Aker BP

Quarterly Report • Apr 27, 2023

QUARTERLY REPORT Q1 2023

FIRST QUARTER 2023 RESULTS

Aker BP delivered strong operational and financial performance in the first quarter 2023, with record production, low unit costs and high cash flow. All field development projects are on track, and the company further strengthened its position as a global leader within low carbon oil and gas production.

Highlights for the quarter

(Numbers in brackets represent the previous quarter)

• New production record of 453 (432) mboepd, driven by continued ramp-up of Johan Sverdrup Phase 2
• Production cost per boe at USD 7.2 (7.2), in line with 2023 guidance of USD 7-8 per boe
• Industry-leading GHG emissions intensity further reduced to 2.9 (3.2) kg CO2e per boe
• Field development projects on track, with detailed engineering and procurement ongoing and major contracts placed
• Operating profit of USD 1,961 (2,214) million, Net profit of USD 187 (112) million and Free cash flow of USD 977 (98) million
• Quarterly dividend of USD 0.55 per share

Comment from Karl Johnny Hersvik, CEO of Aker BP:

"It is a true pleasure to report yet another strong quarter for Aker BP. We produced more oil and gas than ever, at low costs, and with the lowest GHG emissions intensity in the oil and gas industry. This is the result of a strong team and a dedicated effort over years to develop a culture for operational excellence and continuous improvement in the company.

I am also pleased to report that our field developments are progressing as planned, including the new projects launched in December where we are well underway with procurement and detailed engineering. Through the Aker BP alliance model, we have established strong relations and close cooperation with our key suppliers, and I am confident that we are well prepared to deliver these projects on time and on budget.

Going forward, our priorities are the same as always. We will operate our assets with high efficiency, we will deliver our growth projects as planned, and we will never stop driving improvements in everything we do. This is our recipe for creating shareholder value."

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 restated.

Key figures

	UNIT	Q1 2023	Q4 2022	Q1 2022 RESTATED
INCOME STATEMENT
Total income	USD million	3 310	3 826	2 291
EBITDA	USD million	2 933	3 491	2 007
Net profit/loss	USD million	187	112	522
Earnings per share (EPS)	USD	0.30	0.18	1.45
OTHER FINANCIAL KEY FIGURES
Net interest-bearing debt	USD million	2 370	2 658	877
Leverage ratio		0.16	0.21	0.12
Dividend per share	USD	0.55	0.53	0.48
PRODUCTION AND SALES
Net petroleum production	mboepd	452.7	432.0	208.2
Over/underlift	mboepd	(3.1)	(3.7)	8.0
Net sold volume	mboepd	449.6	428.3	216.2
- Liquids	mboepd	384.1	362.2	171.1
- Natural gas	mboepd	65.5	66.0	45.0
REALISED PRICES
Liquids	USD/boe	78.4	86.6	100.9
Natural gas	USD/boe	98.7	150.4	171.0
AVERAGE EXCHANGE RATES
USDNOK		10.24	10.18	8.85
EURUSD		1.07	1.02	1.12

FINANCIAL REVIEW

Income statement

(USD MILLION)	Q1 2023	Q4 2022	Q1 2022 RESTATED
Total income	3 310	3 826	2 291
EBITDA	2 933	3 491	2 007
EBIT	1 961	2 214	1 707
Pre-tax profit	1 824	2 177	1 780
Net profit/loss	187	112	522
EPS (USD)	0.30	0.18	1.45

The company changed its accounting principle for abandonment provisions in the fourth quarter 2022. The change is related to the discount rate applied in the calculation which will now consist of a risk-free rate only, while it historically has included a credit risk element. This contributes to an increase in the book value of the abandonment provisions and the corresponding assets and leads to higher depreciation. In the fourth quarter 2022, the company also revised its accounting policy related to deferred tax on capitalised interests, increasing the applied deferred tax rate from 22 to 78 percent. Prior periods have been restated accordingly.

Total income in the first quarter amounted to USD 3,310 (3,826) million. The main driver for the reduction was lower oil and gas prices, partly offset by an increase in volume sold. Realised liquids prices decreased by nine percent to USD 78.4 (86.6) per boe and realised natural gas price decreased by 34 percent to USD 98.7 (150.4) per boe. Sold volumes increased by five percent to 449.6 (428.3) mboepd in the quarter.

Production expenses for the oil and gas sold in the quarter amounted to USD 263 (286) million, with change in over/ underlift as the main reason for the reduction from last quarter. The average production cost per barrel produced was stable at USD 7.2 (7.2). See note 3 for further details on production expenses. Exploration expenses amounted to USD 98 (32) million, with dry well expenses as the main reason for the increase.

Depreciation amounted to USD 599 (641) million, corresponding to USD 14.7 (16.1) per barrel of oil equivalent. The decrease is driven amongst other by reduced abandonment provision at year end and change in the relative production between the fields, partly offset by higher production.

Impairments amounted to USD 373 (636) million. This was mainly driven by the previously announced termination of the Troldhaugen project and by reduced short term forward prices leading to an impairment of technical goodwill allocated to the Edvard Grieg & Ivar Aasen CGU. Further information about impairment is provided in note 5.

Operating profit was USD 1,961 (2,214) million for the first quarter.

Net financial expenses increased to USD 137 (37) million, mainly caused by loss on currency derivatives driven by the strengthened USD against NOK. For more details, see note 8.

Profit before taxes amounted to USD 1,824 (2,177) million. Tax expense was USD 1,637 (2,064) million. The effective tax rate was 90 (95) percent, impacted by the impairment of technical goodwill with no effect on deferred tax. This resulted in a net profit of USD 187 (112) million.

Other comprehensive income

During the second half of 2022, the merger process with the previous Lundin entities was completed. These entities had other functional currency than USD which gave rise to significant currency translation elements in the group consolidation. From 1 January 2023 the activity in the previous Lundin entities is carried out in Aker BP ASA and the mentioned impact on comprehensive income is thus no longer present.

Balance sheet

(USD MILLION)	31.03.2023	31.12.2022	31.03.2022 RESTATED
Goodwill	13 636	13 935	1 647
Property, plant and equipment (PP&E)	16 220	15 887	10 370
Other non-current assets	3 122	2 984	1 877
Cash and equivalent	3 280	2 756	2 817
Other current assets	1 671	2 000	1 228
Total assets	37 928	37 562	17 940
Equity	12 267	12 428	2 547
Bank and bond debt	5 304	5 279	3 558
Other long-term liabilities	14 184	13 607	8 680
Tax payable	4 758	5 084	2 257
Other current liabilities	1 416	1 164	898
Total equity and liabilities	37 928	37 562	17 940
Net interest-bearing debt	2 370	2 658	877
Leverage ratio	0.16	0.21	0.12

At the end of the first quarter 2023, total assets amounted to USD 37.9 (37.6) billion, of which non-current assets were USD 33.0 (32.8) billion.

Equity amounted to USD 12.3 (12.4) billion at the end of the quarter, corresponding to an equity ratio of 32 (33) percent.

Bond debt totalled USD 5.3 (5.3) billion, and the company's bank facilities were not drawn. Other long-term liabilities amounted to USD 14.2 (13.6) billion.

Tax payable decreased by USD 326 million to 4,758 (5,084) million.

At the end of the first quarter 2023, the company had total available liquidity of USD 6.7 (6.2) billion, comprising of USD 3.3 (2.8) billion in cash and cash equivalents and USD 3.4 (3.4) billion in undrawn credit facilities.

Cash flow

(USD MILLION)	Q1 2023	Q4 2022	Q1 2022
Cash flow from operations	1 682	807	1 375
Cash flow from investments	(705)	(708)	(282)
Cash flow from financing	(454)	(329)	(248)
Net change in cash & cash equivalents	523	(231)	845
Cash and cash equivalents	3 280	2 756	2 817

Net cash flow from operating activities was USD 1,682 (807) million in the quarter. Taxes paid amounted to USD 1,569 (2,955) million. Net cash used for investment activities was USD 705 (708) million, of which investments in fixed assets amounted to USD 597 (570) million for the quarter.

Investments in capitalised exploration were USD 79 (38) million. Payments for decommissioning activities amounted to USD 29 (19) million.

Net cash outflow from financing activities was USD 454 (329) million. The main items were dividend disbursements of USD 348 (332) million and interest payments (including interest element of lease payments) of USD 78 (4) million.

Dividends

The Annual General Meeting has authorised the Board to approve the distribution of dividends pursuant to section 8-2 (2) of the Norwegian Public Limited Companies Act.

During the first quarter 2023, the company paid a dividend of USD 0.55 per share. On 26 April 2023, the Board resolved to pay a quarterly dividend of USD 0.55 per share in the second quarter 2023, which will be disbursed on or about 11 May 2023. The ex-dividend date is 3 May 2023.

Hedging

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

The company had no significant commodity derivatives exposure per 31 March 2023.

OPERATIONAL REVIEW

Aker BP's net production was 40.7 (39.7) mmboe in the first quarter 2023, corresponding to 452.7 (432.0) mboepd. Net sold volume was 449.6 (428.3) mboepd.

