, Idun Nord and Alve Nord) continued according to plan. The development concept was concluded in the quarter, and the plan is to submit PDOs to the authorities before year-end.

Ula Area

KEY FIGURES	AKER BP INTEREST	Q1 2022	Q4 2021	Q3 2021	Q2 2021	Q1 2021
Production, boepd
Ula	80 %	3 157	4 165	4 622	3 539	5 464
Tambar	55 %	1 434	1 915	2 725	1 927	1 413
Oda	15 %	1 014	1 297	1 192	930	1 865
Total production		5 605	7 376	8 539	6 396	8 741
Production efficiency		60 %	77 %	84 %	64 %	80 %

First quarter production at Ula decreased compared to the previous quarter, mainly driven by a 35-day field shutdown on Tambar due to component failure on a wellhead. The production was also negatively impacted by well shut-ins at Ula. Production efficiency was 60 (77) percent. Maintenance activities are scheduled in the second quarter to improve the production efficiency at Ula and Tambar.

Production on Oda was shut in for 14 days in March due to drilling of a new sidetrack which is expected to boost Oda production from May.

The Ula Power Project progressed well, with completion of commissioning of the third and final generator.

Valhall Area

KEY FIGURES	AKER BP INTEREST	Q1 2022	Q4 2021	Q3 2021	Q2 2021	Q1 2021
Production, boepd
Valhall	90%	44 945	45 623	40 983	44 699	52 526
Hod	90%	593	426	467	596	446
Total production		45 538	46 050	41 450	45 295	52 972
Production efficiency		89 %	84 %	76 %	81 %	91 %

First quarter production from Valhall was 45.5 mboepd net to Aker BP, slightly down compared to the previous quarter, mainly driven by natural decline. Production efficiency was 89 (84) percent.

During the quarter, the Maersk Reacher jack-up rig was replaced by Maersk Integrator. The rig will continue to support stimulation and intervention activities and bring more wells up to their full production potential.

The Hod field development project progressed according to plan, and first oil was achieved in April, only 22 months after the project was sanctioned. Hod is developed with a normally unmanned wellhead platform, remotely operated from the Valhall field centre. Six wells have been drilled and completed. The first of these wells has started production, and work will continue to stimulate the remaining wells and bring them on stream. The Hod field is powered from shore via Valhall and hence the CO2 emissions from the field will be close to zero.

Preparation for an additional infill well on Valhall Flank West also progressed according to plan. The well will be drilled by Maersk Invincible in the second quarter.

The joint Valhall NCP & King Lear project progressed according to plan in the first quarter. The selected development concept consists of a new process and wellhead platform (NCP) which will provide Valhall with significant gas processing capacity, and an unmanned platform on the King Lear gas field. The project will be connected to the existing power from shore solution at Valhall, resulting in close to zero emissions from operations. A final investment decision is targeted in fourth quarter 2022. Production start is scheduled for 2027.

North of Alvheim, Krafla and Fulla (NOAKA)

The NOAKA area is located between Oseberg and Alvheim in the Norwegian North Sea and consists of several oil and gas discoveries. The partners (Aker BP ASA, Equinor ASA and LOTOS Exploration & Production Norge AS) are planning for a coordinated development of the area, with Aker BP as the operator of North of Alvheim and Fulla (NOA Fulla), and with Equinor as the operator of Krafla.

The gross resource estimate amounts to around 600 million barrels of oil equivalent, with further upside potential from future exploration in the area. Gross capex is currently estimated to be in the range of USD 10 billion, with a corresponding break-even oil price in line with Aker BP's investment criteria of USD 30 dollars per barrel. These estimates will be further refined before the final investment decision which is planned in the fourth quarter 2022.

Sale of shares in Cognite

Cognite is an industrial software company that was co-founded by Aker BP to develop a state-of-the-art data platform to support its digitalization strategy. Aker BP was Cognite's first customer and was instrumental in the development of its main product, Cognite Data Fusion (CDF), which is now a commercial success with many customers across various industries. As such, Aker BP has achieved its objectives for its ownership in Cognite, and in the first quarter, Aker BP entered into an agreement to sell its shares to Saudi Aramco Development Company The NOA Fulla development concept includes a fixed platform at the Frigg Gamma Delta field, operated by Aker BP. The fixed platform, NOA PdQ, will function as an area hub, with processing, drilling, and living quarters. Further, the Frøy field will be re-developed with a normally unmanned installation, as a copy of the Valhall Flank West and the Hod B platforms. The development concept also includes robust and flexible subsea production systems with dual drilling layout for the Fulla, Langfjellet and Rind fields, all tied back to the NOA PdQ. Krafla will be developed with an unmanned production platform and five subsea templates. The Krafla development will be tied back to the NOA PdQ for oil and produced water processing. The NOAKA area will be powered from shore to ensure minimal carbon footprint.

(SADC) for a consideration of USD 118 million. As part of the transaction, Aker BP granted SADC an option with maturity in November 2024 which under certain conditions gives SADC the right to sell the shares back to Aker BP for USD 81 million.

The sale of the shares resulted in a gain of USD 99 million in the first quarter.

EXPLORATION

Total exploration spend in the first quarter was USD 67 (95) million, while USD 58 (83) million was recognised as exploration expenses in the period, relating to dry well costs, seismic, area fees, field evaluation and G&G costs.

The drilling of the Øst Frigg Alfa and Grefsenkollen wells in production licence 873 was completed in the quarter. The former resulted in a minor discovery, while Grefsenkollen was dry. Preliminary estimates for Øst Frigg Alfa place the size of the discovery between 0.6-6.9 million barrels of oil equivalent. Work is ongoing to evaluate the remaining oil potential throughout the entire Øst Frigg field.

HEALTH, SAFETY, SECURITY 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 2022	Q4 2021	Q3 2021	Q2 2021	Q1 2021
Total recordable injury frequency (TRIF) L12M	Per mill. exp. hours	1.8	1.9	1.6	1.2	1.4
Serious incident frequency (SIF) L12M	Per mill. exp. hours	0	0	0	0	0
Acute spill	Count	3	0	0	0	0
Process safety events Tier 1 and 2	Count	0	0	0	0	0
CO2 emissions intensity L12M	Kg CO2/boe	4.8	4.8	4.4	4.2	4.3

The company maintains its systematic and targeted approach to further secure a positive HSSE performance. Mitigating actions to turn the TRIF trend had a positive impact in the first quarter. For the first quarter in isolation, the TRIF was 0.5, reflecting one minor personal injury.