Alvheim Area

KEY FIGURES	AKER BP INTEREST*	Q1 2023	Q4 2022	Q3 2022	Q2 2022	Q1 2022
Production, mboepd
Alvheim	80% (65%)	32.3	35.3	38.1	35.3	34.7
Bøyla (incl. Frosk)	80% (65%)	4.6	3.3	1.8	1.3	1.6
Skogul	65%	1.3	1.6	1.9	2.5	2.4
Vilje	46.904%	1.8	2.2	1.9	2.0	2.1
Volund	100% (65%)	2.8	3.5	5.7	2.8	4.6
Total production		42.8	45.8	49.4	43.8	45.3
Production efficiency		98 %	99 %	100 %	97 %	98 %

*Production prior to the third quarter 2022 does not incorporate production related to Lundin Energy's ownership shares in the area. Aker BP's interest prior to the third quarter 2022 is presented in brackets.

Production from the Alvheim area was 42.8 mboepd net to Aker BP, down from the previous quarter due to natural decline which was partly offset by Frosk which started production in March. Production efficiency remained strong at 98 percent.

The lifetime extension project for the Alvheim FPSO is progressing as planned. The purpose is to prolong the lifetime to 2040. The project upgraded the turbine generator control system in the first quarter.

The Frosk development project was successfully completed, and production started in March. The project was delivered on schedule and within budget, only 18 months after the Plan for Development and Operation (PDO) was submitted.

The Kobra East & Gekko (KEG) project is on track. The 4-well drilling campaign commenced in January and has progressed ahead of schedule. Production start is planned for first quarter 2024.

The Tyrving project (previously known as Trell and Trine) is progressing according to plan. Fabrication is ongoing on several locations and preparations are underway for the pipelay campaign later in 2023. Drilling of the three Tyrving wells is expected to commence in the first half of 2024 with production start in 2025.

Edvard Grieg & Ivar Aasen

KEY FIGURES	AKER BP INTEREST*	Q1 2023	Q4 2022	Q3 2022	Q2 2022	Q1 2022
Production, mboepd
Edvard Grieg Area	65% (0%)	71.8	86.1	84.8	-	-
Ivar Aasen	36.1712% (34.7862%)	12.6	13.6	14.2	7.0	14.0
Total production		84.3	99.7	99.0	7.0	14.0
Production efficiency		87 %	99 %	99 %	52 %	87 %

*Production prior to the third quarter 2022 does not incorporate production related to Lundin Energy's ownership shares in the area. Aker BP's interest prior to the third quarter 2022 is presented in brackets.

Production from Edvard Grieg & Ivar Aasen was 84.3 mboepd in the first quarter, down from the previous quarter due to six days unplanned shut-down related to power and processing outage. For the same reasons production efficiency was also reduced to 87 percent for the quarter.

At Ivar Aasen, the 2022 IOR campaign was completed in December and all three wells started producing in the first quarter. The Edvard Grieg IOR campaign for 2023 is progressing as planned with expected first oil late in the second quarter.

The Hanz project is progressing according to plan. First oil is expected in first quarter 2024.

The Utsira High Project is progressing as planned with detail engineering and procurement ongoing. The project consists of two separate subsea tie-in projects. Symra (previously named

Lille Prinsen) will be a tie-in to the Ivar Aasen platform, while Solveig phase 2 will be connected to the Edvard Grieg platform. Drilling will commence in third quarter 2025, while production start-up is scheduled for first quarter 2026 for Solveig and first quarter 2027 for Symra. Gross recoverable resources are estimated to 85 million barrels oil equivalent, and total investments are estimated to approximately NOK 16 billion in real terms. Aker BP is the operator for both developments.

The Troldhaugen development, which was also previously included in the Utsira High Project, was discontinued in the first quarter. As previously communicated, the Troldhaugen development was subject to the performance of an extended well test (EWT). The EWT resulted in a reduction of the expected recoverable volumes and consequently the project was no longer considered to have sufficient financial robustness.

Johan Sverdrup

KEY FIGURES	AKER BP INTEREST*	Q1 2023	Q4 2022	Q3 2022	Q2 2022	Q1 2022
Production, mboepd
Total production	31.5733% (11.5733%)	215.7	180.6	162.0	57.9	62.9

*Production prior to the third quarter 2022 does not incorporate production related to Lundin Energy's ownership shares in Johan Sverdrup. Aker BP's interest prior to the third quarter 2022 is presented in brackets.

Johan Sverdrup produced safely and with high production efficiency in the first quarter.

Production from the Phase 2 development was ramped up to the full field facilities design capacity of 720 mbblpd. Implementation of measures and planning of further testing to increase this capacity to 755 mbblpd is ongoing.

Production started successfully from two new wells through the Phase 2 subsea template. In addition, two new wells started producing from the existing field centre, bringing the total number of producing wells up to 23.

Skarv Area

KEY FIGURES	AKER BP INTEREST	Q1 2023	Q4 2022	Q3 2022	Q2 2022	Q1 2022
Production, mboepd
Total production	23.835 %	41.8	41.6	42.1	38.9	34.6
Production efficiency		99 %	97 %	97 %	90 %	86 %

Skarv produced safely with stable rates at 41.8 mboepd. Production efficiency was record high at 99 percent.

Plan for Development and Operations (PDO) for three separate developments in the Skarv area was submitted to the Norwegian Ministry of Petroleum and Energy in December. The developments, coordinated by the Skarv Satellite Project (SSP), consist of the gas and condensate discoveries Alve Nord, Idun Nord and Ørn. These projects are estimated to bring approximately 120 million barrels of oil equivalents (gross)

through Skarv FPSO from 2027. The SSP project has now entered the execution phase, with detailed engineering and procurement ongoing. Drilling is planned to commence in 2025.

The Skarv partnership has approved equipment commitments related to further infill wells in the area. An infill well on Ærfugl is currently being matured towards an investment decision in May 2023.

Ula Area

KEY FIGURES	AKER BP INTEREST	Q1 2023	Q4 2022	Q3 2022	Q2 2022	Q1 2022
Production, mboepd
Ula	80 %	6.1	4.1	2.8	1.9	3.2
Tambar	55 %	2.0	0.7	1.4	0.6	1.4
Oda	15 %	2.5	4.0	4.4	1.2	1.0
Total production		10.6	8.8	8.7	3.7	5.6
Production efficiency		80 %	56 %	62 %	36 %	60 %

Production from the Ula area increased to 10.6 mboepd in the first quarter, driven by good performance of several wells at Ula which came back on production, and by improved Tambar performance after repairs of equipment failure. Oda production declined due to water breakthrough in the main production well.

A project has been launched to establish a late-life strategy for Ula, to facilitate safe and profitable operations until cease of production in 2028. In parallel, a field decommissioning study to prepare a work program for well plugging and platform removal is ongoing.

Valhall Area

KEY FIGURES	AKER BP INTEREST	Q1 2023	Q4 2022	Q3 2022	Q2 2022	Q1 2022
Production, mboepd
Valhall	90%	42.9	42.4	40.7	29.1	44.9
Hod	90%	14.5	13.1	10.0	0.8	0.6
Total production		57.4	55.5	50.6	29.9	45.5
Production efficiency		91 %	89 %	87 %	56 %	89 %

Production from the Valhall area remained high at 57.4 mboepd, driven by good well performance and improved production efficiency of 91 percent.

A new infill well on Valhall Flank North passed final investment decision in the quarter. Planned production start is late 2023.

The Noble Integrator rig continued to support the stimulation and intervention activities at Valhall, aimed at bringing more wells up to their full production potential. Towards the end of the first quarter, the rig was moved to Hod to embark on the first phase of a campaign to permanently plug and abandon eight wells at the old Hod A platform. The second phase of this campaign is planned to commence in the second half of 2023 with the rig Noble Invincible.

Valhall PWP-Fenris

The Plan for Development and Operations (PDO) for the joint Valhall PWP & Fenris development project (previously named Valhall NCP & King Lear) was submitted to the Norwegian Ministry of Petroleum and Energy (MPE) in December 2022, and in first quarter 2023, the MPE submitted a proposition for the project to the Norwegian parliament (Stortinget) where a resolution is expected before the end of the spring session.

The joint development project comprises a new centrally located production and wellhead platform (PWP) bridge-linked to the Valhall central complex with 24 well slots, and an unmanned installation (UI) with 8 slots at Fenris (formerly King Lear) subsea tied back 50 kilometres to the PWP. The project has now entered the execution phase with the start of detailed engineering and procurement.

Total recoverable resources for Valhall PWP-Fenris are estimated to be 230 mmboe gross, divided into 160 mmboe at Fenris

Yggdrasil (formerly NOAKA)

The Yggdrasil area (formerly NOAKA) is located between Oseberg and Alvheim in the Norwegian North Sea. The area holds several oil and gas discoveries with gross recoverable resources estimated at around 650 million barrels of oil equivalents, with further exploration and appraisal potential. Gross investments in the area are estimated to NOK 115 billion in real terms.

Yggdrasil consist of the licence groups Hugin, Fulla and Munin. The partners in the licences are Aker BP ASA, Equinor ASA and LOTOS Exploration & Production Norge AS. Aker BP is the operator and will develop and operate the full area.

The final investment decision was made by the partners in fourth quarter 2022, and on 16 December 2022, plans for development and operation were submitted to the Norwegian Ministry of Petroleum and Energy (MPE). In first quarter 2023, the MPE submitted the proposition for the Yggdrasil development to the Norwegian parliament (Stortinget) where a resolution is expected before the end of the spring session.

The Yggdrasil development concept includes a processing platform with well area and living quarters, Hugin A. It will function as an area hub. Hugin A is planned with low manning levels and is also being developed to be periodically unmanned after a few years of operation.

and 70 mmboe at Valhall. The development plan includes a total of 19 wells, of which 15 at Valhall PWP and 4 at Fenris. Production start is planned for the second and third quarter 2027, respectively.

The project will also involve a modernisation of Valhall that ensures continued operation when parts of the current infrastructure are to be phased out in 2028, thus enabling production of the remaining Valhall reserves from 2029 onwards, which are estimated at 135-140 mmboe gross. In addition, the project will add gas capacity to Valhall and thus enable Valhall to serve as a hub for potential new gas discoveries in the future.

The development will leverage Valhall's existing power from shore system with minimal emissions, estimated at less than 1 kg CO2/boe.

The Frøy field will be developed with a normally unmanned wellhead platform, Hugin B, that will be tied back to Hugin A.

Munin is an unmanned production platform. It will be tied back to Hugin A for oil and produced water processing.

Yggdrasil also represents an extensive subsea development with a total of nine templates, pipelines and umbilicals. 55 wells are planned in the area, of which 38 subsea wells and 17 platform wells. Additionally, the area concept has high flexibility for potential tie-in of new discoveries.

The oil will be exported via Grane Oil Pipe and the gas will be exported through Statpipe.

The Yggdrasil area will be powered from shore to ensure minimal carbon footprint. In March, the MPE awarded Aker BP a licence to connect the platforms in the Yggdrasil area to the onshore power grid.

The Yggdrasil development has moved into the execution phase, and the main priorities are currently detailed engineering and procurement.

EXPLORATION

Total exploration spend in the first quarter was USD 119 (60) million, while USD 98 (32) million was recognised as exploration expenses in the period, relating to dry well costs, seismic, area fees, field evaluation and G&G costs.

The Gjegnalunden prospect in production licence 867 (80 percent interest) was drilled in the quarter. Preliminary estimates place the size of the discovery between 3-9 million barrels of oil equivalent. The discovery is not considered to be commercial at present time.

The Styggehøe prospect in production licence 1141 (70 percent interest), the Angulata prospect in production license 554 (30 percent interest) and the P-Graben appraisal well in production license 265 (27 percent interest) were all drilled in the quarter and concluded as dry.

Drilling of the Ve prospect, in production license 919 in the North Sea, was started in the first quarter and completed early in the second quarter. The well resulted in a small oil discovery with preliminary estimates of between 3-5 million barrels of oil equivalent. The licensees will assess the discovery together with other discoveries in the vicinity regarding a possible development. Aker BP is the operator with 80 percent interest in the licence.

In January 2023, Aker BP was offered interests in 17 new production licenses offshore Norway, of which nine as operator, through the Awards in pre-defined areas (APA 2022) licensing round. Of the 17 production licenses awarded to Aker BP, 13 are in the North Sea (six as operator) and four in the Norwegian Sea (three as operator).

BUSINESS DEVELOPMENT

Licence for CO2 storage

Aker BP and OMV have entered into a collaboration agreement for carbon capture and storage (CCS) and were awarded a licence in accordance with the CO2 Storage Regulations on the Norwegian Continental Shelf (NCS) on 31 March 2023.

The licence is located in the Norwegian North Sea and will be named Poseidon. Aker BP will be the operator of the licence, with 50 percent interest (in the initial announcement, the

interest was stated as 60 percent by mistake). The licence comes with a work program which includes a 3D seismic acquisition and a drill or drop decision by 2025.

Aker BP will evaluate Poseidon's potential as a business opportunity and as a potential means of reducing the company's net carbon footprint in the future.

HEALTH, SAFETY, SECURITY AND ENVIRONMENT

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

KEY HSSE INDICATORS	UNIT	Q1 2023	Q4 2022	Q3 2022	Q2 2022	Q1 2022
Total recordable injury frequency (TRIF) L12M	Per mill. exp. hours	1.0	1.1	1.3	1.6	1.6
Serious incident frequency (SIF) L12M	Per mill. exp. hours	0.3	0.4	0.2	0.2	0.1
Acute spill	Count	1	0	0	0	3
Process safety events Tier 1 and 2	Count	0	0	0	0	0
GHG emissions intensity*, equity share	Kg CO2e/boe	2.9	3.2	3.8	5.3	5.0

*The definition of emissions intensity has been changed from previous quarterly reports, and now also includes emissions of methane and N2O, as well as CO2 emissions from exploration activities. Previous periods have been restated accordingly.

Safety

The positive trend in TRIF continued in the first quarter 2023, when no serious incidents were recorded. The company had one chemical spill incident in the quarter, involving a leak of 1.5 m³ of scale inhibitor from a tank at Ula, which was categorised as a Tier 3 event (moderate severity) under the PSA classification system.

Decarbonisation

Aker BP's GHG emissions intensity was further reduced to 2.9 (3.2) kg CO2e per boe in the quarter. The main driver for the reduction was the electrification of Edvard Grieg and Ivar Aasen, which was implemented towards the end of last year.

OUTLOOK

The Board is of the opinion that Aker BP is uniquely positioned for value creation. The key characteristics of the company are:

• A world-class portfolio of producing assets operated with high efficiency and low cost
• Among the industry's lowest CO2 emissions and a clear pathway to net zero
• A comprehensive improvement agenda to drive industrial transformation through alliances and digitalisation
• A unique resource base that enables strong growth based on highly profitable projects in a capital-efficient tax system
• A strong financial framework allowing the company to fund its growth plans and growing dividends in parallel

Guidance

The company's financial plan for 2023 remains unchanged and consists of the following key parameters:

• Production of 430-460 mboepd
• Capex of USD 3.0-3.5 billion
• Exploration spend of USD 400-500 million
• Abandonment spend of USD 100-200 million
• Production cost of USD 7-8 per boe
• Quarterly dividends of USD 0.55 per share, equivalent to an annualised level of USD 2.2 per share

Disclaimer

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 restated.

FINANCIAL STATEMENTS WITH NOTES

15 · Aker BP Quarterly Report · Q1 2023

INCOME STATEMENT (UNAUDITED)

		Group
		Q1	Q4	Q1		01.01.-31.03.
				Restated		Restated
(USD 1 000)	Note	2023	2022	2022	2023	2022
Petroleum revenues		3 298 239	3 803 738	2 249 823	3 298 239	2 249 823
Other income		12 115	22 191	41 466	12 115	41 466
Total income	2	3 310 354	3 825 929	2 291 288	3 310 354	2 291 288
Production expenses	3	263 338	286 424	220 131	263 338	220 131
Exploration expenses	4	97 692	32 094	57 523	97 692	57 523
Depreciation	6	598 952	641 225	299 436	598 952	299 436
Impairments	5,6	373 210	636 213	-	373 210	-
Other operating expenses		16 161	16 026	7 041	16 161	7 041
Total operating expenses		1 349 352	1 611 981	584 130	1 349 352	584 130
Operating profit/loss		1 961 002	2 213 947	1 707 158	1 961 002	1 707 158
Interest income		25 364	13 458	1 350	25 364	1 350
Other financial income		314 593	590 702	122 898	314 593	122 898
Interest expenses		43 617	35 764	19 732	43 617	19 732
Other financial expenses		433 693	605 653	31 475	433 693	31 475
Net financial items	8	-137 353	-37 257	73 041	-137 353	73 041
Profit/loss before taxes		1 823 649	2 176 691	1 780 199	1 823 649	1 780 199
Tax expense (+)/income (-)	9	1 636 669	2 064 333	1 258 624	1 636 669	1 258 624
Net profit/loss		186 980	112 357	521 575	186 980	521 575
Weighted average no. of shares outstanding basic and diluted		631 793 145	631 585 639	359 787 854	631 793 145	359 787 854
Basic and diluted earnings/loss USD per share		0.30	0.18	1.45	0.30	1.45

STATEMENT OF COMPREHENSIVE INCOME (UNAUDITED)

		Group
	Q1	Q4	Q1 01.01.-31.03.
			Restated		Restated
Note (USD 1 000)	2023	2022	2022	2023	2022
Profit/loss for the period	186 980	112 357	521 575	186 980	521 575
Items which may be reclassified over profit and loss (net of taxes) Foreign currency translation	-	1 012 811	-	-	-
Items which will not be reclassified over profit and loss (net of taxes) Foreign currency translation Actuarial gain/loss pension plan	- -	295 325 3	- -	- -	-
Total comprehensive income/loss in period	186 980	1 420 496	521 575	186 980	521 575

STATEMENT OF FINANCIAL POSITION (UNAUDITED)