The company experienced three spill incidents during the period. Two of the incidents involved low hydrocarbon discharge volumes of less than 0.2 m3 , while the third incident, caused by a stuck level indicator, led to a discharge of approximately 6 m3 of hydrocarbons. Actions have been taken to correct the root causes and prevent reoccurrence.

Following the omicron outbreak in the beginning of the year, the company re-established its response team for long term events, AKL, to strengthen the prevention of Covid-19 outbreaks offshore and to support our second line emergency

response. Only smaller outbreaks and single cases have been experienced during the first quarter, none with a significant operational impact. The company continues to work systematically to maintain safe and reliable operations the during normalisation period following removal of most of the national regulations in Norway in mid-February.

As previously reported, in September 2019 a discrepancy was identified between Ivar Aasen's reported seawater treatment chemical discharges and the field discharge permit. A subsequent review uncovered a similar incident at Alvheim. The company implemented measures to ensure compliance and to improve its systems for monitoring chemical usage and discharge across all its operated assets. The incidents were reported to the police, and the company has now been fined NOK 1.1 million. The company has accepted the fine.

ACQUISITION OF LUNDIN ENERGY

On 21 December 2021, Aker BP announced a transaction agreement with Lundin Energy AB, pursuant to which Aker BP will acquire Lundin Energy's oil and gas related assets. In return, Lundin Energy's shareholders will receive 0.95098 shares in Aker BP plus a cash consideration of USD 7.76 per share held in Lundin Energy. Lundin Energy's shareholders will also retain shares in Lundin Energy AB, which will remain listed as a renewables company.

The transaction has been approved by the shareholders of both companies at their respective general meetings, which were held on 31 March 2022 for Lundin Energy and 5 April 2022 for Aker BP.

The transaction has also been approved by the Ministry of Petroleum and Energy and by the Norwegian Competition Authority, and the final approval from the Ministry of Finance is expected shortly.

Closing of the transaction is expected to take place 30 June 2022.

OUTLOOK

The world economy is currently in a challenging situation, characterized by global supply chain constraints and high inflation, combined with increased geopolitical tensions following Russia's invasion of Ukraine. This has so far resulted in higher oil and gas prices, but also high volatility and increased uncertainty with regards to the market outlook.

Aker BP has a strong financial position and remains well positioned for future value creation. For 2022, the company's financial plan consists of the following key parameters1 . The numbers relate to Aker BP's current portfolio only, and do not reflect any effects from the Lundin transaction.

• Production of 210-220 mboepd
• Capex of around USD 1.6 billion
• Exploration spend of around USD 400 million
• Abandonment spend of around USD 100 million
• Production cost of around USD 10 per boe
• Dividends of USD 1.9 per share for the full year, to be paid in four quarterly instalments

¹ Most 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 8.5.

FINANCIAL STATEMENTS WITH NOTES

INCOME STATEMENT

		Group
		Q1	Q4	Q1	01.01.-31.03.
(USD 1 000)	Note	2022	2021	2021	2022	2021
Petroleum revenues		2 249 823	1 820 879	1 132 700	2 249 823	1 132 700
Other income		41 466	28 201	537	41 466	537
Total income	2	2 291 288	1 849 080	1 133 238	2 291 288	1 133 238
Production costs	3	220 131	202 374	175 906	220 131	175 906
Exploration expenses	4	57 523	82 620	70 917	57 523	70 917
Depreciation	5	231 125	219 312	257 554	231 125	257 554
Impairments		-	79 016	29 656	-	29 656
Other operating expenses		7 041	5 536	8 225	7 041	8 225
Total operating expenses		515 820	588 858	542 258	515 820	542 258
Operating profit/loss		1 775 468	1 260 222	590 980	1 775 468	590 980
Interest income		1 350	1 441	366	1 350	366
Other financial income		122 898	31 041	9 515	122 898	9 515
Interest expenses		19 732	26 072	47 011	19 732	47 011
Other financial expenses		43 053	49 093	52 717	43 053	52 717
Net financial items	7	61 463	-42 683	-89 846	61 463	-89 846
Profit/loss before taxes		1 836 931	1 217 539	501 134	1 836 931	501 134
Tax expense (+)/income (-)	8	1 300 020	853 509	374 104	1 300 020	374 104
Net profit/loss		536 911	364 030	127 029	536 911	127 029
Weighted average no. of shares outstanding basic and diluted		359 787 854	359 787 854	359 839 591	359 787 854	359 839 591
Basic and diluted earnings/loss USD per share		1.49	1.01	0.35	1.49	0.35

STATEMENT OF COMPREHENSIVE INCOME

	Group
	Q1	Q4	Q1	01.01.-31.03.
Note (USD 1 000)	2022	2021	2021	2022	2021
Profit/loss for the period	536 911	364 030	127 029	536 911	127 029
Items which will not be reclassified over profit and loss (net of taxes) Actuarial gain/loss pension plan	-	-	-	-	-
Total comprehensive income/loss in period	536 911	364 030	127 029	536 911	127 029

STATEMENT OF FINANCIAL POSITION

		Group
(USD 1 000)	Note	31.03.2022	31.12.2021	31.03.2021
ASSETS
Intangible assets
Goodwill	5	1 647 436	1 647 436	1 647 436
Capitalized exploration expenditures	5	198 237	256 535	462 637
Other intangible assets	5	1 390 331	1 407 551	1 416 065
Tangible fixed assets
Property, plant and equipment	5	8 256 944	7 976 308	7 392 321
Right-of-use assets	5	104 054	94 177	126 861
Financial assets
Long-term receivables		74 469	73 346	74 927
Other non-current assets	15	107 731	30 304	29 042
Long-term derivatives	11	2 004	1 375	5 955
Total non-current assets		11 781 206	11 487 032	11 155 243
Inventories
Inventories		120 323	126 442	110 895
Receivables
Trade receivables		394 682	366 785	274 510
Other short-term receivables	9	657 056	500 154	283 742
Short-term derivatives	11	56 401	18 577	24 532
Cash and cash equivalents
Cash and cash equivalents	10	2 816 731	1 970 906	392 276
Total current assets		4 045 194	2 982 863	1 085 955
TOTAL ASSETS		15 826 400	14 469 895	12 241 198

STATEMENT OF FINANCIAL POSITION

	Group
(USD 1 000)	Note	31.03.2022	31.12.2021	31.03.2021
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		-986 604	-1 352 462	-1 705 359
Total equity		2 707 748	2 341 891	1 988 993
Non-current liabilities
Deferred taxes	8	3 477 985	3 323 213	2 781 602
Long-term abandonment provision	14	2 735 529	2 656 358	2 665 343
Long-term bonds	13	3 558 315	3 576 735	3 474 328
Long-term derivatives	11	16 382	2 370	-
Long-term lease debt	6	93 526	91 835	115 299
Other non-current liabilities	15	82 516	-	-
Total non-current liabilities		9 964 252	9 650 511	9 036 572
Current liabilities
Trade creditors		94 026	147 366	83 157
Accrued public charges and indirect taxes		18 829	28 147	18 226
Tax payable	8	2 256 665	1 497 291	452 131
Short-term derivatives	11	27 860	35 082	6 293
Short-term abandonment provision	14	103 131	100 863	87 850
Short-term lease debt	6	42 184	44 378	85 047
Other current liabilities	12	611 704	624 366	482 929
Total current liabilities		3 154 399	2 477 493	1 215 633
Total liabilities		13 118 652	12 128 004	10 252 205
TOTAL EQUITY AND LIABILITIES		15 826 400	14 469 895	12 241 198

STATEMENT OF CHANGES IN EQUITY - GROUP

				Other equity
					Other comprehensive income
(USD 1 000)	Share capital	Share premium	Other paid-in capital	Actuarial gains/losses	Foreign currency translation reserves	Accumulated deficit	Total other equity	Total equity
Equity as of 31.12.2020	57 056	3 637 297	573 083	-76	-115 491	-2 164 587	-1 707 071	1 987 281
Dividend distributed	-	-	-	-	-	-112 500	-112 500	-112 500
Profit/loss for the period	-	-	-	-	-	127 029	127 029	127 029
Purchase of treasury shares	-	-	-	-	-	-12 818	-12 818	-12 818
Equity as of 31.03.2021	57 056	3 637 297	573 083	-76	-115 491	-2 162 875	-1 705 359	1 988 993
Dividends distributed	-	-	-	-	-	-375 000	-375 000	-375 000
Profit for the period	-	-	-	-	-	723 675	723 675	723 675
Purchase/sale of treasury shares	-	-	-	-	-	4 223	4 223	4 223
Other comprehensive income for the period	-	-	-		-	-
Equity as of 31.12.2021	57 056	3 637 297	573 083	-76	-115 491	-1 809 977	-1 352 462	2 341 891
Dividend distributed	-	-	-	-	-	-171 054	-171 054	-171 054
Profit/loss for the period	-	-	-	-	-	536 911	536 911	536 911
Equity as of 31.03.2022	57 056	3 637 297	573 083	-76	-115 491	-1 444 120	-986 604	2 707 748

STATEMENT OF CASH FLOW

				Group
		Q1	Q4	Q1	01.01.-31.03.
(USD 1 000)	Note	2022	2021	2021	2022	2021
CASH FLOW FROM OPERATING ACTIVITIES
Profit/loss before taxes		1 836 931	1 217 539	501 134	1 836 931	501 134
Taxes paid	8	-388 256	-198 475	-	-388 256	-
Taxes refunded	8	-	38 350	11 420	-	11 420
Depreciation	5	231 125	219 312	257 554	231 125	257 554
Impairment		-	79 016	29 656	-	29 656
Accretion expenses	7,14	32 921	28 815	27 668	32 921	27 668
Total interest expenses (excluding amortized loan costs)	7	16 691	23 034	39 638	16 691	39 638
Changes in derivatives	2,7	-31 664	1 444	8 321	-31 664	8 321
Amortized loan costs	7	3 041	3 038	7 372	3 041	7 372
Expensed capitalized dry wells	4,5	39 443	33 243	12 201	39 443	12 201
Changes in inventories, trade creditors and receivables		-75 118	23 164	-5 181	-75 118	-5 181
Changes in other balance sheet items		-289 820	-257 771	10 577	-289 820	10 577
NET CASH FLOW FROM OPERATING ACTIVITIES		1 375 295	1 210 710	900 358	1 375 295	900 358
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields		-16 041	-16 123	-78 576	-16 041	-78 576
Disbursements on investments in fixed assets (excluding capitalized interest)		-335 307	-421 862	-216 162	-335 307	-216 162
Disbursements on investments in capitalized exploration		-48 557	-45 656	-26 978	-48 557	-26 978
Cash received from sale of financial asset	15	118 005	-	-	118 005	-
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-281 900	-483 642	-321 717	-281 900	-321 717
CASH FLOW FROM FINANCING ACTIVITIES
Repayment of bonds		-	-	-514 690	-	-514 690
Interest paid (including interest element of lease payments)		-55 394	-8 444	-62 585	-55 394	-62 585
Payments on lease debt related to investments in fixed assets		-18 130	-18 125	-740	-18 130	-740
Payments on other lease debt		-3 634	-3 071	-20 051	-3 634	-20 051
Paid dividend		-171 054	-150 000	-112 500	-171 054	-112 500
Net purchase/sale of treasury shares		-	-	-12 818	-	-12 818
NET CASH FLOW FROM FINANCING ACTIVITIES		-248 213	-179 640	-723 384	-248 213	-723 384
Net change in cash and cash equivalents		845 183	547 429	-144 742	845 183	-144 742
Cash and cash equivalents at start of period		1 970 906	1 420 783	537 801	1 970 906	537 801
Effect of exchange rate fluctuation on cash held		643	2 694	-783	643	-783
CASH AND CASH EQUIVALENTS AT END OF PERIOD	10	2 816 731	1 970 906	392 276	2 816 731	392 276

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 2021 annual financial statements. The interim financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair statement of the financial position, results of operations and cash flows for the dates and interim periods presented. Interim period results are not necessarily indicative of results of operations or cash flows for an annual period. These interim financial statements have been subject to a review in accordance with the International Standard on Review Engagements 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity.

These interim financial statements were authorised for issue by the company's Board of Directors on 27 April 2022.

Note 1 Accounting principles

The accounting principles used for this interim report are consistent with the principles used in the group's 2021 annual financial statements.

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

The significant judgements made by management in applying the group's accounting policies and the key sources of estimation uncertainty are in all material respects the same as those that applied in the group's 2021 annual financial statements.