			Group
				Restated
(USD 1 000)	Note	31.03.2023	31.12.2022	31.03.2022
ASSETS
Intangible assets
Goodwill	6	13 635 654	13 934 986	1 647 436
Capitalised exploration expenditures	6	273 097	251 736	198 237
Other intangible assets	6	2 254 664	2 344 354	1 390 331
Tangible fixed assets
Property, plant and equipment	6	16 219 528	15 886 659	10 370 177
Right-of-use assets	6	322 819	111 336	104 054
Financial assets
Long-term receivables		166 368	169 528	74 469
Other non-current assets		103 420	104 480	107 731
Long-term derivatives	12	1 607	2 907	2 004
Total non-current assets		32 977 157	32 805 987	13 894 439
Inventories
Inventories		193 178	209 506	120 323
Financial assets
Trade receivables		580 093	950 942	394 682
Other short-term receivables	10	894 160	686 237	657 056
Short-term derivatives	12	3 165	153 096	56 401
Cash and cash equivalents
Cash and cash equivalents	11	3 280 245	2 756 012	2 816 731
Total current assets		4 950 842	4 755 793	4 045 194
TOTAL ASSETS		37 927 999	37 561 780	17 939 633

STATEMENT OF FINANCIAL POSITION (UNAUDITED)

			Group
				Restated
(USD 1 000)	Note	31.03.2023	31.12.2022	31.03.2022
EQUITY AND LIABILITIES
Equity
Share capital		84 348	84 348	57 056
Share premium		12 946 640	12 946 640	3 637 297
Other equity		-764 114	-603 482	-1 147 017
Total equity		12 266 874	12 427 506	2 547 335
Non-current liabilities
Deferred taxes	9	9 502 412	9 359 146	3 404 663
Long-term abandonment provision	15	4 308 764	4 050 396	5 082 496
Long-term bonds	14	5 304 158	5 279 164	3 558 315
Long-term derivatives	12	45 807	16 981	16 382
Long-term lease debt	7	244 428	98 095	93 526
Other non-current liabilities		82 366	82 306	82 516
Total non-current liabilities		19 487 935	18 886 088	12 237 898
Current liabilities
Trade creditors		69 813	133 875	94 026
Accrued public charges and indirect taxes		22 291	36 632	18 829
Tax payable	9	4 757 530	5 084 142	2 256 665
Short-term derivatives	12	184 580	34 924	27 860
Short-term abandonment provision	15	144 356	115 202	103 131
Short-term lease debt	7	101 216	36 298	42 184
Other current liabilities	13	893 405	807 113	611 704
Total current liabilities		6 173 190	6 248 186	3 154 399
Total liabilities		25 661 125	25 134 274	15 392 298
TOTAL EQUITY AND LIABILITIES		37 927 999	37 561 780	17 939 633

STATEMENT OF CHANGES IN EQUITY - GROUP (UNAUDITED)

				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
Restated equity as of 31.12.2021	57 056	3 637 297	573 083	-76	-115 491	-1 955 054	-1 497 538	2 196 814
Dividend distributed	-	-	-	-	-	-171 054	-171 054	-171 054
Restated profit/loss for the period	-	-	-	-	-	521 575	521 575	521 575
Restated equity as of 31.03.2022	57 056	3 637 297	573 083	-76	-115 491	-1 604 533	-1 147 017	2 547 335
Dividend distributed	-	-	-	-	-	-834 677	-834 677	-834 677
Private placement	27 292	9 309 343	-	-	-	-	-	9 336 636
Restated profit/loss for the period	-	-	-	-	-	1 081 365	1 081 365	1 081 365
Purchase/sale of treasury shares	-	-	-	-	-	1 524	1 524	1 524
Other comprehensive income for the period		-	-	-3	295 325	-	295 323	295 323
Equity as of 31.12.2022	84 348	12 946 640	573 083	-78	179 834	-1 356 320	-603 482	12 427 506
Dividend distributed	-	-	-	-	-	-347 612	-347 612	-347 612
Profit/loss for the period	-	-	-	-	-	186 980	186 980	186 980
Equity as of 31.03.2023	84 348	12 946 640	573 083	-78	179 834	-1 516 952	-764 114	12 266 874

STATEMENT OF CASH FLOWS (UNAUDITED)

		Group
		Q1 Q4 Q1			01.01.-31.03.
				Restated		Restated
(USD 1 000)	Note	2023	2022	2022	2023	2022
CASH FLOW FROM OPERATING ACTIVITIES
Profit/loss before taxes		1 823 649	2 176 691	1 780 199	1 823 649	1 780 199
Taxes paid	9	-1 568 942	-2 955 009	-388 256	-1 568 942	-388 256
Depreciation	6	598 952	641 225	299 436	598 952	299 436
Impairment	5,6	373 210	636 213	-	373 210	-
Expensed capitalised dry wells	4,6	63 771	9 745	39 443	63 771	39 443
Accretion expenses related to abandonment provision	8,15	40 354	40 286	21 343	40 354	21 343
Total interest expenses	8	43 617	35 764	19 732	43 617	19 732
Changes in unrealised gain/loss in derivatives	2,8	329 713	-575 779	-31 664	329 713	-31 664
Changes in inventories, trade creditors/receivables and accrued income		133 760	269 322	-281 739	133 760	-281 739
Changes in other balance sheet items		-156 069	528 394	-83 198	-156 069	-83 198
NET CASH FLOW FROM OPERATING ACTIVITIES		1 682 014	806 850	1 375 295	1 682 014	1 375 295
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields	15	-28 564	-19 296	-16 041	-28 564	-16 041
Disbursements on investments in fixed assets (excluding capitalised interest)	6	-597 442	-570 227	-335 307	-597 442	-335 307
Disbursements on investments in capitalised exploration	6	-79 409	-37 788	-48 557	-79 409	-48 557
Investments in financial asset		-	-95 000	-	-	-
Consideration paid in Lundin Energy transaction net of cash acquired		-	13 862	-	-	-
Cash received from sale of financial asset		-	-	118 005	-	118 005
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-705 415	-708 449	-281 900	-705 415	-281 900
CASH FLOW FROM FINANCING ACTIVITIES
Interest paid (including interest element of lease payments)		-77 979	-3 531	-55 394	-77 979	-55 394
Payments on lease debt related to investments in fixed assets		-14 797	-6 976	-18 130	-14 797	-18 130
Payments on other lease debt		-13 524	-5 662	-3 634	-13 524	-3 634
Paid dividend		-347 612	-331 812	-171 054	-347 612	-171 054
Net purchase/sale of treasury shares		-	18 489	-	-	-
NET CASH FLOW FROM FINANCING ACTIVITIES		-453 913	-329 492	-248 213	-453 913	-248 213
Net change in cash and cash equivalents		522 686	-231 091	845 183	522 686	845 183
Cash and cash equivalents at start of period		2 756 012	3 041 997	1 970 906	2 756 012	1 970 906
Effect of exchange rate fluctuation on cash held		1 547	-54 894	643	1 547	643
CASH AND CASH EQUIVALENTS AT END OF PERIOD	11	3 280 245	2 756 012	2 816 731	3 280 245	2 816 731

NOTES (unaudited)

(All figures in USD 1 000 unless otherwise stated)

These unaudited 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 2022 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.

The acquisition of the Lundin Energy's oil and gas business ("Lundin Energy") was completed on 30 June 2022, and the transaction was thus reflected in the statement of financial position in the second quarter 2022 report. Hence, Q1 2023 is not directly comparable to Q1 2022 since the latter does not include any activity from Lundin Energy. At 31 December 2022, the merger processes with the legacy Lundin Energy entities were completed. These entities had other functional currency than USD which gave rise to significant currency translation elements in the group consolidation. From 1 January 2023 the activity in the legacy Lundin entities are carried out in the legal entity Aker BP ASA and the mentioned impact on comprehensive income is thus no longer present.

These interim financial statements were authorised for issue by the company's Board of Directors on 26 April 2023.

Note 1 Accounting principles

The accounting principles used for this interim report are consistent with the principles used in the group's 2022 annual financial statements. This includes two changes in accounting principles as described below. The comparison period Q1 2022 has been restated accordingly in this report.

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.

Discount rate for abandonment provisions

As described in the accounting principles in the 2021 Annual Financial Statements, the discount rate for calculating abandonment provisions has historically included a credit element in addition to a risk free rate. In line with the development in industry practice with regards to the interpretation of the relevant guidelines in IAS 37, the company changed the discount rate in Q4 2022 so that this no longer includes a credit element. Comparative figures from 1 January 2021 was restated accordingly. The table below shows the restatement impact for the comparison period Q1 2022.