Note 2 Income

	Group
	Q1		Q1	01.01.-31.03.
Breakdown of petroleum revenues (USD 1 000)	2022	2021	2021	2022	2021
Sales of liquids	1 553 928	1 199 242	989 511	1 553 928	989 511
Sales of gas	693 134	618 441	139 224	693 134	139 224
Tariff income	2 760	3 195	3 966	2 760	3 966
Total petroleum revenues	2 249 823	1 820 879	1 132 700	2 249 823	1 132 700
Sales of liquids (boe 1 000)	15 403	15 216	16 468	15 403	16 468
Sales of gas (boe 1 000)	4 053	3 649	3 620	4 053	3 620
Other income (USD 1 000)
Realized gain/loss (-) on commodity derivatives	-2 317	-6 638	-3 044	-2 317	-3 044
Unrealized gain/loss (-) on commodity derivatives	38 449	3 432	-2 312	38 449	-2 312
Other income	5 334	31 407	5 893	5 334	5 893
Total other income	41 466	28 201	537	41 466	537

Note 3 Production costs

	Group
	Q1	Q4	Q1	01.01.-31.03.
Breakdown of production cost (USD 1 000)	2022	2021	2021	2022	2021
Cost of operations	150 022	139 544	112 523	150 022	112 523
Shipping and handling	49 688	41 874	47 719	49 688	47 719
Environmental taxes	18 225	10 428	10 834	18 225	10 834
Production cost based on produced volumes	217 935	191 845	171 076	217 935	171 076
Adjustment for over/underlift (-)	2 196	10 529	4 830	2 196	4 830
Production cost based on sold volumes	220 131	202 374	175 906	220 131	175 906
Total produced volumes (boe 1 000)	18 738	19 042	19 999	18 738	19 999
Production cost per boe produced (USD/boe)	11.6	10.1	8.6	11.6	8.6

Note 4 Exploration expenses

	Group
	Q1	Q4	Q1		01.01.-31.03.
Breakdown of exploration expenses (USD 1 000)	2022	2021	2021	2022	2021
Seismic	1 446	3 079	4 213	1 446	4 213
Area fee	4 355	7 067	4 167	4 355	4 167
Field evaluation	4 311	31 218	40 643	4 311	40 643
Dry well expenses1)	39 443	33 243	12 201	39 443	12 201
Other exploration expenses	7 968	8 012	9 693	7 968	9 693
Total exploration expenses	57 523	82 620	70 917	57 523	70 917

1) Dry well expenses in Q1 2022 are mainly related to the Grefsenkollen well

Note 5 Tangible fixed assets and intangible assets

TANGIBLE FIXED ASSETS - GROUP

Property, plant and equipment		Production	Fixtures and
	Assets under	facilities	fittings, office
(USD 1 000)	development	including wells	machinery	Total
Book value 31.12.2020	1 088 754	6 062 384	114 999	7 266 137
Acquisition cost 31.12.2020	1 088 754	9 886 875	241 304	11 216 933
Additions	814 409	620 779	12 750	1 447 938
Disposals/retirement	-	-	-	-
Reclassification	-107 727	428 436	2 395	323 103
Acquisition cost 31.12.2021	1 795 436	10 936 089	256 449	12 987 974
Accumulated depreciation and impairments 31.12.2020	-	3 824 491	126 305	3 950 795
Depreciation	-	832 768	43 440	876 207
Impairment/reversal (-)	-	184 664	-	184 664
Disposals/retirement depreciation	-	-	-	-
Accumulated depreciation and impairments 31.12.2021	-	4 841 922	169 744	5 011 666
Book value 31.12.2021	1 795 436	6 094 167	86 705	7 976 308
Acquisition cost 31.12.2021	1 795 436	10 936 089	256 449	12 987 974
Additions	280 467	133 729	1 743	415 939
Disposals/retirement	-	-	-	-
Reclassification	-17 371	85 681	7 273	75 583
Acquisition cost 31.03.2022	2 058 533	11 155 499	265 464	13 479 496
Accumulated depreciation and impairments 31.12.2021	-	4 841 922	169 744	5 011 666
Depreciation	-	200 894	9 992	210 886
Impairment/reversal (-)	-	-	-	-
Disposals/retirement depreciation	-	-	-	-
Accumulated depreciation and impairments 31.03.2022	-	5 042 817	179 736	5 222 553
Book value 31.03.2022	2 058 533	6 112 682	85 728	8 256 944

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

Right-of-use assets
		Vessels and
(USD 1 000)	Drilling Rigs	Boats	Office	Other	Total
Book value 31.12.2020	41 864	57 395	31 525	1 950	132 735
Acquisition cost 31.12.2020	47 963	62 016	46 427	2 303	158 709
Additions	-	-	5 989	-	5 989
Allocated to abandonment activity	-11 518	-1 941	-	-	-13 458
Disposals/retirement	-	3	-	-	3
Reclassification	-18 034	-2 636	-	-	-20 669
Acquisition cost 31.12.2021	18 412	57 436	52 416	2 303	130 567
Accumulated depreciation and impairments 31.12.2020	6 099	4 620	14 902	353	25 974
Depreciation	-	2 076	8 164	177	10 416
Impairment/reversal (-)	-	-	-	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 31.12.2021	6 099	6 696	23 066	530	36 390
Book value 31.12.2021	12 313	50 740	29 350	1 774	94 177
Acquisition cost 31.12.2021	18 412	57 436	52 416	2 303	130 567
Additions	15 654	-	5 539	-	21 193
Allocated to abandonment activity1)	-	-126	-	-	-126
Disposals/retirement	-	-	-	-	-
Reclassification2)	-7 388	-782	-	-	-8 170
Acquisition cost 31.03.2022	26 678	56 528	57 954	2 303	143 464
Accumulated depreciation and impairments 31.12.2021	6 099	6 696	23 066	530	36 390
Depreciation	-	752	2 223	44	3 019
Impairment/reversal (-)	-	-	-	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 31.03.2022	6 099	7 448	25 289	574	39 410
Book value 31.03.2022	20 579	49 080	32 665	1 729	104 054

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

		Capitalized exploration expenditures	Other intangible assets
(USD 1 000)	Goodwill
Book value 31.12.2020	1 647 436	521 922	1 521 311
Acquisition cost 31.12.2020	2 726 583	668 029	2 368 985
Additions	-	177 443
Disposals/retirement/expensed dry wells	-	98 827	-
Reclassification	-	-302 413	-
Acquisition cost 31.12.2021	2 726 583	444 232	2 368 985
Accumulated depreciation and impairments 31.12.2020	1 079 146	146 107	847 674
Depreciation	-	-	77 459
Impairment/reversal (-)	-	41 589	36 301
Disposals/retirement depreciation	-	-	-
Accumulated depreciation and impairments 31.12.2021	1 079 146	187 696	961 434
Book value 31.12.2021	1 647 436	256 535	1 407 551
Acquisition cost 31.12.2021	2 726 583	444 232	2 368 985
Additions	-	48 557	-
Disposals/retirement/expensed dry wells	-	39 443	-
Reclassification	-	-67 413	-
Acquisition cost 31.03.2022	2 726 583	385 933	2 368 985
Accumulated depreciation and impairments 31.12.2021	1 079 146	187 696	961 434
Depreciation	-	-	17 220
Impairment/reversal (-)	-	-	-
Disposals/retirement depreciation	-	-	-
Accumulated depreciation and impairments 31.03.2022	1 079 146	187 696	978 654
Book value 31.03.2022	1 647 436	198 237	1 390 331

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

	Group
	Q1	Q4	Q1	01.01.-31.03.
Depreciation in the income statement (USD 1 000)	2022	2021	2021	2022	2021
Depreciation of tangible fixed assets	210 886	199 344	232 504	210 886	232 504
Depreciation of right-of-use assets	3 019	2 540	2 595	3 019	2 595
Depreciation of other intangible assets	17 220	17 428	22 455	17 220	22 455
Total depreciation in the income statement	231 125	219 312	257 554	231 125	257 554
Impairment in the income statement (USD 1 000)
Impairment/reversal of tangible fixed assets	-	88 168	-53 135	-	-53 135
Impairment/reversal of other intangible assets	-	-50 741	82 791	-	82 791
Impairment/reversal of capitalized exploration expenditures	-	41 589	-	-	-
Impairment of goodwill	-	-	-	-	-
Total impairment in the income statement	-	79 016	29 656	-	29 656

Note 6 Leasing

The incremental borrowing rate applied in discounting of the nominal lease debt is between 1.8 percent and 6.9 percent, dependent on the duration of the lease and when it was intially recognized.

	2022	2021	2021
(USD 1 000)	Q1	Q1	01.01.-31.12.
Lease debt as of beginning of period	136 213	215 760	215 760
New lease debt recognized in the period	21 192	5 282	5 989
Payments of lease debt1)	-23 815	-24 199	-96 173
Interest expense on lease debt	2 050	3 407	11 558
Currency exchange differences	70	96	-921
Total lease debt	135 711	200 346	136 213
Short-term	42 184	85 047	44 378
Long-term	93 526	115 299	91 835
1) Payments of lease debt split by activities (USD 1 000):
Investments in fixed assets	19 838	861	50 423
Abandonment activity	245	19 778	31 715
Operating expenditures	2 432	1 803	7 499
Exploration expenditures	206	495	1 858
Other income	1 093	1 261	4 678
Total	23 815	24 199	96 173
Nominal lease debt maturity breakdown (USD 1 000):
Within one year	48 451	95 208	51 010
Two to five years	72 924	84 512	68 602
After five years	38 885	55 107	42 837
Total	160 260	234 827	162 448

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 7 Financial items

	Group
	Q1	Q4	Q1		01.01.-31.03.
(USD 1 000)	2022	2021	2021	2022	2021
Interest income	1 350	1 441	366	1 350	366
Realized gains on derivatives	7 453	5 524	9 515	7 453	9 515
Change in fair value of derivatives	10 635	-	-	10 635	-
Net currency gains	6 085	25 517	-	6 085	-
Other financial income1)	98 725	-	-	98 725	-
Total other financial income	122 898	31 041	9 515	122 898	9 515
Interest expenses	30 589	33 221	44 451	30 589	44 451
Interest on lease debt	2 050	2 368	3 407	2 050	3 407
Capitalized interest cost, development projects	-15 948	-12 555	-8 220	-15 948	-8 220
Amortized loan costs	3 041	3 038	7 372	3 041	7 372
Total interest expenses	19 732	26 072	47 011	19 732	47 011
Net currency loss	-	-	4 031	-	4 031
Realized loss on derivatives	7 701	15 010	-	7 701	-
Change in fair value of derivatives	-	4 876	6 008	-	6 008
Accretion expenses	32 921	28 815	27 668	32 921	27 668
Other financial expenses	2 432	392	15 009	2 432	15 009
Total other financial expenses	43 053	49 093	52 717	43 053	52 717
Net financial items	61 463	-42 683	-89 846	61 463	-89 846

1) Related to gain from the sale of shares in Cognite during Q1 2022 (see note 15)

Note 8 Tax

	Group
	Q1	Q4	Q1		01.01.-31.03.
Tax for the period (USD 1 000)	2022	2021	2021	2022	2021
Current year tax payable/receivable	1 168 289	667 609	228 646	1 168 289	228 646
Change in current year deferred tax	128 653	181 180	141 355	128 653	141 355
Prior period adjustments	3 077	4 720	4 103	3 077	4 103
Tax expense (+)/income (-)	1 300 020	853 509	374 104	1 300 020	374 104

	Group
	2022	2021	2021
Calculated tax payable (-)/tax receivable (+) (USD 1 000)	Q1	Q1	01.01.-31.12.
Tax payable/receivable at beginning of period	-1 497 291	-163 352	-163 352
Current year tax payable/receivable	-1 168 289	-228 646	-1 526 236
Net tax payment/refund	388 256	-11 420	223 166
Prior period adjustments and change in estimate of uncertain tax positions	22 273	-48 390	-57 165
Currency movements of tax payable/receivable	-1 615	-323	26 297
Net tax payable (-)/receivable (+)	-2 256 665	-452 131	-1 497 291

	Group
	2022	2021	2021
Deferred tax liability (-)/asset (+) (USD 1 000)	Q1	Q1	01.01.-31.12.
Deferred tax liability/asset at beginning of period	-3 323 213	-2 642 461	-2 642 461
Change in current year deferred tax	-128 653	-141 355	-684 723
Prior period adjustments	-26 118	2 214	3 971
Deferred tax charged to OCI and equity	-	-	-
Net deferred tax liability (-)/asset (+)	-3 477 985	-2 781 602	-3 323 213

			Group
	Q1	Q4	Q1		01.01.-31.03.
Reconciliation of tax expense (USD 1 000)	2022	2021	2021	2022	2021
78 % tax rate on profit/loss before tax	1 432 806	949 681	390 884	1 432 806	390 884
Tax effect of uplift	-44 780	-79 880	-48 564	-44 780	-48 564
Permanent difference on impairment	-	-39 691	-1 320	-	-1 320
Foreign currency translation of monetary items other than USD	-4 861	-19 768	2 397	-4 861	2 397
Foreign currency translation of monetary items other than NOK	6 222	14 950	9 354	6 222	9 354
Tax effect of financial and other 22 % items	-69 785	8 971	18 588	-69 785	18 588
Currency movements of tax balances1)	-2 502	8 441	-3 600	-2 502	-3 600
Other permanent differences, prior period adjustments and change in estimate of	-17 081	10 805	6 365	-17 081	6 365
uncertain tax positions
Tax expense (+)/income (-)	1 300 020	853 509	374 104	1 300 020	374 104

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 group's functional currency is USD.