	Q1	01.01.-31.12.
Breakdown of restatement impact on the income statement (USD 1 000)	2022	2021
Depreciation - prior to restatement	231 125	964 083
Depreciation - after restatement	299 436	1 192 889
Change	68 310	228 807
Impairment - prior to restatement	-	262 554
Impairment - after restatement	-	262 554
Change	-	-
Net financial items - prior to restatement	61 463	-241 718
Net financial items - after restatement	73 041	-189 913
Change	11 578	51 804
Tax expense/income - prior to restatement	1 300 020	2 222 080
Tax expense/income - after restatement	1 255 766	2 084 012
Change	-44 253	-138 069
Net profit/loss - prior to restatement	536 911	850 704
Net profit/loss - after restatement	524 433	811 771
Change	-12 479	-38 933

Breakdown of restatement impact on the statement of financial position (USD 1 000)	31.03.2022	31.12.2021
Property, plant and equipment - prior to restatement	8 256 944	7 976 308
Property, plant and equipment - after restatement	10 370 177	10 214 438
Change	2 113 233	2 238 131
Long-term abandonment provision - prior to restatement	2 735 529	2 656 358
Long-term abandonment provision - after restatement	5 082 496	5 071 491
Change	2 346 968	2 415 133
Deferred tax - prior to restatement	3 477 985	3 323 213
Deferred tax - after restatement	3 295 662	3 185 144
Change	-182 322	-138 069
Equity - prior to restatement	2 707 748	2 341 891
Equity - after restatement	2 656 336	2 302 957
Change	-51 412	-38 933

Deferred tax on capitalised interest

The tax regime for oil and gas companies in Norway limits the tax deduction on parts of the company's interest expenses to 22 percent, while the general tax rate in the industry is 78 percent. Parts of these interest expenses have been capitalised as Property, plant and equipment, and deferred tax has been calculated at 22 percent in line with the tax deduction outside the special tax regime, in line with industry peers. The company has revised its accounting policy, and concluded to change the applied deferred tax rate from 22 to 78 percent for interest capitalised as Property, plant and equipment, to better reflect the tax consequences that would follow from the manner in which the company expects to recover the carrying amount of Property, plant and equipment. Prior periods have been restated accordingly. The figures below include the restatements related to abandonment provisions in the table above, to the extent applicable.

	Q1	01.01.-31.12.
Breakdown of restating impact on the income statement (USD 1 000)	2022	2021
Tax expense/income - prior to restating	1 255 766	2 084 012
Tax expense/income - after restating	1 258 624	2 067 855
Change	2 858	-16 157
Net profit/loss - prior to restatement	524 433	811 771
Net profit/loss - after restatement	521 575	827 928
Change	-2 858	16 157
Breakdown of restating impact on the statement of financial position (USD 1 000)	31.03.2022	31.12.2021
Deferred tax - prior to restating	3 295 662	3 185 144
Deferred tax - after restating	3 404 663	3 291 287
Change	109 000	106 143
Equity - prior to restating	2 656 336	2 302 957
Equity - after restating	2 547 335	2 196 814
Change	-109 000	-106 143

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 were applied in the group's 2022 annual financial statements.

Note 2 Income

	Group
	Q1	Q4	Q1	01.01.-31.03.
Breakdown of petroleum revenues (USD 1 000)	2023	2022	2022	2023	2022
Sales of liquids	2 711 519	2 886 641	1 553 928	2 711 519	1 553 928
Sales of gas	581 865	913 536	693 134	581 865	693 134
Tariff income	4 854	3 561	2 760	4 854	2 760
Total petroleum revenues	3 298 239	3 803 738	2 249 823	3 298 239	2 249 823
Sales of liquids (boe 1 000)	34 567	33 326	15 403	34 567	15 403
Sales of gas (boe 1 000)	5 896	6 074	4 053	5 896	4 053
Other income (USD 1 000)
Realised gain/loss (-) on commodity derivatives	-34	5 744	-2 317	-34	-2 317
Unrealised gain/loss (-) on commodity derivatives	-1 083	4 402	38 449	-1 083	38 449
Other income	13 232	12 046	5 334	13 232	5 334
Total other income	12 115	22 191	41 466	12 115	41 466

Note 3 Production expenses

	Group
	Q1	Q4	Q1	01.01.-31.03.
Breakdown of production expenses (USD 1 000)	2023	2022	2022	2023	2022
Cost of operations	200 937	192 948	150 022	200 937	150 022
Shipping and handling	74 432	73 763	49 688	74 432	49 688
Environmental taxes	16 478	21 083	18 225	16 478	18 225
Production expenses based on produced volumes	291 847	287 794	217 935	291 847	217 935
Adjustment for over/underlift (-)	-28 509	-1 370	2 196	-28 509	2 196
Production expenses based on sold volumes	263 338	286 424	220 131	263 338	220 131
Total produced volumes (boe 1 000)	40 742	39 741	18 738	40 742	18 738
Production expenses per boe produced (USD/boe)	7.2	7.2	11.6	7.2	11.6

Note 4 Exploration expenses

	Group
	Q1	Q4	Q1	01.01.-31.03.
Breakdown of exploration expenses (USD 1 000)	2023	2022	2022	2023	2022
Seismic	12 339	3 561	1 446	12 339	1 446
Area fee	5 062	3 758	4 355	5 062	4 355
Field evaluation	1 836	830	4 311	1 836	4 311
Dry well expenses1)	63 771	9 745	39 443	63 771	39 443
G&G and other exploration expenses	14 684	14 201	7 968	14 684	7 968
Total exploration expenses	97 692	32 094	57 523	97 692	57 523

1) Dry well expenses in Q1 2023 are mainly related to the wells Gjegnalunden, Styggehøe and P-Graben.

Note 5 Impairments

Impairment testing

Impairment tests of individual cash-generating units are performed when impairment/reversal triggers are identified, and goodwill is tested for impairment at least annually. In Q1 2023, impairment test has been performed for fixed assets and related intangible assets, including technical goodwill.

Impairment is recognised when the book value of an asset or a cash-generating unit, including associated goodwill, exceeds the recoverable amount. Correspondingly, a reversal of impairment is recognised when the recoverable amount exceeds the book value. Prior period impairment of goodwill is not subject to reversal. The recoverable amount is the higher of the asset's fair value less cost to sell and value in use. The impairment testing for 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 2023.

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 2023 to the end of Q1 2026. From Q2 2026, the oil and gas prices are based on the company's long-term price assumptions. Long-term oil and gas price assumptions are unchanged from previous quarter.

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

Year	USD/BOE
2023	79.2
2024	75.7
2025	72.5
2026	69.4
From 2027 (in real 2023 terms)	65.0

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

Year	GBP/therm
2023	1.28
2024	1.47
2025	1.26
2026	0.84
From 2027 (in real 2023 terms)	0.67

Oil and gas reserves

Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable reserves including potentially additional risked volumes.

Future expenditure

Future capex, opex and abandonment cost are calculated based on the expected production profiles and the best estimate of the related cost. The cost profiles include an estimated impact of the currently high cost escalation in the industry.

Discount rate

The post tax nominal discount rate used is 8.7 percent, consistent with the rate applied at Q4 2022.

Currency rates
Year	USD/NOK
2023	10.47
2024	10.35
2025	10.30
2026	8.56
From 2027	8.00

The long-term currency rate is unchanged from year-end 2022.

Inflation

The long-term inflation rate is assumed to be 2.0 percent. The currently high cost escalation in the industry is reflected in the cash flows rather than in the inflation rate.

Impairment testing of assets including technical goodwill

The technical goodwill recognised in previous business combinations is allocated to each CGU for the purpose of impairment testing. Hence, the impairment test of technical goodwill is included in the impairment testing of assets, and the technical goodwill is written down before the asset. The carrying value of the assets is the sum of tangible assets, intangible assets and technical goodwill as of the assessment date. In line with the methodology described in the annual report, deferred tax (from the date of acquisitions) reduces the net carrying value prior to the impairment charges. When deferred tax liabilities from the acquisitions decreases as a result of depreciation, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable.

Below is an overview of the impairment charge and the carrying value per cash generating unit where impairments have been recognised in Q1 2023:

		Edvard Grieg &
Cash-generating unit (USD 1 000)	Troldhaugen	Ivar Aasen CGU
Net carrying value	107 372	4 382 300
Recoverable amount	-	4 116 462
Impairment/reversal (-)	107 372	265 837
Allocated as follows:
Technical goodwill	33 495	265 837
Other intangible assets/license rights	42 940	-
Tangible fixed assets	30 938	-

The main reason for the Troldhaugen impairment is related to the decision by the partership to not accede the PDO for the Troldhaugen project. The Edvard Grieg & Ivar Aasen CGU impairment is mainly related to decrease in short-term oil and gas prices and the decrease of deferred tax liabilities as described above.

Sensitivity analysis

The table below shows how the impairment or reversal of impairment of assets and technical goodwill would be affected by changes in the various assumptions, given that the remaining assumptions are constant.

		Change in impairment after
Assumption (USD 1 000)	Change	Increase in assumptions	Decrease in assumptions
Oil and gas price forward period	+/- 50 %	-	2 308 901
Oil and gas price long-term	+/- 20 %	-	827 613
Production profile (reserves)	+/- 5 %	-	279 978
Discount rate	+/- 1 % point	102 752	-
Currency rate USD/NOK	+/- 2.0 NOK	-	692 639
Inflation	+/- 1 % point	-	227 105

Note 6 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
Restated book value 31.12.2021	1 795 436	8 332 297	86 705	10 214 438
Restated acquisition cost 31.12.2021	1 795 436	13 403 026	256 449	15 454 911
Additions	1 036 027	-1 203 100	18 215	-148 858
Acquisition of Lundin Energy	933 182	6 726 306	3 811	7 663 300
Disposals/retirement	-	-	17 483	17 483
Reclassification	-2 132 595	2 266 639	7 273	141 317
Foreign currency translation	-17 874	108 146	42	90 314
Acquisition cost 31.12.2022	1 614 177	21 301 017	268 306	23 183 501
Restated accumulated depreciation and impairments 31.12.2021	-	5 070 729	169 744	5 240 473
Depreciation	-	1 635 302	39 944	1 675 245
Impairment/reversal (-)	-	385 562	-	385 562
Disposals/retirement depreciation	-	-	-17 483	-17 483
Foreign currency translation	-	13 017	27	13 044
Accumulated depreciation and impairments 31.12.2022	-	7 104 610	192 232	7 296 841
Book value 31.12.2022	1 614 177	14 196 407	76 075	15 886 659
Acquisition cost 31.12.2022	1 614 177	21 301 017	268 306	23 183 501
Additions	497 027	389 789	2 562	889 379
Disposals/retirement	-	-	-	-
Reclassification1)	-215 487	227 718	3 207	15 438
Acquisition cost 31.03.2023	1 895 718	21 918 525	274 075	24 088 318
Accumulated depreciation and impairments 31.12.2022	-	7 104 610	192 232	7 296 841
Depreciation	-	532 191	8 820	541 011
Impairment/reversal (-)	30 938	-	-	30 938
Disposals/retirement depreciation	-	-	-	-
Accumulated depreciation and impairments 31.03.2023	30 938	7 636 801	201 052	7 868 790
Book value 31.03.2023	1 864 780	14 281 724	73 024	16 219 528

1) The reclassification is mainly related to the Frosk development project in the Alvheim area, which entered into production phase during Q1 2023

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. Estimated future Removal and decommissining costs are included as part of cost of production facilities or fields under developement

Right-of-use assets
		Vessels and
(USD 1 000)	Drilling Rigs	Boats	Office	Other	Total
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	22 542	-	11 223	-	33 765
Acquisition of Lundin Energy	11 069	-	23 688	-	34 757
Allocated to abandonment activity	-	-366	-	-	-366
Disposals/retirement	6 099	10	8 086	-	14 194
Reclassification	-28 072	-2 338	-	-	-30 409
Foreign currency translation	-2	-	-1 952	-	-1 954
Acquisition cost 31.12.2022	17 850	54 723	77 290	2 303	152 166
Accumulated depreciation and impairments 31.12.2021	6 099	6 696	23 066	530	36 390
Depreciation	2 776	3 938	11 826	177	18 716
Impairment/reversal (-)	-	-	-	-	-
Disposals/retirement depreciation	-6 099	-	-8 086	-	-14 185
Foreign currency translation	-	-	-92	-	-92
Accumulated depreciation and impairments 31.12.2022	2 776	10 634	26 714	706	40 829
Book value 31.12.2022	15 075	44 089	50 576	1 597	111 336
Acquisition cost 31.12.2022	17 850	54 723	77 290	2 303	152 166
Additions1)	242 573	-	-	-	242 573
Allocated to abandonment activity	-1 117	-194	-	-	-1 312
Disposals/retirement	-	-	-	-	-
Reclassification2)	-20 764	-397	-	-	-21 161
Acquisition cost 31.03.2023	238 543	54 131	77 290	2 303	372 267
Accumulated depreciation and impairments 31.12.2022	2 776	10 634	26 714	706	40 829
Depreciation	3 970	1 072	3 532	44	8 618
Impairment/reversal (-)	-	-	-	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 31.03.2023	6 746	11 706	30 246	750	49 448
Book value 31.03.2023	231 797	42 425	47 044	1 553	322 819

1) The additions are related to the rigs Deepsea Nordkapp and Scarabeo 8.

2) Reclassified mainly 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

		Capitalised
		exploration expenditures	Depreciated	Other intangible assets Not depreciated	Total
(USD 1 000)	Goodwill
Book value 31.12.2021	1 647 436	256 535	641 967	765 584	1 407 551
Acquisition cost 31.12.2021	2 726 583	444 232	1 480 063	888 922	2 368 985
Additions	-	251 764	743	-	743
Acquisition of Lundin Energy	12 542 852	-	25 653	1 256 577	1 282 230
Disposals/retirement/expensed dry wells	-	135 800	-	-	-
Reclassification	-	-110 907	855 022	-855 022	-
Foreign currency translation	134 964	1 012	275	12 339	12 614
Acquisition cost 31.12.2022	15 404 399	450 301	2 361 756	1 302 816	3 664 572
Accumulated depreciation and impairments 31.12.2021	1 079 146	187 696	838 096	123 338	961 434
Depreciation	-	-	91 711	-	91 711
Impairment/reversal (-)	377 398	10 869	-	258 325	258 325
Disposals/retirement depreciation	-	-	-	-	-
Foreign currency translation	12 868	-	-60	8 808	8 748
Accumulated depreciation and impairments 31.12.2022	1 469 413	198 565	929 747	390 471	1 320 218
Book value 31.12.2022	13 934 986	251 736	1 432 009	912 345	2 344 354
Acquisition cost 31.12.2022	15 404 399	450 301	2 361 756	1 302 816	3 664 572
Additions	-	79 409	2 573	-	2 573
Disposals/retirement/expensed dry wells	-	63 771	-	-	-
Reclassification	-	5 723	6 946	-6 946
Acquisition cost 31.03.2023	15 404 399	471 662	2 371 275	1 295 870	3 667 145
Accumulated depreciation and impairments 31.12.2022	1 469 413	198 565	929 747	390 471	1 320 218
Depreciation	-	-	49 323	-	49 323
Impairment/reversal (-)	299 332	-	-	42 940	42 940
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 31.03.2023	1 768 745	198 565	979 070	433 411	1 412 481
Book value 31.03.2023	13 635 654	273 097	1 392 205	862 459	2 254 664

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
		Restated		Restated
2023	2022	2022	2023	2022
541 011	600 841	279 197	541 011	279 197
8 618	6 284	3 019	8 618	3 019
49 323	34 100	17 220	49 323	17 220
598 952	641 225	299 436	598 952	299 436
30 938	489	-	30 938	-
42 940	258 325	-	42 940	-
-	-	-	-	-
299 332	377 398	-	299 332	-
373 210	636 213	-	373 210	-
				01.01.-31.03.

Note 7 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 recognised.

	Group
	2023	2022	2022
(USD 1 000)	Q1	Q1	01.01.-31.12.
Lease debt as of beginning of period	134 393	136 213	136 213
New lease debt recognised in the period2)	242 573	21 192	33 765
Payments of lease debt1)	-33 100	-23 815	-74 068
Interest expense on lease debt	4 779	2 050	7 496
Lease debt from acquisition of Lundin Energy	-	-	34 757
Currency exchange differences	-3 001	70	-3 769
Total lease debt	345 644	135 711	134 393
Short-term	101 216	42 184	36 298
Long-term	244 428	93 526	98 095
1) Payments of lease debt split by activities (USD 1 000):
Investments in fixed assets	17 294	19 838	46 942
Abandonment activity	1 518	245	751
Operating expenditures	4 500	2 432	13 878
Exploration expenditures	5 927	206	6 222
Other income	3 862	1 093	6 275
Total	33 100	23 815	74 068
Nominal lease debt maturity breakdown (USD 1 000):
Within one year	114 676	48 451	42 646
Two to five years	245 341	72 924	87 179
After five years	22 463	38 885	26 403
Total	382 480	160 260	156 227

2) The new lease debt recognised in Q1 2023 is related to the rigs Deepsea Nordkapp and Scarabeo 8.