Note 9 Other short-term receivables

	Group
(USD 1 000)	31.03.2022	31.12.2021	31.03.2021
Prepayments	45 310	45 429	63 972
VAT receivable	6 512	13 354	7 326
Underlift of petroleum	20 851	36 944	40 584
Accrued income from sale of petroleum products	496 875	290 254	80 843
Other receivables, mainly balances with license partners	87 508	114 172	91 018
Total other short-term receivables	657 056	500 154	283 742

Note 10 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)	31.03.2022	31.12.2021	31.03.2021
Bank deposits	2 816 731	1 970 906	392 276
Cash and cash equivalents	2 816 731	1 970 906	392 276
Unused RCF facility	3 400 000	3 400 000	4 000 000

The RCF is undrawn as at 31 March 2022 and the remaining unamortized fees of USD 13.7 million related to the facility are therefore included in other non-current assets.

The senior unsecured Revolving Credit Facility (RCF) was established in May 2019 and consist of two tranches. A Working Capital Facility with a committed amount of USD 1.4 billion and a Liquidity Facility with a committed amount of USD 2.0 billion until 2025 and USD 1.65 billion for the final year. The Working Capital Facility is due in 2025 with option for one year extension and the Liquidity Facility is due in 2026. The interest rate is LIBOR plus a margin of 1.25 percent for the Working Capital Facility and 1.00 percent for the Liquidity Facility. Drawing under the Liquidity Facility will add a utilization fee. A commitment fee of 35 percent of applicable margin is paid on the undrawn part of the facility. The financial covenants are as follows:

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

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

The financial covenants are calculated on a 12 months rolling basis. As at 31 March 2022 the Leverage Ratio is 0.12 and Interest Coverage Ratio is 38.6 (see APM section for further details), which are well within the thresholds mentioned above. Based on the group's current business plans and applying oil and gas price forward curves at end of Q1 2022, the group's estimates show that the financial covenants will continue to comply with the covenants by a substantial margin.

The financial covenants in the group's current debt facilities exclude the effects from IFRS 16, and therefore cannot be directly derived from the group's financial statements. See reconciliations of Alternative Performance Measures for detailed information.

Note 11 Derivatives

		Group
(USD 1 000)	31.03.2022	31.12.2021	31.03.2021
Unrealized gain currency contracts	2 004	1 375	5 513
Unrealized gain commodity derivatives		-	442
Long-term derivatives included in assets	2 004	1 375	5 955
Unrealized gain commodity derivatives	38 650	-	-
Unrealized gain currency contracts	17 751	18 577	24 532
Short-term derivatives included in assets	56 401	18 577	24 532
Total derivatives included in assets	58 405	19 952	30 487
Fair value of option related to sale of Cognite1)	15 995	-	-
Unrealized losses currency contracts	387	2 370	-
Long-term derivatives included in liabilities	16 382	2 370	-
Unrealized losses commodity derivatives	9 190	8 989	6 293
Unrealized losses currency contracts	18 670	26 094	-
Short-term derivatives included in liabilities	27 860	35 082	6 293
Total derivatives included in liabilities	44 242	37 452	6 293

1) See note 15

The group uses various types of financial hedging instruments. Commodity derivatives are used to hedge the price risk of oil and gas, foreign exchange derivatives to hedge the group's currency exposure, mainly in NOK, EUR and GBP, and interest rate derivatives to hedge volatility in interest rates.

The derivative portfolio is revaluated on a mark to market basis, with changes in value recognized in the income statement. In Q1 2022 the company entered into certain natural gas futures contracts to hedge its gas price exposure. In addition, the company has granted a put option in relation to the sale of shares in Cognite, as described in note 15. Except for these new elements, the nature of the derivative instruments and the valuation method are consistent with the disclosed information in the annual financial statements as of 31 December 2021.

As of 31 March 2022, the company has commodity contracts to protect downside price risk of oil and gas, and foreign exchange contracts to secure USD value of NOK cashflows.

Note 12 Other current liabilities

	Group
Breakdown of other current liabilities (USD 1 000)	31.03.2022	31.12.2021	31.03.2021
Balances with license partners	51 183	48 456	14 810
Share of other current liabilities in licenses	355 966	311 694	250 378
Overlift of petroleum	26 146	40 044	3 207
Payroll liabilities, accrued interest and other provisions	178 408	224 173	214 535
Total other current liabilities	611 704	624 366	482 929

Note 13 Bonds

		Group
Senior unsecured bonds (USD 1 000)	Maturity	31.03.2022	31.12.2021	31.03.2021
AKERBP – USD Senior Notes 4.750% (19/24)	Jun 2024	-	-	743 806
AKERBP – USD Senior Notes 3.000% (20/25)	Jan 2025	497 514	497 295	496 636
AKERBP – USD Senior Notes 2.875% (20/26)	Jan 2026	497 280	497 103	496 571
AKERBP – EUR Senior Notes 1.125% (21/29)	May 2029	824 836	843 995	-
AKERBP – USD Senior Notes 3.750% (20/30)	Jan 2030	993 819	993 622	993 030
AKERBP – USD Senior Notes 4.000% (20/31)	Jan 2031	744 866	744 720	744 285
Long-term bonds - book value		3 558 315	3 576 735	3 474 328
Long-term bonds - fair value		3 469 031	3 752 778	3 619 250

Interest is paid on a semi annual basis, except for the EUR Senior Notes which is paid on an annual basis. None of the bonds have financial covenants.