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
	Q1	Q4 Q1		01.01.-31.03.
			Restated		Restated
(USD 1 000)	2023	2022	2022	2023	2022
Interest income	25 364	13 458	1 350	25 364	1 350
Realised gains on derivatives	55 202	19 325	7 453	55 202	7 453
Change in fair value of derivatives	-	571 377	10 635	-	10 635
Net currency gains	259 066	-	6 085	259 066	6 085
Other financial income	325		98 725	325	98 725
Total other financial income	314 593	590 702	122 898	314 593	122 898
Interest expenses	46 046	48 093	30 589	46 046	30 589
Interest on lease debt	4 779	1 789	2 050	4 779	2 050
Capitalised interest cost, development projects	-20 294	-27 206	-15 948	-20 294	-15 948
Amortised loan costs1)	13 087	13 087	3 041	13 087	3 041
Total interest expenses	43 617	35 764	19 732	43 617	19 732
Net currency loss	-	337 509	-	-	-
Realised loss on derivatives	64 345	225 207	7 701	64 345	7 701
Change in fair value of derivatives	328 630	-	-	328 630	-
Accretion expenses related to abandonment provision	40 354	40 286	21 343	40 354	21 343
Other financial expenses	364	2 651	2 432	364	2 432
Total other financial expenses	433 693	605 653	31 475	433 693	31 475
Net financial items	-137 353	-37 257	73 041	-137 353	73 041

1) The figure includes amortisation of the difference between fair value and nominal value on the bonds acquired in the Lundin transaction in Q2 2022

Note 9 Tax

			Group
	Q1	Q4	Q1 01.01.-31.03.
			Restated		Restated
Tax for the period (USD 1 000)	2023	2022	2022	2023	2022
Current year tax payable/receivable	1 535 967	2 169 807	1 168 289	1 535 967	1 168 289
Change in current year deferred tax	110 878	-111 893	87 257	110 878	87 257
Prior period adjustments	-10 176	6 420	3 077	-10 176	3 077
Tax expense (+)/income (-)	1 636 669	2 064 333	1 258 624	1 636 669	1 258 624

	Group
	2023	2022	2022
Calculated tax payable (-)/tax receivable (+) (USD 1 000)	Q1	Q1	01.01.-31.12.
Tax payable/receivable at beginning of period	-5 084 142	-1 497 291	-1 497 291
Current year tax payable/receivable	-1 535 967	-1 168 289	-7 162 988
Current year tax payable/receivable related to change in tax system	-	-	176 391
Net tax payment/refund	1 568 942	388 256	5 332 125
Net tax payable related to acquisition of Lundin Energy	-	-	-2 181 017
Prior period adjustments and change in estimate of uncertain tax positions	42 564	22 273	29 847
Currency movements of tax payable/receivable	251 074	-1 615	245 846
Current tax charged to other comprehensive income (foreign currency translation)	-	-	-27 055
Net tax payable (-)/receivable (+)	-4 757 530	-2 256 665	-5 084 142

	Group
	2023	2022	2022
		Restated
Deferred tax liability (-)/asset (+) (USD 1 000)	Q1	Q1	01.01.-31.12.
Deferred tax liability/asset at beginning of period	-9 359 146	-3 291 287	-3 291 287
Change in current year deferred tax	-110 878	-87 257	12 294
Change in current year deferred tax related to change in tax system	-	-	-189 444
Deferred tax related to acquisition of Lundin Energy	-	-	-5 802 641
Prior period adjustments	-32 388	-26 118	-27 925
Deferred tax charged to other comprehensive income (mainly foreign currency translation)	-	-	-60 144
Net deferred tax liability (-)/asset (+)	-9 502 412	-3 404 663	-9 359 146

	Group
	Q1	Q4 Q1			01.01.-31.03.
			Restated		Restated
Reconciliation of tax expense (USD 1 000)	2023	2022	2022	2023	2022
78 % tax rate on profit/loss before tax	1 422 519	1 697 906	1 388 553	1 422 519	1 388 553
Tax effect of uplift	-41 011	-42 638	-44 780	-41 011	-44 780
Permanent difference on impairment	233 491	294 386	-	233 491	-
Foreign currency translation of monetary items other than USD	-206 660	125 443	-4 861	-206 660	-4 861
Foreign currency translation of monetary items other than NOK	-92 944	303 967	6 222	-92 944	6 222
Tax effect of financial and other 22 % items	252 867	-247 255	-66 927	252 867	-66 927
Currency movements of tax balances1)	76 897	-90 300	-2 502	76 897	-2 502
Other permanent differences, prior period adjustments and change in estimate of uncertain tax positions	-8 491	22 826	-17 081	-8 491	-17 081
Tax expense (+)/income (-)	1 636 669	2 064 333	1 258 624	1 636 669	1 258 624

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).

From 1 January 2023 the temporary tax regime uplift rate was reduced from from 17.69 to 12.4 percent.

In accordance with statutory requirements, the calculation of current tax is required to be based on each company's local currency. This may impact the effective tax rate as the group's presentation currency is USD and the operating entities in the group can have different functional currency than USD.

Note 10 Other short-term receivables

		Group
(USD 1 000)	31.03.2023	31.12.2022	31.03.2022
Prepayments	111 384	123 980	45 310
VAT receivable	14 276	12 406	6 512
Underlift of petroleum	75 353	53 630	20 851
Accrued income from sale of petroleum products	524 861	335 505	496 875
Other receivables, mainly balances with license partners	168 287	160 715	87 508
Total other short-term receivables	894 160	686 237	657 056

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 available liquidity.

	Group
Breakdown of cash and cash equivalents (USD 1 000)	31.03.2023	31.12.2022	31.03.2022
Bank deposits	3 280 245	2 756 012	2 816 731
Cash and cash equivalents	3 280 245	2 756 012	2 816 731
Unused RCF facility	3 400 000	3 400 000	3 400 000

The RCF is undrawn as at 31 March 2023 and the remaining unamortised fees of USD 9.9 million related to the facility are therefore included in other non-current assets.

The senior unsecured Revolving Credit Facility (RCF) of USD 3.4 billion was established in May 2019 and consist of two tranches: (1) Working Capital Facility with a committed amount of USD 1.4 billion until 2025 and USD 1.3 billion until 2026, and

(2) Liquidity Facility with a committed amount of USD 2.0 billion until 2025 and USD 1.65 billion until 2026.

The interest rate for USD is Term SOFR plus a margin of 1.00 percent for the Working Capital Facility and 0.75 percent for the Liquidity Facility. Drawing under the Liquidity Facility will add a utilisation fee. A commitment fee of 35 percent of applicable margin is paid on the undrawn part of the total facility. The financial covenants are as follows:

• Leverage Ratio: Net interest-bearing debt divided by twelve months rolling EBITDAX (excluding any impacts from IFRS 16) shall not exceed 3.5 times - Interest Coverage Ratio: Twelve months rolling EBITDA divided by Interest expenses (excluding any impacts from IFRS 16) 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. See reconciliations of Alternative Performance Measures for detailed information.

As at 31 March 2023 the Leverage Ratio is 0.16 and Interest Coverage Ratio is 78.6 (see APM section for further details). Based on the group's current business plans and applying oil and gas price forward curves at end of Q1 2023, the group's estimates show that the financial covenants will continue to comply with the covenants by a substantial margin.

Note 12 Derivatives

	Group
(USD 1 000)	31.03.2023	31.12.2022	31.03.2022
Unrealised gain currency contracts	1 607	2 907	2 004
Long-term derivatives included in assets	1 607	2 907	2 004
Unrealised gain commodity derivatives	-	-	38 650
Unrealised gain currency contracts	3 165	153 096	17 751
Short-term derivatives included in assets	3 165	153 096	56 401
Total derivatives included in assets	4 772	156 003	58 405
Fair value of option related to sale of Cognite	15 995	15 995	15 995
Unrealised losses currency contracts	29 812	986	387
Long-term derivatives included in liabilities	45 807	16 981	16 382
Unrealised losses commodity derivatives	1 083	-	9 190
Unrealised losses currency contracts	183 497	34 924	18 670
Short-term derivatives included in liabilities	184 580	34 924	27 860
Total derivatives included in liabilities	230 387	51 905	44 242

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

The derivative portfolio is revalued on a mark to market basis, with changes in value recognised in the income statement. 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 2022. All derivatives are measured at fair value on a recurring basis (level 2 in the fair value hierarchy, except for Cognite put option which is considered level 3).

As of 31 March 2023, the company has foreign exchange contracts to secure USD and EUR value of NOK cashflows for future tax payments and capital expenditure.

Note 13 Other current liabilities

	Group
Breakdown of other current liabilities (USD 1 000)	31.03.2023	31.12.2022	31.03.2022
Balances with license partners	94 231	43 132	51 183
Share of other current liabilities in licenses	502 967	460 783	355 966
Overlift of petroleum	24 136	30 922	26 146
Payroll liabilities, accrued interest and other provisions	272 071	272 276	178 408
Total other current liabilities	893 405	807 113	611 704

Note 14 Bonds

			Group
Senior unsecured bonds (USD 1 000)	Maturity	31.03.2023	31.12.2022	31.03.2022
AKERBP – USD Senior Notes 3.000% (20/25)	Jan 2025	498 391	498 172	497 514
AKERBP – USD Senior Notes 2.875% (20/26)	Jan 2026	497 990	497 813	497 280
AKERBP - USD Senior Notes 2.000% (21/26)1)	July 2026	913 848	907 387	-
AKERBP – EUR Senior Notes 1.125% (21/29)	May 2029	808 460	795 304	824 836
AKERBP – USD Senior Notes 3.750% (20/30)	Jan 2030	994 608	994 411	993 819
AKERBP – USD Senior Notes 4.000% (20/31)	Jan 2031	745 447	745 302	744 866
AKERBP - USD Senior Notes 3.100% (21/31)1)	July 2031	845 413	840 776	-
Long-term bonds - book value		5 304 158	5 279 164	3 558 315
Long-term bonds - fair value		4 972 331	4 829 678	3 469 031

1) These bonds have a nominal value of USD 1 billion and were recognised at fair value in connection with the Lundin Energy transaction at 30 June 2022. The difference between fair value and nominal value is linearly amortised over the lifetime of the bonds (see note 8).

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 15 Provision for abandonment liabilities

	2023	Group 2022 Restated	2022
(USD 1 000)	Q1	Q1	01.01.-31.12.
Provisions as of beginning of period	4 165 598	5 172 354	5 172 354
Incurred removal cost	-29 875	-16 168	-79 236
Accretion expense	40 354	21 343	119 895
Abandonment liabilities from acquisition of Lundin Energy	-	-	745 900
Foreign currency translation	-	-	6 692
Impact of changes to discount rate	273 999	-	-1 876 918
Change in estimates and provisions relating to new drilling and installations	3 044	8 098	76 911
Total provision for abandonment liabilities	4 453 120	5 185 627	4 165 598
Short-term	144 356	103 131	115 202
Long-term	4 308 764	5 082 496	4 050 396

Reference is made to note 1 for a description of change in the accounting principle for abandonment provision from Q4 2022. Following the change in accounting principle, the nominal pre-tax discount rate (risk-free) at end of Q1 is between 3.5 percent and 4.6 percent, depending on the timing of the expected cashflows.The corresponding range at end of Q4 was 3.9 to 4.7 percent. The calculations assume an inflation rate of 2.0 percent.

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 occurred between the end of the reporting period and the date of this report.

Note 18 Investments in joint operations

Total number of licenses	31.03.2023	31.12.2022
Aker BP as operator	126	120
Aker BP as partner	68	62

Changes in production licenses in which Aker BP is the operator:			Changes in production licenses in which Aker BP is a partner:
License:	31.03.2023	31.12.2022 License:		31.03.2023	31.12.2022
PL 036G1)	80.000%		0.000 % PL 035D1)	50.000%	0.000 %
PL 159H1)	23.835%		0.000 % PL 272D1)	50.000%	0.000 %
PL 10512)	0.000%		60.000 % PL 554E1)	30.000%	0.000 %
PL 10572)	0.000%	60.000 % PL 8962)		0.000%	30.000 %
PL 10942)	0.000%	60.000 % PL 9682)		0.000%	30.000 %
PL 1141B1)	70.000%		0.000 % PL 1148B1)	10.000%	0.000 %
PL 11711)	50.000%		0.000 % PL 1149B1)	30.000%	0.000 %
PL 11721)	40.000%		0.000 % PL 1182S1)	30.000%	0.000 %
PL 11751)	50.000%		0.000 % PL 11851)	20.000%	0.000 %
PL 11761)	60.000%		0.000 % PL 11911)	30.000%	0.000 %
PL 11931)	80.000%	0.000 %
Total	8		3 Total	8	2

1) Interest awarded in the APA Licensing round

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

End of financial statement

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 capitalised exploration wells less dry well expenses1)

Free cash flow (FCF) is net cash flow from operating activities less net cash flow from investment activities

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 expenses based on produced volumes, divided by number of barrels of oil equivalents produced in the corresponding period (see note 3)

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

		Q1	Q4	Q1	01.01.-31.03.	01.01.-31.12.
				Restated
(USD 1 000)	Note	2023	2022	2022	2023	2022
Abandonment spend
Payment for removal and decommissioning of oil fields		28 564	19 296	16 041	28 564	78 870
Payments of lease debt (abandonment activity)	7	1 518	57	245	1 518	751
Abandonment spend		30 082	19 353	16 287	30 082	79 621
Depreciation per boe
Depreciation	6	598 952	641 225	299 436	598 952	1 785 672
Total produced volumes (boe 1 000)	3	40 742	39 741	18 738	40 742	112 853
Depreciation per boe		14.7	16.1	16.0	14.7	15.8
Dividend per share
Paid dividend		347 612	331 812	171 054	347 612	1 005 731
Number of shares outstanding		631 793	631 586	359 788	631 793	496 765
Dividend per share		0.55	0.53	0.48	0.55	2.02
Capex
Disbursements on investments in fixed assets (excluding capitalised interest)		597 442	570 227	335 307	597 442	1 580 045
Payments of lease debt (investments in fixed assets)	7	17 294	7 832	19 838	17 294	46 942
CAPEX		614 737	578 059	355 145	614 737	1 626 987
EBITDA
Total income	2	3 310 354	3 825 929	2 291 288	3 310 354	13 009 898
Production expenses	3	-263 338	-286 424	-220 131	-263 338	-932 870
Exploration expenses	4	-97 692	-32 094	-57 523	-97 692	-242 193
Other operating expenses		-16 161	-16 026	-7 041	-16 161	-52 577
EBITDA		2 933 163	3 491 385	2 006 594	2 933 163	11 782 258
EBITDAX
Total income	2	3 310 354	3 825 929	2 291 288	3 310 354	13 009 898
Production expenses	3	-263 338	-286 424	-220 131	-263 338	-932 870
Other operating expenses		-16 161	-16 026	-7 041	-16 161	-52 577
EBITDAX		3 030 856	3 523 479	2 064 117	3 030 856	12 024 451
Equity ratio
Total equity		12 266 874	12 427 506	2 547 335	12 266 874	12 427 506
Total assets		37 927 999	37 561 780	17 939 633	37 927 999	37 561 780
Equity ratio		32%	33%	14%	32%	33%
Exploration spend
Disbursements on investments in capitalised exploration expenditures		79 409	37 788	48 557	79 409	251 764
Exploration expenses	4	97 692	32 094	57 523	97 692	242 193
Dry well	4	-63 771	-9 745	-39 443	-63 771	-135 800
Payments of lease debt (exploration expenditures)	7	5 927	178	206	5 927	6 222
Exploration spend		119 257	60 315	66 843	119 257	364 380

		Q1	Q4	Q1	01.01.-31.03.	01.01.-31.12.
(USD 1 000)	Note	2023	2022	2022	2023	2022
Interest coverage ratio
Twelve months rolling EBITDA		12 708 828	11 782 258	5 669 543	12 708 828	11 782 258
Twelve months rolling EBITDA, impacts from IFRS 16	7	-25 672	-20 835	-14 207	-25 672	-20 835
Twelve months rolling EBITDA, excluding impacts from IFRS 16		12 683 156	11 761 424	5 655 336	12 683 156	11 761 424
Twelve months rolling interest expenses	8	169 476	154 019	131 790	169 476	154 019
Twelve months rolling amortised loan cost	8	41 861	31 815	18 128	41 861	31 815
Twelve months rolling interest income	8	49 973	25 959	3 465	49 973	25 959
Net interest expenses		161 364	159 876	146 453	161 364	159 876
Interest coverage ratio1)		78.6	73.6	38.6	78.6	73.6
Leverage ratio
Long-term bonds	14	5 304 158	5 279 164	3 558 315	5 304 158	5 279 164
Cash and cash equivalents	11	3 280 245	2 756 012	2 816 731	3 280 245	2 756 012
Net interest-bearing debt excluding lease debt		2 023 913	2 523 151	741 584	2 023 913	2 523 151
Twelve months rolling EBITDAX		12 991 190	12 024 451	6 009 183	12 991 190	12 024 451
Twelve months rolling EBITDAX, impacts from IFRS 16	7	-24 988	-20 153	-12 638	-24 988	-20 153
Twelve months rolling EBITDAX, excluding impacts from IFRS 16		12 966 202	12 004 299	5 996 545	12 966 202	12 004 299
Leverage ratio1)		0.16	0.21	0.12	0.16	0.21
Net interest-bearing debt
Long-term bonds	14	5 304 158	5 279 164	3 558 315	5 304 158	5 279 164
Long-term lease debt	7	244 428	98 095	93 526	244 428	98 095
Short-term lease debt	7	101 216	36 298	42 184	101 216	36 298
Cash and cash equivalents	11	3 280 245	2 756 012	2 816 731	3 280 245	2 756 012
Net interest-bearing debt		2 369 557	2 657 545	877 294	2 369 557	2 657 545
Free cash flow
Net cash flow from operating activities Net cash flow from investment activities		1 682 014 -705 415	806 850 -708 449	1 375 295 -281 900	1 682 014 -705 415	5 729 472 -3 116 596
Free cash flow		976 599	98 401	1 093 395	976 599	2 612 876

1) These ratios are calculated based on Aker BP group figures only, with no proforma adjustments for the Lundin Energy transaction.

Operating profit/loss see Income Statement

Production cost per boe see note 3

To the Shareholders of Aker BP ASA

Report on Review of Interim Financial Information

Introduction

We have reviewed the accompanying condensed consolidated balance sheet of Aker BP ASA as at 31 March 2023, and the related condensed consolidated income statement, the statement of comprehensive income, the statement of changes in equity and the cash flow statement for the threemonth period then ended, and a summary of significant accounting policies and other explanatory notes. Management is responsible for the preparation of this interim financial information in accordance with IAS 34 Interim Financial Reporting. Our responsibility is to express a conclusion on this interim financial information based on our review.

Scope of Review

We conducted our review in accordance with International Standard on Review Engagements 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity. A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (ISAs), 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 consolidated interim financial information is not prepared, in all material respects, in accordance with IAS 34 Interim Financial Reporting.

Stavanger, 26 April 2023 PricewaterhouseCoopers AS

Gunnar Slettebø State Authorised Public Accountant

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