Note 14 Provision for abandonment liabilities

	Group
	2022	2021	2021
(USD 1 000)	Q1	Q1	01.01.-31.12.
Provisions as of beginning of period	2 757 221	2 805 507	2 805 507
Incurred removal cost	-16 168	-86 896	-185 973
Accretion expense	32 921	27 668	113 748
Impact of changes to discount rate	-	-	-340 973
Change in estimates and provisions relating to new drilling and installations	64 685	6 914	364 912
Total provision for abandonment liabilities	2 838 659	2 753 193	2 757 221
Short-term	103 131	87 850	100 863
Long-term	2 735 529	2 665 343	2 656 358

Estimates are based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The calculations assume an inflation rate of 2.0 percent and a nominal discount rate before tax of between 3.7 percent and 5.2 percent. The credit margin included in the discount rate is 3.3 percent.

Note 15 Sale of shares in Cognite

In Q1 the company sold its shares in Cognite AS to Saudi Aramco Development Company for a consideration of USD 118 million. As part of the transaction, Aker BP has granted the buyer an option with maturity in November 2024 which under certain conditions gives the buyer the right to sell the shares back to Aker BP for USD 81 million. On this basis, Aker BP is considered to have continuing involvement in Cognite AS, in accordance with guidelines in IFRS 9. Hence, both an asset and a liability of USD 81 million is recognized in the statement of financial position at 31 March 2022.

In addition, the option is recognized as a liability and measured at fair value through the income statement. The valuation is considered level 3 in the fair value hierarchy due to the significance of unobservable market data in the valuation.

Note 16 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 17 Subsequent events

The group has not identified any events with significant accounting impacts that have occured between the end of the reporting period and the date of this report.

Note 18 Investments in joint operations

Total number of licenses	31.03.2022	31.12.2021
Aker BP as operator	81	80
Aker BP as partner	45	44

Changes in production licenses in which Aker BP is the operator:			Changes in production licenses in which Aker BP is a partner:
License:	31.03.2022	31.12.2021 License:		31.03.2022	31.12.2021
PL8582)	0.000%		40.000 % PL127B2)	0.000%	50.000 %
PL914S2)	0.000%		34.786 % PL272C1)	50.000%	0.000 %
PL941B1)	80.000%	0.000 % PL7222)		0.000%	20.000 %
PL9862)	0.000%	50.000 % PL8922)		0.000%	30.000 %
PL10262)	0.000%	40.000 % PL9812)		0.000%	40.000 %
PL10282)	0.000%	50.000 % PL10522)		0.000%	20.000 %
PL10472)	0.000%	40.000 % PL10542)		0.000%	30.000 %
PL11411)	70.000%		0.000 % PL10692)	0.000%	50.000 %
PL11421)	73.010%		0.000 % PL11401)	40.000%	0.000 %
PL11431)	73.010%		0.000 % PL11451)	40.000%	0.000 %
PL11441)	40.000%		0.000 % PL11491)	30.000%	0.000 %
PL11531)	40.000%		0.000 % PL11511)	20.000%	0.000 %
PL11581)	40.000%		0.000 % PL11541)	30.000%	0.000 %
			PL11631)	20.000%	0.000 %
			PL11651)	40.000%	0.000 %
Total	7		6 Total	8	7

1) Interest awarded in the APA Licensing round

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

Note 19 Selected historical interim information

	2022		2021
(USD 1 000)	Q1	Q4	Q3	Q2	Q1
Total income	2 291 288	1 849 080	1 562 675	1 123 754	1 133 238
Production costs	220 131	202 374	208 798	158 235	175 906
Exploration expenses	57 523	82 620	97 477	102 020	70 917
Depreciation	231 125	219 312	246 846	240 372	257 554
Impairments	-	79 016	153 881	-	29 656
Other operating expenses	7 041	5 536	6 534	8 965	8 225
Total operating expenses	515 820	588 858	713 537	509 592	542 258
Operating profit/loss	1 775 468	1 260 222	849 138	614 162	590 980
Net financial items	61 463	-42 683	-47 444	-61 744	-89 846
Profit/loss before taxes	1 836 931	1 217 539	801 694	552 418	501 134
Tax expense (+)/income (-)	1 300 020	853 509	595 860	398 607	374 104
Net profit/loss	536 911	364 030	205 834	153 811	127 029

	2022		2021
(boe 1 000)	Q1	Q4	Q3	Q2	Q1
Sold volumes
Liquids Gas	15 403 4 053	15 216 3 649	16 892 3 787	14 871 2 879	16 468 3 620

	2022	2021
(USD 1 000)	Q1	Q4	Q3	Q2	Q1
Assets
Goodwill	1 647 436	1 647 436	1 647 436	1 647 436	1 647 436
Other intangible assets	1 588 568	1 664 086	1 778 753	1 873 199	1 878 702
Property, plant and equipment	8 256 944	7 976 308	7 666 727	7 630 389	7 392 321
Right-of-use asset	104 054	94 177	105 248	115 705	126 861
Receivables and other assets	1 412 666	1 116 982	963 070	833 760	803 603
Cash and cash equivalents	2 816 731	1 970 906	1 420 783	975 360	392 276
Total assets	15 826 400	14 469 895	13 582 017	13 075 850	12 241 198
Equity and liabilities
Equity	2 707 748	2 341 891	2 127 860	2 030 304	1 988 993
Other provisions for liabilities incl. P&A (long)	2 834 426	2 658 728	2 639 476	2 680 537	2 665 343
Deferred tax	3 477 985	3 323 213	3 142 033	3 050 315	2 781 602
Bonds and bank debt	3 558 315	3 576 735	3 594 939	3 614 833	3 474 328
Lease debt	135 711	136 213	157 641	178 980	200 346
Other current liabilities incl. P&A	855 550	935 825	929 586	923 494	678 456
Tax payable	2 256 665	1 497 291	990 482	597 387	452 131
Total equity and liabilities	15 826 400	14 469 895	13 582 017	13 075 850	12 241 198

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)

Capex is disbursements on investments in fixed assets1)

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

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

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

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

Equity ratio is total equity divided by total assets

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

Interest coverage ratio is calculated as twelve months rolling EBITDA, divided by interest expenses, excluding any impacts from IFRS 16.

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

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

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

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

1) Includes payments of lease debt as disclosed in note 6.

		Q1	Q4	Q1	01.01.-31.03.	01.01.-31.12.
(USD 1 000)	Note	2022	2021	2021	2022	2021
Abandonment spend
Payment for removal and decommissioning of oil fields		16 041	16 123	78 576	16 041	172 512
Payments of lease debt (abandonment activity)	6	245	203	19 778	245	31 715
Abandonment spend		16 287	16 326	98 354	16 287	204 227
Depreciation per boe
Depreciation	5	231 125	219 312	257 554	231 125	964 083
Total produced volumes (boe 1 000)	3	18 738	19 042	19 999	18 738	76 439
Depreciation per boe		12.3	11.5	12.9	12.3	12.6
Dividend per share
Paid dividend		171 054	150 000	112 500	171 054	487 500
Number of shares outstanding		359 788	359 788	359 840	359 788	359 643
Dividend per share		0.48	0.42	0.31	0.48	1.36
Capex
Disbursements on investments in fixed assets (excluding capitalized interest)		335 307	421 862	216 162	335 307	1 376 879
Payments of lease debt (investments in fixed assets)	6	19 838	20 150	861	19 838	50 423
CAPEX		355 145	442 012	217 023	355 145	1 427 302
EBITDA
Total income	2	2 291 288	1 849 080	1 133 238	2 291 288	5 668 747
Production costs	3	-220 131	-202 374	-175 906	-220 131	-745 313
Exploration expenses	4	-57 523	-82 620	-70 917	-57 523	-353 034
Other operating expenses		-7 041	-5 536	-8 225	-7 041	-29 261
EBITDA		2 006 594	1 558 550	878 190	2 006 594	4 541 139
EBITDAX
Total income	2	2 291 288	1 849 080	1 133 238	2 291 288	5 668 747
Production costs	3	-220 131	-202 374	-175 906	-220 131	-745 313
Other operating expenses		-7 041	-5 536	-8 225	-7 041	-29 261
EBITDAX		2 064 117	1 641 170	949 107	2 064 117	4 894 173
Equity ratio
Total equity		2 707 748	2 341 891	1 988 993	2 707 748	2 341 891
Total assets		15 826 400	14 469 895	12 241 198	15 826 400	14 469 895
Equity ratio		17%	16%	16%	17%	16%
Exploration spend
Disbursements on investments in capitalized exploration expenditures		48 557	45 656	26 978	48 557	177 464
Exploration expenses	4	57 523	82 620	70 917	57 523	353 034
Dry well	4	-39 443	-33 243	-12 201	-39 443	-98 827
Payments of lease debt (exploration expenditures)	6	206	227	495	206	1 858
Exploration spend		66 843	95 260	86 190	66 843	433 529

		Q1	Q4	Q1	01.01.-31.03.	01.01.-31.12.
(USD 1 000)	Note	2022	2021	2021	2022	2021
Interest coverage ratio
Twelve months rolling EBITDA	19	5 669 543	4 541 139	2 340 418	5 669 543	4 541 139
Twelve months rolling EBITDA, impacts from IFRS 16	6	-14 207	-14 035	-22 535	-14 207	-14 035
Twelve months rolling EBITDA, excluding impacts from IFRS 16		5 655 336	4 527 104	2 317 883	5 655 336	4 527 104
Twelve months rolling interest expenses	7	131 790	145 651	185 958	131 790	145 651
Twelve months rolling amortized loan cost	7	18 128	22 460	22 149	18 128	22 460
Twelve months rolling interest income	7	3 465	2 481	2 760	3 465	2 481
Net interest expenses		146 453	165 630	205 347	146 453	165 630
Interest coverage ratio		38.6	27.3	11.3	38.6	27.3
Leverage ratio
Long-term bonds	13	3 558 315	3 576 735	3 474 328	3 558 315	3 576 735
Cash and cash equivalents	10	2 816 731	1 970 906	392 276	2 816 731	1 970 906
Net interest-bearing debt excluding lease debt		741 584	1 605 829	3 082 052	741 584	1 605 829
Twelve months rolling EBITDAX	19	6 009 183	4 894 173	2 535 098	6 009 183	4 894 173
Twelve months rolling EBITDAX, impacts from IFRS 16	6	-12 638	-12 177	-21 387	-12 638	-12 177
Twelve months rolling EBITDAX, excluding impacts from IFRS 16		5 996 545	4 881 996	2 513 711	5 996 545	4 881 996
Leverage ratio		0.12	0.33	1.23	0.12	0.33
Net interest-bearing debt
Long-term bonds	13	3 558 315	3 576 735	3 474 328	3 558 315	3 576 735
Long-term lease debt	6	93 526	91 835	115 299	93 526	91 835
Short-term lease debt	6	42 184	44 378	85 047	42 184	44 378
Cash and cash equivalents	10	2 816 731	1 970 906	392 276	2 816 731	1 970 906
Net interest-bearing debt		877 294	1 742 042	3 282 398	877 294	1 742 042

Operating profit/loss see Income Statement

Production cost per boe see note 3

KPMG AS Sørkedalsveien 6 Postboks 7000 Majorstuen 0306 Oslo

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

To the Board of Directors of Aker BP ASA

Independent Auditors' Report on Review of Interim Financial Information

Introduction

We have reviewed the accompanying condensed consolidated statement of financial position of Aker BP ASA as at 31 March 2022 and the related condensed consolidated income statement, condensed consolidated statement of cash flow and condensed consolidated statement of changes in equity for the three-month period ended 31 March 2022 and notes to the condensed consolidated interim financial information (the "condensed consolidated interim financial statements").

Management is responsible for the preparation and presentation of these condensed consolidated interim financial statements in accordance with International Accounting Standard 34, Interim Financial Reporting as adopted by the EU. Our responsibility is to express a conclusion on these condensed consolidated interim financial statements based on our review.

Scope of Review

We conducted our review in accordance with the International Standard on Review Engagements 2410, Review of Interim Financial Information Performed by the Independent Auditor of the Entity.

A review of interim financial statements consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing, and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the accompanying condensed consolidated interim financial statements are not prepared, in all material respects, in accordance with International Accounting Standard 34, Interim Financial Reporting as adopted by the EU.

Other matters

Our report does not extend to the summary financial information for interim periods included in Note 19 which is not a required disclosure under International Accounting Standard 34 Interim Financial Reporting as adopted by the EU.

Oslo, 27 April 2022

KPMG AS

Roland Fredriksen State Authorised Public Accountant (Norway)

lo	Elverum	Mo i Rana	Stord
ą	Finnsnes	Molde	Straume
endal	Hamar	Skien	Tromsø
rgen	Haugesund	Sandefjord	Trondheim
dø	Knarvik	Sandnessjøen	Tynset
ammen	Kristiansand	Stavanger	Ålesund

34 · Aker BP Quarterly Report · Q1 2022

Aker BP ASA

Fornebuporten, Building B Oksenøyveien 10 1366 Lysaker

www.akerbp.com

CONTACT

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

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